Coalbed Methane Block Research Articles

Research on trajectory control technology for L-shaped horizontal exploration wells in coalbed methane

Horizontal wells have significant advantages in coal bed methane exploration and development blocks. However, its application in new exploration and development blocks could be challenging. Limited geological data, uncertain geological conditions, and the emergence of micro-faults in pre-drilled target coal seams make it hard to accurately control the well trajectory. The well trajectory prior to drilling needs to be optimized to ensure that the drilling trajectory is within the target coal seam and to prevent any reduction in drilling ratio (defined here as the percentage of the drilling trajectory in the entire horizontal section of the well located in the target coal seam) caused by faults. In this study, the well trajectory optimization is achieved by implementing the following process to drill pilot hole, acquire 2D resonance, and azimuthal gamma logging while drilling. The pilot hole drilling can obtain the characteristic parameters of the target coal seam and the top and bottom rock layers in advance, which can provide judgment values for the landing site design and real-time monitoring of whether the wellbore trajectory extends along the target coal seam; 2D resonance exploration can obtain the construction of set orientation before drilling and the development of small faults and formation fluctuations in the horizontal section, which can optimize the well trajectory in advance; the azimuth gamma logging while drilling technology can monitor the layers drilled by the current drill bit in real time, and can provide timely and accurate well trajectory adjustment methods.The horizontal well-Q in the Block-W of the Qinshui Basin was taken as a case study and underwent technical mechanism research and applicability analysis. The implementation of this new innovative process resulted in a successful drilling of a 711 m horizontal section, with a target coal seam drilling rate of 80%. Compared to previous L-type wells, the drilling rate increased by about 20%, and the drilling cycle shortened by 25%. The technical experience gained from this successful case provides valuable insight for low-cost exploration and development of new coalbed methane blocks.

Research on Fracturing Optimization of Coalbed Methane Wells Aiming at Economic Benefit—A Case Study of Liulin Block

Hydraulic fracturing is an essential technology in the development of coalbed methane reservoirs. Hydraulic fracturing can create a highly conductive fracture in the reservoir and increase its permeability. At present, the focus of coalbed methane reservoir fracturing optimization is gradually shifting to the fracturing scale. In the current development process, more and more coalbed methane blocks try to increase the fracturing scale to increase the gas production of coalbed methane wells. Field tests show that gas production of coalbed methane wells will increase to a certain extent with the increase of fracturing scale. However, the increase in the scale of fracturing also increases its cost. Therefore, the most economical fracturing scale is not necessarily the optimal fracturing scale for gas production. The field test usually pays more attention to the gas production effect, but the development of a coalbed methane field should pay more attention to the economic benefit, and the optimization of fracturing should take the economic benefit as the goal. Taking economic benefits as the starting point, this paper uses fracturing simulation to calculate the fracture extension under different geological conditions and different fracturing scales. It also uses numerical simulation to calculate the gas well productivity under different fracture extension conditions. The economic evaluation model was established to calculate the economic benefits under different fracturing scales, and the optimal fracturing scale was obtained. Finally, the typical maps of fracturing optimization under different geological conditions are formed. The optimization method of fracturing scale integrating economy, fracturing, and gas reservoir is realized. The research results have been successfully applied to the optimization scheme of Liulin block development, and very good results have been achieved. Because this method is targeted at different geological conditions, it can be used to guide the fracturing optimization of other coalbed methane blocks and has very important significance for the development and optimization of coalbed methane reservoirs.

Culture-independent assessment of the indigenous microbial diversity of Raniganj coal bed methane block, Durgapur.

