Regional evaluation of the coalbed-methane potential of the Foothills/Mountains of Alberta,Canada

Coal is present in the Alberta Foothills/Mountains in five zones: the Kootenay, Gething, Gates, Brazeau and Coalspur coal zones. For coalbed-methane (CBM) evaluation purposes, they can be divided into shallow (less than 1000 m depth) and deep (greater than 1000 m depth) coal zones. The potential gas content of all shallow coal zones totals about 878 × 10⁹ m³ (31 Tcf) of CBM, which is considered an inferred, initial, in-place, coalbed-methane resource estimate based on limited data. The limited amount of data on formation testing and measured gas content indicate that the inferred resource is bordering on the speculative category.The gas content of all deep coal zones (deeper than 1000 m) totals 2.8 × 10¹² m³ (about 99 Tcf) of in-place coalbed-methane gas. Consequently, the total ultimate coalbed-methane resource could be 3.7 × 10¹² m³ (130 Tcf). However, coalbed-methane recovery from deep coals is generally not attempted because of the high cost of drilling and the low permeability that results from high overburden load and stress.The only (limited) Foothills coalbed-methane production has been from the southern Alberta Kootenay Coal Zone, which is very prospective for coalbed-methane production. The shallow Gates Coal Zone in the central and northern Foothills is also prospective, but needs to be better tested. The best potential for coalbed methane in the Coalspur Coal Zone is in the Edson area (Entrance Syncline and Triangle Zone). The Kootenay and Gates coal zones are not well defined in the northern part of the Calgary (NTS 82O) map sheet.     

Preliminary hydrogeological assessment of Late Cretaceous–Tertiary Ardley coals in part of the Alberta Basin,Alberta, Canada

A preliminary hydrogeological evaluation was undertaken on the gas potential of shallow coals in the Pembina–Warburg exploration area in the Alberta Basin, Alberta Canada. Regional data for the Late Cretaceous–Tertiary Ardley Coal Zone (ACZ) were compiled and supplemented with site-specific data collected from a key test- well drilled as part of a regional exploration program. Limited regional pressure data suggest hydraulic communication between the uppermost Ardley with the overlying Paskapoo Formation. A comparison between hydraulic head and topography suggests that flow, at least in part of the Ardley–Paskapoo, is gravity driven. However, a decoupling of the hydraulic regime appears evident from pressure test data in beds stratigraphically below the uppermost Scollard (Ardley) and above the base of Scollard at least in the eastern part of the study area where the test-well was drilled. The decoupling is evident in regional pressure data but the precise stratigraphic position may vary.Regionally, formation waters typically are Na–HCO₃ type with salinities (as TDS) of less than 2000 mg/L. Anomalously high bicarbonate (dissolved inorganic carbon or DIC) concentrations exceeding 1500 mg/L with δ¹³C_DIC + 22.50‰ and dissolved methane identified in formation waters collected directly from Ardley coal in test-well 103 point to the presence of secondary biogenic gas. The ¹³C isotopes for DIC, coupled with ¹⁸O and ²H isotopes for associated groundwater and regional hydraulic data, suggest that the uppermost Ardley Coal Zone in the eastern part of the study area is part of a regional, topographically driven, dynamic flow system in which methanogenic processes are modifying groundwater chemistry and gas charging parts of the area. Whether or not biogenic gas-charging in the Ardley is pervasive is uncertain. The relatively small coal data set requires that further exploration in the study area should consider the presence of microbial gas and the potential for hydrogeological controls on its distribution. However, further detailed testing will be necessary to develop a consistent and useful database for exploration and development.     

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.     

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.     

