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Sensitivity in polymer-bonded explosives (PBXs) relies on the presence of defects, such as cracks and voids, which create localized thermal energy, commonly known as hotspots, and initiate reactions through various localization phenomena. Our prior research has explored the use of internal gas pressure induced by thermite ignition to generate localized defects for PBX sensitization. However, further research is required to gain a more comprehensive understanding of the defect generation process resulting from internal gas pressure. This study investigates the process of defect generation in PBXs in response to internally induced gas pressure by applying controlled compressed gas to a fabricated cavity within the materials, simulating the gas pressure emitting from thermite. X-ray micro-computed tomography was employed to visualize the microstructure of the sample before and after gas injection. The experiments reveal the significance of gas pressure, cavity shape, temperature, and specimen compaction pressure in the defect generation. Numerical simulations using Abaqus/Standard were conducted to assess the defect generation in mock PBXs under varying gas pressures, cohesive properties, and binder thicknesses. The simulation results demonstrate the substantial influence of these properties on the ability to generate defects in mock PBXs. This study contributes to a better understanding of the factors influencing defect generation in mock PBXs. This knowledge is crucial for achieving precise control over defect generation, leading to improved ignition and detonation characteristics in PBXs. [ABSTRACT FROM AUTHOR]

The success of foam-induced flow diversion in fractured carbonates hinges on proper injection strategies, requiring an in-depth understanding of the factors responsible for stimulating fracture–matrix interactions. In this study, we present a novel investigation of the interactions between the fracture and the matrix influenced by the mobility control effect during CH4-foam injections. These interactions were probed at the pore scale using a three-phase flow system integrated with a high-resolution micro-CT scanner. In situ phase saturations were monitored and quantified to interpret the resulting fluid transport at various injection parameters. At the initial stage of foam injection, the surfactant solution was able to invade the matrix leading to water/oil displacement events, however, impeding gas penetration. Increasing total injection velocity produced higher in situ foam quality in the fracture than the injected quality, where significant fraction of the surfactant solution from the foam was primarily diverted into the matrix. A pronounced increase in the average gas saturation within the matrix was only observed at the highest injection velocity. The pore-scale evidence showed the occurrence of combined displacement processes (water/oil, gas/oil, gas/oil/water) in the matrix, attributed to the established mobility control in the fracture, which contributed to the diversion of surfactant solution and gas to the matrix. Lastly, the injection–soaking–production technique effectively mobilized the residual oil after a long injection process of CH4-foam. At this stage, the surfactant solution was no longer playing a role as the primary invading fluid; rather, it was the diverted gas that led to the increase in the matrix-oil production. [ABSTRACT FROM AUTHOR]

As an efficient and clean energy, coalbed methane development and utilization have deep significance in promoting energy conservation and emission reduction, reducing greenhouse gas emissions. Therefore, molecular simulation was utilized to study the influence of N2/CO2 on the adsorption and diffusion of methane in coal under different gas injection methods and to elucidate the influence of varying gas injection methods on the efficiency of coalbed methane extraction, which provides a basis for the efficient development of coalbed methane. The results show that the adsorption effect of gases in coal decreases with the increase of temperature and increases with the rise of pressure, and the adsorption performance of the three gases in coal shows the law of CO2 > CH4 > N2. In addition, the injection of CO2/N2 had an obvious inhibition effect on CH4 adsorption, and the inhibition effect of CO2 was more significant, and the inhibition effect on CH4 adsorption reached the maximum when the two gases were mixture injected. In terms of diffusion, compared with separate injection, mixed injection of N2 + CO2 promotes CH4 diffusion more effectively, which can be reflected in the relative concentration distribution and velocity distribution. The injection of N2 helps to increase the porosity of coal, and the injection of CO2 and N2 + CO2 will lead to the decrease of porosity, but the mixed gas injection has less effect than the injection of CO2 alone. [ABSTRACT FROM AUTHOR]

The gas lift technique applies gas bubble injection into the vertical wells to raise production. Gas and liquid rates, shifts in flow regimes, and system equilibrium influence this process. This study explores the efficient implementation of gas lift techniques to maximize production from the Asmari Formation in the Abu Ghirab Field, southeastern Iraq, using a continuous gas lift for maximum production rate by PIPESIM TM software. The results of the gas lift design for the four wells (AGCS-33, 26, 28, and 36) show that the Vogel method provided the best results for the gas lift design, and faults and facies distribution impact the gas lift injection and oil production rates. These will become evident with wells AGCS-33 and 36 as their proximity to faults will increase oil production rates with a gas injection rate limit of 7 MMSCF/d. Conversely, for wells 26 and 28, the limit will marginally rise, starting at 5 MMSCF/d. In addition, the effect of gas lift is clearly in the middle western of the crest, which shows an increasing percentage of oil production of 136.6% at minimum rate and 198.5% at maximum for the well AGCS-26, 89.7% and 105.7% for the well AGCS-36. Wellhead pressure has a significant impact on gas-lift performance, and improving gas-lift efficiency can be accomplished using an electric control valve. The feasibility of implementing gas lift in the Asmari Formation depends on the water cut, well location, and water saturation distribution within the Formation. [ABSTRACT FROM AUTHOR]

In gas injection, which is one of the fascinating enhanced oil recovery techniques, the main mechanism involves decreasing interfacial tension (IFT). Although various mechanisms can affect the IFT of a system, in most experimental and numerical studies, condensation is considered the dominant mechanism among condensation-vaporization and vaporization. Investigating the impact of each mechanism is crucial as they can influence the IFT of the system and, consequently, the effectiveness of the gas injection method. This study introduces a novel model to assess the influence of different mechanisms on system IFT. The model defines system IFT, adjusts fluid relative permeability to represent miscible, immiscible, and near-miscible states, and utilizes the Buckley–Leverett method to analyze gas fractional flow and saturation profiles when injecting carbon dioxide (CO2), methane (CH4), and nitrogen (N2). Furthermore, the research explores the impact of injection pressure and IFT at minimum miscible pressure (IFT0) on gas injection efficiency. Based on our results, for both live and dead oil, the condensation mechanism reduces IFT and near-miscible pressure; switching to a condensing-vaporizing mechanism increases these parameters. This trend was consistent across all gases studied (N2, CO2, CH4), with a more significant effect observed on the CH4-live oil system compared to N2 and CO2. Controlling the condensing mechanism in IFT measurements enhances gas flow rate and relative permeability curve within the medium. Higher injection pressure in the condensing mechanism and IFT0 = 0.5 leads to faster fluid movement and improved relative permeability due to increased driving forces. Higher IFT0 accelerates the relative permeability of fluids and gas movement within the medium by promoting miscibility sooner. The impact of IFT0 was more pronounced on the dead oil–gas system compared to the live oil–gas system in this study. [ABSTRACT FROM AUTHOR]

To study the smelting reduction behavior of methane in the HIsarna process, the isothermal reduction experiments of HIsarna slag with 6 wt% of FeO were conducted at the temperatures of 1450, 1475, and 1550 °C, using 5 vol% CH4‐Ar. The effect of the gas injection flow rate on the overall reduction rate was investigated in the range of 0.5–1.5 L min−1. The results confirm that the decomposed carbon black acts as the dominant reductant in the reduction process compared to hydrogen. Increased gas flow rate increases the reaction rate, while temperature shows no significant effect. The reduction process could be described by the JMAEK model: by fixing the gas flow rate at 1.0 L min−1 with different temperatures, the exponent n value is around 1.5, indicating FeO mass transfer is the limiting step since there are sufficient carbon blacks as nucleation sites. The reduction process follows the first‐order model controlled by the reactant concentration with the gas flow rate being at 0.5 L min−1 and in the second reaction stage of the gas flow rate at 1.5 L min−1. The determined activation energy for the methane reduction is 59.8 kJ mol−1. [ABSTRACT FROM AUTHOR]

