The original gas in place (OGIP) of a gas reservoir is the primary key parameter for the development of gas reservoirs, which can directly affect the reserve classification of gas reservoirs, the calculation of development benefits, and determination of development sequence. The gas reservoir with concealed gas-bearing area is one of the most complex types in gas reservoir development, its OGIP evaluation is challenging because of the influence of concealed gas-bearing area. In this work, based on the material balance principle, through comprehensively considering the effects of energy and gas supply from the concealed gas-bearing area, gas expansion, pore contraction, bound water expansion, water production, and water invasion in the production area and the concealed gas-bearing area, the material balance equations (MBEs) under the influence of the concealed gas-bearing area are established in two stages before and after the concealed gas starts to overflow. In addition, methods for determining the OGIPs of gas reservoirs by linear fitting are proposed. Finally, the new proposed reserve evaluation methods are validated using degradation verification approach, and then a field application is carried out. Results show that the proposed reserve evaluation methods are rational and reliable. Ignoring the role of concealed gas-bearing area may lead to the overestimation of OGIP for production area of a gas reservoir. This method can be used not only to calculate the OGIP of the production area, but also the OGIP of the concealed gas-bearing area. This work can provide the basis for the adjustment of the development scheme.

Pronounced wall-molecule interactions arise at nanoscale, profoundly varying the CH4-CO2 mixture thermodynamics as well as adsorption behavior, apparently different from that at bulk space where intermolecular interactions dominate. Inherently, wall-molecule interaction strength is crucial for controlling nanoconfined CH4-CO2 behavior, which however remains a knowledge gap as the most research focus on the mixture behavior within specific nanopore wall types to date. In this work, calibrating the attraction term resulting from the wall-molecule interactions, a modified EoS (Equation of State) for nanoconfined fluids is developed. Then, on the basis of fundamental equilibrium of chemical potential, a model characterizing the nanoconfined CH4-CO2 behavior is proposed by incorporating the modified EoS, multiple-component SLD (Simplified local density method) framework, and the adsorption mixture thickness, which can be efficiently solved by well-designed iteration procedures. Results indicate that: (a) CH4 fraction evidently reduces while approaching the nanopore wall, both small pore size and strong wall interactions contribute to its magnitude; (b) High CO2 adsorption selectivity over CH4 can be achieved under low pressure-temperature condition, especially with the bulk CO2 fraction of 0.5; (c) A large variation in CO2 selectivity, reaching up to 123.8%, can be induced by wall energy parameter, which is much greater than the pore size effect. The research is able to provide a clear understanding of molecule-wall interaction strength on CH4-CO2 behavior in nanoconfinement.

