The low salinity effect at high temperatures

Xie, Quan; Brady, Patrick V.; Pooryousefy, Ehsan; Zhou, Deyun; Liu, Yongbing; Saeedi, Ali

doi:10.1016/j.fuel.2017.03.088

Cited by 92 publications

(53 citation statements)

References 43 publications

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“…Similarly, 5 wt % NaCl showed a BPS of 4 (µmol/m 2 ) 2 , but CaCl 2 showed a BPS of 4.7 (µmol/m 2 ) 2 at the same concentration. Similar results were also reported by Brady et al [35], who showed that, at the same salinity level (142,430 mg/L), formation brine (with presence of divalent cations) triggers a greater BPS compared to softened brine (same salinity as formation brine, but with absence of divalent cations). Therefore, we believe that injecting low salinity water or remove divalent cations from the hydraulic fracturing fluids likely causes a strong water-wet system, thus prevails water uptake due to capillary pressures acting as driving forces.…”

Section: Surface Complexation Modellingsupporting

confidence: 90%

“…Similar results were also observed by Brady et al [20] who showed that increasing pH from 4 to 9 triggers BPS decreasing from 0.42 to almost 0 µmol/m 2 using an oil with AN/BN = 0. Likewise, Xie et al [35] showed that BPS decreases from 2.8 to 1.6 µmol/m 2 with pH increases from 7 to 10 using an oil with AN = 3.98 and BN = 1.3 mg KOH/g. Together, BPS results suggest that increasing pH likely decreases the adhesion between oil/brine and brine/kaolinite, thus a more water-system, which in return facilitates water uptake in shales because capillary forces would be driving forces.…”

Section: Surface Complexation Modellingmentioning

confidence: 92%

“…The bond product sum counts the number of electrostatic connections between the two. Surface complexation modelling (and DLVO theory) presumes an electric double layer at each interface and the existence of charged surface species whose concentrations depend upon the chemical makeup of the water and the oil and mineral surface [35]. In the surface complexation model, the kaolinite surface area was assumed as 10 m 2 /g with site density of 10 µmol/m 2 [36].…”

Section: Surface Complexation Modellingmentioning

confidence: 99%

“…The chemical reactions on the surface of kaolinite can be described by the reactions in Table 1. We used 25 • C Log K for all of the chemical reactions in Table 1 because water chemistry dominates the surface complexation of the oil/brine/rock system and temperature plays a secondary effect [35]. The surface species concentrations were calculated using PHREEQC version 3.3.9 (Parkhurst and Appelo 2013) and a diffuse layer surface model.…”

Section: Surface Complexation Modellingmentioning

confidence: 99%

“…Surface complexation shows that divalent cations (Ca 2+ and Mg 2+ ) electrostatically linked oil and clays [35]. Together, increasing divalent cations (Ca 2+ and Mg 2+ ) increases oil-clay adhesion, thereby producing a more oil-wet system.…”

Section: Implications and Conclusionmentioning

confidence: 99%

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Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

et al. 2018

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Abstract:Hydraulic fracturing technique is of vital importance to effectively develop unconventional shale resources. However, the low recovery of hydraulic fracturing fluids appears to be the main challenge from both technical and environmental perspectives in the last decade. While capillary forces account for the low recovery of hydraulic fracturing fluids, the controlling factor(s) of contact angle, thus wettability, has yet to be clearly defined. We hypothesized that the interaction of oil/brine and brine/rock interfaces governs the wettability of system, which can be interpreted using Derjaguin-Landau-Verwey-Overbeek (DLVO) and surface complexation modelling. To test our hypothesis, we measured a suit of zeta potential of oil/brines and brine/minerals, and tested the effect of ion type (NaCl, MgCl 2 and CaCl 2 ) and concentrations (0.1, 1, and 5 wt %). Moreover, we calculated the disjoining pressure of the oil/brine/mineral systems and compared with geochemical modelling predictions. Our results show that cation type and salinity governed oil/brine/minerals wettability. Divalent cations (Ca 2+ and Mg 2+ ) compressed the electrical double layer, and electrostatically linked oil and clays, thus increasing the adhesion between oil and minerals, triggering an oil-wet system. Increasing salinity also compressed the double layer, and increased the site density of oppositely charged surface species which made oil and clay link more strongly. Our results suggest that increasing salinity and divalent cations concentration likely decrease water uptake in shale oil reservoirs, thus de-risking the hydraulic fracturing induced formation damage. Combining DLVO and surface complexation modelling can delineate the interaction of oil/brine/minerals, thus wettability. Therefore, the relative contribution of capillary forces with respect to water uptake into shale reservoirs, and the possible impairment of hydrocarbon production from conventional reservoirs can be quantified.

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Section: Surface Complexation Modellingsupporting

confidence: 90%

Section: Surface Complexation Modellingmentioning

confidence: 92%

Section: Surface Complexation Modellingmentioning

confidence: 99%

Section: Surface Complexation Modellingmentioning

confidence: 99%

Section: Implications and Conclusionmentioning

confidence: 99%

See 3 more Smart Citations

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

et al. 2018

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The Comprehensive Study of the Connate Water Chemical Composition Effect on Oil Recovery in Carbonate Rocks

Nugraha

Wang

2021

Proceedings of the International Petroleum and Petrochemical Technology Conference 2020

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Wettability alteration process at pore-scale during engineered waterflooding using computational fluid dynamics

Chen

Chang

et al. 2022

Model. Earth Syst. Environ.

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Engineered waterflooding modifies chemistry of injected brine to efficiently and environmentally friendly enhance oil recovery. The common practice of engineered waterflooding includes low salinity waterflooding (LSW) and carbonated waterflooding. Among these oil recovery methods, wettability alteration has been perceived as a critical physicochemical process for additional oil recovery. While extensive work has been conducted to characterize the wettability alteration, the existing theory cannot explain the conflict oil recovery between secondary mode (injecting engineered water at the very beginning of flooding) and tertiary mode (injecting engineered water after conventional waterflooding), where secondary engineered waterflooding always gives a greater incremental oil recovery than tertiary mode. To explain this recovery difference, a preferential flow channel was hypothesized to be created by secondary flooding, which likely reduces sweep efficiency of tertiary flooding. To test this hypothesis, computational fluid dynamic simulations were performed with finite volume method coupled with dynamic contact angles in OpenFOAM to represent wettability characteristics (from strongly oil-wet to strongly water-wet) at pore scale to quantify the role of pre-existing flow channel in the oil recovery at different flooding modes. The simulation results showed that secondary engineered waterflooding indeed generates a preferential flow pathway, which reduces recovery efficiency of subsequent tertiary waterflooding. Streamline analysis confirms that tertiary engineered waterflooding transports faster than secondary engineered waterflooding, implying that sweep efficiency of tertiary engineered waterflooding is lower than secondary engineered waterflooding. This work provides insights for a greater oil recovery at secondary mode than tertiary mode during engineered waterflooding at pore scale.

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The low salinity effect at high temperatures

Cited by 92 publications

References 43 publications

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

The Comprehensive Study of the Connate Water Chemical Composition Effect on Oil Recovery in Carbonate Rocks

Wettability alteration process at pore-scale during engineered waterflooding using computational fluid dynamics

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