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Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration

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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: closed (31 December 2022) | Viewed by 19995

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Special Issue Editors

Prof. Dr. Tao Jiang

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Guest Editor

College of Marine Science and Technology, China University of Geosciences, Wuhan 430074, China
Interests: deep-water sedimentation dynamics; geology of natural gas hydrate; marine sediment luminescence chronology

Prof. Dr. Ming Su

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Guest Editor

School of Marine Sciences, Sun Yat-Sen University, Guangzhou, China
Interests: marine geology; deep-water deposits; petroleum geology; gas hydrates
Special Issues, Collections and Topics in MDPI journals

Dr. Zenggui Kuang

E-Mail Website
Guest Editor Assistant

Southern Marine Science and Engineering Guangdong Laboratory (Guangzhou), Guangzhou 510075, China
Interests: marine geology; deep-water deposits; gas hydrates

Special Issue Information

Dear Colleagues,

Natural gas hydrate and deep-water hydrocarbon have become hotspots of global oil and gas exploration in recent years. Natural gas hydrate is an efficient and clean energy source with huge resource potential, generally occurring within submarine sediments at a water depth of more than 300 meters and in permafrost areas. It is estimated that the global resource of natural gas hydrate could reach up to 20 trillion tons of oil equivalent. Marine gas hydrates are mainly distributed in the Gulf of Mexico, the Nankai Trough, the Ulleung Basin, the offshore of India, the coast of New Zealand, the South China Sea, and other areas. The natural gas hydrate resources in submarine sediments warrant more attention for their effective exploitation.

Internationally, deep-water hydrocarbon typically refers to oil and gas resources in waters with a depth of more than 200 meters. It was reported that the recoverable reserves of the world’s accumulated deep-water oil and natural gas are 412×10⁸ t and 132×10¹² m³, respectively. So far, more than 60 countries have carried out deep-water hydrocarbon exploration, and more than 1,300 deep-water hydrocarbon fields have been discovered worldwide. Among them, the Gulf of Mexico, the offshore of Brazil, and the continental shelf of West Africa have achieved great success. Moreover, world-class deep-water hydrocarbon fields have also been continuously discovered in the Eastern Mediterranean, the North Sea, the Northwest Shelf of Australia, and the South China Sea. Nonetheless, the exploration of global deep-water hydrocarbons still faces many obstacles.

At present, the key issue is that conventional geological theories and understanding cannot be applied to natural gas hydrate and deep-water hydrocarbon exploration due to their complex exploration and development processes. Therefore, innovative theories and technologies are needed to realize the commercial exploitation of natural gas hydrate and deep-water oil and gas under complex conditions. This Special Issue focuses on discoveries and new methods, comprehensive laboratory experiments and field investigations, theoretical and numerical simulation, and the in-depth understanding of natural gas hydrate and deep-water hydrocarbon accumulation. Moreover, this Special Issue may provide a solid geological basis for commercializing natural gas hydrate and deep-water oil and gas. We welcome original research and review articles.

Potential topics include, but are not limited to, the following:

The accumulation mechanism and controlling factors of natural gas hydrate and deep-water hydrocarbon;
The origin and geochemical characteristics of gas hydrate and deep-water hydrocarbon;
Geophysical characterization of focused fluid flows and their sources;
Deep-water sedimentary systems related to gas hydrate and hydrocarbon accumulation;
Source-to-sink system and distribution of favorable deep-water reservoirs;
Numerical simulation of the formation of favorable deep-water reservoirs and hydrocarbon accumulation;
The symbiotic relationship between natural gas hydrate and deep-water hydrocarbon;
Morphology, architecture, flow dynamics, evolution, and sedimentation of deep-water hydrocarbon.

