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Record 2015/31 | GeoCat 87832

Cooper Basin Architecture and Lithofacies Regional Hydrocarbon Prospectivity of the Cooper Basin, Part 1 Hall, L. S., Hill, A. J., Troup, A., Korsch, R. J., Radke, B., Nicoll, R. S., Palu, T. J., Wang, L. & Stacey, A.

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Cooper Basin Architecture and Lithofacies Regional Hydrocarbon Prospectivity of the Cooper Basin, Part 1 GEOSCIENCE AUSTRALIA RECORD 2015/31

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Hall, L. S. , Hill, A. J. , Troup, A. , Korsch, R. J. , Radke, B. , Nicoll, R. S. , Palu, T. J. , Wang, L. & 1,4 Stacey, A.

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Geoscience Australia Department of State Development, South Australia Geological Survey of Queensland Geological Survey of Victoria

Department of Industry, Innovation and Science Minister for Resources, Energy and Northern Australia: The Hon Josh Frydenberg MP Assistant Minister for Science: The Hon Karen Andrews MP Secretary: Ms Glenys Beauchamp PSM Geoscience Australia Chief Executive Officer: Dr Chris Pigram This paper is published with the permission of the CEO, Geoscience Australia

© Commonwealth of Australia (Geoscience Australia) 2016 With the exception of the Commonwealth Coat of Arms and where otherwise noted, this product is provided under a Creative Commons Attribution 4.0 International Licence. (http://creativecommons.org/licenses/by/4.0/legalcode) Geoscience Australia has tried to make the information in this product as accurate as possible. However, it does not guarantee that the information is totally accurate or complete. Therefore, you should not solely rely on this information when making a commercial decision. Geoscience Australia is committed to providing web accessible content wherever possible. If you are having difficulties with accessing this document please email [email protected]. ISSN 2201-702X (PDF) ISBN 978-1-925124-93-4 (PDF) GeoCat 87832 Bibliographic reference: Hall, L. S., Hill, A., Troup, A., Korsch, R., Radke, B., Nicoll, R. S., Palu, T., Wang, L. & Stacey, A. 2015. Cooper Basin Architecture and Lithofacies: Regional Hydrocarbon Prospectivity of the Cooper Basin, Part 1. Record 2015/31. Geoscience Australia, Canberra. http://dx.doi.org/10.11636/Record.2015.031

Field outlines are provided from Encom GPInfo, a Pitney Bowes Software (PBS) Pty Ltd product. Whilst all care is taken in compilation of the field outlines by PBS, no warranty is provided regarding the accuracy or completeness of the information. It is the responsibility of the customer to ensure, by independent means, that those parts of the information used by it are correct before any reliable is placed on them. Top right cover photo: aerial view of sand dunes, Cooper Basin. Photo by Ian Oswald-Jacobs, 1996. Image reproduction courtesy of Energy Resources Division, Department of State Development, South Australia.

Contents Executive Summary..................................................................................................................................1 1 Introduction ............................................................................................................................................3 1.1 Basin Overview ................................................................................................................................4 1.2 Exploration History ...........................................................................................................................5 1.3 Production ........................................................................................................................................7 1.4 Reserve and Resource Estimates ...................................................................................................8 2 Regional Basin Model Construction ....................................................................................................10 2.1 Data................................................................................................................................................10 2.1.1 Well Data ..................................................................................................................................11 2.1.2 Seismic Data ............................................................................................................................12 2.1.3 Digital Elevation Data ...............................................................................................................13 2.1.4 Surface Geology .......................................................................................................................13 2.1.5 Potential Field Data ..................................................................................................................13 2.1.6 Published Data Packages ........................................................................................................13 2.2 Interpretation ..................................................................................................................................14 2.2.1 Review of Existing Seismic Interpretation in TWT ...................................................................14 2.2.2 Velocity Analysis and Depth Conversion .................................................................................15 2.2.3 Regional 3D Basin Model .........................................................................................................16 2.3 Electrofacies Analysis ....................................................................................................................19 2.3.1 Methodology .............................................................................................................................19 2.3.2 South Australia .........................................................................................................................19 2.3.3 Queensland ..............................................................................................................................20 2.3.4 Gridding ....................................................................................................................................20 3 Structural setting ..................................................................................................................................21 3.1 Structural Elements ........................................................................................................................28 3.1.1 Troughs ....................................................................................................................................28 3.1.2 Ridges ......................................................................................................................................30 3.1.3 Basement inheritance...............................................................................................................31 4 Tectonic Evolution ...............................................................................................................................32 4.1 Pre-Permian Basement Evolution ..................................................................................................32 4.1.1 Metamorphic Basement ...........................................................................................................34 4.1.2 Cambro–Ordovician Warburton Basin .....................................................................................35 4.1.3 Devonian Adavale Basin system ..............................................................................................35 4.1.4 Silurian and Carboniferous Granite Emplacement ...................................................................36 4.2 Basin Evolution: Pennsylvanian to Holocene ................................................................................37 4.2.1 Pennsylvanian–Triassic Cooper Basin .....................................................................................38 4.2.2 Jurassic–Cretaceous Eromanga Basin ....................................................................................42 4.2.3 Cenozoic Lake Eyre Basin .......................................................................................................45 4.2.4 Present Day Stress Field..........................................................................................................47 5 Lithostratigraphy and Environments of Deposition ..............................................................................49 5.1 Overview ........................................................................................................................................49

Cooper Basin Architecture and Lithofacies

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5.2 Gidgealpa Group ............................................................................................................................50 5.2.1 Merrimelia Formation and Tirrawarra Sandstone ....................................................................51 5.2.2 Patchawarra Formation ............................................................................................................53 5.2.3 Murteree Shale .........................................................................................................................58 5.2.4 Epsilon Formation ....................................................................................................................59 5.2.5 Roseneath Shale ......................................................................................................................64 5.2.6 Daralingie Formation ................................................................................................................65 5.2.7 Toolachee Formation ...............................................................................................................70 5.3 Nappamerri Group .........................................................................................................................75 5.3.1 Arrabury Formation ..................................................................................................................75 5.3.2 Tinchoo Formation ...................................................................................................................76 6 Reservoirs and Seals ..........................................................................................................................78 6.1 Introduction ....................................................................................................................................78 6.2 Reservoirs ......................................................................................................................................79 6.2.1 Introduction ...............................................................................................................................79 6.2.2 Key reservoir intervals ..............................................................................................................80 6.3 Seals ..............................................................................................................................................82 7 Conclusions .........................................................................................................................................83 Acknowledgements ................................................................................................................................84 References .............................................................................................................................................85

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Executive Summary

The Cooper Basin is a Pennsylvanian–Middle Triassic intracratonic basin in northeastern South Australia and southwestern Queensland. The basin is Australia’s premier onshore hydrocarbonproducing province and is nationally significant, providing domestic gas for the East Coast Gas Market. Exploration activity in the region has recently expanded with explorers pursuing a range of newly-identified unconventional hydrocarbon plays. These include the extensive basin-centred and tight gas accumulations in the Gidgealpa Group, deep coal gas associated with the Patchawarra and Toolachee formations, as well as the less extensive shale gas plays in the Roseneath and Murteree shales (Goldstein et al., 2012; Menpes et al., 2013; Greenstreet, 2015). Despite this recent activity, the basin remains relatively immature and under-explored in comparison to more densely drilled North American basins, particularly in terms of its unconventional resource potential (Greenstreet, 2015). Previous regional studies of the Cooper Basin geology and petroleum prospectivity include Gravestock et al. (1998) for the South Australian region and Draper (2002) for Queensland. Both reports highlight that despite the amount of exploration activity in the basin, certain elements of the basin’s structure and evolution remain poorly understood. Given the amount of renewed industry interest in the basin over the last five years and the additional open-file data now available since these previous studies, a review of the regional basin geology and petroleum prospectivity is timely. This report presents an overview of the architecture, tectonic evolution and lithostratigraphy of the Cooper Basin. Structural architecture, formation extent and thickness is characterised through construction of a regional 3D geological model, designed to capture the formations associated with the major play types in the basin. Existing published Cooper Basin horizons (NGMA, 2001; DMITRE, 2001; DMITRE, 2009) are integrated with formation tops and new seismic data interpretations, ensuring seamless integration of datasets across the state border. The late Neoproterozoic to Cenozoic evolution of the Cooper Basin region is discussed in the context of the broader tectonic evolution of eastern Australia. In addition, stratigraphy ages have been updated to produce a revised Cooper Basin stratigraphic chart, consistent with the 2012 Geological Time Scale (Gradstein et al., 2012) and updated spore pollen age calibration (e.g. Nicoll et al., 2015). The new formation ages, along with the timing of key tectonic events and regional erosion estimates, are assigned to the 3D geological model, enabling extraction of time-slice cross-sections through the basin, capturing the regional burial history of the Cooper–Eromanga–Lake Eyre succession. Isopachs extracted from the 3D model are used to review the extent and thickness of each formation. The Permian Toolachee and Patchawarra formations in Queensland are shown to have a wider extent compared with previous studies. In addition, the boundaries of the Roseneath and Murteree shales were revised, although their distribution still remains uncertain in areas such as the Arrabury Depression. Lithofacies analysis published for South Australia (Sun & Camac, 2004) are integrated with new electrofacies mapping results in Queensland to produce the first basin wide set of lithofacies maps for the Toolachee, Daralingie, Epsilon and Patchawarra formations. The resulting net sand, silt, shale and coal thickness maps characterise the regional distribution of key source, reservoir and seal intervals across the basin. Maps of net coal and shale thickness clearly demonstrate an abundance of potential


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source rock facies in the Toolachee and Patchawarra formations in all regions. Additional potential source rock facies can be found in the Roseneath and Murteree shales and coals and shales of the Daralingie and Epsilon formations. Net sand thickness maps highlight possible reservoir facies distribution. This study presents the most detailed regional 3D basin model published for the Cooper Basin to date. The model is designed to characterise the formations associated with the basin’s key petroleum systems elements, providing a framework for regional scale petroleum systems analysis and resource assessments studies (Hall et al., 2015; Kuske et al., 2015). While this work provides important insights into both the conventional and unconventional hydrocarbon prospectivity of the basin, it also has application for the assessment of other resources such as groundwater (e.g. Smith et al., 2015a, b, c).

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1 Introduction

The Cooper Basin is a Pennsylvanian–Middle Triassic intracratonic basin in northeastern South 2 Australia and southwestern Queensland. It covers an area of approximately 127,000 km (Stewart et al., 2013) and is up to 2400 m thick. The Cooper Basin succession does not outcrop, and is overlain by up to 2600 m of Jurassic–Cretaceous Eromanga Basin and Cenozoic Eyre Basin succession. The Cooper Basin is often grouped with the overlying Jurassic–Cretaceous Eromanga Basin and together these form Australia’s largest onshore producer of gas and oil from conventional reservoirs. The Cooper Basin is predominantly gas-producing with a considerable light liquid component. In contrast the overlying Eromanga Basin hosts predominantly liquids which have mostly migrated from underlying Cooper Basin source rocks. Production in the Cooper Basin to date has been from eight formations in a thick continental succession containing several coal-bearing units and carbonaceous siltstones, predominantly from the Pennsylvanian–Permian Gidgealpa Group (Boreham & Hill, 1998). Exploration activity in the region increased and diversified in 2009 as explorers pursued a range of newly identified hydrocarbon plays in unconventional reservoirs. These include extensive tight gas accumulations in the Gidgealpa Group, deep dry coal seam gas associated with the Patchawarra and Toolachee formations, the less extensive shale gas plays in the Roseneath and Murteree shales and mixed lithotype hybrid plays (Goldstein et al., 2012; Menpes et al., 2013; Greenstreet, 2015). Overall, the Cooper Basin has the richest datasets of any onshore sedimentary basin in Australia (Carr et al., 2016). Between 1959 and June 2015, there have been over 3065 petroleum wells drilled within the outline of the Cooper Basin as defined by Stewart et al. (2013) and seismic coverage (both 2D and 3D) is extensive. Despite the relatively high data density, the basin remains relatively immature and under-explored in comparison to more densely drilled North American basins (Greenstreet, 2015). The most recent detailed regional studies published for the Cooper Basin were Gravestock et al. (1998) covering the South Australia section of the basin and Draper (2002) for the Queensland part. Both these studies highlight that despite the amount of data available across the basin, certain elements of the basin structure and evolution remain poorly understood. Given the amount of renewed industry interest in the basin over the last five years, and the wealth of additional data and new studies published over the last fifteen years, this regional review of the basin geology and petroleum prospectivity is timely. This report presents an overview of the architecture, tectonic evolution and lithostratigraphy of the Cooper Basin. Structural architecture, formation extent and thickness is characterised through construction of a regional 3D geological model, designed to capture the formations associated with the major play types in the basin. While this work provides important insights into both the conventional and unconventional hydrocarbon prospectivity of the basin (Hall et al., 2015; Kuske et al., 2015), it also has application for the assessment of other resources such as ground water (e.g. Smith et al., 2015a, b, c). This is the first part of a series reports reviewing various aspects of the hydrocarbon prospectivity of the Cooper Basin (see also Hall et al., 2016).


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1.1 Basin Overview The Cooper Basin is almost completely covered with tenements and leases, with well-developed infrastructure. The basin and surrounding area contains approximately 256 gas fields and 166 oil fields currently on production (Figure 1.1). Processing facilities include the Moomba and Ballera plants for sales gas and ethane, and the Jackson plant for crude oil (Figure 1.1; Santos, 2015a). The basin is nationally significant, providing natural gas to the East Coast Gas Market. This is Australia’s biggest domestic market, which consumed about 65% (687 PJ) of Australia’s total gas production in 2012 (DI & BREE, 2013). While hydrocarbons produced from the basin have historically been for only domestic consumption, gas sales are also contracted supply to the Liquid Natural Gas (LNG) export terminals located in Gladstone, Queensland (Figure 1.2).

Figure 1.1: Cooper Basin permits, pipelines and infrastructure as of May 2015. Pipelines updated from Webster & Dunstan (2004).

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Figure 1.2: Australian pipeline infrastructure (updated from Webster & Dunstan, 2004) and location of LNG export facilities.

1.2 Exploration History The first Oil Exploration Licence (OEL) was granted in 1945 to A.J. Keast on behalf of the Zinc Corp. 2 Ltd. It covered 10,360 km between Lake Frome and the NSW border, within the southern margin of the Cooper Basin in South Australia (O’Neil, 1998). Exploration in the basin by Santos and its partners began in 1954. Their initial wildcat well, Innamincka 1 drilled in 1959, was the first well to drill through the Cooper Basin succession, reaching gently dipping Ordovician beds at a depth of 3852 m (O’Neil, 1998). The well penetrated thick Triassic sediments underlain by a thin Permian section. Oil and gas potential was suggested by minor hydrocarbon shows in sediments within the Mesozoic succession (O’Neil, 1998). Thirty-five cores were taken during the drilling and ten drill stem tests were run, providing evidence of both gas with water and oil-cut mud in the Permian and Mesozoic sections (O’Neil, 1998). Over the next few years new seismic data were acquired and more wells were drilled, steadily increasing the geological understanding of the basin. This work culminated with several wells being


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drilled along the Gidgealpa–Merrimelia–Innamincka (GMI) ridges. The well Gidgealpa 1 penetrated a thick Permian section with several sands with good reservoir properties and gas shows, but well stability issues meant that these could not be tested. The second well, Gidgealpa 2 was drilled onstructure and drill stem tests in the Permian sands after the discovery of gas on 31 December 1963, 3 indicated a flow of 56,634 m /day (2 mmcfd) and on completion, produced gas and condensate (O’Neil, 1998). This discovery of commercial gas at Gidgealpa 2 resulted in new players being attracted to the basin and to acceleration in exploration. The first Permian oil discovery was announced by Bridge Oil in 1970 when light crude oil flowed from the Tirrawarra Formation in their Tirrawarra 1 well, while the first Jurassic-hosted oil was discovered in Strzelecki 3 (1978) in the Hutton Sandstone of the overlying Eromanga Basin. The discovery of natural gas in the Moomba 1 well by Delhi–Santos in 1966 was followed by further exploration wells proving the existence of large widespread gas reserves, paving the way for the commercial development of the Cooper Basin (O’Neil, 1998). Gas sales to Adelaide began in 1969, followed by Sydney in 1976 and Brisbane 20 years later (Santos, 2015). Since that time, conventional oil and gas reservoirs have been explored for, and developed continuously. Between 2009 and 2014, there was a revival in exploration activity in the Cooper Basin, driven by high resource prices and an increased interest in newly identified unconventional hydrocarbon plays in the basin. In 2014, a new record of 119 petroleum wells were drilled in the SA part of the basin, coupled with major 3D seismic acquisition. In 2015, activity levels began to taper during a period of low global oil prices, but infill gas development drilling and oil discovery appraisals still continue. For conventional oil and gas explorers the flanks of the major depocentres remain the main targets. Here reservoirs in the Cooper and Eromanga basins are charged from source rocks in the troughs themselves. Major gas fields include Moomba and Big Lake on the South Australian side and Challum in Queensland, whereas the western flank of the basin is a hotspot for oil exploration and production. Additionally, numerous companies are pursuing a range of unconventional plays within the basin (e.g. Hillis et al., 2001; Goldstein et al., 2012; Greenstreet, 2015). These include: •

the Roseneath, Epsilon, Murteree (REM) shale play

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basin-centred gas play within the Gidgealpa Group

•

gas saturated deep coal plays in the Toolachee, Daralingie, Epsilon and Patchawarra formations that do not require dewatering)

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hybrid mixed lithotype play within the Gidgealpa Group containing interbedded tight sandstones, shales and coals

•

deep coal seam gas play in the Weena Trough.

