Queensland Geological Record 2017/01 the Shale Oil Potential of the Toolebuc Formation, Eromanga and Carpentaria Basins, Queensland: Regional Overview S

Department of Natural Resources and Mines Geological Survey of Queensland

Queensland Geological Record 2017/01 The shale oil potential of the Toolebuc Formation, Eromanga and Carpentaria basins, Queensland: Regional overview S. Edwards & A. Troup Acknowledgements

The authors would like to thank Justin Gorton and Behnam Talebi for their comments and review, Micaela Grigorescu for initial figure preparation and editorial assistance, and the GSQ’s Spatial and Graphics Services, in particular Gina Nuttall, Liam Hogan, Paula Deacon and Sharon Beeston, for final figure drafting and layout.

The authors would also like to thank Melanie Fitzell for her contributions in instigating the early stages of this project.

Address for correspondence:

Geological Survey of Queensland Department of Natural Resource and Mines PO Box 15216 City East QLD 4002 Email: [email protected]

The Queensland Government supports and encourages the dissemination and exchange of information. The copyright in this publication is licensed under a Creative Commons Attribution 4.0 International (CC BY 4.0) licence.

Under this licence you are free, without having to seek permission from DNRM, to use this publication in accordance with the licence terms.

You must keep intact the copyright notice and attribute the State of Queensland, Department of Natural Resource and Mines, as the source of the publication.

For more information on this licence visit http://creativecommons.org/licenses/by/4.0/deed.en

Cover photographs: Core photography from the Hylogger™ for GSQ Julia Creek 1.

ISSN 2203-8949 (CD) ISBN 978-1-922067-88-3 (CD) ISSN 2206-0340 (Online) ISBN 978-1-922067-87-6 (Online) Issued: April 2017

Reference: EDWARDS, S. & TROUP, A., 2017: The shale oil potential of the Toolebuc Formation, Eromanga and Carpentaria basins, Queensland: Regional Overview. Queensland Geological Record 2017/01. i

Contents

Introduction...... 1 Geological overview...... 4 Eromanga and Carpentaria basins...... 4 Toolebuc Formation ...... 6 Depositional environment and facies ...... 9 Exploration history...... 11 Resource assessment methodology...... 15 Summary ...... 18 References...... 19

FIGURE 1. Unconventional hydrocarbon potential in Queensland’s sedimentary basins...... 2 2. Extent of the Toolebuc Formation in Queensland...... 3 3. Stratigraphic column of the Early Cretaceous ...... 5 4. Core photography from the Hylogger™ for GSQ Julia Creek 1 ...... 7 5. Typical wireline log response for the Toolebuc Formation in GSQ Julia Creek 1...... 8 6. USGS-based methodology adapted for the assessment of the Toolebuc Formation...... 17 ii Queensland Geological Record 2017/01 1

INTRODUCTION

Exploration for petroleum in Queensland began in earnest in 1960 after the introduction of the Australian Government Petroleum Search Subsidy Act 1957. Exploration was conducted across the state, but gradually focussed into the Bowen– Surat and Cooper–Eromanga regions, where the larger discoveries were made. Within historical exploration well completion reports there are many examples of hydrocarbon shows within tight reservoirs or over source rock intervals. A review of these reports and other published petroleum systems studies has highlighted formations across Queensland that may have potential for unconventional petroleum, though further assessment of their characteristics is required to determine their potential as viable exploration targets (Figure 1).

The exploration for unconventional petroleum resources, other than coal seam gas, is still in its infancy in Queensland. While coal seam gas (CSG) has defined reserves underpinning three liquefied natural gas (LNG) export projects, only 50 wells have been drilled across the state to assess other unconventional resources. Further studies are necessary to build an understanding of the potential for these resources.

In this context, the Geological Survey of Queensland (GSQ) has examined the Toolebuc Formation in western Queensland. The Toolebuc Formation of the Eromanga and Carpentaria basins (Figure 2) has been historically disregarded as a hydrocarbon exploration target, due to its low thermal maturity, porosity and permeability. Despite these characteristics, many well completion reports held by the Queensland Department of Natural Resources and Mines (DNRM) describe oil staining, petroliferous odours and mudlog gas kicks from this formation. Where it is shallow and immature, the Toolebuc Formation is a target for oil shale development, particularly near Julia Creek, in the northern Eromanga Basin, and has been noted to have high vanadium and molybdenum contents. Given this potential for oil shale at shallow depths, the focus of this assessment is to determine whether the formation may be prospective for shale gas or oil where it has been buried more deeply.

This GSQ record forms the first part of a series of records detailing the shale oil potential of the Toolebuc Formation. It will summarise the outcomes of previous studies completed on the Toolebuc Formation and its characteristics as well as introduce the assessment criteria set out by Charpentier & Cook (2010) and Charpentier & Cook (2011). Further records will discuss the data and interpretation, the prospectivity evaluation and petroleum systems modelling of the formation.