Prof. Dr. Tao Jiang
Prof. Dr. Ming Su
Guest Editors
Zenggui Kuang
Guest Editor Assistant

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Keywords

natural gas hydrate
deep-water hydrocarbon
deep-water sedimentary processes
flow dynamics
geochemical characteristics
gas genetic type
fluid flows
gas migration pathways
bottom-simulating reflector (BSR)
seismic anomalies
mass transport deposits
deep-water canyon/channel
deep-water sand-rich reservoir
numerical simulation
accumulation model

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Published Papers (10 papers)

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Research

18 pages, 8131 KiB

Open AccessArticle

The Facies Analysis, Evolution, and Coal-Bearing Source Rock Features of the Middle–Late Triassic Shallow-Water Delta in the North Carnarvon Basin, Northwest Shelf of Australia

by Zhiwei Zeng, Wei Wang, Hongtao Zhu, Xianghua Yang and Dan Li

Energies 2023, 16(5), 2265; https://doi.org/10.3390/en16052265 - 27 Feb 2023

Viewed by 2503

Abstract

The sedimentary facies, architecture, and depositional mechanism of deltaic systems have been one of the global research hotspots in recent decades; however, the detailed distribution, sedimentary evolution, source rock potential, and major control factors of the coal-bearing shallow-water delta are still unclear. A typical shallow-water braided delta with coal-bearing source rocks developed in the Middle–Late Triassic Mungaroo Formation of the North Carnarvon Basin, which can be a good study area for an analysis of coal-bearing source rocks. In this study, the sedimentary facies, distribution and evolution, and coal-bearing source rock features of the Triassic strata were analyzed based on the integrated study of wireline logs, drilled cores, thin sections, seismic facies and attributes, and geochemical data. A range of shallow-water delta sedimentary facies was identified, including the proximal delta plain channel/interdistributary bay, distal delta plain channel/interdistributary bay, and the delta front. The coal-bearing shallow-water delta system of the Middle–Late Triassic Mungaroo Formation was characterized by the largest scale delta system with relatively broad proximal and distal delta plains and relatively narrow delta front subfacies. The scale of the delta system showed a trend of increasing from the Early Triassic Locker Shale to the Middle–Late Triassic Mungaroo Formation and then decreasing to the Late Triassic Brigadier Formation. The distal delta plain subfacies of the Mungaroo Formation should have the highest potential coal-bearing source rock, and the proximal delta plain also can be a favorable target for source rock evaluation. The major control factors of the coal-bearing source rocks of the Mungaroo shallow-water delta mainly included the Triassic megamonsoon climate, the topographic features, eustatic changes, and provenance supply. The proximal and distal delta plains of the shallow-water delta system with thin coal seams, carbonaceous mudstone, and dark mudstone lithologies’ association could be a favorable source rock exploration facies for the next stage of natural gas field exploration. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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16 pages, 7215 KiB

Open AccessArticle

Reconstruction of Lake-Level Changes by Sedimentary Noise Modeling (Dongying Depression, Late Eocene, East China)

by Zhongheng Sun, Tao Jiang, Hongtao Zhu, Xinluo Feng and Pengli Wei

Energies 2023, 16(5), 2216; https://doi.org/10.3390/en16052216 - 24 Feb 2023

Viewed by 1622

Abstract

The late Eocene succession of the Dongying Depression forms a highly productive hydrocarbon source. However, due to lack of an unambiguous fine chronostratigraphic framework for the late Eocene stratigraphy, it is challenging to understand the paleolake’s evolution and the driven mechanism of lake-level variation, a limitation which hinders hydrocarbon exploration. In this work, high-resolution gamma-ray logging data were analyzed to carry out the cyclostratigraphic analysis of the third member (Es₃) of the Shahejie Formation in the Dongying Depression. Significant 405-kyr eccentricity cycles were recognized based on time series analysis and statistical modeling of estimated sedimentation rates. We abstracted ~57 m cycles of the GR data in the Es₃ member, which were comparable with the long eccentricity cycles (~405-kyr) of the La2004 astronomical solution, yielding a 6.43 Myr long astronomical time scale (ATS) for the whole Es₃ member. The calibrated astronomical age of the third/fourth member of the Shahejie Formation boundary (41.21 Ma) was adopted as an anchor point for tuning our astrochronology, which provided an absolute ATS ranging from 34.78 ± 0.42 Ma to 41.21 ± 0.42 Ma in Es₃. According to the ATS, sedimentary noise modeling for the reconstruction of lake-level changes was performed through the late Eocene Es₃. The lake-level changes obtained based on sedimentary noise modeling and spectrum analysis reveal significant ~1.2 Myr cycles consistent with global sea level variations which were related to astronomical forcing. Potential driven mechanisms of marine incursion and/or groundwater table modulation were linked to explain the co-variation of global sea level changes and regional lake level changes. Our results suggest global sea level fluctuations may have played an important role in driving the hydroclimate and paleolake evolution of the late Eocene Dongying Depression. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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17 pages, 20177 KiB

