Interim Otway Basin unconventional resource assessment · 2017-02-23 · 6.2 Summary shale resource assessment results ... The ‘shale gas’ revolution of the last ten years in

Interim Otway Basin unconventional resource assessment Geoscience Australia

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Executive summary

The offshore Otway Basin has a significant petroleum production history, yet relatively little exploration has been conducted onshore, especially for unconventional oil and gas. New production from unconventional resources in these basins could offset declining production from the offshore fields to feed into the National Energy Market, if policy settings and market conditions make extraction viable. This assessment provides an understanding of the potential for undiscovered unconventional gas and liquids in the Otway Basin, and highlights significant knowledge gaps.

A probabilistic volumetric assessment method has been used to assess the potential for unconventional gas and liquids resources, including shale and tight gas and liquids.

The Eumeralla Formation, Crayfish Sub-group and Casterton Formation were assessed to have shale gas and liquids potential in the Otway Basin. In addition, the Eumeralla Formation and Crayfish Sub-group were found to have tight gas and liquids potential. The table below summarises the potentially recoverable tight and shale gas-in-place (GIP), and liquids-in-place (OIP) resources estimated as 5% median assessed volume (P50) in the Otway Basin. Liquids-in- place as defined in this study includes both oil and condensate and will be abbreviated to OIP.

Otway Basin potentially recoverable tight and shale gas-in-place (GIP) and liquids-in-place (OIP) resources (estimated as 5% median assessed volume (P50)). NB: probabilistic summation has been used.

Potentially recoverable GIP (TCF) (5% @ P50)

Potentially recoverable OIP (B bbl) (5% @ P50)

Otway Basin tight resources 5.8 0.4

Otway Basin shale resources 1.7 1.0

Total Otway Basin (TCF) 7.6

Total Otway Basin (B bbl) 1.5

For all assessments, publically available data relevant to Otway Basin shale and tight resource plays was limited, necessitating the use of local analogues and geologically reasonable assumptions. Significant improvements could be made to the reliability of this assessment if more data were available. Of particular note is the use of well data to define the prospective rock volumes. This has likely produced a very conservative estimate of the gas- and liquids-in- place as only the geology penetrated by existing drilling has been able to be evaluated. Further work using a basin-wide 3D model would enable the assessment of the full geological volume and potentially alter the resource assessment result significantly.

Otway Basin unconventional resource assessment iii

Contents

Executive summary ................................................................................................................................. iii

Contents .................................................................................................................................................. iv

1 Introduction ............................................................................................................................................ 6 1.1 Petroleum – conventional versus unconventional ........................................................................... 7 1.2 Petroleum systems .......................................................................................................................... 8

1.2.1 Petroleum accumulation types ................................................................................................... 9 1.3 Unconventional resource assessments .........................................................................................10

1.3.1 Assessment methods ...............................................................................................................10

2 Regional geology .................................................................................................................................12 2.1 Structural geology ..........................................................................................................................12 2.2 Basin evolution and depositional history ........................................................................................14 2.3 Otway Basin petroleum systems ...................................................................................................18

2.3.1 Source rocks ............................................................................................................................18 2.3.2 Generation and expulsion ........................................................................................................19 2.3.3 Reservoirs and seals ................................................................................................................20 2.3.4 Play types .................................................................................................................................20

3 Resource development in the Otway Basin ........................................................................................22 3.1 Petroleum prospectivity and exploration history ............................................................................22 3.2 Infrastructure market and community ............................................................................................23

4 Play type summary ..............................................................................................................................25 4.1 Shale resources .............................................................................................................................25

4.1.1 Eumeralla Formation ................................................................................................................25 4.1.2 Crayfish Sub-group ..................................................................................................................28 4.1.3 Casterton Formation .................................................................................................................32

4.2 Tight resources ..............................................................................................................................34 4.2.1 Eumeralla Formation ................................................................................................................34 4.2.2 Crayfish Sub-group ..................................................................................................................35

5 Method .................................................................................................................................................36 5.1 Shale resources method ................................................................................................................37

5.1.1 Data inputs and sources ...........................................................................................................37 5.1.2 Defining area, prospective area, thickness and net thickness .................................................41 5.1.3 Reservoir characterisation and volume factors ........................................................................45 5.1.4 Estimating OIP and GIP using @Risk ......................................................................................46 5.1.5 Recovery factor ........................................................................................................................46

5.2 Tight resources method .................................................................................................................47 6 Results .................................................................................................................................................49

6.1 Shale resource assessment...........................................................................................................49 6.1.1 Eumeralla Formation ................................................................................................................49 6.1.2 Crayfish Sub-group ..................................................................................................................50 6.1.3 Casterton Formation .................................................................................................................52

6.2 Summary shale resource assessment results ...............................................................................54 6.3 Tight resource assessment ............................................................................................................55

iv Otway Basin Unconventional Resource Assessment

6.3.1 Eumeralla Formation ................................................................................................................55 6.3.2 Crayfish Sub-group ..................................................................................................................56

6.4 Summary tight resource assessment results .................................................................................57

7 Assessment limitations ........................................................................................................................59 7.1 Shale resource assessment...........................................................................................................59 7.2 Tight resource assessment ............................................................................................................61

8 Conclusion ...........................................................................................................................................63

9 References ..........................................................................................................................................65 Appendix A @Risk input tables ..............................................................................................................70

A.1 Shale resource assessment ..........................................................................................................70 A.1.1 Eumeralla Formation ................................................................................................................70 A.1.2 Crayfish Sub-group ..................................................................................................................74 A.1.3 Casterton Formation ................................................................................................................76

A.2 Tight resource assessment ...........................................................................................................79 A.2.1 Eumeralla Formation ................................................................................................................79 A.2.2 Crayfish Sub-group ..................................................................................................................80

Otway Basin unconventional resource assessment v

1 Introduction

In the onshore Otway Basin petroleum exploration commenced in 1892, and in 1978 the first commercial hydrocarbon accumulation was discovered at the North Paaratte gas field in the Port Campbell Embayment (Figure 3-1). The first gas production in the onshore Otway Basin was from the North Paaratte Field in June 1986, followed by production from the Katnook, Ladbroke Grove and other small onshore fields and larger offshore fields such as Casino and Thylacine. The most recent production to come online is from the Speculant/Halladale field offshore in the South Australian Otway Basin in September 2016 (Origin Energy, 2015a; 2016).

Most of the hydrocarbon occurrences in the Otway Basin are hosted in the Upper Cretaceous Waarre Formation (Victoria) and the Lower Cretaceous Crayfish Sub-group (South Australia; Figure 2-3, Constantine, 2001; Boult and Hibburt, 2002). Potential source units include the non-marine Casterton Formation (upper Jurassic–Lower Cretaceous), the fluvio-lacustrine Pretty Hill and Eumeralla formations; and in the offshore region, the marine pro-deltaic Belfast Mudstone (Upper Cretaceous) (O’Brien et al., 2009).

Numerically quantifying the potential of unconventional plays in the onshore Otway Basin has been complicated by a lack of data resulting from a lack of exploration for these resource types. Thus there are few existing regional-scale unconventional resource estimates. In 2013, AWT International calculated a best estimate recoverable resource of 9 TCF of dry gas and 1.6 billion barrels (B bbls) of oil in the Eumeralla Formation (AWT International, 2013). In 2015, four Otway Basin resources: conventional gas, tight gas, shale gas and coal seam gas were reviewed, but not quantified by the Victorian Department of Economic Development (Goldie Divko, 2015). In 2012, DMITRE completed a recoverable sales gas resource assessment for the onshore South Australian portion of the Otway Basin, and estimated that the Crayfish Sub-group potentially held a 623 BCF @P50 unconventional resource (DMITRE, 2012).

The aim of this study is to quantify the unconventional potential of the onshore Otway Basin where possible, by assessing the potential for shale gas and liquids, and tight gas and liquids plays using existing publically available data. No assessment of coal seam gas or conventional gas plays will be included. The primary focus of the report is on the area of the Otway Basin west of the Otway Ranges and south of the Otway Hinge Zone (Figure 1-1) due to the sparsity of data, and the very different character of the region east and north of these features (see Section 2.1 for more detail). Data from wells in the eastern Otway including Olangolah 1, Anglesea 1A and Hindhaugh Creek 1 have been considered where necessary to ensure a regional geological perspective is maintained.

6 Otway Basin unconventional resource assessment

Figure 1-1 Location of the Otway Basin unconventional petroleum assessments. Study area includes the Otway Basin between the coastline and the Otway Hinge Zone, and west of the Otway Ranges.

1.1 Petroleum – conventional versus unconventional The ‘shale gas’ revolution of the last ten years in the US has prompted other countries to assess their own unconventional gas and oil potential but as yet no other country has been able to repeat the success of the US. The apparent overnight success of shale production actually took more than 20 years to come to fruition. Much needed to be learnt about the hydrocarbon-bearing geology and technological development was required to maximise the liberation of oil and gas while minimising drilling (and hence cost). The availability of existing infrastructure, ready markets, and favourable landholding and resource ownership rights were also essential to the success of the US industry. Until massive scales of economy can be reached through the entire value chain, unconventional oil and gas remain expensive to develop, and present a barrier to early exploration and development investment.

The use of the terms ‘conventional’ and 'unconventional' to describe petroleum accumulations is very imprecise, and is an accident of history. Conventional petroleum accumulations are so called because they were the first to be accessed by shallow drilling and have provided the majority of oil produced worldwide to date. However, they are relatively rare, comprising a small part of the petroleum continuum. Conventional petroleum accumulations occur as discrete pools of oil and gas in geological traps, having migrated away from the petroleum source via permeable rock layers. Unconventional is used to refer to a collection of other types of petroleum accumulations. These other accumulations include shale oil and gas, oil shales, tight oil and gas, basin-centred gas, coal seam gas and methane hydrates. Not all unconventional accumulation types are relevant in Australia.

Unconventional and conventional accumulations can form from the same source (Figure 1-2). To paraphrase an old advertisement – ‘oils ain’t oils’. Differences in expulsion, transport, and trap mechanisms results in the application of different extraction methods for conventional and

Otway Basin unconventional resource assessment 7

unconventional reservoirs. Due to low formation permeabilities, many wells are required to produce from an unconventional reservoir as the sweep area of a single well plus its hydraulically-stimulated fracture cloud is much smaller than in a high permeability conventional reservoirs. This is often cited as the definitive difference between conventional and unconventional reservoirs.

In an effort to develop a geologically-based differentiation between conventional and unconventional gas systems, the USGS introduced the term ‘continuous accumulation’ (Gautier et al., 1995, Schmoker, 1995) for unconventional accumulations. A continuous accumulation is a single large field (commonly of regional dimensions) that is not significantly influenced by the water column. It does not owe its existence directly to the buoyancy of gas in water and is not composed of discrete, countable fields delineated by downdip water contacts. The fields that are identified within continuous accumulations are actually indistinctly bounded areas with better production characteristics known as sweet spots (Schmoker, 2002). Unconventional gas systems that are also continuous accumulations include coalbed methane, basin-centred gas, so-called tight gas, fractured shale (and chalk) gas, and gas hydrates. These types of accumulations, although diverse in many ways, all meet the geologic criteria of continuous accumulations (Schmoker, 2002).

1.2 Petroleum systems In order to clarify the use of the various terms throughout this report, a brief process-oriented summary of petroleum systems is included.

The term ‘petroleum system’ describes the genetic relationship between an active source rock and the resulting oil and gas accumulations (Magoon and Dow, 1994). It includes all the essential elements and processes needed for oil and gas accumulations to exist. These include the source, reservoir, seal, and overburden rocks, and the trap formation, generation, migration and accumulation processes. All essential elements and processes must occur in the appropriate time and space in order for petroleum to accumulate (Magoon and Dow, 1994).

Organic material, incorporated during the deposition of sedimentary material, is heated during burial, converting the organic material to petroleum in a process called maturation. A portion of the petroleum formed may be expelled from the source rock, and may then migrate through permeable sediments and structures until it is trapped by an impermeable barrier forming a conventional accumulation; otherwise the petroleum escapes to the Earth’s surface. Alternatively, some or all of the petroleum may stay trapped in or quite near the source rock, forming an unconventional accumulation. Methane hydrates form differently and are not further discussed here.


Figure 1-2 The various types of oil and gas accumulations (Goldstein et al., 2012).

1.2.1 Petroleum accumulation types

Conventional oil and gas reservoirs

Conventional reservoirs occur as discrete accumulations trapped by a geological structure and/or stratigraphic feature, typically bounded by a down-dip contact with water (Figure 1-2). The petroleum was not formed in situ; it migrated from the source rocks into the trap. The petroleum is extracted through relatively few wells; usually with no permeability enhancement required. In contrast in tight-discrete-gas reservoirs, migrated gas accumulates in low permeability rocks and hydraulic stimulation is required for extraction.

Shale oil and gas

Shales are a common petroleum source rock, and can retain more petroleum than they expel during maturation. They have low to moderate porosity with pore sizes on the nanomillimetre scale, and have very low permeability. They are sometimes referred to as ‘self-sourcing reservoirs’. They occur with significant (10–100 km) lateral continuity, can be of considerable thickness (0.1–100 ms), and require hydraulic fracturing for extraction.

Basin-centred gas, tight (pervasive) gas

Basin-centred and tight gas reservoirs are abnormally pressured, gas-saturated accumulations in low-permeability reservoirs lacking a down-dip water contact. The hydrocarbons migrated and the gas was trapped as a ‘bubble’ within a high-pressure, water-saturated reservoir. This phenomenon is caused by the relative permeability of gas and water in the reservoir. The water pressure prevents the oil and gas from migrating through capillary pressure. The reservoir can be laterally and vertically extensive, with gas saturation pervasive throughout. The rate of migration of gas into the reservoir exceeds the rate of gas migrating out of the reservoir, which implies that these reservoirs exist only contemporaneously with active gas generation from a nearby source.


Coal seam gas

Coals release methane through either thermal or biogenic maturation. As gas is generated the significant increase in volume fractures the coal. The gas is transiently held in place by hydrostatic pressure. Removal of water by hydraulic fracturing and pumping extraction allows the release of adsorbed gas, so it, together with the free gas can flow to the surface.

Oil shale

In oil shales the organic matter has not been converted to petroleum and is immature. These shales can be mined and heated quickly to 550°C (retorted) in order to generate oil. This is a very energy intensive and expensive process, and hence is a relatively uncommon form of oil production.

1.3 Unconventional resource assessments

1.3.1 Assessment methods

There are three main classes of resource assessments – generative, gas- or oil-in-place and estimated ultimate recovery (EUR). Generative assessments assess the ability of a petroleum system to generate petroleum. Gas- or oil-in-place assessments calculate the concentration of petroleum in the reservoir at the present day. This relies on having measured gas, condensate and oil concentration data. Estimated ultimate recovery assessments use petroleum production data and reservoir simulation models to forecast future production potential from the reservoir assuming a given set of parameters. EUR assessments can only be used for reservoirs with existing production, as they rely heavily on the known production characteristics of the reservoirs.

For all three of these approaches, it is possible to use a probabilistic assessment approach, defining parameters within the assessment as probability distributions in order to provide a statistically based range of possible outcomes. A probabilistic assessment incorporates probability distribution functions and Monte Carlo modelling to account for natural variability and uncertainty. Where there are many data points available, a distribution curve is fitted to the data. However, in most cases, statistically reliable data is not available, and a distribution curve is manually built to encompass the available data, with an allowance for expected natural variation. The estimation of gas- or oil-in-place (for example) is made using software which takes random draws from each parameters’ probability distribution function to calculate each iteration. After many thousands of iterations are run, the results of the simulation are presented as a series of probability distributions for each input and output parameter. This probabilistic method captures estimates of uncertainty in each parameter, and propagates these throughout each calculation, resulting in a range of estimates. Reports typically give a low estimate (P90 – 90% probability that at least this much oil or gas can be found in place), a middle estimate (P50 (median) – 50% chance of occurrence; or mean), and a high estimate (P10 – only a 10% chance that this volume of oil or gas will be found or exceeded).

An estimated recoverable volume is calculated by applying a recovery factor to the assessed volume of oil or gas. The recovery factor is intended to reflect risks in exploration (need to find ‘sweet spots’, data quality), risks in development (applying a Mechanical Earth Model to optimise drilling and hydraulic stimulation to the local stress regime for mobilisation of oil and gas), as well as other factors impacting development (e.g. government policy, uncertainties in project approvals, finance and infrastructure). In established reservoirs with high levels of knowledge, known production characteristics and current technology able to recover a high percentage of oil and gas from the


reservoir, recovery factors for unconventional gas resources can be as high as 30%, and for shale oil between 2–7% (EIA, 2013).

In this study, a probabilistic volumetric gas- and liquids-in-place assessment method was used to assess the potential for unconventional resources including tight gas and liquids, and shale gas and liquids in the Otway Basin. The P10, P50, mean and P90 GIP and OIP resources for each prospective area, and the cumulative P10, P50, mean and P90 GIP and OIP resources for each reservoir and basin is reported. The potentially recoverable tight and shale GIP and OIP resources estimated as 5% median assessed volume (P50) are reported as the final results of the assessment. The resource assessment was made using publically available data, which is sparse and possibly unrepresentative for some parameters. The application of a low (5%) recovery factor is intended to reflect the uncertainties in the resources in place and their path to commercialisation in the medium term.

Assessments of the unconventional potential of the Gippsland, Canning, Perth and Cooper basins have also been completed as part of Geoscience Australia’s unconventional resource assessment series. All of the assessment reports, and the underlying digital data including map packages are available at http://www.ga.gov.au/.


http://www.ga.gov.au/

2 Regional geology

2.1 Structural geology The Otway Basin is a northwest–southeast striking passive margin rift basin, and extends west-northwest from the King Island High along the Victorian coast for 500 km to Cape Jaffa in South Australia. The distribution of Cretaceous rocks defines the rift margin in the north, and the southwest offshore limit is taken at the 4500 m isobath. The Otway Basin covers an area of about 155,000 km2, approximately 80% of which is located offshore (Constantine, 2001).

The Australian southern margin, including the Otway Basin is underlain by a suite of basement terranes that played an important role in both focusing initial extensional strain and determining the ultimate rifted margin architecture (Stacey et al., 2013). Northwest-trending half graben underlie much of the western Otway Basin, pointing to a common structural control and possible continuation of Archean and/or Proterozoic basement rocks eastwards beneath the Lower Paleozoic Delamerian Fold Belt and overlying Mesozoic rift basins (Gibson et al., 2012). These basins extend as far east as the Shipwreck Trough off western Tasmania where there is an abrupt change in basin geometry from northwest to dominantly north–south or northeast-trending structures. This switch in basin geometry coincides with a west-dipping, crustal-scale, Paleozoic structure (Avoca-Sorell Fault System, Figure 2-1; Gibson et al., 2012).

There are five elongate structurally-controlled Cretaceous depocentres in the onshore South Australian Otway Basin: the Robe, Penola, Tantanoola, St Clair and Rivoli Troughs and thirteen half graben in the onshore Victorian Otway Basin: the Penola, Tantanoola, Mocamboro, Digby, Tahara, Ardonachie, Morenda, Windermere, Koroit, Elingamite, Ross Creek, Gellibrand and Ombersely Troughs (Figure 2-1). The Penola and Tantanoola Troughs straddle the Victoria–South Australia border. These troughs are separated by a complex series of highs including the Lake Eliza, Beachport, Kalangadoo, Lake Condah, Branxholme, Stoneyford and Moorlie (Constantine, 2001; Boult and Hibburt, 2002).

