Article pubs.acs.org/EF
Experimental Investigation of Interactions between Water and a Lower Silurian Chinese Shale Weina Yuan,†,‡ Xiao Li,† Zhejun Pan,*,§ Luke D. Connell,§ Shouding Li,† and Jianming He† †
Key Laboratory of Shale Gas and Geoengineering, Institute of Geology and Geophysics, Chinese Academy of Sciences, Beijing 100029, China ‡ University of Chinese Academy of Sciences, Beijing 100049, China § CSIRO Earth Science and Resource Engineering, Private Bag 10, Clayton South, Victoria 3169, Australia ABSTRACT: Hydraulic fracturing and well drilling bring water into shale reservoirs. The water interacts with the shale, which can destabilize the wellbore and impact the rate of gas production from the reservoir. Although wellbore instability has been extensively studied, the effect on gas production requires further work. In this work, the interactions of water with shale from China’s Sichuan Basin were studied from macroscopic and microscopic perspectives. The visual information provided by studying shale at the microscopic scale helps in understanding the effects of water−shale interactions on gas production. We first studied the shale’s wettability and water adsorption capacity and then investigated its water adsorption characteristics, swelling strain, and Young’s modulus with different water contents. Field-emission scanning electron microscopy was also used to observe the storage of water in the shale matrix and the interaction of shale minerals with water. Our experimental data show that the adsorption capacity of the shale is low, although it is overall hydrophilic. The adsorption data indicated that diffusion may be the main mechanism for water adsorption by the sample under our experimental conditions. Capillary pressure may also help transport water into the matrix. The shale sample exhibited free swelling and its Young’s modulus decreased after uptake of water, which may be attributed to hydration of clay minerals in the shale sample. Microscopic observations showed that some water remained in the sample’s pores even when the water vapor pressure was much lower than the saturation pressure. This suggests that the residual water may be difficult to remove from the reservoir and that hydraulic fluid would have a greater influence on smaller pores than on larger pores.
1. INTRODUCTION Shale gas is one of the most promising unconventional natural gas resources. It has been a huge success in North America and is receiving increasing interest worldwide. High-quality gas shales typically have initial water saturation of less than 45%.1,2 Most of this water is in the bound state and thus is not movable under reservoir conditions. However, the horizontal drilling and hydraulic fracturing necessary for the economic extraction of shale gas require large amounts of water. Water-based drilling fluid is often used to create circulation, which cools the drill bit and carries the rock cutoffs to the surface.3 A significantly larger amount of water is required in multistage hydraulic fracturing of the horizontal well. Typically, 2900−20700 m3 of water was required for hydraulic fracturing of one horizontal well of the Barnett Shale in 2010, compared with around 25% of this amount for drilling and sand mining.4 Approximately 60−90% of the hydraulic fracturing fluid was lost in the shale formation.5 The trapped drilling fluid and hydraulic fracturing fluid in the shale reservoir affects its level of water saturation, especially in the regions near the wellbore and hydraulic fractures. These fluids interact strongly with the shale, generating problems throughout the drilling operation and also affecting reservoir fracturing and gas production.6 Water−shale interactions cause wellbore instability, which has been one of the most challenging and costly problems in drilling operations.7 Drilling through shale formations is almost inevitable; thus, issues associated with water−shale interactions have been extensively investigated.7−13 One of these is the control of clay-rich shale © XXXX American Chemical Society
caused by swelling. Different chemicals have been added to drilling fluid to control shale swelling, and the interactions between shale and fluids of varying chemical compositions have been studied.14−16 Experimental studies have been performed on shale swelling due to water intake, and the mechanisms of shale swelling have been discussed.7−9,17−24 Another issue is that water−shale interactions can affect the transport of gas in shale. On one hand, they limit the gas production rate. Swelling of shale changes the permeability of the gas shale reservoir,6 and models have been developed to quantify the relationship between swelling strain and the permeability of shale or clayey rocks.25,26 The hydration of shale may induce stress distribution;13 hydration stress is considered to be a major cause of permeability impairment in stress-sensitive reservoirs.27 Experiment has also shown that the presence of water reduces the diffusion coefficient of gas in shale28 and the gas flow kinetics in kerogen nanopores.29 On the other hand, water imbibitions occur after contact with shale, and this may help accelerate early-time gas production by extending shut-in periods.30,31 In addition, shale−water interactions can alter the mechanical properties of shale and consequently affect the fracturing of the reservoir. Experimental studies have revealed the relationship between water content and the mechanical properties of shale and other clay-bearing rocks.9,10,32,33 Changes in the mechanical properties of shale may Received: April 23, 2014 Revised: June 14, 2014
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frequency pressure waves to agitate water. The agitated water cleans the surface by washing away loose fragments from the sample surface. Because the strength and cementation of this shale were very strong and the time for cleaning was short, the impact of ultrasonic cleaning to the sample was minimal. Then the sample was dried in a vacuum oven at 100 °C until the weight of the sample was unchanged. Contact angles were tested by squeezing deionized water drops (10 μL) from a fixed-volume microsyringe and observing the shape of the drops on the shale surface using a camera (Figure 1).
