Real Shale Research Articles

Effective mineralization of organic pollutants in real shale gas flowback water via Fenton reactions over CuNiAl LDHs catalysts

Effective mineralization of organic pollutants in real shale gas flowback water via Fenton reactions over CuNiAl LDHs catalysts

A thermodynamics-based coupled model for multi-phase flowback in deformable dual-porosity shale gas reservoirs

Over the past decades, there has been growing interest in modelling multi-phase flowback in shale gas reservoirs during hydraulic fracturing, primarily due to the significant risk of groundwater pollution. However, the lack of fully coupled simulations and a unified theoretical model has hindered the study of coupled adsorptive hydro-mechanical behaviour and its influence on fluid flowback prediction. In this paper, we have extended the non-equilibrium thermodynamics-based Mixture Coupling Theory to derive the constitutive relationship and governing equation for adsorptive multi-phase fluid flows in deformable dual-porosity media. Helmholtz free energy density has been used to establish the relationship between solids and fluids. The interaction of adsorptive fluids in the pore and fracture space has been fully considered, leading to a new form of constitutive equation, which obtained the molecular adsorptive effect on the rock by introducing adsorption entropy production. The proposed governing equations determine the fully coupled evolution of solid deformation and multi-phase flow, with the consideration of adsorption as well as pore and fracture porosity change. Numerical simulation is then performed to study the flowback of a real shale gas well and the influence of coupled behaviour on model prediction. The simulation shows that the flowback flux is mainly by the fracture (more than 99.9 %) and the overall cumulative volume is 2427.1 m3 within 225 h which accounts for about 5.3 % of the total injected fracturing fluid, and the sensitivity analysis reveals that the manual fracture porosity is the most sensitive factor to the cumulative flowback. This work provides new insights into the flowback process of shale reservoirs in a fully coupled view and the proposed theoretical tool should contribute to the modelling of other adsorptive multi-phase flow problem in deformable dual-porosity media such as carbon storage and coalbed methane production.

Electrochemical analysis of ion-exchange membranes fouling during electrodialysis treatment of real shale gas flowback water

Electrodialysis (ED) is considered an effective technology for desalinating shale gas flowback fluid toward environmental risk control and resource recovery. However, membrane fouling remains a significant challenge and the particular fouling behavior of ion-exchange membranes (IEMs) in real scenario remains unclear. In this study, we employed interface characterization techniques including electrochemical impedance spectroscopy (EIS) to investigate the fouling behavior of both anion-exchange membranes (AEMs) and cation-exchange membranes (CEMs) during the desalination process. Notably, a positive correlation was observed between the transmembrane electric potential (TMEP) of the target membrane and the extent of membrane fouling during ED processing. EIS data revealed the membrane bulk exhibited the most pronounced increase in modeled electrical resistance, suggesting that internal fouling more significantly inhibited mass transfer compared to external fouling. Under varying current densities, the resistance of the AEM and CEM membrane bulk increased from an initial value of 3.93–16.53 Ω cm2 and from 3.90 to 9.87 Ω cm2, respectively, corresponding to their maximum TMEP increase by factors of 6.0 and 2.0 during the ED treatment. Our results demonstrate that AEM undergone a more severe organic fouling than CEM (scaling) during desalination of real shale gas flowback fluid. Effective strategies to mitigate the fouling issue in IEMs were finally proposed. These findings provide valuable guidance on future process optimizing and fouling mitigation in the ED treatment of real shale gas flowback fluid.

Numerical simulation of hydraulic fracture propagation after thermal shock in shale reservoir

The scale of propagation of hydraulic fractures in deep shale is closely related to the effect of stimulation. In general, the most common means of revealing hydraulic fracture propagation rules are laboratory hydraulic fracture physical simulation experiments and numerical simulation. However, the former is difficult to meet the real shale reservoir environment, and the latter research focuses mostly on fracturing technology and the interaction mechanism between hydraulic fractures and natural fractures, both of which do not consider the influence of temperature effect on hydraulic fracture propagation. In this paper, the hydraulic fracturing process is divided into two stages (thermal shock and hydraulic fracture propagation). Based on the cohesive zone method, a coupled simulation method for sequential fracturing of deep shale is proposed. The effects of different temperatures, thermal shock rates, and times on the scale of thermal fractures are analyzed. As well as the effects of horizontal stress difference and pumping displacement on the propagation rule of hydraulic fractures. The results show that the temperature difference and the thermal shock times determine the size and density of thermal fractures in the surrounding rock of the borehole, and the number of thermal fractures increases by 96.5% with the increase of temperature difference. Thermal fractures dominate the initiation direction and propagation path of hydraulic fractures. The main hydraulic fracture width can be increased by 150% and the length can be increased by 46.3% by increasing the displacement; the secondary fracture length can be increased by 148.7% by increasing the thermal shock times. This study can provide some inspiration for the development of deep shale by improving the complexity of hydraulic fractures.

