Search

Abstract 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 Among the Enhanced Oil Recovery (EOR) methods, gas-based EOR methods are very popular all over the world. The gas injection has a high ability to increase microscopic sweep efficiency and can increase production efficiency well. However, it should be noted that in addition to all the advantages of these methods, they have disadvantages such as damage due to asphaltene deposition, unfavorable mobility ratio, and reduced efficiency of macroscopic displacement. In this paper, the gas injection process and its challenges were investigated. Then the overcoming methods of these challenges were investigated. To inhibit asphaltene deposition during gas injection, the use of nanoparticles was proposed, which were examined in two categories: liquid-soluble and gas-soluble, and the limitations of each were examined. Various methods were used to overcome the problem of unfavorable mobility ratio and their advantages and disadvantages were discussed. Gas-phase modification has the potential to reduce the challenges and limitations of direct gas injection and significantly increase recovery efficiency. In the first part, the introduction of gas injection and the enhanced oil recovery mechanisms during gas injection were mentioned. In the next part, the challenges of gas injection, which included unfavorable mobility ratio and asphaltene deposition, were investigated. In the third step, gas-phase mobility control methods investigate, emphasizing thickeners, thickening mechanisms, and field applications of mobility control methods. In the last part, to investigate the effect of nanoparticles on asphaltene deposition and reducing the minimum miscible pressure in two main subsets: 1- use of nanoparticles indirectly to prevent asphaltene deposition and reduce surface tension and 2- use of nanoparticles as a direct asphaltene inhibitor and Reduce MMP of the gas phase in crude oil was investigated.

Miscible natural gas injection is widely considered as a practical and efficient enhanced oil recovery technique. However, the main challenge in this process is the high minimum miscibility pressure (MMP) between natural gas and crude oil, which limits its application and recovery factor, especially in high-temperature reservoirs. Therefore, we present a novel investigation to quantify the effect of chemical-assisted MMP reduction on the oil recovery factor. Firstly, we measured the interfacial tension (IFT) of the methane-oil system in the presence of chemical or CO2 to calculate the MMP reduction at a constant temperature (373K) using the vanishing interfacial tension (VIT) method. Afterwards, we performed three coreflooding experiments to quantify the effect of MMP reduction on the oil recovery factor under different injection scenarios.The interfacial tension measurements show that adding a small fraction (1.5 wt%) of the tested surfactant (SOLOTERRA ME-6) achieved 9% of MMP reduction, while adding 20 wt% of CO2 to the methane yields 13% of MMP reduction. Then, the coreflooding results highlight the significance of achieving miscibility during gas injection, as the ultimate recovery factor increased from 65.5% under immiscible conditions to 77.2% using chemical-assisted methane, and to 79% using gas mixture after achieving near miscible condition. The results demonstrate the promising potential of the MMP reduction to significantly increase the oil recovery factor during gas injection. Furthermore, these results will likely expand the application envelop of the miscible gas injection, in addition to the environmental benefits of utilizing the produced gas by re-injection/recycling instead of flaring which contributes to reducing the greenhouse gas emissions.

BackgroundSimultaneous bilateral rhegmatogenous retinal detachment (RRD) is a rare and challenging condition in ophthalmology. This case report focuses on a modified pneumatic retinopexy technique, designed to improve treatment outcomes for this difficult condition.Case presentationA 59-year-old male presented with decreased visual acuity in his right eye for one week. Examination revealed extensive retinal detachment in the right eye with multiple superior breaks and macula off, separated by approximately 3 clock hours. The left eye exhibited one quartile of retinal detachment with superior breaks and macula on. Bilateral simultaneous PR was performed for retinal repair. In the modified PR procedure, 0.7 ml of low-concentration perfluoropropane and 0.7 ml of filtered pure air were intravitreally injected into the right and left eyes, respectively. A head position maneuver was then employed to sequentially close retinal breaks, followed by laser photocoagulation once the surrounding retina reattached. Two days after gas injection, both retinas were completely reattached. Best corrected visual acuity improved to 0.6 in the right eye and 0.9 in the left eye at the 8-month follow-up.ConclusionThe innovative modified pneumatic retinopexy technique presented in this case report offers a promising new approach for effectively treating simultaneous bilateral rhegmatogenous retinal detachment.

