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Site Specific Studies for Geological Storage of Carbon Dioxide
Southeast Queensland CO 2 Storage
Sites – Geological Basins Desk-Top Study
Includes a detailed assessment of the Bowen Basin
in particular the Wunger Ridge
Jacques Sayers, Cameron Marsh, Adam Scott, Yildiray Cinar, John Bradshaw,
Allison Hennig, Aleks Kalinowski, Annette Patchett, Ric Daniel,
Stuart Barclay, and Jim Underschultz
December 2006, CO2CRC Report No: RPT05-0225
Australian School of Petroleum

Site Specific Studies for Geological Storage of Carbon Dioxide.
Southeast Queensland CO 2 Storage
Sites – Geological Basins Desk-Top Study.
Includes a detailed assessment of the Bowen Basin
in particular the Wunger Ridge
Jacques Sayers, Cameron Marsh, Adam Scott, Yildiray Cinar, John Bradshaw,
Allison Hennig, Aleks Kalinowski, Annette Patchett, Ric Daniel, Stuart
Barclay, and Jim Underschultz
December 2006, CO2CRC Report No: RPT05-0225

Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC)
GPO Box 463
Level 3, 24 Marcus Clarke Street
Canberra ACT 2601
Phone: +61 2 6200 3366
Fax: +61 2 6230 0448
Email: pjcook@co2crc.com.au
Web: www.co2crc.com.au
Reference: Sayers, J., Marsh, C., Scott, A., Cinar, Y., Bradshaw, J., Hennig, A., Kalinowski, A., Patchett, A.,
Daniel, R., Barclay, S., & Underschultz, J., 2005. Site Specific Studies for Geological Storage of Carbon
Dioxide. Southeast Queensland CO 2 Storage Sites-Geological Basins Desk-Top Study. Includes a detailed
assessment of the Bowen Basin in particular the Wunger Ridge . CO2CRC Publication No. RPT05-0225.
© CO2CRC 2006
Unless otherwise specified, the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC)
Retains copyright over this publication through its commercial arm, Innovative Carbon Technologies Pty Ltd.
You must not reproduce, distribute, publish, copy, transfer or commercially exploit any information contained
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intellectual property right.
Requests and inquires concerning copyright should be addressed to the Communications Manager, CO2CRC,
GPO BOX 463, CANBERRA, ACT, 2601. Telephone: +61 2 6200 336.

Table of Contents
Preface............................................................................................................................................... vii
Executive Summary ........................................................................................................................... 1
1. Introduction .................................................................................................................................... 3
2. Geographical and Industrial Setting ............................................................................................ 5
2.1. Setting ...................................................................................................................................... 5
2.2. CO 2 Properties.......................................................................................................................... 8
2.3. Chapter References .................................................................................................................. 9
3. Geological Setting, Regional Stratigraphy and Structure ........................................................ 10
3.1. Eastern Queensland Basins .................................................................................................... 10
3.1.1. North Queensland Coastal Cenozoic Basins (includes Oil Shale Basins – Duaringa,
Yaamba, Casuarina, Hillsborough, Narrows and Nagoorin)................................................. 10
3.1.2. North Queensland Coastal Mesozoic Basin (Laura Basin). ......................................... 10
3.1.3. Styx Basin...................................................................................................................... 11
3.1.4. Clarence-Moreton Basin............................................................................................... 11
3.1.5. Nambour Basin. ............................................................................................................ 12
3.1.6. Maryborough Basin. ..................................................................................................... 14
3.1.7. Callide Basin................................................................................................................. 14
3.1.8. Esk and Abercorn Troughs. .......................................................................................... 14
3.1.9.Tarong Basin.................................................................................................................. 14
3.1.10.Calen Basin.................................................................................................................. 14
3.1.11. Lakefield Basin............................................................................................................ 15
3.2. Great Artesian, Surat, Eromanga, Carpentaria and Mulgildie Basins................................... 15
3.3. Older/Deeper Basins .............................................................................................................. 16
3.3.1 Cooper Basin ................................................................................................................. 16
3.3.2 Devonian to Carboniferous Basins (Warburton, Adavale, Drummond, Hodgkinson,
Gilberton, Bundock, Clarke River, and Burdekin Basins). ..................................................... 16
3.4. Galilee Basin .......................................................................................................................... 17
3.5. Bowen Basin .......................................................................................................................... 17
3.6. Wunger Ridge – Bowen Basin............................................................................................... 24
3.7. Chapter References ................................................................................................................ 25
4. Geological and Geophysical Datasets ......................................................................................... 28
4.1. Geological data....................................................................................................................... 28
4.2. Geophysical data .................................................................................................................... 30
5. Bowen Basin Summary Reviews................................................................................................. 31
5.1. Introduction............................................................................................................................ 31
5.2. Denison Through Study Area.................................................................................................31
5.3. East Bowen Basin Study Area – Burunga Anticline / Dulucca Area..................................... 32
5.4. Southeast Bowen Basin Study Area....................................................................................... 33
5.4.1. Well Data and Result .................................................................................................... 33
5.4.2. Seismic Data ................................................................................................................. 35
5.5. Roma Shelf Study Area.......................................................................................................... 36
5.6. Northeast Bowen Basin Study Area....................................................................................... 37
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5.7. Chapter References ................................................................................................................ 37
6. Southwest Bowen Basin Study Area - Wunger Ridge Flank................................................... 39
6.1. Seismic Interpretation ............................................................................................................ 39
6.1.1. Previous Work and Structural Framework................................................................... 39
6.1.2. Time Interpretation Seismic horizons .......................................................................... 39
Basement (BASE) ........................................................................................................................................... 41
Bandanna Formation (BAND)........................................................................................................................ 41
Rewan Formation (REWA)............................................................................................................................. 41
Showgrounds Sandstone (SHOW) .................................................................................................................. 41
Snake Creek Mudstone (SNAK)...................................................................................................................... 41
Moolayember Formation (MOOL)................................................................................................................. 41
Walloon Coal Measures (WALL) ................................................................................................................... 41
Orallo Formation (ORAL).............................................................................................................................. 42
Faults ............................................................................................................................................................. 42
6.1.3. Depth Conversion .........................................................................................................42
6.1.4. Mapping ........................................................................................................................ 43
Potential Storage Site Options Meandarra updip-to-Weribone East .................................... 43
Kinkabilla updip-to-Taylor downdip .............................................................................................................. 44
Teelba Creek updip-to-Nardoo downdip ........................................................................................................ 44
Maps and Basin Fill ...................................................................................................................................... 51
6.2. Geological Overview ............................................................................................................. 51
6.2.1. Basement ....................................................................................................................... 51
6.2.2. Permian Sediments........................................................................................................51
The Back Creek Group ................................................................................................................................... 51
6.2.3. Triassic Sediments ........................................................................................................ 52
Rewan Formation........................................................................................................................................... 52
Showgrounds Sandstone/Snake Creek Mudstone ........................................................................................... 53
Clematis Sandstone ........................................................................................................................................ 53
Moolayember Formation................................................................................................................................ 54
6.3. Showgrounds Sandstone-Snake Creek Mudstone reservoir/seal pairs.................................. 54
6.3.1. Previous Work............................................................................................................... 54
6.3.2. Cathodoluminescence Petrography .............................................................................. 55
6.3.3. Thin Section Petrography ............................................................................................. 56
6.3.4. X-ray Diffractometry.....................................................................................................57
6.3.5. Analysis of Results ........................................................................................................ 57
6.3.6. Showgrounds Sandstone Sedimentology....................................................................... 57
6.3.7. Core Interpretation ....................................................................................................... 59
6.3.8. Electrical Well-Log to Core Comparison ..................................................................... 66
6.3.9. Petrophysics.................................................................................................................. 69
6.3.10. Showgrounds- Snake Creek Mudstone Stratigraphy................................................... 70
6.3.11. Reservoir Prediction and distribution: Vertical and lateral Facies Extent and
Connectivity. ........................................................................................................................... 72
6.3.12. Showgrounds Sandstone Reservoir Prediction and Distribution................................ 75
6.4. Containment Potential: Implications for CO 2 Storage ........................................................... 77
6.4.1. Seal Distribution and Continuity .................................................................................. 77
6.4.2. Seal Capacity ................................................................................................................ 80
6.5. Geomechanical Modelling ..................................................................................................... 81
6.6. Hydrodynamic Modelling ...................................................................................................... 81
6.6.1. Introduction................................................................................................................... 81
6.6.2. Pre-production Flow System......................................................................................... 82
6.6.3. Post-production Flow System ....................................................................................... 82
6.6.4. Hydraulic Communication............................................................................................ 85
Rewan Formation- Showgrounds Sandstone.................................................................................................. 87
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Showgrounds Sandstone- Precipice Formation............................................................................................. 87
6.6.5. Water Salinity................................................................................................................ 87
6.6.6. Analysis of Results ........................................................................................................ 87
6.6.7. Further Work ................................................................................................................ 88
6.7. Reservoir Model and Simulation ........................................................................................... 88
6.7.1. Introduction................................................................................................................... 88
6.7.2. Model Description......................................................................................................... 88
6.7.3. Simulation Scenarios.....................................................................................................89
6.7.4. Simulation Results......................................................................................................... 93
6.8. Conclusions from reservoir simulation of coarse scale models ............................................. 94
Suitability of Reservoir, Seal and Trap........................................................................................................... 94
Aquifer Connectivity....................................................................................................................................... 95
Injection Characteristics ................................................................................................................................ 95
Impact of Modelled Site on Existing Natural Resources ................................................................................ 96
6.9. Chapter References ................................................................................................................ 96
7. Summary and Implications - Southeast Queensland CO 2 Storage Sites................................. 99
Summary ....................................................................................................................................... 99
Implications................................................................................................................................. 100
8. Recommendations- Southeast Queensland CO 2 Storage Sites.............................................. 101
Transportable Knowledge Base .................................................................................................. 101
Non-transportable Knowledge Base ........................................................................................... 101
Other............................................................................................................................................ 102
9. Acknowledgements..................................................................................................................... 103
10. Appendices ................................................................................................................................ 104
List of authors................................................................................................................................. 105
List of contributors......................................................................................................................... 106
List of reviewers ............................................................................................................................. 106
iii

Tables
Table 2.1. Physical properties of Carbon Dioxide.............................................................................. 8
Table 3.1. Summary of the key risk factors associated with geological storage of CO 2 in Queensland
sedimentary basins. ........................................................................................................................... 13
Table 5.1. Preliminary assessment of wells of the southeast Bowen Basin area. ............................. 34
Table 6.1. Interpreted and phantomed horizons ............................................................................... 40
Table 6.2. Listing of petrography samples numbers.. ....................................................................... 55
Table 6.3. Porosity and net reservoir thickness of the Showgrounds Sandstone. ............................. 70
Table 6.4. Sample numbers and location of where seal samples were taken from. .......................... 80
Table 6.5. Reservoir properties......................................................................................................... 91
Table 6.6. Variation with pressure of CO 2 properties....................................................................... 91
Table 6.7. Relative permeability and capillary pressure .................................................................. 91
Table 6.8. Summary of simulation study.. ......................................................................................... 92
iv

Figures
Figure 2.1. Location map showing key study areas and features in southeast Queensland ............... 5
Figure 2.2. Close-up images of study areas in the Bowen Basin........................................................ 7
Figure 2.3. Phase diagram for carbon dioxide. .................................................................................. 9
Figure 3.1. Location of selected sedimentary basins in southeast Queensland................................ 11
Figure 3.2. Stratigraphy of the Great Artesian Basin....................................................................... 15
Figure 3. 3. Basic elements of the Galilee Basin. ............................................................................. 18
Figure 3.4. Sequence Stratigraphy of the Bowen and Surat basins. ................................................. 20
Figure 3.5. Structure of the Denison Trough.. .................................................................................. 21
Figure 3.6. Key structural elements of the Taroom Trough.............................................................. 22
Figure 3.7.Schematic geological cross-section through the Roma Shelf area.................................. 23
Figure 3.8. Geological cross-sections through the northern Bowen Basin. ..................................... 24
Figure 5.1. Generic geological cross-section of the southeast Bowen Basin area........................... 34
Figure 5.2. Seismic lines used in the southeast Bowen Basin study area. ........................................ 35
Figure 5.3. Hydrocarbon fields on the Roma Shelf – Bowen Basin.................................................. 36
Figure 6.1. Seismic sections across the Wunger Ridge study area. .................................................. 45
Figure 6.2. Seismic sections across the Wunger Ridge study area. .................................................. 45
Figure 6.3. Depth map of basement across the Wunger Ridge study area ....................................... 46
Figure 6.4. TWT–depth pairs for 41 wells located in the Wunger Ridge study area........................ 47
Figure 6.5. Depth conversion flowchart. .......................................................................................... 47
Figure 6.6. Potential storage site options in Wunger Ridge study area.. ......................................... 48
Figure 6.7. BANDANNA-to-SHOWGROUNDS isopach map........................................................... 49
Figure 6.8. Seismic sections across the Wunger Ridge study area. East–west seismic-line C81-6, tie
to Kinkabilla-1 & Inglestone-1.......................................................................................................... 49
Figure 6.9. Seismic sections across the Wunger Ridge study area. East–west seismic line C81-3,
north of Kinkabilla-1......................................................................................................................... 50
Figure 6.10. Seismic section across the Wunger Ridge study area. (a) East-west seismic line HIS-
1008, Wunger Ridge flank. (b) East-west seismic line HIS-1001, downdip Wunger Ridge flank..... 50
Figure 6.11. Diagrammatic cross-section of the Wunger Ridge study area. .................................... 52
Figure 6.12. Petrographical classification of samples.. ................................................................... 56
Figure 6.13. Cross plots of permeability and porosity vs depth for Wunger Ridge samples ............ 58
Figure 6.14. Cross plot of porosity vs permeability for Wunger Ridge facies type samples............. 59
Figure 6.15.East–west/south–north cross-section of the Wunger Ridge flank.................................. 60
Figure 6.16. Photograph of Waggamba-1 core. Shows lowstand – late lowstand systems tract...... 62
Figure 6.17. Photograph of Namarah-2 core. Shows Showgrounds Sandstone, an interpreted fluvial
section. .............................................................................................................................................. 62
Figure 6.18. Photograph of Namarah-2 core. Shows Showgrounds Sandstone, shoreface to delta
distributary sandstone....................................................................................................................... 62
v

Figure 6.19. Photograph of Harbour-1 core. Shows approximately one metre of high permeability
Showgrounds Sandstone cross bedded sandstone reservoir. ............................................................ 62
Figure 6.20. Photograph of Sirrah-5 core. Depicts a low permeability baffle which is related to a
conglomeratic facies in Sirrah-5....................................................................................................... 64
Figure 6.21. Photograph of Sirrah-5 core. Depicts the Showgrounds Sandstone. Cross bedding
indicates traction current processes typical of a fluvial system........................................................ 64
Figure 6.22. Photograph of Glen Fosslyn-1 core. At the top of the figure is a wave modified ripple
in the Showgrounds Sandstone indicating shallow semi open–open water .................................... 64
Figure 6.23. Photograph of Namarah-2 core. Shows the vertical (v )and horizontal (h) bioturbation
within the Showgrounds Sandstone at Namarah-2 ........................................................................... 64
Figure 6.24. Core description of the Sirrah-5 core .......................................................................... 65
Figure 6.25. Core plug analysis for Sirrah-5....................................................................................66
Figure 6.26. Well log display from Glen Fosslyn-1 covering the Showgrounds Sandstone ............. 67
Figure 6.27. Idealised braided fluvial facies and grainsize profile .................................................. 68
Figure 6.28. Photograph of Harbour-1 core. Depicts the fining upward section............................. 68
Figure 6.29. Idealised meandering fluvial facies and grainsize profile............................................ 68
Figure 6.30. Photograph of Rednook-1 core. Depicts a coarsening upwards section, interpreted as
a lacustrine deltaic sequence. ........................................................................................................... 69
Figure 6.31. Example of the facies profile for a fluvially dominated lacustrine delta...................... 69
Figure 6.32. Relative palaeo-water level curve. ............................................................................... 71
Figure 6.33. Photograph of Glen Fosslyn-1 core. Shows intra-Showgrounds Sandstone shale....... 72
Figure 6.34. Photograph of Yellowbank Creek North-1 core. Shows the rapid transgression of the
Showgrounds Sandstone by the Snake Creek Mudstone ................................................................... 72
Figure 6.35. Multi-channel thickness vs. sedimentary environment cross-plot. ............................... 73
Figure 6.36. Width-to-thickness ratio chart...................................................................................... 74
Figure 6.37.Generic diagram of point-bar complex from the Mississippi River ............................. 76
Figure 6.38. Block diagram of a fluvial braided channel.. ............................................................... 76
Figure 6.39. Interpretation of palaeogeography/environment of deposition of the Showgrounds
Sandstone lowstand systems tract. .................................................................................................... 78
Figure 6.40. Interpretation of palaeogeography/environment of deposition of the Showgrounds
Sandstone early transgressive systems tract. ....................................................................................79
Figure 6.41. Interpretation of palaeogeography/environment of deposition of the Showgrounds
Sandstone mid transgressive systems tract. ......................................................................................79
Figure 6.42. Interpretation of palaeogeography/environment of deposition of the Snake Creek
Mudstone highstand systems tract..................................................................................................... 80
Figure 6.43.Pre-production flow system of the Showgrounds Sandstone......................................... 83
Figure 6.44. Modified flow system for ~1990. .................................................................................. 84
Figure 6.45. Head vs spud data for wells sub-divided into formation. ............................................. 86
Figure 6.46. Head vs spud data for wells.......................................................................................... 86
Figure 6.47. Generic model of lithologies, sedimentary environments and trapping mechanisms of
the Showgrounds Sandstone present within the model area. ............................................................ 90
Figure 6.48. Numerical simulation results showing gas saturation and reservoir pressure ............ 93
vi

Preface
Queensland is a major producer of electricity, derived overwhelmingly from coal but with coal seam
methane an increasingly important energy source. As a result of this high level of dependency on
fossil fuels, Queensland is also a large scale emitter of carbon dioxide. The State has no wish to
limit its access to cost effective energy but at the same time seeks to contribute to the overall
objective of decreasing Australia’s greenhouse gas signature. One of the options for doing this lies
with the application of carbon dioxide capture and storage (CCS) or geosequestration to major
stationary emissions.
This report outlines a study of a part of Queensland’s Bowen Basin, where a detailed study of CO 2
storage capacity has been undertaken by a large number of CO2CRC researchers from a range of
institutions. The study provides an excellent example of the type of work that must be undertaken if
we are to effectively characterize a geological storage site and demonstrate that it will meet the
requirements of storage security and capacity. The study convincingly demonstrates that the
Wunger Ridge is likely to be technically suitable as a CO 2 storage site. Obviously more work is
necessary to turn that potential into a technical and economic reality but this Report represents a
very important first step.
I thank all the researchers for their work and also the peer reviewers for their contribution.
Peter J. Cook CBE FTSE
Chief Executive CO2CRC
Cooperative Research Centre for Greenhouse Gas Technologies
July 2006
vii

Executive Summary
The GEODISC program within the Australian Petroleum Cooperative Research Centre
(1999 –2003) project conducted research into geological storage of CO 2 to help provide
information on options for geological storage of CO 2 . A follow-up programme conducted through
the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC; 2004 – present)
aims to further develop that research to better understand the risk and uncertainties associated with
long term geological storage. This report represents research that characterises storage sites within
CO2CRC Project 1.1.
A regional review of Queensland’s sedimentary basins was carried out to identify technically viable
areas for injection and storage, prior to focusing the remaining work programme on the storage sites
with the highest potential of success at various scales (i.e. pilot, demonstration and semi regional).
This regional review confirmed that the Galilee and Bowen sedimentary basins
possessed geological characteristics suitable for the injection and storage of CO 2 generated in
southeast Queensland. As the Galilee Basin is significantly further away from potential CO 2
emission sources, the Bowen Basin was considered more suitable from a “proving of technology”
viewpoint and assessed more comprehensively.
A review of the Bowen Basin identified that the eastern side had poor reservoir and seal
characteristics in contrast to the western side which had formations with fair to good injectivity
and storage potential which were overlain by significant regional seals. The review identified the
Showgrounds Sandstone (reservoir) – Snake Creek Mudstone (seal) pair, overlain by the
Moolayember Formation (secondary seal) in the Wunger Ridge area, as having the most favourable
properties for CO 2 injection and storage. Multi-scale projects from pilot to sub-commercial sites can
be demonstrated here although detailed estimates of storage volumes have not been carried out.
A study of the Showgrounds Sandstone indicates that permeability and environment of deposition
can be correlated and that the environment is predictable using sequence stratigraphic concepts.
The interpreted geological model encompasses braided, then meandering stream systems trending
southwest–northeast terminating at the palaeoshoreline in deltaic environments. Permeability ranges
up to eight Darcies with net sand thickness up to 17 m in the Showgrounds Sandstone on the
Wunger Ridge. Petrological analyses showed the sand facies as being sourced from both the
Timbury Hills Formation and Roma Granite, both representing economic basement and having
alternate periods of dominance. The sandstones sourced from the granite generally have better
reservoir characteristics.
Regionally, the potential contamination of the Great Artesian Basin (GAB), which is an important
water resource and overlies the targeted reservoir–seal pair, is a key risk to the eventual success of
the project. This risk was addressed by identifying seals with proven historical integrity using the
distribution of hydrocarbon pools trapped in the subsurface, as well as assessing the seals’ integrity
directly from samples.
Mercury injection capillary pressure (MICP) measurements showed the Snake Creek Mudstone
capable of holding a column of CO 2 up to 910 m. Seismic interpretation suggests that the combined
primary and secondary seal thickness exceeds 250 m on the Wunger Ridge flank and that it is
relatively un-faulted, suggesting that the seal has lateral integrity across the flank area. Anticipated
trapping mechanisms on the flank area include small scale stratigraphic traps and residual trapping
which exert little pressure on bounding seals. As such, the seal competence required is relatively
low for strength but high for lateral continuity. High seal strength is desirable around any potential
injection site where high pressures are expected as a result of the injection operation. The Wunger
Ridge area is in one of the most quiescent areas for earthquake activity in Australia.
The hydrodynamic results suggest that the Showgrounds Sandstone is not in hydraulic
communication with the overlying GAB within the greater Wunger Ridge area. Hydrodynamic
results showed a pre-production weak aquifer drive within the Showgrounds Sandstone of 0.2 m/yr
towards a hydrodynamic low east of the Wunger Ridge in the Teelba Creek area, which suggests
1

that a long-term mechanism exists to move water away from the potential storage area.
Post–production, the hydrodynamic flow of 0.9 m/yr is focused towards a low caused by
hydrocarbon production activities on the southern Wunger Ridge. Hydrodynamic flows ranging
from 0.2–0.9 m/yr are fairly modest when compared with the flow rate of the CO 2 front which was
simulated to be migrating at an average of 174 m/y for the first 25 years (the injection phase).
Multiple reservoir engineering scenarios tested injection rates for various permeability–height
combinations, horizontal–vertical well combinations, as well as variations of other geological
(i.e. heterogeneity) and engineering parameters (i.e. injection pressure and well spacing parameters).
Reservoir volumetric estimates are currently uncertain and are not included in this report. Future
volumetric estimates will be based on both static 3D geological and dynamic models.
The preliminary dynamic modelling of a 30 x 10 km area suggests that storage space for a scenario
involving the expected 25 year life-span of a small 200 Megawatt (MW) power station would be
available. Such a scenario would involve injection rates at approximately 1.2 Mt per year for a
total volume of approximately 30 Mt.
Simulation runs using simple models, based on a coarse-scale grid, suggest that either one
horizontal or two vertical wells are required to inject at the proposed rate. Geological heterogeneity
increases injection pressure around the wellbore and reduces injection rates compared to
homogeneous models, resulting in the need for more injection wells.
This study has ascertained CO 2 storage potential on the Wunger Ridge flank based on reservoir
simulation of coarse-scale models. A second phase of work would be required to encompass further
complexities of the geology and ascertain the extent of the impact of petroleum exploration
activities on the project. Large-scale storage potential may exist in low permeability rocks in areas
away from well control. Small-scale storage potential will exist when fields of the Denison Trough,
Roma Shelf and Wunger Ridge become depleted. The Moonie field could also become available for
storage subject to operator consent.
2

1. Introduction
Significant debate in the international community regarding elevated levels of carbon dioxide (CO 2 )
raised interest in geological storage of CO 2 as being an intermediary solution prior to possible noncarbon
based energy solutions being implemented in the future. Coal-fired power stations represent
Australia’s primary energy source across all states.
The primary objectives of the project were to identify both potential pilot and large-scale storage
sites, build a three dimensional (3D) geological model, simulate fluid flow and develop a greater
understanding of the risk and uncertainties associated with long term geological storage at specific
sites, as part of the process of geoscientific and engineering site characterisation.
Geoscience Australia is responsible for coordinating Project 1.1 – Technologies for Assessing Sites
for CO 2 Storage for the CO2CRC using additional specialised input from agencies including the
Commonwealth Scientific and Industrial Research Organisation (CSIRO), Australian School of
Petroleum (ASP) and the University of New South Wales (UNSW). The work on the south east
Queensland region to date represents 4.5 work years of effort undertaken by geoscientists at
Geoscience Australia.
The project included:
1. regional basin evaluations for Queensland;
2. professional opinions on specific sites;
3. data entering and Geoscientific interpretation and analysis in Geographical Information
Systems (GIS), Geoframe TM and Petrosys TM software;
4. the acquisition and quality controlling of seismic and well data to largely cover the Bowen
and Galilee basins. The data covering the Galilee Basin was used for in a separate project;
5. short-term assessments within the Taroom and Denison troughs;
6. a multidisciplinary assessment of the Wunger Ridge area, and
7. research paper accepted for publication by American Association of Petroleum Geologists
(AAPG).
The assessment considered all basins in Queensland, of which the Bowen and Galilee basins were
prioritised for further evaluation. Of the two basins, the Bowen Basin is considered in this report.
Within the Bowen Basin, individual study areas were targeted for study, these include the:
1. Denison Trough;
2. east Bowen Basin Study Area (Burunga Anticline/Dulucca area);
3. southeast Bowen Basin Study Area;
4. northeast Bowen Basin Study Area;
5. Roma Shelf, and
6. Wunger Ridge flank.
The above options were prioritised. Option 5 was only superficially assessed at this stage, for
reasons discussed in the main body of the report. Option 1 is considered viable but storage sites
would require testing in relatively low porosity and low permeability reservoirs (i.e. ~ < 70 mD and
5 % porosity). The suitability of CO 2 storage in tight reservoirs is known to be viable overseas
(e.g. In Salah, Algeria) but until recently was not considered seriously in Australia. Options 2, 3 and
4 were assessed because of the area’s proximity to power-stations located on the eastern seaboard.
Option 6 was considered as the most favourable option for a comprehensive study, involving 3D
geological models and reservoir simulation.
3

The Wunger Ridge area (60 km by 40 km; southwest Bowen Basin) was considered too large to run
a full reservoir simulation at an appropriate resolution. A small 29.5 km by 10 km area on the
Wunger Ridge flank contained many of the geological and hydrological elements expected to be
found along the western flank of the Bowen Basin, and as such, results were deemed potentially
transferable to other areas of the basin. Simple 2D and 3D geological models were built and
reservoir simulations were run using multiple scenarios to provide the greatest amount of
understanding of the more significant factors affecting the behaviour of CO 2 in the subsurface.
This report principally focuses on the geology, hydrodynamics, geophysics, and reservoir
engineering aspects of the Wunger Ridge flank site. The report also summarises the geoscientific
findings of the regional evaluations.
4

2. Geographical and Industrial Setting
2.1. Setting
The Bowen Basin is a mature hydrocarbon basin located in eastern central Queensland. The Basin
extends from just south of Townsville to beyond the Queensland–New South Wales border, and
stretches from Moura to west of Springsure or Moonie to east of St George, covering approximately
150,000–200,000 km 2 (Figure 2.1).
Figure 2.1. Location map showing key study areas and features in southeast Queensland. a) Denison Trough, b)
east Bowen Basin (Burunga Anticline/Dulacca area and NE Bowen Basin), c) Wunger Ridge and flank
(Roma Shelf to the north, d) southeast Bowen Basin (for a closer view of assessed areas (a – d) see Figure 2.2).
The Brisbane (including Tarong and Rockhampton–Gladstone) region emits a significant quantity
of CO 2 . Combined, Queensland emitted 145.1 Mt (million tonnes) or 2.73 TCF (trillion cubic feet)
of CO 2 for 2002 (Australian Greenhouse Office, 2005).
5

