Revealing oil migration in the frontier Bight Basin, Australia

Journal Pre-proof Revealing oil migration in the frontier Bight Basin, Australia Richard H. Kempton, Julien Bourdet, Se Gong, Andrew S. Ross PII:

S0264-8172(19)30573-2

DOI:

https://doi.org/10.1016/j.marpetgeo.2019.104124

Reference:

JMPG 104124

To appear in:

Marine and Petroleum Geology

Received Date: 21 June 2019 Revised Date:

29 October 2019

Accepted Date: 1 November 2019

Please cite this article as: Kempton, R.H., Bourdet, J., Gong, S., Ross, A.S., Revealing oil migration in the frontier Bight Basin, Australia, Marine and Petroleum Geology (2019), doi: https://doi.org/10.1016/ j.marpetgeo.2019.104124. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2019 Published by Elsevier Ltd.

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REVEALING OIL MIGRATION IN THE FRONTIER BIGHT BASIN, AUSTRALIA

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RICHARD H. KEMPTONa*, JULIEN BOURDETa, SE GONGb AND ANDREW S. ROSSa

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a CSIRO Energy, 26 Dick Perry Ave, Kensington, WA, Australia, 6151

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b CSIRO Energy, 14 Julius Avenue, North Ryde, NSW, Australia, 2113

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*Corresponding author: Richard Kempton ([email protected]) +61 8 64368537

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ABSTRACT

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The Bight Basin along the southern margin of Australia represents one of Australia’s most prospective deep-

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water frontier hydrocarbon exploration regions, however its 15 km-thick sedimentary succession remains

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largely untested. Whilst there is some evidence of oil from shows, fluid inclusions and natural strandings of

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asphaltite along the basin margin, it is unclear if any hydrocarbons were generated in the deep-water Ceduna

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Sub-basin. Fluid inclusions offer a unique method to test for petroleum migration that would otherwise remain

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hidden and a study, using CSIRO’s Grains with Oil Inclusion (GOI™) technique, was undertaken on Gnarlyknots-

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1A along with other historic exploration wells. With the exception of Jerboa-1, in the Eyre Sub-basin, the GOI

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results (<0.1% up to 1.1%) both reaffirm evidence for hydrocarbon migration along the shallow-water shelf

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edges and, most significantly, provide new insight on the petroleum potential of the deep-water Ceduna sub-

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basin. Anomalous occurrences of oil and some gas-condensate assemblages in the primary Coniacian drilling

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target of Gnarlyknots-1A, as well as Turonian and Santonian intervals, indicate multiple phases of hydrocarbon

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migration trapped within micro-fractures of detrital grains. This fluid inclusion evidence provides the first

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consistent indication of a working, liquids-prone, petroleum system in this deep-water part of the basin.

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KEYWORDS

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Great Australian Bight, GAB, Bight Basin, Ceduna Sub-basin, fluid inclusion, petroleum, hydrocarbon, Grains

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with oil inclusion (GOI), Gnarlyknots-1A, oil migration.

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1. INTRODUCTION

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The Jurassic-Cretaceous Bight Basin is a large, mainly offshore basin situated along the western and central

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parts of the continental margin of southern Australia. It overlaps the oceanic area known as the Great

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Australian Bight (GAB) and is considered one of Australia’s most prospective frontier hydrocarbon exploration

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regions (Totterdell et al., 2010). Despite its size, only nine petroleum exploration wells were drilled up to the

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mid-1990s (Fig. 1); Echidna-1 (1972), Platypus-1 (1972), Potoroo-1 (1975), Apollo-1 (1975), Jerboa-1 (1980),

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Duntroon-1 (1986), Borda-1 (1993), Greenly-1 (1993), Vivonne-1 (1993). These wells were drilled in relatively

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shallow waters (less than 270 m) near the basin margin and were all plugged and abandoned with only minor

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oil shows in Greenly-1. To test hydrocarbon prospectivity in these wells, Lisk et al. (2001) undertook a regional

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study using the Grains with Oil Inclusion (GOI) method and identified trace amounts of migrated oil in all wells

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over multiple intervals.

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The drilling of Gnarlyknots-1/1A–drilled in 1,316 m water depth in 2003–marked a resurgence of interest in the

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basin and was the first well to test the hydrocarbon potential of the deep-water Ceduna Sub-basin. While the

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well confirmed the presence of favourable play elements but failed to encounter hydrocarbons, some

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evidence for wet-gas hydrocarbon anomalies were detected along with geochemical evidence for mature

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source (Tapley, 2005). Furthermore, considerable uncertainty remained regarding the liquids generation

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capability of the source intervals due to the lack of well penetration. Under the auspices of the Great

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Australian Bight Research Program (Begg, 2018), this paper presents new data on the detection and

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characterisation of previously hidden oil shows, by the GOI method, in Gnarlyknos-1A and other wells. With

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recent activity in the basin increasing, this has implications for the liquid potential in the deep-water

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prospective part of the basin.

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2. REGIONAL SETTING AND EXPLORATION HISTORY

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The Jurassic-Cretaceous Bight Basin is a large, mainly offshore basin that extends along the southern Australian

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margin, from the southern tip of Western Australia, across the Great Australian Bight to the western tip of

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Kangaroo Island. The basin formed within a tectonic framework dominated by the break-up of eastern

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Gondwana and evolved through repeated episodes of extension and thermal subsidence leading up to, and

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following, the commencement of seafloor spreading between Australia and Antarctica (Totterdell and

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Bradshaw, 2004). It contains five main depocentres—the Ceduna, Duntroon, Eyre, Bremer and Recherche sub-

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basins (Bradshaw et al., 2003; Fig. 1)—in modern day water depths between 200 m and >4,000 m. Its largest

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and thickest depocenter, the Ceduna Sub-basin, covers an area of approximately 126,300 km and contains a

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sedimentary section approximately 15 km thick (Fig. 2).

