Submitted Successfully!
To reward your contribution, here is a gift for you: A free trial for our video production service.
Thank you for your contribution! You can also upload a video entry or images related to this topic.
Version Summary Created by Modification Content Size Created at Operation
1
Feng Yang
 -- 2844 2023-01-20 08:35:57 |
2 update references and layout
Rita Xu
Meta information modification 2844 2023-01-28 03:12:42 |

Video Upload Options

Do you have a full video?
Send video materials Upload full video

Confirm

Are you sure to Delete?
Yes No
Cite
If you have any further questions, please contact Encyclopedia Editorial Office.
Lu, Y.;  Yang, F.;  Bai, T.;  Han, B.;  Lu, Y.;  Gao, H. Shale Oil Occurrence Mechanisms. Encyclopedia. Available online: https://encyclopedia.pub/entry/40442 (accessed on 06 May 2024).
Lu Y,  Yang F,  Bai T,  Han B,  Lu Y,  Gao H. Shale Oil Occurrence Mechanisms. Encyclopedia. Available at: https://encyclopedia.pub/entry/40442. Accessed May 06, 2024.
Lu, Yangbo, Feng Yang, Ting’an Bai, Bing Han, Yongchao Lu, Han Gao. "Shale Oil Occurrence Mechanisms" Encyclopedia, https://encyclopedia.pub/entry/40442 (accessed May 06, 2024).
Lu, Y.,  Yang, F.,  Bai, T.,  Han, B.,  Lu, Y., & Gao, H. (2023, January 20). Shale Oil Occurrence Mechanisms. In Encyclopedia. https://encyclopedia.pub/entry/40442
Lu, Yangbo, et al. "Shale Oil Occurrence Mechanisms." Encyclopedia. Web. 20 January, 2023.
Shale Oil Occurrence Mechanisms
Edit
This entry is adapted from the peer-reviewed paper 10.3390/en15249485

Shale oil resources are important supplements for the gradually decreasing oil production from conventional reservoirs. The exploitation and development of shale oil have achieved considerable progress, the commercial extraction of hydrocarbons from shales is still difficult, especially in the lacustrine sedimentary basins of China.

