Article

Role of adsorption and swelling on the dynamics of gas injection in coal - article no. B04203

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Abstract

An experimental technique is presented to perform gas injection experiments on coal cores confined by an external hydrostatic pressure, which makes use of the so-called transient step method. The experiments are intended to improve the knowledge on the different mechanisms acting during CO storage in coal seams, in particular, those related to permeability. Helium, nitrogen, and carbon dioxide have been injected at pressure ranging from 10 to 80 bars and at confining pressures varying between 60 and 140 bars. The experiments with helium have been used to study the mechanical compliance of the coal core, whereas those with the adsorbing N and CO to study the effects of adsorption and swelling on the flow dynamics. The obtained experimental transient steps were successfully described using a mathematical model, consisting of mass balances accounting for gas flow and adsorption, and mechanical constitutive equations for the description of porosity and permeability changes during injection. A semiempirical relationship between permeability and operating pressures is validated, and the corresponding parameters have been evaluated. Results showed increase in permeability with decreasing effective pressure on the sample and, when an adsorbing gas was injected, a reduction in permeability caused by swelling, with CO having a stronger effect compared to N.

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... The specific permeability model under TSC is as follows: Zhou et al. (2016) The ISCM can be directly reflected in the variation of pore size (Zhou et al. 2016), and the permeability model including the ISCM under CCSC was established. There is a considerable difference between the f values obtained by Zhou et al., (2016) with those in the reference (Pini et al. 2009). The specific equation is as follows: Liu et al. (2017) The dual porosity-matrix fracture interaction model (DP-MFI) was established by Liu et al., (2017), which was evaluated according to the field and experimental data, and the evolution laws and influencing factors of ISCM under various boundary conditions were studied. ...
... where ∆σ t is the total stress. Based on the permeability models under three boundary conditions (Zang et al. 2015), the permeability data from Pini et al. (2009) and Connell et al. (2010b) were used to evaluate the ISCM. Here are the key conclusions. ...
... Constant effective stress condition Liu et al. (2017)mainly used data from references (Connell et al. 2010b;Liu and Harpalani 2013c;Pini et al. 2009;Robertson and Christiansen 2005), which is used to fit models to study the trends of the ISCM under various boundary conditions. Here are the key conclusions. ...
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Coal bed methane (CBM), the high-quality and efficient fuel, has caught the interest of many nations as they strive for environmentally friendly development. Therefore, the efficient exploitation and utilization of CBM has become one of the international focal research problems. A significant factor affecting the mining of CBM is coal permeability. To better capture the changes that occur during the extraction of CBM, the internal swelling coefficient of matrix (ISCM) has been gradually in permeability introduced into the permeability models, and such models have become an important type of the development of permeability models. The goal is to find out more precisely the evolution mechanism of the ISCM and its influence on the permeability models. In this paper, the selection of coal structure, determination of boundary conditions and influencing factors of permeability for were first analyzed. Then, according to the research process of ISCM, the permeability models including the ISCM were reviewed and divided into four phases: proposal phase, development phase, evaluation phase and display of internal structure phase. On the basis of the ISCM values in the current coal permeability models, the primary influencing factors and evolutionary laws of the ISCM are explored. The results obtained provide guidance for future theoretical refinement of permeability models with the ISCM.
... The different adsorbability of N 2 , CO 2, and CH 4 to the coal matrix results in a significant difference of gas permeability under the same pressure [40,47]. Pini et al. (2009) [48] observed that the swelling of coal due to CO 2 was larger than that due to N 2 . Pan and Connell (2011) [17] measured bituminous coal swelling strains caused by CH 4 , N 2 , and CO 2 perpendicular and parallel to the bedding direction. ...
... The different adsorbability of N 2 , CO 2, and CH 4 to the coal matrix results in a significant difference of gas permeability under the same pressure [40,47]. Pini et al. (2009) [48] observed that the swelling of coal due to CO 2 was larger than that due to N 2 . Pan and Connell (2011) [17] measured bituminous coal swelling strains caused by CH 4 , N 2 , and CO 2 perpendicular and parallel to the bedding direction. ...
... However, a relatively good match is obtained between our model results and the experimental results. [48] observed that the swelling of coal due to CO2 was larger than that due to N2. ...
Article
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As an unconventional natural gas, coalbed methane (CBM) has been recognized as a significant fuel and chemical feedstock that should be recovered. Permeability is a key factor that controls CBM transport in coal. The slippage effect is an influential phenomenon that occurs during gas penetration processes, especially in low-permeable media. Apparent permeability may differ greatly from intrinsic permeability due to gas slippage. However, the gas slippage effect has not been considered in most analytical permeability models. Based on the cubic law, a new analytical model suited for the permeability analysis of coal under different stress conditions is derived, taking into consideration gas slippage and matrix shrinkage/swelling due to gas desorption/adsorption. To enhance its application, the model is derived under constant hydrostatic stress and pore pressure. The new analytical model is then compared with the existing models, and its reliability is verified by the comparison between the analytical prediction and the experimental permeability data under different stress conditions.
... To verify the presented permeability model, experimental data from Robertson and Christiansen 57 and Pini et al. 56 were utilized, with a particular focus on examining the impact of effective stress and adsorption strain on permeability. Table 1 presents basic information about the permeability experiments, including details such as the experimental methods used, confining pressure levels, sampling locations, and testing gas and pressure variation ranges. ...
... The experimental data from Pini et al. 56 and Robertson and Christiansen 57 were utilized to compare the proposed models with classical models (i.e., PM model and SD model). Palmer and Mansoori (1998) considered the matrix shrinkage effect as pressure dependent and proposed a permeability prediction model assuming uniaxial strain and constant vertical stress. ...
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The Qingshui Basin in China is a hotspot for coalbed methane exploration, and the selection and arrangement of the surface well are crucial engineering issues for the drainage process. To address this, the present study establishes several novel coal permeability models based on the strain relationship of representative elementary volumes (REV) and discusses the evolution mechanism of permeability. Moreover, the spatiotemporal evolution patterns of permeability during the drainage process are analyzed, and a methodology is presented for the selection and arrangement of a surface well based on the predrainage time at the working face. The results indicate that in the permeability model, the volumetric strain of REV is linearly correlated with the volumetric strain of their respective fractures, with the correlation coefficient representing the initial fracture porosity. The variation pattern of coal permeability near surface wells during the drainage process is closely aligned with the trend of the adsorption strain. Additionally, the selection and arrangement of surface wells are correlated with the predrainage time at the working face, including the minimum number and location of vertical wells, as well as the optimal length of horizontal wells. The research findings provide valuable insights into enhancing the efficiency of coalbed methane drainage.
... At present, isothermal-adsorption-permeability measurement system is widely used to measure permeability of rock and coal, which measure the permeability under different in-situ stress, temperature, gas injection pressure and et al. (Sander et al., 2017). There are three methods for permeability measurement, namely, steady-state method (Wollenweber et al., 2010;Wang et al., 2019a;Mitra et al., 2012), transient method (Feng et al., 2016a;Pini et al., 2009;Siriwardane et al., 2009) and periodic oscillation method (Fischer, 1992;Heller et al., 2002). In addition, researchers combined some detection technologies or equipment such as acoustic emitter (Cai et al., 2014;Zhang and Li, 2017), computed tomography scanner (CT) (Wang et al., 2019b), microwave heating (Huang et al., 2020) and strain analyzer (Meng and Li, 2018;Espinoza et al., 2014) on the basis of the permeability measurement system to measure the internal fracture propagation, pore structure and strains during the process of permeability measurement. ...
... In addition, the details of some experimental data that have been reported (Pini et al., 2009;Zhao et al., 2021;Harpalani and Schraufnagel, 1989, 1990a, 1990bHarpalani and Chen, 1997;Lin et al., 2008;Kumar et al., 2012;Niu et al., 2013;Anggara et al., 2016;Meng and Li, 2017;Feng et al., 2016b;Wang et al., 2017;Shi et al., 2018), as shown in Table 1. It is well known that, in the ordinary seepage experiment, the sample is treated with undergo the gas pressure holding stage before the permeability of coal or rock samples was measured at the gas pressure, i. e., the sample is injected with gas at the pressure for a period of time. ...
... Most the laboratory tests on coal permeability evolution for varied pressures or varied confining stresses were conducted in one direction, e.g. 37,45,47 Note: These parameters are only for Pan and Connell's model. Robertson 45 performed two sets of experimental tests on coal permeability to investigate, firstly, the effect of confining stress on coal permeability by keeping gas pressure constant but varying confining stress (same confining pressure to all surfaces of the cores); and secondly, the effect of gas pressure on coal permeability by keeping confining pressure constant and by varying gas pressure. ...
... The permeability data tested under constant confining stress were collected to calibrate the model predictions since these experiments involve constant stress boundary. These data were collected from works 45,47,[57][58][59][60] and plotted in Fig. 17. It can be seen although the experimental permeability ratios may increase or decrease with pressure, they fall within a lower bound and an upper one. ...
Article
To investigate the anisotropy of coal swelling, this study proposes an effective stress model for saturated, adsorptive fractured porous media by considering gas adsorption induced surface stress change on solid-fluid interface. The effective stress model can be used to capture the anisotropic swelling of coal combining anisotropic mechanical properties and to link with the anisotropic permeability. Direction dependent fracture compressibility is used to describe the evolution of anisotropic stress-dependent permeability behaviour. Particularly, the impact of gas adsorption on fracture compressibility is considered in the model. The proposed models were tested against experimental results and compared to relevant existing models available in literatures. The model predicts that the coal swelling in the direction perpendicular to the bedding plane, is greater than that in the parallel plane. Coal permeability in each direction can be affected by the stress changes in any directions. The permeability parallel to the bedding plane is more sensitive to change in stresses than in perpendicular to the bedding due to higher fracture compressibility. The cleat compressibility could increase with gas adsorption, especially for carbon dioxide. Permeability loss in the direction parallel to the bedding plane is more significant than that in the direction perpendicular to the bedding plane. The presented models provide a tool for quantifying gas adsorption-induced anisotropic coal swelling and permeability behaviours.
... It should be noted that the measured data used for model validation depends on the stress boundary under which the model is derived; otherwise, it may lead to significant errors. Coal permeability tests are normally carried out with the constant stress boundary (Robertson 2005;Chen et al. 2012;Liu and Rutqvist 2010;Pini et al. 2009), while some tests are conducted under uniaxial strain conditions (Mitra et al. 2012;Liu and Harpalani 2014). With the uniaxial strain boundary conditions, the lateral stress should be maintained dynamically changing to ensure zero lateral strain, which is comparatively difficult to achieve than keeping constant confining stress condition Connell 2016;Mitra et al. 2012). ...
... The pulse-decay method was originally used to determine the permeability of tight rocks, but it has only recently been applied to coal permeability determination experiments. Such experimental methods are mainly reported in research papers by scholars (Brace et al. 1968;Pini et al. 2009;Mitra 2010;Feng et al. 2016Feng et al. , 2017. Compared with the steady-state method, the pulse-decay method only needs to measure the gas pressure data of the up-/ downstream of the tested coal core, and estimate the permeability based on the pulse decay curve. ...
Article
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Gas permeability in coal plays a critical role in predicting coalbed methane (CBM) production. The permeability evolution induced by gas depletion in low-permeability coal is complicated and affected by multi-mechanistic flow components. This study runs a series of permeability tests using the pulse-decay method for helium and CH4, CO2 depletions in coal under both the constant stress boundary (CSB) and uniaxial strain boundary (USB) conditions. With the measured pulse-decay curves, the gas desorption effect on pore pressure depletion can be clearly noticed and gas permeability change can be estimated. The result shows that the helium permeability under the CSB condition is slightly lower than that under the USB condition, and it decays nonlinearly with pressure drawdown and does not rebound in the low-pressure region, which indicates that the helium permeability evolution is mainly controlled by the effective stress in the tested coal. For the sorbing gas CH4/CO2, the permeability profile under the two boundary conditions behaves somewhat similarly; it initially declines with the pressure depletion and then starts to rebound in low-pressure region. The permeability ‘rebound’ of CH4 is comparatively less than that of CO2 due to the larger adsorption capacity of CO2 in coal. With the comparison of permeability behaviors of the different test fluids, it is inferred that the sorbing gas permeability ‘rebound’ should be mainly caused by the matrix shrinkage. The result of this study reveals that coal reservoirs produce CBM using a multi-mechanism approach, and the effect of matrix flows on the permeability behavior and the overall CBM production should be highly emphasized.
... The permeability of rock for liquids or gases is determined in the laboratory with permeameters using air (Müller, 1964) or helium (Pini et al., 2009) as the flowing medium. The methods are based on placing cylindrical samples between an up-stream and a down-stream reservoir, at different pressure. ...