Low thermal evolution degree of gas and connected fracture network are key features in the continental shale gas reservoirs. When the pressure decreases lower than the dew point pressure, gas condensate diminishes the mobility of subsurface fluid forms in the near well region, which further reduces the productivity and final recovery factor in addition to the low connected fracture network. This work is motivated to investigate the application of gas injection, proven to be a feasible technique in conventional/marine-shale gas condensate reservoirs, in continental shale gas condensate reservoirs. We apply a compositional model to investigate the mechanism of gas injection treatment taking a continental shale gas condensate reservoir in the Fuxing area, Sichuan Basin, China as an example. The results demonstrate that for the removal of gas condensate during CO2 injection, re-vaporization plays the main mechanism through two processes including pressurization and development of miscibility, while the former is overwhelming. Considering the variation trend of the total volume of gas condensate, we divide the whole injection process into four and six stages in the single fracture model and fracture network model, respectively, and reason the trend with respect to phase behavior and flow pattern. A sensitive study on the injected gas type indicates that the sorting of the gas injection performance to remove gas condensate produced gas followed by CH4, and followed by CO2. Finally, we investigate the performance of cyclic produced-gas injection and optimize the injection scheme. This work provides technical and theoretical support for the development of continental shale gas reservoirs. [ABSTRACT FROM AUTHOR]

The use of foam injection as an enhanced oil recovery (EOR) technique has been suggested since the 1960s to address issues with gas injection. Foam is composed of gas, water, and surfactant, which is utilized to stabilize the foam. This study investigates the synergy effect of anionic surfactant and two zwitterionic surfactants on enhancing solution stability. The anionic surfactant used is sodium dodecyl sulfate, while the chosen zwitterionic surfactants are cocamidopropy hydroxy sultine and Cocamido Propyl Betaine. Analyzing the images of the generated foam showed that initially, the small and uniform bubbles are formed in all concentrations. The foam size is then increased and in concentrations higher than a critical value, the bubbles grow faster which is likely due to the formation of micelles and deposition of surfactants. This leads to early collapse of the foam structure. The quantitative half-life results approved that the most optimal compound was obtained with equal proportions of sodium dodecyl sulfate and Cocamido Propyl Betaine with concentration of 3 wt% (1:1 ratio, 0.15 wt%-0.15 wt%). To quantitatively study on foam characteristics, conductivity and interfacial tension tests were performed. The results of the conductivity tests showed that micelles were formed in concentrations of more than 0.3 wt%. Interfacial tension measurements revealed that addition of a small amount of surfactants to the base solution, led to reduction of the interfacial tension value from 29.2 (mN/m) in base solution to less than 1 mN/m for solutions treated with surfactant. [ABSTRACT FROM AUTHOR]

The curtaining effect is a common challenge in focused ion beam (FIB) surface preparation. This study investigates methods to reduce this effect during plasma FIB milling of Inconel 718 (nickel‐based superalloy). Platinum deposition, silicon mask and XeF2 gas injection were explored as potential solutions. These methods were evaluated for two ion beam current conditions; a high ion beam intensity condition (30 kV–1 µA) and a medium one (30 kV–100 nA) and their impact on curtaining reduction and resulting cross‐section quality was assessed quantitatively thanks to topographic measurements done by atomic force microscopy (AFM). XeF2 assistance notably improved cross‐section quality at medium current level. Pt deposition and Si mask individually mitigated the curtaining effect, with greater efficacy at 100 nA. Both methods also contributed to reducing cross‐section curvature, with the Si mask outperforming Pt deposition. However, combining Pt deposition and Si mask with XeF2 injection led to deterioration of these protective layers and the reappearance of the curtaining effect after a quite short exposure time. LAY DESCRIPTION: The so‐called curtaining effect is a common challenge in focused ion beam (FIB) surface preparation. It is characterised by a relief occurring on the FIB prepared surface whereas a perfectly flat surface would ideally be expected. The issue of FIB‐induced curtaining effect represents a significant challenge in large‐scale 3D analysis applications, notably in methodologies reliant on FIB serial sectioning, such as 3D electron backscatter diffraction (3D EBSD). A strong curtaining effect can alter data quality and so their interpretation after 3D reconstruction. This study investigates methods to reduce this effect during plasma FIB milling of Inconel 718 (nickel‐based superalloy). Platinum deposition, silicon mask and XeF2 gas injection were explored as potential solutions. These methods were evaluated for two ion beam current conditions: a high ion beam intensity condition (30 kV–1 µA) and a medium one (30 kV–100 nA) and their impact on curtaining reduction, and resulting cross‐section quality was assessed quantitatively thanks to topographic measurements done by atomic force microscopy (AFM). XeF2 assistance notably improved cross‐section quality at medium current level. Pt deposition and Si mask individually mitigated the curtaining effect, with greater efficacy at 100 nA. Both methods also contributed to reducing cross‐section curvature, with the Si mask outperforming Pt deposition. However, combining Pt deposition and Si mask with XeF2 injection led to deterioration of these protective layers and the reappearance of the curtaining effect after a quite short exposure time. [ABSTRACT FROM AUTHOR]

With the development of the petroleum industry and advancements in technology, gas injection techniques have gradually matured and become an important means to enhance oil recovery in reservoir development. Gas channeling is a major challenge in the process of gas injection development. The presence of gas channeling can lead to a decrease in the swept volume of gas flooding, severely affecting the effectiveness of gas injection development. This paper focuses on low-permeability reservoirs, comprehensively analyzing the development characteristics of low-permeability reservoirs and the dynamic characteristics of gas flooding production. It selects and evaluates indicators for assessing the development degree of gas channeling and establishes a fuzzy comprehensive evaluation method for evaluating gas channeling in the gas injection development of low-permeability reservoirs. Based on the evaluation values derived from the fuzzy comprehensive evaluation, it classifies the development levels of gas channeling. Application in oilfield cases shows that the evaluation results of this method are generally consistent with the dynamic response of production data, with high evaluation accuracy. This provides strong support for implementing gas channeling prevention and control measures on site and improving the effectiveness of gas injection development. [ABSTRACT FROM AUTHOR]

CO2-enhanced oil recovery (CO2-EOR) is a crucial method for CO2 utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO2 and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO2 utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO2-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO2-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO2-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO2-EOR techniques in heterogeneous and fractured reservoirs. [ABSTRACT FROM AUTHOR]

In order to analyse the effect of the injection point size of the CBM (Coalbed Methane) well level monitor on the amplitude and frequency of pressure pulsations in the wellhead manifold, numerical simulations and experiments were carried out to investigate the effect of different injection point sizes on the amplitude and frequency of pressure pulsations downstream of the sudden expansion structure. Using compressed air as the fluid and the size of the injection point as the variable, the amplitude and frequency of pressure pulsations at different locations downstream of the sudden expansion structure were tested. The results show that the pressure pulsation amplitude is affected by the size of the injection point, and the larger the injection point is, the larger the pressure pulsation amplitude is; the size of the injection point has less influence on the pressure pulsation frequency downstream of the protruding and expanding structure, and the pressure pulsation frequency at 0.5 m and 1 m downstream of the protruding and expanding structure is in the vicinity of 76 Hz. Therefore, the echo signal processing should be filtered around this frequency to obtain accurate liquid level echo signals, so as to improve the accuracy of liquid level monitoring and realise the efficient development of coalbed methane wells. [ABSTRACT FROM AUTHOR]