In recent years, the deep coalbed methane was developed rapidly, with breakthroughs in daily production of tens of thousands of cubic meters per well in multiple deep coalbed methane blocks. In order to develop deep coalbed methane more scientifically and efficiently, significantly improve the recovery rate of coalbed methane, establishing a reasonable, reliable, and comprehensive coalbed methane material balance equation, and studying the controlled reserves, average coal reservoir pressure, proportion of different types of gas production, productivity evaluation indicators, and EUR of deep coalbed methane reservoirs or gas wells have important theoretical and practical significance. At present, there are few reports on the material balance equation of coalbed methane considering the presence of free gas, coal matrix shrinkage, the presence of dissolved gas, the pressure difference between micropores enriched with adsorption gas and mesopores occupied by free gas and water, and the impact of coal formation stimulation. Firstly, based on the principle of material balance in deep coalbed methane reservoirs, a material balance equation for deep coalbed methane reservoirs under formation stimulation background was established by further considering the pressure difference between micropores enriched with adsorption gas and mesopores occupied by free gas and water, changes in coal reservoir physical parameters caused by formation stimulation, and dissolved gas, except considering pore compression caused by stress sensitivity, matrix shrinkage, water expansion, and water production in conventional material balance equation of coalbed methane reservoir. Then, a linear fitting method for evaluating the reserves of adsorbed gas, free gas, and dissolved gas, an explicit calculation method for average formation pressure, an evaluation method for the production proportion of adsorbed gas, free gas, and dissolved gas, a productivity evaluation method for deep coalbed methane wells, and an EUR prediction method were proposed. Finally, the proposed methods were applied in an example to evaluate the reserves of adsorbed gas, free gas, and dissolved gas controlled by the well. The variation law of the production proportions of adsorbed gas, free gas, and dissolved gas in the production process of deep coalbed methane well were revealed, and the characteristics of changes in productivity indicators were analyzed. The EUR and coalbed methane recovery under different abandoned pressures were predicted. Results show that: The proposed method for evaluating coalbed methane reserves only requires two or more actual measurements of the average coal reservoir pressure and corresponding cumulative gas and water production data, and can use linear fitting to evaluate the reserves of adsorbed gas, free gas, and dissolved gas controlled by deep coalbed methane wells. The proposed method for calculating the average formation pressure of deep coalbed methane is an explicit expression, which avoids the complex computer programming calculation of implicit solving methods; The proposed evaluation method for the production proportion of adsorbed gas, free gas, and dissolved gas in deep coalbed methane wells does not require the installation of carbon isotope monitoring devices at the wellhead, and can real-time evaluate the proportion of different gas production. The proposed productivity indexes of comprehensive fluid, free gas, adsorbed gas, dissolved gas, and water at bottomhole condition for deep coalbed methane wells can be used to identify the rationality of working systems of the deep coalbed methane well; The proposed EUR prediction method for deep coalbed methane wells can organize production data into a linear expression of apparent pressure p/Z * and Gp. Given a certain abandoned pressure, the EUR of deep coalbed methane wells can be predicted. In the initial stage of production of the example well, the production proportion of free gas is almost equivalent to that of adsorbed gas. During the production process, the proportion of free gas first rapidly increases, then slowly decreases, and finally gradually stabilizes at 29%. The production proportion of adsorbed gas first rapidly decreases, then slowly increases, and finally gradually stabilizes at 70%, while the production proportion of dissolved gas remains low. When the abandoned pressure is 4, 3, and 2 MPa, the coalbed methane recovery rates of the deep coalbed methane well are 37.8%, 44.2%, and 52.4%, respectively. Reducing the abandoned pressure is an effective way to improve the coalbed methane recovery rate of the deep coalbed methane reservoirs.

Original gas in place(OGIP)is the material foundation for coalbed methane(CBM)development,while the av-erage reservoir pressure and recovery factor are the primary evaluation metrics for CBM extraction.Currently,the evalu-ation methods for OGIP in undersaturated CBM reservoirs predominantly rely on material balance principles incorporat-ing both gas and aqueous phases,considering changes in porosity and saturation.These conventional approaches employ pseudo-deviation coefficient Z*to equivalate adsorbed gas to free gas,requiring numerous parameters and involving com-plex calculations.Traditional average pressure calculation methods additionally consider aqueous phase production,neces-sitating iterative computations of gas deviation factor Z,making the process cumbersome.In reality,for undersaturated CBM reservoirs,neither numerous parameters nor iterative calculations of the gas deviation factor are fundamentally re-quired.This study first establishes a material balance equation for undersaturated CBM reservoirs based on the adsorbed gas material balance principle,directly utilizing the relationship between remaining adsorbed gas reserves and pressure.This includes the Langmuir-Freundlich(L-F)adsorption model and the Dubinin-Astakhov(D-A)adsorption model based on micropore filling.Subsequently,the material balance equation is linearized to develop evaluation methods for OGIP,average reservoir pressure,and recovery factor in undersaturated CBM reservoirs.Finally,the methods are validated and applied in case studies.Research demonstrates:The proposed methods for calculating reserves and average reservoir pres-sure in undersaturated CBM reservoirs require only a few adsorption model parameters,along with pressure data from two or more well tests and corresponding cumulative gas production data.These methods enable the evaluation of OGIP and average reservoir pressure,as well as the prediction of recovery factor at a given abandonment pressure.The calculation process is simple,requires fewer parameters,saves computational time,and meets field accuracy requirements,making it suitable for widespread application.Using production data generated from a conceptual numerical simulation model,the relative error between the reserves evaluated by the proposed method and the numerical simulation results is-0.762 577％.The relative error for the evaluated average reservoir pressure during the pseudo-steady state phase falls within-0.60％to 0.25％,confirming the rationality and reliability of the method.Application and analysis of real-world wells with different adsorption models show that the reserve evaluation results align with field observations.The calculated average reservoir pressure curve passes through the actual shut-in pressure measurement points.At abandonment pressures of 2,1.5,1 MPa,the calculated recovery factors for Well A are 46.65％,55.54％,and 66.65％,respectively,while for Well B,they are 57.49％,65.05％,and 73.96％,providing significant guidance for field development.For undersaturated CBM reservoirs with known OGIP,the average reservoir pressure can be calculated without actual pressure measurement data.Compared to conventional methods,this approach significantly improves computational efficiency.The research findings can be ap-plied to assess remaining CBM reserves,evaluate well productivity,and diagnose inter-well interference.They hold sub-stantial theoretical and practical significance for production performance analysis,development strategy optimization,and production system adjustment.

