The commercial extraction of methane from coal beds is now well established in a number of countries throughout the world, including the USA, Australia, China, India and Canada. Because coal is almost pure carbon, its reservoir character is fundamentally different to conventional gas plays. Coalbed methane (CBM) forms as either biogenically- or thermogenically-derived gas. The former occurs in ‘under mature’ (< 0.5% vitrinite reflectance) coals and is the result of bacterial conversion of coal into CO or acetate, which is then transformed by archaea into CH . Thermogenic gas is formed as part of the coalification process and is purely a chemical devolatilization that releases CH . Methane is primarily stored in coal through adsorption onto the coal surface; thus it is pore surface area that determines the maximum gas holding potential of a reservoir (as opposed to pore volume in a conventional reservoir). Although macro-, meso-, and micropores are present in the coal matrix, it is thought that the micropores are where most methane adsorption occurs. In many of the micropores, the methane molecule may actually stretch, minutely, the pore and thus with de-gassing of the reservoir, could result in matrix shrinkage, allowing opening of the fracture (cleat) system in the coal and thus enhancing permeability. The organic composition of the coal is paramount in determining porosity and permeability character and thus maximum gas holding capacity. In general, the higher the vitrinite content the higher the gas holding potential (and ultimately the amount of desorbed gas) and permeability (all other factors being the same). There are other organic component/gas property relationships but these seem to be specific to individual basins, or even seams. Characterising a CBM reservoir during an exploration programme is a challenge but the two most vital measures to determine are permeability and % gas saturation. Permeability will largely determine gas (and water) flow rate, dictating how commercial a prospect might be. Gas saturation, determined from desorption and adsorption measurements, also influences gas rate and the ultimate recoverability of gas from a reservoir. Modelling of gas flow from the reservoir is highly dependent on knowledge of these parameters. Designing a successful pilot well programme and ultimately production wells will rely mostly on the permeability and % gas saturation character. Certification of resources and reserves, which is also very important to CBM companies as they explore and develop their permits, depends heavily on accurate estimates of reservoir character; primarily seam continuity, % gas saturation and permeability. ► Methane in coal can occur as biogenic, thermogenic or as a mix of those gas types. ► Key reservoir parameters are permeability and percent gas saturation. ► Pore surface area is the key parameter maximum gas holding capacity. ► Reservoir properties are influenced to a high degree by the organic composition. ► Well type and placement is crucial for maximum certification value.
High-pressure methane sorption isotherms were measured on selected Paleozoic and Mesozoic organic-rich shales, considered as shale gas targets in Europe. The samples include the Upper Cambrian–Lower Ordovician Alum Shale, Carboniferous (Mississippian–Pennsylvanian) shales and Lower Toarcian Posidonia Shale. In addition, samples from producing shale gas formations in the USA (Barnett, Haynesville and Eagle Ford) were studied for comparison. Excess sorption measurements were performed over an extended range of pressures (up to 25 MPa) and temperatures (up to 150 °C) on dry samples and at 38 °C on moisture-equilibrated samples to study the effect of organic matter content (TOC), maturity, mineralogy and moisture content on the methane sorption capacity. Additionally, water isotherms were measured at 24 °C and at relative humidities (RH) from 8 to 97%. A 3-parameter ( , , ) excess sorption function based on the Langmuir equation for absolute sorption was used to fit the measured methane sorption isotherms. The water sorption isotherms were parameterized by the Guggenheim–Anderson–de Boer (GAB) function. In both cases, excellent fits to the measured data were achieved. The methane sorption capacities of the dry shales show a positive correlation with TOC but significant deviations from this trend exist for individual samples. The TOC-normalized sorption capacities correlate positively with maturity in terms of Vitrinite Reflectance (VR ) up to a certain value of VR (~ 2.5%) above which an opposite trend is observed. No correlation was observed between the clay content and the TOC-normalized sorption capacity to methane, indicating that clay minerals do not significantly contribute to methane sorption in these organic-rich shales. The shape of the excess isotherms changes systematically with temperature and maturity. The Langmuir pressure ( ) increases exponentially with temperature and follows a negative power-law trend with maturity. Compared to dry samples, the sorption capacity in moisture-equilibrated samples (at 97% RH) is reduced by 40 to 60%. No difference is observed between 97% and 75% RH, indicating that the critical moisture content is at or below 75% RH. The monolayer sorption capacities for water obtained from the GAB fit are 0.5 to 3 times those for methane, derived from the Langmuir fit. There is a weak positive correlation between the methane and the water sorption capacity, suggesting that methane and water molecules share some of the sorption sites and these reside partly within the organic matter.