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A new sequence stratigraphic scheme for the Bight Basin has been developed by Geoscience Australia based

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on the identification of four megasequences, each related to a different basin phase and their component 2nd-

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order supersequences (Fig. 3; Totterdell et al., 2000). Basin Phase 1 records the initiation of sedimentation

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during the Middle-Late Jurassic period of intracontinental extension with two rift-related depositional units,

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the Sea Lion and Minke supersequences, filling extensive half graben systems. These units consist of fluvial-

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lacustrine sandstone, siltstone and shale, with minor coal. This extensional phase was followed by Basin Phase

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2 and a period of slow thermal subsidence throughout most of the Early Cretaceous. Deposition during this

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time was largely non-marine and comprises the Berriasian Southern Right Supersequence of mainly of fluvial-

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lacustrine sandstone and claystone, and the thick, dominantly fine-grained, lacustrine succession of the

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Valanginian to mid-Albian Bronze Whaler Supersequence.An abrupt increase in subsidence rate in the mid-

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Albian signalled the start of Basin Phase 3 and a period of accelerated subsidence that coincided with a period

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of rising global sea level. This combination of factors resulted in an increase in accommodation, the first major

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marine flooding event in the basin and the widespread deposition of marine silts and shales of the mid-Albian

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to early Cenomanian Blue Whale Supersequence along a seaway open to the west. Progradation of deltaic

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sediments into this seaway (White Pointer Supersequence) commenced in the Cenomanian, following uplift

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and erosion along the eastern margin of the continent. This was followed by the accumulation of the marine-

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marginal marine mixed clastic sediments of the Turonian-Santonian Tiger Supersequence, including the

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deposition of organic-rich facies attributed to the global OAE2 event (Totterdell and Mitchell, 2009; Boreham,

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2009). Continental break-up in the Late Santonian was followed by a period of thermal subsidence, Basin

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Phase 4, and the establishment of the southern Australian passive margin. It was during this phase that a

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second large progradational delta developed, represented by the sand-rich fluvial, deltaic and marine

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sediments of the Hammerhead Supersequence. A dramatic reduction in sediment supply at the end of the

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Cretaceous saw the abandonment of deltaic deposition and the development of a cool-water carbonate

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margin during the Cainozoic.

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Ten wells have been drilled in the Bight Basin since 1972 to test the hydrocarbon potential, the most recent

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being Gnarlyknots-1A in 2003. None of these wells encountered significant hydrocarbons. Well post-mortems

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indicated they may have failed for a variety of reasons from poor reservoir (Greenly-1, Potoroo-1) to a lack of

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suitable conduits for migration (Borda-1, Duntroon-1, Vivonne-1). However due to poor quality seismic data

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available at the time more than 50% of the wells failed to test valid trapping structures (Messent, 1998). Minor

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oil and gas indications are reported in Duntroon-1, Echidna-1 and Gnarlyknots-1A, with the latter having

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tantalising shows in cuttings and sidewall cores (SWC) commencing at 4,383 mRT, immediately below the

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primary seal. These were characterised by very dull yellowish/white to moderately bright yellowish-green

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direct fluorescence, with weak diffusing cuts (Tapley et al., 2005). The strongest show recorded in the basin to

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date is from Greenly-1, where minor oil was recovered as a surface scum along with gas from a repeat

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formation test at 4,209.2 mRT (Messent, 1998).

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Whilst marine surveys to detect hydrocarbon seepage within the Bight basin have been unsuccessful

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(Totterdell and Mitchell, 2009), coastal bitumen strandings along the southern coastline of Australia have been

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reported since the mid-1800s (Howchin, 1903; Ward, 1944; Sprigg and Woolley, 1963; Padley, 1995; Hall et al.,

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2014; Edwards et al. 2016, 2018; Ross et al., 2017; Corrick at al., 2019, 2020). The majority of these coastal

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bitumens have been associated with Indonesian sourced oils (waxy bitumens), however it has been proposed

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by various authors (McKirdy, 1984a, b; Padley, 1990 and 1992, 1995; Edwards et al., 1998; Hall et al., 2014;

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Corrick et al., 2019) that the southern margin is the likely origin of the asphaltites.

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Previous fluid inclusion studies undertaken by Lisk et al. (2001) using the Grains with Oil Inclusion (GOI)

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method identified trace amounts of oil trapped in fluid inclusions in wells from the GAB (supplemental Table

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S1). In the Duntroon Sub-basin, oil expulsion and migration were indicated from possible Middle to Lower

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Cretaceous source rocks by the presence of oil inclusions within intercalated sandstones at Borda-1, Duntroon-

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1, Greenly-1, Platypus-1 and Vivonne-1. Evidence for oil migration into shallower Upper Cretaceous and

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Tertiary sandstones was also recorded. The presence of only a single well on the shallow margin of the Ceduna

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Sub-basin, Potoroo-1, made it impossible to reach a strong conclusion about migration effectiveness in the

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wider area despite inclusion data which was considered positive evidence for local oil migration. In the Eyre

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Sub-basin, palaeo-oil columns interpreted in Jerboa-1 (Ruble et al., 2001)–subsequently revised in this paper–

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were taken to corroborate minor oil indications in the Upper Jurassic (Bein and Taylor, 1981).

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Other evidence for the presence of hydrocarbons in the Bight basin comes from Fluid Inclusion Stratigraphy

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(FIS) analysis performed on cuttings samples from Duntroon-1 and Platypus-1 and, more recently, Gnarlyknots-

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1A. The technique involves automated crushing and on-line GC-MS analysis of volatile species trapped within

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fluid inclusions (Hall et al., 2002). In Gnarlyknots-1A, a methane-depleted wet gas to gas-condensate response

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was observed in the primary well objective, consistent with a highly mature palaeo-charge (Tapley et al.,

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2005). This was supported by the frequent occurrence of yellow to blue-white fluorescent inclusions in quartz

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grains over a broad stratigraphic interval. Strong proximal pay indications were indicated within local shale

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seals below 4,600 mRT and interpreted as proximity to a potential oil column below the TD of the well. In

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Duntroon-1 and Platypus-1, a background of wet-gas range species was apparent through the tested sections,

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with a distinct increase in higher molecular weight species (paraffins and alkylated naphthenes) in the lower

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parts of the sections, particularly Duntroon-1 (Lisk et al., 2001).

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3. MATERIALS AND METHODS

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To screen the Bight Basin for hidden oil indications, thirty-six samples from sandstone intervals were analysed

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from seven exploration wells, including the previously unanalysed Gnarlyknots-1A well (Table 1), using CSIRO’s

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Grains with Oil Inclusions (GOI™) technique. The GOI technique is a petrographic point counting method that

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records the number of framework grains containing oil-bearing inclusions, expressed as a percentage of the

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total number of grains in each sample (Eadington et al., 1996). GOI data reported from 23 Australian oilfields

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(Eadington et al., 1996; Lisk et al, 1997) reveal at least one order of magnitude difference between samples

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taken from oil zones when compared to samples from beneath the oil water contact (Fig. 4). Using this

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database these authors suggested that a GOl value of 5% could be considered an empirical threshold for

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samples that have been exposed to high oil saturation while values of less than 1% were likely to indicate

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zones of migration of oil. This technique has been applied widely throughout Australia to identify relict oil

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columns and hydrocarbon migration pathways whose hydrocarbon signature has been subsequently lost (Lisk

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et al., 2002).

