Water wettability alternation of CO2-water-shale system due to nanoparticles: Implications for CO2 geo-storage

Lu, Yiyu; Liu, Yanlin; Tang, Jiren; Jia, Yunzhong; Tian, Rongrong; Zhou, Jiankun; Chen, Xiayu; Xu, Zhi; Cheng, Qi

doi:10.1016/j.ijggc.2023.103836

Cited by 16 publications

(7 citation statements)

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“…Based on this, chances are great that the nanostructure on the rock surface may promote these chemical reactions in the CO 2 –water–rock system and change the pore structure further according to the LP-NA results and our previous work (Figure ). First, a high temperature would trigger an environment to grow very humid.…”

Section: Resultssupporting

confidence: 61%

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Investigation on Capillary Force Recovery of Nanoparticle-Coated Shale after Supercritical CO₂ Exposure: Implications for CO₂ Sequestration

et al. 2023

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The surface wettability and morphology of shale may both be modified by SiO 2 nanofluid (SNF), directly influencing the capillary force and CO 2 geo-storage. However, the literature requires more information and studies with respect to nanoparticles' effect on shale surface at reservoir conditions of high pressure and temperature. Here, we investigate the stability of nanoparticle layers formed by SNF on Longmaxi (marine) and Yanchang (continental) shale in ScCO 2 and nanoparticles' efficiency of wettability reversal at different nanofluid aging times and concentrations. Besides, low-pressure nitrogen gas adsorption (LP-NA) was performed to evaluate the effect of nanoparticles on shale pore structures after ScCO 2 exposure. Results indicate that the nanoparticle structure could be stable in ScCO 2 and render the wettability of shale samples to be more hydrophilic, while the quartz-rich Longmaxi shale surface shows a denser nanostructure than the clay-rich Yanchang shale surface does and presents a stronger water wettability. More micropores are transformed into mesopores or macropores for ScCO 2and SNF-treated Longmaxi samples than solely ScCO 2 samples, but the pore structure parameters show trivial alteration in Yanchang samples after SNF treatment. The difference in the capillary force recovery between Longmaxi (recovered by 660.5%) and Yanchang (recovered by 500.6%) shale implies that silica nanofluid may be more suitable for Longmaxi formation in the CGS application.

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Section: Resultssupporting

confidence: 61%

“…FTIR area percentage of functional groups of shale samples treated by different conditions. Reproduced with permission from . Copyright [2023] [Elsevier].…”

Section: Resultsmentioning

confidence: 99%

Investigation on Capillary Force Recovery of Nanoparticle-Coated Shale after Supercritical CO₂ Exposure: Implications for CO₂ Sequestration

et al. 2023

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“…The characterization of the rock’s pore structure can be indirectly achieved by measuring both the amplitude and relaxation rate of the hydrogen nucleus resonance signal. Referring to eq , it is apparent that the relaxation time T 2 of hydrogen nuclei is directly proportional to the pore radius, while the amplitude of the resonance signal correlates with the volume of fluid present within the pores. , Consequently, the NMR T 2 spectrum not only serves as a means to describe the pore structure of the core sample but also enables a quantitative assessment of the distribution characteristics of fluids within these pores.…”

Section: Experimental Principlesmentioning

confidence: 99%

Classification of Pore Structure and Identification of Multiple Types of Pore Fluids in Chang 7 Shale Reservoir of the Ordos Basin Based on Nuclear Magnetic Resonance

Zhi,

Liu,

Song

et al. 2024

Energy Fuels

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The presence of distinctive mineral components imparts a remarkably intricate microscopic pore structure, which results in a diverse array of pore fluid types. Utilizing the principles of low-field nuclear magnetic resonance, we undertook a classification of the pore structure of Chang 7 shale reservoirs using 15 shale samples. The T 2 relaxation time boundaries for various types of pore fluids were identified and delineated through a combination of centrifugal testing and heat treatment. These efforts allowed for quantitative characterization of the complete pore size distribution characteristics of the target reservoir. The research findings ascertain that the pore structure of the target shale can be categorized into three types, I, II, and III, and three types of fluids coexist within shale pores. In Type I shale, free fluid predominantly occupies medium and large pores with a pore radius exceeding 24 nm with an average saturation of 30.5%. Claybound fluid, on the other hand, is confined to micropores with a pore radius less than 4.5 nm with an average saturation of 35.3%. Type II shale features free fluid residing primarily in large pores with a pore radius greater than 41.9 nm with an average saturation of 26.6%. Clay-bound fluid is found in micro-and small pores with a pore radius of less than 10.3 nm, exhibiting an average saturation of 40.7%. Type III shale exhibits free fluid concentrated in large pores with a pore radius exceeding 94.3 nm and an average saturation of 17.2%. Clay-bound fluid is present in medium and small pores with a pore radius less than 29.3 nm and an average saturation of 50.1%. Furthermore, r 2C1 and r 2C2 , calculated by T 2c1 and T 2c2 through conversion coefficients, effectively distinguish the free fluid and clay-bound fluid. r 2C2 can be employed as an indicator for assessing the boundary of the reservoir flow capacity.

