Quantitative validation of pore structure characterization using gas slippage measurements by comparison with predictions from bundle of capillaries models

Letham, Eric Aidan; Bustin, R. Marc

doi:10.1016/j.marpetgeo.2018.01.014

Cited by 6 publications

(6 citation statements)

References 21 publications

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“…We have calculated the mean hydraulic radius of many capillaries with noncircular cross-section shape and found that all of the exponent values in the slippage factor equations are equal to −0.5 for capillaries with regular pore shape. By compiling a large data set of permeability measurements, Letham and Bustin found that pores in relatively high permeable rocks tend to be slit-shaped and pores in low permeable rocks are more circular . These agree with the pore morphology of organic matter in overmature shales .…”

Section: Theory and Model Developmentsupporting

confidence: 53%

“…The slippage factor for helium is always observed to be larger than that for nitrogen in coals and gas shales . Apart from the physical property of the probing gas and experimental conditions, the distribution and interconnectivity of pores (i.e., tortuosity and accessibility) also play an important role in apparent permeability and gas slippage. , …”

Section: Introductionmentioning

confidence: 99%

“…22 Apart from the physical property of the probing gas and experimental conditions, the distribution and interconnectivity of pores (i.e., tortuosity and accessibility) also play an important role in apparent permeability and gas slippage. 23,24 The gas slippage phenomenon was first studied by Kundt and Warburg. 25 Afterward, Klinkenberg applied Kundt and Warburg's observations and interpretations to reservoir rocks and found a linear relationship between the apparent gas permeability coefficients and the reciprocals of the average pore pressures.…”

Section: Introductionmentioning

confidence: 99%

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Experimental Investigation about Gas Transport in Tight Shales: An Improved Relationship between Gas Slippage and Petrophysical Properties

et al. 2021

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This study presents both experimental and theoretical investigations about gas transport in shales. Gas apparent permeability coefficients and Klinkenberg slippage factors were determined on Longmaxi shales using He, Ar, N2, CH4, and CO2. Then, a model was developed to interpret the experimentally determined gas slippage factor, considering the effects of intrinsic permeability, porosity, tortuosity, and gas physical properties. The proposed model is verified by correlating Klinkenberg-corrected permeabilities and gas slippage factors of shales probed by He, Ar, N2, CH4, and CO2 at different confining pressures. The model can quantitatively describe the gas dependence of slippage factors (He > Ar > N2 > CH4 > CO2). According to the model presented, the slippage factor increases proportionally to the ratio of the characteristic gas parameter (C ) to tortuosity. The model also leads to a practicable approach to determine the effective tortuosity of tight rocks at in situ reservoir stress state. Effective tortuosity of shales determined using helium slippage measurements are far larger than the generally assumed values. Another advantage of the model is its ability to quantitatively account for the variation in permeability values at similar gas slippage and the counterintuitive reduction in gas slippage during compaction observed in previous experiments. The proposed model correctly matches a set of gas slippage measurements and provides insight into gas transport in tight porous medium.

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Section: Theory and Model Developmentsupporting

confidence: 53%

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Experimental Investigation about Gas Transport in Tight Shales: An Improved Relationship between Gas Slippage and Petrophysical Properties

et al. 2021

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“…Note that eq provides estimates of effective polymer thickness ratio and it involves parameters e and r (from eqs and ), which, in turn, are based on the bundle-of-capillary-tubes model. However, these equations are still valid to evaluate the effect of pore size (including a layer of adsorbed polymer) on fluid distribution in porous media, both qualitatively and quantitatively. − …”