Given the basin’s existing conventional production, and its processing and pipeline infrastructure, these plays are well placed to be rapidly commercialised, should exploration be successful (Carson, 2014). In December 2011, Santos drilled the first dedicated vertical shale gas well (Moomba 191). Following completion, this was connected to the Moomba processing facilities in October 2012, bringing the first shale gas production to eastern Australian gas markets (Goldstein et al., 2012; Santos, 2012). Santos announced in July 2015 that the Cooper Basin’s first stand-alone deep coal producer, Tirrawarra South 1, was successfully brought online in May and is flowing wet gas in-line

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(Santos, 2015). This well is located within/adjacent to the Tirrawarra oil and gas field (Figure 1.3) and will provide the Joint Venture with long-term dynamic performance data from the deep coal.

1.3 Production In 2015, the Cooper Basin contained approximately 82 oil fields and 98 gas fields on production in South Australia, with an additional 84 oil fields and 158 gas fields in Queensland. These feed into production facilities at Moomba in South Australia, and at Ballera and Jackson in Queensland. Major gas and oil field locations are shown in Figure 1.3. As of December 2013, the Cooper and Eromanga basins have produced in the order of 315 mmbbl of oil, 92 mmbbl of condensate and 6.2 tcf of gas since gas sales began in 1969 (APPEA, 2014).

Figure 1.3: Major Cooper/ Eromanga Basin oil and gas fields.


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1.4 Reserve and Resource Estimates Total reported gas reserves and resources for the Cooper-Eromanga Basin couplet at 30 June 2014, as published by AEMO (2015), are listed in Table 1.1. Conventional 2P gas reserves are 1793 PJ, with an additional 5 PJ of unconventional 2P gas reserves (AEMO, 2015). As of 2011, Geoscience Australia estimated the Cooper–Eromanga known remaining 2P crude oil reserves as 66 mmbbl (388 PJ), along with 35 mmbbl (204 PJ) condensate and 41 mmbbl (172 PJ) LPG (Carson, 2014). As at 30 June 2014, the Cooper–Eromanga 2P reserves for Queensland were 295 PJ gas, 4212 ML of oil, 523 ML condensate and 458 ML of LPG (DMNR, 2015a, b). No coal seam gas reserves have been reported for the basin. Reserve and resource estimates remain confidential for the South Australian side of the Cooper Basin, except for numbers announced by listed companies (DSD, 2015c). Recent assessments of Australian basins by Advanced Resource Industries (ARI) (EIA, 2013) and AWT International (AWT) (AWT, 2013) under the auspices of the US Department of Energy (US DOE) and the Australian Council of Learned Academies (ACOLA) respectively, have sought to quantify Australia’s shale gas resources. Both assessments included the Cooper Basin, but only considered the REM shale play. The extensive basin-centred and tight gas accumulations in the Gidgealpa Group and deep coal gas associated with the Patchawarra and Toolachee formations were overlooked. For the Cooper Basin, Risked Technically Recoverable Oil Resources of 1 billion bbls and 93 tcf of Risked Technically Recoverable Gas Resources were estimated, 89 tcf in the Nappamerri Trough and 4 tcf in the Patchawarra Trough (Table 1.2; EIA, 2013). AWT estimated a 49 tcf (35 tcf dry gas and 14 tcf wet gas) gas resource in the Nappamerri Trough (Table 1.3; AWT, 2013). Table 1.1: Total reported Cooper–Eromanga Basin gas reserves and resources at 30 June 2014, as published by AEMO (2015). One Petajoule (PJ) is the equivalent of 0.0011 trillion cubic feet (tcf) of gas (Carson, 2014). Resource Type

2P Reserves

3P/2C Reserves and Resources (Additional to 2P)

Prospective Resources

Total Reserves and Resources

PJ

tcf

PJ

tcf

PJ

tcf

PJ

tcf

1793

2.0

4855

5.3

3571

3.9

8426

9.3

CSG

0

0.0

0

0.0

38,852

42.7

38,852

42.7

Unconventional

5

0.0

6,652

7.3

162,910

179.2

169,562

186.5

1798

2.0

11507

12.7

205,333

225.9

216,840

238.5

Conventional

Total

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Table 1.2: Published Cooper Basin technically recoverable resource assessment results from the EIA/ ARI World Shale Gas and Shale Oil Resource Assessment (EIA, 2013). Risked Risked Risked Risked Technically Technically Technically Technically Recoverable Recoverable Recoverable Recoverable Associated Wet Gas Total Gas Dry Gas Gas

Risked Oil-inplace

Risked Technically Recoverabl e Oil

Risked Gas inplace

Billion bbl

Billion bbl

tcf

tcf

tcf

tcf

tcf

REM (Nappamerri Trough)

17

1

307

1

79

9

89

REM (Patchawarra Trough)

9

0

17

0

1

3

4

REM (Tenappera Trough)

3

0

1

0

0

0

0

Formations

Table 1.3: Published Cooper Basin technically recoverable resource assessment results from ACOLA/ AWT Engineering Energy (AWT, 2013). Formations

Best Estimate Recoverable Dry Gas

Best Estimate Recoverable Wet Gas

Best Estimate Recoverable Total Gas

tcf

tcf

tcf

35

14

49

REM (Nappamerri Trough)


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2 Regional Basin Model Construction

This chapter describes the construction of an internally consistent regional 3D model of the Cooper Basin, based on available open-file data primarily sourced from the Department of State Development (South Australia), the Department of Natural Resources and Mines (Queensland) and Geoscience Australia. The 3D model framework was based on existing interpretations (e.g. NGMA, 2001; DMITRE, 2001, 2009) with the following updates and modifications: •

Updated structural surfaces consistent with new open file well data (up to May 2015).

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Revised seismic interpretation in selected areas.

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Better integration of existing interpretations across the state border.

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Addition of structural surfaces and isopachs for the Daralingie and Epsilon formations and the Roseneath and Murteree shales.

Other published regional 3D models (Meixner et al., 2012; Nelson et al., 2012) and structure surface maps from recent well completion reports were also used as a guide to constraining the model geometry. Lithofacies maps were created for the entire basin, based on the electrofacies mapping study of Sun & Camac (2004) in South Australia. This includes new electrofacies analysis in Queensland, and updated analyses for wells in South Australia made available since 2004. Results are consistent with the formation isopachs generated from the 3D model and highlight net sand, silt, shale and coal distribution for key Permian formations across the entire Cooper Basin.

2.1 Data As a result of ~60 years of continuous exploration, the Cooper Basin region has the largest datasets of any onshore sedimentary basin in Australia (Carr et al., 2016). However, while there is good data coverage across most of the study area, certain data poor areas remain poorly constrained, including the eastern Nappamerri Trough and the depocentres in the northeastern basin. Basic pre-processing of all datasets was conducted prior to use to ensure consistency during integration into the 3D model. These steps included: •

Projection transformation to UTM 54S, if data was not already available in this coordinate system.

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Correction of elevations relative to the Australian Height Datum in metres (mAHD).

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Resampling of existing grids to 500 m grid cell size.

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Figure 2.1: Cooper Basin petroleum exploration wells, stratigraphic drill holes and 2D seismic data coverage (Carr et al., 2016). Cooper Basin outline from Stewart et al. (2013). Data displayed over topographic data (Whiteway, 2009).

2.1.1 Well Data Between 1959 and June 2015, there were over 3065 petroleum wells drilled within the known extent of the Cooper Basin as defined by Stewart et al. (2013), with ~2020 in South Australia and ~1045 in Queensland (Figure 2.1; GA, 2015a). In addition, many more wells have been drilled over the broader Cooper–Eromanga area. The well header data used in this study is sourced from the Geoscience Australia National Petroleum Wells Database (GA, 2015a). Formation tops and public domain wireline log data were sourced from the state survey databases, as follows: •

Queensland Petroleum Exploration Data (QPED) (DNRM, 2015)

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Petroleum Exploration and Production System–South Australia (PEPS–SA) (DSD, 2015)

Formation tops from the state databases were combined into a single database with formation names standardised to ensure consistency across the state border. Preferred names are consistent with the


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Geoscience Australia Stratigraphic Names Database (GA, 2015b). The database included approximately 1760 wells with tops intersecting the Cooper Basin section. This formation top set was then simplified to only capture the tops of the structure surfaces included in the 3D geological model. Basic quality checks were applied to the formation picks to ensure all depth and thickness values were geologically reasonable, but no further interpretation was undertaken.

2.1.2 Seismic Data Seismic data have been acquired across the Cooper Basin since the 1960s and the coverage of both 2D and 3D data is now extensive (Figure 2.1). Several vintages of open file interpreted seismic horizon data have been released for the Cooper Basin (Table 2.1): •

Structural surfaces and isopachs of significant seismic horizons in depth and two-way travel time current to 2001 for South Australia only (DMITRE, 2001).

•

Structural surfaces in depth and two-way travel time to the top of the Cadna-owie Formation, Permian succession and Warburton Basin, current to 2001 for all of the Cooper Basin (NGMA, 2001).

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Structural surfaces in depth and two-way travel time to the top of the Cadna-owie Formation, Permian succession and Warburton Basin, current to 2009 for South Australia only (DMITRE, 2009).

•

Additional seismic horizon maps are available from selected recent well completion reports, including. Boston 1, Encounter 1 and Gaschnitz 1 (Beach Energy 2013a, 2011a; Santos–Delhi– Origin, 2012).

Table 2.1: Cooper-Eromanga Basin seismic horizons interpreted in previous public domain studies. Horizon Description Name

Area – Vintage

Reference

a

Top Winton Formation at the base of the Tertiary

SA - 2001

DMITRE (2001)

c

Top Cadna-owie Formation

SA - 2009; QLD - 2001 DMITRE (2009); NGMA (2001)

h

Top Hutton Sandstone

SA - 2001

DMITRE (2001)

j

Base Eromanga Basin (also referred to as Top Cooper Basin)

SA - 2001

DMITRE (2001)

n

Top Nappamerri Group

SA - 2001

DMITRE (2001)

p

Top, or near top, of Permian sediments (Toolachee SA - 2009; QLD - 2001 DMITRE (2009); Formation) NGMA (2001)

r / ru

Top Daralingie unconformity & correlative unconformities

SA - 2001

DMITRE (2001)

rss

Top Daralingie Sandstone sediments

SA - 2001

DMITRE (2001)

v

Top Patchawarra Formation

SA - 2001

DMITRE (2001)

wx

Top Glacial sediments

SA - 2001

DMITRE (2001)

z

The top of what is traditionally considered 'Basement', usually the top of the Warburton Basin

SA - 2009; QLD - 2001 DMITRE (2009); NGMA (2001)

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2.1.3 Digital Elevation Data Digital elevation data used is derived from the Australian Bathymetry and Topography Grid (Whiteway, 2009). Input data resolution is 250 m.

2.1.4 Surface Geology The surface geology of the region is sourced from the 1:1 m scale Surface Geology of Australia dataset (Raymond et al., 2012).

2.1.5 Potential Field Data Geophysical data are available over the basin, including gravity and aeromagnetics. Airborne magnetic data is available across the Cooper Basin at a line spacing of 400 m or less (Milligan and Franklin, 2010; Milligan et al., 2010). In addition, full coverage of ground based gravity is available over the basin at generally greater than 4 km station spacing (Bacchin et al., 2008; Nakamura et al., 2011; Bacchin, 2015a, b) These datasets provide valuable insight into the subsurface architecture of the stacked Eromanga, Cooper, and Warburton basins, which were particularly useful for mapping the basement ridges and troughs within the region. Nevertheless, they were not used directly in the construction of the regional geological model.

2.1.6 Published Data Packages Several published studies provide additional data and constraints for the regional Cooper Basin model that was constructed for this study. Meixner & Holgate (2009) and Meixner et al. (2012) produced a 3D model of the Cooper Basin region using geologically constrained inversions of Bouguer gravity data. The model was used to predict temperatures and their uncertainty throughout the basin down to 4–5 km depth, to aid geothermal exploration. Although the model does not contain enough horizons to effectively map out the key petroleum systems elements within the Cooper Basin, it does provide a useful starting point for development of the regional 3D model discussed here. In addition, the model delineates regions of low density within the basement of the Cooper and Eromanga basins that are inferred to be granitic bodies. This helps to delineate the distribution of the high-heat-producing granites, including the granodiorite of the Big Lake Suite (BLS) at the base of the Cooper and Eromanga basins. As part of the Great Artesian Basin Water Resource Assessment (GABWRA) (Smerdon and Ransley, 2012; Smerdon et al., 2012), a 3D model of the GAB was published with an accompanying report (Nelson et al., 2012; GA, 2013). Whilst not directly focused on the Cooper Basin, the published model provided useful regional constraints on the regional geometry and stratigraphy of the overlying Eromanga Basin. An additional review of the Cooper Basin and associated data listings have also been compiled as part of the more recent groundwater-focussed bioregional assessment study for the region (Smith et al., 2015a,b,c)


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Additional datasets and supplementary information can be found on the state survey websites: •

Department of State Development, SA Petroleum website http://petroleum.statedevelopment.sa.gov.au/

•

Queensland Government, Mining and Resources website https://www.business.qld.gov.au/industry/mining/geoscience-data-information

2.2 Interpretation 2.2.1 Review of Existing Seismic Interpretation in TWT All available seismic and well data were loaded into the Petrel software platform (http://www.software.slb.com/products/petrel) by 3D GEO Pty Ltd. More than 8189 2D seismic lines were included in the project. Seismic lines that were not loaded were either of poor quality or did not contain all required navigation information. Also provided were preliminary seismic interpretations for key horizons. Existing Cooper Basin seismic interpretations published by state surveys were reviewed in two-way travel time (TWT) based on well and seismic data in the Petrel project. The purpose of this review was not to reinterpret all horizons, but to update existing interpretations in selected areas, to ensure: •

structural surfaces were consistent with new open file well data (up to May 2015)

•

better integration of structural surfaces across the state boarder.

Additional horizons were interpreted for the Daralingie and Epsilon formations and the Roseneath and Murteree shales, where data permitted. No additional interpretation or review was conducted for the overlying Eromanga Basin horizons. The typical characteristics of each horizon are described in Table 2.2 and are shown in Figure 2.2, although these can vary greatly across the basin. In particular, the character of top pre-Permian basement is influenced by variations in the underlying basement lithology, which includes Proterozoic metamorphic rocks, Warburton Basin sedimentary rocks and volcanic rocks, sedimentary rocks equivalent in age to the Devonian Adavale Basin and the Big Lake Suite granodiorites (Boucher, 1997; Alexander et al., 1998). For each horizon, TWT data from seismic lines were gridded with available well data, in order to produce a final map, which tied in all available wells. Pre-existing interpreted horizons were used as trend surfaces to ensure the maximum information content for these was carried across. Well velocity data and hence TWT was limited to 761 of the 3749 wells, as a result, additional well adjustments were required when TWT was converted into depth (see further discussion below). Table 2.2: Description of Cooper Basin seismic horizons. Seismic Horizon

Horizon Description

Top Nappamerri Group (n-horizon)

Moderate to strong, continuous negative reflector

Top Toolachee Formation (p-horizon)

Strong, continuous positive reflector, marking the top of coaly horizons

Top Daralingie Formation (r-horizon)

Moderate to strong positive reflector, sometimes showing unconformable relationship with the overlying units

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Seismic Horizon

Horizon Description

Top Roseneath Shale (s-horizon)

Moderate, continuous negative reflector, representing the top of the shale interval

Top Epsilon Formation (t-horizon)

Moderate, continuous to intermittent, positive reflector. Hummocky

Top Murteree Shale (u-horizon)

Moderate to strong, continuous negative reflector, representing the top of the shale interval

Top Patchawarra Formation (v-horizon)

Moderate, intermittent, positive reflector

Top Glacial sediments (wx-horizon)

Variable

Top pre-Permian basement (z-horizon)

Mostly represented by a moderate to strong positive reflector, showing unconformable relationship with the overlying units

2.2.2 Velocity Analysis and Depth Conversion A total of 813 wells were assessed for velocity information. Velocity data were analysed for 137 wells in the basin and of these, 47 wells had synthetic seismogram data. Velocity data were either checkshot or VSP surveys. Wells with inconsistent data were excluded from any further analysis. An average velocity map was calculated for the top Nappamerri Group surface. Interval velocity maps were then generated based on check-shot data, for each key Cooper Basin interval. TWT structural surfaces were converted to depth surfaces using the derived velocity model.

Figure 2.2: Example seismic picks around Burley 2 in the Nappamerri Trough.


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2.2.3 Regional 3D Basin Model The converted depth surfaces (relative to the Australian Height Datum in meters) and the surface elevation data were migrated into Zetaware’s Trinity basin modelling software tool kit (www.zetaware.com). All datasets were then combined into a 3D geological model (Figure 2.3). To ensure internal consistency of the model, significant further adjustments were required of the depth surfaces and associated isopachs. Key modifications included: •

additional warping of structure surfaces to fit well picks, not included in initial TWT interpretation due to the lack of available check shot data

•

correction of isopachs to ensure these reached 0 thickness at the interpreted edge of formation extent

•

removal of interpolation errors where formation isopach thicknesses were much less than the spacing of the data points.

The final structural surfaces exported from the 3D model for all Cooper Basin horizons are presented in Figure 2.4. Isopachs calculated from the model are shown in Chapter 6.

Figure 2.3: Oblique view of the regional 3D geological model of the Cooper Basin, looking north. The structural surface shown is top “pre-Permian” basement clipped to the Cooper Basin outline (Stewart et al., 2013). For more detailed images of the cross-sections shown, please refer to Figure 3.4.

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Figure 2.4 a): Cooper Basin structure surfaces in depth (m) extracted from the 3D model.


