Enhanced Coalbed Methane Research Articles

A study of laboratory testing and calculation methods for coal sorption isotherms

Measurement of the volume of gas adsorbed per unit mass of coal with increasing pressure at a constant temperature produces an isotherm that describes the gas storage capacity of this type of coal. The accurate testing and interpretation of coal sorption isotherm plays an important role in the areas of coal mine methane drainage, coalbed methane (CBM) reservoir resource assessment, enhanced coalbed methane (ECBM) recovery, as well as the carbon dioxide (CO2) sequestration in deep coal seams or similar geological formations. Different coal sorption isotherm testing apparatus and associated calculation methods are critically reviewed and presented in this paper. These include both volumetric and gravimetric based methods, as well as experimental sorption tests with confining stress and direction sorption methods. The volumetric techniques utilise experimental apparatus with sample cell and injection pump and that with both sample cell and reference cell. Whilst the gravimetric approachesinclude methods with sample cell and suspension magnetic balance and that with both sample cell and reference cell. Different testing methods are compared and discussed in this study. A unique in-house-built coal sorption isotherm testing apparatus at the University of Wollongong was presented together with the calculation method, procedures and experimental results. The isotherm results can be calculated by both Soave-Redlich-Kwong (SRK) equation and calibration cure methods which can be used directly to convert the volume of adsorbed gas in different test conditions to standard condition (NTP).

Classification of coal seams for coal bed methane exploitation in central part of Jharia coalfield, India – A statistical approach

Laboratory analyses data of coal core samples and coal seam characteristics, derived from well logs, have been used for quantitative analysis of proximate and petrophysical parameters of coals to assess the potential of coal bed methane (CBM) reservoir as clean energy source in central part of Jharia coalfield, India. Coal core samples and well log data of 27 exploratory wells have been used for this analysis. Coal seam permeability data for 14 major coal seams, obtained from shallow resistivity log, varies from 0.60md to 1.25md. Gas content values, calculated from available empirical equation varies from 11.11cc/g to 11.91cc/g. Hierarchical Cluster Analysis (HCA) has been applied to group the 14 coal seams of the study area based on these above mentioned parameters for quantitative assessment of CBM potentiality of coal seams. Based on this HCA, the total 14 numbers of coal seams/objects occurring within the depth intervals of 214.58–1345.05m have been classified into three categories in order of potentiality as CBM reservoir depending upon average coal seam permeability and average gas content. The data set, generated from the experimental work and assessment of CBM potentiality, may further be used in the investigations for enhanced CBM (ECBM) recovery with CO2 sequestration into coal beds in the Jharia coalfield.

CO2 Injectivity in a Multi-lateral Horizontal Well in a Low Permeability Coal Seam: Results from a Field Trial

Enhanced coalbed methane (ECBM) production by CO2 injection offers the potential of increasing recovery of the gas in place over primary recovery methods and at the same time storing CO2. A field ECBM trial via CO2 storage has been carried out in the east margin of the Ordos Basin, Shanxi province, China. A unique aspect of the trial was using a multi-lateral horizontal well, which was clearly beneficial for production or injection for low permeability formations. This paper described a reservoir model constructed to simulate the CO2 injection behaviour using the coal seam reservoir simulator SIMED II. The simulation work included history matching the bottomhole pressure while using injection rate as control. A complexity in the modelling was representation of the multi-lateral horizontal well as its branches were not aligned with x or y coordinates. Thus approximation was taken to represent the well in the model. The simulation result showed good match for some data but could not match well the whole range of data, suggesting possible well opening or closing to flow during injection and shut-in periods. It has been suggested that the permeability decrease due to gas adsorption induced coal swelling may play an important role in the gas flow behaviour, especially near the wellbore where the amount of CO2 adsorbed was highest. However, due to the coarse grid size applied in this finite difference model and the difficulty to refine them near the well branches while maintaining overall size of the model, the permeability loss due to adsorption induced coal swelling was diluted by the relatively large grid size. Thus this may not accurately reflect the permeability change and the quality of the history matching results are affected. A suggestion is to use refined grid blocks near wellbore to examine the impact of swelling on the overall CO2 flow behaviour for this project.