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Selection of samples was focused principally on identifying migration pathways in the Upper Cretaceous Tiger

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and Hammerhead Supersequences in Gnarlyknots-1A. Samples were also selected from Borda-1, Duntroon-1,

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Greenly-1, Jerboa-1, Platypus-1, Potoroo-1 and Vivonne-1 to: (1) test the continuity of anomalous GOI results

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identified by Lisk et al. (2001), (2) test new sandstone intervals in these wells, and to (3) repeat the Jerboa-1

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palaeo-oil zone result reported by Ruble et al. (2001). The Echidna-1 well from the Duntroon Sub-basin was not

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sampled due to the low net-to-gross of the interval and previous negative results.

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To reduce the potential for unwanted fluorescence from the surface of the grains, all cuttings samples were; (i)

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cleaned by digestion in dilute hydrogen peroxide for 48 hours, (ii) ultrasonicated to remove fine clay particles

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from mineral surfaces, (iii) sieved to isolate the sand-sized particle fraction, and (iv) mineral separated to

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remove para-magnetic fractions such as shale. Following the method of Edington et al. (1996) a total of 36

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single-polished fluid inclusion thin sections were prepared to a nominal thickness of 80 µm, with the addition

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of Irgalite® blue pigment to suppress fluorescence from the epoxy. GOI analysis was undertaken by

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partitioning the fluid inclusion thin section into approximately 2,000 Fields of View (FOV), each 0.5 x 0.5 mm,

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and scanning for hydrocarbon inclusions via a computer-controlled microscope stepping stage. The process

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allows for the acquisition of attribute data such as vapour bubble size, location and fluorescence colour (UV

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emission 365 nm, barrier filter 420 nm).

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4. GOI RESULTS AND DISCUSSION

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Oil-bearing inclusions were identified in 32 of 36 samples and in all wells, with the exclusion of Jerboa-1. The

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resultant GOI values are all low at 0.4% or less, with the exception of 1.1% in Greenly-1 (Table 1). While none

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of the GOI exceed the empirical threshold of 5% for samples from an oil column, at these low abundances they

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are all consistent with the presence of oil at low saturation in the pore space at the time of trapping. This is

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consistent with theoretical considerations of buoyancy and capillarity that suggest oil saturation on a

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migration pathway is unlikely to exceed a few per cent (Hirsch and Thompson 1995). Consequently, water

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saturations are higher and a proportionally smaller number of grains are exposed to oil.

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4.1 GNARLYKNOTS-1A

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Gnarlyknots-1A was a test of petroleum systems in the deep-water Ceduna sub-basin. Oil-bearing inclusions

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were identified in all 14 samples from both the Tiger (Turonian–Santonian) and Hammerhead (Campanian–

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Maastrichtian) supersequences and their presence indicates generation of liquid hydrocarbons. GOI

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abundances in the well range from <0.1% up to a maximum of 0.4% (Fig. 5) and are below the threshold for a

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palaeo-oil column (Fig. 4). The intra-Santonian primary drilling objective (reassigned post-drill as top Coniacian;

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Tapley et al., 2005) was tested by three ditch cutting samples below 4,390 mRT and spaced evenly over a 25 m

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interval under a thick mudstone seal. Minor GOI anomalies of 0.2% to 0.4%, comprising a statistically

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significant number of grains with oil-bearing inclusions (Table 1), were identified. While in-situ generation of

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hydrocarbons at depths below the top oil window at approximately 4,100 mRT is a possibility, the well is only

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marginally mature at total depth (88°C by horner plot at 4698 mRT; Gnarlyknots-1A well completion report,

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2004) and the oil-bearing inclusions in this anomaly are interpreted as having arisen from migration. A

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methane-depleted wet gas to gas-condensate FIS response (Tapley et al., 2005) was previously interpreted

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over this same interval, so the GOI results suggest that a liquids-rich entrapment history was more significant

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than previously realised. Older Turonian-Coniacian sands, with minor GOI anomalies of 0.3% (4,605 mRT) and

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0.2% (4,710 mRT), are similarly interpreted as migrated hydrocarbons. Younger Coniacian-Santonian sands

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with minor GOI anomalies of 0.2% to 0.4%, including the top Santonian secondary drilling objective at

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approximately 3,760 mRT, together with minor anomalies 0.2% to 0.3% in the overlying post-breakup

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Hammerhead Supersequence are all above oil window and good evidence for migrated hydrocarbons.

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4.2 GREENLY-1

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Greenly-1 is located at shallower water depths along the basin margin and has the best oil shows in the basin.

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In this study, oil-bearing inclusions are identified in all samples from the Cenomanian–Campanian White

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Pointer and Tiger supersequences (Fig. 6) and are consistent with the previous GOI data of Lisk et al. (2001)

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from these same successions and the overlying Hammerhead (Campanian–Maastrichtian) and Wobbygong

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(Palaeocene) supersequences.

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The Cenomanian White Pointer Supersequence (Platypus Formation), near the total depth of the well, was

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previously tested by a GOI of 0.7% at 4,812-4,815 mKB (Lisk et al, 2001). A GOI of 1.1% was obtained in this

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study in the 4,809-4,812 mMD interval above this and, together, shows continuity of this anomalous zone

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upward to the base of the seal. In addition to oil inclusions in quartz, a noteworthy number were also noted in

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pore-filing carbonate cement and not counted as part of the GOI. While GOI magnitudes of 1.1% and 0.7%

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might be permissive of oil saturations near the base of a palaeo-oil column, a significant structural

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misinterpretation of this well due to a miss-pick in the seismic (Messent, 1998) means the interval was likely

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out of closure. Even though the interval is within the oil window (below 3,600 mKB; Messent, 1998) and in-situ

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generation of organic matter cannot be discounted, the GOI are taken as strong evidence for migration,

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particularly given the uniformity in fluorescence colour and location attributes. This is supported by

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conventional shows that comprise trace to 10% direct fluorescence, with cut, in cuttings from 4,806–4,816

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mKB and in SWCs over the 4,797–4,817.5 mKB interval.