The Rockhampton–Gladstone region (Figure 2.1) is a major emission node as it contains five major
CO 2 emitters, representing 49 % of Queensland’s total possible sequesterable stationary CO 2
emissions. The area has the potential for a large scale capture project, with storage in either the
southern Bowen Basin and/or Denison Trough (part of the Bowen Basin). Geological assessments
of the major sedimentary basins in Queensland suggested that the Bowen and Galilee basins contain
a number of small to large scale options for the geological storage of CO 2 . The Bowen Basin alone
could provide sufficient storage volume to make significant cuts to Queensland’s CO 2 emissions
profile.
The Bowen Basin contains producing hydrocarbon pools which upon depletion may provide long
term storage and injectivity options, relatively close to southeast Queensland’s major CO 2 emission
hubs. On that basis, it was decided to concentrate on this basin for the first phase of the work.
A summary of the geology and risk factors associated with the potential for CO 2 storage of the
sedimentary basins in Queensland is provided in Chapter 3.
The Bowen Basin is located between 300 and 600 km west to northwest of Brisbane and 100 to 200
km west of the Rockhampton - Gladstone region. The Basin supplies both gaseous hydrocarbons
and coal to the electricity producers and major industries. These are also the major CO 2 emitters in
southeast Queensland. This has resulted in a large infrastructure network of rail lines and pipelines
joining the Bowen Basin to the east coast of Queensland. This infrastructure may provide potential
access corridors for CO 2 pipelines in the future. These pipelines could subsequently be extended
further west to the Galilee Basin if a suitable storage site is identified.
Due to the large volumes of CO 2 expected to be emitted from the southeast Queensland region, a
number of possible CO 2 geological storage options were examined in the Bowen Basin. The basin
was divided into a number of study areas, as discussed in the introduction.
1. Denison Trough;
2. east Bowen Basin Study Area (Burunga Anticline/Dulucca area);
3. southeast Bowen Basin Study Area;
4. northeast Bowen Basin Study Area;
5. Roma Shelf, and
6. Wunger Ridge flank.
The Roma Shelf located near the township of Roma and northeast Bowen Basin are yet to be fully
assessed for geological storage of CO 2 . This is due to an increase in a number of risk factors in the
northeast of the Bowen Basin, including faulting, and interpreted poor reservoir quality. The Roma
Shelf assessment is contingent on the Wunger Ridge results.
The Denison Trough (Figure 2.2a) is favourably located due to its proximity to a major emission
hub in the Rockhampton–Gladstone region. The Denison Trough contains a significant volume of
hydrocarbons that are currently in production. The development of infrastructure for the
compression and transport of hydrocarbon gas from the Denison Trough to the east coast may assist
in provision of access to land for CO 2 transportation facilities (e.g. pipelines).
6

Figure 2.2. Close-up images of study areas in the Bowen Basin.
a) Denison Trough, b) east Bowen Basin (Burunga Anticline/Dulacca area and NE Bowen Basin), c) Wunger
Ridge and Roma Shelf to the north, d) southeast Bowen Basin.
7

Due to its location (proximal to the Rockhampton–Gladstone region) and existing pipeline
corridors, the Denison Trough in the northwest Bowen Basin appears suitably located to act as a
node/distribution centre for multiple CO 2 injection sites in the Galilee and Bowen basins.
The east Bowen Basin area (Burunga Anticline, Dulacca area; Figure 2.2b) is located adjacent to the
township of Wandoan, 300 to 350 km from Brisbane, Rockhampton and Gladstone regions. With
only small CBM (coal bed methane) fields located in this region, the smallest area examined, the
Burunga Anticline/Dulacca area, has limited infrastructure and minimal data on the deeper potential
CO 2 storage reservoirs. The limited data indicates a high risk of less than optimal reservoir (using
the current minimum cut-off of 50 mD for optimal CO 2 injection).
The Wunger Ridge flank area (Figure 2.2c) contains significant producing hydrocarbon
accumulations and associated infrastructure. Located in the southwest Bowen Basin, it is suitably
placed to accept CO 2 emissions from a southeast Queensland hub servicing the greater Brisbane
area. Direct pipeline access to Brisbane, via the Jackson–Moonie–Brisbane oil pipeline potentially
provides an easement for CO 2 infrastructure.
The southeast Bowen Basin area (Figure 2.2d) is the closest region to Brisbane, less than 300
kilometres, and has direct pipeline access via the Roma–Brisbane gas pipeline in the north and the
Jackson–Moonie–Brisbane oil pipeline in the south. The southeast Bowen Basin area has very
minor hydrocarbon production and as such has little internal infrastructure.
Work is presently being conducted by a private consortium that is considering building an
integrated gasification combined cycle (IGCC) plant in Queensland (IEAGHG, 2005). This
consortium may have to consider injection in less than optimal reservoirs with a minimum average
permeability of around 2–5 mD. If this innovative programme is successful in injecting CO 2 at rates
which match the expected emissions, then the east and southeast Bowen Basin areas could
potentially become attractive.
2.2. CO 2 Properties
Industrial and power generation processes in the state of Queensland are currently emitting large
volumes of CO 2 with power usage and corresponding CO 2 emissions expected to grow significantly
in the coming years. If geological storage of CO 2 is to have a significant impact on these emissions
then storage space must be used effectively.
Injecting CO 2 in a supercritical phase has major benefits for injectivity and storage efficiency. In a
supercritical phase, the CO 2 has a viscosity less than the liquid phase, a diffusivity similar to the gas
phase, but has been compressed to the point were it has similar density to the liquid phase
(Table 2.1). Having CO 2 in a supercritical phase greatly increases the volume of CO 2 able to be
stored within a geological formation. At 800 m, the pressure exerted at depth is approximately 8
Mpa, and the temperature is normally greater than 32 0 C, which are the conditions at which CO 2
enters a supercritical phase (Figure 2.3, Bachu, 2001). Therefore, having a reservoir–seal pair at
depths greater than 800 m is desirable for CO 2 storage.
Table 2.1. Physical properties of Carbon Dioxide (After Cook et al., 2000).
Phase Density (g/mL) Viscosity (poise) Diffusivity (cm 2 /s)
Gas 0.001 0.00005–0.00035 0.1–1.0
Supercritical fluid 0.2–0.9 0.002–0.001 0.00033
Liquid 0.8–1.0 0.003–0.024 0.000005–0.00002
8

10000
1000
AOI for carbon
dioxide injection
Carbon Dioxide Phase Diagram
Zone of Interest for Geological Storage
SOLID
100
10
Pressure Mpa
LIQUID
SUPERCRITICAL
Critical Point
1
Triple Point
VAPOR
GAS
Temperature Celcius
STP = 15 Centigrade and
0.101325 Mpa
0
-100 -50 0 50 100 150 200
Figure 2.3. Phase diagram for carbon dioxide. Shows temperature and pressure relationships for different
phase states of CO 2 (after Bachu, 2001).
2.3. Chapter References
Australian Greenhouse Gas Office, 2005. State and Territory Greenhouse Gas Emission - An
Overview. Department of the Environment and Heritage, Australian Government.
Bachu, S., 2001. Geological sequestration of anthropogenic Carbon Dioxide: Applicability and
current issues, in Gerhard, L.C., Harrison, W.E and Hanson, eds., Geological perspectives of global
climate change. P. 285–303.
Bradshaw, B., Bradshaw, J., Dance, T., Reilly, N.S., Sayers, J., Spencer, L. & Wilson, P., 2003.
GEODISC ArcView GIS Version 2.01. APCRC Confidential GIS.
Cook, P.J., Rigg, A. & Bradshaw, J., 2000. Putting it back were it came from: is geological disposal
an option for Australia?. APPEA Journal 40(1), p. 654–666.
IEAGHG, 2005. Greenhouse issues no. 70, September 2005. www.ieagreen.org.uk.
9

3. Geological Setting, Regional Stratigraphy and Structure
To make a full assessment of the potential for geological storage of CO 2 from southeast Queensland
sources, it was important to examine all storage possibilities within Queensland. The first step in
this process was a regional overview of Queensland sedimentary basins (Figure 3.1) to identify all
possible areas where CO 2 might be stored in geological formations.
Igneous and metamorphic rocks generally lack significant pore space and permeability to store
substantial volumes of hydrocarbons and as such, are not considered suitable for the geological
storage of CO 2 . As a result, the only possible locations for the geological storage of CO 2 are areas
where there are significant volumes of sedimentary rocks (i.e. sedimentary basins).
Deposition in sedimentary basins began in Queensland in the Proterozoic in the northwest and north
of the state (Mount Isa) with predominantly fine grained sediments resulting in rocks that today
contain little to no effective porosity and therefore little storage capacity (Day et al., 1983).
Deposition continued in Queensland throughout the early Palaeozoic, Mesozoic and Cenozoic
across large parts of the state, resulting in a number of basins with the geological characteristics that
could allow them to store CO 2 in the subsurface (Day et al., 1983).
Some key characteristics related to geological storage of CO 2 of the sedimentary basins active
during early Palaeozoic, Mesozoic and Cenozoic were documented and compared to the five basic
risk factors used to assess suitability for CO 2 storage (Table 3.1). As a result of the overview, this
project focused on the Permo-Triassic Bowen Basin. A detailed analysis of the Carboniferous–
Triassic Galilee Basin is the subject of a separate project.
3.1. Eastern Queensland Basins
The following summaries relied heavily on the work performed under the GEODISC program and
where possible are using data directly from that report.
3.1.1. North Queensland Coastal Cenozoic Basins (includes Oil Shale Basins – Duaringa,
Yaamba, Casuarina, Hillsborough, Narrows and Nagoorin).
These basins, as a group, tend to be small, shallow, lightly explored and shale prone with poor
reservoir development. These characteristics indicate a large uncertainty for potential storage
volume and reservoir quality risk. Carbon dioxide injection into oil shale could be a future option
using organic adsorption similar to coal. However this is still only at the conceptual stage with a
trial underway located in the state of Kentucky, U.S.A.
The GEODISC project stated that, the onshore Hillsborough Basin displays poor reservoir character
and therefore offers no potential for CO 2 sequestration. In addition to this, a ban on offshore
exploration, due to its proximity to the Great Barrier Reef, means the rest of the Hillsborough Basin
can not be assess (Bradshaw et al., 2003). GEODISC did not assess the other Cenozoic Basins.
3.1.2. North Queensland Coastal Mesozoic Basin (Laura Basin).
Three petroleum exploration wells and one stratigraphic well have been drilled in the Laura Basin
(Denaro & Shield, 1993). The base of the sealing units are between 282–359 m deep and the basin
is therefore too shallow to maintain CO 2 in the supercritical state. Due to an absence of suitable
reservoirs at depths greater than 800 m and the economic importance of the groundwater resources
in this region, the Laura Basin has been assessed as having little potential for the geological storage
of CO 2 .
“The Laura Basin is not a viable geological sequestration option due to the lack of suitable ESSCI’s
at depths >800m and the economic importance of groundwater resources in the area”
(Bradshaw et al., 2003).
10

l
l
145° 150°
l
Moranbah
Long reac h
Galilee
Basin
SB
CTB
Roc kha m pton
Blackwater Stanwell
Gladstone
Blac ka ll
Sp ring sure
Moura
CYB
CTB
Callide
MB
-25°
l
Cooper
Basin
Bowen
Basin
Wandoan
Eromanga
Basin
Surat
Basin
Wunger
Ridge
St George
CMB
0 50 100 200
Figure 3.1. Location of selected Key Population sedimentary Centres basins Power in Stations southeast Pipelines Queensland. Rail Basins are shaded. CMB =
Clarence–Moreton Km Basin; EAT = Esk and Abercorn Troughs; TB = Tarong Basin; NB = Nambour Basin;
l
MB = Maryborough Basin; CYB = Callide Basin; CTB = Coastal Cenozoic Basins; SB = Styx Basin. Underlying
older basins have not been shown.
Rom a
Moonie
l
Kogan Creek
Millmerran
TB
Tarong
EAT
Swanbank
Brisbane
NB
3.1.3. Styx Basin
The Styx Basin (Figure 3.1) contains a shallow, less than 400 m, Cretaceous age succession of
coastal sandstone, shale, conglomerate and coal (Malone et al., 1969; Day et al.,1983). The basin is
considered too small and shallow with little good quality reservoir development to store the volume
of CO 2 required to match emissions.
3.1.4. Clarence-Moreton Basin.
Ipswich and Greater Brisbane Area.
Based on the 19 exploration wells (~ < 250 m deep) and 5 stratigraphic wells drilled (P.R.A.D.S,
1990), the Ipswich Coal Measures are interpreted to crop out within the Ipswich and Greater
Brisbane area (Figure 3.1) or are close to the surface. All formations beneath the Ipswich Coal
Measures have very high volcanic content, which is prone to diagenetic alteration that reduces
injectivity and therefore offer no reservoir potential. The Ipswich Basin is dominated by a series of
north–northwest trending faults (P.R.A.D.S, 1990) which are unfavourably orientated with respect
to the regional stress regime. This indicates a potential seal risk associated with the faults (Enever,
1990). The Ipswich Basin has no CO 2 sequestration potential due to the shallow depth and the lack
of effective vertical and lateral seals.
The geological sequestration potential of the Ipswich Basin is considered to be negligible, with the
only (though relatively poor) option being to inject CO 2 into coal seams from the Ipswich Coal
Measures (Bradshaw et al., 2003).
11

Western Part of Basin
Glamorgan-1 is the deepest of only a few wells drilled into the western Clarence–Moreton Basin.
The well intersected five metres of sandstone at a depth of 875 m (KB). Tuff fragments within the
sandstone indicate a high potential for reactivity with a CO 2 fluid (i.e. they are prone to diagenetic
alteration, which reduces injectivity). The area has high reservoir risk and negligible potential
storage volume. Reservoir quality does improve to the west (Thompson, 1987) and into the
adjoining Surat Basin. However, these potential reservoirs are relied upon heavily to supply
substantial quantities of ground water for irrigation and therefore cannot be used for CO 2 storage.
Southern Highlands Queensland
In this basin conventional gas was intersected at a depth of only 580 m, where the coal rank is low.
Russell (1994) suggested the source of the gas was thermogenic migrating from a mature deeper
source. This implies vertical migration and minimal long term sealing potential in the deeper
section. In addition, sample analysis shows the porosity of the main reservoir interval to be less than
7% (Thompson, 1987). As mentioned above, low porosity and permeability reservoirs are still being
evaluated for their potential as CO 2 storage sites.
New South Wales
Petroleum exploration to date (12 wells) has targeted various intervals and has failed to prove even
very small hydrocarbon volume potential (< 30 BCF). Sandstones in this part of the Clarence–
Moreton Basin are very lithic and the fluvial depositional environment indicates high potential for
laterally discontinuous seals (i.e. likely upward migration). Reservoir analysis estimates porosities
of less than five percent and permeabilities of less than 10 mD. The sandstone generally has a high
lithic content, including feldspars, carbonates, chert and volcanics. Some of the best porosity
measurements originate from the Walloon Coal Measures sandstones which have a clay dominated
matrix and no overlying sealing unit.
Clarence–Moreton Basin – Summary
The present dataset is not extensive enough for a detailed CO 2 storage assessment of the basin,
however the data that does exist suggests that overall the Clarence–Moreton Basin has a high
reservoir risk with unproven to leaky seals. The Ma Ma Creek seal, considered the most reliable
(O’Brien et al., 1994), has internal lithologies from which a reading of 11.2% porosity was
measured (Thompson, 1987). This reading exceeds the porosity of most sandstone reservoirs in the
Clarence–Moreton Basin.
The GEODISC project stated the Clarence-Moreton Basin has good potential to hydrodynamically
sequester large volumes of CO 2 within the Ripley Road Sandstone (Southern Highlands Queensland
and New South Wales, Bradshaw et al., 2003). However reservoir quality of sandstones in this basin
is generally poor, but erratic and leaky faults pose a significant containment risk – highlighted by
the discovery of gas in fractured basalts at a depth of 580m.
3.1.5. Nambour Basin.
The Nambour Basin shown in figure 3.1 has little potential for CO 2 storage because of the shallow
depth and absence of suitable seals. The basin is poorly explored, with a total sediment thickness
of approximately 500 m (Day et al., 1983). Storage volume would be comparatively low with
comparatively high risk as the CO 2 would be stored at sub-critical temperatures and pressures
without a regional seal to prevent vertical migration. The Nambour, Moreton and Maryborough
basins were interconnected during the Early Jurassic (Day et al., 1983) suggesting that a sequence
stratigraphic model incorporating data from all three basins may possibly indicate areas useful for
niche CO 2 storage opportunities. “The Nambour Basin has no potential to sequester CO 2 from either
major or minor sources” (Bradshaw et al., 2003).
12

Table 3.1. Summary of the key risk factors associated with geological storage of CO 2 in Queensland sedimentary basins.
Basin
Group
Basin Names Basin Initials Basin Age
Key Risk Factors
Depth Reservoir Seal Groundwater Size Faulting
Data Volume
Additional Comments
Coastal Tertiary Basins
(inc. Oil Shale Basins –
Duaringa, Yaamba,
Casuarina, Hillsborough,
Narrows and Nagoorin
CTB
Tertiary
Mostly
shallow
Shale prone
Anticipated to
be adequate
No reservoirs
Mostly small
Can be
significant
Poor at depth
Under explored at depth
due to poor reservoir
development and
exploration results
Laura Basin (north of
Cairns)
LB
Jurassic to
mid-
Cretaceous
Seal ~350m Good Too shallow
Economically
significant
Significant Minor Poor
Parts protected by
Great Barrier Reef
World Heritage marine
park
Styx Basin
SB
Early
Cretaceous
Too shallow
Poorly
developed
High risk Minor usage Very small Variable Significant
Heavily explored and
mined for coal. ~500 ─
600m
Eastern Qld Basins
Clarence–Moreton Basin
Nambour Basin
Maryborough Basin
CMB
NB
MB
Latest Triassic to mid-Cretaceous
Potentially
adequate
Relatively
shallow
Adequate
Poor – 11%
Highly lithic
Economically
porosity
and volcanic.
significant in
(Thompson,
High risk
parts
1987)
Quite large
Present Not present Minor usage Small
Poor potential
(P.R.A.D.S, High risk Shallow use Significant
1990)
Can be
significant
Some faulting
(P.R.A.D.S,
1990)
Heavily (Hill,
1994)
Inadequate
Sufficient
Poor
Basin being monitored
for future exploration
Extends under Fraser
Island and Great
Barrier Reef World
Heritage Marine Park
Callide Basin/Yarrol
Block
CAL
Middle
Permian to
Late Triassic
Too shallow Poor quality High risk Shallow usage Small Some Sufficient
Esk and Abercorn
Troughs
EAT
Early to
Middle
Triassic
Shallow Very poor High risk MA Very small Some Small
Thickest known
accumulation of
volcanic extrusives in
Qld (Day et al., 1983)
Poorly
Tarong Basin TB Late Triassic
~300m (Day
et al., 1983)
developed
(Day et al.,
NA NA Very small NA Small
1983)
Calen Basin (Mackay) CB Permian
Generally too
shallow
Heavily
intruded
NA NA Very small NA Small
Very heavily intruded
(Brakel, 1989)
Unknown –
Lakefield Basin (underlies
Laura Basin)
LFB Permian Adequate
only top 100m
penetrated
(Wellman,
Unknown Not used Significant Variable Inadequate
10km of seismically
define sediments
(Wellman, 1995)
1995)
Great Artesian
Basin (GAB)
Surat, Eromanga,
Carpentaria and
Mulgildie Basins
GAB
Jurassic to
Cretaceous
Adequate
Fantastic
Adequate (but
numerous water
bore
penetrations)
Economically
significant
Covers most
of state
Some
Significant
10s to 100s of thousands
of water bores present
leakage risk
Older/Deeper Basins
Cooper Basin
Warburton, Adavale,
Drummond, Hodgkinson,
Gilberton, Bundock,
Clarke River and
Burdekin Basins
COB
ODB
Permian to
Triassic
Devonian to
Carboniferou
s
Very deep
Mostly very
deep (overlain
by up to two
other basins)
Generally
poor
Generally
very poor
(significant
diagenesis)
Excellent
No water but
significant
hydrocarbons
Quite Large Significant Significant
Adequate NA Significant Significant Adequate
1000km from nearest
power station
Remote from CO 2
sources.
Good
Galilee Basin
GB
Carboniferou
s to Triassic
Deep
Variable some
very good
Anticipated to be
adequate
Unused fresh
water
Large Some Sparse
Poorly explored
compared to other
basins
Potential
Bowen Basin
BB
Permian to
Triassic
Deep
Variable some
very good
Excellent
Unused fresh
water
Large Variable Good
Triassic sandstones have
the best porosity
13

3.1.6. Maryborough Basin.
Exploration results indicate that the transgressive sequence at the base of the Maryborough
Formation contains suitable reservoir–seal development (Day et al., 1983). However, potential
reservoirs are of poor quality (P.R.A.D.S, 1990). There appears to be limited storage capacity in
this basin based on the 11 exploration and 39 stratigraphic wells drilled into the basin, and the aerial
extent of explored structures within the basin. Inversion in the middle Cretaceous resulted in major
folding and faulting (Hill, 1994). The Maryborough Basin extends beneath the shelf southeast of
Fraser Island, where it is folded and faulted (Hill, 1994) increasing the potential for CO 2 leakage
near two world heritage national parks (Fraser Island and the Great Barrier Reef). Overall the
Maryborough Basin is considered too high risk for the small potential storage volume that may
exist.
The GEODISC project concluded that the Maryborough Basin onshore dry structures have 0.05%
change of successfully sequestering CO 2 . Much larger offshore structures exist, but would need to
be tested for hydrocarbons before CO 2 sequestration could occur (Bradshaw et al., 2003).
The offshore features are also in environmentally sensitive areas (Great Barrier Reef Marine Park
and Fraser Island), therefore making further exploration and drilling difficult. The hydrodynamic
trapping of CO 2 in the Maryborough Basin is unlikely due to a lack of sub-surface well data and
excessive depths associated with high reservoir pressures and high costs.
3.1.7. Callide Basin.
The Callide Basin (Figure 3.1) is unsuited for geological storage of CO 2 as the sediments contain a
significant proportion of volcano-clastic material. This material is prone to diagenetic alteration,
reducing injectivity. The Callide Basin overlies a 1000 m succession of volcanic rocks,
conglomerates, sandstones and carbonaceous mudstones with poor reservoir quality. The Triassic
coal sequences are an economic resource, therefore, are unavailable for geological storage of CO 2 .
The Callide Basin offers no potential for the geological sequestration of CO 2 (Bradshaw et al.,
2003).
3.1.8. Esk and Abercorn Troughs.
These troughs (Figure 3.1) are very small and shallow with limited data. There is considerable
reservoir risk as they contain extrusive volcanics (Day et al., 1983).
3.1.9.Tarong Basin.
The Tarong Basin contains the Tarong Beds which comprise conglomerate, pebbly sandstone,
sandstone, shale and coal to a total thickness of approximately 300 m (Day et al.,1983). The small
size and shallow depth make the Tarong Basin an implausible site for geological storage of CO 2 .
3.1.10.Calen Basin.
The Permian sediments in the Calen Basin (Figure 3.1) are generally too shallow and the coal
measures are intruded by numerous Permian to Cretaceous aged dolerites, rhyolites and granites that
dramatically increase the seal risk (Brakel, 1989). Although this interpretation was undertaken
without petroleum well data, the assessment concludes that there is little potential for the geological
storage of CO 2 .
The Permian sediments of the Calen Basin are in general too shallow and offer no potential for the
sequestration of CO 2 (Bradshaw et al., 2003).
14

3.1.11. Lakefield Basin.
The Lakefield Basin underlies the Laura Basin in north Queensland, is considered to be of Permian
age, and based on seismic interpretation, contains up to 10 km of sediments (Wellman, 1995). No
wells have penetrated more then 112 m into the Lakefield Basin section. There is insufficient data
available to make a realistic assessment of this basin (Wellman, 1995).
3.2. Great Artesian, Surat, Eromanga, Carpentaria and
Mulgildie Basins
The Surat, Eromanga, Carpentaria and Mulgildie basins are hydraulically connected together to
make up the Great Artesian Basin, a world class groundwater resource (Figure 3.2). This water
resource supports a significant proportion of the Queensland rural economy. There are thousands
of registered and an unknown number of unregistered water-bores drilled to exploit this resource,
posing a substantial leakage risk to any regional scale CO 2 storage site. Localised, field scale
opportunities for CO 2 storage may exist particularly in depleted hydrocarbon fields located within
these basins.
Figure 3.2. Stratigraphy of the Great Artesian Basin (after Radke et al., 2000).
15

Moonie Oil Field
PL 1 permit, Surat Basin, onshore eastern Queensland, approximately 300 kilometres west of
Brisbane. Santos Ltd has a 100% interest and is the operator (Santos, 2005).
Oil was discovered on the Moonie Anticline within the Jurassic Precipice Formation in 1961.
The 24.3 million-barrel (3859 mega litre) oil field was brought into production during 1964 with
peak production of approximately 9000 bbls/day occurring during 1966. As at 1996 cumulative
oil production was approximately 3686 mega litres (23.2 MMbbls).The Precipice Sandstone at the
Moonie location has an average permeability of 290 mD with an average porosity of 18% (Cadman
et al. 1998).
The field is in the latter stages of decline with 0.0694 mmboe of crude oil produced during 2004
with a very high water cut. Most of the 50 wells at Moonie and the nearby satellite fields are shut in,
and less than 10 wells are still producing. Eight wells on the fields are used for water injection.
Recently a 3D seismic survey has been acquired over the field
(http://www.santos.com.au/Content.aspx?p=2268).
The Moonie field has the potential to be suitable for enhanced oil recovery or as a CO 2 storage site.
As cooperation with Santos Ltd would be required for this to be realised, it was thought impractical
to make it the subject of a separate geological or geophysical review with the limited available open
file data. This is particularly true considering that post 3D data acquisition, all available seismic,
well and field data would have been incorporated into determining the location of the two
subsequent wells drilled on the Moonie structure.
The GEODISC project concluded that, depleted gas fields in the Surat Basin (UEI’s 30, 31, 33, 34,
and 35) represent a very low risk sequestration option with a high geologic chance of success
(35-52%) for volumes of < 0.19 TCF of CO 2 (Bradshaw et al., 2003).
3.3. Older/Deeper Basins
3.3.1 Cooper Basin
The Cooper Basins’ location in central Australia is approximately 1000 km from the nearest coal
fired power station. Exploiting petroleum resources from the Cooper Basin is the primary activity
at this time. This activity results in the venting to the atmosphere of potentially sequesterable CO 2 .
The Cooper Basin has not been reviewed in this study.
The GEODISC project concluded that, the Cooper Basin is an ideal site for carbon-dioxide
sequestration with a 90% chance of successful CO 2 sequestration (Bradshaw et al., 2003).
3.3.2 Devonian to Carboniferous Basins (Warburton, Adavale, Drummond, Hodgkinson,
Gilberton, Bundock, Clarke River, and Burdekin Basins).
The Carboniferous to Devonian Adavale Basin has the highest storage potential of the older basins,
although comparatively this is still low and containment may be problematic due to fault leakage
and the potential for injected CO 2 to dissolve the carbonate formations. The basin has been
extensively investigated with 46 exploration wells and 11 appraisal wells, with the most likely
storage option being within the Gilmore field once it is depleted. The Gilmore field is a 118 BCF,
3352 m deep potentially fault controlled gas field and is the only commercial hydrocarbon
accumulation discovered in the basin to date (deBoer, 1996). Sedimentary rocks
within Devonian ─ Carboniferous aged basins, tend to be diagenetically altered, with sediments
buried deeply. Additionally reservoir characteristics are poor and the basins are overlain by up to
1000 -3000 m of superior reservoirs (Miyazaki & Ozmic, 1987). The reservoir quality, remoteness
from CO 2 sources, and juxtaposition with more suitable storage options makes these basins
unsuitable for CO 2 storage.
16

