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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]

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]

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]

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]

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]

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]

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]

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]

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]

Extralow-permeability reservoirs have emerged as a significant area of focus for CO2 geological sequestration due to their stable subterranean structure and expansive storage capacity, offering substantial potential in addressing global climate change. However, the full extent of CO2 geological sequestration potential within these extralow-permeability reservoirs remains largely unexplored. To address this gap, this paper utilizes the Shahejie Formation (Es1 member) of the Shuang 229 block in the Liaohe oilfield, Bohai Bay Basin, as a case study. This section is characterized by its abundant oil-gas reserves and serves as an exemplar for conducting experimental research on CO2 storage within extralow-permeability reservoirs. The results demonstrate that the reservoir lithology of the Es1 member is fine sandstone and siltstone, with high compositional and structural maturity. Moreover, the average porosity is 14.8%, the average permeability is 1.48 mD, and the coefficient of variation of the reservoir is approximately 0.5, which indicates a low- to extralow-permeability homogeneous reservoir. In addition, the overburden pressure is >2.0 MPa, the fault can withstand a maximum gas column height of >200 m, and the reservoir exhibits favorable overburden and fault sealing characteristics. Notably, stepwise increasing gas injection in the Shuang 229-36-62 well reveals that the injected liquid CO2 near the wellhead exhibits a relatively high density, close to 1.0 g/cm3, which gradually decreases to approximately 0.78 g/cm3 near a depth of 2000 m underground. The injected fluid changes into a supercritical state upon entering the formation, and the CO2 injection speed is optimal, at 0.08 HCPV/a. According to these findings, it is predicted that the highest burial CO2 volume via the injection of 1.5 HCPVs in the Wa 128 block area is 1.11 × 105 t/year, and the cumulative burial volume reaches approximately 2.16 × 106 t. This shows that the CO2 sequestration potential of extralow-permeability reservoirs is considerable, providing confidence for similar instances worldwide. [ABSTRACT FROM AUTHOR]

Multi-stage fractured horizontal well technology is an effective development method for unconventional reservoirs; however, shale oil reservoirs with ultra-low permeability and micro/nanopore sizes are still not ideal for production and development. Injecting CO2 into the reservoir, after hydraulic fracturing, gas injection flooding often produces a gas channeling phenomenon, which affects the production of shale oil. In comparison, CO2 huff-n-puff development has become a superior method in the development of multi-stage fractured horizontal wells in shale reservoirs. CO2 huff and injection can not only improve shale oil recovery but also store the CO2 generated in industrial production in shale reservoirs, which can reduce greenhouse gas emissions to a certain extent and achieve carbon capture, utilization, and storage (CCUS). In this paper, the critical temperature and critical parameters of fluid in shale reservoirs are corrected by the critical point correction method in this paper, and the influence of reservoir pore radius on fluid phase behavior and shale oil production is analyzed. According to the shale reservoir applied in isolation to the actual state of the reservoir and under the condition of a complex network structure, we described the seepage characteristics of shale oil and gas and CO2 in the reservoir by embedding a discrete fracture technology structure and fracture network, and we established the numerical model of the CO2 huff-n-huff development of multi-stage fractured horizontal wells for shale oil. We used the actual production data of the field for historical fitting to verify the validity of the model. On this basis, CO2 huff-n-puff development under different gas injection rates, huff-n-puff cycles, soaking times, and other factors was simulated; cumulative oil production and CO2 storage were compared; and the influence of each factor on development and storage was analyzed, which provided theoretical basis and specific ideas for the optimization of oilfield development modes and the study of CO2 storage. [ABSTRACT FROM AUTHOR]

Conventional recovery enhancement techniques are aimed at reducing the abandonment pressure, but there is an upper limit for recovery enhancement due to the energy limitation of reservoirs. Gas injection for energy supplementation has become an effective way to enhance gas recovery by reducing hydrocarbon saturation in gas reservoirs. This review systematically investigates progress in gas injection for enhanced gas recovery in three aspects: experiments, numerical simulations and field examples. It summarizes and analyzes the current research results on gas injection for EGR and explores further prospects for future research. The research results show the following: (1) Based on the differences in the physical properties of CO2, N2 and natural gas, effective cushion gas can be formed in bottom reservoirs after gas injection to achieve the effects of pressurization, energy replenishment and gravity differentiation water resistance. However, further experimental evaluation is needed for the degree of increase in penetration ability. (2) It is more beneficial to inject N2 before CO2 or the mixture of N2 and CO2 in terms of EGR effect and cost. (3) According to numerical simulation studies, water drive and condensate gas reservoirs exhibit significant recovery effects, while CO2-EGR in depleted gas reservoirs is more advantageous for burial and storage; current numerical simulations only focus on mobility mass and saturation changes and lack a mixed-phase percolation model, which leads to insufficient analysis of injection strategies and a lack of distinction among different gas extraction effects. Therefore, a mixed-phase-driven percolation model that can characterize the fluid flow path is worth studying in depth. (4) The De Wijk and Budafa Szinfelleti projects have shown that gas injection into water drive and depleted reservoirs has a large advantage for EGR, as it can enhance recovery by more than 10%. More experiments, simulation studies and demonstration projects are needed to promote the development of gas injection technology for enhanced recovery in the future. [ABSTRACT FROM AUTHOR]

Closed-cell aluminum foams have many excellent properties, such as low density, high specific strength, great energy absorption, good sound absorption, electromagnetic shielding, heat and flame insulation, etc. As a new kind of material, closed-cell aluminum foams have been used in lightweight structures, traffic collision protections, sound absorption walls, building decorations, and many other places. In this paper, the recent progress of closed-cell aluminum foams, on fabrication techniques, including the melt foaming method, gas injection foaming method, and powder metallurgy foaming method, and on processing techniques, including powder metallurgy foaming process, two-step foaming process, cast foaming process, gas injection foaming process, mold pressing process, and integral foaming process, are summarized. Properties and applications of closed-cell aluminum foams are discussed based on the mechanical properties and physical properties separately. Special focuses are made on the newly developed cast-forming process for complex 3D parts and the improvement of mechanical properties by the development of small pore size foam fabrication and modification of cell wall microstructures. [ABSTRACT FROM AUTHOR]

