AN EVALUATION OF PETROLEUM

SYSTEMS WITHIN THE BILLILUNA

SUB-BASIN AND ADJACENT
STRUCTURAL REGIONS,
NORTHEASTERN CANNING BASIN

by

PETER JAMES HAWKE

A thesis submitted to the University of Adelaide in partial fulfilment for the Degree of
MASTER OF PHILOSOPHY (PETROLEUM GEOSCIENCE)

Australian School of Petroleum

The University of Adelaide
Australia
September, 2017
 Abstract
The intracratonic Canning Basin, Western Australia, contains three Palaeozoic petroleum
systems (The Larapintine L2, Ordovician – Silurian; The Larapintine L3 and L4, Devonian –
early Carboniferous; and the Gondwannan G1 and G2, late Carboniferous – Permian). The
NW-SE oriented Fitzroy Trough and Gregory Sub-basin (separated only by the Jones Arch)
are the regional source kitchens, and shelfal positions updip from the Fitzroy Trough are oil
productive from the Larapintine L3 and L4 petroleum system in fields such as Blina and
Sundown, and more recently the Ungani field. A lack of exploration drilling in comparable
shelfal positions updip from the Gregory Sub-basin is perceived to account for the absence of
similar hydrocarbon discoveries. Through the use of a newly reprocessed regional 2D seismic
grid and an enhanced stratigraphic framework produced from well correlations and
palaeogeographic reconstructions, it is demonstrated that elements of all of the three petroleum
systems are present on the Betty Terrace, Balgo Terrace and within the Billiluna Sub-basin of
the northeast Canning Basin. Good quality reservoirs such as the late Devonian Knobby
Sandstone (averaging 20.6% porosity and 567 mD permeability), the Tournaisian Laurel
Formation (featuring up to 22% porosity), members of Visean-Sakmarian Grant Group (up to
18.5% porosity and 1015 mD permeability), and the Sakmarian Poole Sandstone (in excess of
20% porosity) were intersected in well bores, tied to 2D seismic data and mapped throughout
the study area. Stratigraphy with regional seal potential (including Laurel Formation shales,
the Grant Group B member, shales of the mid-Carboniferous Anderson Formation and the
Permian Noonkanbah Formation) are determined from exploration wells to be present across
the project area. A regional geochemical source rock assessment indicates that the Permian
Noonkanbah Formation is organically rich (2.17% TOC), and that the pre-Carboniferous
stratigraphy (members of Anderson Formation, 0.14% TOC; Laurel Formation, 0.56% TOC;
Devonian Gogo Formation, 0.14% TOC; and the Silurian Carribuddy Group Bongabinni
Member, 0.13% TOC) are organically lean. The Llanvirn Goldwyer Formation (1.5% TOC) is
regionally organically rich, though is unlikely to be found in a basinal palaeogeographic setting
within the study area. Thermal maturity was investigated using 1D and 2D petroleum systems
models, which determined that (1) the Noonkanbah Formation is immature, and (2) that the
pre-Carboniferous source rocks are mature for hydrocarbon generation, reaching peak thermal
maturity in the Triassic (200 Ma). 4-way dip closures, 3-way fault bound dip closures, and
horst block trapping configurations were identified on 2D seismic, but an analysis of

i
exploratory dry holes indicates that structural closures that developed in the Carboniferous
were likely reconfigured during the Triassic Fitzroy Movement, where hydrocarbons leaked
out of traps. Modelling indicates that the timing of hydrocarbon generation occurred over two
main periods; the Siluro-Devonian (436 Ma – 350 Ma) and in the Triassic (220 Ma – 192 Ma).
It is designated that exploration within all three petroleum systems in the project area is
considered to be high-risk. It is concluded from this study that the Larapintine L3 and L4
petroleum system represents the best prospectivity in positions nearest the Gregory Sub-basin.

ii
 Statement of Confidentiality
A confidentiality agreement, between Pangaea Resources Pty Ltd and The University of
Adelaide, embargos the public inspection or borrowing of this thesis until UIF
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 Statement by the Author
I certify that this work contains no material which has been accepted for the award of any
other degree or diploma in my name in any university or tertiary institution and, to the best of
my knowledge and belief, contains no material previously published or written by another
person, except where due reference has been made in the text. In addition, I certify that no
part of this work will, in the future, be used in a submission in my name for any other degree
or diploma in any university or other tertiary institution without the prior approval of the
University of Adelaide and where applicable, any partner institution responsible for the joint
award of this degree.

Subject to a two year confidentiality period, as stated on page iii, I give consent to the
following:

That this copy of my thesis, when deposited in the University Library, be made
available for loan and photocopying, subject to the provisions of the Copyright Act
1968.
That the digital version of my thesis may be made available on the internet, via the
University’s digital research repository, the Library Search and also through internet
search engines, unless permission has been granted by the University to restrict
access for a period of time.

Peter J. Hawke

iv
 Acknowledgements
An enormous amount of thanks goes to my primary supervisor Dr. Simon Holford. Amongst
his extremely busy schedule he guided the project through the ups-and-downs of supervisor
changes and numerous years of work towards the finish line. I thank him for his direction and
guidance, support, encouragement, and for putting up with me as a remote candidate.

Secondly, a huge amount of thanks goes to my external supervisor Dr. Douglas Hamilton at
Pangaea. Doug stepped up through his demanding calendar to guide me through to the
culmination of this study. I thank him graciously for his time, particularly as I neared end of
the journey, for his efforts and attention to detail, and providing valuable direction.

There are numerous other key individuals to whom I owe thanks. Firstly, to Mr. Andrew R.
Scott at Altuda Energy Corporation, who was a key person that helped me get this project off
the ground. His support and encouragement is greatly appreciated. It not for Andrew Scott’s
efforts and initial supervisory role in the early stages of this study, this project would likely
not have commenced. Dr. Mark Tingay also played a significant initial supervisory role, and
for that I say thanks, especially for taking me on as a remote student. Mr. Andy Mitchell and
Dr. Kathryn Amos were key players in the establishment of my candidature at the ASP, and I
thank Andy for his guidance as the ASP Postgraduate Research Coordinator. The ASP family
is a great team to work with, and I thank them for being so accommodating.

Secondly, I owe an enormous amount of thanks to Pangaea and its past and current executive
team members. Without their approval, support, encouragement and guidance this project
would be non-existent. This project owes an enormous amount of gratitude to Pangaea for the
provision of newly reprocessed 2D seismic data – a key ingredient in this study. Many people
at Pangaea helped contribute to this thesis, either directly in research guidance or indirectly
through support, and for that I say thanks. Special recognition go to Ms. Lisa Miller for her
guidance at various stages of the project.

Many thanks to my fellow students at the ASP for providing support during my initial
candidature period in Adelaide. Thanks to the staff and fellow postgrads at Kathleen Lumley
College who settled me into Adelaide life during my early living-in period. Thanks to
Professor Steve Begg for accommodating me in his excellent Decision Making and Risk
Analysis course (perhaps one of the best courses at the ASP!). And generally, thanks to the

v
city of Adelaide for being an awesome place in which to study. The ASP is set apart by
having an excellent home ground!

I cannot forget to mention my friends and family in Sydney. I apologise for my unavailability
at various social gatherings. My parents and brother were instrumental in pushing me on this
journey. A very special thanks goes to Ms. Jesamina Barbaro, whom without her
understanding, support, patience and delicious Italian cooking I would not have reached the
finish line.

Now to those who will likely never see this. Thanks to Spotify and their endless list of
musicians who encouraged me through the endless Friday and Saturday evenings when
approaching the end of this project. So here’s to Daft Punk, Artic Monkeys, Cold Play,
Deadmau5, Empire of the Sun, Fleetwood Mac, Galantis and many other excellent producers
for their contribution. Thanks also goes to my coffee percolator for the late night
encouragement.

vi
List of Contents

Abstract i
Statement of Confidentiality iii
Statement by the Author iv
Acknowledgements v
List of Contents vii

Chapter 1 - Introduction 1
1.1 Definition of the Problem 1
1.2 Geography 3
1.3 Geological Overview 4
1.4 Key Project Contributions 5
1.5 The Study Area 6
1.6 Research Questions 6
1.7 Project Aim, Objectives and Methodology 7

Chapter 2 - Geological Overview 9

2.1 Regional Geology 9
2.2 Geological Division of the Study Area 10
2.3 Geological History 11
2.3.1 Archean 11
2.3.2 Ordovician to Silurian 12
2.3.3 Devonian to Mid-Carboniferous 12
2.3.4 Late Carboniferous to Permian 16
2.3.5 Triassic 16
2.3.6 Jurassic and Younger 16
2.4 Petroleum Systems 18
2.4.1 Petroleum Systems in the Canning Basin 18
2.5 Source Rock Potential - Review of Wulff (1987) 20
2.6 Previous Exploration 21
2.7 Production 26

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Chapter 3 - Data Availability and Quality 29
3.1 Well Data 29
3.2 Well Data Quality 31
3.3 Seismic Data 35
3.3.1 Improvements to Seismic Data 36
3.3.2 Seismic Data Quality 38

Chapter 4 - Stratigraphic Framework 41

4.1 Pre-Ordovician 42
4.1.1 Precambrian 42
4.1.2 Cambrian 42
4.2 Early to Middle Ordovician 43
4.2.1 Nambeet Formation 46
4.2.2 Willara Formation 46
4.2.3 Goldwyer Formation 47
4.2.4 Nita Formation 49
4.3 Late Ordovician 55
4.3.1 Carribuddy Group – Bongabinni Member 56
4.3.2 Carribuddy Group – Minjoo Marker Bed 56
4.3.3 Carribuddy Group – Nibil Member 57
4.4 Early to Middle Silurian 61
4.4.1 Worral Formation 61
4.5 Late Silurian to Devonian 63
4.5.1 Poulton Formation 63
4.5.2 Devonian Conglomerate 64
4.5.3 Bungle Gap Limestone 67
4.5.4 Lennard River Group 69
4.5.5 Gogo Formation 71
4.5.6 Virgin Hills Formation 73
4.5.7 Knobby Sandstone 75
4.5.8 Luluigui Formation 84
4.6 Carboniferous 87
4.6.1 Fairfield Group – Laurel Formation 87
4.6.2 Anderson Formation 96
4.7 Permo-Carboniferous 107
4.7.1 Grant Group and Reeves Formation 107

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 4.8 Permian 120
4.8.1 Poole Sandstone 120
4.8.2 Noonkanbah Formation 126
4.8.3 Liveringa Group 131
4.8.4 Liveringa Group – Condren Sandstone 131
4.8.5 Liveringa Group – Lightjack Formation 131
4.8.6 Millyit Sandstone 134
4.9 Triassic and Younger 136
4.9.1 Blina Shale 136
4.10 Summary of Results 137
4.11 Well Correlation 143

Chapter 5 - Seismic Interpretation 147

5.1 The Use of Seismic in this Project 147
5.2 Well-To-Seismic Ties: 149
5.2.1 Synthetic Generation: 150
5.2.2 Effect of Well Bore Rugosity on Synthetic Seismograms: 151
5.2.3 Synthetic Seismograms: 151
5.3 Interpretation of Horizons: 156
5.3.1 Near Top Meda Transpression 158
5.3.2 Near Top Laurel Carbonate 160
5.3.3 Near Top Grant Group 161
5.3.4 Near Top Knobby Sandstone. 162
5.3.5 Near Top Poole Sandstone 162
5.3.6 Near Top Noonkanbah Formation 163
5.3.7 Near Top Ordovician 163
5.3.8 Near Top Basement 165
5.4 Interpretation of Faults 169
5.4.1 Confidence in Fault Interpretation 169
5.5 Velocity Analysis and Depth Conversion: 171
5.5.1 Dynamic Depth Converter (DDC) 171
5.6 Two-Way-Travel Time Structure and Time-thickness (Isochron) Mapping 174

Chapter 6 - Basin Architecture: Structural Framework 175

6.1 Seismic Interpretation Results 175
6.2 TWT Structure and Isochron Maps 183

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 6.2.1 The Case for a Revised Tectonic Elements Map 183
6.2.2 Northwestern Study Area 185
6.2.3 Southeastern Study Area 187
6.2.4 Structural Lead Identification 192

Chapter 7 - Source Rock Assessment 210

7.1 Introduction 210
7.2 Method and Data 210
7.3 Analytical Techniques and Definitions 211
7.3.1 Definition of a Source Rock 211
7.3.2 Total Organic Carbon 211
7.3.3 Rock Eval Pyrolysis 213
7.3.4 Organic Matter Type 217
7.3.5 Vitrinite Reflectance 220
7.4 Source Rock Geochemistry 221
7.4.1 Candidate Source Rock Intervals 221
7.4.2 Noonkanbah Formation 222
7.4.3 Anderson Formation 228
7.4.4 Laurel Formation 234
7.4.5 Gogo Formation 242
7.4.6 Carribuddy Group – Bongabinni Member 246
7.4.7 Goldwyer Formation 248
7.4.8 Summary of Source Rock Characteristics 257

Chapter 8 - Petroleum Systems Modelling 258

8.1 Introduction 258
8.2 Definition of a Petroleum Systems Model 258
8.2.1 General Structure and Method of a Petroleum Systems Model 259
8.2.2 Structure and Method of Models in the Project Area 262
8.3 Model Locations 262
8.3.1 1D Models 262
8.3.2 2D Models 262
8.4 Data Inputs and Parameters – 1D Models 265
8.4.1 Present-day Model 265
8.4.2 Paleo Geometry 265
8.4.3 Boundary Conditions 272

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 8.4.4 Facies – 1D and 2D models 273
8.4.5 Basal Heat Flow – 1D and 2D Models 275
8.4.6 Calibration – Geothermal Gradients 276
8.5 Data Inputs and Parameters – 2D Models 281
8.5.1 Present-day Model 281
8.5.2 Paleo Geometry 285
8.5.3 Boundary Conditions 286
8.5.4 Facies 287
8.5.5 Calibration 288
8.6 Results 292
8.6.1 Temperature 293
8.6.2 Thermal Maturity 297
8.6.3 Modelling Results – Goldwyer Formation 300
8.6.4 Modelling Results – Bongabinni Member 306
8.6.5 Modelling Results – Gogo Formation 311
8.6.6 Modelling Results – Laurel Formation 316
8.6.7 Modelling Results – Anderson Formation 321
8.6.8 Modelling Results – Noonkanbah Formation 326
8.7 Hydrocarbon Accumulation Analysis 330
8.7.1 Modelling Results 331
8.8 Summary of Results 339

Chapter 9 - Discussion – An Evaluation of Petroleum Systems in the Northeast Canning

Basin 342
9.1 Prospectivity – Are Active Petroleum Systems Present within the Northeast Canning
Basin? 342
9.2 Analysis of Exploratory Tests within the Study Area 346
9.2.1 Lake Betty 1 347
9.2.2 Lanagan 1 348
9.2.3 Ngalti 1 350
9.2.4 Lawford 1 351
9.2.5 Olios 1 353
9.2.6 Bindi 1 355
9.2.7 Kilang Kilang 1 358
9.3 Prospectivity within the Larapintine L2 Petroleum System 360
9.3.1 Source Rocks 360
9.3.2 Reservoir Rocks 363

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 9.3.3 Seals 366
9.3.4 Trap Development 366
9.3.5 Timing and Migration 367
9.3.6 Play-type Targeting, Risks and Remarks 368
9.3.7 Key recommendations 370
9.4 Prospectivity within the Larapintine L3 and L4 Petroleum Systems 371
9.4.1 Source Rocks 371
9.4.2 Reservoir Rocks 375
9.4.3 Seals 376
9.4.4 Trap Development 378
9.4.5 Timing and Migration 378
9.4.6 Simulated Accumulations – 2D Model RB82-28 379
9.4.7 Play-type Targeting, Risks and Remarks 382
9.4.8 Key recommendations 384
9.5 Prospectivity within the Gondwannan G1 and G2 Petroleum System 385
9.5.1 Source Rocks 385
9.5.2 Reservoir Rocks 387
9.5.3 Seals 389
9.5.4 Trap Development 390
9.5.5 Timing and Migration 392
9.5.6 Play-type targeting, risks and remarks 392
9.5.7 Key Recommendations 394

Chapter 10 - Conclusions and Recommendations 396

10.1 Conclusions 396
10.2 Recommendations: 399

References 401
Appendix A 410
Appendix B 414
Appendix C 424
Appendix D 455
Appendix E 461

xii
List of Figures

Figure 1.1. The Regional Canning Basin 2

Figure 1.2. Australian continent with prominent sedimentary basins 3
Figure 1.3. The Canning Basin with regional towns labelled 6
Figure 1.4. Overview of methodology 8
Figure 2.1. The regional Canning Basin. Tectonic elements and regional locations labelled 10
Figure 2.2. Structural features within the Study Area 11
Figure 2.3. Stratigraphic column of the Canning Basin 14
Figure 2.4. Tectonic development of the main Canning Basin elements 15
Figure 2.5. Late Cretaceous sediments are preserved west of Lake Gregory 17
Figure 2.6. Stratigraphic chart with relations to tectonic events, petroleum systems and
selected hydrocarbon occurrences 19
Figure 2.7. Current population of explorers in the Canning Basin 26
Figure 2.8. Regional production in the Canning Basin 28
Figure 3.1. Study area wells datumed on RT elevation 34
Figure 3.2. Seismic grid and well locations 36
Figure 3.3. Example of improvements to seismic data post-reprocessing 37
Figure 3.4. Seismic grid with key regional lines 40
Figure 4.1. Study area in a regional context 43
Figure 4.2. Stratigraphic column of Ordovician and Silurian stratigraphy 44
Figure 4.3. Percival 1 geophysical log 45
Figure 4.4. S Goldwyer Formation correlation 47
Figure 4.5. Lake Havern 1 geophysical log 51
Figure 4.6. Paleogeographic map of the Ordovician 53
Figure 4.7. Paleogeography of the Llanvirnian. 54
Figure 4.8. Ordovician porosity and permeability data 55
Figure 4.9. Percival 1 geophysical log over Siluro-Ordovician section 57
Figure 4.10. Paleogeography of the Late Ordovician to Silurian 59
Figure 4.11. Percival 1 geophysical log over Worral Formation 62
Figure 4.12. Lake Betty 1 geophysical log over Poulton Formation 64
Figure 4.13. Atrax 1 and Selenops 1 geophysical logs over the Devonian Conglomerate 65

xiii
Figure 4.14. Devonian Conglomerate porosity measurements 66
Figure 4.15. Atrax 1 geophysical log over Bungle Gap Limestone 68
Figure 4.16. Bungle Gap Limestone porosity measurements 68
Figure 4.17. Ngalti 1 geophysical log over Lennard River Group 70
Figure 4.18. Selenops 1 geophysical log over Gogo Formation 72
Figure 4.19. Selenops 1 geophysical log over Virgin Hills Formation 74
Figure 4.20. Virgin Hills Formation porosity and permeability measurements 75
Figure 4.21. (Left to right) Atrax 1, Lanagan 1, Olios 1, Ngalti 1 geophysical logs over the
Knobby Sandstone 78
Figure 4.22. Paleogeography of the Late Devonian 81
Figure 4.23. Knobby Sandstone porosity and permeability measurements 82
Figure 4.24. Lake Betty 1 geophysical log over Luluigui Formation 85
Figure 4.25. Geophysical logs over Laurel Formation across project area. 91
Figure 4.26. Kilang Kilang 1 geophysical log 92
Figure 4.27. Paleogeography of the Early Carboniferous 94
Figure 4.28. Laurel Formation porosity measurements 96
Figure 4.29. Geophysical logs over the Anderson Formation. 102
Figure 4.30. Bindi 1 geophysical log. Sequence stratigraphic analysis overlain 104
Figure 4.31 Age of the Grant Group 108
Figure 4.32. Geophysical log definition of the Grant Group across the project area 113
Figure 4.33. Bindi 1 geophysical log 115
Figure 4.34. Palaeogeography of the Visean to Stephanian 116
Figure 4.35. Palaeogeography of the Asselian to Tastubian 117
Figure 4.36. Grant Formation porosity and permeability measurements 119
Figure 4.37. Geophysical logs over Poole Sandstone across project area 122
Figure 4.38. Paleogeography of the Sakmarian 124
Figure 4.39. Geophysical logs over the Noonkanbah Formation across the project area 128
Figure 4.40. Paleography of the Aktastinian to Baigendzhinian 129
Figure 4.41. Geophysical logs over Liveringa Group 132
Figure 4.42. Bindi 1 geophysical log. Sequence stratigraphic analysis overlain 133
Figure 4.43. Bindi 1 geophysical log over Millyit Sandstone 135
Figure 4.44. Dip section A - A' in the northwestern project area 144
Figure 4.45. Dip section B - B' in the southeastern project area 145
Figure 4.46. Strike section C - C' across the project area 146
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Figure 5.1. Distribution of wells ties in project area 149
Figure 5.2. Ngalti 1 synthetic seismogram 153
Figure 5.3. Kilang Kilang 1 synthetic seismogram 154
Figure 5.4. Lanagan 1 synthetic seismogram 155
Figure 5.5. The Meda Transpression Unconformity 159
Figure 5.6. 2D Seismic grid with regional loop ties 165
Figure 5.7. Example of seismic on RB81-6 and westerly dipping reflection events 166
Figure 5.8. Ordovician package used to Lake Haven 1 to the study area 168
Figure 5.9. Time-Depth relationship between wells within the project area 172
Figure 5.10. Schematic illustrating apparent time structures 173
Figure 6.1. Distribution of seismic lines presented in Table 6.1 176
Figure 6.2. Line 82GN-20 demonstrates structural configuration (dip section) in the north
western portion of the study area 177
Figure 6.3. Line 82GN-01 demonstrates structural configuration (dip section) in the mid-
north portion of the study area 178
Figure 6.4. Line 82GE-33 demonstrates structural configuration (strike section) in the
northern portion of the study area 179
Figure 6.5. Line RB81-07 demonstrates structural configuration (dip section) in the north
eastern portion of the study area 180
Figure 6.6. Line RB81-01 demonstrates structural configuration (dip section) in the south
eastern portion of the study area 181
Figure 6.7. Line RB81-10 demonstrates structural configuration (strike section) in the central-
south eastern portion of the study area 182
Figure 6.8. Tectonic divisions provided by GSWA 184
Figure 6.9. Division of the northwestern, central and southeastern study area 184
Figure 6.10. Key structural leads identified from seismic interpretation 194
Figure 6.11. TWT structure on Near Top Noonkanbah Formation 195
Figure 6.12. TWT structure on Near Top Poole Sandstone 196
Figure 6.13. TWT structure on Near Top Grant Group 197
Figure 6.14. TWT structure on Near Top Meda Transpression Unconformity 198
Figure 6.15. TWT structure on Near Top Fairfield Group 199
Figure 6.16. TWT structure on Near Top Devonian 200
Figure 6.17. TWT structure on Near Top Ordovician 201
Figure 6.18. TWT structure on Near Top Basement 202
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Figure 6.19. Noonkanbah Formation isochron 203
Figure 6.20. Poole Sandstone isochron 204
Figure 6.21. Grant Group isochron 205
Figure 6.22 Anderson Formation isochron 206
Figure 6.23. Fairfield Group isochron 207
Figure 6.24. Siluro-Devonian isochron 208
Figure 6.25. Ordovician isochron 209
Figure 7.1. Summary of the outcomes and useful calculations related to source rock analysis
by Rock Eval Pyrolysis 214
Figure 7.2. Kerogen type classification from H/C v O/C ratios and HI v Tmax 219
Figure 7.3. Noonkanbah Formation regional TOC 223
Figure 7.4. Noonkanbah Formation remaining generative potential (S2) 224
Figure 7.5. Noonkanbah Formation kerogen type 225
Figure 7.6. Noonkanbah Formation regional Tmax 227
Figure 7.7 Anderson Formation regional TOC 229
Figure 7.8 The Anderson Formation kerogen typing 232
Figure 7.9. Anderson Formation Tmax 233
Figure 7.10. Laurel Formation regional TOC 235
Figure 7.11. Laurel Formation regional TOC and Rock Eval Pyrolysis 236
Figure 7.12. Laurel Formation Study area TOC 237
Figure 7.13. Laurel Formation kerogen classification 240
Figure 7.14. Laurel Formation Tmax measurements by tectonic province 241
Figure 7.15. Gogo Formation TOC and pyrolysis measurements 243
Figure 7.16. Gogo Formation regional pyrolysis 245
Figure 7.17. Gogo Formation regional Tmax 245
Figure 7.18. Bongabinni Member regional TOC 247
Figure 7.19. Goldwyer Formation regional TOC 249
Figure 7.20. Goldwyer Formation regional TOC 250
Figure 7.21. Goldwyer formation kerogen typing by OI vs HI crossplot 252
Figure 7.22. Goldwyer Formation regional Tmax 253
Figure 7.23. Paleogeographic position of continents in the Ordovician 255
Figure 8.1. Illustration of a digital petroleum systems model workflow 260
Figure 8.2. Summary illustration of a PetroMod petroleum systems model workflow 261
Figure 8.3. Location of wells and seismic lines used for 1D and 2D modeling 264
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Figure 8.4. Average paleo-water depth used in 1D models 267
Figure 8.5. Location of 1D models 271
Figure 8.6. Mean surface temperatures used to configure PetroMod SWIT 273
Figure 8.7. Temperature calibration for 1D models 279
Figure 8.8. Vitrinite reflectance calibration for 1D models 280
Figure 8.9. PetroMod age assignment input parameters used in 2D model RB81-7 284
Figure 8.10. Average paleo-water depth for 2D models 286
Figure 8.11. SWIT curve for 2D models 287
Figure 8.12. VR calibration for 2D models 290
Figure 8.13. Porosity calibration for 2D models 291
Figure 8.14. Location of 1D and 2D models 292
Figure 8.15. Well burial history results for Lake Betty, 1 Olios 1, and Bindi 1 294
Figure 8.16. Well burial history results for Kilang Kilang 1 and Ngalti 1 295
Figure 8.17. Present day RB81-7 model with pre-grid faults 296
Figure 8.18. Maturity profiles for 1D models in the Gregory Sub-basin 297
Figure 8.19. 2D model RB81-7 maturity of sediments across the study area 299
Figure 8.20. Goldwyer Formation maturity vs time diagram 301
Figure 8.21. Goldwyer Formation transformation ratio vs time diagram 302
Figure 8.22. Goldwyer Formation generation rate vs time diagram 304
Figure 8.23. Goldwyer Formation expulsion rate vs time diagram 305
Figure 8.24. Bongabinni Member maturity vs time diagram 307
Figure 8.25. Bongabinni Member transformation ratio vs time diagram 308
Figure 8.26. Bongabinni Member generation rate vs time diagram 309
Figure 8.27. Bongabinni Member expulsion rate vs time diagram 310
Figure 8.28. Gogo Formation maturity vs time diagram 312
Figure 8.29. Gogo Formation transformation ratio vs time diagram 313
Figure 8.30. Gogo Formation generation rate vs time diagram 314
Figure 8.31. Gogo Formation expulsion rate vs time diagram 315
Figure 8.32. Laurel Formation maturity vs time diagram 316
Figure 8.33. Laurel Formation transformation ratio vs time diagram 317
Figure 8.34. Laurel Formation generation rate vs time diagram 319
Figure 8.35. Laurel Formation expulsion rate vs time diagram 320
Figure 8.36. Anderson Formation maturity vs time diagram 322
Figure 8.37. Anderson Formation transformation ratio vs time diagram 323
xvii
Figure 8.38. Anderson Formation generation rate vs time diagram 324
Figure 8.39. Anderson Formation expulsion rate vs time diagram 325
Figure 8.40. Noonkanbah Formation maturity vs time diagram 326
Figure 8.41. Noonkanbah Formation transformation ratio vs time diagram 327
Figure 8.42. Noonkanbah Formation generation rate vs time diagram 328
Figure 8.43. Noonkanbah Formation expulsion rate vs time diagram 329
Figure 8.44. RB81-7 2D model present day accumilation analysis 332
Figure 8.45. Arbitrary line 82GN-20 2D model accumilation analysis 334
Figure 8.46. RB82-28 present day 2D model accumilation analysis 336
Figure 8.47. RB81-10 present day 2D model accumilation analysis 338
Figure 9.1. The Lake Betty 1 structure on 2D seismic 348
Figure 9.2. The Lanagan 1 structure on 2D seismic 349
Figure 9.3. The Ngalti 1 structure on 2D seismic 350
Figure 9.4. The Lawford 1 structure on 2D seismic 352
Figure 9.5. The Olios 1 structure on 2D seismic 354
Figure 9.6. The Bindi 1 structure on 2D seismic 356
Figure 9.7. The Kilang Kilang 1 structure on 2D seismic 358
Figure 9.8. Palaeogeography of the Llanvirnian (Ordovician) 362
Figure 9.9. Stratigraphic column of Ordovician and Silurian rocks 364
Figure 9.10. Burial history diagram of the RB81-7 Gregory Sub-basin pseudo well 367
Figure 9.11. Petroleum system elements diagram for plays in the Larapintine L2 petroleum
system 368
Figure 9.12. Play-type targets within the Larapintine L2 petroleum system 370
Figure 9.13. Palaeogeography of the early Carboniferous 373
Figure 9.14. Petroleum system elements diagram for plays within the Larapintine L3 and L4
petroleum system 379
Figure 9.15. 2D model RB82-28 accumilation analysis 381
Figure 9.16. Play-type targets within the Larapintine L3 and L4 petroleum system 384
Figure 9.17. Palaeogeography of the mid to late Carboniferous 388
Figure 9.18. Palaeogeography of the early Permian 389
Figure 9.19. Burial history diagram of the RB82-28 Betty Terrace pseudo well 391
Figure 9.20. Critical moment diagram for plays within the Gondwannan G1 and G2
petroleum system 392
Figure 9.21. Play-type targets within the Gondwannan G1 and G2 petroleum system 394
xviii
List of Tables

Table 2.1. Hydrocarbon occurrences in the Canning Basi 23

Table 2.2. Hydrocarbon plays in the Canning Basin 24
Table 2.3. Production within the Canning Basin as of 1993 27
Table 3.1. Summary of the nine study area wells used in this project 30
Table 3.2. Quality control applied to study area wells 32
Table 3.3. Seismic surveys utilised in this project 35
Table 4.1. Ngalti 1 porosity measurements 83
Table 4.2. Summary of Laurel Formation intersections within project area 88
Table 4.3. Kilang Kilang 1 porosity data for the Laurel Formation 95
Table 4.4. Age of the Anderson Formation 97
Table 4.5. Anderson Formation porosity measurements 105
Table 4.6. Grant Group porosity measurements 118
Table 4.7 Poole Sandstone porosity measurements 125
Table 4.8. Noonkanbah Formation porosity measurements 130
Table 4.9. Liveringa Group porosity measurements 134
Table 4.10 Summary of lithology, characteristics and reservoir properties for stratigraphy in
this study. 142
Table 5.1. Well ties in this study 149
Table 5.2. Examples of synthetic seismogram parameters used to perform synthetic ties in
this project 150
Table 5.3. Major seismic stratigraphic surfaces and their sequence characteristics 157
Table 6.1. 2D seismic lines presented to demonstrate seismic interpretation and geologic
features with the project area 176
Table 6.2. Summary of key structural leads identified from seismic interpretation 193
Table 7.1. Petroleum potential classification based on organic matter TOC and Rock Eval
Pyrolysis 212
Table 7.2. A guide on making interpretations from TOC and Rock Eval Pyrolysis
measurements 215
Table 7.3. Kerogen type and thermal maturity hydrocarbon products from Rock Eval
Pyrolysis measurements 216

xix
Table 7.4. Relative quantity of generated hydrocarbons from HI 216
Table 7.5. Generative potential classification based on S) 217
Table 7.6. Kerogen type classification 217
Table 7.7. Definition of hydrocarbon product windows from vitrinite reflectance 220
Table 7.8. Anderson Formation pyrolysis and TOC measurements within study area 230
Table 7.9. Anderson Formation pyrolysis and TOC measurements at Wamac 1 231
Table 7.10. Goldwyer Formation regional TOC and Rock Eval Pyrolysis seperated by
tectonic region 249
Table 7.11. Goldwyer Formation regional TOC and pyrolysis measurements separated by
WMC subdivision 251
Table 7.12. Summary of source rock characteristics 257
Table 8.1. Well name and total depth summary of 1D models in this project 262
Table 8.2. Summary of seismic lines upon which 2D models were constructed 263
Table 8.3. Summary and explanation of paleo-water depths used in petroleum systems
models 266
Table 8.4. Summary of lithology components for stratigraphic formations 274
Table 8.5. Petrophysical properties for common lithologies in PetroMod 275
Table 8.6. Present-day heat flow for wells in the study area 276
Table 8.7. Mean surface temperature of project area and bottom-hole static temperatures for
wells in the project area. 277
Table 8.8. Explanation of header terms used in PetroMod age assignment 284
Table 8.9. Summary of maturity on the top and base of key stratigraphic markers in the
project area, from 1D models 298
Table 8.10. Summary of modelling results for the Gondwannan G1 and Larapintine L3 and
L4 petroleum systems 340
Table 8.11. Summary of results for the Larapintine L2 petroleum system 341
Table 9.1. Summary of exploratory tests within the project area, highlighting reasons for
failure 346

xx
 Chapter 1 - Introduction

1. Introduction

1.1 Definition of the Problem

The intracratonic Canning Basin contains sediments belonging to three major Palaeozoic
petroleum super systems: Ordovician – Silurian (Larapintine L2), Devonian – early
Carboniferous (Larapintine L3 and L4) and late Carboniferous – Permian (Gondwannan G1
and G2) (Bradshaw et al, 1994). Carlsen and Ghori, (2005) state that Palaeozoic aged
petroleum systems account for 25% of recoverable global hydrocarbons. In 2013, the U.S.
Energy Information Administration evaluated that the Canning Basin may contain 235 Tcf of
recoverable gas in Goldwyer Formation shales and 9.8 billion barrels of oil (EIA, 2013).
Thus, there is an anticipation amongst petroleum explorers that the Canning Basin should
contain significant recoverable petroleum resources.

Contrary to the above proposition, the Canning Basin mainly produces oil from six small
fields (Table 2.3), the largest of which – the Blina Field, is located on the Lennard Shelf
nearby to other producing areas (Figure 1.1). Exploration activity currently accounts for
approximately 300 wells drilled in the basin, and approximately 90,000 line kilometres of 2D
seismic acquisition (Figure 1.1). Carlsen and Ghori (2005) recognise that the Canning Basin
is significantly under-explored; where other global Palaeozoic petroleum basins contain
significantly higher well densities of 500 wells per 10,000 km2.

1
 Chapter 1 - Introduction

Figure 1.1. The Canning Basin. Tectonic elements with regional well coverage (blue), and
2D seismic coverage (light grey).

Presently, exploration in the basin has a regional focus for conventional and unconventional
hydrocarbons (Chapter 2.6), though there is a sustained exploration effort on the Lennard
Shelf and neighbouring shelfal positions surrounding the Fitzroy Trough – a large northwest-
southeast trending graben that contains in excess of 10 kilometres of sediment – a regional
source kitchen.

The problem to be addressed in this study is to determine whether active petroleum systems
exist within the project area that have likely generated and expelled hydrocarbons. The study
area for this project is located in a shelfal position along strike from the Lennard Shelf; in a

2
 Chapter 1 - Introduction

northeastern portion of the Canning Basin known as the Betty Terrace, Balgo Terrace and
Billiluna Sub-basin (Figure 1.1).

1.2 Geography

The Canning Basin (approximately 595,000 km2) is a sedimentary basin occupying

approximately one quarter of Western Australia (Purcell, 1984). The basin is comparable in
size to other onshore and offshore Australian sedimentary basins, such as the Bonaparte
Basin, Officer Basin and the Georgina Basin (Figure 1.2). The Canning Basin is situated
along the north-western Australian coastline to the north of Port Headland, stretching north of
Derby and east out to Lake Mackay at its’ most southeastern point. Large parts of the basin
lie within the Great Sandy and Gibson Deserts, and the geographical region is largely
uninhabited (Yeates, Gibson, Towner, and Crowe, 1984).

Figure 1.2. Australian continent with prominent sedimentary basins. Canning Basin
highlighted in red (modified after GA, 2015).

3
 Chapter 1 - Introduction

1.3 Geological Overview

The Canning Basin consists of numerous tectonic provinces that trend in a northwest-
southeast direction inland from the WA coast. The basin has a long, multi-stage depositional
history extending from the Ordovician to the Cretaceous, and can be divided into several
distinct structural and sedimentological phases (Chapter 2.3), which relate to the development
of petroleum systems. Rifting in the Ordovician created northwest-southeast trending graben
systems accommodating the Larapintine L2 petroleum system. Stratigraphy belonging to this
system includes the highly proclaimed Goldwyer Formation shales, understood to be mature
and organically rich (Wulff, 1987; Chapter 2.5) in various positions within the basin.

Early Devonian to Carboniferous aged sediments comprising the Larapintine L3 and L4

petroleum systems were deposited following Early Devonian exhumation. Notable sequences
include the Devonian aged Gogo Formation; a marine shale sequence understood to actively
charge hydrocarbons into Late Devonian reservoirs (Yellow Drum Formation) at the Blina oil
field (Table 2.2). Further, the Carboniferous Fairfield Group comprises the Laurel Formation
which features a marginal marine carbonate platform developed in shelfal regions (including
this study area; Chapter 6); a regionally mappable reservoir and organically rich source rock
(Wulff, 1987; Chapter 2.5).

Late Carboniferous to Cretaceous sediments belonging to the Gondwannan G1 and G2

petroleum systems were deposited following uplift and erosion due to a period of exhumation
in the middle Carboniferous (Edwards et.al, 1997). A marginal marine Grant Group
comprises interbedded sandstone and shale couplets potentially harbouring petroleum. The
Grant Group underlies the Permian marine Noonkanbah Formation, representative of a
marine transgression in the basin, which is a regionally mappable seal (Chapter 4).

Exhumation in the Triassic, Cretaceous and Tertiary removed large tracts of sediment from
across the Canning Basin. Apatite Fission Track Analysis (AFTA) (Duddy, et al, 2003)
demonstrates that sediments within the Canning Basin petroleum systems reached their
maximum paleo-temperatures during the Triassic.

4
 Chapter 1 - Introduction

1.4 Key Project Contributions

Several geological contributions that evolved from undertaking this study are:

1. Previous regional petroleum geology studies (for example: Brown, et al., (1984);
Smith, (1984); and Yeates, et al., (1984); Apak and Backhouse (1999); Carlson and
Ghori (2005); Haines and Ghori, (2010)) involved mapping 1980’s vintage 2D
seismic data. Reprocessing the vintage data within the project area greatly enhanced
its clarity and therefore its interpretability (Chapter 5 and 6). The tectonic framework
is enhanced in this thesis by a slight revision to the tectonic elements map (Chapter
6.2.1).
2. Triassic exhumation is not visible on seismic data, so work by Duddy et al (2003) is a
significant contribution to geological knowledge. Although petroleum prospectivity
assessments have been undertaken in the past, exhumation in Triassic and younger
times have never been applied to the project area principally because they haven’t
been detected. This thesis encompasses Duddy’s work to assess the petroleum
systems in light of this data.
3. Wulff (1987) produced the most comprehensive source rock geochemical and thermal
maturation study of the project area. 1D modelling was undertaken by Wulff, however
2D petroleum systems modelling has never before been produced within the study
area, which this project delivers (Chapter 8).
4. By reviewing previous petroleum systems studies, producing a comprehensive source
rock geochemical analysis, producing a stratigraphic framework, utilising recent
AFTA derived Triassic exhumation (Duddy et al 2003), interpreting reprocessed 2D
seismic data, and producing 2D petroleum systems modelling; this thesis becomes the
most comprehensive petroleum systems analysis of the northeast Canning Basin.

5
 Chapter 1 - Introduction

1.5 The Study Area

The study area for this project is located in a northeastern portion of the Canning Basin,
across three major tectonic regions – the Billiluna Sub-basin, the Balgo Terrace and the Betty
Terrace. The size of the study area is approximately 38,000 km2 (Figure 1.3).

Figure 1.3. The Canning Basin. Regional towns labelled and study area identified (red)

1.6 Research Questions

The key questions addressed in this project are:

Are organically rich and thermally mature source rocks present within the project
area? Did these source rocks generate and expel hydrocarbons?
Are good quality reservoir rocks and seals present in the study area?
Are favourable trapping mechanisms and sealing rocks present in the study area?

6
 Chapter 1 - Introduction

Do trapping geometries develop prior to the generation and migration of

hydrocarbons?
Do all petroleum system elements and processes occur together with suitable timing
to promote the accumulation and preservation of hydrocarbons?

1.7 Project Aim, Objectives and Methodology

This study ultimately aims to evaluate the petroleum systems within the Billiluna Sub-basin,
Betty Terrace and Balgo Terrace structural regions of the northeastern Canning Basin in
Western Australia, to identify and determine if the petroleum systems within the study area
are likely to have generated hydrocarbons, and if accumulations of petroleum are likely to
exist within the region.

This project has eight objectives:

1. Review the existing exploration results and publications pertinent to the study area,
and collate all existing data from exploration to produce an updated, relevant poro-
perm, TOC, Rock Eval Pyrolysis and petrophysical log database.
2. Produce well correlations in a stratigraphic framework to highlight petrophysical
characteristics, correlative properties, reservoir properties, and seal potential of
stratigraphy within the project area.
3. Interpret the reprocessed 2D seismic grid to map the key formations across the study
area. Map geophysical structure and stratigraphy whilst defining trapping geometries.
Perform a simple depth conversion of key regional seismic lines to enable 2D
petroleum systems modelling of the project area.
4. Analyse the geochemical database to characterise organic richness, thermal
maturation and generation potential of candidate source rock intervals.
5. Model the existing well locations in petroleum systems modelling software and
calibrate the models with existing Vitrinite Reflectance (thermal maturity)
measurements.
6. Produce 2D models across the Betty Terrace, Balgo Terrace and Billiluna Sub-basin
to understand the evolution of petroleum systems in regions without well penetration.

7
 Chapter 1 - Introduction

7. Assess prospectivity of the study area for petroleum potential by integrating the
results of the source rock study, structural and stratigraphic framework and petroleum
systems modelling.
8. Recommend key steps to further reduce exploration risk within the study area.

The methodology is outlined in Figure 1.4.

Review previous
Collect data Data QC
work

Load reprocessed
seismic

Source Rock Reservoir Produce well

Interpret seismic
evaluation evaluation correlations

Basin modelling Basin architecture

Prospectivity
Conclusions
assessment

Figure 1.4. Overview of methodology

8
 Chapter 2 – Geological Overview

2. Geological Overview

2.1 Regional Geology

The geology of the Canning Basin has been documented by a number of authors including
Brown, et al., (1984); Smith, (1984); and Yeates, et al., (1984). A recent review of the north
eastern Canning Basin has been conducted by authors Apak and Backhouse (1999) and
Carlson and Ghori (2005). The following review of the regional geology will include
reference to features pertinent to the study area – The Betty Terrace, Balgo Terrace and
Billiluna Sub-basin.

The Canning Basin has a long, multi-stage depositional history extending from the
Ordovician to the Cretaceous, and can be divided into several distinct structural and
sedimentological phases. More than 10km of sediments lie within the Fitzroy Trough, and up
to 18km of strata may be present in the Gregory Sub-basin – the basin’s deepest depocentre
(Yeates, Gibson, Towner, and Crowe, 1984).

The Canning Basin is subdivided into various structural provinces (Figure 2.1). The
expansive Kidson Sub-basin and Willara Sub-basin are situated in the centre, and the
Anketell Shelf and Wallal Embayment truss the basin to the southwest; where the
stratigraphy is mostly horizontal to sub-horizontal (Yeates, Gibson, Towner, and Crowe,
1984). The north and north-eastern areas of the Canning Basin have experienced a more
intense multi-phase deformational history. The centrally located Kidson Sub-basin and
neighbouring Broome and Crossland Platforms transition in the northeast. The northwest-
southeast oriented Fitzroy Trough and Gregory Sub-basin are located on the north eastern
side of the basin. The northern most structural provinces of the Canning Basin are the
Lennard Shelf, Billiluna Sub-basin and Balgo and Betty Terrace areas (Figure 2.2).

9
 Chapter 2 – Geological Overview

Figure 2.1. The regional Canning Basin. Tectonic elements and regional locations labelled.

2.2 Geological Division of the Study Area

The study area includes the Billiluna Sub-basin, the Balgo Terrace and the Betty Terrace;
each of which are separated by major fault systems (Figure 2.2); a north-northeast trending
Halls Creek fault system active during the Pre-Cambrian and possibly the Palaeozoic; a
Palaeozoic north-south trending marginal basin fault system on the eastern boundary; and a
major northwest-southeast trending fault system largely controlling the Gregory Sub-basin
(Smith, 1984). The Billiluna Shelf area comprises the north-eastern-most structural region of
the Canning Basin. It is bounded by the northwest-southeast trending Mueller Fault and
inter e te by the Halls Creek fault blocks on the northern basin margin. The Balgo Terrace
lies southwest of the Billiluna Shelf, situated between and controlled by the Mueller Fault

10
 Chapter 2 – Geological Overview

and the Stansmore Fault. The Betty Terrace is located south-westward and is influenced by
similar northwest-southeast trending structural regimes (Smith, 1984).

Figure 2.2. Structural features within the Study Area. Inferred faults are dashed (Modified after Tyler
2000), Solid faults are derived from Seismic interpretation, brown lines show tectonic elements
provided by the WA Geological Survey.

2.3 Geological History

2.3.1 Archean

The Canning Basin unconformably lies above Archean basement. Archean east-west
compressional events imprint a visible steep westerly dipping fabric to Archean rocks. These
north-south oriented compressional tectonic movements facilitated east-west trending folds in

11
 Chapter 2 – Geological Overview

the southern region of the basin (Irwin 1998), and show a clear unconformity that is
commonly visible on regional seismic lines (Chapter 5.3.8).

2.3.2 Ordovician to Silurian

Deposition in the Canning Basin commenced in the Early Ordovician after a period of
extension (Samphire Marsh Movement, Figure 2.3 and Figure 2.4) (Haines and Ghori, 2010).
An important feature of Ordovician time is the development of the Larapintine Seaway
(Figure 4.6, Cook and Totterdell, 1990) connecting the Canning, Amadeus and Georgina
Basins. Together with northwest-southeast trending troughs that developed due to extensional
tectonics, it accommodated shallow marine sandstones, carbonates and conglomerates
(Carranya Beds). These rocks crop out on the northern basin margin and are locally hundreds
of metres thick in basin depocentres (Nambeet Formation equivalent) (Smith, 1984). A
depositional hiatus and extensive erosion preceded uneven subsidence in the Late Silurian
and Early Devonian resulting in the waning of the Kidson sub-basin and down-to-the-basin
faulting in the Fitzroy Graben (Yeates, et al., 1984). The Siluro-Devonian marginal marine
Carribuddy Formation disconformably overlies the Carranya Beds. These evaporites
(anhydrites) are extensive and provide a regional seal in most areas of the Canning Basin
(Yeates, et al., 1984). The Carribuddy Formation may also contain local reservoir facies north
of the Gregory Sub-basin, equivalent of the Nambeet and Willara units to the south, though
possibly eroded by Devonian regional events (Haines and Ghori, 2010).

2.3.3 Devonian to Mid-Carboniferous

The Early Devonian Prices Creek Movement resulted in uplift, folding and erosion (Figure
2.3, Edwards, et al., 1997), prior to deposition of Devonian – lower-mid Carboniferous strata
(Figure 2.4). A terrestrial sandstone (Tandalgoo Formation) is generally widespread (Haines
and Ghori, 2010), although is believed to not cross the Fenton Fault hinge into the Gregory
sub-basin or adjacent areas (Smith, 1984). During this time the Fitzroy and Gregory sub-
basins obtained graben style properties, and secondary faulting generated parallel to the
elongate axis forming terrace and shelf structuration near the eastern basin margin (Yeates, et
al., 1984). Following subsidence of the Fitzroy Trough and Gregory Sub-basin, a Late
Devonian Lennard River Group of shallow marine carbonates, evaporites, sandstones and

12
 Chapter 2 – Geological Overview

shales were deposited. Carbonate sequences were commonly built up on shelfal areas, where
as the Fitzroy and Gregory sub-basins – now the major basin depocentres – received a
predominantly clastic influx. The fluvial Knobby Sandstone disconformably overlies the
Lennard River Group (Smith, 1984). The unit transitions into a shale, siltstone and sandstone
progression of the Luluigui Formation in the central depocentres. As subsidence slowed,
lagoonal limestones of the Early Carboniferous Fairfield Group filled the depressions (Figure
2.3. This sequence combined with the Laurel Formation and merged into the shallow marine
clastic sequences of the Anderson Formation (Edwards, et al., 1997).

13
 Chapter 2 – Geological Overview

Figure 2.3. Stratigraphic column of the Canning Basin

(Haines, 2009)

14
 Chapter 2 – Geological Overview

Figure 2.4. Tectonic development of the main Canning Basin elements. (Brown et al, 1984)

15
 Chapter 2 – Geological Overview

2.3.4 Late Carboniferous to Permian

The compression, uplift and erosion of the middle Carboniferous Meda Transpression was
prior to deposition of Upper Carboniferous – Permian strata (Figure 2.3 and Figure 2.4,
Edwards, et al., 1997). The Late Carboniferous – Early Permian Grant Group is glacigene in
parts (Pre-Grant Group) (Edwards, et al., 1997), mixing with marginal marine well-sorted
medium-grained sandstones, deposited extensively, though thinly (Casey and Wells, 1960).
Stratigraphic relations within the Grant Group are complex, featuring porous sandstone and
shale interbedded successions, potentially both reservoir and seal units (Haines and Ghori,
2010). A post-glacial transgression resulted in the deposition of the Early-Mid Permian
fluviatile Poole Sandstone; inferred to be present in deeper trough areas and noted to not crop
out in the eastern regions (Casey and Wells, 1960). The Mid-Permian Noonkanbah Formation
conformably overlies the Poole Sandstone (Figure 2.3), featuring fossiliferous and calcareous
fine sandstone and shale sequences (Yeates, et al., 1984). The Liveringa Formation’s three
members all appear in the eastern provinces (Balgo, Condren Sandstone and Hardman
members) with sharp conformable boundaries (Guppy, Lindner, Rattigan, and Casey, 1958).
The Late Permian Mylit Sandstone is inferred to extend into, and overly Mid-Permian rocks
in southern parts of the basin, though likely not well preserved in outcrop (Smith, 1984).

2.3.5 Triassic

The Early Triassic Blina Shale is likely to be undifferentiated in areas where it

unconformably overlies the fluvial Mylit Sandstone (Casey and Wells, 1960). The Early-Mid
Triassic fluvial (siltstone, sandstone) Culvida Sandstone (equivalent of the Erskine
Sandstone in the Fitzroy Trough) overlies the Mylit Sandstone, and e flora-rich,
fossiliferous, massive, current-banded sandstones (Casey and Wells, 1960). The post-glacial
transgression ceased in the Mid-Triassic during the Fitzroy Movement (Figure 2.3 and Figure
2.4), where anticlinal structures formed, and several kilometres of sediments (up to 2.9 km)
were eroded from within the Fitzroy Trough (Edwards et al., 1997; Duddy et al., 2003).

2.3.6 Jurassic and Younger

Younger sequences, as noted by Casey and Wells (1960), are observed in locales within the
eastern Canning Basin. A restricted deposit of Late Cretaceous massive, partly shaley

16
 Chapter 2 – Geological Overview

sandstone with occasional conglomerate interbeds are observed in the Godfreys Tank area,
west of Lake Gregory (Figure 2.5). These Godfrey Beds are noted by Casey and Wells (1960)
to be 60 metres thick. Tertiary laterite and pisolitic ironstones are observed up to 15 metres
thick in confined areas near Christmas Creek (Figure 2.5) close the north-eastern basin
margin. Massive marl and carbonate beds (Lawford Beds) are noted to overly the Godfrey
Beds near Christmas Creek. Recent Quaternary deposits include evaporites, gravels and
alluvial soils, as well as widespread medium to coarse grained aeolian sands that cover large
areas as dunes in the Great Sandy and Gibson Deserts (Casey and Wells, 1960).

Figure 2.5. Late Cretaceous sediments are preserved west of Lake Gregory. Tertiary
laterites are preserved near the north-eastern basin margin near Christmas Creek.

17
 Chapter 2 – Geological Overview

2.4 Petroleum Systems

A ‘Petroleum System’ is a geologic system that encompasses the hydrocarbon source rocks
and all related oil and gas, and which includes all of the geologic elements and processes that
are essential if a hydrocarbon accumulation is to exist (Magoon and Dow, 1994). A
petroleum system requires a (1) source rock of sufficient organic richness and thermal
maturity to generate and expel hydrocarbons, a (2) reservoir or carrier bed with suitable
porosity and permeability characteristics to allow hydrocarbons to migrate a accumulate in
a definable (3) trapping geometry, a (4) sealing lithology or geologic configuration to contain
accumulated hydrocarbons, and an (5) optimal timing of the occurrence of these elements and
processes (including migration) to allow the hydrocarbon products to be preserved over
geologic time to the present day.

2.4.1 Petroleum Systems in the Canning Basin

Palaeozoic petroleum systems provide approximately 25% of recoverable hydrocarbons

globally (Carlsen and Ghori, 2005). Bradshaw et al (1994) e h
recognize that the Canning Basin hosts three major Palaeozoic petroleum super systems
based on isotopic and biomarker studies: Ordovician – Silurian (Larapintine L2), Devonian –
early Carboniferous (Larapintine L3 and L4) and late Carboniferous – Permian
(Gondwannan G1 and G2). Stratigraphic sequences of the Canning Basin can be treated
according to these divisions (Figure 2.6).

Three main structural and stratigraphic phases have influenced the establishment of
petroleum systems in the research area. Figure 2.6 relates these petroleum systems to
stratigraphy. Early Ordovician extension (Samphire Marsh Movement) created northwest-
southeast trending troughs accommodating Ordovician to Silurian aged rocks of the
Larapintine L2 petroleum system (Haines and Ghori, 2010). The Early Devonian Prices
Creek Movement resulted in uplift, folding and erosion that facilitated the Larapintine L3 and
L4 petroleum system (Edwards, et al., 1997) with deposition of Devonian to Early-Mid
Carboniferous strata. The compression, uplift and erosion of the Mid Carboniferous Meda
Transpression was responsible for the deposition of Upper Carboniferous to Permian rocks
representing the Gondwannan G1 and G2 petroleum system (Edwards, et al., 1997).

18
 Chapter 2 – Geological Overview

Figure 2.6. Stratigraphic chart with relations to tectonic events, petroleum systems and
selected hydrocarbon occurrences (Modified after Haines 2009)

19
 Chapter 2 – Geological Overview

2.5 Source Rock Potential - Review of Wulff (1987)

Wulff (1987) has provided the most comprehensive study of source rock potential to the
study area. Their study examines five source rock intervals that are anticipated to contain
suitable organic richness and optimal thermal maturity to generate hydrocarbons within the
Canning Basin. The intervals tested by Wulff (1987) are the Permian aged Noonkanbah
Formation (belonging to the Gondwannan G1 petroleum system), Carboniferous Laurel
Formation (Larapintine L3 petroleum system) Devonian Gogo Formation and Pillara
Formation (Larapintine L3) and the Ordovician Goldwyer Formation (Larapintine L2). Wulff
(1987) accessed well data from twenty-one exploration wells. Importantly, Atrax 1, Bindi 1,
Kilang Kilang 1, Lake Betty 1, Ngalti 1, Olios 1 and Selenops 1 are utilised in their work,
thus providing a good point for discussion in this research project. It is worth noting here that
two wells have been drilled since Wulff’s 1987 report; Lanagan 1 (drilled in 2008) and
Lawford 1 (drilled in 2008 and re-entered in 2011).

Wulff concluded that the Devonian and Ordovician sequences are the most likely to have the
ability to generate significant quantities of hydrocarbons. This was because the Gogo
Formation experienced a transitional marine to marine depositional environment, similar to
that of the shallowest unit the e t (unit 4). Their interpretation comes
after determining a predominately type II to type III kerogen (Algal marine or terrestrial
organic matter) for the Devonian and Ordovician aged sections. They recommend that
exploration targets for these units should be focused on preserved thicknesses expected to be
found in the hanging wall section (down thrown block) of large listric faults commonly
observed in the area. Wulff’s work concluded that the Permian and Carboniferous aged
stratigraphy is unlikely to be able to source significant quantities of hydrocarbons; Wulff
(1987) explains that the lower section of the Permian Noonkanbah Formation is composed
principally of type III kerogen due to its terrestrial deposition, and that the upper marine unit
of the Noonkanbah Formation, although containing up to 2% Total Organic Carbon (TOC) is
predominantly comprised of oxidised and reworked material (type IV kerogen). According to
their maturation study the interval is likely not buried deep enough to enter the oil window.
Wulff (1987) concludes that the Carboniferous Laurel Formation, though is mature for oil
generation, is comprised mostly of Inertinite (with TOC less than 1%), and is unlikely to
generate significant quantities of hydrocarbons.

20
 Chapter 2 – Geological Overview

Horstman (1984) 87 and Duddy et al. (2003) have completed thermal history
reconstructions using Canning Basin wells. Horstman (1984) utilised the projection of
Vitrinite Reflectance data to determine that 500 metres to 1000 metres of sediment was
removed from the Canning Basin during a Triassic exhumation event. Wulff (1987) goes
further with Apatite Fission Track Analysis (AFTA) revealing that the basin has been
ffected by at least two significant thermal events in the Carboniferous (the Meda
Transpression event) and the Triassic (Fitzroy Movement event). Duddy et al. (2003) have
advanced the use of AFTA to postulate that four events impacted the thermal histories of
the Canning Basin (Carboniferous, Triassic/Jurassic, Cretaceous and Tertiary). The work by
Duddy et al. (2003) is significant as it demonstrates that sediments attained maximum
maturity in the Triassic before significant exhumation in the Triassic and Jurassic.

2.6 Previous Exploration

Exploration in the Canning Basin began in 1922 when Freney Oil Company drilled four wells
after seeing encouraging signs of oil in a water bore near Pillara Range (Cadman et al. 1993).
Exploration accelerated in 1952 with the Bureau of Mineral Resources (BMR)
Reconnaissance Gravity Program. The first seismic survey was shot in 1963 by Hackathorn
to verify leads identified by photo interpretation and geological mapping (Jacobson, 1984).
Early data acquisition within the study area was generally regional in nature due to the
remote location (~350 km inland), particularly because early acquisition methodology
involved mobilizing masses of equipment through desolate areas. Exploration in the basin
ceased during the petroleum industry recession of the 1970’s and resumed in the early
1980’s. Today, available seismic data is generally evenly spaced across the study area. Data
is mostly mid-1980’s vintage, however a few smaller survey lines date back to the 1960’s and
70’s. Larger seismic surveys within the research area include the Billiluna 1981, Bloodwood
1982, Mt Bannerman 1982 and Sturt 1985 seismic surveys. The importance of data quality to
prospect identification and evaluation is discussed by Jacobson (1984). The variable surface
conditions in the region have a significant impact on the quality of seismic, with data
collected in zones of sandy plains, variable surface weathering, and high rainfall. Modern day
data processing techniques aim to overcome poorer seismic quality and was utilised to
improve the clarity of data used in this project.

21
 Chapter 2 – Geological Overview

Early drilling efforts have generally been lean and thus only sparse well coverage exists in
the study area. Petroleum exploration wells the area include Atrax 1, Selenops 1, Olios 1,
Ngalti 1, BMR Lucas 13 and 14, BMR Billiluna 1 and BMR Mount Bannerman 4. Most of
these wells target shallower Permian objectives, while Olios 1, Ngalti 1, Strax 1 and
Selenops 1 penetrate to the deeper Devonian rocks. A number of mineral exploration holes
are located near the northern study area margin, though these are very shallow.

Table 2.1 summarises the occurrences of oil and gas within shelfal and depocentre regions of
the basin. Most historic oil and gas encounters are from the Ordovician, or Devonian to
Carboniferous sections of the stratigraphy; that is, the Larapintine L2 and Larapintine L3
and L4 petroleum systems. The reader is referred to Cadman et al. (1993) for further
information on the accumulations that are not mentioned here.

Cadman et al. (1993) summarize hydrocarbon play types within the Canning Basin and their
associated discoveries. Table 2.2 summarises this detail with reference to Palaeozoic
petroleum systems.

22
 FITZROY DAMPIER
LENNARD SHELF BARBWIRE TCE
TROUGH TCE
PET.
FM St
SYS. Janpam Crimson Point
Kora Terrace Meda Ellendale Boronia Yulleroo George Mirbelia Dodonea Pictor
North Lake Torment
Range

G2 Liveringa
G2 Noonkanbah
G2 Poole
G2 Grant Oil
L4 Anderson Oil Gas
L3 Laurel Oil Oil Oil Gas Gas Gas
L3 Nullara Oil Gas
L3 Napier
L3 Pillara/Gogo Oil
L3 Mellinjerrie Oil
L3 Poulton
L3 Tandalgoo
L3 Carribuddy
L2 Nita Oil Gas
L2 Goldwyer Oil
L2 Willara
L2 Nambeet Gas
Table 2.1. Hydrocarbon occurrences in the Canning Basin, modified after Cadman et al., (1993).
 Chapter 2 – Geological Overview

PET.
RESERVOIR SEAL TRAP / OBJECTIVE SOURCE 'DISCOVERY' WELL
SYS.
LATE CARBONIFEROUS to PERMIAN
Grant Fm Grant Fm Compressional culmination with internal stratigraphic Laurel Fm Sundown No. 1
sandstone shales/siltst traps shales Oil

Gondwannan G1
Grant Fm Grant Fm Laurel Fm West Terrace No.1, Oil
Unfaulted four-way dip closure within palaeo-monadnock
sandstone shales/siltst shales
Grant Fm Grant Fm Laurel Fm Boundary No. 1
?
sandstone shales/siltst shales Oil
Grant Fm Grant Fm Faulted, four-way dip closure on Laurel Fm carbonate Laurel Fm
Crimson Lake No.1, Oil
sandstone shales/siltst horizon shales
CARBONIFEROUS
Anderson Fm Anderson Fm Laurel Fm Lloyd No. 1
Faulted four-way dip closure

Larapintine L4
sandstone shales shales Oil
Anderson Fm Anderson Fm
? ? Point Torment No.1, Gas
sandstone shales
Anderson Fm Anderson Fm Laurel Fm Kora No. 1
Unfaulted four-way dip closure
sandstone shales shales Oil
Laurel Fm Laurel Fm Laurel Fm Terrace No.1
Four-way dip closure
carbonates shales shales Oil
Anderson Fm Anderson Fm Laurel Fm West Kora No. 1
Four-way dip closure
sandstone shales shales Oil
Anderson Fm Anderson Fm Compressional culmination with internal stratigraphic Laurel Fm Sundown No. 1

Larapintine L3
sandstone shales traps shales Oil
Laurel Fm Laurel Fm Laurel Fm Meda No. 1
Reef-like seismic anomaly
sandstone shales shales Oil
Laurel Fm Gogo Fm
Fairfield Group shales Faulted, four-way dip closure on Intra-Fairfield Group Ellendale No. 1 Oil and Gas
clastics shales
Laurel Fm Laurel Fm Laurel Fm St George Range No. 1 Gas
Anticline
limestone shales shales
Laurel Fm Laurel Fm Laurel Fm Yulleroo No. 1
Anticline
sandstone shales shales Gas
DEVONIAN
Yellow Drum Fm, leached Gogo Fm Blina No. 1
Fairfield Group shales Compaction drape closure over Devonian reef
dolostones shales Oil
Nullara Fm Nullara Fm Gogo Fm Janpam North No.1, Oil
Reef-like seismic anomaly
carbonates shales shales

Larapintine L3
Nullara Fm Nullara Fm Gogo Fm Meda No. 1
Reef-like seismic anomaly
calcarenite shales shales Gas
Nullara Fm Blina No. 1
May River Member shales Unfaulted shale draped biohermal and biostromal mound Gogo Fm shales
leached dolostones Oil
Gogo Fm Gogo Fm Gogo Fm Boronia No. 1
?
clastics shales shales Oil
Mellinjerie Lst Mirbelia No. 1
Lower Pillara Fm shales Fault dependent closure at top Nita Fm level. ?
dolostones Oil
ORDOVICIAN
Nita Fm Nita Fm Goldwyer Fm Pictor No. 1
Tilted fault block with internal four- way dip closure
Larapintine L2

dolostones shales shales Oil

Goldwyer Fm Goldwyer Fm Goldwyer Fm Dodonea No. 1
Fault dependent closure at top Nita Fm level.
carbonates shales shales Oil
Nambeet Fm Dodonea No. 1
Upper Nambeet Fm ? Fault dependent closure at top Nita Fm level. Upper Nambeet Fm ?
dolomitic ss Gas

Table 2.2. Hydrocarbon plays in the Canning Basin (modified after Cadman et al., 1993)

24
 Chapter 2 – Geological Overview

Currently, the entirety of the Canning Basin is under exploration lease. There are at present
twenty-two exploration companies present in the basin (Figure 2.7). The largest proportion of
exploration leases are held by Buru Energy Ltd, New Standard Energy Ltd (NSE)/Conoco
Phillips (in Joint Venture), Hess Corporation and Backreef Oil Pty Limited. Buru Energy and
the Conoco Phillips/NSE joint venture are the parties that have most recently completed work
programs. Buru Energy Ltd is currently the largest explorer in the basin (by acreage position
and perseverant work programs), and has had the most recent exploration success with their
Valhalla (2007) prospect, Yulleroo (discovered in 1967 and tested in 2008) and most recent
Ungani well discoveries (2011 and 2012, Figure 2.8). Buru’s Ungani play recently completed
Extended Production Testing (EPT) producing 1,025 barrels of oil per day during the EPT
(Buru Energy, 2015).

In 2012 Hess Corporation acquired unlisted Kingsway Oil, instantly making Hess
Corporation the then largest tenement holder in the basin (by acreage position), with interest
in permits cove ing large parts of the Kidson Sub-basin. In 2013 Apache Energy Ltd. entered
into a Joint Venture agreement with Buru Energy to explore the potential of the Ordovician
Goldwyer Formation on the Broome Platform and Dampier Terrace (western Canning Basin)
valued at $25 Million, and Fitzroy Graben (central-north Canning Basin) valued at
approximately $7.2 Million (plus the majority of work program costs), to earn approximately
40% interest in the permits. Other recent activities to note include the Goldwyer Shale Gas
exploration program undertaken by New Standard Energy Ltd. together with ConocoPhillips,
as part of a $73 Million four-year work program to evaluate the unconventional potential of
the Ordovician Goldwyer Formation across the Kidson Sub-basin (funded by ConocoPhillips
to earn a 75% interest in the project). The joint venture drilled a three-well program in 2012
and 2013. ConocoPhillips exited the joint venture in 2014.

One take away message from these investments is a heightened interest in large acreage
positions containing regional unconventional prospects, where recent shale exploration joint
ventures coupled with encouraging drilling results have led to new exploration in the Canning
Basin.

25
 Chapter 2 – Geological Overview

Figure 2.7. Current population of explorers in the Canning Basin

2.7 Production

The first commercial oil was found by Home Energy Company at Blina 1 on the Lennard
Shelf, recovered from within the Fairfield Group (Cadman et al 1993). The Blina field
(Figure 2.8) is one of the small fields still in production, currently operated by Buru Energy
Ltd.

Another small neighbouring producing area, the West Kora field (Figure 2.8), was discovered
by Esso Australia in 1984 and produced 20,000 barrels of oil at 350 barrels per day, but was
eventually shut-in due to increased water cut from 35% to 85%. Now operated by Buru
Energy, there are plans for a workover program to bring the field back into production. Both
of these oil fields are located on shelf structures nearer to the Western Australia coast.

26
 Chapter 2 – Geological Overview

Geological characteristics similar to those hosting producible oil may be present in

neighbouring shelf regions, including this project research area.

Table 2.3 summarises Canning Basin commercial production as of 1993. A common feature
is that all the producing fields are relatively small; remarkable given the large size of the
basin. This leads to questions such as; (1) is the relatively small commercial production
related to a deficiency in exploration, or; (2) is this an indication that one (or some) of the
basin petroleum systems (i.e. either the Larapintine L2, L3 and L4 or Gondwannan G1 or G2
systems) have properties that are not optimally performing to enable the generation,
migration or preservation of hydrocarbons?

Refer to Cadman et al. (1993) for a compilation of production data on the fields shown in
Table 2.3.

Initial Recoverable Reserves Remaining Recoverable

Field
(P90) MMSTB Reserves (P90) MMSTB

Blina 2.059 0.673

Boundary 0.017 0.006

Lloyd 0.143 0.006

Sundown 0.303 0.101

West Terrace 0.154 0.006

West Kora 0.024 (TSTM)

Table 2.3. Production within the Canning Basin as of 1993 (Cadman et al. 1993)

27
 Chapter 2 – Geological Overview

Figure 2.8. Regional production in the Canning Basin

28
 Chapter 3 – Data Availability and Quality

3. Data Availability and Quality

Data for this project was obtained from the Geological Survey of Western Australia (GSWA).
Data was accessed using the GSWA’s online Petroleum and Geothermal Information library
(WAPIMS). The data available for this project consisted generally of publicly accessible
open-file information. With the exception of reprocessing that was applied to open-file 2D
seismic, all other hard information used in the project is not proprietary to any organisation.

3.1 Well Data

Nine open-file petroleum exploration wells were used for this project. These wells are termed
“study area wells” as they provide direct exploration tests within the study area. The study
area wells are summarised in Table 3.1. Other regional petroleum wells that are also open-file
were consulted for use of their geochemical data, and applied to the evaluation of source rock
richness and maturity in later chapters. This was necessary as the study area wells did not
penetrate stratigraphy deep enough to allow proper evaluation, nor did they contain enough
geochemical information within the sections that they did intersect. Further, as this is a
regional project, regional data sources are required to assess regional trends and the use of
these wells will facilitate a regional investigation. Table 3.1 and Figure 3.2 illustrate the
location of wells used for this project. The reader is referred to the Appendix A, C and D for
a detailed disclosure of all well related data.

29
 Chapter 3 – Data Availability and Quality

Well Status Total Completed Data measurements Summary and additional

Depth information
TOC RockEval VR
Pyrolysis

Atrax 1 Plugged and 786.0 15/7/1984 51 13 0 Full well completion

Abandoned report (WCR), Digital
geophysical logs

Bindi 1 Plugged and 2507.0 14/8/1984 19 14 7 Full well completion

Abandoned report (WCR), Digital
geophysical logs

Kilang Plugged and 2300.0 03/12/1984 108 40 21 Full well completion

Kilang 1 Abandoned report (WCR), Digital
geophysical logs

Lake Betty 1 Plugged and 3145.0 15/12/1971 141 39 15 Full well completion
Abandoned report (WCR), Digital
geophysical logs

Lanagan 1 Plugged and 1530.0 21/9/2008 0 0 0 Full well completion

Abandoned report (WCR), Digital
geophysical logs

Lawford 1 Plugged and 2698.0 27/10/2011 0 0 0 Full well completion

(and Lawford Abandoned report (WCR), Digital
1 reentry) geophysical logs

Ngalti 1 Plugged and 2758.0 17/10/1984 123 11 0 Full well completion

Abandoned report (WCR), Digital
geophysical logs

Olios 1 Plugged and 1963.0 02/11/1983 105 15 27 Full well completion

Abandoned report (WCR), Digital
geophysical logs

Selenops 1 Plugged and 1263.0 04/8/1984 85 3 0 Full well completion

Abandoned report (WCR), Digital
geophysical logs

Table 3.1. Summary of the nine study area wells used in this project.

30
 Chapter 3 – Data Availability and Quality

3.2 Well Data Quality

Before utilising the well data for this project, hard data measurements were screened for
quality assurance. This was achieved numerous ways:

As a starting point, Well Completion Reports (WCR) that were obtained from the
GSWA were checked for their completeness. This meant browsing through the reports
to confirm that all of the reporting data types (i.e. WCR chapters, digital log data and
paper log copies, appendices and attachments) were obtained from the GSWA when
requested.
Well locations were converted from their native (original and reported) datum into the
current Geodetic Datum of Australia (1994) projection. The converted locations were
then loaded into Google Earth (satellite image viewing software) and referenced to
nearby physiographic features e te e h e (for example road access,
property fence lines, etc.) to ensure that the location of the well is correct th respect
to current mapping projection systems. This was an important step because well
locations need to be accurate when performing well-to-seismic ties in later stages of
this project. Generally, most of the wells were noted to lie in the correct area, however
some of the wells were given an updated location based on WCR surveyors’ notes.
The wells that were shifted from the datum-converted location are noted in Figure 3.2,
along with comments.

31
 REPORTED LOCATION REVISED LOCATION
COMMENTS
(CONVERTED TO GDA94, MGA z51S) (GDA94, MGA z51S)
WELL NAME
Seismic
Latitude Longitude Easting Northing Rev Easting Rev Northing Google Earth location
profile
Well surveyed, though
possible access track and pad
82GE31
Atrax 1 19° 24' 05.49188" S 126° 36' 18.23851" E 248486.775 m E 7852996.793 m S 249015.00 m E 7852827.00 m S visible 545m towards ESE,
VP1025
Need to QC with seismic to
confirm
Bindi 1 82C1 SP344 19° 43' 14.81535" S 126° 48' 01.50719" E 269465.288 m E 7817922.76 m S 269465.288 m E 7817922.76 m S Converted location is good
GDA94 location is correct,
Kilang Kilang 1 RB81-6 20° 12' 41.93338" S 127° 07' 41.54882" E 304437.132 m E 7763993.515 m S 304422.27 m E 7763993.53 m S
visual pad disturbance
"Godfrey K"
SP42
Lake Betty 1 19° 34' 02.95169" S 126° 19' 49.53925" E 219914.846 m E 7834193.031 m S 220258.00 m E 7834192.00 m S Visible well pad disturbance
(82GE34 for
synthetic)
Recent well - should be in
correct position, but Google
earth images pre-dates WCR
Lanagan 1 19° 35' 00" S 126° 25' 36" E 230173.742 m E 7832750.408 m S 230043.00 m E 7832593.00 m S
date. Location lies on
seismic line. Use WCR
converted location
RB82-31 Well surveyed "144.0m>255
Ngalti 1 19° 52' 02.66036" S 127° 18' 50.51775" E 323472.083 m E 7802308.642 m S 323472.083 m E 7802308.642 m S
SP580 deg WSW of Dopper Stn"

83GN15A Converted location is good,

Olios 1 19° 30' 15.19105" S 126° 47' 34.75023" E 268375.83 m E 7841890.262 m S 268329.47 m E 7841877.80 m S
VP240 small adjustment

S87L-08 Recent well. Location is

Lawford 1 19° 59' 38.8" S 126° 37' 51.3" E 252115 m E 7787570 m S 252115 m E 7787570 m S
SP 534 good.

Using QC’d navigation

locations (+/- 40m) the well
sits nearer WCR location. At
82GE31
Selenops 1 19° 24' 50.14033" S 126° 43' 05.52977" E 260391.471 m E 7851784.825 m S 260446.00 m E 7851654.00 m S this location can see dark
VP1369
grey possible well pad area.
Adopt this location as it sits
on correct VP

Table 3.2. Quality control applied to study area wells

 Chapter 3 – Data Availability and Quality

Geophysical logs from each well were inspected to tte t t any acquisition
and recording matters that are pertinent to further interpretations. The principal
inspection was carried out on the Caliper log for every well (Figure 3.1). It was noted
that well bore rugosity was a common feature in most of the core study wells. It is
important to note the presence of these imperfections because this can affect accurate
recording of other geophysical tools. Refer to Chapter 5.5.2 for further comments. It
was found, that although well bore rugosity was prevalent during drilling of the study
area wells, rugosity did not seem to have a significant negative impact on the affected
well Density (RHOB) and Porosity/Sonic (DT) tools, and successful well-to-seismic
ties were achievable as a result (Chapter 5.2.2).
The GSWA provide open-file well bore measurements in a compilation (excel
format). The compilation contains a large variety of data, including an archive of
geochemistry (TOC measurements, Rock-Eval Pyrolysis measurements) and
petrophysical properties (porosity and permeability), amongst many other data types.
These databases were found to be very useful as a starting point for this project. The
data summaries were screened for accuracy, by browsing through WCR records and
other existing data acquisition reports for the original numerical forms. This was
found to be a particularly important step in quality assurance because on occasion
some numbers had been incorrectly entered into the database. This screening process
was also useful familiari t with the availability of well bore data.

Once a diligent quality assurance process was completed, well data was extracted from
GSWA archives and partitioned into more user friendly excel spreadsheets for future
examination. For example, separate documents were created for data type availability, well
summaries, geochemistry, petrophysical data, etc.

33
 Chapter 3 – Data Availability and Quality

Figure 3.1. Study area wells datumed on RT elevation. All wells show some
degree of rugosity (indicated by grey shading). Atrax 1, Selenops 1, Lake Betty
1, Kilang Kilang 1 and Ngalti 1 are particularly affected. Ngalti 1 100mRT –
800mRT shows complete saturation of the Caliper tool (CAL), likewise for
Lake Betty 1 1700mRT – 1900mRT. Many other wells show significant
washout and near complete CAL saturation. The Density Correction (DRHO)
indicates where the Density log is not giving proper recordings of the true
formation density values (0> is correction for lesser contact). Even where
rugosity is not so apparent (e.g. Lawford 1) DRHO shows indirect wellbore
contact throughout the central section of the well. In rugose areas, it is possible
that the Sonic (DT) tool is decentralised resulting in inaccurate sonic time
values. 34
 Chapter 3 – Data Availability and Quality

3.3 Seismic Data

The study area is covered by a reasonable selection of 2D reflection seismology data. The
data was obtained from the GSWA online archives (WAPIMS) in SEGY format and loaded
into IHS Kingdom for interpretation. All of the publicly available 2D reflection seismic data
was freely available for this project. An example of the data as it was initially obtained is
shown in Figure 3.3. Table 3.3 summarises the surveys that were used in this project.

SURVEY LINE ABBREVIATION YEAR

Betty Terrace SS 81C 1981
Mt Bannerman 1982 SS 82GN, 82GE 1982
Billiluna SS RB81 1981
Bloodwood 1982 SS RB82 1982
White Hills SS 80WH 1981
Samphire Terrace SS 81B 1981
Roberts Range SS 81RR 1981
Doman SS 82C 1982
Lake Havern SS 82LH 1982
Lake Doman SS 82LD 1982
Ryan High Regional SS 86RH 1986
Pinbilly SS A-79 1979
Barbwire Range Semi-Detail SS BR65 1965
Orange Pool SS BV93 1993
Barbwire Terrace SS C72 1972
Meda 1982 SS H82 1982
Nibil SS NIB86 1986
Sturt SS PS85 1985
Anna Plains SS S84 1984
Lake McLernon SS S85 1985
Willara SS S87 1987
Lawford SS S87L 1987
Great Sandy SS S98C 1998
Table 3.3. Seismic surveys utilised in this project.

35
 Chapter 3 – Data Availability and Quality

3.3.1 Improvements to Seismic Data

It was anticipated that interpreting the publicly available grid in its original form would be
relatively difficult. Figure 3.3 demonstrates the quality of original seismic acquisition
processing. It was determined by Pangaea that 120 seismic lines were to be reprocessed to aid
in the evaluation of their exploration acreage STP-EPA-0030 and STP-EPA-0031. A total of
4,707 line km was reprocessed in this workflow. Pangaea e e te which lines to reprocess
based on the expected improvement the 2D line would have compared to its original image.
All of the reprocessed lines were made available for use in this project. Figure 3.3
demonstrates an example of the improvement to a significant regional seismic line within the
study area. The general improvement is dramatic. Figure 3.2 illustrates the distribution of the
seismic grid that was interpreted as part of this project. Further examples of the quality of the
seismic reprocessing is shown throughout chapters 5 and 6.

.
Figure 3.2. Seismic grid and well locations.

36
Figure 3.3. Example of improvements to seismic data post-
reprocessing. Original images were scanned from data tape (top)
in the first instance, and tapes were sent to reprocessing houses
for final reprocessing ques to PSTM (bottom). Resulting
improvements are dramatic. This improvement is representative
of the high majority of 2D lines in this dataset.
 Chapter 3 – Data Availability and Quality

It is noted that the seismic reprocessing, although exploited in the project, is not a material
component of the research, and so the data is taken on board from an interpret t t
view. None of the reprocessing workflow formed part of this research project. The data, once
received from the reprocessing house, was simply loaded into IHS Kingdom interpretation
software and interpretations are based on the newly reprocessed seismic. Due to the poor
quality of the original seismic processing, the majority of the original seismic grid was not
utilised in this project. An exception to this is that in a small number of places the original
processed version of a 2D line was the only version available (because the line was not
reprocessed along with the other surveys), and to aid in loop ties. he only option to
refer to the original line.

3.3.2 Seismic Data Quality

The seismic grid utilised in project, shown in Figure 3.2 and summarised in Table 3.3, is
generally 1980’s vintage and has poor visual quality (in its’ un-reprocessed and publicly
available form). Most reflection events are subtle, and the data is generally noisy. As a result
of the reprocessing, overall seismic imaging of the study area e . The key
difference for the purposes of this project are the clearer reflection events of regional features
(for example the Meda Transpression unconformity – Chapter 5.3.1). The selected mapping
events, shown in Table 5.3, were strikingly more distinct when using the reprocessed grid.
Events such as the Meda Transpression Unconformity, the Near Top Ordovician marker and
Near Top Basement marker were generally easier to map with the reprocessed seismic. The
Meda Transpression and Basement markers are far more difficult to map on un-reprocessed
seismic, because the reflector terminations used to identify the correct position of the
horizons are surrounded by low amplitude, noisy reflection events.

Spatially, the seismic grid over the study area adequately enables the interpreter to
characterise the tectonic regions in question. The only minor problem with the grid layout, is
that in certain regions there are less seismic lines to resolve loop ties. An example is shown in
the centre of Figure 3.4 northwest of Ngalti 1 (19° 39’S, 127° 08’E), where there is a
deficiency in seismic coverage (area between red and blue lines, where the blue lines were
key lines for a central loop tie). This results in lower confidence in the interpretation because
there are lesser available lines to loop tie within the parts of the Bloodwood 1982 and Betty
Terrace 1981 surveys northwest of Ngalti 1. Further, correlation was more difficult between
the Ngalti 1 and Bindi 1 wells on the east-west oriented 81C (Betty Terrace 1981 SS) line

38
 Chapter 3 – Data Availability and Quality

(lower red line pairs on Figure 3.4). This grid deficiency is again notable in the Billiluna Sub-
basin; the seismic model would have been more geologically resolved if line PS85-60 (Sturt
1985 SS) or RB81-7 (Billiluna 1981 SS) allowed intersection with Proterozoic outcrop to the
North East of the basin. The red highlighted lines in Figure 3.4 were found to be key in
regionally correlating between the northwest and southeast project areas.

Conclusively, reprocessed seismic imaging is generally good across the whole of the study
area and seismic imaging of major faults is clear. This is assisted by strong reflection events
at the Near Top Laurel Carbonate marker due to its high reflection coefficient contrast at the
event and below the event into the Knobby Sandstone level. Another Intra-Devonian
reflection event (which was not chosen for mapping in this project) aids the interpreter in
relative positioning within the seismic section, and provides several “train track” events to
juxtapose across faults. Seismic imaging of minor faults is adequate for the purposes of this
research project.

39
 Chapter 3 – Data Availability and Quality

Figure 3.4. Seismic grid with key regional lines (red) and key lines for central area loop tie (blue).
More seismic within the central ‘pentagon’ area would have enabled a more confident loop tie in
seismic interpretation.

40
 Chapter 4 – Stratigraphic Framework

4. Stratigraphic Framework

The Can ing Basin is presently filled with sedimentary rocks of Ordovician to Cretaceous
age. The objective for this Chapter is to produce a meaningful stratigraphic framework of
regionally extensive stratigraphy that is identifiable from Geophysical Log Characteristics.
The framework will then be discussed in terms of a regional setting and inferences for
hydrocarbon prospectivity for the study area.

This Chapter also discusses results of Isochron (TWT thickness) maps derived from seismic
interpretation (Chapters 5 and 6), because isochrons inform of stratigraphic spatial variability
that cannot be derived from well correlations alone. This Chapter (Chapter 4) is prior to
seismic (Chapters 5 and 6) to comprehensively introduce the reader to the stratigraphy. Well
correlation cross sections (Figure 4.44 to Figure 4.46) are available at the end of this Chapter.
Isochron maps (Figure 6.19 to 6.25) are available at the end of Chapter 6.

Pre-Cambrian, Cambrian, Ordovician and Silurian aged rocks are not penetrated by wells
within the project area so their existence is considered where the limits of the seismic and
published literature will allow. It remains possible that older sequences exist at depths within
the study area that are potentially prospective for hydrocarbons, however conclusions can
only be drawn as a function of the seismic and well data at hand.

Inferences for older rocks are derived from two wells (Percival 1 and Lake Havern 1, Figure
4.1). Text concerning deeper stratigraphy will be general in nature. Stratigraphy with good
well intersections (i.e. where better well coverage and well data exists) allow a more detailed,
hierarchical discussion to convey a characterization of regional setting and relationships; and
identify potential petroleum system reservoirs and sealing intervals.

Most of the information within this section was ultimately derived from WCR files
(discussed in Chapter 2). GSWA provided a tabled summary of regional reservoir quality
data. Geophysical logs were loaded into Rockware Logplot 7 for editing and presentation in
this study. Core data is scarce within the project area and surrounds, particularly to enable a
quantifiable characterization of sealing capacity, so deductions from cuttings lithology and
geophysical log characteristics are all that is available to the interpreter.

41
 Chapter 4 – Stratigraphic Framework

4.1 Pre-Ordovician

4.1.1 Precambrian

Surface geological maps show Precambrian rocks outcropping along the northeastern basin
margin, and belonging to the Halls Creek Province (Figure 2.2). They are of Archaean to
Early Proterozoic age. The Pre Cambrian section dips to the west under the project area, the
top of which is represented by a steeply dipping angular unconformity under Paleozoic strata
(mapped as the Near Top Basement horizon on 2D Seismic, Figure 5.7). Klappa et al. (1985)
noted similar Proterozoic sequences in the Amadeus Basin th t are hydrocarbon bearing (for
example the Neoproterozoic Heavitree Quartzite) and that the sequence in the Canning Basin
should not be overlooked in regards to hydrocarbon prospectivity. However, the Precambrian
rocks are mostly very deep, commonly exceeding 4 seconds in TWT on 2D seismic. For the
purposes of this research project the petroleum systems of the Pre Cambrian are not
considered.

4.1.2 Cambrian

Rocks of Cambrian age are not known to exist in the sedimentary sequence of the Canning
Basin. Some horizontal reflections were noted to occur below the Near Top Basement
horizon (Figure 6.7) – these could possibly represent Cambrian strata, but no wells are
available to verify this, so for simplicity these ‘intra-basement’ reflections were mapped as
Basement.

42
 Chapter 4 – Stratigraphic Framework

Figure 4.1. Study area in a regional context. Seismic tie to Lake Havern well. Seismic lines
(red) show the arbitrary line (black dashed and arrows). Study area circled in red. Interpretation
is shown in Figure 5.8.

4.2 Early to Middle Ordovician

Overview

Early to Middle Ordovician rocks in the Northeastern Canning Basin comprise a relatively
comfortable succession containing the Early Ordovician Nambeet Formation, Early to Middle
Ordovician Willara Formation, Middle Ordovician Goldwyer Formation and Nita Formation
(France, 1984). The Ordovician sequence is divided into 5 super-sequences by Kennard et al
(1994) and Romine et al (1994) (summarized in Figure 4.2). There are no wells within the
study area that intersect Ordovician age sedimentary rocks. The following investigation of
regional wells, together with seismic evidence in subsequent Chapters, provides some
confidence that an Ordovician package is present within the Billiluna Sub-basin, Balgo and
Betty Terraces, however the study area may sit in a paleogeographic setting that discourages
the accommodation of shale lithologies.

43
 Chapter 4 – Stratigraphic Framework

Figure 4.2. Stratigraphic column of Ordovician and Silurian stratigraphy

(Modified after Haines, 2007)

Percival 1 (Figure 4.3) - drilled on the Barbwire Terrace (on the southwestern flank of the
Gregory Sub-basin); and Lake Havern 1 (Figure 4.5) – drilled on the northern edge of the
Ryan Shelf, are the two nearest wells to intersect a portion of preserved Ordovician
stratigraphy. Percival 1 intersected a sequence that is most readily correlatable to regional
Ordovician markers, whereas Lake Havern 1 intersected a sequence of Ordovician rocks that
appear to be of different paleogeographic origin.

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 Chapter 4 – Stratigraphic Framework

LITHOLOGY
Carribuddy Group

Nita Fm (Leo Mbr)

Goldwyer WMC U4
Goldwyer WMC U3
Goldwyer WMC U2

Goldwyer WMC U1

Willara Fm

Nambeet Fm

Figure 4.3. Percival 1 geophysical log. Lithology indicated on right (modified after
France, 1984).

45
 Chapter 4 – Stratigraphic Framework

4.2.1 Nambeet Formation

Characteristics

The Early Ordovician (Tremadocian) fluvial to marginal marine Nambeet formation is

described at Percival 1 primarily as an orthoquartzitic medium grained well-sorted sandstone
with dolomite and shale banding, capped by interbedded dolomite, blackish fissile shale and
argillaceous fissile siltstone (France, 1984).

Geophysical Log Characteristics

The top of the formation is marked by a spike in the gamma ray log underneath a blocky
Willara Formation sandstone (Figure 4.3). The Orthoquartzitic section of the Nambeet
Formation shows a generally homogenous resistivity log, sonic log and high gamma ray
values (increasing gamma ray trend towards the base of the formation). The density log
shows generally high values reflecting the dolomitic and indurated characteristics of the
formation.

The Nambeet Formation does not directly correlate to wells within the study area, and a
regional seismic tie (encapsulated within the Goldwyer Formation correlation and Figure 5.8)
to Lake Havern 1 is the only indication that the interval exists within the project area.

4.2.2 Willara Formation

Characteristics and Geophysical Log Characteristics

The Early to Middle Ordovician (Arenig to Llanvirn) Willara Formation at Percival 1 is a

relatively homogenous sandstone unit, described predominately as fine grained, moderately
well-sorted and massive in character (France, 1984). As such, the gamma ray response of the
interval is clean and blocky. Logs show low resistivity and density values and the unit is
relatively slow on the sonic log compared to intervals above and below.

The Willara Formation does not directly correlate to wells within the study area, and a
regional seismic tie (encapsulated within the Goldwyer Formation correlation and Figure 5.8)
via Lake Havern 1 is the only indication that the interval may exist within the study area.

46
 Chapter 4 – Stratigraphic Framework

4.2.3 Goldwyer Formation

Overview

The Middle Ordovician (Llanvirn) Goldwyer Formation is separated into four stratigraphic
subunits, Unit 1 to Unit 4 (oldest to youngest). Recent workers Kennard et al. (1994) utilized
wireline log data, whole core and relations to regional tectonic events to subdivide the
Formation. Kennard et al’s recent work generally correlates to earlier subdivisions proposed
by Western Mining Corporation (WMC, operators of the Percival 1 well), though Goldwyer
Formation relationships were originally thought to be restricted to the Mowla Terrace and
Broome Platform (close to the West Australian seaboard). Associations have recently
(experimentally) been made to further regions in the northwest (Admiral Bay, Willara Sub-
basin, etc.) utilizing the earlier subdivisions of WMC (Haines, 2004) because of their simple
definition. The same WMC subdivisions are carried here.

Goldwyer Formation Type Section

Kennard et al. (1994) proposed a type section for the Goldwyer Formation at Solanum 1 on
the Barbwire Terrace between 283 mRT to 563 mRT. The type section is shown in Figure
4.4, along with the preserved section at Percival 1.

Top WMC 4
Top WMC 3

Top WMC 2

Top WMC 1

Base Goldwyer

Figure 4.4. Solanum 1 (left) and Percival 1 (right) show Goldwyer Formation correlation (modified
after France, 1984; France and Scibiorski, 1984).

47
 Chapter 4 – Stratigraphic Framework

Unit Division at Percival 1: Characteristics and Geophysical Log Characteristics

Unit 1

Percival 1 (Figure 4.3) intersected a mostly complete section of the Middle Ordovician
Goldwyer Formation, with a gross thickness of 153 metres. The basal unit (Unit 1) comprises
soft dark grey calcareous sub-fissile micromicaceous shale capped by interbedded dark grey
argillaceous siltstone, dolomitic limestone and grey sucrosic dolomite (France, 1984).
Geophysical logs over Unit 1 show a consistently hot gamma ray response, invariable mid-
range resistivity and homogeneous sonic log. The density log increases over the lower part of
the package representing the change from limestone to argillaceous siltstone. Unit 1 is 86
metres thick at Percival 1.

Unit 2

Unit 2 of the Goldwyer formation is observed as interbedded blackish firm fissile shales, with
firm argillaceous pyritic siltstone and microcrystalline limestones (France, 1984). Unit 2 is
characterized by an invariably fast sonic log, decreasing density log with increasing depth
and marked increasingly hot trend in the gamma ray log response with depth, showing a
blocky character. Goldwyer Formation Unit 1 is separated from Unit 2 by a hotter and
blockier gamma ray log response (where Unit 2 shows a decreasing upwards GR trend). Unit
2 is 16 metres thick at Percival 1.