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.

ABSTRACT: To ensure the long-term, efficient, and stable development of deep coalbed methane, it's urgent to conduct research on gas production prediction and influencing factors analyses. In this study, based on the three zones (stimulated zone with proppant filled, stimulated zone without proppant filled, and un-stimulated zone) distribution in deep coalbed methane reservoirs developed with fractured horizontal wells, composite pseudo-steady-state gas-water productivity equations are established. Subsequently, coupling this productivity equation with pressure propagation models considering well shut-in, dynamic permeability models, and the material balance equations, a composite gas production prediction model for fractured horizontal wells in deep coalbed methane reservoirs is proposed and solved. Finally, the validations using commercial numerical simulation software and history matching with field case are conducted, and the influencing factors on gas production in deep coalbed methane reservoirs are analyzed. Results show good agreements between the predicted and actual results are achieved for both synesthetic case and field case. The sensitive influencing factors on gas production are ranked as follows: number of fractures, free gas saturation, fracture half-length, permeability of Zone I, Zone I size, degree of coal fines blockage, permeability of Zone II, Zone II size, permeability of Zone III, and horizontal well spacing. 1. INTRODUCTION As a type of unconventional resource, coalbed methane is a very clean natural gas resource. Its development and utilization not only increase the rare low-carbon clean energy, but also serve as a practical carbon neutral industrial path, which can significantly reduce methane emissions during coal mining and reduce the greenhouse gas effect of methane. The shallow coalbed methane resources in China are 30.1 trillion cubic meters, and the preliminary estimate of deep coalbed methane resources can reach 40 trillion cubic meters. Obviously, deep coalbed methane resources are richer than those in the middle and shallow areas. Regarding the depth limit of deep coalbed methane, American scholars defined it as coalbed methane with a burial depth greater than 1,524 meters in the coal reservoir; Based on the progress of coalbed methane in recent years, Xu has proposed that deep coalbed methane specifically refers to those with a burial depth greater than 1500 meters in coal reservoirs. The industry gradually agrees that coalbed methane with a burial depth greater than 1500 meters is called deep coalbed methane.

The Bozi 3 reservoir is an ultra-deep condensate reservoir (−7800 m) with a high temperature (138.24 °C) and high pressure (104.78 MPa), leading to complex phase behaviors. Few PVT studies could be referred in the literature to meet such high temperature and pressure conditions. Furthermore, it is questionable regarding the applicability of existing condensate production techniques to such a high temperature and pressure reservoir. This study first characterized the phase behavior via PVT experiments and EOS tuning. The operating conditions were then optimized through reservoir numerical simulation. Results showed that: (1) the critical condensate temperature and pressure of Bozi 3 condensate gas were 326.24 °C and 43.83 MPa, respectively; (2) four gases (methane, recycled dry gas, carbon dioxide, and nitrogen) were analyzed, and methane was identified as the optimal injection gas; (3) gas injection started when the production began to fall and achieved higher recovery than gas injection started when the pressure fell below the dew-point pressure; (4) simultaneous injection of methane at both the upper and lower parts of the reservoir can effectively produce condensate oil over the entire block. This scheme achieved 8690.43 m3 more oil production and 2.75% higher recovery factor in comparison with depletion production.

