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20 pages, 27908 KiB

Open AccessArticle

Sedimentary Facies Types and Their Control of Reservoirs in the Lower Jurassic Lacustrine Facies Shale of the Lianggaoshan Formation, Northeastern Sichuan Basin, China

by Chao Ni, Xueju Lv, Xinjian Zhu, Jianyong Zhang, Jiahao Wang, Mingyang Wang and Ruibin Xu

Processes 2023, 11(8), 2463; https://doi.org/10.3390/pr11082463 - 16 Aug 2023

Cited by 1 | Viewed by 1540

Abstract

In recent years, new breakthroughs have been made in the field of shale oil and gas exploration in the Lower Jurassic Lianggaoshan Formation in Sichuan Basin. At present, there is a lack of systematic studies on reservoir properties and sedimentary facies of the [...] Read more.

In recent years, new breakthroughs have been made in the field of shale oil and gas exploration in the Lower Jurassic Lianggaoshan Formation in Sichuan Basin. At present, there is a lack of systematic studies on reservoir properties and sedimentary facies of the Lianggaoshan Formation shale. Therefore, in this study, taking the Lianggaoshan Formation in Sichuan Basin as an example, the sedimentary facies types of shale reservoirs and their control over shale oil and gas are systematically studied, based on a large number of outcrops, experimental testing, logging, and seismic interpretation methods. The results show that five sedimentary microfacies are developed in the Lianggaoshan Formation in the study area, namely, semi-deep lake mud, shallow lake mud, wave-influenced shallow lake mud, delta-influenced shallow lake mud, and underwater interbranch bay microfacies. The stratum thickness of the Lianggaoshan Formation is in the range of 26–315 m, and mainly distributed in the eastern region, but rapidly thinned in the northwestern region. The sedimentary sequence framework of the Lianggaoshan Formation has been constructed. Moreover, the lithology of the Lianggaoshan Formation shale has been divided into three types, including shale, massive mudstone and silty mudstone. The brittleness index and total organic carbon (TOC) value of three types of shale show a negative correlation. Silty mudstone has the highest brittleness, while that of black shale is the lowest. For porosity and permeability, massive mudstone is better than silty mudstone, and silty mudstone is better than black shale. There are many kinds of matrix pores in the Lianggaoshan Formation shale, and the development degree of inorganic pores is higher than that of organic pores. Finally, based on the analysis of oil-bearing, pore types, physical properties and productivity, it is considered that black shale facies is the most favorable lithofacies type. The deep–semi-deep lacustrine facies belt obviously controls the shale oil enrichment of the Lianggaoshan Formation. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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17 pages, 4970 KiB

Open AccessArticle

“Tri-in-One” Accumulation Model of Lithologic Reservoirs in Continental Downfaulted Basins: A Case Study of the Lithologic Reservoir of Nantun Formation in Tanan Sag, Mongolia

by Shaojun Liu, Shengxian Zhao, Xuefeng Yang, Jian Zhang, Meixuan Yin, Qi’an Meng, Bo Li and Ziqiang Xia

Processes 2023, 11(8), 2352; https://doi.org/10.3390/pr11082352 - 4 Aug 2023

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Abstract

This article analyzes the key controlling factors and hydrocarbon distribution rules of lithologic reservoirs in a continental downfaulted basin according to the structural features, sedimentary evolution, types of sedimentary facies, source rock features, diagenesis evolution, reservoir features, hydrocarbon formation mechanisms, exploration status, and [...] Read more.