Unit 3

Unit 3 is observed as interbedded black infrequently carbonaceous shales, microcrystalline to

sucrosic dolomite and massive microcrystalline limestone (increasing dolomite towards base)
(France, 1984). Geophysical logs over the interval reflect these lithologies, showing marked
increases in sonic transit times (increases at base) and generally lower gamma ray (with
spikes over the carbonaceous shales). The gamma ray shows a subtle overall fining upwards
trend. Unit 3 is separated from Unit 2 by a lower gamma ray log response and faster sonic
transit times. Unit 3 is 35 metres thick at Percival 1.

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 Chapter 4 – Stratigraphic Framework

Unit 4

The upper-most subdivision (Unit 4), is observed as grey to black finely crystalline
argillaceous and carbonaceous dolomite (France, 1984). Unit 4 is observed as an unvarying
high-range resistivity and sonic log, and a hot blocky gamma ray log response over the
interval. The gamma ray character differentiates Unit 4 from the surrounding intervals. The
top of the Goldwyer Formation (uppermost section of Unit 4) is commonly situated below a
marked deflection (decrease) in gamma ray resembling a “U” or “V” shape. A similar
(though inverted) form can be seen in the resistivity and sonic logs (an inflected response
over the same interval), which separates the Nita Formation above. Unit 4 is 16 metres thick
at Percival 1.

4.2.4 Nita Formation

The Ordovician Nita Formation at Percival 1 is described as finely crystalline and sucrosic
Dolomite (France, 1984). Geophysical logs over the interval (Figure 4.3) show a
‘characteristic’ “U” or “V” shape in the gamma ray log, increases in resistivity, density and
sonic logs that represent the tight and dense dolomite lithology. The Nita Formation is 16
metres thick at Percival 1.

Comparison between Percival 1 and Lake Havern 1: Does an Ordovician package exist

within the study area?

Percival 1 geophysical logs were compared to Lake Havern 1 logs. The Lake Havern 1 well
was then correlated seismically to the study area.

The Ordovician aged rocks at Lake Havern 1 are not characterized by the same features as at
Percival 1. Top of the Ordovician section at Lake Havern 1 (Figure 4.5) is interpreted from
logs to be at 1756 mRT. The section is purported to belong to the Goldwyer Formation, and
is described as dominantly fine grained sandstone with thin dolomitic fissile shales,
claystones and banded dolomite. The section is recorded as an increase in gamma and
resistivity logs due to an increase in shale content from the overlying Carribuddy Group at

49
 Chapter 4 – Stratigraphic Framework

the well location. The gamma ray over the interval is observed as a “saw tooth” variable and
noisy log character. The Nita Formation was not te e te above the Goldwyer Formation
at Lake Havern 1.

Below the Goldwyer Formation, Lake Havern 1 intersected 646 metres (1950 mRT to 2296
mRT, described as Ordovician aged “Middle Formation”) of fine grained sandstone and
minimal thin shales with dolomite, distinguished only from the overlying Goldwyer
Formation by a change to a more-so invariable gamma ray and sonic log response below
1950 mRT. This section may belong to the Willara Formation (correlating the cooler blockier
gamma ray log response to 2188 mRT to 2230 mRT at Percival 1). Further inspection of the
Lake Havern 1 geophysical logs over the “Middle Formation” indicates a basal section (2224
to 2296 mRT) that looks to represent a portion of Nambeet Formation, indicated by a
coarsening gamma ray trend, increasing trend in resistivity and increasing shift in density
curve responses (that signals an increase in dolomitic content). However, palynology
(discussed below) from Lake Havern 1 does not assist with this allocation.

Age Control at Lake Havern 1

In the northeastern portion of the Canning Basin, well intersections of Ordovician aged rocks
are limited, and because the described Goldwyer Formation is vastly different between Lake
Havern 1 and Percival 1, some doubts are raised about the correct age association of Lake
Havern 1’s Ordovician aged section. Palynological evidence was sought by the Lake Havern
1 well perator to alleviate these doubts. The identified microspores found below 1756 mRT
are reported to be of a ‘younger Late Famennian period, though possibly older’ (Purcel in
Irwin, 1998). The “Middle Ordovician” section identified from logs at 1950 mRT was not
age t e from Palynology evidence, though a lower portion of this “Middle Ordovician”
section (at 2291 mRT) was shown to be ‘at least of Devonian age’ (Purcel in Irwin, 1998),
which could also imply the samples tested at these depths are cavings from shallower in the
well.

The perator of the tenement commissioned further age dating of this zone by Ostracod and
Conodont analysis. The analysis concluded that organic matter and phosphatic fragments
found within 2 of the 3 samples at 2200 mRT to 2300 mRT supported an Ordovician age of
the sediments (Jones and Niccol in Irwin, 1998), which gives some confidence that the

50
 Chapter 4 – Stratigraphic Framework

intersected package belongs somewhere within either the Goldwyer Formation, Willara
Formation or Nambeet Formation. It is also possible th t all three formations are present
and correlation difficulties are due to facies changes.

The conclusion here is that an Ordovician aged package is present at Lake Havern 1.

Carribuddy Group

Goldwyer Formation

Willara Formation (?)

Nambeet Formation (?)

Figure 4.5. Lake Havern 1 geophysical log (modified after Irwin, 1998).

51
 Chapter 4 – Stratigraphic Framework

A lack of seismic data precludes the ability to correlate the preserved section from Percival 1
to the study area, however a regional seismic correlation (Figure 4.1 and Figure 5.8) from the
project area to Lake Havern 1 shows Ordovician aged rocks to be present on the Balgo and
Betty Terraces and within the Billiluna Sub-basin. Correlating the geologic units within the
Ordovician package is more difficult due to poor seismic imaging over deeper stratigraphy
across the Gregory Sub-basin.

A key question is thus answered; Ordovician aged stratigraphy exists within the project area.
Another key question – whether the Goldwyer Formation organic shale is present within the
project area; will be considered using paleogeographic reconstructions (discussed below).

Middle Ordovician Depositional Setting

The Lake Havern 1 Ordovician section appears sandier than the preserved section at Percival
1. This is likely because Lake Havern 1 is located nearer to the coastline of the Ordovician
Larapintine Seaway (Cook and Totterdell, 1990, Figure 4.6), whereas Percival 1 is likely
within the neritic zone. The source of the Ordovician sediments at Lake Havern 1 are perhaps
more so derived from a supratidal near shore influence (noted fine grained siliciclastic rocks)
rather than shallow marine/intertidal (carbonates) (Figure 4.7). Both Percival 1 and Lake
Havern 1 indicate periods of intermittent carbonate deposition, which indicates either paleo-
highs or lower base level (relative to marine seaways). The Epeiric Sea present during the
Late Arenigien accommodated basinal shales along the developing Fitzroy Graben (Figure
4.7) noting that the extensional tectonic regime present at the time (Haines and Ghori, 2010)
facilitated increased rates of accommodation generation due to subsidence. The observations
at Percival 1 and particularly Lake Havern 1 portray intersections of low relative base level,
where the Ordovician section may be sandier. It is anticipated that the Ordovician section
(particularly the Goldwyer Formation) in a more basinal location (to the northwest in Figure
4.7) may contain thicker sections of mud-rich (and possibly more organic) stratigraphy.

Abundant macrofossil fauna identified throughout the Goldwyer Formation at Percival 1

suggest a marine influence on sedimentation (Haines, 2004), where individual subunits of the
formation imply varying water depths. The gamma ray log at Percival 1 suggests an overall
base level increase from the base to the top of the Formation, where the top of Unit 2 and
Unit 4 represent flooding surfaces related to broad deepening and shallowing patterns.

52
 Chapter 4 – Stratigraphic Framework

Goldwyer Formations Unit 1 and Unit 2 are interpreted as shallow marine, and Unit 3 and
Unit 4 are interpreted as shallow to restricted marine (possibly lacustrine) (France, 1986).

In answering the second key question; it appears that the study area may have experienced a
greater (c rse grained) siliciclastic dominated paleogeographic setting than Percival 1. This
means that the Goldwyer Formation lithotypes, if present, are potentially sandy in nature and
may lack the organic rich shale lithologies required for a generative source rock for the
Larapintine L2 petroleum system.

Figure 4.6. Paleogeographic map of the Ordovician (modified after Cook and Totterdell, 1990).

53
 Chapter 4 – Stratigraphic Framework

Paleogeography of the
Llanvirian (Ordovician)

Figure 4.7. Paleogeography of the Llanvirnian. Legend

on right applies to all paleogeography maps in this
study (modified after Brown, in Purcel 1984)

Reservoir Properties

Reservoir quality data is elusive for Ordovician aged stratigraphy, however some core
derived porosity and permeability data was obtained from Percival 1 by the well operator
(Figure 4.8). At Percival 1, porosity in the Nita Formation ranges 0.8% to 0.9%, averaging
0.85%. Permeability is reported nil. In the Goldwyer Formation Unit 4 shows porosities of
1.2% to 2.4%, averaging 1.7%, and Unit 3 similarly shows porosities 0.8% to 2.3%,

54
 Chapter 4 – Stratigraphic Framework

averaging 1.5%. Permeability is a maximum of 0.01 mD in Unit 4 and a maximum of 0.3 mD

in Unit 3. Reservoir property data is not available for the Nambeet Formation or Willara
Formation.

Ordovician Ordovician
2000 2000

2010 2010
Percival 1
2020 Φcore, Nita 2020
Fm Percival 1 Κh,
Depth (mRT)

Depth (mRT)
2030 2030
Nita Fm
2040 Percival 1 2040
Φcore, Percival 1 Κh,
Goldwyer Goldwyer Fm
2050 2050
Fm U4 U4
2060 Percival 1 2060
Φcore,
2070 Goldwyer 2070
Fm U3
2080 2080
0 1 2 3 0 0.1 0.2 0.3 0.4
Porosity (%) Permeability (%)

Figure 4.8. Ordovician porosity and permeability data (modified after France, 1984)

The dolomites of the Nita Formation could provide a suitable seal within the Larapintine L2
petroleum system, where Percival 1 shows the interval to be 16 metres thick. Tight porosity,
nil permeability and fast sonic velocities (indicative of low porosity) is suggestive of good
sealing potential in the Nita Formation.

4.3 Late Ordovician

Late Ordovician strata are also not intersected by wells within the study area; however their
occurrence is documented across the Gregory Sub-basin. Stratigraphy of this age primarily
includes the Carribuddy Group. Percival 1 is the nearest well to intersect Late Ordovician
stratigraphy (Figure 4.9). Lake Havern 1 also intersects rocks of similar age, however
Percival 1’s section is regionally correlatable using Haines (2004). The Carribuddy Group
was found to be an interbedded claystone and dolomite sequence containing the Nibil
Member, the Minjoo Marker Bed and the Bongabinni Member.

55
 Chapter 4 – Stratigraphic Framework

A discrete Late Ordovician package was not mappable on seismic data, so inferences of
stratigraphic presence, extent and thickening are summed within the Near Top Ordovician
seismic horizon and seismic interpretation maps, described in subsequent sections.

4.3.1 Carribuddy Group – Bongabinni Member

Characteristics

The Bongabinni Member is described at Percival 1 as deep brownish-grey to blackish sub-

fissile to fissile claystone that is silty and sandy in part (France, 1984). The formation is
known in other regions of the Canning Basin (such as the Willara Sub-basin on the West
Australian coast, Figure 2.1) to be a potential source rock within the present day oil window
(Haines and Ghori, 2006), and excellent oil shows (oil bleeds from core) have been noted at
Cudalgarra 1, along the Admiral Bay Fault Zone (northern margin of the Willara Sub-basin,
Figure 2.1). If the Bongabinni Member is present at depths within the Gregory Sub-basin, or
within the project area, the unit may provide to be a suitable source rock for the Larapintine
L2 petroleum system, and if the unit is sufficiently thick, it’s description leads to the
possibility of it acting as a seal for deeper Ordovician reservoirs.

Geophysical Log Characteristics

Geophysical logs (Figure 4.9) over the interval show a uniform resistivity log response,
invariable sonic and density response, and a hot blocky gamma ray with a slight deflection in
the centre of the unit.

4.3.2 Carribuddy Group – Minjoo Marker Bed

Characteristics

The Minjoo Marker Bed at Percival 1 comprises a thin (3 metre thick) brownish yellow
microcrystalline, argillaceous dolomite (France, 1984).

56
 Chapter 4 – Stratigraphic Framework

Geophysical Log Characteristics

Geophysical logs over the interval show a spike in resistivity, sonic and density logs, and a
sharp deflection in the gamma ray log response over the interval, representing a sharp contact
with the thin dolomite zone (Figure 4.9).

4.3.3 Carribuddy Group – Nibil Member

Characteristics

The Nibil member at Percival 1 is observed as brownish grey soft dolomitic claystone
(France, 1984).

Geophysical Log Characteristics

The Top of the Nibil Member (also top of the Carribuddy Group) is marked by a baseline
shift in gamma ray, resistivity, sonic and density values underneath the overlying basal
Worral Formation carbonate unit. Geophysical logs over the Nibil Member show generally
high gamma ray log values, slight deflections of the resistivity log, sonic and density log in
the upper portion of the Member (1877 mRT to 1885 mRT) (Figure 4.9).

Worral Formation

Carribuddy Group – Nibil Member

Carribuddy Group – Minjoo Marker Bed (3m thick)

Carribuddy Group – Bongabinni Member

Nita Formation

Goldwyer Formation
57
Figure 4.9. Percival 1 geophysical log over Siluro-Ordovician section (modified after France, 1984).
 Chapter 4 – Stratigraphic Framework

Depositional Setting

Overall, the Carribuddy Group represents a supratidal to intertidal/restricted marine

depositional influence, with accommodation also influenced by an extensional tectonic
regime.

The Bongabinni Member is representative of lower flow regime deposition (sub-fissile

claystone and fine sandstone) that appears oxidized in part (Haines, 2009), and was likely
deposited in an intertidal or restricted marine (lagoonal) environment. Haines (2009) notes
that the Admiral Bay Fault Zone hanging wall (nearer the Willara Sub-basin, on the West
Australian coast) includes thicker deposits of the Bongabinni Member due to syn-tectonic
accommodation generation. Brown (in Purcell, 1984, Figure 2.4) notes that the Admiral Bay
Fault Zone was active at a similar time to the Fitzroy Graben, therefore a similar package of
thicker Bongabinni Member mud-rich rocks may exist within the Gregory Sub-basin.

The Minjoo Member, elsewhere in the basin, is represented by a dolomitic mudstone that
grades to halite (Haines, 2009). The observations at Percival 1 indicate that extensive
hypersaline conditions likely did not exist on the Barbwire Terrace, instead mud-rich and
carbonate lithofacies prevailed, indicating lower flow regime deposition and marine
influence. Hypersaline basins were likely present elsewhere at the time.

The Nibil Member is a dolomitic claystone, also indicative of lower plane bed energy. The
Nibil Member was likely deposited in a restricted marine environment, not significantly
different to environmental conditions experienced by that of the other Carribuddy Group
members.

58
 Chapter 4 – Stratigraphic Framework

Paleogeography of the
Late Ordovician -
Silurian

Figure 4.10. Paleogeography of the Late Ordovician to Silurian (modified after Brown, in Purcel 1984)

Reservoir Properties

Description of the Carribuddy Group Bongabinni and Nibil members (fine grained and
therefore tight) indicates possible sealing potential in the Ordovician package. The
Bongabinni log character alludes to source rock potential.

59
 Chapter 4 – Stratigraphic Framework

Discussion – Ordovician Aged Section

There are no discrete mappable packages of intra-Ordovician stratigraphic units on 2D

seismic (Chapter 5.3.7), so TWT seismic interpretation and the products of seismic
interpretation capture a general package under a single Near-Top Ordovician horizon. Two-
ay travel time thickness (Isochron) mapping of the Near Top Ordovician package shows
the thickest section preserved is on the order of 1.6 seconds TWT thickness, down dip of the
Stansmore Fault in the Gregory Sub-basin. The Ordovician thins to 0.3 seconds TWT
westward towards the Jones Arch (a basement high northwest-ward of the study area). The
package thins to approximately 0.4 to 0.6 seconds TWT on the Balgo and Betty Terraces.
Within the Billiluna Sub-basin the Ordovician section is approximately 1 second thick at the
Mueller Fault and thins to approximately 0.3 seconds TWT (and assumed to continue to thin
onto Pre-Cambrian basement) at the near zero edge on the northern basin margin. Generally,
the Ordovician appears thicker in the southern portion of the study area, averaging
approximately 0.6 seconds TWT on the terraces and as thick as 1.6 seconds in the central
project area depocentre. The Ordovician thickens in a southwest direction (basinward), and is
thinner in the north and northwestern portions of the project area.

A clear uncertainty surrounds what Ordovician lithologies exist within the project area,
however as the Pre-Carboniferous stratigraphy thickens into the Gregory Sub-basin (seismic
line RB81-07, Figure 6.5) some confidence is provided that the Ordovician aged section will
thicken from the Barbwire Terrace and Ryan Shelf areas (using the Lake Havern 1
correlation) towards the study area. Paleogeographic reconstructions indicate that the
Goldwyer Formation is potentially sandy in nature and may lack the organic rich shale
lithologies required for a generative source rock for the Larapintine L2 petroleum system.

The Ordovician section has been demonstrated by Haines (2004) to exist regionally across
the Canning Basin. Haines performed a high-resolution correlation using geophysical logs.
The reader is referred specifically to Plate 3 of Haines (2004), where the Ordovician section
is carried from Contention Heights 1 (Kidson Sub-basin) to Percival 1 (Barbwire Terrace)
and across the Fitzroy Trough to Blackstone 1 (Lennar Shelf). Plate 3 demonstrates that the
Ordovician packages (Goldwyer Formation and Nita Formation) thicken substantially from
the Kidson Sub-basin along strike in a northeast direction, and towards the Fitzroy Trough.
The Ordovician correlation across the Fitzroy Trough is perhaps more difficult due to poor

60
 Chapter 4 – Stratigraphic Framework

seismic imaging across the Gregory Sub-basin thick sediment accumulation, and the
Carribuddy Group is shown to be eroded at Blackstone 1.

4.4 Early to Middle Silurian

Regionally, the Silurian aged section comprises the upper-most portion of the Carribuddy
Group known as the Sahara Formation and the marginal marine Worral Formation. Although
these early to middle Silurian aged rocks are not intersected by wells within the study area,
the Worral Formation was intersected at Percival 1 on the Barbwire Terrace. The top of the
Silurian Worral Formation corresponds with the top of the Larapintine L2 Petroleum System.

4.4.1 Worral Formation

Characteristics

The Silurian marginal marine Worral Formation generally unconformably overlies the Late
Ordovician Carribuddy Group. The Worral Formation encompasses a lower Dodonea
Member, a middle Elsa Sandstone Member and an upper Waldecks Member (France, 1984).
The Dodonea Member is a pale grey microcrystalline to cryptocrystalline dolomite that is 11
metres thick at Percival 1. The fluvial Elsa Sandstone Member is an orange fine grained sub-
angular poorly sorted friable sandstone with minor dolomite at its base (France, 1984). It is
42 metres thick at Percival 1. The upper portion of the Worral Formation is the Waldecks
Member, which is an interbedded succession of laminar sub-fissile micromicaceous
claystone, brown calcitic arenaceous siltstone, and translucent medium grained sub-angular to
well-rounded and moderately-sorted indurated sandstone (France, 1984). The Waldecks
Member is 63 metres thick at Percival 1.

Geophysical Log Characteristics

The top of the Worral Formation (Waldecks Member) is marked on geophysical logs (Figure
4.11) as a baseline increase on gamma ray log, resistivity, density and sonic log responses
from the overlying Tandalgoo Formation. The interval has an invariably fast sonic, high
density and mid-range resistivity response; though the gamma ray displays heterogeneity

61
 Chapter 4 – Stratigraphic Framework

over the interbedded claystone lithologies with a coarsening upwards trend. On geophysical
logs the Elsa Sandstone Member is distinguishable due to a blocky gamma ray log response,
and decreasing baselines in the resistivity, sonic and density logs. The Dodonea Member is
observed as an increasing shift in the resistivity, sonic and density logs, and an increase in
gamma ray values over the interval.

Tandalgoo Formation (time equiv. Poulton Formation)

Worral Formation – Waldecks Member

Worral Formation – Elsa Sandstone Member

Worral Formation – Dodonea Member

Carribuddy Group

Figure 4.11. Percival 1 geophysical log over Worral Formation (modified after France, 1984).

Depositional Setting

Overall, the Worral Formation is representative of regressive base level. The Worral
Formation’s basal Dodonea Member suggests some marine influence during Middle Silurian
time. The Elsa Member’s blocky sand is either channel facies with regressed sea level or
aeolian. The Waldecks Member’s interbedded clays and siltstone with sandy intervals
suggests alternating base level and movement of shallow distributaries in a general low
energy environment. It is probable that the coarsening upwards trend on the gamma ray log
suggests a progradational episode. The Top of the Elsa Member’s blocky character could
represent a small scale flooding surface. The Worral Formation’s lower carbonate is probably
a high-stand. The top of the Elsa Sandstone member is likely a sequence boundary, and the
Waldecks Member is evidence of a low-stand systems tract.

62
 Chapter 4 – Stratigraphic Framework

Reservoir Properties

The description of the Worral Formation’s Elsa Sandstone leads to the possibility of the
interval as potential reservoir unit (42 metre thick fluvial sandstone), and the 63 metre thick
sub-fissile claystone. The Waldecks Member may provide a suitable overlying seal. No
reservoir property data was obtainable for the Worral Formation.

4.5 Late Silurian to Devonian

An unconformity (not regionally mappable on 2D seismic data) related to the Late Silurian
Prices Creek Compressional Event separates the Silurian aged section from Devonian aged
rocks. Devonian strata are the oldest that are penetrated by wells within the study area. The
Devonian (Figure 2.3) comprises (oldest to youngest) the Poulton Formation (Tandalgoo
Formation age equivalent), a Devonian aged Conglomerate, Bungle Gap Limestone, Gogo
Formation, Virgin Hills Formation and Knobby Sandstone (with time equivalent Luluigui
Formation and Nullara Limestone).

4.5.1 Poulton Formation

The Early to Middle Devonian Poulton Formation (time equivalent of the Tandalgoo
Formation at Percival 1) was intersected within the project area at Lake Betty 1. Crank (1972)
described the formation in Lake Betty 1 as a grey, fine grained, angular well-sorted
micaceous sandstone, with minor interbeds of brownish grey siltstones and mudstones.

Geophysical Log Characteristics

The top of the interval on geophysical logs (Figure 4.12) is marked by a deflection on the
gamma ray log. Logs over the zone show a slight increasing resistivity trend and coarsening
upward gamma ray log character that represents a transition from interbedded argillaceous
units to sands underneath. The base of the zone shows increases in the GR log and density log
over mud rich intervals. Lake Betty 1 reached Total Depth (TD) within the Poulton
Formation, intersecting 67 metres of the unit.

63
 Chapter 4 – Stratigraphic Framework

Poulton Formation

Figure 4.12. Lake Betty 1 geophysical log over Poulton Formation (modified
after Crank, 1972).

Depositional setting

The fine grained sediments (fine sand, siltstone and mudstone) indicates lower flow regime,
or sediment settling out of suspension. The gamma ray log over the interval shows an overall
upward coarsening sequence, suggestive of a progradational package. A marginal marine
environment is proposed for the Poulton Formation, potentially a deltaic sequence (delta
mouth or prodelta sediments).

Reservoir Properties

The description of the Poulton Formation leads to the possibility of the interval as a potential
reservoir unit, however the fine grained sandstone may be tight (low permeability). No
reservoir property data was obtainable for the Poulton Formation.

4.5.2 Devonian Conglomerate

A Devonian aged conglomeratic sequence (125 metres thick at Atrax 1 and 336 metres at
Selenops 1) is present along the northern border of the project area (partly shown on cross
section A-A’, Figure 4.13). The unit is observed as a range of boulder (200+ mm), cobble (64
– 128 mm) and pebble (2 – 64mm) sized polymict clasts containing orthoquartzite, granite,
dolerite and quartz diorite material (Klappa et al., 1985). Argillaceous siltstones and
feldspathic sandstones commonly make up the matrix. Multiple zones of conglomerate are

64
 Chapter 4 – Stratigraphic Framework

intersected (tops 662 mRT and 721 mRT at Atrax 1 and tops 927 mRT, 1027 mRT, 1034
mRT, and 1187 mRT at Selenops 1) with an interbedded argillaceous siltstone and sandstone
sequence between the deposits.

Geophysical Log Characteristics

Geophysical logs over the interval at Selenops 1 show a marked increasing shift in the
resistivity and sonic log from the Gogo Formation above and decreasing density and gamma
ray log responses within sandier intervals. At Atrax 1 the conglomerate shows a decreasing
shift underneath the Bungle Gap Limestone, within an increase in gamma ray and slowing in
sonic log responses. The interval is observed as an overall coarsening upward gamma ray log
response, shows high-range blocky resistivity, and mostly homogeneous sonic and density
log responses with infrequent stepwise increases over thicker conglomerate horizons. The
interval shares similar variability in all logs throughout the interval (Figure 4.13).

Devonian Conglomerate

Figure 4.13. Atrax 1 (left) and Selenops 1 (right) geophysical logs over the Devonian Conglomerate (modified
after Klappa et.al, 1985a; 1985b).

65
 Chapter 4 – Stratigraphic Framework

Depositional Setting

The conglomerates are probably proximal features of alluvial fan deposits (fan apex or upper
fan) along the northern basin margin, where the interbedded finer clastics represent either
changes to base level or altered positioning of fan distributary systems. The occurrence of
alluvial fans along the northern basin margin follows the Prices Creek Compressional
Movement, which likely provided the uplift to which sediments were then stripped and are
now redeposited as Devonian aged coarse clastics and surrounding associated lithotypes.

Reservoir Properties

Devonian Conglomerate
600

700 Atrax 1
Φsonic
800
Atrax 1
Depth (mRT)

900 Φcore

Selenops 1
1000 Φsonic

1100 Selenops 1
Φcore
1200

1300
0 10 20
Porosity (%)

Figure 4.14. Devonian Conglomerate porosity measurements (modified after

Klappa et al., 1985a; 1985b)

Reservoir property data for the Devonian Conglomerate was obtained via core measurements
and sonic calculated porosities at Atrax 1 and Selenops 1 (Figure 4.14). The Devonian
Conglomerate is shown to have 4.5% to 7.7% porosity at Selenops 1 and 9.6% to 10.9%
porosity at Atrax 1, which makes the interval an attractive reservoir, however no permeability
data is currently at hand. The sonic porosity measurements from Atrax 1 are in good
agreement with core results. The Selenops 1 sonic porosities show variable results, and vary

66
 Chapter 4 – Stratigraphic Framework

by as much as a factor of 2.5 across a similar depth interval, and given the Selenops 1 core
results, the sonic porosities at the same well are perhaps non-representative.

4.5.3 Bungle Gap Limestone

The Middle to Late Devonian Bungle Gap Limestone was intersected at Selenops 1 on the
Balgo Terrace. No other wells intersected the formation. Selenops 1 intersected 59 metres of
Bungle Gap Limestone.

Characteristics

The Bungle Gap Limestone is observed as a grey thick-bedded to massive arenaceous

limestone grading to very calcareous sandstone in part, categorized as a grainstone or
packstone (Klappa et al 1985). Very fine to fine grained quartzose sands are common
throughout the limestone interval. The unit commonly shows biogenic inclusions; commonly
gastropod, foram, bryozoan and ostracod constituents; along with ooids, peloids and
intraclasts. Klappa et al (1985) noted that calcite occludes primary porosity, and fracturing is
also similarly filled.

Geophysical Log Characteristics

Geophysical logs over the interval show a low gamma ray log response that is subtly
coarsening upwards, and also a high-ranging resistivity and sonic log that display a broad bell
shape curve. The resistivity and sonic logs show sharp increasing boundaries that makes the
unit readily distinguishable from the surrounding lithologies (Figure 4.15).

67
 Chapter 4 – Stratigraphic Framework

Bungle Gap Limestone

Devonian Conglomerate

Figure 4.15. Atrax 1 geophysical log over Bungle Gap Limestone (modified after
Klappa et al., 1985a).

Depositional Setting

Klappa et al. (1985) suggests that the clastic components are debris flow deposits of a
marginal slope environment. It’s probable that the Bungle Gap Limestone was deposited in a
transgressive systems tract, where accommodation for carbonate accumulation was provided
by a rising water level that introduced a shallow marine influence within the sequence.
Marginal slope-type sandstones could then represent either higher energy flow (laminar) style
remnants or a brief shallowing of the marginal marine environment with partial distributary
influence.

Reservoir Properties

600
Bungle Gap Limestone

610

620 Atrax 1
Depth (mRT)

Φsonic
630
Atrax 1 Φcore

640

650

660
0 2 4 6 8
Porosity (%)

Figure 4.16. Bungle Gap Limestone porosity measurements (modified

after Klappa et al., 1985a). 68
 Chapter 4 – Stratigraphic Framework

Reservoir property data for the Bungle Gap Limestone was obtained at Atrax 1 via core
measurements and sonic porosity calculations (Figure 4.16). Core porosities range 2.4% to
4.2%, while sonic derived porosities vary up to 6.5%. Permeability data is unavailable for the
interval. Lithological descriptions (secondary calcite and fracture fill) and porosity data
suggest the limestone may not be a suitable reservoir within the study area.

4.5.4 Lennard River Group

The Middle to Late Devonian Lennard River Group was intersected at the Ngalti 1 well on
the Betty Terrace. Ngalti 1 reached Total Depth within the Lennard River Group.

Characteristics

The Lennard River Group is comprised of interbedded limestone, sandstone, siltstone and
minor amounts of claystone. Limestone content increases with depth. The limestone is
observed off-white to buff, cryptocrystalline, silty and slightly fossiliferous, with minor
argillaceous intervals (Smith, 1985b). The basal portion of the Lennard River Group’s
limestone is observed as fossiliferous, with common brachiopods, molluscs and bryozoans,
and shows common peloidal carbonate mud intraclasts, giving evidence of reworking of
limestone sediments (Martin, in Tybor 1985). The sandstone is white, very fine to fine
grained, angular to sub-angular, moderately to poorly sorted, siliceous in part and dolomitic
in part. The Siltstones are light grey, micromicaceous, rarely calcareous and rarely
argillaceous. The claystone is dark blackish grey, firm, micromicaceous, sub-fissile and
dolomitic in part (Smith, 1985b).

Geophysical Log Characteristics

The top of the Lennard River Group (transition) is marked on wireline logs (Figure 4.17) as
an increasing baseline shift in the gamma ray response, increasing baseline shift in resistivity
response, is slightly noisier and faster in the sonic log, and is slightly denser and less variable
in the density response than the overlying Knobby Sandstone. The interval is shown to have

69
 Chapter 4 – Stratigraphic Framework

increasing sonic and resistivity log responses with increasing depth, and an intermittently
high gamma ray log over claystone interbeds.

Lower Knobby Sandstone

Lennard River Group Transition

Nb: Top of Lennard River Group

proper picked off ROP below logged
interval

Figure 4.17. Ngalti 1 geophysical log over Lennard River Group (modified after
Smith, 1985b).

Depositional Setting

The interbedded sandstone, siltstone, claystone and limestone character of the Lennard River
Group alludes to alternating base level between high velocity laminar flow and lower velocity
(turbidity?) currents. It was revealed in work by Martin (in Tybor, 1985) that limestones
commonly show evidence of reworking, so the limestones are possibly redeposited rip-ups
from a near shore marine (suggesting wave influence), into a delta-mouth type environment,
in either the intertidal or swash zone.

Reservoir Properties

The description of the Lennard River Group’s lithology leads to the assumption that the
interval will be impermeable (cryptocrystalline limestone and fine grained siliceous dolomitic
sandstones). If hydrocarbons are present in this zone, it would require a stimulated recovery.
The interval may be a suitable seal. No reservoir property or seal potential data was
obtainable for the Lennard River Group.

70
 Chapter 4 – Stratigraphic Framework

4.5.5 Gogo Formation

Characteristics

The Devonian Gogo Formation consists of laminated and thin bedded medium grey, soft to
firm massive and blocky micromicaceous shales, light greenish grey soft calcareous
argillaceous siltstones, and very fine grained white well-sorted argillaceous sandstone.
Interbedded clastic lithotypes are observed commonly interlaminated with fossiliferous
microcrystalline limestone stringers (Klappa et al, 1985).

Geophysical Log Characteristics

The Gogo Formation is dominated by an aggradational log character of thick, monotonous,

high gamma-ray shales and infrequent lower gamma-ray spikes of thinly interbedded fine-
grained sandstones (Figure 4.18). The gamma-ray log response is accompanied by a
markedly uniform, mid-range resistivity and mid-range density log character. The sonic log
shows only slight variability. The top of the Gogo Formation is marked on geophysical logs
(Figure 4.18) as a gradual increasing baseline shift in the gamma ray log, and decreasing
baseline shift in the resistivity and sonic logs. The top of the interval is also marked by a
deflection in the density curve.

71
 Chapter 4 – Stratigraphic Framework

Virgin Hills Formation

Gogo Formation

Devonian Conglomerate

Figure 4.18. Selenops 1 geophysical log over Gogo Formation (modified after
Klappa et al., 1985b).

Depositional Setting

The Gogo Formation is characterized by aggradational gamma-ray log patterns that are
dominated by finer grained shales and siltstones deposited from suspension settling. Fine-
grained sandstones that are thinly interbedded within the shale-rich sequence were deposited
from traction current processes, suggesting deposition from infrequent turbidity currents.
Regionally, fossiliferous microcrystalline limestone stringers are commonly observed
interbedded with the clastic lithologies suggesting either brief platformal carbonate
deposition or wave energy reworking (thin limestones). The Gogo Formation is interpreted as
resulting from a deeper water basinal environment, with intermittent shallow marine
influence or intertidal zone wave energy reworking.

72
 Chapter 4 – Stratigraphic Framework

Reservoir Properties

escription the t (blocky, massive shales and argillaceous siltstones)

e the possibility of a potential sealing unit within the Devonian section, or a potential
source rock. Source rock potential is examined in Chapter 7. No reservoir property data was
obtainable for the Gogo Formation.

4.5.6 Virgin Hills Formation

The Devonian Virgin Hills Formation was intersected only at Selenops 1 in the northern
project area, between 464 mRT to 767 mRT.

Characteristics

The Virgin Hills Formation consists of interbedded sandstone, siltstone, shales, and
limestone. A limestone interval caps the formation. The andstone is observed as grey, very
fine to fine grained, sub-angular to sub-rounded, moderately well-sorted, argillaceous,
bioturbated, ripple and cross laminated (Klappa et al, 1985). The siltstone is observed as
medium to dark grey, firm, micaceous, pyritic, bioturbated and very argillaceous. The shales
are medium to dark grey, soft and crumbly, micromicaceous and sub-blocky to sub-fissile.
The interval is also interbedded (1 to 3 metre interbed thicknesses) and also capped by tan to
cream, fine and coarsely crystalline, brittle and blocky to massive limestone. The limestone is
described by Klappa et al (1985) as a grainstone or packstone, noting the occurrence of
crinoids, bryozoans, molluscs, brachiopod and peloid fragments.

Geophysical Log Characteristics

The top of the Virgin Hills Formation is marked on wireline logs (Figure 4.19) as a sharp
baseline increase on the gamma ray log, sonic log and density log due to an increase in
argillaceous and calcareous (limestone) rock types over the interval. The Resistivity log
shows a spike at the top of the unit coinciding with a thick (14 metres) limestone bed. The
Virgin Hills Formation unconformably underlies the Grant Group at this location. The
geophysical logs over the interval show a generally homogeneous resistivity and density log

73
 Chapter 4 – Stratigraphic Framework

response, though the sonic log shows slower values along with a lower gamma ray response
between 635 mRT to 717 mRT due to a slight increase in sand content and less limestone
over the zone. The base of the formation is observed as a chaotic response in wireline logs,
however after looking at the logged drilling cuttings, the reason for this chaotic response is
unclear. One possibility is an increase in argillaceous siltstone content.

Depositional Setting

The fine grained character of clastic lithologies suggest a low energy depositional influence.
Bioturbation indicates oxygenation, so deep water is less likely than near shore. Cross
bedding and ripple lamination from core evidence suggests pro-delta sedimentation for mud
rich facies and mouth-bar for fine sands. The erratic interbedded carbonates (packstones and
grainstones) suggest that the limestone zones are perhaps allocthonous detrital (rip ups) rather
than insitu carbonate deposition – a carbonate reef was probably located some distance away
from this location. This is suggestive of wave influence. A progradational system is plausible
here, possibly within a low-stand system.

Grant Group

Virgin Hills Formation

Gogo Formation

Figure 4.19. Selenops 1 geophysical log over Virgin Hills Formation (modified after Klappaet
al., 1985b).
74
 Chapter 4 – Stratigraphic Framework

Reservoir Properties

Reservoir property data was obtained from core measurements and also calculated from sonic
logs at Selenops 1 on the Betty Terrace (Figure 4.20). Sonic calculations indicated 9%
porosity in the upper (purer) limestone interval. Core derived porosities are much more
variable in the upper limestone (though more siliciclastic) zone, ranging 3.7% to 10.5%.
Permeability ranges 0.25 to 1.2 mD at Selenops 1. Porosity data suggests that the Virgin Hills
Formation may be a suitable reservoir target, however permeability data indicates that the
clastic zone may be tight.

Virgin Hills Formation Virgin Hills Formation

470 474
476
475 478
480 Selenops 1
Depth (mRT)
Depth (mRT)

Selenops 1
480 Φcore
Φsonic 482

Selenops 1 484
485
Φcore
486
488
490
490

495 492
0 5 10 15 0 0.5 1 1.5
Porosity (%) Permeability (mD)

Figure 4.20. Virgin Hills Formation porosity and permeability measurements (modified after Klappa et al., 1985b).

4.5.7 Knobby Sandstone

The Late Devonian Knobby Sandstone is a prominent Formation within the study area.
Historically, explorers have viewed it is a conventional reservoir target. It is intersected in
wells Atrax 1 (586.5 mRT to 602 mRT), Lanagan 1 (1508 mRT to 1530 mRT), Ngalti 1
(1067 mRT to 2705 mRT) and Olios 1 (1560 mRT to 1962 mRT). It is mapped from seismic
data to exist regionally across the study area’s tectonic regions.

75
 Chapter 4 – Stratigraphic Framework

Characteristics

At Atrax 1 and Olios 1 (on the Balgo Terrace near the northern basin margin) the Knobby
Sandstone is e as mostly sandstone with minor shale at the base of the interval (for
example 588.4 mRT to 599 mRT at Atrax 1). The sandstone is observed as medium to dark
grey but lightening in colour towards the base, very fine to fine grained, sub-rounded to
rounded, moderately well-sorted, silty in part and planar to cross bedded with rare burrowing
(Klappa et al, 1985). The silty sections are greenish grey, firm, micromicaceous and sub-
blocky to sub-fissile. The basal shale is observed as light to medium grey, sub-fissile,
micromicaceous, pyritic and non-calcareous. Shale rip-ups and a minor zone (trace amounts
to 5% returned cuttings) of black vitreous conchoidal coal also occur at the base of the
interval at Olios 1.

Lanagan 1 (on the Betty Terrace, down dip of Atrax 1 and Olios 1) only intersected the upper
22 metres of the Knobby Sandstone (Lanagan 1 reached TD at 1530 mRT). The formation is
e as sandstone with minor claystone (NSO, 2008). The sandstone is described as
light grey, very fine to fine grained, sub-angular to angular, well-sorted, calcareous in part
and micromicaceous. The claystone is observed as medium grey, firm, sub-blocky to sub-
fissile, calcareous, arenaceous in part, and grades to dark grey shale in part with trace
limestone.

At Ngalti 1 (on the Betty Terrace in the central project area) a thick section of Knobby
Sandstone was te e te . t . et e t is the largest intersection of the formation
within the project area. The Knobby Sandstone is divisible into three sub-units at this
location (Upper 1067 mRT to 1701.4 mRT, Middle 1701.4 mRT to 2179.7 mRT, Lower
21179.7 mRT to 2579.3 mRT).

Upper Unit (1067 mRT – 1701.4 mRT)

The upper unit of the Knobby Sandstone is e as sandstone; clear and translucent, fine
to medium grained. It is also coarse grained in part and grain size coarsens with depth within
the upper unit, where it’s sub-angular, moderatelysorted and argillaceous. Rare zones in core
(e.g. 1072.8 mRT to 1073.8 mRT) include mud pellet rip-ups and show cross bedding and
trough-cross bedding, though is mostly planar bedded. The upper-most portion of the upper
unit also comprises interbedded shale that decreases in occurrence with depth; medium to
dark grey, micaceous and firm (Smith, 1985b).
76
 Chapter 4 – Stratigraphic Framework

Middle Unit (1701.4 mRT – 2179.7 mRT)

The middle unit is observed as an interbedded sequence of sandstone and claystone rip-ups,
and rare interbeds of siltstone. The sandstone is observed as clear, fine to medium grained but
also rarely coarse grained, angular to sub-angular, poorly sorted, rarely argillaceous and
commonly micaceous. The siltstone is observed as medium grey, slightly siliceous and
argillaceous. The claystone rip-ups are pelletal, and occur below 1786.07 mRT. The middle
unit shows common cross beds, trough-cross bedding, rare soft-sediment deformation
structures and is also planar bedded (Smith, 1985b).

The unit shows a slump structure at 1780.3 mRT, consisting of fine grained angular
micaceous sandstone with quartz flour matrix material.

Lower Unit (2179.7 mRT – 2579.3 mRT)

The lower unit is observed as a sandstone interbedded with minor siltstone and claystone.
The sandstone is translucent, fine to medium grained, angular to sub-rounded, well-sorted
and has minor amounts of siliceous cement. Carbonaceous flecks and trace mica is noted. The
siltstone is grey and reddish brown, firm and blocky, micromicaceous, non-calcareous and
pyritic in part. The claystone is white to off-white, moderately firm, carbonaceous in part,
micaceous in part and grades to silty shale in part (Smith, 1985b).

77
 Chapter 4 – Stratigraphic Framework

Geophysical Log Characteristics

Top Knobby
Sandstone
Base Knobby Sandstone

Figure 4.21. (Left to right) Atrax 1, Lanagan 1, Olios 1, Ngalti 1 geophysical logs
over the Knobby Sandstone (modified after Klappa et al., 1984; Klappa et al., 1985a;
Smith, 1985b; NSO, 2008).

78
 Chapter 4 – Stratigraphic Framework

The top of the Knobby Sandstone is marked at Atrax 1 and Lanagan 1 by an inflection on the
gamma ray log, sonic log and density log responses (Figure 4.21). At Olios 1 the top of the
formation is marked by a subtle baseline increase to the gamma ray log response. At Ngalti 1
the top is marked by an increasing baseline shift to the gamma ray log and a decreasing
baseline shift to the resistivity, sonic and density tool responses.

The Knobby Sandstone is observed on wireline log data to show little variability in the
resistivity log response over the interval, except for an increase in values across the blocky
sandstone at Atrax 1. The log response across the interval in all wells shows generally fast
sonic values. The gamma ray response at Atrax 1 shows a characteristic sandstone response.
The gamma ray logs at Lanagan 1, Olios 1 and Ngalti 1 are different in character, with
consistently high trends and is generally quite chaotic (resembling a “saw tooth” character).
The reason for this is likely a combination of altering grain size (very fine grained sandstones
and zones with clays) along with mineralogy – the formation is representative of a fluvial
system that may have a high influx of uranium-rich sediments that results in a ‘hot sand’
gamma ray response. The Knobby Sandstone is observed to contain interbedded zones of
clays however the clay content is probably not prominent enough to produce the observed
geophysical response. A Spectral Gamma Ray log was not acquired in any well, however a
petrography study at Olios 1 suggests that Monazite is the likely radioactive mineral causing
high value responses influencing the gamma ray log (Klappa et al, 1984).

Lanagan 1 and Olios 1 reached TD within the Knobby Sandstone. There is no Wireline log
data below 2693 mRT at Ngalti 1 (i.e. wireline log data does not reach the base of the
Formation).

Depositional Setting

The overall fine-grained character of the sediments observed across all the well intersections
suggests a general low energy and low flow velocity environment of deposition. The
observations at Atrax 1, Lanagan 1 and Olios 1 suggest mid to lower plane bed energy
systems whereas the coarser grains sizes (medium to coarse grained sandstones) observed at
Ngalti 1 suggest mid plane bed grading to upper plane bed (higher velocity planar flow). The
slump deposit in the Middle Unit (1701.4 mRT to 2179.7 mRT) at Ngalti 1 is a collapse
structure during either subaerial exposure or higher-energy soft sediment deformation. One

79
 Chapter 4 – Stratigraphic Framework

key paleogeographic clue is the minor amount of coal observed at Olios 1, which indicates a
near-by terrestrial environment, such as delta plain deposits (the observations of coal at Olios
1 are likely rip-ups). The cross beds, planar beds and burrowing observed at Atrax 1 alludes
to fluvial flood deposits with tidal influence. It is likely that the Knobby Sandstone is
representative of a fluvial dominated depositional setting (Figure 4.22); with Atrax 1, Olios 1
and Lanagan 1 situated distal of sediment supply such as mouth bar or pro delta flood plain.
e t t Ngalti 1 e te ete t e t the Knobby Sandstone likely a mid-
meandering system deposit. The “saw tooth” gamma ray response is suggestive of
t (equal accommodation and sediment supply). The Knobby Sandstone, showing
erosive (slumping) and coal/clay rip-ups (evidence of exposure), is likely representative of a
low-stand or transgressive systems tract.

80
 Chapter 4 – Stratigraphic Framework

Paleogeography of the
Late Devonian

Figure 4.22. Paleogeography of the Late Devonian (modified after Wulff, 1987)

81
 Chapter 4 – Stratigraphic Framework

Reservoir Properties

The Knobby Sandstone shows excellent reservoir quality (Figure 4.23). The operators of
Ngalti 1 also calculated sonic porosities from the Knobby Sandstone, which show good
agreement with core derived measurements (Table 4.1). It is clear that the best reservoir
section at Ngalti 1 is the Upper Unit of the Knobby Sandstone, above 1071 mRT, with an
average of 20.6 % porosity and 567 mD of permeability. Only sonic derived porosities were
derived from the Lower Unit at Ngalti 1 (Table 4.1).

Knobby Sandstone
900

1100 Olios 1
Φsonic

1300
Depth (mRT)

Ngalti 1
Φcore,
1500 Upper Unit

1700 Ngalti 1
Φcore,
Middle
1900 Unit

0 10 20 30
Porosity (%)

Knobby Sandstone - Upper Unit Knobby Sandstone - Middle Unit

1060 1776

1778
1065
1780
Depth (mRT)

1782
Depth (mRT)

1070
Ngalti 1 Κh Ngalti 1 Κh
1784
Ngalti 1 Κv
1075 Ngalti 1 Κv
1786

1788
1080
1790

1085 1792
0 250 500 750 1000 0 50 100 150
Permeability (mD) Permeability (mD)

Figure 4.23. Knobby Sandstone porosity and permeability measurements (modified after Klappa at al., 1984; Smith, 1985b)
82
 Chapter 4 – Stratigraphic Framework

Well Interval Porosity (%, Sonic derived)

Upper Unit

1067 – 1078 mRT 20%

1078 – 1594 mRT 10 – 20%

1600 – 1071 mRT 8 – 11%

Middle Unit

1720 – 1753 mRT 6%

Ngalti 1 1781 – 1802 mRT 8%

2012 – 2021 mRT 8%

2045 – 2062 mRT 5%

2097 – 2105 mRT 5%

Lower Unit

2180 – 2476 mRT 5%

2477 – 2566 mRT 5%

Table 4.1. Ngalti 1 porosity measurements (Smith, 1985b).

83
 Chapter 4 – Stratigraphic Framework

4.5.8 Luluigui Formation

The Late Devonian Luluigui Formation is restricted within the project area to the Gregory
Sub-basin (Smith et al., 2013). It was intersected at Lake Betty 1 (2579.5 mRT to 3078.5
mRT).

Characteristics

The Late Devonian Luluigui Formation is observed as an interbedded sequence of sandstone

and siltstone with minor shale (Crank, 1972). The sandstone is described as whitish to light
and medium grey, fine grained, sub-angular, moderately sorted, micaceous, kaolinitc, rarely
pyritic and variably calcareous. Cross beds and laminations, pebbly claystone and thin
(centimeter-scale) limestones are observed as core features. The siltstone is described as
medium to dark grey, argillaceous but also arenaceous in part, variably calcareous
(containing one inch veins in core), occasionally fossiliferous (pelecypods and ostracods),
and sub-fissile in part. Minor shale is described as dark grey, sub-fissile to blocky, slightly
calcareous, micaceous, and silty in part. Rare slumping is observed (at 2944 mRT in
Lake Betty 1) (Crank, 1972).

Geophysical Log Characteristics

The top of the Luluigui Formation is marked on geophysical logs by a subtle baseline
decrease in the resistivity log and gamma ray log, and a decreasing trend in the density log
response (Figure 4.24). Over the interval, the Formation is characterized by a subtly
increasing though otherwise homogeneous resistivity and sonic response. The decreasing
density log response and increasing resistivity corresponds with gradual increases in
calcareous cuttings. At 2857 mRT there is a baseline increase in the resistivity log and
gamma ray log response along with a sharp increase in the density log, as well as a spike in
the gamma ray. This change corresponds with an increase in calcareous content (calcite
crystals and calcite veining) and a zone of claystone observed in returned core and cuttings.
The Luluigui Formation shows three broad coarsening upwards gamma ray trends (capped at
3000 mRT, 2772 mRT and 2579 mRT).

84
 Chapter 4 – Stratigraphic Framework

Laurel Formation

Luluigui Formation

Poulton Formation

Figure 4.24. Lake Betty 1 geophysical log over Luluigui Formation (modified after
Crank, 1972). Gamma ray trends in green arrows.

Depositional Setting

The observed overall fine grain sizes noted at Lake Betty 1 are representative of a lower
plane bed energy system (low velocity flows). The cross bedded and planar laminated
evidence alludes to flood plain type deposits (lower energy and altering depositional dips)
which were likely subjective to tidal influence. The broad coarsening upward cycles are an
indicator of channel bank or distributary channel facies. This could place the Lake Betty 1
location in a fluvial flood plain or pro delta/delta plain environment, distal from fluvial
sediment supply, showing tidal influence. The Luluigui Formation is likely within a low-
stand systems tract.

85
 Chapter 4 – Stratigraphic Framework

Reservoir Properties

The description of the Luluigui Formation (interbedded fine grained siliciclastics) suggests
that the interval may be a potential reservoir, however it may be tight (low permeability,
indicated by fine grained characteristics). No reservoir property data was obtainable for the
Luluigui Formation.

Discussion and Framework – Devonian Aged Section

The Devonian Conglomerate (found at Atrax 1 and Selenops 1) and Bungle Gap Limestone
(only at Atrax 1) are localized occurrences found in the northwest. Cross section A-A’
(Figure 4.44) demonstrates the framework for this section of the stratigraphy. Note that with
only two well intersections for the lower Devonian packages, the framework represents a
likely overly simplified view of the sequence. Klappa et.al. (1985) suggest that the
continuous high amplitude reflection event that is labeled on seismic line 82GE-33 as an
‘Intra-Devonian Reflection Event’ (Figure 6.4, SP 760 1.7 seconds TWT, below the
reflection poor Knobby Sandstone – the top of which is interpreted as Near Top Devonian)
may represent the Bungle Gap Limestone. Another possibility is that this reflection event
represents the Devonian aged Pillara Limestone (not intersected by wells within the study
area). The Bungle Gap Limestone is not intersected in wells in the southeastern project area;
however the ‘Intra Devonian Reflection Event’ is a commonly noted regionally mappable
horizon (though was not mapped for this project) within the seismic dataset.

The seismically ‘quiet’ zone under the Near Top Devonian horizon makes it difficult to map
the extent of the Devonian Conglomerate, the Gogo Formation and the Virgin Hills
Formation, however as the Poulton Formation is present down dip at Lake Betty 1, it is
thought that the Conglomerate, Gogo and Virgin Hills Formations transition basinward to
equivalents from the Northwestern project area (and the Devonian Conglomerate transitions
into a finer grained lateral equivalent lithology), shown on section A-A’ (Figure 4.44). The
Lanagan 1 and Olios 1 wells are not of assistance as these wells reached TD in the younger
Knobby Sandstone. The Devonian Conglomerate, Gogo Formation and Virgin Hills
Formation are not intersected in wells in the southeastern project area.

The Knobby Sandstone and time equivalent Luluigui Formation are arguably the most
prominent Devonian formations in the region (intersected by all wells except Bindi 1, Kilang

86
 Chapter 4 – Stratigraphic Framework

Kilang 1 and Selenops 1). The Knobby Sandstone is generally thick – in excess of 400 metres
in most of the wells across the study area, shown on cross sections A-A’, B-B’ and C-C’
(Figure 4.44 to Figure 4.46). Well correlation illustrates that the unit slightly thickens down
dip into the Gregory Sub-basin in the northern project area (A-A’). In the south the unit is
anticipated to thicken dramatically, demonstrated on B-B’ and the Siluro-Devonian Isochron
(Figure 6.24, southwest of Ngalti 1). Seismic line RB81-7 (Figure 6.5) also suggests
thickening of the entire Siluro-Devonian section down dip across the Stansmore Fault. The
Knobby Sandstone is known to exist on the Betty Terrace (at Ngalti 1) and interpreted to
continue across the Balgo Terrace in the central and southern portion of the study area. The
Knobby Sandstone is anticipated to be more limited in its occurrence in the northwestern
study area – it thins at Atrax 1 to 15m thick, and truncates under the Meda Transpression
Unconformity before reaching the Selenops 1 well to the west (Klappa et.al, 1985). The
Knobby Sandstone is suggested to be the youngest formation in the Billiluna Sub-basin from
surface geology information (aside from an alternative Fairfield Group interpretation; refer
seismic interpretation in Chapter 6.2.3, which has no external data tie).

4.6 Carboniferous

4.6.1 Fairfield Group – Laurel Formation

The Early Carboniferous (Tournaisian) Laurel Formation is a regionally prominent

stratigraphic package across the Canning Basin. The Formation contains a regionally
mappable carbonate marker. The Laurel Formation is mapped using 2D seismic data to
exist within the project area. The formation was te e te in six petroleum exploration
wells within the project area. The tops of the formation are shown in Table 4.2 and Figure
4.25.

87
 Chapter 4 – Stratigraphic Framework

WELL Lake Betty 1 Kilang Kilang 1 Bindi 1 Lanagan 1 Ngalti 1 Olios 1

Top Laurel
Formation 1658.28 1717.0 2474.0 983.3 796.0 883.0
(mRT)

Top Laurel
Not
Carbonate 2305.0 Not Intercepted 983.3 796.0 1131.0
Intercepted
(mRT)

Base
Laurel Not
2459.7 Not Intercepted 1292.3 1015.6 1431.0
Carbonate Intercepted
(mRT)

Not
Base
Not Intercepted Intercepted
Laurel
2579.5 (Well TD within (Well TD 1508.0 1037.5 1560.0
Formation
Formation) within
(mRT)
Formation)

Table 4.2. Summary of Laurel Formation intersections within project area. Tops derived from geophysical logs.

Characteristics

The Laurel Formation is mainly a clastic sequence with zones of limestone (the Laurel
Carbonate). Within the project area, the Laurel Formation is characterized by interbedded
sandstone, siltstone, minor claystone, shale and limestone (Smith, 1985a; 1985b; and Klappa
et al, 1985). The Sandstone across most of the project area is coloured clear translucent to
medium grey, very fine to fine grained, silty in part and also argillaceous in part, sub-angular
to sub-rounded, moderately sorted, slightly calcareous and also friable in part (at Olios 1)
(Klappa et al, 1985). The sandstone is noted fine to medium grained at the Bindi 1 location
(Lehmann and Haines, 1985) and generally medium grained and massively-bedded at the
Kilang Kilang 1 location (Smith, 1985a). The siltstone is observed as greyish brown,
calcareous, slightly to moderately carbonaceous, micaceous and sub-blocky to sub-fissile (at
Kilang Kilang 1) (Smith 1985a). The claystone is observed as grey to dark grey, very soft,
non-calcareous, arenaceous in part, micromicaceous and blocky to sub-fissile. The shale is

88
 Chapter 4 – Stratigraphic Framework

observed as medium to dark grey, blocky to fissile, shows a waxy texture in part, pyritic in
part and arenaceous in part (Smith, 1985a).

The limestone is generally concentrated to thick intervals, known as the Laurel Carbonate
marker (for example 2305.0 mRT to 2459.7 mRT at Lake Betty 1, Table 4.2) however
relatively thin limestone interbeds are noted within the Laurel Formation. The interbedded
limestone is noted as cream, buff and light brown to grey, finely to microcrystalline and
fossiliferous (Crank, 1972).

The Laurel Carbonate marker is composed of a limestone, or interbedded unit of predominant

limestone with fine-grained clastics. Within the project area, the Carbonate markers
limestone is tan and greyish brown, finely to microcrystalline and cryptocrystalline,
moderately fossiliferous (noting crinoids, pelecypods and brachiopods), and is classified as a
wackestone to grainstone (Klappa et al, 1985). Interbedded zones contain brownish siltstone
grading to very fine sandstone. The carbonate at Lanagan 1 is also interbedded with medium
grey, soft, sub-blocky claystone. At Olios 1 the marker is interbedded with minor very fine
grained sub-angular to sub-rounded silica cemented sandstone (Klappa et al, 1985).

Geophysical Log Characteristics

The Early Carboniferous Laurel Formation is truncated in part by the Meda Transpression
Unconformity. The reader is referred to Chapter 5.3.1 and Chapter 6.2 of this study for
insights into the degree of erosion. The seismic interpretation Figures, particularly line RB81-
7 and RB81-10 (Figures 6.5 and 6.7), demonstrate the relationship between the top of the
Laurel Formation (or top of the Laurel Carbonate where the upper Laurel Formation
sequence is eroded by truncation) to the Meda Transpression Unconformity. Importantly, the
truncation effect of the unconformity means that the top of the Laurel Formation is often
different between wells, and consequent there are varying amounts of preserved Laurel
Formation above the Laurel Carbonate.

The thickest succession of Laurel Formation above the Laurel Carbonate was encountered at
Lake Betty 1 (646.72 metres) and a 248 metre thick section is preserved above the carbonate
at Olios 1 (Figure 4.25). All other locations either did not intersect the Laurel Carbonate, or
the upper portion of the Laurel Formation was eroded.

89
 Chapter 4 – Stratigraphic Framework

In every case where the upper Laurel Formation is encountered within the project area, the
top of the interval is marked by a baseline increase in the gamma ray log response and a
baseline decrease in the sonic log. The Laurel formation (both the section above the Laurel
Carbonate and the section below the Laurel Carbonate) are characterized by a “saw tooth”
gamma ray response (e.g. 1750 mRT to 1850 mRT at Kilang Kilang 1 and 1450 mRT to 1550
mRT at Olios 1) and coarsening upward gamma ray responses (1000 mRT to 1020 mRT at
Olios 1 and 1800 mRT to 1900 at Lake Betty 1). Blocky gamma ray log responses are also
noted (for example 1900 mRT to 1950 mRT at Kilang Kilang 1). Two funnel (or bell curve)
trends in the gamma ray log are noted at Kilang Kilang 1, that show a coarsening upward and
then fining cycle capped by an abrupt deflection in the log at 2210 mRT to 2300 mRT,
followed by a (inverted) fining then coarsening upward cycle at 2120 mRT to 2210 mRT.

A major character change in wireline log response occurs at the intersection of the Laurel
Carbonate (Figure 4.25). The top of the Laurel Carbonate is marked on geophysical logs by a
pronounced baseline decrease in gamma ray log, together with a distinct increasing shift in
baseline to the sonic, density and resistivity log responses. Over the carbonate interval the
sonic and density log responses remain invariable, and are high (density) and fast (sonic). The
resistivity log response over the interval is invariable at Lake Betty 1, though other wells that
intersect the Laurel Carbonate show “saw tooth” variability in the resistivity log. The gamma
ray log over the interval displays a very subtle funnel character toward lower values (lowest
response in the centre of the carbonate and higher in the transition zones at the top and base
of the carbonate interval).

The lower portion of the Laurel Formation (below the Laurel Carbonate) is similar in
appearance to the upper portion in observed geophysical log characteristics. The base of the
Laurel Carbonate is marked by an increase in baseline in the gamma ray response, and
baseline decreases to the resistivity, density and sonic log responses. The gamma ray log over
the lower portion of the Laurel Formation shows a “saw tooth” response, and perhaps shows
a very subtle overall fining upwards trend in all wells that intersect this lower portion (for
example 2480 mRT to 2550 mRT at Lake Betty 1, Figure 4.25).

90
 Top/Base of Laurel Formation
Top/Base of Laurel Carbonate

Figure 4.25. Geophysical logs over Laurel Formation across project area. Wells are labelled, (modified after Crank, 1972; Klappa et al., 1984; Lehmann and Haines, 1985; Smith, 1985a; 1985b;
NSO, 2008; Cookson and Jones, 2013). Fining patters indicated by green arrows. 91
 Chapter 4 – Stratigraphic Framework

Depositional Setting

The overall fine to very fine sandstone, and finer grained clastic lithologies indicate a low
energy depositional setting, suggestive of lower plane bed energy. Intermittent limestone
deposition and a significant limestone package (The Laurel Carbonate) is key to determining
some marine influence in Early Carboniferous time. The interbedded fine sandstone, siltstone
and clays suggest periods of altering water levels. This is supported by the funnel shape
gamma ray curves at Kilang Kilang 1; 2210 mRT to 2300 mRT illustrates a coarsening up
trend followed by a fining parasequence cycle capped by an abrupt deflection in the log that
likely represents a transgressive surface, followed by a second (inverted) funnel shape; fining
then coarsening upward cycle at 2120 mRT to 2210 mRT (Figure 4.26).

Top of Laurel

LST
FS

SB?
FS

FS HST

MFS
TST
TSE
FS

Figure 4.26. Kilang Kilang 1 geophysical log. Sequence stratigraphic analysis

overlain (modified after Smith, 1985a). Green arrows indicate fining patterns.

92
 Chapter 4 – Stratigraphic Framework

Figure 4.26 illustrates alternating base level in sequence stratigraphic terms. A maximum
flooding surface (MFS) is noted at 2170 mRT. The sharp deflection in the gamma ray log
response at 2210 mRT is likely a transgressive surface of erosion (TSE). Together, the Laurel
Formation at Kilang Kilang 1 represents a Transgressive sequence followed by a period of
high relative base level accommodating sediment supply (high stand systems tract, HST). A
low stand systems tract (LST) follows to the top of the Laurel Formation. The inference from
this analysis, is that the time equivalent section to the Laurel Carbonate (not present in this
well) is potentially in the zone between 2000 mRT to 2200 mRT; where a high stand at
Kilang Kilang 1 allows higher base level in an up-dip location, thus facilitating a carbonate
prone environment (refer paleogeographic map, Figure 4.27).

The Kilang Kilang 1 well is likely in a basinal position (down dip) relative to prime reefal
carbonate deposition, which explains why the primary carbonate zone is not found in the
well. The Bindi 1 well was not drilled deep enough to te e t the Laurel Carbonate. The
Laurel formation was likely deposited in a marginal marine or lacustrine type setting.

93
 Chapter 4 – Stratigraphic Framework

Paleogeography of the
Early Carboniferous

Figure 4.27. Paleogeography of the Early Carboniferous (modified after Wulff, 1987).

Reservoir Properties

Sonic derived porosities were calculated at Kilang Kilang 1 and Olios 1 for zones in the
Laurel Formation (Table 4.3). Olios 1 sonic porosities show excellent reservoir potential in
the upper clastic zone (ranging 12.1% to 22%) and also in the lower clastic zone (16.7% to
19.8%), below the carbonate (Figure 4.28). At Kilang Kilang 1, reservoir quality decreases
(though is still attractive) likely due to deeper burial at Kilang Kilang 1, and likely higher
proportions of finer grained clastics; with a more porous zone below 1981 mRT (up to 17%

94
 Chapter 4 – Stratigraphic Framework

sonic porosity). No data is available for the carbonate section, however the description (finely
crystalline fossiliferous limestone) suggests that reservoir potential exists for the zone.

Well Interval Porosity (%, Sonic derived)

1714 – 1755 mRT 9%

1760 – 1872 mRT 8%

1883 – 1978 mRT 8 – 9%

1981 – 2003 mRT 17%

Kilang Kilang 1
2016 – 2068 mRT 8 – 10%

2086 – 2124 mRT 8 – 10%

2173 – 2214 mRT 10%

2235 – 2251 mRT 12%

Table 4.3. Kilang Kilang 1 porosity data for the Laurel Formation (Smith, 1985a).

95
 Chapter 4 – Stratigraphic Framework

Laurel Formation
800

900

1000

1100
Depth (mRT)
1200 Olios 1
Φsonic
1300

1400

1500

1600
0 10 20 30
Porosity (%)

Figure 4.28. Laurel Formation porosity measurements (modified

after Klappa, 1984).

4.6.2 Anderson Formation

The Early-Middle Carboniferous Anderson Formation is a conformable sequence of variable

amounts of interbedded sandstone, siltstone and claystone, subdivided into seven units; ‘A’ to
‘G’, oldest to youngest. The Anderson Formation lies conformably above the Laurel
Formation. The top of the Anderson Formation lies unconformably underneath the Grant
Group. The Carboniferous Meda Transpression divides the Grant Group from the Anderson,
often implicating significant truncation. The Anderson Formation is completely removed by
erosion across large portions in the northern project area and southeastern project areas, and
is preserved in complete package in the central project area (refer to Anderson Formation
Isochron, Figure 6.22). Kilang Kilang 1 intersected a condensed section (1448 mRT to 1717
mRT, 269 metres thick), whereas the ee e e t t Bindi 1 (1832 mRT to 2474.5
mRT, 642.5 metres thick) is the e t in the project area. Figure 4.29 illustrates sub-unit
division at Kilang Kilang 1 and Bindi 1.

96
 Chapter 4 – Stratigraphic Framework

Age

Biostratigraphic dating at Bindi 1 places the following ages on the observed stratigraphy,
obtained from side-wall cores (Purcel, in Lehmann and Haines, 1985).

Suggested Age
Depth (mRT) Sub-unit Palynological unit
(stage)

G. maculosa Assemblage / Tournaisian –

1918.7 Lower Unit G
A. frustulentus Microflora Westphalian

1999.4 Indeterminate

2173 – 2481.4 Unit C, Unit B, Unit A G. frustulentus Microflora Tournaisian – Visean

Table 4.4. Age of the Anderson Formation (Purcel, in Lehmann and Haines, 1985).

Characteristics

Unit A

The deepest unit of the Anderson Formation comprise interbedded white, co e grained,
loose angular well-sorted quartzose sandstone; mottled brown micaceous, massive,
slickensided claystone; and dark brown micaceous arenaceous siltstone (Lehmann and
Haines, 1985). Unit A at Kilang Kilang 1 is similarly observed as at Bindi 1, however the
concentrations of siltstone and claystone are considerably less (Smith, 1985a).

Unit B

Unit B of the Anderson formation comprise a massively bedded quartzose sandstone; pale
greenish grey, coarse grained but also medium in part, rarely granular in part, sub-angular
to sub-rounded, and poorly sorted. Rare siltstone occurs in the unit, described as per Unit C
below (Lehmann and Haines, 1985).

97
 Chapter 4 – Stratigraphic Framework

Unit C

Unit C is observed as a medium purplish brown rarely carbonaceous massively bedded

siltstone that grades in part to non-fissile claystone; and grey and greenish brown fine to
medium grained, sub-angular to sun-rounded quartzose and micaceous sandstone (Lehmann
and Haines, 1985). The basal 13.5 metres of the sub-unit grades to very-coarse grained, and is
also described as loose and well-sorted.

Unit D

Unit D is observed as massively bedded quartzose sandstone. The sandstone is described as

transparent off-white to pale grey, mainly coarse with minor medium and also very coarse
grains in part, angular to sub-angular, occasionally aggregated showing variably silicified
quartzose grains, and a pyritic and argillaceous matrix. Variably developed quartz crystals
and secondary overgrowths visible (Lehmann and Haines, 1985).

Unit E

Unit E is a mottled and variably coloured purplish to brownish micromicaceous massively

bedded claystone that is arenaceous in part and grades to siltstone in part (Lehmann and
Haines, 1985).

Unit F

Unit F is similar to Unit D. It is observed as a massively bedded quartzose sandstone. The

sandstone is described as transparent off-white to pale gray, coarse grained with minor
medium and also very coarse grains in part, angular to sub-angular, occasionally aggregated
showing variably silicified quartzose grains, and a pyritic and argillaceous matrix. Variably
developed quartz crystals and secondary overgrowths are noted (Lehmann and Haines, 1985).

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 Chapter 4 – Stratigraphic Framework

Unit G

The shallowest subunit, Unit G, is comprised of claystone and sandstone. The claystone is
observed as pale and light green to maroon, moderately firm to slightly friable, rarely
carbonaceous, micaceous, occasionally slickensided and massively bedded. The Sandstone is
off-white to pale grey, medium to coarse grained but also fine to medium grained aggregates
noted, angular to well-rounded, loose, moderately to well-sorted, showing quartz crystal faces
and overgrowths (Lehmann and Haines, 1985). The unit at Kilang Kilang 1 is also observed
to contain an argillaceous dolomitic zone between 1462 mRT to 1480 mRT (Smith, 1985a).
A Trace amount of greyish black to black brittle coal is observed at Lawford 1 (Cookson and
Jones, 2013).

Geophysical Log Characteristics

The top of the Anderson Formation is marked on geophysical logs by a large inflection on the
gamma ray log and subtle deflection (over the uppermost 3 metres) on the resistivity log
response. The wireline log responses over the Anderson Formation’s 7 subunits are variable,
and provide the basis for the subunit division that is shown in Figure 4.29.

Unit A

The top of Unit A at is marked by an inflection on the gamma ray log that is well pronounced
at the Bindi 1 location. The top of the subunit is also noted by a slight baseline decrease in the
resistivity log, sonic and density log responses. The gamma ray log over the zone at Kilang
Kilang 1 is relatively clean and subtly fining upwards, whereas the same zone at Bindi 1
shows a hotter and more variable gamma response, due to a higher concentration of fine
grained clastics (siltstone and claystone interbeds) than at Kilang Kilang 1. The resistivity
and sonic logs are generally mid-range and homogeneous. Correlating Unit A of the
Anderson Formation is perhaps the most dubious..

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 Chapter 4 – Stratigraphic Framework

Unit B

The Top of Unit B is marked on wireline logs by a distinct baseline decrease in the gamma
ray log underneath Unit C. The top is also marked by a pronounced baseline increase to the
resistivity and sonic logs. The zone is characterized by a relatively clean and blocky gamma
ray log response (with the exception of increases to the log response at 2310 mRT at Bindi 1
and 1650 mRT), and largely invariable resistivity, density and sonic log responses.

Unit C

The top of Unit C is shown by a significant baseline increase to the gamma ray log response
underneath Unit D, along with baseline decreases to the resistivity sonic and density tools.
Unit B is characterized by a hot and blocky gamma ray log response, invariable resistivity
and sonic responses, and a chaotic response in the density log across the unit.

Unit D

The Top of Unit D is marked by a baseline decrease to the gamma ray log underneath Unit E.
The resistivity, sonic and density logs also show a baseline increase to their respective
responses. The gamma ray log is generally blocky over the zone however is also subtly fining
upwards in the upper portion of the subunit (from 2090 mRT at Bindi 1 and 1560 mRT at
Kilang Kilang 1). The sonic and density log responses are homogeneous. The resistivity log
response is also generally invariable although shows a subtle decreasing upwards trend from
2090 mRT at Bindi 1.

Unit E

Unit E is a thin zone at both well locations (thickest at Bindi 1; 26 metres), and is observed
on geophysical logs as a pronounced baseline increase on the gamma ray log, and a baseline
decrease to the resistivity, sonic and density log responses (though the resistivity log at
Kilang Kiang 1 shows an inflection). The gamma ray, sonic, density and resistivity log
responses are variable in character with infrequent zones of high values in each log
corresponding to high percentages of claystone (observed as a similar log package as Unit C).

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 Chapter 4 – Stratigraphic Framework

Unit F

The top of Unit F is observed as a prominent baseline decrease to the gamma ray log and
sonic log responses. The resistivity log response at Bindi 1 shows a baseline increase though
the opposite response is noted in the same interval at Kilang Kilang 1. Across the unit, all log
responses are invariable and blocky. The inconsistency is also noted in the density log
response.

Unit G

Unit G is observed as an (upper) fining-upward gamma ray log response and a (lower) hot
and blocky gamma ray response at Bindi 1 (1860 mRT to 1900 mRT, not observed at Kilang
Kilang 1). The resistivity log is invariable across the zone at Bindi 1, though the log shows a
blocky character at Kilang Kilang 1 together with a step up (blocky character) in density and
sonic responses at 1463 mRT, which represents the zone of argillaceous dolomite observed in
drill cuttings. The density log and sonic logs at Bindi 1 show reduced and variable (chaotic)
responses over the Unit G interval.

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 Chapter 4 – Stratigraphic Framework

Unit G

Unit F

Unit E

Unit D

Unit C

Unit B Anderson Formation

Unit A

Figure 4.29. Geophysical logs over the Anderson Formation. Wells are labelled (modified after Lehmann and Haines, 1985;
Smith, 1985a; Cookson and Jones, 2013).

Depositional Setting

Noticeable variability in observed lithologies and geophysical log characteristics across the
Anderson Formation allude to alternating water depths and flow velocities, suggestive of
variable depositional settings during Early – Middle Carboniferous time.

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 Chapter 4 – Stratigraphic Framework

Units A, C, E and G represent periods of lower energy environments and likely lower plane
bed velocities, whereas Units B, D and F represent periods of higher energy environment,
likely upper plane bed energy.

Palynology evidence acquired at Bindi 1 between 1641.1 mRT to 2224.9 mRT (Units C to G)
and 2348.1 mRT to 2481.4 mRT (Unit A) both concluded that preserved palynomorphs were
severely oxidized, suggesting sub-aerial exposure of the sediments. A Trace amount of coal
observed in Unit G at Lawford 1 alludes to either an exposed terrestrial environment or a high
energy (rip ups) from a neighboring coal deposit.

Considering the deeper Laurel Formation represents a period of marginal marine influence, it
is possible that the lower-most unit of the Anderson (Unit A) also shares a similar influence.
This is supported in sequence stratigraphic terms by Figure 4.30, showing Unit A within a
transgressive sequence (TST), leading into a high stand (HST) at the top of Unit C. the
gamma ray log clearly represents a trend of coarsening overall grain size throughout
Anderson Formation sedimentation (common finer clastics at the base, and abundance of
coarser clastics up-section). A low stand is evidenced in Figure 4.30 from the sequence
boundary (SB) at 2160 mRT toward the top of the Formation.

It is probable that the lower section (Unit A) represents a conclusion to a marginal marine (or
estuarine) setting (that was prevalent during Laurel Formation deposition). Units B and C
probably signal a transgressive coast, such as a strand-plain or wave dominated estuary
(noting that sedimentary structures were not observed in the absence of whole core data,
however coarse grained sands are prevalent in Units B, D and F). A change to a regressive
coast is likely from the sequence boundary (SB) at 2160 mRT. At this point base level
decreased to accommodate a progradational marine influence with fluvial influence such a
deltaic environment, suggested by upper plane bed flow regimes and observed coal rip ups.
The sand bodies within Units B, D and F are probable stacked delta lobes.

103
 Chapter 4 – Stratigraphic Framework

FS Top of Anderson Formation

FS

FS
LST

SB?

FS
HST

FS
MFS

FS TST

Figure 4.30. Bindi 1 geophysical log. Sequence stratigraphic analysis overlain (modified after
Lehmann and Haines, 1985). Green arrows indicate fining patterns.

Reservoir Properties

Sonic derived porosities were calculated by the well operators at Kilang Kilang 1, Bindi 1
and Lawford 1, presenting average to good reservoir quality (Table 4.5). Sonic porosities at
Bindi 1 suggest that Units A (6% - 11%), C (8.5%), and G (13%) retain the better reservoir
quality data, however this is arguably deceptive given the gamma ray log; where it is perhaps
expected to have more favourable reservoir properties in units D and F (a low stand system).
Sonic porosities are lower in these zones at Bindi 1 (averages of 5% and 7% respectively),
though the sonic log clarifies the reasons for the reported results (due to slower average
transit values in zones A, C and G). No core derived data exists for the Anderson Formation.

104
 Chapter 4 – Stratigraphic Framework

From the gamma ray log at Bindi 1, it is anticipated that Anderson Units B, D and F represent
candidate reservoir intervals, and Units A, C, E and G represent candidate sealing intervals.

Porosity (%, Sonic

Well Unit Interval
derived)

Anderson Fm G and F 1481 – 1511 mRT 13%

Kilang Kilang 1
Anderson Fm E to A 1515 – 1710 mRT 10 – 20%

8 – 20%, Average
Anderson Fm G 1832 mRT
13%

Anderson Fm F 1919 mRT 3 – 11%, Average 7%

Anderson Fm D 2023 mRT 3 – 10%, Average 5%

5 – 15%, Average
Anderson Fm C 2158.5 mRT
8.5%

Anderson Fm B 2237 mRT 3 – 10%, Average 5%

Bindi 1
Anderson Fm A 2332.5 mRT 5 – 13%, Average 8%

Anderson Fm A 2386 – 2389.5 mRT 11%

Anderson Fm A 2398 – 2405 mRT 6%

Anderson Fm A 2409.5 – 2421.5 mRT 9%

Anderson Fm A 2436.5 – 2439.5 mRT 11%

Anderson Fm A 2443.5 – 2452 mRT 9%

Lawford 1 Anderson Fm G to A 1661 – 2645 mRT 9.4%

Table 4.5. Anderson Formation porosity measurements (Lehmann and Haines, 1985; Smith, 1985a; Cookson
and Jones, 2013).

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 Chapter 4 – Stratigraphic Framework

Discussion and Framework – Carboniferous Section

The Carboniferous aged section is known from well data to exist within the study area, and
h ee mapped from 2D seismic to extend regionally. The Fairfield Group isochron
(containing the Laurel Formation and Laurel Carbonate) is presented in Figure 6.23 and the
Anderson Formation isochron is shown on Figure 6.22. The Fairfield Group is mapped to be
the thickest down dip of the Stansmore Fault, thickening to 800 milliseconds TWT before
thinning to 231 milliseconds thickness on the Kilang Kilang 1 high (20° 08’S, 127° 08’E).
The Fairfield Group continues as a thick package to the south into the southern Gregory Sub-
basin (20° 26S, 127° 31E), he e t anticipated to exceed 903 milliseconds TWT
thickness. Across most of the Betty and Balgo Terraces the Fairfield Group package exists
averaging 200 milliseconds TWT thickness. The Fairfield Group is truncated in the northern
project area before reaching the Atrax 1 and Selenops 1 wells. A thicker portion of the
Fairfield Group is noted atop the Billiluna Sub-basin graben (on the foot wall of the Mueller
Fault, 19° 36S, 127° 34E) at a maximum of 519 milliseconds TWT thickness. The seismic
interpretation (refer RB81-7, Figure 6.5) indicates a possible package of Fairfield Group in
the Billiluna Sub-basin that reaches a near zero edge at the northeast basin margin (19° 30’S,
127° 35’E).

The Fairfield Group is intersected in wells Bindi 1, Kilang Kilang 1, Lake Betty1, Lanagan
1, Ngalti 1, Lawford 1 and Olios 1. Cross sections A-A’ (Figure 4.44), B-B’ (Figure 4.45)
and C-C’ (Figure 4.46) demonstrate the stratigraphic framework for the Fairfield Group
(including the Laurel Carbonate). Well data confirms that the Fairfield Group thickens
basinward (section A-A’ and B-B’) off the Betty and Balgo Terraces into the Gregory Sub-
basin. It is apparent that primary carbonate buildup (the Laurel Carbonate) was concentrated
on the Betty Terrace during Early Carboniferous time, between the Selenops 1/Atrax 1 area
(19° 25’S, 127° 40’E) to the Lanagan 1/Lake Betty 1 area (19° 35S, 126° 25’E), and along
depositional strike towards Ngalti 1 (19° 52’S, 127° 18’E). As Ngalti 1 intersected a similar
thickness of carbonate to that t Lake Betty 1 (approximately 200 metres t each), and as the
carbonate thickens substantially up dip at Olios 1, a suitable model would show carbonate
development continuing up dip from Ngalti 1. The Carbonate transitions to fine grain
lithotypes before reaching the Kilang Kilang 1 location (section B-B’, Figure 4.45). A
schematic showing a primary Laurel Carbonate depositional model is shown in Figure 4.27.

Seismic interpretation and isochron mapping demonstrates the extent of the preserved section
of Anderson Formation within the project area. The Anderson Formation is either part
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 Chapter 4 – Stratigraphic Framework

removed (shown on line 82GE -33, Figure 6.4) or completely removed (shown on RB81-7,
Figure 6.5) by truncation of the Meda Transpression Unconformity. The Anderson Formation
isochron (Figure 6.22) clearly reveals the erosive outcome of the Meda Transpression
Unconformity. The Anderson Formation is completely removed from large tracts of the
project area. The Formation is only partly preserved to approximately 200 milliseconds TWT
thickness across the southeastern Betty and Balgo Terraces. The thickest mapped preserved
section is in the central project area, surrounding the Bindi 1 location (19° 43’S, 126° 49’E).
It is anticipated that more preserved section of Anderson Formation could exist northeast of
Bindi 1 (around 19° 34’S, 126° 58’E) where the isochron reaches a maximum of 1439
milliseconds TWT thickness. A relatively thick section (between 303 to 831 milliseconds
TWT thickness) of preserved Anderson Formation is also mapped to exist in the hanging wall
of the Stansmore Fault west of Kilang Kilang 1 (20° 11’S 127° 17’E). A preserved section is
mapped to continue northwest along the Betty Terrace out of the project area, west of Atrax
1. The Anderson Formation does not extend north of the Mueller Fault onto the Billiluna
Sub-basin.

4.7 Permo-Carboniferous

4.7.1 Grant Group and Reeves Formation

The Grant Group is a variably conformable succession of interbedded sandstones, siltstones

and claystones. The Grant Group lies uncomfortably above the Anderson Formation (where
the Anderson Formation is preserved) or over the Laurel Formation (where the Anderson
Formation is removed by truncation). The base of the Grant Group is mapped on 2D seismic
data as the regional Meda Transpression Unconformity, which separates Carboniferous and
older strata from the Permo-Carboniferous and younger sediments. The Grant Group is
mapped from seismic data to exist regionally within the project area, cropping out on the
Balgo Terrace (refer t the Grant Group isochron, Figure 6.21) in the north and on the
eastern basin margin. The Grant Group is intersected in all wells within the project area.

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 Chapter 4 – Stratigraphic Framework

Age

Subdivisions of the Grant Group have proved difficult to correlate across the Canning Basin
(Apak and Backhouse, 1999), and age control is sparse due to a lack of well intersections.
Figure 4.31 demonstrates the variations in nomenclature of the Grant Group members. Apak
and Backhouse (1998) redefined the Grant Group using available palynology data over the
Barbwire Terrace, where they carry the upper section as the ‘Grant Group’ and a lower
blocky sandstone renamed as the Reeves Formation (after Reeves Hill, a location west of the
exploration well Fraser River 1, where the type-section for the Reeves Formation is derived).
Apak and Backhouse (1999) place the members of their Grant Group within the
Pseudoreticulatispora confluens Zone (Asselian to Sterlitamakian stage of the Early
Permian). The Reeves Formation (formerly included within the Grant Group) is Visean to
Stephanian (Figure 4.31).

Figure 4.31 Age of the Grant Group (Modified after Apak and Backhouse, 1999).

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 Chapter 4 – Stratigraphic Framework

Members of the Grant Group are challenging to correlate from the Barbwire Terrace (the
focus area of Apak and Backhouse’s work) across the Gregory Sub-basin to this study area.
The Reeves Formation is generally the simplest to carry using geophysical logs, however the
formation becomes challenging on the Balgo Terrace, where the blocky-sandstone log
response becomes interbedded (refer Olios 1 and Atrax 1, Figure 4.32). The upper Grant
Group members (Apak and Backhouse’s parasequences 1-4, or older nomenclature –
‘Carolyn’, ‘Winifred’ and ‘Betty’ Formations) can be risky to nominate in a regional setting
on well log data alone. To avoid nomenclature-related issues in this project, the members of
the Grant Group and Reeves Formation are simply referred to using a genetic interval
approach; Grant Group units ‘A’, ‘B’ and ‘C’ (oldest to youngest) (Figure 4.31) and
correlated on that basis. No age related re-definition is proposed here. As a reminder,
correlation sections A-A’, B-B’ and C-C’ show the optimal frame for understanding the
correlatives of the Grant Group, so the reader is referred to the correlations sections (Figure
4.44 to Figure 4.46) for visual assistance. The correlation framework is outlined in the
Permo-Carboniferous discussion that follows.

Characteristics

Grant A

The lowermost member (also the Reeves Formation; Apak and Backhouse, 1998) is
composed of an upper claystone and sandstone sequence, and a lower sandstone. The upper
claystone is described as medium grey to greenish grey, finely micaceous, rarely
carbonaceous, with variable amounts of very fine to coarse Diamictite (‘dropstone’ deposits).
The upper sandstone is off-white to pale grey and translucent quartzose, medium to coarse
grained, sub-angular to angular and rarely sub-rounded to rounded, pyritic in part, micaceous
in part and feldspathic in part. Quartzite and biotite flakes are noted in variable amounts
(Klappa et al, 1985a; 1985b).

The lower sandstone interval is described as pale grey, fine to coarse grained, angular to sub-
angular and also sub-rounded to rounded in part, poorly sorted and loose, rarely pyritic, rarely
feldspathic, variably coloured coarse grained (orange, rose, green grey and black) lithics and
granitic fragments, rare quartzite chips and biotite are noted. The sandstone becomes better
sorted to a predominant coarse grainsize with increasing depth. The lower interval also

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 Chapter 4 – Stratigraphic Framework

features pale grey mottled micromicaceous claystone, grey carbonaceous siltstone and black
hard fibrous coal fragments (Klappa et al, 1985a; 1985b).

Grant B

The Grant B member is comprised of sandstone, siltstone and claystone. The sandstone is
pale grey to frosted, medium grained but rarely coarse, loose, sub-angular to rounded and
rarely well-rounded, calcareous in part, trace pyritic, with trace lithic and carbonaceous
fragments noted. The siltstone is light to medium grey and bluish grey, firm, massive,
arenaceous in part and also argillaceous in part, rarely carbonaceous, with rare biotite noted.
The claystone is light to pale grey, occasionally medium grey, very finely micaceous,
arenaceous in part, carbonaceous, and contains sporadic very fine to fine quartzose grains in
varying abundance (Klappa et al, 1985a; 1985b).

Grant C

The uppermost interval of the Grant Group consists of a sandstone interbedded with siltstone
and claystone. The sandstone is pale to light grey, fine to medium grained but rarely coarse
and also rarely silty in part, loose, angular to sub-angular, quartzose, coarsely micaceous,
pyritic and feldspathic in part. The siltstone is light to medium grey, very finely micaceous,
and carbonaceous. The claystone is dark grey, micromicaceous, blocky, and grades to
carbonaceous shale in part, with black brittle coal fragments noted (Klappa et al, 1985a;
1985b).

Geophysical Log Characteristics

Grant C

Within the project area the top of the Grant Group is mostly represented on wireline logs as a
sharp inflected gamma ray contact that represents a disconformity between the Permian Poole
Sandstone and the Grant Group. Where the sharp contact is not present and the contact is
gradual (Lanagan 1 and Bindi 1) a conformable contact is proposed. A mostly complete

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 Chapter 4 – Stratigraphic Framework

section of Grant C is observed at Bindi 1, where the interval 990 mRT to 1060 mRT is
removed in other wells in the project area.

The top of Grant C is marked by a shale that shows an inflection on the gamma ray response
and deflection on the resistivity and sonic log responses. Underneath the capping shale, the
Grant C interval shows either a coarsening upward gamma ray (as at Selenops 1, Olios 1), a
low baseline gamma ray (as at Lake Betty 1, Lanagan 1, Ngalti 1), or an interbedded gamma
ray log response (such as at Bindi 1 or Kilang Kilang 1). Where the gamma ray response
shows a low sandstone baseline or sandstone interbeds (for example at Olios 1, Bindi 1 and
Kilang Kilang 1) the resistivity log shows elevated values and the density log shows a
decreased trend.

Grant B

Grant B is the most inconsistent in terms of geophysical log characteristics within the Grant
Group. Lanagan 1, Lake Betty 1, Olios 1 and Ngalti 1 show the top of Grant B represented by
a sharp contact inflection on the gamma ray log. The Sonic log shows a similarly shaped
deflection at the same point. Kilang Kilang 1 shows a sharp contact deflection at the top of
the interval with a similarly shaped inflection on the sonic log. The sharp contact may
indicate a disconformable contact to the overlying Grant C interval. The top of Grant B at
Bindi 1 is picked at the top of an invariable gamma ray response below a fining upwards
sequence. The gamma ray log in all wells is variable over the interval, showing a variety of
fining upwards and coarsening upwards patterns, as well as blocky interbedded signatures.
At Lake Betty 1 and Lanagan 1, a stepwise increasing shift in the resistivity and sonic logs
are observed approximately in the middle of the interval.

Grant A

Grant A is the simplest interval in the Permo-Carboniferous section to identify and correlate
on geophysical logs. The top of Grant A is identified by a decrease baseline shift in the
gamma ray response. Over the interval, the gamma ray log is both consistently low and
blocky (Lake Betty 1, Lanagan 1, Bindi 1, Ngalti 1, Kilang Kilang 1), or shows a blocky
variable interbedded sequence (Olios 1 and Lawford 1) but in every case the gamma ray

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 Chapter 4 – Stratigraphic Framework

response shows a generally low baseline. The resistivity, density and sonic logs over the
interval is generally invariable with the exception of Olios 1 that shows a variable character
to match the interbedded gamma ray response.

112
 Not Acquired

Top of Grant Group/Grant C Member

Top of Grant B Member
Logs not acq’d
Top of Grant A Member
in upper section
Base of Grant Group

Figure 4.32. Geophysical log definition of the Grant Group across the project area. Well are labelled (modified after Crank, 1972; Klappa et al., 1984; Lehmann and Haines, 1985; Klappa et al.,
1985a; 1985b; Smith, 1985a; 1985b; NSO, 2008; Cookson and Jones, 2013).
 Chapter 4 – Stratigraphic Framework

Depositional Setting

The overall mixed grainsize components (medium to coarse grained sandstones) with poorly
sorted character represent variable flow regimes, with an overall larger grainsize,
representative of higher energy depositional flows, likely upper flow regime. The rip up
clasts of claystones, vari-coloured lithics and granitic fragments is evidence of reworking.
Coal fragments in the lower section hint at a near-by terrestrial environment. The interval
comprising both Grant A and the lower-most section of Grant B (1500 mRT to 1830 mRT) at
Bindi 1 capped by a probable transgressive surface (TSE) points to a low stand system
(higher rate of sediment supply relative to rate of accommodation generation). This is
suggestive of a regressive environment, with high percentage coarse-grainsize sedimentation,
possibly a delta mouth or strand plain (Figure 4.33 and Figure 4.34).

A transgressive systems tract overlies the low stand, between a potential TSE at 1500mRT, to
a maximum flooding surface (MFS) at 1260 mRT at Bindi 1. Aggradational sequences are
observed on the gamma ray log separated by minor flooding events at 1360 mRT and 1445
mRT. This transgressive system, comprised of finer grained sediments (medium sands,
siltstone and claystone) reflected in a higher baseline gamma ray response, indicates slightly
lower energy deposition (than the lowermost LST) due to higher base level; likely mid-plain
to lower plane bed energy. This is indicative of a transgressive environment, such as an
embayed coast or tidal influenced estuary. The Diamictite (‘drop stones’) noted throughout
Grant A are validation of a glacial period in the Late Carboniferous, discussed by Apak and
Backhouse (1999).

A maximum flood lies at 1247 mRT. This MFS indicates higher base level, and higher rates
of accommodation relative to the rate of sediment supply. A transgressive surface lies at 1215
mRT. This transgressive surface likely represents a period of erosion due to higher local
energy flows, where the erosional surface is potentially a remnant of subaerial exposure,
removing some (or most) of the underlying high stand (HST) and subsequent low stand
(LST), and is therefore also the location of a sequence boundary (SB). Surface incisions
(incised valleys) are expected due to subaerial exposure and e identified by Apak and
Backhouse (1999).

The upper section of the Grant Group in Bindi 1 represents a transgressive system (TST),
above the SB at 1215 mRT. The finer grained sediments (fine grained sandstones, siltstones
and claystones) represents lower plain bed energy, and a higher base level. The gamma ray

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 Chapter 4 – Stratigraphic Framework

log response confirms intermittent aggradational periods as well as fining up sections. The
observed coal fragments (rip ups) suggests a nearby terrestrial environment (Figure 4.35).
The upper unit is suggestive of a transgressive setting, such as a tidal influenced estuary. A
flooding surface caps the top of the Grant Group.

Top of Grant Group

FS
A HST is expected up-section
FS TST

Upper part of HST at 1230 – 1260

TSE and
HST mRT and all of the subsequent LST
MFS
are eroded by TSE at 1230 mRT
FS TST
FS
TS

FS
FS LST

SB?

Figure 4.33. Bindi 1 geophysical log. Sequence stratigraphic analysis overlain (modified after Lehmann and Haines, 1985).

115
 Chapter 4 – Stratigraphic Framework

Figure 4.34. Palaeogeography of the Visean to Stephanian (modified after Wulff, 1987).

116
 Chapter 4 – Stratigraphic Framework

Figure 4.35. Palaeogeography of the Asselian to Tastubian (modified after Wulff, 1987).

