Lattice Boltzmann pseudopotential multiphase modeling of transcritical CO2 flow using a crossover formulation

Ashirbekov, Assetbek; Kabdenova, Bagdagul; Kuljabekov, Alibek; Monaco, Ernesto; Wang, Lei; Rojas‐Solórzano, Luis

doi:10.46690/ager.2022.06.12

Cited by 5 publications

(4 citation statements)

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“…This prediction should cover both the injection phase and the subsequent hundreds to thousands of years. There are two types of CO 2 migration in saline formations that are affected by changes in vertical permeability [11].…”

Section: Resultsmentioning

confidence: 99%

“…Furthermore, the Leverett J-function [54] was utilised to incorporate the influence of the reservoir heterogeneity on the capillary pressure curves for every individual grid cell: 𝐽 𝑆𝑎𝑡 Ɵ (11) where 𝐽 𝑆𝑎𝑡 = the capillary pressure (dimensionless), 𝑘 = the permeability, 𝜙 = the porosity, Ɵ = the contact angle, and 𝜎 = the interfacial tension. The ECO2M module in conjunction with the nonisothermal multicomponent multiphase flow simulator TOUGH2 was utilised to model the fluid flow [42,43].…”

Section: Methodsmentioning

confidence: 99%

“…CO 2 injection in hydrocarbon reservoirs is a more economically valuable method of storing carbon dioxide because it generates additional money from enhanced oil recovery [9]. To maximise efficiency and guarantee safety, carbon dioxide (CO 2 ) is injected at a depth of more than 800 m, which enables it to achieve a supercritical condition [10,11]. Nevertheless, there is a chance that CO 2 will rise and possibly leak through cracks, microfractures, poorly maintained wells, and unrecorded wells because of the density differential between the injected CO 2 (which is in a supercritical state at the injection depth) and the formation water [12].…”

Section: Introductionmentioning

confidence: 99%

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Optimizing CO2-Water Injection Ratio in Heterogeneous Reservoirs: Implications for CO2 Geo-Storage

Al-Khdheeawi

2024

Energies

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The performance of carbon geo-sequestration is influenced by several parameters, such as the heterogeneity of the reservoir, the characteristics of the caprock, the wettability of the rock, and the salinity of the aquifer brine. Although many characteristics, like the formation geology, are fixed and cannot be altered, it is feasible to choose and manipulate other parameters in order to design an optimized storage programme such as the implementation of CO2 injection techniques, including continuous injection or water alternating CO2, which can significantly increase storage capacity and guarantee secure containment. Although WAG (water-alternating-gas) technology has been widely applied in several industrial sectors such as enhanced oil recovery (EOR) and CO2 geo-sequestration, the impact of the CO2-to-water ratio on the performance of CO2 geo-sequestration in heterogeneous formations has not been investigated. In this study, we have constructed a 3D heterogeneous reservoir model to simulate the injection of water alternating gas in deep reservoirs. We have tested several CO2-water ratios, specifically the 2:1, 1:1, and 1:2 ratios. Additionally, we have estimated the capacity of CO2 trapping, as well as the mobility and migration of CO2. Our findings indicate that injecting a low ratio of CO2 to water (specifically 1:2) resulted in a much better performance compared to situations with no water injection and high CO2-water ratios. The residual and solubility trappings were notably increased by 11% and 19%, respectively, but the presence of free mobile CO2 was reduced by 27%. Therefore, in the reservoir under investigation, the lower CO2-water ratio is recommended due to its improvement in CO2 storage capacity and containment security.

