Enhanced Coalbed Methane Research Articles

Cracking Process and Stress Field Evolution in Specimen Containing Combined Flaw Under Uniaxial Compression

Hydraulic slotting, an efficient technique for underground enhanced coal bed methane (ECBM) recovery, has been widely used in China. However, its pressure relief mechanism is unclear. Thus far, only limited research has been conducted on the relationships among the mechanical properties, flaw parameters, and crack propagation patterns of coal after hydraulic slotting. In addition, because of the limitations of test methods, an in-depth information is not available for this purpose. In this work, numerical models of specimens containing combined flaws are established based on particle flow code method. Our results provide insights into the effects of flaw inclination angle on the mechanical properties, crack propagation patterns, and temporal and spatial evolution rules of stress field in specimens containing combined flaws during the loading process. Besides, based on the initiation position and underlying mechanism, three types of crack initiation modes are identified from the failure processes of specimens. Finally, the crack propagation pattern is quantitatively described by the fractal dimension, which is found to be inversely proportional to the uniaxial compressive strength and elastic modulus of the specimen. To verify the rationality of the numerical simulation results, laboratory tests were conducted and their results match well with those obtained from the numerical simulation.

Molecular dynamics study of CO2 sorption and transport properties in coal

An understanding of gas transport in nano-scale porous media is crucial for many industrial applications, for example, processes associated with CO2 injection, storage and enhanced coalbed methane (ECBM) production. In this study, we carried out combined molecular dynamics (MD) and Grand Canonical Monte Carlo (GCMC) simulations on the transport properties (i.e. self- and transport diffusivities and permeability) of CO2, in a realistic intermediate rank bituminous coal (flexible coal model) at a temperature of 328K (55°C) and a range of pressures up to 25MPa. Self-diffusivity and sorption isotherms of CO2 are obtained directly from the MD and GCMC simulations. The Maxwell–Stefan diffusion model was then applied to correlate the self- and transport diffusivities. The permeability was computed through an integration of the transport diffusivity over the sorption concentration obtained from the simulations. The results show that CO2 self-diffusivity decreases with increasing reservoir gas pressure up to 8MPa, then increases with pressure due to the interaction between coal and CO2. The transport diffusivity increases with the reservoir gas pressure as a result of an enhanced thermodynamic factor. The simulation results reveal a negative correlation between the sorption-induced coal swelling and CO2 self-diffusivity due to the interaction between CO2 and coal. Rigorous modeling of gas recovery and production thus requires consideration of specific interaction of the gas and coal matrix. Permeability of CO2 exponentially increases with the decreasing reservoir gas pressure, which is comparable with published field data.

Sorption charateristics of methane among various rank coals: impact of moisture

Enhanced coalbed methane (ECBM) in deep coal seams is being actively investigated around the world. Since the in situ coal seams are always saturated with water, methane sorption behavior on coal in the presence of water can help accurately assess the amount of recoverable methane. Thus, methane sorption isotherms have been measured on a high-rank anthracite, a low-volatile bituminous, a middle-volatile bituminous and a high-volatile bituminous coal with the manometric technology at 30 °C under six different moisture contents. The Dubinin–Astakhov (D–A) equation was used to fit the experimental sorption isotherm data. In all cases, the moisturized coals exhibited lower sorption capacity than the corresponding dry materials and moisture has a significant effect on CH4 sorption capacity. The maximum sorption capacity, V 0, displays a linear decline with the moisture content for the Changcun and Malan samples, but it is nonlinear for the other two coal samples. The net heat of CH4 sorption, βE, is also reduced by the presence of water, but varies only slightly between a relatively small span of about 8.8 and 10.0 kJ mol−1 for the dry samples studied, despite the difference in coal rank. In addition, the maximum sorption capacity of CH4 in dry coals presents the typical “U-shape” trend with coal rank. Moisture has a greater impact on the sorption capacity in low-rank coals than that in high-rank coals. The mechanisms responsible for the effect of moisture on CH4 sorption among various rank coals are also presented. The pore-blocking effect is the main influencing factor for high-rank anthracite, whereas, the competition sorption is dominant for low-rank coals.