117
 Chapter 4 – Stratigraphic Framework

Reservoir Properties

Sonic derived porosities were calculated at Bindi 1, Olios 1, Atrax 1, Ngalti 1 and Kilang
Kilang 1 by the well operators, revealing excellent reservoir quality (Table 4.6 and Figure
4.36). Excellent reservoir properties are confirmed by core data measurements at Atrax 1,
showing 18.5% porosity and 754 – 1015 mD permeability in Grant unit A (Figure 4.36).

Well Unit Interval Porosity (%, Sonic derived)

Ngalti 1 Grant C to A 280 – 796 mRT 13 – 40%, Average 20%

Grant C 831 – 882 mRT 18 – 25%

Grant B 952 – 985 mRT 20%

Kilang Kilang 1 Grant B 1005 – 1097 mRT 10 – 18%

Grant B 1149 – 1161 mRT 20%

Grant A 1204 – 1447 mRT 8 – 18%, Average 12%

Grant C 990 mRT 13 – 30%, Average 21%

Grant C 1303.5 mRT 5 – 22%, Average 13%

Bindi 1
Grant B 1583 mRT 7 – 18%, Average 10%

Grant A 1662 mRT 7 – 20%, Average 12.5%

Table 4.6. Grant Group porosity measurements (Lehmann and Haines, 1985; Smith, 1985a; 1985b).

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 Chapter 4 – Stratigraphic Framework

Grant Formation Grant Formation

200 Olios 1 200
Φsonic,
300 Grant C 300
Atrax 1
Φsonic,
400 400
Grant B
Depth (mRT)

Depth (mRT)
Selenops 1
500 Φsonic, 500
Grant B Atrax 1 Κh,
Grant A
600 Atrax 1 600
Φsonic,
700 Grant A 700
Atrax 1
Φcore,
800 800
Grant A
Olios 1
900 Φsonic, 900
0 20 40 Grant A 500 1000
Porosity (%) Permeability (mD)

Figure 4.36. Grant Formation porosity and permeability measurements (Klappa, 1984; Klappa et al., 1985a; 1985b).

Discussion – Permo-Carboniferous Section

The Grant Group isochron (Figure 6.21) shows that the Grant Group exists regionally within
the project area. The Grant Group thins to a near zero edge on the Balgo Terrace in the north
(16° 21’ S, 126° 46’ E) and in the north east (19° 43’ S, 127° 33’ E) or intersects the Mueller
Fault at the Billiluna Sub-basin boundary. The Grant Group A, B and C intervals
gradationally thicken and deepen in a south-southwest direction off the Balgo Terrace in the
northern project area (around the Selenops 1 well towards Lawford 1) to 500 milliseconds
TWT thickness, as is also demonstrated on the section A-A’ (Figure 4.44). In the central
project area (19° 37’ S, 127° 12’ E), the isochron shows that the Grant Group thickens in the
central area depocentre to 1 second TWT thickness, before thinning over Ngalti 1 and the
Kilang Kilang 1 area to 200 milliseconds TWT thickness (section B-B’, Figure 4.45). In the
south eastern study area the Grant Group is mapped to thicken in broad patches to 900
milliseconds TWT thickness on the Betty Terrace (20° 06’ S, 127° 29’ E) and Balgo Terrace
(20° 20’ S, 127° 59’ E) before intersecting the

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 Chapter 4 – Stratigraphic Framework

eastern basin margin. Section C-C’ (Figure 4.46) confirms that the Grant Group thickens
between Kilang Kilang 1 and Lake Betty 1, through the central depocentre (at Bindi 1),
h h confirmed by seismic mapping. The Grant Group is mapped to thicken southwest-
ward into the Gregory Sub-basin in excess of 600 milliseconds TWT thickness.

4.8 Permian

4.8.1 Poole Sandstone

The Permian (Sakmarian) Poole Sandstone is a regionally extensive sandstone package that is
intersected by all wells within the study area. The unit underlies the Noonkanbah Formation,
where the contact is generally conformable though sharp (Kilang Kilang 1, Ngalti 1, Bindi 1,
Lake Betty 1) in the basinward portion of the study area, but also gradual in places (Lanagan
1, Olios 1) in the northeastern project area. The Poole Sandstone overlies the Grant Group
with a disconformable contact.

Age

Two sidewall cores at Bindi 1 (921 mRT and 930.1 mRT) reveal high palynomorphs yields,
and indicate the Poole Sandstone to be of Asselian to Sakmarian (Early Permian) age
(Lehmann and Haines, 1985).

Characteristics

The Early Poole Sandstone is predominantly a sandstone unit, with interbeds of siltstone and
claystone. The sandstone is clear to frosted, medium to coarse grained but also fine grained in
part, rounded to sub-angular, moderately to poorly sorted, commonly friable and
unconsolidated, micaceous in part, in a argillaceous quartzose flour matrix. The siltstone is
dark grey to black, micromicaceous and argillaceous. The claystone is black, soft,
micromicaceous and slightly arenaceous. Minor amounts of black, blocky, vitrinitic to sub-
vitrinitic coal is also observed in the interval (for example at Kilang Kilang 1), giving a ‘salt
and pepper’ texture to cuttings (Smith, 1985a).

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 Chapter 4 – Stratigraphic Framework

At Bindi 1 (central study area) the Poole Sandstone is more argillaceous; comprised mostly of
interbedded claystones and sandstones (Lehmann and Haines, 1985) (described as above)
with 10 metres of blocky sandstone at the top of the interval. A 3 metre thick claystone lies at
the base.

At Lake Betty 1 (northeastern project area) the Poole Sandstone was observed mainly as a
sandstone; finer grained than in the southern area (observed as a very fine to fine grained
interval and silty in part; Crank, 1972), and often grades to siltstone and minor shale; grey,
sub-fissile to blocky and pyritic in part. A lower (5 metre thick) claystone is present in the
northern project area at Atrax 1, described as dark grey, soft to firm, massive to sub-fissile,
micaceous, carbonaceous to coaly and resinous to earthy (Klappa et al, 1985a).

Geophysical Log Characteristics

The top of the Poole Sandstone on geophysical logs (Figure 4.37) is represented by a sharp
deflection in the gamma ray log (at Lake Betty 1, Bindi 1, Ngalti 1 and Kilang Kilang 1) or a
gradational reduction in gamma ray response (at Lanagan 1 and Olios 1). A subtle but sharp
infection in the sonic log response is also noted (at Lake Betty 1 and Ngalti 1) though a sharp
deflection in the sonic log at the top of the interval is noted at Kilang Kilang 1.

Over the interval, the gamma ray response is usually observed as a low base line and shows a
blocky character. Exceptions to this are at Bindi 1, Olios 1 and Lanagan 1, where the Poole
Sandstone is more argillaceous. The resistivity log response is uniform over the interval, as is
the sonic and density log responses (an exception to this is noted at Ngalti 1 and Kilang
Kilang 1; where the sonic log reduces in baseline character (below 250 mRT at Ngalti1) or
increases in baseline character (below 730 mRT at Kilang Kilang 1, representing calcareous
content in the lower Nura Nura member).

121
 Logs not acq’d

Logs not acq’d over interval

over interval Logs not acq’d

over interval

Top/Base of Poole Sandstone

Figure 4.37. Geophysical logs over Poole Sandstone across project area. Wells labelled (modified after Crank, 1972; Klappa et al., 1984; Lehmann and Haines, 1985; Klappa et al., 1985a; 1985b; Smith,
1985a; 1985b; NSO, 2008; Cookson and Jones, 2013).
 Chapter 4 – Stratigraphic Framework

Depositional Setting

The lower claystone at Bindi 1 and Lake Betty 1 is labelled elsewhere in the basin as the
Nura Nura member. The Nura Nura member represents the flooding surface separating the
Poole Sandstone from the Grant Group.

Acritarchs observed in the Poole Sandstone at the Bindi 1 location indicate a marginal marine
to shallow marine environment. Increasing concentrations of acritarchs at the base of the
interval (also featuring a claystone zone at the base) suggests a lower marine portion and a
higher energy environment up-section, terminating in blocky sandstone at the top. Coal
observed at Kilang Kilang 1 indicates a nearby terrestrial environment. This indicates a
regressive environment for the Poole Sandstone overall; possibly a tide dominated estuary at
the base connected to a fluvial sediment source, prograding to a deltaic environment. The
blocky sandstones are possible stacked delta lobes (Figure 4.38).

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 Chapter 4 – Stratigraphic Framework

Paleogeography of the
Sakmarian
(Early Permian)

Figure 4.38. Paleogeography of the Sakmarian (modified after Wulff, 1984)

124
 Chapter 4 – Stratigraphic Framework

Reservoir Properties

Sonic derived porosities were calculated at Ngalti 1, Bindi 1, Olios 1 and Kilang Kilang 1 for
the Poole Sandstone, revealing excellent reservoir quality (Table 4.7), in excess of 20%
porosity across the study area. Note that as the porosity results are derived from the sonic log,
the very high sonic porosities observed at Ngalti 1 are perhaps unrealistic, given the baseline
decrease in the sonic log from 231 mRT.

Well Interval Porosity (%, Sonic derived)

Ngalti 1 178 – 280 mRT 29 – 40%

Kilang Kilang 1 661 – 803 mRT 23 – 35%

Bindi 1 910 mRT 20 – 27%, Average 25%

Olios 1 275 – 299 mRT 28 – 32.6%, Average 30%

Table 4.7 Poole Sandstone porosity measurements (Klappa et al., 1984; Lehmann and Haines, 1985; Smith
1985a; 1985b).

Discussion and Framework

The Poole Sandstone is mapped to exist regionally throughout the project area. Isochron
mapping (Figure 6.20) demonstrates the package thickens to 210 milliseconds TWT in the
southern project area within the Gregory Sub-basin (20° 34’ S, 127° 29’ E). The Poole
Sandstone gradually thins northwards onto the Betty Terrace to 100 milliseconds TWT (20°
02’ S, 127° 27’ E), and continues to thin in a northward direction onto the Balgo Terrace,
averaging 50 milliseconds TWT thickness in broad areas across the northern half of the
project area. The Poole Sandstone thins to 21 milliseconds TWT thickness on the Balgo
Terrace (20° 03’ S, 127° 58’ E) before reaches a near-zero edge on the eastern and northern
basin margins. The Pool Sandstone is mapped to not exist on the Billiluna Sub-basin.

Isochon mapping of the Poole Sandstone (Figure 6.20) shows little variability in TWT
thickness across the study area. This is confirmed in cross sections A-A’, B-B’ and C-C’

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 Chapter 4 – Stratigraphic Framework

(Figure 4.44 through Figure 4.46). Section A-A’ (Figure 4.44) and B-B’ (Figure 4.45)
show a th e correlation for the package, which is agreeable with the isochron
mapping. Section C-C’ (Figure 4.46) shows a slight thinning between Kilang Kilang 1 and
Bindi 1 (142.5 metres to 80 metres), also visible on the isochron (thinning from 100
milliseconds to 49 milliseconds TWT).

4.8.2 Noonkanbah Formation

The Early Permian (Aktastinian to Baigendzhinian) Noonkanbah Formation is a regionally

mappable shale and interbedded siltstone interval that conformably overlies the Poole
Sandstone. The Noonkanbah Formation represents the Maximum Permian Transgression in
the Canning Basin.

Age

Palynological evidence at Lake Betty 1 (431 – 635 mRT) suggests an Early Permian –
Artinskian (Vittanina Assemblage of Balme 1964) age for the Noonkanbah Formation.

Characteristics

The Noonkanbah Formation is observed as mostly shale interbedded with siltstone. The shale
is described as light and dark grey to blackish grey, soft and sticky, blocky to sub-fissile,
micaceous, arenaceous in part, calcareous in part, carbonaceous in part, and pyritic. The
siltstones are observed as light and dark grey, argillaceous, micaceous, carbonaceous in part
and rarely grade to very fine sandstone. The rare thin sandstone interbeds are described as
light to medium grey, very fine grained, sub-angular, poorly sorted and unconsolidated in part
(Klappa et al, 1985a; 1985b; Lehmann and Haines, 1985; Smith, 1985a; 1985b).

Geophysical Log Characteristics

The Noonkanbah Formation is characterized with an increase in gamma ray baseline from the
overlying Triassic aged rocks and underlying Poole Sandstone (Figure 4.39). The baseline

126
 Chapter 4 – Stratigraphic Framework

difference is more pronounced in the southeastern project area at Ngalti 1 and at Kilang
Kilang 1 (though the top of the interval is not acquired on logs at Kilang Kilang 1). The
gamma ray response is subtly variable in small blocky packages over the zone. A subtle
decrease in resistivity baseline is also noted over the interval. The Noonkanbah Formation is
observed to have a generally invariable resistivity and sonic log response.

127
 Logs not acq’d Logs not acq’d
over interval over interval

Logs not acq’d

over interval

Top / Base of Noonkanbah Formation

Figure 4.39. Geophysical logs over the Noonkanbah Formation across the project area (modified after Crank, 1972; Klappa et al., 1984; Lehmann and Haines, 1985; Klappa et al., 1985a; 1985b;
Smith, 1985a; 1985b; NSO, 2008; Cookson and Jones, 2013).
 Chapter 4 – Stratigraphic Framework

Depositional Setting

The overly fine-grained nature of the formation (shale and siltstones) indicates low velocity
flow (lower plane bed) energy. Rare intermittent sandstones indicate periods of higher energy
environments or lower base level. The Noonkanbah Formation represents a maximum base
level during Permian time. A shallow marine to marginal marine depositional environment is
evident; potentially influenced by a restricted marine environment such as an estuary (Figure
4.40).

Paleogeography of the
Aktastinian to Baigendzhinian
(Early Permian)

Figure 4.40. Paleography of the Aktastinian to Baigendzhinian (modified after Wulff, 1984).

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 Chapter 4 – Stratigraphic Framework

Reservoir Properties

Sonic derived porosities were calculated at Bindi 1 and Olios 1 (Table 4.8). The sonic
calculated results are potentially deceptive given the fine grained nature of the formation.
Lithologic descriptions and well log character suggest the Noonkanbah Formation to be a
regional seal across the study area, where it is expected to be tight. There is no core data on
hand for the Noonkanbah Formation.

Well Interval Porosity (%, Sonic derived)

Bindi 1 629 mRT 10 - 30%, Average 17%

Olios 1 235.5 – 254 mRT 14.9 – 19.1%, Average 17%

Table 4.8. Noonkanbah Formation porosity measurements (Klappa, 1984; Lehmann and Haines, 1985).

Discussion and Framework

The Noonkanbah Formation is mapped to exist across the project area. Isochron mapping
shows that the package thickens to 443 milliseconds TWT southwest of Kilang Kilang 1 (20°
15’ S, 127° 02’ E). The Noonkanbah Formation is essentially isopachus e t e
th e across large portions of the project area, averaging 270 milliseconds TWT
thickness (ranging 250 to 300 milliseconds TWT thickness) in the southern portion of the
project area. The package gradually thins to 70 to 120 milliseconds TWT in the northwestern
study area (around Lake Betty 1 and Lanagan 1). The Noonkanbah Formation continues to
thin to a near-zero edge in the northeast, and does not exist on the Billiluna Sub-basin.

Cross sections A-A’, B-B’ and C-C’ (Figure 4.44 to Figure 4.46) show good agreement
between the isochron mapping and the well thicknesses. The Noonkanbah Formation thickens
into the Gregory Sub-basin between Ngalti 1 and Kilang Kilang 1 (66 metres to 406.5 metres;
section B-B’, Figure 4.45) and thins between the southeast and northwestern areas via Bindi 1
(section C-C’, Figure 4.46). In the northwestern project area (section A-A’, Figure 4.44) the
package is generally isopachus until it thins dramatically at Selenops 1 (where it is 26 metres
thick).

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 Chapter 4 – Stratigraphic Framework

4.8.3 Liveringa Group

Age

The Liveringa Group is a conformable succession of sandstone and siltstone intersected in all
study area wells, except Atrax 1. The Liveringa Group (in complete preserved section)
comprises the Condren Sandstone, Godfrey Beds, Hardman Formation, Lightjack Formation
and Triwhite Sandstone. The preserved section within the study area, however, is limited to
the Condren Sandstone and Lightjack Formation, implying a period of erosion or non-
deposition between members. Palynological evidence at Lake Betty 1 suggests a Late
Permian age (Dulhuntyspora Assemblage of Balme, 1964) for the Liveringa Group.

4.8.4 Liveringa Group – Condren Sandstone

Characteristics

The Condren Formation comprises sandstone and siltstone. The sandstone component is off-
white, light to medium grey, coarse grained, rarely fine grained, sub-angular to sub-rounded
and rounding improves with depth, clean and loose quartzose, rarely pyritic and
carbonaceous. Minor coal is observed. The lower portion of the formation shows very fine to
fine grained sandstone that is angular to sub-angular and grading to siltstone in part. The
main siltstone component is medium grey, grading to very fine sandstone in part,
micromicaceous, rarely pyritic, and shows fine carbonaceous flecks.

4.8.5 Liveringa Group – Lightjack Formation

Characteristics

The Lightjack Formation is characterized by sandstone interbedded with siltstone and

claystone. The sandstone is off-white and pale grey grading to medium brownish grey, very
fine grained and grading to siltstone in part, angular to sub-angular, quartzose, micaceous and
pyritic. The claystone intervals are light to medium grey, sub-fissile to blocky, arenaceous in
part and grading to very fine sandstone in part, occasionally carbonaceous, rarely pyritic and
rarely calcareous (Crank, 1972; and Lehmann and Haines, 1985). The siltstone is light grey,
grades to very fine sandstone in part, very micaceous, slightly to moderately calcareous in

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 Chapter 4 – Stratigraphic Framework

part and carbonaceous in part. Brachiopods are observed at Bindi 1 between 520 mRT to 525
mRT and 560 mRT to 565 mRT along with shell fragments (Lehmann and Haines, 1985).

Liveringa Group – Geophysical Log Characteristics

Note: Geophysical logs were only recorded over the interval at Bindi 1, Lanagan 1 and Ngalti
1. Referring to Bindi 1; the top of the Liveringa Group (Condren Sandstone) is marked on
wireline logs as a baseline decrease in the gamma ray, resistivity and sonic log responses
(Figure 4.41). The gamma ray is generally low and blocky over the interval and shows a
coarsening upwards trend, whereas the sonic and resistivity logs parallel each other with a
gradual increase in baseline with increasing depth. The top of the Condren Sandstone
member is represented on geophysical logs as a baseline increase in gamma ray response and
increases in baseline to the resistivity and sonic log responses. Over the Condren Sandstone
member, all geophysical logs display a homogeneous response. In cuttings (where no logs
were acquired) the Condren Sandstone is represented by the intersection of finer grained
lithologies

Top of Liveringa Group / Condren Sandstone

Top of Lightjack Formation
Base of Liveringa Group

Figure 4.41. Geophysical logs over Liveringa Group (modified after Lehmann and Haines,
1985; Smith, 1985b; NSO, 2008).

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 Chapter 4 – Stratigraphic Framework

Depositional Setting

The fine grained sandstone, siltstone and claystone indicates low energy flow (low plane bed
deposition) within the Lightjack Formation. The brachiopods and shell fragments observed at
Bindi 1 indicate a marine influence on deposition. The coarser grained sediments within the
Condren Sandstone indicate a change to a higher energy environment. An overall coarsening
trend is apparent up section. A maximum flooding surface (MFS) is located within the
Noonkanbah Formation (Figure 4.42), which places the lower Liveringa Group within a high
stand (HST). A sequence boundary is likely present at 463.5 mRT at Bindi 1, with the upper
Liveringa Group (most of the Condren Sandstone) representing a low stand (LST). A shallow
marine or marginal marine environment is assigned to the Lightjack Formation (evidenced by
Palynology confirmation at Lake Betty 1, and brachiopods at Bindi 1), and a regressive
fluvial dominated environment is assigned to the Condren Sandstone.

Top of Liveringa Group / Condren Sandstone

FS LS Top of Lightjack Formation
SB? Base of Liveringa Group
FS
FS HS

Figure 4.42. Bindi 1 geophysical log. Sequence stratigraphic analysis overlain (modified after Lehmann and Haines, 1985).

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 Chapter 4 – Stratigraphic Framework

Reservoir Properties

Sonic derived porosities were calculated at Kilang Kilang 1 for the Liveringa Group,
presenting excellent reservoir quality, ranging between 21% and 30% porosity (Table 4.9).

Well Interval Porosity (%, Sonic derived)

48 – 167 mRT 25 – 29%

Kilang Kilang 1
200 - 320 mRT 21 - 30%

Table 4.9. Liveringa Group porosity measurements (Smith, 1985a).

Framework

No mappable package exists for the Liveringa Group on seismic data, and only 3 wells
intersected the formation. A thin, generally isopachus unit is anticipated for the Liveringa
Group within the project area, potentially thickening slightly towards the southwest, similar
to the of other Permian sediments.

4.8.6 Millyit Sandstone

The Late Permian – Early Triassic Millyit Sandstone is only present at Bindi 1.

Characteristics

The Millyit Sandstone is predominantly a sandstone unit. The sandstone is observed light
grey to brownish grey, very fine grained grading to fine and medium grained with depth
(though also rare well-rounded coarse grains are noted), sub-angular, quartzose, micaceous in
part, rarely glauconitic, showing occasional carbonaceous flecks. Occasional small bivalve
shell fragments are noted at Bindi 1 between 260 mRT to 286 mRT (Lehmann and Haines,
1985).

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 Chapter 4 – Stratigraphic Framework

Geophysical Log Characteristics

The top of the Millyit Sandstone is characterized by a baseline increase on the gamma ray log
response (Figure 4.43). The top is only marginally recorded on wireline logs (sonic and
resistivity) but show an elevated subtle broad bell shape response over the zone. The gamma
ray response is subtly bell shaped to blocky, with subtle variability.

Top of Millyit Sandstone

Base of Millyit Sandstone

Figure 4.43. Bindi 1 geophysical log over Millyit Sandstone (modified after
Lehmann and Haines, 1985).

Depositional Setting

The variable grain sizes present throughout the Millyit Sandstone indicates either changes to
base level or a mixture of depositional influences during Late Permian – Early Triassic time.
The concentration of sandstone along with the presence of carbonaceous lithotypes and shell
fragments suggests multi-environment influences, potentially in a near-shore dominated
territory. The low stand present in the underlying upper Liveringa Group indicates the Millyit
is likely a continuation of a regressive environment, potentially near-shore shallow marine,
such as strand plain or intertidal zone.

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 Chapter 4 – Stratigraphic Framework

Framework

No mappable package exists for the Millyit Sandstone on seismic data. A thin, generally
isopachus unit is anticipated for the Millyit Sandstone within the project area, potentially
thickening slightly to the southwest, with other Permian sediments.

4.9 Triassic and Younger

Triassic and younger rocks were intersected at Bindi 1 and Lake Betty 1.

4.9.1 Blina Shale

The Blina Shale was intersected at Bindi 1 and Lake Betty 1.

Characteristics

The Blina Shale is predominantly a siltstone, based on the single well intersection at Bindi 1
(Lehmann and Haines, 1985). The siltstone is observed as pale to light grey, firm and slightly
friable, mostly argillaceous in part but also arenaceous and grading to very fine sandstone in
part. It is micaceous, showing occasional carbonaceous flecks and is rarely glauconitic.
Minor silty light grey glauconitic claystone is also noted in the interval.

Geophysical Log Characteristics

No geophysical logs were acquired over the interval.

Depositional Setting

The overall fine grain sizes within the Blina Shale indicates a low energy flow regime, with
subtle base level alterations suggested by the minor claystone and arenaceous components.
The observations noted for the Blina Shale (without log data) are consistent with the tidal flat

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 Chapter 4 – Stratigraphic Framework

environment presented by Yeates and Muhling (1977). The siltstone at Bindi 1 is potentially
a shoreline component with sediment supply from longshore drift.

4.10 Summary of Results

Table 4.10 summarizes the stratigraphy within the project area, highlighting lithological
characteristics and reservoir properties, as a quick guide for future reference.

137
 AVE AVE
UNIT /
AGE FORMATION RESERVOIR SEAL POROSITY PERMEABILITY LITHOLOGY COMMENTS
MEMBER
(%) (mD)

TRIASSIC Blina Shale Seal? Firm siltstone No data

Millyit Predominantly
Reservoir? No data
Sandstone sandstone

Excellent
Sandstone and
Condren Reservoir 25 % (sonic) reservoir
siltstone
potential
Liveringa
Group Interbedded
Excellent
sandstone,
Lightjack Reservoir 25 % (sonic) reservoir
siltstone and
potential
claystone
PERMIAN Noonkanbah Shale with Sonic porosity
Seal 17% (sonic)
Formation siltstone interbeds overestimated?

Predominantly
Excellent
Poole ≥ 20 % sandstone with
Reservoir reservoir
Sandstone (sonic) siltstone and
quality
claystone interbeds

Interbedded
sandstone,
Grant Group C Reservoir 21 % (sonic)
siltstone and
claystone
 Interbedded
sandstone,
B Seal 10 % (sonic)
siltstone and
claystone
Excellent
A Reservoir 18.5 % 754 – 1015 mD Blocky sandstone reservoir
quality

Interbedded
G Seal 13 % (sonic) claystone and
sandstone
Massively bedded
F Reservoir 7 % (sonic) quartzose
sandstone

Massively bedded
E Seal?
claystone
CARBONIFEROUS
Massively bedded
Anderson D Reservoir 5 % (sonic) quartzose
Formation sandstone

Massively bedded
C Seal 8.5 % (sonic) siltstone and non-
fissile claystone

Massively bedded
B Reservoir 5 % (sonic) quartzose
sandstone

Loose coarse
A Reservoir 9 % (sonic)
grained sandstone
 Interbedded
18.4 % sandstone, Good reservoir
Clastic Reservoir
(sonic) siltstone and minor quality
shale
Laurel
Formation Finely crystalline
and fossiliferous
Carbonate Reservoir? No data
limestone, also
blocky shales
Interbedded
Luluigui sandstone,
Reservoir? No data
Formation siltstone and minor
shale
Fine grained Excellent
Knobby
Reservoir 20.6 % 567 mD sandstone and reservoir
Sandstone
minor siltstone quality
Interbedded
Virgin Hills sandstone,
Reservoir 7.4 % 0.52 mD May be tight
Formation siltstone, shale and
limestone
DEVONIAN Grey, blocky
Gogo
Seal? micromicaceous No data
Formation
shales
Interbedded
limestone,
Lennard River
Reservoir? sandstone, No data
Group
siltstone and
claystone
Thick bedded Calcite and
massive
Bungle Gap fracture fill
Seal 3.3 % arenaceous
Limestone indicate
limestone, with
impermeable
secondary calcite
and fracture fill
 Devonian Polymict
Reservoir 10.3 %
Conglomerate conglomerate

Poulton Fine grained well-

Reservoir? No data
Formation sorted sandstone

Sub-fissile
micromicaceous
Waldecks Seal? claystone, siltstone No data
and medium
grained sandstone
Worral Fine grained
SILURIAN
Formation Elsa Reservoir? poorly sorted No data
friable sandstone
Microcrystalline to
Dodonea Seal? cryptocrystalline No data
dolomite
Grey blackish sub-
fissile to fissile Possible source
Bongabinni Reservoir? Seal?
claystone, silty in rock?
part

Carribuddy Brownish yellow

Group microcrystalline No data,
Minjoo Seal?
ORDOVICIAN argillaceous potential seal?
dolomite
Brownish grey soft
No data,
Nibil Seal? dolomitic
potential seal?
claystone
Finely crystalline
Nita Formation Seal 0.85 % Nil
sucrosic dolomite
 Black finely
crystalline
Possible source
WMC 4 Reservoir Seal? 1.7 % 0.01 mD argillaceous
rock?
carbonaceous
dolomite
Carbonaceous
Goldwyer WMC 3 Reservoir Seal? 1.5% 0.3 mD shale and sucrosic
Formation dolomite
Firm blackish
WMC 2 No data
fissile shale
Dark grey sub-
WMC 1 fissile shale and No data
siltstone
Massive, well-
Willara
Reservoir? sorted fine No data
Formation
sandstone
Medium grained
Nambeet
Reservoir? well-sorted No data
Formation
sandstone
Table 4.10 Summary of lithology, characteristics and reservoir properties for stratigraphy in this study.
 Chapter 4 – Stratigraphic Framework

4.11 Well Correlation

Three well correlations were built across the project area (Figure 4.44 to Figure 4.46).
The results ere discussed in the text within this hapter.

143
Figure 4.44. Dip section A - A' in the
northwestern project area.
Figure 4.45. Dip section B - B' in the
southeastern project area.
Figure 4.46. Strike section C - C'
across the project area.
 Chapter 5 – Seismic Interpretation

5. Seismic Interpretation

Seismic interpretation was a key component of this study. Mapping horizons across the
project area enabled a thorough investigation of subsurface geometries.

Chapter 5 details the methodology used in the seismic interpretation workflow. The key
objectives of the seismic interpretation workflow were to:

Tie the 2D seismic dataset to external well data via synthetic seismograms, so that
formation tops at the wells could be correctly identified on 2D data;
Internally tie the seismic interpretation across the study area to ensure a robust
horizon mapping package;
Correlate seismic horizons between wells;
Map the distribution of prominent regional seismic markers that represent key
stratigraphic formations;
Define the tectonic framework and identify the key faulting geometries;
Produce maps of structure and time-thickness (isochron); and,
Derive an estimate of depth of the mapped packages for use in petroleum systems
modelling.

5.1 The Use of Seismic in this Project

Mature source rocks, reservoir rocks, lithologies with sealing potential and trapping
geometries are all fundamental elements of an active petroleum system, therefore it is
important in this study to determine the existence and extent of source rocks, reservoirs, seals
and traps. To achieve this, stratigraphic horizons that are representative of petroleum system
elements were mapped throughout the study area in order to determine their presence, spatial
variability and geometric form.

To resolve the research questions it is clear that the interpretation needs to focus on mapping
the elements of the three petroleum systems that exist within the study area. The seismic
dataset was tied to the nine wells within the study area (Chapter 5.2). Eight seismic surfaces

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 Chapter 5 – Seismic Interpretation

were readily identified and regionally mappable on the 2D seismic data (Chapter 5.3). These
surfaces define the major stratigraphic units of the northeastern Canning Basin and
encompass the three petroleum systems of the region (Table 5.3). Each of these surfaces are
characterized by particular seismic amplitudes and/or seismic geometries, and have genetic
significance within the stratigraphy.

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 Chapter 5 – Seismic Interpretation

5.2 Well-To-Seismic Ties:

Synthetic seismograms were generated for all wells in the study area, and tied to seismic lines
in Table 5.1 (illustrated in Figure 5.1). No synthetic seismograms were generated for wells
outside of the study area.

Well Seismic line

Atrax 1 82GE-31
Selenops 1 82GE-31
Olios 1 83GN-15A
Lanagan 1 S85LM-06
Lake Betty 1 82GE-34
Bindi 1 81C-1A
Lawford 1 S85LM-22
Ngalti 1 RB82-31
Kilang Kilang 1 RB8106
Table 5.1. Well ties in this study.

Figure 5.1. Distribution of wells ties in project area. Seismic lines used for synthetic
ties are shown in red.

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 Chapter 5 – Seismic Interpretation

5.2.1 Synthetic Generation:

Table 5.2 summarizes the parameters to recreate each synthetic seismogram utilizing the
synthetic generation wizard in IHS Kingdom.

Well T-D Chart Velocity Density Wavelet Trace

Extracted from
seismic by Extracted 4
Ngalti 1 original DT log
frequency traces at the
check shots converted Constant
matching: borehole,
Ngalti 1 recorded at the from feet to density value
500m radius within a 50m
well – Datum meters below of 1
along RB82- radius, along
250m AMSL RT
31, 39 traces, RB82-31
phase angle 0

Extracted from
Kilang Kilang 1 seismic by Extracted 6
DT log
original check frequency traces at the
converted Constant
shots recorded matching: borehole,
Kilang Kilang 1 from feet to density value
at the well – 500m radius within a 100m
meters below of 1
Datum 250m along RB81-6, radius, along
RT
AMSL 28 traces, RB81-6
phase angle 0

Extracted from
Lanagan 1 seismic by Extracted 7
DT log
original check frequency traces at the
converted Constant
shots recorded matching: borehole,
Lanagan 1 from feet to density value
at the well – 200m radius within a 50m
meters below of 1
Datum 250m along S85LM- radius, along
RT
AMSL 06, 39 traces, S85LM-06
phase angle 0

Table 5.2. Examples of synthetic seismogram parameters used to perform synthetic ties in this project.

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 Chapter 5 – Seismic Interpretation

5.2.2 Effect of Well Bore Rugosity on Synthetic Seismograms:

Well bore rugosity was illustrated in Chapter 3.2 and Figure 3.1. Shallow well data that
intersects stratigraphy above the Meda Transpression event have generally good quality
wireline log data. Wireline log data quality depreciates quickly below the Meda
Transpression Unconformity event due to borehole rugosity (Figure 3.1). It is common to see
complete (or nearly complete) saturation of the caliper tool, and consequently, it is inferred
that the Density tool experiences poor well bore contact e t spurious values. Further,
the sonic sonde is likely to decentralize within the bore hole revealing inaccurate sonic times.

In all scenarios, the Density log (DT) was omitted from the synthetic generation to avoid
contamination from any borehole rugosity. This was e t e to produce good quality
synthetic ties across all wells. The sonic log was utilised as a minimum to compute velocity
in all synthetics. This procedure found that the overall effect of well bore rugosity was
minimal on synthetic seismograms, and successful ties were resolved for all wells. Thus,
confidence is provided that the horizon identification is correct when interpreting seismic in
this project. Three well ties are produced here for illustration, the remainder are available in
Appendix B.

5.2.3 Synthetic Seismograms:

Out of all the wells, Ngalti 1, Kilang Kilang 1 and Lanagan 1 arguably gave the best tie to the
extracted trace for each respective well location. A small discussion is presented here to
highlight some of the success and pitfalls of synthetic ties in this study.

At Ngalti 1, there is good agreement between the generated synthetic and the extracted trace
(Figure 5.2). Although the synthetic trace does not always equal the extracted trace in
amplitude or travel time throughout the entire well, there are sections where the correlation
between the trace and the synthetic are very good. Importantly, all formation tops (Devonian
and younger) referred to in Table 5.3 are resolved with very good matches between the
synthetic and extracted trace. The good correlation at Ngalti 1 (and other wells generally) is
attributed to proper wellbore readings of the Density (RHOB) and Sonic (DT) tools above
1250 mRT (approx. 0.8 seconds TWT). Note that the Caliper log (800 mRT to 1600 mRT at
Ngalti 1) is less saturated than other wells in the project area (refer to Caliper tool comparison
in Figure 3.2). A large washout is apparent below 1500 mRT at Ngalti 1. Note that the

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 Chapter 5 – Seismic Interpretation

synthetic has a high amplitude peak-trough-peak at approximately 1.0 seconds, related to the
poor well bore contact of the logging tools at this depth. The seismic only shows a single
large peak at the same location.

Largely, it can be said that the synthetic ties for each of the wells are good to very good,
illustrated by ties for Ngalti 1, Kilang Kilang 1 and Lanagan 1 in Figure 5.2 through Figure
5.4. The results obtained from successfully tying the wells to seismic data gave confidence in
placing horizon interpretation at correct levels on the seismic dataset.

152
Figure 5.2. Ngalti 1 synthetic seismogram (left), synthetic overlay on seismic RB82-31 (right).
Figure 5.3. Kilang Kilang 1 synthetic seismogram (left), synthetic overlay on seismic RB81-6 (right).
Figure 5.4. Lanagan 1 synthetic seismogram (left), synthetic overlay on seismic S85LM-06 (right). Note that the deeper reflection events (below the Meda Transpression/Fairfield group, between
0.8 – 0.9 seconds) do not tie to the extracted trace in amplitude or travel time, likely due to the bell-shaped washout in the caliper log below 1000mRT (MATC).

.
 Chapter 5 – Seismic Interpretation

5.3 Interpretation of Horizons:

Table 5.3 summarises the seismic characteristics of each correlated seismic package in this
study. The reader is referred to Chapter 6.1 to view the horizon interpretation.

Stratigraphic Horizon
Seismic package characteristics
surface colour

Identified by moderate to strong peak in seismic

amplitude
Near Top Moderately bright, continuous, lateral intra-
Noonkanbah sequence reflectivity due to massively bedded shale
Formation character
Maximum Flooding Surface of the Permian
transgression

Identified by moderate peak in seismic amplitude

Near Top Poole Sequence of partially irregular to partially laterally
Sandstone continuous brightly amplified reflections
Transgressive Systems Tract

Identified by strong peak in seismic amplitude

Interbedded Grant units (C, B and A) observed as
Near Top Grant
non-continuous to irregular, brightly amplified
Group
events
Flooding Surface above Low Stand Systems Tract

Identified by truncation of seismic reflectors and

marked change in seismic character across the
unconformity
Meda Transpression
Unconformable surface between Grant Group and
Unconformity
Anderson Formation (where preserved) or Fairfield
Group

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 Chapter 5 – Seismic Interpretation

Identified by strong peak in seismic amplitude

Package of bright amplitude, highly laterally
Near Top Laurel
continuous events
Carbonate
Often displayed as bright ‘tram tracks’
Regional carbonate marker

Identified by moderate to strong trough in seismic

amplitude
Near Top Knobby Package of moderate to bright amplitude non-
Sandstone laterally continuous events
Underlies Fairfield Group Carbonate marker
Low Stand Systems Tract

Identified by strong peak in seismic amplitude

Interpretation observes a package of upper
Near Top moderately bright generally laterally continuous but
Ordovician partly irregular events atop a lower package of low
amplitude and seismically dull irregular reflections.
Maximum Flooding Surface of the Ordovician

Identified as irregular to chaotic, moderately bright

to bright reflections that dip steeply towards the
west (on seismic lines in a NW-SE or E-W
Near Top Basement orientation)
Identified as irregular to chaotic, moderately bright
reflections (no apparent dip) (on seismic lines in a
N-S orientation

Table 5.3. Major seismic stratigraphic surfaces and their sequence characteristics.

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 Chapter 5 – Seismic Interpretation

5.3.1 Near Top Meda Transpression

The Near Top Meda Transpression horizon was the first event to be mapped throughout the
dataset. It is an important horizon because it represents a good regional marker, is easily
identifiable on seismic and is a good surface upon which to datum for further interpretation. It
is also significant because the surface indicates the top of the Larapintine L4 Petroleum
System. All of the wells within the study area penetrate the horizon, providing good well
control, however because the Near Top Meda Transpression horizon is a regional
unconformity, lithological relationships across this horizon change. The Grant ‘A’ sand
consistently overlies the unconformity but strata below the unconformity vary from
carbonates of the Fairfield Group to shale-rich interbedded siliciclastics of the Anderson
Formation where preserved.

Due to the nature of the unconformity, the seismic character of the horizon changes between
a peak and trough, and so internal loop ties are based more on the change in seismic character
above and below as opposed to a specific amplitude response. Generally, the location of the
horizon is interpreted to be at the place of maximum discordance between the overlying
Grant Group and underlying strata (Figure 5.5).

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 Chapter 5 – Seismic Interpretation

Figure 5.5. The Meda Transpression Unconformity is at the place of maximum

discordance between the overlying Grant Group and underlying strata.

The interpretation on line RB81-10 (Figure 6.7) demonstrates the onlap of the Grant Group
over the older, broadly folded pre-Permian strata below the Meda Transpression
unconformity. The onlapping geometries and the angular discordances were key
characteristics used to map this horizon within the study area. Note that there are some subtle
disconformities within the lower Grant Group that can blur the exact position of the Meda
Transpression pick, which places a minor uncertainty on the precise location of the horizon in
some areas, particularly where deformation of Middle Carboniferous and older strata is
minimal. Because this truncation is represented by reflector terminations (not a consistent
peak or trough), there were a few places where there were slight misties with the regional
interpretation – principally in the central portion of the study area over the horst block
separating the Billiluna Sub-basin from the Balgo Terrace (Figure 3.4, and RB81-07, SP1200,
Figure 6.5) – though they were resolved to an acceptable standard as they were observed.
Seismic mapping shows that the unconformity is indeed regional, as the truncation event can
be mapped across the whole study area.

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 Chapter 5 – Seismic Interpretation

Confidence in the interpretation of the Meda Transpression event is high over most of the
project area, particularly on the up-thrown side of the Muller Fault (Balgo Terrace) and
throughout the central project area, where the truncation of the Anderson Formation and
Fairfield Group sediments is clear. Mapping of the horizon into the Gregory Sub-basin is less
confident because the reflection terminations that are used to map the character of the horizon
are not as clear (the events above and below the horizon are less angular in their non-
conformance).

5.3.2 Near Top Laurel Carbonate

The Near Top Laurel Carbonate was the second horizon to be mapped throughout the study
area. The horizon was critical to map because it signifies the near top of the Larapintine L3
petroleum system (and indicates the absence of the L4 petroleum system where the Anderson
Formation is eroded). The Larapintine L3 and L4 systems have been targeted as primary
objectives since exploration in the Canning Basin began. The L3 and L4 petroleum systems
host stratigraphy that have revealed the majority of positive basin-wide drilling results to date
(Table 2.1 and 2.2, and Figure 2.8). Therefore, mapping the Laurel Carbonate is an important
horizon to map in this project.

The Near Top Laurel Carbonate is marked by a package of bright amplitude events equaling
approximately 300 milliseconds two-way-travel time (TWT) thickness in the central portion
of the study area, and the package generally thins basinward. The horizon is clearly visible on
RB81-07 (approximately 0.8s TWT, SP 950, Figure 6.5). Thicker packages are also present
on the hanging wall blocks of large normal faults (i.e. within the Stansmore Fault hanging
wall, RB81-7 SP 550, Figure 6.5). The Laurel Carbonate splits into two thinner bright
reflection packages in the northern study area (for example at Lanagan 1, Figure 5.4) with
seismically dull reflection character in the middle, due to lesser intra-Laurel carbonate
interbeds that causes lesser intra-Laurel reflectivity. The carbonate package is the lower
section of the Laurel Formation within the Early Carboniferous Fairfield Group.

Within the study area, the upper partition of the Laurel Formation is largely truncated by the
Meda Transpression unconformity. The marker is te e te by most petroleum wells in the
study area, which produced confidence in the interpretation via good well-to-seismic ties. The

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 Chapter 5 – Seismic Interpretation

horizon allows confident internal loop ties due to a readily identifiable, high amplitude,
laterally continuous seismic response.

The Upper clastic section of the Laurel Formation is truncated by the Meda Transpression
Unconformity on up-thrown fault blocks on the Betty Terrace. Seismic mapping shows that
the carbonate is present throughout the study area, though two-way travel-time structure and
time thicknesses are variable. Seismic mapping shows that the carbonate marker occurs on
the terraces up dip of the Gregory sub-basin and occurrence of the carbonate is less common
basin-ward (into the Gregory Sub-basin) where the continuous bright amplitudes diminish
and the carbonate transitions to shale lithotypes of the surrounding Laurel Formation.

5.3.3 Near Top Grant Group

The Near Top Grant Group was the third horizon to be carried through the study area. The
top of the Grant Group is generally marked by a strong peak on seismic data (thought also a
low amplitude peak at Ngalti 1), representing a shale rich member (Grant ‘C’) at the top of
the formation appearing laterally continuous throughout the project area. The interbedded
relationships of the Grant Group are visible on seismic as non-continuous to irregular,
brightly amplified events. The Grant Group constitutes sandstones interbedded with shale
packages and is divisible in this project into 3 units (Grant C, B and A, youngest to oldest).
The seismic characteristics of these individual members are difficult to correlate within the
Group due to the intricate interbedded marginal marine depositional history (deltaic
sandstones interbedded with prodelta shale lenses). The Grant Group is intersected by all
wells within the study area.

The Horizon for the Near Top Grant Group ties well to external well data and the Near Top
Grant Group package fits the expected seismic character given the above lithological
description. Loop ties for the Grant Formation are satisfactory within the data set. Both the
external and internal seismic ties provide confidence in the interpretation. Seismic mapping
of the Near Top Grant Group reveals that the package exists across the study area, and
reaches near time zero near the northeastern margin of the Balgo Terrace. This is validated by
outcrop on surface geology maps.

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5.3.4 Near Top Knobby Sandstone.

The Near Top Knobby Sandstone is recognized to be a moderate to strong trough in the
seismic dataset due to a negative Reflection Coefficient Impedance t t that is observed
across the faster velocities of the Carbonate rich Laurel Formation (Fairfield Group) into the
relatively slow velocity sediments of the predominantly clastic Knobby Sandstone. The
seismic package is observed as moderate to bright amplitude non-laterally continuous events
representing high sand content partially interbedded with finer clastic lithologies.

The Knobby Sandstone marker location is the last bright amplitude event at the base of the
Laurel Formation package (base of the bright amplitude events at SP 600, 1.2s TWT on line
82GN-20, Figure 6.2). The benefit of mapping the Near Top Knobby Sandstone in this
project, is that the Laurel Formation marker provides a well pronounced ‘tram track’ of
parallel reflections to map (Figure 5.2), which places higher confidence in the mapping of the
Knobby Sandstone horizon throughout the dataset. This procedure saved considerable time.

The Knobby Sandstone is interpreted to exist regionally throughout the study area and
thickens basinward (refer to Chapter 4.5.7). The Knobby Sandstone is suggested to be the
youngest level of stratigraphy (other than Cenozoic cover) within the Billiluna Sub-basin,
however the interpretation here questions this by the inclusion of Fairfield Group packages in
the Billiluna area. Cenozoic cover is abundant and sections of Carboniferous age may be
inaccessible. An isopachus Devonian and Fairfield Group interpretation into the Billiluna
Sub-basin supports the interpretation presented in this thesis. This is an uncertainty, and
Chapter 6.2.3 attempts to provide some resolution.

5.3.5 Near Top Poole Sandstone

The Near Top Poole Sandstone was the fifth horizon carried through the study area. The
horizon is recognized as a moderately strong peak on seismic data due to a positive
Reflection Coefficient Impedance Contrast between the Noonkanbah Formation and the
Poole Sandstone. The seismic sequence is mostly observed as a package of partially laterally
continuous but also partly irregular events caused by interbedded rock packages of variable
porosity (sands and shales). The Poole Sandstone was intersected by all wells within the
study area which produced good well to seismic ties for the horizon (Kilang Kilang 1
synthetic, Figure 5.3). A strong RC impedance contra t present at the top of the unit provides

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a good marker to correlate across the study area, which facilitates good internal loop ties, and
gives confidence in the interpretation.

Seismic mapping reveals that the Poole Sandstone is present throughout the Balgo and Betty
Terraces, and sub-crops on the down-thrown side of the Mueller Fault. The Poole Sandstone
is interpreted to e e t within the Billiluna sub-basin, verified by surface geological
maps.

5.3.6 Near Top Noonkanbah Formation

The Near Top Noonkanbah Formation was the sixth horizon to be carried through the seismic
dataset. The horizon represents the position of the maximum Permian marine transgression.
As such, the marker is observed as a moderate to strong peak, caused by slower velocity
sediments within the Triassic section interfacing faster velocity sediments within the Permian
Noonkanbah Formation. This contrast produces a positive Reflection Coefficient Impedance
Contrast at the horizon. The seismic package is generally observed as moderately high
intraformational reflectivity occurring as continuous lateral events representing a massively
bedded shale, though irregular events are noted due to packages of intraformational sandstone
deposits. The Noonkanbah Formation is penetrated by all wells within the study area and
confidently ties to external wells (for example Olios 1, Appendix B). The horizon has an
excellent internal loop tie. Seismic mapping shows that the Noonkanbah Formation is present
throughout the dataset, though is not present within the Billiluna Sub-basin, verified by
surface geological maps.

5.3.7 Near Top Ordovician

The Near Top Ordovician Horizon is a character interpretation based on its published
geological model (Deep burial, argillaceous lithologies, thickens basinward off the terraces
and into the Gregory Sub-basin). A reasonably strong Reflection Coefficient Impedance
Contrast is expected to be present at the top of this unit contrasting the coarser grained Nita
Formation and Carribuddy Group above, thus giving a strong peak on seismic. Based on
seismic mapping, the interpreted Ordovician package is a sequence of two parts; a
moderately bright generally laterally continuous (but partly irregular) events atop a lower
package of low amplitude and seismically dull irregular reflections. As there are no
intersections of Ordovician rocks within the study area, and the only correlation is via a

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character tie to the Lake Havern 1 well (Figure 5.8), there is low confidence in the accurate
selection of reflection events chosen to represent the Near Top Ordovician. However, the
argument for the presence of an Ordovician package within the project area is still strong
irrespective of the interpretation accuracy. The Ordovician section is mapped throughout the
dataset within a reasonable amount of error or uncertainty.

The interpretation suggests that Ordovician rocks are present in the study area, giving
evidence to confirm the presence of rocks of the Larapintine L2 petroleum system, which is a
significant component of overall prospectivity of the study area. Figure 5.8 demonstrates the
Ordovician tie.

The Near Top Ordovician horizon is based on a seismic character tie to the Lake Havern 1
well (south of the project area. The well reached total depth in Ordovician aged stratigraphy)
(Figure 5.8). The Lake Havern 1 well does not have a time-depth chart. Other wells within
the study area do not penetrate deeper than the Devonian section, which does not allow a
local well-to-seismic tie.

There is some uncertainty in internally tying the Near Top Ordovician horizon between the
northern and southern t of the project area. There are only two north-east oriented lines
that provide the main route of correlation between the southern and northern parts of the
study area; Betty Terrace SS line 81C-1A and Billiluna SS line RB81-11 (Figure 5.6). The
lines RB81-11 and the RB82-17 were reprocessed by different processing houses and a
reasonable mistie is apparent at its intersection (attributed to slightly different processing
sequences which results in time variances in the phase). A small section of line RB81-16 is
also required to complete an arbitrary line to view the tie in a wider context. The southern
correlation path via 81C-1A, which relies somewhat on line 81C-07 which was not
reprocessed to Pre-Stack Time Migration (PSTM) and the reflection events are poorly
imaged, especially for the deeper Near Top Ordovician marker. This results in a less
confident internal tie for the Ordovician.

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Figure 5.6. Seismic grid. Red lines indicate main path to tie horizons across the central
project area.

5.3.8 Near Top Basement

Near Top Basement is not penetrated by any well in the study area or immediate surrounds,
so the basement horizon is solely mapped on its reflection character. The Near Top Basement
horizon is based on seismic imaging of a steeply westerly dipping Precambrian rock 'fabric'
underneath interpreted Ordovician strata (Figure 5.7), presenting a steep angular
unconformity (refer Chapter 2.3.1 and Irwin, 1998). The sequence is observed as irregular to
chaotic, moderately bright to bright reflections that dip steeply towards the west. The
basement fabric provides for a reasonable and consistent marker in the southern part of the
study area, as the seismic surveys in the south are oriented in general alignment with the
fabric dip (east-west). In the northern part of the study area the fabric is not as clear, because
the surveys are oriented in a north-south direction, which does not allow the seismic to best
image the Precambrian fabric. Although the steeply dipping fabric is not as clear in the

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northern part of the study area, the basement is represented by a chaotic reflection character
that maintains a reasonable reflection interpretation.

Figure 5.7. Example of seismic on RB81-6. Westerly dipping reflection events used to
identify Basement are clear (red arrows).

In some localities (for example the most northeastern section of Line RB81-6) there are
pockets of horizontal strata immediately below the Basement horizon. These strata might be
features of Ordovician rocks in this immediate locality rather than Precambrian. These
features are not regularly present on adjacent dip lines. They have been mapped as basement
features for consistency in the interpretation, and probably do not have significant meaning
within the scope of this project.

The only method to tie the Basement horizon to any external data is via surface geology
maps. Precambrian rocks outcrop to the northeast of the Billiluna Sub-basin and to the north
of the Balgo Terrace. Mt Bannerman 1982 seismic line 82GN-02 is acquired over basement
outcrop to the north of the study area and images the chaotic reflections representative of
basement. It would have been beneficial to be able to tie the westerly dipping fabric to

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outcrop on the eastern edge of the study area, however seismic coverage precludes this. A
reasonably confident interpretation of the Near Top Basement horizon is presented here
within the scope of this study.

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Figure 5.8. Arbitrary line used to tie Ordovician package from Lake Haven 1 to the study area. Map (right) shows the arbitrary line (dashed with arrows).
 Chapter 5 – Seismic Interpretation

5.4 Interpretation of Faults

The study area is located on the northeastern corner of the Canning Basin, and comprises
several terraces with stratigraphy thickening into a regional depocentre. Pursuant to
reviewing work by previous authors (Brown, et al., 1984; Smith, 1984; and Yeates, et al.,
1984), the expectation is to see large, down-to-the-basin normal faults between these terraced
areas. This expectation is validated by seismic mapping. Large normal faults are observed,
some exemplifying large throws. Figures 6.2 through 6.7 illustrate faulting geometries and
highlight the structural overprint within the study area.

It is evident from seismic interpretation that the structural overprint is significant. Some faults
are relatively small with minor throws (only affecting stratigraphy within limited shallow
sections) and are too small and erratic within the study area to warrant correlating within the
scope of the project.

The process of fault interpretation in this study essentially comprised defining the tectonic
elements (depocentres and terraced areas) to form a significant basin scale framework, as
well as mapping faults that are likely to provide large structural traps for prospect generation.
The larger faults were correlated by block or 'package' across the study area. Given that there
is a finite time available for the interpretation of this dataset (a number of weeks allocated to
correlating faults), spending more than the allotted time presented a case of diminishing
returns with regards to the fault correlation interpretation at the seismic interpretation stage of
this project.

Fault interpretation was largely undertaken prior to horizon interpretation. This was for the
purpose of familiarization and creating an understanding in the interpreter’s mind of faulting
styles. It was also more practical to have the common faults in place prior to horizon mapping
so that mapping horizons in close proximity to faults was faster.

5.4.1 Confidence in Fault Interpretation

Confidence is generally high in mapping horizons across faults within most of the study area.
Assurance is provided by correlation polygons used within IHS Kingdom to compare
packages of seismic reflection events across fault planes. Further to this, seismic reflection
character is optimized by the seismic reprocessing that was applied to the dataset prior to

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interpretation. Bright ‘tram track’ amplitudes associated with the Fairfield Group (discussed
in section 5.3.2) also assures of confident correlation.

There are, however, two aspects where horizon correlation across faults is less confident. The
first uncertainty is correlating the Near Top Meda Transpression Unconformity horizon
across the Stansmore Fault into the Gregory Sub-basin. Shot point 250 on RB81-7 (Figure
6.5) illustrates a broad anticline in post-Devonian stratigraphy, resultant of compression
associated with the Triassic Fitzroy Movement. Because the unconformity surface parallels
the other post-Devonian surfaces the unconformity loses its distinct character and reflection
terminations.

The second less confident aspect is in regards to the Horst system that separates the Balgo
Terrace from the Billiluna Sub-basin. The lack of confidence in this scenario revolves around
not having any wells within the Billiluna Sub-basin in which to tie the seismic interpretation.
The only method to correlate regional line RB81-7 (Figure 6.5) into the Billiluna Sub-basin is
via surface geology maps showing Devonian outcrop. Near Top Ordovician and Near Top
Basement horizons in the Billiluna Sub-basin rely on an isopachus interpretation.

The Near Top Devonian horizon ties surface geology in the Billiluna Sub-basin (RB81-7,
Figure 6.5), though it’s questionable whether there is any Fairfield Group within the Billiluna
Sub-basin, and if so, how much section is preserved. There are no wells to tie seismic data in
the Billiluna Sub-basin. The interpretation shown on RB81-7 (Figure 6.5) between shot point
1300 and 1400 assumes that the Laurel Carbonate isopach remains consistent across the top
of the Billiluna Horst block and into the Billiluna Sub-basin. Unfortunately Cenozoic cover
prevents validation of the interpretation. The reflection character of the Laurel Carbonate
deteriorates at the top of the Horst (shot point 1200, RB81-7; Figure 6.5). The sediments may
be time equivalent siliciclastic sediments rather th carbonates.

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5.5 Velocity Analysis and Depth Conversion:

Velocity Analysis and Depth Conversion are frequently performed in most seismic
interpretation projects. Given the objectives of this petroleum systems study, a subsequent
important workflow in this project was simulating petroleum systems and their potential
hydrocarbon accumulations in petroleum systems models (discussed in Chapter 8).
Schlumberger PetroMod basin modeling software was used for this workflow. To create and
simulate the structural and stratigraphic geometries of the seismic interpretation in petroleum
systems models, the seismic interpretation (which is constructed in the time domain) needs to
be converted to the depth domain so that the depth domain interpretation can be digitized and
then simulated in Petromod.

Whilst considering the seismic and modelling workflows for this project, and given the time
constraints, it was decided that extensive time spent on Velocity Analysis and Depth
Conversion was not required. Depth maps were deemed to be unnecessary within the scope
of this project, and instead, a simple depth approximation utilizing IHS Kingdom’s ‘Dynamic
Depth Conversion’ tool would be sufficient, and also produce the suitable 2D depth sections
for Petromod.

5.5.1 Dynamic Depth Converter (DDC)

The dynamic depth conversion (DDC) is performed by specifying time and depth data pairs;
such as horizons, formation tops, grids or control points, and selecting a velocity model type
(average or interval velocity). These parameters are specified within HIS Kingdom’s DDC
module.

A time-depth (TD) chart was compiled to gain an understanding of any obvious lateral
variations to velocity across the project area. Figure 5.9 shows that there is good agreement
with time-depth relationships between wells within the project area. The depth conversion
was performed using the 2D seismic interpretation horizons and well formation tops to
develop an average velocity model.

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Study Area T-D

800

1000
Lake Betty 1
1200
Selenops 1
1400
Atrax 1
Depth (mBSD)

1600
Bindi 1
1800

Kilang
2000
Kilang 1

2200 Ngalti 1

2400 Olios 1

2600

2800
0.5 1 1.5 2
TWT (sec)

Figure 5.9. Time-Depth relationship between wells within the project area.

For dynamic depth conversion IHS Kingdom takes the horizon and formation top data
through a process to generate a number of time, depth, velocity, isochron and isochore grids
for each layer of stratigraphy in the model (Kingdom, 2013), according to the following;

1. Create first time grid

2. Compute first time/depth pairs
3. Create average velocity grid
4. Create depth grid
5. Create second layer time, average velocity and depth grids
6. Create isochron grid
7. Create isochore grid
8. Repeat for each additional layer

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The DDC’s resulting conversion is activated within Kingdom by selecting ‘Virtual Depth’
within a 2D section, thus dynamically converting the seismic from the time domain into the
depth domain.

Depth structure maps were not produced because a rigorous depth conversion was not
performed. Therefore, the only insight to spatial structural variability was allowed via TWT
structure maps. There is a large uncertainty present because a complete understanding of the
depth structure is not at hand, and any structure that is presented in any discussion is
therefore an ‘apparent time structure’. Structure maps (in TWT) will not take account of
velocity variability. For example, there may be areas of thick higher velocity material that
may be observed evenly deposited atop an apparent structural trap, thus causing “pull-up”.
The example in Figure 5.10 demonstrates that time interpretation without a proper depth
conversion can falsely pronounce structures. Simply, the structures presented here in time
may not actually occur in depth. This uncertainty is relevant here because there are several
levels of stratigraphy assumed to contain high velocity material, namely the Laurel Carbonate
within the Fairfield Group, the Devonian Bungle Gap Limestone and carbonates in the
Ordovician section (likely within the Nita Formation and Goldwyer Formation).
Travel-Time

High velocity carbonate

Seismic pull-up giving

apparent time structure

Figure 5.10. Schematic illustrating apparent time structures.

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5.6 Two-Way-Travel Time Structure and Time-thickness (Isochron) Mapping

The horizon PSTM interpretation was exported from IHS Kingdom to a Petrosys mapping
Seismic Data File (SDF). IHS Kingdom fault interpretation was similarly taken from
Kingdom into Petrosys for use in contouring. TWT maps were prepared using this data for
each interpreted horizon.

Each horizon was contoured within Petrosys. The contouring was successful with use of
standard gridding functions. Hand contouring was useful in all of the maps to a small extent
to remove anomalous features (bull’s-eyes etc.) that were not verifiably present in the actual
interpretation. Gridding anomalies were most common in areas of greater seismic line
spacing or where there is a lack of data to constrain the grid. Hand contouring was also useful
at the ‘near zero edge’ of shallower units to tie the interpretation to surface geology maps.
Hand contouring was necessary to contour the deeper areas of the Gregory sub-basin where
only few seismic lines allow proper definition of the subsurface, and to clip the gridding
function to a clipping polygon (so that the grid does not extrapolate further than the seismic
grid).

TWT thickness (isochron) maps were produced in Petrosys by subtracting a deeper TWT
structure map from the TWT surface immediately above. Hand contouring was required for
the isochron maps for the shallow Near Top Poole Sandstone as well as the deeper Near Top
Ordovician. The Ordovician only required minimal assistance with guide contours that could
then be applied to the gridding function and allowed to infill, similarly for most other
horizons in places of less seismic data.

The Near Top Poole Sandstone isochron required extensive hand contouring. This was
principally because this layer of the stratigraphy is generally quite thin and fairly isopachus
across the study area, with only a few exceptions in fault hanging walls, thus hindering the
ease at which the gridding algorithm can ascertain values or trends to contour. Hand
contouring for the Near Top Poole Sandstone isochron is made fairly obvious by the lack of
detail in contouring compared to other isochron maps, though I expect that the true variability
of the Poole Sandstone stratigraphic unit to be much more inhomogeneous in reality (the
same could be said about the other isochron maps presented here also, even though their
isochrons show more erraticism represented by each contour). Figures 6.11 to 6.25
demonstrate the TWT structure and isochron maps within the study area.

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6. Basin Architecture: Structural Framework

Basin architecture determines the distribution (extent and thickness) of likely source rock and
reservoir rock intervals, and defines structural styles and trapping geometries. Therefore, the
characterisation of basin architecture is a critical component of petroleum systems analysis.
Together, with source rock richness (Chapter 7) and petroleum systems modelling (Chapter
8), the mapping of basin architecture formed a significant portion of this research project.

Chapter 6 discusses the structural and stratigraphic framework of the Balgo Terrace, Betty
Terrace and Billiluna Sub-basin, which is the result of workflows outlined in Chapter 4 and
Chapter 5.

The key research questions that Chapter 6 aims to answer are:

What is the nature of regional faulting within the study area?

What is the distribution of prominent source rocks and reservoir rocks?
Do regionally prominent source rocks and reservoir rocks exist within the study area?
Are favourable trapping geometries and packages likely to contain sealing rocks
present in the study area?
What is the likely time-thickness and time-configuration of the key stratigraphic
units?

6.1 Seismic Interpretation Results

The following section presents the results of the seismic interpretation to give insight into
structural features. Figure 6.3 through Figure 6.7 demonstrates a representative example of
the seismic grid in different regions of the project area. Key lines were chosen to demonstrate
structural and stratigraphic variability. The lines that are presented are summarised in Table
6.1, and the distribution of the lines are highlighted in Figure 6.1.

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Survey name Line

Mt Bannerman 1982 SS 82GE-33
Mt Bannerman 1982 SS 32GN-01
Mt Bannerman 1982 SS 82GN-20
Billiluna SS RB81-1
Billiluna SS RB81-7
Billiluna SS RB81-10
Table 6.1. 2D seismic lines presented to demonstrate seismic interpretation and geologic features with the
project area.

Figure 6.1. Distribution of seismic lines presented in Table 6.1.

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Figure 6.2. Line 82GN-20 demonstrates structural configuration (dip section) in the north western portion of the
study area. Bare seismic (reprocessed) (top), interpretation of reflection events (middle) and geologic model
from 2D (bottom).

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Figure 6.3. Line 82GN-01 demonstrates structural configuration (dip section) in the mid-north portion of the study area.
Bare seismic (reprocessed) (top), interpretation of reflection events (middle) and geologic model from 2D (bottom).

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Figure 6.4. Line 82GE-33 demonstrates structural configuration (strike section) in the northern portion of the study
area. Bare seismic (reprocessed) (top), interpretation of reflection events (middle) and geologic model from 2D
(bottom).

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Figure 6.5. Line RB81-07 demonstrates structural configuration (dip section) in the north eastern portion of the study area.
This line gives the longest cross section image of the geologic configuration across all tectonic provinces within the study
area. Westerly-dipping pre-Cambrian fabric that is used to identify Basement is clear in the image. Bare seismic
(reprocessed) (top), interpretation of reflection events (middle) and geologic model from 2D (bottom).

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Figure 6.6. Line RB81-01 demonstrates structural configuration (dip section) in the south eastern portion of the study area.
Bare seismic (reprocessed) (top), interpretation of reflection events (middle) and geologic model from 2D (bottom).

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Figure 6.7. Line RB81-10 demonstrates structural configuration (strike section) in the central-south eastern portion of the
study area. Bare seismic (reprocessed) (top), interpretation of reflection events (middle) and geologic model from 2D
(bottom).

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6.2 TWT Structure and Isochron Maps

Two-Way-Time (TWT) structure maps were produced for the interpreted horizons in Table
6.2. The results are shown in Figure 6.11 through Figure 6.18 at the end of this Chapter.

Isochron maps were produced for the interpreted horizons in Table 6.2. The results are shown
in Figure 6.19 through Figure 6.25 at the end of this Chapter.

6.2.1 The Case for a Revised Tectonic Elements Map

The tectonic elements that are provided by the Western Australia Geological Survey (GSWA)
are shown in Figure 6.8. A revision to the tectonic elements map (Figure 6.8) is supported
here by correlating larger faults within the project area. Dashed-lines in Figure 6.8 represent
uncertainty in the correlation in the central portion of the study area due to lesser data, and
also on the northern basin margin where there is either no seismic, or data quality diminishes.
The revision is not extreme, although it implies that the geological characteristics of the
Gregory Sub-Basin are closer to the centre of the project area. As the Gregory Sub-basin is
considered to host significant organically rich source rocks, it suggests that source rocks
within the Gregory Sub-basin are nearer to potential reservoirs and trapping geometries that
may exist within the study region, and that hydrocarbons require less lateral migration to fill
traps. The interpretation here is similar to a map presented in Smith (1984), though the
tectonic elements described here show the inferred faulting (dashed lines) to follow the
boundary of the central depocentre, rather than cutting across it.

The revised tectonic element outlines are utilized in all TWT structure and isochron maps in
this Chapter.

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Figure 6.8. Tectonic divisions provided by GSWA (left) and proposed revision to the tectonic divisions
pursuant to seismic interpretation (right). The spatial positioning is similar, but implies that the Gregory Sub-
basin extends further to the northeast.

The Discussion below divides the study area into two main portions; the northwest, and
southeast. The central study area is intermittently referred to in the ensuing sections (Figure
6.9). The division is not based on any geologic feature but rather makes the interpretation
more manageable.

Figure 6.9. The northwestern, central and southeastern portions of the study area. Separation is
arbitrary, but provided to aid in managing the interpretation.

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6.2.2 Northwestern Study Area

Seismic interpretation reveals that there are two collections of stratigraphic (apparent
seismic) dips in the northwestern portion of the study area. The regionally extensive
Carboniferous Meda Transpression unconformity (Near Top Meda Transpression Horizon)
separates the geology and represents an angular unconformable surface in most of the project
area, most clearly observed on strike line 82GE-33 (Figure 6.4) where Carboniferous and
older strata are truncated. Stratigraphy below the Meda Transpression unconformity (i.e. the
Anderson Formation (where preserved), Fairfield Group, the Siluro-Devonian and
Ordovician aged rocks) shows gentle apparent dips (approximately 15-20 degrees in time
section e . ) into the basin dipping towards the south and southeast, whereas
stratigraphy above the Meda Transpression (ie the Grant Group, Noonkanbah Formation and
Poole Sandstone) is generally flatter lying, and dip towards a similar south-southeast
direction. The interpretation shows deeper packages of Ordovician to Early Carboniferous
age are conformable and parallel in their extent, as is the stratigraphy post-Meda
Transpression erosion. In the northwestern portion of the study area stratigraphic dips are
generally similar across the Balgo and Betty Terraces, where the only variation is due to the
proximity of the central depocentre (ie dips on line 82GN-01 appear steeper than on
82GN-20, which is also consistent with TWT structure of Carboniferous and older strata).

It is clear from contour mapping that the dips observed from lines 82GN-20, 82GN-01 and
82GE-33 are on the northern edge of a depocentre located in the central portion of the study
area (considered here an extension of the Gregory Sub-basin rather than a separate feature –
per revision of tectonic elements, Chapter 6.2.1). The depocentre is more pronounced in pre-
Carboniferous time (see TWT maps of the Fairfield Gp, Figure 6.15; Siluro-Devonian, Figure
6.16; and Ordovician sections, Figure 6.17), and there is a slight thickening of pre-Meda
Transpression sediments in this part of the region towards and within the Gregory Sub-basin.
Stratigraphy above the Meda Transpression remain fairly isopachus and the trend into this
central depocentre is less pronounced.

Basement in the northwestern portion of the study area is mapped as a chaotic reflection
character underneath a package of Ordovician age reflections. The westerly dipping ‘fabric’
(Chapter 5.3.8) is not clearly observed in this northern area. Basement is seen to deepen in
accordance with the central depocentre (southwards) and is in excess of 4 seconds TWT on
82GE-33. Line 82GE-33 and 82GN-20 (Figure 6.4 and Figure 6.2 respectively) demonstrate

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a shallowing basement trend (to 2 seconds TWT) towards the west as the strata moves
towards the Jones Arch (west of the study area). All pre-Carboniferous stratigraphy appear
to thin towards the Jones Arch and towards the northern basin limit. The Anderson
Formation is generally preserved in the central depocentre and thins to the north with other
strata, though The Meda Transpression truncates the units of the Anderson Formation
completely to the west (towards the Jones Arch) (there is no preserved Anderson Formation
on line 82GN-20), and the Anderson Formation subcrops before reaching Selenops 1 or Olios
1 in the north (Meda Transpression TWT structure, Figure 6.14).

Dip lines 82GN-20 (Figure 6.2) and 82GN-01 (Figure 6.3) demonstrate the main fault
elements within the northwestern part of the study area. Most of the faulting was active
throughout the Ordovician extension, and again in the Mid Carboniferous. Fault throws are
difficult to quantify in Early Ordovician time as reflection events within acoustic basement
are not clearly identifiable. It is assumed that fault throws observed within the main
stratigraphic section are generally representative of throws that are not clearly visible due to
poor reflections.

82GN-20 (Figure 6.2) shows sediments intersecting the northern limit of the basin at the
eastern end of the Pinnacle Fault; a normal fault that is a more prominent feature on the
Lennard Shelf (a similar strike-related shelfal position to the northwestern portion of the
study area). The Pinnacle Fault show to be active throughout the Ordovician and appears
to control sedimentation through to the Permian (Poole Sandstone). Near surface data quality
issues make the shallow parts of the Pinnacle Fault difficult to identify, though it is likely that
the Pinnacle Fault controlled sedimentation along the northern basin margin into the Triassic.
82GN-20 (Figure 6.2) and 82GN-01 (Figure 6.3) demonstrate the Hinge Fault in this portion
of the study area. The Hinge Fault is a large normal fault the separates that Balgo Terrace
from the Betty Terrace. The Hinge Fault was active throughout the Ordovician and in periods
through to the mid-Carboniferous, evidenced by slight thickening in Devonian and
Carboniferous reflection packages. 82GN-20 also shows the normal Stansmore Fault system.
The Stansmore Fault system is one of the most significant faults in the study area, and
separates the Betty Terrace from the Gregory Sub-Basin. The Stansmore Fault was active
throughout Ordovician times and in periods through to the Mid-Carboniferous, shown by
slight thickening of the Siluro-Devonian section below the Intra-Devonian reflection event
(labeled on 82GN-20, Figure 6.2). The fault does not appear to control sedimentation post-
Meda Transpression time.

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Strike line 82GE-33 (Figure 6.4) demonstrates faulting geometries within the Betty Terrace.
Here, normal faults are consistent with main faulting regimes (the nearby Stansmore and
Hinge Faults). The faulting patterns are illustrated to offset Siluro-Devonian to Carboniferous
stratigraphy (related to mid-Carboniferous Meda Transpression deformation). The seismic
suggests that these faults do not exten to the Ordovician strata, though data quality also
deteriorates and some of the large faults in 82GN-33 may in fact penetrate Ordovician aged
section (Figure 6.4).

82GN-01 (Figure 6.3) and 83GE-33 (Figure 6.4) show some instances of shallower faulting
through the Anderson Formation and into the Grant Group. The shallow faulting observed
here is possibly remnants of the Triassic aged Fitzroy movement, or more recent Jurassic
events. Duddy et al. (2003) concluded that Triassic to Jurassic tectonic events removed up to
2500 metres of Triassic sediment within the Canning Basin, and faulting seen in shallow
parts of the preserved section may be related to this exhumation.

6.2.3 Southeastern Study Area

Seismic lines RB81-07 (Figure 6.5), RB81-01 (Figure 6.6) and RB81-10 (Figure 6.7) of the
Billiluna 1981 Seismic Survey are some of the longest 2D lines in the project and present a
good reflection image of the subsurface across the southeastern project area. Line RB81-07
specifically, provides an excellent cross section of the otherwise data-poor Billiluna Sub-
basin, as well as the Balgo Terrace, Betty Terrace and proximal section of the Gregory Sub-
basin.

Seismic interpretation e RB81-07 Figure 6.5 and RB81-01 Figure 6.7) show that
stratigraphic (apparent seismic) dips of post-Carboniferous stratigraphy (Grant Group,
Noonkanbah Formation and Poole Sandstone) are at approximately 10 degrees to the
southwest (basinward), conformable, and thickening basinwards. There is, however, a greater
variability in pre-Carboniferous stratigraphic dips in the southeastern portion of the study
area due to a broad anticline that developed in the Triassic (RB81-7, SP 300, Figure 6.5),
though dips overall appear to trend towards the Gregory-sub basin. Reflections in the
Billiluna Sub-basin (RB81-07) dip towards the Mueller Fault between approximately 10 and
15 degrees.

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 Chapter 6 – Basin Architecture: Structural Framework

Reflections in the Betty Terrace and Gregory Sub-basin tend to show a broad anticline
appearance (RB81-07, Figure 6.5) in the central project area, where the Stansmore Fault cuts
the anticline between the Gregory Sub-basin and Betty Terrace. It is difficult to confirm
whether the stratigraphic thickening of the post-Carboniferous units at the southwestern-most
edge of line RB81-07 (left flank; basinward side of the broad anticline, Figure 6.5) is related
to the large graben system of the Gregory Sub-basin, possibly reactive in periods up to the
mid-Jurassic. The RB81-7 line is not quite long enough th , though the opposing listric
fault to the Stansmore, on the southwestern edge of the Gregory Sub-basin (illustrated by the
dashed line), is likely related to a mirror image of what is visible on the southwestern flank
of RB81-7.

Stratigraphic reflections within the Balgo Terrace and Betty Terrace appear generally
horizontal; also appearing as a subtle broad syncline on the Balgo Terrace (RB81-07, Figure
6.5), though the same synclinal form cannot be seen in the southern end of the project area
(RB81-01, Figure 6.6). TWT structure over the Balgo Terrace in this region (refer to
intersection of RB81-07 and RB81-10 and TWT maps for Fairfield Group, Figure 6.15, and
Devonian sections, Figure 6.16) reveals a trough in the Balgo Terrace, and a structural nose
developing through Ordovician to Early Carboniferous time. The Ngalti 1 well was drilled on
the ridge at the apex of this structural nose.

Basement in the southeastern portion of the study area is characteristically different than
observed in the northwestern area. Lines RB81-07 (Figure 6.5) and RB81-01 (Figure 6.6)
show a westerly dipping ‘fabric’ (steeply dipping pre-Cambrian beds, or tilted fault blocks).
Reflection events are also slightly more chaotic here than in the younger Canning Basin
stratigraphy. The Ordovician rocks appear to unconformably overly the basement in this
regard. As noted in text earlier in this Chapter, only the northwest-southeast oriented lines
(such as RB81-07, Figure 6.5) reveal this fabric because seismic imaging on lines oblique to
the fabric do not capture these ‘intra-basement’ reflections and instead represent basement as
a chaotic package.

Basement in the southeastern study area is in excess of 4 seconds TWT trending into the
Gregory Sub-basin (and continues below the section view on RB81-07). In the central part of
the project area, basement averages 2 seconds TWT on the Balgo Terrace and shallows to 1
second TWT in the Billiluna Sub-Basin, eventually outcropping at the northeastern basin
margin (TWT structure on Near Top Basement, Figure 6.18; not visible on seismic data). The

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southern-most part of the project area shows similar basement (apparent) depths, and is
viewed on RB81-10 (Figure 6.7) shallowing to 1 second TWT towards the southeastern basin
margin. Basement continues to shallow out of the section view to approximately tie surface
geology.

Seismic line RB81-07 (Figure 6.5) demonstrates the major faults that define the tectonic
regions within the study area. The reader is also referred to the TWT structure map on the
Near Top Basement (Figure 6.18) as this will aid in visualizing the geometries of the major
faulting elements. The Stansmore Fault separates the Betty Terrace from the Gregory Sub-
basin. All of the pre-Carboniferous stratigraphy appears to thicken in the Stansmore Fault
hanging wall (into the Gregory Sub-basin, Figure 6.15 and Figure 6.16). The Fairfield Group
show to be truncated by the Meda Transpression unconformity in the footwall in this
vicinity, though small sections of preserved Anderson Formation may indicate an upper limit
of Fairfield Group deposition on the Betty and Balgo Terraces, suggesting that Fairfield
Group deposition is controlled by the Stansmore Fault in the Gregory Sub-basin. This
demonstrates a synrift sequence, also observed with lesser throw on RB81-1 (Figure 6.6). A
similar thickening can be seen in the Siluro-Devonian section across the Stansmore Fault, and
also a slight thickening in the Ordovician strata (Figure 6.5; also isochron maps for the
Fairfield Group, Figure 6.23; Siluro-Devonian, Figure 6.24; and Ordovician, Figure 6.25).
This indicates that the Stansmore Fault (and the Gregory Sub-basin system in a larger
context) was active in periods from the Ordovician through to the mid-Carboniferous,
alluding to syndepositional faulting associated with the Gregory Sub-basin. The same
thickening cannot be seen in Late Carboniferous and younger rocks.

The Hinge Fault in the southeast area (RB81-07, Figure 6.5) shows slight synrift thickening
in the Ordovician and thickening of the Siluro-Devonian stratigraphy, terminating at the
Meda Transpression Unconformity. Whilst deformation is clear in the Carboniferous at this
location (for example in the Fairfield Group), the same influence on deposition is not as
clearly observed in the preserved section of the Fairfield Group as it is across the Stansmore
Fault, where only a minor amount of thickening is observed.

The Mueller Fault (imaged on RB81-07, Figure 6.5) is a large listric fault separating the
Billiluna Sub-basin from the Balgo Terrace. A decline in seismic data quality makes
identifying fault throws slightly more difficult in the Billiluna Sub-basin. The interpretation
shows the Mueller Fault throwing down to the northeast into the Billiluna Sub-basin and

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away from the Gregory Sub-basin. RB81-07 shows very slight TWT thickening of the
Ordovician and Siluro-Devonian packages across the Mueller Fault into the Billiluna Sub-
basin at the fault intersection (Figure 6.5).

The interpretation also indicates a package of Carboniferous Fairfield Group in the Billiluna
Sub-basin (RB81-7, Figure 6.5). As mentioned previously, there are no wells in the Billiluna
Sub-basin, and Cenozoic cover (per surface geology) makes tying the interpretation to
external data nearly impossible, however younger units (Permian) and older units (Devonian)
show outcrop on surface geology maps that tie the respective parts of the interpretation. To
keep the mapping as isopachus as possible across the Mueller Fault, the Fairfield Group is
interpreted to exist in the Billiluna Sub-basin. Note however, that if no Fairfield Group were
to exist in the Sub-basin, the Devonian would be thicker than what is shown here (RB81-7,
Figure 6.5), which could imply that the Mueller Fault might actually dip in the opposite
direction towards the Gregory Sub-basin (assuming a normal/extensional stress regime,
which is evident throughout Canning Basin geological history). Another alternative that
would allow the Siluro-Devonian to exist at surface along the whole Billiluna Sub-basin in
place of the Fairfield Group; is to suppose that the Fairfield Group (or equivalent) was
deposited in the Billiluna Sub-basin, and due to reactivation on the Mueller Fault (potentially
during the Triassic aged Fitzroy event) the fault was inverted, and the Fairfield Group eroded
in Triassic time; thereby bringing the Siluro-Devonian to surface. An expectation though
would be to see inverted reflection events with a possible null-point (though this may have
also been eroded along with the Fairfield Group). Again, seismic data quality makes these
determinations difficult, and it is thought that the interpretation represents the (simpler?)
optimistic view for the purposes of this study.

Two-way-travel time (TWT) structure on the top of the Late Carboniferous to Permian units
(Noonkanbah Formation, Poole sandstone and Grant Group; Figure 6.19 to Figure 6.21) show
that these surfaces gently dip at approximately 10 degrees to the southeast into the Gregory
Sub-basin. Dips of the Late Carboniferous to Permian strata steepen slightly in the northwest
(mentioned above). There is a high at this level in the stratigraphic sequence in the Gregory
Sub-basin at 20° 14’S, 127° 10’E (Kilang Kilang 1 the flank of this structure, approximately
on line RB81-07, Figure 6.5; and cross section B-B’, Figure 4.45). The Noonkanbah
Formation and Poole Sandstone outcrop on the northwestern and southwestern basin margin,
and along a northwestern trend across the Balgo and Betty Terraces. The Grant Group is
noted to outcrop further into the study area on the Balgo Terrace (Figure 6.13). Faulting is

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likely to intersect these Late Carboniferous to Permian units, potentially a product of the
Triassic Fitzroy Movement, however faults were not correlated across these surface as they
were not significant to the tectonic province definition or prospect generation, or achievable
within time constraints allocated for this stage of the project (refer to Chapter 5.4).

The Meda Transpression Unconformity is a regional marker across the study area and
represents a regional exposure surface. The unconformity truncates Early Carboniferous
stratigraphy across the Canning Basin (Figure 6.14). The Meda Transpression surface is also
a proxy here for TWT structure of the Anderson Formation (Figure 6.22), because in many
places the Anderson Formation is truncated to great extent by the regional unconformity. The
Meda Transpression surface generally mirrors younger surfaces in apparent seismic dip with
the exception of a low in the surface in the central project area on the Betty Terrace 19° 36’S,
127° 13’E (TWT structure on the Near Top Meda Transpression; Figure 6.14) that appears to
develop a connection or ‘trough’ in the Gregory Sub-basin. The high that is present in the
younger surfaces (at 20° 14’S, 127° 10’E, Figure 6.13) is also present in the Meda
Transpression surface, suggesting that the feature was generated after the unconformity
associated with this Carboniferous event. The high occurs generally consistently on
reflections at this location (RB81-07) and is probably associated with compressional events in
the Triassic Fitzroy Movement. Another subtle high in this surface is noted in the
southeastern project area on the Betty Terrace at 20° 15’S, 127° 46’E.

TWT structure on the top of Late Carboniferous and older units (Fairfield Group, Siluro-
Devonian, Ordovician and Basement packages, Figure 6.15 through Figure 6.18) show a very
different structural form than younger units, explained by the structural overprints introduced
by the Carboniferous Meda Transpression event and also the Triassic Fitzroy Movement.

Two broad (approximately 50 kilometers wide each) northeast-southwest oriented lows are
noted as major structural features separated by a ridge in the central project area (20°S, 127°
10’E, RB81-10; Figure 6.7), deepening to approximately 2.4 seconds TWT in each low at the
Fairfield Group level (Figure 6.15). The northern-most low continues over the Betty and
Balgo Terrace and appears to continue to the northern basin margin. The southern low
appears more disconnected from the basin margin and is generally more confined to the
Gregory Sub-basin. A projected position (a useful but non-optimal cross section) of the lows
and central ridge can be seen on RB81-10 (edge of the northern low at SP 1, central ridge at
SP 400 and southern low at SP 750; Figure 6.7) The ridge appears on RB81-10 as an

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anticline, and the lows are synflormal off the anticline flanks to the northeast and southwest.
The features are probably the product of mid Carboniferous compression events, after uplift
and erosion of the Pre-Carboniferous stratigraphy. The northern low may be influenced by
north-south oriented strike slip faults of the Halls Creek region (Figure 6.8), as the low trend
intersects the northern basin margin where the Halls Creek zone had greater influence on the
basin.

Up dip across the Stansmore Fault (northeast-ward), the central area ridge (or anticline)
broadens to a more complex faulted structural nose (19° 50’S, 127° 21’E, Figure 6.15). The
nose trends similar to the central ridge – northeast-southwest, and is intersected and flanked
along strike by grabens associated with the Hinge Fault system. Ngalti 1 tested the apex of
this structural feature. The structure extends from the Stansmore Fault, across the Betty and
Balgo Terraces and intersects the Mueller Fault. It is questionable from current seismic data
as to whether the same structural feature continues across the Mueller Fault into the Billiluna
Sub-basin.

In the southeastern project area, an elongate northeast trending high exists in the pre-
Carboniferous levels at 20° 17’S, 127° 46’E (approximately 26 km x 13 km, Figure 6.16).
The high spans across the Betty and Balgo Terraces. Viewing the projected position of the
high on RB81-10 (Figure 6.7) shows that it probably formed as a product of Mid-
Carboniferous tectonic events. The high is intersected by a graben at the crestal position
(refer TWT structure on Near Top Fairfield Group, Figure 6.15), RB81-10 shows that there is
a minor amount of apparent throw offsetting the Fairfield Group and Siluro-Devonian
section.

6.2.4 Structural Lead Identification

Seismic interpretation has produced numerous apparent time structures within the project
area, across several levels of stratigraphy. Structural development is most clearly noted on the
TWT structure map on the Near Top Fairfield Group (Figure 6.10). Structural development
also translates through other levels, illustrated in Figure 6.16 and Figure 6.17. Although many
more traps are identifiable, it is prudent to identify a selection that appear common
throughout the stratigraphy (Table 6.2). Closure areas are based on closing contours in Table

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6.2. The purpose of identifying structural traps at this stage gives another goal to 2D basin
modelling. It is not a goal here to construct a detailed prospect portfolio.

Closing Closure
Trap contour (TWT Area Seismic reference Nature of Trap
msBSD) (Km2)
Structural; fault bound
A 800 363 RB82-28
to northeast

Arbitrary line (S85LM-08, Structural; fault bound

B 900 139
S85LM-08A, 82GN-03 to north

Structural; atop the

C 750 20 RB81-7 Billiluna Horst, fault
bound to north and south

Structural, fault bound to

D 700 308 RB81-7
northeast and southwest

Structural; found bound

E 500 63 RB82-23
to northeast
Table 6.2. Summary of key structural leads identified from seismic interpretation.

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Figure 6.10. Key structural leads identified from seismic interpretation. Leads are apparent time structures that
exist on multiple levels. Demonstrated on the Near Top Fairfield TWT map in this instance.

The red seismic lines on Figure 6.10 indicate where 2D modelling would be most valuable.
2D petroleum systems models will test apparent time structures, and importantly have
regional distribution to enable a thorough understanding of thermal maturity and petroleum
system evolution across the project area.

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 Billiluna
Sub-basin

Figure 6.11. TWT structure on Near Top Noonkanbah Formation.

 Billiluna
Sub-basin

Figure 6.12. TWT structure on Near Top Poole Sandstone.

 Billiluna
Sub-basin

Figure 6.13. TWT structure on Near Top Grant Group.

 Billiluna
Sub-basin

Figure 6.14. TWT structure on Near Top Meda Transpression Unconformity.

 Billiluna
Sub-basin

Figure 6.15. TWT structure on Near Top Fairfield Group.

 Billiluna
Sub-basin

Figure 6.16. TWT structure on Near Top Devonian.

 Billiluna
Sub-basin

Figure 6.17. TWT structure on Near Top Ordovician.

 Billiluna
Sub-basin

Figure 6.18. TWT structure on Near Top Basement.

 Billiluna
Sub-basin

Figure 6.19. Noonkanbah Formation isochron.

 Billiluna
Sub-basin

Figure 6.20. Poole Sandstone isochron.

 Billiluna
Sub-basin

Figure 6.21. Grant Group isochron.

 Billiluna
Sub-basin

Figure 6.22 Anderson Formation isochron.

 Billiluna
Sub-basin

Figure 6.23. Fairfield Group isochron.

 Billiluna
Sub-basin

Figure 6.24. Siluro-Devonian isochron.

Figure 6.25. Ordovician isochron.
 Chapter 7 – Source Rock Assessment

7. Source Rock Assessment

7.1 Introduction

A petroleum system, defined in Chapter 2, is a geologic system that encompasses the

hydrocarbon source rocks and all related oil and gas, and which includes all of the geologic
elements and processes that are essential if a hydrocarbon accumulation is to exist (Magoon
and Dow, 1994). To investigate whether active petroleum systems exist within the project
area, source rocks of sufficient organic richness and thermal maturity able to generate
hydrocarbons must be identified, and the optimal timing of the occurrence of petroleum
system elements and processes must be resolved to determine whether hydrocarbons may be
preserved over geologic time to present day.

The goal for this Chapter is to investigate the stratigraphy within the study area to identify
source rock potential in relation to organic richness. To accompany this assessment, the
stratigraphy will also be examined for thermal maturity in Chapter 8. Between this Chapter
and the next, the requirement is to understand source rock quantity (organic richness), quality
(organic matter type) and thermal maturity.

7.2 Method and Data

To investigate source rock richness, Total Organic Carbon (TOC) and Rock Eval Pyrolysis
data was obtained from published reports (refer to Reference List), Well Completion Reports
(WCR) and also from the GSWA online database (GSWA, 2013), which is a collation of
regional well data for the entire Canning Basin. The data was quality controlled for reporting
accuracy and loaded into Microsoft Excel. It is important to note that the analysis within this
Chapter contains data from outside of the project area, because the project area alone has a
relatively lean number of wells compared to other shelfal positions in the Canning Basin.
Where appropriate, wells located outside of the study area that provide information are
identified in the text. All data used in this Chapter are available in Appendix C.

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7.3 Analytical Techniques and Definitions

This analysis makes use of three parameters to consider candidate source rock quantity,
quality and thermal maturity:

1. Total Organic Carbon (TOC)

2. Rock Eval Pyrolysis
3. Vitrinite Reflectance (%Ro)

7.3.1 Definition of a Source Rock

A source rock is a rock that is capable of generating or that has generated movable quantities
of hydrocarbons (Beaumont and Foster, 1999). Source rocks within this Chapter are
discussed regarding their ‘potential’ to generate hydrocarbons. Terms ‘petroleum potential’,
‘genetic potential’ and ‘generative potential’ are arbitrary terms that are used interchangeably
to deliberate how a prospective source rock may perform. In any case, the potential of a given
source rock represents the amount of petroleum (oil or gas) that the kerogen within the rock is
able to generate, if it were subjected to an adequate temperature over a sufficient time period
(Tissot and Welte 1984).

The potential of a source rock also is variable (thus a qualitative term), and depends on the
mineral and maceral (organic component) composition a given rock. In a conventional
sense, source rocks are usually represented as shales (siliciclastic mudstones that break along
cleavages, known as fissile shales). Carbonate rocks are also able to be generative source
rocks. Tissot and Welte (1984) state that carbonates can produce a higher amount of
petroleum per amount of organic matter. This is because carbonates tend to contain lesser
amounts of reworked terrestrial matter and high percentages of marine organics.

7.3.2 Total Organic Carbon

Total Organic Carbon (TOC, weight %) characterises the amount of organically derived
carbon in a sample of rock and comprises kerogen and bitumen. TOC does not wholly define
petroleum source rock capability, though is essential if a source rock is to generate any
hydrocarbons at all (Peters and Cassa, 1994). TOC is most commonly measured using the
Direct Combustion technique; whereby a small ground sample is first treated with

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hydrochloric acid to remove carbonate based carbon, and is then washed and dried to 100°C
for 30 minutes. The residue is combusted in a high-frequency induction furnace to 1200°C
and measured as Carbon Dioxide (Peters and Cassa, 1994). Other methods of TOC
determination are highlighted in Peters and Cassa (1994).

Results in the ensuing text utilise present-day TOC; that is, TOC measurements which reflect
organic carbon at maximum thermal maturity settings. For mature source rocks, present-day
TOC measurements echo quantities of organic carbon that have matured through
hydrocarbon product windows over geologic time and have undergone some degree of
conversion to petroleum. For mature source rocks, present-day TOC will be less than initial
TOC (TOCi; organic carbon at initial burial). For immature source rocks, present-day TOC
can be similar or equal to TOCi. It is important to recognise this difference because present-
day TOC often underestimates the total source rock generative potential. TOCi estimates are
utilised within petroleum systems modelling (Chapter 8). Peters et al. (2005) provides a
method for estimating TOCi.

Peters and Cassa (1994) characterise source rock potential using the TOC parameter in Table
7.1.

Table 7.1. Petroleum potential classification based on organic matter TOC and Rock Eval Pyrolysis (Peters and Cassa, 1994).

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7.3.3 Rock Eval Pyrolysis

Rock Eval Pyrolysis was first developed by Espitalié (1977) at the French Petroleum Institute
as a rapid screening tool to characterise source rock capacity. The method, also highlighted
by Tissot and Welte (1984), is a useful solution to characterise source rocks in place of other
chemical methods that are time intensive and expensive to isolate kerogens. Rock Eval
Pyrolysis is a suitable substitute to expensive and time consuming chemical analyses as it is
relatively inexpensive, and takes about 20 minutes per analysis (Peters, 1986).

