An Experimental Study on the Effect of a Nanofluid on Oil-Water Relative Permeability

The low porosity and low permeability of tight oil reservoirs call for improvements in the current technologies for oil recovery.Traditional chemical solutions with large molecular size cannot effectively flow through the nanopores of the reservoir.In this study,the feasibility of Nanofluids has been investigated using a high pressure high temperature core-holder and nuclear magnetic resonance(NMR).The results of the experiments indicate that the specified Nanofluids can enhance the tight oil recovery significantly.The water and oil relative permeability curve shifts to the high water saturation side after Nanofluid flooding,thereby demonstrating an increase in the water wettability of the core.In the Nanofluid flooding process the oil recovery was enhanced by 15.1%,compared to waterflooding stage.The T2 spectra using the NMR show that after Nanofluid flooding,a 7.18%increment in oil recovery factor was gained in the small pores,a 4.9%increase in the middle pores,and a 0.29%increase in the large pores.These results confirm that the Nanofluids can improve the flow state in micro-sized pores inside the core and increase the ultimate oil recovery factor.

Study on gas-liquid relative permeability experiments of fractured-porous reservoirs

For carbonate reservoirs,gas-water and oil-gas relative permeability curve are of importance for parameters calculation in oil-field development,dynamic analysis and numerical reservoir simulation.The oil-gas/gas-water relative permeability curves were measured with unstable method under normal temperature and low pressure,using fifteen artificial fractured cores.The shape and change characteristics of gas/water and oil/gas relative permeability curve were mainly analyzed.The results showed that for the relative permeability curve of water driving gas.The saturation of equal permeability point,the saturation range of two-phase flow region and the displacement efficiency has a good power-function relation with core permeability.In addition,the saturation of equal permeability point,the saturation range of two-phase flow region and the displacement efficiency will decrease with the increasing of core permeability.However,for oil-gas relative permeability curves,the saturation of equal permeability point,the saturation range of two-phase flow region and the displacement efficiency will increase with the increasing of core permeability.It should be noted that the gas relative permeability presents a straight line in the normalized relative permeability curve,which indicates that the main flow is dominated by fracture with low displacement efficiency.The research results provide theory basis for fracture-vuggy carbonate reservoir development and new research idea for the further study of this kind of reservoir.

Characterization of the generalized permeability jail in tight reservoirs by analyzing relative-permeability curves and numerical simulation

This study comprehensively characterizes the boundary values of generalized permeability jail in tight reservoirs through relative-permeability curve analysis,numerical simulation,and economic evaluation.A total number of 108 relative-permeability curves of rock samples from tight reservoirs were obtained,and the characteristics of relative-permeability curves were analyzed.The irreducible water saturation(Swi)mainly ranges from 20% to 70%,and the residual gas saturation(Sgr)ranges from 5% to 15% for 55% of the samples.The relative-permeability curves are categorized into six types(Category-Ⅰ to Ⅵ)by analyzing the following characteristics:The relative permeability of gas at Swi,the relative permeability of water at Sgr,and the relative permeability corresponding to the isotonic point.The relative permeability curves were normalized to facilitate numerical simulation and evaluate the impact of different types of curves on production performance.The results of simulation show significant difference in production performance for different types of relative-permeability curves:Category-Ⅰ corresponds to the case with best well performance,whereas Categories-Ⅴ and Ⅵ correspond to the cases with least production volume.The results of economic evaluation show a generalized permeability jail for Categories-Ⅳ,Ⅴ,and Ⅵ,and the permeability jail develops when the relative permeability of gas and water is below 0.06.This study further quantifies the range of micro-pore parameters corresponding to the generalized permeability jail for a tight sandstone reservoir.

Experimental analysis of the pore structure, relative permeability, and water flooding characteristics of the Yan'an Formation sandstone, southwestern Ordos Basin