2 Edwards & Troup

138° 140° 142° 144° 146° 148° 150° 152° 154°

Prospective basins and formation extents

Mesozoic basins Laura Basin Maryborough Basin

12° 12° Extent of Toolebuc Formation Extent of Walloon Coal Measures 0 100 200

Kilometres Late Palaeozoic basins Permian extent in the Cooper Basin Nappamerri Trough

14° Text Extent of Roseneath Shale, Epsilon Formation 14° ± and Murteree Shale in the Cooper Basin Extent of the Aramac Coal Measures and Betts Creek beds in the Galilee Basin Laura Extent of Permian Coal Measures in the Bowen Basin Basin Taroom Trough Extent of the Black Alley Shale

16° 16° Extent of Tinowon Formation

Mid Palaeozoic basins Adavale Basin and Warrabin Trough Carpentaria Basin Early Palaeozoic basins

18° Georgina Basin 18° Isa Super Basin Proterozoic basins Burdekin Basin Extent of Lawn Hill Formation, Termite Range Formation and Riversleigh Siltstone in the Isa Super basin

20° 20° Millungera Basin

Georgina Basin Styx Basin

22° 22°

Drummond Basin Galilee Basin

Eromanga

Northern Northern Territory Basin

24° 24°

Maryborough Bowen Basin Basin Adavale Basin

Warrabin

26° Trough 26° South Australia Cooper Nambour Basin Basin 14B\Reports\Toolebuc\DeepGas-Oil.mxd

Eromanga Basin Surat Basin

28° 28°

Ipswich Basin Clarence-Moreton New South Wales 138° 140° 142° 144° 146° 148° 150° 152° Basin 154° Figure 1. Unconventional hydrocarbon potential in Queensland’s sedimentary basins.

Queensland Geological Record 2017/01 3

138° 140° 142° 144° 146° 148° 150° 152° 154°

12° Boreholes by operator 12° # 0 100 200 GSQ E Kilometres LRH k PGN Beryl Anticline 14° 14° ± Canaway Fault Toolebuc extent (approx.)

Well Number Well Name 1 LRH BESSIES 1 2 LRH EUSTON 1 16° 3 LRH KATHERINE 1 16° 4 LRH SANCHO 1 5 LRH KATHERINE WEST 1 6 LRH KATHERINE EAST 1 7 LRH SCOTTY CREEK 1 8 LRH ROCKY CREEK 1 9 LRH FITTLEWORTH 1 10 LRH SILVERFOX 1 11 PGN MINION 4 18° 18° Carpentaria 12 PGN MINION 5 13 PGN MINION 8 B a s i n 14 PGN MINION 9 15 PGN MINION 6 16 PGN MINION 3 17 GSQ JULIA CREEK 1 18 LRH SALTERN 1 19 LRH WONGANELLA 1 20° 20 LRH SALTERN 1A 20° 21 LRH PRAIRIE 1A JULIA CREEK 22 LRH HOLLOWBACK 1 )"") 23 LRH ALMA 1 # 24 LRH CULLODEN 1 25 LRH DARR 1 26 LRH NORA 1 27 LRH WARDOO 1 E k k E 28 LRH BRIXTON 2 22° 22° E E k k k 29 LRH PRAIRIE 1 k E E

E E E E E E E E E EE

Northern Northern Territory E E 24° 24° BEDOURIE )" E r o m a n g a B a s i n

26° 26° South Australia CHARLEVILLE )" 17A\Records\QGR2017-01.mxd

28° 28°

New South Wales 138° 140° 142° 144° 146° 148° 150° 152° 154° Figure 2. Extent of the Toolebuc Formation in Queensland.

4 Edwards & Troup

GEOLOGICAL OVERVIEW

Eromanga and Carpentaria basins

The Eromanga and Carpentaria basins are part of the Great Australian Superbasin—a series of interconnected Mesozoic basins covering most of Queensland (Jell et al., 2013). The Carpentaria and Eromanga basins cover most of western Queensland. They are separated by the Euroka Arch, a broad subsurface ridge developed in the Late Jurassic (Exon & Senior, 1976).

The Late Triassic to Late Cretaceous Eromanga Basin underlies approximately 1,000,000 km2 of Central Australia, including Queensland, Northern Territory, New South Wales and South Australia and is up to 2700 m thick (Gallagher & Lambeck, 1989). It overlies several different basement terranes, including the Georgina, Cooper and Galilee basins, as well as the Mount Isa Province and Maneroo Platform. There are two main depocentres; the central Eromanga Depocentre overlying the Cooper Basin and the Poolowanna Trough (Radke, 2009).

The depositional history of the Eromanga Basin can be subdivided into four main phases. Localised deposition began in the late Triassic, which transitioned to extensive fluviatile and lacustrine deposition in the Early Jurassic to earliest Cretaceous (Cook et al., 2013b). A marine incursion lead to paralic deposition in the Early Cretaceous, with the deposition of the Wallumbilla and Toolebuc formations and the Allaru Mudstone. Terminal paralic, fluvial and lacustrine conditions extended into the Late Cretaceous (Cook et al., 2013b). The Eromanga Basin formations are described in detail in Draper (2002) and Cook et al. (2013b).