Gas injection is a well-known method for enhancing oil recovery (EOR). The utilization of greenhouse gases, such as carbon dioxide (CO2) or flue gas, offers the dual advantage of reducing greenhouse gas emissions while potentially enhancing the sweep efficiency in oil recovery. Nevertheless, one of the notable challenges encountered when using these gases is the precipitation and deposition of asphaltenes, leading to formation damage and a decrease in reservoir permeability, particularly in the case of light oil reservoirs. In this study, CO2 and flue gas were injected into an elongated core sample comprising four individual core plugs under reservoir conditions to displace the light live oil. The recovery factor and asphaltene deposition along the core holder were assessed and compared as two crucial parameters within the gas injection scenario. Our results indicate a significantly higher recovery factor of 86% achieved with CO2 injection compared to 36% with flue gas injection, attributable to differences in their interfacial tension and miscibility. However, the CO2 injection method exhibits more pronounced formation damage. Individual assessment of each core plug reveals that permeability impairment is most acute in the initial two core plugs, situated closer to the injection face of the extended core. These findings enhance our understanding of the mechanisms contributing to permeability impairment resulting from asphaltene deposition during CO2 and flue gas injection for EOR. [ABSTRACT FROM AUTHOR]

Gas injection displacement is a widely used technique to enhance the recovery of coal methane (CH4) or oil reservoirs. Additionally, this method plays a crucial role in effectively developing CH4 resources in a closed goaf. In the present study, the distribution characteristics of fissures in a closed goaf were determined using a physical simulation test, and the connected fissure network was extracted and modeled. Further, CH4 extraction numerical simulation tests were conducted on the connected fissure network under gas injection conditions. The migration and distribution characteristics of CH4 were analyzed in the connected fissure network under different gas injection conditions, including gas injection position, gas injection rate, and gas injection type. The research also evaluated the impact of different gas injection conditions on CH4 production in vertical wells. Finally, a model was developed to determine characteristic parameters for CH4 production in vertical production wells, which were calculated and compared across different gas injection conditions. Results revealed a negative correlation between CH4 volume fraction and gas injection time in vertical wells under different gas injection conditions, contrary to the S-type growth curve. Gas injection positions significantly influenced the migration and distribution of gas within the connected fissure network, with higher CH4 productivity and production efficiency in the gas injection position P2 compared to P1. The increase in the gas injection rate enhanced CH4 production efficiency, albeit having little effect on CH4 productivity. Gas injection types yielded no significant influence on CH4 production efficiency, although CH4 productivity was lower with 100% CO2 injection compared to 100% N2 and mixed gas. This investigation provides the foothold for enhancing the recovery of CH4 in closed goafs and contributes to the progress of carbon emission reduction technology in coal mining areas. [ABSTRACT FROM AUTHOR]

Blowing agent-assisted extrusion cooking is a novel processing technique that can alter the expansion of extruded snacks and, thus, enhance their physical appeal, such as texture. However, to this day, this technique has only been studied for ingredients with limited protein contents (<30%). In this study, protein-enriched snacks were extruded using nitrogen gas as a blowing agent at a wide protein range (0–50%) to better explore the potential of this technique in manufacturing high-protein snacks. The results showed that, with nitrogen gas injection, extrudate radial expansion was significantly (p < 0.05) improved at 10% and 40% protein, while extrudate density was significantly reduced at 30% and 50% protein. Nitrogen gas-injected extrudates, especially at 50% protein, exhibited improvements in texture, including a reduction in hardness and an increase in crispness. Collectively, this study showed the promising potential of nitrogen gas-assisted extrusion in improving the physical appeal of innovative healthy snacks at a high protein level (i.e., 50%). [ABSTRACT FROM AUTHOR]

Foam can effectively improve reservoir heterogeneity, increase gas–liquid flow rate, reduce viscous fingering, and help to improve sweep efficiency. This paper mainly studies the characteristics and performance of microbial foam production, and proposes an enhanced oil recovery method for profile control by in situ microbial foam production. By optimizing the carbon and nitrogen sources of the medium, Pseudomonas aeruginosa PAO1 produced single and double rhamnolipids and biogas composed of N2, CO2, and CH4, and it could also produce foam in high salt, weak acid, and weak alkali environments. Gas injection experiments were carried out using self-produced biogas, the foaming effect is good in the range of gas–liquid ratio 1:1–3:1 and gas injection speed 20–40 ml/min, which was 71.43%–91.25% more than the foam volume produced by CO2 injection, and the foam production was positively correlated with the protein concentration of the foam. In the early stage of incubation, the foam was 20–100 μm in diameter, with high protein concentration and strong foam stability, which slowed down the drainage, polymerization, and disproportionation of the liquid film of the foam system. The foam performance test results show that the foam half-lifetime is long, up to 109 min. Foam culture medium has good viscosity reduction effect, emulsifying properties and less corrosive. The displacement experiment shows that the foam generated in situ by PAO1 in the core has good stability, reproducibility, and profile control performance, which can reduce the permeability of the core to half of the initial permeability and improve the reservoir heterogeneity. Therefore, microbial in situ foam production can be an effective method to enhance oil recovery in heterogeneous reservoirs, which is low cost, low pollution, and simple operation. [ABSTRACT FROM AUTHOR]

Oscillation characteristics in a cavity are investigated under real experimental conditions through unsteady numerical simulations of the time-evolving oscillatory damping of a high-Mach-number freestream over a two-dimensional forward-facing cavity. The post-disturbance flow field is taken as the initial condition. Temporal variations in the flow field and wall resistance coefficient are obtained. The forward-facing cavity experiences underdamped oscillatory behavior when subjected to disturbances. The convergence of the oscillations is influenced by the cavity volume, with significant reductions in cavity damping observed when stagnation regions develop within the cavity. During the initial phase of disturbance, each oscillation cycle consists of gas injection and jet phases. In the former, external gas stagnates within the cavity, resulting in a gradual increase in internal density and pressure. High-temperature regions extend from the external flow into the cavity, and bow shocks approach the cavity wall, adversely affecting aerodynamic drag reduction and thermal protection for aircrafts. In the jet phase, the flow field structure resembles the opposing jet. As the gas is expelled, the internal cavity pressure decreases, forming a cold jet that envelops the cavity's surface. The temperature within the boundary layer on the surface decreases, and bow shocks are pushed away from the wall, resulting in thermal-protection and drag-reduction effects. Transitions between phases induce instability in the internal flow states within the cavity. During the transition from the gas injection phase to the jet phase, the wall drag coefficient reaches its peak value; the reverse transition results in the lowest wall drag coefficient. [ABSTRACT FROM AUTHOR]

Effects of secondary gas injection on flame shape and combustion stability of a premixed swirl methane/air flame were investigated experimentally. Without secondary gas injection, an attached M-shaped flame was observed with pressure oscillations up to a sound pressure level of 68 dB. The flame exhibited significant oscillations due to flame–vortex interactions induced by velocity fluctuations. The secondary methane or air was separately injected into the outer recirculation zone to suppress the flame oscillations at a volume flow rate of 0.5% of the primary flow rates. For lower primary air flow rates ( Q air ≤ 60 L/min), both secondary methane and air injections were able to suppress the thermoacoustic instability and performed the sound pressure level reduction of 45 dB. Meanwhile, the flame transformed from an attached unstable M-shaped flame to a detached stable V-shaped flame. The secondary methane or air injection served to stabilize the flame and anchor its spatial heat release distribution by limiting the variation of flame shape in the outer recirculation zone, suppressing thermoacoustic oscillation. For higher primary air flow rates ( Q air = 80 L/min), the secondary methane injection could reduce sound pressure levels to noise levels, while secondary air injection could not. The velocity disturbances and heat release fluctuations introduced by secondary methane injection could lead to a transformation in flame shape and achieve the suppression of thermoacoustic oscillation. However, the velocity disturbances induced by secondary air injection were insufficient to stabilize the flame. [ABSTRACT FROM AUTHOR]

