Geoscience Australia has begun a systematic evaluation of the shale gas/oil (unconventional) resource potential of Australia's onshore sedimentary basins. According to the Australian Gas Resource Assessment 2012 [1] Australia's unconventional gas resource endowment is likely to be greater than its estimated total conventional gas resources with some basins likely to have significant unconventional oil potential. An assessment of Australia's unconventional resource potential will use methodology developed by the United States Geological Survey based on statistically derived estimates of hydrocarbon recovery from actual production data, or basin analogues in data-poor areas. The Georgina Basin, containing Proterozoic-Paleozoic age sediments and covering an area of ~325,000 sq. km in south-central Australia, is the first basin to be assessed and since there is no petroleum production history, suitable analogues will be sought. The assessment also relies heavily on the updated stratigraphy, tectonic history, petrography, geochemistry and petroleum systems modelling, with a discussion emphasis on the latter two datasets. The Georgina Basin is host to basin-wide oil staining and contains proven petroleum systems with relative short migration distances from source to trap, which likely represent multiple hybrid unconventional systems and breached conventional reservoirs. For example, the result of localised migration is exemplified in the composition of residual free hydrocarbons from organic-rich mudstones in which light and heavy hydrocarbons were recorded in samples 3 m apart. The most prolific oil-prone effective sources occur in the Middle Cambrian Thorntonia Limestone (early to middle Ordian) and overlying Arthur Creek Formation (latest Ordian to late Boomerangian). These source rocks were diachronously deposited from west to east under marine anoxic bottom waters, which periodically extended into the photic zone, and represent the local expression of a prolonged Middle-Late Cambrian oceanic anoxic event that lead to deposition of organic-rich 'black shales' on a global scale. The oil stains are varyingly altered by biodegradation and are geochemically characterised by a strong isotopic depletion in 13C, high abundance of monomethylalkanes, C15-C23 odd carbon number predominance for n-alkylcyclohexanes, C27 slightly dominant over C29 desmethylsteranes and high content of tricyclic terpanes. Source richness and maturity estimates are derived from Rock Eval, saturated and aromatic hydrocarbons, FAMM and hydrogen isotopic relationships between n-alkanes and isoprenoids. For example, the 'hot shale' unit comprising predominately dolostone at the base of the Arthur Creek Formation, currently the focus of drilling activity for unconventional hydrocarbons, has TOC and HI up to 15.5 % and 500 mg hydrocarbons/g TOC, respectively. Maturity levels range from the early oil to early dry gas windows. This unit appears to have all the geochemical pre-requesites for a significant unconventional hydrocarbon play. Geohistory modelling using formation-specific compositional kinetics indicates petroleum generation and expulsion begins in the latest Cambrian-Early Ordovician due to relatively rapid burial of the Arthur Creek Formation. Deposition ends with the start of the Alice Springs Orogeny and following uplift and erosion during the Devonian, hydrocarbon generation ceases. An unconventional petroleum resource assessment of the Georgina Basin will be undertaken in February 2013 and available for benchmarking and refinement against any future shale gas and shale oil production. [1] Geoscience Australia and Bureau of Resource and Energy Economics, 2012, Australian Gas Resource Assessment 2012, Canberra, 56 p. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=74032

Geoscience Australia has begun a systematic evaluation of the shale gas/oil (unconventional) resource potential of Australia's onshore sedimentary basins. According to the Australian Gas Resource Assessment 2012 [1] Australia's unconventional gas resource endowment is likely to be greater than its estimated total conventional gas resources with some basins likely to have significant unconventional oil potential. An assessment of Australia's unconventional resource potential will use methodology developed by the United States Geological Survey based on statistically derived estimates of hydrocarbon recovery from actual production data, or basin analogues in data-poor areas. The Georgina Basin, containing Proterozoic-Paleozoic age sediments and covering an area of ~325,000 sq. km in south-central Australia, is the first basin to be assessed and since there is no petroleum production history, suitable analogues will be sought. The assessment also relies heavily on the updated stratigraphy, tectonic history, petrography, geochemistry