Multiple phases of rifting and inversion, and particularly the mid-Cretaceous inversion and Eocene to Recent compression has had major implications for conventional and unconventional prospectivity in the Otway Basin breaching conventional traps at several levels, and locally creating fracture porosity. This potentially impacts upon the prospectivity of unconventional plays, though it is still a matter of debate whether natural discontinuities are advantageous or disadvantageous. Natural fracturing has been observed in the Eumeralla Formation in Flaxmans 1, Bellarine 1 and Fergusons Hill 1, and in the Crayfish Sub-group in Glenaire 1 ST1 to name just a few. The fractured basement play charged by Casterton Formation shales as seen in Sawpit 1, Gordon 1 in the Penola Trough is another example (Tassone, 2013).


Figure 2-1 Principal structural elements of Otway Basin (Stacey et al., 2013).


2.2 Basin evolution and depositional history Basement in the Otway Basin generally comprises early Palaeozoic igneous rocks and metasediments of the Kanmantoo Fold Belt including the metamorphic Glenelg River Complex. The Lachlan Fold Belt and Antarctic Craton form the eastern and western boundaries of the Kanmantoo Fold belt respectively (Figure 2-2). In the north and northwest of the basin evidence the basement comprises equivalents to Kanmantoo Group metasediments and volcanics which were deposited in an extensional regime during Early Cambrian rifting. Mafic intrusives and extrusives were also emplaced (Foden et al., 1990; Turner et al., 1993). Subsequent compression during the Cambro-Ordovician Delamerian Orogeny deformed the sequence, and was in turn followed by post-orogenic extension and further emplacement of igneous intrusives and extrusives. In Victoria, extensive turbidites were deposited during the Ordovician, followed by a thick sequence of clastic sediments and pulses of felsic volcanism and granite intrusion during the Silurian–Devonian, but have not been encountered in South Australia.

A major period of glaciation in the Late Carboniferous to Early Permian (Bourman, 1987; Wopfner, 1980) scoured the earlier Palaeozoic basement surface. Depressions were subsequently filled with Permian shale, diamictite and sand (Flöttman and Cockshell, 1996). It is possible that Permian sediments are preserved beneath the Otway Basin within depressions glacially scoured into the older Palaeozoic bedrock surface. Permian deposits were eroded during Early Cretaceous rifting and have been reworked into Cretaceous sediments.

Triassic and Early Jurassic sediments are unknown in the South Australian portion of the Otway Basin (Yu, 1988), but reworked Triassic spores and pollen have been described from a number of drillholes. Extensive flood basalts and sills were extruded in Victoria, Tasmania and Antarctica as a result of rift initiation in the late Jurassic. The discovery of oil in fractured basement in Sawpit 1 indicates lateral-migration from early cretaceous source rocks has the ability to charge basement reservoirs in the Penola Trough.

Figure 2-2 Basement framework of southeast Australia (Boult and Hibburt, 2002).


Rifting in the Late Jurassic and Early Cretaceous triggered the continental break-up of eastern Gondwana forming the Australian and Antarctic continents and developing a series of graben and half-graben of limited and varying orientations (Krassay et al., 2004, and Stacey et al., 2013) in the proto-Otway Basin. The onset of the major rifting phase produced east-west extensional depressions in the western Otway Basin, while in the eastern Otway (east of the Moyston Fault) graben development was controlled by northeast and west-northwest trending faults (Figure 2-1). These early depressions developed into the Robe, Colac and Gellibrand Troughs and possibly the Torquay Sub-basin. The rift graben were progressively infilled by up to 8 km of Otway Group sediments including the fluvio-lacustrine Casterton Formation, and the fluvio-lacustrine and alluvial Crayfish Sub-group (Pretty Hill and Laira formations; Figure 2-3). Significant syn-depositional faulting was occurring at this time causing significant facies changes and thickness variations in the Crayfish Sub-group (Boult and Hibburt, 2002; O’Brien et al., 2006). This intensive early rift phase ended in the Barremian. Fault-related tilting, folding and uplift at this time resulted in extensive erosion forming an unconformity at the top of the Crayfish Sub-group which can be clearly seen in the Penola Trough. As rifting intensity waned the coaly silicilastics of the fluvial Eumeralla Formation were deposited into a ‘sag-like’ extensional tectonic setting, blanketing the earlier trough and basement highs, and thickening rapidly southwards. As Eumeralla Formation deposition was only mildly controlled by faulting, the rapid facies changes and thickness variations observed in the underlying Crayfish Sub-group are not seen (Boult and Hibburt, 2002).

Compressional inversion and uplift in the early Late Cretaceous separated the Torquay Sub-basin from the eastern Otway Basin and shifted the locus of extension offshore (Krassay et al., 2004). This event caused the cessation of Eumeralla Formation deposition, and subsequent associated uplift and erosion resulted in the Otway Unconformity which separates the Lower Cretaceous Otway Group from the overlying Upper Cretaceous Sherbrook Group (Figure 2-3, O’Brien et al., 2006). In the western Otway Basin several hundred metres, and in the eastern Otway between 1500 m and 3500 m of Eumeralla Formation was eroded during this phase (Constantine, 2001; Tassone et al., 2014).

In the late Cenomanian the rift axis broadened and moved further southward. During this time, the Tartwaup-Mussel Fault Zone was the primary basin-margin fault zone and strongly influenced the deposition of the Sherbrook Group during the Late Cretaceous. North of the Tartwaup-Mussel Fault Zone deposition was dominantly terrestrial and the Sherbrook Group is relatively thin, while to the south the Sherbrook Group is dominantly marine and much thicker (O’Brien et al., 2006). The Sherbrook Group includes the Waarre, Flaxman and Paaratte formations, and the Belfast Mudstone and Timboon Sandstone (Figure 2-3). The coarse-grained marginal marine to coastal plain siliciclastics of the Waarre Formation represent the basal unit of this group and are the principal reservoir in all onshore conventional gas accumulations. The overlying lower delta plain facies of the Flaxman Formation (Boyd and Gallagher, 2001), and the middle to outer shelf, open marine pro-delta facies of the Belfast Mudstone was deposited during the subsequent sea level rise. This was followed by the marine lower- to upper-deltaic sandstones, mudstones and occasional coals of the Paaratte Formation (Duddy, 2003; Boyd and Gallagher, 2001). The Timboon Sandstone marks the onset of fluvial terrestrial interdistributary deposition (Boyd and Gallagher, 2001).

Continental breakup between Australia and Antarctica occurred in the late Maastrichtian and was accompanied by relatively minor structuring and regional uplift in the Otway Basin. This led to the development of the regional Late Maastrichtian unconformity which separates the pre-rift Sherbrook Group from the post-rift transgressive siliciclastic Wangerrip Group (Figure 2-3, Lavin, 1997a; Partridge, 1999; O’Brien et al., 2006).

In response to the progressive opening of the proto-Southern Ocean, the Otway margin rapidly subsided triggering a major transgressive event and the progressive starvation of the margin and


deposition of the increasingly marine and carbonate-rich sediments of the Nirranda and Heytesbury groups (Figure 2-3, O’Brien et al., 2006; Constantine, 2001). Subsequent plate movement between Australia and Antarctica, and a change to a northwest–southeast compressive regime formed a transform plate margin and the Australo-Antarctic Gulf. This later opened further, completely removing the land bridge between Tasmania and the mainland by approximately 33.5 Ma and creating the circum-Antarctic oceanic current (Exon et al., 2002). This event is marked in the Otway Basin by the intra-Lutetian unconformity between the Nirranda Group and the overlying Heytesbury Group. This unconformity marks the transition from more restricted, higher sediment supply dominantly terrestrial depositional environments of the Heytesbury Group, to the cooler, open-marine, more sediment starved environments and the deposition of marine carbonates and clastics of the Nirranda Group (Figure 2-3, Exon et al., 2002, O’Brien et al., 2006, Holdgate and Gallagher, 2003; Krassay et al., 2004). The deposition of this thick sequence of carbonates is thought to have played a key role in the development of Otway Basin petroleum systems, with associated burial and loading triggering source rock maturation from the mid-Oligocene (O’Brien et al., 2006).

During the late Miocene and into the Pliocene, continued northwest–southeast compression uplifted large reverse-fault blocks of Eumeralla Formation which form the major topographic features visible today. These include the Otway Ranges, Barongarook High, Barrabool Hills and Bellarine High in the eastern Otway; and in the Central Otway near the South Australian border – the Merino Uplift and Dartmoor Ridge (Constantine, 2001). Large volumes of the Eumeralla Formation were eroded during uplift in the Otway Basin at this time. Thickness estimates range from 3500 m of sediments being removed in the eastern part of the basin to 200 m elsewhere (Tassone et al., 2014). This exhumation led to the exposure of deeply buried Lower Cretaceous sediments, which, coupled with higher geothermal gradients in the eastern Otway Basin, has rendered the Lower Cretaceous source rocks in the eastern Otway much more mature than their western Otway counterparts at similar depths (Tassone et al., 2014). For example in Anglesea 1A, in the onshore Torquay Sub-basin, rocks are in the oil window (VRo 0.7–1.0%) at 594 m, and in the dry gas window (VRo 1.3–3.0%) at 1760 m (Oil Development N.L., 1962), which is in marked contrast to the Penola Trough, where the oil/condensate window is predicted to be between 3050–3800 m and the gas window at depths in excess of 3800 m (DMITRE, 2012).


Figure 2-3 Otway Basin stratigraphic and basin event chart (Stacey et al., 2013). Based on the now superseded timescale of Young and Laurie (1996) and Partridge (2001).


2.3 Otway Basin petroleum systems Most of the recent exploration in the onshore Otway Basin has focused on the basin’s considerable potential for unconventional hydrocarbon resources, particularly in the western Otway Basin. Source rocks in three sub-systems within the Austral petroleum supersystem have been identified in the Otway Basin. These, and key occurrences attributed to each sub-system are summarised in Table 2-1 below. The following sections summarise the key elements of the petroleum supersystem in the Otway Basin.

Table 2-1 Summary of Austral petroleum supersystem in the Otway Basin (Edwards et al., 1999, Boreham et al., 2004; O’Brien et al., 2009).

Petroleum sub-system

Source age Formation Hydrocarbon occurrences (examples only)

Mixed source Austral 1 and 2 Port Fairy 1 Caroline 1

Austral 1 Late Jurassic to earliest Cretaceous

Casterton Formation and Crayfish Sub-group fluvio-lacustrine shales

Haselgrove 1, Katnook 1, Redman 1, Troas 1, Nunga Mia 1, Zema 1

Austral 2 Early Cretaceous Eumeralla Formation fluvial and coaly facies

Eastern Otway Basin fields, Flaxmans 1, Lindon 1 and 2,

Austral 3 Late Cretaceous to earliest Tertiary

Sherbrook and Wangerrip groups fluvio-deltaic facies

Wilson 1

2.3.1 Source rocks

In the Otway Basin, the source rocks of the Austral 1 petroleum sub-system include the Casterton Formation and Crayfish Sub-group. The Casterton Formation is widely recognised as an excellent source rock (Lovibond et al, 1995; Lavin and Muscatello, 1997) and is considered generative for both oil and gas (Mehin and Constantine, 1999). The Austral 1 petroleum sub-system is recognised as the source for oil recovered from Troas 1 and Nunga Mia 1 in South Australia, and Windermere 1 in Victoria. Together the Casterton Formation and Lower Sawpit Shale are considered the principal source rocks of the Penola Trough (Lovibond et al, 1995; Moriarty et al, 1995; Padley et al, 1995; Edwards et al, 1999; Boreham et al., 2004).

With the exception of the Penola Trough, the Early Cretaceous Austral 2 petroleum sub-system (Eumeralla Formation) is widely recognised as the source for the majority of gas discoveries in the eastern Otway Basin including the Port Campbell and Shipwreck Trough area (Mehin and Link, 1994; Foster and Hodgson, 1995; Luxton et al, 1995; Edwards et al, 1999). Gas shows reported at Triton 1 in the Victorian offshore (Luxton et al, 1995) and gas accumulations at Troas 1 and Breaksea Reef 1 in the South Australian offshore have also been ascribed to the Austral 2 petroleum sub-system. Gases and oils from the central Otway Basin (e.g. Port Fairy 1, Windermere 2 and Caroline 1) are thought to be the product of mixed Austral 1 and 2 sources, and also a local variant of the Eumeralla Formation organic facies unique to central Otway Basin (Boreham et al., 2004; 2009).

The Austral 3 interval in the offshore Gippsland Basin (Latrobe Group) are widely recognised as the major source interval of the substantial oil and gas accumulations (O’Brien et al., 2006). A possible source rock interval is the Belfast Mudstone, which was interpreted geochemically to be a moderately good source in Breaksea Reef 1 (Voluta Trough; Hill, 1995). The Waarre and Flaxman formations contain marine and marginal marine intervals that could also be viable source rocks (O’Brien et al., 2009). However, Austral 3 source rocks in the Otway Basin (Sherbrook and basal Wangerrip groups) are typically immature across the Otway Basin, particularly in the onshore, and have not yielded any


commercial quantities of hydrocarbons (Figure 2-4; O’Brien et al., 2009). Until further exploration is undertaken, especially in the deeper water offshore areas, the ability of the Austral 3 petroleum sub-system to generate substantial volumes of hydrocarbons in the Otway Basin, remains largely unknown.

Figure 2-4 Modelled maturity at the top Austral 3 surface in the Otway Basin. Pink colours indicate immature source rocks, greens indicate mature source rocks, and blues indicate overmature source rocks (O’Brien et al., 2009).

High carbon dioxide (CO2) production has long been considered a major risk for gas exploration in the Otway Basin as accumulations can vary widely in composition from gas rich in methane (96.6%) and low in CO2 (0.14%), to poor in methane (2.77%) and high in CO2 (95.4%; Mehin and Kamel, 2002). Carbon dioxide in the Ladbroke Grove field ranges between 29.2%–56.6%. The presence of minor helium along with CO2 (and nitrogen) in Otway Basin petroleum accumulations suggests the CO2 is of magmatic origin. CO2 also appears to have migrated very recently, and at least in the Port Campbell area, is associated with basement penetrating fault intersections. However, with the use of modern technology gas accumulations with initial CO2 concentrations as high as 54% are proving to be economically viable in the Otway Basin (Mehin and Kamel, 2002; Boult et al., 2004). Commercial quantities of CO2 were discovered in 1992 at Boggy Creek 1 in the Port Campbell Embayment (Goldie Divko, 2015), and in 1965 and 1967 at Kalangadoo 1 and Caroline 1 respectively in South Australia (Boult and Hibburt, 2002) and subsequently produced at a small scale.

2.3.2 Generation and expulsion

In the Penola Trough, and the western Otway Basin more broadly, an Early Cretaceous charge of oil/wet gas into the Pretty Hill reservoir from the Casterton Formation and lower Pretty Hill Formation


shales has been suggested due to burial by the Laira Formation. Early oil/wet gas was flushed or diluted by subsequent dry gas charge as a result of increased heat flow associated with continental breakup and burial by the thick Eumeralla Formation (Boreham et al., 2004). Much of the lower part of the section in the Penola Trough is now thought to be over-mature to the south and southeast of the Katnook Graben. Additional Tertiary burial may have been sufficient to restart generation in the source kitchen generating additional gas to “top up” the already filled structures where the Late Cretaceous and Tertiary cover exceed these depths (Boult et al., 2004). In the eastern Otway Basin a single charge history has been interpreted (e.g. Geographe 1, Thylacine 1, La Bella 1, Lavers 1; Boreham et al., 2004). An early charge from the Austral 1 sub-system may have occurred and subsequently leaked from fault-bound traps (O’Brien et al., 2009).

The strong spatial and stratigraphic relationship between gases/oils and their source rocks suggest only short- to medium-range migration distances from mature sources to traps rather than long-range migration (Boreham et al., 2004).

2.3.3 Reservoirs and seals

Key conventional reservoirs in the onshore Otway Basin are sands in the Sherbrook Group (Waarre Sandstone, Flaxmans Formation and intra-Belfast Mudstone sands), the Windermere Sandstone within the Eumeralla Formation, and Crayfish Sub-group sands including the Katnook and Sawpit Sandstones and sandier sections of the Pretty Hill Formation (Lavin, 1997b; Boult et al., 2004). South of the Tartwaup Hinge Zone limited drilling suggests additional reservoir potential may exist in the Copa Formation (basal Waarre Formation equivalent; Boult and Hibburt, 2002).

Unconventional reservoirs are much less well understood than their conventional counterparts but are likely to include tight reservoirs in the Eumeralla Formation and Crayfish Sub-group, and shale reservoirs in the Casterton Formation and Crayfish Sub-group and possibly also the Eumeralla Formation (Tassone, 2013; Goldie Divko, 2015). These will be discussed in depth in Chapter 4.

The Crayfish Sub-group, and especially the Laira Formation and Sawpit Shale provide the primary regional seal and intraformational seals for conventional reservoirs, particularly in the western Otway Basin. There is however some exploration risk associated with rapid lateral facies changes in the Laira Formation beyond the central Penola Trough. Intraformational shales and siltstones within the Eumeralla Formation provide an additional seal for conventional reservoirs, particularly in the eastern Otway Basin where the Crayfish Sub-group is sandier (Lavin, 1997b; Constantine, 2001, Boult and Hibburt, 2002; Boult et al., 2004). Marine claystones of the Sherbrook Group provide the regional seal and intraformational seals for accumulations in the Port Campbell and Shipwreck Trough areas. These seals thicken progressively offshore, but are spatially restricted and thin in the onshore Otway Basin (Department of Resources Energy and Tourism, 2009).

2.3.4 Play types

Summaries of conventional hydrocarbon play types in the Otway Basin have previously been presented by others and are not the key focus of this assessment (e.g. Lavin, 1997b, Boult and Hibburt, 2002 etc.). Multiple phases of major structuring associated with rift tectonics, differences in the magnitude and timing of subsidence and burial across the basin, facies variation and late displacement by CO2 charge imply that there are significant risks for the trapping and preservation of hydrocarbons within the conventional petroleum systems of the Otway Basin (Boult and Hibburt, 2002).


The Eumeralla Formation, Crayfish Sub-group and Casterton Formation shale gas and liquids plays are currently an exploration focus in the Otway Basin and will be discussed further in Section 4.1. Other presently untested shale plays include the Austral 3 Sherbrook Group shales. While organic content seems fair in these shale, the Austral 3 petroleum sub-system does not appear to have generated commercial quantities of hydrocarbons in the Otway Basin. In the Gippsland Basin, the equivalent stratigraphic intervals (Latrobe Group) are widely recognised as the major source interval of the oil and gas in the offshore (O’Brien et al., 2006).


