2019
DOI: 10.1007/s12517-019-4955-2
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Fracturing fluid retention in shale gas reservoirs:mechanisms and functions

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Cited by 19 publications
(14 citation statements)
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“…During the process of fracturing fluid flowback in a shale gas well, all kinds of damage factors are unavoidable and irreversible. Considering the difficulty of treatment and the negative impact on fracture damage of flowback fluids, the fracture forming capacity of the retained fracturing fluid should be actively developed . For instance, take advantage of the hydrophilicity of clay minerals and the unique structure of the organic–clay complex to redistribute the residual fracturing fluids in the shale matrix, achieving the goal of preventing formation damage.…”
Section: Resultsmentioning
confidence: 99%
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“…During the process of fracturing fluid flowback in a shale gas well, all kinds of damage factors are unavoidable and irreversible. Considering the difficulty of treatment and the negative impact on fracture damage of flowback fluids, the fracture forming capacity of the retained fracturing fluid should be actively developed . For instance, take advantage of the hydrophilicity of clay minerals and the unique structure of the organic–clay complex to redistribute the residual fracturing fluids in the shale matrix, achieving the goal of preventing formation damage.…”
Section: Resultsmentioning
confidence: 99%
“…Field data show that lower flowback rates generally result in higher gas production . A large number of studies have also confirmed that residual fracturing fluid can promote fracture propagation through water–rock interaction during shut-in .…”
Section: Introductionmentioning
confidence: 93%
“…where K w is water permeability, mD; μ w is water viscosity, Pa s; P c is capillary force, Pa; ⌀ is porosity; A c is imbibition crosssectional area, cm 2 ; S wf is the water saturation of the imbibition front; S wi is the initial water saturation; V imb is the volume of imbibed water, cm 3 ; and t is the imbibition time, s. Shale formation has a tremendous capacity for imbibition of water that is injected during MHF stimulation. 60,61 You et al 62 summarized the factors that promote imbibition, including well-developed bedding and natural fractures, ultralow initial water saturation, high content of clay mineral, high capillary pressure, dual-wettability (water and hydrocarbon), and high content of soluble salt. The initial water saturation, S wi , in the main shale gas production layer is usually less than 30−45% and much less than the irreducible water saturation (64− 80%).…”
Section: Feasibility Of Zfr Of Hydraulic Fracturing Fluidmentioning
confidence: 99%
“…Shale formation has a tremendous capacity for imbibition of water that is injected during MHF stimulation. , You et al summarized the factors that promote imbibition, including well-developed bedding and natural fractures, ultralow initial water saturation, high content of clay mineral, high capillary pressure, dual-wettability (water and hydrocarbon), and high content of soluble salt. The initial water saturation, S wi , in the main shale gas production layer is usually less than 30–45% and much less than the irreducible water saturation (64–80%). Bedding and micronatural fractures are well-developed in most gas shales, which possess an extremely high capillary force, P c , with the combination of nanopores ranging from 100 to 200 nm .…”
Section: Feasibility Of Zfr Of Hydraulic Fracturing Fluidmentioning
confidence: 99%
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