This article analyzes the key controlling factors and hydrocarbon distribution rules of lithologic reservoirs in a continental downfaulted basin according to the structural features, sedimentary evolution, types of sedimentary facies, source rock features, diagenesis evolution, reservoir features, hydrocarbon formation mechanisms, exploration status, and hydrocarbon resource potential. The results show that three major controlling factors (sandbody types, effective source rocks, and effective reservoirs) and one coupled factor (fractures that act as a tie) influence hydrocarbon accumulation in the lithologic traps in the Nantun Formation in Tanan Sag. With the increase in depth, sufficient hydrocarbon is generated in the source rock with thermal evolution. When the depth threshold is reached and critical conditions of hydrocarbon supply are met, hydrocarbon generation and expulsion are more intensive. Traps that are surrounded or contacted by source rock or connected by faults are able to form reservoirs. As the buried depth increases, the intensity of hydrocarbon generation–expulsion grows, and the trap is more petroliferous. Hydrocarbon accumulation and reservoir formation are also controlled by sandbody accumulation conditions. When the critical conditions for hydrocarbon generation are met and concrete oil and gas are charged in, the better physical properties of the sandbody will always indicate more hydrocarbon accumulation in the trap. The allocation of sand type, effective source rock, and an effective reservoir is optimized under the effect of fractures and the coupled hydrocarbon reservoir with these three elements. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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14 pages, 4016 KiB

Open AccessArticle

Quantitative Characteristics of Micro Bedding Fractures in the Wufeng–Longmaxi Formation Based on High-Resolution Map Imaging Technology

by Conghui Zhao, Dong Wu, Fengbo Hu, Meng Sun, Tao Li and Hu Wang

Processes 2023, 11(7), 1942; https://doi.org/10.3390/pr11071942 - 27 Jun 2023

Viewed by 1194

Abstract

The study of microfractures in shale is mainly based on qualitative description. Conversely, quantitative description of the parameters of shale microfractures can provide a quantitative basis for shale fracture characterization and shale physical properties. Nine shale reservoir samples of the Wufeng–Longmaxi Formation in [...] Read more.

The study of microfractures in shale is mainly based on qualitative description. Conversely, quantitative description of the parameters of shale microfractures can provide a quantitative basis for shale fracture characterization and shale physical properties. Nine shale reservoir samples of the Wufeng–Longmaxi Formation in the Jiaoshiba area were studied, using the backscattered two-dimensional multiscale resolution imaging technology, combined with high-resolution map imaging technology (MAPS), and thousands of images were obtained using scanning electron microscopy. Gray image analysis was used to extract microfracture information from images (2 × 2 cm multiresolution). The “maximum circle method” was used to calculate the length and aperture characteristics of the fractures. Parameters such as the area of the bedding fractures, the surface rate of the fractures, and the linear density of the fractures were obtained by the integration of apertures. The fracture length was between 2~7 mm, the aperture was between 1~6 μm, the linear density was between 1~6/m and the surface rate was 1%. The bedding fractures do not contribute much to the porosity of the shale reservoir; however, shale reservoirs with high porosity have a high development of bedding fractures and good permeability. The development of a bedding fracture is controlled by the lithology within shale reservoirs. Different types of lithology contain different bedding fractures, but they have a certain regularity. Moreover, the content of organic matter and TOC (total organic content) in the shale reservoir control the development of a bedding fracture, where a high organic and TOC content are accompanied by a high number of fractures. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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15 pages, 4668 KiB

Open AccessArticle

Estimation of Shale Gas Reserves: A Modified Material Balance Equation and Numerical Simulation Study

by Reda Abdel Azim, Saad Alatefi and Ahmad Alkouh

Processes 2023, 11(6), 1746; https://doi.org/10.3390/pr11061746 - 7 Jun 2023

Cited by 1 | Viewed by 1613

Abstract

This study presents a comprehensive material balance equation (MBE) to estimate the reserve of shale gas reservoirs including free and adsorbed gas volume. The presented material balance equation takes into account the effect of stress change, matrix shrinkage, water volume production and influx, [...] Read more.

