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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: 5 June 2024 | Viewed by 9263

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Dr. Shuangbiao Han

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Guest Editor

College of Geoscience and Surveying Engineering, China University of Mining and Technology, Beijing, China
Interests: unconventional oil and gas; natural hydrogen resources; shale oil and gas

Dr. Lei Chen

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Guest Editor

School of Geosciences, China University of Petroleum (East China), Qingdao 266580, China
Interests: unconventional oil and gas geology; accumulation mechanism and distribution mode of hydrocarbon
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Dear Colleagues,

Remarkable achievements have been made in the theory and exploration practice of conventional reservoirs, and the large-scale and efficient development of unconventional oil and gas has been gradually realized. Unconventional oil and gas geological theories such as tight oil and shale gas have been preliminarily formed, and the integrated geological engineering evaluation technology of “sweet spots” has been established. The research of various types of oil and gas reservoirs as an interconnected whole sequence could yield new ideas for the study of conventional and unconventional hydrocarbon accumulation mechanisms, and for distribution prediction.

The Special Issue aims to present and disseminate the most recent advances related to the theory, technology and application of different types of oil and gas.

Topics of interest for publication include, but are not limited to:

Oil and gas exploration and evaluation techniques in mature exploration areas;
Shale oil and gas exploration and evaluation techniques;
Tight oil and gas exploration and evaluation techniques;
Coalbed methane exploration and evaluation techniques;
Natural gas hydrate exploration and evaluation techniques;
Integrated geological engineering technology of unconventional oil and gas.

Dr. Shuangbiao Han
Dr. Lei Chen
Guest Editors

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Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2600 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Published Papers (8 papers)

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Research

23 pages, 7124 KiB

Open AccessArticle

Geochemical Characteristics of Mesoproterozoic Source Rocks in North China: Insights for Organic Matter Enrichment and Thermal Evolution

by Shuangbiao Han, Yu Qiao, Chaohan Xiang, Jinchuan Zhang, Ye Wang, Mengxia Huo, Xiaoyan Mu, Jie Huang and Junhao Zhu

Energies 2024, 17(3), 596; https://doi.org/10.3390/en17030596 - 26 Jan 2024

Cited by 1 | Viewed by 545

Abstract

In recent years, the exploration of oil and gas in China’s Precambrian strata has garnered significant attention, leading to notable advancements in exploration play assessment. However, there is a dearth of published literature on Proterozoic source rocks’ organic sources, sedimentary environments, marine hydrochemistry, and other attributes. This study focuses on investigating potential source rocks within the Hongshuizhuang and Xiamaling Formations in the Jibei Depression of North China. A comprehensive analysis was conducted to evaluate hydrocarbon generation characteristics, using hydrocarbon biomarkers and polar compounds as geochemical indicators for precursor biota and maturity levels. The results indicate high organic matter abundance with predominantly type I-II₁ organic matter composition in the studied source rocks. These samples are at an immature–low mature stage, with the potential for primarily generating aromatic crude oil. The parent material is mainly attributed to lower aquatic organisms, such as bacteria and algae. The sedimentary environment exhibits marine facies, characterized by high evaporation rates, salinity levels, and strong euxinic conditions, that led to sulfur incorporation into the organic matter matrix. It should be noted that correlations between biomarker parameters and maturity may not be fully applicable to ancient source rocks; however, the methyldibenzothiophene ratio (MDR) demonstrates a strong correlation with Tmax. The compounds and their total monoisotope ions abundance (TMIA) were primarily identified and analyzed using FT–ICR MS. It was observed that these compounds were influenced by the depositional environment and organic matter maturity. Importantly, it was clearly demonstrated that the DBE and carbon number range of CH compounds gradually increased with maturity, due to the removal of N, S, and O functional groups. Specifically, N₁ compounds predominantly consisted of carbazoles with short alkyl side chains which readily converted into N₁O_x compounds. On the other hand, O₁ compounds mainly comprised benzofurans with low abundance, indicating a reducing sedimentary environment, as suggested by their low TMIA values. Furthermore, S₁ compounds were primarily thiophenes whose DBE range and carbon number increased with maturity, possibly suggesting an abiotic input of inorganic sulfur. Notably, the maturity indices (MAT) proved suitable for Mesoproterozoic source rocks while exhibiting strong linear relationships. Full article

(This article belongs to the Special Issue Formation and Distribution of Conventional and Unconventional Oil and Gas)

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23 pages, 9367 KiB

Open AccessArticle

Origin, Migration, and Characterization of Gas in the Xinglongtai Area, Liaohe Subbasin (Northeast China): Insight from Geochemical Evidence and Basin Modeling

by Sibo Yang, Meijun Li, Yanshan Wang, Hong Xiao, Shuangquan Huang, Wujiang Kang and Fangzheng Wang