also affect its brittleness, which is a useful indication of whether the rock can be easily fractured hydraulically.34 Therefore, studying the interactions of reservoir shale with water is of great significance to the development of shale gas. Previous studies have mainly been conducted on non-gas shale and have focused on wellbore stability, with few studies relating to shale gas production.35−38 Thus, much more work is required to address the effects of water−shale interactions after hydraulic fracturing on reservoir properties and gas production, such as investigating the phase and status of the trapped fracturing fluids. Experiments have shown that pores of shale are as small as the nanometer scale and that gas storage and production are closely related to the presence of nanopores.39,40 Correspondingly, studies of shale reservoirs have been performed at the microscopic scale. Similarly, the microscopic study of the behavior of water in shale is of great significance for understanding of shale−water interactions in nanometer-sized pores. Given shale’s complex mineral constitution and typical pore structure, the interaction mechanisms of shale and water are very complicated.11,41 Study of the interactions from a microscopic viewpoint is useful because it can provide visual information about these mechanisms. Hence, the objective of this study is to improve our understanding of the effects of shale−water interactions on reservoir gas production using macroscopic experiments and microscopic observations. The Lower Silurian shale in Sichuan Basin, China, is one of the country’s most promising shale formations for gas production.42 Exploration and production results have shown that economic production rates can be achieved for this shale. To better understand shale−water interactions and their implications on shale gas production, a Lower Silurian shale sample from the Sichuan Basin at a depth of about 2158 m was studied. The mineral content of the shale is presented in Table 1. Contact Table 1. Mineral Content of the Lower Silurian Shale Sample quartz
clay minerals
organic matter
albite
microcline
pyrite
others
70.0%
13.0%
2.9%
6.0%
3.0%
3.0%
2.1%
angle tests were conducted to study the shale’s wettability. A sample was cored perpendicular to the bedding. The core sample was dried and then placed in atmospheres with different relative humidities and also immersed in deionized water to measure water adsorption and swelling strain. After the adsorption of water reached equilibrium, the Young’s modulus was measured. This method allowed us to analyze the relationships among the shale’s water content, the swelling strain, and the Young’s modulus. The process of water transport into and out of the shale was also observed at the microscopic scale using a field-emission scanning electron microscope (FESEM).
Figure 1. Sessile drop tests: (a) water droplet on the surface parallel to the bedding; (b) water droplet on the surface perpendicular to the bedding.
Tests were conducted at 12 selected spots on the surface of the shale sample, with three on the surface parallel to the bedding and nine on the surface perpendicular to the bedding. Since water imbibition started quickly after the droplet sat on the surface, the contact angles were obtained from the initial state. The results are shown in Table 2. All of the measured contact angles are less than 90°, indicating that the shale studied tends to be hydrophilic, with the surface perpendicular to the bedding generally being more hydrophilic than the surface parallel to the bedding. The volume change of droplets on the sample surfaces over time was recorded, and Figure 1 shows two example measurements. The change in the droplet volumes is presented in Figure 2. The volume change rates were also different for the surfaces parallel and perpendicular to the bedding, as shown in Figure 2.
2. EXPERIMENTAL PROCEDURES AND RESULTS 2.1. Shale Wettability. Wettability is an important property for hydrocarbon recovery in clay-rich reservoirs.43 It has a dominant effect on reservoir capillary pressure and the relative permeability behavior of hydrocarbons and thus on the rate of hydrocarbon recovery. Wettability was tested in this work using the sessile drop method. Sections of shale sample were prepared by cutting both parallel and perpendicular to the bedding planes. The sections were polished using sandpaper to make the surfaces flat and then cleaned in an ultrasonic water bath for about 30 s. Ultrasonic cleaning uses cavitation bubbles induced by highB
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Table 2. Contact Angle Results for the Shale Sample parallel to the bedding contact angle (deg)
75
72
78
perpendicular to the bedding 55
60
55
55
58
56
54
58
62
was also recorded for the shale under three different relative humidity conditions (78%, 93%, and immersed in deionized water) (Figure 4). The shale adsorbed water quickly during the
Figure 2. Water droplet volume change over time.