3 Resource development in the Otway Basin

3.1 Petroleum prospectivity and exploration history The Otway Basin has proven prospectivity for conventional oil and gas and promising unconventional oil and gas plays, in addition to numerous hydrocarbon shows and indications. While there is undiscovered petroleum potential in the Otway Basin, gas is considered much more likely to be found than oil, particularly in South Australia. The discoveries of a small but significant volume of oil in Sawpit 1 and oil shows in Wynn 1, and condensate in Moreys 1, Kilanoola 1 etc. shifted the perception that the basin was only gas-prone and demonstrated that a significant oil discovery may be possible (Boult and Hibburt, 2002; DMITRE, 2012).

Drilling in the Otway Basin commenced in 1892 with a 281 m deep bore drilled by Salt Creek Petroleum in the South Australian part of the basin, but it was not until the 1920s that wells were sunk for that purpose in Victoria (Constantine, 2001; Goldie Divko, 2015). Early exploration was largely unsuccessful until Port Campbell 1 intersected a sub-commercial quantity of gas in the Waarre Formation in 1959. More than a decade of largely unsuccessful follow-up drilling followed and interest in the Otway Basin waned. In 1978 the discovery of the North Paaratte gas field (Figure 3-1) triggered a new phase of exploration interest and the subsequent discovery of numerous small fields on and offshore (Boult and Hibburt, 2002).

The drilling of Katnook 1 and 2 in 1987 and 1988 respectively heralded the discovery of the Katnook field and the first commercial field discovered in the South Australian Otway Basin, followed shortly after by the Ladbroke Grove 1 gas discovery in 1989 (Parker, 1992). The discovery of the Minerva and La Bella gas fields offshore Port Campbell in 1993 marked the culmination of this phase of exploration.

Santos’ discovery of five Waarre Formation hosted small gas fields onshore near Port Campbell, and discovery of two large offshore gas fields (Thylacine and Geographe, also hosted in the Waarre Formation) in 2001 marked a turning point in exploration in the Otway Basin and established the Port Campbell Embayment as an active gas producing province (Constantine, 2001).

Recent drilling in the Otway Basin includes near-shore conventional gas wells Speculant 1, Speculant 2 ST1 and Halladale 2 (Origin Energy), and onshore unconventional wells Moreys 1 (Port Campbell Embayment), Sawpit 2, Jolly 1/ST 1 and Bungaloo 1 (all Penola Trough; Lakes Oil and Armour Energy Ltd). Both Speculant 1 and Speculant 2 ST1 intersected commercial quantities of gas in the Waarre Formation, with first gas produced from the Halladale/Speculant field in September 2016 (Origin Energy, 2015a; 2016). The Speculant discovery has been booked as a 2P 49 PJe discovery (Origin Energy, 2015b).

In the Port Campbell Embayment, Moreys 1 well encountered gas in several stratigraphic intervals, and a DST in the Eumeralla Formation flowed gas and condensate to the surface over a three hour period before fading out, possibly suggesting the Eumeralla Formation reservoir is hydrocarbon saturated (Lakes Oil, 2012; Armour Energy, 2012).

Sawpit 2 was drilled in early 2013 in the South Australian Penola Trough with a conventional primary objective in the upper Sawpit Sandstone and a secondary shale gas target in the lower Sawpit Shale. While no net pay was identified in the conventional target, elevated mud gas readings were observed in the Casterton Formation and also in an unidentified organically rich unit below the Casterton


Formation. Follow-up analysis revealed the Sawpit Shale and Casterton Formation to be thermally immature in this location (Beach Energy, 2013).

Drilled as the follow-up well to Sawpit 2 in April 2014, Jolly 1 encountered a thick section of shale and sandstones with elevated gas readings in the Lower Sawpit Shale and Casterton Formation from 3430 m depth (Beach Energy, 2014a, b). Later well Bungaloo 1 (June 2014) also encountered elevated mud gas readings in the Casterton Formation and lower Sawpit Shale, and hydrocarbon fluorescence was observed in lower Sawpit Shale sandstones (Cooper Energy, 2014a). Further analyses from these wells has confirmed the presence of a deep conventional gas play in the lower Sawpit Sandstone and a Casterton Formation shale gas play (Cooper Energy, 2016).

Other recent exploration activity includes the proposed Lakes Oil Portland Energy Basin Centred Gas Project (PEP 175 and PEP 167, Port Fairy area) which is hosted in the Eumeralla Formation, and is interpreted to be gas saturated across the permits (Lakes Oil, 2016). In the relatively less explored Casterton Formation, Somerton Energy estimated that Victorian permit PEP 171 could contain more than 25 TCF of gas (Goldstein et al., 2012).

Figure 3-1 Gas fields, pipeline and road infrastructure in the Otway Basin. Field and pipeline information from GP Info (2016).

3.2 Infrastructure market and community The South East of South Australia and western Victoria exhibit a high diversity of local industry — consequently opportunities for gas marketing linked to industry development in the region are good. The region is strategically located close to the major cities of Adelaide and Melbourne and the eastern Australian market, and has good transport infrastructure including the Port of Geelong and Portland.

Gas from producing offshore fields in the eastern Otway Basin (e.g. Thylacine, Geographe, Speculant/Halladale etc.) comes ashore via a series of pipelines to gas processing and storage facilities in the Port Campbell region (Figure 3-1). These include the Otway Gas Plant and the Iona


gas storage facility. Energy Australia operates the Iona gas storage facility which uses the depleted gas field reservoirs of Iona, Wallaby Creek and North Paaratte to store gas during periods of low demand. The facility is connected to the Victorian market via the South West Pipeline and to the South Australian market via the South East Australian Gas (SEA) pipeline (Department of Economic Development, Jobs, Transport and Resources, 2017).

In 2002–03, the SEA Gas pipeline was constructed to transport offshore Otway gas from the Iona gas facility in Victoria to Adelaide. Origin Energy Retail Ltd constructed and commissioned the South East South Australia (SESA) pipeline in 2005. This 45 km pipeline connects the SEA Gas Pipeline in Victoria to Epic Energy’s South East Pipeline System and the Ladbroke Grove Power Station. As gas production from Ladbroke Grove 2 and 3 ceased in late 2006 and mid-2005, respectively, sales gas from the SESA pipeline now feeds both turbines of the Ladbroke Grove Power Station. In addition to the two trunk gas lines, Epic Energy owns and operates a 46 km long pipeline from the Katnook gas processing plant to the Apcel paper mill at Snuggery; a second 19 km line, runs from this line to Mt Gambier. A third short line runs from Katnook east to the Safries potato chip factory. Another line constructed in the second half of 2000 connects Kalangadoo to Nangwarry timber mill (DMITRE, 2012; Department of State Development South Australia, 2017).

Gas from producing wells in the Katnook, Haselgrove, Haselgrove South and Redman gas fields in the South Australian Penola Trough is piped to a gas treatment plant located 300 m southeast of Katnook 1. The plant was built in 1991 and operated through to 2011, and was upgraded pending resumption of processing in 2014. Condensate is stored onsite at the Katnook Plant before transportation by road tanker to the Shell Refinery at Geelong in Victoria (Rawson Resources, 2014; Department of State Development South Australia, 2017).


4 Play type summary

Two primary unconventional play types were considered for assessment in the onshore Otway Basin: shale and tight resources. The following is a brief summary of the play types as defined in the literature, and, the reasoning for including or excluding the play types in the final assessment.

4.1 Shale resources The Eumeralla Formation, Crayfish Sub-group and Casterton Formation shale plays assessed in this study was chosen primarily based on maturity, total organic content (TOC), known performance as a source rock, thickness and spatial extent. Other shale plays may however prove viable.

In the deeper parts of the offshore Voluta Trough in South Australia, a Sherbrook Group shale liquids play has been suggested as being possible (DMITRE, 2012). The area likely to have mature shales in the Waarre Formation (and Sherbrook Group more generally) onshore is likely restricted to small areas on the coastal fringe as modelled by O’Brien et al. and seen in Figure 2-4. The only significant penetrations at >2000 m (the approximate top of the oil window in the Otway Basin) are in: Curdie 1, Flaxmans 1, and Port Campbell 2 in the Port Campbell Embayment; Najaba 1A in the Tantanoola Trough; and Fahley 1 in the Portland Trough in the eastern Otway Basin. In the western onshore Otway Basin significant thicknesses of deep Sherbrook Group are seen in Northumberland 2, Mt Salt 1, Burrungule 1, Lake Bonney 1 and Caroline 1 wells all which are all located in the western extension of the Portland Trough. As mature sections of the Waarre Formation and other Sherbrook Group formations are spatially restricted onshore, and have no shale data available, the Sherbrook Group has not been assessed as a potential shale resource in this study.

4.1.1 Eumeralla Formation

Age

The Eumeralla Formation is early Aptian–Albian and includes the Windermere Sandstone (Early Aptian) and Heathfield Sandstone (Early Albian) (Lavin, 1997a; Duddy, 2003).

Stratigraphic relationships

The Eumeralla Formation overlies the Crayfish Sub-group and underlies the Waarre Formation (Sherbrook Group; Figure 2-3). The exact relationship between the Windermere Sandstone and the underlying Katnook Sandstone in the Eumeralla Formation remains unclear (Lavin, 1997a).

Lateral equivalents/members

In the Victorian Otway Basin, the Windermere and Heathfield sandstones and the Killara Coal Measures are recognised as distinct units within the Eumeralla Formation (Figure 2-3). The Windermere Sandstone occurs at the base of the Eumeralla Formation. The type section of the Windermere Sandstone is found in Windermere 2, where it reaches a thickness of 105 m (Goldie Divko, 2015), but is not very commonly found in the Victorian Otway Basin.


The Heathfield Sandstone is recognised in the Penola Trough e.g. in Bus Swamp 1 (Duddy, 2003), but is also found in other areas including the Windermere Trough (Windermere 1 and 2), and the Port Campbell Embayment (Dunbar East 1 and Blackwood 1).

Black coals of the Killara Coal Measures have been intersected by petroleum exploration companies for many decades in the Windermere Trough (e.g. Killara 1, Banganna 1 and Taralea 1), and in Stoneyford 1 on the Stoneyford High. The Killara Coal Measures can occur throughout the Eumeralla Formation, but due to the laterally limited extent of individual coal measures, are difficult to correlate across any distance (Goldie Divko, 2015).

Spatial extent and thickness

The Eumeralla Formation is spatially extensive and was originally deposited across the entire onshore Otway Basin (Goldie Divko, 2015). The Eumeralla Formation can reach thicknesses in excess of 2000 m in the central and eastern Otway Basin (e.g. Windermere 1 (2288 m), 2743 m in Fergusons Hill 1 and 2479 m in Anglesea 1A). In the Penola Trough to the west, the Eumeralla tends to be thinner (e.g. between 775 m (Bus Swamp 1) and 1378.4 m thickness (Glenaire 1 ST1)). The Eumeralla Formation varies in thickness due to significant erosion and uplift, with between 1.5 km and 3.5 km of Eumeralla Formation removed in the eastern Otway Basin during the mid-Cretaceous event (Constantine, 2001; Tassone et al., 2014). At a regional scale the formation thins towards the northern margin and towards the Torquay Sub-basin in the east and the top of the Eumeralla Formation dips in the western and central parts of the Basin, further increasing thickness variability (Constantine, 2001).

Using data compiled for this study the top surface of the Eumeralla Formation is found at depths between 0 m and 2892.25 m (Mocamboro 11 and Caroline 1 respectively), and the its base at depths between 305 m and 3749 m (Wanda 1 and Geltwood Beach 1 respectively).

Sedimentology and paleoenvironment

The Eumeralla Formation consists of a series of highly laterally variable facies including medium- to coarse-grained fluvial channel sandstones and interbedded mudstone, fine-grained sandstones and shale, including palaeosols and coal seams that developed in levees and floodplains (Duddy, 2003). The Windermere Sandstone member consists of interbedded basement-derived sandstones and mudstones while the Heathfield Sandstone is a basement-derived quartzose sandstone (Lavin, 1997b; Goldie Divko, 2015).

Source rock geochemistry

The Austral 2 petroleum sub-system, and in particular the Eumeralla Formation is widely recognised as the source for the majority of gas and minor oil discoveries in the Otway Basin, especially in the central and eastern Otway (Edwards et al., 1999; Boreham et al., 2004). In particular, the Eumeralla Formation is thought to be the primary source interval for gas in the Port Campbell Embayment and Shipwreck Trough areas (Mehin and Link, 1994; Boreham et al., 2004) including the Minerva and La Bella fields (Luxton et al., 1995).

Eumeralla Formation derived oil and gas is thought to be derived from two coal seams (one Aptian and one lower Albian), interpreted to occur basin wide (BHP Petroleum, 1992; Tupper et al., 1993). These are thought to have excellent potential for the generation of gas and light oil (Preston, 1992; Geary and Reid, 1998). In addition to the coal seams, organic rich shales and mudstones present throughout the Eumeralla Formation may have additional source rock potential (O’Brien and Thomas, 2007), though the lateral variability in facies makes these difficult to map and predict local source potential (Tassone, 2013). The medium-gravity, waxy oils recovered from the onshore Victoria wells


Flaxmans l, Windermere 1, and Port Campbell 4, and degraded oils from Lindon 1 and 2 demonstrate that the oil potential within the Austral 2 petroleum sub-system cannot be ruled out (Department of Resources Energy and Tourism, 2009; McKirdy 1987; Tabassi and Davey, 1986; McKirdy et al., 1994; Edwards et al., 1999). Though there is also evidence that gases and oils from the central Otway Basin (e.g. Port Fairy 1, Windermere 2 and Caroline 1) may be the product of a mixed Austral 1 and 2 source (Boreham et al., 2004; 2009).

Kerogen types in the Eumeralla Formation are highly variable, but dominated by Type II, with lesser amounts of Type 1, Type III and Type IV present, the latter particularly notably in the upper Eumeralla Formation (Boult and Hibburt, 2002; Department of Resources Energy and Tourism, 2009). Oil prone kerogens were detected in Ross Creek 1 in the eastern Otway Basin (Preston, 1992), and waxy oils were recovered from Flaxmans 1 and Port Campbell 4 (O’Brien and Thomas, 2007). Exploration results offshore indicate Eumeralla Formation source rocks are predominantly kerogen Type III and hence gas-prone, with the potential for minor quantities of condensate (O’Brien et al., 2006). The range of kerogen types, and the increasing number of oils recovered confirm that the Eumeralla can generate both oil and gas.

The two primary coal seam sources identified have TOC between 0.2–66 wt%, averaging 8.5 wt%, and Hydrogen Indices (HI) of 16–477 mg S2 g/TOC and averaging HI 108.6 mg S2 g/TOC (Constantine, 2001). Siltstones and mudstones in the Eumeralla Formation have TOC in the range of 1 wt% (Boult and Hibburt, 2002).

The Otway Basin’s geological history of variable burial and uplift has resulted in a range of thermal maturities (Tassone, 2013; Tassone et al., 2014). Vitrinite reflectance data indicate that the Eumeralla Formation from west of the Moyston Fault Zone increases in maturity in a southwesterly direction (Mehin and Constantine, 1999). From the onshore northern margin to the coastal zone and offshore, the present vitrinite reflectance at the top of the Eumeralla Formation ranges from immature (VRo <0.50%) to mature (VRo 1.0–1.3%) (Geary and Reid, 1998).The base of the unit is from early mature (VRo 0.5–0.7%) onshore along the northern margin of the basin to late mature to over-mature (VRo 1.2–2.6%) near the coast. The Gellibrand Trough in the eastern Otway Basin and the deepest sections of the Port Campbell Embayment may contain Eumeralla Formation at depths great enough to be mature (Tassone, 2013). Modelled maturity at the top Eumeralla Formation surface by O’Brien et al. (2009) is shown in Figure 4-1.

More than 70 hydrocarbon shows are recorded in the Eumeralla Formation (Goldie Divko, 2015), and include the following wells: Fenton Creek 1, Flaxmans 1, Langley 1, Port Campbell 4, Skull Creek West 1, Tregony 1, Vaughan 1, Wallaby Creek 2 and Windermere 2 (O’Brien and Thomas, 2007). Of these, Flaxmans 1 had a particularly high DST flow rate, which was attributed to fracture porosity. Successful flows from North Paaratte 2, Skull Creek North 1, Dunbar East 1, Fenton Creek 1 and Wallaby Creek 1 during DST’s could not be maintained over time, which was attributed to tight reservoir conditions. Bellarine 1, drilled specifically to test the Eumeralla Formation, had gas shows, while Hindhaugh Creek 1 and Ferguson Hill 1 flowed ignitable gas to surface. Gas and some condensate and oil, were found in Port Campbell 4. Other oil and condensate shows have been observed in Port Campbell 4, Braeside 1, Iona 2, and Skull Creek West 1 in the Port Campbell Embayment. In 2012, Moreys 1 flowed gas and condensate from the Eumeralla Formation to the surface (Tassone, 2013).

In the South Australian part of the Penola Trough, the Windermere Sandstone commercially produced gas from Katnook 1 (Kopsen and Scholefield, 1990), and a 2 m gas column exists within Crankshaft 1 (DMITRE, 2012).


Figure 4-1 Modelled maturity at the top Eumeralla Formation surface in the Otway Basin. Pink colours indicate immature source rocks, greens indicate mature source rocks, and blues indicate overmature source rocks (O’Brien et al., 2009).

Reservoir characteristics

No measured petrophysical data directly related to Eumeralla Formation shales is publically available.

Previously identified potential

Although primarily considered a tight gas target, organic-rich shales and coaly shales have been identified in the Eumeralla Formation. Shale gas potential may be present in the Port Campbell Embayment, Windermere Trough/Tyrendarra Embayment and eastern Otway Basin (Tassone, 2013; Goldie Divko, 2015). In 2013 AWT International for ACOLA calculated a best estimate recoverable resource of 9 TCF of gas and 1.6 billion barrels (B bbls) of oil in the Eumeralla Formation over an area of 4109 km2 between Portland and Port Campbell (AWT International, 2013).

4.1.2 Crayfish Sub-group

Age

The Crayfish Sub-group is Lower Cretaceous (Valanginian–early Aptian; Goldie Divko, 2015), and consists of the Berriasian–Hauterivian Pretty Hill Formation, Hauterivian–Barremian Laira Formation and Barremian Katnook Sandstone (Lavin, 1997b).


The Crayfish Sub-group unconformably overlies the upper Jurassic to Lower Cretaceous Casterton Formation and underlies the Aptian–Albian Eumeralla Formation (Figure 2-3).



The Crayfish Sub-group is subdivided into the Pretty Hill and Laira formations, and the Katnook and Windermere Sandstones. In the Penola Trough, the Pretty Hill Formation is subdivided into four informal members: the Pretty Hill Sandstone, Sawpit Sandstone, Sawpit Shale and McEachern Sandstone (Lovibond et al., 1995).

While the Laira Formation and Pretty Hill Formation seem to be relatively easily distinguished in the western Penola Trough, stratigraphically differentiating between the Laira and Pretty Hill formations elsewhere seems to be difficult, leading to some uncertainty about the spatial distribution of each of the main Crayfish Sub-group formations. Goldie Divko (2015) suggested that there is no Laira Formation east of the SA/VIC border, however, the stratigraphy compiled for this study using well completion report (WCR) data and publically available reports and databases seems to indicate the presence of Laira Formation in the Victorian Penola Trough and the Windermere Trough/Tyrendarra Embayment.

