Oil Potential of the Upper Turama River and Fly River Delta Areas, Papua New Guinea Foreland

STEPHEN WOOD MASTERS THESIS

OIL POTENTIAL OF THE UPPER TURAMA RIVER AND FLY RIVER DELTA AREAS, PAPUA NEW GUINEA FORELAND

JULY 2010

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TABLE OF CONTENTS

ABSTRACT ...... 12 STATEMENT OF CONFIDENTIALITY...... 13 STATEMENT BY THE AUTHOR ...... 14 ACKNOWLEDGEMENTS...... 15 1 INTRODUCTION ...... 17 1.1 Definition of the Problem ...... 17 1.1.1 Key Objectives ...... 17 1.2 Geography ...... 18 1.3 Geological Overview ...... 19 1.4 Basement Fabric ...... 22 1.5 Stratigraphy and Basin Evolution ...... 23 1.6 Commercial Hydrocarbons ...... 28 1.7 Workflow Summary...... 30 2 STUDY AREA AND EXPLORATION ...... 32 RESULTS ...... 32 2.1 Definition of the Study Area ...... 32 2.2 Well Result Summary ...... 33 2.3 Key Well Post Mortems ...... 37 2.3.1 Kimu 1 ...... 37 2.3.2 Koko 1 ...... 39 2.3.3 Bujon 1 ...... 41 2.3.4 Fluid Inclusion Results...... 43 2.4 Seeps...... 46 3 ORGANIC GEOCHEMISTRY ...... 49 3.1 Previous Geochemical Work on PNG Oils ...... 49 3.2 Sample Inventory ...... 54 3.3 Geochemical Investigation ...... 57 3.3.1 General Data Plots...... 57 3.3.2 Oil Family L – Lacustrine ...... 62 3.3.3 Oil Family MC – Marine Carbonate ...... 72 3.3.4 Oil Family LJ – Late Jurassic Foldbelt Type...... 76 3.3.5 Oil Family O – Cretaceous...... 80 3.3.6 Oil Family C – Coal Sourced ...... 84 3.3.7 Oil Family X – Mixed Family Oils ...... 87 3.3.8 Kanau 1 – Oil to Source Correlations...... 93 3.3.9 Calculation of Oil Maturity...... 103 3.4 Summary of Results ...... 108 4 SOURCE ROCKS...... 114 4.1 Existing Work on PNG Source Rocks ...... 114 4.2 Definitions ...... 115 4.3 Review of Lund (1999) ...... 120

4.4 Source Rock Assumptions for this Study...... 123 4.5 Data and Data Revision...... 125 4.6 Source Potential Results...... 127 4.6.1 Triassic...... 130 4.6.2 Jurassic ...... 141 4.6.3 Cretaceous...... 143 4.6.4 Coal Source Rocks ...... 147 4.6.5 Algal Source Rocks...... 155 4.7 Summary ...... 159 5 BASIN MODELLING ...... 160 5.1 Overview of Previous Work ...... 163 5.2 Definitions...... 168 5.3 Modelling Locations ...... 168 5.4 Data ...... 170 5.5 Basin Modelling ...... 171 5.6 Kanau 1 - Basin Model ...... 176 5.6.1 Stratigraphy...... 176 5.6.2 Calibration ...... 177 5.6.3 Petroleum Generation...... 187 5.7 Omati Trough 1 – Basin Model ...... 191 5.7.1 Stratigraphy...... 191 5.7.2 Calibration ...... 193 5.7.3 Petroleum Generation...... 203 5.8 Omati Trough 2 – Basin Model ...... 207 5.8.1 Stratigraphy...... 207 5.8.2 Petroleum Generation...... 207 5.9 Summary of Results ...... 211 6 DISCUSSION AND PROSPECTIVITY ...... 215 6.1 Oil to Source Rock Correlation Summary ...... 215 6.2 Regional Temperatures ...... 216 6.3 Oil Maturity ...... 217 6.4 Oil Migration ...... 221 6.5 Gas Charge ...... 228 6.6 Charge History...... 229 6.7 Play Fairway Map ...... 231 7 CONCLUSIONS AND RECOMMENDATIONS...... 234 7.1 Conclusions ...... 234 7.2 Recommendations ...... 237 8 REFERENCES ...... 239 9 APPENDICES...... 249 9.1 Koko 1 Carbon Isotope data ...... 249 9.2 Geochemistry Data Tables ...... 250 9.3 Rock Eval Data Tables...... 293 9.4 Correspondence with Geotech Lab regarding Pyrolysis Gas Chromatography.... 321

9.5 Basin Modelling Data ...... 322 9.6 Basin Modelling – Definition of Terms ...... 326 9.7 Present Day Foreland Heat Flow – Esimation from North Paibuna 1 ...... 331 9.8 Thicknesses from the NW Papuan Basin ...... 332 9.9 Publications and Presentations...... 333

LIST OF FIGURES (F) AND TABLES (T)

CHAPTER 1

F1.1 Location of PNG (Papua New Guinea) relative to Australia to the south 18 and Indonesia / Irian Jaya across the border to the west

F1.2 Sedimentary basins of PNG. Location of the Papuan Basin is shown 19

F1.3 Geological Cross Section through the Papuan Basin 20

F1.4 Geological Elements of the Papuan Basin 20

F1.5 Various published lineaments identified in North Australia 22 and their linkages to Papua New Guinea (from Hill et al. 1995)

F1.6 Chronostratigraphy chart for the Papuan Basin 24

F1.7 Paleogeography of the Toro Sandstone, Late Tithonian to 26

Berriasian

F1.8 Permits, Application Permits and Oil and Gas Fields in the 28

Papuan Basin

F1.9 Thesis Workflow Diagram 31

CHAPTER 2

F2.1 Radarsat Image showing Rivers, Wells and Location of the 32

Study Area

F2.2 Kimu 1 – Well Results Summary 38

F2.3 Koko 1 – Well Results Summary 40

F2.4 Bujon 1 – Well Results Summary 42

F2.5 GOI Results from Koko 1, Kimu 1 and Bujon 1 44

F2.6 Location of the PPL77, Panakawa Seeps. Gas seeps 46 also shown

F2.7 Photographs showing the Surface Expression of the Panakawa 47 Seep site

T2.1 Well Post Mortem Summary Table 34

T2.2 GOI (Grains containing oil inclusions) results indicating oil migration or 43 palaeo oil columns in the Bujon 1, Kimu 1 and Koko 1

CHAPTER 3

F3.1 Oil Families of the Papuan Basin, as proposed by Waples and 51 Wulff (1996)

F3.2 Geographic and Stratigraphic location of Samples used in this 55 Study

F3.3 Example of a Geotechnical Summary Sheet used to Interpret 56 the Oils. The full collection is found in Appendix 9.2

F3.4 Sofer Plot - 13C (Saturates) vs 13C (Aromatics) 58

F3.5 13C Saturates vs Pr / Ph 59

F3.6 Sterane Ternary Diagram 60

F3.7 Oil Discrimination based on Tricyclic Terpanes 61

F3.8 Location of Oils Classified into Family L 63

F3.9 Chromatographs for Saturated Hydrocarbons for Oils in Family L 64

F3.10 Saturate and m/z 85 chromatograms – Koko 1 and Adiba 1 65

F3.11 Comparison of Terpanes (m/z 191) – Koko 1 and Adiba 1 66

F3.12 Comparison of 3 Methylhopanes – Koko 1 FI oil and 67 Adiba 1 Extract

F3.13 Comparison of Carotane – Koko 1 and Adiba 1 68

F3.14 Typical Geochemical Characteristics of an Overfilled Lake (top) 71 Balanced Filled Lake (middle) and Underfilled Lake (bottom).

F3.15 Map showing the Location of Oils grouped into Family MC 72

F3.16 Chromatographs for Saturated Hydrocarbons for Oils in Family MC 73

F3.17 Pristane to Phytane versus Dibenzothiophene/Phenenthrene 74 for Kimu 1 Extracts and Oils from Family MC

F3.18 Map Showing the Location of Oils Grouped into Family LJ 76

F3.19 Chromatographs for Saturated Hydrocarbons for Oils in Family LJ 77

F3.20 Triterpane Distribution of a Typical Foldbelt oil, compared to oil 78 from Kanau 1 (2525 m)

F3.21 Map showing the Location of Oils grouped into Family O 80

F3.22 Chromatographs for Saturated Hydrocarbons for Oils in Family O 81

F3.23 Map showing the Location of Oils Grouped into Family C 84

F3.24 Chromatographs for Saturated Hydrocarbons for Oils in Family C 85

F3.25 Location of Oils classified into Family X 87

F3.26 Chromatographs for Saturated Hydrocarbons for Oils in Family X 88

F3.27 Summary of Exact Geochemical Data from the Kanau 1 95 Triassic

F3.28 Geochemical Profiles through the CABGOC 123-4 well Lower 97 Coastal Congo Basin for the Depth Interval 8000-10,100 Feet

F3.29 m/z 191 Traces for Koko 1 FL Oil – Lower Imburu Sandstone 99 1159 – 1162m

F3.30 Equation and Molecules involved in Calculating the 103 Methylphenanthrene Ratio

F3.31 Relationship between MPI-1 and Rm% (mean) 104 (Radke and Welte 1983)

F3.32 Structure of the C29 20R Isomer (left) and C29 20S Isomer (right) 105

F3.33 C29 Sterane Ratio vs Vr % (from MPI -1) using Undegraded to 106 Mildly Degraded oils. Vr (Rm) from Coal Petrology is also shown, where available

F3.34 Charge Distribution by Family for the study area – 3.34 a) are 112 Mature Oils generated and Expelled from Source Rocks. 3.34 b) represents Oils of Relatively Low Maturity Generated from the Source Rock, but is still within or close to the Source Package

T3.1 Source Rock Discrimination using biomarkers (oiltracers) 50

T3.2 Summary of oil and source rock samples used in study 54

T3.3 Biodegradation Scale (Wenger et al. 2002) 57

T3.4 Oils classified in Family L – Lacustrine Facies 62

T3.5 Oils classified in Family MC – Marine Carbonate 72

T3.6 Oils classified into Family LJ 76

T3.7 Oils classified into Family O 80

T3.8 Oils classified into Family C 84

T3.9 Oils Recognised as Containg Oils from Two Families 88 (Family X)

T3.10 Comparison of Several Key Parameters for Mixed and 90 Unmixed Oils found at Kimu 1

T3.11 Comparison of Several Key Parameters for Mixed and 91 Unmixed Oils found at Bujon 1

T3.12 Comparison of Geochemical Parameters for the Koko 1 99 FI oil and Kanau 1 Extract

T3.13 Geochemical parameters between the Panakawa Seep and 102 Kanau Extract

T3.14 Subdivision of Oil Families by Maturity and Physical State 108

T3.15 Summary of Results from the Geochemistry of each Oil Family 109 described in Chapter 3

CHAPTER 4

F4.1 Modified Van Krevelen diagram showing Rock Eval data from 118 various Type I - II - III source rocks

F4.2 Location of Wells used in Source Rock Characterisation Study. 121 Current Study Area Marked.

F4.3 Kerogen mix map of the Magobu Coal Measures (Lund 1999) 122

F4.4 Wells used in the Rock Eval source potential study. Gridded 126 backdrop represents a Top Basement depth structure map (grid courtesy of Oil Search Limited)

F4.5 Bulk Source Rock Data by Biozone – TOC (Total Organic Carbon) 128

F4.6 Bulk Source Rock Data by Biozone – HI mgHC/gTOC 129

F4.7 Kanau 1 – Triassic Section showing Gamma Ray log, TOC and 132 Location of Core No1 (Top). Bottom shows a Representative Photo from the Section and a Core Description

F4.8 Rock Eval data for the Triassic (1) 134

F4.9 Rock Eval data for the Triassic (2) 135

F4.10 Lacustrine Depositional Systems – Mongolian Basin (Slaydon 138 and Traynor 2000)

F4.11 Rock Eval diagrams for the Magobu Formation 142

F4.12 Rock Eval diagrams for the Barikewa Formation 144

F4.13 Rock Eval diagrams for the Lower Imburu Formation 145

F4.14 Rock Eval Source Plots to assess Potential for Lower Ieru Formation 146

F4.15 Rock Eval Plots for Coals and Coaly Shales 150

F4.16 Pyrolysis GC Responses for typical source rock types (Dembicki, 2009) 151

F4.17 Summary of Pyrolysis GC data and Interpretive Ratios for the Komewu 2 153 Coal (Halosa Age – Magobu)

F4.18 Summary of Pyrolysis GC data and Interpretive Ratios for the Aramia 1 154 Coal (Indotata age – Magobu)

F4.19 Rock Eval Data – Algal Source Rocks – Kimu 1 158 F4.20 Summary of Pyrolysis GC data and Interpretive ratios for the Kimu 1 159 Sidewall Core (2165.5m)

T4.1a Definitions for Organic Constituents in Sedimentary Rocks and their 117 products upon Maturation (Peters et al. 2005)

T4.1b Maceral groups, their Origins and Respective Kerogen Types (Peters 117 et al. 2005)

T4.2 Summary of Source Rock guidelines based on Source Potential Data 119 and Kerogen Type (Peters and Cassa, 1994)

T4.3 Summary of Wells used in Source Rock Potential Study 125

T4.4 Kanau 1 – Organic Petrology Data from Triassic 136

T4.5 Calculations of Original TOC for the Triassic source rock – Kanau 1 140

T4.6 Summary of Coals and high TOC source rocks 148

T4.7 Summary of Organic Petrology data for Kimu 1 against measured 156 TOC

T4.8 General Source Characteristics from Rock Eval data - Bulk range 159 of most data

CHAPTER 5

F5.1 A Workflow Diagram to Demonstrate the Approach used in Basin 161 Modelling (Prayitno et al. 1992)

F5.2 Wells (coloured red) used in 1998 Basin Modelling Study 163 (Lund et al 1998). The current study area shown in dashed outline.

F5.3 Transformation Ratio plot for Jurassic source rocks at Kamusi 1 164

F5.4 Maturity Maps for the Barikewa and Magobu Formations 165 (Waples et al., 1998 with annotations added)

F5.5 Map showing the Turama River portion of the Study Area and the 168 location of basin models (red) and those which provide calibration (grey). Seismic data also shown

F5.6 Regional Paleoheat Flow for Basin Models (Lund et al. 1998) 172

F5.7 Cross Section showing Stratigraphy within the Foreland, demonstrating 174 thicknening of the Darai Limestone and Era Beds into the Omati Trough

F5.8 Comparison of Vr, AFTA and Present Day Temperatures from Kanau 1 177 (Green 2001)

F5.9 Kanau 1 – Initial Calibration – Steady State Model 179

F5.10 Kanau 1 – Steady State – Model 1 180

F5.11 Kanau 1 – Steady State – Model 2 181

F5.12 Kanau 1 – Transient – Model 3 182

F5.13 Kanau 1 – Transient – Model 4 183

F5.14 Temperature versus Time profiles – Kanau 1 models 185

F5.15 Kanau 1 – Transformation History for the favoured calibration 187

F5.16 Kanau 1 – Maturity history using Vr and Tr for the favoured calibration 188

F5.17 Seismic data from PN91-122 showing the Position of the Omati 191 Trough 1 Basin Model

F5.18 Comparison of Komewu 2 Temperature Data and Thermal History Data 193 versus Depth based on 10Ma and 1Ma Heating Rates

F5.19 Comparison of FAMM and Vr with depth for Kamusi 1. With comments 195 by Faiz et al. (1997)

F5.20 Omati Trough 1 (Kamusi 1) Calibration – Steady State – Model 1 197

F5.21 Omati Trough 1 (Kamusi 1) Calibration – Transient – Model 2 198

F5.22 Omati Trough 1 (Kamusi 1) Calibration – Transient – Model 3 199

F5.23 Omati Trough 1 (Kamusi 1) Calibration – Transient – Model 4 (FAMM) 200

F5.24 Omati Trough 1 (Kamusi 1) Calibration – Transient – Model 5 (FAMM) 201

F5.25 Transformation Ratio over time - Omati Trough 1 (Kamusi 1) 203

F5.26 Transformation Ratio over time – Bottom of Source Rock – 204 Calibration 2 – Low heat flow model

F5.27 Transformation Ratio over time – Bottom of Source Rock – 205 Calibration 4 – High heat flow model

F5.28 Seismic Data from PN90-109x showing the Position of the Omati 207 Trough 2 Basin Model

F5.29 Transformation History over Time for Omati Trough 2 208

F5.30 Transformation Ratio - Omati Trough 2 209

F5.31 Oil Expulsion History with Time for the Kanau 1 and Omati Trough 1 211 and Omati Trough 2 Basin Models

T5.1 Summary of Thermal History Data used in Study 169

T5.2 Comparison of Assumptions used in Basin Modelling. 171 Lund et al (1998) compared to Present Study

T5.3a Source Rock Characteristics used for Basin Models 175

T5.3b Expulsion Thresholds used in Basin Models for Various Source Rocks 175

T5.4 Summary of Inputs used for calibration Models 1 to 4 – Kanau 1 178

T5.5 Summary of Inputs used for Calibration Models 1 to 5 – Omati Trough 1 196

T5.6 Comparison of Inputs used for Basin Modelling Studies 212

CHAPTER 6 F6.1 Corrected Temperature Map for the Toro Sandstone – Present Day 215 (Adapted from Schofield 2001)

F6.2 Maturity Ranking Diagram 217

F6.3 Oil Maturity Distribution Map - Low Maturity Oils (<0.65%Vr) 219

F6.4 Map of Mature oils - Biodegraded Charge 221

F6.5 Map of Mature Oils - Late Charge 223

F6.6 Cross section through the Fly River delta area 224

F6.7 Map of Mature Oils – Fluid Inclusion Oils 226

F6.8 Isotopic data from PNG Foldbelt gases, Kimu 1, Koko 1 and 227 NW shelf gases (after ECL 2005)

F6.9 Charge History of the Turama River Area 229

F6.10 Play Fairway map for the Study Area 231

T6.1 Oil to Source Rock Correlation Summary 214

ABSTRACT

The Papuan Foreland is a structurally simple region and is generally under-explored relative to the Papuan Foldbelt where significant oil and gas fields have been discovered. Despite several gas discoveries in the Foreland, well results suggest an oil based petroleum system exists. This study aimed to define the origin of these oils, explain both the charge and migration history and use the results to define areas for future oil exploration.

The study focused on two areas of the Foreland: The Turama River (north) and Fly River Delta (south). The organic geochemistry of thirty-five oils were described from ten wells and two seeps in the study area. These were divided into five oil families, consisting of; Family L (lacustrine), Family MC (marine carbonate), Family LJ (Late Jurassic sourced), Family O (Cretaceous-Tertiary sourced), Family C (coal sourced). A sixth family, Family X represented mixed oil families.

Oil to source correlations were performed for the oil families. Biomarker and isotopic data demonstrated that oils from Family L appear to be sourced from Late Triassic mudstones which were drilled at Kanau 1 deposited in a synrift environment. Family MC oils may also be sourced from this synrift based on biomarker evidence but the correlation is less certain with respect to isotopic data. Oil to source correlations appear simple for Families LJ and C since low oil maturity suggests in-situ generation for most of the oils from these families. Lack of data and probable deep erosion of the Late Cretaceous means that the source for Family O oils is uncertain.

Source rock evaluation data was investigated for the greater study area which showed that using Total Organic Carbon and Hydrogen Index cut offs, oil prone source rock typically of poor to fair quality is developed in the Magobu, Barikewa and Lower Imburu Formations. Source potential for the Triassic is fair to good. Coals within the Magobu are also shown to be oil prone. Assessment of algal rich units in the Barikewa to Lower Ieru section at Kimu 1 were also assessed for oil source potential but appear gas prone.

Using knowledge of the source rocks and stratigraphy from wells and seismic, Basin Mod 1D models were created to evaluate the charge history; one model was based in the Darai Plateau at Kanau 1, with two pseudo-wells used to model the Omati Trough. Basin history indicates two charge events: 1) a Late Cretaceous event recorded by biodegraded Family L oil on footwall highs or in fluid inclusions. 2) A Miocene to Present Day charge which likely contributed Family MC and/or L oils either as seeps or as fresh oil ‘overprints’ upon previously biodegraded oils. Biodegradation of Late Cretaceous oil is believed to be a likely origin of biogenic gases such as at Kimu 1 and Koko 1.

A play fairway map was created for the study area, indicating the Turama River and Fly River Trough areas have oil potential. Basin modelling suggests late oil charge is possibly limited in volume in the Turama River area.

STATEMENT OF CONFIDENTIALITY

Due to a confidentiality agreement between Oil Search Limited and

the Australian School of Petroleum, this thesis is not available for

public inspection or borrowing until 31 July 2012.

STATEMENT BY THE AUTHOR

This work contains no material which has been accepted for the award of any other degree or diploma in any university or other tertiary institution. To the best of my knowledge and belief, this thesis contains no material previously published or written by another person, except where due reference has been made in the text.

I give consent to this copy of my thesis to be deposited in the University Library, but subject to a 2 year confidentiality agreement, as stated on page 13. Once the date of confidentiality has been passed, I give permission for the following:

• For the thesis to be made available for loan and photocopying, subject to the provisions of the Copyright Act 1968.

• For the digital version of my thesis to be made available on the web, via the University’s digital research repository, the Library catalogue, the Australasian Digital Theses Program (ADTP) and also through web search engines.

Stephen Wood

ACKNOWLEDGEMENTS

A large dose of thanks to my primary supervisor Associate Professor Bruce Ainsworth. Amongst his busy schedule and a somewhat turbulent time through my many supervisor changes has managed to help me steer the boat to the finish line and give valuable advice throughout the project.

Other supervisors which contributed significantly to the project include Peter Tingate and Dr. Graham Bradley who I thank graciously for their time, effort and attention to detail and putting aside both work and personal time to give me some valuable direction. Also to Associate Professor David McKirdy who also provided advice at regular intervals and proof read several sections for which I’m grateful. Also to Dr. Tobias Payenburg and Andy Mitchell who both helped me to start off on the project and provide administrative direction.

I would like to salute some of the original progenitors that took me on the road to undertaking this thesis. These include Dr. Herbert Volk, Tony Allan, Dr. Neil Sherwood and Dr. Simon George at CSIRO for much of their geochemical and petrological work which promoted prospectivity in the region. These authors also provided valuble input at several stages during the thesis. Building on foundations from the CSIRO studies, Trent Spry and Jim Preston through the ECL (Exploration Consultants Limited) opened the way for this thesis by putting the pieces together and pointing out the significance of several pieces of overlooked data. Thanks guys and thanks for getting me enthused on the subject of geochemistry in petroleum exploration. Its certainly got me gripped.

Dr. Chris Boreham at Geoscience Australia is thanked for contributing the geochemical and stable isotopic analyses of the Koko 1 oil and providing additional advice on several aspects of the geochemistry section. Thanks also to Stuart Barclay at SRK for geochemical advice.

Thanks to Oil Search Limited for their approval of the project, the ability to use the vast PNG technical database as well as the use of industry software. Many people at Oil Search helped contribute to the thesis, either through technical advice or setting up databases and tidying data for use in the thesis. Special mention must go to Nigel Wilson, Mark Wilson, Ian Longley, Steve Winn, Kevin Hill and Tony Young for their great support throughout various stages of the project and their advice. Peter Hamilton 16

needs particular thanks for his so-very-excellent drafting contributions which are always very professional. Mention also to the following staff who also helped me, including Simon Skirrow, Dorothy Weregola, Kevin Foong, Stephanie Kreibich, John Noonan, Michael Dale, Ariel Bautista & Grant Taylor.

Thanks to Diana Giordano and the crew at Recall (Kestral) in Melbourne for organising my core visit.

A big acknowledgement to Cindy Barber and Birgitta Hartung-Kagi at Geotech, Perth for their geochemical advice.

Many thanks to fellow students at the ASP for providing that shoulder of support and understanding for when I was down in Adelaide. Special thanks Sally-Anne Edwards for helping me out with accommodation.

I also can’t forget to mention my friends back in Sydney. Although I think its likely I annoyed various people over the last ~2 years due to my ‘non availability’ I think most have generally understood why it was happening and that life would return to normal again at some stage. My parents and sister were instrumental in pushing me onward.

Special mention to Nathan Jones. Thanks again mate for helping me on the artistic front.

Now for some people that may never see this. Lots of home time has meant that music has been a big part of getting me through the thesis and the discovery of Triple J and their varied music genres has assisted greatly here and also delivered me a new hobby. So heres to Bloc Party, Kate Miller-Heidke, Vampire Weekend, The Killers, Mercy Arms, Radiohead, Josh Pyke, Augie March and a whole bunch of other great music creators that got me through. Oh and I’d also like to make mention of my ‘lifesaving’ stovetop espresso and a series of good Italian and PNG coffees. 17

1 INTRODUCTION

1.1 Definition of the Problem

In Papua New Guinea (PNG) the only source of oil production is from the Papuan Highlands (Figure 1.1) where the first commercial oil discovery was made at Kutubu field by Niugini Gulf Oil in 1986 (Rickwood 1990; Owen and Lattimore 1998). The Papuan Lowlands (also called Foreland, Figure 1.1) is an area with relatively gentle topography to the SW of the Highlands, where the density of wells is lower. Exploration success has been limited in the Foreland but discoveries to date have demonstrated that gas is the most likely hydrocarbon to be discovered in the province e.g. Kimu 1 (Schofield 2000a). A dichotomy exists between existing studies. Wulff et al (1994) state that the greater foreland area is largely non prospective for oil based on the requirement for long distance migration from the major kitchens and the gas generative propensity of the source rocks. In contrast Lund et al. (1998) through basin modelling indicate a three phase hydrocarbon generation history and state that substantial volumes of oil have been generated from Jurassic source rocks. Barndollar (1993) also considers the region to be highly prospective for oil. No commercial oil discoveries have been encountered in the PNG Foreland, however oil has been recovered in several wells including Bujon 1 (Phillips 1994) and Kimu 1 (Schofield et al. 1999a). Oil recovery was also achieved at Koko 1 and although the oil was biodegraded, pressure data suggests this well contains the Foreland’s only oil column. (Schofield et al. 1999b). Much of the worlds oil reserves occur in foreland areas adjacent to fold-thrust belts (Osborne, 1990).

The problem to be addressed here is to investigate whether or not there is a commercial oil based petroleum system in the Papuan Foreland. The study area has been defined in the region between the upper reaches of the Turama River and also the Fly River (Figures 1.1-1.4) where wells recovered oil in the form of shows, extracts or samples. Other oil indications in the area include the existence of at least two oil seeps in the region (Daly and Severson 1991; Niugini Energy 2006).

1.1.1 Key Objectives

The project has five key objectives:

1. Review of the existing exploration results in the study area

2. Interpretation of the main oil families, based on the geochemistry of reservoired oils, fluid inclusion oils, oil extracts and oil seeps. Definition of which formations are likely source rocks for each of these oil families. 3. Use Rock Eval &/or organic petrology screening data to assess the oil source potential of the stratigraphy. 4. Basin modelling of oil prone source rocks to predict the charge history in the area. Relate the oils recovered in the wells to the charge history. 5. Map out potential fairways for oil exploration, based on the probable presence of mature oil generative source rocks.

1.2 Geography

The island of New Guinea is located to the north of Australia as shown in Figure 1.1.

Figure 1.1: Location of Papua New Guinea relative to Australia to the south and Indonesia / Irian Jaya across the border to the west. Papuan Highlands indicated by arrow (figure courtesy of Oil Search Limited)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library. Papuan Lowlands

Owen and Lattimore (1998) describe the country of PNG to represent the eastern half of the island of New Guinea as well as some 600 offshore islands, with the western part of the mainland representing Irian Jaya. PNG is the largest country in the South Pacific, with a population of nearly 5 million people. The landscape has great geographical diversity characterised by high mountain ranges, low lying swamps to volcanoes and is endowed with lush tropical vegetation. The country is rich in natural

resources, including a vast rainforest cover, which represents 75% of the land area, rich marine life, agriculture and significant deposits of oil, gas, gold, copper and other minerals. The exploitation of these natural resources has lead to the development of a dualistic economy dominated by the capital – intensive oil, mineral and forestry sectors.

1.3 Geological Overview

Papua New Guinea consists of several sedimentary basins, but only the Papuan Basin has been proven to contain commercial hydrocarbons. The study area is located in the Papuan Basin (Figure 1.2).

Figure 1.2: Sedimentary basins of PNG. Location of the Papuan Basin shown (figure courtesy of Oil Search Limited)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

The Papuan Basin is a basin located across both the onshore and offshore areas and consists of Mesozoic and Tertiary fill. The PNG Foreland is tectonic element which is a flat to gently undulating region SW of the Papuan Foldbelt. The structural relationship of the PNG Foldbelt and Foreland is shown in the cross section in Figure 1.3. Elevation for the Foreland ranges from 0-300m above sea level and the geological structure of the foreland is relatively simple, consisting of gentle dips and faults with normal or strike slip sense. The main tectonic elements of the foreland are the Omati

Trough, Bosavi Arch, Fly-Strickland Depocentre, Komewu Fault Zone, Aramia Graben, Morehead Graben, Lake Murray High and Oriomo High (Figure 1.4).

Figure 1.3: Geological Cross Section through the Papuan Basin (Wulff et al.1994) PNG Foreland PNG Foldbelt

A NOTE: This figure/table/image has been removed

to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Figure 1.4: Geological Elements of the Papuan Basin adapted from Wulff et al. (1994). Major tectonic elements in the basin are shown.

A NOTE: This figure/table/image has been removed

to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

It is important to note that the ‘Foreland’ is not a Foreland Basin in the traditional sense. Encyclopaedia Britannica (2009) defines a foreland basin as “subsurface features, filled with sediment eroded from the adjacent mountain ranges…..Foreland

basins are formed because the overthrusting of the mountains onto a neighbouring lithospheric plate places a heavy load on the plate and flexes it down”. In the PNG context the Foldbelt is also loading and downwarping the area to its SW however this is relatively minor within the study area. The effect is far more pronounced in the Gulf of Papua (GoP) and the Fly Strickland Depocentre (FSD) where Schofield (2000) mapped >700m and >800m of section, respectively of Plio-Recent strata (blue areas in Figure 1.4). For the purposes of this study the Foreland refers to the area SW of the Papuan Foldbelt and NW of the Pasca Trough, but excluding the Darai Plateau (see Figure 1.4)

The two key features that have influenced the evolution of the study area are the Bosavi Arch and the Komewu Fault Zone (KFZ). The Bosavi Arch is a Late Paleocene to Recent northeast-trending regional high that runs roughly through the centre of the Foreland whereas the KFZ is a Miocene fault system that separates the Omati Trough from the Fly Platform (Schofield 2000, see Figure 1.3). Schofield (2000) through regional mapping found that fault throws along the KFZ are greatest in the east, and movement along the KFZ resulted in subsidence of the Omati Trough and influenced carbonate sedimentation.

Fold and thrust deformation in the Papuan Basin occurred in the Late Miocene to Holocene (Hill, 1991; Hill and Raza 1999) and this compression also led to minor reactivation of pre-existing faults in the Papuan Foreland (Schofield 2000). One of the largest expressions of this inversion is the Darai Plateau (Figure 1.3) located on the northern boundary of the foreland. Hill (1991) described the Darai Plateau as a single very large anticline (the Darai anticline) and suggests that on the basis of the comparable area of the Darai Plateau to the Omati Trough that the underlying Darai fault may have been extensional like the Komewu Fault, but was subsequently inverted, probably on a deep seated listric fault detached within basement (Hobson 1986)

1.4 Basement Fabric

New Guinea has a number of lineaments and tear faults, corresponding to zones of tectonism, foldbelt deflections or features which may only appear on gravity and magnetics data (Hill et al. 1996). These features have a predominant trend of NNE- SSW and some can be traced into Northern Australia, where they are exposed as long lived Proterozoic or Palaeozoic shear zones (Figure 1.5)

Figure 1.5: Various published lineaments identified in Northern Australia and their likely linkages to Papua New Guinea (from Hill et al. 1995)

A NOTE:

This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

These zones are important to the New Guinea petroleum system since they provide compartmentalisation of depocentres, influence source and reservoir rock distribution and burial history across the basin (Hill et al. 1996). The Bosavi Lineament (Figure 1.5) described by Hill and Gleadow (1989) is relevant to PNG’s existing hydrocarbon discoveries. The authors observe that the lineament provides vertical offset of the sediments which results in changing of the source rock maturity, resulting in gas condensate to the west of the lineament, and oil to its east.

Imposed upon the NNE trending lineament is a secondary fabric, orientated WNW to NW which represents the predominant strike direction of the basin. Like the NNE

fabric, this secondary fabric appears to be an ancient basement grain and is also recognised in Australia (Elliot 1994).

1.5 Stratigraphy and Basin Evolution

Figure 1.6 shows a chronostratigraphy chart which summarises the age and stratigraphic relations between the major rock units in the Papuan Basin and their corresponding geological history.

A summary of the geological history of the Papuan Basin is outlined as follows. This history is based on work of the following authors; Skwarko et al. 1976; Home et al. 1990; Wulff et al. 1994; Hill et al. 1996. Additional authors which have contributed more detailed knowledge are given in the text. Titles in bold represent major formations.

Deposition in the basin began with the Kuta Limestone. This is a pre-rift sucession which consists of marine arkose, limestone and shale and is Late Triassic in age. The unit appears restricted in distribution and hence the basin is interpreted as being close to emergent during deposition or alternatively the unit experienced widespread uplift and erosion. Jablonski et al. (2006) presents seismic evidence that the Gulf of Papua (GoP) may contain failed rift arms containing Permian synrift sequences. This is unconfirmed by drilling to date.

Preceding and coeval with the break-up of Gondwana in PNG, Home et al. 1990 identified two rifting events based on field and seismic evidence. The first in the Triassic, the second in the Early-Middle Jurassic. The rifts resulting from these events were similarly orientated, from E-W to ESE-WNW.

Volcanism associated with the Triassic event resulted in the deposition of syn-rift Kana Volcanics, consisting of volcanoclastics and greywacke, deposited in a shallow marine environment. Unlike the Kuta Limestone, this unit appears more widespread, cropping out to the north of the foldbelt (up to 3500m thick). Jablonski et al. (2006) presents seismic evidence that PNG was affected by the Bowen Orogeny / Fitzroy movement during the Upper Triassic, observing Triassic section truncated against the base Jurassic unconformity, believed to be developed due to compression and uplift of the Triassic section.

THIS PAGE IS LEFT INTENTIONALLY BLANK A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library. 25

The Early-Mid Jurassic rift event, and ensuing post-rift thermal collapse led to the deposition of the Magobu and Barikewa Formations. The Magobu, and also the equivalent Bol Arkose consists of felspathic sandstones, siltstones, mudstones and occasional coal deposited in a fluvial to delta plain environment. The Barikewa Formation consists of fine grained clastics and shales deposited in an outer shelf environment during the onset of thermal collapse following the rift episode. The Barikewa is recognised as a source rock for oil and gas fields in the Foldbelt. Where clastic influx was higher, shallow marine to fluvio-deltaic sandstones of the Koi-Iange were deposited.

The boundary between post-rift and syn-rift within the Magobu and Barikewa units has been difficult to identify, however Home et al. (1990) estimates the boundary at approximately 170Ma.

During the Kimmeridgian and Early Tithonian a marine transgression resulted in the deposition of fine grained outer shelf to slope sediments of the Lower Imburu Formation where clastic influx was generally low and marine circulation was likely restricted. The Lower Imburu is also recognised as a source rock for PNG oils and gases. In more proximal positions coarse clastics were deposited in the north of the basin in a series of fluvial-estuarine channels which were reworked into a NW-SE trending shoreface, the most important being the Iagifu, Hedinia and Digimu Sandstone Members all of which represent reservoirs of commercial importance in the PNG Foldbelt (respective reservoirs indicated in Figure 1.6)

During the Late Tithonian to Berriasian a major fall in base level resulted in the deposition of the Toro Sandstone. This unit developed as a reservoir facies over a very large portion of the basin and is the most common reservoir to contain commercial hydrocarbons (indicated in Figure 1.6). At this time two large sand feeder systems existed, one directed to the north east, and another in the position of the present day Fly River delta with sand re-worked into a roughly NW orientated shoreface belt, best developed in a belt in the vicinity of the main frontal thrust of the foldbelt. This is depicted in a palaeogeography map in Figure 1.7.

Figure 1.7: Palaeogeography of the Toro Sandstone, Late Tithonian to Berriasian (Robinson & Winn,1998)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

A transgression ended the deposition of coarse clastics during the Early Valanginian depositing the fine grained Ieru Formation. The Ieru represents a seal facies for hydrocarbons traps in the basin. During the onset of flooding, the locus of coarse clastics was back stepped approximately 100km to the SW depositing the shoreface-estuarine Alene Sandstone within the generally fine grained Alene Member. The Alene Sandstone is the main gas reservoir for discoveries in the Foreland (indicated in Figure 1.6). A further transgressive event in the Hauterivian reduced the clastic influx and terminated Alene Sandstone deposition. Sea level perturbations enabled the succession to be divided into the Alene, Juha and Bawia Members, collectively known as the Lower Ieru Formation.

During the Late Cretaceous, a wide area of the basin was subjected to uplift and erosion, preceeding the Coral Sea Rifting event. Uplift and erosion was greatest in the GoP, decreasing in a NW direction. The far NW of the Papuan Basin experienced major downwarping which subsequently formed a deep marine basin. The Upper Ieru Formation was deposited during this time, fed by the stripping and erosion of the existing stratigraphy. Sediments were outer shelf shaly sands and muds. The Upper Ieru is divided into the Giero, Ubea and Haito Members. Sari et al. (1996) identified that the Giero and Ubea members, particularly in the NW of the basin, contain slope to basin floor fan reservoirs. However, these are generally fine grained and appear to have poor reservoir characteristics.

Sea floor spreading occurred in the Tasman Sea and Coral Sea during the latest Cretaceous. During the Paleocene, thermal collapse of the Papuan basin occurred. During the Eocene to Early Oligocene, the northern margin of the Australian plate experienced the early stages of convergent tectonics and the collapse event resulted in the deposition of the shelfal to bathyal carbonates of the Mendi Formation (mostly in the GoP). During the Late Oligocene to Late Miocene, the thermal collapse became more widespread, resulting in the deposition of platform to reefal Darai Limestone over a large proportion of the Papuan basin. The Darai is the main gas reservoir for discoveries in the Gulf of Papua (see Figure 1.6).

During the Late Miocene to Recent the whole Australian craton experienced compression due to collision with island arcs during northward drift of the Australian plate which saw the activation and inversion of the roughly NW-SE fabric of PNG resulting in the PNG Foldbelt. The folds and thrusts developed in a variety of tectonic styles, both thin and thick skinned. Detritus shed from rising highlands terminated the carbonate deposition. The subsequent initiation of a Foreland Basin followed by an early Pliocene transgression which created marine conditions, which resulted in deposits of the fine grained mudstones of the Orubadi Beds (with minor carbonate) and finally the Pleistocene marginal marine to non marine Era Beds. In the PNG Foldbelt, these units are largely restricted to the synclines since the unit was eroded due to uplift on the anticlines. Continued thermal subsidence following cessation of spreading in the Coral Sea, as well as crustal loading due to the onset of compression, resulted in thick sequences of Orubadi and Era Beds in the GoP. Thick sequences were also developed onshore in the NW of the basin but the central onshore contains only a thin veneer of these sediments since it is undergoing

isostatic rebound. Quaternary volcanics and volcaniclastics, which include the large stratovolcanoes prominent on PNG’s present landscape are also part of this sucession and exhibit radiometric ages of 0.2 – 1.6Ma.

1.6 Commercial Hydrocarbons

The location of hydrocarbon discoveries, oil pipelines and gas pipelines plus the Kumul Terminal are shown in Figure 1.8. Oil exploration in PNG began in the early 1900’s. Investigation of the gas blows and oil seepages in the Vailala River region by Dr Arthur Wade, petroleum geologist, resulted in the drilling for oil at Upoia (Figure 1.8), producing small amounts of light oil. Their reports indicate that commercial oil was believed to have been discovered but was considered by Wade to be too large to be developed in a reasonable time frame (Rickwood, 1990). Although small non- commercial discoveries were made during the 1950s and 1960s it was not until the discovery of the Kutubu fields in the 1980’s that the oil industry in PNG came to be recognized as a viable concern (Owen and Lattimore, 1998).

Figure 1.8: Oil and gas fields of the Papuan Basin (Figure courtesy of Oil Search Limited)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

The Juha to SE Gobe trend represents the foldbelt series of discoveries, where oil, gas and condensate, are trapped in thrust faulted anticlines. Oil production occurs from the SE Mananda, Agogo, Kutubu, Moran and Gobe Main and SE Gobe fields. The primary productive reservoir in each field is shown in Figure 1.6. Field sizes, which are quoted in original recoverable 2P (or probable) reserves, range from 348mmbls (million barrels of oil) at Kutubu to 3.4mmbls at SE Mananda (Oil Search web site, 2008). A substantial resource of gas and gas-condensate exists in PNG, some of which is associated with the existing oil fields. The largest gas- condensate discovery is the Hides field with a contingent resource estimated at 5.3 TCF (Trillion Cubic Feet of gas) (Oil Search Website). During May 2008 an agreement was signed between participants in the gas joint venture and the PNG government to develop an LNG scheme in PNG and to bring the undeveloped gas and condensate, to both local and international markets. A FEED (Front End Engineering and Design) project was initiated shortly after the agreement was signed to assess feasibility of the project, which is to include the installation of a gas pipeline (see proposed route, Figure 1.8)

1.7 Workflow Summary

The structure of this thesis is devised to provide a logical series of analyses and results, where one chapter further develops the results from the previous chapter. Chapters 1 and 2 include the Introduction, Study Area description and Exploration Results and give an Overview of the Geography, Basin Location, Stratigraphy and also outline the rationale for the study area, based primarily on the extent of a working oil based petroleum system. A strategy in the construction of the thesis was the placement of Organic Geochemistry early in the thesis (Chapter 3) which allows guidance of the study in later chapters. The various sections of work are described below and is also shown in as a workflow diagram in Figure 1.9. a) Organic geochemistry results for oils in the study area are derived from results obtained from various labs. Individual reports are referenced in Chapter 3. b) Assessment of the similarities and differences between oils and source extracts in the study area led to the interpretation of oil families by the author. c) The geochemical characteristics of each oil family point to particular depositional environments. These are interpreted by the author, but with some additional reference to descriptions given in lab results as section a) where due reference is given in the text. d) Chapter 4 focuses on source rock quality of the Triassic to Cretaceous section, with particular consideration to portions of the stratigraphy as indicated by the organic geochemical results. The sources of the Rock Eval and Organic Petrology, sections e) and f), derived from lab sources. Interpretation of the data, primarily using source quality cross plots was performed and interpreted by the author. g) Chapter 5 involves the integration of the known information from stratigraphy, source rocks, depocentres and organic geochemistry of oils to model charge history in the region. h) Existing lab results from thermal history data used in basin models i) Prospectivity Analysis (Chapter 6) aims to combine the key findings of the study, particularly with respect to oils and their likely source rock intervals. A series of maps are provided which summarise the possible extent of oil play fairways. j) Conclusions and Recommendations – Chapter 7 summarises the key results from the study and outlines scope for further work.

2 STUDY AREA AND EXPLORATION

RESULTS

2.1 Definition of the Study Area

The study area encompasses an area of approximately 21,000 square kilometres, in a region located between the upper headwaters of the Turama River in the north and the Fly River and its associated delta in the south, as shown in Figure 2.1.

Figure 2.1: Radarsat image showing rivers, wells and location of the study area. Key details of the well results are detailed in Table 2.1

Geologically the area occupies part of the Foreland. The northern portion of the study area is located on the Bosavi Arch, a tectonic feature which appears to be a favourable region for the migration of hydrocarbons, as indicated by results in the

wells Kimu 1, Koko 1 and Bujon 1 (see section 2.3). A portion of the inversion feature known as the Darai Plateau is located in the NE of the study area. Although technically the Darai Plateau is akin to the PNG Foldbelt, the Plateau simply represents a ‘pop up block’ of rift to passive margin stratigraphy directly adjacent to todays Foreland. Given this intimate association to the Foreland and the study area, the Darai Plateau also requires consideration in this thesis. The middle and southern portion of the study area is a gently structured portion of the Foreland, known as the Fly Platform. Two oil seeps are known in this area (Daly and Severson, 1991) in addition to at least one well, Adiba 1, which reported oil shows (Philips, 1995).

2.2 Well Result Summary

An important aspect in developing a hydrocarbon play concept in any basin is an understanding of the existing exploration history. The study area contains a series of wells with a variety of results, ranging from discoveries to dry wells. Note that the definition of a discovery in this case refers to a well encountering a column of either oil or gas. There is no implication that the volume and/or nature of the hydrocarbons represents a commercial resource.

Table 2.1 summarises the key information from wells in the study area that are pertinent to the context of understanding the petroleum systems present in this portion of the Foreland. The location of the wells are shown in Figure 2.1.

Table 2.1: Well Post Mortem Summary Table

Adapted and extended for this study from Schofield (2000b)

Well Spud Status Result(s) or Shows Formation at Currently Valid Trap Valid Trap at Likely reason for failure COMMENTS date TD mapped as at primary secondary structural objective? objective? high? Bujon-1 23-1-1994 P&A • 12-16m palaeo column with Permian Yes No No Vertical seal: recent • Fault dilation on Bosavi low (10-20%) gas saturations Granite faulting and extension Arch opened pre-existing in Toro (256±6Ma) leading to fault dilation fault planes leading to • Fluid inclusions show palaeo vertical seal failure. column contains marine, • Evidence of at least two carbonate-rich source rocks, phases of charge. hopane:sterane 0.23, slightly • Low in Top Carbonate biodegraded reflector at Bujon-1 well • Live oil from SWC/cuttings location – possible has strong lacustrine channelling fingerprint, moderately to slightly biodegraded. Hopane:sterane (0.47-0.72) in live oil showing more mature source rocks than sampled from palaeo column

Iamara 1 1962 P&A • Oil shows in 4x core intervals Permian No No No Not on structure • Drilled on Oriomo High Granite

Kamusi-1 10-1-1996 P&A • Background gas in Toro SS Top Yes No No Vertical seal: recent Toro mapped to sub-crop Koi-Iange faulting & extension Carbonates on bend in KFZ <1% C1-C4, log anomaly in Toro SS related fault dilation Mapped within possible shadow • Lateral seal: juxtaposition zone for HC migration out of Omati Fluid inclusion study of reservoirs and Trough suggests recent migration carbonate section Low in Top Carbonate reflector at • Source interval shown to be Kamusi-1 well location – possible early to peak mature sinkhole

Well Spud Status Result(s) or Shows Formation at Currently Valid Trap at Valid Trap at Likely reason for failure COMMENTS date TD mapped as primary secondary structural objective? objective? high?

Kimu-1 21-11- P&A: • Oil shows Hedinia, Iagifu and Barikewa Fm Yes Yes Yes Lateral seal: fault Better than expected reservoir 1998 gas L. Imburu sandstone juxtaposition of pre-Alene development; Alene only unit to seal because of cross-fault reservoir discovery • reservoirs Dry gas flow at 7.79mmscf juxtaposition. through ” choke, 29m net gas column Two and possibly three phases of oil charge suggested by GC-MS and fluid inclusion work Fresh oil from recent charge sampled (even at low reservoir temperatures) Koko-1 9-2-1999 P&A: Hedinia SS: Permian Yes No Yes Vertical seal: failure on Most of Cretaceous section Non- 57cubic feet of gas recovered, Granite Toro objective; Lateral removed by erosion: early charge commercial GWC 1047mRT (269±7Ma) seal: failure against Darai biodegraded by influx of oxic marine oil & gas L. Imb. SS mbr: Lst on thick reservoir water and low reservoir temperature discovery beds Single salinity range (hyper-saline) Dry gas and biodegraded oil recovered for inclusions indicates early charge and longevity of structure Gas Water Contact: 1164.5 mRT Kapul-1 20-12- P&A • No shows Lower Yes Yes Yes Access to charge, Prominent structure which grew 2004 Imburu probably due to lack of during Oligocene to Early Miocene, • GOI (grains containing oil carrier beds from trough clearly older than the nearby inclusions) data suggests to Kapul area Kamusi structure. presence of migrated hydrocarbons Deeper erosion at this well than nearby wells (Juha Member is below Darai) Korobos 22-10- P&A • Trace to fair oil shows Lower Upper Yes Yes Yes Timing of structure Remapping indicates well drilled ea-1 2007 Imburu and Clathrata Koi-Iange relative to charge OR only slightly downdip from crest Sandstone availability of =>therefore valid structure biodegraded oil product • Allan diagrams indicate a degree of Gas levels remaining at to provide background throughout well juxtaposition of reservoir biogenic gas sandstones but low hydrocarbon indications do not point to breached trap.

Well Spud date Status Result(s) or Shows Formation at Currently Valid Trap at Valid Trap at Likely reason for COMMENTS TD mapped as primary secondary failure structural objective? objective high? ?

Kanau 1 20-5-1975 P&A • Light yellow to yellow Triassic No No No Not on structure, drilled Well drilled a probable synrift package at green sample on gravity high. base with good source potential recognised. fluorescence, occasional Darai Plateau inversion Considerable erosion of Darai Limestone at whitish and weak golden feature likely post-dated surface (only drilled thin Darai of 497m) yellow crush cut present in charge event, which interpreted due to uplift and erosion of the Bol Sandstone and occurred at maximum plateau Late Triassic. burial, pre uplift • Scattered fluorescence also occasionally present in the Koi-Iange. Komewu-1 10-4-1957 P&A • Minor oil trace in Barikewa ?Permian No No No Not on structure: drilled • Cretaceous section missing due to and Alene Dacitic lava on gravity high faulting on KFZ: hangingwall Darai, footwall Jurassic sequence

Komewu-2 30-11-1957 P&A • Minor oil traces near Base ?Permian No No No Not on structure: drilled • Penetrated normal “hangingwall” Carbonate and in Magobu Granite on gravity high section but drilled off-structure Fm (shown by seismic which was shot post-drill)

Adiba-1 24-10-1995 P&A • Weak shows in the Toro and ?Permian Yes Yes Yes Charge (migration • Well is interpreted to have tested Koi Iange sandstones Granite shadow zone) at least a small valid closure and • Dead oil stains reported in highlights a charge volume or the Magobu timing issue in this area

Aramia 1 12–4-1955 P & A • 13 drill stem tests were Yes Yes Yes Charge • Well intepreted to be relatively conducted over several Carboniferous crestal Granite ? sandstone intervals, most • Analysis of gas recovered Test flowing brine / water – Tests No.4 from the Magobu showed C1 in the Magobu showed = 63%, C2 = 2%, Nitrogen = 32%. measurable volumes of gas Elevated Helium (1.7%) is also present.

Magobu 4-11-1970 P&A • No shows ? Permian No No No Not on structure • Drilled to Magobu Formation Island 1 Dacitic Lava • Excellent quality Magobu where thin coals are developed. sandstones with flow rates ~2000bbls water per day

2.3 Key Well Post Mortems

Three wells drilled within the study area are considered key to the study; Kimu 1, Koko 1 and Bujon 1, location shown in Figure 2.1. These wells are different from the others shown in Table 2.1 since these are the only three wells to have encountered significant oil, where ‘significant’ in this case is defined as oil volumes which are greater than oil shows ie able to be recovered either in downhole sample tools or in stained sidewall cores.

2.3.1 Kimu 1

A summary of the key geological figures relating to Kimu 1 is shown in Figure 2.2. Kimu 1 was drilled in 1999 by Oil Search Limited. The well is located on the footwall of an E-W orientated tilted fault block trap. There were no significant differences in the pre to post drill stratigraphy, however an additional reservoir was encountered with respect to the prognosis, the Lower Imburu Sandstone. The well reached total depth in the Barikewa Formation at 2270m (Schofield et al.1999)

Logs and pressure data indicated that the well had encountered a 30m gas column in the Alene Sandstone of the Lower Ieru Formation and all deeper reservoirs were water wet. The Sequential Formation Tester (SFT) – a combination pressure and sample tool, confirmed the presence of a dry gas in the Alene, and recovered water with a film of oil in the Hedinia Sandstone. An open hole straddle Drill Stem Test (DST) was performed over the gas bearing interval. During the final one hour flow period this unit flowed dry gas through a “ flow prover at a rate of 7.5 million standard cubic feet per day. The well was subsequently plugged and abandoned as a gas discovery with oil shows. Post well analysis using Allan diagrams demonstrates that Kimu 1 has a valid trap in the Alene sand, with deeper sands being juxtaposed against younger sands across the main fault (Schofield, 2000b).

The gas resource at Kimu is estimated at approximately 700bcf, quoted as upside recoverable resources (Southwell et al. 2008)

38 Figure 2.2: Kimu 1 - Well Results Summary Kimu 1

96-163-2

Chamber 1 - Water SFT #3_5 Chamber 2 - Gas Chamber 3 - Water

Chamber 2 - Water SFT #3_7 Chamber 3 - Filtrate + oil film & trace gas SFT #3_6 Water

Compiled from work by Schofield (2001), Schofield (2000c) & Schofield et al. (1999) 39

2.3.2 Koko 1

A summary of the key geological figures relating to Koko 1 is shown in Figure 2.3.

Koko 1 was drilled in 1999 by Oil Search Limited. The well was placed on the footwall of the Komewu Fault Zone near to the crest of a basement drape trap. Although thinning of the Cretaceous section had been expected in the well, it was found that significant erosion had removed a large portion of the Cretaceous section below the Darai Limestone, eroding down to the lower portion of the Alene Mudstone just above the Toro Sandstone. Several reservoirs were well developed, notably the Toro, Hedinia and Iagifu Sandstones. The well reached total depth in granitic basement at 1361m (Schofield et al.1999)

The well encountered gas in the Hedinia Sandstone (4.5m column) and oil and gas in the Lower Imburu Sandstone (5.5m gas, 2.5m oil). This result was indicated on logs, pressure data and various SFT samples. Koko 1 discovered the only oil column found to date in the Foreland. The SFT tool recovered 200mls of heavy oil with tar and asphaltenes, dry gas from the Lower Imburu Sandstone and dry gas from the Hedinia Sandstone. The well was plugged and abandoned as a non-commercial oil and gas discovery.

Post well analysis demonstrates that the Toro Formation at Koko 1 subcropped the carbonate section with hydrocarbons being encountered in the thinner sand intervals of the Hedinia Sandstone and Lower Imburu sandstone member. This is probably due to variable cross-fault seal against the carbonate section (Schofield, 2000b)

Figure 2.3: Koko 1 - Well Results Summary 40

90-94-36

‘Toro Subcrop’

SFT#4_4 / SFT#4_6 Water

Gas Column – 4.3m Oil Column – 2.5m Lower Imburu Formation

SFT #4_7 Dry gas and Water

SFT #4_4 (x2 samples) - Gas SFT #4-8 Chamber 2 - Water with 200mls heavy oil SFT #4-8 Chamber 1, SFT #4_9 - Water

Compiled from work by Schofield (2001), Schofield (2000c) & Schofield et al. (1999) 41

2.3.3 Bujon 1

A summary of the key geological figures relating to Bujon 1 is shown in Figure 2.4.

Bujon 1 was drilled in 1994 by Philips Petroleum Limited. The well was drilled near to the crest of a large regional basement drape trap and reached total depth in granitic basement at 2252m. The well encountered shows in the Toro Sandstone as well as shows in less well developed sandstones in the Barikewa and Magobu Formations. Logs and pressures indicated that the all reservoirs were water wet. However, sidewall cores from the Toro Sandstone were noted to exhibit oil staining. The saturation of oil was calculated in the lab and found to reach a maximum of 7.3%. In addition, an SFT tool sampled filtrate and 1.65 cubic feet of gas from the

Toro Sandstone, which was analysed at site to consist of only C1 and C2. Assessments of the logs over the Toro in Bujon 1 indicate the reservoir contains a 16 to 20m hydrocarbon column with low levels of hydrocarbon saturation, 5 to 9% (Taylor, 2008). This is consistent with the hydrocarbon saturation determined from sidewall cores (SWC). The pressure data indicates all reservoirs, including the Toro are water wet. The well was plugged and abandoned as a dry well with oil shows (Philips, 1994)

Bujon 1 was mapped to have been drilled on a valid depth closure (Philips 1994) but believed to have been breached by the dilation of crestal faults where a recent northwest dipping normal fault is mapped to cut through the crest of the Bujon structure, a concept supported by borehole break out data from Kimu 1 (see Figure 2.4, Schofield, 2000b).

Figure 2.4: Bujon 1 - Well Results Summary 42

92-126-01

Era Beds

Stress Field

CRESTAL FAULT BREACHED STRUCTURE Darai Limestone

1485m – SWC Recovered with 7.3% oil saturation Upper Ieru Bawia

Juha 1487m RFT recovered 1.65CF gas and 9 litres fluid (probable mud filtrate) Alene SS Toro SS Low hydrocarbon saturation calculated - Probable residual oil column Imburu Shale Hedinia - Iagifu

Koi Iange Magobu Barikewa Basement TD 2252mRT Compiled from work by Schofield (2001) Taylor 2008 & Philips (1994) 43

2.3.4 Fluid Inclusion Results

CSIRO studies on the three key wells discussed in the previous section discovered evidence for a palaeo oil charge, either in the form of palaeo oil columns or intense palaeo oil migration within a variety of reservoir sandstones (Middleton and Dutkiewicz 1999; Kreiger 1995). These findings were revealed through fluid history studies involving the Grains containing Oil Inclusions (GOI) technique.

In brief, the GOI technique is a grain counting technique developed by Eadington et al (1996). The technique is intended to develop an understanding of the oil migration record, which is recorded even in rocks that are gas or water saturated or contain residual hydrocarbons. Comparative data, developed by Eadington et al (1996) from from known producing oil zones, based primarily on Australasian oil fields, show that these zones have GOI values of 5% to 93%. In quartz reservoirs the healing of fractures due to compaction is an ongoing process that traps oil inclusions regardless of whether overgrowths are crystallising or not. This enables the identification of palaeo oil zones or evidence of significant oil migration, even if later tectonic events, water flushing or later charge events have subsequently modified the reservoired hydrocarbons.

A summary of the significant GOI results from Kimu 1, Koko 1 and Bujon 1 is shown in Table 2.2. A diagram showing the GOI pattern over the well lengths and their respective reservoirs are shown in Figure 2.5.

Table 2.2: GOI results indicating oil migration or palaeo oil columns in Bujon 1, Kimu 1 & Koko 1. Results summarised from Middleton and Dutkiewicz (1999), Kreiger (1995)

Well Depth Formation GOI% Interpreted Fluid History

Bujon 1 1474-1486m Toro Sandstone 10.3-20.7% Palaeo oil column (12-16m in height)

Kimu 1 1873-1879m Hedinia Sandstone 0.9-1.7% Intense oil migration

Koko 1 1048m Hedinia Sandstone 4.7% Palaeo oil column (>6m in height)

Koko 1 1159-1162m Lower Imburu 12-32% Palaeo oil column Sandstone (>9m in height)

Figure 2.5: GOI Results from Koko 1, Kimu 1 and Bujon 1 (from Volk et al. 2005)

Diagram showing the position of paleo oil columns (GOI>5%) in Bujon 1 and Koko 1 (Toro and Lower Imburu respectively) as well as intense oil migration (GOI =1.7%) in the Hedinia at Kimu 1.

Middleton and Dutkiewicz (1999) found that the Koko 1 well contained palaeo oil columns in the Lower Imburu and Hedinia Sandstones where current day gas, and some oil, is reservoired. The fluid inclusion results indicate that oil was accumulated when the formation fluid was hypersaline, with measurements indicating entrapment of oil in the Lower Imburu Sandstone occurring when salinity was 214,000 ppm to 235,000 ppm (defined herein as NaCl equivalent).

Krieger (1995) found that Bujon 1 well had a palaeo oil column indicated in the Toro Sandstone, the same interval over which a residual hydrocarbon column is currently interpreted. The remaining reservoirs show low GOI values of <1% consistent with the reservoirs experiencing migration under low oil

saturation. The salinity of formation waters at the time of entrapment had a wide range of values from 52,200 – 281,000 ppm.

Middleton and Dutkiewicz (1999) found that the Kimu 1 well showed no evidence of palaeo oil columns, however elevated GOI values, indicating intense oil migration was indicated in the Hedinia Sandstones. Salinity data from inclusions indicate that the gas column in the Alene Sandstone was entrapped when water salinities were 68,000 ppm NaCl. Salinity in the Hedinia Sandstones shows a minimum value of 13,800 ppm which is similar value to todays formation water indicating entrapment of inclusions continuing to trap fluids to the present day.

Note that the appearance of high salinity fluid inclusions have also been observed to occur widely across the Papuan Basin and many of the oil fields in the Papuan Foldbelt (such as Juha and Iagifu-Hedinia) have been noted to have high salinity fluid inclusions (Kreiger 1996). Kreiger (1996) points out that given the marine nature of the Toro sandstone, salinities expected are approximately 35,000 ppm. Therefore the appearance of many salinities of >120,000 ppm would suggest that fluids have dissolved evaporite lithologies. Some of the highest salinities were observed to occur in the Foreland. Salinity results show a maximum in the Omati Trough, with the North Paibuna well has a maximum paleo salinity of 343,000 ppm. Kriger (1996) suggests that this may be the source of the brine waters in the basin. Evaporites have never been drilled in the basin, however analogues exist across the border in Irian Jaya, where the Triassic Tipuna Formation consists of fluvial to aeolian environments with the presence of redbeds and possibility evaporitic carbonates may indicate deposition in playa or sabkha environments (Struckmeyer et al. 1990) and represents a possible source of hypersaline fluids if this same lithology extends into the Papuan Basin.

These fluid inclusion results form an important part of the charge history of the area and are assessed further by their organic geochemical signature (Chapter 3) and modelling the charge history (Chapter 5).

2.4 Seeps

Oil seeps in the Papuan Foreland are relatively rare which contrasts with the PNG Foldbelt where more abundant seeps are known (Kaufman et al 1994; Waples & Wulff 1996). This would appear to indicate that the region is relatively devoid of an oil charge. However, Barndollar (1993) suggests the possibility that fewer seeps are observed in the foreland because of the less intense faulting compared to the foldbelt and/or the low human population density. The seeps are an important part of understanding the oil based petroleum systems of the Foreland and hence form part of the geochemical oil families discussed in Chapter 3. The nature of the seeps are described here.

Three distinct seep areas have been reported in the Foreland and are shown in Figure 2.6. Two of these seeps have a reasonable degree of confidence concerning their nature and their location and both have been analysed by geochemical techniques. The third area of seeps concerns a series of unconfirmed gas seeps for which there are locations but minimal description and no geochemistry reported. The following discussion focuses on the two seeps which appear to be more substantiated in their nature by open file and prospectus information.

Figure 2.6 – Location of the PPL77 and Panakawa oil seeps. Gas seeps also shown.

The Panakawa Seep is located in the northern part of PPL 267 which is held by the licence holder Niugini Energy (NGE), and the following descriptions are taken from the NGE Annual Report (2006). A seep is reported at Panakawa Village and also a gas seep near to the airport. An excavator was reportedly, but accidentally used to expose the Panakawa oil seep, and revealed in a cutting as shown in Figure 2.7. A flow rate of 5 Barrels of Oil Per Day (BOPD) was measured from three seeps, which were reported to be found ~ 2.5-3m below the surface. The gas seeps, apparently found in the airport is described as “weak gas bubbling”. The NGE prospectus also mentions at least two other oil seeps, in addition to the Panakawa seep.

Review of the geochemistry of this oil is shown in Chapter 3, based on data from a comprehensive analysis by Barber (2006).

