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Tight sandstone water-bearing gas reservoirs typically exhibit low porosity and low permeability, with reservoir rocks characterized by complex pore structures, often featuring micron-scale or smaller pore throats. This intricate reservoir structure significantly restricts fluid flow within the reservoir, necessitating a certain threshold pressure gradient (TPG) to be overcome before flow can commence. This study focuses on the Ordos Basin and explores the influence of high water content tight sandstone gas reservoirs on TPG under different water saturation and formation pressure conditions through experiments. A mathematical model of TPG is established using multiple linear regression method. The results show that TPG is primarily affected by water saturation, followed by formation pressure. As the water saturation increases, the TPG of the core decreases, and the change becomes more pronounced when the water saturation exceeds 50%. As formation pressure increases, the weakening of the slippage effect in gas molecules leads to TPG stabilization, especially when local pressure exceeds 25.0 MPa. The research also shows that low-permeability cores exhibit greater TPG variation with pressure changes, while high-permeability cores remain more stable. A mathematical model was developed and validated to predict TPG based on permeability, water saturation, and formation pressure. These findings highlight the need to monitor formation water content during tight sandstone gas reservoir development to optimize production strategies, providing valuable insights for improving reservoir management and guiding future research. [ABSTRACT FROM AUTHOR]

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]

Abstract Underground rocks are generally subjected to water erosion and dynamic disturbances. To exclude the effect of clay minerals on the water–rock interaction mechanism, clay-free artificial porous rock (APR) was used to investigate the coupling effect of water saturation and loading rate on tensile behavior. Dynamic Brazilian disc experiments were performed on APR with six water saturation levels (100, 80, 60, 40, 20, and 0%) using a split Hopkinson pressure bar (SHPB) combined with a high-speed camera. The results indicated that the number of cracks in the APR specimens increased with the water saturation level during the dynamic damage process, with more radial cracks at the water saturation of 80–100%. The dynamic tensile strength (DTS) and dissipated energy density exhibited different change trends with water saturation levels under different loading rates and the rate dependence was most significant in the fully saturated state (100%). At lower loading rates, DTS initially decreased rapidly and then more slowly with increasing water saturation. At higher loading rates, DTS exhibited a ‘decrease then increase’ trend. Moreover, the water-affecting factor exhibited an overall decreasing trend with the loading rate and gradually converged to 1.0. These phenomena can be attributed to the interplay between the weakening and strengthening water-effect mechanisms based on the microstructure and water distribution in the APR specimens.

Abstract The longevity of waste asphalt can be considerably improved through cold recycling techniques combined with various additives. This research investigates the cold regeneration of aged asphalt concrete using Reclaimed Asphalt Pavement (RAP), Portland cement, cationic bitumen emulsion, and additional aggregates. The primary goal is to evaluate the performance enhancements in terms of average density, compressive strength, water resistance, and swelling across different mix compositions. Three distinct mixtures were formulated and assessed. Mix No. 1, composed solely of RAP, showed the lowest average density and highest swelling, indicating poor performance due to the lack of binding agents. Mix No. 2, which incorporated RAP, Portland cement, and water, exhibited the highest density and compressive strength, highlighting the crucial role of Portland cement in improving structural integrity. Mix No. 3, a more complex mixture including RAP, aggregates, Portland cement, water, and bitumen emulsion, displayed balanced properties with enhanced moisture resistance and reduced swelling. The experimental findings emphasize the effectiveness of adding Portland cement and bitumen emulsion to improve the mechanical and durability characteristics of recycled asphalt mixtures. Specifically, Mix No. 2 and Mix No. 3 demonstrated significant performance improvements, making them suitable for road maintenance applications. This study advocates for the widespread use of cold recycling methods with additive integration to achieve sustainable and cost-effective pavement restoration solutions.

Abstract Water flooding is one of the most important methods for oil field development, It accounts for more then 70% of China's crude oil production. However, in the progress of water flooding, preferential flow paths often formed between oil and water wells, which seriously restricts production rate. How to effectively identify the preferential flow paths has become the key to improving the effect of water flooding. In this paper, to solve the problem of difficult identification of preferential flow paths in reservoirs, through the change of core seepage law with high pore volume water flooding experiment, parameters such as multiple of water flux, change value of permeability, and water saturation were selected for analysis. The weight coefficient for each parameter was determined by the variation coefficient method of objective weight. Subsequently, a comprehensive reservoir identification index was obtained by weighting each parameter, which was used to describe the development degree of the preferential flow paths. Finally, quantitative criteria of preferential flow paths were given. The spatial characterization of preferential flow paths was realized by post processing of the Eclipse software. The new method for identifying preferential flow paths fully considers the changes in physical properties and fluid mobility of water-flooded reservoirs. The results of the new applied to a typical water-flooded reservoir in the Bohai Bay Basin show that the preferential flow paths calculated by the new method were highly consistent with the judgment results of tracers. It can accurately and quickly identify the preferential flow paths. This study provides a scientific basis for adjusting measures of water-flooded reservoirs to further enhance oil recovery. Moreover, the new method holds broader prospects for application in the field of porous media transport.

Abstract Moisture content of rock/coal can change its mechanical properties and absorption capacities, which can directly affect gas diffusivity, change the stress distribution and hence cause significant impacts on the overall gas or coal extraction process. Observation of the water penetration process and water distribution in the coal matrix will be beneficial for the understanding of the fluid-solid coupling mechanism in hydraulic fracturing, aquifer cracking and coal seam infusion. However, the observation of water penetration process and the determination of water distribution mode were hard to be non-destructively achieved as coal is a non-uniform, inhomogeneous and un-transparent material. µ-CT imaging, which is based on variation of X-ray attenuation related to the density and atomic composition of the scanned objects, enables a four-dimensional (spatial-temporal) visualise of the heterogeneous and anisotropic coal samples. The primary aim of this paper is extending the application of µ-CT imaging to explore the moisture penetration and distribution within coal samples during water infusion process, which has been reported by very little literature. The working principle and procedures of CT imaging was firstly introduced. Then, the determination equation of moisture distribution based on density profile was established. The CT determined moisture content has been compared with weighting method for verification. The paper has demonstrated that µ-CT can be used for non-destructively imaging the moisture distribution within coal samples.

