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.

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.

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 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 Thermal Maturation Regime Revisited in the Dongying Depression, Bohai Bay Basin, East China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-17
Author(s):  
Haiping Huang ◽  
Hong Zhang ◽  
Zheng Li ◽  
Mei Liu
Keyword(s):  
Organic Geochemistry ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
East China ◽  
Burial Depth ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Bohai Bay Basin ◽  
Dongying Depression ◽  
Hydrocarbon Maturation

To the accurate reconstruction of the hydrocarbon generation history in the Dongying Depression, Bohai Bay Basin, East China, core samples of the Eocene Shahejie Formation from 3 shale oil boreholes were analyzed using organic petrology and organic geochemistry methods. The shales are enriched in organic matter with good to excellent hydrocarbon generation potential. The maturity indicated by measured vitrinite reflectance (%Ro) falls in the range of 0.5–0.9% and increases with burial depth in each well. Changes in biomarker and aromatic hydrocarbon isomer distributions and biomarker concentrations are also unequivocally correlated with the thermal maturity of the source rocks. Maturity/depth relationships for hopanes, steranes, and aromatic hydrocarbons, constructed from core data indicate different well locations, have different thermal regimes. A systematic variability of maturity with geographical position along the depression has been illustrated, which is a dependence on the distance to the Tanlu Fault. Higher thermal gradient at the southern side of the Dongying Depression results in the same maturity level at shallower depth compared to the northern side. The significant regional thermal regime change from south to north in the Dongying Depression may exert an important impact on the timing of hydrocarbon maturation and expulsion at different locations. Different exploration strategies should be employed accordingly.

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.

Direct evidence for fluid overpressure during hydrocarbon generation and expulsion from organic-rich shales

Geology ◽  
2020 ◽  
Vol 48 (4) ◽  
pp. 374-378
Author(s):  
Miao Wang ◽  
Yong Chen ◽  
Wyatt M. Bain ◽  
Guoqi Song ◽  
Keyu Liu ◽  
...  
Keyword(s):  
Direct Evidence ◽  
Wall Rock ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Calcite Veins ◽  
History Of ◽  
Fluid Overpressures ◽  
Adjacent Wall ◽  
Record Variable

Abstract Fluid overpressures are widely expected during hydrocarbon generation and expulsion from source rocks, yet direct evidence for this phenomenon is lacking in the case of organic-rich shales. Here we show that formation of bed-parallel fibrous calcite veins in mature laminated organic-rich shales in the Eocene Dongying depression, Bohai Bay Basin, east China, occurred in direct response to fluid overpressure due to hydrocarbon generation. The evidence for overpressure is recorded by coexisting primary aqueous and petroleum inclusions in the calcite fibers. Our results show that all analyzed fluid-inclusion assemblages record variable degrees of overpressure during vein dilation, ranging from only modestly in excess of hydrostatic, to approaching and perhaps exceeding lithostatic. Thus, our results indicate that fluid pressures during dilation of horizontal veins are not necessarily equal to the opposing force of overburden throughout the history of opening. This suggests that at least some of the vein dilation is accommodated by concomitant narrowing of the adjacent wall-rock laminae, likely by scavenging (dissolution and reprecipitation) of CaCO3 from the adjacent wall rock.

scholarly journals Relative sorption coefficient: Key to tracing petroleum migration and other subsurface fluids

2019 ◽  
Vol 9 (1) ◽  
Author(s):  
L. Zhang ◽  
Y. Wang ◽  
M.-W. Li ◽  
Q.-Z. Yin ◽  
W. Zhang
Keyword(s):  
Sedimentary Basins ◽  
Distribution Patterns ◽  
Polar Compounds ◽  
Source Rocks ◽  
Polar Molecules ◽  
Sorption Coefficient ◽  
Petroleum Migration ◽  
New Findings ◽  
Novel Concept ◽  
Incorrect Information

