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. 2021 Jan 11;6(3):2215–2229. doi: 10.1021/acsomega.0c05490

Synergetic Effect of Water, Temperature, and Pressure on Methane Adsorption in Shale Gas Reservoirs

Wencheng Han 1, Aifen Li 1,*, Asadullah Memon 1, Min Ma 1
PMCID: PMC7841931  PMID: 33521461

Abstract

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Adsorption is one of the most important forms of storage of gas in shale reservoirs. Shale gas adsorption in the actual reservoir is not only affected by individual factors such as water content, temperature, and pressure but also by the synergetic effect of these factors. In this study, we conducted laboratory experiments on methane adsorption in dry and wet shale at different pressures and temperatures. The synergetic effect of water content, temperature, and pressure on shale gas adsorption is explored. The results show that increasing temperature weakens the interaction between methane and shale and reduces adsorption capacity due to the exothermic nature of adsorption. Water reduces methane adsorption capacity by occupying adsorption sites and blocking pores in the shale system. Although temperature and water reduce methane adsorption individually, the effect of these two factors weakens each other. Temperature has a more significant effect on methane adsorption in shales with low water content, while water has a more remarkable impact on methane adsorption at a low temperature. Furthermore, the increase in pressure reduces the negative influence of water and temperature on methane adsorption. By quantitatively analyzing the relationship between methane adsorption in dry and wet shales, a predictive adsorption model for wet shale considering the influence of in situ conditions is proposed and validated. Validation shows that the proposed model has high accuracy and broad applicability to shales with different properties.

1. Introduction

Nowadays, shale gas has gradually become an essential strategic resource and a powerful energy supplement due to its wide distribution range, large reserves, and long stable production cycle.1−3 Shale gas reservoirs are quite different from conventional gas reservoirs. Gas in the shale reservoir is mainly stored in the form of free gas, adsorbed gas, and dissolved gas.4−9 The free gas is compressed in the micropores and cracks of shale.4,6−9 The adsorbed gas is mainly adsorbed on the inner surface of the micropores provided by organic matter (OM) and clay minerals.5−8 Moreover, the dissolved gas is usually stored in kerogen.10,11 It is generally believed that the contribution of adsorbed gas to the total gas content is up to 20–85%.12 Thus, exploring the adsorption characteristics of shale gas under real reservoir conditions is particularly important for a reasonable evaluation of shale gas reserves.

Adsorption is a complex process since it is controlled by various factors. On the one hand, it depends on the inherent properties of shale, such as the total organic carbon (TOC) content, mineral constituents, kerogen types, and maturity. On the other hand, it relies on the external conditions of shale reservoirs, such as temperature, pressure, and water content. Abundant micropores are developed in organic-rich shale, providing a large proportion of adsorption sites for methane.13 Therefore, it is commonly accepted that the adsorption capability of shale is positively related to its TOC level.14−17 As the most critical inorganic component in shale, clay minerals are considered to have a considerable contribution to methane adsorption due to their microstructure.18−23 Furthermore, the strong positive correlation between the clay level and methane adsorption in shale with low TOC content has been reported.13,24−27 However, no definite relationship between the clay content and methane adsorption was observed in TOC-rich shale.28−31 Although the TOC content is the dominant controlling factor in shale adsorption, kerogen type and thermal maturity also significantly influence the adsorption capability of shale. Type II kerogen is considered to be the most common source of shale gas reservoir,32 and type III kerogen has the highest sorption ability due to the fact that more micropores and hydrocarbons are generated in it.24,25 Experimental investigation found that methane adsorption capacity was positively correlated to the thermal maturity of shale.33−35

The in situ conditions of high temperature, high pressure, and water content play significant roles in the shale gas adsorption process. Due to the exothermic nature of physical adsorption, less adsorbed gas is expected in the high-temperature shale gas reservoirs. The experimental investigation suggested that higher temperature results in a lower gas sorption content in the Devonian shale reservoir.9 Zhang believed that methane adsorption in both shale and isolated kerogen decreased with increasing temperature,7 which is in line with the conclusions obtained from other investigations.36−41 It is widely reported that methane excess adsorption in shale and coal does not increase monotonically but first increases and then decreases with increasing pressure.17,28,42−45 However, the absolute adsorption increases monotonically and is greater than the excess adsorption.46,47 The difference between absolute adsorption and excess adsorption is related to the ratio of the free gas density to the adsorbed gas density.44,46 The density of free gas in the low-pressure stage is much lower than the density of adsorbed gas; therefore, the excess adsorption is approximately equal to the absolute adsorption. With the increase of pressure, when the increasing rates of the free gas density and the adsorbed gas density are equal, the excess adsorption reaches the maximum.46 Thereafter, as the pressure continues to increase, the increasing rate of the free gas density is greater than that of the adsorbed gas density, which decreases excess adsorption, and the difference between excess adsorption and absolute adsorption becomes greater.46 Molecular simulation suggested that methane adsorption in type II kerogen reaches the maximum at a pressure of 10 MPa and then declines with increasing pressure.44 Xiong found that the pressure corresponding to the maximum methane adsorption in chlorite is between 14 and 18 MPa,43 while the pressure of 10–19 MPa was observed in organic-rich shales.17,28,45

