Coalbed Methane Gas Research Articles

Application of Density Lineament Mapping as an Indication of CBM Potential in Tanjung Agung, Muara Enim, South Sumatera

Abstract Coal Bed Methane (CBM) gas is formed and trapped within coal seams, offering significant economic potential as it can be converted into electricity or transported through pipelines for various purposes. Indonesia is estimated to have approximately 574 trillion cubic feet (TCF) of CBM gas reserves, capable of meeting domestic energy needs. South Sumatera is classified as a province with the largest coal reserves in Indonesia, indicating abundant potential for CBM gas resources. This research aims to identify potential CBM indicators based on structural lineament interpretation using DEMNAS data. Field research was conducted to gather necessary data, and the findings from the study indicate that the surveyed area has a high potential for Coal Bed Methane (CBM) due to the high lineament density, ranging from 570/km2 to 710/km2 indicating high permeability that supports the well development of CBM gas. Optimal permeability can enhance the quantity of trapped Coal Bed Methane (CBM) gas, given the available space for the gas.

Analytical Model for Rate Transient Behavior of Co-Production between Coalbed Methane and Tight Gas Reservoirs

Analytical Model for Rate Transient Behavior of Co-Production between Coalbed Methane and Tight Gas Reservoirs

High-Order Models for Gas Transport in Multiscale Coal Rock.

The coal reservoirs exhibit great heterogeneity and strong anisotropy in multiscale pore/fracture structures. Developing highly accurate multiscale models for real-time prediction of microgaseous flow in complicated porous media with pronounced contrast in transport coefficients is crucial but not yet available, which is time-consuming, expensive, and even computationally impossible. In this study, a multiscale approximate solution of the gas flow and pressure field is derived in this paper for predicting coalbed methane (CBM) transport in macro-microscopic two-scale porous media of typical coal rocks in Guizhou Province, China, and the detailed finite element algorithm is established. The multiscale approximate solutions are constructed from the first- and second-order auxiliary cell functions and low- or high-order derivatives of the homogenized pressure field, which can accurately approximate the solution of the original problem to a certain extent. The numerical accuracy and validity of the multiscale approximate solutions under various working conditions are analyzed in detail by comparing and verifying the results with the direct numerical simulation results of fine-mesh high-precision finite elements. The results show that the homogenized approximate solution can only roughly capture the characteristics of the macroscopic pressure evolution, the first-order approximate solution can partially reproduce the macro-microscopic pressure oscillation phenomenon, and the second-order approximate solution can accurately predict the pressure profile and its evolution law with time in porous media with macro-micro configuration under various complex conditions. The second- and high-order two-scale approximate solutions constructed in this paper exhibit high numerical accuracy and excellent computational efficiency. We also develop multiscale approximate solutions for predicting microgaseous flow at a low reservoir pressure where the slippage effects are very pronounced. Potential applications of our high-order models to the coal reservoirs with a hierarchical matrix and fractures are discussed. The developed multiscale models exhibit excellent applicability to investigating the crossflow effects and coupling mechanisms between the matrix and cleats or fractures with multiple configurations in the CBM and shale gas reservoirs, which is crucial for the effective implementation of hydraulic fracturing technology. This study provides a fundamental understanding of gas transport in multiscale matrix-fracture networks, which helps to improve the optimization design of hydraulic fracturing in tight reservoirs.

Analysis of Carboniferous‐Permian coal‐accumulating environment and coalbed methane enrichment in the southern Qinshui Basin

Global research on the geological particularities of coal‐accumulating environments and the enrichment patterns of coalbed methane (CBM) is still relatively weak. This paper studies the geological characteristics and coal accumulation patterns of Carboniferous‐Permian coal‐bearing seams in the southern Qinshui Basin. The results show that the coal‐bearing strata in the basin represent the offshore marine and continental intercalated coal seam sediments developed. The southern part of the basin is dominated by lacustrine facies, and the delta front sub‐facies is locally developed. The characteristics of coal accumulation environment in the southern Qinshui Basin are characterized by basement properties, fault networks and coal‐bearing sedimentary facies, which collectively control the spatial and temporal distribution characteristics of the coal‐rich belt. The differences in coal accumulation environment in the southern basin affect the tectonic evolution, the thickness of the coal seam roof and floor and the hydrogeological conditions of the coal‐rich area, which further control the CBM enrichment in the Taiyuan‐Shanxi Formation. The aim of this study is to explore the factors of CBM enrichment and gas control mode, so as to enrich and improve the theory and method of CBM exploration, which will also help identify the appropriate underground geological structure environment for carbon sequestration (CCS), reduce greenhouse gas emissions and effectively respond to the challenge of global warming.