Moisture content of rock/coal can change its mechanical properties and absorption capacities, which can directly affect gas diffusivity, change the stress distribution and hence cause significant impacts on the overall gas or coal extraction process. Observation of the water penetration process and water distribution in the coal matrix will be beneficial for the understanding of the fluid-solid coupling mechanism in hydraulic fracturing, aquifer cracking and coal seam infusion. However, the observation of water penetration process and the determination of water distribution mode were hard to be non-destructively achieved as coal is a non-uniform, inhomogeneous and un-transparent material. µ-CT imaging, which is based on variation of X-ray attenuation related to the density and atomic composition of the scanned objects, enables a four-dimensional (spatial-temporal) visualise of the heterogeneous and anisotropic coal samples. The primary aim of this paper is extending the application of µ-CT imaging to explore the moisture penetration and distribution within coal samples during water infusion process, which has been reported by very little literature. The working principle and procedures of CT imaging was firstly introduced. Then, the determination equation of moisture distribution based on density profile was established. The CT determined moisture content has been compared with weighting method for verification. The paper has demonstrated that µ-CT can be used for non-destructively imaging the moisture distribution within coal samples. [ABSTRACT FROM AUTHOR]

Tight sandstone gas has become an important field of natural gas development in China. The tight sandstone gas resources of Yan'an gas field in Ordos Basin have made great progress. However, due to the complex gas–water relationship, its exploration and development have been seriously restricted. The occurrence state of water molecules in tight reservoirs, the dynamic change characteristics of gas–water two-phase seepage and its main controlling factors are still unclear. In this paper, the water-occurrence state, gas–water two-phase fluid distribution and dynamic change characteristics of different types of tight reservoir rock samples in Yan'an gas field were studied by means of water vapor isothermal adsorption experiment and nuclear magnetic resonance methane flooding experiment, and the main controlling factors were discussed. The results show that water molecules in different types of tight reservoirs mainly occur in clay minerals and their main participation is in the formation of fractured and parallel plate pores. The adsorption characteristics of water molecules conform to the Dent model; that is, the adsorption is divided into single-layer adsorption, multi-layer adsorption and capillary condensation. In mudstone, limestone and fine sandstone, water mainly occurs in small-sized pores with a diameter of 0.001 μm–0.1 μm. The dynamic change characteristics of gas and water are not obvious and no longer change under 7 MPa displacement pressure, and the gas saturation is low. The gas–water dynamic change characteristics of conglomerate and medium-coarse sandstone are obvious and no longer change under 9 MPa displacement pressure. The gas saturation is high, and the water molecules mainly exist in large-sized pores with a diameter of 0.1 μm–10 μm. The development of organic matter in tight reservoir mudstone is not conducive to the occurrence of water molecules. Clay minerals are the main reason for the high water saturation of different types of tight reservoir rocks. Tight rock reservoirs with large pore size and low clay mineral content are more conducive to natural gas migration and occurrence, which is conducive to tight sandstone gas accumulation. [ABSTRACT FROM AUTHOR]

Tight sandstone water-bearing gas reservoirs typically exhibit low porosity and low permeability, with reservoir rocks characterized by complex pore structures, often featuring micron-scale or smaller pore throats. This intricate reservoir structure significantly restricts fluid flow within the reservoir, necessitating a certain threshold pressure gradient (TPG) to be overcome before flow can commence. This study focuses on the Ordos Basin and explores the influence of high water content tight sandstone gas reservoirs on TPG under different water saturation and formation pressure conditions through experiments. A mathematical model of TPG is established using multiple linear regression method. The results show that TPG is primarily affected by water saturation, followed by formation pressure. As the water saturation increases, the TPG of the core decreases, and the change becomes more pronounced when the water saturation exceeds 50%. As formation pressure increases, the weakening of the slippage effect in gas molecules leads to TPG stabilization, especially when local pressure exceeds 25.0 MPa. The research also shows that low-permeability cores exhibit greater TPG variation with pressure changes, while high-permeability cores remain more stable. A mathematical model was developed and validated to predict TPG based on permeability, water saturation, and formation pressure. These findings highlight the need to monitor formation water content during tight sandstone gas reservoir development to optimize production strategies, providing valuable insights for improving reservoir management and guiding future research.

Abstract Understanding water saturation levels in tight gas carbonate reservoirs is vital for optimizing hydrocarbon production and mitigating challenges such as reduced permeability due to water saturation (Sw) and pore throat blockages, given its critical role in managing capillary pressure in water drive mechanisms reservoirs. Traditional sediment characterization methods such as core analysis, are often costly, invasive, and lack comprehensive spatial information. In recent years, several classical machine learning models have been developed to address these shortcomings. Traditional machine learning methods utilized in reservoir characterization encounter various challenges, including the ability to capture intricate relationships, potential overfitting, and handling extensive, multi-dimensional datasets. Moreover, these methods often face difficulties in dealing with temporal dependencies and subtle patterns within geological formations, particularly evident in heterogeneous carbonate reservoirs. Consequently, despite technological advancements, enhancing the reliability, interpretability, and applicability of predictive models remains imperative for effectively characterizing tight gas carbonate reservoirs. This study employs a novel data-driven strategy to prediction of water saturation in tight gas reservoir powered by three recurrent neural network type deep/shallow learning algorithms—Gated Recurrent Unit (GRU), Recurrent Neural Networks (RNN), Long Short-Term Memory (LSTM), Support Vector Machine (SVM), K-nearest neighbor (KNN) and Decision tree (DT)—customized to accurately forecast sequential sedimentary structure data. These models, optimized using Adam's optimizer algorithm, demonstrated impressive performance in predicting water saturation levels using conventional petrophysical data. Particularly, the GRU model stood out, achieving remarkable accuracy (an R-squared value of 0.9973) with minimal errors (RMSE of 0.0198) compared to LSTM, RNN, SVM, KNN and, DT algorithms, thus showcasing its proficiency in processing extensive datasets and effectively identifying patterns. By achieving unprecedented accuracy levels, this study not only enhances the understanding of sediment properties and fluid saturation dynamics but also offers practical implications for reservoir management and hydrocarbon exploration in complex geological settings. These insights pave the way for more reliable and efficient decision-making processes, thereby advancing the forefront of reservoir engineering and petroleum geoscience.

