Critical Desorption Pressure Research Articles

The Gas Production Characteristics of No. 3 Coal Seam Coalbed Methane Well in the Zhengbei Block and the Optimization of Favorable Development Areas

The characteristics and influencing factors of gas production in CBM wells are analyzed based on the field geological data and the productivity data of coalbed methane (CBM) wells in the Zhengbei block, and then the favorable areas are divided. The results show that the average gas production of No. 3 coal seam CBM wells in the study area is in the range of 0~1793 m3/d, with an average of 250.97 m3/d; 80% of the wells are less than 500 m3/d, and there are fewer wells above 1000 m3/d. The average gas production is positively correlated with gas content, critical desorption pressure, permeability, Young’s modulus, and Schlumberger ratio, and negatively correlated with fracture index, fault fractal dimension, Poisson’s ratio, and horizontal stress difference coefficient. The relationship between coal seam thickness and the minimum horizontal principal stress is not strong. The low-yield wells have the characteristics of multiple pump-stopping disturbances, unstable casing pressure control, overly rapid pressure reduction in the single-phase flow stage, sand and pulverized coal production, and high-yield water in the later stage during the drainage process. It may be caused by the small difference in compressive strength between the roof and floor and the coal seam, and the small difference in the Young’s modulus of the floor. The difference between the two high-yield wells is large, and the fracturing cracks are easily controlled in the coal seam and extend along the level. The production control factors from strong to weak are as follows: critical desorption pressure, permeability, Schlumberger ratio, fault fractal dimension, Young’s modulus, horizontal stress difference coefficient, minimum horizontal principal stress, gas content, Poisson’s ratio, fracture index, coal seam thickness. The type I development unit (development of favorable areas) of the Zhengbei block is interspersed with the north and south of the block on the plane, and the III development unit is mainly located in the east of the block and near the Z-56 well. The comprehensive index has a significant positive correlation with the gas production, and the prediction results are accurate.

An Analytical Method for Timely Predicting of Coal Seam Pressure during Gas Production for Undersaturated Coalbed Methane Reservoirs

Coal seam pressure is an important parameter for production performance evaluation and prediction of coalbed methane (CBM). CBM production from undersaturated CBM reservoirs can be divided into two stages according to critical desorption pressure. At present, few prediction models of coal seam pressure performance consider the comprehensive influence of critical desorption pressure, dissolved gas, matrix shrinkage, and stress sensitivity. For the purpose of accurately predicting coal seam pressure during gas production for an undersaturated coalbed methane reservoir, the material balance principle is used to establish the analytical method for predicting coal seam pressure, considering the comprehensive influence of the critical desorption pressure, dissolved gas, matrix shrinkage, and stress sensitivity. Then, the proposed method is verified against a numerical simulation case using a computer modelling group (CMG) and two actual coalbed methane wells. Finally, the sensitivities of influencing factors on the coal seam pressure are analyzed. The results show that good agreements were obtained between the calculated coal seam pressures using the proposed method and those from the CMG-GEM simulation case and actual CBM wells, with the relative errors all being less than 1%. When ignoring the influence of critical desorption pressure and mistaking pd for pi as well as ignoring Cs, the relative error can reach as high as 31.3%. The main factors affecting the coal seam pressure are the critical desorption pressure and free gas saturation. The proposed method is simple to use, and without shutting-in the well, it can provide an important basis for production performance evaluation and development strategies.

