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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 (31 May 2022) | Viewed by 27741

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Special Issue Editors

Prof. Dr. Shu Tao

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Department of Energy and Environment, School of Energy Resources, China University of Geosciences, Beijing, Beijing 100083, China
Interests: exploration and development of unconventional oil and gas resources such as coalbed methane, shale gas, shale oil, oil shale, and tight sandstone gas
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Prof. Dr. Dengfeng Zhang

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Faculty of Chemical Engineering, Kunming University of Science and Technology, Kunming 650500, China
Interests: unconventional natural oil and gas exploration and production, carbon dioxide geologic sequestration

Dr. Huazhou Huang

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School of Resources and Geosciences, China University of Mining and Technology, Xuzhou 221116, China
Interests: coalbed methane reservoir characterization; coproduced water with coalbed methane; coalbed methane drainage; abandoned coal mine gas extraction; gob gas extraction in coal mining area
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Dr. Shuoliang Wang

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School of Energy Resources, China University of Geosciences (Beijing), Beijing 100083, China
Interests: unconventional natural oil and gas exploration and production; carbon dioxide geologic sequestration; enhanced oil recovery; ultra low velocity ercolation; vertical equilibrium; relative permeability
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Dr. Yanjun Meng

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College of Mining Engineering, Taiyuan University of Technology, Taiyuan 030024, China
Interests: coalbed methane reservoir engineering; fracturing fluid; reservoir damage
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

With the massive consumption of conventional energy sources, unconventional oil and gas exploration and development are rapidly emerging. In the past decade, the role and position of unconventional oil and gas in global oil and gas production has been continuously strengthened. Following the effective large-scale development of resources such as oil sands, tight gas, and coalbed methane, the "unconventional oil and gas revolution" in the United States has achieved rapid growth in shale oil and gas and tight oil and gas production in recent years, pushing the development of unconventional oil and gas into a new stage. The rapid development of unconventional oil and gas exploration and development has revealed a large amount of new data and new information on geology and engineering, including reservoir characterization, accumulation geology, favorable area evaluation, fracturing technology, development trends, etc. The aim of this Special Issue is to introduce the latest progresses in unconventional oil and gas geology and engineering.

This Special Issue focuses on the latest progresses in unconventional oil and gas exploration and development, including reservoir characterization, accumulation geology, favorable area evaluation, fracturing technology, development trends, etc. in fields such as coalbed methane, shale gas, shale oil, natural gas hydrate, tight sandstone gas, etc.

Prof. Dr. Shu Tao
Prof. Dr. Dengfeng Zhang
Dr. Huazhou Huang
Dr. Shuoliang Wang
Dr. Yanjun Meng
Guest Editors

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Keywords

unconventional oil and gas
reservoir description
geology and engineering
dynamic evaluation

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Research

15 pages, 2586 KiB

Open AccessArticle

Experimental Investigation of Pore Characteristics and Permeability in Coal-Measure Sandstones in Jixi Basin, China

by Huazhou Huang, Yuantao Sun, Xiantong Chang, Zhengqing Wu, Mi Li and Shulei Qu

Energies 2022, 15(16), 5898; https://doi.org/10.3390/en15165898 - 14 Aug 2022

Cited by 8 | Viewed by 1758

Abstract

The research of pore and permeability characteristics of tight sandstone reservoirs in coal-measure is critical for coal-measure gas development. In this study, the pore systems of tight sandstones were studied based on low-field nuclear magnetic resonance (LF-NMR) data. The permeability of tight sandstones was obtained by the tester based on the pulse transient method. The permeability variation with the effective stress, grains, and pore characteristics was analyzed. The results show that the tight sandstone reservoirs in the coal-measure have low total porosity (2.80–4.14%), low effective porosity (0.51–1.56%), and low permeability (0.351 × 10⁻⁶–13.910 × 10⁻⁶ um²). LF-NMR T₂ spectra of the testing sandstones show that the micropores are the most developed, but most of the micropores are immovable pores. The pore characteristics are significantly affected by the grain size of sandstones. The pore connectivity ranks from good to poor with decreasing sandstone particle size. The total porosity and effective porosity increase with the grain size. There is a near-linear negative relationship between permeability and effective stress when the effective stress is between 405 psi and 808 psi. The greater the number of movable pores and the larger the effective porosity, the bigger the permeability of the sandstone. The effective porosity of sandstones is a sensitive indicator for evaluating the permeability of tight sandstone reservoirs. The stress sensitivity coefficient of permeability (S_s) increases with the increase of the effective stress. The sandstone with lower permeability, smaller effective porosity, and finer grains has a higher S_s. The particle size of sandstone from coal-measure has a great influence on both permeability and S_s. The findings will provide a better understanding of the characterization of pore structure and permeability in the process the coal-measure gas extraction, which is useful for the efficient development of coal-measure gas. Full article

