Constraining Late Cretaceous exhumation in the Eromanga Basin using sonic velocity data

2016 ◽  
Vol 56 (1) ◽  
pp. 101
Author(s):  
Mitchell Keany ◽  
Simon Holford ◽  
Mark Bunch
Keyword(s):  
Late Cretaceous ◽  
Vitrinite Reflectance ◽  
Sedimentary Basins ◽  
Analysis Data ◽  
Source Rocks ◽  
Fine Grained ◽  
Seal Integrity ◽  
Central Australia ◽  
Petroleum Wells ◽  
Eromanga Basin

Exhumation in sedimentary basins can have significant consequences for their petroleum systems. For example, source rocks may be more mature than their present-day burial depths suggest, increased compaction can result in reduced reservoir quality, and seal integrity problems are commonly encountered. The Eromanga Basin in central Australia experienced an important phase of exhumation during the Late Cretaceous, though the magnitude and spatial distribution of exhumation is poorly constrained. In this study exhumation magnitudes have been determined for 100 petroleum wells based on sonic transit time analyses of fine grained shales, siltstones and mudstones within selected Cretaceous stratigraphic units. Observed sonic transit times are compared to normal compaction trends (NCTs) determined for suitable stratigraphic units. The Winton Formation and the Bulldog Shale/Wallumbilla Formation were chosen for analysis in this study for their homogenous, fine-grained and laterally extensive properties. Exhumation magnitudes for these stratigraphic units are statistically similar. Results show net exhumation in the southern Cooper-Eromanga Basin (<500 m [~1,640 ft]) and higher net exhumation magnitudes (up to 1,400 m [~3,937 ft]) being recorded in the northeastern margins of the basin. Gross exhumation magnitudes show significant variation across short distances suggesting different tectonic processes acting upon the basin. Independent vitrinite reflectance and apatite fission track analysis data, available for a subset of wells, give statistically similar exhumation magnitudes to those that have been calculated through the compaction methodology, giving confidence in these results. The effect on source rock generation is illustrated through 1D basin modelling where exhumation is shown to impact the timing and type of the hydrocarbons generated. The improved quantification of this exhumation permits a better understanding of the Late Cretaceous tectonics and palaeogeography of central Australia.

COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA

2003 ◽  
Vol 43 (1) ◽  
pp. 117 ◽  
Author(s):  
C.J. Boreham ◽  
J.E. Blevin ◽  
A.P. Radlinski ◽  
K.R. Trigg
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Middle Eocene ◽  
Vitrinite Reflectance ◽  
Mineral Resources ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Gas Generation ◽  
Australian Context ◽  
Effective Source

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.

ORGANIC PETROLOGY AND GEOCHEMISTRY OF SOURCE ROCKS IN THE PEDIRKA-SIMPSON BASINS CENTRAL AUSTRALIA

1981 ◽  
Vol 21 (1) ◽  
pp. 187
Author(s):  
M. Smyth ◽  
J. D. Saxby
Keyword(s):  
Petroleum Hydrocarbons ◽  
Vitrinite Reflectance ◽  
Geothermal Gradient ◽  
Source Rocks ◽  
Volatile Hydrocarbons ◽  
Organic Petrology ◽  
Reflected Light ◽  
Petrology And Geochemistry ◽  
Central Australia ◽  
Simpson Desert

Sediments from the Permian Pedirka Basin and the overlying Triassic Simpson Desert Basin have been studied to determine their potentials as source rocks for hydrocarbons. Principal techniques used are reflected light microscopy, including vitrinite reflectance, solvent extraction and kerogen isolation.Dispersed organic matter (DOM) occurs through the Permian and Triassic sequences, and is most abundant near the top of the Triassic, constituting up to 2 per cent of the sediments by volume. Of this DOM, 30 to 50 per cent is vitrinite plus exinite. The Permian and Triassic coals have vitrinite reflectivities of up to 0.9 per cent. The geothermal gradient in the vicinity of Poolowanna 1 is probably sufficient to cause the cutinite within the Triassic sediments to break down into petroleum hydrocarbons. In the case of the Poolowanna Jurassic oil show, migration up faults and accumulation in high-temperature reservoirs have been accompanied by the loss of volatile hydrocarbons.