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Section: Resultsmentioning

confidence: 99%

Section: Methodsmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Optimizing CO2-Water Injection Ratio in Heterogeneous Reservoirs: Implications for CO2 Geo-Storage

Al-Khdheeawi

2024

Energies

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“…In this regard, pore-scale simulation can be an effective tool to explore the influences of water phase on CO 2 huff-n-puff by taking into account the complex water distributions in porous media and various parameters from microscopic perspectives. Lattice Boltzmann method (LBM) is an effective pore-scale simulation method to simulate physical and chemical behaviors. − Wei et al performed the immiscible three-phase Shan–Chen LBM to investigate the effect of droplet shape and size, gravity, and meniscus curvature on the spontaneous motion of droplets and bubbles . Based on a color-gradient LBM, Zhu et al studied the effects of wettability, viscosity ratio, and capillary number on the relative permeability.…”

Section: Introductionmentioning

confidence: 99%

Pore-Scale Study on Shale Oil–CO₂–Water Miscibility, Competitive Adsorption, and Multiphase Flow Behaviors

Wang

Cai

et al. 2023

Langmuir

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Due to the fracturing fluid imbibition and primary water, oil−water two-phase fluids generally exist in shale nanoporous media. The effects of water phase on shale oil recovery and geological carbon sequestration via CO 2 huff-n-puff is non-negligible. Meanwhile, oil−CO 2 miscibility after CO 2 huff-n-puff also has an important effect on oil− water two-phase flow behaviors. In this work, by considering the oil− CO 2 competitive adsorption behaviors and the effects of oil−CO 2 miscibility on water wettability, an improved multicomponent and multiphase lattice Boltzmann method is proposed to study the effects of water phase on CO 2 huff-n-puff. Additionally, the effects of oil−CO 2 miscibility on oil−water flow behaviors and relative permeability are also discussed. The results show that due to Jamin's effect of water droplets in oil-wetting pores and the capillary resistance of bridge-like water phase in water-wetting pores, CO 2 can hardly diffuse into the oil phase, causing a large amount of remaining oil. As water saturation increases, Jamin's effect and the capillary resistance become more pronounced, and the CO 2 storage mass gradually decreases. Then, based on the results from molecular dynamics simulations, the influences of oil−CO 2 miscibility on oil−water relative permeability in calcite nanoporous media are studied, and as the oil mass percentage in the oil−CO 2 miscible system decreases, the oil/water relative permeability decreases/ increases. The improved lattice Boltzmann model can be readily extended to quantitatively calculate geological CO 2 storage mass considering water saturation and calculate the accurate oil−water relative permeability based on the real 3D digital core.

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Pore-scale investigation of forced imbibition in porous rocks through interface curvature and pore topology analysis

Cai,

Qin,

Wang

et al. 2024

Journal of Rock Mechanics and Geotechnical Engineering

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Lattice Boltzmann pseudopotential multiphase modeling of transcritical CO2 flow using a crossover formulation

Cited by 5 publications

References 4 publications

Optimizing CO2-Water Injection Ratio in Heterogeneous Reservoirs: Implications for CO2 Geo-Storage

Optimizing CO2-Water Injection Ratio in Heterogeneous Reservoirs: Implications for CO2 Geo-Storage

Pore-Scale Study on Shale Oil–CO₂–Water Miscibility, Competitive Adsorption, and Multiphase Flow Behaviors

Pore-scale investigation of forced imbibition in porous rocks through interface curvature and pore topology analysis

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Lattice Boltzmann pseudopotential multiphase modeling of transcritical CO2 flow using a crossover formulation

Cited by 5 publications

References 4 publications

Optimizing CO2-Water Injection Ratio in Heterogeneous Reservoirs: Implications for CO2 Geo-Storage

Optimizing CO2-Water Injection Ratio in Heterogeneous Reservoirs: Implications for CO2 Geo-Storage

Pore-Scale Study on Shale Oil–CO2–Water Miscibility, Competitive Adsorption, and Multiphase Flow Behaviors

Pore-scale investigation of forced imbibition in porous rocks through interface curvature and pore topology analysis

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Product

Resources

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Pore-Scale Study on Shale Oil–CO₂–Water Miscibility, Competitive Adsorption, and Multiphase Flow Behaviors