17

Figure 7 b): Cooper Basin structure surfaces in depth (m) extracted from the 3D model.

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2.3 Electrofacies Analysis Electrofacies analysis was used to provide data on the thickness and percentage of electrofacies for the Patchawarra, Epsilon, Daralingie and Toolachee formations. This study builds on the work of Sun & Camac (2004) conducted for the South Australian part of the basin, by: •

inclusion of additional data for the Queensland region of the basin

•

incorporation of additional results from wells drilled in the Weena Trough and surrounds since the completion of the Sun & Camac study (John Morton, pers. comm. September 2015).

2.3.1 Methodology A brief overview of the electrofacies mapping methodology as applied by Sun & Camac (2004) is given below. Refer to that report for a more detailed description of the electrofacies mapping workflow and calibration steps. Cut-off values were determined from calibration of drill core facies and geophysical log signatures for four electrofacies: coal, clean sandstone, silty or muddy sandstone, and siltstone/shale. These are intended to provide a general guide for interpretation of Cooper Basin lithofacies distribution and palaeogeography, leading to improved prediction of reservoir, source and seal rocks. Wireline log values were used to establish quantitative electrofacies, highlighting different lithologies. For the chosen wells, digital gamma-ray and sonic logs were used to determine the thickness of certain facies over specific formation intervals. Electrofacies values should be corrected for environmental effects, such as the addition of KCl (potassium chloride) to drilling mud, which elevates gamma response. An average reduction of 20 API has been applied to the gamma ray value for all wells drilled with KCl mud. Table 2.3: Electrofacies criteria for the Cooper Basin from Sun & Camac (2004). Lithology

Gamma Ray (API)

Sonic (μsecs/ft)

Coal

not applicable

≥ 115

Clean sandstone

≤ 80

N/A

Silty sandstone/coarse siltstone

> 80 and < 130

N/A

Silty shale

> 130

N/A

Carbonaceous mudstone/shale

>145

N/A

2.3.2 South Australia This study used the electrofacies of the 830 wells from South Australia (Sun & Camac, 2004). Minor modifications were applied in the southwest corner of the basin to include updated coal thickness data, based on well completion reports for selected wells drilled since the completion of the Sun & Camac study (John Morton, pers. comm. September 2015).


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2.3.3 Queensland Existing electrofacies for Queensland wells (Draper, 2002) were calculated using a different method and cut-offs than the Sun & Camac (2004) electrofacies of the South Australian section of the basin. To align the electrofacies for the Queensland section of the Cooper Basin with those of South Australia, new electrofacies calculations were conducted on 136 wells from the Queensland section of the Cooper Basin, using the criteria of Sun & Camac (2004) (Table 2.3). Wells were initially selected based on those with TOC samples in the Gidgealpa Group, constrained by those with available digital wireline log data. Additional wells were added to build a better coverage across the full extent of the basin. Of the 136 wells selected, 20 wells were outside the extent of the Gidgealpa Group, and have been excluded from gridding. Where available, density (RHOB) was used in preference to sonic logs to delineate coal based on a 3 cut-off of 1800 kg/m . This was calibrated against the sonic cut-off (115 µs/ft) of Sun & Camac (2004) and found to be in good agreement. The remaining electrofacies were calculated based on the cut-offs listed in Table 2.3. The same correction of 20 API was used for wells drilled on KCl mud.

2.3.4 Gridding The electrofacies isolith and isopach maps were gridded using the surface modelling module within the Petrosys software (http://www.petrosys.com.au/) according to the following workflow. 1. Isolith map grids were created for sand, silt, shale and coal as a percentage of the total formation thickness. a. The Petrosys standard gridding algorithm was applied. b. Grids were clipped to the appropriate formation extents from the 3D model. c. Grids were renormalised to ensure that isoliths grids added up 100% in all areas. 2. Net isopach thickness maps in metres were created by multiplying the isolith map in percentage by the gross formation thickness from the 3D model. 3. Grids and associated contours were exported to ArcGIS. The electrofacies mapping study results are discussed in detail in Chapter 5.

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3 Structural setting

This chapter reviews the major structural elements of the Cooper Basin, in the context of the updated 3D basin model. 2

2

The Cooper Basin covers an area of approximately 127,000 km , 33,000 km in northeastern South 2 Australia and 94,000 km southwestern Queensland, as estimated from the Cooper Basin outline defined by Stewart et al. (2013) (Figure 3.1; Figure 3.2). It represents a Pennsylvanian to Triassic depositional episode that ceased at the end of the Middle Triassic, due to widespread contractional folding, uplift and erosion (Gravestock & Jensen-Schmidt, 1998; Draper, 2002; McKellar, 2013). The Cooper Basin is over 4400 m deep and the unconformity at its upper surface varies in depth below present land surface from 970 m to 2800 m (Figure 3.1; Figure 3.2; Figure 3.3; Figure 3.4). The Cooper Basin is divided into northeastern and southwestern areas, which show different structural and sedimentary histories, and are separated by a series of northwest–southeast trending ridges, known as the Jackson–Naccowlah–Pepita (JNP) Trend (Heath, 1989; McKellar, 2013). The three major troughs in the southwest (Patchawarra, Nappamerri and Tenappera troughs) are separated by the Gidgealpa–Merrimelia–Innamincka (GMI) and Murteree ridges, which approximately align northeast–southwest, and are parallel to the main depositional axis of the basin (Figure 3.1; Figure 3.2; Gravestock & Jensen-Schmidt, 1998). In the northeastern Cooper Basin, the Permian succession is thinner than in the southwest, and the major depocentres, including the Windorah Trough and Ullenbury Depression, are generally less well defined (Draper, 2002; McKellar, 2013).


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Figure 3.1: Cooper Basin structural elements overlain on the pre-Permian basement horizon. The outline of the Cooper Basin is from Stewart et al. (2013). Structural elements are modified from Gravestock & Jensen-Schmidt (1998), Draper (2002), Ransley et al. (2012) and McKellar (2013).

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Figure 3.2: Structural elements of the Cooper Basin overlain on total Cooper Basin sediment thickness in metres. The outline of the Cooper Basin is from Stewart et al. (2013). Structural elements are modified from Gravestock & Jensen-Schmidt (1998), Draper (2002), Ransley et al. (2012) and McKellar (2013).


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Figure 3.3: Location map for regional cross-sections through the Cooper Basin shown in Figure 3.4.

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Figure 3.4a: Regional cross-sections through the Cooper Basin extracted from the 3D model. Cross-section location map is shown in Figure 3.3.


25

Figure 11b,c: Regional cross-sections through the Cooper Basin extracted from the 3D model. Cross-section location map is shown in Figure 3.3.

26


Figure 11d,e: Regional cross-sections through the Cooper Basin extracted from the 3D model. Cross-section location map is shown in Figure 3.3.


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3.1 Structural Elements The Cooper Basin is divided into northeastern and southwestern areas, which show different structural and sedimentary histories, and are separated by the JNP Trend (Heath, 1989; Gravestock & JensenSchmidt, 1998; McKellar, 2013). Depocentres in the southwestern Cooper Basin are generally deeper and contain a thicker and more complete Permian succession than the northeastern basin (Hill & Gravestock, 1995; McKellar, 2013). Each region can be further divided into discrete troughs and ridges (Figure 3.1; Figure 3.2; Figure 3.4), which are described in more detail below.

3.1.1 Troughs 3.1.1.1 Nappamerri Trough The Nappamerri Trough contains the thickest sedimentary succession in the Cooper Basin. The trough is deepest in its eastern half, where it reaches depths over 4400 m and contains a Pennsylvanian to Triassic succession up to ~2400 m thick (Figure 3.1; Figure 3.2; Figure 3.4; Gravestock & Jensen-Schmidt, 1998). Although the Halifax 1 well does not reach basement, it intersects the deepest Permian sediments drilled in the basin to date, at a total depth of 4209 m (Beach Energy, 2013b). The trough trends northeast–southwest, and is bound by major structures both to the northwest and southeast. The southwestern end of the Nappamerri Trough appears to be compartmentalised by north-northwest to northwest-trending structures (Gravestock & JensenSchmidt, 1998). These may mark the location of strike-slip faults in the underlying Warburton Basin succession (Kuang, 1985; Apak et al., 1997).

3.1.1.2 Wooloo and Allunga troughs The Wooloo Trough lies to the west of the Nappamerri Trough and is separated from it by northweststriking strike-slip faults (Boucher, 1991). The Allunga Trough runs parallel to the Nappamerri Trough, intersecting the southern end of Wooloo Trough (Figure 3.2; Figure 3.4). At its eastern end, the Allunga Trough transitions into the Dunoon Embayment. The Wooloo and Allunga troughs contain a maximum thickness of Permian–Triassic rocks of 1000 to 1200 m, and reach maximum depths of up to 3100 m (Figure 3.1; Figure 3.2).

3.1.1.3 Tenappera Trough The Tenappera Trough is an indistinct northeast–southwest trending structural depression separated from the Nappamerri Trough to the north by the Murteree Ridge (Gravestock & Jensen-Schmidt, 1998). Although much shallower than the Nappamerri Trough (with a maximum depth of around 3000 m), this depocentre contains a considerable thickness of Permian–Carboniferous strata of over 1000 m (Figure 3.2; Figure 3.4).

3.1.1.4 Patchawarra Trough The Patchawarra Trough is located entirely within South Australia, and trends northeast–southwest along the northwestern margin of the basin. It is subtly compartmentalised by northwest-trending structures that are interpreted to mark an underlying strike-slip fault assemblage through the Warburton Basin (Roberts et al., 1990; Gravestock & Jensen-Schmidt, 1998).

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The Patchawarra Trough reaches a maximum depth of over 3650 m (Figure 3.1; Figure 3.4). Although the thickness of the Cooper Basin succession in this trough reaches a maximum of 1000 m, it is still less than half of that in the Nappamerri Trough (Figure 3.2), with significant sections of the Permian rocks missing as a result of non-deposition or erosion at the mid Permian Daralingie unconformity (Gravestock & Jensen-Schmidt, 1998).

3.1.1.5 Weena Trough and Milpera Depression The Weena Trough lies in the southwest corner of the basin. It is aligned east–west and has a flatbottomed, steep-sided geometry (Gravestock & Jensen-Schmidt, 1998; Simon, 2000). This trough has been interpreted as a Pennsylvanian glacial valley by Gravestock & Jensen-Schmidt (1998). Maximum depths reach only around 2240 m, although the total thickness of the Cooper succession reaches over 1000 m (Figure 3.1; Figure 3.2; Figure 3.4). The Milpera Depression lies to the north of the Weena Trough and reaches a depth of over 2100 m. Although the full Cooper Basin section is not penetrated, a minimum of ~490 m of Permo-Triassic sediments were intersected in Davenport 1 (Beach Energy, 2012a).

3.1.1.6 Arrabury Trough The Arrabury Trough is a poorly defined feature which lies immediately to the north of the JNP Trend (McKellar, 2013). The northwestern part of this trough is a deep embayed extension to the Patchawarra Trough but, eastwards, this depocentre is shallower and more irregular. Depocentre geometries are less well constrained than to the south, but limited well intersections give a maximum depth of around 3050 m and a maximum Cooper Basin succession thickness of 770 m (Figure 3.1; Figure 3.2; Figure 3.4).

3.1.1.7 Windorah Trough The central part of the northern Cooper Basin forms the Windorah Trough (Figure 3.1; Figure 3.2; McKellar, 2013). These depressions are separated by a subtle northeast-trending high, and collectively overlie the Devonian Barrolka Trough (Figure 4.2; Draper et al., 2004). The Windorah Trough coincides with the curved axis of the Cooper Syncline of Hoffmann (1989) and the PermoTriassic succession thickens into these depressions. Well intersections indicate that Permian sediments reach depths of over 3000 m and a total thickness for the Cooper Basin succession of over 625 m (Figure 3.1; Figure 3.2; Figure 3.4).

3.1.1.8 Ullenbury Depression The northern Cooper Basin extends to the northeast into the Ullenbury Depression. The Ullenbury Depression is deeper than the other northern depocentres (maximum depth 2750 m). Although poorly constrained, the total thickness of the Cooper Basin succession is only estimated to reach 500 to 600 m (Figure 3.1; Figure 3.2; Figure 3.4). The Ullenbury Depression has a pronounced asymmetric tilt deepening to the northwest, where it ends abruptly against the uplifted zone between the Morney and Warbreccan Anticlines. This depression is elongate and constrained by the parallel Harkaway and Windorah anticlines (Figure 3.1).

3.1.1.9 Thompson Depression Northeast of the Ullenbury Depression and Windorah Trough, the regional depocentre terminates in the shallower Thompson Depression, which overlies the Devonian succession of the Warrabin Trough


29

(Figure 4.2; Draper et al., 2004). Limited well intersections give a maximum depth of around 2545 m and a maximum thickness for the Cooper Basin succession of about 300 m (Figure 3.1; Figure 3.2; Figure 3.4).

3.1.2 Ridges 3.1.2.1 Gidgealpa, Merrimelia, Packsaddle and Innamincka ridges In the southern part of the basin, the most prominent structural highs are the Gidgealpa, Merrimelia, Packsaddle and Innamincka ridges (Figure 3.1; Figure 3.2; Figure 3.4; Gravestock & Jensen-Schmidt, 1998; McKellar, 2013). These are located partly in-line and partly en-echelon, to form an arcuate southwest–northeast trending ridge complex (GMI trend), separating the Nappamerri and Patchawarra troughs. Each ridge is asymmetric with major faults bounding the northern margin, and minor faults on the southern margin (Gravestock & Jensen-Schmidt, 1998). Some are demonstrably cored by deep thrust faults in the underlying Warburton Basin (Roberts et al., 1990), which were reactivated during episodes of contraction from the Permian to the Cenozoic (Sun, 1997).

3.1.2.2 Dunoon, Murteree and Della–Nappacoongee ridges Further south are the northeast-trending Dunoon, Murteree and Della–Nappacoongee ridges (commonly known as the MN trend), which separate the Allunga and Nappamerri troughs from the Tenappera Trough (Gravestock & Jensen-Schmidt, 1998; McKellar, 2013). The Dunoon and Murteree ridges are flat-topped, symmetrical ridges, faulted on both sides, whereas the major bounding fault for the Della–Nappacoongee Ridge is on its northern side. These ridges have been considered to have developed as a result of reactivation of northwestdirected thrust faults in the underlying Warburton Basin during a deformational event penecontemporaneous with the Devonian–Carboniferous Alice Springs Orogeny in central Australia and the Middle–Late Carboniferous Kanimblan Orogeny in eastern Australia. It has been suggested that this created a high-relief paleotopography that controlled facies deposition in the troughs (Gravestock & Jensen-Schmidt, 1998). Timing and mechanisms of tectonics, however, remain debated. Both well and seismic data show that along many of the more prominent ridges, the Permian is eroded and Triassic strata are thin (Figure 3.2; Figure 3.4). For example, the Dunoon and Murteree ridges are devoid of Permian–Triassic sediments (Figure 3.2).

3.1.2.3 Tinga Tingana Ridge The Tinga Tingana Ridge strikes north–south, stretching from the southern margin of the Cooper Basin to the Dunoon Ridge, separating the Weena Trough from the rest of the Cooper Basin (Gravestock & Jensen-Schmidt, 1998).

3.1.2.4 Jackson – Naccowlah – Pepita (JNP) Trend The JNP Trend marks the boundary between the northeastern and southwestern Cooper Basin (Figure 3.1; Figure 3.2; Figure 3.4; Heath, 1989; Hill & Gravestock 1995; McKellar, 2013). It aligns west-northwest to east-southeast and extends to the southeast beyond the Cooper Basin. The JNP Trend is most prominent on the southeastern side of the Cooper Basin, where it marks the northern boundary of the Nappamerri Trough.

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3.1.2.5 Northwest trending structures Prominent northwest-trending ridges bound the major depocentres in the northeast part of the basin, and include the Durham Downs, Harkaway and Windorah anticlines (Figure 3.1; Figure 3.2; Figure 3.4). In the zone northeast of the Harkaway Anticline, the anticlines are faulted along their main axes, with modest down-throw on their northeastern flanks. These disruptions change from thrust faults at the southeastern margin of the basin to extensional faults northwestwards into the basin (Hoffmann, 1989).

3.1.2.6 North trending structures North-trending ridges lie to the southeastern side of the northeastern Cooper Basin, including the Mount Howitt Anticline, Chandos Anticline, and the Canaway Ridge (Figure 3.1; Figure 3.2; Figure 3.4). The thrust faulted Canaway Ridge marks the northeastern boundary of the Cooper Basin, separating the Cooper Basin from concurrent deposition farther east in the southern Galilee and Bowen basins (Hoffmann, 1989; McKellar, 2013).

3.1.2.7 Northeast to north-northeast trending structures Along the shallower, northwestern margin of the northeastern Cooper Basin lie a series of northeast to north–northeast trending anticlines and ridges. This structural belt includes the Warbreccan, Morney and Betoota anticlines, the Curalle Dome and the Mount Howie Ridge (Figure 3.1). This belt transitions southwestwards into the Deramookoo Shelf and the Birdsville Track Ridge, which separates the Cooper from the Pedirka Basin to the northwest (Hibburt & Gravestock 1995). This structural belt is part of a major north-northeast trending belt of en-echelon faults that extends from the Adelaide Rift System through to northern Queensland (Sprigg, 1986; Campbell & O’Driscoll, 1989). Contractional reactivation of these structures occurred in the mid Miocene (Ambrose et al., 2007), and uplifts in the order of 350 m to 500 m occurred near the margin of the basin during the Cenozoic (Krieg, 1985; Foster et al., 1994; Alexander & Jensen-Schmidt, 1995).