... For transient step methods (e.g. Brace et al., 1968;Pini et al., 2009) the pressure in the up and downstream reservoirs are allowed to re-equilibrate and the permeability is measured through the time at which the two reservoirs reach equilibrium. Since permeability is a directional property, whenever possible, specimens were drilled parallel and perpendicular to the stratification or foliation. ...
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The Swiss Atlas of Physical Properties of Rocks (SAPHYR) project aims at centralize, uniform, and digitize dispersed and often hardly accessible laboratory data on physical properties of rocks from Switzerland and surrounding regions. The goal of SAPHYR is to make the quality-controlled and homogenized data digitally accessible to an open public, including industrial, engineering, land and resource planning companies as well as governmental and academic institutions, or simply common people interested in rock physics. The physical properties, derived from pre-existing literature or newly measured, are density, porosity and permeability as well as seismic, magnetic, thermal and electrical properties. The data were collected on samples either from outcrops or from tunnels and boreholes. At present, data from literature have been collected extensively for density, porosity, seismic and thermal properties. In the past years, effort has been placed especially on collecting samples and measuring the physical properties of rock types that were poorly documented in literature. A workflow for quality control on reliability and completeness of the data was established. We made the attempt to quantify the variability and the uncertainty of the data. The database has been recently transferred to the Federal Office of Topography swisstopo with the aim to develop the necessary tools to query the database and open it to the public. Laboratory measurements are continuously collected, therefore the database is ongoing and in continuous development. The spatial distribution of the physical properties can be visualized as maps using simple GIS tools. Here the distribution of bulk density and velocity at room conditions are presented as examples of data representation; the methodology to produce these maps is described in detail. Moreover we also present an exemplification of the use of specific datasets, for which pressure and temperatures derivatives are available, to develop crustal models.
... We compared the model results of eq 25 with experimental data under constant external stress conditions. 53 The parameters used in the model were ε L = 0.05187 and p L = 2.913 MPa. 24 From those, the matching relationship between the model and the test data is shown in Figure 15. ...
Article
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The complexity of the evolution of the permeability of coal is determined by the reservoir structure. Further, there exists an interaction between the fracture matrix, which further complicates changes in permeability. When the actual mining conditions of a coal mine are considered, a permeability model that considered the combined effects of stress, gas adsorption, and temperature was proposed. Subsequently, the model is verified by published test data. Based on the analysis of permeability, a calculation model of the slip coefficient that considered the combined effects of stress, gas adsorption, and temperature is proposed. With respect to this, any change in the slippage coefficient is only determined by the width of the fracture channel, which affected the flow of coal gas. In the process of a temperature increase, the slip coefficient tends to increase and the larger effective stress corresponds to a larger slip coefficient. In addition, under constant-temperature conditions, we also discuss the evolution of coal permeability and the variation of the coal gas slippage factor under different boundary conditions through the proposed model. This study aims to further the understanding of the seepage characteristics and slippage effects of coalbed methane, which would have a positive impact on the mining of coal.
... The other boundary condition is to control the tri-axial stress state as either a constant confining-pressure or constant effective-stress. Numerous experimental results have demonstrated that if the flow regime of the percolating fluid remains viscous, then coal permeability is positively related to gas pressure (Pini et al. 2009;Harpalani and Schraufnagel 1990;Wang et al. 2011;Kumar et al. 2015). If the gas flow regime shifts from slippage flow to viscous flow due to increasing gas pressure, the resultant coal permeability to first decrease and then partially rebound (Wang et al. 2019). ...
Article
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Identifying changes in coal permeability with gas pressure and accurately codifying mean effective stresses in laboratory samples are crucial in predicting gas-flow behavior in coal reservoirs. Traditionally, coal permeability to gas is assessed using the steady-state method, where the equivalent gas pressure in the coal is indexed to the average of upstream and downstream pressures of the coal, while ignoring the nonlinear gas pressure gradient along the gas flow path. For the flow of a compressible gas, the traditional method consistently underestimates the length/volume-averaged pressure and overestimates mean effective stress. The higher the pressure differential within the sample, the greater the error between the true mean pressure for a compressible fluid and that assumed as the average between upstream and downstream pressures under typical reservoir conditions. A correction coefficient for the compressible fluid pressure asymptotes to approximately 1.3%, representing that the error in mean pressure and effective stress can be on the order of approximately 30%, particularly for highly pressure-sensitive permeabilities and compressibilities, further amplifying errors in evaluated reservoir properties. We utilized this volume-averaged pressure and effective stress to correct permeability and compressibility data reported in the literature. Both the corrected initial permeability and the corrected pore compressibility were found to be smaller than the uncorrected values, due to the underestimation of the true mean fluid pressure, resulting in an overestimation of reservoir permeability if not corrected. The correction coefficient for the initial permeability ranges from 0.6 to 0.1 (reservoir values are only approximately 40% to 90% of laboratory values), while the correction coefficient for pore compressibility remains at approximately 0.75 (reservoir values are only approximately 25% of laboratory value). Errors between the uncorrected and corrected parameters are quantified under various factors, such as confining pressure, gas sorption, and temperature. By analyzing the evolutions of the initial permeability and pore compressibility, the coupling mechanisms of mechanical compression, adsorption swelling, and thermal expansion on the pore structure of the coal can be interpreted. These findings can provide insights that are useful for assessing the sensitivity of coal permeability to gas pressure as truly representative of reservoir conditions.
... Adsorption can trigger bulk strain of the solid frame in porous media [1,2]. Alternatively, bulk strain and pore fluid pressure control the magnitude of fluid mass adsorbed on the pore walls of a porous material [3,4]. Empirical models for the described three-way coupling between sorption, pore fluid pressure, and solid stress or strain generally assume linear relationships between adsorption-induced strain and total adsorbed mass [5,6]. ...
... A novel technology for minimizing carbon dioxide emissions at their source is called enhanced coal bed methane recovery, in which an adsorption process is applied to recover methane in the underground coal bed using carbon dioxide injection. This occurs because carbon dioxide is preferentially adsorbed onto coal over methane [7,8], therefore, the coal will capture carbon dioxide and release methane as a useful natural gas. This process allows a reduction in carbon dioxide and also makes carbon dioxide storage economically feasible [7]. ...
Article
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Activated carbon derived from longan seeds in our laboratory and commercial activated carbon are used to investigate the adsorption of methane (CH4) and carbon dioxide (CO2). The adsorption capacity for activated carbon from longan seeds is greater than commercial activated carbon due to the greater BET area and micropore volume. Increasing the degree of burn-off can enhance the adsorption of CO2 at 273 K from 4 mmol/g to 4.2 and 4.8 mmol/g at 1000 mbar without burn-off, to 19 and 26% with burn-off, respectively. This is because an increase in the degree of burn-off increases the surface chemistry or concentration of functional groups. In the investigation of the effect of the hydroxyl group on the adsorption of CO2 and CH4 at 273 K, it is found that the maximum adsorption capacity of CO2 at 5000 mbar is about 6.4 and 8 mmol/g for cases without and with hydroxyl groups contained on the carbon surfaces. The opposite behavior can be observed in the case of methane, this is due to the stronger electrostatic interaction between the hydroxyl group and carbon dioxide. The simulation results obtained from a Monte Carlo simulation method can be used to support the mechanism in this investigation. Iron oxide is added on carbon surfaces with different concentrations to reveal the effects of ferric compounds on the adsorption of CO2. Iron at a concentration of about 1% on the surface can improve the adsorption capacity. However, excessive amounts of iron led to a limited adsorption capacity. The simulation result shows similar findings to the experimental data. The findings of this study will contribute to the progress of gas separation technologies, paving the way for long-term solutions to climate change and greenhouse gas emissions.
... Knudsen and surface diffusions prevail in the nanometer-sized pores of the matrix, while molecular diffusion and two-phase Darcy flow occur mainly within the cleat network. All these transport mechanisms induce mechanical couplings related to both (i) the pore pressure changes which may alter the effective stress and consequently impact the bulk volume of the coal and, (ii) the sorption processes which contribute to swell or shrink the coal matrix [8,9]. Indeed, coal can sorb various gases including CO 2 , CH 4 and N 2 , and the adsorption of these gases induces swelling strains [10][11][12]. ...
Article
We present a 3D model coupling a discrete element model and a pore network model specifically developed to describe the different diffusion mechanisms at stake in coal matrix as well as the associated adsorption induced deformations. The material is assumed to be saturated with gas and diffusion occurs through the combination of Knudsen diffusion within the pore space, surface diffusion at the solid surface, and adsorption-desorption at the pore-solid interface. The model is hydro-mechanically coupled in the sense that changes in pore pressure produce hydrostatic forces that deform the solid skeleton, while deformation of the pore space induces pore pressure changes that promote interpore flow. Sorption induced deformations are taken into account by considering an additional pressure term related to the concentration of gas within the medium (the so-called solvation pressure). The implemented transport models are verified against analytical solutions describing diffusion in porous media with and without sorption-desorption, and a comparison is made with a swelling experiment performed on a coal specimen to illustrate the relevance of the proposed approach for describing adsorption induced deformation. As a result, this new pore-scale model offers a precise way to assess coal matrix sorption induced deformation and contributes to the knowledge of CBM storage and transport processes.
... It is worth mentioning that the water swelling is generally smaller than gas swelling due to the low water content and high gas pressure in the coal seam. And gas swelling is controlled not only by water content and gas pressure, but also by gas type and coal rank [51,52]. Since different coal bodies have different natures of water adsorption and gas adsorption, the contribution ratio of water adsorption swelling and gas adsorption swelling to matrix adsorption swelling is also distinct. ...
Article
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Accurate knowledge of gas flow within the reservoir and related controlling factors will be important for enhancing the production of coal bed methane. At present, most studies focused on the permeability evolution of dry coal under gas adsorption equilibrium, gas flow and gas diffusion within wet coal under the generally non-equilibrium state are often ignored in the process of gas recovery. In this study, an improved apparent permeability model is proposed which accommodates the water and gas adsorption, stress dependence, water film thickness and gas flow regimes. In the process of modeling, the water adsorption is only affected by water content while the gas adsorption is time and water content dependent; based on poroelastic mechanics, the effective fracture aperture and effective pore radius are derived; and then the variation in water film thickness for different pore types under the effect of water content, stress and adsorption swelling are modeled; the flow regimes are considered based on Beskok’s model. Further, after validation with experimental data, the proposed model was applied to numerical simulations to investigate the evolution of permeability-related factors under the effect of different water contents. The gas flow in wet coal under the non-equilibrium state is explicitly revealed.
... The majority of experimental studies on these coupled diffusion/sorption phenomena between the matrix-fracture system (dualporosity systems) have been accomplished via studying the relationship between the measured coal permeability and applied pore pressure on the samples under different stress conditions (Harpalani and Schraufnagel 1989;Fan and Liu 2018;Wang et al. 2015;Kumar et al. 2012;Pini et al. 2009;Wang et al. 2017;Pan et al. 2010;Mitra et al. 2012;Robertson and Christiansen 2005). However, the pore pressure differences between the matrix and fracture systems in these experiments were poorly understood. ...
Article
Measurements of coal permeability are normally analyzed without considering the interaction among microfracture and pore size distributions within the sample (control volume). Without this inclusion, nearly all permeability predictions are monomodal as reported in the literature. However, experimental observations are multimodal for most cases. In this study, we hypothesize that these discrepancies or mismatches between measurements and analytical predictions are due to the exclusion of the interaction among microfracture and pore size distributions within the sample (control volume). We report a first experimental study of triple-porosity interactions on a prismatic sample containing millimeter-scale fractures (Ⅰ) and micron- (Ⅱ) through nanometer-scale (Ⅲ) pores. Migration speeds of sorbing (e.g., CH4) gases are conditioned by the strain field, which is in turn conditioned by effective stresses and swelling strains. These distinct pore populations exhibit characteristic times for a time-staged equilibration of the strain field as multiple plateaus. This time-staged evolution of strain in turn delimits the evolving fracture permeability into a series of stages. The relatively high permeability of fractures and micropores defines a brief intermediate equilibrium permeability, after which the nanopore system controls the final permeability evolution. Our results indicate that the multimodal evolution of coal fracture permeability can be explained by the time-staged evolution of strain due to multiporosity interactions and could be defined by a time-staged equilibration of the strain fields as multiple plateaus.
... For experimental research, it is difficult to complete the experiment under the absolute constant volume condition due to the limitation of the experimental equipment. Experimental studies under the other three types of boundary conditions have been reported, and the details of these experiments are displayed in the Table 1 [6,[43][44][45][46][47][48]. However, it is a pity that we did not find that the samples used in these experiments under the three kinds of boundary conditions were the same sample. ...
