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The proton exchange membrane fuel cell (PEMFC), with a high energy conversion efficiency, has become an important means of hydrogen energy utilization. However, water condensation is unavoidable in the PEMFC because of low operating temperatures. The impact of liquid water on PEMFC performance and stability is significant. The gas diffusion layer (GDL) provides a critical transport path for liquid water in the PEMFC. Liquid water saturation and distribution in the GDL determine water flooding and mass transfer efficiency in the PEMFC. In this study, focusing on the effects of the water introduction method, osmotic pressure, and contact angle, the liquid water transport in the GDL was numerically investigated based on a pore-scale model using the volume of fluid (VOF) method. The results showed that compared with the conventional water introduction method without cracks, the saturation and spatial distribution of water inside the GDL obtained in the simulation were more consistent with the experimental results when the water was introduced through the microporous layer (MPL) crack. It was found that increasing the osmotic pressure resulted in a faster rate of water penetration, faster approaching the steady-state performance, and higher saturation. The ultra-high osmotic pressure contributed to the secondary breakthrough with a significant increase in saturation. Increasing the contact angle caused higher capillary resistance, especially in the region with small pore sizes. At a constant osmotic pressure, as the contact angle increased, the liquid water gradually failed to penetrate into the small pores around the transport path, causing saturation reduction and an ultimate failure to break through the GDL. Increasing the contact angle contributed to a higher breakthrough pressure and secondary breakthrough pressure. [ABSTRACT FROM AUTHOR]

In a proton exchange membrane fuel cell (PEMFC) system, proper management of water and heat transport is essential to improve its overall performance and durability. To comprehensively investigate the internal processes of PEMFCs, an improved two-phase non-isothermal model based on heat and water transfer mechanisms inside the fuel cell is developed. The results show that the model proposed in this work can predict the fuel cell's performance accurately and is capable of exploring water and heat transfer phenomena inside fuel cells. Additionally, the water and heat transfer of cathodes and anodes under different relative humidity and temperatures are studied. It can be concluded that when the PEMFC operates under a constant voltage, the anode water content gradually increases, while the cathode water content gradually decreases. The maximum water content occurs at the interface between cathode catalyst layer and cathode gas diffusion layer, while the minimum value is attained at the interface between anode catalyst layer and anode gas diffusion layer. When the fuel cell operates at 0.75 V, although the water content of CCL is the highest, no back-diffusion of dissolved water occurs. [ABSTRACT FROM AUTHOR]

Polymer flooding has been proved by many scholars for use in heavy oil reservoirs. However, due to mobility control effects and injectivity, selecting the appropriate solution viscosity is essential. It is difficult to form a deep understanding of the effect and mechanism of polymer flooding using conventional experimental methods with oil recovery as the reference standard, so it is necessary to conduct further study with the aid of simulation methods. In this study, a one-dimensional displacement mathematical model based on the Buckley–Leverett theory was established, and in the range of water–oil viscosity ratio from 0.1 to 0.6, the variation of water saturation along the flow caused by polymer solution was studied. The research results showed that under the action of a polymer solution, compared with water flooding, there was a decreasing region of water saturation along the flow due to oil phase accumulation. The larger the water–oil viscosity ratio, the larger the area of water saturation decline and the greater the degree of water saturation decline, resulting in a better the displacement effect. However, under the condition of oil–phase viscosity of 70 mPa·s, when the water–oil viscosity ratio reached 0.4, the range and degree of water saturation decline along the way no longer changed, all the crude oil that could be swept had been displaced, and the outlet end was close to producing only water, not oil; therefore, further increasing the water–oil viscosity ratio could not increase the oil recovery. At the same time, the increase in pressure had not changed, that is, the increase in pressure had not resulted in the same increase in oil recovery. When the viscosity of oil phase increased to 140 mPa·s, the same rule was displayed, the appropriate water–oil viscosity ratio was also 0.4. The paper analyzed the action mechanism of polymer solution through process description, and the results provided a clear selection method for selecting reasonable polymer solution concentration, as well as a reference for polymer solution range under different crude oil viscosity conditions. [ABSTRACT FROM AUTHOR]

Predicting reservoir parameters accurately is of great significance in petroleum exploration and development. In this paper, we propose a reservoir parameter prediction method named a fusional temporal convolutional network (FTCN). Specifically, we first analyze the relationship between logging curves and reservoir parameters. Then, we build a temporal convolutional network and design a fusion module to improve the prediction results in curve inflection points, which integrates characteristics of the shallow convolution layer and the deep temporal convolution network. Finally, we conduct experiments on real logging datasets. The results indicate that compared with the baseline method, the mean square errors of FTCN are reduced by 0.23, 0.24 and 0.25 in predicting porosity, permeability, and water saturation, respectively, which shows that our method is more consistent with the actual reservoir geological conditions. Our innovation is that we propose a new reservoir parameter prediction method and introduce the fusion module in the model innovatively. Our main contribution is that this method can well predict reservoir parameters even when there are great changes in formation properties. Our research work can provide a reference for reservoir analysis, which is conducive to logging interpreters' efforts to analyze rock strata and identify oil and gas resources. [ABSTRACT FROM AUTHOR]