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

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16 pages, 3602 KiB

Open AccessArticle

Multiple-Level Tectonic Control of Coalbed Methane Occurrence in the Huaibei Coalfield of Anhui Province, China

by Zhigen Zhao and Sheng Xue

Energies 2022, 15(14), 4977; https://doi.org/10.3390/en15144977 - 7 Jul 2022

Cited by 4 | Viewed by 1692

Abstract

The Huaibei coalfield is an important coal base and one of the hot spots of coalbed methane development in China. Therefore, a detailed understanding of gas occurrence in the Huaibei coalfield is of great significance. This paper analyzes the gas occurrence from the perspective of multiple-level tectonic control, i.e., the regional tectonic level, the coalfield tectonic level, the mining area tectonic level, and the coal mine tectonic level. This study deduces that gas occurrence in the Huaibei coalfield is characterized by multiple-level tectonic control. At the regional level, the Huaibei coalfield is located in the southeast margin of the North China plate, affected by the tectonic evolution of the North China plate and by the evolution of the Dabie–Tanlu–Sulu orogenic belt. Therefore, the regional geological tectonic is complex, leading to the high gas content and serious gas hazard. At the coalfield level, gas occurrence in the Huaibei coalfield is controlled by east–west faults, NNE faults, and the Xuzhou–Suzhou arc nappe tectonic, which results in the highest gas occurrence in the Suxian mining area, followed by the Linhuan mining area and the Suixiao mining area, while the lowest amount of gas occurs in the Guoyang mining area. At the mining area level, considering the Suxian mining area as an example, the gas occurrence is controlled by the distance from the Tancheng–Lujiang fault zone and the intensity of tectonic compression, i.e., coal mine gas in the east is the highest, followed by coal mines in the south, while coal mine gas in the west is the lowest. At the coal mine level, gas occurrence is controlled by the buried depth of the coal seam, the tensional normal fault, magmatic activity, and uplift and erosion of strata. Finally, the findings of this study may help in the prevention of gas hazard and the exploration and development of coalbed methane in the Huaibei coalfield and other coalfields of similar geological characteristics. Full article

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

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15 pages, 2950 KiB

Open AccessArticle

A Study on the Adaptability of Nonhydrocarbon Gas-Assisted Steam Flooding to the Development of Heavy Oil Reservoirs

by Yong Huang, Wulin Xiao, Sen Chen, Boliang Li, Liping Du and Binfei Li

Energies 2022, 15(13), 4805; https://doi.org/10.3390/en15134805 - 30 Jun 2022

Cited by 6 | Viewed by 1779

Abstract

In view of the serious heat loss in the process of steam injection for heavy oil recovery, nonhydrocarbon gas combined with steam has attracted much attention in recent years to realize the efficient development of heavy oil. Due to the wide variety of nonhydrocarbon gases, their performance in pressurization, dissolution, viscosity reduction, and heat loss decrease is changeable. In this paper, four groups of one-dimensional physical simulation experiments on different nonhydrocarbon gas-assisted steam flooding methods were carried out, and the effect on oil displacement characteristics under high temperature and pressure conditions was studied. Moreover, the differences in N₂, CO₂, and flue gas in energy supplementation, heat transfer, and oil recovery efficiency were also analyzed. The results showed that the three nonhydrocarbon gas-assisted steam flooding methods could significantly improve the oil displacement efficiency, which was specifically embodied as a faster oil production rate and longer production period. Compared with pure steam flooding, the recovery was increased by 12.13%, 16.71% and 13.01%, respectively. The effects of N₂ in energy supplementation and heat transfer reinforcement were the greatest among the three nonhydrocarbon gases, followed by those of flue gas, and the CO₂ effects were the worst. The temperature at the end of the sandpack model increased by 14.3 °C, 8.8 °C and 13.1 °C, respectively. In addition, CO₂-assisted steam flooding had a prominent oil recovery effect, and the oil content of the sands in the front and middle of the model was significantly lower than that of other displacement methods. Most importantly, combined with the analysis of the remaining oil in the oil sands after displacement, we explained the contrasting contradictions of the three non-hydrocarbon gases in terms of recovery and energy supply/heat transfer, and further confirmed the gas properties and reservoir adaptability of the three non-hydrocarbon gases. The results may provide a theoretical basis for the selection of nonhydrocarbon gases for heavy oil reservoirs with different production requirements. Full article

