Coal Core Samples Research Articles

Coal petrography, mineralogy, elemental compositions and palaeoenvironmental interpretation of Late Carboniferous coal seams in three wells from the Kozlu coalfield (Zonguldak Basin, NW Turkey)

A number of coal seams of Late Carboniferous age in the coal-bearing Karadon, Kozlu, and Alacaağzı formations have been mined in several deep underground mines in the Zonguldak Basin (NW Turkey). For this study, a total of 154 coal core samples were collected from three research wells that were drilled in the tectonically complex settings of the Kozlu coalfield. All the coal samples were studied by means of coal petrography, mineralogy, and geochemistry. Special attention was given to the compositions and origins of fracture/cleat-filling minerals that were identified by SEM-EDX on polished blocks. The coal seams investigated are of bituminous rank. They are characterized by low total sulphur contents (≤1.0%, on dry basis) and high gross calorific values (22.5–40.2MJ/kg, on dry, ash-free basis), whereas ash yields and volatile matter contents are variable. X-ray powder diffraction data indicate that the mineralogical compositions of the studied coal seams are rather similar, and clay minerals, along with quartz and carbonate minerals, were identified in almost all seams. The statistical evaluations and SEM data show that some elements such as Mg, Ti, Zr, Nb, and Th are generally affiliated with silicate minerals, whereas elements like Cu, Zn, Mo, and Pb are mainly associated with sulphide minerals. The silicate minerals are generally detrital, and the majority of carbonate minerals are of epigenetic origin. The epigenetic carbonate and sulphide minerals suggest that circulated solutions within coal seams were mainly derived from Ca2+-rich solutions leached from overlying formations such as Cretaceous aged Zonguldak formations and from hydrothermal solutions that likely were derived from andesitic dykes within the basin. The regional tectonic activities during coalification seem to have deformed coal-bearing formations and, therefore, intra-basinal solutions could have penetrated into the studied coal seams. The epigenetic mineralisation also resulted in elemental enrichments and elevated ash yields, total sulphur, and volatile matter contents in some coal seams. Thus, deformation during coalification controlled some coal quality parameters in the studied wells. The coal facies diagrams suggest that palaeomires mostly accumulated under limno-telmatic conditions, whereas a telmatic environment was more common in palaeomires of the Kozlu Formation. Coal petrography suggests that peat-forming vegetation and water tables in palaeomires were changeable during the Late Carboniferous.

Geochemical and organo-petrographic characterization for hydrocarbon generation from Barakar Formation in Auranga Basin, India

Keeping in pace with global studies of shale gas/oil, the authors had selected fifty-one (41 shales and 10 coal) core samples of Barakar Formation (lower Sakmarian–Kungurian) from four boreholes of Auranga basin, to understand hydrocarbon generation potential. The Rock-Eval pyrolysis along with total organic carbon content (TOC), organo-petrographic, vitrinite reflectance, Fourier Transform infrared spectroscopy (FTIR), X-ray fluorescence (XRF) analyses were carried. These studies indicate that all the samples (coal and shale) have fair to excellent hydrocarbon generation in respect of TOC and S2 (under Rock-Eval pyrolysis). Further, the thermal maturity (Tmax) of shales and coals are placed in ranges from 409 to 468 and 420–426°C respectively. However, vitrinite grains having reflectance>0.60% (↑Vt60%) may indicate the onset of thermogenic oil generation could possible in the majority of the samples. The presence of alginite, sporinite, resinite, liptodetrinite and suberinite along with perhydrous vitrinite and inertinite macerals is observed. The linear relationship of total maceral content (TMC) with TOC may help in their determination empirically. Multiple regression analysis denote maceral reactivity in the generation of S2. In addition, A-factor (aliphatic/aromatic peak intensity) and C-factor (carbonyl/aromatic peak intensity) under FTIR spectra, suggest dominance of kerogen type III, IV and II/III. The geochemical indices like CIA (chemical index of alteration), CIW (chemical index of weathering) and ICV (index of compositional variation) indicate strong to intermediate weathering, under passive continental margin depositional environment supporting luxurious vegetation and organic matter preservation.