This study investigates the shale oil drainage characteristics from the Gulong Sag, The objective is to clarify the development method for effective recovery enhancement of terrestrial shale oil. The investigation employs elastic depletion, CO2 displacement, and CO2 huff and puff coupled with nuclear magnetic resonance (NMR) measurements and numerical simulation methods. The study found that the elastic depletion, CO2 displacement, and CO2 huff and puff utilization efficiencies were 17.4%, 18.87%, and 21%, respectively. The study evaluated the oil drainage efficiency of different pore sizes in elastic depletion and CO2 huff and puff modes. The results demonstrated a clear trend in the order of micropore, mesoporous and macropore, with micropores exhibiting the highest oil drainage efficiency due to gas channeling during CO2 displacement. The use of CO2 huff and puff has been shown to improve oil drainage efficiency by 6.02%∼9.2% for different pore sizes. The numerical simulation optimization results suggest an injection volume of 3,000 t per round per well, an injection rate of 100 t/d, and a soaking time of 20 d for optimal CO2 huff and puff injection. This will increase oil production by 65,000 m³, resulting in an overall improvement of 24%. The study results provide a strong theoretical foundation for improving the recovery rates of terrestrial shale oil and gas through injection.

The flaring of large volumes of the natural gas that is produced as a by-product of crude oil, has puzzled the energy-hungry world for long. In recent years, it has also drawn the angst of the environmental and global-warming advocacy groups. The issues behind gas flaring are complex, as they involve a dynamic interplay of geosciences, engineering, economics, finance and natural resource policy-making.The purpose of this research is to analyze the associated gas problem quantitatively from a country-wide perspective. Unlike prior studies, this work focusses on the upstream side where the crucial strategic decisions are made upfront. To this end, a mathematical model is proposed for seeking the optimal integrated management strategy for the said national resource. The model is based on the Mixed Integer Linear Programming (MILP) technique and consists of scores of techno-economic decision variables and constraint equations along with a profit maximization objective.The model is general in nature but is applied herein to Nigeria as a case study. Several simulation runs are made to provide results for explanatory and prediction purposes. Model results indicate, for example, that a minimum gas price of $4.4/Mscf and minimum spend of $22B are jointly required to achieve zero-flaring, yielding a $10B profit. This is achievable via a strategy of reinjecting all associated gas produced from medium and large-sized fields, but gathering and selling all gas from small fields. Capital availability, rather than nationwide government-decreed flaring control, is shown to be the dominant determinant of profitable flaring mitigation. The model has proven to be a valuable tool for establishing the inter-relations between the key problem parameters under various pricing and resource base scenarios, and for prognosticating the trajectory of the gas industry in various jurisdictions.

Abstract Batch experiments were conducted to collect data for obtaining insights into the chemical mechanisms and kinetics of red mud neutralization by both atmospheric (passive treatment) and injected CO2 (active treatment) in the absence and presence of gypsum. Active treatments allowed effective sequestration of CO2 within 1 h. A mixing ratio of gypsum to red mud at 0.04–0.06 enabled effective control of pH rebound, completely eliminating the causticity of the red mud by reducing the pH value of red mud to

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 It is necessary to improve oil production from reservoirs. Various methods have been proposed to increase oil extraction from reservoir. Each method has specific challenges. In this research, the effect of water and gas injection in to Azadegan reservoir has been analyzed. Azadegan oil field is located south of Iran. In this study, water, immiscible gas and water alternating gas injected to reservoir and its effect on enhanced oil recovery have been investigated. Finally, a comparison between results of methods is provided. Results show that effective method for enhanced oil recovery is immiscible gas injection with 46% oil production efficiency and water alternating gas injection with 36% oil production efficiency. This study shows that oil production efficiency can be increased if duration of gas injection is increased. This study shows, increasing viscosity of water in water alternating gas scenario did not improve the production of Azadegan reservoir.

