Methane and CO2 sorption and desorption measurements on dry Argonne premium coals: pure components and mixtures

Sorption and desorption behaviour of methane, carbon dioxide, and mixtures of the two gases has been studied on a set of well-characterised coals from the Argonne Premium Coal Programme. The coal samples cover a maturity range from 0.25% to 1.68% vitrinite reflectance. The maceral compositions were dominated by vitrinite (85% to 91%). Inertinite contents ranged from 8% to 11% and liptinite contents around 1% with one exception (Illinois coal, 5%). All sorption experiments were performed on powdered (−100 mesh), dry coal samples.Single component sorption/desorption measurements were carried out at 22 °C up to final pressures around 51 bar (5.1 MPa) for CO₂ (subcritical state) and 110 bar (11 MPa) for methane.The ratios of the final sorption capacities for pure CO₂ and methane (in molar units) on the five coal samples vary between 1.15 and 3.16. The lowest ratio (1.15) was found for the North Dakota Beulah-Zap lignite (VR_r=0.25%) and the highest ratios (2.7 and 3.16) were encountered for the low-rank coals (VR_r 0.32% and 0.48%) while the ratio decreases to 1.6–1.7 for the highest rank coals in this series.Desorption isotherms for CH₄ and CO₂ were measured immediately after the corresponding sorption isotherms. They generally lie above the sorption isotherms. The degree of hysteresis, i.e. deviation of sorption and desorption isotherms, varies and shows no dependence on coal rank.Adsorption tests with CH₄/CO₂ mixtures were conducted to study the degree of preferential sorption of these two gases on coals of different rank. These experiments were performed on dry coals at 45 °C and pressures up to 180 bar (18 MPa). For the highest rank samples of this sequence preferential sorption behaviour was “as expected”, i.e. preferential adsorption of CO₂ and preferential desorption of CH₄ were observed. For the low rank samples, however, preferential adsorption of CH₄ was found in the low pressure range and preferential desorption of CO₂ over the entire pressure range.Follow-up tests for single gas CO₂ sorption measurements consistently showed a significant increase in sorption capacity for re-runs on the same sample. This phenomenon could be due to extraction of volatile coal components by CO₂ in the first experiment. Reproducibility tests with methane and CO₂ using fresh sample material in each experiment did not show this effect.     

Selection of coals of different maturities for CO2 Storage by modelling of CH4 and CO2 adsorption isotherms

CO₂ injection in unmineable coal seams could be one interesting option for both storage and methane recovery processes. The objective of this study is to compare and model pure gas sorption isotherms (CO₂ and CH₄) for well-characterised coals of different maturities to determine the most suitable coal for CO₂ storage. Carbon dioxide and methane adsorption on several coals have been investigated using a gravimetric adsorption method. The experiments were carried out using both CO₂ and CH₄ pure gases at 25 °C from 0.1 to 5 MPa (1 to 50 bar). The experimental results were fitted using Temkin's approach but also with the corrected Langmuir's and the corrected Tóth's equations. The two last approaches are more accurate from a thermodynamical point of view, and have the advantage of taking into account the fact that experimental data (isotherms) correspond to excess adsorption capacities. These approaches allow better quantification of the adsorbed gas. Determined CO₂ adsorption capacities are from 0.5 to 2 mmol/g of dry coal. Modelling provides also the affinity parameters of the two gases for the different coals. We have shown these parameters determined with adsorption models could be used for classification and first selection of coals for CO₂ storage. The affinity ratio ranges from a value close to 1 for immature coals to 41 for high rank coals like anthracites. This ratio allows selecting coals having high CO₂ adsorption capacities. In our case, the modelling study of a significant number of coals from various ranks shows that anthracites seem to have the highest CO₂ storage capacities. Our study provides high quality affinity parameters and values of CO₂ and CH₄ adsorption capacities on various coals for the future modelling of CO₂ injection in coal seams.     

