Hydrocarbon fluid correlation studies often rely on compounds that are source-specific, but only represent a minor fraction of the bulk fluid (e.g. steranes). The correlation in the present study utilises compounds that represent a significant proportion of the bulk fluid (semi-volatile aromatics (SVA)) and diamondoids. Comprehensive two dimensional gas chromatography coupled to time-of-flight mass spectrometry (GC × GC-TOFMS) was used to analyse diamondoids and SVA in whole oil/condensate samples from the Browse Basin, North West Shelf, Australia. Together with aromatic maturity ratios and the stable carbon isotopic composition for selected diamondoids and alkylbenzenes, these analyses demonstrate that numerous accumulations within the Browse Basin contain hydrocarbons from mixed sources. The diamondoid and SVA data provides further information on the current hydrocarbon fluid discrimination, which is primarily based on saturated biomarker compositions. Results of this study reveal a complex fill history by identifying the presence of a high maturity fluid(s) in the biodegraded accumulations on the Yampi Shelf, i.e. in the greater Cornea field and at Gwydion-1. This high maturity fluid is most likely derived from the Lower–Middle Jurassic Plover Formation (J10–J20 supersequences) in the greater Cornea area and, in the case of Gwydion-1, additional hydrocarbons may also be derived from the Upper Jurassic Vulcan Formation (J30–K10 supersequences). Other accumulations that comprise mixtures include Mimia-1 and Concerto-1 ST1 Deep, located to the north of the Ichthys field, and could represent charge from several Jurassic source rocks. The most mature fluids analysed in this basin are family II Plover-sourced and reservoired condensates from Kronos-1, Dinichthys North-1 and Gorgonichthys-1, as demonstrated by their elevated concentrations of the methyladamantanes and methyldiamantanes. The Dinichthys North-1 and Gorgonichthys-1 condensates also show a significant enrichment in the δ13C compound-specific values of the di-, tri- and tetra-methylbenzenes, whereas the Kronos-1 condensate does not, suggesting derivation from different source kitchens.

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 and top seals. The K10 clinoform topset play (namely the Brewster Member of the Upper Vulcan Formation) hosts gas in the Ichthys/Prelude and Burnside accumulations. The gas is probably largely sourced from the organic-rich shales of the J30¿K10 supersequences (Vulcan Formation), with an additional contribution from the J10¿J20 supersequences (Plover Formation) in satellite fields, such as observed at Concerto 1 ST1. Other similar K10 plays are mapped in the southern Caswell and Oobagooma sub-basins and could receive charge from J30¿K10 potential source pods. The K30 clinoform topset play (M. australis sand of the Echuca Shoals Formation) is a reservoir for gas on the Leveque Shelf at Psepotus 1, with additional evidence for oil migration into this play at Braveheart 1 in the northern Caswell Sub-basin. This play extends in underexplored areas on the Leveque Shelf to the inboard Barcoo Sub-basin and on the southern Yampi Shelf to the outboard Caswell Sub-basin. The K40 clinoform topset play (D. davidii sand of the Jamieson Formation) hosts gas (Adele 1) and light oil (Caswell 1). The light oil is probably sourced primarily from the K20¿K30 supersequences (Echuca Shoals Formation) in the central Caswell Sub-basin. This play extends outboard in the Caswell Sub-basin to Caswell 2 ST2 and Phrixus 1. The submarine fan play comprises sandstone-prone basin floor fans that extend across the basin floor from the toe of the slope and are sealed by down-lapping mudstone facies. This play may overlie either second, third, fourth or fifth-order sequence boundaries and are particularly well developed within the Upper Cretaceous K60 supersequence (Wangarlu Formation). The K30 submarine fan play (Echuca Shoals Formation) hosts gas in the outboard northern Caswell Sub-basin (Abalone Deep 1 and Adele 1). Isotopic evidence for the gas at Adele 1 suggests that the K20¿K30 supersequences (Echuca Shoals Formation) is the most likely source. This play is underexplored elsewhere within the basin, but it includes the tentatively interpreted play around Omar 1 in the Barcoo Sub-basin. There is evidence for oil migration through the K50 (Wangarlu Formation) submarine fan play at Discorbis 1, with the source of hydrocarbons possibly being from the K20¿K30 supersequences (Echuca Shoals Formation). This play extends into the inboard northern Caswell Sub-basin. The K60 submarine fan (Wangarlu Formation) play either hosts oil and gas (Abalone 1, Caswell 2 and Marabou 1) or contains evidence of hydrocarbon migration (Discorbis 1 and Gryphaea 1) in numerous wells. The most likely source of petroleum is from the K20¿K30 supersequences (Echuca Shoals Formation). The results of this study reveal the existence of multiple stacked Cretaceous plays in the basin, including those in underexplored vacant acreage. Presented at the 2017 Southeast Asia Petroleum Exploration Society (SEAPEX) Conference