ABSTRACT: In order to study the specific influence of various factors on gas leakage during the underground coal gasification (UCG), a numerical model of the Controlled Retracting Injection Point (CRIP) process for UCG was established by the computer modeling group software. Considering the geomechanical effect, the gas distribution characteristics during the CRIP process are explored, as well as the effects of gasification pressure difference, production pressure, gasified-gas pressure, reservoir permeability, and water energy on gas migration. Moreover, an assessment system of gas leakage during the UCG process was established based on dominant factors to provide the possibility for quick judgment of gas leakage. The results showed that the relative magnitude of gasifier pressure and initial coalbed pressure determines whether gas leakage occurs. The highest point of gasifier pressure occurs at a distance of 75 meters from the production well in the direction of the gas injection retreat. Gasifier pressure, gasification pressure difference, and permeability were the main factors, which form a complete gas leakage evaluation system. The gas leakage class was divided by 10 degrees, and Class 1 to Class 5 should enhance leak prevention measures. 1. INTRODUCTION The energy sector is a primary field for achieving carbon neutrality and peak carbon emissions. Since the beginning of this century, the world has been gradually transitioning towards a low-carbon energy structure. A new wave of industrial and technological revolutions has sparked a surge in the low-carbon revolution, new energy revolution, and intelligent revolution (Zou et al., 2019). Coal resources play a crucial role in global energy supply, at least for the next quarter-century. However, the environmental issues associated with its combustion partially offset its value (Takyi et al., 2023). Approximately 80% of the coal mined in China is burned directly on the surface for purposes such as power generation and heating (Imran et al., 2014). This utilization of coal resources will bring serious environmental pollution.

A method to generate fractures with rough surfaces was proposed according to the fractal interpolation theory. Considering the particle-particle, particle-wall and particle-fluid interactions, a proppant-fracturing fluid two-phase flow model based on computational fluid dynamics (CFD)-discrete element method (DEM) coupling was established. The simulation results were verified with relevant experimental data. It was proved that the model can match transport and accumulation of proppants in rough fractures well. Several cases of numerical simulations were carried out. Compared with proppant transport in smooth flat fractures, bulge on the rough fracture wall affects transport and settlement of proppants significantly in proppant transportation in rough fractures. The higher the roughness of fracture, the faster the settlement of proppant particles near the fracture inlet, the shorter the horizontal transport distance, and the more likely to accumulate near the fracture inlet to form a sand plugging in a short time. Fracture wall roughness could control the migration path of fracturing fluid to a certain degree and change the path of proppant filling in the fracture. On the one hand, the rough wall bulge raises the proppant transport path and the proppants flow out of the fracture, reducing the proppant sweep area. On the other hand, the sand-carrying fluid is prone to change flow direction near the contact point of bulge, thus expanding the proppant sweep area.

Abnormally high-pressure fractured low-permeability reservoirs have the characteristics of large rock pore volume compressibility and easy to change. In order to accurately calculate the detection radius in abnormally high-pressure fractured lowpermeability oil and gas reservoirs, based on the mechanism of the change of pore volume compressibility, porosity and permeability caused by the change in oil and gas reservoir pressure, the calculation model of pore volume compressibility, porosity and permeability is established, and a new calculation method for calculating the detection radius suitable for abnormally high-pressure fractured low-permeability oil and gas reservoirs is proposed. It is found that for abnormally high-pressure fractured low-permeability oil and gas reservoirs, the pore volume compressibility first decreases rapidly and then gradually flattens with the decrease of pore pressure in the production process. When calculating the detection radius, the change mechanism of pore volume compressibility,porosity and permeability cannot be all ignored. The stress sensitive effect of porosity and permeability is usually considered.However, if the change of pore volume compressibility is ignored, the pressure propagation distance of such oil and gas reservoirs will be seriously underestimated, and the greater the production, the greater the degree of underestimate. The research results have guiding significance for well test design and reasonable well spacing determination in abnormally high-pressure fractured low-permeability oil and gas reservoirs.