Optimal spacing for vertical wells can be effectively predicted with several published methods, but methods suitable for assessing the proper horizontal well spacing are rare. This work proposes a method for calculating the optimal horizontal well spacing for an ultra-low permeability reservoir – the Yongjin reservoir in the Juggar Basin, northwestern China. The result shows that a spacing of 640 m is the most economical for the development of the reservoir. To better develop the reservoir, simulation approaches are used and a new model is built based on the calculated well spacing. Since the reservoir has an ultra-low permeability, gas injection is regarded as the preferred enhanced oil recovery (EOR) method. Injection of different gases including carbon dioxide, methane, nitrogen and mixed gas are modelled. The results show that carbon dioxide injection is the most efficient and economical for the development of the reservoir. However, if the reservoir produces enough methane, reinjecting methane is even better than injecting carbon dioxide.

The Triassic massive sandstone reservoir in the Tahe oilfield has a strong bottom-water drive and is characterized by great burial depth, high temperature and salinity, a thin pay zone, and strong heterogeneity. At present, the water-cut is high in each block within the reservoir; some wells are at an ultra-high water-cut stage. A lack of effective measures to control water-cut rise and stabilize oil production have necessitated the application of enhanced oil recovery (EOR) technology. This paper investigates the development and technological advances for oil reservoirs with strong edge/bottom-water drive globally, and compares their application to reservoirs with characteristics similar to the Tahe oilfield. Among the technological advances, gas injection from the top and along the direction of structural dip has been used to optimize the flow field in a typical bottom-water drive reservoir. Bottom-water coning is restrained by gas injection-assisted water control. In addition, increasing the lateral driving pressure differential improves the plane sweep efficiency which enhances oil recovery in turn. Gas injection technology in combination with technological measures like channeling prevention and blocking, and water plugging and profile control, can achieve better results in reservoir development. Gas flooding tests in the Tahe oilfield are of great significance to identifying which EOR technology is the most effective and has the potential of large-scale application for improving development of deep reservoirs with a strong bottom-water drive.

Injection of natural/associated gas is widely used as an efficient method of enhanced oil recovery in carbonate oil reservoirs in both miscible and immiscible conditions. Due to reservoir oil compositional changes by injected gas, asphaltenes instability may occur. In spite of the broad reported studies on gas injection process, the effect of miscible gas injection phenomenon on asphaltenes precipitation and deposition at reservoir conditions has not been well attended. The aim of this study is to recognize the effect of miscible and immiscible injection of natural gas on the asphaltenes deposition, permeability alteration and oil recovery. Additionally, the impact of different live and recombined oil samples on asphaltenes instability is investigated. Permeability alteration by the formation of asphaltenes is analyzed through the permeability measurements before and after gas flooding. Permeability reduction is found to be function of miscibility state, injection pressure and type of oil samples. It is observed that experiments conducted with live oil and at lower injection pressures show more permeability reduction. It is assumed an additional oil recovery associated with fluid path diversion caused by asphaltenes deposition in miscible and immiscible conditions. The miscible gas flooding causes the lower asphaltenes deposition and lower recovery enhancement. These effects are due to the fluid path diversion, nevertheless, miscible natural gas injection has high potential of oil recovery. Due to miscible bank development, the composite core along with higher injection pressure respect to minimum miscibility pressure shows higher recovery in comparison to the short core sample.

Mixing in a reactor can be achieved mechanically or by the injection of a gas. This can be done by injecting a gas towards the bottom of the tank. The induced flow recirculation and then the stirring quality depends on the bubbles morphology, rising velocity and frequency detachment. This study focus on the case where the stirred fluid exhibits a yield stress. It is in line with previous studies on the gas cavity at the injection point [1], the induced flow recirculation [2] and the numerical simulation [3]. Here we quantified the bubbles diameters, aspect ratios and velocities as a function of the air flow rate, rheological parameters and tank size. Scaling laws and correlations based on the characteristic dimensionless numbers governing the flow have been proposed and validated experimentally. It was found that bubble frequencies and consequently bubble volumes and velocities are mainly governed by the balance between inertial and buoyancy forces. However, viscous and yield stress effects play an important role along buoyancy and inertial in defining the bubble aspect ratios. Weakly inertial flows are characterized by elongated bubbles while high inertial flows produce almost spherical bubbles. These experimental results are of practical interest for the design of reactor or digester where yield stress fluids have to be stirred.

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.