Article
Permeability is a key parameter to evaluate the ability of coal reservoir for transmitting coalbed methane (CBM). Deformations of internal components of coal caused by the variations of physical fields control the evolution of coal permeability. And there is obvious non-uniform in the deformations of coal bulk and fracture due to the heterogeneity of coal. However, at present, the evolution of non-uniform deformation and its relationship with coal permeability are unclear. In this study, first of a two-part series, we completed a series of experiments to measure the permeability, axial strain, radial strain, overall strain and fracture strain of a coal sample under different boundary conditions (constant confining pressure, constant effective stress and uniaxial strain) at different injection pressures of carbon dioxide (0.2 MPa, 1.0 MPa, 2.0 MPa, 3.0 MPa, 4.0 MPa and 5.0 MPa). And we defined the comprehensive non-uniform deformation index (CNDI) as the ratio of the fracture strain to the overall strain to quantify the degree of the non-uniform deformation between coal bulk and fracture. The experimental results show that the deformation of the coal sample in the longitudinal joint direction is smaller than that in the transverse joint direction, which indicates that the mechanical properties of the coal sample is anisotropic in different directions. And there are obvious differences between the deformations of coal bulk and fractures. When the gas pressure is in the range of 0.2 ~ 5.0 MPa, the non-uniform deformations are vaguely related to the change of gas pressure, but closely related to the type of boundary conditions. The influence of gas pressure under displacement-controlled boundary condition (uniaxial strain) on the CNDI is greater than that under stress-controlled boundary conditions (constant confining pressure, constant effective stress). In addition, we also observed the phenomenon by the experimental results of the constant effective stress group: the permeability decreases gradually with the gas pressure even after removing the influence of gas slip effect, which is inconsistent with the traditional theoretical solution under the constant effective stress condition. Based on the fact that coal sample is a heterogeneous body, we tentatively believe that one of the reasons for this inconsistency may be that the traditional definition of effective stress does not include the effect of gas adsorption.
... In the development of a permeability measurement method, a pressure pulse decay (PPD) method has been adopted; it has been improved by many scholars due to its advantages of less time consumption and higher accuracy (Fedor et al., 2008;Pini et al., 2009;Wang et al., 2013;Gaus et al., 2019;Li et al., 2020;Zhang et al., 2022). The PPD experimental apparatus mainly comprises a core holder and two chambers upstream and downstream. ...
Article
Permeability is an essential factor used for evaluating the commercial exploitation of unconventional energy. The pressure pulse decay method is one of the most effective methods to measure permeability and has been improved by adding a pressure transducer upstream and a chamber upstream and downstream. The relationship between the pulse pressure and equilibrium time under different storage volumes is investigated based on a developed apparatus. Moreover, the effect of compressive storage on permeability measurements has been examined by comparing the Brace’s et al.’s solution and Jones’ solution. The following results were obtained for the constant injection pressure. 1) The equilibrium pressure increases with a decrease in the upstream storage volume and decreases with an increase in the downstream storage volume. 2) The equilibrium time increases with an increase in the storage volume, and the similar volume of the upstream and downstream can accelerate the test procedure. 3) A linear relationship between the storage volume and equilibrium time is not apparent when the volume of the upstream and downstream are asymmetric. However, this linear relationship is evident when the volume of the upstream and downstream are symmetrical. 4) The influence of the downstream storage volume is more significant than the upstream volume on the measurement of permeability. The results are of guiding significance for selecting the proper storage volume to measure permeability.
... Larsen et al. (1997) and Goodman et al. (2005b) suggested that the change of physical structure was related to coal matrix swelling which could compress coal seam cleat spaces, which reduced the fracture aperture and even partially closed the fracture, and thereby reduced the permeability and injectivity of coal seam (Niu et al., 2017). However, Pini et al. (2009) suggested that reducing the effective CO 2 injection pressure could alleviate the negative effect that matrix swelling exerted on the coal reservoir permeability. Moreover, the change of the MVB coal's physical structure could reduce the glass transition temperature of the coal, therefore, the CO 2 adsorption may reduce coal strength (Sampath et al., 2019), which will induce coal seam cracks to form under in-situ stress, which is not conducive to the longterm stability of sequestrated CO 2 in the MVB coal reservoirs. ...
... The sorbing CO2 swells the rock matrix and causes a reduction in the natural fracture aperture (H.-H. Liu & Rutqvist, 2009;Mazumder & Wolf, 2008;Pini, Ottiger, Burlini, Storti, & Mazzotti, 2009). This swelling behaviour follows the Langmuir Isotherm and usually approaches the maximum influence at twice of the Langmuir pressure (S. ...
... 2004;Wu et al. 2022). Pini et al. (2009) held the external stress constant and measured the permeability during gas pressure changes. Connell et al. (2010) measured the permeability under constant effective stress and different gas pressure, demonstrating the controlling effect of the gas adsorption on permeability. ...
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Understanding the gas flow behavior in coal mining is conducive to the efficient production of coalbed methane. In coal mining, in-situ stress usually manifests as three-dimensional anisotropy in deep formations, and affects the gas permeability in reservoirs. In this work, a permeability model for anisotropic coal by combining gas sorption effects and the three-dimensional stress compression was proposed. Then, the effect of stress-induced fracture expansion on the fracture-matrix system was quantitatively analyzed, and this effect was incorporated into the permeability model. Combining the theoretical work, the seepage tests under conditions of true triaxial stress was conducted, and the permeability of coal, sandstone, and composite coal-rock were measured. Results showed that the stress first causes fracture compression, thus causing the permeability reduction. Because of the continuous increase of stress, the resulting fracture initiation and expansion increase the seepage channel of rock, and its permeability showed a sudden increase trend. In addition, the measured permeability test data is in good agreement with the model predicted. It also shows that the new model can describe the reservoir anisotropy permeability behaviors owing to stress compression induced damage and the initiation of new fractures. This work may provide an important theoretical reference for the evolution of rock permeability and reserve assessment of deep oil and gas reservoirs. Article highlights A permeability model for coal rock considering the effect of three-dimensional stress compression and sorption was proposed. Combined with the in-situ environment, the seepage test for coal rock under true triaxial stress was carried out. According to the new model, the permeability behavior of rocks under 3D stress was simulated.
... The permeability of coal seams significantly controls CBM production, which is not only affected by the physical properties of coalbeds, such as coal cleat and bedding direction, but also related to external factors, such as in situ stress, gas sorption, temperature, and pore pressure, damage. At present, the effects of gas pressure and external stress on coal permeability have been extensively investigated (Fu et al. 2001;Robertson and Christiansen 2006;Pini et al. 2009;Jasinge et al. 2011;Liu et al. 2012;Chen et al. 2012;Wang et al. 2021a, b). Effective stress and gas sorption/desorption-induced coal matrix swelling/shrinkage have competitive control on the net change of coal permeability Wang et al. 2017Wang et al. , 2021a. ...
Article
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Coupled coal–gas interaction in coal seams is crucial to the efficient recovery of Coalbed methane (CBM), and carbon dioxide-enhanced CBM (CO2-ECBM). Coal is physically deformed and damaged during gas extraction/injection and permeability enhancement in coal seams, which might alter the reservoir properties of coalbeds in terms of coal diffusivity and permeability and thus affect gas desorption and transport. In turn, gas desorption and transport also change the geomechanical behaviors of the coal, including coal deformation and mechanical parameter alterations. In many cases, when investigating gas transport in coal, it is necessary to consider the coupling between stress, deformation and gas flow in coal. First, this review paper presents a comprehensive review of the mechanisms and properties of gas adsorption in coal, the geomechanical behavior of coal including mechanical deformation and mechanical property alterations, and mechanisms of gas transport in coal including gas diffusivity and permeability evolution in coalbeds under coupled coal–gas interactions. Next, several waterless fracturing techniques such as liquid N2 fracturing and supercritical CO2 fracturing are discussed for improving the permeability of coalbeds. Finally, an overview of the current knowledge and research gaps are identified. Article highlights Mechanical property alterations of coal during coupled coal-gas interactions are reviewed. Diffusion and permeability models during coal-gas interaction are reviewed. Several waterless fracturing techniques for enhancing coal permeability are reviewed.
... Shale can exhibit notable mechanical deformation upon gas adsorption (Gor et al., 2017;Pini et al., 2009;Pijaudier-Cabot, et al., 2011). Deformation of solids phase will, in turn, disturb the thermodynamic equilibrium between the adsorbed and free gas at the pore surface. ...
Conference Paper
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A thermodynamically rigorous constitutive model is used to describe the full coupling among the nonlinear processes of transport, sorption, and solid deformation in organic shale where the pore fluid is the binary mixture of carbon dioxide and methane. The constitutive model is utilized in a numerical solution that simulates injection of carbon dioxide in shale before producing carbon dioxide and methane from the same. The solution considers advection and diffusion as viable mechanisms of pore fluid transport where the latter comprises molecular, Knudsen, and surface diffusion in ultralow permeability shale. Results indicate that complete or partial exclusion of the coupling between sorption and solid phase deformation from the solution would result in underestimation of carbon dioxide storage capacity and natural gas recovery factor of the rock. In this aspect, sorption-induced deformation and strain-induced changes in gas sorption capacities are all conducive to both outcomes.
... Enever et al. found that by discussing the interaction mechanism between permeability and effective stress of gas-bearing coal and rock mass in Australian coal mines, There is an exponential relationship between the change of coal seam permeability and the transformation of in-situ stress. It is considered in the literature that the permeability in raw coal can be regarded as an application function of effective stress and pore pressure between fluids (Pomeroy and Robinson, 1967;Somerton et al., 1975b;Enever and Hennig, 1997;Pini et al., 2009;Siriwardane et al., 2009;Liu et al., 2011a;Liu et al., 2011b;Wang et al., 2011). Bae, Li et al. also concluded that permeability decreases with the increase in temperature (Bae and Bhatia, 2006;Li et al., 2010). ...
Article
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The extraction of coal bed methane (CBM) by injecting CO2 into deeply buried unmined coal seams in competition with CH4 adsorption to provide a clean fuel is known as enhanced coal bed methane recovery (ECBM) and has proven to be an effective technological strategy to address global warming. The study of the interaction of coal with CO2 and CH4 under multi-physical field conditions is particularly necessary. In this work, a series of experiments were conducted on a home-made test system to investigate the competing sorption patterns of high and medium ash coal samples subjected to variables such as gas pressure, temperature, nodulation and lateral limit constraints. The results show that there is a sorption isotherm relationship between coal samples and exposure time. The adsorption capacity sorption of CH4/CO2 varied considerably for different ash coal samples. As the CO2 pressure increased from 2.3 to 5.5 MPa, the strain on the coal samples increased from 0.082 to 0.4%. The deformation in the vertical laminae direction is always greater than that in the parallel laminae direction. A correlation coefficient K exists between 1 and 2, and there is an internal expansion pattern in the adsorption deformation of coal. This paper can contribute to the improvement of ECBM efficiency.
... Shale may exhibit notable mechanical deformation upon gas adsorption (Gor et al., 2017;Pini et al., 2009). Deformation of the solid phase will, in turn, disturb the thermodynamic equilibrium between the adsorbed and free gas at the pore surface. ...
Article
A thermodynamically rigorous constitutive model is used to describe the full coupling among the nonlinear processes of transport, sorption, and solid deformation in organic shale where the pore fluid is the binary mixture of carbon dioxide and methane. The constitutive model is utilized in a numerical solution that simulates injection of carbon dioxide in shale before producing carbon dioxide and methane from the same. The solution considers advection and diffusion as viable mechanisms of pore fluid transport where the latter comprises molecular, Knudsen, and surface diffusion in ultralow permeability shale. Results indicate that gas adsorption would be the main storage mechanism for sequestration in shale which can comprise up to 70% of the stored CO2 mass while a third of this storage could be due to the geomechanical effects. Therefore, complete or partial exclusion of the coupling between sorption and solid phase deformation from the solution would result in underestimation of carbon dioxide storage capacity and natural gas recovery of the rock. Surface diffusion, sorption-induced deformation, as well as strain-induced changes in gas sorption capacities, are all conducive to both outcomes. Sensitivity analysis shows that the solution results are most sensitive to the change of adsorption capacities, followed by initial permeability, Young's modulus, Poisson's ratio, surface diffusivities, and initial pore radius.