GEODISC concluded that the Drummond, Warburton and Adavale basins have little to very poor
potential to sequester CO 2 , due primarily to poor reservoir quality, major faulting and the lack of
predictable seal (Bradshaw et al., 2003).
3.4. Galilee Basin
The Galilee Basin is a significant geological feature of central Queensland, covering an area of
approximately 247,000 km 2 (Hawkins et al., unpublished) and measuring approximately 700 km
north–south and 520 km east–west (Hawkins et al., 1978; Figure 3.3). Three main depocentres - the
Koburra Trough (east), the Lovelle Depression (west) and the southern Galilee Basin
(south) - contain up to 3000 m, 730 m, and 1400 m of Late Carboniferous to Middle Triassic
sedimentary rocks, respectively (Jackson et al.,1981; Hawkins, unpublished). Most of the structures
in the basin are low amplitude and are the result of reactivation of older basement faults penetrating
the underlying Drummond and Adavale basins. Tectonic events were dominantly compressional
resulting in uplift and erosion of parts of the basin during the Permian and Triassic. The Eromanga
Basin, is up to 1200 m thick and overlies the Galilee Basin. A regional southwesterly tilt was
associated with the collision of the Australian and PNG plates (Home et al.,1990).
Sedimentation in the Galilee Basin was dominated by fluvial to lacustrine (and in part glacial)
depositional systems. This resulted in a sequence of sandstones, mudstones, siltstones, coals and
minor tuff in what was a relatively shallow intracratonic basin. The entire Galilee sequence is
saturated with potable water in both the Permian and Triassic strata with probable recharge from the
northeast into the outcropping Triassic reservoirs. Sediment provenance is variable and includes
recycled older sedimentary, metamorphic, granitic, volcanic and tuffaceous rocks. The climate has
varied from glacial to warm and back to temperate during deposition of Galilee Basin sediments.
Forty years or more of exploration in the Galilee Basin has failed to discover any economic
accumulations of hydrocarbons, despite the presence of apparently good to very good reservoirs and
seals, in both the Permian and Triassic sequence. Vitrinite reflectance values indicate that the basin
has previously reached thermal maturity for hydrocarbon generation.
The presence of oil and gas shows indicate some sort of petroleum charge mechanism existed in the
area. The absence of economic hydrocarbon accumulations could be attributed to (among other
factors) an absence of a significant volume of suitable source rock and / or incompatible timing
between hydrocarbon generation and the formation of structural traps. Although exploration
interest in the basin has waned, some exploration for coal seam methane continues in some areas.
A preliminary review of the Galilee Basin data indicates that it has potential to store CO 2 .
Several formations and areas contain sandstones with good porosity and permeability
characteristics. Several sealing lithologies exist within the Galilee Basin, however sealing capacity
over geological time remains unproven due to a lack of hydrocarbon accumulations. Potential
stratigraphic and hydrodynamically assisted stratigraphic traps have been identified in some areas.
A thorough regional geological study is currently underway to assess the quality of the basin for
CO 2 storage, estimate storage capacity, and investigate in detail issues such as the extent and
presence of the large fresh water resource.
The GEODISC project concluded that, the Galilee Basin has good potential to sequester CO 2 within
hydrodynamic/stratigraphic traps. Potential dry structures are not considered a viable sequestration
option due to small storage capacity (Bradshaw et al., 2003).
3.5. Bowen Basin
This study focuses on the Wunger Ridge area in the Bowen Basin. During an initial overview of the
Bowen Basin it became apparent that there was a need to clearly define the sedimentary units within
the Bowen Basin as many different lithological names have been applied to sedimentary units
17

deposited over the same time period. Over 50 publications, 100’s of well completion reports and
more than 50 stratigraphic charts were used to produce a basin wide stratigraphic correlation and
interpreted environment chart based on facies (Appendix 10.1- autho-stratigraphic chart).
Coal industry lithological terms were excluded as the use of these is predominantly restricted to
shallow parts of the basin.
This chart (Appendix 10.1) was used in conjunction with detailed log and seismic interpretation to
summarise the basin stratigraphy and interpret genetic stratigraphic relationships across the basin.
These relationships assisted in the development of an exploration model to determine the extent,
location and heterogeneity of key reservoirs, seals and potential CO 2 migration pathways.
Figure 3. 3. Basic elements of the Galilee Basin.
The Permo-Triassic Bowen Basin is a large (200,000 km 2 ) asymmetric elongate feature. The basin
consists of a thick rift-sag-foreland basin succession formed within two main depocentres, the
Denison and Taroom troughs. These troughs were identified during the initial overview as suitable
for the injection and storage of CO 2 during an Australia wide CO 2 storage review undertaken as part
of the GEODISC program (Bradshaw et al., 2003).
18

The Denison Trough is a western extension of the Bowen Basin. The Trough contains up to 6500 m
of preserved terrestrial and marine clastic rocks that are Permian–Triassic in age (Brown et al.,
1983). Reservoir–seal pairs are well developed within the Early Permian sag phase succession of
the Denison Trough (Figure 3.4) and provide several potential intervals for geological storage of
CO 2 . Reservoir quality is generally good depending on facies type but also varies considerably due
to modification by diagenetic processes such as the infilling of pores by clays and silica cement.
Late Permian coals extend across the Trough providing a reliable seismic mapping marker and these
coals are exploited by various companies at the margin of the Trough. The Trough is extensively
structured and contains several north–south trending grabens which were deformed during the Late
Triassic into fault-propagated anticlines (Figure 3.5). These features provide structural traps that in
most cases are filled to spill with hydrocarbons (Brown et al., 1983). The Denison Trough is a
relatively mature hydrocarbon province with several producing fields, some potentially nearing the
end of production. Depleted gas fields are thus a potential option for geological storage of CO 2 .
Other options such as dry structures, hydrodynamic trapping and regional sub-crop will be of higher
risk given the extensive faulting and containment issues.
The Taroom Trough is the largest depocentre in the Bowen Basin with up to 9000 m of Permian and
Triassic sediments (Figures 3.4 and 3.6). The Permian aged strata in the Taroom Trough are
generally deeper marine facies than in the Denison Trough. During the Permian, sediments were
sourced primarily from a volcanic arc located to the east of the Taroom Trough. Reservoir quality is
thus poor, particularly in the east. Late Permian coals from the Baralaba Coal Measures (Bandanna
Formation) extend across the Taroom Trough (Figure 3.4). Triassic strata contain several terrestrial
sequences with reservoir quality sandstones overlain by regional shales. The most economically
important Triassic aged sequence from the Taroom Trough occurs on the west flank within the
fluvial Showgrounds Sandstone that is contemporaneous with the upper part of the Clematis
Sandstone. The Showgrounds Sandstone is sealed by the lacustrine Snake Creek Mudstone.
Reservoir modelling conducted in this project focussed on the Triassic aged Showgrounds
Sandstone and its associated seal in the Wunger Ridge area. Within the Taroom Trough, the absence
of Jurassic petroleum accumulations around the Wunger Ridge area implies that the seal is suitable
for geological storage of CO 2 . It was for this reason, coupled with the reservoir quality of the
Showgrounds Sandstone that the Wunger Ridge was selected as the focus of this study.
Petroleum fields are mainly restricted to the western flank, with only a few accumulations on the
eastern flank (Shaw et al. 1999; eastern fields not shown in Figure 3.7). The source rock is located
in the central Taroom Trough with hydrocarbons being generated within Late Permian age strata
(mainly Baralaba Coal Measures and Burunga Formation; Figure 3.4), and migrating subsequently
up the eastern and western flanks into structural and stratigraphic traps (Korsch et al., 1998;
Cadman et al., 1998). There is a scarcity of hydrocarbon pools on the eastern flanks of the Taroom
Trough, despite the presence of several large fault propagated folds forming anticlinal closures
(Shaw et al., 1999). The absence of hydrocarbons in large anticlinal structures on the eastern flank is
probably due to a combination of absence of a valid migration pathway, and inadequate source rock
in the eastern side of the trough.
Even though thick intervals of sandstone have been deposited and preserved, overall the reservoir
quality is poor along the eastern flank of the Taroom Trough. This is largely due to high clay
content of the deposited sediment and diagenesis. The Taroom Trough may contain dissolution,
residual or stratigraphic traps along its broad downwarped geometry.
In the northeast Bowen Basin (Nebo Synclinorium and Collinsville Shelf) Permian aged strata are
highly deformed and truncated, with eroded anticline crests exposed at the surface (Figure 3.8).
It is therefore highly unlikely, in the northern basin area, that any CO 2 injected into the sub-surface
would be contained in the long term.
GEODISC concluded, the Bowen Basin has a range of different geological options for the
sequestration of CO 2 . The most suitable sequestration options vary depending on the volume
of CO 2 to be sequestered (Bradshaw et al., 2003).
19

Figure 3.4. Sequence Stratigraphy of the Bowen and Surat basins (after Korsch et al., 1998).
20

Figure 3.5. Structure of the Denison Trough. Note: north–south trending grabens which were
deformed during the Late Triassic into fault-propagated anticlines (After Elliot 1985).
21

Figure 3.6. Key structural elements of the Taroom Trough (after Rigby, 1987).
22

Figure 3.7.Schematic geological cross-section through the Roma Shelf area. Located in the western
Taroom Trough showing structural relationships. The Wunger Ridge fields (right hand side) have been
projected approximately 60 km north onto cross-section. The distribution of oil and gas fields is shown
relative to pinchouts and erosional edges and occurs above Permian source rocks (from Cadman et al.,
1998). Arrows indicate hydrocarbon migration pathways and show how hydrocarbons leak up through
the formations, creating stacked accumulations.
23

Figure 3.8. Geological cross-sections through the northern Bowen Basin. Figure shows
exhumed, highly folded and truncated Permo-Triassic strata (after Clare, 1985).
3.6. Wunger Ridge – Bowen Basin.
The Wunger Ridge is located on the southwestern flank of the Taroom Trough (Figure 3.6) and was
chosen as the preferred site on which to produce a detailed technical geological storage assessment.
The area was selected on the following basis:
• proving containment in the subsurface is seen as the critical risk for the project. The regional
seal has trapped hydrocarbons within a single stratigraphic unit over a geological time period
of ~ 100 Ma. This is in contrast to the Roma Shelf where stacked hydrocarbon pools indicate
leakage up faults that penetrate the intraformational seals.
• reservoir deliverability has been demonstrated over a number of years by a number of fields.
Injection testing in the Showground Sandstone in the Wunger Ridge area as opposed to other
locations within the Bowen Basin would also provide significantly more data on the effectiveness
of a regional solution. This is because results obtained from geological modelling and reservoir
simulations would be transferable to several other areas within the Bowen Basin that have similar
geological characteristics. For example, only minor changes to reservoir properties and the inclusion
of fault conduits would need to be added in order to apply the Wunger Ridge model to the Roma
Shelf. Data and characteristics of the Wunger Ridge area consists of;:
24

• A comprehensive set of wells and seismic lines is available, providing an understanding of
subsurface trends and uncertainties.
• Approximately 400 m of core from 31 wells including 11 that sampled the entire
Showgrounds Sandstone–Snake Creek Mudstone interval were available as geological
control.
• Pressure data density is good over the Wunger Ridge due to the presence of producing fields.
depth is sufficient to allow injected CO 2 to remain supercritical after injection.
• Long migration pathways maximise the potential for residual gas and dissolution storage
mechanisms to occur.
• Water quality in the Showground Sandstone unit is lower (i.e. more saline) than overlying
fresh water aquifers reducing the potential for water resource conflicts.
3.7. Chapter References
de Boer, R.A., 1996. The integrated development of Gilmore field and an
independent power plant. APPEA, 36, 117–129.
Bradshaw, B., Bradshaw, J., Dance, T., Reilly, N.S., Sayers, J., Spencer, L. & Wilson, P., 2003.
Geodisc ArcView GIS Version 2.01. APCRC Confidential GIS.
Brakel, A.T., 1989. Calen Basin. Bureau of Mineral Resources, Geology and Geophysics Bulletin,
v.231, p107–110. In Harrington H.J. & others. Permian Coals of Eastern Australia, Chapter 9.
National Energy Research Development and Demonstration Council, Final Report on Project
78/2617.
Brown, R.S., Elliot, L.G. & Mollah, R.J., 1983. Recent exploration and petroleum discoveries in the
Denison Trough, Queensland. Australian Petroleum Exploration Journal, 23 (1), 120–135.
Cadman, S. J., Pain, L. & Vuckovic, V., 1998. Bowen and Surat Basins, Clarence–Morton Basin,
Sydney Basin, Gunnedah Basin and other minor onshore basins, Queensland, NSW and NT.
Australian Petroleum Accumulations Report 11, Bureau of Resource Sciences, Canberra.
Clare, R., 1985. Structure of the northern Bowen Basin. The GSA Coal Geology Group, Bowen
Basin Coal Symposium, November 1985.
Day, R.W., Whitaker, W.G., Murray, C.G., Wilson, I.H. & Grimes, K.G., 1983.
Queensland Geological Survey Publication 383 — Queensland Geology, A companion volume to
the 1:2 500 000 scale geological map (1975). S.R. Hampson, Government Printer Queensland.
Denaro, T.J. & Shield, C.J., 1993. Coal and petroleum exploration, Cape York
Peninsula: Queensland. Department of Mines and Energy, Geological Record 1993/15, pp104.
Enever, J.R., 1990. In Situ stress measurements in the Bowen Basin and their implications for coal
mining and methane extraction. in The GSA Queensland Division, Bowen Basin Coal Symposium,
September 1990.
Elliot, L., 1985. The stratigraphy of the Denison Trough. The GSA Coal Geology Group, Bowen
Basin Coal Symposium, November 1985.
Green, P. M. & McKellar, J. L., 1996. Relationships between Latest Triassic–Early Cretaceous
strata in the Clarence–Moreton, Surat and Eromanga Basins. Queensland Government Mining
Journal, December. Pg. 67–71.
Hawkins, P.J., 1978. Galilee Basin — Review of Petroleum Prospects. Queensland
Government Mining Journal, February 1978, pp 96–112.
25

Hawkins, P.J., Gray, A.R.G., Brain, T.J. & Scott, S.G. (unpublished). Geology and
Resource Potential of the Northern Galilee Basin. Obtained from Qld Dept of Mines.
Hill, P.J., 1994. Geology and Geophysics of the offshore Maryborough Basin,
Capricorn and northern Tasman Basins: Results of AGSO Survey 91. AGSO Record, 1994/1, pp71.
Home, P. C., Dalton D. G. & Brannan, J., 1990. Geological evolution of the Western Papuan Basin,
in G. J. Carman and Z. Carman, ed., Petroleum Exploration in Papuan New Guinea: Proceedings of
the First Papua New Guinea Petroleum Convention, Port Moresby, 12–14 th February 1990, Papua
New Guinea Chamber of Mines and Petroleum, p. 107–119.
Jackson, K.S., Horvath, Z. & Hawkins, P.J., 1981. An assessment of the petroleum prospects for the
Galilee Basin, Queensland. The APEA Journal, v. 21, 1, pp 172–186.
Kalinowski A. & Newlands, I. 2005. The Galilee Basin, A big opportunity?, Cooperative Research
Centre for Greenhouse Gas Technologies, Barossa Valley Symposium Nov–Dec 2005 (poster,
unpublished, confidential to CO2CRC).
Korsch, R.J., Boreham, C.J., Totterdell, J.M., Shaw, R.D. & Nicoll, M.G., 1998. Development and
petroleum resources of the Bowen, Gunnedah and Surat Basins, Eastern Australia. APPEA Journal,
pp199–237.
Malone, E.J., Olgers, F., Kirkegaard, A.G., 1969. The geology of the Duaringa and Saint
Lawrence 1:250 000 Sheet areas, Queensland Bureau of Mineral Resources, Australia, Report 121.
Miyazaki, S. & Ozimic, S., 1987. Adavale Basin, Queensland, Australian
Petroleum Accumulations report, Australian Bureau of Mineral Resources, Geology and
Geophysics, pp 20.
O’Brien, P.E., Powell, T.G. & Wells, A.T., 1994. Petroleum potential of the
Clarence–Moreton Basin. In: Wells, A.T., and O’Brien, P.E., (eds) Geology and Petroleum
Potential of the Clarence–Moreton Basin, New South Wales and Queensland. Australian Geological
Survey Bulletin 241.
Petroleum Resources Assessment and Development Sub-program (P.R.A.D.S),
1990, Petroleum Resources of Queensland (Review to June 30, 1989). Queensland Resource
Industries Review Series. Department of Resource Industries, Queensland.
Radke, B. M., Ferguson, J., Cresswell, R. G., Ransley, T. R. & Habermehl, M. A., 2000.
Hydrochemistry and implied hydrodynamics of the Cadna-owie–Hooray Aquifer, Great Artesian
Basin, Australia. Bureau of Rural Sciences, Canberra.
Rigby, S.M., 1987. Murilla Creek — An Untested stratigraphic Play in the Surat Basin, The
Australia Petroleum Exploration Association Journal (APEA), 27 (1), pp. 230–245.
Russell, N.J., 1994. A palaeogeothermal study of the Clarence–Moreton Basin.
In: Wells, A.T., and O’Brien, P.E., (eds) Geology and Petroleum Potential of the Clarence–Moreton
Basin, New South Wales and Queensland. Australian Geological Survey Bulletin 241.
Santos, 2005. http://www.santos.com.au/Content.aspx?p=2268.
Shaw, R.D., Korsch, R.J., Boreham, C.J., Totterdell, J.M., Lelbach, C. & Nicoll, M.G., 1999.
Evaluation of the undiscovered hydrocarbon resources of the Bowen and Surat Basins, southern
Queensland. AGSO Journal of Australian Geology and Geophysics, 17 (5/6), pp 43–65.
Thompson, P.S., 1987. Petrological and Petrophysical data from Mesozoic
26

sandstone of the Bundamba Group, Clarence–Moreton Basin. Bureau of Mineral Resources,
Geology and Geophysics Record 1987/8.
Wellman, P., 1995. The Lakefield Basin; A new Permian Basin in far north
Queensland. Queensland Government Mining Journal, 96; pp 19–23.
27

4. Geological and Geophysical Datasets
4.1. Geological data
Initial geological data compilation included petroleum, coal seam methane, water and Geological
Survey of Queensland (GSQ) stratigraphic wells. This project almost exclusively used petroleum
well data as it was the most suitable to assess the subsurface geology for the injection and storage of
CO 2 . A comprehensive quality control was carried out on the well location in order to maintain
confidence in the geological interpretation (Appendix 10.6.1).
From the petroleum well database of approximately 4000 wells, a subset of approximately 600
wells was utilised (Figure 4.1.; see Appendix 10.6.1 for well list). Wells were included in this subset
if the well:
• penetrated a depth greater than the 800 m required for supercritical storage of CO 2 ;
• could be integrated into a digital dataset. The electrical log dataset was obtained from the
Queensland Department of Natural Resources, Mines and Energy (QDNRME);
• was perceived as critical to the understanding of the area (i.e. wells in key areas, or well-tie
to seismic lines), and
• additional wells were added in areas lacking sufficient data to make a realistic assessment.
Once the key wells had been selected, all the available data associated with these wells was
collected and examined, including:
• well completion reports acquired from QDNRME QDEX (Queensland digital exploration)
database;
• approximately 400 wireline logs from QDNRME and approximately 20 wireline logs were
hand digitised, and
• approximately 60 drillcores from Geoscience Australia’s and QDNRME’s core stores.
Cross examination of the location of many of the wells selected from QDNRME’s database with a
database at Geoscience Australia indicated that many wells had a significant discrepancy in
geographic location, with some wells plotting up to 100 km apart. It was decided to examine all of
the 600 wells in the dataset and compare the location with that reported in the well completion
report. Many wells were found to have location errors, in particular the geographical datum in many
of the wells had been entered incorrectly, causing many of the location errors seen, and to a lesser
extent key stroke error was also responsible.
To prevent repeating work that had previously been conducted, formation tops were acquired from a
CD produced by the QDNRME / Geological Survey of Queensland (GSQ) Geoscience Data
Queensland Petroleum Geoscience Data. This CD contained a database with the GSQ formation
picks and another database with the formation picks the operator submitted with the well
completion report. These two databases were compared and a preferred formation picks set was
obtained from both sets. The lithostratigraphic tops were subsequently normalised into a single
“pseudo-sequence” stratigraphic name using the autho-stratigraphic chart of the Bowen Basin
(Appendix 10.1). The Wunger Ridge area picks were then checked against the composite log with
specific attention to the Showgrounds Sandstone, Snake Creek Mudstone and Rewan Formation.
28

Figure 4.1. Location of all wells used in the assessment of the Bowen Basin study
areas See Appendix 10.6.1 for a full list of wells used.
29

Figure 4.2. Location of core samples examined in the greater Wunger Ridge area. See also Figure 2.1c for
location relative to the Bowen Basin.
4.2. Geophysical data
Datasets available for the seismic interpretation are listed below.
• Reflection seismic data were available in printed format, mostly as final stacks with
occasional migrated stacks. The seismic data used was normal polarity (Australian standard,
reverse USA) producing a peak (right hand deflection) as the seismic wave moves from high
to low velocity material (e.g. sandstone/shale to coal). The data was provided by the
QDNRME in Brisbane as TIFF images. No data in the area were available in SEGY format
at the time of request. The data are generally poor-to-average in areas of high density
faulting and the resolution is low as all data used was recorded between 1979 and 1992.
Modern seismic surveys have a shorter shotpoint interval and hence show increased
resolution.
• A seismic line location file was provided by the QDNRME in ASCII format and was loaded
into the Petrosys TM mapping software as Australian Geodetic Datum 1966 (AGD66), later
converted to Geocentric Datum of Australia 1994 (GDA94).
• Synthetic seismograms were available for about 10 % of the wells used. The time needed to
make other synthetic seismograms was thought unwarranted in view of the objectives and
the overall time constraints on the project.
• Time-depth data from well completion reports were available for a large percentage of the
wells in various forms and at various levels of accuracy (e.g. time-depth plots and tables)
• Potential field (TIFF) images were available but were considered to have insufficient
resolution. Details for individual lines and surveys can be found in Appendix 10.6.6.
30

5. Bowen Basin Summary Reviews
5.1. Introduction
During the early stages of the state wide review of potential storage sites within Queensland, it
became apparent that the CO 2 storage site options with the greatest potential were located in the
western Bowen Basin (e.g. Denison Trough, Roma Shelf and Wunger Ridge). The review
concluded that the site with the most significant storage potential coupled with comparatively
low geological risk was in the Wunger Ridge area. At the Wunger Ridge, an assessment of the
Showgrounds Sandstone and Snake Creek Mudstone reservoir/seal pair indicated excellent seal
characteristics with good lateral extent. Liquid and gaseous hydrocarbons have been exploited
along the ridge for approximately 26 years with generally very good recovery implying good
reservoir connectivity at the field scale in a number of areas.
Initially, the risk factors were considered to be:
• low reliability of structural maps due to unavailability of digital seismic data;
• the unavailability of production pressure data for fields, which could be used to evaluate the
state of depletion of a field and hence the potential availability of that field for CO 2 storage;
• the Showgrounds Sandstone formation water: this water is usable, at least for the watering
of stock. Injection of CO 2 into this formation could pose a conflict of use as well as
generational legacy issues, as the water resource could be sterilised;
• this area is currently explored and exploited for hydrocarbons which also raises the potential
for a resource conflict. The effect, positive or negative of re-pressuring a regional area was
unknown, and
• the thickness of the reservoir, as it is comparatively thin (i.e. < 17 m).
Due to the proximity of the eastern parts of the Bowen Basin to coal-fired power stations as well
as other factors, a number of other areas (i.e. east Bowen Basin, southeast Bowen Basin, Denison
Trough, Roma Shelf) in the basin have, as previously stated, undergone a review at the reservoir
scale.
5.2. Denison Through Study Area
The Denison Trough is located in the northwest Bowen Basin. The basin is comparatively close
to the Rockhampton–Gladstone region, an area that could evolve as a major emissions hub
(i.e. servicing 49 % of Queensland’s total stationary CO 2 emissions; Figure 2.1a). The Denison
Trough was subject to a review to investigate the nature and number of CO 2 storage site options
(Appendix 10.2). The results are summarised below.
Reservoir analysis and production data indicate that the Catherine Sandstone and Aldebaran
Sandstone are the most prospective units. Reservoir quality has restricted the Aldebaran
Sandstone’s suitability for injection and storage of CO 2 to isolated narrow regions around existing
hydrocarbon fields. Areas where hydrocarbons are unable to be produced have been assessed as
having significantly increased injectivity and storage risk due to very low porosity and permeability
(e.g. the Warrinilla Field). The Catherine Sandstone is similarly restricted, with erosion limiting seal
coverage. As a result, only one area has been identified where the Catherine Sandstone and
Aldebaran Sandstone can be targeted simultaneously (i.e. Springsure Anticline- Figure 3.5).
The use of depleted fields for the storage of CO 2 in the Denison Trough has some associated volume
risks due to the fault-bounded nature of the lowest known hydrocarbon accumulations in the fields.
Hydrocarbon pools are mostly limited by north–south striking faults, although west-to-east faults
exist in some areas. A detailed geomechanical study would be required if the Denison Trough
depleted fields option was to be explored further.
31

A four year demonstration site for carbon capture and storage (CCS) technology, located
approximately 200 km east of the Denison Trough, with an annual CO 2 output of 75 000 tonnes has
previously been proposed (Spero, 2005). There are 11 fields within the Denison Trough which have
an equal or greater storage potential than the projected CO 2 volume produced. Four of these fields
could have 12 years of storage potential, with two of those having more than forty years of storage
potential for this scale of project. However, it should be noted that the fields are all currently in
production, and as such, are most likely unavailable for use as CO 2 storage sites at the present time.
A second proposal indicated a possible 25 year project (Sayers et al., 2006) with a CO 2 output of
approximately 1.2 million tonnes per annum (Mt/y) for a total storage volume of 30 Mt. The entire
Denison Trough CO 2 equivalent volume produced from fields is approximately 14.9 Mt,
representing less than thirteen years storage.
The Denison Trough therefore appears to offer many years of potential storage in depleted fields for
a small scale demonstration CCS projects. However, higher risk storage and injection scenarios in
low permeability rocks could be investigated to accommodate the storage capacity required for
larger CCS projects (Sayers et al, 2006).
5.3. East Bowen Basin Study Area – Burunga Anticline / Dulucca
Area
This project assessed the CO 2 storage potential of sites close to stationary CO 2 sources in the east
Bowen Basin, Queensland (Figure 2.1b; Appendix 10.3). The Flat Top Formation within the
Burunga Anticline and the Showgrounds Sandstone within the Trelinga structure (Dulucca area),
were the primary focus of the investigation.
The project involved:
• a sedimentary basin analysis, involving the analysis and interpretation of 12 composite well
logs and 14 well completion reports;
• a paleogeographic reconstruction and the assessment of the suitability of reservoir sand and
overlying seal units;
• a petrophysical evaluation, and
• a seismic interpretation of 40 sections to assess structural form and trends.
The report concluded that both the Showgrounds Sandstone and the Flat Top Formation possess
negligible storage potential in this region of the Bowen Basin. The Flat Top Formation is a highly
variable lithological unit with low net-to-gross sandstone and poor porosity–permeability
correlation within individual facies. Hence, the predictability of reservoir quality in this unit is low.
The Showgrounds Sandstone, also has poor reservoir quality, is truncated by the (basal) Surat Basin
unconformity and overlain by the fresh water bearing sandstone units of the Great Artesian Basin.
A sealing unit is absent so that CO 2 injected into the Showgrounds Sandstone could potentially
migrate directly into the overlying fresh water aquifer. Both the Flat Top Formation and
Showgrounds Sandstone are therefore considered to have significant reservoir and seal risk.
The only alternative reservoir in the area is the Precipice Sandstone, a fresh water aquifer within the
eastern Surat Basin. Whilst the Precipice Sandstone possesses significant storage potential, injecting
CO 2 into the Precipice Sandstone would, as already stated, sterilise the fresh water resource from
future use so that using this aquifer for geological storage is not considered a viable option at
present.
32

5.4. Southeast Bowen Basin Study Area
The southeast Bowen Basin is in close proximity to a number of power stations and population
centres and therefore may be a practical option for CO 2 storage for southeast Queensland.
Regional reconnaissance work was carried out in the southeast Bowen Basin to assess the CO 2
storage potential of the area (Figure 2.1c; Appendix 10.4). This area was considered for a number of
reasons including:
• the presence of known hydrocarbon accumulations in the Cabawin oil field indicates that
long term storage of fluids has occurred at a local scale;
• the reservoirs are located deep enough to contain CO 2 in its supercritical phase;
• targeting the oil migration pathway which may have preserved porosity would provide
enough distance to allow for a significant proportion of the injected volume of CO 2 to be
trapped residually in saline groundwater, and
• the availability of well and seismic data.
Sixteen wells, distributed along a north–south line, and six seismic sections, located towards the
southern end of the study area (Figures 5.1–5.2), were investigated to assess the potential of Triassic
and Permian sandstones to store CO 2 . Only formations older than the Jurassic Precipice Sandstone
were examined. The Precipice Sandstone, although a good reservoir sandstone, is a significant fresh
water aquifer, as previously discussed, and was therefore not considered for assessment.
5.4.1. Well Data and Result
The preliminary assessment was made from well logs, with the horizons being identified where
possible in each well (Table 5.1). The base of the Precipice Sandstone represents the Triassic–lower
Jurassic unconformity. The top of the Permian section, usually defined by the first appearance of a
series of coals below the Base Jurassic unconformity, was only fully penetrated in a few wells,
meaning geological assessment was not possible over much of the study area. Basement which is
penetrated only by the few deepest wells, is typically volcanic in nature.
Permian and Triassic sandstones were identified from wireline logs in the following wells: Undulla-
1 (Kianga and Back Creek Formations), Alick Creek-1 (Blackwater and Back Creek Groups, Buffel
Formation), and Cabawin-1 (Cabawin and Kianga formations; Table 5.1). These sandstones were
investigated for reservoir potential using the well logs and well completion reports including (where
available) descriptions of core, side-wall core, cuttings, porosity and permeability data, and
company reports. Apart from the section penetrated in Cabawin-1, which is discussed below, no
reservoirs suitable for CO 2 storage were found. Reasons for this include:
• the absence of porosity and permeability due to the presence of a clay and tuffaceous matrix
and / or cementation processes (calcareous, pyritic, or silicic) or silicification. The immature
volcano-lithic sandstones containing a large tuffaceous component, as well as coaly and
carbonaceous material, all of which might react with injected CO 2 ;
• the limited lateral and vertical extent of sandstones resulting in small potential storage
volumes, and
• the absence of a vertical seal.
33