Methane and carbon dioxide adsorption–diffusion experiments on coal: upscaling and modeling

Numerical modelling of the processes of CO₂ storage in coal and enhanced coalbed methane (ECBM) production requires information on the kinetics of adsorption and desorption processes. In order to address this issue, the sorption kinetics of CO₂ and CH₄ were studied on a high volatile bituminous Pennsylvanian (Upper Carboniferous) coal (VR_r=0.68%) from the Upper Silesian Basin of Poland in the dry and moisture-equilibrated states. The experiments were conducted on six different grain size fractions, ranging from <0.063 to 3 mm at temperatures of 45 and 32 °C, using a volumetric experimental setup. CO₂ sorption was consistently faster than CH₄ sorption under all experimental conditions. For moist coals, sorption rates of both gases were reduced by a factor of more than 2 with respect to dry coals and the sorption rate was found to be positively correlated with temperature. Generally, adsorption rates decreased with increasing grain size for all experimental conditions.Based on the experimental results, simple bidisperse modelling approaches are proposed for the sorption kinetics of CO₂ and CH₄ that may be readily implemented into reservoir simulators. These approaches consider the combination of two first-order reactions and provide, in contrast to the unipore model, a perfect fit of the experimental pressure decay curves. The results of this modeling approach show that the experimental data can be interpreted in terms of a fast and a slow sorption process. Half-life sorption times as well as the percentage of sorption capacity attributed to each of the two individual steps have been calculated.Further, it was shown that an upscaling of the experimental and modelling results for CO₂ and CH₄ can be achieved by performing experiments on different grain size fractions under the same experimental conditions.In addition to the sorption kinetics, sorption isotherms of the samples with different grain size fractions have been related to the variations in ash and maceral composition of the different grain size fractions.     

CBM and CO2-ECBM related sorption processes in coal: A review

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.     

Displacement behavior of CH4 adsorbed on coals by injecting pure CO2, N2, and CO2–N2 mixture

Gas adsorption isotherms of Akabira coals were established for pure carbon dioxide (CO₂), methane (CH₄), and nitrogen (N₂). Experimental data fit well into the Langmuir model. The ratio of sorption capacity of CO₂, CH₄, and N₂ is 8.5:3.5:1 at a lower pressure (1.2 MPa) regime and becomes 5.5:2:1 when gas pressure increases to 6.0 MPa. The difference in sorption capacity of these three gases is explained by differences in the density of the three gases with increasing pressure. A coal–methane system partially saturated with CH₄ at 2.4 MPa adsorption pressure was experimentally studied. Desorption behavior of CH₄ by injecting pure CO₂ (at 3.0, 4.0, 5.0, and 6.0 MPa), and by injecting the CO₂–N₂ mixture and pure N₂ (at 3.0 and 6.0 MPa) were evaluated. Results indicate that the preferential sorption property of coal for CO₂ is significantly higher than that for CH₄ or N₂. CO₂ injection can displace almost all of the CH₄ adsorbed on coal. When modeling the CH₄–CO₂ binary and CH₂–CO₂–N₂ ternary adsorption system by using the extended Langmuir (EL) equation, the EL model always over-predicted the sorbed CO₂ value with a lower error, while under-predicting the sorbed CH₄ with a higher error. A part of CO₂ may dissolve into the solid organic structure of coal, besides its competitive adsorption with other gases. According to this explanation, the EL coefficients of CO₂ in EL equation were revised. The revised EL model proved to be very accurate in predicting sorbed ratio of multi-component gases on coals.     

Sorption of carbon dioxide–methane mixtures

The paper reports the results of experiments concerning the sorption/desorption processes, observed under laboratory conditions, in two types of coal extracted from operational coal-mines in Poland, using CH₄ and CO₂ to observe their relative inter-reaction with the coal samples when introduced in varying proportions and conditions. Numerous studies concerning the sorption/desorption phenomena have described the operational mechanisms and the relationship of mine gases to the organically-created coal-body in mines. The differences in the behaviour of certain gases is twofold: firstly the essentially different characteristics of CO₂ and CH₄, and secondly the structure of the coal-bed itself: its degree of metamorphism and content of macerals. From the results yielded, it was observed that the divergence of the isotherms of sorption of CH₄ and other gases in comparison with the isotherms of sorption of CO₂ and a CO₂/CH₄ mixture differed and that the curve on the sorption isotherm was more clearly distinct after the introduction of CO₂ molecules to the system: coal with a higher degree of metamorphism—CH₄, which is closely related to the rigidity of the structure according to the level of metamorphism. Since coals with higher carbon content exhibit lower molecular bonding than low-carbonised coals, the characteristic feature of the bonds in the first case is their mobility. Knowledge of the physical and chemical properties of hard coals, as well as their interaction with mining gases, is of great use in solving problems concerned with the extraction of methane from mines or its storage in goafs.     