The structural evolution of organic matter during maturation of coals and its impact on petroleum potential and feedstock for the deep biosphere

The structural evolution of coals during coalification from peat to the end of the high volatile bituminous coal rank (VR_r = 0.22–0.81%) has been studied using a natural maturity series from New Zealand. Samples were studied using a range of standard coal analyses, Rock–Eval analysis, infrared spectroscopy (IR), X-ray photoelectron spectroscopy (XPS), and pyrolysis gas chromatography (Py-GC). The structural evolution of coal during diagenesis and moderate catagenesis is dominated by defunctionalisation reactions leading to the release of significant amounts of oxygen and thereby to an enrichment of aromatic as well as aliphatic structures within the residual organic matter. Based on the evolution of pyrolysis yields and elemental compositions with maturity it can be demonstrated that oxygen loss is the major cause for increasing Hydrogen Index values or hydrocarbon generating potentials of coals at such maturity levels. For the first time, the loss of oxygen in form of CO₂ has been quantified. During maturation from peat to high volatile bituminous coal ranks ∼10–105 mg CO₂/g TOC has been released. This is equivalent to 2.50E−4 to 1.25E−3 mg CO₂ generated from every litre of sediment per year falling into the range of deep biosphere utilisation rates. Immature coals, here New Zealand coals, therefore manifest the potential to feed deep terrestrial microbial life, in contrast to more mature coals (VR_r > ∼0.81%) for which defunctionalisation processes become less important.     

Microporosity in Alberta Plains coals

The nature of porosity in 11 Alberta Plains coals is scanned using different characterization techniques, namely, gas adsorption, helium and mercury displacement, and mercury porosimetry. Surface areas calculated from carbon dioxide adsorption at 25°C (varying between 75 and 506 m²/g) are consistently higher than those calculated from nitrogen at −196°C (varying between 1 and 9 m²/g). The samples from Paskapoo deposits have slightly higher surface areas as compared to samples from Horseshoe Canyon deposits. The carbon content in the tested coals (73.4 to 76.8%) is too narrow of range to determine the influence of this parameter on surface area and porosity.Total pore volumes are measured in the range 1.2 to 3000 nm and then divided into macropores (30 to 3000 nm), transitional pores (1.2 to 30 nm) and micropores (less than 1.2 nm). Almost all the surface area in coals is located in the micropores. Coals vary widely in their total pore volumes and porosities range between 9.5 and 22.3%. Percent pore volume contained in micropores varies between 29.5 and 75.9, in transitional pores between 1.1 and 20.5 and in macropores between 18.5 and 50.0.     

A preliminary study of mineralogy and geochemistry of four coal samples from northern Iran

This study is related to four Jurassic-age bituminous coal (0.69–1.02 Ro%) samples collected from coal mines from the west, central and east of central, Alborz in northern Iran. Geological settings played key roles in determining the geochemistry and mineralogy of coals from the central Alborz region of northern Iran. The mineralogy of coals from the eastern part of the region is dominated by kaolinite; halloysite; and carbonates such as calcite, dolomite/ankerite, and siderite. The coals were deposited in a lacustrine environment. In the western part of the region, where the depositional setting was also lacustrine with volcanic input and tonstein deposition (glass shards present), the coal primarily contains kaolinite (68%) and fluorapatite (26%). In contrast, coal from the central part of the region, which was deposited in a terrestrial environment and on eroded limestone and dolomite rocks, is dominated by dolomite (98%) with little input by kaolinite. These coals have low sulphur (0.35–0.70 wt.%), which is mostly in the organic form (0.34–0.69 wt.%). Pyritic sulphur is detected only in one coal and in small quantities. The boron contents of these coals range from 9 to 33 mg/kg, indicating that deposition occurred in a fresh water environment. Coal with higher concentrations of Ba, Sr, and P contain fluorapatite and goyazite–gorceixite series [BaAl₃ (PO₄)₂ (OH)₅, H₂O] minerals, which indicates volcanoclastic input. Compared to world coal averages, these coals exhibit low concentrations of elements of environmental concern, such as As (1.3–5.9 mg/kg), Cd (< 0.02–0.06 mg/kg), Hg (< 0.01–0.07 mg/kg) Mo (< 0.6–1.7 mg/kg), Pb (4.8–13 mg/kg), Th (0.5–21 mg/kg), Se (< 0.2–0.8 mg/kg) and U (0.2–4.6 mg/kg). Two of the northern Iranian coals have concentrations of Cl (2560 and 3010 mg/kg) that are higher than world coal average.     