In Queensland, exploration in the Eromanga Basin can be divided into two domains, based generally on the underlying basement terranes. Where the Eromanga Basin overlies the Cooper Basin and to a limited extent surrounding it, exploration has been extensive with the discovery of 95 conventional oil fields in Eromanga Basin reservoirs, including Australia’s largest onshore oil field at Jackson. These fields are sourced primarily from the underlying Cooper Basin, though it is thought that up to 25% of the oil may have been sourced from the Birkhead and Poolowanna formations in the lower Eromanga Basin (Boreham & Summons, 1999). Beyond this region, exploration has been unsuccessful.

The Middle Jurassic to Late Cretaceous Carpentaria Basin underlies over 550,000km2 of the western lowlands of the Cape York Peninsula, much of the Gulf Country and the Gulf of Carpentaria in Northern Queensland. It overlies crystalline Proterozoic to Palaeozoic provinces, as well as several smaller infrabasins (McConachie et al., 1990; McConachie & Draper, 1997). Four depocentres have been described for the basin: the Western Gulf, Weipa, Boomarra and Staaten sub-basins. Deposition began in the Middle Jurassic with a series of terrestrial formations across the basin. A marine incursion began with the deposition of the Rolling Downs Group, which includes the Wallumbilla Formation, the Toolebuc Formation, the Allaru Mudstone and the Normanton Formation. These formations are described in detail in Cook (2013).

Queensland Geological Record 2017/01 5

ERA PERIOD EPOCH STAGE CARPENTARIA BASIN EROMANGA BASIN (AGE) S N SW NE

Turonian Late (in part) Cenomanian Winton Mackunda Formation Normanton Formation Formation

Allaru Mudstone Allaru Mudstone

Albian Toolebuc Formation Toolebuc Formation

Coreena Member

Wallumbilla Formation

Aptian Doncaster Member Wallumbilla Formation

MESOZOIC (in part) Early CRETACEOUS (in part) Wyandra ? Sandstone Barremian Cadna-owie Member Formation "uppermost Westbourne Hauterivian Gilbert River Formation" Formation ? ??Hooray

Helby beds Sandstone Valanginian Murta Formation ? ?

(in part) “upper ? ? ? ? Berriasian Namur Namur JURASSIC (in part) Late Sandstone Sandstone” ?? Tithonian ?

? 14B\Reports\Toolebuc\3 ? ?? ? ? ? ? ? Figure 3. Stratigraphic column of the Early Cretaceous (after McKellar in Cook et al., 2013, Figure 7.2).

The Carpentaria Basin is considered to be high risk for conventional hydrocarbon exploration, with uncertainty around all components of the petroleum system (McConachie et al., 1990). Dead oil stains, tarry and bituminous odours and fluorescence from the Gilbert River and Toolebuc formations in the Carpentaria Basin are detailed in Passmore et al. (1993). The onshore Mesozoic source rocks are only marginally mature, and the only likely Permian source rocks are overlain by unsealed Mesozoic sandstones (McConachie & Draper, 1997). The main play type in the onshore section of the basin is compaction and drape of the basal Mesozoic sandstones over basement highs, with stratigraphic pinchouts important in areas where onlap was insufficient to cover them (McConachieet al., 1990).

This review will focus on the Toolebuc Formation. Detailed descriptions of the other formations in the basins can be found in Cook et al. (2013).

6 Edwards & Troup

TOOLEBUC FORMATION

The Toolebuc Formation is present across much of the Carpentaria and Eromanga basins in western Queensland. It represents the maximum transgression of an epicontinental sea during the Early Cretaceous. It was first given formation status as the Toolebuc Limestone by Vine et al. (1967).

Senior et al. (1975) redefined the Toolebuc Limestone as the Toolebuc Formation, due to the observation that the limestone component was subordinate to the mudstone component. They proposed the use of Toolebuc Formation as a name for the calcareous, heterogeneous sequence which overlies the relatively non-calcareous siltstone and mudstone of the Wallumbilla Formation and underlies the relatively non- calcareous Allaru Mudstone. The type section for the Toolebuc Formation is in BMR Boulia 3A (Burger, 1974; Senior et al., 1975).

The Toolebuc Formation comprises laminated calcareous and kerogenous mudstone, minor coquinite and limestone, labile sandstone and oil shale. The mudstone may contain laminae of crystalline carbonate formed from the remains of bivalves Inoceramus and Aucellina (Ozimic, 1986). The formation was deposited in a restricted, oxygen-depleted, marine environment, as indicated by the low diversity of benthic fauna and lack of bioturbation (Henderson, 2004).

The formation exhibits a distinct, serrated, gamma-ray anomaly in wireline logs, which occasionally has multiple peaks (Figure 5). Towards the southern extent of the formation, the peak diminishes and takes on a blocky character, eventually merging with background gamma-ray values. Senior et al. (1975) and Ozimic (1986) noted that the gamma-ray anomaly generally coincides with kerogenous mudstones rather than the coquinite or limestone facies. Ramsden et al. (1982) concluded that the gamma- ray anomaly was largely due to the uranium associated with organic matter in the kerogenous mudstones and with phosphatic skeletal fish debris in the accompanying coquinites, where the uranium was remobilised during diagenesis. Hoffmann (1986) noted that the Toolebuc concretions and oil shale are easily recognised in the field due to the strong petroliferous odour emitted when struck with a hammer.