Gas-enhanced oil recovery (EOR) through huff-n-puff (HnP) is an important method of recovering oil from fracture-stimulated reservoirs. HnP productivity is hampered by fracture channeling, leading to early gas breakthroughs and gas losses. To mitigate these issues, foam-generating surfactants have been developed as a method of reducing injected gas phase mobility and increasing oil recovery. This work investigates foam generation and propagation by a proprietary surfactant blend in high-temperature, high-pressure, high-permeability, and high-shear conditions that simulate the environment of a proppant-packed fracture. Bulk foam tests confirmed the aqueous stability and foaming viability of the surfactant at the proposed conditions. Through several series of floods co-injecting methane gas and the surfactant solution through a proppant pack at residual oil saturation, the effects of several injection parameters on apparent foam viscosity were investigated. The foam exhibited an exceptionally high transition foam quality (>95%) and strong shear-thinning behavior. The foam viscosity also linearly decreased with increasing pressure. Another flood series conducted in an oil-free proppant pack showed that swelling of residual oil had no effect on the apparent foam viscosity and was not the reason for the inversely linear pressure dependency. An additional flood series with nitrogen as the injection gas was completed to see if the hydrophobic attraction between the methane and surfactant tail was responsible for the observed pressure trend, but the trend persisted even with nitrogen. In a previous study, the dependence of foam viscosity on pressure was found to be much weaker with a different foaming surfactant under similar conditions. Thus, a better understanding of this important phenomenon requires additional tests with a focus on the effect of pressure on interfacial surfactant adsorption. [ABSTRACT FROM AUTHOR]

Background: Despite the growing interest in CO2 angiography, some mechanical aspects related to CO2 injection still need to be deepened, and some improvements are still possible. This work explores the possibility of optimizing gas injection into small-sized arteries. Since the image quality depends on how the gas fills the vessel and is strongly dependent on injection flow, the possibility of controlling the flow is mandatory to obtain good results. To better control the flow, we propose to adjunct small tubes with known hydraulic resistances in parallel to the injection catheter, allowing the generation of the desired injection flow by modulating the injection pressure. Methods: Using a mechanical mock of the cardiovascular system, we measured pressures and flows of interest and acquired the optical images of the vessel during gas injections. We performed a simulation with four different calibrated adjunct resistances in various injection pressure conditions, with and without saline flushing. Results: Our tests demonstrated that the optimized injection of the gas maintains the same procedure durations and reduces the gas volume and the local pressure increase, avoiding the local gas "explosion" in the injection site. Conclusions: Our proposal appears effective and paves the way for research into optimizing clinical CO2 angiography procedures. [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]

A solid-phase microextraction (SPME) injection gas chromatography was validated with the flame ionization detection method (GC-FID) using a capillary column to detect ethanol. The method was used to determine ethanol in fluids with biomedical, clinical, and forensic importance, including water, phosphate-buffered saline (PBS), and artificial sweat. The strategy produced good peak resolution and showed a linear correlation between the concentration and peak areas for ethanol in all matrices. The inter- and intra-day precisions of the method were below 15.5% and 6.5%, respectively, varying according to the matrix. The method achieved detection limits below 1.3 mg/L, varying according to the matrix. Lower limits were obtained for the aqueous solution (0.22 mg/L), followed by the PBS solution (0.96 mg/L), and finally, the sweat solution (1.29 mg/L). This method is easy to perform and suitable for use in routine clinical biochemistry and forensic laboratories, allowing ethanol detection at lower concentrations using lower temperature and time of extraction, when compared with other studies. [ABSTRACT FROM AUTHOR]

CO2 flooding is a pivotal technique for significantly enhancing oil recovery in low-permeability reservoirs. The movement and sweeping rules at the front of CO2 flooding play a critical role in oil recovery; yet, a comprehensive quantitative analysis remains an area in need of refinement. In this study, we developed 1-D and 2-D numerical simulation models to explore the sweeping behavior of miscible, immiscible, and partly miscible CO2 flooding patterns. The front position and movement rules of the three CO2 flooding patterns were determined. A novel approach to the contour area calculation method was introduced to quantitatively characterize the sweep coefficients, and the sweeping rules are discussed regarding the geological parameters, oil viscosity, and injection–production parameters. Furthermore, the Random Forest (RF) algorithm was employed to identify the controlling factor of the sweep coefficient, as determined through the use of out-of-bag (OOB) data permutation analysis. The results showed that the miscible front was located at the point of maximum CO2 content in the oil phase. The immiscible front occurred at the point of maximum interfacial tension near the production well. Remarkably, the immiscible front moved at a faster rate compared with the miscible front. Geological parameters, including porosity, permeability, and reservoir thickness, significantly impacted the gravity segregation effect, thereby influencing the CO2 sweep coefficient. Immiscible flooding exhibited the highest degree of gravity segregation, with a maximum gravity segregation degree (GSD) reaching 78.1. The permeability ratio was a crucial factor, with a lower limit of approximately 5.0 for reservoirs suitable for CO2 flooding. Injection–production parameters also played a pivotal role in terms of the sweep coefficient. Decreased well spacing and increased gas injection rates were found to enhance sweep coefficients by suppressing gravity segregation. Additionally, higher gas injection rates could improve the miscibility degree of partly miscible flooding from 0.69 to 1.0. Oil viscosity proved to be a significant factor influencing the sweep coefficients, with high seepage resistance due to increasing oil viscosity dominating the miscible and partly miscible flooding patterns. Conversely, gravity segregation primarily governed the sweep coefficient in immiscible flooding. In terms of controlling factors, the permeability ratio emerged as a paramount influence, with a factor importance value (FI) reaching 1.04. The findings of this study can help for a better understanding of sweeping rules of CO2 flooding and providing valuable insights for optimizing oil recovery strategies in the field applications of CO2 flooding. [ABSTRACT FROM AUTHOR]