... At the same time, adsorption or desorption of CH 4 /CO 2 by coal matrix material due to an increase or decrease in gas/fluid pressure at constant effective stress can cause swelling or shrinkage by several percent (e.g., Levine, 1996;Karacan, 2007;Day et al., 2012;Hol and Spiers, 2012;Liu et al., 2016), also affecting strongly the evolution of fracture permeability in coal seams. Many field pilots and laboratory experiments investigating ECBM production have further demonstrated that the net swelling of coal caused by CH 4 displacement by injected CO 2 causes an increase in the mean stress under confined subsurface conditions, simply closing transport paths and reducing coal seam permeability (van Bergen et al., 2006;Pini et al., 2009;Fujioka et al., 2010;Kiyama et al., 2011). Much attention has therefore been paid to understanding how these effects interact and how the permeability of coal samples develops during sorption of gases, such as N 2 , CH 4 , and CO 2 (e.g., Palmer, 2009;Liu et al., 2011a;Liu et al., 2011b;Pan and Connell, 2012;Zhou et al., 2013;Shi et al., 2018). ...
Article
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Permeability evolution in coal reservoirs during CO2-enhanced coalbed methane (ECBM) production is strongly influenced by swelling/shrinkage effects related to sorption and desorption of CO2 and CH4, respectively. Recent research has demonstrated fully coupled stress–strain–sorption–diffusion behavior in small samples of cleat-free coal matrix material exposed to a sorbing gas. However, it is unclear how such effects influence permeability evolution at the scale of a cleated coal seam and whether a simple fracture permeability model, such as the Walsh elastic asperity loading model, is appropriate. In this study, we performed steady-state permeability measurements, to CH4 and CO2, on a cylindrical sample of highly volatile bituminous coal (25 mm in diameter) with a clearly visible cleat system, under (near) fixed volume versus fixed stress conditions. To isolate the effect of sorption on permeability evolution, helium (non-sorbing gas) was used as a control fluid. All flow-through tests reported here were conducted under conditions of single-phase flow at 40°C, at applied Terzaghi effective confining pressures of 14–41 MPa. Permeability evolution versus effective stress data were obtained under both fixed volume and fixed stress boundary conditions, showing an exponential correlation. Importantly, permeability ( κ ) obtained at similar Terzaghi effective confining pressures showed κ h e l i u m > κ C H 4 >> κ C O 2 , while κ -values measured in the fixed volume condition were higher than those in the fixed stress case. The results show that permeability to CH4 and CO2, under in situ conditions where free swelling of rock is not possible, is strongly influenced by the coupled effects of 1) self-stress generated by constrained swelling, 2) the change in effective stress coefficient upon sorption, 3) sorption-induced closure of transport paths independently of poroelastic effect, and 4) heterogeneous gas penetration and equilibration, dependent on diffusion. Our results also show that the Walsh permeability model offers a promising basis for relating permeability evolution to in situ stress evolution, using appropriate parameter values corrected for the effects of stress–strain–sorption.
... The prediction of wettability remains equivocal as reservoir temperature is increased (Iglauer, 2017). It is also important to note that the coal swelling increases with increasing pressure and potentially induces significant reductions in permeability 10.1029/2021JB023723 13 of 15 and therefore limits CO 2 flow in coal seams (Pini et al., 2009). As a consequence, it is a complex problem to optimize CO 2 storage conditions that requires consideration of the competing influences of component-dependent wettability and related gas adsorption and impacts on matrix swelling and multiphase permeability. ...
Article
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Successful sequestration of CO2 into coalbeds relies on sufficient capacity and rates of uptake. Storage volumes are controlled by CO2 adsorption which in turn is affected in a complex manner by the evolving wettability of the sorption surface. However, mechanisms and interrelations between CO2 adsorption and coal wettability remain poorly constrained – especially under recreated in situ reservoir conditions where measurements are difficult. We circumvent this difficulty by combining direct measurements of adsorbed water and inferred wettability through Nuclear Magnetic Resonance spectroscopy with mechanisms recovered from molecular dynamic (MD) simulations. The MD simulations confirm that CO2 gas molecules adsorb to the coal pore surface, partially displace the adsorbed water, and transform the coal surface into a heterogeneous surface comprising solid interspersed with gas pockets. We then use the Cassie‐Baxter equation as a basis to characterize the wettability of this heterogeneous H2O‐solid‐CO2 surface to clarify the relationship between CO2 adsorption and coal wettability – using measurements of adsorbed H2O, alone. This enables the first direct evaluation of coal wettability at in situ pressures of CO2. Constrained observations suggest that water wettability weakens significantly with increasing CO2 pressure. Under low CO2 pressure, changes in wettability are contributed directly by CO2 adsorption and increases in CO2 density ‐ when CO2 adsorption reaches saturation at high gas pressure, then changes are determined primarily by changes in CO2 density. We document a robust method and results for the accurate prediction of CO2 storage capacity in coalbeds and concomitant enhanced methane recovery.
... In most previous experiments, coal bulk was used to measure 145 the ad-/desorption strain ( ) and its permeability. [19][20][21] As the coal is treated as a single-porosity 146 medium, intact coal only consists of solid grains served as CSG storehouse. Thus, its strain of solid 147 grains ( ) can be measured. ...
... The AE was measured using the CTA-1 AE signal acquisition instruments with the R3A sensors, and the permeability was measured by the transient step method. 56 At the same time of loading and unloading, the AE and permeability parameters of the coal sample were measured simultaneously. The experimental coal samples taken from Huaibei Coalfield in China were bituminous coal of medium rank and remolded to the size of ϕ50 * 100 mm. ...
Article
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Coalbed methane (CBM) is not only the material cause of gas explosion and coal‐gas outburst disasters during underground coal mining, but also a kind of clean energy. Coal permeability is an important parameter for CBM drainage. Although many coal permeability models have been developed in the past decades to describe the permeability evolution characteristics under elastic state, few of them could explain the permeability behavior of the mining‐disturbed coal which is often the situation of CBM drainage during underground coal mining. The paper analyzed the mechanical factors affecting the damage‐permeability characteristics of mining‐disturbed coal, proposed the concept of the deviatoric stress ratio (DSR), and then established the statistical damage and permeability evolution models based on DSR. Results show that the deformation and damage of coal is controlled by the deviatoric stress and minimum principal stress. The plastic damage degree of coal mass becomes more serious with DSR increase, which leads to the improvement in permeability. The damage constitutive model was established based on the Weibull distribution function and DSR, and then the permeability model of mining‐disturbed coal was built combining the Kozeny–Carman equation. The acoustic emission (AE) and permeability experiments of the loading and unloading coal sample were conducted. After normalizing and fitting the accumulative AE counts, the damage and permeability evolutions with respect to DSR were found out. The model‐predicted permeability could match with the experiment results, verifying the reliability of the theoretical permeability model. The purpose of this paper is to provide a new approach for modeling damage and permeability of mining‐disturbed coal based on DSR. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.
... 20 Pini et al had tested the turning point of permeability rebound at about 2 MPa. 21 Meng et al believed the coal matrix swelling had played a prevailing role in the permeability variation that is similar to roller coasters. 22 On the other hand, under constant effective stress conditions, the permeability should significantly decrease when increasing the gas pressure. ...
Article
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As an important indicator, permeability can predict the gas drainage yield and prevent the mine gas disasters. We first reviewed our previous inversion method to investigate permeability coefficient of gas in coal particles; however, the relationship between permeability and adsorption pressure had not been summarized and explained theoretically. Here, a permeability evolution model including two crucial parameters of initial permeability and deformation coefficient was developed. The inversion gas permeability coefficients were converted into permeability, and then, the permeability of the same coal sample was fitted according to the evolution model. The results show that (i) the modeled results are matched reasonably well with the inversion permeability data, and thus, this model has been validated; and (ii) as volatile matter content increases, the initial permeability decreases exponentially, but the deformation coefficient basically grows in a linear trend. These two parameters are coupling to lead to a negative exponential decrease in permeability as gas pressure rises.
... A considerable amount of literature has been published on in-situ gas production in CBM well (Gierhart et al., 2007;Pashin et al., 2007;Clarkson et al., 2010), laboratory permeability measurements (Pini et al., 2009;Wang et al., 2015;Danesh et al., 2017), and various permeability models (Gray, 1987;Seidle et al., 1992;David et al., 1994;Palmer and Mansoori, 1996;Shi and Durucan, 2004;Cui and Bustin, 2005;Robertson and Christiansen, 2006;Zhang et al., 2008;Liu et al., 2011;Wang et al., 2012;Song et al., 2020). On the basis of a dual-porosity structure of coal, these permeability models above focus on the Darcy flow in the natural fracture system. ...
Article
Coal seams are usually fractured reservoirs where the factures/cleats are fluids flow channels, and the matrix blocks serve as the storage space. The gas transport within the matrix has crucial impacts on the variation of cleat aperture and thus affects the reliable determination of coal permeability. Most literatures on laboratory measurements and the development of relevant analytical models focus on response gas pressure dependent coal permeability change, under the assumption that gas transport in coal is in equilibrium. This means that these models are not suitable for the assessment of transient permeability when the gas transport in coal is unsteady flow. In this paper, we real-time measured the entire process of the coal deformation induced by gas injection, and further obtained the diffusion-dependent curve of coal permeability against time by modifying the typical pressure-pulse-decay approach. An improved permeability model was then proposed by incorporating an Internal Deformation Coefficient into the pore compressibility of coal seams. The results show that the gas inflow can decline the pressure differential between the downstream pressure and the upstream pressure, during which the deformation of coal experiences a transition from early rapid expansion to latter slow expansion. As the gas was diffusing into coal matrices, the coal permeability was observed to first decrease and then become stable. It is also found that Internal Deformation Coefficient increases with the injection gas pressure. This indicates that the matrix blocks preferentially swell toward cleats. The modified permeability model achieves much better fit of the coal permeability-pore pressure relationship when compared with two widely used permeability models. This approach can be extended to evaluate the deformation compatibility between coal cleats and matrices.
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More and more gas extraction in deep coal seam is conducted under extreme geological conditions. The coal permeability determines the efficiency of gas extraction. To research the evolution of permeability and gas seepage in deep coal seam under three-dimensional (3D) stress condition, a permeability model (DCTDS model) was established by introducing the ratio of internal swelling and the elastic modulus reduction ratio under 3D stress. The influence of adsorption–desorption and effective stress on fracture aperture was considered in the DCTDS model. Subsequently, the DCTDS model was validated. Sensitivity analysis of parameters was conducted based on the laboratory test data under various boundary conditions. The results demonstrate that the change of coal permeability is effectively presented by the DCTDS model. The coal permeability decreased more with increasing pressure when the porosity and Biot’s coefficient were smaller in the dominant range of adsorption swelling. The coal permeability increased more when the porosity, Poisson’s ratio, and ratio of internal swelling were smaller in the dominant range of effective stress. Finally, based on the constructed DCTDS model, gas extraction in deep coal seams was simulated. The extraction effect was improved with smaller borehole spacing, and elastic modulus, Poisson’s ratio of coal. The extraction effect became more notable with larger borehole aperture, Biot’s coefficient, and initial permeability. The gas extraction efficiency decreased gradually with extension of extraction time.
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Methane and water vapor transport in shale (mud rocks) is important in many resource and environmental issues, e.g., effectively exploiting shale gas and clearly understanding water and methane global cycles. To investigate methane and water vapor permeability in shale, a new permeability determination method was proposed using a linearization approach based on previous studies. The experimental samples are crushed Carboniferous shale from the eastern Qaidam Basin in China. Simultaneous methane and water vapor transport experiments in shale were performed. Water vapor was derived through deionized water evaporation under different methane pressures. The relative humidity dynamically changed during the experiment. The methane and water vapor transport processes were observed and recorded, and the methane and water vapor permeability in the shale matrix was calculated. Both the methane and water vapor permeabilities temporally varied, and a critical abrupt point occurred in the decreasing process over time. After the abrupt point, the permeability rapidly decreased, which was mainly due to capillary condensation plugging at high relative humidities. Pore throat closure could dramatically affect permeability. The relationship between permeability and water saturation (Sw) conformed to an exponential equation. Methane permeability was sensitive to water saturation variation at very low or high levels (Sw < 20% or Sw > 50%, respectively) and relatively insensitive at a moderate water content. Water vapor permeability variation with water saturation was similar to that in methane but basically remained stable at a moderate water saturation (10% < Sw < 50%). At high water saturations, water vapor permeability reduction was more sensitive than that in methane.