3.1.3 Basement inheritance The complex structural fabric in the northern Cooper Basin appears to have been inherited from basement features, but was reactivated and superimposed on the Cooper Basin succession postdeposition, during and after the Late Cretaceous (Hoffmann, 1989). This is consistent with the total Cooper Basin sediment thickness variation across the northern part of the basin, which suggests that this region was not as influenced by paleotopography as was the southern region (Figure 3.2).


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4 Tectonic Evolution

This chapter presents an overview of the late Neoproterozoic to Cenozoic evolution of the Cooper Basin region in the context of the broader tectonic evolution of eastern Australia. The Cooper Basin unconformably overlies lower Paleozoic sedimentary and volcanic rocks of the Warburton Basin to the southwest and Devonian sedimentary rocks associated with the Adavale Basin (including the Barrolka and Warrabin troughs) in the northeast (Figure 4.1; Figure 4.2; Gravestock & Jensen-Schmidt, 1998; Draper, 2002, Radke, 2009; Stewart et al., 2013). The Warburton Basin transitions into Cambrian–Ordovician metasedimentary rocks of the Thomson Orogen in the east and northeast (Purdy et al., 2013; Stewart et al., 2013). The Cooper Basin is entirely and disconformably overlain by the Jurassic–Cretaceous Eromanga Basin, which in turn is unconformably overlain by the Cenozoic Eyre Basin (Stewart et al., 2013). The late Neoproterozoic to Cenozoic evolution of the Cooper Basin region is summarised in Figure 4.1 (Champion et al., 2009).

4.1 Pre-Permian Basement Evolution Pre-Permian basement to the Cooper Basin represents a series of sedimentary basins and metamorphic terranes. There is also evidence for igneous activity within the basement rocks. These elements are described in the following sections.

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Figure 4.1: Late Neoproterozoic to Cretaceous time–space plot for the Cooper Basin region, adapted from Champion et al. (2009).


33

Figure 4.2: Pre-Permian geological provinces (Stewart et al., 2013) superimposed on regional gravity (Bacchin et al., 2008). Location of the Barrolka and Warrabin troughs are from Draper et al. (2004). Big Lake Suite granodiorite locations are from Meixner et al. (2012). The major crustal boundaries are from Korsch & Doublier (2015a, b).

4.1.1 Metamorphic Basement The eastern part of the Cooper Basin is underlain by Cambrian–Ordovician metasedimentary rocks of the Thomson Orogen (Figure 4.2), a component of the Tasmanides of eastern Australia, which also includes the Delamerian Orogen, Lachlan Orogen, Mossman Orogen and New England Orogen (Purdy et al., 2013). The southwestern boundary of the Thomson Orogen remains poorly defined (Purdy et al., 2013), and its relationship with the coeval Warburton Basin is essentially unknown. The southern part of the Cooper Basin may be underlain by the North Flinders arm of the Adelaide Rift System (Meixner et al.,

34


2012). It has been suggested that basement below the southern Cooper Basin and Warburton Basin consists of the northeastern Gawler Craton and the northern extension of the Delamerian Orogen (Korsch & Doublier, 2015a, b).

4.1.2 Cambro–Ordovician Warburton Basin The central and western Cooper Basin is unconformably underlain by sedimentary and volcanic rocks of the Cambrian–Ordovician Warburton Basin (Figure 4.1; Figure 4.2), which is discussed in detail in Roberts et al. (1990), Sun et al. (1994), Gravestock & Gatehouse (1995), Sun (1997), Purdy et al. (2013) and Draper (2013). The basin includes shallow shelf, slope and basin sediments of the Kalladeina Formation (carbonates) and deep water sediments of the Dullingari Group (shale, siltstone and chert), which were deposited along the margins of the Australian craton (Boucher, 2001; Radke, 2009; Draper, 2013). The Warburton Basin transitions into the Thomson Orogen to the northeast, as greenschist-grade metasedimentary rocks (Draper, 2006; Purdy et al., 2013). The Warburton Basin was subject to deformation and erosion in the Silurian Benambran/ Alice Springs Orogeny phase 1 (Figure 4.1; Gatehouse, 1986; Champion et al., 2009). Thrusting of the upper Warburton succession resulted in the creation of significant paleotopographic ridges. As a result, by the time of initial glacial deposition in the southwestern Cooper Basin in the Pennsylvanian to early Permian, there may still have been 600 m relief between depocentres. 2

Approximately 13,000 km of basement under the southwestern part of the Cooper Basin may have experienced shock metamorphism from a mega-bolide impact. Such an impact possibly triggered crustal rebound, emplacement of the Big Lake Granite (see below), and subsequent isostatic rise of the eastern Warburton Basin (Glikson et al., 2013a, b). Distinct zones of alteration within the Cooper and Warburton basins (Boucher, 1997) may be attributed to hydrothermal alteration following such a shock metamorphic event or to the movement of hydrothermal fluids from an as yet unknown magmatic source.

4.1.3 Devonian Adavale Basin system The Adavale Basin system, as defined by Draper et al. (2004), collectively refers to the Adavale Basin and other remnants of Devonian sedimentary and volcanic rocks in the region. Although the main Adavale Basin lies to the east of the Cooper Basin, Devonian aged sedimentary rocks are intersected in the Warrabin and Barrolka troughs, beneath the northeast Cooper Basin (Figure 4.1; Figure 4.2; Murray, 1994; Draper et al., 2004; McKillop, 2013), and can be identified on seismic data. The Adavale Basin developed initially in the Early Devonian as an intracontinental volcanic rift basin (Finlayson et al., 1988; Draper et al., 2004; McKillop, 2013). Deposition terminated with the onset of northwest to southeast oriented contraction associated with the third Devonian–Carboniferous phase of the Alice Springs Orogeny (ca 340–300 Ma; Figure 4.1). The deformation resulted in the development of regional-scale folds and widespread erosion (McKillop et al., 2005; Champion et al., 2009).


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4.1.4 Silurian and Carboniferous Granite Emplacement Two periods of granite emplacement have been inferred prior to onset of deposition of the Cooper Basin; one in the Silurian and the other in the Carboniferous (Draper et al., 2004; Figure 4.1). In southwest Queensland, Roseneath 1 intersected biotite-muscovite granite beneath the Cooper Basin, which yields a K–Ar muscovite age of 405 ± 2 Ma (Murray, 1986; 1994). About 100 km to the east, just beyond the limits of the Cooper Basin, a similar biotite–muscovite granite in Ella 1 has a K–Ar muscovite age of 408 ± 2 Ma (Murray, 1994); SHRIMP age dating on zircon from this granite has given a crystallisation age of 428 ± 5 Ma (L.P. Black, in Draper, 2006). This suggests that the granite in Roseneath 1 has a similar crystallisation age to that from Ella 1. Other granites intersected beneath the Cooper Basin in Queensland (e.g. Wolgolla 1, Tickalara 1, Budgerygar 1) have yet to be dated. Obtaining ages from these granites would provide a significant additional constraint on the evolution of the Cooper Basin. In South Australia, granites have been intersected in the basement beneath the Cooper Basin, mainly beneath the Nappamerri Trough (Figure 4.2). These are referred to as the Big Lake Suite (BLS) and consist of granodiorite and are mainly S-type granites (Gatehouse et al., 1995). Zircon from Moomba 1 gave SHRIMP U-Pb age of 323 ± 5 Ma (latest Mississippian to basal Pennsylvanian), and zircon from granite in McLeod 1 had a SHRIMP U-Pb age of 298 ± 4 Ma (basal Permian) (Gatehouse et al., 1995). The oldest sedimentary unit in the Cooper Basin, the Merrimelia Formation, is inferred to have been deposited in the Late Pennsylvanian (Figure 4.1; Figure 4.3). This formation occurs above the granite sample in McLeod 1, suggesting an age relationship problem, with the granite age being younger than the age of the overlying sediment; although, the Moomba 1 granite age accords with the inferred depositional age of the Merrimelia Formation. Re-dating of these granites is now underway. Marshall (2013) dated zircon from granite samples collected from five wells in South Australia which penetrated the Big Lake Suite by U–Pb LA–ICP–MS. Marshall considered that the granites had emplacement ages ranging from 326 Ma to 277 Ma; four of the samples contained older inherited zircon, which ranged in age from 420 Ma to 406 Ma. Ages obtained on granite from specific wells are: Moomba 1 – 326 ± 7 Ma (inheritance 417 ± 13 Ma); Jolokia 1 – 318 ± 13 Ma; Habanero 1 – 315 ± 10 Ma (inheritance 420 ± 15 Ma); McLeod 1 – 307 ± 8 Ma (inheritance 415 ± 12 Ma); and Big Lake 1 – 277 ± 11 Ma (inheritance 406 ± 18 Ma). The inherited ages of zircons in the wells in South Australia are all within error of the crystallisation age of the granite in the well Ella 1 in Queensland. In Big Lake 1, the granite occurs beneath the Tirrawarra Sandstone, which is latest Pennsylvanian to Asselian (ca. 300–295 Ma; Figure 4.1; Figure 4.3). The age of the sediment is significantly older than the emplacement age of the granite determined by Marshall (2013). No evidence of contact metamorphism has been described in this drill hole and the basement below the Tirrawarra Sandstone is described as being weathered granite on top of fresher but still weathered granite (Wiltshire, 1972). Recently, Middleton et al. (2014a) dated zircon from the Big Lake Suite granite in the Habanero 1 well by LA–ICP–MS. Analyses from 24 zircon grains gave an age of 421 ± 4 Ma, and 10 analyses gave younger ages which spread from 345 ± 15 Ma to 274 ± 12 Ma. Clearly, the differing ages of the granites currently available, and the age relationships with the overlying sedimentary rocks of the Cooper Basin, are yet to be resolved. In developing a 3D map of the Cooper Basin, Meixner et al. (2012) used a density model based on the inversion of gravity data to infer the lateral extent of the Big Lake Suite and other granites beneath the Cooper Basin. They infer the presence of several other granitic plutons which have yet to be intersected by drilling.

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40

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K-feldspar Ar– Ar thermochronology and illite Rb–Sr dating support an elevated thermal regime lasting 20–30 Ma in the Pennsylvanian, which was attributed to incremental intrusion of the Big Lake Suite (McLaren & Dunlap, 2006; Middleton et al., 2014b). Emplacement of the granites could potentially be syn-tectonic with the Mount Eclipse Phase of the Alice Springs Orogeny (Sun, 1997; Champion et al., 2009). Granodiorites of the Big Lake Suite are associated with a present day elevated thermal anomaly in the Nappamerri Trough (e.g. Middleton, 1979; Beardsmore, 2004; McLaren & Dunlap, 2006; Meixner & -2 Holgate, 2009; Meixner et al., 2012). Vertical heat flow above the granite ranges from about 90 mWm -2 to over 110 mWm , but decreases towards and beyond the edge of the granodiorite (Beardsmore, 2004). Thus, high surface heat flow is thought to originate from the Big Lake Suite granites that are enriched in the heat-producing elements uranium, thorium and potassium. Measured concentrations of -3 U, Th and K give a total volumetric heat production in the range of 7.2–10.1 µWm (Middleton, 1979; McLaren & Dunlap, 2006; Meixner et al., 2012). This is considerably higher than the basement heat -3 production of average upper crustal rocks of 1.7 µWm (Beardsmore and Cull, 2001: Rudnick & Gao, 2003; Meixner et al., 2012). In contrast, other granites in the region do not appear to be associated with elevated heatflow. Meixner et al. (2012) assigned these granites heat production values of 1.9– -3 2.5 µWm based on a median value of Australian granites from the OZCHEM database (Champion et al., 2007). The high heat-producing granites of the Big Lake Suite likely had a significant local thermal effect on the sediments deposited above them.

4.2 Basin Evolution: Pennsylvanian to Holocene The Pennsylvanian to Holocene structural and stratigraphic evolution of the Cooper Basin can be divided into three main stages of basin formation (Figure 4.1; Figure 4.3; Moussavi-Harami, 1996a; Gravestock & Jensen-Schmidt, 1998; Draper, 2002; McKellar, 2013): •

Stage I: Pennsylvanian to Triassic Cooper Basin

•

Stage II: Jurassic to early Cretaceous Eromanga Basin

•

Stage III: Cenozoic Lake Eyre Basin.

The divisions between each depositional stage were driven by regional tectonic activity along the convergent eastern Australian plate margin (e.g. Veevers, 1984; Gallagher, 1988; Korsch et al., 2009b; Raza et al., 2009; Bryan et al., 2012). Stratigraphy of the Cooper Basin has been updated for this study (after Price et al., 1985; McKellar et al., 1999; Gray & McKellar, 2002; Goldstein et al., 2012; McKellar, 2013; Metcalfe et al., 2014; DSD, 2015a; Nicoll et al., 2015; J.L. McKellar, pers. comm., April 2015; G.R. Wood, pers. comm., April 2015) and is shown in Figure 4.3. The new formation ages, the timings of key tectonic events and erosion estimates discussed below are assigned to the 3D geological model, enabling extraction of time-slice cross-sections through the basin, capturing the regional burial history of the Cooper-Eromanga-Lake Eyre succession (Figure 4.4).


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4.2.1 Pennsylvanian–Triassic Cooper Basin The Cooper Basin formed in an intraplate setting, well inboard of the convergent plate margin affecting eastern Australia. Although the basin is relatively well studied, the tectonic history of the Cooper Basin is complex and is still poorly understood, so debate still continues regarding the basin’s origin and geological history (Draper & McKellar, 2002; McKellar, 2013). Numerous authors have suggested that the Cooper Basin initiated as an intracratonic sag basin due to thermal subsidence, possibly as a result of deep mantle processes or related to high heat flow from the high heat-producing granites of the Big Lake Suite and punctuated by episodic uplift (Kapel, 1966; Battersby, 1976; Zhou, 1993; Hill & Gravestock, 1995). However the basin does not have a large circular geometry, as would be expected for this type of subsidence mechanism. Other authors have proposed a variety of tectonic models for basin development, including extension (e.g. Stanmore, 1989; Evans et al., 1990), contractional tectonism (Kuang, 1985; Wopfner 1985; Apak et al., 1997; Sun, 1997) and dextral strike-slip tectonics (Kantsler et al., 1983; Middleton and Hunt, 1989). Deposition in the Cooper Basin occurred over a time span of nearly 100 Ma, which implies that it is likely to be a polyphase basin, having been influenced by both contractional and extensional events during its evolution. Thermal subsidence may have played a large role, but a number of other mechanisms are superimposed, such as the reactivation of pre-existing structures during contractional and extensional events. The orientations of these structures are important in that they produced different tectonic styles in different parts of the basin. Initial subsidence of the Cooper Basin began in the Pennsylvanian, possibly related to cooling following the Pennsylvanian granite emplacement (Gallagher & Lambeck, 1989; Gravestock & Jensen-Schmidt, 1998; Draper, 2002). The earliest depositional history was likely to have been influenced by glacial geomorphology as basement ridges within a pre-existing landscape possibly exerted some control on the location of glacial sedimentation (Tirrawarra Sandstone and Merrimelia Formation) (Figure 4.3; Figure 4.4; Gravestock & Jensen-Schmidt, 1998). The subsequent waning of glaciation and the post-glacial setting was a time of widespread peat swamp deposition (Patchawarra Formation), which spanned ~20 Ma. This, and the overlying lacustrine deposits (Murteree and Roseneath shales), suggest widespread quiescence through most of the remaining early Permian. Apak et al. (1997), however, suggested that this was punctuated by two episode of minor tectonic uplift, recorded by the development of local unconformities on structural highs within the middle and upper Patchawarra Formation. Well to the east, there was a major phase of extension, which commenced in the late Pennsylvanian, and led to the initiation of the Bowen, Gunnedah and Sydney basins (e.g. Korsch et al., 2009a). This phase of mechanical extension was followed later in the early Permian by a phase of subsidence driven by thermal relaxation, prior to the onset of foreland loading in the mid Permian (see below). It is likely that these events had a far field effect on subsidence in the Cooper Basin. Structural growth of the basement ridges commenced in the early to mid-Permian, leading to the formation of the Daralingie unconformity (Figure 4.3; Heath, 1989; Apak et al., 1997). This tectonic event had negligible effects in the troughs, but created significant erosion (75 m to 350 m removed) on some ridges, including the GMI, NM and JNP trends (Hill & Gravestock, 1995, Moussavi-Harami, 1996b; Alexander et al., 1998; Draper, 2002). First identified by Battersby (1976), this event is apparent as an angular unconformity with the pinch-out of early Permian strata against major ridges, and by late Permian to Early Triassic strata which overstep the ridges (Gravestock & Jensen-Schmidt, 1998). This unconformity style is also evident on the southern and western margins of the Cooper Basin. The northeast–southwest trending GMI and NM ridges developed as contractional structures

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due to thrust reactivation of basement structures, whereas the northwest–southeast oriented JNP trend formed as a strike-slip structure (Apak et al., 1997). This event can be correlated with the Aldebaran deformational event in the eastern Australian marginal basins (Korsch & Totterdell, 2009a, b; Korsch et al., 2009b), although it may have occurred slightly later in the Cooper Basin than in the Bowen and Gunnedah basins. Another phase of subsidence began in the late Permian, resulting in more extensive deposition, incorporating the Toolachee Formation and Nappamerri Group (Figure 4.3). This is likely to represent continuing thermal subsidence (Draper, 2002), although minor contractional events have been suggested during the deposition of the Toolachee Formation (Apak et al., 1997). At this time, subsidence in the basins on the east coast was influenced by foreland loading (including static loads and dynamic platform tilting) (Waschbusch et al., 2009). It is possible that far field effects of dynamic platform tilting played a role in the subsidence of the Cooper Basin at this time. Tectonism recommenced during deposition of the Middle Triassic Tinchoo Formation, resulting in northwest tilting of the Cooper Basin, which is reflected in the Nappamerri Group thickening to the north, and erosion from the southern areas of the basin. This is likely to be related to widespread contraction across eastern Australia, associated with later phases of the Hunter–Bowen Orogeny.