A Fully Coupled Gas–Water–Solids Mathematical Model for Vertical Well Drainage of Coalbed Methane

The coupling relationship between the deformation field, the diffusion field, and the seepage field is an important factor in fluid transport mechanisms in the long-term coalbed methane (CBM) exploitation process. A mathematical model of gas–water two-phase fluid–structure coupling in a double-porosity medium in coal reservoirs is established in this paper. Taking Hancheng Block, a typical production block in Qinshui Basin, as the geological background critical desorption pressure, reservoir permeability anisotropy is considered in the model. COMSOL Multiphysics (COMSOL_6.0) was used to create the model. The accuracy and rationality of the model were verified by comparing field production data with the results of the simulation. Using the simulation, the influence law of various reservoir geological characteristics parameters (Langmuir strain constant, ratio of critical desorption pressure to reservoir pressure of coal seam (CDPRP), elastic modulus, initial water saturation, Langmuir pressure, etc.) on CBM productivity, reservoir pressure, and permeability ratio was discussed, and a thorough analysis of the factors affecting productivity was obtained using the orthogonal test method. The findings of this study indicate that the change in permeability is the result of the superposition effect of many factors. Different stages of drainage have different primary regulating factors. Rock skeleton stress has a consequence on coal matrix permeability in the early drainage stage, and coal matrix shrinkage is primarily impacted in the later drainage stage. Besides the initial water saturation, other reservoir geological parameters (e.g., CDPRP, Langmuir volume, Langmuir strain constant, elastic modulus) have a strong relationship with productivity. When the value of coal geological parameters increases, the degree of productivity release is higher (as the initial water saturation increases, the production decreases correspondingly). Different coal and rock parameters have varying levels of impact on the drainage stage of CBM wells. The influences of the CDPRP, Langmuir volume, Langmuir strain constant, and elastic modulus on gas production are mainly concentrated in the initial and intermediate drainage stages and begin to fall off during the last drainage stage. Per the multi-factor analysis, the main coal–rock parameters affecting the productivity release are the Langmuir strain constant, followed by the CDPRP and other parameters. The analysis findings can offer theoretical guidance for CBM well selection and layer selection and enhance the block’s overall CBM development level. The improved productivity prediction model for CBM, which is based on fluid–structure coupling theory, can offer a new technical benchmark for CBM well productivity prediction.

An Explicit Data-Driven Model for Estimation of Free and Absorbed Gas Volumes in Shale Gas Reservoirs.

Shale gas reservoir fluid flow is characterized by complex interactions between a number of variables, including stress sensitivity, matrix shrinkage, and critical desorption pressure. The behavior and productivity of shale gas reservoirs are significantly influenced by these variables. Therefore, in this study, an in-house finite element poro-elastic simulator was integrated with an in-house Fortran-coded artificial neural network model for accurate estimation of free and absorbed gas volumes in shale gas reservoirs, taking into account the combined effects of stress sensitivity, matrix shrinkage, and critical desorption pressure. The in-house finite element simulator was used to create a database of free and absorbed gas volumes under different reservoir, fluid, and geo-mechanical characteristics of shale gas, while the in-house neural network code was utilized using the outcomes of the poro-elastic simulator in order to propose an explicit data-driven mathematical formula of free and absorbed volumes of shale gas. The study findings indicate that the neural network model achieved high accuracy with an R-squared value exceeding 99% during both the training and blind-testing phases. The newly developed ANN-based correlations can be used as a quick and easy-to-use tool to forecast the volume of shale gas in place both free and adsorbed without any prior experience with utilizing or implementing machine learning models.

Optimization Method of Production System for Coalbed Methane Wells throughout Life Cycle

Different from conventional gas reservoirs, the permeability of coalbeds is affected by stress sensitivity and matrix shrinkage during production. These two conditions lead to lower permeability in the reservoir and affect the production efficiency of the gas well. In addition, coalbed methane wells have single-phase water flow in the initial stage of production. When the reservoir pressure is reduced to its critical desorption pressure, the adsorbed gas in the reservoir desorbs into the pore space and participates in the flow. The flow state in the reservoir changes from single-phase to two phase, and the permeability of the reservoir decreases. The occurrence of these three damage mechanisms is related to the flow rate of fluid in the reservoir. At present, there is a lack of research on the optimization of drainage and production systems considering the damage mechanism of coal reservoirs. This study comprehensively considers how to optimize the production rate of coal reservoirs under the influence of stress sensitivity, matrix shrinkage and two phase flow in the production process to achieve the purpose of production with the least damage to the reservoir.

