Pore-scale characterization of residual gas remobilization in CO2 geological storage

Moghadasi, Ramin; Goodarzi, Sepideh; Zhang, Yihuai; Bijeljic, Branko; Blunt, Martin J.; Niemi, Auli

doi:10.1016/j.advwatres.2023.104499

Cited by 6 publications

(5 citation statements)

References 39 publications

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“…Particularly, the flow pattern in Bakken field located in shale rock system with nanoscale pore structure exhibits capillary fingering regime . For CO 2 geological storage, low viscosity CO 2 was injected to brine at a low flow rate of 0.04 mL/min corresponding to viscosity ratio M = 0.03 and capillary number Ca = 1.8 × 10 –8 . Afterward, the residual CO 2 was displaced by brine with M = 32.82 and Ca = 6 × 10 –7 .…”

Section: Resultsmentioning

confidence: 99%

“…74 For CO 2 geological storage, low viscosity CO 2 was injected to brine at a low flow rate of 0.04 mL/min corresponding to viscosity ratio M = 0.03 and capillary number Ca = 1.8 × 10 −8 . 75 Afterward, the residual CO 2 was displaced by brine with M = 32.82 and Ca = 6 × 10 −7 . 75 As a rule of thumb, the capillary number Ca ranged from 10 −8 to 10 −2 in typical reservoir conditions.…”

Section: Pore-scale Fluid−fluid Interface Evolution Analysis 351 Theo...mentioning

confidence: 99%

“…75 Afterward, the residual CO 2 was displaced by brine with M = 32.82 and Ca = 6 × 10 −7 . 75 As a rule of thumb, the capillary number Ca ranged from 10 −8 to 10 −2 in typical reservoir conditions. 76 In this paper, the microfluidic experiments combined with the dynamic pore-scale evolution analysis established a broad M−Ca phase diagram (Ca = 8.87 × 10 −8 to 3.05 × 10 −3 , M = 0.001 to 1000) of the displacement patterns during the drainage and imbibition process, and implemented the quantification of the crossover zone, having realistic significance in actual reservoirs.…”

Section: Pore-scale Fluid−fluid Interface Evolution Analysis 351 Theo...mentioning

confidence: 99%

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Effects of Capillary and Viscous Forces on Two-Phase Fluid Displacement in the Microfluidic Model

Chen,

Liu,

Wang

et al. 2023

Energy Fuels

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Immiscible fluid−fluid displacement in porous media is an important phenomenon that impacts the field of underground energy and environmental engineering, such as enhanced oil/gas recovery, geological CO 2 sequestration, and transport and remediation of groundwater pollutants. In enhanced oil recovery, the occurrence of the fingering instability of the two-phase flow interface causes a significant reduction in the oil recovery factor for waterflooding. In geological CO 2 sequestration, the efficiency of CO 2 capillary/residual trapping is limited by the noncompact displacement pattern, presenting only part of brine displaced by scCO 2 . Although extensive studies have investigated viscous and capillary fingering in porous media, how viscous and capillary forces affect the crossover is not well understood. Quantifying and characterizing the transition of immiscible fluid−fluid displacement patterns are therefore important. In this article, comprehensive investigation of capillary number and viscosity ratio effects on displacement patterns and efficiency was established by a series of displacement microfluidic experiments in a homogeneous pore network. Three pairs of nonwetting−wetting immiscible fluids with viscosity ratios M ranging from 1/1000 to 1000 were used to perform the displacement experiments. The drainage experiments of water displacing silicone oil were conducted under five flow rate conditions with capillary number log 10 Ca ranging from −7.19 to −3.45, while the imbibition experiments of silicone oil displacing water displayed at four flow rates with log 10 Ca varying from −7.25 to −2.52. The relationship between displacement efficiency S inv and fractal dimension D f as a function of M and Ca was established to quantitatively determine the transition of displacement patterns (capillary fingering, viscous fingering, stable displacement, and ordered dendritic). The results indicated that D f increased with S inv under unfavorable conditions (M < 1) and decreased as S inv for M > 1, and lower invading fluid saturations were observed in the crossover zone between capillary fingering and viscous fingering for M = 1/20 and 1/200. Based on the pore-scale analysis of pore-filling events and microscopic observation, the theoretical model of the transitions for invasion modes were proposed to determine the critical capillary corresponding to viscosity ratio and contact angle. This study extends the classic log 10 M−log 10 Ca phase diagram and quantifies the dynamic effects of capillary force and viscous force on the immiscible fluid−fluid displacement process.

