Permeability Reduction Rate Research Articles

Seepage-stress coupling characteristics of initial damaged glass fiber reinforced concrete under different loading conditions

Different loading methods induce variations in the macroscopic performance of the specimens. In this investigation, experiments were conducted on glass fiber reinforced concrete subjected to varying degrees of damage. Initially, axial compression loading and unloading were performed, followed by continuous axial compression loading. The study elucidates the evolution of permeability and strength characteristics of specimens under these two loading regimes. The experimental results delineate the trend of permeability and its corresponding strength attributes under complex stress paths. It was observed that during the axial compression loading and unloading phases, the permeability of the specimens follows a negative exponential function. As axial pressure increases, internal pores within the specimens were compacted, leading to a reduction in seepage pathways and a significant decline in permeability. At different stages of axial compression (0–5 MPa, 5–15 MPa, 15–25 MPa), the rate of permeability reduction diminishes progressively, with minimal change observed in the high-stress stage. During the unloading phase, due to incomplete recovery of plastic deformation, permeability shows only a limited increase, with the maximum recovery rate being less than 40 %. During the initial phase of continuous axial compression loading, the permeability first diminishes, subsequently entering an elastic stage where it stabilizes. However, upon reaching the point of instability failure due to crack propagation, permeability increases sharply. Additionally, as the number of freeze-thaw cycles rises, the degree of internal damage within the specimen escalates, manifesting as an increase in both pore size and quantity. Notably, the initial permeability and peak strength exhibited opposing trends: after 40 freeze-thaw cycles, initial permeability increased by 36 %, while peak strength decreased by 22 %.

Influence of Rock Fabric on Physical Properties of Shale Oil Reservoir Under Effective Pressure Conditions

Abstract The physical properties of shale oil reservoirs under overburden pressure are of great significance for reservoir prediction and evaluation during exploration and development. Based on core, thin section, and SEM observations, as well as test data such as XRD, TOC, and porosity and permeability under pressure conditions, this study systematically analyzes the variation of physical properties of different lithofacies shales in the Jiyang depression and the influence of rock fabric on the physical variation under pressure. The porosity and permeability of shale samples significantly decrease under pressure. According to the phased reduction in porosity and permeability, the pressurization process is divided into three pressure stages: low pressure (<8 MPa), medium pressure (8–15 MPa), and high pressure (>15 MPa). The reduction of porosity is fastest in the low-pressure stage and slowest in the medium-pressure stage. The reduction of permeability is fastest in the low-pressure stage and the slowest in the high-pressure stage. The rock fabric has a significant impact on porosity and permeability under pressure conditions. The permeability of laminated shale and bedded shale is higher than that of massive shale under pressure, and the permeability loss rate is lower than that of massive shales. Especially under lower pressure, the difference can be 10–20 times. In addition, the reduction rate of porosity and permeability under pressure is negatively correlated with felsic minerals content, which is positively correlated with carbonate minerals content and clay minerals content. The contribution of clay minerals to the porosity reduction rate is dominant, followed by carbonate minerals. The contribution of carbonate minerals to the permeability reduction rate is dominant, followed by clay minerals. The TOC content has no significant impact on the porosity and permeability of shales under pressure in the study due to the low maturity.

Anisotropic flow characteristics in single-fractured tensile and shear fractures in granite subjected to various confining stress

Anisotropic flow characteristics in single-fractured tensile and shear fractures in granite subjected to various confining stresses were investigated by experiments and experimental results-based flow simulations. Anisotropic characteristics in aspects such as the permeability reduction rate, stress dependency of permeability, and flow paths in fracture and fracture aperture distribution were analysed and compared between tensile and shear fractures. The main conclusions are as follows: (1) for tensile fractures, the permeability in the X direction, k X , is slightly lower than the permeability in the Y direction, k Y , and the average permeability anisotropic coefficient, α k ( α k = k X / k Y ), is in the range 0.236–0.779. For shear fractures, k X is obviously lower than k Y , and α k is in the range 0.038–0.163; therefore, the permeability anisotropy in shear fractures is stronger than in tensile fractures. (2) Strong channelling effects exist in both shear and tensile fractures. The stress-dependence coefficient of permeability is 0.731 MPa −1 in the X direction and 0.365 MPa −1 in the Y direction for tensile fractures, and 0.034 and 0.010 MPa −1 , respectively, for shear fractures, indicating that the dependency of permeability on stress also shows anisotropy. (3) An empirical model for α k based on stress and fracture aperture variograms is proposed. Based on α k , permeability along both the X and Y directions can be well predicted, especially under relatively high confining stress.