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Figure 4.3: Stratigraphy of the Cooper Basin (after Price et al., 1985; McKellar et al., 1999; Gray & McKellar, 2002; Goldstein et al., 2012; McKellar, 2013; Metcalfe et al., 2014; DSD, 2015b; Nicoll et al., 2015; J.L. McKellar, pers. comm., April 2015; G.R. Wood, pers. comm., April 2015), showing depositional facies, conventional petroleum occurrences and identified source rocks.

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Figure 4.4: Regional time-slice cross-sections through the Cooper–Eromanga–Lake Eyre basin succession, showing regional basin evolution and selected tectonic events. The cross-section used for this reconstruction is line a) in Figure 3.3 and Figure 3.4.


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Deposition in the Cooper Basin sensu stricto was terminated by a final major phase of tectonic reactivation, uplift and erosion in the Late Triassic, driven by apparent northeast–southwest contraction, which lasted for up to 30 Ma, and gave rise to the major post-Nappamerri unconformity (Figure 4.3; Kuang, 1985; Apak et al., 1997; Gravestock & Jensen-Schmidt, 1998; McKellar, 2013). As with the Daralingie unconformity, this event had negligible effect in the troughs, but resulted in further erosion on the structural highs (Hill & Gravestock, 1995; Moussavi-Harami, 1996b; Mavromatidis, 2006). Moussavi-Harami (1996b) estimated up to 180 m of missing section for selected Cooper Basin wells at this time; however it is unclear how much material was removed across the basin. The region also experienced a significant Late Triassic (202 ± 9 Ma) diagenetic event associated with basin-wide hydrothermal fluid circulation, coincident with fault reactivation and unconformity development (Zwingmann et al., 2001; Middleton et al., 2014b, 2015). This Late Triassic unconformity is a common feature in coeval basins to the east, including the Galilee, Bowen, Gunnedah and Sydney basins, and marks the end of the Hunter–Bowen Orogeny, referred to as the Goondiwindi Event in the Gunnedah and Bowen basins (e.g. Wiltshire, 1982; Gravestock et al., 1998; Korsch et al., 2009b).

4.2.2 Jurassic–Cretaceous Eromanga Basin The Eromanga Basin is a relatively thin, but extensive blanket of Early Jurassic to mid Cretaceous sedimentary rocks that extends well beyond the limit of the Cooper Basin and covers much of eastern Australia (Gravestock et al., 1998; Cook et al., 2013; Stewart et al., 2013). In the vicinity of the Cooper Basin, the Eromanga Basin contains two main depocentres; the Central Eromanga Depocentre and the Poolowanna Trough separated by the Birdsville Track Ridge (Radke, 2009). In excess of 2500 m of sediments accumulated in the Central Eromanga Depocentre overlying the Cooper Basin. Early models of Eromanga Basin formation proposed that initial subsidence resulted predominantly from deep crustal metamorphism (e.g. Middleton, 1980; Zhou, 1993). There is also considerable evidence that subduction-related dynamic platform tilting contributed significantly to subsidence in the Eromanga Basin (e.g. Gallagher, 1990; de Caritat and Braun, 1992; Gallagher et al., 1994; Russell & Gurnis, 1994; Gurnis et al., 1998; Waschbusch et al., 2009; Matthews et al., 2011), and that this process occurred against a background of broader-scale vertical motions and tilting of the Australian continent (Russell & Gurnis, 1994). In the western part of the Eromanga Basin however, in the vicinity of the Cooper Basin the subsidence is inconsistent with platform tilting. An additional mechanism related to thermal decay was proposed by Gallagher (1990), along with a rapid increase in subsidence in the Early Cretaceous resulting from an excess sediment loading. The possible cause of the intracratonic subsidence is still under debate but may have been driven by several different mechanisms including: •

mantle downwelling, or avalanche events (Pysklywec & Mitrovica 1997, 1998)

•

the passive response to the continent passing over sinking detached lithospheric slabs in the mantle (Russell & Gurnis 1994; Schellart & Spakman, 2015)

•

removal of a mantle plume (Waschbusch et al., 2009).

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Figure 4.5: Eromanga Basin stratigraphy, depositional environment, thickness and petroleum occurrences (from DSD, 2015d). The stratigraphy is based on Moussavi-Harami (1996c).


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The sedimentary succession of the Eromanga Basin can be divided into four main depositional stages (Figure 4.4; Figure 4.5; Krieg et al., 1995; Moussavi-Harami, 1996a; Gray et al., 2002; Radke, 2009; Ransley et al., 2012; Cook et al., 2013): •

Stage I: Late Triassic localised deposition of the Cuddapan Formation

•

Stage II: Early Jurassic to Early Cretaceous extensive fluviatile and lacustrine deposition

•

Stage III: Early Cretaceous marine incursion

•

Stage IV: late Early Cretaceous to Cenomanian paralic fluvial and lacustrine deposition.

Deposition of Late Triassic sediments was not subject to the earlier Permo-Triassic controls on deposition, and was possibly a forerunner to events which influenced the broader development of the Jurassic–Cretaceous Eromanga Basin (Figure 8; Draper, 2002; Gray et al., 2002; Cook et al., 2013). These units are now preserved as isolated remnants, and have been found only in the Windorah and eastern Patchawarra troughs (Powis, 1989; Gravestock & Jensen-Schmidt, 1998). The sediments have been divided into the Morney beds (APT4.2, Price et al., 1985; Stanmore and Johnstone, 1988) and the Cuddapan Formation (APT5, formerly called the Bluebush beds; Price et al., 1985) (Figure 4.3). Early Jurassic to Late Cretaceous deposition within the Eromanga Basin was relatively continuous and widespread. Deposition was controlled by plate tectonic events on the margins of the Australian plate to the east and south. Volcanic activity on the evolving continental boundary to the east influenced sediment provenance and depositional environment. On the southern margin, separation of Australia and Antarctica during the Late Cretaceous also influenced deposition within the Eromanga Basin (Alexander et al., 2006). In the Early Jurassic to Early Cretaceous, the lower non-marine succession accumulated through extensive, sand-dominated, braided fluvial systems that drained centrally towards lowland lakes and swamps (Figure 4.5; Wiltshire, 1989; Draper, 2002). In the Cooper Basin region, this lower non-marine succession consists of intertonguing braided fluvial sandstones (Hutton and Namur sandstones), lacustrine shoreface sandstone (McKinley Member) and meandering fluvial, overbank and lacustrine sandstone, siltstone, shale and minor coal (Poolowanna, Birkhead and Murta formations) (Figure 4.5; Radke, 2009; Radke et al., 2012; Cook et al., 2013). Little tectonic activity occurred in the Cooper Basin region during this time (Ransley et al., 2012). In the Early Cretaceous, a continuation of the convergent plate setting is inferred along the eastern margin of Gondwana (Raza et al., 2009), with extension initiating in a back-arc setting at about 125 Ma, as a precursor to the opening of the Tasman Sea (Crawford et al., 2003; Cook et al., 2013). Volcanic activity associated with the Whitsunday Volcanic Province also began around this time, ending by about 90 Ma. The youngest formation in the Eromanga Basin, the Cenomanian Winton Formation, contains volcaniclastic detritus, which suggests that it was deposited from about 99 Ma to at least 93 Ma (Bryan et al., 2012; Tucker et al., 2013). A widespread marine incursion occurred across the continent in the late Early Cretaceous. There is a conformable transition from non-marine to marginal marine sediments (Cadna-owie Formation) to marginal to open marine shales and sandstones (Bulldog Shale, Coorikiana Sandstone, Oodnadatta, Wallumbilla, Toolebuc, Allaru and Mackunda formations) (Figure 4.5; Draper, 2002; Radke et al., 2012; Cook et al., 2013). In the Late Cretaceous, a major plate realignment started at about 100 Ma, and resulted in regional uplift, denudation and cooling along much of the eastern margin of Gondwana (Raza et al., 2009;

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Bryan et al., 2012). This period of activity ended with the inception of seafloor spreading in the southern Tasman Sea at about 84 Ma (Veevers et al. 1991; Gaina et al. 1998; Cook & Jell, 2013). During the early stages of this event, uplift and erosion of the eastern highlands resulted in increased sediment supply to the Central Eromanga Basin. This overcame marine conditions in the basin, and led to the accumulation of the non-marine, Cenomanian Winton Formation (Figure 4.5; Gray et al., 2002; Alexander et al., 2006; Bryan et al., 2012; Radke et al., 2012; Ransley et al., 2012; Cook et al., 2013), from about 99 Ma to at least 93 Ma (Tucker et al., 2013). It consisted of meandering fluvial systems that crossed a flood basin dominated by coal swamps and lakes. The thickness of the Winton Formation reaches up to around 1200 m over the Cooper Basin region, with maximum thicknesses occurring over the Patchawarra Trough. This deposition occurred very rapidly, equivalent to sedimentation rates of ~ 200 m/Ma The uplift of eastern Australia finally resulted in the termination of deposition in the Eromanga Basin in the Cenomanian by 90 Ma, and this was followed by the erosion of a large part of the Winton Formation (Draper, 2002; Mavromatidis & Hillis, 2005; Jensen-Schmidt et al., 2006). Similar midCretaceous uplift and erosion is observed in the Surat Basin to the east, highlighting the continental nature of this event (Korsch & Totterdell, 2009b; Raza et al., 2009). Structural inversion of the region produced significant fault reactivation within the Central Eromanga Basin, with fault displacements of up to 780 m on the Curalle Dome, 400 m on the Canaway Fault, and 300 m on the Harkaway Fault (Hoffmann, 1989; Ransley et al., 2012). The regional distribution and magnitude of erosion of the Winton Formation is not well constrained. Moussavi-Harami (1996b) estimated that there was between 150 m and 440 m of missing section at the top of the Eromanga Basin, based on a restored isopach map. More recently, Mavromatidis & Hillis (2005) used compaction analysis to estimate exhumation of between 600 m and 1000 m of Eromanga Basin sediments over the Cooper Basin region during the entire Late Cretaceous–Quaternary period, the majority of which is likely to have occurred in the Late Cretaceous. Apatite fission track (AFTA) data suggest that the Cooper Basin was subjected to a high heatflow event in the mid-Cretaceous, where paleotemperature profiles were highest at about 100–90 Ma, with cooling prior to 70 Ma (Duddy & Moore, 1999; Deighton & Hill, 1998; Deighton et al., 2003). Using geochemical techniques, Middleton et al. (2014b, 2015) also identified a Cretaceous thermal event at ca 128 Ma to ca 86 Ma, which was primarily restricted to the Nappamerri Trough; this was interpreted to be an episodic fluid flow event associated with regional tectonism.

4.2.3 Cenozoic Lake Eyre Basin The Lake Eyre Basin is a Cenozoic sedimentary succession overlying the Eromanga Basin, covering parts of northern and eastern South Australia, southeastern Northern Territory, western Queensland and northwestern New South Wales (Stewart et al., 2013). The basin is less than 300 m thick over the Cooper Basin region (Figure 4.6; Ransley et al., 2012), and contains sediments deposited from the Paleocene (66 Ma) through to the Quaternary (Alley, 1998). The Lake Eyre Basin is further subdivided into sub-basins, with the northern part of the Callabonna Sub-basin overlying the Cooper Basin (Figure 4.6; Callen et al., 1995; Ransley et al., 2012). Cenozoic subsidence in northeastern South Australia and southwestern Queensland produced a large shallow depression, which continued to accommodate fluvial and lacustrine sediments. Initially, a fluvial system probably drained through to the Eucla Basin. With Early Oligocene deformation and renewed relief of the Birdsville Track Ridge (Wopfner et al., 1974; Moore & Pitt, 1984), sub-basins


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formed to create internally-draining basins. Uplift of the northern Flinders Ranges in the Miocene (Foster et al., 1994) further subdivided drainage in the Tirari Sub-basin. Renewed uplift of the Eastern Highlands generated a regional southwestward tilt that greatly increased drainage (Figure 4.6: Ransley et al., 2012).

Figure 4.6: Thickness of Paleogene–Neogene Lake Eyre Basin succession over the Eromanga Basin (from Ransley et al., 2012). Deposition occurred in three phases, punctuated by periods of tectonic activity and deep weathering (Callen, 1990; Alley, 1998; Ransley et al., 2012; Roach et al., 2014).

The first phase of deposition lasted from the late Paleocene to the middle Eocene and is represented by the Eyre Formation and equivalents (Wopfner, 1974; Callen et al., 1995). The Eyre Formation consists of carbonaceous sand, silt and gravel, with some lignite and clay beds, interpreted to represent deposition in a braided stream fluvial setting (Alexander et al., 2006; Alley, 1998). It is of

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variable thickness over the Cooper Basin region, generally under 100 m, but known to exceed this above the Tenappera Trough (reaching 112.5 m in Mulga 2) There is little evidence of deposition between the Late Eocene and Late Oligocene, and this hiatus is marked by silcrete formation on the top of the Eyre Formation (Roach, 2012). Widespread gentle folding and uplift, including on the Birdsville Track Ridge, initiated division of the Lake Eyre Basin into its sub-basins during this time, although over the Cooper Basin Moussavi-Harami (1996b) estimated the total amount of erosion associated with this event was less than 30 m. The second phase of deposition commenced in the Late Oligocene (ca 28 Ma) and extended through to the Pliocene (Callen et al., 1995; Roach et al., 2014). Sediments include clay, fine-grained sand, carbonate, and minor conglomerate of the Namba and Whitula formations and correlatives (Callen et al., 1995). The Namba Formation is restricted to the Callabonna Sub-basin in South Australia, where it reaches a maximum thickness of 210 m (Alexander et al., 2006). The Whitula Formation overlies the Windorah Trough, Yamma Yamma Depression, Farrars Syncline and Thompson Depression, and has a maximum recorded thickness of 160 m. A new phase of contraction began during the Miocene, which resulted in a relative increase in paleoseismic activity, fault reactivation and deformation across many Australian basins in Miocene to Holocene times (Hillis et al., 2008). This was driven by plate boundary forces at the margins of the Indian–Australian Plate, including its ongoing continental collision with the Eurasian Plate and subduction along the Tonga–Kermedec Trench (Sandiford et al., 2004; Hillis et al., 2008). In the region surrounding the Cooper Basin, fault reactivation and associated localised uplift and erosion occurred along the Warbreccan, Morney and Betoota anticlines and the Curalle Dome (Ambrose et al., 2007). Moussavi-Harami (1996b), however, interpreted only 15–54 m of missing section from selected wells directly overlying the Cooper Basin. Further Miocene uplift of the Southern Highlands initiated artesian conditions and westward through flow of groundwater within the Great Artesian Basin (Ransley et al., 2012). The third phase of deposition in the Lake Eyre Basin began in the Pliocene and was characterised by deposition of red and yellow–brown sand and sandy clay (eolian Tirari Formation and equivalents), and development of gypsum and carbonate paleosols (Roach et al., 2014).

4.2.4 Present Day Stress Field The stress field established in the Miocene remains similar today (Hillis et al., 2008). Maximum present day horizontal stress orientations across the Cooper Basin have been established from borehole breakouts and drilling-induced tensile fractures (Hillis and Reynolds 2003; Reynolds et al., 2005; Hillis et al., 2008). These studies observe an east–west maximum horizontal stress orientation that is consistent over much of the basin, except in the Patchawarra Trough, where maximum horizontal stress rotates to a northwest–southeast orientation (Figure 4.7). The increase in horizontal stress from the late Cretaceous through to the present day is one possible cause of the observed overpressure in the Cooper Basin (Van Ruth et al., 2003). AFTA data suggests geothermal gradients have been elevated in the past 2–5 Ma, but the cause of this Pliocene heating is unknown (Duddy & Moore, 1999; Gravestock et al., 1998).


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Figure 4.7: Maximum horizontal stress indicators (Reynolds et al., 2005, Hillis et al., 2008) and regional stress trajectories (Hillis and Reynolds, 2000) overlain on depth to base Cooper Basin.

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5 Lithostratigraphy and Environments of Deposition

5.1 Overview This chapter reviews the Cooper Basin lithostratigraphy and depositional environments by formation. Formation extents and thicknesses were mapped using isopachs extracted from the 3D model. Formation ages were updated in a revised Cooper Basin stratigraphic chart, consistent with the 2012 Geological Time Scale (Gradstein et al., 2012) and updated spore pollen age calibration (Nicoll et al., 2015). The updated regional lithofacies maps highlighting net sand, silt, shale and coal distributions for key formations across the whole basin improve regional understanding of depositional environments and offer a general picture of source and reservoir distribution. During the mid-Carboniferous, the Australian Plate within Gondwanaland drifted to high latitudes, and o the Cooper Basin was located around 70 S when Gondwana and Laurussia collided to form Pangaea (Figure 5.1; Veevers, 1984; Alexander et al., 1998). The resulting deformation along the eastern Australian Plate is thought to have produced uplift in central Australia. Decay of the ice sheet in the early Permian released enormous volumes of sediment to produce a typical Cooper Basin succession of basal diamictites overlain by non-marine peat swamps and floodplain facies, interspersed with lacustrine deposits (Alexander et al., 1998). During the Early Triassic, the Cooper Basin was located close to south magnetic pole (Figure 5.1), but there is no record of ice formation at this time. Following the end-Permian mass extinction event, the lacustrine and fluvial sediments at this time were lean in organics and oxidised (Alexander et al., 1998). Stratigraphically, the Cooper Basin is divided into two groups; the Pennsylvanian to upper Permian Gidgealpa Group, and the Lower to Middle Triassic Nappamerri Group (Figure 4.3). The Gidgealpa Group comprises initial glacial deposits transitioning to coal swamp, fluvial and lacustrine deposits (Alexander at al., 1998; McKellar, 2013) that include the major source rock units for the basin (Boreham & Hill, 1998). In contrast, the overlying Triassic Nappamerri Group has typically organically lean fluvial deposits (Alexander at al., 1998; McKellar, 2013).


