The increased viscosity effect for fracturing fluid imbibition in shale

Zhang, Linyang; Wu, Keliu; Chen, Zhangxin; Li, Jing; Yu, Xinran; Hui, Gang; Yang, Min

doi:10.1016/j.ces.2020.116352

Cited by 13 publications

(8 citation statements)

References 88 publications

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“…71 Similarly, the research on the influence of moisture on coal adsorption and permeability is also deepening gradually, beginning with the influence of water on gas adsorption 16,17 and subsequently considering the capillary condensation of water in matrix pores, including the influence of fracture water film, before, finally, revealing the impact mechanisms between water film and coal permeability. 46 At present, most of the study on water film has been based on compacted rock samples, such as shale, 74,75 and research conclusions only revealed the close relationship between water film thickness and relative humidity or water saturation in the samples. 18,76 In this section, the influence of stress and adsorption on water film thickness will be discussed, and finally, the complex relationship between stress, adsorption, water film thickness, permeability, and the contribution of matrix permeability and fracture permeability to resultant permeability will be revealed.…”

Section: Discussionmentioning

confidence: 99%

A Study of the Dynamic Changes in Wet Coal’s Water Film and Permeability under Stressed Conditions

Cheng

et al. 2022

Energy Fuels

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Coal permeability is an important influential factor in the efficient development and utilization of coalbed methane (CBM); however, coal is in an environment of combined gas and water and is exposed to continuous reservoir pressure for considerable periods, which makes permeability changes in its natural state extremely complicated and those changes difficult to evaluate. In this study, we established a dual-porosity permeability model suitable for wet coal that considered the influence of stress and gas adsorption. In the process of modeling, the shapes of the matrix pores and fractures were simplified into regular cylindrical and slit; based on the generalized Hooke’s law, the effective stress–strain relationship of the coal matrix and fracture was represented; meanwhile, the adsorption capacity decay coefficient λ was introduced to describe the influence of moisture on gas adsorption; and then changes in the pore radius and fracture width under the action of stress and gas adsorption were quantified. Moreover, the interaction between the water film and the pore wall and the influence of stress and gas adsorption in the natural reservoir environment were considered, relating to the dynamic water film calculation formula in matrix pores and fractures under the influence of stress and gas adsorption that was derived, revealing the dynamic evolution law of water film thickness under the action of stress and gas adsorption. By combining the above influential factors and based on the relationship between permeability–porosity–pore radius (fracture width), a dual-porosity permeability model that considered the effects of stress, gas adsorption, and dynamic water film combinations was established. Further, we compared the predicted results of this model with published experimental data and discuss the influence of stress and gas adsorption on water film thickness and the contribution of matrix permeability and fracture permeability to resultant permeability under different water saturations. The complex variation of wet coal permeability under stress and gas adsorption is revealed.

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Section: Discussionmentioning

confidence: 99%

A Study of the Dynamic Changes in Wet Coal’s Water Film and Permeability under Stressed Conditions

Cheng

et al. 2022

Energy Fuels

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“…Moreover, the higher the saturated hydrocarbon content, the lower the viscosity is (Figure 2), exhibiting an obvious negative correlation with a correlation coefficient R 2 of 0.86. Studies have shown that for crude oil, the higher the content of the saturated hydrocarbon, the lower the viscosity, and the easier it is to extract it from underground reservoirs (Boak and Kleinberg, 2020;Zhang et al, 2021).…”

Section: Saturated Hydrocarbonmentioning

confidence: 99%

Experimental Methods for the Quantitative Assessment of the Volume Fraction of Movable Shale Oil: A Case Study in the Jimsar Sag, Junggar Basin, China

Zhao

Hou

et al. 2021

Front. Earth Sci.

