Methane Reservoirs Research Articles

Influence of coalification on pore structure evolution in middle-ranked coals

The influence of coalification on coal structure evolution in middle ranked coals is significant for physical assessment of coalbed methane (CBM) reservoirs, which provides insights on the intrinsic connection between coalification jump and pore heterogeneity. A total of 26 middle-ranked coals were samples covering Liupanshui Coalfield in Guizhou Province, Anhe Coalfield in Henan Province, Huaibei Coalfield in Anhui Province, Sanjiang Basin in Heilongjiang Province, Ordos Basin in Shaanxi Province and Qinshui Basin in Shanxi Province. Based on a series of experiments including vitrinite reflectance, coal maceral identification, nitrogen adsorption and the pore fractal method, the inner link between physical property parameters of coal reservoirs and coal rank was revealed. The results show that the coal maceral in middle rank coals is dominated by vitrinite and inertinite and two types of adsorption pores are divided according to the nitrogen adsorption/desorption curves along with pore size distribution. The specific surface area is positively correlated with total pore volume, micropore volume and negatively correlated with averaged pore size and transitional pore volume. The coal samples with low average pore sizes have relatively high total pore volume, specific surface area and micropore volume per unit nm. With the increase of coal rank, the fluctuating points of micropore and transitional pore volume correspond to 1.16%–1.19%, 1.41%–1.43% and 1.86%–1.91% of Ro, max, respectively. The boundary of Ro, maxcorresponding to the second coalification jump can be more specifically defined as 1.16%–1.19% from the established nominal range of 1.1%–1.3%. The pore fractal dimension DNA1and DNA2increase with increasing specific surface area. Furthermore, the DNA2has a negative correlation with micropore volume and averaged pore size, indicating that the coal with smaller average pore diameter and lower micropore content has a more complex pore structure.

CBM reservoir thickness prediction using the seismic nonlinear stochastic inversion method

Due to the complex reservoir conditions and rapid changes in lithological facies in seismic exploration, predicting coalbed methane (CBM) reservoirs is quite challenging. Conventional inversion methods are not highly effective at predicting reservoir thickness, and cannot keep up with current demands. Our aim is to demonstrate how seismic data can be used to forecast coal thickness, as well as the distribution and orientation of subtle structures that may be linked to enhanced permeability zones. In this study, we used a nonlinear stochastic inversion method based on making full use of seismic data and constraining it with known information, such as drilling and logging analysis. This method has been successfully applied in a mining area in Wuxiang County in the southeastern part of Shanxi Province. Compared with the actual geological data, it is found that the prediction accuracy is consistent with the drilling results, and the distribution of the predicted CBM reservoir thickness is consistent with the geological information. Furthermore, due to the randomness of the subsurface medium, the accuracy of reservoir prediction can be increased by observing the target layer seismic reflection wave amplitude, frequency, and other properties.

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.

Symbiotic Combination and Accumulation of Coal Measure Gas in the Daning–Jixian Block, Eastern Margin of Ordos Basin, China

Coal measure gas resources, including coalbed methane (CBM), shale gas, and tight gas are abundant in the Daning–Jixian Block. The complexity of the source–reservoir–cap relationship in the coal measure strata leads to unclear symbiotic characteristics and gas accumulation, which in turn, restrict the exploration and exploitation of the coal measure gas. In this study, the enrichment and accumulation of coal measure gas are discussed and summarized in detail. The results show that there are eight lithofacies and six reservoir combinations in the superposed strata of the coal measures in the study area. Controlled by the tidal flat-lagoon facies, the “sand-mud-coal” type mainly distributes in P1s2 and P1t, showing a good gas indication. Based on the variation of the total hydrocarbon content, key strata, and pressure coefficient of the coal measure gas reservoir, four superposed gas-bearing systems are identified in the vertical direction. According to the relationship between the gas-bearing system and gas reservoir, the enrichment of coal measure gas in the study area can be divided into three modes, including an intra-source enrichment mode, a near-source migration enrichment mode, and a far-source migration enrichment mode. The symbiotic accumulation of a coal measure gas model is further proposed, that is, an “Adjacent to co-source reservoir” type superimposed coalbed methane and shale gas reservoir model, a “Three gas symbiosis” superimposed reservoir model in the local gas-bearing system, and a “Co-source far reservoir” tight sandstone gas reservoir model. Clarifying the symbiotic relationship of coal measure gas reservoirs is beneficial to the exploration and further production of unconventional gas in the study area.