This study presents a comprehensive material balance equation (MBE) to estimate the reserve of shale gas reservoirs including free and adsorbed gas volume. The presented material balance equation takes into account the effect of stress change, matrix shrinkage, water volume production and influx, and critical desorption pressure. The material balance equation is converted into a linear relationship between the reservoir production and expansion parameters used during the derivation procedures that include rock-fluid properties and production history data. The proposed straight line reserve evaluation technique yields a slope of original free and absorbed gas in organic matrix, while the y-intercept yields the volume of original free gas in the in-organic matrix. A field case study of shale gas located in Australia is presented. Results show that the proposed MBE and the corresponding straight line reserve evaluation technique are rational and competent in estimating the free gas and adsorbed gas volumes accurately with error less than 6% compared to the numerical simulation model presented in this study using an in-house simulator based on finite element technique and FORTRAN language. Hence, the presented technique in this study can be used as a quick and easy to use tool to accurately estimate the free and adsorbed gas reserves and to improve the development of the production strategies of shale gas reservoirs. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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18 pages, 52758 KiB

Open AccessArticle

Pore Distribution Characteristics of Different Lithofacies Shales: Evidence from Scanning Electron Microscopy

by Junjie Wang, Shuangfang Lu, Pengfei Zhang, Qi Zhi and Hongsheng Huang

Processes 2023, 11(4), 1120; https://doi.org/10.3390/pr11041120 - 5 Apr 2023

Cited by 2 | Viewed by 1858

Abstract

To disclose the pore distribution characteristics of different lithofacies lacustrine shales, ten samples collected from the Shahejie Formation, Dongying Sag, Bohai Bay Basin, China, were examined using argon ion beam milling–scanning electron microscopy (SEM). A quantitative method was adopted to characterize shale pore [...] Read more.

To disclose the pore distribution characteristics of different lithofacies lacustrine shales, ten samples collected from the Shahejie Formation, Dongying Sag, Bohai Bay Basin, China, were examined using argon ion beam milling–scanning electron microscopy (SEM). A quantitative method was adopted to characterize shale pore distributions based on the SEM images. Mercury intrusion capillary pressure was employed to determine the pore throat size distributions of the shales. The SEM images indicated that in shale reservoirs, interparticle pores at the edges of brittle particles and intraparticle pores in clay mineral aggregates primarily contribute to the reservoir spaces and that in calcite-rich shales, dissolution pores provide secondary reservoir space. Among the morphologies of dissolution, intraparticle, and interparticle pores, the morphology of the dissolution pores is the simplest, followed by those of intraparticle and interparticle pores in that order. Clay and felsic minerals primarily control the shale pore sizes and the larger the clay mineral content in the shales, the smaller their pore size; the felsic minerals demonstrate the opposite behavior. The image-based point counting data indicate that shale pore sizes are mostly between 20 nm and 2 μm. In contrast, most pore throats are less than 20 nm in diameter, implying that the pores in the nanometer to micrometer scales are connected by tiny throats. Among the four lithofacies shales, felsic-rich shales are favorable for shale oil accumulation and seepage because of their large pore sizes and throats their ability to form intercalated shale oil adjacent to organic-rich shales. Calcareous shales with a large number of dissolution pores and a large content of organic matter could produce self-generation and self-storage matrix shale oil and would typically develop fractures, thereby creating a seepage channel for shale oil. This study presents the micro-distributions of different lithofacies of shale pores, which would help in understanding the occurrence and seepage of oil in shale reservoirs. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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15 pages, 3044 KiB

Open AccessFeature PaperArticle

Quantum Physisorption of Gas in Nanoporous Media: A New Perspective

by Junqian Li

Processes 2023, 11(3), 758; https://doi.org/10.3390/pr11030758 - 4 Mar 2023

Cited by 7 | Viewed by 2110

Abstract

Although numerous investigations have revealed the gas physisorption characteristics of porous media, the essence of physisorption behavior of gas within nanoscale space is still indistinct. We speculated that the physisorption behavior of a complex molecular system (e.g., CH₄ and CO₂) [...] Read more.