Open AccessArticle

Effects of Depositional Processes in Submarine Canyons and Distribution of Gas Chimneys on Gas Hydrate Accumulation in the Shenhu Sea Area, Northern South China Sea

by Yunlong He, Zenggui Kuang, Cong Cheng, Tao Jiang, Cheng Zhang, Biyu Lu, Chengzhi Yang, Jiayu Liu and Changlong Xiang

Energies 2023, 16(1), 234; https://doi.org/10.3390/en16010234 - 25 Dec 2022

Cited by 3 | Viewed by 2022

Abstract

Previous gas hydrate production tests conducted by the Guangzhou Marine Geological Survey (GSGM) in 2017 and 2020 indicated the great potential of gas hydrates in the Shenhu Sea area in the Pearl River Mouth Basin (PRMB), China. In this study, the effects of deposition processes in submarine canyons and the distribution of gas chimneys on gas hydrate accumulation were investigated using high-resolution two- dimensional (2D) and three-dimensional (3D) seismic data. Four intact submarine canyons were identified in the study area. Five deepwater depositional elements are closely related to submarine canyons: lateral accretion packages (LAPs), basal lags, slides, mass transport deposits (MTDs), and turbidity lobes. MTDs and lobes with multiple stages outside the distal canyon mouth reveal that the sedimentary evolution of the canyon was accompanied by frequent sediment gravity flows. Gas chimneys originating from Eocene strata are generally up to 3 km wide and distributed in a lumpy or banded pattern. The analysis of seismic attributes confirmed fluid activity in these gas chimneys. Gas hydrates are mainly distributed in ridges among different canyons. Based on the gas sources of gas hydrates and depositional evolution of submarine canyons, depositional processes of sediment gravity flows in submarine canyons and the distribution of gas chimneys significantly affect the accumulation of gas hydrates. Based on these findings, this study establishes a conceptional model for the accumulation of gas hydrate, which can provide guidance in the prediction for favorable gas hydrates zones in the area and nearby. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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18 pages, 30613 KiB

Open AccessArticle

New Insights into the Genetic Mechanism of the Miocene Mounded Stratigraphy in the Qiongdongnan Basin, Northern South China Sea

by Litao Xu, Wanzhong Shi, Ren Wang, Jinfeng Ren, Yulin He, Hao Du, Tingna Zuo, Jin Huang and Yang Dong

Energies 2022, 15(24), 9478; https://doi.org/10.3390/en15249478 - 14 Dec 2022

Cited by 1 | Viewed by 1390

Abstract

The origin of deep-water mounds has been a topic of debate in recent years. In this study, newly collected seismic data were employed to characterize the mounds within the Meishan Formation in the Qiongdongnan Basin and a novel model was proposed. The result showed that pervasive mounds and ‘V’-shaped troughs were alternately distributed at the top of the Meishan Formation. They appeared as elongated ridges flanked by similarly elongated gullies, with the trending parallel with the strike of the basinward slope. The mounded features were considered to be formed in response to the tectonically induced seabed deformation. The differential subsidence steepened the slope that was equivalent to the top of the Meishan Formation (ca. 10.5 Ma), which offered sufficient driving forces triggering the slope’s instability. Correspondingly, the uppermost deposits glided along a bedding-parallel detachment surface, creating a number of listric detachment faults that ceased downward to this surface. The uppermost layer was cut into a range of tilted fault blocks with tops constituting a seemingly mounded topography. Some of the downfaulted troughs between mounds steered the gravity flows and were filled by sand-rich lithologies. The differential subsidence played a decisive role in the formation of a mounded stratigraphy, which in turn acted as clues to the important tectonic phase since the late Miocene. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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22 pages, 3892 KiB