Article
CO2 geo-sequestration is a practical approach to achieve net-zero carbon target. However, one of the main challenges for successful CO2 geo-sequestration is the reduced coal permeability and injectivity that are caused by coal swelling. Coal has complex and heterogenous internal pore and fracture structure. The processes of gases adsorbing, desorbing, and transporting within multiscale heterogeneous coal structures are more complicated compared with conventional rocks. This paper aims to gain insights about the gas transport behaviours in coal by developing a coupled model to simulate gas flow multiphysics as well as dynamic coal deformation. This work develops an image-based 3D fracture network model, called Fracture Box Model (FBNM). In this model, each fracture is described by arrays of box elements such that the regional change of fracture opening widths can be preserved. Compared with other fracture models (e.g. discrete fracture network), FBNM can simulate complicated multiphysical gas transport more efficiently, but also be able to simulate corresponding coal matrix deformation. By comparing permeability results between direct simulation method with FBNM, it is found that FBNM can effectively estimate the permeability of original fracture networks, but requiring significantly less computational cost. To study the implications of gas types, effective stress, gas adsorption, and thermal expansion on coal permeability, gas injection pressures, gas types, coal seam temperatures are varied and investigated in the simulations. In addition to the advantage of computational efficiency, FBNM is more preferable for complicated flow transport simulations where direct simulation methods are still challenging. This work provides a promising framework to be further developed for multiphase and multicomponent flow simulations for CO2 geo-sequestration projects.
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This work presents the development of a 3D hybrid coupled dual continuum and discrete fracture model for simulating coupled flow, reaction and deformation processes relevant to fractured reservoirs with multiscale fracture system, e.g., coal and shale, efficiently and accurately. In this hybrid model, the natural fracture network and coal matrix are described together by a dual continuum approach and the large fractures are represented explicitly by the discrete fracture approach. A combination of different types of elements is used for spatial discretization. Large fractures are discretised with lower-dimensional interface elements and continuum domains with higher-dimensional elements. The coupling between the two models is achieved via the principle of superposition. To reduce computational time of simulations for complex and large-scale problems, a hybrid MPI/OpenMP parallel scheme is implemented in this work. The developed model is applied to investigate coupled thermal, hydraulic, and mechanical processes associated with CO2 sequestration and enhanced coalbed methane recovery. The results demonstrate capabilities of the model to adequately capture the effects of multiscale fracture system and their coupled behaviour during CO2 injection and methane recovery from coal reservoirs. Performance of the proposed parallelisation scheme was tested by comparing computation times of serial and parallel implementations. A good performance improvement was achieved, the speedup using parallelized scheme reaches up to about 10 times along with satisfactory scalability for considered application example. The findings of this work support developments and improvements of efficient advanced numerical models to study coupled THCM behaviour in fractured porous geomaterials.
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Current permeability models are normally derived on the assumption of local equilibrium between coal matrixes and fracture within the representative elementary volume (REV) during gas extraction/injection. Under this assumption, the gas pressure and its associated swelling strain will distribute uniformly throughout the entire REV irrespective of the equilibration process between coal matrixes and fracture. This uniform distribution has long been considered as the reason why current permeability models cannot explain permeability data as widely reported. Significant efforts have been made to resolve this issue for the last decade but all these efforts ignore the transient nature of local equilibration evolution from initial to ultimate equilibrium states. In this study, we developed a concept of local non-equilibrium index (LNEI) to define a complete permeability model under the influence of gas extraction/injection. The application of this concept transforms equilibrium permeability models to non-equilibrium ones. Equilibrium models represent only two end points (before gas extraction/injection and after the completion of gas extraction/injection) while our non-equilibrium one represents the complete evolution of coal permeability between two end points. Our non-equilibrium model is degenerated to replicate all equilibrium models as reported in the literature and used as a key cross-coupling relation to formulate the non-equilibrium multiphysics model. Our non-equilibrium multiphysics model is verified against two rare experimental data sets and applied to predict the effects of the local equilibration process on both the evolution of coal permeability and the gas production under field conditions.
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Sequestration of carbon dioxide (CO2) in deep coal seams has been identified as a promising technique to mitigate global warming with added benefit of enhancing coalbed methane recovery. Understanding coal structure and its reactivity with injected CO2 is important for CO2 sequestration in coal. Despite the long-standing hypothesis, there is no direct evidence of softening effects of CO2 on coal due to CO2-coal interactions. Here, we used optical microscopy and nanoindentation to study changes in microstructures and nanoscale mechanical properties of untreated and CO2-treated anthracite coal. Microscopic images indicated coal surface cracked after short-term treatment and then became highly wrinkled and distorted after long-term treatment. These changes reflect that CO2 dissolves in the macromolecular network and acts as a solvent allowing a rearrangement of the network. Nanoindentation directly confirmed the softening effects of CO2 on nanoscale mechanical properties, including Young's modulus, hardness, and fracture toughness. Interestingly, all these changes were reversible to some extent after removing CO2 from coal. These findings provide new evidence for clarifying the polymeric macromolecular structure of coal and directly demonstrated the softening effect of CO2 on the macromolecular structure.
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Understanding the difference between CH4 and CO2 adsorption mechanisms is essential for better implementation of CO2 Enhanced Coal Bed Methane Recovery (CO2-ECBM). In this paper, with the help of low-pressure physisorption of N2 at 77 K and CO2 at 273 K, an adsorption model based on microporous filling and surface covering has been used to estimate the gas adsorption capacity. The model was validated by CH4 and CO2 high-pressure adsorption experiments at 303 K and gas pressure up to 6 MPa using four coal samples with different ranks. Then the model-based adsorption space and bulk density were used to determine the factors affecting the differences between CH4 and CO2 adsorption. Results show that the correlation between the model calculated adsorption capacity and the experimental adsorption capacity is 0.952 for CH4 and 0.967 for CO2, which supports the reliability of the model. The microporous filling is found to account for 85.06–93.41% and 91.87-97.15% of the total gas adsorption capacity for CH4 and CO2, respectively, meaning that should be the main adsorption behavior in coal. In terms of adsorption space, it should also be noted that for these four samples, 2.85–13.88% of the CO2 is adsorbed within 0.33–0.38 nm which is inaccessible to CH4. Within different pore sizes at the microporous filling stage, the bulk densities of CH4 and CO2 are 19.737–31.171 mol/L and 30.197–47.885 mol/L, respectively; the bulk density of CH4 is 1.5 times bigger than that of CO2 for the same pore size. Based on these findings, a method for calculating adsorption phase density has been proposed.
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Previous studies on coal permeability models have considered that the coal matrix is separated from each other. Under the influence of adsorption, the deformation of matrix was equal to that of the fracture. However, many recent studies have shown that the coal matrix was not separated from each other, and that only a part of the matrix expansion during adsorption influenced the fracture deformation. Therefore, the internal swelling coefficient (ISC), which is used for the direct relationship between the fracture deformation and the matrix deformation, have been proposed in the development of coal permeability models. However, ISC was assumed constant in most of the previous permeability models. Only a few studies have focused on the variation of the ISC. Moreover, the influence of the ISC on gas drainage is still not clearly understood. In this study, coal was assumed to be composed of matrix and fracture, and the space of pore and fracture in coal was regarded as a single fracture. Assuming that the matrix unit was connected by the matrix bridge and considering the matrix–fracture interaction, a numerical simulation approach was used to calculate the ISC under the influence of adsorption using a simplified calculation model of a coal unit. The evolution of the ISC under different geometric conditions was simulated. The effects of various factors, such as the height, width, number and the types of adsorptive gas on the variation of the ISC were analyzed. The simulation results show that the ISC increased with the increase of matrix bridge height and matrix bridge number, whereas it decreased with the increase of matrix bridge width. For the same gas pressure, the quantitative order of the ISC after adsorbing different types of gas was found in the following ascending order: CH4 < CH4/CO2 mixture < CO2. Finally, based on the relationship between the ISC and the gas pressure, the influence of the ISC on gas drainage in deep low-permeability coal seam was analyzed.
Chapter
Gas drainage technologies are the main means of lowering the gas content of coal seams and eliminating the gas hazard of coalmines. As China has a huge reservoir of coalbed methane (CBM) resources, the extraction and utilization of coal seam gas resources can realize the significant triple benefits of ensuring the safe mining of coal resources, promoting the clean and efficient use of coalmine gas, and protecting the environment.
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Although the permeability model has been studied for many years, the effect of adsorption strain has not been well explained. In this study, a new permeability model including a swelling increment factor (SIF) is proposed. The SIF expressed by the physical parameters and pressure affects the evolution of permeability. The permeability model consists of three parts: the matrix strain of effective stress, the fracture strain of effective stress, and the adsorption strain of coal. It is found that gas adsorption makes a big contribution to the evolution of permeability. Three different forms of the permeability model are derived such as constant volume condition, constant confining stress, and uniaxial strain condition. The permeability model considered the SIF fits the experiment and field data well. The permeability model can be widely used in different conditions to explain the mechanism of permeability in matrix-fracture and the adsorption strain relationship among fracture, matrix, and coal bulk.
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Earth's porous crust and the fluids within it are intimately linked through their mechanical effects on each other. This paper presents an overview of such "hydromechanical" coupling and examines current understanding of its role in geologic processes. An outline of the theory of hydromechanics and rheological models for geologic deformation is included to place various analytical approaches in proper context and to provide an introduction to this broad topic for nonspecialists. Effects of hydromechanical coupling are ubiquitous in geology, and can be local and short-lived or regional and very long-lived. Phenomena such as deposition and erosion, tectonism, seismicity, earth tides, and barometric loading produce strains that tend to alter fluid pressure. Resulting pressure perturbations can be dramatic, and many so-called "anomalous" pressures appear to have been created in this manner. The effects of fluid pressure on crustal mechanics are also profound. Geologic media deform and fail largely in response to effective stress, or total stress minus fluid pressure. As a result, fluid pressures control compaction, decompaction, and other types of deformation, as well as jointing, shear failure, and shear slippage, including events that generate earthquakes. By controlling deformation and failure, fluid pressures also regulate states of stress in the upper crust. Advances in the last 80 years, including theories of consolidation, transient groundwater flow, and poroelasticity, have been synthesized into a reasonably complete conceptual framework for understanding and describing hydromechanical coupling. Full coupling in two or three dimensions is described using force balance equations for deformation coupled with a mass conservation equation for fluid flow. Fully coupled analyses allow hypothesis testing and conceptual model development. However, rigorous application of full coupling is often difficult because (1) the rheological behavior of geologic media is complex and poorly understood and (2) the architecture, mechanical properties and boundary conditions, and deformation history of most geologic systems are not well known. Much of what is known about hydromechanical processes in geologic systems is derived from simpler analyses that ignore certain aspects of solid-fluid coupling. The simplifications introduce error, but more complete analyses usually are not warranted. Hydromechanical analyses should thus be interpreted judiciously, with an appreciation for their limitations. Innovative approaches to hydromechanical modeling and obtaining critical data may circumvent some current limitations and provide answers to remaining questions about crustal processes and fluid behavior in the crust.
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Sequestration of CO2 and H2S into deep unminable coal seams is an attractive option to reduce their emission into atmosphere and at the same time displace preadsorbed CH4 which is a clean energy resource. High coal seam permeability is required for efficient and practical sequestration of CO2 and H2S and recovery of CH4. However, adsorption of CO2 and H2S into coals induces strong swelling of the coal matrix (volumetric strain) and thus reduces significantly coal permeability by narrowing and even closing fracture apertures. Our experimental data on three western Canadian coals show that the adsorption-induced volumetric strain is approximately linearly proportional to the volume of adsorbed gas, and for the same gas, different coals have very similar volumetric strain coefficient. Impacts of adsorption-induced swelling on stress and permeability around wellbores were analytically investigated using our developed stress and permeability models. Our model results indicate that adsorption-induced volumetric strain has significant controls on stress and permeability of producing and sequestrating coal seams and consequently the potential of acid gas sequestration. Coal seams may undergo >10 times enhancement of permeability around CH4-producing wellbores due to a reduction in effective stress as a result of coal shrinking caused by methane desorption accompanying a reduction in reservoir pressure. Injection of H2S and CO2 on the other hand results in strong sorption-induced swelling and a marked increase in effective stress which in turn leads to a reduction of coal seam permeability of up to several orders of magnitude. Injection of mixtures of N2 and CO2 such as found in flue gas results in weaker swelling, the amount of which varies with gas composition, and provides the greatest opportunity of sequestering CO2 and secondary recovery of CH4 for most coals. Because of the marked swelling of coal in the presence of H2S, even minor amounts of H2S result in a marked reduction in permeability, and hence sequestration of H2S in deep coals will be likely impractical. Furthermore, high stresses resulting from sorption of acid gases will potentially cause the coal to yield, fracture or slip, and produce fine particles, which further affect permeability and thus methane production and acid gas sequestration.