Summary There are lots of challenges for carbonate-based Underground Gas Storage (UGS) evaluation, among which the problem of heterogeneous reservoir modeling restricts the optimization of UGS. In this study, based on the static and dynamic data of seismic, geological and development, the matrix, bedding dissolution cave, vertical dissolution cave and fracture composite heterogeneous reservoirs in the target area are comprehensively characterized for the demand of UGS. The concept of reservoir-seepage system was proposed. The concrete method was to decompose the complex heterogeneous carbonate rock mass into Matrix-Cavity Pore Body (MCPB) and Fracture-Cavity Seepage Body(FCSB), and then use different scale data combined with reservoir simulation technology to characterize the MCPB and FCSB, so as to effectively simulate the complex heterogeneous carbonate reservoir-seepage system. Statically, the model is consistent with the results of geological conditions and seismic prediction, and can be used for the optimization of heterogeneous reservoirs. Dynamically, the numerical simulation of gas reservoir based on multiple medium model objectively reflects the seepage process along the fracture direction during production. This technology can effectively guide the overall evaluation of UGS and the scheme of injection-production wells.

当前,世界各国的国家综合实力及世界格局正发生着前所未有的变化,全球能源格局正经历颠覆性重塑,能源安全已被推高到国家安全的战略高度.在油气供给危机全球和平发展的背景下,资源量巨大、分布面积较广的煤层气资源开发意义重大.煤层气开发利用,不仅是增加了不可多得的低碳清洁能源,更是现实的"碳中和"工业路径(大幅度减少采煤过程的甲烷排放,降低甲烷的温室气体效应).近二十年的煤层气开发实践表明,我国煤层气储层低压、低渗、低饱和特征突显,解吸-扩散-渗流经典理论表现出严重的"水土不服",不能合理解释我国煤层气单井产量和采收率低的原因,以固-气吸附解吸及扩散理论为主导的传统的煤层气藏工程方法、数值模拟技术、排采控制技术与提高采收率技术,其预测结果很难与生产实际吻合,因此煤层气开发面临传统解吸扩散理论是否合理、开采技术是否配套的重大科学问题.

边水气藏水平井见水后产量下降,准确预测见水时间有利于选择合理的开发及配产方式、提高边水气藏采收率.考虑水侵速度、储层倾角及气相非达西效应等因素,建立边水气藏水平井见水时间预测模型;计算P边水气藏W井的见水时间,与未考虑水侵速度等因素的见水时间对比,并对影响因素进行敏感性分析.结果表明:水侵过程中,水质点向井底移动的速度为水侵速度与舌进速度的迭加,存在一个临界边界可将水质点运移过程分为纯水侵阶段和水侵迭加舌进阶段;预测模型计算结果与实际见水时间基本吻合,相对误差为-5.9％,验证模型可靠性;对见水时间产生正向影响的因素为储层有效厚度、储层倾角、水平井长度及水平井与气水边界的初始距离,产生负向影响的因素为水侵速度及气井产量,气相非达西效应影响甚微;影响水平井见水时间的主要因素由强到弱依次为气井产量、水侵速度、水平井与气水边界的初始距离、储层有效厚度、储层倾角和水平井长度.该结果为边水气藏水平井合理配产及提高采收率提供依据.

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.