Although numerous investigations have revealed the gas physisorption characteristics of porous media, the essence of physisorption behavior of gas within nanoscale space is still indistinct. We speculated that the physisorption behavior of a complex molecular system (e.g., CH₄ and CO₂) exhibits a quantum effect due to the confinement effect of nanopores. Gas molecules occur in varied orbitals following certain probabilities and, therefore, have separate energy levels inside a nanoscale space. Energy level transition of molecules from excited state to ground state triggers gas physisorption, while non-uniform spatial distribution of energy-quantized molecules within nanopores dominates the gas physisorption behavior. The spatial distribution of gas molecules can be adjusted by temperature, pressure and potential energy field. Based on the quantum effect, we developed a physisorption equation from the perspective of quantum mechanics to re-understand the basic principles of gas physisorption within nanopores. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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18 pages, 10038 KiB

Open AccessArticle

Characterization on Structure and Fractal of Shale Nanopore: A Case Study of Fengcheng Formation in Hashan Area, Junggar Basin, China

by Weizheng Gao, Xiangchun Chang, Pengfei Zhang, Zhongquan Liu, Zhiping Zeng, Yue Wang and Tianchen Ge

Processes 2023, 11(3), 677; https://doi.org/10.3390/pr11030677 - 23 Feb 2023

Cited by 2 | Viewed by 1669

Abstract

The Lower Permian Fengcheng Formation in Halaalate Mountain in the Junggar Basin has enormous potential for shale oil, while few investigations on quantifying pore structure heterogeneity have been conducted. Thus, total organic carbon (TOC), X-ray diffraction (XRD), scanning electron microscopy (SEM), and low-temperature [...] Read more.

The Lower Permian Fengcheng Formation in Halaalate Mountain in the Junggar Basin has enormous potential for shale oil, while few investigations on quantifying pore structure heterogeneity have been conducted. Thus, total organic carbon (TOC), X-ray diffraction (XRD), scanning electron microscopy (SEM), and low-temperature N₂ adsorption tests were conducted on the shales collected from the HSX1 well in the Hashan region to disclose the microscopic pore structure and its heterogeneity. Results show that the selected shales mainly consist of quartz, plagioclase, calcite, and clay minerals. The primary pore types are intergranular pores in quartz and carbonate and intragranular pores in clays, while organic matter (OM) pores are rare. Typical types of H2 and mixed H2-H3 were observed. Type H3 shale pore size distributions (PSD) are unimodal, with a peak at about 70 nm, while Type H2-H3 shales are bimodal, with peaks at about 70 nm and 3 nm, respectively. Type H3 shales have lower D₂ than Type H2-H3 shale, corresponding to weaker pore structure heterogeneity. Multifractal analyses indicate that macropores in Type H3 shales have stronger heterogeneity with large D₁₀−D₀ ranges, while minor D₋₁₀−D₀ ranges mean weaker heterogeneity of micro- and mesopores, and so do Types H2-H3 shales. The higher the contents of plagioclase and clay minerals, the more heterogeneous the micro- and mesopores are; a larger content of quartz leads to more heterogeneous macropores. Specific surface area, micro-, and mesopores contents positively correlate to D₂, while average pore diameter and macropores are on the contrary, thus the higher the content of micro- and mesopores and the specific surface area, the lower the content of macropores and average pore diameter, the more complex the microscopic pore structure of shale. Micro- and mesopores control the heterogeneity of shale pore development with a great correlation of D₋₁₀−D₀ and D₋₁₀−D₁₀, and D₂ can effectively characterize the heterogeneity of a high porosity area with a strong correlation of D₂ and D₀−D₁₀. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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16 pages, 5477 KiB

Open AccessArticle

Lithofacies Characteristics and Pore Controlling Factors of New Type of Permian Unconventional Reservoir in Sichuan Basin

by Rong Li, Zhifu Xiong, Zecheng Wang, Wuren Xie, Wenzheng Li and Jiuzhen Hu

Processes 2023, 11(2), 625; https://doi.org/10.3390/pr11020625 - 18 Feb 2023

Cited by 3 | Viewed by 2075

Abstract

Alongside volcanic eruptions in the middle and late Permian, the sedimentary environment and process changed, and the lithofacies characteristics varied conspicuously in the marine deposits of the Sichuan Basin (China). The tuffaceous rocks, as a new type of unconventional reservoir, provide strong evidence [...] Read more.