shale oil occurrence space occurrence state

1. Introduction

One of the most significant achievements in fossil fuels in the last decade is the commercial extraction of hydrocarbons from unconventional shale reservoirs. In 2019, the total crude oil production in the U.S. reached 609 million tons, of which 65% was produced from tight shales [1]. Crude oil production has doubled since 2010 in the U.S., primarily driven by the effective development of tight shale systems using horizontal drilling and hydraulic fracturing. In fact, shale systems have been ignored for a long time, and regarded only as source rocks of hydrocarbons throughout history. The retained hydrocarbons in shales were unappreciated until advanced drilling and completion technologies were applied to economically extract oil and gas [2]. Currently, unconventional shales have received new attention in petroleum generation, retention, migration, and accumulation for academic and industrial researchers around the world.
The effective developments of liquid hydrocarbons have been successfully achieved in a lot of shale systems in North America, including the Wolfcamp shales in the Permian Basin [3], Eagle Ford shales in southern Texas [4], Bakken shale formations in the Williston Basin [5], etc. Shale oil formations in North America were mainly deposited in marine sedimentary basins. The organic matter of these shales is at a high thermal maturity stage. These shales are also characterized by high light hydrocarbons content and movable oil content. Meanwhile, there are also considerable shale oil resources in China, including the Triassic Yanchang Formation in the Ordos Basin [6], the Cretaceous Qingshankou Formation in the Songliao Basin [7], the Permian Lucaogou Formation in the Santanghu Basin, and the Palaeogene Shahejie Formation in Bohai Bay Basin [8], etc. Unlike the marine sedimentary basins, shale oil formations in China were mainly deposited in lacustrine sedimentary environments [9]. Lacustrine shales are characterized as strongly heterogeneous in fabric, texture, and mineralogy. Shale oil extracted from the lacustrine source rocks commonly contains more asphaltene and resin content [10]. Thus, lacustrine shale oil is less movable compared to shales from marine sedimentary basins. Operators drilled many wells in lacustrine shale formations but did not always achieve satisfactory results. For example, the initial yield of the BY1 well, drilled in the first demonstration plot of China, was about 8.22 m3/d after hydraulic fracturing and quickly decreased to 1.6 m3/d [11]. Oil production from the HF1 well, drilled in the first breakthrough plot of lacustrine shale oil in China, was 23.6 m3/d initially and soon decreased to about 1 m3/d [12]. Thus, the effective development of shale oil in China is fairly difficult considering the severe reservoir heterogeneity and low flow ability of hydrocarbons [13]. The limited production of lacustrine shale oil is probably related to the poor understanding of petroleum generation and retention in shale systems [14].
Compared to conventional reservoirs, shales are much tighter with low porosity and ultra-low permeability. Minerals in shales, including organic matter and inorganic matter, are much more fine-grained and diversified. Shale systems are further complicated by the diagenetic transformation of inorganic minerals and hydrocarbons generated from organic matter [14]. Furthermore, the particle size and pores of shales are extremely fine [15]. Consequently, the hydrocarbon generation, expulsion, and retention are significantly different from the conventional reservoirs. Many characterization technologies used in sandstones and carbonates are not applicable to shales [16]. It is challenging to accurately estimate the pore structure, oil content, and oil movability of shale systems.
Previous investigations about shale oil have found that shale oil enrichment in lacustrine basins is affected by the lithofacies, minerals, interlayers, reservoir characteristics (pores, porosity, permeability, fractures), and organic geochemistry properties [17][18][19]. In lacustrine shale systems, laminated shales are thought to be favorable for shale oil accumulation [17]. Liu et al. thought that the laminated siliceous mudstones with moderate total organic carbon (TOC) content have abundant reservoir space and are the most favorable lithofacies for shale oil enrichment [18]. Bai et al. investigated the lacustrine shale oil accumulation in the Bohai Bay Basin and found that the interparticle pores in carbonates act as the reservoir spaces of shale oil [19]. Hu et al. thought that fractures provide oil migration pathways from source rocks to the reservoir, thus the interbedded intervals with abundant fractures are favorable for shale oil accumulation [20]. The fluid movability, abnormal fluid pressure, interlayers, and developed fractures are important to the high production of shale oil. In terms of the occurrence mechanism, molecular simulations have been adopted to analyze the adsorption behavior of shale oil at a micro-scale [21]. The occurrence space of shale oil can be observed by direct imaging techniques. Indirect methods, including nuclear magnetic resonance (NMR) and pyrolysis experiments, are also applied to investigate the occurrence state and content of shale oil [22][23][24]. Rock pyrolysis experiments divide hydrocarbons in shales into free oil and pyrolytic hydrocarbons, taking 300 °C as the boundary [22].

2. The Geological Definition of Shale Oil

2.1. Definition of Shale Oil

Shale oil refers to the non-gaseous hydrocarbons stored in organic-rich shales, mudstones, and their thin interlayers (siltstones, carbonates, etc.) [25]. During the early stage, the definition of shale oil was disputed by many researchers from a couple of different perspectives, including sedimentary lithology, reservoir space, and organic matter characteristics, etc. [26]. The initial definition of shale oil only refers to the oil accumulated in the organic-rich shales and mudstones with self-generated and self-stored characteristics. With the development of unconventional reservoirs, researchers and operators have loosened the definition: shale oil contains the petroleum not only retained in shales but also stored in interlayered tight sandstones and carbonate. In other words, petroleum accumulated in both self-generated self-stored reservoirs and short-distance migrated reservoirs can be ascribed to shale oil. In the “geological evaluation method for shale oil” (GB/T38718-2020) formulated by the standardization administration of China in 2020 [27], shale oil refers to oil stored in organic-rich shale systems with a thickness of fewer than 5 m for each organic-lean interbedded layer and a ratio of less than 30% for the accumulated thickness of the interbedded layers.

2.2. The Occurrence State of Shale Oil

Oil stores in organic-rich shale systems via free, adsorption, and absorption (solvation) states [28]. Free shale oil mainly stores within interlayered fractures, structural fractures, and overpressured fractures [29]. It also occurs as a free state in the recrystallized intercrystalline pores and dissolution-related pores with large pore diameters and forms locally continuous hydrocarbon aggregation [30]. Adsorbed shale oil is mainly associated with organic matter and clay minerals. Because of the van der Waals force and Coulomb force between these minerals and hydrocarbon molecules, oil in the adsorbed state presents with a solid-like form for which flow is difficult [31]. The absorption state of shale oil is that shale oil is dissolved in kerogen, which causes the kerogen to expand.

