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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H1: Petroleum Engineering".

Deadline for manuscript submissions: closed (25 April 2022) | Viewed by 12354

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Prof. Dr. Jianhui Zeng

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Guest Editor

1. State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China
2. College of Geosciences, China University of Petroleum, Beijing 102249, China
Interests: formation and distribution of oil and gas reservoirs; dynamics of hydrocarbon migration and accumulation; basin fluid analysis, water–rock interaction and reservoir evaluation

Prof. Dr. Dongxia Chen

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Guest Editor

1. State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China
2. College of Geosciences, China University of Petroleum, Beijing 102249, China
Interests: formation and distribution of oil and gas reservoirs; abnormal pressure and dynamic characterization; fault sealing quantitative characterization; sandstone carrier quantitative characterization

Dr. Jianhua Zhao

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Guest Editor

1. School of Geosciences, China University of Petroleum (East China), Qingdao 266580, China
2. Key Laboratory of Deep Oil and Gas, China University of Petroleum (East China), Qingdao 266580, China
Interests: unconventional resources; basin research
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Special Issue Information

Dear Colleagues,

The characteristics and mechanisms of hydrocarbon migration and accumulation have attracted more and more attention, whether in conventional or unconventional reservoirs. The migration and accumulation of hydrocarbons is a dynamic equilibrium process. When the charging dynamics are greater than the resistance, hydrocarbon migration occurs; when the charging dynamics are less than the resistance, hydrocarbon accumulation occurs. Hydrocarbon migration often undergoes complex geological processes and is controlled by many factors. Such geological–historical processes occurring in the subsurface cannot be directly observed, and even residual traces are difficult to obtain, making it one of the weakest research aspects in petroleum geology. Therefore, accurate characterization and understanding of the migration and accumulation mechanisms of hydrocarbons at different scales (pore-, core-, sand-, basin-scale) are challenging and of grand importance.

We invite investigators to submit original research articles, as well as review articles, that will stimulate continuous efforts on new methods and techniques for numerical simulation, migration and accumulation dynamics characteristics, conduit (carrier beds, fault zones, and some carriers associated with unconformities) quantitative characterization, dating of hydrocarbon charge and migration pathways tracing, as well as on understanding of the migration and accumulation mechanisms of conventional and unconventional reservoirs, thereby reducing hydrocarbon exploration risks in petroliferous basins.

Prof. Dr. Jianhui Zeng
Prof. Dr. Dongxia Chen
Dr. Jianhua Zhao
Guest Editors

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Keywords

Conduit quantitative characterization
Migration pathways tracing
Migration and accumulation dynamics characteristics
Dating of hydrocarbon charge
Accumulation of tight oil and gas
Accumulation of shale oil and gas

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Published Papers (6 papers)

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26 pages, 18761 KiB

Open AccessArticle

Differential Genetic Mechanisms of Deep High-Quality Reservoirs in the Paleogene Wenchang Formation in the Zhu-1 Depression, Pearl River Mouth Basin

by Cheng Wang, Dongxia Chen, Hongbo Li, Siyuan Chang, Ziyi Liu, Fuwei Wang and Qiaochu Wang