The oil and gas potential of the Yan'an Formation in the Ordos Basin has yet to be fully tapped. In this study, the pore structure, mobile fluid saturation, and water flooding micro-mechanism of the Yan'an Formation sandstone are systematically studied through the application of a series of rock physics and fluid experiments. The results show that there is a good positive correlation between porosity and permeability, and the reservoirs are divided into types Ⅰ, Ⅱ, and Ⅲ. Mercury injection tests show that the average pore throat radius of the oil-bearing reservoir ranges from 1 to 7 μm. The displacement pressure of the Yan'an Formation is also relatively low, and it decreases from 0.1 MPa to 0.01 MPa as the rock porosity increases from 11% to 18%. NMR tests show that small (diameter <0.5 μm) and medium pores (diameter ranging from 0.5 to 2.5 μm) are predominant in the reservoir. Different types of reservoirs have different characteristics of relative permeability curve. In addition, when the average oil recovery rate is less than 1 ml/min, the oil displacement efficiency increases faster. However, when the average oil recovery rate is between 1–3.5 ml/min, the oil displacement efficiency is maintained at around 27%–30%. Physical properties of the reservoir, pore-throat structure, experimental pressure difference, and pore volume injected — all have significant effects on oil displacement efficiency. For Type Ⅰ and Type Ⅱ reservoirs, the increase of the pore volume injected has a significant effect on oil displacement efficiency. However, for Type Ⅲ reservoirs, the change of pore volume injected has insignificant effect on oil displacement efficiency. This study provides a reference for the formulation of estimated ultimate recovery (EUR) measures for similar sandstone reservoirs.

Test of the Relative Permeability Curve of a Gas and Oil Condensate System and its Effect on the Recovery of Oil and Gas

The relative permeability curve has been measured with simulation oil (refined oil) and gas (nitrogen or air) at room temperature and a lowpressure, both of which are very important parameters for depicting the flow of fluid through porous media in a hydrocarbon reservoir. This basic measurement is often applied in exploitation evaluation, but the underground conditions with high temperature and pressure, and the phase equilibrium of oil and gas, are not taken into consideration when the relative permeability curve is tested. There is an important theoretical and practical sense in testing the diphase relative permeability curve of the equilibrium of oil and gas under the conditions of high temperature and pressure. The test method for the relative permeability curve is proposed in this paper. The relative permeability of the equilibrium of oil and gas and the standard one are tested in two fluids, and the differences between these two methods are stated. The research results can be applied to the simulation and prediction of CVD in long cores and then the phenomenon can better explain that the recovery of condensate gas rich in condensate oil is higher than that of CVD test in PVT. Meanwhile, the research shows that the relative permeability curve of equilibrium oil and gas is sensitive to the rate of exploitation, and the viewpoint proves that an improved gas recovery rate can properly increase the recovery of condensate oil.

Non-Darcy flow in oil accumulation (oil displacing water) and relative permeability and oil saturation characteristics of low-permeability sandstones

Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or caprock, limited buoyancy effect, complex oil-gas-water distribution, without obvious oil-gas-water interfaces, and relatively low oil （gas） saturation. Based on the simulation experiments of oil accumulation in low-permeability sandstone （oil displacing water）, we study the migration and accumulation characteristics of non-Darcy oil flow, and discuss the values and influencing factors of relative permeability which is a key parameter characterizing oil migration and accumulation in low-permeability sandstone. The results indicate that： 1） Oil migration （oil displacing water） in low- permeability sandstone shows non-Darcy percolation characteristics, and there is a threshold pressure gradient during oil migration and accumulation, which has a good negative correlation with permeability and apparent fluidity; 2） With decrease of permeability and apparent fluidity and increase of fluid viscosity, the percolation curve is closer to the pressure gradient axis and the threshold pressure gradient increases. When the apparent fluidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics, while when the apparent fluidity up＂ non-Darcy percolation curve; 3） Oil-water is less than 1.0, the percolation curve is a ＂concave- two-phase relative permeability is affected by core permeability, fluid viscosity, apparent fluidity, and injection drive force; 4） The oil saturation of low- permeability sandstone reservoirs is mostly within 35%-60%, and the oil saturation also has a good positive correlation with the permeability and apparent fluidity.

Relative permeability estimation of oil-water two-phase flow in shale reservoir

Oil-water two-phase flow is ubiquitous in shale strata due to the existence of connate water and the injection of fracturing fluid.In this work,we propose a relative permeability model based on a modified Hagen-Poiseuille(HP)equation and shale reconstruction algorithm.The proposed model can consider the nanoconfined effects(slip length and spatially varying viscosity),oil-water distribution,pore size distribution(PSD),total organic matter content(TOC),and micro-fracture.The results show that the increasing contact angles of organic matters(OM)and inorganic minerals(iOM)increase the relative permeability of both oil and water.As the viscosity ratio increases,the relative permeability of oil phase increases while that of water phase decreases,due to the different water-oil distribution.The effective permeability of both oil and water decreases with the increasing TOC.However,the relative permeability of water phase increases while that of oil phase decreases.The increasing number and decreasing deviation angle of micro-fracture increase the effective permeability of oil and water.However,microfracture has a minor effect on relative permeability.Our model can help understand oil-water twophase flow in shale reservoirs and provide parameter characterization for reservoir numerical simulation.