Dry shale samples are commonly used in most investigations. As a matter of fact, shale is generally deposited as mudstone in the tidal marsh or deep-water basin,48 and it is carried out in the water environment from kerogen degradation to methane generation.49,50 Organic-rich shales are considered to be originally deposited in water-containing conditions.49 Researchers believe that a low-oxygen marine environment is conducive to the deposition of shale gas reservoirs.51,52 Ren summarized the initial water saturation of shale gas reservoirs worldwide and found that the initial water saturation of most reservoirs is lower than 70%.53 Besides, hydraulic fracturing technology has become an indispensable tool in shale gas development. Retention of fracturing fluid also causes shale gas reservoirs to contain a certain amount of water.54−56 Water is everywhere in shale gas reservoirs,57−59 and its effect on methane adsorption capacity should be taken into consideration in the gas reserve evaluation. Fortunately, the influence of water on shale gas sorption has been drawing increasing attention. It is commonly believed that water negatively affects methane adsorption in reservoirs.22,8,20,31,60−63 This is attributed to water occupying the adsorption sites and blocking the flow channels.64−66 Chalmers and Bustin found that the distribution of sorption sites in organic and inorganic matter may affect the adsorption capability of wet shale.67 Yuan believed that water in the shale reservoir severely reduces methane adsorption and decreases gas diffusion.20 Gasparik found that the amount of methane adsorbed in moist shale was 40% lower than that in dry shale.28,62 Zhao found that water is adsorbed in clay pores and OM pores with oxygen-containing functional groups, which significantly reduces methane adsorption in shales.32 Xiong found that water is stored in aggregates in the chlorite pores, thereby inhibiting the adsorption of methane molecules.43 Fan and Yang experimentally investigated methane sorption in wet shale and suggested that water reduces methane sorption in three steps, relying on the shale physical properties.10,68 Merkel suggested that water affects gas adsorption only when the moisture is lower than a specific value, which is similar to the adsorption in wet coal.60 However, further investigations showed that both methane adsorption capacity and effective porosity present a linear decrease as water content increases.53,69,70

The individual influence of water, temperature, and pressure on the shale adsorption capability has been well documented. However, these factors always work together to control the adsorption process under in situ conditions. Understanding the synergistic effect of water, temperature, and pressure on methane adsorption is key to accurately assess shale gas content in the reservoir. In this study, methane adsorption in dry shale and wet shale was measured at different conditions, and how multifactors of water, temperature, and pressure synergistically impact shale gas adsorption were analyzed. Finally, based on the quantitative analysis of the relationship between dry shale and wet shale adsorption, a new adsorption prediction model considering the synergetic impact of temperature, pressure, and water content for wet shale was proposed, and the applicability of the model has also been validated by a considerable number of published sorption data.

2. Experimental Section

2.1. Sample Preparation

Shale samples adopted in this study were obtained from a shale gas reservoir located in southeastern Sichuan, China. The collected shales were dried at 110 °C for 10 h after being taken from the reservoir. Then, a small fraction of the samples were ground to particles with a size of 0.075–0.15 mm for the TOC test and mineral constituent measurement. The remainder of the samples was ground to particles with a size of 0.18–0.38 mm for the shale gas adsorption test. The TOC content and the mineral constituent of the shale sample are shown in Table 1. Boyer recommends high-quality kerogen with a TOC range of 2–4%.71 The TOC content of this sample is 3.659%, indicating that the shale we used has great potential for adsorbed gas storage. Besides, the shale sample has a high quartz level of 56%, implying that hydraulic fracturing may effectively promote shale gas production in this reservoir.

Table 1. Basic Properties of the Shale Sample.

  mineral constituent (%)
TOC (%) total clay quartz calcite plagioclase K-feldspar dolomite pyrite
3.659 16 56 4 12 4 4 4
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To investigate the effect of water on methane adsorption characteristics in shale, wet shale with different water contents needs to be prepared. The samples were dried at 110 °C under evacuation for 10 h to remove gases and the residual water content. Then, water was added to a previously evacuated flask containing dry shale samples of known mass, and the flask was then placed in an oven with an evacuation feature. The mass was weighed regularly until the required water amount was reached.72,73 Finally, wet shales containing water of approximately 1, 2, 3, and 4% were obtained. The value of the water content was estimated by eq 1

2.1. 1

where Wt is the water content, %, and mdry and mwet are, respectively, the mass of dry and wet samples, g.

2.2. Isothermal Adsorption Test

Figure 1 shows the schematic diagram of the adsorption apparatus (YRD-HPHTsor) built on a volumetric method. The apparatus consisted of the methane and helium source with purity greater than 99.99%, a reference cell (RC), a sample cell (SC), a booster pump, a high-pressure gas vessel, a vacuum pump, an oil bath, and the data collection system. The RC and SC are constructed using stainless steel. The connection of the SC to the apparatus is made with a metal gasket face seal fitting, which provides a good seal. A filter gasket is used between the junction of tubing and fitting to prevent entrainment of adsorbent in the cell during vacuuming. “HIP” series valves (High Pressure Equipment Co.) are used in the apparatus due to their durability under high pressure and temperature. An oil bath (Memmert GmbH + Co., Germany) designed to maintain a temperature change of no more than 0.1 °C to provide a constant temperature to the system was employed. Pressure transducers (Setra Systems, Inc.) and temperature transducers (Omega Engineering, Inc.) were used to record the pressure and temperature in the RC and the SC, respectively. Pressure transducers and temperature transducers have a resolution of 1 × 10–3 MPa and 1 × 10–3 °C, respectively. The transducers and temperature control units are interfaced with a personal computer, and the temperature and pressure are recorded by the data collection system in real time.

