Micro-scale displacement of NAPL by surfactant and microemulsion in heterogeneous porous media

Javanbakht, Gina; Arshadi, Maziar; Qin, Tianzhu; Goual, Lamia

doi:10.1016/j.advwatres.2017.05.006

Cited by 70 publications

(40 citation statements)

References 42 publications

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“…An artificial flat core model with dimensions of 30 mm × 30 mm × 4:5 mm and permeability ratios of 1, 6, and 9, respectively, was utilized. Simulated oil used from the Daqing oilfield, with a viscosity of 10 mPa•s at 45°C and water with mineralization of 508 mg/L, was used for microscopic water flooding (2) water flooding at a constant rate of 0.03 mL/h until the end of oil production from the model, (3) inject the three displacement systems at a constant speed of 0.03 mL/h and observe the distribution of residual oil in the model, (4) calculate the oil displacement efficiency and all kinds of residual oil saturation after the experiment, and (5) replace the model and repeat the above steps. The artificial flat core flooding experiment consists of the following processes: (1) saturate with formation water after the core is vacuumed, then inject the simulated oil into the model until the outlet end is free of water; afterwards, initiate water flooding until there is no more oil production from the core; (2) inject three displacement systems and stop the displacement process when the water cut reaches 98%;…”

Section: Experimental Designmentioning

confidence: 99%

“…Due to the complex pore structure and severe heterogeneity of low permeability reservoirs, causing large volumes of residual oil in the pores, it is imperative to take reasonable measures to reduce the effect of reservoir heterogeneity on ultimate recovery. Numerous technologies for improved oil recovery have been developed to date [1][2][3][4][5]. Polymer flooding is widely used for improved recovery efficiency in China's oilfield development [6][7][8][9].…”

Section: Introductionmentioning

confidence: 99%

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Study on Distribution Characteristics and Displacement Mechanism of Microscopic Residual Oil in Heterogeneous Low Permeability Reservoirs

2019

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In order to explore the development methods suitable for heterogeneous low permeability reservoirs and study the distribution characteristics of residual oil, photoetched glass and artificial core models with three permeability ratios of 1, 6, and 9 were prepared in this research. Three displacement schemes including polymeric surfactant flooding, polymeric surfactant with binary flooding, and binary flooding were designed at the same expenses to obtain the displacement mechanism of various residual oil saturations. The results show that the best displacement efficiency can be achieved by polymeric surfactant flooding, followed by polymeric surfactant with binary flooding, and binary flooding for the models with the same permeability ratio. Binary flooding mainly activates cluster and oil drop residual oils, polymeric surfactant with binary flooding mainly activates cluster, oil film, and column residual oils, whereas polymeric surfactant flooding mainly activates cluster, oil drop, and column residual oils. In addition, with the increase of the model permeability ratio, the recovery ratio of water flooding decreases, whereas the enhanced oil recovery and the variations in residual oil saturation gradually increase after carrying out different displacement measures. The viscoelastic and shearing effects of the polymeric surfactant flooding system can better displace the residual oil, assisting in the further development of heterogeneous low permeability reservoirs.

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Section: Experimental Designmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Study on Distribution Characteristics and Displacement Mechanism of Microscopic Residual Oil in Heterogeneous Low Permeability Reservoirs

2019

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“…For the digital core analysis, the representative elementary volume (REV) usually needs to be investigated, especially for the calculation of permeability and porosity. In this study however, our purpose is to find the heterogeneity in the core sample, and give the relation between porosity and permeability, which allows us to not consider the permeability-based REV and porosity-based REV [22]. In this study, real rock samples were taken, and core images were obtained by CT scanning technology.…”