Mechanical behaviors and failure processes of precracked specimens under uniaxial compression: A perspective from microscopic displacement patterns

Hydraulic slotting is an efficient permeability enhancement method that has been widely used in China for enhanced coalbed methane (ECBM) recovery. Although some research has been conducted on hydraulic slotting, the mechanical behaviors such as strength, deformation, and cracking processes of coal treated by this technique are still unclear. This paper numerically investigates the mechanical behaviors of specimens containing combined flaws with various inclination angles. Research results show that different flaw inclination angles result in variations in strength and deformation of precracked specimens. We also analyzed the crack initiation, propagation, and coalescence processes to understand the underlying mechanisms for the aforementioned variations. To evaluate the crack initiation and propagation process and its corresponding mechanisms, we proposed 12 types of displacement field modes from the perspective of particles relative motion. Based on this, evolution of the displacement field during loading process is analyzed and 11 types of crack and three types of crack initiation modes are extracted from the cracking processes of specimens with different inclination angles. Analysis of the displacement field not only indicates the type of each crack, but also reveals the formation mechanism of the three crack initiation modes. A comparison between the numerical results and the previous laboratory test results shows that numerical simulation can reproduce most of the phenomenon observed in the laboratory test. The research result is expected to contribute to the further understanding of the mechanical behavior of coal subjected to hydraulic slotting or the stability of rock structures.

Using stable carbon isotopes to track potential leakage of carbon dioxide: Example from an enhanced coal bed methane recovery site in West Virginia, USA

Produced natural gas, shallow groundwater, and soil vadose gas samples were collected at the CONSOL Energy Inc. CO2 Sequestration Pilot Test Site in Marshall County, WV to test the feasibility of using carbon isotope signatures to detect potential leakage of CO2. CO2 was injected into the Upper Freeport coal bed at a depth of ∼396m intermittently from September 2009 to December 2013. Water and gas samples were collected over a 12-month period (August 2013–August 2014). The injected CO2 had δ13C values ranging from −12.0‰ to −11.0‰ V-PDB. The average δ13CCO2 values of the soil vadose gas, the groundwater, and the produced CO2 from overlying Pittsburgh coal bed were −25.0‰, −16.6‰ and +22.8‰ V-PDB, respectively. These distinct carbon isotope signatures allow us to use δ13C as a natural tracer to detect any potential leakage from the injected coal bed into the overlying monitored zones. In September 2013, the monitored downstream production well in Upper Freeport showed presence of injected CO2 indicating injected CO2 plume had migrated in the coal bed over the entire study area. However, the carbon isotope values observed in the overlying formations indicate no significant leakage of injected CO2 from the underlying Upper Freeport coal bed.

Influence of coupled effect among flaw parameters on strength characteristic of precracked specimen: Application of response surface methodology and fractal method

Hydraulic slotting is an effective method for enhanced coalbed methane (ECBM) recovery, and it has been widely employed in China. Although there have been many studies of this technique, the influence of slot parameters on the strength characteristic of the coal, which is an important factor that affects the permeability enhancement effect, has rarely been studied. Thus, only limited information is available regarding the pressure relief and permeability enhancement mechanisms of this technique. In the current study, the influence of flaw parameters on the compressive strength of a precracked sample under biaxial compression is discussed. The results indicate that an increase in the flaw length and width has a negative effect on the compressive strength, whereas an increase in the flaw inclination angle has a positive effect on the compressive strength. The results of the response surface methodology (RSM) indicate that the interactions among the flaw parameters have a significant influence on the compressive strength. The propagation patterns of cracks are quantified by the fractal dimension, which is used to explore the mechanism of compressive strength variation with changes in the flaw parameters. The study results indicate that the variation in the flaw parameters changes the propagation pattern of cracks, resulting in different compressive strengths. In addition, an opposite variation trend of the compressive strength and fractal dimension with flaw parameters is also observed. The research results are expected to guide the field application of hydraulic slotting.