The method subjects a small (100 mg) sample to progressive heating up to 550°C in an inert
atmosphere at a programmed temperature profile, stepping 25°C per minute. During the test,
hydrocarbons that are existing within the sample (bitumen) are released at moderate (~300°C)
temperatures (at the S1 peak). Programmed temperatures continue to rise at 25°C per minute
in the test chamber where kerogen is ‘pyrolised’ to generate hydrocarbons and hydrogen-like
compounds (at an S2 peak) utilising the remaining organic carbon. Oxygen rich volatiles
(carbon dioxide) are later released (at an S3 peak). The compounds are passed through a
flame-ionisation detector (FID) and a thermal conductivity meter to measure S2 and S3. The
temperature at which maximum hydrocarbons are generated in the test chamber is recorded
as the Tmax parameter (Tissot and Welte 1984). Figure 7.1 illustrates the temperature profile
of a pyrolysis record. Tmax values always increase with higher thermal maturity (Hantschel
and Kauerauf, 2009) and hence are a good tool for quick estimates. The correlation between
Tmax and hydrocarbon product windows varies with organic matter type, where sensitivity is
greatest in determining maturity in type II kerogens. Correlations can be made with vitrinite
reflectance (Burrus, 1985).

Peters (1986) illustrates some pitfalls of the Rock Eval Pyrolysis method. A key take-away
from the work of Peters 8 , is that interpretation of Pyrolysis and TOC data should be
made encompassing lithological information, mineral matrix information, well conditions,
locally generated or migrated hydrocarbon information and laboratory pyrograms. It is
important to note that abundant mineral matrix information, data on locally derived
hydrocarbons and laboratory pyrograms are unavailable at the time of this study.

Peters (1986) notes that due to the adsorption of pyrolytic organic compounds onto the
mineral matrix of the Rock Eval sample, Pyrolysis results in the S2 and Tmax parameter that
correspond with Total Organic Carbon content less than 0.5% should be discarded from
interpretation (Peters, 1986). S2 and Tmax results corresponding to TOC less than 0.5% can

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 Chapter 7 – Source Rock Assessment

produce unreliable HI or OI values, or other by-products of ratios involving the S2 and Tmax
parameter. This advice was taken on board when constructing interpretation charts in this
study.

The reader is referred to Peters (1986), where he deliberates the various potential pit-falls of
the Rock Eval Pyrolysis method. Laboratory equipment is assumed to be functioning,
maintained and calibrated correctly. Pyrograms were not accessible during this study to
confirm that the tabled data are recorded correctly.

Figure 7.1. Summary of the outcomes and useful calculations related to source rock
analysis by Rock Eval Pyrolysis (Tissot and Welte, 1984).

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 Chapter 7 – Source Rock Assessment

Term Description
Amount of free hydrocarbons that can be volatilized out of the
rock without thermal cracking of kerogen. S1 increases and S2
S1
decreases in thermally mature rocks. Expressed as kg HC/ton or
Derived from Pyrolysis

mg HC/g rock
Generated hydrocarbons from kerogen cracking (breakdown)
S2 suggestive of the reaming generative potential. Expressed kg
HC/ton or mg HC/g rock
A measure of the oxygen content of the rock. Expressed in
S3
mg/kg or kg/ton rock.
A measure of the thermal maturity of the sample. Corresponds
Tmax to the pyrolysis oven temperature observed at maximum
hydrocarbon generation by kerogen breakdown.

Potential Yield (PY)

Ultimate genetic capacity of rock
S1 + S2
Calculated from Pyrolysis

Pyrolysable Carbon (PC) Proportion of TOC that is capable of breaking down to

S1 + S2 x 0.803 hydrocarbons
Production Index (PI) Ratio of hydrocarbons already generated and amount already
S1/S2 + S2 generated. A measure of maturity of the sample
Indication of the remaining generative capacity of a kerogen.
Hydrogen Index (HI)
Higher HI indicates higher generative potential. Expressed as
S2/TOC x 100
mg HC/g TOC
Oxygen Index (OI) Amount of CO2 produced from Pyrolysis. Indication of the
S3/TOC x 100 amount of Oxygen in a sample. Expressed as mg CO2/g TOC
Table 7.2. A guide on making interpretations from TOC and Rock Eval Pyrolysis measurements (Peters, 1986;
Peters and Cassa, 1994)

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 Chapter 7 – Source Rock Assessment

Table 7.3. Kerogen type (top) and thermal maturity hydrocarbon products (bottom) from Rock Eval Pyrolysis
measurements (Peters and Cassa, 1994).

Peters (1986) and Peters and Cassa (1994) provide a guide on making interpretations from
TOC and Rock Eval Pyrolysis measurements (Table 7.2). Table 7.4 suggests relative
quantities of hydrocarbons that can be generated based on Hydrogen Index (HI) (modified
after Peters and Cassa, 1994; and Waples, 1985 in Wulff, 1987). Table 7.5 summari es
source rock generative potential based on the S2 parameter (Wulff, 1984).

HI Relative Quantity of Hydrocarbons

(mg HC/g TOC) Generated
> 600 Very large
300 - 600 Large
200 - 300 Moderate
50 - 200 Small
< 50 Small
Table 7.4. Relative quantity of generated hydrocarbons from HI (Modified after Peters and Cassa, 1994;
Waples, 1985; in Wulff 1987)

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 Chapter 7 – Source Rock Assessment

S2
(mg HC/g or
kg HC/ton) Generative Potential Classification
0-1 Poor
1-2 Marginal
2-6 Moderate
6 - 10 Good
10 - 20 Very Good
20 + Excellent
Table 7.5. Generative potential classification based on S2 (Waples, 1985; in Wulff, 1987)

7.3.4 Organic Matter Type

The amount of kerogen and the maceral type is useful for characterising petroleum potential
in a source rock. Peters and Cassa (1994) categorise kerogens into four types for
classification purposes; type I, II, III and IV. Wulff (1987) explains Peters and Cassa’s (1994)
kerogen types, summarised in Table 7.6.

Kerogen Type Explanation

Derived from lacustrine algae. Occurrences are type I
kerogens are limited anoxic lakes and a few restricted
Type I
marine environments. Type I kerogens have high
generative capacities for liquid hydrocarbons.
Derived from marine algae, pollen, spores, fossil resin,
and bacterial cells lipids. Despite variable origins, type
Type II II kerogens have good capabilities to generate liquid
hydrocarbons. Most type II are found in marine
sediments deposited under reducing conditions.
Composed of terrestrial organic material lacking in
waxy components. Cellulose and lignin are contributors.
Type III
Type III kerogens have lower generative potential than
type II. Considered to generate mainly gas
Contain mainly reworked organic debris and highly
Type IV oxidized material of various origins. Generally
considered to have no source potential.
Table 7.6. Kerogen type classification (Wulff, 1987; Peters and Cassa, 1994)

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Kerogen types are determined by cross-plotting laboratory derived measurements of the

hydrogen-to-carbon ratio against the oxygen-to-carbon ratio (Atomic H/C vs Atomic O/C) on
a Van Krevalen diagram, and was originally developed to characterised coals (Peters and
Cassa, 1994). Tissot et al (1974) modified the method to include sedimentary source rock
kerogens. The modified version of the Van Krevalen diagram utilises Rock Eval Pyrolysis
calculated Hydrogen Indices and Oxygen Indices in place of the laboratory derived Atomic
ratios, which makes the experiment far more rapid and cheaper (Peters and Cassa, 1994).
Figure 7.2 demonstrates the Atomic display (A) and the Pyrolysis display (B). Kerogen type
can also be identified by cross plotting the samples calculated HI against Tmax (Peters and
Cassa, 1994).

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 Chapter 7 – Source Rock Assessment

Figure 7.2. Kerogen type classification from H/C v O/C ratios and HI v Tmax (Peters
and Cassa, 1994).

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 Chapter 7 – Source Rock Assessment

7.3.5 Vitrinite Reflectance

There are three primary groups of macerals (organic components, the equivalent of ‘minerals’
in igneous rocks) in sedimentary rocks. They are liptinite (previously known as exinite)
vitrinite and inertinite (Tissot and Welte, 1984). Vitrinite macerals are derived from terrestrial
plants and mature along the Type III kerogen pathway (Peters and Cassa 1994). Vitrinite
Reflectance is a measure of the amount (presented as a percentage, %Ro) of incident light
reflected from the surface of vitrinite maceral components in a sedimentary rock. The mean
percentage is usually derived from a histogram of observed responses and presented as the
mean vitrinite reflectance.

The vitrinite reflectance boundaries used in this project are derived from PetroMod to remain
consistent with modelled thermal maturity overlays (Chapter 8). The boundaries are similar
to widely published maturity windows of Dow (1977) and (Peters and Cassa, 1994), show in
Table 7.7.

Hydrocarbon product Vitrinite reflectance (% Ro)

window PetroMod Dow (1977) Peters and Cassa (1994)

Immature 0 - 0.55 0 - 0.6 0.2 - 0.6

Early oil window 0.55 - 0.7 0.6 - 0.65

Main oil window 0.7 - 1.0 0.6 - 1.0 0.65 - 0.9

Late oil window 1.0 -1.3 0.9 - 1.35

Wet gas window 1.3 - 2.0 1.0 - 1.35

1.35 +
Dry gas window 2.0 - 4.0 1.35 - 3.0

Over mature 4.0 + 3.0 +

Table 7.7. Definition of hydrocarbon product windows from vitrinite reflectance. Petromod window are utilised
in this project for consistency with modelling results. Comparison of definitions in published literature
(modified after Dow, 1977; Peters and Cassa, 1994).

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7.4 Source Rock Geochemistry

7.4.1 Candidate Source Rock Intervals

The investigation of the project area stratigraphy in Chapter 4 revealed that several packages
contain candidate source rock intervals, based on their geological and petrophysical (wireline
log response) character, summarised in Table 7.8.Table 7. Each formation in Table 7.8 will
be examined for its capacity to generate hydrocarbons.

FORMATION / LITHOLOGY PETROPHYSICAL

UNIT CHARACTER

Noonkanbah Shale with siltstone interbeds Mid-range blocky gamma ray

Formation response

Anderson Formation Rarely carbonaceous claystone and Generally hot gamma ray response
Unit G medium grained sandstone

Anderson Formation Massively bedded claystone Generally mid-range to hot gamma

Unit E ray response

Anderson Formation Massively bedded siltstone and non- Generally mid-range to hot gamma
Unit C fissile claystone ray response

Laurel Formation Finely crystalline fossiliferous Interbedded gamma ray response,

limestone and blocky shales some hot zones

Gogo Formation Grey, blocky micromicaceous shales Gamma ray shows mid-high range
blocky character

Bongabinni Formation Grey blackish sub-fissile to fissile Hot, blocky gamma ray
claystone, silty in part

Goldwyer Formation / Black finely crystalline argillaceous Hot gamma ray log response
WMC 4 carbonaceous dolomite

Goldwyer Formation / Black fissile shale and siltstone Hot gamma ray log response
WMC 2

Table 7.8. Candidate source rock intervals derived from Chapter 4.

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7.4.2 Noonkanbah Formation

The Early Permian (Aktastinian to Baigendzhinian) Noonkanbah Formation is a sequence of

shale interbedded with siltstone, deposited in a shallow marine to marginal marine
depositional environment with fluvial influence (refer to Chapter 4.8.2 of this study).

The Noonkanbah Formation, regionally, shows good to very good organic content, averaging
2.17% TOC across the Canning Basin. TOC ranges from 0.07% in a very shallow (75 mRT)
sample at Olios 1 to 9.37% at Cycas 1 (Figure 7.3). Within the project area, organic content
in the Noonkanbah Formation is less than the basin average but is still classified as good,
averaging 1.69% TOC, the highest is 4% at Ngalti 1 (Figure 7.3).

Despite high organic content, the Noonkanbah Formation regionally shows poor organic
yields in Pyrolysis results. Free hydrocarbons in samples indicated by the S1 parameter are
poor, averaging 0.11 kg HC/ton across the Canning Basin. Values range 0.1 to a maximum of
0.85 kg HC/ton. Generative potential shown by the S2 parameter is also poor to fair,
averaging 1.09 kg HC/ton, ranging 0.04 to 5.04 kg HC/ton, throughout the Canning Basin
(Figure 7.4). Ultimate potential yield is also therefore poor, averaging 0.98 kg HC/ton across
the basin, ranging 0.1 to 5.50 kg HC/ton (Figure 7.3).

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Regional Potential Yield S1 + S2

Regional TOC
(kg/ton)
0 0

200 200

400 400

600 600

Depth (mRT)
Depth (mRT)

800 Noonkanbah Fm 800 Noonkanbah Fm

1000 1000

1200 1200

1400 1400

1600 1600
0 2 4 6 8 10 0 2 4 6

TOC % S1 + S2 (kg/ton)

Study Area TOC Study Area Potential Yield S1 + S2

(kg/ton)
0 0

100 100

200 200

300 Atrax 1 300 Atrax 1

Bindi 1 Bindi 1
400 Kilang Kilang 1 400 Kilang Kilang 1
Depth (mRT)

Depth (mRT)

Lake Betty 1
Lake Betty 1
500 Ngalti 1 500
Ngalti 1
Olios 1
600 600 Olios 1
Selenops 1
Selenops 1
700 700

800 800

900 900

1000 1000
0 2 4 6 0 1 2 3 4 5
TOC % S1 + S2 (kg/ton)

Figure 7.3. Noonkanbah Formation. Clockwise from top left: Regional TOC; regional potential yield; potential yield within study area;
study area TOC (modified after GSWA, 2013).

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 Chapter 7 – Source Rock Assessment

Within the project area, free hydrocarbons as indicated by the S1 parameter are also poor,
averaging 0.08 kg HC/ton, ranging 0.01 to 0.27 kg HC/ton. Generative potential is also
characterised as poor to fair, averaging 0.76 kg HC/ton S2, ranging from 0.06 to 3.77 kg
HC/ton. Figure 7.3 indicates that project area wells (such as Bindi 1, Kilang Kilang 1 and
Lake Betty 1, Figure 3.2) show good to very good petroleum potential. These wells are
located distal to the anticipated terrestrial influence indicated by paleogeographic
reconstructions (Figure 4.40).

Wulff (1987) observed that there is a clear definition within the Noonkanbah Formation
between an upper marine section and lower terrestrial section in Kilang Kilang 1, Ngalti 1,
Lake Betty 1, Olios 1 and Bindi 1. Kilang Kilang 1 clearly demonstrates this trend (Figure
7.4), showing an average S2 of 2.41 kg HC/ton below 575 mRT (yield averages 2.55 kg
HC/ton), whereas the zone above 575 mRT averages S2 at 0.27 kg HC/ton. S1 and TOC is
consistent between the upper and lower portions of the well. Wulff (1987) points out that the
TOC in these wells correlates to abundances of non-marine sporinite and cutinite within the
lower terrestrial section. The cause, as suggested by Wulff (1987) and agreed here, is likely
increased marine organism bioturbation and organic material consumption in the marine
portion.

Remaining Generative Potential S2

(kg/ton)
300

350

400

450
Depth (mRT)

Kilang Kilang 1
500

550

600

650

700
0 1 2 3 4
S2 (kg/ton)
Figure 7.4. Noonkanbah Formation remaining generative potential (S2) (modified after GSWA, 2013).

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Kerogen classification of the regional Noonkanbah Formation data suggests a type III to type
IV kerogen, and it is likely inert. This is indicated by the HI and OI Van Krevalen diagram
and also confirmed by cross-plotting HI and Tmax parameters (Figure 7.5). The HI
classification provided by Peters and Cassa (1994) (Table 7.3) indicates a type III or type IV
kerogen, with average Noonkanbah Formation HI across the basin at 33 mg HC/g TOC. The
HI ranges 6.45 to 143.89 mg HC/g TOC. Typing the kerogen is indicative of a terrestrial or
oxidised sedimentary source, which implies reworking of sediments from the nearby
terrestrial influence, consistent with the paleogeographic reconstruction (Figure 4.40).
Vitrinite and inertinite macerals were identified from side-wall cores (SWC) at Kilang Kilang
1 and Olios 1, confirming the terrestrial influence.

Figure 7.5. Noonkanbah Formation kerogen type; HI v OI (left), HI v Tmax (right) (modified after GSWA, 2013).

The low HI (6.45 to 143.89 mg HC/g TOC, averaging 33 mg HC/g TOC) is suggestive of a
gas hydrocarbon product under optimal maturity conditions (Peters and Cassa, 1994).

The Noonkanbah Formation shows Tmax values ranging from 419°C to 438°C across the
Canning Basin, averaging 430°C (Figure 7.6). This suggests that regionally, the Noonkanbah
Formation is immature for hydrocarbon generation according to Tmax values. Tmax

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measurements within the project area shows that the Noonkanbah Formation is immature on
average (but marginally more mature than wells in the regional dataset; Figure 7.6),
averaging 431°C (ranging 422°C to 437°C). Production Indices (PI) are also suggestive that
the interval is regionally immature to early mature for hydrocarbon generation, with PI
averaging 0.12 across the basin. PI within the study area averages slightly higher at 0.13
(ranges 0.02 to 0.63). Anomalously high PI ratios are observed at Kilang Kilang 1 (0.63); the
cause for this is likely due to oxidation, or adsorption of pyrolytic oxygen compounds onto
the mineral matrix of the sample and a low S2 (S3 of 2.56 kg/ton, S2 of 0.07 kg HC/ton and
TOC of 0.56%) (Peters, 1986). PI can also be unreliable with small S1 and S2 products,
because dividing a small number by a slightly larger number derives this index (Peters,
1986). Vitrinite reflectance at the same depth at Kilang Kilang 1 confirms the zone is
immature to early mature for oil (Ro 0.63%).

Vitrinite reflectance data indicates that the Noonkanbah Formation within the study area
ranges between 0.39 and 0.82 Ro%, averaging 0.60 Ro%. Refer to well maturation profiles in
Chapter 8.6.8

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Tmax (°C) Tmax (°C)

0 0

200 200

400 400
Atrax 1
600 600 Bindi 1
Depth (mRT)

Depth (mRT)
Kilang Kilang 1
Lake Betty 1
800 Noonkanbah Fm 800
Ngalti 1
Olios 1
1000 1000 Selenops 1

1200 1200

1400 1400

1600 1600
416 420 424 428 432 436 440 416 420 424 428 432 436 440
Temperature (°C) Temperature (°C)

Figure 7.6. Noonkanbah Formation regional Tmax (left) and study area Tmax (right) (modified after GSWA, 2013).

Summary of Petroleum Potential

It is clear from TOC and Rock Eval measurements (Figure 7.3), that the Noonkanbah
Formation contains enough organic carbon (TOC) to generate considerable quantities of
hydrocarbons, showing very good petroleum potential. The Noonkanbah Formation,
however, is thermally immature (and early mature for oil at best) for hydrocarbon generation
at the sampled locations. Where buried deeper, maturity is expected to increase, and the
Noonkanbah Formation may exist in a generative window for oil.

It is important to note, that in a basin with low well-density, conventional petroleum wells
tend be located on highs generally targeting structural traps. Therefore, the samples may be
acquired from locations that are perhaps biased toward shallower locations. This implies that
the Noonkanbah Formation is likely to be found at a higher level of thermal maturity in a
structurally deeper setting.

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 Chapter 7 – Source Rock Assessment

The nterval has been evaluated using samples that are regionally immature, according to the
data at hand. Because the samples are immature, production indices are low, indicating the
samples have probably retained organic content from conversion to hydrocarbons. This
means that ideal conditions are available here for characterising an accurate organic richness
of the Noonkanbah Formation (Wulff, 1987).

7.4.3 Anderson Formation

The Early to Middle Carboniferous Anderson Formation is an interbedded sequence of

sandstone siltstone and shale, divisible within the project area into seven subunits, based on
lithology and geophysical log response (refer to Chapter 4.6.2). Anderson Formation Unit C,
Unit E and Unit G are dominated by claystone lithologies with high gamma-ray log responses
suggestive of high organic content, and were accordingly investigated for source rock
potential. Unit C is a massively bedded siltstone and non-fissile claystone, represented on
wireline logs as a generally mid-range to hot gamma ray response. Unit E is a massively
bedded claystone with generally mid-range to hot gamma ray response. Unit G is a rarely
carbonaceous claystone with a generally hot gamma ray log response.

Despite the encouraging gamma-ray log responses, the Anderson Formation regionally shows
low total organic content, with poor to marginally fair hydrocarbon generating potential
(Figure 7.7). The Anderson Formation shows 0.64% TOC on average, ranging from 0.02 to
12.7% TOC. The range of TOC is evidently skewed by the Wamac 1 well (located
approximately 120 km northwest of Broome, in the offshore portion of the Canning Basin)
which intersected 370 metres of organically rich Anderson Formation showing excellent
TOC and petroleum potential (ranging 2.57 to 12.7% TOC).

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 Chapter 7 – Source Rock Assessment

Regional TOC Regional Potential Yield S1 + S2

0
(kg/ton)
0

500 500

1000 1000
Depth (mRT)

1500

Depth (mRT)
Anderson Fm 1500 Anderson Fm

2000 2000

2500 2500

3000 3000

3500 3500
0 2 4 6 8 10 12 14 0 2 4 6 8 10 12 14 16
TOC % S1 + S2 (kg/ton)

Study Area TOC Study Area Potential Yield S1 + S2

(kg/ton)
1200 1200

1400 1400

1600 Anderson G 1600

Anderson F
Anderson G
Depth (mRT)

Depth (mRT)

1800 Anderson E 1800

Anderson A
Anderson D
Anderson C
2000 2000
Anderson B
Anderson A
2200 2200

2400 2400

2600 2600
0.00 0.25 0.50 0.75 1.00 0.00 0.25 0.50 0.75 1.00
TOC % S1 + S2 (kg/ton)
Figure 7.7 Anderson Formation. Clockwise from top left: Regional TOC; regional potential yield; potential yield within study
area; study area TOC (modified after GSWA, 2013).
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 Chapter 7 – Source Rock Assessment

Within the project area, geochemical data characterising the Anderson Formation is available
at Bindi 1 and Kilang Kilang 1 (the only two wells to intersect this formation). The Anderson
Formation shows very low organic content and poor petroleum potential across all subunits,
averaging 0.14% TOC. Table 7.8 indicates that Unit G represents the most organically rich
zone averaging 0.26% TOC, where a single interval in Unit G at Bindi 1 reaches 0.55% TOC
– the most organically rich portion within the project area. Unit E has a single data point –
0.08% TOC at Kilang Kilang 1, and Unit C shows very low TOC; 0.09% at Bindi 1 and
0.06% at Kilang Kilang 1. Anderson Formation Unit A (a quartzose sandstone interbedded
with claystone) shows 0.26% and 0.35% TOC at Bindi 1; which is still very low organic
contents, but therefore the second most organically rich Anderson Formation subunit within
the project area (Table 7.8). Average ultimate genetic yield shows 0.25 kg HC/ton in the
study area, and 1.68 kg HC/ton (1.06 kg HC/ton with Wamac 1 results removed) (Figure 7.7).

SUB-
WELL UNIT DEPTH TMAX S1 S2 S3 S1+S2 TOC
Unit G 1833.1 0.07
Unit G 1918.7 425 0.17 0.11 0.19 0.28 0.55
Bindi 1 Unit C 2224.9 0.09
Unit A 2348.1 0.26
Unit A 2393 426* 0.08* 0.13* 0.24* 0.21* 0.35
Unit G 1460 0.17
Unit F 1490 0.04
Unit F 1512.2 0.14
Unit E 1520 0.08
Kilang Unit D 1550 0.08
Kilang 1 Unit D 1580 0.08
Unit C 1610 0.06
Unit B 1640 0.06
Unit A 1670 0.04
Unit A 1700 0.06
Table 7.8. Anderson Formation pyrolysis and TOC measurements within study area. Note: * Denotes Rock Eval
with TOC <0.5% (modified after GSWA, 2013).

The regional Anderson Formation has low free hydrocarbon content released in the S1
parameter at 0.32 kg HC/ton, ranging between 0.01 to 2.35 kg HC/ton. The S1 average
quoted here is not regionally representative and is an over-estimation of free hydrocarbons
released by pyrolysis for the Anderson Formation. To clarify, the Wamac 1 well shows good

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 Chapter 7 – Source Rock Assessment

petroleum potential with an average of 1.05 kg HC/ton S1, ranging 0.14 to 2.35 kg HC/ton,
and is the reason the S1 basin average is above 0.2 kg HC/ton (Table 7.9).

The regional Anderson Formation also has low generative potential, with 1.74 kg HC/ton S2,
ranging 0.02 to 13.58 kg HC/ton S2. Discounting the Wamac 1 pyrolysis results the basin S2
average drops to 0.86 kg HC/ton S2, which is a fairer representation of regional data.

WELL DEPTH (mRT) TMAX S1 S2 S3 S1+S2 TOC

1940 422 0.65 12.89 6.5 13.54 12.7
2050 427 0.14 2.37 1.25 2.51 2.57
Wamac 1
2200 424 1.06 13.58 2.9 14.64 10.3
2300 424 2.35 4.5 1.2 6.85 7.7
Table 7.9. Anderson Formation pyrolysis and TOC measurements at Wamac 1 well (modified after GSWA,
2013).

Kerogen classification of the regional Anderson Formation data suggests a type III kerogen,
indicated by the HI and OI Van Krevalen diagram (type III gas prone), and also the HI and
Tmax cross plot (Figure 7.8) showing type III to type IV. The HI classification provided by
Peters and Cassa (1994) (Figure 7.8) concurs with a type III kerogen, with average Anderson
Formation HI across the basin at 88 mg HC/g TOC. The HI ranges between 0.16 to 259 mg
HC/g TOC. Typing the kerogen as type III supports a terrestrial or oxidised sedimentary
source. Depositional setting conclusions drawn from lithological descriptions and sequence
stratigraphic interpretation of wireline log data (Figure 4.30) indicates that a strong terrestrial
influence was present during Anderson Formation deposition, which is reinforced here by
kerogen typing. Coal observed in Unit G at Lawford 1 and palynological evidence in Units A
and C through G confirm the terrestrial influence.

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 Chapter 7 – Source Rock Assessment

Figure 7.8 The Anderson Formation shows a type III kerogen indicated by the HI v OI cross plot (left) and the HI v Tmax
(right) (modified after GSWA, 2013).

Within the project area, a single data point at Bindi 1 shows a HI of 20, indicating a type IV
kerogen (Peters and Cassa, 1994). The low HI numbers indicate that a gas hydrocarbon
product is likely under optimal maturity conditions (Peters and Cassa, 1994).

The Anderson Formation shows Tmax values ranging from 328°C to 498°C across the
Canning Basin, averaging 429°C (Figure 7.9). This suggests that regionally, the Anderson
Formation is immature for hydrocarbon generation according to Tmax values (note that the
Tmax value of 498°C is anomalously high, caused by low S2 – 0.3 kg HC/ton). Data within
the project area shows that the Anderson Formation is immature, with data at Bindi 1
indicating Tmax values at 425 °C. The Production Indices (PI) ratio is probably unreliable for
the Anderson Formation; suggestive that the interval is regionally at peak maturity for oil
generation, with PI averaging 0.34 across the basin. The S1 and S2 products directly impact
PI, and because the pyrolysis results are very low, the PI is susceptibly high as a result

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 Chapter 7 – Source Rock Assessment

(dividing one small number by another slightly larger number). The same effect is observed
at Bindi 1 within the study area, where the PI shows the interval is post-mature (0.61).

Regional Tmax
0

500

1000
Depth (mRT)

1500
Anderson Fm

2000

2500

3000

3500
320 360 400 440 480
Tmax (°C)
Figure 7.9. Anderson Formation Tmax indicates the formation
is regionally immature (modified after GSWA, 2013).

Vitrinite Reflectance data (a single measurement at Kilang Kilang 1) suggests that the
Anderson Formation has reached peak maturity for oil generation within the study area, at
0.76 Ro%. Note that a single data point is not a sufficient amount of data to characterise the
maturity of the interval. Peters (1986) recommends that more reliable geochemical
interpretations are based on datasets with measurements every 9 to 18 metres.

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7.4.4 Laurel Formation

The Early Carboniferous (Tournaisian) Laurel Formation is predominantly a clastic sequence

comprising interbedded sandstone, siltstone, claystone and shale. It shows and interbedded
gamma-ray response with hot intervals. The sequence also comprises a regionally mappable
carbonate package. The reader is referred to Chapter 4.6.1 for a comprehensive description of
the Laurel Formation.

Regional assessment

Regionally, the Laurel Formation has fair petroleum potential with variable organic contents,
ranging from 0.03% to 5.81% TOC and averaging 0.56% TOC across the Canning Basin
(Figure 7.10). Average S1 and S2 data indicate poor petroleum potential across the basin –
though S1 and S2 parameters are also variable, and zones (Figure 7.11) of Laurel Formation
sediments in neighbouring tectonic provinces show fair to good organic contents. Regionally,
pyrolysis yields are lean on average; S1 ranges 0.1 to 2.52 kg HC/ton, averaging 0.33 kg
HC/ton. S2 ranges 0.1 to 14.6 kg HC/ton, averaging 0.56 kg HC/ton.

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Regional Potential Yield S1 + S2

Regional TOC (kg/ton)
500 500

1000 1000

1500 1500
Depth (mRT)

Depth (mRT)
2000 2000
Laurel
Formation Laurel
Formation
2500 2500

3000 3000

3500 3500

4000 4000
0 1 2 3 4 5 6 0 5 10 15 20 25
TOC % S1 + S2 (kg/ton)

Figure 7.10. Laurel Formation regional TOC (left) and regional pyrolysis measurements (modified after GSWA,
2013).

Figure 7.11 demonstrates TOC and ultimate genetic potential across the basin, coloured by
tectonic region. Lower images in Figure 7.11 show the same, but the data are filtered to only
the neighbouring Gregory Sub-basin, as well as other similar shelfal-basinal ‘pairs’; the
Lennard Shelf and Fitzroy Graben (and also Pender Terrace). Figure 7.11 indicates that the
basinal positions have the most encouraging organic content for the Laurel Formation in the
Canning Basin – The Fitzroy Graben and Gregory Sub-basin show fair petroleum potential,
averaging 0.61% TOC (ranging 0.03% to 5.81%), and 0.69 kg/ton ultimate genetic yield
(S1+S2).

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 Chapter 7 – Source Rock Assessment

TOC Potential Yield S1 + S2

(kg/ton)
500 500
Balgo
Terrace Balgo
Terrace
1000 Barbwire 1000
Terrace Barbwire
Terrace
Betty
Betty
1500 Terrace 1500 Terrace
Broome Broome
Platform Platform

Depth (mRT)
Depth (mRT)

2000 Fitzroy 2000

Fitzroy
Trough Trough
Gregory Gregory
2500 Sub-basin 2500 Sub-basin
Jurgurra Jurgurra
Terrace Terrace
3000 3000 Lennard
Lennard
Shelf Shelf

Mowla Mowla
3500 Terrace 3500 Terrace

Pender Pender
Terrace Terrace
4000
4000
0 10 20
0 1 2 3 4 5 6
TOC % S1 + S2 (kg/ton)

TOC Potential Yield S1 + S2

(kg/ton)
500 500

1000 1000

Fitzroy
Fitzroy
1500 1500 Graben
Graben

Gregory Gregory
Sub-basin
Depth (mRT)

Depth (mRT)

2000 Sub-basin 2000

Lennard Lennard
Shelf Shelf
2500 2500
Pender Pender
Terrace Terrace

3000 3000

3500 3500

4000 4000
0 2 4 6 8 0 10 20
TOC % S1 + S2 (kg/ton)
Figure 7.11. Laurel Formation regional TOC and Rock Eval Pyrolysis identified by tectonic province. Clockwise from left:
236
Regional TOC; Regional potential yield; Potential yield nearer study area; TOC nearer study area (modified after GSWA, 2013).
 Chapter 7 – Source Rock Assessment

Study Area TOC Study Area Potential Yield S1 + S2

(kg/ton)
500 500

1000 1000

1500 Olios 1 1500

Depth (mRT)
Depth (mRT)

Olios 1

Bindi 1 Bindi 1

2000 Kilang 2000 Lake Betty 1

Kilang 1
Lake Betty 1

2500 2500

3000 3000
0 1 2 3 4 0 1 2 3 4 5
TOC % S1 + S2 (kg/ton)
Figure 7.12. Laurel Formation Study area TOC (left) and study area potential yield (modified after GSWA, 2013).

Whilst the pyrolysis yields are subdued (keep in mind the sampling bias introduced by
structurally higher drilling positions), the results support the concept of higher organic
contents in a basinal setting with potential for hydrocarbon migration up-dip to shelfal
reservoirs. Encouraging organic contents in a basinal paleogeographic setting (Figure 4.27)
combined with an extensional tectonic environment (rapid accommodation generation and
possible anoxic environment) present in the Gregory Sub-basin or Fitzroy Trough, supports
stratigraphic thickening and the preservation of organic matter. This concept (also partially
addressed by Wulff, 1987) supported by the elevated TOC in Figure 7.11 implies that thicker
organically rich zones may be present in hanging wall sections of the Stansmore Fault (refer
isochron maps, Figure 6.23; and RB81-07, Figure 6.5).

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Local organic richness and pyrolysis yields

TOC data is available within the study area from Olios 1, Bindi 1, Kilang Kilang 1 and Lake
Betty 1, pyrolysis data is restricted to Olios 1 and Lake Betty 1. Most of the well data
indicates poor petroleum potential for the area; averaging 0.46% TOC (ranging 0.03% to
3.29%) (Figure 7.12). Organic content is also observed to be variable, and perhaps also
supports the ‘organically rich basin’ concept – where Lake Betty 1 (located in the Gregory
Sub-basin) shows richer organic content averaging higher than the regional at 1.07%, and as
high as 3.29% TOC (ranging 0.03% to 3.29%). This is encouraging, and demonstrates that
the basinal portion of the study area shows fair to good petroleum potential.

Tissot and Welte (1984) state that whilst 0.5% TOC is regarded as the low threshold for
clastic source rock potential, carbonates can produce a higher quantity of petroleum per
amount of organic matter, and 0.3% is considered the minimum (Tissot and Welte, 1984).
This is because carbonates tend to contain lesser amounts of reworked terrestrial matter and
high percentages of marine organics (e.g. algae) which could suggest an affinity with a type I
kerogen (Wulff, 1987). Lake Betty 1 shows average organic content over the lower Laurel
Carbonate averaging 0.36% TOC (ranges 0.22% to 0.57% TOC). Olios 1 shows an average
of 0.18% TOC (ranges 0.08% to 0.45% TOC). Kilang Kilang 1 and Bindi 1 did not intersect
the lower Laurel Carbonate interval. The data indicates that the carbonate within the project
area is lean for organic contents and poor petroleum generating potential, even when
considering Tissot and Welte’s (1984) more accommodating thresholds.

Pyrolysis yields from all project area wells suggest poor petroleum potential. Free
hydrocarbons (S1) average 0.31 kg HC/ton from Olios 1 and Lake Betty 1, raging 0.1 to 2.52
kg HC/ton. Remaining generative potential (S2) averages 1.12 kg HC/ton, ranging 0.34 to
2.19 kg HC/ton. Ultimate genetic potential indicates that the interval is lean (Figure 7.12)
averaging 1.43 kg/ton.

Kerogen classification

Kerogen classification of the regional Laurel Formation data suggests a type III to type IV
kerogen. This is indicated by the HI and OI Van Krevalen diagram (type III gas prone, but
also encroaching on marginal type II), and also the HI and Tmax cross plot (Figure 7.13),
indicating type III. The HI classification provided by Peters and Cassa (1994) (Table 7.3)

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 Chapter 7 – Source Rock Assessment

concurs with a type III kerogen, with average Laurel Formation HI across the basin at 58 mg
HC/g TOC. The HI ranges from 3.4 to 419 mg HC/g TOC. Classifying the kerogen as type III
supports a terrestrial organic matter influence. Depositional setting and paleogeographic
reconstructions (Figure 4.27) indicate that a terrestrial influence was present in neighbouring
provinces whilst a marginal marine influence was prevalent in the study area. The terrestrial
organic material influence is reinforced here by kerogen typing. A HI of 241 is observed at
Olios 1 (possibly contaminated by migrating hydrocarbons, suggested by an immature Tmax
422°C (Wulff, 1987), which suggests a type II kerogen (Peters and Cassa, 1994), signposting
that a marine influence cannot be ruled out. Of course, more data would assist in typing the
study area kerogens (pyrolysis data is only available at Olios 1 and Lake Betty 1). In any
case, the carbonate platform that developed during the Tournaisian is expected to be reflected
by a type II kerogen pathway, so an overall type II/type III kerogen could be anticipated with
greater data coverage.

The HI data (as above), both regionally and within the project area, indicates that a gas
hydrocarbon product is likely under optimal maturity conditions (Peters and Cassa, 1994).

Tmax maturity

The Laurel Formation shows Tmax values ranging from 317°C to 530°C across the Canning
Basin, averaging 443°C. This suggests that on average, the Laurel Formation is regionally
within the early mature hydrocarbon generative window according to Tmax temperatures. A
better understanding of maturity characteristics is achieved by filtering Tmax temperatures by
tectonic province (Figure 7.14). Tmax on the Lennard Shelf indicates that the Laurel
Formation is largely immature to marginally early mature. In the basinal positions of the
basin (Fitzroy Graben and the Gregory Sub-basin) the majority of well data suggest that the
Laurel Formation is mature (most is at early to peak maturity) for hydrocarbon generation
(between 435°C and 470°C).

Tmax within the project area shows that the Laurel Formation is immature to marginally
early mature. Lake Betty 1 suggests samples reach peak maturation, with Tmax at 450 °C
(Figure 7.14, lower right). Vitrinite reflectance confirms that the Laurel Formation is within
the early mature oil generation window within the project area (averaging 0.6 %Ro). Refer to
petroleum systems modelling for maturity trends (Chapter 8.6.6).

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 Chapter 7 – Source Rock Assessment

Figure 7.13. Laurel Formation kerogen classification on HI vs OI crossplot (left) indicates types IV and HI vs Tmax (right) shows
type III (modified after GSWA, 2013).

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 Chapter 7 – Source Rock Assessment

Lennard Shelf Tmax Fitzroy Graben Tmax

500 500

1000 1000 Crimson Lake 1

Canegrass 1 Ellendale 1

1500 Langoora 1 1500 Kora 1

Lloyd 1
Mt Hardman 1
Depth (mRT)

Depth (mRT)
2000 Mariana 1 2000
St George
Meda 2 Range 1
Sundown 1 Valhalla 1 ST1
2500 2500
Kambara 1 West Kora 1

3000 3000 Yulleroo 1

3500 3500

4000 4000
400 450 500 300 400 500 600
Tmax (°C) Tmax (°C)

Gregory Sub-basin Tmax Study Area Tmax

500 500

1000
1000

1500 Jones Range 1

Olios 1
1500
Depth (mRT)
Depth (mRT)

2000 Lake Betty 1

Lake Betty 1
White Hills 1
2500
2000

3000

2500
3500

4000 3000
400 450 500 400 420 440 460 480
Tmax (°C) Tmax (°C)

Figure 7.14. Laurel Formation Tmax measurements by tectonic province. Clockwise from top left: Tmax on Lennard Shelf;
Tmax within Fitzroy Graben; Tmax within study area; Tmax within Gregory Sub-basin (modified after GSWA, 2013).
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 Chapter 7 – Source Rock Assessment

Summary of Petroleum Potential

It can be concluded, that the Laurel Formation is within the early to peak hydrocarbon
generating maturity window to generate hydrocarbons within the project area, however the
interval within the study area and neighbouring shelfal positions (Lennard Shelf) are lean in
organic richness. Basinal positions contain encouraging indicators of elevated organic matter
(from the well intersections at hand) and are also of a sufficient thermal maturity to generate
hydrocarbons. The implication, is that the formation should be targeted for source rock
potential in basinal positions, and in the case of the project area, migration would need to be
relied upon to move hydrocarbons into shelfal reservoirs.

7.4.5 Gogo Formation

The Devonian Gogo Formation is a sequence of laminated to massively bedded shale and
siltstone. The interval is represented as a generally mid to high-range, blocky, gamma-ray
geophysical log response.

Very little data are available to appraise the formation for source rock potential. The Gogo
Formation was only sampled for organic contents and pyrolysis yields at Gap Creek 1,
Kambara 1, Matches Springs 1 and Selenops 1.

The Gogo Formation is believed to source the Blina Oil Field (Cadman, 1993; and Wulff,
1987). Notwithstanding this, data at hand suggests that the formation (regionally) has poor
petroleum potential with low organic contents; ranging from 0.1% to 0.53% TOC and
averaging 0.23% TOC across the Canning Basin (Figure 7.15). Only 1 data point (2819.62
mRT at Kambara 1) shows TOC over 0.5%, therefore most of the hydrocarbon yields stated
here are unreliable.

Data obtained by Wulff (Table XIV in Wulff 1987) indicates that the Gogo Formation has
better hydrocarbon source potential than what is shown here (but cannot be added here
because no depth data is supplied by Wulff). TOC for the Gogo Formation in Wulff (1987)
averages 1.25% (ranges 0.44% to 3.1% TOC). Pyrolysis yields are higher at 0.18 kg HC/ton
S1 (ranges 0.02 to 1.08 kg HC/ton) and average 2.4 kg HC/ton S2 (ranges 0.33 to 7.02 kg
HC/ton). This demonstrates fair to good petroleum potential for the Gogo Formation.

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 Chapter 7 – Source Rock Assessment

Within the project area, Selenops 1 shows very low organic content averaging 0.14% TOC
(ranges 0.11% to 0.18% TOC) (Figure 7.15).

700 Regional TOC 750 Study Area TOC

770

1200 790

810

1700 830

Depth (mRT)
Depth (mRT)

850 Selenops 1
Gogo fm
2200
870

890
2700
910

930
3200
950
0 0.2 0.4 0.6 0 0.2 0.4 0.6 0.8 1
TOC % TOC %

Regional Potential Yield S1 +

S2 (kg/ton)
700

1200

1700
Depth (mRT)

Gogo Fm

2200 Kambara 1

2700

3200

0 1 2
S1 + S2 (kg/ton)

Figure 7.15. Gogo Formation TOC and pyrolysis measurements. Clockwise from top left: regional TOC; study area
TOC; regional potential yeild (modified after GSWA, 2013).
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 Chapter 7 – Source Rock Assessment

The valid data point from Kambara 1 shows very low pyrolysis yields – 0.3 kg HC/ton S1
and 0.5 kg HC/ton S2, which indicates poor petroleum potential. Lean averages for S1 and S2
data also indicate poor petroleum potential across the basin – free hydrocarbon pyrolysis
yield (S1) ranges 0.02 to 1.2 kg HC/ton, averaging 0.22 kg HC/ton. Hydrocarbons generated
by kerogen cracking (S2) range 0.02 to 0.7 kg HC/ton, averaging 0.26 kg HC/ton. Ultimate
genetic yield averages 0.48 kg/ton (Figure 7.15).

Classifying kerogen type using a single data point is unreliable as interpretation of Rock Eval
data is best achieved using lots of data (Peters 1986), however the Van Krevalan cross-plots
are provided here for completeness. Kerogen classification of the regional Gogo Formation
data suggests a type III to type IV kerogen. This is indicated by the HI and OI Van Krevalen
diagram (type III gas prone) and also the HI and Tmax cross plot (Figure 7.16). The HI
classification provided by Peters and Cassa (1994) (Table 7.3Table 7.6) concurs with a type
III kerogen (the Kambara 1 valid data point shows HI of 94 mg HC/g TOC), with average
Gogo Formation HI across the basin at 92 mg HC/g TOC. The HI ranges from 6.6 to 411 mg
HC/g TOC. Classifying the kerogen as type III to type IV supports a terrestrial organic matter
influence, though again, this is probably unreliable given pyrolysis results are reflective of
<0.5% TOC. Data within Wulff (1987) indicates average HI of 190 mg HC/g TOC,
indicating type III kerogen. Although, as numerous data points within Wulff (1987) are above
200 HI, a type II kerogen is also plausible.

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 Chapter 7 – Source Rock Assessment

Figure 7.16. Gogo Formation regional pyrolysis indicates a type III to IV kerogen. HI v OI (left) and HI vs Tmax (right)
(modified after GSWA, 2013).

The valid data point at Kambara 1 shows that the sample is immature for hydrocarbon
generation at 424°C Tmax. The regional average (although invalid) also indicates immature
samples averaging 427°C Tmax (ranging 383°C to 444°C) (Figure 7.17).

Regional Tmax
700

1200

1700
Depth (mRT)

Gogo fm

2200 Kambara 1

2700

3200

360 380 400 420 440 460

Tmax (°C)
Figure 7.17. Gogo Formation regional Tmax (modified
after GSWA, 2013).
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 Chapter 7 – Source Rock Assessment

Summary of Petroleum Potential

No data exists for the Gogo Formation on the Billiluna Sub-basin, however TWT structure
(Figure 6.16) and isochron mapping (Figure 6.24) of the Siluro-Devonian aged section
indicates thickening within hanging wall sections of listric faults within the project area,
which is likely to encourage rapid accommodation generation for the preservation of organic
matter. Combined with a deeper water depositional setting (Chapter 4.5.5), the Gogo
Formation should be regarded as a potential source rock within, or down-dip of the project
area.

TOC and Rock Eval measurements (Wulff, 1987) indicate encouraging source rock potential
for the Gogo Formation, and demonstrate that the interval possesse good petroleum
potential under optimal maturity conditions. Classification by Peters and Cassa (1994)
suggests that the interval may generate moderate relative quantities of hydrocarbons (HI
average of 190 mg HC/g TOC).

It is important to note here that it is very likely that the Gogo Formation samples are biased
toward shallower depths as a function of structurally high drilling locations. The analysis
here, therefore, is perhaps unfair and not an optimistic representation of interval potential as a
source rock. If the Gogo Formation was to charge the Blina Field, it is likely that
hydrocarbons migrated to reservoirs on the Lennard Shelf from deeper basinal positions that
contain sufficient amounts of organic matter. It is possible that a similar play type may be
available within the project area.

7.4.6 Carribuddy Group – Bongabinni Member

The Bongabinni Member of the Carribuddy Group is a greyish black, sub-fissile to fissile
claystone with a hot and blocky gamma ray wireline log response. The Bongabinni Member
is appraised as an organically rich, oil-prone source rock in the Admiral Bay Fault Zone
(along the northern boundary of the Willara Sub-basin, Figure 2.1) (Ghori and Haines, 2007).

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 Chapter 7 – Source Rock Assessment

Very little data are available to appraise the Bongabinni Member for source rock potential.
The Bongabinni Member was only sampled for organic contents at Frankenstein 1, Leo 1 and
Sally May 1. Pyrolysis data is not available for the interval.

The Bongabinni Member contains low TOC, averaging 0.13% (ranging 0.03 – 0.32 %) across
the regional dataset (Figure 7.18). This indicates that the Bongabinni Member has poor
petroleum potential by TOC. These results are contradictory to work by Ghori and Haines
(2007), where they attest that Ordovician source rocks are the most organically rich within
the basin. It would therefore be unwise to discount the ability of the Bongabinni Member on
TOC data alone. Thermal history modelling (Chapter 8.6.4) provides positive feedback to
accompany future Rock Eval Pyrolysis lab work.

Regional TOC
1400.00

1500.00

1600.00

1700.00
Depth (mRT)

1800.00

1900.00 Bongabinni Mbr

2000.00

2100.00

2200.00

2300.00
0.00 0.20 0.40
TOC %

Figure 7.18. Bongabinni Member regional TOC (modified after GSWA, 2013).

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 Chapter 7 – Source Rock Assessment

7.4.7 Goldwyer Formation

The middle Ordovician (Llanvirn) Goldwyer Formation is considered to be an oil-prone

marine source rock within the Larapintine L2 petroleum system (Haines, 2004). Several
exploration programs by operators within the Canning Basin have searched regionally for
organically rich, thick, and thermally mature packages of the Goldwyer Formation. Of note
are recent efforts (in 2012) by New Standard Energy, ConocoPhillips and PetroChina within
the Kidson Sub-basin. Further, Wulff (1987) claimed that the Goldwyer Formation is likely
the best unit within the southern or central Canning Basin to generate hydrocarbons, thus the
formation is anticipated to be organically rich and thermally mature within the Larapintine L2
Petroleum System.

The Goldwyer Formation is an interbedded sequence sub-divided into 4 units (WMC Units 1
to 4, oldest to youngest). The formation comprises a calcareous sub-fissile shale with
occasional limestone (WMC Unit 1), a blackish fissile shale with siltstone and limestone
(WMC Unit 2), a black occasionally carbonaceous shale (WMC Unit 3) and a grey to black
argillaceous and carbonaceous dolomite (WMC Unit 4). WMC Units 2 and 4 show a high
ranging gamma-ray log response.

The Goldwyer Formation has not been intersected by petroleum wells within the study area.
The nearest well intersection that contains TOC and Pyrolysis data is Percival 1 on the
Barbwire Terrace. Thirty-seven regional well intersections (refer to Appendix C) provide a
sufficient dataset to appraise the formation for regional source rock potential.

The Goldwyer Formation has good regional petroleum potential with organic contents
ranging from 0.5% to 4.8% TOC and averaging 1.5% TOC across the Canning Basin (Figure
7.19). Pyrolysis yields indicate that the Goldwyer Formation has very good to excellent
regional hydrocarbon potential. Free hydrocarbons (S1) average 4.06 kg HC/ton (ranges 0.07
to 21.19 kg HC/ton). Hydrocarbons generated by kerogen cracking (S2) are also fair to good,
averaging 4.11 kg HC/ton (ranges 0.2 to 41.45 kg HC/ton). Ultimate genetic yield averages
7.8 kg/ton, also indicating good hydrocarbon yields (Figure 7.19).

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 Chapter 7 – Source Rock Assessment

Regional TOC Regional Potential Yield S1 + S2

800
800
(kg/ton)

1300 1300

1800 1800

2300 2300
Depth (mRT)

Depth (mRT)
Goldwyer Goldwyer Fm
2800 2800
Fm

3300 3300

3800 3800

4300 4300

4800
4800
0 20 40 60
0 2 4
TOC % S1 + S2 (kg/ton)

Figure 7.19. Goldwyer Formation regional TOC (left) and regional potential yield (right) (modified after GSWA, 2013).

Filtering the TOC and Pyrolysis dataset by tectonic region (Table 7.10) demonstrates that the
Broome Platform, Kidson Sub-basin and Barbwire Terrace contain the most organically rich
and highest yielding zones within the Goldwyer Formation. Figure 7.20 demonstrate that
the Barbwire Terrace averages 8.21 kg/ton in ultimate genetic yield, the Kidson Sub-basin
averages 9.26 kg/ton and the Broome Platform averages 9.22 kg/ton in ultimate genetic yield.
Hydrocarbon yields are summarised by S1 and S2 components in Table 7.10.

TOC (wt.%) S1 (kg HC/ton) S2 (kg HC/ton)

Region
Ave Min Max Ave Min Max Ave Min Max
Barbwire Terrace 0.78 0.12 4.05 0.44 0.07 3.5 5.96 0.44 28.32
Broome Platform 0.89 0.06 4.8 6.11 0.07 21.9 3.23 0.1 41.45
Kidson Sub-basin 0.78 0.03 3.8 4.2 0.42 10.5 5.06 0.02 10
Table 7.10. Goldwyer Formation regional TOC and Rock Eval Pyrolysis seperated by tectonic region (modified
after GSWA, 2013).

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 Chapter 7 – Source Rock Assessment

Regional TOC Regional Potential Yield S1 + S2

(kg/ton)
800 800

Anketell Anketell
1300 Shelf 1300 Shelf
Barbwire Barbwire
Terrace Terrace
1800 1800
Broome Broome
Platform Platform
2300 Kidson 2300 Kidson
Sub-basin Sub-basin
Depth (mRT)

Depth (mRT)
Lennard Lennard
2800 Shelf 2800 Shelf
Mowla Mowla
Terrace Terrace
3300 Munro 3300 Munro
Arch Arch
Ryan Ryan
3800 Shelf 3800 Shelf
Willara Willara
Sub-basin Sub-basin
4300 4300

4800 4800
0 2 4 0 10 20 30
TOC% S1 + S2 (kg/ton)

Figure 7.20. Goldwyer Formation regional TOC (left) and regional potential yield, separated by tectonic province (modified
after GSWA, 2013).

Filtering TOC and Pyrolysis datasets by WMC subdivisions (Table 7.11) on a regional basis
indicates that Unit 1 and 2 (the oldest two units) have the highest average TOC (1.18% and
0.86% TOC, respectively). Unit 2 has the highest average yield of free hydrocarbons (S1) at
7.9 kg HC/ton. WMC Unit 4 has the highest yield of cracked hydrocarbons from kerogen
(S2) at 7.56 kg/ton. The low TOC of WMC Unit 4 does not preclude its ability to generate
hydrocarbons – shown by excellent S1 and S2 numbers.

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 Chapter 7 – Source Rock Assessment

TOC% S1 kg HC/ton S2 kg HC/ton

WMC Unit
Ave Min Max Ave Min Max Ave Min Max
4 0.46 0.05 4.8 2.99 0.02 13.47 7.56 0.55 41.45
3 0.62 0.1 3.7 3.6 0.01 13.93 3.89 0.04 12.5
2 0.86 0.12 4.7 7.9 0.1 21.19 3.2 0.1 6.16
1 1.18 0.13 4 2.72 0.11 19.14 2.14 0.37 7.02
Table 7.11. Goldwyer Formation regional TOC and pyrolysis measurements separated by WMC subdivision
(modified after GSWA, 2013).

Table 7.11 demonstrates a small inconsistency where average S2 shows to be the greatest for
WMC 4, however regionally the same zone comprises the lowest average TOC (0.46%) and
relatively lower averages of S1. This is likely due to sampling bias, rather than the
characteristics of the rock. WMC 4 is the shallowest subunit, therefore it is likely more
commonly intersected. Average measurements therefore comprise a larger sample population
(note that the range of TOC is widest for WMC 4). Goldwyer Formation intersections are
likely to be biased to structurally higher (less mature) settings due to a historical conventional
exploration focus (refer Chapter 2.6). Note that pyrolysis yields appear good relative to low
TOC. This is because Rock Eval pyrolysis is generally only run on samples with TOC greater
than 0.5%, and all TOC measurements are still included in the analysis within Table 7.12.

Regional (averaged) Pyrolysis data demonstrates that free hydrocarbon (S1) yields are similar
in quantity to hydrocarbons cracked from kerogen (S2) during the Rock Eval experiment.
This indicates that regionally, the Goldwyer Formation has undergone a period of generation
and thus consumed organic content, also summarised in a high average Production Indices
(PI) of 0.47. PI demonstrates that the TOC data is potentially not sufficiently indicating initial
TOC (TOCi) numbers, due to consumption. The TOC numbers here are likely under-
represented and initial TOC is likely higher than what is shown. Due to maturation, TOCi
numbers should be assumed slightly higher. Further, an apparent trend in Table 7.11 is that
the older WMC units (which are those structurally deeper) have been regionally exposed to
higher (deeper) maturation settings than the shallower units. The Goldwyer Formation in
more immature locations should reveal more truthful TOCi.

Kerogen classification of the Goldwyer Formation suggests a regional type II kerogen,

indicated by the HI and OI Van Krevalen diagram (type II oil prone) and also the HI and
Tmax cross plot (Figure 7.21). Tmax trends suggest a type II to type III kerogen. The HI
classification provided by Peters and Cassa (1994) (Table 7.3) concurs with a type II to type

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 Chapter 7 – Source Rock Assessment

III kerogen with average Goldwyer Formation HI across the basin at 269 mg HC/g TOC. The
HI ranges from 5.5 to 1073 mg HC/g TOC. Classifying the kerogen as type II to type III
supports a marine organic matter influence. Classification by Peters and Cassa (1994) also
suggests that the Goldwyer Formation may generate moderate to large relative quantities of
hydrocarbons under optimal maturity conditions (HI average of 269 mg HC/g TOC, ranges 2
to 2695 kg HC/g TOC).

Figure 7.21. Goldwyer formation kerogen typing by OI vs HI crossplot (left) indicates type II. HI vs Tmax crossplot
(right) indicates kerogen type II to III (modified after GSWA, 2013).

The Goldwyer Formation shows Tmax values ranging from 384°C to 453°C across the
Canning Basin, averaging 431°C (Figure 7.22). This suggests that on average, the Goldwyer
Formation is regionally marginally mature to early mature for generating hydrocarbons
according to Tmax temperatures. A better understanding of Tmax maturity is achieved by
filtering Tmax temperatures by tectonic province (Figure 7.22). Tmax on the Kidson Sub-
basin and Broome Platform – two of the three regions that demonstrate the best petroleum
potential (Figure 7.20) – indicates that the Goldwyer Formation is immature to early oil

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 Chapter 7 – Source Rock Assessment

mature respectively. Tmax shows that the formation on the Barbwire Terrace (another region
of very good petroleum potential) is within the early to peak oil generation windows,
summarized in Figure 7.22. The Barbwire Terrace shows average Tmax at 437°C (ranging
426°C to 453°C).

Regional Tmax Regional Tmax - Optimal

Anketell
Maturation Window Shelf
800 800
Barbwire
1300 1300 Terrace

Broome
1800 1800 Platform

Kidson
2300 2300 Sub-basin
Depth (mRT)
Depth (mRT)

Goldwyer Fm Lennard
2800 2800
Shelf

3300 3300 Mowla

Terrace

3800 3800 Munro

Arch
4300 4300
Ryan
Shelf
4800 4800
380 400 420 440 460 480 425 445 465 Willara
Tmax (°C) Tmax (°C) Sub-basin

Figure 7.22. Goldwyer Formation regional Tmax (left) and regional Tmax separated by tectonic province (right)
(modified after GSWA, 2013).

Tmax data (Figure 7.22) indicates that the Goldwyer Formation is within the early to peak
mature hydrocarbon generative window on the neighbouring Barbwire Terrace (the nearest
region to the project area to intersect the formation), averaging 437°C Tmax. Seismic
evidence (Figure 5.8) demonstrates that the Ordovician aged section deepens and thickens
dramatically from the project area off the Stansmore Fault into the Gregory Sub-basin. A
similar structural style is assumed (though is documented in literature; i.e. Brown in Wulff,
1987) from the Barbwire Terrace into the Gregory Sub-basin. This implies that the Goldwyer
Formation thickens and deepens into structurally deeper (likely higher maturity) settings

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 Chapter 7 – Source Rock Assessment

within the Gregory Sub-basin, in turn optimising a hydrocarbon generative window. Simply,
to discount the availability of mature Goldwyer Formation zones near to the project area
would be unwise because the formation is known to exist in deeper settings.

Vitrinite Reflectance data is unavailable for Ordovician aged stratigraphy, because Vitrinite
macerals (terrestrial plants) did not develop until Devonian time (Peters et al, 2005).

Gloeocapsomorpha prisca

A marine algae – Gloeocapsomorpha prisca – is known to be prevalent during the early to

middle Ordovician, with abundances of the organism reported to occur within WMC Unit 4.
Occurrences of the algae are noted in other zones, related to the position of the Canning
Basin during the Llanvirn (Figure 7.23; and Haines, 2004). Haines also states that the organic
rich zone associated with G. prisca is restricted to the Mowla and Barbwire Terraces,
however the organic horizon may continue into the Gregory Sub-basin (proposed here by
seismic derived assumptions and geochemical log observations – discussed in this section). It
is reported that there is a correlation between WMC Unit 4 and organic rich horizons with G
prisca occurrence (Wulff, 1987). This may imply that G. prisca generally occurs where
WMC Unit 4 is organically rich. To investigate the regional relationship between G. prisca
and organic rich zones across the Canning Basin, geochemical logs were created for 28
regional wells, and are available in Appendix C. The light orange highlighting indicates
zonation of G prisca on the geochemical logs.

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 Chapter 7 – Source Rock Assessment

Figure 7.23. Paleogeographic position of continents in the Ordovician. 'C' represents the Canning Basin (Wulff,
1987).

Some conclusions can be drawn from inspecting the Goldwyer Formation geochemical logs.
The principal conclusions are, that the G prisca zone was found more regionally than
reported, and its occurrence is not always a precursor to higher organic content. To elaborate:

Whilst G. prisca is advertised to be associated with WMC Unit 4 (Haines, 2004), the
algae is found from regional palynology (within WCRs and illustrated in the
geochemical logs) to occur in fairly even occurrences across the WMC subunits.
Further, on many occasions within WMC Unit 4, the algae was reported to not occur.
This indicates that the correlative is not required to find organic rich facies.
The occurrence of G. prisca does not always indicate an organically rich zone (for
example at Great Sandy 1, the presence of the algae corresponds with low TOC
(<0.5%) and low yields.
There are often other zones in wells that display lower organic contents occurring
with the presence of G. prisca; for example the algae was found in WMC Unit 2 at
Canopus 1, corresponding to low TOC, though WMC Unit 1 in the same well shows
much higher organic content (up to 1.4% TOC) without the algae.
G. prisca was found in WMC Unit 4 on the Willara Sub-basin (Willara 1, Darriwell 1,
Great Sandy 1 and Calamia 1 wells) and Broome Platform (Edgar Range 1, Hedonia

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 Chapter 7 – Source Rock Assessment

1, Hilltop 1, Whistler 1 and Carina 1 wells), which is more regional than proposed in
Haines (2004).
The Percival 1 geochemical log gives an encouraging overview of the Goldwyer
Formation nearest the study area, showing WMC Unit 4 to comprise up to 1% TOC
and be within the early to peak hydrocarbon generation window.
Solanum 1, also on the Barbwire Terrace, shows encouraging TOC and pyrolysis
yields. The well displays up to 2.44% TOC, averaging 5.8 kg HC/ton ultimate genetic
yield (S1+ S2), shows very good S1 (up to 3.5 kg HC/ton) and excellent S2 (up to
19.3 kg HC/ton) yields.

These conclusions are important because according to the source rock geochemical logs it is
now apparent that prospectivity extends beyond WMC Unit 4, and other zones within the
Goldwyer Formation clearly demonstrate the potential for hydrocarbon generation.

Summary of Petroleum Potential

TOC data (Figure 7.19) demonstrates that the Goldwyer Formation is regionally organically
rich across the Canning Basin (averaging 1.5%). The Barbwire Terrace demonstrates fair to
good petroleum potential by TOC (Table 7.11) and pyrolysis yields (Figure 7.20 and Table
7.10). WMC Units 1 and 2 show the best petroleum potential by TOC (averaging 0.86% and
1.18% TOC respectively) and Unit 2 has good pyrolysis yields (averaging 7.9 kg HC/ton S1
and 3.2 kg HC/ton S2). WMC Unit 4 shows excellent hydrocarbon yields and excellent
remaining potential (averaging 2.99 kg HC/ton S1 and 7.56 kg HC/ton S2). Geochemical logs
drawn for the Goldwyer Formation show encouraging petroleum potential in Percival 1 and
Solanum 1 (wells on the nearby Barbwire Terrace – the nearest region to the study area
known to intersect the Goldwyer Formation).

The Goldwyer Formation is shown to be an organically rich and thermally early-mature

interval (grading to peak maturity) within the Larapintine L2 Petroleum System. Wulff
(1987) demonstrated that the Goldwyer Formation is organically rich and thermally mature,
utilizing a relatively small dataset. Work presented here is in agreement with th e
conclusions, though also demonstrates that a larger dataset incorporates a wider variety of
inferences for the te t the formation to be a good source rock.

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7.4.8 Summary of Source Rock Characteristics

Table 7.12 provides a summary and quick reference guide of source rock characteristics
within the project area. The results determined in this Chapter accompany petroleum systems
modelling (Chapter 8) to fully evaluate source rock potential within the northeast Canning
Basin.

Average TOC and Rock Eval Pyrolysis characteristics

Formation Kerogen
TOC (%) S1 (kg HC/ton) S2 (kg HC/ton) PY (S1+S2) Tmax (°C) HI
Type
Noonkanbah 2.17 (regional) 0.11 (regional) 1.09 (regional)
0.98 430 33 III to IV
Formation 1.69 (study area) 0.08 (study area) 0.76 (study area)

Anderson
0.14 0.32 0.86 1.06 429 88 III
Formation

Laurel 0.56 (regional) 0.33 (regional) 0.56 (regional) 0.69 (regional)

443 58 III to IV
Formation (0.46 study area) 0.31 (study area) 1.12 (study area) 1.43 (study area)

Gogo
0.14 0.22 0.26 0.48 427 92 III to IV
Formation

Gogo
1.25 0.18 2.4
Formation*

Bongabinni
0.13
Member

Goldwyer
1.5 4.06 4.11 7.8 437 269 II Oil prone
Formation
Table 7.12. Summary of source rock characteristics (modified after GSWA, 2013). Note: * indicates values
from literature. Note that average PY here is not the sum of the average S1 and average S2 values. Refer to text
for greater detail.

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8. Petroleum Systems Modelling

8.1 Introduction

A petroleum system, defined in Chapter 2, is a geologic system encompassing the source

rocks and includes all of the geologic elements and processes that are essential if a
hydrocarbon accumulation is to exist (Magoon and Dow, 1994). Chapter 7 analysed
geochemical data to determine source rock quantity (organic richness) and quality (organic
matter type). This Chapter accompanies Chapter 7 to complete the source rock
characterization of the northeast Canning Basin.

The goal for this Chapter is to investigate whether source rocks within the project area are
buried deep enough to reach a sufficient level of thermal maturity to enable the source rocks
to generate hydrocarbons. Chapter 8 also examines the timing of when petroleum source
rocks reach thermal maturation windows to produce hydrocarbon products.

8.2 Definition of a Petroleum Systems Model

A petroleum systems model is a digital data model of a petroleum system where the
interrelated elements and processes can be computer-simulated (Hantschel and Kauerauf,
2009). Petroleum systems modelling (similarly; ‘Thermal history modelling’, ‘Source rock
maturation modelling’; and collectively ‘Basin modelling’) is dynamic forward modelling of
geologic processes in sedimentary basins tested over geologic time. Sediments within a basin
are back-stripped to initial deposition and forward-modelled to present day to simulate the
processes enacting within the petroleum system (Hantschel and Kauerauf, 2009).

Generally, the main goal of petroleum systems modelling is to simulate the geological history
of a stratigraphic section in order to investigate whether the interval in question reaches
optimal thermal maturity windows to generate hydrocarbons. A second goal is to understand
the timing of hydrocarbon generation relative to the availability of reservoirs and the
development of trapping geometries, where hydrocarbons may be preserved over geologic
time to present day. The latter goal is a key focus of 2D modelling.

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8.2.1 General Structure and Method of a Petroleum Systems Model

The general structure and method of a petroleum systems model involves specifying
geological (stratigraphic, paleogeographic, lithological and structural), geothermal (heat flow,
surface and sub-surface temperatures) and geochemical (source rock organic characteristics)
parameters of a study area, computing compaction and thermal maturity profiles, and
calibrating the results to laboratory measurements (Hantschel and Kauerauf, 2009; Prayitno
et. al., 1992). A comprehensive review of the methodology is provided by Hantschel and
Kauerauf (2009). A summary of the computer simulation workflow is illustrated in Figure 8.1
and Figure 8.2.

There are six elements of a thorough petroleum systems model (Hantschel and Kauerauf,
2009), which are are summarized below. Note that these elements are generally applicable to
3D models. The specific parameters defined for 1D and 2D models in this research project
are explained in the ensuing sections. To avoid repetition, parameters for 2D modelling are
often combined with the similar 1D controls as indicated below and in the sections to follow.

1. Present day model (1D and 2D modelling)

Horizons
Facies maps
Fault surfaces
2. Age assignment (1D and 2D modelling)
3. Paleo geometry of geological configuration (1D and 2D modelling)
Water depths
Erosion
Salt thickness (not required in this study)
Paleo thickness of sediments
4. Boundary conditions (1D and 2D modelling)
Surface-Water Interface temperatures
Basal heat flow
5. Facies (1D and 2D modelling)
Facies definition
TOC and HI (Geochemistry)
Rock composition
6. Seismic (2D modelling)

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Attributes (maps)
Reference horizons (for depth conversion)

Figure 8.1. Illustration of a digital petroleum systems model workflow (Prayitno et. al., 1992).

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Figure 8.2. Summary illustration of petroleum systems model workflow, specific to PetroMod
basin modelling software (Hantschel and Kauerauf, 2009)

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8.2.2 Structure and Method of Models in the Project Area

To model source rock maturity, a variety of parameters, described in more detail in section
8.4 and 8.6, are inputted into PetroMod petroleum systems modelling software.

8.3 Model Locations

8.3.1 1D Models

1D models were constructed for wells in Table 8.1, illustrated in Figure 8.3. Well locations
were chosen for geographic spread across tectonic regions, well depth (deeper wells intersect
deeper stratigraphic units) and availability of maturity (Vitrinite Reflectance) data.

Well
Well Total Depth (mRT)
Completed
Bindi 1 2507 14/08/1984
Olios 1 1963 02/11/1983
Kilang Kilang 1 2300 03/12/1984
Ngalti 1 2758 17/10/1984
Lake Betty 1 3145 15/12/1971
Table 8.1. Well name and total depth summary of 1D models in this project.

8.3.2 2D Models

A regional 2D model; RB81-7, was built to simulate the evolution of petroleum systems
across the Gregory Sub-basin, Betty Terrace, Balgo Terrace and Billiluna Sub-basin. Further
2D models were built to test the evolution of petroleum systems in association with structural
traps where possible accumulations may exist (Chapter 6.2.4). These secondary (but no less
important) 2D models were constructed using 2D seismic lines identified in Table 8.2, and
illustrated in Figure 8.3. The line locations are based on areas that;

1. Are on key structural traps identified in Chapter 6.2.4;

2. Where the stratigraphy (outlined in Chapter 4) appears to host suitable reservoir and
sealing elements; and

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3. Where source rocks are organically rich and thermally mature for the generation of
hydrocarbons (discussed in Chapter 7 and also this Chapter).

In summary, 2D model locations were selected to simulate the evolution of petroleum

systems and to test petroleum system interactions across structural traps identified within the
project area.

Seismic line Line orientation

RB81-7 Dip line – NE-SW
RB81-10 Strike line – NW-SE
RB82-28 Dip line – NE-SW
Arbitrary Line 82GN-03, S85LM-08 and S85LM-
Dip line – NNE-SW
08A
Table 8.2. Summary of seismic lines upon which 2D models were constructed in this project.

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Figure 8.3. Location of wells and seismic lines used for 1D and 2D modeling.

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8.4 Data Inputs and Parameters – 1D Models

8.4.1 Present-day Model

Age assignment

Age assignment relates the present day well bore intersections (or surfaces in 2D modelling)
with their geological age of deposition and exhumation (Hantschel and Kauerauf, 2009). The
age assignment input Table instructs PetroMod on geological formation attributes (such as
geological age, quantities of preserved and removed section, and source rock TOC) to
incorporate in the simulation. The age assignment for each 1D model is provided in
Appendix E.

8.4.2 Paleo Geometry

Water depths

Water in geologic basins provide accommodation for sediment accumulation, thus

influencing a control for sediment thicknesses and hence compaction. Paleo-water depths are
therefore an important parameter in basin modelling because they impact the burial and uplift
of a sedimentary basin. Paleo-water depths in PetroMod are also boundary conditions for
fluid flow and heat flow equations. Water depths are generally derived from assumptions
made about eustatic sea-level change and interpretations of paleogeographic settings
(Hantschel and Kauerauf, (2009). Large uncertainties are associated with paleo-water depth
estimates (Corcoran and Doré, 2005), and they are especially difficult to define in older rocks
where less sedimentology-derived observations are on hand. In respect of this uncertainty, a
wider range of error is anticipated to be present for Silurian and older sequences.

Paleo-water depth (PWD) estimates for this project were largely made from paleogeographic
reconstructions (both from Chapter 4 and also various publications; Brakel et. al., 1990; Cook
and Totterdell, 1990; Gorter, 1987; and Smith et. al., 2013), and estimates published in
WCRs.

Average paleo-water depths are illustrated in Figure 8.4. Key PWDs concerning 1D and 2D
modelling are explained in Table 8.2. A 40 metre water depth is selected for the

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Mississippian epoch reflecting shallow or marginal marine conditions. A marine setting in the
Permian was set at approximately 200 metre water depth. Another marine setting was set at
200 metres in the Triassic, related to the deposition of the Blina Shale. Smith et. al (2013)
suggests a marginal marine water depth of approximately 20 metres accommodating the Late
Jurassic Alexander Formation and Wallal Sandstone.

System / Paleo-water
Age Comments
Epoch depth

Late Jurassic 160 Ma 20 m Marginal marine paleogeographic setting

(Smith et. al (2013)

Triassic 260 Ma 200 m Marine paleogeographic setting (Chapter

4.9 and Gorter, 1987)

Permian 235 Ma 200 m Marine paleogeographic setting,

maximum Permian transgression (Chapter
4.8.2 and Brakel et. al., 1990)

Mississippian 344 Ma 40 m Shallow marine/marginal marine

paleogeographic setting (Chapter 4.6.1)

Devonian 380 Ma 35m Marginal marine paleogeographic setting

(Chapter 4.5.7)

Silurian 430 Ma 50 m Marginal marine paleogeographic setting

(Chapter 4.3.3)

Ordovician 475 Ma 150 m Marine paleogeographic setting –

Larapintine Seaway Development
(Chapter 4.3.3. and Cook and Totterdell,
1990)

Table 8.3. Summary and explanation of paleo-water depths used in petroleum systems models.

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Figure 8.4. Average paleo-water depth used in 1D models.

Erosion – 1D and 2D modelling

Several tectonic episodes are reported to occur during the geologic history the
(Yeates, et al., (1984) and Edwards, et al., (1997); refer to Chapter 2). The episodes
that have likely led to exhumation of sediments are the Early Devonian Prices Creek
Movement, the Middle Carboniferous Meda Transpression and the Triassic Fitzroy
Movement. Recently, Duddy et. al., (2003) used Apatite Fission Track Analysis (AFTA) to
determine an accurate burial history of eastern Canning Basin sediments, using the White-
Hills 1 well, located south of the project area (Figure 8.5).

The eroded quantities described here, along with the procedures to estimate them, apply to
1D modelling and 2D modelling.

The 2D models simulate Carboniferous and older stratigraphy so consideration needs to be

given to exhumation associated with the Early Devonian Prices Creek Movement. The 1D
models do not intersect sediments as old as this structural episode. No Devonian inversion is
visible on 2D seismic, and regional workers do not quantify Devonian exhumation in
published literature (Edwards et al., 1997). Although uplift may have occurred during the

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Devonian, no readily available present day evidence (for example, seismically visible
unconformities) was observed, so it is assumed that the local effects of this tectonic episode
are either minimal, or that the event described by regional Canning Basin workers were not as
significant on the Betty or Balgo Terraces. Therefore, no exhumation was specified for the
Early Devonian Prices Creek Movement.

Erosion during Carboniferous and Triassic periods need quantification for both timing and
depth. For both exhumation events, final quantities were based on estimates derived during
2D modelling, and the 1D models were revised after the 2D models were complete.

Carboniferous Meda Transpression

Timing for Meda Transpression related exhumation is based on seismic observations (RB81-
7, Chapter 6.2.3 and Figure 6.5). It is assumed that there was no deposition or hiatus between
the boundary of Anderson Formation and Grant Group (i.e. Near Top Anderson Formation
horizon). Erosion due to the Meda Transpression is estimated to start at 322 Ma until 305 Ma.

Quantifying the thickness of additional section removed during this event was achieved by
using regional seismic line RB81-7. The eroded sequence was ‘restored’ during construction
of the RB81-7 2D basin model (creation of erosion maps). RB81-7 (Figure 6.2.3) shows that
the Anderson Formation and a large component of the Fairfield Group is eroded at SP 300.
The top of the Anderson Formation was flattened in PetroMod and the eroded section
digitized into the model. The eroded section is estimated to be equal to the thickness of the
thickest preserved section, which is presently on the downthrown side of the Stansmore Fault,
RB81-7 SP 900. On RB81-7 this is equal to approximately 250 metres. This eroded thickness
was applied to all 1D models.

Two assumptions are made using this estimate:

1. That the eroded thickness is equal to the thickest preserved portion of the Anderson
Formation and Fairfield Group. This may not be true, and a significantly larger
amount of rock may h e bee eroded than what is preserved at RB81-7 SP 600.
Alternatively, the exhumation enacted by the Meda Transpression may be spatially
variable and less than 250 metres, however the input for PetroMod does not permit an
error range for these allowances.

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2. That the eroded thickness is isopachus across the project area, estimated from RB81-
7. Again, it is likely that the eroded thickness varies considerably across the project
area, though an estimate must be made for the PetroMod erosion parameter.

Mesozoic and Cenozoic exhumation

Very little indication of erosion is given by seismic data for exhumation during the Mesozoic
and Cenozoic, other than a shallow angular unconformity at the present day surface. Timing
and exhumed thicknesses were estimated after work by Duddy et.al. (2003). The workers
used Apatite Fission Track Analysis (AFTA) to conclude that, based on the White Hills 1
well, three periods of uplift occurred. The reader is referred to Duddy et. al. (2003) for the
methodology. The following are broad estimates of exhumation provided by AFTA:

1. 2900 m of total uplift and erosion between 230 Ma to 180 Ma;

2. 1450 m between 135 Ma and 120 Ma; and
3. 550 m between 45 Ma and 10 Ma. Re-burial occurs between each of these events
(Figure 8.5).

It is acknowledged that techniques to estimate exhumation thicknesses in uplifted basins can

have associated uncertainties on the order of several hundreds of meters, and that reconciling
estimates of uplift is an important component of attempting to accurately estimate
exhumation magnitude (Corcoran and Doré, 2005). It should be noted that ±500 metres or
more of section may be in addition to the exhumed thicknesses stated here.

The above exhumed quantities were added to 1D models and also ‘restored’ during 2D
modelling before simulation. A 1D pseudo well was extracted from 2D models to compare
burial history and maturation curves at the location of Kilang Kilang 1; the result was
compared to the Vitrinite Reflectance data, where it was found that the eroded thicknesses
were causing the maturity profile to over-mature considerably. It was determined that the
exhumation applied to each model needed to be reduced e to honor the present day
maximum paleo-temperatures represented by VR measurements.

Duddy et.al. (2003) confess that other thicknesse are within the allowances of AFTA
(Figure 8.5, bottom left), so reduced thickness were attempted with much better fits for the
VR data within the project area (refer VR vs. depth calibration, Figure 8.5):

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1. 2200 m of total uplift and erosion between 230 Ma to 180 Ma;

2. 1050 m between 135 Ma and 120 Ma; and
3. 270 m between 45 Ma and 10 Ma. (Figure 8.5).

Again, these are broad estimates with proportional re-burial assumed between these episodes.

There is generally good agreement between exhumed quantities across the project area,
where slight differences to exhumation between wells are attributed to unevenness in burial
and spatial variability in the location of each respective well within the Gregory Sub-basin
(Figure 8.5):

Kilang Kilang 1 and Lake Betty 1 share similar present day depths (1620mRT and
1600mRT, respectively) and similar maximum maturity on the top of the Fairfield
Group (0.8 – 1.1 %Ro).
White Hills 1 is located towards the southeastern end of the Gregory Sub-basin, where
the trough shallows onto the Ryan High (Figure 8.5). The Fairfield Group at this
location reaches a similar maximum paleo-temperature on the top of the Fairfield
Group (<0.95 – 1.1 %Ro) at a shallower present day depth (1100mRT).
Bindi 1 is located in the central project area depocentre, presently 2350mRT to the top
of the Fairfield Group, and shows a similar maximum paleo-temperature (>1.05
%Ro+), indicating a similar maximal burial in the Triassic, though less subsequent
uplift relative to neighboring wells. This may be because the central project area (and
central Gregory Sub-basin) was less adversely affected by exhumation in Triassic or
later periods.

The net exhumation (gross erosion above minus the reburial component) estimate for each
exhumation episode was used as input for PetroMod, and only varied slightly to ensure
calibration parameters at each well we e honored. The final Mesozoic and Cenozoic
exhumation parameters used are as follows.

1. 1050 m of total uplift and erosion between 230 Ma to 180 Ma;

2. 550 m between 135 Ma and 120 Ma; and
3. 300 m between 45 Ma and 10 Ma.

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Figure 8.5. (Top left) Location of 1D models in bold, study area in red; White Hills 1 located south of the project area near the
Ryan Shelf. (Top right) measured and predicted VR for White Hills 1; measured and predicted data trends are similar therefore
qualifying heat flow at max. paleo-temp. is similar to present day. (Bottom left) Total section removed from top of Poole
Sandstone at White Hills 1 at 95% confidence, numbers to right show modified depths for this project. (Bottom right) Burial
history model for White Hills 1 after AFTA. (All figures except top right in Duddy et. al., 2013).

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Paleo thickness

Paleo-thickness refers to the thickness of each formation within a 1D model, and was simply
determined by formation tops at each well location. Well tops were loaded into PetroMod,
along with starting and ending ages for deposition, taken from palynology where possible
(Chapter 4). Generally, good age control is available for all formation boundaries. PetroMod
automatically populates base and thickness values from well tops and the elevation datum
that is assigned to a well location. Formation tops are tabulated in Appendix E.

8.4.3 Boundary Conditions

Sediment-water interface temperatures

Sediment-water interface temperature (SWIT) is the upper boundary in heat flow calculations
(Hantschel and Kauerauf, 2009). SWIT is calculated using estimates of average paleo-surface
temperatures with water depth corrections. Average surface temperatures are dependent on
latitude (Wygrala, 1989 e e ).

PetroMod provides a simple utility to automatically estimate SWIT. By entering the present
day latitude of the Canning Basin (18°S) and selecting ‘southern Australia’ as the basin
continental association, PetroMod derives an estimate of SWIT over geologic time (Figure
8.6).

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Figure 8.6. Mean surface temperatures used to configure PetroMod Surface-water-interface-temperatures. Black
line indicates average temperature at 18° latitude (modified after PetroMod, 2014)

8.4.4 Facies – 1D and 2D models

Hantschel and Kauerauf, (2009) explain that in basin modelling terms, ‘facies’ are
sedimentary groups with common properties, separated into the ‘lithology group’ and the
‘organic facies group’.

Lithologies are characterised by thermal conductivities, heat flow capacity, radiogenic heat
flow production, permeability, compressibility and capillary entry pressures (Hantschel and
Kauerauf, 2009).

Organic facies are characterised by all kinetic parameters involved in the generation and
cracking of petroleum; including Arrhenius-type activation energy and frequency data from
primary and secondary petroleum cracking, total organic carbon (TOC) and hydrogen index
(HI) numbers, adsorption parameters, densities, viscosities, and critical fluid parameters
(temperatures, pressures and specific volumes) (Hantschel and Kauerauf, 2009).

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PetroMod provides a relatively simple but comprehensive method for defining facies
parameters for use in this study – the Lithology Editor. The Lithology editor is preloaded
with a range of pre-defined lithologies and accompanying lithology group parameters.

Facies definition and Rock composition

In this study, facies were determined using cuttings descriptions and formational summaries
from WCRs. The lithologies were compiled into a representative selection for each formation
within the project area. The representative facies were then created in the Lithology Editor by
‘mixing’ (for example; sandstone, siltstone, claystone, shale, carbonate/limestone) from the
predefined library within PetroMod. Table 8.4 shows the facies definition per formation.

Component %
Formation Carbonate /
Sandstone Siltstone Shale Conglomerate Coal
Limestone
Blina Shale 5 95
Millyit Sandstone 90 5 5
Liveringa Group 40 30 25 5
Noonkanbah Formation 10 30 60
Poole Sandstone 85 5 10
Grant Group 60 10 30
Anderson Formation 70 15 15
Laurel Formation 15 20 30 35
Luluigui Formation 30 30 35 5
Knobby Sandstone 80 10 10
Virgin Hills Formation 15 20 50 15
Gogo Formation 15 20 50 15
Poulton Formation 100
Bungle Gap Limestone 33 33 34
Devonian
25 10 65
Conglomerate
Ordovician 80 10 10
Table 8.4. Summary of lithology components for stratigraphic formations in the project area.

Predefined PetroMod constraints for the ‘lithology group’ used in this study shown in Table
8.5.

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Radiogenic
Porosity-depth
Surface Grain Thermal heat
coefficient
Lithology porosity density conductivity production at
(Athy's factor k;
(Φ; %) (kg/m3) at 20°C 40% porosity
km-1)
(µW/m3)
Sandstone 41 2700 3.95 0.42 0.31
Siltstone 55 2710 2.01 0.57 0.51
Shale 70 2610 1.45 1.38 0.85
Carbonate/Limestone 51 2680 2 0.84 0.52
Conglomerate 30 2700 2.3 0.51 0.3
Coal 74 1600 1 0.28 0.42
Table 8.5. Petrophysical properties for common lithologies in the PetroMod lithology editor.

TOC and HI (Geochemistry) – 1D and 2D models

PetroMod requires an average of measured TOC and HI for source rock intervals in order to
simulate hydrocarbon generation and expulsion quantities. TOC and HI we e derived from
the same geochemical database compiled within Chapter 7 of this study, which was
ultimately collated from WCRs. Refer to Chapter 7 and Appendix C for further detail on
source rock parameters.

8.4.5 Basal Heat Flow – 1D and 2D Models

Basal heat flow refers to the amount of heat that enters a sedimentary basin sequence, and is a
product of the mechanical and radiogenic state of the underlying lithosphere, asthenosphere
and also the intra-basinal sequence (Hantschel and Kauerauf, 2009; and Waples 2001).
Hantschel and Kauerauf, (2009) note that the McKenzie heat flow model (McKenzie, 1978)
is frequently used in basin analysis, however recent work by Waples (2001) shows that the
lithospheric stretching model proposed by McKenzie is not sufficient, as radiogenic sources
can account for more than half of the heat flow at the top of basement. A common
assumption; suggesting that all heat passing through the lithosphere originates from below the
lithosphere, is incorrect (Waples, 2001).

Due to the difficulty of constraining paleo heat flow, this study adopted the admittedly
simplistic assumption that heat flow has remained constant over geological time, and is
equivalent to the present-day heat flow. The use of present day heat flow is supported by

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Duddy et. al., (2003), where they demonstrated that the heat flow trend at the time of
maximum paleo-temperatures is similar to trends of present day heat flow (Figure 8.5).

This method introduces an assumption that heat flow does not vary from the Ordovician to
present day, which is undoubtedly incorrect. However by using the approach of Waples
(2001), heat flow measurements due to radiogenic sources will total a higher quantity than
that of a McKenzie model; which facilitates higher levels of maturity. Even though using
constant heat flow removes variability to heat flow over geological time, a higher overall heat
flow should more accurately model maturity at a time when paleo-temperatures were at a
maximum.

Goutorbe et al., (2008) determined present day heat flow from wells within and around the
study area, shown in Table 8.6. 1D and 2D models were assigned heat flow from the nearest
present day measurement.

Well Present Day Heat flow (mW/m2)

Bindi 1 58
Kilang Kilang 1 56
Ngalti 1 60
Olios 1 62
White Hills 1 60
Table 8.6. Present-day heat flow for wells in the study area (Goutorbe et al., 2008).

8.4.6 Calibration – Geothermal Gradients

To ensure that temperature gradients in 1D and 2D models are realistic, they require
calibration with measured data points. Models can be calibrated using various temperature or
maturity controls including VR, AFTA and temperatures measured during the drilling of a
well (Hantschel and Kauerauf, 2009).

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Well Total Depth (mRT) BHT (°C)

Mean Surface Temp. - 32.0
Atrax 1 786 53.8
Selenops 1 1262 59.3
Ngalti 1 2695 101.1
Olios 1 1965 88.3
Lake Betty 1 3146 155.0

Table 8.7. Mean surface temperature of project area (BOM, 2015) and bottom-hole static temperatures
(corrected for drilling circulation times) for wells in the project area.

Simulated temperature gradient overlays were extracted in PetroMod from present day
temperature inputs (calculated using the boundary condition inputs detailed above) and
compared to Horner-plot-corrected bottom-hole (static) temperatures (BHT). Olios 1, Ngalti
1 Atrax 1, Selenops 1 and Lake Betty 1 have BHT data. Figure 8.7 provides the modelling
results. Olios 1 and Ngalti 1 have good agreement between the modelled temperature profile
and BHTs (85°C compared to 88°C measured at Olios 1, and almost precisely 101°C at
Ngalti 1). Lake Betty 1 shows a temperature gradient too low for the measured BHT,
although the Lake Betty 1 WCR notes that the ‘circulation times’ and ‘observed time since
circulation finished’ is not confidently known, which may degrade the quality of the Horner
correction for the well). Deviations in the calculated temperature curve are at formation
boundaries are caused by slight variations to facies thermal properties (including thermal
conductivity).

Vitrinite Reflectance (VR) maturity profiles were constructed in PetroMod using the Sweeny
and Burnham (1990) Easy%Ro method. The maturation curves were plotted against
measured VR obtained from well locations. All wells except Lake Betty 1 contained VR and
Ngalti 1 has limited populations of VR, so these wells were compared to Vitrinite
Reflectance Equivalent (VRe) calculated from Tmax, to aid in calibration in the absence of
VR measurements. The results are shown in Figure 8.8.

Vitrinite data for post-Carboniferous stratigraphy within the project area is plentiful, where
most formations in the northeast Canning Basin have some form of terrestrial influence.
There is good agreement between the maturation curve and VR data at the well locations.
Kilang Kilang 1 and Olios 1 demonstrate the best fits between simulated and measured
maturity from VR. The maturity profile deviates from the VR population at Bindi 1, though

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the VR data is insufficiently deep to build an optimal well maturation profile, relative to other
wells. The VR population below 900 mRT at Bindi 1 is lower in reflectance than then
modelled maturity. Cook, in Lehman and Haines (1985) report pyrite and iron oxides were
present in the Bindi 1 VR samples along with commonly identified Inertinite, which indicates
an oxidizing environment. This may be introducing a low level of suppression in the VR
population at Bindi 1 (Carr, 2000). At Lake Betty 1, where no VR is available, the modelled
maturity is in good agreement with VRe from Tmax.

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 \ Temperature
+ BHT

Figure 8.7. Temperature calibration for

1D models. Clockwise from top left:
Kilang Kilang 1, Ngalti 1, Bindi 1, Lake
Betty 1, and Olios 1. Models show good
agreement with BHST for respective
wells.
 \ Predicted Vitrinite
+ VR
+ VRe from Tmax

Figure 8.8. Vitrinite reflectance

calibration for 1D models. Clockwise
from top left: Kilang Kilang 1, Ngalti 1,
Bindi 1, Lake Betty 1, and Olios 1.
Models show generally good agreement
with VR and VRe measurements
 Chapter 8 – Petroleum Systems Modelling

8.5 Data Inputs and Parameters – 2D Models

2D basin models were constructed in this study to understand the evolution of petroleum
systems in the northeast Canning Basin. The exercise was undertaken to;

1. Determine whether source rocks within the project area reach optimal thermal
maturity to generate and expel hydrocarbon products, and to visualise this
development via a 2D cross section through the Billiluna Sub-basin, Balgo and Betty
Terraces into the Gregory Sub-basin;
2. Determine whether hydrocarbons migrate from kitchen areas into reservoirs and
trapping geometries in shelfal positions;
3. Determine whether accumulations may exist, preserved through geologic time to
present day; and
4. Facilitate the culmination of all of the work in the previous chapters of this study.

2D petroleum systems modelling has never before been undertaken within the project area, so
the 2D models demonstrate an original contribution to the geoscientific discipline with
respect to petroleum systems analysis in the northeast Canning Basin.

8.5.1 Present-day Model

PetroMod functions by taking a present day geological geometry along with all geological
parameters, and strips the model to initial deposition. PetroMod then forward-simulates the
geometries and parameters in a finite-element model (FEM), so that the model honors the
present day configuration of the basin.

The present day model was derived from depth converted seismic interpretation,
geochemistry and porosity data, heat flow parameters, and age assignments for deposition,
exhumation and structural episodes.

Depth conversion

Seismic was converted to the depth domain using the IHS Kingdom Dynamic Depth
Converter utility (Chapter 5.5.1).

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Screen captures were obtained for the depth converted 2D seismic lines selected for 2D
modelling (in Table 8.2 and Figure 8.3), and imported into PetroMod. The seismic images
were then digitized in PetroMod to carry over the present day 2D geological model.

Horizons and Fault Surfaces

Horizons and faults were digitized from the depth converted seismic section for each 2D
model. The horizons and faults were then gridded to mesh the pre-grid nodes (a node is
created for each digitized mouse-click along a horizon or fault surface) to the Finite Elements
in the model. The FEM was given a maximum e sublayer thickness of 100 metres to give
the present day geometry a realistic appearance. Increasing sublayer thicknesses did lengthen
the simulation time, however it was deemed reasonable because a meaningful model in
appearance is more t t e than one that e cubic and excessively simple.

Age assignment

As per 1D modelling, age assignment for 2D modelling involves instructing PetroMod on the
attributes of a formation to include within a model. Age assignment relates the present day
surfaces digitized from 2D seismic, with their geological age of deposition and erosion
(Hantschel and Kauerauf, 2009). Age assignment for 2D modelling is slightly more complex
than 1D, and requires parameters explained in Table 8.8 (model RB81-7 is used as an
example in Figure 8.9).

Timing of Faulting

The timing of faulting in 2D models is important to define because it allows PetroMod the
ability to correctly forward-model the geological history from initial deposition to final
hiatus. Fault timing characterises the structural history in sedimentary basins. Correctly timed
faults in 2D models can impact migration conduits and also can determine how trapping
geometries are filled in accumulation analysis. The timing of faulting is estimated based on;

Published literature concerning the tectonic history of the Canning Basin (Brown et
al., 1984)

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Observations of fault timing drawn from seismic interpretation.