The shale is black to dark grey, calcareous, variably pyritic and generally massive apart from bedding-parallel fissility. Dissolution analysis shows that calcium carbonate content ranges from 2 to more than 50% by weight (wt %) (Lewis, 2000). Calcareous micro-plankton are abundant (Glickson & Taylor, 1986) and include planktic foraminifera (Haig, 1979; Haig & Lynch, 1993) and nano-fossils (Shafik, 1985), radiolaria (Hoffman, 1986) and some intervals have scattered bivalve fragments. Fish remains, especially scales, bones, and teeth are common, along with reptilian bone fragments as well as belemnites (Henderson, 2004). These fragments are believed to contribute to the distinctive gamma ray response (Moore et al., 1986; Patterson et al., 1986; Lewis et al., 2010). Based on diffraction spectra of shale samples, clays are dominated by smectite and kaolinite (Hoffman, 1986; Patterson et al., 1986).

Queensland Geological Record 2017/01 7 m), Toolebuc Formation Toolebuc m),

Base Toolebuc m).

Top Toolebuc Top m) and uppermost Wallumbilla Formation (from 199.87 Wallumbilla m) and uppermost

Figure 4. Core photography from the Hylogger™ for GSQ Julia Creek 1 showing the lowermost Allaru Mudstone (to 156.65 Figure 4. Core photography from the Hylogger™ for GSQ Julia Creek 1 showing lowermost (156.65–199.87

8 Edwards & Troup

GSQ JULIA CREEK 1

COMPANY: Geological Survey of Queensland LATITUDE: -20.904520 S LONGITUDE: 147.472587 E DRILLED DEPTH: 500.02 DATE PLOTTED: 06-Apr-2017 VERTICAL UNITS: METRES VERTICAL SCALE: 1:600

Figure 5. Typical wireline log response for the Toolebuc Formation in GSQ Julia Creek 1.

The organic carbon content of the shale facies is variable but commonly exceeds 10 wt % (Lewis, 2000) with recorded values up to 35 wt % (Riley & Saxby, 1982). The Toolebuc Formation occurs at shallow depths in the Julia Creek area and is sufficiently rich enough in organic matter to have been considered as a potential oil-shale resource (Patterson, 1994). Trace metals, especially vanadium, nickel, molybdenum, zinc and copper are strongly concentrated in the shale and are thought to be associated with the organic fraction (Riley & Saxby, 1982; Sundararaman & Boreham, 1993; Lewis, 2000; Lewis et al., 2010). Organic geochemical profiling of samples from across the Eromanga Basin by various authors indicates that organic matter shows little variation in elemental compositions with hydrogen to carbon ratio (H/C) between 0.9 and 1.3%, and nitrogen content of approximately 2.5%, possibly indicating a consistent source (Riley & Saxby, 1982; Saxby, 1986; Boreham & Powell, 1987). Sherwood & Cook (1986) interpreted the organic content of the Toolebuc shale as indicative of predominantly algal origin, a view supported by the distribution of biomarkers extensively documented by Boreham & Powell (1987). They interpreted the organic geochemical signatures of the Toolebuc shale facies, including biomarkers sources from dinoflagellates, as consistent with a planktic source, rather than a benthic source.

Queensland Geological Record 2017/01 9

Coquina intervals may comprise up to 80% shelly debris (Lewis, 2000) with thin beds and laminae of black shale interlaminated with shell-rich beds. These horizons are predominantly comprised of Inoceramus debris which are typically fragmented, and persistent in exposures and core intersections of the coquina. Minor, sporadically distributed Aucellina valves have also been noted.

In general, Inoceramus valve fragments up to 10 cm in diameter are present in coquina intervals. Large valves are intact, although the remains of in situ paired valves can be identified along with juveniles, sized 2–4cm, which may occur paired and in situ within concretionary horizons resting on the outer surface of larger specimens (Henderson, 2004). Bedding surfaces commonly contain a large range of fragmentation styles and fragment sizes.

Intact paired valves are present at most locations, though they are uncommon. (Henderson, 2004) describes a variety of fragmentation styles, including:

1. fragmented in situ shells

2. partial valves split by broad, debris filled fractures

3. coarse-grained debris zones where the bulk of shell fragments exceed 3 cm in diameter

4. debris zones consisting of shell fragments in the range of 3 mm to 1.5 cm, typically with angular margins

5. zones where the shells have been degraded to randomly oriented individual prisms.

It has been suggested this fragmentation is the result of fracturing during burial, current activity or predation, or a combination of these (Henderson, 2004).

Depositional environment and facies

The depositional environment of the Toolebuc Formation has been the subject of a number of studies. The characteristics of the formation all suggest it was deposited in a restricted epicontinental sea (Ozimic & Saxby, 1983) representing the maximum transgression of the Cretaceous epicontinental sea in eastern Australia (Henderson, 2004).