CBM Gas Content Prediction Model Based on the Ensemble Tree Algorithm with Bayesian Hyper-Parameter Optimization Method: A Case Study of Zhengzhuang Block, Southern Qinshui Basin, North China

Gas content is an important parameter for evaluating coalbed methane reservoirs, so it is an important prerequisite for coalbed methane resource evaluation and favorable area optimization to predict the gas content accurately. To improve the accuracy of CBM gas content prediction, the Bayesian hyper-parameter optimization method (BO) is introduced into the random forest algorithm (RF) and gradient boosting decision tree algorithm (GBDT) to establish CBM gas content prediction models using well-logging data in the Zhengzhuang block, south of Qinshui Basin, China. As a result, the GBDT model based on the BO method (BO-GBDT model) and the RF model based on the BO method (BO-RF model) were proposed. The results show that the mean-square-error (MSE) of the BO-RF model and the BO-GBDT model can be reduced by 8.83% and 37.94% on average less than that of the RF and GBDT modes, indicating that the accuracy of the models optimized by the BO method is improved. The prediction effect of the BO-GBDT model is better than that of the BO-RF model, especially in low gas content wells, and the R-squared (RSQ) of the BO-GBDT model and the BO-RF model is 0.82 and 0.66. The accuracy order of different models was BO-GBDT > GBDT > BO-RF > RF. Compared with other models, the gas content curve predicted by the BO-GBDT model has the best fitness with the measured gas content. The rule of gas distribution predicted by all four models is consistent with the measured gas content distribution.

Experimental investigation on fracture characteristics by liquid nitrogen compound fracturing in coal

The stimulation efficiency of hydraulic fracturing in coalbed methane (CBM) reservoir are low due to high filtration. In this study, a new compound fracturing method is proposed to improve the CBM reservoir fracturing efficiency combining the advantages of liquid nitrogen (LN2) fracturing and hydraulic fracturing. The compound fracturing starts from LN2 fracturing forming complex fractures and non-filtration zones, follows by injecting nitrogen gas (N2) to displace LN2 near the borehole into the fracture tips and prevent subsequent sand-carrying fluids from freezing in the borehole, and finishes by using sand-fluid mixtures carrying proppant into the frozen coal seam. To test the feasibility, fracturing experiments were conducted to investigate the performances of LN2 compound fracturing. The lab results show that LN2 compound fracturing can create more complex and highly conductive fracture networks than water fracturing and pure LN2 fracturing. Compared with LN2 fracturing, the average fracture aperture, fractures number, and total fracture volume induced by compound fracturing increased by 28%, 10%, and 34%, respectively. Compared with water fracturing, the fractures number, and total fracture volume induced by compound fracturing increased by 55% and 42%, respectively. The reason for the improved conductivity as follows: in the pad stage of the compound fracturing, coal is fractured by LN2 with low viscosity and low temperature, forming a large number of small-scale fractures. In the slurry stage, coal is fractured by water, which further activates the small-scale fractures, increasing the number and aperture of fractures. The key findings obtained in this work is the proposed LN2 compound fracturing method that helps sustainable development of CBM resources in an efficient and environmentally friendly way.