Figure 1.

Figure 1

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Schematic diagram of the methane adsorption apparatus.

The detailed experimental steps have been extensively reported.22,65,74 The four main steps in our study are as follows:

  • (1)

    Air-tightness checking: the entire system was charged with helium up to 28 MPa. Air-tightness is assured if no pressure drop is detected for 5 h at a designed temperature.

  • (2)

    Reference cell calibration: the multiple gas expansion method reported previously was employed in this study.33 A known-volume steel block was placed in the SC, and helium was introduced from the RC to the SC. The pressure and temperature before and after helium expansion were recorded. Then, another known-volume steel block was added to the SC, and the procedure was repeated. Finally, the volume of the RC can be calculated accurately after five helium expansions. It has been confirmed that this calibration method has an error of less than 0.4%.33

  • (3)

    Free space determination: after the RC volume was determined, the free space in the SC except for the samples’ skeleton can be measured through helium expansion from the RC to the SC at the designed experimental temperature. In this study, expansions were carried out over eight pressure steps ranging from 1 to 12 MPa. The free space volume was calculated at each pressure step, and the average was taken as the final free space volume.

  • (4)

    Isothermal adsorption: the RC was charged with methane, which was introduced from the RC to the SC step by step until the final pressure was reached.

The excess adsorption amount was obtained according to eq 2

2.2. 2

where nex is the excess adsorption capacity, cm3/g, STP; mt is the total mass of methane charged into the SC, g; ms is the mass of the sample, g; ρg is the bulk density of methane, g/cm3; Vfree is the free space of the SC, cm3; Vm is the molar volume of gas under standard conditions, i.e., 22 400 cm3/mol; and MCH4 is the molar mass of methane, g/mol.

Notably, adsorption is a time-dependent process, and the time for adsorption equilibrium at each experimental pressure is 8–12 h in this work. The equilibrium time is related to shale properties and external conditions. Investigations found that the equilibrium time decreases with the increase of temperature and pressure and increases with the increase of the TOC content and particle size of shale samples.75,76 The experimental study found that there is a good linear correlation between the reciprocal of the adsorption capacity and the reciprocal of the square root of time.77 It is often assumed that adsorption is instantaneous equilibrium in the current numerical simulation of shale gas, which is not consistent with the actual adsorption process, and may cause errors in the simulation results. In addition, the accurate calculation of excess adsorption capacity relies on a reliable equation of state (EOS). It is widely believed that the multiparameter wide-range EOS proposed by Setzmann and Wagner is the most accurate EOS for methane.78 Hence, this EOS was employed in this study to determine the density of methane.

2.3. Langmuir Model

The classical Langmuir model is considered suitable to describe the isotherms of most shales and coals in the literature,22,30,79−81 as shown in eq 3.82Equation 3 shows the Langmuir equation, which describes the relationship between absolute adsorption capacity and pressure. However, the excess adsorption capacity obtained by the experiments cannot represent the actual sorption capacity since the volume occupied by the adsorption phase is ignored in the adsorption calculation.42,73 It is preferable to use the absolute adsorption isotherm, which represents the real adsorption behavior of the gas. In this work, the excess adsorption data were converted into absolute adsorption data by eq 4,73 and “adsorption capacity” mentioned in other sections refers to the absolute adsorption capacity.

2.3. 3
2.3. 4

where nab is the absolute adsorption capacity, cm3/g, STP; n0 is the Langmuir volume, cm3/g, STP; P and PL are experimental pressure and Langmuir pressure, respectively, MPa; and ρa is the density of the adsorbed methane, g/cm3. The value of ρa varies from scholars to academics,26 and the liquid methane density has been used as the density of adsorbed methane in many studies on shale and coal adsorption.20,83,84 Therefore, this density is adopted in this work, i.e., 0.421 g/cm3.

3. Results and Discussion

3.1. Methane Adsorption Measurement

Methane adsorption in dry and wet shales with different water contents were measured at 30, 45, 60, and 80 °C. The Langmuir model was employed to fit the absolute adsorption data using the least-squares method. The coefficient of determination (R2) was employed to evaluate the quality of the fittings. Table 2 shows the Langmuir parameters obtained by model fitting. The comparison between the measured adsorption data and the calculated results from the Langmuir model is shown in Figure 2.

Table 2. Fitting Results of the Langmuir Model for Methane Adsorption in Shales.

temperature (°C) water content (%) n0 (cm3/g), STP PL (MPa) R2
30 0 4.971 4.775 0.9919
1.12 4.609 5.298 0.9918
2.03 4.347 5.662 0.9939
3.15 4.066 6.057 0.9940
4.22 3.825 6.379 0.9938
45 0 4.636 5.375 0.9952
1.1 4.357 5.910 0.9948
2.03 4.141 6.130 0.9991
3.05 3.941 6.655 0.9960
4.22 3.709 7.207 0.9993
60 0 4.177 5.849 0.9906
1.06 4.044 6.467 0.9915
2.23 3.908 7.146 0.9920
3.07 3.817 7.600 0.9918
4.16 3.701 8.153 0.9960
80 0 3.831 6.761 0.9902
1.04 3.757 7.478 0.9920
2.05 3.692 8.204 0.9957
3.10 3.624 8.919 0.9940
4.20 3.556 9.649 0.9957
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Figure 2.

