Estimating Coalbed Gas Content and Sorption Isotherm Using Well Log Data

Contribution of non-coal facies to the total gas-in-place in Mannville coal measures, Central Alberta

The coalbed methane potential and producibility of any coal-bearing strata are strongly affected by the hydrogeological regime of formation waters and by coal permeability, which in turn depends on the effective stress regime of the coals. Peat that accumulated in the Alberta basin during the Late Cretaceous and early Tertiary led to the formation of coal deposits that may contain significant coalbed methane resources. The flow of formation waters plays an important role in the maintenance and producibility of this resource. The present-day flow is driven by gravity (topography) and erosional rebound and is controlled by rock permeability and the presence of gas-saturated sandstones. The estimated gas in place in the Tertiary–Upper Cretaceous coals decreases significantly with stratigraphic age, ranging between less than 2 bcf/mi2 in the lower coal zones and 12 bcf/mi2 in the uppermost coals. The gas content, especially of the deeper coals, is lower than would be expected for the corresponding coal rank and burial depth, most likely because the underpressuring has caused the release of gas from the coals and accumulation in adjacent sands. The shallow coals, although of low rank, may contain important amounts of late-stage biogenic methane. The salinity of formation water in shallow coal seams, where the flow is driven by topography, is low, generally less than 1500 mg/L, although in places, it reaches 3000–5000 mg/L. The salinity of formation water in the deeper, underpressured strata in the west-central part of the basin is significantly higher, reaching 18,000 mg/L. This affects treatment and/or disposal strategies with regard to the water produced concurrent to coalbed methane.The producibility of this resource depends on coal permeability, which decreases west-southwestward with increasing burial depth, from the order of several darcys in the shallow zones to millidarcys in the deep zones. The minimum effective stress, which affects coal permeability by closing fractures, increases west-southwestward from zero at the erosional edge of these strata to approximately 20 MPa near the Rocky Mountain deformation front. Fractures, including those in coal seams, will generally be vertical and will propagate on a southwest-northeast axis along the direction of the maximum horizontal stress, in a direction generally perpendicular to the Rocky Mountain deformation front.Considering the hydrogeological and stress regimes in conjunction with estimations of the gas content in coals, the region with probably good coalbed methane potential and producibility are the Ardley coal zone in the Scollard Formation and maybe, to a lesser extent, the coal zones of the stratigraphically deeper Edmonton and Belly River groups along their respective subcrop in central and southern Alberta. The deep Edmonton and Belly River strata in western and central Alberta have most likely a reduced coalbed methane potential as a result of lower gas content and of low permeability. These regional considerations need to be applied against local studies of coal thickness, rank, permeability, and gas content to identify the best targets for coalbed methane exploration and production.

Influence of lamprophyre sills on coal metamorphism, coalbed gas composition and coalbed gas occurrence in the Tongxin Minefield, Datong Coalfield, China

Self-heating of coal-shales has been reported in some South African coal mines to be one of the causes of spontaneous combustion but not the coal alone. Spontaneous combustion tests were conducted on a series of coal-shale samples collected from affected coal mines using a newly developed liability index referred to as the Wits-CT index. The ash content, volatile matter and the carbon content of the samples were investigated, and their effects towards spontaneous combustion liability were established. The study indicated that as ash content increases, the liability towards spontaneous combustion decreased, while as the volatile matter and carbon content increases, the liability towards spontaneous combustion increased. It was further found that the ash content showed a negative effect on the liability index, while volatile matter and carbon content showed positive effect on the liability index. Coal-shales with low ash content and high volatile matter and carbon content are more likely to be prone to spontaneous combustion.