Background: Dark eye circle (DEC) is one of the most common cosmetic problems. It has a great impact on the patients' quality of life. Carboxytherapy is a cosmetic technique using pure carbon dioxide for different uses in different areas of the body. The goal of this study is to evaluate the efficacy and tolerability of carboxytherapy in the cosmetic correction of DECs. Methods: This study was conducted on 27 patients requesting the correction of DEC. The treatment was performed using a carboxy device in medical grade. The gas injection was performed intradermal after local anesthesia, with a pressure of one tenth bar and a speed of 20 cc/min, 1 cc in each upper and lower eyelid. The treatment sessions were done every 2 weeks for four sessions. Results: The mean physicians' score of DECs before and after treatment was 8.7 ± 0.81 and 4.6 ± 1.1, respectively. The mean patients' score before and after treatment was 9.2 ± 0.5 versus 5.41 ± 1.37. The mean scores showed a significant reduction of skin discoloration without major side effects (p < 0.00001). Conclusion: Carboxytherapy seems to be an effective treatment option for dark circles around the eyes with a good safety profile and patient satisfaction. [ABSTRACT FROM AUTHOR]

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In the current work, a computational fluid dynamics-based model was utilized to investigate the performance of the H2 shaft furnace under a scenario where room-temperature H2 is injected through a center gas distributor (CGD) installed at the unit bottom. Modelling was conducted to simulate scenarios where the CGD operation is applied with different feed gas rates (ranging from 0 to 250 Nm3/t-pellet). The results showed that a high temperature level and thus a better internal thermochemical state can be maintained with a proper CGD gas feed rate. However, an overly high CGD feed rate (being 150 Nm3/t-pellet or a higher value) induces a detrimental scenario where the thermal energy recycled by the room-temperature CGD gas is insufficient to compensate for the decrease of sensible heat of the preheated feed gas from the bustle-pipe. This eventually results in a noteworthy chemical reserve zone of high H2 content and little solid reduction in the furnace center. A large quantity of H2 consequently remains unutilized and leaves the furnace from the top. Under the investigated conditions, the final solid reduction degree rises to maximal value when the CGD gas feed rate is 100 Nm3/t-pellet. The findings of this work revealed that the room-temperature CGD gas injection operation holds significant promise for practical applications. [ABSTRACT FROM AUTHOR]

The corrosion mechanism of L245NS steel and L360QS steel of gas injection/withdrawal pipeline of underground gas storage in different acidic gas environments was studied by means of SEM, EDS, XRD, XPS, and GC-MS. The results show that Fe2O3, Fe3O4, and CaCO3 with poor protection were formed on the surface of L245NS steel, which provided a channel for the corrosive medium to contact the surface of the metal matrix and accelerated the corrosion rate of the pipeline. Meanwhile, CI− had a small radius and strong penetrability, which was easy to pass through the product film to reach the surface of the metal matrix to participate in the reaction, resulting in corrosion defect pits. The inner wall of L360QS steel was attached with gum, forming a dense protective film on the inner surface of the pipeline, and it was difficult for corrosive substances to enter the metal matrix, which played a role in inhibiting the corrosion of the pipeline. [ABSTRACT FROM AUTHOR]

Using subterranean rock cores as samples, the impact of depletion exploitation and cyclic gas injection on the occurrence and dynamic utilization of condensate oil and the damage to reservoirs were studied. Initially, the internal pore structure of the rock core was analysed using computer tomography (CT), followed by depletion and cyclic gas injection experiments, with insitu CT scanning of the samples. The results indicate that under different fracture apertures, condensate oil exhibits wave flow and slug flow states. The production effectiveness of cyclic gas injection is significantly superior to depletion exploitation production, with condensate oil saturation decreasing by over 30%. During cyclic gas injection, fractures serve as the main flow channels, with condensate oil being extracted first. In cyclic gas injection, the most significant effect is seen during the first injection, with a decrease in oil saturation of around 3%. Subsequent injections show decreases of approximately 1% and 0.5% in oil saturation respectively. As the gas injection volume increases, the extent of cumulative production rate improvement also gradually increases; however, once the injection volume reaches the reservoir pressure, the rate of cumulative production rate improvement will gradually decrease. These findings provide technical support for optimizing the development mode of condensate gas reservoirs, clarifying the seepage law of condensate oil and gas, and providing technical support for the efficient development of fractured condensate gas reservoirs. [ABSTRACT FROM AUTHOR]

Evaluating underground gas storage (UGS) sealing capacity is essential for its safe construction and operational efficiency. This involves evaluating both the static sealing capacity of traps during hydrocarbon accumulation and the dynamic sealing capacity of UGS under intensive gas injection and withdrawal, and alternating loads. This study detailed the methodology developed by Sinopec. The approach merges disciplines like geology, geomechanics, and hydrodynamics, employing both dynamic-static and qualitative-quantitative analyses. Sinopec's evaluation methods, grounded in the in situ stress analysis, include mechanistic studies, laboratory tests, geological surveys, stress analysis, and fluid-solid interactions. Through tests on the static and dynamic sealing capacity of UGS, alongside investigations into sealing mechanisms and the geological and geomechanical properties of cap rocks and faults, A geomechanics - rock damage - seepage mechanics dynamic coupling analysis method has been developed to predict in situ stress variations relative to pore pressure changes during UGS operations and evaluate fault sealing capacity and cap rock integrity, thereby setting the maximum operational pressures. Utilizing this evaluation technique, Sinopec has defined performance metrics and criteria for evaluating the sealing capacity of depleted gas reservoirs, enabling preliminary sealing capacity evaluations at UGS sites. These evaluations have significantly informed the design of UGS construction schemes and the evaluation of fault sealing capacity and cap rock integrity during UGS operations. [ABSTRACT FROM AUTHOR]

Dynamic compressors are widely used in many industrial sectors, such as air, land, and marine vehicle engines, aircraft environmental control systems (ECS), air-conditioning and refrigeration, gas turbines, gas compression and injection, etc. The data-driven formulas of mass flow rate and isentropic efficiency of dynamic compressors are required for the design, energy analysis, performance simulation, and control- and/or diagnosis-oriented dynamic simulation of such compressors and the related systems. This work develops data-driven models for predicting the performance of dynamic compressors, including empirical models for mass flow rate and isentropic efficiency, which have high prediction accuracy and broad application range. The performance maps of two multi-stage axial compressors of an aero engine and a centrifugal compressor of an aircraft ECS were chosen for evaluation of the existing empirical formulas and testing of the new models. There are 16 empirical models of mass flow rate and 14 empirical models of isentropic efficiency evaluated, and the results show that it is necessary to develop highly accurate empirical formulas both for mass flow rate and isentropic efficiency. With the data-driven method, two empirical models for mass flow rate and one for isentropic efficiency are developed. They are in general form, with some terms removable to make them simple while enhancing their applicability and prediction accuracy. The new models have much higher prediction accuracy than the best existing counterparts. The new mass flow rate models predict for the three compressors a mean absolute relative deviation (MAD) not greater than 1.3%, while the best existing models all have MAD > 2.0%. The new efficiency model predicts for the three compressors an MAD of 1.0%, 0.4%, and 1.9%, respectively, while the best existing model predicts for the three compressors an MAD of 1.8%, 0.8%, and 3.2%, respectively. [ABSTRACT FROM AUTHOR]