Using a combination of focused ion beam milling and scanning electron microscopy we describe the evolution of secondary organic porosity in eight Woodford Shale (Late Devonian–Early Mississippian) samples with mean random vitrinite reflectance values ranging from 0.51% Ro to 6.36% Ro. Organic porosity was observed to be absent in samples with vitrinite reflectance values of up to 0.90% Ro with the first appearance of secondary pores starting with the 1.23% Ro sample. Porosity in the organic matter was unexpectedly absent in a sample with a vitrinite reflectance of 2.00% Ro; however, organic pores were again found in samples with higher thermal maturities. Porosity, when present, did not appear to be uniformly distributed among the organic matter that was within less than a micron of each other suggesting important differences in composition of the organic matter. Thin regions of organic matter were observed between grains raising the possibility that small amounts of the deposited organic matter were compacted between grains to form thin layers and/or the structures are part of the secondary organic matter (interpreted to be post-oil bitumen) which was left behind as a residue during oil migration through the shale. Some regions of porous organic matter appeared to be grain protected whereas others did not which indicates that these non-protected porous organic regions may be stress supporting with porosity intact under in situ reservoir conditions. These observations suggest that thermal maturity alone is insufficient to predict porosity development in organic shales, and other factors, such as organic matter composition, complicate porosity development. ► Comparison of pore structure in various gas shales ► Organic porosity development over a range of vitrinite reflectance values ► Factors complicating organic porosity development beyond thermal maturity ► Observations on the effect of stress on organic porosity
China will continue to be one of the largest coal producers and users in the world. The high volume of coal use in China has focused attention on the amounts of toxic trace elements released from coal combustions and also the valuable trace elements extracted or potentially utilized from coal ash. Compared to world coals, Chinese coals have normal background values for most trace elements, with the exception of higher Li (31.8 μg/g), Zr (89.5 μg/g), Nb (9.44 μg/g), Ta (0.62 μg/g), Hf (3.71 μg/g), Th (5.84 μg/g), and rare earth elements (∑ La-Lu + Y, 136 μg/g). This is not only due to the higher ash yields of Chinese coals but also to alkali volcanic ashes found in some southwestern coals. The background values of toxic elements of Hg (0.163 μg/g), As (3.79 μg/g), and F (130 μg/g) in Chinese coals are comparable to coals from most other countries. The genetic types for trace-element enrichment of Chinese coals include source-rock- controlled, marine-environment-controlled, hydrothermal-fluid-controlled (including magmatic-, low-temperature-hydrothermal-fluid-, and submarine-exhalation-controlled subtypes), groundwater-controlled, and volcanic-ash-controlled. The background values of trace elements were dominated by sediment source regions. Low-temperature hydrothermal fluid was one of the major factors for the local enrichment of trace elements in southwestern China. Serious human health problems caused by indoor combustion of coal in China include endemic fluorosis, arsenosis, selenosis, and lung cancer. Endemic fluorosis, mainly occurring in western Guizhou, was mostly attributed to the high fluorine in clay that was used as a briquette binder for fine coals, in addition to a small quantity of fluorine from coal. Fluorine in the coal from endemic-fluorosis areas of western Guizhou is within the usual range found in China and the world. Endemic arsenosis in southwestern Guizhou is attributed to indoor combustion of high-As coal. Endemic selenosis in Enshi of Hubei was due to high Se in carbonaceous siliceous rocks and carbonaceous shales. Fine particles of quartz, released into air during coal combustion, are hypothesized as a possible cause for the lung cancer epidemic in Xuanwei, Yunnan, China. Valuable elements, including Ge, Ga, U, REE (rare earth element), Nb, Zr, and Re are concentrated to levels comparable to conventional economic deposits in several coals or coal-bearing strata in China. The Ge deposits at Lincang, Yunnan province and Wulantuga, Inner Mongolia have been exploited and industrially utilized. The enrichment of Ge in the two deposits was caused by hydrothermal fluids associated with adjacent granitoids. The Ga (Al) ore deposit in the Jungar Coalfield, Inner Mongolia, was derived from the neighboring weathered and oxidized bauxite of the Benxi Formation (Pennsylvanian). The Nb(Ta)–Zr(Hf)–REE–Ga deposits in the Late Permian coal-bearing strata of eastern Yunnan and Chongqing of southwestern China were attributed to ashes of the alkali volcanic eruptions.