and petroleum systems modelling, with a discussion emphasis on the latter two datasets. The Georgina Basin is host to basin-wide oil staining and contains proven petroleum systems with relative short migration distances from source to trap, which likely represent multiple hybrid unconventional systems and breached conventional reservoirs. For example, the result of localised migration is exemplified in the composition of residual free hydrocarbons from organic-rich mudstones in which light and heavy hydrocarbons were recorded in samples 3 m apart. The most prolific oil-prone effective sources occur in the Middle Cambrian Thorntonia Limestone (early to middle Ordian) and overlying Arthur Creek Formation (latest Ordian to late Boomerangian). These source rocks were diachronously deposited from west to east under marine anoxic bottom waters, which periodically extended into the photic zone, and represent the local expression of a prolonged Middle-Late Cambrian oceanic anoxic event that lead to deposition of organic-rich 'black shales' on a global scale. The oil stains are varyingly altered by biodegradation and are geochemically characterised by a strong isotopic depletion in 13C, high abundance of monomethylalkanes, C15-C23 odd carbon number predominance for n-alkylcyclohexanes, C27 slightly dominant over C29 desmethylsteranes and high content of tricyclic terpanes. Source richness and maturity estimates are derived from Rock Eval, saturated and aromatic hydrocarbons, FAMM and hydrogen isotopic relationships between n-alkanes and isoprenoids. For example, the 'hot shale' unit comprising predominately dolostone at the base of the Arthur Creek Formation, currently the focus of drilling activity for unconventional hydrocarbons, has TOC and HI up to 15.5 % and 500 mg hydrocarbons/g TOC, respectively. Maturity levels range from the early oil to early dry gas windows. This unit appears to have all the geochemical pre-requesites for a significant unconventional hydrocarbon play. Geohistory modelling using formation-specific compositional kinetics indicates petroleum generation and expulsion begins in the latest Cambrian-Early Ordovician due to relatively rapid burial of the Arthur Creek Formation. Deposition ends with the start of the Alice Springs Orogeny and following uplift and erosion during the Devonian, hydrocarbon generation ceases. An unconventional petroleum resource assessment of the Georgina Basin will be undertaken in February 2013 and available for benchmarking and refinement against any future shale gas and shale oil production. [1] Geoscience Australia and Bureau of Resource and Energy Economics, 2012, Australian Gas Resource Assessment 2012, Canberra, 56 p. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=74032

Geoscience Australia has begun a systematic evaluation of the shale gas/oil (unconventional) resource potential of Australia's onshore sedimentary basins. According to the Australian Gas Resource Assessment 2012 [1] Australia's unconventional gas resource endowment is likely to be greater than its estimated total conventional gas resources with some basins likely to have significant unconventional oil potential. An assessment of Australia's unconventional resource potential will use methodology developed by the United States Geological Survey based on statistically derived estimates of hydrocarbon recovery from actual production data, or basin analogues in data-poor areas. The Georgina Basin, containing Proterozoic-Paleozoic age sediments and covering an area of ~325,000 sq. km in south-central Australia, is the first basin to be assessed and since there is no petroleum production history, suitable analogues will be sought. The assessment also relies heavily on the updated stratigraphy, tectonic history, petrography, geochemistry and petroleum systems modelling, with a discussion emphasis on the latter two datasets. The Georgina Basin is host to basin-wide oil staining and contains proven petroleum systems with relative short migration distances from source to trap, which likely represent multiple hybrid unconventional systems and breached conventional reservoirs. For example, the result of localised migration is exemplified in the composition of residual free hydrocarbons from organic-rich mudstones in which light and heavy hydrocarbons were recorded in samples 3 m apart. The most prolific oil-prone effective sources occur in the Middle Cambrian Thorntonia Limestone (early to middle Ordian) and overlying Arthur Creek Formation (latest Ordian to late Boomerangian). These source rocks were diachronously deposited from west to east under marine anoxic bottom waters, which periodically extended into the photic zone, and represent the local expression of a prolonged Middle-Late Cambrian oceanic anoxic event that lead to deposition of organic-rich 