Geochemical Characterization of Source Rocks in Oil and Gas Fields

A special issue of Minerals (ISSN 2075-163X). This special issue belongs to the section "Mineral Exploration Methods and Applications".

Deadline for manuscript submissions: closed (31 July 2023) | Viewed by 7913

Special Issue Editors

Geology Department, Faculty of Science, Mansoura University, Al Manşūrah 11432, Egypt
Interests: geology; sedimentology; stratigraphy; sequence stratigraphy; exploration geology; petroleum geology; geological mapping; sedimentary basins; structural geology; exploration geophysics
School of Earth Sciences and Engineering, Xi'an Shiyou University, Xi'an, 710065 China
Interests: petroleum geology; organic geochemistry, shale oil mobility evaluation
Special Issues, Collections and Topics in MDPI journals
School of Petroleum Engineering and Environmental Engineering, Yan’an University, Yan'an 716000, China
Interests: petroleum and source rock geochemistry, hydrocarbon generation and accumulation mechanism

Special Issue Information

Dear Colleagues,

Petroleum source rocks are often fine-grained. Organic-rich sediments that are capable of generating and expelling oil and/or gas in commercial quantities. The ultimate aim of hydrocarbon exploration campaign is to achieve the highest production in lowest time span. Proper evaluation of the source rock potentiality in terms of the organic matter quantity, quality (kerogen type) and maturity is crucial for petroleum exploration and development strategies. These parameters are often dependent on both initial depositional conditions of the source rocks as well as secondary processes such as burial and tectonics. Therefore, identification of the source rock properties not only has economic merits but is also paramount for understanding the basin evolution. Geochemical data (Rock-Eval pyrolysis and biomarkers) is widely for the evaluation of the source rock characteristics and its capability to generate oil and gas hydrocarbons. Additionally, correlation between hydrocarbon and source rock characteristics was proven as the most effective way to understand the hydrocarbon play evolution and thus will enhance the predictability of oil and gas accumulations. Therefore, this research topic aims at enhancing our understanding the long-standing issues about the factors controlling the potentiality of oil and gas source rocks in different geological contexts.  

Dr. Mahmoud Leila
Dr. Yubin Bai
Dr. Bojiang Fan
Guest Editors

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Keywords

  • geochemistry
  • source rock
  • hydrocarbons
  • biomarkers
  • rock-eval pyrolysis
  • kerogen type

Published Papers (6 papers)