Methane adsorption in porous carbon systems such as coal and the organic matrix of gas shales is an important factor in determining the feasibility of CO injection for enhanced natural gas recovery and possible sequestration of CO . Methane and CO adsorb competitively on carbon surfaces and an understanding of each gas individually is important for determining a model to predict the feasibility of this approach for permanent CO storage. Coal and gas shales have a very heterogeneous pore system, ranging from the micro, meso, and macro-scales, with the pore size strongly affecting the adsorption behavior. In micropores, the force fields of opposing pore walls are close enough that they will overlap and significantly influence the adsorption behavior, which affects adsorbate packing and density. To determine the size at which these effects become non-negligible and to determine the magnitude of this impact, grand canonical Monte Carlo simulations have been carried out to estimate the adsorption isotherms of methane across a range of pore sizes and at various temperature and pressure conditions characteristic of subsurface conditions. These isotherms have been calculated on graphitic surfaces as an initial model of coal and kerogen of gas shales. The general trend within pore sizes is that larger pores exhibit lower excess density compared to smaller pores. However, at pressure above 1 MPa, the adsorption capacities of 0.6-nm pores drop below those of the wider pores, ultimately decreasing below that of the 1.2-nm pore at 18 MPa. The density of adsorbed methane changes non-monotonically with increasing pore width, and drops to a minimum in 1.2-nm pores at 12 MPa. The isotherms have been compared with experimental data to gauge their accuracy, and the behavior of the adsorbed layer has been examined in detail. At pressures less than 2.5 MPa, the molecular simulation estimates underpredict the excess adsorption, while at pressures greater than 2.5 MPa up to 20 MPa, the simulation estimates overpredict the excess adsorption. This discrepancy is likely due to the limitation of the experimental-based model that was used to generate the pore size distribution and the surface functionalities of the porous media that were ignored in the molecular simulation investigations, but likely play an important role in determining accurate capacities under confinement at the nanoscale. ► Pore size in a simplified coal model shows a strong effect on methane adsorption. ► Layering effects of of methane are examined from simulation results. ► A simulation model is presented for subsurface gas adsorption behavior. ► Simulation results are compared and contrasted with outside experimental data. ► Several metrics for adsorption and their weaknesses and challenges are discussed.