Nitrogen enhanced drainage of CO2 rich coal seams for mining

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.

Characterisation of bioavailability of Surat Basin Walloon coals for biogenic methane production using environmental microbial consortia

The study sets out to characterise the bioavailability of six Surat Basin Walloon coals from different stratigraphic layers in a single borehole to environmental methanogenic consortia. Factors that control bioavailability have also been investigated on grounds of coal petrographic composition and the organic composition of solvent-extractable matter. Finely crushed coal core samples were inoculated with digested sludge culture from domestic wastewater treatment in serum bottles kept anoxically before incubation at mesophilic temperature over 30days for biomethane production. Degradation of coal compounds was demonstrated via GC–MS characterisation of methanol and dichloromethane (DCM) extracts, in combination with aqueous volatile fatty acids and alcohols and total organic carbon (TOC) analysis on fresh and microbially-digested coal samples. The resulting methane yields ranged from 14 to 33μmol/g, with an average of 21μmol/g (0.515m3/t), comparable to those previously reported for subbituminous coals. Organic solvent-extractable materials that accounted for 3.8 to 12% of coal weight were generally dominated by aliphatic compounds, composed of mainly medium-long-chain n-alkanes, n-alcohols and esters. Aromatics were detected up to three fused rings, and are rich in dibenzofuran, alkyl benzene, diphenyls and alkyl PAH (polymeric aromatic hydrocarbon). The abundance of solvent-extractable matter was found to be positively associated with liptinite content, particularly suberinite, sporinite and liptodetrinite. Preservation of these compounds was thought to rely on vitrinite, such as telinite and collotelinite that are rich in micropores, serving as storage for the hydrocarbons. Environmental factors, such as microbe-carrying groundwater might compromise coal extractability by converting coal hydrocarbons to biogas. Bioavailability of coal was shown to be controlled by three factors: 1) Water solubility - Bioassay eliminated an average 98% of aqueous compounds (based on TOC), which were dominated by volatile fatty acids and alcohols, and to a lesser degree, medium-chain (primarily C10 to C20) n-alcohols, esters and aliphatic amine; 2) Solvent extractability – 34.5% of solvent-extractable compounds were shown to be biodegraded (based on peak intensity in GC–MS), with methanol extracts being more bioavailable than DCM's; 3) Heterogeneous moieties, particularly aliphatic hydroxyl group, ester bond, ether bond and CN bond in aliphatic amine - These functional groups present heteroatoms that can lower the activation energy of nearby bonds, making them vulnerable for microbial cleavage. Compound degradation in bioassays was shown to be clearly associated with methane yield, but only a small proportion degraded was converted to methane. Further improvement may be achieved via proper adaptation of the current microbial community.

Hydrogeochemistry and coal-associated bacterial populations from a methanogenic coal bed

Biogenic coalbed methane (CBM), a microbially-generated source of natural gas trapped within coal beds, is an important energy resource in many countries. Specific bacterial populations and enzymes involved in coal degradation, the potential rate-limiting step of CBM formation, are relatively unknown. The U.S. Geological Survey (USGS) has established a field site, (Birney test site), in an undeveloped area of the Powder River Basin (PRB), with four wells completed in the Flowers-Goodale coal bed, one in the overlying sandstone formation, and four in overlying and underlying coal beds (Knoblach, Nance, and Terret). The nine wells were positioned to characterize the hydraulic conductivity of the Flowers-Goodale coal bed and were selectively cored to investigate the hydrogeochemistry and microbiology associated with CBM production at the Birney test site. Aquifer-test results indicated the Flowers-Goodale coal bed, in a zone from about 112 to 120m below land surface at the test site, had very low hydraulic conductivity (0.005m/d) compared to other PRB coal beds examined. Consistent with microbial methanogenesis, groundwater in the coal bed and overlying sandstone contain dissolved methane (46mg/L average) with low δ13C values (−67‰ average), high alkalinity values (22meq/kg average), relatively positive δ13C-DIC values (4‰ average), and no detectable higher chain hydrocarbons, NO3−, or SO42−. Bioassay methane production was greatest at the upper interface of the Flowers-Goodale coal bed near the overlying sandstone. Pyrotag analysis identified Aeribacillus as a dominant in situ bacterial community member in the coal near the sandstone and statistical analysis indicated Actinobacteria predominated coal core samples compared to claystone or sandstone cores. These bacteria, which previously have been correlated with hydrocarbon-containing environments such as oil reservoirs, have demonstrated the ability to produce biosurfactants to break down hydrocarbons. Identifying microorganisms involved in coal degradation and the hydrogeochemical conditions that promote their activity is crucial to understanding and improving in situ CBM production.