Table 5.1. Preliminary assessment of wells of the southeast Bowen Basin area.
Well
(north-to-south)
Base of
Precipice
Sandstone (m)
Top of
Permian
Section (m)
Triassic
Reservoir
Potential?
Permian
Reservoir
Potential?
Juandah-1 1457 1994 No No
Gurulmundi-1 1250 Not enough data No No
Dulacca-1 1629 Not enough data Not enough data Not enough data
Auburn-1 1618.5 Not enough data Not enough data Not enough data
Miles-1 1228 Not enough data Not enough data Not enough data
Columboola-1 1167 1185 No Not enough data
Tey-1 1626 1626 No Not enough data
Bennett-1 1714.5 1716 No Not enough data
Undulla-1 1725 1737 No Minor Potential
Leichhardt-1 1771 1790 No Not enough data
Alick Creek-1 Not present 1640 No Minor Potential
Tara-1 Not present 1639 No Not enough data
Cabawin East-1 2384 3194 No Not enough data
Cabawin-1 2326 3007 Minor Potential Minor Potential
Tartha-1 2185 Not enough data No Not enough data
Southwood-1 2082 2249 No No
Cabawin-1 is the only well to have intersected a significant hydrocarbon accumulation. There are
several potential sandstone–conglomerate reservoir intervals in the Triassic section of the well,
which are thicker here than in any other part of the study area (Figure 5.1). These intervals have
better porosity and permeability characteristics than others in the study area, and are generally
composed of quartz and chert pebbles with minor ash. However, there is doubt about the volume
of CO 2 that could be injected since these sandstones have not been intersected in off-set wells.
There are no obvious regional sealing units in this area, however a thickness of poor quality
(in terms of reservoir) Triassic sequence could act as a significant baffle to vertical migration.
Figure 5.1. Generic geological cross-section of the southeast Bowen Basin area. The cross-section shows
distribution and thickness of Permian and Triassic sediments from north-to-south in the southeast Bowen Basin.
Wells from north-to-south: Juandah-1 (also representing Gurulmundi-1, Dulacca-1, Auburn-1), Columboola-1
(also representing Miles-1), Undulla-1 (also representing Tey-1, Bennet-1, Leichhardt-1), Alick Creek-1 (also
representing Tara-1), Cabawin East-1, Cabawin-1, Tartha-1, Southwood-1.
34

5.4.2. Seismic Data
Seven horizons (Orallo Formation, Walloon Coal Measures, Moolayember Formation, Snake Creek
Mudstone, Showgrounds Sandstone, Top of Permian, and Basement) were interpreted (where
possible) on seismic lines H79-3, H79-7, H79-9, H79-12, T82CW5, and T82CW16, all located
within the southern part of the study area (Figure 5.2). Horizons were initially interpreted from well
logs. The top of the Permian and the Walloon Coal Measures are generally easy to pick and are the
most consistent reflectors as both are represented by the top-most of a series of strongly–reflecting
coals. The Orallo Formation, Snake Creek Formation and Basement were more difficult to pick.
The Orallo Formation appears to be a fairly subtle horizon; the Snake Creek Mudstone was not
recognised on well logs and therefore could not be tied to the seismic sections; and few wells were
deep enough to intersect basement. The basement is difficult to recognise without well control as it
does not appear to be consistent in character on the seismic lines and is structurally more complex
than the overlying formations. The Moolayember Formation and Showgrounds Sandstone are
absent on the highs, possibly due to:
• erosion as suggested by truncated seismic horizons and a thinner Permian sequence in some
cases;
• or non-deposition as suggested in other areas by onlap onto the structural high, or
• the facies was not recognised due to changes in sediment provenance and local control on
accommodation space.
Conceptually, a potential storage site within the Triassic Showgrounds Sandstone/Clematis
Sandstone or Moolayember Formation may exist in the axis of the Taroom Trough to the west of
the southeast Bowen Basin area. However, the complete absence of well control would require a
substantial financial investment to be made to prove or disprove storage potential.
Figure 5.2. Seismic lines used in the southeast Bowen Basin study area.
The circled area is a structural high; the area to the west and south is the
Taroom Trough containing a thicker preservation of the sedimentary sequence.
35

5.5. Roma Shelf Study Area
The Roma Shelf is located on the western edge of the Permo–Triassic Bowen Basin, between 200
and 500 km from southeast Queensland power stations (Figure 2.2). The Roma Shelf is a mature
hydrocarbon province with approximately 131 million–barrels of oil equivalent hydrocarbons and
water produced to 2002 (~ 59 Mt CO 2 equivalent).
Hydrocarbon accumulations on the Roma Shelf are spread out over 100 km and found within small
fault limited traps, typically within stacked reservoirs of the Permian–Triassic Bowen and Jurassic
Surat basins (part of the Great Artesian Basin). The stacked nature of reservoir pools suggests that
migrating hydrocarbons filled the lowest available porous sandstone (at the lowest closing contour),
then migrated vertically to overlying formations via fault conduits. This process repeated creating
stacked hydrocarbon accumulations until the peak of generation had passed and/or hydrocarbons
reached the fresh water aquifer of the Great Artesian Basin. The Artesian Basin has a strong
regional flow in the order of 2.5 m/y; this has resulted in a smear of hydrocarbons being carried
westward (Figures 3.2 and 5.3). Stacked hydrocarbons on the Roma Shelf suggest that CO 2 storage
potential is restricted to known pool limits of depleted fields, with significant risk of CO 2 leaking
vertically up faults into the artesian system.
Detailed analysis of additional trapping mechanisms for CO 2 storage on the Roma Shelf, namely
long distance migration and dissolution trapping, has not been carried out to date. However, the
most suitable reservoir appears to be the Showgrounds Sandstone, the same unit being tested on the
Wunger Ridge. The Showgrounds Sandstone is expected to have similar properties (because of its
matching depositional facies) on the Roma Shelf as seen at the Wunger Ridge.
As a result the Wunger Ridge modelling may be a good representation of CO 2 storage behaviour on
the Roma Shelf. Should a full analysis of the Roma Shelf CO 2 storage potential be required, it
should only take minimal time to transfer the observed geological knowledge and techniques into a
meaningful geological model of the Roma Shelf.
Figure 5.3. Hydrocarbon fields on the Roma Shelf – Bowen Basin. a) Field outlines of the Permo-Triassic,
Bowen Basin hydrocarbon pools. b) Field outlines of the Jurassic Surat Basin hydrocarbon pools on the
Roma Shelf. The coincident location of some accumulations imply vertical migration of hydrocarbons.
36

5.6. Northeast Bowen Basin Study Area
The geological CO 2 storage potential of the north-eastern Bowen Basin was investigated due to the
area’s proximity to major power stations and other major stationary sources of CO 2 located along
the eastern seaboard (Figure 2.1b; Appendix 10.5).
Several potential reservoir units exhibiting characteristics suitable for CO 2 storage have been
identified, albeit with varying confidence. The sandstones in the region are of Permian–Triassic age
with the majority having a volcano-lithic origin. Subsequent diagenetic and hydrological processes
have altered the volcano-genic constituents of the sandstone matrix, resulting in high clay content.
Consequently, the sandstones developed within the area display low porosity with unknown
permeability due to a lack of permeability data in the study area.
Investigating the mineralogy within the sandstone matrix and it’s reactivity within a CO 2 rich
environment is outside the scope of this project. These aspects will require further investigation
should geological storage of CO 2 be further considered in the study area.
The northern part of the study area has minor thin volcanogenic, lithic rich sandstones of Permian
age. Such sandstones do not appear to have reservoir potential. Exploration in this area is focused
on Coal Seam Methane (CSM) exploration/production.
The northern section of the study area is currently producing methane gas from coal seams, and
several coal mines exist around the Moura region. It is unlikely that within the coal measures,
regionally connected reservoir sandstone intervals exist in the areas which are producing methane
gas from coal seams. CSM production requires significant dewatering of the coal seam to reduce the
pore pressure and release the methane gas. Producible coal seams connected to permeable sandstone
aquifers require additional water extraction reducing the economic viability of the project. Therefore
a risk reduction strategy adopted by CSM producers is to target areas where sandstone quality and
development is poor such as the north eastern Bowen Basin.
The southern section of the study area appears to have the greatest potential for geological storage
of CO 2 , based on the data currently available. Rocks located near Champagne Creek show the
greatest potential. Sunshine Gas Ltd is hoping to produce gas from the Triassic Moolayember
Formation from several isolated hydrocarbon accumulations within the Champagne Creek structure.
The southern area is also host to the Peat and Scotia Coal-Seam-Methane field. Work into
enhanced-coal-seam-methane production through CO 2 sequestration may highlight further potential;
however it is beyond the scope of this study.
The best reservoir unit in the region is the Jurassic Precipice Sandstone from the Surat Basin.
However, this unit is a key fresh water aquifer, has no overlying sealing lithology in this region and
ranges in depth from outcrop to 450m. Subsequently the Precipice Sandstone which is the best
reservoir unit in the region is not considered a suitable unit for CO 2 storage.
Further work to fully characterise potential reservoirs throughout the eastern area of the Taroom
Trough up to the ESSCI level may be required in the near future. In the Denison Trough three
injection test sites are being prepared to test the technical viability of CO 2 injection and storage in
low porosity and permeability rocks. The outcome of these tests would be directly applicable to
sites located along the eastern Taroom Trough.
5.7. Chapter References
Bradshaw, B., Bradshaw, J., Dance, T., Reilly, N.S., Sayers, J., Spencer, L. and Wilson, P., 2003.
Geodisc ArcView GIS Version 2.01. APCRC Confidential GIS.
Sayers, J., Marsh, C., Scott, A., Cinar, Y., Bradshaw, J., Hennig, A., Barclay, S. and Daniel, R.,
2006. Assessment of a potential storage site for carbon dioxide – A case study, southeast
37

Queensland Australia. Environmental Geosciences Journal Special Issue, American Association of
Petroleum Geologists.
Spero, C., 2005. Oxy-Fuel Technology Update on the Callide A Retrofit feasibility study.
Australian Journal of Mining conference, Geosequestration in Australia 3-4 th March, Melbourne,
Australia, 2005.
Sunshine Gas, 2005. Australian Stock Exchange Announcement April 7, 2005.
http://www.sunshinegas.com.au/inv_asx.php?q=2&y=2005.
38

6. Southwest Bowen Basin Study Area - Wunger
Ridge Flank
6.1. Seismic Interpretation
6.1.1. Previous Work and Structural Framework
A regional interpretation of the Bowen Basin was carried out in the 1990’s by the then Bureau of
Mineral Resources, now Geoscience Australia, in conjunction with what is now the Queensland
Department of Natural Resources, Mines and Energy (QDNRME). The interpretation used regional
seismic lines tied to a regional array of wells as well as deep crustal transects. Significantly more
seismic data existed locally within the Wunger Ridge flank study area than were utilised in the
regional studies, so that fault trends and maps of individual horizons interpreted by the Bureau of
Mineral Resources (data and interpretation available from Geoscience Australia) were considered
too generalised for the purpose of this study. All available seismic data within the Wunger Ridge
flank study area (Figure 2.2c) were thus used so as to produce a more detailed interpretation.
This section presents interpretive results: detailed geophysical reviews are summarised in
(Appendix 10.6.6.).
Previous regional interpretations included those carried out at a sequence stratigraphy level (Brakel
et al., in press); deep crustal transect level (Korsch et al., 1992) and at a regional structural and
exploration level (Korsch et al., 1998; Shaw et al., 1999).
Key tectono-history summaries contained in the above references, and pertinent to the study area,
are summarised below.
• A late Carboniferous to Early Permian extensional or rift phase is recognised in the Bowen
Basin from the presence of large-scale half grabens and associated extrusion of volcanic
rocks (Korsch et al., 1992). Large scale faults imaged on deep crustal transects were not
observed on the shallow seismic data used in this study.
• During the Permian, the rift phase and subsequent thermal subsidence phase switched to a
compressional regime associated with east-to-west thrust belts. These thrusts were imaged
on deep crustal transects and observed in outcrop geology (Korsch et al., 1992). Foreland
loading from the east during the late Permian to mid Triassic produced significant downwarping
of the Taroom Trough (Figure 3.5): the Trough received significant sedimentation
from the east resulting in the deposition of the Rewan Formation. It is interpreted that downwarping
of the Taroom Trough in the east may have caused some degree of flexure in the
west, probably resulting in relatively low accommodation space in the west Bowen Basin.
• The final Bowen Basin phase in the mid–late Triassic was one of uplift and erosion, forming
the unconformable boundary between the Bowen and the overlying Surat Basin.
6.1.2. Time Interpretation
Seismic horizons
Six seismic horizons were interpreted within the study area, and an additional two horizons were
phantomed (copied from an already interpreted horizon and shifted in time (Table 6.1).
For example, the Showgrounds Sandstone was phantomed down from the Snake Creek Mudstone
due to the thin interval that prevented the resolution of both horizons within acceptable accuracy on
printed sections. The Rewan Formation was also phantomed through an unconformity down from
the Snake Creek Mudstone for similar reasons, so that intervals are of constant thickness with the
exception of near the zero edges where both the Showgrounds Sandstone and Rewan Formation
were adjusted. Figure 6.1 shows typical horizons interpreted on different vintages of data, where
different seismic processing flows used resulted in non-uniformity of seismic character; itself
leading to difficulties in tying different vintages of data.
39

Seismic horizons were tied to wells using time–depth picks obtained from well velocity surveys
(Appendix 10.6.6: Table 10.5.8), and to well synthetics where available (Appendix 10.6.6: Table
10.5.1). To insure the reliability of interpreted horizons, the horizon tied to the top Bandanna
Formation (i.e. represented by a coal) was checked by the associated characteristic peak, as it is
well imaged. The above quality check was particularly important in wells where no synthetics
were available. All seismic sections used were normal polarity — Australian Standard (i.e. peak
represents decrease in acoustic impedance, dominantly a function of velocity).
Table 6.1. Interpreted and phantomed horizons. Abbreviations: Fm - Formation, Mdst - mudstone,
Sst- sandstone, WCR - well completion report.
Horizon Abbreviation Colour Reasoning for interpreting horizons
Orallo Fm ORAL Blue
The Orallo Fm approximately represents the
base of the Cretaceous marine incursions.
The interval above the horizon has a
different time–depth gradient to the interval
below it,
and thus, helps in creating more precise
depth maps
The Walloon Coal Measures gives an
Walloon Coal
approximate depth estimate to fresh water
WALL Orange
Measures
aquifers of the Great Artesian Basin, and
the isopach helps derive basin fill history
Moolayember Fm
Snake Creek
Mdst
Showgrounds
Sst
Rewan Fm
Bandanna Fm
MOOL
SNAK
SHOW
REWA
BAND
Dark
Green
Light
Green
Not shown
on figures
Not shown
on figures
Not shown
on figures
Basement BASE Purple
The Moolayember Fm is a secondary seal
overlying the regional seal.
The top Moolayember Fm is also equivalent
to the top of the Bowen Basin and base of
the Surat Basin, and as such, important for
understanding basin fill history.
The Snake Creek Mdst regionally seals the
Showgrounds Sst reservoir and is a prime
horizon to interpret.
The Showgrounds Sst is the reservoir being
considered for storage: it was phantomed
down from the Snake Creek Mdst
The Rewan horizon was phantomed down
from the Snake Creek Mdst to help define
the base of the Showgrounds Sst
The top Bandanna Fm represents the top
Permian and is readily identifiable.
Basement is identified in WCRs as either
Kuttung Volcanics, Combargo Volcanics,
granite, Timbury Hills Fm, or Kianga Fm.
The basement is readily identified on the
Wunger Ridge, and in most places off the
ridge (Figure 6.1a). The BASE horizon was
interpreted to define a Permian isopach and
map fault trends, critical for understanding
basin infill and trap integrity.
40

Basement (BASE)
The BASE horizon is associated with an increase in velocity as seen on the sonic log, and in over
90% of cases, is readily identified as a strong trough on normal polarity sections (Appendix 10.6.6:
Table 10.6.8), and flat or peak signature elsewhere. The increase in velocity is due to the presence
of older, metamorphic/volcanic/igneous rock types usually associated with faster velocities.
The horizon is a peak in places and this may be caused by tuning effects from the overlying coaly–
sandy Permian succession, resulting in wavelet polarity interference.
Bandanna Formation (BAND)
The BAND horizon is associated with a decrease in velocity as seen on the sonic log, and is readily
identified as a moderate-to-strong peak on normal polarity sections (Appendix 10.6.6: Table 10.6.8).
The decrease in velocity is due to the presence of low velocity coals. The horizon is occasionally
interpreted on a trough or flat amplitude signature, for example where the coal has most likely been
eroded.
Rewan Formation (REWA)
The REWA horizon was phantomed down from the SNAK horizon. The TWT values applied are
summarised in Appendix 10.6.6 ( Table 10.6.8).
Showgrounds Sandstone (SHOW)
The SHOW horizon represents the top of the primary reservoir; in 70% of cases it is associated with
an increase in velocity as seen on the sonic log (Appendix 10.6.6: Table 10.6.8), and has next to no
velocity contrast elsewhere. The SHOW horizon is mostly identified as a weak-to-moderate trough
on normal polarity sections. The SHOW horizon is represented by a generally weaker amplitude
signature than the SNAK horizon, and so, was approximated by phantoming down from the SNAK
horizon see Appendix 10.6.6: section 10.6.5
Snake Creek Mudstone (SNAK)
The SNAK horizon represents the top of the primary seal for the Showgrounds Sandstone
reservoir:, in 70% of cases, it is associated with a decrease in velocity, as seen on the sonic log
(Appendix 10.6.6: Table 10.6.8), and is identified as a weak-to-moderate peak on normal polarity
sections. It is identified as a trough or flat amplitude signature elsewhere.
Moolayember Formation (MOOL)
The MOOL horizon represents the top of a secondary seal and overlies the Snake Creek Mudstone
(seal) and Showgrounds Sandstone (reservoir). The MOOL horizon is associated with a decrease in
velocity on the sonic log (Appendix 10.6.6: Table 10.6.8), and is identified as a peak in 70% of
cases on normal polarity sections, and a flat or trough amplitude signature in other cases. The trough
amplitude signature is seen where the top Moolayember Formation represents the erosional
boundary between the Bowen and Surat basins (Figure 6.2).
Walloon Coal Measures (WALL)
The WALL horizon, for the purposes of this study, represent a marker horizon close to fresh water
aquifers present within the Surat Basin. The WALL horizon is associated with a decrease in velocity
on the sonic log (Appendix 10.6.6: Table 10.6.8), and is identified as a peak on normal polarity
sections. The decrease in velocity is due to the presence of low velocity coals. The horizon is readily
identifiable throughout most of the study area.
41

Orallo Formation (ORAL)
The ORAL horizon represents an approximate base of the Cretaceous marine sequence and as such
is also characterised by a significant change in the compaction gradient. Mapping the horizon gives
flexibility in using it to associate different velocity functions to the depth conversion. The ORAL
horizon is associated with a decrease in velocity on the sonic log (Appendix 10.6.6: Table 10.6.8),
and is identified as a weak-to-strong peak on normal polarity sections. The horizon is difficult to
interpret in places. Other aspects of the interpretation, for example, involving misties, bulk shifts,
seismic reference datums and details of well-ties, can be found in Appendix 10.6.6.
Faults
Faults were identified within the BASE–to–MOOL horizon interval; no faults were interpreted
above the MOOL horizon. Faulting density is greater on the Wunger Ridge itself, and less so in
areas north and east of the ridge. The level of faulting density on the ridge makes individual faults
difficult to interpret on printed seismic sections, and it is also beyond the scope of this semi-regional
study. As a consequence of the time required to correctly identify complex fault patterns, and in
view of the goals of the project, it was thought unwarranted to spend a significant amount of time to
define fault trends in detail as these are located away from the main area of interest – the east
Wunger Ridge flank. The faults interpreted on the ridge, however, do help establish faulting
episodes and were, therefore, interpreted although approximations were made so as to simplify fault
maps (Figure 6.3). The Wunger Ridge flank can be seen to be relatively unfaulted in contrast to the
faulting density on the ridge itself.
6.1.3. Depth Conversion
Forty one wells are located within and adjacent to the study area, but of these wells, only about 50%
had measured time–depth data. Well-control was also poorly distributed. The absence of consistent,
measured time–depth data prevented the use of average velocity methods in depth conversion at
each well location to construct depth maps, as this would have resulted in poor depth
approximations in the areas between the well control. Consequently, the time–depth data from the
41 wells were combined to establish a regional time–depth trend (Figure 6.4). Several spurious
points not lying on-trend for two wells were removed prior to merging all 41 well time–depth pairs.
These spurious points were due to typographical errors in the well completion reports. The resulting
least-squares curve fit shows potential depth errors in the order of ±100 m for any one horizon.
The following theoretical regional function Z(T) relating depth and TWT (Equation 1) was used to
calculate depth (Robein, 2003: 72), where it is usually approximated as a second order polynomial
(Equation 2).
Z(T) = V 0 * T + a * T 2 + b * Z 3 + … Equation 1
The velocity V 0 is the instantaneous velocity at the reference T 0 , in our case the seismic reference
datum is 244 m ASL. The Z(T) equation (i.e. Equation 2) obtained by fitting a least-squares fit to
the time–depth data (Figure 6.4) is:
Z(T) = 1.103 * T + 0.0003 * T 2 Equation 2
The above function was applied to the TWT grids using the arithmetic formulae function available
in the Petrosys TM (seismic mapping software package) gridding module. A processing flow was
developed (Figure 6.5) to produce eight depth maps, one for each of the interpreted horizons. All
time–depth and isopach maps and time–depth plots for individual wells can be found in Appendix
10.6.6.
42

6.1.4. Mapping
Time structure, depth, isochron and isopach maps (Appendix 10.6.6) were produced in Petrosys TM .
Structure and isopach maps (Figures 10.5.4–10.5.11, 10.5.13–10.5.24) allowed a number of key
observations to be made with regards to:
• structural dip and subsequent predicted CO 2 migration routes;
• understanding basin-fill and erosion of sediments;
• estimation of probable future exploration activity within the study area (Figure 6.6) to better
estimate the range of storage site options, and minimise conflict with petroleum exploration.
For example, the Permian Tinowon Sandstone reservoir is presently being targeted for
exploration (Brady, 2004; Merrill et al., 2004; Willink et al., 2004) so that stratigraphic plays
might be worked up in any part of the study area. All areas are located on currently held
exploration permits where activity is ongoing.
• estimation of which part of the study area would be suitable for testing different geological
and engineering scenarios by building 3D geological models and reservoir simulations.
The structurally highgraded areas are shown in figure 6.6. Potential storage site options
include:
1) Meandarra updip-to-Weribone East;
2) Kinkabilla updip-to-Taylor downdip, and
3) Teelba Creek updip-to-Nardoo downdip (Figures 6.3 and 6.6).
Potential Storage Site Options
Meandarra updip-to-Weribone East
Modelling this storage option would test residual, stratigraphic, intra-reservoir baffle and structural
trapping scenarios along an extended migration path (Figure 6.6, option a). Some of the other
positive features of this option would also be the relatively thick seal (i.e. 300–500 m) and unfaulted
reservoir-to-seal section. Some faults do exist but fault tips terminate at around top Permian level
(Figure 6.2). The figure does, however, show the very attractive nature of this potential storage
option, in particular the apparent seal integrity and long migration route.
Some of the negative features of this storage site option are:
• no well control in the site area for the target reservoir;
• the relatively deep reservoir, and thereby increased cost of operations;
• the limited seismic control in places, masking key structural information, and
• tighter reservoir as interpreted from regional trends.
Drilling would, however, be required to prove up injectivity in this area. The closest well at
Overston-1 and -2 (Figure 6.3) showed poor-to-average porosities and permeabilities, and flow
rates from drill-stem tests of 0.25 MMcf/d and 1.5 MMcf/d with strong depletion indicating poor
reservoir characteristics. Hydraulic fracturing has been shown to improve the flow rate in the
short-term but the rate of decline is substantial (Sunshine Gas Ltd, 2005).
The approximate migration direction for CO 2 in the areas to the north of the Meandarra updip-to-
Weribone East option was estimated as east–west, with the CO 2 in the long term (i.e. > 100 years)
probably moving towards the Roma Shelf. This migration route would be less favourable for
reasons discussed in section 5.5. Additionally, Overton-1 intersected hydrocarbons (Merill et al.,
2004), so the structural trend south of the Overston structure may be targeted for exploration.
This exploration could interfere with any CO 2 storage projects.
43

Kinkabilla updip-to-Taylor downdip
This storage option would potentially test residual, stratigraphic, intra-reservoir baffle and structural
trapping scenarios along an extended migration path (Figure 6.6, option b). Some of the other
positive features of this option would be the relatively thick seal (i.e. 200–300 m) and relatively
unfaulted reservoir-to-seal section. There is well control at Kinkabilla-1, Kinkabilla Creek-1 and
Inglestone-1 (Figure 6.3). Some faults do exist but these disappear at around the top Permian level
(Figures 6.7 and 6.8). Similar structural profiles 10 km to the north of line C81-6 show no faulting
(Figure 6.9). Faulting density varies but is still relatively low compared to the density at the Wunger
Ridge, and there appears to be no faulting at the Showgrounds Sandstone level.
Some of the negative features of this storage site option are:
• the relatively deep reservoir, and thereby increased cost of operations;
• the limited seismic control in places, possibly masking key structural information
(Figure 6.6), and
• tighter reservoirs as interpreted from regional trends and palaeogeography maps
(Section 6.4). Drilling would be required to prove up reservoir characteristics.
Teelba Creek updip-to-Nardoo downdip
This storage option would ultimately test residual, stratigraphic, intra-reservoir baffle and structural
trapping along an extended migration path (Figure 6.6, option c). Some of the other positive features
of this option would be:
• greater well-control, and higher permeabilities present in the area (Section 6.4);
• shallower reservoir targets than in other storage site options; in the order of 400–500m less,
so that drilling would be less expensive;
• possibly reduced exploration activity in the area due to the lack of exploration success to
date;
• non-uniform structural gradient and azimuth, which add complexity to CO 2 migration routes.
Some of the negative features of this storage option are:
• the minimal seismic data interpreted in this area, and
• the thin seal (i.e. Snake Creek Mudstone and Moolayember Formation), and higher faulting
density, which increases the chance of a seal breach being present.
The Kinkabilla updip-to-Taylor downdip option was favoured against the Meandarra updip-to-
Weribone East option principally, because of the increased well-control, and better permeabilities
present in the Wunger Ridge wells. Additionally, the favoured option would still test all trapping
scenarios. The Teelba Creek updip-to-Nardoo downdip option probably suffers from a higher
probability of seal breach, although this would need to be confirmed by interpreting more seismic
lines. For the purpose of this report the Kinkabilla updip-to-Taylor downdip is referred to as the
Wunger Ridge flank.
44

Figure 6.1. Seismic sections across the Wunger Ridge study area. (a) East–west seismic line HSI-1003 on
Wunger Ridge flank. (b) East–west seismic line 78B-39, across Waggamba-1. Seismic horizons, from bottomto-top:
magenta - basement, purple - top Permian, light green - Snake Creek Mdst (also approximates top
of Showgrounds Sst), dark green - Moolayember Fm, orange - Walloon Coal Measures, blue - Orallo Fm.
Figure 6.2. Seismic sections across the Wunger Ridge study area. East–west seismic line S78-3, updip Meandarra-1
to downdip Weribone East-1. Seismic horizons, from bottom-to-top: magenta - basement, purple - top Permian,
light green - Snake Creek Mdst (also approximates top of Showgrounds Sst), dark green - Moolayember Fm,
orange - Walloon Coal Measures, blue - Orallo Fm.
45

Figure 6.3. Depth map of basement across the Wunger Ridge study area. Referenced to a SRD of +244 m ASL.
Red coloured well symbols - shows well-control on basement and were used in depth conversion; red outline -
46

0
TWT ~ Depth (SRD = 244m)
TWT (ms)
y = 0.0003x 2 + 1.103x
R 2 = 0.9969
0 500 1000 1500 2000 2500
500
1000
1500
Depth (m)
2000
2500
3000
3500
4000
Figure 6.4. TWT–depth pairs for 41 wells located in the Wunger Ridge study area. Note: ‘x’ in the equation
refers to TWT, and ‘y’ refers to depth; both sets of data are referenced to a SRD of + 244 m.
Figure 6.5. Depth conversion flowchart. The depth–TWT function used requires wells to be retied in the
depth domain because of the regional trend nature of the function. Words in italics are Petrosys TM
software functions.
47

a
b
c
Figure 6.6. Potential storage site options in Wunger Ridge study area. Pink patch — storage site options. Option a:
northern patch — Meandarra updip–to–Weribone East; option b: middle patch — Kinakabilla updip–to–Taylor
downdip; option c: southern patch — Teelba Creek updip–to–Nardoo downdip. Green patch — estimated location
of Permian Tinowon Sandstone zero edge play; brown patch — estimated areas of future exploration (based on
structural highs and flatter structural gradient); light blue patch — open acreage at time of study.
48

Figure 6.7. BANDANNA-to-SHOWGROUNDS isopach map. Red coloured well symbols — shows
control points on basement, also used in depth conversion; red outline — limit of interpreted seismic.
Figure 6.8. Seismic sections across the Wunger Ridge study area. East–west seismic-line C81-6, tie to Kinkabilla-1
& Inglestone-1. Seismic horizons, from bottom-to-top: magenta — basement, purple — top Permian, light green
Snake Creek Mdst (also top of Showgrounds Sst), dark green — Moolayember Fm, orange — Walloon Coal
Measures, blue — Orallo Fm.
49