'black shales' on a global scale. The oil stains are varyingly altered by biodegradation and are geochemically characterised by a strong isotopic depletion in 13C, high abundance of monomethylalkanes, C15-C23 odd carbon number predominance for n-alkylcyclohexanes, C27 slightly dominant over C29 desmethylsteranes and high content of tricyclic terpanes. Source richness and maturity estimates are derived from Rock Eval, saturated and aromatic hydrocarbons, FAMM and hydrogen isotopic relationships between n-alkanes and isoprenoids. For example, the 'hot shale' unit comprising predominately dolostone at the base of the Arthur Creek Formation, currently the focus of drilling activity for unconventional hydrocarbons, has TOC and HI up to 15.5 % and 500 mg hydrocarbons/g TOC, respectively. Maturity levels range from the early oil to early dry gas windows. This unit appears to have all the geochemical pre-requesites for a significant unconventional hydrocarbon play. Geohistory modelling using formation-specific compositional kinetics indicates petroleum generation and expulsion begins in the latest Cambrian-Early Ordovician due to relatively rapid burial of the Arthur Creek Formation. Deposition ends with the start of the Alice Springs Orogeny and following uplift and erosion during the Devonian, hydrocarbon generation ceases. An unconventional petroleum resource assessment of the Georgina Basin will be undertaken in February 2013 and available for benchmarking and refinement against any future shale gas and shale oil production. [1] Geoscience Australia and Bureau of Resource and Energy Economics, 2012, Australian Gas Resource Assessment 2012, Canberra, 56 p. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=74032

Geoscience Australia has begun a systematic evaluation of the shale gas/oil (unconventional) resource potential of Australia's onshore sedimentary basins. According to the Australian Gas Resource Assessment 2012 [1] Australia's unconventional gas resource endowment is likely to be greater than its estimated total conventional gas resources with some basins likely to have significant unconventional oil potential. An assessment of Australia's unconventional resource potential will use methodology developed by the United States Geological Survey based on statistically derived estimates of hydrocarbon recovery from actual production data, or basin analogues in data-poor areas. The Georgina Basin, containing Proterozoic-Paleozoic age sediments and covering an area of ~325,000 sq. km in south-central Australia, is the first basin to be assessed and since there is no petroleum production history, suitable analogues will be sought. The assessment also relies heavily on the updated stratigraphy, tectonic history, petrography, geochemistry and petroleum systems modelling, with a discussion emphasis on the latter two datasets. The Georgina Basin is host to basin-wide oil staining and contains proven petroleum systems with relative short migration distances from source to trap, which likely represent multiple hybrid unconventional systems and breached conventional reservoirs. For example, the result of localised migration is exemplified in the composition of residual free hydrocarbons from organic-rich mudstones in which light and heavy hydrocarbons were recorded in samples 3 m apart. The most prolific oil-prone effective sources occur in the Middle Cambrian Thorntonia Limestone (early to middle Ordian) and overlying Arthur Creek Formation (latest Ordian to late Boomerangian). These source rocks were diachronously deposited from west to east under marine anoxic bottom waters, which periodically extended into the photic zone, and represent the local expression of a prolonged Middle-Late Cambrian oceanic anoxic event that lead to deposition of organic-rich 'black shales' on a global scale. The oil stains are varyingly altered by biodegradation and are geochemically characterised by a strong isotopic depletion in 13C, high abundance of monomethylalkanes, C15-C23 odd carbon number predominance for n-alkylcyclohexanes, C27 slightly dominant over C29 desmethylsteranes and high content of tricyclic terpanes. Source richness and maturity estimates are derived from Rock Eval, saturated and aromatic hydrocarbons, FAMM and hydrogen isotopic relationships between n-alkanes and isoprenoids. For example, the 'hot shale' unit comprising predominately dolostone at the base of the Arthur Creek Formation, currently the focus of drilling activity for unconventional hydrocarbons, has TOC and HI up to 15.5 % and 500 mg hydrocarbons/g TOC, respectively. Maturity levels range from the early oil to early dry gas windows. This unit appears to have all the geochemical pre-requesites for a significant unconventional hydrocarbon play. Geohistory modelling using formation-specific compositional kinetics indicates petroleum generation and expulsion begins in the latest Cambrian-Early Ordovician due to relatively rapid burial of the Arthur Creek Formation. Deposition ends with the start of the Alice Springs Orogeny and following uplift and erosion during the Devonian, hydrocarbon generation ceases. An unconventional petroleum resource assessment of the Georgina Basin will be undertaken in February 2013 and available for benchmarking and refinement against any future shale gas and shale oil production. [1] Geoscience Australia and Bureau of Resource and Energy Economics, 2012, Australian Gas Resource Assessment 2012, Canberra, 56 p. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=74032