It is widely acknowledged that conventional mining and extraction techniques have left many parts of the world with depleting coal reserves. A sustainable method for improving the recovery of natural gas from coalbeds involves enhancing the production of biogenic methane in coal mines. By taking a culture-independent approach, the diversity of the microbial community present in the formation water of an Indian reservoir was examined using 16S rRNA gene amplification in order to study the potential of microbial-enhanced coal bed methane (CBM) production from the deep thermogenic wells at a depth of 800-1200 m. Physicochemical characterization of formation water and coal samples was performed with the aim of understanding the in situ reservoir conditions that are most favorable for microbial CBM production. Microbial community analysis of formation water showed that bacteria were more abundant than archaea. Proteobacteria, Firmicutes, and Bacteroidetes were found as the most prevalent phyla in all the samples. These phyla play a crucial role in providing substrate for the process of methanogenesis by performing fermentative, hydrolytic, and syntrophic functions. Considerable variation in the abundance of microbial genera was observed amongst the selected CBM wells, potentially due to variable local geochemical conditions within the reservoir. The results of our study provide insights into the impact of geochemical factors on microbial distribution within the reservoir. Further, the study demonstrates lab-scale enhancement in methane production through nutrient amendment. It also focuses on understanding the microbial diversity of the Raniganj coalbed methane block using amplicon sequencing and further recognizing the potential of biogenic methane enhancement through microbial stimulation. The findings of the study will help as a reference for better strategization and implementation of on-site microbial stimulation for enhanced biogenic methane production in the future.

Evaluation of Reconstruction Potential for Low-Production Vertical Wells of CBM in the Southern Qinshui Basin

Production practice has shown that not all low-production coalbed methane (CBM) wells can be reconstructed into high-production wells through secondary stimulation, so it is necessary and timely to establish an evaluation index system, form an evaluation method, and evaluate the reconstruction potential of low-production wells. Based on the development practice of CBM in the southern Qinshui Basin, this paper analyzes the influencing factors of low production in vertical wells from the aspects of coal and rock reservoir conditions, drilling and completion engineering, and drainage engineering. It is proposed that the evaluation of the reconstruction potential of low-production wells should focus on the quality of CBM resources, the difficulty of CBM desorption and diffusion, and the degree of damage to coal reservoirs caused by the initial reservoir stimulation. Twelve parameters, including gas content, gas saturation, reservoir pressure gradient, critical desorption–reservoir pressure ratio, and permeability, were systematically selected as evaluation indicators, and the grading reference values for each evaluation indicator were comparatively given. Then, a multi-factor comprehensive evaluation method for the reconstruction potential of low-production wells based on gray correlation analysis method was established. The reconstruction potential of low-production wells was divided into three levels: high, medium, and low. When reconstructing low-production wells, it is recommended to prioritize the low-production wells with high reconstruction potential, followed by those with medium reconstruction potential, while low-production wells with low reconstruction potential are not recommended for reconstruction. Finally, the evaluation method was used to evaluate the reconstruction potential of five low-production wells in a CBM block, and suggestions for the reconstruction order and reconstruction potential levels for each well were given.

Field experiment of stress sensitivity effect in the Mabidong CBM block, southern Qinshui Basin, China

Coalbed methane (CBM) has made significant contributions to global energy supply and carbon neutrality. The stress sensitivity effect (SSE) is an important factor that influences CBM production, and it indicates that reservoir properties change with stress. Although there is abundant research on the SSE in CBM, most studies are based on theoretical analyses or laboratory physical simulations. Only few studies focused on the SSE of CBM during field production. Therefore, this study aims to investigate the SSE through a field experiment. To this end, a field well from the Mabidong CBM block in the southern Qinshui Basin is selected. Then, the corresponding experimental installations are set up. A parametric inversion method based on the Newman product method and type curve matching is established to interpret the experimental data. The entire experimental process includes six stages of pressure build tests, lasting for 290 days. The field experiment data are inverted using the parametric inversion method. The SSE in the CBM during production is revealed by analyzing the variations in the formation parameters of each stage. The results indicate that both the permeability and fracture half-length are related to the average pressure. The average pressure declines as the production proceeds, and this leads to an increase in the effective stress and a decrease in the permeability and fracture half-length. Relationships between permeability, fracture half-length, and average pressure are derived, and they can be used to better interpret the dynamic production data of CBM wells in the Mabidong Block. Moreover, these results indicate that decreasing the flow rate can mitigate the SSE, especially when the gas desorbs. Thus, during CBM production, the flow rate needs to be strictly controlled for maintaining a stable pressure drop and reducing reservoir damage caused by the SSE.

Petrographic and Geochemical Controls on Methane Genesis, Pore Fractal Attributes, and Sorption of Lower Gondwana Coal of Jharia Basin, India.

