Investigation of multiphase fluid imbibition in shale through synchrotron‐based dynamic micro‐CT imaging

Peng, Sheng; Xiao, Xianghui

doi:10.1002/2017jb014253

Cited by 64 publications

(23 citation statements)

References 36 publications

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“…Only less than 15 % of the fracture is filled by water, which shows its dominant oil‐wetting tendency. Peng and Xiao imbibition experiments via the dynamic imaging of multi‐phase fluid imbibition through the Eagle Ford shale support our results, as it indicates that the microfractures in Eagle Ford shale are generally oil‐wet. In the next step, we marginally increase the water pressure to simulate the early stages of the forced imbibition.…”

Section: Workflow Of Numerical Simulationsupporting

confidence: 77%

“…Oil fills back the oil‐wet sections and the residual water mostly remains in the larger pores surrounded by oil, see Figure . The observations made by Peng and Xiao during immiscible oil and water displacements illustrate similar oil‐water residual patterns. By post‐processing the phase profiles and calculating the effective permeabilities, the tortuosity parameter (α) throughout the microfracture for both phases approaches zero.…”

Section: Workflow Of Numerical Simulationsupporting

confidence: 58%

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Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

Mohammadmoradi

Kantzas

2018

Can J Chem Eng

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Shale matrix water intake during hydraulic fracturing is considered undesirable due to the high volume of unrestrained water loss; however, it is also rewarding because it can reduce the possibility of groundwater contamination. The water intake also plays a dual role in changing the shale production performance; water imbibition into matrix pores can dramatically reduce the effective permeability and, at the same time, might enhance hydrocarbon production by creating adsorption-induced micro-fractures. Quantifying the formation intake capacity and its breadth is the key to optimizing fracturing operation, flowback, and production strategy. This work entails complementary semi-analytical and numerical analyses and investigates the effects of basic rock and fluid properties, wettability heterogeneity, and pore space connectivity on the shale imbibition characteristics. We consider a semi-analytical formulation of the spontaneous water imbibition, together with model results and validations, and try to provide a framework to link the capillary imbibition capacity/rate to lab-scale observations. The core-scale measurements provide input for a sensitivity study on the matrix imbibition capacity in six shale plays in North America. The results suggest that rock permeability, hydraulic tortuosity, and initial and residual hydrocarbon saturations are among the most influential factors on the spontaneous water intake during shut-in periods. Direct quasi-static simulations are then conducted through a submicron tomography image of the Eagle Ford shale, and two-phase pore-level fluid occupancies are reconstructed during spontaneous and forced imbibition processes. According to the numerical results, the presence of continuous organic matter laminae can lower the destructive effects of water imbibition on the hydrocarbon permeability.

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Section: Workflow Of Numerical Simulationsupporting

confidence: 77%

Section: Workflow Of Numerical Simulationsupporting

confidence: 58%

Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

Mohammadmoradi

Kantzas

2018

Can J Chem Eng

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“…Therefore, the proportion of macropores of coal is highly correlated to the TPI, and TPI could indicate the seepage characteristics of coal. The paleo-environment governs the degree of pore development by affecting the petrographic composition and content of macerals [12,[52][53][54][55][56][57][58]. Zhang et al studies have found that the macro-and mesopores are closely correlated to TPI with the R-cluster analysis method, while there are no data to support the specific relationship between pore and coal facies [20].…”

Section: Characteristics Of Coal Faciesmentioning

confidence: 99%

Pore-Fractures of Coalbed Methane Reservoir Restricted by Coal Facies in Sangjiang-Muling Coal-Bearing Basins, Northeast China