Energies 2022, 15(9), 3277; https://doi.org/10.3390/en15093277 - 29 Apr 2022

Cited by 2 | Viewed by 1656

Abstract

The Lufeng Sag and Huizhou Sag, both located in the Zhu-1 Depression, have similar geographical locations, but their reservoir characteristics in the Paleogene Wenchang Formation show obvious differences. Primary intergranular pores are mainly developed in the Lufeng Sag. However, secondary pores are the main reservoir space in the Huizhou depression. Overall, the reservoir properties of the Lufeng Sag are better than those of the Huizhou Sag. To analyse the differences between the Paleogene reservoirs in these two areas, this study mainly uses assay data, such as rock thin sections, scanning electron microscope images, drilling, and logging, to analyse the differential development mechanisms of high-quality reservoirs, and two types of reservoir development models were concluded. The results show that the anti-compaction primary porosity preservation mode is mainly developed in the Lufeng Sag. High compositional maturity quartz sandstone is the congenital condition of primary porosity development. The top and bottom calcareous cementation formed of the large set of thick sand bodies increases the rock’s anti-compaction ability. The early shallow burial slows down the compaction action of overlying strata. Under the low geothermal temperature, it can delay the time for deep reservoirs to enter the middle diagenetic stage. The reservoirs in the Huizhou Sag are developed with the secondary dissolution pore development model. The Wenchang Formation reservoir in the Huizhou Sag has a large area of contact with source rocks, and organic acids can migrate to sandstone reservoirs for dissolution. Additionally, the secondary dissolution pores are more developed because the Wenchang Formation reservoirs in the Huizhou Sag contain more easily dissolved substances. Full article

(This article belongs to the Special Issue Advances in Oil and Gas Migration and Accumulation)

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19 pages, 21428 KiB

Open AccessArticle

The Influence of Hydrothermal Activity on the Long-Distance Migration and Accumulation of Hydrocarbons: A Case Study from the Y8 Area in the Songnan-Baodao Sag of Qiongdongnan Basin

by Jun Gan, Shuling Xiong, Gang Liang, Zhiye Gao, Xing Li, Wei Yang, Zhenxue Jiang and Yaohua Wang

Energies 2022, 15(9), 3089; https://doi.org/10.3390/en15093089 - 23 Apr 2022

Cited by 1 | Viewed by 1919

Abstract

The Qiongdongnan (QDN) basin in the northwestern South China Sea has been shown to be rich in petroleum resources and has significant exploration potential for deepwater oil and gas resources. Therefore, it is of great significance to clarify the gas accumulation process in the deepwater area of the QDN basin, specifically the Y8 area. In this study, fluid inclusion analysis, including the identification and localization of fluid inclusions under a microscope, laser Raman spectrum analysis and homogenization temperature (T_h) measurement, reconstruction of the thermal evolution burial history, geochemical analysis, and typical seismic section analysis were comprehensively used to interpret the gas accumulation process of the Y8 area. The laser Raman spectrum analysis results of fluid inclusions verified the existence of methane and confirmed the hydrocarbon charging event in this area. However, the Th of fluid inclusions in the reservoir, the mixed compositions of hydrothermal compositions (H₂S + SO₂) and hydrocarbons (methane) in the fluid inclusions, and the low T_max values of some wells in the Y8 area comprehensively confirmed that the coincidence of hydrothermal activity with the accumulation process affected the long-distance gas accumulation of the Y8 area. The hydrothermal activity was also confirmed by the presence of fluid diapirs in seismic profiles of the Y8 area. Furthermore, the hydrocarbon accumulation process was reconstructed using the modified thermal evolution history considering the effect of hydrothermal activity. Overall, this study attributed the high T_h of fluid inclusions in the reservoirs of the Y8 area to hydrothermal activity and proposed a long-distance migration model of hydrocarbon accumulation coinciding with hydrothermal activity, both of which are beneficial to understanding the accumulation process of the Y8 area. Full article

(This article belongs to the Special Issue Advances in Oil and Gas Migration and Accumulation)

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21 pages, 12402 KiB

Open AccessArticle

Reservoir Densification, Pressure Evolution, and Natural Gas Accumulation in the Upper Paleozoic Tight Sandstones in the North Ordos Basin, China