Figure 2.7: Photographs showing the surface expression of the Panakawa seep site (top left and top middle) with bottled oil from the seep shown in the top right and bottom left.

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Photos from NGE chairmans address (May 2006)

The PPL77 seep was found on seismic line PN90-103 during seismic acquisition by Chevron Overseas Petroleum during 1990 and is reported in Daly and Severson (1991). The seep is located on the footwall of the Komewu Fault, just south of the

Kamusi 1 well (as shown in Figure 2.6). The nature of the seep was described by the Chevron representative on site as an oily sheen on the surface of the swamp water which was observed after pushing a 2 m pole down into the swamp. The oil show was light and disappeared within 2-3 minutes unless the pole action was repeated. Oil odours were not detected over the normal background of swamp odours. Local inhabitants indicated that the seep was not prolific enough to produce quantities sufficient for lamps or other purposes. The seep was analysed by organic geochemical methods.

Information on the gas seeps is relatively scarce. The primary reference for the existence of these seeps and geographic locations is given in Bibilo and Haumu (1991). There are 3 gas show locations, consisting of 5 vents, recorded in the Awora River along a parallel trend. There is little description regarding the nature of the seeps but it is commented that the largest downstream seep (size 30ft x 30ft) was visited three times in a year and the intensity was always maintained. Bibilo and Haumu (1991) comment that the most likely source of the gas are numerous plant detritus in the Pleistocene and Pliocene but the possibility of Miocene limestone sourced gas cannot be ruled out. No samples were taken. These seeps will be considered with respect to a possible relationship to the oil based petroleum systems in later chapters.

3 ORGANIC GEOCHEMISTRY

3.1 Previous Geochemical Work on PNG Oils

Oil discoveries in PNG, particularly those in the foldbelt trend were examined by Chevron following the discovery of oil and gas during the late 80’s and early 1990’s. Key studies include those of Moldowan and Lee (1987), Ahmed et al. (1988) and Kaufman (1994) and they are the source of the following summary.

Light oil, condensate and gases obtained from seeps and subsurface reservoirs in PNG are genetically similar and have hydrocarbon compositions that are typically associated with generation from Type II/III to Type III kerogens. Based on the available geochemistry (and rock extract data) the source rock contains a mixture of marine and terrestrial organic matter deposited under mildly oxygenated conditions probably in an open marine to deltaic environment. The likely source rocks are of Jurassic age and show good to marginal potential and are comparable in organic facies and petroleum potential to the other Upper Jurassic source rocks present on the Northwest Shelf of Australia.

In addition to the commercial fields, (which includes the Kutubu, Gobe and SE Gobe oil fields – Figure 1.8), two other oil systems have been identified in the Papuan Basin. These include a Tertiary oil source as well as a probable Cretaceous oil source. The source intervals for these oils are unknown, but the Alene Member is suggested by Kaufman et al. (1994) as a possible Cretaceous source (see Figure 1.6).

The application of biomarkers are important to petroleum exploration, primarily because they can be used by geologists to interpret the characteristics of petroleum source rocks, which is especially valuable when only oil samples are available (Peters et al. 2005). “Biomarkers are complex organic compounds composed of carbon, hydrogen and other elements.…and show little or no change in structure from their parent organic molecules in living organisms” (Peters et al. 1995). Table 3.1 summarises the key biomarkers known to be valuable in petroleum geochemistry in addition to their geological significance. Many of these biomarkers are important to understanding oil families in Papua New Guinea. 50

Table 3.1 - Source Rock Descrimination using Biomarkers (condensed version of table. Sourced from: http://www.oiltracers.com/chatable.html) Information Ubi

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

In addition to the above biomarkers, stable carbon isotope measurements will also be mentioned throughout this thesis. Carbon isotopes are a useful way of determining genetic relationships among oils and bitumens (Peters et al. 2005) and are a common tool used in petroleum systems studies. Unless otherwise indicated, carbon isotope values or carbon isotopic data refers to the stable isotope ratio of 13C/12C. Units for this carbon isotopes ratio are given in ‘per mill’ and are expressed in parts per thousand deviation (13C) from the PDB (Pee Dee Belemnite) standard, which is equal to 0 per mill. (Peters et al. 2005)

In a comprehensive study of 137 oil, condensate and seep samples from the Papuan Basin, Waples and Wulff (1996) classified the data into five families on the basis of geochemical characteristics. The geographic distribution of these families are shown in Figure 3.1. In summary they include the following:

Family 1: Contain oleanane and bicadinine resins and have moderate* carbon isotope values (*on a scale of -21.5 = heavy to -26.9 = light)

Family 2: Contain oleanane but no bicadinanes and have moderate carbon isotope values

Family 3: No oleanane or bicadinanes and C29 steranes > C27; saturates much isotopically lighter than aromatics

Family 4: No oleanane or bicadinanes, sterane distribution highly variable, isotopic composition of saturates and aromatics more similar Figure 3.1 – Oil Families of the Papuan Basin, as proposed by 13 Waples and Wulff (1996) Carbon isotope value ( C) – Units in per mill

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Family 5: Two poorly characterised but isotopically heavy oils from the Gulf of Papua without oleanane or bicadinanes.

Subtle distinctions within each family resulted in various subfamilies (eg 4A, 2B) but these are not elaborated here. It is worth noting that Waples and Wulff (1996) do not define any oil families for the Foreland, with the exception of the Omati 1 crude which is classified into Family 3, part of the Foldbelt family of oils.

Organic geochemical information for the Foreland is available from many wells in the province. Basin scale studies, the largest by Robertson Research (1990) involved analysis of large batches of samples, mostly of rock extracts and source rock quality data (from cuttings, core and SWC) from the majority of wells in the Foreland. However, the organic geochemical data were interpreted on an individual basis and little attempt was made to compare results between wells or put them into a regional and stratigraphic context.

The most detailed studies of oils in the Foreland focused on just three wells Kimu 1, Koko 1 and Bujon 1 located on the Bosavi Arch (Figure 2.2). Work on the oils recovered from these wells includes a series of detailed studies by CSIRO examining both recovered oils, rock extracts and fluid inclusion oils (Volk et al. 2005). Additional work is also found in or reported by Boatwright (1994); Alexander (1999) and George et al. (2004).

The main conclusion from the aforementioned organic geochemical studies on the oils and fluid inclusion oils suggest that at least three different source rock facies have generated oil in this area. Summarised by Volk et al. (2005), the sources are as follows:

1) “a marine, probably Late Cretaceous or younger source rock deposited under reducing conditions is indicated by the Bujon 1 fluid inclusion (FI) oil. This source rock had a moderate contribution from higher plant organic matter, including oleanane and/or lupane. The Bujon 1 FI oil has similarities with FI oils from the Iagifu 7X and P’nyang 2X wells in the Papuan Fold Belt”

2) “an algal-dominated, lacustrine source rock is indicated by the biodegraded Koko 1 RFT [SFT] crude oil, the unbiodegraded FI oil from Koko 1, and the Bujon 1 oil stains from the Toro and Imburu formations. These lacustrine oils have high abundances of tricyclic terpanes, pregnane, homopregnane and gammacerane,

contain carotane, and have high C26/C25 tricyclic terpane ratios. The source of the lacustrine oils is inferred to contain moderate amounts of terrestrial organic matter, indicated by a dominance of C29 steranes and abundant aromatic higher plant biomarkers, and could be gypsiferous shales embedded in Oligocene-Miocene carbonates, or Triassic-age sediments deposited on igneous basement during early rifting associated with the break-up of Gondwana”

3) “The Kimu 1 FI oil was generated from a mature, marine, suboxic source rock, but has a different geochemical composition to free oil from a similar interval, which was derived from a carbonate-rich source rock”

The ECL (2005) study was the first to observe at all the results in a regional context, integrating the geochemical work by Robertson (1990), Geotech Results (Alexander 1999) as well as the CSIRO studies (Volk et al. 2005). One key finding, through the review of gas isotope data, data produced by Alexander (1999), was the recognition that the Koko 1 and Kimu 1 gases are derived from the mixing of biogenic and thermogenic gases, values of 13C of -44.9 and -48.5 per mill respectively. The biogenic component is likely derived from the degradation of oil or degradation of oil associated with wet gas. This study also recognised that numerous wells across the Foreland also appear to contain either lacustrine contributions in the oils or lacustrine organic matter within the early Jurassic, Triassic and Cretaceous sections. The significance of this on a wider scale is that the lacustrine petroleum system could extend beyond the wells located on the Bosavi Arch.

The following section seeks to integrate and extend the findings of the above studies by understanding characteristics of the known oils and comparing these to other recovered oils in the study area to create a more comprehensive set of oil families. In addition, extracts from inferred source rocks high graded by the above studies will also be examined to establish oil to source correlations.

3.2 Sample Inventory

The organic geochemical information interpreted within this chapter were obtained from reports, either reported by labs or derived from proprietary analyses by oil companies. Details on the origin for each oil analysis are shown Table 3.2 and their stratigraphic locations are shown in Figure 3.2.

Oils which were analysed in the study area are derived from four types of recovery:

1) Oil recovered in downhole pressure and sampling tools including the SFT (Sequential Formation Tester) tool 2) Oil extracted from core, SWC (Side Wall Core) or cuttings. These included both samples from reservoir lithofacies as well as source rocks 3) Oil extracted from fluid inclusions (FI) and 4) Oil from surface seeps.

Table 3.2: Summary of oil and source rock samples used in study AREA WELL NAME OIL SAMPLE TYPE DEPTH* FORMATION OR MEMBER SOURCE SOURCE ROCK Bujon 1 MCI (cuttings) 1474 Toro Sandstone George et al (1995) Bujon 1 E (swc) 1498 Toro Sandstone Boatright (1994) Bujon 1 E (swc) 1884 Koi Iange Sandstone Boatright (1994) Bujon 1 E (swc) 2075 Barikewa Formation Boatright (1994) Kanau 1 E (cuttings) 1635 Iagifu Sandstone Geotech (1996) Kanau 1 E (cuttings) 2525 Magobu Formation Robertson Research Study (1990) Kanau 1 E (core) 3476 Triassic (no formal name) Volk et al (2007) Kanau 1 E (core) 3477.7 Triassic (no formal name) Robertson Research Study (1990) Kanau 1 E (core) 3478.5 Triassic (no formal name) Robertson Research Study (1990) Kanau 1 E (cuttings) 3505-3519 Triassic (no formal name) Robertson Research Study (1990) Kimu 1 E (swc) 1617 Alene Sandstone Alexander (1999) Kimu 1 E (swc) 1651.5 Alene Sandstone Alexander (1999) Kimu 1 SFT - Rec. Oil 1873.5 Hedinia Sandstone Alexander (1999) Kimu 1 MCI (cuttings) 1873-1879 Hedinia Sandstone CSIRO (2002) Kimu 1 E (swc) 2024.5 Barikewa Formation Alexander (1999)

UPPER TURAMA RIVER Kimu 1 E (swc) 2244 Barikewa Formation Alexander (1999) Koko 1 E (cuttings) 928 Toro Sandstone Alexander (1999) Koko 1 E (cuttings) 1042 Hedinia Sandstone Alexander (1999) Koko 1 MCI (cuttings) 1162 Lower Imburu Sandstone CSIRO (2002) Koko 1 SFT - Rec. Oil 1163 Lower Imburu Sandstone CSIRO (2002) & C. Boreham (2008)** Komewu 2 E (core) 2862 Magobu Formation Geotech (2006) Korobosea 1 E (cuttings) 2069 Imburu D Member Geotech (2008) Korobosea 1 E (cuttings) 2087 Clathrata Sandstone Geotech (2008) Panakawa Seep Surface Seep NA NA Barber - Geotech (2006) PPL77 Seep Surface Seep NA NA Daly and Severson (1991)

Adiba 1 E (swc) 1374 Toro Sandstone Geotech (1996) Aramia 1 E (core) 1937 Magobu Formation Geotech (2006) Iamara 1 E (core) 1656 Magobu Formation Ahmed et al (2009) Iamara 1 E (core) 1742 Magobu Formation Ahmed et al (2009) Iamara 1 E (core) 1745 Magobu Formation Ahmed et al (2009) Magobu Island 1 MCI (cuttings) 1609-1612 Iagifu Sandstone Ruble et al (1998) Magobu Island 1 MCI (cuttings) 1646-1649 Koi Iange Sandstone Ruble et al (1998) Magobu Island 1 E (cuttings) 2382-2399 Magobu Formation Robertson Research Study (1990) FLY RIVER DELTA Magobu Island 1 E (cuttings) 2548-2551 Magobu Formation Ahmed et al (2008) Magobu Island 1 E (cuttings) 2563-2582 Magobu Formation Robertson Research Study (1990) KEY: E (cuttings / SWC) = Oil extract performed on cuttings or sidewall core SFT - Rec. Oil = Recovered oil in Sequential Formation Tester / downhole sampling tool MCI - Molecular composition of (fluid) Inclusions * Metres measured depth ** Isotopic Data - See Appendix 9.1

FIGURE 3.2 : Geographic and stratigraphic location of samples used in this study. Location of wells on Figure 2.1 55

FLY RIVER DELTA AREA UPPER TURAMA RIVER AREA

Aramia 1 Adiba 1 Iamara 1 Magobu Island 1 Koko 1 Korobosea 1 Kimu 1 Komewu 2 Bujon 1 Kanau 1 STRATIGRAPHY Alene SS 2 Toro SS Hedinia SS PPL77 Seep Iagifu SS Lwr Imburu SS Panakawa Seep Koi Iange SS Clathrata SS Barikewa Magobu 33 Triassic 4 Recovered Oil (SFT) Oil Extract Oil Extract from source rock Fluid Inclusion Oil SS = Sandstone (Coloured box indicates 1 sample taken in this formation / member, unless otherwise specified with a number) 56

Table 3.2 shows that 35 oils were investigated and that the bulk of the information available is from analysed oil extracts. Oils recovered from SFT, fluid inclusions and seeps are generally rare. The approach used was to utilise a standard summary sheet (see example in Figure 3.3) as a record to interpret each of the geochemical analyses. The resulting sheets are found in Appendix 9.2. The sheets are not exhaustive and do not capture every possible geochemical parameter. However, they are intended to summarise what is considered a series of useful geochemical parameters that has proved important to previous oil to oil and oil to source correlation studies in PNG (eg Volk et al. 2005, Moldowan and Lee ,1987).

Figure 3.3: Example of a geochemical summary sheet used to interpret the oils. The full collection is found in Appendix 9.2, complete with an abbreviation list.

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

The dataset contains oils of both fresh and biodegraded states. Comments on the degree of biodegradation refer to the Wenger et al. 2002 scale which is shown in Table 3.3. The scheme outlines the relative stability of the various classes of compounds and based on the chemical make up of the oil discussed, allocates a biodegradation rank from 1-10.

Note that for all chromatograph figures in Chapter 3, as well as the Appendix (such as the example given in in Figure 3.3) no vertical scale is given. The vertical scales for chromatographs are not considered important to interpreting the geochemical data, but it is the ‘relative response’ of each compound compared to another which gives key geochemical information. The carbon number or compounds of relevance are clearly labeled on chromatographs displayed (or at least where possible) and the vertical axis can be considered lablled as ‘relative response’.

Table 3.3 – Biodegradation Scale (Wenger et al. 2002)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

3.3 Geochemical Investigation

The objectives of this work were as follows:

1) To classify the oils into genetic families using biomarkers, aromatic hydrocarbons and carbon isotope data.

2) To establish a source rock which generated each of the oil families described.

3) To determine a likely maturity for each oil family, expressed in Vitrinite Reflectance (Vr %).

3.3.1 General Data Plots

Figures 3.4 – 3.7 show data for each of the oils in the study area. These will be used for reference to assist in the interpretation of the oil families. The data plotted are as follows: 1. Carbon Isotopic data (13C/12C - reported in per mill – parts per thousand deviation from the standard) a) Sofer plot - saturates 13C versus aromatics 13C (Figure 3.4) b) Saturates 13C versus pristane / phytane (Figure 3.5)

2. Sterane ternary plot C27-C28-C29 (Figure 3.6)

3. Tricyclics plot : C26/C25 Tricyclics versus C24/C23 Tricyclics (Figure 3.7)

FigureFigure 33.4:.4: SSoferofer PlotPlot - 13C ((Saturates)Saturates) vversusersus 13C (Aromatics)(Aromatics)

C (Aromatics) 13

13C (Saturates)

Carbon isotope cross plot for oils in the study area compared to Foldbelt oils and the Goroka Seep. The Panakawa Seep plots close to the Foldbelt-Goroka group The Koko and Kanau 1 oils appear much lighter and appear to be from a different petroleum system. When compared, the Koko 1 oil and Kanau 1 appear similar in isotopic composition, suggesting the possibility that the Triassic is the source of the Koko oil. This concept is supported by biomarker evidence (see text) 59 s to belong a different family the Foldbelt-Goroka oils .4 the Koko andKoko Kanau .4 the oils are distinct from the other oils. C (Saturates) 13 saturates. In contrast to Figure 3.4 the Panakawa seep appear milar isotopically to the Panakawa seep. Similar to Figure 3 C (Saturates) versus Pristane / Phytane 13

Figure 3.5: Pristane to Phytane (Pr / Ph) versus carbon isotope value for the based on this plot. It can be noted that the PPL77 seep, is very si 60 Figure 3.6: Sterane Ternary C 28 100% Diagram. Based 5(H),14(H),17(H)20R This ternary diagram shows that in general each oil family can be distinguished based on their relative proportion of C27-28-29 steranes 80% 20% One sample from Family O (Bujon 1) is noted to contain sterane characteristics similar to Family L 60% 40% Lacustrine (Family L) Kanau (3505-3519m) Cretaceous 40% 60% (Family O)

Koko SFT 30% - C28 Steranes

80% 20% Marine Carbonate (Family MC) Family LJ (Late Jurassic) Coal (or Kanau terrestrial) 100% Sourced

C27 0% 20% 40% 60% 80% 100% C29 Figure 3.7: Oil discrimination based on Tricyclic Terpanes (plot based on Figure 13.76 and 13.77, Peters et al. 2005

Note: Only includes oils where extended tricyclics were present in moderate to high abundance

FI Lacustrine Influenced

Iamara 1 SFT 1656m Kimu 1 1873.5m FI Kimu 1 (1651.5m) Iamara 1 1745m

Kimu 1 (FI)

Carbonate Influenced Kanau (3505-3519m) source rock extract

2.25

Oil discrimination based on tricyclic terpanes. Although this data does not provide total discrimination between the oil families, the plot is useful in dividing lacustrine versus carbonate derived or carbonate influenced oils. Family L oils plot on the NE of the diagram. Other oils plot to the left, with the Panakawa seep showing an elevated carbonate signature. The Kanau 1 61 source rock extract appears to show also show a carbonate influence 62

3.3.2 Oil Family L – Lacustrine

Oil Family L consists of seven oils from the study collection. The oils assigned to this family are shown in Table 3.4 and locations are shown on the study area map (Figure 3.8).

Table 3.4: Oils classified in Family L – Lacustrine Facies Well Oil Sample Formation Basis Biodegradation

Adiba 1 E (swc) Toro Sandstone %C28 Steranes, Gammacerane B (5-6)

Bujon 1 E (swc) Barikewa Formation 28 Steranes MB (4)

Koko 1 MCI (cuttings) Lower Imburu Sandstone %C28 Steranes, Gammacerane, Carotanes, TetPP * F

Koko 1 SFT - Rec. Oil Lower Imburu Sandstone %C28 Steranes, Gammacerane, Carotanes, TetPP * B (7)

Koko 1 E (cuttings) Toro Sandstone %C28 Steranes MB (3-5)

Koko 1 E (cuttings) Hedinia Sandstone %C28 Steranes MB (3-5) Kanau 1 E (cuttings) 3505-3519m Triassic %C28 Steranes, Gammacerane F (2-3)

# 3 Methyl hopanes F = Fresh Oil * Tetracyclic polyprenoids MB = Moderately Biodegraded B = Heavily Biodegraded

Figure 3.8: Location of oils classified into Family L

Oils in this family are found in both the Upper Turama and Fly River Delta areas (Figure 3.8). As shown in Table 3.4, most oils belonging to this family have either undergone moderate to heavy biodegradation. This was also the conclusion of previous workers based on geochemical interpretations of oil extracts from the wells Koko 1 (Alexander, 1999) and Bujon 1 (Boatright, 1994). Some examples of saturate chromatograms from this family are shown in Figure 3.9. Figure 3.9: Chromatographs for saturated hydrocarbons for oils in Family L, obtained by GC-MS

Chromatograms show the generally biodegraded nature of the oils from Family L. The exception is the Koko 1 Fluid Inclusion (FI) oil which is undegraded. Vertical scale; relative response. Horizontal scale; retention time. Source of images; Table 3.2

Oils from this family are interpreted to be have been derived from a lacustrine source rock. This comment is based on the presence of one or more of the following geochemical features:

• and carotanes are biomarkers diagnostic of lakes, (Jiang and Fowler 1986)

• Abundunt series of tricyclic terpanes, typically C19 – C26 (Aquino Neto et al. 1981)

• C26 / C25 tricyclic terpane ratio of > 1 (diagnostic of lake deposits, Scheifelbein, 1999)

• Elevated levels of gammacerane. These imply a hypersaline environment but are also known to be in high concentrations from source rocks in other environments eg carbonates (Moldowan et al. 1985)

• High level of 3 relative to 2 methylhopanes - diagnostic of input by methanotrophic bacteria (Neunlist and Rohmer, 1985; Zundel and Rohmer 1985; Summons et al. 1999) and have been found to be associated with saline lacustrine sources such as the well known Green River Formation (Collister et al. 1992).

• Tetracyclic polyprenoids (diagnostic of lake sources - Holba et al. 2000)

Since all Family L oils have been subject to biodegradation, the Koko 1 Fluid Inclusion (FI) oil has been used as the reference for oils in this group since it is unaltered and contains a collection of distinctive lacustrine biomarkers. The FI oil from Koko 1 was used by Volk et al. (2005) to demonstrate the geochemical signature of a fresh example of the biodegraded oil column found in the Lower Imburu Sandstone. Volk et al. (2005) note despite biodegradation, that the FI oil contains a very similar suite of biomarkers to the oil in the Lower Imburu. The lacustrine source affinity at Koko FI / SFT and the Bujon 1 oils have been well documented in various publications (Volk et al. 2004, George et al. 2004. Boatright, 1994) as discussed in the introduction to this chapter. Some examples of the key features of these oils are displayed on their relevant chromatographs in the following section.

Adiba 1 oil

The Adiba 1 oil was not previously recognized as belonging to the lacustrine oil family as defined in geochemical study of the foreland by Volk et al. 2005. Geotech (1996) analysed an oil extract from the Toro sandstone and showed it to contain a very similar series of biomarkers to Koko 1. Readily identifiable in this oil, despite biodegradation to level 5-6, are several of the aforementioned biomarkers indicative of lacustrine source affinity. These features include high relative amounts of C28 steranes (Figure 3.6 - isosteranes since it is degraded) elevated gammacerane, evidenced for 3 methylhopanes and C26/C25 tricyclic terpane ratio >1, which are shown in Figures 3.10 – 3.13. Biomarkers which have proved difficult to identify in the Adiba 1 oil are the presence of and carotanes, despite several spectrum diagrams produced by Geotech but which failed to adequately identify these compounds. However, despite the above regarding carotenes the other geochemical parameters above are convincing evidence for this oil being allocated to Family L.

Figure 3.10: Saturate and m/z 85 chromatograms – Koko 1 and Adiba 1 Koko 1 RFT (SFT) (top) and Fluid Inclusion Oil (bottom) Normal steranes and Pr/Ph absent Biodegraded lacustrine oil with significant UCM

Abundance Relative (unresolved complex UCM UCM mixture) Degradation level 7 (based on Wenger et al 2002) A

This held It is to included by figure/table/image comply Fresh Lacustrine Oil the

University Non waxy Abundance Relative with in the NOTE: copyright print Figures from Volk et al. 2005 of has copy Adelaide been Adiba 1 - Saturates chromatogram - 1374m regulations. of removed the Biodegraded oil with Library. Normal steranes and Pr/Ph absent thesis significant UCM

Degradation Level 5-6 (based on Wenger et al. 2002)

Retention

Time UCM Data from Adiba 1 Well Completion Report 65 (work by Geotech 1996) Figure 3.11: Comparison of Terpanes (m/z 191) – Koko 1 and Adiba 1

m/z 191 Koko 1 Fluid Inclusion Oil Abundance Relative

Abundance Relative It This held is to included by comply figure/table/image the University with in the NOTE: copyright print Figures from Volk et al. 2005 of has copy Adelaide been

m/z 191 Adiba 1 - 1374m regulations.

of Gammacerane removed the Library. thesis Abundance Relative

Data from Adiba 1 Well Completion Report 66 (work by Geotech 1996) Figure 3.12: Comparison of 3 methylhopanes – Koko 1 FI oil and Adiba 1 extract Koko 1 Fluid Inclusion Oil A

This It held is to included by figure/table/image comply the University Abundance Relative with in the NOTE: copyright print

Retention of Time has copy Figure from Volk et al. 2005 Adelaide been regulations. of removed Adiba 1 - m/z 205 showing methylhopane distribution the Library. thesis

Good evidence for presence of C32 3 methylhopanes

Data from Adiba 1 Well Completion Report (work by Geotech 1996) 67 C30 - C31 3 Methylhopane (presence unclear. Co-eluted peaks?) Figure 3.13: Comparison of Carotane – Koko 1 and Adiba 1 Koko 1 RFT (SFT) and Fluid Inclusion Oil

Retention Time Abundance Relative

A It held This is to Abundance Relative The comparison included by comply figure/table/image

the appears to demonstrate

University with

thatin and carotane are the

Figures from Volk et al. 2005 NOTE:

notcopyright present in the Adiba 1 print

Adiba 1 - m/z 125 (below) with m/z 124.8-125.8 (above) of oil extract has copy Adelaide been regulations. n-C28 of removed the Library. thesis

Carotanes not present? 68 Data from Adiba 1 Well Completion Report (work by Geotech 1996) 69

The incorporation of other oils into the same family is more difficult given the biodegraded nature of the oils. Many of these oils contain a smaller set of biomarkers than established in the Koko 1 FI oil. A combination of biodegradation, and incomplete biomarker sets reduces the ability to correlate some of the oils. For more highly biodegraded oils, one parameter which appears useful is the relative abundance of 24-methycholestanes (C28 steranes). A higher relative concentration of this sterane points to input of lacustrine algae (Huang and Meinschein, 1979). Figure

3.6 shows a sterane ternary plot for C27, C28 and C29 steranes from all oils and seeps in the study area. The lacustrine oils all contain ~30% or more C28 steranes. The sample richest in C28 steranes is the Kanau 1 (46%), a Triassic source rock extract. For several oils where distinctive biomarkers are not present, this becomes the only basis of a tie to Family L eg the Koko 1 reservoir rock extracts from Toro & Hedinia sandstones, where C28 steranes are 30% and 29% respectively.

Isotopic data in Family L oils are only available for the Koko 1 SFT sample (see Figures 3.4 and 3.5). Assuming that Koko 1 SFT oil is representative of the family, these appear to be relatively light with respect to their 13C values ie <-30 in both saturates and aromatics values. The Koko 1 oil plots in the vicinity of the Kanau 1 source extracts suggesting a possible oil to source correlation. This possibility is further discussed in section 3.3.8

Note that a series of other oils from Bujon 1 and Iamara 1 also appear to contain geochemical characteristics of Family L, but appear to be mixed oils. These are dealt with in a later section (Family X).

Source Rock Depositional Environment

Given the presence of the above biomarkers, the following can be concluded regarding the source rock that generated the Family L oils:

• The source contains lacustrine biota (a source for carotenes, C28 steranes, tetracyclic polyprenoids, extended tricyclic terpanes and C26>C25 tricyclic terpane ratio)

• The source depositional environment was suboxic. This interpretation is based on the one reliable or ‘fresh’ oil within this family derived from a FI oil at Koko 1 where the Pr/Ph value is 2. The other oils show lower Pr/Ph values, probably due to biodegradation

• The environment was hypersaline, based on the presence of gammacerane at moderate levels ~0.2 (gammacerane/C30 hopane)

Using the geochemistry of the oil, conclusions can be drawn over the style of depositional environment for this source rock. Bohacs et al. (2000) has developed a series of models for lakes. The three basin types portrayed in these studies are known as: overfilled, balanced filled and underfilled. These models have been developed by studying various types of lakes, both recent and ancient. The model developed relate to the interplay of environmental factors that are involved in generating a lake of each type. For example an environment where sediment and water input dominate over subsidence gives rise to an overfilled lake, whereas the converse (little water and sediment compared to subsidence) would produce an underfilled lake. Comparison of the geochemistry of Family L oils with this model shows that these oils show most similarity to a balanced filled lake. The geochemical characteristics of a balanced filled lake are shown in Figure 3.14. Examples of balanced filled lakes include the Laney Member of the Green River Formation in Wyoming and the Bucomazi Formation in offshore west Africa and represent some of the worlds richest source rocks (Carroll and Bohacs, 2001). Note also that the biomarker gammacerane does not appear in all oils ie the biomarker is not present in the Bujon 1 and Koko 1 extracts, but have been allocated to this lake derived family based on other data shown in Table 3.4. Further study could illuminate a sub- family within these lake oils, however this will not be undertaken here.

Figure 3.14: Typical geochemical characteristics of an overfilled lake (top) balanced filled lake (middle) and underfilled lake (bottom). Family L oils most closely match that of the balanced filled category. Figure from Bohacs (2002). A

This held It is to included by figure/table/image comply the University with in the NOTE: copyright print of has copy Adelaide been regulations. of removed the Library. thesis

3.3.3 Oil Family MC – Marine Carbonate

Oil family MC consists of three oils from the study collection. The oils assigned to this family are shown in Table 3.5 and locations are shown in Figure 3.15.

Table 3.5: Oils classified in Family MC – Marine Carbonate Well Oil Sample Formation Basis Biodegradation # Panakawa Seep Surface Seep NA C29/C30 Hopane ratio, %C27 steranes, DBT* F PPL77 Seep Surface Seep NA Minimal Data - Isotopic Tie to Pan. Seep F Kanau 1 E (core 3476m) Triassic C29/C30 Hopane ratio, %C27 steranes, ADBT* F * (alkyl) dibenzothiophene F = Fresh Oil

Figure 3.15: Map showing the location of oils grouped into Family MC

A list of key characteristics for oils in this family include:

• C29/C30 Hopane ratio > 1 (carbonate source rock, ten Haven et al. 1988). This feature was also identified by Alexander (1999) in extracted oils from Kimu 1 and forms some of the later discussion on Family X (mixed oils)

• Relatively low levels of steranes and diasteranes (characteristic of carbonate sourced oils. Hughes, 1984)

Figure 3.16: Chromatographs for saturated hydrocarbons for oils in Family MC, obtained by GC-MS

Chromatograms show the relatively fresh nature of oils from Family MC. Vertical scale; relative response. Horizontal scale; retention time. Source of images; Table 3.2

• Dominance of cholestanes (C27 steranes) pertaining to ~50% of steranes demonstrating significant input of marine organic matter (Huang and Meinschein, 1979) (Figure 3.6)

• Pr/Ph ratio of 1-1.5, indicative of an anoxic to suboxic source rock (Didyk et al. 1978)

• Saturate 13C values of approximately -27 per mil

Barber (2006) reports that despite a slight UCM present in the Panakawa seep (shown in Figure 3.16) any alteration appears to be relatively minor. This comment was based on inspection of the alkane distribution and analysis of the napthalenes. The PPL77 seep appears to have a similar chromatogram to the Panakawa seep (Figure 3.16) and the similarity of these oils is also supported by isotopic and Pr/Ph plot (Figure 3.5).

The carbonate “influence” in these oils was also assessed by distribution of tricyclic terpanes in the oils. Peters et al. (2005) demonstrated the use of tricyclic ratios in discriminating carbonate as well as lacustrine oils where global datasets show that carbonate oils have low C24/C23 and C26/C25 ratios. Lacustrine oils show the opposite relationship. Using this knowledge, Figure 3.7 shows a plot of C26/C25 to C24/C23 tricyclics for all oils in the study region. In a gross sense there is a distinct relationship

74 shown by oils in the plot, with those of marine carbonate affinity plotting in the bottom left of the diagram and oils of lacustrine affinity clearly plot to the upper right, capturing all samples that are considered part of Family L. On this basis the Panakawa seep is clearly derived from a carbonate source rock.

Elevated levels of dibenzothiophenes (DBT) in some oils of this family are also consistent with their derivation from carbonate source. Figure 3.17 (after Hughes et al. 1985) shows a representation of the DBT levels relative to phenanthrene plotted versus Pr/Ph ratio for oils in the Kimu well, in addition to the Kanau source rock extract and Panakawa seep.

Figure 3.17: Pristane to Phytane versus Dibenzothiophene/Phentanthrene for Kimu 1 extracts and oils from Family MC

Kimu 1 - 1873.5m

Classifications by Hughes et al. 1985. Plot by Barber (2006) with additions for this study The plot shows that although the Panakawa seep does not reach the threshold for a carbonate source rock, it is much higher than that of the other oils as most of the other oils, including the source rock extract show very low levels of DBT. Interestingly, the oil from 1873.5m is interpreted to be a mixed family MC oil shown to demonstrate an elevated DBT/Phenanthrene ratio relative to the other extracts.

Barber (2006) claims that the Panakawa seep oil contains insufficient DBT to be of carbonate origin, tending to suggest the source is marine to lacustrine derived shown in Figure 3.17. Considering the DBT related evidence presented above, and the C29/C30 hopane ratio, a carbonate source is still interpreted here but perhaps a more argillaceous source giving rise to a lower sulfur oil. Preston (2007) also argues for a source rock of sulfate-poor carbonate affinity.

Isotopic data is available for the two oil seeps. The seeps have a saturate 13C value of -27.7 to -27.3 per mil.

Source Rock Depositional Environment

Oils from this family are interpreted to be have been derived from a marine- carbonate source rock. This conclusion is based on several features including the

C29/C30 ratio, dominance of marine derived steranes, the generally low level of steranes / diasteranes as well as the elevated DBT in at least some oils in this family. The low level of DBT in the Kanau 1 source extract, despite having carbonate characteristics appears to have very low DBT. Comparison of various oils types in a study by Grande et al. (1993) show that marine carbonate oils also contain a high relative abundance of tricyclic terpanes. The presence of these compounds, particularly evident in the Panakawa Seep, is indicative of a depositional environment of moderately elevated salinity.

Figure 3.4 shows that the Panakawa oil is heavier isotopically than those in family L and Triassic source rock oils, but plot near or close to the Foldbelt oils. Figure 3.5 shows that the two seep oils are similar with respect to their isotopic composition and Pr/Ph ratio which is the primary basis for the inclusion of the PPL77 oil in this family. The plot also differentiates these oils from the foldbelt collection, showing that their source rock was deposited in a less oxic depositional environment. Hence, despite an initial similarity with the foldbelt the geochemistry of these two oils is quite different hence it is argued that it is quite unlikely to be derived from the same source rock. The foldbelt oils are known to be generated from an argillaceous marine source rock that contains significant terrestrial organic matter. Other carbonate sourced oils previous known include those that belong to Family O (next section) and include those described by George et al. (1995) from FI oil at Bujon 1. However, a distinguishing characteristic of these oils is the presence of oleanane and/or other angiosperm biomarkers, which are not present in oils of Family MC. The source rock extract from the Triassic at Kanau 1 (3476m) poses a possible source rock, given similarities to the seep oil including C29/C30 ratio and predominance of C27 steranes. Evidence against this however would be the low level of DBT/Phenanthrene in this extract (Figure 3.17) as well as the lack of isotopic similarity. Further discussion of a likely source rock, including a possible Triassic source for these oils will found in a later section (3.3.8).

3.3.4 Oil Family LJ – Late Jurassic Foldbelt Type

Oil family LJ consists of seven oils from the study collection. The oils belonging to this family are shown in the table 3.6 and their locations are shown on Figure 3.18.

Table 3.6: Oil classified into Family LJ Well Oil Sample Formation Basis Biodegradation # Kanau 1 E (cuttings) Iagifu Sandstone Poor tie, Steranes F Kanau 1 E (P-cuttings) Magobu Formation Steranes, Terrestrial Triterpanes F Kimu 1 E (swc) 2024.5m Barikewa Formation Pr/Phy, Steranes F Kimu 1 E (swc) 2244.0m Barikewa Formation Pr/Phy, Steranes F Korobosea 1 E (cuttings) Imburu D Pr/Phy, Terrestrial Triterpanes F* Korobosea 1 E (cuttings) Clathrata Sandstone Steranes, Terrestrial Triterpanes F* Magobu Island 1E (cuttings) 2390m Magobu Formation Similar to Family C, Ts/Tm value relative to maturity F F = Fresh Oil

*Contamination appears to have introduced a UCM hump, but 25 norhopane level suggests very light biodegradation

Figure 3.18: Map showing the location of oils grouped into Family LJ

The distinguishing characteristics of this family include one or more of the following:

• A variable proportion of marine & terrestrial organic matter but appears to

consist dominantly of terrestrial organic matter – (C29>C27 steranes, as shown on Figure 3.6)

• Presence of the biomarker diahopane, occasionally with other terrestrial triterpanes

• Prominent diasteranes

• Low maturity - 0.45 to 0.61 Vr %

Oils in this family contain little or no oil degradation. Figure 3.19 demonstrates a collection of representative saturate plots for oils in this family. Figure 3.19: Chromatographs for saturated hydrocarbons for oils in Family LJ, obtained by GC-MS

Chromatograms showing the relatively undegraded nature of oils from Family LJ.

Oils are waxy with a predominance of >nC22 (with the exception of Kanau 1 - 1635m). Vertical scale; relative response. Horizontal scale; retention time. Source of images see Table 3 2 A distinctive feature of many of these oils is the waxy nature of the saturate portion. These can be seen in Figure 3.19 where the predominant saturate fraction is >C22. This is consistent with the dominance of C29 steranes. As Figure 3.19 the obvious exception is the Kanau 1 oil (1635m) where although waxy alkanes are present up to C31 the maxima of the chromatograph is at

C13-C14. As noted in table 3.6, as well as shown in Figure 3.19, a prominent hump exists at the front of the chromatogram in the Korobosea 1 oil extracts (2069 and 2087m). However, this appears to be related to drilling mud contamination (C. Barber, pers comm., 2008). This appears consistent with the very low levels of 25- norhopanes, where relative high concentration of these compounds is normally indicative of biodegradation (Peters et al.1996). In contrast to oils of the foldbelt, the Pr/Ph value from oils of this family is highly variable, 1.1 – 4.7, but typically a value of ~2 - 3. Figure 3.20 demonstrates the similarity of the triterpanes in an example oil from this family and a typical oil from the Kutubu field in the PNG Foldbelt.

Figure 3.20: Triterpane distribution of a typical Foldbelt oil, showing a similar triterpane pattern to Kanau 1 oil (2525m). Both Figures from Robertson Research (1990) with annotations added.

Figure 3.20 above shows a very similar distribution of biomarkers is visible in the Kanau 1 oil compared to that of the foldbelt. A distinctive characteristic of foldbelt oils is the presence of the biomarker diahopane. Previous studies have drawn a correlation of this feature as a possible terrigenous marker due to its presence in coals and non-marine oils (Philp and Gilbert, 1986; Volkman et al. 1983). Diahopane was first identified in PNG oils by Moldowan & Lee (1987) who recognized peaks X Y and Z (Diahopane) as Figure 3.20, which are terrestrial triterpanes, the authors recognising these biomarkers as distinctive features of many PNG foldbelt oils. Also evident on Figure 3.20 is the high relative abundance enhanced level of

79 moretanes in the Kanau 1 oil compared to the Iagifu 3X oil. This feature is consistent with the relatively low maturity level for this oil, which is calculated at 0.61 Vr %, using steranes (see later discussion in 3.3.9). The foldbelt oils are known to be generated in the late oil window with maturities of ~0.9 Vr (Kaufman et al.1994). Moretanes are also observed as prominent features of the other oils in this family indicative of low maturity.

Carbon isotopic data for oils in this family is not available. However, it would be expected that the data would plot in the Foldbelt area on Figure 3.4, and have a saturate 13C value of approximately -25 to -27.

Source Rock Depositional Environment

Oils from this family are interpreted to be have been derived from a source rock not dissimilar from those that generated the oils in the Foldbelt. This comment is based on the presence of several key characteristics of Foldbelt oils which are reported in previous studies, including Waples and Wulff (1996) and Moldowan & Lee (1987). The biomarkers concerned include diahopane + other terrestrial triterpanes, a mixture of marine and terrestrial steranes as well as the waxy nature of this oils. A possible interpretation of the consistently low maturity values (~0.5-0.6 Vr) from this family is that the oils have been generated in place. This would be consistent with the low Ts/Tm values in these oils of ~0.4 or less. The exception appears to be the Kanau 1 2525m oil which shows a Ts/Tm of 0.86 despite a low maturity of 0.61% (based on steranes). The maturity of this oil may indeed be higher than calculated since steranes have been shown in section 3.3.8 to be a somewhat mediocre estimate of thermal maturity. However, the presence of Moretanes as Figure 3.20 would tend to dismiss this.

Foldbelt oils are considered to be geochemically similar to those from the NW Shelf, containing biomarker characteristics analogous to oils of the Australian North West Shelf (Westralian Supersystem), consistent with generation from Mesozoic land- plant-derived organic matter deposited in a marine environment. (Winn et al. 1994, Bradshaw et al. 1997). The depositional environment of the source rocks for Family LJ appear to vary widely in their oxicity, a comment based on the variability of the Pr/Ph ratio (~1-2). This probably reflects the variability in marine to terrestrial organic matter input. Significant terrestrial input is also suggested by the dominance of the

C29 steranes presence of diahopane and unidentified terrestrial triterpanes.

3.3.5 Oil Family O – Cretaceous

Oil family O consists of four oils from the study collection, which all constitute oils analysed from fluid inclusions by the MCI technique (Molecular Composition of Inclusions). The oils classified to this family are shown in Table 3.7 and locations are shown on the study area map in Figure 3.21.

Table 3.7: Oil classified into Family O Well Oil Sample Formation Basis Biodegradation Level

Magobu Island 1MCI (cuttings) Iagifu Sandstone C29/C30Hopane ratio, Oleanane F

Magobu Island 1MCI (cuttings) Koi Iange SandstoneC29/C30Hopane ratio, Oleanane F

Bujon 1 MCI (cuttings) Toro Sandstone C29/C30Hopane ratio, Oleanane MF Kimu 1 MCI (cuttings) Hedinia Sandstone Minimal data - tie using basic data, saturate distribution, 28-BN F

F = Fresh Oil 28-BNH = 28 Bisnorhopane MF = Moderately Fresh

Figure 3.21: Map showing the location of oils grouped into Family O

The saturates chromatograms for the various oils in this family are shown in Figure

3.22. Figure 3.22 – Chromatographs for saturated hydrocarbons for oils in Family O, obtained by GC-MS

Chromatographs showing relatively light, unwaxy and unbiodegraded nature of Family O oils. The exception is the Bujon 1 oil (Toro) which shows a pronounced UCM hump indicating the oil is biodegraded, in addition to a

predominance of >C22, hence a waxy oil. Vertical scale; relative response. Horizontal scale; retention time. For source of images, see Table 3.2 Due to the fluid inclusion nature of these oils, which results in low oil yields, only limited data is only available for these oils. As can be seen in Figure 3.22 the saturates chromatograph for the four oils shown appear similar in shape, particularly the Kimu 1 and Magobu Island 1 oils where the saturate distribution can be observed to reach a maxima around C16. The Bujon 1 saturate trace appears different, demonstrating a predominance of carbons >C22 and hence a waxy oil. In addition the Bujon 1 saturate chromatograph contains a UCM hump indicating biodegradation.

One or more of the following oil characteristics, are common to this family:

• Presence of oleanane – indicates a Late Cretaceous to Tertiary age source rock containing organic matter from angiosperms (Moldowan et al. 1994)

• High C29 / C30 hopane ratio > 1 – indicates a carbonate source rock (ten Haven et al. 1988)

• Low Pr / Ph values (1.05 - 1.7)

• Presence of 28,30 bisnorhopane - used in correlation but are also probable bacterial markers associated with anoxic depositional environments. (Peters et al. 2005)

Magobu Island 1 oil also exhibits the presence of 1,2,7 trimethylnapthalenes (TMN’s) which can be used as a marker for angiosperm input (Strachan et al. 1988). Furthermore, Ruble et al. (1998) points out that the ratio of 1,2,7-TMN relative to 1,3,7-TMN, which is a geological age indicator, is well above the threshold levels in for a Cretaceous or younger source rock. This information is consistent with the possible presence of oleanane whose age implications together indicate a source rock of Late Cretaceous or Tertiary age (Ruble et al. 1998).

Steranes appear to show variability in these oils. When compared, (see Figure 3.6) Bujon 1 and Magobu Island 1 (1609-1612m) oils, the former shows a more terrestrial organic matter and plots closer to the Family L oils. The Magobu Island 1 oil contains more marine organic matter.

Source Rock Interpretation

Oils from this family are interpreted to have been derived from a carbonate source rock of Late Cretaceous to Tertiary age. This comment is based on the presence of the biomarker oleanane in all oils and is further reinforced by the 1,2,7 TMN to 1,3,7 TMN in the Magobu Island 1 (1609-1612m) oils which collectively indicate an angiosperm source input. Similar to Family MC, these fluid inclusion oils exhibit a carbonate signature as indicated by the C29 / C30 hopane >1 ratios (ten Haven et al. 1988). In Family MC this was also accompanied by elevated levels of marine organic matter eg C27 steranes, however, although this appears dominant for the 1609- 1612m, terrestrial organic matter is dominant in the Bujon 1 oil. The Bujon oil is also noted to be waxy. Hence there appears to be several aspects which appear somewhat different to the other oils in this family. The sterane plot (Figure 3.6) indicates that the Bujon 1 oil has a possible lacustrine affinity. At the present stage, the oils are incorporated together, however it is recognised that the Bujon 1 may represent a somewhat different source facies to the other oils in this family.

A study of fluid inclusion geochemistry in the PNG foldbelt identified an oil family not unlike the oils encorporated under Family O. George et al. (1997) described a series of oils recovered from DST’s in Iagifu 7X , viewed as traditional foldbelt oils, and compared the oil geochemistry to that of the oils trapped in fluid inclusions within the same interval. The results showed that the fluid inclusion oils were derived from a less terrestrially influenced marine source rock deposited under less oxic conditions. These oils also contained the biomarker oleanane, as well as 1,2,7 TMN with a maturity of ~1 Vr %.

Age indicators in the oils point to a carbonate source rock which is Late Cretaceous to Tertiary in age. Two possibilities exist as source candiates for this oil: either a source bed from the Darai Limestone or alternatively a Late Cretaceous limestone belonging to the Upper Ieru. Later discussions in Chapter 4 discuss various reasons to dismiss the Darai Limestone as a source rock. In the study area limestones in the Late Cretaceous are not known. The Chronostratigraphy chart (Figure 1.6) shows Late Cretaceous limestones of Campanian age associated with the Pale Sandstone. The unit outcrops in the East Papuan Basin and was described in detail by Boult and Carman (1993). Inspection of the literature shows that this limestone represents portions of the sandstone which contain significant calcareous cement or carbonate cemented bands, probably sourced from shelly material within the framework of the sandstones (Barclay 2002; Philips, 1990 cited in Boult and Carman, 1993). These appear to represent calcareous sandstones rather than limestone stringers. No other limestones of this age are known in the Papuan Basin, however this does not discount the possibility that limestones lithologies may still exist in the unit but have simply not been identified in wells or may have been subsequently eroded at the Late Cretaceous unconformity with no record of them within existing wells.

3.3.6 Oil Family C – Coal Sourced

Oil family C consists of seven oils from the study collection, two of which are source rock extracts from coals. The oils classified in this family are shown in Table 3.8 and locations are shown on the study area map (Figure 3.23).

Table 3.8: Oil classified into Family C Well Oil Sample Formation Basis Biodegradation Level

Aramia 1 E (core - source extract) Magobu Formation High %C29 Steranes, very low Ts/Tm ratio F

Komewu 2 E (core - source extract) Magobu Formation High %C29 Steranes, very low Ts/Tm ratio F Iamara 1 E (core) 1742m Magobu Formation High %C29 Steranes, very low Ts/Tm ratio F Iamara 1 E (core) 1745m Magobu Formation High %C29 Steranes, very low Ts/Tm ratio F

Magobu Island 1 E (cuttings) 2563-2582m Magobu Formation High %C29 Steranes, very low Ts/Tm ratio F

Magobu Island 1 E (cuttings) 2548-2551m Magobu Formation High %C29 Steranes, very low Ts/Tm ratio F F = Fresh Oil

Figure 3.23: Map showing the location of oils grouped into Family C

Oils from this family consist of oil extracts and two source rock extracts, all of which were taken from the Magobu Formation. Oils from Family C consist of the following geochemical characteristics:

• No evidence of biodegradation

• High Pr/Ph of >3, indicating an oxic source rock. (Didyk et al. 1978)

• Elevated C29 steranes of 60-80%, indicating significant input of terrestrial organic matter (Huang and Meinschein, 1979) – Figure 3.6

• Low Ts/Tm values 0.03 to 0.12. Indicative of low clay source or alternatively low maturity (McKirdy et al. 1984).

• Oils produced appear waxy (carbons predominantly >C22), although some oils

also show a narrow but tall peak around C16

• CPI-1 (Carbon Preference Index) values of 1.2 – 1.8

• Minor C30 diahopane

Saturate chromatographs from 4 representative oils from Family C are shown below:

Figure 3.24: Chromatographs for saturated hydrocarbons for oils in Family C, obtained by GC-MS

Source Rock Interpretation

Chromatograms showing the relatively undegraded and waxy nature of oils from Family C. Vertical scale; relative response. Horizontal scale; retention time. For source of images, see Table 3.2

The aforemtentioned characteristics are all consistent with derivation of an oil from a coaly source rock. Two of the oil extracts are taken directly from coal source rocks. These were recovered from wells Aramia 1 and Komewu 2 and have the following characteristics:

• High oxicity of the depositional environment (Pr/Ph ~6)

• High relative abudance of C29 steranes

• Presence of C30 diahopane

Similarities between the source rock extracts as well as the Iamara 1 and Magobu Island 1 oils allows a basis for tying these oils to Family C (Table 3.8)

Some distinct similarities of this family to Family LJ is noted, particularly the mixed nature of the source, ie, elevated C29 steranes with C30 diahopane present. It is also noted that diasteranes are present in most oils of this family, also known to be present in Family LJ oils. Note that the abundance of diasteranes implies that there is some clay within the source rock (Van Kaam-Peters et al. 1998) which may imply that the coals contain at least some clay rich portions.

Some oils in this family contained limited data to confidently group to Family C. The

Magobu Island 1 oil (2563-2582m) sample contains negligible amounts of C27 steranes ie no measured marine algae and >80% C29 steranes. Also a Ts/Tm value was low, despite a maturity of 0.61%. In the absence of other data this oil was allocated to Family C.

A comparable extract based on saturate distribution is a shallower extract from

Magobu Island 1 (2390m). This oil also contains an abundance of C29 steranes and the presence of diahopane. However, several features tend to indicate a less coaly, more clay rich unit is involved including the low Pr/Ph and higher Ts/Tm value (Didyck et al. 1978., McKirdy et al. 1984). This oil was allocated to Family LJ (see 3.3.4).

3.3.7 Oil Family X – Mixed Family Oils

Overview

Four oils from extracts and one SFT sample, listed in Table 3.9, exhibit evidence of containing a mixture of oils from two families. Identification of mixed oils has been identified through two geochemical characteristics; either the oil appears be a mix of biodegraded and fresh oils consisting of the same or different families or alternatively the oil contains a collection of biomarkers which belong to different families. The spatial distribution of oils are shown in Figure 3.25.

Figure 3.25: Location of oils classified into Family X

TABLE 3.9 - Oils recognised as containing oils from two families (Mixed oil family) 88 Well Oil Sample Formation Family 1 Basis Family 2 Basis

Bujon 1 E (swc) Toro Sandstone Lacustrine / Carotanes, %C28 Steranes Lacustrine Waxy n-alkanes overprint a UCM. C26/C25 ratio

Bujon 1 E (swc) Koi Iange Sandstone Lacustrine / Carotanes, %C28 Steranes Lacustrine Waxy n-alkanes overprint a UCM. C26/C25 ratio Iamara 1 E (core) 1656m Magobu Formation Lacustrine C26/C25 Tricyclic Terpanes %C28 Steranes, 3 MH* Family O Oleanane, 24 norcholestane, 1,2,5 TMN, 1,2,7 TMN

Kimu 1 E (swc) Alene Sandstone (1651.5m) Biodegraded UCM prominent - Family unclear Marine Carbonate C29/C30 Hopane ratio, %C27 steranes

Kimu 1 SFT - Rec. Oil Hedinia Sandstone (1873.5m) Marine Carbonate C29/C30 Hopane ratio, %C27 steranes Biodegraded UCM present , Family unclear * 3 Methyl hopanes UCM = Unresolved complex mixture (normally indicative of biodegradation)

TMN = Tri Methyl Napthalenes

Figure 3.26: Chromatographs for saturated hydrocarbons for oils in Family X, obtained by GC-MS (for source of images see Table 3.2) Vertical scale is 'relative response'. Horizontal scale is 'Retention Time'

Bujon 1 1498m - Toro Sandstone Bujon 1 - 1884m - Koi Iange

C25 Fresh n-alkanes C25 Fresh n-alkanes overprinting UCM overprinting UCM (C16 - C35) Ph C22 (C17 - C36) Pr Ph C22 C30 C20 C35 Pr C30 C20

Moderate-Major UCM UCM

Kimu 1: 1873.5m - Hedinia Sandstone Kimu 1: 1651.5m - Alene Sandstone

C22 Fresh n-alkanes C22 Fresh n-alkanes overprinting UCM overprinting UCM C25 (C14-C27) (C12-C29) C18 Pr Ph

Ph C17 Pr C17

Major C12 UCM UCM (minor)

Iamara 1 - 1656m - Magobu

Chromatograms showing the mixed nature of oils classified into Family X. All oils show a UCM which is overprinted by fresh n-alkanes. The UCM hump is only relatively minor in the C16 Fresh n-alkanes Kimu 1 (1651.5m) as well as Iamara 1 (1656m) Pr overprinting UCM (C14-C31)

C10 C22 C30

Minor UCM 89

A short description follows for each oil by well, outlining the rationale and significance of each mixed oil. The identification of mixed oils is important to this study as it assists in understanding the charge history which can be used to constrain the basin modeling results.

Kimu 1

Oils from Kimu 1 (1651.5m, 1873.5m) obtained from the Alene Sandstone and Hedinia Sandstone respectively, are interpreted to be mixed oils. This comment is based on the saturate chromatographs (Figure 3.26). Observed in the graph for both oils is a large UCM in the baseline consistent with heavy biodegradation, although this hump is more pronounced in the Alene Sandstone oil compared to the Hedinia

Sandstone oil. An n-alkane overprint occurs containing carbons from C12 to C30 and maxima just beyond C22. These n-alkanes should not be present, based on Table 3.3, given the greater degree of degradation experienced shown by the UCM as well as 25-norhopanes. Both oils are hence interpreted as a degraded oil mixed with a fresh oil. Alexander (1999) concluded similarly, interpreting that the Alene oil is believed to be mix of severely biodegraded oil and a slightly biodegraded crude whereas the Hedinia oil was believed to be generally unbiodegraded with a minor contribution from severely biodegraded oil.

Geochemical features of these oils include C29/C30 hopane ratio >1 and dominance of C27 steranes (as Figure 3.6). Tricyclic terpane distribution for the oil at 1651.5m (see Figure 3.7) demonstrates a carbonate influence whereas the Hedinia oil lies in the midrange between lacustrine and carbonate influenced.

As indicated by Alexander (1999, page 11) with regards to the Kimu 1 oil extracts: “The presence of n-alkanes in reservoirs with current temperatures below 650C is unusual. The biodegradation process must have ceased for reasons other than the current temperature or the introduction of the n-alkane components [which] occurred very recently”. Another oil extract in the Alene Sandstone (1617m - Appendix 9.2.7) has not been allocated to a family and is highly biodegraded with no n-alkane overprint. The oil shows a mix of both marine and terrestrial steranes. (C27, C29 respectively). This oil is assumed to be the biodegraded portion of the Alene and Hedinia oils. The geochemical parameters comparing the three oils is shown in Table 3.10.

Table 3.10: Comparison of several key parameters for mixed and unmixed oils found at Kimu 1. The 1617m oil (grey) is the reference of ‘unmixed’ but biodegraded oil. Kimu 1 oils Steranes% (C :C :C ) Pr / Ph C /C Hopane Ts/Tm 27 28 29 29 30 1617m 32:24:44 - 0.88 1.49

1651.5m 37:22:41 0.86 1.15 1.2

1873.5m 42:27:31 2.09 1.12 0.86

A comparison of the Alene (1617m) oil to the two oils from Family X, shows the value of marine steranes or C27 has increased and as well as an increase in the C29 /

C30 hopane ratio and decrease in the Ts/Tm ratio. Comparison of these parameters between the biodegraded oil and the mixed oil is interpreted to indicate that the input oil was from a Family MC oil. This theory is further supported by Figure 3.17 where the oil with the greatest amount of fresh oil (1873.5m) contains an elevated DBT/Phenanthrene ratio relative to the other Kimu 1 extracts. Figure 3.7 also shows that the 1651.5m oil plots significantly toward the bottom left of the diagram indicating a strong carbonate influence (Peters et al. 2005)

Bujon 1

Mixed oils from Bujon 1 in the Toro and Koi-Iange Sandstones (1498m, 1884m respectively), contain mixed oils based on the saturates distributions (Figure 3.26). Observed in the chromatogram for both oils is a large UCM in the baseline consistent with heavy biodegradation, combined with an overprint of n-alkanes. The overprint is a waxy oil, with n-alkanes ranging from C16 to at least C35. These n- alkanes should not be present, similar to the above description of Kimu 1, based on the size of the UCM, and hence a degraded oil mixed with a fresh oil is interpreted. Organic geochemistry shows this oil to contain and carotenes as well as a

C26/C25 tricyclic terpane ratio >1. These extracts hence contain at least some contribution from Family L oil. The biodegradation level of the first oil, although complicated by the overprint can be estimated by inspecting the oil extract from the Barikewa (2075m), which demonstrates biodegradation to level 5 and also contains the above lake characteristics. This is also consistent with the conclusions of Boatright (1994) who also concluded biodegradation in the oils extracted from the Koi-Iange and Barikewa, however for the Toro sandstone, the oil was interpreted to be fairly fresh (level 2 or less). This study disagrees with this interpretation, based on the intensity of the UCM hump in the baseline with similarity to the Barikewa oil from Bujon 1 where no n-alkanes are present. Hence a mixed oil is deemed more likely.

Based on the available evidence, biodegradation of a Family L oil probably occurred first in the reservoirs followed by a later overprint. The overprint of waxy oil could constitute an oil charge from one of three possible families:

1. Family C or Family LJ based on the waxy nature of the overprint. Waxy oils

(those with carbons >C22) are known within these families

2. Recharge by Family L oil. Although discussions earlier on Family L oil does not show these oils to be waxy, the Family L type example oil – Koko 1 FI oil, shows the presence of waxy long chain n-alkanes up to C33. Katz (1990) states that the principal difference in bulk geochemistry between a marine oil and a lacustrine oil is that a lake typically generates a high wax crude (ie oils containing a predominance of alkane chains > C22).

To determine the oil family for the likely fresh oil, a comparison of geochemical parameters from the unmixed oil and the Family X oils are shown in Table 3.11.

Table 3.11: Comparison of several key parameters for mixed and unmixed oils found at Bujon 1. Oil at 2075m is the unmixed but biodegraded reference oil Bujon 1 oils Steranes% (C :C :C ) Pr / Ph C /C Hopane Ts/Tm 27 28 29 29 30 1498m 27:30:43 1.5 0.79 1.29

1884m 19:38:43 0.7 0.65 2.27

2075m 15:40:45 - 0.51 1.92

Inspection of Table 3.10 shows that the sterane distributions between the reference and the 1884m oil is similar despite a mixed oil interpreted from the chromatogram. The Toro oil (1498m) shows a marked difference to the other oils, with a higher proportion of marine steranes (C27) and slightly higher oxicity (Pr/Ph=1.5) and lower

Ts/Tm. None of these oils indicates a carbonate influence, indicated by C29/C30 all <1 (ten Haven et al. 1988). Inspection of Figure 3.7 shows that the position of these oils is similar, all remaining in the lacustrine influenced area, with no shift to the lower left. This observation, coupled with the persistence of the C29/C30 ratio appears to indicate that the overprinting oil at Bujon 1 is not the same as that at Kimu 1. The most likely interpretation, based on the data here is that the overprint is a second pulse of Family L oil. This comment is based on the lack of Family MC evidence as well as the relative abundance of C29 steranes which would be expected to increase if the input was from Family C or LJ.

Iamara 1

The extract from a sandstone within the Magobu, obtained from core at 1656m appears to exhibit a mixed oil signature. The saturate chromatogram shown in Figure 3.26 shows a very slight UCM in the baseline consistent with input of at least some biodegraded oil. Ahmed et al. (2008) points out that this oil shows characteristics of mixed biodegraded residues with some freshly charged oil, but that the biodegradation level is at a moderate level, based on the reduction of some of the n-alkanes and also the absence of any 25-norhopanes which would indicate heavy biodegradation.

This oil contains a mix of biomarker and other geochemical characteristics that belong to two distinct oil families which have been described previously. These include:

1. Family L characteristic including:

• Elevated C28 steranes (29%).

• Tricyclic terpanes C26/C25 ratio (1.28) and enhanced levels of tricyclics from

C19-26

• Presence of 3 methylhopanes

2. Family O characteristics. These include the presence of:

• Oleanane

• 1,2,5 & 1,2,7 TMN

An additional series of compounds, not identified in other Family O oils provides additional evidence for the age of the source rock. Ahmed et al. (2008) indicate that this oil contains high abundances of 24-norcholestane and 24-nordiacholestane, which are more abundant in Cretaceous and Tertiary rocks. These features are also consistent with the presence of oleanane in the oil indicating a Late Cretaceous to Tertiary source. Other features that can be compared include Pr/Ph values, 2.1 for this oil, are similar to both these families. Peak maximas shown on the saturate chromatographs appear to reach similar values to both Family L and O, at ~C16

93 position and hence comparison of other features to either of the two parent families does not indicate which oil is the dominant contributor to this oil extract.

The charge history is most likely explained by a mixture of Family L and Family O oil charge. Study of Family L has shown these oils are commonly biodegraded in the study area, and hence is the possible contribution of the moderate biodegradation. However, evidence does not exclude contribution of a biodegraded Family O oil with a fresh Family L. There is insufficient data to discern the actual pattern of charge and biodegradation in this oil. Although the possibility for a Late Cretaceous to Tertiary lacustrine source rock (ie a single oil charge) is a possibility, this is considered unlikely given the common occurrence of lake oils across the study area which never contain oleanane. Hence a mixed oil interpretation is suggested.

Summary of Results

In summary, the following oil groups have been demonstrated

• Kimu 1 – Alene and Hedinia: biodegraded oil + recharge by Family MC oil

• Bujon 1 – Toro and Koi Iange sands - biodegraded Family L, recharge by Family L oil

• Iamara 1 - Family L + Family O (moderate biodegradation)

Through the use of basin modeling (Chapter 5) the charge history of the region from recognised source rocks can be tested and used to identify the probable source rock for the above oils where a family cannot be allocated.

