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.

The simulation of hydrocarbon migration and accumulation is critical for understanding petroleum systems, yet existing methods face significant limitations, particularly in unconventional reservoirs. Traditional physical experiments are constrained by scale, complexity, and difficulty in reproducing real subsurface conditions, while conventional numerical simulation models struggle to capture the multi-scale dynamics of fluid flow in low-permeability formations. Many current approaches fail to incorporate key microscopic mechanisms, such as capillary effects, wettability alterations, and multi-phase interactions, leading to inaccuracies in predicting hydrocarbon accumulation. To address these challenges, this study provides a comprehensive review of HMA simulation techniques and proposes a novel multi-scale quantitative numerical simulation method. The approach integrates the lattice Boltzmann method for pore-scale fluid dynamics, pore network modeling for core-scale characterization, and geological modeling methods for reservoir-scale simulations. The results demonstrate that wettability, influenced by high-temperature and high-pressure conditions, plays a critical role in hydrocarbon accumulation by reducing capillary pressure and enhancing migration efficiency. This integrated framework significantly improves the accuracy and predictive capability of HMA simulations, offering a more reliable methodology for unconventional resource exploration and development.

渗流代理模型的构建是油气藏模拟技术研究的前沿方向,而目前广泛使用的纯数据驱动渗流代理模型无理论支撑,对数据数量和质量的要求较高,很大程度上限制了渗流代理模型的发展.为此提出了数据驱动与物理驱动相融合的双驱动渗流代理模型,其在纯数据驱动渗流代理模型的基础上,融合油气渗流理论,模拟预测油气渗流过程.结果表明:相较于纯数据驱动渗流代理模型,即使训练数据极度稀疏,双驱动渗流代理模型仍具有较高的预测精度;通过在训练数据中加入不同等级的干扰噪声,验证了双驱动渗流代理模型的鲁棒性优于纯数据驱动渗流代理模型;通过迁移学习,将训练好的双驱动渗流代理模型应用到新的渗流场,实现了快速收敛并节省了计算资源.

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.

Despite the significant progress made in tight gas exploration and development in recent years, the understanding of the dynamic mechanisms of tight gas accumulation is still limited, and numerical simulation methods are lacking. In fact, the gap between theory and field application has become an obstacle to the development of tight gas exploration and development. This work sheds light on the dynamic mechanisms of hydrocarbon accumulation in tight formations from the aspect of capillary self-sealing theory by embedding calculation of pressure- and temperature-dependent capillary force in a pore network model. The microscale dynamic mechanisms are scaled up to the reservoir level by geological simulation, and the quantitative evaluation of reserves based on real geological sections is realized. From the results, several considerations are made to assist with resource assessment and sweet spot prediction. Firstly, the self-sealing effect of capillary in the micro-nano pore-throat system is at the core of tight sandstone gas accumulation theory; the hydrocarbon-generated expansion force is the driving force, and capillary force comprises the resistance. Furthermore, microscopic capillary force studies can be embedded into a pore network model and scaled up to a geological model using relative permeability curve and capillary force curve. Field application can be achieved by geological numerical simulations at the reservoir scale. Finally, high temperature and high pressure can reduce capillary pressure, which increases gas saturation and reserves.

An accurate description of fluid flow is critical for the prediction of the productivity of shale gas reservoirs. In this paper, we present the current advances and a systematic summary on the fluid flow in shale gas reservoirs. First, shale pore structures, consisting of organic pores and inorganic pores ranging from nanoscale to micro-scale, and reservoir fluids, including free gas, absorbed gas, and water, are systematically presented. Thereafter, multi-physics flow phenomena motivated by scale effects, such as continuum flow, slip flow, transition flow, free molecular flow, and surface diffusion for gas, as well as the effective viscosity and slip boundary condition for water, are carefully summarized. Meanwhile, these flow mechanisms are discussed with molecular dynamics (MD) simulations and theoretical analysis. Subsequently, on the basis of upscaling approaches, including capillary bundle models, the lattice Boltzmann method (LBM), and pore network models (PNMs), fluid flow through heterogeneous shale matrix is reviewed and the influences of scale effects and pore structures are clarified. Additionally, shale gas well performance is discussed by combining the multiple transport mechanisms and a fracturing-shut-in-flowback-production process. Our review concluded that the fluid flow behaviour in shale gas reservoirs is a complex multi-scale process accompanied by multi-physical phenomena and multi-fluid distributions. Keeping this in mind is helpful for predicting the shale gas production and recoverable gas resources. We expect this study can not only help by providing a better understanding of the fluid flow in shale reservoirs but also provide significant implications to address other multiphase flow processes.