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Minor GOI anomalies of 0.3%, up to 0.6%, at shallower depth intervals of the White Pointer Supersequence

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and in the overlying base Tiger Supersequence are similarly interpreted as migrated oil applying the same

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logic. These intervals are coincident with conventional oil shows, which includes oil recovered as a surface

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scum on water at 4,209 mKB. The GOI and oil inclusion abundances generally decrease above the level of the

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mid-Tiger Supersequence, including the Hammerhead and Wobbygong supersequences.

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4.3 OTHER WELLS

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Low GOI responses of 0.4% and less in Potoroo-1 (supplemental Fig. S1), Duntroon-1 (supplemental Fig. S2),

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Borda-1 and Platypus-1 are all consistent with previous GOI results from Lisk et al. (2001). In Potoroo-1 a GOI

203

of 0.4% from an interval near the base of the Blue Whale Supersequence shows continuity above a previous

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GOI of 0.5% (Lisk et al., 2001), however this is based on the identification of only 2 grains with oil inclusion and

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the counting statistics are poor in this coarse-grained sand. Perhaps more significantly a new interval tested at

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the base of the Tiger Supersequence, albeit with a lower GOI of 0.2%, identified 34 grains with oil inclusions in

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a very fine-grained sand (1778-1786 mRT). The Bronze Whaler Supersequence, at the very base of the well, is

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marginally mature below 2,788 mRT (VR 0.64%; Geoscience Australia, Petroleum Wells Database) so the oil

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inclusions in the Tiger Supersequence represent migration.

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Likewise, the base Tiger Supersequence in Duntoon-1 had a minor GOI anomaly of 0.4% (2505-10 mMD) and

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continuity with a previous GOI of 0.4% GOI in the sample below (Lisk et al., 2001). Again, these represent

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migrated hydrocarbons as the interval is above the oil window, which starts at 3,100 mRT (VR 0.58%;

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Geoscience Australia, Petroleum Wells Database) in the marginally mature Bronze Whaler Supersequence.

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4.4 JERBOA-1 (REINTERPRETATION)

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Palaeo-oil columns previously reported in Jerboa-1 by Liu and Eadington (1998) and Ruble et al. (1999) are

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reinterpreted in this study after reviewing the existing and new GOI thin sections. As a result, previous

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evidence for palaeo-oil columns at 2,470-80 mMD (6.6% GOI) and 2,490-95 mMD (10.4% GOI) in the Upper

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Jurassic Sea Lion Supersequence are no longer supported (supplemental Fig. S3). The revised GOI are 0.0% in

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both intervals and the difference is ascribed to high levels of background fluorescence and contamination in

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the original sample thin sections. Higher molecular weight hydrocarbons (oil) were not extracted from the

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2,470-80 mMD sample during Molecular Composition of oil Inclusion analysis and, as originally presented by

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Ruble et al. (2001), there was a low biomarker yield relative to high background levels of components in the

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associated system blanks in the 2,490-95 mMD sample. Given that MCI from high GOI samples >5% typically

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yield robust geochemical data, the low yields are consistent with the revised lack oil inclusions in both

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samples.

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Traces of residual oil (stains) were reported by Bein and Taylor (1981) in thin sections at 2,145 mMD and

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within the upper MCI interval at 2,472.5 mMD in Jerboa-1. The biomarker distributions of these hydrocarbon

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stains showed unusual features interpreted as being derived predominantly from immature local terrestrial

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source material. They were geochemically different to the supposed fluid inclusion oil at 2,490-95 mMD which

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Ruble et al. (2001) reported as having been derived from a carbonate-rich source-rock containing algal and

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bacterial organic material likely deposited in a lacustrine environment.

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5. OIL-BEARING INCLUSION ASSEMBLAGES AND ATTRIBUTES

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A fluid inclusion assemblage, or in this case an oil inclusion assemblage, is defined as the most finely

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discriminated group of petrographically associated fluid inclusions that formed at about the same time, or

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during the same set of diagenetic conditions (Goldstein and Reynolds, 1994). Liquid to vapour ratios, location

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and fluorescence colour attributes were acquired and are shown graphically for Gnarlyknots-1A and Greenly-1

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(Fig. 7), with the full dataset in supplemental Table S2.

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5.1 LIQUID TO VAPOUR RATIO

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Three types of oil-bearing inclusion assemblage are observed in the samples studied. Those with; (1) small

240

bubble and small variance amongst the inclusions of an assemblage (coded SMLBUBL SMLVAR)–they comprise

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two phases (liquid and vapour) at room temperature, with somewhat consistent volumetric ratios (L:V)

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containing small vapour bubbles and dominant liquid oil phase, (2) large bubble and small variance (coded

243

LRBUBL SMLVAR)–they comprise two phases (liquid and vapour) at room temperature, with somewhat

244

consistent volumetric ratios (L:V) containing a dominant vapour phase and a minor rim of liquid oil, and (3)

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large variance in the liquid-vapour ratio (coded LRG VAR)–the contain both small and large vapour phase oil-

246

bearing inclusions with the liquid oil phase exhibiting either uniform or variable colours. Indeterminate

247

assemblages comprised either single inclusions or multiple inclusions with unclear vapour bubbles.

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Oil-bearing assemblages from Gnarlyknots-1A comprise mostly those assemblages of inclusions with small

249

bubbles and small variance in L:V ratio (Fig. 8A, B) and account for 64% of the total assemblages (Fig. 7A). This

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may be higher as some indeterminate assemblages (23%) are recorded as having at least one small vapour

251

bubble inclusion. Inclusions of this type are likely to homogenise into the liquid oil phase at the trapping

252

conditions of the reservoir. Their presence in Gnarlyknots-1A is particularly significant given a FIS methane

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depleted wet-gas to gas-condensate anomaly in the primary objective (Tapley et al., 2005). In addition, 10% of

254

the total assemblages have highly variable L:V inclusions and 3% with consistent vapour-rich inclusions. The

255

former suggests two phase trapping of both oil and gas-condensate at the same time with residual oil

256

interacting with later gas or oil un-mixing from gas-condensate at reservoir conditions due to changes in

257

pressure/temperature (phase separation). The latter were likely trapped as gas-condensate at reservoir

258

conditions, with phases unmixing at room temperature. Together, these assemblages suggest multiple phases

259

of hydrocarbon migration through this well intersection. In the samples from the primary objective the highly

260

variable L:V inclusion assemblages are a higher percentage (16%), with proportionally less oil inclusions.