Open AccessArticle

Cenozoic Depositional Evolution and Stratal Patterns in the Western Pearl River Mouth Basin, South China Sea: Implications for Hydrocarbon Exploration

by Entao Liu, Yong Deng, Xudong Lin, Detian Yan, Si Chen and Xianbin Shi

Energies 2022, 15(21), 8050; https://doi.org/10.3390/en15218050 - 29 Oct 2022

Cited by 4 | Viewed by 1895

Abstract

Investigating the deposition evolution and stratal stacking patterns in continental rift basins is critical not only to better understand the mechanism of basin fills but also to reveal the enrichment regularity of hydrocarbon reservoirs. The Pearl River Mouth Basin (PRMB) is a petroliferous continental rift basin located in the northern continental shelf of the South China Sea. In this study, the depositional evolution process and stacking pattern of the Zhu III Depression, western PRMB were studied through the integration of 3D seismic data, core data, and well logs. Five types of depositional systems formed from the Eocene to the Miocene, including the fan delta, meandering river delta, tidal flat, lacustrine system, and neritic shelf system. The representative depositional systems changed from the proximal fan delta and lacustrine system in the Eocene–early Oligocene, to the tidal flat and fan delta in the late Oligocene, and then the neritic shelf system in the Miocene. The statal stacking pattern varied in time and space with a total of six types of slope break belts developed. The diversity of sequence architecture results from the comprehensive effect of tectonic activities, sediment supply, sea/lake level changes, and geomorphic conditions. In addition, our results suggest that the types of traps are closely associated with stratal stacking patterns. Structural traps were developed in the regions of tectonic slope breaks, whereas lithological traps occurred within sedimentary slope breaks. This study highlights the diversity and complexity of sequence architecture in the continental rift basin, and the proposed hydrocarbon distribution patterns are applicable to reservoir prediction in the PRMB and the other continental rift basins. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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17 pages, 6643 KiB

Open AccessArticle

Numerical Simulation on Erosion Wear Law of Pressure-Controlled Injection Tool in Solid Fluidization Exploitation of the Deep-Water Natural Gas Hydrate

by Yang Tang, Peng Zhao, Xiaoyu Fang, Guorong Wang, Lin Zhong and Xushen Li

Energies 2022, 15(15), 5314; https://doi.org/10.3390/en15155314 - 22 Jul 2022

Cited by 2 | Viewed by 1689

Abstract

The pressure-controlled injection tool (PCIT) is the key equipment in the process of high-pressure water jet fragmentation in the solid fluidization exploitation of deep-sea natural gas hydrate (NGH). The internal flow field erosion wear numerical simulation model of PCIT is established through computational fluid dynamics software to study the influence law and main factors of the drilling fluid erosion wear of PCIT. The influence laws of different drilling fluid physical parameters and different structural parameters on PCIT erosion wear were analyzed based on the Euler–Lagrangian algorithm bidirectional coupled discrete phase model (DPM) and the solid–liquid two-phase flow model. The results show that the easily eroded areas are the cone of the sliding core, the plug transition section, the plug surface, and the axial flow passage. The sliding core inlet angle and solid particle size are the main factors affecting the PCIT erosion rate. When the inlet angle of the sliding core is 30°, the diameter of solid-phase particles in drilling fluid is less than 0.3 mm, and the erosion degree of the PCIT could be effectively reduced. The research results can provide guidance for the design and application of the PCIT and advance the early realization of the commercial exploitation of hydrate. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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16 pages, 6478 KiB