The technology of CO2-enhanced coalbed methane (CO2-ECBM) can reduce greenhouse gas emissions, and has the function of clean energy production and environmental protection. In order to study the drainage and production laws of CH4 production by CO2 injection in water-bearing coal seams under gas-water two-phase flow conditions, as well as the effects of different initial water saturation and CO2 injection conditions on CH4 production, CO2 storage, and reservoir permeability. A coupled fluid-solid-thermal model for competitive adsorption, temperature changes, coal deformation, and water transport was constructed. The high accuracy of the model was demonstrated by comparing with the field data, existing experiments and numerical solutions of existing model, and the advantages of the model were specified. CO2-ECBM numerical simulation were subsequently carried out using COMSOL. The results shown that, CO2 injection can enhance the rate and amount of CH4 production, which indicated the feasibility of CO2 injection to increase production. With the continuous CO2 injection, the CH4 concentration in the reservoir decreased, the CO2 concentration increased, the temperature near the gas injection well increased, the temperature near the production well decreased and the temperature from the gas injection well to the production well slowly decreased. Water phase relative permeability gradually decreased and gas phase relative permeability gradually increased during gas injection and extraction period. Due to the combined effect of effective stress and matrix shrinkage/expansion, the reservoir permeability exhibited a trend of “decrease-increase-decrease”. The higher the initial water saturation of the coal seam, the lower the CH4 production and the lower the permeability decrease. The maximum decrease in cumulative CH4 production was 15.19%. Ignoring the impact of water in coal seams can overestimate CH4 production, and the impact of coal seam water should be considered in numerical simulation. The higher the CO2 injection temperature and pressure, the greater the CH4 production and the greater the permeability decrease. The cumulative CH4 production increased by 13.27% and 39.77%, and permeability decreased by 20.4% and 46.14%, respectively. Increasing the CO2 injection temperature and pressure was conducive to increase CH4 production.

Abstract The dynamic compression test of geopolymer concrete (GC) before and after water saturation was carried out by the split Hopkinson pressure bar (SHPB). And the effects of water saturation and strain rate on impact toughness of GC were studied. Based on Weibull statistical damage distribution theory, the dynamic constitutive model of GC after water saturation was constructed. The results show that the dynamic peak strain and specific energy absorption of GC have strain rate strengthening effect before or after water saturation. The impact toughness of GC decreases after water saturation. The size distribution of GC fragments has fractal characteristics, and the fractal dimension of GC fragments after water saturation is smaller than that before water saturation. The dynamic constitutive model based on Weibull statistical damage distribution theory can accurately describe the impact mechanical behavior of GC after water saturation, and the model fitting curves are in good agreement with the experimental stress–strain curves.

Understanding water saturation levels in tight gas carbonate reservoirs is vital for optimizing hydrocarbon production and mitigating challenges such as reduced permeability due to water saturation (Sw) and pore throat blockages, given its critical role in managing capillary pressure in water drive mechanisms reservoirs. Traditional sediment characterization methods such as core analysis, are often costly, invasive, and lack comprehensive spatial information. In recent years, several classical machine learning models have been developed to address these shortcomings. Traditional machine learning methods utilized in reservoir characterization encounter various challenges, including the ability to capture intricate relationships, potential overfitting, and handling extensive, multi-dimensional datasets. Moreover, these methods often face difficulties in dealing with temporal dependencies and subtle patterns within geological formations, particularly evident in heterogeneous carbonate reservoirs. Consequently, despite technological advancements, enhancing the reliability, interpretability, and applicability of predictive models remains imperative for effectively characterizing tight gas carbonate reservoirs. This study employs a novel data-driven strategy to prediction of water saturation in tight gas reservoir powered by three recurrent neural network type deep/shallow learning algorithms—Gated Recurrent Unit (GRU), Recurrent Neural Networks (RNN), Long Short-Term Memory (LSTM), Support Vector Machine (SVM), K-nearest neighbor (KNN) and Decision tree (DT)—customized to accurately forecast sequential sedimentary structure data. These models, optimized using Adam's optimizer algorithm, demonstrated impressive performance in predicting water saturation levels using conventional petrophysical data. Particularly, the GRU model stood out, achieving remarkable accuracy (an R-squared value of 0.9973) with minimal errors (RMSE of 0.0198) compared to LSTM, RNN, SVM, KNN and, DT algorithms, thus showcasing its proficiency in processing extensive datasets and effectively identifying patterns. By achieving unprecedented accuracy levels, this study not only enhances the understanding of sediment properties and fluid saturation dynamics but also offers practical implications for reservoir management and hydrocarbon exploration in complex geological settings. These insights pave the way for more reliable and efficient decision-making processes, thereby advancing the forefront of reservoir engineering and petroleum geoscience. [ABSTRACT FROM AUTHOR]

The conventional Archie formula struggles with the interpretation of water saturation from resistivity well log data due to the increasing complexity of exploration targets. This challenge has prompted researchers to explore alternative physical parameters, such as acoustic characteristics, for breakthroughs. Clarifying the influencing factors of porous media acoustic characteristics is one of the most important approaches to help understanding the mechanism of acoustic characteristics of carbonate reservoirs. The article uses digital rock technology to characterize the pore structure, quantitatively identify fractures and pore structures in carbonate rocks, and establish digital models. Through conventional acoustic testing, the pressure wave (P-wave) and shear wave (S-wave) velocities of rock samples at different water saturations are obtained, and the dynamic elastic modulus is calculated. A finite element calculation model is established using the digital rock computational model to provide a basis for fluid saturation calculation methods. Based on real digital rock models, different combinations of virtual fractures are constructed, and factors affecting acoustic parameters are analyzed. The study finds that as porosity increases, the velocity difference between porous cores and fractured cores also increases. These findings provide important technical support and a theoretical basis for interpreting acoustic well logging data and evaluating carbonate reservoirs with different pore and fracture types. [ABSTRACT FROM AUTHOR]

The dynamic compression test of geopolymer concrete (GC) before and after water saturation was carried out by the split Hopkinson pressure bar (SHPB). And the effects of water saturation and strain rate on impact toughness of GC were studied. Based on Weibull statistical damage distribution theory, the dynamic constitutive model of GC after water saturation was constructed. The results show that the dynamic peak strain and specific energy absorption of GC have strain rate strengthening effect before or after water saturation. The impact toughness of GC decreases after water saturation. The size distribution of GC fragments has fractal characteristics, and the fractal dimension of GC fragments after water saturation is smaller than that before water saturation. The dynamic constitutive model based on Weibull statistical damage distribution theory can accurately describe the impact mechanical behavior of GC after water saturation, and the model fitting curves are in good agreement with the experimental stress–strain curves. [ABSTRACT FROM AUTHOR]

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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.

