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.

THE STRUCTURAL DEVELOPMENT AND HYDROCARBON POTENTIAL OF PALAEOZOIC SOURCE ROCKS IN THE ADAVALE BASIN REGION

1984 ◽  
Vol 24 (1) ◽  
pp. 393 ◽  
Author(s):  
V. L. Passmore ◽  
M. J. Sexton
Keyword(s):  
Middle Devonian ◽  
Oil And Gas ◽  
Structural Features ◽  
Source Rocks ◽  
Geochemical Data ◽  
Mature Stage ◽  
Hydrocarbon Generation ◽  
Structural Development ◽  
Seismic Reflection Data ◽  
Basin Region

The Adavale Basin of southwestern Queensland consists of a main depression and several isolated synclinal extensions, traditionally referred to as troughs. The depressions and troughs are erosional remnants of a once more extensive Devonian depositional basin, and are now completely buried by sediments of the overlying Cooper, Galilee and Eromanga Basins. Geophysical and drilling investigations undertaken since 1959 are the only source of information on the Adavale Basin. A single sub-economic discovery of dry gas at Gilmore and a few shows of oil and gas are the only hydrocarbons located in the basin to date.In 1980, the Bureau of Mineral Resources in cooperation with the Geological Survey of Queensland commenced a major, multidisciplinary investigation of the basins in southwestern Queensland. Four long (> 200 km) seismic lines from this study over the Adavale Basin region and geochemical data from 20 wells were used to interpret the Adavale Basin's development and its present hydrocarbon potential.The new seismic reflection data allow the well-explored main depression to be correlated with the detached troughs, some of which have little or no well information. The BMR seismic data show that these troughs were previously part of one large depositional basin in the Devonian, the depocentre of which lay east of a north-trending hingeline. Structural features and Devonian depositional limits and patterns have been modified from earlier interpretations as a result of the new seismic coverage. The maximum sediment thickness is re-interpreted to be 8500 m, considerably thicker than previous interpretation.recognised. The first one, a diachronous Middle Devonian unconformity, is the most extensive, and reflects the mobility of the basement during the basin's early history. The second unconformity within the Late Devonian Buckabie Formation reveals that there were two phases of deformation of the basin sediments.The geochemical results reported in this study show that most of the Adavale Basin sediments have very low concentrations of organic carbon and hydrocarbon fractions. Maturity profiles indicate that the best source rocks of the basin are now in the mature stage for hydrocarbon generation. However, at Gilmore and in the Cooladdi Trough, they have reached the dry gas stage. The maturity data provide additional evidence for the marked break in deposition and significant erosion during the Middle Devonian recognised on the seismic records, and extend the limits of this sedimentary break into the northern part of the main depression.Hydrocarbon potential of the Adavale Basin is fair to poor. In the eastern part of the basin, where most of the data are available, the prospects are better for gas than oil. Oil prospectivity may be improved in any exinite-rich areas that exist farther west, where palaeo-temperatures were lower.

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.

scholarly journals Oil And Gas Generation History Based On Burial History Reconstruction And Thermal Maturity Modeling Of Petroleum Systems In Northern Iraq

2020 ◽  
Vol 10 (4) ◽  
pp. 95-120
Author(s):  
Rzger Abdulkarim Abdula
Keyword(s):  
Source Rock ◽  
Late Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Burial History ◽  
Gas Generation ◽  
Northern Iraq ◽  
Oil Generation

Burial history, thermal maturity, and timing of hydrocarbon generation were modeled for five key source-rock horizons at five locations in Northern Iraq. Constructed burial-history locations from east to west in the region are: Taq Taq-1; Qara Chugh-2; Zab-1; Guwair-2; and Shaikhan-2 wells. Generally, the thermal maturity status of the burial history sites based on increasing thermal maturity is Shaikhan-2 < Zab-1 < Guwair-2 < Qara Chugh-2 < Taq Taq-1. In well Qara Chugh-2, oil generation from Type-IIS kerogen in Geli Khana Formation started in the Late Cretaceous. Gas generation occurred at Qara Chugh-2 from Geli Khana Formation in the Late Miocene. The Kurra Chine Formation entered oil generation window at Guwair-2 and Shaikhan-2 at 64 Ma and 46 Ma, respectively. At Zab-1, the Baluti Formation started to generate gas at 120 Ma. The Butmah /Sarki reached peak oil generation at 45 Ma at Taq Taq-1. The main source rock in the area, Sargelu Formation started to generate oil at 47, 51, 33, 28, and 28 Ma at Taq Taq-1, Guwair-2, Shaikhan-2, Qara Chugh-2, and Zab-1, respectively. The results of the models demonstrated that peak petroleum generation from the Jurassic oil- and gas-prone source rocks in the most profound parts of the studied area occurred from Late Cretaceous to Middle Oligocene. At all localities, the Sargelu Formation is still within the oil window apart from Taq Taq-1 and Qara Chugh-2 where it is in the oil cracking and gas generation phase.