3.3.8 Kanau 1 – Oil to Source Correlations

Overview

The Kanau 1 well drilled a sedimentary section consisting of mudstones and sandstones which have been dated as Triassic (Brereton ,1976) from 3290-3519m. During drilling of this interval, shows were reported and a post well analysis of the mudstones indicated excellent oil source potential in a post generative state (Brereton, 1976). Brereton (1976) upon review of the stratigraphy in this sequence speculated that this unit could be equivalent to the late Triassic Kana Volcanics which outcrop in the Kubor Range. This was based on the presence of feldspathic arenites (common in this unit) along with volcanic siltstones and dacite pebble

94 conglomerates. Poor stratigraphic control on this interval means this association is uncertain and the unit is constrained by a single palynological date with the top of the unit picked only on logs. Subject to any future studies on this unit, the section from 3290-3519m in Kanau 1 will be termed Triassic throughout the thesis.

The Kanau 1 Triassic interval is known to have been deposited at a time when extensional faulting was active (Home et al. 1990) and therefore it is possible to have formed in a synrift setting. However, the focus of this section will examine the geochemistry of oil extracts obtained within this interval. The source potential of this interval will be discussed in further detail in Chapter 4. Examination of the geochemistry from this interval will assist in oil to source correlations, as well as providing a better understanding of the depositional environment of the source rock.

Organic_Geochemistry The saturate chromatographs for all oils from this interval are shown in Figure 3.27 with their locations within the Triassic interval marked. In general terms, the organic geochemistry of oil extracts from the Kanau 1, from the Triassic interval, show a wide variety of facies and states of biodegradation. This comment is based on the extract geochemistry available from this interval which constitutes six extract analyses. The detail in this analysis varies however. The carbon distribution shows that the oils consist of both waxy (predominance of >C22 saturates) and non-waxy oils. Also, several oils appear to contain mixed waxy oil and biodegraded oil. Others show very low levels of biodegradation. From the available data, there are only a few aspects the oils have in common. These include:

• Low pristane to phytane values consistent with an anoxic to suboxic source rock depositional environment (0.5 – 2.1, although biodegradation may have affected some of these values)

• Elevated levels of C24 tetracyclic terpane relative to C30 hopane (0.1 – 0.39)

• Relatively light carbon isotope values in the range -31 to -33 per mill (saturates) (Figure 3.4 & 3.5)

Figure 3.27: Summary of organic geochemical data from the Kanau 1 Triassic Source Rock Interval Lithology column for the Triassic in Kanau 1 well, drilled from 3290 - 3519m. TOC% of the source interval increases with depth. Chromatograph of Geochemical % C27 C24 Tetracyclic Oil extracts demonstrate a progression from anoxic, restricted lake Terpane /C H Pr/Ph Saturates (GC-MS) Interpretation Steranes 30 C16 conditions in the lower part of the succession, to progressively more 3450-3470m - Chromatograph very similar suboxic, carbonate conditions. This suggests the lake was subject to to 3505-3519m a marine incursion. --2.1 -Sub oxic source depositional Lithology environment Gamma Ray Depth Total Organic Carbon Log (mMD) Oil Extract 3476m - Marine organic matter 0 API 150 0 % TOC 4 with lesser terrestrial Zones 49 0.39 1.7 material. Top Triassic - Carbonate source rock - Late oil window (0.93 Vr%)

3477.7m - Waxy terrestrial organic 34 0.15 0.7 matter with lesser marine organic matter - Heavily biodegraded oil mixed with fresh oil

3478m

-Predominantly biodegraded --0.4 oil mixed with fresh waxy oil with light biodegradation

3478.5m - Terrestrial organic matter with lesser marine organic matter 25 0.12 0.5 -Mix of biodegraded oil with Core 1 fresh waxy oil with light biodegradation

3505-3519m - Terrestrial organic matter 14 0.1 1.2 mixed with lacustrine algal organic matter *indicates samples with - Anoxic, hypersaline depositional environment, Lithology Key detailed geochemistry probably a lake Orange (siltstone) Lithology and Gamma Ray (Brereton 1976m) - Fresh oil mixed with minor Grey (mudstone) Geochemical Data from 1) Robertston (1990)., Volk et al (2007) degraded oil? Yellow (sandstone) 95 96

Basic organic matter input to the sources appear very different. This is well represented by the sterane ternary plot (see Figure 3.6) where all Kanau 1 samples appear to plot apart from each other and show no particular consistency in the relative contributions of

C27-C28-C29 steranes. Features of note in the sample at 3476m include the appearance of alkyldibenzothiophenes and a high C29 / C30 hopane ratio. These parameters suggest a carbonate source rock (ten Haven et al. 1988). A second extract taken near the base of the Kanau 1 well at 3505-3519m contains a significant proportion of %C28 steranes

(Figure 3.6), extended tricyclic terpanes in the range C19 – C24 and the presence of gammacerane. These parameters are typical of oils from a lacustrine source similar to Family L. These features are not observed in the other oil extracts, the remainder of which appear to have more terrestrial characteristics, indicated by their waxy nature and predominance of %C29 steranes. Despite the variety of biomarkers and general nature of the oils, sense of the organic geochemical data can be made when plotted in their respective positions along the wellbore as shown in Figure 3.27. Figure 3.27 shows each saturate chomatograph against several organic geochemical parameters. From the parameters shown it is apparent there is a progressive increase of several values from the base of the source interval up-section. The basal sample has low %C27 steranes and has a hypersaline source rock environment, based on the presence of gammacerane.

With decreasing depth the value of %C27 steranes, or marine algal input, is shown to be increasing towards the top of the source section, in addition to a general increase value of

Pr / Ph, as well as the C24 tetracylic terpane to C30 hopane ratio, which together implies an increasing marine influence and less anoxic conditions prevailing.

Analogue

The Kanau 1 Triassic interval was probably deposited in a half graben (Home et al. 1990) which would have occurred along the Darai Fault (and other similar faults orientated NE- SW) would hence lead to the deposition of a synrift source rock section. These represent major contributors of hydrocarbon in various petroleum provinces in other basins (eg Angola, Brazil). An example of a geochemical examination of a synrift source rock section can be found in Burwood et al. (1991) through examination of the Bucomazi source rock in the Lower Congo Basin, Angola. A summary of the results is shown in Figure 3.28. The paper by Burwood et al. (1991) examines the traditional logic of the Lower Congo Basin, which had defined the entire drilled source rock interval as a “lacustrine synrift”. However following the geochemical analysis in Burwood et al. (1991) the ‘non

Figure 3.28: Geochemical profiles through the CABGOC 123-4 well Lower Coastal Congo Basin for the depth interval 8000-10,100 feet (Burwood et al. 1991)

Figure demonstrates the non uquiquity of the oil geochemistry in lacustrine source sequences, using three figures, over the same interval. The diagrams show a trend from lacustrine at the base to increasing marine character uphole. This is demonstrated by an increase in the gammacerane to Trisnohopane ratio (top middle), a more varied source rock kinetic parameter (left of middle), an increasing C30 sterane abundance (bottom left) in addition to an increasing C25 to C26 Tricyclic Terpane ratio. Also significant is the highly varied carbon isotope values over the inverval, which varies considerably even within individual facies (see kerogen pyrolysate signature) with up to 8 p er mill variation

98 ubiquity’ of oils deposited in a synrift source system were recognised. The paper demonstrates this through a series of biomarker parameters which include an increasing proportion of C30 steranes, increasing C25/C26 tricyclic ratio and a decreasing gammacerane / 25,28,30 TNH ratio from the lower to the upper portion of the succession. These factors lead to a series of conclusions from the paper which recognize a source interval that was suggestive of a trend from basal lacustrine and hypersaline which becomes more marine influenced with time (as shown in Figure 3.28). Examination of the organic geochemical data available from Kanau 1 (Triassic section) indicates a similar trend, shown in Figure 3.27. The earlier discussion highlighted that the organic geochemistry of the extracts from this interval were varied with respect to their depositional environment. Although the same parameters from Figure 3.28 are not available, a trend based on organic geochemistry can be established which shows a lower section with a stressed environment containing elevated %C28 steranes, increasing relative proportions of gammacerane indicating hypersalinity and low %C27 steranes, to a more marine dominated environment indicated by increasing %C27 steranes and C24 tetracyclic terpane / C30 hopane ratio. The general trend of increasing Pr/Ph ratio over time also supports the concept of a lower restricted and enclosed basin progressing to a more open environment where oxic organic matter is being deposited in the system.

Oil to Source Correlations

The organic geochemical extract at 3505-3519m appears to be geochemically quite different to the extracts in the shallower section of the well, primarily indicated by its more restricted signature. This is based on the elevated levels of C28 steranes, presence of gammacerane and elevated tricyclic terpanes. Comparison of these parameters to oils in Family L classification show many close similarities, particularly to oils such as the Koko 1 SFT and FI oils. Table 3.12 shows a series of organic geochemical parameters for the Koko 1 FI oil and the Kanau 1 extract at 3505- 3519m. Figure 3.29 shows a comparison of m/z 191 traces, showing the distribution of tricyclic terpanes in the two oils.

Table 3.12: Comparison of Geochemical parameters for the Koko 1 oil and Kanau 1 extract

Koko 1 FI Oil Kanau 1 Extract (1159-1162m) (3505-3519m) Volk et al. 2005 Robertson 1990

Pr/Ph 2 1.17

%Steranes 22 : 30 : 48 14 : 46 : 40 (C27:28:29)

Gammacerane / 0.19 0.25

C30 Hopane

Tricyclic Terpanes C19 - C29 C19 - C29

C26/C25 Tricyclic 1.5 0.75 Terpane

or carotanes Present Absent

13C (saturates) -34.9 -32.4

per mill

Figure 3.29: A portion of the 191 m/z traces from Koko 1 FI Oil – (Volk et al. 2005). Top, compared to an extract from Kanau 1 - 3505 – 3519m (Robertson 1990) - Bottom. Figure shows both Tricyclic (/3) and Tetracyclic (/4) Terpanes.

Matching compounds - as indicated, Vertical scale is ‘relative response’. Horizontal is retention time. 100

In addition to the matching biomarkers, a distinct similarity in the relative peak heights of tricyclic terpanes, particularly in the range 19 – 24, shown as 19/3 to 24/3 respectively, is observed. A strong piece of evidence for linking this oil to the Kanau 1 extract at 3505-3519m is the isotopic plot (Figure 3.4). The plot demonstrates that the oil contains light 13C (saturate) values of ~ -34 per mil whereas the source rock extracts contain values of ~ -31 per mil. Waples (1985) indicate that oils are on the average ~2 per mill negative than source kerogens. The maximum difference here is ~3 per mill which might initially indicate no correlation. However, the generally heavier source rock values could be explained by a combination of two factors: 1) the high degree of biodegradation in the Koko 1 oil (as 3.3.2) 2) mixing of the Kanau 1 (3505- 3519m) oil with other oils within this section that show intense biodegradation (eg 3478m on Figure 3.27). Mixing can be a key difficulty in performing oil to source correlations (Curiale, 2008). These factors may allow the difference to be incorporated. Several parameters usually required for a lacustrine oil are not found in the Kanau extract. One of these aspects is the lack of C26/C25 peaks which are <1

(0.75). However, as pointed out in Figure 3.29 co-elution may have occurred in the C24 tetracyclic terpane which may be masking its presence. The somewhat poor quality of the 191 m/z trace from Robertson (1990) does not assist in identifying the C26 peak. In addition, no or carotanes are reported. The overall conclusion from this attempt at an oil to source correlation is that this can be given moderate to good confidence. The level of C28 steranes, presence of gammacerane, similar carbon isotope data, as well as the geological context as a synrift the source samples are all considered compelling evidence for suggesting that the Kanau 1 Triassic source rock is the probable source of the Koko 1 oil and for the Family L oils.

Based on Figure 3.6, it is noted that the Panakawa Seep (Family MC – marine carbonate) plots in a very similar position to the Kanau 1 extract from 3476m and represent another possible oil to source correlation. Several other factors show evidence for an oil to source correlation. A table of various geochemical parameters are summarized in Table 3.13 between the Panakawa Seep and the above Kanau extract. Similarities include:

• The presence of sulfur species in both oils, specifically dibenzothiophene and alkyldibenzthiophene.

• Pr / Ph are broadly similar in both oils, 1.5 – 2, indicating the source for the oils was deposted in a suboxic depositional environment (Didyk et al. 1978)

101

• Both are carbonate sourced oils based on the C29/ C30 hopane and ratio of

C24/C23 tricyclic terpane ratio (ten Haven et al. 1988).

Despite the above, there are difficulties with this oil to source correlation. An aspect of prime importance in establishing a correlation is the carbon isotope data for the seep and Triassic oils which are quite different. This is shown in Figure 3.4, where the Panakawa seep oil appears more similar to the Foldbelt oils in this regard. The difference between the saturate values as shown in Table 3.7 is up to ~6 per mil which generally indicates a non-correlation (difference > ~2 per mill, Waples 1985). This would appear to negate any possibility of correlation.

However, if consideration is given to the Bucomazi source rock examined by Burwood et al. (1991) it can be noted that amongst the widely varying geochemistry a highly variable carbon isotopic signature can be observed (Figure 3.28). For example, in the lacustrine – marine? transition zone, the isotopic variation within a 400ft (~120m) sequence can exhibit a difference of ~8 per mill with the same source rock facies. If this aspect is considered together with the varied organic geochemistry of synrift sequences, then the isotopic difference could be accounted for and hence the oil to source correlation of the Panakawa oil and the Kanau (3476m) oil extract can be established. Based on the isotopic data (Figure 3.4 and 3.5) another model could be considered, ie a Foldbelt source or Late Jurassic could be responsible for oils of this type, but it would be require to be a different organic facies of the same source rock. The source facies would be a carbonate oil source rock with a more restricted and predominantly marine depositional environment (section 3.3.3). These aspects would explain the close correlation as shown in Figure 3.4, and allow for the variation in less oxic nature of the source demonstrated in Figure 3.5. A Late Jurassic source of carbonate affinity has not been identified in the Papuan Basin. However, it is worth noting that Preston (2007) correlated the Panakawa seep with Upper Jurassic oils in the NW Shelf, primarily on the basis of isotopic data. The difficulty in relying on this approach is comparison of two different basins, where isotopic correlation may be coincidental and where the facies may not necessarily be comparable.

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Table 3.13: Geochemical parameters for the Panakawa Seep and Kanau 1 extract (3476m)

Panakawa Seep Kanau 1 - Triassic – 3476m

Pr/Ph 2 1.5

% Steranes 48 : 24 : 28 49 : 22 : 29 (C27:28:29)

C29/C30 Hopane 2.19 1.4

C24/C23 0.30 0.45 Tricyclic Terpanes

Sulfur Dibenzothiophene Alkyldibenzothiophene Compounds

C , 30 bisnor- Absent Present 28 Hopane

The quality and limited amount of data available are not conclusive in deciding which of the two source models best explains the origin of Family MC oils. There is no comprehensive analysis of the source rock section, particularly with isotopic data to firm up the correlation and in addition no isotopic data on the 3476m oil from Kanau 1. Given the very different geochemistry of this extract to others within the source rock section, it is possible that the isotopic composition may also be different. The correlation with a synrift Triassic source appears most plausible on the basis of the data available, particularly because of the very different biomarker signatures of Family LJ oils and the MC oils which makes this correlation most unlikely. Other geochemical parameters particularly steranes and carbonate indicators appear compelling and the isotopic value, although quite different, is in keeping with analogues from such synrift sections. There is however insufficient isotopic data to confirm a variation of this magnitude exists. A possible source rock candidate, a Late Triassic carbonate, would be the Kuta Limestonem, a formation that outcrops on the Kubur Range and has been dated as Late Norian to Rhaetian (Late Triassic) discussed by Skwarko et al. 1976. This is further discussed in Chapter 4.

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3.3.9 Calculation of Oil Maturity

Peters et al. (2005) (page 1026) define thermal maturity as “the extent of heat driven reactions that convert sedimentary organic matter into petroleum and finally to gas and graphite”. Maturity for the various oils in this study was estimated using a combination of biomarker and aromatic hydrocarbon parameters:

1) C29 sterane isomer ratios 2) An aromatic parameter, the Methylphenanthrene Index (abbreviated as MPI-1) For the Magobu Island 1 set of fluid inclusion oils, the methyl napthalene ratio and methyl phenanthrene ratio (Radke 1988) was used to calculate maturity since MPI-1 could not be calculated due to poor data quality. The use of these two different approaches for estimating maturity (sterane versus aromatic) allows for cross checking of the calculated maturities and allows flexibility in calculating maturity where only one parameter is quoted. This is especially usefull for the sterane values, since these are more commonly measured than MPI-1. A brief overview of each of the approaches to maturity calculation is given below: MPI-1 involves monitoring of the reaction between the various isomers of phenananthrene and methylphenanthrene. The concept is that with increasing temperature, methyl groups become mobile, which results in the preference of thermodynamically more stable 2 and 3 methylphenanthrenes over the 1 and 9 methylphenanthrenes. MPI-1 is diagrammatically defined using Figure 3.30: Figure 3.30: Equation and molecules involved in calculating the Methylphenanthrene Index (Radke & Welte, 1983. Figure by Peters et al (2005)

A NOTE: This figure/table/image has been removed

to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Figure 3.31 illustrates the relationship between MPI-1 and the measured vitrinite

104 reflectance (Rm in coals and shale). Rc or calculated reflectance can be can be derived by the equations shown.

Figure 3.31: Relationship between MPI-1 and Rm% (mean) (Radke and Welte 1983, Figure from Peters et al. 2005)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Note that the relation requires an understanding of the thermal range of the oils concerned, since the gradient, and hence the equation, changes from a positive correlation to a negative correlation around 1.35% Rm. Based on data on source depths and maturity from nearby wells, it is believed that the oils are not thought to have expelled beyond this threshold. Hence, the equation Rc = 0.6MPI-1 + 0.4 has been used for all oils in the study area. The main advantage of using the MPI-1 value is that it is has good sensitivity to thermal maturity, especially in the late oil window (~0.8 Rm % or greater). However, the ratio must be used with caution for biodegraded oils. Table 3.3 indicates that methylphenanthrenes are effected at biodegradation levels between 3 to 5 and are absent beyond this. This invalidates the use of MPI-1 as a maturity indicator at these biodegradation levels, and beyond level 5 the calculation is not viable.

The calculation of thermal maturity using steranes involves the monitoring of the C29 20S/20S+20R ‘isomerisation’ ratio which rises from 0 to ~0.5 with increasing thermal state (Seifert and Moldowan, 1986). The ratio monitors the amount of the 20R (biological isomer) relative to the 20S isomer (geological isomer) which is more thermally stable. The configuration of the C29 20S and C29 20R isomers is shown in Figure 3.32.

105

Figure 3.32: Structure of the C29 20R isomer (left) and C29 20S isomer (right) (Note: Bold lines project upward, dotted lines project downward relative to the plane of the ring system)

The ratio 20S/(20S + 20R), which is normally calculated using the C29 steranes since the peaks involved are often clearest on the m/z 217 chromatogram and free from co-elution with other compounds. The ubiquity of sterane data for oils in the study area, compared to MPI which is not reported as often, means that the 20S/(20S + 20R) value provides a commonly available maturity parameter across the study area. However, Peters et al. (2005) do not recommend the use of the parameter to indicate the onset of petroleum generation unless it is calibrated for each basin against other maturity parameters.

To enable use in this study, sterane maturity values were calibrated using the Rc % from MPI-1. Calibration of the sterane data for maturity was performed by utilising a calibration curve and used various maturity data involving Rc values for oil derived from MPI-1, Vr from measured reflectance as well as FAMM data (see Figure 3.33). Oil data was plotted onto an Rc% versus 20S/20S+20R diagram and samples to use as calibration were chosen from where both MPI-1 as well as 20S/20S+20R values were available for the same oil. Samples which showed significant biodegradation or contained mixed charges were avoided. Three maturity relation curves are given on the diagram, as published by Mackenzie (1984) and Waples & Machihara (1991) and these were used in order to provide guidance for a relationship of thermal maturity to 20S/(20S+20R) trend. Based on Figure 3.33, the results appear somewhat scattered with respect to each other and the reference curves, with the Komewu 2 and Aramia 1 oils, both from coals, lying closest to the reference curves.

Figure 3.33: C Sterane ratio value vs Vr% (from MPI-1) using undegraded/mildly Figure 3.33: 29 106 degraded oils. Vr from Coal Petrology is also shown, where available (reference curves from Mackenzie 1984; Waples and Machihara, 1991) 29 C

20S = S isomer of C29 sterane 20R = R isomer of C29 sterane 107

Interestingly, the FAMM data for these two samples is in good agreement with the MPI derived maturity values. The two samples from Kimu 1 and the two from Iamara 1 appear to have a higher maturity than demonstrated by the sterane data. The Kanau 1 source rock (3476m) does not appear to lie near the calibration curves. One interpretation is that the steranes data do not work as a maturity indicator for these particular organic facies. Better agreement is shown by the Koko 1 fluid inclusion oil and Magobu Island oil extract in the upper maturity range between 0.7 and 0.8 Vr. Using the points close to the reference curve, in this case a curve based on the Neogene basin of Japan (Waples and Machihara ,1991) one of the calibration curves for the calculation of maturity from sterane data was chosen from the 3 reference curves and a polynomial equation was derived. However, it would appear that maturity cannot be calculated for values beyond approximately 0.8 Rc% or a value of 0.51 20S/(20S+20R). This is since the maturity curve flattens beyond this point, leading to a dramatic increase of maturity and beyond which the sterane ratio is constant. The maturity, or equivalent Vr derived from sterane data will be shown on interpreted oils in Appendix 9.2. However caution must be exercised when using these values given the scatter shown for some oils on the calibration curve. In addition, at the upper end of the range, maturity might be underestimated by the sterane curve. This study will consider that, particularly for undegraded oils, MPI-1 will be considered the more reliable maturity estimator, if there is discrepancy in the estimation between aromatic and biomarker parameters. Other Information on Sterane Maturity Steranes in petroleum are unaffected by biodegradation until level 6-7 (Table 3.3). However, it is worthy of note that the 20R and 20S isomers are degraded at nearly equal rates in some severely biodegraded oils (maintaining the ratio) and in other cases selective removal of one isomer may occur (Peters et al. 2005). The greater resistance of the steranes (compared to the methylphenanthrenes) means that the 20S/20S + 20R value is potentially useful in measuring maturities in oils that have suffered heavy levels of biodegradation. Other factors which can influence the sterane ratio include organofacies differences and weathering (Peters et al. 2005). The maturity data will be used in the assessment of the onset of oil expulsion for each oil family as well as distinguishing truly ‘active and mature’ source rocks from those that are at low levels of maturity and generated in-situ or close to source.

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3.4 Summary of Results

From the inspection and interpretation of the 35 oils, the study area has been shown to contain at least five distinct oil families. These include: Lacustrine (L), Marine Carbonate (MC), Late Jurassic (LJ), Cretaceous (O) & Coal Sourced (C). A sixth family (X) represents a mixed oil of one or more of the five families above. A handful of oils were not allocated to a family due to their ambiguous nature or absence of any distinctive geochemical feature by which they could be grouped. These oils are found under Miscellaneous in Appendix 9.2.7.

Table 3.14 summarises the key geochemical characteristics for each oil family. Also shown is the most likely source rock for each. Some are known with good confidence and have oil to source correlations eg Family L. For other oil families, source rocks can only be theorised from the known stratigraphy, based on the geochemical characteristics of that oil eg Family O. There is some overlap with respect to distinguishing oils that are coal sourced and those which are oils derived from the Late Jurassic. Several more subtle features such as the Ts/Tm value in comparison to the level of maturity was used to make a decision on which family a particular oil could be grouped. From the breakdown of the oil history, evidence of recharge and the level of thermal maturities, the oils can be broken down into several groups, as Table 3.14

Table 3.14: Subdivision of Oil Families by Maturity and Physical State

The geographic distribution of these oils and their nature is depicted in Figure 3.34a and 3.34b. Family L and O general appear to be a palaeo charge event, since they are biodegraded or only found in FI oils and appear to have effected both the Turama River and Fly River areas. However, an exception to this trend is one sample at Iamara 1 (1656m), consisting of mixed Family L and Family O oil, probably with only

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Table 3.15 - Summary of Results

The following table summarises the key results from the geochemistry of each oil family described in Chapter 3

Oil Family Geochemical Characteristics Source Rock Environment Source from Organic Geochemistry Rock Candidate Oil to Source Correlation L – Lacustrine • Variety of distinctive lake Lacustrine Upper Triassic shales Good confidence biomarkers eg carotanes, Correlation based on a single low gammacerane, C26 > C25 Sub-oxic depositional maturity extract from the Triassic at tricyclic terpane, extended environment. Kanau 1 (3505-3519m). Correlation tricyclics, tetracyclic established by several similarities to Family L including the presence of polyprenoids Hypersaline water chemistry, gammacerane, elevated C28 steranes probably within an arid climate and similar carbon isotope values to • Elevated levels %C28 steranes the Koko 1 Lower Imburu sandstone oil to the Kanau 1 extract 13C • Generally biodegraded oil (saturates) of -34.9 versus -32.4 per mill respectively. • Maturities (where reliable) are 0.73 – 0.78 Vr MC – Marine • Dominance of %C27 steranes Anoxic to suboxic depositional Upper Triassic shales OR Low to moderate confidence Carbonate environment but with some Late Jurassic which Correlation based on a single • Carbonate indications: moderate level of clay input. contains a significant relatively high maturity extract from carbonate content. the Triassic at Kanau 1 (3476m) C29/ C30 hopane ratio>1 Moderately elevated salinity which shows several characteristics of this oil family. Carbon isotope data • Elevated alkyldibenzothiophenes initially indicates a non-correlation but or dibenzothiophenes A calcareous marl or muddy analogues may permit a correlation to limestone is suggested from the be drawn. The Kuta Limestone • Diasteranes > steranes data represents a possible source rock. Another is a Late Jurassic source, • Oils generated in the oil window ie.similar isotopic signature to foldbelt with onset of maturity at oils, but no carbonate source rocks 0.79 - 0.86Vr are known in the Late Jurassic.

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Oil Family Geochemical Characteristics Source Rock Environment Source from Organic Geochemistry Rock Candidate Oil to Source Correlation

LJ – Late • A variable proportion of marine & Marine environment with Magobu or other Late Good Confidence Jurassic terrestrial organic matter but generally significant input of terrestrial Jurassic source rock Extracts are low maturity and are organic matter. %C29>%C27 steranes taken from Late Jurassic section, known to be the source of oils • Presence of the biomarker Variable oxygen levels. discovered in the PNG foldbelt. diahopane and other terrestrial Anoxic-oxic environment, triterpanes indicated by Pristane to Phytane values. • Low maturity (0.45 to 0.62 Vr)

O – Late • Presence of oleanane Source is a carbonate source The source is a section in Low Confidence rock deposited in a relatively the Late Cretaceous Cretaceous Source is not known with anoxic environment. The carbonate (most likely). • C29 / C30 hopane ratio > 1 confidence and no analogue is source rock is of Late No source rock analogue indicating a carbonate source rock known in the basin. Source may Cretaceous to Tertiary age can be found in the have been present in the Upper based on the presence of Papuan Basin. The Darai • Pr / Ph of 1.05 - 1.7 Ieru Formation but subsequently oleanane Limestone is dismissed eroded at Late Cretaceous on the grounds that it is unconformity. • Presence of the biomarker 28,30 unlikey to be mature. bisnorhopane.

• Moderate - advanced maturities of 0.76 – 1 Vr %

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Oil Family Geochemical Characteristics Source Rock Environment Source Oil to Source Correlation from Organic Geochemistry Rock Candidate C – Coal Sourced • Unbiodegraded oil Coal swamp or lagoonal Magobu Formation coals Moderate to good confidence environment, highly oxic, large

inputs of terrestrial organic • High Pristane to Phytane matter Oil extract from the source rocks are available and show similar features to migrated oils. The • Elevated %C steranes 29 generic series of parameters initially have similarity to Folbelt • Very low Ts/Tm values 0.03 to oils, however the Ts/Tm values appear too low to indicate a clay 0.12 rich source rock.

• Waxy Oils

• Presence of C30 diahopane

• Relatively low maturities 0.51 – 0.74 calculated vitrinite reflectance.

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Figure 3.34: Charge distribution by family for the study area – 3.34 a) are mature oils generated and expelled from source rocks. 3.34 b) represents oils of relatively low maturity generated from the source rock, but are still within or close to the source package.

3.34 a) 3.34 b)

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moderate levels of biodegradation. Evidence of a mature coal sourced oil is found at the Iamara 1 and Magobu Island 1. Evidence of this oil in the north appears to be low maturity. The fresh nature of these coal sourced oils in a low temperature reservoir implies recent generation and expulsion. All other occurrences of oil Family C as well as Family LJ are of low maturity and have probably been generated in-situ. Family MC appears to be restricted to the northern portion of the study area and represents a distinct oil family which occurs individually as the Panakawa and PPL77 seeps, but also as an overprint, mixing with oil that has previously biodegraded in the reservoir.

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4 SOURCE ROCKS

4.1 Existing Work on PNG Source Rocks

The drilling of source rocks in a typical petroleum basin is relatively rare as is the drilling of rocks that are sufficiently mature for hydrocarbon generation. This tends to be a typical situation in many basins, since exploration wells are placed on structural highs where the deepest, mature and most basinal facies are usually never penetrated (Waples,1985).

The following statements are from Kaufman et al. (1994). In the oil and gas fields in the PNG Foldbelt, rich source is not generally intersected in wells however, zones with marginal source potential are identified within the Upper Jurassic which contain low to moderate quantities of Type II/III to Type III (mixed marine and terrestrial) organic matter. These organic constituents will produce a mixture of oil and gas when mature. The thought is that the source rock improves in richness into a basinal deep called the Kubor Kitchen, believed to be the likely source of Foldbelt hydrocarbons. The formation responsible is believed to be the Upper Jurassic Imburu Formation, with some potential in the Lower Jurassic (Chevron 1990, Waples and Wulff 1996). The Late Jurassic as a source rock concept is supported by oil – source correlations, demonstrating that the oils and source rocks are genetically similar (Moldowan & Lee, 1987)

A regional study of source rocks in the Foreland were performed by Burns and Bein (1980). Assessment of several wells in the Foreland as well as the Darai Plateau indicated elevated TOC (Total Organic Carbon) values in the Late Jurassic, inparticular good to very good oil sources were noted in the Kimmeridgian - Callovian as well as in the Callovian- Early Jurassic sequences, average of 1.57 to 1.75% TOC respectively.

Volk et al. (2005) have attempted to explain the source of oils in the Foreland, particularly lacustrine typed oils such as those found in the Koko 1 and Bujon 1 oils. Candidates include gypsiferous shales in the Oligocene-Miocene Carbonates or Triassic age sediments deposited on basement during rifting of Gondwana. ECL (Exploration Consultants Limited) (2005) also suggests the possibility that algal rich sediments within the Cretaceous – Jurassic section could act as possible source rocks for the lake derived oils based on intervals described using organic petrology in Kimu 1, Koko 1 and Bujon 1. Based on results presented in Chapter 3, the Triassic appears to be a likely source of lacustrine oil based on the results of an oil-source

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correlation. Despite this, the other concepts deserve some consideration and will be addressed in later sections. A report of prime importance to this thesis is an honours thesis entitled: “Papuan Foreland Source Rock identification using Wireline Log, Sequence Stratigraphic and Geochemical analyses” by Lund, 1999. The report aimed to quantify through logs, sequence stratigraphy and geochemistry, zones of possible source potential in the Jurassic and Lower Cretaceous, particularly for the Papuan Foreland, but the study also included several offshore wells and includes a comprehensive compilation of source rock potential data. The study identified four potential source units in the Papuan Foreland including Lower Imburu, Koi-Iange, Barikewa and Magobu Coal Measures. The study will be examined in more detail later in section 4.3.

4.2 Definitions

To screen stratigraphic units which could be considered potential oil source rocks, the TOC% (Total Organic Carbon) and Rock Eval pyrolysis data have been analysed from wells within the study area. The most comprehensive compilation of this data for the Foreland is the report by Lund 1999, and this section will form a basis to develop an assessment of source rock potential. To begin, a definition of the modern methods of assessing source potential and will be defined here in brief.

A petroleum source rock is a fine-grained organic-rich rock that could generate or have already generated significant amounts of petroleum (Peters et al. 2005). Various depositional environment give rise to organic rocks which have hydrocarbon generating potential. These will not be outlined here, however a general theme leading to source rock creation is the development of anoxia where the oxidative destruction of organic matter is severely limited, leading to organic matter preservation (Demaison and Moore 1980).

The following terms relating to source potential are from Waples (1985). TOC% is a determination of the amount of organic material present in a rock sample. This is the first screening technique for a source rock and involves a process of heating a carbonate free sample to high temperatures. The amount of carbon dioxide liberated in this process can be related to the TOC% of the rock. This is usually expressed in weight percent of the rock (the cut off point lying from 0.5-1% TOC) and forms a screening technique for samples which are analysed

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by the next step known as Rock Eval pyrolysis. Rock Eval is a method of using high temperature pyrolysis to mimic processes occurring in the subsurface, albeit occurring naturally over long time scales and lower temperatures. The process involves heating a small amount of rock, in the absence of oxygen, from ~250 – 5500C where during the heating process two sets of hydrocarbons and CO2 are produced. Terms are given to these sets expressed in milligrams of hydrocarbons per gram sample. These include:

S1 = The first of the hydrocarbons occur at ~2500C represent the solvent extractable bitumen and refer to hydrocarbons already present in the rock

S2 = The second of the hydrocarbons generated, at temperatures at ~420- 4600C and represent hydrocarbons released by thermal decomposition of the rock. This represents the remaining hydrocarbon potential of the source rock.

S3 = This is a non hydrocarbon peak and is an accumulation of carbon dioxide gas created during the pyrolysis process. This gas is only fed to the detector only once analysis of the hydrocarbon measurements are complete. The carbon dioxide represents the oxygen content (expressed in milligrams of CO2/gram) of the kerogens in the sample, which tends to be a negative indicator of source potential.

The above data are a measure of a rock to generate or release hydrocarbon. However, the generative potential for a particular source rock is dominated, not only by the level of organic enrichment but also by the type of organic matter it contains. This can usually be assessed by organic petrology in a similar method to assessment of coal constituents, and is also the method of determining the thermal maturity of a rock. A kerogen is defined as a portion of organic matter in a rock which is insoluble in organic solvents and is formed by polymerisation of dead organisms and from which oil and gas are generated during maturation (Waples, 1985). Table 4.1(a + b) shows a diagram of the major classes of organic constituents, or kerogens in rocks. Those generally considered suitable for generation of oil are both alginates and exinites (collectively termed liptinites) whereas source rocks containing abundant vitrinite generate mostly gas.

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Table 4.1a: Definitions for organic constituents in sedimentary rocks

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Table 4.1b: Maceral groups, their origins and respective kerogen types

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Tables from Peters et al. (2005)

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A host of organic constituents are recognised within rocks and can contribute various proportions of oil, gas or no hydrocarbon products during maturation. However, the process of organic petrology is generally time consuming especially for thick sections of interest and instead the results of the Rock Eval can be used to indicate the kerogen type. This is achieved by normalizing the above data using the TOC value, yielding values of milligrams per gram of TOC. The normalized S2 and S3 values are called the Hydrogen Index (HI) and Oxygen Index (OI) respectively. These values serve as a measure of kerogen type. The four principal types of kerogen in sedimentary rocks include Type I (very oil prone), II (oil-prone) & III (gas prone) defined by Tissot et al. (1974). Later studies have also identified a Type IV (inert or non generative) by Demaison et al. (1983). Typical HI cut off values for various hydrocarbon products for these kerogen types are shown in the Table 4.2 by Peters and Cassa (1994).

A common graphical approach of assessing source quality is a plot as shown in Figure 4.1. This shows OI versus HI for various well known source rocks. Note that this plot is known as a ‘modified’ van Krevlen plot since the original author (van Krevelan, 1961) used atomic oxygen and hydrogen on the x and y axes, respectively. Since the latter is more difficult to measure, the use of HI and OI allows for a more rapid assessment and with lower costs.

Figure 4.1: Modified van Krevlan diagram showing Rock Eval data from various Type I – II – III source rocks

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Figure from Peters et al. (2005)

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Table 4.2: Summary of source rock guidelines based on source potential data and kerogen type (Peters and Cassa, 1994)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

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4.3 Review of Lund (1999)

As mentioned previously a comprehensive study of source potential is found in the report by Lund (1999) entitled “Papuan Foreland Source Rock identification using Wireline Log, Sequence Stratigraphic and Geochemical analyses”. The report aimed to quantify through logs, sequence stratigraphy and geochemistry, zones of possible source potential in the Jurassic and Lower Cretaceous, particularly for the Papuan Foreland, but also included several offshore wells. The geographic range of this report means that the results are pertinent to the current study area, however not all wells in the current area were included and also some wells outside the study area were incorporated. This is outlined in the next sections.

The map shown in Figure 4.2 shows the 14 wells included in the study. The current study area is also marked.

The wells chosen to be used in the study were based on three criteria; availability of TOC% data, well penetration to at least the Lower Imburu and the well needed both sonic and resistivity logs over the Mesozoic section. The use of several methods allows for cross checking of each method to TOC% data in order to assess its effectiveness as a source predictor. Identification of flooding surfaces were based on a previous sequence stratigraphy study by Robertson & Winn (1998) was used identify flooding surfaces and hence zones of organic enrichment. Use of the wireline logs to assess source quality uses a technique known as LogR. In brief, this concept uses a process known as LogR involving overlaying of a sonic and deep resistivity (normally). These logs are chosen since they are least affected by borehole rugosity. The process relies on observing a decrease in density and changing of pore fluids which, when base lined correctly can give an estimation of source rock quality and indirect measurement of TOC%. Although the study demonstrated that LogR technique could be used as a bulk organic content measurement, this process was suggested not replace proper sampling using traditional source rock measurements (TOC% and Rock Eval pyrolysis) since the study suggested that the accuracy of LogR techniques approach was generally low which was attributed in part to the sensitivity of the method to the quality of the wireline logs.

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Figure 4.2: Location of wells used in source rock characterisation study. Current study area marked (Lund 1999)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Sequence stratigraphy proved to be a better method of good source prediction indicating that flooding surfaces appeared to have the best source potential which correlated with the Rock Eval data. The results of the study indicated that the following biostratigraphic units appear to be sufficiently rich in hydrocarbon generating organic matter to represent source intervals (shown in Figure 1.6):

• Jurassica – Clathrata (Lower Imburu Formation)

• Spectabilis – Digitata (Barikewa – Koi-Iange – Upper Magobu)

• Indotata – Turosa (Magobu Coal - Bol Balimbu)

The six formations have average source characteristics of 1-3% TOC%, sometimes >10%, generative potential (S1+S2) of 2 - 20mg HC/g rock and HI of 100-300 mg HC/gTOC, occasionally >400 mg HC/gTOC.

In addition to assessing source quality data, the study also evaluated kerogen mixes within the major source intervals. These are depicted in maps which illustrate the

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kerogen mixes (Type II/III/IV) as well as normalized kerogen mixes after removing the intertinite (or non generating) proportion of the organic matter. An example of these maps is shown in Figure 4.3, based on the Magobu Coal Measures.

Figure 4.3: Kerogen Mix Map of the Magobu Coal Measures (Lund 1999)

A NOTE: This figure/table/image has been removed to comply with copyright regulations.

It is included in the print copy of the thesis held by the University of Adelaide Library.

All four maps show a wide range of kerogen types for each unit. The Lower Imburu has pre-dominantly more Type II than Type III kerogen, with small amounts of Type IV (inertinite), indicating a mixed oil and gas potential. The Koi-Iange and Barikewa formations are generally more dominantly Type III kerogen with a higher percentage of inertinite than the Lower Imburu Formation. The Magobu Coal Measures has the lowest type II/III ratio of the four units with a substantial amount of inertinite. The large proportion of inertinite in the Magobu Coal Measures is thought to be a result of the high maturities. Overall, the mapping shows that the location of oil-prone source rocks are consistently in the very north-western part of the Omati Trough for the Lower Imburu to Barikewa formations. The oil-prone source rocks for the Magobu Coal Measures, on the other hand, are located between Wabuda 1 and Magobu Island 1 in the Fly River delta (Figure 4.3).

The primary conclusions from the source potential study were that both the Rock Eval and visual kerogen data suggest good liquids and gas potential and points to likely

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source depocentres in the Omati and Wabuda Troughs to be prospective, which contain 3km and 2.5km of source rocks, respectively.

4.4 Source Rock Assumptions for this Study

Understanding the oil based petroleum potential of the Foreland relies on obtaining numerous source potential (TOC% and Rock Eval pyrolysis) data over as much stratigraphic section as possible in order to build up a composite understanding of the bulk potential of any particular stratigraphic unit. Note that for the purposes of this assessment the following assumptions are used:

1. All source rocks are Mesozoic or older in age. This assertion is based on three criteria: a) The Tertiary (Darai, Orubadi and Era beds – see Figure 1.6) is not considered a source interval since this section overlies the section where the hydrocarbons are reservoired, including a thick Ieru seal below making it an unlikely source without complex juxtaposition. The tertiary consists of the shallowest formations in the Foreland (~1km combined thickness) and hence is unlikely to be mature. b) Source rock data is very rare in the Tertiary, precluding proper assessment. c) Discussion with CSIRO on their extensive work on the Tertiary of PNG indicates that based on petrological work a rock possessing organic constituents with possible source potential has never been identified (T. Allan pers comm 2005)

2. On a first pass basis, source rocks cut offs are those used for shales ie since no significant carbonates are known within the Mesozoic.

The identification of a rock of sufficient organic richness to be declared a source rock in petroleum exploration is primarily based on the results from TOC% or Rock Eval pyrolysis data. Tissot and Welte (1984) indicate a minimum TOC% for considering a shale as a source rock is 0.5%. Waples (1985) also uses a minimum value of 0.5% source rock cut off, considering this rock to have ‘slight’ source capacity, but also points out that even for rocks with a TOC% of 0.5 to 1%, these rocks will not function as highly effective source rocks since expulsion of the hydrocarbons is difficult, in addition to the fact that these rocks are generally oxidised and hence overall these

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sources rarely offer source potential. Review of other literature such as Peters and Cassa (1994) indicates a good source begins at 1% TOC%.

The beginning of the oil threshold for a source rock based on HI is considered to be somewhere between 200 mg/gTOC (Peters and Cassa 1994) ranging up to 176- 254mg/gTOC (Waples 1985 siting Saxby 1980).

Based on the above literature the following cut-offs will be used to assess oil source potential: 1) TOC > 1% 2) HI > 200

These cut-offs will be applied to the entire Rock Eval database created for this study (see section 4.5).

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4.5 Data and Data Revision

Prior to direct use of the Lund (1999) study as a guide to the stratigraphic location of source rocks, a review of the TOC%, Rock Eval pyrolysis and well reports was performed. Several key areas for improvements were recognised. These included:

1. Additional source data from new wells drilled since 1999

2. Additional data from wells already included in the 1999 study but obtained post 1999.

3. Contamination removal from the dataset

4. Consideration of deeper horizons as source rocks, particularly the Triassic.

The following table lists the wells for which TOC% and Rock Eval data were compiled. These are shown spatially on Figure 4.4, demonstrating the wells considered from the previous study, in addition to those added for the current study.

Table 4.3: Summary of wells used in source rock potential study DLUND 1999 WELLS ADDED Bujon 1 * ^ Adiba 1 Darai 1 Aramia 1 Dibiri 1A * Barikewa 1 Goari 1 Duadua 1ST1 Goaribari 1 Iamara 1 Kamusi 1 Kimu 1 Kanau 1 * Koko 1^ Komewu 2 * Komewu 1 Kusa 1 Magobu Island 1 * Morigio 1 * Mutare 1 * North Paibuna 1 ^ Omati 1 Rama 1 Wabuda 1 *

* Source rock analysis acquired post 1999 was added to this well ^ Contamination identified and removed NOTE: Anchor Cay 1, Mira 1 and Uramu 1A wells were removed from the dataset. Mira 1 and Uramu 1A contain no source rock data in Mesozoic strata Note that although Anchor Cay 1 occurs on the map as 4.2, review of the original 1999 Rock Eval dataset shows it was not used.

The total dataset following removal of non Mesozoic data and clean up for contamination constitutes approximately 1300 TOC% measurements, 700 Rock Eval

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Figure 4.4: Wells used in the Rock Eval source potential study. Gridded backdrop represents a Top Basement depth structure map (grid courtesy of Oil Search Limited)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

measurements derived from 24 wells. It is important to note that the appearance of a well in Table 4.3 does not necessarily constitute that the full drilled stratigraphic section has been analysed. Often companies only used targeted geochemical programmes on specific stratigraphic intervals and others implementing comprehensive closely spaced analyses throughout the entire well. All data, including the depth intervals covered by each well is shown in Appendix 9.3. Table 4.3 tracks the wells used in the Lund (1999) study, the additional data added, as well as any revisions to well data or contamination removal.

Contamination was identified through various methods. Organic petrology was useful in identifying contamination in cuttings samples at Bujon 1 where “major organic mud additives” are reported (Sherwood ,2007). A re-inspection of the source potential data demonstrates spurious data (eg commonly single samples with high HI with very low TOC%). North Paibuna 1 had similar issues with contamination, which was recognised by Robertson Research(1994) during the post well geochemical study. In both Bujon 1

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and North Paibuna 1 the cause of the contamination was a mud additive known as Soltex©. Soltex© is asphalt based and is used in mud systems to create greater stabilisation in shale formations and also enhanced mud cake development (Drilling Specialities Company Website). The hydrocarbon based nature of this additive means that HI and TOC% values can be artificially enhanced if entrained in rock cuttings. Individual cuttings intervals that were identified to be contaminated were based on geochemical reports or alternatively by removing all data points from well sections that were drilled following the addition of Soltex to the mud system. Note that if the same contaminated intervals contained Rock Eval from core or side wall core, these points were left in the dataset. Contamination was also identified in two intervals in the Koko 1 well but in the form of phalates identified during rock extraction (Barber pers comm; 2007) and hence these points were removed from the dataset. Data which is believed to be contaminated are marked in the tabulated data in Appendix 9.3.

4.6 Source Potential Results

Assessment of source potential by stratigraphic age was achieved by plotting up the whole Rock Eval dataset by stratigraphic unit. These are shown in Figures 4.5 and 4.6. This figure shows both TOC% and HI values, with the data arranged into nannofossil zones and sorted in stratigraphic order. The stratigraphic relation of the nannozones to the stratigrapy is shown in Figure 1.6. Note that the vertical thickness of each zone does not imply a stratigraphic thickness but is a representation of the number of analyses available for each. In this case it is apparent that the most commonly available data is through the Barikewa – Koi-Iange – Magobu (Jurassic age) with less common source data in the Cretaceous.

From plotting the TOC% and Rock Eval data the following general conclusions can be drawn regarding source potential:

• Almost all formations drilled have oil source potential, based on TOC >1% and HI > 200.mgHC/gTOC

• The Upper and Lower Ieru are generally gas prone, with HI values rarely >200 mg HC / gTOC

• The Toro Formation is a reservoir facies and is hence normally non source. However, the plots demonstrate some marginal source potential, particularly in

UPPER 128 Figure 4.5 - Bulk Source Rock Data by biozone - TOC% IERU LOWER IERU TORO LOWER IMBURU

1% TOC - oil threshold - see text BARIKEWA MAGOBU

TRIASSIC Figure 4.6 - Bulk Source Rock Data by biozone - HI mgHC/gTOC UPPER IERU 129 0 LOWER IERU TORO LOWER IMBURU

200 HI - oil threshold - see text BARIKEWA MAGOBU

TRIASSIC 130

• the Libispinosum – Reticulatum palyzone where TOC% values are up to 30%.

• The presence of elevated S1 values in this zone of up to 2.71 demonstrates that this unit contains free hydrocarbons, which is the probable reason for the elevated TOC values. HI values are low, <150 – 228mgHC/gTOC consistent with low overall poor source potential.

• Several coals or shaley cannel coals are present in the Magobu Formation Barikewa Formation, Lower Imburu and Lower Ieru Formations. These organic rich sources have TOC values of 27 – 58% and appear to have some oil potential based on HI values of up to 400mgHC/gTOC.

The following section seeks to look at each formation in more detail to assess its bulk characteristics.

The section has two aims:

1) To examine the source potential of units identified as possible source rocks from organic geochemistry (Chapter 3)

2) To develop appropriate inputs for the basin modeling section using source potential data

Note that assessment of source potential characteristics for the Jurassic has already been established through the study by Lund (1999) both from a petrological and Rock Eval pyrolysis. Hence treatment will be more liberal to the Magobu, Barikewa and Lower imburu section section, with more focus given to the intervals which have not been looked at in detail previously, and for which organic geochemistry indicates are potential source rocks. These include the Triassic, the Ieru Formation and coals in the Magobu and Barikewa Formations. Algal sources proposed by ECL (2005) also will be assessed.

4.6.1 Triassic

Well intersections of the Triassic are rare in the Papuan Basin. In the study area the Triassic is drilled at Kanau 1 between 3295-3519m and the lithology consists of both mudstones and coarse sandstones. The Kanau 1 well completion report suggests that the Triassic was recognised to have “excellent oil potential in a post generative state”

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(Brereton 1976). Later studies by Volk et al. (2005) and Robertson (1990) also recognised source potential in this unit. The Kanau 1 well is important since Chapter 3 demonstrated that this Triassic age interval is a likely source rock candidate for the lacustrine oil family identified at wells such as Koko 1 and Bujon 1. Further evidence for this oil to source correlation will examined here, based on lithological descriptions, Rock Eval pyrolysis and organic petrology.

Lithology

Given the probable source potential based on the above studies, in addition to the TOC% and HI plots in Figures 4.5 and 4.6, a better understanding of the formation was warranted through inspection of a core that was cut in this interval, the only core cut in the well. Brereton (1976) indicates the interval cored was from 3475-3484 (9m) however only ~50% (<5m) was recovered. The location, photographs and details of the core relative to the drilled stratigraphic section are shown in Figure 4.7.

Some key points from the inspection of the core include:

• The section drilled in core is dominantly a coarse-grained sandstone facies with lesser mudstone facies (approximately 70% / 30% respectively)

• The package consists of dark grey to black shales encased in sandstones with sharp tops and bases bounding the sandstones.

• The mudstones are generally weak – bedded to massive, sandstones are generally massive but exhibit graded bedding in places (as Figure 4.7)

• Carbonate veinlets cut the rock in places and give a positive response to hydrochloric acid (HCL)

The distal nature of the mudstones, with the abrupt appearance of coarse grained quartzose facies is interpreted to indicate that the depositional environment is a relatively deepwater environment which experiences periodic influx of coarse clastic flow, probably massflow or turbiditic in nature. The size of some of the clasts, the presence of feldspar as inclusions, as well as their angular nature suggests the clastic input is relatively close to source. A high TOC is indicated for the mudstones in this interval (1-3% as Figure 4.7).

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Figure 4.7: Kanau 1 – Triassic section showing Gamma Ray log, TOC (%) and location of Core No1 - Top. Bottom shows representative photos from this section. Key features are indicated.

Mudstone

Calcite Vein

Sandstone

Left: Close up on core indicating mudstone and sandstone lithologies. Graded bedding is observed in the core (direction of grading shown by red arrow). A calcite vein is observed.

Right: ~40cm long length section from core 1 from the Triassic, Kanau 1

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As discussed in Chapter 3, at least one of the intervals appears to indicate the presence of oil derived from a carbonate source rock. Although a carbonate is not identified in this core, a positive reaction to acid in this interval is demonstrated. However, much of the portions of the core that react appear to be carbonate veins and hence appears to be secondary, probably remobilised calcite.

Rock Eval Data

Rock Eval data plots for the Triassic section drilled at Kanau 1 are shown in Figures 4.8 - 4.9. Two new terms are introduced here: Potential Yield (S1 + S2) and Production Index, (S1/(S1+S2)), both of which have units of mg/g dry rock. The source potential data from that the Triassic is generally a fair to good quality source rock based on the TOC% versus Potential Yield plot (Figure 4.8a). Maturity data based on TMax 0C versus PI (Production Index) plots demonstrate that the Triassic has reached the oil generation window (Figure 4.8b). Source rock organic matter based on the modified Van Krevelan diagram (OI versus HI - Figure 4.9a) appears to show that the unit consists mostly of Type II organic matter but also possibly Type I based on the very low OI values . A second diagram on Figure 4.9 was originally published by Volk et al. (2005) plotting TMax versus HI. Although Figure 4.8 has shown that the maturity is elevated (numerous points around a TMax of 4500C), these points plot very close to the boundary of Type II to Type I source which lead Volk et al. (2005) to propose this unit as a possible source for lacustrine oils in the Foreland.

Figure 4.8: Rock Eval data for the Triassic (1) 134

4.8b 4.8a

Rock Eval data for the Triassic contains poor to good quality source rock

PI versus Tmax indicates the Triassic lies within the oil window Figuregue 4.9: 9 Rock Eval data for the Triassic ((2)) 4.9a 4.9b

Plot indicates the Triassic has elevated maturity and contains mostly Type II organic matter although is also close to the Type I boundary

Modified Van Krevelen diagram (HI versus OI) indicates the Triassic source rock contains

Type I / II organic matter 135

Figure by Volk et al (2005) with additions by author 136

Organic Petrology

As discussed earlier in this chapter, the organic constituents of any source rock are a fundamental part of understanding the generative potential of a suspected source interval. In addition to the above findings from Rock Eval, the nature of the organic matter can also be examined using organic petrology data to provide confidence in the interpretation. Organic petrology data on the Triassic is provided by Robertson Research (1990) for this interval, in addition to a more recent study by CSIRO (Volk et al. 2007). The results are summarised by interval in Table 4.4 below. Table 4.4: Kanau 1 – Organic Petrology Data from the Triassic

SAMPLE MATURITY % CALCULATED

Sample Depth (m) Sample Type Spore Colour Index Vr (Roil average%) Inertinite Vitrinite Algal Sapropel Waxy Sapropel

3350 - 3375 Ctgs (P) 70 20 * 10 3400 - 3425 Ctgs. 7.5 - 8.0 0.81(19) - - - - a/a Ctgs (P) 4.5 - 5.0C 0.46(22)C 60 20 * 20 3450 - 3470 Ctgs (P) 55 20 * 25 3477.7 Core 15 10 5 70 3478.0 Core ?8.0 0.74(8) 15 15 5 65 3478.1 Core 15 10 5 70 3478.5 Core ?8.0 0.74(22) 10 10 5 75 3485 - 3490 Ctgs. 55 25 * 20 3505 - 3519 Ctgs (P) 65 10 * 25 Results from Robertson Research (1990)

SAMPLE MATURITY MACERALS % (WHOLE ROCK BASIS) Sample Depth (m) Sample Type FAMM Vr (Roil average%) Inertinite Vitrinite Liptinite 3475.78 - 3475.87m Core 1.03 0.79 (30) 41 0.3 Results from Volk et al (2007)

KEY (P) - Picked from cuttings C = Caved (30) = number of measurements Ctgs = Cuttings

Examining the Robertson data, the descriptions report the presence of a variable proportion of waxy sapropel, from 10-75%, with several intervals demonstrating the presence of algal sapropel as a minor constituent of 5%. In general however the section contains high intertinite or non-generating macerals with roughly equal amounts of vitrinite and sapropel, leading Robertson (1990) to describe the section as dominantly containing humic kerogens and assesses the unit as a fair quality gas source rock. However, detailed inspection of Table 4.4 shows that the most intertinic rich samples are based on cuttings which are spread over an interval of 5-25m, many of which are within a coarse grained (silt to sand) facies. In contrast, the more sapropelic samples appear to be derived from core samples that are taken at individual depths and probably targeted the mudstone facies. This suggests that there are at least thin intervals of good oil potential as demonstrated by the core data, and overall a persistent sapropelic influence which varies in concentration through the section.

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A more recent study of organic petrological constituents in this section by CSIRO reports the following “the sample mainly comprises barren sandstone and siltstone with intercalated organic matter (OM)-rich, mudstone laminations. Based on visual estimation, organic matter content for the total sample is about 5.5% by volume, mostly as inertinite, but the individual OM-rich laminations contain up to 15% inertinite, 4% vitrinite and 1.5% liptinite. Although the OM consists mainly of inertinite and vitrinite derived from higher plants, the liptinite is mainly derived from algae, in part from dinoflagellate/acritarch cysts which are generally indicative of marine palaeoenvironments. Higher plant derived liptinite is a minor component and some of this is reworked”. Based on the amount of liptinite present, Volk et al. (2007) classify the rock as a poor source. Organic matter present are consistent with input of both marine and terrestrial sources. The poor source potential is likely to be related to the fact that the sample is relatively rich in coarse clastics and is over a very narrow sample interval, whereas the Robertson data shows consistency of the results over the ~70m drilled interval.

Maturity for this section appears to be in the early - mid oil window at 0.74 - 0.81 Vr, (the value of 0.46 Vr is caved). Note the maturity measurement by CSIRO is also consistent with the measured thermal maturity (0.79%). An alternative measurement (FAMM) suggests a higher level of maturity, 1.03 equivalent Vr, apparently due to vitrinite suppression due to the presence of perhydrous vitrinite (described more fully in Chapter 5).

Source Potential

Home et al. (1990) state that the ?Middle to Late Triassic is known to be have been a period of synrift tectonics in the basin, deposited along WNW-ESE grabens and half grabens. Faulting was most intense in the north in the Kubor Anticline where up to 3500m of volcanics and volcaniclastic sediments accumulated. Evidence for the synrift nature of the formation includes the restricted distribution of the unit, as well as rapid lateral thickness variations in the Kubor area observed in fault bounded outcrops.

Synrift deposits are known to often host prolific source rocks and in the case of lake sources “includes some of the worlds richest source rocks (Carrol and Bohacs, 2001). The Kanau 1 intersection of the Triassic appears to be a promising oil source.

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The Rock Eval data indicates that this source rock has fair - good potential, contains Type I-II organic matter and lies in the oil generative window. Maturity appears consistent with the Rock eval, with measurements showing mid to late oil window maturities, depending on the method used to calculate maturity of the section (Vr or FAMM). Although petrology indicates great variability and probably overall intertinic source, the presence of oil generating macerals (probably as thin laminations as waxy sapropel) in the mudstones would be consistent with Type II organic matter. The algal sapropel reported, although a minor constituent may possibly represent a non-marine algae or Type I source, but further detail is not available.

Definition of a depositional environment from examining the core indicates a probable deepwater environment with periodic clastic influx but of a sufficient depth to develop sufficient anoxia to develop source rocks. Petrology indicates a mixed depositional environment. Context for the understanding of this can be sought from other basins where the genetic features of lakes are better understood. Two aspects require further investigation for this source including; the appearance of turbidites in the sequence and coarse clastics. and the marine carbonate signature which is demonstrated by one of the oil extracts, performed by Volk et al. (2007). Figure 4.10 shows a model of a cross section through a basin in Mongolia.

Figure 4.10: Lacustrine Depositional Systems – Mongolian Basin (Slaydon and Traynor 2000)

Depositional styles of a lake sequence. These are possibly analogous to the Kanau 1 source rock, particularly the turbidite sequences encased in mud rich facies. Carbonates may also be present.

This model demonstrates key features of many lake basins, in-particular the presence of coarse clastic deposition near the lake margins in addition to the episodic

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deposition of those same clastics into deep water in the form of turbidites. This appears consistent with the features noted in the Kanau 1 core, involving still, deeper water facies within intercalated coarse clastics, some of which is up to pebble size and contains angular immature clasts. Note also the deposition of lacustrine carbonates on a basin high within the lake. Carbonates as source rocks are not uncommon in lacustrine basins and form important parts of the petroleum system, for example for fields in the Green River Formation where carbonate oil shales are the dominant source rock (Ruble et al. 2001). Carbonates were found to have higher yields and greater HI values than mudrocks in Devonian lacustrine carbonates in Scotland (Parnell and Rahman, 1990). Hence, models for carbonates within this facies exist. Their presence is also suggested a geochemical signature in the oil extract performed by Volk et al. (2007) at 3476m. Chapter 3 poses the Late Triassic Kuta Limestone as a possible source rock. This unit outcrops to the NE of the study area, behind the foldbelt. The Kuta Limestone is described as a shallow water fringing reef deposited on granite wash (Bain and McKenzie, 1975) and hence may fit into the model shown in this Figure 4.10 above, where the granite basement in the PNG instance would represent the Kubor High (Figure 1.4).

Overall the key point is that the Triassic appears to be, or has been, an oil source rock. With the Darai Plateau uplifted present day, it is likely that any generation has been switched off. It also should be noted that although this rock has reasonable source potential it seems likely that the rock originally had higher source potential which has since been spent. Prior to input of this formation to a 1D basin model, a more accurate representation of the original source characteristics is required.

Reconstruction of Original Source Potential

Equations which enable the reconstruction of original source potential prior to expulsion can be found in Peters et al. (2005) with derivations provided by Claypool (2002). In order to estimate the original potential of the Triassic source rock, the average of the measured values was calculated. These were:

PI = 0.10 . HI = 200 . TOC = 2.5%

These form the current day state of the source rock and is denoted by the use of the superscript ‘x’. Peters et al. (2005) present several equations which require these

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inputs in addition to several assumptions to perform the back calculation. The immature source is assumed to have a PI of 0.02. In addition, the original HI of the source rock must be assumed, which can be input from an already known immature source. Since a section comparable to the Kanau 1 source is known, and that the source is relatively mature (Vr% of ~0.8 to 1). Several calculations using different HI assumptions have been used. These are shown in Table 4.5 which show both a calculated TOC% as well as a calculation of thermal evolution of the source. Three different scenarios have been proposed (based on appropriate values from Table 4.3) and include:

i. Assuming a predominantly Type II source – HI = 300mgHC/gTOC

ii. Assuming a mixed Type II/III source – HI = 450 mgHC/gTOC iii. Assuming a predominantly Type I source – HI = 600mgHC/gTOC

Using these models accounts for the variability in organic matter that is observed through Rock Eval and organic petrology. Both Type II (marine) and possibly Type I organic matter appears to be present in the source. The marine aspect to the source appears present but the amount of input from Type I sources is difficult to discern based on organic petrology, but appears low based on the Robertson (1990) descriptions. Choice of a realistic calculation for the original TOC and HI requires a comparison of the maturity of the source with the calculated term ‘f’ (a measure in % source rock exhaustion). With a maturity a range of HI values (as shown in Table 4.5) ‘f’ values have been calcualted from 0.4 – 0.8 (%). Given the maturity range of 0.74 – 1.03 Vr (Table 4.4) f values of 0.67 and 0.8 are probably most realistic, corresponding to a calculated ‘original’ TOC value for the Triassic at 3 - 4% and HI of ~450 - 600. Representative values will be implemented in the Basin Modelling, performed in Chapter 5.

