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Field trials of nitrogen injection enhanced gas drainage in hard-to-drain coal seam by using underground in-seam (UIS) boreholes
Abstract
Three stages of nitrogen (N2) injection enhanced gas drainage through underground in-seam boreholes were carried out in a coal mine located in the southern Sydney basin. Due to the high CO2 content and low permeability, hard-to-drain coals were encountered during the excavation process in this coal mine. Two parallel in-seam boreholes (the length of 36 m, the diameter of 96 mm and the borehole space of 5 m) were drilled on the rib of the gateroad. A total of ten-cylinder packs of nitrogen (approximately 1500 m³) were injected into the coal seam. Different nitrogen injection pressures (150 KPa, 250 KPa, 350 KPa and 450 KPa) and injection methods (continuous injection and cyclic injection) were employed. Gas flow rates and gas compositions from the production borehole were recorded during and after the nitrogen injection process. It was observed that gas breakthrough was tightly related to the nitrogen injection pressure. The higher injection pressure was, the shorter breakthrough time was. Specifically, no gas breakthrough was obtained when the injection pressure was 150 KPa. The minimum of breakthrough time was 35 min when 450 KPa’s injection pressure was employed. Strong post-injection effect was monitored after each stage of injection and it was affected by the volume of the injected nitrogen. Under the current injection conditions, the performances of different injection methods were like each other, which was out of our expectation. After the injections, the results of cores showed that less than 5 % of the total injected nitrogen was remained in the coal seam. The coal seam gas content dropped 0.99–1.65 m³/t after these three stages of injection. All these findings provide implications and guidance not only for laboratory experiment and numerical modelling, but also for the field application of this new technology.
... reduces the oxygen content in the space and stops the combustion of combustibles, thus preventing and extinguishing the fire. The mechanism of nitrogen fire prevention and extinguishing is mainly based on oxidation (Bobo and Fubao, 2014), spontaneous combustion, and combustion of combustibles in coal, which can create an inert and flame-retardant effect (Zhao and Wang, 2007;Dong et al., 2011;Lin et al., 2022), suppressing explosions. Injecting inert gas has several advantages, such as permeating the entire fire area to eliminate potential ignition sources, preventing re-ignition, and reducing the oxygen concentration in the fire area to suppress gas explosions (Zhao and Xue, 2012;Christopher, 2013;Deming et al., 2014;Wang et al., 2017). ...
Fires formed by the high gas protrusion in coal mines are difficult and risky to extinguish during the mine closure process due to the mine’s large closed range and underground gas stock. To achieve efficient and safe unsealing, reduce the risk of re-ignition and gas explosion, and accurately determine the fire extinguishing effect, a dual-drive rapid fire extinguishing technology is proposed. This technology involves ground precise positioning of drilling holes, rapid and large flow of liquid nitrogen injection, and curtain grouting to block fires in ultra-large high-gas mines. The practical results demonstrate that the implementation of surface injection of liquid nitrogen for fire extinguishing and cooling, and plugging effectively reduces the concentration of CO in the underground space from 230 PPm to 0 PPm, and decreases the CH4 concentration content from 90% to less than 0.75%. The fire extinguishing and cooling effect is fast and significant. A technical scheme for unsealing the fire area of the whole mine is formulated on a large scale based on the state of pumping and releasing pressure in the closed space of the mine. This scheme has important guiding significance for safety rescue and rescue operations after serious fire accidents occur in similar high-gas prominent mines.
... This can lead to exceeding gas limits and adversely impact the normal production of the mine. Therefore, reducing the residual gas content is crucial to mitigate the potential hazards of gas explosions and prevent coal seam gas accumulations in tailgate or air return ways (Lin et al. 2022a). ...
The gas content is crucial for evaluating coal and gas outburst potential in underground coal mining. This study focuses on investigating the in-situ coal seam gas content and gas sorption capacity in a representative coal seam with multiple sections (A1, A2, and A3) in the Sydney basin, where the CO 2 composition exceeds 90%. The fast direct desorption method and associated devices were described in detail and employed to measure the in-situ gas components ( Q 1 , Q 2 , and Q 3 ) of the coal seam. The results show that in-situ total gas content ( Q T ) ranges from 9.48 m ³ /t for the A2 section to 14.80 m ³ /t for the A3 section, surpassing the Level 2 outburst threshold limit value, thereby necessitating gas drainage measures. Among the gas components, Q 2 demonstrates the highest contribution to Q T , ranging between 55% and 70%. Furthermore, high-pressure isothermal gas sorption experiments were conducted on coal samples from each seam section to explore their gas sorption capacity. The Langmuir model accurately characterizes CO 2 sorption behavior, with fit coefficients ( R ² ) greater than 0.99. Strong positive correlations are observed between in-situ gas content and Langmuir volume, as well as between residual gas content ( Q 3 ) and sorption hysteresis. Notably, the A3 seam section is proved to have a higher outburst propensity due to its higher Q 1 and Q 2 gas contents, lower sorption hysteresis, and reduced coal toughness f value. The insights derived from the study can contribute to the development of effective gas management strategies and enhance the safety and efficiency of coal mining operations.
Outburst of coal and gas represents a significant risk to the health and safety of mine personnel working in development and longwall production face areas. There have been over 878 outburst events recorded in twenty-two Australian underground coal mines. Most outburst incidents have been associated with abnormal geological conditions.
Details of Australian outburst incidents and mining experience in conditions where gas content was above current threshold levels are presented and discussed. Mining experience suggests that for gas content below 9.0 m³/t, mining in carbon dioxide (CO2) rich seam gas conditions does not pose a greater risk of outburst than mining in CH4 rich seam gas conditions. Mining experience also suggests that where no abnormal geological structures are present that mining in areas with gas content greater than the current accepted threshold levels can be undertaken with no discernible increase in outburst risk. The current approach to determining gas content threshold limits in Australian mines has been effective in preventing injury from outburst, however operational experience suggests the current method is overly conservative and in some cases the threshold limits are low to the point that they provide no significant reduction in outburst risk. Other factors that affect outburst risk, such as gas pressure, coal toughness and stress and geological structures are presently not incorporated into outburst threshold limits adopted in Australian mines. These factors and the development of an outburst risk index applicable to Australian underground coal mining conditions are the subject of ongoing research.
Coal seam with low permeability is widely distributed in China. Injection of flue gas (N2:CO2 = 0.85:0.15) is an effective approach to improve coal seam gas drainage efficiency. This process relates complex responses among ternary gases (CH4, CO2, and N2) competitive sorption on coals, gas diffusion, gas‐water migration by means of two‐phase flow, and coal deformation. In this paper, an improved hydraulic‐mechanical model coupling above interactions is established for flue gas injection enhanced gas drainage. This model is used to simulate flue gas enhanced drainage by finite element method. The sensitivity analyses of key factors are made to recovery a better understanding on the processes controlling flue gas enhanced drainage. Results show that the flue gas enhanced drainage can indeed improve the efficiency of gas extraction and reduce the gas pressure to the required value in a shorter duration. Due to the competitive adsorption and gas sweeping effect of injected flue gas, CH4 is driven toward drainage borehole, and CH4 pressure and content near the injection borehole decrease faster than that near the drainage borehole. The peak CH4 pressure laterally moves from the injection borehole to the drainage borehole. Higher injection pressure, initial permeability, and smaller sorption affinity ratios may lead to greater CH4 production rate at early drainage stage, but smaller CH4 production rate at late stage. The factors controlling the behavior of flue gas enhanced drainage are initial permeability, injection pressure, and sorption affinity ratios in order. This work offers useful framework to investigate important technical challenges associated with enhanced mine gas drainage, as well as unconventional gas development.
