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Proton Exchange Membrane Fuel Cell (PEMFC) technology has been receiving more attention recently and can play a more expanded role in space missions with low gravity or microgravity. The liquid water generation in the Gas Diffusion Layer (GDL) of a Proton Exchange Membrane Fuel Cell (PEMFC) increases the resistance to oxygen flow toward the catalyst layer. Water flooding inside the GDL can affect the PEMFC performance especially at higher current densities. Therefore, a good understanding of the effect of liquid water amount in the GDL is crucial to water management and, subsequently, to the performance of the fuel cell. The purpose of the present study is to investigate the effect of the microstructure characteristics of the GDL on the water flooding and liquid water distribution inside the GDL. A one-dimensional theoretical model has been developed. Results indicate that the porosity gradient has a significant effect on the liquid water saturation and the performance of the PEM fuel cell. [ABSTRACT FROM AUTHOR]

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Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency 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.)

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing 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.)

Water-flooding reservoirs are the mainstay in developing mature oilfields in eastern China， and they have entered the ultra-high water cut stage as a whole after long-term water injection development. Laboratory studies and field practice show that there is still potential for significantly enhancing oil recovery. However， the difficulty of scientific and efficient development has increased due to the heterogeneity of reservoirs and development dynamics， and further research is needed to enhance oil recovery technology. Uncompartmentalized reservoirs face challenges such as severe extreme water consumption in the later stage of ultra-high water cut， affecting stable production and enhanced oil recovery through water flooding. Therefore， the theory of high water consumption zones was deepened， and the development technology of near-resistance layer recombination， the vector development technology of ultra-high water cut reservoirs， and the development technology of flow field adjustment in the later stage of ultra-high water cut were developed through innovation， achieving water consumption control and reduction， with an average oil recovery of 43.7%. In response to the characteristics of fault block reservoirs with numerous faults and small fault blocks， as well as the challenges of small remaining oil reserves and difficult exploitation during the ultra-high water-cut stage， understanding of the accumulation patterns of remaining oil and hydrodynamic regulation mechanisms was deepened. A series of leading development technologies were developed through innovation， such as artificial peripheral water flooding and stereoscopic development， improving reserve control and water flooding efficiency， with an average oil recovery of 29.4%. These technologies have supported the stable and profitable production of fault block reservoirs. Given the poor physical properties of low-permeability reservoirs and the difficulty of effective water flooding， nonlinear flow mechanisms and pressure flooding development mechanisms were researched， supporting development technologies were formed， and the development limits were constantly broadened. A series of differential development technologies have been innovated， such as water injection of simulated horizontal wells in ultra-low permeability reservoirs， well pattern adaptation for enhanced oil recovery in general low-permeability reservoirs， and pressure flooding in low-permeability and tight reservoirs， with an average oil recovery of 15.7%， realizing rapid and efficient development of low-permeability reservoirs. Through the above technical research， the efficient development of water-flooding reservoirs in ultra-high water cut stage is realized. According to the development characteristics and situation of different types of reservoirs， the directions for further enhancing oil recovery of water-flooding reservoirs are being put forward.

Enhancing oil recovery from clayey reservoirs is a significant challenge in petroleum industry due to complex interactions between fluids and rock surfaces, particularly clay swelling. This study presents the first empirical analysis of magnetic fields' impact on fluid flow in clayey porous media. Our core findings indicate that magnetic treatment of water increases oil recovery by an average of 15–30% in clayey media, with limited effectiveness in pure quartz media. Detailed experiments unraveled that improved recovery factor by magnetic treatment stem from both mitigated swelling and altered magnetic properties at clay surface; introducing 30% clay to porous medium decreased the recovery by 32% compared to pure quartz sand. Heating the clay to around 1000 °C to reduce its swelling property improved the recovery by only 16%, suggesting magnetic treatment is not solely attributed to clay swelling mitigation. Treating ferromagnetic films at clay surface with HCl to produce non-magnetic FeCl3 resulted in a high recovery factor, similar to the clay-free medium. Moreover, it was determined that a magnetic field intensity of 43760–51740 A/m is optimal for fluid displacement in clayey media. Notably, the intensity of 47760 A/m increased recovery to 84.5% in a 30% clay medium, compared to 49.7% without treatment. Interestingly, it was observed that the maximum flow rate was associated with zero potential difference across the medium, providing a faster method to determine the optimum magnetic field intensity. Lastly, the concept of ‘Magnetic memory’ was investigated, referring to the persistence of magnetic field's influence after its removal. Our findings indicated that pressure build-up time stability lasted 10 days post-treatment, after which water behavior reverts, and clay swelling resumes. This insight into the temporal dynamics of magnetic field application provides a deeper understanding of its long-term impacts on fluid flow in clayey reservoirs.