Studying the mechanism of phase interface snap-off during gas liquid immiscible displacement and its influencing factors have great significance in the field of enhanced oil and gas recovery such as gas driving, gas water alternation and foam driving. In this work, based on the original pseudopotential lattice Boltzmann model, we improved the fluid-fluid force scheme, added the fluid-solid force, coupled the Redlich-Kwong (RK) equation of state, and used the exact difference method (EDM) to add the external forces to the LBM framework. As well as verified the accuracy of the model by calibrating the thermodynamic consistency of the model and simulating a series of two phase systems such as testing the interfacial tension, static equilibrium contact angle and retention of the liquid phase at the corner. Based on the modified pseudopotential lattice Boltzmann model, we have carried out gas-liquid immiscible displacement simulations in a pore-throat-pore system, and the results have shown that: the snap-off phenomenon is related to the displacement pressure difference, pore-throat length ratio and pore-throat width ratio, and the snap-off phenomenon occurs only when the displacement pressure difference is within a certain range. When the displacement pressure difference is larger than the upper limit of the critical displacement pressure difference, the snap-off will be inhibited even if the snap-off condition predicted by the classical static rule has been reached; When the displacement pressure difference is less than the lower limit of the critical displacement pressure difference, it cannot overcome the "pinning" effect of the capillary tube and results in ineffective displacement. For the pore-throat structure with constant pore-throat width ratio, the displacement pressure difference range in which the snap-off phenomenon occurs increases as the pore-throat length ratio increases; For the pore-throat structure with constant pore-throat length ratio, the displacement pressure difference range in which the snap-off phenomenon occurs increases as the pore-throat width ratio decreases.

Knowledge of a shale pore structure is essential and critical to estimating gas storage and predicting gas production. Shale is a heterogeneous rock in terms of its composition and consists of organic matter (OM) and inorganic matter (IOM). Due to their difference in surface wettability and affinity to methane, the quantitative determination of apparent pore size distributions (APSDs) of OM and IOM as well as their contributions to the Barrett-Joyner-Halenda (BJH) pore volume is a very important task, but it is still a puzzling issue, especially considering the occurrence of water under the in situ condition. In this work, combining the water adsorption and low-pressure N-2 adsorption-desorption experiments, we obtained the APSDs of dry and moist shale and clay samples, where the latter is assumed to the representative of IOM. Then, given the water distribution related to the surface wettability, a novel approach is proposed to quantitatively determine the APSDs of OM and IOM as well as their contributions to the BJH pore volume of shale under dry and in situ conditions. Our experimental results demonstrated that small nanopores (<5 nm) presented under a dry condition may be absent on the clay APSD curves under a moist condition due to the capillary condensation effect but are still shown on the shale APSD curves due to the existence of hydrophobic OM nanopores. Under a dry condition, the APSDs of OM and IOM for our samples show that OM is rich in small nanopores (i.e., 3-50 nm) while IOM pores show a wider range of size (i.e., 3-200 nm), and the contribution of OM-hosted volume to BJH pore volume is 26.7% and 20%. While under a moist condition (RH = 98%), IOM pore volumes of 26% and 20% are occupied by water molecules, and the OM-hosted proportion increases to 36% and 26%, respectively. This study proposed a significant approach to deeply characterize shale pore structure, which provides a more solid and reliable foundation for the shale gas storage estimation and well performance prediction.

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.

Water huff-n-puff is an effective technology to enhance oil recovery (EOR) of low-permeability reservoirs, which are usually developed with hydraulic fracturing. Fluid exchange between fractures and the matrix is the main EOR mechanism. However, the presented water huff-n-puff simulations usually assume vertical fracture morphology, while the horizontal fractures formed in shallow reservoirs are rarely reported. In this study, we first introduced the water huff-n-puff process in a low-permeability oil reservoir with horizontal fractures and described the multiphase flow characteristics during the huff, soak, and puff stages. Then combined with a series of experiments, a comprehensive method is used to determine the key flow parameters, that is, capillary pressure and relative permeability. Finally, using the Chang 6 reservoir as an example, a series of numerical simulations were conducted to demonstrate the effect of water huff-n-puff on the well performance in this field. The simulation results showed that oil production is mainly affected by the injection volume and injection rate, while water production mainly depends on the well shut-in time. For a typical well in this field, the optimal injection volume, injection rate, and well shut-in time are 300 m3, 10 m3/d, and 30 days, respectively. In addition, our results showed that increasing the number of cycles not only benefits fluid exchange but also enhances the formation pressure. Both of them can accelerate the development of low-permeability oil reservoirs.