The Spallation Neutron Source (SNS) creates neutrons by striking a liquid mercury target with short pulses of high-energy protons. SNS targets have been operated with helium microbubble gas injection into portions of the flowing mercury since 2017. The measurements during in situ testing showed that the strain response of the stainless steel target vessel significantly decreased with gas injection. Strain reductions ranged from 40% to 75% for targets operating with gas-injection rates between 2 and 3 standard liters per minute. These strain reductions have allowed SNS to operate reliably at 1.4 MW over the last few years and are expected to significantly improve the fatigue life of the target vessel. The achieved mitigation of the pulse response and the associated cavitation damage with gas injection is a cornerstone of the upgrade basis to the redesigned mercury vessel for planned higher power operation.Existing methods can simulate the structural response of the target operated without gas injection. Developing simulation techniques that account for the benefits of gas injection adds a considerable challenge. A combined mercury/bubble material model based on the Rayleigh–Plesset equation was developed to improve simulation of the response of a structure containing liquid and gas by incorporating bubble growth volume feedback. This paper details the implementation of the mercury/bubble material model in the pulse simulation of an existing target design. The newly developed simulation technique combines the current no-gas mercury material model for no-gas regions and the bubbly mercury material model for the regions with gas bubbles. The results of the strain response simulation using the new techniques are promising. The challenges of the technique development are also discussed. For example, the bubble size distributions are crucial for the simulations but remain an area of active research.

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.

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.

The effectiveness of small-bubble gas injection to mitigate cavitation-induced erosion damage and decrease strain in Spallation Neutron Source (SNS) target vessels was characterized using photography, laser-line scanning, and in-situ vessel strain measurements. Observations from early targets showed that erosion damage caused appreciable mass loss along the target vessel inner wall. Later target designs incorporated a cavitation mitigation technique called small-bubble gas injection, in which small helium gas bubbles were introduced into the flowing mercury during operation. Samples removed from target vessels after operation revealed that gas injection greatly reduced or eliminated erosion damage. Photographs of the target interiors showed areas where significant erosion damage occurred in targets that were operated without gas injection. The same areas had no observable erosion damage in targets that were operated with gas injection. Laser-line scan measurements were performed on samples from several target vessels operated with and without gas injection to measure the extent of erosion damage and quantify the effect of gas injection on erosion. In-situ strain measurements during operation showed that gas injection reduced the target vessel strain by 25%–75%. These results provide conclusive confirmation that gas injection effectively mitigated erosion damage and reduced strain in SNS target vessels during operation.

To achieve future emission targets for internal combustion engines, the use of hydrogen gas generated by renewable energy sources (known as “green” hydrogen) instead of fossil fuels plays a key role in the development of new combustion-based engine concepts. For new hydrogen engine generations, there are different challenges concerning the injector layout and functionality. Especially when talking about direct hydrogen injection, the key challenge is to ensure a proper mixing between hydrogen and the combustion air—the mixing of gas with a gas is not trivial as shown in this article. In terms of injector functionality, it must be ensured that the requested amount of hydrogen gas needs to be provided in time and, on the other hand, accurately metered to provide an appropriate mixing formation quality inside the combustion chamber. This contribution discusses deep injector analysis techniques with pneumatic and optical approaches for an improved overall understanding of functionality and effects caused by operation with a gaseous fuel. A metering technique for gas flow characterization and, for test simplification, a comparison of hydrogen with helium and nitrogen as possible surrogate gases indicate that helium and nitrogen can act as a substitute for hydrogen in functional testing. Furthermore, this contribution focuses on the usability of helium instead of hydrogen for the determination of spray properties. This is shown by the comparison of spray propagation images that were observed with the Schlieren technique in a pressure vessel proving comparable spray properties. In a next step, the usage of spray-guiding devices to improve the global gas distribution during the injection period is discussed. Here, it turns out that the volume increase does obviously not depend on the nozzle design. Thus, the advantage of multi-hole guiding-devices is based on its flexible gas-jet orientation.

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.