Carbon dioxide (CO2) enhanced coalbed methane (ECBM) is an effective method to improve methane (CH4) production and this technology has already been used to increase gas production in several field trials worldwide. One major problem is the injection drop in the later period due to permeability decrease caused by coal matrix swelling induced by CO2 injection. In order to quantify the swelling effect, in this work, coal samples were collected from the Bulli coal seam, Sydney Basin and adsorption tests with simultaneous matrix swelling measurement were conducted. The adsorption and swelling characteristics were analyzed by measuring the adsorption mass simultaneously with the strain measurement. Then experiments were conducted to replicate the ECBM process using the indirect gravity method to obtain the swelling strain change with CO2 injection. The results show that the coal adsorption capacity in CO2 is almost two times greater than that in CH4, and nitrogen adsorption is the least among these gases. A Langmuir-like model can be used to describe the strain with the gas pressure and the swelling strain induced by gas adsorption has a linear relationship with gas adsorption quantity. Moreover, swelling strain increase was observed when CO2 was injected into the sample cell and the swelling strain was almost the sum of the strains induced by different gases at corresponding partial gas pressure.
Coal seams with high CO2 gas contents can be difficult to drain gas for outburst management. Coal has a high affinity for CO2 with adsorption capacities typically twice that of CH4. This paper presents an analysis of nitrogen injection into coal to enhance drainage of high CO2 gas contents. Core flooding experiments were conducted where nitrogen was injected into coal core samples from two Australian coal mining basins with initial CO2 gas contents and pressures that could be encountered during underground mining. Nitrogen effectively displaced the CO2 with mass balance analysis finding there was only approximately 6-7% of the original CO2 gas content residual at the end of the core flood. Using a modified version of the SIMED II reservoir simulator, the core flooding experiments were history matched to determine the nitrogen and methane sorption times. It was found that a triple porosity model (a simple extension of the Warren and Root dual porosity model) was required to accurately describe the core flood observations. The estimated model properties were then used in reservoir simulation studies comparing enhanced drainage with conventional drainage with underground in seam boreholes. For the cases considered, underground in seam boreholes were found to provide shorter drainage lead times than enhanced drainage to meet a safe gas content for outburst management.
Gas content of coal is mostly determined using a direct method, particularly in coal mining where mine safety is of paramount importance. Direct method consists of measuring directly the volume of gas desorbed from coal in several steps, from solid then crushed coal. In mixed gas conditions the composition of the desorbed gas is also measured to account for contribution of various coal seam gas in the mix. The determination of gas content using the direct method is associated with errors of measurement of volume of gas but also the errors associated with measurement of composition of the desorbed gas. These errors lead to uncertainties in reporting the gas content and composition of in-situ seam gas. This paper discusses the current direct method practised in Australia and potential errors and uncertainty associated with this method. Generic methods of estimate of uncertainties are also developed and are to be included in reporting gas content of coal. A method of direct measurement of remaining gas in coal following the completion of standard gas content testing is also presented. The new method would allow the determination of volume of almost all gas in coal and therefore the value of total gas content. This method is being considered to be integrated into a new standard for gas content testing.
Coalbed gas content measurements are commonly used in mine safety as well as coalbed methane resource assessment and recovery applications. Gas content determination techniques generally fall into two categories: (1) direct methods which actually measure the volume of gas released from a coal sample sealed into a desorption canister and (2) indirect methods based on empirical correlations, or laboratory derived sorption isotherm gas storage capacity data. Direct gas content determination techniques may be further subdivided into quick-crushing and extended desorption methods. The quick-crushing methods are primarily used in mine safety applications outside the United States, but have also been used for resource recovery applications. Quick-crushing methods rely on crushing the coal sample soon after collection to release all the desorbable gas, thus significantly shortening the amount of time required for desorption measurements. However, some data useful for resource recovery applications are lost. Extended desorption techniques are most commonly used for resource assessment and recovery applications where information on desorption rates is useful for reservoir modeling, and for fundamental coalbed methane research. Extended desorption methods allow the gases in the coal sample to desorb under controlled laboratory conditions until a defined low desorption rate cutoff point is reached. The sample may then be crushed to measure the amount of gas remaining within the sample. Direct method techniques for gas content measurement are the focus of this paper.
Although coal-gas interactions have been comprehensively investigated, fewer studies consider the impact of thermal effects. In this study, a fully coupled model of coal deformation, gas transport, and thermal transport is developed and solved using the finite element method. A general model is developed to describe the evolution of coal porosity under the combined influence of gas pressure, thermally induced solid deformation, thermally induced gas adsorption change, and gas-desorption-induced solid deformation. This porosity-evolution relationship is implemented into a fully coupled model for coal deformation, gas transport, and thermal transport using the finite element (FE) model. The FE model represents important nonlinear responses due to the effective stress effects that cannot be recovered where mechanical influences are not rigorously coupled with the gas and the thermal transport systems. The controlling effects of gas pressure, temperature and gas sorption on these nonlinear responses of coal porosity and permeability to gas production are quantified through a series of simulations. It is found that the gas-desorption-induced deformation is the most important factor that controls these nonlinear responses. In this work, among the factors such as thermal expansion of solid and gas, and convective heat flux, in addition to the thermal diffusion, the heat sink due to thermal dilatation of gas is most prominent factor in altering the temperature of coal seam. This conclusion demonstrates that the thermal impact on coal-gas interactions cannot be neglected especially where the temperature is high.
Microwave heating is a promising technology in coal processing and coal seam permeability enhancement. It is vital to investigate the influencing factors for microwave heating of coal to ensure the optimal heating effect and the best energy efficiency. To address this, different types of coal samples with various water saturation were treated with various microwave powers and irradiation times. Thermocouple and infrared thermal image system were used to measure the temperature of coal samples during and after microwave treatment. Through analysing the temperature, the effects of dielectric property and water saturation of coal, microwave power and treatment time on microwave heating were investigated. It was found the heating rate of coal samples increases with the loss factor at the initial heating period, which then changes as the composition changes under microwave irradiation. It was also found that coal samples with low water saturation have much better microwave heating effects. Moisture not only impedes microwave heating but also facilitates uniformed heating, which impedes the formation of thermal fractures. Additionally, the experiment results suggest the average temperature increases with microwave power and irradiation time. However, extending the microwave irradiation time is more effective when the microwave power increases to a certain extent.