Geoscience Australia has begun a systematic evaluation of the shale gas/oil (unconventional) resource potential of Australia's onshore sedimentary basins. According to the Australian Gas Resource Assessment 2012 [1] Australia's unconventional gas resource endowment is likely to be greater than its estimated total conventional gas resources with some basins likely to have significant unconventional oil potential. An assessment of Australia's unconventional resource potential will use methodology developed by the United States Geological Survey based on statistically derived estimates of hydrocarbon recovery from actual production data, or basin analogues in data-poor areas. The Georgina Basin, containing Proterozoic-Paleozoic age sediments and covering an area of ~325,000 sq. km in south-central Australia, is the first basin to be assessed and since there is no petroleum production history, suitable analogues will be sought. The assessment also relies heavily on the updated stratigraphy, tectonic history, petrography, geochemistry and petroleum systems modelling, with a discussion emphasis on the latter two datasets. The Georgina Basin is host to basin-wide oil staining and contains proven petroleum systems with relative short migration distances from source to trap, which likely represent multiple hybrid unconventional systems and breached conventional reservoirs. For example, the result of localised migration is exemplified in the composition of residual free hydrocarbons from organic-rich mudstones in which light and heavy hydrocarbons were recorded in samples 3 m apart. The most prolific oil-prone effective sources occur in the Middle Cambrian Thorntonia Limestone (early to middle Ordian) and overlying Arthur Creek Formation (latest Ordian to late Boomerangian). These source rocks were diachronously deposited from west to east under marine anoxic bottom waters, which periodically extended into the photic zone, and represent the local expression of a prolonged Middle-Late Cambrian oceanic anoxic event that lead to deposition of organic-rich 'black shales' on a global scale. The oil stains are varyingly altered by biodegradation and are geochemically characterised by a strong isotopic depletion in 13C, high abundance of monomethylalkanes, C15-C23 odd carbon number predominance for n-alkylcyclohexanes, C27 slightly dominant over C29 desmethylsteranes and high content of tricyclic terpanes. Source richness and maturity estimates are derived from Rock Eval, saturated and aromatic hydrocarbons, FAMM and hydrogen isotopic relationships between n-alkanes and isoprenoids. For example, the 'hot shale' unit comprising predominately dolostone at the base of the Arthur Creek Formation, currently the focus of drilling activity for unconventional hydrocarbons, has TOC and HI up to 15.5 % and 500 mg hydrocarbons/g TOC, respectively. Maturity levels range from the early oil to early dry gas windows. This unit appears to have all the geochemical pre-requesites for a significant unconventional hydrocarbon play. Geohistory modelling using formation-specific compositional kinetics indicates petroleum generation and expulsion begins in the latest Cambrian-Early Ordovician due to relatively rapid burial of the Arthur Creek Formation. Deposition ends with the start of the Alice Springs Orogeny and following uplift and erosion during the Devonian, hydrocarbon generation ceases. An unconventional petroleum resource assessment of the Georgina Basin will be undertaken in February 2013 and available for benchmarking and refinement against any future shale gas and shale oil production. [1] Geoscience Australia and Bureau of Resource and Energy Economics, 2012, Australian Gas Resource Assessment 2012, Canberra, 56 p. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=74032