The typically conformable contacts with the underlying Wallumbilla Formation and overlying Allaru Mudstone imply that the deepening of the epicontinental sea which led to the deposition of the Toolebuc Formation, followed by subsequent shallowing, was gradual. The maximum deepening of the epicontinental sea positioned the sea floor below wave base and beyond the depth of wind-generated currents (Henderson, 2004), as evidenced by flat-lying laminations with little indication of current direction. Sporadic occurrences of sea floor currents are shown by local alignment of shells and shell fragments, which suggests that the bivalve communities were established near the margin of deep currents and experienced some circulation during storm events

10 Edwards & Troup

(Henderson, 2004). At the time of deposition of the organic-rich shale facies, the sea floor was under anoxic or dysoxic conditions (Hoffman, 1986; Henderson, 2004). Hutton & Cook (1983) noted telalginite and lamalginite in the kerogenous shale, suggesting algal productivity in the euphotic zone, as well as growth of algal mats on the sea bed. Glickson (1983) recognised mat-forming filamentous cyanobacteria, which were thought to be the major contributor to the total organic carbon (TOC) content of the formation.

The formation is dominated by a single species of bivalve, Inoceramus sutherlandi, with minor Aucellina hughendensis present in some beds (Ozimic & Saxby, 1983; Hoffman, 1986; Henderson, 2004). These two species were highly adapted to the low-oxygen conditions on the Toolebuc seafloor (Henderson, 2004). The coquinites have single or multiple laminae and are typically interbedded with organic-rich shale, suggesting fluctuations in oxygen levels that either suited the establishment of bivalve communities or led to their death (Ozimic & Saxby, 1983). Conversely, the colonisation of bivalve communities may be attributed to the destruction of algal mats (Ozimic & Saxby, 1983).

There have been several attempts to describe and subdivide the Toolebuc Formation based on its lithotypes, lithofacies and electrofacies. These studies all vary slightly in their approach, definitions and study areas, but arrive at similar descriptions of the formation, consisting of calcareous mudstone, shelly mudstone to coquinite, and an organic rich shale.

Ozimic & Saxby (1983) discuss four facies within the Toolebuc Formation and its equivalents, the Wooldrige Limestone Member to the west and Urisino beds to the south. Facies A and B consist of “black to dark grey, laminated kerogenous and calcareous shale interbedded with light grey calcite laminae, which when abundant, forms coquinite”. These facies were defined in core from the Toolebuc Formation type section in BMR Boulia 3A and BMR Longreach 6. Facies A occurs throughout the Carpentaria Basin and most of the Eromanga Basin, with Facies B more prominent to the east of the Canaway Fault and Beryl Anticline. Facies C and D are associated with the Urisino beds and the Wooldridge Limestone Member respectively. Ozimic & Saxby (1983) included boreholes across the Eromanga and Carpentaria basins, but primarily along the shallow margins, where BMR stratigraphic drillholes intersecting the Toolebuc Formation were located. Several petroleum wells with deeper intersections were also used, however this work was conducted at a time when there were fewer petroleum wells drilled into the central part of the Eromanga Basin.

Moore et al. (1986) examined the upper Wallumbilla Formation, Toolebuc Formation and lower Allaru Mudstone in PELs 5 and 6 in South Australia and ATP 259P in southwest Queensland. They define three lithotypes in the Toolebuc Formation based on core from DIO Gilpeppee 2, sidewall cores from DIO Morney 1 and other wells and cuttings descriptions, which were then correlated with natural gamma and sonic log responses as follows: a. lowermost black calcareous mudstone (high gamma, low sonic) b. middle dark grey fossiliferous mudstone or coquinite (moderate gamma with high sonic) c. upper dark grey mudstone (moderate gamma ray).

Queensland Geological Record 2017/01 11

They subdivide the sequence into four electrofacies types, based on lithology and log- response, which tie into the lithotypes for the Toolebuc Formation.

Hoffmann (1986) examined the Toolebuc Formation near Julia Creek and found that the Toolebuc Formation in this area has two main facies—a clay-rich pelagic facies and a bioclastic limestone facies. A calcareous mudstone was also noted in the uppermost section of one of the examined drillcores.

Overall, the formation is laterally extensive with consistent lithology. However, it has been noted that individual facies can wedge out or change thickness across relatively short distances (Henderson, 2004). This likely reflects the variability of the depositional environment, and may present a challenge in tracking reservoir facies.

This study by GSQ has used a 3-fold subdivision of the formation, similar to that of Moore et al. (1986), based on core logging of 15 GSQ stratigraphic wells. Further detail and discussion on the facies subdivision in this study will be presented in the data and interpretation record.

In summary, each study has had a slightly different approach to the subdivision of the formation. However, in general, the formation can be subdivided into two to three units based on lithological or geophysical characteristics.

Exploration history

Oil shale

The majority of exploration which specifically targeted the Toolebuc Formation focussed on evaluating its oil shale resource potential, particularly near Julia Creek. The processing of the shale for oil also provides potentially viable by-products including high vanadium and molybdenum contents. In 1965, Australian Aquitaine Petroleum (AAP) Limited discovered the Julia Creek oil shale deposit while exploring the area for uranium.

A prominent and widespread, radiogenic anomaly recognised in wireline logs whilst drilling for conventional oil resources, identified the deposit in theT oolebuc Formation. The presence of vanadiferous oil shale within the Toolebuc Formation initiated a twenty year period of extensive exploration and research by companies including AAP, The Oil Shale Corporation (TOSCO), CSR Limited, Shell, and Esso.