Molecular Insights into CO2-Rich Industrial Waste Gas Enhanced Shale Gas Recovery and Sequestration in Real Shale Gas Reservoirs

Molecular Insights into CO₂-Rich Industrial Waste Gas Enhanced Shale Gas Recovery and Sequestration in Real Shale Gas Reservoirs

Performances and mechanisms of the peroxymonosulfate/ferrate(VI) oxidation process in real shale gas flowback water treatment

Shale gas flowback water (SGFW), which is an inevitable waste product generated after hydraulic fracturing during development, poses a severe threat to the environment and human health. Managing high-salinity wastewater with complex physicochemical compositions is critical for ensuring environmental sustainability of shale gas development. Desalination processes have been recommended to treat SGFW to adhere to the discharge limits. However, organic fouling has become a significant concern in the steady operation of desalination processes, and the effective removal of organic compounds is challenging. This study aimed to develop an effective oxidation method to mitigate membrane fouling in real SGFW treatment process. It adopted the peroxymonosulfate (PMS)/ferrate (Fe(VI)) process, involving both free and non-free radical pathways that can alleviate the negative effects of high-salinity environments on oxidation. The operating parameters were optimized and removal effects were examined, while the synergistic oxidation mechanism and organic conversion of the PMS/Fe(VI) process were also analyzed. The results showed that the PMS/Fe(VI) process exhibited a synergistic effect compared with the PMS and Fe(VI) processes alone, with a total organic carbon (TOC) removal efficiency of 46.8% under optimal reaction conditions in real SGFW. In the Fe(VI)/PMS process, active species such as Fe(V)/Fe(IV), ·OH, and SO4−· were jointly involved in the oxidation of organic matter. Additionally, 99.5% of the total suspended solids and 95.2% of Ba2+ in the SGFW were removed owing to the formation of a coagulant (Fe3+) and SO42− during the reaction. Finally, an ultrafiltration membrane fouling experiment proved that oxidation processes can increase the membrane-specific flux and alleviate fouling resistance. This study can serve as a reference for the design of real SGFW treatment processes and is significant for the environmental management of shale gas development.

Shale oil redistribution-induced flow regime transition in nanopores

The previous neglect of shale oil multi-component characteristics and the nanpore wall properties of real shale result in an insufficient understanding of shale oil flow mechanisms in nanopores. Meanwhile, research on the flow regimes of shale oil remains lacking. In this study, molecular dynamics simulations are employed to investigate the flow of shale oil in hydroxylated quartz nanopores and rough kerogen nanopores. Simulation results show that the flow regime changed as the pressure gradient (∇p) increased to a critical value (∇pc). The velocity profile was parabolic when ∇p < ∇pc, but gradually became piston-like when ∇p ≥ ∇pc. Because increasing ∇p leads the adsorbed molecules desorbing, aggregating in the pore center, and forming clusters that are not easy to shear. Increasing vertical force from pore wall causes fluid aggregation in the pore center as ∇p increases. The ∇pc in kerogen nanopores is larger than that in quartz nanopores due to the rough kerogen surface and sticky layers. Multi-component fluids have higher ∇pc than single-component fluids in quartz nanopores. However, they have the same ∇pc in kerogen nanopores due to the rough kerogen surface. This investigation can provide theoretical basis for high-efficient production of shale oil.

Enhancement strategies of aerobic denitrification for efficient nitrogen removal from low carbon-to-nitrogen ratio shale oil wastewater

The strategy of high reflux ratio and long solids retention time was adopted to realize efficient nitrogen removal from real shale oil wastewater. This was undertaken with a low chemical oxygen demand to total nitrogen (COD/TN) ratio by strengthening aerobic denitrification in an anoxic/aerobic membrane bioreactor (A/O-MBR). The TN removal load climbed from 22 to 25 g N/(kg MLSS·d) as the COD/TN ratio declined from 8 to 3. The abundance of heterotrophic nitrifying and aerobic denitrifying (HNAD) bacteria increased by 13.8 times to 42.5%, displacing anoxic denitrifying bacteria as the predominant bacteria. The abundance of genes involved in denitrification (napAB, narGHI, norBC, nosZ) increased, however the genes related to assimilatory nitrate reduction (nirA, narB, nasC) decreased. The capacity of the dominant HNAD bacteria in an A/O-MBR to efficiently utilize a carbon source is the key to efficient nitrogen removal from shale oil wastewater with a low COD/TN ratio.