The Barakar coal seams of Jharia Basin have been evaluated for the geochemical and petrographic control of coalbed methane (CBM) reservoir characteristics. The coal core samples are analyzed for the total gas content, gas chromatography, stable isotopes (δ13C1), and geochemical, petrographic and vitrinite reflectance. The significant face (1.6–7.6%) and butt (0.9–5.3%) cleat intensities specify the brittle characteristics of coal seams and also favor the gas flow mechanism. The thermal cracking position of hydrocarbon compounds was evaluated, which signifies the excellent source rock potential of coal for gas genesis. The inputs of type III and IV organic matter illustrated by the van Krevelan diagram signify thermally matured coal seams. The low values of sorption time (τ) between 2.1 and 5.6 days designate excellent diffusion characteristics that is favored by the cleat intensities. The values of total gas content and sorption capacity (VL) reveal that moderate saturation indicates a higher gas content, attributed to the seam thickness and thermal maturity. Similarly, the CH4 concentrations (89.4–96.6 vol %) display that the genesis pattern is a function of thermal maturity; however, some samples fall under the mixed type substantiated by the stable isotope (δ13C1) (−25.40 to −64.90‰), emphasizing bacterial hold by seasonal influx of freshwater. The ternary facies diagram (Vmmf, Immf, Lmmf) also supports notable generation of methane gas and storage in the coal seams of the Jharia Basin. The volume percentage of each maceral determined from petrographic study was used to estimate the fraction of conversion (f) of the organic content (0.19–0.97). The values of “f” indicate that the Barakar coal has undergone maximum conversion, which may be attributed to the older early Permian coal and placed at a greater depth after deposition due to the basin sink. The high fraction of conversion and thermal maturity may also be explained due to the existence of volcanic intrusion (sills and dykes). The uniformity in the distribution of functional groups is shown by Fourier transform infrared spectra representing moderate to stronger peaks of aromatic carbon (CO and C=C) between 1750 and 1450 cm–1, which indicates that the presence of a larger total organic carbon content likely validates the removal of aliphatic compounds during gas genesis. The variations in the BET curve have been categorized as H1 hysteresis following the type II adsorption pattern, suggesting that cylindrical pores and some of the coal samples have a type IV H4 hysteresis pattern, characterized as the slit type of pores. The average values of the pore diameter indicate the dominance of mesopores suitable for gas storage and release and hence a major part of the pore volume is contributed by the mesopores having a width mainly between 2.98 and 4.48 nm. The significant role of the meso-macropore network (D1 fractals) in methane storage of the coal matrix is represented by a moderate positive relationship of VL with D1, which accentuated that meso-macropores developed due to devolatilization and dehydration of organic matter and also by geochemical alteration of macerals and minerals formed heterogenetic inner surfaces suitable for gas adsorption. The estimated recoverable resource applying Mavor Pratt methods is 8.78 BCM, which is found to be a more realistic resource value for the studied CBM block.

Daily production prediction for coalbed methane based on Bayesian temporal matrix factorization

Effective and accurate daily production prediction of coalbed methane (CBM) is significant for enhancing CBM recovery and developing economic evaluations of CBM exploitation. As production time increases, CBM well data gradually show some characteristics of big data and is susceptible to incomplete data and noise data. Traditional geological modeling, however, requires a variety of input factors. In the present study, we apply a time series analysis method based on Bayesian temporal matrix factorization (BTMF) without the deletion of exceptional values to investigate the characteristics of CBM development. In addition, different from the widely used data preprocessing, we innovatively scale the multidimensional data to accomplish the analysis and prediction of different attributive data. By studying the temporal and attributive characteristics of the CBM production curve, the model is applied to a CBM block in China to impute the production data and perform a multi-step rolling prediction of daily gas production.Evaluation metrics, including the mean absolute percentage error (MAPE) and the root mean square error (RMSE), are applied to evaluate the performance. It is found that the imputation by the application of BTMF achieves highly satisfactory estimates (in all tested CBM wells, the maximum MAPE and RMSE are 0.1182 and 245.5882, respectively) and is comparable to the other factorization models. Results also show that BTMF is able to account for the variance in gas production with different multi-step rolling predictions and different predicting scenarios, with the MAPE matrix of five CBM wells of different predicting strategies varies from 0.051 to 0.208, 0.121 to 0.307, 0.099 to 0.221, 0.062 to 0.224 and 0.054 to 0.135, respectively. Because of the similar mechanisms of CBM development, this method can provide a reference for predicting the daily gas production of other CBM wells.