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Deep insights into the movability of the retained shale oil are of great significance to shale oil. Rock and crude oil samples were collected from well J174 in the Jimsar Sag, Junggar Basin. Rock samples were subjected to different extraction followed by analysis of the component in the extracts, and measurement of porosity in conjunction with nuclear magnetic resonance and high-pressure mercury injection analysis. The results of these analyses were used to establish an experimental method for quantitative assessment of movable shale oil. The extract content of the component varied among different extraction and between mud shale and non-mud shale samples. The saturated hydrocarbon in the extracts of the mud shale was similar to those of the non-mud shale after extraction with CHCl3 alone or after sequential extraction with nC6 + CHCl3. The aromatic hydrocarbon in the extract were significantly lower for the mud shale than for the non-mud shale after extraction with nC6, but the opposite was observed after sequential extraction with nC6 + CHCl3. The contents of the non-hydrocarbon in the extract were significantly lower for the mud shale than for the non-mud shale after extraction with nC6, but the opposite was observed after extraction with CHCl3 or nC6 + CHCl3. The contents of the asphaltene in the extract were not significantly different for the mud shale and non-mud shale after extraction with nC6, but the contents were higher for the mud shale than for the non-mud shale after extraction with nC6 + CHCl3 or CHCl3. The viscosity of the crude oil was negatively correlated with the saturated hydrocarbon, was positively correlated with the aromatic hydrocarbon and non-hydrocarbon, and was not correlated with the asphaltene. For the mud shale and non-mud shale, their porosity after extraction with nC6 or CHCl3 was higher than their original porosity. Moreover, their porosity after extraction with CHCl3 was higher than after extraction with nC6. The movable oil was significantly correlated with the lithology, with sandstone allowing for a higher fluid movability than mud shale and dolomite allowing for a higher fluid movability than siliceous rocks.

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“…Shale reservoirs contain not only rich organic matter but also different proportions of inorganic minerals (e.g., calcite, quartz, and clay), so they have mixed wettability. − These particularities make the imbibition mechanism of the fracturing fluid in shale reservoirs extremely complex. Some researchers believe that a low flowback rate indicates that the fracturing performance of horizontal wells is satisfactory and a large number of network fractures have been created in the reservoir, increasing the oil drainage area. ,, These phenomena indicate that imbibition plays an important role in shale oil developments regardless of the arguments for its positive or negative effects. Therefore, understanding the imbibition mechanisms of fracturing fluid in shale oil formations can lay a solid foundation for the effective exploitation of such reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

et al. 2023

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The breakthrough of shale oil in North America led to a worldwide energy revolution. Shale reservoirs show multiscale properties and a large proportion of nanopores compared to conventional reservoirs, which makes the imbibition mechanisms of fracturing fluids within shale reservoirs exceptionally complicated. For instance, the fracturing fluid shows a distinct imbibition behavior at different scales. Traditional models face significant challenges in imbibition characterization. Understanding the imbibition mechanisms in shale oil formations from a multiscale perspective can help to make full use of the positive effect and enhance oil recovery. We review imbibition mechanisms in shale reservoirs from the nanoscale to the reservoir scale. The imbibition principles in a single nanopore and the improvement of the traditional characterization models are clarified. Then, at the pore scale, we elaborate on the imbibition laws obtained from the microfluidic chip, pore network model, and direct simulations. We also outline the imbibition dynamics at the core scale, the influences of capillary forces and osmotic pressure, and the variations of the pore structure. Finally, the imbibition behavior at the reservoir scale and field examples considering the imbibition effect are introduced. We analyze the existing problems on each scale and discuss the future trends in this area. This work is expected to help readers systematically understand the mechanisms and behavior of fracturing fluid imbibition in shale oil reservoirs at different scales and accelerate the exploitation of shale resources.

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The increased viscosity effect for fracturing fluid imbibition in shale

Cited by 13 publications

References 88 publications

A Study of the Dynamic Changes in Wet Coal’s Water Film and Permeability under Stressed Conditions

A Study of the Dynamic Changes in Wet Coal’s Water Film and Permeability under Stressed Conditions

Experimental Methods for the Quantitative Assessment of the Volume Fraction of Movable Shale Oil: A Case Study in the Jimsar Sag, Junggar Basin, China

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

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