Figure 4. Amounts of water uptake by shale over time for three different relative humidity (RH) values.
2.2. Water Adsorption. A cylindrical core sample, 25.2 mm in diameter and 34.04 mm in height, was prepared. The sample was drilled perpendicular to the bedding. The ends of the sample were sealed with epoxy resin so that water or its vapor could only be transported through the cylindrical surface. This was done to make sure that a cylindrical geometry could be applied to the diffusion modeling. The core sample was dried and then placed in closed chambers where the relative humidity (RH) was controlled by three different saturated salt solutions (MgCl2, NaCl, and K2SO4) following the procedure of the American Society for Testing and Materials. The MgCl2, NaCl, and K2SO4 saturated solutions provided 47%, 78%, and 93% relative humidity in the chamber, respectively, under the laboratory conditions with a temperature at 24 °C. The sample was also immersed into deionized water to study the amount and rate of water uptake at the same temperature. The sample with equilibrium water content was weighed to obtain the water adsorption isotherm (Figure 3).44
early stages before the adsorption reached equilibrium. Because the water adsorption at a relative humidity of 47% was so low, diffusion kinetics data could not be captured. 2.3. Shale Physical Property Changes with Water Content. The effect of shale−water interactions on physical property changes of the shale was tested. Radial and axial displacements of the sample were periodically measured during water adsorption. After the adsorption reached equilibrium, a uniaxial loading test was performed to obtain the Young’s modulus, with the loading stress to 4 MPa. These measurements were conducted on samples under four different humidity conditions (dry, 78% RH, 93% RH, and immersed in deionized water). The axial and radial swelling strain data for the shale are presented in Figure 5. samples with the same water content
Figure 5. Shale swelling strain. Axial denotes perpendicular to the bedding, and radial denotes parallel to the bedding.
Figure 3. Water adsorption isotherm.
developed equivalent swelling strains in different relative humidity environments. The shale also showed anisotropic swelling, with the axial strain higher than the radial strain. As water was adsorbed, the Young’s modulus decreased by up to 38% at the adsorption equilibrium in deionized water, as shown in Figure 6.
At relative humidities of 47%, 78%, and 93% and in deionized water, the equilibrium water contents for the sample were 0.04%, 0.5%, 1.01%, and 1.22%, respectively. According to the classification of the International Union of Pure and Applied Chemistry (IUPAC),45 the pattern of the water adsorption isotherm on this shale is type III. The water adsorption kinetics C
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process of increasing the vapor pressure were identified as condensed water. Figure 7 shows the water condensation on a naturally broken surface of the shale with respect to water vapor pressure. At a water vapor pressure of 5.40 Torr (719.9 Pa), water has not started to condense, but when the vapor pressure increases to 5.45 Torr (726.6 Pa), water starts to condense on the low spots of the shale surface. At a vapor pressure of 5.55 Torr (739.4 Pa), water starts to cover the entire surface. Figure 8 shows a zoomedin area of a feldspar in Figure 7. It can be seen that water tends to accumulate in the microfracture areas of the mineral. Figure 9 shows the dewatering process. At 5.11 Torr (680.8 Pa), the low spots of the surface are still filled with water, and when the pressure drops to 5.1 Torr (679.5 Pa), the water on the surface starts to evaporate until the surface is almost dry. The difference between the condensation pressure (5.45 Torr) and the evaporation pressure (5.1 Torr) demonstrates the capillary pressure of these low spots, which could be considered as pores or cavities. Figure 10 shows the water in a pore that is about 5−10 μm in size. At 5.35 Torr (712.8 Pa), water starts to evaporate from the pore. At 0.5 Torr (66.6 Pa), there is still water in the pore, which requires more time to evaporate completely. Figure 11 shows the interactions between water and chlorite. The chlorite was still dry at a vapor pressure of 5.15 Torr (686.1 Pa) (left photo). After the sample was moistened, the vapor pressure was drawn down. The right photo shows that water still forms a coating layer on the flakes of chlorite at a vapor pressure of 5.05 Torr (672.8 Pa), demonstrating strong wettability of water on chlorite. Figure 12 shows an area of the shale with various types of minerals. In Figure 12b, water condenses in the pores, or low spots, on the surfaces. After the vapor pressure was reduced, most of the water evaporated. Figure 12c shows that the water stays in the middle of the minerals’ flaky structure.