3. Occurrence Space Characterization of Shale Oil

Shale systems are severely heterogeneous. Figure 1 illustrates the mineral compositions of Barnett shale from Fort Worth Basin [30] and Chang 7 shale from Ordos Basin [6]. There is significant variation in mineral compositions of shales, even from the same formation. Shale oil movability is closely related to the minerals, pore structure, pore size distribution, and pore connectivity.
Energies 15 09485 g001
Figure 1. Mineral compositions of Barnett shale from Fort Worth Basin [30] and Chang 7 shale from Ordos Basin [6].
There are several types of micropores and nanopores in shale reservoirs, including organic matter-hosted pores, intergranular pores, dissolution-related pores, and microfractures [32]. Recently, many advanced technologies have been introduced to qualitatively and quantitatively characterize the occurrence space of shale oil. These techniques can be mainly classified into three categories: image observation method, fluid injection method, and high-energy ray method (Figure 2).
Energies 15 09485 g002
Figure 2. Experimental methods used to characterize the pore structure of shales.

3.1. Image Observation Technology

Image observation is a kind of technology that uses high-resolution imaging technology to directly observe the microscopic pore characteristics of shales. Using advanced imaging instruments, including focused ion beam-scanning electron microscopy (FIB-SEM), field emission-scanning electron microscopy (FE-SEM), atomic force microscopy (AFM), scanning transmission electron microscopy (STEM), helium ion-scanning electron microscopy (HIM), etc., the geometrical morphology of nano-scaled pores in shales can be visually observed. Generally, samples are mechanically polished before image observation. However, the cutting force during mechanical polishing may produce artificial fractures and pores. The abrasive particles used in mechanical polishing also easily occlude pores. Thus, shale samples prepared by mechanical polishing are not always satisfactory for image observation. In order to produce smooth and flat surfaces, Loucks et al. [32] utilized argon ion polishing technology in a metal surface treatment to prepare shale samples and obtained a high-quality sample surface. Combined with scanning electron microscopy, types of nano-scaled pores in organic matter of shales were observed [33][34][35]. Subsequently, argon ion polishing technology has been widely used to prepare shale samples.
For the conventional reservoirs, an optical microscope is feasible to observe their pore structure, with pore diameters being one micrometer or larger. However, the resolution of optical microscopes (about 0.01mm) is not high enough to observe the mineral arrangements and pore morphology of shales. Field emission-scanning electron microscopy (FE-SEM) can acquire images with a high resolution of up to 5 nm. After argon ion polishing, the samples are coated with gold or carbon to increase the conductivity and then used for FE-SEM imaging (Figure 3, [36]). Mastalerz et al. [37] studied the effect of argon ion polishing on shale samples during sample preparation and believed that the organic matter thermal alteration usually involves the volatilization of light hydrocarbon components. Thus, more care should be taken during the polishing of immature samples and oil window samples. With the application of FE-SEM, Wang et al. [38] investigated the pore structure of lacustrine shales in the Ordos Basin and found that hydrocarbon generation, mineral transformation, and compaction affected the evolution of pores.
Energies 15 09485 g003
Figure 3. FE-SEM images showing moveable oil spilling from (a) interparticle pores of clay minerals ([modified from Zheng et al. [36]]); (b) microfracture of shales in the Ordos Basin.
Scanning transmission electron microscopy (STEM) scans the sample surface using electron beams and images by electron penetration. Laura constructed the three-dimensional (3D) structure of shales using STEM tomography and found that the nano-scaled pores below 20nm dominate in number but do not form connected pore networks, while the pores with pore sizes between 20nm and 60nm are well connected and therefore controlled the transport property of shales [39].
Focused ion beam-scanning electron microscopy (FIB-SEM) accelerates the ion beam generated by liquid metal (most FIB uses Ga) ion source through an ion gun and strips the surface atoms to complete the micro- and nano-scaled surface topography. Combined with the computer algorithms, FIB-SEM presents the 3D distribution of pores and quantitatively provides the pore structure parameters and pore connectivity [40]. Zhou et al. [41] used FIB-SEM to study the two-dimensional and three-dimensional characteristics of shales from the Longmaxi Formation and calculated pore size distributions of the three-dimensional (3D) digital rock reconstructed from 600 consecutive FIB-SEM images.
Helium ion microscopy (HIM) is a method of imaging samples by accelerating and concentrating helium beams in the sample surface. Compared with electron beams, helium ion beams can better detect the internal structural characteristics of small pores; due to that, coating before electron microscope observation may destroy fine pores. HIM can obtain more reliable images of pores by direct observation without coating. Huang et al. used HIM to study the formation and evolution of organic matter pores in shales [42]. They divided the formation process of organic matter pores into four stages: formation, expansion, connection, and consolidation. King et al. found that organic matter contains an anomalous population of pores of the order ~2 nm [43]. They thought that these narrow pores were produced when the excess internal pressure failed to create escape pathways for the generated fluids during the kerogen diagenesis process.
Atomic force microscopy (AFM) is a scanning probe technology that approaches the sample surface with a highly sensitive probe installed on the cantilever. The interaction force between the needle tip of the probe and the sample surface deforms the cantilever beam. Using the optical leverage principle, the small deformation of the cantilever beam is amplified and converted into electrical signals so as to obtain the surface morphology and roughness information of the sample. The AFM not only produces high-resolution 2D and 3D images, but also characterizes the mechanical properties of the sample, such as Young’s modulus, adhesion force, and electric potential (Figure 4). Javapour et al. [44] used AFM to characterize the surface topography of shales, especially the nano-pore characteristics of shale surfaces. Tian et al. [45] studied the kerogen and minerals in shales using AFM with the PeakForce Tapping mode and reported that the adhesion decreased in the order: kerogen > illite > montmorillonite > calcite > muscovite. Bai et al. [46] found that surface roughness affects the adhesion of shale: the higher the surface roughness, the greater the adhesion force. Wang et al. [47] characterized the organic matter of shales by atomic force microscopy combined with infrared spectroscopy (AFM-IR) and obtained the distribution of functional groups of organic matter.
Energies 15 09485 g004
Figure 4. (a) Pore surface of mica scanning by AFM; (b) The adhesion force curves of shale oil on mica surface detect by AFM (modified from Bai et al. [46]).