A comprehensive study on oil shale, lead by BMR, examined the Toolebuc Formation in the early 1980s (Ozimic & Saxby, 1983). This study focussed on the Toolebuc Formation where it was shallow, and interpolated characteristics into its subsurface extent. Based on this work, Ozimic & Saxby (1983) restricted the probable area of productive oil shale north of a line connecting Bedourie and Charleville, resulting in a resource estimate of 245 × 109 m3. Of this, approximately 20% is between depths of 50 m to 200 m and a candidate for open cut mining technology, while the remainder, below 200 m, would likely need to be produced through in situ retorting. Despite the

12 Edwards & Troup volume of resource present, the Toolebuc Formation is considered to be low-grade, as the yield of the shale is only 37 litres per tonne, on average (Ozimic & Saxby, 1983; Geoscience Australia & BREE, 2014).

In some of the BMR drillholes, a kerosene-like fluid with petroliferous odour was observed flowing to surface with drilling fluid returns (Ozimic & Saxby, 1983). However, it was concluded that due to the low thermal maturity of the Toolebuc Formation in the assessment area, the hydrocarbons are likely to have come from a more mature Eromanga Basin or Palaeozoic source, rather than being in situ. (Ozimic & Saxby, 1983). The pristine/phytane ratio is low at approximately 1.7, which suggests that it may have come from a marine source, while the pristine/n-C17 ratio indicates that it originated from more mature sources than the Toolebuc Formation.

A thorough summary of the exploration of the Toolebuc Formation in the Julia Creek region was conducted by (Whitchers, 1993). The earliest drilling in the area was by AAP, primarily targeting sedimentary uranium, with some oil shale assaying conducted. Following this assaying, TOSCO entered into a joint venture with AAP to further evaluate the prospect as an oil shale and vanadium deposit. Exploration and analysis of the prospect continued through the 1970s and 1980s, with CSR Limited reporting that it could produce about 5000 billion barrels of oil from its Julia Creek lease in central Queensland (Bell, 1984). Despite this, the tenure was relinquished in 1988.

In late 1991 and early 1992, CRA Exploration Pty Limited was granted six exploration permits in the Julia Creek area. They examined the deposit for in situ power or gas generation and for production of bitumen, but found that it was uneconomic under the conditions at the time. The tenure was subsequently relinquished (Thomas & Shirley, 1993).

In 2010, Blue Ensign Technology Limited, who own the patent and intellectual property of the Rendall process for production of synthetic crude oil from kerogen in oil shale, reported a potential resource of 2 billion barrels of synthetic crude oil extractable with the use of their Rendall system (http://blueensigntech.com.au/content/ julia-creek-resource).

In mid-2012, Global Oil Shale Group agreed to develop the Julia Creek oil shale tenements; with a JORC indicated and measured resource of 2.18 billion barrels of oil at an average 61 barrels per tonne grade (http://www.proactiveinvestors.com/ companies/news/31233/xtract-energy-boost-as-it-agrees-deal-with-global-oil-shale- group-to-develop-julia-creek-31233.html). During 2013, the company completed its first drilling program consisting of 116 drillholes up to 60 m deep; further testing was planned during 2014 and 2015 (http://globaloilshale.com/?page_id=22).

Data acquired during the exploration programs undertaken by Blue Ensign Technology Limited and Global Oil Shale Group is currently confidential.

Queensland Geological Record 2017/01 13

In summary, the Toolebuc Formation has been the target for uranium, vanadium, oil shale and molybdenum exploration since the 1960s with variable success. While resources have been defined several times, there has been no commercial production of the minerals resources in the formation; the economics have never been right. The most recent exploration has defined a JORC indicated and measured resource of 2.18 billion barrels of oil at an average grade of 61 barrels per ton near Julia Creek.

As of October 2016, the Toolebuc Formation has been recorded in 2386 petroleum wells, stratigraphic boreholes and water bores across the Eromanga and Carpentaria basins, though very few of these specifically included the formation as a primary or even secondary target. Despite this, these drillholes provide a good dataset for further examination on the resource potential of the formation.

Petroleum

In addition to the recognisable natural gamma peak observed in these wells, the Toolebuc Formation yields a consistent gas peak in mudlogs above background levels in surrounding formations, with some well completion reports (e.g. Gaddy et al., 1998) noting observations such as:

“Mud gas shows were recorded from the Toolebuc Formation where fluorescence and cut were recorded. … There is no recorded porosity or permeability within the Toolebuc Formation even though hundreds of wells have penetrated the interval.”

This characteristic underpinned the initial screening of the formation and will be further examined and discussed in the second record.

Prior to 2011, there were only sporadic attempts to examine the potential of the formation, with 3 DST tests conducted on the formation after strong gas shows were noted. EAL Norris 1 conducted a DST over the Toolebuc Formation after elevated ditch gas was recorded, though the test failed to produce any formation fluid (Greenwood, 1982). DIO Denley 1 ran a DST over the Toolebuc Formation after encountering a gas show of 320 units over a background of 10 units with a breakdown of 64/9/16/8/3. However, only 45’ of rathole mud was recovered (Taylor, 1985). BON Denbigh Downs 1 ran a DST over the Toolebuc formation at approximately 404.46– 415.13 m but concluded that the zone was too tight to be commercially successful (French, 1989).