Threshold pressure gradient (TPG) is a key parameter determining the pore-scale fluid dynamics. In tight gas reservoirs, both gas and water exist in the porous rock, and the existing water can be divided into irreducible and movable water. However, how movable water saturation will influence TPG has not yet been investigated. Therefore herein, nuclear magnetic resonance (NMR) and high-pressure mercury intrusion (HPMI) experiments were performed to determine pore-scale water distribution, movable water saturation, and pore throat distribution in the core plugs. Subsequently, the air bubble method was used to measure TPG as a function of movable water saturation and permeability inside tight gas core plugs, finding that TPG increased from 0.01 MPa/m to 0.25 MPa/m with the movable saturation increased from 2% to 35%. Finally, a semi-empirical model was derived to describe the correlation between TPG, movable water saturation, and permeability, which performed better than previous models in the literature. These insights will advance the fundamental understanding of TPG in tight gas reservoirs and provide useful guidance on tight gas reservoirs development. [ABSTRACT FROM AUTHOR]

The kinetics of methane hydrate formation in marine sediments with different water saturations are important to assess the feasibility of the hydrate production and understand the process of the secondary hydrate formation in the gas production from hydrate reservoir. In this paper, the behaviors of methane hydrate formation in marine sediments from the South China Sea at different water saturation levels were experimentally studied in isobaric conditions. The marine sediments used in the experiments have the mean pore diameter of 12.178 nm, total pore volume of 4.997 × 10-2 mL/g and surface area of 16.412 m²/g. The volume fraction of water in the marine sediments ranges from 30% to 50%. The hydrate formation rate and the final water conversion increase with the decrease of the formation temperature at the water saturation of 40%. At the same experimental conditions, the hydrate formation rate decreases with the increase of the water saturation from 40% to 50% due to the reduction of the gas diffusion speed. At the water saturation of 30%, the hydrate formation rate is lower than that at the water saturation of 40% due to the effect of the equilibrium hydrate formation pressure, which increases with the decrease of the water saturation. The final water conversion is shown to increase with the increase of the water saturation, even the formation process at higher water did not end. The experiments at low water saturation show a better repeatability than that at high water saturation. [ABSTRACT FROM AUTHOR]

The development of technologies for the accelerated formation or decomposition of gas hydrates is an urgent topic. This will make it possible to utilize a gas, including associated petroleum one, into a hydrate state for its further use or to produce natural gas from hydrate-saturated sediments. In this work, the effect of water content in wide range (0.7–50 mass%) and the size of quartz sand particles (porous medium; <50 μm, 125–160 μm and unsifted sand) on the formation of methane and methane-propane hydrates at close conditions (subcooling value) has been studied. High-pressure differential scanning calorimetry and X-ray computed tomography techniques were employed to analyze the hydrate formation process and pore sizes, respectively. The exponential growth of water to hydrate conversion with a decrease in the water content due to the rise of water–gas surface available for hydrate formation was revealed. Sieving the quartz sand resulted in a significant increase in water to hydrate conversion (59% for original sand compared to more than 90% for sieved sand). It was supposed that water suction due to the capillary forces influences both methane and methane-propane hydrates formation as well with latent hydrate forming up to 60% either without a detectable heat flow or during the ice melting. This emphasizes the importance of being developed for water–gas (ice–gas) interface to effectively transform water into the hydrate state. In any case, the ice melting (presence of thawing water) may allow a higher conversion degree. Varying the water content and the sand grain size allows to control the degree of water to hydrate conversion and subcooling achieved before the hydrate formation. Taking into account experimental error, the equilibrium conditions of hydrates formation do not change in all studied cases. The data obtained can be useful in developing a method for obtaining hydrates under static conditions. [ABSTRACT FROM AUTHOR]