In the Changning block of the southern Sichuan Basin, the shale gas wells in the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation (Wufeng-Longmaxi) demonstrate significant difference in flowback rate of fracturing fluid, given the same fracturing scale and production time. Based on the P90 curve of flowback rate with time, wells with high flowback rates in this area are categorized, and they are generally defined with the 100-day flowback rate of >40%, the 200-day flowback rate of >50%, and the first-year flowback rate >60%. Through comprehensive research on the geological characteristics of the Changning block, the geological factors that cause high gas well backflow rates have been identified. The results are obtained in four aspects. First, gas wells with high flowback rates generally show higher flow rates for smaller distances to the fault, and the NE faults formed during the late Yanshanian to early Himalayan and with fault throw >200 m have the greatest impact on the flowback rate. Second, plane heterogeneity of water saturation contributes to the high flowback rate of some wells. Third, the proportion of the Middle Ordovician Baota Formation in the horizontal section of wells is positively related to the flowback rate, and the drilling and fracturing of the Baota limestone with high water content can lead to high flowback rates of gas wells to some extent. Fourth, unidirectional linear natural fractures between wells can easily cause inter-well frac-hit, leading to high flowback rates of gas wells. In conclusion, the research results are helpful in predicting areas where high backflow rate gas wells may occur and developing corresponding drainage and production methods in advance. [ABSTRACT FROM AUTHOR]

Water content plays a significant role in the dynamic mechanical properties of rocks in hydraulic, deep underground, and mining engineering. However, the previous study generally concentrated on the oven-dried and water-saturated rock with spherical pores. Therefore, this study aims to investigate the impact of different water saturation levels and microstructure on the dynamic mechanical properties of artificial porous rock (APR) with multi cracks. The specimens with six water saturation levels (100%, 80%, 60%, 40%, 20%, and 0%) were tested under various loading rates using a split Hopkinson pressure bar (SHPB). The obtained results include the typical failure modes, stress–strain curves, dynamic uniaxial compressive strength (DUCS), fragmentation performance, and energy dissipation. The findings indicate that the DUCSs of unsaturated specimens initially increase with water saturation (20% ~ 80%) but subsequently decrease to the lowest value under fully saturated conditions. The dissipated energies of wet specimens are higher than that of dry specimens. Moreover, the dry specimen is prone to fail in a rock burst pattern, whereas the wet specimens exhibit a pulverization pattern. In addition, the corresponding water-effect mechanisms are discussed based on the microstructure of the APR. [ABSTRACT FROM AUTHOR]

Cross-formational water flow has the potential to significantly impact the economic feasibility and efficiency of coalbed methane (CBM) production, making it necessary to examine its effects on reservoir parameters such as cleat porosity and gas and water relative permeability curves, as well as total gas and water in place. To assess the extent of hydraulic connectivity and its consequences, well logs or zone isolation tests should be utilized to confirm hydraulic interaction in areas where cross-flow is suspected. This study discovered that high water saturation caused by hydraulic connections delays the peak of gas production. The results further indicate that there are significant differences between the relative permeability plots obtained from simulated production data and the initial relative permeability plots when cross-flow occurs. These findings have crucial implications for methane management in mining. The total water in place ranged from 40227 to 79428 STB, and the total gas in place ranged from 4.5 x 108 to 5.3 x 108 SFC/ton for the cases analyzed. Therefore, this paper's findings could aid in determining the hydraulic connection between coal beds and surrounding formations, as well as the influence of cross-formational flow on reservoir parameters obtained from Production Data Analysis (PDA). [ABSTRACT FROM AUTHOR]

Shale porosity measurements have crucial scientific and economical applications in unconventional petroleum systems. As a standard technique, liquid saturation methods, including water saturation (WS) and oil saturation (OS), have been widely used to measure the porosity of many rock types. For clay-rich shale reservoirs with high organic matter content, it is well known that the WS method may cause clay swelling and induce structural changes in the pore system. The OS method affects the accuracy of porosity measurements because of some of the oil being dissolved by kerogen within the shale; however, this has not received sufficient research attention. In this study, we compare the previously reported and newly tested OS porosities with helium (He) expansion porosity. Results show that OS porosity generally exceeds the He porosity. Furthermore, the higher the total organic carbon (TOC) content and lower the maturity of shale, the greater the difference between the OS and helium porosities. When using the OS method, the effect of kerogen-dissolved oil causes an overestimation of the shale porosity by ∼30%. To the best of our knowledge, this is the first time to note the kerogen-dissolve oil effects on OS porosity. Herein, we propose a new, simple, and effective correction method for estimating OS porosity that involves subtracting the kerogen-dissolved oil content from raw OS porosity. In addition, the quantification model of kerogen-dissolved oil capacity is established, taking into account the abundance and maturity of organic matter. Taking the He porosity as the benchmark, the absolute error of the corrected OS porosity does not exceed 1% and the average relative error is only ∼10%. The obtained results can help improve the accuracy of shale porosity evaluation methods. [ABSTRACT FROM AUTHOR]

Based on the parallel rock samples of tight oil reservoirs, the imbibition comparison experiments respecting to formation water and active water under different experimental conditions have been initiated. With adoption of the experimental measures i.e. Nuclear Magnetic Resonance (NMR), the micro-production mechanism of the enforcement of the imbibition oil recovery effect by the active agent has been analyzed. Surfactant may promote the imbibition effect of samples with different wettability, different water saturation and different sizes. The imbibition recovery ratios of No. 1 hydrophilic core in formation water and active water are respective 15.79% and 17.68%, and the active water imbibition increased by 1.88%, with an enforcement ratio of 11.97%. The imbibition recovery ratios of No. 3 lipophilic core in formation water and active water are respective 10.64% and 13.26%, and the active water imbibition increased by 2.62%, with an enforcement ratio of​ 24.62%. The enforcement effect of surfactant on the lipophilic core is higher than that on the hydrophilic core. The enforcement ratio of No. 1 core in macropores is 8.78%, and that of No. 3 rock is 36.14%, indicating that the surfactant can effectively reduce the seepage resistance of the lipophilic cores and enhance the imbibition recovery ratio of macropores. The increase magnitude and the enforcement ratio of the imbibition recovery of No. 4 low water-contained core are lower than those of No. 6 high water-contained core, indicating that the surfactant has a greater impact on the imbibition of high water-contained cores. The enforcement ratio in active water imbibition in core No. 4 is 28.59% in micropores and 15.46% in macropores; and respective 1460.74% and 9.56% for No. 6 core. The enforcement ratios of micropores in the two cores are both higher than those in macropores. It shows that the surfactant has a great influence on the permeability of micropores in the core. The increment magnitude in active water imbibition of small No. 2 core is 22%, and that of No. 2 large core is 26.93%, indicating that the surfactant has a greater impact on the imbibition of large cores.