Figure 6.9. Seismic sections across the Wunger Ridge study area. East–west seismic line C81-3, north of Kinkabilla-
1. Seismic horizons, from bottom-to-top: magenta - basement, purple- top Permian, light green - Snake Creek Mdst
(also approximates top of Showgrounds Sst), dark green — Moolayember Fm, orange — Walloon Coal Measures,
blue - Orallo Fm.
Figure 6.10. Seismic section across the Wunger Ridge study area. (a) East-west seismic line HIS-1008,
Wunger Ridge flank. (b) East-west seismic line HIS-1001, downdip Wunger Ridge flank. Seismic horizons, from
bottom-to-top: magenta-basement, purple-top Permian, light green-Snake Creek Mdst (also top of Showgrounds
Sst), dark green-Moolayember Fm, orange- Walloon Coal Measures, blue- Orallo Fm.
50

Maps and Basin Fill
The Basement to Moolayember Formation structure maps (Appendix 10.6.6; Figures 10.5.4 -
10.5.11, 10.5.13–10.5.20) indicate higher faulting density on the Wunger Ridge. Few faults extend
into the Surat Basin sediments (i.e. above the Moolayember Formation), an observation consistent
with recognised late Permian faulting and early Jurassic reactivation, as observed from the seismic
data (Korsch et al., 1998) followed by a relatively quiescent period. The marked shift in location
between the Surat and Bowen Basin depocentres is evident by comparing the pre-Snake Creek
Mudstone horizon (Figure 10.5.17) and Walloon Coal Measures horizon (Figure 10.5.18) maps.
The shift in depocentres can be seen to swing from the northeast Taroom Trough to the southeast.
Note that localised depocentres, adjacent to the greater Waggamba-1 (Figure 6.3) area, stack up in
both basins.
The Basement-to-Bandanna and Snake Creek Mudstone-to-Moolayember isopachs show Permian
and Triassic depocentres located on the eastern side of the study area with a well-defined north–
south hinge-line present halfway between Meandarra-1 and Weribone East-1 (Figures 6.3 and 6.7).
The Snake Creek Mudstone and Showgrounds Sandstone intervals are not shown as the
Showgrounds Sandstone and Rewan horizons were phantomed, and therefore isopach maps are
meaningless. The Showgrounds Sandstone and Snake Creek Mudstone intervals are, however,
expected to thicken in the Taroom Trough. Sedimentation rates kept up with subsidence rates
resulting from foreland loading from the east and associated subsidence of the Taroom Trough.
As a result, the Taroom Trough received significant sedimentation in the early Jurassic, which
formed the Rewan Formation. Rates of subsidence slowed, and the Showgrounds Sandstone was
probably deposited in a less pronounced trough than present in the early stages of deposition of the
Rewan Formation. The large part of the thickness variation seen in the Bandanna-to-Showgrounds
Sandstone isopach is, therefore, due to the Rewan Formation infilling and truncation.
6.2. Geological Overview
6.2.1. Basement
Basement rock types intersected by petroleum exploration wells across the Wunger Ridge area are
interpreted to be Devonian to Permian in age. These rocks include plutonic granitic rocks (Roma
Granite), meta-sedimentary rocks (Timbury Hills Formation), and felsic volcanic rocks including
rhyolites and dacites (Combarngo Volcanics; Butcher, 1984; Appendix 10.1). Overlying basement
rocks are Permian to Cretaceous aged basin fill sediments of the Bowen and Surat basins (Figure
6.20).
During the Permian, major subsidence in the east led to the formation of the Bowen Basin and
subsequent deposition of sediments within the main Taroom Trough (Figure 3.3). These sediments
originated from a volcanic arc to the east of the Bowen Basin with minor influence from a stable
craton in the west (Butcher, 1984). Subsidence of the Taroom Trough was highest in the east, where
the Permian, Back Creek Group (Butcher, 1984; see Appendix 10.1) was deposited, gradually
lessening towards the west.
6.2.2. Permian Sediments
The Back Creek Group
The Back Creek Group is one of the original terms used to define Permian aged marine rocks in the
Taroom Trough. The Back Creek Group comprises marine to marginal marine siltstones, lithic
sandstones, coals and tuffaceous, calcareous and pyritic claystones, dominantly sourced from the
eastern volcanic arc as well as limited occurrences of limestone. Due to rapid, almost continuous
sedimentation, and a lack of palynology, the unit is generally considered hard to differentiate and
therefore often just grouped as one.
51

Figure 6.11. Diagrammatic cross-section of the Wunger Ridge study area. The Moolayember Formation extends
well beyond the Bowen Basin into the Galilee Basin to the northwest. Basement age is uncertain and varies
between authors and rock types (Modified from Butcher, 1984).
The character of the Back Creek Group changes to the west due largely to decreased
accommodation space (ratio of sediment supply to subsidence or water level rise) and an increased
component of quartz rich sediment sourced from the stable craton to the southwest.
This produces pronounced changes in reservoir characteristics and an increased ability for different
sedimentary cycles to be distinguished. The effort to define these cycles has been controlled by their
economic importance, with increased palynological control leading to numerous attempts to
redefine the Back Creek Group (Appendix 10.1).
Following the deposition of the Back Creek Group, the coal prone Bandanna or Kianga Formation
(Appendix 10.1) was deposited (Butcher, 1984). Interpreted as a series of fluvial and flood plain
sequences, the base of this formation can be hard to distinguish from the underlying Back Creek
Group (Butcher, 1984). Despite similar characteristics, separation of the Bandanna Formation from
the Back Creek Group is usually based on the greater proportion of thicker coal seams found in the
Bandanna Formation (Butcher, 1984).
Porosities (< 10%) and permeabilities (generally < 1 mD) within the sandstone facies are poor, due
to the lithic and argillaceous matrix; however cleaner quartzose sandstones exist (Butcher, 1984).
An example of cleaner sandstones can be found in Waggamba-1, in the Tinowon Formation which
is also currently the target of renewed exploration activity within the Taroom Trough.
6.2.3. Triassic Sediments
Rewan Formation
Deposition of the Rewan Formation into the Taroom Trough began with the onset of foreland thrust
loading associated with the Hunter–Bowen Event (Fielding et al., 2001) and continued during the
early Triassic (Butcher, 1984). The Rewan Formation consists of mudstones, siltstones, sandstones
and conglomerates, including multi-coloured lithic arenites containing rhyolitic tuff (Butcher,
1984). This formation has undergone extensive silicification and clay alteration resulting in low
porosity and a permeability often less than 1 mD (Butcher, 1984).
52

Showgrounds Sandstone/Snake Creek Mudstone
Unconformably overlying the Rewan Formation is the Showgrounds Sandstone; equivalent to the
Clematis Sandstone elsewhere in the Bowen Basin. The Showgrounds Sandstone represents the
early onset of a Triassic transgressive system that includes the Snake Creek Mudstone and the
Moolayember Formation (seals). The overlying Snake Creek Mudstone is expected to hold back a
significant height of CO 2 in this region without too much risk of leakage into the overlying fresh
water formations of the Surat Basin (Figure 6.11) especially as the overlying Moolayember
Formation is likely to be an effective seal in its own right.
Wells drilled east of the Wunger Ridge all have a similar description of an interval defined as the
Showgrounds Sandstone. This description is of white to brown sandstones, with fine to very coarse,
angular to subangular grains. The grains are largely quartz of various colours (including clear, white
and orange) with varying amounts of rock fragments. The matrix is predominately a white clay and
there are varying amounts of calcareous cement. No conventional core samples were taken in the
wells, and as such, no core analysis was undertaken to estimate porosity and permeability. Side-wall
core samples were taken in Kinkabilla-1 (Figure 6.3) and descriptions are consistent with that from
well cuttings, that is a tight, poorly sorted sandstone with abundant lithic fragments. Drill Stem
Tests (DST) were conducted in Kinkabilla Creek-1, however, the results can not be reinterpreted
due to the poor quality of the data submitted to the Queensland Government. The original DST
report indicated the sand to be tight despite apparent permeability being indicated on the resistivity
logs. The above interpretations are based on interpreting raw data reports (UOD, 1966; SCO, 1987;
Coho, 1982).
Clematis Sandstone
The Clematis Sandstone ranges from a quartzose sandstone north of the study area to a volcanolithic,
sublabile sandstone in the southeast Bowen Basin (Dickens and Malone, 1973). The thickness
of the Clematis Sandstone ranges from approximately 100 m in the west to 300 m in the east, where
the volcanic component is at its greatest (Dickens and Malone, 1973). Planar cross-bedding, present
throughout the Clematis Sandstone, suggests an approximately north–south trending braided
channel facies model for deposition of sediments with siltstone interbeds, possibly representing
short-lived flood plains (Dickens & Malone, 1973).
The presence of a highly volcano-lithic succession of the Clematis Sandstone on the east side of the
Taroom Trough adjacent to the Wunger Ridge is confirmed by petroleum wells drilled in the area.
Cabawin-1 and Tartha-1 (Figure 5.2) wells, drilled in the 1960s both intersected a thick Clematis
Sandstone composed of predominantly greenish–grey quartzose pebbly sandstone with chert and
silicified ash in a white to green tuffaceous matrix, which would not be suitable for CO 2 injection.
Other wells may have intersected the Clematis Sandstone (e.g. Kinkabilla-1, Kinkabilla Creek-1 and
Inglestone-1 (Figure 6.3): located approximately 36 km from the Wunger Ridge). Unfortunately at
these locations, the Clematis Sandstone cannot be differentiated from the Showgrounds Sandstone,
although they will still provide information on the quality of potential reservoir sandstones east of
the Wunger Ridge, as is discussed below. No wells have penetrated the Clematis Sandstone in the
central part of the southern Taroom Trough.
It is recommended that the Clematis Sandstone be investigated further to the north, on the flank of
the Roma Shelf, in conjunction with a planned study of that area. Even though this area has
extremely limited data (i.e. one well in the west and two wells in the far-east, with nothing in the
middle of the trough), it is further away from the palaeovolcanolithic source located on the
southeastern edge of the Taroom Trough and therefore may have better reservoir quality. Modelling
at the Wunger Ridge indicates lower porosity/permeability injection sites are potentially feasible but
require an order of magnitude increase in the number of wells. At this stage it is not recommended
that a possible Clematis Sandstone injection site be assessed.
53

The storage potential of the Clematis Sandstone was investigated as a possible eastward extension
to the Showgrounds Sandstone. Based on palaeogeography maps (section 6.4) and the authostratigraphic
chart (Appendix 10.1), this would mean moving the injection site further down dip
into the thicker Clematis Sandstone which is a partial time equivalent of the Showgrounds
Sandstone. There are no wells drilled in the middle of the Taroom Trough intersecting the Clematis
Sandstone and thus no data. Therefore any geological assessment of the ability of the Clematis
Sandstone to store CO 2 would be based on data from wells tens of kilometres away which indicate
the Clematis Sandstone exhibits poor reservoir characteristics.
Moolayember Formation
The Moolayember Formation, the final stage and most widely spread depositional unit (Figure
6.11), of the Triassic transgressive system, is a predominantly deltaic unit (identified from core in
Rednook-1 (Figures 4.2 and 6.3), which conformably builds into the Snake Creek Mudstone
lacustrine system. The Moolayember Formation is expected to have significant sealing capacity, or
at the very least create an extremely tortuous migration pathway for any vertically migrating fluids
as it has a shaly base with a very broad coarsening upward nature. It also extends well past the
Showgrounds Sandstone pinch out edge (Figure 6.11).
6.3. Showgrounds Sandstone-Snake Creek Mudstone
reservoir/seal pairs
For a reservoir/seal pair to be suitable for CO 2 storage, the reservoir facies need to contain sufficient
permeability (pore scale connectivity), porosity (pore volume) and lateral connectivity of geological
bodies (at the scale of individual point bars and braided channels and bars) to cope with the
intended injection rate, and ultimate volume of injection. In addition to this the reservoir must be
sealed vertically and horizontally to trap the intended injection volume. Within the Bowen Basin,
one reservoir–seal pair, the Showgrounds Sandstone (reservoir)–Snake Creek Mudstone (seal),
stood out as appearing to be of significant lower risk than others.
The Wunger Ridge and flank area, in particular, stood out over other site options as previously
discussed in Section 6.1.4. Of particular note, hydrocarbons have been successfully trapped within
the Showgrounds Sandstone beneath the Snake Creek Mudstone since hydrocarbon expulsion and
migration, thus the seal has been proven over a large area and over time (Butcher, 1984; Home et
al., 1990). The Snake Creek Mudstone in the Wunger Ridge area appears not to have been
compromised through any significant structural events with no evidence of upward migration of
hydrocarbons into the upper Moolayember Formation or overlying Jurassic to Cretaceous, Surat
Basin. The absence of stacked hydrocarbon pools across the Wunger Ridge suggests the Snake
Creek Mudstone is a reliable long term sealing lithology which is relatively un-faulted at this
location.
By contrast, at the Roma Shelf, 70 km north of the Wunger Ridge, the presence of hydrocarbons in
the younger and shallower Jurassic aged strata indicates the Snake Creek Mudstone seal is
compromised, most likely by faulting. Maturity modelling of sediments within the Taroom Trough
indicates maximum expulsion occurred during the Mid Cretaceous approximately 90 Ma before
present (Korsch et al., 1998).
6.3.1. Previous Work
There is little published information on the Showgrounds Sandstone in the Wunger Ridge area, as
such Butcher’s 1984 paper is the main source for this brief review. Butcher divided the
Showgrounds Sandstone into three main facies units of fluvial origin with the upper unit showing
evidence of “marine influence” in a deltaic environment (interpreted to be lacustrine in this review).
It should be noted that Butcher’s units divide the Showgrounds Sandstone horizontally into
lithological units with an overlying third unit.
54

Using this method there is a potential to misinterpret the relationship between different lithologies
in space, as opposed to time, by using a sequence stratigraphic approach which ensures that the
facies are predictable.
Butcher (1984) described the units as follows:
• Facies unit 1 — fluvial proximal with an abrupt upper and lower contact “a braided
system”. He indicates this unit has the better reservoir quality overall and that there is
significant reservoir variability within the unit.
• Facies unit 2 — a fluvial unit with an abrupt lower boundary that fines upwards
“a meandering system”.
• Facies unit 3 — is generally a coarsening upwards sequence with an abrupt upper shale
contact “a deltaic system”.
6.3.2. Cathodoluminescence Petrography
A number of samples were collected from core ranging in age from 44 to 18 years old and stored at
Geoscience Australia. The sample set comprised contemporaneous (Triassic) samples, two
tuffaceous and six Showgrounds Sandstone from the Wunger Ridge and one tuffaceous and three
Showgrounds Sandstone samples from the Roma Shelf. In addition to this, one sample from each of
the Freitag (Permian) and Aldebaran (Permian) Formations in the Denison Trough were analysed
(Table 6.2). The samples from the Roma Shelf and Denison Trough were taken as comparison
samples and as part of a scoping study into the CO 2 storage potential of those regions, for this
reason only Wunger Ridge samples will be discussed here.
Cathodoluminescence Petrography (CL) was carried out on samples from the Wunger Ridge and
indicates that the quartz was derived from a dominantly plutonic source, with some minor
contributions from both volcanic and metamorphic sources (Appendix 10.6.2). In addition to this,
CL showed that the quartz in the tuffaceous samples had the same source rocks as the Showgrounds
Sandstone samples, suggesting they are in fact tuffaceous sandstones rather than volcanic tuffs.
Further evidence confirming the tuffaceous nature and volcanic input into the system is the presence
of non-luminescent glassy fragments in sample HT1804a (Table 6.2), suggesting an extremely short
detrital grain transport from volcanic source sediment.
Table 6.2. Listing of petrography samples numbers. Taken from Barclay (2005; Appendix 10.6.2; see Figure 4.2 for
location of Wunger Ridge wells).
Sample
No.
Well Name
Year
Well
Drilled
Depth Taken
Well Location Meters Feet Formation Sample
From
C5091 Combarngo-1 1961 Roma Shelf 5091’4’’ Showgrounds Sst whole core
C5089 Combarngo-1 1961 Roma Shelf 5089’4’’ Showgrounds Sst whole core
H1978 Harbour-1 1987 Wunger Ridge 1978.67 Tuff (Snake Ck) half core
H1987 Harbour-1 1987 Wunger Ridge 1987.3 Showgrounds sst half core
HT1804a Hollow Tree-1 1963 Wunger Ridge 1804.2 Tuff whole core
L6604 Lorelle-1 1963 Roma Shelf 6604’4’’ Tuff/Showgrounds whole core
L6608 Lorelle-1 1974 Roma Shelf 6608’4’’ ?Showgrounds Sst whole core
J6152 Silver Springs-1 1974 Wunger Ridge 6152 Showgrounds Sst whole core
J6150 Silver Springs-1 1963 Wunger Ridge 6150 Showgrounds Sst whole core
W3419 Warrinilla-1 1963 DenisonTrough 3419 Freitag Fm whole core
W3457 Warrinilla-1 1963 Denison Trough 3457 Aldebaran Sst whole core
WB7074 Combarngo-1 1963 Wunger Ridge 7074’3’’ ?Showgrounds Sst whole core
Y1869 Yellowbank Ck Nth-1 1987 Wunger Ridge 1869.5 Showgrounds Sst half core
Y1870 Yellowbank Ck Nth-1 1987 Wunger Ridge 1870.25 Showgrounds Sst half core
55

6.3.3. Thin Section Petrography
Thin section petrography of the Wunger Ridge samples identified mostly quartz–rich rocks, being
classified as either sub-litharenites or sub-arkoses (Figure 6.12). Besides quartz, other detrital
(deposited by sedimentary processes) minerals present in the samples include: feldspar, clay grains
displaying evidence of compaction, minor amounts of mica (muscovite and biotite), and
metamorphic rock fragments. Diagenesis has resulted in the precipitation of secondary minerals in
all samples analysed, including quartz (as overgrowths), clays (illite, kaolinite and minor chlorite),
and carbonates (calcite and dolomite). These secondary minerals have had some impact on the
porosity and permeability of the samples, with the illite and calcite minerals having the biggest
impact on reducing porosity where present.
Based on the thin section analysis the tuffaceous samples can be classified as coarse grained poorlywelded
tuffs or tuffaceous sandstones. Sample HT1804a (Table 6.2) contains layered volcanic glass
fragments that do not display significant deformation, supporting the tuff classification with limited
fluvial reworking. Despite this the tuffaceous samples are not especially different from the
sandstone samples in terms of their mineralogy.
Quartz
•
•
•
•
• •
• •
•
•
•
Sample
Number
• C5089
• C5091
• H1978
• H1987
• HT1804a
• J6150
• J6152
• L6604
• L6608
• W3419
• W3457
• WB7074
• Y1869
• Y1870
Feldspar
Rock fragments
Figure 6.12. Petrographical classification of samples. Figure shows that the Showgrounds Sandstone is a
relatively stable quartz dominated unit, with few components likely to react with CO 2 injected into the unit
(after Folk, 1974).
56

6.3.4. X-ray Diffractometry
X-ray Diffractometry (XRD) analysis of samples from the Wunger Ridge show quartz is the
dominant mineral present in all samples. Other minerals identified in the samples by XRD were
kaolin in most samples and a poorly crystallised mica mineral identified as illite which was present
in some samples. All of the sandstone samples contained clay minerals, either kaolinite, illite or
chlorite with the majority containing a mixture. Total clay content for the sandstone samples varied
from 2 % (J6152 in Table 6.2; Figure 6.12) up to a maximum of 43 % (Y1869). It is worth noting
that the samples with relatively high clay content show an apparent higher degree of feldspar
dissolution.
Tuffaceous samples analysed with XRD show no notable differences to the sandstone samples, with
sample HT1804a being an exception. This sample contains a significant amount of calcite
suggesting that the tuffaceous sandstone sediments contained a mineralogical source of calcium
(e.g. anorthite). This sample was taken from a location a few centimetres above metamorphosed
basement which is the most obvious source of the calcite.
6.3.5. Analysis of Results
Combined, the CL, XRD and thin section petrography indicate that the quartz found in the
tuffaceous sediments and the Showgrounds Sandstone is related, coming from a predominantly
plutonic source with additional input from volcanic and metamorphic sources. This similarity
suggests that the tuffaceous sediments are actually sandstones, containing a high proportion of
volcanic clay (i.e. tuffaceous sandstones). The interpretation of a volcanic origin for the clay present
in the tuffaceous sandstones is strengthened by the presence of volcanic glass fragments.
Overall the samples analysed from the Wunger Ridge are dominated by quartz grains with only
minor amounts of other constituent minerals. This suggests that the Showgrounds Sandstone is
chemically stable and as such injecting or storing CO 2 in the formation is not anticipated to cause
adverse chemical reactions leading to a significant reduction in porosity and permeability. Some of
the samples contain clay minerals which appear to have the greatest influence on reducing porosity
and thus prospective CO 2 storage volume. A full report on the CL, XRD and thin section analyses,
including photomicrographs, can be found in Appendix 10.6.2.
6.3.6. Showgrounds Sandstone Sedimentology
The Showgrounds Sandstone comprises conglomerates, sandstones (containing clear to white subangular
to sub-rounded quartz), siltstones and shales, deposited in a dominantly fluvial environment
(Butcher, 1984).
Southwest of the Wunger Ridge, intersections of economic basement in wells are typically
described as granite and often referred to in company Well Completion Reports as the Roma
Granite. North of the granite the economic basement intersected in wells is described as the
Timbury Hills Formation which is a regional metamorphic rock. Petrographic analysis indicates
these two rock types appear to be the source of sediment for the Showgrounds Sandstone, with
minor volcanic input from an eastern volcanic arc.
Cathode luminescence (CL) indicates changing sedimentary provenance for the quartz component.
In the Wunger Ridge area, a plutonic provenance (i.e. Roma Granite) is dominating the drainage
cell although there is the influence of a metamorphic terrain (i.e. Timbury Hills Formation) and an
ash fall. The rock is described using Folk’s (1974) classification as sub arkose–sub litharenite to
quartz argentite (Appendix 10.6.2).
Petrographic analysis has been conducted on what was previously lithologically described as a tuff
in the Wunger Ridge area and appeared to be contemporaneous with the Showgrounds Sandstone.
The tuff was tested as a potential late provenance of the Showgrounds Sandstone on the basis of
similar quartz grains within the tuff. The analysis indicates that the tuff was misnamed and the rock
is actually sandstone with high volcanic ash content.
57

Significantly this information can be used to trace the back stepping Showgrounds Sandstone
further to the west than has previously been interpreted. The ash fall is likely to have dramatically
increased the sediment supply during a comparatively short period of time, resulting in a locally
well defined unit. The tuffaceous sandstone’s change in grain size may provide some of the best
evidence for localised palaeo-flow direction as the grain size progressively increases toward the
source. Unfortunately time constraints of this project prevented this aspect from being assessed.
Classification of rock samples using Folk’s (1974) classification indicates samples taken from
southeast of the Wunger Ridge are litharenites (Appendix 10.6.2). The high proportion of rock
fragments indicates that an older sedimentary/metamorphic terrain makes up a significant part of
the drainage cell in that area. This is interpreted to indicate that the drainage cell, has less exposed
Roma Granite to erode and provide sediment and therefore, is disconnected from the Wunger Ridge.
Alternatively the sample could be from a minor tributary which entered the main fluvial system.
Due to the characteristics of the catchment such as extent, elevation and orientation relative to
prevailing rainfall, this minor tributary was unable to substantially alter the sedimentology of the
system. Given the distance and the inferred west-to-east palaeo-dip, the first scenario is considered
more plausible.
In the Wunger Ridge area, the collection and analysis of additional samples could test whether the
relative abundances of quartz provenances determined from petrography could be used to determine
individual palaeo-drainage cells. If this was successful there was the potential to improve the
robustness of the palaeoenvironmental interpretation (palaeogeographic maps, see section 6.4).
However, for this study, it is considered that the work would not significantly alter the reservoir risk
or uncertainty for CO 2 storage.
Figure 6.13. Cross plots of permeability and porosity vs depth for Wunger Ridge samples. Uses a 60 API cut-off
to show potential sandstone reservoir. The plots indicate that there is no correlation between permeability or
porosity and depth.
To reduce the risk of drilling an injection well in an area that has poor injection and storage
characteristics, an understanding of the distribution of porosity and permeability needs to be
developed. To scope out possible porosity, permeability, depth and facies relationships, a subset
of the well data has been analysed. Theoretically, there is a direct relationship between porosity
and permeability in that as porosity increases, permeability increases. Generally, as sedimentary
rocks are buried to greater depths, diagenetic processes reduce the porosity by chemical and
mechanical alteration.
In contrast to theoretical trends there is no relationship seen between porosity and depth across the
narrow depth range (i.e.1900–2400 m) of the Showgrounds Sandstone on the Wunger Ridge
(Figure 6.13). Whilst there is no relationship between sandstone porosity and depth, both porosity
58

and permeability are sedimentary facies dependant (Figure 6.14). Both fluvial braided and
meandering systems display good porosity/permeability correlation. As expected, floodplain facies
show the lowest porosity/permeability values. Deltaic facies are highly variable and therefore less
predictable. For example, there is a positive correlation between good permeability (> 10 mD)/good
porosity (> 10 %) and the sandstones in the braided and meandering fluvial system (Figure 6.14).
Porosity vs. Permeability by Facies
100000
10000
1000
Permeability (mD)
100
10
1
0.1
0.01
0 5 10 15 20 25
Porosity (%)
Fluvial Braided Fluvial Lag Distributary-Deltaic Flood plain Fluvial meandering channel
Figure 6.14. Cross plot of porosity vs permeability for Wunger Ridge facies type samples. Uses no GR cut-off.
The cross-plot shows an apparent correlation between porosity (>10 %) and permeability (>10 mD) for the fluvial
braided and meandering environments.
Preliminary data analysis indicated that predicting the environment of deposition and the associated
facies types would provide the most efficient means of predicting reservoir quality, and therefore
reducing overall risk for potential injection sites.
6.3.7. Core Interpretation
Drill core from exploration wells provides one of the primary datasets that is used to verify the
palaeoenvironments and the porosity/permeability values interpreted from electrical log data.
However core is not taken over the full bore length due to the cost involved. Therefore, it is
necessary to integrate data which is taken over the full length of the bore, such as electrical log data
(which measures the average electrical response of the lithology over a given interval) to core data,
to give a high resolution insight over a particular zone of interest.
The porosity and permeability data in well completion reports can be quality controlled through
direct comparison to measurements made on the core. For example, it was observed at Tintara-1
(Figures 4.2 and 6.3) that the permeability of the majority of the Showgrounds Sandstone ranges
around 20–30 mD. A measured permeability of 151 mD was obtained from a core sample at a depth
59

of 2303.15 m which correlated to a clean streak approximately 1–2 mm thick, interpreted to be a
bedding plane.
The core demonstrated that individual permeability readings may be related to millimetercentimetre
scale isolated features in the rock rather than characteristic of the whole rock volume at
the scale of an individual geological body such as a point bar. While an attempt to integrate
permeability conduits and barriers at the core scale should be attempted, it is the accurate portrayal
of the rock volume that the reservoir model attempts to represent.
It is observed that, within the fluvial sandstones, the medium to coarse grain sandstones which are
interpreted as proximal braided fluvial facies are the ones with the best porosity (7–22 %) and
permeability (>1000 mD; Figure 6.14). Transgressive mouth bars tend to exhibit a regular but clay
prone environment and represent the least suitable environment to target for injection and storage.
Overall the examined core indicated that the highly permeable rock (>100 mD) is restricted to the
higher energy braided and meandering fluvial facies (Figure 6.14).
Figure 6.15.East–west/south–north cross-section of the Wunger Ridge flank. Turns north–south at the Nardoo-1
hinge point. The section is flattened on the top Snake Creek Mudstone. The wireline curve depicted is the Gamma
Ray. Note the blocky nature and connectivity of the braided channels in Sirrah-5 and how the sandstone packages
become vertically disconnected downdip towards the east and north (meandering – deltaic).
60