3.2. Fluid Injection Technology

The fluid injection technique quantitatively characterizes pore structure by injecting fluids that do not react with the minerals of the samples. By precisely recording the amount of injected fluid during the fluid intrusion and extrusion processes, the pore structure parameters can be estimated based on the hypothetical models. This experiment is easy to perform on various porous media, whether regular or irregular. Thus, it is one of the most widely-used techniques in characterizing the pore structure of materials. According to the injected fluids, this kind of technique mainly includes mercury intrusion porosimetry (MIP), nitrogen adsorption, carbon dioxide adsorption, helium injection, etc.
The MIP technique records the injection pressure values and the volume of mercury intrusion. Based on this information, pore structure parameters, such as pore size distribution and pore volume, can be estimated according to the Washburn theory. Mercury intrusion porosimetry can be further divided into high-pressure mercury injection and constant-speed mercury injection. The differences between these two methods are the mercury injection rate and the maximum mercury injection pressure. The constant-rate mercury intrusion technique is usually conducted at a low injection rate (less than 5 × 10−5 mL/min) and limited injection pressure (maximum pressure is 900 psi) to finely characterize the pore throat information. The maximum pressure of high-pressure mercury injection is fairly higher than that of constant-speed mercury injection. The smallest pore diameter that can be detected using a maximum injection pressure of 60,000 psi is about 3–4 nm. The high-pressure mercury injection is usually applied for characterizing the wide pore size distribution of shales. However, the high-pressure mercury may compress the pores of soft minerals (clays and organic matter in shales) and even create artificial fractures at high-injection pressure conditions. Thus, the pore structure information of shales detected by MIP should be cautiously examined with the aid of other information.
Nitrogen adsorption is especially used for the investigation of nano-scaled pores [48]. Particle or powder samples are vacuumized before the experiment. Then, high-purity nitrogen is used as an adsorbent to adsorb on the pore surface of samples under different relative pressures at −196 °C. Nitrogen adsorption and desorption curves are plotted with the relative pressure as abscissa and adsorption amount as ordinate. The pore size distribution and specific surface area can be interpreted according to the physical adsorption theory [48]. The hysteresis loops, formed by the divergence between the adsorption and desorption branches, are associated with specific pore shapes. The IUPAC (International Union of Pure and Applied Chemistry) divided hysteresis loops into four types [48], as follows. The type H1 hysteresis loop is related to the cylindrical pores with openings at both ends. The type H2 hysteresis loop is always observed in the inkbottle-shaped pores with a thin neck and wide body. The type H3 hysteresis loop is associated with slit-shaped pores or fractures, while the type H4 hysteresis loop is usually related to narrow slit-shaped pores. Previous investigations have shown that the organic matter-hosted pores in shales are constituted by narrow pore throats connecting to large pore bodies [49]. Thus, the wide hysteresis loops (type H2) are always observed in shales with developed organic matter-hosted pores, while the type H3 hysteresis loops are found in pores with clay minerals (plate-like particles) [49][50]. Nitrogen adsorption is widely used to characterize nanoporous materials. However, the effective diffusion coefficients of nitrogen are low (10−14–10−12 m2/s) in micropores at low temperatures [51], which restricts the access of nitrogen to inner pores. This will result in the underestimation of the total pore volume. Moreover, samples for nitrogen adsorption are always crushed into particles that might destroy the authentic pore structure.
Other fluid injection technology, such as water injection and imbibition, is used to not only characterize the pore structure but also increase oil production. Fluid imbibition experiments were conducted to characterize the connectivity of shales according to the time exponent of water imbibition [52]. Low salinity water injection can effectively enhance oil recovery of tight reservoirs by changing rock wettability and reducing interfacial tension [53]. The enhanced oil recovery factor was reported to be up to 14% in carbonate reservoirs using low-salinity water injection [53].