Since 2011, 27 petroleum wells have examined the shale oil or gas potential of the formation in the northern Galilee Basin and Maneroo Platform regions. Exoma Energy Limited (Ltd) and Pangaea Resources Pty Ltd have both conducted exploration campaigns which aimed to evaluate the Toolebuc Formation as a shale gas or shale oil resource. These efforts were targeted in the northern Eromanga Basin, where it overlies the Maneroo Platform or the Galilee Basin.

Exoma Energy Ltd drilled 21 wells between mid-2011 and late 2012 (including two re-drills) on the Maneroo Platform and western flank of the Galilee Basin.The

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Toolebuc Formation was the primary target in 10 of the wells, and a secondary target in the remainder. Some reports record dark shales with petroliferous odour within the Toolebuc Formation, and the majority of wells record gas at low levels whilst drilling through the formation. Fluorescence was noted from the Toolebuc Formation in LRH Culloden 1 with a description of “pinpoint dull yellow natural fluorescence, very slow weak, dull yellow cut fluorescence, no residual ring observed” (Cane, 2013). Free oil was reported to be recovered from 35 m above the Toolebuc Formation in LRH Bessies 1 (Whitcombe, 2011), though no further analysis was reported on this oil or its origins. Geochemical analyses of samples from the Toolebuc Formation acquired during the drilling campaign have the high total organic carbon (TOC) and low Tmax values typical of the formation. Exoma Energy Limited has since relinquished their Maneroo Platform tenures.

In 2012, Pangaea Resources Pty Limited drilled seven wells (Minion series) in the western Eromanga Basin near Winton. In PGN Minion 3, 4 and 6, the Toolebuc Formation was a secondary exploration target with core acquired (Hoffman & Levy, 2012, 2013a, 2013b), while only cuttings samples were collected over the Toolebuc Formation in PGN Minion 5 (Levy & Hoffman, 2012). PGN Minion 8 was drilled as a cored stratigraphic drillhole, targeting both the Toolebuc Formation and coal measures of the Galilee Basin (Hoffman & Levy, 2013c). The primary target for PGN Minion 9 was the Toolebuc Formation (Hoffman & Levy, 2013d).

For all of the Minion wells, a sweet hydrocarbon odour was noted by well site personnel and traces of a brown ‘oil scum’ were observed on the surface of the mud tanks while drilling through the Toolebuc Formation (Hoffman & Levy, 2012, 2013a, 2013b, 2013c, 2013d; Levy & Hoffman, 2012). In addition to the hydrocarbon shows, a honey-brown oil staining was noted in the cores of all the Minion wells, within the Toolebuc Formation (Hoffman & Levy, 2012, 2013a, 2013b, 2013c, 2013d). PGN Minion 9 core was taken using the CorePro pressurised coring system. Four pressurised cores were taken and sent to TerraTek for saturation and porosity measurements. At the PGN Minion 9 site, the Toolebuc Formation was determined to be water saturated (73–88%), with minimal gas saturation (3–22%) and minor oil saturation (1–11%). Effective porosity values for the Toolebuc Formation ranged from 10–17% (Hoffman & Levy, 2013d). Following extensive geochemical and petrographic analysis of samples from the Toolebuc Formation, Pangaea Resources concluded that while the main components of a potential hydrocarbon resource exist, the maturity of the Toolebuc Formation at the Minion well sites was insufficient for the generation of hydrocarbons; not yet reaching the oil window.

In 2014, Real Energy Corporation Limited drilled two petroleum wells into the Cooper Basin to target basin-centred gas in the Windorah Trough. These wells intersected the Toolebuc Formation where it is deepest and likely to be more mature.

In summary, despite having been intersected by over 2000 wells across the Eromanga and Carpentaria basins and having a consistent gas kick in mudlogs, no commercial accumulation has been discovered. Unsuccessful exploration of the formation from a unconventional hydrocarbon perspective by Exoma Energy and Pangaea Resources Pty Limited in the northern Eromanga Basin has been attributed to low maturity in these regions.

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RESOURCE ASSESSMENT METHODOLOGY

The term ‘unconventional petroleum resources’ encompasses petroleum accumulations that are not producible through use of conventional drilling and completion technologies. Schmoker (2003) discussed the subjectivity of defining a petroleum resource as ‘unconventional’ and proposed the use of the term ‘continuous petroleum resources’, for accumulations which:

1. consist of large columns of rock pervasively charged with oil or gas

2. do not depend on the buoyancy of oil or gas in water for their existence.

These accumulations can occur in shales, tight sandstones or coal seams, and may contain varying ratios of gas and liquid petroleum content. Unconventional petroleum fields are typically defined by domains consisting of similar reservoir characteristics, completion methods, production characteristics, and/or economics rather than discrete accumulations located in structural and/or stratigraphic traps.