261

By comparison, assemblages from Greenly-1 with small vapour bubbles that are likely to homogenise into the

262

oil phase (Fig. 8D) account for 73% of the total assemblages (Fig. 7A), with this likely to be higher if

263

indeterminate assemblages (20%) are included. Assemblages that likely trapped mixtures of gas-

264

condensate/oil account for only 7% of the total, whereas vapour-rich inclusions that only trapped gas-

265

condensate are absent (Fig. 7A). In the anomalous GOI zone of 1.1% near the base of the well only oil

266

inclusions are recorded. The results in Greenly-1, however, do not express the expected fluid type in wells

267

from the basin margin, with Potoroo-1 having similar proportions of vapour rich inclusions as those in

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Gnarlyknots-1A (11%; both small and large variance) and Duntroon-1 having a noteworthy 34% combined

269

total. In this well 21% of the assemblages have highly variable L:V inclusions, suggesting two phase trapping of

270

both oil and gas-condensate, and 13% with consistent vapour-rich inclusions, suggesting the trapping of gas-

271

condensate.

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5.2 LOCATION

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Oil-bearing inclusion assemblages, including those in Gnalryknots-1A, occur almost exclusively along

274

unconstrained healed micro-fractures in detrital quartz and feldspar (Fig. 7B; Fig. 9A, B; Table S2). No

275

relationship with cements could be established and their relative timing of formation is uncertain. Some oil-

276

bearing diagenetic fractures, however, appear to terminate at the quartz overgrowth boundary, being noted in

277

four samples from Gnarlyknots-1A (Fig. 9C) and one sample from Duntroon-1. They provide evidence

278

suggesting some hydrocarbons were trapped prior to the onset of quartz cementation. Trace numbers of oil

279

inclusions were observed at the quartz overgrowth boundary in Potoroo-1 and Duntroon-1, but at abundances

280

too low to be statistically significant.

281

Quartz cement is not well developed in the samples studied for GOI as temperatures across the basin are not

282

sufficiently elevated to promote significant amounts of quartz cementation. Conceptual models commonly

283

assume that quartz cementation has an effective threshold temperature of around 70–80°C (Lander and

284

Walderhaug, 1999) with recent calibrations of these models using high resolution isotope data proposing

285

temperatures from 60–70°C (Harwood et al., 2013). The current formation temperature near the base of

286

Gnarlyknots-1A is 88°C, placing it in the lower range of temperatures for the formation of quartz cement. Thus,

287

the diagenetic fractures that are host to the oil-bearing inclusions probably formed over an extended time

288

compared to other sedimentary basins where ongoing quartz cementation effectively retards their

289

development.

290

In addition, the 1.1% GOI anomaly in Greenly-1 at 4,809-12 mMD has numerous occurrences of oil inclusions in

291

pore-filling carbonate cement that were not included in the GOI count (Fig. 9D). Similar occurrences were also

292

noted by Lisk et al. (2001) at 4,161-64 mMD and 4,812-15 mMD in Greenly-1 and 3,730-33 mMD and 3,859-62

293

mMD in Platypus-1. The carbonate cement phases appear complex and their timing relationship relative to the

294

diagenetic fractures could not be established. In the case of Greenly-1, however, the oil inclusions in carbonate

295

cement at 4,809-12 mMD have the same vapour to liquid and fluorescence colour attributes as those included

296

in the GOI count and, on this basis, are considered to have trapped the same oil at probably the same time.

297

5.3 FLUORESCENCE COLOUR

298

When exposed to ultraviolet light most oil-filled inclusions will emit visible light (fluoresce). Across the whole

299

dataset, and including Gnarlyknos-1A, the dominant fluorescence colour of oil-bearing inclusion assemblages is

300

near-white (Fig 7C; Table S2). These near-white assemblages are mostly uniform in colour, but do encompass

301

small colour variations to include those with slightly bluish or yellowish tints. Uniform near-blue and near-

302

yellow fluorescing assemblages occur at lower proportions, together with those that exhibit gradational

303

variants between near-white, near-blue and near-yellow. The uniform near-white fluorescing assemblages

304

mostly have small vapour bubbles that are likely to homogenise into the oil phase at trapping conditions.

305

While some assemblages with near-blue fluorescence also have small vapour bubbles, most of those with

306

higher vapour contents (i.e. likely to have been trapped as gas-condensate) fluoresce this colour.

307

Fluorescence colour can be loosely correlated with API gravity. Empirically, oil that fluoresces toward the red

308

wavelengths (those that appear orange/yellow) tend to have lower API gravities while oil that fluoresces

309

toward the blue wavelengths have higher API gravities (Stasiuk and Snowdon, 1997). Based on correlations

310

presented by Bourdet et al. (2014), and using the same fluorescence microscope, inclusions in this study

311

assigned as having near-white fluorescence would have inferred °API gravities of around 30-40 while those

312

with near-blue fluorescence, would have inferred °API gravities >45.

313

6. IMPLICATIONS FOR SOURCE AND TIMING OF MIGRATION

314

Migration of oil and gas in the Bight Basin, from the hydrocarbon-bearing fluid inclusion identified in this study

315

and those previously reported by Lisk et al. (2001), is more frequently encountered in intervals of the Late

316

Cretaceous White Pointer, Tiger and Hammerhead supersequences (Fig. 10). While these intervals were the

317

targets for exploration, hydrocarbon-bearing inclusions appear less frequent in intervals from the Late Jurassic

318

to Early Cretaceous Sea Lion, Bronze Whaler and Blue Whale supersequences and in the Tertiary Wobbegong

319

and Dugong supersequences of the overlying Eucla Basin.

320

6.1 DEEP-WATER CEDUNA SUB-BASIN

321

Gnarlyknots-1A was the first well to test the hydrocarbon potential of the deep-water Ceduna Sub-basin. The

322

fluid inclusion results of this study have revealed good evidence for hydrocarbon migration in this well over

323

multiple depth intervals of the Late Cretaceous Tiger and Hammerhead supersequences. The oil inclusions,

324

and almost certainly the gas-condensate inclusions, attest to multiple phases of migration through this well

325

intersection. While there is no evidence for palaeo-accumulation, the presence of these fluid inclusions implies

326

that some source rocks reached maturity and expelled hydrocarbons in the past, either vertically from beneath

327

or laterally down-dip from the well intersection.

