GIFFSLAND HYDROCARBONS - A PERSPECTIVE FROM THE BASIN EDGE

1984 ◽  
Vol 24 (1) ◽  
pp. 91 ◽  
Author(s):  
J. G. Stainforth
Keyword(s):  
Heat Flow ◽  
Upper Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Lower Tertiary ◽  
Late Tertiary ◽  
Carbonaceous Shales ◽  
Basin Edge ◽  
Gippsland Basin

Permit VIC/P19 lies palaeogeographically seaward of the main producing part of the Gippsland Basin. Deposition of the Latrobe Group commenced with volcanics and continental 'rift-stage' sediments during the Late Cretaceous. This phase was succeeded first by paludal sedimentation in the failed rift during the Campanian and Maastrichtian, and then by cyclic paralic sedimentation during the Paleocene and Eocene.Analysis of the hydrocarbons recovered during recent exploration of permit VIC/P19 shows that they were sourced from moderately mature coals and carbonaceous shales in the Campanian/-Maastrichtian paludal sequence.A maturation model that assumes elevated but decreasing heat flow, related to sea-floor spreading, produces an excellent fit to the observed maturity data and predicts a long history of hydrocarbon generation during the Tertiary. The maturity of the Upper Cretaceous source sequence depends more on the thickness of the overlying Lower Tertiary clastic Latrobe sediments than on the thickness of the Upper Tertiary carbonate wedge. The Late Tertiary phase of burial had relatively little effect on maturation because of its rapidity and the lower heat flow and higher thermal conductivities of the deeper sequence at the time. Overpressures in mature Upper Cretaceous source rocks, resulting from hydrocarbon generation, have driven pore fluids, including hydrocarbons, laterally up-dip into normally pressured reservoirs.The main oil province of the Gippsland Basin has a greater thickness of Lower Tertiary than has VIC/P19. As a result, source rocks are more mature there, and became wholly so by the end of deposition of the Latrobe Group. This facilitated charge of traps at the top of the Latrobe Group, which contain most of the oil and gas discovered to date in the Basin.

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.

scholarly journals Oil generation from coal source rocks: the influence of depositional conditions and stratigraphic age

2005 ◽  
Vol 7 ◽  
pp. 9-12 ◽  
Author(s):  
Henrik I. Petersen
Keyword(s):  
North Sea ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Oil Generation ◽  
Generation Capacity ◽  
The Subject ◽  
Coal Composition ◽  
Gippsland Basin ◽  
Australasian Region

Although it was for many years believed that coals could not act as source rocks for commercial oil accumulations, it is today generally accepted that coals can indeed generate and expel commercial quantities of oil. While hydrocarbon generation from coals is less well understood than for marine and lacustrine source rocks, liquid hydrocarbon generation from coals and coaly source rocks is now known from many parts of the world, especially in the Australasian region (MacGregor 1994; Todd et al. 1997). Most of the known large oil accumulations derived from coaly source rocks have been generated from Cenozoic coals, such as in the Gippsland Basin (Australia), the Taranaki Basin (New Zealand), and the Kutei Basin (Indonesia). Permian and Jurassic coal-sourced oils are known from, respectively, the Cooper Basin (Australia) and the Danish North Sea, but in general only minor quantities of oil appear to be related to coals of Permian and Jurassic age. In contrast, Carboniferous coals are only associated with gas, as demonstrated for example by the large gas deposits in the southern North Sea and The Netherlands. Overall, the oil generation capacity of coals seems to increase from the Carboniferous to the Cenozoic. This suggests a relationship to the evolution of more complex higher land plants through time, such that the highly diversified Cenozoic plant communities in particular have the potential to produce oil-prone coals. In addition to this overall vegetational factor, the depositional conditions of the precursor mires influenced the generation potential. The various aspects of oil generation from coals have been the focus of research at the Geological Survey of Denmark and Greenland (GEUS) for several years, and recently a worldwide database consisting of more than 500 coals has been the subject of a detailed study that aims to describe the oil window and the generation potential of coals as a function of coal composition and age.

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.

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.

scholarly journals Formation conditions and evolution of oil and gas source strata of the Laptev sea shelf ore and gas province

2021 ◽  
pp. 46-59
Author(s):  
V. Yu. Kerimov ◽  
Yu. V. Shcherbina ◽  
A. A. Ivanov
Keyword(s):  
Oil And Gas ◽  
Numerical Models ◽  
Sedimentary Basins ◽  
Water Area ◽  
Source Rocks ◽  
Gas Content ◽  
Laptev Sea ◽  
Hydrocarbon Generation ◽  
Gas Source ◽  
The Laptev Sea

Introduction. To date, no unified well-established concepts have been developed regarding the oil and gas geological zoning of the Laptev Sea shelf, as well as other seas of the Eastern Arctic. Different groups of researchers define this region either as an independently promising oil and gas region [7, 8], or as a potential oil and gas basin [1].Aim. To construct spatio-temporal digital models of sedimentary basins and hydrocarbon systems for the main horizons of oil and gas source rocks. A detailed analysis of information on oil and gas content, the gas chemical study of sediments, the characteristics of the component composition and thermal regime of the Laptev sea shelf water area raises the question on the conditions for the formation and evolution of oil and gas source strata within the studied promising oil and gas province. The conducted research made it possible to study the regional trends in oil and gas content, the features of the sedimentary cover formation and the development of hydrocarbon systems in the area under study.Materials and methods. The materials of production reports obtained for individual large objects in the water area were the source of initial information. The basin analysis was based on a model developed by Equinor specialists (Somme et al., 2018) [14—17], covering the time period from the Triassic to Paleogene inclusive and taking into account the plate-tectonic reconstructions. The resulting model included four main sedimentary complexes: pre-Aptian, Apt-Upper Cretaceous, Paleogene, and Neogene-Quaternary.Results. The calculation of numerical models was carried out in two versions with different types of kerogen from the oil and gas source strata corresponding to humic and sapropel organic matter. The results obtained indicated that the key factor controlling the development of hydrocarbon systems was the sinking rate of the basins and the thickness of formed overburden complexes, as well as the geothermal field of the Laptev Sea.Conclusion. The analysis of the results obtained allowed the most promising research objects to be identified. The main foci of hydrocarbon generation in the Paleogene and Neogene complexes and the areas of the most probable accumulation were determined. Significant hydrocarbon potential is expected in the Paleogene clinoforms of the Eastern Arctic.

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