The Katnook Sandstone is identified only in wells in the South Australian Otway Basin to date and grades laterally into the Laira Formation and possibly also the Pretty Hill Formation where identified in the Penola Trough, though this relationship is uncertain (see previous; Morton and Drexel, 1995).


The Pretty Hill Formation is spatially extensive, occurring across the entire onshore Otway Basin, although it is absent or very thin across basement highs in the western and central parts of the basin (Constantine, 2001). The thickness of the Pretty Hill Formation is highly variable, likely due to its deposition during a period with significant syn-rift faulting activity, and to a bimodally dipping top surface (southwesterly in the western and central basin, southerly in the eastern basin; Constantine, 2001; Tassone, 2013). The Pretty Hill Formation is thickest in the Penola Trough, where it reaches a thickness of 1810 m in Jolly 1. Thicknesses across the rest of the Otway Basin are more typically on the order of a few hundred metres, though in Greenslopes 1 in the Windermere Trough 1182 m is intersected.

As penetrated in wells, the Pretty Hill Formation top surface occurs at depths between 654.71 m–3513 m (Killarney 1 and Glenaire 1 ST1 respectively) and the basal surface at depths between 732.84 m–4000 m (Killarney 1 and Salamander 1 respectively).

The Laira Formation appears to be spatially restricted to the Penola Trough (e.g., Glenaire 1 ST1, 1976.8– 3513 m), but was also apparently penetrated in Banganna 1 and Taralea 1 in the Windermere Trough/Tyrendarra Embayment where it is 67 m and 95.5 m thick respectively. As penetrated, the Laira Formation top surface occurs at depths between 870–2704.5 m (Bus Swamp 1 and Taralea 1 respectively) and the basal surface at depths between 1050–3513 m (Bus Swamp 1 and Glenaire 1 ST1 respectively).


The Pretty Hill Formation consists of sandstone with varying proportions of interbedded siltstone, claystone and shale deposited in a complex fluvio-lacustrine and alluvial environment which was strongly influenced by localised structural conditions potentially causing major facies variation from graben to graben (Morton and Drexel, 1995; Tassone, 2013). The upper and lower Sawpit Shales are better developed on the northern flank of the Penola Trough, away from the major drainage axis. One occurrence of saline alga indicating brackish conditions is seen in Moyne Falls 1 (Goldie Divko, 2015). Marine incursions in the Crayfish Sub-group are suggested by geochemical markers in condensate from Troas 1 and saline-hypersaline markers suggestive of carbonate-evaporite playa facies are seen


in oils from Crayfish A1 and Zema 1 (Padley et al., 1995), though these facies have not been drilled to date.

The Laira Formation includes lacustrine mudstones and claystones with fine-grained alluvial sandstones. The Laira Formation is generally thought to record a gradual change from the primarily fluvial-flood plain environment which dominates the Pretty Hill Formation through to a shallow lacustrine environment at the top of the formation as evidenced by the presence of the algae Microfasta evansii, though this transition has also been observed locally as a sharp contact (Duddy, 2003; Boult et al., 2004). The Laira Formation becomes increasingly sandy west of the Penola Trough (Morton and Drexel, 1995).

The fluvial Katnook Sandstone consists of fine to medium-grained, cross-bedded sandstone, interbedded with dark grey micaceous siltstone. A high sinuosity environment with some flood-basin deposition, and a low sinuosity channel system have been identified as two distinct facies within the Katnook Sandstone (Boult and Hibburt, 2002).


The Crayfish Sub-group (along with the Casterton Formation) is part of the Austral 1 petroleum sub-system (Bradshaw, 1993; Summons et al., 1998; Edwards et al., 1999; Boreham et al., 2004).

Padley et al. (1995) and Edwards et al. (1999) have identified the Austral 1 petroleum sub-system as the most likely source for much of the oil and gas in the Pretty Hill Formation in South Australia (O’Brien et al., 2006, O’Brien and Thomas, 2007). Detailed isotopic work by Boreham et al. (2004) identified the Austral 1 sub-system as the likely source of hydrocarbons in the Windermere, Haselgrove, Haselgrove South and Katnook accumulations. The Ladbroke Grove accumulation (Edwards et al., 1999) and oil from Troas 1 and Nunga Mia 1 (O’Brien and Thomas, 2007) are also thought to have been derived from an Austral 1 source. In the Victorian Otway Basin, the oil shows in Garvoc 1, Woolsthorpe 1 and Hawkesdale 1 (Kopsen and Scholefield, 1990) may also be sourced from an Austral 1 source. Oils from Windermere 1 are thought to be specifically from the Crayfish Sub-group (Boreham et al., 2004).

Kerogens in the Pretty Hill Formation are dominated by Type III with some Type II and IV kerogens present, suggesting both oil and gas-generative capacity. The Laira Formation is also potentially generative for both oil and gas (Mehin and Constantine, 1999). In the Sawpit Shale in the South Australian Penola Trough, kerogens are dominated by Type III gas prone kerogen with some Type II algal rich kerogen (Boult et al., 2004; Goldstein et al., 2012).

TOC in the Pretty Hill formation ranges between 0.2–13.8 wt% and averages 1.7 wt% (Mehin and Constantine, 1999). In the Sawpit Shale in the South Australian Penola Trough, TOC values range from 0.37–2.61 wt% and average 1.12 wt% (Goldstein et al., 2012), the coaly shales in particular have an average TOC 20.3 wt% and HI 289 mg S2 g/TOC (Boult et al., 2004). While the Sawpit Shale is typically thought to be the primary source within the Crayfish Sub-group, Laira Formation shales may also contribute with previously calculated average TOC values of 0.25–2.02 wt% and HI 92 mg S2 g/TOC (Boult and Hibburt, 2002; Boult et al., 2004), and for comparison using more recent data – the Laira Formation has TOC between 0.08–34.6 wt%, averaging 1.54 wt%, and HI 10–516 mg S2 g/TOC, averaging HI 113 mg S2 g/TOC (this study). As sampled, intra formational shales in the upper Pretty Hill Formation are less likely to effective source rocks with average TOC 0.6–1.22 wt% and HI 76 mg S2 g/TOC, (Boult and Hibburt, 2002; Boult et al., 2004).

On the northern margin of the Otway Basin, the thermal maturity at the top surface of the Pretty Hill Formation is thought to be early mature for oil (VRo 0.5–0.7%), and reaches mid-maturity levels


(VRo 0.7–1.0%) towards the coast (Mehin and Constantine, 1999). Maturity modelling by O’Brien et al (2009) using an inferred Crayfish Sub-group top surface which is modelled to be 500 m above basement is shown in Figure 4-2.

Oil shows in the Pretty Hill Formation include those in Hawkesdale 1 and Woolsthorpe 1 (Campi and O’Brien, 2011). Digby 1 flowed 54 B bbls from the Pretty Hill Formation, while Glenaire 1 had strong gas shows from both the Laira Formation shales and Pretty Hill Formation sands (Tassone, 2013). In the South Australian Penola Trough the Pretty Hill Formation hosts the commercial Katnook, Ladbroke Grove, Haselgrove, Haselgrove South and Redman gas fields, and flowed significant amounts of oil, condensate and gas from Wynn 1, Killanoola 1 and Jacaranda Ridge 1 and 2 (DMITRE, 2012).

Figure 4-2 Modelled top Crayfish Sub-group maturity in the Otway Basin. Pink colours indicate immature source rocks, greens indicate mature source rocks, and blues indicate overmature source rocks (O’Brien et al., 2009).


No Victorian petrophysical data directly related to Crayfish Sub-group shales is publically available. Limited data from the Sawpit Shale are available from Jolly 1, Sawpit 2 and Bungaloo 1 in the South Australian Penola Trough.

Table 4-1 Crayfish Sub-group (Sawpit Shale) shale reservoir properties summary. Data summarised from analyses from Beach Energy (2013, 2014b, c).

Average Minimum Maximum Standard deviation

Median

Effective Porosity 0.063 0.040 0.101 0.017 0.057

Effective Gas Saturation 0.237 0.008 0.753 0.210 0.156

Effective Oil Saturation 0.027 0.001 0.157 0.045 0.016

As Received Bulk Density 2.596 2.516 2.646 0.048 2.615


The adsorbed gas content in the Sawpit Shale in Jolly 1 and Sawpit 2 ranges from 8.82–27.78 scf/ton and averages 17.42 scf/ton, though the number of available analyses (five) is small.


The Laira Formation has been identified as a possible shale gas play in the Penola Trough, while the Pretty Hill Formation has being identified primarily as a tight gas play (Tassone, 2013; Goldie Divko, 2015). However, the presence of shales in the intervals interpreted as ‘Pretty Hill Formation’ across the broader Otway Basin extent (Duddy, 2003), and shaley ‘Laira Formation’ intersections outside of the Penola Trough (Banganna 1 and Taralea 1, Windermere Trough), as well as a few shale intersections with undifferentiated ‘Crayfish Sub-group’ attributions – suggest that there may be a broader shale gas potential across the Crayfish Sub-group. In 2012, DMITRE completed a recoverable sales gas resource assessment for the onshore South Australian portion of the Otway Basin, and estimated that the Crayfish Sub-group potentially held a 623 BCF @P50 unconventional resource (DMITRE, 2012).

4.1.3 Casterton Formation

Age

The Casterton Formation is Upper Jurassic to Lower Cretaceous (Tithonian–Berriasian; Tassone, 2013).


The Casterton Formation unconformably overlies Paleozoic basement and underlies the Early Cretaceous Pretty Hill Formation (Figure 2-3; Morton and Drexel, 1995).


None.


The pre-rift to syn-rift lacustrine Casterton Formation is thought to be spatially restricted to the centres of narrow graben which formed during the early rift phase. While the fluvio-deltaic and alluvial fan deposits are restricted to the edge of the graben the formation thins where it onlaps older rocks on the flanks of the graben (Lavin and Muscatello, 1997).

All intersections and penetrations of the Casterton Formation to date (18) were made in the Penola and Digby troughs, and Windermere Trough/Tyrendarra Embayment. In the Victorian Penola Trough, the Casterton Formation reaches a maximum thickness of 243 m in Gordon 1, in the South Australian Penola Trough the thickest intersection is 373 m Bungaloo 1 (Beach Energy, 2014c). Seismic interpretation suggests the formation may reach thicknesses of 500 m in the Robe Trough (Morton and Drexel, 1995). In the Windermere Trough/Tyrendarra Embayment area penetrated thicknesses range between 25 m (Ballangeich 1) and 535 m (Hawkesdale 1)

As penetrated, the top surface of the Casterton Formation is found at depths between 718 m–3769 m and the base of the formation is at depths between 939 m–3976 m (both min/max depths in Moyne Falls 1 and Jolly 1 respectively).



The Casterton Formation comprises lacustrine shale and siltstone, with minor fluvio-deltaic sandstones and possible alluvial fan deposits near active faults. In the Victorian Casterton Formation, intercalated basalt flows and tuffs are also common (Morton and Drexel, 1995; Tassone, 2013, Goldstein et al., 2012). In the Victorian type section for the Casterton Formation (Casterton 1), the unit consists of interbedded carbonaceous shale, with minor feldspathic sandstone and siltstone and basaltic volcanics (Cundill, 1965).


The Casterton Formation is included in the Austral 1 petroleum sub-system (along with the Crayfish Sub-group) and is considered the primary source rock in the Penola Trough (Bradshaw, 1993; Summons et al., 1998; Edwards et al., 1999; Boreham et al., 2004; O’Brien et al., 2009). As the Casterton Formation is part of the Austral 1 petroleum sub-system, source correlations identified in Crayfish Sub-group section previously also apply here.

Kerogen type in the Casterton Formation is generally Type II–III with some non-generative Type IV, with HI 35–216 mg S2 g/TOC suggesting some oil and gas generative potential (Mehin and Constantine, 1999; Boult et al., 2004). The recognition of Type I–II kerogen in Gordon 1, Sawpit 1 and Casterton 1 suggests the Casterton Formation is more oil-prone, at least locally (Tassone 2013). In Casterton 1 these lamalginite and bituminite-rich sediments have TOC reaching 45.9 wt% and HI 192 mg S2 g/TOC (Boult et al., 2004).

The Casterton Formation has been widely recognised as a good to excellent source rock in lacustrine depocentres (e.g. Casterton 1) for many years, but quality can be quite variable due to lateral facies variation (Lovibond et al., 1995; Lavin, 1997b, Lavin and Muscatello, 1997), and knowledge of the organic richness of the Casterton Formation continues to evolve as progressively more wells penetrate the unit. In 1999, Mehin and Constantine quoted a TOC average of 2.6 wt%, with a range of 0.4–8.9 wt% in the Casterton Formation (Mehin and Constantine, 1999). By 2001, Constantine was quoting Casterton TOC ranges of 0.4–45.9 wt%, averaging 4.8 wt%, with HI 34–459 mg S2 g/TOC, averaging HI 149 mg S2 g/TOC (Constantine, 2001). Average TOC values in the Windermere Trough/Tyrendarra Embayment are 1.38 wt%, in the Ardonachie/Tahara troughs they are 5.53 wt% and in the Penola Trough they are 3.15 wt% (Tassone, 2013). In the South Australian Penola Trough Casterton Formation TOC ranges from 0.6–9 wt% and averages 1.9 wt% (Goldstein et al., 2012). The most recent Casterton Formation TOC data available is from Bungaloo 1 in the South Australian Penola Trough where TOC values are 0.08–4.15 wt% and average 0.80 wt% (Beach Energy, 2014c).

On the northern flank of the Otway Basin the Casterton Formation is interpreted to be in the early oil window between 2300–3050 m, the oil-condensate window between 3050–3800 m and the gas window at depths in excess of 3800 m and is likely to increase in maturity towards the centre of the basin (DMITRE, 2012; Mehin and Constantine, 1999). The Casterton Formation is found at depths between 1475 m (Tullich 1) and 2450 m (Casterton 1) in the Victorian Penola Trough, and between 2396 m (Sawpit 2) and 3976 m (Jolly 1) in the South Australian Penola Trough. Using the DMITRE (2012) maturity trend, this indicates the Casterton Formation is likely to be in the immature to early oil window as presently drilled in Victoria, and oil to gas mature in the deeper parts of the trough as drilled in South Australia. In the Windermere Trough the Casterton Formation is found at depths between 718 m (Moyne Falls 1) and 2608 m (Greenslopes 1) and is likely to be in the immature-early oil window as currently drilled. As deeper wells are drilled, or maturity trends better defined, more mature Casterton Formation intervals are likely to be encountered.


Oil cut mud was recovered from the Casterton Formation in a Digby 1 DST, and oil shows were found in Woolsthorpe 1. Oil recovered from fractured basement in Gordon 1 is thought to come from the Casterton Formation (Tassone, 2013). Three other wells in the Ardonachie Trough had weak oil and gas shows, but no DST tests were carried out (Goldie Divko, 2015). In the South Australian Penola Trough Sawpit 1 had oil shows in fractured basement thought to be derived from the Casterton Formation (Tassone, 2013), while Jolly 1 had gas shows and elevated gas readings were seen in Bungaloo 1 throughout the Casterton Formation (Cooper Energy, 2014b; Beach Energy, 2014c).


No petrophysical data is available for Casterton Formation shales in the Victorian Otway Basin. Limited data is available from the Jolly 1, Sawpit 2 and Bungaloo 1 wells in the South Australian Penola Trough and is summarised below in Table 4-2.

Table 4-2 Casterton Formation shale reservoir properties summary. Data summarised from analyses from Beach Energy (2013, 2014b, c).

Average Minimum Maximum Standard deviation Median

Effective Porosity 0.037 0.022 0.073 0.019 0.026

Effective Gas Saturation 0.145 0.053 0.278 0.077 0.139

Effective Oil Saturation 0.016 0.003 0.039 0.014 0.010

As Received Bulk Density 2.684 2.583 2.737 0.050 2.703

The adsorbed gas content in the Casterton Formation in Jolly 1 and Sawpit 2 ranges from 12.37–30.72 scf/ton and averages 19.6 scf/ton though the number of available analyses (eight) is small.


The Casterton Formation is considered to be highly prospective in the South Australian Penola Trough currently, and has been targeted specifically as a shale gas target in this area. In addition, the Casterton Formation in the Ardonachie/Tahara troughs and the Windermere Trough/Tyrendarra Embayment may also have some shale resource potential (Tassone, 2013; Goldie Divko, 2015). Somerton Energy estimated that Victorian permit PEP 171 could contain more than 25 TCF of gas in the Casterton Formation (Goldstein et al., 2012).

4.2 Tight resources


The general characteristics of the Eumeralla Formation have previously been discussed in Section 4.1.1. The following section summarises aspects of the Eumeralla Formation specific to the tight resource play.


The measured porosity and permeability of Eumeralla Formation sandstones are variable in the eastern portion of the basin (Tassone, 2013). The sandstones are tight at Anglesea 1, Ferguson Hill 1 and Sherbrook 1. In the west of Victoria, the porosity is somewhat higher, but still mostly tight (Goldie


Divko, 2015). In the Port Campbell Embayment, reservoir porosities and permeabilities are 8–25% and 0.1–100 mD respectively (Tassone, 2013).

No measured gas saturation data is publically available, but following the drilling of Moreys 1 and after doing permit scale interpretation over the Portland Energy project, Lakes Oil have indicated the Eumeralla Formation is gas saturated (Lakes Oil, 2012; 2016). Apart from such anecdotal statements, very limited measured petrophysical data to assessing the tight resource potential is available for the Eumeralla Formation.

Tight gas potential in the Eumeralla Formation has been recognised in the Port Campbell Embayment. There may also be potential in the Windermere Trough/Tyrendarra Embayment, and in the eastern Otway Basin more generally (Tassone, 2013; Goldie Divko, 2015). The Eumeralla Formation is not buried deeply enough in the northern South Australian Otway Basin to be a self-sourcing tight gas play, and would have to rely on long-range migration for charge, but may have more potential in the southern parts of the South Australian Otway Basin where it is deeply buried by a thick section of Sherbrook Group (Department of State Development South Australia, 2017).


The general characteristics of the Crayfish Sub-group have previously been discussed in Section 4.1.1. The following section summarises aspects of the Crayfish Sub-group specific to the tight resource play.


The Pretty Hill Formation in Victoria has good reservoir characteristics at shallow to moderate depths of burial (1000–2300 m) with average porosity and permeability of 20.7% and 390 mD respectively (Mehin and Constantine, 1999). The reservoir quality below the depth of approximately 2300 m is largely unknown due to the lack of well penetrations.

In the gas fields in the South Australian Penola Trough, the Crayfish Sub-group gas reservoirs at depths of 2500–2800 m have effective average core porosity and permeability of 10–18% and 0.6–549 mD respectively (Parker, 1995). In Glenaire 1 ST1 in the Penola Trough, well log evaluation was carried out for the depth interval of 3400–3705 m, which includes both the Laira and Pretty Hill formations. Beyond these few values, very limited petrophysical data to assess the tight resource potential is available for the Crayfish Sub-group.

The Pretty Hill Formation is considered to potentially be prospective for tight gas in the Windermere Trough/Tyrendarra Embayment, Ardonachie/Tahara Trough, the Penola Trough and the eastern Otway Basin (Tassone, 2013; Goldie Divko, 2015). The deeper parts of the South Australian Penola Trough and Robe Trough have also been recognised as potential targets for tight gas plays in the Crayfish Sub-group (Goldstein et al., 2012).