An Advanced Early-Stage Production Forecasting Model for Middle-High Rank Coal Development

Reasonable production prediction of coalbed methane (CBM) is of great significance for improving the economic benefit of CBM reservoirs. Current prediction methods for CBM production focus on the later stages of development, with few studies on early production forecasting. The objective of this work is to provide a reliable new idea for the early production prediction of CBM through various analyses and demonstrations. First, the CBM development modes are classified according to the production characteristics of the Panhe demonstration block of Shaanxi Province, China. Second, an efficient and feasible early production prediction model is established based on the geological potential and development potential. Finally, using the proposed model, different modes’ production characteristics and optimization strategies are analyzed. The research shows that the gas production profiles can be divided into two modes: single-peak mode (SPM) and multipeak mode (MPM). The peak production and average EUR of the SPM are 49.6% and 32.4% higher than those of the MPM, but the stable production period is only 0.2~1 year. In terms of the geological potential of CBM wells, the gas content, critical desorption pressure, and formation coefficient of the SPM are 6.7%, 13.3%, and 37.8% higher than those of the MPM, and the gas wells are mainly located in the high part of the coal seam (the average height difference is about 20 m). Besides, the concept of quasidesorption degree Pdq is innovatively introduced to characterize the development potential of gas well. The Pdq has an exponential relationship with CBM production, and the coefficient of the exponential term in SPM is approximately 22% larger than that in MPM. Moreover, the production of gas wells is greatly affected by the continuity of production. In the process of gas production, the influence of factors such as equipment shutdown should be minimized. To examine the applicability of the proposed method, the model is applied to an actual CBM well in Panhe, and the prediction accuracy is higher than 85%.

Analysis of Coalbed Methane Production Characteristics and Influencing Factors of No. 15 Coal Seam in the Shouyang Block

Based on the basic geological data and production data of coalbed methane wells in the Shouyang Block, the characteristics and influencing factors of coalbed methane well production were analyzed, and the primary controlling factors were identified by the grey correlation method. The results show that the average daily gas production of the coalbed methane wells in the study area for the single mining of No. 15 coal ranges from 0 to 604.34 m3/d, with an average of 116.82 m3/d. The overall average gas production is relatively low, with only 7 of the 42 wells having an average gas production greater than 200 m3/d. Gas production tends to increase as the gas content increases. There is a significant positive correlation between gas saturation and average gas production. Burial depth and coal seam thickness also show a positive correlation with average gas production. On the other hand, there is a negative exponential relationship between average gas production and critical desorption pressure. Permeability, as determined by well tests in the area, exhibits a negative correlation with the gas production of coalbed methane wells. The correlation between gas production and the mean three-dimensional stress is weak. As the fractal dimension D value of fractures increases, gas production decreases. A smaller difference in horizontal principal stress is more favorable for the formation of network fractures, facilitating reservoir fracturing and resulting in better reconstructive properties. Moreover, an increase in the sand–mud ratio leads to a decrease in average gas production. The correlation between fault fractal dimension and average gas production is weak. The grey correlation method was employed to determine the controlling factors of coalbed methane production in the study area, ranked from strong to weak, as follows: coal thickness > fracture fractal dimension D value > gas saturation > coal seam gas content > horizontal stress difference coefficient > permeability > critical desorption pressure > mean value of three-dimensional principal stress > coal seam burial depth > sand–mud ratio > fault fractal dimension.