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Research

27 pages, 6832 KiB  
Article
Pore Characteristics, Oil Contents and Factors Influencing Laminated Shale in the First Member of the Qingshankou Formation in the Gulong Sag, Northern Songliao Basin
by Yuxuan Zhang, Huifang Pan, Yubin Bai, Guolong Chen, Jinglan Luo and Yang Zhang
Minerals 2023, 13(9), 1220; https://doi.org/10.3390/min13091220 - 17 Sep 2023
Cited by 2 | Viewed by 819
Abstract
To clarify the reservoir characteristics of laminated shale, the occurrence mechanism of shale oil and its influencing factors in the Gulong Sag, northern Songliao Basin, are studied to better guide the exploration and development of shale oil there. First, X-ray diffraction (XRD) and [...] Read more.
To clarify the reservoir characteristics of laminated shale, the occurrence mechanism of shale oil and its influencing factors in the Gulong Sag, northern Songliao Basin, are studied to better guide the exploration and development of shale oil there. First, X-ray diffraction (XRD) and field-emission scanning electron microscopy (FE-SEM) are used to characterize the pore types, pore geneses and factors influencing the pore volume in the study area. Second, the organic matter of the samples is extracted with a mixture of dichloromethane and methanol. Total organic carbon (TOC), nitrogen adsorption and Rock-Eval tests are performed on the samples before and after extraction to reveal the pore size distribution after extraction. The factors influencing free and adsorbed shale oil and the lower limit of pore size are discussed in detail. The results show that interparticle pores (interP pores), intraparticle pores (intraP pores), organic matter pores (OM pores) and microfractures can be found in the laminated shale (Q1) in the Gulong Sag, Songliao Basin, and that the interP pores and intercrystalline pores in clay minerals are the main pores. The FE-SEM results show that the diameters of interP pores vary from several hundred nanometers to several microns, and their morphologies are mainly triangular, strip-shaped or irregular. The morphology of the intercrystalline pores in the clay minerals is generally irregular, depending on the crystal type and arrangement of clay minerals. According to the characteristics of the nitrogen adsorption and desorption curves, the pore morphologies are mainly slit-shaped pores, parallel-plate-shaped pores and ink-bottle-shaped pores. The pore size distribution is mostly bimodal, and the pore volume contribution is the greatest in the pore size range of 10~20 nm. Before and after extraction, the overall characteristics of the pore size distribution change only slightly, but the number of micropores increases significantly. Different minerals have different degrees of influence on the proportions of micropores, mesopores and macropores. Quartz mainly inhibits the formation of micropores, while the overall effect on mesopores and macropores is positive depending on the diagenetic period. Feldspar has a strong positive correlation with the micropore and mesopore proportions but is not highly correlated with the macropore proportions. The influence of the carbonate mineral content on the pore volume is not obvious because of its complex composition. The TOC content and vitrinite reflectance (Ro) are the two most important factors controlling free oil and adsorbed oil, and the contents of mineral components, such as felsic minerals, carbonate minerals and clay minerals, have no obvious correlation with shale oil content. With increasing pore volume, the contents of free oil and adsorbed oil increase, but the proportion of adsorbed oil decreases gradually. The correlation between the specific surface area and adsorbed oil content is poor. At normal temperatures and pressures, the lower limit of the pore diameters that can contain free oil is 4 nm, and the lower limit of the pore diameters that can contain movable oil is 10 nm. Full article
(This article belongs to the Special Issue Geochemical Characterization of Source Rocks in Oil and Gas Fields)
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16 pages, 5127 KiB  
Article
Application of Organic Petrology and Raman Spectroscopy in Thermal Maturity Determination of the Karoo Basin (RSA) Shale Samples
by Vongani Chabalala, Nikki Wagner and Nandi Malumbazo
Minerals 2023, 13(9), 1199; https://doi.org/10.3390/min13091199 - 13 Sep 2023
Viewed by 710
Abstract
An assessment performed using raman spectroscopy has found space in the black shales of the Cisuralian-age rocks of the Karoo Basin in South Africa, particularly those from the Guadalupian Ripon, Cisuralian Whitehill and Prince Albert Formations. It is used in conjunction with geochemical [...] Read more.
An assessment performed using raman spectroscopy has found space in the black shales of the Cisuralian-age rocks of the Karoo Basin in South Africa, particularly those from the Guadalupian Ripon, Cisuralian Whitehill and Prince Albert Formations. It is used in conjunction with geochemical screening techniques such as organic petrology and programmed pyrolysis. In turn, the combination of these techniques is used for the assessment of the thermal maturity of the sedimentary organic matter from the perspective of hydrocarbon generation, retention, and expulsion. To provide further understanding of the black shales in the Cisuralian-age rocks of the Karoo Basin in South Africa, this study focuses on the characterization of samples from the KWV−01 borehole drilled in the southeastern Karoo Basin. In addition, the USA Devonian/Carboniferous Berea Sandstone project samples were included for comparison, and were used as a quality assurance measure. Organic petrology was utilized to assess the organic quality and thermal maturity of the black shales. The results obtained showed that the Karoo Basin shales are overmature, containing an abundance of solid bitumen, and this often characterizes a shale reservoir with moveable