5 Method

A probabilistic volumetric analysis method was used to calculate shale and tight liquids- and gas-in-place in the Otway Basin. The method is similar to that applied in previous studies (EIA, 2011, 2013; AWT International, 2013). The mathematical approach used in this assessment is summarised as follows. Gas in shale reservoirs can be broken into two main parts: free gas and adsorbed gas. The calculation for free gas-in-place (FGIP) uses the following standard reservoir engineering equation:

FGIP =𝐴𝐴ℎ𝛷𝛷(1 − 𝑆𝑆𝑆𝑆)

𝐵𝐵𝑔𝑔

Where:

• FGIP = free gas-in-place (sm3)

• A = prospective area (m2)

• h = net shale thickness (m)

• Φ = porosity (fraction)

• Sw = water saturation (fraction) • Bg = gas formation volume factor (volume at reservoir condition/volume at surface condition)

The adsorbed gas-in-place (AGIP) is calculated (after EIA, 2011; 2013) as:

AGIP = 𝐺𝐺𝐺𝐺𝑎𝑎 × 𝜌𝜌𝑏𝑏

Where:

• AGIP = adsorbed gas-in-place (m3)

• GCa = adsorbed gas content in shale (sm3/g) • ρb = bulk density of shale (g/cm3)

This method was chosen as it is a relatively simple approach, and is useful in dealing with the uncertainty associated with undertaking assessments in basins where data are sparse. The methodology used to produce an assessment of the shale and tight liquids- and gas-in-place can be broken down into the following key steps:

• Collate available geological data and create required derivative datasets

• Decide which formations are to be assessed in the basin

• Define the prospective volume for each formation

• Calculate the shale or tight gas- and liquids-in-place using distributions fitted to real or analogous data in @Risk

• Apply a recovery factor

These steps will be discussed in more detail in the following sections.


5.1 Shale resources method

5.1.1 Data inputs and sources

Details of the input data used to characterise the Eumeralla Formation, Crayfish Sub-group and Casterton Formation shale resource plays are shown in Table 5-1. Further details are discussed in the text following the tables. Selected input data and the related statistical analyses are contained in the spreadsheets which accompany this report.

Data compilation

Assessment extent

The Otway Basin as assessed in this study includes the area of the Otway Basin west of the Otway Ranges (Figure 1-1) and south of the Otway Hinge Zone and excludes the region east and north of these features due to the sparsity of data, and the very different geological character (see Section 2.1 for more detail). Data from wells in the eastern Otway including Olangolah 1, Anglesea 1A and Hindhaugh Creek 1 have been considered where necessary to ensure a regional geological perspective is maintained.

Datums

The GDA94 datum was used for all GIS data in the assessment. When calculating polygon areas the Albers equal area projection was used. All data uses the ground surface as the height datum.

Well locations

Well locations and basic statistics are compiled from sources including Geological Survey of Victoria (GSV), Geoscience Australia (GA) and GP Info in order to create a complete representation of the well locations. Where overt errors, particularly in total depth (TD), were observed during the course of the study these were manually corrected.


Table 5-1 Summary of data sources and associated assumptions/limitations of parameters specific to the Eumeralla Formation, Crayfish Sub-group and Casterton Formation shale resource plays.

Parameter Data source(s) Description/Assumptions Limitations

Formation extent, thickness and depth

Stratigraphy compiled from GSV and GA databases with additional information from: Beach Energy (2013, 2014b, c), Cooper Energy (2014b), Lakes Oil N L.(2012), Oil Company of Australia Ltd. (1992), Panax Geothermal (2010), Sagasco Resources Ltd. (1995a), and Santos (2000, 2001)

This dataset is a compilation removing old stratigraphic names and attempting to resolve lateral equivalents. It also incorporates updates where available from newer WCR’s and company updates.

This stratigraphy does not represent a detailed stratigraphic reinterpretation of any kind.

Geochemistry data Geochemistry data from GA and GSV database compiled with additional data from: Anglo Australian Oil Company (1992), Beach Energy (2013, 2014c), Cliff (1994), Hartogen Energy Limited (1989) and Sagasco Resources Ltd. (1995a).

Rock Eval and vitrinite reflectance data were compiled and QC’d and used to underpin the prospective area and thickness mapping process.

Geochemistry data in parts of the Otway Basin are very sparse and from many different laboratories and vintages. While every attempt was made to include only the most reliable analyses, the compiled geochemistry dataset should be used with caution.

Net shale ratio Calculated for 56 sections across three formations. Calculated for key wells from WCR composite logs and cuttings information. Number of sections evaluated: Eumeralla (22), Crayfish Sub-group (26), and Casterton Formation (8).

Relatively few values in some prospective area polygons. Poor composite log quality may result in unrealistic estimates.

Total porosity WCR’s of Jolly 1, Sawpit 2 and Bungaloo 1 (Beach Energy, 2013; 2014b, c)

Lab measured total porosity in the Sawpit Shale and Casterton Formation.

Sawpit Shale values used to characterise the Eumeralla Formation and Crayfish Sub-group shales. The shale rock properties in the Eumeralla Formation may be different to those in the Sawpit Shale in SA, and to those in the Crayfish Sub-group.

Bulk density WCR’s of Jolly 1, Sawpit 2 and Bungaloo 1 (Beach Energy, 2013; 2014b, c)

Lab measured bulk density in the Sawpit Shale and Casterton Formation.

As above

Total gas saturation WCR’s of Jolly 1, Sawpit 2 and Bungaloo 1 (Beach Energy, 2013; 2014b, c)

Lab measured total gas saturation in the Sawpit Shale and Casterton Formation.

As above

Total oil saturation WCR’s of Jolly 1, Sawpit 2 and Bungaloo 1 (Beach Energy, 2013; 2014b, c)

Lab measured total oil saturation in the Sawpit Shale and Casterton Formation.

As above


Parameter Data source(s) Description/Assumptions Limitations

Condensate-to-gas ratio

Eumeralla Formation: WCR’s of Fenton Creek 1, Grumby 1, La Bella 1, McIntee 1, Port Campbell 1 and Wallaby Creek 1 (Watt and Horner, 1997; Patchett, 1981; Locke, 1994; Zurcher, 2001; Frome-Broken Hill Company Proprietary Limited, 1964; and Harrison, 1981). Crayfish Sub-group and Casterton Formation: WCR’s of Haselgrove 1, 2 and South 1 DW1, Katnook 2 and 3, Ladbroke Grove 2, Redman 1 and Wynn 1 (Sagasco Resources Ltd, 1995a, b, c; Ultramar Australia Inc, 1990, and Boral Energy Resources Ltd, 1997a, b, 1999, 2000)

Eumeralla Formation: Well test data (DST, RFT, PT) on the Waarre Sandstone Crayfish Sub-group and Casterton Formation: Well test data (DST, RFT) data on the Pretty Hill Formation

The gas from the Eumeralla Formation may be different from the Waarre gas. Facies variation may result in different shale rock properties in the Pretty Hill Formation in Victoria. Fluids from the Casterton may be different from those from the Pretty Hill Formation.

Gas-to-oil ratio Eumeralla Formation: WCR’s of Mylor 1 and Wild Dog Road 1 (Cliff, 1994; Trupp et al., 1993). Crayfish Sub-group and Casterton Formation: WCR’s of Port Campbell 4 and Jacaranda Ridge 1 (Benedek, 1964; Origin Energy Resources Ltd, 1999).

Eumeralla Formation: Gas-to-oil ratio from the Waarre Formation Crayfish Sub-group and Casterton Formation: Gas-to-oil ratio from the Pretty Hill Formation.

The oil from the Eumeralla Formation may be different from the Waarre oil, and the Crayfish Sub-group and Casterton Formation oils may be different to the Pretty Hill Formation oils.

Oil formation volume factor

WCR of Mylor 1 (Cliff, 1994) Oil Formation factor for oil from the Waarre Formation

The oils from the Eumeralla Formation, Crayfish Sub-group and Casterton Formation may be different to the Waarre oil.

Gas formation volume factor

Mehin and Kamel (2002) Gas expansion factor data for Waarre Formation gas from Mylor 1 and Wild Dog Road 1

The Bg data in Mylor 1 and Wild Dog Road 1 are from the gas reservoirs in the Waarre Formation, which may not fit the properties of the Eumeralla Formation, Crayfish Sub-group or Casterton Formation.

Adsorbed gas content WCR’s of Jolly 1 and Sawpit 2 (Beach Energy, 2013; 2014b)

Gas storage capacity from isotherm test in the Sawpit Shale and Casterton Formation.

Sawpit Shale values used to characterise the Eumeralla Formation and Crayfish Sub-group shales. The shale rock properties in the Eumeralla Formation may be different to those in the Sawpit Shale in SA, and to those in the Crayfish Sub-group.


Geochemistry data

TOC data

TOC values which indicate shale and coaly shale lithologies will be included for each formation. Values below 0.5% TOC will be regarded as not representing shales and hence excluded from the TOC average used to define the area and thickness of organically rich shales. The TOC thresholds used are shown below and are from Hall et al. (2016):

• Coal ≥50 wt%

• Shaly coal 20 wt%–50 wt%

• Coaly shale 10 wt%–20 wt%

• Shale 0.5 wt%–10 wt%

It is noted that these threshold values have been determined for fluvial, terrestrially derived shales and that in more marine influenced systems, the nomenclature of ‘coal’ is not appropriate. The 50 wt% cutoff threshold has been retained, however, on the premise that shale TOC values over 50 wt% are likely to have petrophysical properties significantly different to shales with <1 wt% TOC. However, at the same time, it is recognised the change in petrophysical properties that occurs with increasing TOC is a continuum (e.g. Wang et al., 2013) and that a case could be made for subdividing the TOC values into many more ‘lithological’ categories in order to best capture these changes.

Wells with no TOC >0.5 wt% for the whole formation as penetrated will be regarded as not containing any organically rich shales. However, data distribution will also be taken into account to ensure wells with insufficient data coverage (less than 10 TOC values within the formation) are not being excluded without good cause.

Rock Eval data

Three key steps were taken to ensure only reliable Rock Eval data was used in the maturity mapping process.

• remove any spurious S1+S2 values where there is only one of S1 or S2 in the analysis,

• calculate PI, HI, OI and PC values, and

• apply 0.1< PI < 0.4 cutoffs Ghori (2013) to exclude any data which may be indicative of contamination or migration.

Tmax reliability and Tmax-VRo conversion

The following text documents the process used to ensure the most reliable Tmax to VRo conversion possible. Tmax values where S2 is low are unreliable (e.g. S2<0.2 mg HC/g; Nuñez-Betelu and Baceta, 1994; Wallace and Roen, 1989; Peters, 1986; and S2< 0.5 mg HC/g; Dewing and Sanei, 2009) and TOC<0.1 wt% also produces unreliable Tmax values (Dewing and Sanei, 2009). Analyses where TOC<0.1 wt% will be removed from the Tmax dataset. The S2 cutoff values however necessitate an additional step for the maturity evaluation using Tmax. For the purposes of this study, a conservative threshold value of S2>0.5 mg HC/g has been used for all formations to ensure Tmax reliability is reasonable without decimating the dataset. While it is recognised that ideally the S2 cutoff value would be varied through the stratigraphic section in order to best represent factors such as kerogen type, maturity level and variable organic content, that level of analysis is beyond the scope of this study.


Tmax values meeting the TOC>0.1 wt%, S2>0.5 and 0.1<PI<0.4 thresholds which were converted into VRo values using the Jarvie equation (Jarvie et al., 2001) proved to have a poor relationship with the measured VRo data when plotted against depth (Figure 5-1), indicating the Jarvie equation conversion does not hold well for Otway Basin shales. As the Jarvie equation (Jarvie et al., 2001) was developed for the Barnett Shale, and so is representative of shales of different age, paleoenvironment, kerogen type and organic richness, the poor fit with measured VRo data in the Otway Basin is not particularly surprising. To ensure maximum reliability, measured VRo data has been preferentially used to map maturity in this assessment. The calculated VRo values have only been used to provide maturity indications in areas where there are currently no measured VRo values.

Figure 5-1 Measured VRo (blue) and Jarvie-calculated VRo (red) values versus depth in the Otway Basin.

5.1.2 Defining area, prospective area, thickness and net thickness

The key steps in determining the net prospective volume for each formation as used in the shale resource assessment are outlined as follows:

• The approximate areal extent of the formation was first evaluated using well data and 3D surfaces (eastern Otway only). Available well penetration/intersection data for each assessment can be seen in Figure 6-1, Figure 6-2 and Figure 6-3,

• Cut-off thresholds for depth, formation thickness, average TOC and maturity were then applied with polygons for each parameter being drawn in ArcGIS. The final prospective area polygons were defined by the intersection of these polygons. The final prospective areas for the Eumeralla Formation, Crayfish Sub-group and Casterton Formation can be seen in Figure 6-1, Figure 6-2 and Figure 6-3, and are summarised in Table 5-3.

• The thickness of the formation within each maturity window was calculated using a regional trend in maturity with depth.


• The net shale thickness within each prospective area was then calculated to create the prospective volume. As there is insufficient geochemistry data and highly variable well log quality all shales within each prospective area are assumed to be organically rich.

Four threshold values were used to find the prospective area. They are defined on the basis of:

• Depth: formation is found at depths between 1000–5000 m,

• Formation thickness: where true vertical thickness of the formation is ≥ 15 m, and

• Total organic content: where average TOC for shales in each well is ≥ 2 wt% +1 stdev.

• Maturity: vitrinite reflectance (VRo %) cutoffs used were: immature 0%–0.7% VRo, oil: 0.7%–1.0% VRo, wet gas: 1.0%–1.3% VRo, gas: 1.3%–3.0% VRo and over-mature: >3.0% VRo, and

A normal probability distribution function was assigned to all of the prospective areas during the final probabilistic modelling process, with the mean prospective area determining the central point. The maximum and minimum values for each prospective area probability function were ±10%.

Two threshold values were used to find the prospective thickness, being defined on the basis of:

• Maturity: As above.

• Net shale thickness: proportion of shale beds which are ≥ 15 m.

These thresholds are designed to ensure that shales within the prospective areas were organically rich and mature enough to have a reasonable chance of hosting hydrocarbons, be sufficiently pressured to preserve gas content and promote gas flow if developed, thick enough to potentially be commercially exploited, and to ensure the shales were at economically drillable depths given today’s technology. Used together these thresholds define the ‘prospective volume’ for each formation. The following sections detail additional mapping and/or calculation information associated with the above key thresholds for the Eumeralla Formation, Crayfish Sub-group and Casterton Formation shale resource assessments.

Prospective area definition

Formation mapping, depth and initial thickness

The Windermere and Heathfield sandstones and the Killara Coal Measures were included as part of the Eumeralla Formation assessment. The Crayfish Sub-group as assessed includes the Pretty Hills Formation, Laira Formation and Katnook Sandstone and any undifferentiated Crayfish Sub-group units (e.g. in North Eumeralla 1) as these formations are unable to be reliably differentiated.

The spatial extent of the Eumeralla Formation, Crayfish Sub-group and Casterton Formation was mapped using well data. In the eastern Otway Basin the extent of the Eumeralla Formation and the Crayfish Sub-group was also informed using surfaces from the Otway and Torquay 3D model (Rawling et al., 2011). Surfaces from this model were modified from a MSL datum to a ground surface datum to allow comparison with onshore well data.

The thickness of the Eumeralla Formation, Crayfish Sub-group and the Casterton Formation between 1000 and 5000 m was defined using available well penetrations and intersections only. Thus, the shale resource assessment was limited to the ‘as penetrated’ volumes defined using well data, and not the full volume of the formation.


TOC

The spatial extent of organically-rich shales for each assessed formation was mapped using measured TOC data. The extent of the prospective areas is highly dependent on the existing TOC dataset, and as such the prospective areas should be regarded as conservative.

Values defined as geochemically representing shales have modern-day TOC values of greater than 0.5 wt% and less than 50 wt%. These values were compiled from publically available sources, averaged for the shales in the assessed formation in each well, and then mapped in two dimensional space. An average TOC of ≥2 wt% + 1 stdev was regarded as having shale resource potential for the purposes of this study.

Geologically reasonable polygons around the average TOC points ≥2 wt% + 1 stdev were used to represent the spatial extent of organically rich shales in the Otway Basin. Polygons were drawn to best represent the major structural and paleoenvironmental subdivisions of the basin to ensure ‘like’ shales were assessed together. The Casterton Formation has two separate areas of identified high-TOC, one in the Penola Trough and one in the Digby Trough area that were assessed collectively. Two areas of elevated TOC in the Crayfish Sub-group were identified in the greater Penola Trough region, these were also assessed collectively.

Maturity

The maturity depth thresholds for the Otway Basin were generated using publically available VRo data to define the depth at which the immature, oil, wet gas and dry gas maturity windows occur. Data from offshore wells (e.g. Crayfish 1A, Neptune 1 etc.) were included to better characterise maturity in the Robe Trough. EIA (2013) maturity windows were applied: immature: 0–0.7% VRo, oil: 0.7–1.0% VRo, wet gas: 1.0–1.3% VRo, gas: 1.3–3.0% VRo and over-mature: >3.0% VRo. The compiled maturity data were initially used to generate a vitrinite reflectance with depth trend line for each high-TOC area. These trends were calculated by plotting all available maturity data relevant to a prospective area polygon against depth and fitting a trend line. As the maturity trends calculated for each high-TOC area were very similar across the Otway Basin, a single regional maturity with depth trend was ultimately applied to all stratigraphic data to generate a set of thickness values for each maturity window. The depths at which the oil, wet gas, dry gas and over mature windows occur are shown in Table 5-2. The number of well penetrations limited the number of generated thickness values. Once the well intersections within each maturity were finalised these were used to spatially map the extent of oil, wet gas and dry gas within each formation. These were used in conjunction with the initial thickness and depth data, and the high-TOC polygons to map the prospective areas of each assessed formation. These are summarised below in Table 5-3.

Table 5-2 Depth of vitrinite reflectance thresholds in the Otway Basin.

VRo threshold (EIA, 2013)

Maturity window Window top depth (m)

0.7% Oil window 2249

1.0% Wet gas window 2972

1.3% Dry gas window 3503

3.0% Overmature window 5197


Table 5-3 Shale resource assessment prospective area polygons summary.

Formation Polygon Oil area (m2) Wet gas area (m2) Dry gas area (m2)

Eumeralla Formation Port Campbell Embayment 395 948 187 396 117 450 239 259 720

Windermere Trough 119 936 282 119 871 924 NA

Tantanoola Trough 306 116 745 NA NA

Hatherleigh/Rivoli area 52 180 203 6 152 091 6 152 091

Crayfish Sub-group Greater Penola Trough 383 707 375 68 037 897 68 022 119

Hatherleigh/Rivoli area 62 913 205 NA NA

Casterton Formation Greater Penola Trough 114 049 888 48 308 561 55 240 247

Windermere Trough 41 400 304 NA NA

Prospective thickness definition

Maturity

The thickness of formation in each prospective area was defined using the previously generated data describing the thickness of the formation within each maturity window. Wells within the prospective area polygons, and where applicable, those immediately outside the prospective area polygons, (and within the same structural unit) were included to create a set of thickness values for the formation in each maturity window for each prospective area polygon. These compiled data were used to define the @Risk thickness distribution.

