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Experimental and Simulation Investigation of N2 Enhanced Gas Drainage in Low Permeable Coal Seam
... Prior to conducting the injection tests, a set of experiments were carried out to characterize the coal samples, and it was observed that the permeability of the samples varied significantly, although the specimens were from the same coal lump. The detailed procedures can be found in previous work [56]. For N 2 flushing test, permeability can affect the breakthrough time, outlet flow rate and the total time of the flushing time. ...
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.
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.
CBM has been recognized as a significant natural gas resource for a long time. Recently, CO2 sequestration in coalbeds for ECBM has been attracting growing attention because of greater concerns about the effects of greenhouse gases and the emerging commercial significance of CBM. Reservoir-simulation technology, as a useful tool of reservoir development, has the capability to provide us with an economic means to solve complex reservoir-engineering problems with efficiency. The pore structure of coal is highly heterogeneous, and the heterogeneity of the pores depends on the coal type and rank.
Australia produces both black and brown coal and is the world's fourth largest producer of black coal, after China, USA and India. Australian underground coal mines operate under controlled safety codes. The establishment of the mine safety management system, including the 1994 outburst management plan, contributed to a significant improvement in mine safety leading to non-fatality in outburst related incidences since 1994. The management of outburst risk, as a part of the overall safety and health management system is described. Also discussed are the introduction of outburst threshold limit values and the desorption rate index which forms the basis for determining safe mining conditions along with the “Authority to Mine” process The measures taken and lessons learned from safe mining of Australia's outburst prone mines represent an opportunity for improved mining safety in other countries, such as China.. The role of the Australian Coal Association Research Program, which supports research in critical areas such as outburst risk control and management, is also discussed.
The research on adsorption isotherms on coal aims on the one hand at providing data to analyze and to predict the behavior of ECBM operations, and on the other hand to develop understanding and to establish correlations that guide in choosing suitable coal seams for ECBM. In this work pure and competitive high pressure adsorption data on coal are presented. For a coal sample from Australia, CO2, CH4 and N2 adsorption isotherms have been measured at 55 ∘C by two different laboratories using two different measurements methods based on a gravimetric approach. The very good reproducibility of the obtained results confirmed the accuracy of the technique used to obtain high pressure adsorption isotherms. High pressure pure adsorption isotherms have been obtained at 45 ∘C and 60 ∘C an up to 200 bar for two coal samples from Italy and Japan, respectively and show the expected behavior of an excess adsorption isotherm. Moreover, for the coal sample from Italy competitive adsorption of CO2, CH4 and N2 was measured using a gravimetric-chromatographic technique. The measurements were performed at conditions representative for the coal seam, namely at a temperature of 45 ∘C and pressures up to 190 bar. As expected from the pure adsorption data, the mixture isotherms clearly confirm that CO2 is preferentially adsorbed on coal over CH4 and even more over N2. These results are the firm basis for an effective design of injection strategies for an ECBM operation.
