Effects of low-salinity water on the interface characteristics and imbibition process

Zhu, Di; Li, Binfei; Li, Haifeng; Li, Bo-Liang; Cao, Yuanbo; Li, Zhaomin

doi:10.1016/j.petrol.2021.109564

Cited by 28 publications

(8 citation statements)

References 35 publications

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“…The oil/brine IFT was lower than the oil/deionized water IFT. This behavior is consistent with many previous studies, in which the oil/brine IFT was significantly affected by brine composition, salinity, and oil composition. − The result shows that increasing the FM concentration caused a slight reduction in IFT. The 30 wt % FM solutions at different initial pH values, 6.1 and 7.0, had similar IFT values but resulted in markedly different oil recoveries (Figure ).…”

Section: Resultssupporting

confidence: 92%

Geochemical Impact of High-Concentration Formate Solution Injection on Rock Wettability for Enhanced Oil Recovery and Geologic Carbon Storage

Oyenowo,

Wang,

Mirzaei-Paiaman

et al. 2024

Energy Fuels

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This paper presents new data on core-scale wettability alteration of carbonate porous media with FM concentrations up to 30 wt % in NaCl brine. Experimental data from Amott tests, core floods, calcite dissolution experiments, and zeta potential measurements were analyzed to mechanistically understand the wettability alteration observed in the experiments. Static calcite dissolution tests showed that the degree of dissolution increased with increasing FM concentration in NaCl brine, even with an initially neutral pH. For example, the calcium concentration in the 30 wt % FM solution was 15.9 times greater than that in the NaCl brine with an initial pH of 7.0. Furthermore, reducing the initial solution pH from 7.0 to 6.1 for the 30 wt % FM solution caused the calcium ion concentration to increase by a factor of 3.2. Geochemical modeling and Raman analysis indicated that increased calcite dissolution was caused by interactions between calcium and FM ions. The 30 wt % FM solution with an initial pH of 6.1 yielded 4.7 times greater oil recovery than the NaCl brine in the spontaneous imbibition. The resulting Amott index indicated the wettability alteration to a water-wet state by the FM solution. The 30 wt % FM solution with an initial pH of 7.0 yielded only 30% greater oil recovery than the brine in the spontaneous imbibition; however, it reached nearly the same total oil recovery (spontaneous and forced) as the 30 wt % FM solution with an initial pH of 6.1. A numerical model was calibrated using core flood data, based on which the relative permeabilities indicated the core-scale wettability alteration by FM solutions. Results showed that increasing the FM concentration in the injection brine rendered the initially oil-wet core to a more water-wet state and that the in situ solution pH played an important role in wettability alteration by FM solution in carbonate media.

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Section: Resultssupporting

confidence: 92%

Geochemical Impact of High-Concentration Formate Solution Injection on Rock Wettability for Enhanced Oil Recovery and Geologic Carbon Storage

Oyenowo,

Wang,

Mirzaei-Paiaman

et al. 2024

Energy Fuels

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“…In the experimental pressure range of 5 to 15 MPa, the imbibition recovery remained constant with the increase in pressure. To analyze pressure's impact on fracturing fluid percolation recovery further, we compared the degree of mobilization of each pore at different experimental pressures (Figures [12][13][14][15]. The experimental results reveal a consistent pattern in the mobilization degree of each pore space under varying pressures, with micropores exhibiting the highest degree of mesopores and macropores displaying the lowest.…”

Section: Distribution Characteristics Of T 2 Spectra Of Different Coresmentioning

confidence: 99%

“…Tight reservoirs are usually produced after a single large-scale volume fracturing, and the depletion development model is adopted in the later stage [10]. The effect of volume fracturing is not only reflected in the hydraulic fracture reconstruction of reservoir rocks within the fracturing construction cycle but also reflected in the hydration imbibition of reservoir rocks in a more extended period so that it can improve the matrix porosity and permeability of the imbibition sweep range of fracturing fluid [11][12][13][14][15]. The minimal radius of the throat in tight reservoirs enhances the capillary imbibition during the whole life cycle of fracturing development, which provides a new method for the synergism of fracturing imbibition, energy enhancement, and oil displacement to enhance oil recovery [16][17][18].…”

Section: Introductionmentioning

confidence: 99%

Investigating the Influencing Factors of Imbibition of Fracturing Fluids in Tight Reservoirs

Liu,

Qu,

Wang

et al. 2024

Processes

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Tight reservoirs are the focus of unconventional oil and gas resource development, but most tight reservoirs exhibit complex pore structures, strong non-homogeneity, and limited water drive development. Fracturing fluid imbibition is a critically important way to improve the recovery of tight reservoirs. In this paper, an NMR experimental device was used to conduct imbibition experiments in tight reservoirs, and the relationship between temperature, pressure, matrix permeability, and imbibition recovery was investigated. Based on the fracturing fluid imbibition recovery curve, the imbibition process is divided into the fast imbibition stage, slow imbibition stage, and imbibition equilibrium. In addition, based on the pore structure division, the recovery changes of each pore under different experimental conditions were quantitatively analyzed. The results indicate that the highest imbibition recovery is achieved at an experimental pressure of 5 MPa within the range of 0 MPa to 15 MPa. Increasing the experimental pressure can increase the imbibition rate but will not increase imbibition recovery. Within the investigated range in this paper, fracturing fluid imbibition increases with rising temperature and matrix permeability. Moreover, the recovery of each pore gradually increases with the experimental pressure ranging from 0 MPa to 5 MPa. The recovery of each pore is positively correlated with matrix permeability and temperature. During the experiment, micropores contributed the most to the recovery, while macropores contributed the least. The study in this paper guides the efficient development of tight reservoirs.

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“…However, when considers these microscopic mechanisms contributed from two types of brine, their contributions are inconsistent or even conflict and hence designing brine fluids for EOR are such a dilemmatic challenge [17]- [19]. Recent works confirms that monovalent brines could promote a strong water-wet system due to repulsive hydration forces constructed between oil-brine and brine-rock interfaces [15], [20] rather than multivalent brines that tend to bridge crude oil components onto rock surfaces [21], [22], while divalent brines were found to be more effective than monovalent species on reducing the 𝜎 due to a stronger screening of electrostatic repulsion between polar species at the oil-water interface [23] Research on NaCl and CaCl2 brines highlighted their distinguish contributions to spontaneous imbibition process, which low-concentration NaCl brines displaced highest oil recoveries [16], [24]. The studies concluded that changes in wettability and 𝜎 were EOR mechanisms, and a role of resulted capillary force was discussed to control the displacement behavior [25].…”

Section: Introductionmentioning

confidence: 99%

Effects of brine valency and concentration on oil displacement by spontaneous imbibition: An interplay between wettability alteration and reduction in the oil-brine interfacial tension

Sukee

Nunta

Nawamin

et al. 2022

Journal of Molecular Liquids

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Effects of low-salinity water on the interface characteristics and imbibition process

Cited by 28 publications

References 35 publications

Geochemical Impact of High-Concentration Formate Solution Injection on Rock Wettability for Enhanced Oil Recovery and Geologic Carbon Storage

Geochemical Impact of High-Concentration Formate Solution Injection on Rock Wettability for Enhanced Oil Recovery and Geologic Carbon Storage

Investigating the Influencing Factors of Imbibition of Fracturing Fluids in Tight Reservoirs

Effects of brine valency and concentration on oil displacement by spontaneous imbibition: An interplay between wettability alteration and reduction in the oil-brine interfacial tension

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