Influence of competitive adsorption, diffusion, and dispersion of CH4 and CO2 gases during the CO2-ECBM process

The displacement mechanisms of adsorbed CH4 by injected CO2 at high pressures in CO2-enhanced coalbed methane (CO2-ECBM) processes involve competitive adsorption, diffusion, and dispersion. Inherent coal heterogeneity and the complexity of the CO2-CH4 displacement model make CO2-ECBM modelling and optimal process design challenging. The pure gas isotherms and Langmuir adsorptions constants for CO2 and CH4 were determined using the manometric method. Notably, CO2 shows higher adsorption capacity than methane, and Langmuir volume (VL) for CO2 is 2 to 2.3 times that of methane. High pressure adsorption isotherms and experimentally determined diffusion coefficients set the sorption kinetics. The diffusion coefficient of CH4 for all four samples was in the range between 1.35×10-12 and 7.42×10-12 m2/s, while for CO2, it varied from 10.9×10-12 to 15.48×10-12 m2/s. The new concept of caucus time was introduced in the sorption kinetics of CO2 and CH4. Each sample has distinct caucus time and was positively correlated with Langmuir volumes of CO2 and CH4 with R2 > 0.9. The critical desorption pressure above which CH4 exhibits retrograde adsorption behaviour is evaluated from co-adsorption isotherms adopting Ideal Adsorption Solution Theory (IAST). The critical desorption pressure for the four samples were 1220, 460, 575 and 740 psi respectively. IAST also predicts a critical mole fraction (∼30 %) in the gas phase above which CO2 becomes the dominant adsorbed phase on coal surfaces. The results of Advective-Dispersion modelling at a larger scale illustrate the value of the Dispersion coefficient in forecasting and screening. Since the time available for diffusion versus dispersion depends upon flowrate, high values of dispersion coefficient can negatively influence favourable competitive adsorption expectations through higher operational cost in CO2 separation. This work suggests the existence of both an optimal operational pressure and flowrate to maximize the potential of CO2-ECBM technology demonstrated in competitive adsorption modelling.

Estimation of Free and Adsorbed Gas Volumes in Shale Gas Reservoirs under a Poro-Elastic Environment

Unlike conventional gas reservoirs, fluid flow in shale gas reservoirs is characterized by complex interactions between various factors, such as stress sensitivity, matrix shrinkage, and critical desorption pressure. These factors play a crucial role in determining the behavior and productivity of shale gas reservoirs. Stress sensitivity refers to the stress changes caused by formation pressure decline during production, where the shale gas formation becomes more compressed and its porosity decreases. Matrix shrinkage, on the other hand, refers to the deformation of the shale matrix due to the gas desorption process once the reservoir pressure reaches the critical desorption pressure where absorbed gas molecules start to leave the matrix surface, causing an increase in shale matrix porosity. Therefore, the accurate estimation of gas reserves requires careful consideration of such unique and complex interactions of shale gas flow behavior when using a material balance equation (MBE). However, the existing MBEs either neglect some of these important parameters in shale gas reserve analysis or employ an iterative approach to incorporate them. Accordingly, this study introduces a straightforward modification to the material balance equation. This modification will enable more accurate estimation of shale gas reserves by considering stress sensitivity and variations in porosity during shale gas production and will also account for the effect of critical desorption pressure, water production, and water influx. By establishing a linear relationship between reservoir expansion and production terms, we eliminate the need for complex and iterative calculations. As a result, this approach offers a simpler yet effective means of estimating shale gas reserves without compromising accuracy. The proposed MBE was validated using an in-house finite element poro-elastic model which accounts for stress re-distribution and deformation effects during shale gas production. Moreover, the proposed MBE was tested using real-field data of a shale gas reservoir obtained from the literature. The results of this study demonstrate the reliability and usefulness of the modified MBE as a tool for accurately assessing free and adsorbed shale gas volumes.