References

  1. EIA. Drilling Productivity Report; U.S. Energy Information Administration: Washington, DC, USA, 2021.
  2. Li, Q.Q.; Xu, S.; Zhang, L.; Chen, F.; Wu, S.; Bai, N. Shale Oil Enrichment Mechanism of the Paleogene Xingouzui Formation, Jianghan Basin, China. Energies 2022, 15, 4038.
  3. Tathed, P.; Han, Y.; Misra, S. Hydrocarbon saturation in upper Wolfcamp shale formation. Fuel 2018, 219, 375–388.
  4. Ko, L.T.; Loucks, R.G.; Ruppel, S.C.; Zhang, T.; Peng, S. Origin and characterization of Eagle Ford pore networks in the south Texas Upper Cretaceous shelf. AAPG Bull. 2017, 101, 387–418.
  5. Shao, D.; Zhang, T.; Ko, L.T.; Li, Y.; Yan, J.; Zhang, L.; Luo, H.; Qiao, B. Experimental investigation of oil generation, retention, and expulsion within type II kerogen-dominated marine shales: Insights from gold-tube nonhydrous pyrolysis of Barnett and Woodford Shales using miniature core plugs. Int. J. Coal Geol. 2020, 217, 1–17.
  6. Guo, Q.L.; Yao, Y.; Hou, L.; Tang, S.; Pan, S.; Yang, F. Oil migration, retention, and differential accumulation in “sandwiched” lacustrine shale oil systems from the Chang 7 member of the Upper Triassic Yanchang Formation, Ordos Basin, China. Int. J. Coal Geol. 2022, 261, 104077.
  7. Liu, B.; Sun, J.; Zhang, Y.; He, J.; Fu, X.; Yang, L.; Xing, J.; Zhao, X. Reservoir space and enrichment model of shale oil in the first member of Cretaceous Qingshankou Formation in the Changling Sag, southern Songliao Basin, NE China. Pet. Explor. Dev. 2021, 48, 608–624.
  8. Li, T.; Liu, B.; Zhou, X.; Yu, H.; Xie, X.; Wang, X.; Rao, H. Classification and evaluation of shale oil enrichment: Lower third member of Shahejie Formation, Zhanhua Sag, Eastern China. Mar. Petrol. Geol. 2022, 143, 105824.
  9. Zhan, H.; Fang, F.; Li, X.; Hu, Z.; Zhang, J. Shale Reservoir Heterogeneity: A Case Study of Organic-Rich Longmaxi Shale in Southern Sichuan, China. Energies 2022, 15, 913.
  10. Guo, Q.; Pan, S.; Yang, F.; Yao, Y.; Zheng, H. Characterizing Shale Oil Occurrence in the Yanchang Formation of the Ordos Basin, Assisted by Petrophysical and Geochemical Approaches. Energy Fuels 2022, 36, 370–381.
  11. Lu, S.F.; Huang, W.B.; Chen, F.W.; Li, J.J.; Wang, M.; Xue, H.T.; Wang, W.M.; Cai, X.Y. Classifcation and evaluation criteria of shale oil and gas resources: Discussion and application. Pet. Explor. Dev. 2012, 39, 249–256.
  12. Zhang, T.; Fu, Q.; Sun, X.; Hackley, P.C.; Ko, L.; Shao, D. Meter-scale lithofacies cycle and controls on variations in oil saturation, Wolfcamp A, Delaware and Midland Basins. AAPG Bull. 2012, 105, 1821–1846.
  13. Hu, T.; Pang, X.; Jiang, F.; Wang, Q.; Liu, X.; Wang, Z.; Jiang, S.; Wu, G.; Li, C.; Xu, T.; et al. Movable oil content evaluation of lacustrine organic-rich shales: Methods and a novel quantitative evaluation model. Earth-Sci. Rev. 2021, 214, 103545.
  14. Knapp, L.J.; Ardakani, O.H.; Uchida, S.; Nanjo, T.; Otomo, C.; Hattori, T. The influence of rigid matrix minerals on organic porosity and pore size in shale reservoirs: Upper Devonian Duvernay Formation, Alberta, Canada. Int. J. Coal Geol. 2020, 227, 103525.
