HYDROCARBON GENERATION IN THE FLY LAKE—BROLGA AREA OF THE COOPER BASIN

1979 ◽  
Vol 19 (1) ◽  
pp. 108
Author(s):  
Michelle Smyth
Keyword(s):  
Organic Matter ◽  
Sedimentary Basins ◽  
Depositional Environments ◽  
Fluorescent Light ◽  
Hydrocarbon Generation ◽  
Coal Seams ◽  
Clastic Sediments ◽  
Permian Coal ◽  
Coal Measures ◽  
Cooper Basin

The Cooper Basin is a major gas producing basin in Australia. Organic material in sediments from its Permian coal measures has been studied using transmitted, reflected and fluorescent light microscope techniques of analysis. In the Fly Lake—Brolga area, of the Patchawarra Trough, Cooper Basin, the interseam sediments of the Patchawarra Formation contain three types of kerogen or dispersed organic matter (d.o.m.): exinitic, vitrinitic and inertinitic. Exinitic d.o.m. is most abundant near the top of the Formation, vitrinitic d.o.m. is more abundant in the middle and lower parts of it, and inertinitic d.o.m. occurs throughout.A correlation between the type of d.o.m. in the sediments and the petrography of associated coals is emerging. Exinitic d.o.m. appears to be associated with coals that have high vitrite-plus-clarite contents, whereas vitrinitic d.o.m. is associated with high "intermediates" coals. Further examples are needed to establish these relationships more firmly.On the basis of results of coal petrographic studies in other Australian Permian sedimentary basins, depositional environments have been proposed for the coal seams in the Fly Lake—Brolga area. These environments are compared with those proposed by Thornton (1978) using the clastic sediments of the Patchawarra Formation.

Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

2017 ◽  
Vol 5 (2) ◽  
pp. SF225-SF242 ◽  
Author(s):  
Xun Sun ◽  
Quansheng Liang ◽  
Chengfu Jiang ◽  
Daniel Enriquez ◽  
Tongwei Zhang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Ordos Basin ◽  
Depositional Environments ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Thermal Maturity ◽  
Yanchang Formation

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

AN INTEGRATED GEOLOGICAL AND GEOPHYSICAL INTERPRETATION OF A PORTION OF THE OFFSHORE SYDNEY BASIN, NEW SOUTH WALES

2003 ◽  
Vol 43 (1) ◽  
pp. 495 ◽  
Author(s):  
P.A. Arditto
Keyword(s):  
New South ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Hydrocarbon Generation ◽  
Late Permian ◽  
Early Permian ◽  
South Wales ◽  
Permian Coal ◽  
Coal Measures ◽  
Reservoir Facies

The study area is within PEP 11, which is more than 200 km in length, covers an area over 8,200 km2 and lies immediately offshore of Sydney, Australia’s largest gas and petroleum market on the east coast of New South Wales. Permit water depths range from 40 m to 200 m. While the onshore Sydney Basin has received episodic interest in petroleum exploration drilling, no deep exploration wells have been drilled offshore.A reappraisal of available data indicates the presence of suitable oil- and wet gas-prone source rocks of the Late Permian coal measure succession and gas-prone source rocks of the middle to early Permian marine outer shelf mudstone successions within PEP 11. Reservoir quality is an issue within the onshore Permian succession and, while adequate reservoir quality exists in the lower Triassic succession, this interval is inferred to be absent over much of PEP 11. Quartz-rich arenites of the Late Permian basal Sydney Subgroup are inferred to be present in the western part of PEP 11 and these may form suitable reservoirs. Seismic mapping indicates the presence of suitable structures for hydrocarbon accumulation within the Permian succession of PEP 11, but evidence points to significant structuring post-dating peak hydrocarbon generation. Uplift and erosion of the order of 4 km (based on onshore vitrinite reflectance studies and offshore seismic truncation geometries) is inferred to have taken place over the NE portion of the study area within PEP 11. Published burial history modelling indicates hydrocarbon generation from the Late Permian coal measures commenced by or before the mid-Triassic and terminated during a mid-Cretaceous compressional uplift prior to the opening of the Tasman Sea.Structural plays identified in the western and southwestern portion of PEP 11 are well positioned to contain Late Permian clean, quartz-rich, fluvial to nearshore marine reservoir facies of the coal measures. These were sourced from the western Tasman Fold Belt. The reservoir facies are also well positioned to receive hydrocarbons expelled from adjacent coal and carbonaceous mudstone source rock facies, but must rely on early trap integrity or re-migrated hydrocarbons and, being relatively shallow, have a risk of biodegradation. Structural closures along the main offshore uplift appear to have been stripped of the Late Permian coal measure succession and must rely on mid-Permian to Early Permian petroleum systems for hydrocarbon generation and accumulation.