by Ren Wang, Kai Liu, Wanzhong Shi, Shuo Qin, Wei Zhang, Rong Qi and Litao Xu

Energies 2022, 15(6), 1990; https://doi.org/10.3390/en15061990 - 9 Mar 2022

Cited by 16 | Viewed by 1939

Abstract

The vague understanding of the coupling relationship among natural gas charging, reservoir densification, and pressure evolution restricted the tight gas exploration in the Lower Shihezi Formation of the Hangjinqi area, north Ordos Basin. In this study, the quantitative porosity evolution model, the pressure evolution process, and the natural gas charging history of tight sandstone reservoirs were constructed by integrated investigation of the reservoir property, the thin section, SEM and cathode luminescence observations, the fluid inclusion analysis and the 1D basin modeling. The results show that the compaction and cementation reduced the primary porosity by 21.79% and 12.41%, respectively. The densification of the reservoir occurred at circa 230 Ma, which was before the natural gas charging time from 192 to 132 Ma. The paleo-overpressure within the tight reservoirs occurred since the Middle Jurassic with the pressure coefficients between 1.1 and 1.55. The continuous uplifting since the Late Cretaceous resulted in the under- and normal-pressure of the Lower Shihezi Formation with the pressure coefficients ranging from 0.67 to 1.05. The results indicate that the densification of the reservoirs was conducive to the formation of paleo-pressure produced by gas generating. The gas predominantly migrated vertically, driven by gas expansion force rather than buoyance and displaced the pore water in the reservoirs near source rocks. Full article

(This article belongs to the Special Issue Advances in Oil and Gas Migration and Accumulation)

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20 pages, 12947 KiB

Open AccessArticle

Petroleum Charging History of the Paleogene Sandstone Reservoirs in the Huangtong Sag of the Fushan Depression, South China Sea

by Xin Wang, Zhenghuan Lu, Meijun Li, Hao Guo, Zhili Zhu, Xiaohan Li, Chengyu Yang, Bang Zeng, Fangzheng Wang and Zichao Ran

Energies 2022, 15(4), 1374; https://doi.org/10.3390/en15041374 - 14 Feb 2022

Cited by 5 | Viewed by 1758

Abstract

The Paleogene sandstone reservoir in the Huangtong Sag of the Fushan Depression is one of the most commercially prolific oil accumulations in the Beibuwan Basin, South China Sea. In this study, twenty-seven crude oil samples from four oilfields in the sag were geochemically analyzed and classified into three oil groups. Oils in the Meitai and Hongguang oilfields show similar geochemical characteristics, with relatively abundant C₃₀ 4α-methyl-24-ethylcholestanes and low contents of oleanane and C₁₉₊₂₀ tricyclic terpanes (TT), and therefore may be derived from the same source kitchen. Oils from the Yong’an oilfield have a greater proportion of oleanane and C₁₉₊₂₀ TT compounds. Oils from the Chaoyang oilfield have intermediate contents of these biomarkers and proportionate values of other related parameters. The unimodal distribution pattern of homogenization temperatures of fluid inclusions found in all the Paleogene reservoirs indicates a single episode of charging. Combining this understanding with the reconstruction of stratigraphy-burial and geothermal histories by 1-D basin modeling, the petroleum charging time was determined to be between 8–2 Ma (the end of the middle Miocene to the early Pliocene). Hydrocarbon migration orientation and charging pathways were traced using molecular indicators (4-/1-methyldibenzothiophene and 1-/4-methodibenzofuran). In the Chaoyang oilfield, the values of these geochemical parameters decreased with decreasing burial depth, indicating vertical oil migration along faults, which are plentiful in the sag. Sandstone bodies with deeper burial depths may therefore be the most promising exploration targets in the Chaoyang area. The Yong’an oils generally migrate from the northwest toward the southeast, suggesting that the source kitchen for the Yong’an oilfield is in the northwest. By similar inference, the hydrocarbon source kitchen for the Hongguang-Meitai area is likely to be on the north side of the Hongguang-Meitai area. By tracing these hydrocarbon charging pathways, the northwest of the Yong’an area and the northern part of the Hongguang-Meitai area are identified as the most promising areas for exploration. Full article

(This article belongs to the Special Issue Advances in Oil and Gas Migration and Accumulation)

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21 pages, 6251 KiB

Open AccessArticle

Hydrocarbon Charging and Accumulation in the Permian Reservoirs of the Wumaying Buried Hill, Huanghua Depression, Bohai Bay Basin, China

by Runze Yang, Xianzheng Zhao, Changyi Zhao, Xiugang Pu, Haitao Liu, Hongjun Li, Lixin Fu and Ying Tang