1D depth burial history and thermal maturity modelling of the Toolebuc Formation, Queensland

2016 ◽  
Vol 56 (2) ◽  
pp. 590
Author(s):  
Behnam Talebi
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Vitrinite Reflectance ◽  
Tight Oil ◽  
Thermal Maturity ◽  
Burial History ◽  
The Us ◽  
Petroleum Wells ◽  
Erosional Event ◽  
Eromanga Basin

The Toolebuc Formation in the Eromanga and Carpentaria basins in western Queensland shares many characteristics with successful tight oil plays in the US. A study by the Geological Survey of Queensland has examined key parameters for this formation, including depth, thickness, lithology, mineralogy, maturity (both vitrinite reflectance and Tmax), total organic carbon and mud gas compositions and identified a possible play fairway in the central Eromanga Basin. Mudgas wetness ratios indicate that in areas modelled to be more mature, oil may be present in the Toolebuc Formation. These areas are typically in the central Eromanga Basin where the Toolebuc Formation is deepest, though oil responses have been calculated for wells that are shallower. This is contradicted by the apparent maturity of the formation based on vitrinite reflectance and Tmax measurements. Initial burial history modelling of the six petroleum wells indicates that DIO Hammond–1, SSL Clinton–1, DIO Tanbar North–1 and DIO Marengo–1 are in main oil window (0.7–1.0 %Ro) while DIO Denley–1 and DIO Ingella–1 are in the early oil window (0.55–0.7 %Ro). A single erosional event of 550 m of the Winton Formation has been assumed for this modelling. These wells are the deepest intersections of the Toolebuc Formation where it has been modelled to have higher maturity, and mudgas wetness ratios indicate oil may be present. Further refinement of these models and examination of additional wells is needed to better understand the potential for the Toolebuc Formation to have generated petroleum.

TIMING CONSTRAINTS ON THE STRUCTURAL HISTORY OF THE WESTERN OTWAY BASIN AND IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY AROUND THE MORUM HIGH, SOUTH AUSTRALIA

2003 ◽  
Vol 43 (1) ◽  
pp. 59 ◽  
Author(s):  
I.R. Duddy ◽  
B. Erout ◽  
P.F. Green ◽  
P.V. Crowhurst ◽  
P.J. Boult
Keyword(s):  
Late Cretaceous ◽  
Vitrinite Reflectance ◽  
South Australia ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Seismic Line ◽  
Late Paleocene ◽  
History Of ◽  
And Migration ◽  
Uplift And Erosion

Reconstructed thermal and structural histories derived from new AFTA Apatite Fission Track Analysis, vitrinite reflectance and (U-Th)/He apatite dating results from the Morum–1 well, Otway Basin, reveal that the Morum High is a mid-Tertiary inversion structure. Uplift and erosion commencing in the Late Paleocene to mid-Eocene (57–40 Ma) removed around 1,500 m of sedimentary section. The eroded section is attributed to the Paleocene- Eocene Wangerrip Group which is considered to have been deposited in a major depocentre in the vicinity of the present Morum High. This depocentre is interpreted to have been one of a number of transtensional basins developed at the margin of the Morum Sub-basin and adjacent to the Tartwaup Hinge Zone and Mussel Fault during the Early Tertiary. The Portland Trough in Victoria represents a similar depocentre in which over 1,500 m of Wangerrip Group section, mostly represented by deltaic sediments of the Early Eocene Dilwyn Formation, is still preserved.Quantification of the maximum paleotemperature profile in Morum–1 immediately prior to Late Paleocene to mid-Eocene inversion shows that the paleo-geothemal gradient at the time was between 21 and 31°C/km, similar to the present-day level of 29°C/km, demonstrating that there has been little change in basal heat flow since the Early Tertiary.Reconstruction of the thermal history at the Trumpet–1 location reveals no evidence for any periods of significant uplift and erosion, demonstrating the relative stability of this part of the Crayfish Platform since the Late Cretaceous.The thermal and burial histories at Morum–1 and Trumpet–1 have been used to calibrate a Temis2D hydrocarbon generation and migration model along seismic line 85-13, encompassing the Crayfish Platform, Morum High and Morum Sub-basin. The model shows the cessation of active hydrocarbon generation from Eumeralla Formation source rocks around the Morum High due to cooling at 45 Ma (within the range 57–40 Ma) resulting from uplift and erosion of a Wangerrip Group basin. There has been almost no hydrocarbon generation from the Eumeralla Formation beneath the Crayfish Platform.Migration of hydrocarbons generated from the Eumeralla Formation began in the Late Cretaceous in the Morum Sub-basin and is predicted to continue to the present day, with the potential for accumulations in suitably placed reservoirs within the Late Cretaceous package both within the Morum Sub-basin and at the southern margin of the Crayfish Platform.