Energies 2023, 16(18), 6429; https://doi.org/10.3390/en16186429 - 05 Sep 2023

Viewed by 683

Abstract

Buried hill zones in the rift basins have a significant impact on the enrichment of natural gas resources, and this is of great significance for exploration and development. This study aims to unravel the origins, migration, and dynamic accumulation process of natural gas in the Xinglongtai structural belt, Liaohe Subbasin. A comprehensive geological and geochemical analysis was performed on source rocks and natural gas samples from various geological structures within the Xinglongtai structural belt. Moreover, basin modeling techniques were employed to trace the genesis and migration of natural gas, offering an in-depth understanding of the dynamic process of accumulation. We identified the Fourth Mbr (Es₄) and Third Mbr (Es₃) of the Shahejie Fm as the main source rocks in the Qingshui and Chenjia Sags. The Es₄, primarily Shallow Lacustrine Mudstones, contributed mainly type II organic matter, while the Es₃, consisting of Nearshore Subaqueous Fan and Deep Lacustrine Mudstones, contributed mainly type III and type II organic matter, respectively. Two distinct hydrocarbon accumulation systems were observed, one inside and one outside the buried hills. The system outside the buried hill is governed by a complex fault system within the lacustrine basin, resulting in dual-source directions, dual-source rock types, two migration phases, and late-stage accumulation. In contrast, the system within the buried hill primarily involves reservoirs nested in the basement, exhibiting dual-source directions, dual-source rock types, a single migration phase, and early-stage charging. The understanding of this interplay, alongside dynamic simulation of generation, migration, and accumulation, can provide valuable insights for predicting natural gas distribution and accumulation patterns in terrestrial faulted lacustrine basins. This knowledge can guide more effective exploration and development strategies for natural gas. Full article

(This article belongs to the Special Issue Formation and Distribution of Conventional and Unconventional Oil and Gas)

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23 pages, 5847 KiB

Open AccessArticle

Quartz Origins and Paleoenvironmental Controls on Organic Matter Accumulation of Marine Shale in the Ordovician Wulalike Formation, Northwestern Ordos Basin, China: Significance for Shale Gas Exploration

by Yanni Zhang, Rongxi Li, Shengli Xi, Jianwen Gao, Lei Chen, Hexin Huang, Bangsheng Zhao and Ahmed Khaled

Energies 2023, 16(14), 5278; https://doi.org/10.3390/en16145278 - 10 Jul 2023

Cited by 1 | Viewed by 1012

Abstract

The Ordovician Wulalike marine siliceous shale is a notable hydrocarbon source rock in the Northwestern Ordos Basin. However, the causes of quartz and organic matter enrichment are still a mystery to experts. In this study, the organic geochemistry (maceral compositions, R_bitu, and TOC) and elemental geochemistry (major and trace elements) with mineralogy (XRD) and petrography were jointly acquired to systematically investigate the quartz origins and the paleoenvironment, and the main controlling factors for organic matter enrichment in the Wulalike shale. The results show that the organic matter is type I kerogen with low TOC concentrations (average 0.51%), and that the thermal evolution has reached mature and high mature stages (mean R_equ is 1.08%). Three types of quartz are developed in Wulalike shale: biogenic quartz (average 63%) is the most dominant, followed by clastic quartz (average 31%) and microcrystalline quartz (average 6%). Babio and Ba/Al values indicate the low paleoproductivity, which is the primary cause for the low TOC found throughout the area. Redox indexes show the anoxic or dysoxic to oxic conditions from the bottom to the top of the section. Paleoclimate and paleowater depth proxies also changed from the bottom to the top. Various paleoenvironments and sedimentological evidence show that Wulalike shale went through the changing environments, and the early sedimentary environments were conducive to organic matter enrichment, leading to a relatively high TOC. The paleoproductivity and preservation conditions have an impact on organic matter enrichment. Based on the results of biogenic quartz distribution and sedimentary environments, it is considered that the bottom of the Wulalike Formation is the most favorable for shale gas exploration and development. Full article

(This article belongs to the Special Issue Formation and Distribution of Conventional and Unconventional Oil and Gas)

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26 pages, 7264 KiB

Open AccessArticle

Prediction of TOC Content in Organic-Rich Shale Using Machine Learning Algorithms: Comparative Study of Random Forest, Support Vector Machine, and XGBoost

by Jiangtao Sun, Wei Dang, Fengqin Wang, Haikuan Nie, Xiaoliang Wei, Pei Li, Shaohua Zhang, Yubo Feng and Fei Li