COALBED METHANE RESOURCES IN THE PERMIAN OF EASTERN AUSTRALIA AND THEIR TECTONIC SETTING

1993 ◽  
Vol 33 (1) ◽  
pp. 161 ◽  
Author(s):  
S. Miyazaki ◽  
R.J. Korsch
Keyword(s):  
Coalbed Methane ◽  
Tectonic Setting ◽  
Temporal Distribution ◽  
Low Permeability ◽  
Burial History ◽  
Coal Seams ◽  
Methane Drainage ◽  
Eastern Australia ◽  
Permian Coal ◽  
Coal Measures

The Bowen and Sydney Basins in eastern Australia contain vast coal resources which provide a source for coalbed methane. Through studies of the spatial and temporal distribution of the sedimentary packages, the structural geometry and tectonic setting of the sedimentary packages, and the maturation and burial history, the Australian Geological Survey Organisation (AGSO) is mapping the distribution and structural styles of the sources of methane, in particular, the Late Permian coal measures. AGSO's results from the Bowen Basin show at least two distinctly different structural styles of potential targets for coalbed methane drainage: on the Comet Ridge, the Permian coal measures are essentially subhorizontal and tectonically undisturbed, whereas in the western Taroom Trough, the coal measures are folded into a series of anticlines, each of which occurs above a thrust fault which in turn forms part of an imbricate thrust fan. Both of these styles occur at depths of less than 1000 m.Calculations by the Bureau of Resource Sciences (BRS) indicate that the inferred coalbed methane resources-in-place are 62 trillion cubic feet (1760 billion m3) for Australia, in which the Bowen and Sydney Basins are currently the only potential provinces of coalbed methane. The low permeability of the coal seams hinders attempts to utilise this vast amount of energy resources.Further exploration is necessary to delineate commercially feasible areas. This delineation is the only process that will be able to determine demonstrated coalbed methane resources.

SOURCE, MATURITY AND GAS COMPOSITION RELATIONSHIPS IN THE SOUTHERN COOPER BASIN

1980 ◽  
Vol 20 (1) ◽  
pp. 191
Author(s):  
D.A. Schwebel ◽  
S.B. Devine ◽  
M. Riley
Keyword(s):  
Vitrinite Reflectance ◽  
Sedimentary Basins ◽  
Geothermal Gradient ◽  
Temperature Gradients ◽  
Land Plants ◽  
Hydrocarbon Generation ◽  
Gas Composition ◽  
Wet Gas ◽  
Structural Zones ◽  
Cooper Basin

In the Permian sedimentary sequence of the Cooper Basin, land plants contributed the bulk of the organic matter to the sediments. Inertinite, vitrinite and exinite are common kerogen types present in the organic-rich shales. Coal thickness varies areally.The geothermal gradient, though varying (from area to area), is everywhere higher than normal for sedimentary basins. The whole of the Permian sequence is mature for hydrocarbon generation. The highest temperature gradients of up to 3.19°F/100’ are measured in the Nappamerrie Trough and are associated with areas of granitic basement. Vitrinite reflectance profiles confirm that the sediments are thermally mature.Trends of gas composition indicate three distinct regions with gases trapped in:the Patchawarra Trough tend to be high in CO2 and wet gas;the Nappamerri Trough tend to be high in CO2 and low in wet gas; andthe Tennapera Trough tend to be low in CO2 and moderately high in wet gas.These differences in gas composition are accounted for by differences in thermal history within structural zones.