Figure 6. Young’s modulus change with respect to the water content of the shale.
2.4. Microscopic Observations of Water−Shale Interactions. To obtain a better understanding of the interactions between water and shale, we made observations using a FESEM. First, a natural section from the sample was prepared and dried. Interesting spots observed under the FESEM were chosen for further analysis using energy-dispersive spectroscopy to identify the minerals present in the shale. For each spot, the FESEM sample room was first evacuated. Then water vapor was gradually introduced to the sample room at 4 °C (the water saturation pressure at 4 °C is 813.5 Pa or 6.1 Torr). The water vapor pressure was increased until the vapor started to condense into liquid until it covered the entire sample. Water was finally gradually removed by again evacuating the sample room. The process was recorded into videos to observe changes in morphology of the sample section. The vapor pressure for each image is shown at the bottom left of the image. Since minerals and pores in the dry state were recorded before vapor condensation, dark spots that occurred during the
Figure 7. Microscope observations of shale with increasing vapor pressure in the sample room. Dark spots represent condensed water. D
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Figure 8. Process of water condensing on shale surfaces. Arrows point to the locations of water.
Figure 9. Microscope observations of shale with decreasing vapor pressure in the sample room. Dark spots represent condensed water.
3. DISCUSSION 3.1. Driving Force of Water into the Shale Matrix. The process of water transport into the shale sample (Figure 4) was modeled using a unipore diffusion model for cylinder sample (eq 1):46 Mt =1− M∞
∞
∑ n=1
4 exp( −Dαn 2t ) 2 a αn 2
where Mt is the total adsorption at time t, M∞ is the total adsorption at equilibrium, a is the radius of the cylinder (12.6 mm in this work), D is the effective diffusivity; and the αn are the roots of J0(aαn) = 0, where J0(x) is the Bessel function of the first kind of order zero. The pore structure of shale is complex, and diffusion in the organic and inorganic sections may differ. However, the results
(1) E
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Figure 10. Process of water being swabbed from pores.
Figure 11. Interaction of chlorite with water.
show that the data can be described very well using this model (Figure 13). This may be the case because the organic material, which tends to be hydrophobic, adsorbs little water compared with inorganic materials and also because the organic matter content of this sample is so low (2.9%; Table 1) that it has only negligible impact. This could be quite different than the methane adsorption kinetics because the amount of methane adsorbed in the organic matter pores is significant compared with the amount stored in other pores via compression. For methane adsorption,
Figure 13. Modeling of the water adsorption rate.
a bidisperse diffusion model may better represent the experimental data.28 The interaction of shale and water vapor is more complex than those with other nonpolar gases. Besides diffusion, other driving forces may also contribute to the transport of water vapor into the shale matrix, such as capillarity, clay swelling, and osmotic
Figure 12. Interaction of shale minerals with water: (a) minerals under dry conditions; (b) minerals in water; (c) minerals after immersion in water. Dark spots represent condensed water (arrows point at water). F
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occurs within a wide pressure range from 0.5 to 5.45 Torr (e.g., Figures 7 and 10). However, because of the wide pore size distribution of the shale and different pore surface properties, it is difficult to quantitatively correlate the macroscopic and microscopic measurements. Shale water storage can be analyzed by comparison of FESEM images. Water vapor was first adsorbed by the minerals of the sample, and as the humidity in the FESEM sample room progressively increased, water vapor began to condense on the surface of the pores. Then the pores were subsequently filled until the whole sample was covered by liquid water (Figures 7 and 8). The water condensed in narrow pores relatively easily, because these pores have larger capillary pressure than wider pores (Figure 8). Later, the water was gradually evacuated by lowering the vapor pressure in the sample room. As the liquid water was progressively removed, large pores emptied first, followed by small pores (Figures 9 and 10). This indicates that the properties of smaller pores were easily affected by water. Figure 10 also shows that even after evacuation to a terminal pressure approaching 0.5 Torr, some water may still remain in the pores, probably as a result of capillary suction. To remove the water from the shale, large forces are needed to overcome the capillary suction because the pore throats of the shale are narrow. Different minerals (e.g., chlorite and feldspar) interacted differently with water. The water tends to condense around feldspar (Figures 8 and 12), while it tends to form a coating layer on chlorite (Figure 11). Because of the limitation of the FESEM in water vapor mode, we were unable to observe water interactions with organic matter and its pores. However, this is an important field for future study since it will have a significant impact on gas transport in organic pores. 