Experimental study on the effect of salt crystallization on multi-scale transportation of shale gas

Salt crystallization will block the pores and fractures of shale reservoirs. It is one of the important reasons for the rapid decline of shale gas wells' initial production. Pressure pulse decay tests show that shale permeability is significantly decreased due to salt crystallization. Salt crystallization primarily block macropores and natural fractures, resulting in an average permeability reduction rate of 79.26%. The major salt crystallization formed after the salt crystallization experiment is CaSO4, and the overall size of the crystallization is 30–50 μm.

Synthesis and plugging effect of inverse emulsion polymerization microspheres (OPME) for oil-based drilling fluids

It is difficult to seal oil-based drilling fluids in the large pore and micro-fracture formation, and there are few suitable materials for the oil phase with good sealing ability at present. In order to solve the problem of the lack of sealing ability of oil-based drilling fluids, acrylamide, 2-acrylamido-2-methylpropane sulfonic acid, and acryloyl morpholine were used as monomers, N'N-methylenebisacrylamide was used as a cross-linking agent, Span-80 and Tween-60 were used as emulsifiers, and 2,2′-azobis(2-methylpropionamidine) dihydrochloride was used as an initiator. Polymer microsphere emulsion OPME was synthesized by inverse emulsion polymerization. The structure of polymer microspheres was characterized by infrared spectroscopy, scanning electron microscopy, electron microscopy, H NMR, laser particle size analysis and thermogravimetric analysis. The optimal synthesis conditions were determined by the control variable method: the monomer ratio of acrylamide, 2-acrylamido-2-methylpropane sulfonic acid, and acryloyl morpholine was 45:20:15, the amount of emulsifier was 8%, and the reaction temperature was 55℃. The synthetic polymer microspheres were added to the oil-based drilling fluids to perform filtration and loss plugging at atmospheric pressure and high-temperature and high-pressure, as well as pore and artificial fracture core plugging evaluation. The evaluation results show that the permeability reduction rate of pore core can reach 82%, and that of fracture core can reach 100% by adding polymer microspheres with 3% dosage. Finally, the pressure transmission experiment proves that the addition of polymer microspheres can slow the pressure transmission and filtrate intrusion, and enhance the stability of wellbore. Therefore, polymer microspheres are a micron-level plugging agent with good compatibility and high performance with oil-based drilling fluids, and the 3% dosage can better seal the formation of large pores and micro-fractures, which has a good potential for field application.

Performance Evaluation and Field Application of Nano Plugging Agent for Shale Water-Based Drilling Fluid

In this paper, nano plugging agent AMPS/AM was prepared, and its plugging performance was evaluated by a microfracture simulation experiment and a shale pressure resistance experiment. The pressure loss decreased by 66.09% compared with the top pressure of 6.9 MPa, and the average core indentation hardness increased 58.12% with 3% AMPS/AM blocking mud. The experiments indicate that AMPS/AM can effectively seal the shale micropore and nanopore structure and greatly improve the stability of fractured shale well wall. The field application results of the YS129H well in the Zhaotong block show that the water-based drilling fluid with nano plugging agent AMPS/AM as the key agent has strong plugging performance. The well mud is of high temperature and pressure water loss < s4 mL, mud cake permeability reduction rate of 85.67%, which indicates that the drilling fluid system has good sealing properties and well wall stability.

Stimulated microbial growth for permeability reductions in granular soils

The controlled production of microbial growth has the potential to reduce groundwater flow in seepage and dewatering systems. Stimulating the growth of indigenous bacteria could clog the pore space and result in a substantial permeability reduction. This study investigated the spatial distribution of permeability reduction under different nutrient stimulation treatments of indigenous bacteria across 16 cm columns of Ottawa 50–70 sand. Spatially uniform permeability reductions of up to an order of magnitude were achieved using both a high glucose (50 mg/l) and a low glucose (10 mg/l) nutrient formulation. The overall permeability began to decrease by day 2 and approached a minimum permeability by day 14. There was no noticeable difference in the final permeability nor the rate of permeability reduction between high and low glucose formulations. Upscaling of experiments is highly recommended for future studies on the spatial uniformity of microbial growth and biologically induced permeability reductions.