AN ASSESSMENT OF THE PETROLEUM PROSPECTS FOR THE GALILEE BASIN, QUEENSLAND

1981 ◽  
Vol 21 (1) ◽  
pp. 172 ◽  
Author(s):  
K. S. Jackson ◽  
Z. Horvath ◽  
P. J. Hawkins
Keyword(s):  
Oil And Gas ◽  
Late Carboniferous ◽  
Reservoir Rock ◽  
Hydrocarbon Generation ◽  
Permian Coal ◽  
Intracratonic Basin ◽  
Oil Source ◽  
Sandstone Facies ◽  
Coal Measures ◽  
Exploration Criteria

The Galilee Basin in central Queensland is an extensive intracratonic basin containing up to 2 800 m of Late Carboniferous to Middle Triassic strata deposited under predominantly fluviatile conditions in two depocentres, the Lovelle Depression and the Koburra Trough.The exploration criteria of petroleum geochemistry, reservoir rock quality, structural and trapping style have been assessed.The source potential is generally poor with the Aramac Coal Measures, basal Jericho Formation, and the underlying Devonian rating best for possible hydrocarbon generation. Organic maturation is generally not reached until the Late Carboniferous Jochus Formation. The predominant organic maceral type for the Late Carboniferous and the Permian is vitrinite, suggesting gas-prone source.The potential for reservoir rock is best developed in the Aramac Coal Measures and Colinlea Sandstone correlative units within a fluvial channel sandstone facies. Structural and stratigraphic traps formed in the Late Carboniferous and the Early Permian are thought to be most prospective. The presence of oil and gas in ENL Lake Galilee 1 does imply that hydrocarbons have been generated in the basin or possibly from the underlying Devonian. The application of oil/source rock correlation data suggests the basal Jericho Formation or the underlying Devonian as the oil source. The Aramac Coal Measures, with a combination of reservoir and source facies even though only marginally mature, are thought to offer the best play.Lack of success to date may well reflect deficiencies in one or more of the exploration criteria. However, examination of drilling locations suggests that many wells were poorly sited owing to the difficulty in seismic mapping below the Late Permian coal seams.

Petroleum potential and depositional environments of Middle Jurassic coals and non-marine deposits, Danish Central Graben, with special reference to the Søgne Basin

1998 ◽  
pp. 1-80 ◽  
Author(s):  
Henrik I. Petersen ◽  
Jan Andsbjerg ◽  
Jørgen A. Bojesen-Koefoed ◽  
Hans P. Nytoft ◽  
Per Rosenberg
Keyword(s):  
Organic Matter ◽  
Special Reference ◽  
Sea Level ◽  
Middle Jurassic ◽  
Depositional Environments ◽  
Thermal Maturity ◽  
Coal Seams ◽  
Petroleum Potential ◽  
Marine Deposits ◽  
Marine Influence

