NEW LIGHT ON THE ORIGIN OF COOPER BASIN OIL

1988 ◽  
Vol 28 (1) ◽  
pp. 303 ◽  
Author(s):  
G.H.Taylor G.H.Taylor ◽  
Susie Y. Liu ◽  
Michelle Smyth

The Cooper Basin in central Australia is a major producer of gas and oil. It is generally accepted that the organic matter in the Permian terrestrial sediments of the Basin was the source of the oil and gas. However, both the coals and the dispersed organic matter (DOM) are rich in inertinite and both inertinite itself and inertinite-rich organic matter have been widely discounted as a possible source for oil.Recent co-ordinated transmission electron microscope and light microscope work on the inertiniterich coals of the Cooper Basin has shown that up to several per cent of some coal samples are composed of microscopic and sub-microscopic alginite. This includes material that had previously been identified with the light microscope alone as degraded sporinite, liptodetrinite or resinite, as well as algal-derived matter, which is too fine to observe with light microscopy. Much of this material of algal origin was selectively degraded at about the time of its deposition, and this degradation appears likely to have had the effect of further enhancing its potential to yield hydrocarbons. Thus, such material should be ranked among the richest potential sources of hydrocarbons when appropriate diagenetic conditions have been attained. Since inertinite and this kind of alginite occur in particularly close association, the presence of inertinite-rich coals and DOM within potential source rocks should be regarded as a highly favourable rather than an unfavourable, indication (as in the past).The quantity of alginite in the very large volumes of inertinite-rich coal in the Basin is more than adequate to account for the oil accumulations. In the Cooper Basin the coals, rather than the DOM, had the better potential for oil generation.

1994 ◽  
Vol 34 (1) ◽  
pp. 279 ◽  
Author(s):  
Dennis Taylor ◽  
Aleksai E. Kontorovich ◽  
Andrei I. Larichev ◽  
Miryam Glikson

Organic rich shale units ranging up to 350 m in thickness with total organic carbon (TOC) values generally between one and ten per cent are present at several stratigraphic levels in the upper part of the Carpentarian Roper Group. Considerable variation in depositional environment is suggested by large differences in carbon:sulphur ratios and trace metal contents at different stratigraphic levels, but all of the preserved organic matter appears to be algal-sourced and hydrogen-rich. Conventional Rock-Eval pyrolysis indicates that a type I-II kerogen is present throughout.The elemental chemistry of this kerogen, shows a unique chemical evolution pathway on the ternary C:H:ONS diagram which differs from standard pathways followed by younger kerogens, suggesting that the maturation histories of Proterozoic basins may differ significantly from those of younger oil and gas producing basins. Extractable organic matter (EOM) from Roper Group source rocks shows a chemical evolution from polar rich to saturate rich with increasing maturity. Alginite reflectance increases in stepwise fashion through the zone of oil and gas generation, and then increases rapidly at higher levels of maturation. The increase in alginite reflectance with depth or proximity to sill contacts is lognormal.The area explored by Pacific Oil and Gas includes a northern area where the Velkerri Formation is within the zone of peak oil generation and the Kyalla Member is immature, and a southern area, the Beetaloo sub-basin, where the zone of peak oil generation is within the Kyalla Member. Most oil generation within the basin followed significant folding and faulting of the Roper Group.


2003 ◽  
Vol 43 (1) ◽  
pp. 117 ◽  
Author(s):  
C.J. Boreham ◽  
J.E. Blevin ◽  
A.P. Radlinski ◽  
K.R. Trigg

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.


2015 ◽  
Vol 2015 ◽  
pp. 1-11 ◽  
Author(s):  
Olumuyiwa Adedotun Odundun

Organic geochemical studies and fossil molecules distribution results have been employed in characterizing subsurface sediments from some sections of Anambra Basin, southeastern Nigeria. The total organic carbon (TOC) and soluble organic matter (SOM) are in the range of 1.61 to 69.51 wt% and 250.1 to 4095.2 ppm, respectively, implying that the source rocks are moderately to fairly rich in organic matter. Based on data of the paper, the organic matter is interpreted as Type III (gas prone) with little oil. The geochemical fossils and chemical compositions suggest immature to marginally mature status for the sediments, with methyl phenanthrene index (MPI-1) and methyl dibenzothiopene ratio (MDR) showing ranges of 0.14–0.76 and 0.99–4.21, respectively. The abundance of 1,2,5-TMN (Trimethyl naphthalene) in the sediments suggests a significant land plant contribution to the organic matter. The pristane/phytane ratio values of 7.2–8.9 also point to terrestrial organic input under oxic conditions. However, the presence of C27 to C29 steranes and diasteranes indicates mixed sources—marine and terrigenous—with prospects to generate both oil and gas.