Offshore oil reservoirs are characterized by loose and heterogeneous strata, high injection-production intensity, and easy water breakthrough along advantageous permeability channels, which can significantly affect development efficiency. The oil reservoir extraction process to an interconnected network of injection were simplified and production wells and developed a novel quantitative identification model for advantageous channels based on inter-well connectivity units. By coupling with a dynamic automatic history matching algorithm, the characteristic parameters of advantageous channels can be obtained directly, accurately and rapidly. Furthermore, a comprehensive evaluation factor of cross-flow intensity was introduced to provide a new method for the classification and characterization of heterogeneous offshore oil reservoirs. Actual field applications show that large channels and advantageous channels can be quickly and accurately identified and predicted, including the vertical development layers, the planar development directions, and the development intensities. Timely guidance for targeted management of low-efficiency cOffshore oil reservoirs are characterized by loose and heterogeneous strata, high injection-production intensity, and easy water breakthrough along advantageous permeability channels, which can significantly affect development efficiency. The oil reservoir extraction process to an interconnected network of injection were simplified and production wells and developed a novel quantitative identification model for advantageous channels based on inter-well connectivity units. By coupling with a dynamic automatic history matching algorithm, the characteristic parameters of advantageous channels can be obtained directly, accurately and rapidly. Furthermore, a comprehensive evaluation factor of cross-flow intensity was introduced to provide a new method for the classification and characterization of heterogeneous offshore oil reservoirs. Actual field applications show that large channels and advantageous channels can be quickly and accurately identified and predicted, including the vertical development layers, the planar development directions, and the development intensities. Timely guidance for targeted management of low-efficiency channels and sustained high-efficiency development are provided by this method in oil fields.hannels and sustained high-efficiency development are provided by this method in oil fields. [ABSTRACT FROM AUTHOR]

Simulation of subsurface energy system involves multi-physical processes such as thermal, hydraulical, and mechanical (THM) processes, and requires a so-called THM coupled modeling approach. THM coupled modeling is commonly performed in geothermal energy production. However, for hydrocarbon extraction, we need to consider multiphase flow additionally. In this paper, we describe a three-dimensional numerical model of nonisothermal two-phase flow in the deformable porous medium by integrating governing equations of two-phase mixture in the porous media flow in the reservoir. To account for inter-woven impacts in subsurface conditions, we introduced a temperature-dependent fluid viscosity and a fluid density along with a strain-dependent reservoir permeability. Subsequently, we performed numerical experiments of a ten-year water flooding process employing the open-source parallelized code, OpenGeoSys. We considered different well patterns with colder water injection in realistic scenarios. Our results demonstrate that our model can simulate complex interactions of temperature, pore pressure, subsurface stress and water saturation simultaneously to evaluate the recovery performance. High temperature can promote fluid flow while cold water injection under non-isothermal conditions causes the normal stress reduction by significant thermal stress. Under different well patterns the displacement efficiency will be changed by the relative location between injection and production wells. This finding has provided the important reference for fluid flow and induced stress evolution during hydrocarbon exploitation under the environment of large reservoir depth and high temperature. [ABSTRACT FROM AUTHOR]

The development of low-permeability oil and gas resources presents a significant challenge to traditional development methods. To address the problem of "no injection and no production" in low -permeability reservoirs, a novel fracture-injection-production integration technology named fracturing-flooding has been proposed by oilfield sites. This technology combines the advantages of conventional fracturing, water flooding, and chemical flooding, resulting in improved reservoir physical properties, increased injection, replenished energy, and increased oil displacement efficiency. The technology is especially suitable for low-permeability reservoirs that suffer from lack of energy, and strong heterogeneity. Fracturing-flooding technology has shown significant results and broad development prospects in some oilfields in China. This paper analyzes the development status of fracturing-flooding technology from its development history, technical mechanism, technical characteristics, process flow, types of fracturing and oil displacement fluids, and field applications. Physical and numerical simulations of fracturing- flooding technology are also summarized. The results suggest that fracturing-flooding technology is more effective than conventional fracturing, water flooding, and chemical flooding in stimulating lowpermeability tight reservoirs and improving oil recovery. Moreover, it has a high input-output ratio and can be utilized for future reservoir stimulation and transformation. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing 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.)

Waterflooding of hydrocarbon deposits is an urgent problem for the oil and gas industry of Ukraine. In the process of active inflow of both edge-water and bottom water into productive reservoirs, significant hydrocarbon reserves are trapped. This results in low final hydrocarbon recovery factors. The process of watering production wells is natural, but this process must be controlled. To improve the efficiency of development of natural gas fields with bottom water, additional research was conducted using digital modeling. Based on a 3D model, the influence of penetration ratio in gas and water bearing formations on ultimate gas recovery is investigated. For the calculations, the penetration ratio was taken as 20%, 40%, 60%, 80%, and 100%. According to the modeling results, a significant impact of the penetration ratio on the efficiency of hydrocarbon production was found. According to the studies, it was found that with an increase the penetration ratio, the duration of the period of waterless operation of wells decreases. It should be noted that the greater the penetration ratio, the lower the gas recovery factor at the time of the breakthrough of the bottom water to the perforation interval. In addition, according to the studies, it was found that the smaller the penetration ratio, the greater the height of the cone of bottom water, as well as the larger the base of the cone. At full reservoir penetration, there is practically no cone formation process. In this case, the bottom water immediately enters the lower perforations of the production well and thus complicates its operation. In the short term, the flowing process is stopped and the well is shut down due to the failure to ensure the conditions for the removal of the gas-liquid mixture from the bottom hole. Based on the results of the calculations, the optimal penetration ratio in gas condensate deposits with bottom water was determined. According to the statistical processing of the calculated data, the optimal penetration ratio is 60.6%. The results of the research are aimed at improving the theoretical understanding of cone formation processes and for practical application in the mining industry in the development of natural gas fields with bottom water.