328

Recent 2D petroleum systems modelling across the Ceduna Sub-basin, using source-specific multi-component

329

kinetics (Totterdell et al, 2008), focused on three main potential source rocks: marine Blue Whale and Tiger

330

supersequence source rocks, comprising mainly Type II kerogen, and deltaic, upper White Pointer

331

Supersequence source rocks, comprising mainly Type II/III kerogen. The basal Tiger Supersequence, which has

332

good-to-excellent generative potential for oil (Totterdell et al., 2008) is mature for both oil and gas generation

333

across the greater part of the depocentre and immature along the basin margins. In the thickest part of the

334

basin and immediately south of Gnarlyknots-1A, where the overburden is between about 5,000 and 5,500 m

335

thick, the basal Tiger Supersequence is gas mature. Overall, modelling results suggested generation and

336

expulsion from this postulated source unit occurred continuously from about the mid-Campanian (~74 Ma),

337

following deposition of the earliest part of the Hammerhead sequence, until the present day. It is speculated

338

here that the migrated oil identified in the inclusions from Gnarlyknots-1A might have come from this source

339

unit.

340

Although a considerable proportion of the organic matter from the Cenomanian White Pointer Supersequence

341

consists of coal (Struckmeyer et al, 2001), some shales and siltstones contain Type II/III kerogen with good-to-

342

excellent source potential for both oil and gas. The upper White Pointer Supersequence lies within the oil

343

window and wet gas window in the greater part of the basin and modelled generation and expulsion occurred

344

since the Early Campanian until the present day (Totterdell et al, 2008). The lower part of this thick succession

345

is typically gas mature throughout the basin, except for the basin margins. It is speculated here that the gas-

346

condensate identified in inclusions from Gnarlyknots-1A might have either come from a White Pointer source,

347

or perhaps gas mature basal Tiger source, but at a different time to the oil.

348

The more proximal end-members of the Albian-Early Cenomanian Blue Whale Supersequence have organic

349

matter content typically comprising Type II/III kerogen with good potential for the generation of both oil and

350

gas (Struckmeyer et al, 2001). The depositional framework suggests that the supersequence was deposited in

351

more open marine conditions further basinward, indicating that source potential is likely to increase in more

352

distal facies. However, for the greater part of the basin, generation and expulsion from potential source rocks

353

of the Blue Whale Supersequence occurred during the Turonian to Santonian but continues to the present-day

354

near the basin margins (Totterdell et al., 2008). Near Gnarlyknots-1A, maturation of this source occurred

355

before essential reservoir, structural and sealing elements were in place (Tapley et al., 2005) and is not likely to

356

account for the migrated hydrocarbons trapped in the fluid inclusions.

357

The bulk geochemical composition of hydrocarbons extracted from fluid inclusions identified in this study from

358

Gnarlyknots-1A, between 4,390 mRT and 4,425 mRT, is discussed by Gong et al. (submitted). The timing of

359

entrapment from pressure-temperature-volume-composition (PVTx) reconstructions of hydrocarbon inclusion

360

assemblages from the 4,410-15 mRT interval in the same well is discussed by Bourdet et al. (submitted).

361

6.2 SHELF EDGE

362

Previous fluid inclusion analysis by Lisk et al. (2001) revealed evidence for oil migration in along the shallow-

363

water shelf edges of the central Ceduna Sub-basin in Potoroo-1 and eastern Ceduna/Duntroon sub-basins in

364

Greenly-1, Duntroon-1, Borda-1 and Playpus-1. This result has been reaffirmed in this study by follow-up

365

analysis of additional intervals and anomalous zones.

366

The highest GOI recorded for any sample from the Bight Basin was obtained from the Cenomanian Platypus

367

Formation (White Pointer Suersequence) in Greenly-1 (1.1%; Fig. 6), with uniformity in the oil inclusion

368

attributes, without gas, suggesting a single source. Although numerous oil indications were reported from the

369

Wigunda (Tiger Supersequence) and Platypus formations (Messent, 1998), with oil and gas recovered from the

370

Wigunda Formation during testing (RFT), the source of this oil is unclear. An Upper Borda Formation (Bronze

371

Whaler Supersequence) source is considered most likely by Smith and Donaldson (1995), however Tapley et al.

372

(2005) speculate that Platypus Formation shales, with excellent potential for oil and gas, may have sourced the

373

oil shows in this well. Expulsion from the Upper Borda Formation is likely to have occurred largely in the Late

374

Cretaceous, following a major phase of structuring prior to breakup (Smith and Donaldson, 1995). Expulsion

375

from the Platypus Formation, however, is likely to have occurred from the Late Oligocene in response to

376

Tertiary burial from a thick wedge of carbonate sediments that prograded across the present-day shelf edge.

377

Perhaps recent charge might be a more compelling explanation for the strong oil shows in Greenly-1 on the

378

grounds of shorter preservation time. The bulk geochemical composition of hydrocarbons extracted from fluid

379

inclusions from the Platypus Formation in Greeny-1, between 4806 mKB – 4818 mKB, is discussed by Gong et

380

al. (submitted).

381

Duntroon-1, from the same area, saw oil migration in both the Tiger and Hammerhead supersequences (Fig.

382

S2), but has notably more gas-condensate assemblages compared to Greenly-1. The source was anticipated to

383

be coals of the Upper Borda and Platypus formations (Messent, 1998). The quality of the source rocks in the

384

immediate vicinity of this well was later interpreted as being limited, with the major migration pathway from

385

the south complicated by the number of fault zones in the area. Interestingly the interval with the highest GOI

386

in the well (0.4%) is located just above a significant fault zone and it is speculated here that this conduit may

387

have facilitated vertical hydrocarbon migration. Oil-bearing inclusions observed in Platypus-1 and Borda-1

388

likewise reaffirm hydrocarbon migration through these wells, albeit at lower intensity, with an Upper Borda

389

Formation source again anticipated from the south in Borda-1.

390

Potoroo-1 lies on the inboard margin of the Ceduna Sub-basin, close to the structural hinge that separates it

391

from the Madura Shelf and, by comparison to Gnarlyknots-1A, evidence for hydrocarbon migration is

392

somewhat less intense (Fig. S1). Reservoir quality is generally poor in the Blue Whale, White Pointer and Tiger

393

supersequences and capillarity effects may be limiting the ingress of hydrocarbons into what are largely

394

siltstones. The observed oil-bearing inclusions could be sourced from mature Tiger and upper White Pointer

395

supersequences approximately 50 km basinward. Alternatively, the hydrocarbons might have been more

396

locally sourced from the Blue Whale Supersequence which lies within the oil window in the innermost part of

397

the Ceduna Sub-basin. Although generation and expulsion from this source occurred during the Turonian to

398

Santonian over the greater part of the basin, it continues to the present day near the basin margin and

399

proximal to Potoroo-1 (Totterdell et al., 2008). The timing of entrapment from pressure-temperature-volume-

400

composition (PVTx) reconstructions of hydrocarbon inclusion assemblages from the 1,778–1,786 mRT interval

401

in Potoroo-1, 4,809–4,812 mRT interval in Greenly-1 and 2,505-2,510 mRT interval in Duntroon-1 is discussed

402

by Bourdet et al. (submitted).