Porosity and water saturation are the most critical and fundamental parameters for accurate estimation of gas content in the shale reservoirs. However, their determination is very challenging due to the direct influence of kerogen and clay content on the logging tools. The porosity and water saturation over or underestimate the reserves if the corrections for kerogen and clay content are not applied. Moreover, it is very difficult to determine the formation water resistivity (Rw) and Archie parameters for shale reservoirs. In this study, the current equations for porosity and water saturation are modified based on kerogen and clay content calibrations. The porosity in shale is composed of kerogen and matrix porosities. The kerogen response for the density porosity log is calibrated based on core-based derived kerogen volume. The kerogen porosity is computed by a mass-balance relation between the original total organic carbon (TOCo) and kerogen maturity derived by the percentage of convertible organic carbon (Cc) and the transformation ratio (TR). Whereas, the water saturation is determined by applying kerogen and shale volume corrections on the Rt. The modified Archie equation is derived to compute the water saturation of the shale reservoir. This equation is independent of Rw and Archie parameters. The introduced porosity and water saturation equations are successfully applied for the Ordovician Goldwyer formation shale from Canning Basin, Western Australia. The results indicate that based on the proposed equations, the total porosity ranges from 5% to 10% and the water saturation ranges from 35% to 80%. Whereas, the porosity and water saturation were overestimated by the conventional equations. The results were well-correlated with the core-based porosity and water saturation. Moreover, it is also revealed that the porosity and water saturation of Goldwyer Formation shale are subjected to the specific rock type with heterogeneity in total organic carbon total clay contents. The introduced porosity and water saturation can be helpful for accurate reserve estimations for shale reservoirs. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing becomes an essential method to develop tight gas. Under high injection pressure, fracturing fluid entering into the formation will reduce the flow channel. To investigate the influence of water saturation on gas flow behavior, this study conducted the gas relative permeability with water saturation and the flow rate with the pressure gradient at different water saturations. As the two dominant tight gas-bearing intervals, the Upper Paleozoic Taiyuan and Shihezi Formations deposited in Ordos Basin were selected because they are the target layers for holding vast tight gas. Median pore radius in the Taiyuan Formation is higher than the one in the Shihezi Formation, while the most probable seepage pore radius in the Taiyuan Formation is lower than the one in the Shihezi Formation. The average irreducible water saturation is 54.4% in the Taiyuan Formation and 61.6% in the Shihezi Formation, which indicates that the Taiyuan Formation has more movable water. The average critical gas saturation is 80.4% and 69.9% in these two formations, respectively, which indicates that the Shihezi Formation has more movable gas. Both critical gas saturation and irreducible water saturation have a negative relationship with porosity as well as permeability. At the same water saturation, the threshold gradient pressure of the Taiyuan Formation is higher than the one in the Shihezi Formation, which means that water saturation has a great influence on the Taiyuan Formation. Overall, compared with the Shihezi Formation, the Taiyuan Formation has a higher median pore size and movable water saturation, but water saturation has more influence on its gas flow capacity. Our research is conducive to understanding the effect of fracturing fluid filtration on the production of natural gas from tight reservoirs. [ABSTRACT FROM AUTHOR]

Assessing the influence of key parameters governing the formation of hydrates and determining the capacity of the latter to store gaseous molecules is needed to improve our understanding of the role of natural gas hydrates in the oceanic methane cycle. Such knowledge will also support the development of new industrial processes and technologies such as those related to thermal energy storage. In this study, high-pressure laboratory methane hydrate formation and dissociation experiments were carried out in a sandy matrix at a temperature around 276.65 K. Methane was continuously injected at constant flowrate to allow hydrate formation over the course of the injection step. The influence of water saturation, methane injection flowrate and particle size on hydrate formation kinetics and methane storage capacity were investigated. Six water saturations (10.8%, 21.6%, 33%, 43.9%, 55% and 66.3%), three gas flowrates (29, 58 and 78 mLn·min−1) and three classes of particle size (80–140, 315–450 and 80–450 µm) were tested, and the resulting data were tabulated. Overall, the measured induction time obtained at 53–57% water saturation has an average value of 58 ± 14 min minutes with clear discrepancies that express the stochastic nature of hydrate nucleation, and/or results from the heterogeneity in the porosity and permeability fields of the sandy core due to heterogeneous particles. Besides, the results emphasize a clear link between the gas injection flowrate and the induction time whatever the particle size and water saturation. An increase in the gas flowrate from 29 to 78 mLn·min−1 is accompanied by a decrease in the induction time up to ~100 min (i.e., ~77% decrease). However, such clear behaviour is less conspicuous when varying either the particle size or the water saturation. Likewise, the volume of hydrate-bound methane increases with increasing water saturation. This study showed that water is not totally converted into hydrates and most of the calculated conversion ratios are around 74–84%, with the lowest value of 49.5% conversion at 54% of water saturation and the highest values of 97.8% for the lowest water saturation (10.8%). Comparison with similar experiments in the literature is also carried out herein. [ABSTRACT FROM AUTHOR]