Modeling of coal bed methane (CBM) production and CO2 sequestration in coal seams

A mathematical model was developed to predict the coal bed methane (CBM) production and carbon dioxide (CO₂) sequestration in a coal seam accounting for the coal seam properties. The model predictions showed that, for a CBM production and dewatering process, the pressure could be reduced from 15.17 MPa to 1.56 MPa and the gas saturation increased up to 50% in 30 years for a 5.4 × 10⁵ m² of coal formation. For the CO₂ sequestration process, the model prediction showed that the CO₂ injection rate was first reduced and then slightly recovered over 3 to 13 years of injection, which was also evidenced by the actual in seam data. The model predictions indicated that the sweeping of the water in front of the CO₂ flood in the cleat porosity could be important on the loss of injectivity. Further model predictions suggested that the injection rate of CO₂ could be about 11 × 10³ m³ per day; the injected CO₂ would reach the production well, which was separated from the injection well by 826 m, in about 30 years. During this period, about 160 × 10⁶ m³ of CO₂ could be stored within a 21.4 × 10⁵ m² of coal seam with a thickness of 3 m.     

Accumulation models for coalbed methane in medium- to high-rank coals: examples from the southern Qinshui Basin and southeastern Ordos Basin

The majority of known coalbed methane (CBM) production worldwide comes primarily from high-abundance CBM-enrichment areas or ‘fairways.’ The high-abundance CBM-enrichment areas are primarily characterised by large CBM resources with high single-well productions. CBM accumulation areas from the medium- to high-rank coals in the southern Qinshui Basin and the Hancheng CBM fields in the Ordos Basin were investigated based on regional geological analyses and physical analogue experiments. The results show that gas contents in the study areas increase with depths over the range from approximately 300 to 800 m, while permeabilities generally decrease with depths. Intervals with optimal gas content and permeability exist at a moderate depth along an inclined coal seam under the coupled control of temperature and stress. Brittle–ductile transition deformation increases the permeability and the pore-specific surface areas of coals. The gas content and permeability of the CBM reservoirs are shown to be two key factors determining the formation of high-abundance CBM areas. The coupling of gas enrichment and high permeability provides a favourable combination for CBM accumulation and high production. Combining CBM exploration and development practices in the study areas with physical analogue experiments, two CBM-enrichment models for medium- to high-rank coal have been recognised for different geological conditions, including (1) the model controlled by the depth in the slope zone and (2) the model controlled by the coal brittle and ductile in the deformation zones.     

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.     

Mercury distribution in coals influenced by magmatic intrusions,and surface waters from the Huaibei Coal Mining District,Anhui, China

The Hg concentrations in 108 samples, comprising 81 coal samples, 1 igneous rock, 2 parting rock samples and 24 water samples from the Huaibei Coal Mining District, China, were determined by cold-vapor atomic fluorescence spectrometry. The abundance and distribution of Hg in different coal mines and coal seams were studied. The weighted average Hg concentration for all coal samples in the Huaibei Coalfield is 0.42 mg/kg, which is about twice that of average Chinese coals. From southwestern to northeastern coalfield, Hg concentration shows a decreasing trend, which is presumably related to magmatic activity and fault structures. The relatively high Hg levels are observed in coal seams Nos. 6, 7 and 10 in the southwestern coal mines. Correlation analysis indicates that Hg in the southwestern and southernmost coals with high Hg concentrations is associated with pyrite. The Hg concentrations in surface waters in the Huaibei Coal Mining District range from 10 to 60 ng/L, and display a decreasing trend with distance from a coal waste pile but are lower than the regulated levels for Hg in drinking water.     