Investigation into the variation characteristics and influencing factors of coalbed methane gas content in deep coal seams

Gas saturation is a critical parameter for the selection and development of coalbed methane, as well as a key indicator reflecting the challenges in coalbed methane development and productivity evaluation of coalbed methane wells. As one of the significant factors influencing gas saturation, gas content plays a vital role in comprehensively investigating coal pore properties to fully comprehend the process and conditions of methane adsorption and desorption. In this study, 3# and 15# coals from Qinshui Basin, China was selected as research subjects. The experimental evaluation encompassed an examination of composition, pore characteristics, permeability characteristics of coal, rock mechanical parameters while discussing the impact of temperature and pressure on coal's adsorption and desorption capacity. The mineral characteristics analysis revealed that vitrinite is the main component with varying percentages and reflectance values in both 3# and 15# coal seams. The gas content and methane concentration in the 15# coal seam are higher than those in the 3# coal seam. The relationship between gas content within a coal seam and burial depth depends on achieving a balance between positive pressure effects caused by overburden stress exertion on gases trapped within pores under high pressures during burial history versus negative temperature effects due to cooling during geological processes over time. Predictions were made regarding deep-coal gas content which holds significant implications for accurately understanding variations in desorption behavior along with optimizing fracturing engineering.

Upgrading low-concentration oxygen-bearing coal bed methane by dual-reflux vacuum swing adsorption

Fugitive methane (CH4) is a typical by-product of mining processes, which is commonly known as coal bed methane (CBM) or coal mine gas (CMG). The capture of these CH4 gases can simultaneously avoid greenhouse gas emissions and provide extra energy benefits. However, the explosion risk of low-concentration CBM (CH4 molar fraction ≤ 30%) requires strictly safe operating protocols to conduct the capture process. Dual reflux vacuum swing adsorption (DR-VSA) is a promising candidate with a vacuum operating condition which can lower the explosion risk and simultaneously reach CH4 enrichment and O2 removal targets in product and effluent streams. Herein, a low-concentration oxygen-bearing CBM (20% CH4, 16% O2 and 64% N2) can be upgraded to 69.7 mol% in the product gas while ensuring an effluent concentration of 2.5 mol% by the DR-VSA cycle using ionic liquidic zeolites (ILZ) as the adsorbents. A rigorous safety analysis has been conducted to investigate the explosion risk in the adsorption column and product tank, suggesting that the DR-VSA process is a safe technology for upgrading low-concentration oxygen-bearing methane.

Exploring Geochemical Signatures in Production Water: Insights from Coal Bed Methane and Shale Gas Exploration—A Brief Review

This article furnishes a brief review of the geochemistry of waters produced during coal bed methane and shale gas exploration. Stable deuterium and oxygen isotopes of produced waters, as well as the stable carbon isotope of dissolved inorganic carbon in these waters, are influenced by groundwater recharge, methanogenic pathways, the mixing of formation water with saline water, water–rock interactions, well completion, contamination from water from adjacent litho-units, and coal bed dewatering, among many others. Apart from the isotopic fingerprints, significant attention should be given to the chemistry of produced waters. These waters comprise natural saturated and aromatic organic functionalities, metals, radioisotopes, salts, inorganic ions, and synthetic chemicals introduced during hydraulic fracturing. Hence, to circumvent their adverse environmental effects, produced waters are treated with several technologies, like electro-coagulation, media filtration, the coupling of chemical precipitation and dissolved air flotation, electrochemical Fe+2/HClO oxidation, membrane distillation coupled with the walnut shell filtration, etc. Although produced water treatment incurs high costs, some of these techniques are economically feasible and sustain unconventional hydrocarbon exploitation.