Research on plugging characteristics of microorganism induced calcite precipitation in sandstone environment

Microorganism-induced calcite precipitation (MICP) has been proposed to increase crude oil recovery for more than two decades. It is only recently that mine trials have emerged. The present study was conducted to advance the application of MICP for enhanced crude oil recovery. The changes of core permeability and bacterial biomass on permeability reduction rate during MICP treatment were investigated by core blocking experiments and reverse unblocking experiments. The permeability conditions for biomass and calcite production blocking were explored. Based on this, the changes in mechanical properties of the cores by MICP were explored by unconfined pressure experiments. Finally, the mineral composition and mineral phases were analyzed by XRD and SEM. Our study shows that MICP is much less effective at permeabilities less than 66mD. The decrease in permeability presented in the experiment comes from the blocking effect of the injection end of the core on the bacteria. The compressive strength of the MICP-treated cores was increased by 10.05% and was more resistant to brittle damage. Also calcite is attached to the sandstone matrix. The characteristic peaks of calcite were observed in the cores treated with MICP by SEM and XRD. In addition, under the same culture conditions, the mineral morphology in the sandstone environment is quite different from that in the shake flask. In the sandstone environment, calcite is tightly adsorbed on the sandstone matrix, showing a typical rhombic hexahedral structure, and in the shake flask environment, it is more Spherical or spherical aggregates. Based on the above study, the blocking mode of MICP is proposed. The free agglomerated calcite particles form a physical seal in the pore throat and the biofilm mineralizes directly in the sandstone matrix together to seal the sandstone cores. The results of this study report a new mineral morphology difference in MICP. It is also a theoretical support for further improving the MICP for enhanced oil recovery.

The potential blockage during CO2 displacement in the high pour point oil reservoir

CO2 displacement is a common technique for the enhanced oil recovery and simultaneously alleviates the greenhouse effect. However, the recent applications of CO2 displacement focus on the formations where the fluid and reservoir properties could not reach absolute miscibility. The reactions between CO2 and high pour point crude oil during the near-miscible displacement process would be far more complex. In this study, slim-tube and one-dimensional core (sand-filling model, splicing long core) displacement experiments were carried out. Group component analysis and saturated hydrocarbon analysis were applied during the process and the possibility of organic solid deposition and blockage was deduced. The indicator of permeability reduction rate of long core was introduced and used to evaluate the impact of the deposition of each short core on the permeability. Through analysis and comparison, deposition and blockage occurred in the front and middle of the long core, and the maximum permeability reduction rate reached about 0.04%. The results showed that although near-miscible displacement could improve the oil recovery, there was still the possibility of potential blockage which should be carefully considered in the design of the gas injection scheme.

Heterogeneity of hydrate-bearing sediments: Definition and effects on fluid flow properties

Heterogenous distribution of gas hydrate in pores is the common characteristic of hydrate formation at various experimental scales. In this work, in order to fill the gap of defining the hydrate phase heterogeneity degree of hydrate-bearing sediments, we conduct a series of pore-scale experiments and simulations on hydrate formation behaviors and two-phase flow properties in hydrate-bearing samples by micro X-ray CT. The enhanced heterogeneous distribution of gas hydrate in small pores has been observed from experimental results, suggesting that the degree of hydrate heterogeneity in sandy or silty sediments may be underestimated. Therefore, the definition of hydrate heterogeneity degree is firstly proposed to characterize the hydrate phase heterogeneity of hydrate-bearing sediments. Additionally, we further investigate the effects of hydrate heterogeneity on fluid flow properties by introducing three types of hydrate distribution in porous media, which are homogeneous, clogging, and clumpy distribution. The clogging type of hydrate distribution could result in the sharply increased rate of permeability reduction, while the clumpy type of hydrate distribution might result in the declined rate of permeability reduction. Meanwhile, the heterogenous hydrate distribution leads to the rapid decrease in gas relative permeability. These findings are significant for laboratory studies and gas recovery in field tests.

Based on self-made shale formation simulated artificial cores to evaluate water-based drilling fluids plugging effect technology

Plugging technology is one of the leading problems in shale gas drilling engineering, as it causes wellbore stability, shale formation collapse, and so on. In order to solve these problems, in this paper, we committed to preparing artificial cores whose original permeability was 1.16×10−4 mD, which could be used to simulate the shale formation, and established a sealing evaluation method to assess the effect of plugging technology by measuring permeability reduction rate K'. Verified the good reproducibility of the artificial cores through a lot of high temperature and high pressure (HTHP) filtration experiments. The Scanning electron microscopy (SEM) was used to prove that the permeability reduction rate is a scientific method to evaluate the sealing effect.

