scholarly journals Source rocks evaluation of the Paleogene Shahejie 3 Formation in the Dongpu Depression, Bohai Bay Basin

2018 ◽  
Vol 37 (1) ◽  
pp. 394-411 ◽  
Author(s):  
Zi-Ran Jiang ◽  
Yin-Hui Zuo ◽  
Mei-Hua Yang ◽  
Yun-Xian Zhang ◽  
Yong-Shui Zhou
Keyword(s):  
Thermal History ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Geochemical Data ◽  
Bohai Bay ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Dongpu Depression ◽  
Two Stages

Present simulation results based on two-dimensional basin cannot obtain accurate evaluations of petroleum resources because of not combining the thermal history in the Dongpu Depression. In this paper, Shahejie 3 Formation source rocks are evaluated using the geochemical data, and based on the thermal history, the thermal maturity evolution of typical wells and the top and bottom of the Shahejie 3 Formation source rocks are modeled using BasinMod software. Results show that source rocks are mainly distributed in the Haitongji-Liutun and Qianliyuan areas, and dominated by medium to high maturity source rocks. Organic matter types are primarily types II and III kerogen with a small amount of type I. The Shahejie 3 Formation source rocks in the Menggangji area experienced two stages of hydrocarbon generation: (1) during the Dongying Formation depositional period (33–17 Ma) and (2) from the Minghuazhen Formation depositional period to present (5.1–0 Ma). The source rocks are generally underdeveloped with low potential for hydrocarbon generation due to nonpoor and thin source rocks in this area. The two stages of hydrocarbon generation are not obvious for other areas. When the bottom of the source rocks reached overmature stage, the mid-lower Shahejie 3 Formation experienced the peak of hydrocarbon generation during the Dongying Formation depositional period. The thermal maturity evolution of the Shahejie 3 Formation source rocks revealed that the main hydrocarbon generation period was during the Dongying Formation depositional period. Therefore, petroleum exploration is suggested to be performed at the Shahejie 3 Formation source rocks in the Qianliyuan and Haitongji-Liutun areas to study the lithology and discover complex petroleum reservoirs in the Dongpu Depression.

scholarly journals Burial and Thermal History Modeling of the Paleozoic–Mesozoic Basement in the Northern Margin of the Western Outer Carpathians (Case Study from Pilzno-40 Well, Southern Poland)

Minerals ◽  
2021 ◽  
Vol 11 (7) ◽  
pp. 733
Author(s):  
Dariusz Botor
Keyword(s):  
Heat Flow ◽  
Thermal History ◽  
Middle Jurassic ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Late Triassic ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Northern Margin ◽  
Outer Carpathians

Hydrocarbon exploration under thrust belts is a challenging frontier globally. In this work, 1-D thermal maturity modeling of the Paleozoic–Mesozoic basement in the northern margin of the Western Outer Carpathians was carried out to better explain the thermal history of source rocks that influenced hydrocarbon generation. The combination of Variscan burial and post-Variscan heating due to elevated heat flow may have caused significant heating in the Paleozoic basement in the pre-Middle Jurassic period. However, the most likely combined effect of Permian-Triassic burial and Late Triassic–Early Jurassic increase of heat flow caused the reaching of maximum paleotemperature. The main phase of hydrocarbon generation in Paleozoic source rocks developed in pre-Middle Jurassic times. Therefore, generated hydrocarbons from Ordovician and Silurian source rocks were lost before reservoirs and traps were formed in the Late Mesozoic. The Miocene thermal overprint due to the Carpathian overthrust probably did not significantly change the thermal maturity of organic matter in the Paleozoic–Mesozoic strata. Thus, it can be concluded that petroleum accumulations in the Late Jurassic and Cenomanian reservoirs of the foreland were charged later, mainly by source rocks occurring within the thrustbelt, i.e., Oligocene Menilite Shales. Finally, this work shows that comprehensive mineralogical and geochemical studies are an indispensable prerequisite of any petroleum system modelling because their results could influence petroleum exploration of new oil and gas fields.