The method of improving the cementing quality of the interface in deep coalbed gas well through the wetting reversal technique

ABSTRACT Coalbed methane, also known as coalbed methane gas, is a natural gas formed by the biogeochemical and pyrolysis processes during the formation and evolution of coal and stored in coal seams. Compared with conventional coalbed methane, deep coalbed methane has a rich resource and is an important substitute for natural gas increase, storage, and production. During the process of coalbed methane extraction, the inability of coal rock to bond well with cement slurry leads to a decrease in the quality of cementing, which has become one of the main problems affecting the extraction of deep coalbed methane. To address this issue, this paper first analyzes the microstructure of the coal rock-cement interface to reveal the mechanism of strengthening the coal rock-cement interface bonding. Then, using the wettability of coal rock as an evaluation index and the surfactant wetting modification method, the paper modified the surface of coal rock to enhance its hydrophilicity, optimized the suitable coal rock wetting modification agent, and finally evaluated the enhancement effect of the coal rock wetting modification agent on the quality of the coal rock-cement interface bonding through interface bonding experiments. The research results indicate that the hydrophobicity of coal rock surface is the main reason for the poor bonding between coal rock and cement. The three primary surfactants can improve the water wettability of coal and rock surfaces by 41.57%–52.95%, among which AES surfactant has the best improvement effect. After soaking in 0.5% AES solution at 85°C for 8 min, the hydrophilicity of coal rock can be increased by 72.3%. There are no obvious cracks between the coal rock-cement interface, and the bonding quality of the coal rock-cement interface has increased 2.69 times. Coal rock surface wetting modification can effectively enhance the interface bonding effect, which is conducive to improving the quality of cementing of deep coalbed methane.

Interchangeable effect of polyols-based zeolite on the separation of CO2, CH4, and N2 gases

The adsorptive separation process for CO2/CH4 and CH4/N2 gas separation has commercial potential, in biogas, Coalbed Methane process etc. although it remains to strive due to the absence of effective adsorbents. Zeolite NaY was used in this study due to its uniform pore structures, surface properties, and potential gas separation adsorbent. Zeolite NaY was modified by polyether polyols (PEPO) to get an adsorbent for selective separation of CO2/CH4 and CH4/N2 gas mixtures. The PXRD, FT-IR, GPC, 1H NMR, TEM, and surface area analysis were used to characterize the PEPO and PEPO-modified zeolite. The single component equilibrium adsorption desorption isotherms with PEPO modified NaY zeolites and NaY zeolite for CO2, CH4 and N2 were measured at 298, 313, and 328 K and up to 5 bar pressure. The isotherm data of CO2, CH4 and N2 were fitted in Dual Site Langmuir equations, and adsorption selectivity of CO2/CH4 and CH4/N2 gas mixtures was predicted using Ideal Adsorbed Solution Theory (IAST) method for 90:10, 50:50 (vol/vol) CH4/N2 and 80:20, 50:50 (vol/vol) CO2/CH4 feed gas mixtures representing coal bed methane gas composition and pressure conditions. The high surface area and hydroxyl groups in PEPO-modified NaY enhanced selectivity for CO2/CH4 and CH4/N2 gas separation. The selectivity predicted by the IAST method were 106.12 and 95.34 for 0.5 % PEPO-NaY (80:20 v/v and 50:50 v/v) for CO2/CH4 and 3.95 and 3.52 for 2 % PEPO-NaY (90:10 v/v and 50:50 v/v) for CH4/N2 at 298 K up to 5 bar respectively.