Pore-Throat Combination Types and Gas-Water Relative Permeability Responses of Tight Gas Sandstone Reservoirs in the Zizhou Area of East Ordos Basin, China

With the aim of better understanding the tight gas reservoirs in the Zizhou area of east Ordos Basin,a total of 222 samples were collected from 50 wells for a series of experiments.In this study,three pore-throat combination types in sandstones were revealed and confirmed to play a controlling role in the distribution of throat size and the characteristics of gas-water relative permeability.The type-I sandstones are dominated by intercrystalline micropores connected by cluster throats,of which the distribution curves of throat size are narrow and have a strong single peak(peak ratio>30%).The pores in the type-II sandstones dominantly consist of secondary dissolution pores and intercrystalline micropores,and throats mainly occur as slice-shaped throats along cleavages between rigid grain margins and cluster throats in clay cement.The distribution curves of throat size for the type-II sandstones show a bimodal distribution with a substantial low-value region between the peaks(peak ratio<15%).Primary intergranular pores and secondary intergranular pores are mainly found in type-III samples,which are connected by various throats.The throat size distribution curves of type-III sandstones show a nearly normal distribution with low kurtosis(peak ratio<10%),and the micro-scale throat radii(>0.5μm)constitute a large proportion.From type-I to type-III sandstones,the irreducible water saturation(Swo)decreased;furthermore,the slope of the curves of Krw/Krg in two-phase saturation zone decreased and the two-phase saturation zone increased,indicating that the gas relative flow ability increased.Variations of the permeability exist in sandstones with different porethroat combination types,which indicate the type-III sandstones are better reservoirs,followed by type-II sandstones and type-I sandstones.As an important factor affecting the reservoir quality,the pore-throat combination type in sandstones is the cumulative expression of lithology and diagenetic modifications with strong heterogeneity.

The Influence Law of Oil Relative Permeability on Water Cut

Water cut is a key evaluation parameter for reservoir development evaluation. Relative permeability curve reflects reservoir characteristics and fluid characteristics. It is important to figure out the influence law of oil relative permeability on water cut. Based on the 269 relative permeability curves of Bohai oilfields, the distribution of oil index of Bohai oilfields were studied. On the basis, combined with Corey expression of relative permeability and fractional flow equation, the theoretical relationship between oil index and water cut increasing rate was established. Three end points of water cut increasing rate curve were proposed and the influence law between three end points and oil index was studied. The results show that the oil index has a linear relationship with three end points. When the value of water oil mobile ratio is large than 1, with the increase of oil index, maximum value of water cut increasing rate gradually increase. When the value of water oil mobile ratio is less than 10, oil index has great effect on recovery percent when water cut increasing rate reaches to the maximum value as well as water cut when water cut increasing rate reaches to the maximum value. The application of SS field shows that the theoretical value is consistent with the field data.

Effect of H_(2)S content on relative permeability and capillary pressure characteristics of acid gas/brine/rock systems:A review

Geological storage of acid gas has been identified as a promising approach to reduce atmospheric carbon dioxide(CO_(2)),hydrogen sulfide(H_(2)S)and alleviate public concern resulting from the sour gas production.A good understanding of the relative permeability and capillary pressure characteristics is crucial to predict the process of acid gas injection and migration.The prediction of injection and redistribution of acid gas is important to determine storage capacity,formation pressure,plume extent,shape,and leakage potential.Herein,the existing experimental data and theoretical models were reviewed to gain a better understanding of the issue how the H_(2)S content affects gas density,gas viscosity,interfacial tension,wettability,relative permeability and capillary pressure characteristics of acid gas/brine/rock systems.The densities and viscosities of the acid gas with different H_(2)S mole fractions are both temperature-and pressure-dependent,which vary among the gas,liquid and supercritical phases.Water/acid gas interfacial tension decreases strongly with increasing H_(2)S content.For mica and clean quartz,water contact angle increases with increasing H_(2)S mole fraction.In particular,wettability reversal of mica to a H_(2)S-wet behavior occurs in the presence of dense H_(2)S.The capillary pressure increases with decreasing contact angle.At a given saturation,the relative permeability of a fluid is higher when the fluid is nonwetting.The capillary pressure decreases with decreasing interfacial tension at a given saturation.However,the existing datasets do not show a consistent link between capillary number and relative permeability.The capillary pressure decreases with increasing H_(2)S mole fraction.However,there is no consensus on the effect of the H_(2)S content on the relative permeability curves.This may be due to the limited availability of the relative permeability and capillary pressure data for acid gas/brine/rock systems;thus,more experimental measurements are required.

