Manipulating the Flow of Nanoconfined Water by Temperature Stimulation

Wu, Keliu; Chen, Zhangxin; Li, Jing; Xu, Jinze; Wang, Kun; Wang, Shuhua; Dong, Xiaohu; Zhu, Zhouyuan; Peng, Yan; Jia, Xiaohan; Li, Xiangfang

doi:10.1002/anie.201712915

Cited by 48 publications

(34 citation statements)

References 36 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Because of the formation of a depletion layer, it is difficult to directly determine the viscosity of water interfaces with hydrophobic nanotubes using an experiment or a MD method. Therefore, most of the conducted studies on the viscosity of water in nanotubes assumed arbitrary values of the interfacial viscosity of water 16,25,26,31,34,43 . Here, we provide an effective approach to determine the interfacial viscosity as well as the radial distribution of water’s viscosity in hydrophilic and hydrophobic nanotubes ( see Methods ).…”

Section: Resultsmentioning

confidence: 99%

“…The interfacial viscosity depends on the surface wettability 16,17,27,43 . For a superhydrophobic surface, the contact angle θ = 180° and .…”

Section: Methodsmentioning

confidence: 99%

“…For a superhydrophilic surface, θ = 0°. The contact angle can be linearly related to the water-surface interaction energy 16,17,27,43 . Therefore, with the linear interpolation between θ = 180° and for a superhydrophobic surface and θ ≅ 155° and for CNTs (these are the average values of θ and considered in literature), the following relation can be derived:where VPR is plotted as a function of the nanotube radius in Fig.…”

Section: Methodsmentioning

confidence: 99%

See 2 more Smart Citations

Fluidity and phase transitions of water in hydrophobic and hydrophilic nanotubes

Shaat

Zheng

2019

Sci Rep

View full text Add to dashboard Cite

We put water flow under scrutiny to report radial distributions of water viscosity within hydrophobic and hydrophilic nanotubes as functions of the water-nanotube interactions ( ), surface wettability ( θ ), and nanotube size ( R ) using a proposed hybrid continuum-molecular mechanics. Based on the computed viscosity data, phase diagram of the phase transitions of confined water in nanotubes is developed. It is revealed that water exhibits different multiphase structures, and the formation of one of these structures depends on R parameters. A drag of water flow at the first water layer is revealed, which is conjugate to sharp increase in the viscosity and formation of an ice phase under severe confinement (R ≤ 3.5 nm) and strong water-nanotube interaction conditions. A vapor/vapor-liquid phase is observed at hydrophobic and hydrophilic interfaces. A state of confinement is revealed at which water exhibits different multiphase structures under the same flow rate. The derived viscosity functions are used to accurately determine factors of flow enhancement/inhibition of confined water.

show abstract

Section: Resultsmentioning

confidence: 99%

“…The interfacial viscosity depends on the surface wettability 16,17,27,43 . For a superhydrophobic surface, the contact angle θ = 180° and .…”

Section: Methodsmentioning

confidence: 99%

Section: Methodsmentioning

confidence: 99%

See 1 more Smart Citation

Fluidity and phase transitions of water in hydrophobic and hydrophilic nanotubes

Shaat

Zheng

2019

Sci Rep

View full text Add to dashboard Cite

show abstract

“…This finding suggests that the salinity of fracturing fluid should be similar to that in the formation water to reduce the water absorption of Chang 7 shale in Ordos basin. 30–32…”

Section: Resultsmentioning

confidence: 99%

Effects of pore structure and salinity on the imbibition of shale samples using physical simulation and NMR technique: A case from Chang 7 shale, Ordos basin

et al. 2019

View full text Add to dashboard Cite

A novel experimental study is conducted to reveal the effect of pore structure and salinity on spontaneous imbibition of shale samples using field emission scanning electron microscopy and low-field nuclear magnetic resonance (NMR). Core samples selected from Chang 7 shale, Ordos basin, contain different proportions of mineral components and exhibit different pore structures, as demonstrated by scanning electron microscopy. During the imbibition process, T2 spectra are obtained for each core sample under different salinities and imbibition time periods using NMR. The results are then used to characterize and compare the water imbibition process in different shale samples, with a focus on investigating the effects of pore structure and salinity. The results show that the amount of absorption water is positively correlated with the development of microcracks and with large pores in shale samples. The shale samples are shown to develop more microcracks as the imbibition time increases and the salinity decreases. These microcracks can improve the samples’ capacity of imbibition effectively, therefore increasing water absorption. Moreover, it is indicated that the imbibition capacity increases with an increasing content of illite clay minerals in the shale samples. Furthermore, the greatest amount of adsorbed water is seen when the water salinity is as high as the synthetic formation water. This is important in choosing hydraulic fracturing fluids, knowing that high-salinity fracturing fluids can effectively reduce water absorption in shale, therefore contributing to low flow-back and better fracturing performance.

show abstract

“…To minimize the effects of non-Newtonian flow, including polymer solution shear thinning and heavy oil TPG, on polymer flooding in heavy oil reservoirs, some methods including applying shear resistant polymer and heavy oil TPG reduction methods have been proposed [61,62]. In the future, we will conduct experiments to extend and improve our understanding of this technology to the nanoconfined flow in unconventional reservoirs [63,64] based on the findings presented in this paper.…”

Section: Discussionmentioning

confidence: 99%

Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Xin

Chen

et al. 2018

Polymers

Self Cite

View full text Add to dashboard Cite

The flow of polymer solution and heavy oil in porous media is critical for polymer flooding in heavy oil reservoirs because it significantly determines the polymer enhanced oil recovery (EOR) and polymer flooding efficiency in heavy oil reservoirs. In this paper, physical experiments and numerical simulations were both applied to investigate the flow of partially hydrolyzed polyacrylamide (HPAM) solution and heavy oil, and their effects on polymer flooding in heavy oil reservoirs. First, physical experiments determined the rheology of the polymer solution and heavy oil and their flow in porous media. Then, a new mathematical model was proposed, and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed considering the non-Newtonian flow. The designed simulator was validated by comparing its results with those obtained from commercial software and typical polymer flooding experiments. The developed simulator was further applied to investigate the non-Newtonian flow in polymer flooding. The experimental results demonstrated that the flow behavior index of the polymer solution is 0.3655, showing a shear thinning; and heavy oil is a type of Bingham fluid that overcomes a threshold pressure gradient (TPG) to flow in porous media. Furthermore, the validation of the designed simulator was confirmed to possess high accuracy and reliability. According to its simulation results, the decreases of 1.66% and 2.49% in oil recovery are caused by the difference between 0.18 and 1 in the polymer solution flow behavior indexes of the pure polymer flooding (PPF) and typical polymer flooding (TPF), respectively. Moreover, for heavy oil, considering a TPG of 20 times greater than its original value, the oil recoveries of PPF and TPF are reduced by 0.01% and 5.77%, respectively. Furthermore, the combined effect of shear thinning and a threshold pressure gradient results in a greater decrease in oil recovery, with 1.74% and 8.35% for PPF and TPF, respectively. Thus, the non-Newtonian flow has a hugely adverse impact on the performance of polymer flooding in heavy oil reservoirs.

show abstract

Manipulating the Flow of Nanoconfined Water by Temperature Stimulation

Cited by 48 publications

References 36 publications

Fluidity and phase transitions of water in hydrophobic and hydrophilic nanotubes

Fluidity and phase transitions of water in hydrophobic and hydrophilic nanotubes

Effects of pore structure and salinity on the imbibition of shale samples using physical simulation and NMR technique: A case from Chang 7 shale, Ordos basin

Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Contact Info

Product

Resources

About