This article reviews the storage of captured CO 2 in coal seams. Other geologic formations, such as depleted petroleum reservoirs, deep saline aquifers and others have received considerable attention as sites for sequestering CO 2 . This review focuses on geologic sequestration of CO 2 in unmineable coalbeds as the geologic host. Key issues for geologic sequestration include potential storage capacity, the storage integrity of the geologic host, and the chemical and physical processes initiated by the deep underground injection of CO 2 . The review topics include (i) the estimated CO 2 storage capacity of coal, along with the estimated amount and composition of coalbed gas; (ii) an evaluation of the coal seam properties relevant to CO 2 sequestration, such as density, surface area, porosity, diffusion, permeability, transport, rank, adsorption/desorption, shrinkage/swelling, and thermochemical reactions; and (iii) a treatment of how coalbed methane (CBM) recovery and CO 2 -enhanced coalbed methane (ECBM) recovery are performed (in addition, the use of adsorption/ desorption isotherms, injection well characterization, and gas injection are described, as well as reservoir screening criteria and field tests operating in the United States and abroad); (iv) leak detection using direct measurements, chemical tracers, and seismic monitoring; (v) economic considerations using CO 2 injection, flue gas injection, and predictive tools for CO 2 capture/ sequestration decisions; (vi) environmental safety and health (ES&H) aspects of CO 2 -enhanced coalbed methane/sequestration, hydrodynamic flow through the coal seam, accurate gas inventory, ES&H aspects of produced water and practices relative to ECBM recovery/sequestration; (vii) an initial set of working hypotheses concerning the chemical, physical, and thermodynamic events initiated when CO 2 is injected into a coalbed; and (viii) a discussion of gaps in our knowledge base that will require further research and development. Further development is clearly required to improve the technology and economics while decreasing the risks and hazards of sequestration technology. These concerns include leakage to the surface, induced seismic activity, and long-term monitoring to verify the storage integrity. However, these concerns should not overshadow the major advances of an emerging greenhouse gas control technology that are reviewed in this paper.
The Bulli Coal Seam, located in the Illawarra Coalfield of New South Wales, has a long and varied history of sudden outbursts. From available information this problem has resulted in twelve fatalities over the last one hundred and one years, with over five hundred separate outburst incidents being identified. These incidents have varied in severity and intensity from the discharge of 1 to 2 tonne of coal, with a slight increase in gas emission, to the discharge of 200 to 400 tonne of coal with some 6,000 m3 of gas being liberated and large items of mining equipment being pushed 1 to 2 metres down the roadway. Geological features associated with these outbursts can be mapped on a regional and mine by mine basis, to provide some indication or warning. Similarly changes in gas content and gas composition can also be determined on a regional and mine by mine basis. However sudden geological changes (such as a 6.5 metre seam displacement within 15 metres) variations in gas content (such as 6 m3/tonne to 15 m3/tonne) and changes in gas composition (from 95% CH4 to 90% CO2) all within one mine does make the prediction or forecasting of outburst incidents exceedingly difficult. A review of the fatal outburst incidents in the Bulli seam can give valuable insight into how efficient coal mining, within the Bulli coal seam is now linked with the effective use of gas drainage techniques and the management of the outburst risk. The number of variables and "unknowns" associated with outbursts have required the development of fully documented procedures and systems, so that at all stages during the mining operation the risk of injury to mine workers is minimised. The main emphasis for these management systems is the prevention of outbursts by relieving gas pressures using drainage techniques to achieve specified threshold gas level to permit safe mining conditions.
Over the past 30 years rapid development of the coalbed methane industry in the USA and Australia has stimulated research into the mechanisms that control gas migration in coal seams. A technique for enhancing gas recovery from coal was trialed in the San Juan Basin, USA in 1998. The results showed a sustained 500% increase in gas production rates. The technique involves using an injectant gas to stimulate coalbed gas diffusion and increase seam permeability. This paper describes the technique, the potential applications for coal mining and presents a conceptual field trial for an Australian coal mine to demonstrate the effectiveness in partially drained coal mine workings.
Seam gas pre-drainage, is widely used as an effective method to control gas and coal outburst in underground coal mines. However, in CO 2 abundant low permeable seams, this technology seems to be less efficient due to the CO 2 sorption characteristics and the lower safe mining threshold limit for CO 2 applied in many outburst risk management plans. This paper presents the experimental investigations of the applicability of nitrogen (N 2) injection to improve gas drainage in CO 2 rich seams. Core specimens were obtained from Bulli coal seam, Sydney Basin and N 2 flood tests were conducted under different permeability conditions (0.3 mD and 0.06 mD). A triaxial permeability test rig equipped with a back pressure regulator was used to conduct the test. The variation of gas composition, gas outlet flow rate, N 2 flushing efficiency, and permeability variation were analyzed. In addition, a comparative study between N 2 flushing coal seam CO 2 and N 2-ECBM was conducted and it was observed that CO 2 was much more difficult to drain out and with longer time compared with CH 4. Based on the test results, a two-stage flushing mechanism was obtained. In the first stage, the original free phase coal seam gas accounted for the large percentage and this stage last for a shorter time. In the second stage, desorption time governed the flushing efficiency and desorbed gas was the primary gas. It took much longer time than the first stage. The final recovery rate in 0.3 mD and 0.06 mD scenarios were 90.5% and 87.7%, and the N 2 consumption/ CO 2 production ratios were 15 and 11.2, respectively. Through these laboratory experiments, we concluded that N 2 injection can significantly decrease coal seam CO 2 content level and increase gas drainage efficiency.