Ladle metallurgy serves as a crucial component of the steelmaking industry, where it plays a pivotal role in manipulating the molten steel to exercise precise control over its composition and properties. Turbulence in ladle metallurgy influences various important aspects of the steelmaking process, including mixing and distribution of additives, alongside the transport and removal of inclusions within the ladle. Consequently, gaining a clear understanding of the stirred flow field holds the potential of optimizing ladle design, improving control strategies, and enhancing the overall efficiency and steel quality. In this project, an advanced Particle-Tracking-Velocimetry system known as "Shake-the-Box" is implemented on a cylindrical water ladle model while compressed air injections through two circular plugs positioned at the bottom of the model are employed to actively stir the flow. To mitigate the particle images distortion caused by the cylindrical plexi-glass walls, the method of refractive matching is utilized with an outer polygon tank filled with a sodium iodide solution. The volumetric flow measurement is achieved on a 6 × 6 × 2 cm domain between the two plugs inside the cylindrical container while the flow rate of gas injection is set from 0.1 to 0.4 L per minute. The volumetric flow field result suggests double gas injection at low flow rate (0.1 L per minute) produce the least disturbed flow while highly disturbed and turbulent flow can be created at higher flow rate of gas injection. [ABSTRACT FROM AUTHOR]

The bottomhole pressure is one of the key parameters for oilfield development and decision-making. However, due to factors such as cost and equipment failure, bottomhole pressure data is often lacking. In this paper, we established a GA-XGBoost model to predict the bottomhole pressure in carbonate reservoirs. Firstly, a total of 413 datasets, including daily oil production, daily water production, daily gas production, daily liquid production, daily gas injection rate, gas–oil ratio, and bottomhole pressure, were collected from 14 wells through numerical simulation. The production data were then subjected to standardized preprocessing and dimensionality reduction using a principal component analysis. The data were then split into training, testing, and validation sets with a ratio of 7:2:1. A prediction model for the bottomhole pressure in carbonate reservoirs based on XGBoost was developed. The model parameters were optimized using a genetic algorithm, and the average adjusted R-squared score from the cross-validation was used as the optimization metric. The model achieved an adjusted R-squared score of 0.99 and a root-mean-square error of 0.0015 on the training set, an adjusted R-squared score of 0.84 and a root-mean-square error of 0.0564 on the testing set, and an adjusted R-squared score of 0.69 and a root-mean-square error of 0.0721 on the validation set. The results demonstrated that in the case of fewer data variables, the GA-XGBoost model had a high accuracy and good generalization performance, and its performance was superior to other models. Through this method, it is possible to quickly predict the bottomhole pressure data of carbonate rocks while saving measurement costs. [ABSTRACT FROM AUTHOR]

Low-tension gas (LTG) flooding has been proven in lab-scale experiments to be a viable tertiary enhanced oil recovery (EOR) technique in low-permeability (~10 mD) oil-wet carbonates. Work carried out previously almost exclusively focused on water-wet cores. The application of LTG in oil-wet carbonates is investigated in this study along with the impact of a hydrocarbon (HC) mixture as the injection gas on oil–water microemulsion phase behavior. The optimum injection gas fraction (ratio of gas injection rate to total injection rate of gas and water) for the hydrocarbon gas mixture in oil-wet carbonates regarding the oil recovery rate was determined to be 60% as it resulted in around 50% residual oil in place (ROIP) recovery. It was shown that proper mobility control can be achieved under these conditions even in the absence of strong foam. The effect of HC gas dissolution in oil was clearly shown by replacing the injection HC gas with nitrogen under the same conditions. Furthermore, the importance of ultra-low interfacial tension (IFT) produced by the injection gas and surfactant slug is proven by comparing injection at sub-optimum salinity to injection at optimum salinity. [ABSTRACT FROM AUTHOR]

This study provides insights into the experience gained from the investigation of the dynamic behavior of a mature sour hydrocarbon reservoir modeling under an acid gas re-injection process production strategy. The primary objective was to analyze and evaluate the production behavior of proposed injection zones by assessing various injection scenarios and obtaining oil production over time. To achieve that, a workflow was developed to prioritize potential injection areas, select the optimal wells, determine the optimal operational parameters and optimize a pilot application design based on expected performance. Within this framework, the study encompasses diverse acid gas injection schemes on a pilot scale approach, including acid gas combined with waterflooding. The outcome of this analysis will eventually lead to the identification of the most promising and highest-performing injection scheme, elucidating the optimal range of operating parameters. This optimal combination forms the basis for the economic analysis of the venture and the subsequent detailed design of a full-scale application, where real-world implementation will validate the projected results. [ABSTRACT FROM AUTHOR]

High-quality steels are defined primarily by a small quantity of non-metallic inclusions and a high degree of chemical homogenisation. The ladle furnace (LF) is the most important metallurgical unit in which the quantity of non-metallic inclusions can be significantly reduced while ensuring metal chemical homogenisation. It is achieved largely due to appropriate controlling and the use of increasingly developed inert gas purging techniques. Various types of porous plugs (channel or radial type) are used in the metallurgical ladles. In aggregate units of intermediate-ladle type, various types of channel plugs and/or gas curtains are successfully used. In the research presented herein, a new and innovative module for inert gas injection into liquid steel for deep refining was tested. The presented research relates to the innovative module using to replace the standard porous plug in the steelmaking ladle on the outside-furnace (LF) processing station. Hybrid modelling methods (numerical and physical modelling) were used to carry out research. Module using causes significantly faster alloy additive dispersion in ladle volume compared with the standard solution (the standard porous plug). Furthermore, the obtained flowing structure positively affects liquid steel refining and mixing processes after alloy additive addition. A new technological solution, i.e., gas-injection module—differs from the traditional porous plugs currently used in the steel mills in terms of geometric parameters, external and internal structure, and what is most importantly, terms of the active surface area—shall be understood in as the surface area wherein slots occur. [ABSTRACT FROM AUTHOR]