Investigation on mechanical properties and damage evolution of coal after hydraulic slotting

Hydraulic slotting technique has been widely adopted in China for underground enhanced coal bed methane (ECBM) recovery. However, the related fundamental research of this technique is insufficient enough to get a comprehensive understanding of its action mechanism. In the current work, numerical models of specimens with various flaw inclination angles are built with particle flow code in two dimensions (PFC2D). The relationship between mechanical properties and flaw inclination angle is analyzed, and the results show that (1) with an increase in the flaw inclination angle θ, the peak axial strain appears a decreasing trend after an initial increase and the peak lateral strain decreases gradually. With regard to the peak volumetric strain, when θ < 30°, it is positive, which implies that the specimen is in the state of volume shrinkage. In contrast, when θ > 30°, the peak volumetric strain is negative and the dilatancy occurs. (2) The elastic modulus and the initial damage coefficient show opposite variation trend with θ. Both of the relationships satisfy the Boltzmann function. (3) The peak strength and the initiation stress increase with θ. Furthermore, the damage constitutive equation of specimens with different flaw inclination angles under uniaxial compression is established with the consideration of the initial damage, loading damage, the stress–strain curves and crack number. The theoretical curves match well with the numerical curves and the achievements reported by other authors. The results of this study are expected to provide crucial guidance for the application of hydraulic slotting in ECBM recovery.

Optimization of enhanced coal-bed methane recovery using numerical simulation

Although the enhanced coal-bed methane (ECBM) recovery process is one of the potential coal bed methane production enhancement techniques, the effectiveness of the process is greatly dependent on the seam and the injecting gas properties. This study has therefore aimed to obtain a comprehensive knowledge of all possible major ECBM process-enhancing techniques by developing a novel 3D numerical model by considering a typical coal seam using the COMET 3 reservoir simulator. Interestingly, according to the results of the model, the generally accepted concept that there is greater CBM (coal-bed methane) production enhancement from CO2 injection, compared to the traditional water removal technique, is true only for high CO2 injection pressures. Generally, the ECBM process can be accelerated by using increased CO2 injection pressures and reduced temperatures, which are mainly related to the coal seam pore space expansion and reduced CO2 adsorption capacity, respectively. The model shows the negative influences of increased coal seam depth and moisture content on ECBM process optimization due to the reduced pore space under these conditions. However, the injection pressure plays a dominant role in the process optimization. Although the addition of a small amount of N2 into the injecting CO2 can greatly enhance the methane production process, the safe N2 percentage in the injection gas should be carefully predetermined as it causes early breakthroughs in CO2 and N2 in the methane production well. An increased number of production wells may not have a significant influence on long-term CH4 production (50 years for the selected coal seam), although it significantly enhances short-term CH4 production (10 years for the selected coal seam). Interestingly, increasing the number of injection and production wells may have a negative influence on CBM production due to the coincidence of pressure contours created by each well and the mixing of injected CO2 with CH4.

A novel ECBM extraction technology based on the integration of hydraulic slotting and hydraulic fracturing

