Water Loss Versus Soaking Time: Spontaneous Imbibition in Tight Rocks

Lan, Qing; Ghanbari, Ebrahim; Dehghanpour, Hassan; Hawkes, Robert

doi:10.1002/ente.201402039

Cited by 61 publications

(28 citation statements)

References 35 publications

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“…The wettability of shale reservoir rocks has been experimentally investigated by a number of researchers for shale rocks across the US (Odusina et al 2011;Wang et al 2012), Canada (Borysenko et al 2009;Makhanov 2013;Xu and Dehghanpour 2014;Lan et al 2014;Lan et al 2015), Australia , China (Liang et al 2016) and Poland (Ksiezniak et al 2015). Lan et al (2014;2015) studied the effect of wettability on the imbibition dynamics by comparing the behaviors of water and oil phases on rock samples from two shale plays in Western Canada, the Montney and Horn River. They observed that the oil completely spreads on the shale sample, while water droplets show a measurable contact angle that is greater than 37 o , therefore, they concluded that the observed wettability cannot be fully explained by the contact angle results.…”

Section: Wettabilitymentioning

confidence: 99%

A critical review of water uptake by shales

Singh

2016

Journal of Natural Gas Science and Engineering

231

146

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The shale boom in North America started more than a decade ago, however, the issue of substantial fracturing fluid loss inside shale did not draw much attention for a decade. In the past few years, many researchers conducted laboratory experiments to 1) observe various processes by which water imbibes into shale rocks, and 2) understand the mechanisms behind each process that contributes to fluid uptake in shale. Although there is consistency in most of the observations that control the liquid filling in shales, some issues remain in regards to wettability. Many mechanisms seem to be contributing to liquid filling in the laboratory experiments, but there is no consensus on the dominant mechanisms. Even though some observations from field provide consistent signatures, we do not yet have a verified answer for the geo-mechanisms behind those observations. This paper provides a critical review of the observations (laboratory and field), the mechanisms behind those observations, and the models to mimic the imbibition behavior of shales. In this regard, following contents are critically reviewed: 1) history of imbibition in shales, 2) laboratory observations, 3) field observations, 4) mechanisms of water imbibition in shales, and 5) simulation models. We also discuss evaporation of water in shale as an additional mechanism that has not been proposed before, but may be contributing to the loss of water in shale formations.

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Section: Wettabilitymentioning

confidence: 99%

A critical review of water uptake by shales

Singh

2016

Journal of Natural Gas Science and Engineering

231

146

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“…Experimental work can build on this knowledge to help understand the interactions between these different structural domains, in order to build an appropriate effective medium description of shale. In addition, multiphase flow in shales is an important area of study to understand fluid migration, and shed light on the fate of unrecovered fracturing fluids from stimulation operations and their effect on productivity (Lan et al 2014, Ghanbari andDehganpour 2015). Spontaneous fracturing fluid (mostly water) uptake by shales can be attributed to capillary forces, adsorption, or osmosis (Zhou et al 2016, Ghanbari andDehganpour 2015).…”

Section: Introductionmentioning

confidence: 99%

Permeability evolution of shale during spontaneous imbibition

Chakraborty

Karpyn

Liu

et al. 2017

Journal of Natural Gas Science and Engineering

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Shales have small pore and throat sizes ranging from nano to micron scales, low porosity and limited permeability. The poor permeability and complex pore connectivity of shales pose technical challenges to (a) understanding flow and transport mechanisms in such systems and, (b) in predicting permeability changes under dynamic saturation conditions. This study presents quantitative experimental evidence of the migration of water through a generic shale core plug using micro CT imaging. In addition, in-situ measurements of gas permeability were performed during counter-current spontaneous imbibition of water in nano-darcy permeability Marcellus and Haynesville core plugs. It was seen that water blocks severely reduced the effective permeability of the core plugs, leading to losses of up to 99.5% of the initial permeability in experiments lasting 30 days. There was also evidence of clay swelling which further hindered gas flow. When results from this study were compared with similar counter-current gas permeability experiments reported in the literature, the initial (base) permeability of the rock was found to be a key factor in determining the time evolution of effective gas permeability during spontaneous imbibition. With time, a recovery of effective permeability was seen in the higher permeability rocks, while becoming progressively detrimental and irreversible in tighter rocks. These results suggest that matrix permeability of ultra-tight rocks is susceptible to water damage following hydraulic fracturing stimulation and, while shut-in/soaking time helps clearing-up fractures from resident fluid, its effect on the adjacent matrix permeability could be detrimental.

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“…What’s more, capillary trapping, near fracture water-block and relative permeability reduction can also be the potential killer for oil and gas production 16–18 . At the same time, scholars also find that hydrocarbon production in Marcellus has significantly improved after undergo 6 months’ shut-ins after hydraulic fracturing 19 . Scholars always explain this phenomenon by near fracture water-block removal or aqueous phase redistribution due to capillary dominated spontaneous imbibition.…”

Section: Introductionmentioning

confidence: 93%

Permeability regain and aqueous phase migration during hydraulic fracturing shut-ins

Lei

Wang

et al. 2019

Sci Rep

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Hydraulic fracturing has become a key technology to economically extract oil and gas from unconventional reservoirs. During hydraulic fracturing, fluid loss and water invasion into formation can cause serious permeability reduction near fracture face. At the same time, field practice also showed that well shut-ins after hydraulic fracturing could significantly increase hydrocarbon outputs, whereas the inner mechanism still remains unknown. In this paper, firstly, we studied permeability reduction after water invasion and permeability enhancement after well shut-ins using a core flooding system. Then, to investigate the inner mechanism, we studied aqueous phase migration during shut-ins using nuclear magnetic resonance (NMR) method. Results showed that fluids invasion reduce matrix permeability while well shut-ins can improve permeability and this improvement depends on the length of shut-ins time. NMR results showed that aqueous phases mainly distribute in macropores and mesopores after water invasion, while in shut-ins period, these invaded aqueous phases redistribute and migrate from larger pore spaces to smaller ones. Aqueous phase redistribution and migration during shut-ins period can remove near fracture water-block, reduce capillary discontinuity and increase the relative permeability of hydrocarbon phase, and this is the reason for permeability enhancement and hydrocarbon output increase after well shut-ins.

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Water Loss Versus Soaking Time: Spontaneous Imbibition in Tight Rocks

Cited by 61 publications

References 35 publications

A critical review of water uptake by shales

A critical review of water uptake by shales

Permeability evolution of shale during spontaneous imbibition

Permeability regain and aqueous phase migration during hydraulic fracturing shut-ins

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