Methane and carbon dioxide sorption on a set of coals from India

Complete sorption isotherm characteristics of methane and CO₂ were studied on fourteen sub-bituminous to high-volatile bituminous Indian Gondwana coals. The mean vitrinite reflectance values of the coal samples are within the range of 0.64% to 1.30% with varying maceral composition. All isotherms were conducted at 30 °C on dry, powdered coal samples up to a maximum experimental pressure of ~ 7.8 MPa and 5.8 MPa for methane and CO₂, respectively.The nature of the isotherms varied widely within the experimental pressure range with some of the samples remained under-saturated while the others attained saturation. The CO₂ to methane adsorption ratios decreased with the increase in experimental pressure and the overall variation was between 4:1 and 1.5:1 for most of the coals. For both methane and CO₂, the lower-ranked coal samples generally exhibited higher sorption affinity compared to the higher-ranked coals. However, sorption capacity indicates a U-shaped trend with rank. Significant hysteresis was observed between the ad/desorption isotherms for CO₂. However, with methane, hysteresis was either absent or insignificant. It was also observed that the coal maceral compositions had a significant impact on the sorption capacities for both methane and CO₂. Coals with higher vitrinite contents showed higher capacities while internite content indicated a negative impact on the sorption capacity.     

Development of the first coal seam gas exploration program in Indonesia: Reservoir properties of the Muaraenim Formation, south Sumatra

The Late Miocene Muaraenim Formation in southern Sumatra contains thick coal sequences, mostly of low rank ranging from lignite to sub-bituminous, and it is believed that these thick low rank coals are the most prospective for the production of coal seam gas (CSG), otherwise known as coalbed methane (CBM), in Indonesia.As part of a major CSG exploration project, gas exploration drilling operations are being undertaken in Rambutan Gasfields in the Muaraenim Formation to characterize the CSG potential of the coals. The first stage of the project, which is described here, was designed to examine the gas reservoir properties with a focus on coal gas storage capacity and compositional properties. Some five CSG exploration boreholes were drilled in the Rambutan Gasfield, south of Palembang. The exploration boreholes were drilled to depths of ~ 1000 m into the Muaraenim Formation. Five major coal seams were intersected by these holes between the depths of 450 and 1000 m. The petrography of coal samples collected from these seams showed that they are vitrinite rich, with vitrinite contents of more than 75% (on a mineral and moisture free basis). Gas contents of up to 5.8 m³/t were measured for the coal samples. The gas desorbed from coal samples contain mainly methane (CH₄) ranging from 80 to 93% and carbon dioxide (CO₂) ranging from 6 to 19%. The composition of the gas released into the production borehole/well is, however, much richer in CH₄ with about 94 to 98% CH₄ and less than 5% CO₂.The initial results of drilling and reservoir characterization studies indicate suitable gas recovery parameters for three of the five coal seams with a total thickness of more than 30 m.     