Energies 2023, 16(10), 4159; https://doi.org/10.3390/en16104159 - 18 May 2023

Cited by 4 | Viewed by 1776

Abstract

The total organic carbon (TOC) content of organic-rich shale is a key parameter in screening for potential source rocks and sweet spots of shale oil/gas. Traditional methods of determining the TOC content, such as the geochemical experiments and the empirical mathematical regression method, are either high cost and low-efficiency, or universally non-applicable and low-accuracy. In this study, we propose three machine learning models of random forest (RF), support vector regression (SVR), and XGBoost to predict the TOC content using well logs, and the performance of each model are compared with the traditional empirical methods. First, the decision tree algorithm is used to identify the optimal set of well logs from a total of 15. Then, 816 data points of well logs and the TOC content data collected from five different shale formations are used to train and test these three models. Finally, the accuracy of three models is validated by predicting the unknown TOC content data from a shale oil well. The results show that the RF model provides the best prediction for the TOC content, with R² = 0.915, MSE = 0.108, and MAE = 0.252, followed by the XGBoost, while the SVR gives the lowest predictive accuracy. Nevertheless, all three machine learning models outperform the traditional empirical methods such as Schmoker gamma-ray log method, multiple linear regression method and ΔlgR method. Overall, the proposed machine learning models are powerful tools for predicting the TOC content of shale and improving the oil/gas exploration efficiency in a different formation or a different basin. Full article

(This article belongs to the Special Issue Formation and Distribution of Conventional and Unconventional Oil and Gas)

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27 pages, 4853 KiB

Open AccessArticle

Coastal Depositional Responses to Relative Sea-Level Rise: Insights from a Superimposed Sandstone–Shale–Coal Reservoir in the Linxing Gas Field, China

by Jincheng Liu, Yan Zhang and Jingqiang Tan

Energies 2023, 16(10), 4144; https://doi.org/10.3390/en16104144 - 17 May 2023

Cited by 1 | Viewed by 909

Abstract

The Ximing Sandstone-to-No. 9 Coal succession of the Taiyuan Formation in the Linxing gas field records a complex internal architecture of a transgressive succession developed in the western coast of the late Pennsylvanian North China epeiric sea. Facies and sequence stratigraphic analyses reveal its depositional evolution from fluvial channels through fluvial-dominated and tide-influenced inner estuaries to tide-dominated estuaries and finally to wave-dominated barrier lagoons. The evolution from fluvial- to tide-dominated deposition has been ascribed to the funnel-shaped valley coupled with an increased tidal prism induced by the upstepping and backstepping shoreline. The evolution from tide- to wave-dominated deposition has been ascribed to the wide North China epeiric seaway lacking local coastline irregularities after the incised-valley fill that provided sufficient fetch for the occurrence of large storm waves. Grain-size analysis reveals the relative importance of traction, saltation, dispersed suspension, and flocculated suspension in the development of the transgressive estuarine to lagoonal deposits. This study not only contributes to a proper understanding of coastal depositional response to the relative sea-level rise but also provides a context within which to interpret the symbiotic relationship of the superimposed sandstone–shale–coal reservoirs and predict the distribution of favorable unconventional gas production formation. Full article

(This article belongs to the Special Issue Formation and Distribution of Conventional and Unconventional Oil and Gas)

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17 pages, 4551 KiB

Open AccessArticle

Application of Inter-Well Connectivity Analysis with a Data-Driven Method in the SAGD Development of Heavy Oil Reservoirs

by Suqi Huang, Ailin Jia, Xialin Zhang, Chenhui Wang, Xiaomin Shi and Tong Xu

Energies 2023, 16(7), 3134; https://doi.org/10.3390/en16073134 - 30 Mar 2023

Viewed by 1355

Abstract

The development of heavy oil reservoirs in China is of great significance to safeguard national energy security, but great challenges are faced due to the complex and heterogeneous reservoir properties. Inter-well connectivity analysis is critical to enhancing the development performance, as it is a good way to interpret fluid flow and provides a theoretical basis for injection-production optimization. Data-driven deep learning methods have been widely used in reservoir development and can be employed to develop surrogate models of injection and production and to infer inter-well connectivity. In this study, the model performance of a recurrent neural network (RNN) and its four variants were evaluated and compared in a temporal production prediction. The comparison results showed that bidirectional gated recurrent unit (Bi-GRU) is the optimal algorithm with the highest accuracy of 0.94. A surrogate model was established to simulate the inter-well connectivity of steam-assisted gravity drainage (SAGD) in the research area by utilizing the Bi-GRU algorithm. A global sensitivity analysis method, Fourier amplitude sensitivity testing (FAST), was introduced and combined with the surrogate model to explain the influence of the input variables on the output variables by quantitatively calculating the sensitivity of each variable. Quantitative results for the inter-well connectivity of SAGD were derived from the sensitivity analysis of the proposed method, which was effectively applied to typical linear patterns and five-spot patterns. Inter-well connectivity varied from 0.1 to 0.58 in test applications, and mutual corroboration with previous geological knowledge can further determine the distribution of the interlayer in the reservoir. The workflow proposed in this study provides a new direction for analyzing and inferring the inter-well connectivity of SAGD in Northeast China heavy oil reservoirs. Full article