Abiotic Methane Reservoirs in the Western Tianshan HP–UHP Metamorphic Belt, China

AbstractNatural gas, consisting primarily of methane (CH4), has become a major source of clean energy in modern society in many parts of the globe. Recent experimental observations and discoveries of deep‐sourced abiotic CH4 in cold subduction zones indicate the important ability of cold subducted slabs to generate natural gas reservoirs. However, most CH4 flux and reservoirs remain unknown and their potential is overlooked in global carbon flux estimations. Massive abiotic CH4‐rich fluid inclusions (FIs) in garnet and omphacite from ultrahigh‐pressure (UHP) eclogites have been found in the Western Tianshan (WT) UHP metamorphic belt, which provides one ideal case for quantification of abiotic CH4 stored in the cold subducted crust. By two methods, we assess the abiotic CH4 content stored in the Chinese WT HP–UHP metamorphic belt. Our calculations show that at least 113 Mt CH4 is stored in the WT eclogites. We also discuss the implications for CH4 reservoirs in subduction zones worldwide and speculate that the cold subduction zones may represent one of the largest, yet overlooked, sources of abiotic CH4 on Earth, which should not be ignored in the global natural resource and carbon flux estimations.

Enhanced Carbon Storage Process from Flue Gas Streams Using Rice Husk Silica Nanoparticles: An Approach in Shallow Coal Bed Methane Reservoirs

Carbon capture and storage (CCS) is considered a key process to reach net-zero emission by the 2050 aim of limiting global warming. Coal bed methane (CBM) is considered potential geological reservoirs for underground CCS due to the CO2–CH4 exchange feasibility by adsorptive phenomena. Global implementation has been focused only on deep reservoirs to provide methane recovery. Thus, this work proposes a modified CCS process based on silica nanoparticle inclusion for shallow CBM reservoirs (<300 m). The nanomaterials were evaluated at high pressure in two main stages including i) CO2 sorption on a single CO2 stream and ii) CO2 selectivity on a flue gas stream (N2–CO2 mixture). This work includes silica nanomaterial synthesized from rice husk as agro-waste sources with better technical-economic feasibility framed in a circular economy to reduce costs and maximize the use of available resources. Rice husk silica (RSi) nanoparticles were doped with 1.0, 3.0, and 5.0 wt % of urea (Si–U), diethylamine (Si-DE), triethylamine (Si-TE), and ethylenediamine (Si-EM) to enhance the CO2 sorption. First, CO2 sorption was evaluated at 30 °C and between 0.084 and 3 MPa using a CO2 stream to determine the best-doped amount of each N-source. Then, the best nanoparticles were used to impregnate CBM at 10 and 20 wt %, and the subsequent CO2 storage on the flue gas stream (70% v/v N2 and 30% v/v CO2) was done. The results showed that CO2 sorption on RSi increases with the N-group coating in the order RSi-DE < RSi-TE < RSi-U < RSi-EM. Also, the best-doped amount for each N-source was 3 wt %. For CBM impregnation, the nanofluid containing 20 wt % of RSi-EM3 presented the best yield increasing the CO2 sorption from 0.05 to 0.75 mmol g–1, meaning an increase of more than 1000% in the sorption capacity.

Characteristics of in situ stress field of coalbed methane reservoir and its influence on permeability in western Guizhou coalfield, China

In-situ stress is an important indicator for the preferential selection of coalbed methane (CBM) exploration dessert zones, and is a key factor affecting the production capacity of coalbed methane wells. Coal reservoir permeability is one of the key parameters to evaluate the recoverability and modifiability of coalbed methane and reflects the seepage capacity of coal reservoirs. In this study, in situ stress data were collected from multiple injection/fall-off tests of multiple parameter wells in western Guizhou province, China The relationships among parameters such as pore pressure (Pp), closure pressure (Pc), breakdown pressure (Pb), in situ stress, coal permeability, and depth were explore. Using Anderson’s classification method, the distribution of three different in situ stress states was counted. A new simplified model diagram of triaxial principal stress and depth in the study area is proposed by linearly fitting the triaxial principal stress and burial depth. The envelope equation and median equation of the lateral pressure coefficient k-value stress ratio with depth of burial obtained by Brown and Hoek method were calculated using hyperbolic regression algorithm. The k-values were found to be discrete at shallower depths and converge at deeper depths, gradually converging to .65. The control of in situ stress on the permeability of coal reservoirs was explored, and a strong positive correlation was found between the permeability and the Z-shaped variation of the lateral pressure coefficient k-values at shallow depths of 1,000 m. Also, the distribution pattern of vertical permeability basically corresponds to the stress transition zone from the strike-slip fault mode to the normal fault mode. The coal seam permeability has a strong sensitivity to effective in situ stress (EIS). In this study, the least squares method with multiple fitting of power exponents is applied to analyze the control mechanism of EIS on permeability in depth and reveal a new relationship between permeability and EIS that is different from that considered by previous authors. Summarizing the above research results, the vertical CBM in western Guizhou is divided into three development potential zones, and 400–1,000 m burial depth is the most favorable vertical development zone.