hydrocarbons (shale gas). The programmed pyrolysis analysis conducted on the black shales of the Karoo Basin yielded artifact results, as they were determined from a very low and poorly defined S2 peak. This indicated the shales to be overmature and categorized them to be of poor hydrocarbon generation potential. Raman spectroscopy was used to gain insights about the molecular structure of the black shales and to assess if this technique could be used as a complimentary tool to determine the thermal maturity of the shale samples. Raman parameters such as G–D1 Band separation, G and D1 band full width at half maximum (Gfwhm and D1fwhm) and G band position were successfully correlated with vitrinite reflectance (RoV), demonstrating a good potential for Raman spectroscopy to predict the thermal maturity of the shales. Overall, the study provides valuable information and knowledge concerning black shale sample characterization (particularly the thermal maturity and molecular structural characterization) in the Karoo Basin, South Africa. Full article
(This article belongs to the Special Issue Geochemical Characterization of Source Rocks in Oil and Gas Fields)
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20 pages, 29426 KiB  
Article
Lithofacies Controls on Hydrocarbon Generation Potentiality of the Syn-Rift Late Cretaceous Rakopi Deltaic Facies in the North-Eastern Offshore Part of Taranaki Basin, New Zealand
by Mahmoud Leila, Ahmed A. Radwan and Mohamed I. Abdel-Fattah
Minerals 2023, 13(9), 1169; https://doi.org/10.3390/min13091169 - 03 Sep 2023
Cited by 5 | Viewed by 1420
Abstract
The Taranaki Basin in New Zealand presents the most promising territory for strategies of hydrocarbon exploration and development. This basin contains multiple source rock levels in its sedimentary successions formed during syn- and post-rift periods. The deepest source rocks, found in the Rakopi [...] Read more.
The Taranaki Basin in New Zealand presents the most promising territory for strategies of hydrocarbon exploration and development. This basin contains multiple source rock levels in its sedimentary successions formed during syn- and post-rift periods. The deepest source rocks, found in the Rakopi Formation, were deposited in deltaic to deep marine environments and consist of gas-prone coal and organic-rich mudstone lithofacies. However, questions remain about the preservation of their organic carbon. This study integrates various organic geochemical analyses (such as Rock Eval pyrolysis, kerogen petrography, and biomarkers) to assess the hydrocarbon potential of the Rakopi coal and mudstone lithofacies. The organic carbon in Rakopi coals and mudstones originated from oxygenated bottom water, but swift burial during the initial rifting phase facilitated the preservation of organic materials. Rakopi coals are less mature than the mudstone facies and contain a mixture of desmocollinite, suberinite, and resinite macerals. In contrast, the mudstone lithofacies are enriched in liptodetrinite. The maceral mixture in the coal led to its elevated hydrogen index and likely facilitated early expulsion of liquid hydrocarbon phases. Regular steranes, diasteranes, and C29 sterane isomers distribution in the coal and mudstone extracts highlighted a greater terrestrial input in the coals, whereas significant marine input is observed in the mudstone extracts. Biomarkers in the coal and mudstone extracts are similar to some nearby oils discoveries in the Taranaki Basin, thereby confirming oil generation from both coal and mudstone lithofacies in the Rakopi Formation. These findings underscore the potential of liptinite-rich coals to generate liquid hydrocarbon phases at marginal oil maturity levels. Full article
(This article belongs to the Special Issue Geochemical Characterization of Source Rocks in Oil and Gas Fields)
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15 pages, 5302 KiB  
Article
Gas Desorption Characteristics of the Chang 7 Member Shale in the Triassic Yanchang Formation, Yan’an Area, Ordos Basin
by Bojiang Fan, Xinyang Dai and Chi Wang
Minerals 2023, 13(5), 622; https://doi.org/10.3390/min13050622 - 29 Apr 2023
Cited by 1 | Viewed by 942
Abstract
In the Yan’an area of the Ordos Basin, the lithological heterogeneity of Chang 7 Member shale is extremely strong. In addition, sandy laminae is highly developed within the Chang 7 Member shale system. In order to explore the gas generation and migration processes [...] Read more.
In the Yan’an area of the Ordos Basin, the lithological heterogeneity of Chang 7 Member shale is extremely strong. In addition, sandy laminae is highly developed within the Chang 7 Member shale system. In order to explore the gas generation and migration processes of Chang 7 Member shale, geochemical characteristics of desorption gas are comprehensively compared and analyzed. In this study, rock crushing experiments were carried out to obtain shale samples, and desorption experiments were carried out to obtain shale samples and sandy laminated shale samples. For the crushing gas and desorption gas, the volume contents of different gas components were obtained using gas chromatography experiments. The rock crushing experiments revealed that the average volume percentage of CH4 in Chang 7 Member shale is 61.93%, the average volume percentage of C2H6 and C3H8 is 29.53%, and the average volume percentage of other gases is relatively small. The shale gas in Chang 7 Member is wet gas; the gas is kerogen pyrolysis gas. Most of the shale gas hosting in Chang 7 Member shale is adsorbed gas. Porosity, permeability and organic matter content are the main geological factors controlling gas migration and gas hosting. Shale with a higher porosity, good permeability and a low organic matter content is conducive to gas migration. The shale gas in Chang 7 Member shale contains CH4, C2H6, C3H8, iC4H10, nC4H10, iC5H12, nC5H12, CO2 and N2. N2 migrates more easily than CH4, and CH4 migrates more easily than CO2. For hydrocarbon gases, gas components with small molecular diameters are easier to migrate. The desorption characteristics of shale might provide clues for guiding hydrocarbon exploration in the study area. The sandy laminated shale with a higher gas content may be the “sweet spot” of shale gas targets. In Chang 7 Member, the locations hosting both shale oil and CH4 may be the most favorable targets for shale oil production. Full article