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Figure 5.1: Paleogeographic reconstructions of the Australian Plate through the Late Carboniferous to Early Triassic (from Alexander et al., 1998, after Veevers, 1984 and Baillie et al., 1994).

5.2 Gidgealpa Group The Gidgealpa Group (Kapel, 1972; Gatehouse, 1972) is entirely non-marine, initially of glacial origin, and is characterised by coal measures that are separated by lacustrine ‘shales’ (Alexander et al., 1998). The Gidgealpa Group unconformably overlies middle Carboniferous and older sedimentary, igneous and metamorphic rocks and is conformably overlain by the Nappamerri Group or disconformably by the Eromanga Basin (Figure 4.3; Alexander et al., 1998; Gray & McKellar, 2002). The Gidgealpa Group is thickest south of the JNP trend, reaching up to 1700 m in the Nappamerri Trough and over 750 m in the Patchawarra Trough (Figure 5.2). The group thins to the northwest, with intersected thicknesses reaching 350–450 m immediately north of the JNP trend. In the Windorah Trough and Ullenbury Depressions, the Gidgealpa Group thickness ranges between 50–170 m (Gray & McKellar, 2002; McKellar, 2013). The Gidgealpa Group ranges in age from Pennsylvanian (Gzhelian) to middle Permian (top Ladinian), from palynological units APP1 to APT3 (Figure 4.3; Gray & McKellar, 2002).

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Figure 5.2: Gidgealpa Group isopach map, with well intersections.

5.2.1 Merrimelia Formation and Tirrawarra Sandstone The Merrimelia Formation is a complex fluvioglacial unit of conglomerate, diamictite, sandstone, conglomeratic mudstone, siltstone and shale (Alexander et al., 1998; Gray & McKellar, 2002). The Merrimelia Formation unconformably overlies Warburton Basin strata and interfingers with the overlying Tirrawarra Sandstone (Alexander et al., 1998). The Tirrawarra Sandstone comprises fine to coarse-grained, moderately well sorted sandstone, common conglomerates with minor shale interbeds and rare thin coal seams and stringers (Kapel, 1972; Gatehouse, 1972; McKellar, 2013). It was deposited by melt-water streams flowing north from retreating glaciers as reworked unconsolidated glacial sediments (Alexander et al., 1998). The Tirrawarra Sandstone interfingers with the underlying Merrimelia and overlying Patchawarra formations (Alexander et al., 1998).


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Isopachs of the combined facies show that the thickest accumulations of glacial sediments are along a deep glacial scour from the southern Patchawarra Trough through the GMI Ridge into the northern Nappamerri Trough and into the Weena Trough (Figure 5.3; Alexander et al., 1998). This depositional model results in rapid and dramatic thickness variations especially in the Weena Trough area. Areas devoid of these units are interpreted as either glacial uplands (e.g. Moomba, Daralingie and Toolachee areas) or uplifted and eroded structures (e.g. GMI Ridge) (Alexander et al., 1998). The 2 glacial sediments are estimated to cover an area of ~29,900 km ; however, the uncertainties associated with the glacial isopach map are large. This is due to the limited number of wells that fully intersect the glacial section and the lack of clear top pre-Permian basement horizon in many areas. Well intersections show that the Merrimelia Formation is mostly restricted to South Australia, with a maximum thickness of around 80 m in the main part of the basin. In the Weena Trough, in Tinga Tingana 1, glacial sediment thickness reaches more than 620 m thick (Delhi, 1968; Alexander et al., 1998). The base is not penetrated in this well and seismic data suggests that an even greater thickness may be locally present. The Tirrawarra Sandstone is more widespread, but is still relatively thin, reaching 75 m thick in South Australia, and thinning to 30 to 40 m in Queensland (Gray & McKellar, 2002). North of the Durham Downs Anticline and JNP trend, the glacial sediments are limited in thickness (10 to 20 m) and extent. There is some debate about the age of these units, whether they extend down into the late Pennsylvanian or are confined to the early Permian (compare Gravestock, 1998 with McKellar, 2013). Palynofloras from the Merrimelia Formation are consistent largely with palynological unit APP1.21, although the basal part of unit APP1.22 is also found in the uppermost sections of the formation (Figure 4.3; Price, 1997; Gray & McKellar, 2002; McKellar, 2013). The Tirrawarra Sandstone contains palynofloras assigned to the upper APP1.21, APP1.22 and basal APP2.1 palynological zones (Price, 1997; Gray & McKellar, 2002). Age dating of the underlying Big Lake Suite granodiorites suggests a minimum emplacement age of 307 Ma (Marshall, 2013). Allowing some additional time for weathering profile development (Wiltshire, 1972), the maximum age of the Merrimelia Formation is assumed to be latest Carboniferous (305 Ma– base Gzhelian). Recent recalibration of the spore pollen zones (Nicoll et al., 2015) and updates to the 2012 Global Timescale (Gradstein et al., 2012), place the top of zone APP1 at around 295 Ma at the top Asselian. This results in an upper Gzhelian to Asselian age for the Tirrawarra Sandstone.

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Figure 5.3: Isopach map of the combined Merrimelia Formation and Tirrawarra Sandstone in metres, with well intersections.

5.2.2 Patchawarra Formation The Patchawarra Formation comprises interbedded sandstone, siltstone, shale and coal (Kapel, 1972; Gatehouse, 1972). Sandstones, dominantly quartzose, are fine to medium-grained, locally coarsegrained with some pebbly sandstone (Alexander et al., 1998; McKellar, 2013). The Patchawarra Formation overlies/ interfingers with the glacial sediments of the Tirrawarra Sandstone, or unconformably directly overlies pre-Permian rocks (Alexander et al., 1998; McKellar, 2013). Across most of the southern basin, the Patchawarra Formation is overlain by the Murteree Shale, but towards the edge of the Cooper Basin in South Australia, it is directly overlain by the Toolachee Formation, or by sediments of the Eromanga Basin. Over structural highs, the intervening units may have been removed by erosion, however in the southern Weena Trough, the Murteree and


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Roseneath shale have thinned due to depositional pinchout (John Morton, pers. comm. September 2015). As a result, distinction between the Patchawarra, Epsilon and Daralingie formations becomes difficult in these areas. In Queensland, beyond the extent of the overlying Murteree Shale, distinction of Patchawarra and Epsilon formations is also problematic as both contain coal measures. The northern extent of the Patchawarra Formation is poorly mapped due to the sparse distribution of well data (Figure 5.4). 2

The Patchawarra Formation is the most widespread Permian unit covering an area of ~69,600 km (Figure 5.4). It is also the thickest unit of the Gidgealpa Group, with an average thickness of ~130 m and a maximum thickness > 680 m in the Nappamerri Trough (as intersected in Kirby 1; Delhi, 1978). The unit thins to the north of the JNP Trend, but still reaches over 300 m thick within the Arrabury Trough. In the southern Windorah Trough and Mt Howitt Anticline regions, well intersections indicate a maximum thickness of around 100 m. Although there is no well control within the Ullenbury Depressions, structural geometries suggest that as much as 200 m of Patchawarra Formation may be present within the depocentre (Figure 5.4). The Patchawarra Formation contains palynofloras assigned to palynological units APP2.1, APP2.2, APP3.1 and APP3.2 (Figure 4.3; Price, 1997; Gray & McKellar, 2002). Taking into consideration revised ages of the spore pollen zones (Nicoll et al., 2015), this places the Patchawarra Formation in the early Permian (Sakmarian–Artinskian–early Kungurian).

5.2.2.1 Facies Distribution Three facies assemblages can be distinguished where the Patchawarra Formation reaches its maximum thickness (Kapel, 1972; Alexander et al., 1998): •

A lower carbonaceous siltstone with minor sandstone and thin coal seams.

•

A middle assemblage dominated by sandstone, with grey-black shale interbeds and thick coal seams.

•

An upper assemblage of siltstone and shale with minor sandstone interbeds.

Cumulative thickness of coal within the Patchawarra Formation varies considerably spatially (Figure 5.5; Figure 5.6). Net coal thickness is greatest in the southwest corner of the basin with nearly 200 m intersected at Klebb 1, 160 m at Le Chiffre, 83 m at Davenport 1 and 65 m in Weena 1 (Pexa Oil NL, 1970; Beach Energy 2012a; Strike Energy, 2015; John Morton, pers. comm. September 2015). Net coal thickness also reaches over 40 m in the Wooloo and southern Patchawarra troughs, but tends to be less than 15 m in wells in the central Nappamerri Trough (Alexander et al., 1998; Sun & Camac, 2004; Nitschke, 2006). North of the JNP Trend in Queensland, cumulative thickness is regionally between 10 and 15 m, with over 15 m intersected in the Windorah Trough and surrounds (Real Energy, 2014a, b, c). Thicknesses approach 30 m on the southeastern crest of the JNP Trend (Draper, 2002). Patchawarra coal seams average 2.1 m thick but can be up to 22 to 30 m, and 30% of seams exceed 2 m thickness (Figure 5.6; Alexander et al., 1998). The maximum single coal thickness intersected was 38 m in Davenport 1 and 35 m in Klebb 2 (Beach Energy 2012a; John Morton, pers. comm. September 2015). They are thinner on average than those in the Toolachee Formation; however they are more numerous in the thicker Patchawarra Formation (Alexander et al., 1998). Net shale thickness is greatest in the Nappamerri and southern Patchawarra troughs, where it reaches up to 250 m (Figure 5.6). Despite a significant reduction in total formation thickness further north, net shale thickness remains greater than 20 m in parts of the Windorah Trough and south of the Ullenbury

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Depression. The lithofacies maps demonstrate an abundance of potential coal and shale source rock facies in the Patchawarra Formation across the basin. The source rock geochemistry and maturity of these will be discussed in separate reports. Patchawarra Formation net sand thickness is greatest in the deepest sections of the basin around the Nappamerri Trough, where it reaches ~680 m around Kirby 1 (Figure 5.6; Delhi, 1978; Sun & Camac, 2004). In the northern basin, net sand thicknesses reaches up to 70 to 80 m in the Windorah Trough region, consistent with recent drilling results in the area (Real Energy, 2014a, b).

Figure 5.4: Patchawarra Formation isopach map in metres with well intersections.


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Figure 5.5: Patchawarra Formation isolith maps by lithology, as a percent of total formation thickness.

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Figure 5.6: Patchawarra Formation isolith maps by lithology, as total net thickness in metres.


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5.2.2.2 Depositional Environment The Patchawarra coal isolith map shows that the proportion of coal tends to be greater along the basin flanks and associated with structure highs. The opposite is the case for the proportion of sand, which tends to be greater along the central axis of the basin (Figure 5.5). These lithofacies distribution patterns are consistent with previous models of a high sinuosity fluvial system flowing over a floodplain with peat swamps, lakes and gentle uplands (Alexander et al., 1995; Gray & McKellar, 2002: Lang et al., 2002; Strong et al., 2002). Coals may have been deposited as high-latitude blanket-raised swamps, with more prominent deposition around the paleo-highs (Lang et al., 2002; Strong et al., 2002). Peat swamps would have been resistant to erosion, and may have controlled fluvial architecture by resisting avulsion and overbank flooding (McCabe, 1984). In addition, reactivated paleo-highs, such as around Moomba and Daralingie, represent restricted sites for major channel sedimentation, with the major sandy fluvial axes confined to the paleo-lows (Lang et al., 2001). Modern peat forming environments in fluvial systems of Western Siberia are considered to be an appropriate analogue for Patchawarra reservoir model development (Lang et al., 2000; Strong et al., 2002). The upper part of the formation reflects inundation of the floodplain from the east by transgression of a broad lake. Deltaic, lagoonal and lacustrine environments developed as precursors to the MurtereeEpsilon-Roseneath deposition (Stuart, 1976; Alexander et al., 1998).

5.2.3 Murteree Shale The Murteree Shale comprises black to dark grey-brown argillaceous siltstone with minor fine-grained sandstone. Carbonaceous material, muscovite and fine-grained pyrite are characteristic of the unit (Gatehouse, 1972; Alexander et al., 1998; Gray & McKellar, 2002; McKellar, 2013). The Murteree Shale conformably overlies and intertongues with the Patchawarra Formation, and is conformably overlain by the Epsilon Formation. Locally the Murteree Shale is unconformably overlain by the Toolachee Formation as a result of tectonism and erosion associated with the Daralingie unconformity (Alexander et al., 1998). The Murteree Shale is preserved in the southwestern Cooper Basin in the Nappamerri and Tenappera 2 troughs and covers an area of ~31,300 km . It is mostly absent on and to the north of the JNP Trend (Figure 5.7; Alexander et al., 1998; Gray & McKellar, 2002) and it appears to pinch out south of the Tinga Tingana Ridge (John Morton, pers. comm. September 2015). This unit has an average thickness of ~33 m. However thickness reaches over 80 m in the Nappamerri, Wooloo, Allunga and Tenappera troughs, with a maximum of 90 m intersected in Holdfast 1 (Figure 5.7; Beach Energy, 2011b). The Murteree Shale is associated with late early Permian (Kungurian) palynofloras conformable with palynological unit APP3.2 (Figure 4.3; Price, 1997; Gray & McKellar, 2002).

5.2.3.1 Depositional Environment Horizontally-laminated siltstone, minor linsen bedding, rare ripple waves and wavy bedding, and occasional rhythmites and turbidites collectively indicate a deep lake environment with restricted circulation (Alexander et al., 1998; Gray & McKellar, 2002).

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Figure 5.7: Murteree Shale isopach map in metres with well intersections.

5.2.4 Epsilon Formation The Epsilon Formation comprises fine to medium-grained quartzose sandstone interbedded with dark grey-brown carbonaceous siltstone and shale, and thin to occasionally thick coal seams (Gatehouse, 1972; Alexander et al., 1998; Gray & McKellar, 2002; Lang et al., 2000, 2001). The Epsilon Formation intertongues with and is conformably overlain by the Roseneath Shale, and conformably overlies the Murteree Shale. Where the Roseneath Shale and Daralingie Formation have been eroded, the Epsilon Formation is unconformably overlain by the Toolachee Formation (Alexander et al., 1998).


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Figure 5.8: Epsilon Formation isopach map in metres, with Epsilon Formation well intersections.

The Epsilon Formation is widespread across the southwestern Cooper Basin, from the Tenappera 2 Trough in the south to the north of the Patchawarra Trough and covers an area of ~31,400 km . However, its extent to the north of the JNP Trend is very limited (Figure 5.8). The formation is not present in the Weena Trough, based on palynology from Forge 1, but has been identified in the Milpera Trough in Davenport 1 (Beach Energy 2012a).The formation was eroded from the Dunoon and Murteree ridges, during the late Permian uplift (Alexander et al., 1998). The Epsilon Formation is an average of ~50 m thick, but reaches an intersected thickness of ~195 m in Moonta ST1 in the Nappamerri Trough (Beach Energy 2012c). The formation is also extensive in the Wooloo and Allunga troughs.

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The Epsilon Formation contains palynofloras conformable with upper APP3.2, APP3.3 and basal APP4.1 (Figure 4.3; Price, 1997; Gray et al., 2002). Updated age constraints on the spore pollen zones (Nicoll et al., 2015), including migration to the 2012 Geological Timescale (Gradstein et al., 2012), place the lower and upper boundaries of zone APP3.3 at 271.4 Ma and 269.6 Ma respectively, giving the Epsilon Formation a late early Permian to early late Permian (upper Kungurian–Roadian) age.

5.2.4.1 Facies Distribution The Epsilon Formation consists of an aggradational lacustrine delta succession, deposited in response to differential subsidence rates. Although it can be divided into at least 11 deltaic cycles based on log signatures, which can be correlated over a large area (Lang et al., 2000, 2001), three major depositional stages have been identified (Fairburn, 1992; Lang 2002), as follows: •

a lower coarsening-upward fine to medium sandy cycle

•

a coal-dominated middle stage

•

an upper progradational succession of shales and sandstones, with occasional coal, up to 45 m thick.

Epsilon Formation cumulative coal thickness reaches 10–15 m in the Patchawarra and western Nappamerri troughs (Figure 5.9; Figure 5.10; Sun & Camac, 2004). The thickest net coal is recorded in Davenport 1 in the Milpera Depression in the southwest of the basin, where it reaches 37 m (Beach Energy 2012a; John Morton, pers. comm. September 2015). Coal thicknesses in the eastern Nappamerri Trough are poorly defined due to limited data coverage. Although coal seams are extensive, they rarely exceed 3 m and are commonly < 0.3 m thick (Alexander et al., 1998; Gray & McKellar, 2002). Net shale thickness is greatest in the deepest sections of the basin around the Nappamerri Trough, where it reaches up to 100 m or more (Figure 5.10; Sun & Camac, 2004). Although the Epsilon Formation is much thinner and less extensive than the Toolachee and Patchawarra formations, the net coal and shale thickness maps show the potential presence of source rock facies across the entire formation (Figure 5.9 and Figure 5.10). The source rock geochemistry and maturity of these will be discussed in separate reports. Net sand thickness is greatest in the central and eastern sections of the Nappamerri Trough, where it reaches up to 40 m (Sun & Camac, 2004), highlighting the formation’s reservoir potential in these regions (Figure 5.10).

5.2.4.2 Depositional Environment Fluvio-deltaic and lacustrine depositional environments were present over three broad depositional stages listed below (Fairburn, 1992; Alexander et al., 1998): •

Delta fill and delta slope successions were coeval with beach development, beach barrier and shoreline deposits.