2021 ◽  
Author(s):  
◽  
Enock Rotich

<p>The Re-Os radiogenic isotope system has over the past three decades been successfully applied to organic-rich sedimentary rocks and oils as a geochronometer and geochemical tracer. The Re-Os geochronometer has provided a direct way of constraining the depositional age of organic-rich sediments as well as the timing of oil generation events. Osmium isotopic compositions have further been utilised in understanding past climatic, oceanographic and geological events recorded in sediments, and in correlating oils to their source. Thus far, however, Re-Os studies of organic-rich sediments have mainly focused on marine black shales where Re and Os are primarily sourced from seawater. The work presented in this thesis seeks to investigate factors controlling Re-Os systematics and potential for geochronology in a range of fluvio-deltaic coaly rocks and terrestrial organic matter-dominated marine sediments, and associated oils from New Zealand’s Taranaki and East Coast basins. The Re-Os data presented here yield the first radiometric age for the late Paleocene Waipawa Formation (57.5 ± 3.5 Ma), a marine sedimentary unit that was formed by episodic input of large amounts of terrestrial woody plant matter resulting in high average sedimentation rates of up to ~10.6 cm/ky. This age is consistent with available biostratigraphic age determinations. The formation possesses Re (38.9 ± 17.6 ppb) and Os (526 ± 75.8 ppt) concentrations similar to those found in typical marine sediments containing amorphous organic matter deposited under much lower sedimentation rates. This indicates that organic matter type and sedimentation rate may not play a significant role in sequestration of these elements in organic-rich sediments. Unlike the Waipawa Formation, coals and coaly mudstones with varying degrees of marine influence (purely terrestrial to strongly marine-influenced) from the Rakopi, North Cape, Farewell and Mangahewa formations record low average Re (0.37 ± 0.25 ppb) and Os (24.5 ± 11.9 ppt) concentrations. These concentrations are up to two orders of magnitude lower than those of similarly marine-influenced coals from the Matewan coalbed, USA, suggesting that Re and Os enrichment in coals does not simply correlate with the level of marine influence; the timing and nature of the marine influence, as well as chelation ability of organic-rich sediments, are equally important. The initial 187Os/188Os (Osi) values for the Waipawa (~0.28) and underlying Whangai (~0.36) formations are broadly similar to those reported for coeval pelagic sediments from the central Pacific Ocean, further constraining the low-resolution marine 187Os/188Os record of the Paleocene. A broad correlation between this record and global temperature (δ18O and TEX86) and carbon isotope (δ13C) records is observed from the middle Paleocene to early Eocene, which is inferred to reflect climate-modulated changes in continental weathering patterns. Unlike the marine sediments, significant variations are noted in the Osi of the Taranaki Basin coaly rocks. These are linked to depositional and diagenetic conditions, degree of water connectivity with the open ocean, and sediment source. The large variations in Osi values combined with small ranges in 187Re/188Os ratios and relatively young ages are considered as factors that hindered development of Re-Os isochrons in these rocks. Crude oils sourced from the Taranaki coals and coaly mudstones also record low average Re (0.31 ± 0.09 ppb) and Os (14 ± 7.6 ppt) concentrations and have 187Re/188Os and 187Os/188Os ratios that do not correlate on an isochron diagram. The lack of an isochron fit for these oils is mainly attributed to a large variation in Osi values (0.47-1.14) resulting from the heterogeneous nature of their potential Rakopi and North Cape coaly source rocks and a lengthy (20 Myr) oil generation event. These Osi values, however, overlap with 187Os/188Os values for the potential source rocks at the time (ca.10 Ma) of oil generation (0.38-1.26), suggesting that Os isotopes may be utilised in tracing these oils. Crude oils that have potentially been sourced from the Waipawa and Whangai formations record much higher Re (2.86 ± 1.92 ppb) and Os (166 ± 142 ppt) concentrations than the coaly-sourced oils, and show Os isotopic compositions that either correlate with those of their potential source rocks (e.g., oil Osi = ~0.63 compared with Waipawa Formation 187Os/188Os = 0.48–0.68 at time of oil generation) or differ due to likely secondary alteration processes within the reservoir such as thermochemical sulfate reduction (TSR).</p>