Section: Introductionmentioning

confidence: 99%

The Investigation of Permeability Calculation Using Digital Core Simulation Technology

et al. 2019

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Digital core simulation technology, as an emerging numerical simulation method, has gradually come to play a significant role in the study of petrophysical properties. By using this numerical simulation method, the influence of micro factors on seepage properties of reservoir rock is taken into consideration, making up the shortcomings of the traditional physical experiment. Three-dimensional core images are reconstructed by a computed tomography scanning technique. Different sizes of the sub-region were simulated by three methods including the direct computation of Navier-Stokes equations, the simulation of the pore network model, and the lattice Boltzmann method. The permeability computed by each simulation was compared. After comparison between these three methods, the results of the direct computation method based on Navier-Stokes equations were found to be higher than the other two methods. The pore network model simulation has an obvious advantage on the computation speed and the simulation area. The lattice Boltzmann method shows the low efficiency due to the time-consuming process. At last, the permeability calculated by the three methods is matched by the Kozeny-Carman equation. A more accurate formula can be obtained by a series of numerical simulations, which can be applied to marco-scale simulation.

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“…Once the microemulsions are added to the treatment fluid, the aqueous‐oil‐surfactant mesophase causes water soluble “swollen micelles, or often referred to as water dilutable ‘oil‐in‐water droplet microemulsion’ or nanoemulsions.” These solvent‐laden swollen micelles can alter the adsorption/desorption kinetics between the surfactant and the formation surfaces to facilitate a more uniform coverage and improve penetration into the fracture and rock pore space (Javanbakht et al, ; Kharghoria et al, ; Penny et al, ). This article focuses on designing microemulsions formulated using water‐immiscible solvents and evaluating their efficacy for improved oil recovery during spontaneous imbibition.…”

Section: Introductionmentioning

confidence: 99%

Experimental Investigation into the Screening of New Surfactant Flowback Aids and Statistical Interpretation of Their Imbibing Capacity for Selected Core Substrates

Khamatnurova

Henkel

et al. 2019

J Surfact & Detergents

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Spontaneous imbibition is a pervasive part of many natural and industrial processes. As an inherent feature of fluid transport in porous media, it is a driver for oil recovery. Understanding spontaneous imbibition and leveraging surface science is fundamental for fluid recovery; specifically, the role of the surfactant in the imbibition processes and the potential to alter capillarity and wettability of reservoir rock. Surfactant success relies on the understanding of the factors governing the interfacial phenomena among crude oil, and formation properties under reservoir conditions. Developing a methodology coupling chemical performance with analytical techniques, and statistical interpretation of core/surfactant/oil interactions, can help establish workflows to advance new chemistries and enhance oil recovery. This article discusses a study of flowback aids formulated as microemulsions corresponding to the thermodynamically stable Winsor Type IV solutions. Neat formulated microemulsions, when dosed at field treatment concentrations, provide either oil‐in‐water droplet microemulsions or nanoemulsions. The solvency potential was measured, and the Kauri‐butanol (Kb) value was determined. Parameters such as critical micelle concentration (CMC) and interfacial tension (IFT) were determined to characterize microemulsion solutions. These systems were tested using either in the column flow test with formation material sieved to match mineral grain size, or sandstone cores of various permeabilities. The results indicate that surfactant‐based flow‐enhancing aids are desirable for improved oil recovery when compared to the control fluid. The statistical analysis of core‐fluid interaction includes an ANOVA followed by assumption evaluations and model interpretation, which demonstrates that the core permeability term, followed by the surfactant term, has the highest contribution whereas oil has no statistical significance to the model.

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Micro-scale displacement of NAPL by surfactant and microemulsion in heterogeneous porous media

Cited by 70 publications

References 42 publications

Study on Distribution Characteristics and Displacement Mechanism of Microscopic Residual Oil in Heterogeneous Low Permeability Reservoirs

Study on Distribution Characteristics and Displacement Mechanism of Microscopic Residual Oil in Heterogeneous Low Permeability Reservoirs

The Investigation of Permeability Calculation Using Digital Core Simulation Technology

Experimental Investigation into the Screening of New Surfactant Flowback Aids and Statistical Interpretation of Their Imbibing Capacity for Selected Core Substrates

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