Improved estimation of coalbed methane content using the revised estimate of depth and CatBoost algorithm: A case study from southern Sichuan Basin, China

The coalbed methane blocks are always structurally and topographically complex, and there are no models to accurately predict the coalbed methane content in the southern Sichuan Basin, China. This study proposes a feasible machine learning model to achieve a more accurate estimation of coalbed methane content with a small data set. A revised estimate of depth (Z) based on hydrogeological grounds was used as a feature of the prediction model, which can resolve the errors introduced by using the commonly used measured depth as a feature in areas with drastic topographical and structural changes. The revised estimate of depth (Z) and the measured depth were applied for data analysis along with three machine learning algorithms (support vector regression, gradient boosting decision tree, and CatBoost) to obtain the optimized model for coalbed methane content estimation. Modeling results show that the coefficient of determination (R2), mean absolute error, and mean square error of all algorithms were improved after replacing the measured depth with the revised estimate of depth (Z). The Catboost algorithm performed better than the other two algorithms in this study. The prediction results based on CatBoost using the revised estimate of depth (Z) showed the highest accuracy among all the comparison models. The analysis results show that the R2 between Z and coalbed methane content was 150% higher than that between measured depth and coalbed methane content. This vast difference between measured depth and revised estimate of depth (Z) outputs was caused by drastic changes in topography and structure.

Coalbed Methane Potential Evaluation and Development Sweet Spot Prediction Based on the Analysis of Development Geological Conditions in Yangjiapo Block, Eastern Ordos Basin, China

The evaluation and prediction of favorable coalbed methane (CBM) sweet spot play an important role in well location deployment and recovery prediction in CBM blocks. This work investigates the CBM geology and accumulation characteristics of No. ( 8 + 9 ) coal in the Carboniferous Taiyuan Formation in Yangjiapo block based on data from 14 CBM wells. The desorption index is proposed to be used to study the CBM desorption potential in Yangjiapo block, and the parameter of reduced water level is adopted to study the CBM hydrodynamics of the block. Furthermore, the analytical hierarchy fuzzy evaluation method is used to evaluate and prediction the CBM development sweet spot in Yangjiapo block. The results show that the buried depth of the No. ( 8 + 9 ) coal seam in Yangjiapo block varies from 693.20 to 1213.20 m, the coal thickness is from 5.40 to 13.10 m, the gas content is from 5.89 to 10.55 m3/t, and the minimum horizontal principal stress is from 9.80 to 20.82 MPa. The desorption potential is better in the southeastern and central-western part of the block. It is found that there is a positive relationship between CBM content and hydrodynamics and indicated that CBM easily concentrates in the lower reduced water level area. The CBM favorable development sweet spot is forecasted to be located in the southeastern part, central-western region, and northeastern part of Yangjiapo block.

Influence of Migration and Plugging of Nanoparticles on Coal Permeability in Coal Reservoirs

The plugging of nanopores in low-permeability coal reservoirs is an important factor that affects productivity reduction. However, the mechanism of plugging of the nanopores in coal reservoirs remains unclear. In this study, the coal samples from the Anze coalbed methane block of the North China Oilfield are used as the research object. Experiments are conducted on the mechanism of nanopore plugging by the variation of nanopore permeability based on the pressure oscillation method and the nanopore (scanning electron microscope) method. The research shows that the foreign working fluid invades a coal sample; the sample changes from being hydrophobic to being water absorbent within a certain period. The instability caused by the expansion of coal clay mineral particles promotes the dispersion and shedding of particles, and the migration of particles is accelerated under the shear stress of the working fluid. In addition, the viscosity and pressure difference of the working fluid are important factors that affect particle plugging. The viscosity of the fluid increased by two times, and permeability decreased by 1.21 times. As the pressure difference increases by two times, permeability can be reduced by up to two orders of magnitude. The findings of this study can help for better understanding of the mechanism of plugging of the nanopores in coal reservoirs and the reasons of production reduction in low-permeability coal reservoirs. Such findings provide theoretical support for the selection of the working fluid, and reasonable production pressure difference can effectively reduce the damage on coal permeability in a low-permeability coal reservoir.