The increasing demand on coal production has led to the gradually increase of mining depth and more high methane mines, which bring difficulties in terms of coalbed methane (CBM) extraction. Hydraulic fracturing is widely applied to improve the production of CBM, control mine gas, and prevent gas outbursts. It improves coal bed permeability and accelerate desorption and migration of CBM. Even though the impacts of hydraulic fracturing treatment on the coal reservoirs are rare, negative effects could not be totally ignored. To defend this defect, the presented work aims to study the influence of water filtration on coal body deformation and permeability evolution. For this purpose, a simulation based finite element method was developed to build a solid-fluid coupled two-phase flow model using commercial software (COMSOL Multiphysics 5.4). The model was verified using production data from a long strike borehole from Wangpo coal mine in Shanxi Province, China. Several simulation scenarios were designed to investigate the adverse impacts of hydraulic fracturing on gas flow behaviors. The mechanisms of both relative and intrinsic permeability evolutions were analyzed, and simulation results were presented. Results show that the intrinsic permeability of the fracture system increases in the water injection process. The impacts of water imitation were addressed that a critical time was observed beyond which water cannot go further and also a critical pressure exists above which the hydraulic pressure would impair the gas flow. Sensitivity analysis also showed that a suitable time and pressure combination could be observed to maximize gas extraction. This work provides an efficient approach to guide the coal bed methane exploitation and other unconventional gas reservoirs. [ABSTRACT FROM AUTHOR]

Tight gas reservoirs commonly occur in clastic formations having a complex pore structure and a high water saturation, which results in a threshold pressure gradient (TPG) for gas seepage. The micropore characteristics of a tight sandstone gas reservoir (Tuha oilfield, Xinjiang, China) were studied, based on X-ray diffraction, scanning electron microscopy and high pressure mercury testing. The TPG of gas in cores of the tight gas reservoir was investigated under various water saturation conditions, paying special attention to core permeability and water saturation impact on the TPG. A mathematical TPG model applied a multiple linear regression method to evaluate the influence of core permeability and water saturation. The results show that the tight sandstone gas reservoir has a high content of clay minerals, and especially a large proportion of illite–smectite mixed layers. The pore diameter is distributed below 1 micron, comprising mesopores and micropores. With a decrease of reservoir permeability, the number of micropores increases sharply. Saturated water tight cores show an obvious non-linear seepage characteristic, and the TPG of gas increases with a decrease of core permeability or an increase of water saturation. The TPG model has a high prediction accuracy and shows that permeability has a greater impact on TPG at high water saturation, while water saturation has a greater impact on TPG at low permeability. [ABSTRACT FROM AUTHOR]

Machine learning technology is becoming increasingly prevalent in the petroleum industry, especially for reservoir characterization and drilling problems. The aim of this study is to present an alternative way to predict water saturation distribution in reservoirs with a machine learning method. In this study, we utilized Long Short-Term Memory (LSTM) to build a prediction model for forecast of water saturation distribution. The dataset deriving from monitoring and simulating of an actual reservoir was utilized for model training and testing. The data model after training was validated and utilized to forecast water saturation distribution, pressure distribution and oil production. We also compared standard Recurrent Neural Network (RNN) and Gated Recurrent Unit (GRU) which are popular machine learning methods with LSTM for better water saturation prediction. The results show that the LSTM method has a good performance on the water saturation prediction with overall AARD below 14.82%. Compared with other machine learning methods such as GRU and standard RNN, LSTM has better performance in calculation accuracy. This study presented an alternative way for quick and robust prediction of water saturation distribution in reservoir. [ABSTRACT FROM AUTHOR]

The adsorption of moisture or brine into coal causes the coal mass mechanical properties to be significantly altered, which can greatly affect the coal mining and coal seam gas extraction process. A study was therefore initiated to investigate the influence of moisture and brine saturations (5–25%) on brown coals' strength through a series of unconfined compressive strength tests, with the aid of acoustic emission, optical 3-D deformation analysis and scanning electron microscopy. According to the results, the coal mass is weakened by up to 26% upon the adsorption of moisture and water saturated samples show no crack propagation, whereas brine saturation enhances coal strength by up to 21% and delays crack propagation due to the crystallization of sodium chloride. Besides, a high brine concentration (25%) greatly improves coal mass strength but impairs the increase of Young's modulus due to its corrosive nature, which is consistent with the values of maximum strain at failure of the tested samples (3.9%, 3.1% and 3.6% for 5%, 15% and 25% brine saturated samples, respectively). In addition, because of the precipitation of sodium chloride in coal and the increase of conductivity of pore fluid, more acoustic emission signals are detected for brine saturated samples, while water saturated samples exhibit mush less acoustic release compared to the unsaturated samples. [ABSTRACT FROM AUTHOR]