AbstractThe accumulation and spatial distribution of economically important petroleum in sedimentary basins are primarily controlled by its migration from source rocks through permeable carrier beds to reservoirs. Tracing petroleum migration entails the use of molecular indices established according to sorption capacities of polar molecules in migrating petroleum. However, little is known about molecular sorption capacities in natural migration systems, rendering these indices unreliable. Here, we present a new approach based on a novel concept of relative sorption coefficient for quantitatively assessing sorption capacities of polar molecules during natural petroleum migration. Using this approach, we discovered previously unrecognized “stripping” and “impeding” effects that significantly reduce the sorption capacities of polar compounds. These discoveries provide new insights into the behaviors of polar compounds and can easily explain why traditional molecular indices yield incorrect information about petroleum migration. In light of these new findings, we established new molecular indices for tracing petroleum migration. We demonstrate via case studies that the newly established indices, unlike traditional molecular indices, are reliable and effective in tracing petroleum migration. Our approach can be applied to diverse basins around the world to reveal distribution patterns of petroleum, which would decrease environmental risks of exploration by reducing unsuccessful wells.

Hydrocarbon generation and evolution of the source rocks of the lower Es3 and upper Es4 members of the Shahejie Formation in the Niuzhuang Sub-sag, Jiyang Depression, Bohai Bay Basin, eastern China

2018 ◽  
Vol 6 (4) ◽  
pp. SN11-SN21
Author(s):  
Zhenkai Huang ◽  
Maowen Li ◽  
Quanyou Liu ◽  
Xiaomin Xie ◽  
Peng Liu ◽  
...  
Keyword(s):  
Activation Energy ◽  
Eastern China ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Bohai Bay Basin ◽  
Jiyang Depression ◽  
Generation Threshold ◽  
Oil Generation ◽  
Shahejie Formation

Systematic organic petrology and geochemistry analyses have been conducted in the source rocks of the lower Es3 and upper Es4 members of the Shahejie Formation in the Niuzhuang Sub-sag, Jiyang Depression, Bohai Bay Basin, eastern China. The results indicate that the main organic types of shale and nongypsum mudstone in the lower Es3 and upper Es4 member are I-II1 kerogen, and the predominant ([Formula: see text]) activation energy frequencies range from 57 to [Formula: see text]. The similar distribution characteristics in the two source rocks indicate that they have a similar hydrocarbon maturation process. An extensive pyrolysis analysis indicates that the source rocks of the upper Es4 member do not have an obvious double peak hydrocarbon generation model. Previous studies indicate that the hydrocarbon index peak at a depth of 2500–2700 m is affected by migrating hydrocarbon. Major differences are not observed in the hydrocarbon generation and evolution process of the shale and nongypsum mudstone. The primary oil generation threshold of the lower Es3 and upper Es4 members is approximately 3200 m, and the oil generation peak is approximately 3500 m. The activation energy distribution of the gypsum mudstone of the upper Es4 member is wider than that of the shale and nongypsum mudstone, and lower activation energies account for a larger proportion of the activation energies. The above factors may lead to a shallower oil generation threshold for gypsum mudstone compared with that for shale and nongypsum mudstone.

GEOLOGY, SOURCE ROCKS AND HYDROCARBON GENERATION IN THE CLARENCE-MORETON BASIN

1982 ◽  
Vol 22 (1) ◽  
pp. 5
Author(s):  
A. R. Martin ◽  
J. D. Saxby
Keyword(s):  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Tectonic Events ◽  
History Of ◽  
Rock Eval ◽  
Coal Measures ◽  
Migration Pathways

The geology and exploration history of the Triassic-Cretaceous Clarence-Moreton Basin are reviewed. Consideration of new geochemical data ('Rock-Eval', vitrinite reflectance, gas chromatography of extracts, organic carbon and elemental analysis of coals and kerogens) gives further insights into the hydrocarbon potential of the basin. Although organic-rich rocks are relatively abundant, most source rocks that have achieved the levels of maturation necessary for hydrocarbon generation are gas-prone. The exinite-rich oil-prone Walloon Coal Measures are in most parts relatively immature. Some restraints on migration pathways are evident and igneous and tectonic events may have disturbed potentially well-sealed traps. Further exploration is warranted, even though the basin appears gas-prone and the overall prospects for hydrocarbons are only fair. The most promising areas seem to be west of Toowoomba for oil and the Clarence Syncline for gas.

Sign in / Sign up

Export Citation Format

Share Document