BACKGROUND: At present, there are few studies on the technical requirements of manual bedside placement of post-pyloric tube in Intensive Care Unit patients. OBJECTIVE: To investigate the application value of downward tract adherence method in the manual bedside placement of jejunal tubes. METHODS: In the downward group, 160 patients underwent manual bedside placement of jejunal tubes by a downward tract adherence method. In the conventional group, 144 patients were treated with conventional gas injection during the placement. The success rate, average time, and adverse reactions of the placement in the two groups were investigated and compared. RESULTS: The success rate of the placement in the downward group was significantly higher (95% vs. 75%, P < 0.001) and the average time for the successful placement was shortened (23 ± 5.91 min vs. 26 ± 5.49 min, P = 0.025) than that in the conventional group. No treatment-related adverse reactions occurred in either group, and there were also no significant differences in vital sign changes. CONCLUSIONS: The use of the downward tract adherence method in the manual bedside placement of postpyloric tubes for the intensive care patients at the bedside has a higher success rate, effectivity and safety. [ABSTRACT FROM AUTHOR]

The clastic reservoir in Tarim Oilfield has entered the middle-to-late stage of development, and consequently, enhanced oil recovery (EOR) is becoming highly challenging. Gas flooding is the practical method for EOR from this type of reservoirs. In this study, taking Tazhong 402 CIII reservoir as an example, the micro-mechanism of EOR by gas injection is investigated by conducting slim-tube, long-core displacement, and micro-visual displacement experiments. A gas injection development plan is formulated based on reservoir characteristics, laboratory experiments, and numerical simulations. The results show that miscible flooding cannot be achieved by injecting natural gas under the current formation conditions; however, natural gas flooding after light hydrocarbon flooding can significantly improve oil recovery. The studied reservoir is divided into two series of development layers: CIII1–3 layers, for which light hydrocarbon alternating natural gas flooding is adopted, and CIII4–8 layers, for which light hydrocarbon combined with natural gas gravity-assisted composite flooding is employed. The findings of this study have guiding significance for gas injection development in deep clastic reservoir in Tarim Basin. [ABSTRACT FROM AUTHOR]

Gas injection for enhanced oil and gas reservoir recovery is a crucial method in offshore Carbon Capture, Utilization, and Storage (CCUS). The B6 buried hill condensate gas reservoir, characterized by high CO2 content, a deficit in natural energy, developed fractures and low-pressure differentials between formation and saturation pressures, requires supplementary formation energy to mitigate retrograde condensation near the wellbore area through gas injection. However, due to the connected fractures, the B6 gas reservoir exhibits strong horizontal and vertical heterogeneity, resulting in severe gas channeling and a futile cycle, which affects the gas injection efficiency at various levels of fracture development. Based on these findings, we conducted gas injection experiments and numerical simulations on fractured cores. A characterization method for oil and gas relative permeability considering dissolution was established. Additionally, the gas injection development boundary for this type of condensate gas reservoir was quantified according to the degree of fracture development, and the gas injection mode of the B6 reservoir was optimized. Research indicates that the presence of fractures leads to the formation of a dominant gas channel; the greater the permeability difference, the poorer the gas injection effect. The permeability gradation (fracture permeability divided by matrix permeability) in the gas injection area should be no higher than 15; gas injection in wells A1 and A2 is likely to achieve a better development effect under the existing well pattern. Moreover, early gas injection timing and pulse gas injection prove beneficial in enhancing the recovery rate of condensate oil. The study offers significant guidance for the development of similar gas reservoirs and for reservoirs with weakly connected fractures; advancing the timing of gas injection can mitigate the retrograde condensation phenomenon, whereas initiating gas injection after depletion may reduce the impact of gas channeling for reservoirs with strongly connected fractures. [ABSTRACT FROM AUTHOR]

Mechanism analysis and technical scheme optimization on CO2 displacement and CO2 storage are based on the high-pressure physical properties of CO2-added formation oil. Oil and natural gas samples from the BZ25-1 block in the Bohai oilfield were used to conduct high-pressure physical property experiments to explore the impacts of CO2-CH4 mixed gas on the properties of formation oil. After injecting different amounts of mixed gas, the saturated pressure was measured by constant mass expansion test, the viscosity was measured by falling ball method, the expansion coefficient was measured by gas injection expansion test, and the gas–oil ratio and volume coefficient were obtained by single degassing test. The results show that with gas injection, the saturation pressure and dissolved gas–oil ratio of formation oil increase, the volume coefficient and expansion factor go up, while the oil viscosity reduces. With the increase in gas addition, the properties of formation oil continue to improve, but the increase in improvement becomes flat. With the increase in pressure, the amount of dissolved gas in the formation oil will also increase. High-purity CO2 is more helpful to change the properties of formation oil, while the gas mixed with CH4 is more beneficial to elevate the formation energy. For the BZ 25-1 block, the gas injection amount of about 80 mol% is appropriate and the CO2 purity of 60% can well balance the oil properties improvement and the formation pressure elevation. [ABSTRACT FROM AUTHOR]

Under casing annulus gas venting, the annulus of the well is in a special state of zero-net liquid flow (ZNLF), leading to gas production without liquid at the wellhead, resulting in significant holdup issues. Therefore, conventional two-phase flow models cannot be used for calculation. To study the flow characteristics of ZNLF in the annulus of the well, this study established a visual experimental device with a total height of 5.4 m, an outer pipe inner diameter of 140 mm, and an inner pipe outer diameter of 72 mm. The flow characteristics of ZNLF were studied by controlling the casing pressure, initial liquid level, and bottom gas injection rate. The experimental results showed that the flow patterns of ZNLF are mainly bubbly flow and churn flow. Bubbly flow occurred at lower gas rates, while churn flow occurred at higher gas rates. In addition, the experiment found that when the gas injection rate and initial liquid column height were controlled to be the same, the liquid holdup decreased as the casing pressure increased. Analysis of the data patterns indicated that the slip velocity is related to the casing pressure. Based on the experimental results of ZNLF in the annulus, this study established standards for flow pattern transitions, holdup, and a pressure drop calculation model. The model results showed good agreement with the experimental results, with errors not exceeding ±5%. [ABSTRACT FROM AUTHOR]

Adjusting injection and production parameters is an essential tool for studying the effect of reservoir heterogeneity on in-situ combustion (ISC) sweep and associated control strategies, as well as for achieving stable ISC. An asynchronous injection and production in-situ combustion (AIPISC) method through the coupling of the gas injector and producer in order to accomplish the balanced sweep of ISC. Using the Hongqian (HQ) ISC in Xinjiang as an example, numerical simulation was utilized to define the reservoir and investigate the sweep characteristics under various sedimentary models. The AIPISC technology was applied to several heterogeneous reservoirs, and the design scheme of AIPISC was created. Under the same heterogeneous reservoir circumstances as the conventional ISC approach, the oil saturation of the AIPISC wall increases from 0.65 to 0.72. The roundness of the combustion chamber was better, and balanced displacement can be achieved. Then the parameters of AIPISC were optimized to determine that the vertical permeability difference of the reservoir should be less than 15, the asynchronous time difference was 6 ∼ 8 months, and the gas injection amplitude was 1.5 ∼ 2.0. The results show that the experiment in HQ Oilfield was successful, and the usefulness of AIPISC was investigated using the electromagnetic approach. [ABSTRACT FROM AUTHOR]