PETROLEUM GEOCHEMISTRY OF THE MURTA MEMBER, MOOGA FORMATION, AND ASSOCIATED OILS, EROMANGA BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 114 ◽  
Author(s):  
T.G. Powell ◽  
C.J. Boreham ◽  
D.M. McKirdy ◽  
B.H. Michaelsen ◽  
R.E. Summons
Keyword(s):  
Organic Matter ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Composition ◽  
Source Rocks ◽  
Marine Oils ◽  
Algal Organic Matter ◽  
Conventional Oil ◽  
Effective Source ◽  
Eromanga Basin ◽  
Chemical Evidence

An investigation has been made of the source potential, degree of maturation and hydrocarbon composition of selected oils and sediments in the Murta Member in ATP 267P and the Moomba and Napacoongee- Murteree Blocks (PEL 5 and 6), Eromanga Basin. Shales in the Murta Member contain low amounts (up to 2.5% TOC) of terrestrial oil- prone organic matter (Types II–III) which consists predominantly of sporinite, lipto- detrinite and inertinite with lower amounts of vitrinite, although some samples contain relatively abundant telalginite. Extractable hydrocarbon yields demonstrate that parts of the Murta Member are effective source rocks at present maturation levels, which are at the threshold of the conventional oil window (vitrinite reflectance = 0.5- 0.6% Ro).Oils from Murta reservoirs in ATP 267P (Kihee, Nockatunga and Thungo) all show the characteristics found by previous analyses of many Murta oils, namely paraffinic, low wax, and high pristane- to- phytane ratios. In contrast Murta oils from Limestone Creek and Biala are waxy. All oils show chemical evidence of generation at relatively low maturation levels. Gas chromatograms of the saturate fractions from the best source facies show the same characteristics noted for the low- wax oils. Samples with lower source potential in contrast contain relatively abundant waxy n- alkanes. Methylphenan- threne Indices and biomarker maturation indicators obtained from the oils show the same values as were measured on sediment samples from the Murta. Hence the oils could not have been derived from deeper, more mature source rocks. The distribution of biomarkers in the low- wax oils is also consistent with an origin from the Murta Member. A corresponding source facies for the high- wax oils has not yet been located. However, chemical maturation indices also suggest a source in the Murta Member or in immediately adjacent strata.The unusual circumstances represented by the Murta oils (low maturity, low- wax terrestrial oils) provide evidence for bacterial contribution to the source material for non- marine oils. Both the low- wax oils and the best source facies contain abundant hydrocarbons derived from bacterial precursors. This bacterial organic matter appears to yield hydrocarbons at an earlier stage of maturation than the predominantly terrestrial plant and algal organic matter with which it is associated. In the case of the Murta Member there are sufficient hydrocarbons generated at relatively low maturity to allow migration to occur. Chemical evidence suggests a low contribution from algal organic matter to the generated hydrocarbons.

FOCUSSING EXPLORATION IN THE OTWAY BASIN: UNDERSTANDING TIMING OF SOURCE ROCK MATURATION

1997 ◽  
Vol 37 (1) ◽  
pp. 178 ◽  
Author(s):  
I.R. Duddy
Keyword(s):  
Late Cretaceous ◽  
Vitrinite Reflectance ◽  
Integrated Approach ◽  
Geothermal Gradient ◽  
High Heat ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Top Down ◽  
Early Maturation ◽  
Hydrocarbon Preservation

Quantitative reconstruction of the thermal and structural histories at key locations in the Otway Basin using an integrated approach based on AFTA® and vitrinite reflectance data reveals a regional pattern of elevated geothermal gradient prior to mid-Cretaceous cooling. Paleogeothermal gradients declined from −50 to 70°C/ km at −95 Ma to present day levels in the range −30 to 40°C/km by around 80 Ma. As a result, significant hydrocarbon generation must have occurred from the thick Late Jurassic to Early Cretaceous Otway Group section during the rapid rift-burial phase that preceded major mid-Cretaceous cooling.Regional decline in geothermal gradient in the Late Cretaceous leads to a 'two-stage' generation history for Otway Group source rocks because subsequent hydrocarbon generation did not recommence until the early maturation effects were overcome by greater Late Cretaceous and Tertiary burial. Such early, high heat flow is regarded as a feature of rift basins, and this results in an inverted pattern of hydrocarbon generation from rift source rocks that is here referred to as 'top-down generation', and which has a key influence on hydrocarbon prospectivity.Analysis of key hydrocarbon discoveries in the basin leads to the conclusion that all significant accumulations can reasonably be inferred to be sourced from the Otway Group, due to 'top-down generation5 delayed until the mid-Tertiary to present-day burial phase. This situation clearly favours hydrocarbon preservation in traps of a range of ages and has the added advantage of limiting the time available for traps to be breached in subsequent structuring episodes.This understanding of the decoupled relationship between the burial and thermal histories provides a sharp focus for further exploration of Otway Group-sourced accumulations, by defining areas with suitable thicknesses of the Late Cretaceous and Tertiary depositional packages which maximise the amount of re-generation since the mid-Tertiary.