For example, The Stansmore Fault (a large listric fault that divides the Gregory Sub-basin
from the Betty Terrace) was a major control on sedimentation at multiple stages during the
basin’s tectonic history, and is observed on seismic to be active to displace Pre-Cambrian
(Basement) Ordovician, Siluro-Devonian, and probably at least Carboniferous stratigraphy,
therefore is assigned ages 570 Ma until 330 Ma.

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 Age Pre-grid Gridded Number of Max time-step
Header Horizon Erosion map Layer Event type Facies map
(Ma) horizon horizon sublayers (Ma)

Gridded
Contains the User selected -
Pre-gridded horizon. 2D map of Division of If deposition
thickness of deposition,
horizon Represents the facies layer into exceeds Max
the eroded erosion or
digitized from model definition sub layers, time-step,
Age of Horizon part of a Layer hiatus.
Explanation 2D seismic geometry for a properties each can Simulation will
horizon name model layer name Instructs
(assigned layer (assigned have perform extra
(assigned upon PetroMod on
upon (assigned during different steps in
defining layer type and
gridding) upon gridding) properties modelling
erosion) processes
gridding)

Table 8.8. (Top) Explanation of header terms used in PetroMod age assignment.
Figure 8.9. (Bottom) PetroMod age assignment input parameters used in 2D model RB81-7.
 Chapter 8 – Petroleum Systems Modelling

8.5.2 Paleo Geometry

Paleo-geometries for 2D models are largely similar to that of the 1D models, however a
number of extra parameters are defined to characterise the older geology (1D models
intersected Devonian aged rocks at the oldest).

Water depths

Paleo-water depth (PWD) estimates for 2D models were set identically to 1D models for
Carboniferous and younger stratigraphy (Chapter 8.4.2). Estimates were derived from
paleogeographic reconstructions (both from Chapter 4 and also various publications;
te 87 Brakel et al., 1990; Cook and Totterdell, 1990; and Smith et al., 2013),
estimates published in WCRs, and initial rifting within the Gregory Sub-basin.

Extra parameters for 2D modelling are a 150 metre water depth to represent the marine
Ordovician Larapintine Seaway (Cook and Totterdell, 1990). Paleo water depths are then
estimated to shallow through the Silurian (40 metres) to the Devonian (25 metres), to
accommodate carbonate development. Paleo-water depths are illustrated in Figure 8.10, and
key PWDs are summarised in Table 8.3.

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Figure 8.10. Average paleo-water depth for 2D models.

8.5.3 Boundary Conditions

Boundary conditions were defined essentially as per 1D modelling, with an extension to the
parameters to allow for Carboniferous and older stratigraphy.

Surface-water interface temperatures

Sediment-water-interface temperature (SWIT) parameters were set identically as per 1D

modelling, however the e t te Beardsmore and Cull (2001) is only available in
PetroMod until the Carboniferous. Wygrala (1989) estimates decreasing 1.5°C per 100
metres of water (up to deep water – 400 metres, where cold water artic conditions are
proposed). Wygrala’s calculation is applied to the PWD trend for Devonian and older
stratigraphy (Figure 8.11).

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Figure 8.11. Sediment-water-interface-temperature curve for 2D models.

8.5.4 Facies

Facies definition, TOC and HI (Geochemistry) and Rock Composition parameters are set
identical to 1D models (refer to Chapter 8.4.4).

It would be prudent to consider facies changes across 2D models, especially since the models
are generally quite large (RB81-7 is 121 km long), and cover multiple tectonic provinces.
Paleogeographic reconstructions (Chapter 4), demonstrate that facies change is likely within
the study area. None of the models, however, intersect more than one well location to
accurately estimate facies variability between well locations. In this study, variations in facies
variability were ‘mixed’ within a customized Rock Composition library (a part of the
PetroMod Lithology editor); a catalog created for this study (Table 8.4 and 8.5). Averages are
representative of the formations across the study area. This implies that formation lithological
composition is averaged across every model.

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8.5.5 Calibration

The 1D models were extracted from 2D models at existing well locations (Kilang Kilang 1,
Ngalti 1 and Lake Betty 1) to test the viability of the heat flow parameters to actual thermal
maturity measurements (Figure 8.12). The 1D effective porosity profiles with core porosity
data was also compared with 2D models for reassurance of overburden quantities that impact
compaction (Figure 8.13.

Thermal maturity

The thermal maturity calibration results were variable at 1D pseudo well locations. In all
cases the maturation profiles (%Ro per depth unit) are similar to existing 1D models. For
example; 2D model RB82-28 closely matched the Vitrinite Reflectance measurements at
Ngalti 1, indicating the RB82-28 model correctly simulates maturation at the Ngalti 1 well
location.

RB81-7 shows a higher maturation curve at both calibration locations (Ngalti 1 and Kilang
Kilang 1). RB81-7 at the top of the Laurel Formation in Kilang Kilang 1 shows 1.16% Ro;
0.4% Ro higher VR than the 1D well maturity profile. The RB81-7 model at the top of the
Laurel Formation in Ngalti 1 shows 0.71% Ro; 0.14% Ro higher VR than the 1D well
maturity profile. Despite the 1D extractions not exactly replicating the 1D maturation curve
at Kilang Kilang 1 and Ngalti 1, RB81-7 extractions still e e te with VR
measurements giving some validity to the simulation.

Arbitrary line 82GN-03 shows lower maturation than the Lake Betty 1 maturity profile. Note
that Lake Betty 1 contains no VR measurements so VRe is calculated from Tmax. 82GN-03
at the top of the Poole Sandstone in Lake Betty 1 shows 0.43% Ro; 0.19% Ro lower VR than
the 1D well maturity profile. Again, the 82GN-03 arbitrary line still lies within the broad
VRe well profile. The RB81-10 2D model has a good match with Ngalti 1 VR measurements
(Figure 8.12).

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Effective porosity

2D modelling was also compared to core porosity measurements to gauge the effectiveness of
the overburden digitized into the model to replace eroded material. There are no core porosity
measurements available for Kilang Kilang 1.

RB81-7 and RB81-10 closely match effective porosity curves and intersect the Lennard River
Group core data cluster in the Ngalti 1 well. This indicates that the overburden quantity
digitized to replace Triassic and younger rocks reasonably compacts deeper stratigraphy to
simulate present day effective porosity.

RB82-28 slightly over-compacts the effective porosity curve at Ngalti 1, though the modelled
curve broadly fits the core porosity measurements in the Knobby Sandstone and Lennard
River Group. This indicates that there is perhaps slightly too much overburden digitized into
Triassic and younger rocks in RB82-28.

289
 \ Predicted Vitrinite (well location)
\ Predicted Vitrinite (2D model)
+ VR
+ VRe from Tmax

Figure 8.12. VR calibration for 2D models. Original

1D model for respective well location in black,
pseudo well extracted at projected location near 1D
well in blue. 2D models show some variability in
maturity profile though generally allowable within
VR and VRe measurements.
 Figure 8.13. Porosity calibration for 2D models
\ Predicted Effective Porosity (well location) against Ngalti 1 well (calibration restricted by
porosity data availability). Predicted effective
\ Predicted Effective Porosity (2D model)
porosity for Ngalti 1 and respective 2D pseudo
+ Core Porosity Measurement wells have good agreement with data
measurements.
 Chapter 8 – Petroleum Systems Modelling

8.6 Results

Chapter 8.6 presents the results from 1D and 2D petroleum systems modelling within the
northeast Canning Basin. Pseudo wells were extracted (Figure 8.14) to enable 1D
investigations of 2D models across tectonic provinces within the study area. The results are
presented in petroleum systems hierarchy; and discuss each formation in depositional
sequence.

Figure 8.14. Location of 1D models, 2D models constructed on seismic lines (red), and 2D model pseudo well
extractions (blue). Pseudo wells give good spatial spread throughout project area.

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8.6.1 Temperature

Figures 8.15 and 8.16 demonstrate 1D well burial history results with temperature overlays
for the modelled wells. It is clear that maximum paleo-temperatures occur in the Triassic as a
result of deeper burial prior to uplift concluding in the Jurassic.

1D models (figures 8.15 and 8.16) demonstrate four periods of subsidence related heating:

1. Carboniferous: 338 – 309 Ma

2. Triassic: 225 – 191 Ma
3. Jurassic – Cretaceous: 160 – 126 Ma
4. Eocene – Miocene: 30 – 9 Ma

2D model RB81-7 demonstrates maximum paleo-temperatures in cross section through the

study area (Figure 8.17). The base of the Gregory Sub-basin reached a maximum of 637°C
during the Triassic. Results from RB81-7 indicate that the Balgo Terrace reached similar
maximum temperatures to that of the Betty Terrace (280°C and 274°C respectively in
Ordovician sediments) during the Triassic, and the Billiluna Sub-basin reaches only a slightly
higher maximum paleo-temperature of 285°C.

293
Figure 8.15. Well burial history results for Lake Betty 1 (top left),
Olios 1 (top right) and Bindi 1 (bottom left) with temperature overlay
for the respective well. Maximum paleo-temperatures occur in the
Triassic as a result of deeper burial prior to uplift concluding in the
Jurassic.
Figure 8.16. Well burial history results for Kilang Kilang 1 (left) and Ngalti 1 (right) with temperature overlays for the respective well. Maximum paleo-temperatures
occur in the Triassic as a result of deeper burial prior to uplift concluding in the Jurassic.
 S NE

Siluro-
Devonian

Ordovician

Billiluna Sub-basin

Betty Terrace Balgo Terrace

Gregory Sub-basin

Figure 8.17. Present day RB81-7 model with pre-grid faults. RB81-7 demonstrates maximum temperature variations across the study area. Temperatures reach 637°C at the base of the Gregory
Sub-basin.
 Chapter 8 – Petroleum Systems Modelling

8.6.2 Thermal Maturity

Figures 8.18 and Table 8.9 compare thermal maturity profiles for 1D wells within the
Gregory Sub-basin and Betty Terrace. There is good agreement between individual well
maturity profiles (%Ro per depth unit) within each province, suggesting that there are no
variations to peak maturation within each respective tectonic region. Note that sediments
within the Gregory Sub-basin reach higher levels of maturity than sediments within the Betty
Terrace (Table 8.9). Figure 8.19 demonstrates maximum maturity in cross section attained in
the Triassic across the study area. The Fairfield Group within the Gregory Sub-basin (as
indicated in Figure 8.18 and Table 8.9) reaches the late oil window. The Fairfield Group
reaches the early oil window on the Betty Terrace, but is immature on the Balgo Terrace and
in the Billiluna Sub-basin.

Figure 8.18. Maturity profiles for 1D models in the

\ Predicted Vitrinite (vari-coloured)
Gregory Sub-basin (left) and on the Betty Terrace
(right). Models indicate that sediments within the + VR
Gregory Sub-basin are more mature that sediments
on the Betty Terrace, due to deeper burial. + VRe from Tmax

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Maximum maturity (%Ro)

Formation Gregory Sub-basin Betty Terrace
Top
Top Fm Base Fm Base Fm
Fm
Noonkanbah Formation 0.51 0.6 0.43 0.45
Grant Group 0.63 0.75 0.47 0.58
Laurel Formation 0.82 1.05 0.58 0.65
Table 8.9. Summary of maturity on the top and base of key stratigraphic markers in the project area, from 1D
models.

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 S NE

Siluro-
Devonian

Ordovician

Billiluna Sub-basin
Betty Terrace Balgo Terrace

Gregory Sub-basin

Figure 8.19. 2D model RB81-7 shows the regional maturity of sediments across the study area, restored to the time of peak maturation in the Triassic (time step 200Ma).
 Chapter 8 – Petroleum Systems Modelling

8.6.3 Modelling Results – Goldwyer Formation

Source rock maturity

Vitrinite vs. Time diagrams enable the determination of when the source rocks identified in
Chapter 7 evolve through respective hydrocarbon maturation windows.

Sediments in the Gregory Sub-basin experience slightly higher maturation rates than
sediments on the Betty Terrace, Balgo Terrace and in the Billiluna Sub-basin.

Figure 8.20 illustrates that the Goldwyer Formation undergoes initial subsidence after Early
Ordovician rifting (475 Ma) until a dramatic increase in maturation rates in the Llandovery
(Late Silurian, 435 Ma). Sediments continued to mature until the Mississippian (350 – 340
Ma) when the Goldwyer Formation within the Gregory Sub-basin reaches maximum
maturity. Figure 8.5 shows that Gregory Sub-basin sediments are reburied in the Triassic
where they attain maximum temperatures, confirmed by AFTA (Duddy et al, 2003), however
Figure 8.20 indicates that maximum maturity for the Goldwyer Formation reaches 4.66% Ro;
the same maturity as in the Carboniferous. This is the upper limit of the Sweeny and
Burnham (1990) Easy%Ro kinetic, and in any case the sediments are over mature by the
Carboniferous.

The Goldwyer Formation in the Gregory Sub-basin and Betty Terrace enters the early oil
window (0.55 – 0.7 %Ro) in the Late Ordovician (450 Ma). Gregory Sub-basin sediments
enter the main oil window (0.7 – 1.0 %Ro) in the Llandovery (Late Silurian, 435 Ma).
Sediments in the Gregory Sub-basin rapidly mature from Llandovery time; entering the late
oil window (1.0 – 1.3 %Ro) in the Wenlock (Middle Silurian 428 Ma), enter the wet gas
window (1.3 – 2.0 %Ro) in the Ludlow (Early Silurian, 422 Ma), enter the dry gas window
(2.0 – 4.0 %Ro) in the Early Devonian (410 Ma) and become over mature (4.0 – 5.0 %Ro) in
the Late Devonian (365 Ma).

The Goldwyer Formation on the Betty Terrace, Balgo Terrace and in the Billiluna Sub-basin
mature through respective hydrocarbon product windows slightly later and at slower rates
than sediments in the Gregory Sub-basin (Figure 8.20). Balgo Terrace and Billiluna Sub-
basin sediments enter the early oil window in the Wenlock (Middle Silurian, 427 Ma), and
the three provinces enter the main oil window in the Pridoli to Lochkovian (~ 419 Ma).

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Billiluna Sub-basin sediments enter the late oil window by the Early Devonian (407 Ma) and
sediments on the terraces enter the same window 10 Ma later (~ 397 Ma).

The Goldwyer Formation on the Billiluna Sub-basin enters the wet gas window in the Middle
Devonian (397 Ma) and enters the dry gas window by the Late Devonian (370 Ma). Betty
Terrace and Balgo Terrace sediments enter the wet gas window in the Late Devonian (380
Ma) and reach the dry gas window in the Mississippian (345 – 332 Ma). Sediments on the
Betty Terrace, Balgo Terrace and within the Billiluna Sub-basin undergo a further stage of
maturation, remaining in the dry gas window during the Triassic Fitzroy Movement,
concluding at 200 Ma.

Over mature

Dry gas window

Wet gas window

Late oil window
Main oil window
Early oil window

Figure 8.20. Goldwyer Formation maturity vs time diagram.

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Transformation ratios

Transformation Ratios (TR) are an indication of how much kerogen has cracked to petroleum
(%), and equals the Production Index (PI; = S1 / (S1+S2)) if no petroleum has been expelled
(Hantschel, T. and A. I. Kauerauf, 2009).

Goldwyer Formation kerogens undergo complete conversion to petroleum (Figure 8.21).

Kerogens in the Gregory Sub-basin initiate cracking in the Early Ordovician (475 Ma),
shortly after deposition. Rapid accommodation generation facilitates rapid burial and hence,
maturation of Gregory Sub-basin sediments. Gregory Sub-basin kerogens convert at higher
rates to kerogens on the Betty Terrace, Balgo Terrace and in the Billiluna Sub-basin.
Conversion rates increase in the Llandovery (Early Silurian, 436 Ma) across all wells.
Complete conversion occurs (100% TR) by the Mississippian (Early Carboniferous, 350 Ma).
Maximum maturity obtained on terraced areas in the Triassic have no impact on kerogen
conversion as the source rock is already exhausted.

Figure 8.21. Goldwyer Formation transformation ratio vs time diagram

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Hydrocarbon generation

Source rock generation occurs as a decomposition reaction when kerogen cracks to

petroleum. The critical point of source rock generation is defined as when transformation
ratios (TR) reach approximately 50% (Hantschel, T. and A. I. Kauerauf, 2009).

Generation masses in PetroMod are likely to be incorrect within the models presented here
because average generative capacities are assigned from a regional source rock analysis
(Chapter 7). In reality, source rock geochemical characteristics are likely to vary more than
what is assumed here. The models are configured this way because timing is arguably more
important for this project to determine than generated quantities.

Figure 8.22 shows that generation in the Goldwyer Formation commences in the Llandovery
(437 Ma), slightly earlier than the Bongabinni Member, attributed to its deeper burial and
hence marginally higher maturity. Generation in the Gregory Sub-basin peaks at a maximum
(though still low) rate of 0.005 mg HC/g TOC/Ma in the Early Devonian (407 Ma), and
ceases by the Mississippian (346 Ma) when Goldwyer Formation kerogens are exhausted.
There is a second, limited period of generation on the Betty Terrace and Balgo Terrace in the
Triassic caused by renewed subsidence; when the Goldwyer Formation on the Betty Terrace,
Balgo Terrace and Billiluna Sub-basin obtain maximum paleo-temperatures (240 Ma);
however this is likely meaningless given that kerogens are essentially exhausted by the
Mississippian. There is no further generation in the Gregory Sub-basin post-Mississippian as
the Goldwyer Formation source rock is already spent. Figure 8.22 illustrates that hydrocarbon
generation is more rapid in the Gregory Sub-basin relative to the terraces due to sediments in
the sub-basin attaining higher maturity at the faster rate.

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Figure 8.22. Goldwyer Formation generation rate vs time diagram.

Hydrocarbon expulsion

‘Expulsion’ specifies the amount of petroleum passing from the source rock to the carrier bed
within a petroleum system (Hantschel, T. and A. I. Kauerauf, 2009), and refers to the phase
of ‘primary migration’; where hydrocarbons populate source rock pore space reaching a
saturation threshold. At the saturation threshold, hydrocarbons are expelled from the source
rock into a carrier system.

In PetroMod, the onset of expulsion is configured by saturation thresholds within the

‘Lithology Editor’. Saturation thresholds are affected by generated volumes. The expulsion
threshold is set to very low pore space saturations (0.5% oil saturation and 0% gas
saturation), meaning that expulsion onset essentially occurs as soon as any hydrocarbons are
generated. In turn, there are no (or very low) amounts of residual hydrocarbons in the models.
Application of this method results in earlier expulsion times (Neumann et al., 2008). For the

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purpose of this study, PetroMod is configured to presume that onset of expulsion occurs
immediately after the onset of generation.

Figure 8.23 demonstrates that expulsion from the Goldwyer Formation in the Gregory Sub-
basin commences in the Llandovery (Early Silurian, 436 Ma) and ceases in the Frasnian (Late
Devonian, 385 Ma), when generation decreases due to waning generation rates. Expulsion on
the terraces and within the Billiluna Sub-basin occur at similar times at very low rates
(maximum 0.49 Mtons at 349 Ma).

Figure 8.23. Goldwyer Formation expulsion rate vs time diagram.

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8.6.4 Modelling Results – Bongabinni Member

Source rock maturity

The Bongabinni Member demonstrates a similar maturation history to the Goldwyer

Formation (expected given similar ages). The Bongabinni Member is considerably more
mature in the Gregory Sub-basin than on the terraces (Figure 8.24). Sediments throughout the
study area undergo continual burial commencing in the Llandovery (Late Silurian, 435 Ma).
Sediments in the Gregory Sub-basin continually subside until the Mississippian (345 Ma),
however sediments on the Betty Terrace, Balgo Terrace and Billiluna Sub-basin undergo
periods of increased maturation from the Mississippian and reach maximum maturity in the
Triassic (200 Ma).

Initial subsidence is at a higher rate in the Gregory Sub-basin, where sediments mature
through the early oil window (0.55 – 0.7 %Ro) in the Llandovery (435 Ma), enter the main
oil window (0.7 – 1.0 %Ro) in the Late Llandovery (430 Ma), continue to the late oil window
(1.0 – 1.3 %Ro) in the Wenlock (Middle Silurian, 425 Ma), enter the wet gas window (1.3 –
2.0 %Ro) in the Ludlow (Late Silurian, 418 Ma), enter the dry gas window (2.0 – 4.0 %Ro)
in the Early Devonian (402 Ma) and become over mature when sediments reach maximum
maturity levels in the Mississippian (345 Ma).

Sediments on the Betty Terrace, Balgo Terrace and in the Billiluna Sub-basin enter the
respective maturation windows at a slightly later time. Sediments enter the early oil window
in the Ludlow (Late Silurian, 420 Ma), enter the main oil window in the Lochkovian (Late
Devonian 415 – 410 Ma), and enter the late oil window in the Early to Middle Devonian (402
– 390 Ma). Sediments in the Billiluna Sub-basin enter the wet gas window in the Middle
Devonian (389 Ma) whereas sediments on the terraces enter the wet gas window slightly
later, in the Late Devonian (375 – 360 Ma). Billiluna Sub-basin sediments enter the dry gas
window in the Early Mississippian (356 Ma) whereas sediments on the Balgo Terrace enter
the dry gas window by the Mississippian (340 Ma). Betty Terrace sediments don’t enter the
dry gas window until the Early Permian (295 Ma). The Bongabinni Member on the Betty
Terrace, Balgo Terrace and in the Billiluna Sub-basin remain in the dry gas window until
present day.

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Member

Over mature

Dry gas window

Wet gas
Late oil window
window
Main oil window
Early oil window

Figure 8.24. Bongabinni Member maturity vs time diagram.

Transformation ratios

Figure 8.25 illustrates the Bongabinni Member kerogens undergo complete conversion to
petroleum, commencing in the Llandovery (Early Silurian, 436 Ma). Kerogens reach 100%
conversion by the Mississippian (Early Carboniferous, 450 Ma), when Gregory Sub-basin
sediments reach maximum maturity (over mature, 4.0 – 5.0 %Ro) and sediments on the Betty
Terrace, Balgo Terrace and in the Billiluna Sub-basin enter the dry gas window (2.0 – 4.0
%Ro). A slight increase in maturity in the Triassic results in no further kerogen conversion as
the source rock is already spent.

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Member

Figure 8.25. Bongabinni Member transformation ratio vs time diagram.

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Hydrocarbon generation

Generation rates are low within the Bongabinni Member. Figure 8.26 illustrates that
generation within the Gregory Sub-basin commences in the Early Devonian (407 Ma) and
concludes by the Mississippian (Late Carboniferous, 350 Ma). Figure 8.26 indicates that the
Bongabinni Member on the Betty Terrace (Pseudo well RB82-28) shows a generative period
from the Silurian (435 Ma) until the Mississippian (~345 Ma) representing peak generation at
0.0022 mg HC/g TOC/Ma; however this is likely anomalous in the model as transformation
ratios range close to 0% (unconverted kerogen). Meaningful generation is interpreted to occur
close to the Late Devonian (or fractionally later) for terraced areas reaching a peak around
345 Ma. A second short generative period occurs in the Triassic (200 Ma) when maximum
paleo-temperatures are obtained.

Figure 8.26. Bongabinni Member generation rate vs time diagram.

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Hydrocarbon expulsion

Figure 8.27 illustrates that the Bongabinni Member expels hydrocarbons over one main
period. Expulsion from sediments within the Gregory Sub-basin show onset in the Early
Devonian (407 Ma) when generation commences. Expulsion continues until the Mid
Devonian (385 Ma), with waning generation. Expulsion is also interpreted to occur on the
terraced areas (indicated by a slight increase in expulsion rate on the Betty Terrace 82GN-03
pseudo well curve) within the Mississippian (350 Ma – 340 Ma) due to peak generation on
the Betty and Balgo Terraces. No (or negligible) expulsion is interpreted to occur in the
Billiluna Sub-basin or from the Betty Terrace RB82-28 and Balgo Terrace models.

Figure 8.27. Bongabinni Member expulsion rate vs time diagram.

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8.6.5 Modelling Results – Gogo Formation

Source rock maturity

The Gogo Formation shows to be considerably more mature in the Gregory Sub-basin than
on neighboring terraces (Figure 8.28). All wells undergo significant burial in the
Mississippian (345 Ma) following uplift of the Carboniferous Meda Transpression. The Gogo
Formation in the Gregory Sub-basin rapidly matures through the main oil and late oil
windows over a 10 My period, entering the wet gas window (1.3 – 2.0 %Ro) in the
Mississippian (336 Ma) whilst sediments on the Betty Terrace and Billiluna Sub-basin
effectively reach the main oil window (0.7 – 1.0 %Ro) at a similar time. Balgo Terrace
sediments reach the main oil window (0.7 – 1.0 %Ro) and the late oil window (1.0 – 1.3
%Ro) within a 10 My period in the Mississippian (336 Ma).

Sediments continue to subside during the Triassic Fitzroy Movement. The Gregory Sub-basin
matures the fastest, likely due to increased rates of rifting focused on the Stansmore Fault,
where the Gogo Formation matures into the dry gas window (2.0 – 4.0 %Ro) in the Middle
Triassic (240 Ma) and reaches peak maturity at 200 Ma. Sediments on the Betty Terrace
gradually subside and enter the late oil window (1.0 – 1.3 %Ro) at the point of maximum
maturity in the Late Triassic (200 Ma), whilst the Gogo Formation in the Billiluna Sub-basin
remains in the main oil window (0.7 – 1.0%Ro) at peak maturity.

Figure 8.28 clearly demonstrates that the Gregory Sub-basin is repeatedly the focal point of
rifting within study area, both during the Carboniferous Meda Transpression and Triassic
Fitzroy Movement. This trend is consistent with most source rocks in the project area,
however is clearly pronounced in relation to the Gogo Formation.

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Over mature

Dry gas window

Wet gas
Late oil window
Main oil window
Early oil

Figure 8.28. Gogo Formation maturity vs time diagram.

Transformation ratios

Kerogens in the Gogo Formation crack to petroleum in two periods; The Mississippian and
Triassic (Figure 8.29).

Kerogens in the Billiluna Sub-basin and on the Balgo Terrace partly convert to petroleum in
the Mississippian (Early Carboniferous, 342 Ma) reaching 20.5% on the Balgo Terrace and
40% in the Billiluna Sub-basin. Kerogens experience a second stage of cracking in the Late
Triassic (between 235 Ma to 200 Ma) as sediments obtain maximum maturity, where they
reach 60% – 70% TR.

Figure 8.29 illustrates that kerogens in the Gregory Sub-basin convert to petroleum at 79%
TR in the Mississippian (345 – 330 Ma), and undergo complete conversion (100% TR) to
petroleum at the end of the Triassic (200 Ma). The Gogo Formation in the Gregory Sub-basin
is spent by the end of the Triassic.

Conversion in the Mississippian occurs when Gogo Formation sediments reach the early to
main oil window (0.55 – 1.0 %Ro) on the Betty Terrace, Balgo Terrace and Billiluna Sub-

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basin, and Gregory Sub-basin sediments mature through the oil window and reach the dry gas
window (2.0 – 4.0 %Ro).

Kerogen conversion in the Triassic reflects sediments obtaining maximum maturity

throughout the project area, where increases in maturity are high enough to encourage
complete kerogen conversion in Gregory Sub-basin sediments.

Figure 8.29. Gogo Formation transformation ratio vs time diagram.

Hydrocarbon generation

Figure 8.30 demonstrates that generation within the Gogo Formation commences in the
Mississippian (349 Ma) when sediments enter the early oil window (0.55- 0.7 %Ro) and
continue to the main oil window (0.7 – 1.0 %Ro). The Gogo Formation undergoes two
periods of generation, the first in the Mississippian (349 – 335 Ma), and the second (main)
generative period in the Middle Permian to Early Jurassic (280 – 175 Ma). Generation rates
are low, reaching a peak at 0.0050 mg HC/g TOC/Ma in the Middle Triassic (240 Ma).

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Figure 8.30. Gogo Formation generation rate vs time diagram.

Hydrocarbon expulsion

Figure 8.31 illustrates two expulsion periods for Gogo Formation sediments. The first (main)
period of expulsion occurs in the Mississippian (Late Carboniferous, 344 Ma), 5 My after
sediments commence generation. The first period of expulsion ceased in the Late
Mississippian (330 Ma).

A second period of expulsion occurs from the Lopingian (Late Permian, 255 Ma) and ceases
in the Late Triassic (200 Ma) due to waning generation rates.

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Figure 8.31. Gogo Formation expulsion rate vs time diagram.

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8.6.6 Modelling Results – Laurel Formation

Source rock maturity

The maturity of the Laurel Formation is highest in the Gregory Sub-basin (Figure 8.32),
showing the highest maturation rates; undergoing subsidence in the Mississippian and in the
Guadalupian (Middle Permian) until the Middle Triassic (265 – 240 Ma). Subsidence wanes
in the Middle Triassic and resumes in the Late Triassic until maximum maturity at 200 Ma.
Laurel Formation sediments undergo slower maturation rates on the Betty Terrace and
sediments very slowly subside on the Balgo Terrace and in the Billiluna Sub-basin.
Sediments on the Betty Terrace, Balgo Terrace and Billiluna Sub-basin all reach maximum
maturity in the Late Triassic (200Ma).

Gregory Sub-basin sediments enter the early oil window (0.55 – 0.70 %Ro) in the Late
Permian (Lopingian, 252 Ma) and reach the main oil window (0.70 – 1.0 %Ro) in the Middle
Triassic (240 Ma). Laurel Formation sediments in the Gregory Sub-basin continue towards
(and essentially enter) the late oil window (1.0 – 1.3 %Ro) at the point of maximum maturity
(200 Ma). Betty Terrace and Balgo Terrace sediments enter the early oil window (0.55 – 0.7
%Ro) at maximum maturity (200 Ma), whilst the Laurel Formation in the Billiluna Sub-basin
remains immature at present day.

Wet gas

Late oil window

Main oil
Early oil

Figure 8.32. Laurel Formation maturity vs time diagram.

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Transformation ratios

Laurel Formation kerogens on the Betty Terrace and Balgo Terrace undergo low fractions of
transformation to petroleum (Figure 8.33). The Betty Terrace shows 10% conversion in the
southern portion of the study area (RB82-28) when sediments reach maximum maturity in the
Late Triassic (200 Ma). Kerogens at Olios 1 reach 4% conversion to petroleum at maximum
maturity.

Kerogens in the Gregory Sub-basin undergo considerably higher ratios of cracking to

petroleum. Transformation ratios of Laurel Formation kerogen in the Gregory Sub-basin
ranges 69 % to 97%, suggesting kerogens within the Gregory Sub-basin effectively
completely convert to petroleum in areas of optimal maturation (main to late oil window –
0.70 – 1.3% Ro). Kerogen conversion commences in the Early Triassic and ceases in the Late
Triassic (252 – 200 Ma), in relation to the timing of maturation within the Gregory Sub-
basin.

Figure 8.33. Laurel Formation transformation ratio vs time diagram.

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Hydrocarbon generation

The Laurel Formation (Figure 8.34) within the Gregory Sub-basin commences generation in
the Early Triassic (255 Ma) when sediments enter the early oil window (0.55 – 0.7 %Ro).
Sediments in the Gregory Sub-basin briefly decrease in generation rates due to waning
subsidence between 240 Ma – 231 Ma (Middle Triassic). The main generative phase for the
central Gregory Sub-basin within the study area (Bindi 1) commences at 231 Ma and reaches
peak generation in the Middle Triassic (226 Ma). Kilang Kilang 1 and Lake Betty 1
demonstrate that other portions of the Gregory Sub-basin vary in generative periods – Kilang
Kilang 1 (southeastern Gregory Sub-basin) reaches peak generation in the Late Triassic (200
Ma). The northern portion of the Gregory Sub-basin appears to reach peak generation earlier,
in the Middle Triassic (242 Ma). This illustrates a Laurel Formation generative trend; where
the northern portion generates ahead of the central Sub-basin, followed by generation in the
south. Laurel Formation generation within the Gregory Sub-basin ceases in the Early Jurassic
(180 Ma). Generative rates are low, reaching 0.00245 mg HC/g TOC/Ma.

Modelling suggests that the Laurel Formation sediments generate at extremely low rates on
the Betty Terrace and Balgo Terrace, with a brief generative period in the Late Triassic (200
Ma), at 0.0009 mg Hg/g TOC/Ma. This generative period commences as sediments on the
Betty Terrace and Balgo Terrace enter the early oil window (0.55 – 0.7 %Ro). Sediments in
the Billiluna Sub-basin do not generate, as these sediments remain immature (<0.55 %Ro).

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Figure 8.34. Laurel Formation generation rate vs time diagram.

Hydrocarbon expulsion

Expulsion from the Laurel Formation within the Gregory Sub-basin (Figure 8.35)
commenced in the Late Triassic (220 Ma), 35 My after the Laurel Formation commenced
generating. Expulsion continues as the Laurel Formation reaches maximum generation rates
in the Late Triassic, and ceases in the Late Jurassic (192 Ma) when expulsion rates fall below
the saturation threshold.

Modelling results (Figure 8.35) illustrate that the Laurel Formation on the Betty Terrace,
Balgo Terrace and Billiluna Sub-basin undergo expulsion commencing in the Mississippian,
however this is anomalous, because sediments do not enter the early oil window (0.55 – 0.70
%Ro) until the Late Triassic (214 Ma). Expulsion does not occur on the Betty Terrace, Balgo
Terrace and Billiluna Sub-basin.

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Figure 8.35. Laurel Formation expulsion rate vs time diagram.

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8.6.7 Modelling Results – Anderson Formation

Source rock maturity

The Anderson Formation shows slightly different maturation rates between the Gregory Sub-
basin and the Betty Terrace (Figure 8.36). Sediments undergo burial from the Mississippian
after older stratigraphy was uplifted during the Carboniferous Meda Transpression Event.
The Anderson Formation in the Gregory Sub-basin shows the highest rates of maturation
during the Lopingian (Late Permian) to Late Triassic (255 – 240 Ma). The Anderson
Formation on the Betty Terrace undergoes lesser subsidence. There appears to be a slight
waning in subsidence rates in the Middle Triassic (230 Ma) prior to continued burial, where
sediments reach maximum maturity in the Late Triassic (200 Ma).

The Anderson Formation in the Gregory Sub-basin enters the early oil window (0.55 – 0.70
%Ro) in the Middle Triassic (245 Ma) and enters the main oil window (0.70 – 1.0 %Ro) in
the Late Triassic (225 – 205 Ma. Note that Bindi 1 matures faster – entering the main oil
window at 225 Ma, reflecting a deeper structural setting relative to the Kilang Kilang 1 well).

Sediments within the Betty Terrace generally remain immature, however the RB82-28
pseudo well indicates Anderson Formation sediments reach the early oil window (0.55 – 0.7
%Ro) as a result of Triassic rifting (200Ma). This alludes to the Anderson Formation
obtaining marginally higher maturity in the southwest portion of the Betty Terrace. Note that
the Anderson Formation is only preserved in isolated packages throughout the study area
(refer Chapter 6.23) because the Anderson Formation was largely eroded as a result of the
Carboniferous Meda Transpression, well before sediments started to mature.

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Main oil window

Early oil window

Figure 8.36. Anderson Formation maturity vs time diagram.

Transformation ratios

Anderson Formation kerogens on the Betty Terrace undergo relatively low conversion to
petroleum, showing TR less than 10% (Figure 8.37). Maximum conversion is at 6% in the
Early Jurassic (192 Ma).

Kerogens in the Gregory Sub-basin undergo high fractions of kerogen cracking. Kilang
Kilang 1 kerogens show ratios of 18%, whilst Bindi 1 indicates ratios of 82%, also in the
Early Jurassic. Maximum kerogen conversion occurs as a result of sediments within the
project area reaching maximum maturation at the end of the Triassic (200 Ma), and are higher
in the Gregory Sub-basin due to higher maturation obtained in the main oil window (0.7 – 1.0
%Ro, Figure 8.36).

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Figure 8.37. Anderson Formation transformation ratio vs time diagram

Hydrocarbon generation

Anderson Formation sediments in the Gregory Sub-basin commence generation in the Early
Triassic (Figure 8.38) when the section enters the early oil window (0.55 – 0.7 %Ro).
Generation rates for the Anderson are low (0.002 mg HC/g TOC/Ma). Peak generation occurs
in the Late Triassic (220 Ma) once sediments enter the main oil window (0.7 – 1.0 %Ro).
Betty Terrace sediments generate hydrocarbons t relatively low rates, where generation
reaches a maximum at the end of the Triassic (200 Ma).

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Figure 8.38. Anderson Formation generation rate vs time diagram.

Hydrocarbon expulsion

Anderson Formation sediments within the Gregory sub-basin expel hydrocarbons

commencing in the Late Triassic (216 Ma), 36 My after sediments commenced generation
(Figure 8.39). Results indicate that expulsion ceases in the Early Jurassic (192 Ma), once
saturation levels fall below the expulsion threshold.

Figure 8.39 illustrates that Anderson Formation sediments on the Betty Terrace commence
expulsion in the Pennsylvanian (Late Carboniferous, 320 Ma), however this is likely an
anomaly in the model, because Betty Terrace generation is below the expulsion threshold at
200 Ma. No meaningful expulsion is interpreted here.

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Further, Gregory Sub-basin sediments are the only region to achieve TR over 50%, thus
initiating generation. The Anderson Formation on the Betty Terrace and Balgo Terrace only
reaches the early oil window (0.55 – 0.7 %Ro) at peak maturity in the Late Triassic (200 Ma).

Figure 8.39. Anderson Formation expulsion rate vs time diagram.

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8.6.8 Modelling Results – Noonkanbah Formation

Source rock maturity

There is slight variability in maturation of the Noonkanbah Formation between the Gregory
Sub-basin and Betty Terrace (Figure 8.40). Wells in the Gregory Sub-basin undergo the
highest subsidence rates, likely due to rapid accommodation generation developing along the
Stansmore Fault. Wells on the Betty Terrace undergo shallower maturation gradients relative
to other provinces. All wells undergo slow subsidence in the Lopingian (Late Permian).
Subsidence increases at 250 Ma, due to the onset of rifting in the Triassic Fitzroy Movement,
where sediments mature through the Early and Middle Triassic (250 – 230 Ma). The
Noonkanbah Formation undergoes a second period of burial in the Late Triassic (210 – 200
Ma), however Bindi 1 undergoes earlier burial commencing from 232 Ma. TWT structure
mapping on the Near Top Noonkanbah Formation (Figure 6.11) shows that Bindi 1 is situated
in an area of focused subsidence, timing of which is indicated in Figure 8.15 and Figure 8.40.
The Noonkanbah Formation in the Gregory Sub-basin reaches the early oil window (0.55 –
0.7 %Ro) in the Late Triassic (200Ma, and Bindi 1 from 215 Ma). Wells on the Betty Terrace
remain immature (0.0 – 0.55 %Ro).

Main oil window

Early oil window

Figure 8.40. Noonkanbah Formation maturity vs time diagram.

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Transformation ratios

Modelling results (Figure 8.41) indicate that Noonkanbah Formation kerogens have not
undergone significant cracking to petroleum, with TR less than 10%. Low levels (2%) of
conversion occur in the Early Triassic (245 Ma), and up to 4% is converted within Gregory
Sub-basin sediments at peak maturity in the Late Triassic (200 Ma). Low TR is attributed to
the largely immature character of the Noonkanbah Formation, and explains absence of
meaningful generation (figures 8.41 and 8.42). The 4% TR in the Late Triassic reflects early
oil window maturation in the Gregory sub-basin at the time.

Figure 8.41. Noonkanbah Formation transformation ratio vs time diagram.

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Hydrocarbon generation

Modelling results confirm that hydrocarbon generation from the Noonkanbah Formation does
not meaningfully commence in the project area. Figure 8.42, shown here for completeness,
indicates extremely small generation rates (maximum 0.000046 mg HC/g TOC/Ma) in
accordance with timing of subsidence (Figure 8.40). The model is meaningless as the
Noonkanbah Formation within the project area only reaches the early oil window (0.55 – 0.7
%Ro) at peak maturity in the Triassic, and is therefore deemed to be non-generative.

Figure 8.42. Noonkanbah Formation generation rate vs time diagram.

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Hydrocarbon expulsion

Modelling results, shown here for completeness (Figure 8.43), demonstrate that the
Noonkanbah Formation does not expel hydrocarbons within the project area. The
Noonkanbah Formation does not generate hydrocarbons (Figure 8.42) to induce expulsion.

Figure 8.43. Noonkanbah Formation expulsion rate vs time diagram.

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8.7 Hydrocarbon Accumulation Analysis

PetroMod migration and accumulation analysis is a valuable aspect of 2D basin modelling

that can provide insights into hydrocarbon migration pathways and areas of hypothetical
hydrocarbon buildups. 2D models were simulated (Figure 8.14) to test possible hydrocarbon
accumulations within structural traps identified in Chapter 6.2.4.

Volumes: A word of caution

It is important to note here, that whilst occurrences of accumulations provides insights and
validity to favourable petroleum system evolution, the following should be understood:

Structures that host simulated accumulations were defined using simple depth
conversion techniques (Chapter 5.5.1) that may not correctly accommodate effects of
velocity of overlying stratigraphy on to underlying rocks. The Laurel Formation is an
example of this possibility. A more detailed depth conversion is advised.
Source rock TOC and Rock Eval Pyrolysis data is averaged in the models, which can
artificially increase the generation and expulsion abilities of source rock intervals,
hence volume.
The Devonian aged section contains several layers of stratigraphy that are not sub-
divided in models constructed in this study. For example, the thick Devonian section
on RB82-28 is configured to represent the Gogo Formation (averaging 0.5% TOC
according to available data). This induces the assumption that the whole Devonian
aged section is at 0.5% TOC, rather than a relatively thin 0.5% TOC layer and other
layers with possibly 0% TOC.
Ages that are applied in Fault Definition are relative estimates from seismic
interpretation and published literature, and could benefit from a more detailed
consideration.
Volumes assume a constant reservoir geometry 500 metres out of the 2D model plane.
2D models are unable to detect 3D mappable closure, and assume that trapping
geometries are valid to support an accumulation if they are detected within the 2D
plane.

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8.7.1 Modelling Results

RB81-7

Regional seismic line RB81-7 was principally built to model the evolution of petroleum
systems across all tectonic regions, and secondly to test the possibility of accumulations
occurring at trap D and E (Figure 6.10).

Results illustrate that no present day accumulations were simulated within trap D or E. A
small gas accumulation was simulated to be present (Figure 8.44) within the Poole Sandstone
on a structural high in the Gregory Sub-basin (27°S 10’ 06”E, 127° 05’ 44”E). Kilang Kilang
1 tested the flank of the structure (4.7 km down dip to the southwest - out of the plane of the
model), however no hydrocarbon shows were noted at the Poole Sandstone level.

The RB81-7 simulation indicates, that although the Kilang Kilang 1 well was dry, the
simulation is still valid because it predicts a small accumulation at the crestal position of the
structure, which is not detectable at the Kilang Kilang 1 location. TWT structure mapping on
the Near Top Poole Sandstone (Figure 6.12) reveals that there is a subtle mappable closure at
in this location.

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 S NE

Triassic

Noonkanbah Fm Poole Sandstone

Siluro-Devonian
Grant Group
Fairfield Group

Ordovician

Correct position
of high is out-
of-plane

Billiluna Sub-basin

Betty Terrace Balgo Terrace

Gregory Sub-basin

Figure 8.44. RB81-7 2D model at present day. Results show a small gas accumulation in the Poole Sandstone.
 Chapter 8 – Petroleum Systems Modelling

Arbitrary Line 82GN-03, S85LM-08, S85LM-08A

Arbitrary Line 82GN-03 was built to simulate the evolution of petroleum systems in the
northern study area, and to also test for any accumulations within Trap B (Figure 6.10).
Modelling results indicate the preservation of two small gas accumulations within the
Devonian section and Poole Sandstone over Trap B (Figure 8.45). Results also indicate six
large oil accumulations within the Devonian and Poole Sandstone in an area up-dip, across
the Hinge Fault on the Betty Terrace and Balgo Terrace (19°S 32’ 29”E, 126° 31’ 23”E,
Figure 6.10, and Figure 6.16). Trap B and the up-dip accumulations are untested by
exploration drilling though there are a number of surrounding wells.

TWT structure on the Near Top Poole Sandstone reveals no mappable closure is present at
this location, as closure only develops in Carboniferous and older stratigraphy. Therefore, the
two Poole Sandstone accumulations are invalid as the model incorrectly assumes that
trapping geometries have developed out of the 2D plane.

TWT structure mapping shows apparent fault bound closure at Trap B in pre-Carboniferous
stratigraphy, so the model correctly assumes apparent closure for the Devonian gas
accumulation in Trap B. Closure is more difficult to justify for accumulations on the Betty
and Balgo Terrace, because the TWT interpretation (Figure 6.16) shows a likely leakage path
to the north. There is a small apparent-time structural closure in the footwall of the Stansmore
Fault that may support the validity of the southern-most Devonian accumulation. The
modelling of other Devonian accumulations are therefore questionable in terms of out-of-
plane trap assumptions.

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 No mappable No mappable
closure closure
S NE

Triassic Noonkanbah Fm Siluro-Devonian

Poole Sandstone
Ordovician
Grant Group
Fairfield Group
Likely leakage
Likely leakage out of plane
Small mappable out of plane
closure against
Accumulation fault
corresponds to
mapped closure

Balgo Terrace

Betty Terrace

Gregory Sub-basin

Figure 8.45. Arbitrary line 82GN-20 2D model. Results indicate sizable oil accumulations however a number of them are invalid as they are located within invalid structural traps.
 Chapter 8 – Petroleum Systems Modelling

RB82-28

Model RB82-28 was primarily built to test a large apparent time structural closure at Trap A
in the southwestern project area. This large apparent structure has not been tested by
exploration drilling. Results indicate eight large oil accumulations in Devonian stratigraphy
and one oil accumulation with a gas cap in the Poole Sandstone.

No mappable closure exists for Poole Sandstone stratigraphy, so trap geometries in the Poole
Sandstone are invalid assumptions in the model. Most of the closure in the Devonian
sequence that is assumed by the model is validated by TWT structure maps. Closure is
provided by a series of tilted fault blocks across a broad anticline. Note that faulting in the
model is more detailed than on TWT maps (small scale faulting was not correlated across the
study area) but all faulting is observed to occur within regional closure across the broad
anticline. Apparent trap validity is highlighted in Figure 8.46.

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 No mappable
closure
S NE
Triassic
Noonkanbah Fm
Poole Sandstone
Grant Group

Anderson Formation

Accumulations
Fairfield Group
corresponds to
No mappable
Accumulation mapped closure
closure
corresponds to across broad anticline
mapped closure

Siluro-Devonian

Ordovician

Figure 8.46. RB82-28 present day 2D model. Results indicate a large oil accumulation across a broadly folded anticline that corresponds to a mapped closure on seismic.
 Chapter 8 – Petroleum Systems Modelling

RB81-10

2D model RB81-10 was principally built to simulate the evolution of petroleum systems
across the Betty Terrace. The model also intersects the southwestern portion of Trap A
(Figure 6.10). Results indicate a moderate gas accumulation in the Poole Sandstone within
the Trap A area, however no mappable closure exists at this location within the Poole
Sandstone, so the model incorrectly assumes trapping geometry (Figure 8.47).

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 No mappable
closure
S NE
Triassic
Noonkanbah Fm
Poole Sandstone Grant Group
Anderson Fm
Fairfield Group

Siluro-Devonian

Ordovician

Triassic Facies
Top Noonkanbah Facies
Top Poole Facies
Top Grant Facies
Top Meda Transpression Facies
Top Fairfield Facies
Top Devonian Facies
Top Ordovician Facies

Figure 8.47. RB81-10 present day 2D model. Results indicate a small gas accumulation however it is not located within a mapped closure.
 Chapter 8 – Petroleum Systems Modelling

8.8 Summary of Results

This Chapter accompanies Chapter 7 to complete the source rock characterization of the
project area. In this Chapter, five 1D models were constructed at existing well locations
(Lake Betty 1, Olios 1, Bindi 1, Ngalti 1 and Kilang Kilang 1; Figure 8.3) and calibrated to
existing thermal maturity measurements. Four 2D models were also constructed across 2D
seismic lines in the project area (RB81-7, RB81-10, RB82-28 and Arbitrary line 82GN-
03/S85LM-08/S85LM-08A; Figure 8.3). The main purpose of modelling was to characterise
the thermal maturity of sediments within the Larapintine L2, L3, L4 and Gondwannan G1
petroleum systems, and t determine the timing of source rock hydrocarbon generation.

Apatite Fission Track Analysis (AFTA) was valuable in providing insight into the geological
history and timing of thermal events. The incorporation of recent work by Duddy et. al.,
(2003) facilitated a thorough investigation into when petroleum system source rocks (The
Goldwyer Formation, Bongabinni Member, Gogo Formation, Laurel Formation, Anderson
Formation and Noonkanbah Formation) entered respective hydrocarbon product
windows. Tables 8.10 and 8.11 summarise the results of this hapter, and also provide a
useful quick-reference guide to accompany Table 7.13. Model RB82-28 (primarily built to
test a large apparent time structural closure at Trap A), which is untested by exploration
drilling to date, indicates eight large simulated oil accumulations in Devonian stratigraphy.

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Table 8.10. Summary of modelling results for the Gondwannan G1 and Larapintine L3 and L4 petroleum systems.
Table 8.11. Summary of results for the Larapintine L2 petroleum system.
 Chapter 9 – Discussion

9. Discussion – An Evaluation of Petroleum Systems in

the Northeast Canning Basin

The Canning Basin contains sediments belonging to three major Palaeozoic petroleum
systems: the Larapintine L2 (Ordovician – Silurian), Larapintine L3 and L4
(Devonian – early Carboniferous), and Gondwannan G1 and G2 (late Carboniferous –
Permian) (Bradshaw et al, 1994). Determining the extent to which these petroleum
systems are present and active within the study area was the primary goal of this
study.

This Chapter aims to address unanswered questions concerning the petroleum

prospectivity within the study area, such as:

Why did key exploration wells fail to detect hydrocarbon accumulations?

What can paleogeography predict about suitability of source rocks,
reservoirs and seals?
How does the timing of petroleum system evolution relate to prospectivity
(petroleum system elements diagrams)?
What play-types should be targeted within each petroleum system?
What are the key recommendations that can help in reducing risk of
exploring in the northeast Canning Basin?

9.1 Prospectivity – Are Active Petroleum Systems Present within the

Northeast Canning Basin?

A synthesis of the analysis of reservoir quality and seal integrity (Chapter 4),
hydrocarbon trapping configurations (Chapter 6), source rock richness (Chapter 7),
and thermal maturity and timing of hydrocarbon generation and migration (Chapter 8)
indicates that the exploration prospectivity within the study area is high risk.
Stratigraphic and seismic frameworks (chapters 4 and 6) indicate that rocks belonging

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 Chapter 9 – Discussion

to all three petroleum systems are present within the study area, but confidence that
all the elements critical to dynamic petroleum systems are active across all three
petroleum systems is lacking. Source rock richness and timing/migration appear to be
the criteria of greatest exploration risk and contributed to the failure of 6 of the 7 dry
holes drilled in the project area (Table 9.1). Structural integrity of the trap is the next
greatest exploration risk and played a role in the failure of the 7th dry hole, and was
also a contributing factor in 4 others. A lack of thermal maturity was only an issue in
the shallowest petroleum system, the Permian Gondwannan G1. Reservoir and seal
are criteria with the least exploration risk.

Although the Larapintine L2 petroleum system contains the world class source rock,
the Ordovician (Llanvirn) Goldwyer Formation, paleogeographic facies
reconstruction suggests that the Goldwyer is in a proximal depositional setting within
the study area and characterised by organically lean sand-rich siliciclastic facies. In
the Larapintine L3 and L4 petroleum system, the source rocks such as the Anderson,
Laurel, and Gogo Formations are thermally mature, but are organically lean.
Conversely, the main source rock in the Gondwannan G1 petroleum system, the
Noonkanbah Formation, is organically rich, but thermally immature. The Triassic
aged Fitzroy Movement created a structural overprint that imposes a significant threat
to trap integrity of Carboniferous aged structures. Triassic aged structures may have
developed marginally too late to trap hydrocarbons that generated at the time of peak
thermal maturity in the Triassic.

Given the current geochemical dataset, hydrocarbon migration is required from

basinal settings (for example the Gregory Sub-basin) to charge shelfal positions
within the study area to consider all petroleum systems prospective (the only regional
exception is the Larapintine L2 petroleum system, where a self-sourcing
unconventional play could be targeted in a distal marine environment).

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 Chapter 9 – Discussion

Synopsis of the Larapintine L2 Petroleum System

There are no wells drilled deep enough within the study area to directly test the
exploration prospectivity of the Larapintine L2 petroleum system. However, analysis
of regional 2D seismic data indicates that rocks of Ordovician-Silurian age are present
in the subsurface across the project area. Petrophysical analysis of Lake Havern 1,
which lies to the southwest of the study area, indicates good quality sandstone
reservoirs and rocks with sealing potential are present within the Ordovician-Silurian
stratigraphy. Projection of these results into the study area, along with the regional 2D
seismic that defines large traps in the hanging wall of the Stansmore Fault, is
encouraging for the prospectivity of the Larapintine L2 petroleum system. However,
the petroleum system is likely inactive, for two reasons. Firstly, paleogeographic
reconstructions for the Goldwyer Formation source rock (Figure 9.8) indicates that
the Goldwyer Formation was deposited in a supra-tidal setting and the lithotypes that
accumulated would have been sand-rich. The paleogeographic reconstruction suggests
that the organically rich marine facies were deposited further basinward in the
Gregory Sub-basin. Secondly, vitrinite-time diagrams and criterial moment charts
created for the source rock (Figure 9.11) indicates that the Ordovician sediments
rapidly mature through all hydrocarbon generative windows (expulsion concludes at
385 Ma), and thus predating the Late Devonian or Mississippian trap development.
Hydrocarbons, if generated, are likely to have migrated out of the system.

Synopsis of the Larapintine L3 and L4 Petroleum System

Exploration prospectivity of the Larapintine L3 and L4 petroleum system is ranked

higher than the Larapintine L2, however is also considered to be high risk. All wells
within the project area intersect Larapintine L3 and L4 stratigraphy, providing tests of
the petroleum system. Rocks of the L3 and L4 petroleum systems are present within
the study area, indicated by seismic interpretation and well correlations (chapters 4, 5
and 6). Although several wells (for example Bindi 1 and Kilang Kilang 1; refer to
Table 9.1) indicate that good quality reservoir rocks, optimal trapping configurations,
and lithologies with probable sealing capacity are present, the petroleum systems are
interpreted to be largely inactive, restricted by source rock organic richness. Source
rock geochemical analysis indicates that the regional source rocks are lean; the Gogo

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 Chapter 9 – Discussion

Formation averages 0.14% TOC (and averaging 1.25% TOC by Wulff, 1987), the
Laurel Formation averages 0.56% TOC regionally and 0.46% TOC within the study
area, and the Anderson Formation averages 0.14% TOC. Geochemical data from
individual wells (Chapter 4.6.1) and paleogeographic reconstructions (Figure 4.27)
indicate that source rock organic richness for the Laurel Formation is likely to
increase basinward within the Gregory Sub-basin. Modelling (summarised in Table
8.10) advises that L3 and L4 source rocks are mature for hydrocarbon generation
across the project area (though the Anderson Formation is immature on the Betty and
Balgo Terraces, and within the oil window in the Gregory Sub-basin), therefore
lateral hydrocarbon migration is required for any prospectivity to eventuate in the
Larapintine L3 and L4 petroleum system.

Synopsis of the Gondwannan G1 and G2 Petroleum System

Exploration prospectivity of the Gondwannan G1 petroleum system is marginal.

Analysis of regional data, and information provided by the Bindi 1 and Kilang Kilang
1 wells, have indicated that even though good quality reservoir rocks, sealing rocks
and optimal traps are accounted for, the Gondwannan G1 petroleum system is largely
inactive within the project area because it lacks a mature source rock. Geochemical
analysis (Chapter 4.8.2) indicates that the Noonkanbah Formation is organically rich
in the study area (averaging 2.17% TOC regionally and 1.69% TOC locally), however
petroleum systems modelling demonstrates that the Noonkanbah Formation is
immature across the Billiluna Sub-basin, Betty and Balgo Terraces, and only reaches
the early oil window (0.55 – 0.7 %Ro) deeper within the Gregory Sub-basin (Figure
8.10). This requires that hydrocarbons must laterally migrate up dip from the Gregory
Sub-basin to fill the shelfal reservoirs targeted within the study area. A scenario
involving vertical hydrocarbon charge from the underlying Laurel Formation is also
considered marginal because geochemical analysis indicates that the Laurel
Formation is organically lean.

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 Chapter 9 – Discussion

9.2 Analysis of Exploratory Tests within the Study Area

Nine exploration wells have been drilled within the project area. Selenops 1 and Atrax
1 were purely stratigraphic tests and did not target any hydrocarbon accumulations.
The remaining seven wells were dry (summarised in Table 9.1). A dry hole analysis
of these wells indicates that source rock richness and timing/migration are the most
common reason for well failure (Table 9.1). Structural integrity of the trap is the
second most common reason for failure followed by seal reliability. Thermal maturity
was a contributor to well failure only in the Gondwannan G1 and G2 petroleum
system. Reservoir development was found to never impact well failure and is thus
considered the criterion of lowest exploration risk. A detailed summary of the dry
hole analysis for each of the wells drilled within the project area is presented herein.

Larapintine L2 Larapintine L3 / L4 Gondwannan G1 / G2

Tim/Mig.

Tim/Mig.

Tim/Mig.
Well
Source Source Source
Seal.

Trap

Trap

Trap
. Res.

. Res.

. Res.
Seal

Seal
cM

cM

M
R

R
ah

ah
ha

c
i

.t
t.

t.

Lake Betty 1 -
Lanagan 1
Ngalti 1 No wells intersect
Lawford 1 Larapintine L2
Olios 1 stratigraphy
Selenops 1 Stratigraphic test - no targeted closure
Atrax 1 Stratigraphic test - no targeted closure
Bindi 1
Kilang Kilang 1
Table 9.1. Summary of exploratory tests within the project area, highlighting reasons for failure.

No wells within the project area drilled deep enough to intersect Larapintine L2
petroleum system stratigraphy (Ordovician – Silurian). All wells tested the
Larapintine L3/L4, but Bindi 1 and Kilang Kilang 1 wells also tested the
Gondwannan G1/G2 petroleum system.

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 Chapter 9 – Discussion

9.2.1 Lake Betty 1

Lake Betty 1 was drilled to primarily test the Devonian Pillara and Ordovician Nita
carbonates, and secondly to test the Carboniferous Laurel Formation, in an interpreted
fault-bound 3-way structural closure defined on poor quality 2D seismic data (Figure
9.1). The well reached total depth in the Devonian Poulton Formation at 3145.8 mRT,
but did not reach the Ordovician Nita carbonate. The Devonian Pillara Carbonate was
absent because of normal faulting (Crank, 1972), such that the well did not test any of
the primary objectives. Lake Betty 1 encountered a gas show in Laurel Formation
sandstones; totalling 78 units of C1.

Geophysical logs confirm the presence of Laurel Formation sandstones and also the
overlying Laurel Formation shales that suitably seal the reservoir. The Laurel
Formation source rock at Lake Betty 1 has zones that are organically rich (1.16% to
3.29% TOC between 1660 – 2200 mRT), and modelling indicates that the source rock
reaches the oil window (0.7 – 1.0 %Ro) in the Gregory Sub-basin during the Triassic;
hence oil was expected, but a show of dry gas was observed.

Poor resolution of the controlling fault on the 2D seismic data, coupled with the
uncertainty of the timing on the fault reactivation e serious question on the
integrity of the structural closure. It is possible that the fault was reactivated during
the late Triassic/early Jurassic Fitzroy compressional phase which post-dates the
maturation of the Laurel Formation source rock. In conclusion, Lake Betty 1 may not
have tested a valid structural closure.

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 Chapter 9 – Discussion

ED81-57
Lake Betty 1
TWT (s) SP 300

Grant Group
0.5

Fairfield Group

1.0

Figure 9.1. The Lake Betty 1 structure on 2D seismic.

The above analysis indicates that the reasons for Lake Betty 1 failure are;

Integrity of the structural closure.

Timing of the fault reactivation post-dating the thermal maturation of the
Laurel source rock.
The well failed to intersect the primary Devonian reservoir, and was not
drilled deep enough for Ordovician stratigraphy.

9.2.2 Lanagan 1

Lanagan 1 drilled a seismically valid large horst related anticline in the (redefined)
Gregory Sub-basin. The primary target was the Carboniferous Laurel Formation and
Devonian Knobby Sandstone reservoirs. No hydrocarbon shows were observed other
than background gas (maximum 10 units) during drilling. Lanagan 1 confirmed the
presence of good quality reservoir rocks in the Knobby Sandstone and Laurel
Formation. Geophysical logs (Figure 4.32) indicate that the Grant Group B member
seal is present, though seismic (Figure 9.2) demonstrates that there may be

348
 Chapter 9 – Discussion

insufficient juxtaposition seal across faults allowing lateral leakage out of the Laurel
Formation. Impermeable Laurel Formation microcrystalline limestones are assumed
to be sufficient to cap the Knobby Sandstone reservoir unit.

S85LM-06
Lanagan 1
TWT (s) SP 200 300 400

Grant Group

Fairfield Group

0.5 Knobby Sandstone

Figure 9.2. The Lanagan 1 structure on 2D seismic.

The Laurel Formation source rock is regionally organically lean (though increases in
organic contents basinward) and thermally mature for oil in the Gregory Sub-basin
(Table 8.10), thus migration from the Sub-basin is required, which is within
achievable distances.

TWT structure on the Near Top Fairfield Group (Figure 6.15) confirms that Lanagan
1 is located in the footwall of a large listric fault. The gas show in the Laurel
Formation is likely sourced from Devonian rocks (which are mature for gas
generation). This indicates that there may be a migration problem at Lanagan 1. The

349
 Chapter 9 – Discussion

listric fault immediately south of Lanagan 1 might be an impermeable migration

barrier causing hydrocarbons to migrate around the fault.

The above analysis indicates that the reasons for failure at Lanagan 1 are:

Absence of seal to cap to Laurel Formation

Preferential migration around an impermeable fault
Regionally lean Laurel Formation source rocks.

9.2.3 Ngalti 1

Ngalti 1 was drilled to test a 3-way fault bound closure defined on 2D seismic data at
the Knobby Sandstone level on the Balgo Terrace (Figure 9.3). No hydrocarbon
shows were observed. The well confirmed the presence of good quality reservoir
rocks in the Knobby Sandstone. The well intersected 271 metres of cryptocrystalline
Laurel Formation, suggested by geophysical logs (Figure 4.25) to be tight. However,
the juxtaposition fault seal required across the fault was likely porous Anderson
Formation siliciclastics. Lack of lateral seal was a contributing factor to well failure.

RB82-31 RB82-43
Ngalti Ngalti

TWT SP 600 100 200

(s)

Grant Group Grant Group

Fairfield Group Fairfield Group

Knobby Sandstone Knobby Sandstone

Figure 9.3. The Ngalti 1 structure on 2D seismic. D p line on left, strike line image on right.

350
 Chapter 9 – Discussion

Source rock charge concerns the presence of the Gogo Formation in this portion of
the study area, which is unknown. Given that no shows were observed; it seems that
an absence of charge is a key reason for failure.

The above analysis indicates that the reasons for Ngalti 1 failure are:

Absence of source rock charge;

Failure to sufficiently acknowledge the presence of the porous Anderson
Formation sandstones across the fault, thus an absence of lateral seal;

9.2.4 Lawford 1

Lawford 1 was drilled on a 4-way dip-closed anticline that was defined on a broad 2D
seismic grid in the Gregory Sub-basin (Figure 9.4). The structure developed in the
Carboniferous, but takes its present day form due to Triassic wrench faulting. The
well confirmed good quality Carboniferous Laurel Formation and Anderson
Formation reservoirs, and a thick preserved Anderson Formation intersection suggests
the interbedded shales appropriately seal the underlying units. The paleogeographic
location of the well (basinal setting) also points to higher shale content for Anderson
Formation seal. No hydrocarbon shows were observed throughout drilling.

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 Chapter 9 – Discussion

S87LM-08
Lawford 1
TWT SP 200 300 400 500 600
(s)

Grant Group

Anderson Formation
0.5
Fairfield Group

Figure 9.4. The Lawford 1 structure on 2D seismic.

The Anderson Formation and Laurel Formation are within the oil window and the
Devonian Gogo Formation is within the dry gas window in the Gregory Sub-basin.
Evidence of hydrocarbon generation was not observed by fluorescence or staining
through the Laurel Formation and Anderson Formation, therefore a more likely
scenario is that the source rocks are lean. Lawford 1 is located in a basinal position
close to the hydrocarbon kitchen, thus migration of hydrocarbons should not be an
issue.

The above analysis indicates that the reasons for failure at Lawford 1 are:

Structural integrity because the closure is defined by a very broad 2D seismic

grid.
Timing of hydrocarbon migration could also be in doubt because, although the
structure initially formed prior to the Carboniferous Meda Transpression, it
was reactivated by the Triassic Fitzroy Movement potentially breaching the
structure.

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 Chapter 9 – Discussion

Alternatively, the source rocks may be lean.

9.2.5 Olios 1

Olios 1 drilled a seismically-defined, fault bound 2-way horst block on the Betty
Terrace thought to have developed during the Carboniferous, to test Devonian
Carbonate reservoirs (Figure 9.5). Subtle disturbance in the overlying Grant Group
and also small throws along the up-dip bounding fault indicate that Triassic episodes
likely influenced the final geometry (potentially reactivating the sealing faults).

The well reached total depth in the Knobby Sandstone after no Devonian Carbonate
reservoir was intersected. The well confirms the presence of good quality reservoir
rocks in the Carboniferous Laurel Formation clastic section (sonic porosities in the
20% range, Figure 4.28), and confirms the Knobby Sandstone has excellent reservoir
quality at this location (sonic porosities in the 10 – 20% range, Figure 4.23).
Hydrocarbon shows were observed during drilling:

Faint petroliferous odor and faint oil stain in the upper Laurel Formation;
Gas shows over Laurel Carbonate member (1055 mRT to 1430 mRT); peak
113 units C1;
Faint petroliferous odor and strong fluorescence in the Laurel Carbonate
member; and
Gas shows over the Knobby Sandstone reaching 577 units C1. Gas continued
until the well reached total depth.

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 Chapter 9 – Discussion

83GN-15A
Olios 1
TWT (s) SP 200 300 400

Grant Group

Fairfield Group

0.5
Knobby Sandstone

Figure 9.5. The Olios 1 structure on 2D seismic.

TWT structure on the Near Top Fairfield Group (Figure 5.16) indicates that Olios 1 is
positioned between two large normal faults, potentially obstructing hydrocarbon
migration from accumulating within the Olios 1 structure.

Olios 1 confirms the presence of the Laurel Formation carbonate reservoir and also
confirms the absence of the lower Laurel Formation sealing shale – gas shows
throughout the section appear continuous into the overlying Laurel Formation
(Klappa, et al, 1984).

The Laurel Formation is in the early oil window at Olios 1 and within the main oil
window in the Gregory Sub-basin, however the Laurel Formation is lean (less than

354
 Chapter 9 – Discussion

1% TOC at Olios 1). Oil shows noted in the upper Laurel Formation are likely
derived from migrated hydrocarbons down-dip where the source rock is mature. The
nature of the oil show (stain and fluorescence), the hydrocarbon product mix (oil and
gas shows), along with limited degrees of staining, suggests that migration could be
problematic, likely due to the fault down-dip of the structure acting as a barrier to
migration.

Gas shows throughout the Laurel Formation and Knobby Sandstone were derived
from a Devonian source rock, where modelling indicates that the Gogo Formation is
mature for gas in the Gregory Sub-basin. The persistence of the show throughout the
Laurel Formation and Knobby Sandstone is due to the absence of the Laurel
Formation seal.

The above analysis indicates that the reasons for Olios 1 failure are:

Migration difficulties regarding down-dip fault barrier;

Migration around faults obscuring an accumulation;
Absence of the Laurel Formation shale source rock.
Similar to the other dry holes (e.g. Lawford 1 and Lake Betty 1), structural
integrity is a risk for those structures reactivated during the Triassic Fitzroy
movement.

9.2.6 Bindi 1

Bindi 1 was drilled into a subtle wrench related anticline defined on 2D seismic data
in the Gregory Sub-basin. The well confirmed good quality sandstone reservoirs
within the Poole Sandstone, Grant Group, and Anderson Formation (noting only 29.5
metres of the upper Laurel was intersected). Bindi 1 produced 3 poor oil shows and
five dry gas shows:

Patchy yellow fluorescence with instant cut and thick residual ring, between
934 – 949 mRT) in the Poole Sandstone; and

355
 Chapter 9 – Discussion

Five small dry gas shows in Anderson Formation between 2350 mRT and
2450 mRT. The four shallowest were less than 2% C1, the deepest was 8%
C1.

Seismic indicates that the Bindi 1 structure relies heavily on closure provided by
juxtaposition of stratigraphy across the growth fault. Good reservoir potential within
the Poole Sandstone, Grant Group, Anderson Formation and within parts of the
Laurel Formation indicates that there are inherent risks in relying on these reservoir
zones for good lateral seal, particularly because throw on the growth fault is small.

81C-6 Bindi 1 (projected)

TWT (s) SP 400 500 600

0.5

Grant Group

Anderson Formation

1.0

Fairfield Group

Figure 9.6. The Bindi 1 structure on 2D seismic. Bindi 1 well projected onto seismic as the well was
drilled off the 81C-6 2D seismic line.

Although, geophysical logs at Bindi 1 indicate the presence of Anderson Formation

lithologies with good sealing potential such as members A, C, E and G (high gamma
ray blocky shales, Figure 4.29), juxtaposition of these seal rocks across the growth
fault is high risk because growth fault throw is small and reservoir horizons are thick.
A lack of lateral seal is also pertinent to other intersected horizons in the Grant Group
B member and Laurel Formation.

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 Chapter 9 – Discussion

The Noonkanbah Formation is immature across the project area, so the oil show in the
Poole Sandstone has either migrated long distances from a Noonkanbah Formation
source kitchen deeper in the Gregory Sub-basin (less likely), or the oil show
demonstrates vertical migration from deeper source rocks. The Anderson Formation,
though lean at Bindi 1 (Chapter 7.4.3) may generate hydrocarbons deeper in the
Gregory Sub-basin, where the source rock is within the main oil window. Immature
Permian source rocks explain why the shallow portion of the well failed.

The gas shows in the Anderson Formation are likely migrated hydrocarbons from the
Devonian gas generative Gogo Formation within the Gregory Sub-basin. Lean source
rocks indicate why the deeper portion of the well failed.

Interestingly, gas shows increase with depth in the lower Anderson Formation. The
well reaches total depth in the upper-most shale of the Laurel Formation (thereby not
penetrating any Laurel Formation reservoir zones). A gas charged Laurel Formation
may exist below final TD of the Bindi 1 well. If this were the case, it would indicate
the Laurel Formation seals are effective.

Timing is a potential cause for failure at Bindi 1.A fault-bound monocline existed at
Bindi 1 prior to Triassic wrenching. The Carboniferous Gogo Formation generative
phase potentially migrated through the Anderson Formation reservoirs at Bindi 1 in
the absence of trap closure. This indicates that the gas at Bindi 1 is due to the Triassic
generative phase from Devonian source rocks. Gas could be residual, but this option
isn’t preferred. Triassic aged traps occur at a similar time to the main Devonian
generative phase, however a petroleum system elements diagram indicates that
Triassic traps may have developed marginally late (Figure 9.14). Hydrocarbons
generated in the Triassic may have migrated out and Triassic traps might have only
caught the tail end of expulsion. If hydrocarbons did accumulate during the

357
 Chapter 9 – Discussion

Carboniferous generative phase, Triassic faulting might have caused leakage of

hydrocarbons from the structure.

The above analysis indicates that the reasons for failure at Bindi 1 are:

Immature Permian Source rocks;

Lean Carboniferous Source rocks;
Timing of the Bindi 1 anticline is potentially too late.
Lack of lateral seal across the growth fault.

9.2.7 Kilang Kilang 1

Kilang Kilang 1 was drilled to test a large, four-way dip closed anticline defined on a
broad 2D seismic in the Gregory Sub-basin to test the Larapintine L3 and L4, and
Gondwannan G1 petroleum systems (Figure 9.7). Timing of the structure is related to
wrench faulting during the Triassic (Smith, 1985a). The well confirmed the presence
and reservoir quality of the Poole Sandstone and Grant Group. No shows were
observed during the drilling of the well, with the exception of a 0.02% C1 gas show in
the Laurel Formation.

Kilang Kilang 1
RB81-6 Kilang Kilang 1 RB82-47
TWT SP 1300 1500 1600 400 300
(s)

0.5
Grant Group

Anderson Formation
Grant Group

1.0 Fairfield Group

Anderson Formation

Knobby Sandstone
Knobby Sandstone
1.5
Fairfield Group

Figure 9.7. The Kilang Kilang 1 structure on 2D seismic. Dip line on left, Strike line on right.

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 Chapter 9 – Discussion

Note that Kilang Kilang 1 was drilled down dip off the crestal position, demonstrated
on the Siluro-Devonian isochron (Figure 6.16 and Figure 9.7). If source rocks are
lean, though still generative to some extent, a small accumulation is still possible up
dip from the well location. Interestingly, a 2D petroleum systems model (RB81-7,
Figure 8.44), built to test the Kilang Kilang 1 crestal position, simulated that a small
gas accumulation is present within the Poole Sandstone. The decision to drill off
structure was perhaps intentional for commercial reasons (requiring a closure filled to
the 1600 millisecond TWT contour level, for example), however the well is thus not a
valid test of the structure.

The Noonkanbah Formation is correlated to this location, suitably sealing the Poole
Sandstone reservoir. The intra-Grant Group seal (Grant B member) shows blocky
shale packages at this location (Figure 4.32)

The Noonkanbah Formation is immature and does not generate hydrocarbons in the
project area, which explains why the Poole Sandstone reservoir was dry. The Laurel
Formation is mature for oil in the Gregory Sub-basin and generates during the
Triassic, however TOC data indicates the Laurel Formation is lean (<0.37%) which
explains the absence of charge.

The small dry gas show in the Laurel Formation suggests that a Devonian source rock
provided the charge (sufficient maturity). Either Devonian source rocks at the Kilang
Kilang 1 location are lean; lower sections of the Laurel Formation provide an
adequate seal for Devonian reservoirs (the well terminated in the Laurel Formation
thus Devonian accumulations remain untested); or trap timing possible occurs slightly
late relative to Devonian expulsion (Figure 9.14).

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 Chapter 9 – Discussion

The above analysis indicates that the reasons for failure at Kilang Kilang 1 are:

Absence for source rock charge in the Poole Sandstone because the
Noonkanbah Formation is immature;
Absence for source rock charge in the Grant Group because the Laurel
Formation is lean;
Timing is potentially an issue, where trap formation in the Triassic is slightly
too late to capture expulsion from mature Devonian source rocks;
Kilang Kilang 1 is not a true test of the structure as the well did not test the
crestal position.

9.3 Prospectivity within the Larapintine L2 Petroleum System (Ordovician

– Silurian)

The Larapintine L2 petroleum system is the oldest petroleum system within the study
area. Exploration prospectivity of the Larapintine L2 petroleum system within the
study area is difficult to assess because of limited data. In light of this lack of
exploration data, the L2 system must be considered high risk.

9.3.1 Source Rocks

As previously noted, there are no well tests of the Llanvirn (Early Ordovician)
Goldwyer Formation or Late Ordovician Bongabinni Member of the Carribuddy
Group which represent the candidate Ordovician source rocks.

Goldwyer Formation

The Goldwyer Formation comprises good average regional TOC (1.5%) and good
pyrolysis yields (averaging 4.06 kg HC/ton S1 and 4.11 kg HC/ton S2). Ultimate
genetic yield is good at 7.8 kg/ton. Van Krevalen diagrams indicate that the source
rock is type II oil prone, supporting a marine origin for organic matter. Geochemical
logs demonstrate good regional source rock coverage in the central Canning Basin. G.

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 Chapter 9 – Discussion

prisca, a marine algae, was found to be widespread and represents marine origin
throughout the formation (Chapter 7.4.7). The occurrence of G. prisca was found to
be more regionally occurring than reported in literature; which is encouraging.

Petroleum systems modelling indicates that the Goldwyer Formation in the Gregory
Sub-basin – the nearest province most likely to contain the organically rich marine
source rock (and similarly the Bongabinni Member) – becomes mature for oil in the
Early Silurian, gas mature in the Late Silurian, and over mature by the Late Devonian.
Rapid subsidence along the Stansmore Fault is attributed to rapid burial and
maturation. Modelling indicates complete kerogen conversion to petroleum (TR
reaches 100% in the Early Mississippian). Generation and expulsion occur from the
Silurian to the Mississippian, which indicates that Ordovician source rocks are
available to charge reservoirs between 436 Ma – 350 Ma.

The main problem with the Goldwyer Formation is facies variability from areas of
known source rock potential. Paleogeographic reconstructions (Figure 9.8) indicate
that the Goldwyer Formation is unlikely to occur in marine form in the project area.
Paleogeographic reconstructions indicate the source rock interval is likely to be
dominated by a sandstone time equivalent, rather than marine shale facies. The
marine environment may extend to distal portions of the Gregory Sub-basin, nearer
the Barbwire Terrace. The interpretation proposed here indicates long distance
migration would be required to transport petroleum from the Goldwyer Formation
into reservoirs within the study area.

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 Chapter 9 – Discussion

Figure 9.8. Palaeogeography of the Llanvirnian (Ordovician).

Bongabinni Member

The Bongabinni Member is organically rich and thermally mature for oil in the
Admiral Bay Fault Zone (Chapter 7.4.6). Elsewhere however, geochemical data
suggests the Member represents poor petroleum potential by TOC, and there are no
Pyrolysis measurements to derive generative yields. The member is not discounted
within the project area because there are no well tests.

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 Chapter 9 – Discussion

Paleogeographic reconstructions of Ordovician to Silurian time (discussed within

chapters 4.2 to 4.5) provide scope for the Bongabinni Member to exist with some
marine influence, but risk is still pronounced because well intersections of the
Bongabinni source rock are elusive near the study area to confirm organic richness of
the source rock.

9.3.2 Reservoir Rocks

Reservoir rocks belonging to the Larapintine L2 petroleum system include the

Ordovician Nita Formation carbonates or members of the Carribuddy Group (Figure
9.9)

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 Chapter 9 – Discussion

Figure 9.9. Stratigraphic column of Ordovician and Silurian aged rocks.

Reservoir property data for Ordovician rocks are scarce throughout the Canning Basin
(Chapter 4.2). In the event that hydrocarbons sourced from the Goldwyer Formation
are reservoired within the Goldwyer Formation (such as a self-sourcing
unconventional play), the Goldwyer Formation shows reservoir porosity averaging
1.7% in WMC Unit 4 and 1.5% average in WMC Unit 3. Permeability is tight at 0.01
mD to 0.3 mD. The Nita Formation is a sucrosic dolomite, which if not diagenetically
altered, can bear good reservoir properties. However, in the few well intersections in
the Canning Basin, porosity measurements averaged 0.85% and permeability data is
reported as nil.

Wireline log data and drill cuttings at Lake Havern 1 suggests that the likely reservoir
is either a sandstone or carbonate equivalent of the Goldwyer Formation or

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 Chapter 9 – Discussion

Carribuddy group. Sandstones would be preferable. If the Silurian Worral Formation

Elsa member is present across the Gregory sub-basin, its channel or aeolian sand
package also makes a favourable reservoir target.

Ordovician source rocks are still generative through to the Mississippian, which
therefore makes it possible to charge Devonian aged reservoirs (of the L3 and L4
petroleum system) in traps developed early during the Carboniferous Meda
Transpression. Early hydrocarbon emplacement is an important consideration because
generation and migration during deposition of the Devonian reservoirs (for example
the Knobby Sandstone) can lead to porosity preservation, as oil in pore space assists
in impeding diagenesis (Bloch et. al., 2002).

The options for Devonian reservoirs in the project area include the Devonian polymict
Conglomerate (averaging 10.3% porosity) or the Knobby Sandstone (averaging
20.6% porosity and 567 mD permeability). The Lennard River Group is present
however no reservoir property data are available. Evidently, the fluvial Knobby
Sandstone is the key candidate Devonian reservoir. Seismic interpretation indicates
that the unit is regionally mappable and the Knobby Sandstone demonstrates excellent
reservoir quality.

The availability of suitable reservoir rocks is not perceived as a problem for the
Larapintine L2 petroleum system. Paleogeographic reconstructions (Figure 9.8) infer
a favourable setting for reservoir development (nearby sand sedimentary source off
the northeastern basin margin combined with progradational sand development),
where several layers of stratigraphy appear suitable to harbour petroleum. Timing of
key reservoir development is mostly related to the development of Carribuddy Group
or Worral Formation sandstone packages between 452 Ma to 416 Ma, and the
Devonian Knobby Sandstone between approximately 374 Ma to 359 Ma.

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 Chapter 9 – Discussion

9.3.3 Seals

he sealing capacity te e th e difficult to quantify in the

absence of complete laboratory data (such as Mercury Injection Capillary Pressures,
MICP); so porosity, permeability, well logs and drill cuttings are used to make
inferences. The Mallowa Salt of the Carribuddy Group would be ideal; however
seismic interpretation does not infer its presence in the project area. The Nita
Formation is potentially a better sealing unit with nil permeability. Shale within the
Carribuddy Group (dolomitic claystone within the Nibil Member represented by a hot
and blocky gamma ray log response) offers another alternative.

In the event that Ordovician source rocks charge the Knobby Sandstone, the seal
would need to originate from the Carboniferous Laurel Formation. Although returned
well cuttings from the formation indicate fine-grained siliciclastic constituents
(siltstone and claystone), the Laurel Formation shale can be eroded under the Meda
Transpression Unconformity, particularly in the footwall of the Stansmore and
Mueller Faults. Paleogeographic reconstructions (Figure 9.13) indicate that the Laurel
Formation shale (if preserved) is more likely found to the southwest of the project
area in a basinal setting.

Timing of seal development is in relation to the deposition of the Nita Formation or

Carribuddy Formation shales (461 Ma to 443 Ma, though timing of dolomite
diagenesis is unknown), or a seal over the Devonian Knobby Sandstone (Laurel
Formation shales) between 359 Ma to 345 Ma.

9.3.4 Trap Development

The timing of trap development for Ordovician hydrocarbons is likely to be around

the Mississippian (360 Ma to 345 Ma), related to the Carboniferous Meda
Transpression. RB81-1 (Figure 6.6) and RB81-7 (Figure 6.5) demonstrates that the
Ordovician and Devonian sections are isopachus across the Billiluna Sub-basin, Balgo
Terrace and Betty Terrace, and show thickening into the Gregory Sub-basin due to

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syn-rifting in the Devonian. There are common thickness variations in the Fairfield
Group and Anderson Formation, and truncation due to the Meda Transpression
Unconformity. The Gregory Sub-basin RB81-7 pseudo well (Figure 9.10) illustrates
continual subsidence until the Mississippian (330 Ma). Tilted fault blocks in the
southwestern project area (RB82-28 modelled accumulations, Figure 8.46) likely
occur between syn-rifting in the Devonian and prior to Carboniferous exhumation.

Figure 9.10. Burial history diagram of the RB81-7 Gregory Sub-basin pseudo well.

9.3.5 Timing and Migration

Ordovician sourced hydrocarbons are required to migrate to Devonian reservoirs.

Although good reservoir potential exists within the project area, the migration
distance is variable based on the proximity of the source rock. Long distance
migration from kitchens near the Barbwire Terrace is feasible.

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Timing can present a critical issue for the prospectivity involving the Larapintine L2
petroleum system (Figure 9.11). No seals are available to cap the Ordovician or
Silurian reservoirs for a conventional play. This indicates that hydrocarbons that
generated when the Ordovician source rocks passed through the oil window likely
migrated out of the system. Ordovician source rocks would be required to be “self-
sealing” (for example a shale gas play). No traps developed until the Late Devonian
or Mississippian. Trap development likely occurred after the deposition of the
Knobby Sandstone reservoir. Ordovician source rocks were generating gas
hydrocarbon products at that time. Traps are available for filling over a 10 My period,
between 360 Ma to 350 Ma.

Figure 9.11. Petroleum system elements diagram for plays in the Larapintine L2 petroleum system.

9.3.6 Play-type Targeting, Risks and Remarks

Exploration prospectively concerning the Larapintine L2 petroleum system is

considered high risk. The following are some play type targets, risks and remarks
regarding future exploration.

Unconventional shale gas plays within the hanging wall block of the
Stansmore Fault are a suitable play-type, with the objective to intersect
basinal-type Goldwyer Formation or Bongabinni Member shale facies,

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Conventional gas accumulations in Devonian reservoirs (for example the

Knobby Sandstone) near or down-dip of the Stansmore Fault, maximizing
hydrocarbon migration exposure from the Gregory Sub-basin. A target
down-dip of the Stansmore Fault will maximize the chance of intersecting
a fine-grained Laurel Formation seal (Figure 9.12).
The Kilang Kilang 1 well location is an example of a suitable Larapintine
L2 prospect. Unfortunately, the Kilang Kilang 1 well did not drill deep
enough to test Devonian stratigraphy (Figure 9.7).
Paleogeographic reconstructions indicate that the Goldwyer Formation is
unlikely to be present in the study area as a marine shale source rock. A
sandstone dominated time equivalent is the likely lithotype within the
project area.
In any case, the accumulation will be a gas hydrocarbon product.
Devonian reservoirs were available for a relatively short time (374 Ma to
359 Ma) – towards the end of the Ordovician generative period, thus
reducing the exposure time for which reservoirs may be charged.
The Laurel Formation may be suitable as a seal because the formation
represents fine-grained components, however the shale-rich
lithostratigraphy may be restricted to basinal depocentres. Further, the
Laurel Formation shales may be eroded under the Meda Transpression
unconformity on terraces within the project area.
Preservation of accumulated hydrocarbons is a risk because of basin
activity in the Triassic. The Fitzroy Movement has been demonstrated to
destroy trap integrity.

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 Chapter 9 – Discussion

Figure 9.12. Play-type targets within the Larapintine L2 petroleum system.

9.3.7 Key recommendations

Some key recommendations to reduce exploration risk relating to the L2 petroleum

system are:

Undertake a study into suitable analogues to guide future exploration in

the Goldwyer Formation and Bongabinni Member Shales.
Obtain lab data to quantify sealing capacity of the Laurel Formation shales
and the Nita Formation Carbonates,

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Obtain further porosity and permeability measurements for Carribuddy

Group reservoirs to calibrate sonic derived porosity.

9.4 Prospectivity within the Larapintine L3 and L4 Petroleum Systems

(Devonian – early Carboniferous)

The Larapintine L3 and L4 petroleum system hosts stratigraphy that has proven to
contribute to hydrocarbon accumulations on the Lennard Shelf – a similar structural
position to the study area (tables 2.1 and 2.2). There are more options available to
explorers when targeting play types within the Larapintine L3 and L4 petroleum
system, however exploration within this system is also considered to be high risk.

9.4.1 Source Rocks

There are three candidate source rocks within the L3 and L4 petroleum systems, each
of which has demonstrated ability to produce hydrocarbons with varying generative
potential; the Devonian Gogo Formation, the Early Carboniferous Laurel Formation,
and the Carboniferous Anderson Formation.

Gogo Formation

The Devonian Gogo Formation, though attractive in description (a black

micromicaceous shale, represented by mid to high ranging blocky gamma ray
aggradational log patterns), has limited geochemical data to appraise it. TOC data
indicates very low organic content (averaging 0.14% TOC) and poor generative
potential (0.22 kg HC/ton S1, 0.26 kg HC/ton S2). Wulff (1987) advertises more
encouraging results at 1.25% average TOC (and 0.18 kg HC/ton S1 and 2.4 kg
HC/ton S2), which indicates fair to good generative potential.

The Gogo Formation is present within the project area at Selenops 1, confirming a
localised occurrence. Paleogeographic settings were not reconstructed specifically for
the source rock, however sedimentological interpretation (Chapter 4.5.5) indicates

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that the formation represents a deeper water basinal environment that preceded
deposition of the Knobby Sandstone (Figure 4.22; which illustrates the regressive
phase succeeding Gogo Formation deposition). Seismic mapping indicates that the
formation is present in the northwestern project area, and it is likely that the zone
extends to the south into the project area-proper. The formation is believed to source
the Blina Oil Field (Cadman, 1993; and Wulff, 1987).

Modelling indicates that the Gogo Formation is mature for oil within the project area.
The source rock has higher maturity within the Gregory Sub-basin than terraced areas,
where it enters the wet gas window by the Mississippian, and reaches the main oil
window on terraced areas at a similar time. At maximum maturity (200 Ma) the
Gregory Sub-basin sediments enter the dry gas window and the interval on the
terraces reach the late oil window. The Billiluna Sub-basin remains in the main oil
window at maximum maturity. Results indicate that the Gogo Formation is available
to charge reservoirs across two expulsion periods; between 344 Ma to 330 Ma and
between 255 Ma to 200 Ma.

Laurel Formation

The Early Carboniferous Laurel Formation (an interbedded siliciclastic package

containing a regional limestone member) is organically lean (averaging 0.46%) and
shows fair genetic potential (0.69 kg/ton genetic yield) within the study area, however
organic content is noted to increase basinward, towards the Gregory Sub-basin (where
TOC is ranked fair, 0.61%). Paleogeographic reconstructions (Figure 9.13)
demonstrate that the source rock is interpreted to increase in shale content away from
the limestone carbonate platform, in southwest and northwest directions. A key
conclusion from geochemical analysis is that the Laurel Formation increases in
organic contents down dip, in a basinal setting, thus hydrocarbon migration is
required to charge shelfal reservoirs.

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Figure 9.13. Palaeogeography of the early Carboniferous.

Modelling indicates that Laurel Formation is mature for oil in Gregory sub-basin by
the Triassic (240 Ma). Sediments on the Betty Terrace and Balgo Terrace reach the
early oil window at a similar time whilst the source rock in the Billiluna Sub-basin
remains immature. Results indicate that the Laurel Formation is available to charge
reservoirs between 220 Ma to 192 Ma.

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Anderson Formation

The Middle Carboniferous Anderson Formation (a package of interbedded

siliciclastics, divisible into 7 sub-units, where units C, E and G were investigated for
source rock potential) is organically lean. Geochemical analysis indicates the source
rock has low TOC (0.64%) and low genetic potential (averaging 0.32 kg HC/ton S1
and 1.74 kg HC/ton S2).

Modelling demonstrates that the Anderson Formation is mature for oil at peak
maturity (200 Ma) in the Gregory Sub-basin, and within the early oil window on the
Betty Terrace at a similar time. Transformation Ratios indicate that the source rock
largely converts to petroleum in the central project depocentre (near Bindi 1), but
kerogens elsewhere have low ratios of kerogen cracking to petroleum. Results
indicate that the Anderson Formation is generative in the Gregory Sub-basin in the
Triassic (between 235 Ma to 190 Ma). Expulsion is modelled to occur between 216
Ma to 192 Ma.

Petroleum systems modelling indicates that the central area depocentre (near Bindi 1)
performs as a source kitchen, which improves the prospectivity of the surrounding
terraces because lateral hydrocarbon migration is minimized. Plays that target oil in
the central study area should ideally focus on trapping geometries closest to the
central area depocentre in the first instance, or exploiting the preserved reservoir-and-
seal couplets within the Anderson Formation that are preserved near Bindi 1.

In almost all cases, hydrocarbon accumulations attributed to the L3 and L4 petroleum

system will be of an oil hydrocarbon product. The exception to this is the Gogo
Formation, where a gas hydrocarbon product would be expected.

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9.4.2 Reservoir Rocks

The candidate reservoir rocks within the Larapintine L3 and L4 petroleum system are
likely the Devonian Conglomerate, Devonian Virgin Hills Formation, Devonian
Knobby Sandstone, The Carboniferous Laurel Formation and the Carboniferous
Anderson Formation.

The Devonian aged polymict conglomerate is a package of boulder, cobble and

pebble clasts that represent alluvial fan apex deposits which likely trend into finer
grained fan-toe sandstones further into the project area. The conglomerate
demonstrates good quality reservoir potential within the project area. Sonic derived
porosities indicate up to 10.9% at Atrax 1 and up to 7.7% porosity at Selenops 1.

The Devonian Virgin Hills Formation is a siliciclastic sequence deposited in a

progradational near shore environment. Core data from Selenops 1 indicates good
porosity, ranging 3.7% to 10.5%. Core data indicates 0.25 mD to 1.2 mD of
permeability, which is tight.

The Late Devonian Knobby Sandstone is a key candidate reservoir within the
Larapintine L3 and L4 petroleum system. Seismic interpretation indicates that the unit
is regionally mappable. Core porosity data indicates that the Knobby Sandstone
demonstrates excellent reservoir quality. Ngalti 1 indicates core porosity in the 10%
to 20% range. The upper section averages 20.6% porosity. Permeability is excellent,
averaging 567 mD.

The Carboniferous Laurel Formation also represents a favourable candidate reservoir.

The Laurel Formation overlies the Knobby Sandstone and is regionally mappable on
seismic data. The formation shows excellent reservoir characteristics – the upper
section demonstrates 12.1% to 22% porosity and the lower siliciclastic zone
demonstrates 16.7% - 19.8% porosity. The carbonate member has no reservoir

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property data however its description as a fossiliferous limestone alludes to further

reservoir potential.