Quantitative Prediction of Deep Coalbed Methane Content in Daning-Jixian Block, Ordos Basin, China

The potential of deep coalbed methane resources is substantial. Gas content is an important parameter for resource assessment. At present, the gas content test method commonly used for shallow coal reservoirs is not suitable for determining deep coalbed methane gas content. Therefore, it is urgent to establish a prediction method for deep coalbed methane gas content. This study aims to quantitatively predict the gas content of coalbed methane in deep coal reservoirs and uncover its influencing factors. For this purpose, we selected the Daning-Jixian area, a region in China with relatively advanced development of deep coalbed methane, as a case study. It established a prediction model for adsorbed gas and free gas content in deep coal reservoirs through a series of experimental tests, encompassing gas content, coal quality, isothermal adsorption, and nuclear magnetic resonance. The model sheds light on the impact of coal-rock characteristics, coal quality attributes, and pore characteristics on adsorbed gas and free gas content. The results show that adsorbed gas dominates in deep coal reservoirs with a high metamorphic degree and that the average proportion of adsorbed gas under reservoir burial depth is 80.15%. At a depth of approximately 1800~2000 m, a turning point is observed where adsorbed gas content begins to decline. Beyond this depth range, the detrimental effect of temperature on coalbed methane content surpasses the beneficial impact of pressure. Coal quality characteristics play a major role in controlling adsorbed gas content, and an increase in water content and ash yield significantly reduces the adsorption performance of coal reservoirs. The content of free gas increases with the increase in burial depth, with its controlling factors primarily being confining pressure and porosity. The increase in the proportion of micropores in the pores of deep coal reservoirs has an adverse effect on the content of free gas. The proportion of adsorbed gas in deep coal reservoirs gradually decreases with the increase in burial depth, while the proportion of free gas gradually rises with the increase in burial depth. The development potential of free gas cannot be overlooked in the exploration and development of deep coalbed methane.

Surface jump mechanism of gas molecules in strong adsorption field of coalbed methane reservoirs

The gas in the coalbed methane (CBM) reservoirs is mainly in the adsorbed state, and the influence of surface jump of adsorbed gas on CBM migration and gas well productivity cannot be ignored. In this paper, firstly, the concepts of strong adsorption field and gas molecular equivalent motion volume are proposed, and the analytical relationship between gas filling degree and equivalent molecular free path is established. Secondly, an analytical model of adsorbed gas concentration and equivalent molecular free path is established, and the linkage mechanism of “ gas filling degree - equivalent molecular free path” of gas occurrence in strong adsorption field is revealed. Thirdly, the molecular dynamics mechanism of gas occurrence and surface jump in the strong adsorption field is revealed, and the coupling effect mechanism of “coal rank-pressure” on microscale surface jump is clarified. It is found that (a) the equivalent motion volume of gas molecules can effectively characterize the gas filling degree in the strong adsorption field; (b) when the activation energy is higher than the isosteric heat of the strong adsorption field, gas molecules enter the adsorption/desorption balance layer and transfer to different restricted areas; (c) when the temperature and adsorbate are determined, the coal properties and pressure are the keys to control the surface jump.

Full-scale pore characteristics in coal and their influence on the adsorption capacity of coalbed methane.

Coalbed methane (CBM) is primarily stored and transported through the pores in the coal matrix, making it essential to study the development of different scales of pores in coal to better understand the evaluation and exploration of CBM. In this study, four coal samples of varying ranks (Ro,max = 0.68%-2.86%) were selected, and different scale pores were obtained through low-pressure CO2 and Ar adsorption (LP-CO2/ArGA) and mercury intrusion porosimetry (MIP) experiments. A full-scale pore evaluation model was established, and the impact of pores on methane adsorption and restriction was analyzed and discussed through high-pressure adsorption experiments. Our results show that (1) at high pressures (> 100 MPa), the MIP technique caused pore compression and overestimated the pore size below 30 nm by up to 47.2%; (2) to obtain a comprehensive pore evaluation, we developed an accurate model that combines LP-CO2/ArGA with NLDFT and BJH and NLDFT models to determine micropore (0.3-1.5 nm) and mesopore (1.5-30 nm) parameters. By combining this model with MIP test results, we can obtain a full-scale pore size in the range of 0.3 nm-200 μm; (3) coal rank affected the development of full-scale pore characteristics. As coal rank increased, the specific surface area (SSA) of micropores and adsorption capacity of methane first decreased, then increased. Micropores were found to be the most important storage space for CBM and control gas adsorption, with a microporous SSA and PV to total SSA and total PV ratio of 97.93% and 63.69%, respectively. (4) We also observed a significant linear relationship between the fractal dimension of micropores and the Langmuir volume (VL) based on fractal theory. As the fractal dimension increased, VL also increased (R2 = 0.8581), indicating that VL is controlled by the complexity of micropores, which is consistent with the comprehensive evaluation index (Dt) and VL (R2 = 0.8744). Based on our predicted model, VL can be estimated using the SSA of micropores and Dt. Our findings shed light on the relationship between pore morphology and CBM occurrence and have practical implications for fields such as catalytic synthesis, E-CBM, and gas purification.