Gel systems are widely used as plugging materials in the oil and gas industry. Gas channeling can be mitigated by reducing the heterogeneity of the formation and the mobility ratio of CO2 to crude oil. Cracks and other CO2 leaking pathways can be plugged during the geological storage of CO2 to increase the storage stability. By adding CO2-responsive groups to the classic polymer gel's molecular chain, CO2 responsive gel is able to seal and recognize CO2 in the formation while maintaining the superior performance of traditional polymer gel. The application of CO2 responsive gels in oil and gas production is still in the stage of laboratory testing on the whole. To actually achieve the commercial application of CO2 responsive gels in the oil and gas industry, it is imperative to thoroughly understand the CO2 responsive mechanisms of the various types of CO2 responsive gels, as well as the advantages and drawbacks of the gels and the direction of future development prospects. This work provides an overview of the research progress and response mechanisms of various types of CO2 responsive groups and CO2 responsive gels. Studies of the CO2 responsive gel development, injectivity, and plugging performance are comprehensively reviewed and summarized. The shortcomings of the existing CO2 responsive gels system are discussed and the paths for future CO2 responsive gel development are suggested. [ABSTRACT FROM AUTHOR]

Windows in new buildings in Korea are equipped with double or triple glazing, a low-E coating, and gas injection between the panes of glass, in accordance with the regulations for the reinforced insulation of windows. However, these windows have certain issues, such as thermal transmittance variations and injected gas leakage. In this study, we investigated the current status of double-glazed windows filled with argon gas and analyzed the actual deterioration degree in terms of insulation performance via field experiments and simulations. Accordingly, we manufactured a 26-millimeter low-E double-glazed window test specimen and conducted tests in accordance with the KS F 2278 standard. The test results indicated that the thermal performance decreased by 10.9% when the argon gas filling rate was reduced from 95% to 0%. The simulation results showed that the thermal performance of windows that were insulated using only glazing decreased by 22.6% with the decrease in the argon gas filling rate; the thermal performance of the double-glazed windows also decreased by 13.6%. A comprehensive analysis of the field surveys and simulations predicted a 92% probability that the argon gas filling rate of double-glazed windows would be below 65% by two years after completion, in addition to a ~4.3% decrease in thermal performance. [ABSTRACT FROM AUTHOR]

Fractured-vuggy reservoirs are known for containing substantial amounts of oil in high positions of reservoir, even after natural energy development and water injection development. However, due to their poor physical properties and fracture distribution, gas channeling becomes a common occurrence when injecting large amounts of gas, which hinders the formation of an effective gas cap, resulting in reduced oil displacement efficiency. This phenomenon results in a lengthy period of effective gas cap formation and reduces the oil displacement efficiency of an artificial gas cap. In this paper, according to the actual geological characteristics, logging data, and production data, the mechanism model and the numerical model of Oilfield A are established. The variation law of flow potential difference before and after gas injection channeling is studied by simulation, and the control method of artificial gas cap gas channeling in fractured-vuggy reservoir is put forward. The results show that the production gas–oil ratio method is the most convenient and practical in the oil field, and the flow potential difference can effectively predict the occurrence of gas channeling. It likely occurs when the ratio of flow potential difference between injection and production wells is less than 0.972. Gas channeling can be controlled effectively by altering the energy of position and pressure, as well as body measures including injection–production well pattern adjustment, injection–production parameter optimization. This technology provides a new approach for controlling gas channeling through gas cap drive in fractured-vuggy reservoirs. After the implementation of this technology, the effect is obvious, and can effectively improve the efficiency of gas top oil displacement and save costs. This gas channeling control technology is of great significance for the development of fractured-vuggy reservoirs. [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]

The development of shale oil often encounters a series of challenges, such as insufficient natural energy, rapid declines in production, and low oil recovery. Given its wide availability and low cost, natural gas serves as an ideal injection medium to enhance shale oil recovery. Based on the foundational data from Chang 7 block X in the Ordos Basin and considering the influence of reservoir stress sensitivity, this study uses numerical simulation methods in conjunction with the random forest algorithm to examine gas flooding in shale oil. This research aims to identify the key factors influencing the effectiveness of natural gas flooding for shale oil and to establish a chart for the adaptive natural gas flooding development boundary. The findings suggest that, for reservoirs with permeability less than 0.2 × 10−3 μm2 and oil saturation below 55%, it is advisable to adopt longer fracture lengths during hydraulic fracturing to achieve better development results. After 10 years of gas flooding, continuing the use of this method is not recommended, and adjusting of the development strategy becomes essential. For extended development periods, avoiding long-length fractures is crucial to mitigate gas channeling and ensure the effectiveness of the development process. This study offers theoretical guidance and technical support for developing shale reservoirs with natural gas flooding. [ABSTRACT FROM AUTHOR]

The conventional liquid acid has several shortcomings in the acidizing process of fractured-vuggy carbonate reservoirs, including high filtration loss, fast reaction rate, high friction resistance, and difficult flowback. To address these issues, a new atomizing acid acidizing technology is proposed, combining the gas injection development practice from the fractured-vuggy carbonate reservoir in the Tahe oilfield. The laboratory experiments were conducted to optimize the type and concentration of atomized acid, iron ion stabilizer, corrosion inhibitor, and atomization stabilizer. The acid atomization rate was evaluated under different combinations of gas and liquid injection flows using a self-made atomized acid well migration simulator, and the best atomization scheme was selected. Furthermore, a kinetic experiment for the acid–rock reaction was carried out to evaluate the retarding performance of the atomized acid. The optimized formula for the atomizing acid system consists of 15~25% hydrochloric acid, 0.005% atomizing stabilizer (AEO-7), 1% iron ion stabilizer (EET), 1.5% corrosion inhibitor (EEH-160), and water. The optimal gas and acid injection scheme is gas injection at 2m3/min and acid injection at 10 mL/min, which maintains an atomization rate of over 80% after the acid mist migrates through the wellbore. Compared with gelling acid, the acid–rock reaction rate of atomized acid is 8.5, 9.1, and 10.6 times slower under acid concentrations of 15%, 20%, and 25% respectively. The retarding effect of atomized acid is superior, facilitating etching and initiating underdeveloped gas drive channels and thereby increasing the probability of gas communication with new reservoirs. The research findings presented in this paper establish a theoretical foundation for the practical implementation of the atomized acid acidizing process in the field. [ABSTRACT FROM AUTHOR]