Flue gas and pure CO2 sorption properties of coal: A comparative study

Presently many research projects focus on the reduction of anthropogenic CO₂ emissions. It is intended to apply underground storage techniques such as flue gas injection in unminable coal seams. In this context, an experimental study has been performed on the adsorption of pure CO₂ and preferential sorption behavior of flue gas. A coal sample from the Silesian Basin in Poland (0.68% V Rr), measured in the dry and wet state at 353 K has been chosen for this approach. The flue gas used was a custom class industrial flue gas with 10.9% of CO₂, 0.01% of CO, 9% of H₂, 3.01% of CH₄, 3.0% of O₂, 0.106% of SO₂ and nitrogen as balance.Adsorption isotherms of CO₂ and flue gas were measured upto a maximum of 11 MPa using a volumetric method. Total excess sorption capacities for CO₂ on dry and wet Silesia coal ranged between 1.9 and 1.3 mmol/g, respectively. Flue gas sorption capacities on dry and wet Silesia coal were much lower and ranged between 0.45 and 0.2 mmol/g, respectively, at pressures of 8 MPa. The low sorption capacity of wet coal has resulted from water occupying some of the more active adsorption sites and hence reducing the heterogeneity of adsorption sites relative to that of dry coal. Desorption tests with flue gas were conducted to study the degree of preferential sorption of the individual components. These experiments indicate that CO₂ is by far the prefered sorbing component under both wet and dry conditions. This is followed by CH₄. N₂ adsorbs very little on the coal in the presence of CO₂ and CH₄. It is also observed that the adsorption of CO₂ onto coal is not significantly hindered by the addition of other gases, other than dilution effect of the pressure.In addition to the sorption experiments, the density of the flue gas mixture has been determined up to 18 MPa at 318 K. A very good precision of these measurements were documented by volumetric methods.     

Interpretation of carbon dioxide diffusion behavior in coals

Storage of carbon dioxide in geological formations is for many countries one of the options to reduce greenhouse gas emissions and thus to satisfy the Kyoto agreements. The CO₂ storage in unminable coal seams has the advantage that it stores CO₂ emissions from industrial processes and can be used to enhance coalbed methane recovery (CO₂-ECBM). For this purpose, the storage capacity of coal is an important reservoir parameter. While the amount of CO₂ sorption data on various natural coals has increased in recent years, only few measurements have been performed to estimate the rate of CO₂ sorption under reservoir conditions. An understanding of gas transport is crucial for processes associated with CO₂ injection, storage and enhanced coalbed methane (ECBM) production.A volumetric experimental set-up has been used to determine the rate of sorption of carbon dioxide in coal particles at various pressures and various grain size fractions. The pressure history during each pressure step was measured. The measurements are interpreted in terms of temperature relaxation and transport/sorption processes within the coal particles. The characteristic times of sorption increase with increasing pressure. No clear dependence of the characteristic time with respect to the particle size was found. At low pressures (below 1 MPa) fast gas diffusion is the prevailing mechanism for sorption, whereas at higher pressures, the slow diffusion process controls the gas uptake by the coal.     

On the effects of petrographic composition on coalbed methane sorption

The effect of petrographic composition on the methane sorption capacity has been determined for a suite of coals and organic-rich shales. Subbituminous and bituminous coals were separated into bright and dull lithotypes by hand-picking. The methane sorption capacities range between 0.5 and 23.9 cm³/g at a pressure of 6 MPa. The low volatile bituminous Canmore coal and the anthracite sample have the highest capacities with the “natural coke” having the lowest. For low-rank coals there is no significant difference between bright and dull samples except for one coal with the dull sample having a greater sorption capacity than its bright equivalent. For higher-rank coals, the bright samples have a greater methane capacity than the dull samples and the difference between sample pairs increases with rank. The boghead coal samples have the highest sorption capacities in the liptinite-rich coals suite and are higher than subbituminous to medium volatile bituminous samples. Pore size distribution indicates that methane is held as solution gas in liptinite-rich coals and by physical sorption in micropores in liptinite-poor coals. These contrasting processes illustrate that liptinite-rich samples need to be independently assessed. The positive relationship between reactive inertinite content and methane sorption capacity occurs within the subbituminous to medium volatile bituminous coals because the reactive inertinite is structurally similar to vitrinite and have a higher microporosity than non-reactive inertinite. Reactivity of inertinite should be assessed in CBM studies of dull coals to provide a better understanding of petrographic composition effects on methane capacity.     