Evaluating production behaviour of CBM wells from Raniganj Coalfield through reservoir characterization under constrained field data conditions

There remains a good level of uncertainty in peak gas rate and the time to reach the peak for coalbed methane (CBM) wells owing to reservoir heterogeneity. The novelty of the present study lies in predicting the production behavior of wells in the emerging CBM block of Raniganj through extensive reservoir characterization coupled with reservoir simulation and validation. Ten regional (R–I to R-X) and two local seams intercepted in the six exploratory boreholes drilled in Raniganj Coalfield were investigated. The reservoir characterization approach was used for uncertainty analysis of the key parameters viz. isotherms, gas content, permeability and porosity, and their impact on the production behavior of the CBM wells. Low, mid and high cases of the parameters were determined through regression analysis.Isotherm and gas content data were experimentally determined while in situ permeability data were obtained from the pressure transient analysis of injection/fall-off test. Reiss model was used for porosity-permeability transformation and Corey's model was used to define the range of relative permeability. The experimental values of Langmuir volume varies between 17.4 and 29.8 cc/gm (daf); Langmuir pressure 2451–7827 kPa; gas content 2.07–13.03 cc/gm (daf); and fracture permeability 0.79–7.12 mD. The model was set up in CMG-GEM simulator to represent a single well producing under commingled completion strategy for all the 12 seams being perforated. Production profiles of both gas and water show a wide range of variation up to 56,201 m3/day and up to 129.84 m3/day, respectively. Data analysis reveals that Raniganj coals are having a wide range of saturation distribution (between 27% and 100%) with a huge upside potential going towards 100% saturation case. Gas content and permeability are found to be the two key factors controlling the CBM production in Raniganj Coalfield. The model results were validated with actual well performance.

Advantageous Seepage Channel in Coal Seam and its Effects on the Distribution of High-yield Areas in the Fanzhuang CBM Block, Southern Qinshui Basin, China

Results of stress sensitivity experiments show that, when the confining pressure reaches 15.5 MPa, six coal cores have strong stress sensitivity effect (SSE) and cleat compressibility varying from 0.0286 to 0.0725 MPa−1. The development of coalbed methane (CBM) is a process of drainage and pressure reduction, which causes inevitable stress-related damage to coal reservoirs. CBM production is affected by different stress-related damage levels, and the damage level depends on different reservoir conditions, working systems, and development stages. The Gu, Huagu, and Pu-Punan zones have high-yield wells with NW–SE distribution, while the Huayna and Huaxi zones have high-yield wells with NE–SW distribution. Based on the stress damage mechanism of reservoir permeability, the factors that control SSE are tectonic stress field, reservoir pressure, and fracture pressure, which in turn affect the productivity changes of CBM wells.

Gray Relational Analysis Optimization for Coalbed Methane Blocks in Complex Conditions Based on a Best Worst and Entropy Method

The uncertainty and complexity of the geological parameters of coalbed methane (CBM) reservoirs may result in the assignment of atypical exact values to a whole block. Therefore, the influence of different resources and productivity characterization indices on the development of CBM blocks was analyzed systematically in this research. Furthermore, this research reported an interval-number index evaluation system and a gray relational analysis optimization model for CBM development. The weights of the evaluation indices were determined by combining the entropy method and the best worst method (BWM) with the objective deviation law of the data and the subjective experience of experts. Based on the gray system theory, a multi-index gray relational analysis optimization model was established to evaluate the interval values and optimize the development potential of CBM blocks with complex geological conditions. The results show that the order of importance of the eight resources and reservoir evaluation indices, from highest to lowest, is permeability, reservoir pressure gradient, gas content, reservoir thickness, reservoir depth, critical reservoir ratio, Young’s modulus, and reservoir temperature. The order of the target blocks, from most to least optimal, is the Sanjiao block, Fanzhuang-Zhengzhuang block, Daning-Jixian block, Gujiao block, and Fengrun block. The evaluation results are consistent with actual conditions. Thus, the multi-index gray relation analysis optimization model, on account of the gray system theory, is feasible for the development evaluation of CBM blocks under complex conditions. This model is suitable for the CBM blocks in the range of 547 km2~675 km2. When using this model, the index values must be representative and accurate.