Transient Diagnosis of Fines Migration Integrating Core Testing and Numerical Reservoir Modeling

SummaryTo manage well productivity, an effort was undertaken to identify fines migration by means of transient diagnosis, quantify its effect on productivity, model the production history, and forecast well performance. Because of its distinguishable transient behavior, mechanical fines migration can be identified among other factors that contribute to productivity decline. Pressure transient analysis (PTA), production data analysis (PDA), laboratory experiments, and numerical-flow-simulation techniques were used to understand the physics of fines migration, quantify its characteristic parameters, validate the model with production history, and verify its efficacy in a field application. Results are consistent with laboratory observations, synthetic studies leveraging a geomechanics reservoir simulator, and field data for moderate to severe fines migration.A new integrated approach was developed to accurately identify and depict declining productivity caused by fines migration through PTA, core testing, and reservoir flow modeling. Previous research has proposed a permeability-reduction flow function that correlates with extended coreflood data to predict the key parameters that characterize the fines-migration effects: critical velocity, permeability-reduction rate, and ultimate residual permeability. From the transient-behavior observations on wells experiencing fines migration, the obvious damage is represented by a positive skin as a function of time in the near-wellbore region. This concurs with the realization that interstitial velocity decreases with the distance from the wellbore. For severe fines migration observed in both synthetic cases and field data, two permeability regions could be identified and described by a radial composite model allowing the damage radius and the average permeabilities of each zone be estimated. Incorporation of a new technique, which correlates the skin-time function with the fines-migration flow relation, enables the calculation of key parameter ranges. These can be integrated with coreflood data for use as initial values in numerical reservoir modeling, potentially simplifying history-matching efforts before performance forecast.The novelty of this workflow is in the ability to identify and quantify the potential influence of mechanical fines migration with PTA and PDA techniques, and incorporation of the fines-migration flow relation to estimate the ranges of the characteristic parameters used in numerical modeling. Understanding the impact of fines migration on well productivity allows engineers to more accurately predict production decline, identify the benefit of remediation, and select optimal development strategies.

Influence of Fluid‐Assisted Healing on Fault Permeability Structure

AbstractMicrocracks in fault damage zones can heal under thermally controlled processes. If a flow communication exists between a fluid source and the fault damage zone, warm fluids can migrate into it, change its thermal conditions, and assist healing. The crack life span depends on the local temperature and is, thus, modified by the infiltration of warm fluids. The features of the initial fault architecture govern how the fluids will propagate within the fault damage zones. This affects the rate of healing and the rate of permeability reduction. The region infiltrated by fluids will then show a significant decrease in its permeability, as seen in many field examples like the Alpine Fault. Conventionally, the damage zones immediately near the fault core have a high permeability that decays as we go further away. However, the region adjacent to the fault core, in the Alpine Fault, New Zealand, has the lowest permeability in the current interseismic period. As shown by our simulations, this can be due to healing and sealing, favored by the localized high geothermal gradients (confirmed by the drilling data) and the upward fluid migration through the fault relay structure, which accelerated mass diffusion and minerals precipitation.

Subsurface Sludge Sequestration in Cyclic Steam Stimulated Heavy-Oil Reservoir in Liaohe Oil Field

Summary There are a lot of sludges produced in oil production and storage processes in Liaohe Oil Field. Usually complicated chemical processes are involved in treating the sludge effectively and such surface-treatment processes are subject to high cost and environmental challenges. Therefore, the feasibility and performance of sludge injection into steam-stimulated wells, and sludge sequestration and associated heavy-oil-recovery improvement are investigated on the basis of results of laboratory research and field operation. The sludge originally produced from the reservoir comprises mainly water, some oil components, and solid phase such as mud and fine sand, and aggregation of the injected sludge components, except water, could block the void porous space. Actually, the sludge is buried into its origin, the reservoir. As the sludge is injected into the steamed reservoir through an enlarged pore at high injection pressure, the permeability of the formation could be significantly decreased (the permeability reduction rate could be more than 98% after sludge blocking in our experiments with sandpacked tubes), and the sludge blocking performance is related to the reactions of oil and solid separated from the sludge, including adherence to the sand surface, consolidation of the sands, and filling in the void porous space. Consequently, the sludge is stored in the steamed formation, and the water in the sludge is separated and produced. At the same time, steam conformance and heating efficiency could be improved by implementing a sludge blocking process, thereby significantly improving oil production. Sludge sequestration has been applied to 45 steamed wells in Shuguang Oilfield until 2018, and all the wells have been stimulated by 7–10 cycles of CSS process. The total sludge injection of the wells is up to 133,200 tons, and more than 15,000 tons of oil and solid separated from the sludge are deposited underground. At the same time, more than 20% increase in cyclic oil production on average is obtained by the sludge-injection process.