Open AccessArticle

Study of the Appropriate Well Types and Parameters for the Safe and Efficient Production of Marine Gas Hydrates in Unconsolidated Reservoirs

by Yuan Chen, Shiguo Wu, Ting Sun and Shu Jia

Energies 2022, 15(13), 4796; https://doi.org/10.3390/en15134796 - 30 Jun 2022

Viewed by 1478

Abstract

The majority of marine hydrates are buried in unconsolidated or poorly consolidated marine sediments with limited cementation and strength. As a result, hydrate decomposition during production may cause significant subsidence of the formation, necessitating a halt in production. The numerical model of unconsolidated hydrate formation, based on geomechanics, was established in order to elucidate the depressurization production process. The sensitive factors of unconsolidated hydrate production were determined by analyzing the influence of formation parameters and production parameters on gas production. Then, a safety formation subsidence was proposed in this paper, and the appropriate well type and parameters for the safe and efficient production of hydrates in unconsolidated formations of various saturations were determined. The sensitivity of gas production to the formation parameters was in the order of formation porosity, hydrate saturation, and buried depth, while the effects of the production parameters were BHP (bottom hole pressure), horizontal length, and heat injection, in descending order. For hydrate reservoirs in the South China Sea, when hydrate saturation is 20%, a horizontal well is necessary and the appropriate horizontal length should be less than 80 m. However, when hydrate saturation is more than 30%, a vertical well should be selected, and the appropriate bottom hole pressure should be no less than 3800 kPa and 4800 kPa for 30% and 40% saturation, respectively. Based on the simulation results, hydrate saturation was the key factor by which to select an appropriate production technique in advance and adjust the production parameters. The study has elucidated the depressurization production of marine unconsolidated hydrate formations at depth, which has numerous implications for field production. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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19 pages, 15350 KiB

Open AccessArticle

Quantitative Analysis of Cenozoic Extension in the Qiongdongnan Basin, South China Sea: Insight on Tectonic Control for Hydrocarbon Reservoir Accumulation and Formation

by Yan Zhang, Li Zhang, Lijun Mi, Xiangyang Lu, Shiguo Wu, Lishan Tang, Jie Zhou, Xiaofeng Xiong and Jitian Zhu

Energies 2022, 15(11), 4011; https://doi.org/10.3390/en15114011 - 30 May 2022

Cited by 4 | Viewed by 1971

Abstract

Cenozoic extension rates were calculated based on 20 seismic profiles across the Qiongdongnan Basin, South China Sea. The results confirmed that the Cenozoic rifting in the Qiongdongnan Basin exhibited multistage extension and spatiotemporal variation. In terms of the N–S striking seismic profiles, the structural forms of the northern and southern sags of the basin were characterized by narrow half grabens, while the structure at the center sag of the basin was characterized by wide and gentle grabens. The fault strikes in the west of the basin were mainly northeast–southwest trending, whereas those in the east of the basin changed from northeast–southwest trending to nearly east–west trending. The extension rate in the east sag was higher than that in the west area. The extension rate in the middle part was lower relative to the east and west sags. This was because the rifting was controlled by the distribution of the main boundary fault along the basin. Temporally, the Cenozoic extension could be divided into three periods: Eocene, Oligocene, and Miocene. The amount of stretching in the three extension stages was unevenly distributed in the entire basin. The maximum was mainly in the Oligocene Lingshui and Yacheng Formations. The Oligocene extension occurred in the entire basin, and the Eocene extension was limited to the Ledong and Changchang sags. Significant fault activity could be observed during the deposition period of the Yacheng and Lingshui Formations and could be attributed to strong extensional activity. The rifting tectonics controlled the distribution of source rocks and oil-generating window as well as hydrocarbon generation, reservoir formation, and accumulation. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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13 pages, 6483 KiB