2007 ◽  
Vol 47 (1) ◽  
pp. 127 ◽  
Author(s):  
G. Ambrose ◽  
M. Scardigno ◽  
A.J. Hill

Prospective Middle–Late Triassic and Early Jurassic petroleum systems are widespread in central Australia where they have only been sparsely explored. These systems are important targets in the Simpson/Eromanga basins (Poolowanna Trough and surrounds), but the petroleum systems also extend into the northern and eastern Cooper Basin.Regional deposition of Early–Middle Triassic red-beds, which provide regional seal to the Permian petroleum system, are variously named the Walkandi Formation in the Simpson Basin, and the Arrabury Formation in the northern and eastern Cooper Basin. A pervasive, transgressive lacustrine sequence (Middle–Late Triassic Peera Peera Formation) disconformably overlies the red-beds and can be correlated over a distance of 500 km from the Poolowanna Trough into western Queensland, thus providing the key to unravelling Triassic stratigraphic architecture in the region. The equivalent sequence in the northern Cooper Basin is the Tinchoo Formation. These correlations allow considerable simplification of Triassic stratigraphy in this region, and demonstrate the wide lateral extent of lacustrine source rocks that also provide regional seal. Sheet-like, fluvial-alluvial sands at the base of the Peera Peera/Tinchoo sequence are prime reservoir targets and have produced oil at James–1, with widespread hydrocarbon shows occurring elsewhere including Poolowanna–1, Colson–1, Walkandi–1, Potiron–1 and Mackillop–1.The Early Jurassic Poolowanna Formation disconformably overlies the Peera Peera Formation and can be subdivided into two transgressive, fluvial-lacustrine cycles, which formed on a regional scale in response to distal sea level oscillations. Early Jurassic stratigraphic architecture in the Poolowanna Trough is defined by a lacustrine shale capping the basal transgressive cycle (Cycle 1). This shale partitions the Early Jurassic aquifer in some areas and significant hydrocarbon shows and oil recoveries are largely restricted to sandstones below this seal. Structural closure into the depositional edge of Cycle 1 is an important oil play.The Poolowanna and Peera Peera formations, which have produced minor oil and gas/condensate on test respectively in Poolowanna–1, include lacustrine source rocks with distinct coal maceral compositions. Significantly, the oil-bearing Early Jurassic sequence in Cuttapirrie–1 in the Cooper Basin correlates directly with the Cycle–1 oil pool in Poolowanna–1. Basin modelling in the latter indicates hydrocarbon expulsion occurred in the late Cretaceous (90–100 Ma) with migration into a subtle Jurassic age closure. Robust Miocene structural reactivation breached the trap leaving only minor remnants of water-washed oil. Other large Miocene structures, bound by reverse faults and some reflecting major inversion, have failed to encounter commercial hydrocarbons. Future exploration should target subtle Triassic to Jurassic–Early Cretaceous age structural and combination stratigraphic traps largely free of younger fault dislocation.


1990 ◽  
Vol 30 (1) ◽  
pp. 166 ◽  
Author(s):  
D.C. Roberts ◽  
P.G. Carroll ◽  
J. Sayers

The Warburton Basin is currently considered economic basement to the gas-oil productive Cooper Basin and the oil productive Eromanga Basin. Only 10 wells have penetrated more than 100 m of the Kalladeina Formation which is identified as the most prospective section within the Warburton Basin. The Kalladeina Formation consists of more than 1600 m of carbonate shelf sediments deposited during the early Cambrian to early Ordovician in a basin consisting of half grabens on the continental side of an active margin.Several intra-Kalladeina Formation seismic events in a 500 km2 region to the west of the Gidgealpa oil and gas field have been tied to wells with palaeontological control. Structure and isopach mapping illustrates large scale thrusts, wrench fault zones and subcrop edges for the Kalladeina Formation. Maps of unconformities and of formations above the Warburton Basin define source, seal and trap relationships.Good carbonate reservoirs have been identified in the Kalladeina Formation but the source potential of this succession appears to be restricted. The overlying Cooper Basin source rocks may have charged the underlying carbonates and this represents one of three play types identified in the area.All Warburton Basin plays are very high risk but potential reserves are also large.