A Novel Semianalytical Model for the Relationship between Formation Pressure and Water Saturation in Coalbed Methane Reservoirs

The accuracy of the relationship between formation pressure and water saturation has a direct impact on predicting the production performance of coal reservoirs. As a result, researchers are becoming more interested in this connection. The most commonly used method to evaluate this connection is the semianalytic method, but it disregards the impact of coal matrix shrinkage on pore compressibility, resulting in inaccurate water saturation estimations for coal reservoirs. A material balance equation that considers the effect of coal matrix shrinkage on cleat porosity and pore compressibility, as well as the gas–water relative permeability curve, is used for the first time in this study to establish a model between pressure and water saturation. Furthermore, this study extends the proposed pressure–saturation model to predict cumulative gas production and gas recovery, resolving the difficult problem of calculating recovery for coalbed methane reservoirs. To verify its accuracy, this study compares the proposed method with numerical simulations and previous methods; the results of the comparison show that the water saturation under formation pressure calculated by the method proposed in this study is closer to the results of the numerical simulation. Sun’s model ignores the effect of matrix shrinkage on pore compressibility, resulting in larger calculation results. The findings of this study indicate that the effect of coal matrix shrinkage on pore compressibility cannot be ignored, and that the proposed method can replace numerical simulation as a simple and accurate method for water saturation evaluation, which can be applied to predict cumulative gas and recovery estimation for closed coalbed methane reservoirs. The proposed method increases the accuracy of the semianalytical method and broadens its application. It is critical for the prediction of coal reservoir production performance and forecasting of production dynamics.

Effect of different salt ions with different concentrations on the stability of carbon dioxide-in-water foam fracturing fluids

Different salt ions with different concentrations can affect the fracturing effect by influencing the stability of the carbon dioxide-in-water (C/W) foam during C/W foam fracturing to increase the penetration of coalbed methane (CBM) reservoirs. Therefore, in this paper, a combination of experiments and molecular dynamics simulations was used to investigate the mechanism of the effect of the concentration of salt ions on the stability of C/W foam fracturing fluids. The initial foam volume and drainage half-life of C/W foam were measured using a C/W foam stability evaluation device to evaluate the foamability and foam stability of C/W foam. The surface tension and viscoelastic modulus of the C/W foam were measured by an interface rheometer (Tracker). Moreover, molecular dynamics simulations were used to obtain the radial distribution functions between different elements and the mean square displacement of water molecules. The results showed that salt ions could reduce the surface tension and change the viscoelastic modulus of the C/W foam. Magnesium and calcium ions reacted with sodium dodecylbenzene sulfonate (SDBS); thus, magnesium and calcium dodecylbenzene sulfonate, which are slightly soluble in water, were formed. Sodium ions improved the stability of the C/W foam fracturing fluid. The liquid-carrying capacity of SDBS was improved, the drainage rate of water on the C/W foam film was decreased, and the stability of the C/W foam fracturing fluid was improved when the concentration of magnesium ions was lower than 100 mg/L or the concentration of calcium ions was lower than 50 mg/L. However, with increasing ion concentration, the stability of the C/W foam continued to decrease, and the stability was the lowest when the concentration of magnesium or calcium ions reached 400 mg/L. The results provide guidance on the application of C/W foam fracturing to increase penetration in coal seams with salt ions.