As a response to stricter exhaust emission regulations, an increasing number of diesel-powered ships are switching to liquefied natural gas (LNG) fuel or installing post-processing devices to reduce exhaust gas. However, these methods are not feasible for small ships operating primarily along the coast. This is because the cost of the exhaust gas post-processing devices is high, while a large-volume fuel system is required in the case of LNG. Thus, this study used a propane gas fuel system based on a 5.0 L gasoline engine for easy application to existing small ships without major modifications. To optimize the control according to changes in the fuel system, a 1D simulation was performed on the engine to be developed, and ignition timing optimization was investigated. In addition, fuel consumption was compared with that of a gasoline-based engine. The propane engine achieved over 95% power in comparison to a gasoline-based engine. During cold-start tests, starting performance at −15 °C was ensured. The purpose of this study is to provide guidelines to assist the development of LPG or propane engines based on gasoline engines through these processes. [ABSTRACT FROM AUTHOR]

Conventional methods for producing porous metals involve the use of chemicals such as thickeners and foaming agents under high temperatures and pressures. However, these methods are costly and pose a risk of dust explosion. Thus, the objective of this research is to achieve the cost-effective and safe production of porous metals by introducing microbubbles generated by ultrasonic oscillation into the molten metal. One end of an ultrasonic horn was inserted into three different molten metals—white metal, Pb-free solder, and zinc—and microbubbles were generated at the horn end by the strong ultrasonic oscillation in the molten metals. The microbubbles that contained molten metal changed phase to porous metal through solidification, and the diameter, porosity, and stress–strain curve of the generated porous metals were measured. The results indicate that the porosity of white metal, Pb-free solder, and zinc foams reached 54%, 76%, and 48%, respectively, and these porous metals had many micropores less than 1 mm in diameter. It was also observed that the higher the melting point, the larger the pore diameter and the lower the porosity. Furthermore, in the case of white metal, a plateau region of large deformation at constant stress was observed in the stress–strain curve. [ABSTRACT FROM AUTHOR]

Acid gas injection operations function as the commercial equivalent of certain aspects within the realm of geological CO2 storage. Acid gas, composed of H2S and CO2, alongside minor quantities of hydrocarbon gases stemming from either petroleum production or processing, constitute the composition of acid gas. The primary aim of acid gas injection operations lies in the disposal of H2S. Nevertheless, substantial volumes of CO2 are concurrently injected due to the economic impracticality of segregating the two gases. This investigation delves into the comprehensive, step-by-step procedure that can be employed to determine the suitability of a field or formation for acid gas injection, utilizing all accessible data, including the literature and data from neighboring fields. This approach incorporates sensitivity analysis of various parameters to ascertain the feasibility of AGI while minimizing costs and time consumption. The focus of this study centers on evaluating the feasibility of Acid Gas Injection (AGI) in a saline aquifer offshore in Iran. The assessment encompasses the examination of reservoir properties, geomechanical aspects, caprock integrity, and gas plume dynamics. The Surmeh formation emerges as a promising candidate for AGI due to the presence of upper dolomite and lower carbonate within the rock formations. Geomechanical analysis reveals a pore pressure of 3800 psi and a fracture pressure of 6100 psi. Caprock integrity, particularly within the Hith formation, emerges as pivotal for both containment and long-term stability. Seismic mapping highlights variations in caprock thickness, influencing containment effectiveness. Capillary trapping emerges as a significant factor in short-term gas entrapment and plume distribution. Numerical simulations elucidate the impact of heterogeneous rock properties on capillary trapping and gas plume movement. The projection estimates approximately 2 TCF (Trillion Cubic Feet) of acid gas injection into the Surmeh formation. Based on the acid gas content and the gas in place at the source of injection, the recommended injection rate stands at 180 MMSCFD (million standard cubic feet per day). The formation's inherent tightness limits injectivity, allowing for a maximum achievable rate of 7 MMSCFD with a permeability of 1 mD (millidarcy). However, a higher porosity (12%) and a permeability of 100 mD enable more efficient injection without fracturing the formation. To achieve this, it becomes imperative to implement two injection wells, each with a capacity of 90 MMSCFD. [ABSTRACT FROM AUTHOR]

Gas injection structures were designed for a vertical oven to improve the gas–solid flow countercurrent structure. This work measured the wall temperature distribution of the vertical oven to reflect gas velocity distribution, and simulated the basic gas–solid flow field. The effects of the number of gas orifice layers and the injection angle on the gas velocity distribution were examined. The results showed that number of gas injection layers had a significant effect on the gas velocity distribution in the lower zone. Compared with the distributions with one or three injection layers, two injection layers produce more uniform gas flow. A small particle size of 6–15 mm increased the bed resistance and solid fraction standard deviation. A nozzle angle of 45° was conducive to increase the gas velocity in the upper zone and forming a more uniform gas distribution. [ABSTRACT FROM AUTHOR]

Numerous reservoirs that play a significant role in worldwide petroleum production and reserves contain fractures. Typically, the fractures must form a connected network for a reservoir to be classified as naturally fractured. Characterizing the reservoir with a focus on its fracture network is crucial for modeling and predicting production performance. To simplify the solution, dual-continuum modeling techniques are commonly employed. However, to use continuum-scale approaches, properties such as the average aperture, permeability, and matrix fracture interaction parameters must be assigned, making it necessary to improve the fracture depiction and modeling methods. This study investigated a fractured reservoir with a low matrix permeability and a well-connected fracture network. The focus was on the impact of the hierarchical fracture network on the production performance of gas-based enhanced oil recovery methods. The discrete fracture network (DFN) model was utilized to create comprehensive two-dimensional models for three processes: gas injection (GI), water alternating gas (WAG), and foam-assisted water alternating gas (FAWAG). Moreover, dimensionless numbers were employed to establish connections between properties across the entire fracture hierarchy, spanning from minor to major fractures and encompassing the fracture intensity. The results indicate that the FAWAG process was more sensitive to fracture types and networks than the WAG and GI processes. Hence, the sensitivity of the individual EOR method to the fracture network requires a respective depth of description of the fracture network. However, other factors, such as reservoir fluid properties and fracture properties, might influence the recovery when the minor fracture networks are excluded. This study determined that among the enhanced oil recovery (EOR) techniques examined, the significance of the hierarchical depth of fracture networks diminished as the ratio of major (primary fracture) aperture to the aperture of medium and minor fractures increased. Additionally, the impact of the assisted-gravity drainage method was greater with increased reservoir height; however, as the intensity ratio increased, the relative importance of the medium and minor fracture networks decreased. [ABSTRACT FROM AUTHOR]