Estimation of ash, moisture content and detection of coal lithofacies from well logs using regression and artificial neural network modelling

Coal core samples and well log data of five exploratory wells of Korba Coalfield (CF), India have been used for prediction of coal facies. The Indian non-coking coal lithofacies are generally classified by analyzing the variation of the geophysical log parameters or by defining the ranges of various proximate parameters (mainly ash % and moisture %) obtained from coal core samples. The objective is to classify each layer as coal, shaly coal and shale depending upon the content of ash % and moisture % of the corresponding layer in coaly horizon. Hierarchical Cluster Analysis (HCA) is applied to classify the non-coal horizons and bands of identified coal seams of each well under the study area based on geophysical log responses: natural gamma ray (NG), high resolution density (HRD) and single point resistance (SPR). Hierarchical clustering separates the zones in a particular coal seam from five wells using the nature of the curve. These zones/clusters are further identified as coal, shaly coal, shale in three wells using regression and multilayer feed forward neural network. The log responses and coal core analyzed proximate parameters of these isolated bands/zones in two wells are used for establishing linear regression and neural network models. The observation shows very satisfactory fit (R2=0.84) between ash content and HRD and poor R2(<0.41) between moisture content and log responses. The MLFN model is based on study of two wells using NG, HRD and SPR log responses as inputs and coal proximate parameters, namely, ash and moisture content as outputs to classify the coal lithofacies. The bands within a coal seam are classified on the basis of the ash and moisture content while training as well as the validation of the model. These linear and MLFN models are used to determine the ash % and moisture % in the remaining three testing wells. MLFN predicted results are more closely to the laboratory analyzed proximate parameters as compared to the results obtained from regression modelling.

Quality Assessment of the Permian Coals from Dighipara Basin, Bangladesh Based On Proximate, Ultimate and Microscopic Analyses

Assessment of coal quality based on proximate (volatile matter, fixed carbon, ash, moisture), ultimate (C, H, N, S, O) and microscopic (macerals, microlithotypes, coal facies) analyses of the Permian coals from the Dighipara basin, Bangladesh was carried out. A total of 11 coal core samples collected from two bore holes of Dighipara basin were analyzed. ASTM standards were followed for proximate and ultimate analyses. ICCP systems were used for the microscopic study. Thermal maturity, physical characteristics of the coal seams, gross calorific value and atomic ratios of H/C and O/C were also considered.Journal of Bangladesh Academy of Sciences, Vol. 39, No. 2, 177-194, 2015

Characterization of the micropore systems in the high-rank coal reservoirs of the southern Sichuan Basin, China

To gain a better understanding of the characteristics of micropore systems in high-rank coal reservoirs, 51 coal core samples collected from 16 wells were examined by maceral analysis, proximate analysis, scanning electron microscopy observation, low-temperature nitrogen gas adsorption, and nuclear magnetic resonance (NMR). The results show that pores in coals can be divided into plant tissue hole, blowhole, dissolved pore, and intercrystalline pore, and they have three structure shapes: open pore, semiclosed pore, and “ink bottle” pore. The total specific surface area (Brunauer-Emmet-Teller [BET]) ranges from 0.611 to (7 to ), averaged at . The total pore volume (Barrett-Joyner-Halenda model [BJH]) ranges from 0.0018 to (0.0001 to ) with an average of , and it shows a good positive relationship with . The adsorption amount shows a good positive relationship with the total and . The average pore size ranges from 5.775 to 17.842 nm. Pores that are smaller than 5 nm make up the main contribution to the pore surface area, and those larger than 10 nm contribute greatly to the pore volume. Inertinite-rich coals have higher total specific surface area, pore volume, pore size, and adsorption capacity than those in vitrinite-rich coals. Lopingian coal reservoirs are characterized by low porosity and extremely low permeability obtained from NMR tests, and the permeability has a positive correlation with the porosity. The average permeability of inertinite is almost twice that of vitrinite .