3.3. Shale Swelling with Water. The swelling strains of the shale immersed in deionized water were 0.25% in the direction perpendicular to the bedding and 0.15% in the direction parallel to the bedding (Figure 5). This is the maximum swelling for this shale in pure water, and the main cause could be hydration of clay minerals. Clay minerals are layered aluminosilicates and contain exchangeable interlayer cations. The sample was dewatered, and layers of clay minerals were closely compacted before being contacted with water. As water moves into the shale, hydration of exchangeable cations occurs.8,9,50 Figure 11 shows that hydration caused a film of water to adsorb on the layer of clay minerals. The change of distance between the clay layers has been detected using X-ray diffraction;51 hydration of shale increases the distance between clay layers and thus induces macroscopic swelling of the sample. However, we did not observe changes in the distance between clay layers using FESEM because of its limited sensitivity. The linear swelling of the shale in this study is much smaller than those of other shales under the same conditions, which range from 0.54−2.4%.7,16 An obvious difference between the other studies and ours is that the clay mineral content of the shales in the published studies was 64−72%, while ours contained only 13%. Organic matter may also contribute to the swelling of shale. This can be illustrated by the swelling of coal induced by water adsorption,52 since the main constituent of coal is organic matter. Other factors may also relate to the different mechanical properties of the shale; for example, swelling is also related to the Young’s modulus and Poisson’s ratio.53 The swelling in both directions (parallel and perpendicular to the bedding) has an approximately linear relationship with water content (Figure 5). The shale sample shows quite strong anisotropic swelling, as do many other shales.7,9,19 Shale has an
potential. The diffusivities obtained from the modeling results at relative humidities of 78% and 93% are approximately 2.94 × 10−11 and 2.7 × 10−11 m2/s, respectively, which are smaller than that of shale in deionized water (4.92 × 10−11 m2/s). This may be the case because microfractures from the surface of the sample accelerate water uptake due to capillarity, thus making the transport rate for liquid water higher than that for water vapor. Clay swelling may play a role for both vapor and deionized water uptake. Moreover, the osmotic potential make water tend to move into the shale sample if lots of salt exist. However, because the swelling ratio is very low and no salt exists in vapor and deionized water, their impact on water uptake is considered to be minimal for this shale. On the basis of the experiment results and diffusion modeling, diffusion is shown to play a controlling role under our experimental conditions because of the large fraction of nanopores in this shale, which required about 30 days for the water adsorption to reach equilibrium. In the wettability experiments, when a water droplet fell onto the two different shale surfaces (parallel and perpendicular to the bedding), water entered the shale. The droplet volume decreased with time as a result of imbibition of water by the shale and evaporation of water into the air (Figure 1). Since the contributions of evaporation on the two different surfaces were equal and relatively minor, the difference in the rates of the droplet volume decrease on the two surfaces can be attributed to differences in the imbibition rate. Imbibition anisotropy has also been observed in previous studies.37,38 It is indicated that the anisotropy property can be related to the clay minerals contained in the shale sample.38,47 Minerals, especially layered clay minerals, were forced to align in the preferred direction during the diagenetic compaction process, and this makes the shale present a laminated texture along the bedding direction macroscopically. Meanwhile, microfractures also developed parallel to the bedding direction. Moreover, the smaller contact angle on the surface perpendicular to bedding direction (Table 2) represents larger capillary pressure on that surface. Thus, more imbibition pathways and larger capillary forces along bedding direction make the anisotropic wettability and imbibition rate of the shale parallel to the bedding higher than those of the shale perpendicular to the bedding (Figure 2). 3.2. Storage of Water in the Shale. The contact angle results showed that the shale was overall hydrophilic. The shale sample contains 70% quartz, 13% clay minerals, and 2.9% organic matter (Table 1). Quartz is a water-wet mineral.48 Experimental data show that the contact angle decreases with increasing clay content and increases with increasing TOC.49 Thus, it is reasonable that the shale sample was overall hydrophilic. Nevertheless, shale consists of hydrophilic clay or other inorganic minerals and hydrophobic organic material, and it is a porous material. It may be both water-wet and oil-wet, as experiments have indicated for other shales.35,37 The adsorption potential of the sample was very low, with a saturated water content of 1.22 wt % in deionized water. This may be because the shale has low porosity and limited pore connectivity, so that little water can transport into the sample. It is indicated that a significant amount of the fracturing fluid would be trapped in the space of natural or hydraulic fractures after hydraulic fracturing. The adsorption isotherm is a type III isotherm according to the IUPAC classification, and this agrees well with the microscopic observation. During microscopic observation, the vapor pressure in the sample room was increased from dry conditions at a pressure of 0.5 Torr to the water saturation pressure of 6.1 Torr at 4 °C. Condensation G
