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New insights from supercritical methane adsorption in coal: gas resource estimation, thermodynamics and engineering application Zhaofeng Wang, and Xu Tang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00477 • Publication Date (Web): 06 Mar 2018 Downloaded from http://pubs.acs.org on March 7, 2018
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New insights from supercritical methane adsorption in coal: gas resource estimation, thermodynamics and engineering application Zhaofeng Wang1,2, Xu Tang3 (1-College of Safety Science and Engineering, Henan Polytechnic University, Jiaozuo, Henan, 454000, China; 2-Collaborative Innovation Center of Coal Safety Production of Henan Province, Jiaozuo, Henan, 454000, China; 3-Virginia Center for Coal and Energy Research, Virginia Polytechnic Institute and State University, Blacksburg, 24060, U.S.) Corresponding author: Xu Tang E-mail:
[email protected]; Tel: 540-998-7174 Address: Virginia Center for Coal and Energy Research (0411), 133 Randolph Hall, 460 Old Turner Street, Blacksburg, VA 24061 Abstract: Accurate coalbed methane (CBM) resource estimation becomes significant for CBM extraction through ground CBM wells and underground coal mines, and adsorbed gas accounts for more than 80% of the total CBM in place resource in subsurface coal seams. However, the CBM resource estimation presents many challenges, especially the inappropriate adsorbed gas estimation method and the oversimplified adsorption thermodynamics description. This work tackles both issues by utilizing a dual-site Langmuir model to describe supercritical methane adsorption behavior in anthracite and analyze the corresponding thermodynamic characteristics. The proposed model not only accurately describes measured adsorption isotherms under elevated pressures (up to 17 MPa) and temperatures (up to 352.55 K) and interpret all observed adsorption phenomena, but also can extrapolate the adsorbed gas content and the total gas content at subsurface conditions beyond test conditions. The estimated density of the adsorbed methane is found to be temperature and pressure dependent, which is higher than the gas density but lower than the liquid methane density. The isosteric enthalpy of adsorption for methane in coal shows adsorption uptake dependence and temperature dependence behavior. Using classic simplified Clausius-Clapeyron equation overestimates the isosteric enthalpy of adsorption, which cannot reveal the associated temperature dependence behavior. Furthermore, the proposed method is applied for estimating deep CBM in place resource and understanding coal and gas outburst prediction technology by using the temperature measurement approach. Key words: methane, coal, adsorption, Langmuir, enthalpy
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1. Introduction Natural gas is the cleanest fossil fuels because its combustion emits 50% less greenhouse gases (CO2) and negligible harmful emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), mercury (Hg) and particulates compared to coal and crude oil [1]. These clean utilization facts of natural gas have led into a boost in natural gas consumption all over the world especially with increasing natural gas production from unconventional reservoirs in the past decades [2-3]. This clean fossil fuel also has continuously increased its share in the global energy mix. As a consequence, it is well possible that natural gas will become one of the most import fuels in the future and will have a huge impact on the future global energy landscape. Natural gas produced from subsurface coal seams, also called coalbed methane (CBM), is one of the major sources of natural gas. CBM provides natural gas supplies around the world, and it has become an important source of clean energy in United States, Canada, Australia, and other countries [4]. The total estimated CBM resource of the world is around over 2.55×1020 m3 [5]. In 2014, the CBM production from China and United States is 3.7×109 m3 and 3.9 ×109 m3, respectively [6,7]. In order to extract CBM from subsurface coal seams, the very first step is to evaluate the CBM in place resource. The main component of CBM is methane, which exists in coal seams mainly in two different states, adsorbed phase and bulk gas phase, with a small portion of methane dissolved in formation water [8]. Some researchers have reported that methane may exist in solid solutions but their findings have not replicated by peers [9]. The adsorbed phase of CBM usually accounts for more than 80% of the total gas in place content in subsurface coal seams [2]. Therefore, it is critical to accurately estimate the adsorbed gas content for a credible total gas in place (GIP) resource estimation. There are two routinely used methods for measuring CBM content in coal seams. The direct method actually measures the volume of gas released from a coal sample, sealed into a desorption canister; meanwhile, the indirect method uses either empirical correlation of the field data, or the laboratory gas storage capacity test based on measured adsorption isotherms [10-11]. This work will detail the indirect method, specifically the laboratory gas storage capacity test because