Section: Methodsmentioning

confidence: 99%

Low-Salinity-Assisted Cationic Polyacrylamide Water Shutoff in Low-Permeability Sandstone Gas Reservoirs

et al. 2020

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The application of polymer-based relative permeability modifiers (RPM) in low-permeability sandstone reservoirs has long intrigued production engineers. We hypothesize that lowering salinity may expand the application of the cationic polyacrylamide (CPAM) in low-permeability sandstone gas reservoirs, because of the favorable polymer–polymer physiochemical interaction at pore surfaces. To test this hypothesis, we conducted six core-flooding experiments to examine the relative permeabilities of water/gas before and after CPAM treatment, as a function of salinity using sandstone core plugs. Moreover, we measured zeta potentials of polymer–polymer, rock–polymer, and rock–brine interfaces before and after the RPM treatment, as a function of salinity. We also measured the contact angles for silicate/brine systems before and after the treatment as a function of salinity. Core-flooding results show that reducing the salinity decreases the water relative permeability but with marginal effect on the gas relative permeability. Lowering salinity also decreases the effective polymer layer thickness at pore surfaces. Moreover, the adsorption of the CPAM onto the negatively charged sandstone rock, together with lowering brine salinity, increases hydrophobicity of the rock. Thus, our results suggest that polymer–polymer interactions at pore surfaces govern the performance of CPAM in low-permeability sandstone rocks.

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“…The gas slip factor, a measure of the average transport pore size, determined with helium is 3.47 MPa and thus well within the range of values for shales reported in other studies. Slip factors range mostly from 1.5 to 6 MPa with the highest published value of 8.6 MPa (Heller et al 2014;Ghanizadeh et al 2014a, b;Fink et al 2017aFink et al , 2018Letham and Bustin 2018;Gaus et al 2019;Nolte et al 2019;Shabani et al 2020). Of course, the results obtained with this "ideal" system should only be applied to natural tight rock systems that have similar transport properties.…”

Section: Implications Of Fluid Flow Tests On Analogue Porous Media Fomentioning

confidence: 97%

Experimental Investigation of Gas Dynamic Effects Using Nanoporous Synthetic Materials as Tight Rock Analogues

et al. 2021

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To improve the understanding of gas transport processes in tight rocks (e.g., shales), systematic flow tests with different gases were conducted on artificial micro- to nanoporous analogue materials. Due to the rigidity of these systems, fluid-dynamic effects could be studied at elevated pressures without interference of poro-elastic effects. Flow tests with narrow capillaries did not reveal any viscosity anomaly in a confined space down to capillary diameters of 2 µm. Experiments with nanoporous ceramic disks (> 99% Al2O3) conducted at confining pressures from 10 to 50 MPa did not indicate any stress dependence of permeability coefficients. Analysis of the apparent permeability coefficients over a mean gas pressure range from 0.2 to 30.5 MPa showed essentially linear Klinkenberg trends with no indication of second-order slip flow. The Klinkenberg-corrected permeability coefficients measured with helium were consistently higher than those measured with all other gases under the same conditions. This “helium anomaly” was, however, less pronounced than the same effect observed in natural rocks, indicating that it is probably not related to fluid-dynamic effects but rather to gas–solid interactions (e.g., sorption). Permeability tests with CO2 on the nanoporous membrane show significant deviations from the linear Klinkenberg trend around the critical point. This is due to the drastic changes of the thermodynamic properties, in particular the isothermal compressibility, in this pressure and temperature range. Helium pycnometry, mercury intrusion porosimetry and low-pressure nitrogen sorption showed good agreement in terms of porosity (~ 28%) and the most prominent pore diameter (~ 68.5 nm).

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Quantitative validation of pore structure characterization using gas slippage measurements by comparison with predictions from bundle of capillaries models

Cited by 6 publications

References 21 publications

Experimental Investigation about Gas Transport in Tight Shales: An Improved Relationship between Gas Slippage and Petrophysical Properties

Experimental Investigation about Gas Transport in Tight Shales: An Improved Relationship between Gas Slippage and Petrophysical Properties

Low-Salinity-Assisted Cationic Polyacrylamide Water Shutoff in Low-Permeability Sandstone Gas Reservoirs

Experimental Investigation of Gas Dynamic Effects Using Nanoporous Synthetic Materials as Tight Rock Analogues

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