Description of a CO2 Enhanced Coal Bed Methane Field Trial Using a Multi-Lateral Horizontal Well

Enhanced recovery of coal bed methane by CO2 injection (CO2-ECBM) offers the potential of increasing recovery of the gas in place over primary recovery methods and at the same time storing CO2. This paper describes a CO2-ECBM field trial using a multi-lateral horizontal well for injection. The trial, preforemed in China's Ordos basin, involved transport of liquid CO2 to the injection site and pumping of this directly into the injection well. A u-tube sampling system was installed in a monitoring well approximately 20m from the main horizontal branch close to the vertical section of the injection well. This u-tube system comprised three intervals separated by inflatable packers from which gas and water samples were automatically collected and recovered to an on-site field laboratory for gas analysis. The middle interval of this packer assembly sampled the target coal seam. At the start of injection a pulse of a non- adsorbing tracer gas was added to the CO2. There was clear breakthrough of the tracer in the middle packer interval of the monitoring well demonstrating the good connection between injection and monitoring wells. The CO2 composition of the gas sample from the coal seam gradually increased over time as injected CO2 migrated to the monitoring well. Some significant aspects of this trial are the use of a multi-lateral horizontal well for ECBM, tracer gas in coal bed methane, the monitoring of gas displacement during ECBM and the u-tube sampling system.

A Field Study on Simulation of CO2 Injection and ECBM Production and Prediction of CO2 Storage Capacity in Unmineable Coal Seam

CO2 sequestration into a coal seam project was studied and a numerical model was developed in this paper to simulate the primary and secondary coal bed methane production (CBM/ECBM) and carbon dioxide (CO2) injection. The key geological and reservoir parameters, which are germane to driving enhanced coal bed methane (ECBM) and CO2 sequestration processes, including cleat permeability, cleat porosity, CH4 adsorption time, CO2 adsorption time, CH4 Langmuir isotherm, CO2 Langmuir isotherm, and Palmer and Mansoori parameters, have been analyzed within a reasonable range. The model simulation results showed good matches for both CBM/ECBM production and CO2 injection compared with the field data. The history-matched model was used to estimate the total CO2 sequestration capacity in the field. The model forecast showed that the total CO2 injection capacity in the coal seam could be 22,817 tons, which is in agreement with the initial estimations based on the Langmuir isotherm experiment. Total CO2 injected in the first three years was 2,600 tons, which according to the model has increased methane recovery (due to ECBM) by 6,700 scf/d.

Numerical modeling of Gondwana coal seams in India as coalbed methane reservoirs substituted for carbon dioxide sequestration

India has recently witnessed the production of coalbed methane (CBM) on a commercial scale. The analysis of Garg and Shukla (2009) summarizes that initial carbon dioxide storage opportunities should be ventured in CBM sector where the effective cost of the process is partly lowered due to enhanced recovery of methane. This research work was carried out to understand and establish the technical feasibility of CO2 driven enhanced CBM recovery in Indian coals. A regional scale underground coal seam/block was modeled using a commercial reservoir simulator, COMET3. It was found that approximately 218 Mm3 of CO2 can be sequestered in place of 74 Mm3 of CH4 produced from the chosen dimensions of coal block. The changes in fracture gas saturation, matrix CO2 concentration and matrix CH4 concentration with space and time were monitored. Eventually, the numerical values for peak saturation at certain time intervals have been reported. This study is an initial technical estimate for CO2 driven ECBM (enhanced coalbed methane) at a regional scale in India. The results are expected to prove useful not only to reduce India's contribution to greenhouse gases emission into the atmosphere but also to partially meet with the growing energy demand by enhanced recovery of methane from deep, unminable coal seams.