Estimation of Shale Gas Reserves: A Modified Material Balance Equation and Numerical Simulation Study

This study presents a comprehensive material balance equation (MBE) to estimate the reserve of shale gas reservoirs including free and adsorbed gas volume. The presented material balance equation takes into account the effect of stress change, matrix shrinkage, water volume production and influx, and critical desorption pressure. The material balance equation is converted into a linear relationship between the reservoir production and expansion parameters used during the derivation procedures that include rock-fluid properties and production history data. The proposed straight line reserve evaluation technique yields a slope of original free and absorbed gas in organic matrix, while the y-intercept yields the volume of original free gas in the in-organic matrix. A field case study of shale gas located in Australia is presented. Results show that the proposed MBE and the corresponding straight line reserve evaluation technique are rational and competent in estimating the free gas and adsorbed gas volumes accurately with error less than 6% compared to the numerical simulation model presented in this study using an in-house simulator based on finite element technique and FORTRAN language. Hence, the presented technique in this study can be used as a quick and easy to use tool to accurately estimate the free and adsorbed gas reserves and to improve the development of the production strategies of shale gas reservoirs.

Characteristics of In Situ Stress and Reservoir Pressure in Deep Coal Seams and Their Influences on Reservoir Depletion: A Field Case Study

The production of coalbed methane resources is greatly dependent on the reservoir depletion process. To improve the depressurization efficiency of deep coalbed methane (DCBM) reservoirs, the fluid production characteristics and implications of in situ stress and reservoir pressure for reservoir depletion in the eastern margin of the Ordos Basin are analyzed. The results indicate that the duration of the single-phase water production stage is overall long, with the gas declining stage occurring too early. The daily gas production volume of DCBM wells is only a few hundred m3. For DCBM reservoirs, it is considered that in situ stress, initial reservoir pressure, and critical desorption pressure significantly affect the fluid production and depressurization process. A high in situ stress in deep coal seams is likely to damage the flow conductivity of fracture systems due to the increase in effective stress during reservoir depletion. Based on the in situ stress characteristics of deep coal seams and their implications for reservoir depletion, we propose that the depressurization of DCBM reservoirs during gas production can be promoted via a new method of stress release. Slots or cavities created in coal seams by high-pressure hydraulic jet can provide space for stress release. This novel depressurization method could help improve the gas production efficiency of DCBM reservoirs.

Effects of Liquid CO2 Phase Transition Fracturing on Methane Adsorption of Coal

Liquid CO2 phase transition fracturing (LCPTF) is a kind of novel waterless fracturing technology for enhancing the coalbed methane (CBM) recovery. Relevant current studies are focused on exploring the transformed effect of LCPTF on the nanopore structure in coal. However, its influence on gas adsorption capacity has been rarely reported. This study addresses coal induced with LCPTF. The structure alterations of mesopores (2–50 nm) and macropores (>50 nm) and their effects on the gas adsorption capacity are evaluated with comprehensive measurements of a mercury intrusion porosimetry, low-temperature N2 adsorption, and isothermal adsorption. The results indicate that LCPTF has an enlarged effect on macropores, resulting in an increase in pore size and volume and a reduction of the pore specific surface area. The pore-enlarged-transformed effects of LCPTF cause an increase in pore size and a reduction of the pore volume and pore specific surface area of mesopores. The variations of the pore structure after LCPTF cause a reduction of the adsorption constant a and the increase in the adsorption constant b, indicating LCPTF’s reductive effect on adsorption capacity as well as its enhanced effect on desorption capacity. A novel effect evaluation method of LCPTF for improving CBM recoverability is proposed based on the variations of gas saturation and critical desorption pressure. This study examines, from the perspective of adsorption and desorption, the mechanism of LCPTF for enhancing CBM recovery, which provides theoretical guidance for LCPTF’s technical improvement and optimization of field application so as to secure a more reliable and efficient CBM recovery.