The inclusion of wells with zero results in the ‘thickness of each maturity window’ probability distributions in @Risk (see later) was used as a rough proxy for how much of the area may be prospective in each maturity window.

Net shale ratio

The net shale ratio describes what proportion of the formation in question meets the prospective shale definition. The net shale ratios were derived visually from composite log and cuttings data for the formation between 1000–5000 m depth; suitable individual shale beds were defined as >15 m thick, and >70% shale/siltstone content. This definition of net shale ratio differs from the industry term which also describes the proportion of shales with sufficient organic richness. The net shale ratio was calculated for 22 wells in the Eumeralla Formation, 26 wells in the Crayfish Sub-group and eight wells in the Casterton Formation which are within or near prospective area polygons. Net shale ratio summary statistics at the formation level are shown in Table 5-4.

Table 5-4 Net shale ratio statistics at the formation level for the Eumeralla Formation, Crayfish Sub-group and Casterton Formation.

Formation Average Minimum Maximum Median Standard deviation

Eumeralla Formation 0.48 0.00 1.00 0.44 0.27

Crayfish Sub-group 0.49 0.00 1.00 0.50 0.29

Casterton Formation 0.59 0.00 1.00 0.70 0.37

There was insufficient measured TOC data, or detailed log interpretations to allow the application of a net ‘organically rich shale ratio’ (called net shale ratio by industry). Thus, all shales that met the


definition of ‘prospective shale’ as defined here and that fell within the prospective area polygon were regarded as organically rich.

5.1.3 Reservoir characterisation and volume factors

Petrophysical properties

The limited petrophysical data used in the assessment was sourced from the Jolly 1, Sawpit 2 and Bungaloo 1 WCR’s (Beach Energy 2013; 2014b, c). All three wells are in the South Australian Penola Trough. Nineteen total porosity, twenty bulk density and eight total oil and gas saturation analyses from the Casterton Formation, and eighteen total porosity, fourteen bulk density and ten total oil and gas saturation analyses from the Sawpit Shale (Crayfish Sub-group) were incorporated in the assessment.

No measured data was available to characterise the Eumeralla Formation. Data from the Sawpit Shale was used to approximate the Eumeralla Formation shale properties. Shale property statistics used in the assessment are summarised in Table 5-5, all data used in the assessment can be found in the @Risk spreadsheet accompanying this report.

Table 5-5 Sawpit Shale and Casterton Formation shale petrophysical properties summary. Data summarised from WCR’s of Jolly 1, Sawpit 2 and Bungaloo 1 (Beach Energy, 2013; 2014b, c).

Formation Parameter Average Minimum Maximum Standard deviation

Median

Sawpit Shale Gas Saturation 0.24 0.008 0.75 0.21 0.16

Oil Saturation 0.03 0.00 0.16 0.05 0.02

Porosity 0.06 0.04 0.10 0.02 0.06

Bulk Density 2.60 2.52 2.65 0.05 2.62

Casterton Formation Gas Saturation 0.14 0.05 0.28 0.08 0.14

Oil Saturation 0.02 0.00 0.04 0.01 0.01

Porosity 0.04 0.02 0.07 0.02 0.03

Bulk Density 2.68 2.58 2.74 0.05 2.70

It is noted that carbon dioxide (CO2) and other gases constitute a significant part of gas accumulations in the Otway Basin, and should be considered as part of any future detailed study, but were not accounted for in this assessment.

Condensate-to-gas ratio and gas-to-oil ratio

There was no measured condensate-to-gas ratio (CGR) or gas-to-oil ratio (GOR) data available for the Eumeralla Formation, Crayfish Sub-group and Casterton Formation shales. The CGR and GOR distributions for the Eumeralla Formation were assumed using well test data in the Waarre Sandstone. The CGR and GOR distributions for the Crayfish Sub-group and Casterton Formation were assumed using well test data in the Pretty Hill Formation and Sawpit Shale from eight wells in the South Australian Penola Trough. The wells used in this process are listed in Table 5-1.


Formation volume factors

There were no measured values available for gas (Bg) and oil (Bo) formation volume factors in the formations assessed at the time of writing. Data from the Waarre Formation in Mylor 1 and Wild Dog Road 1 (Cliff, 1994; Mehin and Kamel, 2002) were used to approximate the formation volume factors in the absence of any other measured data.

Adsorbed gas content

Eight adsorbed gas content (GCa) values from Jolly 1 and Sawpit 2 (Beach Energy 2013; 2014b) were used to characterise the Casterton Formation shales in this assessment. There was no GCa data available for the Eumeralla Formation and Crayfish Sub-group at the time of writing. Four analyses from the Sawpit Shale in Jolly 1 and Sawpit 2 were used to approximate the GCa for these units.

5.1.4 Estimating OIP and GIP using @Risk

Probability distributions for all parameters were generated in @ RiskPro 6.3 (@Risk, an extension to Microsoft Excel) and used to calculate the OIP and GIP for the assessed shales using the equations shown in the @Risk spreadsheets accompanying this report. In most cases, statistically reliable data is not available, and a distribution curve is manually built to encompass the available data, with an allowance for expected natural variation. The number of different types of distribution types used was kept to a minimum. In the Otway Basin assessment fitted curves were used for porosity, water saturation and density parameters, all other petrophysical parameters have defined distributions.

The estimation of gas- or liquids- in-place is made 10 000 times using @Risk, taking random draws from each parameters’ probability distribution function. The decision to use 10 000 was based on initial sensitivity testing which indicated the result distributions were effectively static beyond this value. The ‘Function’ column as shown in the @Risk input parameters tables (e.g. Appendix Table A-1 etc.) lists the scripted description of the probability distribution function in @Risk. Further information on these can be found directly in the @Risk spreadsheet associated with this report or in the @RiskPro 6.3 program documentation (http://www.palisade.com/risk/). Once all the parameters had distributions assigned in @Risk, the GIP and OIP were calculated. For this assessment all the input parameters are assumed to be independent. The underlying formulae used can be seen in full in the @Risk spreadsheet associated with this report.

This probabilistic method captures estimates of uncertainty in each parameter, and propagates these throughout each calculation, resulting in a range of estimates. The Otway Basin shale resource assessment GIP and liquids-in-place OIP results were reported at P10, P50, mean and P90 levels for each assessed prospective area polygon and rolled up into ‘formation level’ values.

5.1.5 Recovery factor

Exploration for, and development of, unconventional resources in Australia is still in the very early stages. As a result, there is a lack of production data for unconventional resources, and in most cases international analogues are tenuous at best. Because of this, it is not feasible to predict recovery factors for Australian unconventional resources with any degree of certainty. There is also a high level of uncertainty associated with the estimated prospective volumes which is related to data availability more generally. A conservative recovery factor of 5% has been used in the recoverable GIP and OIP Otway Basin resource assessment to reflect this. As with other parameters, this factor can be updated as more data become available with the progress of future projects.


http://www.palisade.com/risk/

5.2 Tight resources method The process of estimating tight GIP and OIP is very similar to the process outlined for the free GIP and OIP shale resource calculation previously, and uses the same underpinning stratigraphic data. For the purpose of this assessment, the initial volume of the Eumeralla Formation and Crayfish Sub-group tight resource plays were defined as the volume between 1000 m and 5000 m depth, with a thickness of greater than 15 m. Key differences in the process are outlined in the following text.

• No maturity thresholds were used to determine the Eumeralla Formation tight resource volume as the gas is, based on gas composition data is not generated immediately in situ. For example, a laboratory analysis of gas from the Eumeralla Formation in Katnook 2 in the Penola Trough indicates the presence dry gas, in an area where the Eumeralla Formation is modelled to be immature (Boral Energy Resources Ltd. 1997a).

• There is no clear evidence suggesting significant long distance migration in the Crayfish Sub-group, and as such it has been treated as a self-sourcing tight resource play, and hence the prospective volume has been mapped based on maturity in addition to the other key thresholds.

• No organically-rich shale extent was required for the Eumeralla Formation assessment as the reservoir is not regarded as self-sourcing (see above) and hence as the extent of the tight resource play was independent of organic content. As the Crayfish Sub-group has been assessed as a potentially locally to sub-regionally self-sourcing reservoir, proximity to high-TOC content has been evaluated, though not as stringently as for the shale assessment as some local-scale migration is possible.

• Gas in the Eumeralla Formation has been assessed as dry gas only as the majority of available analyses suggest gas reservoired in the Eumeralla Formation is dry. Though preliminary indications from a DST in Moreys 1, mud gas from Windermere 2 and oil and condensate shows (e.g. Port Campbell 4, Braeside 1, Iona 2, and Skull Creek West 1) in the Port Campbell Embayment and Windermere Trough indicate at least some liquids may be present (Armour Energy Limited, 2012; Tassone, 2013; O’Brien et al., 2009).

• The net-to-gross ratio is used to estimate how much of the formation is an effective tight reservoir in a vertical sense. Two well log interpretations were used to estimate the net-to-gross ratio, one for the Crayfish Sub-group (Glenaire 1 ST1), and one for the Eumeralla Formation (Port Fairy 1).

The prospective areas for the Eumeralla Formation and Crayfish Sub-group tight resource assessments are shown in Table 5-3.

Table 5-6 Tight resource assessment prospective area polygons summary.

Formation Oil area (m2) Wet gas area (m2) Dry gas area (m2)

Eumeralla Formation NA NA 17 233 870 881

Crayfish Sub-group (Penola + Hatherleigh/Rivoli areas)

1 746 734 313 726 932 454 277 334 640

The data sources used to inform a geologically reasonable estimation of these parameters for the Eumeralla Formation and Crayfish Sub-group tight resource assessments are shown below in Table 5-7. All data used in the assessments is presented in the accompanying spreadsheets.


Table 5-7 Summary of data sources and associated assumptions/limitations of all petrophysical parameters for the Eumeralla Formation and Crayfish Sub-group tight resource plays.

Parameter Data source Description/Assumptions Limitations

Effective porosity

Eumeralla Formation: WCR of Port Fairy 1 (Essential Petroleum Resources Limited, 2002) Crayfish Sub-group: WCR of Glenaire 1ST1 (Beach Petroleum Ltd, 2007)

Well log interpretation results of the Eumeralla and Laira/Pretty Hill formations

Facies variation across the onshore Otway Basin may lead to different rock properties in different areas.

Effective water saturation


DST in the Eumeralla Formation and well log interpretation results of the Eumeralla and Laira/Pretty Hill formations

As above

Net-to-gross ratio


Well log interpretation results of the Eumeralla and Laira/Pretty Hill formations

As above

Gas formation volume factor

Mehin and Kamel (2002) Bg data on the Waarre gas from Mylor 1 and Wild Dog Road 1

The Bg data used is from the Waarre Formation, which may not be appropriate for Eumeralla Formation and Crayfish Sub-group gases.

Condensate-to-gas ratio

Eumeralla Formation: WCR’s of Fenton Creek 1, Grumby 1, La Bella 1, McIntee 1, Port Campbell 1 and Wallaby Creek 1 ((Watt and Horner, 1997; Patchett, 1981; Locke, 1994; Zurcher, 2001; Frome-Broken Hill Company Proprietary Limited, 1964; and Harrison, 1981). Crayfish Sub-group: WCR’s of Haselgrove 1, Katnook 2, Redman 1 and Wynn 1 (Sagasco Resources Ltd, 1995a, b; and Boral Energy Resources Ltd, 1997a,b, 1999)

Eumeralla Formation: Well testing data (DST, RFT, PT) on the Waarre Sandstone Crayfish Sub-group: Well testing data (DST, RFT) data on the Pretty Hill Formation.

The gas from the Eumeralla Formation may be different from the Waarre gas. Facies variation may result in different shale rock properties in the Pretty Hill Formation in Victoria.


6 Results

6.1 Shale resource assessment


Shales in the Eumeralla Formation have been identified as mature for oil and wet gas (as penetrated) primarily in the Port Campbell Embayment. Some indications of shale oil potential are also seen in the Tantanoola Trough, the Windermere Trough/Tyrendarra Embayment, and the Rendelsham area. Indications of wet gas maturity are seen in similar areas, but in fewer wells. Dry gas indications are only seen in Geltwood Beach 1 (Rendelsham area), and in Flaxmans 1 and Fergusons Hill 1 (Port Campbell Embayment). In all of these areas Eumeralla Formation shales are also organically rich to some degree. The prospective area polygons are shown below in Figure 6-1.

Figure 6-1 Prospective areas for the Eumeralla Formation shale assessment in the Otway Basin, and wells with Eumeralla Formation at >1000 m.

@Risk inputs

A summary of all @Risk inputs used to calculate the Eumeralla Formation shale resource assessment are listed in Appendix Table A-1


Results

Table 6-1 Estimated shale gas-in-place (GIP) and liquids-in-place (OIP) at P10, P50, mean and P90 levels, for the Eumeralla Formation in the Port Campbell Embayment, Windermere Trough, Tantanoola Trough and Hatherleigh/Rivoli areas, Otway Basin.


Shales within the Crayfish Sub-group as penetrated have been identified as mature for oil in the Windermere Trough/Tyrendarra Embayment, the Tantanoola Trough, across the greater Penola Trough, and to a lesser degree in the Robe Trough, St Clair Trough and the Hatherleigh area. Mature wet gas penetrations are located primarily in the South Australian Penola Trough. A few more isolated wet gas mature penetrations are also found in the deeper parts of the Port Campbell Embayment, and in the Windermere, Tantanoola and St Clair Troughs. Dry gas indications are seen only in the South Australian Penola Trough, and in Windermere 2 (Windermere Trough) and Ross Creek 1 (Port Campbell Embayment) where the few wells to have exceeded 3500 m in depth are located.

The areas where mature source rocks and TOC ≥2 wt% + 1 stdev coincide are much more spatially restricted and are limited to the greater Penola trough and Hatherleigh/Rivoli area. Isolated indications of elevated TOC and with sufficient maturity to produce hydrocarbons are seen in Pretty Hill 1

Name Distribution P90 P50 Mean P10

Port Campbell shale GIP (TCF)

3.06 4.89 5.07 7.29

Port Campbell shale OIP (B bbl)

0.23 0.79 0.89 1.69

Windermere Trough shale GIP (TCF)

2.98 4.18 4.26 5.62

Windermere Trough shale OIP (B bbl)

1.84 2.60 2.65 3.51

Tantanoola Eumeralla shale OIP (B bbl)

7.73 11.19 11.43 15.39

Tantanoola Eumeralla shale Associated Gas (TCF)

10.62 15.65 16.08 22.15

Hatherleigh Trough shale GIP (TCF)

0.65 1.53 1.66 2.84

Hatherleigh Trough shale OIP (B bbl)

0.22 0.80 0.89 1.67


(Windermere Trough), Lindon 1 (extension of the Tantanoola Trough) and possibly Ross Creek 1 in the Port Campbell Embayment area.

Three prospective areas were identified in the Crayfish Sub-group: two in the greater Penola Trough and one in the Hatherleigh/Rivoli area. As the two Penola Trough areas are spatially quite close, and geologically similar, the two areas have been assessed together. The prospective area polygons are shown in Figure 6-2.

Figure 6-2 Prospective areas for the Crayfish Sub-group shale assessment in the Otway Basin, and wells with Crayfish Sub-group at >1000 m.

@Risk inputs

A summary of @Risk inputs used to calculate the Crayfish Sub-group gas assessment are listed in Appendix Table A-2.


Results

Table 6-2 Estimated shale gas-in-place (GIP) and liquids-in-place (OIP) at P10, P50, mean and P90 levels, for the Crayfish Sub-group in the greater Penola Trough and Windermere Trough areas, Otway Basin.


Penola Trough shale GIP (TCF)

2.76 7.24 7.95 14.12

Penola Trough shale OIP (B bbl)

1.35 4.69 5.24 9.94


0.53 0.76 0.78 1.04

Windermere Trough shale Associated Gas (TCF)

0.67 0.98 1.00 1.37

6.1.3 Casterton Formation

Shales within the Casterton Formation as penetrated have been identified as mature for oil in the greater Penola Trough and in the Windermere area. Mature wet and dry gas penetrations are found only in the South Australian Penola Trough in Bungaloo 1 and Jolly 1. This result is strongly limited by the spatial distribution of deep wells (>3500 m in depth). The areas where mature source rocks and TOC ≥2 wt% + 1 stdev coincide are found in all these areas. Isolated indications of elevated TOC are also seen in Bus Swamp 1, Digby 1 and Woolsthorpe 1 but are immature.

Three prospective areas were identified in the Casterton Formation: two in the greater Penola Trough and one to the north of the Windermere Trough. As the two Penola Trough areas are spatially quite close, and geologically similar, the two areas have been assessed together (Table 6-3). The prospective area polygons are shown below in Figure 6-3.


Figure 6-3 Prospective areas for the Casterton Formation shale resource assessment in the Otway Basin, and wells with Casterton Formation at >1000 m.

@Risk inputs

A summary of all @Risk inputs used to calculate the Casterton Formation shale resource assessment are listed in Appendix Table A-3.

Results

Table 6-3 Estimated shale gas-in-place (GIP) and liquids-in-place (OIP) at P10, P50, mean and P90 levels, for the Casterton Formation in the greater Penola Trough and Windermere Trough areas, Otway Basin.


Penola Trough shale GIP (TCF)

0.69 0.91 0.94 1.24

Penola Trough shale OIP (B bbl)

0.04 0.09 0.11 0.20


0.00 0.01 0.01 0.01

Windermere Trough shale Associated Gas (TCF)

0.00 0.01 0.01 0.02


6.2 Summary shale resource assessment results Table 6-4 and Table 6-5 summarise the shale GIP and OIP, and recoverable shale GIP and OIP results at the formation level for the three shale resource assessments completed in this study.

Table 6-4 Estimated shale gas-in-place (GIP) and liquids-in-place (OIP) by ‘formation’ at the P10, P50, mean and P90 levels for the Eumeralla Formation, Crayfish Sub-group and Casterton Formation in the Otway Basin.


Eumeralla Formation shale GIP (TCF)

20.97 26.66 27.04 33.56

Eumeralla Formation shale OIP (B bbl)

12.01 15.64 15.84 19.90

Crayfish Sub-group shale GIP (TCF)

3.76 8.26 8.99 15.30

Crayfish Sub-group shale OIP (B bbl)

2.07 5.49 6.04 10.76

Casterton Formation shale GIP (TCF)

0.70 0.91 0.95 1.26

Casterton Formation shale GIP (B bbl)

0.05 0.10 0.12 0.20


Table 6-5 Estimated potentially recoverable (5%) shale gas-in-place (GIP) and liquids-in-place (OIP) by ‘formation’ at the P10, P50, mean and P90 levels for the Eumeralla Formation, Crayfish Sub-group and Casterton Formation in the Otway Basin.

6.3 Tight resource assessment


The area of the Eumeralla Formation interpreted to be potentially prospective for tight resources is shown below in Figure 6-4. The relatively sparse data coverage in the eastern Otway Basin can also be seen at the right of the figure.