Purpose: This study aimed to report a case of intravitreal gas injection in the supine position for hypotony after intrascleral intraocular lens (IOL) fixation in a patient with Vogt-Koyanagi-Harada (VKH) disease. Observations: A 72-year-old Japanese female patient presented with blurred vision in her right eye. Both eyes exhibited a sunset glow fundus due to VKH disease. The right IOL was dislocated; therefore, IOL fixation was performed. The patient's hypotony and choroidal effusion persisted postoperatively and her intraocular pressure (IOP) remained 2–4 mmHg despite the performance of two steroid courses. C3F8 (perfluoro pane gas) was injected into the vitreous cavity on postoperative day 35. The patient was instructed to assume a supine position on the third day after injection. At 6 days post-injection, her IOP began to rise; her IOP remained within the normal range until 1 year later. Conclusions and Importance: This is the first report of successful intravitreal gas injection in a supinated patient with VKH disease to treat postoperative hypotony.

Hydrogen is the energy vector that will lead us toward a more sustainable future. It could be the fuel of both fuel cells and internal combustion engines. Internal combustion engines are today the only motors characterized by high reliability, duration and specific power, and low cost per power unit. The most immediate solution for the near future could be the application of hydrogen as a fuel in modern internal combustion engines. This solution has advantages and disadvantages: specific physical, chemical and operational properties of hydrogen require attention. Hydrogen is the only fuel that could potentially produce no carbon, carbon monoxide and carbon dioxide emissions. It also allows high engine efficiency and low nitrogen oxide emissions. Hydrogen has wide flammability limits and a high flame propagation rate, which provide a stable combustion process for lean and very lean mixtures. Near the stoichiometric air–fuel ratio, hydrogen-fueled engines exhibit abnormal combustions (backfire, pre-ignition, detonation), the suppression of which has proven to be quite challenging. Pre-ignition due to hot spots in or around the spark plug can be avoided by adopting a cooled or unconventional ignition system (such as corona discharge): the latter also ensures the ignition of highly diluted hydrogen–air mixtures. It is worth noting that to correctly reproduce the hydrogen ignition and combustion processes in an ICE with the risks related to abnormal combustion, 3D CFD simulations can be of great help. It is necessary to model the injection process correctly, and then the formation of the mixture, and therefore, the combustion process. It is very complex to model hydrogen gas injection due to the high velocity of the gas in such jets. Experimental tests on hydrogen gas injection are many but never conclusive. It is necessary to have a deep knowledge of the gas injection phenomenon to correctly design the right injector for a specific engine. Furthermore, correlations are needed in the CFD code to predict the laminar flame velocity of hydrogen–air mixtures and the autoignition time. In the literature, experimental data are scarce on air–hydrogen mixtures, particularly for engine-type conditions, because they are complicated by flame instability at pressures similar to those of an engine. The flame velocity exhibits a non-monotonous behavior with respect to the equivalence ratio, increases with a higher unburnt gas temperature and decreases at high pressures. This makes it difficult to develop the correlation required for robust and predictive CFD models. In this work, the authors briefly describe the research path and the main challenges listed above.

Gas and downhole water sink-assisted gravity drainage (GDWS-AGD) is a new process of enhanced oil recovery (EOR) in oil reservoirs underlain by large bottom aquifers. The process is capital intensive as it requires the construction of dual-completed wells for oil production and water drainage and additional multiple vertical gas-injection wells. The costs could be substantially reduced by eliminating the gas-injection wells and using triple-completed multi-functional wells. These wells are dubbed triple-completion-GDWS-AGD (TC-GDWS-AGD). In this work, we design and optimize the TC-GDWS-AGD oil recovery process in a fictitious oil reservoir (Punq-S3) that emulates a real North Sea oil field. The design aims at maximum oil recovery using a minimum number of triple-completed wells with a gas-injection completion in the vertical section of the well, and two horizontal well sections—the upper section for producing oil (from above the oil/water contact) and the lower section for draining water below the oil/water contact. The three well completions are isolated with hydraulic packers and water is drained from below the oil–water contact using the electric submersible pump. Well placement is optimized using the particle swarm optimization (PSO) technique by considering only 1 or 2 TC-GDWS-AGD wells to maximize a 12-year oil recovery with a minimum volume of produced water. The best well placement was found by considering hundreds of possible well locations throughout the reservoir for the single-well and two-well scenarios. The results show 58% oil recovery and 0.28 water cut for the single-well scenario and 63.5% oil recovery and 0.45 water cut for the two-well scenario. Interestingly, the base-case scenario using two wells without the TC-GDWS-AGD process would give the smallest oil recovery of 55.5% and the largest 70% water cut. The study indicates that the TC-GDWS-AGD process could be more productive by reducing the number of wells and increasing recovery with less water production.