Water flooding and pressure maintenance are recommended to improve oil recovery practices after low recovery of petroleum reservoirs occurs during primary production. Salt crystal formation is a frequent occurrence when using these techniques. Several experimental, numerical, and theoretical studies have been done on the mechanisms underlying scaling and permeability reduction in porous media; however, there has not been a satisfactory model developed. This study developed a phenomenological model to predict formation damage caused by salt deposition. Compared with existing models, which provide a scaling tendency, the proposed model predicts the profile of scale deposition. The salt precipitation model simulates reactive fluid flow through porous media. A thermodynamic, kinetic, and flow hydrodynamic model was developed and coupled with the ion transport equation to describe the movement of ions. Further, a set of carefully designed dynamic experiments were conducted and the data were compared with the model predictions. Model forecasts and experimental data were observed to have an average absolute error (AAE) ranging from 0.68% to 5.94%, which indicates the model's suitability.

Sweep efficiency of stagnant and poorly drained reservoir zones is extremely relevant task during gas and chemical flooding of hard-to-recover reserves. The paper presents the results of the field implementation of the in-situ CO2 generation technology to recovery of residual oil reserves and increase the sweep efficiency factor. The article presents the results of theoretical and laboratory studies, as well as field cases of an energy- and resource-saving method for oil recovery increase and improving oil production. The results of the reservoir stimulation confirmed the increase in the total incremental oil production after treatment operation on recovering residual oil reserves on. [ABSTRACT FROM AUTHOR]

Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office 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.)

Waterflooding of hydrocarbon deposits is an urgent problem for the oil and gas industry of Ukraine. In the process of active inflow of both edge-water and bottom water into productive reservoirs, significant hydrocarbon reserves are trapped. This results in low final hydrocarbon recovery factors. The process of watering production wells is natural, but this process must be controlled. To improve the efficiency of development of natural gas fields with bottom water, additional research was conducted using digital modeling. Based on a 3D model, the influence of penetration ratio in gas and water bearing formations on ultimate gas recovery is investigated. For the calculations, the penetration ratio was taken as 20%, 40%, 60%, 80%, and 100%. According to the modeling results, a significant impact of the penetration ratio on the efficiency of hydrocarbon production was found. According to the studies, it was found that with an increase the penetration ratio, the duration of the period of waterless operation of wells decreases. It should be noted that the greater the penetration ratio, the lower the gas recovery factor at the time of the breakthrough of the bottom water to the perforation interval. In addition, according to the studies, it was found that the smaller the penetration ratio, the greater the height of the cone of bottom water, as well as the larger the base of the cone. At full reservoir penetration, there is practically no cone formation process. In this case, the bottom water immediately enters the lower perforations of the production well and thus complicates its operation. In the short term, the flowing process is stopped and the well is shut down due to the failure to ensure the conditions for the removal of the gas-liquid mixture from the bottom hole. Based on the results of the calculations, the optimal penetration ratio in gas condensate deposits with bottom water was determined. According to the statistical processing of the calculated data, the optimal penetration ratio is 60.6%. The results of the research are aimed at improving the theoretical understanding of cone formation processes and for practical application in the mining industry in the development of natural gas fields with bottom water. [ABSTRACT FROM AUTHOR]

As conventional oil reservoirs are gradually being depleted, researchers worldwide are progressively shifting their focus towards the development and comprehensive study of tight oil reservoirs. Considering that hydraulic fracturing is one of the main approaches for developing tight sandstone reservoirs, it is of great significance to explore the mechanism of spontaneous imbibition and waterflooding behavior after hydraulic fracturing in tight oil reservoirs. This research delves into the analysis of tight sandstone core samples obtained from the Shahejie Formation in the Bohai Bay Basin. All core samples are used for a series of experiments, including spontaneous imbibition and water flooding experiments. An additional well-shut period experiment is designed to understand the impact and operational dynamics of well shut-in procedures in tight reservoir development. Utilizing nuclear magnetic resonance (NMR) technology, the pore sizes of a sample are divided into three types, namely, macropores (>100 ms), mesopores (10–100 ms), and micropores (<10 ms), to thoroughly assess the fluid distribution and changes in fluid signals during the spontaneous imbibition and water flooding stages. Experimental outcomes reveal that during the spontaneous imbibition stage, oil recovery ranges from 12.23% to 18.70%, predominantly depending on capillary forces. The final oil recovery initially rises and then falls as permeability decreases, while the contribution of micropores progressively grows as the share of mesopores and macropores deceases. With water flooding processes carried out after spontaneous imbibition, enhanced oil recovery is observed between 28.26% and 33.50% and is directly proportional to permeability. The well shut-in procedures can elevate the oil recovery to as high as 47.66% by optimizing energy balance. [ABSTRACT FROM AUTHOR]

Based on PetroChina's status and situation of low-permeability oil reservoir development, this paper analyzes the key common issues in the production capacity construction of new oilfields, the stable production of old oilfields, and enhanced oil recovery, and, in connection with the progress made in major development technologies and the results of major development tests for low-permeability oil reservoirs in recent years, puts forward the technical countermeasures and development directions. For optimizing the development of low-grade reserves, a comprehensive life-cycle development plan is essential, alongside experimenting with gas injection and energy supplementation in new fields. Addressing challenges in reservoir classification, multidisciplinary sweet spot prediction, and displacement–imbibition processes can significantly boost well productivity. In fine water flooding reservoirs, the focus should shift to resolving key technological challenges like dynamic heterogeneity characterization, and functional and nano-intelligent water flooding. For EOR, accelerating the application of carbon capture, utilization, and storage (CCUS) advancements, along with air injection thermal miscible flooding, and middle-phase microemulsion flooding, is crucial. This approach aims to substantially enhance recovery and establish a new model of integrated secondary and tertiary recovery methods. [ABSTRACT FROM AUTHOR]