Because most coal mines in China have high gas content with low permeability, it is necessary to increase the efficiency of the CBM extracting technology. Enhanced coalbed methane (ECBM) recovery is a suitable option in this regard. This paper demonstrates a novel ECBM extraction technology, which involves the integration of hydraulic slotting (HS) and hydraulic fracturing (HF). The efficiency of the method is evaluated by field test. The slots produced by the HS method are used to control the extension direction of fracture cracks, and the efficiency of CBM extraction from the single drilling is improved by performing slotting drilling in coordination with fracturing drilling. The numerical software Coupled Analysis of Flow and Solid Mechanics in Rock Failure Process Analysis (RFPA2D-Flow) was used to analyse the direction of the crack propagation in the HF process. The coal-crack-propagation process, hydraulic gradient evolution, acoustic emission phenomena, and the change in the stress of coal body with the propagation of the fracturing crack were studied. The results of the study show that because the water pressure around the fracture bore is affected by the slots created, the hydraulic gradient in the horizontal direction is larger than that in the vertical direction, and the cracks more easily extend along the direction of the larger hydraulic gradient following the initiation of the cracks. After HF, a fully unloading area, a transition pressure-relief area, and the original stress area around the fracturing boreholes are formed. Results of the field test show that once the ECBM extraction is completed, the coal-seam disturbance range of the single drilling increases, and the CBM extraction efficiency is significantly improved. This novel ECBM extraction technology is a very promising method for improving the effect of the CBM extraction in the field.

Deformation transition of intact coal induced by gas injection

Gas migration in coal bed is a multiple-physical process, of which not only includes gas desorption/diffusion through coal matrix and gas Darcy flow through the cleat system, but also results in deformation of solid coal. Especially for enhanced coal bed methane (ECBM) and CO2 capture and sequestration (CCS), gas injection is mainly controlled by the gas diffusivity in the coal matrix and coal permeability. Although the relevant coal permeability models have been frequently developed, how the dual-porosity system of coal affects gas adsorption/diffusion is still poorly understood. In this paper, a series of experiments were carried out in order to investigate deformation evolution of intact coal subjected to hydrostatic pressure of different gases (including pure H2, N2 and CO2) under isotherm injection. In the testing process, the coal strain and injected gas pressure were measured simultaneously. The results show that the pressure of non-adsorptive helium remained unchanged throughout the isothermal injection process, in which the volumetric strain of the coal shrinked firstly and maintained unchanged at lower isobaric pressure. With the injected pressure increasing, the coal volume underwent a transition from shrinking to recovery (still less than initial volume of the coal). In contrast, N2 injection caused the coal to shrink firstly and then recover with decreasing gas pressure. The recovery volume was larger than the initial volume due to adsorption-induced swelling. For the case of CO2 injection, although the stronger adsorption effect could result in swelling of the solid coal, the presence of higher gas pressure appears to contribute the swelling coal to shrink. These results indicate that the evolution of coal deformation is time dependent throughout the migration of injected gas. From the mechanical characteristics of poroelastical materials, distribution of pore pressure within the coal is to vary with the gas injection, during which the pore pressure in the cleats will rapidly increase, in contrast, the pore pressure in the matrix will hysteretically elevate. Such a difference on changes of pore pressure between the cleats and the matrix will contribute to the shrinkage of the matrix as a result of initially greater effective stress. Besides, both gas-adsorption-induced swelling and decreasing effective stress also control the coal deformation transition. This work gives us an insight into investigation on influence of effective stress on coal-gas interaction.

The transient behaviour of CO 2 flow with phase transition in injection wells during geological storage – Application to a case study

Abstract This article presents a study on the transient behaviour of CO 2 in wellbores during injection of CO 2 for geological storage or enhanced recovery of oil or gas. To deal with the transient flow equations, we developed a novel modelling scheme that fully includes the storage/inertial terms, and tested the scheme by simulating observations from a field trial of CO 2 enhanced coal bed methane recovery. Because the field trial involved short periods of CO 2 injection, transient thermal and wellbore storage effects played a significant role in the wellbore׳s hydraulics. It was shown that our model׳s simulation presented a satisfactory agreement with the field trial data. A further sensitivity analysis demonstrated the importance of representing wellbore transients. The results and observations from this work include the following. (1) A set of field measurements for low temperature (below −20 °C) carbon dioxide injection is presented, which can serve as an experimental benchmark for verification and validation of theoretical and numerical models. (2) A modelling scheme for transient flows is developed, which shows that for the transient flow concerned the storage /inertia terms in the flow equations must be included and that large errors can result if they are ignored. (3) Unlike a long-term steady injection problem, for short-term injection or at an early stage of injection the thermal exchange between the injecting carbon dioxide and its surroundings is mainly dependent on the thermal scenario in the immediate vicinity of the wellbore, and the geothermal gradient of far-field is less important in this situation. (4) When the injected carbon dioxide is in a two-phase state, the Joule–Thomson coefficient may no longer be the best approach to characterising the dependence of temperature on pressure. Instead, the phase transition and the heat transfer processes may play an equal or a more important role in determining the pressure and the temperature profiles of the fluid within the wellbore.