Although the greater adsorption potential of carbon dioxide (CO2) in coal is an appealing fact in relation to the long-term safe storage of CO2 in coal seams, the resulting coal structure modification, particularly through coal matrix swelling, adds many uncertainties to the process. To date, many studies have been initiated, particularly on the effects of injecting CO2 and reservoir properties on this swelling process and the associated reservoir permeability depletion. These influences are largely dependent on the maturity of the coal mass and its structure, including the cleat system. However, minor attention has been given to date to the effect of coal rank on CO2 adsorption-induced coal matrix swelling and was therefore, investigated in the present study. The volumetric strain of the Australian brown coal samples for both CO2 and N2 under various confinements (tri-axial) and injections was measured at 35 0C constant temperature to investigate the influence of CO2 properties and reservoir depth on CO2 adsorption-induced swelling in coal and was compared with the results in literature to obtain the effect of coal rank. Based on the experimental evaluation of coal matrix swelling under various CO2 and reservoir conditions, super-critical CO2 adsorption leads to greater coal matrix swelling in coal, and the degree of swelling is dependent on reservoir depth and coal maturity. This coal matrix swelling reduces with increasing reservoir depth, due to the associated reduction in CO2 sorption capacity into coal. However, this also depends on the pore pressure conditions, and lower effective stresses leading to greater swelling reduction, regardless of coal rank. The potential of N2 to recover the swelled areas was tested by permeating the coal mass with N2 at different pressures and for different durations (24, 48 and 72 hours). The results show a greater potential for recovery at lower effective stresses for any coal type and for longer durations of N2 flooding.
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.
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.
This paper presents a field trial for developing a gas mixture enhanced coalbed methane (GECBM) technology that can be integrated with underground coal mine methane (CMM) drainage systems. The field trial was carried out in a deep underground coalmine roadway in two stages, initially degassing using a conventional method for 30 days in three boreholes installed in the underground coal seam and then injecting the gas mixture from one of the boreholes for about 2 months. The field trial focuses on the investigation of the technical and economic feasibilities of G-ECBM technology applied to underground CMM drainage systems. The results revealed that the G-ECBM technology integrated with underground methane drainage systems can provide an effective method to enhance the coalbed methane (CBM) recovery from coal mines and the efficiency of underground gas drainage systems, and hence improve the mining safety. The field measurements showed that the single-borehole flow rate and concentration of CH4 for the production boreholes with G-ECBM have increased by a factor of 4.73 and 1.68 on average, respectively, compared with the conventional production boreholes without G-ECBM. The results also showed the economic prospect of applying G-ECBM technology to underground CMM drainage systems.
This paper describes the results of a single well micro-pilot test performed at an existing well in the anthracitic coals of the South Qinshui basin, Shanxi Province, China. A set of reservoir parameters was obtained from the micro-pilot test. The field data was successfully history matched using a tuned reservoir model which accounted for changes in permeability due to swelling and pressure change. Prediction of initial performance showed significant production enhancement of coalbed methane while simultaneously storing the CO2. The calibrated reservoir model was used to design a multi-well pilot at the site to validate the performance prediction. The design is now completed. The recommendation is to proceed to the next stage of multi-well pilot testing and to demonstrate the enhanced coalbed methane (ECBM) technology.