The volume sweep coefficient is essential for evaluating the development effect and formulating development adjustment plans for oil fields. This paper aims to study the variation law of volume sweep coefficient in different stages of water injection development. From the perspective of the injection pore volume multiple， a calculation model is built of displacement efficiency and injection pore volume multiple， and a calculation method of volume sweep coefficient is proposed based on oil-water relative flow theory and reservoir engineering principle. In addition， three test areas of Shengli Oilfield are taken as examples for calculation and analysis. The results show that the relationship between the displacement efficiency and the injection pore volume multiple satisfies an exponential equation， and the relationship curve between the two is upward convex. As the injection pore volume multiple increases， the displacement efficiency gradually increases from the minimum displacement efficiency and approaches the maximum displacement efficiency. The displacement efficiency calculation model is verified， and the average relative error between the predicted and measured values is only 1.90%. During the water flooding development， the relationship curve between the volume sweep coefficient and the injection pore volume multiple shows an evolution trend of fast rising， slow rising， and near platform. The calculation results can guide the effect evaluation of development adjustment measures. At present， the volume sweep coefficient of the three test areas is about 90%. There is a large amount of remaining oil in the swept area. It is urgent to study the description and start-up method of the main remaining oil in the swept area.

A partially enclosed fault reservoir is a common reservoir type. The partially enclosed faults caused by low-order faults lead to different fluid flow and distribution laws of remaining oil between partially enclosed fault reservoirs and completely enclosed reservoirs. Through the existing technology， it is difficult to quantitatively describe the evolution law of the dominant flow channel in the deep part of the reservoir in the whole process of water flooding， which affects the efficient development of this kind of reservoir. Therefore， the physical model of a partially enclosed fault reservoir was designed and fabricated， and the water flooding experiment was carried out. The numerical inversion model was established according to the model parameters and experimental results. The dominant flow channel was quantitatively characterized based on the standardized flow rate algorithm. Then， the numerical inversion model was used to compare with the evolution law of the dominant flow channels in fault-free reservoirs and reveal the evolution law of the dominant flow channel in the physical model of the partially enclosed fault reservoir. The results show that the accumulative oil yield and the oil production rate of the production well in the fault-occluded area were low. The reduction of the flow area in the fault discontinuity led to the earliest breakthrough in the production well. Although the production wells on the other side of the fault had close oil production in the early stage， the blocking effect of the fault on injection water led to a higher flow diversion rate and the highest oil production rate in the late stage in the strongly fault-occluded area. During the anhydrous oil production period， a dominant flow area played a positive role in oil displacement， which developed into a spindle-shaped dominant flow channel at the bottom of the reservoir through vertical equilibrium distribution and “finger-shaped” distribution. After water production in each well， a dominant flow channel was formed from the injection well to the bottom of the production well， except for the strongly fault-occluded area. With the increase in injection volume， this channel developed in the vertical direction and around the production well and played a negative role in oil displacement. Compared with fault-free reservoirs， partially enclosed faults made the development of dominant flow channels lag in strongly fault-occluded areas and difficult water sweep in strongly fault-occluded areas， resulting in significant differences in the distribution of remaining oil in each area， and the remaining oil is concentrated in the upper part of the strongly fault-occluded area and near the faults in strongly fault-occluded areas.

Controlled salinity water flooding also known as engineered water flood has been tested as a potential enhanced oil recovery (EOR) method in laboratory as well as at pilot/field scale. However, there are cases seen where the method has failed to show its potential for EOR. Scientists believe that the lack of understanding of case specific underlying mechanism is the primary reason. Many of the literatures claims reduction of interfacial tension as the primary oil recovery mechanism; but recent findings highlighted that modification of electrical charges on rock surface with response to injection brine salinity has greater effect. In order to investigate the same and in search of more insightful mechanism, in this study we have designed and performed experiments with selected chemicals which can modify surface properties of sandstone and also the oil water interfacial tension. The electrical charge of the rock surface and oil–brine​ interfacial tension were modified by tuning salinity of injection water and adding surfactants (sodium dodecyl benzene sulfonate, SDBS and cetyltrimethylammonium bromide, CTAB). The electrical charge of the sandstone surfaces was quantified with zeta potential measurement. The oil recovery potential of the injection fluids was tested through laboratory core flooding experiments at controlled near reservoir conditions. Superposition of all the obtained results revealed that low salinity injection brine modifies the sandstone surface to higher negatively charged state than high salinity water. Therefore, with a negatively charged oil–brine interface it causes strong repulsive forces promoting detachment of residual oil and subsequent mobilization. The hypothesis is also proved by the fact that SDBS in spite of resulting in a lower interfacial tension reduction than CTAB yielded higher oil recovery. This is because of the negative zeta potential caused by SDBS to sandstone surface in comparison to the positive zeta potential observed in the case of CTAB.