Kinetics of coal swelling in gases: Influence of gas pressure, gas type and coal type

The increasing interest in enhanced coal bed methane (ECBM) production and reporting of greenhouse gas emissions from mines has spotlighted gas diffusion and gas-induced swelling in coals. Although it is generally agreed that carbon dioxide (CO2) diffuses faster than methane (CH4) in coal and that diffusion rates decline as the pressure is increased, there is no general agreement on the physical mechanism responsible. In this paper kinetic data for sorption-induced swelling for five Australian bituminous coals have been analysed. Gases investigated included CO2 and CH4, Xe and ethane. It was found that swelling rates are influenced by gas type. CH4 swelled coal more slowly than CO2 at the same pressures. Other swelling kinetic data showed that, of the gases investigated, xenon was the slowest, followed by ethane. CO2 swelling was found to be the fastest overall. The swelling rate was found to depend on maceral composition, with the slower-swelling coals being vitrinite-rich. However, the swelling rate of different coals varied differently with increasing pressure: the slowest swelling coal showed an increase in swelling rates with an increase in system pressure, whereas the fastest swelling coals showed a decrease in the swelling rates at high pressures.

The Importance of Baseline Surveys of Near-Surface Gas Geochemistry for CCS Monitoring, as Shown from Onshore Case Studies in Northern and Southern Europe

The monitoring of the integrity of onshore geological carbon capture and storage projects will require an approach that integrates various methods with different spatial and temporal resolutions. One method proven to be quite effective for site assessment, leakage monitoring, and leakage verification is near-surface gas geochemistry, which includes soil gas concentration and gas flux measurements. Anomalous concentrations or fluxes, relative to the natural background values, can indicate the potential occurrence of a leak. However the natural background can be quite variable, especially for CO<sub>2<sub/>, due to biological production and accumulation in the soil that changes as a function of soil type, land use, geology, temperature, water content, and various other parameters. To better understand how these parameters influence natural, near-surface background values, and to examine the potential of different sampling strategies as a function of the survey goals, this paper reports results from two highly different case studies, one from northern Europe (Voulund, Denmark) and one from southern Europe (Sulcis, Sardinia, Italy). The small Voulund site, with its homogeneous soil, climate, and topography, was surveyed twice (in fall and in spring) within the EU-funded SiteChar project to examine the effects of different land use practices and seasons on baseline values. Forested land was found to have lower CO<sub>2<sub/> concentrations during both campaigns compared to cultivated and heath land, and higher CH<sub>4<sub/> values during the spring sampling campaign. Continuous monitoring probes showed much more detail, highlighting seasonal changes in soil gas CO<sub>2<sub/> concentrations linked primarily to temperature variations. The much larger Sulcis site, studied within an ENEA-funded project on potential CO<sub>2<sub/>-ECBM (Enhanced Coal Bed Methane) deployment, was surveyed at the regional scale and on detailed grids and transects for site assessment purposes. Despite the completely different soil and climate conditions, the statistical distribution of the Sulcis data was similar to that of Voulund. Much higher soil gas CO<sub>2<sub/> anomalies were found at this site, however, due to the less permeable sediments (i.e., better water retention and greater gas accumulation) and the warmer temperatures. Detailed surveys at this site highlighted various significant anomalies, some of which can be explained by near surface biological processes, whereas others, especially helium anomalies, were more difficult to explain. These results show the utility of baseline surveys, and highlight the need for follow-up studies to clarify any unexplained anomalies before any CO<sub>2<sub/> storage.