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Section: Resultsmentioning

confidence: 99%

Section: Pore-scale Fluid−fluid Interface Evolution Analysis 351 Theo...mentioning

confidence: 99%

Section: Pore-scale Fluid−fluid Interface Evolution Analysis 351 Theo...mentioning

confidence: 99%

See 1 more Smart Citation

Effects of Capillary and Viscous Forces on Two-Phase Fluid Displacement in the Microfluidic Model

Chen,

Liu,

Wang

et al. 2023

Energy Fuels

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“…Further work should also use the level-set model to evaluate how ripening impacts the critical gas saturation, at which the gas starts flowing in a percolating cluster through the sample. How this process impacts the gas’s relative permeability (and possibly the oil’s relative permeability) compared with standard fluid injection experiments could have important field-scale implications. ,, Finally, it is notable that increasing capillary heterogeneity leads to an increasing amount of gas storage in the porous medium . Since the capillary pressure of trapped bubbles is in the order of magnitude of the mean capillary entry pressure of the porous medium, these trapped ganglia can become susceptible to ripening after trapping.…”

Section: Discussionmentioning

confidence: 99%

“…Hence, to ensure safe storage, it is of great importance to investigate mechanisms that can impact the permanency of capillary-trapped CO 2 ganglia over the storage time. One such mechanism is Ostwald ripening where the gas concentration gradient in the liquid drives mass transfer from gas bubbles with higher pressure to bubbles with lower pressure to equilibrate the fluid distribution. − This can lead to growth and possibly reconnection of large CO 2 ganglia that can trigger flow and cause decreased residual gas saturation …”

Section: Introductionmentioning

confidence: 99%

Ripening of Capillary-Trapped CO₂ Ganglia Surrounded by Oil and Water at the Pore Scale: Impact of Reservoir Pressure and Wettability

Singh,

Friis,

Jettestuen

et al. 2024

Energy Fuels

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Mass transfer by Ostwald ripening can impact the life and volume of capillary-trapped CO 2 in the subsurface. CO 2 storage in depleted hydrocarbon reservoirs encounters various preferences for wetting of the porous rock, while different reservoir pressures impact the miscibility between CO 2 and oil. The ripening behavior of CO 2 ganglia under such conditions is hitherto unknown. Herein, we study the impact of reservoir pressure and wettability on the ripening of CO 2 ganglia in the presence of oil (decane) and water at the pore scale, using a previously developed model that calculates the mass transfer based on chemical potential differences and the stationary three-phase fluid configurations with a multiphase level-set method. Through a comprehensive set of pore-scale simulations on 2D and 3D pore geometries, we show that ripening under immiscible conditions is faster than under near-miscible conditions, despite the fact that the permeability coefficients for CO 2 in oil and water in the mass-transfer equation are higher for the near-miscible condition. The longer equilibration time with increased reservoir pressure occurs because lower CO 2 −liquid interfacial tensions and CO 2 −liquid contact angles closer to 90°lead to lower bubble capillary pressures, lower pressure differences between the bubbles, and lower gradients in bubble pressure with volume. Ripening is faster for strong wetting states where the CO 2 −liquid contact angles are far lower (or higher) than 90°. We find that reservoir pressure, wettability, and oil/water capillary pressure can alter the CO 2 mass-transfer direction and hence the distribution of CO 2 ganglia at thermodynamic equilibrium. Simulations on a residual three-phase configuration in sandstone show that ripening leads to the growth of larger CO 2 ganglia, dissolution of small bubbles, and redistribution of trapped oil ganglia.

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Ostwald ripening of gas bubbles in porous media: Impact of pore geometry and spatial bubble distribution

Singh,

Friis,

Jettestuen

et al. 2024

Advances in Water Resources

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Pore-scale characterization of residual gas remobilization in CO2 geological storage

Cited by 6 publications

References 39 publications

Effects of Capillary and Viscous Forces on Two-Phase Fluid Displacement in the Microfluidic Model

Effects of Capillary and Viscous Forces on Two-Phase Fluid Displacement in the Microfluidic Model

Ripening of Capillary-Trapped CO₂ Ganglia Surrounded by Oil and Water at the Pore Scale: Impact of Reservoir Pressure and Wettability

Ostwald ripening of gas bubbles in porous media: Impact of pore geometry and spatial bubble distribution

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Pore-scale characterization of residual gas remobilization in CO2 geological storage

Cited by 6 publications

References 39 publications

Effects of Capillary and Viscous Forces on Two-Phase Fluid Displacement in the Microfluidic Model

Effects of Capillary and Viscous Forces on Two-Phase Fluid Displacement in the Microfluidic Model

Ripening of Capillary-Trapped CO2 Ganglia Surrounded by Oil and Water at the Pore Scale: Impact of Reservoir Pressure and Wettability

Ostwald ripening of gas bubbles in porous media: Impact of pore geometry and spatial bubble distribution

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Ripening of Capillary-Trapped CO₂ Ganglia Surrounded by Oil and Water at the Pore Scale: Impact of Reservoir Pressure and Wettability