Energies 2021, 14(23), 8109; https://doi.org/10.3390/en14238109 - 3 Dec 2021

Cited by 4 | Viewed by 1723

Abstract

The Wumaying buried hill experienced multi-stage tectonic movements, which resulted in a complicated and unclear nature of the hydrocarbon accumulation process. To solve these problems, in this study—based on the structural evolution and burial–thermal history of the strata, using petrology, fluid inclusion microthermometry, geochemical analysis of oil and gas, Laser Raman spectrum, and fluorescence spectrum—the history of hydrocarbon charging was revealed, and the differences in hydrocarbon charging of different wells was clarified. The results indicate that the only source for Permian oil and gas reservoirs are Carboniferous–Permian coal-measure source rocks in the Wumaying buried hill. There are three periods of hydrocarbon charging. Under the channeling of faults and micro cracks, low-mature oil and gas accumulation was formed in the first period, and the accumulation time was 112–93 Ma. In the late Cretaceous, a large-scale uplift exposed and damaged the reservoirs, and part of the petroleum was converted into bitumen. In the middle–late Paleogene, the subsidence of strata caused the coal-measure to expel mature oil and gas, and the accumulation time of mature oil and gas was 34–24 Ma. Since the Neogene, natural gas and high-mature oil have been expelled due to the large subsidence entering the reservoir under the channeling of active faults; the accumulation time was 11–0 Ma. The microfractures of Permian reservoirs in the Wumaying buried hill are the main storage spaces of hydrocarbons, and the fractured reservoirs should be explored in the future. The first period of charging was too small and the second period was large enough in the WS1 well, resulting in only a late period of charging in this well. Full article

(This article belongs to the Special Issue Advances in Oil and Gas Migration and Accumulation)

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19 pages, 4812 KiB

Open AccessEssay

Wettability of Tight Sandstone Reservoir and Its Impacts on the Oil Migration and Accumulation: A Case Study of Shahejie Formation in Dongying Depression, Bohai Bay Basin

by Kunkun Jia, Jianhui Zeng, Xin Wang, Bo Li, Xiangcheng Gao and Kangting Wang

Energies 2022, 15(12), 4267; https://doi.org/10.3390/en15124267 - 10 Jun 2022

Cited by 6 | Viewed by 1854

Abstract

The migration and accumulation of oil in tight sandstone reservoirs are mainly controlled by capillary force. Due to the small pore radius and complex pore structure of tight sandstone reservoirs, the capillary force is very sensitive to wettability, so wettability significantly affects oil migration and accumulation. However, the study of oil migration and accumulation in tight sandstone reservoirs often needs to combine multiple methods, the process is complex, and the research methods of wettability are not uniform, so the mechanism of wettability affecting oil migration and accumulation is not clear. Taking the tight sandstone of the Shahejie Formation in the Dongying sag, Bohai Bay Basin, as the research object, the wettability characteristics of a tight sandstone reservoir and their influence on oil migration and accumulation were analyzed by means of a pore permeability test, XRD analysis, micro-CT experiment, contact angle tests, spontaneous imbibition experiments, and physical simulation experiments on oil migration and accumulation. The results show that the reservoir is of the water-wet type, and its wettability is affected by the mineral composition. Wettability in turn affects the spontaneous imbibition characteristics by controlling the capillary force. Oil migration in tight sandstone reservoirs is characterized by non-Darcy flow, the oil is in the non-wetting phase and subject to capillary resistance. The key parameters to describe the oil migration and accumulation characteristics include the kickoff pressure gradient, the critical pressure gradient, and ultimate oil saturation. Wettability affects oil migration characteristics by controlling the capillary force. The more oil-wet the reservoir is, the more favourable it is to oil migration and oil accumulation and therefore the higher the reservoir’s ultimate oil saturation is. Full article

(This article belongs to the Special Issue Advances in Oil and Gas Migration and Accumulation)

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