Objective The results of laboratory tests on the electrical resistivity of sand are widely used in the interpretation of field electrical resistivity tomography. However, the influences of testing conditions and the field implementations of relationship curves between the electrical resistivity and properties of sand need further research. Methods First, the electrical resistivity test device was developed by using the two-electrode method. Then, the influences of current type, alternating current (AC) frequency, voltage and grain size of sand on the relationship between electrical resistivity and water saturation (ρ-Sr), as well as electrical resistivity and salinity of the pore water (ρ-n), were studied. Results The results showed that an AC current frequency of 10 Hz and an input voltage of 1 V were recommended to reduce the test error of resistance. There was a power function between the electrical resistivity and water saturation (ρ-Sr), as well as electrical resistivity and salinity of pore water (ρ-n), under AC and direct current (DC). As DC might cause an electrolysis reaction of the electrodes of the sand column under the high salinity of pore water, the AC electrical method was suggested. When the water saturation is greater than 50%, the electrical resistivity difference caused by the grain size of sand becomes small. Moreover, the electrical resistivity did not decrease significantly with increasing water saturation, which suggested that a relatively stable interface of the electrical resistivity might exist in the unsaturated zone with 50% saturation rather than in the water table. When the salinity of pore water is greater than 2 g/L, the electrical resistivity of all five types of saturated sands did not decrease obviously with increasing salinity. Conclusion Research results comfirm the electrical resistivity method easily distinguishes fresh water from brackish water but has difficulty further subdividing brackish water, salt water and brine.

In order to explore the relative permeability characteristics of gas-water in the crushed coal rock mass around the drilling hole of gas extraction, the gas-water coupling permeation test system of the crushed rock mass was used to carry out the gas-water coupling permeation test by using the steady-state osmosis method, and the variation characteristics of the coal sample permeability parameters with osmotic pressure and axial pressure were obtained, and the interaction relationship between the permeation parameters was analyzed. The results show that the porosity of the crushed coal mass under pressure shows a rapid decline, a slow decline and stabilization with the increase of axial pressure. With the increase of water saturation, the relative permeability of coal-like gases decreases rapidly, the relative permeability of water increases linearly, the relative permeability of gases and water shows a competitive relationship, and the sensitivity of gas permeability to water saturation is higher. The total permeability of gas and water decreases with the increase of the effective force, obeying the exponential function relationship, the effective force will affect the deformation process of the pore structure of the crushed coal rock mass, and with the decrease of porosity, the effective permeability of the gas decreases and the relative permeability increases. The influence of osmotic pressure on the relative permeability of water and gas can be divided into gas dominant stage, isotonic stage and water dominant stage, and the critical osmotic pressure extraction value ranges from 0.4 MPa to 0.6 MPa.

In the calculation of shale gas resources/reserves, isothermal adsorption parameters are mainly determined by dry sample data at the laboratory temperature, and the regression effect of total organic carbon content (TOC) isothermal adsorption parameters is poor. Based on the physical significance of key parameters in Langmuir and Henry adsorption models, the problems in determining the isothermal adsorption parameters in the calculation of shale gas reserves/reserves are analyzed by taking the marine shale in the Upper Ordovician Wufeng Forming–Lower Silurian Longmaxi Formation in the Sichuan Basin as an example. Based on a large number of measured isothermal adsorption data, the effects of TOC, temperature and water saturation on the shale gas adsorption parameters are analyzed. The influence model of TOC, temperature and water saturation on isothermal adsorption parameters of shale gas is established, and a novel method for calculating the adsorption parameters of shale gas from under experimental conditions to original reservoir conditions is proposed. The results are obtained as follows. First, there are problems in the calculation of shale gas resources/reserves, such as poor and contradictory fitting relation between isothermal adsorption parameters and TOC, difficulty in the conversion of Van't Hoff equation, and difficulty in direct application of water saturation (Sw) in resource/reserves calculation. Second, the problem of poor direct fitting relation between Langmuir pressure (pL) and TOC is solved by integrating the Langmuir adsorption model with the Henry adsorption model and by establishing a new parameter – Henry constant a for methane adsorption capacity of shale. Third, when Sw30 MPa), the effect of Sw on the methane adsorption capacity of shale shows a similar trend, and the effect of water molecules on the adsorption capacity on shale pore surface is constant. It is concluded that the proposed novel method for determining the isothermal adsorption parameters of shale with different TOC, temperature and water saturation conditions provides a technical support for the accurate calculation of shale gas resources/reserves and contributes to the scientific development of shale gas industry.

Foam flooding by Foam Assisted Water-Alternating-Gas (FAWAG) is an important enhanced oil recovery method that has proven successful in experimental and pilot studies. The present study is carried out to monitor the movement of the foam front once injected into the porous medium. This study aims to investigate applications of resistivity waves to monitor foam propagation in a sandstone formation. In the present lab-scale experiments and simulations, resistivity measurements were carried out to monitor the progression of foam in a sand pack, and the relationships between foam injection time and resistivity, as well as brine saturation, were studied. The brine saturation from foam simulation using CMG STAR is exported to COMSOL and calculated true formation resistivity. A diagram was produced summarizing the progression of foam through the sand pack in the function of time, which enabled us to establish how foam progressed through a porous medium. A surfactant and brine mixture was injected into the sand pack, followed by nitrogen gas to generate the foam in situ. As foam progressed through the sand pack, resistance measurements were taken in three zones of the sand pack. The resistance was then converted into resistivity and finally into brine saturation. As foam travels through the sand pack, it is predicted to displace the brine initially in place. This gradually increases each zone's resistivity (decreases the brine saturation) by displacing the brine. Also, an increase in the surfactant concentration results in higher resistivity. Finally, a comparison of three different surfactant concentrations was evaluated in terms of resistivity results, water saturation, and foam propagation monitoring to obtain the optimum surfactant concentration involved in foam flooding.

In the Changning block of the southern Sichuan Basin, the shale gas wells in the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation (Wufeng–Longmaxi) demonstrate significant difference in flowback rate of fracturing fluid, given the same fracturing scale and production time. Based on the P90 curve of flowback rate with time, wells with high flowback rates in this area are categorized, and they are generally defined with the 100-day flowback rate of >40%, the 200-day flowback rate of >50%, and the first-year flowback rate >60%. Through comprehensive research on the geological characteristics of the Changning block, the geological factors that cause high gas well backflow rates have been identified. The results are obtained in four aspects. First, gas wells with high flowback rates generally show higher flow rates for smaller distances to the fault, and the NE faults formed during the late Yanshanian to early Himalayan and with fault throw >200 m have the greatest impact on the flowback rate. Second, plane heterogeneity of water saturation contributes to the high flowback rate of some wells. Third, the proportion of the Middle Ordovician Baota Formation in the horizontal section of wells is positively related to the flowback rate, and the drilling and fracturing of the Baota limestone with high water content can lead to high flowback rates of gas wells to some extent. Fourth, unidirectional linear natural fractures between wells can easily cause inter-well frac-hit, leading to high flowback rates of gas wells. In conclusion, the research results are helpful in predicting areas where high backflow rate gas wells may occur and developing corresponding drainage and production methods in advance.