NMR investigation on gas desorption characteristics in CBM recovery during dewatering in deep and shallow coals

Abstract Coalbed methane (CBM) development requires dewatering until the reservoir pressure is less than the critical desorption pressure. Significant quantities of CBM in China are buried >1000 m deep. Therefore, the desorption characteristics of deep CBM reservoirs must be investigated for the further development of deep CBM. In this study, the variation laws of adsorbed and free CH4 during adsorption in dry samples and during desorption via dewatering are investigated using nuclear magnetic resonance. During CH4 adsorption in dry samples by increasing CH4 pressure and during CH4 desorption in water-injected samples by dewatering, a Langmuir relationship exists between the volume of adsorbed CH4 and the pressure in deep and shallow coals, and the volume of free CH4 and the pressure are linearly related. When the pressure is the same, the volume of adsorbed CH4 in the dry coal samples during adsorption is larger than that in the water-injected samples during desorption by dewatering. When the pressure is the same, for the difference in the adsorbed CH4 volume between adsorption and desorption isotherms, shallow coal is less significant than deep coal. The slopes of free CH4 in deep coal are lower than those in shallow coal during adsorption and desorption.

The generalized method for estimating reserves of shale gas and coalbed methane reservoirs based on material balance equation

As the main unconventional natural gas reservoirs, shale gas reservoirs and coalbed methane (CBM) reservoirs belong to adsorptive gas reservoirs, i.e., gas reservoirs containing adsorbed gas. Shale gas and CBM reservoirs usually have the characteristics of rich adsorbed gas and obvious dynamic changes of porosity and permeability. A generalized material balance equation and the corresponding reserve evaluation method considering all the mechanisms for both shale gas reservoirs and CBM reservoirs are necessary. In this work, a generalized material balance equation (GMBE) considering the effects of critical desorption pressure, stress sensitivity, matrix shrinkage, water production, water influx, and solubility of natural gas in water is established. Then, by converting the GMBE to a linear relationship between two parameter groups related with known formation/fluid properties and dynamic performance data, the straight-line reserve evaluation method is proposed. By using the slope and the y -intercept of this straight line, the original adsorbed gas in place (OAGIP), original free gas in place (OFGIP), original dissolved gas in place (ODGIP), and the original gas in place (OGIP) can be quickly calculated. Third, two validation cases for shale gas reservoir and CBM reservoir are conducted using commercial reservoir simulator and the coalbed methane dynamic performance analysis software, respectively. Finally, two field studies in the Fuling shale gas field and the Baode CBM field are presented. Results show that the GMBE and the corresponding straight-line reserve evaluation method are rational, accurate, and effective for both shale gas reservoirs and CBM reservoirs. More detailed information about reserves of shale gas and CBM reservoirs can be clarified, and only the straight-line fitting approach is used to determine all kinds of reserves without iteration, proving that the proposed method has great advantages compared with other current methods.

Occurrence and Migration Mechanisms of Methane in Marine Shale Reservoirs

The occurrence mechanism of methane is very important as evaluating the gas-bearing properties of marine shale reservoirs, and the evaluation of the development effect of shale gas wells need to focus on the migration mechanism of methane. In this study, LTNA technology and NMR technology were used to analyze the pores and methane of shale. The results show that inorganic pores have better connectivity, larger pore size, and micro–nano cracks between pores compared to organic pores. Most of the pores in shale are micropores and mesopores, which provide most of the specific surface area, but the contribution of macropores to pore volume cannot be ignored. Adsorbed gas volume depends on the pore surface area and gas pressure, while free gas volume depends on pore volume and gas pressure. The pore structure of micropores and mesopores is complex, and the specific surface area is large. The dispersion force between pore surface molecules and methane molecules is firm, which makes the pore wall an ideal enrichment space for adsorbed gas. Macropores have larger pore volumes and can store more free gas. In the process of gas well development, free gas is first discharged from pores under the action of the pressure gradient. As the pore pressure is lower than the critical desorption pressure, adsorbed gas begins to desorb in large quantities. It should be noted that the desorption process of adsorbed gas is slow and persistent, which makes it impossible for gas wells to achieve higher recovery in a shorter production cycle. Therefore, improving the recovery rate of adsorbed gas is the key to future research on shale gas development effects. This study is helpful in clarifying the occurrence and migration mechanism of methane in marine shale reservoirs and guiding the development of gas wells.