(This article belongs to the Special Issue Formation and Distribution of Conventional and Unconventional Oil and Gas)

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18 pages, 7739 KiB

Open AccessArticle

Lithofacies Characteristics and Their Effects on Shale Oil Enrichment: A Case Study from Shahejie Formation of the Qibei Sag, Bohai Bay Basin, China

by Congsheng Bian, Bincheng Guo, Xiugang Pu, Xu Zeng, Wei Liu, Yongxin Li, Kejia Zhou, Qianhui Tian and Chao Ma

Energies 2023, 16(5), 2107; https://doi.org/10.3390/en16052107 - 21 Feb 2023

Viewed by 1112

Abstract

The lithology and lithofacies assemblage of shale are highly complex and heterogeneous in the continental shale formations due to rapid changes in the sedimentary environment and source material, complicating the evaluation of shale oil enrichment areas, such as the member 3 of the Shahejie Formation in the Qikou sag, Bohaibay Basin, China. We used core observations and descriptions of well F39 × 1 and performed X-ray diffraction, scanning electron microscopy, nitrogen adsorption analysis, and nuclear magnetic resonance analysis to investigate the shale lithofacies characteristics and types in member 3 of the Shahejie Formation, and their effects on shale oil enrichment. The results showed the following. (1) The lithofacies are divided into four types according to the shale’s laminar structure, lithological characteristics, mineral composition, and organic matter content: thin laminar shale, thick laminar shale, massive mudstone, and argillaceous siltstone. These are divided into six subcategories. Each lithofacies has thin vertical layers. (2) The thin and thick laminar shale layers have favorable conditions for shale oil enrichment, such as a high total organic carbon content (TOC) (1.1–1.6%), many micropores (with the diameter of 0.5–2 µm) and fissures, a high residual hydrocarbon content (1.0–2.3 mg/g), and a good source-reservoir relationship, making them suitable for shale oil exploration. (3) The degree of lamina development influences the organic matter and residual hydrocarbon contents, the number of micropores, and the degree of shale oil enrichment. The semi-deep and deep lake facies are favorable areas for shale oil development. Full article

(This article belongs to the Special Issue Formation and Distribution of Conventional and Unconventional Oil and Gas)

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15 pages, 5475 KiB

Open AccessFeature PaperArticle

Quantitative Evaluation of Gypsum-Salt Caprock Sealing Capacity Based on Analytic Hierarchy Process—A Case Study from the Cambrian in the Tarim Basin, Western China

by Shan Zhao, Hua Liu, Yongfeng Zhu, Shen Wang and Xianzhang Yang

Energies 2022, 15(19), 7139; https://doi.org/10.3390/en15197139 - 28 Sep 2022

Viewed by 1137

Abstract

Gypsum-salt caprock is one of the most important caprocks in petroliferous basins around the world. Its sealing capacity extremely affects hydrocarbon accumulation and distribution. However, there are numerous variables that affect caprock sealing performance, making a quantitative evaluation challenging. The analytic hierarchy process (AHP), which has the advantage of turning several influencing factors into multi-level single objectives, can be utilized in this context to quantify the weight of each element impacting caprock sealing capacity. As a result, using the Tarim Basin’s Cambrian as an example, this article quantitatively assessed the gypsum-salt caprock sealing capacity using AHP. The results show that factors affecting the sealing capacity of Cambrian gypsum-salt caprock in the Tarim Basin can be summarized into three major categories and nine sub-categories, including the lithology (rock assemblage type and lithology zoning), the thickness (total thickness of thick single layer, maximum thickness of thick single layer, total thickness, and ratio of caprock to stratum), and the mechanical properties (internal friction coefficient, compressive strength, peak strength). The sealing ability evaluation index (C) was created by applying AHP to quantify a number of different characteristics. The capacity of the caprock to seal is inversely correlated with the C-value. The value of C in the plane climbs consistently from Tabei to Tazhong and subsequently to the Bachu region, indicating a steady improvement in caprock sealing ability. Additionally, the evaluation’s findings are in line with how hydrocarbon accumulations are currently distributed. Furthermore, hydrocarbons are mostly distributed in subsalt and subsalt-dominated layers when C is greater than 2. On the contrary, hydrocarbons are mainly distributed in post-salt layers when C is less than 2. Furthermore, in areas affected by faults, hydrocarbons are favorably distributed in subsalt layers when C reaches 2, and fault activity is poor or strong in the early period and weak in the late period. Full article

(This article belongs to the Special Issue Formation and Distribution of Conventional and Unconventional Oil and Gas)

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