Due to the high water saturation in high-water-cut tight sandstone gas reservoirs, factors such as threshold pressure gradient (TPG) and stress sensitivity (SS) cannot be overlooked in terms of their impact on seepage parameters. Therefore, this paper primarily investigates the seepage mechanisms in tight, high-water-cut sandstone gas reservoirs. While considering the influence of water saturation on various seepage mechanisms, it establishes a gas well productivity equation under stable seepage conditions and presents an analysis of the influencing factors. In a comparison of the unobstructed flow rates calculated using the productivity equation developed in this paper with those obtained from conventional gas well productivity equations and actual gas well productivity tests, the new equation demonstrates smaller errors. This provides a theoretical basis for evaluating productivity and making rational production allocation decisions in high-water-cut tight sandstone gas reservoirs. [ABSTRACT FROM AUTHOR]

Coal resources are often subjected to the combined effects of stress fields and seepage fields during the mining process. Therefore, studying the micro-mechanics and strength softening laws of coal specimens under water saturation in deep mining has important practical significance. This article is based on experimental research conducted on coal specimens from the Wanfu Coal Mine in Shandong Province. The following conclusions were drawn: (1) The peak value of the T2 spectrum amplitude of the coal specimens presented a three-peak shape with increasing immersion time, indicating the generation and development of new pore structures. The spectrum area was positively correlated with the mass increment and satisfied three water absorption stages. (2) A relationship curve was established between stress, pore structure, and water absorption time of coal specimens, and the critical points of two water saturation during the process of coal specimen strength softening were determined to be 22.51% and 81.29%, respectively, according to the relationship between the three. (3) Based on changes in the coal specimens' pore structure and mineral composition with increasing immersion time, a microscopic pore structure model of coal specimens' water absorption was established. (4) The vibration counts of coal specimens under different water saturation exhibited multiple fractal characteristics. By analyzing the parameters of the multifractal spectrum, it was concluded that the secondary expansion of primary cracks was the main type of failure during the process of coal specimen destruction. [ABSTRACT FROM AUTHOR]

This study investigated the impact of formation water on the mass transfer between CO2 and crude oil in low-permeability reservoirs through CO2 miscible flooding. Formation water leads to water blocks, which affect the effectiveness of CO2 miscible flooding. Therefore, we studied the impact and mechanisms of formation water on the CO2-oil miscibility. The microscale interaction between formation water-CO2-core samples was investigated using CT scanning technology to analyze its influence on core permeability parameters. In addition, CO2 miscible flooding experiments were conducted using the core displacement method to determine the effects of formation water salinity and average water saturation on minimum miscibility pressure (MMP) and oil displacement efficiency. The CT scanning results indicate that high-salinity formation water leads to a decrease in the porosity and permeability of the core as well as pore and throat sizes under miscible pressure conditions. The experimental results of CO2 miscible flooding demonstrate that CO2-oil MMP decreases as the salinity of the formation water increases. Moreover, as the average water saturation in the core increases, the water block effect strengthens, resulting in an increase in MMP. The recovery factors of cores with average water saturations of 30%, 45%, and 60% are 89.8%, 88.6%, and 87.5%, respectively, indicating that the water block effect lowers the oil displacement efficiency and miscibility. [ABSTRACT FROM AUTHOR]

Improving the durability of asphalt concrete road surfaces by increasing their moisture resistance is an urgent task. Modified bituminous binders should be compacted into coatings with the lowest possible water saturation. The purpose of this study was to establish the effect of modifiers on the hydrophobicity of bituminous films in order to achieve minimum water saturation and to build a mathematical model of the wetting process with water. As modifiers, we used a product of amination of distillation residues of petrochemistry, waste sealing liquid (a solution of high molecular weight polyisobutylene in mineral oil), and a condensation product of polyamines and higher fatty acids. The water-repellent effect of modifiers was studied by measuring the contact angle of bituminous film with a water drop. The water saturation of asphalt concrete samples was determined by the amount of water absorbed by asphalt concrete at 20 °C. A close correlation was revealed between the hydrophobicity of modified bitumen and the water saturation of asphalt concrete. Generalized equations and a graphical representation of a function of several variables allowed for optimizing compositions by the content of modifiers to achieve the required performance properties of asphalt concrete coatings. [ABSTRACT FROM AUTHOR]

Abstract The main objective of net pay determination, as an important step of any reservoir study, is to exclude non-reservoir intervals so that better results are obtained from reservoir characterization, hydrocarbon in-place calculations, and dynamic flow simulation of the reservoir. This study is a comprehensive presentation of the most applicable methods available for net pay determination, highlighting their strengths, limitations, and their input data, and presenting a new procedure to prepare the input data, determine the reservoir net pay, and validate the final results. These methods include conventional best-fit line and quadrant methods in a porosity–permeability cross-plot, Worthington method, rules of thumb, cumulative hydrocarbon column plot, and production constraints. This study, unlike previous ones, presents a stepwise methodology to reach the correct answer considering both rock and fluid properties. The necessity for the definition of net pay is discussed in the current study in the first step. Determination of net pay and the net-to-gross ratio is done by definition of some cut-off values for petrophysical properties such as porosity, water saturation, and shale volume. The new procedure presented in this study as a flowchart to determine pay zone uses different methods to determine cut-off values. The sequential and systematic use of all these methods gives a consistent and more reliable answer. The key steps to determine net pay is to find the porosity cut-off based on a porosity–permeability cross-plot and a pre-defined limiting value for permeability and then to use this value to find the shale volume and water saturation cut-offs using their cross-plots versus porosity. To take into account the fluid properties effect, a mobility cut-off is used as the starting point instead of permeability. Cumulative hydrocarbon column plots are used as a sensitivity tool to determine what percentage of the hydrocarbons will be discarded by any cut-off value. Finally, the determined net pay should be validated using the results of production logging and wireline formation tests. The proposed methodology was applied to a real field to determine its net pay. Porosity and water saturation cut-offs were calculated to be 2% and 55%, respectively, and due to the clean nature of the reservoir, a shale volume cut-off was not necessary. Simultaneous application of porosity and water saturation cut-offs discarded 6.3% of the hydrocarbon column for the field example.

The conventional Archie formula struggles with the interpretation of water saturation from resistivity well log data due to the increasing complexity of exploration targets. This challenge has prompted researchers to explore alternative physical parameters, such as acoustic characteristics, for breakthroughs. Clarifying the influencing factors of porous media acoustic characteristics is one of the most important approaches to help understanding the mechanism of acoustic characteristics of carbonate reservoirs. The article uses digital rock technology to characterize the pore structure, quantitatively identify fractures and pore structures in carbonate rocks, and establish digital models. Through conventional acoustic testing, the pressure wave (P-wave) and shear wave (S-wave) velocities of rock samples at different water saturations are obtained, and the dynamic elastic modulus is calculated. A finite element calculation model is established using the digital rock computational model to provide a basis for fluid saturation calculation methods. Based on real digital rock models, different combinations of virtual fractures are constructed, and factors affecting acoustic parameters are analyzed. The study finds that as porosity increases, the velocity difference between porous cores and fractured cores also increases. These findings provide important technical support and a theoretical basis for interpreting acoustic well logging data and evaluating carbonate reservoirs with different pore and fracture types.