The Influence of Fracturing Fluid Volume on the Productivity of Coalbed Methane Wells in the Southern Qinshui Basin

Hydraulic fracturing is the main technical means for the reservoir stimulation of coalbed methane (CBM) vertical wells. The design of fracturing fluid volume (FFV) is mainly through numerical simulation, and the numerical simulation method does not fully consider the water block damage caused by the leakage of fracturing fluid into the reservoir. In this work, the variance analysis method was used to analyze the production data of 1238 CBM vertical wells in the Fanzhuang block and Zhengzhuang block of the Qinshui Basin, to clarify the relationship between the FFV and the peak gas production (PGP) under the different ratios of critical desorption pressure to reservoir pressure (Rc/r), and to reveal the controlling mechanism of fracturing fluid on CBM migration. The results show that both the FFV and Rc/r have a significant impact on gas production. When Rc/r < 0.5, the PGP decreases with the increase of the FFV, and the FFV that is beneficial to gas production is 200–500 m3. When Rc/r > 0.5, the PGP increases first and then decreases with the increase of FFV. Specifically, the FFV that is favorable for gas production is 500–700 m3. Excessive FFV does not significantly increase the length of fractures due to leaks in the coal reservoir. Instead, it is more likely to invade and stay in smaller pores, causing water block damage and reducing gas production. Reservoirs with high Rc/r have larger displacement pressure, which can effectively overcome the resistance of liquid migration in pores, thereby reducing the damage of the water block. Therefore, different reservoir conditions need to match the appropriate fracturing scale. This study can provide guidance for the optimal design of hydraulic fracturing parameters for CBM wells.

Impact factors and contributions of commingled production in multiple coal seams

AbstractThe multilayer development of coalbed methane (CBM) is affected by many factors, and the gas production contribution of each seam is unclear. In this study, 12 geological and 10 engineering parameters were adopted to reveal the key factors affecting the combined‐layer drainage productivity of CBM wells before using numerical simulation to clarify the contribution of each coal seam. The results show that the coal reservoir in the Laochang mining area exhibited the advantages of high gas content, intact coal body structure, and large thickness of the combined coal seams, and it was deficient with low saturation and ratio of critical desorption pressure to reservoir pressure. The medium permeability after fracturing and the influence of a small range of fracturing leads to the steep and deep pressure drop funnel of the coal reservoir, and most of the reservoir pressure drop is ineffective; this may be the reason for the unstable production and rapid attenuation of most CBM wells in the study area. The gas production of the Nos. 13 and 18 coal seams is stable and makes a significant contribution, and they can be used as the key objects of follow‐up CBM exploration and development in this area. Geological factors, such as coal body structure, ratio of critical desorption pressure to reservoir pressure, thickness of combined coal seams, and gas saturation, as well as engineering factors, such as permeability and half length of fractures after fracturing, are the main factors affecting the productivity of the CBM wells in the Laochang mining area.

Impact of Coal Orthotropic and Hydraulic Fracture on Pressure Distribution in Coalbed Methane Reservoirs

Coalbed methane (CBM) shows tremendous in situ reserves, attracting a great deal of research interests around the world. The efficient development of CBM is closely related to the dynamic pressure distribution characteristics in the coal seam. As the dominant component of the geological reserve for CBM, the adsorption-state gas will not be exploited until the local coal pressure becomes less than the critical desorption pressure. Therefore, although the CBM reserve is fairly large, the production performance is generally limited, with a poor understanding of the dynamic pressure field during the CBM production. In this work, in order to address this issue properly, the coal’s inherent properties, the coal’s orthotropic features, as well as artificial hydraulic fracturing are considered, all of which affect pressure propagation in the coal seam. Notably, to the current knowledge, the impact of coal’s orthotropic features has received little attention, while the coal’s orthotropic features are formed during a fairly long geological evolution, changing the dynamic pressure field a lot. Numerical simulation is performed to shed light on the pressure propagation behavior. The results show that (a) coal’s orthotropic features mitigate the depressurization process of CBM development; (b) the increasing length of a hydraulic fracture is helpful for efficient decline in the average formation pressure; and (c) there exists an optimal layout mode for multi-well locations to minimize the average pressure. This article provides an in-depth analysis upon pressure distribution in CBM reservoirs under impacts of coal orthotropic feature and hydraulic fractures.

