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.

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.

HYDROCARBON HABITAT OF THE COOPER/EROMANGA BASIN, AUSTRALIA

1983 ◽  
Vol 23 (1) ◽  
pp. 75 ◽  
Author(s):  
A. J. Kantsler ◽  
T. J. C. Prudence ◽  
A. C. Cook ◽  
M. Zwigulis
Keyword(s):  
Geothermal Gradient ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Oil Generation ◽  
Late Tertiary ◽  
Modelling Studies ◽  
Permian Coal ◽  
Intracratonic Basin ◽  
Hydrocarbon Charge ◽  
Eromanga Basin

The Cooper Basin is a complex intracratonic basin containing a Permian-Triassic succession which is uncomformably overlain by Jurassic-Cretaceous sediments of the Eromanga Basin. Abundant inertinite-rich humic source rocks in the Permian coal measures sequence have sourced some 3TCF recoverable gas and 300 million barrels recoverable natural gas liquids and oil found to date in Permian sandstones. Locally developed vitrinitic and exinite-rich humic source rocks in the Jurassic to Lower Cretaceous section have, together with Permian source rocks, contributed to a further 60 million barrels of recoverable oil found in fluvial Jurassic-Cretaceous sandstones.Maturity trends vary across the basin in response to a complex thermal history, resulting in a present-day geothermal gradient which ranges from 3.0°C/100 m to 6.0°C/100 m. Permian source rocks are generally mature to postmature for oil generation, and oil/condensate-prone and dry gas-prone kitchens exist in separate depositional troughs. Jurassic source rocks generally range from immature to mature but are postmature in the central Nappamerri Trough. The Nappamerri Trough is considered to have been the most prolific Jurassic oil kitchen because of the mature character of the crudes found in Jurassic reservoirs around its flanks.Outside the central Nappamerri Trough, maturation modelling studies show that most hydrocarbon generation followed rapid subsidence during the Cenomanian. Most syndepositional Permian structures are favourably located in time and space to receive this hydrocarbon charge. Late formed structures (Mid-Late Tertiary) are less favourably situated and are rarely filled to spill point.The high CO2 contents of the Permian gas (up to 50 percent) may be related to maturation of the humic Permian source rocks and thermal degradation of Permian crudes. However, the high δ13C of the CO2 (av. −6.9 percent) suggests some mixing with CO2 derived from thermal breakdown of carbonates within both the prospective sequence and economic basement.

HYDROCARBON GENERATION IN THE AMADEUS BASIN, CENTRAL AUSTRALIA

1984 ◽  
Vol 24 (1) ◽  
pp. 42
Author(s):  
K. S. Jackson D. M. McKirdy ◽  
J. A. Deckelman
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Liquid Hydrocarbons ◽  
Gas Source ◽  
Organic Facies ◽  
Hydrocarbon Fields ◽  
Central Australia ◽  
Oil Source ◽  
To Receive

The Proterozoic to Devonian Amadeus Basin of central Australia contains two hydrocarbon fields — oil and gas at Mereenie and gas at Palm Valley, both within Ordovician sandstone reservoirs. Significant gas and oil shows have also been recorded from Cambrian sandstones and carbonates in the eastern part of the basin. The hydrocarbon generation histories of documented source rocks, determined by Lopatin modelling, largely explain the distribution of the hydrocarbons. The best oil and gas source rocks occur in the Ordovician Horn Valley Siltstone. Source potential is also developed within the Late Proterozoic sequence, particularly the Gillen Member of the Bitter Springs Formation, and the Cambrian.Consideration of organic maturity, relative timing of hydrocarbon generation and trap formation, and oil/source typing leads to the conclusion that the Horn Valley Siltstone charged the Mereenie structure with gas and oil. At Palm Valley, only gas and minor condensate occur because the trap was formed too late to receive an oil charge. Differences in organic facies may also, in part, account for the dry gas and lack of substantial liquid hydrocarbons at Palm Valley. In the eastern Amadeus Basin, the Ordovician is largely absent but Proterozoic sources are well placed to provide the gas discovered by Ooraminna 1 and Dingo 1. Any oil charge here would have preceded trap development.

Hydrocarbon Generation Indication from Source Rock to Reservoir Rock: Case Studies of Anambra and Abakaliki Basins South-Eastern Nigeria

2016 ◽  
Author(s):  
Samuel Salufu ◽  
Rita Onolemhemhen ◽  
Sunday Isehunwa
Keyword(s):  
Case Studies ◽  
Source Rock ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Hydrocarbon Generation ◽  
Geochemical Analysis ◽  
Anambra Basin ◽  
Oil Generation

ABSTRACT This paper sought to use information from outcrop sections to characterize the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin in minimizing uncertainty and risk that are allied with exploration and field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. The methods of study includes detailed geological, stratigraphical, geochemical, structural,, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty eight samples of shale were collected from these Basins; geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software in order to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural, were used to developed a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥ 1wt%, Tmax ≥ 431°C, Vitrinite reflectance values are ≥ 0.6%, and S1+S2 values are > 2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin shows that S1+S2 values range from< 1 – 20mg/g, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from423°C – 466°C. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Abakaliki Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage as a result of S1+S2 values lesser than 2.5mg/g despite TOC values of ≥ 0.5wt% and vitrinite reflectance values of ≥ 0.6%. The novelty of this study is that the study has been able to show that here there is much more oil than the previous authors claimed, and the distribution of this oil and gas in the basins is controlled by two major factors; the pattern of distribution of the materials of the source rock prior to subsidence and during the subsidence period in the basin, and the pattern and the rate of tectonic activities, and heat flow in the basin. If these factors are known, it would help to reduce the uncertainties associated with exploration for oil and gas in the two basins.

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.