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

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21 pages, 87626 KiB

Open AccessArticle

Heat Control Effect of Phase Change Microcapsules upon Cement Slurry Applied to Hydrate-Bearing Sediment

by Guokun Yang, Tianle Liu, Hai Zhu, Zihan Zhang, Yingtao Feng, Ekaterina Leusheva and Valentin Morenov

Energies 2022, 15(12), 4197; https://doi.org/10.3390/en15124197 - 7 Jun 2022

Cited by 9 | Viewed by 2479

Abstract

This study aims to develop a novel low-heat cement slurry using phase change microcapsule additives to reduce the decomposition of hydrate-bearing sediments during cementing. Microcapsules were prepared by coating mixed alkanes with polymethyl methacrylate, and lipophilic-modified graphite was incorporated to enhance the thermal conductivity of microcapsules. The effects of microcapsules upon the hydration heat, pore distribution, and compressive strength of the cement slurry/stone were studied through a variety of tests. The results showed that the phase-change temperature, thermal enthalpy, and encapsulation efficiency of the microcapsules were 8.99–16.74 °C, 153.58 Jg⁻¹, and 47.2%, respectively. The introduction of lipophilic-modified graphite reduced the initial phase-change temperature of microcapsules by 0.49 °C, indicating an improvement in their temperature sensitivity. The maximum hydration heat of cement slurry decreased by 41.3% with 7% dosage of microcapsules; the proposed microcapsules outperformed comparable low-heat additives. Moreover, the presence of microcapsules could reduce the number of large pores in (and thereby improve the compressive strength of) cement stone. The innovation of this study is that it comprehensively and intuitively confirms the feasibility of the application of low-heat cement slurry with MPCM as the key in hydrate sediments rather than just focusing on the reduction of hydration heat; furthermore, a self-made cementing device was developed to simulate the cementing process of hydrate deposition. The results show that the thermal regulation of microcapsules inhibited the temperature increase rate of the cement slurry, significantly reducing the damage caused to the hydrate. These findings should improve the safety and quality of cement in offshore oil and gas well applications. Full article

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

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16 pages, 5280 KiB

Open AccessArticle

A New Relative Permeability Characterization Method Considering High Waterflooding Pore Volume

by Guangfeng Qi, Jingang Zhao, Hu He, Encheng Sun, Xin Yuan and Shuoliang Wang

Energies 2022, 15(11), 3868; https://doi.org/10.3390/en15113868 - 24 May 2022

Cited by 3 | Viewed by 1524

Abstract

In the process of waterflooding development, high waterflooding PVs will make the fluid percolation in the reservoir more complicated, resulting in lower efficiency of waterflooding. High waterflooding PVs will affect the relative permeability and change the seepage law of oil–water two-phase flow in a high water-cut period. In this study, we performed high waterflooding PVs relative permeability experiments using nine natural cores. The unsteady measurement method is used to test the relative permeability curve. The results show that: (1) the relative permeability is affected by the waterflooding PVs, the recovery efficiency of 2000 waterflooding PVs is 10.72% higher than that of 50 waterflooding PVs on the core scale; (2) it makes water mobility increase sharply, while oil phase flow capacity remains low and decreases at high water cut stage. A new relative permeability characterization method considering high waterflooding PVs is established, which is applied to the numerical simulator. It shows that the remaining oil saturation of the high-permeability belt is higher than the calculation results of the traditional numerical simulator. It means that the injected water does not diffuse much into the low-permeability zone of the formation. The modified simulator is validated with the actual China offshore oilfield model. The numerical saturation of the key section of the passing well is in good agreement with the actual logging interpretation results, and the water cut curve fits better in the whole area. The modified simulator could predict oil production accurately after high waterflooding PVs treatment. Full article