Unconventional shale plays are considered to be a self-sourcing reservoir and typically are the source rocks for conventional petroleum accumulations elsewhere in a basin. Shale plays contain the remaining hydrocarbons in the source rock which have not been expelled and are typically both adsorbed to organic and/or inorganic material as well as occupying any available free pore space.

As they are not constrained by structure or water contacts, defining the extent of continuous petroleum resources is more difficult than defining conventional petroleum fields. Play fairway mapping can be used when examining new plays to determine areas where right conditions coincide and a resource might exist. However, there is still great uncertainty around specific reservoir properties within these areas.

The United States Geological Survey (USGS) has developed a production-based, probabilistic method for resource estimation that is determined using the productivity of cells within an assessment area (Charpentier & Cook, 2011). The assessment area and reservoir characteristics are defined using existing well information and type-fit to existing commercial analogues (typically North American) to predict an estimated ultimate recovery (EUR) for each cell followed by a calculation of recoverable resource volume over the assessment unit.

The first stage of these assessments is to define an assessment unit based on the geological characteristics of the target formation; examining the region from a fairway mapping point of view. For shale gas assessments, these criteria are defined by Charpentier & Cook (2011) as:

• total organic carbon (TOC) > 2 weight % • kerogen type I, II or IIS • Ro > 1.1%

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• net thickness >15m • petroleum thermogenic in origin.

Other desirable characteristics include:

• high gamma ray values in shale • hydrogen index (HI) > 250 mg/g • depth > 1500 m • lack of intense structural deformation • overpressured.

It is important to note that these criteria were determined based on North American shale plays and that variations based on geological settings in other continents or frontier regions should be considered. For example, Charpentier & Cook, (2011) note that the criteria are defined for the assessment of thermogenically-derived petroleum in shales (source rocks) and the criteria for the assessment of tight gas, tight oil (including shale oil) and biogenically-generated hydrocarbons would require a modified set of assessment criteria. In general, the following criteria should be considered for shale reservoirs (Charpentier & Cook, 2010):

• lateral extent • thickness • total organic carbon • thermal maturity • well data on production and shows • pressure data • mineralogy • mechanical stratigraphy • organic geochemistry • natural fractures.

The Toolebuc Formation has data available for most of these characteristics, however the quantity and quality of the data is highly variable. As such, the criteria for shale gas assessment units defined by Charpentier & Cook (2011) have been modified and restricted to reflect the state of knowledge regarding the Toolebuc Formation and its likely status as a tight oil play, rather than shale gas play. The following criteria were used to delineate a potential play fairway for the Toolebuc Formation:

• TOC >2 wt% • modelled Rv,max > 0.6% (based on early entry into the oil window) • Gross thickness >30 m • the presence of butane and pentane in mudlogs as evidence for higher, thermogenic hydrocarbons (liquids-rich) in formation.

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Figure 6 outlines the broad methodology and workflow used to assess the shale oil potential of the Toolebuc Formation.

Figure 6. USGS-based methodology adapted for the assessment of the Toolebuc Formation.

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SUMMARY

The Toolebuc Formation extends throughout the Eromanga and Carpentaria basins in western Queensland. It comprises laminated calcareous and kerogenous mudstone, minor coquinite and limestone, labile sandstone and oil shale that were deposited in an epicontinental sea during the Early Cretaceous.

There have been several attempts to describe and subdivide the Toolebuc Formation based on its lithotypes, lithofacies and electrofacies. Each study has had a slightly different approach to the subdivision of the formation. However, in general, the formation can be subdivided into two to three facies based on lithological or geophysical characteristics.

Where the formation is shallow, particularly in the north near Julia Creek, the Toolebuc Formation has been the target for uranium, vanadium, oil shale and molybdenum exploration since the 1960s with variable success. While resources have been defined several times, there has been no commercial production of the mineral resources in the formation; the economics have never been right. The most recent exploration has defined a JORC indicated and measured resource of 2.18 billion barrels of oil at an average grade of 61 barrels per ton.

The formation has been historically disregarded as a hydrocarbon exploration target, due to its apparent low thermal maturity, porosity and permeability. Despite these characteristics, many well completion reports from across the Eromanga Basin in particular, describe oil staining, petroliferous odours and mudlog gas kicks. These characteristics indicate the formation may have generated hydrocarbons where it is buried deeper, and invite investigation as to whether the formation may present a target for unconventional hydrocarbon exploration.

Despite having been intersected by over 2000 wells across the Eromanga and Carpentaria basins and having a consistent gas kick in mudlogs, no commercial accumulation has been discovered. Unsuccessful exploration of the formation from a shale oil perspective by Exoma Energy and Pangaea Resources Pty Limited in the northern Eromanga Basin has been attributed to low maturity in these regions.

Charpentier & Cook (2010) and Charpentier & Cook (2011) present methodologies for examining new unconventional hydrocarbon plays, which consist of examining the characteristics of the target formation compared to what has been successful in the “US shale gas experience”. The basic criteria that should be considered for shale reservoirs are thickness, TOC, pressure, mineralogy, mechanical stratigraphy, organic geochemistry and natural fractures. These have been examined for the Toolebuc Formation, to the extent that available data allows, and the methods and results will be presented in Record 2 of this series.

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