  15. Zhang, Y.; Jiang, S.; He, Z.; Li, Y.; Xiao, D.; Chen, G.; Zhao, J. Coupling between Source Rock and Reservoir of Shale Gas in Wufeng-Longmaxi Formation in Sichuan Basin, South China. Energies 2021, 14, 2679.
  16. Wang, S.; Wang, J.; Zhang, Y.; Li, D.; Jiao, W.; Wang, J.; Lei, Z.; Yu, Z.; Zha, X.; Tan, X. Relationship between Organic Geochemistry and Reservoir Characteristics of the Wufeng-Longmaxi Formation Shale in Southeastern Chongqing, SW China. Energies 2021, 14, 6716.
  17. Li, Q.; Xu, S.; Hao, F.; Shu, Z.; Chen, F.; Lu, Y.; Wu, S.; Zhang, L. Geochemical characteristics and organic matter accumulation of argillaceous dolomite in a saline lacustrine basin: A case study from the paleogene xingouzui formation, Jianghan Basin, China. Mar. Pet. Geol. 2021, 128, 105041.
  18. Liu, B.; Wang, H.; Fu, X.; Bai, Y.; Bai, L.; Jia, M.; He, B. Lithofacies and depositional setting of a highly prospective lacustrine shale oil succession from the Upper Cretaceous Qingshankou Formation in the Gulong sag, northern Songliao Basin, northeast China. AAPG Bull. 2019, 103, 405–432.
  19. Bai, C.; Yu, B.; Han, S.; Shen, Z. Characterization of lithofacies in shale oil reservoirs of a lacustrine basin in eastern China: Implications for oil accumulation. J. Pet. Sci. Eng. 2020, 195, 107907.
  20. Hu, S.; Li, S.; Xia, L.; Lv, Q.; Cao, J. On the internal oil migration in shale systems and implications for shale oil accumulation: A combined petrological and geochemical investigation in the Eocene Nanxiang Basin, China. J. Pet. Sci. Eng. 2020, 184, 106493.
  21. Xu, J.L.; Wang, R.; Zan, L. Shale oil occurrence and slit medium coupling based on a molecular dynamics simulation. J. Pet. Sci. Eng. 2023, 220, 111151.
  22. Sanei, H.; Wood, J.M.; Ardakani, O.H.; Clarkson, C.R.; Jiang, C. Characterization of organic matter fractions in an unconventional tight gas siltstone reservoir. Int. J. Coal Geol. 2015, 150, 296–305.
  23. Li, M.; Chen, Z.; Qian, M.; Ma, X.; Jiang, Q.; Li, Z.; Tao, G.; Wu, S. What are in pyrolysis S1 peak and what are missed? Petroleum compositional characteristics revealed from programed pyrolysis and implications for shale oil mobility and resource potential. Int. J. Coal Geol. 2020, 217, 103321.
  24. Zhang, P.; Lu, S.; Li, J.; Chang, X. 1D and 2D Nuclear magnetic resonance (NMR) relaxation behaviors of protons in clay, kerogen and oil-bearing shale rocks. Mar. Petrol. Geol. 2020, 114, 104210.
  25. Donovan, A.; Evenick, J.; Banfield, L.; McInnis, N.; Hill, W. An Organofacies-Based Mudstone Classification for Unconventional tight Rock and Source Rock Plays. In Proceedings of the SPE/AAPG/SEG Unconventional Resources Technology Conference, Austin, TX, USA, 24–26 July 2017.
  26. Wang, Q.; Tao, S.; Guan, P. Progress in research and exploration & development of shale oil in continental basins in China. Nat. Gas Geosci. 2020, 31, 417–427.