This study aims to determine the characteristic of Kutai Basin coals on chemical composition parameter through proximate and ultimate analysis. Coal samples are taken from the Kutai Basin, where in this basin there are two formations containing coal, namely Pulaubalang and Balikpapan Formation. The methods used proximate and ultimate analysis. The statistical analysis of the results show the average concentration of moisture as 13.4 %, ash content as 5.8 %, volatile matter as 40.6 %, and fixed carbon as 40.2 % on Pulaubalang Formation and the average concentration of moisture as 14.0 %, ash content as 4.5 %, volatile matter as 40.8 %, and fixed carbon as 40.6 % on Balikpapan Formation. The increased volatile contents are characteristic of lower-rank coals, while the decreased values are indicative of higher-rank coals. The statistical analysis of the results show the average concentration of carbon as 63.21 %, hydrogen 6.10 %, nitrogen as 1.30 %, sulphur as 0.67 %, and oxygen as 22.96 % on Pulaubalang Formation and the average concentration of carbon as 59.24 %, hydrogen 5.92 %, nitrogen as 1.34 %, sulphur as 1.23 %, and oxygen as 27.75 % on Balikpapan Formation. The analytical results suggest the existing coal on Pulaubalang and Balikpapan Formation are of sub-bituminous A coal rank. Moreover proximate and ultimate analyses when interpreted in detail may form an effective tool to characterize the coals of any area.

Density is an important coal property that determines the potential of gas resources in CBM reservoir. This paper aims to investigate coal density and structure variation during primary CBM and CO2-ECBM experiments. A coal core sample from Alberta Mannville formation with the rank of SubB was used to conduct the core flooding experiments covering the stages of inert gas flow, methane production, methane displacement by CO2 and inert gas flow after CO2 desorption. The x-ray CT experiments were carried out parallel to the core flooding experiment to provide x-ray images of coal core saturated with different gases at different stress conditions. The x-ray techniques were used for visualization and mapping of larger fractures and mineral streaks, as well as identification of flow paths. The coal density and density distribution changed with the gas adsorptive capacity and the stress condition were obtained. The results show that net stress, gas adsorption capacity, and the production history are all key factors affecting coal core structure, leading coal density and density distribution variations. Hence, the core flow path, which contributes to the coal permeability, changes with those factors during CBM/ECBM processes. The results from this study provide laboratory coal characterization techniques using x-ray imaging analysis. Introduction Coalbed methane (CBM) is a new energy source and has the potential to contribute a significant portion of Canadian natural gas production. Coal reservoir characterization is one of the important steps to successfully develop CBM reservoirs. Coal seams are heterogeneous in terms of lithotypes and morphologies. This creates a challenge in understanding the subsurface behavior of the coal and injected gas during primary and enhanced gas recovery processes. As an organic rock, coal structure is easily deformed by the net stress imposed on it. Besides, adsorption of gases causes the coal matrix to swell and desorption of gases causes the coal matrix to shrink(1, 2). Therefore, coal experiences many changes in stress conditions uring the production life of the CBM reservoir. Because the network of natural fractures and cleats in a coal determines to a large extent the mechanical properties of the coal. Coal is very soft and has low elastic modulus compared to the rock formation. The stress and time dependent deformation of the coal porous structure is expected to change the behavior of the most important properties of the coal, such as porosity and permeability, which in turn change the reservoir production profiles. Coal physical properties such as density are therefore dynamically changed with the coal structure deformation. Coal bulk densities are highly useful for determination of the ash content of the coal. Because of the excellent correlation between core ash and gas content and the excellent correlation between core ash and open-hole bulk density data, it is possible to accurately estimate the gas content from the high resolution bulk density log data(3). Coal bulk density is also used in the estimation of the total gas content in a given drainage area(4).

Cook Inlet Basin of south-central Alaska is a forearc basin containing voluminous Tertiary coal deposits with sufficient methane content to suggest a major coalbed gas resource. Coals ranging in thickness from 2 to 50 ft (0.6 to 15 m) and in gas content from 50 to 250 scf/ton (1.6 to 7.8 cm2/g) occur in Miocene-Oligocene fluvial deposits of the Kenai Group. These coals have been identified as the probable source of more than 8 tcf gas that has been produced from conventional sandstone reservoirs in the basin. Cook Inlet coals can be divided into two main groups: (1) those of bituminous rank in the Tyonek Formation that contain mainly thermogenic methane and are confined to the northeastern part of the basin (Matanuska Valley) and to deep levels elsewhere; and (2) subbituminous coals at shallow depths (<5000 ft [1524 m]) in the Tyonek and overlying Beluga formations, which contain mainly biogenic methane and cover most of the central and southern basin. Based on core and corrected cuttings-desorption analyses, gas contents average 230 scf/ton (7.2 cm2/g) for bituminous coals and 80 scf/ton (2.5 cm2/g) for subbituminous coals. Isotherms constructed for samples of both coal ranks suggest that bituminous coals are saturated with respect to methane, whereas subbituminous coals at shallow depths along the eroded west-central basin margin are locally unsaturated. A preliminary estimate of 140 tcf gas in place is derived for the basin.