Mineral occurrence and its impact on fracture generation in selected Qinshui Basin coals: An experimental perspective

The effect of mineral matter on the fracture evolution was investigated for Lower Permian and Upper Pennsylvanian coal samples from the Qinshui Basin of China. Optical microscopy, scanning electron microscopy with energy dispersive X-ray spectrometry (SEM–EDS), and X-ray computed tomography (X-ray CT) were used to investigate the composition and modes of occurrence of minerals within the coals and to characterize the natural and induced fractures present within the samples. The spatial distribution of mineral matter investigated by X-ray CT demonstrates that the variation of mineralization within the cleats/fractures occurred at fine scales, and most of minerals were scattered in coal core samples. The original fractures normally were present as two sets: one set was almost parallel to the bedding plane, and the other was almost perpendicular to the bedding plane. For created fractures, the difference in density between the matrix and mineral matter may weaken the cohesion of coals, and it could explain why the created fractures propagate along the junction of minerals and organic coal matrix. The internal fracture porosities varied from 0.06% to 20.69%, which indicates a strong internal heterogeneity of the coals after a stress is applied. The inclination of the main shear fractures ranges from 55° to 95°. Using energy analysis, the fracture energy appears to represent nearly half of the total dissipated energy, which can be correlated with the fracture density and orientation. The formation and distribution of shear fractures is related to the spatial distribution of mineral matter and the overall mineral content. These investigations serve to characterize hydro-fracturing and pulverized coal generation during coalbed methane development.

Analysis of Sorption-Induced Permeability Reduction Considering Gas Diffusion Phenomenon in Coal Seam Reservoir

The sorbed gas diffuses in a coal matrix, where diffusion varies considerably with pore structure and pressure. The diffusion is an essential factor due to high sorption affinity of \(\hbox {CO}_{2}\) on coal grain surface. The sorption within the matrix causes swelling or shrinkage of matrix, in which the amount of sorbed gas affects gas diffusion. In this study, in order to observe permeability change occurred when the sorbed gas diffuses in a coal matrix, experiments were conducted with a bituminous coal sample. Firstly, gas partial pressure was measured through a diffusion experiment with a transient flow method. Secondly, flowing experiments were conducted to examine the permeability reduction yielded by sorption phenomena according to the various pore pressures. The results were then analyzed for the effect of diffusion coefficient on permeability change. The diffusion coefficient of \(\hbox {CH}_{4}\) in low-pressure section was greater than that of \(\hbox {CO}_{2}\) owing to the difference in their molecular weight. However, as pressure increased, the diffusion coefficient of \(\hbox {CO}_{2}\) became greater because of higher sorption affinity of \(\hbox {CO}_{2}\) compared to \(\hbox {CH}_{4}\). Finally, it was revealed that the gas diffused instantaneously in the case of crushed coal in which its diffusion coefficient had infinite value due to the destroyed pore structure. Meanwhile, in the coal core sample in which pore structure was preserved as original state, it was ascertained that diffusional flow occurred gradually corresponding to concentration gradient, and hence, the permeability was reduced accordingly. This phenomenon was also confirmed through pore images obtained from X-ray CT.

Stimulating methane generation within coal seam reservoirs

Methane generation by microbial activity or biogenesis is a significant source of coal bed methane (Faiz and Hendry, 2006; Strapoć et al, 2011). Being able to stimulate microbial methane generation in a coal seam reservoir has the potential to add significant value to depleted or undersaturated fields. Several laboratory studies have demonstrated that this process can be stimulated through the addition of inorganic nutrients (Jones et al, 2010; Orem et al, 2010). These studies, performed at atmospheric pressure on crushed coal, provide encouraging support for the concept of inducing in-situ biogenic methanogenesis and increasing gas-in-place in coal bed methane reservoirs. Important questions, however, remain about how laboratory results relate to what occurs in the reservoir. This extended abstract presents the results from a series of core flooding experiments conducted at reservoir pressure and temperature on intact coal core samples. Nutrient consumption is characterised by measuring the nutrient balance between the inflow and outflow waters. Gas content is measured through a helium flood at the end of the experiment, during which the pore pressure is dropped to atmospheric pressure to drive off any adsorbed gas. These experiments confirm that microbial gas generation does occur at reservoir pressure and temperature, and at high enough rates to rapidly increase gas content.