  27. GB/T38718-2020; Geological Evaluation Method for Shale Oil. The Standardization Administration of China: Beijing, China, 2020.
  28. Jarvie, D.M. Shale Resource Systems for Oil and Gas: Part 2—Shale-Oil Resource Systems. In Shale Reservoirs—Giant Resources for the 21st Century; Breyer, J.A., Ed.; AAPG: Tulsa, OK, USA, 2012; Volume 97, pp. 89–119.
  29. Li, T.; Jiang, Z.; Xu, C.; Liu, B.; Liu, G.; Wang, P.; Li, X.; Chen, W.; Ning, C.; Wang, Z. Effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation, Zhanhua Sag, eastern China: Evidence from gas adsorption and nuclear magnetic resonance. Mar. Pet. Geol. 2017, 88, 932–949.
  30. Han, Y.; Horsfeld, B.; Wirth, R.; Mahlstedt, N.; Bernard, S. Oil retention and porosity evolution in organic-rich shales. AAPG Bull. 2017, 101, 807–827.
  31. Matsubara, H.; Umezaki, T.; Funatsu, T.; Tanak, H.; Ikeda, N.; Aratono, M. Thinning and thickening transitions of foam film induced by 2D liquid–solid phase transitions in surfactant–alkane mixed adsorbed films. Adv. Colloid Interface Sci. 2020, 282, 102206.
  32. Loucks, R.G.; Reed, R.M.; Ruppel, S.C.; Jarvie, D.M. Morphology, genesis, and distribution of nanometer-scale pores in siliceous mudstones of the Mississippian Barnett Shale. J. Sediment. Res. 2009, 79, 848–861.
  33. Yang, F.; Xu, S.; Hao, F.; Hu, B.; Zhang, B.; Shu, Z.; Long, S. Petrophysical characteristics of shales with different lithofacies in Jiaoshiba area, Sichuan Basin, China: Implications for shale gas accumulation mechanism. Mar. Petrol. Geol. 2019, 109, 394–407.
  34. Milliken, K.L.; Rudnicki, M.; Awwiller, D.N.; Zhang, T. Organic matter-hosted pore system, Marcellus Formation (Devonian), Pennsylvania. AAPG Bull. 2013, 97, 177–200.
  35. Deng, H.; Hu, X.; Li, H.A.; Luo, B.; Wang, W. Improved pore-structure characterization in shale formations with FESEM technique. J. Nat. Gas Sci. Eng. 2016, 35, 309–319.
  36. Zheng, H.; Yang, F.; Guo, Q.; Pan, S.; Jiang, S.; Wang, H. Multi-scale pore structure, pore network and pore connectivity of tight shale oil reservoir from Triassic Yanchang Formation, Ordos Basin. J. Petrol. Sci. Eng. 2022, 212, 110283.
  37. Mastalerz, M.; Schieber, J. Effect of ion milling on the perceived maturity of shale samples: Implications for organic petrography and SEM analysis. Int. J. Coal Geol. 2017, 183, 110–119.
  38. Wang, F.; Guo, S. Influential factors and model of shale pore evolution: A case study of a continental shale from the Ordos Basin. Mar. Petrol. Geol. 2019, 102, 271–282.
  39. Laura, F.; Kovscek, A.R. Nano-Imaging of Shale Using Electron Microscopy Techniques. In Proceedings of the SPE/AAPG/SEG Unconventional Resources Technology Conference, Virtual, 20–22 July 2020.
  40. Bai, B.; Elgmati, M.; Zhang, H.; Wei, M. Rock characterization of Fayetteville shale gas plays. Fuel 2013, 105, 645–652.
  41. Zhou, S.; Yan, G.; Xue, H.; Guo, W.; Li, X. 2D and 3D nanopore characterization of gas shale in Longmaxi formation based on FIB-SEM. Mar. Petrol. Geol. 2016, 73, 174–180.