Investigation of coal pore and fracture distributions and their contributions to coal reservoir permeability in the Changzhi block, middle-southern Qinshui Basin, North China

Pores and fractures in coal have an important influence on gas desorption, diffusion, and seepage during coalbed methane (CBM) recovery. The occurrence and spatial distribution of pores and fractures in the Changzhi CBM block coals of the middle-southern Qinshui Basin, North China, were investigated by means of scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS) and low-temperature liquid nitrogen isotherm adsorption/desorption (LT-N2AD). In addition, pore and fracture contributions to the permeability of the coal reservoir were evaluated. The results show that there are many pores and fractures with different widths and lengths in the coals, most of which are isolated. The microfractures serve as a bridge for gas migration between pores, cleats, and macrofractures. Based on the relationship between cross-cutting microfractures and cleats, the multiple populations of microfractures in the coals can be classified as 1st class and 2nd class microfractures. Statistical analyses reveal that the aperture distributions of these fractures are heterogeneous and that the expected fracture aperture distributions can be described by a log-normal Gaussian function. Based on the statistically expected fracture aperture and its actions on gas flow, three levels of potential flow paths and three permeability domains are concluded to occur in coal reservoirs, including cleats, 1st class microfractures, and 2nd class microfractures. For this study area, due to the occurrence of mineralized cleats, the CBM reservoir permeability is significantly reduced. The current coal reservoir permeability contribution is mostly from the 1st class and 2nd class microfractures. Lastly, based on the pore and fracture spatial distributions of the coal and the three statistically expected permeability domains, the coupled pore-fracture network configuration models of coal reservoirs were constructed, which are useful for evaluating coal reservoir permeability.

Mechanical behavior of low-rank bituminous coal under compression: An experimental and numerical study

The mechanical behavior of coal has an important influence on coal reservoir stimulation and the dynamic change of coal reservoir permeability during coalbed methane (CBM) production. Generally, coal is regarded as an elastic-brittle material, which is reasonable when the surrounding stress is small. However, with the increasing depth of CBM exploitation, the in-situ stress increases continuously, so the coal will inevitably show some plastic behavior. In this work, the typical low-rank bituminous coal from the Baode CBM block on the eastern margin of the Ordos Basin was selected to carry out uniaxial and triaxial compression tests under various confining pressures (Pc) for further investigation of mechanical behavior. The results show that, as a complex porous material, the coal samples have a series of deformation responses during the loading process, which can be classified into four phases. Both the yield stress (σy) and the peak stress (σpeak) increase nonlinearly as Pc increases. Additionally, with increasing Pc, the elastic modulus (E) increases at a decreasing rate, while the Poisson's ratio (ν) decreases at a decreasing rate. Moreover, a change from volumetric compressibility to dilatancy in the coal was clearly observed in the tests, and the stress at the onset of dilation (σd) is also significantly influenced by Pc. Finally, based on irreversible thermodynamics and empirical support, a coupled elastoplastic damage constitutive model for low-rank bituminous coal was established by introducing the non-associated plastic flow laws and the damage evolution rules; the numerical simulation result of the model is in good agreement with the experimental measurements. This model can be used for further investigation of the mechanical properties of coal reservoirs under different in-situ stress conditions during the exploitation of CBM.