The Carboniferous Anderson Formation is the youngest candidate reservoir within the
Larapintine L3 and L4 petroleum system. The formation is a package of interbedded
siliciclastics divisible into 7 sub-units. Units A, B, D, and F represent the candidate
reservoir members, while units C, E and G show potential to act as sealing intervals
(for example reservoir and seal couplets, in addition to the source rock potential
described above). Reservoir quality is good; 6% to 11% porosity in unit A, 3% - 10%
in unit B and unit D, and 3% - 11% porosity in unit F. Geophysical logs (Figure 4.29)
illustrate the regionally correlatable character of the reservoir and seal pairs across the
project area. The main problem with the Anderson Formation is that large sections are
eroded by the Meda Transpression unconformity, discussed above.

The availability of suitable reservoir rocks is not deemed a problem for the
Larapintine L3 and L4 petroleum system. Paleogeographic reconstructions infer a
favourable setting for reservoir development throughout periods in the Devonian to
Carboniferous, where candidate reservoir zones align with periods of progradational
sediment deposition. Timing of key reservoir development is mostly related to the
deposition of the Devonian Conglomerate approximately between 390 Ma – 380 Ma,
the Knobby Sandstone between approximately 374 Ma – 359 Ma, the Laurel
Formation between 359 Ma – 345 Ma, and the Anderson Formation between 345 Ma
– 326 Ma.

9.4.3 Seals

Candidate seals are identified based on geophysical logs, porosity and permeability
measurements, and drill cuttings. Seals within the L3 and L4 petroleum system
includes the Devonian Bungle Gap Limestone, Shales in the Carboniferous Laurel
Formation and sub-units C, E and G of the Carboniferous Anderson Formation.

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The Devonian Bungle Gap Limestone is a thickly bedded arenaceous limestone that
overlies the Devonian Conglomerate reservoir. It has secondary calcite and fracture
fill, indicating impermeability. No laboratory data is available to validate the sealing
potential. The interval is inferred to be regionally present within the Near Top
Devonian seismic package, but is only confirmed in the northeastern project area at
Atrax 1.

The Carboniferous Laurel Formation is mainly considered a candidate reservoir

within the L3 and L4 petroleum system due to its good reservoir characteristics,
although it contains interbedded shale lithologies that may provide seal coverage over
the Devonian Knobby Sandstone. Reservoir property data (Table 4.3 and Figure 4.28)
indicates that seal potential is minimal (ranging 12.1% to 22% sonic porosity), and the
reliability of regional shale extent is probably limited, however will likely improve in
a basinal setting.

Anderson Formation sub-units C, E and G are the youngest candidate seals at the top
of the L3 and L4 petroleum system, providing coverage over the Laurel Formation
reservoir. Unit C (a massively bedded siltstone and non-fissile claystone), unit E (a
massively bedded claystone), and unit G (an interbedded claystone and sandstone
sequence) appear suitably impermeable. Figure 4.29 and Figure 4.46 illustrate the
regional correlation of the Anderson Formation sub-units and demonstrate zone
potential as a package of reservoir and seal couplets. The persistent issue with the
Anderson Formation (this time concerning its seal potential) is that large sections are
eroded, and its ability to regionally seal the below reservoir units limited to hanging
wall blocks of large listric faults, or surrounding the Bindi 1 well (Figure 6.22).

Timing of seal availability relates to the deposition of the Bungle Gap Limestone
(approximately 397 Ma – 391 Ma), Laurel Formation (349 Ma – 345 Ma) and
Anderson Formation (345 Ma – 326 Ma).

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 Chapter 9 – Discussion

9.4.4 Trap Development

Trap development for hydrocarbons generated in the Larapintine L3 and L4

petroleum system is similar to that of the L2 system; likely to be around the
Mississippian (360 Ma to 345 Ma), related to the Carboniferous Meda Transpression.
The Gregory Sub-basin RB81-7 pseudo well (Figure 9.10) illustrates continual
subsidence until the Mississippian (330 Ma).

The timing of trap development is likely between the Late Devonian and immediately
prior to Meda Transpression erosion. This indicates that the timing of initial trap
development is relatively low risk as most Carboniferous and Devonian sediments
reach optimal maturity in the Triassic (after traps are in place), however, the Triassic
aged Fitzroy Movement created a structural overprint that imposes a significant threat
to trap integrity of Carboniferous aged structures.

9.4.5 Timing and Migration

Hydrocarbons generated from the Anderson Formation are mature for oil in the
Gregory Sub-basin and reach the early oil window at maximum maturity on terraced
areas, indicating that hydrocarbons require long distance lateral migration from areas
such as hanging wall blocks of the Stansmore Fault, or from the central area
depocentre near Bindi 1.

Although Carboniferous sediments on the Betty Terrace and Balgo Terrace are within
the oil window, long distance lateral migration is still a requirement because source
rocks are organically lean within the project area.

Timing is considered favourable for the evolution of L3 and L4 petroleum system

elements and processes. Figure 9.14 illustrates that in all cases; optimal maturity,
generation and expulsion occur after reservoirs, seals and traps have developed.

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Figure 9.14. Petroleum system elements diagram for plays within the Larapintine L3 and L4 petroleum
system.

A petroleum system element diagram (Figure 9.14) summaries that reservoirs and
seals develop through the Devonian and Carboniferous. Trap development occurs
during reservoir and seal development. No hydrocarbons have charged reservoirs at
this time. The first period of charge (Devonian) occurs after all reservoirs are
available, and occurs after traps have formed. The second (main) period of charge
(Triassic) occurs after all reservoir, seal and traps develop.

9.4.6 Simulated Accumulations – 2D Model RB82-28

Figure 9.15 illustrates an accumulation analysis of 7 hypothetical oil accumulations in

the Devonian Knobby Sandstone within a series of tilted fault blocks. This large
apparent structure has not been tested by exploration drilling, and is the largest
undrilled structure within the project area (Trap ‘A’, Figure 6.10). Although the
hypothetical volume should not be taken as correct, the model demonstrates the
favourable evolution of the Larapintine L3 and L4 petroleum system. The
accumulations are simulated to be sealed by the Fairfield Group. Keep in mind that
the interbedded shales are averaged (smoothed) in the model (Chapter 8.54), so
further stages of vertical migration may be possible.

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 Chapter 9 – Discussion

Migration vectors indicate liquid phase hydrocarbon flow. Vectors are relics rather
than indicative of present day migration (note the Ordovician stratigraphy is not
within the present day oil window!). Vectors indicate fluid escape along faults
migrating into younger stratigraphy. Note that faulting in the Grant Group may
continue shallower but is below seismic resolution to define. Triassic and younger
regional events may facilitate trap breaches and hence hint at the inherent risk of
leakage.

380
SW NE

Grant Group

Anderson Formatio

Fairfield Group

Siluro-Devonian

Ordovician

Figure 9.15. 2D model RB82-28 simulating eight large oil accumulations within the study area.
 Chapter 9 – Discussion

9.4.7 Play-type Targeting, Risks and Remarks

The Anderson Formation has been eroded from large portions of the project area, and thus its
ability to fulfil the role of reservoir, seal and source rock is limited. Prospectivity within the
Anderson Formation is restricted to hanging wall blocks of large listric faults (such as the
Stansmore Fault) or in the central project area depocentre, near Bindi 1 – where modelling
often indicates increased maturity of Devonian and Carboniferous source rocks (Table 8.10)
due to deeper burial.

Due to the interbedded nature of the Anderson Formation, and its characteristics as a
generative source rock, porous reservoir rock, and zones of sealing potential; a play on
the Anderson Formation could be self-generative and self-sealing where large
proportions of the formation are preserved.
Plays within the Laurel Formation should focus on areas within the hanging wall
blocks of large listric faults to encourage preservation of the overlying seal, and also
reduce the lateral migration distances required to charge reservoirs. A basinal setting
will likely promote organic rich shale deposition.
The Laurel Formation shales, although suitable as a seal, may be restricted to basinal
depocentres. Further, the Laurel Formation shales may be eroded under the Meda
Transpression unconformity on terraces within the project area.
The Devonian Conglomerate is confirmed to exist as a suitable reservoir. Plays should
target the fan-toe sandstone equivalent reservoirs towards the central basin depocentre
(near Bindi 1). This will reduce lateral migration distances from a basinal Gogo
Formation organic rich source rock.
Considering the Anderson Formation and Laurel Formation play types (above), an
unconventional basin-centered accumulation may be prospective in the central area
depocentre (Figure 9.16). Further, an analogue play type may be present in the
southeast project area in the hanging wall block of the Stansmore Fault, where a
thicker preserved section of the Anderson Formation and Laurel Formation is
anticipated.
The largest structure within the project area (Trap A, Figure 6.10 and Figure 9.15)
remains undrilled. The Knobby Sandstone is confirmed to exist at a suitable reservoir.
Risk over this trap relates to hydrocarbon migration from organically rich source

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rocks, and coverage by a Laurel Formation seal. The prospect warrants further
investigation.
Preservation of accumulated hydrocarbons is a risk. Basin activity in the Triassic may
destroy trap integrity.
Hydrocarbon leakage is a potential risk. The Fitzroy Movement is perceived as the
greatest relative risk to trap integrity and hydrocarbon preservation. Any trap breaches
would be likely at a similar time to hydrocarbon generation and migration, thus it’s
also possible that hydrocarbon charge continues after trap breach and therefore
continual reservoir charge mitigates this risk.

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Figure 9.16. Play-type targets within the Larapintine L3 and L4 petroleum system.

9.4.8 Key recommendations

The key recommendations to reduce risk in exploration for L3 and L4 petroleum system
related hydrocarbon plays are:

Acquire vitrinite reflectance data from the Lake Betty 1 well location to calibrate 1D
models. Similarly, undertake a sample in-fill program for vitrinite data across well
locations in the study area. Some more VR would be useful at Ngalti 1 and Bindi 1;

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Acquire Apatite Fission Track Analysis (AFTA) at 2 to 3 well locations within the
project area, for example at Bindi 1, Ngalti 1 and Olios 1, to assist in calibrating basin
models and thermal histories. This will aid in a better understanding of the thermal
maturity of the northeast Canning Basin, and will assist in reconciling exhumation
estimated at White Hills 1 to the project area;
Obtain porosity and permeability data to calibrate sonic derived porosity within the
Laurel Formation;
Perform a thorough depth conversion of the seismic interpretation to attain a better
understanding of depth-structures;
Enhance the fault interpretation across the seismic grid with attention to correlating
smaller scale faults;
Enhance the current 2D models by interpreting further seismic horizons to better
reflect the lateral correlation of the Gogo Formation and Goldwyer Formation
isopachs. This will provide a better assessment of accumulation analysis in the RB82-
28 2D model.
Enhance the current 2D models by exploiting the use of facies maps (including heat
flow and TOC) to accommodate the lateral special variability in formations between
wells. For example, TOC can be varied between wells indicated by percentage
composition of shale lithologies. This will improve the conceptual accuracy of
models.
Undertake a study into a suitable analogue to guide future exploration.

9.5 Prospectivity within the Gondwannan G1 and G2 Petroleum System (late

Carboniferous – Permian)

The Gondwannan G1 and G2 petroleum system is the shallowest system in the project area.
Exploration prospectivity of the Gondwannan G2 petroleum system is considered to be high
risk.

9.5.1 Source Rocks

The candidate source rock within the Gondwannan G1 and G2 petroleum system is the
Noonkanbah Formation, however petroleum reservoired within the Grant Group has been

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identified to have generated from the deeper Laurel Formation (Table 2.2) due to immaturity
and low genetic potential of Noonkanbah Formation sediments.

Noonkanbah Formation

The Early Permian Noonkanbah Formation (a marginal marine to marine shale interbedded
with siltstone) has good to very good organic contents (2.17% TOC regionally and 1.69%
TOC in the project area). Despite favourable TOC, the formation shows poor genetic yields
(0.11 kg HC/ton S1, 1.09 kg HC/ton S2). Kerogen typing shows that the formation is also
likely inert – representing a type III to type IV kerogen.

Modelling indicates that the Noonkanbah Formation reaches peak maturity in the Late
Triassic (200 Ma). The formation reaches the early oil window in the Gregory Sub-basin,
though remains immature on the Betty Terrace, Balgo Terrace and Billiluna Sub-basin at
peak maturity. The source rock shows very low transformation ratios well below the 50%
threshold required for generation (showing a maximum 4% TR), thus it does produce
petroleum to charge reservoirs within the project area, and migration is required from a
deeper structural setting.

Laurel Formation

Although a member of the Larapintine L3 and L4 petroleum system, the effective source rock
for plays in late Carboniferous to Permian stratigraphy is the Carboniferous Laurel Formation
– a clastic and carbonate sequence. As discussed in above, the Laurel Formation is available
to charge reservoirs between 220 Ma to 192 Ma. Vertical hydrocarbon migration through the
Anderson Formation (where preserved) is required to charge Gondwannan G1 and G2
reservoirs.

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 Chapter 9 – Discussion

9.5.2 Reservoir Rocks

The Late Carboniferous to Early Permian Grant Group (Grant Group members A and C), the
Permian Poole Sandstone and Permian Liveringa Group are the candidate reservoir rocks of
the G1 and G2 petroleum system.

The Late Carboniferous Grant Group member A (a medium to coarse grained sandstone)
represents excellent reservoir quality, with 18.5% core porosity (Atrax 1) and 754 mD to
1015 mD permeability. Sonic derived porosities at Bindi 1, Kilang Kilang 1 and Olios 1 also
demonstrate excellent reservoir quality, ranging 7 % up to 26%. Grant Group member C (an
interbedded siliciclastic sequence) also displays excellent reservoir properties, showing an
average sonic porosity of 13% at Bindi 1, up to 20% at Kilang Kilang 1 and up to 37% at
Olios 1.

The Permian Poole Sandstone (a medium to coarse grained sandstone) deposited in a shallow
marine to marginal marine paleogeographic environment (Figure 9.18) demonstrates
excellent reservoir quality, with in excess of 20% sonic derived porosity across the project
area (Table 4.7).

The Permian Liveringa Group Condren Sandstone (a coarse grained sandstone) and
Lightjack Formation (an interbedded fine grained siliciclastic sequence) show good reservoir
potential, however the upper Condren Sandstone is proposed as the main reservoir unit of the
Liveringa Group, based on a cleaner gamma ray log relative to the Lightjack Formation.
Sonic derived porosities at Kilang Kilang 1 show excellent reservoir characteristics, in excess
of 21% porosity.

The availability of suitable reservoir rocks is not deemed problematic for the G1 and G2
petroleum system. Paleogeographic reconstructions infer a favourable setting for reservoir
development throughout periods in the late Carboniferous to Permian, where candidate
reservoir zones align with periods of low stand systems and progradational sediment

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deposition (Figure 9.17 and Figure 9.18). Timing of key reservoir development is mostly
related to the deposition of the Late Carboniferous Grant Group A member between 326 Ma
to 303 Ma, the Grant Group C member between 299 Ma to 294 Ma, Poole Sandstone between
approximately 294 Ma to 284 Ma, and the Liveringa Group between 265 Ma to 253 Ma.

Figure 9.17. Palaeogeography of the mid to late Carboniferous.

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 Chapter 9 – Discussion

Figure 9.18. Palaeogeography of the early Permian.

9.5.3 Seals

Candidate seals within the G1 and G2 petroleum system includes the Late Carboniferous
Grant Group B member and the Permian Noonkanbah Formation. The Triassic Blina Shale is

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noted to occur at Bindi 1 and Lake Betty 1, however its regional extent is unknown. The
Blina Shale may act as a potential seal within the project area.

The Late Carboniferous Grant Group B member (a fine grained siliciclastic interval) provides
an ‘intra-Grant Group seal’. Correlation of the B member across the study area (Figure 4.32,
and figures 4.44 through 4.46) demonstrates that the seal is regional. Sonic derived porosity
data indicates that the seal may be ineffective to hold back large hydrocarbon columns (sonic
porosities up to 20% are observed at Kilang Kilang 1), however core calibrated data is not
available. Based on the regional extent and lithological character, the Grant Group B member
is considered capable to seal hydrocarbons.

The Permian Noonkanbah Formation is regionally extensive across the project area from well
and seismic correlations. As per the Grant Group B member, core calibrated data is not
available, however based on the regional extent and lithological character, the interval is
considered capable to seal hydrocarbons.

Timing of seal availability relates to the deposition of the Late Carboniferous Grant Group B
member (approximately 303 Ma to 299 Ma) and the Permian Noonkanbah Formation (284
Ma to 275 Ma).

9.5.4 Trap Development

Trap development for hydrocarbons generated in the Gondwannan G1 and G2 petroleum

system is likely as a result of the Triassic Fitzroy Movement. Seismic evidence of structures
that developed during the Triassic is limited. Shallow faulting is difficult to discern on
seismic due to poor near-surface imaging. For example, the broad anticline on line RB81-7,
(SP250, Figure 6.5) appears contiguous through most stratigraphy; the TWT surface on the
regional Meda Transpression unconformity, Grant Group, Poole Sandstone, Noonkanbah
Formation, and shallow reflection packages shows broad folding. The structure may have

390
 Chapter 9 – Discussion

initially developed in the Carboniferous but takes its present day geometry from the Triassic
Fitzroy Movement (for example Lawford 1).

The RB82-28 pseudo well on the Betty Terrace (Figure 9.19) indicates uplift in the Triassic,
which supports a regional structural episode at the time, supported by AFTA (Duddy et al,
2003), and indicates the timing of the Triassic Fitzroy Movement to occur between
approximately 200 Ma to 181 Ma.

This indicates that trap development occurred at a similar time to sediments reaching
maximum maturity in the project area.

Figure 9.19. Burial history diagram of the RB82-28 Betty Terrace pseudo well.

391
 Chapter 9 – Discussion

9.5.5 Timing and Migration

The Noonkanbah Formation does not expel hydrocarbons because it is immature within the
project area. Within the study area the Noonkanbah Formation contributes to the G1 and G2
petroleum system as a regional seal over the Poole Sandstone and Grant Group sediments.
Hydrocarbons generated from the Laurel Formation are expected to migrate from areas of
deeper burial and higher organic richness (i.e. the Gregory Sub-basin), as Permian sediments
on the terraces are largely immature (or early oil mature at peak maturity).

Figure 9.20. Critical moment diagram for plays within the Gondwannan G1 and G2 petroleum system.

Timing is potentially restrictive for accumulations within the G1 and G2 petroleum system.
Figure 9.20 illustrates that reservoirs develop in the Late Carboniferous and Permian. Seals
develop in the Late Carboniferous and Late Permian. Unless the Triassic Blina Shale is
present, there is no seal for the Liveringa Group reservoir. Expulsion from the mature Laurel
Formation occurs in the Triassic. Trap development occurs at the later stages of expulsion,
with overlap across a narrow 8 My period between 200 Ma to 192 Ma.

9.5.6 Play-type targeting, risks and remarks

The Laurel Formation source rock matures to the oil window in the Gregory Sub-basin.
Lateral migration is required to charge reservoirs. In any case, the accumulation will likely be

392
 Chapter 9 – Discussion

an oil hydrocarbon product, unless hydrocarbons from deeper systems migrate vertically to
shallower targets at the G1 and G2 level.

Thermal maturity is a risk for the Gondwannan G1 and G2 petroleum system, with only the
Laurel Formation maturing to the oil window, and only within the Gregory Sub-basin.

Hydrocarbon leakage is a potential risk. This would be due to more recent (Jurassic and
Cretaceous) periods of basin activity, highlighted by Duddy et al (2003). Any reactivation on
faults in the Jurassic is perceived as the greatest relative risk to trap integrity and hydrocarbon
preservation in the G1 and G2 petroleum system.

Explorers should target migrated accumulations into late Triassic trapping configurations,
within the Grant Group or Poole Sandstone (to intersect Grant Group B member or
Noonkanbah Formation seal) on the Betty and Balgo Terraces. Traps should ideally be sought
close to basinal positions (either near Bindi 1 or near the Gregory Sub-basin proper) to
minimize migration distances (Figure 9.21), however a migration study is recommended to
contemplate multi-phase hydrocarbon migration to traps nearer to the northeastern basin
margin. The migration study should model geological history reconstructions to the late
Triassic and consider any Jurassic reconfigurations.

393
 Chapter 9 – Discussion

Figure 9.21. Play-type targets within the Gondwannan G1 and G2 petroleum system.

9.5.7 Key Recommendations

The key recommendations to reduce risk in exploration for G1 and G2 related hydrocarbon
plays are:

Similar to the L3 and L4 system; acquire vitrinite reflectance data from the Lake
Betty 1 well location to calibrate 1D models. Similarly, undertake a sample in-fill
program for vitrinite data across wells locations in the study area.
Acquire Apatite Fission Track Analysis (AFTA) at 2 to 3 well locations within the
project area to assist in calibrating basin models and thermal histories.

394
 Chapter 9 – Discussion

Obtain porosity and permeability data to calibrate sonic derived porosity within the
Grant Group and Poole Sandstone;
Perform a thorough depth conversion of the seismic interpretation to attain a better
understanding of depth-structures. This is particularly important for shallower
stratigraphy as currently no significant structures appear in TWT, with the exception
of the Kilang Kilang 1 structural closure (for example, the Near Top Poole Sandstone,
Figure 6.13);
Enhance the fault interpretation across the seismic grid with attention to correlating
smaller scale faults in shallow stratigraphy;
Enhance the current 2D models by exploiting the use of facies maps (including heat
flow and TOC) to accommodate the lateral special variability in formations between
wells. For example, TOC can be varied between wells indicated by percentage
composition of shale lithologies. This will improve the conceptual accuracy of the
models.

395
 Chapter 10 – Conclusions and Recommendations

10. Conclusions and Recommendations

10.1 Conclusions

This study evaluated the petroleum systems on the Betty Terrace, Balgo Terrace and within
the Billiluna Sub-basin in the northeast Canning Basin. The following conclusions can be
drawn from this study:

Reservoir Rocks

. Excellent reservoir conditions exist for the Devonian Knobby Sandstone and Permo-
Carboniferous Grant Group (member A).
. The Carboniferous Anderson Formation (units B, D, and F), the upper clastic zone of the
Carboniferous Laurel Formation, the Grant Group (members B and C), and the Permian
Poole Sandstone show excellent reservoir potential.
. 2D Seismic indicates that there are numerous undrilled prospects within the project area.

Seal Rocks

4. There appears to be good sealing capacity in the lower Laurel Formation shales (indicated
in the Lake Betty 1 well).
5. The Carboniferous Anderson Formation (units A, C, E, and G) show potential as
intraformational seals (indicated in the Bindi 1 well).
6. The Permian Noonkanbah Formation represents good sealing potential. The formation
signifies the maximum Permian transgression in the Canning Basin.

Source Rocks and Thermal Maturity

7. The Noonkanbah Formation is organically rich, but modelling indicates it is immature

within the project area.
8. The Anderson Formation is organically lean, but modelling indicates it is mature for oil in
the Gregory Sub-basin and immature on the terraced areas within the project area.

396
 Chapter 10 – Conclusions and Recommendations

9. The Laurel Formation is organically lean on the Betty and Balgo Terraces, though
appears more organically rich in basinal positions. Modelling indicates that the formation
is mature for oil within the Gregory Sub-basin and early mature for oil on the terraced
areas. Exploration at this level should focus on migrating hydrocarbons from basinal
positions to shelfal reservoirs.
10. Modelling indicates that the Gogo Formation is mature for oil on terraced areas and
mature for gas in the Gregory Sub-basin. Geochemical data indicates that the Gogo
Formation has lean generative potential, however data is sparse.
11. The Bongabinni Member geochemical data suggests the member is a lean source rock but
published literature advertises otherwise. Data is limited, so the source rock potential is
not discounted at this stage. Modelling indicates that the Bongabinni Member is mature
for gas on terraces and over mature in the Gregory Sub-basin.
12. The highly proclaimed organically rich Goldwyer Formation shales are unlikely to be
present within the project area due to an unfavourable paleogeographic setting. The
Goldwyer formation is likely to exist as a proximal sand-rich facies equivalent within the
study area. The formation, should it be found in future to be present within the study area;
is mature for gas on the terraced areas and over mature in the Gregory Sub-basin
according to modelling undertaken in this project.
13. 1D and 2D modelling, supported by AFTA (Duddy et al., 2003), indicates sediments
obtain maximum maturity in the Late Triassic (200 Ma).
14. Peak maturity is pushed forward from the Carboniferous to the Triassic. The Triassic
generative phase gives some hope to hydrocarbon charge into Carboniferous and Triassic
structures, thus enhancing the prospectivity.
15. 1D and 2D modelling indicates that all source rocks (except the Permian Noonkanbah
Formation) appear to have generated hydrocarbons at some point within the Gregory Sub-
basin and terraced areas.
16. 2D modelling indicates thermal maturity regionally increases in a southwest direction
towards the Gregory Sub-basin, which is a source kitchen.
17. Seismic indicates the development of a central area depocentre surrounding the Bindi 1
well location. This is considered to be an extension of the Gregory Sub-basin source
kitchen, thus improving prospectivity within the project area. Hydrocarbons generated in
the Gregory Sub-basin therefore require less lateral migration than what was previously
indicated by published literature.

397
 Chapter 10 – Conclusions and Recommendations

18. The central area depocentre facilitates a slight a revision to the tectonic elements map,
which allows for the Gregory Sub-basin source kitchen to extend northeast.
19. 2D modelling indicates favourable petroleum system evolution over a large undrilled
structural closure in the southern project area, which warrants further investigation.

Prospectivity:

20. The Gondwannan G1 and G2 petroleum system is unlikely to be prospective within the
project area. Prospectivity may exist where the Noonkanbah Formation can be found in a
thermally mature setting. A migration study will enable consideration of accumulations
resulting from multiple stage hydrocarbon migration to traps nearer the basin margin.
21. The Larapintine L3 and L4 petroleum system is proven to contain the most options for
explorers in the study area. Prospectivity is enhanced by AFTA data (Duddy et al., 2013)
and a thorough understanding of thermal maturity. Devonian and Carboniferous aged
reservoirs are the most highly prospective. Exploration should focus on migrating
petroleum from thermally mature areas to traps near the central area depocentre or on
terraced positions near the Gregory Sub-basin. A Migration study should be undertaken to
minimize risk.
22. The Larapintine L2 petroleum system is untested within the project area, but appears
prospective. Perhaps, the simplest way to assess this petroleum system is to undertake a
basic narrow-diameter core-hole drilling program to test Ordovician source rock organic
richness where allowable within drillable depths. Prospectivity may exist within the
Billiluna Sub-basin, which is currently untested.
23. The Billiluna Sub-basin has not been tested by exploration drilling, and there is little
validation of subsurface stratigraphy in data at hand. A narrow-diameter drilling program
within the Billiluna Sub-basin will confirm the nature of stratigraphy across the Billiluna
horst block.

398
 Chapter 10 – Conclusions and Recommendations

10.2 Recommendations:

The key recommendations that can be made after concluding this study are summarised as
follows.

Lab Data Acquisition:

1. Obtain lab data (i.e. Mercury Injection Capillary Pressure, MICP) to quantify sealing
capacity of the Laurel Formation shales and the Nita Formation Carbonates;
2. Obtain further porosity and permeability measurements for the Grant Group, Laurel
Formation and Carribuddy Group reservoirs to calibrate sonic derived porosity;
3. Undertake a sample in-fill program for Vitrinite Reflectance data across well locations in
the study area. More VR would be useful at Ngalti 1, Lake Betty 1 and Bindi 1;
4. Acquire Apatite Fission Track Analysis (AFTA) at 2 to 3 well locations within the project
area; for example at Bindi 1, Ngalti 1 and Olios 1, to assist in calibrating basin models
and thermal histories, and also further reconcile exhumation estimated at White Hills 1 to
the project area.

Seismic Interpretation:

5. Perform a thorough depth conversion of the seismic interpretation to attain a better

understanding of depth-structures. This is particularly important for shallower
stratigraphy as currently no significant structures appear in TWT;
6. Enhance the fault interpretation across the seismic grid with attention to correlating
smaller scale faults. This will aid in understanding hydrocarbon migration;
7. Ideally, reprocess the key internal loop tie lines (Figure 3.4) with the same reprocessing
house to ensure correct phase and bulk shifts are applied.

Modelling:

8. Enhance the current 2D models by interpreting further seismic horizons to better reflect
the lateral correlation of the Gogo Formation and Goldwyer Formation isopachs. This
will provide a better assessment of accumulation analysis in the RB82-28 2D model.

399
 Chapter 10 – Conclusions and Recommendations

9. Enhance the current 2D models by exploiting the use of facies maps (including heat flow
and TOC) to accommodate the lateral variability in formations between wells. For
example, TOC can be varied between wells by indicating a percentage composition of
shale lithologies. This will improve the conceptual accuracy of the 2D models.

Drilling:

10. In the correct economic environment, drilling further exploratory wells are the key to
understanding the petroleum systems in the northeastern Canning Basin. The largest
apparent structure in the study area remains undrilled (Trap A, Figure 6.10). Petroleum
systems modelling (RB82-28, Figure 8.46) indicates that Trap A has the potential to
accumulate significant hydrocarbon volumes.

400
 References

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409
 Appendix A

Appendix A

Reservoir Property Data

Porosity and permeability measurements from open file well completion reports and a
database constructed by the Geological Survey of Western Australia was utilised in this
study. These data are included in this Appendix.

410
Formation Well Type Depth (mRT) Porosity % Vert. Porosity % Permeability mD Vert. Permeability mD
Bungle Gap Limestone Atrax 1 Sonic 603 6.5
Bungle Gap Limestone Atrax 1 Sonic 621 6.5
Bungle Gap Limestone Atrax 1 Core 627.2 2.7 0.1
Bungle Gap Limestone Atrax 1 Core 632.05 2.9 0.1
Bungle Gap Limestone Atrax 1 Core 640.9 4.2 0.1
Bungle Gap Limestone Atrax 1 Sonic 650.5 3.5
Goldwyer Formation WMC 3 Percival 1 Core 2050.98 1.2
Goldwyer Formation WMC 3 Percival 1 Core 2050.98 1.2
Goldwyer Formation WMC 3 Percival 1 Core 2053.45 0.8 0.02
Goldwyer Formation WMC 3 Percival 1 Core 2053.45 0.8 0.02
Goldwyer Formation WMC 3 Percival 1 Core 2053.45 0.8 0.02
Goldwyer Formation WMC 3 Percival 1 Core 2060.17 2.3
Goldwyer Formation WMC 3 Percival 1 Core 2060.17 2.3
Goldwyer Formation WMC 3 Percival 1 Core 2060.17 2.3
Goldwyer Formation WMC 3 Percival 1 Core 2063.4 1.2 0.3
Goldwyer Formation WMC 3 Percival 1 Core 2063.4 1.2 0.3
Goldwyer Formation WMC 3 Percival 1 Core 2064.18 1.9
Goldwyer Formation WMC 3 Percival 1 Core 2064.18 1.9
Goldwyer Formation WMC 3 Percival 1 Core 2064.18 1.9
Goldwyer Formation WMC 4 Percival 1 Core 2041.13 1.2
Goldwyer Formation WMC 4 Percival 1 Core 2041.13 1.2
Goldwyer Formation WMC 4 Percival 1 Core 2041.13 1.2
Goldwyer Formation WMC 4 Percival 1 Core 2043.9 1.8
Goldwyer Formation WMC 4 Percival 1 Core 2043.9 1.8
Goldwyer Formation WMC 4 Percival 1 Core 2044.04 2
Goldwyer Formation WMC 4 Percival 1 Core 2044.04 2
Goldwyer Formation WMC 4 Percival 1 Core 2044.12 2.4 0.01
Goldwyer Formation WMC 4 Percival 1 Core 2044.12 2.4 0.01
Goldwyer Formation WMC 4 Percival 1 Core 2044.12 2.4 0.01
Goldwyer Formation WMC 4 Percival 1 Core 2045.58 1.3
Goldwyer Formation WMC 4 Percival 1 Core 2045.58 1.3
Goldwyer Formation WMC 4 Percival 1 Core 2045.58 1.3
Grant Group Ngalti 1 Sonic 280 13-40
Grant Group A Atrax 1 Sonic 521 22
Grant Group A Atrax 1 Sonic 541.5 26.5
Grant Group A Atrax 1 Sonic 551 20.5
Grant Group A Atrax 1 Sonic 572 17
Grant Group A Atrax 1 Sonic 582 17
Grant Group A Atrax 1 Core 583.4 18 754
Grant Group A Atrax 1 Core 585.6 18.5 1015
Grant Group A Olios 1 Sonic 698.5 16.2
Grant Group A Olios 1 Sonic 727.5 23.6
Grant Group A Olios 1 Sonic 736 21.3
Grant Group A Olios 1 Sonic 769 23.9
Grant Group A Olios 1 Sonic 780 26
Grant Group A Olios 1 Sonic 784.5 22.8
Grant Group A Olios 1 Sonic 795 24.5
Grant Group B Atrax 1 Sonic 455 26
Grant Group B Selenops 1 Sonic 362.5 22
Grant Group B Selenops 1 Sonic 377.5 29
Grant Group B Selenops 1 Sonic 395 24
Grant Group B Selenops 1 Sonic 415 26
Grant Group B Selenops 1 Sonic 436 22
Grant Group C Olios 1 Sonic 310 31.5
Grant Group C Olios 1 Sonic 326 31
Grant Group C Olios 1 Sonic 350 27.5
Grant Group C Olios 1 Sonic 411 33.3
Grant Group C Olios 1 Sonic 426 36.7
Grant Group C Olios 1 Sonic 436.5 34.1
Grant Group C Olios 1 Sonic 448 34.9
Grant Group C Olios 1 Sonic 473 33.4
Grant Group C Olios 1 Sonic 492 30.7
Grant Group C Olios 1 Sonic 499.5 26.3
Knobby Sandstone Ngalti 1 Core 1067.1 20 238
Knobby Sandstone Ngalti 1 Core 1067.15 8.3
Knobby Sandstone Ngalti 1 Core 1067.4 19.4 195
Knobby Sandstone Ngalti 1 Core 1067.7 22 386
Knobby Sandstone Ngalti 1 Core 1067.75 5.5
Knobby Sandstone Ngalti 1 Core 1068 22.3 460
Knobby Sandstone Ngalti 1 Core 1068.3 19 476
Knobby Sandstone Ngalti 1 Core 1068.4 794
Knobby Sandstone Ngalti 1 Core 1068.6 18.6 685
Knobby Sandstone Ngalti 1 Core 1068.9 18.9 326
Knobby Sandstone Ngalti 1 Core 1069.1 818
Knobby Sandstone Ngalti 1 Core 1069.25 20.5 512
Knobby Sandstone Ngalti 1 Core 1069.6 22.3 870
Knobby Sandstone Ngalti 1 Core 1069.6 332
Knobby Sandstone Ngalti 1 Core 1069.9 18.8 262
Knobby Sandstone Ngalti 1 Core 1070.2 22.7 870
Knobby Sandstone Ngalti 1 Core 1070.3 69
Knobby Sandstone Ngalti 1 Core 1070.45 22.6 830
Knobby Sandstone Ngalti 1 Core 1070.7 22.3 527
Knobby Sandstone Ngalti 1 Core 1070.9 442
Knobby Sandstone Ngalti 1 Core 1071.1 18.1 316
Knobby Sandstone Ngalti 1 Core 1071.4 22.6 668
Knobby Sandstone Ngalti 1 Core 1071.4 242
Knobby Sandstone Ngalti 1 Core 1071.7 19.7 368
Knobby Sandstone Ngalti 1 Core 1072 22.9 979
Knobby Sandstone Ngalti 1 Core 1072.1 565
Knobby Sandstone Ngalti 1 Core 1072.3 21.9 314
Knobby Sandstone Ngalti 1 Core 1072.56 22.6 589
Knobby Sandstone Ngalti 1 Core 1072.6 125
Knobby Sandstone Ngalti 1 Core 1072.9 21.1 870
Knobby Sandstone Ngalti 1 Core 1073.2 19.4 356
Knobby Sandstone Ngalti 1 Core 1073.25 208
Knobby Sandstone Ngalti 1 Core 1073.5 20.8 553
Knobby Sandstone Ngalti 1 Core 1073.76 22 721
Knobby Sandstone Ngalti 1 Core 1073.8 320
Knobby Sandstone Ngalti 1 Core 1074.08 21 623
Knobby Sandstone Ngalti 1 Core 1074.3 309
Knobby Sandstone Ngalti 1 Core 1074.4 17.5 397
Knobby Sandstone Ngalti 1 Core 1074.75 21 532
Knobby Sandstone Ngalti 1 Core 1075 527
Knobby Sandstone Ngalti 1 Core 1075.1 20.6 623
Knobby Sandstone Ngalti 1 Core 1075.4 22.2 818
Knobby Sandstone Ngalti 1 Core 1075.6 668
Knobby Sandstone Ngalti 1 Core 1075.7 20.5 630
Knobby Sandstone Ngalti 1 Core 1076 17.5 626
Knobby Sandstone Ngalti 1 Core 1077.1 19.9 731
Knobby Sandstone Ngalti 1 Core 1077.9 23.3 794
Knobby Sandstone Ngalti 1 Core 1077.9 637
Knobby Sandstone Ngalti 1 Core 1779.1 11.8 2.82
Knobby Sandstone Ngalti 1 Core 1779.15 3.5
Knobby Sandstone Ngalti 1 Core 1779.25 11.5 2.02
Knobby Sandstone Ngalti 1 Core 1779.45 10.3 0.89
Knobby Sandstone Ngalti 1 Core 1780.24 11.2
Knobby Sandstone Ngalti 1 Core 1780.5 1.4
Knobby Sandstone Ngalti 1 Core 1780.55 12.1 21.5
Knobby Sandstone Ngalti 1 Core 1780.85 9.5 0.75
Knobby Sandstone Ngalti 1 Core 1781.2 10.3 0.68
Knobby Sandstone Ngalti 1 Core 1781.9 12.4 11.2
Knobby Sandstone Ngalti 1 Core 1782.17 12.2 22.6
Knobby Sandstone Ngalti 1 Core 1782.25 20.7
Knobby Sandstone Ngalti 1 Core 1782.47 13.3 72
Knobby Sandstone Ngalti 1 Core 1782.77 12.1 55
Knobby Sandstone Ngalti 1 Core 1783.03 12.2 95
Knobby Sandstone Ngalti 1 Core 1783.38 11.6 76
Knobby Sandstone Ngalti 1 Core 1783.5 25.5
Knobby Sandstone Ngalti 1 Core 1783.7 12.9 28.4
Knobby Sandstone Ngalti 1 Core 1784 12.5 19.7
Knobby Sandstone Ngalti 1 Core 1784.32 10.9 8.71
Knobby Sandstone Ngalti 1 Core 1784.6 11.8 24.9
Knobby Sandstone Ngalti 1 Core 1784.7 15.5
Knobby Sandstone Ngalti 1 Core 1784.9 12.6 47.5
Knobby Sandstone Ngalti 1 Core 1785.2 12.2 36.1
Knobby Sandstone Ngalti 1 Core 1785.5 12.2 43.9
Knobby Sandstone Ngalti 1 Core 1786 12.1 37.7
Knobby Sandstone Ngalti 1 Core 1786 0.96
Knobby Sandstone Ngalti 1 Core 1786.3 12.5 26
Knobby Sandstone Ngalti 1 Core 1786.6 13.1 96
Knobby Sandstone Ngalti 1 Core 1786.9 11.5 68
Knobby Sandstone Ngalti 1 Core 1787.2 12.2 31.5
Knobby Sandstone Ngalti 1 Core 1787.3 78
Knobby Sandstone Ngalti 1 Core 1787.5 11.9 24.1
Knobby Sandstone Ngalti 1 Core 1787.8 12.2 63
Knobby Sandstone Ngalti 1 Core 1788.15 11.7 31.3
Knobby Sandstone Ngalti 1 Core 1788.45 12.5 74
Knobby Sandstone Ngalti 1 Core 1788.55 87
Knobby Sandstone Ngalti 1 Core 1788.75 12.3 84
Knobby Sandstone Ngalti 1 Core 1789.05 12.1 94
Knobby Sandstone Ngalti 1 Core 1789.3 10.4 3.03
Knobby Sandstone Olios 1 Sonic 1561.5 14
Knobby Sandstone Olios 1 Sonic 1574 12.6
Knobby Sandstone Olios 1 Sonic 1589.5 18
Knobby Sandstone Olios 1 Sonic 1623 17.3
Knobby Sandstone Olios 1 Sonic 1657.8 15.7
Knobby Sandstone Olios 1 Sonic 1679.5 16.6
Knobby Sandstone Olios 1 Sonic 1715.5 12.6
Knobby Sandstone Olios 1 Sonic 1746 10.4
Knobby Sandstone Olios 1 Sonic 1776.7 16.6
Knobby Sandstone Olios 1 Sonic 1785.5 12.3
Knobby Sandstone Olios 1 Sonic 1813 13.3
Knobby Sandstone Olios 1 Sonic 1826.3 11.5
Knobby Sandstone Olios 1 Sonic 1845.5 13.3
Knobby Sandstone Olios 1 Sonic 1846.6 17.5
Knobby Sandstone Olios 1 Sonic 1859.7 6
Knobby Sandstone Olios 1 Sonic 1881.5 6
Knobby Sandstone Olios 1 Sonic 1899 12.5
Knobby Sandstone Olios 1 Sonic 1902 11.5
Knobby Sandstone Olios 1 Sonic 1926.5 12.1
Laurel Formation Olios 1 Sonic 926 22
Laurel Formation Olios 1 Sonic 930 21
Laurel Formation Olios 1 Sonic 938 22
Laurel Formation Olios 1 Sonic 955.2 19
Laurel Formation Olios 1 Sonic 964 15.8
Laurel Formation Olios 1 Sonic 967 19.7
Laurel Formation Olios 1 Sonic 969.5 20.7
Laurel Formation Olios 1 Sonic 981.2 21.6
Laurel Formation Olios 1 Sonic 983.2 14.1
Laurel Formation Olios 1 Sonic 986.5 20
Laurel Formation Olios 1 Sonic 993 19.3
Laurel Formation Olios 1 Sonic 995 20.5
Laurel Formation Olios 1 Sonic 1001.5 16.8
Laurel Formation Olios 1 Sonic 1011.5 20.5
Laurel Formation Olios 1 Sonic 1023 18.5
Laurel Formation Olios 1 Sonic 1037.5 19.3
Laurel Formation Olios 1 Sonic 1044 14.4
Laurel Formation Olios 1 Sonic 1055 17
Laurel Formation Olios 1 Sonic 1061.5 13.4
Laurel Formation Olios 1 Sonic 1069.8 12.1
Laurel Formation Olios 1 Sonic 1439 19.8
Laurel Formation Olios 1 Sonic 1450.5 18.7
Laurel Formation Olios 1 Sonic 1477.7 18
Laurel Formation Olios 1 Sonic 1498.8 19.3
Laurel Formation Olios 1 Sonic 1526.5 16.7
Laurel Formation Olios 1 Sonic 1542.5 17.8
Laurel Formation Olios 1 Sonic 1553.5 18.3
Nita Formation Percival 1 Core 2026.63 0.9
Nita Formation Percival 1 Core 2026.63 0.9
Nita Formation Percival 1 Core 2026.63 0.9
Nita Formation Percival 1 Core 2031.25 0.8
Nita Formation Percival 1 Core 2031.25 0.8
Nita Formation Percival 1 Core 2031.25 0.8
Poole Sandstone Ngalti 1 Sonic 179 29-40
Unnamed Conglomerate Atrax 1 Sonic 727 10
Unnamed Conglomerate Atrax 1 Core 778.2 9.6 0.8
Unnamed Conglomerate Atrax 1 Core 778.6 10.9 0.5
Unnamed Conglomerate Selenops 1 Sonic 935 5.5
Unnamed Conglomerate Selenops 1 Sonic 1000 15.5
Unnamed Conglomerate Selenops 1 Sonic 1028 0
Unnamed Conglomerate Selenops 1 Core 1075.65 4.7 0.01
Unnamed Conglomerate Selenops 1 Core 1079 5.5 0.01
Unnamed Conglomerate Selenops 1 Core 1081.3 7.7 0.01
Unnamed Conglomerate Selenops 1 Core 1083.4 4.5 0.01
Unnamed Conglomerate Selenops 1 Sonic 1086.5 14
Unnamed Conglomerate Selenops 1 Sonic 1118 2
Unnamed Conglomerate Selenops 1 Sonic 1182 18.5
Unnamed Conglomerate Selenops 1 Sonic 1190 7
Unnamed Conglomerate Selenops 1 Sonic 1202 7
Virgin Hills Formation Selenops 1 Sonic 472.5 9
Virgin Hills Formation Selenops 1 Core 476 3.7 0.25
Virgin Hills Formation Selenops 1 Core 479 10.5 0.64
Virgin Hills Formation Selenops 1 Core 482 7.5 0.43
Virgin Hills Formation Selenops 1 Core 485 4.4 1.2
Virgin Hills Formation Selenops 1 Core 488 8.4 0.34
Virgin Hills Formation Selenops 1 Core 491 9.9 0.25
 Appendix B

Appendix B

Synthetic Seismograms

Synthetic seismograms were generated for all wells in the study area, and tied to seismic lines
prior to seismic interpretation. Images of all of these synthetics are included in this Appendix.

414
415

Atrax 1 synthetic seismogram (left), synthetic overlay on seismic (right).

416

Bindi 1 synthetic seismogram (left), synthetic overlay on seismic (right).

417

Kilang Kilang 1 synthetic seismogram (left), synthetic overlay on seismic (right).

418

Lake Betty 1 synthetic seismogram (left), synthetic overlay on seismic (right).

419

Lanagan 1 synthetic seismogram (left), synthetic overlay on seismic (right).

420

Lawford 1 synthetic seismogram (left), synthetic overlay on seismic (right).

421

Ngalti 1 synthetic seismogram (left), synthetic overlay on seismic (right).

422

Olios 1 synthetic seismogram (left), synthetic overlay on seismic (right).

423

Selenops 1 synthetic seismogram (left), synthetic overlay on seismic (right).

 Appendix C

Appendix C

Geochemical Data

Geochemical data from open file well completion reports and a database constructed by the
Geological Survey of Western Australia was utilised in this study. These data are included in
this Appendix.

Note, that colouring on these charts has the following meaning.