The Browse Basin is located offshore on Australia's North West Shelf and is a proven hydrocarbon province hosting gas with associated condensate and where oil reserves are typically small. The assessment of a basin's oil potential traditionally focuses on the presence or absence of oil-prone source rocks. However, light oil can be found in basins where source rocks are gas-prone and the primary hydrocarbon type is gas-condensate. Oil rims form whenever such fluids migrate into reservoirs at pressures less than their dew point (saturation) pressure. By combining petroleum systems analysis with geochemical studies of source rocks and fluids (gases and liquids), four Mesozoic petroleum systems have been identified in the basin. This study applies petroleum systems analysis to understand the source of fluids and their phase behaviour in the Browse Basin. Source rock richness, thickness and quality are mapped from well control. Petroleum systems modelling that integrates source rock property maps, basin-specific kinetics, 1D burial history models and regional 3D surfaces, provides new insights into source rock maturity, generation and expelled fluid composition. The principal source rocks are Early-Middle Jurassic fluvio-deltaic coaly shales and shales within the J10-J20 supersequences (Plover Formation), Middle-Late Jurassic to Early Cretaceous sub-oxic marine shales within the J30-K10 supersequences (Vulcan and Montara formations) and K20-K30 supersequences (Echuca Shoals Formation). All of these source rocks contain significant contributions of land-plant derived organic matter and within the Caswell Sub-basin have reached sufficient maturities to have transformed most of the kerogen into hydrocarbons, with the majority of expulsion occurring from the Late Cretaceous until present.

The Browse Basin hosts considerable gas and condensate resources, including the Ichthys and Prelude fields that are being developed for liquefied natural gas (LNG) production. Oil discoveries are sub-economic. This multi-disciplinary study integrating sequence stratigraphy, palaeogeography and geochemical data has mapped the spatial and temporal distribution of Jurassic to earliest Cretaceous source rocks. This study allows a better understanding of the source rocks contribution to the known hydrocarbon accumulations and charge history in the basin, including in underexplored areas. The Jurassic to earliest Cretaceous source rocks have been identified as being the primary sources of the gases and condensates recovered from accumulations in the Browse Basin as follows: - The Lower–Middle Jurassic J10–J20 (Plover Formation) organic-rich source rocks have been deposited along the northeast-southwest trending fluvial-deltaic system associated with a phase of pre-breakup extension. They have charged gas reservoired within J10–J20 accumulations on the Scott Reef Trend and in the central Caswell Sub-basin at Ichthys/Prelude, and in the Lower Cretaceous K40 supersequence on the Yampi Shelf. - Late Jurassic–earliest Cretaceous J30–K10 source rocks are interpreted to have been deposited in a rift, north of the Scott Reef Trend and along the Heywood Fault System (e.g. Callovian–Tithonian J30–J50 supersequences, lower Vulcan Formation). The J30–K10 shales are believed to have sourced wet gas reservoired in the K10 sandstone (Brewster Member) in the Ichthys/Prelude and Burnside accumulations, and potentially similar plays in the southern Caswell Sub-basin. - The organic-rich source rocks observed in the Heywood Graben may be associated with deeper water marine shales with higher plant input into the isolated inboard rift. They are the potential source of fluids reservoired within the Crux accumulation, which has a geochemical composition more closely resembling a petroleum system in the southern Bonaparte Basin.

