scholarly journals Modelling the hydrocarbon generation and migration in the West Netherlands Basin, the Netherlands

2000 ◽  
Vol 79 (1) ◽  
pp. 29-44 ◽  
Author(s):  
R.T. van Balen ◽  
F. van Bergen ◽  
C. de Leeuw ◽  
H. Pagnier ◽  
H. Simmelink ◽  
...  
Keyword(s):  
Lower Jurassic ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
The West ◽  
Hydrocarbon System ◽  
Coal Deposits ◽  
Geochemical Analyses ◽  
And Migration ◽  
Potential Traps

AbstractThe hydrocarbon systems of the Mesozoic, inverted West Netherlands Basin have been analyzed using 2-D forward modelling. Three source rocks are considered in the modelling: Lower Jurassic oil-prone shales, Westphalian gas-prone coal deposits, and Lower Namurian oil-prone shales. The Lower Namurian hydrocarbon system of the basin is discussed for the first time.According to the modelling results of the Early Jurassic oil system, the oil accumulations were filled just after the main inversion event. Their predicted locations are in agreement with exploration results. Modelling results of the Westphalian gas system, however, show smaller and larger sized accumulations at unexplored locations. The gas reservoirs were filled during the Late Jurassic-Early Cretaceous rifting phase. Results of modelling of the Lower Namurian oil system indicate that gas formed by secondary cracking of the oils can have mixed with the Westphalian coal-derived gas. Such a mixing is inferred from geochemical analyses. The existence of a Lower Namurian hydrocarbon system in the West Netherlands Basin implies that hydrocarbons are possibly trapped in the Westphalian and Namurian successions. These potential traps in the basin have not yet been explored.

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.

TECTONIC CONTROLS ON SEDIMENTATION AND MATURATION IN THE OFFSHORE NORTH PERTH BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 450 ◽  
Author(s):  
John F. Marshall ◽  
Chao- Shing Lee ◽  
Douglas C. Ramsay ◽  
Aidan M.G. Moore
Keyword(s):  
Seismic Reflection ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Late Permian ◽  
Early Permian ◽  
The West ◽  
Australian Continent ◽  
Multichannel Seismic Reflection ◽  
Well Data ◽  
Coal Measures

The major tectonic and stratigraphic elements of the offshore North Perth Basin have been delineated from regional BMR multichannel seismic reflection lines, together with industry seismic and well data. This analysis reveals that three sub- basins, the Edel, Abrolhos and Houtman Sub- basins, have formed as a result of three distinct episodes of rifting within the offshore North Perth Basin during the Early Permian, Late Permian and Late Jurassic respectively. During this period, rifting has propagated from east to west, and has culminated in the separation of this part of the Australian continent from Greater India.The boundaries between the sub- basins and many structures within individual sub- basins are considered to have been produced by strike- slip or oblique- slip motion. The offshore North Perth Basin is believed to be a product of transtension, possibly since the earliest phase of rifting. This has culminated in separation and seafloor spreading by oblique extension along the Wallaby Fracture Zone to form a transform passive continental margin.This style of rifting and extension has produced relatively thin syn- rift sequences, some of which have been either partly or completely removed by erosion. While the source- rock potential of the syn- rift phase is limited, post- rift marine transgressional phases and coal measures do provide adequate and relatively widespread source rocks for hydrocarbon generation. Differences in the timing of rifting across the basin have resulted in a maturation pattern whereby mature sediments become younger to the west.

Sequential distribution of gas reservoirs in the Hangjinqi area, Ordos Basin, North China: Application of continuous and discontinuous hydrocarbon accumulation mode

2020 ◽  
pp. 1-49
Author(s):  
Haikuan Nie ◽  
Xiaoliang Wei ◽  
Jinchuan Zhang ◽  
Qian Chen ◽  
Guangxiang Liu ◽  
...  
Keyword(s):  
Shale Gas ◽  
Ordos Basin ◽  
Water Soluble ◽  
Source Rocks ◽  
Formation Mechanisms ◽  
Burial Depth ◽  
Hydrocarbon Generation ◽  
Distribution Characteristics ◽  
Gas Reservoirs ◽  
Continuous Accumulation