Legend

Data point from well within study area

Zone contains G. Prisca algae

424
 Noonkanbah Formation
o
Well Depth (mRT) TOC % Tmax ( C) S1 (kg/ton) S2 (kg/ton) S3 (kg/ton) S1+S2 S2/S3 PI PC HI OI
Atrax 1 30 0.83 0.02 0.06 1.35 0.08 0.0444 0.25 0.01 7.229 162.7
Atrax 1 45 1.95 431 0.02 0.44 1.48 0.46 0.2973 0.043 0.04 22.56 75.9
Atrax 1 60 1.4 436 0.01 0.24 1.01 0.25 0.2376 0.04 0.02 17.14 72.14
Atrax 1 75 1.66 433 0.01 0.34 0.97 0.35 0.3505 0.029 0.03 20.48 58.43
Atrax 1 90 1.61 431 0.03 0.35 0.61 0.38 0.5738 0.079 0.03 21.74 37.89
Atrax 1 105 1.15 428 0.02 0.71 2.99 0.73 0.2375 0.027 0.06 61.74 260
Auld 1 100 0.43
Bindi 1 859.2 3.44 434 0.04 1.14 0.7 1.18 1.6286 0.03 0.09 33.14 20.35
Bindi 1 905.6 2.18 427 0.13 1.75 0.4 1.88 4.375 0.07 0.15 80.28 18.35
Booran 1 1000 3.13 434 0.5 1.41 0.52 1.91 2.7115 0.26 0.16 45.05 16.61
Booran 1 1086 2.97 430 0.85 1.29 0.44 2.14 2.9318 0.4 0.18 43.43 14.81
Booran 1 1160 4.81 435 0.59 4.46 0.39 5.05 11.436 0.12 0.42 92.72 8.108
Booran 1 1235 3.8 434 0.49 5.01 0.45 5.5 11.133 0.09 0.46 131.8 11.84
Canegrass 1 500.5 3.07 432 0.04 0.97 0.76 1.01 1.2763 0.04 31.6 24.76
Canegrass 1 500.5 3.07 432 0.04 0.97 0.76 1.01 1.2763 0.04 0.08 31.6 24.76
Canegrass 1 525 4.7 430 0.1 4.68 0.6 4.78 7.8 0.02 99.57 12.77
Canegrass 1 525 4.7 430 0.1 4.68 0.6 4.78 7.8 0.02 0.4 99.57 12.77
Canegrass 1 550 0.34
Canegrass 1 550 0.34
Contention Heights 1 106.68 2.05
Crab Creek 1 706.5 1.91 432 0.05 0.9 0.42 0.95 2.1429 0.05 0.08 47.12 21.99
Curringa 1 806 3.55
Cycas 1 339.2 4.91
Cycas 1 425.6 9.37
East Yeeda 1 780 1.16 428 0.03 0.63 1.75 0.66 0.36 0.05 0.05 54.31 150.9
East Yeeda 1 840 0.78 426 0.02 0.45 2.34 0.47 0.1923 0.04 0.04 57.69 300
East Yeeda 1 930 1.69 429 0.03 0.48 1.31 0.51 0.3664 0.06 0.04 28.4 77.51
East Yeeda 1 990 1.7 431 0.03 0.44 1.84 0.47 0.2391 0.06 0.04 25.88 108.2
East Yeeda 1 1010 1.98 431 0.03 0.64 1.02 0.67 0.6275 0.04 0.06 32.32 51.52
East Yeeda 1 1040 2.52 427 0.04 1.27 1.06 1.31 1.1981 0.03 0.11 50.4 42.06
East Yeeda 1 1070 3.38 425 0.09 3.01 1.34 3.1 2.2463 0.03 0.26 89.05 39.64
Hakea 1 549.1 2.33 434 0.07 1.34 0.19 1.41 7.0526 0.05 0.12 57.51 8.155
Hangover 1 465 0.63 0.02 0.11 0.23 0.13 0.4783 0.15 17.46 36.51
Hangover 1 485 1.17
Hangover 1 510 1.97 432 0.03 0.57 0.51 0.6 1.1176 0.05 28.93 25.89
Hangover 1 510 1.62 430 0.03 0.37 0.24 0.4 1.5417 22.84 14.81
Hangover 1 535 1.88
Hangover 1 560 1.02
Hangover 1 580 1.63
Hangover 1 595 2.13 436 0.04 0.4 0.42 0.44 0.9524 0.09 18.78 19.72
Hangover 1 613 2.61 438 0.05 0.55 0.67 0.6 0.8209 0.08 21.07 25.67
Hangover 1 615 2.06 434 0.03 0.48 0.29 0.51 1.6552 0.06 23.3 14.08
Hangover 1 660 1.87
Hangover 1 680 2.12
Hangover 1 695 2.05 435 0.03 0.4 0.1 0.43 4 0.07 19.51 4.878
Hangover 1 705 2.59
Hangover 1 715 2.8
Hangover 1 725 3.81 434 0.08 2.33 1.06 2.41 2.1981 0.04 61.15 27.82
Hangover 1 735 3.41 430 0.05 1.87 0.62 1.92 3.0161 0.03 54.84 18.18
Hangover 1 750 1.07 0 0
Hangover 1 756 2.51 430 0.07 1.46 0.75 1.53 1.9467 0.05 58.17 29.88
Hangover 1 760 2.71 433 0.06 1.92 0.93 1.98 2.0645 0.03 70.85 34.32
Jum Jum 1 1115 0.95 0.09 0.11 0.73 0.2 0.1507 0.45 0.02 11.58 76.84
Jum Jum 1 1150 0.62 0.59 0.04 0.54 0.63 0.0741 0.94 0.05 6.452 87.1
Jum Jum 1 1340 2.34 419 0.17 0.27 0.79 0.44 0.3418 0.39 0.04 11.54 33.76
Kambara 1 802.8 3.27 434 0.7 2.4 0.4 3.1 6 0.23 73.39 12.23
Kilang Kilang 1 330 1.55 428 0.02 0.46 0.4 0.48 1.15 0.04 0.04 29.68 25.81
Kilang Kilang 1 359 0.71 426 0.13 0.27 0.17 0.4 1.5882 0.33 0.03 38.03 23.94
Kilang Kilang 1 360 1.79 425 0.04 0.33 1.01 0.37 0.3267 0.11 0.03 18.44 56.42
Kilang Kilang 1 390 1.32 0.02 0.13 1.21 0.15 0.1074 0.13 0.01 9.848 91.67
Kilang Kilang 1 406.4 2.39 429 0.17 0.48 0.3 0.65 1.6 0.26 0.05 20.08 12.55
Kilang Kilang 1 420 1.39 433 0.04 0.2 1 0.24 0.2 0.17 0.02 14.39 71.94
Kilang Kilang 1 437.7 0.56 0.12 0.07 2.56 0.19 0.0273 0.63 0.02 12.5 457.1
Kilang Kilang 1 450 1.51 426 0.14 0.32 0.24 0.46 1.3333 0.3 0.04 21.19 15.89
Kilang Kilang 1 450 1.19 0.04 0.14 1.98 0.18 0.0707 0.22 0.01 11.76 166.4
Kilang Kilang 1 476 1.52 431 0.1 0.23 0.66 0.33 0.3485 0.3 0.03 15.13 43.42
Kilang Kilang 1 480 1.29 0.02 0.14 1.06 0.16 0.1321 0.13 0.01 10.85 82.17
Kilang Kilang 1 510 1.41 433 0.03 0.2 1.76 0.23 0.1136 0.13 0.03 14.18 124.8
Kilang Kilang 1 524 1.96 430 0.09 0.38 0.22 0.47 1.7273 0.19 0.04 19.39 11.22
Kilang Kilang 1 540 1.3 435 0.03 0.23 1.88 0.26 0.1223 0.12 0.02 17.69 144.6
Kilang Kilang 1 545 1.54 431 0.24 0.53 0.26 0.77 2.0385 0.31 0.06 34.42 16.88
Kilang Kilang 1 570 0.88 437 0.07 0.24 2.3 0.31 0.1043 0.23 0.03 27.27 261.4
Kilang Kilang 1 600 1.99 428 0.27 1.57 1.35 1.84 1.163 0.15 0.15 78.89 67.84
Kilang Kilang 1 610 2.48 430 0.13 0.7 0.33 0.83 2.1212 0.16 0.07 28.23 13.31
Kilang Kilang 1 630 2.62 429 0.1 3.77 0.11 3.87 34.273 0.03 0.32 143.9 4.198
Kilang Kilang 1 631 3.48 428 0.14 3.07 1.61 3.21 1.9068 0.04 0.27 88.22 46.26
Kilang Kilang 1 642.5 2.39 430 0.11 2.04 0.15 2.15 13.6 0.05 0.18 85.36 6.276
Kilang Kilang 1 660 2.63 429 0.09 3.33 0.24 3.42 13.875 0.03 0.28 126.6 9.125
Kora 1 940 3.85
Kora 1 970 4.05
Lake Betty 1 396.24 1.97 430 0.11 0.57 1.7 0.68 0.3353 28.93 86.29
Lake Betty 1 426.72 1.71 429 0.1 0.35 1.95 0.45 0.1795 20.47 114
Lake Betty 1 457.2 1.44 422 0.24 1.73 4.94 1.97 0.3502 120.1 343.1
Lake Betty 1 487.68 1.39 0.1 0.19 3.25 0.29 0.0585 13.67 233.8
Lake Betty 1 518.16 1.59 432 0.1 0.34 2.32 0.44 0.1466 21.38 145.9
Lake Betty 1 548.64 2.13 433 0.1 0.62 2.59 0.72 0.2394 29.11 121.6
Lake Betty 1 579.12 2.17 431 0.1 0.62 2.22 0.72 0.2793 28.57 102.3
Lake Betty 1 609.6 2.07 435 0.1 0.45 1.92 0.55 0.2344 21.74 92.75
Lake Betty 1 640.08 3.09 434 0.1 0.98 1.8 1.08 0.5444 31.72 58.25
Lake Betty 1 670.56 3.29 434 0.1 2.19 1.61 2.29 1.3602 66.57 48.94
Meda 1 595 2.2
Mimosa 1 405 1.5
Mimosa 1 510 2.2
Minjin 1 750 2.38 427 0.08 1.28 0.39 1.36 3.2821 0.06 0.11 53.78 16.39
Minjin 1 766 2.41 424 0.06 0.72 0.51 0.78 1.4118 0.08 0.06 29.88 21.16
Moogana 1 995 1.44
Moogana 1 1010 1.72
Ngalti 1 120 1.04
Ngalti 1 137.3 0.27
Ngalti 1 150 0.34
Ngalti 1 175.5 4 429 0.06 3.23 0.34 3.29 9.5 0.02 0.27 80.75 8.5
Olios 1 75 0.07
Olios 1 105 1.45 432 0.04 0.31 0.76 0.35 0.4079 0.114 0.03 21.38 52.41
Olios 1 135 1.55 435 0.02 0.24 0.48 0.26 0.5 0.077 0.02 15.48 30.97
Olios 1 165 1.36 434 0.02 0.23 0.3 0.25 0.7667 0.08 0.02 16.91 22.06
Olios 1 195 1.58 434 0.01 0.31 0.27 0.32 1.1481 0.031 0.03 19.62 17.09
Olios 1 225 1.28 436 0.03 0.27 1.76 0.3 0.1534 0.1 0.02 21.09 137.5
Olios 1 225 1.39 432 0.02 0.33 1.56 0.35 0.2115 0.057 0.03 23.74 112.2
Olios 1 255 1.39 432 0.02 0.33 1.56 0.35 0.2115 0.057 0.03 23.74 112.2
Petaluma 1 295 3.05 430 0.1 2.64 1.96 2.74 1.3469 0.04 0.23 86.56 64.26
Petaluma 1 305 4.2 428 0.16 3.49 3.87 3.65 0.9018 0.04 0.3 83.1 92.14
Petaluma 1 330 1.61 429 0.05 0.54 2.18 0.59 0.2477 0.08 0.05 33.54 135.4
Petaluma 1 335 1.64 419 0.23 0.98 2.94 1.21 0.3333 0.19 0.1 59.76 179.3
Petaluma 1 350 2.09 430 0.1 0.61 1.86 0.71 0.328 0.14 0.06 29.19 89
Petaluma 1 355 1.94 425 0.2 1.39 1.7 1.59 0.8176 0.13 0.13 71.65 87.63
Petaluma 1 550 1.74 429 0.06 0.49 2.13 0.55 0.23 0.11 0.05 28.16 122.4
Petaluma 1 555 2.07 430 0.07 0.63 2.17 0.7 0.2903 0.1 0.06 30.43 104.8
Petaluma 1 670 3.58 430 0.14 2.79 2.27 2.93 1.2291 0.05 0.24 77.93 63.41
Petaluma 1 675 3.22 431 0.12 2.36 2.31 2.48 1.0216 0.05 0.21 73.29 71.74
Philydrum 1 512 4.65 428 0.19 5.04 1.1 5.23 4.5818 0.04 0.43 108.4 23.66
Puratte 1 1170 2.48
Puratte 1 1245 1.96 431 0.03 0.43 1.09 0.46 0.3945 0.07 21.94 55.61
Puratte 1 1270 1.67 428 0.02 0.35 0.81 0.37 0.4321 0.05 20.96 48.5
Puratte 1 1290 1.81 430 0.04 0.36 1.09 0.4 0.3303 0.1 19.89 60.22
Puratte 1 1310 1.82 426 0.07 0.64 1.06 0.71 0.6038 0.1 35.16 58.24
Puratte 1 1330 2.2 431 0.05 0.69 1.29 0.74 0.5349 0.07 31.36 58.64
Puratte 1 1350 2.61 428 0.07 1.44 1.05 1.51 1.3714 0.05 55.17 40.23
Puratte 1 1365 3.18
Puratte 1 1370 2.98 431 0.09 2.08 1.09 2.17 1.9083 0.04 69.8 36.58
Puratte 1 1390 2.34 430 0.05 1.58 1.23 1.63 1.2846 0.03 67.52 52.56
Puratte 1 1410 2.15 427 0.05 1.43 1.05 1.48 1.3619 0.03 66.51 48.84
Selenops 1 30 2.04 433 0.01 0.31 2.2 0.32 0.1409 0.03 15.2 107.8
Selenops 1 45 0.33
Tappers Inlet 1 697.99 1.94 0.08 0.19 0.81 0.27 0.2346 0.3 0.02 9.794 41.75
Tappers Inlet 1 762 2.42 428 0.07 0.33 1 0.4 0.33 0.18 0.03 13.64 41.32
Tappers Inlet 1 822.96 2.77 430 0.07 0.46 1.04 0.53 0.4423 0.13 0.04 16.61 37.55
Tappers Inlet 1 908.3 2.77 431 0.1 0.77 1.01 0.87 0.7624 0.11 0.07 27.8 36.46
West Kora 1 900 3.7 423 0.16 0.85 0.28 1.01 3.0357 0.16 0.08 22.97 7.568
West Kora 1 975 2.38 423 0.16 1.36 0.17 1.52 8 0.11 0.12 57.14 7.143
West Philydrum 1 400 2.38 436 0.05 0.96 0.42 1.01 2.2857 0.05 0.08 40.34 17.65
Wilson Cliffs 1 347.5 2.48
 Anderson Formation
Well Sub-unit Depth (mRT) TOC % Tmax (°C) S1 (kg/ton) S2 (kg/ton) S3 (kg/ton) S1+S2 S2/S3 PI PC HI OI
Bindi 1 Anderson G 1833.1 0.07 0
Bindi 1 Anderson G 1897.1 0
Bindi 1 Anderson G 1918.7 0.55 425 0.17 0.11 0.19 0.28 0.579 0.61 0.02 20 34.55
Bindi 1 Anderson E 1999.4 0
Bindi 1 Anderson C 2176 0
Bindi 1 Anderson C 2179 0
Bindi 1 Anderson C 2224.9 0.09 0
Bindi 1 Anderson A 2348.1 0.26 0
Bindi 1 Anderson A 2373 0
Bindi 1 Anderson A 2393 0.35 426 0.08 0.13 0.24 0.21 0.542 0.38 0.35 37.14 68.57
Bindi 1 Anderson A 2435.5 0
Kilang Kilang 1 Anderson G 1460 0.17 0
Kilang Kilang 1 Anderson F 1490 0.04 0
Kilang Kilang 1 Anderson F 1512.2 0.14 0
Kilang Kilang 1 Anderson E 1520 0.08 0
Kilang Kilang 1 Anderson D 1550 0.08 0
Kilang Kilang 1 Anderson D 1580 0.08 0
Kilang Kilang 1 Anderson C 1610 0.06 0
Kilang Kilang 1 Anderson B 1640 0.06 0
Kilang Kilang 1 Anderson A 1670 0.04 0
Kilang Kilang 1 Anderson A 1700 0.06 0
 Laurel Formation
Well Tectonic Region Depth (mRT) TOC % Tmax (oC) S1 (kg/ton) S2 (kg/ton) S3 (kg/ton) S1+S2 S2/S3 PI PC HI OI
Aquanita 1 Lennard Shelf 1600 0.17
Aquanita 1 Lennard Shelf 1605 0.48
Aquanita 1 Lennard Shelf 1610 0.32
Aquanita 1 Lennard Shelf 1615 0.26
Aquanita 1 Lennard Shelf 1620 0.19
Aquanita 1 Lennard Shelf 1625 0.16
Aquanita 1 Lennard Shelf 1630 0.2
Aquanita 1 Lennard Shelf 1635 0.36
Aquanita 1 Lennard Shelf 1640 0.42
Aquanita 1 Lennard Shelf 1645 0.36
Aquanita 1 Lennard Shelf 1655 0.21
Aquanita 1 Lennard Shelf 1665 0.3
Aquanita 1 Lennard Shelf 1670 0.24
Aquanita 1 Lennard Shelf 1680 0.3
Aquanita 1 Lennard Shelf 1685 0.27
Aquanita 1 Lennard Shelf 1690 0.34
Aquanita 1 Lennard Shelf 1700 0.3
Aquanita 1 Lennard Shelf 1705 0.24
Bindi 1 Betty Terrace 2481.4 0.38
Blackstone 1 Lennard Shelf 1532.2 1.79
Blackstone 1 Lennard Shelf 1532.2 1.94
Blackstone 1 Lennard Shelf 1536.2 0.2
Blackstone 1 Lennard Shelf 1536.8 1.94
Blackstone 1 Lennard Shelf 1536.8 2.08
Blackstone 1 Lennard Shelf 1556 4.84 425 1.31 20.29 1.85 21.6 0.061 419.2 38.22
Blackstone 1 Lennard Shelf 1556 4.84 425 1.31 20.2 1.85 21.51 0.06 417.4 38.22
Blackstone 1 Lennard Shelf 1690.3 0.3
Blackstone 1 Lennard Shelf 1819.3 0.1
Blina 1 Lennard Shelf 1113.1 0.63
Blina 1 Lennard Shelf 1122.6 0.42
Blina 1 Lennard Shelf 1130 0.41
Canegrass 1 Lennard Shelf 1304 1.17 436 0.1 1.28 0.06 1.38 0.07 109.4 5.128
Canegrass 1 Lennard Shelf 1304 1.17 436 0.1 1.28 0.06 1.38 0.07 0.11 109.4 5.128
Canegrass 1 Lennard Shelf 1400 0.51 432 0.09 0.57 0.16 0.66 0.14 111.8 31.37
Canegrass 1 Lennard Shelf 1400 0.51 432 0.09 0.57 0.16 0.66 0.14 0.05 111.8 31.37
Cow Bore 1 Jurgurra Terrace 1300 0.28
Cow Bore 1 Jurgurra Terrace 1309 0.53 414 0.05 0.25 0.72 0.3 0.19 0.03 47.17 135.8
Cow Bore 1 Jurgurra Terrace 1320 0.49
Cow Bore 1 Jurgurra Terrace 1340 0.7 427 0.03 0.21 0.67 0.24 0.13 0.02 30 95.71
Cow Bore 1 Jurgurra Terrace 1360 0.77 427 0.03 0.25 0.49 0.28 0.11 0.02 32.47 63.64
Cow Bore 1 Jurgurra Terrace 1380 0.64
Cow Bore 1 Jurgurra Terrace 1400 0.52
Cow Bore 1 Jurgurra Terrace 1408 0.42
Cow Bore 1 Jurgurra Terrace 1411 0.42
Cow Bore 1 Jurgurra Terrace 1420 0.42
Cow Bore 1 Jurgurra Terrace 1440 0.48
Cow Bore 1 Jurgurra Terrace 1450 0.46
Cow Bore 1 Jurgurra Terrace 1460 0.44
Cow Bore 1 Jurgurra Terrace 1470 0.56 427 0.02 0.25 0.26 0.27 0.07 0.02 44.64 46.43
Cow Bore 1 Jurgurra Terrace 1480 0.63
Cow Bore 1 Jurgurra Terrace 1504 0.68 425 0.06 0.27 0.52 0.33 0.18 0.03 39.71 76.47
Cow Bore 1 Jurgurra Terrace 1510 0.59 428 0.03 0.26 0.18 0.29 0.1 2 44.07 30.51
Cow Bore 1 Jurgurra Terrace 1519 0.52
Cow Bore 1 Jurgurra Terrace 1530 0.62
Cow Bore 1 Jurgurra Terrace 1537 0.54
Cow Bore 1 Jurgurra Terrace 1540 0.52
Cow Bore 1 Jurgurra Terrace 1550 0.69
Cow Bore 1 Jurgurra Terrace 1560 0.62 432 0.02 0.31 0.24 0.33 0.06 0.03 50 38.71
Cow Bore 1 Jurgurra Terrace 1570 0.64
Cow Bore 1 Jurgurra Terrace 1580 0.72
Cow Bore 1 Jurgurra Terrace 1590 0.68
Cow Bore 1 Jurgurra Terrace 1600 0.73 427 0.06 0.32 0.51 0.38 0.16 0.03 43.84 69.86
Cow Bore 1 Jurgurra Terrace 1610 0.74
Cow Bore 1 Jurgurra Terrace 1620 0.71 435 0.03 0.37 0.17 0.4 0.08 0.03 52.11 23.94
Cow Bore 1 Jurgurra Terrace 1630 0.71 435 0.04 0.47 0.13 0.51 0.08 0.04 66.2 18.31
Cow Bore 1 Jurgurra Terrace 1660 0.73
Cow Bore 1 Jurgurra Terrace 1690 0.86
Cow Bore 1 Jurgurra Terrace 1705 0.88 437 0.11 0.22 0.37 0.33 0.017 0.05 25 42.05
Cow Bore 1 Jurgurra Terrace 1710 0.77
Cow Bore 1 Jurgurra Terrace 1730 0.81 438 0.12 0.35 0.48 0.47 0.26 0.04 43.21 59.26
Cow Bore 1 Jurgurra Terrace 1750 0.75
Cow Bore 1 Jurgurra Terrace 1770 0.82 436 0.13 0.3 0.69 0.43 0.3 0.04 36.59 84.15
Cow Bore 1 Jurgurra Terrace 1790 0.95 397 0.46 0.69 0.97 1.15 0.4 0.1 72.63 102.1
Cow Bore 1 Jurgurra Terrace 1810 0.49 0.64 1.13 0.43
Cow Bore 1 Jurgurra Terrace 1810 0.59
Cow Bore 1 Jurgurra Terrace 1830 0.79 0.33 0.17 1.06 0.5 0.66 0.04 21.52 134.2
Cow Bore 1 Jurgurra Terrace 1850 0.24
Cow Bore 1 Jurgurra Terrace 1870 0.34
Cow Bore 1 Jurgurra Terrace 1890 0.09
Cow Bore 1 Jurgurra Terrace 1910 0.21
Cow Bore 1 Jurgurra Terrace 1930 0.27
Cow Bore 1 Jurgurra Terrace 1950 0.46
Cow Bore 1 Jurgurra Terrace 1970 0.36
Cow Bore 1 Jurgurra Terrace 1990 0.46
Cow Bore 1 Jurgurra Terrace 2110 0.8 438 0.15 0.32 0.22 0.47 0.32 0.04 40 27.5
Crab Creek 1 Broome Platform 1490 0.12
Crab Creek 1 Broome Platform 1537 0.12
Crab Creek 1 Broome Platform 1551.2 0.1
Crimson Lake 1 Fitzroy Trough 1577 0.46
Crimson Lake 1 Fitzroy Trough 1640 0.59 440 0.08 0.41 0.08 0.49 0.16 69.49 13.56
Crimson Lake 1 Fitzroy Trough 1676 0.83 436 0.16 1.22 0.27 1.38 0.12 147 32.53
Crimson Lake 1 Fitzroy Trough 1710 0.74 442 0.11 0.57 0.24 0.68 0.16 77.03 32.43
Crimson Lake 1 Fitzroy Trough 1783 0.51 439 0.1 0.39 0.15 0.49 0.2 76.47 29.41
Crimson Lake 1 Fitzroy Trough 1836 0.64 443 0.05 0.39 0.28 0.44 0.11 60.94 43.75
Crimson Lake 1 Fitzroy Trough 1962 0.3
Curringa 1 Pender Terrace 1854.5 5.05
Curringa 1 Pender Terrace 1865 2.57
Curringa 1 Pender Terrace 1868.9 2.61
Curringa 1 Pender Terrace 1871.04 5.81
Curringa 1 Pender Terrace 1874.98 0.15
Cycas 1 Fitzroy Trough 2816 0.14
Cycas 1 Fitzroy Trough 2837.5 0.14
Cycas 1 Fitzroy Trough 2897.5 0.14
Cycas 1 Fitzroy Trough 2952.5 0.12
Cycas 1 Fitzroy Trough 2987.5 0.12
East Crab Creek 1 Broome Platform 1446 0.08
East Yeeda 1 Fitzroy Trough 3040 0.22
East Yeeda 1 Fitzroy Trough 3070 0.38
East Yeeda 1 Fitzroy Trough 3085 0.32
East Yeeda 1 Fitzroy Trough 3100 0.27
East Yeeda 1 Fitzroy Trough 3115 0.22
East Yeeda 1 Fitzroy Trough 3130 0.18
East Yeeda 1 Fitzroy Trough 3145 0.13
East Yeeda 1 Fitzroy Trough 3160 0.15
East Yeeda 1 Fitzroy Trough 3175 0.26
East Yeeda 1 Fitzroy Trough 3190 0.14
East Yeeda 1 Fitzroy Trough 3205 0.24
East Yeeda 1 Fitzroy Trough 3220 0.17
East Yeeda 1 Fitzroy Trough 3235 0.23
East Yeeda 1 Fitzroy Trough 3250 0.16
East Yeeda 1 Fitzroy Trough 3265 0.22
East Yeeda 1 Fitzroy Trough 3280 0.23
East Yeeda 1 Fitzroy Trough 3295 0.2
Ellendale 1 Fitzroy Trough 1550 0.19
Ellendale 1 Fitzroy Trough 1570 0.84 486 0.17 1.19 1.36 0.12 141.7
Ellendale 1 Fitzroy Trough 1590 0.44
Ellendale 1 Fitzroy Trough 1610 0.57 487 0.09 0.57 0.66 0.14 100
Ellendale 1 Fitzroy Trough 1630 0.48
Ellendale 1 Fitzroy Trough 1650 0.64 493 0.13 0.78 0.91 0.35 121.9
Ellendale 1 Fitzroy Trough 1670 0.42
Ellendale 1 Fitzroy Trough 1690 1.3 530 0.43 2.53 2.96 0.14 194.6
Ellendale 1 Fitzroy Trough 1690 0.73 439 0.22 0.59 0.25 0.81 0.27 0.07 80.82 34.25
Ellendale 1 Fitzroy Trough 1695 0.83 438 0.24 0.94 0.15 1.18 0.2 0.1 113.3 18.07
Ellendale 1 Fitzroy Trough 1710 0.73 473 0.18 1.29 1.47 0.12 176.7
Ellendale 1 Fitzroy Trough 1730 0.78 512 0.21 1.22 1.43 0.15 156.4
Fitzroy River 1 Fitzroy Trough 2080 0.09
Fitzroy River 1 Fitzroy Trough 2100 0.12
Fitzroy River 1 Fitzroy Trough 2120 0.21
Fitzroy River 1 Fitzroy Trough 2140 0.17
Fitzroy River 1 Fitzroy Trough 2160 0.62
Fitzroy River 1 Fitzroy Trough 2180 0.5
Fitzroy River 1 Fitzroy Trough 2200 0.16
Fitzroy River 1 Fitzroy Trough 2220 0.18
Fitzroy River 1 Fitzroy Trough 2240 0.17
Fitzroy River 1 Fitzroy Trough 2260 0.16
Fitzroy River 1 Fitzroy Trough 2280 0.18
Fitzroy River 1 Fitzroy Trough 2300 0.06
Fitzroy River 1 Fitzroy Trough 2320 0.19
Fitzroy River 1 Fitzroy Trough 2340 0.2
Fitzroy River 1 Fitzroy Trough 2360 0.15
Fitzroy River 1 Fitzroy Trough 2380 0.25
Fitzroy River 1 Fitzroy Trough 2400 0.18
Fitzroy River 1 Fitzroy Trough 2420 0.19
Fitzroy River 1 Fitzroy Trough 2440 0.34
Fitzroy River 1 Fitzroy Trough 2460 0.31
Fitzroy River 1 Fitzroy Trough 2480 0.33
Fitzroy River 1 Fitzroy Trough 2500 0.13
Fitzroy River 1 Fitzroy Trough 2520 0.18
Fitzroy River 1 Fitzroy Trough 2540 0.32
Fitzroy River 1 Fitzroy Trough 2560 0.44
Fitzroy River 1 Fitzroy Trough 2580 0.23
Fitzroy River 1 Fitzroy Trough 2600 0.36
Fitzroy River 1 Fitzroy Trough 2620 0.43
Fitzroy River 1 Fitzroy Trough 2640 0.55
Fitzroy River 1 Fitzroy Trough 2660 0.53
Fitzroy River 1 Fitzroy Trough 2680 0.36
Fitzroy River 1 Fitzroy Trough 2700 0.38
Fitzroy River 1 Fitzroy Trough 2720 0.48
Fitzroy River 1 Fitzroy Trough 2740 0.33
Fitzroy River 1 Fitzroy Trough 2760 0.31
Fitzroy River 1 Fitzroy Trough 2780 0.45
Fitzroy River 1 Fitzroy Trough 2800 0.39
Fitzroy River 1 Fitzroy Trough 2820 0.49
Fitzroy River 1 Fitzroy Trough 2840 0.44
Fitzroy River 1 Fitzroy Trough 2860 0.43
Fitzroy River 1 Fitzroy Trough 2880 0.5
Fitzroy River 1 Fitzroy Trough 2900 0.53
Fitzroy River 1 Fitzroy Trough 2920 0.57 0.02 0 0.35 0.02 1 61.4
Fitzroy River 1 Fitzroy Trough 2940 0.64
Fitzroy River 1 Fitzroy Trough 2960 0.79
Fitzroy River 1 Fitzroy Trough 2980 0.7 0.01 0 0.54 0.01 1 0 77.14
Fitzroy River 1 Fitzroy Trough 3000 0.4
Fitzroy River 1 Fitzroy Trough 3020 0.56
Fitzroy River 1 Fitzroy Trough 3040 0.74 0 0 0.3 0 40.54
Fitzroy River 1 Fitzroy Trough 3060 1.13
Fitzroy River 1 Fitzroy Trough 3080 0.75
Fitzroy River 1 Fitzroy Trough 3100 0.59 0.01 0.02 0.02 0.03 0.33 3.39 3.39
Fitzroy River 1 Fitzroy Trough 3120 0.98
Hakea 1 Fitzroy Trough 1699 0.13
Hakea 1 Fitzroy Trough 1703 0.17
Janpam 1 Lennard Shelf 1450 0.19
Janpam 1 Lennard Shelf 1460 0.15
Janpam 1 Lennard Shelf 1470 0.16
Janpam 1 Lennard Shelf 1485 0.22
Janpam 1 Lennard Shelf 1500 0.27
Janpam 1 Lennard Shelf 1515 0.48
Janpam 1 Lennard Shelf 1530 0.33
Janpam 1 Lennard Shelf 1535 0.4
Jones Range 1 Gregory Sub-basin 1655 0.31
Jones Range 1 Gregory Sub-basin 1675 0.25
Jones Range 1 Gregory Sub-basin 1685 0.53
Jones Range 1 Gregory Sub-basin 1700 0.36
Jones Range 1 Gregory Sub-basin 1705 0.28
Jones Range 1 Gregory Sub-basin 1735 0.36
Jones Range 1 Gregory Sub-basin 1770 0.49
Jones Range 1 Gregory Sub-basin 1780 0.37
Jones Range 1 Gregory Sub-basin 1805 0.34
Jones Range 1 Gregory Sub-basin 1815 0.5
Jones Range 1 Gregory Sub-basin 1830 0.51
Jones Range 1 Gregory Sub-basin 1830 0.51 444 0.27 0.29 0.03 0.56 56.86 5.882
Jones Range 1 Gregory Sub-basin 1835 0.2
Jones Range 1 Gregory Sub-basin 1870 0.19
Jones Range 1 Gregory Sub-basin 1895 0.18
Jones Range 1 Gregory Sub-basin 1900 0.21
Jones Range 1 Gregory Sub-basin 1905 0.17
Jones Range 1 Gregory Sub-basin 1910 0.14
Jones Range 1 Gregory Sub-basin 1910 0.13
Jones Range 1 Gregory Sub-basin 1930 0.23
Jones Range 1 Gregory Sub-basin 1945 0.12
Jones Range 1 Gregory Sub-basin 1970 0.17
Jones Range 1 Gregory Sub-basin 1990 0.17
Jones Range 1 Gregory Sub-basin 2005 0.19
Jones Range 1 Gregory Sub-basin 2030 0.3
Jones Range 1 Gregory Sub-basin 2035 0.29
Jones Range 1 Gregory Sub-basin 2040 0.31
Jones Range 1 Gregory Sub-basin 2050 0.21
Jones Range 1 Gregory Sub-basin 2060 0.3
Jones Range 1 Gregory Sub-basin 2085 0.27
Jones Range 1 Gregory Sub-basin 2090 0.26
Jones Range 1 Gregory Sub-basin 2105 0.19
Jones Range 1 Gregory Sub-basin 2120 0.21
Jones Range 1 Gregory Sub-basin 2130 0.42
Jones Range 1 Gregory Sub-basin 2140 0.28
Jones Range 1 Gregory Sub-basin 2165 0.15
Jones Range 1 Gregory Sub-basin 2255 0.48
Jones Range 1 Gregory Sub-basin 2265 0.04
Jones Range 1 Gregory Sub-basin 2285 0.05
Jones Range 1 Gregory Sub-basin 2300 0.17
Jones Range 1 Gregory Sub-basin 2305 0.1
Jones Range 1 Gregory Sub-basin 2315 0.06
Jones Range 1 Gregory Sub-basin 2340 0.06
Jones Range 1 Gregory Sub-basin 2355 0.06
Jones Range 1 Gregory Sub-basin 2385 0.07
Justago 1 Lennard Shelf 215 0.17
Justago 1 Lennard Shelf 385 0.1
Kambara 1 Pender Terrace 1610 0.56 0.1 0.1 0.1 17.86 17.86
Kambara 1 Pender Terrace 1667.4 1.89 432 0.2 0.5 0.6 0.7 0.29 26.46 31.75
Kambara 1 Pender Terrace 1695.5 1.65 429 0.3 0.3 1.4 0.6 0.5 18.18 84.85
Kambara 1 Pender Terrace 1702 1.77 427 0.2 0.2 1 0.4 0.5 11.3 56.5
Kambara 1 Pender Terrace 1739.8 3.49 429 1.2 14.6 2.4 15.8 0.08 418.3 68.77
Kambara 1 Pender Terrace 1753.8 1.88 423 0.3 0.9 1.4 1.2 0.25 47.87 74.47
Kilang Kilang 1 Gregory Sub-basin 1730 0.11
Kilang Kilang 1 Gregory Sub-basin 1757 0.19
Kilang Kilang 1 Gregory Sub-basin 1760 0.07
Kilang Kilang 1 Gregory Sub-basin 1790 0.1
Kilang Kilang 1 Gregory Sub-basin 1820 0.07
Kilang Kilang 1 Gregory Sub-basin 1850 0.12
Kilang Kilang 1 Gregory Sub-basin 1880 0.09
Kilang Kilang 1 Gregory Sub-basin 1882 0.31
Kilang Kilang 1 Gregory Sub-basin 1910 0.06
Kilang Kilang 1 Gregory Sub-basin 1940 0.07
Kilang Kilang 1 Gregory Sub-basin 1970 0.07
Kilang Kilang 1 Gregory Sub-basin 2000 0.11
Kilang Kilang 1 Gregory Sub-basin 2010 0.15
Kilang Kilang 1 Gregory Sub-basin 2030 0.07
Kilang Kilang 1 Gregory Sub-basin 2060 0.13
Kilang Kilang 1 Gregory Sub-basin 2090 0.08
Kilang Kilang 1 Gregory Sub-basin 2120 0.12
Kilang Kilang 1 Gregory Sub-basin 2136.9 0.08
Kilang Kilang 1 Gregory Sub-basin 2150 0.14
Kilang Kilang 1 Gregory Sub-basin 2180 0.08
Kilang Kilang 1 Gregory Sub-basin 2210 0.12
Kilang Kilang 1 Gregory Sub-basin 2240 0.08
Kilang Kilang 1 Gregory Sub-basin 2260 0.13
Kilang Kilang 1 Gregory Sub-basin 2270 0.12
Kora 1 Fitzroy Trough 2300 1.29
Kora 1 Fitzroy Trough 2305 2.94
Kora 1 Fitzroy Trough 2335 0.33
Kora 1 Fitzroy Trough 2348 1.01
Kora 1 Fitzroy Trough 2360 0.57
Kora 1 Fitzroy Trough 2365 0.39
Kora 1 Fitzroy Trough 2395 0.56
Kora 1 Fitzroy Trough 2397 0.49
Kora 1 Fitzroy Trough 2425 0.46
Kora 1 Fitzroy Trough 2459 0.53
Kora 1 Fitzroy Trough 2474 0.36
Kora 1 Fitzroy Trough 2485 0.61
Kora 1 Fitzroy Trough 2515 0.82
Kora 1 Fitzroy Trough 2517 0.73
Kora 1 Fitzroy Trough 2525 0.56 445 0.15 0.59 0.94 0.74 0.2 0.06 105.4 167.9
Kora 1 Fitzroy Trough 2532.7 1.06
Kora 1 Fitzroy Trough 2535 0.58 448 0.14 0.56 0.81 0.7 0.2 0.06 96.55 139.7
Kora 1 Fitzroy Trough 2542.5 1.01
Kora 1 Fitzroy Trough 2545 0.7 448 0.18 0.75 0.72 0.93 0.19 0.06 107.1 102.9
Kora 1 Fitzroy Trough 2552.2 1.42
Kora 1 Fitzroy Trough 2555 0.63 446 0.19 0.65 0.78 0.84 0.23 0.07 103.2 123.8
Lake Betty 1 Gregory Sub-basin 1660 1.73
Lake Betty 1 Gregory Sub-basin 1700 1.59 432 0.1 0.34 2.32 0.44 21.38 145.9
Lake Betty 1 Gregory Sub-basin 1800 2.13 433 0.1 0.62 2.59 0.72 29.11 121.6
Lake Betty 1 Gregory Sub-basin 1859.28 1.98 449 0.2 1.64 0.93 1.84 82.83 46.97
Lake Betty 1 Gregory Sub-basin 1889.76 1.36 452 0.16 1.42 0.74 1.58 104.4 54.41
Lake Betty 1 Gregory Sub-basin 1900 2.17 431 0.1 0.62 2.22 0.72 28.57 102.3
Lake Betty 1 Gregory Sub-basin 1910 2.38
Lake Betty 1 Gregory Sub-basin 1920.24 0.37
Lake Betty 1 Gregory Sub-basin 1950.72 1.41 449 0.17 1.31 0.76 1.48 92.91 53.9
Lake Betty 1 Gregory Sub-basin 1981.2 1.16 447 0.15 0.91 0.65 1.06 78.45 56.03
Lake Betty 1 Gregory Sub-basin 2000 2.07 435 0.1 0.45 1.92 0.55 21.74 92.75
Lake Betty 1 Gregory Sub-basin 2011.68 2.08 453 0.14 1.54 0.41 1.68 74.04 19.71
Lake Betty 1 Gregory Sub-basin 2042.16 0.28
Lake Betty 1 Gregory Sub-basin 2072.64 0.33
Lake Betty 1 Gregory Sub-basin 2100 3.09 434 0.1 0.98 1.8 1.08 31.72 58.25
Lake Betty 1 Gregory Sub-basin 2103.12 0.22
Lake Betty 1 Gregory Sub-basin 2133.6 0.44
Lake Betty 1 Gregory Sub-basin 2164.08 0.76
Lake Betty 1 Gregory Sub-basin 2194.56 0.82
Lake Betty 1 Gregory Sub-basin 2200 3.29 434 0.1 2.19 1.61 2.29 66.57 48.94
Lake Betty 1 Gregory Sub-basin 2225.04 0.62
Lake Betty 1 Gregory Sub-basin 2255.52 0.49
Lake Betty 1 Gregory Sub-basin 2286 0.53
Lake Betty 1 Gregory Sub-basin 2316.48 0.57
Lake Betty 1 Gregory Sub-basin 2346.96 0.32
Lake Betty 1 Gregory Sub-basin 2377.44 0.41
Lake Betty 1 Gregory Sub-basin 2407.92 0.22
Lake Betty 1 Gregory Sub-basin 2438.4 0.27
Lake Betty 1 Gregory Sub-basin 2468.88 0.3
Lake Betty 1 Gregory Sub-basin 2474.2 0.03
Lake Betty 1 Gregory Sub-basin 2499.36 0.42
Lake Betty 1 Gregory Sub-basin 2529.84 0.42
Lake Betty 1 Gregory Sub-basin 2560.32 0.6
Langoora 1 Lennard Shelf 1382 0.75 427 0.03 0.33 0.83 0.36 0.083 44 110.7
Langoora 1 Lennard Shelf 1491 0.85 427 0.2 0.87 0.47 1.07 0.187 102.4 55.29
Lloyd 1 Lennard Shelf 1765 0.03 0.15 0.74 0.18 0.17
Lloyd 1 Lennard Shelf 1767.5 429 0.06 0.29 0.55 0.35 0.17
Lloyd 1 Lennard Shelf 1770 430 0.05 0.22 0.39 0.27 0.19
Lloyd 1 Lennard Shelf 1772.5 0.15 0.14 0.47 0.29 0.52
Lloyd 1 Lennard Shelf 1775 0.16 0.12 0.44 0.28 0.57
Lloyd 1 Lennard Shelf 1777.5 0.05 0.11 0.49 0.16 0.31
Lloyd 1 Lennard Shelf 1780 0.06 0.16 0.52 0.22 0.27
Lloyd 1 Lennard Shelf 1837.5 0.02 0.09 0.64 0.11 0.18
Lloyd 1 Lennard Shelf 1840 0.02 0.07 0.45 0.09 0.22
Lloyd 1 Lennard Shelf 1842.5 0.02 0.05 0.47 0.07 0.29
Lloyd 1 Lennard Shelf 1845 0.04 0.08 0.47 0.12 0.33
Lloyd 1 Lennard Shelf 1852.5 0.01 0.06 0.38 0.07 0.14
Lloyd 1 Lennard Shelf 1855 0.07 0.11 0.33 0.18 0.39
Lloyd 1 Lennard Shelf 1857.5 0.09 0.1 0.35 0.19 0.47
Lloyd 1 Lennard Shelf 1860 0.06 0.09 0.49 0.15 0.4
Lloyd 1 Lennard Shelf 1862.5 0.06 0.16 0.5 0.22 0.27
Lloyd 1 Lennard Shelf 1865 0.04 0.11 0.5 0.15 0.27
Lloyd 1 Lennard Shelf 1875 0.01 0.02 0.35 0.03 0.33
Logue 1 Jurgurra Terrace 1368.103 0.13
Logue 1 Jurgurra Terrace 1389.432 0.21
Logue 1 Jurgurra Terrace 1398.573 0.14
Logue 1 Jurgurra Terrace 1419.902 0.15
Logue 1 Jurgurra Terrace 1429.043 0.1
Logue 1 Jurgurra Terrace 1459.513 0.14
Logue 1 Jurgurra Terrace 1527 0.25
Mangaloo 1 Barbwire Terrace 930 0.49
Mangaloo 1 Barbwire Terrace 950 0.22
Mangaloo 1 Barbwire Terrace 970 0.34
Mangaloo 1 Barbwire Terrace 1000 0.48
Mangaloo 1 Barbwire Terrace 1007.5 0.66
Mangaloo 1 Barbwire Terrace 1027.5 0.15
Mangaloo 1 Barbwire Terrace 1047.5 0.16
Mangaloo 1 Barbwire Terrace 1070 0.26
Mangaloo 1 Barbwire Terrace 1080 1
Mangaloo 1 Barbwire Terrace 1090 0.47
Mangaloo 1 Barbwire Terrace 1110 0.19
Mangaloo 1 Barbwire Terrace 1132.5 0.49
Mangaloo 1 Barbwire Terrace 1150 0.3
Mangaloo 1 Barbwire Terrace 1160 0.21
Mangaloo 1 Barbwire Terrace 1230 0.37
Mangaloo 1 Barbwire Terrace 1240 1.5
Mangaloo 1 Barbwire Terrace 1250 1.5
Mangaloo 1 Barbwire Terrace 1260 0.3
Mangaloo 1 Barbwire Terrace 1270 0.48
Mangaloo 1 Barbwire Terrace 1280 0.26
Mangaloo 1 Barbwire Terrace 1340 0.11
Mangaloo 1 Barbwire Terrace 1348.6 0.18
Mangaloo 1 Barbwire Terrace 1350 0.16
Mangaloo 1 Barbwire Terrace 1360 0.19
Mangaloo 1 Barbwire Terrace 1370 0.1
Mangaloo 1 Barbwire Terrace 1400 0.92
Mangaloo 1 Barbwire Terrace 1410 0.39
Mangaloo 1 Barbwire Terrace 1420 0.66
Mangaloo 1 Barbwire Terrace 1440 0.19
Mangaloo 1 Barbwire Terrace 1470 0.09
Mangaloo 1 Barbwire Terrace 1615 0.11
Mariana 1 Lennard Shelf 1175 1.04 423 0.05 0.38 0.5 0.43 0.12 0.04 36.54 48.08
Mariana 1 Lennard Shelf 1194.2 0.19
Mariana 1 Lennard Shelf 1205 0.79 425 0.03 0.24 0.7 0.27 0.11 0.02 30.38 88.61
Mariana 1 Lennard Shelf 1270 0.51 0.04 0.14 0.8 0.18 0.22 0.01 27.45 156.9
Mariana 1 Lennard Shelf 1276 0.35
Mariana 1 Lennard Shelf 1285 0.34
Meda 1 Lennard Shelf 1542 0.2
Meda 1 Lennard Shelf 1542.2 0.67
Meda 1 Lennard Shelf 1556 0.46
Meda 1 Lennard Shelf 1597.1 0.73
Meda 1 Lennard Shelf 1665
Meda 2 Lennard Shelf 1673 1.04 435 0.18 1.11 0.6 1.29 0.14 106.7 57.69
Meda 2 Lennard Shelf 1673 1.04 435 0.18 1.11 0.6 1.29 0.14 106.7 57.69
Meda 2 Lennard Shelf 1724 0.75 479 0.07 0.37 0.86 0.44 0.159 49.33 114.7
Meda 2 Lennard Shelf 1724 0.75 479 0.07 0.37 0.86 0.44 0.16 49.33 114.7
Mimosa 1 Lennard Shelf 1125 0.4
Moogana 1 Pender Terrace 2030 2.17
Mt Hardman 1 Fitzroy Trough 1999.4 0.68
Mt Hardman 1 Fitzroy Trough 1999.4 0.68
Mt Hardman 1 Fitzroy Trough 2008.6 0.64
Mt Hardman 1 Fitzroy Trough 2017.7 0.62
Mt Hardman 1 Fitzroy Trough 2026.9 0.69
Mt Hardman 1 Fitzroy Trough 2036 0.65
Mt Hardman 1 Fitzroy Trough 2045.2 0.68
Mt Hardman 1 Fitzroy Trough 2054.3 0.66
Mt Hardman 1 Fitzroy Trough 2063.5 0.97 436 1.73 1.45 1.73 178.4 149.5
Mt Hardman 1 Fitzroy Trough 2072.6 0.95
Mt Hardman 1 Fitzroy Trough 2081.7 1.05 441 0.9 0.9 0.9 85.71 85.71
Mt Hardman 1 Fitzroy Trough 2090.9 1.11 441 0.4 1.2 0.4 36.04 108.1
Mt Hardman 1 Fitzroy Trough 2100 1.03 441 0.3 1.3 0.3 29.13 126.2
Mt Hardman 1 Fitzroy Trough 2109.2 1.22 446 0.7 1.6 0.7 57.38 131.1
Mt Hardman 1 Fitzroy Trough 2118.3 0.81 451 0.3 0.9 0.3 37.04 111.1
Mt Hardman 1 Fitzroy Trough 2127.5 0.72 441 0.2 0.9 0.2 27.78 125
Mt Hardman 1 Fitzroy Trough 2136.6 0.55 416 0.3 0.8 0.3 54.55 145.5
Mt Hardman 1 Fitzroy Trough 2145.7 0.48
Mt Hardman 1 Fitzroy Trough 2154.9 0.32
Mt Hardman 1 Fitzroy Trough 2164 0.41
Mt Hardman 1 Fitzroy Trough 2173.2 0.42
Mt Hardman 1 Fitzroy Trough 2182.3 0.37
Mt Hardman 1 Fitzroy Trough 2191.5 0.47
Mt Hardman 1 Fitzroy Trough 2200.6 0.53
Mt Hardman 1 Fitzroy Trough 2209.8 0.57
Mt Hardman 1 Fitzroy Trough 2218.9 0.37
Mt Hardman 1 Fitzroy Trough 2228 0.54
Mt Hardman 1 Fitzroy Trough 2237.2 0.4
Mt Hardman 1 Fitzroy Trough 2246.3 0.38
Mt Hardman 1 Fitzroy Trough 2255.5 0.37
Mt Hardman 1 Fitzroy Trough 2264.6 0.58
Mt Hardman 1 Fitzroy Trough 2273.8 0.49
Mt Hardman 1 Fitzroy Trough 2282.9 0.63
Mt Hardman 1 Fitzroy Trough 2292.1 0.36
Mt Hardman 1 Fitzroy Trough 2301.2 0.54
Nuytsia 1 Mowla Terrace 986.5 0.14
Nuytsia 1 Mowla Terrace 988.7 0.06
Nuytsia 1 Mowla Terrace 1011.7 0.13
Olios 1 Balgo Terrace 825 0.18
Olios 1 Balgo Terrace 840 0.34
Olios 1 Balgo Terrace 855 0.55 432 0.11 0.42 0.39 0.53 1.07692 0.208 0.04 76.36 70.91
Olios 1 Balgo Terrace 870 0.19
Olios 1 Balgo Terrace 885 0.09
Olios 1 Balgo Terrace 900 0.14
Olios 1 Balgo Terrace 915 0.25
Olios 1 Balgo Terrace 930 0.2
Olios 1 Balgo Terrace 945 0.86 422 2.52 2.08 0.76 4.6 2.73684 0.548 0.38 241.9 88.37
Olios 1 Balgo Terrace 960 0.39
Olios 1 Balgo Terrace 975 0.13
Olios 1 Balgo Terrace 990 0.19
Olios 1 Balgo Terrace 1005 0.09
Olios 1 Balgo Terrace 1020 0.12
Olios 1 Balgo Terrace 1035 0.06
Olios 1 Balgo Terrace 1050 0.1
Olios 1 Balgo Terrace 1065 0.13
Olios 1 Balgo Terrace 1080 0.09
Olios 1 Balgo Terrace 1095 0.21
Olios 1 Balgo Terrace 1110 0.19
Olios 1 Balgo Terrace 1125 0.24
Olios 1 Balgo Terrace 1140 0.22
Olios 1 Balgo Terrace 1155 0.18
Olios 1 Balgo Terrace 1170 0.19
Olios 1 Balgo Terrace 1185 0.17
Olios 1 Balgo Terrace 1200 0.19
Olios 1 Balgo Terrace 1215 0.17
Olios 1 Balgo Terrace 1230 0.15
Olios 1 Balgo Terrace 1245 0.18
Olios 1 Balgo Terrace 1260 0.14
Olios 1 Balgo Terrace 1275 0.18
Olios 1 Balgo Terrace 1290 0.3
Olios 1 Balgo Terrace 1305 0.18
Olios 1 Balgo Terrace 1320 0.18
Olios 1 Balgo Terrace 1335 0.45
Olios 1 Balgo Terrace 1350 0.31
Olios 1 Balgo Terrace 1365 0.12
Olios 1 Balgo Terrace 1380 0.13
Olios 1 Balgo Terrace 1395 0.08
Olios 1 Balgo Terrace 1410 0.13
Olios 1 Balgo Terrace 1425 0.11
Orange Pool 1 Lennard Shelf 888.1 0.48
Orange Pool 1 Lennard Shelf 923.3 1.12
Orange Pool 1 Lennard Shelf 971.3 0.7
Orange Pool 1 Lennard Shelf 982.6 0.55
Orange Pool 1 Lennard Shelf 1034.5 0.17
Perindi 1 Pender Terrace 1773.6 0.21
Philydrum 1 Fitzroy Trough 1450 0.37
Puratte 1 Fitzroy Trough 2800 0.87
Puratte 1 Fitzroy Trough 2830 0.88
Puratte 1 Fitzroy Trough 2865 0.7
Puratte 1 Fitzroy Trough 2895 0.6
Puratte 1 Fitzroy Trough 2915 0.7
Puratte 1 Fitzroy Trough 2940 0.76
Puratte 1 Fitzroy Trough 2970 0.51
St George Range 1 Fitzroy Trough 2902.6 0.5
St George Range 1 Fitzroy Trough 2904.744 0.77 0.1 0.04 0.78 0.14 5.195 101.3
St George Range 1 Fitzroy Trough 2935.224 0.7 0.09 0.05 0.51 0.14 7.143 72.86
St George Range 1 Fitzroy Trough 2944.368 0.56
St George Range 1 Fitzroy Trough 2950.464 0.53
St George Range 1 Fitzroy Trough 2953.512 0.45
St George Range 1 Fitzroy Trough 2959.608 0.4
St George Range 1 Fitzroy Trough 2987.04 0.21
St George Range 1 Fitzroy Trough 2993.136 0.19
St George Range 1 Fitzroy Trough 2999.232 0.29
St George Range 1 Fitzroy Trough 3002.5848 0.4
St George Range 1 Fitzroy Trough 3011.424 0.34
St George Range 1 Fitzroy Trough 3017.52 0.3
St George Range 1 Fitzroy Trough 3032 2.61 489 0.05 0.47 0.45 0.52 18.01 17.24
St George Range 1 Fitzroy Trough 3032 2.61 489 0.05 0.47 0.45 0.52 18.01 17.24
St George Range 1 Fitzroy Trough 3032.76 0.33
St George Range 1 Fitzroy Trough 3038.856 0.99 317 2.36 2.02 3.62 4.38 204 365.7
St George Range 1 Fitzroy Trough 3066.288 0.51
St George Range 1 Fitzroy Trough 3072.384 0.23
St George Range 1 Fitzroy Trough 3078.48 0.3
St George Range 1 Fitzroy Trough 3090.672 0.25
St George Range 1 Fitzroy Trough 3099.816 0.32
St George Range 1 Fitzroy Trough 3118.104 0.32
St George Range 1 Fitzroy Trough 3124.5 0.2
St George Range 1 Fitzroy Trough 3142.488 0.33
St George Range 1 Fitzroy Trough 3148.584 0.31
St George Range 1 Fitzroy Trough 3154.68 0.33
St George Range 1 Fitzroy Trough 3160.776 0.36
St George Range 1 Fitzroy Trough 3163.824 0.41
St George Range 1 Fitzroy Trough 3185.16 0.24
St George Range 1 Fitzroy Trough 3188.208 0.39
St George Range 1 Fitzroy Trough 3191.256 0.35
St George Range 1 Fitzroy Trough 3258.312 0.4
St George Range 1 Fitzroy Trough 3261.36 0.29
St George Range 1 Fitzroy Trough 3279.648 0.53
St George Range 1 Fitzroy Trough 3300.984 0.38
St George Range 1 Fitzroy Trough 3307.08 0.35
St George Range 1 Fitzroy Trough 3328.416 0.52
St George Range 1 Fitzroy Trough 3334.512 0.5
St George Range 1 Fitzroy Trough 3349.752 0.3
St George Range 1 Fitzroy Trough 3358.896 0.31
St George Range 1 Fitzroy Trough 3371.088 0.3
St George Range 1 Fitzroy Trough 3377.184 0.58
St George Range 1 Fitzroy Trough 3383.28 0.55
St George Range 1 Fitzroy Trough 3392.424 0.39
St George Range 1 Fitzroy Trough 3398.52 0.47
St George Range 1 Fitzroy Trough 3422.904 0.43
St George Range 1 Fitzroy Trough 3425.952 0.55
St George Range 1 Fitzroy Trough 3435.096 0.48
St George Range 1 Fitzroy Trough 3442.1 0.1
St George Range 1 Fitzroy Trough 3447.288 0.31
St George Range 1 Fitzroy Trough 3453.384 0.41
St George Range 1 Fitzroy Trough 3456.432 0.31
St George Range 1 Fitzroy Trough 3462.528 0.27
St George Range 1 Fitzroy Trough 3474 0.67 521 0.05 0.39 0.54 0.44 58.21 80.6
St George Range 1 Fitzroy Trough 3474 0.67 521 0.05 0.39 0.54 0.44 58.21 80.6
St George Range 1 Fitzroy Trough 3483.864 0.59
St George Range 1 Fitzroy Trough 3489.96 0.62 0.12 0.17 0.39 0.29 27.42 62.9
Sundown 1 Lennard Shelf 1805 0.33
Sundown 1 Lennard Shelf 1815 0.27
Sundown 1 Lennard Shelf 1855.5 0.52 432 0.24 0.43 1.1 0.67 0.36 0.06 82.69 211.5
Sundown 1 Lennard Shelf 1860 0.3
Sundown 1 Lennard Shelf 1865 0.25
Sundown 1 Lennard Shelf 1880 0.25
Sundown 1 Lennard Shelf 1890 0.29
Sundown 1 Lennard Shelf 1900 0.27
Sundown 1 Lennard Shelf 1900.5 0.51 437 0.11 0.3 0.41 0.41 0.27 0.03 58.82 80.39
Sundown 1 Lennard Shelf 1935 0.28
Sundown 1 Lennard Shelf 1950 0.27
Sundown 1 Lennard Shelf 1955 0.22
Sundown 1 Lennard Shelf 1965 0.26
Sundown 1 Lennard Shelf 1968.1 0.58 441 0.16 0.46 0.29 0.62 0.26 0.05 79.31 50
Sundown 1 Lennard Shelf 1977.5 0.76 437 0.19 0.53 0.32 0.72 0.26 0.05 69.74 42.11
Sundown 1 Lennard Shelf 1980 0.25
Valhalla 1 ST1 Fitzroy Trough 1985 0.16
Valhalla 1 ST1 Fitzroy Trough 2005 0.21
Valhalla 1 ST1 Fitzroy Trough 2035 0.37
Valhalla 1 ST1 Fitzroy Trough 2045 0.3
Valhalla 1 ST1 Fitzroy Trough 2070 0.34
Valhalla 1 ST1 Fitzroy Trough 2085 0.34
Valhalla 1 ST1 Fitzroy Trough 2100 0.4
Valhalla 1 ST1 Fitzroy Trough 2150 0.27
Valhalla 1 ST1 Fitzroy Trough 2170 0.42
Valhalla 1 ST1 Fitzroy Trough 2185 0.33
Valhalla 1 ST1 Fitzroy Trough 2220 0.44
Valhalla 1 ST1 Fitzroy Trough 2235 0.28
Valhalla 1 ST1 Fitzroy Trough 2285 0.37
Valhalla 1 ST1 Fitzroy Trough 2320 0.49
Valhalla 1 ST1 Fitzroy Trough 2335 0.62 441 0.16 0.49 1.96 0.65 79.03 316.1
Valhalla 1 ST1 Fitzroy Trough 2350 0.65 439 0.17 0.49 2.14 0.66 75.38 329.2
Valhalla 1 ST1 Fitzroy Trough 2390 0.55
Valhalla 1 ST1 Fitzroy Trough 2440 0.8 442 0.21 0.61 1.51 0.82 76.25 188.8
Valhalla 1 ST1 Fitzroy Trough 2450 0.75 448 0.16 0.55 1.46 0.71 73.33 194.7
Valhalla 1 ST1 Fitzroy Trough 2500 0.88 442 0.26 0.61 1.36 0.87 69.32 154.5
Valhalla 1 ST1 Fitzroy Trough 2535 0.84 441 0.36 0.88 1.58 1.24 104.8 188.1
Valhalla 1 ST1 Fitzroy Trough 2545 1.33 439 0.58 1.19 1.53 1.77 89.47 115
Valhalla 1 ST1 Fitzroy Trough 2565 1.08 442 0.34 0.87 1.33 1.21 80.56 123.1
Valhalla 1 ST1 Fitzroy Trough 2620 0.83 445 0.24 0.53 1.47 0.77 63.86 177.1
Valhalla 1 ST1 Fitzroy Trough 2630 0.75 442 0.16 0.45 1.34 0.61 60 178.7
Valhalla 1 ST1 Fitzroy Trough 2640 0.9 441 0.19 0.49 1.57 0.68 54.44 174.4
Valhalla 1 ST1 Fitzroy Trough 2660 0.61 464 0.16 0.31 1.12 0.47 50.82 183.6
Valhalla 1 ST1 Fitzroy Trough 2670 0.77 452 0.15 0.33 1.17 0.48 42.86 151.9
Valhalla 1 ST1 Fitzroy Trough 2680 1.27 443 0.53 1.04 1.63 1.57 81.89 128.3
Valhalla 1 ST1 Fitzroy Trough 2690 0.6 465 0.14 0.35 0.92 0.49 58.33 153.3
Valhalla 1 ST1 Fitzroy Trough 2725 0.77 470 0.14 0.42 1.04 0.56 54.55 135.1
Valhalla 1 ST1 Fitzroy Trough 2740 0.72 464 0.13 0.4 0.89 0.53 55.56 123.6
Valhalla 1 ST1 Fitzroy Trough 2755 0.99 465 0.2 0.66 0.89 0.86 66.67 89.9
Valhalla 1 ST1 Fitzroy Trough 2815 0.56
Valhalla 1 ST1 Fitzroy Trough 2860 0.75 418 0.15 0.47 1.43 0.62 62.67 190.7
Valhalla 1 ST1 Fitzroy Trough 2875 0.7 422 0.16 0.53 1.41 0.69 75.71 201.4
Valhalla 1 ST1 Fitzroy Trough 2890 0.48
Valhalla 1 ST1 Fitzroy Trough 2930 0.54
Valhalla 1 ST1 Fitzroy Trough 2945 0.54
Valhalla 1 ST1 Fitzroy Trough 2960 0.62 426 0.11 0.31 1.31 0.42 50 211.3
Valhalla 1 ST1 Fitzroy Trough 2975 0.62 348 0.12 0.22 1.22 0.34 35.48 196.8
Valhalla 1 ST1 Fitzroy Trough 2985 0.64 366 0.11 0.26 1.16 0.37 40.63 181.3
Valhalla 1 ST1 Fitzroy Trough 3000 0.53
Valhalla 1 ST1 Fitzroy Trough 3015 0.54
Valhalla 1 ST1 Fitzroy Trough 3035 0.64 0.09 0.15 0.97 0.24 23.44 151.6
Valhalla 1 ST1 Fitzroy Trough 3045 0.5
Valhalla 1 ST1 Fitzroy Trough 3095 0.63 366 0.13 0.22 0.51 0.35 34.92 80.95
Valhalla 1 ST1 Fitzroy Trough 3110 0.49
Valhalla 1 ST1 Fitzroy Trough 3115 0.44
Valhalla 1 ST1 Fitzroy Trough 3135 0.42
Valhalla 1 ST1 Fitzroy Trough 3150 0.85 469 0.13 0.4 0.77 0.53 47.06 90.59
Valhalla 1 ST1 Fitzroy Trough 3160 0.53
Valhalla 1 ST1 Fitzroy Trough 3180 0.54
Valhalla 1 ST1 Fitzroy Trough 3195 0.62 447 0.09 0.26 0.92 0.35 41.94 148.4
Valhalla 1 ST1 Fitzroy Trough 3210 0.59
Valhalla 1 ST1 Fitzroy Trough 3220 0.58
Valhalla 1 ST1 Fitzroy Trough 3315 0.82 449 0.13 0.36 0.71 0.49 43.9 86.59
Valhalla 1 ST1 Fitzroy Trough 3325 0.81 0.09 0.19 0.57 0.28 23.46 70.37
Valhalla 1 ST1 Fitzroy Trough 3345 0.84 0.11 0.18 0.39 0.29 21.43 46.43
Valhalla 1 ST1 Fitzroy Trough 3360 0.63 455 0.12 0.24 0.48 0.36 38.1 76.19
Valhalla 1 ST1 Fitzroy Trough 3370 0.81 448 0.15 0.25 0.28 0.4 30.86 34.57
Valhalla 1 ST1 Fitzroy Trough 3385 0.87 457 0.16 0.39 0.33 0.55 44.83 37.93
Valhalla 1 ST1 Fitzroy Trough 3400 0.66 450 0.1 0.21 0.35 0.31 31.82 53.03
Valhalla 1 ST1 Fitzroy Trough 3410 0.64 0.08 0.19 0.34 0.27 29.69 53.13
West Kora 1 Fitzroy Trough 2263 1.98 430 0.11 0.24 0.16 0.35 0.31 0.02 12.12 8.081
West Kora 1 Fitzroy Trough 2279 0.71 434 0.09 0.21 0.16 0.3 0.3 0.02 29.58 22.54
West Kora 1 Fitzroy Trough 2290 1.74
West Kora 1 Fitzroy Trough 2291 0.52 0.1 0.15 0.23 0.25 0.4 0.02 28.85 44.23
West Kora 1 Fitzroy Trough 2320 1.26
West Kora 1 Fitzroy Trough 2367 0.31
West Kora 1 Fitzroy Trough 2380 1.08
West Kora 1 Fitzroy Trough 2387 0.3
West Kora 1 Fitzroy Trough 2410 0.81
West Kora 1 Fitzroy Trough 2435.9 0.63 0.07 0.08 0.25 0.15 0.47 0.01 12.7 39.68
West Kora 1 Fitzroy Trough 2440 0.7
West Kora 1 Fitzroy Trough 2448 0.47
West Kora 1 Fitzroy Trough 2470 0.58
West Kora 1 Fitzroy Trough 2500 0.7
West Kora 1 Fitzroy Trough 2530 0.64
White Hills 1 Gregory Sub-basin 1090 0.25
White Hills 1 Gregory Sub-basin 1100 0.17
White Hills 1 Gregory Sub-basin 1105 0.43
White Hills 1 Gregory Sub-basin 1110 0.33
White Hills 1 Gregory Sub-basin 1120 0.4
White Hills 1 Gregory Sub-basin 1130 0.35
White Hills 1 Gregory Sub-basin 1140 0.67 0.29 43.28
White Hills 1 Gregory Sub-basin 1150 0.29
White Hills 1 Gregory Sub-basin 1160 0.19
White Hills 1 Gregory Sub-basin 1173 0.27
White Hills 1 Gregory Sub-basin 1180 0.5 0.17 34
White Hills 1 Gregory Sub-basin 1190 0.46
White Hills 1 Gregory Sub-basin 1200 0.27
White Hills 1 Gregory Sub-basin 1210 0.23
White Hills 1 Gregory Sub-basin 1220 0.36
White Hills 1 Gregory Sub-basin 1230 0.3
White Hills 1 Gregory Sub-basin 1239 0.29
White Hills 1 Gregory Sub-basin 1240 0.63 438 0.21 0.19 0.21 33.33 30.16
White Hills 1 Gregory Sub-basin 1250 0.22
White Hills 1 Gregory Sub-basin 1260 0.28
White Hills 1 Gregory Sub-basin 1270 0.52 0.15 28.85
White Hills 1 Gregory Sub-basin 1280 0.88 438 0.23 0.47 0.18 0.7 0.33 53.41 20.45
White Hills 1 Gregory Sub-basin 1290 0.79 437 0.15 0.41 0.17 0.56 0.27 51.9 21.52
White Hills 1 Gregory Sub-basin 1300 0.37
White Hills 1 Gregory Sub-basin 1310 0.29
White Hills 1 Gregory Sub-basin 1320 0.37
White Hills 1 Gregory Sub-basin 1330 0.5 0.07 14
White Hills 1 Gregory Sub-basin 1340 0.63 438 0.21 0.32 0.11 0.53 0.4 50.79 17.46
White Hills 1 Gregory Sub-basin 1350 0.62 0.13 20.97
White Hills 1 Gregory Sub-basin 1360 0.46
White Hills 1 Gregory Sub-basin 1369 0.62 420 0.15 0.32 0.62 0.47 0.32 51.61 100
White Hills 1 Gregory Sub-basin 1370 0.79 438 0.31 0.16 0.31 39.24 20.25
White Hills 1 Gregory Sub-basin 1380 0.72 435 0.27 0.17 0.27 37.5 23.61
White Hills 1 Gregory Sub-basin 1390 0.46
White Hills 1 Gregory Sub-basin 1400 0.54 0.13 24.07
White Hills 1 Gregory Sub-basin 1410 0.59 440 0.21 0.23 0.21 35.59 38.98
White Hills 1 Gregory Sub-basin 1414 0.38
White Hills 1 Gregory Sub-basin 1420 0.51 0.15 0.15 0.15 29.41 29.41
White Hills 1 Gregory Sub-basin 1430 0.45
White Hills 1 Gregory Sub-basin 1440 0.51 0.24 47.06
White Hills 1 Gregory Sub-basin 1450 0.45
White Hills 1 Gregory Sub-basin 1460 0.59 447 0.18 30.51
White Hills 1 Gregory Sub-basin 1470 0.71 442 0.3 0.35 0.3 42.25 49.3
White Hills 1 Gregory Sub-basin 1480 0.74 0.15 0.21 0.15 20.27 28.38
White Hills 1 Gregory Sub-basin 1490 0.4
White Hills 1 Gregory Sub-basin 1500 0.36
White Hills 1 Gregory Sub-basin 1510 0.53 0.3 56.6
White Hills 1 Gregory Sub-basin 1516.4 0.84 433 0.13 0.54 0.83 0.67 0.19 64.29 98.81
White Hills 1 Gregory Sub-basin 1520 0.53 440 0.1 0.35 0.19 0.45 0.22 66.04 35.85
White Hills 1 Gregory Sub-basin 1530 0.43
White Hills 1 Gregory Sub-basin 1540 0.47
White Hills 1 Gregory Sub-basin 1550 0.65 449 0.16 0.48 0.13 0.64 0.25 73.85 20
White Hills 1 Gregory Sub-basin 1560 0.43
White Hills 1 Gregory Sub-basin 1570 0.5 0.24 0.45 0.19 0.69 0.35 90 38
White Hills 1 Gregory Sub-basin 1580 0.66 448 0.15 0.45 0.16 0.6 0.25 68.18 24.24
White Hills 1 Gregory Sub-basin 1590 0.46
White Hills 1 Gregory Sub-basin 1600 0.84 453 0.22 0.64 0.19 0.86 0.26 76.19 22.62
White Hills 1 Gregory Sub-basin 1610 0.7 0.19 0.28 0.19 27.14 40
White Hills 1 Gregory Sub-basin 1620 0.6 0.1 0.15 0.27 0.25 0.4 25 45
White Hills 1 Gregory Sub-basin 1621.7 0.45
White Hills 1 Gregory Sub-basin 1630 0.55 0.13 0.21 0.13 23.64 38.18
White Hills 1 Gregory Sub-basin 1640 0.59 0.11 0.18 0.11 18.64 30.51
White Hills 1 Gregory Sub-basin 1650 0.65 0.17 0.2 0.17 26.15 30.77
White Hills 1 Gregory Sub-basin 1660 0.66 0.18 0.21 0.18 27.27 31.82
White Hills 1 Gregory Sub-basin 1670 0.61 0.1 0.17 0.1 16.39 27.87
White Hills 1 Gregory Sub-basin 1675.5 1.95 448 0.31 0.89 0.57 1.2 0.26 45.64 29.23
White Hills 1 Gregory Sub-basin 1680 0.7 0.15 0.24 0.15 21.43 34.29
White Hills 1 Gregory Sub-basin 1690 0.74 0.16 0.24 0.16 21.62 32.43
White Hills 1 Gregory Sub-basin 1692.5 0.57 445 0.12 0.27 0.39 0.39 0.31 47.37 68.42
White Hills 1 Gregory Sub-basin 1700 0.65 0.13 0.23 0.13 20 35.38
White Hills 1 Gregory Sub-basin 1710 0.48
White Hills 1 Gregory Sub-basin 1720 0.47
White Hills 1 Gregory Sub-basin 1730 0.57 0.1 17.54
White Hills 1 Gregory Sub-basin 1740 0.6 0.08 13.33
White Hills 1 Gregory Sub-basin 1750 0.71 0.11 0.17 0.11 15.49 23.94
White Hills 1 Gregory Sub-basin 1760 0.51 0.09 17.65
White Hills 1 Gregory Sub-basin 1770 0.64 0.12 0.18 0.08 0.3 0.4 28.13 12.5
White Hills 1 Gregory Sub-basin 1773 0.62 0.12 0.23 0.86 0.35 0.34 37.1 138.7
White Hills 1 Gregory Sub-basin 1780 0.78 0.1 0.18 0.18 0.28 0.36 23.08 23.08
White Hills 1 Gregory Sub-basin 1789.1 0.41
White Hills 1 Gregory Sub-basin 1790 0.78 0.18 0.2 0.18 23.08 25.64
White Hills 1 Gregory Sub-basin 1800 0.64 0.18 0.21 0.18 28.13 32.81
White Hills 1 Gregory Sub-basin 1810 0.44
White Hills 1 Gregory Sub-basin 1820 0.45
White Hills 1 Gregory Sub-basin 1830 0.57 0.11 0.14 0.27 0.25 0.44 24.56 47.37
White Hills 1 Gregory Sub-basin 1840 0.51 0.18 0.2 0.18 35.29 39.22
White Hills 1 Gregory Sub-basin 1850 0.44
White Hills 1 Gregory Sub-basin 1860 0.52 0 0.1 0.23 0.1 0.3 19.23 44.23
White Hills 1 Gregory Sub-basin 1860 0.65 460 0.13 0.3 0.74 0.43 46.15 113.8
White Hills 1 Gregory Sub-basin 1870 0.71 0.19 0.26 0.19 26.76 36.62
White Hills 1 Gregory Sub-basin 1876.5 1.43 446 0.37 1.05 0.4 1.42 0.26 73.43 27.97
White Hills 1 Gregory Sub-basin 1880 0.6 456 0.1 0.23 0.25 0.33 0.3 38.33 41.67
White Hills 1 Gregory Sub-basin 1890 0.72 458 0.1 0.29 0.24 0.39 0.26 40.28 33.33
White Hills 1 Gregory Sub-basin 1900 0.61 0.17 0.16 0.17 27.87 26.23
White Hills 1 Gregory Sub-basin 1910 0.55 0.13 0.22 0.13 23.64 40
White Hills 1 Gregory Sub-basin 1910.4 0.72 469 0.11 0.21 0.91 0.32 0.34 29.17 126.4
White Hills 1 Gregory Sub-basin 1920 0.6 447 0.38 0.16 0.38 63.33 26.67
White Hills 1 Gregory Sub-basin 1930 0.52 0.24 46.15
White Hills 1 Gregory Sub-basin 1938.8 1.06 425 0.12 0.32 0.68 0.44 0.27 30.19 64.15
White Hills 1 Gregory Sub-basin 1950 0.67 0.18 0.15 0.37 0.33 0.55 22.39 55.22
White Hills 1 Gregory Sub-basin 1958.3 0.98 431 0.31 0.58 1.27 0.89 0.35 59.18 129.6
White Hills 1 Gregory Sub-basin 1960 0.83 0.19 0.24 0.37 0.43 0.44 28.92 44.58
White Hills 1 Gregory Sub-basin 1970 0.99 454 0.23 0.39 0.39 0.62 0.37 39.39 39.39
White Hills 1 Gregory Sub-basin 1980 0.65 0.12 0.3 0.12 18.46 46.15
White Hills 1 Gregory Sub-basin 1990 1.11 463 0.17 0.42 0.35 0.59 0.29 37.84 31.53
White Hills 1 Gregory Sub-basin 2000 0.79 0.12 0.17 0.37 0.29 0.41 21.52 46.84
White Hills 1 Gregory Sub-basin 2010 0.76 0.12 0.16 0.2 0.28 0.43 21.05 26.32
White Hills 1 Gregory Sub-basin 2020 0.76 0.19 0.18 0.19 25 23.68
White Hills 1 Gregory Sub-basin 2029.9 0.87 482 0.12 0.35 0.62 0.47 0.26 40.23 71.26
White Hills 1 Gregory Sub-basin 2030 0.68 0.14 0.19 0.14 20.59 27.94
White Hills 1 Gregory Sub-basin 2040 0.87 0.16 0.33 0.16 18.39 37.93
White Hills 1 Gregory Sub-basin 2050 0.79 0.13 0.31 0.13 16.46 39.24
White Hills 1 Gregory Sub-basin 2060 1.17 465 0.2 0.35 0.45 0.55 0.36 29.91 38.46
White Hills 1 Gregory Sub-basin 2070 1.28 465 0.28 0.45 0.4 0.73 0.38 35.16 31.25
White Hills 1 Gregory Sub-basin 2080 1.2 468 0.22 0.42 0.39 0.64 0.34 35 32.5
White Hills 1 Gregory Sub-basin 2090 0.93 0.22 0.33 0.41 0.55 0.4 35.48 44.09
White Hills 1 Gregory Sub-basin 2100 0.83 0.14 0.21 0.3 0.35 0.4 25.3 36.14
White Hills 1 Gregory Sub-basin 2104.8 0.7 485 0.12 0.24 0.46 0.36 0.33 34.29 65.71
White Hills 1 Gregory Sub-basin 2110 0.65 0.16 0.21 0.31 0.37 0.43 32.31 47.69
Yarrada 1 Lennard Shelf 1798 0.64
Yarrada 1 Lennard Shelf 1810.8 1.36
Yarrada 1 Lennard Shelf 1836.5 0.45
Yarrada 1 Lennard Shelf 1861.8 0.51
Yarrada 1 Lennard Shelf 1891.7 0.45
Yarrada 1 Lennard Shelf 1903 0.51
Yarrada 1 Lennard Shelf 1925 0.46
Yulleroo 1 Fitzroy Trough 690.07 0.12
Yulleroo 1 Fitzroy Trough 828.9 0.13
Yulleroo 1 Fitzroy Trough 2213.91 0.46
Yulleroo 1 Fitzroy Trough 2235 0.5 0.01 0.05 0.83 0.06 0.17 10 166
Yulleroo 1 Fitzroy Trough 2321 2.49 436 0.35 0.67 0.39 1.02 0.34 26.91 15.66
Yulleroo 1 Fitzroy Trough 2519.63 0.5
Yulleroo 1 Fitzroy Trough 2548 0.65 436 0.16 1.13 0.27 1.29 0.12 173.8 41.54
Yulleroo 1 Fitzroy Trough 2874.72 0.33
Yulleroo 1 Fitzroy Trough 3027.73 0.43
Yulleroo 1 Fitzroy Trough 3111.55 0.54 462 0.08 0.22 0.36 0.3 0.267 40.74 66.67
Yulleroo 1 Fitzroy Trough 3142 0.65 465 0.06 0.35 0.32 0.41 0.15 53.85 49.23
Yulleroo 1 Fitzroy Trough 3239 0.56 499 0.03 0.81 0.35 0.84 0.04 144.6 62.5
Yulleroo 1 Fitzroy Trough 3348.84 0.36
Yulleroo 1 Fitzroy Trough 3381 0.52 494 0.04 0.39 0.3 0.43 0.09 75 57.69
Yulleroo 1 Fitzroy Trough 3490.26 0.63 0.14 0.19 0.35 0.33 0.424 30.16 55.56
Yulleroo 1 Fitzroy Trough 3524 0.64 0.07 0.11 0.35 0.18 0.39 17.19 54.69
Yulleroo 1 Fitzroy Trough 3583.53 0.96 471 0.11 0.29 0.31 0.4 0.275 30.21 32.29
Yulleroo 1 Fitzroy Trough 3658.21 2.18 448 0.69 0.83 0.4 1.52 0.454 38.07 18.35
Yulleroo 1 Fitzroy Trough 3694 2.48 449 0.64 0.61 1.25 0.51 24.6
Yulleroo 1 Fitzroy Trough 3695 2.85 446 0.73 0.73 1.46 0.5 25.61
Yulleroo 1 Fitzroy Trough 3696 4.4 449 0.75 1.06 0.56 1.81 0.41 24.09 12.73
Yulleroo 1 Fitzroy Trough 3830.73 0.32
 Gogo Formation
Well Depth (mRT) TOC % Tmax (oC) S1 (kg/ton) S2 (kg/ton) S3 (kg/ton) S1+S2 S2/S3 PI PC HI OI
Gap Creek 1 425 0.45 427 0.21 0.38 0.28 0.59 0.36 84.44 62.22
Gap Creek 1 500 0.15
Kambara 1 2819.62 0.53 424 0.3 0.5 0.1 0.8 0.38 94.34 18.87
Kambara 1 2985 0.17 432 1.2 0.7 0.1 1.9 0.63 411.8 58.82
Kambara 1 3015 0.44 444 0.1 0.3 0.1 0.4 0.25 68.18 22.73
Kambara 1 3045 0.37 444 0.1 0.2 0.1 0.3 0.33 54.05 27.03
Kambara 1 3135 0.23 0.2 86.96
Matches Spring 1 1234 0.32 425 0.02 0.1 0.12 0.17 31.25
Matches Spring 1 1234 0.32 425 0.02 0.1 0.12 0.167 31.25
Matches Spring 1 1237 0.3 383 0.03 0.02 0.44 0.05 0.6 6.667 146.7
Matches Spring 1 1346 0.1 444 0.03 0.05 1.27 0.08 0.38 50 1270
Selenops 1 780 0.17
Selenops 1 795 0.17
Selenops 1 810 0.12
Selenops 1 825 0.13
Selenops 1 840 0.11
Selenops 1 843 0.15
Selenops 1 855 0.18
Selenops 1 870 0.15
Selenops 1 885 0.18
Selenops 1 900 0.13
Selenops 1 915 0.14
C104 0.44 422 0.05 0.33 0.38 88
C83 0.93 412
I171 1.08 429 0.05 1.8 1.85 171
I172 0.45 415 0.06 1.15 1.21 217
P421 1.2 422 0.07 2.25 2.32 192
P491 1.36 418 0.09 1.36 1.45 110
P492 0.65 423 0.02 0.46 0.48 73
P2181 0.76 422 0.05 1.62 1.67 219
E151 1 429 0.02 0.34 0.36 36
E152 2.08 410 0.14 4.4 4.54 218
E201 1.32 416 1.08 7.02 8.1 613
GSWA72335 1.89 428 0.05 2.83 2.88 149
Eromophilia 1 1.49 428 0.14 1.96 2.1 131
Eromophilia 1 3.1 427 0.16 5.06 5.22 163
Eromophilia 1 1.08 0.36 3.03 3.39 280
 Bongabinni Member
o
Well/Hole ID Top Depth (m) TOC % Tmax ( C) S1 (kg/ton) S2 (kg/ton) S3 (kg/ton) S1+S2 S2/S3 PI PC HI OI
Frankenstein 1 1960 0.16
Frankenstein 1 1980 0.16
Frankenstein 1 2000 0.14
Frankenstein 1 2015 0.2
Frankenstein 1 2026.98 0.1
Frankenstein 1 2033 0.12
Frankenstein 1 2051 0.03
Frankenstein 1 2069 0.08
Frankenstein 1 2087 0.09
Frankenstein 1 2100.55 0.17
Frankenstein 1 2105 0.08
Frankenstein 1 2121 0.32
Frankenstein 1 2123 0.07
Frankenstein 1 2141 0.1
Frankenstein 1 2159 0.07
Frankenstein 1 2166.73 0.15
Frankenstein 1 2177 0.08
Frankenstein 1 2186 0.07
Frankenstein 1 2195 0.07
Leo 1 1460 0.24
Leo 1 1475 0.16
Leo 1 1490 0.2
Leo 1 1505 0.13
Leo 1 1520 0.15
Leo 1 1535 0.12
Sally May 1 1521.2 0.08
Sally May 1 1548.7 0.08
Sally May 1 1564.1 0.2
 Goldwyer Formation
Well Tectonic Region Depth (mRT) TOC % Tmax (°C) S1 (kg/ton) S2 (kg/ton) S3 (kg/ton) S1+S2 S2/S3 PI PC HI OI
Acacia 1 Barbwire Terrace 858.67 0.97
Acacia 1 Barbwire Terrace 861.6 0.18
Acacia 1 Barbwire Terrace 865.4 0.13
Acacia 1 Barbwire Terrace 870 0.13
Acacia 1 Barbwire Terrace 874 0.19
Acacia 1 Barbwire Terrace 874.5 0.19
Acacia 1 Barbwire Terrace 878.2 0.15
Acacia 1 Barbwire Terrace 893.45 0.17
Acacia 1 Barbwire Terrace 904.9 0.16
Acacia 1 Barbwire Terrace 917.1 0.21
Acacia 1 Barbwire Terrace 917.62 0.17
Acacia 1 Barbwire Terrace 927.3 0.24
Acacia 1 Barbwire Terrace 935 0.19
Acacia 1 Barbwire Terrace 935 0.19
Acacia 1 Barbwire Terrace 944.9 0.37
Acacia 1 Barbwire Terrace 960.05 0.54
Acacia 1 Barbwire Terrace 974 0.71 432 0.22 0.88 0.14 1.1 0.2 123.9 19.72
Acacia 1 Barbwire Terrace 978.82 0.76
Acacia 1 Barbwire Terrace 987.19 0.74
Acacia 1 Barbwire Terrace 993.2 1.92 438 0.49 6.24 0.88 6.73 0.073 325 45.83
Acacia 1 Barbwire Terrace 995 1.02 438 0.22 2.39 0.88 2.61 0.084 234.3 86.27
Acacia 1 Barbwire Terrace 995 1.24
Acacia 1 Barbwire Terrace 1003.7 0.6
Acacia 1 Barbwire Terrace 1009.95 0.97
Acacia 1 Barbwire Terrace 1014 0.91 433 0.11 1.92 0.09 2.03 0.054 211 9.89
Acacia 1 Barbwire Terrace 1019.49 1.24
Acacia 1 Barbwire Terrace 1019.5 1.01 438 0.19 2.06 0.65 2.25 0.084 204 64.36
Acacia 1 Barbwire Terrace 1026 0.73
Acacia 1 Barbwire Terrace 1033 0.87 435 0.14 1.6 0.15 1.74 0.08 183.9 17.24
Acacia 1 Barbwire Terrace 1037.8 0.33
Acacia 1 Barbwire Terrace 1037.8 1.3
Acacia 1 Barbwire Terrace 1043 0.15
Acacia 1 Barbwire Terrace 1048.2 0.2
Anna Plains 1 Willara Sub-basin 1143 0.49
Antares 1 Mowla Terrace 1255 0.18
Antares 1 Mowla Terrace 1260.5 0.13
Antares 1 Mowla Terrace 1278 0.13
Antares 1 Mowla Terrace 1292 0.15
Antares 1 Mowla Terrace 1295 0.11
Aquila 1 Broome Platform 859 0.22
Aquila 1 Broome Platform 893 0.23
Aquila 1 Broome Platform 942 0.56 434 0.11 0.68 0.26 0.79 0.14 121.4 46.43
Aquila 1 Broome Platform 956 0.27
Aquila 1 Broome Platform 976.5 0.25
Aquila 1 Broome Platform 1020 0.22
Aquila 1 Broome Platform 1020.5 0.3
Aquila 1 Broome Platform 1030 0.28
Aquila 1 Broome Platform 1040 0.36
Aquila 1 Broome Platform 1050 0.81 436 0.39 1.24 0.33 1.63 0.24 0.14 153.1 40.74
Aquila 1 Broome Platform 1053 0.31
Aquila 1 Broome Platform 1055 1.07 438 0.56 2.36 0.34 2.92 0.19 0.24 220.6 31.78
Aquila 1 Broome Platform 1060 1.39 438 0.87 3.66 0.34 4.53 0.19 0.38 263.3 24.46
Aquila 1 Broome Platform 1060 1.11 437 0.7 2.17 0.33 2.87 0.24 0.24 195.5 29.73
Aquila 1 Broome Platform 1060 0.65 0.63 1.28 0.51
Aquila 1 Broome Platform 1065 1.55 439 1 3.89 0.35 4.89 0.2 0.41 251 22.58
Aquila 1 Broome Platform 1069.5 1.91 436 1.25 4.42 0.56 5.67 0.22 231.4 29.32
Aquila 1 Broome Platform 1070 1.52 438 0.89 4.05 0.32 4.94 0.18 0.41 266.4 21.05
Aquila 1 Broome Platform 1070 0.95 435 0.72 2.2 0.4 2.92 0.25 0.24 231.6 42.11
Aquila 1 Broome Platform 1080 0.74 435 0.44 1.23 0.36 1.67 0.26 0.14 166.2 48.65
Aquila 1 Broome Platform 1087.5 0.89 430 0.41 0.81 0.58 1.22 0.34 91.01 65.17
Aquila 1 Broome Platform 1090 0.83 435 0.55 1.5 0.45 2.05 0.27 0.17 180.7 54.22
Aquila 1 Broome Platform 1100 0.85 435 0.52 1.39 0.5 1.91 0.27 0.16 163.5 58.82
Aquila 1 Broome Platform 1110 1.23 436 1.02 2.55 0.38 3.57 0.29 0.3 207.3 30.89
Aquila 1 Broome Platform 1118.5 3.2 436 2.71 7.02 0.82 9.73 0.28 219.4 25.63
Aquila 1 Broome Platform 1120 1.46 431 1.51 3.1 0.51 4.61 0.33 0.38 212.3 34.93
Aquila 1 Broome Platform 1120 0.45 0.64 1.09 0.41
Aquila 1 Broome Platform 1130 1.04 430 0.9 1.65 0.47 2.55 0.35 0.21 158.7 45.19
Aquila 1 Broome Platform 1140 1.16 426 1.21 2.38 0.56 3.59 0.34 0.3 205.2 48.28
Aquila 1 Broome Platform 1141 2.22 433 1.12 2.75 0.65 3.87 0.29 123.9 29.28
Aquila 1 Broome Platform 1150 1.18 429 1.09 1.92 0.71 3.01 0.36 0.25 162.7 60.17
Aquila 1 Broome Platform 1160 0.87 426 0.71 1.24 0.58 1.95 0.36 0.16 142.5 66.67
Aquila 1 Broome Platform 1164 0.77 432 0.31 0.67 0.42 0.98 0.32 87.01 54.55
Blackstone 1 Lennard Shelf 2621.3 0.22
Blackstone 1 Lennard Shelf 2651.8 0.24
Blackstone 1 Lennard Shelf 2674.3 0.14
Blackstone 1 Lennard Shelf 2676.3 0.14
Blackstone 1 Lennard Shelf 2676.9 0.14
Blackstone 1 Lennard Shelf 2677.4 0.13
Blackstone 1 Lennard Shelf 2677.5 0.12
Blackstone 1 Lennard Shelf 2678.1 0.14
Blackstone 1 Lennard Shelf 2678.7 0.13
Blackstone 1 Lennard Shelf 2679.3 0.15
Blackstone 1 Lennard Shelf 2680 0.14
Blackstone 1 Lennard Shelf 2682.2 0.2
Blackstone 1 Lennard Shelf 2712.7 0.22
Blackstone 1 Lennard Shelf 2738.5 0.14
Blackstone 1 Lennard Shelf 2740.6 0.06
Blackstone 1 Lennard Shelf 2741.2 0.16
Blackstone 1 Lennard Shelf 2741.2 0.16
Blackstone 1 Lennard Shelf 2742 0.13
Blackstone 1 Lennard Shelf 2743.2 0.24
Blackstone 1 Lennard Shelf 2773.7 0.23
Blackstone 1 Lennard Shelf 2804.2 0.24
Blackstone 1 Lennard Shelf 2832.7 0.16
Blackstone 1 Lennard Shelf 2833.1 0.17
Blackstone 1 Lennard Shelf 2833.5 0.13
Blackstone 1 Lennard Shelf 2833.9 0.18
Blackstone 1 Lennard Shelf 2834.5 0.19
Blackstone 1 Lennard Shelf 2834.6 0.23
Blackstone 1 Lennard Shelf 2834.9 0.16
Blackstone 1 Lennard Shelf 2835.7 0.17
Blackstone 1 Lennard Shelf 2836.3 0.18
Blackstone 1 Lennard Shelf 2836.9 0.08
Blackstone 1 Lennard Shelf 2865.1 0.22
Blackstone 1 Lennard Shelf 2895.6 0.24
Blackstone 1 Lennard Shelf 2912.7 0.13
Blackstone 1 Lennard Shelf 2913.3 0.11
Blackstone 1 Lennard Shelf 2926.1 0.21
Blackstone 1 Lennard Shelf 2956.6 0.22
Blackstone 1 Lennard Shelf 2978.23 0.11
Blackstone 1 Lennard Shelf 3008.8 0.1
Blackstone 1 Lennard Shelf 3045 0.15
Blackstone 1 Lennard Shelf 3045.6 0.23
Blackstone 1 Lennard Shelf 3048.6 0
Calamia 1 Willara Sub-basin 958 0.11
Calamia 1 Willara Sub-basin 979.5 0.05
Calamia 1 Willara Sub-basin 1002.5 0.2
Calamia 1 Willara Sub-basin 1008 0.18
Calamia 1 Willara Sub-basin 1027 0.44
Calamia 1 Willara Sub-basin 1175.5 0.15
Calamia 1 Willara Sub-basin 1218 0.2
Calamia 1 Willara Sub-basin 1224.5 0.2
Canopus 1 Mowla Terrace 1230 0.18
Canopus 1 Mowla Terrace 1230 0.18
Canopus 1 Mowla Terrace 1240 0.23
Canopus 1 Mowla Terrace 1240 0.21
Canopus 1 Mowla Terrace 1240 0.23
Canopus 1 Mowla Terrace 1250 0.34
Canopus 1 Mowla Terrace 1250 0.34
Canopus 1 Mowla Terrace 1260 0.32
Canopus 1 Mowla Terrace 1260 0.23
Canopus 1 Mowla Terrace 1260 0.32
Canopus 1 Mowla Terrace 1270 0.22
Canopus 1 Mowla Terrace 1270 0.22
Canopus 1 Mowla Terrace 1280 0.35
Canopus 1 Mowla Terrace 1285 0.24
Canopus 1 Mowla Terrace 1285 0.24
Canopus 1 Mowla Terrace 1290 0.26
Canopus 1 Mowla Terrace 1290 0.26
Canopus 1 Mowla Terrace 1300 0.26
Canopus 1 Mowla Terrace 1305 0.24
Canopus 1 Mowla Terrace 1305 0.24
Canopus 1 Mowla Terrace 1315 0.22
Canopus 1 Mowla Terrace 1315 0.22
Canopus 1 Mowla Terrace 1320 0.36
Canopus 1 Mowla Terrace 1320 0.3
Canopus 1 Mowla Terrace 1320 0.36
Canopus 1 Mowla Terrace 1325 0.26
Canopus 1 Mowla Terrace 1335 0.29
Canopus 1 Mowla Terrace 1340 0.33
Canopus 1 Mowla Terrace 1345 0.31
Canopus 1 Mowla Terrace 1350 0.4
Canopus 1 Mowla Terrace 1360 0.41
Canopus 1 Mowla Terrace 1360 0.33
Canopus 1 Mowla Terrace 1370 0.4
Canopus 1 Mowla Terrace 1380 0.4
Canopus 1 Mowla Terrace 1380 0.34
Canopus 1 Mowla Terrace 1380 0.4
Canopus 1 Mowla Terrace 1390 0.3
Canopus 1 Mowla Terrace 1400 0.29
Canopus 1 Mowla Terrace 1400 0.32
Canopus 1 Mowla Terrace 1410 0.4
Canopus 1 Mowla Terrace 1420 0.42
Canopus 1 Mowla Terrace 1420 0.36
Canopus 1 Mowla Terrace 1430 0.37
Canopus 1 Mowla Terrace 1440 0.3
Canopus 1 Mowla Terrace 1440 0.25
Canopus 1 Mowla Terrace 1450 0.27
Canopus 1 Mowla Terrace 1460 0.3
Canopus 1 Mowla Terrace 1460 0.34
Canopus 1 Mowla Terrace 1470 0.32
Canopus 1 Mowla Terrace 1475 0.31
Canopus 1 Mowla Terrace 1480 0.28
Canopus 1 Mowla Terrace 1485 0.29
Canopus 1 Mowla Terrace 1490 0.31
Canopus 1 Mowla Terrace 1500 0.23
Canopus 1 Mowla Terrace 1510 0.27
Canopus 1 Mowla Terrace 1520 0.29
Canopus 1 Mowla Terrace 1520 0.28
Canopus 1 Mowla Terrace 1530 0.28
Canopus 1 Mowla Terrace 1540 0.3
Canopus 1 Mowla Terrace 1540 0.32
Canopus 1 Mowla Terrace 1550 0.35
Canopus 1 Mowla Terrace 1560 0.32
Canopus 1 Mowla Terrace 1560 0.33
Canopus 1 Mowla Terrace 1570 0.43
Canopus 1 Mowla Terrace 1580 0.32
Canopus 1 Mowla Terrace 1590 0.4
Canopus 1 Mowla Terrace 1590 0.38
Canopus 1 Mowla Terrace 1600 0.34
Canopus 1 Mowla Terrace 1610 0.36
Canopus 1 Mowla Terrace 1610 0.43
Canopus 1 Mowla Terrace 1620 0.39
Canopus 1 Mowla Terrace 1650 0.81 420 0.57 0.77 0.55 1.34 0.43 0.11 95.06 67.9
Canopus 1 Mowla Terrace 1670 1.16 425 0.89 1.01 0.64 1.9 0.47 0.16 87.07 55.17
Canopus 1 Mowla Terrace 1690 0.75 434 0.34 0.37 0.62 0.71 0.48 0.06 49.33 82.67
Canopus 1 Mowla Terrace 1695 1.4 430 0.6 1.09 0.29 1.69 0.36 0.14 77.86 20.71
Canopus 1 Mowla Terrace 1710 0.36
Canopus 1 Mowla Terrace 1730 0.4
Carina 1 Broome Platform 1560 0.36
Carina 1 Broome Platform 1580 0.32
Carina 1 Broome Platform 1600 0.5 419 0.49 0.71 0.73 1.2 0.41 0.1 142 146
Carina 1 Broome Platform 1620? 0.18
Carina 1 Broome Platform 1640? 0.35
Contention Heights 1 Ryan Shelf 1508.76 0.26
Contention Heights 1 Ryan Shelf 1530.1 0.19
Crystal Creek 1 Mowla Terrace 1818 0.19
Crystal Creek 1 Mowla Terrace 1890 0.53 445 0.21 1.12 0.1 1.33 0.16 0.11 211.3 18.87
Crystal Creek 1 Mowla Terrace 1923.2 0.36
Crystal Creek 1 Mowla Terrace 1940 0.61
Crystal Creek 1 Mowla Terrace 1983 0.62 445 0.34 1.2 0.23 1.54 0.22 0.13 193.5 37.1
Crystal Creek 1 Mowla Terrace 2082.7 0.33
Crystal Creek 1 Mowla Terrace 2117 0.17
Crystal Creek 1 Mowla Terrace 2166.5 1.08 432 0.51 1.34 0.3 1.85 0.28 0.15 124.1 27.78
Crystal Creek 1 Mowla Terrace 2181 3.37 453 1.51 2.61 0.05 4.12 0.37 0.34 77.45 1.484
Crystal Creek 1 Mowla Terrace 2202.5 0.58 418 0.24 0.52 0.05 0.76 0.32 0.06 89.66 8.621
Crystal Creek 1 Mowla Terrace 2230.5 0.69 417 0.29 0.46 0.23 0.75 0.39 0.06 66.67 33.33
Crystal Creek 1 Mowla Terrace 2246.5 0.94 429 0.34 0.55 0.26 0.89 0.38 0.07 58.51 27.66
Cudalgarra 2 Willara Sub-basin 1413.53 0
Cudalgarra 2 Willara Sub-basin 1462.16 0
Cudalgarra 2 Willara Sub-basin 1469.7 301 0.02 1.39 0.02
Cudalgarra 2 Willara Sub-basin 1471.33 0
Cudalgarra 2 Willara Sub-basin 1477.55 0
Cudalgarra 2 Willara Sub-basin 1480.7 249 0.04 1.97 0.04
Darriwell 1 Willara Sub-basin 1575 0.16
Darriwell 1 Willara Sub-basin 1575 0.19
Darriwell 1 Willara Sub-basin 1576.5
Darriwell 1 Willara Sub-basin 1588.5 0.13
Dodonea 1 Barbwire Terrace 1537.8 3.6 441 1.11 23.56 0.4 24.61 0.04 2.05 652.8 11.11
Dodonea 1 Barbwire Terrace 1538.28 1.7 442 0.75 8.34 1.07 9.09 0.08 0.75 490.6 62.94
Dodonea 1 Barbwire Terrace 1538.43 2.2 438 0.8 13.3 1.49 14.1 0.06 1.18 604.5 67.73
Dodonea 1 Barbwire Terrace 1539.67 1.8 442 0.94 10.3 1.23 11.24 0.08 0.93 572.2 68.33
Dodonea 1 Barbwire Terrace 1539.98 2.1 441 0.81 12.8 1.49 13.61 0.06 1.13 609.5 70.95
Dodonea 1 Barbwire Terrace 1540.1 1.05 440 1.25 28.3 1.24 29.55 0.04 2.45 2695 118.1
Dodonea 1 Barbwire Terrace 1540.1 4.05 440 1.25 28.32 29.57 0.04 699.3
Dodonea 1 Barbwire Terrace 1541.59 0.6 443 0.18 1.79 1.3 1.97 0.09 0.16 298.3 216.7
Dodonea 1 Barbwire Terrace 1541.95 0.83
Dodonea 1 Barbwire Terrace 1542.31 0.87 444 0.26 2.64 0.86 2.9 0.09 0.24 303.4 98.85
Dodonea 1 Barbwire Terrace 1542.31 0.67
Dodonea 1 Barbwire Terrace 1542.48 1.05 442 0.35 2.98 0.88 3.33 0.11 0.28 283.8 83.81
Dodonea 1 Barbwire Terrace 1542.95 0.83 443 0.24 2.22 1 2.46 0.1 0.2 267.5 120.5
Dodonea 1 Barbwire Terrace 1546.24 1.4 0
Dodonea 1 Barbwire Terrace 1546.77 1.5 0
Dodonea 1 Barbwire Terrace 1548.24 1.4 444 0.59 6.83 1.28 7.42 0.08 0.62 487.9 91.43
Dodonea 1 Barbwire Terrace 1548.77 1.5 443 0.62 7.07 1.82 7.69 0.08 0.64 471.3 121.3
Dodonea 1 Barbwire Terrace 1548.99 0.74 441 0.64 2.06 1.96 2.7 0.24 0.22 278.4 264.9
Edgar Range 1 Broome Platform 947.9 0.17
Edgar Range 1 Broome Platform 948.6 0.15
Edgar Range 1 Broome Platform 948.8 0.17
Edgar Range 1 Broome Platform 949.1 0.19
Edgar Range 1 Broome Platform 949.5 0.29
Edgar Range 1 Broome Platform 950.4 0.29
Edgar Range 1 Broome Platform 951 0.2
Edgar Range 1 Broome Platform 978.4 0.24
Edgar Range 1 Broome Platform 1012 0.25
Edgar Range 1 Broome Platform 1039 0.19
Edgar Range 1 Broome Platform 1042.7 0.29
Edgar Range 1 Broome Platform 1043.6 0.36
Edgar Range 1 Broome Platform 1044.2 0.26
Edgar Range 1 Broome Platform 1044.9 0.4
Edgar Range 1 Broome Platform 1045.2 0.42
Edgar Range 1 Broome Platform 1048.5 0.26
Edgar Range 1 Broome Platform 1048.5 0.32
Edgar Range 1 Broome Platform 1080.5 0.23
Edgar Range 1 Broome Platform 1136 0.27
Edgar Range 1 Broome Platform 1144.5 0.33
Edgar Range 1 Broome Platform 1188.7 0.16
Edgar Range 1 Broome Platform 1188.9 0.12
Edgar Range 1 Broome Platform 1189.6 0.16
Edgar Range 1 Broome Platform 1190.5 1.1 0.1 0.2 0.3 0.33 18.18
Edgar Range 1 Broome Platform 1191.2 0.68 0.6 0.9 1.5 0.4 132.4
Edgar Range 1 Broome Platform 1214.6 0.34
Edgar Range 1 Broome Platform 1264.9 0
Edgar Range 1 Broome Platform 1271 1.68 435 1.19 2.2 0.68 3.39 0.35 131 40.48
Edgar Range 1 Broome Platform 1306.1 1.17 435 0.93 1.15 0.83 2.08 0.45 98.29 70.94
Edgar Range 1 Broome Platform 1313.6
Edgar Range 1 Broome Platform 1348.8 0.65 425 0.49 0.49 0.82 0.98 0.5 75.38 126.2
Edgar Range 1 Broome Platform 1350 0.16
Frankenstein 1 Anketell Shelf 2267 0.07
Frankenstein 1 Anketell Shelf 2285 0.18
Frankenstein 1 Anketell Shelf 2303 0.25
Frankenstein 1 Anketell Shelf 2321 0.32
Frankenstein 1 Anketell Shelf 2327.14 0.3
Frankenstein 1 Anketell Shelf 2339 0.25
Frankenstein 1 Anketell Shelf 2347.09 0.37
Frankenstein 1 Anketell Shelf 2357 0.25
Frankenstein 1 Anketell Shelf 2375 0.27
Great Sandy 1 Willara Sub-basin 1535 0.16
Great Sandy 1 Willara Sub-basin 1545 0.17
Great Sandy 1 Willara Sub-basin 1555 0.19
Great Sandy 1 Willara Sub-basin 1565 0.21
Great Sandy 1 Willara Sub-basin 1575 0.18
Great Sandy 1 Willara Sub-basin 1585 0.2
Great Sandy 1 Willara Sub-basin 1595 0.19
Great Sandy 1 Willara Sub-basin 1600 0.23
Great Sandy 1 Willara Sub-basin 1605 0.24
Great Sandy 1 Willara Sub-basin 1608 0.23
Great Sandy 1 Willara Sub-basin 1608 0.23
Great Sandy 1 Willara Sub-basin 1615 0.18
Great Sandy 1 Willara Sub-basin 1615 0.19
Great Sandy 1 Willara Sub-basin 1623 0.18
Great Sandy 1 Willara Sub-basin 1623 0.18
Great Sandy 1 Willara Sub-basin 1625 0.2
Great Sandy 1 Willara Sub-basin 1635 0.23
Great Sandy 1 Willara Sub-basin 1635 0.3
Great Sandy 1 Willara Sub-basin 1640 0.23
Great Sandy 1 Willara Sub-basin 1640 0.23
Great Sandy 1 Willara Sub-basin 1645 0.25
Great Sandy 1 Willara Sub-basin 1645 0.21
Great Sandy 1 Willara Sub-basin 1653 0.25
Great Sandy 1 Willara Sub-basin 1653 0.25
Great Sandy 1 Willara Sub-basin 1655 0.2
Great Sandy 1 Willara Sub-basin 1665 0.18
Great Sandy 1 Willara Sub-basin 1668 0.18
Great Sandy 1 Willara Sub-basin 1668 0.18
Hedonia 1 Broome Platform 922 0.48 0.61 1.09 0.44
Hedonia 1 Broome Platform 930 0.64 439 0.26 0.96 0.27 1.22 0.21 0.1 150 42.19
Hedonia 1 Broome Platform 935.4 0.6 430 0.3 0.69 0.33 0.99 0.3 115 55
Hedonia 1 Broome Platform 936.9 0.58 0.61 1.19 0.49
Hedonia 1 Broome Platform 945 1.19 430 0.84 2.09 0.42 2.93 0.29 175.6 35.29
Hedonia 1 Broome Platform 960 2.07 435 1.72 4.28 0.41 6 0.29 206.8 19.81
Hedonia 1 Broome Platform 975 1.48 427 1.3 2.69 0.62 3.99 0.33 181.8 41.89
Hedonia 1 Broome Platform 976
Hedonia 1 Broome Platform 990 1.19 435 0.91 1.93 0.26 2.84 0.32 162.2 21.85
Hedonia 1 Broome Platform 1005 1.19 427 0.95 1.69 0.37 2.64 0.36 142 31.09
Hedonia 1 Broome Platform 1020 0.84 430 0.49 0.95 0.3 1.44 0.34 113.1 35.71
Hedonia 1 Broome Platform 1020 0.99
Hedonia 1 Broome Platform 1022.5 1 432 0.84 1.14 0.14 1.98 0.42 114 14
Hedonia 1 Broome Platform 1022.5 0.84
Hedonia 1 Broome Platform 1046.7 0.99 428 0.58 0.86 0.62 1.44 0.4 86.87 62.63
Hilltop 1 Broome Platform 1052.5 2.1 433 1.68 4.74 0.25 6.42 0.26 0.53 225.7 11.9
Hilltop 1 Broome Platform 1079.1 1.45 438 1.1 2.37 0.31 3.47 0.32 0.29 163.4 21.38
Hilltop 1 Broome Platform 1098 2.5 432 2.29 4.51 0.34 6.8 0.34 0.56 180.4 13.6
Hilltop 1 Broome Platform 1128.1 1.3 438 0.92 1.42 0.28 2.34 0.39 0.19 109.2 21.54
Hilltop 1 Broome Platform 1170 0.8 447 0.42 0.54 0.31 0.96 0.44 0.08 67.5 38.75
Kidson 1 Kidson Sub-basin 4284.4 2.1 8 5.8 0 13.8 0.58 276.2
Kidson 1 Kidson Sub-basin 4284.4 0.6 3.4 4
Kidson 1 Kidson Sub-basin 4297.7 2.4 7.2 6.7 0 13.9 0.52 279.2
Kidson 1 Kidson Sub-basin 4312.9 1.5 7.1 6.5 0 13.6 0.52 433.3
Kidson 1 Kidson Sub-basin 4328.2 3 7.6 8.6 0 16.2 0.47 286.7
Kidson 1 Kidson Sub-basin 4343.4 3.5 9.2 9.5 0 18.7 0.49 271.4
Kidson 1 Kidson Sub-basin 4358.6 3.4 9.8 8.8 0 18.6 0.53 258.8
Kidson 1 Kidson Sub-basin 4358.6 0.9 5.7 6.6
Kidson 1 Kidson Sub-basin 4364.4 0.18
Kidson 1 Kidson Sub-basin 4364.43 0.07
Kidson 1 Kidson Sub-basin 4365 0.32
Kidson 1 Kidson Sub-basin 4365 0.24
Kidson 1 Kidson Sub-basin 4365.7 0.27
Kidson 1 Kidson Sub-basin 4366 0.23
Kidson 1 Kidson Sub-basin 4366.3 0.24
Kidson 1 Kidson Sub-basin 4366.9 0.2
Kidson 1 Kidson Sub-basin 4367.5 0.29
Kidson 1 Kidson Sub-basin 4367.5 0.2
Kidson 1 Kidson Sub-basin 4367.8 0.24
Kidson 1 Kidson Sub-basin 4368.1 0.2
Kidson 1 Kidson Sub-basin 4368.2 0.25
Kidson 1 Kidson Sub-basin 4368.7 0.27
Kidson 1 Kidson Sub-basin 4368.75 0
Kidson 1 Kidson Sub-basin 4373.9 0.2
Kidson 1 Kidson Sub-basin 4389.1 3.8 10.5 10 0 20.5 0.51 263.2
Kidson 1 Kidson Sub-basin 4404.4 3 9.2 8.4 0 17.6 0.52 280
Kunzea 1 Broome Platform 354.42 1.34 436 0.07 10.28 10.35 0.01 767.2
Kunzea 1 Broome Platform 373.9 1.98 431 0.28 13.5 0.53 13.78 0.02 681.8 26.77
Kunzea 1 Broome Platform 379.95 4.8 434 0.65 41.45 42.1 0.02 863.5
Kunzea 1 Broome Platform 390.18 1.84 437 0.16 12.5 12.66 0.01 679.3
Kunzea 1 Broome Platform 390.5 1.69 427 0.19 10.48 0.67 10.67 0.018 620.1 39.64
Kunzea 1 Broome Platform 409.9 0.15
Kunzea 1 Broome Platform 422.9 0.11
Kunzea 1 Broome Platform 449.8 0.15
Leo 1 Willara Sub-basin 1655 0.15
Leo 1 Willara Sub-basin 1670 0.16
Leo 1 Willara Sub-basin 1685 0.23
Leo 1 Willara Sub-basin 1700 0.2
Leo 1 Willara Sub-basin 1715 0.14
Leo 1 Willara Sub-basin 1730 0.1
Leo 1 Willara Sub-basin 1745 0.12
Leo 1 Willara Sub-basin 1760 0.15
Leo 1 Willara Sub-basin 1775 0.12
Leo 1 Willara Sub-basin 1790 0.15
Leo 1 Willara Sub-basin 1805 0.14
Leo 1 Willara Sub-basin 1820 0.17
Leo 1 Willara Sub-basin 1835 0.19
Leo 1 Willara Sub-basin 1850 0.18
Leo 1 Willara Sub-basin 1865 0.22
Leo 1 Willara Sub-basin 1880 0.18
Leo 1 Willara Sub-basin 1895 0.17
Leo 1 Willara Sub-basin 1910 0.21
Leo 1 Willara Sub-basin 1925 0.16
Leo 1 Willara Sub-basin 1940 0.23
Matches Spring 1 Mowla Terrace 2280 0.4
Matches Spring 1 Mowla Terrace 2293.7 0.24
Matches Spring 1 Mowla Terrace 2321.1 0.21
Matches Spring 1 Mowla Terrace 2340.9 0.3
Matches Spring 1 Mowla Terrace 2348.5 0.32
Matches Spring 1 Mowla Terrace 2366.8 0.26
Matches Spring 1 Mowla Terrace 2383.6 0.26
Matches Spring 1 Mowla Terrace 2398.8 0.53 442 0.3 1.44 0.01 1.74 0.17 271.7 1.887
Matches Spring 1 Mowla Terrace 2404.9 1.52 443 2.3 9.56 0.49 11.86 0.19 628.9 32.24
Matches Spring 1 Mowla Terrace 2407.5 0.45 0.62 1.07 0.42
Matches Spring 1 Mowla Terrace 2408 1.77 443 1.78 9.93 0.85 11.71 0.15 561 48.02
Matches Spring 1 Mowla Terrace 2408.8 3.7 1.3
Matches Spring 1 Mowla Terrace 2409 0.52 0.64 1.16 0.45
Matches Spring 1 Mowla Terrace 2409.9 0.45 0.62 1.07 0.42
Matches Spring 1 Mowla Terrace 2430 1.88 443 1.18 5.1 0.64 6.28 0.19 271.3 34.04
Matches Spring 1 Mowla Terrace 2448.7 0.3
Matches Spring 1 Mowla Terrace 2609.1 0.8
Matches Spring 1 Mowla Terrace 2730.9
Matches Spring 1 Mowla Terrace 2732.6 1.38 441 1.09 2.35 0.68 3.44 0.32 170.3 49.28
Matches Spring 1 Mowla Terrace 2733.9 0.21 0.47 0.68 0.31
Matches Spring 1 Mowla Terrace 2750 0.16
Matches Spring 1 Mowla Terrace 2753 0.14
Matches Spring 1 Mowla Terrace 2754.3 0.3
Matches Spring 1 Mowla Terrace 2754.8 0.62 430 0.78 0.91 0.4 1.69 0.46 146.8 64.52
Matches Spring 1 Mowla Terrace 2761.5 1.2 0.3
Matches Spring 1 Mowla Terrace 2764.6 1.48 439 0.96 2.43 0.6 3.39 0.28 164.2 40.54
Matches Spring 1 Mowla Terrace 2769.1 2.11 441 1.3 3.21 0.83 4.51 0.29 152.1 39.34
Matches Spring 1 Mowla Terrace 2801.2 0.82 445 0.56 0.93 0.72 1.49 0.38 113.4 87.8
Matches Spring 1 Mowla Terrace 2811.8 0.34
Matches Spring 1 Mowla Terrace 2833.8 0.6 0.1
McLarty 1 Broome Platform 1685.5 1.9 7.4 3.1 10.5 0.7 163.2
McLarty 1 Broome Platform 1688.59 1.22 391 11.91 2.69 1.91 14.6 0.82 220.5 156.6
McLarty 1 Broome Platform 1694.7 1.9 6.3 2.7 9 0.7 142.1
McLarty 1 Broome Platform 1697.74 1.14 393 11.01 2.54 1.85 13.55 0.81 222.8 162.3
McLarty 1 Broome Platform 1703.8 2 6.6 3.4 10 0.66 170
McLarty 1 Broome Platform 1706.88 0.93 419 10.14 2.99 1.84 13.13 0.77 321.5 197.8
McLarty 1 Broome Platform 1713 1.1 5 2.3 7.3 0.68 209.1
McLarty 1 Broome Platform 1716.02 1.02 394 11.56 2.74 1.88 14.3 0.81 268.6 184.3
McLarty 1 Broome Platform 1722.1 1.6 5.8 2.5 8.3 0.7 156.3
McLarty 1 Broome Platform 1725.17 1.13 408 13.01 3.09 1.86 16.1 0.81 273.5 164.6
McLarty 1 Broome Platform 1731.3 1.8 6.1 2.8 8.9 0.69 155.6
McLarty 1 Broome Platform 1734.31 1.05 396 13.47 2.8 1.81 16.27 0.83 266.7 172.4
McLarty 1 Broome Platform 1740.4 2 6.3 2.9 9.2 0.68 145
McLarty 1 Broome Platform 1743.46 1.03 400 11.38 2.48 1.75 13.86 0.82 240.8 169.9
McLarty 1 Broome Platform 1749.5 1.3 6.6 3.2 9.8 0.67 246.2
McLarty 1 Broome Platform 1752.6 1.1 398 9.1 2.11 1.57 11.21 0.81 191.8 142.7
McLarty 1 Broome Platform 1757.88 0.1
McLarty 1 Broome Platform 1757.93 0.1
McLarty 1 Broome Platform 1758 0.1
McLarty 1 Broome Platform 1758.09 0.31
McLarty 1 Broome Platform 1758.1 0.1
McLarty 1 Broome Platform 1758.2 0.2
McLarty 1 Broome Platform 1758.4 0.2
McLarty 1 Broome Platform 1758.6 0.1
McLarty 1 Broome Platform 1758.7 0.38
McLarty 1 Broome Platform 1758.8 0.2
McLarty 1 Broome Platform 1759 0.11
McLarty 1 Broome Platform 1759 0.1
McLarty 1 Broome Platform 1759.1 0.2
McLarty 1 Broome Platform 1759.3 0.2
McLarty 1 Broome Platform 1759.5 0.1
McLarty 1 Broome Platform 1759.6 0.22
McLarty 1 Broome Platform 1759.6 0.2
McLarty 1 Broome Platform 1759.8 0.2
McLarty 1 Broome Platform 1759.9 0.2
McLarty 1 Broome Platform 1760.1 0.2
McLarty 1 Broome Platform 1760.2 0.1
McLarty 1 Broome Platform 1760.4 0.2
McLarty 1 Broome Platform 1760.5 0.3
McLarty 1 Broome Platform 1761.74 1.1 388 11.63 2.66 1.04 14.29 0.81 241.8 94.55
McLarty 1 Broome Platform 1766.3 1.9 6.9 3.2 10.1 0.68 168.4
McLarty 1 Broome Platform 1770.89 0.78 417 9.01 2.28 1.54 11.29 0.8 292.3 197.4
McLarty 1 Broome Platform 1780.03 0.6 424 9.56 2.76 1.34 12.32 0.78 460 223.3
McLarty 1 Broome Platform 1789.18 0.56 420 5.65 1.84 1.73 7.49 0.75 328.6 308.9
McLarty 1 Broome Platform 1798.32 0.53 395 4.98 1.39 1.77 6.37 0.78 262.3 334
McLarty 1 Broome Platform 1807.46 0.81 398 10.93 2.39 1.52 13.32 0.82 295.1 187.7
McLarty 1 Broome Platform 1816.61 1.14 427 13.93 3.59 1.64 17.52 0.8 314.9 143.9
McLarty 1 Broome Platform 1823.3 2.6 5.8 3.1 8.9 0.65 119.2
McLarty 1 Broome Platform 1825.75 0.92 423 10.82 2.74 1.55 13.56 0.8 297.8 168.5
McLarty 1 Broome Platform 1834.9 0.93 429 10.27 3.37 1.43 13.64 0.75 362.4 153.8
McLarty 1 Broome Platform 1844.04 0.96 429 9.55 3.17 1.72 12.72 0.75 330.2 179.2
McLarty 1 Broome Platform 1853.18 0.83 434 7.1 2.29 0.88 9.39 0.76 275.9 106
McLarty 1 Broome Platform 1862.33 0.69 426 7.93 2.57 1.23 10.5 0.76 372.5 178.3
McLarty 1 Broome Platform 1871.47 1.05 427 9.65 2.49 1.46 12.14 0.79 237.1 139
McLarty 1 Broome Platform 1880.62 1.15 422 11.6 3.21 1.69 14.81 0.78 279.1 147
McLarty 1 Broome Platform 1883.7 2.4 0.1 0.1 0.2 0.5 4.167
McLarty 1 Broome Platform 1891.28 2.2 427 15.98 5.7 1.32 21.68 0.74 259.1 60
McLarty 1 Broome Platform 1892.8 3.6 0.4 0.2 0.6 0.67 5.556
McLarty 1 Broome Platform 1892.9 0.2
McLarty 1 Broome Platform 1893 0.16
McLarty 1 Broome Platform 1893 0.3
McLarty 1 Broome Platform 1893.1 0.22
McLarty 1 Broome Platform 1893.1 0.2
McLarty 1 Broome Platform 1893.5 0.2
McLarty 1 Broome Platform 1893.6 0.2
McLarty 1 Broome Platform 1893.9 0.2
McLarty 1 Broome Platform 1894 0.3
McLarty 1 Broome Platform 1895.9 1.75 384 21.19 3.04 0.75 24.23 0.87 173.7 42.86
McLarty 1 Broome Platform 1897.38 1.82 384 15.01 3.88 0.58 18.89 0.79 213.2 31.87
McLarty 1 Broome Platform 1900.43 2.05 398 17.33 4.9 1.1 22.23 0.78 239 53.66
McLarty 1 Broome Platform 1901.95 2.4 429 18.21 4.77 1.52 22.98 0.79 198.8 63.33
McLarty 1 Broome Platform 1901.95 1.91 429 18.21 4.77 1.52 22.98 0.79 249.7 79.58
McLarty 1 Broome Platform 1903.48 2.5 430 20.46 6.16 1.54 26.62 0.77 246.4 61.6
McLarty 1 Broome Platform 1903.48 2.21 430 20.46 6.16 1.54 26.62 0.77 278.7 69.68
McLarty 1 Broome Platform 1905 1.66 422 13.51 3.51 1.6 17.02 0.79 211.4 96.39
McLarty 1 Broome Platform 1905 2.3 6 3.2 9.2 0.65 139.1
McLarty 1 Broome Platform 1905 1.66 422 13.5 3.51 1.6 17.01 0.79 211.4 96.39
McLarty 1 Broome Platform 1914.14 1.89 422 14.72 3.66 1.63 18.38 0.8 193.7 86.24
McLarty 1 Broome Platform 1917.2 1.87 428 16.91 3.91 1.8 20.82 0.81 209.1 96.26
McLarty 1 Broome Platform 1923.29 1.85 427 14.86 3.6 1.64 18.46 0.8 194.6 88.65
McLarty 1 Broome Platform 1932.43 1.95 430 15.03 3.95 1.63 18.98 0.79 202.6 83.59
McLarty 1 Broome Platform 1941.58 1.41 430 11.93 3.47 1.49 15.4 0.77 246.1 105.7
McLarty 1 Broome Platform 1941.6 4.7 8.8 4.4 13.2 0.67 93.62
McLarty 1 Broome Platform 1950.72 1.86 429 13.45 3.9 1.39 17.35 0.78 209.7 74.73
McLarty 1 Broome Platform 1959.86 1.56 416 12.94 3.34 1.48 16.28 0.79 214.1 94.87
McLarty 1 Broome Platform 1961.4 1.22 428 12.95 3.1 2.29 16.05 0.81 254.1 187.7
McLarty 1 Broome Platform 1961.4 1.4 7.3 3.1 10.4 0.7 221.4
McLarty 1 Broome Platform 1969.01 2.2 428 3.06 4.48 1.69 7.54 0.41 203.6 76.82
McLarty 1 Broome Platform 1973.6 1.9 429 16.8 3.55 1.84 20.35 0.83 186.8 96.84
McLarty 1 Broome Platform 1978.15 2.2 419 17.08 4.37 1.62 21.45 0.8 198.6 73.64
McLarty 1 Broome Platform 1978.2 1.7 6.9 2.9 9.8 0.7 170.6
McLarty 1 Broome Platform 1987.3 2.15 428 14.15 3.54 1.42 17.69 0.8 164.7 66.05
McLarty 1 Broome Platform 1996 0.22
McLarty 1 Broome Platform 1996.4 2 2.7 3.3 6 0.45 165
McLarty 1 Broome Platform 1996.44 3.1 429 19.12 4.64 1.5 23.76 0.8 149.7 48.39
McLarty 1 Broome Platform 1998 2.71 428 19.14 3.92 1.97 23.06 0.83 144.6 72.69
McLarty 1 Broome Platform 2002.2 3 1.4 1.4 2.8 0.5 46.67
McLarty 1 Broome Platform 2002.4 1.8 1.6 1.3 2.9 0.55 72.22
McLarty 1 Broome Platform 2002.5 1.6 2.6 3.3 5.9 0.44 206.3
McLarty 1 Broome Platform 2002.7 2 2.8 3.5 6.3 0.44 175
McLarty 1 Broome Platform 2002.8 3.1 2.8 3.2 6 0.47 103.2
McLarty 1 Broome Platform 2002.9 2.48 433 3.43 2.65 0.73 6.08 0.56 106.9 29.44
McLarty 1 Broome Platform 2003 3.1 2.3 3 5.3 0.43 96.77
McLarty 1 Broome Platform 2003.1 3 2.1 2.1 4.2 0.5 70
McLarty 1 Broome Platform 2003.15 3.6 441 3.06 3.99 0.53 7.05 0.43 110.8 14.72
McLarty 1 Broome Platform 2003.3 2.5 2.2 3 5.2 0.42 120
McLarty 1 Broome Platform 2003.5 2.2 2.5 2.9 5.4 0.46 131.8
McLarty 1 Broome Platform 2003.6 2.3 2.8 3.7 6.5 0.43 160.9
McLarty 1 Broome Platform 2003.8 2.3 3.1 4.6 7.7 0.4 200
McLarty 1 Broome Platform 2003.9 2.6 1.8 2.1 3.9 0.46 80.77
McLarty 1 Broome Platform 2004.1 3 6.6 2.6 9.2 0.72 86.67
McLarty 1 Broome Platform 2005.58 2.35 432 17.06 4.06 1.21 21.12 0.81 172.8 51.49
McLarty 1 Broome Platform 2005.6 2.9 1.9 2.4 4.3 0.44 82.76
McLarty 1 Broome Platform 2014.73 1.14 425 12.22 2.64 1.8 14.86 0.82 231.6 157.9
McLarty 1 Broome Platform 2017.7 1.7 6.5 2.7 9.2 0.71 158.8
McLarty 1 Broome Platform 2023.87 0.93 424 12.4 2.29 1.83 14.69 0.84 246.2 196.8
McLarty 1 Broome Platform 2033.02 0.83 398 5.44 1.42 1.72 6.86 0.79 171.1 207.2
McLarty 1 Broome Platform 2036.1 4 9.9 4.5 14.4 0.69 112.5
McLarty 1 Broome Platform 2042.16 0.78 425 7.43 1.93 1.6 9.36 0.79 247.4 205.1
McLarty 1 Broome Platform 2051.3 1.46 417 11.91 3.11 1.82 15.02 0.79 213 124.7
McLarty 1 Broome Platform 2060 0.25
Munro 1 Willara Sub-basin 1606.3 0.24
Munro 1 Willara Sub-basin 1612.39 0.26
Munro 1 Willara Sub-basin 1618.5 0.18
Munro 1 Willara Sub-basin 1621.54 0.28
Munro 1 Willara Sub-basin 1630.68 0.21
Munro 1 Willara Sub-basin 1636.8 0.15
Munro 1 Willara Sub-basin 1639.82 0.2
Munro 1 Willara Sub-basin 1648.97 0.23
Munro 1 Willara Sub-basin 1652 0.7 345 0.01 0.04 0.7 0.05 0.2 5.714 100
Munro 1 Willara Sub-basin 1652 0.31
Munro 1 Willara Sub-basin 1658.11 0.24
Munro 1 Willara Sub-basin 1667.26 0.21
Munro 1 Willara Sub-basin 1676.4 0.24
Munro 1 Willara Sub-basin 1685.54 0.34
Munro 1 Willara Sub-basin 1694.69 0.23
Munro 1 Willara Sub-basin 1703.83 0.24
Munro 1 Willara Sub-basin 1710 0.17
Munro 1 Willara Sub-basin 1712.98 0.35
Munro 1 Willara Sub-basin 1722.1 0.16
Munro 1 Willara Sub-basin 1722.12 0.3
Munro 1 Willara Sub-basin 1731.26 0.23
Munro 1 Willara Sub-basin 1740.41 0.23
Munro 1 Willara Sub-basin 1744.9 0.3
Munro 1 Willara Sub-basin 1746.5 0.17
Munro 1 Willara Sub-basin 1749.55 0.25
Munro 1 Willara Sub-basin 1758.7 0.22
Munro 1 Willara Sub-basin 1758.7 0.15
Munro 1 Willara Sub-basin 1758.7 0.22
Munro 1 Willara Sub-basin 1767.84 0.25
Munro 1 Willara Sub-basin 1776.98 0.23
Munro 1 Willara Sub-basin 1786.13 0.24
Munro 1 Willara Sub-basin 1795.27 0.25
Musca 1 Broome Platform 1510 0.17
Musca 1 Broome Platform 1510 0.1
Musca 1 Broome Platform 1520 0.24
Musca 1 Broome Platform 1520 0.1
Musca 1 Broome Platform 1520 0.14
Musca 1 Broome Platform 1530 0.29
Musca 1 Broome Platform 1530 0.14
Musca 1 Broome Platform 1530 0.24
Musca 1 Broome Platform 1535 0.24
Musca 1 Broome Platform 1535 0.27
Parda 1 Broome Platform 1277.1 0.18
Parda 1 Broome Platform 1286.3 0.15
Parda 1 Broome Platform 1292.3 0.22
Parda 1 Broome Platform 1307.6 0.29
Parda 1 Broome Platform 1310.7 0.18
Parda 1 Broome Platform 1314.9 0.17
Parda 1 Broome Platform 1315 0.27
Parda 1 Broome Platform 1315.5 0.19
Parda 1 Broome Platform 1316 0.3
Parda 1 Broome Platform 1316.7 0.28
Parda 1 Broome Platform 1316.8 0.22
Parda 1 Broome Platform 1317.3 0.3
Parda 1 Broome Platform 1322.8 0.24
Parda 1 Broome Platform 1332 0.17
Parda 1 Broome Platform 1338.1 0.26
Parda 1 Broome Platform 1365.5 0.3
Parda 1 Broome Platform 1380.7 0.23
Parda 1 Broome Platform 1396 0.23
Parda 1 Broome Platform 1411.2 0.28
Parda 1 Broome Platform 1426.6 0.29
Parda 1 Broome Platform 1441.7 0.25
Parda 1 Broome Platform 1456.9 0.25
Parda 1 Broome Platform 1472.2 0.25
Parda 1 Broome Platform 1486.5 0.27
Parda 1 Broome Platform 1486.5 0.3
Parda 1 Broome Platform 1487.1 0.22
Parda 1 Broome Platform 1487.7 0.28
Parda 1 Broome Platform 1488.3 0.24
Parda 1 Broome Platform 1488.9 0.06
Patience 2 Kidson Sub-basin 2934 0.61 426 0.44 3.01 6.08 3.45 0.128 493.4 996.7
Patience 2 Kidson Sub-basin 2943 0.31
Patience 2 Kidson Sub-basin 2958 0.26
Patience 2 Kidson Sub-basin 2970 0.27
Patience 2 Kidson Sub-basin 2985 0.32
Patience 2 Kidson Sub-basin 3018 0.56 436 0.44 1.74 3.5 2.18 0.202 310.7 625
Patience 2 Kidson Sub-basin 3033 0.47
Patience 2 Kidson Sub-basin 3057 0.37
Patience 2 Kidson Sub-basin 3075 0.29
Patience 2 Kidson Sub-basin 3114 0.49
Patience 2 Kidson Sub-basin 3153 0.33
Pegasus 1 Munro Arch 2347.5 0.2
Pegasus 1 Munro Arch 2352.5 0.3
Pegasus 1 Munro Arch 2357.5 0.2
Pegasus 1 Munro Arch 2357.5 0.3
Pegasus 1 Munro Arch 2360 0.2
Pegasus 1 Munro Arch 2362.5 0.2
Pegasus 1 Munro Arch 2365 0.2
Pegasus 1 Munro Arch 2370 0.3
Pegasus 1 Munro Arch 2375 0.3
Pegasus 1 Munro Arch 2385 0.4
Pegasus 1 Munro Arch 2390 0.2
Pegasus 1 Munro Arch 2390 0.4
Pegasus 1 Munro Arch 2392.5 0.4
Pegasus 1 Munro Arch 2487.5 0.2
Pegasus 1 Munro Arch 2605.5 0.3
Percival 1 Barbwire Terrace 2038 0.19
Percival 1 Barbwire Terrace 2038.6 0.12
Percival 1 Barbwire Terrace 2042.25 0.66 446 0.29 0.7 0.08 0.99 106.1 12.12
Percival 1 Barbwire Terrace 2045.2 0.67 453 0.41 0.63 0.14 1.04 94.03 20.9
Percival 1 Barbwire Terrace 2049.51 1 448 0.44 0.89 0.07 1.33 89 7
Percival 1 Barbwire Terrace 2067.95 0.59 434 0.19 0.44 0.1 0.63 0.05 74.58 16.95
Percival 1 Barbwire Terrace 2147.5 0.13
Percival 1 Barbwire Terrace 2152.5 0.25
Percival 1 Barbwire Terrace 2165 0.31
Percival 1 Barbwire Terrace 2172.5 0.27
Percival 1 Barbwire Terrace 2177.5 0.16
Percival 1 Barbwire Terrace 2180 0.21
Pictor 1 Mowla Terrace 1070 0.18
Pictor 1 Mowla Terrace 1160 0.31
Pictor 1 Mowla Terrace 1250 0.22
Pictor 1 Mowla Terrace 1340 0.21
Pictor 1 Mowla Terrace 1355 0.2
Pictor 1 Mowla Terrace 1370 0.2
Pictor 1 Mowla Terrace 1385 0.2
Pictor 1 Mowla Terrace 1400 0.32
Pictor 1 Mowla Terrace 1430 0.83 429 0.58 0.51 0.56 1.09 0.53 0.09 61.45 67.47
Pictor 1 Mowla Terrace 1445 1.54 434 1.15 1.31 0.3 2.46 0.47 0.2 85.06 19.48
Pictor 1 Mowla Terrace 1460 0.92 435 0.52 0.54 0.24 1.06 0.49 0.09 58.7 26.09
Pictor 1 Mowla Terrace 1475 0.46
Pictor 1 Mowla Terrace 1490 0.32
Pictor 1 Mowla Terrace 1505 0.42
Solanum 1 Barbwire Terrace 284.9 0.37
Solanum 1 Barbwire Terrace 287.9 0.16
Solanum 1 Barbwire Terrace 289.07 0.48
Solanum 1 Barbwire Terrace 292.6 0.28
Solanum 1 Barbwire Terrace 294.58 0.21
Solanum 1 Barbwire Terrace 298.25 0.34
Solanum 1 Barbwire Terrace 301.65 0.91 439 0.18 4.36 0.36 4.54 0.04 479.1 39.56
Solanum 1 Barbwire Terrace 302.8 0.42
Solanum 1 Barbwire Terrace 303 0.44
Solanum 1 Barbwire Terrace 303.24 0.95 440 0.21 5.14 0.45 5.35 0.04 541.1 47.37
Solanum 1 Barbwire Terrace 304.3 0.2
Solanum 1 Barbwire Terrace 306.5 1.08 439 0.16 6.21 0.33 6.37 0.03 575 30.56
Solanum 1 Barbwire Terrace 308.2 1.31 438 0.34 7.99 0.29 8.33 0.04 609.9 22.14
Solanum 1 Barbwire Terrace 308.7 1.74 440 0.32 12.04 0.4 12.36 0.03 692 22.99
Solanum 1 Barbwire Terrace 309 2.44 438 0.48 19.31 0.32 19.79 0.02 791.4 13.11
Solanum 1 Barbwire Terrace 309.7 0.16
Solanum 1 Barbwire Terrace 311.36 0.35
Solanum 1 Barbwire Terrace 311.9 1.51 438 0.61 17.58 0.31 18.19 0.03 1164 20.53
Solanum 1 Barbwire Terrace 312.24 0.37
Solanum 1 Barbwire Terrace 312.64 1.28 439 0.5 14.97 0.32 15.47 0.03 1170 25
Solanum 1 Barbwire Terrace 314.6 0.78 439 0.3 9.12 0.27 9.42 0.03 1169 34.62
Solanum 1 Barbwire Terrace 314.8 1.13 438 0.36 13.2 0.43 13.56 0.03 1168 38.05
Solanum 1 Barbwire Terrace 315.24 1.22 439 0.4 14.32 0.39 14.72 0.03 1174 31.97
Solanum 1 Barbwire Terrace 315.34 2.32 442 0.63 16.59 17.22 0.04 715.1
Solanum 1 Barbwire Terrace 315.59 0.77 437 0.33 8.96 0.34 9.29 0.04 1164 44.16
Solanum 1 Barbwire Terrace 316.6 0.81 439 0.38 9.36 0.38 9.74 0.04 1156 46.91
Solanum 1 Barbwire Terrace 317.33 0.18
Solanum 1 Barbwire Terrace 317.6 1 438 0.16 4.64 0.26 4.8 0.03 464 26
Solanum 1 Barbwire Terrace 318 1.55 439 0.26 7.66 0.23 7.92 0.03 494.2 14.84
Solanum 1 Barbwire Terrace 318.4 1.06 437 0.2 4.82 0.24 5.02 0.04 454.7 22.64
Solanum 1 Barbwire Terrace 319.1 1.25 436 0.23 5.96 0.13 6.19 0.04 476.8 10.4
Solanum 1 Barbwire Terrace 319.94 0.86 436 0.15 3.64 0.13 3.79 0.04 423.3 15.12
Solanum 1 Barbwire Terrace 320.42 0.55 436 0.07 1.88 0.33 1.95 0.04 341.8 60
Solanum 1 Barbwire Terrace 322.02 0.47
Solanum 1 Barbwire Terrace 326.43 0.85 441 0.17 3.44 3.61 0.05 404.7
Solanum 1 Barbwire Terrace 326.8 1.88 440 0.31 11.6 0.39 11.91 0.03 617 20.74
Solanum 1 Barbwire Terrace 329.8 0.25
Solanum 1 Barbwire Terrace 346 0.16
Solanum 1 Barbwire Terrace 346.39 0.13
Solanum 1 Barbwire Terrace 361 0.13
Solanum 1 Barbwire Terrace 397.63 0.26
Solanum 1 Barbwire Terrace 401 0.18
Solanum 1 Barbwire Terrace 406.1 0.14
Solanum 1 Barbwire Terrace 407 0.18
Solanum 1 Barbwire Terrace 449.1 0.12
Solanum 1 Barbwire Terrace 471.2 0.23
Solanum 1 Barbwire Terrace 484.05 0.74 435 3.5 1.49 0.37 4.99 0.7 201.4 50
Solanum 1 Barbwire Terrace 490.7 0.77 437 0.31 1.81 0.34 2.12 0.15 235.1 44.16
Solanum 1 Barbwire Terrace 498.4 0.71 434 0.26 1.13 0.43 1.39 0.19 159.2 60.56
Solanum 1 Barbwire Terrace 504.5 1.06 435 0.41 2.58 0.45 2.99 0.14 243.4 42.45
Solanum 1 Barbwire Terrace 515 1.16 435 0.42 2.57 0.37 2.99 0.14 221.6 31.9
Solanum 1 Barbwire Terrace 519.58 1.17 437 0.67 2.52 3.19 0.21 215.4
Solanum 1 Barbwire Terrace 521.07 0.74 436 0.23 1.48 0.4 1.71 0.13 200 54.05
Solanum 1 Barbwire Terrace 523.3 1.15 436 0.39 2.35 0.29 2.74 0.14 204.3 25.22
Solanum 1 Barbwire Terrace 526 0.55 426 0.13 0.72 0.54 0.85 0.15 130.9 98.18
Solanum 1 Barbwire Terrace 526.2 1.34 433 0.48 2.82 0.3 3.3 0.15 210.4 22.39
Solanum 1 Barbwire Terrace 531.8 1.1 433 0.54 2.35 0.26 2.89 0.19 213.6 23.64
Solanum 1 Barbwire Terrace 532 1.09 434 0.45 2.13 0.3 2.58 0.17 195.4 27.52
Solanum 1 Barbwire Terrace 539 0.8 435 0.42 1.59 0.34 2.01 0.21 198.8 42.5
Solanum 1 Barbwire Terrace 543.4 0.59 431 0.21 0.91 0.22 1.12 0.19 154.2 37.29
Solanum 1 Barbwire Terrace 544.18 0.75 436 0.22 1.25 0.12 1.47 0.15 166.7 16
Solanum 1 Barbwire Terrace 549.3 0.63 434 0.17 0.85 0.18 1.02 0.17 134.9 28.57
Solanum 1 Barbwire Terrace 551.5 0.57 437 0.12 0.66 0.13 0.78 0.15 115.8 22.81
Solanum 1 Barbwire Terrace 552 0.6 436 0.2 0.83 0.1 1.03 0.19 138.3 16.67
Solanum 1 Barbwire Terrace 553.5 0.51 431 0.23 0.85 0.13 1.08 0.21 166.7 25.49
Solanum 1 Barbwire Terrace 556.04 0.22
Solanum 1 Barbwire Terrace 557 0.79 432 0.23 0.99 0.19 1.22 0.19 125.3 24.05
Solanum 1 Barbwire Terrace 557.5 0.42
Solanum 1 Barbwire Terrace 558.1 0.88 435 0.48 1.49 0.21 1.97 0.24 169.3 23.86
Solanum 1 Barbwire Terrace 559.7 0.65 433 0.34 0.96 0.24 1.3 0.26 147.7 36.92
Sunshine 1 Broome Platform 692 0.24
Sunshine 1 Broome Platform 694 0.13
Sunshine 1 Broome Platform 697 0.19
Sunshine 1 Broome Platform 700 0.17
Sunshine 1 Broome Platform 702 0.19
Sunshine 1 Broome Platform 703 0.22
Sunshine 1 Broome Platform 706 0.18
Sunshine 1 Broome Platform 709 0.16
Sunshine 1 Broome Platform 712 0.21
Sunshine 1 Broome Platform 715 0.21
Sunshine 1 Broome Platform 718 0.24
Sunshine 1 Broome Platform 721 0.3
Sunshine 1 Broome Platform 724 0.23
Sunshine 1 Broome Platform 727 0.27
Sunshine 1 Broome Platform 730 0.36
Sunshine 1 Broome Platform 733 0.44
Sunshine 1 Broome Platform 736 0.38
Sunshine 1 Broome Platform 738 0.39
Thangoo 1A Kidson Sub-basin 869.3 0.42 0.66 1.08 0.39
Thangoo 1A Kidson Sub-basin 959.2 0.45 0.55 1 0.45
Thangoo 1A Kidson Sub-basin 959.52 2.57 441 1.43 5.88 0.63 7.31 0.2 228.8 24.51
Thangoo 1A Kidson Sub-basin 961.05 3.4 443 1.86 7.86 1.03 9.72 0.19 231.2 30.29
Vela 1 Broome Platform 1860 0.1
Vela 1 Broome Platform 1867 0.23
Vela 1 Broome Platform 1870 0.14
Vela 1 Broome Platform 1890 0.14
Vela 1 Broome Platform 1900 0.14
Vela 1 Broome Platform 1910 0.14
Whistler 1 Broome Platform 835 0.11
Whistler 1 Broome Platform 838 0.17
Whistler 1 Broome Platform 839 0.23
Whistler 1 Broome Platform 841 0.17
Whistler 1 Broome Platform 844 0.16
Whistler 1 Broome Platform 847 0.17
Whistler 1 Broome Platform 850 0.23
Whistler 1 Broome Platform 853 0.29
Whistler 1 Broome Platform 853.4 0.23
Whistler 1 Broome Platform 856 0.2
Whistler 1 Broome Platform 859 0.28
Whistler 1 Broome Platform 862 0.29
Whistler 1 Broome Platform 865 0.51 440 0.14 1.5 0.67 1.64 0.09 294.1 131.4
Whistler 1 Broome Platform 867.8 0.63 438 0.31 1.99 0.19 2.3 0.13 315.9 30.16
Whistler 1 Broome Platform 868 0.38
Whistler 1 Broome Platform 871 0.44
Whistler 1 Broome Platform 874 0.37
Whistler 1 Broome Platform 877 0.45
Whistler 1 Broome Platform 880 0.42
Whistler 1 Broome Platform 883 0.43
Willara 1 Willara Sub-basin 1874.52 0.22
Willara 1 Willara Sub-basin 1880.6 0.22
Willara 1 Willara Sub-basin 1880.6 0.12
Willara 1 Willara Sub-basin 1881.2 0.1
Willara 1 Willara Sub-basin 1881.22 0.23
Willara 1 Willara Sub-basin 1881.8 0.1
Willara 1 Willara Sub-basin 1883.1 0.2
Willara 1 Willara Sub-basin 1886.71 0.46
Willara 1 Willara Sub-basin 1895.8 0.36
Willara 1 Willara Sub-basin 1895.86 0.36
Willara 1 Willara Sub-basin 1905 0.24
Willara 1 Willara Sub-basin 1911.1 0.23
Willara 1 Willara Sub-basin 1914.14 0.18
Willara 1 Willara Sub-basin 1923.29 0.15
Willara 1 Willara Sub-basin 1926.3 0.14
Willara 1 Willara Sub-basin 1932.43 0.45
Willara 1 Willara Sub-basin 1941.58 0.73 430 0.11 1.01 1.15 1.12 0.1 138.4 157.5
Willara 1 Willara Sub-basin 1941.6 0.13
Willara 1 Willara Sub-basin 1950.72 0.26
Willara 1 Willara Sub-basin 1953.8 0.15
Willara 1 Willara Sub-basin 1956.8 0.27
Willara 1 Willara Sub-basin 1959.86 0.19
Willara 1 Willara Sub-basin 1966 0.14
Willara 1 Willara Sub-basin 1969.01 0.23
Willara 1 Willara Sub-basin 1972 0.16
Willara 1 Willara Sub-basin 1978.15 0.2
Willara 1 Willara Sub-basin 1981.2 0.19
Willara 1 Willara Sub-basin 1987.3 0.2
Willara 1 Willara Sub-basin 1996.44 0.24
Willara 1 Willara Sub-basin 1999.5 0.14
Willara 1 Willara Sub-basin 2005.58 0.21
Willara 1 Willara Sub-basin 2014.73 0.25
Willara 1 Willara Sub-basin 2014.8 0.16
Willara 1 Willara Sub-basin 2023.87 0.2
Willara 1 Willara Sub-basin 2026.9 0.13
Willara 1 Willara Sub-basin 2033.02 0.2
Willara 1 Willara Sub-basin 2042.16 0.19
Willara 1 Willara Sub-basin 2042.2 0.2
Willara 1 Willara Sub-basin 2051.3 0.24
Willara 1 Willara Sub-basin 2060.45 0.25
Willara 1 Willara Sub-basin 2069.59 0.26
Willara 1 Willara Sub-basin 2072.6 0.17
Willara 1 Willara Sub-basin 2078.74 0.23
Willara 1 Willara Sub-basin 2082.7 0.2
Willara 1 Willara Sub-basin 2083.3 0.11
Willara 1 Willara Sub-basin 2084.5 0.24
Willara 1 Willara Sub-basin 2085.1 0.1
Willara 1 Willara Sub-basin 2085.7 0.3
Willara 1 Willara Sub-basin 2085.7 0.03
Willara 1 Willara Sub-basin 2086.4 0.02
Willara 1 Willara Sub-basin 2087.88 0.22
Willara 1 Willara Sub-basin 2097.02 0.26
Willara 1 Willara Sub-basin 2103.1 0.2
Willara 1 Willara Sub-basin 2106.17 0.22
Willara 1 Willara Sub-basin 2115.31 0.27
Willara 1 Willara Sub-basin 2124.46 0.25
Willara 1 Willara Sub-basin 2133.6 0.21
Willara 1 Willara Sub-basin 2133.6 0.2
Willara 1 Willara Sub-basin 2142.74 0.32
Willara 1 Willara Sub-basin 2151.89 0.22
Willara 1 Willara Sub-basin 2161.03 0.25
Willara 1 Willara Sub-basin 2164.1 0.2
Willara 1 Willara Sub-basin 2170.18 0.26
Willara 1 Willara Sub-basin 2179.32 0.24
Willara 1 Willara Sub-basin 2188.46 0.37
Willara 1 Willara Sub-basin 2194.6 0.3
Willara 1 Willara Sub-basin 2197.61 0.47
Willara 1 Willara Sub-basin 2206.75 0.4
Willara 1 Willara Sub-basin 2215.9 0.31
Willara 1 Willara Sub-basin 2225 0.2
Willara 1 Willara Sub-basin 2225.04 0.55 236 0.19 0.07 0.52 0.26 0.73 12.73 94.55
Willara 1 Willara Sub-basin 2234.18 0.44
Willara 1 Willara Sub-basin 2243.33 0.28
Willara 1 Willara Sub-basin 2252.47 0.24
Willara 1 Willara Sub-basin 2255.5 0.2
Willara 1 Willara Sub-basin 2261.62 0.27
Willara 1 Willara Sub-basin 2263.7 0.6 0.1 0.1 0 0.2 0.5 16.67
Willara 1 Willara Sub-basin 2264.4 0.11
Willara 1 Willara Sub-basin 2264.66 0.27
Willara 1 Willara Sub-basin 2264.9 0.38
Willara 1 Willara Sub-basin 2273.81 0.31
Willara 1 Willara Sub-basin 2282.95 0.31
Willara 1 Willara Sub-basin 2286 0.1
Willara 1 Willara Sub-basin 2292.1 0.35
Willara 1 Willara Sub-basin 2304.29 0.29
Willara 1 Willara Sub-basin 2313.43 0.37
Willara 1 Willara Sub-basin 2316.5 0.3
Willara 1 Willara Sub-basin 2322.58 0.35
Willara 1 Willara Sub-basin 2331.72 0.31
Willara 1 Willara Sub-basin 2340.86 0.22
Willara 1 Willara Sub-basin 2347 0.2
Willara 1 Willara Sub-basin 2350.01 0.32
Willara 1 Willara Sub-basin 2368.3 0.28
Willara 1 Willara Sub-basin 2374.8 0.4
Willara 1 Willara Sub-basin 2376.8 0.1
Willara 1 Willara Sub-basin 2377.4 0.06
Willara 1 Willara Sub-basin 2377.44 0.35
Willara 1 Willara Sub-basin 2378 0.08
Willara 1 Willara Sub-basin 2386.58 0.23
Willara 1 Willara Sub-basin 2395.73 0.28
Willara 1 Willara Sub-basin 2404.87 0.27
Willara 1 Willara Sub-basin 2407.9 0.2
Willara 1 Willara Sub-basin 2414.02 0.24
Willara 1 Willara Sub-basin 2423.16 0.24
Willara 1 Willara Sub-basin 2432.3 0.29
Willara 1 Willara Sub-basin 2438.4 0.3
Willara 1 Willara Sub-basin 2450.59 0.25
Willara 1 Willara Sub-basin 2459.74 0.3
Willara 1 Willara Sub-basin 2468.9 0.41
Willara 1 Willara Sub-basin 2478.02 0.26
Willara 1 Willara Sub-basin 2496.31 0.27
Willara 1 Willara Sub-basin 2499.4 0.1
Willara 1 Willara Sub-basin 2505.46 0.23
Willara 1 Willara Sub-basin 2514.6 0.27
Willara 1 Willara Sub-basin 2523.74 0.31
Willara 1 Willara Sub-basin 2529.8 0.3
Willara 1 Willara Sub-basin 2532.89 0.32
Willara 1 Willara Sub-basin 2542.03 0.35
Willara 1 Willara Sub-basin 2545.7 0.4
Willara 1 Willara Sub-basin 2548.1 0.1
Willara 1 Willara Sub-basin 2548.2 0
Willara 1 Willara Sub-basin 2551.18 0.25
Willara 1 Willara Sub-basin 2560.3 0.23
Willara 1 Willara Sub-basin 2560.32 0.38
Willara 1 Willara Sub-basin 2569.46 0.33
Willara 1 Willara Sub-basin 2578.61 0.3
Willara 1 Willara Sub-basin 2587.75 0.26
Willara 1 Willara Sub-basin 2590.8 0.25
Willara 1 Willara Sub-basin 2596.9 0.24
Wilson Cliffs 1 Kidson Sub-basin 2679.2 0.09
Wilson Cliffs 1 Kidson Sub-basin 2680 0.09
Wilson Cliffs 1 Kidson Sub-basin 2680.7 0.19
Wilson Cliffs 1 Kidson Sub-basin 2681 0.03
Wilson Cliffs 1 Kidson Sub-basin 2682.1 0.09
Wilson Cliffs 1 Kidson Sub-basin 2683.5 0.06
Wilson Cliffs 1 Kidson Sub-basin 2685.3 0.42
Wilson Cliffs 1 Kidson Sub-basin 2685.3 0.42
Wilson Cliffs 1 Kidson Sub-basin 2712.72 0.64
Wilson Cliffs 1 Kidson Sub-basin 2715.8 0.75 1.1 0.2 0 1.3 0.85 26.67
Wilson Cliffs 1 Kidson Sub-basin 2734.1 0.42
Wilson Cliffs 1 Kidson Sub-basin 2746.2 0.37
Wilson Cliffs 1 Kidson Sub-basin 2770.7 0.46
Wilson Cliffs 1 Kidson Sub-basin 2779.8 3.21 430 2.48 2.96 7.48 5.44 0.46 92.21 233
Wilson Cliffs 1 Kidson Sub-basin 2779.8 0.7 1.1 0.02 1.12 2.857
Wilson Cliffs 1 Kidson Sub-basin 2780.5 0.4
Wilson Cliffs 1 Kidson Sub-basin 2781 0.08
Wilson Cliffs 1 Kidson Sub-basin 2782 0.22
Wilson Cliffs 1 Kidson Sub-basin 2782.2 0.08
Wilson Cliffs 1 Kidson Sub-basin 2783.4 0.09
Wilson Cliffs 1 Kidson Sub-basin 2804.16 0.43
Wilson Cliffs 1 Kidson Sub-basin 2807.2 0.35
Wilson Cliffs 1 Kidson Sub-basin 2813.3 0.37
 Goldwyer Formation Geochemical Logs
Acacia 1 Acacia 1 Acacia 1: Tmax vs DEPTH Acacia 1: PI vs DEPTH Acacia 1: S1 & S2 vs DEPTH
800 800 800 800 800 60 1000.00
Immature Mature
G. prisca ends at 793.25mRT TOC Immature Mature Postmature
S1
Postmature