Table 4.5: Calculations of original TOC for the Triassic source rock – Kanau 1 Type II Organic Matter Type I/II Organic Matter Type I Organic Matter ORIGINAL POTENTIAL MEASURED POTENTIAL ORIGINAL POTENTIAL MEASURED POTENTIAL ORIGINAL POTENTIAL MEASURED POTENTIAL PI0 0.02 Pix 0.1 PI0 0.02 Pix 0.1 PI0 0.02 Pix 0.1 HI0 300 Hix 200 HI0 450 Hix 200 HI0 600 Hix 200 TOCx 2.5 TOCx 2.5 TOCx 2.5

f* 0.40 f* 0.67 f* 0.80

TOC0 = 2.79 TOC0 = 3.34 TOC0 = 4.17

0 TOC = 83.33(Hix)(TOCx) f= 1-Hix(1200-[HI0/1-PI0]) Equations from Peters et al 2005 [HI0(1-f) x 83.33-TOCx)+HIx(TOCx)] HI0(1200-[Hix/1-Pix]) Derivations by Claypool pers comm 2002

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4.6.2 Jurassic

Source potential based on Rock Eval data for the Jurassic has been established by Lund (1999) as discussed in an earlier section and hence this section will be concentrated primarily on indications of source type and maturity indicated by cross plots which were not performed in the Lund (1999) study. For this assessment three cross plots were compiled for the Jurassic section. These included: a) Source Richness – TOC% versus Potential Yield (S1 + S2) b) Source Quality - HI versus OI (otherwise known as a modified Van Krevlan diagram) c) Thermal Maturity - Production Index versus TMax

Note that for the purpose of the Jurassic assessment, source rock data was taken from areas outside the study area, as well as data from the Gulf of Papua. The purpose of using wells from a greater area has two advantages; the final source rock dataset represents a bulk result or average potential over the interval. The use of a greater study area also enables the incorporation of wells that are drilled in deep troughs which probably better reflects the true source rock facies, which was discussed in the introduction to this chapter. This approach also leads to several drawbacks, but which will be accepted for this study, including the possibility of local improvement or reduction in source quality. In addition advanced maturity may influence the source rock potential.

Magobu Formation (Early to Middle Jurassic)

Rock Eval cross plots to assess source potential for this formation are shown in Figure 4.11. Potential yield plots that the TOC for the units varies from 1 – 2%. And that source rocks in the Magobu Formation are predominantly poor to fair in quality with a small portion of the dataset rated as good quality. The OI versus HI plot indicates that the source rock consists of a mixed Type II / III source rocks with a smaller population that is probably Type IV. The PI versus TMax plot indicates that most of the Magobu source rocks are within the oil window, with several points having entered the wet gas window. Lund (1999) through regional mapping of the kerogen types within the Magobu showed that the unit contains a substantial amount of intertinite which was interpreted to be related to high maturities.

142 Figure 4.11: Rock Eval Diagrams for the Magobu Formation

Production Index versus TMax

Contamination? Contamination or migrated hydrocarbons

Rock Eval data for the Magobu indicates the source rock contains Poor to Fair source (plot 1) Type II / III organic matter (plot 2) with most samples found within the oil window (plot 3) 143

Possible free hydrocarbon (elevated S1) or contamination are indicated on the thermal maturity plot.

Barikewa Formation (Middle to Early Jurassic)

Rock Eval cross plots to assess source potential for this formation are shown in Figure 4.12. The potential yield plots show the TOC for this unit varies from 0.5 – 2.5% and indicates the source rocks are of poor to fair quality. OI versus HI or modified Van Krevlan diagram indicates the kerogen type in this formation consists of a Type II/III source as well as a Type IV source in roughly equal abundance with respect to the number of data points. The Barikewa appears to range from immature to oil window maturities with rare points in the wet gas window.

Lower Imburu Formation (Late Jurassic)

Rock Eval cross plots to assess source potential for this formation are shown in Figure 4.13. TOC for the units varies from 0.5 – 1.5% and appears to consist of substantially less points than the number of samples in the Magobu and Barikewa. Potential yield plots indicate that source rocks in the Lower Imburu Formation are predominantly poor to fair in quality with occasionally good to very good potential. The OI versus HI plot indicates that the source rock consists of a mixed Type II / III and minor Type IV. The PI versus TMax plot indicates that most of the Lower Imburu source rocks are immature, but a smaller proportion appears to be within the oil window. Possible free hydrocarbon (elevated S1) or contamination are indicated on the thermal maturity plot.

4.6.3 Cretaceous

Lower Ieru Formation (Early Cretaceous)

Rock Eval cross plots to assess source potential for this formation are shown in Figure 4.14. The potential yield plots indicate that the TOC for this unit varies from 0.5 – 2.5% and that the source rocks are of poor quality. OI versus HI diagram indicates the kerogen type in this formation consists of Type IV kerogen with minor Type III. The Lower Ieru appears to range from immature to oil window maturities.

144 Figure 4.12: Rock Eval Diagrams for the Barikewa Formation

Production Index versus TMax

Contamination or migrated hydrocarbons

Rock Eval data for the Barikewa indicates the source rock contains Poor to Fair source (plot 1) Type II / III and IV organic matter (plot 2) with most samples immature to within the oil window (plot 3) Figure 4.13: Rock Eval Diagrams for the Lower Imburu Formation

Production Index versus TMax

Contamination?

Contamination or migrated hydrocarbons

Rock Eval data for the Lower Imburu indicates the source rock contains Poor to Fair with occasionally 145 good source (plot 1) Type II / III and minor type IV organic matter (plot 2) with most samples immature with a small proportion of samples within the oil window (plot 3) 146

Figure 4.14: Rock Eval Diagrams for the Lower Ieru Formation

Production Index versus TMax

ContaminationCoContntamamininatatioion oro migratedmigrated hydrocarbonshyydrocarbons

Contamination?

Rock Eval data for the Lower Ieru indicates the source rock contains predominantly poor source rock (plot 1) Type IV with minor type III organic matter (plot 2) with most samples immature to within the oil window (plot 3) 147

Upper Ieru Formation (Late Cretaceous)

Review of this dataset is important for understanding the origin of an apparent marine carbonate source rock which contains the Late Cretaceous to Tertiary biomarker oleanane. However, upon compilation, a very small amount of source rock data is available for the Upper Ieru, but nevertheless show very low TOC values for this unit (multispinum zone, figure 4.8 and 4.9) with only a single Rock Eval point exceeding 200. This single point belongs to the well Darai 1 on the Darai Plateau. The sample having a TOC of 1.3%, HI of 318 and OI of 392. Review of the lithology is described as an argillaceous sandstone, however minor limestone is also reported. The organic petrology reports minor intertinite (25%) and dominant vitrinite (75%) which together imply a gas prone source. However, It could be speculated that the appearance of limestones in a section with HI capable of oil potential (>200) may present the possibility of oil source rock in this section and hence a possible source rock for the Family C oil described in Chapter 3. Much more work would need to be done to firm up this conclusion. This lack of sample is most likely due to the fact that the Base Darai unconformity has cut down onto the Ieru surface with the oldest rocks below this surface usually of Cenomanian age. Hence source rocks which were once deposited in the Turonian to Maastriachtian and then subsequently removed cannot be ruled out. It is important to note that these sections are preserved in the PNG Foldbelt as well as in the East Papuan Basin. Hence, the presence of source in the Upper Ieru in the Foreland hence remains uncertain.

4.6.4 Coal Source Rocks

The Rock Eval dataset contains six intervals which appear to constitute coals or coaly shales with significant TOC values. Note that Peters and Cassa (1994) technically classify a coal as containing >50% TOC but also considered in this section will be fine grained rocks where organic material is abundant but contain >30% TOC. The six organic rich intervals identified are summarised in Table 4.6. Table 4.6 shows that three of these intervals occur within the Magobu Formation and one each are shown to occur within the Barikewa, Lower Imburu and Lower Ieru. Note the TOC refers to a single point or cuttings interval, however it is apparent from a review of the lithological descriptions that some of these coals are developed over significant intervals.

TABLE 4.6: SUMMARY OF COALS AND HIGH TOC% SOURCE ROCKS WELL METRES (md) TOC% FORMATION AGE CUTTINGS DESCRIPTIONS (bold = probable gross thickness of coal)

Goari 1 2095 31 LOWER IERU lubrookiae - torynum Carbonaceous matter commonly reported from 2030 - 2165. Very prominent in cuttings from 2110 - 2165m (55m)

Mutare 1 1035 58 LOWER IMBURU pellucida - jurassica ? Thin band of lignite at 1035m. Common black coal reported in cuttings from 1261m - 1285m (24m)

Morigio 1 3468 35 BARIKEWA spectabilis - aemula Minimal information. Probably thin coal ~50m but likely less.

Aramia 1 1937 55 MAGOBU indotata Carbonaceous shales, sandstones and thin coals from 1937 - 1970 (33m)

Komewu 2 2862 27 MAGOBU halosa Predominantly coal from 2844 - 2937m (93m) interbedded with sandstones, mudstones and siltstones

Magobu Island 1 2391 54 MAGOBU complex Described as rare coal seams in the interval 2365 - 2574m (209m)

DESCRIPTIONS FROM FOLLOWING (RESPECTIVELY IN WELL ORDER):

ESSO Papua New Guinea (1979) Hawkins et al. (1964) OPIC (1989) Jefferies (1956) Sticpewich et al. (1958) 148 Hocking et al. (1971) 149

Termed here gross coal thickness, the coals based on well penetrations range from approximately 24 – 209m Since most coal bearing zones are reported from cuttings returns, it is difficult to discern the thickness of individual seams, but based on well completions reports for each respective well, most appear to be relatively thin bands within an overall gross coal zone, such that the net coal to the thickness of the zone appears low. The Komewu 2 coal appears to be an exception, containing an interval from 2844 – 2937m (93m) described as coals interbedded with sandstones, mudstones and siltstones.

Rock Eval Results

Source quality diagrams were plotted for the coals and coaly shales to investigate their oil potential. These graphs are shown in Figure 4.15 (a+b) and include OI versus HI and PI versus TMax only (TOC is too high to use potential index plot). The modified van Krevelen plot (OI vs HI) show that the coals and coaly shales fall into two groups: the first, which all belong to the Magobu Formation appear to be oil prone with high HI (283- 486) and low OI values (9-12) and are probably Type II source rocks based on their position on the plot near the Type II kerogen boundary. The second group belonging to the Barikewa, Lower Imburu and Lower Ieru formations appear to be Type III source rocks and hence are likely gas generating, with relatively low HI (70-159) and high OI (53-116). The PI versus TMax plot demonstrates that the coals encountered are immature with the exception of the Komewu 2 coal which has entered the oil window, but the low PI indicating S1 or free hydrocarbon enrichment. Figure 4.15 (a+b) suggests that for the Type III sources, despite a high TOC the type of organic matter within these sources would generate little oil and is not simply due to overmaturity surpressing the original source potential. A review of the Robertson Research study (1990) for the apparent ‘gas prone’ coals shows no organic petrology results to check the intepretation. These are interpreted to have no oil potential. Focusing on the coals and coaly shales with oil potential belonging to the Magobu, additional information is available to establish the nature of these sources. Pyrolysis Gas Chromatography (PyGC) is a method of pyrolysing microgram quantities of solvent extracted kerogens from a source rock which provides a chromatographic ‘fingerprint’ which can be used to indicate the kerogen type (Larter and Douglas, 1980). A diagram below (Figure 4.16,

Figure 4.15 - Source Rock Quality Plots for coals and coaly shales 150

4.15a 4.15b

All coals are immature with the exception of a single Halosa age coal (Komewu 2) which is mature - but possibly enriched with hydrocarbon

Type II oil prone coals belonging to Magobu

Gas prone Type III coals

Barikewa Lower Imburu Lower Ieru 151

Figure 4.16: Pyrolysis GC responses for typical source rock types. Dembicki (2009)

UCM (Unresolved Complex Mixture)

Dembicki 2009) shows the results and characteristics of a typical Type I, Type II and Type III kerogen. The following summary of PyGC features is taken from Dembicki (2009). The pyrolysis products of the oil prone Type I and II kerogens typically extend out to the high molecular weight compounds >C15. Type I kerogen produces abundant long chained n-alkanes as well as n-alkenes (prominent peaks in >C15 range). Type II is similar but characterised by more napthenic components (see UCM) whereas type III gas prone kerogens show the bulk of the pyrolysis in the

Other information that can be used in addition to the fingerprint of each source type is the use of ratios that can be derived from this information. Larter and Douglas (1980) devised an index of m-xlylene/n-octene which serves as an indicator of kerogen type. Geotech lab (C.Barber pers comm. 2007, Appendix 9.4) has also provided a series of guidelines for further interrogating PyGC data. Pyrolysis GC plots for the Komewu 2

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cannel coal and Aramia 1 coaly canneloid shale are shown on Figure 4.17 and 4.18 respectively. The calculated data derived from the PyGC output are shown including the m-xlylene/n-octene index, Gas to Oil Generation Index ((C1-C5)/C6+) and n-alkane

+ n-alkene abundance index (sum of C15-C31). Cutoffs for these various indicators are shown on the figures. Results show that both Komewu 2 and Aramia 1 contain high molecular weight range hydrocarbons, however Aramia 1 shows a large unresolved hump characteristic of Type II sources. The indices provided by Geotech show that both are oil prone sources and for Komewu 2 the m-xlylene/n-octene ratio correctly indicates sporinite is a dominant maceral within the cannel coal, when compared to the organic petrology results (CSIRO,2007). Table 4.1b indicates that sporinite is a Type II maceral. However other Type II macerals are also in abundance as well as a suberinite portion, an oil generating liptinite maceral (Sherwood,2006). The Komewu 2 cannel coal appears to be highly oil prone and appears to be a Type II source rock based on organic constituents and PyGC data. However, it is noted that a large portion of the organic matter is gas generating – non generative (proportion of vitrinite and intertinite present) hence suggesting a proportion of gas would be contributed along with oil upon maturation.

The presence of oil staining gives good evidence for the Aramia 1 coal as an oil source rock, however the organic petrology indicates a mixed contribution of organic matter with a vitrinite dominated assemblage consistent with the m-xlylene/n-octene ratio. Overall a mixed petrology with neglibible intertinite and an assemblage dominated by vitrinite with lesser liptinites of Type II origin (liptodetrinite and sporinite – shown in Table 4.1b). This is somewhat reflected in the PyGC signature with prominent long chains in the > C15 fraction. However, in contrast to the organic petrology peaks in the C15 and beyond C20 tends to suggest the presence of an algal or Type I input. However, no algal material is described in the organic petrology. Based on the empirical evidence of oil staining, the presence of Type II macerals as well as the largely oil prone Py GC results, this source is interpreted as a Type II-III source containing lower amounts of Type I organic matter. The absence of Type I macerals from organic petrology might be explained by fine dispersal of this material through the source which may lead to the maceral being unnoticed.

FIGURE 4.17 : SUMMARY OF PYROLYSIS GC DATA AND INTERPRETIVE RATIOS FOR THE KOMEWU 2 COAL (HALOSA AGE - MAGOBU) 153

Depth (mMD) 2862 C15-C31 * 9.78 C1-C5/C6 # 0.32 mX/nO^ 0.85 Interpretation Oil Prone, Sporinite Macerals TOC % 27 HI 416 OI 7

ORGANIC PETROLOGY (CSIRO 2007) Shaly cannel coal. Abundant suberinite, abundant sporinite, abundant liptodetrinite, abundant cutinite, sparse resinite, possible rare Botryococcus related telalginite. Abundant pyrite, abundant iron oxides. Note: About 30% of the vitrinite is suberinitic

MACERAL GROUP ABUNDANCE % (Whole Rock Basis) LIPTINITE 12 VITRINITE 45 INTERTINITE 15

Relative Abundance TOTAL 75

Alkane + Alkene Abundance* Gas/Oil Generation Index # m-p-xylene/n-octene ^ >5 Oil Prone <0.5 Oil Prone Alginites <0.4 <5 Gas Prone >0.5 Gas Prone Sporinite 0.4 - 1.3 Vitrinites 1.3 - 20 GEOTECH CUTOFFS (2007) GEOTECH CUTOFFS (2007) Larter and Douglas 1979 Retention Time FIGURE 4.18 : SUMMARY OF PYROLYSIS GC DATA AND INTERPRETIVE RATIOS FOR THE ARAMIA 1 COAL (INDOTATA AGE - MAGOBU) 154 Depth (mMD) 1937 C15-C31 * 7.44 C1-C5/C6 # 0.35 mX/nO^ 2.55 Interpretation Oil prone, Vitrinite Macerals TOC % 55 HI 385 OI 9

MACERAL GROUP ABUNDANCE % (Whole Rock Basis) LIPTINITE 14 VITRINITE 55 INTERTINITE 2 TOTAL 71

ORGANIC PETROLOGY (CSIRO 2007)

Relative Abundance Coaly canneloid shale. 3% liptodetrinite, 3% sporinite, 5% cutinite, 1% resinite, 2% suberinite. Common vitrinite derived from leaf tissue. Rare oil droplets, including fluid inclusions, generally ~1-5 μm in diameter Sparse oil stains on vitrinite. Abundant pyrite, abundant iron oxides

4.6.5 Algal Source Rocks

The ECL study (2005) reviewed organic petrology data from the study area and pointed out that zones rich in algal matter have been observed by organic petrology. Several wells from the region were pointed out to contain algal rich sediment. They indicate that the nature of the organic matter explains the lacustrine character of some of the oils recovered and hence are potential source rocks for these hydrocarbons.

Chapter 3 described a good oil to source correlation for the Kanau 1 Triassic section to the Koko 1 oil, thus presenting a source rock for oils from Family L. Nevertheless an assessment will be made here for an alternative source model for Family L oils.

The algal matter reported was identified in several wells in the Foreland, more than to be described here including Bujon 1 and Koko 1. However, the Kimu 1 well is used as an example in this section to test the link between the organic constituents and source rock quality.

Table 4.7 summarises the organic petrological constituents of the Cretaceous to Jurassic section of the Kimu 1 well. To assess source potential the measured TOC is also shown against each sample where available. A generally common organic constituent in this well is a maceral known as lamalginite. Cook and Sherwood (1991) defines this organic matter as belonging to a family which include the Green River Formation, a Type I source rock. At 1739m and 2239m another distinctive organic constituent occurs. Although only reported as ‘rare’ in abundance, Botryococcus species is related fresh – brackish waters in lacustrine settings (Cook and Sherwood, 1991). Liptodetrinite is also reported throughout the section, which is also an oil prone Type II source rock (see Table 4.1). There is a general pattern to the information displayed on Table 4.7. Where the lamalginite proportion is common to abundant, the TOC value is typically near or greater than 1%, the oil source cut off for this study. Conversely where sparse lamalginite occurs, the TOC% is slightly lower eg 1782m. The samples shown on this table were plotted using source potential plots as previous treatment of source rocks. Figure 4.19 shows the results which indicates that these samples almost entirely rate as poor source rocks and that the OI versus HI plot shows the organic matter is probably Type II. The source quality appears to be best in the sample from 2239m which contains botryoccocus as shown by the HI value (272)

TABLE 4.7: SUMMARY OF ORGANIC PETROLOGY DATA FOR KIMU 1 AGAINST MEASURED TOC% KIMU-1 Sample Alg. Wxy. Exi Formation Inert. Vit. Dom. Description TOC% Depth Sap. Sap. (Liptinite) 0.79 1614 sparse rare sparse L>I>V Sparse lamal and liptodet. Veryhachium species present. Rare dull orange fluor bitumen Lower Ieru (Alene) 1645 rare rare abundant L>I>V Abundant lamalginite and liptodetrinite 1690 sparse rare-sparse abundant L>I>V Abundant lamalginite and liptodetrinite. Rare dull orange fluorescing bitumen 1713 sparse rare-sparse common L>I>V Comm lamal, sparse liptodet, rare Botryococcus-related telalginite.Coalified leaf tissues 0.90 Toro 0.21 1782 rare rare sparse L>V>I Sparse lamalginite and liptodetrinite. Upper Imburu 1849 rare rare sparse L>V>I Sparse lamalginite and liptodetrinite. Sparse yellow oil drops Upper Imburu (Hedinia) 1921 rare rare sparse L>V>I Sparse lamalginite and liptodetrinite. 1.07 Upper Imburu (Iagifu) 1967 sparse sparse abundant L>I>V Common lamalginite and liptodetrinite 0.95 Lower Imburu (ss) 2017 sparse sparse sparse L>V>I Sparse lamalginite and liptodetrinite. 0.84 2040.5 rare-sparse sparse sparse L>V>I Common lamalginite and liptodetrinite. Rare dull orange fluorescing bitumen 1.06 Lower Imburu 2127.8 sparse rare abundant L>>I>V Abund lamal and comm liptodet. Rare dull or fluor bitumen. Rare ylw fluor intersitial oil drops 1.29* Koi Iange 2165.5 sparse sparse abundant L>>I>V Abundant lamalginite and sparse liptodetrinite. Rare dull orange fluor bitumen. 1.73 2239 sparse common abundant L>>I>V Abundant lamalginite and common liptodetrinite, rare Botryococcus-related telalginite 1.02 Barikewa 2260 sparse sparse sparse L>I>V Sparse lamalginite and liptodetrinite Sample Exceeds oil source cut off (1%)

* Py GC Available (Fig 4.19) Petrology Data Table modified from ECL (2005) based on results by Alexander (1999)

Organic petrology assessment of the Cretaceous to Jurassic (Alene to Barikewa) with formations shown against organic matter observed in each sample. Note the elevated TOC (>1%) commonly associated with samples containing common to abundant lamalginite (as yellow). The TOC is highest in the sample at 2239m containing both abundant lamalginite common liptodetrinite as well as Botryococcus, a freshwater to brackish algae 156 157

but this sample still only rates as a fair source rock (Figure 4.19). The TMax versus PI plot indicates that these samples are immature, which is consistent with the mid mature maturation levels measured during organic petrology work (Alexander 1999). Source potential was also assessed by review of a single PyGC result which is derived from a sidewall core sample at 2165.5m. The sample has a TOC of 1.29% a HI of 229mgHC/gTOC and contains abundant lamalginite and sparse liptodetrinite. The PyGC trace for this sample is shown on Figure 4.20, alongside several ratios similar to the earlier assessment in 4.6.4 on coals. The PyGC trace dominantly contains low carbon constituents and minimal abundance of long chain hydrocarbons. The alkane to alkene abundance as well as gas to oil generation index indicate a gas prone source rock. However the m-p-xylene/n-octene ratio correctly indicates that the sample contains predominantly alginite. These results appear inconsistent with one another since an alginite rich rock (66% of the organic matter) would likely be oil prone but the PyGC ratios indicate a gas prone source rock. In conclusion, there is good evidence that organic enrichment in these rocks, particularly for the Lower Imburu, Koi-Iange and Barikewa could represent at least poor-fair quality source rocks based on TOC% and Rock Eval pyrolysis data. However, the HI index and TOC% these rocks are not of the overall intensity that would be expected of a lacustrine source rock. For example lacustrine oil shales in the Canadian Arctic Archipelago have TOC of 1 – 44% with HI values typically ranging from 300 – 800gHC/gTOC (Goodarzi 1987). Type I sources in the Green River Formation have characteristics of 1 – 59% TOC and HI from 55 – 985gHC/gTOC (Caroll and Bohacs 2001). The single PyGC analysis that is available indicates that although the samples are rich in algal organic matter they are essentially gas prone which is consistent with the HI values which are generally ~200 gHC/gTOC. A possible explanation for the results is that although the samples are organic rich, the type of organic matter within the algae is not hydrogen rich either due to the species of algae or alternatively a secondary process has reduced the kerogen quality. Note also based on Chapter 3, no oils from lacustrine Family L were interpreted to be present in Kimu 1. The results cannot rule out the possibility that these same source intervals could be better quality in deeper portions of the basin and could represent sources for the Family L oils, but based on this study and the data studies from Kimu 1 it is considered unlikely, but further analysis on this well, or other wells could review this conclusion further.

FIGURE 4.19: Kimu 1 - Py GC Results from sample at 2165.5m PYGC RATIOS Depth (mMD) 2165.5 C15-C31 * 3.55 C1-C5/C6 # 0.82 mX/nO^ 0.19 Interpretation Gas Prone Alginite Macerals TOC % 1.29 HI 225 Low molecular weight peaks dominant OI 27 Py GC plot, suggesting a gas prone source MACERAL GROUP ABUNDANCE % (proportion of organic matter) ALGINITE 66 EXINITE 15 VITRINITE 6 INTERTINITE 13 Very few long chains present TOTAL 100 in >C15 range suggesting low oil (ALEXANDER 1999) potential Relative Abundance

Alkane + Alkene Abundance* Gas/Oil Generation Index # m-p-xylene/n-octene ^ >5 Oil Prone <0.5 Oil Prone Alginites <0.4 <5 Gas Prone >0.5 Gas Prone Sporinite 0.4 - 1.3 C8 C12 C15 C17 C23 Vitrinites 1.3 - 20 GEOTECH CUTOFFS (2007) GEOTECH CUTOFFS (2007) Larter and Douglas 1980 Retention Time 158 159

Note that the concept of gypsiferous shales in the Oligocene-Miocene Carbonates was also a concept of sourcing lake oils suggested by Volk et al. (2005). This conclusion is based on the report of an evaporite within the basal portion of the Darai Limestone at Aramia 1, and given the hypersaline nature of the depositional environment interpreted for the oil, this is a possible candidate. Communication with CSIRO (T.Allan pers comm., 2008) following a review of cuttings samples, now suggests that an evaporite was mis-reported in the completion reports from this interval. The sample is a carbonate or calcarenite.

4.7 Summary

The following table summarises the sources described in this chapter, their kerogen types as well as their probable source quality values. The chapter has demonstrated that several of the oil families identified in Chapter 3 have viable source rocks.

TABLE 4.8: GENERAL SOURCE CHARACTERISTICS FROM ROCK EVAL DATA (BULK RANGE OF MOST DATA)

FORMATION TOC% HI (mghc/TOC rock) Organic Matter (Source Type)

LOWER IERU 0.5 - 1.0 100-250 Type III (minor Type II)

LOWER IMBURU 0.5 - 1.5 150-500 Type II / III (minor Type IV)

BARIKEWA 0.5 - 2.5 150-450 Type II / III / IV Algal Source Rocks* 1.3 - 1.7 272 - 225 Uncertain - Type II or Type III

MAGOBU 1 - 2.0 200-500 Type II / III / IV COALS - Oil Prone 27 - 55% 283 - 416 Type II or Type II/III COALS - Gas Prone 31 - 57% 70 - 159 Type III

TRIASSIC 1.5 - 3 100-300 Type I / II * Refers to best source rocks identified

The chapter has satisfactorily explained the presence of source rocks in intervals as suspected in Chapter 3, particularly for the Triassic and Jurassic. In addition, rich source rocks in the form of coals which are oil to oil - gas prone offer liquids potential. Algal rich units, which are richest in the Barikewa have also been identified which, based on limited Rock Eval and PyGC data appear to be gas prone at Kimu 1. What has not been explained in this section is the likelihood of source in the Late Cretaceous which may be a viable source for Family C, since geochemical data contains oleanane and have a carbonate signature (Chapter 3). Insufficient data is available to evaluate this, with only a single sample hinting that at possible oil prone source presence but much more data is required to draw a firm conclusion.

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5 BASIN MODELLING

The main aim of basin modelling is to attempt to estimate what source rocks within a petroleum basin are likely to be mature and their time of peak expulsion. More detailed studies, involving 2D or even 3D modelling are used to estimate actual volumes of petroleum generated. This information reduces risk. However, due to the nature of modelling such locations, typically basinal deeps which rarely contain wells, assumptions or extrapolations must be made with regards to the geological history and thermal conditions of the rocks to be modeled. These can be handled in modern basin modelling packages, and in this thesis the programme BasinMod 1D™ is used, a well known package used in industry.

The process of basin modeling is briefly summarised by Waples et al. (1992). The approach begins with the inputting, to a computer model; stratigraphic unit tops, ages, lithologies present in each unit, erosion estimates, hiatuses and temperature data. The incorporation of compaction effects in the modeling requires porosity and lithology information from each stratigraphic unit. Heat flow, when selected to generate the temperature gradient is improved by rock conductivity data (if available) and by accurate temperature data from the well. Thermal maturation data are usefull in assessing heat flow changes through time. Finally, consideration of kinetics for source rocks are required through an estimate of the kerogen type.

Figure 5.1 shows a workflow diagram for the approach used in basin modeling. After the above data has been inputted, the model is calibrated against temperatures in the well using depth versus temperature plots, where the computed profile is compared with actual data and modifications made to heatflow / conductivity, possibly using multiple iterations, until a reasonable match achieved. Computed and observed maturity data are then compared in order to assess heat flow and surface temperature changes through time. The amount of missing section in unconformities and the length of hiatuses might also be evaluated with the maturity data if poorly known. Once these constraints are established, the modeling of petroleum generation as a function of time can then be predicted.

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Figure 5.1: A workflow digram to demonstrate the approach used in Basin Modelling (Prayitno et al 1992)

A NOTE: This figure/table/image has been removed

to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Figure outlines the steps used in Basin Modelling which include: Inputting geological geothermal and geochemical data, calculating heat flow, computing results, calibrating to the data (possibly through multiple iterations) and finally using the best fit geological model to derive the burial, maturity and thermal history.

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5.1 Overview of Previous Work

Workers assessing prospectivity of the Foreland have rarely used basin modeling in their evaluations. Studies of significance to the region on source rock maturity are broken into two sets: a) Maturity mapping by Hulse and Harris (2000) and basin modeling by Barndollar (1993) and Lund et al. (1998). b) Insights from Fission Track studies (Geotrack, 1991; Hill and Gleadow 1989; Hill and Gleadow 1990). A re-analysis of data from the 1991 study, pertaining to the Kanau 1 well is also available (Green, 2001)

The most comprehensive study of basin modeling in the Foreland is that of Lund et al. (1998). The study used measured downhole temperature data and a combination of thermal history indicators utilized within the modeling programme BasinMod 1D™ to derive a model of thermal and burial history in the Foreland. The approach and results of this study will be discussed here, with relevant insights from the other studies mentioned as appropriate. The products of Lund et al. (1998) were eighteen well models and ten depocentre – ‘pseudo’ models were used to evaluate the thermal history. The area studied is shown in Figure 5.3, with the current study area marked. The workflow for developing the thermal model was as follows:

• Collection of stratigraphy, lithology and temperature data for each well

• Collection of thermal history data. These included vitrinite reflectance (Vr), pyrolysis TMax, fluorescence alteration of multiple maceral data (FAMM) and apatite fission track data (AFTA)

• Compilation of historical data such as heat flow, water depths, surface temperatures, uplift and erosion rates / amounts and fluid flow. These were based on the geological history.

• Source rock potential data based on Rock Eval, as developed by Lund (1999)

• Seismic mapping to guide the recognition of depocentres and the placement of pseudo well models and to estimate the amount of Late Cretaceous erosion.

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Figure 5.2: Wells (coloured red) used in 1998 Basin Modelling Study (Lund et al 1998). The current study area shown in dashed outline.

A NOTE: This figure/table/image has been removed

to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

The calibration and modeling was achieved in BasinMod 1D™, a programme commonly used in industry to model burial history and petroleum generation through time.

Results of the Lund et al. (1998) basin modeling on the Foreland are as follows: In general terms across the Foreland a three phase hydrocarbon generation history is present, which comprises Late Jurassic (Gulf of Papua only), Late Cretaceous and Late Tertiary events. Relevant to the current study is the importance of the Omati Trough (see Figure 5.4) as a depocentre, particularly as a source of late charge in the region. Two distinct periods of kerogen transformation are present in the Latest Jurassic / Cretaceous and Late Tertiary (Miocene) from Magobu, Barikewa and Lower Imburu source rocks. A typical generation history for the Omati Trough, shown as an example from Kamusi 1, a well within the study area, is shown in Figure 5.2. Note that the vertical axis, “The transformation ratio (TR), the ratio of kerogen already transformed versus the total petroleum generation potential,

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Figure 5.3: Transformation Ratio plot for Jurassic source rocks at Kamusi 1

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

is used to indicate maturity and ranges from 0 to 100% converted in the source rock” (Platte River, 2006). A nominal cut off is applied used using values of 0 - 0.3 TR to indicate generation and > 0.3 expulsion. Figure 5.2 shows that the Magobu Coal Measures have generated significant hydrocarbons (oil plus gas) with most of the expulsion occurring in the Late Cretaceous to earliest Tertiary. Only smaller amounts occur during the Late Tertiary. In contrast, for the Barikewa and Lower Imburu sources, generation began in the Late Cretaceous to Early Tertiary, but significant expulsion did not occur until the Late Miocene to Pliocene. The regional maturity at Late Cretaceous time and Present Day (end Pliocene) for the Magobu and Barikewa source rock respectively is shown in Figure 5.4.

Figure 5.4: Maturity maps for the Barikewa and Magobu Formations. (From Waples et al., 1998 with annotations added). Study area in red boxes. Barikewa Maturity (present day) Base Magobu Maturity (Late Cretaceous)

Omati Trough

Trough

Wabuda

Maps show the widespread oil mature nature of the Barikewa (left) in both the Omati and Wabuda Troughs. The Magobu is oil mature in shallow reaches, with the source rock lying within the gas window over much of the Omati Trough and Gulf of Papua. Hydrocarbon drainage directions out of the Omati Trough are 165 shown in red arrows for the Barikewa. Present Day Migration Vectors 166

Predominant migration directions for the hydrocarbons indicated by the study are marked, which show the Omati Trough expelled hydrocarbons to the north, to the west and to the south. The Wabuda Trough is described to have expelled hydrocarbons to the west. For the Magobu map, migration directions are not described for the Cretaceous events, but clearly a significant proportion of the Foreland was oil mature, with deeper portions generating gas. Lund et al.. (1998) point out that ancient structures such as the Bosavi Arch are well placed to have captured the migrating hydrocarbons from both early and late charge phases. Young structures formed prior to the end for the Miocene would be necessary to capture the late phase of migration.

The importance of the Omati Trough was also suggested by Barndollar (1993) who also recognised Cretaceous (65Ma) and Early Miocene (22Ma) charge events. The results are slightly different to the Lund et al. (1998) study since the author notes that for the Jurassic interval (modeled as a single source) the Early Miocene event has higher rates of generation, whereas the earlier event only reaches early maturity and may not have resulted in sufficient expulsion to be significant. Hulse and Harris (2000) use temperature mapping and regional structure maps to indicate mature depocentres. They highlight the present day maturity of the trough at the LJ9 biozone (Lower Imburu) in addition to areas north of the Darai Plateau buried beneath the presently developing PNG Foldbelt, which was thought to charge the plateau. This concept was tested by the Bosavi 1 well drilled on a valid structure on the Darai Plateau but which failed to encounter hydrocarbons.

Fission tracks analysis are based on the observation that the crystal lattices of some minerals preserves the scars of spontaneous nuclear fission events. This enables their use as natural thermometers, that unlike most thermal indicates is the only thermal indicator that preserves information on the ‘timing’ of past thermal events (Beardsmore and Cull 2001). Further detail on the use of this tool is given in Appendix 9.6. Fission track studies (Duddy et al. 1991) suggest that the Papuan Basin has experienced four episodes of elevated paleotemperatures, occurring during the Permo-Triassic, Late Cretaceous-Early Tertiary, Pliocene and at the present day. Note that these studies, particularly for the Late Cretaceous – Early Tertiary, suggest that the maximum heating was probably due to either deep burial or an increase in heat flow (Duddy et al. 1991, Hill and Gleadow, 1990). This has implications for the way in which the basin modeling is handled and will be discussed further in the calibration section of this chapter.

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5.2 Definitions

An array of different thermal history indicators are at the disposal of modelers to predict the petroleum generation history of a basin. The use of several different indicators in conjunction with geological evidence provides a series of constraints from which the most reasonable burial history can be constructed. The indicators that will be used in this thesis include Vitrinite Reflectance (Vr), FAMM (Fluorescence Alteration of Multiple Macerals), Temperature at Maximum S2 (TMax) & AFTA (Apatite Fission Track Analysis). Measurements of BHT (bottom hole temperature) values are also important to understanding the present day temperature profile which are also integrated into the model. Where possible, these BHT values are upward corrected using a Horner Plot. Note that the background to each of the above terms and Horner Plot corrections is given in Appendix 9.6.

5.3 Modelling Locations

Chapter 3 demonstrated the complexity of the charge history within the study area which shows that multiple oil source rocks appear to have been active. These oils record variable residence times, from old biodegraded charges to fresh, possibly from more recent oil charges. Chapter 4 evaluated source potential in the region which indicated that there are candidates for generating each oil or at least a theorised position on the stratigraphy.

The more complex charge history of the region appears to be found in the north of the study area surrounding the Kimu gas discovery. Hence the complex oil history, in addition to gas charges has meant that the basin modeling will be focused on the Turama River region of the study area to explain the oils recovered oils from both wells and oil seeps.

The objectives of this work are as follows:

1) To investigate if the identified source rocks have reached sufficient maturity to expel oil

2) Understand the timing of oil expulsion from these source rocks

3) Construct a charge history chart for the various 1D basin models indicating the timing of explusion for the various source rocks

168

Basin modelling has been performed on three locations which are shown on Figure 5.5. These include:

• Kanau 1 - a well on the Darai Plateau.

• Omati Trough 1 – a pseudomodel using nearby well data and seismic on line PN91-124

• Omati Trough 2 – a pseudomodel simulating thicker tertiary burial using seismic data from PN90-109x and extrapolated stratigraphy from Omati Trough 1

• North Paibuna - a 1D basin model not modeled for hydrocarbon generation but used to establish a value for the Foreland regional heat flow. This is further explained later.

Figure 5.5: Map showing the Turama River portion of the study area and the location of basin models (red) and those which provide calibration data (grey) and seismic Data.

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Basement colourfill (depth - metres) provided courtesy of Oil Search Limited

169

The well model Kanau 1 and Omati Trough 1 pseudowell location were picked on the basis of their proximity to ancient basement faults which demonstrate stratigraphic thickening and for which there is adequate seismic or well evidence for a synrift depocentre. Omati Trough 2 is a nominal location, in the deeper portion of the Omati trough but where thickening of the Darai Limestone relative to Omati Trough 1 can be seen on seismic. The construction of basin models for these wells and pseudowells are explained in the following sections.

5.4 Data

A summary of data used for modeling the burial history in the wells / pseudo-wells are summarized in Table 5.1 below.

Table 5.1: Summary of thermal history data used in study

BHT TEMP(oC) DST TEMP (oC) SOURCE Komewu 2 X STICPEWICH J.C 1958 Kanau 1 NU Brereton (1976) Kamusi 1 X CNODC (1996) North Paibuna 1 X SANTA FE ENERGY RESOURCES (1994) Vr% Komewu 2 Robertson Research (1990) Sherwood (2007) Kanau 1 Volk et al (2007) Swift (1980) Kamusi 1 CNODC (1996) North Paibuna 1 Scotchmer (1994)

FAMM Komewu 2 Sherwood (2007) Kanau 1 Volk et al (2007) Kamusi 1 Sherwood (1997) North Paibuna 1 Faiz et al. (1997)

ROCK EVAL TMAX Komewu 2 Geotech (1998) Geotech (2007) Kanau 1 Geotech (1998) Geotech (2007) Kamusi 1 CNODC (1996) North Paibuna 1 Geotech (1998) Geotech (2007) AFTA Komewu 2 Duddy et al (1991) Kanau 1 Green (2001) Kamusi 1 X North Paibuna 1 X

/ X / NU DATA AVAILABLE / NOT AVAILABLE / NOT USABLE (SEE TEXT)

NU Not Used BHT Bottom Hole Temperature (from wireline log) Vr% Vitrinite Reflectance TMax Temperature at maximum S2 peak FAMM Fluorescence Alteration of Multiple Maceral technique AFTA Apatite Fission Track Data

An summary of each key well for the modelling study is as follows:

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Kanau 1 – Drills a full stratigraphic section. Comprehensive thermal history data available

Komewu 2 – Comprehensive suite of thermal history data which includes Fission Track. Used to complement the data at Kamusi 1

Kamusi 1 – Located above the synrift sequence. Pseudo stratigraphy was added below well. Basic thermal history data available

North Paibuna 1 – Temperature, Vr and FAMM data available

Raw data for all items listed in the table can be found in Appendix 9.5

5.5 Basin Modelling

Modelling Assumptions

Table 5.2 below outlines the various assumptions that were used in the original basin modelling study (Waples et al. 1998). As noted below, many of the original assumptions have been utilized in the current study, with a couple of key exceptions. These adjustments were implemented to emphasise a simple model in approach and only adding complexity where necessary.

Temperatures – Horner plots to correct BHT values were used however emphasis was placed on using the well history as closely as possible and reviewing drilling reports, the process more fully described in Appendix 9.6. Horner plots are a generally acceptable form of temperature correction for many basins. This is in contrast to Waples et al. (1998), where values of 40 for all values of tc (circulation time) were used, or upward corrections of 9% from Horner corrected results were implemented. A preference for either method cannot really be developed without additional DST temperatures from the dataset to provide a detailed guide into appropriate temperature corrections. Note that only one DST temperature was available. DST readings are valuable as they tend to measure pristine temperatures from fluid drawn in distant from the borehole. In this case the DST temperature from Kanau 1 was measured at 92oC. This was dismissed on the basis that the BHT values recorded in this same interval were measured at ~50oC which would require a large and highly unlikely correction of ~80% to match the DST temperature.

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Table 5.2: Comparison of basin modelling assumptions from Lund et al. (1998) and the current study Assumption (1998) Approach Assumption 2009 (grey = alteration to 1998 study) Present Day Temperatures Calculated using transient heat As left flow option

Paleosurface Temperatures Derived from paleolatitude and As left paleo elevation constraints

Present Day Heat Flow Calculated using transient heat As left flow option

Thermal Conductivities and BasinMod Defaults but As left Heat Capacitates corrected to be more globally reaslistic ie to be consistent with equations of Sekiguchi (1984) Radiogenic Heat Used Rybach 1996 equation As left using average gamma ray value

Compaction Model Basin Mod Default As left

Erosion at Late Cretaceous Well data, using Gobe Field as a/a Unconformity a datum. Seismic data used for pseudomodels

Rifting Heat Flow assumed factors of 1.6 – 1.2 at Steady State or Transient Jurassic and Late Cretaceous settings Respectively

Delta Heat in Darai Variable setting at 1.5 Ma Used as required Limestone 8-60mW/m3 (Transient models only)

All Jurassic – Cretaceous Kerogen mixes based on Source rocks used as this rocks are source rocks Kerogen maps study – Chapter 4 (except Toro to Iagifu sandstones) TOC% data for source rocks Increased to account for Values as Chapter 4 ie are too low maturity and increase to measured values* depocentres All values increased by 25-50%. Uniform heat flow calculation Extension of all model to Not used across foreland 7500m

Ro% [Vr] is surpressed Use FAMM data, which agrees No preference. Use other with TMax data to confirm or dismiss validity of Vr

Horner plots give Use Time of Circulation values Trust Horner plots. Use temperature estimates which of 40 hours OR upward correct Time of Circulation are too low horner corrected values by 9% (circulation time) values as from well reports

* Except the Triassic 172

Studies of DST vetted temperature corrections of BHT values can be found in Waples and Ramley (2001) which found corrections in the order of 20%. In some cases the tc value is not recorded. In these cases a standard value of 5 will be used, which broadly typifies the length of time though which a measurement point is drilled passed plus the time of hole cleaning.

Heat Flow Setting

Lund et al. (1998) chose to use the Rifting heat flow setting for modelling of thermal history in the Papuan Foreland. This setting introduces heat pulses through the model at specified times in geological history. The regional heat flow over time for the Lund et al. (1998) study is given in the following Figure 5.6.

Figure 5.6: Regional Paleoheat flow for basin models (Lund et al 1998)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

As shown above, two heat pulses are modelled as shown: the first in the Early – Mid Jurassic, the second at the end of the Cretaceous. These two heating events are a response to the inputs of factors of 1.6 and 1.2 respectively. In brief, a factor, also known as a stretching factor, under assumption that extension is instantaneous then an increase in factor is linked to an increase in the thermal gradient in a basin (Beardsmore and Cull 2001). Although these events are based from a knowledge of the geological history, the basis for these heat pulses is tenuous. This comment is based on fission track data and what this information has illuminated regarding the intensity and timing of thermal events (Duddy et al.1991) and was summarized in section 5.1. Firstly, no thermal event which is specific to the Jurassic in the AFTA data. Instead data from (Duddy et al. 1991) indicate a regional cooling event occurred

173 over a wide age range, from the period 300-200Ma (Permian to earliest Jurassic). The Late Cretaceous to Tertiary thermal event is regularly observed in the AFTA (50- 90Ma) from PNG wells. Rifting, based on geological evidence is known to have occurred in PNG during the Triassic Early-Mid Jurassic and Late Cretaceous-Early Tertiary in PNG (Home et al. 1990). The broad range of ages for the Permian-Jurassic event does not allow accurate determination of the heating event or relative contribution of each event. In addition, these elevated paleotemperatures could be related to a combination of either elevated geothermal gradients and/or deeper burial (Hill and Gleadow 1990, Duddy et al. 1991). Note also that Pigram and Symonds (1993) and Davies et al. (1996) have questioned if the rift could be responsible for either a heat flow increase or major thermally induced uplift, given the large distance between PNG and the Cretaceous Coral Sea Rift. Further work may be required to distinguish the modeling approaches further. In the interest of starting with a simple model, matching the existing thermal history data and only adding complexity where necessary, modelling in this section will begin using steady state or ‘constant heat flow’ conditions over time. A transient thermal setting may also be introduced. For details on the particular nature of these thermal settings, see Appendix 9.6.

Delta Heat Settings

Local qualitative evidence, which is based on a combination of high rainfall volumes and heavy karstification, would suggest that the Darai Limestone is an important aquifer which is likely to carry heat away. This is handled in Basin Mod implementing a setting known as Delta Heat. This assumption was implemented throughout the basin modelling by Lund et al. (1998) who assumed that groundwater flow becomes most important from a thermal standpoint when high topographic relief was developed. In the study area this is assumed to have been introduced relatively recently, at an age of 1.5 Ma (Lund et al. 1998) and is consistent with the probable thrusting of frontal structures within the PNG foldbelt. For example the Iehi anticline (Figure 1.8) is interpreted to have been thrust at 1 Ma (Hill and Gleadow ,1989). Note that the existence of this thermal disturbance through the Darai Limestone means that estimation of present day heat flow is difficult a comment based on the fact that the onset of this feature is relatively recent allowing no time for equilibration to be established. This is handled using a well from outside the study area and is discussed in the following section.

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Present Day Heat Flow Calculation - Note that the existence of a thermal disturbance, as observed as a common feature in the basin by Lund et al. (1998) through the Darai Limestone means that estimation of present day heat flow is difficult. In order to get a handle on the present day heat flow a well from a deeper part of the foreland was examined to the SE of the study area – North Paibuna 1. A cross section showing the location of North Paibuna 1 relative to wells in the study are is shown in Figure 5.7 below and on Figure 5.5.

Figure 5.7: Cross Section showing stratigraphy within Foreland, demonstrating the thickening of the Darai Limestone and Era Beds into the Omati Trough

North Paibuna 1 is seen as a better modeling location heat flow since the well is in the deepest portion of the Omati Trough and is buried by ~500m of Era beds (age of 5Ma and younger). It is logical to assume that the well reached maximum maturity at present day. Erosion at this location is assumed to be minimal, as it is assumed that the well has always remained in the deep of the basin, with no significant uplift, which for the purposes of this assessment will be accepted. Two sets of calibration data for maturity are available through Vr and FAMM, the calibrations diagrams for which are shown in Appendix 9.7. Matching of the Vr gives a very low heat flow of 15mW/m2. This is extremely low using tectonic analogues by Deighton (1990) who indicate that post rift passive margins have a heat flow of 40-65mW/m2. A more realistic value can be achieved by matching FAMM data, resulting in a heat flow of 42mW/m2. This figure is consistent with the tectonic setting and will be assumed to represent the regional present day heat flow in the Foreland. This value will be given credence where there is uncertainty with understanding the present day heat flow and where delta heat effects appear to be active.

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Source Rocks Characteristics for source rocks in the study were developed in Chapter 4. All sources are given the following kinetic parameters and for individual models, use local well control. These are shown in the Table 5.3a below. Table 5.3b summarises the expulsion thresholds that have been established for oils where the source rock is known, primarily derived from Table 3.14. Note that for the Late Jurassic, the maturity of oils from this source was found to be generally low (0.45- 0.61%, see Table 3.14). Hence the explusion threshold for oils in the Late Jurassic (including the Magobu, Barikewa and Lower Imburu) will assume to be similar to that established for oils recovered in the foldbelt. A value of 0.85% Vr is derived from the most common value from a series of DST oils recovered from Iagifu 7X in the Kutubu Field (George et al. 1997). Cannel coal source rocks within the Late Jurassic are also allocated a 0.85% Vr threshold since information on their explusion threshold is not available. For the Triassic, the expulsion threshold of Family L oil has been assumed (0.75% Vr) to account for the typically labile characteristics of lacustrine source rocks

Table 5.3a: Source rock characteristics for basin models MODEL KANAU 1 OMATI TROUGH 1 OMATI TROUGH 2 FORMATION Kerogen Type Kanau 1 (average TOC) Komewu 1 + 2 (average TOC)

LOWER IERU Type III (minor Type II) 0.75 0.8 2 LOWER IMBURU Type II / III 1.0 1.0 2 BARIKEWA Type II / III 0.95 1.4 2 Cannel Coal - Halosa Age Type II 27 30

MAGOBU FORMATION Type II / III 2.4 1.3 2

Triassic Type I / II 3% * 3% * * from Kanau 1 with TOC increased to back out maturity

Table 5.3b: Expulsion thresholds used in basin models for various source rocks

FORMATION Kerogen Type Threshold Used

LOWER IERU Type III (minor Type II) Not Known (assume 0.85%)

LOWER IMBURU Type II / III 0.85%

BARIKEWA Type II / III 0.85% Cannel Coal - Halosa Age Type II Not Known (assume 0.85%) Algal Source* Type I Not Known (assume 0.85%)

MAGOBU FORMATION Type II / III 0.85%

5.6Triassic Kanau 1 - Basin Model Type I / II 0.75% (Lake oil assumed)

5.6.1 Stratigraphy

The Kanau 1 well is drilled upon the Darai Plateau (Figure 5.5) which has been interpreted to have formed due to inversion along old extensional faults of Mesozoic / Early Tertiary passive margin during the Plio-Pleistocene collision of the Australian

176 and Pacific plates (Hill 1990, Buchanan and Warburton, 1996). Hence, prior to inversion of the Darai plateau this area is likely to represent a half graben, orientated NW-SE, the same direction as the bounding Darai Fault (Figure 5.5). Kanau 1 well intersected ~500m of Darai Limestone with no Plio-Pleistocene clastics at surface. The present day structural position of the well indicates ~1700m of post Miocene uplift with up to 1000m of carbonates eroded at the wellsite (Hill and Gleadow 1990; Hill 1991). This would be in keeping with the Darai 1 and Turama 1 wells also drilled on the Darai plateau which encountered ~1000-2000m of Darai, possibly representing the uneroded thickness of limestone at Kanau 1. However Hulse and Harris (2000) through assessment of Strontium data at Kanau 1 suggest the erosion is more likely to be in the vicinity of 500m. Estimation of the amount of limestone interpreted to be missing upon this well is important to understanding the palaeo-burial depth and hence the generation history of the plateau, a scenario which Basin modeling can test.

Chapter 4 demonstrated the presence of source rock at Kanau 1 within the Triassic sequence and some empirical evidence (oil shows) supports the concept that this section has generated oil (Brereton 1976). Chapter 3 also demonstrated the presence of free oil in this section, several of which were mature (Figure 3.27). Jurassic sequences of the Magobu, Barikewa and Lower Imburu are also intersected in the well. The stratigraphy for this model was developed from the drilled section at Kanau 1 which penetrated almost a full stratigraphic section, with exception of probable erosion of Ieru at base Darai. The Kanau 1 well drilled to a Total Depth (TD) of 3519m in the Triassic. Estimation of the total thickness of Triassic below the well could not be established, since athough seismic data is available, no time-depth relationship could be established for the well due to lack of information from the sonic log (receiver spacing not known). The final thickness for the Triassic was chosen as a nominal 500m, increased from a drilled thickness of 224m. As described in 4.6.1, the sediments are angular, feldspar rich and immature, probably suggesting the package is near top basement. Analogues for the thickness of Triassic can be found in Bain and McKenzie (1974) where outcrops of the Kana Volcanics on the Kubor anticline are between 200 and 700m.

5.6.2 Calibration

Data for calibration of the Kanau 1 model is shown in Table 5.1, with raw data and stratigraphy shown in Appendix 9.3 and 9.5. These include Vr, AFTA, a single FAMM measurement in addition to BHT values. The data quality is generally good and the

177

Horner corrected BHT values use either two or three temperature measurements likely to give reliable temperature estimates. Burial history of Kanau 1 using AFTA was performed by Green (2001) who notes that the AFTA is consistent with a single thermal event which was 30-400C higher than present day temperatures. Vitrinite reflectance data from Swift (1986) is also available from the Kanau 1 well. This data shown in Figure 5.8 where the AFTA are observed to also be in agreement with the Vr data. Also shown is the estimated geothermal gradient at present day which is observed to be parallel to the paleo-geothermal gradient as defined by AFTA. Ignoring one poor quality AFTA result (3215m, contamination – as Figure 5.8) these observations show a highly consistent result and indicate that the thermal history at Kanau 1 is best explained as a single thermal event due to deep burial and later cooling associated with erosion. Figure 5.8: Comparison of Vr data, AFTA and present temperatures for the Kanau 1 well (Green, 2001)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

The fission track indicates that the timing of cooling is between 50 and 20 Ma. This age is roughly consistent with cooling around the Papuan basin following the onset of the Coral Sea Rift which started in the Latest Cretaceous (Home et al. 1990).

178

The data available were entered into BasinMod 1D with an aim to achieve a calibration to the consistent trend formed by the Vr and AFTA paleo temperature results. AFTA temperature data was also converted to Vr using a maturity relation by Burnham and Sweeney (1989) using a 1Ma heating duration consistent with Figure 5.8.

The initial, simple calibration is shown in Figure 5.9 assuming a Steady State thermal setting, no Late Cretaceous erosion and an arbitary heat flow of 30mW/m2 simply to demonstrate the features of the model and data available. The initial calibration shows the agreement of Vr and AFTA consistent with Figure 5.8. However TMax and a single FAMM point appear to be generally high to this maturity trend, alongside several Vr points. Hence, as shown in Figure 5.9 two trends are available for calibration; a Vr and AFTA trend, as well as a hotter temperature trend defined by TMax and FAMM. Testing of heat flow values shows that a range of inputs and erosion entries can be used to match either of these two thermal profiles. To derive the most representative model, four calibrations are presented. These calibrations are shown in Figures 5.10 – 5.13, with inputs for each model shown summarised in Table 5.4.

Table 5.4: Summary of inputs used for calibration models 1-4 - Kanau 1.

MODEL Thermal Heat Flow. Maturity Upper Ieru Comment Setting Present Match Erosion Day(PD) (VR/AFTA) (m) OR 50Ma (TMax/FAMM) Model 1 Steady 35@PD VR/AFTA 1200 Good match to lower (Figure 5.10) State maturity profile

Model 2 Steady 42@PD TMax/FAMM 1600 Good match to upper (Figure 5.11) State maturity profile

Model 3 Transient 42@PD a/a 1250 Good match to upper (Figure 5.12) maturity profile

Model 4 Transient 42@PD a/a 700 Poor match – predicted (Figure 5.13) 46@50Ma maturity profile too steep

Model 1 uses a low heat flow relative to the foreland regional value (35 versus 42mW/m2 as section 5.5) to match the Vr/AFTA trend. Model 2 utilises the foreland

Figure 5.9: Kanau 1 – Initial Calibration Steady State Model Heat flow 30mW/m2. 60Ma: NO Ieru erosion. 1.5Ma: - NO Darai or Era Erosion

Temperature (C) 100 80 60 40 20 Fm -1000 Trend defined by Vr and AFTA Trend defined by TMax and FAMM Darai

Uncorrected Upper Ieru Predicted Bawia 0 temperature Juha Alene Horner corrected using Toro 2 values each Upper Imburu Predicted Hedinia-Iagifu maturity Lower Imburu 1000 Temperature Koi-Iange Maturity VR LLNL %Ro Barikewa TMAX AFTA Depth Subsea (m) BHT Horner corrected FAMM Magobu CM 2000 using 3 values each Initial calibration shown for the Kanau 1 1D burial history model showing increasing trend for both maturity and temperature, indicating various features Triassic from the model.

3000 BasementBasement t = 0 0.1 1 10

Maturity VR LLNL (%Ro) 179 Figure 5.10: Kanau 1 – Steady State – Model 1 180 Heat flow 35mW/m2. 60Ma: 1200m Ieru erosion . 1.5Ma: - NO Darai or Era Erosion

Temperature (C) 120 100 80 60 40 20 Fm -1000

Temperature Darai Maturity VR LLNL %Ro TMAX Upper Ieru AFTA 0 BHT Bawia FAMM Juha Alene Toro Upper Imburu Hedinia-Iagifu Lower Imburu 1000 Koi-Iange Barikewa Depth Subsea(m)

Magobu CM 2000 Low heat flow model – Match to Vr and AFTA trend

Triassic

3000 BasementBasement t = 0 0.1 1 10 Maturity VR LLNL (%Ro) Figure 5.11: Kanau 1 – Steady State – Model 2 Heat flow 42mW/m2. 60Ma: 1600m Ieru erosion 1.5Ma: - NO Darai or Era Erosion Temperature (C) 140 120 100 80 60 40 20 Fm -1000

Darai Temperature Maturity VR LLNL %Ro Upper Ieru TMAX 0 Bawia AFTA BHT Juha FAMM Alene Toro Upper Imburu Hedinia-Iagifu Lower Imburu 1000 Koi-Iange Barikewa

Depth Subsea (m) Temperature mismatch = Delta heat effect Magobu CM 2000 Model using assumed regional heat flow of 42mW/m2. Large mismatch between predicted and measured temperatures interpreted to be caused by the Darai ‘delta heat’ effect. AFTA is plotted using a 10Ma rate after Burnham Triassic and Sweeney (1989) 3000 BasementBasement t = 0 0.1 1 10

Maturity VR LLNL (%Ro) 181 182

Figure 5.12: Kanau 1 – Transient - Model 3 Heat flow 42mW/m2. 60Ma: 1250m Ieru erosion .1.5Ma: - NO Darai or Era Erosion Temperature (C) 140 120 100 80 60 40 20 Fm -1000

Darai Temperature Maturity VR LLNL %Ro TMAX Upper Ieru AFTA 0 BHT Bawia FAMM Juha Alene Toro Upper Imburu Hedinia-Iagifu Lower Imburu 1000 Koi-Iange Barikewa Depth Subsea (m) Calibration similar to Figure 5.11, but assuming a Transient Heat Flow model. This Magobu CM 2000 allows a smaller amount of Ieru erosion compared to the steady state model. Maturity is slightly overpredicted in the lower part of the Figure relative to the single FAMM point. Triassic

3000 BasementBasement t = 0 0.1 1 10 Maturity VR LLNL (%Ro) Figure 5.13: Kanau 1 – Transient Model 4 Heat flow 42mW/m2. 60Ma: 700m Ieru erosion Heat flow 50mW/m2. 1.5Ma: - NO Darai or Era Erosion Temperature (C) 140 120 100 80 60 40 20 Fm -1000

Temperature Trend defined by TMax and FAMM Darai Maturity VR LLNL %Ro TMAX Upper Ieru AFTA BHT 0 Bawia FAMM Juha Alene Toro Upper Imburu Hedinia-Iagifu Lower Imburu 1000 Koi-Iange Barikewa Depth Subsea (m)

Magobu CM 2000

Model assumes an increase in heat flow (~20%) at the Late Cretaceous. The predicted maturity profile is flatter in gradient than the Triassic measured data giving a poor data match. Basement 3000 Basement t = 0 0.1 1 10 Maturity VR LLNL (%Ro) 183 184 regional heat flow of 42mW/m2 which ties the TMax/FAMM trend. Note the large temperate mis-match evident in Figure 5.10 between predicted and measured temperatures, and particularly evident in Figure 5.11. This is interpreted as relating to the Darai ‘Delta Heat’ effect. Since this effect is very recent (1.5Ma see section 5.5), the measured temperatures will be ignored and focus aimed at matching measured maturity. Figure 5.12 implements a transient thermal setting (full description in Appendix 9.6), another alternative in matching the data, since heat is lost at a slower rate through this setting the overall Ieru erosion required to match the data is lower. One assumption made by Green (2001) for use of the AFTA is a heating rate, which was 1Ma duration for the Figure 5.8 which is based on Burnham and Sweeneys’ (1989) temperature to Vr relationships. Their work shows that short heating durations will result in lower overall maturity measurements, and conversely longer heating durations result in higher maturity measurements. Hence, used in Figure 5.11 and 5.12 are AFTA points which assume a 10Ma heating rate. These appear to agree with the trend created by the TMax data and the single FAMM point at the base of the well, allowing these calibrations to be consistent with the AFTA. Note that all models for Kanau 1 implement 1000m of uplift, with no erosion at surface to simulate the inversion of the Darai Plateau at 1.5 Ma. This value is based on the relative offset of the Toro reservoirs at Kanau 1 relative to Bujon 1 and uplift timing for the plateau consistent with that used in Lund et al. (1998).

Models 1 - 3 represents calibrations which match the measured maturity data. All models require input of erosion. A simple method of matching the maturity data was to add significant erosion at base Darai at the Late Cretaceous unconformity. This level of erosion is substantial (700-1600m) but can be defended on a thickness basis in other areas of the basin. For example wells in the Hides fields in the NW of the basin (see Figure 1.8) typically have ~1500m of Upper Ieru sediments (see Appendix 9.8). Model 4 (see Figure 5.13). was implemented to test the concept that additional heat flow, combined with erosion was experienced during the Late Cretaceous. However the modelled maturity profile appears flatter than either of the measured maturity profiles This is interpreted to indicate that negligible additional heat flow was input during the Coral Sea Rift event at Kanau 1. In order to distinguish the likelihood of each of the three favoured models, a temperature versus time plot was created for models 1, 2 and 3 (Figure 5.14) and

Temperature (C) Temperature (C) Temperature (C) 140 120 100 160 150 100 160 150 100 80 60 40 20 50 50 0 0 0 250 250 (Figure 5.12) (Figure 3 Model E E (Figure 5.11) (Figure 2 Model 5.10) (Figure 1 Model Triassic M M

L L

-TMax-FAMM i

–Vr-AFTA -TMax-FAMM

T 200

200 i

s r

i L

L c s

s Jurassic i

c s

i c D D

M 150 M 150

Age (my) T Age (my) Age Tor

T Cretaceous

E o

o r

~145-155 o ~115-125 100 100 ~145-155 L L ~75 95 0 95 C Coral Sea Coral Sea 0 C (~60Ma) 0 0 0 0 C C C C Rift Pal Pal 50 50 Eoc Toro (80-95 Eoc Toro (80-95 Toro (80-95 Triassic Tertiary >125 Triassic Triassic >125 >125 0 li Ol Oli C 0 0 C C 0 0 C) 0 C) Mio Mi C) o Pli Pli Pl Pl H 0 e H 0 e 120 110 - 125 115 - rfls–Knu1models Kanau profiles – Figure 5.14: 0 C 0 C been more recently buried been more Triassichad and seen inthissampleifthe Toro wouldYounger ages be 50-20Ma. age rangeof shows theTriassic tighter supported because a is the interpretation of 60-0Ma, large agerange sample hasa theToro AFTA.Although with the whichreached ismoreconsistent temperatures the higher to due is preferred model TMax/FAMM match to the history Based onthetemperature with 50-20Ma. Late Cretaceous, agesof at the maximum recognises thethermal 1only Rift. AFTAinKanau CoralSea of the to onset prior intheLateCretaceous temperatures indicatesmaximum history Temperature Green 2001). (from Fission Track(AFTA)shown Apatite favoured calibrationswith ranges from three timeplotsderivedfrom versus Temperature with magnitude from AFTA from magnitude with consistent NOT Temperatures

with magnitude from AFTA from magnitude with consistent Temperatures

Temperature versustime 185

THIS PAGE IS LEFT INTENTIONALLY BLANK 186 constraints from the AFTA study (Green 2001) from the uppermost and lowermost sample (Toro and Triassic respectively) are marked on the diagram. It can be noted that for Model 1, the Toro and Triassic do not reach the 80-950 and >1250 (respectively) thresholds required by the AFTA. However, the Model 2 and Model 3 temperature histories however are both consistent with the AFTA, giving similar results, with model 3 suggesting a slightly higher burial temperature for the Triassic during the Late Cretaceous. One key difference between Model 2 and Model 3 is the temperature reached during the Tertiary. Annealing of fission tracks occurs at ~1100 degrees, dependant on the heating rate (Hergarty 1998). As shown in Figure 5.14, Model 2 demonstrates burial to temperatures of 110-1200 whereas model 3 sees temperatures 115-1250. If model 3 is accepted then the cooling age would be expected to be more recent than the 20Ma. Since the burial in model 2 is near the annealing temperature, in contrast to model 3 where the value has been more fully exceeded, model 2 is interpreted to be more consistent with the age of cooling from AFTA and is hence the most likely temperature history. Evidence supporting this concept is the chorine content is low and hence more susceptible to resetting ie average for the Triassic sample 3477m is 0.37 weight% chlorine compared to 0.43% from the Durango standard used for this study (Green 2001). Chlorine rich apatites are more resistant to annealing than fluor-apatites (Beardsmore and Cull ,2001). This model will be used to estimate petroleum generation. Note that testing of this model shows, as would be expected, that any additional Darai Limestone added at surface (ie assumed to be eroded) would push the temperature higher toward model 3. This gives confidence that the existing amount of Darai Limestone at the Kanau 1 location of ~500m is roughly the amount that was present prior to uplift and hence no significant erosion has taken place. This is in contrast to earlier discussions by Hill and Gleadow (1990) and Hulse and Harris (2000) 1000m to 500m respectively that was interpreted by these authors. These authors did not have the benefit of the new fission track (Green 2001) through which to constrain their modelling.