Stable isotopic and molecular composition of desorbed coal seam gases from the Walloon Subgroup, eastern Surat Basin, Australia

This study used compositional and stable isotopic analysis to test hypotheses on the distribution and origins of Walloon Subgroup coal seam gas (CSG) in the eastern Surat Basin, Queensland, Australia. The Middle Jurassic Walloon Subgroup play differs from many other low-rank CSG plays—particularly in methane carbon isotopic signature, i.e., the CSG is not as ‘microbial’ as could be expected. The carbon isotope compositions of desorbed methane from three cored appraisal wells fall within the generally accepted range for thermogenic or mixed gas (δ13C −58.5‰ to −45.3‰). The δ13C–CH4 values from stratigraphically placed coal core samples increased (became more ‘thermogenic’) from the top of the upper (Juandah) coal measures to the base of the Tangalooma Sandstone. Below the Tangalooma Sandstone, in the lower (Taroom) coal measures, the δ13C–CH4 values decreased with increasing depth. These positively parabolic δ13C profiles tracked total measured gas content in two out of the three wells studied. The third well displayed lower variance of δ13C–CH4 and gas content increased uniformly with depth.A genetic classification based on methane stable carbon isotopes alone might interpret this pattern as a transition from microbially- to thermogenically-sourced methane in the central coal seams. However, a δ13C–CO2 profile for one well tracks total gas content and δ13C–CH4, and exhibits an inverse relationship with δD–CH4. These results, together with the mostly dry nature of the gas samples [(C1/(C2+C3)) ratios up to ~10,000] and relatively uniform δD–CH4 values (δD −238‰ to −202‰), suggest that microbial CO2 reduction is the primary source of Walloon Subgroup methane. As such, stratigraphic variations in gas content mainly reflect the extent of microbial methanogenesis. We suggest that peak microbial utilisation of H2–CO2 occurred at the Tangalooma Sandstone level, enriching the residual CO2 pool and derived methane in 13C. Carbon [Δ13C(CO2–CH4)] and deuterium isotopic differences [ΔD(H2O–CH4)], and cross-plots of δD–H2O and δ18O–H2O are also consistent with kinetic isotope fractionation during microbial-mediated carbonate reduction. The results are relevant for applying microbially enhanced coal bed methane (MECoM) in the Surat Basin.

Understanding the significance ofin situcoal properties for CO2sequestration: An experimental and numerical study

Over the years, there has been a rapid increase in atmospheric CO2 concentrations, from 280 ppm in 1850 to 360 ppm in 1998. Therefore, mitigation methods such as carbon sequestration in subsurface reservoirs have been suggested. CO2 sequestration is attractive, especially in relation to coal, with the additional potential benefit of CH4 recovery. However, the potential of CO2 sequestration is not well understood for various types of coals due to important in situ properties of coal. In this study, data from previous studies for coal permeability, density, moisture content, mineral content, vitrinite reflectance, compressive strength and temperature are compared with the CO2 adsorption results to understand the significance of these in situ coal properties on CO2 sequestration. To verify the findings, a custom-designed advanced core flooding apparatus is used to simulate the effects of various in situ properties on CO2 sequestration. This apparatus can test samples of 203 mm in diameter and up to 1000 mm in length. Hence, heterogeneity effects can be understood, as previous CO2 sequestration-related formulae have been based on coal samples of sizes ranging up to only about 100 mm. However, initially, a reconstituted coal core sample has been used to simplify the heterogeneity effects. Flow rates are estimated by analysing the lag of downstream pressures over time. With the use of a 203-mm-diameter and 816-mm-long reconstituted Victorian brown coal sample, flow rate reductions of 70% and 98% are observed for injection pressures of 2 and 4 MPa, respectively, due to CO2 injection. This study highlights the appropriateness of a candidate coal reservoir for CO2 storage in terms of in situ properties. Copyright © 2013 John Wiley & Sons, Ltd.