Stabilizing and enhancing permeability for sustainable and profitable energy extraction from superhot geothermal environments

Superhot geothermal environments in granitic crusts of ca. 400–500 °C and depths of 2–4 km are recognized as a frontier of geothermal energy. In developing such environments, hydraulic fracturing is a promising way to create or recreate permeable fracture networks to effectively access the energy through enhanced geothermal systems (EGS). However, there is a concern about the possibility of stabilizing or enhancing the permeability created by hydraulic fracturing, required for sustainable and profitable energy production, because pressure solution of the fracture surfaces may reduce permeability. On the other hand, permeability may be enhanced by free-face dissolution of the fracture surfaces even if pressure solution occurs. However, the rates of permeability reduction and enhancement are not fully understood, and the possibility of stabilizing/enhancing permeability is therefore unclear. We have conducted hydrothermal flow-through experiments on 400 °C fractured granite samples to clarify the influences of stress level and plasticity of the fracture on the rate of permeability reduction by pressure solution and the influences of pore water pressure and corresponding mineral solubility on the rate of permeability enhancement by free-face dissolution. Results suggest that permeability may be either stabilized or enhanced in superhot EGS even when pressure solution can occur by keeping the difference between the concentration of the pore water and the solubility of quartz higher than the stress-dependent permeability stabilization criterion.

EFFECTIVENESS OF DECREASING PERMEABILITY AND INCREASING SHEAR STRENGTH OF SANDY SOIL USING EXOPOLYSACCHARIDE BIOPOLYMER

Sand is a type of soil with high porosity and a tendency toward a high permeability rate and low shear strength, which often causes problems in terms of piping and low slope stability. Permeability and shear strength have a very close relationship with soil stability. In this paper, we analyzed the addition of the bacterial producer exopolysaccharide on sandy soil for increased instability. The addition of this bacterial producer is expected to improve soil stability by reducing its permeability and increasing its shear strength. To find an alternative approach to overcome the problems of low permeability and shear strength, experiments were conducted using five types of non-pathogenic inoculated bacterial producer, namely, Lactobacillus sakei, Agrobacterium tumifaciens, Bacillus subtilis, Pseudomonas sp, and Nitrobacter sp, added to five samples of river and beach sand. After 30 days of bacterial inoculation, the permeability of the sand samples was tested using a constant head test, and the shear strength was tested using a direct shear test, which was confirmed through scanning electron microscopy (SEM). Based on the permeability test, the permeability of the sand samples inoculated with Bacillus subtilis was reduced the most at 74.43%. Based on the direct shear test, the highest increase in shear strength, i.e., about 58.91%, was in the samples inoculated with Lactobacillus sakei. SEM photographs with 10,000 x magnification showed the presence of bacteria and the formation of extracellular polysaccharides in the walls of the sand, which affected the permeability reduction rate and increased the shear strength of the sand samples. Based on the permeability and shear strength results, it can be seen that the correlation between the two is weak, and thus when the shear strength of the sample increases, the permeability does not necessarily decrease; the correlation depends on the type and characteristics of the bacterial producer.