Effect of CO2 injection on heterogeneously permeable coalbed reservoirs

Enhanced coalbed methane (ECBM) can be recovered by injecting a gas such as carbon dioxide into the reservoir to displace methane. The contrast between density, viscosity, and permeability of the resident and displacing fluids affects the efficiency of ECBM recovery. The prediction of earlier breakthrough becomes complex as the permeability may vary by orders of magnitude during gas injection and methane recovery. Predominantly, the reservoir permeability is modulated by the pore pressure of the sorptive gas (CH4 and CO2) and effective stresses. Here we explore the possibility of early breakthrough and its implications for managing coalbed reservoirs during CO2 assisted ECBM. A coupled finite element (FE) model of binary gas flow, diffusion, competitive sorption and permeability change is used to explore the effect of CO2 injection on net recovery, permeability evolution and injectivity in uniform and homogeneously permeable reservoirs. This effect is evaluated in terms of dimensionless pressure (pD), permeability (kD) and fracture spacing (xD) on the recovery of methane and permeability evolution for ECBM and non-ECBM scenarios. We have considered two scenarios (4MPa and 8MPa) of constant pressure injection of CO2 for ECBM. The increase in production rate of CH4 is proportional to kD but inversely proportional to xD.Further, a reservoir with initial permeability heterogeneity was considered to explore the effect of CO2 injection on the evolution of permeability heterogeneity – whether heterogeneity increases or decreases. The evolution of permeability heterogeneity is investigated for the same two CO2 injection scenarios. For the specific parameters selected, the model results demonstrate that: (1) The injection of CO2 in coalbed reservoirs increases the production nearly 10-fold. (2) At higher injection pressures the recovery is rapid and the production increases dramatically – the production increases 2-fold on increasing the CO2 injection pressure from 4MPa to 8MPa. (3) However, CO2 breakthrough occurs earlier at higher injection pressures. (4) The permeability heterogeneity in the reservoir is reduced after a threshold time (∼500days) although the overall heterogeneity is increased relative to the initial condition and is overall increased for both non-CO2 and CO2 injection scenarios. This indicates that the homogenizing influence of CO2-sorption-swelling is outpaced by CH4-desorption-shrinkage and effective stress influences. This leaves the reservoir open to short-circuiting and earlier breakthrough of CO2 rather than having this effect damped-out by the homogenizing influence of swelling. (5) The cumulative volume of CO2 produced and stored in the reservoir is proportional to the injection pressure.

Core flooding experiments of CO2 enhanced coalbed methane recovery

This paper presents the results of CO2 enhanced coal bed methane (ECBM) core floods on intact coal core from the Bowen Basin and the Hunter Valley, Australia, at pore pressures of 4MPa and 10MPa. The core floods involved flooding with CO2 to displace methane from the core and then reversing the flood by injecting methane to displace the CO2 from the previous flood. An important parameter for ECBM is the displacement or sweep efficiency which was estimated directly from the mass balance over the core flood. Displacement efficiencies obtained through CO2 injection were excellent with more than 99% of the CH4 recovered during the core floods. The reverse experiments in which CH4 was injected to displace CO2 were notably less effective with an average of 95% displacement obtained for the Bowen Basin core sample and only 71% displacement obtained for the Hunter Valley core sample by the end of the experiment. History matching was performed with the reservoir simulator SIMED II which used a hydrostatic permeability model, the extended Langmuir model, and a bi-disperse diffusion model. In general, good history matches were obtained between simulated and observed flow rates, mass balances, and breakthrough times demonstrating that the model could accurately represent the ECBM process. It was found that the triple porosity gas diffusion model provided an improved agreement to observations over the unipore model. Connell–Lu–Pan's hydrostatic permeability model was used in the history matching which differentiates between bulk and pore sorption strain. During the CO2 flooding experiments a change in permeability was observed as CO2 displaced CH4 in the core. As the stress conditions were constant, this was the result of the sorption strain impacting on the porosity and thus permeability. However, for the reverse core flood in which CH4 was injected to displace CO2, no permeability changes were observed, implying that pore and bulk strain were the same and thus cancelled out.