Numerical simulation-based correction of relative permeability hysteresis in water-invaded underground gas storage during multi-cycle injection and production

By conducting relative permeability experiments of multi-cycle gas-water displacement and imbibition on natural cores,we discuss relative permeability hysteresis effect in underground gas storage during multi-cycle injection and production.A correction method for relative permeability hysteresis in numerical simulation of water-invaded gas storage has been worked out using the Carlson and Killough models.A geologic model of water-invaded sandstone gas storage with medium-low permeability is built to investigate the impacts of relative permeability hysteresis on fluid distribution and production performance during multi-cycle injection and production of the gas storage.The study shows that relative permeability hysteresis effect occurs during high-speed injection and production in gas storage converted from water-invaded gas reservoir,and leads to increase of gas-water transition zone width and thickness,shrinkage of the area of high-efficiency gas storage,and decrease of the peak value variation of pore volume containing gas,and then reduces the storage capacity,working gas volume,and high-efficiency operation span of the gas storage.Numerical simulations exhibit large prediction errors of performance indexes if this hysteresis effect is not considered.Killough and Carlson methods can be used to correct the relative permeability hysteresis effect in water-invaded underground gas storage to improve the prediction accuracy.The Killough method has better adaptability to the example model.

A Novel Empirical Equation for Relative Permeability in Low Permeability Reservoirs

In this paper, a novel empirical equation is proposed to calculate the relative permeability of low permeability reservoir. An improved item is introduced on the basis of Rose empirical formula and Al-Fattah empirical formula, with one simple model to describe oil/water relative permeability. The position displacement idea of bare bones particle swarm optimization is applied to change the mutation operator to improve the RNA genetic algorithm. The parameters of the new empirical equation are optimized with the hybrid RNA genetic algorithm(HRGA) based on the experimental data. The data is obtained from a typical low permeability reservoir well 54 core 27-1 in Gu Dong by unsteady method. We carry out matlab programming simulation with HRGA. The comparison and error analysis show that the empirical equation proposed is more accurate than the Rose empirical formula and the exponential model. The generalization of the empirical equation is also verified.

Classification Study on Relative Permeability Curves

The classification method of relative permeability curves is rarely reported, when relative permeability curves are applied;if the multiple relative permeability curves are normalized directly, but not classified, the calculated result maybe cause a large error. For example, the relationship curve between oil displacement efficiency and water cut, which derived from the relative permeability curve in LD oilfield is uncertain in the shape of low water cut stage. If being directly normalized, the result of the interpretation of the water flooded zone is very high. In this study, two problems were solved: 1) The mathematical equation of the relationship between oil displacement efficiency and water cut was deduced, and repaired the lost data of oil displacement efficiency and water cut curve, which solve the problem of uncertain curve shape. After analysis, the reason why the curve is not available is that relative permeability curves are not classified and optimized;2) Two kinds of classification and evaluation methods of relative permeability curve were put forward, the direct evaluation method and the analogy method;it can get the typical relative permeability curve by identifying abnormal curve.