Water production in enhanced coalbed methane operations

Coalbed methane (CBM) formations provides a considerable amount of the US natural gas production and have the potential of storing significant amounts of carbon dioxide (CO2) through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of CO2 or a mixture of CO2 and nitrogen (N2) has been proven to recover additional natural gas resources. However, since coalbeds are normally saturated with water and can be in communication with an aquifer, a large amount of water is often co-produced during the natural gas extraction.The conventional approach for CBM production relies on the reduction of the gas partial pressure in the coal seam. This can be accomplished by either pumping the formation water to the surface and/or by injecting gases such as N2 and CO2. Disposal of the produced water is an environmental challenge as harmful impurities must be removed by appropriate purification techniques. Consequently, a reduction of water production in CBM operations is desirable.In this paper we present a numerical investigation of the potential reduction in water production during ECBM operations that are commonly used to increase methane (CH4) recovery. We use a three-dimensional coalbed model with an aquifer located at the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength and sorption characteristics including sorption induced strain. The amount of gas/water that is produced varies significantly depending on the aquifer strength and injection gas composition. We demonstrate that injection of CO2 and/or N2 in some settings reduces the water handling problem substantially.CBM is an important worldwide energy source with a large number of formations being excellent candidates for ECBM recovery processes. Our analysis of the interplay between coal characteristics, aquifer support and the resultant behavior in terms of gas/water production provides valuable input for optimization of future planning and operations.

Relationships between the sorption behaviour of methane, carbon dioxide, nitrogen and ethane on coals

Sequestration of carbon dioxide in coal seams can reduce emissions of carbon dioxide to the atmosphere. If such sequestration simultaneously results in enhanced coal bed methane (ECBM) production, some of the sequestration costs can be recovered by the value of the methane produced. This requires knowledge of both the carbon dioxide and methane sorption behaviour of coal at high pressures. In order to elucidate the connection between them, we investigated the sorption of carbon dioxide, methane, ethane and nitrogen at 55°C at pressures up to 20MPa for a number of coals. Sorption isotherms were fitted by a modified Dubinin–Radushkevich model. The maximum sorption capacities of the coals for the different gases were found to be highly correlated. The relationship between maximum sorption capacity of a coal for a gas and its critical temperature was approximately proportional. The relationship between methane and nitrogen maximum sorption capacity was particularly close: on a volume basis, the maximum sorption capacity of all coals examined for methane was twice that of nitrogen. The ratio of maximum sorption capacity of carbon dioxide and methane decreased linearly with increasing carbon content. The ethane/methane sorption ratio also tended to decrease with increasing rank though to a smaller extent, indicating that the proportionally greater sorption at low rank coals is not unique to carbon dioxide. The heat of sorption tends to increase with increasing vitrinite reflectance; this may reflect the greater polarisability of higher rank coals (which also determines their reflectance).