Coal bed methane gas in-place estimation for the North-Western region of Zimbabwe

Coal Bed Methane (CBM) is natural gas occurring in coal seams. It can be used for domestic (heating and cooking) and industrial purposes, electricity generation, transportation (as compressed natural gas or liquefied natural gas), and in boilers supporting mining operations. It is established that Zimbabwe has CBM in the North-Western region. At the time of this study, only one organization (Industrial Development Corporation) has reported an Original Gas in Place (OGIP) estimate for the region as 765 Bm3. In this study we use Monte Carlo Simulation (MCS) to estimate the range of OGIP values for the region. MCS is a widely used probabilistic method, preferred over deterministic methods in which only best-estimate values of parameters are used to predict a single OGIP value. This single OGIP value may be either positively (overestimated) or negatively skewed (underestimated). However, the probabilistic approach using MCS accounts for the uncertainty in values of parameters. This is done by incorporating appropriate range and probability distributions (e.g. triangular, normal, uniform, etc.) of input parameters (e.g. target area, formation thickness, coal bulk density, and adsorbed methane content), and repeating calculations to generate a cumulative distribution curve for the OGIP. The generated curve provides statistical confidence levels represented as probability distributions, i.e. P10, P50, and P90 represents low, mid, and high probability estimates, respectively. Our results show that P10, P50, and P90 values for the North-Western region OGIP are 5699 Bm3, 2347 Bm3, and 706 Bm3, respectively. The Resource Density (RD) estimation is found to range from 0.015 Bm3/km2 to 0.113 Bm3/km2 over the geographic area. This range is comparable to Alberta plains shallow and deep basins in Canada which boosts a higher level of confidence for CBM potential in Zimbabwe. The results are encouraging for further exploration and planning of exploitation of CBM in Zimbabwe.

A Review of Biogenic Coalbed Methane Experimental Studies in China

Biogenic coalbed methane (CBM) is an important alternative energy that can help achieve carbon neutrality. Accordingly, its exploration and development have become a research hotspot in the field of fossil energy. In this review, the latest detection technologies for and experimental research on biogenic CBM in China in recent decades are summarized. The factors influencing the generation of biogenic CBM and the identification method of biogenic CBM are systematically analyzed. The technologies to detect biogas and the research methods to study microbial diversity are summarized. The literature shows that biogenic CBM is easily produced in the presence of highly abundant organic matter of low maturity, and the organic matter reaching a certain thickness can compensate for the limitation of biogenic CBM gas production due to the small abundance of organic matter to a certain extent. Biogenic CBM production could be increased in an environment with low salinity, medium alkalinity, and rich Fe2+ and Ni2+ sources. Furthermore, biogenic CBM can be identified by considering three aspects: (1) the presence of gas composition indicators; (2) the content of heavy hydrocarbon; and (3) variation in the abundance of biomarkers. In recent years, research methods to study the microbial community and diversity of CBM-producing environments in China have mainly included 16S rRNA gene library, fluorescence in situ hybridization, and high-throughput sequencing, and the dominant microorganisms have been determined in various basins in China. The results of numerous studies show that the dominant bacterial phyla are commonly Firmicutes and Proteobacteria, while the archaeal fraction mainly includes Methanoculleus, Methanobacterium, Methanocorpusculum, and Methanothrix. This review summarizes and discusses the advances in biogenic CBM production and the associated microbial community in order to promote further development of coal biotransformation and CO2 bio-utilization to meet energy demands under carbon neutrality.