At present, there is a common problem that the mixing mode is single and it is difficult to overcome the inherent bottleneck of multiphase mixing. A mixing device combining the advantages of jet entrainment and mixing dispersion was designed and built. In an effort to determine the mixing degree of two phases, the mixing coefficient of gas–liquid charging was measured using the cylinder method with the optimal working parameters. To explore the optimization of the mixing conditions and control mechanism of multiphase materials, the law of gas–liquid shear mixing in the process of multi-force field synergistic change was revealed. Based on the testing of the gas injection capacity under different working conditions and the calculation of the gas–liquid two-phase mixing coefficient, it was concluded that the flow rate was the direct key factor affecting the gas injection capacity. The working speed also had a certain impact on the gas injection capacity. When working at a high speed and high flow rate, the jet beam broke through the cutting barrier and presented a superposition effect. The jet impact assisted the rotation, and the suction performance of the device was significantly improved, which was conducive to the mixing of the gas and liquid phases. According to the test results of the measuring cylinder method, the calculated average inflation volume is 0.01 m 3 / (m 2 · m i n) , the inflation uniformity coefficient is 77.51, and the mixing coefficient of the gas and liquid phases is 0.12. [ABSTRACT FROM AUTHOR]

Foam-assisted gas injection exhibits promising potential for enhancing sweep efficiency through the amelioration of gravity segregation, particularly within reservoirs characterized by heterogeneity. In this work, the implicit-texture (IT) model featuring two flow regimes is employed to examine the impact of heterogeneity on gravity segregation. The validation of the numerical results for water–gas coinjection and pre-generated foam injection is accomplished through a comparative analysis with analytical solutions. A hypothetical two-layer model with varying permeabilities and thickness ratios is used to examine the impact of foam on gravity segregation. The numerical findings demonstrate satisfactory conformity with analytical solutions in homogeneous reservoirs. A high-permeability top layer in a layered model with a fixed injection rate results in sweep efficiency similar to that of a homogeneous reservoir with each individual permeability. A low-permeability top layer could increase the sweep efficiency, but with severe permeability contrast, the bottom high-permeability layer could impact the displacement process, even with a thin thickness. The sweep efficiency increases with the thickness of the high-permeability top layer and decreases with a thicker low-permeability top layer under fixed injection pressure. The predicted segregation length through a single-layer approximation cannot match the results of the layered models where the permeability contrast is too great or the thickness of two layers is comparable. [ABSTRACT FROM AUTHOR]

As one of the future main directions for underwater artillery, a ventilated launch can significantly reduce the huge water resistance during the underwater launching process. This paper aims to clarify the effect of starting conditions on the internal flow field and interior ballistic performance of an underwater ventilated launcher. Firstly, a three-dimensional unsteady model of gas–liquid two-phase flow is established. Following, an interior ballistic program of the underwater ventilated launch is developed. A coupling model between interior ballistic and gas–liquid interaction is then established, accounting for the projectile's dynamic boundary effect and gas–liquid interaction. Subsequently, the simulation accuracy of the model is confirmed. Finally, the effect of parameter adjustments on the internal flow field and interior ballistic properties are contrasted and examined by altering the starting conditions. The results indicate that adjusting the gas injection pressure and projectile starting pressure can effectively regulate the drainage and resistance reduction effect, thereby obtaining the desired interior ballistic performance of the underwater ventilated launch. The findings offer recommendations for future underwater launchers. [ABSTRACT FROM AUTHOR]

One method to accelerate carbon sequestration within mine tailings from remote mines involves the injection of diesel generator exhaust into dry stack tailings. The techno-economic feasibility of this approach heavily depends on understanding the flow characteristics inside the perforated injection pipes embedded within the tailings. Two distinctive yet dynamically coupled transport phenomena were identified and evaluated: (i) gas transport inside the pipe and (ii) gas injection into the porous body of the tailings. This paper presents two models to investigate these transport phenomena, a three-dimensional (3D) and a one-plus-one-dimensional (1 + 1)D model. An experimental investigation of the pressure profile through the injection pipe was carried out to validate the models at the experimental scale. To apply the (1 + 1)D model to larger scales, the results were compared with those of the 3D model, as the (1 + 1)D model required significantly less computational resources and time. To include the effect of the perforations in the pipe on the pressure profile of the (1 + 1)D model, an analytical fluid velocity profile was developed in relation to geometric and physical parameters. The performance of the (1 + 1)D model with an impact factor was then evaluated against the 3D model results for the inlet pressure, pressure profile and gas outflow distribution under various conditions than those investigated experimentally. The developed (1 + 1)D model can be used to design an energy-efficient approach for large-scale implementation with a wide range of desired operating parameters. [ABSTRACT FROM AUTHOR]

Hydrogen removal of H-supersaturated liquid steel produced in a hydrogen-rich environment in an industrial vacuum degasser (VD) is simulated here using a two-phase (argon–steel) Eulerian model. The dehydrogenation efficiency is evaluated for a series of ladle plug layouts and argon-purging modes. Increasing the plug number from the prototype double-plug of the ladle to four or slightly prolonging the degassing time of a triple-plug ladle enables to obtain the specified dehydrogenation efficiency and the end-point hydrogen level. Varying the plug position of the triple-plug ladle makes no significant difference in the dehydrogenation efficiency, which, however, is improved by adjusting the plug angle. For the triple-plug ladle, the non-uniform argon-purging mode improves the melt hydrodynamic conditions, but the optimal dehydrogenation performance is achieved in the uniform mode. The plug number has the greatest impact on the dehydrogenation efficiency compared to the other ladle designs considered. The high-efficiency dehydrogenation of H-supersaturated liquid steel in the VD can be achieved through using the quadruple plugs, or by using the triple plugs positioned at 0.57R, 0.57R, and 0.41R and the angles of 108.6° and 71.4°, with the uniform argon-purging flow rate. [ABSTRACT FROM AUTHOR]