Figure 2

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Adsorption isotherms of methane in shale with different water contents at (a) 30 °C, (b) 45 °C, (c) 60 °C, and (d) 80 °C.

Figure 2 shows the measured isotherms of methane adsorption in wet shales at different temperatures. A general trend at all temperatures can be observed where the absolute adsorption amount increases rapidly as pressure increases in the range of 0–10 MPa. Then, the adsorption reaches a plateau gradually. Besides, it is evident that water has a significant effect on methane adsorption. The higher the water content of the shale sample, the lower the methane adsorption amount. This coincides with the findings of previous investigations.20,28,62,85 It can also be observed from Figure 2 that the fitting results of the Langmuir model are in excellent agreement with the experimental results.

Langmuir volume (n0) and Langmuir pressure (PL) are commonly used to evaluate the gas adsorption capacity and production ability of shale gas reservoirs. These are also critical parameters for numerical simulation of the gas flow in shale reservoirs. Table 2 shows the Langmuir parameters and R2 at different temperatures and different water contents. All of the values of R2 in Table 2 are higher than 0.99, which indicates that the Langmuir model is good enough to characterize the methane adsorption behavior in moist shale at different conditions. It is feasible to use this classic model in our work due to its concise expression and high accuracy. The adsorption of methane in shale gas reservoirs is complexly affected by external factors. The impact of water, temperature, and pressure on methane adsorption is further analyzed in the following sections.

3.2. Effect of Temperature

The process of gas adsorption in shale is accompanied by energy release, which is inevitably affected by temperature. In this section, the effect of temperature on shale gas adsorption in dry shale is discussed by comparing the Langmuir volume (n0), Langmuir pressure (PL), and the adsorption reduction rate at 30, 45, 60, and 80 °C. As for the role of temperature in moist shale adsorption, the synergetic effect of water and temperature is further discussed in Section 3.4. Figure 3 displays the correlations between the Langmuir parameters, adsorption reduction rate, and temperature.

Figure 3.

Figure 3

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Correlation between temperature and (a) Langmuir parameters and (b) adsorption reduction.

Langmuir volume n0 has a good linear correlation with temperature, as presented in Figure 3a. As the temperature increased from 30 to 80 °C, n0 of 4.971 cm3/g reduced to 3.825 cm3/g. This indicates that an increase of 50 °C leads to a 23.05% reduction in the maximum adsorption capacity. The molecular simulation found that increasing temperature reduces the isosteric heats of adsorption,43 while methane adsorption sites tend to shift from low-energy sites to high-energy sites, resulting in a decrease in methane adsorption.36,43 Langmuir pressure PL is a temperature-dependent parameter related to the enthalpy of adsorption, and the relationship between PL and temperature can be expressed as86,87

3.2. 5

where T is the temperature in K; ΔH is the adsorption enthalpy, J/mol; ΔS0 is the standard adsorption entropy, J/mol/K; R is the ideal gas constant of 8.3145 J/mol/K; and P0 is the atmospheric pressure of 0.101 MPa. The negative linear relationship between ln PL and 1/T can be observed in Figure 3a, which indicates that the higher the temperature, the higher the PL. It can be inferred that the pressure required for the maximum adsorption of methane in shale is higher at high temperatures.

Based on the adsorption at 30 °C, the adsorption reduction rate at 45, 60, and 80 °C is, respectively, calculated at different pressures, as presented in Figure 3b. Within the experimental pressure range of 0–22 MPa, adsorption capacity decreased by 27.91–44.01% when the temperature was increased from 30 to 80 °C. In comparison, the adsorption capacity was reduced by 8.64–16.26% when the temperature increased from 30 to 45 °C. Besides, the adsorption reduction rates at different temperatures decreased rapidly when the pressure was lower than 8 MPa, and they showed a gradual reduction when the pressure was greater than 8 MPa. This implies that the temperature negatively affects shale gas adsorption more significantly under low pressure than under high pressure, which should be related to the exothermic nature of adsorption.44 The thermal motion of methane molecules increases after the temperature is increased, making adsorption more difficult. However, low pressure implies fewer methane molecules and a longer molecular mean free path, which causes the increased temperature to be more effective in promoting the thermal movement of methane molecules and greatly reducing the adsorption capacity.88,89 At higher pressure, the free pore space decreases with the increasing number of methane molecules. Stronger interactions such as collision and repulsion between molecules make the desorbed methane molecules more likely to return to the sorption sites, which weakens the negative influence of temperature on methane sorption.

3.3. Effect of Water Content

To explore the role of water in adsorption, methane adsorption in wet shale at 45 °C is analyzed in detail in this section. The synergetic effect of water and temperature is further discussed in Section 3.4. Figure 4 presents the effect of water content on the Langmuir parameters and the adsorption reduction rate.

Figure 4.

Figure 4

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Correlation between water content and (a) Langmuir parameters and (b) adsorption reduction rate at 45 °C.