Air leakage is one of the most important factors that affect the underground gas extraction in mining-disturbed coal seams. It was demonstrated that the gas concentration in most in-seam boreholes decreased to a very low level in a short time. Such a low concentration may lead to secondary disasters such as coal spontaneous combustion, gas explosion and gas combustion. Aiming at this problem, a fully coupled mechanical- composite gas flow (MCF) model was developed to reveal the mechanism of air leakage around the borehole. The reliability of the model was verified by matching the calculating results with gas extraction data monitored in the field. Then, with the MCF model, factors affecting the gas extraction effect were systematically investigated. It was found that the mining-disturbed zone led to an increase of both the gas and air flow rate, but a decrease of the gas concentration in the borehole. Both the gas and air flow rate reduced with an increase of the sealing length of the borehole, while the gas concentration showed an increase trend. The optimal sealing length of the in-seam borehole in Pingmei 8th Mine was identified as 10−14 m. In addition, the attributes of the coal seam itself also have obvious influence on the quality of the gas extracted. The results indicate that both the borehole and the mining-induced fractures around the borehole should be appropriately treated to improve the quality of gas extracted. Therefore, we propose a new sealing method which integrates cement grouting and gel injection. In this method, after the sealing of the gas extraction boreholes, the sodium silicate and ammonium bicarbonate aqueous solutions were mixed and injected into the coal seam. The produced silicone gel could block the mining-induced fractures and the crescent-shaped gap between the sealing material and borehole wall, thus preventing the air leakage. The research results could help to optimize borehole sealing and improve the quality of gas extracted, thus prevent disasters such as coal spontaneous combustion and gas explosion, so as to guarantee the safety of mining and reduce the greenhouse gas emission.
Coal and gas outbursts have long posed a serious risk to safe and efficient production in coal mines. It is recognised that coal and gas outbursts are triggered by excavation unloading followed by gas-driven rapid propagation of a system of pre-existing or mining-induced fractures. Gas-filled fractures parallel to a working face are likely to experience opening first, then expansion and rapid propagation stages under unloading conditions. The fracture opening is driven by the effective stress inside the fracture, while the fracture expansion and rapid propagation is propelled by the pressure build-up of desorbed gas in the vicinity of the fracture. Based upon this understanding, this research aimed to identify the key factors affecting outburst initiation and its temporal evolution during roadway developments. Specifically, the response of pre-set fractures in a thin coal seam sandwiched between rock layers to roadway development is simulated using a geomechanical model coupled with fracture mechanics for fracture opening and propagation. In addition, kinetic gas desorption and its migration into open fractures is considered. During simulations outburst is deemed to occur when the fracture length exceeds the dimension of a host element. The findings of this research suggest that the simulated coal and gas outburst caused by roadway development may be considered as a dynamic gas desorption-driven fracture propagation process. The occurrence of coal and gas outbursts is found to be influenced mainly by the coal properties, fracture attributes, and initial gas pressure and the in situ stress conditions. Furthermore, the model predictions in terms of dome-shaped erupted-zone and layer-by-layer coal breakage are consistent with the field reports. In addition, the model results suggest that delayed occurrence of coal and gas outbursts, especially after sudden exposure of a coal seam or after blasting disturbance, reported in the literature may be related to the gas desorption behaviour.
Coal failure has been observed in many coal seam reservoirs during gas production, which generated significant impacts to coal permeability and to the efficiency of gas recovery. In this paper we develop a flow-geomechanical-coupled numerical approach and use two genuine field examples to discuss the relevant large-scale coal failure behaviours in fields. One example is with the CBM production in Cedar Hill reservoir, San Juan Basin; and the other one is with the CO2-injected ECBM process in Allison Unit, San Juan Basin. Major observations from the present work include: 1) Laboratory tests and analytical analyses based on uniaxial strain conditions may have considerable deviations in prediction of the coal failure during gas production in fields, because such a condition would not hold there because of non-uniform pressure distributions in the field due to gas production/injection. 2) Field-scale coal strength parameters (e.g., the friction angle) should be remarkably weaker than its counterparts measured with core samples because, if otherwise, the coal failure that has been observed would not occur. 3) In CBM processes, coal failure usually occurs first in the immediate vicinity of a wellbore, and then may expand to the whole field with continuing gas depletion. 4) ECBM processes can have complex strain history including inelastic coal failure due to primary production as well as elastic unloading due to CO2 injection.
This study aimed to investigate the influence of cyclic hot/cold shock on the change in the permeability of coal sample under different temperature gradients. The low permeability of Chinese coal seams has always hindered the exploitation and use of coalbed methane resources. In the present study, bituminous coal produced from the Xutuan Mine was selected as the test coal sample. The hot/cold shock experiments of single, multiple cycles treatment under the same temperature gradient, different temperature gradients were carried out by heating of samples in a drying oven, followed by a low-temperature treatment using liquid nitrogen. The fixed-point photography and nitrogen percolation tests were carried out on the coal samples at various stages of exposure. The results showed that the cracking effect of coal was proportional to the number and the temperature gradient of the cycle hot/cold shock treatment. After two treatments, the maximum increment of the permeability of coal samples reached 1129.79%. The permeability increment of coal sample with heating temperature of 100 °C is 2.89–6.44 times that of coal sample with 20 °C. This paper used a quadratic function to fit and discuss the seepage results of coal samples. The influence of hot/cold shock treatment on the Klinkenberg effect of nitrogen flow in coal was also analyzed.
Studies of the microstructure and permeability evolution behavior of coal under conditions of liquid nitrogen (LN2) fracturing are helpful to clarify the mechanism of fracturing. The evolution of the 3D microstructure of the bituminous coal before and after LN2 fracturing was studied, using a high-resolution 3D X-ray microanalyzer and ‘Dragonfly’ software. The pore-fracture structure was preliminarily segmented using a digital terrain model (DTM) threshold segmentation and then was optimized using a ‘deep learning’ model. The box-counting method and a pore network model (PNM) were used to analyze the fractal features, spatial size distribution, and connectivity of pore-fractures. The results of the fractal analysis showed that the 2D fractal dimension of porefracture in the horizontal and vertical directions increased significantly after LN2 fracturing. The PNM analyses showed that the number and size of equivalent pores and throats after fracturing were significantly higher than prior to fracture. The relatively large fractures play a decisive role in the coal permeability, although they account for a small proportion of the total number of fractures. The results of the permeability tests showed that
LN2 fracturing can effectively destroy the original structure of the coal and improve its permeability. At a constant confining pressure, the permeability and permeability increment increased exponentially with increasing gas pressure. The permeability increment curve can be divided into two stages: micro-fracture seepage and large-fracture seepage. During the first phase, the incremental change in permeability is small. During the second stage, the permeability increment increases sharply due to the re-opening of micro-fractures and the formation of large fractures.
