Tianyi Zhao

Shale gas, mainly consisting of adsorbed gas and free gas, has served a critical role of supplying the growing global natural gas demand in the past decades. Considering that the adsorbed methane has contributed up to 80% of the total gas in place (GIP), understanding the methane adsorption behaviors is imperative to an accurate estimation of total GIP. Historically, the single-site Langmuir model, with the assumption of a homogeneous surface, is commonly applied to estimate the adsorbed gas amount. However, this assumption cannot depict the methane adsorption characteristics due to various compositions and pore sizes of shales. In this work, a multi-site model integrating the energetic heterogeneity in adsorption is derived to predict methane adsorption on shale. Our results show that the multi-site model is capable of addressing the heterogeneity of shales by a wide range of adsorption energy distributions (owing to the complex compositions and different pore sizes), which is different from the single-site model only characterized by single adsorption energy. Consequently, the multi-site model results have better accuracy against the experimental data. Therefore, applying the multi-site Langmuir model for estimating GIP in shales can achieve more accurate results compared with using the traditionally single-site model.

Understanding the mechanisms of snap-off during gas–liquid immiscible displacement is of great significance in the petroleum industry to enhance oil and gas recovery. In this work, based on the original pseudo-potential lattice Boltzmann method, we improved the fluid–fluid force and fluid–solid force scheme. Additionally, we integrated the Redlich–Kwong equation of state into the lattice Boltzmann model and employed the exact difference method to incorporate external forces within the lattice Boltzmann framework. Based on this model, a pore–throat–pore system was built, enabling gas–liquid to flow through it to investigate the snap-off phenomenon. The results showed the following: (1) The snap-off phenomenon is related to three key factors: the displacement pressure, the pore–throat length ratio, and the pore–throat width ratio. (2) The snap-off phenomenon occurs only when the displacement pressure is within a certain range. When the displacement pressure is larger than the upper limit, the snap-off will be inhibited, and when the pressure is less than the lower limit, the gas–liquid interface cannot overcome the pore–throat and results in a “pinning” effect. (3) The snap-off phenomenon is controlled using the pore–throat structures: e.g., length ratio and the width ratio between pore and throat. It is found that the snap-off phenomenon could easily occur in a “long-narrow” pore–throat system, and yet hardly in a “short-wide” pore–throat system.

The imbibition phenomenon widely exists in nature and industrial applications. It is of great significance to study the mechanism of imbibition and the influence laws of related factors. In this paper, based on the assumption of interacting capillaries, a capillary bundle model of counter-current imbibition is established. In addition, the characteristics of imbibition and the influences of capillary size and fluid viscosity are analyzed. The results show that water is imbibed into the smaller capillaries and expelled from the larger capillaries. The rate of the meniscus in water-imbibition capillaries is proportional to the square root of time. In the interacting capillaries, oil production by counter-current imbibition decreases and then increases gradually with the increase of the capillary diameter difference. When the total cross-sectional area of the capillary remains unchanged, the cross-sectional area of the total water-imbibition capillaries is affected by the size distribution of the capillaries. The larger the viscosity of the non-wetting phase, the more uneven the imbibition front, the lower the imbibition efficiency. The higher the viscosity of the wetting phase, the more uniform the imbibition front, and the higher the imbibition efficiency.

Shale reservoirs are rich in nanoscale pore-microfractures, and generally contain water (especially inorganic pores) under reservoir conditions. Therefore, evaluating gas flow capacity under water-bearing conditions is of great significance for analyzing reservoir capacity and forecasting production. Based on the single-phase gas transfer theory in nanopores, we established a gas transport model in both circular pores and slit pores by considering pore-fracture patterns of actual samples. As will be shown, inorganic pore fractures are mostly slit-type, while organic pores are mostly circular. This gas transport model also uses weighting coefficients superimposed on slip flow and molecular free flow. Further, the effect of water saturation on gas flow is quantified by considering the distribution characteristics of inorganic and organic pores in shale and also by combining the pore distribution characteristics of actual samples. The flow characteristics of gas in organic and inorganic pores under water-bearing conditions in the reservoir are further compared. The study lays a theoretical foundation for the reasonable evaluation and prediction of shale gas well capacity under reservoir water conditions.

Shale gas has attracted increasing attention as a new potential source of natural gas in recent years. Accurate micro-storage and mechanism of shale gas is important for defining and describing the adsorption characteristics, gas-in-place estimates. Organic-rich shale gas reservoirs were usually deposited under water environment which has great impact on shale gas adsorption. Different from the widely used solid-gas interface adsorption theory, the pore system in original shale reservoir is divided into solid-gas system and solid-liquid-gas system. In same statement, shale pores have stronger interaction with water molecules than CH₄ molecules, especially in solid-gas system. Water molecules mainly formed as competitive adsorption with shale gas on solid surface (solid-gas system) and liquid water surface (solid-liquid-gas system). Maxim gravitational potential energy, Ψ _max, the distance where Ψ _max occurs, z _m and limited pore side, D _L are given. When pore size D < D _L, no matter in what position the adsorbed molecules is, it force by both sides of the pore silts. When D > D _L, the ratio of unaffected area increases to approximately 100% with pore side. When D < 10 nm, the ratio increases rapidly this means that the ratio of free gas increases quickly. When D > 50 nm, the ratio of unaffected area almost reaches 100%, which means that the content of free gas is far greater than the adsorbed gas. This study not only provides a new classification of shale pore system, but also can act as a reference to better understanding the adsorption mechanism of shale reservoir.

Accurate micro-storage and mechanism of shale gas is important for defining and describing the adsorption characteristics, and for gas-in-place estimation. In this paper, reservoir forming process is divided into early stage and late stage, and the initial gas-water distribution in different stage is redefined. Different from the widely used solid-gas interface adsorption theory, the pore system in original shale reservoir is divided into solid-gas system and solid-liquid-gas system. Gas pores existing in organic matters belong to solid-gas system, and are classified into residual gas pores and metamorphic gas pores. Plant tissue pores in organic and mineral pores belong to solid-liquid-gas system. Their characteristics are described.