Cores from wells located on the Wunger Ridge flank (Figure 4.2) tend to have a higher clay content
and lower permeability. This may be due to a:
• relative decrease in the amount of fluvial reworking and recutting by channels migrating across
the channel belt as the amount of accommodation space increases;
• sediment from an additional (less mature) source rock provenance entering the fluvial system
down stream; or
• reduced geochemical alteration, caused by reduced hydrodynamic processes.
The first of these options is the most likely because, as the accommodation space increases off-flank
the preservation potential and the vertical separation of sandstone units increases, as more of the
finer grained facies are preserved, a feature evident in the core and well-logs (Figure 6.15).
The Waggamba-1 well shows an example of a thicker section deposited in an area of increased
accommodation space (i.e. 38 m of Showgrounds Sandstone). The Waggamba-1 core contains
evidence that there are two provenances which are preserved in the lower part, with rapid changes
in shale content, colour and grain size (Figure 6.16), representing an alternating dominance between
local granitic and metamorphic terrains .
The Waggamba-1 core was one of the few cores which were interpreted to have a preserved
lowstand systems tract of the Showgrounds Sandstone. In this core, the sandstone facies has better
permeability (~ 150 mD), whilst the poorly sorted and texturally immature conglomerate has
virtually no permeability.
Based on structure maps, the lowstand systems tract of the Showgrounds Sandstone (Section 6.3.10
-6.3.12) could be interpreted to occupy a roughly west–east orientated valley with the thickest
section around Waggamba-1. Core observations from Tintara-1 and Teelba Creek-1 suggest they
are on the southern edge of the lowstand system, (Figures 4.2, 6.3 and 6.15). There is an increase in
thickness of the conglomerate from Tintara-1 toward Waggamba-1. This increase may indicate that
Waggamba-1 is located towards the main axis of the palaeo-valley.
Based on well intersections and orientation of regional structural trends such as faults and ridges, it
was hypothesised that the valley may turn slightly between Silver Springs field and Sirrah-5
(Figures 4.2 and 6.3) to run approximately north–northwest to south–southeast before resuming the
east–west trend to the Waggamba-1 well.
Teelba Creek-1 does not have any conglomerate in the core investigated. The sandstone facies
displays poor permeability due to an increase in clay content compared to Harbour-1 (Figure 4.2
and 6.3), which is in a more proximal position to the southwest. Teelba Creek-1 is interpreted to
have intersected the southern side of the palaeo-valley or an interfluve beyond the edge of the
conglomeratic fluvial system identified in the Tintara-1 and Waggamba-1 wells. As other wells
along the flank of the Wunger Ridge to the south of the Waggamba-1 area are not interpreted to
have intersected the facies observed at Waggamba-1 or Tintara-1, this absence suggests a roughly
west-to-east trending conglomerate body which is laterally constrained in the north–south direction.
In the wells along the Wunger Ridge, a northeasterly trend of increasing vertical separation of
interpreted sandstone facies is apparent, along with a reduction in grainsize, representing a
corresponding reduction in energy in the system to the north (Figure 6.16). An example of this is the
difference in grainsize and bed thickness found in the fluvial–distributary channel facies of
Namarah-2, which ranges from fine to coarse grained sandstone with bed thicknesses of 1–1.5 m
(Figures 6.17 & 6.18), compared to the more proximal fluvial facies in Habour-1 and Sirrah-5;
ranging from medium grained sandstone to conglomerate with bed thicknesses of approximately 3
m (Figures 6.19–6.21).
The fluvial–distributary channel facies interpretation for Namarah-2 is based on the presence of
climbing ripples which is due to decelerating flow with an abundance of sediment indicative of a
distributary systems entering standing bodies of water (sea/lake/pond, Boggs, 1995), and
bioturbation, which is indicative of a deltaic, lacustrine environment (Miall, 1990).
61

Figure 6.16. Photograph of Waggamba-1 core. Shows
lowstand – late lowstand systems tract conglomerate
and sandstone bedding. Cross bedding indicates
traction current processes are operating indicating a
fluvial environment. Not readily apparent in this
photograph is the marked change between the
conglomerate and the sandstone indicating the system
may have dual provenances (taken from BON, 1981).
Figure 6.17. Photograph of Namarah-2 core. Shows
Showgrounds Sandstone, an interpreted fluvial section.
Diagenetic alteration has reduced the permeability
whilst largely preserving the porosity at this location.
Figure 6.18. Photograph of Namarah-2 core. Shows
Showgrounds Sandstone, shoreface to delta distributary
sandstone. Diagenetic alteration has reduced the
permeability whilst largely preserving the porosity at
this location.
Figure 6.19. Photograph of Harbour-1 core. Shows
approximately one metre of high permeability (K)
(with good porosity (Ø)) Showgrounds Sandstone cross
bedded sandstone reservoir. The high quality reservoir
generally thins from the Wunger Ridge. A comparison
can be made from this location at Harbour-1 to that in
Namarah-2 (Figures 6.19 & 6.20) to the north where
the same porosity has orders of magnitude less
permeability.
62

Many of the wells in the central part of the Wunger Ridge have climbing ripples, however they
lack bioturbation in the core. Glenfosslyn-1 is an example of a well with climbing ripples in the
core (Figure 6.22) with no bioturbation. The absence of bioturbation indicates a lack of duration
for the water body, or a significantly higher rate of sedimentation, which would not be a favourable
environment for burrowing fauna. Based on this interpretation, the climbing ripples found in
Glenfosslyn-1, most likely represent a crevasse splay infilling a laterally limited flood-plain lake,
rather than a deltaic mouth bar infilling a large extensive permanent water body.
The presence of lacustrine trace fossils in the Namarah-2 core (Figure 6.23) and increased shale
content indicates an environment with lower fluvial sediment input than that taken from a similar
stratigraphic position at Glenn Fosslyn-1. The implication is that Namarah-2 location is more distal
to the palaeo-sediment source than the Glen Fosslyn-1 location to the southeast, and probably
represents the approximate location of the shoreline of the Showgrounds Sandstone fluviodeltaic
system (Figure 4.2).
Sirrah 5 core has the best permeability in coarse sandstone and looks similar to the sandstone
observed in the Silver Springs-1 and Yellowbank Creek North-1 core. The sandstone has coarse
cross bedding which indicates traction currents are operating. Using the coarse grain size as a guide
the system was flowing at a minimum of 0.5 metres-per-second (Boggs, 1995).
The depositional system at Sirrah-5 is interpreted to be a braided fluvial sandstone with an
approximate vertical height of nine metres. It appears from an investigation of the core that facies
has a strong control on the porosity and permeability at this location (Figure 6.14). Well sorted
braided fluvial sandstone has the better permeability (mostly multiple Darcy) whilst the poorly
sorted braided fluvial conglomeratic facies has the lowest permeability (mostly less than 50 mD)
(Figures 6.20, 6.21, 6.24 and 6.25). At Silver Springs the sandstone reservoir thickness ranges from
about one metre to about eight metres across the field and is interpreted to be a fluvial braided
facies, which is onlapping onto a palaeo high. In this facies the preserved thickness is largely
controlled by the proximity of the palaeo highs as the braided fluvial system passed through palaeo
valleys and other topographic lows and was terminated rapidly by a transgression (Figure 6.15 –
Sirrah-5 well log).
Observations from the core have confirmed that there is a correlation between the environment of
deposition and permeability. This suggests that using a sequence stratigraphic approach to produce
a geological model should reduce the reservoir risk and help constrain or highlight the uncertainties
for various potential injection sites. At the well-bore scale the environment of deposition should
always be considered when interpreting the electrical logs particularly as an increase in gamma
ray response does not necessarily represent a reduction of energy in the depositional environment.
Generally the permeability declines northward along the Wunger Ridge area due to an increase in
clay content (reduction in energy), the presence of carbonate cement and the hydrothermal alteration
of feldspar grains. The increase in clay content can be predicted with a facies map developed from
the interpretation of core and electrical log data, however at this point in time no model has been
developed to predict areas of elevated carbonate cementation and hydrothermal alteration other than
to observe that the risk appears to be greater in the north.
63

Figure 6.20. Photograph of Sirrah-5 core. Depicts a
low permeability baffle which is related to a
conglomeratic facies in Sirrah-5. The conglomerate
appears poorly sorted with cross bedding which
indicates traction processes. This has been interpreted
to indicate a fluvial environment. The core indicates
permeability is facies controlled at this location (Taken
from BON, 1989).
Figure 6.21. Photograph of Sirrah-5 core. Depicts the
Showgrounds Sandstone. Cross bedding indicates
traction current processes typical of a fluvial system.
In this case interpreted to be a braided system
(Taken from BON, 1989).
Figure 6.22. Photograph of Glen Fosslyn-1 core.
At the top of the figure is a wave modified ripple in
the Showgrounds Sandstone indicating shallow semi
open–open water (wr). In the middle of the figure is a
set of climbing ripples (cr) indicating decelerating flow
characteristic of processes where by a moving body of
water is entering a standing body of water such as
mouth bars and crevasse splays. In this case the lack
of bioturbation would suggest a crevasse lake or a very
active mouth bar.
Figure 6.23. Photograph of Namarah-2 core.
Shows the vertical (v )and horizontal (h) bioturbation
concentrated in the shale prone section within the
Showgrounds Sandstone at Namarah-2. The presence
of bioturbation is an indicator of relatively long term
or well connected water bodies.
64

Figure 6.24. Core description of the Sirrah-5 core. Shows an overall fining upwards fluvial system.
The low permeability conglomerate beds have not been documented on this log. Photographs from
1947.90–1948.20 m which appear in Figure 6.24 highlight what is missing from the above log.
This shows the value of re-examining core to solve specific problems (taken from BON, 1989).
65

Figure 6.25. Core plug analysis for Sirrah-5. Shows the basic measurements that are measured from core plugs
obtained from the core. The measurements have been taken from a braided fluvial system. In this case the low
permeability “baffle” (1947.9–1949.1 m) was related to a poorly sorted conglomerate bed (taken from BON, 1989).
6.3.8. Electrical Well-Log to Core Comparison
Petroleum exploration companies normally run electrical logs in all wells drilled. This gives
companies a better understanding of the subsurface and an idea of rock properties such as, density,
interval transit time or sound propagation (sonic), and radioactivity (gamma ray (GR)). Well logs
are cheaper than drill-cores and therefore there are more electrically logged bore holes than cored
66

oreholes. Depositional processes interpreted from core can be compared to the GR and sonic log
responses to interpret palaeo electro-facies (Figure 6.26).
The GR log is a measurement of the natural radioactivity of the formations. In sedimentary
formations the log normally reflects the shale content of the formations. This is because the
radioactive elements tend to concentrate in clays and shales. Clean formations (e.g. sandstone)
usually have a very low level of radioactivity (Schlumberger, 1989). Therefore, the GR curve is
related to core via shale content where the cleaner or less shale prone the lithology the lower the
GR reading.
Glen Fosslyn well dispay
0 GR 200 2000 0.2 25 0 140 40 1.95 2.65
DT
Nphi ( φ)
us/ft
Reversed
Nphi
Normal
Rhob
(density)
Showgrounds Sandstone
Neutron/Density
crossover
Total
φ
Rewan
Formation
Permeability
from core
Porosity
from core
Core interval
Grain density
from core
60 API
cut off
05-267-1
Figure 6.26. Well log display from Glen Fosslyn-1 covering the Showgrounds Sandstone. The display compares
data measured from core such as grain density, porosity and permeability to electrically derived
log data such as Gamma Ray (GR), Neutron porosity (Nphi), Density (Rhob), Velocity (DT), and Self Potential
(SP). Plotting all the data together allows a rapid method for quality controlling the data and for forming an
understanding of the relationships between permeability, porosity and neutron–density cross-over.
This report will not elaborate on the shape of the GR curve beyond three basic profiles or log
motifs. Along with core data to determine the scale of an individual or a single stacked channel
sequence, the shape of the GR vertical profile can be used to interpret the palaeoenvironment that
the wellbore penetrated. In a non-marine sequence a “blocky” GR profile in this area is indicative
of a braided fluvial system (Figure 6.27). An upward increase of GR units (upward fining profile)
is indicative of a meandering fluvial system (Figure 6.28 and 6.29). An upward decrease of GR
units (upward coarsening profile) is indicative that a distributary process is occurring which could
be anything from a crevasse splay with an area of a few hundred square metres, to a delta plain up to
tens of square kilometres in area (Figure 6.30 and 6.31).
67

Figure 6.27. Idealised braided fluvial facies
and grainsize profile (right) and corresponding
gamma ray profile (left). (After Kassan and Lang, 1999).
Figure 6.28. Photograph of Harbour-1 core. Depicts
the fining upward section, which indicates an
upward reduction of energy at the bed scale. This has
been interpreted as a meandering fluvial sequence.
Note that if only the interval 1987–1988m is
considered then it might be interpreted as a braided
system.
Figure 6.29. Idealised meandering fluvial facies
and grainsize profile (right) and corresponding
gamma ray profile (left). (After Kassan & Lang, 1999).
68

Figure 6.30. Photograph of Rednook-1 core.
Depicts a coarsening upwards section, interpreted
as a lacustrine deltaic sequence.
Figure 6.31. Example of the facies profile for a fluvially
dominated lacustrine delta. Profile has a similar
thickness scale to that found in the northern area of the
Wunger Ridge. Note the vertically disconnected sand
bodies. (After Bohac, 2002).
Very high energy systems with heterogeneous lithologies and high shale content may also have a
fairly high GR count and therefore apparently upward decreasing GR readings may be
misinterpreted. For instance rip up clasts in the lower part of the channel where the energy of the
fluvial channel is at a maximum will increase the GR reading in the thalweg leading to an erroneous
interpretation of environment (e.g. false coarsening upward section 2370–2385 m in Waggamba-1;
Figure 6.15). For this reason care needs to be taken in areas where there is a transition in
environment of deposition or where there is an absence of core. In such areas it is important to
spend significant time examining well cuttings descriptions and associated data to determine
palaeoenvironment.
Note that the GR log alone cannot be used to determine lithology particularly within
intercontinental basins where coals are developed, because like sandstones they are represented by
a low GR response. In such cases the sonic log is used to differentiate coal (coals show slower sonic
values) from sandstone lithologies. Shale and sandstone are determined from locally derived gamma
ray cut-offs based on the analysis of core, porosity and permeability data. For instance the sandstone
must have interconnected pores to be considered as a potential reservoir for the injection and
storage of CO 2 .
This study sets the sandstone reservoir GR maximum at around 50–60API units based on direct
measurements of rock properties from core plugs (porosity and permeability data), and or
neutron- density values, which provides an estimate of porosity (Figure 6.26). Even though the GR
count will vary depending on the purpose of the analysis, for this study, the term sandstone is used
for a unit with the above GR response.
6.3.9. Petrophysics
Data from approximately 20 wells was collated and forwarded to a consulting petrophysicist to
conduct basic petrophysical analysis to aid in the development of building representative geological
models. The quality and quantity of the data used for this analysis varied, but included:
GR, resistivity, calliper, density, sonic, neutron, and formation micro-scanner logs, as well as fluid
and rock properties. Results from this work included calculations of effective porosity, net reservoir
thickness, shale volume, total porosity, water saturation, permeability, and volume of clay bound
water. Petrophysical analyses for the wells are included in Appendix 10.6.4.
69

Table 6.3. Porosity and net reservoir thickness of the Showgrounds Sandstone.
Well
Depth of top
reservoir
mKb
Net Showgrounds
Sandstone Reservoir (m)
0.5 Vcl > res > 0.08por
Bellbird-1 2263 13.9 0.1
Bungarie-1 2314 17.9 0.091
Glen Fosslyn-1 2078.7 5 0.181
Inglestone-1 2748.1 4.8 0.088
Kinkabilla Creek-1 2697 43.1 0.139
Namarah-3 2157.4 4.6 0.113
Namarah-5 2153.5 4.05 0.148
Namarah-6 2176.5 4.8 0.104
Nardoo-1 1946.5 6.6 0.118
Renlim-1 1888.6 8.1 0.14
Sirrah-5 1940 10.9 0.151
Taylor-3 2008.2 1.6 0.118
Taylor-5 2000 10.8 0.151
Taylor-7 1985.5 5.4 0.134
Taylor-9 2013.5 2.6 0.15
Taylor-11 2023.7 1.65 0.098
Tinker-2 2100.4 0 0
Tinker-3 2080.7 0 0
Weribone-East-1 2145.4 4.2 0.097
Effective porosity
(dec)
6.3.10. Showgrounds- Snake Creek Mudstone Stratigraphy
The Showgrounds Sandstone generally unconformably overlies metamorphic and igneous rocks or
the Triassic Rewan Formation. The Showgrounds Sandstone is differentiated from the underlying
Rewan Formation on the basis of:
• a change in sedimentary provenance, which is reflected as a colour change from the
dominantly green Rewan Formation to the grey Showgrounds Sandstone;
• clasts of green Rewan Formation sourced rock above the unconformable surface inferring
that there is a time gap between the deposition of the Rewan Formation and the
unconformity;
• an increase in the amount of energy which is reflected as an increased grain size in the
lower Showgrounds Sandstone, and
• the presence of an unconformity at the base of the Showgrounds Sandstone which is
generally seen in core as an erosional surface.
Using a sequence stratigraphic approach, the Showgrounds Sandstone and Snake Creek Mudstone
are interpreted to belong to one depositional cycle (Figure 6.32). Using this method to interpret the
main Showgrounds Sandstone fluvial unit, a braided and meandering fluvial and deltaic system can
develop coevally or as lateral equivalents across an area.
The sequence begins with a relative reduction in accommodation space (regression) which forms or
enhances an eroded surface in the west. This event is recorded by an unconformity on top of which
a lag deposit of coarse grained material is deposited. East of the Wunger Ridge, the late lowstand
systems tract event is recorded by a texturally immature deposit of conglomerate, probably
deposited in a palaeo-valley. On the Wunger Ridge, the absence of accommodation space has
precluded the deposition and/or preservation of the lowstand deposits.
70

Figure 6.32. Relative palaeo-water level curve. Depicts which systems tracts were developed for the
Showgrounds Sandstone, Snake Creek Mudstone and the Moolayember Formation.
This lowstand facies is interpreted to have limited potential for the purpose of CO 2 injection and
storage due to:
• absence of permeability in the conglomerate, due generally to poor sorting and high clay
content, and
• high degree of vertical heterogeneity of the lithology, interpreted to indicate a dual sediment
source provenance and depositional factors (e.g. variations in energy and space).
Following the lowstand systems tract, an increase in relative accommodation (transgression)
occurred. As the transgression progressed, initially, mostly fluvial facies were deposited, probably
during the late lowstand to earliest transgressive systems tract (Figure 6.32). During this period, the
fluvial system is interpreted to have reached its maximum lateral extent. Towards the east of the
Wunger Ridge a minor transgressive event appears to have occurred during this late lowstand to
earliest transgressive system, which is recorded in some wells as very finely laminated lacustrine
shale which looks similar to the Snake Creek Mudstone (Figure 6.33).
The lowstand systems tract is overlain by a late lowstand to very early transgressive fluvial to
deltaic system. It is this system which this study interprets to contain Butchers (1984) units 1 and
2 and has the highest reservoir quality, thickness and extent.
Subsequent to the fluvial system, the late–mid transgressive deltaic facies were deposited and are
interpreted to be the upper Showgrounds Sandstone. Finally this is overlain by the mid-transgressive
lacustrine shale generally known as the Snake Creek Mudstone which represents the maximum
71

flooding surface and completes the cycle (Figure 6.32). The mid transgressive systems tract is
where the maximum rate of accommodation space has occurred, with the rate of relative water level
rise reaching a maximum, as the Snake Creek Mudstone lacustrine system inundated the landscape,
completely covering the previously deposited Showgrounds Sandstone. The Snake Creek Mudstone
is a very homogeneous, finely laminated (sometimes appears massive) dark grey to black shale and
is considered to be the primary sealing lithology (Figure 6.34).
Figure 6.33. Photograph of Glen Fosslyn-1 core.
Shows intra-Showgrounds Sandstone shale that
sits within the fluvial Showgrounds Sandstone that
has been interpreted as a minor transgressive
event. The shale can be seen on the gamma ray log
at this well and at a number of other locations as
well
Figure 6.34. Photograph of Yellowbank Creek
North-1 core. Shows the rapid transgression of the
Showgrounds Sandstone by the Snake Creek
Mudstone in the Wunger Ridge area (Taken from
Reeve, et al., 1988).
Core taken from the Wunger Ridge area shows no evidence of a retrograding shoreline (shoreface
and barrier complexes) associated with the transgressive surface. It has been interpreted that this
apparently rapid transgression indicates a very flat transgressive surface rather than a significant
reduction of fluvial input.
Subsequent to the deposition of the mid transgressive Snake Creek Mudstone, the Moolayember
Formation represents the late transgressive to early highstand systems tract. In the study area, the
Moolayember Formation is an upward coarsening and shallowing sequence of stacked deltas
building out into the Snake Creek Lake. For this study the lower part of the Moolayember
Formation is considered to be a secondary sealing lithology.
6.3.11. Reservoir Prediction and distribution: Vertical and lateral Facies Extent and
Connectivity.
Sedimentary facies are influenced by the relief gradient, type of sediment, distance from the
sediments source area, the rate of accommodation space formation and the proximity to a standing
body of water. Along the Wunger Ridge it is apparent from core and electrical log analysis that the
preservation of vertically connected (multi-story) sandstone bodies is controlled by the ratio
between sediment supply versus amount of accommodation space at the location.
Analysis of multi-channel fill thickness by environment of deposition data indicates that the greatest
sandstone accumulations are associated with the fluvial braided and meandering systems (Figure
6.35). The lower end of the meandering system is associated with vertically unconnected low
energy flood-plain channel systems. Generally the preserved thickness of the braided system is
72

associated with the increase in total net accommodation associated with the transgression event and
palaeo-valley thickness (Figure 6.35).
A reduced vertical thickness of sandstone bodies associated with deltaic mouth bars and deltaic
distributary channels (Figure 6.35) are interpreted to be due to a number of factors including:
• the increasing amount of relative accommodation space, leading to an increase in the
preservation of shale and therefore, an increase in vertical heterogeneity;
• a significant reduction in energy of the system, as it becomes less confined and approaches
a standing water body, leading to a relative increase in shale content, and
• the distributary processes themselves through local changes in gradient redistribute
sediment into new areas once a gradient threshold is exceeded which produces increasingly
vertically disconnected sand bodies at increasing distances away from the head of the delta.
The delta systems (lateral equivalents to the braided Showgrounds Sandstone) are interpreted here,
as being deposited in a lake as opposed to open marine conditions reported by Butcher 1984.
100.00
Wunger Area Environment vs. multi channnel thickness
10.00
thickness (m)
1.00
0.10
0.01
0 1 2 3 4 5 6 7 8
sa m ple
deltaic distributary Deltaic mouthbar Fluvial Braided
Fuvial Braided very coarse-conglmrt Fluvial braided sandy Fluvial meandering
Fluvial splay
Figure 6.35. Multi-channel thickness vs. sedimentary environment cross-plot. Depicts the range in accumulated
deposits for different facies in the Wunger Ridge area.
73

Figure 6.36. Width-to-thickness ratio chart used to predict the likely lateral extent of fluvial sand bodies. Uses
vertical well intersections extracted from various data, and based on the observation of fluvial channel belt
morphologies (Strong, et al., 2002).
In the Wunger Ridge area, the fluvial braided systems vertical thickness is controlled by
accommodation where the lower values are associated with areas close to palaeo-highs along the
Wunger Ridge and fluvial lags in the feeder valleys. The braided system is a high energy system
which is continually eroding into itself such that even though accommodation space is being
developed any shale which is deposited as the channel is abandoned, is removed when the channel
system reinhabits the local area. This produces a deposit of vertically and horizontally well
connected sandstones.
Channel width-to-thickness ratio prediction charts (Figure 6.36) derived from analogue data can be
used to estimate the potential range in the width of channel systems from observations of channel
thickness observed from core and interpretation of electro facies (Strong, et al., 2002). Based on a
fluvial multi-channel stack thickness of 8–9 m the active channel belt width is likely to be in the
range of 1-4 km (Figures 6.35 & 6.36). The predicted spread of the channel belt width from wells
which have a vertical thickness of connected sandstone of between 4–8 m gives a range of 1–3 km
indicating that there are multiple, but essentially parallel active channels in the area (Figures 6.35 &
6.36).
74

The interpretation of multiple channel belts suggests that lateral connectivity of sand facies would
be high within the 1–4 km range across the channel belt, but beyond that distance, a semi regional
inter-channel flood plain may act as a large semi regional scale baffle (Figure 6.36). Using this data
reservoir quality and connectivity of the Showgrounds Sandstone has been predicted across the
Wunger Ridge flank by interpreting palaeoenvironments from wells and creating palaeogeography
maps of the flank.
6.3.12. Showgrounds Sandstone Reservoir Prediction and Distribution
Palaeogeographic maps represent an instantaneous snap shot in time of a theoretical landscape
which attempts to represent a vertical aggregate of environments over some period of geological
time (Figures 6.37–6.38). In this case the four maps represent four critical phases in the depositional
history of the Showgrounds Sandstone (LST, Early TST, Mid TST,HST). Such maps should be
viewed more as probability maps where the authors interpret that particular palaeoenvironments on
the map have a higher probability of existing in that place over other palaeoenvironments.
Data and interpretations obtained from cores were extrapolated to wells which did not have core via
the interpretation of electrical logs obtained from the wells. In this way, a more complete dataset
was used to interpret the palaeoenvironment. In turn, this dataset was combined with width-tothickness
ratios, dipmeter data, pressure data and seismic data to produce the palaeogeographic
maps (Figures 6.39–6.42). The interpreted southwest to northeast reduction in energy of the fluvial
system has been incorporated into the palaeogeographic map, and represented by a change in the
fluvial style.
In the southwest part of the study area there is a dominantly braided fluvial system that would be
laterally well connected. Here the grain size of the fluvial system is at a maximum, the log motif is
blocky, the shale content within the sandstone is at its lowest and the section has the lowest
preserved shale. The absence of shale content hinders the formation of stable banks and leads to a
braided fluvial system dominating the area (Boggs, 1995; Figure 6.38).
In the northeast part of the study area, the fluvial environment experiences a reduction in (energy)
slope as the fluvial system begins to react to the presence of a standing body of water to the east
(Miall, 1990). The evidence comes from a reduction in grain size, a change from a blocky GR motif
to an upward fining motif and an increase in the preservation of shale over the interval. A product of
the process is a change in fluvial style to a meandering system. The transition from braided system
which typically has multiple active unrestricted channels to a meandering fluvial system that has far
fewer active channels, leads to a deepening of the remaining dominant channels (Boggs, 1995;
Figure 6.37). An increase in shale content enables the formation of stabilised banks and helps to
deepen the fluvial system which produces a deeper water column with a vertical and lateral
segregation of flow (energy), which forms eddies on encountering obstacles, and helical flow as the
flow changes direction (Boggs, 1995). It is helical flow which form point bars typical of the
meandering system (Boggs, 1995).
75

Point-bar complex within a meandering fluvial channel system
Figure 6.37.Generic diagram of point-bar complex from the Mississippi River. Shows the relationships
between the deposits of actively migrating channels and the dominantly muddy infills of closed
abandoned channels. Vertical exaggeration unknown but significant (After Jordan & Pryor, 1992).
Longitudinal bar
Transverse
bar
06-028-5
Figure 6.38. Block diagram of a fluvial braided channel. Depicts sandstone with high vertical and lateral
connectivity (From Boggs, 1995, modified from Galloway & Hobday, 1983).
76

Beyond the meandering system, a deltaic system is interpreted with four main elements: a fairly
straight distributary channel system, mouth bars, intra distributary flood plain and bays. Generally
speaking, there is an increase in grain size as the rate of fluvial discharge increases as an individual
delta lobe develops and progrades into the water body (Reading, 1996). Over all, the deltas backstep
as they get younger (higher) which is evidenced as a decrease in grain size and vertical height
(Reading, 1996).
The original environment of deposition appears to have a strong influence on the porosity and more
importantly permeability of the Showgrounds Sandstone in the Wunger Ridge area. Based on the
interpretation of the environment, and other data, the palaeogeographic maps indicate that areas
between Mireeka-1 and Waggamba-1 have relatively lower reservoir and seal risk (Figures 4.2 and
6.39–6.42).
In the meandering system the sandstone facies has a range in permeability of up to 1000 mD. For
instance, in the well Glen Fosslyn-1 core data indicates that the point bar sandstone facies has a
permeability between 100–1000 mD. The gross heterogeneity of the fluvial meandering system
caused by the preservation of clay within the abandonment channels, would suggest that a greater
number of baffles would preferentially help trap CO 2 in the fluvial meandering system than the
braided system (Figure 6.38). The risk of drilling an injection well into a shale plug or an
unconnected point bar that would reduce the ultimate injection rate can be reduced by drilling a
horizontal well along strike.
6.4. Containment Potential: Implications for CO 2 Storage
6.4.1. Seal Distribution and Continuity
The presence of a well defined Snake Creek Mudstone intersected in wells located along the
western flank of the Taroom Trough, indicates that a wide-spread fairly uniform shale deposit
exists. The Snake Creek Mudstone unit pinches out along the western flank and passes laterally into
a siltier unit along the eastern edge of the Taroom Trough. At the scale of this project the unit
effectively covers the entire area of interest. Thickness of this seal in the outer wells Overston-1,
Kinkabilla Creek-1, Kinkabilla-1 and Ingleston-1 suggests that it does not vary significantly from
that on the Wunger Ridge itself. The thinness of the Snake Creek Mudstone (< 40 m) does not
permit an adequate representation of the member based on seismic data.
77