Estimation of the water–oil–gas relative permeability curve from immiscible WAG coreflood experiments using the cubic B-spline model

Immiscible water-alternating-gas（WAG） flooding is an EOR technique that has proven successful for water drive reservoirs due to its ability to improve displacement and sweep efficiency.Nevertheless,considering the complicated phase behavior and various multiphase flow characteristics,gas tends to break through early in production wells in heterogeneous formations because of overriding,fingering,and channeling,which may result in unfavorable recovery performance.On the basis of phase behavior studies,minimum miscibility pressure measurements,and immiscible WAG coreflood experiments,the cubic B-spline model（CBM） was employed to describe the three-phase relative permeability curve.Using the Levenberg-Marquardt algorithm to adjust the vector of unknown model parameters of the CBM sequentially,optimization of production performance including pressure drop,water cut,and the cumulative gas-oil ratio was performed.A novel numerical inversion method was established for estimation of the water-oil-gas relative permeability curve during the immiscible WAG process.Based on the quantitative characterization of major recovery mechanisms,the proposed method was validated by interpreting coreflood data of the immiscible WAG experiment.The proposed method is reliable and can meet engineering requirements.It provides a basic calculation theory for implicit estimation of oil-water-gas relative permeability curve.

A Method for Calculating Oil Field Relative Permeability Curve by Using Water Drive Characteristic Curve in High Water Cut Stage

With the production of strong bottom water reservoir, it will soon enter the ultra-high water cut stage. After entering the ultra-high water cut period, the main means of stable production is liquid extraction. Large liquid volume has a certain impact on the physical property distribution and fluid seepage law of the oilfield. The relative permeability curve measured according to the industry standard is not used for the prediction of development indicators and the understanding of the dynamic law of the oilfield. In order to understand the characteristics of water drive law in high water cut stage of water drive oilfield, starting from the water drive characteristic curve in high water cut stage, the method for calculating the relative permeability curve is deduced. Through numerical simulation verification and fitting the actual production data, it is confirmed that the obtained relative permeability curve is in line with the reality of the oilfield, It can provide some guiding significance for understanding the production law and water drive law of strong bottom water reservoir in ultra-high water cut stage.

Wettability modification effects on relative permeability end-points:Comparative analysis of surfactant agents for enhanced oil recovery

This research examines the impact of wettability alteration on the end points of relative permeability,a crucial property of fluids and porous media that influences the displacement processes of immiscible fluids through such media.The estimation of the mobility ratio for oil recovery relies on these end points,which are influenced by connate water saturation and residual oil saturation.To investigate this relationship,carbonate rock is generally subjected to wettability alteration using surfactant agents,and core flooding is employed to determine the relative permeability before and after the alteration.The wettability of the rock is commonly assessed through contact angle measurements.Two surfactants,TritonX-100(Tx-100)and Cedar,were tested in reducing the wettability of the porous media for oil.The contact angle measurements revealed that Tx-100 was more effective for this purpose than Cedar.Furthermore,the relative permeability tests indicated that both surfactants decreased residual oil saturation,but Tx-100 also improved system pressure.In contrast,Cedar reduced residual oil saturation but increased system pressure,possibly because of its high viscosity.The results also demonstrate that injecting Tx-100 leads to a 14%increase in ultimate oil recovery compared with water injection,while Cedar injection increased the recovery factor by 5%.This difference may be attributed to the incomplete coverage of the pore wall by Cedar or its weaker chemical structure than Tx-100.Notably,in carbonate cores,neither non-ionic surfactant enhanced oil recovery.

A Statistical Model for the Relative Hydraulic Conductivity of Water Phase in Unsaturated Soils

Permeability coefficients of fluids occupying the pore space of a porous medium have significant influence on the flow of these fluids through the porous medium. In the case of unsaturated soils, in addition to other parameters such as void ratio, void distribution, particle size distribution and initial density the degree of saturation also affects the permeability coefficient of water. The degree of saturation, in unsaturated soil, is directly related to the matric suction of the soil through soil water characteristic curve. Matric suction is one of the two stress state variables widely used to characterize the deformation behavior of unsaturated soils. Therefore, it can be stated that both flow and deformation behaviors of unsaturated soil are affected by the permeability coefficient of water. Numerical modeling of coupled deformation-flow behavior of unsaturated soil requires a mathematical equation that relates the permeability coefficient to the degree of saturation. Since the parameters that affect the permeability coefficient of water in unsaturated soil have similar direct or indirect effects on the soil water characteristic curve, permeability can be effectively predicted using the soil water characteristic curve as done in statistical models. In this paper, a statistical model is proposed for the permeability of water in unsaturated soil using soil water characteristic curve of the soil. The calibrated parameters of the soil water characteristic curve are directly used in the prediction of permeability with- out additional calibration using measured permeability data. The predictive capability of the new equation is verified by matching the measured data of eight different soils found in the literature.