The application of Microbial Enhanced Oil Recovery relies heavily on the microorganisms in oil wells. However, due to the difficulties in separating bacteria from oil samples, studies on bacterial communities in oil samples are limited. In this study, oil and produced water samples from the same well were collected from the western oilfield of the Ordos Basin, and DNA extraction was effective. Full-length 16S rRNA genes were sequenced using PacBio to study the impact of water flooding on the microbial community structure and the potential biochemical functions of bacteria in a low-permeability reservoir. The results showed that water flooding decreased the temperature and salinity while increasing the dissolved oxygen in the tested oil well. It has influence on the reservoir community. Nitrate-reducing bacteria such as Bradyrhizobium and Methylovirgula are enriched in the reservoir. Nitrate and nitrite can be used as electron acceptors by denitrification to produce N2, which can inhibit the growth of sulfate-reducing bacteria. Additionally, bacteria strains such as Flexistipes and Marinobacter can use hydrocarbons as energy source to degrade crude oil and change its properties. The study demonstrated the presence of a large number of advantageous bacteria in low-permeability reservoirs after water flooding, providing a biological foundation for the application of microbial enhanced oil recovery.

Tight oil reservoir has tiny pores so the imbibition effect is obvious. In order to enhance efficiency of waterflooding for tight oil reservoir, the method of combining water flooding and soaking was proposed. In order to clarify the mechanism of enhanced oil recovery of this new method and its main influencing factors, the impact of imbibition effect was considered and a model was proposed for imbibition. Combining this new model and the numerical simulation model for waterflooding, the numerical simulation for the waterflooding-soaking method was built. The results show that the effect of imbibition increases the swept volume of reservoir and displaces crude oil from the matrix, which improves the production efficiency. The main geology factors affecting oil recovery include matrix / fracture porosity, permeability and coefficient of imbibition. The main engineering factors affecting oil recovery include injection pressure, fracture interval and half-length. The field case also shows that this method can enhance production rate, its rate is twice time of the one by water flooding, the efficient period is about 200 d and the cumulative enhance oil is about 340 t. It indicates that this new method can enhance recovery rate of tight oil reservoirs in China and the built model can optimize parameters of this new method. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency 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.)

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency 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.)

Pressure-driven water injection technology shows significant potential in addressing the key challenges of low-permeability oil reservoirs, improving water flooding development efficiency. Grounded in FDEM theory, this study establishes fluid matrix constitutive equations and employs FDEM to resolve rock stress–strain fields. A numerical simulation method for pressure-driven water injection in low-permeability reservoirs is developed to study the impact of different well pattern densities. The results indicate that the 90° horizontal well pattern using the five-spot method yields optimal outcomes, with approximately 32.32% higher cumulative liquid production than vertical well patterns. The 45° horizontal well pattern with the reversed nine-spot method also performs well, with about 30% higher cumulative liquid production than single-row vertical wells. Pressure-driven water injection improves matrix oil–water permeability and expands water flooding coverage. Based on the pressure gradient distribution driven by different well patterns, an evaluation method for the inter-well utilization capacity and its effectiveness was established. This method quantitatively assesses the reservoir depletion under various horizontal well encryption schemes. For research on timing of water injection in pressure-driven water flooding. Compared to pressure-driven water injection after 90 days, there is increased cumulative oil production after 40 days, emphasizing the importance of early pressure maintenance for higher cumulative oil production and enhanced recovery rates in low-permeability reservoir development. These findings provide crucial theoretical and practical support. [ABSTRACT FROM AUTHOR]

To verify the effects of water flooding speed (i.e. water injection rate) on oil recovery efficiency and residual oil distribution in heterogenous reservoirs, water flooding experiments with different flooding speed are carried out in microheterogenous cores, vertically heterogenous cores, and areally heterogenous cores. In the experiments, the cores are sequentially saturated with synthetic brine and synthetic oil, and then flooded with synthetic brine with different injection rates. The results demonstrate that the increase of flooding speed shortens water-free production period and decreases oil recovery efficiency for all the three kinds of heterogenous cores, resulting in more residual oil in the cores. This is because higher flooding speed forms preferential pathways in high permeable areas, inducing inferior sweep efficiency in low permeable areas. This unfavorable effect of higher flooding speed overrides the favorable effects on the recovery of oil droplets trapped in pore throats and pore dead-ends and oil films on pore surfaces, making more residual oil left in the low permeable areas of the cores and decreasing the ultimate oil recovery efficiency. These findings could provide in-depth knowledge on the effects of water flooding speed on oil recovery efficiency and residual oil distribution. [ABSTRACT FROM AUTHOR]

Currently, there is no well-established framework for studying development patterns in high-pressure, low-permeability reservoirs. The key factors influencing development effect typically include the reservoir properties, well pattern, well spacing, and the rate of oil production. Reservoir A is a representative of this type of reservoir. Starting from its physical properties, a study of the development mechanism was conducted using the tNavigator (22.1) software. A total of 168 sets of numerical experiments were conducted, and 3D maps were innovatively created to optimize the development mode. Building upon the preferred mode, an exploration was carried out for the applicability of gas flooding and the optimization of water flooding schemes for such reservoirs. All experimental results were reasonably validated through Reservoir A. Furthermore, due to the high original pressure in such reservoirs, the injection of displacement media was challenging. Considering economic benefits simultaneously, a study was conducted to explore the rational utilization of natural energy. The research proved that for a reservoir with a permeability of about 10 mD, the suitable development scheme was five-point well pattern, a well spacing of 350 m, water–gas alternating flooding, and an initial oil production rate of 2%. When the reservoir underwent 8 months of depleted development, corresponding to a reduction in the reservoir pressure coefficient to 1.09, the development efficiency was relatively favorable. Over a 15-year production period, the oil recovery reached 29.98%, the water cut was 10.31%, and the reservoir pressure was maintained at around 67.18%. The geology of the newly discovered reservoir is not specific in the early stage of oilfield construction, and this research can help to determine a suitable development scheme. [ABSTRACT FROM AUTHOR]