中国致密砂岩气资源丰富,勘探潜力大,但已有的开发实践证实开发面临巨大挑战.为了从微观角度深入认识致密砂岩气成藏机理,气水分布,提高致密砂岩气采收率,基于孔隙网络模型,开展了致密砂岩气充注数值模拟研究,探讨了微观尺度下致密砂岩气充注机制,并分析了充注过程中气水的赋存特征,建立了不同温度压力条件下毛细管力学模型,指出了不同地质条件下含气性差异与变化的特征.研究结果表明:①毛细管压力是孔隙内流体与孔隙壁面之间的分子间相互作用力的宏观表达,相较常温常压,在高温高压地层中毛细管压力更小,成藏下限可能更低;②由于孔隙结构的非均质性特征,并非所有大孔隙都被天然气充注,与小孔隙或者窄喉道相连的大孔隙可能无法被充注而呈现局部高含水特征,开发过程中,这部分水作为自由水被产出;③孔隙网络模拟揭示了岩心尺度上的致密砂岩微观含气性增长机制与气水分布形成过程,有利于深入认识致密油气成藏机理,以及气水分布.结论认为,基于孔隙网络充注模拟技术,在实验室条件下揭示了微观气水分布形成过程和致密砂岩气充注机理,对指导致密砂岩气开发具有重要指导和借鉴意义.

Although significant progress has been made in the tight gas exploration and development, there is still a limited understanding of the fluid charging and hydrocarbon accumulation in the sweet spot. In this study, a novel method is proposed to generate the stochastically constructed porous media which represents the transition region between tight surrounding sandstone and sweet spot. Based on the constructed porous media, the fluid charging and hydrocarbon accumulation processes of the tight reservoir are simulated by the lattice Boltzmann method (LBM). The numerical simulation results show that, although a piston-like pattern can be observed in field-scale simulation or laboratory experiments, at the micro-scale, due to the inherent heterogeneity of the porous media, the fluid charging pattern tends to be fingering-like. The existence of the transition region between tight surrounding sandstone and sweet spot becomes a water-bearing gas layer or even gas-bearing water layer at the top/bottom of the gas layers (sweet spot). The existence of fractures is favorable for hydrocarbon charging into the reservoir rocks, but not for the hydrocarbon accumulation due to the gas escaping through the fractures. Combined with well logging interpretation results, three typical water bodies (isolated water body, water body at the top, or bottom of the gas layer) are identified from the view of fluid charging and hydrocarbon accumulation.

Summary The transport behaviors of both single-phase gas and single-phase water at nanoscale deviate from the predictions of continuum flow theory. The deviation is greater and more complex when both gas and liquid flow simultaneously in a pore or network of pores. We developed a pseudopotential-based lattice Boltzmann (LB) method (LBM) to simulate gas/water two-phase flow at pore scale. A key element of this LBM is the incorporation of fluid/fluid and fluid/solid interactions that successfully capture the microscopic interactions among phases. To calibrate the model, we simulated a series of simple and static nanoscale two-phase systems, including phase separation, a Laplace bubble, contact angle, and a static nanoconfined bubble. In this work, we demonstrate the use of our proposed LBM to model gas/water two-phase flow in systems like a single nanopore, two parallel nanopores, and nanoporous media. Our LBM simulations of static water-film and gas-film scenarios in nanopores agree well with the theory of disjoining pressure and serve as critical steps toward validating this approach. This work highlights the importance of interfacial forces in determining static and dynamic fluid behaviors at the nanoscale. In the Applications section, we determine the water-film thickness and disjoining pressure in a hydrophilic nanopore under the drainage process. Next, we model water imbibition into gas-filled parallel nanopores with different wettability, and simulate gas/water two-phase flow in dual-wettability nanoporous media. The results showed that isolated patches of organic matters (OMs) impede water flow, and the water relative permeability curve cuts off at water saturation [= 1–volumetric total organic carbon (TOC)]. The residual gas saturation is also controlled by the volumetric TOC, ascribed to the isolation of organic patches by the saturating water; therefore, the gas relative permeability curve cuts off at water saturation (= 1–volumetric TOC).