HYDROCARBON GENERATION, MIGRATION AND ENTRAPMENT IN THE JACKSON-NACCOWLAH AREA, ATP 259P, SOUTHWESTERN QUEENSLAND

1985 ◽  
Vol 25 (1) ◽  
pp. 62 ◽  
Author(s):  
P.W. Vincent I.R. Mortimore ◽  
D.M. McKirdy
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Structural Development ◽  
Southeastern Part ◽  
Gas Field ◽  
Early Tertiary ◽  
Oil Generation ◽  
Oil Source ◽  
Eromanga Basin

The northern part of the Naccowlah Block, situated in the southeastern part of the Authority to Prospect 259P in southwestern Queensland, is a major Eromanga Basin hydrocarbon province. The Hutton Sandstone is the main reservoir but hydrocarbons have been encountered at several levels within the Jurassic-Cretaceous sequence. In contrast, the underlying Cooper Basin sequence is generally unproductive in the Naccowlah Block although gas was discovered in the Permian at Naccowlah South 1. Oil and gas discoveries within the Eromanga Basin sequence are confined to the Naccowlah-Jackson Trend. This trend forms a prominent high separating the deep Nappamerri Trough from the shallower, more stable northern part of the Cooper Basin.The Murta Member is mature for initial oil generation along the Naccowlah-Jackson Trend and has sourced the small oil accumulations within this unit and the underlying Namur Sandstone Member. The Birkhead Formation is a good source unit in this area with lesser oil source potential also evident in the Westbourne Formation and 'basal Jurassic'. Source quality and maturation considerations imply that much of the oil discovered in Jurassic reservoirs along the Naccowlah-Jackson Trend was generated from more mature Jurassic source beds in the Nappamerri Trough area to the southwest. Maturation modelling of this deeper section suggests that hydrocarbon generation from Jurassic source units commenced in the Early Tertiary. Significant oil generation and migration has therefore occurred since the period of major structural development of the Naccowlah-Jackson Trend in the Early Tertiary. This trend, however, has long been a major focus for hydrocarbon migration paths out of the Nappamerri Trough as a result of intermittent structuring during the Mesozoic. Gas reservoired in Jurassic sandstones at Chookoo has been generated from more mature Jurassic source rocks in the deeper parts of the Nappamerri Trough.Permian sediments in the Nappamerri Trough area are overmature for oil generation and are gas prone. Gas generated in this area has charged the lean Permian gas Field at Naccowlah South, along the Wackett-Naccowlah- Jackson Trend. North of this trend Permian source rocks are mainly gas prone but more favourable levels of maturity allow the accumulation of some gas liquids and oil. However, geological and geochemical evidence suggests that Permian sediments did not source the oil found in Jurassic-Cretaceous reservoirs in the Jackson- Naccowlah area.

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.

Analysis on Migration Patterns and the Distribution of Oil-Gas Controlling Factors of Yushulin Area

2012 ◽  
Vol 616-618 ◽  
pp. 821-832
Author(s):  
Lei Zhang ◽  
Qian Yang ◽  
Xue Juan Zhang ◽  
Zhi Ru Yang
Keyword(s):  
Vertical Migration ◽  
Oil And Gas ◽  
Migration Pattern ◽  
Hydrocarbon Generation ◽  
Gas Migration ◽  
Lateral Migration ◽  
Migration Patterns ◽  
Migration Pathway ◽  
Oil Source ◽  
Oil Gas

In order to ascertain the oil and gas migration pattern and its effect on gas/oil distribution of Yushulin area of Sanzhao depression in Northern Songliao Basin, this paper makes a comprehensive analysis of the oil source condition, the source-reservoir-seal assemblage relationship, the oil and gas migration pathway and patterns in Putaohua and Fuyang oil reservoir, summarizes the oil and gas migration patterns of Yushulin area, and analyses different oil and gas migration pattern influence on oil/gas distribution in Yushulin area combined with structural history, hydrocarbon generation and expulsion history, sedimentary microfacies research. The results show that there are mainly four types of oil and gas migration patterns in Yushulin area: indigenous – downward type - vertical migration pattern, indigenous - normal type - vertical migration pattern, proximal - lateral migration pattern and proximal – “U” type - complex migration pattern.

Deep fluids and their role in hydrocarbon migration and oil deposit formation exemplified by supercritical СO2

2021 ◽  
pp. 1-11
Author(s):  
Sara LIFSHITS
Keyword(s):  
Supercritical Fluid ◽  
Oil And Gas ◽  
Gas Permeability ◽  
Sedimentary Rocks ◽  
Source Rocks ◽  
Reservoir Properties ◽  
Hydrocarbon Migration ◽  
Geological Processes ◽  
Before And After ◽  
Oil Source

ABSTRACT Hydrocarbon migration mechanism into a reservoir is one of the most controversial in oil and gas geology. The research aimed to study the effect of supercritical carbon dioxide (СО2) on the permeability of sedimentary rocks (carbonates, argillite, oil shale), which was assessed by the yield of chloroform extracts and gas permeability (carbonate, argillite) before and after the treatment of rocks with supercritical СО2. An increase in the permeability of dense potentially oil-source rocks has been noted, which is explained by the dissolution of carbonates to bicarbonates due to the high chemical activity of supercritical СО2 and water dissolved in it. Similarly, in geological processes, the introduction of deep supercritical fluid into sedimentary rocks can increase the permeability and, possibly, the porosity of rocks, which will facilitate the primary migration of hydrocarbons and improve the reservoir properties of the rocks. The considered mechanism of hydrocarbon migration in the flow of deep supercritical fluid makes it possible to revise the time and duration of the formation of gas–oil deposits decreasingly, as well as to explain features in the formation of various sources of hydrocarbons and observed inflow of oil into operating and exhausted wells.

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