Characterization of the CO2 fluid adsorption in coal as a function of pressure using neutron scattering techniques (SANS and USANS)

Small angle neutron scattering techniques have been applied to investigate the phase behavior of CO₂ injected into coal and possible changes in the coal pore structure that may result from this injection. Three coals were selected for this study: the Seelyville coal from the Illinois Basin (R_o = 0.53%), Baralaba coal from the Bowen Basin (R_o = 0.67%), and Bulli 4 coal from the Sydney Basin (R_o = 1.42%). The coals were selected from different depths to represent the range of the underground CO₂ conditions (from subcritical to supercritical) which may be realized in the deep subsurface environment. The experiments were conducted in a high pressure cell and CO₂ was injected under a range of pressure conditions, including those corresponding to in-situ hydrostatic subsurface conditions for each coal. Our experiments indicate that the porous matrix of all coals remains essentially unchanged after exposure to CO₂ at pressures up to 200 bar (1 bar = 10⁵ Pa). Each coal responds differently to the CO₂ exposure and this response appears to be different in pores of various sizes within the same coal. For the Seelyville coal at reservoir conditions (16 °C, 50 bar), CO₂ condenses from a gas into liquid, which leads to increased average fluid density in the pores (ρ_pore) with sizes (r) 1 × 10⁵ ≥ r ≥ 1 × 10⁴ Å (ρ_pore ≈ 0.489 g/cm³) as well as in small pores with size between 30 and 300 Å (ρ_pore ≈ 0.671 g/cm³). These values are by a factor of three to four higher than the density of bulk CO₂ (ρ_CO2) under similar thermodynamic conditions (ρ_CO2 ≈ 0.15 g/cm³). At the same time, in the intermediate size pores with r ≈ 1000 Å the average fluid density is similar to the density of bulk fluid, which indicates that adsorption does not occur in these pores. At in situ conditions for the Baralaba coal (35 ^OC, 100 bar), the average fluid density of CO₂ in all pores is lower than that of the bulk fluid (ρ_pore / ρ_CO2 ≈ 0.6). Neutron scattering from the Bulli 4 coal did not show any significant variation with pressure, a phenomenon which we assign to the extremely small amount of porosity of this coal in the pore size range between 35 and 100,000 Å.     

Chemical and physical properties of iron hydroxide precipitates associated with passively treated coal mine drainage in the Bituminous Region of Pennsylvania and Maryland

Changes in precipitate mineralogy, morphology, and major and trace element concentrations and associations throughout 5 coal mine drainage (CMD) remediation systems treating discharges of varying chemistries were investigated in order to determine the factors that influence the characteristics of precipitates formed in passive systems. The 5 passive treatment systems sampled in this study are located in the bituminous coal fields of western Pennsylvania and northern Maryland, and treat discharges from Pennsylvanian age coals. The precipitates are dominantly (>70%) goethite. Crystallinity varies throughout an individual system, and lower crystallinity is associated with enhanced sorption of trace metals. Degree of crystallinity (and subsequently morphology and trace metal associations) is a function of the treatment system and how rapidly Fe(II) is oxidized, forms precipitates, aggregates and settles. Precipitates formed earlier in the passive treatment systems tend to have the highest crystallinity and the lowest concentrations of trace metal cations. High surface area and cation vacancies within the goethite structure enable sorption and incorporation of metals from coal mine drainage-polluted waters. Sorption affinities follow the order of Zn > Co ≈ Ni > Mn. Cobalt and Ni are preferentially sorbed to Mn oxide phases when these phases are present. As pH increases in the individual CMD treatment systems toward the pH_pzc of goethite, As sorption decreases and transition metal (Co, Mn, Ni and Zn) sorption increases. Sulfate, Na and Fe(II) concentrations may all influence the sorption of trace metals to the Fe hydroxide surface. Results of this study have implications not only for solids disposal and resource recovery but also for the optimization of passive CMD treatment systems.     