5.6.3 Petroleum Generation

Results of the petroleum generation history are shown in Figure 5.15 and 5.16, shown for the calibration established by Model 2. Source rock characteristics assumed for the model are outlined in Table 5.3. Figure 5.15 shows that both the full thickness of the Triassic and the lower Magobu Formation are the only

Figure 5.15: Kanau 1 burial history for the favoured thermal calibration

Triassic Jurassic Cretaceous Tertiary

Uplift followed by burial by Darai and 0.8 Era Beds. No further generation

0.6

0.4 Transformation Ratio (fraction)

0.2 On-set of generation and expulsion during the Latest Cretaceous 0 (Triassic and Magobu) 187 188

Figure 5.16: Kanau 1 maturity history using Vr and TR (transformation ratio) for the favoured thermal calibration (Figure 5.11)

E MTriassicL L JurassicD M E Cretaceous L Pal Eoc TertiaryOli Mio PliPlHe 10 1 T ri assi c Hydrocarbon Expulsion Maturity VR LLNL bottom (where expulsion threshold exceeded) Transformation Ratio bottom

Expelled Hydrocarbons 0.8 Magobu CM

Triassic Source (Type I/II) ~20% TR by 0.75 Vr % 0.6 T ri assi c Magobu CM 1 0.85 Vr

0.75 Vr 0.4 Maturity VR LLNL (%Ro) LLNL VR Maturity

Magobu Source (Type II/III) (fraction) Ratio Transformation ~45% TR by 0.85 Vr % 0.2

Vr% and Transformation Ratio over time for the Triassic and Magbou source rocks. Expulsion thresholds for both sources shown (0.75 and 0.85% respectively). Diagram shows that expulsion occurs during the Cretaceous for both the Triassic and Magobu with no further transformation following the Coral Sea Rift. 0.1 0 250 200 150 100 50 0 Age (my) 189 formations to experience transformation. The transformation history is shown in Figure 5.16. The figure assumes explusion thresholds of 0.75% and 0.85% in the Triassic and Magobu respectively, from Table 5.3. The transformation history shows that the source rocks predominantly expelled hydrocarbons during the Late Cretaceous (115Ma – 50Ma) with no further conversion of the source rocks following the Late Cretaceous unconformity. Comparison of these results to the basin modeling study by Lund et al. (1998) will be discussed in the summary chapter. Integration of the results from a migration history standpoint will be discussed in Chapter 6.

190

5.7 Omati Trough 1 – Basin Model

5.7.1 Stratigraphy

Located within the Omati Trough, this model is in a position approximately 4km from the edge of the Komewu Fault (see Figure 5.17). The pseudo model is located on seismic line PN91-124, orthogonal to the Komewu Fault. The stratigraphy used in this model is derived primarily from the well Kamusi 1 (10.5 km to the SE) which projects onto the line and shows excellent tie to the seismic events. The interpreted seismic line showing the position of the pseudomodel is shown in Figure 5.17. Komewu 2 (36 Km from the pseudo well) is on strike, but further updip from Kamusi 1 but assists in identifying that Middle Jurassic is present in the sequence below Total Depth (TD) of Kamusi 1. An important feature which is present on this seismic line is what is interpreted to be a synrift sequence directly below Kamusi 1. The well reaches a Total Depth (TD) at ~2 seconds (3.2km) and does not reach this sequence. The synrift is identified by a series of events which fan out as they approach the fault and is capped by what appears to be an erosional surface above which are subhorizontal reflectors. These gently dipping reflectors persist through the data as exemplified by the reservoir levels ie Toro and Iagifu and is interpreted as a post rift package consistent with the interpretation of this unit in a passive margin sedimentary wedge (Home et al. 1990). An example of a synrift (lake) sequence is also shown on Figure 5.17 which demonstrates several features characteristic of synrift deposits including the thickening into the major bounding fault in addition to a series of packages showing updip erosion / pinch out

The stratigraphy for this model, based on the drilled stratigraphy at Kamusi 1 and some reference to Komewu 2 shows ~1500-2000m of Darai are present with a thin covering 100-300 of Era - Orubadi beds. The combined Jurassic and Cretaceous section is 2000m thick. The synrift section contains no wells and hence basement was picked on line PN91-124 and then the sequence was converted to depth using interval velocity maps based on work by Schofield (2001). This indicates a thickness of the synrift of ~1.1km

Since no wells drill into the synrift a model must be developed for the likely stratigraphy in this sequence. The intersection of Triassic sands and shales at

Kapul-1 SW Omati Trough 1 NE 1basinmodel Omati Trough PN91-122 showingthepositionof Figure 5.17:

Top Carbonate

Base Seismic datafrom Carbonate Erosion TD (Kamu si 1) surface and Komewu Growth and truncation Fault block of events faulting?

Synrift. Top Probable Triassic to Basement Jurassic Sediments

Kapul-1 SW of copy regulations. removed Omati A Trough 1 NE

Adelaide Top This Carbonate of the figure/table/image to thesis comply Library. It Example of a synrift lake sequence is NOTE: included Base on seismic from Indonesia (Bohacs 2002) held Carbonate University print regulations. removed A with Top Alene Top Toro This by Top Iagifu copy TD (Kamu si 1) copyright in the figure/table/image has to the of of University comply It been Top the print Adelaide NOTE: Triassic is Komewu included thesis Fault Basement with

22km 191 Library. held

Interpretation courtesy of Oil Search Limited copyright in has by the been the 192

Kanau 1 which drills in a similar position near the Darai Fault parallel to the Komewu Fault (Figure 5.17) presents one option for the possible fill. Seismic evidence for this may be used given the section appears to be poorly reflective in general but there are occasional bright events which may suggest the presence of sandstones, particularly toward the top of the sequence. The assumption that the Triassic fills this sequence also fits descriptions of the unit where the Triassic is “distinguished from the overlying Jurassic synrift megasequence by their more restricted distribution and the evidence from the Kubor area of pre Jurassic uplift and erosion of Triassic synrift rocks” (Home et al.1990). However the possibility still exists that at least some of this package may also contain Jurassic synrift, part of the Gondwana Early- Mid Jurassic rift phase as defined by Home et al. (1990). For the purposes of this pseudomodel the assumption will be made that the synrift is entirely Triassic of sands and shales. Other interpretations are that this sequence is simply a different facies within the Triassic or that the entire sequence is Jurassic with no Triassic.

5.7.2 Calibration

As shown in Table 5.1 the Kamusi 1 well contains a variety of data for use in thermal calibration. However one dataset that the well does not have available is AFTA. The Komewu 2 well drilled ~40km along strike is drilled in a similar structural position and contains four AFTA measurements from which a burial history can be inferred. Discussion on the calibration will begin by assessing the thermal history of Komewu 2, to assist in the calibration of Kamusi 1.

A series of datasets from the Komewu 2 well are shown in Figure 5.18 plotted as depth versus temperature. Two plots are shown and BHT and AFTA data are shown in each, with the BHT subject to a 14% upward correction since no Time Since Circulation data are available. This value is based on the average from a temperature correction study which used horner plots in the Foreland (Wood, 2006). Different heating rates are used for plotting Vr% and FAMM on the graph, 1Ma and 10Ma based on Burnham and Sweeney (1989) models. An inspection of the data shows that the BHT and AFTA data are roughly parallel and allowing for AFTA error are only separated by ~10oC. The upward corrected temperature data indicates a temperature gradient of 2.4 degrees/100m.

Figure 5.18 – Comparison of Komewu 2 temperature data and thermal history data versus depth based on 10Ma (left) and 1Ma (right) heating rates

Temperature Profile

FAMM Higher Agreement than AFTA of FAMM & AFTA

Vr broadly agrees with FAMM here 193 194

Vr% appears to be scattered, AFTA data for Komewu 2 were measured by Duddy et al. (1991) and were interpreted by Hill and Gleadow (1990) who point out that the results are generally consistent with the present day temperatures and whose ages are similar to the stratigraphic age of the rocks, with the samples probably reflecting contemporaneous volcanic activity at the time of deposition. Review of Figure 5.18 would indicate that the profile most consistent with this interpretation is the 10Ma heating rate. This comment is based on the fact that the FAMM and AFTA agree in this plot and also that they also agree with temperatures near the base of the well. The key difference in the 1Ma value is that this data appears to record a higher event recorded in the FAMM which is not recorded in the AFTA. The implication of these results for Kamusi is that maximum burial is probably present day and that the FAMM is probably reflecting true maturity temperature. This makes the assumption that the burial history in Komewu 2 is similar at Kamusi 1, which appears logical since they are along strike from one another, except that Kamusi 1 is drilled in a slightly deeper portion of the Omati Trough, intersecting ~2.2 km of Darai Limestone compared to ~1500m of Komewu 2.

The Kamusi 1 thermal history data are shown in Figure 5.19 which includes Vr%, FAMM and TMax data. Note that data is only available from the Ieru through to Lower Imburu. Hence, for use in this pseudomodel calibration will be attempted for the existing data and extrapolated to depth. The data show that Vr% and FAMM do not agree, the only exception being the uppermost sample where low surpression is reported in the sample. The FAMM data, in contrast to the Vr, show only a very silght increase with depth and at least one sample appears to favour the trend from Vr. At least one of these samples appears reworked, and this fact, combined with the very steep trend with depth enables the possibility that at least some of these samples could be caved. Lund et al. (1998) also point out the issue of similar values over a considerable depth interval for Kamusi 1. Values from TMax appear not to favour either dataset, but generally trend between the two trends. Hence the data is conflicting, and probably poor quality, and hence a confident calibration is difficult Hence testing of FAMM and Vr trends will be attempted and the most geological reasonable calibration will be used for petrolelum generation.

Figure 5.19: Comparison of FAMM and Vr% with depth (zoomed) for Kamusi 1 Temperature Maturity VR LLNL Comments* are by Faiz et al. (1997) %Ro TMAX AFTA BHT FAMM

Fm 1900

2000 Darai Low Surpression* Upper Ieru Reworked* Bawia Juha Similar values 2500 with depth. Alene Cavings? Toro Upper Imburu

Hedinia-Iagifu Depth Subsea (m)

3000 Lower Imburu

Barikewa

3500 t = 0 0.398107 1

Maturity VR LLNL (%Ro) 195 196

Calibrations for the temperature and thermal maturity data for the Omati Trough 1 model are shown in Figures 5.20 – 5.24. The model begins with a calculated heat flow of 42mW/m2 based on the earlier discussion with respect to regional foreland heat flow. The workflow and inputs for each model are summarised in Table 5.5.

Table 5.5: Summary of Inputs for Calibration Models - Omati Trough 1

MODEL Thermal Heat Flow Maturity Upper Ieru Comment Setting Present Match Erosion Day(PD) (VR) (m) OR 60Ma (TMax/FAMM) Model 1 Steady 42@PD VR 2200 Initial calibration – match (Figure State to Vr data. Good match 5.20) to single corrected BHT Model 2 Transient 42@PD VR 1500 Good match as above, (Figure but using a Transient 5.21) heat flow model Model 3 Transient 42@PD FAMM 2500 Match to top and bottom (Figure of FAMM trend 5.22) Model 4 Transient 55@PD FAMM 1500 Higher heat flow used. (Figure Match to uppermost FAMM trend. 5.23) Model 5 Transient 35@PD FAMM 3500 Match to ‘steeper portion’ (Figure of FAMM trend 5.24)

Models 1 and 2 use a steady state and transient model (respectively) to model Vr%. It is noted that the single corrected BHT values, is matched in model 1 but the temperature prediction is high to the value in model 2. As previous this is probably reflecting the delta heat effect but will be largely ignored. Model 3 – 5 are used to match the FAMM trend. Given the scatter in the FAMM data, an adequate but not exact match to the FAMM data is achieved but a series of calibration experiments were implemented. Choice of the most representative burial history is difficult, a comment based on both the quality of the data, particularly of the FAMM, as well as the lack of constraints, which formerly were provided by AFTA data, which Kamusi 1 does not contain. Analogues for erosion in the basin were discussed earlier, and in the basin and a review of missing stratigraphy show that ~1500m of Ieru is known from the Hides and Juha areas and hence thicknesses significantly beyond this are not likely. Only Models 2 and 4 have erosion levels that are realistic and for other models, erosion inputs are high. Based on the options available, and accepting the foreland regional heat flow of 42, Model 2 is viewed as the most likely model. Model 4 is considered as a low likelihood model since the erosion amount (1500m) is consistent with analogues but the chosen heat flow is higher than the established

Figure 5.20: Omati Trough 1 (Kamusi 1) - Steady State - Model 1 Heat flow 42mW/m2. 60Ma: 2200m of Ieru erosion Temperature (C) 160 140 120 100 80 60 40 20 Fm 0 Era/Orubadi

1000

Darai

2000 BawiaUpper Ieru Juha Alene Depth Subsea (m) Toro Upper Imburu Temperature Maturity VR LLNL Hedinia-Iagifu 3000 Model matches Vr and assumes %Ro Lower Imburu TMAX foreland regional heat flow. AFTA Corrected Large erosion input required. A single Barikewa BHT corrected BHT value is matched. Cannel Coal FAMM

Magobu CM 4000 t = 0 0.1 1 10 Maturity VR LLNL (%Ro) 197 198

Figure 5.21: Omati Trough 1 (Kamusi 1) – Transient – Model 2 Heat flow 42mW/m2. 60Ma: 1500m of Ieru erosion Temperature (C) 180 150 100 50 20 Fm 300

Calibration similar to Figure 5.20 but uses a transient heat flow. Predicted temperature is high to the single 1000 corrected value (interpreted to be related to the Darai delta

heat effect). Darai

2000 Upper Ieru Bawia Juha Alene

Depth Subsea (m) Toro Upper Imburu Temperature Hedinia-Iagifu 3000 Maturity VR LLNL Lower Imburu %Ro TMAX Barikewa AFTA Corrected BHT Cannel Coal FAMM Magobu CM 4000 t = 0 0.1 1 10 Maturity VR LLNL (%Ro) Figure 5.22: Omati Trough 1 (Kamusi 1) - Transient - Model 3 Heat flow 42mW/m2. 60Ma: 2500m of Ieru erosion Temperature (C) 180 150 100 50 20 Fm 0 Era/Orubadi

Match to upper and lowermost FAMM points. Erosion input required is high.

1000

Darai

2000 BawiaUpper Ieru Juha Alene Depth Subsea (m) Toro Temperature Upper Imburu Maturity VR LLNL Hedinia-Iagifu 3000 %Ro Lower Imburu TMAX AFTA Barikewa BHT Corrected BHT Cannel Coal FAMM

Magobu CM 4000 t = 0 0.1 1 10

Maturity VR LLNL (%Ro) 199 Figure 5.23: Omati Trough 1 (Kamusi 1) - Transient - Model 4 (FAMM) 200 Heat flow 55mW/m2. 60Ma: 1500m of Ieru erosion Temperature (C) 250 200 150 100 50 0 Fm 0 Era/Orubadi

Match to highest and lowest FAMM point ignoring steep trend. Result roughly parallel to the Vr trend.

1000

Darai

2000 BawiaUpper Ieru Juha Alene Depth Subsea (m) Toro Upper Imburu Temperature Maturity VR LLNL Hedinia-Iagifu 3000 %Ro Lower Imburu TMAX AFTA Corrected BHT Barikewa BHT Cannel Coal FAMM

Magobu CM 4000 t = 0 0.1 1 10 Maturity VR LLNL (%Ro) Figure 5.24: Omati Trough 1 (Kamusi 1) - Transient - Model 5 (FAMM) Heat flow 35mW/m2. 60Ma: 3500m of Ieru erosion

Temperature (C) 140 120 100 80 60 40 20 Fm 0 Era/Orubadi

Temperature Match to steeper portion of FAMM values Maturity VR LLNL 1000 %Ro TMAX AFTA Darai BHT

FAMM

2000 BawiaUpper Ieru Juha Alene Depth Subsea (m) Toro Upper Imburu Hedinia-Iagifu 3000 Match steep portion of FAMM data. Erosion is Lower Imburu Corrected BHT unusually higher and implements a lower heat flow than the established regional. Considered Barikewa a poor calibration due to poor assumptions Cannel Coal

Magobu CM 4000 t = 0 0.1 1 10 Maturity VR LLNL (%Ro) 201 202 regional (55mW/m2). Since heat flow is inferred from a model outside of the study area in the southern Omati Trough, the possibility exists that heat flow may be higher with the northern Omati Trough. There is insufficient data or rigorous heat flow values established to evaluate this further. Hence both these models will be considered with respect to modeling petroleum generation from the Omati Trough 1 model.

5.7.3 Petroleum Generation

The favoured burial history model for the Omati Trough 1 pseudomodel is shown in Figure 5.25 which shows both the low heat flow and high heat flow models based on Model 2 and Model 4 respectively. Model 2 involves matching Vr data, essentially a cooler model, whereas Model 4 matches the high temperature trend defined by FAMM data. Source rock characteristics and explusion thresholds are again derived from Table 5.3. Inspection of Figure 5.25 indicates that significant transformation (>30%) of the source rocks occurs predominantly in the Late Cretaceous. For Model 2, only the Triassic and the Magobu experience significant transformation however for Model 4 the shallower source rocks are also involved. Figure 5.26 shows the Transformation Ratio over time for Model 2. Results demonstrate that although the Triassic has generated and expelled hydrocarbons by the Late Cretaceous (140Ma-60Ma) only generation with no expulsion occurred in the Magobu. The Magobu marginally reaches the expulsion threshold in the period 10Ma to present day. Further transformation of the Triassic during the same period is negligible. Model 4 (Figure 5.25 & 5.27) shows a similar burial history to Model 2 with two phases of generation and explusion. Using this ‘optimistic’ thermal model, generation and explusion occurs throughout the Cretaceous from the Triassic, but also Magobu, Barikewa and Cannel Coals. Late expulsion (15Ma – present day) involved the same sources that expelled during the Cretaceous, but there is little remaining source potential. This is shown by the degree of transformation that occurred during late explusion is relatively minor, with transformation only increasing by 0.05 % and the Triassic shows no explusion. The exception is the Barikewa. During the Cretaceous, this source rock experienced less transformation and hence more source potential remains during the period 15Ma - Present day, transformation increasing by ~0.20% during this time.

exhausted) (the Triassic hasbeen the Jurassic agesourcesonly day occursin 20Ma topresent Transformation during theperiod active. no othersources during theLateCretaceous with (including CannelCoal) occurs of theTriassicand Magobu Almost completetransformation HighHeatFlow Model 4- present day. during 20Mato occurs conversion oftheMagobu transformation andsignificant sources active.Slight Late Cretaceouswithnoother the Triassicoccursduring Majority ofthetransformation Low HeatFlow Model 2– Figure 5.25: rnfrainRtooe ieposfrOaiTrough1 Transformation RatiooverTimeplots forOmati

Depth Subsea (m) Depth Subsea (m) -1000 -1000 6000 4000 2000 2000 6000 4000 0 0 250 Triassic T 200 Jurassic J 150 Age (my) Age Cretaceous K 100 50 Pal Tertiary N Q 0 H t = 0 t = t=0 Fm Basement Triassic Magobu CM Cannel Coal Barikewa Lower Imburu Hedinia-Iagifu Upper Imburu Toro Alene Juha Bawia Upper Ieru Darai Era/Orubadi Basement Triassic Magobu CM Cannel Coal Barikewa Lower Imburu Hedinia-Iagifu Upper Imburu Toro Alene Juha Bawia Upper Ieru Darai Era/Orubadi 0.2 0.4 0.6 0.8 0.4 0.6 0.8 0.2 0 1 1 0

Transformation Ratio (fraction)

Transformation Ratio (fraction) 203 204 Tertiary 45% Cretaceous Jurassic Triassic Figure 5.27: Transformation over Time - Bottom of Source Rock Model 4 – High heat flow Model

Triassic Jurassic Cretaceous Tertiary 205 206

5.8 Omati Trough 2 – Basin Model

5.8.1 Stratigraphy

The Omati Trough 2 model is located within the Omati Trough, to the SE of the Kamusi 1 well / Omati Trough 1 (see Figure 5.28) where it is observed that there is thickening of the stratigraphic section, particularly the Tertiary, deeper into the Omati Trough. Omati Trough 2 is a pseudomodel, where the stratigraphy in the model has been built by simply using the Omati Trough 1 model (most likely case - model 2) the main adjustments reflecting the thickening of the Darai Limestone (~1km additional), thickening of the Koi Iange to Basement section (Jurassic). The location of the well, and features are shown in Figure 5.28, based on the interpretation of seismic line PN90-109x. A synrift package containing probable Triassic sediments (as seen at Omati Trough 1) does not appear to be present. However, a seismic reflector which appears just above top basement is interpreted to represent a thin veneer of Triassic (~44m) which will be included in the basin model as a Triassic source rock unit.

Source rock characteristics for the model are largely consistent with Omati Trough 1, but honouring the seismic data by adding ~1km additional burial by the Darai Limestone with a slightly thickened Jurassic section and assuming only a thin Triassic unit. The main aim of this model is to observe the effect on the maturation history where there is a greater thickness of younger sediments deposited, in this case, primarily Darai Limestone.

5.8.2 Petroleum Generation

Burial history, coloured with transformation ratio colour is shown in Figure 5.29. As shown in the diagram, the burial during Late Cretaceous time (~60Ma) is not as deep as that experienced by the sedimentary section during late burial of ~3km of Darai Limestone (25Ma – present day). Source rock transformation history in this diagram shows that significant conversion (>30%) occurs in the Triassic and Magobu during the Late Cretaceous. These source rocks are also involved in the late charge, in addition to the Cannel Coal and Barikewa. Analysis of the detail for transformation history and Vr is shown in Figure 5.30. Explusion from the Triassic and Magobu occurs during the Late Cretaceous, with almost 90% of the source potential removed from the Triassic source during this event. Late charge, which occurred during the burial of the Darai Limestone involves some elevated but

Figure 5.28: Seismic data from PN90-109x showing the location of the Omati Trough 2 Basin Model Location of Seismic line PN90-109x shown on left with the Location of the Omati Trough 2 pseudo model. Interpreted seismic line shown below showing basement, Koi Iange, Top Iagifu, Top Toro, Upper Ieru, Mendi (intra darai event) and Top Darai. Tie to the seismic events is achieved by tying to the well Kapul 1, ~8km from the Kamusi 1 well

Several features of the seismic line indicated include:

• Thickening of the Darai into the Omati Trough • Thickening of the Koi Iange to Basement section (Jurassic) package into the Omati Trough • A bright reflector just above basement which is interpreted to represent Top Triassic

Top Era Beds Kapul 1 Omati Trough 2 Top Darai Thickening of Darai Limestone

Top Mendi Upper Ieru Toro Iagifu Koi Iange

Basement Thickening of Koi Iange to Basement Top Triassic?

Two Way Time (TWT) 35km

Interpretation courtesy of Oil Search Limited 207 208

Figure 5.29: Transformation Ratio for Omati Trough 2.

Triassic Jurassic Cretaceous Tertiary

0.8

0.6

Upper Ieru

0.4 Transformation Ratio (fraction)

0.2

Diagram shows transformation of the Triassic and slightly in the Magobu only during the Late Cretaceous. During the period 20Ma to present day the Magobu undergoes significant transformation with the Cannel Coal also experiencing transformation, and to 0 a lesser extent the Barikewa Figure 5.30: Omati Trough 2 - Transformation over Time

TriassicT JurassicJ CretaceousK Pal Tertiary N QH 10 1 T ri a ssi c Hydrocarbon Expulsion Maturity VR LLNL bottom (where expulsion threshold exceeded) Transformation Ratio bottom Magobu

Diagram shows significant transformation of Magobu CM the Triassic (90%) during the Late Cretaceous. Magobu - 0.85 Vr CannelCannel0.8 Coal The Magobu is also involved (60% achieved by 45% Tr Coal transformation). During the period 20Ma to present day the Magobu is almost fully exhausted, increasing by 20%, with a very small amount of expulsion from the cannel Triassic - 0.75Vr achieved coal by ~40% transformation 0.6 Expulsion at Late Cretaceous time MagobuT ri a ssi c CM Thresholds 1 0.85 Vr Cannel Coal Barikewa

0.75 Vr Barikewa0.4 Maturity VR LLNL (%Ro) LLNL VR Maturity Late expulsion from Triassic - Vr Transformation Ratio (fraction) Triassic and Magobu. very minor expulsion 0.2 from Cannel Coal Magobu - Vr

0.1 0

250 200 150 100 50 0 209 Age (my) 210 minimal explulsion from the Triassic and Magobu, with negligible explusion from the Cannel Coal. Conversion appears greatest from the Magobu where the Tr value rises by ~20%. In the Triassic, a lower amount of conversion is modeled, showing a rise of ~10%.

5.9 Summary of Results

The Kanau 1, Omati Trough 1 and Omati Trough 2 burial history models have demonstrated several key aspects to the hydrocarbon generation history in the study area.

Two generation periods are recognised:

1) The Cretaceous charge related was clearly an important period of hydrocarbon generation in the region, where 65-95% Tr occurs in source rocks of the Triassic and Magobu only. This charge was related to burial by the Upper Ieru which has been subsequently eroded. Testing of the calibrations indicates this event was not accompanied by an increase in heat flow.

2) A Miocene to Recent charge, typically 20Ma – present day, which only occurs only in the Omati Trough driven by late burial by Tertiary strata (Darai Limestone and Era Beds). Transformation (Tr) of source rocks during this event was relatively small (up to 20% Tr) compared to the Cretaceous event.

The charge age range and the source rocks identified as belonging to each respective charge event are shown in Figure 5.31. The implications of this modeling is that there appear to be significant volumes of oil generated over long periods of geological time, particularly for the Cretaceous event. This is related to the large inputs of Upper Ieru erosion that have been necessary in order to match the thermal history data.

Since this significant charge event occurred 135-50Ma ago, with large kerogen transformations observed in the Triassic, the results have implications for the origin of the heavily biodegraded nature of some of the oil families from Chapter 3, particularly Family L. This is discussed in Chapter 6. These implications will be discussed in Chapter 6 with relation to exploration risk. Note that these studies have also suggested that the approach to basin modeling the thermal history can be simplified. Reasonable matching of the data has been achieved using simple

FIGURE 5.31: Oil expulsion history with time for the Kanau 1 and Omati Trough 1+ 2 models.

AGE (Ma) 220 206 160 144 135 115 100 65 5560 35 23 11 5 2

PERIOD JURASSIC CRETACEOUS TERTIARY

EPOCH Early Middle Late Early Late Paleocene Eocene Olig. Mioc. Plio. Q

CORAL SEA Carbonate FOLD PHASE Passive margin sedimentation RIFTING Sedimentation BELT

NO LATE CHARGE

Darai Plateau TRIASSIC (95%) Model (Kanau 1) MAGOBU (78%)

Omati Trough 1 TRIASSIC (95%) TRIASSIC (95%) Model MAGOBU (60%)

Omati Trough 2 TRIASSIC (90%) TRIASSIC (98%) Model MAGOBU (65%) *MAGOBU (85%)

Expulsion & *High heat flow model Migration (95%) = Transformation Ratio at end of period suggests the Barikewa may also be contribute to the late charge event

Diagram illustrating the charge events from each basin model. All models shows significant expulsion during the latest Cretaceous, from the Triassic and Magobu only. In all cases the Triassic has essentially exhausted its source potential by ~50Ma

Late charge during the Tertiary shows that although some transformation of the Magobu occurs, the amount of 211 transformation is small compared to the Cretaceous event. The large charge appears most favourable at Omati Trough 2, where ~20% increase in transformation ratio is experienced. 212 input of burial and erosion, and implementing the use of either steady state or transient models. This contrasts with the approach by Lund et al. (1998) which used a more complicated approach by implementing the rifting heat flow to ‘pulse’ additional heat into the models. Table 5.6 shows a comparison of inputs used for the Lund et al. (1998) compared to that of the current study for the same wells of each.

Table 5.6 Comparison of Inputs used for Basin Modelling Studies

Well Name Amount of Late Cretaceous Amount of Late Cretaceous Erosion (m) Erosion (m) Lund et al. 1998 Current Study Kamusi 1 480 1500 Kanau 1 290 1600

Well Heat Flow – Late Cretaceous Heat Flow – Late Cretaceous Name (Lund et al. 1998) Current Study Kamusi 1 44mW/m2 42-55mW/m2

Kanau 1 35mW/m2 42mW/m2

Comparison of the figures in Table 5.4 above show that for Kamusi 1 compared to Omati Trough 1 model, the heat flow values are generally similar. However the Kanau 1 model used in this study is somewhat higher. This makes the assumption that the Foreland regional heat flow obtained from North Paibuna 1 is representative of the northern Omati Trough. The thickness of erosion cannot be demonstrated to be preserved in wells local to the area, but thicknesses of Upper Ieru of this thickness can be found in the NW of the basin. This finding has important implications for hydrocarbon generation in the area. This is further discussed in Chapter 6.

The generation and expulsion history of the resultant models is reasonably consistent. For example comparison of Figure 5.2 (Kamusi 1) and Omati Trough 1 (Figure 5.26) show a consistent transformation history for the Magobu, showing a significant conversion in the Cretaceous with less significance in the Tertiary. Note that the Triassic was not modeled in Lund et al. (1998). With respect to the Kanau 1 model, Lund et al. (1998) modeled a late charge during the Miocene to present day. Investigation of the model shows that the reason for this difference compared to the results of the current study is that Lund et al. (1998) assumed that ~400m of Era Beds had been deposited prior to uplift. This was discussed in section 5.6.2 and has been

213 further refined due to the availability of new AFTA data, which implies there was no significant late burial.

Fluid inclusion evidence also supports the idea of an Cretaceous charge, expecially for Family L oils from the Triassic source rocks. The Koko 1 fluid inclusion oil is estimated to charge the reservoir at 890C (Middleton & Dutkiewicz 1999). Given that the present day Lower Imburu temperature is ~600C (using later Figure 6.1 and accounting for depth) at present day, the fluid inclusion oil must record a ‘pre-uplift’ temperature, further supporting the idea of an ancient charge.

214

6 DISCUSSION AND PROSPECTIVITY

This section summarises, discusses and integrates the key findings of this thesis regarding oil families, source rocks and charge history of the study area. It has been found that viable petroleum system ‘elements’ exist within the basin for oil. These are important to understanding the heavy oil discoveries at Koko 1 and the greater significance of fresh oil seeps known in the region. The key aim of this chapter is to understand the migration paths and charge history mechanisms that occurred in the area and recommend areas for future exploration of oil. The results will discuss oil primarily but there may also be aspects which assist gas exploration.

6.1 Oil to Source Rock Correlation Summary

Table 6.1 summarises the key relationships relating oil to source rock correlations that have been developed in this thesis and their confidence based on the information available. Note these are the ‘preferred’ interpretations on the basis of the study. Further studies may develop other sources for the various oil families or tie to more specific intervals.

TABLE 6.1 – Oil to Source Rock Correlation Table SOURCE ROCK OIL FAMILY GENERATED BASIS OF CORRELATION CONFIDENCE

LACUSTRINE (FAMILY L) ISOTOPIC AND MODERATE TO UPPER TRIASSIC (Triassic aged shales at Kanau 1) BIOMARKER CORRELATION GOOD LOW TO MARINE CARBONATE (FAMILY MC) BIOMARKER CORRELATION MODERATE

LATE JURASSIC (FAMILY LJ) BIOMARKER ASSEMBLAGE GOOD SIMILAR GEOCHEMISTRY TO FOLDBELT OILS. JURASSIC (Magobu Barikewa Lower Imburu) LOW MATURITY IMPLIES GENERATION INSITU

COALY SOURCED (FAMILY C) BIOMARKER CORRELATION TO SOURCE ROCK GOOD LOW MATURITY IMPLIES GENERATION INSITU MARINE CARBONATE OIL OF NO SOURCE ROCK KNOWN. BIOMARKERS LOW LATE CRETACEOUS - ? TERTIARY (Upper Ieru?) FAMILY O (LATE CRETACEOUS - TERTIARY) INFER AGE AND LITHOLOGY.

Chapter 5 has modeled these source rocks and demonstrate that primarily the Triassic and the Jurassic Magobu Formation are effective sources. Low likelihood models demonstrate the Barikewa may also contribute to oil charge. With an oil to source rock link established the spatial distribution of the oil families can be understood with respect to the location of synrift packages in the basin and hence migration pathways can be established for the oils. The appearance of Family O oils in the fluid inclusions is more problematic and although the source rock remains unclear, explanations will be provided to explain their origin.

215

6.2 Regional Temperatures

In order to understand the charge timing in the study area a key concept for the basin must be developed. Reservoir temperature is known to be a key control over the biodegradation of oil. Larter et al. (2006) indicate that biodegradation of oil occurs in reservoirs which are in contact with a water leg and that have not been exposed to temperatures >800C. In addition, Later et al. (2003) provide time durations for biodegradation of an oil column, suggesting that the time is 1-2 for light oils and 10 - 20Ma for heavy oils. With this in consideration the regional temperature at reservoir level requires assessment. A present day temperature map of the northern portion of the Foreland at top Toro sandstone is shown in Figure 6.1.

Figure 6.1: Corrected Temperature Map for the Toro Sandstone – Present Day (adapted from Schofield ,2001) Red box = Study area

Map shows predominance of low temperatures in the study area with areas exceeding the biodegration threshold of 800C near Kamusi 1 and to the east of Magobu Island 1 The persistence of low temperatures in the Toro Sandstone is evident from Figure 6.1 with the only area where the temperatures are only above the biodegradation

216 threshold in the Kamusi 1 area. Temperatures east of Magobu Island 1 are also near 800C. Note that the mapped areas which are <800C at the Toro Sandstone can also be assumed to be below the degradation threshold at deeper levels, to at least the top of the Barikewa. This comment is based on inspection of corrected temperature gradients shown in a report by Wood (2006). The implication of this map to the charge history is that if a fresh oil has been recovered in a core / extract / cuttings in the Toro to Barikewa section, then it is likely that the oil is a product of a late charge event, that is 20Ma to present day, and if light oils are assumed, consistent with Foldbelt oils, then the charge must be in the period 2Ma to present day. A second option that could be considered is old oil that has leaked from a deeper, hotter trap and has hence been preserved. This second concept is largely dismissed on the grounds that basement is relatively high in the region, eg 1260mSS – 1840mSS at Koko 1 and Komewu 1 respectively, and hence there is little ‘stratigraphic room’ for a deeper hotter trap. This concept may function in the Fly River delta area in the vicinity of Magobu Island 1 where basement is ~2600mSS.

6.3 Oil Maturity

Chapter 3 examined the geochemistry of the known oils in the region (3.3.1 – 3.3.8) in addition the thermal maturity of the oils (3.3.9). This section attempts to understand the pattern and significance of maturity in the area, particularly with respect to oil families to develop prospectivity.

A graph of oil maturities are summarised in Figure 6.2. The maturity values are colour coded by oil family and ranked from low to high, with a maturity range of 0.45 – 1 Vr. Note that this diagram does not include all oils, some of which are too biodegraded to be reliable, or are mixed oils where the contribution of different oils is likely to give an unrealistic value. The exception at Kimu 1 (1873.5m) is given since Alexander (1999) considered this oil to contain very minimal biodegraded oil. As described in Chapter 3.9, maturity measurements are only valid over certain biodegradation ranges. Hence, using the Wenger scale (Table 3.3) those oils with biodegradation of up to level 3 use MPI derived maturity values since this is the beginning of degradation for methylphenalthrene. For oils with biodegradation >3 but <7 the maturity relation from steranes are used. Oils with biodegradation > level 7 are not included. The onset of oil generation threshold from Waples (1980)

OIL FAMILY KEY Family O Figure 6.2: Maturity Ranking Diagram Family LJ Family C Mature Oils Family MC Family L Unknown Family Low Maturity 0.65 Vr #

Figure shows the range of measured maturities (where reliable/available) for the study which range from 0.45 - 1 Vr. Affiliated oil families are shown in colour as listed in key. The #onset of oil generation is shown based on Waples (1980). Oil from Kimu 1 at 1873.5m is shown as a mixed ?biodegraded family with fresh Family MC oil, whose maturity would normally be unreliable due to the mixed nature but is included since the oil is interpreted to consist primarily of a single oil. The maturity of the oils is consistent with others oils from Famliy MC. Figure shows that 217 approximately half of the oils are of low maturity and primarily belong to Family LJ and Family C. Mature oils >0.65 consist of Family MC / L / C / O and unknown families. 218 of 0.65 Vr is also indicated on the diagram. This is a broadly indicative value for the onset of petroleum generation in source rocks. Based on the value of 0.65 Vr, the oils can be broken down into two major groups, as shown in Figure 6.2 and are outlined as follows:

• Low maturity: 12 of the 24 oils shown in the diagram are low maturity and have been generated near or very near the source rock. These are largely represented by oils from Family LJ and Family C. Two oils are noted to be derived from the Triassic from Kanau 1 - Family L and another from an unknown family. Maturity of oils in this group range from 0.45 to 0.62 Vr.

• Mature oils: 12 of the 24 oils are observed to have been generated within the oil window and range from 0.69 – 1 Vr, the oils belong to a variety of oil families including Family L, Family MC, Family C and Family O.

Prior to detailed discussion of the mature oils, the significance of low maturity oil with respect to migration will be discussed here. Figure 6.3 shows a map of these low maturity oils – the predominance of low maturity for oils in the data collection for Family LJ and Family C. This is a feature common to both northern and southern portions of the study area. There is a suggestion that maturity is increasing in a SE direction into the deeper portion of the Omati Trough. Based on maturity values < 0.65 Vr, these oils are interpreted to have been expelled at or near the source rocks. Oils on Figure 6.3, constituting oils from Family LJ and C for the purposes of this assessment of commercial hydrocarbons, are probably unimportant to the study area. This comment is based on the results above which show approximately half of the identified oils demonstate maturity levels, are below the onset of oil generation. The Family L and unknown oils found at Kanau 1 are consistent with the idea of the Triassic representing a source rock (section 3.3.8). From Figure 6.3 it is interesting to note that along strike, deeper into the Omati Trough, oils recovered at Omati 1 are classified by Waples and Wulff (1996) to be part of the foldbelt fields, or Family 3 – (see Figure 3.1). Therefore, it appears logical to assume that the Late Jurassic, sources to Family LJ, although immature in the study area becomes deeper and thermally mature in a SE direction where these sources reach much higher levels of thermal maturity.

219 Figure 6.3 - Oil Maturity Distribution Map - Low Maturity Oils (<0.65%Vr) Map shows the distribution of low maturity oils. These oils are interpreted to be derived insitu from source Rocks in near vicinity. The progenitor source rocks for these oils have been insufficiently buried to reach peak expulsion. There is a slight increase in maturity in a SE direction along the axis of the Omati Trough. Oil at Omati 1 recovered by DST indicate that Family LJ sources have reached peak expulsion in this area likely to due to deeper burial, identified at Late Jurassic source by Waples and Wulff (1996)

0.61% (Magobu) 0.50% (Iagifu Sand) 0.58% (Triassic) 0.60% (Triassic)

0.45%0.45% ((ImburuIm D) 0.54% ((ClathrataCla Sand) Late Jurassic 0.61% (Lower Imburu) Sourced Oil 0.62% (Barikewa)

0.62% (Magobu)

0.51% (Magobu)

0.61% (Magobu) 0.61% (Magobu)

Iamara 1 Adiba 1 Magobu Island 1 Koko 1 Komewu 2 Kimu 1 Bujon 1 Kanau 1

Darai Limestone Ieru Alene / Toro Imburu Hedinia to Koi Iange

Barikewa & 5km Magobu Basement

Triassic (synrift) 200km Note: Cross section is indicative and not to scale - distances are approximate. 220

6.4 Oil Migration

To understand the regional distribution of the maturity, migration and physical state of the oils, the location, maturity and families from Figure 6.2 have been plotted on maps as Figure 6.4 – 6.5 and 6.7. The low maturity set were discussed in 6.3 and are not further discussed here. The oils are broken into 3 groups 1) mature oils - biodegraded 2) mature oils – fresh 3) mature oils - fluid inclusions. Each group is described as follows:

1) Figure 6.4 demonstrates the distribution of biodegraded oils. Note that no maturity information is available for these oils due to their biodegraded nature. The exception is the Koko 1 - 1163m (a FI oil but shown here for completeness) which shows a maturity of 0.74 Vr. This oil is interpreted to have trapped a pristine version of the biodegraded oil which was recovered from the Lower Imburu reservoir (Volk et al. 2005). Hence the declaration that these oils are mature is primarily based on the concept that the oils are found in reservoirs, not source rocks, and are linked to the same oil family as Koko 1 FI oil and is hence interpreted to have a similar history. A feature that is evident is that oils belonging to Family L are the predominant biodegraded oil family and are always found on the footwalls of major faults; in this case the Darai and Komewu Faults, in addition to a less well constrained basin fault on the edge of the Aramia Graben (after Barndollar 1993) where Family L oil is found at Adiba 1. Family L is interpreted to be derived from a lake source rock within a Triassic synrift (3.3.8) which are typically developed in the hangingwall of these faults (Figure 5.17). The biodegraded oils are likely to have developed due to early maturation of Triassic synrift source rocks during the Cretaceous, demonstrated in Chapter 5, and hence this oil is consistent with an old charge. An inferred migration pathway between these synrifts and footwall highs are drawn as shown where oil is interpreted to have exploited the fault zone to access shallower reservoirs. The concept of footwalls as early formed traps containing oil was discussed by Fisher and Warburton (1996), who posed the possiblity Mananda – Kutubu and Gobe fields may have been formed by virtue of their footwall position to the Kubor Basin. A single biodegraded oil found at Kimu 1 belongs to an uncertain family. Without further evidence, the biodegraded nature of this oil suggests it is derived from an old expulsion event, either a highly degraded Family L oil where the key biomarkers have been removed, or oil with a similar age of charge and similar biodegradation history but from a different source rock.

221 Figure 6.4 - Map of Mature oils - Biodegraded Oils

Map shows the distribution of biodegraded oils, typically belonging to Family L, but an unknown oil at Kimu 1 is also observed. The spatial relationship of these oils on the footwalls of major faults suggests That the oil is derived from synrift packages on the hangingwall of these faults.

(no maturitmaturityy calculated)calculated)

0.74%074%0.74% (Lower(Lower ImburuIbImburu FI)

Depocentre Containing mature Jurassic and Triassic source rocks

Aramia Graben

no maturity calculated

Iamara 1 Adiba 1 Magobu Island 1 Koko 1 Kamusi 1X Kimu 1 Bujon 1 Kanau 1

Darai Limestone Ieru Alene / Toro Imburu Hedinia to Koi Iange

Barikewa & 5km Magobu Basement

Triassic (synrift) 200km Note: Cross section is indicative and not to scale - distances are approximate. 222

2) Figure 6.5 demonstrates the distribution of mature – fresh oils. Fresh oils, are interpreted to be related to late charge, probably due to burial of Triassic or Late Jurassic source rocks during the period 20Ma – present day (Chapter 5). Family MC oils are recorded as a fresh overprint mixed with biodegraded oil of unknown family at Kimu 1. Family MC oil are also interpreted at the Panakawa and PPL 77 seeps, which together with oil at Kimu 1 form a radiating pattern around the syn-rift package located near the Komewu Fault (Figure 5.7). Although this pattern of similar oils, in addition to evidence for an oil to source correlation (3.3.8) to the synrift appears to indicate the oil emanates from the source pod near Kamusi 1X / Omati Trough 1, evidence from basin modelling (Section 5.7) suggests against this. Modelling demonstrates that at the Omati Trough 1 location no late charge occurs from Triassic source rocks. Only the Magobu is involved in late charge, or Barikewa in high heat flow models, and oil from these sources would probably belong to either Family LJ or Family C (Chapter 3 & 4). Hence, attention turns deeper into the Omati Trough – the Omati Trough 2 area where transformation increases from 90 – 98% - (Figure 5.31) for the Triassic and a more likely location of mature source for this oil. Oil at Bujon 1 does not appear to belong to Family MC but records a dual charge from Family L source rocks (3.3.7), an earlier biodegraded with a later fresh oil. The origin of Bujon 1 oil is also attributed as from the Omati Trough 2 area where conversion of the Triassic source rock for this oil are more likely. Oils in the southern or Fly River delta region record a different charge signature. At the Iamara 1 well, two oil extracts obtained from the Magobu hint to mature fresh oils from a coal source rock. A third extract demonstrates the presence of a mixed oil containing biomarkers from Family L and Family O (3.3.7). The maturity of this oil is not shown on Figure 6.2 but if the values of 0.78 Vr is representative and not in error due to the mixed nature of the oil, this would indicate a mature oil. Interestingly the value is similar but slightly higher than the Koko 1 FI oil of 0.74 Vr - belonging to Family L. Given the mature nature of these oils, a younger charge event is invoked since low temperatures also prevail at the Iamara 1 well (see Figure 6.1).

223 Figure 6.5 - Map of Mature Oils - Fresh Oils Map shows the distribution of fresh mature oils which are likely derived from late burial of source rocks. Basin modelling suggests that the source is of late oils at Bujon 1 and Kimu 1 are likely to be derived from the Omati Trough 2 area. Basin geometry and presence of a synrift on seisimic line PG90-24 depocenture is a likely origin for mature relatively fresh oil recovered at Iamara 1.

Depocentre Containing mature Jurassic and Triassic source rocks 0.80% Wabuda 1 Aramia Graben 0.86% Top Carbonate 0.5

Base 1.0 Time Way Two Iagifu

Carbonate (seconds) Sandstone

2.0 Top Jurassic Syn AND/OR Rift Triassic Basement 3.0 Source Rocks? 3.5

Mixed L / O oil (Magobu) PA90-24 0.74% (Magobu) 0.70% (Magobu)

Cross Section Figure 6.6

Iamara 1 Adiba 1 Magobu Island 1 Kamusi 1X Kimu 1 Bujon 1 Kanau 1 Panakawa PPL77

Darai Limestone Ieru Alene / Toro Imburu Hedinia to Koi Iange

Barikewa & 5km Magobu Basement

Triassic (synrift)

200km Note: Cross section is indicative and not to scale - distances are approximate. 224

The origin of hydrocarbons for these oils can be developed through evidence presented by Mollan and Blackburn (1990). Mapping in the area of the Fly River delta by Mollan and Blackburn (1990) indicate a series of NW-SE faults which mostly have normal styles with some syndepositional growth down to the north east and a series of less common faults in an east-west direction, mirrored by the linear edges along the margins, with a basinal low roughly centred on the Fly River delta. These patterns indicated a deepening trough in an easterly direction and is demonstrated in a cross section for this area, shown in Figure 6.6.

Figure 6.6: Cross section through the Fly River delta area (from Mollan and Blackburn 1990)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Cross section position shown in Figure 6.5. Correlation shows the thickening of all formations in a basin-ward direction. Erosion or basinward thinning occurs towards Kusa 1 and Goari 1. The position of the oil generation zone is shown (2700m), Magobu which is interpreted by Burns and Bein (1980) to occur just below TD of the Island 1 Magobu Island 1 well. The base of the oil generation zone occurs at 4800m.

Figure 6.5 also includes an interpreted seismic line - PA90-24. The seismic line consists of poor quality seismic, particularly in the lower portion of the section. However, the nature of the shallow reflectors is constrained by reference to the Magobu Island 1 and Wabuda 1 wells. Interpretation of this line appears to demonstrate the presence of a half graben in the deep section, a fault primarily mapped by the relative offset of a probable basement reflector, the actual fault not visible. The divergence of a pick named Top Syn Rift and the Top Basement pick

225 shows that growth of the Jurassic and/or Triassic seems plausible. Growth against this major fault introduces the possibility of source rocks, possibly including Triassic lacustrine rocks consistent with oils of this nature at Iamara 1. This is poor quality data but is reasonable evidence for the existence for a graben in the vicinity of the Fly River Delta. Using Figure 6.6 and evidence for the thermal onset of oil based on Burns and Bein (1980) a broad position of a trough, here informally termed the Fly Delta Trough is drawn on Figure 6.5 which appears to onset just below TD of the Magobu Island 1 well. Mollan and Blackburn (1990) describe the most likely drainage direction based on seismic interpretation to be updip to the south west, probably toward the Oriomo High and a migration path is drawn on Figure 6.5 consistent with recovery of oil at Iamara 1. Note that although oil of Family O was recovered, thought to be derived from a Late Cretaceous to Tertiary source, neither the Ieru or Darai Limestone fall below the top of the oil generation threshold. This suggests that either longer distance migration is required from the east where the basin is deeper, or that this biomarker is related to an earlier oil charge when the basin was deeper, and that migration of Family L oil picked up oleanane along the migration path.

3) Several of these oils belonging to Family O are related to oils trapped in fluid inclusions, shown on Figure 6.7. Maturity for these oils is 0.9 - 1Vr in the south and 0.69-0.76Vr in the north of the study area. Note that fluid inclusion oil for Family L is left out from Figure 6.7 since it is believed related to a preserved oil related to the discussion on Mature – biodegraded oils. The fluid inclusion nature of these oils suggests these oils record an earlier charge than is now found within their respective reservoirs. As discussed in section 3.3.5, oils of a similar geochemistry are also found within fluid inclusions in the Foldbelt fields (George et al. 1997) possessing an anoxic signature, carbonate influenced and higher maturity than conventional Foldbelt oils. These oils are no longer found within pore space within the reservoirs and which is interpreted to have been swept by later oil charges. Evidence for this exists at Bujon 1 where a fluid inclusion oil from Family O is found in the Toro Sandsone with GOI values of ~10-21%, showing that the Toro once contained a paleo-oil column of 12- 16m in height (Kreiger ,1995). As shown in Chapter 3, the Toro reservoir now contains oil from Family L in addition to a gas charge (Figure 2.4). No source rock for Family O oils have been identified. Hence without other information the migration path for oils at Bujon 1 and Kimu 1 is inferred to be

226 Figure 6.7 - Map of Mature Oils - Fluid Inclusion Oils Map shows the distribution of fluid inclusion oils, which entire belong to Family O. (Koko 1 oil not shown since Family L). The source rock / mature depocentre for these oils is unknown but is suggested to be to the east for Magobu Island 1 oil where the basin deep is located. Bujon and Kimu oils are suggested to be sourced from the north, based on fluid inclusion evidence that Foldbelt fluid inclusion oils are similar to the Bujon 1 oils Foldbelt

0.76% Toro Sand

0.69% Hedinia Sand

Depocentre Containing mature Jurassic and Triassic source rocks

Aramia Graben

0.9-1.0% Iagifu / Koi Iange

Iamara 1 Adiba 1 Magobu Island 1 Koko 1 Kamusi 1X Kimu 1 Bujon 1 Kanau 1

Darai Limestone Ieru Alene / Toro Imburu Hedinia to Koi Iange

Barikewa & 5km Magobu Basement Triassic (synrift) 200km

Note: Cross section is indicative and not to scale - distances are approximate. 227 from a basinal deep in the vicinity of the Foldbelt, probably the Kubor Kitchen, where oils of this nature are known. For the Magobu Island 1 FI oils, the most likely origin of these is from a basinal deep to the east towards where the basin is thickest and is the most likely region where Late Cretaceous – Tertiary age source rocks might be mature.

6.5 Gas Charge

The Foreland study by ECL (2005) examined isotopic data from gases at Koko 1 as well as Kimu 1 and concluded “The Koko & Kimu gases are very dry gases which are mixtures of biogenic & thermogenic gases”. This is demonstrated in Figure 6.8 which shows isotopic data from gases of Kimu, Koko, Foldbelt gases as well as gases from the NW Shelf of Australia.

Figure 6.8: Carbon Isotopic data from PNG Foldbelt gases, Kimu 1,Koko 1 and NW shelf gases (after ECL 2005)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

The thermogenic gases show a linear trend with the Kimu and Koko gases to the

228

SE of this trend, suggesting an elevated biogenic component. The biogenic component is thought to have been derived from the biodegradation of oil or wet gas associated oil. However, the isotopic composition of the methanes with values of approximately -45 to -48 13C indicate these gases are not entirely biogenic, since typically biogenic gases have 13C values of -60 to -90, and thermogenic gases have values of about -50 (Waples 1985). The relationship of the Koko dry gas within the Lower Imburu reservoir above a biodegraded oil leg (Figure 2.3) is seen as consistent with this model. Basin modeling also shows that early charged oil will have long residence times, since charge began as early as 135Ma, with cooling probably beginning following uplift and erosion associated with Coral Sea Rift, at 50–60Ma. Since biodegradation is interpreted to be an early event the thermogenic component is interpreted to be added as a late charge, probably due to maturation of Magobu source rocks during the Miocene to present day. Modelling of oil versus gas charge was not assessed in Chapter 5, however as shown in Figure 4.3, a Type II/III source generates a mixed oil and gas charge. The above results will be synthesised into the following charge history description.

6.6 Charge History

The charge history in general terms appears to be a story of old oils and new oils. That is that some charge events occurred in the Cretaceous and others have been caused by Tertiary burial leading to oil generation from the Miocene to Present day. This is reflected in the physical state of the oils recovered in the area where both mixed and fresh are observed, and sometimes are mixed together. Up to three oil charges appear to be recorded in wells a good example is Bujon 1, which contains Family O oil within fluid inclusions, a biodegraded Family L oil with the Toro reservoir overprinted with a fresh oil pulse also from Family L oil (3.3.7).

The following cartoon figures in Figure 6.9 depict the probable charge history for the Darai Plateau to northern Omati Trough area, based on what is understood from geochemistry, fluid inclusion evidence, source rocks and burial history. Wood and Heidorn (2007) through carefull seismic interpretation date the age of the Kimu fault structure at Eocene age. However, in Figure 6.9 the Kimu structure is depicted as a basement drape to put in place an ancient feature. This because if the gas model presented in 6.5 is accepted, then a ‘paleo’ – Kimu or a nearby structure is required in order to capture and biodegrade the gas necessary to fill

229 FIGURE 6.9: Charge History of the Foldbelt a) Family O Upper Turama River Area oil from

1) EARLY TO LATE CRETACEOUS a) Charge from north provide Family O charge oil charge to Bujon 1 and Kimu 1 (source rock unknown) ’ Family O oil out • Oil expulsion from Triassic and Magobu b) Family L source rocks in the Omati Trough and ‘sweeps Darai Plateau) b) Basement drape structures charged with Family L oil. Family O oils ‘swept away’ from Bujon 1 / Kimu 1

Triassic to Middle-Late Jurassic containing source rocks. Lacustrine / Marine Carbonate (Triassic) and mixed Type II/III sources (Magobu, Barikewa, Remove green Lower Imburu) arrowsErosion 2) LATE CRETACEOUS TO PALEOCENE Erosion • Uplift and erosion of the Upper Ieru due to the Coral Sea Rift event • Reduction in reservoir temperature <800C leads to biodegradation of oils creating dry gas as a by-product

3) MIOCENE • Late charge due to source rock ‘reburial’ by the Darai Limestone in Omati Trough only Charge primarily contributed by the Magobu, which includes gas and minor contribution by the Triassic • Oil re-charge to Kimu 1 and Bujon 1 by Triassic synrift source rocks - Family MC and L Respectively

4) PLIOCENE TO PRESENT DAY • Deposition of the Era Beds • Oil / gas charge continues • Uplift along the Darai Fault creates the Darai Plateau

Gas Migration / Accumulation Oil Migration / Accumulation 230

Kimu. This is required since no ‘palaeo’ oil column is observed at the Kimu 1 well, only intense oil migration (Middleton and Dutkiewicz ,1999). The concept can be supported by basement structuring to the north of Kimu, visible on Figure 2.2.

6.7 Play Fairway Map

Figure 6.10 depicts a play fairway map for the region primarily for oil but gas is also shown, based on areas exposed to long residence time oil. Discussion is not focused on a particular reservoir zone, however evidence has shown that oils appear to be migrating in zones including the Alene, Toro, Hedinia, Iagifu and Koi Iange sandstones and as well as sands within the Magobu Formation. The areas of primary interest are areas based on the presence of late oil charge which is interpreted to be derived from the Triassic synrift, contributing both Family L and Family MC oils in the form of seeps or oil overprints. Late oil is given in two green colours, the lighter green, prevalent in the north, is the probable distribution of a late oil charge, however the prospectivity related to this oil charge is possibly limited. This comment is based on data from Chapter 5, particularly Figure 5.31 where is shown that the conversion of source rocks during the Miocene to present day period is only achieved in the Omati Trough 2 area, and only then demonstrates an increase in Transformation ratio from 90 to 98%, representing an increase of 8%. Hence the volume of this oil charge may be small and although basin modelling (section 5.8) shows mature Magobu sources also exist in this area, the empirical evidence from the oil extract geochemistry show no mature Family LJ or C oils in the area. Also, no oil shows are seen at Kamusi 1 or Kapul 1. Further work is required to understand this contradiction. Chapter 4, particularly Figure 4.11 indicates that the Magobu has only poor to fair source potential and could be a factor. The dark green colour surrounding the Fly River delta area indicates that mature oil is found of a fresh nature and indicates the likely drainage area based on the position of the maturity threshold and mapping by Moller and Blackburn (1990). Basin modelling was not performed in this area, however this does not rule out larger oil volumes in this region, especially with the thickening of the Tertiary section towards the east. Areas of gas charge are primarily based on the distribution of ancient or Cretaceous oil charge, particularly by Family L oils recorded to charge footwall highs. Since fresh oil was not identified at Koko 1, this area is interpreted to be cut off from any late charge related to the oil seeps. Hence to encorporate this, a fault is spectulatively based on the position of a deflection of the Komewu Fault to the SE of Koko 1 as indicated. Section 6.5 discussed the input of a thermogenic gas to both Koko 1 and Kimu 1.

231

Figure 6.10: Oil and gas play fairway map for the study area

Fault

Prospectivity map shows: 1) Late oil in both north and south of study area. 2) Areas likely to be dry gas prone with no evidence of fresh oil charge 232

A possible origin of thermogenic gas at Koko 1 is suggested by a review of the gas composition data (Alexander 1999). Gas at Koko 1 contains an elevated nitrogen component (3.8% in the Lower Imburu) with minor helium (0.2%) and is much higher than nitrogen found at Kimu 1 (0.7%) where helium is below detection levels. Table 2.1 summarised the exploration history and results of the offset wells in the study area and it is noted that the Aramia 1 well flowed gas during several drill stem tests along with abundant brine / formation water. A single analysis from one test in a sand within the Magobu Formation indicates both elevated nitrogen (32%) as well as helium. This intepretation is tentative, but possibly suggests a gas charge from the Aramia Graben area was responsible for adding a thermogenic component to gases at Koko 1. The origin of thermogenic gas at Kimu 1 is uncertain but could represent a contribution from mature Magobu source rocks or gas from mature Triassic source which are demonstrated to be mature in the Omati Trough (section 5.8, 5.7).

233

7 CONCLUSIONS AND RECOMMENDATIONS

7.1 Conclusions

The key conclusions from the study are as follows:

1. Shows, recovered oils and seeps within the study area point to the existence of an oil based petroleum system.

2. Five different oil families have been identified based on a study of geochemical data for recovered oils, oil extracts, fluid inclusion oils and seep oils. The oil families identified include: a. Family L - Lacustrine oil family commonly biodegraded. b. Family MC – Marine carbonate sourced oil. c. Family LJ – Oil similar in nature to oils recovered in the Foldbelt. d. Family C oils – Coal sourced oil. e. Family O – Carbonate sourced oils from a Late Cretaceous to Tertiary source rock, found commonly in fluid inclusions.

A sixth family - Family X, represents mixed oil families consisting of commingled oil between two of the above families a – e.

3. Evidence is presented for an oil to source rock correlation for Triassic shales as a source for Family L oils, with a moderate to good confidence.

4. Evidence is presented for an oil to source rock correlation for Triassic carbonates as a source for Family MC oils, with a low to moderate confidence

5. The source rock for Family LJ oils is likely Late Jurassic (Lower Imburu, Barikewa and/or Magobu Formations), based on an analogy to the Foldbelt. Source rocks capable of oil generation are present in all formations (see later section).

6. Family C oils are likely derived from the Jurassic, probably the Magobu Formation based on source rock data (see point 8c)

234

7. The source for Family O oils is unknown. This is due to both data availability in the Late Cretaceous / Tertiary and the erosive nature of unconformity at the base Darai which has eroded the Late Cretaceous sediments during the Coral Sea Rifting event. Large amounts of erosion are supported by basin modelling.

8. The key results with respect to source rock quality in the study area are as follows: a. The Triassic is a Type I/II source rock. A reconstruction of the original source potential indicates the rock originally had TOC values of 3 - 4% and HI of 450 – 600. b. The Lower Imburu, Barikewa and Magobu Formations have oil source potential with TOC values of 0.5 – 2.5% and HI values of 150 - 500. c. Coals and coaly shales are identified in the Lower Ieru, Lower Imburu, Barikewa and Magobu Formations. However only coals in the Magobu Formation demonstrate oil and gas potential with those in other formations only offering gas potential. Oil prone sources of this type have TOC of 27-55% and HI from 283 – 416. d. Algal rich source rocks containing botrycoccus and other algal species examined in the Kimu 1 well appear to be largely gas prone. e. Upper Ieru, Lower Ieru and Toro Formations are gas prone or non source.

9. Basin modeling work on the northern part of the study area has demonstrated the following: a. That simple models involving either steady state or transient heat flow can be used to match the maturity data in contrast to the previous study by Lund et al. (1998) where dramatic increases and decreases in heat flow were used (Rifting heat flow setting). b. Calibration at Kanau 1 demonstrates that Vr is probably surpressed and that the higher temperature trend from TMax and FAMM is more consistent with data from AFTA. c. Calibration at Kamusi 1X is difficult, probably due to data quality. d. Modelling suggests that the Late Cretaceous charge event is a time when significant transformation occurs, particularly for Triassic source rocks and in most cases the Magobu source rocks. This is due to significant burial by Upper Ieru, which

235 requires substantial erosion amounts which are required to match the data, 1500 - 1600m for favoured models. e. Late charge is only present in the Omati Trough and is absent at the Darai Plateau. The source responsible is primarily the Magobu with minimal contribution from the Triassic. f. Charge is rarely recognised from the Barikewa or younger source rocks, and only in models involving high heat flow. g. Source rock ‘burn out’ during the Cretaceous appears to limit the effectiveness and volume of late charge. This creates a key risk for oil exploration in the study area, especially in younger structures which either do not access source rocks with sufficient source potential remaining during late charge or the charge volume is limited. h. The timing and volume of the Cretaceous charge would indicate that early oil charges have experienced a long residence time for these oils which are a likely reason for dry gases in the region, eg Kimu.