•

Distributary channels developed on a prograding delta and were oriented perpendicular to the lake shoreface. Crevasse splays, backswamp facies, and raised peat swamps were present in the northern Patchawarra Trough.

•

Lacustrine or back-barrier lagoonal facies predominated.


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Figure 5.9: Epsilon Formation isolith maps by lithology, as a percent of total formation thickness.

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Figure 5.10: Epsilon Formation isolith maps in meters by lithology.


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5.2.5 Roseneath Shale The Roseneath Shale comprises light to dark brown-grey siltstone, mudstone and minor fine-grained sandstone units (Alexander et al., 1998; Gray & McKellar, 2002: McKellar, 2013). The Roseneath Shale conformably overlies and intertongues with the Epsilon Formation, and is overlain by and intertongues with the Daralingie Formation (Alexander et al., 1998). The Roseneath Shale occurs mainly in the southwestern part of the Cooper Basin where it extends across the 2 Nappamerri, Wooloo, Allunga and Tenappera troughs, and covers an area of ~21,900 km (Figure 5.11). However it was eroded from the Dunoon and Murteree ridges and crests of other ridges during the late early Permian uplift (Alexander et al., 1998). South of the Tinga Tingana Ridge, it appears to pinch out (John Morton, pers. comm. September 2015). It is additionally present on the southeastern end of the JNP Trend (Figure 5.11). The Roseneath Shale has an average thickness of 57 m, however it thickens into the Nappamerri and Tenappera troughs, reaching a maximum thickness of ~240 m in Halifax 1 in the Nappamerri Trough (Beach Energy, 2013b). In the Jackson–Naccowlah East area, it is in the order of 20–30 m thick. Palynofloral assemblages from the Roseneath Shale are attributable to the uppermost part of palynological unit APP3.3, APP4.1 and the basal part of APP4.2 (Figure 4.3; Price, 1997; Gray & McKellar, 2002). Updated age constraints on the spore pollen zones (Nicoll et al., 2015), including migration to the 2012 global timescale, place the lower and upper boundaries of zone APP4.1 at 269.6 Ma and 266.8 Ma respectively, giving the Roseneath Shale an upper Roadian to early Wordian age. Both the lower and upper boundaries are time transgressive.

5.2.5.1 Depositional Environment A lacustrine environment of deposition is interpreted for the Roseneath Shale, similar to that of the Murteree Shale (Alexander et al., 1998)

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Figure 5.11: Roseneath Shale isopach map in metres with well intersections.

5.2.6 Daralingie Formation The Daralingie Formation comprises interbedded carbonaceous and micaceous siltstone, mudstone, coal and minor sandstone (Alexander et al., 1998; McKellar, 2013). The unit covers an area of 2 ~19,300 km and is restricted to the region south of the GMI Ridge and southwestwards of the JNP Trend (Figure 5.12). The Daralingie Formation is transitional with and conformably overlies the Roseneath Shale, and its top was eroded during the late Permian uplift in the southern Cooper Basin. The formation is disconformably overlain by the Toolachee Formation. The Daralingie Formation is an average of ~50 m thick, and reaches a maximum intersected thickness of ~130 m in Halifax 1 in the Nappamerri Trough (Beach Energy 2013b).


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Palynofloras associated with the Daralingie Formation are encompassed by zone APP4.2 and the uppermost section of zone APP4.1 (Figure 4.3; Price, 1997; Gray & McKellar, 2002). Updated spore pollen zone ages constrain the upper boundary of zone APP4.1 to 266.8 Ma, giving the Daralingie Formation a maximum age of mid Permian (upper Wordian) (Nicoll et al., 2015). The start of the Daralingie unconformity, and hence the minimum age of the Daralingie Formation, is poorly constrained. This unconformity is associated with the Hunter - Bowen Orogeny (Korsch & Totterdell, 2009a, b; Korsch et al., 2009b), the onset of which is at the base of zone APP4.2 in basins further east (Figure 4.3). To improve consistency with regional tectonic events across eastern Australia, this unconformity is assumed to begin in the lower –middle part of zone APP4.2, giving the Daralingie Formation a minimum age of mid-Capitanian.

5.2.6.1 Facies Distribution Daralingie Formation cumulative coal thickness ranges between 1 and 5 m, but reaches up to 7 to 8 m in the Wooloo and Tenappera troughs (Figure 5.13; Figure 5.14; Sun & Camac, 2004). Coal thicknesses in the eastern Nappamerri Trough are poorly defined due to limited data coverage. Although coal seams are extensive, individual seams rarely exceed 3 m and are commonly < 0.3 m thick (Alexander et al., 1998; Grey and McKellar, 2002). Net shale thickness is greatest in the deepest sections of the basin in the central Nappamerri Trough, where it reaches up to 65 m in well intersections (Figure 5.14; Sun & Camac, 2004). Shale thicknesses may be greater still in the eastern Nappamerri Trough but there is no open file well data to constrain this. Although the Daralingie Formation is much thinner and less extensive than the Toolachee and Patchawarra formations, the net coal and shale thickness maps show the potential presence of source rock facies across the entire formation. The source rock geochemistry and maturity of these will be discussed in separate reports. Daralingie Formation net sand thickness is greatest in the Nappamerri Trough, where it reaches over 50 m, highlighting the formation’s reservoir potential (Figure 5.14; Sun & Camac, 2004).

5.2.6.2 Depositional Environment Fluvial and deltaic environments produced characteristically upward-coarsening cycles of shoaling deltas and beaches on a lake margin. This contrasts with the upward-fining cycles of the overlying Toolachee Formation (Boucher, 1997). The Daralingie Formation was deposited by northeasterly prograding delta systems which developed during the recession of “Roseneath Lake”.

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Figure 5.12: Daralingie Formation isopach map in metres with well intersections.


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Figure 5.13: Daralingie Formation isolith maps by lithology, as a percent of total formation thickness.

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Figure 5.14: Daralingie Formation net isopachs in meters by lithology.


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5.2.7 Toolachee Formation The Toolachee Formation is the uppermost unit of the Gidgealpa Group (Kapel, 1972; Gatehouse, 1972; Morton & Gatehouse, 1985). It comprises interbedded fine to coarse-grained quartzose sandstone, mudstone, carbonaceous shale with thin coal seams and conglomerates (Alexander et al., 1998; Gray & McKellar, 2002; Nakanishi & Lang, 2001). Basal conglomerates occur adjacent to ridges and may contain reworked pre-Permian basement rocks. The Toolachee Formation is the most widespread of all Permian units in Queensland and extends across the entire southwestern Cooper Basin (Figure 5.15; Gray & McKellar, 2002), covering an area 2 of ~88,500 km . However, it has been eroded off many of the ridge crests, including those of the Murteree and Dunoon ridges, as well as in the southern Tenappera Trough (Alexander et al., 1998). There is no evidence that the Toolachee Formation extends to the Weena Trough area, although a very small section may be present in the Milpera Depression in Davenport 1 (Figure 5.15; Beach Energy 2012a). The additional section in this region may have been removed by erosion rather than depositional pinchout (John Morton, pers. comm. September 2015). Alternatively there may have been no accommodation space available to allow post-Patchawarra deposition. In Queensland, the regional basin model presented here, the study of Meixner et al. (2012) and available well data suggest that the extent of the Toolachee Formation may be up to 60 to 80 km further north than indicated by Draper (2002). This unit unconformably overlies the Daralingie Formation and older rocks on ridges. The Toolachee Formation is conformably but slightly diachroneously overlain by the Arrabury Formation, or unconformably by Eromanga Basin sediments (Alexander et al., 1998). The top of the formation is defined as the contact between organic-rich lithologies of the Toolachee Formation, and organic-poor rocks of the Nappamerri Group (Gatehouse, 1972) but as a practicality for electrofacies mapping (Youngs & Boothby, 1985) and seismic mapping, the formation top is taken as the top of the uppermost coal, the ‘P’ seismic horizon. The Toolachee Formation forms a blanket deposit over the Daralingie unconformity surface and is an average of 60 m thick. The maximum intersected thickness is ~280 m in Halifax 1, in the Nappamerri Trough (Alexander et al., 1998; Beach Energy 2013b); however greater thicknesses may be present to the east of this well. Although generally 25–50 m thick in Queensland, the Toolachee Formation thickens to 100–130 m immediately north of the JNP Trend (Figure 5.15). Although there is no well control within the Yamma Yamma Depression, structural geometries (Meixner et al., 2012, NGMA, 2001) suggest that approximately 200 m of Toolachee Formation may be present within this depocentre. In the southern Ullenbury Depression, known thickness is at least 75 m but 3D modelling indicates this could be up to 200 m in the central part of this depression. This region of uncertainty underlies the Central Eromanga Depocentre of Radke et al. (2000) where the main Jurassic sandstone formations of the Eromanga Basin include coal measures (Bradshaw & Yeung, 1992). It is surmised that a thicker cover of coal-bearing units in the Eromanga Basin has resulted in attenuated and limited seismic resolution of the underlying and prospective Gidgealpa Group. It appears that the interpreted formation extents of the Patchawarra and Toolachee formations of Draper (2002) are, in reality, a confidence limit placed on the seismic interpretation. Gidgealpa Group isopachs (NGMA, 2001) crosscut but are truncated by this confidence limit, and support the 3D modelling extents of Meixner et al. (2012). The Toolachee Formation has yielded palynofloras largely conformable with palynological unit APP5, although older (late APP4.3) palynofloras have been reported from strata (“Munkarie beds”) considered to lie at the base of the formation in the southern Cooper Basin, both in Queensland and

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South Australia (Figure 4.3; Price, 1997; Gray & McKellar, 2002). Updated spore pollen zone ages place the base of APP4 at 458.0 Ma, base APP5 at 258.0 Ma and top APP5 at 251.9 Ma (Nicoll et al., 2015), giving the Toolachee Formation a late Permian age (mid Wuchiapingian to Chanhsingian). The termination of the Daralingie unconformity, and hence the onset of Toolachee Formation deposition, is consistent with the end of Aldebaran deformational event of the Hunter–Bowen Orogeny recorded in other basins across eastern Australia (Korsch & Totterdell, 2009a, b; Korsch et al., 2009b).

Figure 5.15: Toolachee Formation isopach map in metres, with well intersections.


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5.2.7.1 Facies Distribution Four sedimentary facies were identified by Nakanishi & Lang (2001): •

fluvial channel facies, which are relatively thick but laterally discontinuous

•

crevasse splay channel facies

•

floodplain-crevasse splay complex

•

floodplan and peat mire facies.

The new electrofacies maps provide updated coal, shale, siltstone and sandstone isopach and isolith maps for the whole of the Cooper Basin and offer a general picture of source and reservoir distribution for the first time (Figure 5.16; Figure 5.17). As in the Patchawarra Formation, there is significant spatial variation in the cumulative coal thickness of the Toolachee Formation (Figure 5.17). Toolachee coal cumulative thickness is greatest in the northern depocentres in South Australia, reaching over 40 m in the northern Patchawarra Trough and over 25 to 30 m in the Arrabury Depression (Sun & Camac, 2004, Senex, 2013). Thicknesses of up to 27 to 28 m are also observed in the southwest part of the basin, around the Marsden 1 and Battunga 1 wells (Santos, 1998; Beach Energy 2012b; John Morton, pers. comm. September 2015). Cumulative thickness decreases to the south, but still reaches 20 m in the Nappamerri Trough and in parts of the Tenappera Trough (Sun & Camac, 2004). The Toolachee Formation is absent in the Weena Trough either due to erosion or lack of accommodation space (Alexander et al., 1998). Throughout the Queensland sector of the basin, cumulative Toolachee Formation coal thickness is regionally much lower, as the Permian section thins. The southeastern crest of the JNP Trend contains up to 10 m cumulative thickness of coal (Draper, 2002). Similar thicknesses of 5 to 15 m are observed across the majority of depocentres further north, which is supported by drilling in Whanto 1, Queenscliff 1, Tamarama 1 and Cocos 1 (M.I.M. Petroleum Exploration Pty Ltd., 1995; Santos–Delhi– Boral–Gulf–OCA, 1998; Real Energy, 2014a, b, c). The average coal seam thickness in the Toolachee Formation is 4.3 m (less in Queensland), but individual seams can reach 22 m (Alexander et al., 1998; Gray & McKellar, 2002). Net shale thickness is greatest in the deepest sections of the basin around the Nappamerri Trough, where it reaches over 180 m (Figure 5.17). Net shale thickness is much less in the north of the basin, with few areas exceeding a net thickness of 20 m. Maps of net coal and shale thickness show an abundance of potential source rock facies within the Toolachee Formation in the central and southern part of the basin (Figure 5.16; Figure 5.17). Although the source rock potential of the shale facies in the Windorah Trough and Ullenbury Depression is lower due to limited thickness, there is still source rock potential from the coal facies in this region. The source rock geochemistry and maturity of these will be discussed in separate reports. Toolachee Formation net sand thickness is greatest in the deepest sections of the basin around the Nappamerri Trough, where it reaches over 60 m (Figure 5.17). Thicknesses may increase further still in the eastern Nappamerri Trough, but this is unconstrained by well data. In the central Windorah Trough and Ullenbury Depression, net sand thickness is much less, with maximum values of around 7 to 15 m, although recent drilling results in the Windorah Trough suggest greater sand thickness (Real Energy, 2014a, b). This is less than the Patchawarra Formation, however is still significant when considering total net sands throughout the Gidgealpa Group interval.

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Figure 5.16: Toolachee Formation isolith maps by lithology, as a percent of total formation thickness.


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Figure 5.17: Toolachee Formation isopach maps in metres by lithology.

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5.2.7.2 Depositional Environment The Toolachee Formation was deposited in fluvial environments during an interval of renewed basin subsidence. In the lower Toolachee Formation, thick fining-upward successions are predominant with minor coal seams. These are interpreted as point bar deposits. Clastic deposition was in ephemeral lakes and back-swamps on the flood-basin. Coals formed in swamps that were subject to flood events. Other sandstone packages represent abandoned channels and crevasse splays (Mackie et al., 1995). In the upper Toolachee Formation, mudstone and coal seams are dominant with thin upwardcoarsening packages that are interpreted to have resulted from overbank flooding and perennial floodbasin lakes (Williams, 1984). Coarse-grained upward-fining packages are locally developed, as in the Gidgealpa Field. These are interpreted as high-sinuosity alluvial channels (Alexander et al., 1998). High-latitude blanket mires were proposed as an analogue for Cooper Basin coals due to their lateral extent, thickness and low ash content. Raised swamps were extremely acidic with restricted and stunted flora, and experienced restricted overbank flooding and avulsion leading to the development of stacked channel sands (McCabe, 1984).

5.3 Nappamerri Group The Nappamerri Group consists of two formations, the late Permian to Early Triassic Arrabury Formation and the Middle to Late Triassic Tinchoo Formation (Channon and Wood, 1989; Powis, 2 1989) and covers an area of ~114,000 km . It conformably overlies the Gidgealpa Group and is unconformably overlain by the Eromanga Basin or eroded remnants of the Late Triassic Cuddapan Formation (Papalia, 1969; Powis, 1989). The Nappamerri Group is widespread across the entire basin, with an average thickness of ~200 m. It is thickest in the Nappamerri Trough, where it reaches almost 600 m in Halifax 1 (Figure 5.18; Beach Energy, 2013 b). Thicknesses also exceed 450 m in the Patchawarra, Arrabury and Windorah troughs (Figure 5.18; Gray & McKellar, 2002). The Nappamerri Group onlaps structural ridges except the Dunoon and Murteree ridges, and has been eroded or was not deposited around the margins of the Cooper Basin in South Australia. In Queensland, the Nappamerri Group has a much broader extent than the underlying Gidgealpa Group. Powis (1989) interpreted a tectonically-driven northward shift in the Triassic depocentre following deposition of the Arrabury Formation, a shift that is supported by northeasterly paleocurrent directions and the regional northerly basin tilt.

5.3.1 Arrabury Formation The Arrabury Formation is the basal unit of the Nappamerri Group (Powis, 1989). In some regions, such as the Patchawarra Trough, it is divisible into the Callamurra, Paning and Wimma Sandstone members (Alexander et al., 1998). The Arrabury Formation comprises basal mudstone and siltstone with thin fine- to medium-grained quartzose sandstone interbeds of the Callamurra and Paning members, which are overlain by sandstone with minor siltstone interbeds of the Wimma Sandstone Member (Alexander et al., 1998).


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The formation is widely distributed over the Cooper Basin, including the GMI Ridge, and its zero edge defines the northern limits of the Cooper Basin (Draper, 2002). The Arrabury Formation is absent south of the Murteree Ridge where it has been eroded (Alexander et al., 1998). The base of the unit is demarcated by the abrupt but conformable change upwards from black to dark grey organic–rich siltstone and coal of the Toolachee Formation. The Arrabury Formation also unconformably overlies sedimentary rocks and volcanics of the Warburton Formation beyond the zero edge of Permian sediments. The Arrabury Formation is unconformably overlain by Eromanga Basin sediments in the southern Cooper Basin, and conformably by Tinchoo Formation in the Patchawarra Trough and northern areas. The Arrabury Formation is generally 200 to 350 m thick in the Nappamerri Trough and between 380 to 390 m in the Arrabury Trough (McKellar, 2013). Near the southeastern and northwestern limits of deposition in Queensland it is mostly 50 to 100 m thick (Grey and McKellar, 2002; McKellar, 2013). The Arrabury Formation is assigned to the APP6–APT2 succession of palynological zone (Gray & McKellar, 2002). Updated zone age assignments place the top of APP6 at 251.5 in the Induan, whilst the top APT2 is estimated to match with the top Olenekian (247.1 Ma). The paleolatitude of the Cooper Basin was high in the Triassic as it was in the Permian, and deposition of the Arrabury Formation was humid rather than arid (Retallack et al., 1996) with high watertables. Deposition was during the worldwide “Early Triassic coal gap” (Veevers et al., 1994) when peatforming plants became extinct (Retallack et al., 1996). Deposition is interpreted as being in vegetated floodplains with ephemeral lakes in low-lands, with pedogenesis in exposed areas. The floodplain was cut by low sinuosity rivers confined to northeast-southwest channel belts in the Patchawarra and Nappamerri troughs (Alexander et al., 1998).