固本清目方对湿性年龄相关性黄斑变性小鼠肠道菌群的影响

目的从肠道菌群探讨固本清目方防治湿性年龄相关性黄斑变性(wet age-related macular degeneration,wAMD)小鼠的作用机制。方法105只C57 BL/6J小鼠随机分为正常组、蒸馏水组、固本清目方预防组和固本清目方治疗组,除正常组外其余小鼠均采用氢醌饲料喂养4个月联合激光光凝术诱导脉络膜新生血管(choroidal neovascularization,CNV)建立wAMD模型,并分别给予药物干预。正常组小鼠常规饲养作为对照。激光后7 d、14 d进行视网膜组织苏木素-伊红染色、脉络膜铺片、肠黏膜通透性检测和肠道菌群检测。结果与蒸馏水组比较,固本清目方预防组和固本清目方治疗组视网膜病变均减轻,其中7 d固本清目方预防组效果最明显;CNV面积均缩小,其中7 d固本清目方预防组、14 d固本清目方预防组、14 d固本清目方治疗组显著缩小(P<0.01);血清伊文思蓝浓度均降低,其中7 d固本清目方预防组显著降低(P<0.05);各组样本物种相对丰度在门和属水平上均存在差异,其中门水平上以拟杆菌门和厚壁菌门为主要优势菌群,与正常组比较,蒸馏水组厚壁菌门和拟杆菌门比值(Firmicutes/Bacteroidota,F/B)升高;与蒸馏水组比较,固本清目方预防组和固本清目方治疗组F/B值均降低。属水平分析:与正常组比较,蒸馏水组在杜氏杆菌属、梭菌属相对丰度均升高;与蒸馏水组比较,固本清目方预防组和固本清目方治疗组均出现不同程度的降低,进一步分析发现正常组、7 d固本清目方治疗组、14 d固本清目方预防组和14 d固本清目方治疗组之间均存在显著差异的生物标志物。结论固本清目方有效防治wAMD小鼠的发生、发展,其作用机制可能与增加肠道有益菌的相对丰度、重塑肠道微生态平衡、降低肠黏膜通透性有关。

Pore network modeling of water block in low permeability reservoirs

A pore network model was used in this paper to investigate the factors, in particular, throat radius, wettability and initial water saturation, causing water block in low permeability reservoirs. A new term - ＇relative permeability number＇ （RPN） was firstly defined, and then used to describe the degree of water block. Imbibition process simulations show that the RPN drops in accordance with the extension of the averaged pore throat radius from 0.05 to 1.5 μm, and yet once beyond that point of 1.5 μm, the RPN reaches a higher value, indicating the existence of a critical pore throat radius where water block is the maximum. When the wettability of the samples changes from water-wet to weakly water-wet, weakly gas-wet, or gas（oil）-wet, the gas RPN increases consistently, but this consistency is disturbed by the RPN dropping for weakly water-wet samples for water saturations less than 0.4, which means weakly waterwet media are more easily water blocked than water-wet systems. In the situation where the initial water saturation exceeds 0.05, water block escalates along with an increase in initial water saturation.

Pore Structure and Permeability Characterization of Highrank Coal Reservoirs: A Case of the Bide-Santang Basin, Western Guizhou, South China

The methods of nuclear magnetic resonance(NMR)spectroscopy,mercury injection porosimetry(MIP),and gas-water relative permeability(GWRP)were used to reveal the pore structure and permeability characteristics of high-rank coal reservoirs in the Bide-Santang basin,western Guizhou,South China,to provide guidance for coalbed methane(CBM)exploration and exploitation and obtain direct insights for the development of CBM wells.The results indicate that the coal reservoirs in the study area are characterized by well-developed adsorption pores and poorly developed seepage pores.The bimodal NMR transverse relaxation time(T2)spectra and the mutation in the fractal characteristic of the MIP pore volume indicate poor connectivity between the adsorption pores and the seepage pores.As a result,the effective porosity is relatively low,with an average of 1.70%.The irreducible water saturation of the coal reservoir is relatively high,with an average of 66%,leading to a low gas relative permeability under irreducible water saturation.This is the main reason for the low recovery of high-rank CBM reservoirs,and effective enhanced CBM recovery technology urgently is needed.As a nondestructive and less time-consuming technique,the NMR is a promising method to quantitatively characterize the pores and fractures of coals.