NOTE: This monograph was published in a former series of GEUS Bulletin. Please use the original series name when citing this monograph. For example: Petersen, H. I., Andsbjerg, J., Bojesen-Koefoed, J. A., Nytoft, H. P., & Rosenberg, P. (1998). Petroleum potential and depositional environments of Middle Jurassic coals and non-marine deposits, Danish Central Graben, with special reference to the Søgne Basin. Geology of Denmark Survey Bulletin, 36, 1-80. https://doi.org/10.34194/dgub.v36.5022 _______________ New data from five wells in the Søgne Basin, Danish Central Graben of the North Sea - West Lulu-1, West Lulu-3, Lulu-1, Amalie-1 and Cleo-1 - together with previously released data from the West Lulu-2 well, show that the cumulative thickness of the Bryne Formation coal seams decreases towards the palaeo-shoreline from 5.05 m to 0.60 m, and that the seams have varying extents. Their overall organic petrographic and geochemical composition reflects the palaeoenvironmental conditions in the precursor mires, in particular the rate of rise in the water table, principally related to the relative rise in sea level, and the degree of marine influence. Laterally towards the palaeo-shoreline, all coal seams have increased proportions of C27 steranes and higher C35-homohopane indices suggesting stronger marine influence on the coastal reaches of the ancient mires. In each well it is also observed that coal seams formed during accelerated relative sea-level rise (T-seams) are characterised by higher contents of sterane C27 and higher C35-homohopane indices than seams formed during slower rates of base-level rise (R-seams). The most landward and freshwater-influenced parts of the seams have higher proportions of sterane C29 and the highest Pr/Ph ratios. The coals, with respect to thermal maturity, are well within the oil window, except in the Amalie-1 well where they are more mature. The largest average hydrogen indices and thermally extracted and generated bitumen yields are obtained from the T-seams. However, generally an increase in the hydrogen index is recorded in a seaward direction for all seams. Multivariate regression analysis demonstrates that collotelinite, telinite, the vitrinite maceral group, vitrinite-rich microlithotypes and the TOC content have a significant positive influence on the remaining generative potential represented by S2. Pyrolysis-gas chromatography reveals that during maturation the coals will generate from 72.4 to 82.0% oil-like components and only 18.0 to 27.6% gas. However, this does not necessarily imply that all of these oil-like components can be expelled to form a crude oil accumulation. Distribution of C27–29 regular steranes shows good correlation between extracts of Bryne Formation coals and oils/condensates present in Bryne Formation sandstones. The sum of evidence indicates that the coals in the Søgne Basin have generated and are still capable of generating liquid and gaseous petroleum, but with respect to petroleum generation potential, they are not as good as the documented oil-prone Middle Jurassic coals from North-East Greenland and Tertiary coals from Asia. Mudstones intercalated with the Bryne Formation coals have a similar or lower generative potential as the coals. In areas outside the Søgne Basin, the coastal plain deposits of the Central Graben Group contain predominantly terrestrial-derived kerogen type III or IIb. The thermal maturity of the organic matter ranges from close to or within the peak oil generation range in the oil window (Alma-1x, Anne-3a and M-8 well) to the late oil window (Elly-3 and Falk-1 wells) or close to the end of the oil window (Skjold Flank-1 well). Only a limited generative potential remains in Elly-3, but the kerogen may initially have possessed a good petroleum potential. In the Falk-1 well, a good generative capacity still remains. The kerogen in Skjold Flank-1 may possess the capability to generate condensate and gas, whereas the organic matter in the Alma-1x, Anne-3a and M-8 wells generally exhibits a poor petroleum generative potential.  

scholarly journals Formation of Very Thick Permian Coal Seams, Cooper Basin, Australia

2019 ◽  
Vol 2019 (1) ◽  
pp. 1-4
Author(s):  
Elena Alganaeva ◽  
Greg Smith
Keyword(s):  
Coal Seams ◽  
Permian Coal ◽  
Cooper Basin

scholarly journals Burial history and the evolution of hydrocarbon generation in Carboniferous-Permian coal measures within the Jiyang super-depression, China

2021 ◽  
Vol 24 (4) ◽  
pp. 397-408
Author(s):  
Han Sijie ◽  
Sang Shuxun ◽  
Zhou Peiming ◽  
Jia Jinlong ◽  
Liang Jingjing
Keyword(s):  
Source Rocks ◽  
Burial Depth ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Geographical Differences ◽  
Subsidence Rate ◽  
Multi Stage ◽  
Residual Thickness ◽  
Permian Coal ◽  
Coal Measures

In the Jiyang Sub-basin, Carboniferous-Permian (C-P) coal-measure source rocks have experienced complex multi-stage tectonics and therefore have a complex history of hydrocarbon generation. Because these coal measures underwent multi-stage burial and exhumation, they are characterized by various burial depths. In this study, we used the basin modeling technique to analyze the relationship between burial history and hydrocarbon generation evolution. The burial, thermal and maturity histories of C-P coals were reconstructed, including primary hydrocarbon generation, stagnation, re-initiation, and peak secondary hydrocarbon generation. The secondary hydrocarbon generation stage within this reconstruction was characterized by discontinuous generation and geographical differences in maturity due to the coupled effects of depth and a delay of hydrocarbon generation. According to the maturity history and the delay effect on secondary hydrocarbon generation, we concluded that the threshold depth of secondary hydrocarbon generation in the Jiyang Sub-basin occurred at 2,100 m during the Yanshan epoch (from 205 Ma to 65 Ma) and at 3,200 m during the Himalayan period (from 65 Ma to present). Based on depth, residual thickness, maturity, and hydrocarbon-generating intensity, five favorable areas of secondary hydrocarbon generation in the Jiyang Sub-basin were identified, including the Chexi areas, Gubei-Luojia areas, Yangxin areas, the southern slope of the Huimin depression and southwest of the Dongying depression. The maximum VRo/burial depth (%/km) occurred in the Indosinian epoch as the maximum VRo/time (%/100Ma) happened in the Himalayan period, indicating that the coupling controls of temperature and subsidence rate on maturation evolution play a significant role in the hydrocarbon generation evolution. A higher temperature and subsidence rate can both enhance the hydrocarbon generation evolution.  