Properties of thermally metamorphosed coal from Tanjung Enim Area, South Sumatra Basin, Indonesia with special reference to the coalification path of macerals

Thermally metamorphosed Tertiary age coals from Tanjung Enim in South Sumatra Basin have been investigated by means of petrographic, mineralogical and chemical analyses. These coals were influenced by heat from an andesitic igneous intrusion. The original coal outside the metamorphosed zone is characterized by high moisture content (4.13–11.25 wt.%) and volatile matter content (> 40 wt.%, daf), as well as less than 80 wt.% (daf) carbon and low vitrinite reflectance (VR_max = 0.52–0.76%). Those coals are of subbituminous and high volatile bituminous rank. In contrast the thermally metamorphosed coals are of medium-volatile bituminous to meta-anthracite rank and characterized by low moisture content (only < 3 wt.%) and volatile matter content (< 24 wt.%, daf), as well as high carbon content (> 80 wt.%, daf) and vitrinite reflectance (VR_max = 1.87–6.20%). All the studied coals have a low mineral matter content, except for those which are highly metamorphosed, due to the formation of new minerals.The coalification path of each maceral shows that vitrinite, liptinite and inertinite reflectance converge in a transition zone at VR_max of around 1.5%. Significant decrease of volatile matter occurs in the zone between 0.5% and 2.0% VR_max. A sharp bend occurs at VR_max between 2.0% and 2.5%. Above 2.5%, the volatile matter decreases only very slightly. Between VR_r = 0.5% and 2.0%, the carbon content of the coals is ascending drastically. Above 2.5% VR_r, the carbon content becomes relatively stable (around 95 wt.%, daf).Vitrinite is the most abundant maceral in low rank coal (69.6–86.2 vol.%). Liptinite and inertinite are minor constituents. In the high rank coal, the thermally altered vitrinite composes 82.4–93.8 vol.%. Mosaic structures can be recognized as groundmasss and crack fillings. The most common minerals found are carbonates, pyrite or marcasite and clay minerals. The latter consist of kaolinite in low rank coal and illite and rectorite in high rank coal. Change of functional groups with rank increase is reflected most of all by the increase of the ratio of aromatic C–H to aliphatic C–H absorbances based on FTIR analysis. The Oxygen Index values of all studied coals are low (OI < 5 mg CO₂/g TOC) and the high rank coals have a lower Hydrogen Index (< 130 mg HC/g TOC) than the low rank coals (about 300 mg HC/g TOC). T_max increases with maturity (420–440 °C for low rank coals and 475–551 °C for high rank coals).Based on the above data, it was calculated that the temperature of contact metamorphism reached 700–750 °C in the most metamorphosed coal.     

Predicted CO2 emissions from maceral concentrates of high volatile bituminous Kentucky and Illinois coals

A large collection of well-characterized coals, documented in the Center for Applied Energy Research's (CAER) database, was used to estimate the CO₂ content of maceral concentrates from Kentucky and Illinois high volatile bituminous coals. The data showed no correlation between CO₂ versus coal ranks and between CO₂ versus maceral content. Subsequently, eight sets of low-ash density-gradient centrifugation (DGC) maceral concentrates from five coal beds were examined, spanning in the high volatile rank range. Heating value was not determined on the concentrates, but instead was calculated using the Mott–Spooner formula. There was a good correlation between predicted CO₂ and maceral content for the individual iso-rank (based on vitrinite reflectance, analyzed on whole (parent) coal) sets. In general, the predicted CO₂ increases from liptinite-rich through vitrinite-rich to inertinite-rich concentrates (note: no “concentrates” are absolutely monomaceral).     

The use of numerical simulation in predicting coalbed methane producibility from the Gates coals, Alberta Inner Foothills, Canada: Comparison with Mannville coal CBM production in the Alberta Syncline