Micro-scale reconstruction and CFD-DEM simulation of proppant-laden flow in hydraulic fractures

A comprehensive investigation of the dynamical characteristics of proppant-laden flow systems in hydraulic fractures is important for the development of unconventional oil and gas resources. In this paper, we combine the micro-scale reconstruction technique and CFD-DEM method to numerically investigate the mobility and distribution rules of proppant-laden fluid in rough hydraulic fractures. To characterize realistic fracture surface morphology, six synthetic fracture models were assembled based on optical scanning data of real shale from three sets of hydraulic fracturing experiments. In order to accurately simulate the fluid-particle two-phase flow in rough fractures, the lift forces and particle rolling effect are considered in the CFD-DEM model. First, the effectiveness of the used CFD-DEM solver was validated by comparing it to the experimental data. We then examined mechanisms for the typical flow behaviors of proppant particles and fracturing fluid in smooth and rough fractures. Subsequently, the surface area ratio of the synthetic fracture model is adopted to characterize the cross-scale relationship between the micro-scale proppant distribution and fracture’s geometric features induced by the macroscale fracturing parameters (i.e., confining stress, fluid viscosity, flow rate, and sand ratio). Lastly, the parameter effects of the fracturing fluid, proppant particle, and fracture aperture on the dynamic characteristics of particulate flow in the hydraulic fracture are further discussed. In summary, the presented numerical model and findings can help better understand particle transport and distribution in real rock fractures and bridge the connectivity of the micro-scale particle flow and macroscopic fracturing parameter, which is vital for hydraulic fracturing process optimization.

The study on modeling and simulation of shale multi-scale matrix-fracture system

Shale is a complex porous medium with multi-scale pores and well-developed fracture networks. This paper aims to use modeling and numerical simulation methods to study the transport of shale gas in a complex multi-scale matrix-fracture system. In this study, mathematical modeling and programming was used to establish digital models of shale gas multi-scale matrix and 3D discrete fracture network. Based on the transport mechanisms of shale gas, this study derives the mathematical models of shale gas transport in different transport media, and uses the finite element method to solve and analysis the transport of shale gas in the multi-scale matrix-fracture system. The model is verified by real shale gas field data. The results show that the fractal dimension of organic pores have great effects on shale gas transport. When the fractal dimension is greater than 1.4, the increase on gas production is particularly obvious. Compared with organic pores, the effect of fractal dimension of inorganic pores is smaller. The existence of the fracture network has an effect of up to 25% on gas production, and the optimal fracture density is 200.

Desalinating Real Shale Gas Wastewater by Membrane Distillation: Performance and Potentials

Shale gas wastewater is a hypersaline industrial effluent in demand of efficient treatment or resource recovery. Membrane distillation (MD) is a heat-driven desalination process of high potential to deal with such streams. However, its application is highly limited by the unsatisfactory hydrophobic membranes that involve a trade-off between vapor permeability and fouling/wetting resistance. Our previous studies highlighted the potential role of an intermediate coating layer of a carbon nanotube (CNT) for the superhydrophobic membrane with 1H,1H,2H,2H-perfluorodecyltriethoxysilane (FAS) grafted to address the trade-off issue against synthetic saline oily wastewater. The work herein investigated its application performance in the continuous concentration and water recovery of real shale gas wastewater, with a commercial PVDF membrane as the reference. The modified membrane recycled 48.2% of the total volume as high-quality water and rejected 99% of feed salinity, achieving a superior concentration rate and flux recovery rate compared to PVDF. The value of the COD, total nitrogen, and ammonia nitrogen in the permeate after the modified membrane was less than 50, 20, and 20 mg/L, meeting the local wastewater discharge standard. It was pointed out that the inorganic fouling for the MD membrane was more of a concern in dealing with a real stream, but the modified membrane exhibited excellent fouling resistance. The cost associated with the treatment was estimated at USD 2.2/m3 for a production capacity of 2000 m3/d. The proposed superhydrophobic membrane has proven to be a feasible alternative from both technical and economic standpoints, offering the potential to improve MD effluent water quality and mitigate membrane fouling.