The thin water film stabilized by disjoining pressure is non-negligible in tight formations which results in significant difference in multiphase flow behavior compared with that in conventional formations. In this work, a pore network model is proposed to simulate two phase flow in tight formations to highlight the contribution of thin water film on multiphase flow. The newly developed pore network model includes the influence of thin water film on fluid configuration, capillary entry pressure, fluid conductance and connectivity during multiphase flow in pore space. Our approach is first validated with the existing pore network model and then the influence of thin water film on two-phase flow is investigated extensively. The results show that the connate water saturation increases and its associated oil relative permeability decreases as the average pore radius decreases. It also suggests that in water-wet systems, the influence of thin water film on both oil and water phases becomes significant when the average pore radius is smaller than 100 nm. Existence of thin water film will increase the proportion of film water and corner water, resulting in an increasement in oil phase relative permeability and a slight decline of water phase relative permeability in tight porous media dominated by angular pores and throats; while in porous media dominated by circular shaped pores and throats, oil and water phase relative permeability are both enhanced due to better connectivity caused by thin water film; at the same time swelling of water film results in lower residue oil saturation and higher end point of water relative permeability. We also found higher water relative permeability when porous media has more irregular pores.

The gas slippage phenomenon under dry conditions has been investigated extensively both numerically and experimentally. However, very limited research has focused on gas slippage behavior under wet conditions. Unlike conventional formation, the influence of water on the gas transport process cannot be neglected in tight formations due to the comparable amount of thin water film attached along the rock surface. It is found experimentally that the gas slippage factor is positively related to water saturation if the water saturation is small, while it decreases with water saturation if it is larger than a critical value. Most of the existing models failed to capture the measured downtrend of the gas slippage factor with increasing water saturation, which resulted from water blocking or gas trapping phenomenon. In this work, a pore-scale network model is proposed to look at the water distribution characteristic and investigate the effect of water on the gas slippage factor. The proposed pore-scale model incorporates the capillary dominated multiphase fluid distribution, real gas effect, and gas transport mechanisms at pore scale. On the basis of our pore network model, the effect of pore structure characteristics including the frequency of mean pore radius, size of mean pore radius, aspect ratio, and coordination number on the gas slippage behavior are investigated and discussed in detail. Similar to previous experimental observations, the simulated gas slippage factor shows a non-monotonic increase trend with water saturation; it starts to decrease under high water saturation, and the critical water saturation depends on the pore structure factors. It increases with the mean pore radius and coordination number but decreases with the aspect ratio. We used the pore network model to investigate the effect of the water phase on the gas slippage behavior at the pore scale for the first time. It emphasized the predominance of water blocking and the gas trapping phenomenon in the estimation of the gas slippage factor at high water saturation.

裂缝控制致密油流体渗流方向和注水水窜方向,影响其产量和采收率.为研究长6和长4+5主构造裂缝及衍生的微裂缝方向,同时阐明优势渗流通道方向,以野外露头研究和岩心铸体薄片观察及扫描电镜观测为基础,结合前人研究成果,识别出长6和长4+5油层组三期构造裂缝,走向分别为近南北向、东西向及北东向,同时薄片中可见微观成岩裂缝,包括溶蚀缝、成岩收缩缝及粒内缝.长4+5油层组代表水窜井动态资料研究显示,北东向和东西向为流体优势渗流方向.研究结果表明:①南北向裂缝形成最早,受燕山期构造运动控制,北东向裂缝形成最晚,北东向和东西向裂缝受喜山期构造运动控制.②研究区构造裂缝规模较大,多条平直缝同时出现,开度值保持固定,具有一定方向性,与非构造成岩裂缝特征差异明显,而宏观构造裂缝与微裂缝之间继承性明显,表现为走向、形态等特征类似,具有相同成因.③广泛存在构造裂缝形成北东向和东西向两个高渗水窜通道,该通道上注采井网表现为前期产量较大,后期易水窜.该研究成果为致密油开发中高渗通道研究及井网部署实践提供了指导.

压回法压井作为非常规井控的有效技术之一,可以减少和避免溢流井喷等事故中地面及平台的危险.目前对于压回过程的计算中,只针对井筒内流动进行研究,而没有考虑储层性质的影响,?因此不完全符合现场实际情况需求.为了研究储层性质对压回过程的影响,首先建立了井筒气液两相流动模型,然后综合考虑泥饼、储层污染带、储层渗透率、孔隙度和饱和度因素影响下的压井液在压回储层后的流动规律,并分析了压回过程井筒的压力变化规律,最后定量出不同因素对压回储层效率的影响.研究结果表明,储层含气饱和度与泥饼渗透率对压井影响较小,而储层厚度、孔隙度影响较大,综合考虑不同储层性质影响的压回法压井能对气井安全钻井提供了技术保障.