Distribution of methane carbon isotope and its significance on CBM accumulation of No.2 coal seam in Yanchuannan CBM block, Ordos Basin, China

Distribution and origins of methane isotope (δ13C(CH4)) in coalbed methane (CBM) block of southeast-Ordos Basin are related to the accumulation and distribution of CBM in Yanchuannan CBM block, which is of great significance for the evaluation of CBM resources. In this paper, the stable isotope ratios of coalbed gases (δ13C(CH4), δD(CH4) and δ13C(CO2)) of the No.2 coal seam associated with water samples collected from Permian Shanxi Formation in southeast of Ordos Basin were investigated. The data set reveals that stable isotope ratios vary within the following ranges: δ13C(CH4) from −54.1‰ to −29.6‰ with an average of −37.73‰, δD(CH4) from −230‰ to −158‰ with an average of −188.39‰, and δ13C(CO2) from −20.6‰ to +2.2‰ with an average of −14.47‰. There are four dominant factors that decides the distribution of methane carbon isotope, including burial depth, Ro,max, hydrodynamic conditions and biogenic gases. The values of δ13C(CH4) naturally desorbed from No.2 coal seam increase with an increase with burial depth, Ro,max and reservoir pressure, which indicates that δ13C(CH4) of almost the whole studied area is controlled by the thermodynamic equilibrium fractionation, except the Xibaigou gentle slope belt (A4). The stable isotope compositions in Xibaigou gentle slope belt (A4) characterized by shallow and up-dip areas suggest that late-stage biogenic methane was generated via CO2-reduction associated with meteoric water recharge, which significantly contributes to δ13C(CH4) stripping and higher gas saturation than expected. Furthermore, it is summarized a variation model of gas-bearing properties and δ13C(CH4) values in Yanchuannan CBM block, which shows that the geological controls on gas-bearing properties are consistent with that on stable carbon isotope of methane, and normally lighter δ13C(CH4) ratios corresponds to lower gas-bearing properties domain. Significantly, this result can be used to evaluate and instruct the enrichment law of CBM and benefit its exploration and development in research area.

Hydrogeochemistry characteristics of produced waters from CBM wells in Southern Qinshui Basin and implications for CBM commingled development

The hydrogeochemistry characteristics of water co-produced with coalbed methane (CBM) can act as effective indicators for exploration and development of CBM. This study investigated the geochemical compositions of the water co-produced with CBM extracted from the Pennsylvanian–Permian Taiyuan Formation and Shanxi Formation in Southern Qinshui Basin (SQB), which is the most active area of CBM development in China. Water samples were collected from 27 CBM producing wells involving twenty “single-layer drainage” wells and seven “commingled drainage” wells distributed in six CBM blocks of SQB. The samples were conducted for concentration measurements of major ions and trace elements, and determinations of hydrogen (H) and oxygen (O) isotope ratios. The results show that more than 95% water samples produced from CBM wells in SQB are of Na-HCO3 type, and the remaining approximately 5% are of Na-SO4 type. The stable isotope analyses indicate that the waters co-produced with CBM predominantly have a meteoric origin; the H and O isotopic compositions of most of the produced waters are characterised by “18O drift”, in addition, some individual produced waters exhibit “D drift”. δD and δ18O values of produced waters in the study area are relatively more negative at shallower depths and have a rising trend with the increase of burial depth of the coal seams. It shows that CBM wells with lighter H and O isotopes in the produced waters tend to produce more water during the same producing time; accordingly, the pressure drop funnels of these wells are relatively hard to form. The produced waters from different target coal seams have unique trace elements signatures, and approximately 65% trace elements in the produced waters from the lower main coal seam (No.15 coal seam) have a higher concentration than that in the produced waters from the upper main coal seam (No.3 coal seam). To identify the main source of the produced waters from commingled drainage wells, five indicative trace elements (Li, Ga, Rb, Sr and Ba) were extracted firstly and then the standard templates of indicative trace elements of produced waters from “single-layer drainage” wells were established. Based on the standard templates, the produced water source and the degree of interlayer interference process of commingled drainage wells sampled in this study were analyzed qualitatively. Finally, a case study was dissected to verify the applicability of water chemistry indicators (indicative trace elements) in evaluating the feasibility of CBM commingled drainage.