Additional Gas Resource for Coal Bed Methane by Applying Underground Coal Gasification and Enhanced Coal Bed Methane

Methane gas obtained from coal sources can be classified into two categories i.e Coal Bed Methane (CBM) and Underground Coal Gasification (UCG) gases. The Industry today often neglects the importance of capturing the UCG as important source of methane potential besides the surface gasification potential. This research will evaluate on the new resource estimation of methane as reserves with application of new technological advances in exploitation. As an analysis, the UCG energy return is significantly higher than that of CBM. Both CBM and UCG output gas can be liquefied, or used as a direct feedstock to local power stations. The CO2 generated from UCG process may be used for Enhanced Coal Bed Methane (ECBM) process because of more adsorption capacity than methane, may lead to additional methane potential. Deeper coal seams may be targeted for CBM, followed by UCG for additional resources in the form of coal gas. A depleted CBM area may be targeted for UCG with some modification on the well profile. Developing an integrated and centrally controlled approach to exploit the coal resources in which, the appropriate extraction methodology should be identified for each particular target coal-seam or groups of coal seam. It is important to strategize the sequencing of energy extraction methods to provide an optimal balance between the energy delivery for sustainable future and its true socio-economic value. As from this analysis, with 245.6 acres of coal, estimated gas can be produced is 3.25 TSCF which is 101 BSCF is coming from CBM, 3.14 TSCF from UCG and another 14.45 BSCF is from ECBM.

A feasibility study of ECBM recovery and CO2 storage for a producing CBM field in Southeast Qinshui Basin, China

This paper presents a geo-engineering and economic analysis of the potential for enhanced coalbed methane (ECBM) recovery and CO2 storage in the South Shizhuang CBM Field, Southeast Qinshui Basin, China. We construct a static model using the well log and laboratory data and then upscale this model to use in dynamic simulations. We history match field water and gas rates using the dynamic model. The parameters varied during the history match include porosity and permeability. Using the history matched dynamic model, we make predictions of CBM and ECBM recoveries for various field developments. We build a techno-economic model that calculates the incremental nominal net present value (NPV) of the ECBM incremental recovery and CO2 storage over the CBM recovery. We analyse how the NPV is affected by well spacing, CH4 price, carbon credit and the type of coal.Our analyses suggest that 300m is the optimum well spacing for the study area under the current CH4 price in China and with a zero carbon credit. Using this well spacing, we predict the recoveries for different injection gas compositions of CO2 and N2 and different injection starting times. The results show that gas injection yields incremental CBM production whatever the composition of the injected gas. Pure CO2 injection yields highest ECBM for low swelling coals while flue gas injection gives highest ECBM for high swelling coals. However, the differences in recoveries are small.Injection can be economically viable depending on the CH4 price and the carbon credit. At current prices and no carbon credit, flue gas injection is commercial. At higher CH4 prices and/or with the introduction of carbon credits, co-optimisation could be commercially viable. High carbon credits favour injecting pure CO2 rather than other gases because this stores more CO2. Injecting CO2 at late stage increases CO2 storage but decreases the project's NPV. High-swelling coals require about $20/tonnes additional carbon credit.