The initial formation pressure of coalbed methane（CBM） reservoir is a key parameter used for the evaluation of CBM reserves and productivity, which plays a guiding role in CBM production. Therefore, it is of great significance to accurately calculate the initial reservoir pressure of CBM reservoir. Based on the pressure potential superposition principle of the seepage mechanics theory, the pressure potential model in the process of fracturing and shut in after fracturing is established, and a method for determining the initial reservoir pressure of CBM reservoir is proposed by using the wellhead pressure drop data in the shut-in stage of hydraulically fractured gas well under two conditions: ignoring or considering the fracture network permeability change in the process of fracturing and shut in after fracturing. And then, a field application is carried out. From the fitting results of the case study, it can be seen that the linear relationships for both methods are obvious, indicating that the established methods are effective. From the perspective of interpretation accuracy, the method of considering the fracture network permeability change after fracturing involves more data points in fitting, and the fracture network permeability change during fracturing and after fracturing is an indisputable fact, so the interpretation result by using the method considering the fracture network permeability change is more reliable. If the change process of fracture network permeability of coal formation during shut in after fracturing is ignored, the interpreted stable permeability of fracture network and initial reservoir pressure will be high. Since this method can not only be used to determine the initial reservoir pressure, but also to determine the stable permeability of fracture network after fracturing and evaluate the change trend of fracture network permeability, it provides a basis for the classification of CBM reservoir types, CBM reserve calculation, fracturing effect evaluation, and optimization design of drainage and production system.

原始煤储层压力是煤层气储量和产能评价中一个非常重要的参数,对煤层气开采具有指导作用,准确计算原始煤储层压力具有重大意义.因此,基于渗流力学理论压力势叠加原理,建立了压裂过程中和压裂后关井过程中压力势模型,并分忽略与考虑煤储层压裂过程中和压裂后裂缝网络渗透率变化两种情况,提出了利用水力压裂煤层气井关井阶段井口压力降落数据反演原始煤储层压力的方法,并进行了实例应用.从实例井拟合结果可以看出,忽略与考虑煤储层裂缝网络渗透率变化的原始地层压力方法线性关系都很明显,说明建立的方法有效.从解释精度的角度来看,考虑煤储层压裂后裂缝网络渗透率变化的方法参与拟合的数据点更多,且压裂过程和压裂后煤储层裂缝网络渗透率变化是不争的事实,解释结果更加可靠.如果忽略压后关井期间煤层裂缝网络渗透率的变化过程,评价的裂缝网络稳定的渗透率及原始煤储层压力会偏高.该方法在确定原始煤储层压力的同时,还可以确定煤储层压裂后裂缝网络稳定的渗透率并评价裂缝网络渗透率变化趋势,为煤层气藏类型划分、煤层气储量计算、压裂效果评价和排采制度优化设计提供依据.

The pursuit, toward transport efficiency, is significantly necessary for energy conversion, water filtration. However, structure design, aiming at further enhancing nanoconfined water flow, is still lacking. With the motivation to bridge the knowledge gap, a simple yet practical model regarding the nanocone structure design is established. This research demonstrates that nanocone, with desirable opening angle and length, possesses the capacity to achieve the optimal flow behavior. Flow resistance occurring inside nanocones, and that at cone entrance, exit, are considered. Optimal nanocone geometry can be determined based on the minimization of total resistance. Results show that (a) suitable opening angle spans from 10° to 30° over a wide range of nanocone geometry; (b) evident decline tendency of the suitable opening angle toward the increasing surface wettability is captured; and (c) water transport capacity inside optimal nanocone is 4–50 times that within cylindrical nanopores. This article forms a theoretical framework for nanocone design.

准确预测解吸区有助于刻画煤层气储量动用范围，为后期开发方案调整与针对性部署提供参考.基于煤层微元割理系统内物质守恒原理，考虑煤基质内气体解吸向煤割理的供气效应、应力敏感与基质收缩对割理孔隙度的影响以及气水两相流对解吸区压力展布的控制作用，建立适用于（未）压裂煤层气直井的解吸区动态预测模型.研究表明：压裂煤层气井的解吸区扩展形态会逐渐由椭圆形演化为圆形；在相同储层条件下，压裂煤层气井的解吸区范围大于未压裂煤层气井；在相同产气条件下，解吸能力较强的煤层对应的解吸区扩展速度较慢.本研究为煤层气井解吸区准确评价奠定理论基础.