Room temperature (RT) synthesis of the ternary cesium lead bromide CsPbBr3 quantum dots with oleic acid and oleylamine ligands was developed by Zeng and coworkers in 2016. In their works, the supersaturated recrystallization (SR) was adopted as a processing method without requiring inert gas and high-temperature injection. However, the oleic acid ligand for haloplumbate is known to be relatively unstable. Hence, in this work, we employed the eco-friendly olive oil to replace the oleic acid portion for the SR process at RT. Resultantly, we found that the cube-shaped nanocrystal has a size of ~40–42 nm and an optical bandgap of ~2.3 eV independent of the surface ligands, but the photoluminescence lifetime (τav) and crystal packing are dependent on the ligand species, e.g., τav = 3.228 ns (olive oil and oleylamine; here less ordered) vs. 1.167 ns (oleic acid and oleylamine). Importantly, we explain the SR mechanism from the viewpoint of the classical LaMer model combined with the solvent engineering technique in details. [ABSTRACT FROM AUTHOR]

High dip angle reservoirs are affected by gravity, resulting in poor sweep performance at the middle and high parts during waterflooding development. Previous studies have proposed top gas injection development for this type of reservoir, which has provided direction for improving the development effect of such reservoirs. However, current research efforts have mainly focused on the analysis of gas injection effects, rather than delving deeper into the gas injection mechanism and its influencing factors. Furthermore, the research methods adopted thus far have been primarily theoretical and fail to take into account the typical characteristics of high dip reservoirs in actual oilfields. Using a similarity criterion, this study establishes a high-temperature and high-pressure physical simulation device with variable inclination to analyze the impact of gas injection under various water injection conditions on the development of high dip reservoirs. The results suggest that the earlier the injection of water and gas, the slower the overall increase in water cut, and the more distinct the oil wall effect after gas injection, leading to a higher ultimate recovery. In the experiments, earlier injection timing can increase the final recovery rate by 9.59%. In addition, a visualized physical simulation device with an adjustable inclination angle has been established to analyze the sweep performance of high dip reservoirs under various gas injection timings. It is concluded that energy supplement in the early stage of pressure decline in the reservoir resulted in a more uniform movement of the oil-water interface at the bottom and the oil-gas interface at the top, and reduced the probability of water and gas channeling. The overall displacement efficiency is found to be improved with this approach. Earlier injection timing increased sweep efficiency by 5.95% and recovery efficiency by 13.2%, respectively. The injection gas source determined in this study, which is associated gas, is beneficial for low carbon plan and exhibits satisfactory oil recovery. The development of high dip reservoirs through top gas injection in combination with bottom water injection can generate a synergistic effect, which significantly enhances sweep efficiency and ultimate oil recovery. This finding provides theoretical guidance for practical implementation in the field. [ABSTRACT FROM AUTHOR]

The N2 flooding enhanced oil recovery process is an important technical means for the development of low permeability reservoirs due to its good energy enhancement effect and good injectivity. Low permeability reservoirs have a large permeability span and strong heterogeneity, which will have a significant impact on gas injection development. In order to explore the influence of matrix permeability and fractures on the production characteristics of N2 flooding, this study conducted a series of displacement experiments with full-scale matrix permeability (0.1–50 mD) and different fracture conditions. The research results indicate that, in non-fracture low permeability cores, the pressure difference decreased with the matrix permeability increase, and the volume of N2 injection required to achieve the highest injection pressure decreased. In addition, the increase in matrix permeability accelerates the gas breakthrough and gas channeling, but is beneficial for improving no-gas oil recovery and ultimate oil recovery due to the decrease in crude oil flow resistance. The impact of different matrix permeability ranges on production characteristics varies. When the matrix permeability is less than 2 mD, the characteristics of oil and gas production are significantly affected by changes in matrix permeability. When the matrix permeability is greater than 2 mD, the impact of changes in matrix permeability on development effectiveness is weakened. The existence of fracture causes a high permeability channel to appear in the low permeability matrix, exacerbating the gas breakthrough and channeling, and significantly reducing the utilization of matrix crude oil (about a 50% decrease in oil recovery). The increase in matrix permeability is beneficial for weakening the heterogeneity between fractures and the matrix, alleviating the gas channeling, thereby increasing the swept volume in the low permeability matrix and improving oil recovery. [ABSTRACT FROM AUTHOR]

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China's oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs. [ABSTRACT FROM AUTHOR]

Argon bottom stirring is commonly practiced in secondary steelmaking processes due to its positive effects on achieving uniform temperatures and chemical compositions throughout a steel melt. It can also be used to facilitate slag metal refining reactions. The inter-mixing phenomena associated with argon gas injection through porous plugs set in the bottom and its stirring efficiency can be summarized by evaluations of 95% mixing times. This study focuses on investigating the impact of different plug positions and ratios of argon flow rates from two plugs on mixing behavior within a 110-tonne, elliptical-shaped industrial ladle. A quasi-single-phase modeling technique was employed for this purpose. The CFD findings revealed that the optimal position of the second plug is to be placed diametrically opposite the existing one at an equal mid-radius distance (R/2). An equal distribution of argon flow rates yielded the best results in terms of refractory erosion. A comparative study was conducted between single- and dual-plug-configured ladles based on flow behavior and wall shear stresses using this method. Furthermore, a transient multiphase model was developed to examine the formation of slag open eyes (SOE) for both single- and dual-plug configurations using a volume of fluid (VOF) model. The results indicated that the dual-plug configuration outperformed the current single-plug configuration. [ABSTRACT FROM AUTHOR]