Figure 4a shows that both n0 and PL have a good linear relationship with water content less than 4.22%. With the increase of water content in shale, n0 decreases linearly. Compared with the dry sample adsorption, the Langmuir volume of the wet sample (Wt = 4.22%) is reduced by 20%, while the Langmuir pressure is increased by 34.1%. Billemont conducted an experiment and molecular simulation to examine the effect of water on methane adsorption in nanoporous carbons and suggested that methane adsorption decreased linearly as the water content increased.69 Huang found that both the methane adsorption capacity and effective porosity in kerogen decreased linearly as the water content increased.70 By summarizing the initial water saturation and methane adsorption data of Fayetteville, Haynesville, Marcellus, Eagle Ford, Barnett, Fushun-Yangchuan, Fuling Shale, and Changning-Weiyuan Shale, Ren found that the initial water saturation in all of these shales is less than 70%. Furthermore, within this water saturation range, the maximum adsorption capacity in these shales has a negative linear correlation with water content.53

Shale is a complex system due to its multicomponent constituent and multiscale pore structure. Therefore, the effect of water on methane adsorption in shale is closely linked to the shale maturity, constituents, and pore structures. A consensus has been reached that water reduces the adsorption of methane in shale. The essential reason for this may be that sorption sites in both organic and inorganic pores are occupied by water. It is widely accepted that clay minerals are the main sites for water adsorption due to their hydrophilic properties, and organic matter (OM) in the shale reservoir is hydrocarbon-wet. In fact, water molecules not only exist in clay but are also present in organic pores. Since the surface of organic pores often contains a certain amount of oxygen-containing functional groups with hydrophilic properties, the mixed-wetting surface properties of OM have been reported.90 This indicates that water molecules might be trapped in organic pores and thereby reduce methane adsorption.

Figure 5 depicts the water distribution in the OM pores and inorganic pores of shale. As shown in Figure 5a, from a molecular perspective, water molecules initially bonded to the functional groups in OM pores at low water content, reducing the number of sorption sites for methane.91 It has been reported that water, respectively, reduces methane adsorption by 22 and 17% in immature and postmature kerogen with the same water content of 0.6%.32 This may be due to the fact that immature kerogen contains more functional groups and water has a stronger affinity with functional groups containing oxygen and nitrogen atoms.92−94 However, competitive adsorption between water and methane was found in clay pores at low water content.26,59,95 Due to the strong dipole moment,26,96 the affinity between clay surface atoms and water is higher than that between clay and methane, and the monolayer adsorption of water occurs at the walls of clay pores.

Figure 5.

Figure 5

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Water distribution in shale pores at (adapted from Sang97 and Yang98) (a) low water content, (b) intermediate water content, and (c) high water content. Adapted with permission from [Sang, G.; Liu, S.; Elsworth, D. Water vapor sorption properties of illinois shales under dynamic water vapor conditions: Experimentation and modeling. Water Resour. Res. 2019. https://doi.org/10.1029/2019WR024992]. Copyright 2019 American Geophysical Union. Adapted with permission from [Yang, R.; Jia, A.; He, S.; Hu, Q.; Dong, T.; Hou, Y.; Yan, J. Water adsorption characteristics of organic-rich Wufeng and Longmaxi Shales, Sichuan Basin (China). J. Pet. Sci. Eng. 2020. https://doi.org/10.1029/2019WR024992]. Copyright 2020 Elsevier Ltd.

As the water content increases, aggregation of water molecules at the center of the OM pores takes place, as shown in Figure 5b, making it difficult for methane molecules to enter the narrow pores and further reducing the sorption capacity of methane.91 Meanwhile, water is adsorbed on the clay pores via multilayer adsorption at an intermediate water content,99,100 and the water film at the pore throat is aggregated to the water bridge. The high gas–water capillary at the throat prevents methane from entering the pores, thereby significantly reducing the flow capability and adsorption capacity of methane in inorganic matter. As the water content increases, the water cluster in the organic pores forms highly ordered structures,98 as shown in Figure 5c, which dramatically limits the entry of methane molecules into such organic pores. With the increase of water bridges in the clay pores, most clay pores are filled with condensed water, seriously reducing the adsorption of methane in clay.

It can be observed from Figure 4a that PL increases linearly as the water content increases. Investigation of methane adsorption in moist coals has shown that the coal sample with higher water content also has a higher PL.101,102 Gensterblum believed that PL is related to the adsorption enthalpy, reflecting the interaction between the adsorbent and the adsorbate.102,103 The lower the PL, the greater the affinity between the adsorbent and the adsorbate. As mentioned above, in shale, water tends to initially adsorb on the surface of clay pores and bond to the functional groups in the OM pores. The number of sites available for methane adsorption is severely reduced, which weakens the interaction between shale and methane and leads to an increase in PL.