Selection of monitoring techniques for a carbon storage and enhanced coalbed methane recovery pilot test in the Central Appalachian Basin

The goals of monitoring, verification, and accounting (MVA) for carbon capture, utilization, and storage (CCUS) studies include improved understanding of injection and storage processes, evaluation of interactions among carbon dioxide (CO2), reservoir fluids, and formation solids, and assessment and minimization of environmental impacts (DOE and NETL, 2009). Site-specific selection of tools for a well-rounded MVA program may include technologies for atmospheric, near-surface, and subsurface monitoring.An upcoming small-scale CCUS study in an active coalbed methane field in Buchanan County, Virginia, presents a unique application for several established, effective MVA methods. The study will involve injecting up to 20,000tonnes of CO2 into three injection wells over a one-year period in order to test the injection and storage potential of the coal seams and to assess the potential for enhanced coalbed methane (ECBM) recovery at offset production wells. The reservoir consists of approximately 15 to 20 coal seams, averaging 0.3m (1.0ft) in thickness and distributed over 300m (1000ft) of vertical section. This reservoir geometry creates an unusual target for CO2 injection and also a challenging one for many monitoring and imaging techniques. MVA for the Buchanan County test will include gas content measurements at offset wells, groundwater monitoring, injectate tracer analysis, well logging, surface deformation measurement, passive microseismic monitoring, and tomographic fracture imaging. Multiple monitoring wells will be drilled in order to facilitate the MVA efforts. Surface deformation measurement, microseismic monitoring, and tomographic fracture imaging are state-of-the art tools that have potential to define the subsurface CO2 plume beyond the borehole scale. The results of the MVA program for the Buchanan County injection demonstration can be used to improve design for potential future studies of CCUS in thin coals.

Injecting pure N2 and CO2 to coal for enhanced coalbed methane: Experimental observations and numerical simulation

Enhanced coalbed methane (ECBM) core flooding experiments are a direct way to observe the gas displacement process, the competitive adsorption and the effect of coal swelling and shrinkage on coal permeability. This study reports two ECBM experiments. In the first experiment, pure N2 is injected (N2-ECBM) to a coal sample saturated with CH4 while, in the second experiment, pure CO2 is injected (CO2-ECBM) to the same coal sample cleaned and resaturated with CH4. We record the volumes and composition of the effluent gas with respect to time. Then the gas rate and gas composition are history matched using a commercial reservoir simulator. The results show that the breakthrough of N2 occurs earlier than CO2 breakthrough (after approximately 0.1day of injection compared to 0.43day). The recovery factor of CH4 is 71% for the N2-ECBM and 86% for the CO2-ECBM at a 10%-molar percentage of CH4 in the produced gas stream. The N2 injection causes moderate increases in coal permeability whereas the injection of CO2 reduces coal permeability significantly. The maximum strain of CO2 injection is higher at the initial stage of CO2 injection but decreases after several days of injection. The extended Langmuir adsorption model predicts the compositional adsorption amounts of N2 and CH4 better for the N2-ECBM than for the CO2-ECBM. A co-optimisation concept is presented to analyse the coupling of ECBM with CO2 storage which shows that early times CO2 storage efficiency is higher than CH4 recovery efficiency. Later CO2 storage efficiency decreases due to CO2 production and CH4 recovery dominates the co-optimisation.

Competitive adsorption of CO2/CH4 mixture on dry and wet coal from subcritical to supercritical conditions

Enhanced coal bed methane (ECBM) recovery enables captured CO2 to be stored while increasing the recovery of CH4. Competitive adsorption of a CO2/CH4 mixture on dry and wet anthracite coal was studied at 318 and 338K and pressures up to 13MPa and was compared with the adsorption behavior of pure CO2 and CH4. The negative excess adsorbed amounts of CH4 in the CO2/CH4 mixture were observed in both dry and wet coal due to the high selectivity of CO2 on coal. Therefore, the total excess adsorbed amount and isotherm shape of mixture on dry and wet coal were similar to the results of pure CO2. The moisture of the coal reduced the sorption amount compared to dry coal in the mixture system, showing a similar moisture effect on the isotherm of pure CO2 in the same range of fluid density. Above the critical point of CO2, the sorption difference between dry and wet coal decreased with an increase in pressure. The fluid density of a mixture in free volume was an important variable to estimate the ECBM recovery efficiently because the sorption behavior of the CO2/CH4 mixture was similar to that of pure CO2 based on the same density condition.