The Browse Basin is located offshore on Australia’s North West Shelf and is a proven hydrocarbon province hosting gas with associated condensate. Oil reserves in the area are small with most in-place oil likely the result of hydrocarbon fluids experiencing pressures less than their saturation pressure resulting in dual phase fluids, coupled with secondary alteration processes and gas leakage. This study reviews the distribution, quality and maturity of source rocks and fluid characteristics in the Browse Basin. All publicly-available Total Organic Carbon (TOC) and Rock-Eval pyrolysis data were compiled and quality checked to determine multiple, viable source rock units. Jurassic and Cretaceous source rock distributions and net thickness were studied using integrated seismic and well log lithofacies mapping, combined with organic geochemistry data. Source rock transformation ratio and generation potential were investigated using a regional pseudo-3D petroleum systems model constructed from new seismic interpretations and calibrated using temperature and maturity data from 34 wells. Results show that the Jurassic Plover Formation (J10-J20 supersequences) coals and carbonaceous shales are effective, primarily gas-prone source rocks which may have some liquid potential when the generated gas migrates into shallow reservoirs at reduced pressures. Additional sources of hydrocarbons include shales in the Upper Jurassic lower Vulcan Formation (J40 supersequence), Lower Cretaceous upper Vulcan Formation (K10 supersequence) and Echuca Shoals Formation (K20-K30 supersequences). However, these are likely to have only expelled hydrocarbons locally in areas of optimal organic-richness and maturity. Key uncertainties include TOC and HI variability due to lack of well penetration in the depocentres. The molecular composition of the fluids were compiled and quality checked and used to investigate the relationship between the saturation pressure and condensate-gas ratio (CGR). By combining the bulk properties and molecular and isotopic compositions of the fluids with the geochemical compositions of the source rocks in a petroleum systems model, four Mesozoic petroleum systems have been identified and mapped to help understand the source rock potential and fluid characters for the Browse Basin.

<p>Geoscience Australia completed a regional assessment of the geological carbon dioxide (CO2) storage potential and petroleum prospectivity of the Browse Basin, offshore northwest Australia. This dual-purpose basin analysis study provided a new understanding of the basin’s Cretaceous succession based on new information regarding basin evolution, sequence stratigraphy, structural architecture and petroleum systems. The basin’s tectonostratigraphic framework was updated, and the integration of revised and recalibrated biostratigraphic data with well log and seismic interpretations has enabled an improved understanding of variations in depositional facies and the spatial distribution of reservoir, seal, and source rock sections. The outputs include models and maps of environments of deposition, play fairways, common risk element maps for regional-scale assessment of CO2 storage potential and petroleum systems model (Abbott et al., 2016; Edwards et al., 2015, 2016; Grosjean et al., 2015; Palu et al., 2017a and b; Rollet et al., 2016b, 2017a,b, 2018).<p> <p>This data pack includes 12 Cretaceous and Cenozoic horizons, and the regional fault maps produced from this study. This interpretation is based on data from 60 wells (Table 1) and 26 regional 2D and 3D seismic reflection surveys (Table 2) (Rollet et al., 2016a). Surfaces were converted from TWT to depth and integrated in a 3D geological model as input into a petroleum systems model (Palu et al., 2017a, b). <p>Data layers include: <p>12 regional depth surface grids and arcmap files generated for key Cretaceous and Cenozoic horizons (Figure 1; Table 3): K10.0_SB (late Tithonian), K20.0_SB (Valanginian), K30.0_SB (Late Hauterivian), K40.0_SB (Aptian), K50.0_SB (Late Cenomanian), K60.0_SB (Early Campanian), K65.0_SB (Maastrichtian), T10.0_SB (Base Cenozoic), T24.0_SB (Ypresian), T30.0_SB (Rupelian), T33.0_SB (Aquitanian) and water bottom based on bathymetry after Whiteway (2009), <p>2 fault population shapefiles (Figure 2): polygon envelop of shallow faults that formed during the Cenozoic collision between Australia and Asia, and horizon fault boundaries of deep regional faults that were formed through the Permian to Cretaceous.