Short description of the Peruvian coal basins

The flow velocity of gases in gobs directly influences the kinetics and intensity of gaseous components release during heating and cooling of coal. The assessment of fire hazard is performed on the basis of concentrations of particular gases in a mine air. These concentrations differ in coal heating and cooling phase which was proven in the study. This paper presented the results of the experimental study on temperature distribution in a simulated coal bed in heating (50–250 °C) and cooling (250–35 °C) phases as well as its correlation to variations in concentration of gases released in these phases and flow rates of gases flowing through the coal bed. The research was performed on twenty-two samples of bituminous coals acquired from various coal beds of Polish coal mines. Considerable differences were observed between heating and cooling phases in terms of the concentrations of gases taken into account in calculations of self-combustion index. In the heating phase temperature increase resulted in the decrease of concentrations ratios of ethane, ethylene, propane, propylene and acetylene, while in the cooling phase these ratios increased systemically. The effect of air (in heating phase) and nitrogen (in cooling phase) flow rate on the self-ignition index CO/CO2 was also determined.

Inertinite-rich Tertiary coals from the Zeya–Bureya Basin, Far Eastern Russia

Protective coal seam mining is an important technical method used to strengthen the effect of gas extraction and prevent accidents caused by gases. However, it is necessary to thoroughly study the selection of the first coal seam to be mined and its effects related to pressure relief and permeability enhancement under the complex conditions of a coal seam group. This includes studying the relationships that govern pressure relief and permeability enhancement and the mechanism of the extraction of gas. In this study, a certain mine was used as engineering background. A damage-permeability model of a coal rock body undergoing mining disturbance was constructed based on experimental results and related theories. COMSOL Multiphysics software was used to perform numerical calculations with the model. The distribution of gas pressure in a coal seam was simulated under different mining conditions for the first mining seam. The first mining layer for protective coal seam mining of a coal seam group was identified. On this basis, the changes in parameters such as coal seam gas content, vertical stress and seepage velocity were studied during the advancement of the working face of the first mining seam. Furthermore, the numerical simulation was used to analyze the arrangement of boreholes for gas extraction from the bottom extraction roadway and the effect of extraction on pressure relief and permeability enhancement during protective coal seam mining. The results of the study showed the following: (1) Selecting 6# coal seam as the first mining seam had the best pressure relief effect on the adjacent seam, followed by 4# coal seam, and 8# coal seam had the worst pressure relief effect. (2) With the advancement of the 6# coal seam working face, the range of the pressure relief of the protected seam gradually expanded, the maximum stress relief degree of 4# coal seam was 25%, and the maximum decrease in gas content was 28.1%. The maximum stress relief degree of 8# coal seam was 60%, and the maximum decrease in gas content was 45.9%. (3) The gas content of coal seams decreased rapidly after extraction using boreholes; the gas contents of 4# coal seam and 8# coal seam decreased 81.25% and 99%, respectively, compared with the original values after 50 days of extraction. The efficiency of extraction by drill holes was related to the degree of decompression in the coal seam.