On the basis of the adsorption in the dry sample, the adsorption reduction rate in wet samples was calculated at different pressures, as shown in Figure 4b. A distinct trend is observed: the higher the water content, the more significant the reduction in adsorption. Compared with the dry sample, the adsorption reduction rates in the moist samples with water contents of 1.10 and 4.22% are 7.81–13.86 and 25.02–39.01%, respectively. Adsorption reduction due to water varies with shales. It is closely related to shale intrinsic properties, such as clay content, the maturity of kerogen, etc. Immature kerogen has more oxygen-containing functional groups, and its adsorption capability is more susceptible to water content.32,70 Water decreased methane adsorption by 22 and 17% in the immature and postmature kerogen with the same water content of 0.6 wt % at 298 K.32 The samples from Bossier shale and Haynesville shale were moisturized to 97% RH resulting in a 78 and 68% reduction in adsorption, respectively.60 It can also be seen in Figure 4b that the adsorption reduction rate decreases with the increase in pressure. The increase in water content of 1.1 and 4.2% resulted in an adsorption reduction of 13.29 and 37.85% at 1 MPa and a reduction of 7.96 and 25.38% at 20 MPa, respectively. It may be deduced that the content of adsorbed methane is relatively less affected by water in high-pressure shale gas reservoirs. A similar phenomenon has also been found in moist kerogen and porous carbons.32,104 This tendency maybe because parts of the pores are blocked by water at low pressure and methane molecules do not have sufficient energy to penetrate the water blockage, which dramatically reduces the chance for methane adsorption on the surface of these water blocked pores. The higher the water content, the more severe the blocking effect. Nevertheless, with increases in gas pressure, the water clusters can be moved, which changes the distribution of methane–water in shale pores, and some blocked pores may be reconnected. Therefore, the effect of water on methane adsorption at high pressure is weakened.

3.4. Synergetic Effect of Water, Temperature, and Pressure

The individual effect of temperature and water content on methane adsorption in shale has been discussed in previous sections. The elevated temperature decreases the methane adsorption capability evidently. Also, the presence of water inhibits methane adsorption on the surface of clay pores and parts of organic pores. Even so, the negative influences of temperature and water on methane sorption are gradually weakened as pressure increases, which reflects that methane adsorption in shale is simultaneously subject to multiple external factors of temperature, pressure, and water content. In this section, we compare the adsorption capability of wet shale at different temperatures and pressures to uncover the synergetic impacts of these external factors on shale gas sorption.

Figure 6a depicts the Langmuir volume (n0) changes with increasing water content at different temperatures. A general trend can be found at all water contents where a lower temperature results in a higher n0 in shale. In this study, wet shale has the highest adsorption capacity at 30 °C, while it has the lowest adsorption capacity at 80 °C. This is ascribed to the exothermic nature of physical adsorption. The heat release accompanies methane adsorption in shale, and the rising temperature reduces the interaction between methane molecules and shale, which reduces the methane sorption capacity.

Figure 6.

Figure 6

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Comparison of methane adsorption under different conditions. (a, b) Langmuir volume vs water content and temperature and (c) adsorption reduction rate vs pressure, temperature, and water content.

It can also be found at all temperatures that n0 decreases linearly with increasing water content when the water content is less than 4.22%. The lines’ slope represents the reduction rate of n0 due to water at each temperature and reflects the degree of water influence on adsorption. A higher absolute slope means that water reduces shale gas adsorption more severely. Figure 6a shows that the slope of the regression is different at different temperatures. As the temperature was increased from 30 to 80 °C, the absolute value of the slope decreased from 0.2706 to 0.0653. Compared with the adsorption in dry shale samples, n0 of wet shale (Wt = 4.2%) decreased by 23.1% at 30 °C and 7.2% at 80 °C. It may be inferred that the increase of temperature weakens the effect of water on methane adsorption.

Further, it can be observed that the adsorption capacity of dry shale varies greatly at different temperatures. However, as the water content increases, the difference gradually becomes smaller. Compared with 30 °C, n0 of dry shale and wet shale (Wt = 4.2%) at 80 °C decreased by 22.9 and 7.0%, respectively. It may be speculated that water weakens the effect of temperature on methane adsorption in shale.

Therefore, both water and temperature synergistically and negatively affect methane adsorption in shale. Moreover, the effect of these two factors weakens each other, which can clearly be observed in Figure 6b. It implies that low-temperature and low-water-content conditions are more conducive for adsorbed gas storage. For shale gas reservoirs with high water content and high temperature, the adsorbed gas content is expected to be low. Physical heating to improve shale gas production has been reported in the literature.105,106 However, due to the weakening effect of temperature and water found in this study, promotion of gas production by heating may be more effective in reservoirs with less water content than in those with high water content.

In the methane adsorption process, increasing the temperature reduces methane adsorption at all sorption sites. However, only sorption sites in the OM pores with specific functional groups and sorption sites in clay pores are affected by water.32,59,70,107 It may be speculated that the water and temperature effects weaken each other because these two factors simultaneously affect the adsorption sites at the same location. A previous study suggested that water reduces methane adsorption in small pores more significantly than in large pores.63 It has also been reported that methane adsorption in OM is more sensitive to temperature than in clay minerals. Therefore, the temperature may mainly negatively affect methane adsorption in small OM pores. Besides, the elevated temperature may release parts of the adsorption sites occupied by water molecules,108,109 thereby increasing the chance of methane molecules returning to these sites, which may compensate for the reduced methane adsorption caused by the increase in water content.

Based on the methane adsorption data of dry samples, the reduction rates of methane adsorption in wet samples at different pressures and temperatures are calculated and presented in Figure 6c. It is suggested that the adsorption reduction rate at different water contents and temperatures decreases with increasing pressure, which indicates that increasing pressure reduces the negative influence of water and temperature on methane. In addition, all curves may be classified into three categories, and each category represents the adsorption reduction at different temperatures in the same wet sample. From bottom to top, the corresponding water contents of the three categories are 1.0, 2.0, and 4.2%. At any temperature, the water content corresponding to the highest and lowest adsorption reduction rate is 4.2 and 1.0%, respectively, reflecting that water controls shale gas adsorption more dominantly than temperature. Findings from molecular simulation showed that water dramatically weakens the adsorption capability of kerogen while the impact of temperature can be relatively ignored,32 which is in agreement with the results of this work.