Quantitative interpretation of coal industrial components using a gray system and geophysical logging data: A case study from the Qinshui Basin, China

The content of industrial components of coalbeds, one of the main parameters of coalbed methane (CBM) reservoirs, is crucial in the entire coal mine resource exploration and exploitation process. Currently, using geophysical logging data to determine the content of industrial components is the most widely implemented method. In this study, the PZ block in the Qinshui Basin was employed as a target block to evaluate ash (Aad), fixed carbon (FCad), volatile matter (Vdaf), and moisture (Mad) under the air-dry (AD) base condition based on the autocorrelation between the geophysical logging curves and industrial component contents combined with the OBGM (1, N) model. The results indicate that 1) the geophysical logging curves combined with the OBGM (1, N) model can accurately predict the Aad and FCad contents and an increase in geophysical logging curve types can effectively improve the model performance, compared to using a single geophysical logging curve for prediction. 2) When predicting the Vdaf content, using the geophysical logging curves combined with Aad and FCad contents had the highest prediction accuracy. Further, prediction bias does not exist, compared to using only the geophysical logging curve or the autocorrelation between the industrial component contents. The entire evaluation process begins with an assessment of the Aad and FCad contents. Then, the Vdaf content was assessed using the content of these two industrial components combined with geophysical logging data. Finally, the Mad content was calculated using the volumetric model. Accurate application results were obtained for the verification of new wells, demonstrating the efficacy of the method and procedure described in this study. 3) The OBGM (1, N) model has the highest prediction accuracy compared with the multiple regression and GM (0, N) models, which have the same computational cost. The geophysical logging interpretation model of the proposed coalbed industrial component contents is simple to calculate and suitable for small samples, providing a new method for the evaluation process of industrial component contents.

Modelling multicomponent gas diffusion and predicting the concentration-dependent effective diffusion coefficient of coal with application to carbon geo-sequestration

Diffusion of multicomponent gases, which is a complex transport mechanism in coalbed methane (CBM) reservoirs, needs to be accounted for in models of enhanced coalbed methane recovery (ECBM) and geological CO2 storage. We develop a numerical model that accounts for diffusion of free gas, diffusion of adsorbed gas, and competitive sorption. Our model also reflects adsorption-induced swelling and the impact of moisture. The simulator for modelling multicomponent gas diffusion is first validated by comparing its computed concentration field against those yielded by the general-purpose finite element solver COMSOL and the available analytical solutions. The model is then validated against the experimental measurements from the published literature. Subsequently, our simulator is used to model the CO2 Enhanced Coalbed Methane (CO2-ECBM) scenarios. The simulation results quantify the influence of different types of diffusion on the effective diffusion coefficient of coal. We analyse diffusion of methane and carbon dioxide that must be considered when modelling CBM reservoirs and analyse performance-based sensitivity of surface diffusion, moisture, matrix deformation, and pressure. Finally, the model is applied to a CO2 storage case. We calculate the CO2 storage volume and the equilibrium time under various pore pressures. The simulation shows that as pore pressure increases, the amount of CO2 stored increases and the equilibrium time decreases. Overall, this model can be applied to estimate the effective diffusion coefficient, to analyse the impact of rock and gas parameters on multicomponent gas diffusion, to provide insight into the physics of multiple gas transport in coal, and to estimate the feasibility of CO2 storage under various pore pressures.

Characteristics of water occurrence in coalbed methane reservoir

Characteristics of water occurrence in coalbed methane reservoir

Summary of research methods for porosity and permeability of coalbed methane reservoir

In order to serve the research on the physical properties of coalbed methane reservoirs and improve the prediction effect of porosity and permeability of coal reservoirs, this paper, based on a large number of literature research, summarizes the concepts, influencing factors and prediction methods of coal seam porosity and permeability. The research shows that the main factors affecting the porosity of coalbed methane reservoir are coal petrographic composition, metamorphic degree, coal body structure and buried depth, compaction, tectonism, etc; The main influencing factors of permeability include component content, coal rank, coal body structure and in-situ stress, buried depth of coal seam, natural fracture of coal seam, matrix shrinkage, Klinkenberg effect, etc. The porosity prediction of coalbed methane reservoir generally adopts true and apparent relative density method, in addition, there are multiple regression method based on logging information, nuclear magnetic resonance logging method, etc; The measurement methods of CBM reservoir permeability mainly include the calculation method based on conventional logging, triaxial stress experimental research method, joint prediction method of nuclear magnetic resonance and electrical imaging logging, dynamic data analysis method and numerical simulation method. The development of coal seam porosity and permeability prediction technology needs innovative breakthroughs in hardware and software.