10. Charge history for the Turama River area (northern portion of study area) is as follows: a. Charge by Family O to Bujon 1 and Kimu 1 - source rock unknown. b. Oil expulsion from Triassic and Magobu source rocks in the Omati Trough and Darai Plateau. Basement drape structures charged with Family L oil which sweeps away Family O oils. c. Uplift and erosion of the Upper Ieru due to the Coral Sea Rift event reduces reservoir temperatures to <800C and leads to biodegradation of oils creating dry gas as a by-product. d. Late charge due to source rock ‘reburial’ by the Darai Limestone/Era Beds in the Omati Trough only. Charge primarily contributed by the Magobu, which includes oil/gas and minor contribution of oil by the Triassic. Oil re-charge to Kimu 1 and Bujon 1 by Triassic synrift source rocks - Family MC and L respectively. e. Deposition of the Era Beds leads to further oil / gas charge.

236 f. Uplift along the Darai Fault creates the Darai Plateau.

7.2 Recommendations

Further investigations that should be carried out to develop these exploration concepts further are as follows:

• Further detailed geochemistry on synrift source rock facies in Kanau 1. Kinetics would be desirable to address source ‘burnout’ from the Late Cretaceous event and get a better handle on preservation of source potential for the Miocene to Recent charge.

• Detailed study of regional temperatures, heat flows and thermal conductivities to better constrain the burial history.

• The effect on generation history, when groundwater flow through the Darai Limestone at ~1.5Ma is considered.

• Source rock evaluation of the Kuta Limestone which outcrops on the Kubor range. Does the unit have oil source potential ?

• Source rock evaluation of the Late Cretaceous and any potential carbonates that may have been responsible for oils from Family O.

• Geochemical analysis of the gas seeps south of the Kimu gas field. Are they biogenic or thermogenic ? The later would give further support for a present day expulsion from the Omati Trough 1 and Omati Trough 2 area or simply indicate dry gas products from degradation of oil.

• Further source rock studies on the Magobu to confirm the oil potential – why are mature oils of Family LJ or C not found at wells in the northern portion of the study area when burial history indicates these sources have passed the peak generation window and Rock Eval indicates a mature source. Is primary migration and/or vertical migration a hinderance to Magobu explusion ?

• Volume calculations to estimate amount of oil expelled and hence estimate the volume of gas resulting from biodegradation of oil. Assuming Kimu is a gas field degraded from oil containing ~700bcf is the volume consistent with the size of the gas

237 field ?. Conversely, what volume of gas is generated through the biodegradation of an oil column such as that discovered at Koko 1.

• What role does the thermogenic charge place in charging Kimu, is it of significant volume or is the bulk of the gas biogenic in nature.

• Additional fission track with high quality readings on new wells, incorporating chlorine content measurements. These are essential in estimating the time and intensity of the Late Cretaceous thermal event.

• Only a single burial history model was created for the Darai Plateau. Using the simple approach, and integrating new fission track data, could late charge be expected for the Darai Plateau prior to uplift at 1.5Ma ? A suitable well for this model would be Turama 1, where ~1700m of Darai Limestone is preserved.

• Substitute default thermal conductivity values for actual measurements on typical PNG formations. This would assist in creating more accurate calibrations to well data for use in basin modelling.

• Burial history modelling in the Fly River delta area, probably the stratigraphy on line PA90-24, to give greater confidence to the idea of late charge from the Fly River Delta Trough. A modern seismic programme could probably delineate the existence and size of this trough with greater confidence.

238

8 REFERENCES

AHMED A.S., BEEUNAS M.A., MOLDOWAN J.M., LEE C.Y & HUIZINGA B.J. 1988. Regional Geochemical Project, Papua New Guinea – Volume I. Chevron Oil Field Research Company

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9 APPENDICES

9.1 Koko 1 Carbon Isotope data

Above data courtesy of Chris Boreham – Geoscience Australia

249

APPENDIX 9.2

Geochemistry Data Tables by Oil Family

LIST OF ABBREVIATIONS BNH Bis norhopane

C29 20R The R isomer of the C29 sterane

C29 20S The S isomer of the C29 sterane CPI-1 Carbon Preference Index -1 DIA Diasterane GCMS Gas Chromotography Mass Spectrometry ISO Isosterane MPI-1 Methylphenanthrene Index (1 - after Radke and Welte 1983) nd Not determined Ph Phytane Pr Pristane Ts/Tm Trisnorhopane / Trisnorneohopane Vr Vitrinite Reflectance % Wt% Weight percent 250

APPENDIX 9.2.1: Family L (Lacustrine) Origin Koko 1 - RFT oil - 1163m Oil Volume not published BIOMARKER PARAMETER CPI-1 (22-32) 0.94 Pr / Ph 1.6 C27/C29 Steranes 0.28 C27 / C28 / C29 ISO Steranes % 14 : 30 : 57 C26/C25 Tricyclic Terpanes 1.7 Ts/Tm 0.59 C29 Hop / C30 Hop 0.66 Hopane / Sterane nd Methyhopanes ( / ) 3 Methylhopanes C28,30 BNH* (0.16) Other* 25-Norhopanes (0.25), Carotane, Gammacerane (0.23) C24 Tetracyclic Terpanes (0.12) MATURITY PARAMETERS MPI-1 0.88 Calculated Vr % 0.93 (suspect value given biodegradation level) C29 20S/20S+20R 0.53 Equivalent Vr % Outside Range ISOTOPIC PARAMETERS 13C (Saturates) per mil^ -34.9 13C (Aromatics) per mil^ -33.7 INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a mixed terrestrial environment with input from algal organic matter (C29 and C28 steranes) but Pr/Ph indicates predominantly anoxic conditions. High biodegradation based on the presence of 25 norhopanes and a UCM, presence of Pristane and Phytane suggests addition of minor fresh oil. Presence of Carotane, C26/C25 tricyclic ratio, elevated C28 steranes suggest a lake source rock. Highly biodegraded up to ~level 7. REPORT Koko-1 1163m RFT crude_alks - CSIRO 2002 & Volk et al (2004) ^ Courtesy Geoscience Australia 2008 - See Appendix 9.1 * Ratioed to C30 Hopane nd = not determined 251 Origin Koko 1 - Lower Imburu FI oil. 1159-1162m Oil Volume 1347ng of n-alkanes recovered BIOMARKER PARAMETER CPI-1 (22-32) 1.03 Pr / Ph 2 C27/C29 Steranes 0.27 C27 / C28 / C29 Steranes % 22 : 30 : 48 C26/C25 Tricyclic Terpanes 1.5 Ts/Tm 0.46 C29 Hop / C30 Hop 0.62 C30 Hopane / C29 Sterane nd Methyhopanes ( / ) 3 Dominant C28,30 BNH* (0.2) Other* B Carotane, Gammacerane (0.19) Tet Terp (0.15) 25 Norhopanes (0.14). Minor dibenzothiophene, Elevated Tricyclic Terpanes (C19-29) MATURITY PARAMETERS MPI-1 0.55 Calculated Vr % 0.73 C29 20S/20S+20R 0.52 Equivalent Vr % NA ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a mixed terrestrial environment with input from algal organic matter (C29 and C28 steranes) but Pr/Ph indicates suboxic conditions. Presence of B carotane, C26/C25 tricyclic ratio, elevated C28 steranes 25 norhopanes are present but oil not fresh ie no biodegradation. REPORT Koko-1 1163m RFT crude Status 12-NOV-02 & Volk etl al (2004) * Ratioed to C30 Hopane nd = not determined 252 Name Adiba 1 - SWC - Extract - Toro Sandstone Depth 1374m Amount Analysed 1995.9ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.1 Pr / Ph 3.6 C27/C29 Steranes 0.94 C27 / C28 / C29 ISO Steranes % 33 : 32 : 35 C26/C25 Tricyclic Terpanes 2.13 Ts/Tm 0.49 C29 Hop / C30 Hop 0.73 Hopane / Sterane nd Methyhopanes ( / ) C32 3 present C28,30 BNH* nd Other* 25-Norhopanes (0.19) Gammacerane (0.18) Elevated Tricyclic Terpanes (C21-29) MATURITY PARAMETERS MPI-1 0.64 Calculated Vr % 0.78 Vr (unreliable due to biodegradation) C29 20S/20S+20R 0.86 Equivalent Vr % Outside Range ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd NTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Oil has been derived from a lacustrine source rock (carotanes, gammacerane, C28 steranes) Oil has been subject to significant biodegradation based on presence of a significant UCM and elevated levels of 25 norhopanes to level 5-6 DATA SOURCE Geotech Analysis - 1995 * Ratioed to C30 Hopane nd = Not determined 253 Origin Bujon 1 - SWC Extract - Barikewa Depth 2075m Extracted Organic Matter (EOM) 2.14% Saturate GCMS BIOMARKER PARAMETER CPI-1 (22-32) nd Pr / Ph - C27/C29 Steranes 0.33 C27 / C28 / C29 Steranes % 15 : 40 : 45 C26/C25 Tricyclic Terpanes 1.43 Ts/Tm 1.92 C29 Hop / C30 Hop 0.51 Hopane to Sterane 1.39 Methylhopanes ( / ) ? C28,30 BNH* 0.14 Other* and Carotane

C28,30 BNH* nd 17 Other* 25-Norhopanes(0.24) Pr MATURITY PARAMETERS MPI-1 0.94 Calculated Vr % 0.96 C29 20S/20S+20R 0.25 Equivalent Vr % 0.50 ISOTOPIC PARAMETERS 13 d C (Saturates) per mil nd 12 d13C (Aromatics) per mil nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a mixed terrestrial environment with input from algal organic matter (C29 and C28 steranes). Biodegradation indicated by presence of UCM and 25 norhopanes Elevated C28 steranes tentatively suggest a lake source rock. Conflicting maturities probably due to biodegradation. REPORT RP7973 - Geotech HC Charac. Report * Ratioed to C30 Hopane nd = not determined 0.2545625 255 Origin Koko 1 - Cuttings Extract - Hedinia Sandstone Depth 1042m Oil Volume 954.2ppm Saturate GCMS BIOMARKER PARAMETER Chromato gra m obtain ed from the a nalysis of saturated hyd roca rbo n s by GC -MS CPI-1 (22-32) 1.09

Pr / Ph 1.37 22 C27/C29 Steranes 0.60 C27 / C28 / C29 Steranes % 27 : 29 : 44 C26/C25 Tricyclic Terpanes 0.72 Ts/Tm 0.82 C29 Hop / C30 Hop 0.73

C30 Hopane / C29 Sterane nd 18 Methyhopanes ( / ) nd C28,30 BNH* nd Other* 25-Norhopanes (0.11) 17 Pr MATURITY PARAMETERS Ph MPI-1 0.82 Calculated Vr % 0.9 C29 20S/20S+20R 0.18 Equivalent Vr % 0.46 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 12 13C (Aromatics) per mil nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a mixed terrestrial environment with input from algal organic matter (C29 and C28 steranes). Biodegradation indicated by presence of UCM and 25 norhopanes Elevated C28 steranes tentatively suggest a lake source rock. Conflicting maturities probably due to biodegradation. REPORT RP7973 - Geotech HC Charac. Report * Ratioed to C30 Hopane nd = not determined

0.178592484 256 Name Kanau 1-Extract-Triassic Depth 3505-3519m Amount Analysed 1550ppm Saturate GCMS BIOMARKER PARAMETER CPI-1 (22-32) 1.16 Pr / Ph 1.17 C27/C29 Steranes 0.35 C27 / C28 / C29 Steranes % 14 : 46 : 40 C26/C25 Tricyclic Terpanes 0.75 (co-elution?) Ts/Tm 0.85 C29 Hop / C30 Hop 0.41 C30 Hopane / C29 Sterane 2.44 Methyhopanes ( / ) nd C28,30 BNH* nd Other* Gammacerane (0.25), extended Tricyclic Terpanes (C19 - C24) C24 tetracyclic terpane (0.1) MATURITY PARAMETERS MPI-1 nd Calculated Vr % - C29 20S/20S+20R 0.38 Equivalent Vr % 0.58 ISOTOPIC PARAMETERS 13C (Saturates) per mil -32.4 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in an anoxic, hypersaline environment and shows input of significant algal organic matter, based on the abundance of C28 steranes and the extended Tricyclic Terpanes. Early level of thermal maturity, probably generated insitu. Geochemistry indicates origin from a lake source rock DATA SOURCE Robertson Research Report (1990) * Ratioed to C30 Hopane nd = not determined nd = Not Detected 0.380035515 257 258

APPENDIX 9.2.2: Family MC (Marine-Carbonate) Name Panakawa Oil Seep Depth NA (surface seep) Amount Analysed NA (bottled oil) BIOMARKER PARAMETER Saturate GC MS CPI-1 (22-32) 1 Pr / Ph 0.97 C27/C29 DIA Steranes 2.27 C27 / C28 / C29 Normal Steranes % 48 : 24 : 28 C26/C25 Tricyclic Terpanes 0.36 Ts/Tm 1.38 C29 Hop / C30 Hop 2.19 Hopane / Sterane 0.43 Methylhopanes ( / ) 2 Methylhopanes C28,30 BNH* nd Other* Dibenzothiophene,C24 Tetracyclic Terpane Extended Tricyclic Terpanes down to C19 MATURITY PARAMETERS MPI-1 0.76 Calculated Vr% 0.86 Vr C29 20S/20S+20R nd Equivalent Vr% - ISOTOPIC PARAMETERS 13C (Saturates) per mil # -27.3 13C (Aromatics) per mil # -26.3 Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a marine anoxic envionment with lesser input of terrestrial organic matter. Carbonate signature (C29/C30 hopane) Extended tricyclics present (algal input). Very slight biodegradation present. DATA SOURCE Geotech Hydrocarbon Characterisation Study - 2006 * Ratioed to C30 Hopane # No analysis report available. Values estimated nd = Not determined from JPreston (2007) graphs 259 Name PPL77 Oil Seep Depth NA (surface seep) Amount Analysed NA (bottled oil) Saturate GC MS BIOMARKER PARAMETER CPI-1 (22-32) 1.05 Pr / Ph 1.22 C27/C29 DIA Steranes nd C27 / C28 / C29 Steranes % nd C26/C25 Tricyclic Terpanes nd Ts/Ts+Tm 0.61 C29 Hop / C30 Hop nd C30 Hopane / C29 Sterane nd Methyhopanes ( / ) nd C28,30 BNH* nd Other* nd MATURITY PARAMETERS MPI-1 nd Calculated Vr % nd C29 20S/20S+20R 0.51 Equivalent Vr % 0.80 ISOTOPIC PARAMETERS 13C (Saturates) per mil -27.7 (whole oil?) 13C (Aromatics) per mil nd Sulphur (wt%) 0.18% INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Minimal information available. Generated from an anoxic source rock. Mid to late oil mature source rock Slight water washing and biodegradation evident. DATA SOURCE Koumaio - Biwai Hills Seep - Daly and Severson - 1991 * Ratioed to C30 Hopane nd = Not determined

0.508928 260 Name Kanau 1 - Extract - Triassic Depth 3476m Amount Analysed 31.18mg Saturate GCMS BIOMARKER PARAMETER CPI-1 (22-32) 1 Pr / Ph 1.5 C27/C29 Steranes 1.67 C27 / C28 / C29 Steranes % 49 : 22 : 29 C26/C25 Tricyclic Terpanes 0.8 Ts/Tm 0.59 C29 Hop / C30 Hop 1.40 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) 2 Dominant C28,30 BNH* (0.32) Other* 30 Norhopanes(0.12), dinosteranes, alkyldibenzothiophenes C24 Tetracyclic Terpanes (0.39) MATURITY PARAMETERS MPI-1 0.88 Calculated Vr % 0.93 C29 20S/20S+20R 0.45 Equivalent Vr % 0.63 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a marine environment (dinosteranes and C27 steranes) in a suboxic to anoxic conditions. Lesser input of terrestrial organic matter. A carbonate signature for the source is indicated by the C29/C30 Hopane ratio and presence of alkydibenzothiophenes DATA SOURCE RP12226 - CSIRO - Evaluation of a Triassic Sample at Kanau 1 - 2007 * Ratioed to C30 Hopane nd = not determined

0.44717348 261 262

APPENDIX 9.2.3: Family LJ (Late Jurassic Sourced) Origin Kimu 1 - Extract - Lwr Imburu SS Depth 2024.5m Amount Analysed 756.9ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.59 Pr / Ph 4.65 C27/C29 Steranes 0.38 C27 / C28 / C29 Steranes % 22 : 20 : 58 C26/C25 Tricyclic Terpanes nd Ts/Tm 0.28 C29 Hop / C30 Hop 0.67 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) 2 Dominant C28,30 BNH* nd Other*

MATURITY PARAMETERS MPI-1 0.35 Calculated Vr % 0.61 C29 20S/20S+20R 0.2 Equivalent Vr % 0.47 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Oil from oxic source with significant terrestrial organic matter. Low maturity oil probably generated insitu. DATA SOURCE RP7973 - Geotech HC Charac. Report - 1999 * Ratioed to C30 Hopane nd = not determined nd Not Detected 0.198036016 263 Origin Korobosea 1- Imburu D - 2069m Oil Volume 556ppm Sample : KOROBOSEA -1, 2069.0m, Cuttings BIOMARKER PARAMETER File ID : 379802S CPI-1 (22-32) 1 Chromatogram obtained from the analysis of saturated hydrocarbon s by GC -MS Pr / Ph 4.15 18 C27/C29 Steranes 0.79 C27 / C28 / C29 Steranes % 35 : 20 : 45 C26/C25 Tricyclic Terpanes nd Ts/Tm 0.20 Two Oils ? C29 Hop / C30 Hop 0.91 C30 Hopane / C29 Sterane None Methyhopanes ( / ) 2 Dominant C28,30 BNH* (0.1) Other* Oleanane (0.05) Abundant C24 Tet. Terp. 17 C25 Norhopane (0.06) Diahopane (0.08) Pr MATURITY PARAMETERS 22 MPI-1 nd Calculated Vr % nd C29 20S/20S+20R 0.15 Ph 31 Equivalent Vr % 0.45 ISOTOPIC PARAMETERS 13 C (Saturates) per mil nd 12 13 C (Aromatics) per mil nd Mud 13 C nd Contamination Sulphur (wt%) nd GEOTECHNICAL SERVICES PTY LTD INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Derived from a mixed marine terrestrial source rock, mixed oil? Low maturity implies generation insitu. Oleanane peak is minimal - not believed as an indicator of source rock age. Two oils ? Indications of mud contamination. REPORT Geotech Analysis 2008 * Ratioed to C30 Hopane nd = not determined

0.148803258 264 Origin Korobosea 1- Clathrata Sandstone - 2087m Oil Volume 271ppm BIOMARKER PARAMETER Sample : KOROBOSEA -1, 2087m, Cuttings CPI-1 (22-32) 1.11 File ID : 379813S

Pr / Ph 1.37 Chromatogram obtained from the analysis of saturated hydrocarbon s by GC -MS C27/C29 Steranes 0.48 C27 / C28 / C29 Steranes % 26 : 21 : 53

C26/C25 Tricyclic Terpanes 0.67 18 Ts/Tm 0.41 C29 Hop / C30 Hop 0.76 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) 2 Dominant C28,30 BNH* (0.2) Other* Oleanane (0.05) C25 Norhopane (0.05) Diahopane (0.07) 17 MATURITY PARAMETERS MPI-1 nd

Calculated Vr % - Pr C29 20S/20S+20R 0.32 Ph Biodegradation OR mud contamination ? Equivalent Vr % 0.54 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd 22 Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT 31 12 Derived from a terrestrial with lesser terrestrial input. Low maturity implies generation insitu. Oleanane is suspect (low vol volume) Mud Contamination Evidence of mud contamination since 25 norhopanes levels do not suggest biodegradation GEOTEC H N IC AL SER VIC ES PTY LTD DATA SOURCE Geotech Analysis 2008 * Ratioed to C30 Hopane nd = not determined nd Not Detected 0.316626006 265 Origin Magobu Island 1 - Magobu - 2390m Extract Volume 5825ppm BIOMARKER PARAMETER Saturate GC MS CPI-1 (22-32) 1.19 Pr / Ph 1.0 C27/C29 Steranes 0.19 C27 / C28 / C29 Steranes % 13 :18 : 69 C26/C25 Tricyclic Terpanes nd Ts/Tm 0.21 C29 Hop / C30 Hop 0.78 C30 Hopane / C29 Sterane 3.75 Methyhopanes ( / ) nd C28,30 BNH* nd Other* Diahopane (0.12) MATURITY PARAMETERS MPI-1 nd Calculated Vr % nd C29 20S/20S+20R 0.42 Equivalent Vr % 0.61 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Extract derived from a source rock containing primarily terrestrial organic matter. Low maturity suggests oil probably has been generated insitu. Waxy oil (dominance of carbons >C22) DATA SOURCE Robertston Researh Report - 1990 * Ratioed to C30 Hopane nd = Not determined

0.420047266 266 Origin Kimu 1 - Extract - Barikewa Depth 2244m Amount Analysed 499.2ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.77 Pr / Ph 4.6 C27/C29 Steranes 0.49 C27 / C28 / C29 Steranes % 26 : 21 : 53 C26/C25 Tricyclic Terpanes nd Ts/Tm 0.41 C29 Hop / C30 Hop 0.64 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) 2 Dominant C28,30 BNH* nd Other*

MATURITY PARAMETERS MPI-1 0.37 Calculated Vr % 0.62 C29 20S/20S+20R 0.27 Equivalent Vr % 0.51 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Oil from oxic source with significant terrestrial organic matter. Low maturity oil probably generated insitu. DATA SOURCE RP7973 - Geotech HC Charac. Report - 1999 * Ratioed to C30 Hopane nd = not determined nd Not Detected 0.272775223 267 Origin Kanau 1 - Extract (Special SIM) - Iagifu Depth 1635m Amount Analysed 524.9ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.32 Pr / Ph 1.6 C27/C29 Steranes 0.59 C27 / C28 / C29 Steranes % 31 : 18 : 52 C26/C25 Tricyclic Terpanes 0.67 Ts/Tm 0.46 C29 Hop / C30 Hop 0.90 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) Unclear C28,30 BNH* nd Other* C24 Tetracyclic Terpane (0.39) Extended tricyclics down to C20 MATURITY PARAMETERS MPI-1 nd Calculated Vr % - C29 20S/20S+20R 0.26 Equivalent Vr % 0.50 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Oil generated from a source rock deposited in an anoxic to suboxic depositional environment containing terrestrial and lesser marine organic matter. Some algal input based on Tricyclics. Early level of maturity indicates generation near source DATA SOURCE Geotech Report - 1996 * Ratioed to C30 Hopane nd = not determined

0.260610356 268 Name Kanau 1 - Extract - Magobu Saturate GCMS Depth 2525m Amount Analysed 1330ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.3 Pr / Ph 1.11 C27/C29 Steranes 0.13 C27 / C28 / C29 Steranes % 10 : 13 : 77 C26/C25 Tricyclic Terpanes nd Ts/Tm 0.86 C29 Hop / C30 Hop 0.78 C30 Hopane / C29 Sterane 3.75 Methyhopanes ( / ) nd C28,30 BNH* nd Other* Diahopane (0.09) ? Terrestrial Triterpanes MATURITY PARAMETERS MPI-1 nd Calculated Vr % nd C29 20S/20S+20R 0.43 Equivalent Vr % 0.61 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock deposited in an anoxic terrestrial environment. but with input of significant terrestrial organic matter. Low maturity indicates generation near source. DATA SOURCE Robertson Research Report (1990) * Ratioed to C30 Hopane nd = not determined

0.425953244 269 270

APPENDIX 9.2.4: Family O (Cretaceous Sourced) Origin Magobu Island 1 - 1609-1612m-Iagifu Extract Volume 9.4ng/g rock Saturate GC MS BIOMARKER PARAMETER CPI-1 (22-32) 1.28 Pr / Ph 1.5 C27/C29 Steranes 1.40 C27 / C28 / C29 Steranes % 42:28:30 C26/C25 Tricyclic Terpanes nd Ts/Tm 1.25 C29 Hop / C30 Hop 1.15 C30 Hopane / C29 Sterane nd Methyhopanes ( / ) nd C28,30 BNH* Present Other* Oleanane (0.09), C24 Tet. Terpanes (0.85), 1,2,5 TMN, 1,2,5,6 TeMN, 1,2,7 TMN MATURITY PARAMETERS Methyl Napthanlene Ratio (MNR) 2.2 Calculated Vr % 1.0 C29 20S/20S+20R 0.39 Equivalent Vr % 0.58 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Marine source rock with input of terrestrial organic matter. Source rock shows evidence of carbonate signature (C29/C30 hopane) but may be due to the advanced maturity. Biomarkers suggest Late Cret. to Tertiary source rock Light biodegradation OR loss of gasoline hc's during processing DATA SOURCE Magobu Island-1 MCI report -CSIRO - 1998 * Ratioed to C30 Hopane nd = Not determined

0.387212945 271 Origin Magobu Island 1 - 1646-1649m- Koi Iange Extract Volume 4.8ng/g rock BIOMARKER PARAMETER Saturate GC MS CPI-1 (22-32) nd Pr / Ph 1.8 C27/C29 Steranes nd C27 / C28 / C29 Steranes % nd C26/C25 Tricyclic Terpanes nd Ts/Tm nd C29 Hop / C30 Hop nd C30 Hopane / C29 Sterane nd Methyhopanes ( / ) nd C28,30 BNH* nd Other* nd MATURITY PARAMETERS Methyl Phenanthrene Ratio (MPR) 1.14 Calculated Vr % 0.9-1.0 C29 20S/20S+20R nd Equivalent Vr % nd ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Insufficient information. Given similarity of maturity calculation, likely similar to FI oil from Magobu Island 1 - Iagifu. Light biodegradation OR loss of gasoline hc's during processing DATA SOURCE Magobu Island-1 MCI report -CSIRO - 1998 * Ratioed to C30 Hopane nd = Not determined 272 Origin Kimu 1 - FI Oil - Hedinia Depth 1873 - 1879m Amount Analysed ND BIOMARKER PARAMETER CPI-1 (22-32) 1.05 Pr / Ph 1.7 C27/C29 Steranes nd C27 / C28 / C29 Steranes % nd C26/C25 Tricyclic Terpanes 0.56 Ts/Ts + Tm 1.02 C29 Hop / C30 Hop 0.71 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) nd C28,30 BNH* 0.71 Other* C24 Tetracyclic Terpane (0.24) presence of Tetramethylnapthalenes MATURITY PARAMETERS MPI-1 0.48 Calculated Vr % 0.69 C29 20S/20S+20R nd Equivalent Vr % - ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Insufficient information is available to give a proper interpretation Source is of terrestrial origin, but not a lacustrine source. Early mature? DATA SOURCE Kimu-1 1873-79m MCI-Status 12-NOV-02 & Volk etl al (2004) * Ratioed to C30 Hopane nd = not determined nd Not Detected 273 Origin Bujon 1 - FI Oil - Toro Saturate GCMS Depth 1474m Amount Analysed 148.7ng/gram qtz BIOMARKER PARAMETER CPI-1 (22-32) nd Pr / Ph 1.05 C27/C29 Steranes 0.77 C27 / C28 / C29 Steranes % 30 : 31 : 39 C26/C25 Tricyclic Terpanes 0.91 Ts/Tm 1.23 C29 Hop / C30 Hop 4.35 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) 2 Dominant C28,30 BNH* (0.11) Other* Oleanane (0.18), C25 Norhopanes, Gammacerane (0.07) C24 Tetracyclic Terpane (0.08) MATURITY PARAMETERS MPI-1 0.6 Calculated Vr % 0.76 C29 20S/20S+20R 0.46 Equivalent Vr % 0.65 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source Rock is a carbonate (based on C29/C30 hopane ratio) and contains both marine and terrestrial organic matter (C27 and C29 steranes) however the Pr/Ph indicates the source rock was deposited in an anoxic environment. Source is Late Cretaceous to Tertiary age (Oleanane) DATA SOURCE CSIRO - George et al Geochemistry_Fluid Inclusions_Bujon 1_1995 * Ratioed to C30 Hopane nd = not determined nd Not Detected 0.464359203 274 275

APPENDIX 9.2.5: Family C (Coal Sourced) Origin Magobu Island 1 - Magobu -2563 to 2582m Extract Volume 2125ppm BIOMARKER PARAMETER Saturate GC MS CPI-1 (22-32) 1.25 Pr / Ph 0.75 C27/C29 Steranes nd C27 / C28 / C29 Steranes % (not detected) : 18 : 82 C26/C25 Tricyclic Terpanes nd Ts/Tm 0.1 C29 Hop / C30 Hop 0.74 C30 Hopane / C29 Sterane 3.34 Methyhopanes ( / ) nd C28,30 BNH* nd Other* nd MATURITY PARAMETERS MPI-1 nd Calculated Vr % nd C29 20S/20S+20R 0.42 Equivalent Vr % 0.61 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Extract derived from a source rock containing primarily terrestrial organic matter. Low maturity suggests oil may have been generated insitu. Waxy oil (dominance of carbons >C22) DATA SOURCE Robertston Researh Report - 1990 * Ratioed to C30 Hopane nd = Not determined

0.420047266 276 Name Magobu Island 1 - Cuttings Extract - Magobu Depth 2548-2551m Amount Analysed 7525mg EOM/kg of rock BIOMARKER PARAMETER CPI-1 (22-32) 1.19 Pr / Ph 2.8 C27/C29 Steranes 0.07 C27 / C28 / C29 Steranes % 5 : 23 : 72 C26/C25 Tricyclic Terpanes 0.92 Ts/Tm 0.12 C29 Hop / C30 Hop 0.88 Hopane / Sterane nd Methyhopanes ( / ) nd C28,30 BNH* Minor Other*

MATURITY PARAMETERS MPI-1 0.56 Calculated Vr % 0.74 Vr C29 20S/20S+20R 0.47 Equivalent Vr % 0.66 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Oil has been derived from a source rock deposited in an oxic environment and which contains an abundant amount of terrestrial organic matter. Ts/Tm value suggests that the source is clay poor, probably a coal DATA SOURCE CSIRO Analysis - 2009 * Ratioed to C30 Hopane nd = Not determined

0.471403564 277 Name Iamara 1 - Core Extract - Magobu Depth 1742m Amount Analysed 3546mg EOM/kg of rock BIOMARKER PARAMETER CPI-1 (22-32) 1.8 Pr / Ph 6.5 C27/C29 Steranes 0.32 C27 / C28 / C29 Steranes % 18 : 25 : 57 C26/C25 Tricyclic Terpanes 4.70 Ts/Tm 0.03 C29 Hop / C30 Hop 0.68 Hopane / Sterane nd Methyhopanes ( / ) nd C28,30 BNH* Minor Other* elevated Tricyclic Terpanes (19-24) MATURITY PARAMETERS MPI-1 0.50 Calculated Vr % 0.70 C29 20S/20S+20R 0.22 Equivalent Vr % 0.48 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Oil has been derived from a source rock deposited in an oxic environment and which contains an abundant amount of terrestrial organic matter. Ts/Tm value suggests that the source is clay poor, probably a coal DATA SOURCE CSIRO Analysis - 2009 * Ratioed to C30 Hopane nd = Not determined

0.217177149 278 Name Iamara 1 - Core Extract - Magobu Depth 1745m Amount Analysed 1464mg EOM/kg of rock BIOMARKER PARAMETER CPI-1 (22-32) 1.2 Pr / Ph 3 C27/C29 Steranes 0.26 C27 / C28 / C29 Steranes % 16 : 24 : 61 C26/C25 Tricyclic Terpanes 1.17 Ts/Tm 0.10 C29 Hop / C30 Hop 0.83 Hopane / Sterane nd Methyhopanes ( / ) nd C28,30 BNH* 0.13 Other* Enhanced tricyclics C19-24

MATURITY PARAMETERS MPI-1 0.57 Calculated Vr % 0.74 C29 20S/20S+20R 0.25 Equivalent Vr % 0.50 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Oil has been derived from a source rock deposited in an oxic environment and which contains an abundant amount of terrestrial organic matter. Ts/Tm value suggests that the source is clay poor, probably a coal. Minor biodegradation. DATA SOURCE CSIRO Analysis - 2009 * Ratioed to C30 Hopane nd = Not determined

0.2545625 279 Origin Komewu 2 - Magobu - 2862m Volume 14260ppm BIOMARKER PARAMETER Komewu 2 - Coal Extract - Core 15 CPI-1 (22-32) nd Pr / Ph nd C27/C29 Steranes 0.20 C27 / C28 / C29 Steranes % 13 : 25 :62 C26/C25 Tricyclic Terpanes Absent Ts/Tm 0.05 C29 Hop / C30 Hop 0.71 Hopane / Sterane nd Methyhopanes ( / ) nd C28,30 BNH* Absent Other* - MATURITY PARAMETERS MPI-1 0.36 Calculated Vr % 0.62 Vr C29 20S/20S+20R 0.45 Equivalent Vr % 0.63 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Data is consistent with an extract from a coal, indicating that the source rock has a high proportion of terrestrial organic matter, deposited in oxic conditions DATA SOURCE GEOTECH - 06 Analysis * Ratioed to C30 Hopane nd = Not determined

0.44717348 280 Name Aramia 1 - Core - Extract - Magobu Depth 1937m Amount Analysed 35452ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.32 Pr / Ph 5.64 C27/C29 Steranes 0.21 C27 / C28 / C29 Steranes % 14 : 19 :67 C26/C25 Tricyclic Terpanes Absent Ts/Tm nd C29 Hop / C30 Hop 0.63 Hopane / Sterane nd Methyhopanes ( / ) nd C28,30 BNH* Absent Other* - MATURITY PARAMETERS MPI-1 0.19 Calculated Vr % 0.51 C29 20S/20S+20R 0.29 Equivalent Vr % 0.52 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Data is consistent with an extract from a coal, indicating that the source rock has a high proportion of terrestrial organic matter, deposited in oxic conditions DATA SOURCE GEOTECH - 06 Analysis * Ratioed to C30 Hopane nd = Not determined

0.290626255 281 282

APPENDIX 9.2.6: Family X (Mixed Source) Origin Kimu 1 - Alene SS - Extract Depth 1651.5m Amount Analysed 959.4ppm BIOMARKER PARAMETER CPI-1 (22-32) nd Pr / Ph 0.86 C27/C29 Steranes 0.9 C27 / C28 / C29 Steranes % 37 : 22 : 41 C26/C25 Tricyclic Terpanes 0.54 Ts/Tm 1.2 C29 Hop / C30 Hop 1.15 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) 2 Dominant C28,30 BNH* nd Other* C25 Norhopane (0.12) C24 Tetracyclic Terpane (0.33) MATURITY PARAMETERS MPI-1 1.48 Calculated Vr % 1.29 C29 20S/20S+20R 0.45 Equivalent Vr % 0.63 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in an environment with input from terrestrial and marine organic matter (C29 and C27 steranes) but Pr/Ph indicates anoxic conditions. The saturate GCMS shows a mixture of an original oil biodegraded with an overprint of a fresh waxy crude. DATA SOURCE RP7973 - Geotech HC Charac. Report - 1999 * Ratioed to C30 Hopane nd = not determined nd Not Detected 0.44717348 283 Origin Kimu 1 - SFT water extract - Hedinia SS Depth 1873.5m Amount Analysed 12ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.12 Pr / Ph 2.09 C27/C29 Steranes 1.36 C27 / C28 / C29 Steranes % 42 : 27 : 31 C26/C25 Tricyclic Terpanes 0.94 Ts/Tm 0.86 C29 Hop / C30 Hop 1.12 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) 2 Dominant C28,30 BNH* 0.08 Other* C25 Norhopane (0.09)

MATURITY PARAMETERS MPI-1 0.64 Calculated Vr % 0.79 C29 20S/20S+20R 0.54 Equivalent Vr % Outside Range ISOTOPIC PARAMETERS \ 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in an environment with input from terrestrial and marine organic matter (C29 and C27 steranes). but Pr/Ph indicates suboxic conditions. The saturate GCMS shows a mixture of relatively fresh oil, mixed with minor amount of biodegraded oil. DATA SOURCE RP7973 - Geotech HC Charac. Report - 1999 * Ratioed to C30 Hopane nd = not determined nd Not Detected 284 Origin Bujon 1 - SWC Extract - Toro Sandstone Saturate GCMS Depth 1498m Extracted Organic Matter (EOM) 0.04% BIOMARKER PARAMETER CPI-1 (22-32) nd Pr / Ph 1.5 C27/C29 Steranes 0.63 C27 / C28 / C29 Steranes % 27 : 30 : 43 C26/C25 Tricyclic Terpanes 1.25 Ts/Tm 1.29 C29 Hop / C30 Hop 0.79 Hopane to Sterane 2.13 Methylhopanes ( / ) nd C28,30 BNH* nd Other* and Carotane

MATURITY PARAMETERS MPI-1 nd Calculated Vr % nd C29 20S/20S+20R nd Equivalent Vr % nd ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a mixed terrestrial environment with input from algal organic matter (C29 and C28 steranes) but Pr/Ph indicates predominantly anoxic conditions. No maturity information available but Ts/Tm suggests thermally mature. Waxy oil mixed with biodegraded oil. Presence of carotanes , C26/C25 tricyclic ratio, elevated C28 steranes suggest a lake source rock DATA SOURCE Boatright (Philips Petroleum) 1994 * Ratioed to C30 Hopane nd = not determined nd Not Detected 285 Origin Bujon 1 - SWC Extract - Koi Iange Saturate GCMS Depth 1884m Extracted Organic Matter (EOM) 0.44% BIOMARKER PARAMETER CPI-1 (22-32) nd Pr / Ph 0.7 C27/C29 Steranes 0.44 C27 / C28 / C29 Steranes % 19 : 38 : 43 C26/C25 Tricyclic Terpanes 1.33 Ts/Tm 2.27 C29 Hop / C30 Hop 0.65 C30 Hopane / C29 Sterane 1.54 Methylhopanes ( / ) ? C28,30 BNH* 0.14 Other* and Carotane MATURITY PARAMETERS MPI-1 nd Calculated Vr % nd C29 20S/20S+20R nd Equivalent Vr % nd ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a mixed terrestrial environment with input from algal organic matter (C29 and C28 steranes) but Pr/Ph indicates predominantly anoxic conditions. No maturity information available but Ts/Tm suggests thermally mature. Waxy oil (with minor biodegradation) mixed with biodegraded oil. Presence of carotanes , C26/C25 tricyclic ratio, elevated C28 steranes suggest a lake source rock DATA SOURCE Boatright (Philips Petroleum) 1994 * Ratioed to C30 Hopane nd = not determined nd Not Detected 286 Name Iamara 1 - Core Extract - Magobu Depth 1656m Amount Analysed 303mg EOM/kg of rock BIOMARKER PARAMETER CPI-1 (22-32) 1.21 Pr / Ph 2.1 C27/C29 Steranes 0.51 C27 / C28 / C29 Steranes % 24 : 29 : 47 C26/C25 Tricyclic Terpanes 1.28 Ts/Tm 0.46 C29 Hop / C30 Hop 0.46 Hopane / Sterane nd Methyhopanes ( / ) 3 present C28,30 BNH* Minor Oleanane (0.91) 24-nor cholestane, Other* 1,2,5-trimethylnaphthalene. 1,2,7-trimethylnaphthalene, enhanced Tricyclics (19-26) MATURITY PARAMETERS MPI-1 0.63 Calculated Vr % 0.78 C29 20S/20S+20R 0.42 Equivalent Vr % 0.61 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Oil has been derived from a source rock deposited in an oxic environment with predominantly terrestrial organic matter (C29) however also evidence of algal organic matter input (C28). The later is supported by the C26/C25 tricyclic ratio and 3 Methylhops. which indicates a lacustrine source. Indications of biodegradation are dismissed by lack of 25 norhopanes. Biomarkers suggest Late Cret - Tertiary source DATA SOURCE CSIRO Analysis - 2009 * Ratioed to C30 Hopane nd = Not determined

0.420047266 287 288

APPENDIX 9.2.7: Miscellaneous (Kanau 1 and Kimu 1 extracts - No Family Allocated) Name Kanau 1-Extract-Triassic Depth 3478.5 Saturate GCMS Amount Analysed 250ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.09 Pr / Ph 0.5 C27/C29 Steranes 0.46 C27 / C28 / C29 Steranes % 25 : 21 : 54 C26/C25 Tricyclic Terpanes nd Ts/Tm 1.11 C29 Hop / C30 Hop 0.90 C30 Hopane / C29 Sterane 1.7 Methyhopanes ( / ) nd C28,30 BNH* nd Other* C24 Tetracyclic Terpane (0.12) MATURITY PARAMETERS MPI-1 nd Calculated Vr % nd C29 20S/20S+20R 0.41 Equivalent Vr % 0.60 ISOTOPIC PARAMETERS 13C (Saturates) per mil -31.5 13C (Aromatics) per mil -31.1 Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock environment experienced sigificnant terrestrial input (C29 steranes) but Pr/Ph indicates predominantly anoxic conditions. Early thermal maturity. Waxy oil mixed with minor biodegraded oil. DATA SOURCE Robertson Research Report (1990) * Ratioed to C30 Hopane nd = not determined

0.413912 289 Name Kanau 1 - Extract - Triassic Saturate GCMS Depth 3477.7m Amount Analysed 595ppm BIOMARKER PARAMETER CPI-1 (22-32) 1.35 Pr / Ph 0.66 C27/C29 Steranes 1.42 C27 / C28 / C29 Steranes % 34 : 24 : 42 C26/C25 Tricyclic Terpanes nd Ts/Tm 1.19 C29 Hop / C30 Hop 0.83 C30 Hopane / C29 Sterane 2.21 Methyhopanes ( / ) nd C28,30 BNH* nd Other* C24 Tetracyclic Terpane (0.15) MATURITY PARAMETERS MPI-1 nd Calculated Vr % - C29 20S/20S+20R 0.50 Equivalent Vr % 0.78 ISOTOPIC PARAMETERS 13C (Saturates) per mil -32.9 13C (Aromatics) per mil -31.7 Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source rock was deposited in a mixed marine terrestrial environment (C27 and C29 steranes) but Pr/Ph indicates predominantly anoxic conditions. Mid to late thermal maturity. Waxy oil mixed with minor biodegraded oil. DATA SOURCE Robertson Research Report (1990) * Ratioed to C30 Hopane nd = not determined

0.501343257 290 Origin Kimu 1 - Alene SS - Extract Depth 1617m Amount Analysed 641.2ppm BIOMARKER PARAMETER CPI-1 (22-32) nd Pr / Ph nd C27/C29 Steranes 0.73 C27 / C28 / C29 Steranes % 32 : 24 : 44 C26/C25 Tricyclic Terpanes nd Ts/Tm 1.49 C29 Hop / C30 Hop 0.88 C30 Hopane / C29 Sterane nd Methylhopanes ( / ) 2 Dominant C28,30 BNH* nd Other* C25 Norhopane (0.16)

MATURITY PARAMETERS MPI-1 1.36 Calculated Vr % 1.22 C29 20S/20S+20R 0.27 Equivalent Vr % 0.51 ISOTOPIC PARAMETERS 13C (Saturates) per mil nd 13C (Aromatics) per mil nd Sulphur (wt%) nd INTERPRETATION OF SOURCE ROCK DEPOSITIONAL ENVIRONMENT Source Rock contains both marine and terrestrial organic matter (C27 and C29 steranes). Oil is highly degraded suggested by the UCM 25 norhopane levels and the absence of alkanes and isoprenoids (level 7) DATA SOURCE RP7973 - Geotech HC Charac. Report - 1999 * Ratioed to C30 Hopane nd = not determined nd Not Detected 0.272775223 291 1 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Adiba 1 1725.0 432 0.14 0.87 0.73 1.01 1.19 0.14 0.92 95 79 performans-?pellucida (C=Contamination) Adiba 1 1943.0 438 0.16 1.26 0.13 1.42 9.69 0.11 0.76 166 17 digitata Adiba 1 2073.0 434 0.14 0.95 0.15 1.09 6.33 0.13 0.79 120 19 halosa Adiba 1 2291.0 nd nd nd nd nd nd nd 0.26 nd nd turbatus Aramia 1 1098.2 Core-20 432 0.03 0.24 0.24 0.27 1.00 0.11 0.66 36 36 multispinum Aramia 1 1098.8 Core-20 nd 0.03 0.17 0.34 0.20 0.50 0.15 0.67 25 51 multispinum Aramia 1 1146.5 Core-24 444 0.02 0.28 0.27 0.30 1.04 0.07 0.80 35 34 ludbrookiae Aramia 1 1148.9 Core-24 0.26 ludbrookiae Aramia 1 1210.4 Core-25 431 0.03 0.24 0.94 0.27 0.26 0.11 0.62 39 152 ludbrookiae Aramia 1 1253.6 Core-26 nd 0.01 0.18 0.52 0.19 0.35 0.05 0.65 28 80 ?tetracantha - denticulata Aramia 1 1378.9 Core-26 429 0.03 0.27 0.99 0.30 0.27 0.10 0.69 39 143 ?tetracantha - denticulata Aramia 1 1679.1 Core-33 432 0.02 0.63 0.34 0.65 1.85 0.03 1.39 45 24 similis Aramia 1 1680.8 Core-33 429 0.01 0.23 0.29 0.24 0.79 0.04 0.68 34 43 similis Aramia 1 1744.4 Core-34 435 0.11 0.69 0.30 0.80 2.30 0.14 1.24 56 24 montgomeryi Aramia 1 1747.1 Core-34 429 0.02 0.37 0.16 0.39 2.31 0.05 0.86 43 19 montgomeryi Aramia 1 1873.0 Core-36 424 0.01 0.40 0.29 0.41 1.38 0.02 0.87 46 33 digitata - ?aemula Aramia 1 1873.6 Core-36 429 0.04 0.32 0.06 0.36 5.33 0.11 0.71 45 8 digitata - ?aemula Aramia 1 1937.3 Core-37 427 10.60 212.40 4.90 223.00 43.35 0.05 55.18 385 9 indotata Aramia 1 1938.2 Core-37 424 0.08 1.11 0.33 1.19 3.36 0.07 1.51 74 22 indotata Barikewa 1 1035.5 430 0.1 0.3 0.8 0.4 0.1 1.7 20 50 ludbrookiae Barikewa 1 1047.0 0.1 0.2 0.3 0.3 0.9 21 ludbrookiae Barikewa 1 1089.6 442 0.0 0.2 0.7 0.3 0.2 0.9 26 84 ludbrookiae Barikewa 1 1144.5 432 0.1 0.5 0.6 0.6 0.2 0.9 53 74 denticulata Barikewa 1 1217.6 446 0.0 0.2 0.6 0.2 0.2 0.9 17 60 denticulata Barikewa 1 1431.0 0.4 davidii Barikewa 1 1446.5 0.0 0.1 0.1 0.0 0.2 45 operculata Barikewa 1 1574.0 0.1 0.9 1.0 0.9 101 burgeri Barikewa 1 1574.2 0.1 0.9 1.0 0.1 0.9 101 burgeri Barikewa 1 1617.5 0.1 1.0 1.1 0.1 1.1 95 torynum Barikewa 1 1617.9 0.1 1.0 1.1 1.1 90 torynum Barikewa 1 1735.8 0.1 0.8 0.9 1.1 72 iehiense Barikewa 1 1736.4 0.1 0.8 0.9 0.1 1.1 76 iehiense Barikewa 1 1837.0 0.1 1.3 1.4 1.2 108 similis Barikewa 1 1837.3 0.1 1.3 1.4 0.1 1.2 112 similis Barikewa 1 1888.8 0.1 1.2 1.3 0.1 1.1 109 similis Barikewa 1 2074.7 1.1 2.3 3.4 0.3 1.5 154 montgomeryi Barikewa 1 2075.1 1.1 2.3 3.4 1.5 153 montgomeryi Barikewa 1 2171.7 429 0.0 0.0 0.7 0.1 0.3 1.4 3 52 montgomeryi Barikewa 1 2192.4 0.3 6.6 6.9 0.0 2.2 306 montgomeryi Barikewa 1 2192.4 0.2 1.5 1.7 0.6 267 montgomeryi Barikewa 1 2193.3 0.3 5.4 5.7 0.1 1.6 338 montgomeryi Barikewa 1 2193.9 0.4 9.1 9.5 0.0 2.3 396 montgomeryi Barikewa 1 2194.2 0.7 11.3 12.0 0.1 2.4 471 montgomeryi Barikewa 1 2194.8 0.4 5.4 5.8 0.1 1.4 386 montgomeryi Barikewa 1 2195.1 0.3 13.6 13.9 0.0 2.7 504 montgomeryi Barikewa 1 2195.7 0.4 5.7 6.1 0.1 1.3 438 montgomeryi Barikewa 1 2272.3 438 1.8 swanense Barikewa 1 2272.5 438 0.2 1.3 0.5 1.5 0.1 1.1 111 42 swanense Barikewa 1 2360.6 436 0.2 0.5 1.1 0.7 0.3 2.5 21 43 clathrata 292

Barikewa 1 2411.5 0.1 1.0 1.1 0.1 1.0 98 clathrata 2 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Barikewa 1 2411.9 0.1 1.0 1.1 1.0 100 clathrata Barikewa 1 2454.8 0.2 1.9 2.1 0.1 1.5 131 clathrata Barikewa 1 2854.4 430 0.3 0.3 1.2 0.6 0.5 2.0 16 58 aemula Barikewa 1 2857.8 0.3 2.4 2.7 1.9 126 aemula Barikewa 1 2858.1 0.3 2.4 2.7 0.1 1.9 128 aemula Barikewa 1 2967.5 0.4 0.9 1.3 0.3 1.9 47 digitata Barikewa 1 2967.8 0.4 0.9 1.3 1.9 47 digitata Barikewa 1 2984.6 0.3 2.0 2.3 0.1 1.7 120 digitata Barikewa 1 2984.9 0.3 2.0 2.3 1.7 117 digitata Barikewa 1 3060.8 0.4 1.6 2.0 0.2 1.6 99 digitata Barikewa 1 3060.8 0.4 1.6 2.0 1.6 100 digitata Barikewa 1 3061.4 442 0.4 1.8 1.8 2.2 0.2 2.3 78 80 digitata Barikewa 1 3135.8 0.4 1.0 1.4 0.3 1.5 68 digitata Barikewa 1 3136.1 0.4 1.0 1.4 1.6 66 digitata Barikewa 1 3139.7 0.3 0.7 1.0 0.3 1.3 53 digitata Barikewa 1 3156.2 439 1.2 1.1 1.3 2.3 0.5 1.9 56 68 digitata Barikewa 1 3184.9 53 0.4 0.8 1.2 1.5 digitata Barikewa 1 3184.9 0.4 0.8 1.2 0.3 1.5 55 digitata Barikewa 1 3247.3 448 0.4 0.6 1.5 1.0 0.4 2.3 27 65 digitata Barikewa 1 3338.8 402 1.0 0.7 1.5 1.7 0.6 2.1 33 72 digitata Barikewa 1 3365.6 0.2 0.1 0.3 0.7 0.5 20 digitata Barikewa 1 3427.2 465 0.6 0.5 2.1 1.1 0.5 2.0 27 104 digitata Barikewa 1 3518.6 471 0.3 0.4 1.7 0.8 0.4 2.1 21 80 digitata Barikewa 1 3610.1 444 0.6 0.5 1.0 1.1 0.5 1.5 35 66 digitata Barikewa 1 3615.2 0.2 0.6 0.8 0.3 1.3 47 digitata Barikewa 1 3659.4 0.1 0.3 0.4 0.3 1.4 22 digitata Barikewa 1 3728.9 471 0.3 0.4 0.8 0.7 0.5 1.7 25 47 digitata Barikewa 1 3792.9 0.2 0.4 0.6 0.3 1.5 27 digitata Barikewa 1 3832.6 496 0.3 0.4 0.6 0.7 0.4 1.2 37 49 digitata Barikewa 1 3869.7 0.1 0.2 0.3 0.3 1.3 16 digitata Barikewa 1 3917.3 0.2 0.4 0.6 0.3 1.3 30 indotata Barikewa 1 3920.9 0.5 0.4 0.8 0.8 0.5 1.5 25 52 indotata Barikewa 1 4003.2 0.0 0.1 0.1 0.0 1.3 8 indotata Barikewa 1 4009.3 0.2 0.1 0.5 0.4 0.6 1.7 8 30 indotata Barikewa 1 4099.3 1.7 halosa-indotata Barikewa 1 4160.2 0.0 0.1 0.1 0.0 0.1 91 halosa-indotata Bujon 1 1137.5 Ctgs 425 0.11 0.53 0.68 0.64 0.78 0.17 0.76 70 89 multispinum Bujon 1 1147.5 Ctgs 424 0.03 0.24 0.36 0.27 0.67 0.11 0.67 36 54 multispinum Bujon 1 1157.5 Ctgs 424 0.02 0.22 0.37 0.24 0.59 0.08 0.66 33 56 multispinum Bujon 1 1177.5 Ctgs 424 0.06 0.23 0.61 0.29 0.38 0.21 0.58 40 105 multispinum Bujon 1 1187.5 Ctgs 425 0.07 0.26 0.73 0.33 0.36 0.21 0.61 43 120 multispinum Bujon 1 1210.0 0.47 multispinum Bujon 1 1215.0 0.58 multispinum Bujon 1 1220.0 0.56 multispinum Bujon 1 1225.0 0.53 ludbrookiae Bujon 1 1240.0 Ctgs 425 0.06 0.33 0.53 0.39 0.62 0.15 0.58 57 91 davidii Bujon 1 1270.0 Ctgs 426 0.06 0.65 0.52 0.71 1.25 0.08 0.70 93 74 davidii Bujon 1 1290.0 Ctgs 428 0.03 0.33 0.48 0.36 0.69 0.08 0.54 61 89 davidii Bujon 1 1320.0 Ctgs 426 0.06 0.44 0.73 0.50 0.60 0.12 0.54 81 135 operculata Bujon 1 1405.0 SWC 0.27 1.39 1.66 0.16 0.82 170 ?testudinaria 293

Bujon 1 1408.0 Ctgs 415 0.16 0.62 0.93 0.78 0.67 0.21 0.56 111 166 ?testudinaria 3 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Bujon 1 1432.0 Ctgs 424 0.14 0.95 0.94 1.09 1.01 0.13 0.73 130 129 tabulata - areolata? Bujon 1 1447.0 SWC 0.13 1.78 1.91 0.07 1.04 171 tabulata - areolata? Bujon 1 1460.0 SWC 0.21 1.66 1.87 0.11 1.17 142 tabulata - areolata? Bujon 1 1608.0 Ctgs 428 0.16 0.98 1.15 1.14 0.85 0.14 0.64 153 180 serrata Bujon 1 1612.0 SWC 0.21 1.52 1.73 0.12 0.90 169 serrata Bujon 1 1662.0 SWC 0.14 1.36 1.50 0.09 0.79 172 similis Bujon 1 1685.0 SWC 0.14 1.02 1.16 0.12 0.81 126 pellucida Bujon 1 1717.0 SWC 0.14 1.52 1.66 0.08 0.94 162 pellucida Bujon 1 1756.0 429 0.42 16.80 2.07 17.22 8.12 1.43 3.35 501 62 jurassica C Bujon 1 1760.0 SWC 0.20 2.50 2.70 0.07 1.33 188 jurassica Bujon 1 1760.5 1.64 jurassica C Bujon 1 1764.0 430 0.22 4.43 2.71 4.65 1.63 0.39 1.61 275 168 jurassica C Bujon 1 1782.0 428 1.38 49.75 2.09 51.13 23.80 0.03 9.49 524 22 montgomeryi C Bujon 1 1784.0 Ctgs 431 0.30 24.60 1.90 24.90 12.95 0.01 5.33 462 36 montgomeryi C Bujon 1 1786.0 428 2.14 80.65 3.36 82.79 24.00 0.03 17.12 471 20 montgomeryi C Bujon 1 1790.0 428 1.10 40.63 2.44 41.73 16.65 0.03 7.71 527 32 perforans C Bujon 1 1795.0 SWC 0.21 0.42 0.63 0.33 0.32 131 ?perforans Bujon 1 1800.0 426 0.31 5.25 2.53 5.56 2.08 0.46 1.42 370 178 perforans C Bujon 1 1806.0 0.87 swanense C Bujon 1 1810.0 0.77 swanense C Bujon 1 1816.0 Ctgs 427 0.51 8.22 1.54 8.73 5.34 0.06 1.76 467 88 swanense C Bujon 1 1821.0 SWC 0.31 3.64 3.95 1.53 238 swanense Bujon 1 1826.0 429 0.31 3.09 2.53 3.40 1.22 0.28 1.12 276 226 swanense C Bujon 1 1830.0 429 0.36 5.56 1.87 5.92 2.97 0.49 1.50 371 125 swanense C Bujon 1 1834.0 431 0.49 8.66 2.05 9.15 4.22 0.05 2.04 425 100 swanense C Bujon 1 1840.0 426 0.34 4.79 2.81 5.13 1.70 0.07 1.43 335 197 swanense C Bujon 1 1848.0 Ctgs 429 0.37 6.18 1.53 6.55 4.04 0.06 1.45 426 106 clathrata C Bujon 1 1866.0 Ctgs 428 0.27 3.34 1.05 3.61 3.18 0.07 0.96 348 109 spectabilis C Bujon 1 1866.0 0.92 spectabilis C Bujon 1 1870.0 428 0.31 3.86 1.67 4.17 2.31 0.35 1.30 297 128 spectabilis C Bujon 1 1876.0 429 0.28 3.31 2.34 3.59 1.41 0.30 1.08 306 217 spectabilis C Bujon 1 1880.0 427 0.24 2.77 1.93 3.01 1.44 0.25 1.10 252 175 spectabilis C Bujon 1 1884.0 426 0.82 0.85 1.67 0.49 0.36 236 spectabilis C Bujon 1 1905.0 0.24 2.10 2.34 0.10 1.20 175 spectabilis C Bujon 1 1905.0 SWC 0.24 2.10 2.34 1.20 175 spectabilis Bujon 1 1910.0 0.66 spectabilis C Bujon 1 1916.0 428 0.32 3.12 2.63 3.44 1.19 0.29 1.03 303 255 spectabilis C Bujon 1 1920.0 Ctgs 432 0.15 1.94 1.16 2.09 1.67 0.07 0.87 223 133 spectabilis C Bujon 1 1920.0 0.81 spectabilis C Bujon 1 1942.0 0.28 2.88 3.16 0.09 1.50 192 spectabilis C Bujon 1 1942.0 SWC 0.28 2.88 3.16 0.09 1.50 192 spectabilis Bujon 1 1944.0 0.25 3.98 4.23 0.06 1.80 221 spectabilis C Bujon 1 1944.0 SWC 0.25 3.98 4.23 0.06 1.80 221 spectabilis Bujon 1 1960.0 0.09 0.40 0.49 0.18 0.69 58 spectabilis C Bujon 1 1960.0 SWC 0.09 0.40 0.49 0.18 0.69 58 spectabilis Bujon 1 1964.0 0.73 spectabilis C Bujon 1 1970.0 0.95 spectabilis C Bujon 1 1976.0 Ctgs 430 0.23 1.65 1.14 1.88 1.45 0.12 0.84 196 136 spectabilis C Bujon 1 1986.0 430 0.24 2.74 1.56 2.98 1.76 0.25 1.14 240 137 spectabilis C 294

Bujon 1 1990.0 0.99 spectabilis C 4 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Bujon 1 1996.0 430 0.23 2.12 3.62 2.35 0.59 0.10 1.13 188 320 spectabilis C Bujon 1 2000.0 434 0.25 3.15 3.09 3.40 1.02 0.07 1.22 258 253 spectabilis C Bujon 1 2028.0 Ctgs 430 0.64 23.92 0.32 24.56 74.75 0.03 20.29 118 2 spectabilis C Bujon 1 2038.0 Ctgs 431 0.48 20.04 0.90 20.52 22.27 0.02 3.47 578 26 spectabilis C Bujon 1 2054.0 Ctgs 428 0.60 13.00 1.23 13.60 10.57 0.04 2.40 542 51 spectabilis C Bujon 1 2075.0 427 9.50 10.14 19.64 0.48 1.95 520 aemula - digitata C Bujon 1 2089.0 SWC 0.13 1.80 1.93 1.03 175 aemula - digitata Bujon 1 2114.0 Ctgs 430 0.34 3.89 1.12 4.23 3.47 0.08 1.23 316 91 aemula - digitata C Bujon 1 2126.0 SWC 0.17 1.42 1.59 0.88 161 aemula - digitata Bujon 1 2130.0 0.78 aemula - digitata C Bujon 1 2136.0 0.89 aemula - digitata C Bujon 1 2140.0 0.91 aemula - digitata C Bujon 1 2146.0 430 0.21 3.42 1.74 3.63 1.97 0.06 1.08 317 161 aemula - digitata C Bujon 1 2163.0 SWC 0.23 2.20 2.43 1.26 175 digitata Bujon 1 2170.0 Ctgs 431 0.32 2.79 0.91 3.11 3.07 0.10 1.06 263 86 digitata C Bujon 1 2181.0 SWC 0.29 2.22 2.51 1.84 121 digitata Bujon 1 2186.0 431 0.72 26.03 1.66 26.75 15.68 0.03 4.78 545 35 digitata C Bujon 1 2190.0 431 0.45 3.31 1.84 3.76 1.80 0.12 1.16 285 159 digitata C Bujon 1 2194.0 hp 428 1.19 34.02 1.81 35.21 18.80 0.03 4.51 754 40 digitata C Bujon 1 2196.0 426 0.90 22.49 1.56 23.39 14.42 0.04 4.62 487 34 digitata C Bujon 1 2202.0 0.14 indotata C Darai 1 915.0 hp 0.40 multispinum Darai 1 935.0 hp 0.92 multispinum Darai 1 937.5 332 0.23 1.36 318 392 multispinum Darai 1 987.5 417 0.21 1.18 32 73 multispinum Darai 1 1005.0 hp 0.53 multispinum Darai 1 1010.0 0.47 multispinum Darai 1 1015.0 0.47 multispinum Darai 1 1020.0 0.45 multispinum Darai 1 1035.0 0.61 multispinum Darai 1 1040.0 hp 0.68 multispinum Darai 1 1050.0 435 0.21 0.94 28 179 multispinum Darai 1 1087.5 0.75 multispinum Darai 1 1140.0 0.64 multispinum Darai 1 1187.5 0.66 multispinum Darai 1 1190.0 hp 0.49 multispinum Darai 1 1227.5 0.57 ludbrookiae Darai 1 1262.5 0.54 ludbrookiae Darai 1 1312.5 0.68 davidii Darai 1 1330.0 hp 0.51 davidii Darai 1 1335.0 hp 0.49 davidii Darai 1 1345.0 hp 0.43 davidii Darai 1 1362.5 0.48 davidii Darai 1 1417.5 0.86 australis Darai 1 1462.5 0.75 testudinaria Darai 1 1485.0 hp 0.73 tabulata Darai 1 1490.0 hp 0.83 tabulata Darai 1 1497.5 0.85 tabulata Darai 1 1505.0 hp 0.78 tabulata - aerolata? 295