The Browse Basin, located offshore on Australia¿s North West Shelf, is a proven hydrocarbon province that hosts large gas accumulations with associated condensate. Small light oil accumulations are found mostly within the Cretaceous succession. Geoscience Australia undertook a multi-disciplinary study of the Browse Basin to better understand the regional hydrocarbon prospectivity and high-grade areas with increased liquids potential in Cretaceous supersequences. The sequence stratigraphy and structural framework of the Cretaceous succession were analysed to determine the spatial relationship of reservoir and seal pairs, and areas of source rock development. Updated biostratigraphy, well lithology and log analysis, seismic stratal geometry, facies, palaeogeographic and play fairway interpretations were completed for seven supersequences from the late Tithonian to Maastrichtian (K10¿K60 supersequences). These data, together with geochemical studies of source rocks and fluids (gases and liquids), were integrated in a regional petroleum systems model to better understand source rock distribution, character, generation potential, and play prospectivity. The regional deposition of the Permo-Carboniferous, Triassic, Jurassic and Cenozoic successions were mapped to constrain the burial history model. Supersequence cross-sections and palaeogeographic maps show the distribution of gross depositional facies, revealing three main Cretaceous stratigraphic play types across the basin. These are basin-margin, clinoform topset and submarine fan plays. Geochemical analyses using molecular and stable carbon and hydrogen isotopic signatures correlate fluids in these plays with potential source rocks. The geochemical fingerprints enabled the identification of four Mesozoic petroleum systems. Burial history modelling demonstrates hydrocarbon generation from potential source rocks within the Jurassic and Lower Cretaceous supersequences. Many accumulations have a complex charge history with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, as recognised from the deconvolution of their geochemical compositions. The basin margin play occurs within the K10¿K40 supersequences (Early Cretaceous upper Vulcan and Echuca Shoals formations) along the inboard Yampi and Leveque shelves. The K20¿K30 (Echuca Shoals Formation) basin margin play received gas (Caspar 1A) potentially sourced from the J10¿J20 supersequences (Plover Formation) and oil (Gwydion 1) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). Seal quality and thickness are good except where the seal facies pinch out around basement highs on the Yampi Shelf, and where they are truncated by the K50 sequence boundary (Wangarlu Formation) inboard on the Leveque Shelf. The K40 basin margin play (Jamieson Formation) received gas (Gwydion 1, Cornea field) that is most likely sourced from the J10¿J20 supersequences (Plover Formation) and oil (Cornea field) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). The marine shales in the K20¿K30 supersequences (Echuca Shoals Formation) have low hydrogen indices (~200 mg hydrocarbons/gTOC) and hence may only be able to expel sufficient hydrocarbons to sustain migration over short distances. The co-existence of oil sourced from these successions and gas sourced from the J10¿J20 supersequences (Plover Formation) suggests that potential Cretaceous-sourced liquids were mobilised and carried to the shelf edge by co-migrating Early¿Middle Jurassic Plover-derived gas. Once present within these shallow reservoirs, further loss of the low and mid-chain hydrocarbons occurred through leakage, water washing and biodegradation. Together, the migration and secondary alteration processes have enhanced the liquids potential on the basin margin. The clinoform topset play extends between the basin-margin and the shelf-edge. These plays consist of higher order progradational sandstone units overlain by intraformational

The Browse Basin, located offshore on Australia¿s North West Shelf, is a proven hydrocarbon province that hosts large gas accumulations with associated condensate. Small light oil accumulations are found mostly within the Cretaceous succession. Geoscience Australia undertook a multi-disciplinary study of the Browse Basin to better understand the regional hydrocarbon prospectivity and high-grade areas with increased liquids potential in Cretaceous supersequences. The sequence stratigraphy and structural framework of the Cretaceous succession were analysed to determine the spatial relationship of reservoir and seal pairs, and areas of source rock development. Updated biostratigraphy, well lithology and log analysis, seismic stratal geometry, facies, palaeogeographic and play fairway interpretations were completed for seven supersequences from the late Tithonian to Maastrichtian (K10¿K60 supersequences). These data, together with geochemical studies of source rocks and fluids (gases and liquids), were integrated in a regional petroleum systems model to better understand source rock distribution, character, generation potential, and play prospectivity. The regional deposition of the Permo-Carboniferous, Triassic, Jurassic