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

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17 pages, 4716 KiB

Open AccessArticle

Pressure Relief Mechanism and Gas Extraction Method during the Mining of the Steep and Extra-Thick Coal Seam: A Case Study in the Yaojie No. 3 Coal Mine

by Hao Zhang, Lehua Xu, Mengmeng Yang, Cunbao Deng and Yuanping Cheng

Energies 2022, 15(10), 3792; https://doi.org/10.3390/en15103792 - 21 May 2022

Cited by 8 | Viewed by 2178

Abstract

Gas disasters, such as coal and gas outburst and gas overflow, always occur during the mining of the steep and extra-thick coal seam in the horizontal, fully mechanized, top coal slice caving (HFMTCSC) method. To solve these issues and guarantee the safe and efficient mining in the Yaojie No. 3 coal mine, 3DEC software was used in this work to investigate the overburden movement and collapse law as well as the stress redistribution and coal-seam deformation characteristics below the goaf. The results show that a pressure arch structure and a hinge structure are formed in succession in the overburden rock, which induces stress redistribution in the coal below the goaf. During the mining of the upper slice, more than 75% of the coal in the lower slice is located at the effective pressure relief zone; therefore, the steep and extra-thick coal seam can then be protected slice by slice. Meanwhile, with the increase of mining depth, the efficient pressure relief range expands. Based on this pressure relief mechanism, crossing boreholes and bedding boreholes were reasonably designed to efficiently extract the pressure relief gas during the mining of the steep and extra-thick coal seam in the Yaojie No. 3 coal mine. Full article

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

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19 pages, 8408 KiB

Open AccessArticle

Biogenic Methane Accumulation and Production in the Jurassic Low-Rank Coal, Southwestern Ordos Basin

by Chao Zheng, Dongmin Ma, Yue Chen, Yucheng Xia, Zheng Gao, Guofu Li and Weibo Li

Energies 2022, 15(9), 3255; https://doi.org/10.3390/en15093255 - 29 Apr 2022

Cited by 3 | Viewed by 2032 | Correction

Abstract

Geological conditions are the key for coalbed methane (CBM) accumulation and production. However, the geological feature of CBM accumulation and production in the Jurassic of Ordos Basin lacks systematic and detailed evaluation, resulting in poor CBM production in this area. This study has determined the genetic types of gas according to geochemistry characteristics of the gas, the geological factors to control CBM accumulation and production performance were revealed, and a comprehensive method was established to evaluate favorable areas based on 32 sets of CBM well production data from Jurassic Yan’an Formation. The results show the coal macerals are rich in inertinite (41.13~91.12%), and the maximum reflectance of vitrinite (R_o,max) in coal is 0.56~0.65%. According to gas compositions and carbon isotopes analysis, the δ¹³C(CH₄) is less than −55‰, and the content of heavy hydrocarbon is less than 0.05%. The value of C₁/(C₂ + C₃) is 6800~98,000, that is, the CBM is a typical biogenic gas of low-rank coal. The CBM accumulation model is the secondary biogenic on the gentle slope of the basin margin, in which gas content is closely related to buried depth and hydrodynamic environment, i.e., the high gas content areas are mainly located in the groundwater weak runoff zone at the burial depth of 450 m~650 m, especially in the syncline. Meanwhile, gas production mainly depends on the location of the structure. The high gas production areas of vertical wells were distributed on the gentle slope with high gas content between anticline and syncline, and the horizontal wells with good performance were located near the core of the syncline. According to the above analysis combined with the random forest model, the study area was divided into different production favorable areas, which will provide a scientific basis for the CBM production wells. Full article

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

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17 pages, 6166 KiB

Open AccessArticle

Characteristics and Origins of the Difference between the Middle and High Rank Coal in Guizhou and Their Implication for the CBM Exploration and Development Strategy: A Case Study from Dahebian and Dafang Block

by Fuping Zhao, Shuxun Sang, Sijie Han, Zhangli Wu, Jinchao Zhang, Wenxin Xiang and Ang Xu