Overpressure release: Fluid inclusion evidence for a new mechanism for the formation of heavy oil

Geology ◽  
2020 ◽  
Vol 48 (8) ◽  
pp. 803-807
Author(s):  
Hongwei Ping ◽  
Chunquan Li ◽  
Honghan Chen ◽  
Simon C. George ◽  
Se Gong
Keyword(s):  
Heavy Oil ◽  
Sedimentary Basins ◽  
Polar Compounds ◽  
Source Rocks ◽  
Geochemical Data ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Heavy Oils ◽  
Dongpu Depression ◽  
Hydrocarbon Distribution

Abstract Heavy oils in sedimentary basins are commonly related to biodegradation and water washing, and thermal degradation of sulfur-rich kerogen at an early hydrocarbon generation stage. However, the potential for overpressure release to form heavy oil has been seldom considered and rarely demonstrated. Paragenetic sequences of diagenetic and oil charge events, pressure-temperature-composition (P-T-x) evolutionary history reconstruction, and molecular geochemical data from a single generation of oil inclusions reveal that heavy shale oil in the PS18–1 well in the Dongpu Depression, Bohai Bay Basin, China, was neither a product of biodegradation nor due to early oil generation during kerogen maturation. Instead, the precipitation and retention of polar compounds of a previously charged, higher-maturity oil from deeper source rocks, induced by intense pressure reduction during basin uplift, represent the most likely mechanism for the formation of the heavy oil. The precipitation of polar compounds during primary and secondary migration due to intense pressure release may be an important mechanism for explaining compositional fractionation effects in the expelled petroleum fluids in source rocks, bitumen, and heavy oil distributions in unconventional shale systems, and deep non-biodegraded heavy oils. This mechanism has wider implications for understanding the hydrocarbon distribution in overpressured basins.

Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

2017 ◽  
Vol 5 (2) ◽  
pp. SF225-SF242 ◽  
Author(s):  
Xun Sun ◽  
Quansheng Liang ◽  
Chengfu Jiang ◽  
Daniel Enriquez ◽  
Tongwei Zhang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Ordos Basin ◽  
Depositional Environments ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Thermal Maturity ◽  
Yanchang Formation

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

Geochemical characterization of hydrocarbon source rocks of the Triassic-Jurassic time interval in the Mandawa basin, southern Tanzania: Implications for petroleum generation potential

2020 ◽  
Vol 123 (4) ◽  
pp. 587-596
Author(s):  
A. Emanuel ◽  
C.H. Kasanzu ◽  
M. Kagya
Keyword(s):  
Source Rocks ◽  
Geochemical Data ◽  
Time Interval ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Geochemical Characterization ◽  
Type Iii ◽  
Petroleum Generation

Abstract Triassic to mid-Jurassic core samples of the Mandawa basin, southern Tanzania (western coast of the Indian Ocean), were geochemically analyzed in order to constrain source rock potentials and petroleum generation prospects of different stratigraphic formations within the coastal basin complex. The samples were collected from the Mihambia, Mbuo and Nondwa Formations in the basin. Geochemical characterization of source rocks intersected in exploration wells drilled between 503 to 4042 m below surface yielded highly variable organic matter contents (TOC) rated between fair and very good potential source rocks (0.5 to 8.7 wt%; mean ca. 2.3 wt%). Based on bulk geochemical data obtained in this study, the Mandawa source rocks are mainly Type I, Type II, Type III, mixed Types II/III and Type IV kerogens, with a predominance of Type II, Type III and mixed Type II/III. Based on pyrolysis data (Tmax 417 to 473oC; PI = 0.02 to 0.47; highly variable HI = 13 to 1 000 mg/gTOC; OI = 16 to 225 mg/g; and VR values of between 0.24 to 0.95% Ro) we suggest that the Triassic Mbuo Formation and possibly the mid-Jurassic Mihambia Formation have a higher potential for hydrocarbon generation than the Nondwa Formation as they are relatively thermally mature.

scholarly journals Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)

2012 ◽  
Vol 63 (4) ◽  
pp. 335-342 ◽  
Author(s):  
Paweł Kosakowski ◽  
Magdalena Wróbel
Keyword(s):  
Organic Matter ◽  
Thermal History ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Burial History ◽  
Se Poland ◽  
Carpathian Foredeep ◽  
Outer Carpathians

Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)Burial history, thermal maturity, and timing of hydrocarbon generation were modelled for the Jurassic source rocks in the basement of the Carpathian Foredeep and marginal part of the Outer Carpathians. The area of investigation was bounded to the west by Kraków, to the east by Rzeszów. The modelling was carried out in profiles of wells: Będzienica 2, Dębica 10K, Góra Ropczycka 1K, Goleszów 5, Nawsie 1, Pławowice E1 and Pilzno 40. The organic matter, containing gas-prone Type III kerogen with an admixture of Type II kerogen, is immature or at most, early mature to 0.7 % in the vitrinite reflectance scale. The highest thermal maturity is recorded in the south-eastern part of the study area, where the Jurassic strata are buried deeper. The thermal modelling showed that the obtained organic matter maturity in the initial phase of the "oil window" is connected with the stage of the Carpathian overthrusting. The numerical modelling indicated that the onset of hydrocarbon generation from the Middle Jurassic source rocks was also connected with the Carpathian thrust belt. The peak of hydrocarbon generation took place in the orogenic stage of the overthrusting. The amount of generated hydrocarbons is generally small, which is a consequence of the low maturity and low transformation degree of kerogen. The generated hydrocarbons were not expelled from their source rock. An analysis of maturity distribution and transformation degree of the Jurassic organic matter shows that the best conditions for hydrocarbon generation occurred most probably in areas deeply buried under the Outer Carpathians. It is most probable that the "generation kitchen" should be searched for there.

Lower limit of hydrocarbon generation in source rocks: A case study from the Dongpu Depression, Bohai Bay Basin, East China

2019 ◽  
Vol 182 ◽  
pp. 103928 ◽  
Author(s):  
Ling Tang ◽  
Xiongqi Pang ◽  
Yan Song ◽  
Zhenxue Jiang ◽  
Shu Jiang ◽  
...  
Keyword(s):  
Lower Limit ◽  
Source Rocks ◽  
East China ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Bohai Bay Basin ◽  
Dongpu Depression

scholarly journals Geochemical Evaluation of the Cretaceous Mudrocks and Sandstones (Wackes) in the Southern Bredasdorp Basin, Offshore South Africa: Implications for Hydrocarbon Potential

Minerals ◽  
2020 ◽  
Vol 10 (7) ◽  
pp. 595
Author(s):  
Temitope Love Baiyegunhi ◽  
Kuiwu Liu ◽  
Oswald Gwavava ◽  
Nicola Wagner ◽  
Christopher Baiyegunhi
Keyword(s):  
South Africa ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Geochemical Data ◽  
Minor Amount ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
The Mean

The southern Bredasdorp Basin, off the south coast of South Africa, is only partly understood in terms of its hydrocarbon potential when compared to the central and northern parts of the basin. Hydrocarbon potential assessments in this part of the basin have been limited, perhaps because the few drilled exploration wells were unproductive for hydrocarbons, yielding trivial oil and gas. The partial integration of data in the southern Bredasdorp Basin provides another reason for the unsuccessful oil and gas exploration. In this study, selected Cretaceous mudrocks and sandstones (wacke) from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 drilled in the southern part of the Bredasdorp Basin were examined to assess their total organic carbon (TOC), thermal maturity, organic matter type and hydrocarbon generation potential. The organic geochemical results show that these rocks have TOC contents ranging from 0.14 to 7.03 wt.%. The hydrogen index (HI), oxygen index (OI), and hydrocarbon index (S2/S3) values vary between 24–263 mg HC/g TOC, 4–78 mg CO2/g TOC, and 0.01–18 mgHC/mgCO2 TOC, respectively, indicating predominantly Type III and IV kerogen with a minor amount of mixed Type II/III kerogen. The mean vitrinite reflectance values vary from 0.60–1.20%, indicating that the samples are in the oil-generation window. The Tmax and PI values are consistent with the mean vitrinite reflectance values, indicating that the Bredasdorp source rocks have entered the oil window and are considered as effective source rocks in the Bredasdorp Basin. The hydrocarbon genetic potential (SP), normalized oil content (NOC) and production index (PI) values all indicate poor to fair hydrocarbon generative potential. Based on the geochemical data, it can be inferred that most of the mudrocks and sandstones (wackes) in the southern part of the Bredasdorp Basin have attained sufficient burial depth and thermal maturity for oil and gas generation potential.

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