Eumeralla Formation potentially recoverable shale GIP (TCF)

1.05 1.33 1.35 1.68

Eumeralla Formation potentially recoverable shale OIP (B bbl)

0.60 0.78 0.79 0.99

Crayfish Sub-group potentially recoverable shale GIP (TCF)

0.19 0.41 0.45 0.76

Crayfish Sub-group potentially recoverable shale OIP (B bbl)

0.10 0.27 0.30 0.54

Casterton Formation potentially recoverable shale GIP (TCF)

0.03 0.05 0.05 0.06

Casterton Formation potentially recoverable shale GIP (B bbl)

0.00 0.00 0.01 0.01


Figure 6-4 Prospective area of the Eumeralla Formation tight resource assessment, and wells with Eumeralla Formation at >1000 m.

@Risk inputs

A summary of all @Risk inputs used to calculate the Eumeralla Formation tight resource assessment are given in Appendix Table A-4.

Results

Table 6-6 Estimated tight gas-in-place (GIP) at the P10, P50, mean and P90 levels of the Eumeralla Formation, Otway Basin.


Eumeralla Formation tight GIP (TCF)

12.13 102.26 167.29 404.20


The areas of the Crayfish Sub-group within the oil, wet gas or dry gas window which are interepreted to be potentially prospective for tight resources are shown in Figure 6-5.


Figure 6-5 Prospective areas of the Crayfish Sub-group tight resource assessment, and wells with Crayfish Sub-group at >1000 m.

@Risk inputs

A summary of all @Risk inputs used to calculate the Crayfish Sub-group tight resource assessment are given in Appendix Table A-5.

Results

Table 6-7 Estimated tight gas-in-place (GIP) and liquids-in-place (OIP) at P10, P50, mean and P90 levels for the Crayfish Sub-group, Otway Basin.


Crayfish Sub-group tight GIP (TCF)

0.47 0.67 0.71 0.99

Crayfish Sub-group tight OIP (B bbl)

0.30 0.44 0.47 0.67

6.4 Summary tight resource assessment results Table 6-8 and Table 6-9 summarise the tight GIP and OIP, and the recoverable GIP and OIP results at the formation level for the two tight resource assessments completed in this study.


Table 6-8 Estimated tight gas-in-place (GIP) and liquids-in-place (OIP) by ‘formation’ at the P10, P50, mean and P90 levels for the Eumeralla Formation and Crayfish Sub-group in the Otway Basin.


Eumeralla Formation tight GIP (TCF)

12.13 102.26 167.29 404.20

Crayfish Sub-group tight GIP (TCF)

0.47 0.67 0.71 0.99

Crayfish Sub-group tight OIP (B bbl)

0.30 0.44 0.47 0.67

Table 6-9 Estimated potentially recoverable (5%) tight gas-in-place (GIP) and liquids-in-place (OIP) by ‘formation’ at the P10, P50, mean and P90 levels for the Eumeralla Formation and Crayfish Sub-group in the Otway Basin.


Eumeralla Formation potentially recoverable tight GIP (TCF)

0.63 4.99 8.36 20.70

Crayfish Sub-group potentially recoverable tight GIP (TCF)

0.02 0.03 0.04 0.05

Crayfish Sub-group potentially recoverable tight OIP (B bbl)

0.01 0.02 0.02 0.03


7 Assessment limitations

The following section outlines some of the key limitations and assumptions associated with the shale and tight resource assessments.

7.1 Shale resource assessment • This assessment is not a generative assessment. The GIP and OIP estimates do not capture the

degree to which the assessed formations are able to produce and expel hydrocarbons, rather it calculates the modern-day concentration of gas and liquids in the rock. A generative assessment allows a better understanding of the petroleum systems in the basin ability to generate hydrocarbons and can be used to evaluate areas with sparse measured gas and oil saturation and reservoir data and would be a complementary to the current assessments results.

• This study has been completed using only publically available data in order to improve the transparency of the results. As the unconventional, and in particular shale gas, industries are immature in the Otway Basin this has further limited the already sparse data availability to characterise the shales as many wells drilled for the purpose are still within the confidentiality period.

• In this study, in the absence of a basin-wide 3D model, the thickness of the assessed formations was defined using well data only. This means only the formations ‘as penetrated’ have been assessed, and as a result, represent a very conservative estimate of the formation thickness and hence volume and likely GIP and OIP. This is particularly true for the Casterton Formation, which has only been penetrated in a total of 18 wells, and only in the greater Penola Trough and Windermere Trough area. The Casterton Formation has not been intersected at all in other key Cretaceous depocentres where it is likely to be present. This approach also omits local scale structural details only able to be revealed through the incorporation of detailed seismic data, fault mapping and more densely spaced well data. As more wells are drilled through the assessed formations the thickness distribution can be incrementally improved. If, eventually an assessment utilising seismic data can be achieved, or if a basin wide 3D model becomes available the assessment can be revised to reflect the full formation volume.

• During the course of this study it became apparent that differentiating between the bottom of the Casterton Formation and the underlying metasedimentary basement is challenging and has likely impact on the volume of the Casterton Formation modelled. This difficulty in accurately identifying the bottom of the Casterton Formation can also be seen at a more regional scale in the highly variable nature of the geophysically and seismically-derived ‘Top Basement’ surfaces assessed for this study. Unfortunately, this regional scale challenge means it will likely take many more wells and seismic/geophysics surveys before a reliable base Casterton Formation / top Basement surface can be generated.

• All petrophysical lithological and geochemical parameters are also defined using ‘as penetrated’ values. While every attempt was made to ensure the full stratigraphic succession of the assessed formations were represented, the data distributions used in @Risk can only represent the current state of data.

• The definition of ‘shale’ in this assessment as ‘70% fine grained lithology’ will likely overestimate the proportion of ‘true’ shale in each formation. Ideally a carefully calibrated log derived electro-facies lithology assignation process would be undertaken, a process which is hindered


significantly by the highly variable quality of the available log data in the basin. The feasibility of this approach was considered but the required investment of time to get an acceptable outcome was found to be beyond the scope of this study.

• The TOC values used in this assessment are modern day values not back-calculated original TOC values. This means that the TOC average + 1 stdev values calculated for each well are likely to be somewhat conservative in terms of generative potential (assuming any). However, the generosity of prospective area polygons to include sparse data points likely more than compensates volumetrically for this.

• Estimating the volume of high TOC shales is complicated by coals in the sequence, particularly in the Eumeralla Formation. While true coals have been removed by imposing the 50 wt% TOC maximum, how many of the ‘shales’ with TOC values between 20–50 wt% are in fact claystones with coaly components was not quantified.

• There was no adjustment of the ‘TOC averages by well’ data to exclude values outside the assessed 1000–5000 m depth range as this would have reduced an already sparse dataset even further. This raises the possibility that the average TOC values used are not a fair representation of organic richness in the assessed volume. Of the 2079 compiled analyses directly used in the three shale assessments, only 200 are at depths <1000 m and 170 of those are from the Eumeralla Formation. Many of the shallow analyses are in areas which are also immature and hence omitted the assessment on those grounds. This suggests that the impact of including these analyses in the TOC averages in the assessment process is likely to be quite small.

• As defined, the prospective areas are highly dependent on the distribution of available TOC data. As only a small proportion of organically rich shales are likely to have been sampled, this is likely to underestimate the area of the basin that contains prospective shales. The addition of more TOC data or the incorporation of additional predictive facies mapping techniques would allow a more ‘whole of basin’ resource assessment to be completed.

• As the TOC values in each formation in each well are often highly variable, using an ‘average TOC’ per well method excludes wells which do have some high TOC shales, but which fall below the 2 wt% +1 stdev threshold during the averaging process due to the presence of some very low TOC shales. This is an issue for all of the shale gas assessments, but is particularly marked in the Eumeralla Formation.

• Where there are only a few TOC analyses for a formation in each well this is also likely to be statistically non-representative of the formation in that location. This limitation is particularly marked in the Crayfish Sub-group in the Windermere Trough area. If more TOC data was acquired in the future, this could significantly alter the prospective areas.

• All the shales within the prospective areas are assumed to be of >2% + 1 stdev TOC. This is an unrealistic expectation. If sufficient high-resolution log data and/or TOC measurements were available the proportion of lithologically defined shales could be constrained further to define a ‘net organically rich ratio’, giving a more geologically realistic indication of the volume of organically rich shale present and further improving the reliability of the resource assessment.

• The scarcity of maturity data has necessitated the calculation of regional trends in maturity with depth. While in general this approach seems reasonable in the Otway Basin given the fairly uniform trend in maturity with depth across the assessed area, this approach could still obscure significant local variation. In areas of highly localised structuring, secondary mineralisation or intrusive emplacement these regional maturity with depth estimations will not be sufficient to model the localised variation in thermal maturity. The regional maturity estimations are also reliant on existing data. In areas of relatively lower data density the regional estimations are likely to be less representative of the regional thermal maturity, even in the absence of any localised effects.


• TOC values are found in the all of the assessed formations beyond the currently mapped extent of the prospective area polygons, but have been excluded on the grounds of maturity as currently drilled. This is particularly evident in the central Otway Basin, for example the Port Campbell Embayment and Windermere Trough areas. There are also very sparsely drilled areas where little data is available to model local maturity conditions. If deep intersections of the assessed formations are found in areas currently modelled as immature, or, if localised variations in maturity with depth are defined, shale plays in other areas could become prospective (by the definition of this study) at a later date.

• The @Risk distributions for shale petrophysical properties were constructed based on a small number of analyses from just a few key wells. Key assumptions and limitations associated with the petrophysical data are listed in Table 5-1. Basing the @Risk distributions on such a small number of analyses means there is a risk that that they do not represent the full spatial distribution (laterally and vertically) of the formations assessed. The reliability of this assessment could be significantly improved by increasing the number and spatial spread of petrophysical analyses available to characterise the shale resource plays.

• The near complete absence of publically available gas contained, gas and oil formation volume factors, and condensate-to-gas and gas-to-oil ratios (GCa, Bg and Bo, CGR and GOR) specific to each assessed formation, could be a significant source of error in this resource assessment. Published values for these parameters or sufficient data to enable the calculation of these parameters (e.g. composition analyses, well test data, isotherm tests, pressure and temperature data etc.) would significantly improve the reliability of this assessment.

7.2 Tight resource assessment • A key assumption in the tight resource assessment is that the entirety of the Eumeralla Formation

and Crayfish Sub-group are considered potential tight resource plays. We know this is not the case, as in some intervals there are sandstones with conventional reservoir potential. The use of the net-to-gross ratio attempts to characterise the proportion of effective tight reservoir in a vertical sense, but as there is only one well log interpretation for the Eumeralla Formation (Killarney 1 EPRL) and one for the Crayfish Sub-group (Glenaire 1 ST1) there is no ability to spatially characterise the reservoir effectiveness. Thus there is a very high level of uncertainty associated with the net-to-gross distribution in @Risk, which in turn increases the uncertainty of the tight GIP and OIP assessment. This means that the current assessment is likely to over-represent the tight resource potential of the basin, by under representing the conventional reservoir potential. This is particularly likely to affect the Crayfish Sub-group, where intervals with higher porosity and permeability tend to be more common than in the typically tight Eumeralla Formation (Goldie Divko, 2015). Detailed work which is beyond the scope of this assessment is needed to spatially map, using modern data and well interpretations, the parts of the Eumeralla Formation and Crayfish Sub-group with the effective porosity required for tight resource plays.

• As assessed in this study, we have assumed that tight resource reservoired in the Eumeralla Formation is all dry gas, and is not necessarily generated in situ based on the little known information. In the Crayfish Sub-group tight resource assessment the tight resource is assumed to be generated in situ and hence potential has been mapped using TOC and maturity data (see Section 5.1 and 5.2 for further detail). These approaches are unlikely to be correct across the whole basin, for example – we know there has been minor condensate encountered in the Eumeralla Formation in the Windermere Trough. Further petroleum systems work is required to spatially discriminate between tight oil, wet and dry gas reservoirs in the Otway Basin.


• The limited amount of measured petrophysical data is a key source of uncertainty in the calculated tight GIP and OIP values. Key assumptions and limitations associated with the petrophysical data are covered in Table 5-7. No directly measured gas saturation data exist for the Eumeralla Formation. One water saturation measurement from Port Fairy 1 and one from Glenaire 1 ST1 was used to underpin the gas saturation distribution (as gas saturation = 1 - water saturation) for the Eumeralla Formation and Crayfish Sub-group respectively. While these give a good approximation at the local scale there is likely to be significant lateral variation in gas saturation, which increases the uncertainty of the GIP assessment. Anecdotal evidence suggests the Eumeralla Formation has much higher gas saturations in some areas than those observed in Port Fairy 1 (Lakes Oil, 2012; 2016), thus the concentration of gas in the Eumeralla Formation tight resource play in particular may have been underestimated. Further measured data or well log interpretations are needed to confirm this anecdotal evidence, and provide a more comprehensive set of data to base the @Risk gas saturation distribution on in order reduce the uncertainty associated with this variable.

• In the absence of a good onshore analogue for the gas and oil formation volume factors (Bg and Bo) in the Eumeralla Formation and Crayfish Sub-group, values from the basal Waarre Formation were used in the absence of any other data. While these Waarre Formation Bg and Bo values may be a geologically plausible analogue for the Eumeralla Formation which shares a common petroleum sub-system with the Waarre Formation (Austral 2), the Crayfish Sub-group is part of the older Austral 1 petroleum sub-system. Not using formation specific Bg and Bo values introduces a higher level of uncertainty into the GIP calculations.

• The condensate-to-gas ratio (CGR) and gas-to-oil ratio (GOR) used for the Eumeralla Formation and Crayfish Sub-group tight resource assessment are also based on local analogues in the absence of any measured values. CGR analyses from the Waarre Formation have been used to characterise the Eumeralla Formation gases, and CGR and GOR analyses from the Pretty Hill Formation in the Penola Trough have been used to characterise the Crayfish Sub-group gases and liquids. While the use of the Waarre Formation CGR values may be a geologically plausible analogue for the Eumeralla Formation which shares a common petroleum sub-system with the Waarre Formation (Austral 2) it is still far from ideal. The use of Pretty Hill Formation CGR and GOR’s likely provides a good local indication of the CGR in the Penola Trough, but how well this represents gases in the Crayfish Sub-group more broadly is highly uncertain. Together these uncertainties around CGR and GOR introduce a higher level of uncertainty into the GIP calculations.


8 Conclusion

In the Otway Basin, potentially prospective shale resource plays include the Eumeralla Formation, Crayfish Sub-group and Casterton Formation. The Eumeralla Formation hosts organically-rich shales in the Port Campbell Embayment, Windermere Trough, Tantanoola Trough and the Hatherleigh/Rivoli area which are prospective for gas and liquids. The Crayfish Sub-group is prospective for shale gas and liquids in the greater Penola Trough and Hatherleigh/Rivoli area. The Casterton Formation hosts organically-rich shales prospective for gas and liquids in the greater Penola Trough and the Windermere Trough areas. The Crayfish Sub-group and Eumeralla Formation are also potentially prospective for tight resources across large parts of the basin.

This assessment suggests that the onshore Otway Basin may contain large volumes of liquids- and gas-in-place. These volumes are to be regarded as undiscovered potentially prospective resources. There is significant uncertainty around their location and estimated magnitude. Recognising the uncertainty associated with estimated in-place resources and their path to commercialisation, a 5% recovery factor was applied. The total P50 gas- and liquids-in-place for the combined Otway Basin resource assessment is estimated at 151.6 TCF and 30.0 B bbl, of which 7.6 TCF and 1.5 B bbl may potentially be recoverable. The P10, P50, mean, and P90 GIP and OIP results and the recoverable GIP and OIP results are summarised in the table below.

Estimated total and potentially recoverable (estimated as 5%) shale and tight gas-in-place (GIP) and liquids-in-place (OIP) at the P10, P50, mean and P90 levels in the Otway Basin. NB: probabilistic summation has been used.

P90 P50 P10 Mean

Otway Basin Total Tight GIP (TCF) 26.2 116.4 416.9 181.4

Otway Basin Total Tight OIP (B bbl) 5.9 8.86 9.3 13.3

Otway Basin Total Shale GIP (TCF) 27.1 34.8 44.3 35.3

Otway Basin Total Shale OIP (B bbl) 15.5 20.7 27.4 21.1

Otway Basin GIP (TCF) 61.5 151.6 452.5 216.7

Otway Basin OIP (B bbl) 23.7 30.0 37.8 30.4

Total Otway Basin potentially recoverable GIP (@5% P50; TCF)

7.6

Total Otway Basin potentially recoverable GIP (@5% P50; B bbl)

1.5

In the Otway Basin conventional gas has been produced from both the onshore and offshore, but only limited exploration for unconventional resources has occurred. This has resulted in limited data availability for this assessment and necessitated the use of geologically reasonable assumptions and analogues to characterise the geochemical and petrophysical properties of shale and tight reservoirs. Higher levels of uncertainty will therefore be inherent in the GIP and OIP calculations. Of particular note is the use of well data to define the prospective rock volumes. This has likely produced a very conservative estimate of the gas- and liquids-in-place as only the geology penetrated by existing drilling has been able to be evaluated. Further work using a basin-wide 3D model would enable the


assessment of the full geological volume and potentially alter the resource assessment result significantly.

Additional publically available data would be required to improve the certainty around these preliminary estimates and enable a more detailed unconventional resource assessment to be carried out. Commercialising Victorian unconventional resources would require identifying the highest-grade occurrences, then developing an understanding of the interplay between stress regime and drilling and hydraulic stimulation practises for the extraction of oil and gas. Liquids and gas from these unconventional resources are likely to remain relatively expensive as compared to conventional resources until high economies of scale can be achieved.


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Appendix A @Risk input tables

A.1 Shale resource assessment

A.1.1 Eumeralla Formation

A summary of all @Risk inputs used to calculate the Eumeralla Formation shale resource assessment are listed in Appendix Table A-1.

Appendix Table A-1 Eumeralla Formation shale play @Risk input parameters.