The first record of Eocene tuff in a Paleogene rift basin near Nantou,Western Foothills,central Taiwan

Microfossils and a U–Pb age dating on zircon grains in the tuff beds exposed in the axial part of the Tsukeng anticline along the Pinglin River in the Western Foothills near Nantou, central Taiwan, show an occurrence of the Eocene volcanics unconformably beneath the uppermost part of the Latest Oligocene Wuchihshan Formation. This is the first discovery of the Eocene tuff exposed in the Western Foothills.The proposed Miocene “Tsukeng Formation” and “Takeng Formation” of Ho et al. (1956) named for sequences exposed in the Nantou area, Western Foothills, have to be abandoned and the standard Oligocene–Miocene lithostratigraphy used commonly in the Western Foothills of northern Taiwan is properly applicable in central Taiwan. The thick pink–brown–green colored volcanics unconformably beneath the uppermost Wuchihshan Formation is named for the first time as the Pinglin Tuff which contains Late Middle Eocene calcareous nannofossils (Zone NP16) consistent with a U–Pb age dating (38.8 ± 1 Ma) on zircon grains in the tuff. The Pinglin Tuff is overlying the Middle Eocene Chungliao Formation which contains indigenous larger foraminifera Discocyclina dispansa ex. interc. sella-dispansa and calcareous nannofossils of Zones NP14–15. The Middle Eocene Pinglin Tuff and Chungliao Formation represent the Paleogene syn-rift sequence unconformably overlain by the Latest Oligocene–Miocene post-rift sequence. This is the first document with conclusive paleontological data and age dating showing an occurrence of Paleogene marine rift basin exposed in the Western Foothills. This study also confirms similar Tertiary basin architecture between the Taiwan Strait–Pearl River Mouth Basin in the NE South China Sea and the Western Foothills onland central Taiwan.     

Geochemical and mineralogical evidence for a coal-hosted uranium deposit in the Yili Basin,Xinjiang, northwestern China

The petrological, geochemical, and mineralogical compositions of the coal-hosted Jurassic uranium ore deposit in the Yili Basin of Xinjiang province, northwestern China, were investigated using optical microscopy and field emission-scanning electron microscopy in conjunction with an energy-dispersive X-ray spectrometer, as well as X-ray powder diffraction, X-ray fluorescence, and inductively coupled plasma mass spectrometry. The Yili coal is of high volatile C/B bituminous rank (0.51–0.59% vitrinite reflectance) and has a medium sulfur content (1.32% on average). Fusinite and semifusinite generally dominate the maceral assemblage, which exhibits forms suggesting fire-driven formation of those macerals together with forms suggesting degradation of wood followed by burning. The Yili coals are characterized by high concentrations of U (up to 7207 μg/g), Se (up to 253 μg/g), Mo (1248 μg/g), and Re (up to 34 μg/g), as well as As (up to 234 μg/g) and Hg (up to 3858 ng/g). Relative to the upper continental crust, the rare earth elements (REEs) in the coals are characterized by heavy or/and medium REE enrichment. The minerals in the Yili coals are mainly quartz, kaolinite, illite and illite/smectite, as well as, to a lesser extent, K-feldspar, chlorite, pyrite, and trace amounts of calcite, dolomite, amphibole, millerite, chalcopyrite, cattierite, siegenite, ferroselite, krutaite, eskebornite, pitchblende, coffinite, silicorhabdophane, and zircon. The enrichment and modes of occurrence of the trace elements, and also of the minerals in the coal, are attributed to derivation from a sediment source region of felsic and intermediate petrological composition, and to two different later-stage solutions (a U–Se–Mo–Re rich infiltrational and a Hg–As-rich exfiltrational volcanogenic solution). The main elements with high enrichment factors, U, Se, As, and Hg, overall exhibit a mixed organic–inorganic affinity. The uranium minerals, pitchblende and coffinite, occur as cavity-fillings in structured inertinite macerals. Selenium, As, and Hg in high-pyrite samples mainly show a sulfide affinity.     