Coal-based power generation produces over 750 Mt of coal ash per year globally, but under 50% of world production is utilised. Large amounts of fly ash are either stored temporarily in stockpiles, disposed of in ash landfills or lagooned. Coal ash is viewed as a major potential source of release of many environmentally sensitive elements to the environment. This paper encompasses over 90 publications on coal fly ash and demonstrates that a large number of elements are tightly bound to fly ash and may not be easily released to the environment, regardless of the nature of the ash. This review provides an extensive look at the extent to which major and trace elements are leached from coal fly ash. It also gives an insight into the factors underlying the leachability of elements and addresses the causes of the mobility. The mode of occurrence of a given element in the parent coal was found to play an important role in the leaching behaviour of fly ash. The amount of calcium in fly ash exerts a dominant influence on the pH of the ash–water system. The mobility of most elements contained in ash is markedly pH sensitive. The alkalinity of fly ash attenuates the release of a large number of elements of concern such as Cd, Co, Cu, Hg, Ni, Pb, Sn or Zn among others, but at the same time, it enhances the release of oxyanionic species such as As, B, Cr, Mo, Sb, Se, V and W. The precipitation of secondary phases such as ettringite may capture and bind several pollutants such ash As, B, Cr, Sb, Se and V. ► The mode of occurrence of elements in coal determines their solubility in fly ash. ► Most elements contained in fly ash display a pH-dependent solubility. ► Most trace elements in fly ash are poorly leached in pH 7–10 region. ► Oxyanionic-forming species are the main concern in alkaline fly ash. ► Absorption and precipitation processes attenuate the release of pollutants.
Coal mine methane (CMM) is a term given to the methane gas produced or emitted in association with coal mining activities either from the coal seam itself or from other gassy formations underground. The amount of CMM generated at a specific operation depends on the productivity of the coal mine, the gassiness of the coal seam and any underlying and overlying formations, operational variables, and geological conditions. CMM can be captured by engineered boreholes that augment the mine's ventilation system or it can be emitted into the mine environment and exhausted from the mine shafts along with ventilation air. The large amounts of methane released during mining present concerns about adequate mine ventilation to ensure worker safety, but they also can create opportunities to generate energy if this gas is captured and utilized properly. This article reviews the technical aspects of CMM capture in and from coal mines, the main factors affecting CMM accumulations in underground coal mines, methods for capturing methane using boreholes, specific borehole designs for effective methane capture, aspects of removing methane from abandoned mines and from sealed/active gobs of operating mines, benefits of capturing and controlling CMM for mine safety, and benefits for energy production and greenhouse gas (GHG) reduction. ► This technical aspects of CMM capture in and from coal mines and utilization. ► The main factors affecting CMM accumulations in underground mines, and mine safety benefits of capturing coal mine methane were emphasized. ► Global CMM emissions and activities for capturing and utilizing CMM were reviewed from a global perspective.
As with other reservoir types permeability is a key controlling factor for gas migration in coalbed methane reservoirs. The absolute permeability of coal reservoirs changes significantly during gas production, often initially decreasing but then increasing as the reservoir pressure and gas content is drawn down. It has also been observed to decrease markedly during CO injection to enhance coalbed methane recovery. In order to predict gas migration models for coal permeability must represent the mechanisms leading to these observed behaviours. The permeability of coal reservoirs behaves in a similar fashion to other fractured reservoirs with respect to effective stress, decreasing exponentially as the effective stress increases. However a unique effect of coal is that it shrinks with gas desorption and swells with adsorption. Within the reservoir this swelling/shrinkage strain leads to a geomechanical response changing the effective stress and thus the permeability. Modelling coal permeability incorporating the impacts from both effective stress and coal swelling/shrinkage dates back about 25 years. Since then a number of permeability models have been developed. In recent years this topic has seen a great deal of activity with a growing body of research on coal permeability behaviour and model development. This article presents a review of coal permeability and the approaches to modelling its behaviour. As an important part of this, the field and laboratory data used to test the models are reviewed in detail. This article also aims to identify some potential areas for future work. ► This article presents a review of coal permeability and the approaches to modelling its behaviour. ► As an important part of this, the field and laboratory data used to test the models are reviewed in detail. ► This article also aims to identify some potential areas for future work.
Coal is a resource primarily used for electric power generation, and currently supplies 41% of global electricity needs. Coal can also be considered as an economic source of strategically important elements, such as Ge, Ga, U, V, Se, rare earth elements, Y, Sc, Nb, Au, Ag, and Re, as well as base metals Al and Mg. The extraction and utilization of these critical elements from coal could result in a number of benefits, which will make this source an economically and environmentally attractive option especially for China, the U.S., Russia, India, and other countries that will remain major coal users for the foreseeable future.