Darai 1 1510.0 hp 0.83 tabulata - aerolata? 5 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Darai 1 1535.0 hp 0.87 torynum Darai 1 1547.5 427 0.14 0.92 88 177 torynum Darai 1 1575.0 0.74 wisemaniae Darai 1 1602.5 0.94 wisemaniae Darai 1 1637.5 0.76 wisemaniae Darai 1 1677.5 333 0.18 1.12 214 335 iehiense Darai 1 1678.5 picked 424 0.19 0.77 75 32 iehiense Darai 1 1702.5 0.86 iehiense Darai 1 1735.0 0.78 simplex Darai 1 1785.0 0.79 similis Darai 1 1812.5 0.61 similis Darai 1 1852.5 0.83 pellucida Darai 1 1853.5 picked 425 0.19 0.82 70.73 34.15 pellucida Darai 1 1853.5 picked 425 0.19 0.82 71 34 pellucida Darai 1 1952.5 422 0.18 0.95 53 86 montgomeryi Darai 1 2000.0 426 0.16 1.04 64 116 montgomeryi Darai 1 2020.0 hp 429 0.06 1.18 0.36 1.24 3.28 0.05 1.01 117 36 montgomeryi Darai 1 2025.0 431 0.03 1.99 303 18 montgomeryi Darai 1 2026.0 picked 430 0.16 0.99 107 26 montgomeryi Darai 1 2030.0 hp 427 0.05 1.81 0.56 1.86 3.23 0.03 1.17 155 48 montgomeryi Darai 1 2045.0 hp 428 0.04 1.37 0.54 1.41 2.54 0.03 0.98 140 55 perforans Dibiri 1 4861.56 2.11 complex Dibiri 1A 3704.84 hp 0.92 indotata Dibiri 1A 3713.99 466.00 0.19 0.45 0.89 0.64 0.51 0.30 0.65 69.00 137.00 indotata Dibiri 1A 3721.61 picked 452.00 0.88 0.89 0.21 1.37 64.00 44.00 indotata Dibiri 1A 3770.38 picked 1.04 indotata Dibiri 1A 3796.28 hp 0.90 indotata Dibiri 1A 3799.33 hp 454.00 0.15 0.49 0.79 0.64 0.62 0.23 1.02 48.00 77.00 indotata Dibiri 1A 3802.38 hp 434.00 0.24 0.63 0.95 0.87 0.66 0.28 1.07 -999.25 -999.25 indotata Dibiri 1A 3805.43 hp 0.79 indotata Dibiri 1A 3810.00 picked 1.27 indotata Dibiri 1A 3849.62 picked 1.19 indotata Dibiri 1A 3884.68 hp 0.80 indotata Dibiri 1A 3892.30 picked 458.00 0.64 0.64 0.24 1.30 49.00 61.00 indotata Dibiri 1A 3931.92 picked 1.19 indotata Dibiri 1A 3951.73 466.00 0.44 0.77 1.19 1.21 0.65 0.36 1.05 73.00 113.00 indotata Dibiri 1A 3954.78 458.00 0.42 0.72 0.97 1.14 0.74 0.37 1.04 69.00 93.00 indotata Dibiri 1A 3970.02 picked 1.19 indotata Dibiri 1A 4008.12 picked 1.27 indotata Dibiri 1A 4044.70 picked 454.00 0.45 0.46 0.30 1.32 34.00 70.00 indotata Dibiri 1A 4084.32 picked 1.25 indotata Dibiri 1A 4091.94 423.00 0.21 0.50 1.33 0.71 0.38 0.30 1.11 45.00 120.00 indotata Dibiri 1A 4094.99 471.00 0.17 0.39 1.02 0.56 0.38 0.30 1.16 34.00 88.00 indotata Dibiri 1A 4098.04 464.00 0.19 0.53 1.00 0.72 0.53 0.26 1.26 42.00 79.00 indotata Dibiri 1A 4113.28 picked 1.33 indotata Dibiri 1A 4146.80 picked 1.30 indotata Dibiri 1A 4200.14 picked 1.24 halosa - indotata Dibiri 1A 4238.24 picked 1.39 halosa - indotata Dibiri 1A 4241.29 0.88 halosa - indotata 296

Dibiri 1A 4244.34 420.00 1.20 9.92 1.31 11.12 7.57 0.11 3.41 291.00 38.00 halosa - indotata 6 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Dibiri 1A 4276.34 picked 410.00 0.27 1.50 60.00 68.00 halosa - indotata Dibiri 1A 4319.02 picked 2.18 halosa - indotata Dibiri 1A 4357.12 picked 1.54 halosa - cadoaense Dibiri 1A 4396.74 picked 1.47 halosa - cadoaense Dibiri 1A 4430.27 400.00 0.31 1.53 3.14 1.84 0.49 0.17 2.70 57.00 116.00 halosa - cadoaense Dibiri 1A 4436.36 389.00 0.33 1.17 2.58 1.50 0.45 0.22 2.10 56.00 123.00 halosa - cadoaense Dibiri 1A 4440.94 picked 1.46 halosa - cadoaense Dibiri 1A 4480.56 picked 1.54 halosa - cadoaense Dibiri 1A 4488.18 hp 418.00 0.56 3.86 1.32 4.42 2.92 0.13 1.90 203.00 69.00 halosa - cadoaense Dibiri 1A 4491.23 418.00 0.71 5.45 1.09 6.16 5.00 0.12 2.23 244.00 49.00 halosa - cadoaense Dibiri 1A 4494.28 hp 418.00 0.49 2.26 1.86 2.75 1.22 0.18 1.99 114.00 93.00 halosa - cadoaense Dibiri 1A 4497.32 423.00 0.57 4.43 1.64 5.00 2.70 0.11 2.25 197.00 73.00 halosa - cadoaense Dibiri 1A 4500.37 423.00 0.51 3.71 2.11 4.22 1.76 0.12 2.60 143.00 81.00 halosa - cadoaense Dibiri 1A 4520.18 picked 398.00 0.17 2.32 68.00 69.00 halosa - cadoaense Dibiri 1A 4593.34 picked 2.01 halosa - cadoaense Dibiri 1A 4631.44 picked 1.39 halosa - cadoaense Dibiri 1A 4669.54 picked 1.47 halosa - cadoaense Dibiri 1A 4696.97 picked 1.58 halosa - cadoaense Dibiri 1A 4748.78 picked 387.00 0.19 2.01 104.00 56.00 halosa - cadoaense Dibiri 1A 4791.46 picked 1.61 halosa - cadoaense Dibiri 1A 4799.08 425.00 1.52 27.68 1.17 29.19 23.65 0.05 5.29 523.00 22.00 halosa - cadoaense Dibiri 1A 4808.22 419.00 0.17 0.61 1.33 0.78 0.46 0.22 1.46 42.00 91.00 halosa - cadoaense Dibiri 1A 4820.41 393.00 0.17 0.48 1.05 0.65 0.46 0.26 1.16 41.00 91.00 halosa - cadoaense Dibiri 1A 4826.51 372.00 0.21 0.53 1.16 0.74 0.46 0.28 1.23 43.00 94.00 halosa - cadoaense Dibiri 1A 4829.56 picked 328.00 0.49 7.44 249.00 234.00 halosa - cadoaense Dibiri 1A 4847.84 hp 335.00 20.60 38.28 35.55 58.88 1.08 0.35 14.05 272.00 253.00 halosa - cadoaense Dibiri 1A 4861.56 picked 2.11 halosa - cadoaense Duadua 1ST1 2245.0 Ctgs 362 1.00 9.40 14.80 10.40 0.64 0.10 7.18 131 206 australis Duadua 1ST1 2255.0 Ctgs 0.61 nd nd australis Duadua 1ST1 2260.0 Ctgs 0.50 nd nd australis Duadua 1ST1 2270.0 Ctgs 0.45 nd nd australis Duadua 1ST1 2280.0 Ctgs 0.54 nd nd australis Duadua 1ST1 2290.0 Ctgs 0.58 nd nd australis Duadua 1ST1 2295.0 Ctgs 0.49 nd nd australis Duadua 1ST1 2310.0 Ctgs 0.62 nd nd australis Duadua 1ST1 2320.0 Ctgs 0.60 nd nd australis Duadua 1ST1 2330.0 Ctgs 0.58 nd nd australis Duadua 1ST1 2340.0 Ctgs 430 0.06 0.53 0.29 0.59 1.83 0.10 0.70 76 41 australis Duadua 1ST1 2347.5 Ctgs 0.66 nd nd australis Duadua 1ST1 2357.5 Ctgs 0.51 nd nd testudinaria-m.australis Duadua 1ST1 2367.5 Ctgs 0.58 nd nd testudinaria-m.australis Duadua 1ST1 2377.5 Ctgs 0.64 nd nd testudinaria-m.australis Duadua 1ST1 2387.5 Ctgs 432 0.06 0.77 0.23 0.83 3.35 0.07 0.76 101 30 testudinaria-m.australis Duadua 1ST1 2397.5 Ctgs 435 0.09 1.49 0.16 1.58 9.31 0.06 0.92 162 17 testudinaria-m.australis Duadua 1ST1 2407.5 Ctgs 0.67 nd nd testudinaria-m.australis Duadua 1ST1 2417.5 Ctgs 430 0.09 1.06 0.12 1.15 8.83 0.08 0.72 147 17 testudinaria-m.australis Duadua 1ST1 2427.5 Ctgs 430 0.11 0.92 0.22 1.03 4.18 0.11 0.77 119 29 testudinaria-m.australis Duadua 1ST1 2437.5 Ctgs 433 0.09 1.09 0.12 1.18 9.08 0.08 0.73 149 16 testudinaria-m.australis Duadua 1ST1 2447.5 Ctgs 0.40 nd nd testudinaria-m.australis 298

Duadua 1ST1 2462.5 Ctgs 0.54 nd nd testudinaria-m.australis 7 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Duadua 1ST1 2467.5 Ctgs 0.45 nd nd testudinaria-m.australis Duadua 1ST1 2497.5 Ctgs 0.21 nd nd testudinaria-m.australis Duadua 1ST1 2502.5 Ctgs 0.39 nd nd testudinaria-m.australis Duadua 1ST1 2517.5 Ctgs 0.55 nd nd mirabilils Duadua 1ST1 2522.5 Ctgs 0.48 nd nd mirabilils Duadua 1ST1 2532.5 Ctgs 0.69 nd nd mirabilils Duadua 1ST1 2537.5 Ctgs 431 0.08 0.81 0.16 0.89 5.06 0.09 0.71 114 23 mirabilils Duadua 1ST1 2557.5 Ctgs 0.61 nd nd mirabilils Duadua 1ST1 2562.5 Ctgs 0.61 nd nd mirabilils Duadua 1ST1 2567.5 Ctgs 0.63 nd nd mirabilils Duadua 1ST1 2577.5 Ctgs 0.63 nd nd iehiense Duadua 1ST1 2587.5 Ctgs 0.34 nd nd iehiense Duadua 1ST1 2592.5 Ctgs 0.43 nd nd iehiense Duadua 1ST1 2607.5 Ctgs 0.47 nd nd iehiense Duadua 1ST1 2617.5 Ctgs 0.41 nd nd serrata Duadua 1ST1 2628.5 Core 0.54 nd nd serrata Duadua 1ST1 2632.5 Ctgs 0.48 nd nd serrata Duadua 1ST1 2637.5 Ctgs 0.47 nd nd serrata Duadua 1ST1 2647.5 Ctgs 0.40 nd nd simplex Duadua 1ST1 2657.5 Ctgs 0.36 nd nd simplex Duadua 1ST1 2667.5 Ctgs 0.58 nd nd simplex Duadua 1ST1 2670.0 Swc-24 433 0.18 1.37 0.31 1.55 4.42 0.12 0.94 146 33 simplex Duadua 1ST1 2672.5 Ctgs 0.39 nd nd simplex Duadua 1ST1 2682.5 Ctgs 0.43 nd nd simplex Duadua 1ST1 2697.5 Ctgs 0.33 nd nd similis Duadua 1ST1 2707.5 Ctgs 0.24 nd nd similis Duadua 1ST1 2722.5 Ctgs 0.61 nd nd similis Duadua 1ST1 2727.5 Ctgs 435 0.11 1.63 0.22 1.74 7.41 0.06 0.85 192 26 similis Duadua 1ST1 2732.5 Ctgs 434 0.13 1.27 0.11 1.40 11.55 0.09 0.78 163 14 similis Duadua 1ST1 2739.2 Swc-5 nd 0.04 0.04 0.08 0.08 0.50 0.50 0.85 5 9 similis Duadua 1ST1 2745.5 Ctgs 435 0.09 1.06 0.20 1.15 5.30 0.08 0.75 141 27 similis Duadua 1ST1 2748.5 Ctgs 435 0.10 1.28 0.19 1.38 6.74 0.07 0.79 162 24 similis Duadua 1ST1 2751.5 Ctgs 0.69 similis Duadua 1ST1 2762.5 Ctgs 0.56 similis Duadua 1ST1 2767.5 Ctgs 0.58 similis Duadua 1ST1 2777.5 Ctgs 432 0.10 0.95 0.28 1.05 3.39 0.10 0.71 134 39 similis Duadua 1ST1 2782.5 Ctgs 432 0.07 0.87 0.46 0.94 1.89 0.07 0.72 121 64 similis Duadua 1ST1 2792.5 Ctgs 435 0.09 1.03 0.21 1.12 4.90 0.08 0.78 132 27 similis Duadua 1ST1 2802.5 Ctgs 434 0.10 1.03 0.30 1.13 3.43 0.09 0.84 123 36 similis Duadua 1ST1 2812.5 Ctgs 433 0.10 1.26 0.26 1.36 4.85 0.07 0.91 138 29 similis Duadua 1ST1 2817.5 Ctgs 433 0.09 1.36 0.28 1.45 4.86 0.06 0.93 146 30 similis Duadua 1ST1 2827.5 Ctgs 434 0.09 1.12 0.27 1.21 4.15 0.07 0.91 123 30 similis Duadua 1ST1 2837.5 Ctgs 435 0.09 1.11 0.44 1.20 2.52 0.08 0.95 117 46 similis Duadua 1ST1 2842.5 Ctgs 434 0.10 1.30 0.42 1.40 3.10 0.07 1.03 126 41 similis Goari 1 2015.0 picked 428 0.21 0.88 228 38 delicata Goari 1 2015.0 picked 424 0.19 0.72 127 61 delicata Goari 1 2015.0 PICKED 1.11 iehiense Goari 1 2015.0 15.79 lubrookiae - torynum Goari 1 2015.0 434 0.14 0.92 79 39 montgomeryi 299

Goari 1 2015.0 0.80 montgomeryi 8 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Goari 1 2015.0 0.68 pellucida - jurassica Goari 1 2015.0 437 0.07 1.02 148 50 perforans Goari 1 2015.0 0.83 serrata Goari 1 2015.0 picked 430 0.12 0.96 145 35 similis Goari 1 2015.0 0.69 similis Goari 1 2015.0 0.46 similis Goari 1 2015.0 0.77 similis Goari 1 2015.0 0.72 swanense Goari 1 2015.0 0.62 swanense Goari 1 2055.0 17.54 lubrookiae - torynum Goari 1 2095.0 picked 426 2.71 21.89 36.27 24.59 0.60 0.11 31.27 70 116 lubrookiae - torynum Goari 1 2135.0 18.56 lubrookiae - torynum Goari 1 2175.0 PICKED 4.86 lubrookiae - torynum Goari 1 2215.0 PICKED 0.91 reticulata Goari 1 2255.0 picked 428 0.49 1.27 0.38 1.76 3.31 0.28 0.91 139 42 lobispinosum Goari 1 2855.0 0.78 spectabilis Goari 1 2895.0 0.52 spectabilis Goari 1 2927.5 434 0.13 1.24 0.69 1.37 1.80 0.09 1.28 97 54 spectabilis Goari 1 2935.0 441 0.12 1.17 76 69 spectabilis Goari 1 2975.0 440 0.14 1.00 80 59 spectabilis Goari 1 3015.0 441 0.12 1.51 100 58 spectabilis Goari 1 3032.5 437 0.14 2.17 1.32 2.31 1.64 0.06 1.92 113 69 spectabilis Goari 1 3037.5 435 0.25 3.62 1.54 3.87 2.35 0.06 2.60 139 59 spectabilis Goari 1 3042.5 435 0.07 0.61 2.13 0.68 0.29 0.10 1.75 35 122 spectabilis Goari 1 3055.0 442 0.14 1.47 78 64 spectabilis Goari 1 3062.0 0.84 spectabilis Goari 1 3064.5 0.82 spectabilis Goari 1 3067.5 0.68 spectabilis Goari 1 3072.5 0.71 spectabilis Goari 1 3077.5 0.54 spectabilis Goari 1 3095.0 0.80 spectabilis Goari 1 3124.0 439 0.14 1.02 91 62 spectabilis Goaribari 1 3191.50 hp* 1.27 spectabilis - aemula Goaribari 1 3197.50 hp* 445.00 0.18 0.98 0.40 1.16 0.16 1.26 77.78 31.75 spectabilis - aemula Goaribari 1 3203.50 hp* 448.00 0.27 0.77 0.95 1.04 0.26 1.23 62.60 77.24 spectabilis - aemula Goaribari 1 3218.50 hp* 452.00 0.40 1.42 1.62 1.82 0.22 1.46 97.26 110.96 spectabilis - aemula Goaribari 1 3225.00 0.78 spectabilis - aemula Goaribari 1 3234.00 0.70 spectabilis - aemula Goaribari 1 3243.00 0.57 spectabilis - aemula Goaribari 1 3250.00 0.86 spectabilis - aemula Goaribari 1 3255.00 446.00 0.76 1.66 1.55 2.42 0.22 0.95 175.00 163.00 spectabilis - aemula Goaribari 1 3275.00 0.70 spectabilis - aemula Goaribari 1 3300.00 454.00 0.37 1.01 0.25 1.38 0.27 0.98 103.00 26.00 indotata - spectabilis Goaribari 1 3303.00 447.00 0.71 1.37 2.31 2.08 0.34 0.99 138.00 233.00 indotata - spectabilis Goaribari 1 3306.00 441.00 0.77 1.45 1.54 2.22 0.35 0.95 153.00 162.00 indotata - spectabilis Goaribari 1 3312.00 442.00 0.74 1.39 1.63 2.13 0.35 0.97 143.00 168.00 indotata - spectabilis Goaribari 1 3315.00 0.10 indotata - spectabilis Goaribari 1 3330.00 0.77 indotata - spectabilis Goaribari 1 3345.00 0.70 indotata - spectabilis 300

Goaribari 1 3360.00 0.20 indotata - spectabilis 9 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Goaribari 1 3375.00 0.72 indotata - spectabilis Goaribari 1 3390.00 0.24 indotata - spectabilis Goaribari 1 3392.00 0.73 indotata - spectabilis Goaribari 1 3405.00 0.78 indotata - spectabilis Goaribari 1 3413.00 456.00 0.48 1.60 0.61 2.08 0.23 1.20 133.00 51.00 indotata - spectabilis Goaribari 1 3419.00 454.00 0.55 1.65 0.98 2.20 0.25 1.29 128.00 76.00 indotata - spectabilis Goaribari 1 3435.00 0.12 indotata - spectabilis Goaribari 1 3450.00 0.24 indotata - spectabilis Goaribari 1 3465.00 0.26 indotata - spectabilis Goaribari 1 3480.00 0.37 indotata - spectabilis Goaribari 1 3495.00 0.14 indotata - spectabilis Goaribari 1 3586.00 0.53 indotata Goaribari 1 3612.00 0.42 indotata Goaribari 1 3620.00 453.00 0.57 0.65 1.27 1.22 0.86 76.00 148.00 indotata Goaribari 1 3643.00 0.65 indotata Goaribari 1 3657.00 0.44 indotata Goaribari 1 3680.50 hp* 456.00 0.48 1.22 1.40 1.70 0.28 1.50 81.33 93.33 halosa Goaribari 1 3704.50 hp* 460.00 0.22 0.49 0.35 0.71 0.31 1.15 42.61 30.43 halosa Goaribari 1 3728.50 hp* 459.00 0.33 0.88 1.08 1.21 0.27 1.19 73.95 90.76 halosa Goaribari 1 3786.00 457.00 0.49 0.79 1.83 1.28 0.38 0.79 100.00 232.00 halosa Goaribari 1 3815.50 hp* 460.00 0.31 0.94 1.54 1.25 0.25 1.65 56.97 93.33 halosa Goaribari 1 3835.00 hp* 475.00 0.23 0.59 1.01 0.82 0.28 0.76 78.00 133.00 halosa Iamara 1 938.0 Ctgs 429 0.17 0.92 41 25 operculata-cerviculum Iamara 1 991.4 Ctgs 423 0.17 0.73 52 27 operculata-cerviculum Iamara 1 1034.0 Ctgs 425 0.15 0.76 30 29 areolata Iamara 1 1076.7 Ctgs 426 0.22 0.99 43 29 mirabilis - dysculum Iamara 1 1130.0 Ctgs 417 0.29 3.29 7 16 pelliferum-jurassicum Iamara 1 1175.8 Ctgs 424 0.15 1.11 31 55 pelliferum-jurassicum Iamara 1 1223.0 Ctgs 426 0.16 0.99 46 53 pelliferum-jurassicum Iamara 1 1274.8 Ctgs 423 0.26 1.85 17 26 pelliferum-jurassicum Iamara 1 1308.4 Ctgs 419 0.13 9.21 5 5 pelliferum-jurassicum Iamara 1 1358.6 Ctgs 432 0.21 1.93 6 7 pelliferum-jurassicum Iamara 1 1403.6 Ctgs 433 0.25 0.96 9 16 pelliferum-jurassicum Iamara 1 1442.5 Ctgs 435 0.12 1.49 30 32 pelliferum-jurassicum Iamara 1 1506.5 Ctgs 430 0.1 3.22 19 10 omatia-digitata Iamara 1 1546.1 Ctgs 431 0.11 2.86 14 20 omatia-digitata Iamara 1 1600.2 Ctgs 433 0.12 1.25 18 115 omatia-digitata Iamara 1 1600.2 P 431 0.08 2.45 42 24 omatia-digitata Iamara 1 1664.2 Ctgs 437 0.1 1.10 16 31 omatia-digitata Iamara 1 1664.2 P 424 0.08 3.27 29 19 omatia-digitata Iamara 1 1713.0 Ctgs 0.47 indotata Iamara 1 1713.0 P 431 0.07 2.07 51 32 indotata Iamara 1 1752.6 Ctgs 428 0.04 4.20 77 13 halosa Iamara 1 1789.2 P 431 0.09 2.10 50 16 halosa Iamara 1 1798.3 Ctgs 0.23 halosa Kamusi 1 2337.8 430 1.04 0.68 davidii Kamusi 1 2590.8 436 1.58 0.93 tabulata Kamusi 1 2804.2 435 2.23 0.76 iehiense Kamusi 1 2904.7 434 0.31 0.21 similis 301

Kamusi 1 3020.6 436 0.89 0.59 montgomeryi 10 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Kamusi 1 3171.4 436 0.35 0.37 clathrata Kanau 1 637.5 0.65 multispinum Kanau 1 737.5 0.82 multispinum Kanau 1 787.5 0.73 multispinum Kanau 1 837.5 0.70 ludbrookiae Kanau 1 875.0 0.80 ludbrookiae Kanau 1 925.0 0.74 denticulata Kanau 1 926.0 picked 425 0.38 0.86 42 34 denticulata Kanau 1 975.0 0.51 denticulata Kanau 1 1000.0 0.62 denticulata Kanau 1 1037.5 0.81 davidii Kanau 1 1137.5 picked 0.69 davidii Kanau 1 1187.5 0.81 australis Kanau 1 1237.5 0.80 testudinaria - burgeri Kanau 1 1300.0 427 0.18 0.93 90 48 areolata Kanau 1 1337.5 0.78 torynum Kanau 1 1387.5 0.93 wisemaniae - delicata Kanau 1 1462.5 0.87 iehiense Kanau 1 1512.5 0.76 serrata Kanau 1 1547.5 0.90 simplex Kanau 1 1612.5 0.78 similis Kanau 1 1650.0 0.84 pellucida Kanau 1 1672.5 0.82 pellucida Kanau 1 1700.0 0.78 jurassica Kanau 1 1737.5 0.86 jurassica Kanau 1 1785.0 0.10 0.80 0.90 0.11 1.00 80 perforans Kanau 1 1787.5 picked 434 0.12 1.15 202 43 perforans Kanau 1 1815.0 3.80 1.10 345 perforans Kanau 1 1825.0 picked 433 0.09 1.66 265 23 swanense Kanau 1 1875.0 picked 433 0.11 1.80 262 20 swanense Kanau 1 1880.0 1.90 1.20 158 clathrata Kanau 1 1905.0 1.40 1.10 2.50 0.56 1.10 127 spectabilis ? Kanau 1 1912.5 picked 436 0.12 1.40 200 23 spectabilis ? Kanau 1 1962.5 picked 432 0.11 1.38 191 45 spectabilis ? Kanau 1 1995.0 0.40 1.45 28 spectabilis - aemula Kanau 1 2037.5 picked 435 0.10 1.53 167 50 digitata Kanau 1 2055.0 0.10 1.90 2.00 1.60 118 digitata Kanau 1 2085.0 0.10 3.10 3.20 1.30 238 digitata Kanau 1 2087.5 picked 434 0.15 1.38 107 30 digitata Kanau 1 2115.0 0.10 0.60 0.70 0.80 75 digitata Kanau 1 2137.5 picked 438 0.11 1.41 154 47 digitata Kanau 1 2176.0 3.39 1.30 261 digitata Kanau 1 2190.0 picked 441 0.10 3.40 3.50 0.09 1.36 125 55 digitata Kanau 1 2205.0 0.10 1.70 1.80 0.06 1.80 94 digitata Kanau 1 2225.0 0.87 indotata Kanau 1 2235.0 0.10 1.70 1.80 0.06 1.40 121 indotata Kanau 1 2250.0 picked 439 0.11 1.57 174 31 indotata Kanau 1 2265.0 1.00 40 indotata Kanau 1 2275.0 picked 435 0.13 1.45 153 121 indotata 302

Kanau 1 2295.0 1.80 1.80 0.80 225 indotata 11 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Kanau 1 2300.0 picked 438 0.13 1.42 167 39 indotata Kanau 1 2325.0 picked 0.10 2.50 2.60 0.04 0.54 indotata Kanau 1 2335.0 1.40 285 indotata Kanau 1 2350.0 0.49 indotata Kanau 1 2375.0 picked 439 0.11 1.80 175 37 indotata Kanau 1 2401.0 picked 439 0.00 0.10 1.67 153 24 indotata Kanau 1 2415.0 0.20 3.50 3.70 0.05 2.00 175 indotata Kanau 1 2425.0 picked 440 0.09 2.42 241 18 indotata Kanau 1 2445.0 0.20 2.50 2.70 0.07 1.40 178 indotata Kanau 1 2450.0 picked 440 0.09 1.88 184 60 indotata Kanau 1 2475.0 picked 441 0.20 1.70 1.90 0.11 1.79 133 18 indotata Kanau 1 2476.0 1.20 141 indotata Kanau 1 2500.0 picked 440 0.13 1.62 154 19 indotata Kanau 1 2505.0 0.30 3.40 3.70 0.08 1.80 188 indotata Kanau 1 2525.0 picked 442 0.08 2.15 208 22 halosa Kanau 1 2535.0 0.20 5.10 5.30 0.04 1.60 318 halosa Kanau 1 2550.0 picked 442 0.09 1.84 158 16 halosa Kanau 1 2565.0 0.10 2.10 2.20 0.05 1.30 161 halosa Kanau 1 2576.0 picked 444 0.12 1.67 149 14 halosa Kanau 1 2590.0 0.20 2.20 2.40 0.08 1.50 146 halosa Kanau 1 2600.0 picked 437 0.21 1.51 70 27 halosa Kanau 1 2624.0 1.10 100 halosa Kanau 1 2625.0 0.72 complex Kanau 1 2625.0 picked 442 0.10 1.10 1.20 0.09 1.56 158 40 complex Kanau 1 2650.0 picked 439 0.08 1.78 184 26 complex Kanau 1 2670.0 picked 442 0.10 1.39 127 138 complex Kanau 1 2700.0 0.99 complex Kanau 1 2700.0 picked 443 0.13 1.36 85 110 complex Kanau 1 2725.0 picked 437 0.14 1.63 114 74 complex Kanau 1 2750.0 picked 441 0.10 3.40 3.50 0.12 1.67 107 151 complex Kanau 1 2751.0 1.30 261 complex Kanau 1 2775.0 1.08 155 complex Kanau 1 2776.0 picked 439 0.20 2.00 2.20 0.11 1.91 133 21 complex Kanau 1 2800.0 1.10 turbatus Kanau 1 2801.0 picked 436 0.15 1.74 117 17 turbatus Kanau 1 2835.0 0.20 1.20 1.40 1.20 100 turbatus Kanau 1 2837.5 picked 434 0.13 1.58 121 16 turbatus Kanau 1 2875.0 0.76 turbatus Kanau 1 2875.0 picked 439 0.15 1.70 108 51 turbatus Kanau 1 2895.0 0.10 2.50 2.60 1.30 192 turbatus Kanau 1 2900.0 picked 437 0.16 1.58 111 13 torosa Kanau 1 2937.5 picked 439 0.12 1.32 86 48 torosa Kanau 1 2975.00 0.69 torosa Kanau 1 2975.00 picked 438 0.12 1.59 107 23 torosa Kanau 1 2985.0 0.10 1.40 1.50 0.07 1.30 107 torosa Kanau 1 3000.0 0.55 torosa Kanau 1 3000.0 picked 433 0.12 1.21 115 24 torosa Kanau 1 3037.5 0.89 torosa 303

Kanau 1 3075.0 picked 438 0.16 1.10 102 19 torosa Kanau 1 3100.0 picked 433 0.20 1.21 114 28 torosa 12 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Kanau 1 3137.5 picked 440 0.14 1.41 124 23 torosa Kanau 1 3187.5 picked 441 0.12 1.43 137 16 torosa Kanau 1 3225.0 picked 440 0.17 1.05 93 34 torosa Kanau 1 3250.0 picked 440 0.11 1.38 177 29 torosa Kanau 1 3287.5 0.85 torosa Kanau 1 3325.0 0.82 triassic Kanau 1 3362.5 picked 440 0.37 1.67 0.17 2.04 10.11 0.18 1.84 91 9 triassic Kanau 1 3412.5 picked 443 0.67 3.28 0.17 3.95 18.89 0.17 1.93 170 9 triassic Kanau 1 3460.0 picked 446 0.77 6.94 0.31 7.71 22.17 0.10 2.61 266 12 triassic Kanau 1 3475.8 ctgs 444 0.21 9.00 0.21 9.21 42.86 0.02 2.71 332 8 triassic Kanau 1 3477.7 446 0.72 5.27 0.17 5.99 30.50 0.12 2.16 244 8 triassic Kanau 1 3478.0 447 0.53 7.05 0.15 7.58 47.00 0.07 3.00 235 5 triassic Kanau 1 3478.1 449 0.53 7.00 0.17 7.53 40.50 0.07 2.88 243 6 triassic Kanau 1 3478.5 452 0.55 8.65 0.10 9.20 86.33 0.06 3.34 259 3 triassic Kanau 1 3487.5 444 0.39 2.40 0.18 2.79 13.08 0.14 1.53 157 12 triassic Kanau 1 3495.0 0.50 3.90 4.40 2.80 139 triassic Kanau 1 3512.0 picked 449 0.58 5.24 0.16 5.82 33.33 0.11 2.62 200 6 triassic Kanau 1 3519.0 0.40 3.80 4.20 2.00 190 triassic Kanau 1 3519.0 0.40 3.80 4.20 2.00 190 triassic Kimu 1 1420.0 Ctgs 420 0.10 0.48 1.86 0.58 0.26 0.17 0.64 75 291 l. multispinum Kimu 1 1441.0 Ctgs 426 0.06 0.29 1.91 0.35 0.15 0.17 0.56 52 341 ludbrookiae Kimu 1 1459.0 Ctgs 0.44 ludbrookiae Kimu 1 1480.0 Ctgs 410 0.06 0.39 0.89 0.45 0.44 0.13 0.54 72 165 davidii Kimu 1 1501.0 Ctgs 425 0.06 0.46 1.14 0.52 0.40 0.12 0.69 67 165 u. davidii Kimu 1 1522.0 Ctgs 0.42 davidii Kimu 1 1540.0 Ctgs 0.31 davidii Kimu 1 1558.0 Ctgs 0.48 davidii Kimu 1 1576.0 Ctgs 425 0.07 0.58 1.79 0.65 0.32 0.11 0.60 97 298 operculata Kimu 1 1594.0 Ctgs 0 0.99 3.02 5.00 4.01 0.60 0.25 1.48 204 338 australis Kimu 1 1603.0 Ctgs 431 0.13 1.10 1.56 1.23 0.71 0.11 0.73 151 214 australis Kimu 1 1614.0 Swc-48 423 0.46 0.91 0.40 1.37 2.28 0.34 0.79 115 51 australis Kimu 1 1669.0 Ctgs 0.19 burgeri Kimu 1 1678.0 427 0.08 1.45 0.26 1.53 5.58 0.05 0.68 213 38 burgeri Kimu 1 1696.0 Ctgs 431 0.18 2.42 1.12 2.60 2.16 0.07 1.07 226 105 burgeri Kimu 1 1708.0 Ctgs 421 0.16 0.92 0.90 1.08 1.02 0.15 0.97 95 93 tabulata - areolata Kimu 1 1713.0 Swc-66 418 1.09 1.11 0.41 2.20 2.71 0.50 0.90 123 46 areolata-tabulata Kimu 1 1782.0 0.21 mirabilis Kimu 1 1818.0 0.36 mirabilis Kimu 1 1858.0 441 2.55 5.89 5.1 8.44 1.15 0.30 1.94 304 263 iehinese Kimu 1 1880.0 Swc-24 0 2.20 1.35 1.41 3.55 0.96 0.62 0.61 221 231 simplex Kimu 1 1933.0 Ctgs 430 0.26 0.97 1.40 1.23 0.69 0.21 0.52 187 269 l. similis Kimu 1 1960.0 Ctgs 429 0.22 1.86 1.51 2.08 1.23 0.11 0.97 192 156 l. similis Kimu 1 1967.0 Swc-21 424 0.27 1.31 0.54 1.58 2.43 0.17 1.07 122 50 l. similis Kimu 1 1996.0 432 0.45 3.08 2.43 3.53 1.27 0.13 1.22 252 199 pellucida - jurassica Kimu 1 2017.0 429 0.3 1.64 2.27 1.94 0.72 0.15 0.95 173 239 u. montgomeryi Kimu 1 2022.0 Swc-18 428 1.39 2.35 1.31 3.74 1.79 0.37 0.89 264 147 u. montgomeryi Kimu 1 2026.0 431 0.14 0.88 0.97 1.02 0.91 0.14 0.59 149 164 u. montgomeryi Kimu 1 2029.0 0.39 u. montgomeryi Kimu 1 2040.5 431 0.09 1.38 0.41 1.47 3.37 0.06 0.84 164 49 perforans - swanense 304

Kimu 1 2044.0 430 0.65 5.13 2.48 5.78 2.07 0.11 1.38 372 180 perforans - swanense 13 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Kimu 1 2050.0 427 1.8 3.46 4.84 5.26 0.71 0.34 1.25 277 387 perforans - swanense Kimu 1 2071.0 429 0.21 1.1 1.46 1.31 0.75 0.16 0.63 175 232 perforans - swanense Kimu 1 2127.8 432 0.19 2.42 0.68 2.61 3.56 0.07 1.06 228 64 clathrata Kimu 1 2137.0 430 0.16 0.91 1.06 1.07 0.86 0.15 0.58 157 183 clathrata Kimu 1 2152.0 431 0.24 1.06 0.91 1.3 1.16 0.18 0.58 183 157 u. spectabilis Kimu 1 2157.0 Swc-52 431 0.22 1.09 0.33 1.31 3.30 0.17 0.81 135 41 u. spectabilis Kimu 1 2165.5 436 0.14 2.9 0.35 3.04 8.29 0.05 1.29 225 27 spectabilis Kimu 1 2182.0 432 0.19 1.42 0.78 1.61 1.82 0.12 0.85 167 92 l. spectabilis Kimu 1 2187.5 Swc-8 427 0.34 1.89 0.41 2.23 4.61 0.15 1.46 129 28 l. spectabilis Kimu 1 2203.9 433 0.2 2.05 0.45 2.25 4.56 0.09 1.16 177 39 l. spectabilis Kimu 1 2222.0 Swc-5 0.46 l. spectabilis Kimu 1 2227.0 434 0.16 1.35 1.48 1.51 0.91 0.11 0.61 221 243 l. spectabilis Kimu 1 2237.5 Ctgs 437 0.28 3.03 1.29 3.31 2.35 0.08 1.04 291 124 clathrata Kimu 1 2239.0 440 0.17 4.7 0.89 4.87 5.28 0.03 1.73 272 51 spectabilis Kimu 1 2244.0 Swc-2 432 0.45 3.98 2.98 4.43 1.34 0.10 1.40 284 213 spectabilis Kimu 1 2260.0 434 0.33 2.33 1.45 2.66 1.61 0.12 1.02 228 142 digitata Koko 1 917.5 Swc-60 0.33 areolata-tabulata Koko 1 922.0 Ctgs 0.31 areolata-tabulata Koko 1 925.0 Swc-58 417.00 0.07 0.49 0.34 0.56 1.44 0.13 0.91 54 37 torynum Koko 1 973.0 Ctgs 0.15 torynum Koko 1 979.3 0.35 torynum Koko 1 988.0 Ctgs 0.15 torynum Koko 1 1000.0 Ctgs 0.27 torynum Koko 1 1009.0 Ctgs 0.31 torynum Koko 1 1018.0 Ctgs 0.29 torynum Koko 1 1027.0 Ctgs 0.31 torynum Koko 1 1035.0 Swc-48 419.00 0.16 1.12 0.48 1.28 2.33 0.13 0.80 140 60 iehiense Koko 1 1039.0 Ctgs 0.39 torynum Koko 1 1040.0 432.00 0.28 1.72 0.15 2.00 11.47 0.14 0.62 277 24 iehinese Koko 1 1042.0 430.00 0.21 1.52 1.17 1.73 1.30 0.12 0.57 267 205 iehinese Koko 1 1053.0 432.00 0.32 1.89 0.25 2.21 7.56 0.14 0.71 266 35 simplex Koko 1 1063.0 Ctgs 0.13 torynum Koko 1 1078.0 0.28 torynum Koko 1 1087.0 Ctgs 0.42 torynum Koko 1 1114.0 Ctgs 0.15 torynum Koko 1 1116.5 434.00 0.19 1.85 0.09 2.04 20.56 0.09 0.91 203 10 pellucida - jurassica Koko 1 1117.0 Ctgs 0.38 torynum Koko 1 1126.0 Ctgs 0.25 torynum Koko 1 1135.0 Ctgs 431.00 0.15 1.00 1.84 1.15 0.54 0.13 0.62 161 297 pellucida - jurassica Koko 1 1144.0 Ctgs 430.00 0.20 1.80 2.04 2.00 0.88 0.10 0.99 182 206 pellucida - jurassica Koko 1 1155.0 433.00 0.24 2.28 0.15 2.52 15.20 0.10 1.07 213 14 pellucida - jurassica Koko 1 1157.5 Swc-35 430.00 0.13 1.30 0.26 1.43 5.00 0.09 0.98 133 27 pellucida - jurassica Koko 1 1176.5 435.00 0.22 2.33 0.26 2.55 8.96 0.09 1.09 214 24 perf-swanense Koko 1 1186.0 Ctgs 426.00 0.24 3.06 1.49 3.30 2.05 0.07 1.14 268 131 Tithonian C Koko 1 1198.0 430 0.29 1.36 1.11 1.65 1.23 0.18 0.53 257 209 perf-swanense Koko 1 1207.0 Ctgs 0.41 torynum Koko 1 1225.0 Ctgs 0.15 torynum Koko 1 1234.0 Ctgs 0.27 torynum Koko 1 1244.3 0.38 torynum 305

Koko 1 1255.0 Ctgs 0.15 torynum 14 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Koko 1 1265.0 Swc-21 432.00 0.19 2.10 0.33 2.29 6.36 0.08 1.21 174 27 spectabilis Koko 1 1273.0 Ctgs 0.21 torynum Koko 1 1282.5 436.00 0.18 1.51 0.13 1.69 11.62 0.11 0.79 191 16 l. spectabilis Koko 1 1291.0 432.00 0.18 0.77 0.68 0.95 1.13 0.19 0.58 133 117 l. spectabilis Koko 1 1303.5 0.37 torynum Koko 1 1315.0 Ctgs 429.00 0.15 0.73 1.34 0.88 0.54 0.17 0.51 143 263 u. digitata C Koko 1 1327.0 Ctgs 0.29 torynum Koko 1 1333.0 Ctgs 0.30 torynum Koko 1 1336.0 Swc-16 0.30 torynum Koko 1 1342.0 Ctgs 0.32 torynum Komewu 1 1556.6 Ctgs 0.32 indotata Komewu 1 1567.6 Ctgs 429 0.86 1.30 1.44 2.16 0.90 0.40 0.72 181 200 indotata Komewu 1 1579.5 Ctgs 431 1.83 2.13 1.77 3.96 1.20 0.46 0.83 257 213 indotata Komewu 1 1591.7 Ctgs 429 0.74 1.11 1.31 1.85 0.85 0.40 0.80 139 164 indotata Komewu 1 1600.2 Ctgs 0.37 indotata Komewu 1 1610.6 Ctgs 427 0.85 0.70 1.66 1.55 0.42 0.55 0.55 127 302 indotata Komewu 1 1620.2 Ctgs 424 0.98 0.73 1.35 1.71 0.54 0.57 0.50 146 270 indotata Komewu 1 1630.7 Ctgs 420 1.54 1.37 3.09 2.91 0.44 0.53 0.59 232 524 indotata Komewu 1 1640.6 Ctgs 429 1.97 2.11 2.41 4.08 0.88 0.48 0.96 220 251 indotata Komewu 1 1649.3 Ctgs 425 1.03 0.84 1.87 1.87 0.45 0.55 0.65 129 288 indotata Komewu 1 1663.6 Ctgs 0.38 indotata Komewu 1 1674.3 Ctgs 425 0.56 0.60 0.95 1.16 0.63 0.48 0.60 100 158 halosa Komewu 1 1683.3 Ctgs 424 1.28 1.61 1.25 2.89 1.29 0.44 0.94 171 133 halosa Komewu 1 1724.3 Ctgs 0.14 halosa Komewu 1 1750.6 Ctgs 405 0.80 0.34 2.74 1.14 0.12 0.70 0.64 53 428 halosa Komewu 1 1761.7 Ctgs 0.39 halosa Komewu 1 1763.0 Ctgs 442 3.00 12.30 4.00 15.30 3.08 0.20 6.11 201 65 halosa Komewu 1 1791.2 Ctgs 0.29 halosa Komewu 1 1811.0 Ctgs 437 1.16 3.68 1.12 4.84 3.29 0.24 2.25 164 50 halosa Komewu 1 1826.4 Ctgs 439 1.76 4.56 1.55 6.32 2.94 0.28 2.20 207 70 halosa Komewu 1 1841.3 Ctgs 439 1.39 4.94 1.40 6.33 3.53 0.22 2.44 202 57 halosa Komewu 1 1869.9 Ctgs 439 0.98 1.44 1.17 2.42 1.23 0.40 0.92 157 127 halosa Komewu 2 1632.2 438 0.18 0.71 20 69 denticulata - ludbrookiae? Komewu 2 1690.1 447 0.17 0.78 45 206 denticulata - ludbrookiae? Komewu 2 1763.9 Core-6 431 0.04 0.28 0.21 0.32 1.33 0.13 0.63 44 33 davidii Komewu 2 1775.5 434 0.20 0.78 26 45 davidii Komewu 2 1885.2 434 0.14 0.88 28 42 testudinaria Komewu 2 1916.3 Core-9 428 0.03 0.66 0.24 0.69 2.75 0.04 1.04 63 23 burgeri-areolata Komewu 2 2003.3 440 0.23 1.08 31 108 wisemaniae - delicata? Komewu 2 2084.8 Core-10 431 0.02 0.43 0.11 0.45 3.91 0.04 0.64 67 17 serrata - ?simplex Komewu 2 2181.6 picked 436 0.17 1.27 58 13 similis Komewu 2 2336.3 Core-12 438 0.04 0.50 0.14 0.54 3.57 0.07 0.69 72 20 l. spectabilis Komewu 2 2363.0 434 0.16 1.33 101 28 spectabilis Komewu 2 2455.2 437 0.13 1.09 90 34 digitata Komewu 2 2506.2 430 0.20 1.60 41 33 digitata Komewu 2 2531.4 435 0.17 1.14 51 40 digitata Komewu 2 2536.5 Core-13 437 0.08 1.31 0.29 1.39 4.52 0.06 0.93 141 31 digitata Komewu 2 2567.9 441 0.23 1.24 44 59 digitata Komewu 2 2604.5 438 0.14 1.03 57 51 digitata 306

Komewu 2 2622.8 441 0.27 1.09 48 61 indotata 15 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Komewu 2 2657.1 440 0.12 1.07 74 21 indotata Komewu 2 2683.0 438 0.11 1.29 84 19 indotata Komewu 2 2723.4 picked 437 0.07 1.67 111 20 indotata Komewu 2 2737.1 433 0.10 1.28 95 30 indotata Komewu 2 2748.5 440 0.09 1.55 44 28 indotata Komewu 2 2775.2 440 0.09 1.21 71 31 halosa? Komewu 2 2811.0 435 0.09 1.37 78 27 halosa? Komewu 2 2839.2 442 0.07 1.63 77 47 halosa? Komewu 2 2852.9 434 0.05 1.24 154 23 halosa? Komewu 2 2861.9 Core-15 443 5.50 111.20 1.90 116.70 58.53 0.05 26.70 416 7 halosa Komewu 2 2866.6 picked 440 0.06 1.59 119 23 halosa Komewu 2 2872.0 431 0.05 2.27 223 21 halosa Komewu 2 2894.1 picked 436 0.06 1.69 146 23 halosa Komewu 2 2912.4 picked 434 0.09 2.41 150 27 halosa Komewu 2 2930.7 439 0.13 1.98 118 38 halosa Komewu 2 2944.4 picked 431 0.21 0.98 188 64 halosa Kusa 1 2449.07 425.00 0.25 1.00 387.00 78.00 similis Kusa 1 2485.64 0.99 similis Kusa 1 2513.08 1.07 similis Kusa 1 2531.36 432.00 0.23 1.16 347.00 55.00 similis Kusa 1 2549.65 1.04 similis Kusa 1 2567.94 0.89 pellucida - jurassica Kusa 1 2586.23 1.03 pellucida - jurassica Kusa 1 2604.52 1.13 pellucida - jurassica Kusa 1 2622.80 430.00 0.23 1.29 79.00 41.00 pellucida - jurassica Kusa 1 2641.09 430.00 0.21 1.19 197.00 43.00 pellucida - jurassica Kusa 1 2659.38 428.00 0.33 1.23 230.00 65.00 montgomeryi Kusa 1 2665.48 hp* 0.96 montgomeryi Kusa 1 2686.81 0.88 montgomeryi Kusa 1 2723.39 0.87 perforans Kusa 1 2729.48 hp* 0.90 perforans Kusa 1 2732.53 hp* 1.24 perforans Kusa 1 2735.58 hp* 0.60 perforans Kusa 1 2738.63 hp* 0.98 perforans Kusa 1 2741.68 hp* 0.91 perforans Kusa 1 2744.72 hp* 0.78 perforans Kusa 1 2747.77 hp* 0.84 swanense Kusa 1 2750.82 hp* 0.81 swanense Kusa 1 2759.96 0.93 swanense Kusa 1 2787.40 0.82 swanense Kusa 1 2787.40 hp* 1.08 swanense Kusa 1 2790.44 hp* 431.00 0.22 1.36 0.53 1.58 0.14 1.19 114.29 44.54 swanense Kusa 1 2793.49 hp* 0.95 swanense Kusa 1 2796.54 hp* 0.08 swanense Kusa 1 2799.59 hp* 434.00 0.09 1.40 0.51 1.49 0.06 1.32 106.06 38.64 swanense Kusa 1 2802.64 hp* 0.74 swanense Kusa 1 2808.73 hp* 1.05 swanense Kusa 1 2814.83 1.10 swanense Kusa 1 2851.40 1.11 spectabilis 307

Kusa 1 2887.98 433.00 0.24 1.03 127.00 47.00 spectabilis 16 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Kusa 1 2897.12 hp* 437.00 0.21 1.19 1.01 1.40 0.15 1.42 83.80 71.13 spectabilis Kusa 1 2900.17 hp* 434.00 0.24 2.28 0.70 2.52 0.10 1.68 135.71 41.67 spectabilis Kusa 1 2903.22 hp* 0.98 spectabilis Kusa 1 2906.27 hp* 1.96 spectabilis Kusa 1 2915.41 435.00 0.27 1.26 165.00 57.00 spectabilis Kusa 1 2942.84 436.00 0.15 1.43 145.00 32.00 spectabilis Kusa 1 2973.32 hp* 436.00 0.29 3.93 0.57 4.22 0.07 2.30 170.87 24.78 spectabilis Kusa 1 2979.42 433.00 0.17 1.52 130.00 40.00 spectabilis Kusa 1 2979.42 hp* 2.37 spectabilis Kusa 1 2982.47 hp* 435.00 0.39 4.98 0.69 5.37 0.07 2.73 182.42 25.27 spectabilis Kusa 1 3006.85 434.00 0.19 2.01 80.00 42.00 spectabilis Kusa 1 3009.90 hp* 435.00 0.33 5.39 0.71 5.72 0.06 2.81 191.81 25.27 spectabilis Kusa 1 3012.95 hp* 440.00 0.12 0.94 1.60 1.06 0.11 1.81 51.93 88.40 spectabilis Kusa 1 3016.00 hp* 436.00 0.18 3.30 1.08 3.48 0.05 2.48 133.06 43.55 spectabilis Kusa 1 3019.04 hp* 439.00 0.18 1.13 1.96 1.31 0.14 1.86 60.75 105.38 spectabilis Kusa 1 3022.09 hp* 438.00 0.19 2.37 1.20 2.56 0.07 2.11 112.32 56.87 spectabilis Kusa 1 3025.14 436.00 0.23 1.79 105.00 42.00 spectabilis Kusa 1 3025.14 hp* 434.00 0.38 4.09 1.02 4.47 0.09 2.55 160.39 40.00 spectabilis Kusa 1 3028.19 hp* 439.00 0.16 3.10 1.45 3.26 0.05 2.57 120.62 56.42 spectabilis Kusa 1 3031.24 hp* 438.00 0.27 4.12 1.37 4.39 0.06 2.81 146.62 48.75 spectabilis Kusa 1 3037.33 hp* 437.00 0.24 3.09 1.54 3.33 0.07 2.69 114.87 57.25 spectabilis Kusa 1 3043.43 436.00 0.19 1.92 71.00 57.00 spectabilis Kusa 1 3061.72 436.00 0.26 1.94 125.00 35.00 spectabilis Kusa 1 3067.81 hp* 438.00 0.38 3.97 1.10 4.35 0.09 2.65 149.81 41.51 spectabilis Kusa 1 3070.86 hp* 438.00 0.26 2.65 1.86 2.91 0.09 2.62 101.15 70.99 spectabilis Kusa 1 3080.00 440.00 0.17 2.54 173.00 28.00 spectabilis Kusa 1 3098.29 439.00 0.19 1.83 168.00 29.00 spectabilis Kusa 1 3116.58 1.75 spectabilis Kusa 1 3134.87 437.00 0.15 1.81 143.00 30.00 spectabilis Kusa 1 3153.16 1.19 spectabilis Kusa 1 3159.25 hp* 438.00 0.19 2.65 0.85 2.84 0.07 2.17 122.12 39.17 spectabilis Kusa 1 3162.30 hp* 435.00 0.28 3.00 1.00 3.28 0.09 2.24 133.93 44.64 spectabilis Kusa 1 3165.35 hp* 444.00 0.09 0.33 1.12 0.42 0.21 1.41 23.40 79.43 spectabilis Kusa 1 3168.40 hp* 442.00 0.27 0.87 1.84 1.14 0.24 1.67 52.10 110.18 spectabilis Kusa 1 3172.97 1.06 spectabilis Kusa 1 3174.49 hp* 443.00 0.04 0.49 1.50 0.53 0.08 1.52 32.24 98.68 spectabilis Kusa 1 3192.78 1.08 spectabilis Kusa 1 3201.92 hp* 442.00 0.10 0.71 1.37 0.81 0.12 1.50 47.33 91.33 spectabilis Kusa 1 3204.97 hp* 443.00 0.19 1.59 1.60 1.78 0.11 1.64 96.95 97.56 spectabilis Kusa 1 3211.07 441.00 0.12 1.52 96.00 55.00 spectabilis Kusa 1 3229.36 1.26 spectabilis Kusa 1 3247.64 1.03 aemula Kusa 1 3265.93 1.48 aemula Kusa 1 3275.08 hp* 443.00 0.15 1.12 1.37 1.27 0.12 1.61 69.57 85.09 aemula Kusa 1 3284.22 438.00 0.26 1.50 131.00 37.00 aemula Kusa 1 3302.51 1.20 aemula Kusa 1 3320.80 1.11 aemula Kusa 1 3348.23 439.00 0.24 1.39 84.00 52.00 aemula Kusa 1 3384.80 436.00 0.25 1.46 169.00 86.00 digitata 308

Kusa 1 3412.24 1.00 digitata 17 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Magobu Island 1 946.40 0.01 0.01 0.13 0.02 0.08 0.50 0.50 2.00 26.00 ludbrookiae Magobu Island 1 976.88 0.02 0.03 0.22 0.04 0.12 0.40 0.67 4.00 33.00 ludbrookiae Magobu Island 1 1007.36 0.02 0.06 0.12 0.08 0.53 0.25 0.69 9.00 17.00 denticulata Magobu Island 1 1037.84 0.29 0.38 0.81 0.67 0.47 0.43 0.85 45.00 95.00 tetracantha Magobu Island 1 1068.32 430.00 0.26 1.58 1.07 1.84 1.48 0.14 1.78 89.00 60.00 davidii Magobu Island 1 1098.80 424.00 0.03 0.14 0.48 0.17 0.29 0.18 0.73 19.00 66.00 operculata Magobu Island 1 1129.28 424.00 0.05 0.16 0.30 0.21 0.54 0.24 1.08 15.00 28.00 operculata Magobu Island 1 1159.76 431.00 0.02 0.21 0.26 0.23 0.82 0.09 0.79 27.00 33.00 operculata Magobu Island 1 1190.24 431.00 0.07 0.41 0.51 0.48 0.81 0.15 0.71 58.00 72.00 operculata Magobu Island 1 1220.72 433.00 0.02 0.20 0.23 0.22 0.89 0.09 0.85 24.00 27.00 cinctum ? Magobu Island 1 1251.20 433.00 0.05 0.28 0.19 0.33 1.50 0.15 0.93 30.00 20.00 cinctum Magobu Island 1 1281.68 438.00 0.10 0.64 0.93 0.75 0.69 0.14 0.99 65.00 94.00 testudinaria Magobu Island 1 1453.90 433.00 0.55 1.28 0.35 1.82 3.68 0.30 1.12 114.00 31.00 iehiense Magobu Island 1 1464.56 437.00 0.08 0.52 0.45 0.60 1.15 0.13 0.85 61.00 53.00 serrata ? Magobu Island 1 1472.18 0.78 serrata ? Magobu Island 1 1490.47 1.05 serrata ? Magobu Island 1 1514.86 0.90 similis Magobu Island 1 1539.24 0.88 similis Magobu Island 1 1552.96 433.00 0.03 0.11 0.25 0.14 0.45 0.21 0.75 15.00 33.00 similis Magobu Island 1 1557.53 0.73 similis Magobu Island 1 1583.44 431.00 0.02 0.05 0.29 0.06 0.16 0.29 0.91 5.00 32.00 similis Magobu Island 1 1589.53 0.62 pellucida - jurassica Magobu Island 1 1592.58 hp* 0.54 pellucida - jurassica Magobu Island 1 1594.10 0.85 pellucida - jurassica Magobu Island 1 1595.63 0.60 pellucida - jurassica? Magobu Island 1 1598.68 hp* 0.64 pellucida - jurassica? Magobu Island 1 1612.39 hp* 0.90 pellucida - jurassica? Magobu Island 1 1620.01 hp* 0.81 pellucida - jurassica? Magobu Island 1 1630.68 0.92 aemula - spectabilis Magobu Island 1 1648.97 1.03 aemula - spectabilis Magobu Island 1 1659.64 0.85 aemula - spectabilis Magobu Island 1 1667.26 1.09 aemula - spectabilis Magobu Island 1 1671.83 hp* 428.00 0.14 0.63 1.00 0.77 0.63 0.18 1.13 55.75 88.50 aemula - spectabilis Magobu Island 1 1677.92 hp* 430.00 0.26 0.64 0.98 0.90 0.65 0.29 1.05 61.00 93.00 aemula - spectabilis Magobu Island 1 1685.54 1.03 aemula - spectabilis Magobu Island 1 1687.07 hp* 0.85 aemula - spectabilis Magobu Island 1 1690.12 hp* 0.78 aemula - spectabilis Magobu Island 1 1703.83 1.01 aemula - spectabilis Magobu Island 1 1708.40 432.00 0.02 0.09 0.27 0.11 0.33 0.17 1.82 5.00 15.00 aemula - spectabilis Magobu Island 1 1722.12 0.92 aemula - spectabilis Magobu Island 1 1738.88 431.00 0.01 0.09 0.26 0.10 0.36 0.10 1.02 9.00 25.00 aemula - spectabilis Magobu Island 1 1740.41 0.95 aemula - spectabilis Magobu Island 1 1761.74 0.95 aemula - spectabilis Magobu Island 1 1767.8 Core 427 0.04 0.70 0.24 0.74 2.92 0.05 1.44 49 17 aemula - spectabilis Magobu Island 1 1792.22 1.20 aemula - spectabilis Magobu Island 1 1810.51 1.02 aemula - spectabilis Magobu Island 1 1828.80 430.00 0.38 1.35 0.32 -999.25 4.22 0.22 1.39 97.00 23.00 digitata ? Magobu Island 1 1847.09 1.01 digitata ? Magobu Island 1 1860.80 437.00 0.03 0.22 0.83 0.25 0.26 0.12 1.46 15.00 57.00 digitata 309

Magobu Island 1 1865.38 1.15 digitata 18 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Magobu Island 1 1866.90 0.63 digitata Magobu Island 1 1873.00 0.70 digitata Magobu Island 1 1876.04 0.90 digitata Magobu Island 1 1879.09 0.91 digitata Magobu Island 1 1883.66 436.00 0.27 1.21 0.63 1.47 1.93 0.18 1.39 87.00 45.00 digitata Magobu Island 1 1891.28 441.00 0.03 0.51 0.37 0.54 1.36 0.06 1.70 30.00 22.00 digitata Magobu Island 1 1901.95 1.02 digitata Magobu Island 1 1920.24 1.19 digitata Magobu Island 1 1921.76 442.00 0.03 0.24 0.52 0.27 0.47 0.11 1.52 16.00 34.00 digitata Magobu Island 1 1938.53 1.33 digitata Magobu Island 1 1952.24 439.00 0.05 0.41 0.57 0.46 0.72 0.11 1.59 26.00 36.00 digitata Magobu Island 1 1956.82 1.29 digitata Magobu Island 1 1975.10 1.37 indotata Magobu Island 1 1982.72 431.00 0.04 0.20 0.43 0.24 0.46 0.17 1.22 16.00 35.00 indotata Magobu Island 1 1993.39 1.25 indotata Magobu Island 1 2011.68 1.26 indotata Magobu Island 1 2013.20 433.00 0.08 0.72 0.45 0.80 1.61 0.10 1.94 37.00 23.00 indotata Magobu Island 1 2029.97 1.32 indotata Magobu Island 1 2043.68 438.00 0.02 0.18 0.34 0.20 0.53 0.10 0.94 19.00 36.00 indotata Magobu Island 1 2048.26 1.27 indotata Magobu Island 1 2066.54 1.31 indotata Magobu Island 1 2068.8 Core 440 0.28 8.61 0.21 8.89 41.00 0.03 3.06 281 7 indotata Magobu Island 1 2074.16 441.00 0.03 0.49 0.48 0.52 1.03 0.06 1.49 33.00 32.00 indotata Magobu Island 1 2084.83 435.00 0.50 2.01 0.52 2.51 3.88 0.20 1.52 132.00 34.00 indotata Magobu Island 1 2101.60 hp* 434.00 0.20 0.93 2.26 1.13 0.41 0.18 1.19 78.00 190.00 indotata Magobu Island 1 2103.12 1.36 indotata Magobu Island 1 2104.64 439.00 0.11 1.65 0.32 -999.25 5.17 0.06 1.77 93.00 18.00 indotata Magobu Island 1 2105.64 0.67 indotata Magobu Island 1 2107.69 0.74 indotata Magobu Island 1 2113.79 1.04 indotata Magobu Island 1 2129.03 hp* 433.00 0.15 0.42 2.73 0.57 0.15 0.26 1.14 37.00 239.00 indotata Magobu Island 1 2130.55 1.35 indotata Magobu Island 1 2135.12 440.00 0.05 0.68 0.29 -999.25 -999.25 0.07 1.36 50.00 21.00 indotata Magobu Island 1 2148.84 1.12 indotata Magobu Island 1 2165.60 436.00 0.10 0.81 0.31 0.91 2.63 0.11 1.92 42.00 16.00 indotata Magobu Island 1 2167.13 1.30 indotata Magobu Island 1 2183.89 1.26 indotata Magobu Island 1 2200.66 436.00 0.65 1.84 0.52 2.49 3.52 0.26 1.69 109.00 31.00 indotata Magobu Island 1 2218.94 1.31 indotata Magobu Island 1 2237.23 1.23 indotata Magobu Island 1 2255.52 1.26 halosa Magobu Island 1 2257.04 438.00 0.14 1.10 0.36 1.24 3.05 0.11 1.90 58.00 19.00 halosa Magobu Island 1 2273.81 1.23 halosa Magobu Island 1 2284.48 1.35 halosa Magobu Island 1 2287.52 443.00 0.03 0.33 0.25 0.36 1.33 0.08 1.38 24.00 18.00 halosa Magobu Island 1 2310.38 437.00 0.36 1.36 0.41 1.72 3.32 0.21 1.46 93.00 28.00 halosa Magobu Island 1 2318.00 435.00 0.08 0.78 0.36 0.86 2.14 0.09 1.73 45.00 21.00 halosa Magobu Island 1 2328.67 1.27 complex Magobu Island 1 2336.29 0.94 complex 310