Significance of indigenous Eocene larger foraminifera Discocyclina dispansa in Western Foothills,Central Taiwan: A Paleogene marine rift basin in Chinese continental margin

The Western Foothills of Taiwan was known to be composed of Late Oligocene to Pleistocene shallow marine strata continuously deposited on the stable passive Chinese continental margin without significant stratigraphic break. Here we present multiple micropaleontological evidences, including occurrence of larger foraminifera Discocyclina dispansa ex. interc. sella-dispansa and calcareous nannoplanktons, to show that there are Middle Eocene marine strata (first named as the Chungliao Formation) exposed in the Tsukeng anticline of the Western Foothills, central Taiwan. Occurrences of intact tests with thin delicate outer rims and well-preserved embryonic chambers suggest that the Discocyclina dispansa ex. interc. sella-dispansa (Lutetian to Bartonian in the Tethys region) are buried indigenously on shallow inner shelf during an episodic transgression in the Early Middle Eocene. The conclusion is consistent with a biostratigraphy study of calcareous nannoplanktons (Zones NP14–15) in the shale/sandstone alternations overlying the Discocyclina-bearing bed of the Chungliao Formation and calcareous nannofossils of Zone NP16 integrated with an age dating of 38.8 ± 1 Ma (Late Middle Eocene) on zircon grains of the overlying Pinglin Tuff. The Middle Eocene syn-rift sequences (Chungliao Formation and Pinglin Tuff) exposed along the Tsukeng anticline are unconformably covered by the latest Oligocene–Miocene post-rift sequence, a scenario similar to what have been drilled in the East China Sea-Taiwan Strait-South China Sea. This rift basin (named as the Nantou Basin) is sitting on the Peikang Basement High margin which further extends southwestward to the Central Uplift of the Pearl River Mouth Basin in the northern slope of the South China Sea. The present work documents a hitherto unknown occurrence of the exposed early Tertiary marine rift basin sequence in the Western Foothills of Taiwan. The study extends our knowledge of the Western Foothills geohistory from the Late Oligocene downward to the Early Middle Eocene. The occurrence of the Paleogene Nantou rift basin in the Western Foothills may also suggest that there could have similar Paleogene rift sequences exposed in other parts of the Taiwan mountain belt like the Hsüehshan Range and the Central Range east of the Western Foothills.     

煤层气地质学新进展

自20世纪80年代以来,我国的煤层气勘探取得了突破性进展。在沁水盆地南部获得了可观的煤层气地质储量;河东煤田的煤层气勘探也取得了重大进展。煤层气地质学研究取得了明显进展:a 煤储层岩石物理研究取得重要进展;b 提出了煤层气藏的概念并依据我国的煤层气地质条件识别出几种主要煤层气藏类型;c 深化了对煤层气藏封闭保存条件的认识,充分认识到煤层气耗散对煤层气封闭保存的重要影响。d 对高煤阶煤层气藏研究有了突破性进展,突破了无烟煤勘探煤层气的禁区,获得了可观的煤层气地质储量;e 强化了低煤阶煤层气藏的研究;f深化了对煤层气藏不均一性的认识,初步揭示了煤层气藏不均一性的产生原因及其分布规律。      

Formation of carbon nano-balls and carbon nano-tubes from northeast Indian Tertiary coal: Value added products from low grade coal

The paper reports the presence of carbon nano-balls and nano-tubes in the clean coal product during our experiments on desulfurization and deashing of northeast Indian high-sulfur Tertiary coal by molten caustic leaching (MCL) method. The Scanning Electron Microscopy (SEM), High Resolution Transmission Electron Microscopy (HR-TEM), X-ray Diffraction (XRD), Raman and Fourier Transform Infrared (FT-IR) spectroscopy analyses revealed the formation of varied sizes of carbon nanomaterials in the clean coal product (MCL product). The nano-balls are in the range of 5–10 nm with nominal areas in the range of 40–100 nm², 160–220 nm², and 550–650 nm². The diameters of the carbon nano-tubes (CNTs) formed are in the range of 18–24 nm. The diameters of the branch carbon nano-tubes (BCNTs) are in the range of 35–92 nm. It is further observed that the alkaline treatment followed by acid treatment favored the formation of the carbon nano-balls, carbon nano-tubes (CNTs), and branch carbon nanotubes (BCNTs) in the coal product. The low-grade coals could also be used for the preparation of nano-carbon-based high value added products.