Enhanced coalbed methane (ECBM) recovery by gas injection is regarded as a feasible method for ECBM recovery. To investigate the mechanism of CH4 displacement by N2 injection, a series of physical experiments were conducted in the laboratory under different N2 injection pressures. The experimental results showed a continuous increase in the N2 volume fraction and a decrease in the CH4 volume fraction with the N2 injection pressure. The CH4 displacement efficiency increases rapidly in the initial stage and then gradually stabilizes. Given the effect of matrix shrinkage and effective stress on coal permeability, a dynamic multi‐field coupling model of ECBM recovery by N2 injection (N2‐ECBM) was proposed in this work. Then, numerical simulations were implemented by the coupling model to analyze the key factors affecting coal permeability, N2 injection pressure and CH4 pressure during the N2–ECBM process. Furthermore, the Response Surface Methodology (RSM) was used to investigate the interactions of multiple factors, the results reveal that an increase in one factor would weaken the influence of another factor. In addition, a RSM regression model was obtained and verified by the experimental data, with a well‐fitting outcomes. Therefore, the RSM model can be used in practical engineering applications to optimize specific extraction parameters for ECBM recovery at minimum cost in a limited extraction period. [ABSTRACT FROM AUTHOR]

Since hydrate resources play a part of the stratigraphic framework structure in sediments, establishing a safe and economic method for hydrates exploitation remains the primary challenge to this day. Among the proposed methods, the spontaneous displacement of CH4 from hydrate cages by CO2 seems to be a perfect mechanism to address gas production and CO2 storage, especially in today's strong demand for carbon reduction and replacing clean energy. After extensive lab researches, in the past decade, injecting a mixture of CO2 and small molecule gas has become a key means to enhance displacement efficiency and has great potential for application. However, there is a lack of in-depth research on gas flow in the reservoir, while the injected gas always passes through low-saturated hydrate areas with high permeability and then occurs gas channel in a short term, finally resulting in the decreases in gas production efficiency and produced gas quality. Therefore, we explored a new injection-production mode of alternate injection of N2 and CO2 in order to fully coordinate the advantages of N2 in enhanced hydrate decomposition and CO2 in solid storage and heat compensation. These alternate "taking" and "storing" processes perfectly repair the problem of the gas channel, achieving self-regulation effect of CH4 recovery and CO2 storage. The 3-D experimental results show that compared to the mixed gas injection, CH4 recovery is increased by >50% and CO2 storage is increased by >70%. Additionally, this alternate injection mode presented a better performance in CH4 concentration of produced gas and showed outstanding N2 utilization efficiency. Further, we analyzed its self-adaptive gas flow mechanism and proposed an application model of "one injection and multiple production". We look forward to this study accelerating the application of CO2-CH4 replacement technology. [ABSTRACT FROM AUTHOR]

Gas injection for enhancing gas recovery (GI–EGR) is a multifaceted process that requires a solid theoretical foundation to be implemented orderly. However, there are limited reports on the micro-mechanisms of GI–EGR technology applied to coalbed methane reservoirs, especially for deep strata. To address this gap, this study utilized molecular simulation techniques to construct the organic pore models of anthracite with varying sizes and morphologies, and explored the micro-dynamic behaviors of CH4 and various gas injected components including N2, CO2 and flue gas confined in nanopores. The aim was to reveal the competitive adsorption mechanisms of gases in multi-component systems under shallow and deep geological conditions. The results demonstrated that the isosteric heats of CH4, N2 and CO2 all increased after the transition from shallow to deep, with rising amplitudes of 18.8%, 22.8% and 17.8%, respectively, in the respective single-component systems. In multi-component adsorption models, the isosteric heats remained higher than those under shallow conditions, but there were some small fluctuations due to the interference between various gases. On the other hand, the self-diffusion coefficients of single CH4, N2 and CO2 in the deep condition decreased by 37.6%, 27.2% and 23.1%, respectively, compared to those in conventional shallow conditions. As a consequence, the difference in diffusivity among various gases would get narrowed. The molecular-level observations herein have the potential to improve the understanding of gas occurrence and lay a solid foundation for the GI–EGR technology. [ABSTRACT FROM AUTHOR]

For field development and drilling decisions, production assets and reservoir engineers require dynamic reservoir properties, such as saturation and pressure changes of a reservoir from the pre‐production virgin state. To date, geophysicists have produced time‐lapse (4D) seismic attributes (mostly on stacked seismic data) rather than dynamic parameters directly. In this paper, we present a new method to estimate saturation and pressure properties from time‐lapse seismic data to provide to reservoir engineers. This new three‐step method is demonstrated over the Edvard Grieg field in the North Sea. We can realize this method thanks to advanced seismic multi‐component acquisition via PP and PS seismic data and processing that allows accurate estimation of amplitude‐variation‐with‐offset parameters P‐ and S‐impedances. With time‐lapse P‐ and S‐impedances optimally resolved, we estimate a stable set of axes identifying water saturation increase (water replacing oil), gas saturation increase (gas injection or gas out of solution), pressure increase (at injectors) and pressure decrease (at producers). Once these axes are obtained, we convert every 4D P‐ and S‐impedance data points into 4D pseudo‐saturation and pseudo‐pressure using a transformation of coordinates. We next use the rock physics relationships of this field to show that a linear relationship can be used to map any 4D change in the field from impedances to saturations and pressures. Key locations in the field with largest saturation and pressure changes are used to find calibration values at these extreme points. Next, from the pseudo‐seismic 4D data, a linear mapping is used to calculate actual reservoir property changes (fractions for saturation and bars for pressure). This allows us to obtain fieldwide dynamic values for water and gas saturations and injection and production related pressure changes. The results are shown, and dynamic changes are interpreted on the Edvard Grieg field data. [ABSTRACT FROM AUTHOR]

The Gas and Downhole Water Sink–Assisted Gravity Drainage (GDWS-AGD) process addresses gas flooding limitations in reservoirs surrounded by infinite-acting aquifers, particularly water coning. The GDWS-AGD technique reduces water cut in oil production wells, improves gas injectivity, and optimizes oil recovery, especially in reservoirs with high water coning. The GDWS-AGD process installs two 7-inch production casings bilaterally. Then, two 2-3/8-inch horizontal tubings are completed. One tubing produces oil above the oil–water contact (OWC) area, while the other drains water below it. A hydraulic packer in the casing separates the two completions. The water sink completion uses a submersible pump to prevent water from traversing the oil column and entering the horizontal oil-producing perforations. To improve oil recovery in the heterogeneous upper sandstone pay zone of the South Rumaila oil field, which has a strong aquifer and a large edge water drive, the GDWS-AGD process evaluation was performed using a compositional reservoir flow model in a 10-year prediction period in comparison to the GAGD process. The results show that the GDWS-AGD method surpasses the GAGD by 275 million STB in cumulative oil production and 4.7% in recovery factor. Based on a 10-year projection, the GDWS-AGD process could produce the same amount of oil in 1.5 years. In addition, the net present value (NPV) given various oil prices (USD 10–USD 100 per STB) was calculated through the GAGD and GDWS-AGD processes. The GDWS-AGD approach outperforms GAGD in terms of NPV across the entire range of oil prices. The GAGD technique became uneconomical when oil prices dropped below USD 10 per STB. Design of Experiments–Latin Hypercube Sampling (DoE-LHS) and radial basis function neural networks (RBF-NNs) were used to determine the optimum operational decision variables that influence the GDWS-AGD process's performance and build the proxy metamodel. Decision variables include well constraints that control injection and production. The optimum approach increased the recovery factor by 1.7525% over the GDWS-AGD process Base Case. With GDWS-AGD, water cut and coning tendency were significantly reduced, along with reservoir pressure, which all led to increasing gas injectivity and oil recovery. The GDWS-AGD technique increases the production of oil and NPV more than the GAGD process. Finally, the GDWS-AGD technique offers significant improvements in oil recovery and income compared to GAGD, especially in reservoirs with strong water aquifers. [ABSTRACT FROM AUTHOR]