Gas reservoirs can be divided into two types based on the migration and accumulation processes, and distribution characteristics associated with the reservoirs: continuous accumulation that is within or adjacent to the source rocks and discontinuous accumulation that is in the reservoir rocks. Correspondingly, reservoirs can also be classified as conventional reservoirs, unconventional reservoirs and reservoirs in a transitional state. In order to demonstrate differences and regularities in the distribution characteristics and formation mechanisms of the two accumulation types, the continuous and discontinuous hydrocarbon accumulations in the Hangjinqi area of the Ordos Basin, China, is systematically analyze. Continuous accumulation (coalbed methane, shale gas, basin-centered gas, water-soluble gas) and discontinuous accumulation reservoirs (various traps) are located in the southern and northern regions of the Hangjinqi area, respectively, and they may be changed with the source rock quality, migration force, reservoir capacity and trapping condition. Several factors, such as hydrocarbon generation ability, porosity, and cap rock-trap combinations, are recognized here as essential factors for the formation and current distribution of gas reservoirs in the study area. Understanding the distribution characteristics of continuous accumulation and discontinuous accumulation can predict the potential gas reservoirs types based on discovered gas reservoirs. It is recommended to explore anticline gas reservoirs in the north of Boerjianghaizi fault, and CBM, shale gas and basin-centered gas reservoirs in the south of Boerjianghaizi fault. Though shale gas exploration activity is still lacking in the study area, we believe that the maturity and the burial depth of the marine-continental organic-rich shale in the Permian Shanxi-Taiyuan Formations are suitable for shale gas generation and preservation, indicating further research on the upper Paleozoic shale source rocks is required.

Modelling hydrocarbon generation and migration in tertiary source rocks of deepwater, Phu Khanh Basin, offshore Vietnam

2021 ◽  
Vol 28 (2) ◽  
pp. 137
Author(s):  
Cu Minh Hoang ◽  
Kieu Nguyen Binh ◽  
Delia Anne Marie Androne ◽  
Min Baehyun ◽  
Ta Quoc Dung ◽  
...  
Keyword(s):  
Source Rocks ◽  
Hydrocarbon Generation ◽  
And Migration

Jurassic source rocks of hydrocarbon fluids in the Eastern part of the Fukan depression (Junggar oil and gas basin)

2020 ◽  
pp. 55-63
Author(s):  
Yang Houqiang ◽  
E. V. Soboleva
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Research Area ◽  
Molecular Composition ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Eastern Side ◽  
Oil And Gas Reservoirs

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.

GEOCHEMICAL TOOLS FOR EVALUATING PETROLEUM GENERATION IN MIDDLE PROTEROZOIC SEDIMENTS OF THE McARTHUR BASIN, NORTHERN TERRITORY, AUSTRALIA

1994 ◽  
Vol 34 (1) ◽  
pp. 692 ◽  
Author(s):  
Roger E. Summons ◽  
Dennis Taylor ◽  
Christopher J. Boreham
Keyword(s):  
Vitrinite Reflectance ◽  
Land Plant ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Strongly Correlated ◽  
Petroleum Potential ◽  
Petroleum Generation ◽  
Early Palaeozoic ◽  
Geochemical Analyses ◽  
Rock Eval

Maturation parameters based on aromatic hydrocarbons, and particularly the methyl-phenanthrene index (MPI-1), are powerful indicators which can be used to define the oil window in Proterozoic and Early Palaeozoic petroleum source rocks and to compare maturities and detect migration in very old oils . The conventional vitrinite reflectance yardstick for maturity is not readily translated to these ancient sediments because they predate the evolution of the land plant precursors to vitrinite. While whole-rock geochemical tools such as Rock-Eval and TOC are useful for evaluation of petroleum potential, they can be imprecise when applied to maturity assessments.In this study, we carried out a range of detailed geochemical analyses on McArthur Basin boreholes penetrating the Roper Group source rocks. We determined the depth profiles for hydrocarbon generation based on Rock-Eval analysis of whole-rock, solvent-extracted rock, kerogen elemental H/C ratio and pyrolysis GC. Although we found that Hydrogen Index (HI) and the Tmax parameter were strongly correlated with other maturation indicators, they were not sufficiently sensitive nor were they universally applicable. Maturation measurements based on saturated biomarkers were not useful either because of the low abundance of these compounds in most Roper Group bitumens and oils.

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