Controls on Gas Content and Carbon Isotopic Abundance of Methane in Qinnan-East Coal Bed Methane Block, Qinshui Basin, China

Qinnan-East Block is one newly planned coal bed methane (CBM) exploration area in the Qinshui Basin, China, and research on the accumulation of gas in this block is quite limited. In this study, on the basis of a series of laboratory experiments and the latest exploration data, the gas content and carbon isotopic ratio of methane [δ13C(CH4)] in the No. 3 coal seam of Permian Shanxi Formation in Qinnan-East Block were investigated, and then the correlations between δ13C(CH4) and vitrinite reflectance, burial depth, gas content, reservoir pressure, and gas adsorption saturation were analyzed; then, the mechanism controlling the gas bearing properties and the distribution of δ13C(CH4) in the study area were addressed. It turns out that the gas content in the study area ranges from 2.87 to 24.63 m3/t with an average of 13.78 m3/t, the CBM reservoir pressure ranges from 0.86 to 5.96 MPa with an average of 3.09 MPa, the reservoir pressure gradient ranges from 0.11 to 1.06 MPa/100 m with an average of 0.49 MPa/1...

Control of coal facies to adsorption-desorption divergence of coals: A case from the Xiqu Drainage Area, Gujiao CBM Block, North China

Adsorption and desorption of coal to methane are substantially related to coal facies, referring to the production potential of a coalbed methane (CBM) well. Based on analyses of the stratified channel samples from coal seams No. 2, No. 4 and No. 9 in the Xiqu Drainage Area, Gujiao CBM Block, North China, the relationship between coal facies and adsorption-desorption behaviors was first proposed and discussed. Using the coal facies diagrams suggested by previous investigators, four types of coal facies were distinguished in the coal seams, including the upper delta plain wet forest swamp (I), the lower delta plain fen (II), the lower delta plain marsh (III) and the back barrier low moor (IV). The upper delta plain wet forest swamp occurred dominantly, developing at the bottom and top of all the coal seams. Both the ash yield and groundwater index (GWI) tend to increase from coal facies I to IV, whereas the volatile compounds, fixed carbon, organic sulfur, total sulfur, micropore volume and specific surface area, tissue preservation index (TPI) and vegetation index (VI) decreased, which indicates changes in the vegetation types, water supplements and disturbance, acid-base properties and redox conditions in the paleomires. Paleomire evolution accompanied the rise and drop of the sea level, with a transgression or regression process that could be represented by the coal facies sequence. Coal seams No. 2, No. 4 and No. 9 were discriminated into two, three and two evolving stages, respectively, and these stages were characterized by complete cycles, except stage 4-I from the lower delta plain marsh. Mudstone partings in the coal seams deposited during the highest sea level. Collectively, paleomire environments, especially the variation of vegetation types and mire water condition, result in adsorption and desorption divergences among different coal facies. Arborescent plants decrease from coal facies I to IV as the hydrodynamic intensity increases, leading to corresponding changes in botanical tissue preservation, medium oxidizability, mineral content and, ultimately, adsorption and desorption behaviors. In view of the gas content and desorption capacity of the coal layers in the same coal seam, the layers from the upper delta plain wet forest swamp may have the best potential for CBM drainage, followed by those from the lower delta plain fen and marsh, while those from the back barrier low moor may have the worst potential.

Facies analysis and depositional model of late Permian Raniganj formation: Study from Raniganj coal bed methane block

The Raniganj Formation (late Permian) forms the uppermost economic coal-bearing unit of the Gondwana succession. The dominant facies interpreted from analysis of cores from the Raniganj formation are classified as Sandstone dominated facies, Sandstone - shale heterolith facies, Shale facies and Coal facies. The natural Gamma response of Raniganj Formation shows predominance of repetitive fining upwards cycles. Integration of core analysis and geophysical log data of the Raniganj formation indicates meandering fluvial environment. The lower part of Raniganj Formation is channel dominated which corresponds to thick amalgamated sand bodies while the upper part represent overbank shows predominance of channel avulsion indicating a gradual change in accommodation space. Five major fining upward depositional sequences, bounded by sub-aerial unconformities (sequence boundaries) have been dentified in Raniganj formation, based on changes in depositional style that are correlated regionally. Each sequence comprises of Low accommodation system tract (LAST) at base and high accommodation system tract (HAST) at top. LAST is characterized by vertically stacked, multistory amalgamated channel sandstone dominated facies, while floodplain dominated facies characterize HAST. The coal seams deposited in LAST are thicker and relatively more continuous than the frequent thin seams of HAST. Such facies distribution study would be helpful for the development strategy for CBM blocks based on production priority.