Coal deposits have attracted much attention in recent years as promising alternative raw sources for rare earth elements and yttrium (REY), not only because the REY concentrations in many coals or coal ashes are equal to or higher than those found in conventional types of REY ores but also because of the world-wide demand for REY in recent years has been greater than supply. In addition to anomalies of enrichment or depletion of light-, medium-, and heavy-REY in coal deposits (normalized to Upper Continental Crust, Post-Archean Australian Shale, or North American Shale Composite), anomalies of redox-sensitive Ce and Eu, and, in some cases, of non-redox-sensitive La, Gd, and Y, could be used as geochemical indicators of the sediment-source region, sedimentary environment, tectonic evolution, and post-depositional history of coal deposits. Factors controlling REY anomalies in coal deposits include the geochemistry of terrigenous source rocks, ingress of hydrothermal fluids, influence of marine environments, percolating natural waters, volcanic ashes, and sedimentary environments of peat formation. Additionally, the smoothness of a normalized REY distribution pattern provides a simple but reliable basis for testing the quality of REY chemical analyses for coal and other sedimentary rocks.
This article reviews the state of research on sorption of gases (CO , CH ) and water on coal for primary recovery of coalbed methane (CBM), secondary recovery by an enhancement with carbon dioxide injection (CO -ECBM), and for permanent storage of CO 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 CO 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 CH 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 CO 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 CO 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 CO storage data on the CO /CH 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. ► We provide a review of the state of the art of gas and water sorption on coal. ► Applicable to coalbed methane and CO2 enhanced coalbed methane production. ► Correlation of sorption with coal specific parameters. ► Provides overview on sorption kinetic measurements on coal.
This paper presents data on widespread abnormal accumulations of lanthanides and yttrium (REY) in many coal deposits worldwide. High REY contents (> 0.1%) have been found in coal seams and coal ashes, as well as in the host and basement rocks of some coal basins. For a preliminary evaluation of coal ashes as an REY raw material, not only the abundance but also the individual REY compositions were taken into account in this paper. Three REY distribution patterns for high-REY coal ashes are fixed, with LREY- (La /Lu > 1), MREY- (La /Sm 1), and HREY- (La /Lu 0.1%) in coal ashes. ► Some of coal deposits contain high REY (0.1–14%) in host and basement rocks also. ► REY in high-REY coals occur mainly as authigenic minerals and organic compounds. ► Coal deposits may be considered as new sources for REY recovery as a by-product.
Unconventional gas reservoirs, including coalbed methane (CBM), tight gas (TG) and shale gas (SG), have become a significant source of hydrocarbon supply in North America, and interest in these resource plays has been generated globally. Despite a growing exploitation history, there is still much to be learned about fluid storage and transport properties of these reservoirs. A key task of petroleum engineers and geoscientists is to use historical production (reservoir fluid production rate histories, and cumulative production) for the purposes of 1) reservoir and well stimulation characterization and 2) production forecasting for reserve estimation and development planning. Both of these subtasks fall within the domain of quantitative production data analysis (PDA). PDA can be performed analytically, where physical models are applied to historical production and flowing pressure data to first extract information about the reservoir (i.e. hydrocarbon-in-place, permeability-thickness product) and stimulation (i.e. skin or hydraulic fracture properties) and then generate a forecast using a model that has been “calibrated” to the dynamic data (i.e. rates and pressures). Analytical production data analysis methods, often referred to as rate-transient analysis (RTA), utilize concepts analogous to pressure-transient analysis (PTA) for their implementation, and hence have a firm grounding in the physics of fluid storage and flow. Empirical methods, such as decline curve analysis, rely on empirical curve fits to historical production data, and projections to the future. These methods do not rigorously account for dynamic changes in well operating conditions (i.e. flowing pressures), or reservoir or fluid property changes. Quantitative PDA is now routinely applied for conventional reservoirs, where the physics of fluid storage and flow are relatively well-understood. RTA has evolved extensively over the past four decades, and empirical methods are now applied with constraints and “rules of thumb” developed by researchers with some confidence. For unconventional reservoirs, these techniques continue to evolve according to our improved understanding of the physics of fluid storage and flow. In this article, the latest techniques for quantitative PDA including type-curve analysis, straight-line (flow-regime) analysis, analytical and numerical simulation and empirical methods are briefly reviewed, specifically addressing their adaptation for CBM and SG reservoirs. Simulated and field examples are provided to demonstrate application. It is hoped that this article will serve as practical guide to production analysis for unconventional reservoirs as well as reveal the latest advances in these techniques. ► Review of analytical and empirical methods for use in unconventional gas reservoirs. ► Review of type-curve analysis, flow-regime analysis, and analytical simulation. ► Review of new empirical methods for decline curve analysis. ► Introduction to hybrid (analytical/empirical) methods. ► Application of techniques to simulated and field unconventional gas examples.