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“…Wettability is an important reservoir parameter that represents the tendency of liquids to expand or adhere to rock surfaces and has a significant effect on hydrocarbon accumulation and production behaviour (Anderson, 1986; Craig, 1971; Liu et al, 2017; Salehi et al, 2008; Wang, Sun, et al, 2021; Wang, Yao, et al, 2021; Zhang et al, 2022). For shale reservoirs, the wettability of rock surfaces is closely related to the oil/water adsorption of rocks (Dutta et al, 2014; Hosseini et al, 2022; Huang et al, 2020; Lu et al, 2023; Yang et al, 2019). As a result of the interaction of the surface tension of each phase, the wetting phase fluid preferentially attaches to the surface of solid particles and occupies narrow pore channels, whereas the nonwetting phase fluid tends to flow into the middle of pores.…”

Section: Introductionmentioning

confidence: 99%

“…For shale reservoirs, the wettability of rock surfaces is closely related to the oil/water adsorption of rocks (Dutta et al, 2014;Hosseini et al, 2022;Huang et al, 2020;Lu et al, 2023;Yang et al, 2019). As a result of the interaction of the surface tension of each phase, the wetting phase fluid preferentially attaches to the surface of solid particles and occupies narrow pore channels, whereas the nonwetting phase fluid tends to flow into the middle of pores.…”

Section: Introductionmentioning

confidence: 99%

Molecular dynamics simulation of the surface wettability of typical minerals in shale

et al. 2023

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Nanoscale pores are an important storage space in shale petroleum reservoirs. Mineral surface wettability significantly affects the adsorption ability of a fluid, and it is of great significance for the efficient development of shale petroleum. Within a nanoscale pore, however, we cannot measure the contact angle through a conventional measuring method, so we used a molecular dynamics (MD) simulation method. A nanoscale ‘oil–water–rock’ wettability model was used to study the wettability of reservoir minerals with micropores. In this study, by means of MD simulation, the wettability models of different minerals (calcite, quartz and illite) and different liquid hydrocarbons (n‐hexane, toluene and acetic acid) were established, and then the temperature and pressure were changed to study the influence of mineral type, liquid hydrocarbon type, temperature and pressure on wettability. The results show that calcite has the strongest wettability of water in n‐hexane, followed by illite and quartz, and toluene has the strongest wettability of water on the surface of calcite minerals, followed by n‐hexane and acetic acid. In the temperature range of 313–378 K, the higher the temperature, the stronger the water wettability. In the pressure range of 5–20 MPa, the higher the pressure, the water wettability is stronger. By comparing the MD simulation results with the previous experimental results, similar wetting characteristics were obtained, which verified the reliability of the simulation results. This MD simulation method provides a new idea for the study of shale mineral wettability, which is of great significance for shale petroleum exploration.

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Water wettability alternation of CO2-water-shale system due to nanoparticles: Implications for CO2 geo-storage

Cited by 16 publications

References 92 publications

Investigation on Capillary Force Recovery of Nanoparticle-Coated Shale after Supercritical CO₂ Exposure: Implications for CO₂ Sequestration

Investigation on Capillary Force Recovery of Nanoparticle-Coated Shale after Supercritical CO₂ Exposure: Implications for CO₂ Sequestration

Classification of Pore Structure and Identification of Multiple Types of Pore Fluids in Chang 7 Shale Reservoir of the Ordos Basin Based on Nuclear Magnetic Resonance

Molecular dynamics simulation of the surface wettability of typical minerals in shale

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Water wettability alternation of CO2-water-shale system due to nanoparticles: Implications for CO2 geo-storage

Cited by 16 publications

References 92 publications

Investigation on Capillary Force Recovery of Nanoparticle-Coated Shale after Supercritical CO2 Exposure: Implications for CO2 Sequestration

Investigation on Capillary Force Recovery of Nanoparticle-Coated Shale after Supercritical CO2 Exposure: Implications for CO2 Sequestration

Classification of Pore Structure and Identification of Multiple Types of Pore Fluids in Chang 7 Shale Reservoir of the Ordos Basin Based on Nuclear Magnetic Resonance

Molecular dynamics simulation of the surface wettability of typical minerals in shale

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Investigation on Capillary Force Recovery of Nanoparticle-Coated Shale after Supercritical CO₂ Exposure: Implications for CO₂ Sequestration

Investigation on Capillary Force Recovery of Nanoparticle-Coated Shale after Supercritical CO₂ Exposure: Implications for CO₂ Sequestration