403

The absence of palaeo-oil zones in the Sea Lion Supersequence from Jerboa-1 (this study) no longer favours

404

migration of hydrocarbons into the structure from Middle-Late Jurassic lacustrine source-rocks deposited in

405

the flanking half-grabens of the Eyre sub-basin. The likelihood of long-distance migration from the Ceduna and

406

Recherche sub-basins into the isolated Late Jurassic reservoirs within the Eyre Sub-basin is also not supported

407

by geological mapping (Totterdell et a1. 2000).

408

7. IMPLICATIONS FOR DEEP-WATER PROSPECTIVITY

409

An historic key risk for exploration of the Ceduna Sub-basin was the possible lack of an effective source rock

410

and thus adequate hydrocarbon charge (Totterdell et al., 2010). While this risk has been significantly reduced

411

by the identification of a high-quality marine source rock of Cenomanian-to-Turonian age (Totterdell et al,

412

2008), there has been no direct evidence for generation from this or any other potential source rock. The

413

hydrocarbon-bearing inclusions identified in Gnarlyknots-1A, however, do potentially allude to some source

414

intervals having been thermally mature for generation and migration in this deep-water region of the Bight.

415

The majority of plays in basin are structural and, as such, are dependent on cross-fault seal. This is most likely

416

reason for the failure of Gnarlyknots-1A to intersect a hydrocarbon column, which was drilled outside any fault

417

independent closure and lacked a valid fault seal on the northern bounding fault (Tapley et al., 2005). The sand

418

content of the well was greater than expected and too high to create adequate fault-gouge seal. This is also

419

consistent with the lack of any palaeo-oil/gas accumulations from the GOI in this well. Tapley et al (2005)

420

suggested that net-to-gross ratios were probably lower in the middle-to-lower Tiger Supersequence below the

421

TD of the well and cross-fault seals were likely to be present.

422

Further outboard seal is probably less of a risk because of the likely presence of thick basinal shales in the Tiger

423

Supersequence and outer shelf to slope fine-grained sediments within the lower part of the Hammerhead

424

Supersequence (Krassay and Totterdell, 2003; King and Mee, 2004). More recent coupled stratigraphic and

425

fault seal modelling has shown a higher probability of cross-fault seal in this outboard area (Strand et al.,

426

2017).

427

8. CONCLUSIONS

428

The results presented here represent a rigorous study, using fluid inclusions from samples from the historical

429

wells in the Great Australian Bight that augment and expand on prior work. This study reaffirms evidence for

430

hydrocarbon migration on the shallow-water margins of the Bight Basin, but most significantly raises the

431

potential of the deep-water Ceduna Sub-basin through new study of the Gnarlyknots-1A well. Anomalous

432

occurrences of both oil and gas-condensate inclusions in the primary drilling objective of this well, together

433

with intervals above and below, suggest multiple phases of hydrocarbon migration that were trapped within

434

healed micro-fractures of the detrital grains. While methane depleted gas-condensate anomalies were

435

previously interpreted, the data presented here provides the first consistent evidence for liquids, and oil

436

migration, in the deep-water Ceduna Sub-basin. While palaeo-oil accumulation in the Eyre Sub-basin is no

437

longer supported by revised GOI in Jerboa-1, hydrocarbon prospectivity along other areas of the shelf edge

438

persists, particularly in the vicinity of the Duntroon Sub-basin.

439

9. ACKNOWLEDGEMENTS

440

This study is part of the Great Australian Bight Research Program. The Great Australian Bight Research

441

Program is a collaboration between BP, CSIRO, the South Australian Research and Development Institute

442

(SARDI), the University of Adelaide, and Flinders University. The Program aims to provide a whole-of-system

443

understanding of the environment, economic and social values of the region; providing an information source

444

for all to use. The authors also thank the reviewers for their comments and suggestions that helped to improve

445

the paper.

446

10. DECLARATION OF INTEREST

447

None

448

449

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450

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451 452

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566

TABLES

567 568

Table 1. GOI results from this study. Well

569 570 571 572 573

CSIRO no

Depth (MDRT)

Count protocol

GWOI

Total grains

GOI (%)

Borda-1 134500 2,678-81 m RG 4 6819 <0.1% Borda-1 134501 2,774-77 m RG 0 2272 0.0% Duntroon-1 134502 1,855-60 m RG 2 2160 <0.1% Duntroon-1 134503 2,150-55 m RG 7 2253 0.3% Duntroon-1 134504 2,505-10 m RG 12 3316 0.4% Duntroon-1 134505 3,025-30 m RG 1 2718 <0.1% Duntroon-1 134506 3,235-40 m RG 2 3840 <0.1% Duntroon-1 134507 3,345-50 m RG 1 4015 <0.1% Greenly-1 134508 3,275-80 m RG 6 3326 0.2% Greenly-1 134509 3,753-56 m RG 2 2298 <0.1% Greenly-1 134510 4,110-13 m RG 14 6661 0.2% Greenly-1 134511 4,377-80 m RG 15 8520 0.2% Greenly-1 134512 4,530-33 m RG 20 6192 0.3% Greenly-1 134513 4,809-12 m RG 16* 1425 1.1% Gnarlyknots-1A 134514 2,170-80 m RG 10 3360 0.3% Gnarlyknots-1A 134515 2,535-40 m RG 8 2540 0.3% Gnarlyknots-1A 134516 2,865-70 m RG 7 3648 0.2% Gnarlyknots-1A 134517 3,175-80 m RG 5 3878 0.1% Gnarlyknots-1A 134518 3,760-65 m RG 11 4994 0.2% Gnarlyknots-1A 134519 3,770-75 m RG 6 3775 0.2% Gnarlyknots-1A 134520 3,930-40 m RG 20 4778 0.4% Gnarlyknots-1A 134521 4,135-40 m RG 19 4352 0.4% Gnarlyknots-1A 134522 4,390-95 m RG 9 4143 0.2% Gnarlyknots-1A 134523 4,400-05 m RG 12 7594 0.2% Gnarlyknots-1A 134524 4,410-15 m RG 29 7027 0.4% Gnarlyknots-1A 134525 4,520-25 m RG 6 6353 <0.1% Gnarlyknots-1A 134526 4,605-10 m RG 19 5954 0.3% Gnarlyknots-1A 134527 4,705-10 m RG 13 8046 0.2% † Jerboa-1 134718/719 2,470-2,480 m RG 0 517 0.0% Jerboa-1 134720 2,490-95 m RG 0 345 0.0% Platypus-1 134528 9,560-70 ft RG 3 3720 <0.1% Platypus-1 134529 9,640-50 ft RG 3 2700 0.1% Platypus-1 134530 11,090-11,100 ft RG 0 201 0.0% † Potoroo-1 134721/722 1,778-1,786 m RG 34 21384 0.2% † Potoroo-1 134531/532 2,398-2,406 m RG 3 2352 0.1% Potoroo-1 134533 2,730-34 m RG 2 500 0.4% GOI rounded to nearest 0.1% except for values between 0.01 and 0.09% which are reported as <0.1%. GWOI = grains with oil inclusions. Rectangle Grid (RG), Point Grid (PG), Square Grid (SG or Random). * Excludes of oil inclusions in carbonate † cement. Consecutive cuttings samples combined