The commercial extraction of methane from coal beds is now well established in a number of countries throughout the world, including the USA, Australia, China, India and Canada. Because coal is almost pure carbon, its reservoir character is fundamentally different to conventional gas plays. Coalbed methane (CBM) forms as either biogenically- or thermogenically-derived gas. The former occurs in ‘under mature’ (< 0.5% vitrinite reflectance) coals and is the result of bacterial conversion of coal into CO2 or acetate, which is then transformed by archaea into CH4. Thermogenic gas is formed as part of the coalification process and is purely a chemical devolatilization that releases CH4. Methane is primarily stored in coal through adsorption onto the coal surface; thus it is pore surface area that determines the maximum gas holding potential of a reservoir (as opposed to pore volume in a conventional reservoir). Although macro-, meso-, and micropores are present in the coal matrix, it is thought that the micropores are where most methane adsorption occurs. In many of the micropores, the methane molecule may actually stretch, minutely, the pore and thus with de-gassing of the reservoir, could result in matrix shrinkage, allowing opening of the fracture (cleat) system in the coal and thus enhancing permeability. The organic composition of the coal is paramount in determining porosity and permeability character and thus maximum gas holding capacity. In general, the higher the vitrinite content the higher the gas holding potential (and ultimately the amount of desorbed gas) and permeability (all other factors being the same). There are other organic component/gas property relationships but these seem to be specific to individual basins, or even seams.
This article reviews the state of research on sorption of gases (CO2, CH4) and water on coal for primary recovery of coalbed methane (CBM), secondary recovery by an enhancement with carbon dioxide injection (CO2-ECBM), and for permanent storage of CO2 in coal seams.Especially in the last decade a large amount of data has been published characterizing coals from various coal basins world-wide for their gas sorption capacity. This research was either related to commercial CBM production or to the usage of coal seams as a permanent sink for anthropogenic CO2 emissions. Presently, producing methane from coal beds is an attractive option and operations are under way or planned in many coal basins around the globe. Gas-in-place determinations using canister desorption tests and CH4 isotherms are performed routinely and have provided large datasets for correlating gas transport and sorption properties with coal characteristic parameters.Publicly funded research projects have produced large datasets on the interaction of CO2 with coals. The determination of sorption isotherms, sorption capacities and rates has meanwhile become a standard approach.In this study we discuss and compare the manometric, volumetric and gravimetric methods for recording sorption isotherms and provide an uncertainty analysis. Using published datasets and theoretical considerations, water sorption is discussed in detail as an important mechanisms controlling gas sorption on coal. Most sorption isotherms are still recorded for dry coals, which usually do not represent in-seam conditions, and water present in the coal has a significant control on CBM gas contents and CO2 storage potential. This section is followed by considerations of the interdependence of sorption capacity and coal properties like coal rank, maceral composition or ash content. For assessment of the most suitable coal rank for CO2 storage data on the CO2/CH4 sorption ratio data have been collected and compared with coal rank.Finally, we discuss sorption rates and gas diffusion in the coal matrix as well as the different unipore or bidisperse models used for describing these processes.This review does not include information on low-pressure sorption measurements (BET approach) to characterize pore sizes or pore volume since this would be a review of its own. We also do not consider sorption of gas mixtures since the data base is still limited and measurement techniques are associated with large uncertainties.
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.
The paper outlines the phenomenon of outbursts of gas and coal in underground coal mines and provides general statistics of their occurrence. Various factors that influence this phenomenon such as geological conditions, physical properties of coal, gas content and gas pressure are discussed. The indices used in different countries for the prediction of conditions that can produce and cause outbursts are presented. Control measures and prediction techniques are discussed with an emphasis on the management systems, decision making and the use of risk analysis to predict the consequences of outbursts. Where control methods cannot be adopted and mining has to be done, procedures for outburst mining are given. Data collection sheets on the occurrence of outburst are provided. An example of a technological development in the remote control of continuous miners is given.