Organic petrography via incident light microscopy has broad application to shale petroleum systems, including delineation of thermal maturity windows and determination of organo-facies. Incident light microscopy allows practitioners the ability to identify various types of organic components and demonstrates that solid bitumen is the dominant organic matter occurring in shale plays of peak oil and gas window thermal maturity, whereas oil-prone Type I/II kerogens have converted to hydrocarbons and are not present. High magnification SEM observation of an interconnected organic porosity occurring in the solid bitumen of thermally mature shale reservoirs has enabled major advances in our understanding of hydrocarbon migration and storage in shale, but suffers from inability to confirm the type of organic matter present. Herein we review organic petrography applications in the North American shale plays through discussion of incident light photographic examples. In the first part of the manuscript we provide basic practical information on the measurement of organic reflectance and outline fluorescence microscopy and other petrographic approaches to the determination of thermal maturity. In the second half of the paper we discuss applications of organic petrography and SEM in all of the major shale petroleum systems in North America including tight oil plays such as the Bakken, Eagle Ford and Niobrara, and shale gas and condensate plays including the Barnett, Duvernay, Haynesville-Bossier, Marcellus, Utica, and Woodford, among others. Our review suggests systematic research employing correlative high resolution imaging techniques and in situ geochemical probing is needed to better document hydrocarbon storage, migration and wettability properties of solid bitumen at the pressure and temperature conditions of shale reservoirs.
Controls of matrix permeability are investigated for Devonian Gas Shales from the Horn River and Liard basins in northeastern British Columbia, Canada. Mineralogy is varied with high carbonate, high quartz and moderate quartz, carbonate and clay rich strata. Quartz content varies between 2 and 73%, carbonate varies between 1 and 93% and clay varies between 3 and 33%. The TOC content ranges between 0.3 and 6 wt.% and porosity varies between about 1 and 7%. For Horn River basin samples, quartz is mainly biogenic in origin derived from radiolarians. TOC content increases with the quartz content suggesting the TOC and quartz both are derived from siliceous phytoplankton. A positive relationship between porosity and quartz content is due to the positive relationship between quartz and TOC. Matrix permeability parallel to bedding varies between 7.5E− 02 and 7.1E− 07 mD at an effective stress of 15 MPa. Variation in permeability is due to a complex combination of factors that includes origin and distribution of minerals, pore‐size distribution and fabric. Mercury intrusion capillary curves indicate that the higher matrix permeability values (> 2E− 03 mD) occurs in samples that contain interconnected pore apertures greater than 16 μm even when these samples may contain less macropores than low permeability samples. The fabric of high permeability samples can be either isotropic or anisotropic; however permeability of anisotropic samples is more sensitive to changes in effective stress than isotropic samples. More highly anisotropic samples contain moderate amounts of quartz, carbonate and in some, clay. High permeability samples that contain a more balanced ratio between micro-, meso- and macroporosity would not only have faster flow rates but also greater access to sorbed gas within the microporosity compared to samples that lack mesopores. Several Muskwa samples compared to Evie and Besa River samples contain higher quartz, moderate clay and high TOC content coupled with high permeability, less sensitivity to effective stress and balanced ratios between micro-, meso- and macroporosity would be a lower exploration risk due a greater propensity to fracture, the ability to produce and store hydrocarbons due to higher TOC contents and greater communication between macropores and micropores in the organic and clay fractions. ► Pore‐size distribution, mineralogy, texture, fabric and TOC control permeability. ► Ratio of micro-, meso- and macroporosity specifically control permeability. ► Higher permeability have pore apertures greater than 16 μm. ► Highly anisotropic samples contain moderate amounts of carbonate, quartz and clay. ► Anisotropic samples more sensitive permeability to increases in effective stress.