Microfracturing of coal due to interaction with CO2 under unconfined conditions

Laboratory experiments conducted in the past century have shown that exposure of coal to CO2 under unconfined, hydrostatic conditions leads to reversible adsorption and swelling. However, several authors also report irreversible changes in sorption capacity, sample volume, equilibration time and brittle failure strength. Some relate these effects to the formation of microfractures, while others consider “structural rearrangements” in the macromolecular structure of coal to be responsible. In this study, we investigate the magnitude of irreversible swelling effects and changes in equilibration time in high volatile bituminous coal (Brzeszcze, Seam 364, Poland), and attempt to explain the results in terms of the operative microphysical processes. We also assess the implications for Enhanced Coalbed Methane (ECBM) operations. Our approach involves detailed dilatometry experiments conducted on fresh, unconfined, mm-scale coal matrix cylinders at CO2 pressures up to 100MPa, and at 40.0°C. Exposure of our samples to CO2 produced reversible and irreversible strains resulting predominantly from competition between adsorption-induced swelling and elastic compression. During the first or second cycle of exposure, substantial hysteresis was observed in volumetric behaviour, notably at CO2 pressures above 35–40MPa. After two or three upward and downward CO2 pressure cycles, the measured strain response became fully reversible. Equilibration with CO2 took about four times longer during the first CO2 pressurisation cycle than in subsequent CO2 pressurisation cycles. Microstructural analysis and comparison showed that microfractures formed in the coal during first exposure to CO2. From the microstructural and mechanical data, we infer that microfracturing was responsible for enhanced CO2 penetration into the present samples. This, in turn allowed more homogeneous access of CO2, and caused adsorption-induced swelling of matrix material not previously accessed by CO2. We further infer that the enhanced penetration, sorption and swelling, in turn, resulted in the observed hysteresis in dimensional response and in the decrease in equilibration time seen in subsequent exposure cycles. Since most microfractures developed parallel to the bedding, roughly following maceral–maceral and bedding/layer interfaces, and because the largest permanent strains and strain hysteresis were measured perpendicular to the bedding, we infer that the formation of microfractures was caused by heterogeneous swelling, in combination with differential accessibility of the coal microstructure. No evidence was found that CO2-induced plasticisation of the macromolecular structure of the coal matrix played any role in the behaviour observed. Simple mechanical considerations indicate that at in situ stresses corresponding to a depth of 1000–1500m, i.e. effective stresses in the range 25–35MPa, adsorption-induced microfractures are unlikely to form. This means that improved access of CO2 to coal matrix material for ECBM production can probably be achieved only by inducing damage into coal seams, either by injection of solvents/solutes, or by performing active mining of the coal and/or the over- or underlying strata.

Seal evaluation and confinement screening criteria for beneficial carbon dioxide storage with enhanced coal bed methane recovery in the Pocahontas Basin, Virginia

The geological storage of carbon dioxide in Appalachian basin coal seams is one possible sink for sequestration of greenhouse gases, with the added benefit of enhanced-coal bed methane (ECBM) recovery. The Pocahontas Basin (part of the central Appalachian Basin) of southwestern Virginia is a major coal bed methane (CBM) province with production mostly from coal beds in the Lower Pennsylvanian Pocahontas and New River formations. As part of the Southeast Regional Carbon Sequestration Partnership's Phase II research program, a CO2-injection demonstration well was installed into Lower Pennsylvanian coal bed-methane producing strata in southwest Virginia. Samples of siliciclastic lithologies above coal beds in this Oakwood Field well, and from several other cores in the Nora Field were taken to establish a baseline of the basic confinement properties of overlying strata to test seal competency at local and regional scales. Strata above CBM-producing coal beds in the Pocahontas and New River formations consist of dark-gray shales; silty gray shales; heterolithic siltstones, sandstones, and shales; lithic sandstones, and quartzose sandstones. Standard measurements of porosity, permeability and petrography were used to evaluate potential leakage hazards and any possible secondary storage potential for typical lithologies. Both lithic- and quartz-rich sandstones exhibit only minor porosity, with generally low permeability (< 0.042 mD). Interconnected porosity and permeability are strongly impacted by diverse cementation types and compaction. Analyzed siliciclastic lithologies are considered tight, with limited primary matrix permeability risks for leakage, providing an ensemble of redundant CO2-ECBM traps. One of the most promising confining intervals above the major coal bed-methane producing interval is the Hensley Shale Member. Analyses of 1500 geophysical logs in southwest Virginia indicate that this unit is moderately thick (> 50 ft, 15 m), laterally continuous (> 3000 km2), and a homogenous shale, which coarsens upward into siltstone and sandstone, or is truncated by sandstone. Calculations from two mercury injection capillary porosimetry tests of the shale indicate that a displacement entry pressure of 207 psi (1427 kPa) would generate an estimated seal capacity of 1365 ft (416 m) of CO2 before buoyant leakage. Scanning electron microscopy indicates a microfabric of narrow pore throats between quartz grains floating in a clay matrix. Modeled median pore throat size between micro-fabric matrix grains for the shale is estimated at 0.26 μm. These characteristics indicate that the shale, where fractures and joints are limited, would be an adequate regional confining interval for deeper CO2 storage with ECBM.