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

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

Advanced core flooding apparatus to estimate permeability and storage dynamics of CO2 in large coal specimens

The ever-increasing carbon dioxide (CO2) emissions into the atmosphere due to human activities are causing a major environmental impact and need to be controlled promptly using innovative technologies. CO2 storage in sub-surface reservoirs such as coal seams with potential for recovering methane is perceived as an efficient technology. However, the storage efficiency of this methodology has not been verified experimentally for various coal types. Although testing has been carried out using coal specimens up to about 100mm in length, the results have not yet been verified with samples over 500mm in length. Theories of coal adsorption need to be verified with these types of samples to understand the effect of swelling, shrinkage and storage at a substantial scale. A state-of-the-art core flooding apparatus has been developed to investigate the change of pore pressure along a coal core sample with the adsorption of CO2. The unique core flooding apparatus can accommodate specimens of 203mm in diameter and up to 1000mm in length. The pore pressure development along the coal sample due to CO2 injection is monitored at 3 intermediate points, and tests show a reduction in permeability with increasing injecting pressures. By testing a reconstituted coal sample of 832mm, the permeability was observed to decrease exponentially with the injection of CO2 as well as with increasing effective stress. Due to CO2 adsorption coal sample swelled by 0.12%, 0.16% and 0.05% corresponding to injection pressures of 900kPa, 1900kPa and 3900kPa and axial loads of 3.2T, 6.4T and 12.8T respectively.

History matching of enhanced coal bed methane laboratory core flood tests

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

Carbon dioxide gas permeability of coal core samples and estimation of fracture aperture width

Abstract The structure of cleats, or natural fractures in coal seams, is an important factor affecting gas permeability. Coal seam permeabilities have been classified into fracture and matrix flows. However, fractures in coal seams are generally not regular and usually are discontinuous. In addition, it is difficult to definitively distinguish the fracture and matrix permeabilities, and to measure the fracture widths or other necessary properties of fractures for permeability estimation. Typically gas permeability has been determined by using the Darcy equation for incompressible fluid flow and homogeneous porous media, even if the gas flow through fractures has different characteristics with respect to effective stress, which is given by the confined stress minus the gas pressure. In this study, permeability measurements were carried out with a new procedure and methodology to estimate the fracture width in coal core samples. This measurement method is an improvement on conventional permeability measuring methods. In this research, it was identified that fracture permeability can be estimated from measurements of gas flow rates in a limited small area using a pipe attachment on the end of the surface of the core. Finally, a linear equation composed of fracture permeability and matrix permeability is presented.

アジア大での環境負荷軽減と石炭需給の安定化 ＣＯ２炭層固定化に関連した液体ＣＯ２に対する吸着，浸透および膨潤特性

A national project on a carbon dioxide (CO2) sequestration has been carried out from 2002 by injecting CO2 into one of the Ishikari coal seams located at the Minami Ishikari Coal Field in Hokkaido, Japan. The coal seam lies at 890 m under the surface with in-situ conditions of 29°C in temperature and 11MPa in static stress. Even if super critical CO2 over 70°C and 8 MPa is supplied at the surface, it becomes liquid CO2 with 29°C and 15MPa at the bottom of injector due to heat loss to low temperature strata and creates a problem of coal seam permeability reduction around the injector. Thus, coal characteristics for liquid CO2 injection are very important to carry out the project. However, measurements of permeability and coal swelling factor for liquid CO2 has not been presented and visualized clearly.In this study, the permeability and swelling of a core sample drilled from the coal seam has been investigated. Furthermore CO2 adsorption/desorption properties of the coal have been measured using with a volumetric method with comparisons of coal samples mined from the Kushiro Coal Mine. As a result, the swelling of the coal matrix has been observed clearly by visualization pictures of crushed coal sample and a hole drilled in the coal core sample sunk in CO2 liquid. The ratio of its area reduction by the swelling in liquid CO2 was 7% during 78hours.

