Cooper Basin source rock atlas

2016 ◽  
Vol 56 (2) ◽  
pp. 594
Author(s):  
Lisa Hall ◽  
Tehani Palu ◽  
Chris Boreham ◽  
Dianne Edwards ◽  
Tony Hill ◽  
...  
Keyword(s):  
Spatial Distribution ◽  
Source Rock ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Predictive Tool ◽  
Resource Potential ◽  
Petroleum Systems ◽  
Petroleum Resource ◽  
Hydrocarbon Yield ◽  
Cooper Basin

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.

Research for the Upstream Petroleum Sector: The Crown Research Institute Concept

1995 ◽  
Vol 13 (2-3) ◽  
pp. 245-252
Author(s):  
J M Beggs
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Publicly Funded ◽  
Petroleum Systems ◽  
Oil And Gas Resources ◽  
Petroleum Sector ◽  
Geological Sciences ◽  
Research Institute

New Zealand's scientific institutions have been restructured so as to be more responsive to the needs of the economy. Exploration for and development of oil and gas resources depend heavily on the geological sciences. In New Zealand, these activities are favoured by a comprehensive, open-file database of the results of previous work, and by a historically publicly funded, in-depth knowledge base of the extensive sedimentary basins. This expertise is now only partially funded by government research contracts, and increasingly undertakes contract work in a range of scientific services to the upstream petroleum sector, both in New Zealand and overseas. By aligning government-funded research programmes with the industry's knowledge needs, there is maximum advantage in improving the understanding of the occurrence of oil and gas resources. A Crown Research Institute can serve as an interface between advances in fundamental geological sciences, and the practical needs of the industry. Current publicly funded programmes of the Institute of Geological and Nuclear Sciences include a series of regional basin studies, nearing completion; and multi-disciplinary team studies related to the various elements of the petroleum systems of New Zealand: source rocks and their maturation, migration and entrapment as a function of basin structure and tectonics, and the distribution and configuration of reservoir systems.

scholarly journals GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

Resolving thermal histories via multi-kinetic apatite fission track data: A case study from Phanerozoic strata within the Peel Plateau NWT, Canada

2021 ◽  
Author(s):  
Jennifer Spalding ◽  
Jeremy Powell ◽  
David Schneider ◽  
Karen Fallas
Keyword(s):  
Low Temperature ◽  
Thermal History ◽  
Fission Track ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Apatite Fission Track ◽  
Petroleum Systems ◽  
History Of ◽  
Thermal Histories ◽  
Peel Plateau