This paper focuses on assessing gas drainage performance from vertical surface goaf holes in an operating mine with high specific gas emission rates (~20 m³/t). Field monitoring results of gas flow rate, suction pressure, and gas composition collected from individual gas drainage holes were analysed in detail. The major challenge of implementing the full potential of goaf gas drainage system is the perceived risk of spontaneous combustion in goaf using arbitrary trigger set points. Although the provenance on the introduction and reasons for the use of CO as a trigger of goaf spontaneous combustion is unknown, the paper highlights that the current use of CO based trigger action response plan (TARP) for sponcom management leads to the premature closure of goaf holes, which largely constrains goaf hole gas drainage performance and has a significant bearing on longwall gas management. The CO concentration in gas captured by goaf holes has been found to be positively correlated with O2 concentration and negatively correlated with CH4. The start-up period, completion period, slow retreat and stoppage of LW faces are the main causes for the increase of oxygen ingress and associated high CO levels. Building upon abundant field measurement data, goaf gas profiles for CO, O2, CH4 and CO2 concentration were established, which suggest that the increase trend of CO level behind the face is a normal behaviour of goaf closure and would recover to trivial concentration after 300 m behind the face. This also helps define the ‘inert zone’ and ‘active zone’ in the goaf, which has distinct goaf gas composition and requires different gas drainage strategies. A dynamic goaf hole operation strategy based on real-time gas monitoring and feedback control of valves would maximise gas drainage performance whilst maintaining the sponcom and gas explosion risk at the minimum.
In this study, laboratory tests using six-cycles of nitrogen (N2) injection were carried out to investigate nitrogen flushing effect on coal seam gas recovery. In each test, N2 was injected for 200 min into a coal sample saturated with carbon dioxide (CO2), in a triaxial-loaded cell. Nitrogen injection was paused for about 20 h to allow gas desorption from the coal sample before commencing the next cycle. It was observed that CO2 levels of the outlet flow recovered from 3%-7% to 20%–40%, with no significant change in gas flow rate. The displaced CO2 in each cycle accounts for 4–7% of the initial total gas volume. Analysis of the test results indicated that at least 22 injection cycles were required to drop the residual gas content below the threshold limit value (TLV). The test results also confirmed that N2 injection can promote gas desorption from coal matrix and reduce un-desorbable residual gas content. In comparison with the continuous injection method, the flushing efficiency was lower for the cyclic injection method (5.6 days vs 21.5 days). However N2 consumption was about 60% less, and its utilization ratio was higher for cyclic injection method. Additionally, a post-injection effect of seam gas desorption was observed following each injection cycle. This study demonstrated that cyclic N2 injection method has several potential advantages for different field applications. This injection method can improve coal seam gas recovery with much reduced N2 consumption, and in particular, reduce the cost for separating gas mixture product in nitrogen enhanced coalbed methane recovery (N2-ECBM) project.
Coal mine methane (CMM) and abandoned mine methane (AMM) are by-products of underground mining of gassy coal beds. The quantity and the emission rate of CMM and AMM may vary depending on the type of mine, gas content of the mined coal bed, and gas sourced from strata and coal beds in overlying and underlying formations affected by mining. Therefore, if a mine has the potential of accumulating gas after being abandoned and sealed properly, that methane may be produced and used as an energy source to serve local communities in the area. Producing AMM also prevents methane, which is a potent greenhouse gas, from leaking to the atmosphere through seals, shaft plugs or surface cracks.
A technical barrier to economical utilization of CMM and AMM is the uncertainty about how much methane may be available in the gas emission zone (GEZ) as a resource during mining, as well as after the panels are sealed and the mine is abandoned. Another difficulty is estimating how much of the potential methane resource can be produced from gob gas ventholes (GGV) converted to capture AMM.
In this study, a comparative assessment is presented to address the issues stated above. The assessment was conducted on two adjacent panels of a longwall mine that operated in Pennsylvania until 2016 in the Northern Appalachian Basin. The study is based on two approaches that might be used depending on the availability of data. The first approach uses an extensive geological data set, geostatistics, and measured shaft gas emission and GGV production values that were collected while the panel (s) were active to assess the AMM resource. The second approach uses a minimal amount of geologic data, uncertainty of the data as probabilistic distributions, and the use of publicly available software to predict during-mining emissions. Results showed that both approaches provide relatively comparable estimates of AMM resources and AMM recovery potential using wellbores. The differences in assessed quantities are mostly due to the characteristics of the two methods. In that regard, this paper can be considered as guidance to choose the assessment approach based on data availability.
This paper investigates predictive modelling of gas production from coal seam reservoirs that contain mixtures of CO2 and CH4. A series of laboratory experiments are presented that are analogues of the gas production process where gas is drained at a controlled rate from a coal core sample with a known initial gas content and composition. The experiments were performed at two initial gas compositions and for two outflow rates. There was excellent agreement in the mass balance of the experiments with the difference between the initial gas volume and cumulative outflow ranging between 0.8 and 1.8% of the initial volume. During the early stages of gas desorption the CO2 concentration of the outflow gas was significantly lower than that in the adsorbed gas but increased significantly at low pore pressures. Thus, the CH4 was preferentially desorbed relative to CO2. For example, in an experiment in which the initial gas content of the coal was ~30% CO2, the CO2 concentration of the produced gas was only ~13% and did not increase significantly until the pore pressure fell below 0.8 MPa, ultimately increasing to ~95%. A reservoir simulator was used to match the desorption observations, and the results indicate, in a finding consistent with previous work, that the extended Langmuir adsorption model based on pure gas isotherms does not provide accurate predictions. A modified extended Langmuir approach was developed, based on using measurements of the initial gas content and its composition, provided a more accurate fit to the experimental observations of gas desorption. A fully predictive procedure using the 2D Equation of State adsorption model with the pure gas adsorption isotherms provided good agreement with gas desorption observations. A series of hypothetical reservoir simulation case studies are presented that illustrate changes of CO2 concentration with time for a variety of initial compositions.
As hydraulic fracturing as a means to enhance coal bed methane was banned in some countries due to possible negative environmental impacts, the microwave heating was proposed as an alternative approach to enhance coal permeability and thus gas productivity. One of the mechanisms on improving coal permeability using microwave irradiation is that thermal stress caused by microwave heating generates fractures. To study the influence of microwave settings to the heating effect of coal samples, a coupled mathematical model for electromagnetic, heat and mass transfer in the process of microwave heating is proposed and is numerically implemented using a finite element method. This coupled model for microwave heating have considered heat and mass transfer, and is validated by comparison with experimental results. Then it is used to simulate the influence of frequency, power and moisture capacity on microwave heating. The simulation results show that microwave heating of coal is highly sensitive to excitation frequency. Frequencies around 3.45 GHz contribute to significant thermal heterogeneity. With the same energy input, different powers do not influence the overall heating effect, but higher powers cause greater thermal heterogeneity. Moisture capacity also has great effect on microwave heating and thermal distribution pattern. Under 2.45 GHz and 1.0 kW, the coal sample with moisture capacity of 5% has the best microwave heating effect.