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This article reviews the storage of captured CO 2 in coal seams. Other geologic formations, such as depleted petroleum reservoirs, deep saline aquifers and others have received considerable attention as sites for sequestering CO 2 . This review focuses on geologic sequestration of CO 2 in unmineable coalbeds as the geologic host. Key issues for geologic sequestration include potential storage capacity, the storage integrity of the geologic host, and the chemical and physical processes initiated by the deep underground injection of CO 2 . The review topics include (i) the estimated CO 2 storage capacity of coal, along with the estimated amount and composition of coalbed gas; (ii) an evaluation of the coal seam properties relevant to CO 2 sequestration, such as density, surface area, porosity, diffusion, permeability, transport, rank, adsorption/desorption, shrinkage/swelling, and thermochemical reactions; and (iii) a treatment of how coalbed methane (CBM) recovery and CO 2 -enhanced coalbed methane (ECBM) recovery are performed (in addition, the use of adsorption/ desorption isotherms, injection well characterization, and gas injection are described, as well as reservoir screening criteria and field tests operating in the United States and abroad); (iv) leak detection using direct measurements, chemical tracers, and seismic monitoring; (v) economic considerations using CO 2 injection, flue gas injection, and predictive tools for CO 2 capture/ sequestration decisions; (vi) environmental safety and health (ES&H) aspects of CO 2 -enhanced coalbed methane/sequestration, hydrodynamic flow through the coal seam, accurate gas inventory, ES&H aspects of produced water and practices relative to ECBM recovery/sequestration; (vii) an initial set of working hypotheses concerning the chemical, physical, and thermodynamic events initiated when CO 2 is injected into a coalbed; and (viii) a discussion of gaps in our knowledge base that will require further research and development. Further development is clearly required to improve the technology and economics while decreasing the risks and hazards of sequestration technology. These concerns include leakage to the surface, induced seismic activity, and long-term monitoring to verify the storage integrity. However, these concerns should not overshadow the major advances of an emerging greenhouse gas control technology that are reviewed in this paper.
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Enhanced coalbed methane recovery (ECBM) increases the recovery of the methane present in a coal seam by injecting CO2 at high pressure. It is attractive from two perspectives, the valuable methane recovered and the storage of the greenhouse gas CO2 for geological times. In the framework of a feasibility study for the Sulcis Coal Province in Italy, the adsorption of pure CO2 and CH4 on dry coal has been measured at 45 and 60°C, using a magnetic suspension balance with in situ density measurement. The results show that the CO2 adsorption isotherms on coal are similar to those for other standard adsorbents such as silica gel and activated carbon. From the excess adsorption isotherms, the absolute adsorption is calculated using the assumption of constant volume of the adsorbed phase. As expected, CO2 get adsorbed more than CH4 in all cases. The Sulcis coal can uptake CO2 at the reservoir conditions in an amount of about 10% of its mass. © 2006 American Institute of Chemical Engineers Environ Prog, 2006
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Earth's porous crust and the fluids within it are intimately linked through their mechanical effects on each other. This paper presents an overview of such "hydromechanical" coupling and examines current understanding of its role in geologic processes. An outline of the theory of hydromechanics and rheological models for geologic deformation is included to place various analytical approaches in proper context and to provide an introduction to this broad topic for nonspecialists. Effects of hydromechanical coupling are ubiquitous in geology, and can be local and short-lived or regional and very long-lived. Phenomena such as deposition and erosion, tectonism, seismicity, earth tides, and barometric loading produce strains that tend to alter fluid pressure. Resulting pressure perturbations can be dramatic, and many so-called "anomalous" pressures appear to have been created in this manner. The effects of fluid pressure on crustal mechanics are also profound. Geologic media deform and fail largely in response to effective stress, or total stress minus fluid pressure. As a result, fluid pressures control compaction, decompaction, and other types of deformation, as well as jointing, shear failure, and shear slippage, including events that generate earthquakes. By controlling deformation and failure, fluid pressures also regulate states of stress in the upper crust. Advances in the last 80 years, including theories of consolidation, transient groundwater flow, and poroelasticity, have been synthesized into a reasonably complete conceptual framework for understanding and describing hydromechanical coupling. Full coupling in two or three dimensions is described using force balance equations for deformation coupled with a mass conservation equation for fluid flow. Fully coupled analyses allow hypothesis testing and conceptual model development. However, rigorous application of full coupling is often difficult because (1) the rheological behavior of geologic media is complex and poorly understood and (2) the architecture, mechanical properties and boundary conditions, and deformation history of most geologic systems are not well known. Much of what is known about hydromechanical processes in geologic systems is derived from simpler analyses that ignore certain aspects of solid-fluid coupling. The simplifications introduce error, but more complete analyses usually are not warranted. Hydromechanical analyses should thus be interpreted judiciously, with an appreciation for their limitations. Innovative approaches to hydromechanical modeling and obtaining critical data may circumvent some current limitations and provide answers to remaining questions about crustal processes and fluid behavior in the crust.
Article
Unipore diffusion models are used widely to model gas transport in a coal matrix in conventional dual-porosity coalbed-reservoir simulators. The unipore models implemented in conventional coalbed-reservoir simulators assume that there is a negligible free-gas phase in the coal matrix and that gas exists only in an adsorbed state under hydrostatic pressure. In low-rank coals, however, a substantial amount of free gas may exist in the macropores of the coal matrix. There is strong laboratory evidence that many coals exhibit bi-or multimodal pore structure. This paper describes the implementation of a bidisperse pore-diffusion model in a coalbed-reservoir simulator. In the bidisperse model, gas adsorption is assumed to take place only in the micropores, with the macropores providing storage for free gas, as well as tortuous paths for gas transport between the micropores and cleats. Gas-production performance from a sub-bituminous Powder River basin coalbed reservoir has been studied using an in-house coalbed-reservoir simulator. The implementation of the triple-porosity formulation in the simulator overcame the reported inconsistency between field gas-production rates and predicted rates obtained with conventional dual-porosity simulators. With the introduction of an appropriate storage volume of free gas in the macropores, the predicted increase in gas-production rates are consistent with the published field data.
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The permeability of Westerly granite was measured as a function of effective pressure to 4 kb. A transient method was used, in which the decay of a small incremental change of pressure was observed; decay characteristics, when combined with dimensions of the sample and compressibility and viscosity of the fluid (water or argon) yielded permeability, k. k of the granite ranged from 350 nd (nanodarcy = 10−17 cm2) at 100-bar pressure to 4 nd at 4000 bars. Based on linear decay characteristics, Darcy's law apparently held even at this lowest value. Both k and electrical resistivity, ρs, of Westerly granite vary markedly with pressure, and the two are closely related by k = Cρs−1.5±0.1, where C is a constant. With this relationship, an extrapolated value of k at 10-kb pressure would be about 0.5 nd. This value is roughly equivalent to flow rates involved in solute diffusion but is still a great deal more rapid than volume diffusion. Measured permeability and porosity enable hydraulic radius and, hence, the shape of pore spaces in the granite to be estimated. The shapes (flat slits at low pressure, equidimensional pores at high pressure) are consistent with those deduced from elastic characteristics of the rock. From the strong dependence of k on effective pressure, rocks subject to high pore pressure will probably be relatively permeable.
Conference Paper
One option to reduce carbon dioxide emissions in order to control the overall levels of CO2 in the atmosphere is permanent storage in subsurface coal seams, while simultaneously producing methane (ECBM-CO2). This option has gained increasing interest world-wide during the last couple of years, as can be observed by growing interest for ECBM in the latest GHGT conferences. Although several desk studies illustrated the potential of the process, only a few experimental field sites have been realized in the world. In November 2001, the EC-funded RECOPOL project started, which targets the development of the first European demonstration plant of CO2 storage in coal seams while enhancing coalbed methane (CBM) production. An international consortium was formed to execute the research, design, construction and operation of the RECOPOL project
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This paper describes the results of a single well micro-pilot test performed at an existing well in the anthracitic coals of the South Qinshui basin, Shanxi Province, China. A set of reservoir parameters was obtained from the micro-pilot test. The field data was successfully history matched using a tuned reservoir model which accounted for changes in permeability due to swelling and pressure change. Prediction of initial performance showed significant production enhancement of coalbed methane while simultaneously storing the CO2. The calibrated reservoir model was used to design a multi-well pilot at the site to validate the performance prediction. The design is now completed. The recommendation is to proceed to the next stage of multi-well pilot testing and to demonstrate the enhanced coalbed methane (ECBM) technology.
Article
Gases like CO2 and CH4 are able to adsorb on the coal surface, but also to dissolve into its structure causing the coal to swell. In this work, the binary adsorption of CO2 and CH4 on a dry coal (Sulcis Coal Province, Italy) and its swelling behavior are investigated. The competitive adsorption measurements are performed at 45 °C and up to 190 bar for pure CO2, CH4 and four mixtures of molar feed compositions of 20.0, 40.0, 60.0 and 80.0% CO2 using a gravimetric-chromatographic technique. The results show that carbon dioxide adsorbs more favorably than methane leading to an enrichment of the fluid phase in CH4. Coal swelling is determined using a high-pressure view cell, by exposing a coal disc to CO2, CH4 and He at 45 and 60 °C and up to 140 bar. For CO2 and CH4 a maximum swelling of about 4 and 2% is found, whereas He shows negligible swelling. The presented adsorption and swelling data are then discussed in terms of fundamental, thermodynamic aspects of adsorption and properties which are crucial for an ECBM operation, i.e. the CO2 storage capacity and the dynamics of the replacement of CH4 by CO2.
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The recovery of coalbed methane can be enhanced by injecting CO2 in the coal seam at supercritical conditions. Through an in situ adsorption/desorption process the displaced methane is produced and the adsorbed CO2 is permanently stored. This is called enhanced coalbed methane recovery (ECBM) and it is a technique under investigation as a possible approach to the geological storage of CO2 in a carbon dioxide capture and storage system. This work reviews the state of the art on fundamental and practical aspects of the technology and summarizes the results of ECBM field tests. These prove the feasibility of ECBM recovery and highlight substantial opportunities for interdisciplinary research at the interface between earth sciences and chemical engineering.
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This paper presents an alternative model of multicomponent gas diffusion and flow in bulk coals, focusing on CH4–CO2 counter-diffusion associated with CO2-sequestration enhanced coalbed methane (CO2-ECBM) recovery. The model was developed based on the bidisperse diffusion mechanism and the Maxwell–Stefan (MS) diffusion theory, which provides an improved simulation of multicomponent gas diffusion dynamics. The model was firstly validated under the condition of pure gas diffusion by comparing with the analytical solutions of a bidisperse diffusion model and the experimental data obtained from pure-gas sorption kinetic tests. Then it was numerically solved by considering CH4–CO2 counter-diffusion and flow in a large coal sample to simulate a laboratory CO2-injection core flush experiment. The simulation shows an excellent agreement with the CO2 flush experiment. A quantitative description of the relationship between micropore diffusivity and concentration has been achieved, which is a deficiency in currently available CBM/ECBM models. The concentration-dependent diffusivities need to be taken into account in modeling the coalbed methane (CBM) recovery, in particular for simulation of ECBM production from and CO2 sequestration in coal seams.
Article
This paper (SPE 52607) was revised for publication from paper SPE 36737, first presented at the 1996 SPE Annual Technical Conference & Exhibition, Denver, 6-9 October. Original manuscript received for review 25 October 1996. Revised manuscript received 17 August 1998. Paper peer approved 1 September 1998. Summary In naturally fractured formations such as coal, permeability is sensitive to changes in stress or pore pressure (i.e., changes in effective stress). This paper presents a new theoretical model for calculating pore volume (PV) compressibility and permeability in coals as a function of effective stress and matrix shrinkage, by means of a single equation. The equation is appropriate for uniaxial strain conditions, as expected in a reservoir. The model predicts how permeability changes as pressure is decreased (i.e., drawdown). PV compressibility is derived in this theory from fundamental reservoir parameters. It is not constant, as often assumed. PV compressibility is high in coals because porosity is so small. A rebound in permeability can occur at lower drawdown pressures for the highest modulus and matrix shrinkage values. We have also history matched rates from a boomer well in the fairway of the San Juan basin by use of various stress-dependent permeability functions. The best fit stress/permeability function is then compared with the new theory. P. 539
Article
The matrix volume of coal shrinks when occluded gases desorb from its structure. In coalbed gas reservoirs, matrix shrinkage could cause the fracture aperture width to increase, causing an increase in permeability. A computer model was developed, based on elastic rock mechanics principles, to evaluate the potential effect of matrix shrinkage on the absolute permeability of coalbed reservoirs as fluid pressure is drawn down during gas production. The model predicts that the fracture width can potentially increase, depending on the combined influence of a number of parameters, particularly Young’s modulus of elasticity, Poisson’s ratio, fracture spacing and matrix shrinkage parameters. Each of these parameters vary depending on coal composition, so each individual coal will behave differently. A sensitivity study was conducted to evaluate the influence of each model parameter using a geologically reasonable range of input values. ‘Base case’, upper and lower limits were selected, based on published data. Gas production was simulated by reducing fluid pressure from 1290 PSI (8.89 MPa) to 100 PSI (0.70 MPa). The matrix shrinkage parameter ε max was found to produce the largest effect on permeability. Permeability changes as large as +250 mD are predicted for the upper case value of ε max . If ε max is small, however, the predicted permeability change will be negligible. An increase in Young’s modulus, Poisson’s ratio and fracture spacing each cause a predicted increase in permeability. Results of this model study should be verified through additional modelling, laboratory and field-based studies.