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inherent anisotropic texture, and clay platelets of shale deposit parallel to the bedding planes during sedimentation and compaction. This directional alignment results in more swelling in the direction perpendicular to the bedding planes than in the direction parallel to the bedding planes.9 The anisotropic swelling suggests that the swelling of shale is related to its textural characteristics in addition to its mineral constituents. The microscopic observation experiment of water−shale interactions lasted 1 day. Water vapor and its condensation were introduced to the sample four times during the 1 day experiment. Interactions between water and minerals exposed on the surface during this period were observed. No noticeable changes were observed before and after water immersion (Figures 11 and 12), indicating that these interactions during this period of time may be reversible. The longer-time interactions between slowly reacting minerals and water will need to be conducted by using new experimental procedures in future research. Besides the fact that the shale swelling would impact the gas flow behavior in the shale matrix, it may also have an impact on the opening of the hydraulic fractures, which are supported by proppants. Swelling of the shale matrix due to water intake tends to close the fractures under reservoir conditions, reducing the conductivity of the fractures and ultimately reducing the shale gas production rate. Since reservoir pressure/stress and temperature are much higher than those under laboratory conditions, the swelling caused by water intake would not be the same under the reservoir conditions. Water−shale interactions under reservoir conditions will require further study in the future. 3.4. Mechanical Property Changes at Different Moisture Levels. The Young’s modulus of the shale sample is reduced by up to 38% in going from the dry state to the watersaturated state with a water content of 1.22% (Figure 6). It decreases with increasing water content in an almost linear relationship, similar to those of some other shales.10,13 The water-induced reduction of the Young’s modulus may have two causes. First, the mineral contact areas of the shale are placed under an external axial load. Hydration may force the clay mineral layers of the shale to partially separate from each other, reducing the contact area and placing the remaining areas under more stress. Consequently, as the sample is exposed to more water, it deforms more under the same external load. Another possible reason is that water inside the sample may serve as a lubricant, reducing the frictional resistance of all minerals of the shale. Other reasons may also exist, and further study is required to better understand this behavior.
bedding. Also, the maximum swelling in the direction perpendicular to the bedding (0.25%) is significantly higher than that in the direction parallel to the bedding (0.15%). (3) The water content has a significant impact on the shale properties. The swelling strain has an almost linear relationship with the water content in the sample. The Young’s modulus is reduced by 38% in going from the dry sample to the water-saturated sample. (4) Experimental data indicated that water transport into the sample occurs mainly by diffusion under the experimental conditions. A unipore diffusion model is able to describe the water and water vapor transport process in the shale matrix. Capillary pressure may accelerate the adsorption rate when the shale is immersed in water.
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Phone: +61 3 9545 8394. Fax: +61 3 9545 8380. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS This work was supported by the Strategic Priority Research Program of the Chinese Academy of Sciences (Grants XDB10030300 and XDB10050400) and a CSIRO Julius Award. The authors also thank Dr. Matthew Glenn for performing the FESEM experiments.
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REFERENCES
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4. CONCLUSIONS This work studied the interaction of water with a lower Silurian shale sample from Sichuan Basin, China, through experiments on the microscopic and macroscopic scales. Water storage and transport mechanisms as well as changes in shale properties such as swelling and Young’s modulus were investigated. The conclusions below can be drawn for the shale studied in this work: (1) The shale studied is overall hydrophilic, and the surface perpendicular to the bedding is more hydrophilic than the surface parallel to the bedding. Nevertheless, the water adsorption capacity of the sample is very low (1.22%). (2) The shale is anisotropic with regard to water interactions. The surface perpendicular to the bedding has a higher water imbibition rate than the surface parallel to the H
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dx.doi.org/10.1021/ef500915k | Energy Fuels XXXX, XXX, XXX−XXX