As the one of the most catastrophic hazards in underground mining, coal and gas outburst seriously threatens the safe mining of collieries. To understand the formation and transport mechanism of outburst coal-gas flow in roadway as well as evaluate the effects of gas desorption on its development, a new apparatus was developed to conduct simulated experiments with different gases of CO2 and N2. Results indicated that the outburst coal-gas flow was a high-speed (up to 41.02 m/s during tests) gas-solid two phases flow with extreme complexity, its transport/destructiveness characteristics were significantly influenced by a number of factors including the outburst pressure, coal sample composition, ejection distance and so on. Among these factors, the gas desorption showed the greatest impact when compared to the controlled tests which only considered the effect of free gas expansion. With the effect of gas desorption, especially the rapid gas desorption from powdered coal, the total outburst energy could be promoted by 1.30–2.43 times; the peak values of outburst shockwave could be enhanced by at least 13.67%–63.22%; the transport type of coal-gas flow could be changed from dynamic pressure pneumatic conveying to the static pressure conveying which providing higher capability for outburst coal/rock conveying; the motion of ejected coal flow could have higher speed, longer transport duration and could suffer secondary acceleration. As the result, the destructiveness of outburst coal-gas flow would be remarkably intensified. A further analysis for the energy consumption during the outburst coal-gas flow transport indicated that the free gas expansion energy was insufficient for the conveying of ejected coal (only accounting for less than half of the total energy), the difference of which was made up by the gas desorption, especially the rapid gas desorption from powdered coal (the average contribution ratio reached 56.0%, while the maximum reached 64.1%). Thus, it can be concluded that the rapid gas desorption from powdered coal played a decisive role on the promotion of outburst.
The performance of pre-gas drainage in low permeable seams especially in CO2 abundant coal seams is not satisfactory. Due to the high affinity of coal to CO2, much lead time is needed for gas drainage boreholes to reduce the coal seam gas content below the threshold limit value (TLV), thus meeting the demand of the scheduled mining activities. In this study, simulations of N2 injection enhanced gas drainage were carried out for CO2-rich coal seams. A binary gas migration model was developed to illustrate gas migration in coal seam. The simulation results matched well with the laboratory test results, indicating that this model could be used to investigate the mechanism of N2 flushing coal seam gas. The parameters affecting the flushing performance were then studied using this model, including coal seam permeability, gas diffusion coefficient, N2 injection pressure andin-situ gas content. These results suggest that coal seam permeability and CO2 diffusion coefficient are the key parameters having significant impacts on the drainage performance whilst N2 diffusion coefficient only has negligible effect. A critical parameter theory was developed to describe the correlation between these parameters (especially coal seam permeability and the diffusion coefficient of coal seam gas). Specifically, in low permeable coal seams, permeability was the critical parameter and the effects of other parameters were insignificant. Similarly, if the diffusion coefficient of coal seam gas was very low, it could become a critical parameter.
Uncertainties exist on the efficiency of CO2 injection and storage in deep unminable coal seems due to potential reduction in the permeability of coal that is induced by CO2 adsorption into the coal matrix. In addition, there is a limited knowledge about the stability of CO2 stored in coal due to changes in gas partial pressure caused by potential leakage. This paper presents an experimental study on permeability evolution in a high rank coal from South Wales coalfield due to interaction with different types of gases. The reversibility of the processes and stability of the stored CO2 in coal are investigated via a series of core flooding experiments in a bespoke triaxial flooding setup. A comprehensive and new set of high-resolution data on the permeability evolution of anthracite coal is presented.
The results show a considerable reduction of permeability above 1.5 MPa CO2 pressure that is correlated with the coal matrix swelling induced by CO2 adsorption. Notably studied in this work, the chemically-induced strain due to gas sorption into coal, that has been isolated and quantified from the mechanically-induced strain as a result of changes in effective stress conditions. The results of post-CO2 core flooding tests using helium (He), nitrogen (N2) and methane (CH4) demonstrated a degree of restoration of the initial permeability. The injection of N2 showed no significant changes in the coal permeability and reversibility of matrix swelling. The initial permeability of the coal sample was partially restored after replacing N2 by CH4. Observation of permeability evolution indicates that the stored CO2 has remained stable in coal under the conditions of the experiments.
Even with technological advancements such as hydraulic fracturing and horizontal drilling, only 20% of the original gas in shales is recoverable through current industry practices. This low recovery factor is attributed to very low permeability and sorption of much of the gas by solid organic matter. Enhanced gas recovery through carbon dioxide sequestration could be performed either by cyclic injection (huff and puff) of carbon dioxide or fracturing/re-fracturing the formation with a viscosified, foamed or energized carbon dioxide hydraulic fracturing fluid. This work employs molecular modeling to conduct a fundamental investigation of the interactions between carbon dioxide and the solid organic part of the shales, the majority of which is kerogen. In the current work, more realistic molecular models for Type II kerogen in oil-gas window, with active sites were used instead of the graphite based carbon models used in many previously published works. Both adsorption onto kerogen surfaces and absorption within it contribute to its high sorption capacity. Previously, researchers have shown through modeling and experiments that kerogen has a higher affinity and adsorption capacity for carbon dioxide than for methane. The current work studies the sorption of carbon dioxide and methane using quasi equilibrium Molecular Dynamics (MD) simulations. The MD simulations of ternary system of methane, carbon dioxide and kerogen revealed that the carbon dioxide is more strongly retained than methane in the bulk kerogen matrix. The self-diffusion coefficient of carbon dioxide (Dself = 10⁻¹⁰ m²/s) in the kerogen was found to be an order of magnitude smaller than that of methane (Dself = 10⁻⁹ m²/s) in the kerogen. The MD simulations revealed that in the process of carbon dioxide - methane 1:1 exchange in the kerogen matrix, the kerogen matrix shrinks in volume. This may lead to disturbance in the fluid pathways that contribute to fluid flow in shales. The molecular investigation performed in this fundamental work is relevant to any carbon dioxide enhanced gas production from shale gas resources.
Gas management at longwall faces has always been a challenging issue to mine operators. Along a longwall face of an Australian colliery where CO2 is the dominant coal seam gas, frequent power trip off occurred due to the high goaf gas (CO2) emission, which significantly affected the normal longwall production and brought about safety threats to the longwall crew. CO2 fringe fluctuation changes close to tailgate (TG) was identified as a major concern. To better understand the CO2 fringe behaviour on the longwall face and develop the corresponding effective control measures, Computational Fluid Dynamics (CFD) model was developed and validated based upon field data collected from the colliery. General gas flow characteristics on the longwall face were obtained based on which parametric studies were then carried out to investigate the impact of ventilation system and gas drainage options on goaf gas fringe behaviour. The use of a back-return ventilation system was demonstrated to be an effective approach to control the CO2 fringe at TG; however, it was not practical due to the restriction of existing panel layout. As a compromise of the back-return system, a new gas drainage option using TG borehole which was more practical and cost effective was proposed and assessed by the CFD models. Model results indicated that goaf gas fringe at TG can be effectively controlled when a suction pressure between − 1500 Pa and − 2000 Pa was applied to the TG borehole. Therefore, it can be concluded from this study that gas drainage conducted through TG borehole can be an effective approach to solve the CO2 accumulation at TG on a longwall face, especially when the back-return system is not applicable on site.
In underground coal mining operations, gas content in a coal seam is used to assess the risk of coal and gas outbursts. A broadly standard procedure has been adopted to estimate the gas content with coal core in the coal mining industry. In soft or friable or geologically complex sections of coal seams, it has proven to be extremely troublesome in taking coal cores as cores can be severely fragmented or sometimes it is simply impossible to core with conventional coring methods due to poor borehole stability, leaving coal cuttings from boreholes as the only practical alternative for sampling. When coal core is replaced with coal cuttings, concerns have been raised about the validity and accuracy of the procedure used for gas content determination with coal core, in particular with respect to the sampling method of coal cuttings and gas content calculation due to faster initial gas desorption rates of coal cuttings. The standard procedure for gas content determination with coal core has been modified to determine gas content of coal with coal cuttings from underground boreholes. This paper describes the modified method and presents and discusses the results when it was trialed in a soft coal seam at Huainan, China.