it allows a better understanding of methane adsorption behavior in coal in the lab. This study therefore not only lays the foundation for accurately estimating adsorbed gas content and the total gas in place resource, but also provides theoretical basis for developing the true gas transport model for new enhanced CBM recovery technologies [12-15]. Adsorbed methane content can be obtained from adsorption isotherm, which is the adsorption content as a function of temperature and pressure. The adsorption isotherm is routinely measured by either gravimetric method or volumetric method. The gravimetric method is more accurate under high pressure conditions because the adsorbed content is much higher at high pressure conditions and the measuring balance can thus measure the adsorbed content more accurately [16]. Whereas the volumetric method is more accurate at low pressure conditions since the accumulated measuring error is relative small. After methane adsorption isotherm is measured, different models are used to correlate the measured data to describe methane adsorption behavior for understanding methane adsorption mechanism in coal. These models, if they are correctly applied, can be used to extrapolate adsorption isotherms beyond test data for estimating GIP resource under different reservoir conditions [17]. Therefore, in order to accurately estimate adsorbed gas content in coal, it is important to accurately measure adsorption isotherms as well as develop a reasonable gas adsorption model. 2 ACS Paragon Plus Environment
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There are many challenges regarding the selection of the most appropriate model for describing methane adsorption behavior in coals. Several gas adsorption models are available to describe methane adsorption isotherms in coal. The Langmuir adsorption (single site) is most widely used one because it captures the methane adsorption behavior in coal under low pressure conditions where the adsorption content increasing with increasing pressure until it reaches a maximum value. Pore-filling models such as Dubinin−Radushkevich (DR) and Dubinin−Astakhov (DA) model have also been used for describing methane adsorption isotherms on coal [18-20]. Even though all these models work pretty well in fitting each adsorption isotherm under low pressure conditions, these models are merely empirical fitting methods. Most of their assumptions are not valid in describing supercritical methane adsorption in coal because these models are proposed for describing subcritical gas adsorption behavior and there are distinguishable differences between measured adsorption isotherms and true adsorption isotherms under high pressure conditions [17, 21]. The measured methane adsorption isotherm in coal also shows a decreasing trend when the pressure is over 15 MPa [18, 19]. For supercritical methane, the monolayer assumption of Langmuir model and the saturation vapor pressure of gas in porefilling models are no longer upheld [22-23]. Furthermore, these available models do not have the capacity to predict adsorption isotherms beyond test conditions. This shortcoming also impedes their applications in estimate deep CBM resources. Therefore, there is an urgent need to develop a new gas adsorption model for describing supercritical methane adsorption behavior and predicting adsorption isotherms beyond test conditions since CBM in deep coal seams are usually in supercritical status. Gas adsorption behavior in different adsorbents depends on thermodynamic properties of gas and adsorbent interaction [24]. As the gas molecules are adsorbed, the molar entropy of the system and the enthalpy between adsorbed phase and adsorbents both decrease. The isosteric enthalpy of adsorption, historically called isosteric heat of adsorption, becomes an important index for the adsorption process because it describes the differential change in molar enthalpy at constant surface coverage. This also means the thermodynamic characteristics of methane adsorption in coal will provide vital information in understanding methane and coal interactions. Even though the oversimplified Clausius–Clapeyron equation is routinely used to calculate the isosteric enthalpy of adsorption for low pressure methane adsorption in coal, this approach loses its power for supercritical methane since it ignores the contribution of the adsorbed phase as well as the compressibility of the supercritical methane [25]. It is well documented that there is a significant difference between measured adsorption isotherms and the true adsorption isotherms due to the contribution of the adsorbed phase, and the supercritical methane behavior deviates significantly from that of an ideal gas [26-33]. Figure 1 shows the compressibility of the supercritical methane. Recent studies also observed that increasing temperature due to methane adsorption in coal also depends on environmental temperatures [34]. Therefore, in order to reasonably describe the thermodynamic characteristics of methane in coal, a model considering both adsorbed phase and the real gas behavior has to be developed. The model should also have the power to exhibit the temperature dependence behavior of isosteric enthalpy of adsorption.