Mathematical Model of Shale Oil Seepage at Micro-Nano Pore Scale

Due to the unclear seepage mechanism for shale oil, it is hard to establish a reasonable mathematical model to describe the flowing law. In this study, a real shale pore structure was reconstructed with CT scanning and a numerical model of fluid flowing in the real shale pore is developed with COMSOL, based on the boundary slip at the micro-nano pore scale to study the causes of nonlinear seepage. A two-fluid model is employed to establish a simple mathematical model to describe the relationship between the flow rate and the pressure gradient using the effective slip length to account for the influence of pore structure and true slip, and the established model is verified with experimental data coming from Jiyang shale oil. The results indicated that the pore structure greatly affected the shape of the seepage curve. With the increase in displacement pressure, the percentage of fluid involved in the flow increased until it became stable, showing a changing trend from nonlinearity to linearity. The established model can fit the experimental data well and reasonably characterize the nonlinear seepage of shale oil.

Study on Activation Behavior of Complex Fracture Network in Weak-Planar Rock

Aiming at the problem of quantifying the composition of complex fracture network and fracture activation after fracturing, a complex fracture network model of weak plane with prefabricated structure is established based on finite element method, global embedded cohesive zone model (CZM), and real shale outcrop. Considering the influence of fully coupled stress/fluid, the effects of weak plane azimuth, horizontal stress difference, fracturing fluid viscosity, and injection rate on fracture network composition, geometry, and stimulated reservoir volume (SRV) are studied. The concept of fracture relative activation rate, which can quantitatively analyze fracture network composition and fracture activation, is proposed. The results show that the fracture geometry of the two kinds of conjugated shale after fracturing is controlled by the most weak mechanical plane, and the fracture network is, respectively, axisymmetric and centrosymmetric. The fracture network is composed of the weak plane fractures with the dominant free gas transport and the matrix microfractures with the dominant adsorbed gas transport. The effects of weak plane azimuth, horizontal stress difference, and fracturing fluid viscosity on SRV length are not monotonous, while the increase of the azimuth, horizontal stress difference, fracturing fluid viscosity, and the reduction of appropriate injection rate will lead to the increase of SRV width. The effect of horizontal stress difference on the relative activation rate of fractures does not change monotonically, while the increase of weak plane azimuth, fracturing fluid viscosity, and injection rate will lead to the increase of the relative activation rate of matrix microfractures, the increase of the total length of activated fractures, and the decrease of the relative activation rate of weak plane fractures.

Asphaltene Precipitation and Deposition under Miscible and Immiscible Carbon Dioxide Gas Injection in Nanoshale Pore Structure

Summary Asphaltene precipitation and deposition is considered one of the prevailing issues during carbon dioxide (CO2) gas injection in gas enhanced oil recovery techniques, which leads to pore plugging, oil recovery reduction, and damaged surface and subsurface equipment. This research provides a comprehensive investigation of the effect of immiscible and miscible CO2 gas injection in nanopore shale structures on asphaltene instability in crude oil. A slimtube was used to determine the minimum miscibility pressure (MMP) of the CO2. This step is important to ensure that the immiscible and miscible conditions will be achieved during the filtration experiments. For the filtration experiments, nanocomposite filter paper membranes were used to mimic the unconventional shale pore structure, and a specially designed filtration apparatus was used to accommodate the filter paper membranes. The uniform distribution (i.e., same pore size filters) was used to illustrate the influence of the ideal shale reservoir structure and to provide an idea on how asphaltene will deposit when utilizing the heterogeneous distribution (i.e., various pore size filters) that depicts the real shale structure. The factors investigated include immiscible and miscible CO2 injection pressures, temperature, CO2 soaking time, and pore size structure heterogeneity. Visualization tests were undertaken after the filtration experiments to provide a clear picture of the asphaltene precipitation and deposition process over time. The results showed an increase in asphaltene weight precent in all experiments of the filtration tests. The severity of asphaltene aggregations was observed at a higher rate under miscible CO2 injection. It was observed that the miscible conditions have a higher impact on asphaltene instability compared to immiscible conditions. The results revealed that the asphaltene deposition was almost equal across all the paper membranes for each pressure used when using a uniform distribution. Higher asphaltene weight percent were determined on smaller pore structures of the membranes when using heterogeneous distribution. Soaking time results revealed that increasing the soaking time resulted in an increase in asphaltene weight precent, especially for 60 and 120 minutes. Visualization tests showed that after 1 hour, the asphaltene clusters started to precipitate and could be seen in the uppermost section of the test tubes and were fully deposited after 12 hours with less clusters found in the supernatant. Also, smaller pore size of filter membranes showed higher asphaltene weight percent after the visualization test. Chromatography analysis provided further evaluation on how asphaltene was reduced though the filtration experiments. Microscopy and scanning electron microscopy (SEM) imaging of the filter paper membranes showed the severity of pore plugging in the structure of the membranes. This research highlights the impact of CO2 injection on asphaltene instability in crude oil in nanopore structures under immiscible and miscible conditions. The findings in this research can be used for further research of asphaltene deposition under gas injection and to scale up the results for better understanding of the main factors that may influence asphaltene aggregation in real shale unconventional reservoirs.