Pre-gas drainage plays a significant role in the prevention of coal and gas outburst in underground coal mines. However, difficulties of reducing the content of coal seam gas, especially localized coal seam CO2, to be below threshold values within a given drainage lead time have been encountered in numerous coal mines in Australia. As the proneness of nitrogen outburst is way smaller than CO2 or methane outburst, nitrogen injection would be an attractive technology for the underground gas drainage management if it is really able to enhance the drainage efficiency. From this point of view, this paper aims at investigating the feasibility of implementing this technology in Bulli seam, Sydney Basin through numerical modelling.
Previous studies have shown that carbon dioxide (CO2) injection can enhance CH4 production (CO2-ECBM) compared to traditionally-used methods, mainly due to the higher adsorptive capability of CO2 in coal, which desorbs the CH4 with higher sweep efficiency. Many studies have been conducted to date on the CO2-ECBM technique for high rank coals. However, there have been very few studies on low rank coal. Therefore, this study uses Victorian brown coal samples to investigate the CO2-ECBM potential of low rank coal. A series of CO2 core flooding tests was conducted on CH4 saturated meso-scale brown coal samples for various CO2 injection conditions, phases and pressures.
A nitrogen flood, ECBM micro pilot was carried out in a deep, low permeability Cameo coal zone of the Mesavede Group in the Piceance Basin. The pilot project entailed the injection of about 28 mmcf (7.9E5 m³) of nitrogen over a period of 15 days at pressures about 650 psig (4482 kPa) above the initial reservoir pressure, followed by a soak period of 15 days, and subsequently 11 days of flow back. The nitrogen flood was a failure inasmuch as there was no pressure change nor nitrogen or methane breakthrough in three closely adjacent monitoring wells, which were considered necessary to meet the metrics required for a field scale economic ECBM project. The results of the pilot test, in conjunction with subsequent laboratory field simulation tests and numerical modeling, are consistent in that they show injection of nitrogen, of necessity above reservoir pressure, neither displaced methane nor promoted methane desorption from the low permeability Cameo coal. The results suggest the injection of nitrogen above reservoir pressure increases the total adsorbed gas resulting in swelling of the coal, which increases the effective stress and hence decreases permeability, the reverse of what is intended. The field, laboratory, and numerical results indicate that for a nitrogen ECBM flood to initiate, in coal such as studied here, the in situ permeability must be high enough that nitrogen can displace, and thus reduce the partial pressure for methane. The results thus indicate that ECBM production by nitrogen flooding will only work in coals where the pre-existing permeability is high enough that conventional coalbed methane production is possible or has already been carried out. Results of our studies provide learnings relevant to carbon dioxide sequestration and ECBM for coals of similar properties to those of this study. An initial high permeability is critical, particularly for carbon dioxide injection, due to its higher volumetric strain coefficient and greater adsorption affinity than methane or nitrogen. Such high in situ permeability exists mainly in shallow coals, which also have the potential of being exploited in the future as a resource and hence may not be viable sites for long term carbon dioxide sequestration.
This article describes the implementation of and results arising from an enhanced gas recovery trial conducted at an Australian coal mine. The objective of the trial was to determine whether pre-drainage of methane from a coal seam can be accelerated and the residual gas content reduced to negligible levels through the use of nitrogen as an enhanced recovery agent. The trial was conducted in a partially depleted reservoir (having been pre-drained using medium radius drilling techniques) and used the existing mine gas drainage facilities and goaf inertisation facilities.
Over a period of 4 months in 2010 1.9 kilo-tonnes of nitrogen was injected into the reservoir. During this time the flow rate, well operating pressures and composition of the gases produced were monitored. Additionally reservoir pressure was monitored at two locations between the injection and production wells using two vibrating wire piezometers.
The effect of the nitrogen injection was to increase the gas production rates at the production wells in a manner consistent with the reservoir model predictions. The anticipated enhanced diffusion effects were however not proven by subsequent gas content testing.
The presence of seam gas in the form of methane or carbon dioxide presents a hazard to underground coal mining operations. In-seam drilling has been undertaken for the past three decades for gas drainage to reduce the risk of gas outburst and lower the concentrations of seam gas in the underground ventilation. The drilling practices have reflected the standards of the times and have evolved with the development of technology and equipment and the needs to provide a safe mining environment underground. Early practice was to adapt equipment from other fields, with rotary drilling being the only form of drilling available. This form of drainage allowed various levels of gas drainage coverage but with changing emphasis, research and development within the coal industry has created specific equipment, technology and practices to accurately place in-seam boreholes to provide efficient and effective gas drainage. Research into gas content determination established a standard for the process and safe levels for mining operations to continue. Surveying technology improved from the wire-line, single-shot Eastman survey instruments which was time-dependent on borehole depth to electronic instruments located in the drill string which transmitted accurate survey data to the drilling crew without time delays. This allowed improved directional control and increased drilling rates. Directional drilling technology has now been established as the industry standard to provide effective gas drainage drilling. Exploration was identified as an additional benefit with directional drilling as it has the ability to provide exploration data from long boreholes. The ability of the technology to provide safe and reliable means to investigate the need for inrush protection and water drainage ahead of mining has been established. Directional drilling technology has now been introduced to the Chinese coal industry for gas drainage through a practice of auditing, design, supply, training and ongoing support. Experienced drilling crews can offer site specific gas drainage drilling services utilising the latest equipment and technology.
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 0.1 day of injection compared to 0.43 day). 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.
Production of coal-bed methane from a reservoir is a function of several parameters, including in situ gas content, the permeability of the coal, and the thickness of the coal seams. Such coal seams usually have low sorption time and there is an easy release of methane from coal upon pressure depletion due to water extraction. Coals with high sorption time are usually not suitable from an economical point of view. This study investigates the role of sorption time in the production behavior of coal under carbon dioxide injection using numerical simulation. A thick coal seam at an intermediate depth of 1600 ft was modeled with two production wells and one injection well between them. Sorption time was varied and the water/methane production and CO2 injection behavior were monitored up to a period of 4000 days. It was found that coals with non-equilibrium sorption time have high CO2 adsorption capacity. Therefore, they can be considered for the enhanced recovery of methane with gas injection. A large quantity of water is released from this type of coal until the start of methane desorption, and despite CO2 injection the onset of gas release remains delayed. At the end of the first year, a reduction of nearly 50% water production was computed for coal with sorption time τ = 0.1 day, while water release reduced by only 23.5% for coal with τ = 50 days. The rate of CO2 injection after six months duration increased to 41.6 mscfd in the case of high sorption time coal, while it rose to only 20 mscfd for low sorption time coal, indicating almost double the rate of gas injection in the former case. The first year methane production from a coal with τ = 0.1 day was 90 mscf, and that for τ = 300 days was 42 mscf. At the end of the fifth year, the cumulative gas production was 842 mscf and 613 mscf respectively for the respective varieties, showing that the difference slowly reduced. Possible mechanisms to understand the behavior of coals with different sorption times are proposed. It is also established that coals with sorption time less than 10 days follow an equilibrium trend in typical Indian Gondwana settings.