In water flooding oilfields, the injected water has a significant impact on the reservoir physical properties. Sandstone reservoirs have strong heterogeneity and high clay content. After years of water flooding and the gravity differentiation of oil and water in the later stage of development, the reservoir is easy to form a local preferential flow path, and the underground seepage field has changed greatly, which further affects the oil and water movement and the remaining oil distribution in the later stage of reservoir development. The initial petro-physical parameters can’t be used to effectively guide the later development plan. A large number of investigations have been carried out in order to fully review the research methods and application of time-varying petro-physical properties in water drive reservoirs, and find suitable methods for different reservoirs in the later development stage. Coring data analysis, displacement experiment, pore network model, pore throat structure fractal characterization and other methods can be used to describe the pore throat characteristic parameters from a microscopic perspective, which are important means to study the changes of microscopic petrophysical properties. Sealed core analysis, water flooding experiment and numerical simulation technology can quantitatively characterize the changes of reservoir parameters, which are important means to study the changes of reservoir macro parameters. By summarizing the advantages and existing problems of various methods of reservoir properties time-varying analysis, it is expected to use reasonable methods to study the time-varying law of reservoir parameters in practical applications, accurately depict the changes of physical parameters in different flow units, establish dynamic geological models, accurately simulate the distribution of residual oil in the later stages of development, and provide reliable basis for oilfield development adjustment. [ABSTRACT FROM AUTHOR]

This study is aimed at using bio-catalyst (enzymes) for enhanced oil recovery in Niger Delta. Three different enzymes produced from microbial isolates with code ID; LPE1, LPE2 and AME were use in analyzing enzymes effect on the rock-fluid and fluid-fluid interaction test to simulate the conditions in the reservoir. The tests carried out include; wettability, interfacial tension (IFT) and adhesion test. The results from these tests show that addition of enzymes to rock-fluid interface has the potential of enhancing recovery of crude oil. From the result, the use of enzyme caused an alteration in the wettability of the rock from oil-wet to water-wet with a 33° difference. The selected enzyme LPE1 showed a significant difference in reduction of interfacial tension by a factor of 4, while LPE2 and AME did not show any significant difference. In conclusion, the wettability and IFT tests results were the basis for choosing LPE1 for core flooding process. Enzyme (LPE1) flooding after waterflood was able to give an additional 11.5 % oil recovery. From the results, the percentage recovery is a pointer to the fact that when the primary and secondary oil recovery methods are no longer viable in terms of economics, the Enyme enhanced oil recovery is the best method of mobilizing trapped crude oil in the Secondly, there is no negative effect on the crude oil quality using the enzyme-EOR because the enzymes only increase the rate of the chemical reaction on the rock media without undergoing any permanent chemical change.

Water flooding has already been shown to be one of the most cost-effective ways to enhance oil recovery in carbonate reservoirs. The main obstacle of this type of reservoir is the low recovery rate due to the oil-wet rock surfaces and modifying the chemistry of water injection could significantly increase oil production. This article aimed at the optimization of salinity and composition of divalent ions in Smart water flooding in dolomite reservoir rocks. Contact angle measurements performed in two steps to screen and select the optimal composition among several types of waters. Core flooding experiments conducted to evaluate the performance of the chosen waters in two different scenarios; It was carried out in three steps including brine (FW) injection, followed by best water (RW) and finally smart water (RW2S) and the second scenario was applied in reverse. Maximum recovery of 59.65% original oil in place (OOIP) was recorded for the second scenario and a lower recovery of 50.72% OOIP was observed for the first. Experimental results confirms that a higher concentration of sulfate ions enhances the water-wetness of dolomite rocks and two main mechanisms behind the smart water injection are wettability alteration and pH increase. [ABSTRACT FROM AUTHOR]

Numerous rare species coexist with a few abundant species in microbial communities and together play an essential role in riparian ecosystems. Relatively little is understood, however, about the nature of assembly processes of these communities and how they respond to a fluctuating environment. In this study, drivers controlling the assembly of abundant and rare subcommunities for bacteria and archaea in a riparian zone were determined, and their resulting patterns on these processes were analyzed. Abundant and rare bacteria and archaea showed a consistent variation in the community structure along the riparian elevation gradient, which was closely associated with flooding frequency. The community assembly of abundant bacteria was not affected by any measured environmental variables, while soil moisture and ratio of submerged time to exposed time were the two most decisive factors determining rare bacterial community. Assembly of abundant archaeal community was also determined by these two factors, whereas rare archaea was significantly associated with soil carbon–nitrogen ratio and total carbon content. The assembly process of abundant and rare bacterial subcommunities was driven respectively by dispersal limitation and variable selection. Undominated processes and dispersal limitation dominated the assembly of abundant archaea, whereas homogeneous selection primarily driven rare archaea. Flooding may therefore play a crucial role in determining the community assembly processes by imposing disturbances and shaping soil niches. Overall, this study reveals the assembly patterns of abundant and rare communities in the riparian zone and provides further insight into the importance of their respective roles in maintaining a stable ecosystem during times of environmental perturbations. [ABSTRACT FROM AUTHOR]

In this study, a one-dimensional, two-phase transient model has been developed to study the transient behavior of water transport in the porous gas diffusion layer (GDL) of a proton exchange membrane fuel cell PEM fuel cell. This model based on the numerical resolution of the mass transport of liquid water and oxygen in the porous GDL is used to gauge the effects of various design and operational parameters, namely, the current density, GDL thickness and GDL permeability, on the overall performance of the system. [ABSTRACT FROM AUTHOR]