This contribution reports on the study of the pore space morphology in two early mature (VR = 0.59 and 0.61) samples of Posidonia Shale from the Hils Syncline in Germany, using Broad Ion Beam (BIB) polishing and high resolution Scanning Electron Microscopy (SEM). This allows imaging pores with resolution down to 10 nm in equivalent diameter (d ), and quantitative estimation of porosity. Using a combination of BSE and SE detectors and semi-automatic segmentation of the gigapixel images, the representative elementary area of the samples, on the scale of a few mm, is inferred to be about 140 × 140 μm . Pore morphologies and pore sizes are clearly related to the mineral fabric, with large differences: very large (typically several microns) pores with internal faceted crystal morphology in recrystallized calcite clasts, and smaller pores (d < 1024 nm) in clay-rich matrix and in nanofossils (typically 200 nm). Pores are less common in organic material and in pyrite aggregates. Pore characteristics are very similar for both samples, and porosity resolvable by BIB-SEM is 2.75 and 2.74%. Pore size distribution can be described by a power-law, with an exponent about 2.0 and 2.2, respectively, for the pore population excluding the fossils. Pores in the carbonate fossils show dual-power-law distribution with power-law exponents of about 1 and 3. By extrapolating the power-law distribution for each sample, total porosity is estimated to be 4.8% (− 0.9, + 1.7%), and 6.5% (− 2.7, + 7.2%), respectively. This estimate can be compared with 3.4–3.7 and 3.3–3.6% as measured by mercury injection porosimetry. We interpret this difference to reflect the unconnected (for mercury) part of the porosity. Comparison of imaged pores and mercury injection porosimetry suggest a very high pore body to pore throat ratio. This results in a pore model where large pores, represented mainly by pores in fossils and calcite grains, are connected via a low-porous (and low-permeable) clay-rich matrix with pore throats below 10 nm in both samples. ► BIB milling gives access to 2D pore space in undamaged, mm areas. ► BIB-SEM allows qualitative and quantitative study of porosity down to 10 nm. ► Pore areas are power law distributed. ► Comparison of BIB-SEM analysis with MIP exemplifies the pore connectivity.
The liptinite maceral group has been revised by ICCP in accordance with the ICCP System 1994. After the revision of the classifications of vitrinite (ICCP, 1998), inertinite, (ICCP, 2001) and huminite (Sykorova et al., 2005) this liptinite classification completes the revised ICCP maceral group classifications. These classifications are collectively referred to as the “ICCP System 1994”. In contrast to the previous ICCP Stopes Heerlen (ICCP, 1963, 1971, 1975, 1993) this new classification system is applicable to coal of all ranks and dispersed organic matter. The classification as presented here was accepted in the ICCP Plenary Session on September 11, 2015 at the ICCP Meeting in Potsdam. The decision to publish this classification in the recent form was accepted at the ICCP Plenary Session on September 23, 2016 in Houston.