Figure 6.39. Interpretation of palaeogeography/environment of deposition of the Showgrounds Sandstone
lowstand systems tract.
78

c)
148°00'
148*20'
148°40'
27°20'
?
?
Model area
27°40'
Approx. direction
of sediment flow
Metamorphic basement
Over-bank and channel flood plain
05-267-5
0 20 km
Approximate granitic basement
Deltaic
Braided and major channel belt
Marginal lacustrine to lacustrine
Braided channel bar, meandering river and crevasse splay
Small scale transgression
Figure 6.40. Interpretation of palaeogeography/environment of deposition of the
Showgrounds Sandstone early transgressive systems tract.
d)
148°00'
148*20'
148°40'
27°20'
Model area
27°40'
Approx. direction
of sediment flow
Metamorphic basement Over-bank and channel flood plain
0 20 km
05-267-6
Approximate Granitic basement
Deltaic
Braided and major channel belt
Lacustrine
Braided channel bar, meandering river and crevasse splay
Figure 6.41. Interpretation of palaeogeography/environment of deposition of the
Showgrounds Sandstone mid transgressive systems tract.
79

Figure 6.42. Interpretation of palaeogeography/environment of deposition of the Snake Creek Mudstone highstand
systems tract. Fading to towards the east represents increased uncertainty of seal quality due to increased influence
of sediment shedding off the volcanic arc.
The seismic-based isopach map of the secondary seal ‘Moolayember Formation’ suggests that the
thickness of the Moolayember Formation ranges from 50–250 m over the Wunger Ridge to 600-
900 m towards the Taroom Trough. This variation is due to:
• the erosional truncation of the upper Moolayember Formation from west-to-east. This would
suggest that the Moolayember Formation was significantly thicker across the Wunger Ridge
and flank prior to Basin inversion in the early Jurassic (i.e. equivalent base Surat Basin time),
and
• continued subsidence within the Taroom Trough depocentre towards the eastern margin.
6.4.2. Seal Capacity
MICP (Mercury Injection Capillary Porosimeter) analyses of samples of the Snake Creek Mudstone
Wunger Ridge, Bowen Basin from Harbour-1 and Hollow Tree-1 were performed by the Australian
School of Petroleum.
Table 6.4. Sample numbers and location of where seal samples were taken from.
Year Depth Taken
Sample Well Name Well Meters Feet Formation Sample
No.
Drilled
From
H1977 Harbour-1 1987 1976.7 6485 Snake Ck mst half core
HT1804b Hollow Tree-1 1987 1804.2 5919 Tuff half core
HT1803 Hollow Tree-1 1987 1803 5915 Tuff half core
H1987 Hollow Tree-1 1987 1802.5 5914 Snake Ck mst half core
MICP data are used to determine threshold or break through pressure used in the interpretation of
the carbon dioxide retention height of sealing rocks. The supercritical carbon dioxide retention
heights for the Snake Creek Mudstone ranges from 490 to 910 m with the retention height of the
interbedded tuffaceous rocks ranging from 4 to 1300 m.
80

The ductility and compressibility of the mudstone constitutes a good sealing lithology, whereas the
tuffaceous rocks are more susceptible to fracturing as a result of bed thinness and brittleness. The
samples were taken from old dry core that could reduce the interpreted results in MICP analysis. As
such seal retention heights may exceed those measured.
These results suggest that the Snake Creek Mudstone, the overlying sealing unit to the
Showgrounds Sandstone, is capable of withholding a substantial column of CO 2 at least equal to the
interpreted structural height of the Wunger Ridge flank (~800 m). The Moolayember Formation has
to date not been tested for seal capacity.
The tuffaceous sandstone unit is not critical to sealing CO 2 within the Showgrounds Sandstone. It is
a lateral, more tuffaceous extension of the Showgrounds Sandstone (see Petrography, Appendix
10.6.2). The variable sealing nature of the tuffaceous lithology unit within the Showgrounds
Sandstone should not contribute to the leakage risk for migrating CO 2 . Instead the tuffaceous part of
the Showgrounds Sandstone should provide a significant baffle, restricting the flow of CO 2 towards
the pinchout edge, thus dispersing potential sudden pressure changes on the Snake Creek Mudstone.
For the full details of the MICP analysis including methodology and full results see Appendix
10.6.5.
6.5. Geomechanical Modelling
No geomechanical modelling was performed as resources were not available.
6.6. Hydrodynamic Modelling
6.6.1. Introduction
The interpretation of hydrodynamic data for this study is based on publicly available data. Current
well pressure and production volume data remains confidential to the field operator and has not
been used in this work, precluding detailed history matching to quality control the data analysis and
subsequent interpretation.
Data from 69 wells was entered into a database to characterise the hydrodynamic conditions,
production effects, and vertical and lateral communication across the entire Wunger Ridge area.
The formation pressure data for this study came from two sources. The first being formation
pressures from drill stem tests (DST’s) and wireline formation tests (WFT) measured in the well
bore at the time of drilling. All formation pressures were passed through a comprehensive quality
control system before use.
The Triassic Showgrounds Formation is at the base of the aquifers of the Great Artesian Basin
(GAB), (Habermehl, 2002), however, due to its depth and the presence of more easily accessible
freshwater above, it is not an active water resource. It is separated from the nearest active aquifer,
the Jurassic Precipice Sandstone, which is both an important and active water resource, by the
Triassic Moolayember Group, one of the major confining units of the GAB sequence (Habermehl,
2002). The hydrodynamic flow system of the Jurassic aquifers of the GAB are reasonably well
understood, however there have has been little examination of the hydrodynamics of the Triassic
reservoirs to date.
The Snake Creek Mudstone sealing unit lies at the base of the Moolayember Group. The lithology,
thickness and the lack of hydrocarbon shows in the Moolayember Group within the study area
makes it a secondary seal for storage within the Showgrounds Sandstone and a barrier to vertical
migration within the study area. The interpretation of hydrodynamic data suggests that within the
greater Wunger Ridge area, the Showgrounds Sandstone is not in hydraulic communication with
overlying fresh water aquifers, in particular the Precipice Sandstone.
A detailed report describing the hydrodynamics is attached in Appendix 10.6.3.
81

6.6.2. Pre-production Flow System
Recharge flow from the Great Dividing Range in the north east is directed south towards the
Wunger Ridge (Figure 6.43). Along the ridge itself, flow remains broadly southwards and the
hydraulic gradient is quite flat, suggesting a low flow rate. What is not visible on the contours,
due to the data sparsity is the influence of the basement highs that project through the Showgrounds
Formation, as at between the Renlim and Silver Springs fields (Tucker, 1989). Along the western
flank of the ridge, flow is parallel to the zero edge of the Showgrounds Formation.
Flow from across the south-western Bowen Basin area is directed into a hydraulic low trending
southwest across the study area (Figure 6.43). The lowest value is defined by Teelba Creek-1
(140 m), but the discharge point of this feature is uncertain. The possibility exists that it extends to
the east across the thickest and most permeable part of the basin to the Moonie Fault where it may
move vertically up into the Precipice Sandstone. Wells in the area were examined to test this
hypothesis, however no suitable data was available.
There were several regional pieces of evidence which suggested the more likely direction of
discharge was to the south as shown. The hydrodynamic setting of the Bowen and Surat basins
shows regional discharge is directed toward the south-west and secondly, the low lies within an area
of high permeability described by Tucker (1989).Thirdly, the presence of a second large basement
high, the Yarrandine high (Rigby, 1987) located to the east of the hydraulic low provides the
possibility of a high transmissivity feature and finally, the presence of a regionally relatively low
hydraulic head value at Grail North-1 (315 m). The western side of the hydraulic low is similarly
confined by high hydraulic head values along the continuing zero edge of the Showgrounds
Formation.
The flow in the pre-production flow system (dark green flow arrow Figure 6.43) is directed almost
at right angles to the predicted migration pathway direction of injected CO 2 (red arrow Figure 6.43).
The flow rate within this system is also low at 0.2 m/yr measured across the predicted migration
pathway. This is based on an assumption of 150 mD across the area. Increasing the permeability to
1000 mD would increase the flow rate locally to approximately 1.3 m/yr. Given the relatively low
structural gradient it is likely that the direction of movement of CO 2 will continue to be controlled
by buoyancy and facies distribution. Theoretically the original flow system would act to deflect the
migration toward the south as the pressure system is restored as injection of CO 2 continued. To
qualify this requires driving force vector analysis (DFVR) to be undertaken which will form the
basis for the next stage of this study.
6.6.3. Post-production Flow System
Although there is little data available post 1993 to predict the current flow system and determine the
radial extent of the production induced drawdown there is some data available for the period
between 1986 and 1991 at both the centre of production along the axis of the ridge and further out
into the basin (Figure 6.44).
The ridge data is confined to the southern end of the Wunger Ridge, there being no data available
for recent wells drilled at the northern end. This is also the site of maximum production and where
the pressure decline is interpreted to be the greatest (~550 psi up to 1991) (Figure 6.44). Recent data
is also confined to wells drilled on the western side of the hydraulic low described previously, as the
only wells available are located on the eastern side around the Waggamba field pre-date production.
The data indicates that production induced pressure decline has extended for a considerable distance
away from the producing fields and out into the deeper parts of the basin. This is interpreted to have
significantly modified the hydraulic gradient across the area (Figure 6.44).
82

148:30
149:00
149:30
N
Depth toTop Permian
400
NAMARAH 1
426, G, III (rewa)
1981
NTH BOUNDARY 1
337, GW, IV
1994
LARK 1
336, GC, IV (rewa)
1993
TINKER 3
369, CM, I,(rewa)_
1989
GLEN FOSSLYN 1
-27:30 400
351, GC, IV
359,G, III
-27:30
DONGA 1
323, ?, (C)
268, ?, (B)
1965
(MOOL)
ELGIN 1
334, ?, (B)
1965
(MOOL)
360
340
SILVER SPRINGS 8
271, MW, IV
1981
SILVER SPRINGS 1
BOXLEIGH 3 346, G, II
RENLIM 2
315, G, II 1979
216, GC, IV
1979
1983
BEECHWOOD 2
1988
77, OM, III, (rewa)
1980
380 380
320
360
340
340
380
360
320
400
Zero Edge of Snake Creek Mudstone
5 10 20 kms
-28:00 -28:00
148:30
149:00
149:30
320
400
340
360
380
380
360
340
320
300
300
Figure 6.43.Pre-production flow system of the Showgrounds Sandstone.
83

148:30
149:00
149:30
N
Depth toTop Permian
?
NAMARAH 1
426, G, III (rewa)
1981
NTH BOUNDARY 1
337, GW, IV
1994
LARK 1
336, GC, IV (rewa)
1993
TINKER 3
369, CM, I,(rewa)_
1989
?
GLEN FOSSLYN 1
-27:30 351, GC, IV
359,G, III
-27:30
DONGA 1
323, ?, (C)
268, ?, (B)
1965
(MOOL)
ELGIN 1
334, ?, (B)
1965
(MOOL)
SILVER SPRINGS
8, 1989
(Tucker)
SILVER SPRINGS 8
271, MW, IV
1981
SILVER SPRINGS 1
BOXLEIGH 3 346, G, II
1979
RENLIM 2
315, G, II
216, GC, IV
1979
1983
-50
0
BOXLEIGH
-72, 1989
50
(Tucker)
BEECHWOOD 2
1988
77, OM, III, (rewa)
1980
100
150
250
200
Zero Edge of Snake Creek Mudstone
5 10 20 kms
-28:00 -28:00
148:30
149:00
149:30
Figure 6.44. Modified flow system for ~1990.
84

The only recent well with reasonable data is located at the southern end of the ridge at North
Sirrah-1. This well was spudded in 1991 and has a hydraulic head value of -69 m. Taylor-14 had a
relatively high hydraulic head value of 276 m in 1989. The Taylor-14 well was drilled off structure
and is interpreted to have intersected an hydraulically isolated low permeability zone. On the
western side of the ridge, slight drawdown effects have been noted at Glenearn North-1 and at
Lynrock-2.
The most recent of the wells on the eastern flank is Louise-1, drilled in 1985. This well is
interpreted to have a hydraulic head of 263 m which implies a drop of approximately 120 m over six
years of Wunger Ridge hydrocarbon production. Examination of Figure 6.44 shows that the group
of wells around Louise-1 seem to show differential drawdown rates. As these wells are quite close
together both spatially and chronologically, the reason for the spread in data may be reflective of
permeability variations. Tucker (1989) describes a “sweet spot” area of high permeability, which
includes Captain Cook-1 and Kippers-1, but excludes Louise-1 and Narrows-1. The data suggests
that the influence of pressure reduction due to approximately 12 years production had extended at
least 16.5 km into the basin to Captain Cook-1 and Louise-1 by the late 1980’s, with significant
reduction in hydraulic head values. The overall effect will be to redirect flow up to the ridge from
the deeper parts of the basin towards the low at Silver Springs/Renlim.
The recalculated flow rate towards this point is 0.9 m/year (based on 150 mD) and this may affect
both the speed and direction of movement of injected CO 2 as flow would be redirected along the
predicted CO 2 path. Although there is no data currently available, production from the northern end
of the ridge has been underway since 1993 and it is likely that there has been some pressure
reduction from here also, which may produce a competing effect drawing the CO 2 to the north,
away from the predicted path.
Since 1990 there has been continued production from fields in both the northern and southern ends
of the Wunger Ridge and it is likely that in reality the current flow system may be more extreme
than that shown on the map and the induced hydraulic gradient maybe even steeper.
6.6.4. Hydraulic Communication
Significant drawdown of pressure detected in wells drilled approximately 16.5 km away from the
southern production within 12 years of initial production indicates regional scale connectivity and
transmissivity. Although the hydrodynamic model assumed a uniform regional connectivity, the
facies model indicates that this is unlikely to be the case. It is more likely that the pressure effects
are focused along zones of high permeability.
A northward trend of increasing reservoir heterogeneity can be interpreted geologically.
A northward trend of increasing hydraulic pressure disconnectedness within the Showgrounds
Sandstone can be interpreted from some of the DST results which show evidence of depleting
reservoirs over the time scale of the test or localised isolation from the greater aquifer system such
as at Taylor-14. Production from this area indicates volumes in the order of 100–450 million cubic
metres gaseous hydrocarbons are able to be accessed although some fields have produced less than
40 million cubic metres implying a lack of reservoir continuity within the area mapped above the
interpreted gas-water contact. This implies that in some areas local connectivity with the greater
aquifer may be limited particularly towards the northern part of the Wunger Ridge (Figures 6.45 and
6.46).
85

500
Waggamba/Yellowbank Ck
Boxleigh/Thomby Ck
Renlim/Silver Springs
Sirrah/Fairymount/McWhirter
Louise/Narrows (Re)
Taylor
Beechwood/East Glen/Nth Boxleigh/Roswin
Namarah (Re)/Parknook (Re)/TInker (Re)
Glen Fosslyn/Lark/Warroon
Link/Major
400
300
Hydraulic Head (m)
200
100
0
-100
MOOL REWA SHOW PREP EVER PERMIAN
-200
1960
1962
1965
1968
1971
1973
1976
1979
1982
1984
1987
1990
1993
1995
1998
Spud Date
Figure 6.45. Head vs spud data for wells sub-divided into formation.
500
Waggamba/Yellowbank Ck
Boxleigh/Thomby Ck
Renlim/Silver Springs
Sirrah/Fairymount/McWhirter
Louise/Narrows (Re)
Taylor
Beechwood/East Glen/Nth Boxleigh/Roswin
Namarah (Re)/Parknook (Re)/TInker (Re)
Glen Fosslyn/Lark/Warroon
Link/Major
400
300
Hydraulic Head (m)
200
100
0
-100
Area 1 (south) Area 2 (north) Area 3 (flank)
-200
1960
1962
1965
1968
1971
1973
1976
1979
1982
1984
1987
1990
1993
1995
1998
Spud Date
Figure 6.46. Head vs spud data for wells.
Sub-divided into: i) along the Wunger Ridge, south of the zero edge of the Rewan Formation, ii) along the Wunger Ridge,
north of the zero edge of the Rewan Formation, and iii) off the ridge and into the basin.
86

Rewan Formation- Showgrounds Sandstone
At the northern end of the Wunger Ridge, production is from either or both the Showgrounds
Formation or the underlying Rewan Formation. There is some suggestion of communication
between the units, although this is difficult to confirm as all of the wells except one are considered
production affected. At Link-1, DSTs were taken in both the Showgrounds and the Rewan
Formation, both having the same hydraulic head value suggesting that the Showgrounds is in
hydraulic communication with the Rewan Formation at this location. This well was drilled soon
after production began from the Rewan Formation at the nearby Tinker Field. The Rewan
Formation data points indicate reduced pressure, potentially due to production from the fields to
the south, which are beyond the zero edge of the Rewan Formation.
Showgrounds Sandstone- Precipice Formation
The western edge of the hydraulic low coincides with the location of the zero edge of both the
Snake Creek Mudstone and the Showgrounds Sandstone, near the Major field (located some distant
west of the Wunger Ridge) and forms the only point of potential communication between the
Showgrounds Sandstone and the Precipice Sandstone. The Major field is located 25 km to the west
of the first line of structures (comprising the Wunger Ridge) that a migrating CO 2 front would
encounter. Comparison of the two maps indicates that the hydraulic head values in the Precipice
Sandstone are very similar to those in the Showgrounds Sandstone. In addition, there are two
hydraulic head values from Elgin-1 (334 m) and Donga-1 (323 m) measured in sands within the
Moolayember Group. Both of these values were taken from Scorer, 1966, and the raw data was not
available for examination, however, both are very similar, within gauge error, to the hydraulic head
values seen at the edge of the Showgrounds Sandstone, and very similar to those contours
interpreted by Scorer (1966) for the overlying Precipice Formation. The similarity of these points
suggests that there may be a small component of flow between these units, however the vertical
direction is not clear and the hydraulic low is channelling the bulk of the water away from this edge
and out to the south of the study area. Examination of the composite logs for Major-1, 2, 3, and 4
indicate that hydrocarbons have managed to penetrate the lower sand prone units of the
Moolayember Formation. Drill stem tests conducted over the hydrocarbon shows indicate a lack of
hydrocarbon volume and poor permeability. However no hydrocarbons have been detected in sand
prone units in the upper Moolayember Formation
6.6.5. Water Salinity
The salinity data for the Showground Sandstone indicate that the salinity is approximately 6000–
9200 ppm NaCl. This level of water salinity is suitable for stock suggesting that saline aquifers of
the greater Wunger Ridge area could be considered as a resource. As there is superior quality water
within the Great Artesian Basin above the Moolayember Formation, storing CO 2 in the Showground
Sandstone reservoir is unlikely to conflict with future water extraction activities in the area.
The water in the overlying Precipice Formation is predominantly fresh, although there are some
local variations (Hitchon, 1971). Hitchon (1971) shows a salinity distribution map for the Precipice
Sandstone, showing that salinities range from higher than 3,000 ppm in the west, near the discharge
region, to less than 1000 ppm in the northeast towards the recharge region.
6.6.6. Analysis of Results
The original predominant flow direction on the eastern side of the flank is southwest at a rate of
approximately 0.2 m/yr using an 150 mD or 1.3 m/yr using 1000mD average permeability. This is
almost at right angles to the predicted migration pathway of injected CO 2 and means the potential
for hydrodynamic trapping is limited and flow will be dominated by buoyancy effects. It may have
an effect of deflecting the CO 2 south, but the degree is unknown at this time.
The Wunger Ridge has been a producing area for nearly 30 years and some fields have undergone
significant pressure depletion. The radial extent of this depletion is unclear, but it is appears to
extend down the flank and out into the deeper parts of the basin. A current day (1998) production
87

affected flow rate has been calculated at 0.9 m/yr (assuming a permeability of150 mD) to 5.9 m/yr
(assuming a permeability of 1000 mD). This switches the flow direction away from the discharge
direction and up onto the ridge. The formation water is interpreted to be broadly moving in the same
direction as the predicted migration pathway and hence migration of CO 2 along this path may be
faster than initially predicted.
Once the flow system has re-equilibrated after production ceases, injected CO 2 will migrate
generally updip under buoyancy drive. However, the presence of a flow path across the migration
pathway may allow some component of the CO 2 displaced water to migrate in this direction and act
as a pressure dissipation mechanism.
6.6.7. Further Work
The next stage in understanding the impact of the formation water flow system in the Showgrounds
Formation on injected CO 2 is to understand the current day flow system. This will provide
information about the potential for a deflection of the predicted CO 2 migration path and the relative
timing required for the aquifer to return to its original state. This requires more detailed production
data from petroleum companies operating in the area. Unfortunately it is unlikely this information
would be made available prior to the fields exhaustion. When the data in terms of static gradient
tests, wellhead pressures, etc becomes available this must be coupled with a mass balance
calculation.
6.7. Reservoir Model and Simulation
6.7.1. Introduction
Coarse-scale geological models based on a smoothed structure map and approximate reservoir
parameters were used as inputs to the reservoir simulations (Figure 6.40). The coarse scale allowed
changes to reservoir saturations and pressures and CO 2 migration rates to be related to specific
parameter changes. The coarse scale geological model approach allowed: 1) the range of results
from reservoir simulation runs to constrain an outer bound of possibilities for CO 2 migration rates,
and 2) initial results to be viewed so as to better scope reservoir simulation for the finer scale
geological models. The detailed reservoir engineering report can be found in Appendix 10.6.7.
6.7.2. Model Description
A coarse scale 3D reservoir model was constructed for simulation study (Figures 6.47b to d).
The total number of grid blocks was 9600 (Nx = 64, Ny = 25, Nz = 6), with cell sizes in the x, y
and z direction being 460, 400 and 1.167 m, respectively. The coarse scale 3D model has a one
degree structural gradient, estimated from the average gradient of the seismic-based depth map
(Figure 6.3). The model area is rectangular in shape (10×29.5 km 2 , Figure 6.40) and was divided
into two equal parts: 1) medium-porosity and medium-permeability (i.e. 150 mD) that occurs in the
eastern part of the reservoir and, 2) high-porosity (20%) and high-permeability (i.e. 1000 mD) that
occurs in the western part. The top of the reservoir rises 800 m from east-to-west (Figure 6.47d),
and although the formation thickness varies within the reservoir (i.e. ~ 3–17 m), a constant reservoir
thickness of 7 m is used based on average thickness. A cross-section through the model shows
medium permeability and low vertical connectivity in the eastern part of the reservoir (Figure
6.47c). A simple checker-board pattern was used to model the permeability distribution in an
attempt to include some degree of geological heterogeneity in the reservoir (Figure 6.47b).
Six aquifers that surround the model area are represented in the simulator using an analytical
method (Carter & Tracy, 1960), although it is known that analytical models are weak in modelling
reservoir fluids flowing back to the aquifer (i.e. they account only for water flow at the
aquifer/reservoir boundary with CO 2 remaining in the reservoir). In such cases, the use of aquifers
represented numerically rather than analytically is preferred, which requires a large number of grid
blocks in a reservoir simulation.
88

For a simplified model, as used in this study, it is preferred to use an analytical model to represent
the six surrounding different aquifers rather than adding additional grid blocks, which is almost
impossible for all aquifers because of computational limitations. For the first model run, the initial
condition for the reservoir was assumed to be at hydrostatic pressure with the total aquifer volume
approximated by the six regions surrounding the reservoir (Figure 6.47d), with model permeabilities
shown averaged from well data. Communication of the aquifer within the surroundings of the model
area was also demonstrated in the study of Tucker (1989).
Tables 6.4-6.6 give a summary of the reservoir, rock and fluid properties, and it was assumed that
only saline water is present at the onset of injection. The fluid properties of CO 2 were obtained for
corresponding reservoir pressure and temperature based on the work of Span and Wagner (1996).
The van Genuchten (1980) model proposed by Preuss et al., (2002) for the CO 2 /brine system, which
represents the drainage of brine by CO 2 , was used to determine multiphase flow. Experimental data
on multiphase flow properties (e.g. relative permeability and capillary pressure) for this model are
not available.
A two-phase GASWATER option of the IMEX TM black oil simulator was used to model an
immiscible displacement of reservoir brine with CO 2 . Dissolution effects of CO 2 in brine, as well as
chemical reactions of CO 2 with the solid phase (rock matrix) were not considered in this study.
Simulations of 1000 years were run as the aim was to examine the CO 2 injectivity and to track CO 2
migration after the injection ceased. Wells were centrally located in the grid blocks and not
modelled comprehensively. Thus, the injection rates determined represent those for locations rather
than for a specified wellbore. The number of actual wells required may increase depending on the
wellbore geometry.
6.7.3. Simulation Scenarios
Table 6.7 summarises the different injection cases with different numbers of vertical and horizontal
wells under various conditions. In Case 1, we simply changed the location of a single vertical
injector in the high permeability part of the model area (Figures 6.47c), while keeping all other
parameters constant and examined the maximum injection rates. The results show that none of the
single injectors reach the proposed injection rate of 1.2 Mt/y (rate of CO 2 emissions from a
hypothetical 200-MW coal-fired power station), so that additional wells are required to get the best
combined rate (Q total -Figure 6.47). A vertical injector located away from the low-permeability
aquifers and regions seems to be optimal for good injectivity: it can also be argued that the wells
located at shallower depths have higher injectivity in case 1. Care has to be taken with the aquifer
description to understand the behaviour of those wells located at the numerical reservoir–analytical
aquifer boundary where CO 2 outflow is not modelled because of the problems related to the
inclusion of analytical aquifers in the simulator as explained previously.
Increasing the injection bottom-hole pressure up to 90% of the fracture gradient (Case 2) clearly
improves the injectivity relative to Case 1 (Table 6.7) such that the required rate of 1.2 Mt/y is
achieved. Locating a single injector in the medium-permeability part of the reservoir (Case 3) for
the same conditions, however, results in lowered injectivity to such an extent that assuming no well
interference, in the order of 9–10 wells would be required to achieve the target injection rate.
The injection rate is also reduced considerably when geological heterogeneity is included through
a checker-board patterned permeability distribution (Figure 6.47b) to values that are about half the
proposed injection rate (Case 4, Table 6.7). The injectors located in the middle of the high
permeability model area have more favourable injection rates than for other locations. This proves
that inclusion of geological heterogeneity is significant in the determination of CO 2 injectivity.
89

Figure 6.47.(a) Generic model profile (not to scale) of lithologies, sedimentary environments and trapping
mechanisms of the Showgrounds Sandstone present within the model area. Top lacustrine shale layer represents
the Snake Creek Mudstone regional seal (thickness ~ 15–30 m). (b) Plan view of modelled permeabilities used in
reservoir simulation Cases 4, 6, 8 and 9. (c) Profile view of modelled permeabilities used in reservoir simulation
Cases 1, 2, 3, 5 and 7. (d) Plan view of model area (high and medium permeability) and surrounding aquifers used
in reservoir simulations.
90

Table 6.5. Reservoir properties. Pres – reservoir pressure, Tres – reservoir temperature, Pfrac – fracture pressure,
µw – water viscosity, Bw – water formation volume factor, ρw, sc – water density at standard conditions. Standard
temperature and pressure (STP) is 25°C (77°F) and 1.01325 * 105 Pa atmospheres (14.7 psi).
Reservoir properties
P res at top depth (1.9 km) 19.3 MPa
T res 70 ºC
P frac
39.4 MPa
Water salinity
20000 ppm
µ w 1.03 mPa.s
B w 1.00214 m 3 /m 3
ρ w, sc 1012.4 kg/m 3
Table 6.6. Variation with pressure of CO 2 properties (from Span and Wagner, 1996). ρ g,sc – gas (CO 2 ) density at
standard conditions, P – pressure, z g – gas (CO 2 ) compressibility factor, µ g – gas (CO 2 ) viscosity, B g – gas (CO 2 )
formation volume factor.
Variation with pressure of CO 2 properties
ρ g,sc 1.9 kg/m 3
P, MPa z g µ g , mPa.s B g , m 3 /m 3
0.101 0.997 0.0171 1.192
2.76 0.912 0.0174 0.040
10.74 0.639 0.0239 0.007
21.38 0.506 0.0555 0.003
32.02 0.625 0.0726 0.002
40.00 0.727 0.0823 0.002
50.00 0.750 0.0928 0.002
Table 6.7. Relative permeability and capillary pressure calculated from the model developed by van Genuchten
(1980). S w – water saturation, k rw – water relative permeability, k rg – gas (CO 2 ) relative permeability, P c – capillary
pressure.
Relative permeability and capillary pressure
S w k rw k rg P c , kPa
0.2 0.0 1.0 400.0
0.3 0.00001 0.74 80.7
0.4 0.00008 0.5 28.1
0.5 0.0008 0.3 14.8
0.6 0.004 0.16 9.0
0.7 0.015 0.06 5.8
0.8 0.048 0.01 3.7
0.9 0.147 0.0006 2.1
0.95 0.275 0.0 1.3
1.0 1.0 0.0 0.0
91

Table 6.8. Summary of simulation study. P inj – well injection pressure, P frac – fracture pressure, Q inj – Injection rate.
See Figures 6.48b to 6.48d for k distribution. Number of grid blocks varies as follows: 0