Mineral matter in the Pennsylvanian coal from the Yangquan Mining District, northeastern Qinshui Basin, China: Enrichment of critical elements and a Se-Mo-Pb-Hg assemblage

The Qinshui Basin, the largest reservoir of commercial coalbed methane in China, has attracted much attention and several studies have focused on the mineralogy and element geochemistry of coals in this basin. However, the sources of minerals and elements, particularly those of high-ash coals in the northeastern basin were yet unidentified. This study investigated mineralogy and geochemistry of the Pennsylvanian No. 8 Coal (including the roof strata and partings) from the Xinjing mine, northeastern Qinshui Basin, Shanxi Province, China. The Xinjing Coal is a low-ash, medium‑sulfur semi-anthracite. The minerals in the studied coals are mainly represented by kaolinite, illite, calcite, ankerite, siderite, dolomite, and pyrite. The Xinjing Coal is characterized by enriched Li, Zr, and Hg, and slightly enriched F, Ga, Ge, Se, Sr, Mo, Hf, and Pb. The diagrams of Al2O3-TiO2, Zr/TiO2-Nb/Y, as well as the REY (rare earth elements and Y) distribution patterns show that the sediment source region of the studied deposit is represented by the old granitoides, sedimentary rocks and bauxites of the Yinshan Upland located to the north of Qinshui Basin.In this study, three geological factors (sediment source regions, injections of hydrothermal fluids, and seawater) are identified as the dominant influences on geochemical and mineralogical compositions. Elevated concentrations of critical elements such as Li and Ga are dominantly derived from the sediment source region. Authigenic minerals including sulfides, quartz, carbonates, phosphates, and clausthalite, as well as the significant variations of Se-Mo-Pb-Hg assemblage across the coal seam, indicate that the Xinjing coal probably has been subjected to a multi-stage hydrothermal activities. Relatively high total sulfur contents (2.3% on average), framboidal pyrite, Sr/Ba (3.3) and Th/U values (2.2) suggest that seawater is another important geological factor affecting the Xinjing coal.

Coalbed Methane Reservoir Parameter Prediction and Sweet-Spot Comprehensive Evaluation Based on 3D Seismic Exploration: A Case Study in Western Guizhou Province, China

As a kind of clean energy, the exploration and development of coalbed methane (CBM) are of great importance and significance. In this paper, the CBM reservoir parameters of a working area in Western Guizhou Province, China, were predicted by using 3D seismic exploration technology, and the sweet-spot area was evaluated based on the prediction results. In terms of data interpretation, while the traditional technology is extended to the study of CBM, new technologies and methods suitable for CBM were also actively explored, especially in the quantitative prediction methods of parameters such as coal seam thickness, CBM content, coal body structure, in situ stress, etc., and a three-highs quantitative prediction technology of CBM sweet spots characterized by high precision, high resolution, and high coincidence was explored, which is based on logging evaluation and petrophysics. In addition, in the comprehensive evaluation of multiparameter sweet spots, the multiparameter weighted step-by-step evaluation method based on inversion was innovatively proposed, which made the prediction of CBM sweet spots more focused, effective, and practical, and the distribution law of sweet spots was more consistent with the geological law, providing enough basis for subsequent well location deployment. Based on this method, the C409 coal seam was selected as the sweet spot.