In contrast to the millimeter-to-micron scale of pore systems found in conventional oil and gas reservoirs, unconventional oil and gas reservoirs have nanoscale pore systems. However, the methods used to characterize conventional reservoirs are not normally effective for studying nanopores. In the present study, a dual-beam field emission scanning microscope–focused ion beam (FESEM–FIB) device was used to investigate nanopores in a core plug sample of the Longmaxi Shale from Pengye Well #1, Chongqing, China. A large number of nanopores were observed, which can be divided into three types: intraparticle pores within mineral particles (intraP pores), interparticle pores between mineral particles (interP pores), and organic-matter pores (OM pores). The latter type is the most abundant. The Pores (Particles) and Cracks Analysis System (PCAS) was used to identify and analyze pores in high-resolution SEM images. The results show differences in pore size, pore area, probability entropy, form factor, and fractal dimension between the three pore types, especially between organic-matter pores and the other two pore types. The pore size of organic-matter pores ranges from 4 to 483 nm (average 37 nm), whereas the pore sizes of intraP pores and interP pores are 57–1136 nm (average 210 nm) and 31–1976 nm (average 219 nm), respectively. Results for pore area also reflect the smaller pore sizes of organic-matter pores. The probability entropy, mean form factor, and fractal dimension of organic-matter pores are 0.90, 0.72, and 1.08 respectively, suggesting disordered pore directions and limited morphological complexity. The form factor and fractal dimension of intraP and interP pores indicate more complex pore shapes for these pore types. InterP pores have more ordered alignments, as indicated by their lower probability entropy. Differences in matrix composition and/or the mode of occurrence of pores give rise to differences in pore size and shape.
Black shale and coal Clarke values are the average trace element contents in the World black shales and coals. These calculations are made in Russian geochemistry but up to now are poorly known in the West. Modern tables of black shale and coal Clarkes are presented, based on comprehensive calculations using very large amount of information (thousands analyses of black shales, coals, and coal ashes for trace elements). In black shale geochemistry, three figures were calculated for each main lithologies: terrigenous (+ tuff), chert, and carbonate. Two Clarke estimations are presented, named “lithological” ( ) and “lithostratigraphical” ( ). In coal geochemistry, seven figures were calculated for each trace element: average content in hard coals and their ashes; average content in brown coals and their ashes; average content in all coals and their ashes; and coal affinity index (or “coalphile index”) = average content in all ashes/Clarke values of sedimentary rocks. The black shale and coal Clarkes presented here provide an important scientific base for many geochemical comparisons and issues.
Organic substances in produced and formation water from coalbed methane (CBM) and gas shale plays from across the USA were examined in this study. Disposal of produced waters from gas extraction in coal and shale is an important environmental issue because of the large volumes of water involved and the variable quality of this water. Organic substances in produced water may be environmentally relevant as pollutants, but have been little studied. Results from five CBM plays and two gas shale plays (including the Marcellus Shale) show a myriad of organic chemicals present in the produced and formation water. Organic compound classes present in produced and formation water in CBM plays include: polycyclic aromatic hydrocarbons (PAHs), heterocyclic compounds, alkyl phenols, aromatic amines, alkyl aromatics (alkyl benzenes, alkyl biphenyls), long-chain fatty acids, and aliphatic hydrocarbons. Concentrations of individual compounds range from < 1 to 100 μg/L, but total PAHs (the dominant compound class for most CBM samples) range from 50 to 100 μg/L. Total dissolved organic carbon (TOC) in CBM produced water is generally in the 1–4 mg/L range. Excursions from this general pattern in produced waters from individual wells arise from contaminants introduced by production activities (oils, grease, adhesives, etc.). Organic substances in produced and formation water from gas shale unimpacted by production chemicals have a similar range of compound classes as CBM produced water, and TOC levels of about 8 mg/L. However, produced water from the Marcellus Shale using hydraulic fracturing has TOC levels as high as 5500 mg/L and a range of added organic chemicals including, solvents, biocides, scale inhibitors, and other organic chemicals at levels of 1000 s of μg/L for individual compounds. Levels of these hydraulic fracturing chemicals and TOC decrease rapidly over the first 20 days of water recovery and some level of residual organic contaminants remain up to 250 days after hydraulic fracturing. Although the environmental impacts of the organics in produced water are not well defined, results suggest that care should be exercised in the disposal and release of produced waters containing these organic substances into the environment because of the potential toxicity of many of these substances.