[1.5

COLUMN]

574

FIGURES

575 576 577

Figure 1. Location of the Bight Basin and sub-basins and wells. Ceduna sub-basin cross section (Figure 2) marked as NW-SE line.

578 579 580

[PROBABLY DOLUBLE COLUMN]

581 582 583

Figure 2. 2D Cross section across the Ceduna Sub-basin showing key interpreted Supersequences. © Commonwealth of Australia (Geoscience Australia) 2019.

584 585

[HIGH RESOLUTION JPEG ATTACHED SEPARATELY]

586

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587 588 589

590 591 592

Figure 3. Sequence stratigraphy framework chart of the Bight Basin showing basin phases and predicted source rock intervals. © Commonwealth of Australia (Geoscience Australia) 2019.

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595

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596

597 598 599

Figure 4. Database of GOI values. An oil zone and water zone pair (mean values) are shown from 23 Australian oil fields (modified by Lisk et al., 1997 after Eadington et al., 1996).

600 601

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602 603 604

Figure 5. GOI log – Gnarlyknots-1A. Age and Formation from Gnarlyknots-1A well completion report (2004). Supersequence (SSQ) inferred from Tapley et al (2005).

605 606

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607

608 609 610

Figure 6. GOI log – Greenly-1. GOI shown from this study and Lisk et al. (2001). Age and Formation from Messent (1998) and Supersequence (SSQ) from Totterdell et al. (2000).

611 612

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613 614 615 616 617 618 619

Figure 7. Summary of oil-bearing inclusion assemblage attributes for all samples analysed in this study from Gnarlyknots-1A (left) and Greenly-1 (right). (A) Liquid to vapour ratio (refer to section 5.1 for detailed explanation of classification and text coding). (B) Location in detrital grains on an eight-category classification; unresolved, fracture intragrain, fracture terminating at quartz overgrowth (QO), QO boundary, within QO, fracture transecting QO and penetrative fractures. (C) Fluorescence colour (UV visible) on a six-category classification; uniform blue, white, yellow and gradational (GRD) blue-white, white-yellow, blue-yellow.

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623 624 625 626 627 628

Figure 8: Liquid:Vapour (L:V) ratios of inclusion assemblages. (A) L:V two phase inclusion with small vapour bubble (Gnarlyknots-1A, 2,535-40 mMD). (B) L:V two phase inclusion with small but slightly larger vapour bubble cf. B (Gnarlyknots-1A, 2,535-40 mMD). (C) L:V, two phase inclusions with vapour-rich inclusions and thin rims of liquid oil (Gnarlyknots-1A, 4,410-15 mMD. (D) As for A (Greenly-1, 4,809-12 mMD). Paired transmitted light (left) and UV illumination (right) photomicrographs.

629

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630 631 632 633 634 635

Figure 9: Location of oil inclusion assemblages. (A) Diagenetic fractures within quartz (Qz; Gnarlyknots-1A, 4,410-15 mMD). (B) Diagenetic fractures within quartz (Greenly-1, 4,809-12 mMD). (C) Diagenetic fractures that terminate at the quartz overgrowth (QO) boundary (QOB; Gnarlyknots-1A, 4,520-25 mMD) (D) pore-filling carbonate cement CC; Greenly-1, 4,809-12 mMD). Paired transmitted light (left) and UV illumination (right) photomicrographs.

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GOI (%) 0.2

0.4

0.6

0.8

1.0

Bronze Whaler

Blue Whale

White Pointer

Tiger

Hammerhead

Wobbegong Dugong

0.0

* *

Minke

Sea Lion

* * *

637 638 639

*

Figure 10. GOI summary by supersequence. Includes GOI data from Lisk et al (2001). *Unrevised Jerboa-1 GOI data from Liu and Eadington (1998).

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1 2

REVEALING OIL MIGRATION IN THE FRONTIER BIGHT BASIN, AUSTRALIA

3 4

RICHARD H. KEMPTONa*, JULIEN BOURDETa, SE GONGb AND ANDREW S. ROSSa

5 6 7

a CSIRO Energy, 26 Dick Perry Ave, Kensington, WA, Australia, 6151

8

b CSIRO Energy, 14 Julius Avenue, North Ryde, NSW, Australia, 2113

9

*Corresponding author: Richard Kempton ([email protected])

10 11

HIGHLIGHTS •

12 13

Australian Bight, revealed by fluid inclusions. •

14 15

18

Oil and gas-condensate inclusions in the Gnarlyknots-1A well indicate multiple phases of hydrocarbon migration trapped within detrital sand grains.

•

16 17

First evidence for a liquids-prone petroleum system in the deep-water Ceduna Sub-basin, Great

Previously hidden hydrocarbon indications are revealed in more detail by fluid inclusions than by the conventional shows.

•

Validation of key petroleum system elements, such as source, generation and migration increase the petroleum prospectivity in this frontier region of the Great Australian Bight.

1 2

REVEALING OIL MIGRATION IN THE FRONTIER BIGHT BASIN, AUSTRALIA

3 4

RICHARD H. KEMPTONa*, JULIEN BOURDETa, SE GONGb AND ANDREW S. ROSSa

5 6 7

a CSIRO Energy, 26 Dick Perry Ave, Kensington, WA, Australia, 6151

8

b CSIRO Energy, 14 Julius Avenue, North Ryde, NSW, Australia, 2113

9

*Corresponding author: Richard Kempton ([email protected])

10

11. DECLARATION OF INTEREST

11

None

12

13