The South Yanchuan block is the deepest developed high-rank coalbed methane (CBM) field in China, the geological conditions in this block are complex and the main controlling factors of CBM content are various. Thus, a decision-making model of the potential of deep high-rank coalbed methane resource based on geographical information system (GIS) and weighted linear combination (WLC) is established, the influence of geological conditions on CBM content is analyzed, the favorable areas of CBM potential are divided. Results show that the buried depth, coal rank and hydrodynamic condition in the coal seam are dominant factors that control the gas content on a block scale, while the gas content has a weak correlation with maceral composition, coal thickness and the effective thickness of the overlying strata. The study area is divided into five units according to the natural breaks method, i.e., the extramely favourable area, the favourable area, the relatively favourable area, the normally favourable area and the unfavourable area, which account for 14.23%, 22.23%, 24.77%, 25.08% and 13.70% in area, respectively. The extramely favourable area is located in the northwestern of the South Yanchuan block, which is considered to be the key exploration and development area. The study will deepen the understanding of the control of CBM potential in south Yanchuan Block, and is of practical significance for CBM recovery in this area.

Coalbed methane (CBM) is the only unconventional gas in Poland with estimated recoverable resources. The prospects for developing deep CBM have been explored in recent years by drilling deep exploration wells within the depocenter of the Upper Silesian Coal Basin. The purpose of this study is to analyze the occurrence and potential for CBM extraction in this area of the basin, which can be considered prospective due to the confirmed presence of significant amounts of gas and thick coal seams at depths &gt; 1500 m. The study examined the vertical and horizontal variability of the gas content in the studied area, the coal rank in the seams, thermal conditions, and coal reservoir parameters. The gas content in the seams, reaching more than 18 m3/t coaldaf at a depth of 2840 m, and indicative estimated gas resources of 9 billion m3 were found. The high gas content is accompanied by positive thermal and coal rank anomalies. The permeability and methane saturation of the coal seams are low, and therefore, potential methane production may prove problematic. However, the development of CBM extraction technologies involving directional drilling with artificial fracturing may encourage gas production testing in the study area.

Summary The facies and core data prediction techniques have not yet found their way in the CBM/CSG business, despite having been used successfully for more than a decade in the conventional O/G business; but we believe this new technique signals that the time has come for this to happen. The method described here is based on the Facimage facies-prediction software run under Geolog. Reasonable qualitative estimates can be generated immediately from a full suite of logs but for each new basin or coal sequence, gas and ash content from cores are required to derive a predictive model and deliver calibrated, quantitative results - by tying core measurements to their log signature, as is done for conventional O/G analysis. Once blind testing has proven the model is satisfactory, gas and ash content together with the different facies can be predicted quantitatively from logs without cores. Rigorous quality control measures ensure that the prediction models used are applicable or, where there is a difference, that there may/must be changes in the geology or a log acquisition problem. The processes used are designed to be devoid of operator bias and can be run as soon as logs are run to allow on-site decisions about testing, suspension or P&A. We demonstrate the principles and methods used to derive gas and ash content without core data, but assuming calibration has been achieved, and how we build the quality control model and how we address the problems of spatial resolution mismatch between core and logs and of shoulder-bed effects.

The possibility of blending acid tar waste with coal as a beneficiation method was explored in this work. It was essential to first establish the material properties of the acid tar and coal samples together with that of the blends in terms of proximate analyses. The acid tar waste to coal blending ratios of 3:1, 1:1 and 1:3 were used. It was observed that acid tar waste exhibited high volatile and moisture content with low ash and carbon content when compared with coal. When compared with coal; a 3:1 blending ratio exhibited 56.9 % and 7.6 % reduction in ash and fixed carbon respectively and on the contrary a 38.1 % increase in volatile matter was observed. An opposite trend was obtained with 1:3 blend ratio. The 1:1 blend ratio was found to decrease the volatile and ash content by 8.3 % and 52.7 % respectively whilst fixed carbon boosted by 4.2 %. The choice for the blending ratio to apply is a trade-off between fixed carbon and volatile matter. If volatile matter is of any significance then a 3:1 mixture would be ideal; such a mixture will aid in easier ignition of coal. On the other hand a 1:3 binary mixture yields a higher fixed carbon fraction, whose effect is to boost the calorific value of the fuel, an excellent factor for combustion. Overall however, it makes economic sense to blend coal with acid tar waste for enhancing sustainability.