Adequacy of equation of state models for determination of adsorption of gas mixtures in a manometric set up

Abstract In Enhanced Coal Bed Methane (ECBM) usually CO 2 mixtures containing impurities such as NO x , etc., are injected in the coal layer. This paper investigates the adequacy of different Equations of State (EoS) for the determination of adsorption of gas mixtures in a manometric set up. We investigate the viability of these EoS by performing experiments in a reference cell and an empty sample cell at a constant temperature of 318.15 K. From these measurements we derive the volume ratio of these cells. We used a variety of EoS and mixing rules to validate whether they can be applied, i.e., lead to the correct volume ratio. It is shown that for a He rich mixture (98% He, 1% O 2 and 1% NO 2 ) it is possible to use the McCarty EoS for pure helium for this purpose but that none of the other EoS, including mixing rules, give acceptable results. For a CO 2 rich mixture (97% CO 2 , 1% He, 1% O 2 and 1% NO 2 ) none of the investigated EoS and mixing rules can be applied. Therefore, we present an experimental stepwise procedure based on the volume ratio measurements, to obtain correct density values with an error between 0.033% for high densities to 0.85% for low densities.

History matching of enhanced coal bed methane laboratory core flood tests

Abstract Enhanced coalbed methane (ECBM) involves the injection of a gas, such as nitrogen or carbon dioxide, into the coal reservoir to displace the methane present. Potentially this strategy can offer greater recovery of the coal seam methane and higher rates of recovery due to pressure maintenance of the reservoir. While reservoir simulation forms an important part of the planning and assessment of ECBM, a key question is the accuracy of existing approaches to characterising and representing the gas migration process. Laboratory core flooding allows the gas displacement process to be investigated on intact coal core samples under conditions analogous to those in the reservoir. In this paper a series of enhanced drainage core floods are presented and history matched using an established coal seam gas reservoir simulator, SIMED II. The core floods were performed at two pore pressures, 2 MPa and 10 MPa, and involve either nitrogen or flue gas (90% nitrogen and 10% CO2) flooding of core samples initially saturated with methane. At the end of the nitrogen floods the core flood was reversed by flooding with methane to investigate the potential for hysteresis in the gas displacement process. Prior to the core flooding an independent characterisation programme was performed on the core sample where the adsorption isotherm, swelling with gas adsorption, cleat compressibility and geomechanical properties were measured. This information was used in the history matching of the core floods; the properties adjusted in the history matching were related to the affect of sorption strain on coal permeability and the transfer of gas between cleat and matrix. Excellent agreement was obtained between simulated and observed gas rates, breakthrough times and total mass balances for the nitrogen/methane floods. It was found that a triple porosity model improved the agreement with observed gas migration over the standard dual porosity Warren–Root model. The Connell, Lu and Pan hydrostatic permeability model was used in the simulations and improved history match results by representing the contrast between pore and bulk sorption strains for the 10 MPa cases but this effect was not apparent for the 2 MPa cases. There were significant differences between the simulations and observations for CO2 flow rates and mass balances for the flue gas core floods. A possible explanation for these results could be that there may be inaccuracy in the representation of mixed gas adsorption using the extended Langmuir adsorption model.

A model for enhanced coal bed methane recovery aimed at carbon dioxide storage

Numerical simulations on the performance of CO2 storage and enhanced coal bed methane (ECBM) recovery in coal beds are presented. For the calculations, a one-dimensional mathematical model is used consisting of mass balances describing gas flow and sorption, and a geomechanical relationship to account for porosity and permeability changes during injection. Important insights are obtained regarding the gas flow dynamics during displacement and the effects of sorption and swelling on the ECBM operation. In particular, initial faster CH4 recovery is obtained when N2 is added to the injected mixture, whereas pure CO2 allows for a more effective displacement in terms of total CH4 recovery. Moreover, it is shown that coal swelling dramatically affects the gas injectivity, as the closing of the fractures associated with it strongly reduces coal’s permeability. As a matter of fact, injection of flue gas might represent a useful option to limit this problem.