Alongside volcanic eruptions in the middle and late Permian, the sedimentary environment and process changed, and the lithofacies characteristics varied conspicuously in the marine deposits of the Sichuan Basin (China). The tuffaceous rocks, as a new type of unconventional reservoir, provide strong evidence for marine and volcanic influences on the lithology and reservoir potential of the rocks. With experimental studies relying on field outcrops, thin sections, scanning electron microscopy and whole-rock X-ray diffraction (XRD), the researchers analyzed the lithofacies characteristics, pore types and controlling factors on the various types of pores in the tuffaceous rocks. We identified three lithofacies types in this new type of Permian reservoir in the Sichuan Basin, namely tuff, sedimentary tuff, and tuffaceous mudstone. The mineral composition of the three lithofacies includes quartz, feldspar, carbonate minerals, pyrite, and clay, among which feldspar is mainly potassium feldspar. Tuff has high tuff content, and the lowest clay and TOC content; tuffaceous mudstones have the highest clay and TOC content, and the lowest tuff content. The pore types of the tuffaceous rocks are mainly nano-scale shrinkage pores, with a small number of intergranular pores including intragranular pores, intergranular pores, and organic pores. The shrinkage pores account for 81.9% of the total pores, and organic pores account for 11.2% of the total pores. In the tuffaceous rocks, the tuff content, quartz and feldspar content, and pyrite content are inversely correlated with porosity, while the clay content and TOC content are positively correlated with porosity. The porosity of tuff is the lowest, followed by sedimentary tuff, and the porosity of tuffaceous mudstone is the highest. Tuffaceous rocks form many micropores in the process of devitrification. Organic matter pyrolysis and organic acid dissolution also increase the reservoir space and porosity of the reservoir. This new type of reservoir has the ability of hydrocarbon accumulation along with the reservoir performance, and thus it has greater exploration prospects. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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12 pages, 6851 KiB

Open AccessArticle

Correction of Light and Heavy Hydrocarbons and Their Application in a Shale Oil Reservoir in Gaoyou Sag, Subei Basin—A Case Study from Well SX84

by Qi Zhi, Shuangfang Lu, Pengfei Zhang, Hongsheng Huang, Junjie Wang and Zizhi Lin

Processes 2023, 11(2), 572; https://doi.org/10.3390/pr11020572 - 13 Feb 2023

Cited by 1 | Viewed by 1748

Abstract

To accurately evaluate the shale oil resources in the Funing Formation of the Gaoyou Sag, Subei Basin, light and heavy hydrocarbon correction models of S₁ were developed based on the rock pyrolysis of liquefrozen, conventional, and oil-washed shales. The improved ΔlogR technique [...] Read more.

To accurately evaluate the shale oil resources in the Funing Formation of the Gaoyou Sag, Subei Basin, light and heavy hydrocarbon correction models of S₁ were developed based on the rock pyrolysis of liquefrozen, conventional, and oil-washed shales. The improved ΔlogR technique was applied to establish the TOC, S₁, and S₂ logging evaluation methods. The results showed that the S₂ values after oil washing were significantly lower than before. The difference between these two S₂ (ΔS₂) values is the heavy hydrocarbon correction amount of S₁, which is about 0.69 S₂. There was almost no loss of light hydrocarbons during liquefrozen shales’ pyrolysis tests; the ratio of liquefrozen to conventional S₁ values is the light hydrocarbon correction factor, which is about 1.67. The corrected S₁ is about 3.2 times greater than the conventional shale-tested value. The S₁ and TOC are obviously “trichotomous”; a TOC greater than 1.5% and corrected S₁ larger than 4.0 mg/g corresponds to the enriched resource. The logging estimated results show that the total shale oil resources in the E₁f₂ of the Gaoyou Sag are about 572 million tons, of which the enriched resource is about 170 million tons. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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15 pages, 8733 KiB

Open AccessArticle

Evaluation of Lacustrine Shale Brittleness and Its Controlling Factors: A Case Study from the Jurassic Lianggaoshan Formation, Sichuan Basin

by Hongsheng Huang, Shuangfang Lu, Pengfei Zhang, Qi Zhi, Junjie Wang and Zizhi Lin

Processes 2023, 11(2), 493; https://doi.org/10.3390/pr11020493 - 7 Feb 2023

Cited by 1 | Viewed by 1567

Abstract

To investigate the brittleness of shale and its influencing factors, triaxial rock mechanics experiments, combined with X-ray diffraction, total organic carbon (TOC) measurement, rock pyrolysis, and scanning electron microscopy, were conducted on shales from the Jurassic Lianggaoshan Formation in the Sichuan Basin. BI [...] Read more.