Two medium to low volatile bituminous rank coals in the Lower Cretaceous Gates Formation (Mannville equivalent), Inner Foothills of Alberta, were cored as part of a coalbed methane exploration program. The target seams (Seam 4 and Seam 10) were intersected at 652 m and 605 m, respectively. The coals were bright banded, relatively competent and reasonably cleated, with cleat spacing between 5–20 mm. The FMI (Formation Micro-Imaging) log identified two primary fracture directions, corresponding to both face and butt cleats, which were developed almost equally in some coal intervals. The amount of shearing was limited, in spite of the presence of numerous thrust faults and fold structures in the corehole vicinity. Total gas content was high, with an average of 17.7 cm³/g (arb; 568.1 scf/t). An adsorption isotherm of the thick Seam 4 showed gas saturation levels of 90% at in-situ reservoir conditions. Methane content was 92–96% and carbon dioxide levels were less than 2%. Isotopic studies on the methane confirmed the thermogenic origin of the gas, as anticipated based on the coal rank. The coal seams were fracture stimulated using 50/50 nitrogen and fresh water along with 9 to 12 tons of 12/20 mesh sand used as a proppant. It is believed that the coals were not stimulated properly because of the small proppant volume and the complex — and often unpredictable — fracture pattern in coals, particularly in the Inner Foothills region that has high stress anisotropy. An injectivity test showed coal absolute permeability to be less than 1 mD, the skin to be −  2 (indicating a slightly damaged coal) and water saturation in the cleats to be 90%. A four-month production test was conducted; gas rates declined from 930 to 310 m³/d (33 to 11 MCFD) and water rates were low (< 5 BWD). Produced water was saline (TDS was 20,000 mg/L) and high in chloride and bicarbonate ions. Production testing was followed by history matching and numerical simulation, which consisted of numerous vertical and horizontal well development scenarios and other parameters. Simulating multiple parallel horizontal wells in the Gates coals resulted in the highest peak gas production rates, cumulative production and recovery efficiencies, in agreement with public data from the Mannville coals in the deeper part of the Alberta Syncline. The positive effect of constructive interference in depressurizing the coal reservoirs and accelerating gas production over short periods of time was demonstrated. Coal quality data from a nearby underground mine shows that drilling horizontal wellbores in the Gates coals would be challenging because of unfavourable geomechanical properties, such as low cohesion and unconfined compressive strength values, and structural complexity.     

Impact of experimental parameters for manometric equipment on CO2 isotherms measured: Comment on “Inter-laboratory comparison II: CO2 isotherms measured on moisture-equilibrated Argonne premium coals at 55°C and up to 15 MPa” by Goodman et al. (2007)

Modelling the sorption properties of coals for carbon dioxide under supercritical conditions is necessary for accurate prediction of the sequestering ability of coals in seams. We present recent data for sorption curves of three dry Argonne Premium coals, for carbon dioxide, methane and nitrogen at two different temperatures at pressures up to 15 MPa. The sorption capacity of coals tends to decrease with increasing temperature. An investigation into literature values for sorption of nitrogen and methane by charcoal also show sorption capacities that decrease dramatically with increasing temperature. This is inconsistent with expectations from Langmuir models of coal sorption, which predict a sorption capacity that is independent of temperature. We have successfully fitted the isotherms using a modified Dubinin–Radushkevich equation that uses gas density rather than pressure. A simple pore-filling model that assumes there is a maximum pore width that can be filled in supercritical conditions and that this maximum pore width decreases with increasing temperature, can explain this temperature dependence of sorption capacity. It can also explain why different supercritical gases give apparently different surface sorption capacities on the same material. The calculated heat of sorption for these gases on these coals is similar to those found for these gases on activated carbon.     

Physical properties of selected block Argonne Premium bituminous coal related to CO2, CH4, and N2 adsorption