Adsorption characteristics of CO 2 and CH 4 on dry and wet coal from subcritical to supercritical conditions

Enhanced coal bed methane (ECBM) recovery has been proposed as an attractive way to store captured CO 2 while recovering CH 4. The adsorption and desorption behaviors of CO 2 and CH 4 on dry and wet coal (anthracite) were studied at 318 and 338 K and up to 150 atm. The sorption capacity of CO 2 and CH 4 on anthracite coal was higher at lower temperatures and dry coal condition, but smaller than those on bituminous coals at a similar condition. In wet coal, the sorption capacity and stability of high pressure CO 2 stored at 318 K could be lower than those at 338 K in the supercritical region because higher density of CO 2 at 318 K could lead to the structural change of wet coal. The difference in the excess adsorbed amount between dry and wet coal was only noticeable under the subcritical conditions at 338 K but became more significant under the supercritical conditions with pressure at 318 K. In dry and wet coal, the CO 2 desorption isotherms had different shapes, depending on temperature, but all the CH 4 desorption isotherms showed a weak positive hysteresis. The mutual solubility between the CO 2-rich (or CH 4-rich) phase and aqueous phase as well as coal swelling should be considered in evaluating the sorption capacity of a wet coal seam. Fluid density in free volume was the important variable to estimate the CO 2 storage capacity or ECBM recovery because the density variation significantly influenced the isotherm shape.

Swelling of moist coal in carbon dioxide and methane

Abstract Determining the feasibility of injecting CO2 into coal seams for enhanced coalbed methane (ECBM) recovery as well as providing long-term carbon sequestration is an active area of research. It is now well known that coal swells in the presence of water and gases, which in turn may affect its in-seam permeability. If the swelling of the coal matrix by each component can be quantified, it may be possible to make better predictions about the suitability of particular seams for ECBM and carbon sequestration. Despite numerous studies where coal swelling has been measured in gases or water, there is relatively little information relating to how swelling of coals by gases is affected by water. In this paper we report on the gas-induced swelling behaviour of four moist Australian coals. Blocks of coal, nominally 30 × 9 × 9 mm, were cut parallel and perpendicular to the bedding plane from larger lumps. Samples were moisture-equilibrated at 97% relative humidity before being exposed to CO2 or CH4 at pressures up to 16 MPa and a temperature of 55 °C. Swelling of each sample was measured directly using digital cameras to monitor the change in length of the block as a function of pressure. Results show that swelling was greater in CO2 than CH4, with lower rank coals swelling more than high rank material. The presence of moisture significantly reduced the amount of additional swelling by the gas compared to dry coals; however, the degree to which the swelling of the coals was affected by moisture depended on the rank of the coal. It was also found that, proportionally, CH4-induced swelling was more affected by the presence of moisture than CO2-induced swelling. Although moist coals swelled less in CO2 or CH4 than dry coals, if the swelling due to moisture is included, the total swelling is more than that induced by the corresponding gas in the dry coal.

Coal characterization for ECBM recovery: Gas sorption under dry and humid conditions, and its effect on displacement dynamics

Enhanced Coal Bed Methane (ECBM) recovery is a technique under investigation as a possible approach to the geological storage of CO2 in a carbon dioxide capture and storage (CCS) system. This technology allows enhancing the recovery of coal bed methane by injecting CO2 in the coal seam at supercritical conditions. Through an in situ sorption/desorption process the displaced methane is produced and the adsorbed CO2 is permanently stored. In the case of coal, the uptake of CO2, CH4 and N2 is a combination of adsorption on its surface and penetration (absorption) into its solid matrix, the latter resulting in coal’s swelling. These two processes act simultaneously, making the coal a challenging material to be studied, in particular with respect to the understanding of the fundamental aspects of gas adsorption. High pressure sorption data of CO2, CH4 and N2 on a coal sample from Australia are presented; the interpretation of the experimental data takes into account the dual nature of the sorption process and a Langmuir-like model is applied to the sorption data, by fitting the isotherm parameters to the experimental values. The results confirm that this equation is a valuable option to describe gas sorption on coal. Moreover, a one-dimensional mathematical model previously derived is used to perform numerical simulations on the performance of ECBM recovery in coal beds. Important insights are obtained regarding the gas flow dynamics during displacement and the effects of gas sorption on the ECBM operation.