In terms of the collaborative optimization of CO2 flooding for Enhanced Oil Recovery (EOR) and CO2 sequestration, previous studies have co-optimized both cumulative oil production and CO2 sequestration by various algorithms. However, these solutions fail to optimize the CO2 injection schemes for high-water cut oil reservoirs. This paper presents an optimization methodology for CO2 flooding and sequestration in high-water cut oil reservoirs. The production optimization was carried out by adjusting the injection and production rate. To solve the proposed objective functions, the simultaneous perturbation stochastic approximation (SPSA) algorithm is applied in this paper, and the CMG-GEM module is utilized to simulate the reservoir production performance. A typical high-water cut reservoir in the Shengli oilfield was used to verify the feasibility of the presented methodology. In this paper, the production performance and net present value (NPV) for continuous gas injection under different water cuts were analyzed. The optimal timing of transforming from water flooding to gas displacement for the high-water cut reservoir was optimized. In addition, the optimal water–gas ratios for Water-Alternating-Gas (WAG) flooding were determined. The sensitivity of NPV to gas injection price and carbon subsidy was analyzed. The results show that when the gas price is 0.178 $/m3 and the carbon subsidy is 0.0169 $/m3, the optimal timing of transforming from water flooding to gas injection should be earlier than the time when the water cut is 0.82. Through the combination of NPV, cumulative oil production rate, and CO2 sequestration volume for WAG flooding, the optimal WAG ratio should be 1:2. The presented method in this paper considers various economic indicators and can optimize CO2 flooding and sequestration in high-water cut oil reservoirs efficiently, which can provide some guidance for the design of CO2 flooding schemes in high-water cut oil reservoirs. [ABSTRACT FROM AUTHOR]

The objective of this study is to develop an analytical model for 1D gas‐water flow with evaporation of water into the mobile gas phase. The evaporation rate is proportional to the fluid‐fluid interfacial area, which is a function of the water saturation. Introduction of saturation‐dependent potential allows reducing the 2 × 2 non‐linear system of PDEs to one hyperbolic equation. The saturation distribution is obtained by non‐linear method of characteristics. The first integral allows for explicit expression of the vapor concentration versus saturation. It was shown that typical properties of rock‐CO2‐water system, the evaporation time has order of magnitude of millions of pore volumes injected. Close match was observed between a series of three corefloods and the analytical model, and the tuned model coefficients belong to their common intervals. This validates the developed model for 1D gas‐water flow with water evaporation into the injected gas. Plain Language Summary: During injection of carbon dioxide or other gases into porous media containing small fractions of water, the water phase will slowly evaporate into the injected gas. This process is important as the gradual drying of the porous media near the injection site can lead to formation damage processes such as fines migration and salt precipitation, resulting in a significant decline in the ability to inject more gas. The evaporation process is dependent on the interfacial area between the gas and water. As the evaporation process progresses, this area gets smaller, and the evaporation rate slows down. In this work, we account for this effect directly, and solve the resulting differential equations, providing simple equations that can be used to predict the rate of water evaporation during gas injection. Key Points: Exact solution of gas transport in porous media with non‐equilibrium evaporation kinetics is obtainedThe new solution relies on introducing a new potential function, which reduces the system of non‐linear PDEs to one equationThe resulting exact solution shows good agreement with laboratory data and can predict accurately the evaporation time [ABSTRACT FROM AUTHOR]

Due to the increasing world population and environmental considerations, there has been a tremendous interest in alternative energy sources. Hydrogen plays a major role as an energy carrier due to its environmentally benign nature. The combustion of hydrogen releases water vapor while it also has a vast industrial application in aerospace, pharmaceutical, and metallurgical industries. Although promising, hydrogen faces storage challenges. Underground hydrogen storage (UHS) presents a promising method of safely storing hydrogen. The selection of the appropriate cushion gas for UHS is a critical aspect of ensuring the safety, efficiency, and reliability of the storage system. Cushion gas plays a pivotal role in maintaining the necessary pressure within the storage reservoir, thereby enabling consistent injection and withdrawal rates of hydrogen. One of the key functions of the cushion gas is to act as a buffer, ensuring that the storage pressure remains within the desired range despite fluctuations in hydrogen demand or supply. This is achieved by alternately expanding and compressing the cushion gas during the injection and withdrawal cycles, thereby effectively regulating the overall pressure dynamics within the storage facility. Furthermore, the choice of cushion gas can have significant implications on the performance and long-term stability of the UHS system. Factors such as compatibility with hydrogen, cost-effectiveness, availability, and environmental impact must be carefully considered when selecting the most suitable cushion gas. The present study provides a comprehensive review of different types of cushion gases commonly used in UHS, including nitrogen, methane, and carbon dioxide. By examining the advantages, limitations, and practical considerations associated with each option, the study aims to offer valuable insights into optimizing the performance and reliability of UHS systems. Ultimately, the successful implementation of UHS hinges not only on technological innovation but also on strategic decisions regarding cushion gas selection and management. By addressing these challenges proactively, stakeholders can unlock the full potential of hydrogen as a clean and sustainable energy carrier, thereby contributing to the global transition towards a low-carbon future. [ABSTRACT FROM AUTHOR]

To analyze the self-sealing process in the Callovo-Oxfordian claystone, self-sealing tests were performed on initially fractured samples under different temperatures with water and gas injection. Cylindrical samples oriented in parallel and perpendicularly to the bedding plane with an artificial initial fracture were used in a triaxial compression cell transparent to X-rays. Water and gas permeability were measured and the evolution of cracks volume was analyzed from X-ray tomography 3D images to characterize the self-sealing process. All tests performed at 20 °C with water injection showed a rapid drop in permeability at the beginning followed by a progressive decrease and a stabilization after one month. The permeability of fractured samples decreases significantly after self-sealing but is still higher (by 2 orders of magnitude) than the permeability of healthy claystone. Otherwise, the less calcite the sample contains (i.e., the more clayey it is), the faster the crack self-seals. The smaller the opening of the initial crack is, the faster the water permeability decreases and the crack closes. No significant influence of the sample orientation on the self-sealing kinetic was identified at this stage. It seems that high temperature has a slight retarding effect on the self-sealing process. For the test with water and gas injection, the injection of gas delays the decrease of water permeability and the self-sealing process, which is probably due to the crack desaturation induced by gas injection. Highlights: Self-sealing tests were performed on initially fractured samples of Callovo-Oxfordian claystone with different temperatures, orientations and fluids (water, gas). Self-sealing process was analyzed thanks to permeability measurements and crack volume estimation from X-ray tomography 3D images. The self-sealing process is fast at the beginning of the test and stabilizes after about one month and the initial permeability of the healthy rock is partially restored. The less calcite the sample contains (the more clayey it is) and the smaller the opening of the initial crack is, the faster the crack self-seals. Temperature and gas seem to have a delay effect on the self-sealing process. There is no significant influence of the sample orientation. [ABSTRACT FROM AUTHOR]

In the geological disposal of high-level radioactive waste in argillaceous rocks, studying the barrier integrity after gas transport and the pathway closure thanks to self-sealing capacity is a crucial aspect for the safety assessment. This paper presents experimental research in Boom Clay (a potential host rock in Belgium) to evaluate the effectiveness of self-sealing and possible fissure reactivation during a second gas invasion event. Initial water permeability under oedometer conditions was first measured on samples at two bedding orientations, being higher the sample with bedding planes parallel to flow, highlighting marked anisotropy. Then, gas injection tests at a constant volume rate were performed. Results indicated that Boom Clay underwent expansion and degradation during gas injection due to the development of fissures that were quantified using microstructural techniques. The computed effective gas permeability was not significantly dependent on bedding orientation and was slightly larger than the initial intrinsic water permeability. The re-saturation of the samples led to a recovery of the initial water permeability for both orientations, replicating the original anisotropy. The microstructural analyses confirmed the gas pathways' closure, indicating good self-sealing and the regaining of the hydraulic barrier function. However, a small volume of large unconnected pores was detected on undrained unloading before the microstructural study. An additional gas injection after the self-sealing resulted in a higher effective gas permeability and a larger increase in pore volume, suggesting the reopening of fissures generated during the first injection. Finally, the experimental data were compiled within a multi-scale phenomenological model to relate the microstructural information to macroscopic flow transport properties capturing the intrinsic permeability increase on gas invasion and its recovery during self-sealing. Highlights: Gas transport on Boom Clay occurs along fissures, increasing its permeability The re-saturation process induces the recovery of the initial water permeability, demonstrating an excellent self-sealing capacity. A subsequent gas injection after the re-saturation suggests the reopening of previous gas paths. A multi-scale model is proposed to account for the permeability changes derived from a microstructural damage variable. [ABSTRACT FROM AUTHOR]