&lt;p&gt;Resolving the thermal history of sedimentary basins through geological time is essential when evaluating the maturity of source rocks within petroleum systems. Traditional methods used to estimate maximum burial temperatures in prospective sedimentary basin such as and vitrinite reflectance (%Ro) are unable to constrain the timing and duration of thermal events. In comparison, low-temperature thermochronology methods, such as apatite fission track thermochronology (AFT), can resolve detailed thermal histories within a temperature range corresponding to oil and gas generation. In the Peel Plateau of the Northwest Territories, Canada, Phanerozoic sedimentary strata exhibit oil-stained outcrops, gas seeps, and bitumen occurrences. Presently, the timing of hydrocarbon maturation events are poorly constrained, as a regional unconformity at the base of Cretaceous foreland basin strata indicates that underlying Devonian source rocks may have undergone a burial and unroofing event prior to the Cretaceous. Published organic thermal maturity values from wells within the study area range from 1.59 and 2.46 %Ro for Devonian strata and 0.54 and 1.83 %Ro within Lower Cretaceous strata. Herein, we have resolved the thermal history of the Peel Plateau through multi-kinetic AFT thermochronology. Three samples from Upper Devonian, Lower Cretaceous and Upper Cretaceous strata have pooled AFT ages of 61.0 &amp;#177; 5.1 Ma, 59.5 &amp;#177; 5.2 and 101.6 &amp;#177; 6.7 Ma, respectively, and corresponding U-Pb ages of 497.4 &amp;#177; 17.5 Ma (MSWD: 7.4), 353.5 &amp;#177; 13.5 Ma (MSWD: 3.1) and 261.2 &amp;#177; 8.5 Ma (MSWD: 5.9). All AFT data fail the &amp;#967;&lt;sup&gt;2&lt;/sup&gt; test, suggesting AFT ages do not comprise a single statistically significant population, whereas U-Pb ages reflect the pre-depositional history of the samples and are likely from various provenances. Apatite chemistry is known to control the temperature and rates at which fission tracks undergo thermal annealing. The r&lt;sub&gt;mro&lt;/sub&gt; parameter uses grain specific chemistry to predict apatite&amp;#8217;s kinetic behaviour and is used to identify kinetic populations within samples. Grain chemistry was measured via electron microprobe analysis to derive r&lt;sub&gt;mro&lt;/sub&gt; values and each sample was separated into two kinetic populations that pass the &amp;#967;&lt;sup&gt;2&lt;/sup&gt; test: a less retentive population with ages ranging from 49.3 &amp;#177; 9.3 Ma to 36.4 &amp;#177; 4.7 Ma, and a more retentive population with ages ranging from 157.7 &amp;#177; 19 Ma to 103.3 &amp;#177; 11.8 Ma, with r&lt;sub&gt;mr0&lt;/sub&gt; benchmarks ranging from 0.79 and 0.82. Thermal history models reveal Devonian strata reached maximum burial temperatures (~165&amp;#176;C-185&amp;#176;C) prior to late Paleozoic to Mesozoic unroofing, and reheated to lower temperatures (~75&amp;#176;C-110&amp;#176;C) in the Late Cretaceous to Paleogene. Both Cretaceous samples record maximum burial temperatures (75&amp;#176;C-95&amp;#176;C) also during the Late Cretaceous to Paleogene. These new data indicate that Devonian source rocks matured prior to deposition of Cretaceous strata and that subsequent burial and heating during the Cretaceous to Paleogene was limited to the low-temperature threshold of the oil window. Integrating multi-kinetic AFT data with traditional methods in petroleum geosciences can help unravel complex thermal histories of sedimentary basins. Applying these methods elsewhere can improve the characterisation of petroleum systems.&lt;/p&gt;

scholarly journals Oil chemometrics and geochemical correlation in the Weixinan Sag, Beibuwan Basin, South China Sea

2020 ◽  
Vol 38 (6) ◽  
pp. 2695-2710
Author(s):  
Yao-Ping Wang ◽  
Xin Zhan ◽  
Tao Luo ◽  
Yuan Gao ◽  
Jia Xia ◽  
...  
Keyword(s):  
Source Rock ◽  
Principal Component ◽  
Sedimentary Basins ◽  
Oil Field ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Crude Oils ◽  
Geochemical Parameters ◽  
Group I ◽  
Oil Source

The oil–oil and oil–source rock correlations, also termed as geochemical correlations, play an essential role in the construction of petroleum systems, guidance of petroleum exploration, and definition of reservoir compartments. In this study, the problems arising from oil–oil and oil–source rock correlations were investigated using chemometric methods on oil and source rock samples from the WZ12 oil field in the Weixinan sag in the Beibuwan Basin. Crude oil from the WZ12 oil field can be classified into two genetic families: group A and B, using multidimensional scaling and principal component analysis. Similarly, source rocks of the Liushagang Formation, including its first, second, and third members, can be classified into group I and II, corresponding to group B and A crude oils, respectively. The principle geochemical parameters in the geochemical correlation for the characterisation and classification of crude oils and source rocks were 4MSI, C27Dia/C27S, and C24 Tet/C26 TT. This study provides insights into the selection of appropriate geochemical parameters for oil–oil and oil–source rock correlations, which can also be applied to other sedimentary basins.