Riemann problem for one-dimensional binary gas enhanced coalbed methane process

With an extended Langmuir isotherm, a Riemann problem for one-dimensional binary gas enhanced coalbed methane (ECBM) process is investigated. A new analytical solution to the Riemann problem, based on the method of characteristics, is developed by introducing a gas selectivity ratio representing the gas relative sorption affinity. The influence of gas selectivity ratio on the enhanced coalbed methane processes is identified.

High-pressure methane and carbon dioxide sorption on coal and shale samples from the Paraná Basin, Brazil

An experimental study has been conducted to assess the potential for coalbed methane production and carbon dioxide storage in coals, carbonaceous shales and source rocks in the Paraná Basin in Brazil. High-pressure sorption tests with methane and carbon dioxide were performed on coal and carbonaceous shales from the Santa Terezinha Coalfield and samples from two principal petroleum source rocks. Measured excess sorption capacities ranged from 0.03 to 0.47 mmol/g for methane and 0.14 to 0.81 mmol/g for carbon dioxide, showing a decrease with decreasing organic matter content. Linear regression lines for methane sorption capacity vs. TOC extrapolated to approximately zero, whereas for carbon dioxide the intercept of the regression line indicated a residual sorption capacity of ~ 0.2 mmol/g on the mineral matter. Present-day gas contents of coals collected from the first CBM well in the Santa Terezinha Coalfield correspond to 13–38% of the measured maximum sorption capacities. Carbon dioxide sorption capacities exceed methane sorption capacities by a factor of 1.9 to 6.9 for these coals. Free sorption capacities of the under-saturated coals in combination with preferential sorption of carbon dioxide could favour CO 2 -enhanced methane recovery and CO 2 storage in coals and shales of the study area. Based upon the calculated coal reserves, gas contents and measured sorption capacities, a total storage potential of 15.4 Gt CO 2 was estimated for an area of 20 × 40 km 2 in the Santa Terezinha coal field, assuming a combined CO 2 enhanced coalbed methane (ECBM) production and CO 2 storage operation. To fully evaluate the potential for carbon dioxide storage and coalbed methane production, further studies are required to assess producibility of methane and efficiency of long-term CO 2 storage in the study area. ►CH 4 and CO 2 sorption measured on coal from first CBM well in Paraná Basin, Brazil. ►Sorption capacity up to 0.47 mmol/g for CH 4 and up to 0.81 mmol/g for CO 2 . ►Significant CO 2 sorption on mineral matter of high-ash coal and shale. ►CO 2 storage potential estimated to be up to 15.4 Gt in 20 × 20 km 2 study area.

Swelling of Coals by Supercritical Gases and Its Relationship to Sorption

If CO2 can be sequestered in coal seams while simultaneously displacing coalbed methane [enhanced coalbed methane (ECBM)], some of the sequestration costs can be recovered through the production of...

CO 2 sequestration in coals and enhanced coalbed methane recovery: New numerical approach

Mixed gases injection into a large coal sample for CO 2 sequestration in coals and enhanced coalbed methane recovery was investigated using a new numerical approach. A dynamic multi-component transport (DMCT) model was applied to simulate ternary gas (CH 4–CO 2–N 2) diffusion and flow behaviors for better understanding and prediction of gas injection enhanced coalbed methane (ECBM) recovery processes. Several cases were designed to analyze the effects of injection gas composition and pressure on gas displacement dynamics in a large coal sample. The calculated results suggest that mixed gas injections have similar profiles of methane recovery as pure N 2 injection, and mixtures of N 2 and CO 2 reduce the ultimate methane recovery compared to pure CO 2. The breakthrough time of pure CO 2 injection is longer than mixed gas injections. Injection gas composition has significant effect on produced gas composition.