Oil Window
TYPE I

Condensate - Wet Gas Zone

Type II

Dry Gas Window

PY S2 Type I oil oil prone oil-prone
850 850 850 850 prone
900.00 usually lacustrine Oil
HI Window

Condensate - Wet Gas Zone

850 Goldwyer Fm
? Unit 2 ? OI 50
900 900 900 900 800.00

900 950 950 950

950 700.00

40 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
1000 1000 1000 Mixed type II/III

Depth (m)
Depth (m)

usually marine
1000

S2 mg/g
? Unit 1 ? 600.00
oil/gas prone
950
No logs below 535mRT
1050 1050 1050 1050
500.00
30

Title
DEPTH ( m )
DEPTH ( m )
1000
1100 1100 1100 1100
400.00 TYPE II-III
oil-gas-prone

1150 1150 1150 1150 20

1050 300.00
Type III gas
Willara Fm ?
prone
1200 1200 1200 1200
200.00 TYPE III

0.2 kg/tonne S2
Acacia Sandstone ? gas-prone
1100
1250 1250 10
1250 1250 Dry Gas Window
0.5% TOC

100.00

kg/ton Dry gas prone TYPE IV

1150 1300 1300 1300 1300 inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 2.0 4.0 6.0 8.0 10.0 0.00
PI (S1/S1+S2) 0 400 425 450 475 500
PY GR Tmax (oC) 0.00 100.00 200.00 300.00 400.00
wt% 0 2 4 6 8 10 12 14 16 Tmax (oC)

TOC wt%

Blackstone 1 Blackstone 1 Blackstone 1: Tmax vs DEPTH Blackstone 1: PI vs DEPTH Blackstone 1: S1 & S2 vs DEPTH
2500 2500 2500 2500 2500 60 1000.00
Immature Postmature
S1 Immature Mature Postmature

Condensate - Wet Gas Zone

TOC PY

Oil Window

Dry Gas Window

Type II
S2 TYPE I
0.5% TOC

Type I oil oil prone oil-prone

HI prone 900.00 usually lacustrine Oil
Window
2600 2600 2600 2600 2600 Dry Gas Window

Condensate - Wet Gas Zone

OI
50
Goldwyer - Unit 2 ?
800.00

2700 2700 2700 2700 2700

700.00
40 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

Depth (m)
Depth (m)

oil-prone

S2 mg/g
Mixed type II/III usually marine
2800 2800 2800 2800 2800 oil/gas prone 600.00

30

Title
DEPTH ( m )

DEPTH ( m )
500.00

2900 2900 2900 2900 2900

400.00 TYPE II-III

oil-gas-prone

3000 3000 3000 3000 3000 20

300.00
Type III gas
prone

200.00 TYPE III

3100 3100 3100 3100 3100

0.2 kg/tonne S2
gas-prone
10
G. prisca not found within paly - 15/09/14 Title 100.00

3200 3200 3200 3200 3200 Dry gas prone TYPE IV

0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 225.0 275.0 325.0 375.0 425.0 475.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 0.2 0.4 0.6 0.8 1.0 inert
0.00
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 50.00 100.00 150.00 200.00 250.00 0 400 425 450 475 500
Title 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Canopus 1 Canopus 1 Canopus 1: Tmax v DEPTH Canopus 1: PI vs DEPTH Canopus 1: S1 & S2 vs DEPTH
1200 1200 1200 1200 1200 60 1000.00
Immature Mature
TOC S1 Postmature
Condensate - Wet Gas Zone
Oil Window

Dry Gas Window

Type II TYPE I
PY S2 Type I oil oil prone oil-prone
0.5% TOC

prone 900.00 usually lacustrine Oil

HI Window

Condensate - Wet Gas Zone

1300 1300 1300 1300 1300 OI
50
800.00

Goldwyer - Unit 4 700.00

1400 1400 1400 1400 1400
40 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Depth (m)

Depth (m)

Mixed type II/III usually marine

S2 mg/g
oil/gas prone 600.00

Goldwyer - Unit 3
1500 1500 1500 1500 1500
500.00
30
DEPTH ( m )

DEPTH ( m )

Title

400.00 TYPE II-III

oil-gas-prone
G. prisca present in SWC at 1600
1600 1600 1600 1600
1600mRT
Goldwyer - Unit 2 20
300.00
Type III gas
Goldwyer - Unit 1 prone

1700 1700 1700 1700 1700 200.00 TYPE III

0.2 kg/tonne S2

gas-prone

10 Dry Gas Window

Title 100.00

Dry gas prone

1800 1800 1800 1800 1800 TYPE IV
inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 2.0 4.0 6.0 8.0 10.0 0.00

PY (S1 + S2) Tmax (oC) PI (S1/S1+S2) 0.00 100.00 200.00 300.00 400.00 0 400 425 450 475 500
140 90 40
Title 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Dodonea 1 Dodonea 1 Dodonea 1: Tmax v Depth Dodonea 1: PI vs DEPTH Dodonea1: S1 & S2 vs DEPTH
1530 1530 1530 1530 1530 60 1000.00
Immature Mature Postmature S1 Immature Mature Postmature
0.2 kg/tonne S2

TOC
Oil Window

Condensate - Wet Gas Zone

Dry Gas Window

PY
S2 Type II TYPE I
Type I oil oil-prone
0.5% TOC

oil prone
HI prone 900.00 usually lacustrine Oil
Window
OI

Condensate - Wet Gas Zone

1535 1535 1535 1535 1535 50

800.00

700.00
1540 1540 1540 1540 1540
40
TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

Goldwyer - Unit 4 oil-prone
Depth (m)

Depth (m)

S2 mg/g

Mixed type II/III usually marine

Goldwyer - Unit 3 oil/gas prone 600.00

1545 1545 1545 1545 1545

500.00
DEPTH ( m )

30
DEPTH ( m )

DEPTH ( m )

400.00 TYPE II-III

oil-gas-prone
1550 1550 1550 1550 1550
20
300.00
Type III gas
prone

1555 1555 1555 1555 1555 200.00 TYPE III

gas-prone
10
Dry Gas Window
G. prisca unknown from paly = 15/09/14
S1 100.00
S2
1560 1560 1560 1560 1560 kg/ton Dry gas prone TYPE IV
0.0 0.2 0.4 0.6 0.8 1.0 inert
0 1 2 3 4 5 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 10.0 20.0 30.0 40.0
0.00
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) -100.00 100.00 300.00 500.00 700.00 0 400 425 450 475 500

DT
HI 0 2 4 6 8 10 12 14 16
Tmax (oC)
OI TOC wt%

Edgar Range 1 Edgar Range 1 Edgar Range 1: Tmax v Depth Edgar Range 1: PI vs DEPTH Edgar Range 1: S1 & S2 vs DEPTH
900 900 900 900 900 60
1000.00
Immature Mature Postmature
TOC S1 Immature Mature Postmature
Oil Window

Condensate - Wet Gas Zone

Dry Gas Window

PY S2 Type II
TYPE I
oil-prone
0.5% TOC

G. prisca in core at 948.5 - 951 mRT HI Type I oil oil prone 900.00 usually lacustrine Oil
prone Window
OI

Condensate - Wet Gas Zone

1000 1000 1000 1000 1000 50

800.00

700.00
1100 Goldwyer - Unit 4 1100 1100 1100 1100
40
TYPE II
HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Depth (m)

Depth (m)

S2 mg/g

usually marine
Mixed type II/III 600.00
Goldwyer - Unit 3 oil/gas prone

1200 1200 1200 1200 1200

30
DEPTH ( m )
DEPTH ( m )

DEPTH ( m )

500.00

Goldwyer - Unit 2

400.00 TYPE II-III

oil-gas-prone
1300 1300 1300 1300 1300
20
Goldwyer - Unit 1
300.00

Willara Fm Type III gas

prone
1400 1400 1400 1400 1400 200.00 TYPE III
0.2 kg/tonne S2

gas-prone
10
Dry Gas Window

S1 100.00
S2
1500 1500 1500 1500 1500 kg/ton TYPE IV
GR Dry gas prone
0.0 0.5 1.0 1.5 2.0 2.5 3.0 TOC (wt%) 0 100 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 1.2 0.0 0.5 1.0 1.5 2.0 2.5 3.0 inert

Tmax (oC) PI (S1/S1+S2) 0.00 100.00 200.00 300.00 400.00

HI 0
0.00
PY (S1 + S2) 140 90 40 400 425 450 475 500
OI 0 2 4 6 8 10 12 14 16
DT Tmax (oC)
TOC wt%

2487 472
McLarty 1 McLarty 1 McLarty 1: Tmax v Depth McLarty 1: PI vs DEPTH McLarty 1: S1 & S2 vs DEPTH
1650 1650 1650 1650 1650 60 1000.00
G. prisca unknown from play 15/09/14 Immature Mature Postmature S1 Immature Mature Postmature
TOC
Oil Window

Condensate - Wet Gas Zone

Type II
Dry Gas Window

S2 TYPE I
PY Type I oil oil prone oil-prone
0.5% TOC

1700 1700 1700 1700 1700 HI prone 900.00 usually lacustrine Oil
Window
OI
Condensate - Wet Gas Zone

50

800.00
1750 1750 1750 1750 1750
Goldwyer - Unit 4

700.00
1800 1800 1800 1800 1800
40
TYPE II
HYDROGEN INDEX ( HI, mg HC/g TOC)

Mixed type II/III oil-prone

Depth (m)

Depth (m)

S2 mg/g

usually marine
oil/gas prone 600.00
1850 1850 1850 1850 1850

Goldwyer - Unit 3
500.00
DEPTH ( m )

30
DEPTH ( m )

DEPTH ( m )

1900 1900 1900 1900 1900

400.00 TYPE II-III

oil-gas-prone
1950 1950 1950 1950 1950
Goldwyer - Unit 2
20
Goldwyer - Unit 1 Type III gas 300.00

2000 prone
2000 2000 2000 2000

200.00 TYPE III

gas-prone
0.2 kg/tonne S2

2050 2050 2050 2050 2050 10

Dry Gas Window
S1
100.00
S2
kg/ton Dry gas prone
2100 2100 2100 2100 2100 TYPE IV
GR 0.0 0.2 0.4 0.6 0.8 1.0 inert
0 1 2 3 4 5 6 TOC (wt%) 0 100 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 5.0 10.0 15.0 20.0 25.0
0.00
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 100.00 200.00 300.00 400.00 500.00 0 400 425 450 475 500

DT
HI 0 2 4 6 8 10 12 14 16
Tmax (oC)
OI TOC wt%
 Willara 1 Willara 1 Willara 1: Tmax v Depth Willara 1: PI vs DEPTH Willara 1: S1 & S2 vs DEPTH
1800 1800 1800 1800 1800 60 1000.00
G. prisca present in core at Immature Mature Postmature
1881mRT, but no zonation TOC Type II

Dry Gas Window

TYPE I

Oil Window

Condensate - Wet Gas Zone

PY Type I oil oil prone oil-prone
prone 900.00 usually lacustrine Oil
1900 1900 1900 1900 1900 Window

Condensate - Wet Gas Zone

50
Goldwyer - Unit 4 800.00
2000 2000 2000 2000 2000
Goldwyer - Unit 3

Goldwyer - Unit 2 ?? 700.00

2100 2100 2100 2100 2100
40 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Mixed type II/III
Depth (m)

Depth (m)

S2 mg/g
usually marine
oil/gas prone 600.00
2200 2200 2200 2200 2200

500.00

DEPTH ( m )
30

DEPTH ( m )

DEPTH ( m )
2300 2300 2300 2300 2300

400.00 TYPE II-III

oil-gas-prone
2400 Goldwyer - Unit 1 ?? 2400 2400 2400 2400
20
Type III gas 300.00
prone
2500 2500 2500 2500 2500

200.00 TYPE III

S1

0.2 kg/tonne S2
gas-prone

2600 2600 2600 2600 2600 S2 10

0.5% TOC

Dry Gas Window

Willara Fm HI S1 100.00
S2
OI kg/ton Dry gas prone
2700 2700 2700 2700 2700 TYPE IV
inert
0.0 0.2 0.4 0.6 0.8 1.0 TOC (wt%) 0 100 GR 200 300 300.0 350.0 400.0 450.0 500.0 0.0 0.5 1.0 1.5 0.0 1.0 2.0 3.0 4.0
0.00
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 200.00 400.00 600.00 800.00 0 400 425 450 475 500
HI 0 2 4 6 8 10 12 14 16
Tmax (oC)
DT
OI
TOC wt%

Wilson Cliffs 1 Wilson Cliffs 1 Wilson Cliffs 1: Tmax v Depth Wilson Cliffs 1: PI vs DEPTH Wilson Cliffs 1: S1 & S2 vs DEPTH 1000.00
2600 2600 2600 2600 2600 60
Immature Mature
G. prisca unknown - no paly - 05/09/14 Immature Postmature
Mature Postmature
TOC S1 TYPE I

Oil Window

Condensate - Wet Gas Zone

Dry Gas Window

oil-prone
PY S2 Type II
900.00 usually lacustrine Oil
Type I oil oil prone Window
HI prone

Condensate - Wet Gas Zone

2650
OI
2650 2650 2650 2650 50
800.00
Goldwyer Fm

700.00

2700 2700 2700 2700 2700 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

40
oil-prone
usually marine
Depth (m)

Depth (m)

600.00

S2 mg/g
Mixed type II/III
oil/gas prone

2750 2750 2750 2750 2750 500.00

DEPTH ( m )
30
DEPTH ( m )

DEPTH ( m )
400.00 TYPE II-III
oil-gas-prone

2800 2800 2800 2800 2800

20 300.00

Type III gas

prone
200.00 TYPE III
2850 2850 2850 2850 2850 gas-prone

0.2 kg/tonne S2
10 Dry Gas Window
0.5% TOC

100.00
S1
S2 TYPE IV
2900 2900 2900 2900 2900 kg/ton Dry gas prone inert
0.0 1.0 2.0 3.0 4.0 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 1.0 2.0 3.0 4.0 5.0 0.00
400 425 450 475 500
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 100.00 200.00 300.00 400.00 500.00 HI 0
Tmax (oC)
DT OI 0 2 4 6 8 10 12 14 16

TOC wt%

Solanum 1 Solanum 1 Solanum 1: Tmax v Depth Solanum 1: PI vs DEPTH Solanum 1: S1 & S2 vs DEPTH 1000.00
200 200 200 200 200 60
Immature Mature
Immature Postmature
G. prisca unknown - no pay -19/5/14 Mature Postmature
S1

0.2 kg/tonne S2
TOC TYPE I
Oil Window

Condensate - Wet Gas Zone

Dry Gas Window

Type II oil-prone
PY S2 Type I oil oil prone 900.00 usually lacustrine Oil
0.5% TOC

Window
prone
250 250 250 250 250 HI

Condensate - Wet Gas Zone

Goldwyer - unit 4 OI 50
800.00

300 300 300 300 300

700.00
Goldwyer - unit 3
TYPE II
40

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
350 350 350 350 350 usually marine
Depth (m)

Depth (m)

Mixed type II/III 600.00

S2 mg/g
oil/gas prone

400 400 400 400 400 500.00

DEPTH ( m )
DEPTH ( m )

DEPTH ( m )

Goldwyer - unit 2 30

400.00 TYPE II-III

450 450 450 450 450 oil-gas-prone

Goldwyer - unit 1
20 300.00

500 500 500 500 500 Type III gas

prone

200.00 TYPE III

gas-prone

550 550 550 550 550 10 Dry Gas Window

100.00
Willara Fm S1
S2 TYPE IV
600 600 600 600 600 kg/ton Dry gas prone inert
0.0 0.5 1.0 1.5 2.0 2.5 3.0 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 5.0 10.0 15.0 20.0 0.00
400 425 450 475 500
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 200.00 400.00 600.00 800.00 1000.00 1200.00HI 0
Tmax (oC)
0 2 4 6 8 10 12 14 16
DT
TOC wt%

Kidson 1 Kidson 1 Kidson 1: Tmax v Depth 4250

Kidson 1: PI vs DEPTH Kidson 1: S1 & S2 vs DEPTH 60
1000.00
4250 4250 4250 4250 Immature Mature Postmature
S1
0.2 kg/tonne S2

G. prisca unknown from paly - 15/09/14 TOC TYPE I

4260
Dry Gas Window
Condensate - Wet Gas Zone
Oil Window

PY S2 Type II 900.00
oil-prone
usually lacustrine Oil
0.5% TOC

4270 4270 4270 4270 4270 HI Type I oil oil prone Window

Condensate - Wet Gas Zone

prone
no S3 for OI
4280 Goldwyer Fm 50
800.00

4290 4290 4290 4290 4290

4300 700.00

4310 TYPE II
4310 4310 4310 4310 40

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
usually marine
Depth (m)

Depth (m)

600.00
S2 mg/g

4320 Mixed type II/III

No digital logs below 4270mRT oil/gas prone
4330 4330 4330 4330 4330
No Tmax data to plot
500.00
4340
DEPTH ( m )

30
DEPTH ( m )

DEPTH ( m )

4350 4350 4350 4350 4350

400.00 TYPE II-III
oil-gas-prone
4360

4370 4370 4370 4370 4370 20 300.00

4380 Type III gas

prone
4390 4390 4390 4390 4390 200.00 TYPE III
gas-prone

4400 10 Dry Gas Window

100.00
4410 4410 4410 4410 4410
S1
TYPE IV
S2
4420 inert
GR 0.0 0.2 0.4 0.6 0.8 1.0 kg/ton Dry gas prone
0.0 1.0 2.0 3.0 4.0 TOC (wt%) 0 100 200 300 350.0 400.0 450.0 500.0 0.0 5.0 10.0 15.0 20.0 0.00
400 425 450 475 500
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 200.00 400.00 600.00 800.00 0
HI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Kunzea 1 Kunzea 1 Kunzea 1: Tmax v Depth 350

Kunzea 1: PI vs DEPTH Kunzea 1: S1 & S2 vs DEPTH 60
1000.00
350 350 350 350 Immature Mature
Mature Postmature Postmature
Immature
S1
0.2 kg/tonne S2

TOC Type II TYPE I

Dry Gas Window
Condensate - Wet Gas Zone
Oil Window

oil-prone
PY S2 Type I oil oil prone 900.00 usually lacustrine Oil
0.5% TOC

360 360 360 360 360 prone Window

HI

Condensate - Wet Gas Zone

no S3 for OI
50
370 800.00
370 Goldwyer - unit 4 370 370 370

380 380 380 380 380 700.00

TYPE II
HYDROGEN INDEX ( HI, mg HC/g TOC)

Goldwyer - unit 3 40
oil-prone
Mixed type II/III usually marine
Depth (m)

Depth (m)

390 390 390 390 390 600.00

S2 mg/g

oil/gas prone

400 400 400 400 400 500.00

30
DEPTH ( m )
DEPTH ( m )

DEPTH ( m )

410 410 410 410 410 400.00 TYPE II-III

oil-gas-prone

420 420 420 420 420 20 300.00

Type III gas
prone
430 430 430 430 430
200.00 TYPE III
gas-prone

G. prisca unknown - no paly 15/09/14

10 Dry Gas Window
440 440 440 440 440
100.00
S1
S2 Dry gas prone TYPE IV
450 450 450 450 450 kg/ton
inert
0.0 2.0 4.0 6.0 8.0 10.0 TOC (wt%) 0 100 GR 200 300 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 10.0 20.0 30.0 40.0 50.0 0.00
400 425 450 475 500
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 200.00 400.00 600.00 800.00 1000.00HI 0
0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Matches Spring 1 Matches Spring 1 Matches Spring 1: Tmax v Depth 2200

Matches Spring 1: PI vs DEPTH Matches Spring 1: S1 & S2 vs DEPTH 60
1000.00
2200 2200 2200
2200 Immature Mature Postmature
G. prisca unknown from paly -15/09/14
TOC Immature Mature Postmature S1
0.2 kg/tonne S2

Type II TYPE I
oil-prone
S2
Dry Gas Window
Condensate - Wet Gas Zone

Type I oil
Oil Window

PY oil prone 900.00 usually lacustrine Oil

0.5% TOC

prone Window
HI
Condensate - Wet Gas Zone

2300 2300
2300
2300 2300 OI
50
800.00

700.00
2400 2400 2400 2400
2400
40 TYPE II
HYDROGEN INDEX ( HI, mg HC/g TOC)

Goldwyer - unit 3 oil-prone

Mixed type II/III usually marine
Depth (m)

Depth (m)

600.00
S2 mg/g

oil/gas prone

2500 2500 2500 2500

2500
500.00
DEPTH ( m )

30
DEPTH ( m )
DEPTH ( m )

400.00 TYPE II-III

2600 2600 2600 2600 oil-gas-prone
2600

20 300.00
Type III gas
prone
2700 2700 2700 2700
2700
200.00 TYPE III
gas-prone

10 Dry Gas Window

100.00
2800 2800 2800 2800 S1
2800
S2 TYPE IV
Dry gas prone
kg/ton inert
0.0 1.0 2.0 3.0 4.0 5.0 TOC (wt%) 0 100 GR 200 300 0.0 0.2 0.4 0.6 0.8 1.0 0.0 5.0 10.0 15.0 0.00
350.0 400.0 450.0 500.0
PI (S1/S1+S2) 0.00 200.00 400.00 600.00
HI 0
400 425 450 475 500
PY (S1 + S2) 140 120 100 80 60 40 Tmax (oC)
OI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Pictor 1 Pictor 1 Pictor 1: Tmax v Depth Pictor 1: PI vs DEPTH Pictor 1: S1 & S2 vs DEPTH
 Pictor 1 Pictor 1 Pictor 1: Tmax v Depth 1000
Pictor 1: PI vs DEPTH Pictor 1: S1 & S2 vs DEPTH 60
1000.00
1000 1000 1000 1000 Immature Mature
Mature Postmature Postmature
Immature S1
TOC

0.2 kg/tonne S2
Type II TYPE I

Dry Gas Window

Condensate - Wet Gas Zone
oil-prone

Oil Window
PY S2 Type I oil oil prone 900.00 usually lacustrine Oil
0.5% TOC

prone Window
HI

Condensate - Wet Gas Zone

G. prisca found within SWCs in zones
1140.4-1234, and 1373 -1413.5mRT OI
1100 1100 1100 1100 1100 50
800.00

700.00

1200 1200 1200 1200 1200 TYPE II

40

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Mixed type II/III usually marine
Depth (m)

Depth (m)
Goldwyer - unit 4 600.00

S2 mg/g
oil/gas prone
Goldwyer - unit 3

1300 1300 1300 1300 1300 500.00

DEPTH ( m )
30

DEPTH ( m )

DEPTH ( m )
Goldwyer - unit 2
400.00 TYPE II-III
oil-gas-prone

1400 1400 1400 1400 1400

20 300.00
Type III gas
prone
Goldwyer - unit 1
200.00 TYPE III
1500 1500 1500 1500 1500 gas-prone

10 Dry Gas Window

100.00
S1
S2 TYPE IV
Dry gas prone
1600 1600 1600 1600 1600 kg/ton inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 0.5 1.0 1.5 2.0 0.00

Tmax (oC) PI (S1/S1+S2) 0.00 20.00 40.00 60.00 80.00 100.00

HI 0
400 425 450 475 500
PY (S1 + S2) 140 120 100 80 60 40
OI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Hedonia 1 Hedonia 1: Tmax v Depth Hedonia 1: S1 & S2 vs DEPTH

900 Hedonia 1 900 900 Hedonia 1: PI vs DEPTH 900 60
1000.00
900 Immature Mature Postmature
Mature Postmature
Immature S1

0.2 kg/tonne S2
TOC Type II TYPE I

Dry Gas Window

Condensate - Wet Gas Zone
oil-prone

Oil Window
PY S2 Type I oil oil prone 900.00 usually lacustrine Oil
920
0.5% TOC

920 920 920 920 prone Window

HI

Condensate - Wet Gas Zone

G. prisca abundant at 1022.5 mRT
and common in 1045-46 mRT OI
50
940 800.00
940 940 940 940

960 960 960 960 960 700.00

TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

40
oil-prone
Mixed type II/III usually marine
980
Depth (m)

980 Goldwyer - unit 4 980 980 600.00

S2 mg/g
Depth (m)

980 oil/gas prone

Goldwyer - unit 3

1000 1000 1000 1000 1000 500.00

DEPTH ( m )
30
DEPTH ( m )

DEPTH ( m )
Goldwyer - unit 2
1020 1020 1020 1020 1020 400.00 TYPE II-III
oil-gas-prone

1040 1040 1040 1040 1040 20 300.00

Type III gas
prone
1060 Goldwyer - unit 1 1060 1060 1060
1060 200.00 TYPE III
gas-prone

10 Dry Gas Window

1080 1080 1080 1080
1080
100.00
S1
S2 TYPE IV
Dry gas prone
1100 1100 1100 1100 kg/ton inert
1100
0.0 0.5 1.0 1.5 2.0 TOC (wt%) GR 200 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 1.0 2.0 3.0 4.0 5.0 0.00
0 100 300 400 425 450 475 500
Tmax (oC) PI (S1/S1+S2) 0.00 50.00 100.00 150.00 200.00 250.00
HI 0
PY (S1 + S2) 140 120 100 80 60 40 OI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Munro 1 Munro 1: Tmax v Depth Munro 1: PI vs DEPTH Munro 1: S1 & S2 vs DEPTH

1600 Munro 1 1600 1600 1600 60
1000.00
1600 Mature Immature Mature Postmature
Immature Postmature
G. prisca unknown in paly 15/09/14
TOC S1

0.2 kg/tonne S2
Type II TYPE I
Dry Gas Window
Condensate - Wet Gas Zone

oil-prone
Oil Window

PY S2 Type I oil oil prone 900.00 usually lacustrine Oil

1620
0.5% TOC

1620 1620 1620 prone Window

1620 HI

Condensate - Wet Gas Zone

OI
50
1640 800.00
1640 1640 1640
1640

1660 1660 1660 1660 700.00

1660
TYPE II
40

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Mixed type II/III usually marine
Depth (m)

1680 Goldwyer - unit 4 1680 1680 1680 600.00

S2 mg/g
Depth (m)

1680 oil/gas prone

Goldwyer - unit 3

1700 1700 1700 1700 500.00

1700
DEPTH ( m )
DEPTH ( m )

DEPTH ( m )

30

Goldwyer - unit 2
1720 1720 1720 1720
1720 400.00 TYPE II-III
oil-gas-prone

1740 1740 1740 1740 20

1740 300.00
Type III gas
prone
1760 Goldwyer - unit 1 1760 1760 1760
1760 200.00 TYPE III
gas-prone

10 Dry Gas Window

1780 1780 1780 1780
1780 100.00
S1
S2 TYPE IV
Dry gas prone
1800 1800 1800 1800 kg/ton inert
1800
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 0.5 1.0 1.5 2.0 0.00
0 100 GR 200 300
Tmax (oC) PI (S1/S1+S2) 0.00 200.00 400.00 600.00 800.00
HI 0
400 425 450 475 500
PY (S1 + S2) 140 120 100 80 60 40 OI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Pegasus 1 Pegasus 1 Pegasus 1: Tmax v Depth Pegasus 1: PI vs DEPTH Pegasus 1: S1 & S2 vs DEPTH 1000.00
2340 2340 2340 2340 2340 60
Immature Mature
Mature Postmature Postmature
Immature S1
0.2 kg/tonne S2

TOC Type II TYPE I

Dry Gas Window
Condensate - Wet Gas Zone

oil-prone
Oil Window

PY S2 Type I oil oil prone 900.00 usually lacustrine Oil

0.5% TOC

prone Window
HI

Condensate - Wet Gas Zone

G. prisca unknown - no paly 19/5/14
OI
50
2390 2390 2390 2390 2390 800.00

700.00

40 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

2440 2440 2440 2440 2440 oil-prone
Mixed type II/III usually marine
Depth (m)
Depth (m)

Goldwyer - unit 4 600.00

S2 mg/g

oil/gas prone
Goldwyer - unit 3

No S1 data 500.00
DEPTH ( m )

30
DEPTH ( m )

DEPTH ( m )

No Tmax data
2490 2490 2490 2490 2490
Goldwyer - unit 2
400.00 TYPE II-III
oil-gas-prone
No Tmax data

20 300.00
2540 2540 2540 2540 2540 Type III gas
prone
Goldwyer - unit 1
No S1 data 200.00 TYPE III
gas-prone

10 Dry Gas Window

2590 2590 2590 2590 2590 100.00

S1
S2 TYPE IV
Dry gas prone
kg/ton inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 0.5 1.0 1.5 2.0 0.00
400 425 450 475 500
140 120 100 80 60 40 Tmax (oC) PI (S1/S1+S2) 0.00 20.00 40.00 60.00 80.00 100.00
HI 0
PY (S1 + S2) OI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Calamia 1 Calamia 1 Calamia 1: Tmax v DEPTH Calamia 1: PI vs DEPTH Calamia 1: S1 & S2 vs DEPTH
950 950 950 950 950 60 1000.00 Chart Title
Immature Mature
TOC S1 Postmature
Condensate - Wet Gas Zone

Dry Gas Window

Oil Window

Type II TYPE I
PY S2 Type I oil oil prone oil-prone
0.5% TOC

prone 900.00 usually lacustrine Oil

HI Window

Condensate - Wet Gas Zone

1000 1000 1000 1000 1000 OI
50
G. prisca abundant in zone at 931.5, - 1494.5mRT 800.00

Goldwyer - Unit 4 700.00

1050 1050 1050 1050 1050
40 TYPE II
HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Mixed type II/III
Depth (m)

Depth (m)

usually marine
S2 mg/g

oil/gas prone 600.00

Goldwyer - Unit 3
1100 1100 1100 1100 1100
500.00
30
DEPTH ( m )

Title
DEPTH ( m )

400.00 TYPE II-III

oil-gas-prone
1150 1150 1150 1150 1150
Goldwyer - Unit 2 20
300.00
Type III gas
Goldwyer - Unit 1 prone

1200 1200 1200 1200 1200 200.00 TYPE III

0.2 kg/tonne S2

gas-prone

10 Dry Gas Window

Title 100.00

Dry gas prone

1250 1250 1250 1250 1250 TYPE IV
inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 2.0 4.0 6.0 8.0 10.0 0.00

PY (S1 + S2) Tmax (oC) PI (S1/S1+S2) 0.00 100.00 200.00 300.00 400.00 500.00 0 400 425 450 475 500
140 90 40
Title 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Carina 1 Carina 1 Carina 1: Tmax v DEPTH Carina 1: PI vs DEPTH Carina 1: S1 & S2 vs DEPTH
1550 1550 1550 1550 1550 60 1000.00
Immature Mature
TOC S1 Postmature
Condensate - Wet Gas Zone

Dry Gas Window

Type II
Oil Window

TYPE I
PY S2 Type I oil oil prone oil-prone
1560
0.5% TOC

1560 1560 1560 1560 prone 900.00 usually lacustrine Oil

HI Window
Condensate - Wet Gas Zone

OI
50
1570 1570 1570 1570 1570 800.00

1580 1580 1580 1580 1580 700.00

40 TYPE II
HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
1590
Depth (m)

Depth (m)

1590 1590 1590 1590 Mixed type II/III usually marine

S2 mg/g

oil/gas prone 600.00

Goldwyer - Unit 4

1600 1600 1600 1600 1600

500.00
30
DEPTH ( m )
DEPTH ( m )

Title

No logs past 1592 mRT

1610 1610 1610 1610 1610
400.00 TYPE II-III
oil-gas-prone

1620 1620 1620 1620 1620 20

300.00
Type III gas
prone
1630 1630 1630 1630 1630
200.00 TYPE III
0.2 kg/tonne S2

gas-prone

1640
G. prisca present in SWC at
1640 1640 1640 1640 10 Dry Gas Window
1551.5mRT and 1584.5mRT
Title 100.00

Dry gas prone

1650 1650 1650 1650 1650 TYPE IV
inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 2.0 4.0 6.0 8.0 10.0 0.00

PY (S1 + S2) Tmax (oC) PI (S1/S1+S2) 0.00 50.00 100.00 150.00 200.00 0 400 425 450 475 500
140 90 40
Title 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%
 Crystal Creek 1 Crystal Creek 1 Crystal Creek 1 : Tmax v DEPTH Crystal Creek 1: PI vs DEPTH Crystal Creek 1 : S1 & S2 vs DEPTH
1800 1800 1800 1800 1800 60 1000.00
Immature Mature
TOC S1 Postmature

Condensate - Wet Gas Zone

Dry Gas Window

Type II

Oil Window
TYPE I
PY S2 Type I oil oil prone oil-prone
0.5% TOC

Oil
1850 1850 1850 1850 1850 HI
prone 900.00 usually lacustrine
Window

Condensate - Wet Gas Zone

G. prisca present in zone at 1575,
OI
and 1751.5 - 1983 mRT 50
800.00
1900 1900 1900 1900 1900

700.00
1950 1950 1950 1950 1950
40 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Depth (m)

Depth (m)
Mixed type II/III usually marine

S2 mg/g
oil/gas prone 600.00
2000 2000 2000 2000 2000
Goldwyer - Unit 4

500.00
30

DEPTH ( m )
DEPTH ( m )

Title
2050 2050 2050 2050 2050

400.00 TYPE II-III

2100 2100
oil-gas-prone
2100 2100 2100
20
300.00
Type III gas
2150 prone
2150 2150 2150 2150

200.00 TYPE III

0.2 kg/tonne S2
gas-prone
2200
2200 2200 2200 2200 10 Dry Gas Window

Title 100.00

2250 Dry gas prone

2250 2250 2250 2250 TYPE IV
inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 2.0 4.0 6.0 8.0 10.0 0.00

PY (S1 + S2) Tmax (oC) PI (S1/S1+S2) 0.00 50.00 100.00 150.00 200.00 250.00 0 400 425 450 475 500
140 90 40
Title 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Darriwell 1 Darriwell 1 Darriwell 1: Tmax v Depth Darriwell 1: PI vs DEPTH Darriwell 1: S1 & S2 vs DEPTH
1570 1570 1570 1570 1570 60 1000.00
Immature Mature Postmature S1 Immature Mature Postmature

0.2 kg/tonne S2
TOC

Oil Window

Condensate - Wet Gas Zone

S2

Dry Gas Window

Type II TYPE I
PY Type I oil oil-prone
0.5% TOC

1572 1572 1572 1572 1572 HI

oil prone
900.00 usually lacustrine Oil
prone Window
OI

Condensate - Wet Gas Zone

50
1574 1574 1574 1574 1574 800.00

1576 1576 1576 1576 1576

700.00

40
TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

Goldwyer - Unit 4 oil-prone
1578
Depth (m)

Depth (m)

1578 1578 1578 1578

S2 mg/g
Mixed type II/III usually marine
Goldwyer - Unit 3 oil/gas prone 600.00

1580 1580 1580 1580 1580

500.00

DEPTH ( m )
30
DEPTH ( m )

DEPTH ( m )
No log data

1582 1582 1582 1582 1582

400.00 TYPE II-III
oil-gas-prone

1584 1584 1584 1584 1584 20

300.00
Type III gas
prone
1586 1586 1586 1586 1586
200.00 TYPE III
gas-prone
10
1588 G. prisca present in zone 1756 - 1588.5mRT 1588 1588 1588 1588 Dry Gas Window

S1 100.00
S2
1590 1590 1590 1590 1590 kg/ton Dry gas prone TYPE IV
0.0 0.2 0.4 0.6 0.8 1.0 inert
0 1 2 3 4 5 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 10.0 20.0 30.0 40.0
0.00
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 200.00 400.00 600.00 0 400 425 450 475 500
DT
HI 0 2 4 6 8 10 12 14 16
Tmax (oC)
OI TOC wt%

Great Sandy 1 Great Sandy 1 Great Sandy 1 : Tmax v Depth Great Sandy 1 : PI vs DEPTH Great Sandy 1: S1 & S2 vs DEPTH 1000.00
1510 1510 1510 1510 1510 60
Immature Mature
Mature Postmature Postmature
Immature S1
TOC

0.2 kg/tonne S2
Type II TYPE I
Dry Gas Window
Condensate - Wet Gas Zone

oil-prone
Oil Window

PY S2 Type I oil oil prone 900.00 usually lacustrine Oil

0.5% TOC

1530 1530 1530 1530 prone Window

1530 HI

Condensate - Wet Gas Zone

G. prisca in zones 1585-1600 (abundant), OI
1720-1730 (uncommon) 50
800.00
1550 1550 1550 1550 1550

700.00

1570 1570 1570 1570 1570 TYPE II

40

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Mixed type II/III usually marine
Depth (m)

Goldwyer - unit 4 600.00

Depth (m)

S2 mg/g
oil/gas prone
1590 Goldwyer - unit 3 1590 1590 1590 1590

500.00
DEPTH ( m )
DEPTH ( m )

DEPTH ( m )

30
1610 1610 1610 1610 1610
Goldwyer - unit 2
400.00 TYPE II-III
oil-gas-prone

1630 1630 1630 1630 1630

20 300.00
Type III gas
prone
1650 1650 1650 1650 1650
Goldwyer - unit 1
200.00 TYPE III
gas-prone

1670 1670 1670 1670 10 Dry Gas Window

1670
100.00
S1
S2 TYPE IV
Dry gas prone
1690 1690 1690 1690 kg/ton inert
1690
0.0 0.5 1.0 1.5 2.0 TOC (wt%) GR 200 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 0.5 1.0 1.5 2.0 0.00
0 100 300 400 425 450 475 500
Tmax (oC) PI (S1/S1+S2) 0.00 200.00 400.00 600.00 800.00 1000.00
HI 0
PY (S1 + S2) 140 120 100 80 60 40 OI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Hiltop 1 Hiltop 1 Hiltop 1: Tmax v Depth Hiltop 1: PI vs DEPTH Hiltop 1: S1 & S2 vs DEPTH 1000.00
1040 1040 1040 1040 1040 60
Immature Mature
Mature Postmature Postmature
Immature S1
0.2 kg/tonne S2

TOC Type II TYPE I

Dry Gas Window
Condensate - Wet Gas Zone

oil-prone
Oil Window

PY S2 Type I oil oil prone 900.00 usually lacustrine Oil

prone Window
HI

Condensate - Wet Gas Zone

1060 1060 1060 1060 1060 OI
50
0.5% TOC

800.00

1080 1080 1080 1080 1080 700.00

40 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Mixed type II/III usually marine
Depth (m)

Goldwyer - unit 4 600.00

S2 mg/g
Depth (m)

oil/gas prone
1100 1100 1100 1100 1100
Goldwyer - unit 3

500.00
DEPTH ( m )

30
DEPTH ( m )

DEPTH ( m )

1120 Goldwyer - unit 2 1120 1120 1120 1120

400.00 TYPE II-III
oil-gas-prone

1140 1140 1140 1140 20 300.00

1140
Type III gas
prone
Goldwyer - unit 1
200.00 TYPE III
gas-prone
1160 1160 1160 1160
G. prisca in zones 930-45, 945-60 1160
10 Dry Gas Window
960-90, 996-1002, 1002-1011,
1075-1084, 1182-1191, 1184, 1286.1, 100.00
353.1mRT. Cuttings = contamination? S1
S2 TYPE IV
Dry gas prone
1180 1180 1180 1180 kg/ton inert
1180
0.0 0.5 1.0 1.5 2.0 2.5 TOC (wt%) GR 200 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 1.0 2.0 3.0 4.0 5.0 6.0 0.00
0 100 300 400 425 450 475 500
Tmax (oC) PI (S1/S1+S2) 0.00 50.00 100.00 150.00 200.00 250.00 300.00
HI 0
PY (S1 + S2) 140 120 100 80 60 40 OI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Parda 1 Parda 1 Parda 1: Tmax v Depth 1270 Parda 1: PI vs DEPTH Parda 1: S1 & S2 vs DEPTH 60
1000.00
1270 1270 1270 1270 Immature Mature
Mature Postmature Postmature
Immature
G. prisca unknown from paly 15/09/14 S1
0.2 kg/tonne S2

TOC Type II TYPE I

Dry Gas Window
Condensate - Wet Gas Zone
Oil Window

oil-prone
PY S2 Type I oil oil prone 900.00 usually lacustrine Oil
0.5% TOC

prone Window
HI

Condensate - Wet Gas Zone

no S3 for OI
50
Goldwyer - unit 4 800.00
1320 1320 1320 1320 1320

700.00

TYPE II
HYDROGEN INDEX ( HI, mg HC/g TOC)

Goldwyer - unit 3 40
oil-prone
Mixed type II/III usually marine
Depth (m)

Depth (m)

600.00
S2 mg/g

oil/gas prone
1370 1370 1370 1370 1370
No log data
500.00
30
DEPTH ( m )
DEPTH ( m )

DEPTH ( m )

400.00 TYPE II-III

oil-gas-prone
1420 1420 1420 1420 1420

20 300.00
Type III gas
prone

200.00 TYPE III

gas-prone
1470 1470 1470 1470 1470
10 Dry Gas Window

100.00
S1
S2 Dry gas prone TYPE IV
inert
kg/ton
0.0 2.0 4.0 6.0 8.0 10.0 TOC (wt%) 0 100 GR 200 300 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 10.0 20.0 30.0 40.0 50.0 0.00
400 425 450 475 500
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 100.00 200.00 300.00 400.00 HI 0
0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Thangoo 1A Tangoo 1A Tangoo 1A Tmax v Depth Tangoo 1A : PI vs DEPTH Tangoo 1A : S1 & S2 vs DEPTH 1000.00
860 860 860 860 860 60
Immature Mature
Immature Postmature
G. prisca unknown - no paly report Mature Postmature
TOC S1
0.2 kg/tonne S2

TYPE I
Oil Window

Condensate - Wet Gas Zone

15/09/14
Dry Gas Window

Type II oil-prone
PY S2 Type I oil oil prone 900.00 usually lacustrine Oil
0.5% TOC

Window
prone
HI
Condensate - Wet Gas Zone

880 Goldwyer - unit 4 880 880 880 880 OI 50

800.00

700.00
Goldwyer - unit 3
900 900 900 900 900 TYPE II
40
HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
usually marine
Depth (m)

Depth (m)

Mixed type II/III 600.00

S2 mg/g

oil/gas prone

920 920 920 920 920 500.00

DEPTH ( m )

30
DEPTH ( m )

DEPTH ( m )

Goldwyer - unit 2

400.00 TYPE II-III

oil-gas-prone

940 940 No DT log 940 940 940

Goldwyer - unit 1
20 300.00

Type III gas

prone

200.00 TYPE III

960 960 960 960 960 gas-prone

10 Dry Gas Window

100.00
Willara Fm S1
S2 TYPE IV
980 980 980 980 980 kg/ton Dry gas prone inert
0.0 1.0 2.0 3.0 4.0 TOC (wt%) 0 100 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 5.0 10.0 15.0 20.0 0.00
400 425 450 475 500
PY (S1 + S2)
GR Tmax (oC) PI (S1/S1+S2) 0.00 100.00 200.00 300.00 400.00 HI 0
Tmax (oC)
0 2 4 6 8 10 12 14 16

TOC wt%

Patience 2 Patience 2 Patience 2: Tmax v Depth Patience 2 Patience 2

 Patience 2 Patience 2 Patience 2: Tmax v Depth 2900 Patience 2: PI vs DEPTH Patience 2: S1 & S2 vs DEPTH 60
1000.00
2900 2900 2900 2900 Immature Mature
Mature Postmature Postmature
G. prisca unknown - no paly repot 19/5/14 Immature
TOC

0.2 kg/tonne S2
Type II TYPE I

Dry Gas Window

Condensate - Wet Gas Zone
Oil Window
oil-prone
PY Type I oil oil prone Oil
900.00 usually lacustrine
0.5% TOC

prone Window

Condensate - Wet Gas Zone

2950 2950 2950 2950 2950 50
Goldwyer - unit 4 800.00

700.00

3000 3000 3000 3000 3000 TYPE II

Goldwyer - unit 3 40

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
Mixed type II/III usually marine
Depth (m)

Depth (m)
600.00

S2 mg/g
oil/gas prone

3050 3050 3050 3050 3050 500.00

DEPTH ( m )
30

DEPTH ( m )

DEPTH ( m )
400.00 TYPE II-III
oil-gas-prone

3100 3100 3100 3100 3100

20 300.00
Type III gas
prone

3150 3150 3150 3150 3150

S1 200.00 TYPE III
gas-prone
S2
10 Dry Gas Window
HI
100.00
OI S1
S2 Dry gas prone TYPE IV
3200 3200 3200 3200 3200 kg/ton
inert
0.0 2.0 4.0 6.0 8.0 10.0 TOC (wt%) 0 100 GR 200 300 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 10.0 20.0 30.0 40.0 50.0 0.00
400 425 450 475 500
PY (S1 + S2) 140 90 40 Tmax (oC) PI (S1/S1+S2) 0.00 200.00 400.00 600.00 800.00 1000.00 1200.00HI 0
0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Percival 1 Percival 1 Percival 1: Tmax v Depth 2000 Percival 1: PI vs DEPTH Percival 1: S1 & S2 vs DEPTH 60
1000.00
2000 2000 2000 2000 Immature Mature
Mature Postmature Postmature
G. prisca unknown from paly 19/5/14 Immature S1

0.2 kg/tonne S2
TOC Type II TYPE I

Dry Gas Window

Condensate - Wet Gas Zone
oil-prone

Oil Window
PY S2 Type I oil oil prone 900.00 usually lacustrine Oil
0.5% TOC

2020 2020 2020 2020 2020 prone Window

HI

Condensate - Wet Gas Zone

OI
50
2040 800.00
2040 2040 2040 2040

2060 2060 2060 2060 2060 700.00

TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

40
oil-prone
Mixed type II/III usually marine
2080
Depth (m)

Depth (m)

2080 Goldwyer - unit 4 2080 2080 2080 600.00

S2 mg/g
oil/gas prone
Goldwyer - unit 3

2100 2100 2100 2100 2100 500.00

DEPTH ( m )
30
DEPTH ( m )

DEPTH ( m )
Goldwyer - unit 2
2120 2120 2120 2120 2120 400.00 TYPE II-III
oil-gas-prone

2140 2140 2140 2140 2140 20 300.00

Type III gas
prone
2160 Goldwyer - unit 1 2160 2160 2160 2160
200.00 TYPE III
gas-prone

10 Dry Gas Window

2180 2180 2180 2180 2180
100.00
S1
S2 TYPE IV
Dry gas prone
2200 2200 2200 2200 2200 kg/ton inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 0.5 1.0 1.5 2.0 0.00
400 425 450 475 500
Tmax (oC) PI (S1/S1+S2) 0.00 50.00 100.00 150.00 200.00
HI 0
PY (S1 + S2) 140 120 100 80 60 40
OI 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

Whistler 1 Whistler 1 Whistler 1 Tmax v Depth Whistler 1 : PI vs DEPTH Whistler 1: S1 & S2 vs DEPTH 1000.00
820 820 820 820 820 60
Immature Mature
Immature Postmature
G. prisca in zone 839 - 867.8mRT Mature Postmature
TOC S1

0.2 kg/tonne S2
TYPE I
Oil Window

Condensate - Wet Gas Zone

Dry Gas Window

Type II oil-prone
PY S2 Type I oil oil prone 900.00 usually lacustrine Oil
0.5% TOC

Window
prone
830 830 830 830 HI

Condensate - Wet Gas Zone

830
Goldwyer - unit 4 OI 50
800.00

840 840 840 840 840

700.00
Goldwyer - unit 3
TYPE II
40

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
850 850 850 850 850 usually marine
Depth (m)

Depth (m)

Mixed type II/III 600.00

S2 mg/g
oil/gas prone

860 860 860 860 860 500.00

DEPTH ( m )
DEPTH ( m )

DEPTH ( m )

Goldwyer - unit 2 30

400.00 TYPE II-III

870 870 870 870 870 oil-gas-prone

Goldwyer - unit 1
20 300.00

880 880 880 880 880 Type III gas

prone

200.00 TYPE III

gas-prone

890 890 890 890 890 10 Dry Gas Window

100.00
Willara Fm S1
S2 TYPE IV
900 900 900 900 kg/ton Dry gas prone
900 inert
0.0 1.0 2.0 3.0 4.0 TOC (wt%) 0 100 GR 200 300 400.0 420.0 440.0 460.0 480.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 5.0 10.0 15.0 20.0 0.00
400 425 450 475 500
PY (S1 + S2) 140 120 100 80 60 40 Tmax (oC) PI (S1/S1+S2) 0.00 100.00 200.00 300.00 400.00 HI 0
Tmax (oC)
0 2 4 6 8 10 12 14 16
DT
TOC wt%

Cudalgara 2 Cudalgara 2 Cudalgara 2 : Tmax v DEPTH Cudalgara 2: PI vs DEPTH Cudalgara 2: S1 & S2 vs DEPTH
1400 1400 1400 1400 1400 60 1000.00
Immature Mature
S1 Postmature
Condensate - Wet Gas Zone

TOC
Dry Gas Window

Type II TYPE I
PY
Oil Window

S2 Type I oil oil prone oil-prone

1410
0.5% TOC

1410 1410 1410 1410 prone 900.00 usually lacustrine Oil

HI Window

Condensate - Wet Gas Zone

OI
50
1420 1420 1420 1420 1420 800.00

No S2 for PI

1430 No TOC data

1430 1430 1430 1430 700.00

40 TYPE II

HYDROGEN INDEX ( HI, mg HC/g TOC)

oil-prone
1440 Mixed type II/III
Depth (m)

1440
Depth (m)

1440 1440 1440 usually marine

S2 mg/g

oil/gas prone 600.00

No S2 for PI No S2
No log data
Goldwyer - Unit 4 No TOC for Hi or OI
No S2 for HI
1450 1450 1450 1450 1450
500.00
30
DEPTH ( m )

DEPTH ( m )

Title

1460 1460 1460 1460 1460

400.00 TYPE II-III
oil-gas-prone

1470 1470 1470 1470 1470 20

300.00
Type III gas
prone
1480 1480 1480 1480 1480
200.00 TYPE III
0.2 kg/tonne S2

gas-prone

1490 G. prisca unknown from paly - 15/09/14

1490 1490 1490 1490 10 Dry Gas Window

Title 100.00

Dry gas prone

1500 1500 1500 1500 1500 TYPE IV
inert
0.0 0.5 1.0 1.5 2.0 TOC (wt%) 0 100 GR 200 300 250.0 300.0 350.0 400.0 450.0 500.0 0.0 0.2 0.4 0.6 0.8 1.0 0.0 2.0 4.0 6.0 8.0 10.0 0.00

PY (S1 + S2) Tmax (oC) PI (S1/S1+S2) 0.00 10.00 0 400 425 450 475 500
140 90 40
Title 0 2 4 6 8 10 12 14 16 Tmax (oC)
DT
TOC wt%

NOTES:

Green triangles = Tmax data from samples with TOC >0.5% and S2 >0.2 kg HC/ton
Red triangles = Tmax data from samples with low TOC <0.5% and low S2 <0.2 kg HC/ton
Orange bands = Occurance of G prisca Ordovician algae
 Appendix D

Appendix D

Thermal Maturity (Vitrinite Reflectance) Measurements

Vitrinite reflectance measurements from open file well completion reports and a database
constructed by the Geological Survey of Western Australia was utilised in this study. These
data are included in this Appendix.

455
Well Depth (mRT) Maceral Type Mean Max Min No of Readings
Bindi 1 859.2 Vitrinite SWC 0.51 1.28 0.7 20
Bindi 1 976 Vitrinite SWC 0.56 0.48 0.32 34
Bindi 1 1065 Vitrinite SWC 0.41 0.48 0.33 23
Bindi 1 1071 Vitrinite SWC 0.56 0.76 0.42 18
Bindi 1 1235 Inertinite SWC 1.3 1.54 1
Bindi 1 1235 Vitrinite SWC 0.56 0.64 0.48 10
Bindi 1 1248.5 Vitrinite SWC 0.42 0.5 0.35 6
Bindi 1 1475.4 Vitrinite SWC 0.45 0.53 0.38 4
Bindi 1 1918.7 Inertinite SWC 1.4 1.76 1.02 25
Bindi 1 1918.7 Vitrinite SWC
Bindi 1 2481.4 Inertinite SWC 1.52 2.16 1.1 17
Bindi 1 2481.4 Vitrinite SWC
Justago 1 250 Exinite DC
Justago 1 390 Exinite DC
Kilang Kilang 1 131.8 Exinite SWC 0.57 1
Kilang Kilang 1 131.8 Inertinite SWC 1.3 1.88 1 15
Kilang Kilang 1 131.8 Vitrinite SWC
Kilang Kilang 1 131.8 Exinite SWC 0.57 1
Kilang Kilang 1 131.8 Inertinite SWC 1.3 1.88 1 15
Kilang Kilang 1 131.8 Vitrinite SWC
Kilang Kilang 1 197.8 Inertinite SWC 1.55 2.34 1.19 17
Kilang Kilang 1 197.8 Vitrinite SWC 0.58 1
Kilang Kilang 1 229.3 Inertinite SWC 1.35 2.5 0.74 14
Kilang Kilang 1 229.3 Vitrinite SWC 0.53 0.62 0.47 8
Kilang Kilang 1 236.8 Inertinite SWC 1.41 1.7 1.24 7
Kilang Kilang 1 236.8 Vitrinite SWC
Kilang Kilang 1 274 Exinite SWC 0.3 0.41 0.21 3
Kilang Kilang 1 274 Inertinite SWC 1.25 1.48 0.95 11
Kilang Kilang 1 274 Vitrinite SWC 0.54 0.63 0.46 8
Kilang Kilang 1 294 Inertinite SWC 1.41 2 0.96 14
Kilang Kilang 1 294 Vitrinite SWC
Kilang Kilang 1 338.7 Exinite SWC 0.31 1
Kilang Kilang 1 338.7 Inertinite SWC 1.38 2.26 0.94 16
Kilang Kilang 1 338.7 Vitrinite SWC 0.7 0.8 0.58 11
Kilang Kilang 1 359 Exinite SWC 0.3 0.35 0.25 5
Kilang Kilang 1 359 Inertinite SWC 1.49 2.24 0.96 16
Kilang Kilang 1 358 Vitrinite SWC 0.67 0.88 0.55 7
Kilang Kilang 1 406.4 Exinite SWC 0.36 0.57 0.25 8
Kilang Kilang 1 406.4 Inertinite SWC 1.34 1.79 1 20
Kilang Kilang 1 406.4 Vitrinite SWC
Kilang Kilang 1 437.7 Exinite SWC 0.4 0.47 0.29 3
Kilang Kilang 1 437.7 Inertinite SWC 1.63 2.68 1.1 12
Kilang Kilang 1 437.7 Vitrinite SWC 0.63 0.74 0.52 4
Kilang Kilang 1 450 Exinite SWC 0.34 0.44 0.29 4
Kilang Kilang 1 450 Inertinite SWC 1.45 2.18 0.93 13
Kilang Kilang 1 450 Vitrinite SWC 0.68 0.83 0.61 8
Kilang Kilang 1 476 Exinite SWC 0.44 0.48 0.4 2
Kilang Kilang 1 476 Inertinite SWC 1.47 1.86 1.11 15
Kilang Kilang 1 476 Vitrinite SWC 0.77 0.8 0.75 3
Kilang Kilang 1 524 Exinite SWC 0.42
Kilang Kilang 1 524 Inertinite SWC 1.47 2022 1.06 15
Kilang Kilang 1 524 Vitrinite SWC 0.8 0.92 0.71 4
Kilang Kilang 1 545 Inertinite SWC 1.61 2.02 1.28 12
Kilang Kilang 1 545 Vitrinite SWC 0.82 0.89 0.71 6
Kilang Kilang 1 610 Exinite SWC 0.34 0.43 0.25 4
Kilang Kilang 1 610 Inertinite SWC 1.37 2.24 0.85 13
Kilang Kilang 1 610 Vitrinite SWC 0.6 0.68 0.46 14
Kilang Kilang 1 631 Exinite SWC 0.29 0.46 0.19 6
Kilang Kilang 1 631 Inertinite SWC 1.47 2.54 0.77 10
Kilang Kilang 1 631 Vitrinite SWC 0.59 0.67 0.47 14
Kilang Kilang 1 642.5 Exinite SWC 0.28 0.43 0.2 4
Kilang Kilang 1 642.5 Inertinite SWC 1.38 1.98 0.82 8
Kilang Kilang 1 642.5 Vitrinite SWC 0.6 0.69 0.52 14
Kilang Kilang 1 807 Exinite SWC 0.19 1
Kilang Kilang 1 807 Inertinite SWC 1.45 2.36 0.84 15
Kilang Kilang 1 807 Vitrinite SWC 0.59 0.65 0.54 5
Kilang Kilang 1 822 Exinite SWC 0.32 0.33 0.31 2
Kilang Kilang 1 822 Inertinite SWC 1.48 2.02 1.06 15
Kilang Kilang 1 822.1 Vitrinite SWC 0.7 0.77 0.59 6
Kilang Kilang 1 889 Inertinite SWC 1.28 1.75 0.96 15
Kilang Kilang 1 889 Vitrinite SWC 0.73 0.77 0.68 8
Kilang Kilang 1 915 Inertinite SWC 1.37 1.77 1.01 15
Kilang Kilang 1 915 Vitrinite SWC 0.72 0.76 0.7 3
Kilang Kilang 1 935 Inertinite SWC 1.46 1.88 1.18 15
Kilang Kilang 1 935 Vitrinite SWC 0.75 0.87 0.45 10
Kilang Kilang 1 1000 Inertinite SWC 1.44 1.78 1.1 15
Kilang Kilang 1 1000 Vitrinite SWC 0.79 0.86 0.69 6
Kilang Kilang 1 1048 Inertinite SWC 1.41 1.78 1.1 7
Kilang Kilang 1 1048 Vitrinite SWC
Kilang Kilang 1 1135 Inertinite SWC 1.55 2.02 1.2 17
Kilang Kilang 1 1135 Vitrinite SWC 0.69 0.85 0.53 14
Kilang Kilang 1 1185 Vitrinite SWC
Kilang Kilang 1 1453.6 Inertinite SWC 1.59 1.92 1.22 9
Kilang Kilang 1 1453.6 Vitrinite SWC 0.76 0.9 0.51 8
Kilang Kilang 1 1512.2 Vitrinite SWC
Kilang Kilang 1 1757.1 Inertinite SWC 1.76 2.12 1.53 12
Kilang Kilang 1 1757.1 Vitrinite SWC
Kilang Kilang 1 1882 Inertinite SWC 1.81 2.35 1.46 21
Kilang Kilang 1 1882 Vitrinite SWC
Kilang Kilang 1 2010 Inertinite SWC 1.99 2.36 1.89 6
Kilang Kilang 1 2010 Vitrinite SWC
Kilang Kilang 1 2136.9 Vitrinite SWC
Kilang Kilang 1 2260 Vitrinite SWC
Ngalti 1 137.3 Inertinite SWC 1.25 1.68 0.84 17
Ngalti 1 175.5 Bituminite SWC 0.25 0.25 0.25 1
Ngalti 1 175.5 Vitrinite SWC 0.42 0.66 0.26 7
Ngalti 1 299 Inertinite SWC 1.3 1.3 1.3 1
Ngalti 1 299 Vitrinite SWC 0.47 0.6 0.34 8
Ngalti 1 581.9 Inertinite SWC 1.4 1.4 1.4 1
Ngalti 1 581.9 Vitrinite SWC 0.43 0.81 0.31 19
Ngalti 1 631.5 Inertinite SWC 0.97 1.54 0.74 1
Ngalti 1 631.5 Vitrinite SWC 0.46 0.5 0.41 2
Ngalti 1 806.1 Inertinite SWC 0.86 0.86 0.86 1
Ngalti 1 806.1 Vitrinite SWC 0.37 0.48 0.26 16
Ngalti 1 812.6 Inertinite SWC 1.24 1.24 1.24 1
Ngalti 1 812.6 Vitrinite SWC 0.6 0.61 0.59 ?2
Ngalti 1 817.6 Inertinite SWC 1.91 2.08 1.64 3
Ngalti 1 1103.9 Inertinite SWC 1.46 1.46 1.46 1
Ngalti 1 1103.9 Vitrinite SWC 0.58 0.63 0.51 7
Ngalti 1 1467.8 Vitrinite SWC
Ngalti 1 1824 Vitrinite SWC 0.67 0.67 0.67 1
Ngalti 1 1185 Inertinite SWC 1.43 1.84 1.02 25
Ngalti 1 1355.5 Inertinite SWC 1.42 1.92 1.02 12
Ngalti 1 1635 Inertinite SWC 1.24 1.48 0.9 12
Ngalti 1 1774.4 Inertinite SWC 1.16 1.16 1.16 1
Ngalti 1 1824 Inertinite SWC 1.34 1.58 1.04 15
Ngalti 1 2119 Vitrinite SWC
Ngalti 1 1950.2 Inertinite SWC 1.42 1.58 1.22 3
Ngalti 1 2157.3 Inertinite SWC 1.52 1.86 1.08 4
Ngalti 1 2179 Inertinite SWC 1.05 1
Ngalti 1 2265 Exinite SWC 0.32 0.32 0.32 1
Ngalti 1 2265 Inertinite SWC 1.23 1.7 0.99 5
Ngalti 1 2287 Inertinite SWC 1.3 1.58 0.96 4
Ngalti 1 2325 Inertinite SWC 1.57 2.08 1.23 4
Ngalti 1 2340.7 Inertinite SWC 1.03 1.03 1.03 1
Ngalti 1 2379.7 Inertinite SWC 1.36 1.36 1.36 1
Ngalti 1 2399 Inertinite SWC 1.86 1.86 1.86 1
Ngalti 1 2430 Inertinite SWC 1.46 1.46 1.46 1
Ngalti 1 2482.1 Inertinite SWC 1.72 1.84 1.58 3
Ngalti 1 2541 Inertinite SWC 1.51 2.1 1.05
Ngalti 1 2598.1 Inertinite SWC 1.7 2.72 1.18 20
Ngalti 1 2615.8 Inertinite SWC 1.86 2.62 1.34 10
Ngalti 1 2630 Vitrinite Cutt
Ngalti 1 2629.4 Inertinite SWC 1.69 1.69 1.69 1
Ngalti 1 2645.7 Inertinite SWC 1.84 2.7 1.34 8
Ngalti 1 2663.3 Inertinite SWC 1.73 2.24 1.21 10
Ngalti 1 2753 Inertinite SWC 1.85 2.66 1.3 15
Ngalti 1 2753.28 Inertinite SWC 2 2.72 1.36 11
Ngalti 1 2753.93 Exinite SWC 0.5 0.58 0.48 5
Ngalti 1 2753.93 Inertinite SWC 1.68 2.62 0.74 14
Ngalti 1 2754.6 Exinite SWC 0.52 0.61 0.38 6
Ngalti 1 2754.6 Inertinite SWC 1.46 2.6 0.91 10
Olios 1 220 Inertinite SWC 1.04 1.41 0.72 10
Olios 1 220 Vitrinite SWC 0.39 0.53 0.25 9
Olios 1 251.9 Inertinite SWC 1.07 1.58 0.7 13
Olios 1 251.9 Vitrinite SWC 0.46 0.52 0.38 15
Olios 1 269.1 Inertinite SWC 1.08 1.58 0.74 9
Olios 1 269.1 Vitrinite SWC 0.47 0.66 0.38 25
Olios 1 303.5 Inertinite SWC 0.88 1.04 0.71 3
Olios 1 303.5 Vitrinite SWC 0.52 0.66 0.38 19
Olios 1 375 Inertinite SWC 1.34 1.34 1.34 2
Olios 1 375 Vitrinite SWC 0.52 0.65 0.38 7
Olios 1 392 Inertinite SWC 1.02 1.31 0.78 7
Olios 1 392 Vitrinite SWC 0.53 0.6 0.41 6
Olios 1 501 Inertinite SWC 1.21 1.81 0.97 4
Olios 1 501 Vitrinite SWC 0.57 0.69 0.39 3
Olios 1 560 Inertinite SWC 1.13 1.33 0.92 8
Olios 1 580 Vitrinite SWC 0.54 0.68 0.38 13
Olios 1 577.9 Inertinite SWC 1.24 1.4 0.98 4
Olios 1 557.9 Vitrinite SWC 0.55 0.71 0.41 8
Olios 1 647 Inertinite SWC 1.1 1.4 0.81 9
Olios 1 647 Vitrinite SWC 0.58 0.7 0.43 12
Olios 1 688.1 Inertinite SWC 1.01 1.19 0.87 3
Olios 1 688.1 Vitrinite SWC 0.56 0.66 0.47 19
Olios 1 703 Inertinite SWC 1.29 1.29 1.29 1
Olios 1 703 Vitrinite SWC 0.52 0.62 0.42 5
Olios 1 733.1 Inertinite SWC 1.35 1.74 0.96 6
Olios 1 733.1 Vitrinite SWC 0.45 0.56 0.39 8
Olios 1 766.5 Inertinite SWC 1.22 1.22 1.22 1
Olios 1 766.5 Vitrinite SWC 0.51 0.64 0.4 6
Olios 1 810 Inertinite SWC 1.55 2.18 1.04 5
Olios 1 810 Vitrinite SWC 0.53 0.67 0.43 6
Olios 1 826.1 Inertinite SWC 1.5 2.22 1
Olios 1 826.1 Vitrinite SWC 0.55 0.62 0.46 4
Olios 1 847.5 Vitrinite SWC 0.55 0.73 0.43 20
Olios 1 871.1 Inertinite SWC 1.25 1.42 1.08 2
Olios 1 871.1 Vitrinite SWC 0.53 0.58 0.47 2
Olios 1 913 Inertinite SWC 1.09 1.34 1 4
Olios 1 913 Vitrinite SWC 0.64 0.71 0.49 8
Olios 1 985 Inertinite SWC 1.23 1.88 0.82 12
Olios 1 985 Vitrinite SWC 0.58 0.62 0.55 2
Olios 1 1114.75 Inertinite SWC 1.05 1.36 0.87 5
Olios 1 1114.75 Vitrinite SWC 0.64 0.74 0.5 25
Olios 1 1371.75 Vitrinite SWC 0.62 0.62 0.62 1
Olios 1 1418 Vitrinite SWC
Olios 1 1434 Inertinite SWC 1.52 1.84 1.4 2
Olios 1 1434 Vitrinite SWC 0.62 1
Olios 1 1458 Inertinite SWC 1.32 2 0.82 13
Olios 1 1458 Vitrinite SWC 0.67 0.77 0.59 3
Olios 1 1512.5 Vitrinite SWC
Olios 1 1537.5 Inertinite SWC 1.52 2.36 1.12 10
Olios 1 1537.5 Vitrinite SWC 0.67 0.79 0.57 4
Olios 1 1571.5 Vitrinite SWC
Olios 1 1701 Vitrinite SWC
Olios 1 1759 Inertinite SWC 1.81 1.92 1.04 9
Olios 1 1759 Vitrinite SWC 0.66 0.66 0.66 1
Olios 1 1858.25 Vitrinite SWC
Olios 1 1890 Inertinite SWC 1.54 1.64 1.3 4
Olios 1 1890 Vitrinite SWC 0.79 0.79 0.79 1
Olios 1 1918 Vitrinite SWC
 Appendix E

Appendix E

1D Petroleum Systems Models – Age Assignments

Age assignment inputs used within 1D petroleum systems models in this study are estimated
from exploratory well locations, published literature and seismic interpretation. These inputs
are summarised in this Appendix.

461
 Depo. start Depo. end Erosion start Erosion end
Header Layer Top (m) Base (m) Thickness (m) Eroded (m) Lithology PSE TOC (wt. %) Kinetic HI (mg HC/gTOC)
(Ma) (Ma) (Ma) (Ma)
Start date of End date of
Base of Thickness of Organic
Top depth Thickness Start date of End date of erosional erosional Remaining generative
Name of formation in formation formation Selection of lithology from Petroleum system component Model to predict petroleum generative
Explanation of of eroded formation formation period period capacity (formation
well-bore (auto (auto library element (formation extent
formation sequence deposition deposition affecting affecting average)
populated) populated) average)
formation formation
Miocene 0 0 0 50 38 15 15 0 Sandstone (typical) Overburden Rock
Tertiary - Eocene 0 0 0 50 120 38 38 15 Sandstone (typical) Overburden Rock
Cretaceous 0 0 0 300 175 135 135 120 Sandstone (typical) Overburden Rock
Triassic 0 0 0 500 220 200 200 180 Triassic_Blina_Mylet_mix Overburden Rock
Undiff. Qa 0 8.5 8.5 300 226 220 200 180 Sandstone (typical) Overburden Rock
Blina Shale 8.5 228 219.5 200 232 226 200 180 Blina_sh_mix Overburden Rock
Bindi 1 Mylet Group 228 292.5 64.5 200 242.5 232 200 180 Mylet_gp_mix Overburden Rock
Liveringa Group 292.5 629 336.5 200 253 242.5 200 180 Liveringa_Gp_mix Overburden Rock
Noonkanbah Fm 629 910 281 266 253 Noonkanbah_sh_mix Source Rock 2.2 Tissot_in_Waples(1992)_TII_Crack 36
Poole Sandston 910 990 80 271 266 Poole_Sst_mix Reservoir Rock 1.5 99.9
Grant Group 990 1832 842 305 271 Grant_sst/sh_mix Reservoir Rock 0.5 70
Anderson Formation 1832 2457 625 250 337 322 322 305 Anderson_sst/slt_mix Source Rock 0.9 Tissot_in_Waples(1992)_TII_Crack 48
Laurel Formation 2457 2504 47 345 337 Laurel_fm_carb_mix Source Rock 0.6 Tissot_in_Waples(1992)_TII_Crack 51

Depo. start Depo. end Erosion start Erosion end

Header Layer Top (m) Base (m) Thickness (m) Eroded (m) Lithology PSE TOC (wt. %) Kinetic HI (mg HC/gTOC)
(Ma) (Ma) (Ma) (Ma)
Start date of End date of
Base of Thickness of Organic
Top depth Thickness Start date of End date of erosional erosional Remaining generative
Name of formation in formation formation Selection of lithology from Petroleum system component Model to predict petroleum generative
Explanation of of eroded formation formation period period capacity (formation
well-bore (auto (auto library element (formation extent
formation sequence deposition deposition affecting affecting average)
populated) populated) average)
formation formation
Miocene 0 0 0 50 38 15 15 0 Sandstone (typical) Overburden Rock
Tertiary - Eocene 0 0 0 50 120 38 38 15 Sandstone (typical) Overburden Rock
Cretaceous 0 0 0 200 175 135 135 120 Sandstone (typical) Overburden Rock
Triassic 0 0 0 1100 220 200 200 180 Triassic_Blina_Mylet_mix Overburden Rock
Undiff. Qa 0 15 15 300 242.5 220 200 180 Sandstone (typical) Overburden Rock
Kilang
Liveringa Group 15 354.5 339.5 100 253 242.5 200 180 Liveringa_Gp_mix Overburden Rock
Kilang 1
Noonkanbah Fm 354.5 660.5 306 266 253 Noonkanbah_sh_mix Source Rock 2.2 Tissot_in_Waples(1992)_TII_Crack 36
Poole Sandston 660.5 803.3 142.8 271 266 Poole_Sst_mix Reservoir Rock 1.5 99.9
Grant Group 803.3 1448 644.7 305 271 Grant_sst/sh_mix Reservoir Rock 0.5 70
Anderson Formation 1448 1717 269 250 337 322 322 305 Anderson_sst/slt_mix Source Rock 0.9 Tissot_in_Waples(1992)_TII_Crack 48
Laurel Formation 1717 2300 583 345 337 Laurel_fm_carb_mix Source Rock 0.6 Tissot_in_Waples(1992)_TII_Crack 51
 Depo. start Depo. end Erosion start Erosion end
Header Layer Top (m) Base (m) Thickness (m) Eroded (m) Lithology PSE TOC (wt. %) Kinetic HI (mg HC/gTOC)
(Ma) (Ma) (Ma) (Ma)
Start date of End date of
Base of Thickness of Organic
Top depth Thickness Start date of End date of erosional erosional Remaining generative
Name of formation in formation formation Selection of lithology from Petroleum system component Model to predict petroleum generative
Explanation of of eroded formation formation period period capacity (formation
well-bore (auto (auto library element (formation extent
formation sequence deposition deposition affecting affecting average)
populated) populated) average)
formation formation
Miocene 0 0 0 75 38 15 15 0 Sandstone (typical) Overburden Rock
Tertiary - Eocene 0 0 0 75 120 38 38 15 Sandstone (typical) Overburden Rock
Cretaceous 0 0 0 400 175 135 135 120 Sandstone (typical) Overburden Rock
Triassic 0 0 0 850 225 200 200 180 Triassic_Blina_Mylet_mix Overburden Rock
Undiff 0 0 0 300 242.5 225 200 180 Mylet_gp_mix Overburden Rock
Liveringa Group 0 61 61 100 253 242.5 200 180 Liveringa_Gp_mix Overburden Rock
Noonkanbah Fm 61 270.5 209.5 266 253 Noonkanbah_sh_mix Source Rock 2.2 Tissot_in_Waples(1992)_TII_Crack 36
Olios 1 Poole Sandston 270.5 306 35.5 271 266 Poole_Sst_mix Reservoir Rock 1.5 99.9
Grant Group 306 815 509 305 271 Grant_sst/sh_mix Reservoir Rock 0.5 70
Anderson Formation 815 815 0 250 337 322 322 305 Anderson_sst/slt_mix Source Rock 0.9 Tissot_in_Waples(1992)_TII_Crack 48
Laurel Formation 815 1131 316 342 337 Laurel_fm_carb_mix Source Rock 0.6 Tissot_in_Waples(1992)_TII_Crack 51
Laurel Basal Carbonate 1131 1431 300 344 342 Laurel_fm_carb_mix Source Rock 0.6 Tissot_in_Waples(1992)_TII_Crack 51
Yellow Drum Fm 1431 1468 37 345.5 344 Yellow_Drum_mix Reservoir Rock
Gumhole Fm 1468 1560 92 347.5 345.5 Gumhole_mix Overburden Rock
Knobby Sandstone 1560 1963 403 349 347.5 Knobby_sst_mix Reservoir Rock

Depo. start Depo. end Erosion start Erosion end

Header Layer Top (m) Base (m) Thickness (m) Eroded (m) Lithology PSE TOC (wt. %) Kinetic HI (mg HC/gTOC)
(Ma) (Ma) (Ma) (Ma)
Start date of End date of
Base of Thickness of Organic
Top depth Thickness Start date of End date of erosional erosional Remaining generative
Name of formation in formation formation Selection of lithology from Petroleum system component Model to predict petroleum generative
Explanation of of eroded formation formation period period capacity (formation
well-bore (auto (auto library element (formation extent
formation sequence deposition deposition affecting affecting average)
populated) populated) average)
formation formation
Miocene 0 0 0 100 38 15 15 0 Sandstone (typical) Overburden Rock
Tertiary - Eocene 0 0 0 100 120 38 38 15 Sandstone (typical) Overburden Rock
Cretaceous 0 0 0 350 175 135 135 120 Sandstone (typical) Overburden Rock
Triassic 0 0 0 900 225 200 200 180 Triassic_Blina_Mylet_mix Overburden Rock
Undiff 0 7 7 300 242.5 225 200 180 Mylet_gp_mix Overburden Rock
Liveringa Group 7 112 105 100 253 242.5 200 180 Liveringa_Gp_mix Overburden Rock
Ngalti 1 Noonkanbah Fm 112 178 66 266 253 Noonkanbah_sh_mix Source Rock 2.2 Tissot_in_Waples(1992)_TII_Crack 36
Poole Sandston 178 279 101 271 266 Poole_Sst_mix Reservoir Rock 1.5 99.9
Grant Group 279 796 517 305 271 Grant_sst/sh_mix Reservoir Rock 0.5 70
Anderson Formation 796 796 0 250 337 322 322 305 Anderson_sst/slt_mix Source Rock 0.9 Tissot_in_Waples(1992)_TII_Crack 48
Laurel Formation 796 1067 271 345 337 Laurel_fm_carb_mix Source Rock 0.6 Tissot_in_Waples(1992)_TII_Crack 51
Knobby Sandstone 1067 1705 638 349 345 Knobby_sst_mix Reservoir Rock
Lennard River Group 1705 2757.8 1052.8 361 349 Bungle_Gap_mix Reservoir Rock 0.5
 Depo. start Depo. end Erosion start Erosion end
Header Layer Top (m) Base (m) Thickness (m) Eroded (m) Lithology PSE TOC (wt. %) Kinetic HI (mg HC/gTOC)
(Ma) (Ma) (Ma) (Ma)
Start date of End date of
Base of Thickness of Organic
Top depth Thickness Start date of End date of erosional erosional Remaining generative
Name of formation in formation formation Selection of lithology from Petroleum system component Model to predict petroleum generative
Explanation of of eroded formation formation period period capacity (formation
well-bore (auto (auto library element (formation extent
formation sequence deposition deposition affecting affecting average)
populated) populated) average)
formation formation
Miocene 0 0 0 150 38 15 15 0 Sandstone (typical) Overburden Rock
Tertiary - Eocene 0 0 0 150 120 38 38 15 Sandstone (typical) Overburden Rock
Cretaceous 0 0 0 550 175 135 135 120 Sandstone (typical) Overburden Rock
Triassic 0 0 0 1050 220 200 200 180 Triassic_Blina_Mylet_mix Overburden Rock
Undiff 0 0 0 200 242.4 220 200 180 Sandstone (typical)
Liveringa Group 0 378 378 300 253 242.5 200 180 Liveringa_Gp_mix Overburden Rock
Noonkanbah Fm 378 678 300 266 253 Noonkanbah_sh_mix Source Rock 2.2 Tissot_in_Waples(1992)_TII_Crack 36
Lake Betty 1
Poole Sandston 678 764 86 271 266 Poole_Sst_mix Reservoir Rock 1.5 99.9
Grant Group 764 1656 892 305 271 Grant_sst/sh_mix Reservoir Rock 0.5 70
Anderson Formation 1656 1656 0 250 337 322 322 305 Anderson_sst/slt_mix Source Rock 0.9 Tissot_in_Waples(1992)_TII_Crack 48
Laurel Formation 1656 2303 647 342 337 Laurel_fm_carb_mix Source Rock 0.6 Tissot_in_Waples(1992)_TII_Crack 51
Laurel Basal Carbonate 2303 2580 277 344 342 Laurel_fm_carb_mix Source Rock 0.6 Tissot_in_Waples(1992)_TII_Crack 51
Luluigui Fm 2580 3078 498 349 344 Bungle_Gap_mix Reservoir Rock 0.5
Poulton Formation 3078 3146 68 373 366 Poulton_estimate_mix Underburden Rock