Article
Static and dynamic geomechanical properties and hydraulic permeability were determined for six large blocks of bituminous coal sampled from active mines in the Foothills and Mountain regions of western Canada. Testing showed a nonlinear shear strength envelope and brittle failure during triaxial loading. The dominant failure mode was along distinct shear planes. Effective compressive strengths increased from 8.6MPa to 80.8MPa with increasing confining pressure. The Mohr–Coulomb failure criterion showed that the coals had friction angle of 29.8° to 39.8° and cohesion ranging between 3.4MPa and 8.0MPa with increasing confining stress. The non-linear Hoek–Brown failure envelope was also fit to the data which provided a better estimation of the strength. Values for static Young's modulus ranged from 1119MPa to 5070MPa and Poisson's ratio ranged from 0.26 to 0.48, also varying with the confining stress. Concurrent ultrasonic measurements indicate that the values for dynamic moduli are consistently higher than those obtained from quasi-static measurements. Permeability of the coals tested at simulated in situ stress conditions and parallel to bedding surfaces was highly variable, ranging from 2.09md in Seam 3, Greenhills Mine, to less than 0.001md in Seam 10, Elkview Mine. This variation may be rationalized based on variations in maceral composition, stress history, degree of shearing, and the mode of deformation (brittle or ductile) of the coal seams in these tectonically complex regions.
Article
This is the first of two papers concerning the movement of gas in coal seams. It deals directly with the physical behavior of the coal seam as a reservoir. Coal seams show considerable differences in behavior from normal porous gas reservoirs in both the mode of gas storage and permeability characteristics. Most of the storage of gas in coal is by sorption into the coal structure, while the coal permeability is cleat-(fracture-) or joint-controlled and may vary over a wide range during production. This permeability fluctuation is not solely a phase relative permeability effect, but is rather a result of the opposing effects of effective stress increase with fluid pressure reduction and shrinkage of the coal. Reducing fluid pressure tends to close the cleats, reducing permeability, while shrinkage tends to open them.
Article
The "swelling" of coal by a penetrant refers to an increase in the volume occupied by the coal as a result of the viscoelastic relaxation of its highly crosslinked macromolecular structure. Projects relating to CO2 sequestration in coal seams suffer a serious setback in terms of injectivity loss resulting from the swelling of coal. Volumetric swelling associated with CO2 sorption on coal has a significant influence on the fracture porosity and permeability of the coal. Two coal samples differing in rank were used for volumetric strain measurements. With CO2, the high-rank Selar Cornish coal showed a maximum volumetric strain of 1.48% corresponding to an average pore pressure of 13 MPa. A matrix swelling coefficient (Cm) of 1.77×10−4 MPa−1 was calculated for this Selar Cornish coal. The low-rank Warndt Luisenthal coal exhibited higher strain of 1.6%, and a matrix swelling coefficient (Cm) of 8.98×10−5 MPa−1 was calculated. The rank dependence of swelling holds true in this set of experiments. Repeat volumetric strain measurement on the same Warndt Luisenthal coal core shows higher volumetric strain values for all pressure steps. A volumetric strain of 1.9% corresponding to a mean pore pressure of 14 MPa was measured. This confirms the process of sequential swelling. A unique feature of this work is that real-time permeability measurements were done under unconstrained conditions. Permeabilities were measured, reducing the pore pressure from 16 to 1 MPa at constant flow rate. Although measured permeability increased with increasing pore pressure under unconstrained swelling, in-situ permeability will actually decrease because of fracture closure in a constrained coal. To validate the permeability swelling relationship, both permeability measurements under unconstrained conditions and volumetric strain measurements were used.
Article
Injection of either carbon dioxide (CO2) or nitrogen (N2) enhances recovery of coalbed methane. In this paper, we provide new analytical solutions for the flow of ternary gas mixtures in coalbeds. The adsorption/desorption of gaseous components to/from the coalbed surface is approximated by an extended Langmuir isotherm, and the gas-phase behavior is predicted by the Peng-Robinson equation of state (EOS). Langmuir isotherm coefficients are used that represent a moist Fruitland coal sample from the San Juan basin (U.S.A.). In these calculations, mobile liquid is not considered. Given constant initial and injection compositions, a self-similar solution consisting of continuous waves and shocks is found. Mixtures of CH4,CO2, and N2 are used to represent coalbed and injection gases. We provide examples for systems where the initial gas is largely CH4, and binary mixtures of CO2 and N2 are injected. Injection of N2-CO2 mixtures rich in N2 leads to relatively fast initial recovery of CH4. Injection of mixtures rich in CO2 gives slower initial recovery, increases breakthrough time, and decreases the injectant needed to sweep out the coalbed. The solutions presented indicate that a coalbed can be used to separate N2 and CO2 chromatographically at the same time coalbed methane (CBM) is recovered.
Article
Carbon dioxide displays a strong affinity for coal due to its propensity to adsorb to the coal surface. The process of CO2 adsorption on coal causes lowering of surface energy and, it is hypothesised that an associated decrease in surface film confinement results in a decrease in material tensile resistance. Following the results of work carried out on the mechanical influence of CO2 on brown coal under in situ conditions [Viete DR, Ranjith PG. The effect of CO2 on the geomechanical and permeability behaviour of brown coal: implications for coal seam CO2 sequestration. Int J Coal Geol 2006;66(3):204–16], a theoretical explanation is proposed for the perceived lack of a weakening effect with the adsorption of CO2 to coal at significant confining pressures. We propose that at significant hydrostatic stresses, resistance to failure is otherwise provided (by external confinement) and the effects of adsorptive weakening are concealed. Our model predicts that adsorptive weakening, fracturing under in situ stresses, and associated permeability increases are not an issue for coal seam CO2 sequestration for sufficiently deep target seams. Lowering of the elastic modulus of coal upon introduction of CO2 may proceed by means other than surface energy lowering and could well occur irrespective of the depth of sequestration. The effect of elastic modulus lowering under in situ conditions would be beneficial for the long-term retention of sequestered gases.
Article
Adsorption/desorption isotherms were established for powdered coal samples. Gas pressure-permeability relationships for cylindrical specimens of coal, under triaxial stress conditions, were also determined. Gas pressure-volumetric strain relationships were established using strain gauges on the same specimens. The results indicate that the permeability of coal to methane increases with decreasing gas pressure, in spite of increased effective stress. The primary reason for this increase in permeability is the shrinking of the coal matrix, which is associated with desorption, thus enlarging the gas flow paths. The volume of the coal matrix shrinks by ≈0.4% when the gas pressure falls from 6.9 MPa to atmospheric pressure. The results suggest that higher flow rates can be expected as a consequence of the shrinkage, and the associated enhanced permeability, over the life of methane-producing wells in coalbeds.
Article
This chapter highlights that a multi-year government-industry R&D collaboration known as the coal-seq project was launched in the United States. Participants in the project include the U.S. department of energy as the project sponsor, advanced resources international, Burlington resources, and BP America. The project objectives were to evaluate the feasibility of CO2 sequestration in deep, unmineable coalseams using enhanced coalbed methane (ECBM) recovery technology. The coal-seq project achieved its objectives via reservoir simulation studies of existing ECBM pilot projects in the San Juan basin, laboratory modeling studies of coal behavior, technical and economic sensitivity studies, and assessments of the potential and economic performance for ECBM recovery and CO2 sequestration in deep, unmineable coals.
Article
Wem in der Wüste das Wasser ausgeht, der glaubt allzu gerne an die rettende Oase am Horizont. Doch wenn sich erst am Ende des Weges der vermeintliche Zufluchtsort als reine Luftspiegelung herausstellt, kann es für eine Umkehr zu spät sein. Es lohnt, sich vorab zu vergewis sern, welche Richtung man einschlägt. Ist die Vision der Industrie von der klimafreundlichen Kohleverstromung mehr als eine Fata Morgana, mehr als heiße Luft?
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A detailed experimental study has been made of the adsorption of pure methane, nitrogen, carbon dioxide, and their binary mixtures on dry activated carbon (Filtrasorb 400, 12 × 40 mesh, Calgon Carbon) at 318.2 K and pressures up to 13.6 MPa. The mixture measurements were made at nominal feed-gas compositions of 20, 40, 60, and 80 mol %. The mixture data clearly elucidate the competitive nature of the individual-component adsorption from the mixtures. Measurements were made using a volumetric technique, coupled with gas chromatographic analysis of the equilibrium gas-phase compositions. Error propagation analysis reveals the expected average experimental uncertainties in the amount adsorbed of 2% for pure methane and nitrogen and 6% for CO2. For the mixture measurements, the uncertainties are estimated to be about 3% for the total adsorption, while the individual-component uncertainties vary from 0.02 to 0.2 mmol/g activated carbon, depending on the mixture composition. The data were correlated using the two-dimensional Zhou−Gasem−Robinson equation of state model. The model fits the pure-component adsorption data within their experimental uncertainties, whereas the total and individual-component adsorptions in the binary systems are represented within one to two times the expected experimental uncertainties. As an additional benefit, the good agreement between the present data and those of Humayun and Tomasko for pure carbon dioxide (using two very different experimental techniques) suggests that these data provide a useful reference for benchmarking new experimental apparatus/techniques intended for the high-pressure adsorption measurements of supercritical gases.
Article
The matrix volume of coal swells when CO2 / CH4 adsorb on the coal structure. In coalbed gas reservoirs, matrix swelling could cause the fracture aperture width to decrease, causing a considerable reduction in permeability. On a unit concentration basis, CO2 causes greater degree of coal matrix swelling compared to CH4. Much of this difference is attributable to the differing sorption capacity that coal has towards carbon dioxide and methane. This condition in a coal reservoir would lead to differential swelling. Differential swelling will have consequences in terms of porosity / permeability loss, with serious implication for the performance and implementation of carbon sequestration projects. Coal can be understood as a macromolecular cross-linked polymeric structure. An experimental effort has been made to measure the differential swelling effect of CO2 / CH4 on this macromolecular structure and to theoretically translate that effect in terms of porosity and permeability. A unique feature of this work is that, real time permeability measurements were done to see the true effect of differential strain from CH4 saturated coal core flooding experiments. Introduction Coal matrix is heterogeneous and is characterized by three different porosity systems - micropore, mesopore and macropore. The macropores are the cleats, which are sub-vertically oriented to the bedding plane in coal. The cleat system consists of the face cleats, continuous throughout the reservoir, and butt cleats, which are discontinuous and terminate against the face cleat.
Article
Micro-pilot field tests were performed at Fenn-Big Valley, Alberta, Canada in a four metre-thick Mannville Formation coal seam by injecting four different gas mixtures: 100% CO 2 , 47% CO 2 -53% N 2 , 13% CO 2 -87% N 2 and 100% N 2 . Before injection, the well was on production for 30 days to obtain gas-and water-productivity data and produced-gas samples for composition determination. The production period was followed by a shut-in test. The pressure data collected during the shut-in period were analyzed to obtain permeability estimates before gas injection. During injection for each micro-pilot, injectivity was maintained at adequate rates (~0.5 (10 6) scf/D or 15(10 3) m 3 /D) in this low one to four md-permeability Mannville reservoir. Soak periods ranged from 30 to 60 days. Then the well was returned to production for 30 days to determine the well's productivity and composition of the produced gas. This huff and puff test was followed by a final shut-in test to obtain pressure and permeability measurements after injection. These data are being used to calibrate reservoir simulators to estimate the CO 2 storage potential and the enhanced hydrocarbon gas recovery in the design of multi-well pilots and for preliminary economic evaluations. These field tests led to the conclusion that low-permeability coal seams which may not be commercial under primary production could still be CO 2 storage sites with the added benefit of improving the possibilities for commercial gas production.