Furthermore, Figure 6c also depicts that for shale with the same water content, the adsorption reduction rate at 30 °C is the highest, while the adsorption reduction rate at 80 °C is the lowest. This suggests that increasing the temperature reduces the adverse impact of water on adsorption, and also further indicates that methane adsorption in shale is a comprehensive and complex process, which is influenced by various external factors together.

3.5. Prediction Model for Adsorption of Wet Shale

As the preparation of wet shale samples is time-consuming and cumbersome, it is necessary to study the relationship between the capacity of methane adsorption in dry and wet shale samples and expect to get a prediction model that can calculate the adsorption amount in wet shale based on the adsorption data of the dry shale sample. To further explore the effect of water on methane adsorption quantitatively, we calculated the ratio of the adsorption capacity of the dry sample to the wet sample (i.e., nd/nw) at each experimental pressure. A higher value of the ratio implies that water reduces methane adsorption more significantly. Further, we analyzed the correlation between the ratio and the water content. The ratio and water content shows an excellent linear relationship at different pressures, as shown in Figure 7. The relationship is expressed as eq 6

3.5. 6

where nd and nw are the absolute adsorption capacity of the dry shale and the wet shale with a water content of Wt, respectively, and k is the slope obtained by the linear regression on nd/nw and Wt. It is worth noting that the slope k quantifies the effect of water content on methane adsorption. A higher k means a more significant negative effect of water on methane adsorption. The intercept of 1 shows that nd = nw when Wt is 0.

Figure 7.

Figure 7

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Correlation between nd/nw and the water content at (a) 30 °C, (b) 45 °C, (c) 60 °C, and (d) 80 °C.

The relationship between the value of nd/nw and Wt at different pressures and temperatures is shown in Figure 7. It can be observed at all temperatures that the lower the pressure, the greater the slope k, and vice versa. It may be inferred that water has a more significant effect on reducing methane adsorption at low pressure, while its effect weakens as pressure increases, which is in agreement with the findings from molecular simulations.32,104 The reason for this may be that a part of the pores is blocked by water, and it is difficult for methane to break through the blockage when the pressure is low, resulting in a very low extent of methane adsorption in shale. However, methane is more likely to break the blocked pores under high gas pressure, entering the pores and being adsorbed on the pore surface. Besides, Figure 7 shows that the increase in temperature leads to a decrease in the slope of the lines at the same pressure, which indicates that the elevated temperature weakens the influence of water on methane adsorption, which is in line with the synergetic effect analyzed in Section 3.4.

To calculate the adsorption capacity of wet shale using eq 6, it is necessary to obtain the slope k. The above analysis shows that the slope k is closely related to temperature and pressure. Therefore, the relationship between the slope k, temperature, and pressure is analyzed in Figure 8. As displayed in Figure 8a, a negative linear correlation between slope k and temperature is found at different pressures, and the R2 values are greater than 0.94. Figure 8b depicts that as the pressure increases, the slope k decreases in a power function with a high R2 value at different temperatures. Therefore, the correlations between the slope k and temperature and pressure can be expressed by eqs 7 and 8, respectively.

3.5. 7
3.5. 8

where T is the temperature, °C; p is the pressure, MPa; and a, b, c, and d are fitting parameters that may be related to shale properties. Assuming that the expression of the slope k is a linear combination of eqs 7 and 8, then the expression of k is shown by eq 9.

3.5. 9

Figure 8.

Figure 8

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Relationship of the slope k and (a) temperature and (b) pressure.

Thus, the relationship among the adsorption capacity of the wet shale nw, the adsorption capacity of the dry shale nd, water content Wt, temperature T, and pressure p can be concluded by substituting eq 9 in eq 6, as shown in eq 10.

3.5. 10

As a newly proposed prediction model, methane adsorption in wet shale at different temperatures and pressures can be calculated by eq 10 based on the dry shale adsorption data. To obtain the values of a, b, c, and d in the proposed model, all experimental data in this study are globally fitted using eq 10, and the fitting results are given in Table 3, which shows a high fitting quality with an R2 of 0.9916. Figure 9 compares the experimental data of wet shale in this study with the adsorption data calculated from the proposed model at different temperatures. It can be seen that the experimental data and the calculated data are in good agreement at different temperatures and water contents.

Table 3. Fitting Results of the Newly Proposed Model.

a b c d R2
–0.0009 –0.1534 0.1234 0.3345 0.9916
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Figure 9.

Figure 9

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Comparison of the experimental adsorption data with the calculated data of the new model.

To further validate the applicability and accuracy of the proposed adsorption model to other shales with different intrinsic properties, the model is applied to fit the adsorption data of 12 samples from other reports in the literature.26,38,62,110,111 The literature we selected provides not only the original experimental data but also the Langmuir parameters. The original experimental data are obtained from the literature using GetData software. Then, the adsorption capacities of dry shale (i.e., nd) and wet shale (i.e., nw) at different pressures and temperatures are calculated using the Langmuir model with the Langmuir parameters provided in the literature. Next, the relationship between nd and nw of each sample is globally fitted by the newly proposed model. The fitting parameters of each sample are given in Table 4. A comparison of the original experimental data with the calculated data from the proposed model is presented in Figure 10.