Gas-Projectile-Assisted Injection Molding (G-PAIM) is a new injection molding process derived from the Gas-Assisted Injection Molding (GAIM) process by introducing a projectile to it. In this study, the short-shot method and the overflow method of both the G-PAIM and GAIM processes were experimentally compared and investigated in terms of the wall thickness of the pipes and its uniformity. The results showed that the wall thickness of the G-PAIM molded pipe was thinner and more uniform than that of the GAIM molded pipe, and the wall thickness of the pipe molded by the Gas-Projectile-Assisted Injection Molding Overflow (G-PAIM-O) process was the most uniform. For the G-PAIM-O process, the influence of processing parameters, including melt temperature, gas injection delay time, gas injection pressure, melt injection pressure and mold temperature, on the wall thickness and uniformity of the G-PAIM-O pipes were studied via the single-factor experimental method. It was found that the effects of gas injection delay time and gas injection pressure on the wall thickness of the G-PAIM-O pipes were relatively significant. The wall thickness of the pipes increased with the increase in gas injection delay time and decreased with the increase in gas injection pressure. The melt temperature, melt injection pressure and mold temperature had little effect on the wall thickness of the G-PAIM-O pipes. In general, the wall thickness uniformity of the G-PAIM-O pipes was slightly affected by these processing parameters. [ABSTRACT FROM AUTHOR]

A numerical simulation procedure is proposed for analyzing the partial replacement of pulverized coal injection by hydrogen, oxygen, and blast furnace gas (BFG) injections mixed with pulverized coal (PCI) within the tuyeres of large blast furnaces. The massive use of hydrogen-rich gas is extremely interesting for ironmaking blast furnaces in the context of net-zero carbon hot metal production. Likewise, this new approach allows for increasing productivity and for reducing the specific emissions of carbon dioxide toward a net-zero carbon ironmaking technology. Nevertheless, the mixture of pulverized coal injection and gas injection is a complex technology. In addition to the impact on chemical reactions and energy exchange, the internal temperature and gas flow patterns can also change drastically. With a view to assessing the state of the furnace in this complex operation, a comprehensive mathematical model utilizing multiphase theory was developed. The model simultaneously handles bulk solids (sinter, pellets, small coke, granular coke, and also iron ore), gas, liquid metal and slag, and coal powder phases. The associated conservation equations take into account momentum, mass, chemical species, and energy while being discretized and solved using finite volume techniques. The numerical model was validated against the reference operating conditions using 220 kg per ton of pig iron (kg/tHM) of pulverized coal. Therefore, the combined injection of different concentrations of fuel hydrogen, blast furnace gas, and oxygen was simulated for replacing 40, 60, and 80 kg/tHM of coal injection. Theoretical analysis showed that the best scenario with stable operation conditions could be achieved with a productivity increase of 20% corresponding to a CO2 reduction of 15% and 60 kg/tHM of PCI replacement. [ABSTRACT FROM AUTHOR]

The use of Horizontal wells is a common method of underground natural gas storage (UGS), but there is still a need to discuss whether they are more suitable for slotted liner or perforation completions. To address this issue, a numerical model is developed to predict the gas injection rate of horizontal wells while considering the skin factor. Here, a novel uncoupled iteration method is employed to determine the skin factor deriving from turbulence in each time step when the bottom hole pressure is fixed. The uncoupled method begins with an estimate of the initial gas injection rate, which is then used to calculate a turbulent skin factor. This turbulent skin factor is then used to update the gas injection rate, iterating continuously until convergence is achieved. The effects of slotted liner and perforation design parameters, formation damage, and injection pressure on the skin factor are analyzed. The main findings suggest that the error in the gas injection rate calculated by the non-coupled model compared with the coupled model is only 0.6%, yet it can reduce the number of sub-iterations to 1/10 of that required by the coupled model. Moreover, the uncoupled model can provide results within four steps, even when the convergence condition is 10−14. The open area and perforation density play a significant role in determining the connection degree between the horizontal well and the reservoir, with a larger perforation density resulting in a negative skin factor. Perforations are more suitable than slotted liners for reservoirs with severe formation damage, and the difference in skin factor between the two can reach a value of 40.87 when the ratio of the damage zone's permeability to that of the normal reservoir zone is 0.05. It is easier to reduce turbulence damage in slotted liner completions than perforation completions, with the turbulence damage of the slotted liner being only 15.9% of that of the perforation. However, to avoid damage it is crucial to prevent the screen tube from being plugged in, as it might otherwise rise to three to ten times the original level. This study provides a theoretical basis and practical reference for the application of slotted liner and perforation method in UGS horizontal wells. [ABSTRACT FROM AUTHOR]

Cement production is the third largest source of nitrogen oxides (NOx), an air pollutant that poses a serious threat to the natural environment and human health. Reducing NOx emissions from cement production has become an urgent issue. This paper aims to explore and investigate more efficient denitrification processes to be applied in NOx reduction from precalciner. In this study, firstly, the flow field, temperature field, and component fraction in the precalciner are studied and analyzed using numerical simulation methods. Based on this, the influence of the reductant injection height and amount on the SNCR was studied by simulating the selective non-catalytic reduction (SNCR) process in the precalciner. The effect of natural gas on the NOx emissions from the precalciner was also investigated. The simulation results showed that, with the increase in height, the NOx concentration in the precalciner decreased, then increased, then decreased, and then increased again. The final NOx concentration at the exit position was 531.33 ppm. In the SNCR denitrification process, the reductant should be injected in the area where the precalciner height is 26–30 m so that the reductant can fully react with NOx and avoid the increase of ammonia escape. The NSR represents the ratio of reductant to NOx, and the results show that the larger the NSR is, the higher the denitrification rate is. However, as the NSR approaches 2, the denitrification rate slows down and the ammonia escape starts to increase. Therefore, according to the simulation results, the NSR should be kept between 1 and 1.6. The denitrification rate reached the maximum value of 42.62% at the optimal condition of 26 m of reductant injection height and 1.6 of NSR. Co-firing of natural gas with pulverized coal can effectively reduce the NOx generation in the furnace. The denitrification rate reached the maximum value of 32.15% when the natural gas injection amount was 10%. The simulation results of natural gas co-combustion and SNCR combined denitrification showed that combined denitrification was better than natural gas co-combustion or SNCR denitrification. Under the condition of NSR of 1 and natural gas injection of 10%, the denitrification rate increased by 29.83% and 31.64% compared to SNCR-only or co-combustion-only denitrification, reaching 61.98%, respectively. Moreover, less reductant is used in co-denitrification, so the problem of excessive ammonia emissions can be avoided. The results of this study provide useful guidance for denitrification process development and NOx reduction in cement production. [ABSTRACT FROM AUTHOR]