Experimental studies on gas and water permeability of fault rocks from the rupture of the 2008 Wenchuan earthquake, China

Duan, Qingbao; Yang, Xiao‐Song

doi:10.1007/s11430-014-4948-7

Cited by 29 publications

(12 citation statements)

References 33 publications

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“…As a result, the gas will slip flow, prompting the slip factor to rise. Previous research has also identified a similar phenomenon in gas permeability studies (Duan and Yang, 2014;Moghadam and Chalaturnyk, 2014;Tanikawa and Shimamoto, 2009;Yang et al, 2017).…”

Section: Effect Of Gas Pressure On Gas Permeabilitysupporting

confidence: 61%

Gas Permeability Change With Deformation and Cracking of a Sandstone Under Triaxial Compressiongas Permeability Change With Deformation and Cracking of a Sandstone Under Triaxial Compression

Lin

Liu

Chen

et al. 2022

Preprint

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In this paper, a THMC (Thermal-Hydrological-Mechanical-Chemical) multi-field coupling triaxial cell was used to systematically study the evolution of gas permeability and the deformation characteristics of sandstone. The effects of confining pressure, axial pressure, and air pressure on gas permeability characteristics were fully considered in the test. The gas permeability of sandstone decreases with increasing confining pressure. When the confining pressure is low, the variation of gas permeability is greater than the variation of gas permeability at high confining pressure. The gas injection pressure has a significant effect on the gas permeability evolution of sandstone. As the gas injection pressure increases, the gas permeability of sandstone tends to decrease. At the same confining pressure, the gas permeability of the sample during the unloading path is less than the gas permeability of the sample in the loading path. When axial pressure is applied, it has a significant influence on the permeability evolution of sandstone. When the axial pressure is less than 30 MPa, the gas permeability of the sandstone increases as the axial pressure increases. At axial pressures greater than 30 MPa, the permeability decreases as the axial pressure increases. Finally, the micro-pore/fracture structure of the sample after the gas permeability test was observed using 3D X-ray CT imaging.

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Section: Effect Of Gas Pressure On Gas Permeabilitysupporting

confidence: 61%

Gas Permeability Change With Deformation and Cracking of a Sandstone Under Triaxial Compressiongas Permeability Change With Deformation and Cracking of a Sandstone Under Triaxial Compression

Lin

Liu

Chen

et al. 2022

Preprint

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“…The correction from gas to liquid permeability is normally carried out as a Klinkenberg correction of laboratory measurements (Klinkenberg 1941). The Klinkenberg correction is quite important for low-permeability sandstones, where a factor of 0.5 may apply, but for high permeabilities (>100 mD) the Klinkenberg correction is less pronounced and a factor in the order of 0.8-0.9 may apply (Tanikawa and Shimamoto 2009;Duan and Yang 2014). The use of core permeability values for upscaling to a full reservoir volume assumes that the sampling of the core samples is representative, which is not always the case.…”

Section: Porosity and Permeability Assessmentsmentioning

confidence: 99%

Pre-drilling assessments of average porosity and permeability in the geothermal reservoirs of the Danish area

et al. 2016

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Denmark constitutes a low-enthalpy geothermal area, and currently geothermal production takes places from two sandstone-rich formations: the Bunter Sandstone and the Gassum formations. These formations form major geothermal reservoirs in the Danish area, but exploration is associated with high geological uncertainty and information about reservoir permeability is difficult to obtain. Prediction of porosity and permeability prior to drilling is therefore essential in order to reduce risks. Geologically these two formations represent excellent examples of sandstone diversity, since they were deposited in a variety of environments during arid and humid climatic conditions. The study is based on geological and petrophysical data acquired in deep wells onshore Denmark, including conventional core analysis data and well-logs. A method for assessing and predicting the average porosity and permeability of geothermal prospects within the Danish area is presented. Firstly, a porosity-depth trend is established in order to predict porosity. Subsequently, in order to predict permeability, a porosity-permeability relation is established and then refined in steps. Both one basin-wide and one local permeability model are generated. Two porosity-depth models are established. It is shown that the average permeability of a geothermal prospect can be modelled (predicted) using a local permeability model, i.e. a model valid for a geological province including the prospect. The local permeability model is related to a general permeability model through a constant, and the general model thus acts as a template. The applied averaging technique reduces the scatter that is normally seen in a porosity-permeability plot including all raw core analysis measurements and thus narrows the uncertainty band attached to the average permeability estimate for a reservoir layer. A "best practice" technique for predicting average porosity and permeability of geothermal prospects on the basis of core analysis data and well-logs is suggested. The porosity is primarily related to depth, whereas the permeability also depends on porosity, mineralogy and grain size, which are controlled by the depositional environment. Our results indicate that porosity and permeability assessments should be based on averaged data and not raw conventional core analysis data. The uncertainty range of permeability values is significantly lower, when average values are used.

