Geochemical evidence for a new Triassic petroleum system on the western margin of Australia

Keywords: Roebuck Basin, Bedout Sub-basin, fluids, source rocks, organic geochemistry, biomarkers, isotopes, Triassic, Keraudren Formation.

In 2014, the surprise discovery of oil in Phoenix South 1 on Australia’s North West Shelf (NWS) heralded the Bedout Sub-basin as a new oil province in Australia (Fig. 1a). The Dorado oil field, discovered in 2018 and located about 40 km south of Phoenix South 1, is one of the largest oil resources found in Australia in decades (Weller and Amiribesheli 2018; Cockerill 2020) and confirms the magnitude of the resources in the Bedout Sub-basin. However, whether these discoveries represent a new oil province is challenged by the presence of gas in the Greater Phoenix area wells, Roc 1–2, Phoenix South 2–3 and Dorado 1–3.

Fig. 1.  (a) Regional map of the Roebuck Basin showing main structural elements, petroleum wells and hydrocarbon fields and discoveries. (b) Permian–Triassic tectono-stratigraphic chart of the Bedout Sub-basin based on the nomenclature after Marshall and Lang (2013) and the Geologic Timescale 2016 (Ogg et al. 2016) showing oil and gas discoveries and formation names by Santos Ltd (Thompson et al. 2019; Thompson 2020).

To better assess the potential for finding similar plays elsewhere on the margin, it is essential to understand the source of the oils and gases in the greater Phoenix area, which is accomplished using a geochemical approach. Analyses of fluids provide information on the source rock they derive from, including kerogen type, age and maturity at the time of hydrocarbon generation. Oil–gas–source correlations using isotopic and molecular data provide insights into the most likely source rock from which the fluids of the Bedout Sub-basin derive.

The oils, natural gas and rock samples analysed in this study for bulk isotopic and biomarker compositions are listed in Table 1. The Phoenix South 1 oils were recovered from the Middle Triassic Barret Member between TR15.0_SB and TR16.0_SB, whereas the Roc 1–2 gases and condensates were taken from the Lower to Middle Triassic Caley Member between TR10.0_SB and TR15.0_SB (Thompson et al. 2018; Rollet et al. 2019) (Fig. 1b). The methods and data have been reported in Grosjean et al. (2019a, 2019b, 2019c, 2020a). At the time of this study, fluids from the recently drilled Dorado wells were not yet available for analysis but will be included in further work.

Table 1.  Bulk properties and relevant geochemical ratios for petroleum fluids and rocks analysed during this study

Roc 1–2 both encountered rich gas condensates with condensate-to-gas ratios of 50.5 and 55.8 bbl/mmscf, respectively. While methane is the dominant component of these natural gases (Grosjean et al. 2019b), they are considered wet gases with C₁/(C₁–C₅) of 82.8%, where wet gases are defined by this ratio as being <98% (Tissot and Welte 1984).

The Phoenix South 1 oils and Roc 1–2 condensates are light fluids (API gravity 43–49°), low in sulfur (S = 0.01–0.08 wt.%) and non-biodegraded. The low gas-to-oil ratios in the range 1691–1764 scf/bbl for the Phoenix South 1 oils are inconsistent with an API > 45°, implying that the oils are undersaturated with respect to gas (Murray and He 2020). Based on vitrinite reflectance equivalent (VREQ-5) data derived from a proprietary combination of aromatic hydrocarbons analysed by GC/MS-MS QQQ at GeoMark Research, the Roc 1–2 condensates are more thermally mature (mean VREQ-5 = 1.16%) than the Phoenix South 1 oils (VREQ-5 = 0.98%) generated at peak oil maturity. The pristane-to-phytane (Pr/Ph) ratios of the Phoenix South 1 oils and Roc 1–2 condensates are in excess of 2.5 (Table 1), indicative of a suboxic/oxic depositional environment for the source rock. Terpanes and steranes distributions reveal mixed marine-terrestrial inputs to the organic matter and a clastic source rock. There is no increased abundance of C₃₃ alkylcyclohexane in these fluids, a biomarker diagnostic for the end-Permian mass extinction event and prevalent in Lower Triassic-sourced Perth Basin oils (Grosjean et al. 2011 and references therein). The low relative amount of retene, a polyaromatic compound likely derived from Araucariacae conifers that evolved during the Jurassic (Alexander et al. 1988), is in agreement with a pre-Jurassic age. The carbon isotopic composition (δ¹³C) of the saturated hydrocarbon fractions ranges from –30.2 to –29.6‰, which is within the range of values observed globally for crude oils derived from Triassic source rocks (Andrusevich et al. 1998).