Long short-term memory suggests a model for predicting shale gas production

Predicting the production behaviors of shale gas wells is of great importance for further developing future unconventional hydrocarbon strategies. An accurate prediction production, as well as reliable shale gas production models, are required to fully understand the shale gas exploitation budget. However, a major problem with classical analytic methods is the insufficient accuracy of the existing models, the time-consuming collection of historical production data, and the costly computational expense. To minimize this problem, a combination of the exponential smoothing method, autoregressive integrated moving average (ARIMA) model, and long short-term memory (LSTM) model was proposed to provide robust support for the production behaviors of shale gas. In this paper, we employed shale gas well production data to establish a database for model training and optimized the predicted model. Hereby, we sought to evaluate the production data predicted by conventional analytical methods, the exponential smoothing method, the ARIMA model, and the LSTM model. Shortly afterward, we objectively compared the predicted results obtained by the novel LSTM model and traditional analytical methods, such as Arps, stretched exponential decline (SEPD), and the Duong model. Herein, we compared the computational cost between the LSTM model and traditional numerical simulation. The combined interpretation of the proposed model demonstrates that the LSTM model achieved scientific accuracy and outstanding results in both short-term and long-term predictions, and realized production prediction of the adjacent well, with excellent agreement with the real shale gas production and a low error, making it an effective tool in forecasting shale gas production. This assay could be used as a potential approach for evaluating deep learning in the petroleum industry and for predicting the future production of unconventional hydrocarbons.

Adaptive anomaly detection-based liquid loading prediction in shale gas wells

Liquid loading is one of the main factors that can severely impede shale gas production. It is crucial for efficient operation of gas production to forecast the liquid loading in real time. Most of the existing techniques for liquid loading prediction are based on physical modeling, which are generally limited by human knowledge of the underlying mechanism of liquid loading formation. In this study, we propose a data-driven method for liquid loading prediction in shale gas wells based on deep anomaly detection technology. In particular, we employ deep neural networks to learn the normal behavior of a well and test a given sequence for anomaly by measuring the sequence reconstruction errors of the neural network with adaptive threshold. Unlike existing physical model-based methods, our method makes no assumptions about the cause of liquid loading, while the prediction results are merely determined by historical records. To verify the effectiveness of our method, we conduct experiments on real shale gas production data coming from 73 shale gas wells and the precision of method is 85.71%. The experimental results demonstrate that our method surpasses existing physical modeling based methods at prediction accuracy and timeliness.

Knudsen diffusion in pore-scale water-bearing shales: modelling and case study

Gas diffusivity in shales is significantly affected by water. However studies on the model of diffusion coefficient for water-bearing shales are very limited. In this work, we proposed a model to calculate the Knudsen gas diffusion coefficient at the presence of water in shale nanopores. This model was used to study the gas diffusivity in a real shale pore structure composed of both organic pores and inorganic pores at different water saturations. The model was also utilized to analyze the sensitivity of the Knudsen diffusion coefficient on a variety of factors. Results indicate that the existence of water drastically reduces the Knudsen diffusion in shales. When water saturation increases from 10% to 50%, gas concentration in inorganic pores rises by 53.7%. This effect can happen both in organic pores and inorganic pores due to pore connectivity. Water in inorganic pores can transport into organic pores and hinders gas diffusion in organic pores. The sensitivity study demonstrates that the increase of temperature, pore radius and porosity can lead to the rise of Knudsen diffusion coefficient. Inversely, the increase of tortuosity induces the decrease of the Knudsen diffusion coefficient. The pore wall roughness also affects the Knudsen diffusion coefficient. The rough wall surface contributes to a lower Knudsen diffusion coefficient compared with the smooth wall surface.