Table 4. Fitting Parameters of the Newly Proposed Model for Shales from the Literature.

sample a b c d R2 data source
AC2-1 0.0002 –0.32 0.0635 0.5641 0.9833 Zou et al.38,110
AC2-2 –0.0006 –0.0401 0.0839 0.1522 0.9831
AC2-3 –0.0015 –0.0541 0.1184 0.2429 0.9977
AC2-4 –0.0013 –0.0075 0.2318 0.1367 0.9991
AC2-5 –0.0012 –0.0566 0.1606 0.3027 0.9870
CY2-1 0.016 1.4088 0.4387 –1.9387 0.9998 Wang et al.26
CY2-2 0.025 0.6614 0.4537 –1.6255 0.9998
CY2-3 0.0189 1.0151 0.2128 –1.8402 0.9996
CY2-4 0.0254 0.649 0.1682 –1.6127 0.9996
CY2-5 0.0282 0.5401 0.1023 –1.5119 0.9997
N/A 0.0012 –17.8359 0.0103 18.8692 0.9986 Gasparik et al.62
N/A 0.0531 –1.2636 0.0072 –2.047 0.9787 Zhou et al.111
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Figure 10.

Figure 10

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Comparison of experimental adsorption data from the literature26,38,62,110,111 with the calculated data of the proposed model. (a–e) Data for samples of AC2-1, AC2-2, AC2-3, AC2-4, and AC2-5. Reproduced with permission from [Zou, J.; Rezaee, R.; Liu, K. Effect of temperature on methane adsorption in shale gas reservoirs. Energy Fuels2017. https://doi.org/10.1021/acs.energyfuels.7b02639]. Copyright 2017 American Chemical Society. Reproduced with permission from [Zou, J.; Rezaee, R.; Xie, Q.; You, L. Characterization of the combined effect of high temperature and moisture on methane adsorption in shale gas reservoirs. J. Pet. Sci. Eng. 2019. https://doi.org/10.1016/j.petrol.2019.106353]. Copyright 2019 Elsevier Ltd. (f) Data for samples CY2-1, CY2-2, CY2-3, CY2-4, and CY2-5. Reproduced with permission from [Wang, L.; Yu, Q. The effect of moisture on the methane adsorption capacity of shales: A study case in the eastern Qaidam Basin in China. J. Hydrol. 2016. https://doi.org/10.1016/j.jhydrol.2016.09.018]. Copyright 2016 Elsevier Ltd. (g) Literature data. Reproduced with permission from [Gasparik, M.; Ghanizadeh, A.; Gensterblum, Y.; Krooss, B. M. “Multi-temperature” method for high-pressure sorption measurements on moist shales. Rev. Sci. Instrum. 2013. https://doi.org/10.1063/1.4817643]. Copyright 2013 AIP Publishing LLC. (h) Literature data. Reproduced with permission from [Zhou, J.; Mao, Q.; Luo, K. H. Effects of moisture and salinity on methane adsorption in kerogen: A molecular simulation study. Energy Fuels2019. https://doi.org/10.1021/acs.energyfuels.9b00392]. Copyright 2019 American Chemical Society.

It can be seen from Table 4 that all of the R2 values of the 12 samples are greater than 0.97, which implies that the model has high accuracy and broad applicability to describe the adsorption characteristics of wet shale at different pressures and temperatures. The calculated sorption data show excellent agreement with the original experimental data in Figure 10, indicating that the proposed model is reliable and has good applicability to different shales.

4. Conclusions

In this study, laboratory experiments were performed to uncover the synergetic effect of water, temperature, and pressure on methane adsorption in shale. By the quantitative analysis, a prediction model of methane adsorption in moist shale was presented. The following main conclusions can be obtained:

  • 1.

    Due to the exothermic nature of adsorption, the increase in temperature weakens the interaction between methane and shale. The maximum adsorption capacity of methane in shale is negatively correlated with temperature.

  • 2.

    Water not only reduces the methane adsorption capacity in clay but also in organic pores. The higher the water content, the lower the adsorption capacity of methane in shale, and when the water content is less than 4.22%, the maximum adsorption capacity has a negative linear correlation with the water content.

  • 3.

    Methane adsorption in shale gas reservoirs is simultaneously influenced by the factors of water, pressure, and temperature. A high pressure weakens the adsorption reduction caused by the negative impacts of water and temperature. Meanwhile, the effect of water and temperature weaken each other. Water has a more significant effect on methane adsorption at a lower temperature, while temperature reduces the adsorption capacity more significantly in shale with lower water content.

  • 4.

    The ratio of the adsorption capacity of dry shale to wet shale at the same pressure has a linear relationship with water content. Based on the quantitative analysis, an accurate and widely applicable adsorption model considering the synergetic impacts of water, temperature, and pressure is proposed and validated with various shale sorption data.

Acknowledgments

This research work is supported by the National Natural Science Foundation of China (Nos. 51490654 and 51774308) and the National Science and Technology Major Project of China (No. 2016ZX05014-003-002).

The authors declare no competing financial interest.

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