An effective tool for understanding the potential source of gases and oils is to compare the compound-specific isotopic analyses of linear alkanes of the fluids with those of the source rocks from which they may be derived. Carbon isotopic values of alkanes for the fluids in the greater Phoenix area wells fall between the Lower–Middle Jurassic fluids from the Browse Basin, the Jurassic fluids from the Beagle Sub-basin, the Permian fluids of the Perth Basin and the Lower Triassic fluids of the Perth Basin (Fig. 2a). Linear alkanes of the Phoenix South 1 oils are on average 1.5‰ more depleted in ¹³C than the Roc 1–2 condensates, which is in agreement with a lower thermal maturity (Clayton and Bjorøy 1994). The alkane carbon isotopic profiles of the Roc 2 gas/condensate pair follow a smooth continuum inferring cogeneration by the same source rock at the same maturity (Boreham et al. 2001).

Fig. 2.  Carbon isotopic compositions of C₁–C₅ gaseous hydrocarbons and C₇–C₃₂ n-alkanes of (a) fluids from the Bedout Sub-basin (red), Browse Basin sourced by Lower–Middle Jurassic source rocks (orange), Beagle Sub-basin (blue), Perth Basin sourced by Permian source rocks (brown), Lower Triassic source rocks (pink) and (b) of source rocks from the Caley Member in Roc 2 (purple) (data from Grosjean et al. 2020b).

Based on the stratigraphic emplacement of the oil and gas discoveries within Lower to Middle Triassic reservoirs between TR10.0_SB and TR17.0_SB (Fig. 1b), Lower to Middle Triassic rocks were investigated for their hydrocarbon source potential using publicly available Rock-Eval pyrolysis data to identify the most suitable candidates for oil to source correlations. Sediments between TR10.0_SB and TR15.0_SB were deposited in a fluvial-deltaic environment with occasional minor marine influences (Abbott et al. 2019; Rollet et al. 2019). In the Bedout Sub-basin, sedimentary rocks that have available geochemical data have a mean total organic carbon (TOC) content of 3.1 wt.% and a mean genetic potential S1 + S2 of 9.4 mg hydrocarbons (HC)/g rock, exhibiting good to excellent hydrocarbon-generating potential. With a mean hydrogen index (HI) of 229 mg HC/g TOC, these source rocks consist mainly of mixed type II/III kerogens and organofacies D/E in the kerogen classification by Pepper and Corvi (1995), capable of generating both oil and gas. However, about one-fifth of the rocks analysed within the Caley Member in Roc 2 stand out as excellent oil-prone source rocks having TOC > 4 wt.% (up to 23.2 wt.%) and HI > 300 mg HC/g TOC (Rollet et al. 2019; Grosjean et al. 2019a). Caley Member shales are enriched in the maceral liptinite, an oil-prone source rock organic component. Liptinite in these shales consists of a mixture of algal-derived lamalginite, marine plankton tasmanitids, brackish–freshwater algae Botryococcus-related telalginite and the land–plant maceral sporinite (Fig. 3a–c) (Ranasinghe and Crosdale 2019). The combination of terrestrial and freshwater/marine algal macerals suggests a deltaic to lagoonal environment, which is supported by detailed sedimentological, ichnological and palynological observations on Roc 2 cores (Allgöwer and Lignum 2019). Pyrolysis products from pyrolysis–gas chromatography are dominated by n-alkenes/n-alkanes pairs extending to long chain lengths, reflecting a prevailing algal contribution and confirming the oil-prone nature of the kerogen (Fig. 3d). The high abundance of aromatic and phenolic compounds among the pyrolysis products indicates a significant land–plant contribution (Larter 1985; Mahlstedt and Horsfield 2019). Bulk kinetics show a narrow activation energy (Ea) distribution (Fig. 3e) consistent with the cracking of mixed aquatic–terrestrial organic matter and petroleum generation occurring between 145°C and 210°C for a geologic heating rate of 3 K/Ma.