Link for citation: Potekhin D.V., Shiryaev E.O., Galkin S.V. 3D-modeling technology of initial oil saturation in transitional oil-water zone by complex of capillarimetry and electric logging methods. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 10, рр. 98-107. In Rus. The relevance. The 3D distribution of the initial oil saturation in the reservoir volume is one of the key elements of geological and technological modeling, largely determining the quality of subsequent development design solutions. The publication presents an analysis of the current state of the problem of studying the oil-water transition zone and the distribution of oil saturation. For terrigenous hydrophilic reservoirs, electric lateral logging quite reliably controls the fluid saturation of the void space of the oil part of the deposit, which suggests the possibility of its integration with widely used capillarimetry methods. Aim: to evaluate the possibility of reliably determining the oil saturation of terrigenous hydrophilic reservoirs by combining the data of electrical lateral logging, filtration-capacitance properties of reservoirs and capillarimetric core studies, to build a 3D model of the distribution of the initial oil saturation of reservoirs in oil deposits, taking into account the allocation of the oil-water transition zone. Object: oil-saturated reservoirs of the Visean oil deposits of the Perm region. Method: methods of multidimensional mathematical modeling in the development of a methodology for determining the initial oil saturation of reservoirs based on a complex of well logging and capillarimetric studies of the core, construction of 3D distribution of the initial oil saturation of the reservoir, taking into account the parameters of the oil-water transition zone. Results. The authors, based on the developed methodology for the deposit of the reservoir Bb of the Aspinskoe field, built a 3D model of the distribution of the initial oil saturation. For the studied reservoir, they carried out the analysis of distribution of zones of free saturation, undersaturation, transition zone and limiting oil saturation. The resulting 3D model can be used in geological and technological modeling of the development of an oil deposit.

The nutrient-limiting conditions in saline–alkali soil as well as the salinity and alkalinity stress are successfully alleviated by water management measures and the addition of organic matter. However, the impacts of these two strategies on the microbe-driven CO2 emissions in saline–alkaline soils are not yet clear. Therefore, a 150-day incubation experiment was conducted in this study to evaluate the short-term effects of water regulation and the addition of organic matter with different characteristics on CO2 emissions and microbial community characteristics in saline–alkali soils under non-flooding conditions. This study was conducted at two water saturations, i.e., 50% WFPS and 80% WFPS. In addition, five organic matter treatments were conducted: CK: control; N: urea; SN: Straw + urea; SNH: Straw + urea + microbial agent; and SNB: Straw + urea + biochar. The results demonstrated that compared with 50% WFPS, 80% WFPS significantly increased cumulative CO2 emission by 27.66%, but significantly decreased salt content and the fungal Chao1 and Shannon indices. The application of the biochar and microbial agent decreased the cumulative CO2 emissions of the SN treatment by 27.39% and 14.92%, respectively. When sufficient carbon supply is available, the decrease in fungal diversity may reduce CO2 emission. The findings demonstrated that SNH and SNB at 80% WFPS might decrease CO2 emissions under straw carbon intake as well as the loss of labile organic carbon (LOC). Additionally, these treatments can alleviate microbial stress caused by salinity, which has a favorable impact on enhancing carbon storage in salinity-affected dryland soils. [ABSTRACT FROM AUTHOR]

Water has a significant impact on the dielectric constant of materials. As a multiphase composite material, the effect of water content must be taken into account when modeling the composite dielectric of cement concrete. Cement concrete traditionally has been thought of as a three-phase mixed material consisting of mortar, aggregate (limestone), and pores (air). Water was used as a constituent material of cement concrete in this paper, and its content was described in terms of water saturation. By abstracting the components of cement concrete into independent medium units and arranging them according to certain rules, the four-phase mixing model of cement concrete can be established. To investigate the effect of water, the dielectric constant of cement concrete was measured using a network analyzer at various water saturation levels. The experimental results show that water significantly can enhance the dielectric constant of cement concrete, and this effect is related to porosity: the higher the water saturation, the faster the dielectric constant increases. According to the established concrete four-phase mixed model, combined with the parallel plate capacitor theory, a composite dielectric model considering water saturation was developed which can improve the prediction accuracy under different water saturation conditions and provide a foundation for the application of ground-penetrating radar (GPR) in the quality inspection of cement concrete pavement. [ABSTRACT FROM AUTHOR]

The main objective of net pay determination, as an important step of any reservoir study, is to exclude non-reservoir intervals so that better results are obtained from reservoir characterization, hydrocarbon in-place calculations, and dynamic flow simulation of the reservoir. This study is a comprehensive presentation of the most applicable methods available for net pay determination, highlighting their strengths, limitations, and their input data, and presenting a new procedure to prepare the input data, determine the reservoir net pay, and validate the final results. These methods include conventional best-fit line and quadrant methods in a porosity–permeability cross-plot, Worthington method, rules of thumb, cumulative hydrocarbon column plot, and production constraints. This study, unlike previous ones, presents a stepwise methodology to reach the correct answer considering both rock and fluid properties. The necessity for the definition of net pay is discussed in the current study in the first step. Determination of net pay and the net-to-gross ratio is done by definition of some cut-off values for petrophysical properties such as porosity, water saturation, and shale volume. The new procedure presented in this study as a flowchart to determine pay zone uses different methods to determine cut-off values. The sequential and systematic use of all these methods gives a consistent and more reliable answer. The key steps to determine net pay is to find the porosity cut-off based on a porosity–permeability cross-plot and a pre-defined limiting value for permeability and then to use this value to find the shale volume and water saturation cut-offs using their cross-plots versus porosity. To take into account the fluid properties effect, a mobility cut-off is used as the starting point instead of permeability. Cumulative hydrocarbon column plots are used as a sensitivity tool to determine what percentage of the hydrocarbons will be discarded by any cut-off value. Finally, the determined net pay should be validated using the results of production logging and wireline formation tests. The proposed methodology was applied to a real field to determine its net pay. Porosity and water saturation cut-offs were calculated to be 2% and 55%, respectively, and due to the clean nature of the reservoir, a shale volume cut-off was not necessary. Simultaneous application of porosity and water saturation cut-offs discarded 6.3% of the hydrocarbon column for the field example. [ABSTRACT FROM AUTHOR]