The influence of CO2 saturation time on the coal gas flow: Fractured bituminous coal

The permeability reduction due to the coal matrix swelling induced by the adsorption of CO2 is the major concern during enhanced coalbed methane recovery (ECBM) as well as CO2 sequestration in coal reservoir. Many problems arise in the context of this process regarding the coal permeability variations, and very few studies have been made with consideration of long-term CO2 saturations on gas flow behaviour alterations. The main objective of this study is therefore to examine the influence of both subcritical and supercritical CO2 flooding durations on N2 and CO2 permeability variation of naturally fractured low volatile bituminous coal under various tri-axial conditions. Five CO2 flooding durations, up to 65 h, both subcritical (6 MPa) and supercritical (14, 20 MPa), were introduced to the sample under three confinements, respectively. Results show that for 11 MPa and 17 MPa confining environment, most permeability reduction occurs during the first CO2 flooding process, and supercritical CO2 flooding causes significant higher N2 permeability reduction (from 14.38% to 50.18%) than subcritical CO2 (from 4.11% to 11.25%). The permeability reduction rate decreases with time but this reduction continues even after a total of 153 h flooding. Longer permeability reduction process is observed upon supercritical CO2 adsorption due to the much higher viscosity of supercritical CO2. Under deep underground condition (>1 km), CO2 exhibits a N2-like flow behaviour because of the dominant poroelastic effect. The influence of CO2 flooding on permeability alterations has been significantly compromised with much smaller permeability reduction after 20 MPa CO2 flooding compared with 14 MPa CO2 flooding (7.33% and 38.75% for 7 MPa CO2 injection pressure, respectively), along with no apparent permeability reduction for the further CO2 flooding scenarios.

Experimental comparisons of gas adsorption, sorption induced strain, diffusivity and permeability for low and high rank coals

Because of coal pore structure, the adsorption and diffusion behaviors are quite different for low and high rank coals. Differences of gas adsorption-diffusion and adsorption deformation of low and high rank coal and its permeability evolution were carried out in isothermal adsorption experiment and desorption-seepage testing system. The law of adsorption and adsorption induced strain, diffusion of low and high rank coal and its influence on the coal permeability were revealed. It turns out that, the methane adsorption-diffusion and adsorption induced-strain of low and high rank coal increase with the increase of the adsorption equilibrium pressure. Because of the control of pore structure, the diffusion property of low rank coal sample is higher than that of high rank coal sample. And the strain perpendicular to the bedding plane is higher than that parallel to the bedding plane. Sorption-induced strain of high rank coal is higher than that of low rank coal, which is related to the amount of gas adsorption in coal. The Langmuir volumetric strain is about twice as high as that of the low rank coal. The law of gas adsorption deformation of coal can be described by a Langmuir isotherm adsorption equation. The influence of methane adsorption-induced swelling strain on the permeability of high rank coal is higher than that of low rank coal. At a constant effective stress, the permeability of low rank coal is higher than that of high rank coal, and with the increases of adsorption equilibrium pressure, the permeability decline by a negative exponential function of different rank coals; the rate of permeability reduction of high rank coal is higher than that of low rank coal.

Thermal and mechanical coupling effects on permeability of weakly cemented sandstone

The weakly cemented sandstone is the host rock in the Cretaceous and Jurassic strata with low intensity, high water-bearing capacity and sensitivity to disturbance. In order to investigate the influence of temperature and confining pressure on the permeability of weakly cemented sandstone, scanning electron microscope were used to characterize microstructure of the particles, a series of triaxial creep tests were performed on coarse sandstone, medium sandstone and fine sandstone separately, and the effect of particle size on the permeability of sandstone was also analyzed. The results indicate that the increase of confining pressure led to the plastic deformation between the rock particles, that permeability was irreversible as the confining pressure changed, and that the permeability reduction rate of coarse sandstone was lower than that of fine sandstone. The sensitivity of weakly cemented sandstone to temperature and confining pressure increased as the sizes of the particles decreased, and the effect on permeability was more obvious.

Characteristics of clay deposits in Saga Plain, Japan

The characteristics of clay soil in the Saga Plain in Japan, as well as the effect of the depositional environment on its engineering properties, have been investigated. While the clay was being deposited there were several large-scale volcanic eruptions in the region. A considerable amount of volcanic ash settled into the clay, which had a marked effect on its engineering properties. The soil is strongly structured and the sedimentation compression curves are well above the sedimentation compression line proposed by Burland, which indicates some degree of cementation. The compression index is high – even for soil samples with in situ vertical effective stresses of 200–300 kPa, the index can be as high as 2·3. The rate of permeability reduction with void ratio is higher than most reported data in the literature. The reason considered is that the compression process involves not only gradual compression of the pores but also breaks down relatively large pores into smaller pores, which can cause rapid reduction of permeability. The stiffness is lower, with results of unconfined compression tests showing that the ratio of undrained shear strength to secant modulus is about 150.