scholarly journals STRUCTURAL SETTING AND HYDROCARBON POTENTIAL OF KHARITE-NUQRA-KOMOMBO RIFT BASINS, SOUTH EGYPT: A PROSPECTIVE APPROACH

2021 ◽  
Vol 6 (3) ◽  
Author(s):  
Mostafa A ◽  
Sehim A ◽  
El Barkooky A ◽  
Hammed M
Keyword(s):  
Vitrinite Reflectance ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Potential ◽  
Rift Basins ◽  
Tectonic Zone ◽  
Structural Setting ◽  
High Resolution Satellite Images ◽  
Potential Source Rock

— The sedimentary basins of Kharite, Nuqra, and Komombo are outlined with the potential geophysical data where the southern N-S Egyptian Nile course separates Nuqra and Kharit as the East Nile basins. Two commercial discoveries of Al Barka and West El Barka oil fields have been declared in the West Nile basin of Komombo. This work presents our insights on the structural setting and hydrocarbon system of these basins through our integrating results in form of interpreted seismic profiles and structural mapping on the different horizons, 1D basin modeling, geochemistry, and geologic maps based on high-resolution satellite images. Structurally, these rift basins are developed as NWtrending asymmetric fault-bounded half-grabens (oblique to the Red Sea trend) through the reactivation of a major Precambrian Pan African tectonic zone by the Neocomian extensional tectonics. The high potential source rock with up to 7wt. % TOC of kerogen II are proved in the Komombo basin. The seismic and drilling results show Neocomian-Barremian maximum subsidence and the possible occurrence of similar Neocomian source rocks in the eastern Nile basins. Additionally, the convenient clastic reservoir rocks occurred in the entire stratigraphic succession and seal capacity in the upper interval of Senonian-Paleocene. Good opportunities for hydrocarbon structural trapping take place in form of rotated fault blocks by the Early Cretaceous extensional rift and mildly inverted structures by a long span of Late Cretaceous to post-Early Eocene Syrian Arc compression in South Egypt. These elements were verified by Al Baraka discovery and present a promising play concept for hydrocarbon potential in the Kharit and Nuqra basins. The geochemical data indicate different basins exhumation and maturation levels, as the 0.5% calculated vitrinite reflectance "Ro" values occur at the depths of 1200ft and 2100ft in Nuqra and Komombo basins, respectively

scholarly journals Evaluation of Shale Source Rocks and Clay Mineral Diagenesis in the Permian Basin, USA: Inferences on Basin Thermal Maturity and Source Rock Potential

Geosciences ◽  
2020 ◽  
Vol 10 (10) ◽  
pp. 381
Author(s):  
Hunter Green ◽  
Branimir Šegvić ◽  
Giovanni Zanoni ◽  
Silvia Omodeo-Salé ◽  
Thierry Adatte
Keyword(s):  
Organic Matter ◽  
Clay Mineral ◽  
Vitrinite Reflectance ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Peak Oil ◽  
Permian Basin ◽  
Thermal Indices ◽  
Rock Eval

The use of mineral diagenetic indices and organic matter maturity is useful for reconstructing the evolution of sedimentary basins and critical assessments for potential source rocks for petroleum exploration. In this study, the relationship of clay mineral diagenesis and organic matter thermal indices (Rock-Eval Tmax) and calculated vitrinite reflectance (%Ro) were used to constrain the maximum burial depths and temperatures of three distinct intervals within the northern Permian Basin, USA. X-ray diffraction of clay fractions (<2 µm) consists of illite, chlorite, and illite-smectite intermediates. Primary clay mineral diagenetic changes progressively increase in ordering from R0 to R1 I-S between 2359.5 and 2485.9 m and the appearance of chlorite at 2338.7 m. Rock-Eval pyrolysis data show 0 to 14 wt% TOC, HI values of 40 to 520 mgHC/g TOC, and S2 values of 0 to 62 mg HC/g, with primarily type II kerogen with calculated %Ro within the early to peak oil maturation window. Evaluation of the potential for oil generation is relatively good throughout the Tonya 401 and JP Chilton wells. Organic maturation indices (Tmax, %Ro) and peak burial temperatures correlate well with clay mineral diagenesis (R0–R1 I-S), indicating that maximum burial depths and temperatures were between 2.5 and 4 km and <100 °C and 140 °C, respectively. Additionally, the use of clay mineral-derived temperatures provides insight into discrepancies between several calculated %Ro equations and thus should be further investigated for use in the Permian Basin. Accordingly, these findings show that clay mineral diagenesis, combined with other paleothermal proxies, can considerably improve the understanding of the complex burial history of the Permian Basin in the context of the evolution of the southern margin of Laurentia.