Magobu Island 1 2339.34 0.85 complex 19 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Magobu Island 1 2345.44 443.00 0.03 0.40 0.49 0.43 0.82 0.07 1.28 31.00 38.00 complex Magobu Island 1 2350.01 1.09 complex Magobu Island 1 2355.34 0.56 complex Magobu Island 1 2357.63 0.57 complex Magobu Island 1 2360.68 0.68 complex Magobu Island 1 2363.72 0.79 complex Magobu Island 1 2371.34 1.15 complex Magobu Island 1 2378.96 446.00 0.02 0.13 0.62 0.15 0.21 0.13 0.82 16.00 76.00 complex Magobu Island 1 2389.63 431.00 1.35 17.95 0.68 19.30 26.44 0.07 7.54 238.00 9.00 complex Magobu Island 1 2391.16 hp* 430.00 11.68 152.26 6.55 163.94 23.25 0.07 53.82 283.00 12.00 complex Magobu Island 1 2394.20 hp* 429.00 1.08 14.24 1.75 15.32 8.14 0.07 5.53 258.00 32.00 complex Magobu Island 1 2407.92 436.00 0.51 2.69 0.49 3.21 5.46 0.16 1.76 153.00 28.00 complex Magobu Island 1 2409.44 448.00 0.04 0.45 1.00 0.48 0.45 0.08 1.35 33.00 74.00 complex Magobu Island 1 2426.21 437.00 0.40 2.09 0.58 2.49 3.61 0.16 1.87 112.00 31.00 turbatus Magobu Island 1 2439.92 445.00 0.01 0.10 0.16 0.11 0.63 0.09 0.98 10.00 16.00 turbatus Magobu Island 1 2444.50 435.00 0.37 0.87 0.83 1.24 1.05 0.30 2.12 41.00 39.00 turbatus Magobu Island 1 2462.78 1.36 turbatus Magobu Island 1 2470.40 444.00 0.03 0.22 0.32 0.25 0.69 0.12 1.12 20.00 29.00 turbatus Magobu Island 1 2479.55 0.65 turbatus Magobu Island 1 2481.07 437.00 0.24 0.51 0.93 0.75 0.54 0.32 1.64 31.00 57.00 turbatus Magobu Island 1 2482.60 442.00 0.19 1.29 1.06 1.48 1.22 0.13 1.84 70.00 58.00 turbatus Magobu Island 1 2485.64 0.75 turbatus Magobu Island 1 2488.69 440.00 0.17 1.06 0.90 1.23 1.18 0.14 1.76 60.00 51.00 turbatus Magobu Island 1 2491.74 1.48 turbatus Magobu Island 1 2494.79 446.00 0.13 1.34 1.12 1.47 1.20 0.09 3.17 42.00 35.00 turbatus Magobu Island 1 2497.84 2.19 turbatus Magobu Island 1 2499.36 436.00 0.22 1.95 0.43 2.17 4.56 0.10 2.38 82.00 18.00 turbatus Magobu Island 1 2500.88 441.00 0.07 0.96 0.16 1.03 5.91 0.07 1.48 65.00 11.00 turbatus Magobu Island 1 2502.88 430.00 0.16 1.81 0.54 1.97 3.35 0.08 1.67 108.00 32.00 turbatus Magobu Island 1 2517.65 436.00 0.48 2.17 0.37 2.64 5.78 0.18 1.63 133.00 23.00 turbatus Magobu Island 1 2531.36 448.00 0.03 0.16 0.16 0.19 1.00 0.16 0.76 21.00 21.00 turbatus Magobu Island 1 2535.94 1.28 turbatus Magobu Island 1 2549.65 435.00 0.33 10.54 0.66 10.87 15.94 0.03 3.89 271.00 17.00 torosa Magobu Island 1 2552.70 4.37 torosa Magobu Island 1 2554.22 435.00 0.50 6.66 0.56 7.16 12.00 0.07 3.70 180.00 15.00 torosa Magobu Island 1 2555.75 2.74 torosa Magobu Island 1 2558.80 4.60 torosa Magobu Island 1 2561.84 441.00 0.13 1.98 0.37 2.11 5.31 0.06 2.33 85.00 16.00 torosa Magobu Island 1 2562.15 torosa Magobu Island 1 2564.89 437.00 0.21 2.02 0.84 2.23 2.40 0.09 1.97 103.00 43.00 torosa Magobu Island 1 2567.94 432.00 0.87 13.65 1.04 14.52 13.13 0.06 6.01 227.00 17.00 torosa Magobu Island 1 2570.99 439.00 0.25 1.49 1.06 1.74 1.41 0.14 1.63 91.00 65.00 torosa Magobu Island 1 2572.51 435.00 0.48 5.50 0.47 5.97 11.59 0.08 2.79 197.00 17.00 torosa Magobu Island 1 2574.04 440.00 0.12 3.75 1.01 3.86 3.73 0.03 4.57 82.00 22.00 torosa Magobu Island 1 2590.80 437.00 0.59 5.92 0.64 6.51 9.25 0.09 3.20 185.00 20.00 basement Magobu Island 1 2609.09 440.00 0.78 4.11 0.76 4.89 5.43 0.16 2.52 163.00 30.00 basement Magobu Island 1 2625.85 1.27 basement Morigio 1 2462.50 hp* 424.00 4.90 5.27 1.48 10.17 0.48 1.99 264.82 74.37 tabulata Morigio 1 2463.00 hp* 2.12 6.41 2.16 8.53 0.25 1.65 tabulata 311 Morigio 1 2465.00 0.86 torynum 20 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Morigio 1 2647.50 hp* 0.86 iehiense Morigio 1 2697.50 433.00 0.24 0.77 0.86 1.01 0.24 0.95 81.00 91.00 serrata Morigio 1 2747.50 428.00 0.76 2.14 0.75 2.90 0.26 0.88 243.00 85.00 simplex Morigio 1 2797.50 427.00 0.62 2.13 0.37 0.23 0.87 245.00 43.00 similis Morigio 1 2847.50 432.00 1.35 0.17 1.03 131.00 17.00 similis Morigio 1 2897.50 430.00 1.54 0.18 0.97 159.00 14.00 similis Morigio 1 2947.50 432.00 1.48 0.26 0.98 151.00 83.00 similis Morigio 1 2952.50 hp* 0.87 pellucida Morigio 1 2962.50 hp* 0.90 pellucida Morigio 1 2972.50 hp* 0.88 pellucida Morigio 1 2982.50 hp* 0.86 pellucida Morigio 1 2992.50 hp* 0.86 pellucida Morigio 1 2997.50 435.00 0.32 1.52 0.94 1.84 0.17 1.08 141.00 87.00 pellucida Morigio 1 3007.50 hp* 0.95 pellucida Morigio 1 3047.50 435.00 0.26 1.13 1.02 1.39 0.19 1.15 98.00 89.00 montgomeryi Morigio 1 3082.50 0.78 montgomeryi Morigio 1 3087.50 hp 0.76 perforans Morigio 1 3092.50 0.80 perforans Morigio 1 3097.50 436.00 0.26 1.38 0.12 1.64 0.16 1.05 131.00 11.00 perforans Morigio 1 3147.50 436.00 0.23 1.32 0.23 1.55 0.15 0.95 139.00 24.00 perforans - swanense? Morigio 1 3197.50 436.00 0.25 1.75 0.23 2.00 0.12 1.03 170.00 22.00 perforans - swanense? Morigio 1 3212.50 hp* 0.96 perforans - swanense? Morigio 1 3217.50 hp* 0.99 perforans - swanense? Morigio 1 3222.50 hp* 1.10 perforans - swanense? Morigio 1 3227.50 hp* 436.00 0.18 1.32 0.23 1.50 0.12 1.05 125.71 21.90 perforans - swanense? Morigio 1 3232.50 hp* 0.99 perforans - swanense? Morigio 1 3237.50 hp* 0.99 perforans - swanense? Morigio 1 3242.50 hp* 0.98 perforans - swanense? Morigio 1 3247.00 hp* 0.95 perforans - swanense? Morigio 1 3247.50 432.00 0.27 1.40 0.31 1.67 0.16 0.99 141.00 31.00 perforans - swanense? Morigio 1 3252.50 hp* 433.00 0.12 1.53 0.30 1.65 0.07 1.02 150.00 29.41 perforans - swanense? Morigio 1 3257.50 hp* 0.88 perforans - swanense? Morigio 1 3262.50 hp* 0.94 perforans - swanense? Morigio 1 3297.50 436.00 0.27 1.41 0.28 1.68 0.16 1.06 133.00 26.00 spectabilis Morigio 1 3307.50 0.40 spectabilis Morigio 1 3312.50 0.59 spectabilis Morigio 1 3317.50 0.90 spectabilis Morigio 1 3347.50 436.00 0.36 1.76 0.34 2.12 0.17 1.18 149.00 29.00 spectabilis - aemula Morigio 1 3352.50 432.00 0.09 1.01 2.16 1.10 0.47 0.08 1.21 83.00 179.00 spectabilis - aemula Morigio 1 3357.50 429.00 0.09 0.96 2.02 1.05 0.48 0.09 1.04 92.00 194.00 spectabilis - aemula Morigio 1 3382.50 0.68 spectabilis - aemula Morigio 1 3387.50 hp 431.00 0.13 0.97 1.52 1.10 0.64 0.12 1.07 91.00 142.00 spectabilis - aemula Morigio 1 3392.50 0.83 spectabilis - aemula Morigio 1 3397.50 436.00 0.49 2.43 0.34 2.92 0.17 1.42 171.00 24.00 spectabilis - aemula Morigio 1 3402.50 0.73 spectabilis - aemula Morigio 1 3407.50 0.56 spectabilis - aemula Morigio 1 3412.50 0.62 spectabilis - aemula Morigio 1 3422.50 436.00 0.15 1.00 1.41 1.15 0.71 0.13 1.04 96.00 136.00 spectabilis - aemula Morigio 1 3427.50 0.86 spectabilis - aemula 312

Morigio 1 3432.50 434.00 0.19 1.15 1.68 1.34 0.68 0.14 1.26 91.00 133.00 spectabilis - aemula 21 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Morigio 1 3437.50 433.00 0.20 1.31 1.76 1.51 0.74 0.13 1.43 92.00 123.00 spectabilis - aemula Morigio 1 3447.50 435.00 0.63 3.16 0.70 3.79 0.17 1.50 211.00 47.00 spectabilis - aemula Morigio 1 3467.50 hp*coal 433.00 6.94 55.93 35.39 62.87 0.11 35.22 158.80 100.48 spectabilis - aemula Morigio 1 3468.00 hp*clyst 434.00 0.52 4.62 2.18 5.14 0.10 2.76 167.39 78.99 spectabilis - aemula Morigio 1 3472.50 432.00 0.15 0.74 1.38 0.89 0.54 0.17 1.33 56.00 104.00 spectabilis - aemula Morigio 1 3477.50 432.00 0.16 1.70 3.46 1.86 0.49 0.09 1.88 90.00 184.00 spectabilis - aemula Morigio 1 3482.50 0.79 spectabilis - aemula Morigio 1 3497.50 440.00 0.64 3.42 0.98 4.06 0.16 2.05 167.00 48.00 spectabilis - aemula Morigio 1 3532.50 0.91 spectabilis - aemula Morigio 1 3537.50 0.71 spectabilis - aemula Morigio 1 3547.50 437.00 0.60 3.23 0.55 3.83 0.16 1.85 175.00 30.00 spectabilis - aemula Morigio 1 3597.50 441.00 0.74 3.39 0.64 4.13 0.18 1.84 184.00 35.00 spectabilis - aemula Morigio 1 3647.50 433.00 0.81 3.55 0.87 4.36 0.19 1.86 191.00 47.00 indotata - digitata Morigio 1 3672.50 438.00 0.20 1.14 1.64 1.34 0.70 0.15 1.03 111.00 159.00 indotata - digitata Morigio 1 3697.50 441.00 0.76 3.51 0.71 4.27 0.18 1.75 201.00 41.00 indotata - digitata Morigio 1 3737.50 441.00 0.67 3.48 0.76 4.15 0.16 1.94 179.00 39.00 indotata - digitata Morigio 1 3797.50 442.00 0.59 2.77 0.69 3.36 0.18 1.73 160.00 40.00 indotata - digitata Morigio 1 3812.50 0.86 indotata - digitata Morigio 1 3817.50 0.92 indotata - digitata Morigio 1 3847.50 445.00 0.60 2.92 0.57 3.52 0.17 1.79 163.00 32.00 indotata - digitata Morigio 1 3897.50 443.00 0.53 2.62 0.58 3.15 0.17 1.51 174.00 38.00 indotata - digitata Morigio 1 3947.50 442.00 0.73 3.09 0.58 3.82 0.19 1.75 177.00 33.00 indotata - digitata Morigio 1 3952.5 Ctgs 437 0.13 0.59 1.18 0.72 0.50 0.18 0.84 70 140 indotata - digitata Morigio 1 3977.50 hp* 442.00 0.41 1.89 1.38 2.30 0.18 1.56 121.15 88.46 indotata - digitata Morigio 1 3987.50 444.00 0.90 3.08 0.67 3.98 0.23 1.76 175.00 38.00 indotata - digitata Mutare 1 924.00 0.26 similis Mutare 1 960.27 0.24 pellucida Mutare 1 993.65 1.08 pellucida Mutare 1 995.93 0.50 pellucida - jurassica ? Mutare 1 1001.42 0.34 pellucida - jurassica ? Mutare 1 1002.33 hp* 1.42 pellucida - jurassica ? Mutare 1 1003.25 424.00 0.33 1.08 159.00 86.00 pellucida - jurassica ? Mutare 1 1003.25 hp* 1.43 pellucida - jurassica ? Mutare 1 1005.38 hp* 1.98 pellucida - jurassica ? Mutare 1 1008.74 hp* 426.00 0.18 1.26 1.24 1.44 0.13 1.57 80.25 78.98 pellucida - jurassica ? Mutare 1 1023.37 hp* 432.00 0.06 0.50 2.22 0.56 0.11 1.63 30.67 136.20 pellucida - jurassica ? Mutare 1 1030.68 hp* 1.60 pellucida - jurassica ? Mutare 1 1031.40 1.08 pellucida - jurassica ? Mutare 1 1033.12 hp* 434.00 0.04 0.42 1.73 0.46 0.09 1.51 27.81 114.57 pellucida - jurassica ? Mutare 1 1034.95 hp* 428.00 5.85 55.75 30.60 61.60 0.09 57.75 96.54 52.99 pellucida - jurassica ? Mutare 1 1038.61 hp* 1.53 pellucida - jurassica ? Mutare 1 1040.43 hp* 438.00 0.03 0.69 1.67 0.72 0.04 1.72 40.12 97.09 montgomeryi -perforans ? Mutare 1 1049.12 1.08 montgomeryi -perforans ? Mutare 1 1055.98 0.28 montgomeryi -perforans ? Mutare 1 1057.81 425.00 0.26 1.16 182.00 61.00 montgomeryi -perforans ? Mutare 1 1066.85 core* 0.42 montgomeryi -perforans ? Mutare 1 1077.01 0.24 montgomeryi -perforans ? Mutare 1 1082.04 0.79 montgomeryi -perforans ? Mutare 1 1094.38 375.00 0.20 1.40 143.00 71.00 montgomeryi -perforans ? 313

Mutare 1 1097.28 0.86 montgomeryi -perforans ? 22 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Mutare 1 1104.09 core* 0.65 montgomeryi -perforans ? Mutare 1 1106.52 core* 426.00 0.11 1.23 2.47 1.34 0.08 3.26 37.73 75.77 montgomeryi -perforans ? Mutare 1 1120.29 426.00 0.26 1.16 150.00 47.00 montgomeryi -perforans ? Mutare 1 1149.86 430.00 0.32 1.30 130.00 209.00 aemula - digitata Mutare 1 1156.82 core* 434.00 0.09 2.27 0.92 2.36 0.04 2.19 103.65 42.01 aemula - digitata Mutare 1 1165.10 431.00 0.16 1.47 104.00 23.00 aemula - digitata Mutare 1 1170.58 0.45 aemula - digitata Mutare 1 1185.21 1.14 aemula - digitata Mutare 1 1187.04 429.00 0.29 1.03 231.00 143.00 aemula - digitata Mutare 1 1193.90 424.00 0.27 1.28 94.00 30.00 aemula - digitata Mutare 1 1203.50 424.00 0.27 1.28 94.00 30.00 aemula - digitata Mutare 1 1203.50 425.00 0.35 1.33 90.00 64.00 aemula - digitata Mutare 1 1219.96 0.71 digitata Mutare 1 1226.06 1.42 digitata Mutare 1 1240.08 428.00 0.18 1.30 71.00 72.00 digitata Mutare 1 1249.68 425.00 0.27 1.54 123.00 45.00 digitata Mutare 1 1254.71 0.60 indotata Mutare 1 1269.34 425.00 0.24 1.61 72.00 44.00 indotata Mutare 1 1271.17 426.00 0.27 1.35 77.00 142.00 indotata Mutare 1 1285.80 427.00 0.34 1.09 61.00 143.00 indotata Mutare 1 1291.59 1.53 indotata Mutare 1 1305.00 426.00 0.28 1.25 88.00 76.00 indotata Mutare 1 1312.01 427.00 0.16 1.70 57.00 35.00 indotata Mutare 1 1328.78 425.00 0.28 1.64 76.00 45.00 indotata Mutare 1 1329.39 0.31 indotata Mutare 1 1340.36 425.00 0.18 1.51 59.00 32.00 halosa Mutare 1 1343.05 core* 402.00 0.19 0.87 0.30 1.06 0.18 0.98 88.78 30.61 halosa Mutare 1 1344.27 core* 0.77 halosa Mutare 1 1346.10 core* 434.00 0.36 1.80 2.69 2.16 0.17 6.08 29.61 44.24 halosa Mutare 1 1352.55 0.98 halosa Mutare 1 1354.07 424.00 0.25 1.57 83.00 43.00 halosa Mutare 1 1361.90 core* 422.00 0.22 3.56 1.88 3.78 0.06 4.18 85.17 44.98 halosa Mutare 1 1369.01 427.00 0.17 2.05 156.00 20.00 halosa Mutare 1 1372.21 429.00 0.20 2.61 163.00 28.00 halosa Mutare 1 1385.47 0.97 halosa Mutare 1 1390.50 426.00 0.34 2.38 128.00 33.00 halosa Mutare 1 1414.27 0.50 halosa North Paibuna 1 3061.7 hp 0.41 denticulata North Paibuna 1 3066.3 Ctgs 433 0.11 0.63 50 41 denticulata North Paibuna 1 3070.9 hp 0.45 denticulata North Paibuna 1 3080.0 hp 0.40 denticulata North Paibuna 1 3089.1 hp 0.45 denticulata North Paibuna 1 3093.7 Ctgs 426 0.16 0.53 32 53 denticulata North Paibuna 1 3098.3 hp 0.53 tetracantha North Paibuna 1 3107.4 Ctgs 317 10.07 10.16 12.90 20.23 0.79 0.50 5.24 194 246 tetracantha North Paibuna 1 3124.2 Ctgs 429 0.19 0.67 31 64 tetracantha North Paibuna 1 3150.1 hp 0.25 davidii North Paibuna 1 3154.7 Ctgs 431 0.15 0.60 48 40 davidii North Paibuna 1 3165.3 0.37 operculata 314

North Paibuna 1 3174.5 0.44 operculata 23 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION North Paibuna 1 3192.8 hp 328 0.74 2.80 5.15 3.54 0.54 0.21 1.49 188 346 operculata North Paibuna 1 3201.9 0.58 operculata North Paibuna 1 3211.1 0.64 operculata North Paibuna 1 3220.2 0.76 operculata North Paibuna 1 3229.4 0.83 operculata North Paibuna 1 3238.5 0.87 operculata North Paibuna 1 3246.1 Ctgs 436 0.06 0.50 248 32 australis North Paibuna 1 3256.8 0.87 operculata North Paibuna 1 3265.9 0.71 operculata North Paibuna 1 3276.6 Ctgs 435 0.06 0.76 265 27 australis North Paibuna 1 3284.2 0.72 operculata North Paibuna 1 3307.1 Ctgs 435 0.12 1.12 105 20 australis North Paibuna 1 3337.6 Ctgs unextd. 432 0.10 1.02 486 58 tabulata C North Paibuna 1 3337.6 Ctgs extd. 428 0.14 1.01 699 319 tabulata C North Paibuna 1 3368.0 Ctgs 437 0.08 0.88 218 61 torynum C North Paibuna 1 3461.0 Ctgs 427 0.31 1.49 3.72 1.80 0.40 0.17 0.99 151 376 torynum C North Paibuna 1 3470.1 0.88 torynum C North Paibuna 1 3479.3 0.92 torynum C North Paibuna 1 3488.4 0.84 torynum C North Paibuna 1 3500.6 0.86 reticulata - lobispinum C North Paibuna 1 3520.4 Core 1 426 0.05 0.47 0.23 0.52 2.04 0.10 0.48 98 48 reticulata - lobispinosum North Paibuna 1 3558.5 Ctgs 424 0.27 0.76 2.65 1.03 0.29 0.26 0.57 133 465 iehiense C North Paibuna 1 3581.4 Ctgs 436 0.13 0.66 215 56 iehiense C North Paibuna 1 3611.9 Ctgs 437 0.10 0.51 374 64 serrata C North Paibuna 1 3619.5 Ctgs 422 0.12 0.69 1.09 0.81 0.63 0.15 0.69 100 158 serrata C North Paibuna 1 3621.0 Ctgs 419 0.11 0.51 1.32 0.62 0.39 0.18 0.77 66 171 serrata C North Paibuna 1 3642.4 Ctgs unextd. 439 0.12 1.29 292 53 simplex C North Paibuna 1 3642.4 Ctgs extd. 435 0.09 1.03 401 201 simplex C North Paibuna 1 3648.5 Ctgs 373 0.29 0.89 1.84 1.18 0.48 0.25 0.71 125 259 simplex C North Paibuna 1 3669.8 Ctgs 431 0.22 0.80 2.14 1.02 0.37 0.22 0.64 125 334 e. similis C North Paibuna 1 3715.5 Core 2 434 0.33 1.13 0.35 1.46 3.23 0.23 0.71 159 49 e. similis North Paibuna 1 3729.2 Ctgs 429 0.18 1.35 0.89 1.53 1.52 0.12 0.75 180 119 e. similis C North Paibuna 1 3770.4 Ctgs 428 0.24 2.18 1.21 2.42 1.80 0.10 1.04 210 116 e. similis C North Paibuna 1 3819.8 Ctgs unextd. 429 0.27 2.24 1.55 2.51 1.45 0.11 1.07 209 145 montgomeryi C North Paibuna 1 3819.8 Ctgs extd. 430 0.13 1.77 1.47 1.90 1.20 0.07 1.03 172 143 montgomeryi C North Paibuna 1 3855.7 Ctgs 439 0.14 0.89 386 17 montgomeryi C North Paibuna 1 3869.4 0.74 montgomeryi C North Paibuna 1 3872.5 0.61 montgomeryi - perforans C North Paibuna 1 3875.5 0.55 montgomeryi - perforans C North Paibuna 1 3878.6 0.53 montgomeryi - perforans C North Paibuna 1 3886.2 Ctgs 434 0.12 0.87 260 71 montgomeryi-perforans C North Paibuna 1 3916.7 Ctgs 436 0.10 1.23 452 21 montgomeryi-perforans C North Paibuna 1 3930.4 Ctgs hp 433 0.20 4.84 0.26 5.04 18.62 0.04 1.61 301 16 perforans-swanense? C North Paibuna 1 3933.4 Ctgs hp 434 0.31 7.42 0.26 7.73 28.54 0.04 1.89 393 14 perforans-swanense? C North Paibuna 1 3936.5 hp* 0.84 swanense C North Paibuna 1 3936.5 hp* 0.84 swanense C North Paibuna 1 3942.6 Ctgs hp 436 0.23 3.75 0.44 3.98 8.52 0.06 1.37 274 32 swanense C North Paibuna 1 3945.6 hp* 0.98 swanense C North Paibuna 1 3945.6 hp* 0.98 swanense C 315

North Paibuna 1 3947.2 Ctgs 433 0.15 0.71 1095 76 swanense C 24 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION North Paibuna 1 3951.7 hp* 0.88 swanense C North Paibuna 1 3951.7 hp* 0.88 swanense C North Paibuna 1 3973.1 hp* 1.07 swanense C North Paibuna 1 3973.1 hp* 1.07 swanense C North Paibuna 1 3976.1 Ctgs hp 433 0.22 1.93 0.43 2.15 4.49 0.10 1.23 157 35 swanense C North Paibuna 1 3979.2 hp* 0.94 swanense C North Paibuna 1 3979.2 hp* 0.94 swanense C North Paibuna 1 3982.2 hp* 0.79 swanense C North Paibuna 1 3982.2 hp* 0.79 swanense C North Paibuna 1 3985.3 hp*1 0.99 swanense C North Paibuna 1 3985.3 hp*2 0.98 swanense C North Paibuna 1 3985.3 hp*1 0.99 swanense C North Paibuna 1 3985.3 hp*2 0.98 swanense C North Paibuna 1 3988.3 Ctgs hp 2 435 0.17 1.93 0.34 2.10 5.68 0.08 1.07 180 32 swanense C North Paibuna 1 3991.4 hp* 0.88 swanense C North Paibuna 1 3997.5 Ctgs hp 436 0.21 1.62 0.39 1.83 4.15 0.11 1.06 153 37 swanense C North Paibuna 1 4003.5 hp* 1.01 swanense C North Paibuna 1 4006.6 hp*1 0.67 swanense C North Paibuna 1 4006.6 hp*1 0.67 swanense C North Paibuna 1 4006.6 Ctgs hp 2 436 0.22 2.15 0.29 2.37 7.41 0.09 1.22 176 24 swanense C North Paibuna 1 4009.6 hp* 1.19 swanense C North Paibuna 1 4015.7 Ctgs hp 433 0.23 1.87 0.33 2.10 5.67 0.11 1.12 167 29 swanense C North Paibuna 1 4038.6 Ctgs 433 0.41 0.75 1561 189 clathrata C North Paibuna 1 4076.7 Mud 422 0.37 0.81 204 440 lt spectabilis C North Paibuna 1 4099.6 Ctgs 326 0.35 1.84 668 706 lt spectabilis C North Paibuna 1 4130.0 Ctgs unextd. 439 0.17 1.34 238 176 e. spectabilis C North Paibuna 1 4130.0 Ctgs extd. 440 0.11 1.25 169 206 e. spectabilis C North Paibuna 1 4160.5 Ctgs 440 0.19 0.87 257 102 e. spectabilis C North Paibuna 1 4183.4 Ctgs 441 0.17 1.78 196 32 e. spectabilis C North Paibuna 1 4198.6 Ctgs 440 0.15 1.43 278 50 e. spectabilis C North Paibuna 1 4213.9 Ctgs 433 0.22 0.75 1473 172 e. spectabilis C North Paibuna 1 4232.1 SWC unextd. 436 0.95 7.02 1.72 7.97 4.08 0.12 2.96 237 58 e. spectabilis North Paibuna 1 4232.1 SWC extd. 439 0.21 5.48 1.73 5.69 3.17 0.04 2.83 194 61 e. spectabilis North Paibuna 1 4244.3 Ctgs 435 0.22 0.70 1590 510 e. spectabilis C North Paibuna 1 4267.2 Mud 428 0.36 0.73 206 510 e. spectabilis C North Paibuna 1 4274.8 Ctgs 439 0.13 1.61 264 50 e. spectabilis C North Paibuna 1 4277.3 SWC 435 1.59 5.70 1.45 7.29 3.93 0.22 1.97 289 74 e. spectabilis North Paibuna 1 4282.4 SWC 438 0.46 2.26 0.91 2.72 2.48 0.17 1.09 207 83 e. spectabilis North Paibuna 1 4287.0 Ctgs 441 0.14 1.76 382 19 e. spectabilis C Omati 1 3084.0 442 0.30 0.94 52 22 ludbrookiae Omati 1 3131.8 442 0.25 0.89 37 20 ludbrookiae Omati 1 3180.6 439 0.19 0.74 30 14 denticulata Omati 1 3224.0 442 0.14 0.76 33 13 davidii Omati 1 3275.1 439 0.14 0.95 39 17 operculata Omati 1 3320.8 434 0.16 0.76 36 13 australis Omati 1 3347.0 0.76 testudinaria - burgeri Omati 1 3364.4 437 0.26 0.90 93 15 testudinaria - burgeri Omati 1 3366.5 427 0.12 0.86 42 8 tabulata Omati 1 3409.2 442 0.13 0.91 29 5 tabulata 316

Omati 1 3454.9 435 0.12 1.30 35 7 areolata 25 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Omati 1 3500.6 439 0.08 1.16 81 7 torynum Omati 1 3550.9 436 0.06 1.08 101 7 iehiense Omati 1 3570.4 0.69 iehiense Omati 1 3597.4 435 0.07 1.02 98 8 iehiense Omati 1 3638.1 438 0.17 1.06 158 9 serrata Omati 1 3648.5 438 0.11 0.85 96 11 serrata Omati 1 3692.7 437 0.15 0.81 81 16 simplex Omati 1 3735.3 0.25 simplex Omati 1 3787.1 443 0.13 0.92 71 17 similis Omati 1 3829.1 438 0.23 0.80 29 29 similis Omati 1 3829.8 443 0.12 0.92 66 12 similis Omati 1 3875.5 444 0.13 0.95 42 16 pellucida - jurassica Omati 1 3918.2 448 0.12 0.90 56 17 montgomeryi Omati 1 3967.0 443 0.16 0.96 39 21 montgomeryi Omati 1 4009.6 444 0.20 0.97 34 18 montgomeryi Omati 1 4043.2 446 0.09 1.04 87 17 perforans Omati 1 4109.0 0.49 swanense Omati 1 4113.3 445 0.10 1.33 120 18 swanense Omati 1 4151.4 446 0.54 1.13 73 35 clathrata Omati 1 4164.5 446 0.22 1.18 140 8 clathrata Omati 1 4188.1 hp* 0.86 clathrata Omati 1 4191.9 hp* 0.84 clathrata Omati 1 4195.3 hp* 442 0.23 1.42 0.10 1.65 14.20 0.14 1.08 131 9 clathrata Omati 1 4196.3 445 0.15 1.00 72 29 clathrata Omati 1 4199.4 hp* 0.96 clathrata Omati 1 4201.1 hp* 1.10 clathrata Omati 1 4202.6 hp* 443 0.44 2.26 0.13 2.70 17.38 0.16 1.67 135 8 clathrata Omati 1 4204.7 hp* 1.61 clathrata Omati 1 4239.0 435 0.29 0.71 66 70 spectabilis Omati 1 4287.0 446 0.30 1.38 94 36 spectabilis Omati 1 4335.8 424 0.31 2.22 202 34 spectabilis Omati 1 4372.4 452 0.30 1.72 78 31 spectabilis Rama 1 2817.50 picked 434.00 0.15 1.20 105.00 79.00 torynum Rama 1 2857.50 picked 431.00 0.16 1.03 142.00 63.00 torynum Rama 1 2917.50 picked 433.00 0.11 0.90 139.00 54.00 reticulata - lobispinum Rama 1 2952.50 0.67 wisemaniae - delicata Rama 1 2997.50 433.00 0.11 0.75 108.00 59.00 serrata Rama 1 3077.50 picked 432.00 0.11 0.89 125.00 20.00 simplex Rama 1 3117.50 433.00 0.11 0.73 122.00 38.00 similis Rama 1 3157.50 434.00 0.07 0.74 188.00 27.00 similis Rama 1 3162.50 hp* 1.72 similis Wabuda 1 1899.97 0.06 tetracantha Wabuda 1 1909.88 0.17 tetracantha Wabuda 1 1920.24 0.07 tetracantha Wabuda 1 1930.60 0.12 tetracantha Wabuda 1 1940.97 0.04 australis-operculata Wabuda 1 1950.87 0.07 australis-operculata Wabuda 1 1960.93 0.08 australis-operculata Wabuda 1 1970.99 0.22 australis-operculata 317

Wabuda 1 1985.01 0.23 australis-operculata 26 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Wabuda 1 1990.19 0.34 australis-operculata Wabuda 1 2000.55 0.88 australis-operculata Wabuda 1 2010.92 0.58 australis-operculata Wabuda 1 2020.98 0.74 australis-operculata Wabuda 1 2030.12 0.78 australis-operculata Wabuda 1 2039.57 0.62 australis-operculata Wabuda 1 2050.69 0.73 australis-operculata Wabuda 1 2060.14 0.72 australis-operculata Wabuda 1 2070.51 0.64 australis-operculata Wabuda 1 2080.87 0.66 australis-operculata Wabuda 1 2090.93 0.74 australis-cinctum Wabuda 1 2100.07 0.66 australis-cinctum Wabuda 1 2110.28 0.79 australis-cinctum Wabuda 1 2120.04 0.56 australis-cinctum Wabuda 1 2130.09 0.70 australis-cinctum Wabuda 1 2140.46 0.69 australis-cinctum Wabuda 1 2150.82 1.07 australis-cinctum Wabuda 1 2160.12 0.80 tabulata - testudinaria Wabuda 1 2170.02 0.92 tabulata - testudinaria Wabuda 1 2175.00 423.00 0.11 0.90 0.11 1.00 86.00 4.00 tabulata - testudinaria Wabuda 1 2180.00 0.86 tabulata - testudinaria Wabuda 1 2190.00 0.81 tabulata - aerolata Wabuda 1 2200.00 0.81 tabulata - aerolata Wabuda 1 2205.00 430.00 0.13 1.60 0.08 0.97 162.00 3.05 tabulata - aerolata Wabuda 1 2210.00 0.86 tabulata - aerolata Wabuda 1 2220.00 1.05 tabulata - aerolata Wabuda 1 2230.00 0.78 tabulata - aerolata Wabuda 1 2240.00 0.79 tabulata - aerolata Wabuda 1 2250.00 0.25 reticulata - lobispinum Wabuda 1 2260.00 0.74 reticulata - lobispinum Wabuda 1 2270.00 0.06 reticulata - lobispinum Wabuda 1 2280.00 0.73 wisemaniae - delicata? Wabuda 1 2297.00 428.00 0.17 0.90 0.16 0.63 146.00 64.91 wisemaniae - delicata? Wabuda 1 2300.00 0.65 wisemaniae - delicata? Wabuda 1 2310.00 0.27 wisemaniae - delicata? Wabuda 1 2320.00 0.21 iehiense Wabuda 1 2330.00 0.61 iehiense Wabuda 1 2340.00 0.03 iehiense Wabuda 1 2350.00 0.06 iehiense Wabuda 1 2360.00 0.69 iehiense Wabuda 1 2370.00 0.09 iehiense Wabuda 1 2380.00 0.73 iehiense Wabuda 1 2390.00 0.46 iehiense Wabuda 1 2400.00 0.56 iehiense Wabuda 1 2410.00 0.33 iehiense Wabuda 1 2420.00 0.84 serrata Wabuda 1 2430.00 0.69 serrata Wabuda 1 2440.00 0.93 serrata Wabuda 1 2450.00 0.53 simplex 318

Wabuda 1 2460.00 0.33 simplex 27 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Wabuda 1 2470.00 0.44 simplex Wabuda 1 2480.00 0.29 simplex Wabuda 1 2490.00 0.31 similis Wabuda 1 2500.00 0.11 similis Wabuda 1 2510.00 0.10 similis Wabuda 1 2520.00 0.03 similis Wabuda 1 2530.00 0.01 similis Wabuda 1 2540.00 0.03 similis Wabuda 1 2550.00 0.45 similis Wabuda 1 2560.00 0.48 similis Wabuda 1 2570.00 0.62 similis Wabuda 1 2580.00 431.00 0.11 1.20 0.08 0.88 123.00 0.06 similis Wabuda 1 2590.00 0.98 similis Wabuda 1 2600.00 0.85 similis Wabuda 1 2610.00 0.73 pellucida - jurassica Wabuda 1 2615.00 432.00 0.17 2.10 0.07 1.44 147.00 43.96 pellucida - jurassica Wabuda 1 2620.00 0.74 pellucida - jurassica Wabuda 1 2630.00 0.86 pellucida - jurassica Wabuda 1 2640.00 0.63 pellucida - jurassica Wabuda 1 2650.00 0.84 pellucida - jurassica Wabuda 1 2660.00 0.92 pellucida - jurassica Wabuda 1 2670.00 0.71 pellucida - jurassica Wabuda 1 2680.00 0.81 pellucida - jurassica Wabuda 1 2690.00 0.92 pellucida - jurassica Wabuda 1 2700.00 0.89 pellucida - jurassica Wabuda 1 2708.00 432.00 0.26 2.10 0.11 1.46 142.00 49.00 montgomeryi Wabuda 1 2710.00 0.83 montgomeryi Wabuda 1 2720.00 0.87 montgomeryi Wabuda 1 2724.00 431.00 0.25 1.80 0.12 1.28 140.00 34.08 montgomeryi Wabuda 1 2730.00 0.80 montgomeryi Wabuda 1 2740.00 0.89 montgomeryi Wabuda 1 2750.00 0.69 montgomeryi Wabuda 1 2755.00 427.00 0.24 4.30 0.05 1.46 289.00 3.37 perforans - swanense Wabuda 1 2760.00 0.81 perforans - swanense Wabuda 1 2770.00 0.94 perforans - swanense Wabuda 1 2780.00 0.89 perforans - swanense Wabuda 1 2790.00 0.71 perforans - swanense Wabuda 1 2800.00 434.00 0.20 1.20 0.15 0.78 117.00 0.01 perforans - swanense Wabuda 1 2802.00 426.00 0.08 0.71 0.10 0.55 129.00 37.38 perforans - swanense Wabuda 1 2810.00 0.88 perforans - swanense Wabuda 1 2815.00 428.00 0.27 1.10 0.20 1.63 66.00 10.28 perforans - swanense Wabuda 1 2820.00 0.88 perforans - swanense Wabuda 1 2830.00 0.69 clathrata Wabuda 1 2834.00 431.00 0.45 2.40 0.16 0.61 389.00 32.96 clathrata Wabuda 1 2835.0 Ctgs 431 0.06 0.72 0.70 0.78 1.03 0.08 0.65 111 108 clathrata Wabuda 1 2840.00 0.86 clathrata Wabuda 1 2850.00 0.91 clathrata Wabuda 1 2860.00 0.79 clathrata 319

Wabuda 1 2870.00 1.02 clathrata Wabuda 1 2880.00 0.33 spectabilis 28 APPENDIX 9.3: ROCK-EVAL PYROLYSIS DATA WELL METRES (md) SAMPLE TMAX S1 S2 S3 S1+S2 S2/S3 PI TOC HI OI AGE (Nannofossil) CONTAMINATION Wabuda 1 2888.00 433.00 0.20 0.90 0.19 0.83 104.00 7.06 spectabilis Wabuda 1 2890.00 0.31 spectabilis Wabuda 1 2894.00 432.00 0.20 1.30 0.16 1.86 58.00 1.08 spectabilis Wabuda 1 2895.00 434.00 0.43 3.90 0.11 1.32 295.00 22.70 spectabilis Wabuda 1 2900.00 0.96 spectabilis Wabuda 1 2902.00 0.96 spectabilis Wabuda 1 2910.00 0.93 spectabilis Wabuda 1 2920.00 1.01 spectabilis Wabuda 1 2925.00 433.00 0.39 2.50 0.14 1.94 127.00 15.17 spectabilis Wabuda 1 2930.00 1.26 spectabilis Wabuda 1 2940.00 0.88 spectabilis Wabuda 1 2950.00 0.58 spectabilis Wabuda 1 2960.00 0.97 spectabilis Wabuda 1 2965.00 433.00 0.50 3.50 0.12 2.38 148.00 12.01 spectabilis Wabuda 1 2970.00 0.87 spectabilis Wabuda 1 2980.00 0.87 spectabilis Wabuda 1 2982.50 hp* 435.00 0.32 5.73 0.68 6.05 0.05 2.51 228.29 27.09 spectabilis Wabuda 1 2985.0 Ctgs 434 0.09 0.78 0.42 0.87 1.86 0.10 0.74 105 57 spectabilis Wabuda 1 2987.50 hp* 2.39 spectabilis Wabuda 1 2989.00 435.00 0.67 5.90 0.10 2.92 201.00 75.95 spectabilis Wabuda 1 2990.00 1.01 spectabilis Wabuda 1 2992.50 hp* 2.37 spectabilis Wabuda 1 2996.00 435.00 0.70 7.50 0.09 2.10 357.00 57.08 spectabilis Wabuda 1 2997.50 hp* 435.00 0.29 4.74 0.99 5.03 0.06 2.58 183.72 38.37 spectabilis Wabuda 1 3000.00 1.23 spectabilis Wabuda 1 3002.50 hp* 1.78 spectabilis Wabuda 1 3007.50 hp* 1.91 spectabilis Wabuda 1 3010.00 1.05 spectabilis Wabuda 1 3012.00 434.00 0.59 4.50 0.12 1.27 354.00 31.05 spectabilis Wabuda 1 3012.50 hp* 433.00 0.15 3.59 0.71 3.74 0.04 2.31 155.41 30.74 spectabilis Wabuda 1 3016.00 0.24 spectabilis Wabuda 1 3020.00 1.01 spectabilis Wabuda 1 3030.00 1.08 spectabilis Wabuda 1 3040.00 0.97 spectabilis Wabuda 1 3044.00 437.00 0.17 1.40 0.11 2.02 65.00 5.03 spectabilis Wabuda 1 3046.00 435.00 0.68 6.19 0.10 1.40 442.00 87.16 spectabilis Wabuda 1 3049.00 1.19 spectabilis

REFERENCES USED IN THE COMPILATION OF APPENDIX 9.3 CONSIST OF THE FOLLOWING: LUND (1999) GEOTECH (1996) GEOTECH (1997) 320

GEOTECH (2006b) 321

APPENDIX 9.4 – CORRESPONDANCE WITH GEOTECH LAB REGARDING PYROLYSIS GAS CHROMATOGRAPHY

======From: Cindy Barber [[email protected]] Sent: Wednesday, 28 February 2007 12:39 To: Wood, Stephen Subject: Re: Duadua-1 St1 pyGC data

Hi Stephen

The pyGC data for Duadua-1 does not indicate Type I kerogen, which is pretty consistent with the Rock Eval data. The distinct peaks you mention eluting before the n-alkane peaks are the alkenes.

Looking at the data, there are two parameters which are most useful:

The first is the 'C15-C31 abundance (alkanes + alkenes). A good oil prone source rock will have high values for this parameter. We generally use a cut-off of 5 - anything below 5 being gas prone.

The second is (C1-C5)/C6+. This is the gas/oil generation index - the lower the value, the better the source rock. We generally use a cut-off of 0.5 to distinguish between gas and oil prone rocks.

So, if you have a source rock with a 'C15-C31 abundance (alkanes + alkenes)' above 5 and a (C1-C5)/C6+ below 0.5, you've got a good oil prone source rock. In the case of the Duadua-1 samples, 'C15-C31 abundance (alkanes + alkenes)' values are below 5, suggesting the samples are more gas prone than oil prone. This data, together with the chromatograms showing distinct alkane/alkene pairs, suggests to me that we have Type II source rocks.

If you look at the Duadua-1 2245m sample, the poor data and the poor chromatogram are more consistent with a Type III gas prone source rock.

I've attached the pyGC data for the Komewu-2, Aramia-1 and Koko-1 samples. These samples are a lot more oil prone than the Duadua-1 samples.

I hope that helps! Let me know if there's any additional information you need.

Regards

Cindy

Cindy Barber Divisional Manager Petroleum Geochemistry

Geotechnical Services Pty Ltd 41-45 Furnace Road Welshpool WA 6106 Australia Ph: +61 8 9458 8877 Fax: +61 8 9458 8857 Email: [email protected] www.geotechnical-services.com.au APPENDIX 9.5: DATA USED IN BASIN MODELLING 322 Temperature from AFTA (Duddy et al 1991) Vr% Calculated from relations by Burnham and Sweeney (1989)

WELL Depth (m) Vr% (Ro mean) FAMM AFTA-T1 AFTA-T2 AVERAGE T1 & 2 Vr % - 1ma Duration Vr % - 10ma Duration KANAU 1 609 0.43 KANAU 1 705 0.38 KANAU 1 795 0.41 KANAU 1 885 0.49 KANAU 1 975 0.52 KANAU 1 1065 0.45 KANAU 1 1095 0.52 KANAU 1 1155 0.43 KANAU 1 1322.5 80 95 87.5 0.47 0.56 KANAU 1 1425 0.57 KANAU 1 1580 0.52 KANAU 1 1725 0.51 KANAU 1 1785 0.46 KANAU 1 1845 0.53 KANAU 1 1972.5 95 105 100 0.55 0.65 KANAU 1 2055 0.55 KANAU 1 2140 0.53 KANAU 1 2205 0.56 KANAU 1 2235 0.56 KANAU 1 2325 0.63 KANAU 1 2415 0.53 KANAU 1 2475 0.58 KANAU 1 2505 0.56 KANAU 1 2590 0.6 KANAU 1 2685 0.65 KANAU 1 2715 0.74 KANAU 1 2775 0.61 KANAU 1 2805 0.75 KANAU 1 2835 0.6 KANAU 1 2850 105 115 110 0.62 0.74 KANAU 1 2985 0.68 KANAU 1 3002 110 125 117.5 0.67 0.81 KANAU 1 3135 0.68 KANAU 1 3255 0.72 KANAU 1 3315 0.79 KANAU 1 3405 0.68 KANAU 1 3476 0.79 1.03 KANAU 1 3477 125 0.74 0.89 KANAU 1 3495 0.95 KANAU 1 3519 0.86 KOMEWU 2 1545 KOMEWU 2 1545 70 80 75 0.41 0.47 KOMEWU 2 1690.1 0.4 KOMEWU 2 1870 KOMEWU 2 1870 80 90 85 0.46 0.54 KOMEWU 2 1916 0.49 0.57 KOMEWU 2 2003.3 0.43 KOMEWU 2 2239 KOMEWU 2 2239 90 90 90 0.49 0.57 KOMEWU 2 2336 0.49 KOMEWU 2 2362.9 0.46 KOMEWU 2 2506.2 0.56 KOMEWU 2 2604.5 0.57 KOMEWU 2 2683 0.66 KOMEWU 2 2775.2 0.65 KOMEWU 2 2862 0.51 0.65 KOMEWU 2 2866.6 0.64 KOMEWU 2 2930.6 0.69 KOMEWU 2 3030 KOMEWU 2 3040 94 110 102 0.56 0.67 KAMUSI 1 2237.2 0.56 KAMUSI 1 2337.8 0.55 KAMUSI 1 2400.3 0.69 KAMUSI 1 2574 0.71 KAMUSI 1 2590.8 0.57 KAMUSI 1 2740.2 0.72 KAMUSI 1 2804.2 0.63 KAMUSI 1 2904.7 0.64 KAMUSI 1 2910.8 0.72 KAMUSI 1 3020.6 0.65 KAMUSI 1 3072.4 0.82 KAMUSI 1 3171.4 0.75 KAMUSI 1 3171.4 0.68 NORTH PAIBUNA 1 3108.7 0.39 NORTH PAIBUNA 1 3113.5 0.7 NORTH PAIBUNA 1 3113.8 0.7 NORTH PAIBUNA 1 3178.8 0.39 NORTH PAIBUNA 1 3264.7 0.45 NORTH PAIBUNA 1 3360.4 0.46 NORTH PAIBUNA 1 3493.6 0.68 NORTH PAIBUNA 1 3493.9 0.43 NORTH PAIBUNA 1 3493.9 0.65 NORTH PAIBUNA 1 3614.6 0.71 NORTH PAIBUNA 1 3614.9 0.7 NORTH PAIBUNA 1 3628 0.47 NORTH PAIBUNA 1 3709.7 0.44 NORTH PAIBUNA 1 3796.9 0.45 NORTH PAIBUNA 1 3903 0.5 NORTH PAIBUNA 1 3935 0.8 NORTH PAIBUNA 1 3956.9 0.46 NORTH PAIBUNA 1 3989.5 0.77 NORTH PAIBUNA 1 3989.8 0.75 NORTH PAIBUNA 1 4046.2 0.46 NORTH PAIBUNA 1 4114.8 0.82 NORTH PAIBUNA 1 4147.7 0.47 NORTH PAIBUNA 1 4205.9 0.44 NORTH PAIBUNA 1 4236.4 0.45 NORTH PAIBUNA 1 4242.5 0.95 NORTH PAIBUNA 1 4268.1 0.45

Source of Vr and FAMM Data Robertson (1990) Faiz et al. (1997) CNODC (1996) Sherwood (1997) Sherwood (2007) Volk et al. (2007) APPENDIX 9.5: Basin Modelling Data (CONTINUED) - Temperature Data 323 Well Depth (md) Max BHT (oC) t Circ stopped Log on Bottom TSC* Horner Corrected Temperature (oC) Source Kamusi 1 2023 45.6 1/2/96 0:30 1/2/96 10:38 10.1 DLL-MSFL-BCS-GR Kamusi 1 2613.4 64.4 20/2/96 23:00 21/2/96 7:42 8.7 DLL-MSFL-BCS-GR Kamusi 1 3194 88.3 6 2/3/96 2:30 2/3/96 14:55 12.4 101.01 Checkshot Kamusi 1 3190 91.7 2/3/96 2:30 2/3/96 20:25 17.9 SLD-CNT-GR Kanau 1 609 31.1 2.0 Temperature Survey Kanau 1 610 31.1 2.0 Induction Kanau 1 1407 46.1 Not Rec Induction Kanau 1 1567 47.8 20.0 49.09 Temperature Survey Kanau 1 1567 47.8 20.0 CN-FD Kanau 1 1568 44.4 4.0 Induction Kanau 1 1707 48.3 15.0 48.77 Temperature Survey Kanau 1 1710 47.8 4.0 Induction Kanau 1 1710 48.3 9.0 CN-FD Kanau 1 3154 76.7 5.5 89.33 Induction Kanau 1 3154 86.1 27.5 Temperature Survey Kanau 1 3154 82.2 11.5 CN-FD Kanau 1 3481 91 21.0 93.48 Temperature Survey Kanau 1 3484 81.6 6.0 Induction Kanau 1 3484 83.9 13.0 CN-FD Komewu 2 545 35.6 Not Rec Temp log Komewu 2 1061 42.2 Not Rec Section Gauge Komewu 2 1064 42.2 Not Rec Electrical Komewu 2 1675 58.9 Not Rec Temp log Komewu 2 1877 61.1 Not Rec Microcaliper Komewu 2 1962 58.9 Not Rec Laterolog Komewu 2 1963 58.9 Not Rec Electrical Komewu 2 1963 58.9 Not Rec Deviation Komewu 2 2861 81.1 Not Rec Laterolog Komewu 2 2861 81.1 Not Rec Electrical Komewu 2 3000 87.8 9/4/58 1:00 9/4/58 21:30 20.5 Temp Komewu 2 3033 84.4 Not Rec Neutron Komewu 2 3038 84.4 Not Rec Electrical North Paibuna 1 1798 46 North Paibuna 1 1798 46 North Paibuna 1 1798 54 North Paibuna 1 1799 54 North Paibuna 1 3366 82 North Paibuna 1 3366 82 North Paibuna 1 3715 101 North Paibuna 1 3715 101 North Paibuna 1 3962 105 5 9.5 113 North Paibuna 1 3962 107 12.67 North Paibuna 1 3963 107 North Paibuna 1 3963 112 North Paibuna 1 4089 108 5 9.65 137 North Paibuna 1 4089 118 15.75 North Paibuna 1 4089 118 North Paibuna 1 4090 135 North Paibuna 1 4276 118 5 12.27 North Paibuna 1 4276 125 21.67 136 North Paibuna 1 4276 127 27 North Paibuna 1 4277 127 North Paibuna 1 4277 135

* Time Since Circulation Yellow boxed range above shows t = Circulation Time range of values used to derive corrected temperature

Source of Temperature Data CNODC (1996) Brereton (1976) Sticpewith (1958) Sante Fe Limited (1994) APPENDIX 9.5: Data Used in Basin Modelling 324 Stratigraphy Table for Basin Models (Chapter 5) Age (Ma)* KANAU 1 OMATI TROUGH 1 OMATI TROUGH 2 Era/Orubadi 5 0 0 L Miocene Hiatus 9 Darai 24 505 321 428 Oligocene hiatus 44 Coral Sea Rift 60 EROSION VARIES - EROSION VARIES - 1500 Upper Ieru A 90 SEE TEXT SEE TEXT -1500 Upper Ieru 97.5 505 2160 3014 Bawia 107 810 2182 3023.5 Juha 127.5 980 2273 3045 Alene 138 1163 2413 3245 Toro 144 1300 2615 3251 Upper Imburu 146.5 1390 2688 3351 Hedinia-Iagifu 149 1520 2810 3517 Lower Imburu 155 1700 2989 3697 Barikewa (Top Koi Iange) 160 1895 3193 3909 Cannel Coal 170 NA 3493 3919 Magobu CM 182 2300 3593 3931 Triassic 210 3295 4192 5264 Basement 230 3795 5344 5365

Bold = From Seismic *Age is Harland et al (1990) NA = Not applicable Age (Ma)* NORTH PAIBUNA 1 Modern Uplift 0.5 -10 Era 3.5 Orubadi 5 537.2 L. Miocene Hiatus 9 Darai Upper 13 1757 Darai Lower 24 653 Oligocene Hiatus 36 Mendi 44 97 Upper Ieru 97.5 Lower Ieru Undiff 127.5 260 Alene 138 48 Toro 144 162 Digimu/Upper Imburu 146 103 Hedinia 146.5 33 Iagifu 149 94 Lower Imburu 155 396 U. Barikewa-Koi-Iange 158 200 Lower Barikewa 160 240 325

9.6 Basin Modelling – Definition of Terms

Vitrinite Reflectance (Vr) – Vr is the most widely accepted indicator of thermal maturity. This term, which developed out of coal rank studies, refers to the relationship where a higher reflectance implies the coal is of a higher rank and thus has been raised to a higher temperature, or buried for a longer time (Beardsmore and Cull, 2001). The algorithm was quantified by two key authors (Lopatin 1971, 1976) and Waples (1980). The method now widely adopted for modelling Vr is Sweeney and Burnham (1990) which developed out of the Lawrence Livermore National Laboratory from detailed studies of Vr kinetics. The data results in numerical values from reflectance, calibrated in the range 0.3 < Ro < 4.5%. Note that Vr (often quoted as Rv max) normally refers to the maximum reflectance measured under oil for a specific wavelength of light but is a slow method since it requires a full rotation of the microscope stage. Ro (mean) which refers to mean random reflectance of an average series of grains is faster but less precise. The relationship between these two different measurements was given by Ting (1978) and expressed as:

Rv max = Ro(%) x 1.066

Several issues surrounding the reliability of this method include the need for the presence of vitrinite in the sample, as well as the experience of the operator in distinguishing vitrinite from other macerals (Beardsmore and Cull, 2001). In addition, variation in chemical characteristics from one vitrinite to another can occur, which has lead to the following maturity measurement to overcome this:

Fluorescence Alteration of Multiple Macerals (FAMM®) - This technique was developed by Wilkins et al. (1992). The key issue this measurement addresses is that vitrinite is derived from many different sources. The most fundamental from a geological standpoint is that the reflectance of vitrinite of marine origin is often lower than for a thermally equivalent terrestrial vitrinite. This is related to the perhydrous nature of marine influenced vitrinite, which leads to what is known as vitrinite reflectance surpression. The method overcomes these problems by measuring the fluorescence emission in response to a laser beam. This measurement is made on a single sample and the beam is focused at all maceral types in the sample. The data are plotted on log-log axes and a best fit polynomial is fitted to the data, where the “normal” value can be read off, termed as Vitrinite Reflectance Equivalent (VrEq).

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Beardsmore and Cull (2001) state that FAMM has many advantages such as the ability to work with samples from different origins and the use of all macerals which removes the subjective nature of conventional Vr measurements. The measurements works well on suppressed samples up until ~0.9 Vr beyond which vitrinite must be singled out and VrEq estimated directly from the fluoresence alteration ratio (Wilkins et al. 1992).

The existence of vitrinite suppression on Australia’s NW Shelf has been well documented (eg Kaiko and Tingate, 1996) Hence this presents the possibility that for similar coeval PNG sediments may also suffer from this phenomenon. Lund et al. (1998) used this approach in their basin modelling.

Temperature at Maximum S2 (TMax): TMax, a term earlier defined in Chapter 4 can also be used a maturity parameter when converted to Ro by using the formula: Ro (calculated) = (0.0180) x (Tmax) - 7.16

The concept was developed by Jarvi et al. (2001) and was based on low sulfur Type II and Type III kerogens. Peters et al. (2005) suggest that use of the formula is not recommended for Type I kerogens and not for very low or high maturity samples (Tmax<4200C or >5000C) or when S2 is less than 0.5mg HC/g rock. They also recommend that due to various factors such as organic matter types, conclusions from Tmax should be supported by other geochemical measurements.

Apatite Fission Track Analysis (AFTA): AFTA is a unique thermal history tool since it is the only measurement that can define the ‘timing’ of a past thermal event. Those methods discussed above have no information about the time temperature path they took to reach their current thermal state.

The following overview on fission track analysis is a synthesis taken from Hegarty (1998). Fission track analysis relates to the assessment of radiation damage trails within detrital apatite grains in sandstones. Apatites are examined since they typically form a common detrital constituent of most sandstones. Each fission track is created by spontaneous fission of a single uranium atom, with tracks forming continuously through time. Once formed the tracks shrink in length at a temperature dependant rate, and can be fully healed or annealed if the rock is buried to temperatures of ~1100C, depending on the heating rate and composition. Hence the length of a track is determined by the maximum paleotemperature since that track formed and the

327 number of tracks provides a measure of time over which tracks accumulated. It is this concept that underpins AFTA. For example apatites that have remained at near surface temperatures have characteristically narrow distribution of ~16μm with more complex length histories resulting in more complex length distributions. An example of three styles of burial history and their resultant fission track distributions are given in the following figure.

Fission Track distributions for different burial histories (Hegarty 1998)

A NOTE: This figure/table/image has been removed

to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

A key limitation of AFTA data is the need to understand the chlorine content. Original studies used the Durango apatite, Mexico, as a typical apatite (Sieber 1986). However, it has since been has been shown that the fission track annealing rate varies with the chemical composition of the host apatite (Green et al. 1985, 1986) with several studies demonstrating significant variation from the standard (eg Otway basin sediments have chlorine rich apatites, Green et al. 1986). Modern studies now consider the measurement of chlorine contents as a necessity and routine part of AFTA (Beardsmore and Cull, 2001)

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Temperature Correction of Bottom Hole Temperatures – Horner Plots

During the drilling of a typical exploration well, a BHT (Bottom Hole Temperature) measurement is routinely measured during the acquisition of wireline logs. These thermometers measure maximum temperatures experienced. If more than one BHT measurement is taken at the same depth then it is possible to correct these values back to a virgin temperature of the rock. These measurements typically never read the true temperature of the rock due to thermal disturbance and/or invasion that is produced from sinking the well, particularly the flow of drilling mud. The most common approach in correcting borehole temperatures is to use a method known as a horner plot, developed by Horner (1951) for pressure build up tests and adopted for temperature corrections by Lachenbruch and Brewer (1959). The parameters required include: T (the BHT), T = time between when circulation stopped and measurement of T, tc = time elapsed between cessation of drilling and cessation of fluid circulation. These terms can be applied to the equation ln[1+(tc/T)] and plotted versus T, a plot (as shown in the following figure) can derive the virgin rock temperature (VRT) by drawing a line through the points. Correction of BHT temperatures in this thesis will use this method which is performed within Basin Mod 1D.

Example of a Horner Plot and derivation of the virgin temperature (from Di Primio et al (2005)

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Steady State versus Transient Regime (from Bordenave 1993 pp 422 )

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Steady State versus Transient Regime (from Bordenave 1993 pp 422 )

“In the steady state regime, the conductive heat flow is constant from the bottom to the top of the sedimentary column, unless lateral heat transfer (by convection or because of rapid lateral variation on conductivity) or sediment radioactivity is significant. In such cases the local geothermal gradient is inversely related to conductivity ie it is lower in good conductivity rocks (eg salt) and higher in poor conductivity rocks such as shales (as a consequence of conductivity variations with depth, the real temperature profile is often far from a straight line, which would be the case with a constant geothermal gradient.

The steady state regime is often a good approximation, but transient effects appear for rates of sedimentation or erosion in excess of 100m/Ma. If sedimentation is rapid, part of the heat flow coming from the basement is spent in heating the newly deposited sediments that are at surface temperatures, so that the surface heat flow is lower than the bottom heat flow. The reverse occurs in the case of rapid erosions”

Rifting Heat Flow (from Basin Model 1D manual, Platte River Associates 2006) “Rifting causes significant perturbations in the thermal history. The details of rifting heat flow are far from well understood and there is no universally accepted rifting heat flow model. Several different approaches have been put forth: McKenzie uniform stretching model, Royden dike intrusion model, Royden two-layered extensional model, Sleep thermal expansion model, Falvey deep crustal metamorphism model, to name a few. BasinMod offers a rifting heat flow option that is a simplification of the Jarvis and McKenzie finite rifting model (1980) which, certainly not without skeptics, is probably the most widely accepted theory (Allen and Allen, 1990), as well as somewhat less complicated to implement. All prevalent rifting heat flow models seem to concur that rifting involves two phases:

1.Rifting phase - stretching, thinning and faulting of the crust accompanied by increased heat flow due to thinning of crust and upwelling of asthenosphere.

2.Subsidence phase - post-rift exponential thermal decay due to re-establishment of thermal equilibrium in mantle lithosphere and asthenosphere.

Rifting scenarios seem to range from instantaneous rifting followed by a sudden increase in heat flux to a maximum followed by exponential decay… At the other end of the spectrum is the rift scenario where stretching occurs over a long period of time during which heat is dissipated. In this finite rift model, the peak heat flow is less at the end of the rifting, or stretching, phase and the subsequent thermal decay curve associated with subsidence is closer to linear than exponential”

APPENDIX 9.7: North Paibuna Calibration– establishment of Foreland Regional Heat Flow

Maturity VR LLNL (%Ro) 0.1 1 Fm 0 Orubadi Temperature Heat flow Maturity VR LLNL 1000 BHT 2 %Ro 42mW/m Darai Upper TMAX FAMM 2000 Corrected Temperature

Darai Lower

3000 Mendi

Depth Subsea (m) Lower Ieru Undiff Alene Toro Digimu/Upper Imburu IagifuHedinia Good match to present 4000 Lower Imburu U. Barikewa-Koi-Iange day ‘ corrected’ temperatures Lower Barikewa 1 and FAMM data

5000 t = 0 140 120 100 80 60 40 20 Maturity VR LLNL (%Ro) 0.1 Temperature (C) 1 Fm 0

Orubadi Heat flow Heat flow reduced considerably to 1000 15mW/m2 match Vr data. This results in a Darai Upper considerable mismatch to the predicted

2000 temperature profile and uses a heat flow which is unrealistically low Darai Lower

3000 Mendi

Depth Subsea(m) Lower Ieru Undiff Alene Toro Digimu/Upper Imburu IagifuHedinia

4000 Lower Imburu U. Barikewa-Koi-Iange

1 Lower Barikewa 330 5000 t = 0 140 120 100 80 60 40 20 Temperature (C) 331

9.8 Thicknesses from the NW Papuan Basin

A NOTE: This figure/table/image has been removed to comply with copyright regulations. It is included in the print copy of the thesis held by the University of Adelaide Library.

Data courtesy of Oil Search Limited stratigraphic database

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9.7 – Publications and Presentations

1) A poster incorporating some early ideas from this thesis was submitted to the PESA Eastern Australasian Basins Symposium III Sydney, 14 – 17 September, 2008

Poster Title:

LACUSTRINE PETROLEUM SYSTEMS IN THE PAPUA NEW GUINEA FORELAND by S. Wood, H. Volk, N. Sherwood and C. J. Boreham

The abstract for this poster is included on the next page.

The results were presented to a small group during the presentation session by Stephen Wood

Note that this poster won ‘best poster’ prize at the conference.

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S. Wood, H. Volk, N. Sherwood and C. J. Boreham (2008) Lacustrine petroleum systems in the Papua New Guinea. In: PESA Eastern Australasian Basins Symposium III, Sydney, 14-17 September, 2008.

NOTE: This publication is included in the print copy of the thesis held in the University of Adelaide Library.