  42. Huang, C.; Ju, Y.; Zhu, H.; Lash, G.G.; Qi, Y.; Yu, K.; Feng, H.; Ju, L.; Qiao, P. Investigation of formation and evolution of organic matter pores in marine shale by helium ion microscope: An example from the Lower Silurian Longmaxi Shale, South China. Mar. Petrol. Geol. 2020, 120, 104550.
  43. King, H.E.; Eberle, A.P.R.; Walters, C.C.; Kliewer, C.E.; Ertas, D.; Huynh, C. Pore Architecture and Connectivity in Gas Shale. Energy Fuel 2015, 29, 1375–1390.
  44. Javadpour, F.; Farshi, M.M.; Amrein, M. Atomic-Force Microscopy: A New Tool for Gas-Shale Characterization. J. Can. Pet. Technol. 2012, 51, 236–243.
  45. Tian, S.; Wang, T.; Li, G.; Sheng, M.; Zhang, P. Nanoscale Surface Properties of Organic Matter and Clay Minerals in Shale. Langmuir 2019, 35, 5711–5718.
  46. Bai, T.A.; Yang, F.; Wang, H.; Zheng, H. Adhesion Forces of Shale Oil Droplet on Mica Surface with Different Roughness: An Experimental Investigation Using Atomic Force Microscopy. Energies 2022, 15, 6460.
  47. Wang, K.; Ma, L.; Taylor, K.G. Nanoscale geochemical heterogeneity of organic matter in thermally-mature shales: An AFM-IR study. Fuel 2022, 310, 122278.
  48. Sing, S.K. Reporting physisorption data for gas/solid systems with special reference to the determination of surface area and porosity. Pure Appl. Chem. 1985, 57, 603–619.
  49. Yang, F.; Ning, Z.; Zhang, R.; Zhao, H.; Krooss, B.M. Investigations on the methane sorption capacity of marine shales from Sichuan Basin, China. Int. J. Coal Geol. 2015, 146, 104–117.
  50. Yang, F.; Lyu, B.; Xu, S. Water sorption and transport in shales: An experimental and simulation study. Water Resour. Res. 2021, 57, e2019WR026888.
  51. Bertier, P.; Schweinar, K.; Stanjek, H.; Ghanizadeh, A.; Clarkson, C.R.; Busch, A.; Kampman, N.; Prinz, D.; Amann-Hildenbrand, A.; Krooss, B.M.; et al. On the use and abuse of N2 physisorption for the characterisation of the pore structure of shales. Clay Miner. Soc. Workshop Lect. Ser. 2016, 21, 151–161.
  52. Yang, F.; Zheng, H.; Guo, Q.L.; Lyu, B.; Nie, S.J.; Wang, H. Modeling water imbibition and penetration in shales: New insights into the retention of fracturing fluids. Energy Fuel 2021, 35, 13776–13787.
  53. Khormali, A.; Koochi, M.R.; Varfolomeev, M.A.; Ahmadi, S. Experimental study of the low salinity water injection process in the presence of scale inhibitor and various nanoparticles. J. Petrol. Explor. Prod. Technol. 2022, 1–14.
More
© Text is available under the terms and conditions of the Creative Commons Attribution (CC BY) license; additional terms may apply. By using this site, you agree to the Terms and Conditions and Privacy Policy.
Upload a video for this entry
Information
Subjects: Engineering, Petroleum
Contributors MDPI registered users' name will be linked to their SciProfiles pages. To register with us, please refer to https://encyclopedia.pub/register :
Yangbo Lu
,
Feng Yang
,
Ting’an Bai
,
Bing Han
,
Yongchao Lu
,
Han Gao
View Times: 229
Revisions: 2 times (View History)
Update Date: 28 Jan 2023
Table of Contents
    1000/1000
    Hot Most Recent
    Feedback