2021 ◽  
Vol 54 (2E) ◽  
pp. 59-85
Author(s):  
Dler Baban

Thirty rock samples were selected from the well Tq-1 that penetrated the Jurassic beds in the Taq Taq Oilfield to be studied the source rock potentiality of the Sargelu Formation. The formation is characterized by three types of microfacies, namely, foraminiferal packstone, grainstone microfacies, fossiliferous packstone microfacies, and foraminiferal wackestone which were deposited in an environment extending from middle to outer carbonate ramp. An average of 3.03 wt.% of total organic carbon was obtained from a Rock Eval pyrolysis analysis carried out on 24 selected rock samples. The petrographic analysis for such organic matters revealed that they are of kerogen types III and IV and they are currently in a post-mature state. Pyrolysis parameters showed that limited generation potential was remained for these sources to expel generated hydrocarbons. The palynological study showed that Amorphous Organic Matter forms the highest percentage of organic matter components with more than 70%, followed by phytoclasts with 10 – 25 % and palynomorphs of less than 10%. The organic matters within the Sargelu Formation are deposited at the distal part of the basin under suboxic to anoxic condition. The color of the organic matter components, examined under transmitted light, showed Thermal Alteration Index values between 3+ and 4-. Such values may indicate that these organic matters are thermally at the end of the liquid oil generation zone and beginning of condensate-wet gas generation zone. The thermal maturity of the Sargelu Formation depending on the calculated VRo% revealed that the formation in the studied oilfield is currently at the peak of the oil generation zone. The Sargelu Formation in the studied field is considered as an effective source rock, as it has already generated and expelled hydrocarbons.


Author(s):  
T. B. Mikerina ◽  
N. P. Fadeeva

Use of infrared spectrometry method for examination of bituminous components of dispersed organic matter in Mesozoic and Cenozoic deposits of the Azov-Kuban petroleum basin gave very important information about conditions of formation of source rocks containing organic matter and the degree of its diagenetic or catagenetic transformation level. Character of infrared spectrums represented by 15 genetic types of chloroform bitumen allows to subdivide the zones with the source beds absence, zones of oil generation and zones where this processes have come to the end.


Author(s):  
Yang Houqiang ◽  
E. V. Soboleva

In recent years, significant successes have been achieved in the search and exploration of oil and gas reservoirs in the Jurassic deposits on the eastern side of the Fukang depression, which is the least studied part of the Junggar oil and gas Basin. In order to find out the source of hydrocarbon generation, we studied source rocks, oil and oil-bearing sandstones (24 samples from 13 wells) from the Badaowan, Sangonghe, Xishanyao, Toutunhe and Qigu production beds of the Fukang depression research area. Based on these studies, the composition of the organic matter of the Jurassic source rocks, the properties and molecular composition of oils, as well as the characteristics of the composition of biomarkers in them are examined in detail. The results of research and interpretation of the data showed that the mudstones of the Badaowan formation were source rocks of oil from the Gumudi zone, the Fukan depression, the Bajiahai ledge and the Shaqi ledge.


2020 ◽  
Author(s):  
Tian-Jun Li ◽  
Zhi-Long Huang ◽  
Xuan Chen ◽  
Xin-Ning Li ◽  
Jun-Tian Liu

AbstractVolcanic activity was quite frequent during the deposition of the Late Carboniferous Ha’erjiawu Formation in the Santanghu Basin. The petrology and organic and inorganic geochemical indicators were used to investigate hydrocarbon potential, paleoenvironmental conditions and organic matter enrichment of the mudstones. The results show that the oil generation capacity of the Ha’erjiawu Formation mudstones, which has abundant oil-prone organic matter (Type II kerogen with hydrogen index values mainly ranging from 250 to 550 mg HC/g TOC) in mature stage (Tmax values mainly ranging from 435 to 450 °C), is considerable. The Ha’erjiawu Formation was deposited in a dysoxic, freshwater-mildly brackish, and warm-humid environment. During its deposition, the Ha’erjiawu Formation received hydrothermal inputs. The volcanic hydrothermal activities played an important role in the organic matter enrichment. In addition, the total organic carbon (TOC) is significantly positively correlated with the felsic mineral content, but it is negatively correlated with the carbonate mineral content and C27/C29 ratios, indicating that terrigenous organic matter input also contributed to the primary productivity in the surface water. Therefore, the formation of the high-quality source rocks in the Ha’erjiawu Formation was jointly affected by the hydrothermal activity and the terrigenous organic matter input.


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