Article
A model for pore pressure-dependent cleat permeability is presented for gas-desorbing, linear elastic coalbeds under uniaxial strain conditions experienced in producing reservoirs. In the model, changes in the cleat permeability of coalbeds, which are idealised to have a bundled matchstick geometry, is controlled by the prevailing effective horizontal stresses normal to the cleats. Variations in the effective horizontal stresses under uniaxial strain conditions are expressed as a function of pore pressure reduction during drawdown, which includes a cleat compression term and a matrix shrinkage term that have competing effects on cleat permeability. A comprehensive analysis has revealed that the shape of the stress – pore pressure curve is predominantly determined by the magnitude of recovery pressure and rebound pressure relative to the initial reservoir pressure. A total of five possible scenarios have been identified with regard to response of the horizontal stress function to reservoir drawdown. When applied to four coalbed wells at two separate sites in the fairway of the San Juan basin, the model predictions at one site, where the three wells have shown increased absolute permeability during gas production, are in excellent agreement with the published pore pressure dependent permeability changes that were obtained independently from history matching the field production data. At a separate site the model correctly predicts, at least qualitatively, a strong permeability rebound at lower drawdown pressures that has been inferred through history matching the production data. An analysis of the effects of initial reservoir pressure on the response of effective horizontal stress to drawdown was carried out, with reference to the range of pressure likely to be encountered in the San Juan basin. The implications of this in terms of pore pressure dependent permeability are discussed.
Article
Coal-seam methane reservoirs have a number of unique feature compared to conventional porous or fractured gas reservoirs. We propose a simplified mathematical model of methane movement in a coal seam taking into account the following features: a relatively regular cleat system, adsorptive methane storage, an extremely slow mechanism of methane release from the coal matrix into cleats and a significant change of permeability due to desorption. Parameters of the model have been combined into a few dimensionless complexes which are estimated to an order of magnitude. The simplicity of the model allows us to fully investigate the influence of each parameter on the production characteristics of the coal seam. We show that the reference time of methane release from the coal matrix into cleats – the parameter which is most poorly investigated – may have a critical influence on the overall methane production.
Article
The gas permeability of a coalbed, unlike that of conventional gas reservoirs, is influenced during gas production not only by the simultaneous changes in effective stress and gas slippage, but also by the volumetric strain of the coal matrix that is associated with gas desorption. A technique for conducting laboratory experiments to separate these effects and estimate their individual contribution is presented in this paper. The results show that for a pressure decrease from 6.2 to 0.7 MPa, the total permeability of the coal sample increased by more than 17 times. A factor of 12 is due to the volumetric strain effect, and a factor of 5 due to the gas slippage effect. Changes in permeability and porosity with gas depletion were also estimated using the measured volumetric strain and the matchstick reservoir model geometry for flow of gas in coalbeds. The resulting variations were compared with results obtained experimentally. Furthermore, the results show that when gas pressure is above 1.7 MPa, the effect of volumetric strain due to matrix shrinkage dominates. As gas pressure falls below 1.7 MPa, both the gas slippage and matrix shrinkage effects play important roles in influencing the permeability. Finally, the change in permeability associated with matrix shrinkage was found to be linearly proportional to the volumetric strain. Since volumetric strain is linearly proportional to the amount of gas desorbed, the change in permeability is a linear function of the amount of desorbing gas.
Article
Theory from fracture mechanics and thermodynamics coupled with the results of experimental studies provides evidence to suggest that the adsorption of carbon dioxide on coal causes a decrease in the coal strength. Coal weakening by the introduction of CO2 to a coal seam may induce fracturing, causing a permeability increase under in situ conditions. Such effects present significant implications for proposals regarding the storage of CO2 in coal seams.A uniaxial and triaxial laboratory study was carried out to explore the effects of the adsorption of CO2 on the compressive strength and permeability of southeast Australian brown coal. Comparison of the stress–strain response of air-saturated and CO2-saturated specimens revealed a compressive strength decrease in the order of 13% and an elastic modulus decrease of about 26% for the uniaxial testing, but no significant strength or elastic modulus decrease for the triaxial testing. The absence of an adsorptive effect on the mechanical behaviour of the triaxial specimens may have been due to an insufficient saturation period under simulated ground conditions, or due to mechanical variability in the brown coal test specimens, however, further testing is required to reveal the reason for the apparent negligible strength reduction with CO2 adsorption at the higher confinement. Carbon dioxide outflow measurements during the stress–strain process demonstrated an initial permeability decrease with pore closure, followed by a significant increase in specimen permeability with fracturing.Issues that require consideration in the application of these results to coal seam CO2 sequestration include: whether the expected regional and localised in situ stresses are sufficient to initiate fracturing with adsorptive weakening; how coal properties (e.g. rank, moisture content) are likely to affect the geomechanical influence of CO2 adsorption, and the expected magnitude of the proposed fracture related permeability increase.
Article
To stabilize the atmospheric concentration of greenhouse gases (GHG), a huge reduction of carbon dioxide (CO2) emissions is required. Although some people believe that this necessitates a considerable reduction in the use of fossil fuels or fuel switching, other options are available that allow the use of fossil fuels and reduce atmospheric emissions of CO2. Sequestration of CO2 from fossil fuel combustion in the subsurface could prevent the CO2 from reaching the surface for millions of years. Geological sequestration of CO2 in deep aquifers or in depleted oil and gas reservoirs is a mature technology. Despite the huge quantities of CO2 that can be sequestered in this way, this approach does not provide any economic benefit. This paper discusses a third option, which consists of injecting CO2 in deep coal seams to sequester the carbon and enhance the recovery of coalbed methane (CBM). Waste CO2 from CBM-fueled power plants could be injected into CBM reservoirs to produce more methane (CH4) for the power plant. The 2:1 coal-sorption selectivity for CO2 over CH4 supports the feasibility of operating fossil-fueled power plants without atmospheric CO2 emissions. Other CO2 sequestration technologies, such as ocean disposal and biofixation, are briefly discussed and the suitability of these approaches is evaluated for use in Alberta, Canada.
Article
CH4/CO2 adsorption isotherm studies on coals samples give adsorption behavior, adsorption ratio, and other influential factors for enhanced coalbed methane recovery (ECBM) and CO2 sequestration by CO2 injection. Yet, they only provide static characteristics, and do not provide information on pressure-driven and concentration-driven during gas recovery and injection processes. The purpose of this study is to construct an experimental apparatus for CH4 displacement with CO2 injection and primarily study the basic procedure of coalbed methane (CBM), ECBM, and CO2 sequestration at driven-conditions.An experimental apparatus was built based on the configuration of one-injection well/one-production well under ideal conditions. The apparatus was used to model CBM with CH4 adsorption, investigate primary production of CBM and ECBM with gases desorption, and study CO2 sequestration with its breakthrough. The change of pressure and gases amount during gases injection and desorption, and residual quantity after gases desorption were employed to ECBM and CO2 sequestration with this equipment. The effect of CO2 injection on CH4 production was investigated on a small scale experimentally. The results indicate that the recovery procedure of ECBM and CO2 sequestration with CO2 injection can be studied with the apparatus and the gases adsorption/desorption characteristics obtained with the apparatus is obviously differ from that obtained with conventional volumetric measurement.
Article
Carbon dioxide dissolves in coals and swells them slightly. The dissolved CO2 seems to act as a plasticizer, enabling physical structure rearrangements and lowering the coal's softening temperature. Plasticized coals are known to rearrange to a more associated form in which fluids, including CO2, will be less soluble. A comparison of the sorption of CO2 and ethane, molecules of similar size, shows much greater CO2 uptake probably because of much faster diffusion of CO2 through the coal because CO2 readily dissolves in coals and ethane does not. Only a little is known of the effects of confining coal and lithostatic pressure on CO2 uptake and on the behavior of plasticized coals.
Article
For over 30 years, horizontal wells have been drilled into coal seams to release trapped methane and improve mine safety. For more than two decades, significant quantities of gas sorbed in coal seams have been collected as a relatively environmentally friendly fossil fuel energy resource. Laboratory experiments have shown that coals preferentially sorb carbon dioxide. Thus, concomitant enhanced coal bed methane production and carbon dioxide sequestration in unminable coal seams is a promising technology being developed as a win–win process to reduce global warming and produce a valuable energy resource. However, because CO2 will not reach all portions of the seam, not all of the in situ methane will be produced and not all of the “theoretical” sequestration capacity will be utilized. For sequestration, the amount of carbon dioxide that could be stored in the coal seam was found to be between 50% and 70% of the thermodynamic limit. The fraction of methane produced was much higher, between 80% and 97%. Reservoir simulations were used to predict how the well pattern and operating conditions can be modified to maximize the amounts of CO2 stored and CH4 recovered. For this study, we used the PSU-COALCOMP compositional coal bed methane reservoir simulator and measured sorption isotherms to predict the maximum amount of carbon dioxide that could be sequestered in a coal seam and show how coal seam characteristics and injection practices will reduce the actual amount sequestered.
Article
The capillary sealing efficiency of fine-grained sedimentary rocks has been investigated by gas breakthrough experiments on fully water saturated claystones and siltstones (Boom Clay from Belgium, Opalinus Clay from Switzerland and Tertiary mudstone from offshore Norway) of different lithological compositions. Sand contents of the samples were consistently below 12%, major clay minerals were illite and smectite. Porosities determined by mercury injection lay between 10 and 30% while specific surface areas determined by nitrogen adsorption (BET method) ranged from 20 to 48 m2 g − 1. Total organic carbon contents were below 2%. Prior to the gas breakthrough experiments the absolute (single phase) permeability (kabs) of the samples was determined by steady state flow tests with water or NaCl brine. The kabs values ranged between 3 and 550 nDarcy (3 × 10−21 and 5.5 × 10−19 m2). The maximum effective permeability to the gas-phase (keff) measured after gas breakthrough on initially water-saturated samples extended from 0.01 nDarcy (1 × 10−23 m2) up to 1100 nDarcy (1.1 × 10−18 m2). The residual differential pressures after re-imbibition of the water phase, referred to as the ‘minimum capillary displacement pressures’ (Pd), ranged from 0.06 to 6.7 MPa. During the re-imbibition process the effective permeability to the gas phase decreases with decreasing differential pressure. The recorded permeability/pressure data were used to derive the pore size distribution (mostly between 8 and 60 nm) and the transport porosity of the conducting pore system (10-5–10-2%). Correlations could be established between (i) absolute permeability coefficients and the maximum effective permeability coefficients and (ii) effective or absolute permeability coefficients and capillary sealing efficiency. No correlation was found between the capillary displacement pressures determined from gas breakthrough experiments and those derived theoretically by mercury injection.
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Coupled gas flow and solid deformation in porous media has received considerable attention because of its importance in pneumatic test analysis, contaminant transport, and gas outbursts during coal mining. Gas flow in porous media is quite different from liquid flow due to the large gas compressibility and pressure-dependent effective permeability. The dependence of gas pressure and gas desorption on gas permeability has a significant effect on gas flow, but has been ignored in most previous studies. Moreover, solid deformation has a direct impact on the porosity, which also leads to desorption or sorption of methane in the coal seam. In this study, a coupled mathematical model for solid deformation and gas flow is proposed and is implemented using a finite element method. The numerical code is used to solve the gas flow equation with Klinkenberg effect, and is validated by comparison with available analytical solutions. Then, it is used to simulate the coupled process during gas migration in a deformable coal seam. The numerical results indicate that the desorption and Klinkenberg effects and mechanical process effect make a significant contribution to gas flow in the coal seam. Without considering the desorption and Klinkenberg effects and the coupling action of mechanical process, the gas pressure in the coal seam would be underestimated.
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CO2 sequestration in coal seams is a relatively new technique to simultaneously achieve enhanced coal bed methane production and reduced CO2 emission. In this article, we integrate understandings in individual research fields to provide improved insight into the nature of this complex process. Our current overall model constructed from a number of sub-models consists of mass transfer in four pore types, namely, fractures, micro-, meso-, and macro-pores, all having pore size dependent characteristics. Key parameters are estimated using well established methods from the general literature. Three mechanisms of coal swelling leading to permeability variations during adsorption are proposed based on molecular simulations. The macroscopic level model is validated using a true tri-axial stress coal permeameter, which provides previously unpublished, accurate dynamic measurements of systems properties in three orthogonal directions including changes to the coal matrix volume. The integrated model provides a more complete and flexible representation for this complex system. (c) 2007 American Institute of Chemical Engineers.
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Data on the adsorption behavior of CO 2, CH 4, and N 2 on coal are needed to develop enhanced coalbed methane (ECBM) recovery processes, a technology where the recovery of CH 4 is enhanced by injection of a gas stream consisting of either pure CO 2, pure N 2, or a mixture of both. The pure, binary, and ternary adsorption of these gases on a dry coal from the Sulcis Coal Province in Italy has been measured at pressures up to 180 bar and temperatures of 45 and 70 degrees C for the pure gases and of 45 degrees C for the mixtures. The experiments were performed in a system consisting of a magnetic suspension balance using a gravimetric-chromatographic technique. The excess adsorption isotherms are successfully described using a lattice density functional theory model based on the Ono-Kondo equations exploiting information about the structure of the coal, the adsorbed gases, and the interaction between them. The results clearly show preferential adsorption of CO 2 over CH 4 and N 2, which therefore indicate that ECBM may be a viable option for the permanent storage of CO 2.