To investigate the brittleness of shale and its influencing factors, triaxial rock mechanics experiments, combined with X-ray diffraction, total organic carbon (TOC) measurement, rock pyrolysis, and scanning electron microscopy, were conducted on shales from the Jurassic Lianggaoshan Formation in the Sichuan Basin. BI₁, based on the elastic modulus and hardness, BI₂, based on mineral composition, BI₃, based on strength parameters, and BI₄, based on the post-peak energy of shale, were calculated. Additionally, the effects of mineral composition, density, hardness, and organic matter on the brittleness of shales were analyzed. The results show that the shale mineral compositions were dominated by quartz (mean of 45.21%) and clay minerals (mean of 45.04%), with low carbonate mineral contents and high TOC contents. The stress–strain curve showed strong brittleness characteristics. When comparing different evaluation methods, the brittleness evaluation method based on the stress–strain curve (damage energy) was found to be more effective than the mineral fraction and strength parameter methods. The higher the density and hardness, the more brittle the shale. The higher the organic matter and quartz content, the less brittle the shale. The brittleness of sub-member I of the Lianggaosan Formation in Well XQ1 was higher than that of sub-members II and III. This study investigated the brittleness of lacustrine shale and its influencing factors, which is beneficial for the development of shale oil in the Sichuan Basin. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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11 pages, 2082 KiB

Open AccessArticle

Gas Generation and Its Carbon Isotopic Composition during Pyrite-Catalyzed Pyrolysis of Shale with Different Maturities

by Yuanhao Cao, Wei Chen, Yinnan Yuan, Tengxi Wang and Jiafeng Sun

Processes 2022, 10(11), 2296; https://doi.org/10.3390/pr10112296 - 4 Nov 2022

Viewed by 1651

Abstract

In this study, two shale samples with different maturities, from Geniai, Lithuania (R_o = 0.7%), and Wenjiaba, China (R_o = 2.7%), were selected for open-system pyrolysis experiments at 400 °C and 500 °C, respectively. The generation of isotopic gases [...] Read more.

In this study, two shale samples with different maturities, from Geniai, Lithuania (R_o = 0.7%), and Wenjiaba, China (R_o = 2.7%), were selected for open-system pyrolysis experiments at 400 °C and 500 °C, respectively. The generation of isotopic gases from the shales with different maturities was investigated, and the effects of pyrite catalysis on the carbon isotopic compositions were also studied. It was found that CO₂, CH₄ and their isotopic gases were the main gaseous products of the pyrolysis of both shales, and more hydrocarbon gases were generated from the low-maturity Geniai shale. The δ13C1 values fluctuated from −40‰ to −38‰, and δ¹³C₂ showed higher values (−38‰~−34‰) for the Geniai shale. In addition, its δ¹³C_CO2 values ranged from −28‰ to −26‰. Compared with the Geniai shale, lower δ¹³C₁ values (−43‰~−42‰) and higher δ¹³C_CO2 values (−19‰~−14‰) were detected for the Wenjiaba shale. As temperature increased, CH₄ became isotopically lighter and C₂H₆ became isotopically heavier, which changes were due to the mass-induced different reaction rates of ¹²C and ¹³C radicals. Furthermore, the pyrite made the kinetic isotope effect stronger and thus made the CH₄ isotopically lighter for both shales, especially at the lower temperature of 400 °C. Full article

(This article belongs to the Special Issue Shale Oil and Gas Production Technologies: Analysis, Modeling and Application)

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