Liu

Cai

et al. 2020

Energies

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The pore-fractures network plays a key role in coalbed methane (CBM) accumulation and production, while the impacts of coal facies on the pore-fractures network performance are still poorly understood. In this work, the research on the pore-fracture occurrence of 38 collected coals from Sangjiang-Muling coal-bearing basins with multiple techniques, including mercury intrusion porosimetry (MIP), micro-organic quantitative analysis, and optic microscopy, and its variation controlling of coal face were studied. The MIP curves of 38 selected coals, indicating pore structures, were subdivided into three typical types, including type I of predominant micropores, type Ⅱ of predominant micropores and macropores with good connectivity, and type Ⅲ of predominant micropores and macropores with poor connectivity. For coal facies, three various coal facies were distinguished, including lake shore coastal wet forest swamp, the upper delta plain wet forest swamp, tidal flat wet forest swamp using Q-cluster analysis and tissue preservation index–gelification index (TPI-GI), and wood index–groundwater influence index (WI-GWI). The results show a positive relationship between tissue preservation index (TPI), wood index (WI), and mesopores (102 nm–103 nm), and a negative relationship between TPI, WI, and macropores/fractures. In addition, groundwater level fluctuations can control the development of type C and D fractures, and the frequency of type C and D fractures show an ascending trend with increasing groundwater index (GWI), which may be caused by the mineral hydration of the coal. Finally, from the perspective of the pore-fractures occurrence in CBM reservoirs, the wet forest swamp of upper delta plain is considered to be the optimization areas for Sangjiang-Muling coal-bearing basins by a comparative study of various coal facies.

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“…The tracer and micro-CT experiment was carried out using the synchrotron-based micro-CT imaging facility at beamline 2-BM of the Advanced Photon Source at Argonne National Laboratory. The basic steps are similar to those in Peng and Xiao (2017). One change is on the exposure time of each projection, which is extended to 160 ms from 100 ms in our previous work.…”

Section: Oil-phase Tracer Imbibition and Micro-ct Imagingmentioning

confidence: 99%

“…This method is applied to five samples from Wolfcamp and Eagle Ford Formations. This study builds on our previous work, in which the focus is mostly on water/oil displacement in microfractures and matrix in shale using only micro-CT and tracer imbibition (Peng & Xiao, 2017).…”

Section: Introductionmentioning

confidence: 99%

Tracer‐Guided Characterization of Dominant Pore Networks and Implications for Permeability and Wettability in Shale

et al. 2019

Self Cite

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Pore network characterization is an important aspect in unconventional reservoir evaluation. While application of the technique of scanning electron microscope (SEM) brings substantial advances in pore characterization in shale, understanding the connected pore network that dominates flow in shale samples is limited by using SEM alone because of small fields of view and lack of views of connectivity in 3D. In this research, a technique integrating tracer imbibition, micro‐computed tomography (CT) imaging, and SEM imaging was developed to provide a solution for multiscale imaging in shale. Tracer imbibition indicates pore connectivity; micro‐CT imaging after tracer imbibition thus provides an overview of the connected pore network at the millimeter scale. With guidance from micro‐CT images after tracer imbibition, a more accurate and detailed characterization of pore systems and related mineralogy can be conducted using higher‐resolution SEM. The method was applied to five samples from Wolfcamp and Eagle Ford Formations. Results reveal the effectiveness of the integrated method by showing different patterns of distribution of the dominant pore network and different controlling mineralogy. Dominant porosity, estimated from grayscale analyses, displays a good correlation with permeability. This result indicates that dominant porosity is more relevant to permeability than is total porosity. Results from imbibition tests are also compared with that from contact angle measurement, and important implications on wettability can be obtained. The integrated method thus has the capacity to link the dominant pore network and wettability with microscale to submicroscale mineralogy, which can help better understand the pore systems and fluid flow in shale.

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Investigation of multiphase fluid imbibition in shale through synchrotron‐based dynamic micro‐CT imaging

Cited by 64 publications

References 36 publications

Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

Pore-Fractures of Coalbed Methane Reservoir Restricted by Coal Facies in Sangjiang-Muling Coal-Bearing Basins, Northeast China

Tracer‐Guided Characterization of Dominant Pore Networks and Implications for Permeability and Wettability in Shale

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