Porosity of gas shale: Is the NMR-based measurement reliable?

Aiming at obtaining an accurate porosity of gas shale, various approaches are attempted. Therein, nuclear magnetic resonance (NMR), being treated as a kind of new-developed technique, possesses the representative significance. However, as a booming technique, the reliability of NMR-based porosity of shale is not exactly defined. Depending on NMR device, this work measured the porosity of shale experiencing different water soaking time, accordingly, judging the reliability of NMR-based porosity. Results indicate the NMR outcomes vary with the water soaking time, making a doubt about the objectivity of NMR-based porosity in reflecting the real shale porosity. Furthermore, some supplementary means were adopted to verify the water soaking-induced variation in the pore system of shale sample, which intensities the suspicion if the NMR-based porosity is reliable or not. To sum up, this work considers that the NMR-based porosity of shale is not reliable enough when water is used as the probe. Besides, this work also offers some suggestions on how to enhance the reliability of NMR-based porosity of shale sample. Basically, this work selects a fresh perspective to analyze the NMR approach in determining shale porosity, which is hopefully helpful in promoting the development of NMR technique in the shale-related field.

An effective integration optimization algorithm for regional fracturing design and drilling placement

Hydraulic fracturing horizontal well technology has a pivotal role in exploiting unconventional resources, but it often requires considerable investment. Integrated optimization of the fracturing design, horizontal well, and drilling platform placement in the whole region is an efficient way to reduce cost and increase economic benefits. However, it is difficult to quickly complete these optimizations because traditional reservoir numerical simulation requires extensive resources in terms of labor, time, and computation. Therefore, we proposed a new algorithm, named Gaussian Process Regression-Bilevel Programming Genetic-Critical Circle Intersection Momentum Shift (GPR-BPG-CCIMS) algorithm to effectively co-optimize the fracturing design, horizontal well and drilling platform placement in the whole region. BPG algorithm shares the merits of Bilevel Programming (BP) and genetic algorithm (GA), which is used for optimizing the horizontal well and fracturing parameters. CCIMS algorithm is applied to optimize the drilling platform placement by merging and shifting drilling platform positions. GPR model is a production proxy model based on machine learning to improve optimization efficiency. The proposed algorithm was applied to a real shale gas reservoir to verify the effectiveness of the algorithm. The results showed that the GPR model exhibited great prediction accuracy by providing the high coefficient of determination (R2 = 0.999), the high percentage of accuracy-precision (PAP = 99.017) and the low root mean square error (RMSE = 0.022). The optimal fracture half length, cluster spacing, fracture fluid per meter, horizontal section length, well location, and drilling platform location were obtained by GPR-BPG-CCIMS algorithm. Compared with the actual net present value (NPV), the optimized NPV was increased by 181 million dollars. The proposed algorithm successfully co-optimizes the engineering parameters of the whole region in a short consumption time, which effectively supports the development scheme design and decision-making. The optimization framework can be extended to other shale gas basins.

Distribution of a water film confined in inorganic nanopores in real shale gas reservoirs

Distribution of the water film and initial water saturation within inorganic nanopores of shale are key problems for the evaluation and prediction of recoverable gas resources. Numerous research on the distribution and quantitative characterization of water film confined in nanopores have been conducted to the present. However, quantitation of water confined in inorganic nanopores of shale gas reservoir still remains challenging due to the complexity of porous media and reservoir conditions. In the present study, a novel model with disjoining pressure, interfacial tension and real gas effect taken into consideration, was proposed to disclose the distribution of water film confined inside circular or elliptic pores. In addition, the phenomena of capillary condensation and partial condensation have been revealed in elliptic pores. The proposed model was verified by comparing the calculation results with data from previous paper. Results show that the capillary condensation behavior of the water film is remarkably affected by the real gas effect. Water condenses easily into water films under the actual gas reservoir conditions, especially for small pores. However, the interfacial tension and high temperature can inhibit the formation of the water film in the confined space at a nanometer scale. Finally, the partial condensation is more likely to occur at both ends of elliptic pores.