CO₂, CH₄, and N₂ adsorption and gas-induced swelling were quantified for block Blind Canyon, Pittsburgh #8 and Pocahontas Argonne Premium coals that were dried and structurally relaxed at 75 °C in vacuum. Strain measurements were made perpendicular and parallel to the bedding plane on ~ 7 × 7 × 7 mm³ coal blocks and gravimetric sorption measurements were obtained simultaneously on companion coal blocks exposed to the same gaseous environment. The adsorption amount and strain were determined after equilibration at P  ≤ 1.8 MPa. There is a strong non-linear correlation between strain and the quantity of gas adsorbed and the results for all gases and coals studied follow a common pattern. The dependence of the coal matrix shrinkage/swelling coefficient (C_gc) on the type and quantity of gas adsorbed is seen by plotting the ratio between the strain and the adsorbate concentration against the adsorbate concentration. In general, C_gc increases with increasing adsorbate concentration over the range of ~ 0.1 to 1.4 mmol/g. Results from the dried block coals are compared to CO₂ experiments using native coals with an inherent level of moisture as received. The amount of CO₂ adsorbed using native coals (assuming no displacement of H₂O by CO₂) is significantly less than the dried coals. The gas-induced strain (S) and adsorption amount (M) were measured as a function of time following step changes in CO₂, CH₄, and N₂ pressure from vacuum to 1.8 MPa. An empirical diffusion equation was applied to the kinetic data to obtain the exponent (n) for time dependence for each experiment. The data for all coals were pooled and the exponent (n) evaluated using an ANOVA statistical analysis method. Values for (n) near 0.5 were found to be independent on the coal, the gas or type of measurement (e.g., parallel strain, perpendicular strain, and gas uptake). These data support the use of a Fickian diffusion model framework for kinetic analysis. The kinetic constant k was determined using a unipore diffusion model for each experiment and the data were pooled for ANOVA analysis. For dry coal, statistically significant differences for k were found for the gases (CO₂ > N₂ > CH₄) and coals (Pocahontas >Blind Canyon > Pittsburgh #8) but not for the method of the kinetic measurement (e.g., strain or gas uptake). For Blind Canyon and Pittsburgh #8 coal, the rate of CO₂ adsorption and gas-induced strain for dry coal was significantly greater than that of the corresponding native coal. For Pocahontas coal the rates of CO₂ adsorption and gas-induced strain for dry and native coal were indistinguishable and may be related to its low native moisture and minimal amount of created porosity upon drying.     

Adsorption of NO, SO2 and light hydrocarbons on activated Greek brown coals

Twenty-eight samples of peat, peaty lignites and lignites (of both matrix and xylite-rich lithotypes) and subbituminous coals have been physically activated by pyrolysis. The results show that the surface area of the activated coal samples increases substantially and the higher the carbon content of the samples the higher the surface area.The adsorption capacity of the activated coals for NO, SO₂, C₃H₆ and a mixture of light hydrocarbons (CH₄, C₂H₆, C₃H₈ and C₄H₁₀) at various temperatures was measured on selected samples. The result shows a positive correlation between the surface area and the gas adsorption. In contrast, the gas adsorption is inversely correlated with the temperature. The maximum recorded adsorption values are: NO = 8.22 × 10^− 5 mol/g at 35 °C; SO₂ = 38.65 × 10^− 5 mol/g at 60 °C; C₃H₆ = 38.9 × 10^− 5 mol/g at 35 °C; and light hydrocarbons = 19.24 × 10^− 5 mol/g at 35 °C. Adsorption of C₃H₆ cannot be correlated with either NO or SO₂. However, there is a significant positive correlation between NO and SO₂ adsorptions. The long chain hydrocarbons are preferentially adsorbed on activated lignites as compared to the short chain hydrocarbons.The results also suggest a positive correlation between surface area and the content of telohuminite maceral sub-group above the level of 45%.     

Fault–valve action and vein development during strike–slip faulting: An example from the Ribeira Shear Zone, Southeastern Brazil