5.3.2 Tinchoo Formation The Tinchoo Formation forms the upper section of the Nappamerri Group. In Queensland, the formation is subdivided into the Gilpepee and Doonmulla members, but these members are not readily identifiable to the southwest in South Australia where the formation has been eroded and is relatively thin (Alexander et al., 1998). The Tinchoo Formation comprises interbedded brown–grey siltstone and light grey sandstone of the Doonmulla Member, which is overlain by dense light grey to green siltstone with minor coal seams of the Gilpepee Member (Powis, 1989; Alexander et al., 1998). Identification of the base of the Tinchoo Formation relies on the upper Wimma Sandstone Member of the Arrabury Formation being present (Powis, 1989), but consensus with this criterion remains elusive. However, in Queensland the lower contact is a mappable seismic marker (Gray & McKellar, 2002). The Tinchoo Formation conformably overlies the Arrabury Formation, except to the northwest of the Cooper Basin towards the Birdsville Track Ridge, where it unconformably overlies the Warburton Basin (Alexander et al., 1998). The Tinchoo Formation is unconformably overlain by the Cuddapan Formation or units of the Eromanga Basin. A maximum thickness of 109 m is preserved in South Australia (Telopea 1) where the formation has been eroded from crests of major ridges and towards the edge of the Cooper Basin (Alexander et al.,

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1998). In Queensland, the formation is 125 to 200 m thick and thickest (to 263 m) adjacent to the Windorah Trough (Powis, 1989; McKellar, 2013). The Tinchoo Formation is conformable with palynological unit APT3 and equivalent biozones, giving a Middle Triassic (Anisian–Ladinian) age (Grey and McKellar, 2002). The succession has characteristic planar cross-bedded, fine to medium grained sandstone with thin siltstone interbeds. Youngs & Boothby (1985) interpreted a depositional environment with highsinuosity fluvial channels based on upward-fining electrofacies signatures. However, low sinuosity fluvial conditions are interpreted in Telopea 1, suggesting a transition in channel type across the flood basin. The upper, more uniform succession was probably deposited under extensive fluvio-lacustrine conditions (Gray & McKellar, 2002).

Figure 5.18: Nappamerri Group isopach map in metres, with well intersections.


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6 Reservoirs and Seals

6.1 Introduction This chapter reviews the main reservoirs and seals across the basin, primarily based on the work of Gravestock et al. (1998) and Gray & Draper (2002).

Figure 6.1: Stratigraphic units and presence of source, conventional reservoir and seal rocks in the Cooper and Eromanga Basins (after Deighton et al., 2003).

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6.2 Reservoirs 6.2.1 Introduction The main commercial reservoirs are in the Patchawarra and Toolachee formations and at a lesser capacity the Epsilon Formation in southwestern Queensland. Commercial reservoirs also exist in the Merrimelia Formation, Tirrawarra Sandstone, Daralingie and Arrabury formations. As reservoir facies are predominantly fluvial, with some paraglacial and shoreface-beach-delta types, their reservoir geometry and internal porosity-permeability variations are significant. Porosity and permeability statistics of the Cooper Basin reservoirs are summarised in Table 6.1. These determinations were made at ambient conditions and are overestimates. A correction factor of 0.95 accommodates overburden pressure (Morton, 1989). Variation in the porosity-permeability relationship of reservoirs is largely accounted for by primary lithology and the burial depth. In general, little of the porosity observed in the reservoirs is primary, although detrital illite is the main cause of reduced porosity and permeability in finer-grained floodplain sand. Porosity may also be reduced by authigenic minerals: quartz overgrowths, siderite, and kaolin in the shallower reservoirs, and illite, clinochlore, and pyrophyllite more deeply buried sandstones. Table 6.1: Summary of Cooper Basin porosity and permeability data from Gravestock et al. (1998). Formation

No.

Sample Depth Min (m)

Sample Depth Max (m)

Sample Porosity Porosity Porosity Perm. Depth Av Min Max Av Min (m)

m

m

m

%

%

%

mD

mD

mD

Perm. Perm. Max Av

Cuddapan Formation

22

2658

2667

2663

0.0

17.6

9.20

0.0

3674

1.58

Tinchoo Formation

56

2489

2506

2497

0.2

19.3

11.9

0.008

1985

26.1

Wimma Sst Mbr

32

2130

2164

2157

2.5

22.9

10.0

0.05

865

0.926

Paning Mbr

202

2125

2505

2173

1.2

22.9

11.6

0.01

885

1.98

Callamurra Mbr

96

2086

2859

2465

1.4

21.1

9.7

0.1

296

0.620

Toolachee Formation

996

1867

3234

2180

0.1

25.3

12.4

0.001

1995

3.363

Daralingie Formation

173

2331

2509

2424

0.4

20.4

9.7

0.0040

414

0.397

Epsilon Formation

238

1952

3114

2409

0.9

21.0

9.1

0.007

407

0.680

Patchawarra Formation

846

1764

3547

2463

0.2

23.8

10.5

0.005

2503

0.933

Tirrawarra Sandstone

718

2208

3114

2643

1.7

18.8

11.1

0.007

329

1.59

Merrimelia Formation

59

1952

3148

2990

0.4

16.5

7.7

0.002

30

0.109


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Reservoir rocks in the lower succession of the Cooper Basin lie within the Tirrawarra Sandstone and Merrimelia Formation and contain a higher proportion of lithic components and range from quartzarenite to litharenite (Rezaee & Lemon, 1996; Chaney et al., 1997; Gravestock et al., 1998). Reservoir rocks are present within the Patchawarra, Epsilon, Daralingie and Toolachee formations and comprise dominantly quartz (65%), minor to trace amounts of altered feldspar, and authigenic components: kaolin (7.1%), illite (7.4%), carbonate (7.7%), carbonaceous material (7.7%) and mica (5.1%) (Gravestock et al., 1998). Secondary porosity, formed by dissolution of lithic and feldspar grains, is predominant in many reservoirs, while microporosity may be significant where kaolin is present (Gravestock et al., 1998).

6.2.2 Key reservoir intervals 6.2.2.1 Merrimelia Formation and Tirrawarra Sandstone Within the Merrimelia Formation, a distinctive paraglacial aeolianite facies has 12 to 18% core porosity and permeability to 75 mD (Gravestock et al., 1998). With both the Merrimelia Field and Pondrinie discovery, this facies has the best reservoir quality in terms of thickness and average porosity in the entire Cooper Basin. The Tirrawarra Sandstone is the major oil reservoir in the southwestern region of the Cooper Basin, and in addition, produces free-flow and tight gas. Oil is produced in Tirrawarra, Fly Lake, Brolga and Mooraki – Woolkina fields. Gidgeapla Field south dome has oil with gas cap and wet gas. Other Tirrawarra sandstone gas fields are Pondrinie, Bookabourdie, Kurunda and Big Lake. The Tirrawarra Sandstone is a widespread single sandstone package which has uniform reservoir character at a regional scale, but only a small field has produced on the Pepita Trend in Queensland. Generally reservoir porosity is 10 to 15% and permeability 1 to 100 mD.

6.2.2.2 Patchawarra Formation The Patchawarra Formation contains the most significant gas-condensate reservoirs in the Cooper Basin (Gravestock et al., 1998). The reservoirs are multi-storey fluvial channel, point bar and crevasse splay sandstones as both structural and stratigraphic traps, at 1800 to 3500 m below present surface. Porosity and permeability range widely but rarely exceed 15% and 100 mD. Maximum porosity values indicate that ‘sweet spots’ may persist at depths approaching 3200 m or more. Patchawarra Formation sandstone reservoirs are of variable thickness but rarely exceed 14 m.

6.2.2.3 Epsilon Formation There is a wide distribution of good reservoirs in the Epsilon Formation but it is considered less predictable for exploitation in comparison to the Patchawarra and Toolachee formations (Gravestock et al., 1998). In fluvio-deltaic and shoreline sandstone reservoirs, distributary and shoreface sandstones rarely exceed 4 m gross thickness but locally reach 10–15 m as in the Big Lake, Munkarie and Yapeni Fields. The broad spread of porosity and permeability values appears unrelated to both gross sand thickness and the two major facies associations. The majority of beds are 2 to 4 m thick and all but the thinnest contribute to net pay. A feature of the Epsilon Formation reservoirs is the variation in net pay thickness and fair to excellent porosity. Thin shoreface sands yield gas flows at the same rate as stacked deltaic sand (Gravestock et al., 1998).

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6.2.2.4 Daralingie Formation Stacked reservoir sandstone in the lower Daralingie Formation is interpreted as lacustrine delta front bar, beach and shoreface deposits in the Moomba Field (Williams, 1994). High-sinuosity fluvial channel sandstone with crevasse splay is the interpreted reservoir facies in the upper parts of the formation (Gravestock et al., 1998). Reservoirs occur at depths of 2300 to 2500 m below surface. Porosity ranges from 0.4 to 20.4% and permeability from 0.4 to 414 mD, with averages of 9.7% and 0.4 mD. The common porosity range is 5–10% and permeability 0.01 to 0.1 mD. Depleted gas reservoirs within the lower Daralingie Formation in the Moomba Field have been used for sales gas and ethane storage since the 1980’s. Reservoir potential of the Daralingie Formation in the northeastern Queensland section is more limited as much of this succession has been removed by erosion.

6.2.2.5 Toolachee Formation The main reservoirs of higher porosity sands occur in the lower Toolachee Formation as stacked, moderately thick (up to 6 m) point bar sands (Gravestock et al., 1998). These have average thickness of 5 m and bank full width estimated at 105 m (Williams, 1984) to 166 m (Mackie et al., 1995). Other reservoir sands of lower porosity are interpreted as abandoned channel and proximal and distal crevasse splay deposits (Mackie et al., 1995). The Toolachee Formation is widespread across the entire basin with the exception of erosion of crests of the Merrimelia, Murteree and Dunoon ridges. The formation thins from > 150 m thickness in the southwestern region, to < 50 m in the northeastern region in Queensland. In the Moomba Field, reservoirs of this formation contain 25% of all Cooper Basin gas discovered to 1994 (Mackie et al., 1995). In Queensland, 38 fields have reservoirs in this formation which produce more gas than liquids. Porosity ranges from 0.1 to 25.3% and permeability from 0.001 to 1995 mD, with averages of 12.4% and 3.4 mD. The most common porosity range is 10 to 15% while permeability is more evenly distributed with a mode of 1 to 10 mD. Reservoirs in the Toolachee Formation lie at depths ranging from 1870 to 3250 m and although there is a general reduction of porosity with depth, as with the Patchawarra Formation, there are some sweet spots at depth.

6.2.2.6 Arrabury Formation Although the Arrabury Formation is generally regarded as a regional seal, reservoirs occur within the Callamurra, Paning and Wimma Sandstone members (Gravestock et al., 1998). The Callamurra Member contains economic oil and gas reservoirs locally, and is a leaky seal elsewhere. This member occurs at depths from 2086 to 2860 m. Channel sandstones occur within high sinuosity rivers which carved into floodplains. Sands are predominantly < 2 m thick, but it is the thicker stacked point bar sands which are most productive. The Paning Member is the most widely distributed member of the Arrabury Formation. Reservoirs occur at depths from 2120 to 2500 m and contain economic accumulations of oil and gas. High sinuosity channel belts with good sand development in the Patchawarra Trough pass laterally into lowenergy low permeability floodplain facies (Channon and Wood, 1989). Two-thirds of sand beds are < 2 m thick.


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Reservoirs in the Wimma Sandstone Member were deposited in low-sinuosity rivers, which form a 70 km long southwest-northeast belt along the Patchawarra Trough (Channon and Wood, 1989). Economic oil and gas reservoirs lie at depths of 2130 to 2160 m. Most sand beds are < 2 m thick.

6.2.2.7 Tinchoo Formation The Tinchoo Formation is restricted to the northeastern Patchawarra Trough and the Queensland sector of the basin. Reservoirs lie at depths of about 2500 m and produce oil. These reservoirs are considered to be high-sinuousity fluvial channels based on upward-fining packages identified in electrofacies (Youngs & Boothby, 1985), although some channels are not upward-fining and are interpreted from core as low-sinuosity channels (Gravestock et al., 1998). Porosity ranges from 0.2 to 19.3%, permeability from 0.008 to 1985 mD, with averages of 11.9% and 26.1 mD respectively. Porosity is most common in the range 10 to 15% and tails off over 20%. However, permeability has wider distribution, mostly 100 to 1000 mD.

6.3 Seals The Nappamerri Group is generally regarded as a major basin wide seal to the Gidgealpa Group. However, it has limited effectiveness as seen by oil and gas accumulations within members of the Arrabury and Tinchoo formations within this Triassic succession, as well as commonly stacked hydrocarbon accumulations up succession in the overlying Eromanga Basin on the one structure. The basal Callamurra Member of the Arrabury Formation is the most effective unit of the entire group as a seal, but this unit is absent in eastern and northern areas of the basin (Gray & Draper, 2002). Heath (1989) noted a strong relationship between oil discoveries in the Eromanga Basin and relatively thin Permo–Triassic seals. Boult et al. (1997) proposed that the Arrabury regional seal influences accumulations such as that in the Gidgealpa Field, by controlling secondary migration of Permian oil and gas into Jurassic–Cretaceous traps. This suggests that the Nappamerri Group has low capillaryseal efficiency and can only contain hydrocarbons while there is ongoing generation and recharge of hydrocarbons. The Murteree and Roseneath shales, in the southwestern part of the Cooper Basin, are moderately effective as competent regional seals (Gray & Draper, 2002). The Murteree Shale provides a seal to the underlying Patchawarra Formation, and the Roseneath Shale is seal to the Epsilon Formation. All of the reservoir units, except for the Tirrawarra Sandstone and Merrimelia Formation, have stacked upward-fining fluvial deposits, or upward-coarsening crevasse splay, delta top, shoreline and bar deposits. The intraformational seal is typically a succession ranging from 3 to 20 m thick, of siltstone, shale and coal (Gravestock et al., 1998).

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7 Conclusions

This report presents an overview of basin architecture, tectonic evolution and lithostratigraphy and is the first part of a series of reports reviewing various aspects of the petroleum prospectivity of the Cooper Basin. Structural architecture, formation extent and thickness is characterised through construction of a regional 3D geological model, designed to capture the formations associated with the major play types in the basin. Existing published Cooper Basin horizons (NGMA, 2001; DMITRE, 2001; DMITRE, 2009) are integrated with formation tops and new seismic data interpretations, ensuring seamless integration of datasets across the state border. The late Neoproterozoic to Cenozoic evolution of the Cooper Basin region is discussed in the context of the broader tectonic evolution of eastern Australia. In addition, stratigraphy ages have been updated to produce a revised Cooper Basin stratigraphic chart, consistent with the 2012 Geological Time Scale (Gradstein et al., 2012) and updated spore pollen age calibration (e.g. Nicoll et al., 2015). The new formation ages, along with the timing of key tectonic events and regional erosion estimates, are assigned to the 3D geological model, enabling extraction of time-slice cross-sections through the basin, capturing the regional burial history of the Cooper–Eromanga–Lake Eyre succession Isopachs extracted from the 3D model are used to review the extent and thickness of each formation. The Permian Toolachee and Patchawarra formations in Queensland are shown to have a wider extent compared with previous studies. In addition, the boundaries of Roseneath and Murteree shales were revised, although their distribution still remains uncertain in areas such as the Arrabury Depression. Lithofacies analysis published for South Australia (Sun & Camac, 2004) are integrated with new electrofacies mapping results in Queensland to produce the first basin wide set of lithofacies maps for the Toolachee, Daralingie, Epsilon and Patchawarra formations. The resulting net sand, silt, shale and coal thickness maps characterise the regional distribution of key source, reservoir and seal intervals across the basin. Maps of net coal and shale thickness clearly demonstrate an abundance of potential source rock facies in the Toolachee and Patchawarra formations in all regions. Additional potential source rock facies can be found in the Roseneath and Murteree shales and coals and shales of the Daralingie and Epsilon formations. Net sand thickness maps highlight possible reservoir facies distribution. This study presents the most detailed regional 3D geological model published for the Cooper Basin to date. The model is designed to characterise the formations associated with the basin’s key petroleum systems elements, providing a framework for future regional scale petroleum systems analysis and resource assessment studies. While this work provides important insights into both the conventional and unconventional hydrocarbon prospectivity of the basin (Hall et al., 2015; Kuske et al., 2015), it also has application for the assessment of other resources such as groundwater (e.g. Smith et al., 2015a, b, c).


83

Acknowledgements

Many thanks to our reviewers, including Martin Smith, Anthony Budd and Paul Henson from Geoscience Australia and John Morton, Alan Samson and Elinor Alexander from the Department of State Development, South Australia. Thanks to 3D GEO Pty Ltd for their assistance with well and seismic data compilation and construction of the Petrel project. We thank Silvio Mezzomo and Bianca Reece for their assistance with figure production, and Daniel Rawson for his help in preparing the manuscript for publication. Thanks also to Dianne Edwards, Steve le Poidevin and Riko Hashimoto for their support and guidance during this project.

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