Study on source rock potential and source rocks spatial distribution in the Manghan Faulted Sag, Kailu Basin

2007 ◽  
Vol 8 (11) ◽  
pp. 1872-1878
Author(s):  
Zhi-jun Yin ◽  
Feng Zhang ◽  
Hua-yao Zou ◽  
Wei-xing Wang ◽  
Lian-min Zhou ◽  
...  
Keyword(s):  
Spatial Distribution ◽  
Source Rock ◽  
Source Rocks

scholarly journals Petroleum resource potential of sedimentary basins on the pacific margin of Canada

2001 ◽  
Author(s):  
P K Hannigan ◽  
J R Dietrich ◽  
P J Lee ◽  
K G Osadetz
Keyword(s):  
Sedimentary Basins ◽  
Resource Potential ◽  
Petroleum Resource ◽  
The Pacific ◽  
Pacific Margin

PETROLEUM PLAY ELEMENT PREDICTION FOR THE CRETACEOUS-TERTIARY BASIN PHASE, NORTHERN CARNARVON BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 315 ◽  
Author(s):  
K. K. Romine ◽  
J. M. Durrant ◽  
D. L. Cathro ◽  
G. Bernardel
Keyword(s):  
Focal Point ◽  
Source Rocks ◽  
Predictive Tool ◽  
Petroleum Systems ◽  
The North ◽  
Northern Carnarvon Basin ◽  
And Migration ◽  
Play Elements ◽  
Migration Pathways ◽  
Carnarvon Basin

A regional tectono-stratigraphic framework has been developed for the Cretaceous and Tertiary section in the Northern Carnarvon Basin. This framework places traditional observations in a new context and provides a predictive tool for determining the temporal occurrence and spatial distribution of the lithofacies play elements, that iss reservoir, source and seal.Two new, potential petroleum systems have been identified within the Barremian Muderong Shale and Albian Gearle Siltstone. These potential source rocks could be mature or maturing along a trend that parallels the Alpha Arch and Rankin Platform, and within the Exinouth Sub-basin.A favourable combination of reservoir and seal can be predicted for the early regressive part of the Creta- ceous-Tertiary basin phase (Campanian-Palaeocene). Lowstand and transgressive (within incised valleys) reservoirs are more likely to be isolated and encased in sealing shales, similar to lowstand reservoir facies deposited during the transgressive part of the basin phase, for example, the M. australis sand play.The basin analysis revealed the important role played by pre-existing Proterozoic-Palaeozoic lineaments during extension, and the subsequent impact on play elements, in particular, the distribution of reservoir, fluid migration, and trap development. During extension, the north-trending lineaments influenced the compart mentalisation of the Northern Carnarvon Basin into discrete depocentres. Relay ramp-style accommodation zones developed, linking the sub-basins, and acting as pathways for sediment input into the depocentres and, later in the basin's history, as probable hydrocarbon migration pathways. The relay accommodation zones are a dynamic part of the basin architecture, acting as a focal point for response to intraplate stresses and the creation, modification and destruction of traps and migration pathways.

PETROLEUM GEOLOGY OF MIDDLE–LATE TRIASSIC AND EARLY JURASSIC SEQUENCES IN THE SIMPSON BASIN AND NORTHERN EROMANGA BASIN OF CENTRAL AUSTRALIA

2007 ◽  
Vol 47 (1) ◽  
pp. 127 ◽  
Author(s):  
G. Ambrose ◽  
M. Scardigno ◽  
A.J. Hill
Keyword(s):  
Oil And Gas ◽  
Regional Scale ◽  
Early Jurassic ◽  
Source Rocks ◽  
Late Triassic ◽  
Red Beds ◽  
Petroleum Systems ◽  
Stratigraphic Architecture ◽  
Central Australia ◽  
Cooper Basin

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.

scholarly journals Petroleum resource potential of sedimentary Basins on the Pacific margin of Canada

1998 ◽  
Author(s):  
P K Hannigan ◽  
J R Dietrich ◽  
P J Lee ◽  
K G Osadetz
Keyword(s):  
Sedimentary Basins ◽  
Resource Potential ◽  
Petroleum Resource ◽  
The Pacific ◽  
Pacific Margin
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