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Figure 1 Compressibility factor of supercritical methane under elevated pressure and temperatures To understand supercritical methane adsorption mechanism in shales, one of the authors has successfully applied a dual site Langmuir model to describe measured methane adsorption behavior based on the constant adsorbed methane density assumption [17]. However, whether the proposed model can be extended to describe supercritical methane behavior in coal is still unknown since coal and shale are totally different materials especially in generation environments, composition and microscopic pore structure. Furthermore, several recent molecular simulation studies challenge the historical assumption that the density of the adsorbed methane is constant and their studies show that the volume of the adsorbed methane is constant [35-39]. Even though their findings provide the scientific insights for understanding supercritical methane adsorption behavior on a microscopic scale, their proposed models have not been used to predict adsorption isotherms beyond test conditions. This constant-volume assumption still has not been applied to investigate the thermodynamic behavior of supercritical methane adsorption in either coal or shale. In order to tackle the aforementioned issues in interpreting supercritical methane adsorption behavior in coal, this work proposes a new gas adsorption model for describing supercritical methane adsorption behavior in anthracite based on the assumption that the volume of adsorbed film is constant. The new model is used to extrapolate the true adsorption content from measured adsorption isotherm for studying adsorption thermodynamics. The isosteric heat of enthalpy is also calculated by considering the contribution of the adsorbed phase as well as the real supercritical methane behavior. The proposed framework is tested using published data from literature. The possible engineering application of the obtained results is also discussed in details. 2. Gas adsorption theory 2.1 Adsorption model For any pure gas and adsorbent adsorption system, the measured adsorption content is always lower than the true adsorption content because current measuring approaches such as, 4 ACS Paragon Plus Environment
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volumetric and gravimetric method assume the volume of the adsorbed phase is negligible. Based on the Gibbs’s concept, the relationship between the measured adsorption content and the true adsorption content can be expressed by equation (1),
ne = na − va ⋅ ρg = na ⋅ (1−
ρg ) ρa
(1)
where the excess adsorption quantity (ne) refers to the difference between the absolute adsorption quantity (na) and the quantity of adsorbate that would be present in the same volume (va) of the adsorbed phase at the density of the bulk gas phase ( ρg ), and ( ρa ) is the density of the adsorbed phase. It is well known that the equation of state (EoS) of the adsorbed phase such as the density and volume cannot be measured experimentally. In order to extrapolate the true adsorption content using equation (1), a proper phase behavior assumption for the adsorbed phase has to be adopted. Comparing to experimental measurements, molecular simulation can provide underlying mechanisms of gas adsorption from molecular perspective and explore wider range of pressure and temperature conditions. It is observed that the density of the adsorbed methane at different nanopores increases with increasing pressure and decreases with increase temperature, and the distance between the adsorbed methane layer and the pore surface does not change for a specific nanopore at elevated pressure and temperature conditions [35-39]. These new insights indicate that the routinely used constant density assumption of the adsorbed methane may be inappropriate for describing methane adsorption behavior in coals. Therefore, this work adopts these new findings and assumes that the volume of the adsorbed layer on the surface of different size of the pores could be averaged as a constant under elevated pressures and temperatures. If we assume the volume of the adsorbed layer is constant, the density of the adsorbed phase ( ρa ) can be calculated by equation (2),
ρa = na / va
(2)
It is known that the absolute adsorption content (na) should always be a monotonically increasing quantity with elevated pressures for a physical adsorption system, which has been widely described by the single site Langmuir model. However, for heterogeneous porous media such as coal, the adsorption energy at each site will vary because of the local surface chemistry and structure variation. Under this scenario, the most favorable adsorption sites will be occupied first followed by the less favorable sites. The widely used single site Langmuir model becomes limited in this application. In order to tackle the issue of heterogeneous adsorbents, the most simplified case of heterogeneous adsorption sits is adopted here where only two different adsorption sites are available [28-33, 40]. Each site is modelled by a separate
K1(T) and K2 (T) ( K1 (T ) = A1 ⋅ exp(− E1 RT ) and constant, K 2 (T ) = A2 ⋅ exp(− E2 RT ) ), weighted by a coefficient (α, 0