and Cenozoic successions were mapped to constrain the burial history model. Supersequence cross-sections and palaeogeographic maps show the distribution of gross depositional facies, revealing three main Cretaceous stratigraphic play types across the basin. These are basin-margin, clinoform topset and submarine fan plays. Geochemical analyses using molecular and stable carbon and hydrogen isotopic signatures correlate fluids in these plays with potential source rocks. The geochemical fingerprints enabled the identification of four Mesozoic petroleum systems. Burial history modelling demonstrates hydrocarbon generation from potential source rocks within the Jurassic and Lower Cretaceous supersequences. Many accumulations have a complex charge history with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, as recognised from the deconvolution of their geochemical compositions. The basin margin play occurs within the K10¿K40 supersequences (Early Cretaceous upper Vulcan and Echuca Shoals formations) along the inboard Yampi and Leveque shelves. The K20¿K30 (Echuca Shoals Formation) basin margin play received gas (Caspar 1A) potentially sourced from the J10¿J20 supersequences (Plover Formation) and oil (Gwydion 1) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). Seal quality and thickness are good except where the seal facies pinch out around basement highs on the Yampi Shelf, and where they are truncated by the K50 sequence boundary (Wangarlu Formation) inboard on the Leveque Shelf. The K40 basin margin play (Jamieson Formation) received gas (Gwydion 1, Cornea field) that is most likely sourced from the J10¿J20 supersequences (Plover Formation) and oil (Cornea field) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). The marine shales in the K20¿K30 supersequences (Echuca Shoals Formation) have low hydrogen indices (~200 mg hydrocarbons/gTOC) and hence may only be able to expel sufficient hydrocarbons to sustain migration over short distances. The co-existence of oil sourced from these successions and gas sourced from the J10¿J20 supersequences (Plover Formation) suggests that potential Cretaceous-sourced liquids were mobilised and carried to the shelf edge by co-migrating Early¿Middle Jurassic Plover-derived gas. Once present within these shallow reservoirs, further loss of the low and mid-chain hydrocarbons occurred through leakage, water washing and biodegradation. Together, the migration and secondary alteration processes have enhanced the liquids potential on the basin margin. The clinoform topset play extends between the basin-margin and the shelf-edge. These plays consist of higher order progradational sandstone units overlain by intraformational

The Browse Basin, located offshore on Australia¿s North West Shelf, is a proven hydrocarbon province that hosts large gas accumulations with associated condensate. Small light oil accumulations are found mostly within the Cretaceous succession. Geoscience Australia undertook a multi-disciplinary study of the Browse Basin to better understand the regional hydrocarbon prospectivity and high-grade areas with increased liquids potential in Cretaceous supersequences. The sequence stratigraphy and structural framework of the Cretaceous succession were analysed to determine the spatial relationship of reservoir and seal pairs, and areas of source rock development. Updated biostratigraphy, well lithology and log analysis, seismic stratal geometry, facies, palaeogeographic and play fairway interpretations were completed for seven supersequences from the late Tithonian to Maastrichtian (K10¿K60 supersequences). These data, together with geochemical studies of source rocks and fluids (gases and liquids), were integrated in a regional petroleum systems model to better understand source rock distribution, character, generation potential, and play prospectivity. The regional deposition of the Permo-Carboniferous, Triassic, Jurassic and Cenozoic successions were mapped to constrain the burial history model. Supersequence cross-sections and palaeogeographic maps show the distribution of gross depositional facies, revealing three main Cretaceous stratigraphic play types across the basin. These are basin-margin, clinoform topset and submarine fan plays. Geochemical analyses using molecular and stable carbon and hydrogen isotopic signatures correlate fluids in these plays with potential source rocks. The geochemical fingerprints enabled the identification of four Mesozoic petroleum systems. Burial history modelling demonstrates hydrocarbon generation from potential source rocks within the Jurassic and Lower Cretaceous supersequences. Many accumulations have a complex charge history with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, as recognised from the deconvolution of their geochemical compositions. The basin