长水平井+体积压裂是海相页岩气开发取得成功的主流技术,但我国的陆相/海陆过渡相页岩与海相页岩储层性质相差较大,陆相/海陆过渡相页岩的开发方式不能照搬海相页岩气的.本文提出陆相/海陆过渡相页岩应采用直井和水平井混合井型开发的技术思想.该技术思想的关键出发点在于陆相/海陆过渡相页岩(1)脆性矿物含量少,水平井体积压裂造复杂缝困难;(2)黏土矿物含量高,水平井体积压裂储层污染面积大;(3)纵向往往伴生其它非常规天然气资源(致密气、煤层气等),采用直井"多气合采"可以控制更多的储量.以鄂尔多斯盆地延长探区为例,本文详细论证了陆相/海陆过渡相页岩的上述特征对直井和水平井开发的影响,提出了基于水平井可控纵向储量占比、脆性指数、储层伤害表征参数和薄砂层占比4个参数的合理井型优选标准.结果表明,当水平井可控纵向储量占比<60％,脆性指数<35％,储层伤害表征参数>20％,薄砂层占比<10％时,可以采用直井开发,反之采用水平井开发.进一步地,基于该标准分析了延长组长7段和山西组山1段陆相页岩水平井与直井的开发实例.本文提出的思想突破了水平井是实现页岩气开发唯一方式的传统认识,强调了直井联合水平井开发陆相/海陆过渡相页岩气的优势,为实现陆相/海陆过渡相页岩气的经济有效开发奠定基础.

Nanoconfinement effects lead to the anomalous phase behavior of hydrocarbons in nanopores. Besides the capillary pressure, the critical properties’ shift and curvature-dependent effect are found to be wettability-dependent parameters. In this work, we propose novel methods to correlate the macroscopic contact angle to the critical properties’ shift and curvature-dependent effect with an in-depth analysis of the microscopic interactions, including molecule-wall interactions and intermolecular interactions at the liquid-vapor interface. Then, we extend the Peng-Robinson equation of state model to investigate the effects of wettability on the phase behavior and interfacial tension (IFT) of nanoconfined hydrocarbons. Our results show that the nanoconfinement effects are not only dependent on the pore size but also on the wettability of the pore wall. In nonhydrocarbon-wet nanopores, the nanoconfinement effects are limited, and the bubble point pressure (Pb) and IFT are close to the bulk values. In hydrocarbon-wet nanopores, with the pore radius smaller than 50 nm, the nanoconfinement effects become visible and they are further strengthened as the contact angle decreases. The calculated results suggest that under reservoir temperature for Eagle Ford reservoir with the pore size of 10 nm, the suppression of Pb and IFT with completely oil-wet cases are nearly six-fold and ten-fold higher than that of intermediate-wet cases.

In order to accurately predict the production performance of coalbed methane (CBM) wells and to formulate a reasonable production system, this paper established a coal reservoir permeability model considering the influence of pulverized coal blockage. Then, on the basis of this model, the flow velocity sensitivity (FVS) experimental data of 15 groups of coal samples taken from the Baode Block, Qinshui Basin, Liulin Block, Hancheng Block, and the Huanglong Coalfield were fitted to determine the permeability models for different coal samples. On this basis, this newly established permeability model was incorporated into a previously developed CBM well performance analysis software, and production history matching was carried out on two CBM wells. Finally, the effects of the parameters of pulverized coal blockage on the permeability of coal reservoirs and the production performance of CBM wells were studied by taking the fitting parameters of CBM Well W1 as the reference. And the following research results are obtained. First, this new model considering the influence of pulverized coal blockage can quantitatively describe the variation of coal reservoir permeability with fluid velocity. In addition, this model can be incorporated into a CBM numerical simulation software or a CBM well performance analysis software to apply it in a wide range. Second, the coal reservoir permeability is less affected by pulverized coal blockage in the Baode Block, but this effect shall not be ignored in the Qinshui Basin and the Huanglong Coalfield. Third, the greater the theoretical maximum permeability damage degree (Dmax) and the permeability damage degree index (n) are, the lower the relative flow velocity (v0.5) corresponding to the critical flow velocity of pulverized coal blockage is and the more obvious the effect of pulverized coal blockage on coal reservoir permeability is. Fourth, in order to reduce the adverse effect of pulverized coal blockage on coal reservoir permeability, it is suggested to reduce the production pressure difference appropriately in the process of production, especially in the initial stage of gas production, so as to avoid severe damage to coal reservoir permeability.