Many studies investigate the effects of increased water content on the strength parameters of rocks. However, there is no study on the effects of water saturation on the crushability of rocks. While rock samples fail under static loading in strength tests, there are dynamic loads in the crushing process. Therefore, the effects of water saturation on the crushability of rocks cannot be expected to be the same as its effects on the other strength parameters. In this study, the effects of water saturation on the crushability of rocks in three different size ranges were investigated for nine different rock samples. First, rocks' physical-mechanical properties and brittleness indices were determined in dry and saturated conditions. Then, to determine the crushability indices (CI) and particle sizes (d50 and d80), test rocks were prepared in three different size ranges. All test rocks were crushed by a jaw crusher, respectively, and CI, d50, and d80 values were determined. The relationships between the strength parameters, brittleness indices, CI, and particle sizes of rocks obtained in dry and saturated conditions were statistically analyzed. The results revealed that the effects of water saturation on the crushability of rocks are different from its effects on the other mechanical behaviors of rocks. On the other hand, it was observed that the effect of water saturation is not the same in all size ranges, and although the crushability of rocks in the medium and fine size range increased, that of the rocks in the coarse size range decreased. [ABSTRACT FROM AUTHOR]

Copyright of Iraqi Journal of Chemical & Petroleum Engineering is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Abstract In the present study, seasonal autoregressive integrated moving average (SARIMA) time series models, nonlinear BL model, multi-layer perceptron artificial neural network and SARIMA-bilinear hybrid models were employed to predict the quality parameters of total dissolved solids (TDS), sodium adsorption ratio (SAR), electrical conductivity (EC) in the Maroon basin in Khuzestan Province. For fitting the mentioned models, the monthly data were used for the calibration (1970–2000), confirmation (2001–2011) and prediction of the model (2012–2018). The appropriate models of SARIMA, the bilinear BL and SARIMA-BL hybrid models of the rationalized parameters of the above-mentioned quality parameters were selected based on the adequacy tests, such as the Akaike criterion and the independence test of the model residuals (Ljung–Box). To determine the effective input parameters of the network, the partial mutual information (PMI) algorithm was used to model the three monthly EC, TDS, and SAR parameters. Also, for input and output layers linear transfer function and for hidden layer various active functions with the back-propagation learning algorithm were used for modeling and predicting this water quality parameters. Comparison of the models showed the tangible superiority of SARIMA-bilinear hybrid models than the artificial neural network with effective input parameters based on PMI algorithm, SARIMA and bl models in performed prediction of the all three monthly qualitative parameters in all three stages, training-validation-test in Maroon basin.

Abstract The spontaneous imbibition (SI) process in shale oil reservoirs is not only influenced by capillary force, but also by the osmotic pressure between the fracturing fluid and formation water in the nanopores media. In this study, experimental methods are used to investigate the mechanisms of osmosis in the SI, taking into account the presence of initial formation water in shale oil reservoirs. To investigate the effect of osmosis, SI experiments were performed on the fine-grained felsic shale of the Qikou sag of Dagang oilfield. Low-field NMR testers and high-precision electronic balances are utilized for the measuring of oil–water migration. The results show that, when S w ≠ 0, high-salinity fluid SI can be divided into four stages: initial imbibition stage, drainage stage, secondary imbibition stage and stationary stage; when S w = 0, there is no drainage stage of high-salinity fluid SI; when S w ≠ 0 or S w = 0, low-salinity fluid SI can be called the “osmosis-enhanced SI”; and we have found that “newly formed pores or microfractures” as well as reducing salinity can promote SI. This article presents a systematic study of SI of shale oil reservoirs under the influence of osmosis, which provide useful information for reservoir numerical simulation and development program design.

Copyright of Coal Geology & Exploration is the property of Xian Research Institute of China Coal Research Institute and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In addition to the temperature and pressure conditions, the pore fluid composition and migration behavior are also crucial to control hydrate decomposition in the exploitation process. In this work, to investigate the effects of these factors, a series of depressurization experiments were carried out in a visible one-dimensional reactor, using hydrate reservoir samples with water saturations ranging from 20% to 65%. The results showed a linear relationship between gas production rates and gas saturations of the reservoir, suggesting that a larger gas-phase space was conducive to hydrate decomposition and gas outflow. Therefore, the rapid water production in the early stage of hydrate exploitation could release more gas-phase space in the water-rich reservoir, which in turn improved the gas production efficiency. Meanwhile, the spatiotemporal evolution of pore fluids could lead to partial accelerated decomposition or secondary formation of hydrates. In the unsealed reservoir, the peripheral water infiltration kept reservoir at a high water saturation, which hindered the overall production process and caused higher water production. Importantly, depressurization assisted with the N2 sweep could displace the pore water rapidly. According to the results, it is recommended that using the short-term N2 sweep as an auxiliary means in the early stage of depressurization to expand the gas-phase space in order to achieve the highest production efficiency. [ABSTRACT FROM AUTHOR]

The study of petrophysical parameters plays a major role in the evaluation of hydrocarbon reservoirs. In this study, using well data in Geolog software, the petrophysical parameters of the Arab Formation (equivalent to Surmeh) in one of the oil fields in southern Iran were studied in two ways. Based on the petrophysical evaluation and using conventional cross-plots (neutron-density) and histogram of porosity and water saturation, the lithology of the Arab Formation was determined. The lithology consists of a combination of calcite, dolomite, and anhydrite. Comparison of the results of porosity changes is more consistent with the values obtained from core analysis. According to the calculated petrophysical properties, the upper part of the Arab (Surmeh) Formation was divided into seven parts. Comparison of water saturation showed that in all zones, the range of changes is high. By comparing the zones quality, zones 5 and 6 are introduced as the best reservoir zones. [ABSTRACT FROM AUTHOR]

The effect of the influence regularity of site saturation and water level on the coherency loss between spatially varying earthquake ground motions (SVEGMs) in a vertical direction is not yet clear. Therefore, taking an onshore-offshore site as an example, the influence regularity of site saturation and water level on the coherency loss of SVEGMs in a vertical direction was studied, in which the saturation degree of the whole site (SD), the groundwater level (GWL), and the thickness of the surface water layer (WLT) were considered. Under each case mentioned above, a large number of vertical in-plane SVEGMs were synthesized and then correspondingly, the mean lagged coherency loss and phase angle of coherence function were obtained, and a series of comparisons were carried out to shed light on the varying trend of the value of lagged coherency loss and phase angle, with predefined parameters. The results showed that SD, GWL, and WLT possess significant effects on the varying trend of the coherence function of vertical SVEGMs. [ABSTRACT FROM AUTHOR]