6.7.4. Simulation Results
Preliminary simulation results were determined using simplified reservoir model parameters to
simulate various structural, geological and injection scenarios in the reservoir. The early reservoir
simulations showed that varying the vertical-to-horizontal permeability ratio (e.g. from 0.1 to 0.01)
in a relatively thin reservoir (i.e. ~ 5 m), has a negligible effect on injection rates.
The 3D model, simulations showed that placing injectors in medium permeability zones (i.e. 150
mD) reduced the injection rate by a factor of 5 (Table 6.7). A large part of the western Bowen Basin
area is likely to have similar medium reservoir permeabilities (Figure 6.47), so a larger number of
wells would be required to reach the target 1.2 Mt/y injection rate. However, the advantage of
injection in a lower-permeability (150 mD) zone is that a larger proportion of the injected volume of
CO 2 would remain trapped residually within the pore space when the local injection induced
pressure regime re-equilibrates with the regional hydrodynamic pressure regime. The simplified 3D
modelling also simulated a high permeability (i.e. 1000 mD) homogenous reservoir followed by the
inclusion of low-permeability baffles (Table 6.7). This provided further complexity with subsequent
reduction of injection and CO 2 migration rates up the flank, enabling an appreciation of system
sensitivities. Additional simulations were run where injection pressure was increased from 70% to
90% of fracture gradient, resulting in higher CO 2 injection rates.
Figure 6.48. Numerical simulation results showing gas saturation and reservoir pressure distributions using
combinations of injectors giving best total rate (Q total ). (a–d) Gas saturations and reservoir pressures for cases 5, 6,
7 and 9, respectively, and for years 7, 25 (injection ceases), 125, and 1025. Cartesian axes shown to locate grid
blocks of Table 6.7; 0

One result, stemming from the testing of lower and higher permeability areas, is that an
intermediate and optimal permeability range must exist where injection rate and long-term trapping
integrity can be maximized against the potential negative effects of higher CO 2 migration rates in a
higher permeability case, and less favourable economics in the lower permeability case.
Secondly and more importantly, if there is an inability to dissipate the injected CO 2 away from the
storage area due to low hydraulic connectivity in the surrounding rocks then adding additional
injection boreholes simply increases the rate of pressure build-up rather than significantly increasing
the injection volume.
The duration period for CO 2 migration before it reaches the Wunger Ridge is case-dependant, but
does show that, for injector wells located in the eastern part of the high permeability zone it is in the
order of 25 to 50 years for a uniform reservoir (cases 5 and 7: Figures 6.48a and c), and greater than
100 years for a reservoir with heterogeneity included (cases 6 and 9: Figures 6.48b and d). The
duration period for CO 2 migration for injection in the eastern model area is greater than 500 years
(not shown), and much of the CO 2 probably remains trapped through residual trapping.
A second phase of modelling could compare the simplified 3D models to more complex reservoir
models (e.g. Gorell & Bassett, 2001). Increased geological heterogeneity could be expected to
increase volumes trapped in stratigraphic traps (e.g. Hovorka et al., 2004). For the simulation
model, characterizing the connectivity of the reservoir and the surrounding aquifer is crucial to
maintaining higher injection rates, as it allows flow within and out of the model area (boundary
effects) to be more realistically simulated (Obdam et al., 2003).
To this end, the simplified 3D model only considered a uniform pressure system. From previous
studies, aquifers in the Bowen/Surat basins have been shown to be dynamic systems with recharge
occurring to the north of the study area and with flow directions predominantly towards the south
and southeast across the study area (Radke et al., 2000). However, models for the aquifer system
(i.e. including flow and pressure) would need to be varied for a local area such as the Wunger Ridge
because of the effects of hydrocarbon production over the last few decades.
6.8. Conclusions from reservoir simulation of coarse scale models
This assessment of the Wunger Ridge flank as a potential CO 2 storage site indicates that the area
remains a viable injection and storage site subject to a range of limitations and assumptions.
Suitability of Reservoir, Seal and Trap
• the characteristics of the reservoir and pressure regime of the surrounding aquifer can
significantly affect reservoir simulation results (e.g. injection pressure profiles and migration
rates).This is particularly the case with small scale (few tens of km), large cell size
(100’s of metres) simulations.
• the Showgrounds Sandstone has the potential to be a viable reservoir for CO 2 injection and
storage. The trap and seal integrity over geological time, have been demonstrated. The more
stratigraphically complex facies with intra-reservoir baffles and medium permeabilities
(i.e. 150 mD), have been shown to have better long term (10’s years – 100’s years) storage
characteristics, when using horizontal wells for injection to offset poorer reservoir
(injectivity and connectivity) characteristics.
• the Showgrounds Sandstone is interpreted to be present on the Wunger Ridge flank and
reservoir characteristics generally have been estimated as ~ 10 < porosity < 20 % and ~ 100
< permeability < 1000 mD.
• the Showgrounds Sandstone has been shown to be hydraulically connected over distances of
the order of 10 km. This is a favourable attribute of a large scale storage site as it indicates a
large proportion of the gross pore volume within the intended storage site may be accessed
from relatively few well locations.
94

• it is difficult to quantify the influence of multiple secondary baffles in the form of shale
bands and micro-scale faults which would increase the tortuosity of the migration pathway.
Modelling indicates that increasing the tortuosity of the migration pathway increases the
potential for en-route trapping for CO 2 , probably slows the migration rate therefore
increasing the effectiveness of dissolution trapping.
• the primary Snake Creek Mudstone and secondary Moolayember Formation seals have been
interpreted to be laterally extensive, and these are relatively un-faulted across the Wunger
Ridge flank.
• as the long-term trapping mechanisms are by trapping CO 2 residually and in small scale traps
(metres to 100’s of metres), the top seals ability to hold back a certain pressure (expressed as
a CO 2 column height) is analysed to ensure that CO 2 migrates laterally through the storage
reservoir during the injection phase. Post-injection, as the pressure re-equilibrates with the
surrounding aquifer, the top seal strength becomes largely superfluous to CO 2 migration,
whereas the seals lateral extent remains an important consideration.
Aquifer Connectivity
• the original predominant aquifer flow direction on the eastern side of the flank is to the
southwest at a rate of 0.2 m/yr. This is approximately perpendicular to the regional migration
pathway for injected CO 2 which is modelled approximately to the west. The implication is
that hydrodynamic flow is acting against any stratigraphic permeability barrier slightly
reducing the barrier’s seal capacity. The hydraulic gradient would have a small effect of
deflecting the migrating CO 2 slightly southward, as estimated at a semi-regional level.
Separate flow paths for CO 2 and H 2 O indicate that, potentially, long-term injectivity may be
enhanced by reducing reservoir pressure as water is able to escape the area down dip as the
CO 2 migrates up dip.
• the Wunger Ridge has been a petroleum producing area for approximately 30 years with
some fields have undergone significant pressure depletion. The radial extent of this depletion
is unclear, but it is believed to extend down the flank, and out into the deeper parts of the
basin. Given the most current information available, and using hydraulic head values
calculated from Waggamba-1, a new production affected flow rate has been calculated at 0.9
m/yr. The increased flow-rate changes the flow direction away from the recharge direction
and up onto the ridge. This means that the formation water is broadly moving in the same
direction as the predicted migration pathway towards the better permeability sands, further
implying that migration of CO 2 along this path may be faster than initially predicted.
Injection Characteristics
• the reservoir simulation runs show that a minimum of two vertical wells are needed to reach
injection rates of 1.2 Mt/y, or alternatively, at least one horizontal well, assuming an idealized
homogenous reservoir model (i.e. porosity = 20 %; K = 1000 mD).
• increasing injection pressure closer to maximum fracture gradient (i.e. 90% instead of 70%)
dramatically improves injection rates, whilst the level of intra-reservoir baffle complexity and
their proximity to the well bore can adversely affect rates.
• if it is not possible to dissipate the injected CO 2 away from the storage area due to low
hydraulic connectivity in the surrounding rocks, then adding additional injection boreholes
potentially increases the rate of pressure build up without a corresponding increase in the
injection rate and volume.
• the migration time for CO 2 , before it reaches the Wunger Ridge is case dependent. The CO 2
plume migration time to reach the Wunger Ridge from injector wells located in the eastern
part of the modelled high permeability zone is in the order of 25 to 50 years assuming a
95

uniform reservoir, and greater than 100 years modelling a reservoir with heterogeneity
included. The migration time for CO 2 injected in the eastern part of the modelled area
(i.e. K = 150 mD) is greater than 500 years.
Impact of Modelled Site on Existing Natural Resources
A number of effects from CO 2 injection activity in the Showgrounds Sandstone reservoir can be
pre-empted and are described below. Some of these effects may impinge positively or negatively on
petroleum resources of the Wunger Ridge.
• reservoir simulation of coarse scale models on the Wunger Ridge flank indicates that it is
unlikely that CO 2 would migrate into the producing fields within the first 25 years, assuming
injection at a rate of 1.2 Mt/y over 25 years. This scenario assumes a fairly uniform reservoir
system with very good reservoir characteristics and injection wells drilled in the order of 10
km away.
Modelling of more tortuous pathways using the same quality reservoir, indicates that
migration times could be significantly greater (i.e. > 100 years). If the injection site is linked
via a highly permeable channel sandstone surrounded laterally by low permeability rocks
directly towards the Wunger Ridge then migration time to the ridge could be substantially
less: this scenario has not been modelled.
• pressure data indicates hydraulic communication between the Louise-1 well on the flank and
the pressure depletion caused by the exploitation of hydrocarbons along the Wunger Ridge.
Therefore, there is a potential for the fields to be affected by changes in pressure from
potential CO 2 injection operations. At this point in time it is unknown whether the net result
would be positive or negative.
• for example, an increase in field pressure (without a significant increase in water movement
into the field area) may enhance hydrocarbon recovery as the increase in the pressure gradient
may drive a greater volume of hydrocarbons toward the wells where semi-depleted reservoirs
are associated with pressure lows. One consequence of a CO 2 injection project is that
migration pathways would be better understood if reservoir pressure in different areas of the
ridge were able to be monitored across the lifespan of the project. Tracers placed within the
CO 2 would further quantify migration pathways.
• on the negative side, increasing the pressure may contract the gas–water/gas–oil contacts
back above intra-reservoir scale stratigraphic baffles reducing the ultimate hydrocarbon
recovery from fields on the Wunger Ridge. Alternatively, increasing the pressure through
CO 2 migration may accelerate water break-through potentially reducing the swept area of
reservoirs which are in pressure connection. The shape of the pressure front would need to
be modelled as it contacts the fields to see what the reaction of individual wells, potentially,
would be.
6.9. Chapter References
Boggs, S., 1995. Principles of sedimentology and stratigraphy (2 nd ed.) Prentice Hall, New Jersey
U.S.A.
Bohac, K., 2002. Continental Sequence Stratigraphy: Insights for Lacustrine Hydrocarbon Systems.
Esso Australia/PESA Short Course. Unpublished Course Notes.
Brady, H., 2004. A major play in the Surat–Bowen Basin Lan Nguyen and eight years of Permian
ideas, PESA news August/September 2004, p22–28.
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Brakel et al., (in press), In Korsch, R.J. & Totterdell, J.M. (eds) Evolution of the Bowen, Gunnedah
and Surat basins, Eastern Australia. Australian Journal of Earth Sciences.
Bridge Oil Limited (BON), 1981. Waggamba-1 Well Completion Report. Unpublished.
Bridge Oil Limited (BON), 1989. Sirrah-5 Well Completion Report. Unpublished.
Butcher, P.M. 1984. The Showgrounds Formation, its setting and seal, in ATP 145P, QLD. APEA
Journal 1984 Vol. 24 Part 1 (336–357).
Coho Exploration Pty Ltd (Coho), 1982. Well Completion Report, Inglestone No. 1.
Fielding, C.R., Silwa, R., Holcombe, R.J. and Jones, A.T., 2001. A new Palaeogeographic Synthesis
for the Bowen, Gunnedah and Sydney Basins of Eastern Australia. PESA Eastern Australasian
Basins Symposium Melbourne, Victoria, 25–28 November 2001.
Folk, R.L., 1974. Petrology of sedimentary rocks. Hemphill, Austin, Texas.
Galloway, W.E. and Hobday, D.K., 1983. Terrigenous clastic depositional systems: application to
petroleum, coal, and uranium exploration. Springer-Verlag, New York.
Home, P.C., Dalton, D.G. & Brannan, J., 1990. Geological Evolution of the Western Papuan Basin.
Petroleum Exploration in Papuan New Guinea: Proceedings of the First PNG Petroleum
Convention, Port Moresby, 12–14 th February 1990, Carman, G.J. and Z eds.
Jordan, D. W., Pryer, W.A., 1992. Hierarchical Levels of Heterogeneity in a Mississippi River
meander belt and application to reservoir systems. AAPG Bulletin, 76, Vol 10, pg 1601–1624.
Kassan, J. and Lang, S. 1999. Sedimentology and Stratigraphy of Fluvial & Deltaic Reservoirs
Field Guide Bowen and Surat Basins, A field guide for Participants of the 1998 Excursion.
Publishers — Whistler Research & GeoSed.
Korsh, R.J., Wake-Dyster, K.D. & Johnstone, D.W., 1992. Seismic imaging of Late Palaeozoic-
Early Mesozoic extensional and contractional structures in the Bowen and Surat basins, eastern
Australia. Tectonophysics, 215, 273–294.
Korsch, R.J., Boreham, C.J., Totterdell, J.M., Shaw, R.D. and Nicoll, M.G., 1998. Development
and petroleum resource evaluation of the Bowen, Gunnedah and Surat Basins, Eastern Australia.
APPEA Journal 1998 Vol. 38 Part1 (pp. 199–237).
Merrill, R.K., Trujillo, S.K., Simpson, S.D. & Wall, R.M., 2004. An international perspective on
entry into hydrocarbon-producing basins of eastern Australia. PESA Eastern Australasian Basins
Symposium II. Adelaide, 19–22 September 2004, 35–40.
Miall, A., D., 1990. Principles of Sedimentary Basin Analysis (2 nd ed.). Springer-Verlag New
York U.S.A.
Reading, H.G., 1996. Sedimentary Environments: Processes, facies and stratigraphy (3 rd ed).
Blackwell Science Ltd, London.
Reeve, J., Adamson, M., Dorsch, C., 1988. Final Well Report, Yellowbank Creek North-1, Surat-
Bowen Basin, Queensland. Sydney Oil Company (Canning) Pty Ltd. Operator for and on behalf of
PL18 Joint Venture. Unpublished.
Robein, E., 2003. Velocities, time-imaging and depth-imaging in reflection seismics - Principles
and methods. EAGE Publications the Netherlands, 461p.
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Schlumberger, 1989. Log Interpretation Principles/Applications. Schlumberger Wireline and
testing, Texas, USA.
Shaw, R.D., Korsch, R.J., Boreham, C.J., Totterdell, J.M., Lelbach, C. & Nicoll, M.G., 1999.
Evaluation of the undiscovered hydrocarbon resources of the Bowen and Surat Basins,
southern Queensland. AGSO Journal of Australian Geology and Geophysics, 17 (5/6),
pp 43- 65.
Strong, P.C., Wood G.R., Lang S.C., Jollands A., Karalaus E. & Kassan J., 2002. High resolution
palaeogeographic mapping of the fluvial–lacustrine Patchawarra Formation in the Cooper Basin,
South Australia APPEA Journal pp65–81.
Sunshine Gas, 2005. Australian Stock Exchange Announcement April 7, 2005.
http://www.sunshinegas.com.au/inv_asx.php?q=2&y=2005
Sydney Oil Company (Canning) Pty Ltd (SOC), 1987. Final Well Report, Kinkabilla Creek-1.
Union Oil Development Corporation (UOD), 1961. Well Completion Report No.1,
Union-Kern-AOG — Cabawin No. 1.
Union Oil Development Corporation (UOD), 1964. Well Completion Report No.28,
Union-Kern-AOG — Tarthra No. 1.
Union Oil Development Corporation (UOD), 1966. Well Completion Report,
Union-Kern-AOG- Kinkabilla No. 1.
Willink, R.J., Pass, G.P., Horton, P., Taylor, R., Sutherland, G. & Pidgeon, B., 2004. Did the
exploration well Myall Creek-1, plugged and abandoned in 1964, actually find the biggest gas
field in the Surat Basin? — Introducing the Tinowon Formation stratigraphic play. PESA Eastern
Australasian Basins Symposium II, p 13–28.
98

7. Summary and Implications - Southeast Queensland CO 2
Storage Sites
Summary
The southeast Queensland CO 2 storage sites project has provided a number of significant results
concerning the potential to store CO 2 in Queensland, with the Bowen Basin being the focus of initial
interest.
• Based on the assessment methodology used by this study and the preceding GEODISC
programme, the Bowen and Galilee basins are considered the most suitable for the injection
and long term storage of CO 2 storage. The rest of the basins are perceived to have limited
potential due to a variety of reasons as outlined in Table 3.1.
• Preliminary results indicate that CO 2 storage on the Wunger Ridge flank appears technically
feasible. Potentially similar sites exist in other parts of the eastern Bowen Basin.
Understanding the variation of facies and associated reservoir quality will be the key to
assessing these other sites.
• The Wunger Ridge flank study area has been dynamically modelled by simulating injection
and reservoir conditions using coarse scale 3D models. The simulations suggest that
injection rates of 1.2 mT/yr can be sustained using a minimum of one horizontal well or two
vertical wells. More complex modelling in Petrel TM and Eclipse TM could examine the
importance of stratigraphic complexity of the reservoir and detail the sensitivities of other
parameters to fluid flow.
• Using a basic net available pore space model, the Wunger Ridge flank area has been
assessed to have a net available pore space for storage, equivalent to approximately
40 - 170 Mt of CO 2 . More correct estimates of storage potential from dynamic modelling
could be obtained from finer scale reservoir modelling and injection simulations as well as
establishing residual gas saturation trapping. Improving the precision of these estimates
will requires in the first instance the acquisition of relative permeability data
(H 2 O-CO 2 ) and as the data becomes available publicly, more well/seismic data to better
understand reservoir heterogeneity and the structure.
• many of the southeast Queensland basins have been established as having very poor
reservoir characteristics including the eastern flank of the Bowen Basin. If the results from
the Stanwell experiment in low permeability rocks located in the Denison Trough proves
encouraging, then low permeability reservoirs (i.e. < 50 mD) should be re-investigated as
they could provide viable long-term storage sites
• the Wunger Ridge study of the Showgrounds Sandstone (reservoir ) Snake Creek Mudstone
(seal) residual-structural trap is representative of the most likely CO 2 storage type to be
found on the western margin of the Taroom Trough. The same basic concept and assessment
methodologies could be applied to similar play types along the western margin with
reasonable confidence, if similar geological and structural characteristics exist.
• the potential storage site on the Wunger Ridge flank is located within a part of the Bowen
Basin that has active exploration targeting the deeper Permian Tinowon Sandstone play,
which has been extended east of the Roma Shelf, about 60 km north of the Wunger Ridge
flank area. As such, there is the possibility that special measures would have to be
considered if an ESSCI was to be established in the area.
99

Implications
It is hoped that the knowledge-base gained from this project can be extrapolated to other parts of
the Bowen Basin (e.g. the Roma Shelf). This project has also documented most of the geological
risk factors, sensitivities and input those into several 3D geological models that incorporated
multiple reservoir simulation scenarios. A number of implications result, as follows.
• reservoir simulations have shown that a thorough understanding of the reservoir (aquifers)
surrounding the storage area is as important as understanding the reservoir within the storage
area itself.
• while hydrodynamic flow systems are relatively slow compared with CO 2 migration,
pre-production studies can provide insight into the likely ultimate destination of formation
water, and the existence of pressure relief systems.
• Modelling using homogenous reservoirs, in low dip areas, (approximately 1 degree in this
case) indicated that the CO 2 plume will migrate towards the better permeability, porosity and
low pressure areas generally but not exclusively in the up dip direction.
• a potential impact to the petroleum industry is that exploration wells which are targeting
future plays drilled within the storage area would require pipe resistant to CO 2 and HCO 3
corrosion to prevent the accidental release of CO 2 into the well bore.
100

8. Recommendations- Southeast Queensland CO 2
Storage Sites
Many of the following recommendations would depend on a commitment from stakeholders in
taking up the Wunger Ridge area as a potential storage site. Additionally, knowledge from some
of the following recommendations are transportable across to other areas.
Transportable Knowledge Base
One analysis that would be transportable world wide would be to measure CO 2 gas saturation for
given capillary sizes under various scenarios of reservoir characteristics, depth / pressure.
Measurements can be done by measuring/analysing core sample characteristics through laboratory
work.
Such a methodology would involve:
• matching facies types (i.e. through electrical log reading and core analysis) to permeability
distributions;
• measuring capillary pressure for both drainage and imbibition. Imbibition measurement of
CO 2 is required to mimic the saturation during injection over a range of
porosities/permeability’s and pressures;
• measuring residual water and CO 2 saturation for different capillary sizes and pressures,
during drainage to estimate the residual trapping capability of a rock for a given capillary
size;
• modelling relative injection pressure, which is related to the difference between the
lithological and hydrological pressures that change with depth and hydrological
environment. The pressure potential across an area can be mapped to indicate potential
migration pathways, and the subsequent location of potential injection sites;
• modelling pressure decline curves away from the injector well that are dependant on
reservoir thickness, permeability, gross connectivity, small scale heterogeneity and
formation pressure distributions, all changing with the geological environment;
• modelling the relative density of CO 2 that changes with depth (especially true for the
larger/longer monoclinal residual traps).
• modelling the effect of differing formation water salinities and the effect they would have
on injection and buoyancy.
Non-transportable Knowledge Base
• geomechanical work is required to document the local lithostatic gradient and estimate the
maximum fracture gradient. This would allow a better estimate of possible injection pressure
rates with subsequent ramifications for CO 2 storage volume. Estimating the maximum
fracture gradient is also a priority as injection pressure thresholds strongly influence possible
rates of injection.
• The sedimentary provenance within the Showgrounds Sandstone appears similar and
continuous across the Wunger Ridge and Roma Shelf areas, however a number of individual
river systems are suspected. Further petrographic work could be undertaken to potentially
improve the understanding of sediment provenance and their relationship with the two areas.
101

This knowledge would assist in the interpretation of the palaeogeography within Roma Shelf
area, thus giving an understanding of the connectivity of the Showgrounds Sandstone
between the Wunger Ridge and Roma Shelf.
• hydrodynamic work has been carried out as comprehensively as possible using available
data: a more detailed review would require gaining permission to obtain field productionpressure
data (i.e. production schedules) from the operator(s) of the Wunger Ridge fields.
This pressure v production data would facilitate the interpretation of the state of depletion,
inter and intra pressure connectivity of fields. The next stage in understanding the flow
system in the Showgrounds Sandstone and its potential impact on the migration direction of
injected CO 2 is to understand the current day flow system. This requires more detailed
production data from petroleum companies operating in the area in terms of static gradient
tests, wellhead pressures, etc. This must be coupled with a mass balance calculation.
• it would also be important to locate the digital SEGY seismic data that may be available as
original tapes. These SEGY tapes may need reprocessing to enable the interpretation of the
data to determine structural as well as stratigraphic information.
Other
• it is recommended that the resource status of various sub 10000 ppm NaCL salinity reservoirs
be monitored.
102

9. Acknowledgements
The project group would like to thank the many people who have contributed to the project,
including:
• colleagues within the Geoscience Australia CO2CRC project team including Kila Bale, Rick
Causebrook, Tess Dance, Lynton Spencer, Frank La Pedalina, Ian Newlands, Tim
Robertson, and Rob Langford;
• interpretive support from colleagues in the Australian School of Petroleum including Max
Watson and Catherine Gibson-Poole
• Erin Parkinson who was hired as a temporary employee to digitise the seismic data, Felix
Booth who was hired as a temporary employee to quality control the well-logs, and
Catherine Martin who digitised the seismic data, and
• Andy Rigg (past) and John Kaldi (present) — Program Manager of the CO2CRC who
helped with logistical support.
Geoscience Australia’s component of this work is published with the permission of the Chief
Executive Officer of Geoscience Australia — Dr Neil Williams, as well as support from the Chief
of the Petroleum and Marine Division — Dr Clinton Foster.
103

10. Appendices
10.1 Bowen Basin- Autho-Stratigraphic chart and references
10.2 Denison Trough
10.3 East Bowen Basin Study area- Burunga Anticline/ Dulucca Area
10.4 Southeast Bowen Basin Study area
10.5 Northeast Bowen Basin Study Area
10.6 Wunger Site Flank Associated Reports
10.6.1 Geological Dataset- Well information
10.6.2 Petrology (Stuart Barclay)
10.6.3 Hydrodynamics (Alison Hennig, Luke Johnson)
10.6.4 Petrophysics (Tim O-Sullivan)
10.6.5 Seal Capacity (Ric Daniel)
10.6.6 Geophysics (Jacques Sayers)
10.6.7 Reservoir Engineering (Yildiray Cinar)
10.7 Glossary of Geosequestration Terms
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List of authors
Note: (main authors-underlined)
Stuart Barclay 1 (CSIRO Petroleum, Sydney) — Geochemist. Stuart carried out the
petrography/petrology analysis of core samples and wrote the stand-alone petrology/petrography
reports. Contacts: Ph. 61 2 9490 8890, e-mail: sbarclay@co2crc.com.au.
John Bradshaw 1 (Geoscience Australia, Canberra) - principal petroleum geologist. John was
project leader of the CO2CRC project group until August 2005, and responsible for leading
strategic aspects of the project including networking of key stake-holders. John also played a
significant role in reviewing of the report. Contacts: Ph. 61 2 6249 9659, e-mail:
john.bradshaw@ga.gov.au.
Yildiray Cinar (University of New South Wales, Sydney) — senior reservoir engineer. Yildiray
was responsible for carrying out both the 2D profile and 3D reservoir simulations of the site area,
and wrote the stand-alone reservoir engineering report. Contacts: Ph. 61 2 9385 5786,
e-mail: ycinar@co2crc.com.au.
Ric Daniel 2 (Australian School of Petroleum, Adelaide) — Seals Data Research Fellow. Ric carried
out the analysis of seal samples using MICP and wrote the stand-alone seal capacity report.
Contacts: Ph. 61 8 8303 4297, e-mail: rdaniel@asp.adelaide.edu.au.
Allison Hennig (CSIRO Petroleum, Perth) — senior petroleum geologist specialising in
hydrodynamics. Allison was responsible for quality controlling and interpreting the hydrodynamics
data and writing the stand-alone hydrodynamics report. Contacts: Ph. 61 8 6436 8743,
e-mail: ahennig@co2crc.com.au.
Aleks Kalinowski (Geoscience Australia, Canberra) — petroleum geologist. Aleks was
responsible for writing the geological summary of the southeast Bowen Basin study area for CO 2
storage potential and wrote the stand-alone report. Contacts: Ph. 61 2 6249 9609, e-mail:
aleks.kalinowski@ga.gov.au.
Cameron Marsh (Geoscience Australia, Canberra) — senior petroleum geologist. Cameron was
responsible for data gathering, geological interpretation and leading aspects of the geological
component of the project. Contacts: Ph. 61 2 6249 9833,
e-mail: cameron.marsh@co2crc.com.au.
Annette Patchett (Geoscience Australia, Canberra) — petroleum geologist. Annette was
responsible for assessing the east Bowen Basin study area (Burunga Anticline/Dulucca area)
for CO 2 storage potential and wrote the stand-alone report. Contacts:
Ph. 61 2 6249 9484, e-mail: apatchett@co2crc.com.au.
Jacques Sayers 3 (Geoscience Australia, Canberra) — senior petroleum geophysicist, and was
the team leader for this project. Jacques was responsible for data gathering and geophysical
interpretation. Contacts: Ph. 61 2 6249 9609, e-mail: jsayers@co2crc.com.au.
Adam Scott (Geoscience Australia (Canberra) — petroleum geologist. Adam was responsible
for data gathering, geological interpretation and leading aspects of the geological component of
the project. Contacts: Ph. 61 2 6249 9148, e-mail: ascott@co2crc.com.au.
Lloyd White 1 (Geoscience Australia, Canberra) — geologist. Lloyd was responsible for writing the
geological summary of the northeast Bowen Basin study area for CO 2 storage potential and wrote
the stand-alone report. Contacts: Ph. 61 2 6249 9621, e-mail: lloyd.white@ga.gov.au.
1 No longer a participant of CO2CRC
2 Not a member of CO2CRC
3 Now at ASP
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List of contributors
Luke Johnson (CSIRO Petroleum, Perth) — petroleum geologist specialising in hydrodynamics.
Luke was responsible for quality controlling and interpreting aspects of the hydrodynamics data.
Tim Robertson (Geoscience Australia, Canberra) — technical assistant throughout the project and
was involved with assembling the seismic database for the project.
List of reviewers
Andrew Barrett 2 (Geoscience Australia, Canberra) — senior geophysicist. Andrew reviewed the
geophysical components of the report.
Rick Causebrook (Geoscience, Canberra) —senior petroleum geologist and is project leader for
CO2CRC Project 1.1. Rick reviewed the whole report.
Alfredo Chirinos (Geoscience Australia, Canberra) — senior geologist. Alfredo reviewed the
whole report.
Rob Langford (Geoscience Australia, Canberra) — senior geologist and is project leader for
CO2CRC Project 1.8. Rob reviewed the appendices of the report.
Frank La Pedalina 4 (Geoscience Australia, Canberra) — geophysicist. Frank reviewed the
geophysical components of the report.
Donghai Xu 2 (Geoscience Australia, Canberra) — senior petroleum engineer. Donghai reviewed
the engineering components of the report.
2 Not a member of CO2CRC
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