In quasi-two-dimensional conditions, different invasion patterns can be observed when a fluid displaces another fluid with a higher viscosity. The transition from interfacial instability to fracture during gas invasion remained poorly understood, and classification criteria for different invasion patterns demanded further improvement. In this study, single-point compressed gas injection experiments were conducted in magnesium lithium phyllosilicate (MLPS) suspensions in a rectangular Hele-Shaw cell. Interestingly, with the increase of the injection pressure and the decrease of the concentration of MLPS suspension, the gas invasion pattern underwent a transition from viscous elastic fracture, elastic fracture, elastic viscous fingering to viscous fingering, in which viscous elastic fracture was observed for the first times. We detailly discuss the characteristics and occurrence conditions of each invasion pattern. Furthermore, by analyzing the velocity field of each invasion pattern, it is found that the relationship between the velocity direction around the gas and the gas growth direction varies with different invasion patterns. A simple and effective quantitative indicator is constructed to distinguish the different invasion patterns. Following the identification of invasion patterns, a further investigation was conducted into the relationship between invasion patterns and experimental conditions. By utilizing the relationships among injection conditions and material rheological properties, two dimensionless numbers, Bingham number and Weissenberg number, are conducted, which have an impact on the various invasion patterns and invasion process. A unified phase diagram based on the Bingham number and Weissenberg number was also proposed to incorporate the possible gas invasion patterns in the MLPS suspension. [ABSTRACT FROM AUTHOR]

We studied the electron spin resonance (ESR) spectra of nitrogen atoms stabilized in nitrogen-neon nanoclusters immersed in superfluid 4 He. The nanoclusters were formed during the condensation of the products of the discharge in N 2 –Ne–He gas mixtures into bulk superfluid 4 He at temperature 1.5 K. We studied nanoclusters formed by injection of gas mixtures with different ratios of heavy impurities in the helium N 2 /(Ne + N 2 ) ranging from 2% to 90%. Analysis of the ESR spectra of nitrogen atoms stabilized in nitrogen-neon nanoclusters provides important information about the environment of the stabilized atoms and a shell structure of the nanoclusters was revealed. For all samples studied, preferential stabilization of N atoms on the surfaces of the nanoclusters was observed. Annealing of the collection of the nanoclusters in the temperature range 1.1–10 K resulted in substantial changes in the structure of the nanoclusters. [ABSTRACT FROM AUTHOR]

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The fault cavern type reservoir in Block 1 of Shunbei area is located in the ultra-deep layer and is classified as a volatile oil reservoir. The reservoir is characterized by very deep burial with an oil/gas ratio between 250 and 500 m3/tone and a saturation pressure range of 28-36 MPa. As of March 2021, the formation pressure has dropped to 30.5 MPa and the pressure retention rate is 35.8%. In order to effectively develop this reservoir, it was decided to use a water injection development method with a planned transition to natural gas injection in March 2022 to further enhance recovery and maintain formation pressure. Through evaluation and research, the pressure distribution, production capacity change and reservoir dynamic response during the water injection development stage were analyzed with respect to the characteristics of fracture-controlled fracture-cave type reservoir in Shunbei-1 block. On this basis, the necessity, feasibility, and expected effects of conversion to natural gas injection are explored, including improvement of displacement efficiency, reduction of fluid output, and enhancement of formation energy replenishment. In addition, this study also carries out in-depth research and prediction on the optimization of natural gas injection parameters, the selection of injection methods and possible problems, aiming to provide scientific basis and technical support for the efficient and sustainable development of this block. In order to smoothly promote the implementation of natural gas injection development, a special reservoir description technique applicable to fault cavern type reservoirs was adopted. Based on this foundation, an in-depth study was conducted on the mechanism of natural gas displacement, so as to optimize the layout of the well network and the setting of injection and extraction parameters. In addition, a set of evaluation system for natural gas injection effect in fault cavern type reservoirs was constructed. By adopting the natural gas injection development method and combining the corresponding supporting technology development and optimization measures, the reservoir development efficiency and oil (gas) production rate have been effectively improved, and the risk of gas flaring has been reduced at the same time. These research results are of great significance for ensuring the comprehensive development and effective utilization of oil and gas resources, and provide strong technical support for future development work. [ABSTRACT FROM AUTHOR]

Foam flooding has been successfully implemented in solving problems that arise during gas flooding as it increases gas viscosity and reduces gas relative permeability resulting in favorable mobility ratios and better volumetric sweep efficiency. This research study aims to evaluate the effect of different flood patterns on field performance during foam enhanced oil recovery. A three-dimensional reservoir simulation model was developed with a reservoir simulator and each flood pattern including normal and inverted four, five, seven, and nine-spots were modeled and simulated separately under consistent conditions of field gas injection rate, bottom-hole pressure of production wells, and surfactant concentration. Field Oil Efficiency (FOE), Net Present Value (NPV), Rate of Return (ROR), and Payout Time (POT) were used in making comparisons. An Original Oil in Place of 139.43 MMSTB was found at the initialization. Simulation results showed that a normal and an inverted five-spot pattern were more effective in their respective categories as they resulted respectively in higher FOE, lower FGOR, higher NPV and ROR, and shorter POT. An inverted five-spot resulted in an FOE of 4.36 %, an NPV of $ 83.48 million, and an ROR of 13.64% higher than that obtained for a normal five spot, and a payout time of 1.54 years shorter than that obtained for the normal five spots. The findings highlight the superior efficiency of the normal and inverted five-spot patterns, with the inverted five-spot pattern demonstrating significantly better performance in terms of FOE, NPV, ROR, and POT. Based on the presented results, an inverted five-spot pattern was recommended in this paper as the best flood pattern during foam-enhanced oil recovery applications. [ABSTRACT FROM AUTHOR]

Carbon geological storage (CGS) is one of the key processes in carbon capture and storage (CCS) technologies, which are used to reduce CO2 emissions and achieve carbon-neutrality and net-zero emissions in developing countries. In Thailand, the Mae Moh basin is a potential site for implementing CGS due to the presence of a structural trap that can seal the CO2 storage formation. However, the cost of CGS projects needs to be subsidized by selling carbon credits in order to reach the project breakeven. Therefore, this paper estimates the economic components of a CGS project in the Mae Moh basin by designing the well completion and operating parameters for CO2 injection. The capital costs and operating costs of the process components were calculated, and the minimum carbon credit cost required to cover the total costs of the CGS project was determined. The results indicate that the designed system proposes an operating gas injection rate of 1.454 MMscf/day, which is equivalent to 29,530 tCO2e per year per well. Additionally, the minimum carbon credit cost was estimated to be USD 70.77 per tCO2e in order to achieve breakeven for the best case CGS project, which was found to be much higher than the current market price of carbon credit in Thailand, at around USD 3.5 per tCO2e. To enhance the economic prospects of this area, it is imperative to promote a policy of improving the cost of carbon credit for CGS projects in Thailand. [ABSTRACT FROM AUTHOR]