Modeling Gas Adsorption–Desorption Hysteresis in Energetically Heterogeneous Coal and Shale

Adsorption of gases in porous adsorbents such as coal and shale generally exhibits the phenomenon of hysteresis. Most of the previous studies on desorption hysteresis were conducted via experimental tests. However, few theoretical models that represent adsorption–desorption hysteresis of gases in porous sorbents are available. To address this issue, this work develops a new adsorption–desorption model for describing adsorption and desorption isotherms of gases with hysteresis. Particularly, the energetically heterogeneous surfaces of an adsorbent are considered via the patchwise model. Based on the change in site energy distribution, a logarithmically pressure-dependent hysteresis index, which is used to measure the degree of hysteresis, is derived for quantitative assessment of the degree of hysteresis. Besides, the correlation between the desorption isotherm and initialized pressure for desorption is established. The accuracy of the proposed model to adequately describe the adsorption–desorption hysteresis of gas in coal and shale is demonstrated by validating the model against laboratory experiments obtained from the literature. The results indicate that the adsorption isotherm depends significantly on site energy distribution. By comparing the site energy distributions for adsorption and desorption isotherms, it is found that the desorption hysteresis can be attributed to the change in pore size distribution caused by adsorption-induced deformation. The analyses support that the proposed model can be used as an effective tool to quantitatively predict the amount of released gas during desorption, which is significant for designing coalbed methane or shale gas production and assessing long-term CO2 storage behavior.

Reinforcement learning based optimization algorithm for maintenance tasks scheduling in coalbed methane gas field

The Coalbed Methane (CBM) well maintenance tasks scheduling optimization is of importance for improving the CBM production efficiency. Traditionally, this problem is addressed using mathematical model based classical optimization method or some meta-heuristic algorithms. However, due to the large-scale nature of this problem, these trials often fail in practical use. Therefore, the Q-learning algorithm based solving method is proposed in this paper. An interactive environment for reinforcement learning is constructed. To validate the effectiveness of proposed method, scenarios with different scales are provided. For the cases with 10, 14, 20, 30, 47, 60, 80 and 100 maintenance tasks respectively, the required solution time is 3.66 s, 4.94 s, 7.66 s, 12.48 s, 21.82 s, 30.82 s, 48.33 s, 73.17 s respectively. The proposed Q-learning algorithm is insensitive with the problem scale, which is promising. Moreover, the Q-learning based algorithm is more efficient than the traditional algorithm along with the increase of the number of tasks.

Correlating Coal Petrology and Methane Adsorption Parameters of High-Volatile Bituminous Coals with P-Wave Velocity.

The parameters of coal petrology and methane adsorption are significant to exploit coal and coalbed methane (CBM). Based on borehole core sampling, a new method using the P-wave velocity to predict coal maceral, coal face index, and Langmuir parameter of high-volatile bituminous coals was proposed. The results showed that the P-wave velocity correlated positively with coal skeletal density, apparent density, and ash yield with fitting coefficients (R 2) of 0.55, 0.57, and 0.57, respectively, but it negatively correlated with coal porosity and moisture content with R 2 of 0.56 and 0.60, respectively. Vitrinite, ranging from 14.8 to 82.7% with an average of 53.8%, positively correlated with coal porosity due to more micropores in vitrinite and thus negatively correlated with the density and P-wave velocity. Inertinite content was in the range of 5.4 to 27.4% with an average of 11.0%, which correlated negatively with the coal porosity and thus positively with the density and P-wave velocity for most of the samples. Furthermore, the P-wave velocity was weakly positively correlated with mineral content, and a negative correlation was found between the P-wave velocity and vitrinite/inertinite ratio (V/I), gelification index (GI), and Langmuir volume (V L). The porosity (Y 1), vitrinite content (Y 2), inertinite content (Y 3), and V L (Y 4) of coals could be predicted based on the equations as follows: Y 1 = 7842.4 e-0.003X , Y 2 = -0.0003X 2 + 1.0731X - 924.09, Y 3 = 0.0003X 2 - 1.2797X + 1405, and Y 4 = -0.04X + 101.24, where X is the P-wave velocity. Generally, P-wave velocity could be largely used to predict the variations of the coal maceral and methane adsorption capacity of high-volatile bituminous coals, providing a new and valuable approach for CBM exploration and gas prevention in coal mines.