Fig. 3.  (a) Distribution of organic macerals in % of abundance in Roc 2 source rocks. (b) Photomicrograph of sample 2808564 (4350.71 mRT) in blue light excitation showing lamalginite, tasmanitids and sporinite. (c) Photomicrograph of sample 2808562 (4349.67 mRT) in blue light excitation Botryococcus-related telalginite. (d) Pyrolysis gas chromatogram of Caley Member kerogen 2808573 (4370.73 mRT). Doublets of n-alkenes/n-alkanes are indicated by their carbon number. T = toluene; X = meta-plus para-xylene. (e) Activation energy distributions of samples 2808563 (4350.46 mRT) and 2808573 (4370.73 mRT) based on heating rates 0.7, 2.0, 5.0 and 15.0 K/min.

With VREQ-5 in the range 0.78–0.81%, the Caley Member source rocks analysed in Roc 2 are not as thermally mature as the fluids. Biomarker distributions are consistent with a mixed marine to terrestrial clastic depositional environment. The carbon isotopic compositions of C₁₄–C₃₂ linear alkanes show values between –29 and –38‰ (Grosjean et al. 2020b), with alkanes isotopic profiles nested in between those of the Lower Triassic Perth Basin oils and the Jurassic-sourced fluids of the Browse Basin, similar to the fluids in Roc 1–2 and Phoenix South 1 (Fig. 2b).

With a mean TOC content of 1.4 wt.% and HI in the range 33–331 mg HC/g TOC in wells of the Bedout Sub-basin, fluvio-deltaic sedimentary rocks between TR15.0_SB and TR16.0_SB are not as organic-rich as the sequence below but the organic matter consists of mixed type II/III kerogen adequately capable of generating oil and gas (Rollet et al. 2019).

Biomarker and isotopic data of the Bedout Sub-basin fluids analysed in this study suggest sourcing from a clastic source rock consistent with a Triassic age and deposition under suboxic/oxic conditions with mixed marine and terrestrial organic matter inputs. The fluid geochemistry in Phoenix South 1 and Roc 1–2 indicates that they represent a new Triassic petroleum system on the western margin of Australia unrelated to the Lower Triassic petroleum system of the Perth Basin. The inferred depositional environment for the source rock is in agreement with derivation from type II/III fluvio-deltaic to lagoonal source rocks present in the Bedout Sub-basin between TR10.0_SB and TR16.0_SB (Rollet et al. 2019). Caley Member source rocks from the Roc 2 well are too immature to have generated the Phoenix South 1 and Roc 1–2 fluids but exhibit carbon isotopic ratios and biomarker distributions correlating broadly with those of the fluids. Sedimentary packages between TR10.0_SB and TR16.0_SB extend to the northwest of the Phoenix South and Roc wells, where they are anticipated to reside in fully mature generative kitchens and provide the effective source of the recovered fluids. The difference in thermal maturity between the Phoenix South 1 oil reservoired in the Barret Member (VREQ-5 = 0.98%) and the Roc 1–2 condensates (mean VREQ-5 = 1.16%) in the deeper Caley Member reservoir suggests derivation from discrete source pods of similar character but of different thermal maturities with the occurrence of stacked source/reservoir pairs separated by intraformational seals (Thompson 2020). This scenario is supported by the presence of a regionally continuous, fine-grained Hove Member providing a top and lateral seal to the Roc and Phoenix South discoveries (Thompson 2020).

The finding of both oil and rich gas condensates in wells of the greater Phoenix area is consistent with hydrogen-rich source rocks of D/E facies. Significantly, D/E sourced fluids are the most susceptible to phase separation as the generation window is close to saturation pressure, which can lead to dual-phase (oil and gas) accumulations (He and Murray 2019). The fluid phase is also controlled by processes such as spill-fill, leakage and in-reservoir alteration (Murray and He 2020). The Phoenix South 1 oil accumulation is undersaturated with respect to gas, which suggests that loss of gas has enriched the remaining fluid in heavy hydrocarbons resulting in the formation of oil. Supplementary work on the Dorado fluids will further improve the understanding of this significant new petroleum system on the NWS of Australia.

All authors confirm there are no conflicts of interest.

No funding from external organisations was received for this research.