Optimization experimental design of stable production life and estimated ultimate recovery in gaseous compound of hydrogen and carbon from shale reservoir

In this study, a mixed numerical model is established to simulate the production performance of gaseous compound of hydrogen and carbon in shale reservoir. Estimated ultimate recovery (EUR) and stable production life (SPL) of gaseous compound of hydrogen and carbon are affected by reservoir parameters and production control parameters, such as Langmuir pressure, Langmuir volume, critical desorption pressure, fracture half length, permeability in stimulated reservoir volume (SRV) area, bottom hole flow pressure and production of gaseous compound of hydrogen and carbon. Therefore, in the later research, in order to reduce the number of numerical experiments, the orthogonal experimental method is used to optimize the influence of hydrocarbon ERU and SPL, and analyze the main control factors affecting these two indices at the same time. The purpose of this paper is to optimize the production of hydrocarbons by orthogonal experimental method and find the main controlling factors affecting the production of compound of hydrogen and carbon. Two groups of orthogonal experiments were designed to find the best scheme in the process of compound of hydrogen and carbon development. The calculative results show that the output of hydrogen and carbon compounds has a highly significant impact on SPL, Langmuir volume and capability in SRV have a significant impact, and Langmuir pressure Critical destruction pressure and hydraulic fracture half-length had no significant effects.

A Method to Evaluated Gas Content with Coalbed Methane Reservoir Based on Adsorption Theory and Production Analysis

In the process of coalbed methane development, the gas content not only determines the reserves of methane in coal reservoir but also is the most important geological parameter affecting the production of coalbed methane. The gas content directly determines whether coalbed methane can be developed efficiently. However, in the current development evaluation process, it is very difficult to accurately predict the gas content in coal seams. An efficient and accurate method to predict gas content has not been found yet. This is mainly restricted by the development mode and technology of coalbed methane. In the current low-cost development model, gas content test data are relatively scarce. Under such circumstances, it is difficult to accurately evaluate the distribution of CBM gas content in the whole area. At the same time, the gas content of coalbed is the key parameter for efficient development of coalbed methane. Under normal circumstances, gas content heterogeneity will result in a large gap between development effects in different regions. At present, there is no evaluation method for gas content parameters of coal reservoir. Under this background, the key parameters of coalbed methane development in southern Qinshui Basin were evaluated. On the basis of systematically summarizing and understanding the development law of coalbed methane in different types of coal reservoirs, a gas content evaluation method based on adsorption theory and production dynamic analysis is proposed. Combined with the coalbed methane production model and isothermal adsorption model, the critical desorption pressure can be calculated accurately by using the bottom hole pressure when casing pressure occurs in production wells. The critical desorption pressure correction model of coalbed methane was innovatively established. Langmuir equation was used to accurately characterize the adsorption characteristics of coalbed methane. Forming a new method for gas content prediction in the case of fewer coring wells. The gas content evaluation technology coupled with isothermal adsorption theory and production dynamic analysis saves the development cost of coalbed methane and improves the prediction accuracy of coal seam gas content in noncoring wells. At the same time, there is a good relationship between the predicted results and the measured gas content at well points. The coincidence rate reached 97.37%. This technology can effectively improve the prediction accuracy of coal seam gas content. This technique is suitable for the productivity evaluation of coalbed methane reservoir. It can also provide scientific basis for the development and reserve evaluation of coalbed methane reservoirs at home and abroad.