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, 2MPa and 10MPa, 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 10MPa cases but this effect was not apparent for the 2MPa 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.
Preliminary estimates of coalbed gas in the major coal-bearing basins of the world range from approximately 3000 trillion cubic feet (TCF) to more than 12 000 TCF. Innovative field research has been conducted primarily in the San Juan and Black Warrior basins. Significant improvements have been made on many aspects of CBM technology, including: 1) dynamic openhole cavitation completions; 2) advanced hydraulic stimulation procedures; 3) enhanced ultimate coalbed gas recovery using the injection of nitrogen or carbon dioxide into the coalbed reservoir; 4) improved reservoir simulation parametric techniques; and 5) seismic methods to predict areas of optimum reservoir permeability.
Sorption isotherms of CO2, CH4 and N2 are determined at 318K and 338K for pressures up to 16MPa in dry Selar Cornish coal using the manometric method. Both equilibrium sorption and desorption were measured. The desorption isotherms show that there is no hysteresis in N2, CH4 sorption/desorption on coal. The time to achieve equilibrium depends on the gases and is increasing in the following order: He, N2, CH4, and CO2. The results show that the sorption ratio between the maximum in the excess sorption N2:CH4:CO2=1:1.5:2.6 at 318K and 1:1.5:2.0 at 338K. Obtained ratios are within the range quoted in the literature.Swelling and shrinkage induced by CO2 injection and extraction from Selar Cornish coal have been measured. The experiments have been conducted on unconfined cubic samples using strain gauges measurements at 321K for pressures up to 4.1MPa. It has been found that the mechanical deformation is fully reversible.The density of CO2 in its sorbed phase, has been extrapolated from the excess sorption isotherm calculated including the swelling. The resulting value is unrealistically high. Possible reasons for this behavior are discussed in the text. Absolute sorption for CO2 has been estimated considering also the change in the coal volume due to swelling. The resulting isotherm calculated with or without the swelling is almost the same.
Coal permeability is highly sensitive to the stress. Meanwhile, coal swells with gas adsorption, and shrinks with gas desorption. Under reservoir conditions these strain changes affect the cleat porosity and thus permeability. Coal permeability models, such as the Palmer and Mansoori and Shi and Durucan models, relate the stress and swelling/shrinkage effect to permeability using an approximate geomechanical approach. Thus in order to apply these models, stress–permeability behaviour, swelling/shrinkage behaviour and the geomechanical properties of the coal must be estimated. This paper presents a methodology for the laboratory characterization of the Palmer and Mansoori and Shi and Durucan permeability models for reservoir simulation of ECBM and CO2 sequestration in coal. In this work a triaxial cell was used to measure gas permeability, adsorption, swelling and geomechanical properties of coal cores at a series of pore pressures and for CH4, CO2 and helium with pore pressures up to 13MPa and confining pressures up to 20MPa. Properties for the permeability models such as cleat compressibility, Young's modulus, Poisson's ratio and adsorption-induced swelling are calculated from the experimental measurements. Measurements on an Australian coal are presented. The results show that permeability decreases significantly with confining pressure and pore pressure. The permeability decline with pore pressure is a direct result of adsorption-induced coal swelling. Coal geomechanical properties show some variation with gas pressure and gas species, but there is no direct evidence of coal softening at high CO2 pressures for the coal sample studied. The experimental results also show that cleat compressibility changes with gas species and pressure. Then the measured properties were applied in the Shi and Durucan model to investigate the permeability behaviour during CO2 sequestration in coal.
New method of analysis to describe the propagation of induced fluid-driven fractures in rock masses which contain pre-existing discontinuities such as joints, bed interfaces, lens boundaries, etc. The analysis is based on a 2-D model, with coupled solid mechanics, fracture mechanics and fluid mechanics. The solid and fracture mechanics are solved by an implicit finite-element approach. The fluid mechanics capability first was established for steady-state conditions. This initial coupling resulted in the version 1.0 of the FEFFLAP model (Finite Element Fracture and Flow Analysis Program). The developments were then extended to the time-dependent domain by replacing the original fluid flow model with a model based on the FAST fluid dynamics module. These new analysis tools can be used for a wide variety of applications such as obtaining a better understanding of the stimulation of unconventional gas reservoirs, i.e. lenticular sandstones, coal beds and Devonian shales, or making improvements in the design of underground waste disposal by hydrofracturing or enhancing the fracturing of geothermal reservoirs
Coal mine methane (CMM) is a term given to the methane gas produced or emitted in association with coal mining activities either from the coal seam itself or from other gassy formations underground. The amount of CMM generated at a specific operation depends on the productivity of the coal mine, the gassiness of the coal seam and any underlying and overlying formations, operational variables, and geological conditions. CMM can be captured by engineered boreholes that augment the mine's ventilation system or it can be emitted into the mine environment and exhausted from the mine shafts along with ventilation air. The large amounts of methane released during mining present concerns about adequate mine ventilation to ensure worker safety, but they also can create opportunities to generate energy if this gas is captured and utilized properly.This article reviews the technical aspects of CMM capture in and from coal mines, the main factors affecting CMM accumulations in underground coal mines, methods for capturing methane using boreholes, specific borehole designs for effective methane capture, aspects of removing methane from abandoned mines and from sealed/active gobs of operating mines, benefits of capturing and controlling CMM for mine safety, and benefits for energy production and greenhouse gas (GHG) reduction.
Gas sorption isotherms have been measured for carbon dioxide and nitrogen and their binary mixture (N2/CO2 80/20) on three different moisture-equilibrated coals from the Argonne Premium Coal Sample Program by the U.S. Department of Energy, varying in rank from 0.25 to 1.68% vitrinite reflectance (VRr). The measurements were conducted at 55 °C and at pressures up to 27 MPa for the pure gases and up to 10 MPa for the gas mixture. The effects of the large differences in equilibrium moisture contents (0.8 to 32.2%) on sorption capacity were estimated on the basis of the aqueous solubility of CO2 and N2 at experimental conditions. Especially for the Beulah−Zap coal with an equilibrium moisture content of 32%, the amount of dissolved CO2 contributes significantly to the overall storage capacity, whereas the amounts of N2 dissolved in the moisture water are low and can be neglected. Sorption measurements with nitrogen/carbon dioxide mixtures showed very low capacities for N2. For Illinois coal, these excess sorption values were even slightly negative, probably due to small volumetric effects (changes in condensed phase volume). The evolution of the composition of the free gas phase in contact with the coal sample has been monitored continuously during each pressure step of the sorption tests. This composition changed strongly over time. Apparently, CO2 reaches sorption sites very quickly initially and is subsequently partly replaced by N2 molecules until concentration equilibration is reached.
