Uncertainty quantification of shale capillary desaturation curves for surfactant EOR in shale through fracturing fluids using predictive modeling

Wijaya, Nur; Sheng, James J.

doi:10.1016/j.fuel.2020.118857

Cited by 15 publications

(4 citation statements)

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“…The capillary number values showed that applying PS green surfactant and the optimum concentration of FB (12,500 ppm) was very effective in improving the oil recovery and reducing the residual oil saturation. The findings of capillary numbers in this experiment are consistent with data from the literature [55,56].…”

Section: Capillary Number Measurementsupporting

confidence: 92%

Synergism of a Novel Bio-Based Surfactant Derived from Pisum sativum and Formation Brine for Chemical Enhanced Oil Recovery in Carbonate Oil Reservoirs

et al. 2023

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The Pisum sativum (PS), known as the green pea, was used in this investigation to produce a novel green surfactant. The performance of the PS green surfactant was also evaluated using various tests, including contact angle, IFT, emulsion, zeta potential, and oil recovery factor measurement in the presence of formation brine (FB) with a total dissolved solid (TDS) of 150,000 ppm. The characterization study using various tests revealed that the PS green surfactant was nonionic. The critical micelle concentration (CMC) measurement results indicated that the PS green surfactant’s CMC value is 1500 ppm. The IFT and contact angle measurements showed that the green surfactant significantly lowered the IFT and contact angles. The lowest IFT value of 3.71 mN/m and the contact angle of 57.37° were achieved at the FB concentration of 12,500 ppm (optimum salinity). The results of the emulsion tests showed that Winsor type III emulsions were achieved using PS green surfactant and crude oil. The core flooding experiments revealed that the tertiary recovery using a solution of 1500 ppm of PS green surfactant and 12,500 ppm of FB resulted in a maximum oil recovery factor of 83.55%.

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Section: Capillary Number Measurementsupporting

confidence: 92%

Synergism of a Novel Bio-Based Surfactant Derived from Pisum sativum and Formation Brine for Chemical Enhanced Oil Recovery in Carbonate Oil Reservoirs

et al. 2023

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“…Ca represents the relative importance of viscous force ( u μ) over the capillary force (γ). The oil/CO 2 –water flows can be driven by an external force F b, x ranging from 2 × 10 –4 to 2 × 10 –6 , while the capillary number Ca = F b, x /γ ranges from 3.1 × 10 –3 to 3.1 × 10 –5 , which is within the typical range of capillary numbers in porous media p = c s 2 ∑ i = 1 3 ρ σ i + c s 2 ∑ i = 1 3 ∑ j ≠ i G σ i σ j ψ σ i ψ σ j γ = ( p in − p out ) R …”

Section: Introductionmentioning

confidence: 86%

“…The oil/CO 2 −water flows can be driven by an external force F b,x ranging from 2 × 10 −4 to 2 × 10 −6 , while the capillary number Ca = F b,x /γ ranges from 3.1 × 10 −3 to 3.1 × 10 −5 , which is within the typical range of capillary numbers in porous media. 68 = +…”

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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“…Surfactants, as an industrial additive, are widely applied in petrochemical, mining, medical treatment, food processing, and other industrial fields due to their unique interfacial properties. − Due to their performance in reducing oil–water interfacial tension, alternating wettability, solubilizing crude oil, and changing the interfacial rheology, they can release the crude oil trapped and adhered in the porous medium of the rock, thus enhancing oil recovery (EOR). − Especially, in response to the emergence of the tertiary oil recovery process in recent years, a growing number of surfactants have been screened, designed, or improved to become efficient chemical flooding agents, such as those applied in alkaline/surfactant/polymer (ASP) flooding. − At present, anionic surfactants, such as sodium dodecyl benzene sulfonate (SDBS), are the most widely used surfactants in the tertiary oil recovery process, which have an amphiphilic molecular structure. When present in oil–water systems, they are bound to be adsorbed and arranged at the oil–water interface to form an interfacial film .…”

Section: Introductionmentioning

confidence: 99%

Impact of Sodium Dodecyl Benzene Sulfonate Concentration on the Stability of the Crude Oil–Mineral Water Interfacial Film: A Molecular Dynamics Simulation Study

Wang

Han

et al. 2022

Energy Fuels

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The interfacial behavior of surfactants exerts a considerable impact on the chemical flooding-produced liquid treatment project. For circumventing the limitations of model simplification and single-factor simulation of previous molecular dynamics (MD) studies, this paper based on the experimental results of crude oil-phase and water-phase composition constructed different simulation systems of “crude oil/SDBS/mineral water” considering the concentration of sodium dodecyl benzene sulfonate (SDBS). The impact of SDBS concentration on the stability of the crude oil–mineral water interfacial film was explored, and the simulation results were verified by comparing with the simulation system of “crude oil/SDBS/pure water” and interfacial tension experiments. The simulated results showed that the SDBS molecules in the system exist in the form of a monolayer film after dynamic relaxation equilibrium, and with the increase in concentration, the number of SDBS molecules per unit area of the film increases, and the molecular chain bending characteristics are weakened. The order of the effect of inorganic cations on the aggregation degree of SDBS is Ca2+ > Na+ > K+ > Mg2+. When the concentration of SDBS increased from 0.15 to 0.70 mol/L, the total oil water interfacial film thickness increased from 1.433 nm in the crude oil/SDBS/mineral water system and 1.272 nm in the crude oil/SDBS/pure water system to 2.125 nm in the crude oil/SDBS/mineral water system and 2.398 nm in the crude oil/SDBS/pure water system. The absolute value of interface formation energy increased from 1223.59 and 1236.32 to 2739.19 and 3033.64, respectively, which are also basically consistent with the experimental results of interface tension. Furthermore, inorganic ions will weaken the performance of the surfactant SDBS and detrimentally affect the structural strength and stability of interfacial films. These results offer useful insights into the stabilization mechanism of oil–water emulsions. In particular, they provide a basis for the design and optimization of new pathways for oil–water emulsion instability in oilfield development.

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Uncertainty quantification of shale capillary desaturation curves for surfactant EOR in shale through fracturing fluids using predictive modeling

Cited by 15 publications

References 50 publications

Synergism of a Novel Bio-Based Surfactant Derived from Pisum sativum and Formation Brine for Chemical Enhanced Oil Recovery in Carbonate Oil Reservoirs

Synergism of a Novel Bio-Based Surfactant Derived from Pisum sativum and Formation Brine for Chemical Enhanced Oil Recovery in Carbonate Oil Reservoirs

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

Impact of Sodium Dodecyl Benzene Sulfonate Concentration on the Stability of the Crude Oil–Mineral Water Interfacial Film: A Molecular Dynamics Simulation Study

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Uncertainty quantification of shale capillary desaturation curves for surfactant EOR in shale through fracturing fluids using predictive modeling

Cited by 15 publications

References 50 publications

Synergism of a Novel Bio-Based Surfactant Derived from Pisum sativum and Formation Brine for Chemical Enhanced Oil Recovery in Carbonate Oil Reservoirs

Synergism of a Novel Bio-Based Surfactant Derived from Pisum sativum and Formation Brine for Chemical Enhanced Oil Recovery in Carbonate Oil Reservoirs

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

Impact of Sodium Dodecyl Benzene Sulfonate Concentration on the Stability of the Crude Oil–Mineral Water Interfacial Film: A Molecular Dynamics Simulation Study

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