Quantitative pore-scale multiphase flow characteristics through CO2 flooding and CO2 foam flooding after water flooding in oil-wet fractured porous media are hardly investigated and unclear. Therefore, micro-scale visualization displacement experiments of CO2 flooding and CO2 foam flooding after water flooding were conducted in this study. Firstly, four micro-scale visualization models are established based on practical sandstone cores. Secondly, micro-scale visual displacement experiments were performed in the conducted porous media. Thirdly, the qualitative analyses of multiphase flow characteristics in different micromodels were carried out. Finally, the volumetric sweep efficiency (VSE), oil recovery factor (ORF) and residual oil distribution were quantitatively analyzed. Results indicate that both the parameters of fractures and displacement methods significantly affect the multiphase flow and residual oil distribution. The residual oil after displacement can be classified into four types: cluster-shaped oil, dead corner oil, oil film and columnar oil. The residual oil after water flooding was mainly cluster-shaped oil and dead corner oil, indicating that sweep efficiency is the main factor restricting ORF of water flooding. Both CO2 flooding and CO2 foam flooding displaced most of the cluster-shaped residual oil and dead corner residual oil after water flooding, while CO2 foam flooding yielded better performance due to the blocking capability of foam system on high permeability areas. The fracture improved the connectivity of micromodels, leading to higher VSE and ORF, but also to earlier fluids breakthrough. Different from wide fracture, narrow fracture significantly improved VSE and ORF. In conclusion, reasonable fracturing and CO2 foam flooding are advantageous to further enhance oil recovery after water flooding in oil reservoirs. Article Highlights: Microscale displacement experiments in micromodels with different pore characteristics through CO2 flooding and CO2 foam flooding after water flooding. Qualitative characteristics of residual oil and multiphase flow during CO2 flooding and CO2 foam flooding in micromodels. Quantitative evaluation of EOR performance through CO2 flooding and CO2 foam flooding after water flooding based on micromodels. [ABSTRACT FROM AUTHOR]

Abstract With the development of smart downhole control devices, such as the electric flow control valve (FCV), research on completion optimization using FCV control is gaining traction for successful field production management. Applying and verifying its applicability to actual assets with uncertain production issues occur are important. This study focuses on managing downhole devices to optimize fluid production in an actual onshore oil field in Alberta, Canada. The target field has been in production operation for over 20 years, and water flooding was used in the early stages of production to maintain reservoir pressure. However, according to the flow characteristics of the field, water injection caused a high water-cut issue due to water channeling. To mitigate the problem, proactive and reactive strategies were investigated to optimize FCV control. Additionally, the effect of completion optimization was estimated considering both the field-level economic value and the fluid production behavior at the device level. In most optimization cases, the cumulative water production could be reduced compared with the base case without valve control. Notably, the flow-balancing strategy increased the revenue of the target field by approximately 23 MM$ by maximizing oil production and suppressing water production. However, reactive and streamline-balancing strategies, which directly control and delay water production, undermined the economic value due to the decrease in oil production. The findings imply that FCV control strategy of suppressing only water production for the field with high water-cut could not be the optimal solution considering the reduction in oil production and the field’s revenue. The results of this study could be used as a reference to optimize downhole devices when applying water flooding in fields where high water-cut is expected.

As conventional oil reservoirs are gradually being depleted, researchers worldwide are progressively shifting their focus towards the development and comprehensive study of tight oil reservoirs. Considering that hydraulic fracturing is one of the main approaches for developing tight sandstone reservoirs, it is of great significance to explore the mechanism of spontaneous imbibition and waterflooding behavior after hydraulic fracturing in tight oil reservoirs. This research delves into the analysis of tight sandstone core samples obtained from the Shahejie Formation in the Bohai Bay Basin. All core samples are used for a series of experiments, including spontaneous imbibition and water flooding experiments. An additional well-shut period experiment is designed to understand the impact and operational dynamics of well shut-in procedures in tight reservoir development. Utilizing nuclear magnetic resonance (NMR) technology, the pore sizes of a sample are divided into three types, namely, macropores (>100 ms), mesopores (10–100 ms), and micropores (

With the development of smart downhole control devices, such as the electric flow control valve (FCV), research on completion optimization using FCV control is gaining traction for successful field production management. Applying and verifying its applicability to actual assets with uncertain production issues occur are important. This study focuses on managing downhole devices to optimize fluid production in an actual onshore oil field in Alberta, Canada. The target field has been in production operation for over 20 years, and water flooding was used in the early stages of production to maintain reservoir pressure. However, according to the flow characteristics of the field, water injection caused a high water-cut issue due to water channeling. To mitigate the problem, proactive and reactive strategies were investigated to optimize FCV control. Additionally, the effect of completion optimization was estimated considering both the field-level economic value and the fluid production behavior at the device level. In most optimization cases, the cumulative water production could be reduced compared with the base case without valve control. Notably, the flow-balancing strategy increased the revenue of the target field by approximately 23 MM$ by maximizing oil production and suppressing water production. However, reactive and streamline-balancing strategies, which directly control and delay water production, undermined the economic value due to the decrease in oil production. The findings imply that FCV control strategy of suppressing only water production for the field with high water-cut could not be the optimal solution considering the reduction in oil production and the field's revenue. The results of this study could be used as a reference to optimize downhole devices when applying water flooding in fields where high water-cut is expected. [ABSTRACT FROM AUTHOR]