Coal mine gas management has evolved from being predominantly dependant on mine ventilation systems to utilising sophisticated surface based directional drilling for pre-drainage of coal seams. However the advent of enhanced gas recovery techniques in the coalbed methane industry has provided an opportunity to address gas management objectives hitherto impractical. Specifically: achieving very low residual gas contents to mitigate against frictional ignitions and fugitive emissions; the means to accelerate gas drainage to accommodate mine schedule changes; and to enable pre-drainage of coal reserves with very low permeability. This article examines a possible enhanced gas recovery field trial at an Australian mine site. Production data from four surface to inseam medium radius gas drainage boreholes was modelled and history matched. The resulting reservoir characteristics were then used to model the performance of the boreholes using an enhanced recovery technique. One of the boreholes is modelled as an (nitrogen) injection well and two flanking wells are modelled as production wells.The model results suggest that accelerated gas flow rates as well as very low residual gas contents are achievable using typical coal mine gas drainage infrastructure and goaf inertisation systems.Research highlights► It is feasible to design an enhanced gas recovery system using a coal mine gas drainage system and coal mine goaf inertisation system. ► Modelling of nitrogen injection into a depleted coal seam gas reservoir indicates that accelerated gas drainage may be achieved. ► Furthermore, modelling of nitrogen injection into a depleted coal seam gas reservoir also indicates that very low residual gas contents may be achievable which in turn may find application for mitigation of frictional ignitions and fugitive emissions in coal mines.
Gas content of coals continuously change throughout their burial histories as a result of the changing state of equilibrium of the coal–gas system caused by variations in P–T conditions and coal rank. To fully evaluate the prospectivity of a coalbed methane resource, numerous coal properties, burial history, P–T conditions, hydrology and the likelihood of secondary biogenic gas generation need to be considered with respect to gas sorption capacity, gas contents and permeability.Previous studies have given differing interpretations on relationships between rank and maceral composition with sorption capacity. The maximum gas storing capacities for Sydney Basin coals is inversely related to rank up to medium volatile bituminous, but a coked, contact metamorphosed coal has an elevated capacity. Comparison of sorption capacities of coals having similar ranks and variable maceral group composition, indicate that rank has a dominating effect over any effects of organic matter type.For the Sydney Basin coals, the in-situ gas contents, on average, increase with depth up to about 600 m and with further increases in depth to 900 m, the gas contents tend to plateau or even decrease. Such a trend probably is consistent with the combined effects of pressure and temperature on the gas sorption capacity during the geological history. R-mode cluster analyses of the coal and gas properties yield a positive correlation between gas contents and inertinite abundance. This is related to undersaturation of the vitrinite-rich coals, possibly due to higher permeability and consequent leakage of more gas from vitrinite-rich coals than from inertinite-rich coals.Although a large amount of methane and other hydrocarbon gases would have been generated in the Sydney Basin at maximum burial during the Early Cretaceous, a large proportion of the gas might not have been sorbed within the coal due to limited gas sorption capacities and enhanced diffusivity at high temperatures. Upon uplift, gas that migrated from deeper in the sequence or from shallower biological activity may have been sorbed into the coals. Without secondary gas replenishment however, many of these coals remain significantly undersaturated.The areas that contain considerable amounts of secondary biogenic gas are highly prospective for coalbed methane production partly because of the higher gas contents, but also because of the higher permeability, which is required for access of the microbes and nutrients in meteoric waters.To fully evaluate prospectivity of coalbed methane resources, numerous coal properties, burial history, geologic setting and the likelihood of secondary biogenic gas generation need to be considered with respect to gas sorption capacity, gas contents and permeability.
Measurements of CO2 adsorption and diffusion properties of coals are reported for various coalfields within Sydney Basin, New South Wales (NSW), Australia. Adsorption measurements were undertaken using a gravimetric method. Measurements carried out on 27 coals show that Sydney Basin coals at CO2 sub-critical conditions, namely gas pressures below 6 MPa and temperatures below 39 °C, can adsorb a maximum volume (Langmuir volume) of 40 to 80 m3 of CO2 per tonne of coal on a dry ash free basis (daf). The coals used in this study are of sub-bituminous to bituminous rank, ranging from 0.66 to 1.45% mean maximum vitrinite reflectance, and are from depths ranging from about 27 m to 723 m. The highest adsorption capacity applies to the highest rank coal, which is also the deepest coal. The standard deviation between Langmuir modeled and measured values is less than 1.5 m3/t, corresponding to a relative error of less than 2.7% for all except one coal. Based on adsorption isotherms, the CO2 storage capacity for in-situ seam pressure conditions range from about 6 to 51 m3/t. CO2 diffusion properties of 15 of these coals, determined using a newly developed system capable of accurately measuring diffusivity of gases in solid coal indicate that CO2 diffusivity (diffusion coefficient) in the Sydney Basin coals varies from 1.2 × 10− 6 to 10.2 × 10− 6 cm2/s. The diffusivity does not show any discernable trend with the variation in depth and rank. Porosity measured by a mercury injection method varies from 4 to 10% and decreases with increase in coal depth and rank. For some of the coal samples adsorption measurements for pure CH4, CO2 and N2 indicate that the Sydney Basin coals can store twice as much CO2 as CH4 and six times more CO2 than N2 (volume basis). Also, measurement of diffusivity in solid coal samples shows that CO2 diffuses twice as quickly as CH4. The data obtained from this study and the estimated coal resources in the state of New South Wales, allow CO2 sequestration potentials to be calculated.
Carbon dioxide contents of coals in the Sydney Basin vary both aerially and stratigraphically. In places, the coal seam gas is almost pure CO2 that was introduced from deep magmatic sources via faults and replaced pre-existing CH4. In some respects this process is analogous to sequestration of anthropogenic CO2. Laboratory studies indicate that CO2:CH4 storage capacity ratios for Sydney Basin coals are up to ∼2 and gas diffusivity is greater for CO2 by a factor of up to 1.5.Present-day distribution of CO2 in the coals is controlled by geological structure, depth and a combination of hydrostatic and capillary pressures. Under present-day P–T conditions, most of the CO2 occurs in solution at depths greater than about 650 m; at shallower depths, larger volumes of CO2 occur in gaseous form and as adsorbed molecules in the coal due to rapidly decreasing CO2 solubility. The CO2 has apparently migrated up to structural highs and is concentrated in anticlines and in up-dip sections of monoclines and sealing faults. CO2 sequestered in coal measure sequences similar to those of the Sydney Basin may behave in a similar way and, in the long term, equilibrate according to the prevailing P–T conditions.In situ CO2 contents of Sydney Basin coals range up to 20 m3/t. Comparisons of adsorption isotherm data measured on ground coal particles with in situ gas contents of Sydney Basin coals indicate that the volumes of CO2 stored do not exceed ∼60% of the total CO2 storage capacity. Therefore, the maximum CO2 saturation that may be achieved during sequestration in analogous coals is likely to be considerably lower than the theoretical values indicated by adsorption isotherms.
Coal Bed Methane: From Prospect to Pipeline, 177
- F N A T Kissell
- Iannacchione
Residual gas in coals and control factors
- Zhang
The result of checking two methods for measuring the permeability of coal seams with computer
- Zhou