scholarly journals Geochemical Characteristics and Oil Source Correlation of Minfeng Area, Dongying Depression, China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Dongmei Bo ◽  
Lin Jiang ◽  
Wen Zhao ◽  
Youlu Jiang ◽  
Hua Liu ◽  
...  
Keyword(s):  
Crude Oil ◽  
Early Stage ◽  
Geochemical Characteristics ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Hydrocarbon Generation ◽  
Gas Field ◽  
Lateral Direction ◽  
Source Correlation ◽  
Oil Source

The identification of the oil-source correlation plays a significant role in petroleum exploration and development. In this study, we identify the oil-source correlation by a hierarchical cluster analysis method combined with traditional methods. The results shed light on the oil-source correlation in Minfeng area and revealed the oil migration and accumulation process. The crude oil in different structural belts and different horizons has different geochemical characteristics. According to the four types of crude oil and their planner distribution, it was considered that the crude oil mainly migrates along with favorable sand bodies and unconformity surfaces in the lateral direction and then charged and accumulated in the glutenite of Sha3 and Sha4 members since the area from sag to Yan Jia Oil and the gas field was lacking of oil source faults. Further analysis shows that the traps of fault blocks in Yong’anzhen are formed in the same phase, while the crude oil generated in the early stage is charged and accumulated in the fault block of the near source. Along with increasing of the buried depth of source rocks, the overlying source rocks gradually entered into the hydrocarbon generation phase, when crude oil started to charge in the fault blocks farther away.

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.

scholarly journals Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

2018 ◽  
Vol 36 (5) ◽  
pp. 1229-1244
Author(s):  
Xiao-Rong Qu ◽  
Yan-Ming Zhu ◽  
Wu Li ◽  
Xin Tang ◽  
Han Zhang
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Bohai Bay Basin ◽  
Important Conclusion ◽  
The North ◽  
Huanghua Depression ◽  
History Of

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

scholarly journals New exploration strategy in igneous petroliferous basins – Enlightenment from simulation experiments

2018 ◽  
Vol 36 (4) ◽  
pp. 971-985
Author(s):  
Qingqiang Meng ◽  
Jiajun Jing ◽  
Jingzhou Li ◽  
Dongya Zhu ◽  
Ande Zou ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Liquid Hydrocarbon ◽  
Hydrogen Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Simulation Experiments ◽  
Gaseous Hydrocarbon ◽  
Oil And Gas Fields ◽  
Gaseous Hydrocarbons ◽  
Hydrocarbon Productivity

There are two kinds of relationships between magmatism and the generation of hydrocarbons from source rocks in petroliferous basins, namely: (1) simultaneous magmatism and hydrocarbon generation, and (2) magmatism that occurs after hydrocarbon generation. Although the influence of magmatism on hydrocarbon source rocks has been extensively studied, there has not been a systematic comparison between these two relationships and their influences on hydrocarbon generation. Here, we present an overview of the influence of magmatism on hydrocarbon generation based on the results of simulation experiments. These experiments indicate that the two relationships outlined above have different influences on the generation of hydrocarbons. Magmatism that occurred after hydrocarbon generation contributed deeply sourced hydrogen gas that improved liquid hydrocarbon productivity between the mature and overmature stages of maturation, increasing liquid hydrocarbon productivity to as much as 451.59% in the case of simulation temperatures of up to 450°C during modelling where no hydrogen gas was added. This relationship also increased the gaseous hydrocarbon generation ratio at temperatures up to 450°C, owing to the cracking of initially generated liquid hydrocarbons and the cracking of kerogen. Our simulation experiments suggest that gaseous hydrocarbons dominate total hydrocarbon generation ratios for overmature source rocks, resulting in a change in petroleum accumulation processes. This in turn suggests that different exploration strategies are warranted for the different relationships outlined above. For example, simultaneous magmatism and hydrocarbon generation in an area means that exploration should focus on targets likely to host large oilfields, whereas in areas with magmatism that post-dates hydrocarbon generation the exploration should focus on both oil and gas fields. In addition, exploration strategies in igneous petroliferous basins should focus on identifying high-quality reservoirs as well as determining the relationship between magmatism and initial hydrocarbon generation.

scholarly journals Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China

2018 ◽  
Vol 36 (4) ◽  
pp. 801-819 ◽  
Author(s):  
Shuangfeng Zhao ◽  
Wen Chen ◽  
Zhenhong Wang ◽  
Ting Li ◽  
Hongxing Wei ◽  
...  
Keyword(s):  
Natural Gas ◽  
Tarim Basin ◽  
Oil And Gas ◽  
Northwest China ◽  
Source Rocks ◽  
Coal Measure ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Isotopic Analyses ◽  
Jurassic Coal

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

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