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“…Klinkenberg gas slip factor as a function of intrinsic permeability. The solid line is a fitting result based on the data from this study and previous studies for clay‐rich fault rocks (Duan et al, 2014; Duan & Yang, 2014), and the dashed lines are results of previous studies for sedimentary rocks (Heid et al, 1950; Jones & Owens, 1980; Tanikawa & Shimamoto, 2009). …”

Section: Discussionmentioning

confidence: 59%

“…Figure 10 plots the slip factor b against the intrinsic permeability

k_{g}^{in}

. The results of natural fault rocks from our previous studies (Duan et al, 2014; Duan & Yang, 2014) are included. The compiled data set (six natural fault rocks and two clay‐rich synthetic samples) appears to be linear in the log‐log diagram (Figure 10), implying a power law relationship that can be written as

b = γ {(k_{g}^{in})}^{- normalδ}

, where γ and δ are dimensionless coefficients.…”

Section: Discussionmentioning

confidence: 99%

“…However, the gas slippage effect of fault rocks has rarely been investigated. Recent studies have shown that the Klinkenberg‐corrected gas permeability of clay‐rich fault rocks is higher than that measured by water (Duan & Yang, 2014). Besides the Klinkenberg effect, the hydrophilic property of clay minerals subjected to water may have a significant influence on pore structure and permeability (Behnsen & Faulkner, 2011; Faulkner & Rutter, 2000; Moore et al, 1982; Rao & Mathew, 1995; Siddiqui et al, 2019).…”

Section: Introductionmentioning

confidence: 99%

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A Comparison of Gas and Water Permeability in Clay‐Bearing Fault and Reservoir Rocks: Experimental Results and Evolution Mechanisms

2020

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To better understand the discrepancy between gas and water permeability and the mechanism of permeability in response to the presence of water in clay‐bearing rocks, we performed transport property experiments on synthetic quartz‐clay mixtures and natural fault gouge, as well as clay‐bearing sandstones for comparison purpose. The experiments were performed on a fluid flow apparatus with effective pressures (Pe) cycling between 5 and 105 MPa. Each sample was subjected to nine Pe cycles, along which permeability and porosity of either the gas‐saturated (nitrogen) or water‐saturated samples were measured. The results show that the permeability of all samples investigated decreases with increasing Pe. Gas permeability exhibits strong pore pressure dependence, which can be explained by the slippage (Klinkenberg) effect. Permeability results measured by water are commonly lower than the gas results. The decrease in permeability after the addition of water can be generally explained by the evolution of porosity, as can be determined from the bulk volume and solid mineral volume measurement results. The loss of permeability is associated with the hydration expansion of clay minerals that causes the reduction of porosity. A conceptual model for the evolution of porosity that incorporates clay expansion and grain rearrangement is proposed to describe the mechanism for water permeability in clay‐bearing rocks. Based on these results, we discuss the effect of clay hydration on fluid transport and mechanical behaviors in clay‐bearing fault zones and reservoir formations following fluid injection.

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Experimental studies on gas and water permeability of fault rocks from the rupture of the 2008 Wenchuan earthquake, China

Cited by 29 publications

References 33 publications

Gas Permeability Change With Deformation and Cracking of a Sandstone Under Triaxial Compressiongas Permeability Change With Deformation and Cracking of a Sandstone Under Triaxial Compression

Gas Permeability Change With Deformation and Cracking of a Sandstone Under Triaxial Compressiongas Permeability Change With Deformation and Cracking of a Sandstone Under Triaxial Compression

Pre-drilling assessments of average porosity and permeability in the geothermal reservoirs of the Danish area

A Comparison of Gas and Water Permeability in Clay‐Bearing Fault and Reservoir Rocks: Experimental Results and Evolution Mechanisms

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