Energies 2022, 15(9), 3181; https://doi.org/10.3390/en15093181 - 27 Apr 2022

Cited by 7 | Viewed by 2031

Abstract

The coalbed methane (CBM) geology in Guizhou is characterized by a high gas content, pressure and resource abundance, indicating superior CBM resource potential. However, there are also many unfavorable factors, such as complex structure geology, significant regional differences in CBM geology, the widespread development of tectonically deformed coal, and the unclear understanding of the configuration of geological factors for CBM enrichment and high yield, which restrict the increase in CBM production and a large-scale development. Taking the Dahebian Block in Liupanshui coal field and the Dafang Block in Qianbei coal field as examples, this study presented the CBM geological differences between middle- and high-rank coals; their origins were analyzed and the effect of depth on gas content and permeability was discussed. A CBM enrichment and high-yield model was illustrated, and the geologic fitness-related exploration and development methods for Guizhou CBM were finally proposed. The results show that (1) significant differences between the middle- and high-rank coals occur in coal occurrence and distribution, coal qualities, and coal reservoir properties. Compared to Dahebian coal, Dafang coal has a higher coal rank, vitrinite content, and gas content, but a lower number of coal layers and permeability. (2) The sedimentary–tectonic evolution of the Longtan coal-bearing sequence is the fundamental reason for CBM geological differences between the Dadebian Block and Dafang Block, consisting of coal occurrence, qualities, maceral, rank, structure, and their associated reservoir properties. (3) The coordinated variation of gas content and permeability contributes to a greater depth for CBM enrichment and a high yield of the middle-rank coal. It is suggested that the best depths for CBM enrichment and high yield in Guizhou are 600–800 m for the middle-rank coal and 500 m for the high-rank coal, respectively. (4) Considering the bottleneck of inefficient CBM development in Guizhou, we proposed three CBM assessment and development technologies, including the CBM optimization of the classification–hierarchical optimization–analytical hierarchy, multiple coal seams commingling production with the pressure relief of tectonically deformed coal, and surface–underground CBM three-dimensional drainage development. The aim of this study was to provide new insights into the efficient exploration and development of CBM in Guizhou. Full article

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

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19 pages, 5742 KiB

Open AccessArticle

Geochemical Characteristics and Process of Hydrocarbon Generation Evolution of the Lucaogou Formation Shale, Jimsar Depression, Junggar Basin

by Wenjun He, Yin Liu, Dongxue Wang, Dewen Lei, Guangdi Liu, Gang Gao, Liliang Huang and Yanping Qi

Energies 2022, 15(7), 2331; https://doi.org/10.3390/en15072331 - 23 Mar 2022

Cited by 6 | Viewed by 2231

Abstract

Lacustrine shale, represented by the Middle Permian Lucaogou Formation in the Jimsar Depression in the eastern Junggar Basin, has become one of the main areas of shale oil exploration in China. In this study, we used 137 samples of shale from the Lucaogou Formation, drawn from 14 wells in the Jimsar Depression, to investigate their characteristics of pyrolysis, organic carbon and soluble organic matter content, biomarkers, organic microscopic composition, and vitrinite reflectance. Basin simulation and hydrocarbon generation thermal simulation experiments were also conducted in a closed system. The results of this study indicate that the input of an algae source was dominant in the source rocks of the Lucaogou Formation, that the water in which the rocks were deposited had high salinity and strong reducibility, and that the source rocks were oil-prone. The Lucaogou source rocks generally had good hydrocarbon generation capability, but showed significant heterogeneity. At the end of the Cretaceous period, the shales in the Lucaogou Formation entered the oil-generation window as a whole. Currently, the shales of the Lucaogou Formation are generally in the high-maturity stage in the deep part of the depression, producing a large amount of high-maturity oil and condensate gas, while those in the shallow part have relatively low maturity and can only produce a large amount of conventional crude oil. The maximum crude oil generation rate of the Lucaogou Formation shale obtained from the thermal simulation results was 220.2 mg/g of the total organic carbon (TOC), and the maximum hydrocarbon expulsion efficiency was estimated to be 59.3–76.4%. Full article

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

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29 pages, 5581 KiB

Open AccessArticle

Performance Evaluation of Multistage Fractured Horizontal Wells in Tight Gas Reservoirs at Block M, Ordos Basin

by Li Wu, Jiqun Zhang, Deli Jia, Shuoliang Wang and Yiqun Yan

Energies 2022, 15(2), 613; https://doi.org/10.3390/en15020613 - 16 Jan 2022

Cited by 3 | Viewed by 3161

Abstract

Block M of the Ordos Basin is a typical low-permeability tight sandstone gas accumulation. To develop these reservoirs, various horizontal well fracturing technologies, such as hydra-jet fracturing, open-hole packer multistage fracturing, and perf-and-plug multistage fracturing, have been implemented in practice, showing greatly varying performance. In this paper, six fracturing technologies adopted in Block M are reviewed in terms of principle, applicability, advantages, and disadvantages, and their field application effects are compared from the technical and economic perspectives. Furthermore, the main factors affecting the productivity of fractured horizontal wells are determined using the entropy method, the causes for the difference in application effects of the fracturing technologies are analyzed, and a comprehensive productivity impact index (CPII) in good correlation with the single-well production of fractured horizontal wells is constructed. This article provides a simple and applicable method for predicting the performance of multi-frac horizontal wells that takes multiple factors into account. The results can be used to select completion methods and optimize fracturing parameters in similar reservoirs. Full article