Fluid inclusion microthermometry and structural data are presented for quartz vein systems of a major dextral transcurrent shear zone of Neoproterozoic–Cambrian age in the Ribeira River Valley area, southeastern Brazil. Geometric and microstructural constraints indicate that foliation–parallel and extensional veins were formed during dextral strike–slip faulting. Both vein systems are formed essentially by quartz and lesser contents of sulfides and carbonates, and were crystallized in the presence of CO₂–CH₄ and H₂O–CO₂–CH₄–NaCl immiscible fluids following unmixing from a homogeneous parental fluid. Contrasting fluid entrapment conditions indicate that the two vein systems were formed in different structural levels. Foliation–parallel veins were precipitated beneath the seismogenic zone under pressure fluctuating from moderately sublithostatic to moderately subhydrostatic values (319–397 °C and 47–215 MPa), which is compatible with predicted fluid pressure cycle curves derived from fault–valve action. Growth of extensional veins occurred in shallower structural levels, under pressure fluctuating from near hydrostatic to moderately subhydrostatic values (207–218 °C and 18–74 MPa), which indicate that precipitation occurred within the near surface hydrostatically pressured seismogenic zone. Fluid immiscibility and precipitation of quartz in foliation–parallel veins resulted from fluid pressure drop immediately after earthquake rupture. Fluid immiscibility following a local pressure drop during extensional veining occurred in pre-seismic stages in response to the development of fracture porosity in the dilatant zone. Late stages of fluid circulation within the fault zone are represented dominantly by low to high salinity (0.2 to 44 wt.% equivalent NaCl) H₂O–NaCl–CaCl₂ fluid inclusions trapped in healed fractures mainly in foliation–parallel veins, which also exhibit subordinate H₂O–NaCl–CaCl₂, CO₂–(CH₄) and H₂O–CO₂–(CH₄)–NaCl fluid inclusions trapped under subsolvus conditions in single healed microcracks. Recurrent circulation of aqueous–carbonic fluids and aqueous fluids of highly contrasting salinities during veining and post-veining stages suggests that fluids of different reservoirs were pumped to the ruptured fault zone during faulting episodes. A fluid evolution trending toward CH₄ depletion for CO₂–CH₄–bearing fluids and salinity depletion and dilution (approximation of the system H₂O–NaCl) for aqueous–saline fluids occurred concomitantly with decrease in temperature and pressure related to fluid entrapment in progressively shallower structural levels reflecting the shear zone exhumation history.     

Gas–water–rock interactions in sedimentary basins: CO2 sequestration in the Frio Formation, Texas, USA

To investigate the potential for the geologic storage of CO₂ in saline sedimentary aquifers, 1600 ton of CO₂ were injected at 1500 m depth into a 24-m sandstone section of the Frio Formation — a regional reservoir in the US Gulf Coast. Fluid samples obtained from the injection and observation wells before, during and after CO₂ injection show a Na–Ca–Cl type brine with 93,000 mg/L TDS and near saturation of CH₄ at reservoir conditions. As injected CO₂ gas reached the observation well, results showed sharp drops in pH (6.5 to 5.7), pronounced increases in alkalinity (100 to 3000 mg/L as HCO₃) and Fe (30 to 1100 mg/L), and significant shifts in the isotopic compositions of H₂O and DIC. Geochemical modeling indicates that brine pH would have dropped lower, but for buffering by dissolution of calcite and Fe oxyhydroxides. Post-injection results show the brine gradually returning to its pre-injection composition.     

Contact angles in CO2-water-coal systems at elevated pressures

Injection of carbon dioxide into coal seams is considered to be a potential method for its sequestration away from the atmosphere. However, water present in coals may retard injection: especially if carbon dioxide does not wet the coal as well as water. Thus contact angles in the coal-water-CO₂ system were measured using CO₂ bubbles in water/coal systems at 40 °C and pressures up to 15 MPa using five bituminous coals. At low pressures, in this CO₂/water/coal system, receding contact angles for the coals ranged between 80° to 100°; except for one coal that had both high ash yield and low rank, with a contact angle of 115°, indicating that it was hydrophilic. With increasing pressure, the receding contact angles for the different coals decreased, indicating that they became more CO₂-wetting. The relationship between contact angle and pressure was approximately linear. For low ash or high rank coals, at high pressure the contact angle was reduced to 30-50°, indicating the coals became strongly CO₂-wetting; that is CO₂ fluids will spontaneously penetrate these wet coals. In the case of the coal that was both high ash and hydrophilic, the contact angle did not drop to 90° even at the highest pressures used. These results suggest that CO₂ will not be efficiently adsorbed by all wet coals equally well, even at high pressure. It was found that at high pressures (> 2 MPa) the rate of penetration of carbon dioxide into the coals increased rapidly with decreasing contact angle, independently of pressure. Injecting CO₂ into wet coals that have both low rank and high ash will not trap CO₂ as well as injecting it into high rank or low ash coals.