USE OF THE METHYLPHENANTHRENE INDEX TO CHARACTERISE EXPULSION OF COOPER AND EROMANGA BASIN OILS

1990 ◽  
Vol 30 (1) ◽  
pp. 373 ◽  
Author(s):  
N. P. Tupper ◽  
D. M. Burckhardt
Keyword(s):  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Thermal Modelling ◽  
Potential Source ◽  
Southern Margin ◽  
Structural Growth ◽  
Oil Source ◽  
Oil Expulsion ◽  
Eromanga Basin ◽  
Cooper Basin

The methylphenanthrene index (MPI) molecular maturity parameter is available for over 100 Cooper and Eromanga Basin oils. Oil maturity data define the threshold and range of expulsion maturity for source rocks and can be used to determine oil-source affinity. Mapping of this maturity range for all potential source rocks identifies areas of greatest oil potential.Cooper and Eromanga oils were expelled over a wide maturity range commencing at 0.6 per cent calculated vitrinite reflectance equivalent in some parts of the basin. Oil occurrence and expulsion maturity are controlled by variations in source quality such that no single expulsion threshold can be applied basin-wide. The full oil potential of the basin will only be realised by selective drilling of prospects with access to source rocks in the 0.60-0.95 per cent vitrinite reflectance range.The timing of oil expulsion is determined by using oil maturity data to calibrate thermal modelling of basin depocentres. Peak expulsion occurred during the Cretaceous and therefore prospects with pre-Tertiary structural growth are favoured.Structural embayments with thick Permian section at the southern margin of the Cooper Basin, plus the flanks of the Patchawarra and Nappamerri troughs, are highly prospective in terms of oil source potential and will be further evaluated by drilling in 1990.

ORIGIN OF GILMORE GAS AND OIL, ADAVALE BASIN, CENTRAL QUEENSLAND

1998 ◽  
Vol 38 (1) ◽  
pp. 399 ◽  
Author(s):  
C.J. Boreham ◽  
R.A. de Boer
Keyword(s):  
Oil And Gas ◽  
Isotope Composition ◽  
Vitrinite Reflectance ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Gas Generation ◽  
Migration Pathway ◽  
Wet Gas ◽  
Modelling Studies ◽  
High Maturity

Dry gas in the Gilmore Field of the Adavale Basin has been sourced from both wet gas associated with oil generation, together with methane from a deep, overmature source. The latter gas input is further characterised by a high nitrogen content co-generated with isotopically heavy methane and carbon dioxide. The eastern margin of the Lissoy Sandstone principal reservoir unit contains the higher content of overmature dry gas supporting reservoir compiirtmenmlisalion and a more favourable migration pathway to this region. The combination of a molecular and multi-element isotopic approach is an effective tool for the recognition of an overmature, dry gas source. This deep source represents a play concept that previously has been undervalued and may be more widespread within Australian sedimentary basins.The maturity level of the wet gas and associated oil are identical, having reached an equivalent vitrinite reflectance of 1.4−1.6 per cent. Modelling studies support the concept of local Devonian source rocks for the wet gas and oil. Reservoir filling from late stage, high maturity oil and gas generation and expulsion, was a result of reactivation of petroleum generation from Devonian source rocks during the Early Cretaceous. The large input of dry gas from a deeper and highly overmature source is a more recent event. This gas can fractionally displace condensable C2+ liquids already in the reservoir possibly allowing tertiary migration into younger reservoirs, or adjacent structures.Oil recovered from Gilmore-2 has been sourced from Devonian marine organic matter, deposited under mildly evaporitic, restricted marine conditions. The most likely source rocks in the Adavale Basin are the basal marine shale of the Log Creek Formation, algal shales at the top of the Lissoy Sandstone, and the Cooladdi Dolomite. Source-sensitive biomarkers and carbon isotope composition of the Gilmore-2 oil have much in common with other Devonian-sourced oils from the Bonaparte and Canning basins. The chemical link between western and eastern Australian Devonian oils may suggest diachronous development of source rocks over a wide extent. This implies that the source element of the Devonian Petroleum Supersystem may be present in other sedimentary basins.

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