Name Distribution Function Min 10% Median Mean 90% Max

All areas

Total porosity Crayfish Shale (fraction)

RiskLaplace(0.057,0.012204,RiskTruncate(0.02,0.09),RiskName("Total porosity Crayfish Shale"))

0.020 0.044 0.057 0.057 0.070 0.090

Water saturation Crayfish Shale (fraction)

RiskExtvalueMin(0.83343,0.1516,RiskTruncate(0.5,1),RiskName("Water saturation Crayfish Shale"))

0.500 0.597 0.790 0.779 0.939 1.000

Gas formation volume factor (rm3/sm3)

RiskNormal(0.00712,0.0007,RiskTruncate(0.006,0.008),RiskName("Gas formation volume factor"))

0.006 0.006 0.007 0.007 0.008 0.008

Bulk density Crayfish (g/cc)

RiskTriang(2.48516,2.646,2.646,RiskName("Bulk density Crayfish"))

2.49 2.54 2.60 2.59 2.64 2.65



Adsorbed gas content Pretty Hill (scf/ton)

RiskNormal(17.42,17.42/10,RiskName("Adsorbed gas content Pretty Hill"))

10.80 15.19 17.42 17.42 19.65 24.03

Condensate-to-gas ratio Waarre (bbl/mmscf)

RiskNormal(4.01,4.01/10,RiskName("Condensate-to-gas ratio Waarre"))

2.46 3.50 4.01 4.01 4.52 5.55

Oil formation volume factor (RB/STB)

RiskNormal(1.8662,1.8662/10, RiskName("Oil formation volume factor"))

1.030 1.627 1.866 1.866 2.105 2.563

Gas oil ratio Waarre (scf/bbl)

RiskNormal(1406,1406/10,RiskName("Gas oil ratio Waarre"))

865.62 1225.80 1405.97 1406.00 1586.19 1930.62

Port Campbell

Thickness Port Campbell Eumeralla Dry Gas (m)

RiskNormal(159.72,159.72/10,RiskTruncate(0,824),RiskName("Thickness Port Campbell Eumeralla Dry Gas"))

97.7 139.2 159.7 159.7 180.2 221.2

Thickness Port Campbell Eumeralla Wet Gas (m)

RiskNormal(132.43,132.43/10,RiskTruncate(0,824),RiskName("Thickness Port Campbell Eumeralla Wet Gas"))

81.8 115.5 132.4 132.4 149.4 181.8

Thickness Port Campbell Eumeralla Oil (m)

RiskNormal(132.43,132.43/10,RiskTruncate(0,824), RiskName("Thickness Port Campbell Eumeralla Oil"))

82.3 115.5 132.4 132.4 149.4 182.7

Area Port Campbell Eumeralla Dry Gas (m2)

RiskNormal(239259720,239259720/20,RiskName("Area PortCampbell Eumeralla Dry Gas"))

1.92E+08 2.24E+08 2.39E+08 2.39E+08 2.55E+08 2.85E+08



Area Port Campbell Eumeralla Wet Gas (m2)

RiskNormal(396117450,396117450/20,RiskName("Area PortCampbell Eumeralla Wet Gas"))

3.21E+08 3.71E+08 3.96E+08 3.96E+08 4.21E+08 4.79E+08

Area Port Campbell Eumeralla Oil (m2)

RiskNormal(395948187,395948187/20,RiskName("Area PortCampbell Eumeralla Oil"))

3.20E+08 3.71E+08 3.96E+08 3.96E+08 4.21E+08 4.71E+08

Net Shale Ratio Port Campbell Eumeralla (fraction)

RiskNormal(0.39, 0.39/10,RiskTruncate(0.18,0.61),RiskName("Net Shale Ratio Port Campbell Eumeralla"))

0.223 0.340 0.390 0.390 0.440 0.539

Windermere

Thickness Windermere Eumeralla Wet Gas (m)

RiskNormal(106.67,106.67/10,RiskTruncate(0,723),RiskName("Thickness Windermere Eumeralla Wet Gas"))

62.6 93.0 106.7 106.7 120.3 152.3

Thickness Windermere Eumeralla Oil (m)

RiskNormal(313,313/10,RiskTruncate(0,320),RiskName("Thickness Windermere Eumeralla Oil"))

181.9 264.0 296.1 292.3 315.3 320.0

Area Windermere Eumeralla Wet Gas (m2)

RiskNormal(119871924,119871924/20,RiskName("Area Windermere Eumeralla Wet Gas"))

9.71E+07 1.12E+08 1.20E+08 1.20E+08 1.28E+08 1.48E+08

Area Windermere Eumeralla Oil (m2)

RiskNormal(119936282,119936282/20,RiskName("Area Windermere Eumeralla Oil"))

9.68E+07 1.12E+08 1.20E+08 1.20E+08 1.28E+08 1.46E+08

Net Shale Ratio Windermere Eumeralla (fraction)

RiskNormal(0.39, 0.39/10,RiskTruncate(0,0.73),RiskName("Net Shale Ratio Windermere Eumeralla"))

0.243 0.340 0.390 0.390 0.440 0.537



Tantanoola

Thickness Tantanoola Eumeralla Oil (m)

RiskNormal(350.5,350.5/10,RiskTruncate(0,701),RiskName("ThicknessTantanoolaEumerallaOil"))

188.95 305.57 350.49 350.50 395.40 489.82

Area Tantanoola Eumeralla Oil (m2)

RiskNormal(306116745,306116745/20,RiskName("Area Tantanoola Eumeralla Oil"))

2.48E+08 2.87E+08 3.06E+08 3.06E+08 3.26E+08 3.66E+08

Net Shale Ratio Tantanoola Eumeralla (fraction)

RiskNormal(0.55, 0.55/10,RiskTruncate(0,1),RiskName("Net Shale Ratio Tantanoola Eumeralla"))

0.339 0.479 0.550 0.550 0.620 0.776

Hatherleigh/Rivoli

Thickness Hatherleigh Eumeralla Dry Gas (m)

RiskNormal(246,246/10,RiskName("Thickness Hatherleigh Eumeralla Dry Gas"))

150.9 214.5 246.0 246.0 277.5 339.5

Thickness Hatherleigh Eumeralla Wet Gas (m)

RiskNormal(531,531/10,RiskName("Thickness Hatherleigh Eumeralla Wet Gas"))

323.5 462.9 531.0 531.0 599.0 742.7

Thickness Hatherleigh Eumeralla Oil (m)

RiskNormal(508,508/10,RiskTruncate(293,723),RiskName("Thickness Hatherleigh Eumeralla Oil"))

308.1 442.9 508.0 508.0 573.1 716.7

Area Hatherleigh Eumeralla Dry Gas (m2)

RiskNormal(6152091,6152091/20,RiskName("Area Hatherleigh Eumeralla Dry Gas"))

5.00E+06 5.76E+06 6.15E+06 6.15E+06 6.55E+06 7.33E+06

Area Hatherleigh Eumeralla Wet Gas (m2)

RiskNormal(6152091,6152091/20,RiskName("Area Hatherleigh Eumeralla Wet Gas"))

4.98E+06 5.76E+06 6.15E+06 6.15E+06 6.55E+06 7.39E+06



Area Hatherleigh Eumeralla Oil (m2)

RiskNormal(52180203,52180203/20,RiskName("Area Hatherleigh Eumeralla Oil"))

4.10E+07 4.88E+07 5.22E+07 5.22E+07 5.55E+07 6.20E+07

Net Shale Ratio Hatherleigh Eumeralla (fraction)

RiskNormal(0.79, 0.79/10,RiskTruncate(0.58,0.92),RiskName("Net Shale Ratio Hatherleigh Eumeralla"))

0.581 0.688 0.785 0.782 0.874 0.920

A.1.2 Crayfish Sub-group

A summary of @Risk inputs used to calculate the Crayfish Sub-group gas assessment are listed in Appendix Table A-2.

Appendix Table A-2 Crayfish Sub-group shale play @Risk input parameters.


All areas

Total porosity Crayfish Shale (fraction)

RiskLaplace(0.057,0.012204,RiskTruncate(0.02,0.09),RiskName("Total porosity Crayfish Shale"))

0.020 0.044 0.057 0.057 0.070 0.090

Water saturation Crayfish Shale (fraction)

RiskExtvalueMin(0.83343,0.1516,RiskTruncate(0.5,1),RiskName("Water saturation Crayfish Shale"))

0.500 0.597 0.790 0.779 0.939 1.000



1.087 1.627 1.866 1.866 2.105 2.563

Gas oil ratio Pretty Hill (scf/bbl)

RiskNormal(1288,1288/10,RiskName("Gas oil ratio Pretty Hill"))

762.81 1122.87 1288.00 1288.00 1453.05 1767.72



Greater Penola

Thickness Penola Crayfish Dry Gas (m)

RiskNormal(43.5,43.5/10,RiskTruncate(0,522),RiskName("Thickness Penola Crayfish Dry Gas"))

27.2 37.9 43.5 43.5 49.1 61.5

Thickness Penola Crayfish Wet Gas (m)

RiskNormal(241.72,241.72/10,RiskTruncate(0,531),RiskName("Thickness Penola Crayfish Wet Gas"))

149.5 210.7 241.7 241.7 272.7 342.6

Thickness Penola Crayfish Oil (m)

RiskNormal(547.85,547.85/10,RiskTruncate(0,723),RiskName("Thickness Penola Crayfish Oil"))

331.6 477.6 547.8 547.7 617.8 721.6

Area Penola Crayfish Dry Gas (m2)

RiskNormal(68022119,68022119/20,RiskName("Area Penola Crayfish Dry Gas"))

5.31E+07 6.37E+07 6.80E+07 6.80E+07 7.24E+07 8.07E+07

Area Penola Crayfish Wet Gas (m2)

RiskNormal(68037897,68037897/20,RiskName("Area Penola Crayfish Wet Gas"))

5.40E+07 6.37E+07 6.80E+07 6.80E+07 7.24E+07 8.10E+07

Area Penola Crayfish Oil (m2)

RiskNormal(383707375,383707375/20,RiskName("Area Penola Crayfish Oil"))

3.08E+08 3.59E+08 3.84E+08 3.84E+08 4.08E+08 4.57E+08

Net Shale Ratio Penola Trough Crayfish (fraction)

RiskNormal(0.58,0.58/10,RiskTruncate(0,1),RiskName("Net Shale Ratio Penola Trough Crayfish"))

0.362 0.506 0.580 0.580 0.654 0.824



0.006 0.006 0.007 0.007 0.008 0.008



Bulk density Crayfish (g/cc)

RiskTriang(2.48516,2.646,2.646,RiskName("Bulk density Crayfish"))

2.49 2.54 2.60 2.59 2.64 2.65

Adsorbed gas content Pretty Hill (scf/ton)

RiskNormal(17.42,17.42/10,RiskName("Adsorbed gas content Pretty Hill"))

10.85 15.19 17.42 17.42 19.65 24.05

Condensate-to-gas ratio Pretty Hill (bbl/mmscf)

RiskNormal(8.2, 8.2/10,RiskName("Condensate-to-gas ratio Pretty Hill"))

4.87 7.15 8.20 8.20 9.25 11.31

Hatherleigh/Rivoli

Thickness Hatherleigh Crayfish Oil (m)

RiskNormal(106.5,106.5/10,RiskTruncate(53,160),RiskName("Thickness Hatherleigh Crayfish Oil"))

64.98 92.85 106.50 106.50 120.15 147.83

Area Hatherleigh Crayfish Oil (m2)

RiskNormal(62913205,62913205/20,RiskName("Area Hatherleigh Crayfish Oil"))

5.12E+07 5.89E+07 6.29E+07 6.29E+07 6.69E+07 7.49E+07

Net Shale Ratio Hatherleigh Crayfish (fraction)

RiskNormal(0.6, 0.6/10,RiskTruncate(0,1),RiskName("Net Shale Ratio Hatherleigh Crayfish"))

0.352 0.523 0.600 0.600 0.677 0.867

A.1.3 Casterton Formation

A summary of all @Risk inputs used to calculate the Casterton Formation shale resource assessment are listed in Appendix Table A-3.


Appendix Table A-3 Casterton Formation shale play @Risk input parameters.


All areas

Total porosity Casterton Shale (fraction)

RiskPareto(2.3448,0.022,RiskTruncate(0.02,0.1),RiskName("Total porosity Casterton Shale"))

0.022 0.023 0.029 0.034 0.053 0.100

Water saturation Casterton Shale (fraction)

RiskExtvalueMin(0.8767,0.063647,RiskTruncate(0.6,1),RiskName("Water saturation Casterton Shale"))

0.600 0.741 0.854 0.844 0.930 1.000



1.157 1.627 1.866 1.866 2.105 2.629



785.29 1122.93 1287.97 1288.01 1453.04 1884.66

Greater Penola

Thickness Penola Casterton Dry Gas (m)

RiskNormal(189.5,189.5/10,RiskTruncate(172,207),RiskName("Thickness Penola Casterton Dry Gas"))

172.0 176.3 189.5 189.5 202.7 207.0

Thickness Penola Casterton Wet Gas (m)

RiskNormal(67,67/10, RiskTruncate(0,201),RiskName("Thickness Penola Casterton Wet Gas"))

42.1 58.4 67.0 67.0 75.6 93.6

Thickness Penola Casterton Oil (m)

RiskNormal(69.54,69.54/10,RiskTruncate(0,201),RiskName("Thickness Penola Casterton Oil"))

43.6 60.6 69.5 69.5 78.4 95.8

Area Penola Casterton Dry Gas (m2)

RiskNormal(55240247,55240247/20,RiskName("Area Penola Casterton Dry Gas"))

4.48E+07 5.17E+07 5.52E+07 5.52E+07 5.88E+07 6.56E+07



Area Penola Casterton Wet Gas (m2)

RiskNormal(48308561,48308561/20,RiskName("Area Penola Casterton Wet Gas"))

3.92E+07 4.52E+07 4.83E+07 4.83E+07 5.14E+07 5.74E+07

Area Penola Casterton Oil (m2)

RiskNormal(114049888,114049888/20,RiskName("Area Penola Casterton Oil"))

9.15E+07 1.07E+08 1.14E+08 1.14E+08 1.21E+08 1.35E+08

Net Shale Ratio Penola Casterton (fraction)

RiskNormal(0.74,0.74/10,RiskTruncate(0.2,1),RiskName("Net Shale Ratio Penola Casterton"))

0.461 0.645 0.740 0.740 0.835 0.994



0.006 0.006 0.007 0.007 0.008 0.008

Bulk Density Casterton (g/cc)

RiskTriang(2.56058,2.737,2.737,RiskName("Bulk Density Casterton"))

2.56 2.62 2.69 2.68 2.73 2.74

Adsorbed gas content Casterton (scf/ton)

RiskNormal(19.58, 19.58/10,RiskName("Adsorbed gas content Casterton"))

11.79 17.07 19.58 19.58 22.09 27.18



5.14 7.15 8.20 8.20 9.25 11.26

Windermere

Thickness Windermere Casterton Oil (m)

RiskNormal(62.1,62.1/10, RiskTruncate(34.2,105),RiskName("Thickness Windermere Casterton Oil"))

38.0 54.1 62.1 62.1 70.1 88.8

Area Windermere Casterton Oil (m2)

RiskNormal(41400304,41400304/20,RiskName("Area Windermere Casterton Oil"))

3.31E+07 3.87E+07 4.14E+07 4.14E+07 4.41E+07 4.95E+07



Net Shale Ratio Windermere Casterton (fraction)

RiskNormal(0.16,0.16/10,RiskTruncate(0,0.32),RiskName("Net Shale Ratio Windermere Casterton"))

0.099 0.139 0.160 0.160 0.180 0.221

A.2 Tight resource assessment

A.2.1 Eumeralla Formation

A summary of all @Risk inputs used to calculate the Eumeralla Formation tight resource assessment are given in Appendix Table A-4.

Appendix Table A-4 Eumeralla Formation tight resource play @Risk input parameters.


Thickness Eumeralla Tight Dry Gas (m)

RiskExpon(520.91,RiskShift(0),RiskTruncate(0,2509.2),RiskName("Thickness Eumeralla Tight Dry Gas"))

0.0 54.4 356.8 500.4 1162.6 2503.0

Area Eumeralla Tight Dry Gas (m2)

RiskNormal(17233870881,17233870881/20, RiskName("Area Eumeralla Tight Dry Gas"))

1.39E+10 1.61E+10 1.72E+10 1.72E+10 1.83E+10 2.09E+10

Net-to-gross Eumeralla tight (fraction)

RiskNormal(0.215384615384615,0.215384615384615/10,RiskName("Net-to-gross Eumeralla tight"))

0.125 0.188 0.215 0.215 0.243 0.297

Effective porosity Eumeralla tight gas reservoir (fraction)

RiskPareto(11.57,0.0816,RiskTruncate(0.02,0.15),RiskName("Effective porosity Eumeralla tight gas reservoir"))

0.082 0.082 0.087 0.089 0.099 0.149



Effective water saturation Eumeralla tight gas reservoir (fraction)

RiskNormal(0.8,0.1,RiskTruncate(0.6,1),RiskName("Effective water saturation Eumeralla tight gas reservoir"))

0.600 0.682 0.800 0.800 0.918 1.000



0.006 0.006 0.007 0.007 0.008 0.008

A.2.2 Crayfish Sub-group

A summary of all @Risk inputs used to calculate the Crayfish Sub-group tight resource assessment are given in Appendix Table A-5.

Appendix Table A-5 Crayfish Sub-group tight resource play @Risk input parameters.


All areas

Net-to-gross Crayfish tight (fraction)

RiskNormal(0.0607533414337789,0.0607533414337789/10,RiskName("Net-to-gross Crayfish tight"))

0.038 0.053 0.061 0.061 0.069 0.084

Effective porosity Crayfish tight gas reservoir (fraction)

RiskTriang(0.080292,0.080292,0.143409,RiskTruncate(0.02,0.18),RiskName("Effective porosity Crayfish tight gas reservoir"))

0.080 0.084 0.099 0.101 0.123 0.143

Effective water saturation Crayfish tight gas reservoir (fraction)

RiskTriang(0.28056,0.68448,0.70367,RiskTruncate(0.3,1),RiskName("Effective water saturation Crayfish tight gas reservoir"))

0.300 0.413 0.573 0.557 0.673 0.703



0.006 0.006 0.007 0.007 0.008 0.008





5.10 7.15 8.20 8.20 9.25 11.37



1.158 1.627 1.866 1.866 2.105 2.567



746.44 1122.93 1287.97 1288.00 1453.04 1789.08

Penola Trough

Thickness Penola Crayfish Tight Dry Gas (m)

RiskNormal(89.69,89.69/10,RiskName("Thickness Penola Crayfish Tight Dry Gas"))

55.7 78.2 89.7 89.7 101.2 125.5

Thickness Penola Crayfish Tight Wet Gas (m)

RiskNormal(176.71,176.71/10,RiskName("Thickness Penola Crayfish Tight Wet Gas"))

107.2 154.1 176.7 176.7 199.4 244.7

Thickness Penola Crayfish Tight Oil (m)

RiskNormal(592,592/10,RiskName("Thickness Penola Crayfish Tight Oil"))

369.5 516.1 592.0 592.0 667.8 821.9

Area Penola Crayfish Tight Dry Gas (m2)

RiskNormal(277334640, 277334640/20, RiskName("Area Penola Crayfish Tight Dry Gas"))

2.25E+08 2.60E+08 2.77E+08 2.77E+08 2.95E+08 3.35E+08

Area Penola Crayfish Tight Wet Gas (m2)

RiskNormal(726932454,726932454/20, RiskName("Area Penola Crayfish Tight Wet Gas"))

5.87E+08 6.80E+08 7.27E+08 7.27E+08 7.73E+08 8.69E+08



Area Penola Crayfish Tight Oil (m2)

RiskNormal(1683821472,1683821472/20, RiskName("Area Penola Crayfish Tight Oil"))

1.37E+09 1.58E+09 1.68E+09 1.68E+09 1.79E+09 2.02E+09

Hatherleigh/Rivoli

Thickness Hatherleigh Crayfish Tight Oil (m)

RiskNormal(106.5,106.5/10, RiskName("Thickness Hatherleigh Crayfish Tight Oil"))

63.86 92.85 106.50 106.50 120.14 148.70

Area Hatherleigh Crayfish Tight Oil (m2)

RiskNormal(62912841,62912841/20,RiskName("Area Hatherleigh Crayfish Tight Oil"))

5.09E+07 5.89E+07 6.29E+07 6.29E+07 6.69E+07 7.50E+07