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

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16 pages, 3373 KiB

Open AccessArticle

Investigation of Flowback Behaviours in Hydraulically Fractured Shale Gas Well Based on Physical Driven Method

by Wei Guo, Xiaowei Zhang, Lixia Kang, Jinliang Gao and Yuyang Liu

Energies 2022, 15(1), 325; https://doi.org/10.3390/en15010325 - 4 Jan 2022

Cited by 6 | Viewed by 2133

Abstract

Due to the complex microscope pore structure of shale, large-scale hydraulic fracturing is required to achieve effective development, resulting in a very complicated fracturing fluid flowback characteristics. The flowback volume is time-dependent, whereas other relevant parameters, such as the permeability, porosity, and fracture half-length, are static. Thus, it is very difficult to build an end-to-end model to predict the time-dependent flowback curves using static parameters from a machine learning perspective. In order to simplify the time-dependent flowback curve into simple parameters and serve as the target parameter of big data analysis and flowback influencing factor analysis, this paper abstracted the flowback curve into two characteristic parameters, the daily flowback volume coefficient and the flowback decreasing coefficient, based on the analytical solution of the seepage equation of multistage fractured horizontal Wells. Taking the dynamic flowback data of 214 shale gas horizontal wells in Weiyuan shale gas block as a study case, the characteristic parameters of the flowback curves were obtained by exponential curve fittings. The analysis results showed that there is a positive correlation between the characteristic parameters which present the characteristics of right-skewed distribution. The calculation formula of the characteristic flowback coefficient representing the flowback potential was established. The correlations between characteristic flowback coefficient and geological and engineering parameters of 214 horizontal wells were studied by spearman correlation coefficient analysis method. The results showed that the characteristic flowback coefficient has a negative correlation with the thickness × drilling length of the high-quality reservoir, the fracturing stage interval, the number of fracturing stages, and the brittle minerals content. Through the method established in this paper, the shale gas flowback curve containing complex flow mechanism can be abstracted into simple characteristic parameters and characteristic coefficients, and the relationship between static data and dynamic data is established, which can help to establish a machine learning method for predicting the flowback curve of shale gas horizontal wells. Full article

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

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17 pages, 6150 KiB

Open AccessArticle

Genesis of Coalbed Methane and Its Storage and Seepage Space in Baode Block, Eastern Ordos Basin

by Hao Chen, Wenguang Tian, Zhenhong Chen, Qingfeng Zhang and Shu Tao

Energies 2022, 15(1), 81; https://doi.org/10.3390/en15010081 - 23 Dec 2021

Cited by 13 | Viewed by 2817

Abstract

The Baode block on the eastern margin of the Ordos Basin is a key area for the development of low-rank coalbed methane (CBM) in China. In order to find out the genesis of CBM and its storage and seepage space in Baode block, the isotopic testing of gas samples was carried out to reveal the origin of CH₄ and CO₂, as well, mercury intrusion porosimetry, low temperature nitrogen adsorption, and X-ray CT tests were performed to characterize the pores and fractures in No. 4 + 5 and No. 8 + 9 coal seams. The results showed that the average volume fraction of CH₄, N₂, and CO₂ is 88.31%, 4.73%, and 6.36%, respectively. No. 4 + 5 and No. 8 + 9 coal seams both have biogenic gas and thermogenic methane. Meanwhile, No. 4 + 5 and No. 8 + 9 coal seams both contain CO₂ generated by coal pyrolysis, which belongs to organic genetic gas, while shallow CO₂ is greatly affected by the action of microorganisms and belongs to biogenic gas. The average proportion of micropores, transition pores, mesopores, and macropores is 56.61%, 28.22%, 5.10%, and 10.07%, respectively. Samples collected from No. 4 + 5 coal seams have developed more sorption pores. Meanwhile, samples collected from No. 8 + 9 coal seams exhibited a relatively low degree of hysteresis (Hg retention), suggesting good pore connectivity and relatively high seepage ability, which is conducive to gas migration. The connected porosity of coal samples varies greatly, mainly depending on the relative mineral content and the proportion of connected pores. Full article

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

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