Comparative geological setting of conventional oil and gas fields and CSG resources in the Surat/Bowen Basin, Queensland

2009 ◽  
Vol 49 (2) ◽  
pp. 580
Author(s):  
Rob Willink
Keyword(s):  
Oil And Gas ◽  
Gas Content ◽  
Small Contribution ◽  
Coal Seams ◽  
Reservoir Properties ◽  
Oil And Gas Fields ◽  
The Difference ◽  
Permian Coal ◽  
Gas Fields ◽  
Coal Measures

The Surat/Bowen Basin has long been of interest to explorers in pursuit of gas and oil in conventional reservoirs. Some 500 BCF of gas and 32 million barrels of oil have been produced from sandstones of Permian, Triassic and Jurassic age. Geochemical evidence suggests that these hydrocarbons were sourced almost exclusively from Permian coal measures, though a small contribution from Triassic coals cannot be discounted. Primary interest in these basins today, however, resides in the exploration for, and commercialisation of, methane trapped in coal seams within the Permian and Jurassic successions. Total industry declared proven, probable and possible (3P) coal seam gas (CSG) reserves exceed 30 TCF, of which some 8 TCF are attributed to reserves in Permian coal seams, and 22 TCF in Jurassic coal seams. With particular reference to a representative regional seismic traverse through the basin, this presentation will explain why known conventional and CSG fields in these basins are located where they are from a regional structural and stratigraphic perspective. The difference between the reservoir properties of coals and sandstones, and between the Permian and Jurassic coals will be discussed in terms of their maceral composition, gas content, adsorption capacity and thermal maturity. In addition, the location of known sweetspots within CSG fairways will be revealed. The presentation will conclude with some speculative comments on what the future holds for both conventional and CSG exploration in these basins and will show that Origin Energy, in particular through its investment with Conoco Phillips in Australian Pacific LNG (APLNG), is well placed to participate in that future.

A SEISMIC SURVEY IN THE COOPER BASIN IN QUEENSLAND

1977 ◽  
Vol 17 (1) ◽  
pp. 78 ◽  
Author(s):  
David King ◽  
Margaret Falvey
Keyword(s):  
Gravity Data ◽  
Seismic Survey ◽  
Seismic Exploration ◽  
Near Surface ◽  
Lower Carboniferous ◽  
Reflection And Refraction ◽  
Permian Coal ◽  
The University ◽  
Coal Measures ◽  
Cooper Basin

Seismic reflection and refraction surveys in the Queensland sector of the Cooper Basin have commonly been impaired by strongly reflecting Permian coal measures and irregular near-surface duricrust. Penetration problems have consequently frustrated attempts to delineate the thickness of the assumed-prospective Permian section. The problem is well illustrated in and around Authority To Prospect No. 219P, where extensive seismic exploration has been unable to establish whether the thin Permian section, intersected in the various wells on structural highs, thickens substantially on the associated flanks. The Clifton seismic survey commissioned by the University of Sydney has exploited multifold CDP profiling using an array of shallow explosive sources, in combination with high fidelity digital recording and processing, to provide effective penetration in an area to the west of Alliance Oil Development N.L. Thunda I well.The Clifton data reveal an unconformity beneath the Permian "P" horizon near the Thunda well: the unconformity dies out off-structure It is probable that thickening of a Devonian-Lower Carboniferous section is chiefly responsible for the accumulation of sediments evident in both seismic and gravity data between the Thunda and Galway structures. A combined interpretation of gravity and seismic data indicates a complex pattern of faulting not previously delineated. Two dimensional modelling indicates that the gravity field comprises significant components from structure within the sediments, from the sediment-basement interface, and from isostatic compensation at the Moho.Deep crustal reflections were successfully recorded in the Clifton survey using source charges of only 5 x 4.5 k. An event at 11-12 secs is identified as a reflection from a laminated-type Moho transition zone near a depth of 33 km.

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