margin play occurs within the K10¿K40 supersequences (Early Cretaceous upper Vulcan and Echuca Shoals formations) along the inboard Yampi and Leveque shelves. The K20¿K30 (Echuca Shoals Formation) basin margin play received gas (Caspar 1A) potentially sourced from the J10¿J20 supersequences (Plover Formation) and oil (Gwydion 1) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). Seal quality and thickness are good except where the seal facies pinch out around basement highs on the Yampi Shelf, and where they are truncated by the K50 sequence boundary (Wangarlu Formation) inboard on the Leveque Shelf. The K40 basin margin play (Jamieson Formation) received gas (Gwydion 1, Cornea field) that is most likely sourced from the J10¿J20 supersequences (Plover Formation) and oil (Cornea field) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). The marine shales in the K20¿K30 supersequences (Echuca Shoals Formation) have low hydrogen indices (~200 mg hydrocarbons/gTOC) and hence may only be able to expel sufficient hydrocarbons to sustain migration over short distances. The co-existence of oil sourced from these successions and gas sourced from the J10¿J20 supersequences (Plover Formation) suggests that potential Cretaceous-sourced liquids were mobilised and carried to the shelf edge by co-migrating Early¿Middle Jurassic Plover-derived gas. Once present within these shallow reservoirs, further loss of the low and mid-chain hydrocarbons occurred through leakage, water washing and biodegradation. Together, the migration and secondary alteration processes have enhanced the liquids potential on the basin margin. The clinoform topset play extends between the basin-margin and the shelf-edge. These plays consist of higher order progradational sandstone units overlain by intraformational

The Browse Basin, located offshore on Australia¿s North West Shelf, is a proven hydrocarbon province that hosts large gas accumulations with associated condensate. Small light oil accumulations are found mostly within the Cretaceous succession. Geoscience Australia undertook a multi-disciplinary study of the Browse Basin to better understand the regional hydrocarbon prospectivity and high-grade areas with increased liquids potential in Cretaceous supersequences. The sequence stratigraphy and structural framework of the Cretaceous succession were analysed to determine the spatial relationship of reservoir and seal pairs, and areas of source rock development. Updated biostratigraphy, well lithology and log analysis, seismic stratal geometry, facies, palaeogeographic and play fairway interpretations were completed for seven supersequences from the late Tithonian to Maastrichtian (K10¿K60 supersequences). These data, together with geochemical studies of source rocks and fluids (gases and liquids), were integrated in a regional petroleum systems model to better understand source rock distribution, character, generation potential, and play prospectivity. The regional deposition of the Permo-Carboniferous, Triassic, Jurassic and Cenozoic successions were mapped to constrain the burial history model. Supersequence cross-sections and palaeogeographic maps show the distribution of gross depositional facies, revealing three main Cretaceous stratigraphic play types across the basin. These are basin-margin, clinoform topset and submarine fan plays. Geochemical analyses using molecular and stable carbon and hydrogen isotopic signatures correlate fluids in these plays with potential source rocks. The geochemical fingerprints enabled the identification of four Mesozoic petroleum systems. Burial history modelling demonstrates hydrocarbon generation from potential source rocks within the Jurassic and Lower Cretaceous supersequences. Many accumulations have a complex charge history with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, as recognised from the deconvolution of their geochemical compositions. The basin margin play occurs within the K10¿K40 supersequences (Early Cretaceous upper Vulcan and Echuca Shoals formations) along the inboard Yampi and Leveque shelves. The K20¿K30 (Echuca Shoals Formation) basin margin play received gas (Caspar 1A) potentially sourced from the J10¿J20 supersequences (Plover Formation) and oil (Gwydion 1) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). Seal quality and thickness are good except where the seal facies pinch out around basement highs on the Yampi Shelf, and where they are truncated by the K50 sequence boundary (Wangarlu Formation) inboard on the Leveque Shelf. The K40 basin margin play (Jamieson Formation) received gas (Gwydion 1, Cornea field) that is most likely sourced from the J10¿J20 supersequences (Plover Formation) and oil (Cornea field) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). The marine shales in the K20¿K30 supersequences (Echuca Shoals Formation) have low hydrogen indices (~200 mg hydrocarbons/gTOC) and hence may only be able to expel sufficient hydrocarbons to sustain migration over short distances. The co-existence of oil sourced from these successions and gas sourced from the J10¿J20 supersequences (Plover Formation) suggests that potential Cretaceous-sourced liquids were mobilised and carried to the shelf edge by co-migrating Early¿Middle Jurassic Plover-derived gas. Once present within these shallow reservoirs, further loss of the low and mid-chain hydrocarbons occurred through leakage, water washing and biodegradation. Together, the migration and secondary alteration processes have enhanced the liquids potential on the basin margin. The clinoform topset play extends between the basin-margin and the shelf-edge. These plays consist of higher order progradational sandstone units overlain by intraformational

The Browse Basin, located offshore on Australia¿s North West Shelf, is a proven hydrocarbon province that hosts large gas accumulations with associated condensate. Small light oil accumulations are found mostly within the Cretaceous succession. Geoscience Australia undertook a multi-disciplinary study of the Browse Basin to better understand the regional hydrocarbon prospectivity and high-grade areas with increased liquids potential in Cretaceous supersequences. The sequence stratigraphy and structural framework of the Cretaceous succession were analysed to determine the spatial relationship of reservoir and seal pairs, and areas of source rock development. Updated biostratigraphy, well lithology and log analysis, seismic stratal geometry, facies, palaeogeographic and play fairway interpretations were completed for seven supersequences from the late Tithonian to Maastrichtian (K10¿K60 supersequences). These data, together with geochemical studies of source rocks and fluids (gases and liquids), were integrated in a regional petroleum systems model to better understand source rock distribution, character, generation potential, and play prospectivity. The regional deposition of the Permo-Carboniferous, Triassic, Jurassic and Cenozoic successions were mapped to constrain the burial history model. Supersequence cross-sections and palaeogeographic maps show the distribution of gross depositional facies, revealing three main Cretaceous stratigraphic play types across the basin. These are basin-margin, clinoform topset and submarine fan plays. Geochemical analyses using molecular and stable carbon and hydrogen isotopic signatures correlate fluids in these plays with potential source rocks. The geochemical fingerprints enabled the identification of four Mesozoic petroleum systems. Burial history modelling demonstrates hydrocarbon generation from potential source rocks within the Jurassic and Lower Cretaceous supersequences. Many accumulations have a complex charge history with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, as recognised from the deconvolution of their geochemical compositions. The basin margin play occurs within the K10¿K40 supersequences (Early Cretaceous upper Vulcan and Echuca Shoals formations) along the inboard Yampi and Leveque shelves. The K20¿K30 (Echuca Shoals Formation) basin margin play received gas (Caspar 1A) potentially sourced from the J10¿J20 supersequences (Plover Formation) and oil (Gwydion 1) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). Seal quality and thickness are good except where the seal facies pinch out around basement highs on the Yampi Shelf, and where they are truncated by the K50 sequence boundary (Wangarlu Formation) inboard on the Leveque Shelf. The K40 basin margin play (Jamieson Formation) received gas (Gwydion 1, Cornea field) that is most likely sourced from the J10¿J20 supersequences (Plover Formation) and oil (Cornea field) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). The marine shales in the K20¿K30 supersequences (Echuca Shoals Formation) have low hydrogen indices (~200 mg hydrocarbons/gTOC) and hence may only be able to expel sufficient hydrocarbons to sustain migration over short distances. The co-existence of oil sourced from these successions and gas sourced from the J10¿J20 supersequences (Plover Formation) suggests that potential Cretaceous-sourced liquids were mobilised and carried to the shelf edge by co-migrating Early¿Middle Jurassic Plover-derived gas. Once present within these shallow reservoirs, further loss of the low and mid-chain hydrocarbons occurred through leakage, water washing and biodegradation. Together, the migration and secondary alteration processes have enhanced the liquids potential on the basin margin. The clinoform topset play extends between the basin-margin and the shelf-edge. These plays consist of higher order progradational sandstone units overlain by intraformational