Open AccessArticle

Research on Diagenetic Evolution and Hydrocarbon Accumulation Periods of Chang 8 Reservoir in Zhenjing Area of Ordos Basin

by Guilin Yang, Zhanli Ren and Kai Qi

Energies 2022, 15(10), 3846; https://doi.org/10.3390/en15103846 - 23 May 2022

Viewed by 1573

Abstract

The Mesozoic Chang 8 Section in the Zhenjing area is a typical low permeability-tight sand reservoir and is regarded as the most important set of paybeds in the study area. Guided by the principles of basic geological theory, the diagenetic evolution process and hydrocarbon accumulation periods of the Chang 8 reservoir in the study area were determined through various techniques. More specifically, core observation, scanning electron microscopy (SEM), X-ray diffraction (XRD), and vitrinite reflectance experiments were performed in combination with systematic studies on rock pyrolysis and the thermal evolutionary history of basins, the illite-dating method, and so on. The Chang 8 reservoir is dominated by feldspar lithic and lithic feldspar sandstones. Quartz, feldspar, and lithic fragments are the major clastic constituents. In clay minerals, the chlorite content is the highest, followed by illite/smectite formation and kaolinite, while the illite content is the lowest. The major diagenesis effect of the Chang 8 reservoir includes compaction, cementation, dissolution, metasomatism, and rupturing. The assumed diagenetic sequence is the following: mechanical composition → early sedimentation of chlorite clay mineral membrane → early cementation of sparry calcite → authigenic kaolinite precipitation → secondary production and amplification of quartz → dissolution of carbonate cement → dissolution of feldspar → late cementation of minerals such as ferrocalcite. Now, the study area is in Stage A in the middle diagenetic period. Through the inclusion of temperature measurements, in conjunction with illite dating and thermal evolutionary history analysis technology in basins, the Chang 8 reservoir of this study was determined as the phase-I continuous accumulation process and the reservoir formation epoch was 105~125 Ma, which was assigned to the Middle Early Cretaceous Epoch. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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17 pages, 32366 KiB

Open AccessArticle

Sedimentary Characteristics of Lacustrine Beach-Bars and Their Formation in the Paleogene Weixinan Sag of Beibuwan Basin, Northern South China Sea

by Jie He, Hua Wang, Tao Jiang, Entao Liu, Si Chen and Ping Jiang

Energies 2022, 15(9), 3391; https://doi.org/10.3390/en15093391 - 6 May 2022

Cited by 2 | Viewed by 2639

Abstract

Beach-bar reservoirs have been promising hydrocarbon-bearing exploration advances in the Beibuwan Basin, especially in the WZ12-2 area within the Weixinan sag. The sedimentary characteristics, distribution and formation mechanisms of beach-bar sand bodies in Mbr2 (Member 2) of the Paleogene Liushagang Fm. in the WZ12-2 area within the Weixinan sag were analyzed based on well-log, seismic and core data on thin section and heavy mineral data. Mbr2 in the WZ12-2 area comprises a third-order sequence, which consists of three systems tracts (lowstand systems tract, transgressive systems tract and a locally developed highstand systems tract). Thick beach-bar sand bodies are developed in the WZ12-2 area during the lowstand systems tract stage. The formation of sandy beach-bar sand bodies can be divided into five stages. By integrating lithology, mineral composition, sedimentary structures and geophysical characteristics, it can be concluded that the beach-bar sand bodies in the study area were controlled by paleotopography, hydrodynamic environment, sediment provenance and lake-level variation. The gentle slope of the Qixi uplift and relatively stable passive tectonic background during the deposition of Mbr2 of the Liushagang Fm. laid a solid paleogeomorphological foundation for beach-bar deposition. Strong hydrodynamic forces and shallow water further contributed to beach-bar sand bodies formation. In addition, the sands in the fan delta in the northwestern part of the area served as point provenance and the deposits in the southeast acted as linear provenance in providing sediments to the beach-bars. High-frequency variations of the lake level drove vertical stacking of the beach-bar sand bodies and considerable lateral extension over a large area. The sedimentary characteristics and formation mechanism of lacustrine beach-bars in this study may provide a reference for hydrocarbon exploration in other similar basins in the world. Full article

(This article belongs to the Special Issue Natural Gas Hydrate and Deep-Water Hydrocarbon Exploration)

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