(This article belongs to the Special Issue Geochemical Characterization of Source Rocks in Oil and Gas Fields)
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14 pages, 10940 KiB  
Article
The Geochemical Characteristics of Source Rock and Oil in the Fukang Sag, Junggar Basin, NW China
by Bocai Li, Youjun Tang, Zhonghong Chen, Yifeng Wang, Daxiang He, Kai Yan and Lin Chen
Minerals 2023, 13(3), 432; https://doi.org/10.3390/min13030432 - 17 Mar 2023
Cited by 1 | Viewed by 1219
Abstract
The Fukang Sag in the Junggar Basin is the main exploration block. However, the origin and source of crude oil are still controversial, which seriously affects the well locating and exploration in this area. In the present work, 30 source rocks and 21 [...] Read more.
The Fukang Sag in the Junggar Basin is the main exploration block. However, the origin and source of crude oil are still controversial, which seriously affects the well locating and exploration in this area. In the present work, 30 source rocks and 21 crude oils were collected for geochemical analysis to clarify the source of the organic matter, the sedimentary environment, and the evolution degree. Among them, the source rocks of the Pingdiquan Formation are type II1 organic matter with good quality, the source rocks of the Badaowan Formation are type II2-III organic matter with fair–good quality, and the source rocks of the Xishanyao Formation are type II2 organic matter with fair quality. All source rocks are in the mature stage. The results of the biomarker compounds show that the lacustrine mudstone of the Xishanyao Formation and the coal-measure mudstone of the Badaowan Formation were deposited in reducing environments. The former was mainly from lower aquatic organisms, and the latter was from terrestrial higher plants. The mudstone of the Pingdiquan Formation was formed in a weakly oxidizing–weakly reducing depositional environment, and its parent material was of mixed origin. Based on the results of the biomarker compounds and carbon isotopes, the crude oils were divided into three categories. The Family I crude oil has the characteristics of low maturity, low salinity, and more input of low-level aquatic organisms, and the carbon isotope has a good affinity with the lacustrine mudstone of the Xishanyao Formation. The Family II crude oil shows medium maturity, low salinity, mainly higher plant input, and heavy carbon isotope, mainly derived from the Badaowan Formation coal-measure mudstone. The Family III crude oil is characterized by high maturity, high salinity, mixed parent materials, and light carbon isotope and originates from the mudstone of the Pingdiquan Formation. The results provide a reference for oil and gas exploration and development in the eastern area of the Junggar Basin; the future research will focus on well areas with high maturity near the Fukang fault zone. Full article
(This article belongs to the Special Issue Geochemical Characterization of Source Rocks in Oil and Gas Fields)
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35 pages, 9922 KiB  
Article
Crude Oil Source and Accumulation Models for the Wenchang Formation, Southern Lufeng Sag, Pearl River Mouth Basin, (Offshore) China
by Hong Pang, Kuiyou Ma, Xungang Huo, Shengmin Huang, Song Wu and Xingang Zhang
Minerals 2023, 13(2), 162; https://doi.org/10.3390/min13020162 - 21 Jan 2023
Viewed by 1531
Abstract
In recent years, a large amount of industrial oil and gas resources have been discovered in the Paleogene Wenchang Formation (WC) of the southern Lufeng sag, confirming that the WC resources are promising prospects for petroleum exploration. However, because of the complex lithology, [...] Read more.
In recent years, a large amount of industrial oil and gas resources have been discovered in the Paleogene Wenchang Formation (WC) of the southern Lufeng sag, confirming that the WC resources are promising prospects for petroleum exploration. However, because of the complex lithology, multiple sources of crude oil and multi-period charging characteristics in the WC, the accumulation process and model have not been clearly understood. Therefore, in this study, the main sources of crude oil and the process of hydrocarbon accumulation in key oil accumulation periods are determined by combining biomarker and geological analyses. Finally, the model of oil and gas accumulation is systematically summarized. The obtained results show that the source rock of the WC is the main source of hydrocarbons in the study area. The crude oil types in the southern Lufeng sag are classified into three types. Type A crude oil comes from source rocks of Wenchang Formation Members 3 and 4. Type B crude oil comes partly from source rocks of Wenchang Formation Members 1, 2, and 3 and partly from source rocks of Wenchang Formation Members 5 and 6. Type C crude oil is a mix of type A and type B crude oil. There are three accumulation periods that typify the study area: in the first period, accumulation was with vertical migration by fault; in the second period, accumulation was with lateral migration by sand body; and in the third period, accumulation was with vertical migration by sand body and adjacent to the source. The methodology and results of the accumulation process in southern Lufeng sag can support offshore oil and gas exploration. Full article
(This article belongs to the Special Issue Geochemical Characterization of Source Rocks in Oil and Gas Fields)
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