The fault-karst carbonate reservoir is a new type of deep carbonate oil and gas resource and a target for exploration and development. The distribution of remaining oil in this kind of oilfield is very complicated because of its unique reservoir characteristics of vertical migration and accumulation, segmented accumulation, and differential accumulation. Therefore, the S91 reservoir block, a typical fracture-vuggy carbonate reservoir in the Tahe oilfield, was taken as the object of this research. According to the development characteristics as well as the porosity and permeability characteristics of the fracture-vuggy, the reservoirs were divided into three types: cave, pore, and fracture. A numerical simulation model of the fracture-vuggy reservoir of the S91 unit was established, and the historical fitting accuracy with dynamic production data was more than 90%. Then, the distribution characteristics of the remaining oil in the depletion stage of the fault-karst carbonate reservoir were further studied and based on the analysis of the reservoir water-flood flow line, the remaining oil distribution characteristics in the depletion stage of the fault solution reservoir were revealed. The results show that the remaining oil distribution patterns during the depletion production stage can be divided into three types: attic type, bottom water coning type, bottom water running type. Due to the serious problem of the bottom aquifer lifting caused by the reservoir development, the residual oil between wells was relatively abundant during the depletion production stage. According to the simulation results, the remaining oil distribution modes in the water drive development stage were identified as three types: sweeping the middle between wells, bottom water connection and circulation, and oil separation through high-permeability channels. In addition, the reservoir connectivity was the main controlling factor for the remaining oil distribution in the fault-karst carbonate reservoir. [ABSTRACT FROM AUTHOR]

Pore and permeability are distributed discontinuously and unevenly in the dominant sedimentary model of the lateral accretion body inside the meandering river point bar of the Fuyang reservoir of the Yushulin oilfield. Based on the water flooding experiments of field core samples, the influence of pore permeability conditions on residual oil distribution type and water cutting rate was studied by using the microscopic visualization technology enabled through a photolithographically fabricated glass model. It is found that the residual oil in samples shows five discontinuous types, which are cluster, columnar, oil droplet, membrane, and blind end. In the stages with low, medium, and high water cutting rates, the proportion of clustered residual oil in the samples with different permeability is high, reflecting the situation that it is difficult for injected water to spread widely in tight oil reservoirs. With the decrease of permeability, the proportion of membrane and blind end residual oil gradually increases, which indicates that the thin pore throat can produce large restrictions on residual oil, resulting in residual oil enrichment. At the same time, the water flooding experiment was carried out by changing the displacement direction and periodic water injection. It was found that changing the displacement direction was beneficial to the recovery of residual oil in the thin pore throat and avoided the dominant seepage of injected water in the big pore throat, and the recovery rate was increased by more than 2.14%. Periodic water injection, which was conducive to adjusting the displacement pressure difference, reduced the constraining force of the throat on residual oil and increased the recovery rate by more than 3.98%. The actual well area with closed coring wells and dynamic production data is preferred for the application of experimental research results. Changing displacement direction and periodic water injection increased the residual oil recovery by more than 3%. [ABSTRACT FROM AUTHOR]

Carbonate reservoirs usually have strong heterogeneity, with complex pore structure and well-developed natural fractures. During reservoir development, when the formation pressure is lower than the bubble point pressure of crude oil, the fluid undergoes phase change and degassing. This leads to the subsequent waterflooding displacement under the oil–gas two-phase condition, also followed by a secondary phase change of oil and gas caused by the increase in formation pressure. In this paper, the glass etching model is used to carry out microfluidic experiments. The porous carbonate model and the fractured porous carbonate model are designed to simulate the process of depletion development and waterflooding development. In the process of depletion development, it can be observed that the crude oil degassing and gas phase occurrence areas of the porous model are in the order of the large pore throat area first, followed by the small pore throat area. And the crude oil degassing and gas phase occurrence order in the fractured porous model is as follows: fractures, large pore throat area and, finally, small pore throat area. In the process of converting to the waterflooding development, the early stage of the replacement reflects the obvious characteristic of "displace oil but not gas"; with the replenishment of formation energy, the gas redissolution area expands from the mainstream to other areas, and the waterflooding mobilization increases. The characteristics of oil, gas and water flow in different stages of carbonate reservoirs with different pore-fracture characteristics that are clarified, and the characteristics of fluid migration and the distribution under the condition of oil and gas coexisting and water flooding after crude oil degassing are explored, and the water displacement mechanism of volatile carbonate reservoirs with different pressure levels is revealed. [ABSTRACT FROM AUTHOR]

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Liquid structures such as droplets and slugs exist inside gas channels of polymer electrolyte fuel cells in low-temperature applications. The efficiency of these electrochemical devices depends on the effective removal of the produced water. The gas channels’ specifications like section geometry, corner angles, and surface wettability properties substantially control the liquid removal process. Here, five channels with various section geometries are modeled and the liquid-slug discharge process is investigated using a transient volume of fluid method. The numerical model consists of a segment of the cathode-side gas channel with the working conditions of an operational fuel cell. The dynamic two-phase flow simulations show that channels with smaller width and height eventuate in proper flow distribution at the gas feed. A channel with the sectional dimensions of 0.5 mm × 0.5 mm results in. 35.18% faster GDL (Gas-Diffusion Layer) clearance, 29.32% faster liquid expulsion compared to other channels having 2–3 times higher dimensions. Therefore, this channel is recommended as the best design for improved fuel cell performance.