Significance of organic matter in recording paleoenvironmental conditions of the Safa Formation coal sequence, Maghara Area, North Sinai, Egypt

Five coal and shale core samples of the Middle Jurassic Safa Formation were taken from a newly drilled water well at the depth interval from 191 to 208 m, and have been investigated in this study. Detailed organic and inorganic geochemical analyses of the Safa Formation reveal no significant differences between the upper seams and the main seam. The extracts of the coal samples have an unusual n-alkane distribution; the GC traces are dominated by unusual compounds eluting between n-C19 and n-C21. These compounds are thought to be diterpanes, which suggest significant conifer contributions to the coals. Higher amounts of hopanes and higher carbon preference index (CPI) values (n-C22 to n-C30) show significant bacterial contributions in samples characterized by high values of tissue preservation index (TPI). The C31 αβ (22S/22S+22R) hopane and C29 ααα (20S/20S+20R) sterane ratios show least variation through the shale–coal sequence. Shale and coal samples from the upper and main seams are characterized by high relative abundance of 17β (H)-hopanes, which could be derived from non-microbial organisms such as ferns. The petrographic and geochemical evidences suggest that the Maghara coal was formed in a “wet forest–swamp” environment situated in a marine-influenced lower delta plain.

97/02520 Maceral/microlithotype analysis of the Hard-grove grindability of lithotypes from the Phalen coal bed, Cape Breton, Nova Scotia

The coal petrologist seeks to determine the petrographic characteristics of organic and inorganic coal constituents and their lateral and vertical variations within a single coal bed or different coal beds of a particular coal field. Definitive descriptions of coal characteristics and coal facies provide the basis for interpretation of depositional environments, diagenetic changes, and burial history and determination of the degree of coalification or metamorphism. Numerous coal core or columnar samples must be studied in detail in order to adequately describe and define coal microlithotypes, lithotypes, and lithologic facies and their variations. The large amount of petrographic information required can be obtained rapidly and quantitatively by use of an automated image-analysis system (AIAS).An AIAS can be used to generate quantitative megascopic and microscopic modal analyses for the lithologic units of an entire columnar section of a coal bed. In our scheme for megascopic analysis, distinctive bands 2 mm or more thick are first demarcated by visual inspection. These bands consist of either nearly pure microlithotypes or lithotypes such as vitrite/vitrain or fusite/fusain, or assemblages of microlithotypes. Megascopic analysis with the aid of the AIAS is next performed to determine volume percentages of vitrite, inertite, minerals, and microlithotype mixtures in bands 0.5 to 2 mm thick. The microlithotype mixtures are analyzed microscopically by use of the AIAS to determine their modal composition in terms of maceral and optically observable mineral components. Megascopic and microscopic data are combined to describe the coal unit quantitatively in terms of (V) for vitrite, (E) for liptite, (I) for inertite or fusite, (M) for mineral components other than iron sulfide, (S) for iron sulfide, and (VEIM) for the composition of the mixed phases (Xi) i = 1,2, etc. in terms of the maceral groups vitrinite V, exinite E, inertinite I, and optically observable mineral content M. The volume percentage of each component present is indicated by a subscript. For example, a lithologic unit was determined megascopically to have the composition (V)13(I)1(S)1(X1)83(X2)2. After microscopic analysis of the mixed phases, this composition was expressed as (V)13(I)1(S)1(V63E19I14M4)83(V67E11I13M9)2. Finally, these data were combined in a description of the bulk composition as V67E16I13M3S1. An AIAS can also analyze textural characteristics and can be used for quick and reliable determination of rank (reflectance).Our AIAS is completely software based and incorporates a television (TV) camera that has optimum response characteristics in the range of reflectance less than 5%, making it particularly suitable for coal studies. Analysis of the digitized signal from the TV camera is controlled by a microprocessor having a resolution of 64 gray levels between full illumination and dark current. The processed image is reconverted for display on a TV monitor screen, on which selection of phases or features to be analyzed is readily controlled and edited by the operator through use of a lightpen.We expect that automated image analysis, because it can rapidly provide a large amount of pertinent information, will play a major role in the advancement of coal petrography.