Numerical investigation of seepage characteristics of propped fracture in coalbed methane reservoirs

The investigation of the pore structure characteristics and the effect on fluid seepage in propped fractures are important considerations for improving coalbed methane (CBM) production and optimizing CBM extraction systems. In this paper, a numerical model was established to study the pore structure characteristics and distribution of fluid pressure, velocity and pathline fields of propped fractures. The results showed that, with the increase of the closure stress, the porosity decreased linearly while the effective pore connectivity ratio first increased, then decreased. The best flow conductivity of the fracture was achieved at the closure stress of 12.67 MPa. In addition, there were disparities in the pore distribution of the different layers due to the uneven transfer of the closure stress from top to bottom. Compared to the top and bottom layers, the effective pore connectivity ratio and fluid pressure were significantly smaller in the middle layer, while the flow velocity and pathline length were larger. The top and bottom layers were the main fluid seepage channels. The results of this study can provide a theoretical basis for CBM production prediction and real-time quantitative optimization of CBM extraction systems.

Variations of Pore Structure and Methane Adsorption of Continental Deformed Shales from Small-Scale Anticline and Syncline: Two Cases Study of the Triassic Yanchang Formation, Ordos Basin and Jurassic Yaojie Formation, Minhe Basin.

In order to investigate the effect of tectonic compression on pore structures and methane adsorption capacity, the continental deformed shales are collected from the Rujigou section in the Ordos Basin and the Hongshawan section in the Minhe Basin as research objects. The porosity, N2 and CO2 adsorption, field emission scanning electron microscopy (FE-SEM), and methane isothermal adsorption experiments are used to investigate the pore structure and methane adsorption of continuous deformation shales. Combined with formation curvature, the quantitative correlations between tectonic compression deformation and reservoir structure parameters and methane adsorption are analyzed. The interlayer pore, intergranular pore, dissolution pore, and microfracture are developed, and the amounts of microfractures are obviously higher in anticlinal cores than that of the anticlinal wings. The porosities for the Rujigou and Hongshawan sections are 2.1-4.73% (avg 3.21%) and 1.49-9.05% (avg 4.80%), respectively. The corresponding mesopore volume, specific surface area, and average diameter for the Rujigou section are 0.022-0.038 cm3/g, 12.35-14.30 m2/g, and 8.76-11.21 nm and for the Hongshawan section are 0.0033-0.0052 cm3/g, 0.376-0.875 m2/g and 21.61-36.37 nm, respectively. The corresponding micropore specific surface area and pore volume for the Rujigou section are 11.301-16.068 m2/g and 0.0033-0.0051 cm3/g and for the Hongshawan section are 10.951-15.912 m2/g and 0.0043-0.0058 cm3/g, respectively. The methane adsorption capacities for the Rujigou and Hongshawan sections are 2.76-3.82 mg/g and 1.62-2.135 mg/g, respectively. The porosity, mesopore and micropore structure parameters, and methane adsorption capacity in synclinal core are lower than those in synclinal wings. However, the above tendency is reversed for the anticline, whose adsorption capacity in the anticlinal core is higher than that in anticlinal wings. There exist high correlations between formation curvature and pore structure, physical property, and methane adsorption, indicating that formation curvature has a significant effect on the shale reservoir. By combining theoretical maximum adsorbed gas and free gas results, it implies that the anticlinal core undergoing moderate structural compression deformation can provide more methane adsorption sites and reservoir space, which is the shale gas favorable accumulation area. This study could provide beneficial references for continental shale gas exploration and evaluation in complex structure areas.

Conductivity Evaluation of Horizontal Wells in Coalbed Methane Reservoirs: Applicability of Micromaterial Tracer Testing Technology.

Horizontal well-staged fracturing technology is widely used in the exploitation of coalbed methane reservoirs. Most coalbed methane wells have little or no flowback fluid after fracturing due to strong adsorption in the reservoir. The fracture conductivity of each fracturing interval can only be evaluated in the water drainage and gas production stage. Traditional chemical tracer monitoring technologies are risky to operate and do not provide accurate qualitative measurements. The potential applicability of trace material tracer testing technology in coalbed methane reservoirs has theoretical and practical significance, as does establishing a set of fracturing tracer technologies (e.g., reagent systems, construction schemes, detection interpretation) suitable for coalbed methane horizontal wells. Geological, laboratory, and field test data are used in this study to preliminarily resolve the trace material tracer adsorption problem in the coalbed by improving the chemical agent formula. The proposed method is applied to determine the conductivity of a fractured section in a coalbed methane well.