Productivity enhancement in multilayered coalbed methane reservoirs by radial borehole fracturing

Coalbed methane (CBM) is an important unconventional natural gas. Exploitation of multilayered CBM reservoir is still facing the challenge of low production rate. Radial borehole fracturing, which integrates radial jet drilling and hydraulic fracturing, is expected to create complex fracture networks in multilayers and enhance CBM recovery. The main purpose of this paper is to investigate the mechanisms and efficacy of radial borehole fracturing in increasing CBM production in multiple layers. First, a two-phase flow and multi-scale 3D fracture network including radial laterals, hydraulic fractures and face/butt cleats model is established, and embedded discrete fracture model (EDFM) is applied to handle the complex fracture networks. Then, effects of natural-fracture nonuniform distribution are investigated to show the advantages of targeted stimulation for radial borehole fracturing. Finally, two field CBM wells located in eastern Yunnan-western Guizhou, China were presented to illuminate the stimulation efficiency by radial borehole fracturing. The results indicated that compared with vertical well fracturing, radial borehole fracturing can achieve higher gas/water daily production rate and cumulative gas/water production, approximately 2 times higher. Targeted communications to cleats and sweet spots and flexibility in designing radial borehole parameters in different layers so as to increase fracture-network complexity and connectivity are the major reasons for production enhancement of radial borehole fracturing. Furthermore, the integration of geology-engineering is vital for the decision of radial borehole fracturing designing scheme. The key findings of this paper could provide useful insights towards understanding the capability of radial borehole fracturing in developing CBM and coal-measure gas in multiple-thin layers.

CBM Desorption Model and Stages Based on a Natural Desorption Experiment.

Coalbed methane (CBM) desorption modeling is critical for understanding CBM desorption mechanisms and objectively analyzing the production characteristics of CBM wells. According to the CBM natural desorption experimental data of 64 coal samples taken from the Qinshui Basin, we established a CBM desorption model, quantitatively identified the CBM desorption stages, and discussed the relationship between CBM desorption characteristics and well productivity. The results indicated a very significant functional relationship between the CBM natural desorption time and cumulative desorption quantity, which could be accurately described by the model V = aLt/(t + bL). On the basis of this model and the numerical description of the desorption data, the CBM natural desorption process was divided into four stages: the desorption startup stage, desorption sensitive stage, desorption steady stage, and desorption decay stage. As indicated by analogical reasoning of the CBM well production process, the desorption startup stage corresponded to the drainage-based pressure drop stage, the desorption sensitive and steady stages corresponded to the steady production stage, and the desorption decay stage corresponded to the production declining stage. The CBM adsorption time exponentially decreased with the increase in the average CBM desorption rate and with the increase in the CBM gas content and vitrinite/inertinite ratio. Furthermore, within a certain range of desorption pressure, a high ratio between the adsorption time and gas content corresponded to the extension of the steady production stage of CBM wells, whereas higher or lower ratios were adverse to steady production.

Modeling and Forecasting of Coal Bed Methane Reservoir from Raniganj Coalfield, India

Demand for a cleaner source of energy is increasing in India. In the search for alternate energy sources, coal bed methane gas receives considerable attention for its potential as a good energy source. During the coalification process, methane gas is captured in the coal seams and later released during coal mining operations. Coal bed methane separation is crucial for both economic benefit and methane emission reduction. The methane production from seams is an efficient way to reduce greenhouse emissions and provide a safe mining operation environment. In India, the production of coal bed methane on a commercial scale has been recently observed. In the present paper, an attempt is made to understand and establish a 3-D excavation of coal bed methane from reservoir simulation (COMET3) for Gondwana coal seams in the Sitarampur block of the Raniganj coalfield in India. The simulation study was carried out for a period of 25 years for the recovery of methane from the reservoir. It is observed from the simulation study that 372 million cubic meters CO2 equivalent greenhouse gas emissions can be prevented by the extraction of methane with space and time. The fracture gas concentration increases with time, and it is observed that fractures are fully saturated with gas in 3000 days.