Anionic surfactants are commonly used as foaming agents in foam-enhanced oil recovery, but their performance is seriously affected by high temperature and high salinity environment. However, there are not many studies on the adsorption pattern and salinity resistance performance of anionic surfactants on solid surfaces. This study evaluated the foaming performance of several anionic surfactants suitable for hightemperature, high-salinity salinity reservoirs. It was found that α-olefin sulfonate (AOS) showed good foaming performance under high temperature and high salt condition. However, the solubility of the foaming agent was low in brine with a salinity of 11×104 mg·L-1. Therefore, a co-solvent (ABS), which is a strong hydrophilic alkyl benzene sulfonate, was chosen to be compounded with AOS in this study. In this study, a foaming agent with excellent foaming performance and solubility at a temperature of 90°C and a salinity of 11×104 mg·L-1 was constructed. The adsorption of the foaming agent was less than 0.3mg/g on the surface of quartz sand, and its foaming rate and foam decay half-life after three adsorptions maintained more than 85% of the original performance. The results of the study can guide the selection of foaming agents for gas injection and mobility control in medium temperature and high salinity clastic reservoirs.

Due to the limited crude oil resources, the role of enhanced oil recovery (EOR) techniques in the production of the oil that has not been extracted during the primary and secondary oil production techniques is crucial. Gas injection is known as an important EOR technology, but one of the main concerns during gas injection is asphaltene precipitation and deposition within reservoir formation. In this study, the effect of temperature (ranges 376-416 K) and concentration of injected gas (N2 (10, 20 and 40, mole percent) and first separator gas (20, 40 and 60, mole percent)) on the onset pressures and amount of asphaltene precipitation in one of the Iranian oil reservoirs were investigated. Two series of experiments were accomplished on live oil by gravimetric method; first: injection of different concentrationsof nitrogen and first separator gas at reservoir temperature and under different pressures (3000-8000 psia) and second: natural depletion at different temperatures. Besides, the experimental data of asphaltene precipitation due to N2, first separator gas, and also CO2 injection were compared together. Finally, the experimental data were modeled with a solid model. The results indicate that the amount of asphaltene precipitation due to N2 injection (0.1-0.2 wt %) is lower than the first separator gas and CO2 injection at the same concentration. Experiments show that in the range of experimental temperatures the asphaltene precipitation changes up to 0.06 wt %. For pressures below the bubble pressure (~ 4700 psi), precipitation changes directly with temperature, and indirect relation is observed for pressures above the bubble point pressure.

Due to the limited crude oil resources, the role of enhanced oil recovery (EOR) techniques in the production of the oil that has not been extracted during the primary and secondary oil production techniques is crucial. Gas injection is known as an important EOR technology, but one of the main concerns during gas injection is asphaltene precipitation and deposition within reservoir formation. In this study, the effect of temperature (ranges 376-416 K) and concentration of injected gas (N2 (10, 20 and 40, mole percent) and first separator gas (20, 40 and 60, mole percent)) on the onset pressures and amount of asphaltene precipitation in one of the Iranian oil reservoirs were investigated. Two series of experiments were accomplished on live oil by gravimetric method; first: injection of different concentrationsof nitrogen and first separator gas at reservoir temperature and under different pressures (3000-8000 psia) and second: natural depletion at different temperatures. Besides, the experimental data of asphaltene precipitation due to N2, first separator gas, and also CO2 injection were compared together. Finally, the experimental data were modeled with a solid model. The results indicate that the amount of asphaltene precipitation due to N2 injection (0.1-0.2 wt %) is lower than the first separator gas and CO2 injection at the same concentration. Experiments show that in the range of experimental temperatures the asphaltene precipitation changes up to 0.06 wt %. For pressures below the bubble pressure (~ 4700 psi), precipitation changes directly with temperature, and indirect relation is observed for pressures above the bubble point pressure.

Underwater plasma has been long recognized as a “green” alternative to conventional chemicals in the wastewater treatment processes. However, practical application of underwater plasma is still challenging due to insufficient treatment performance. Recently, we proposed a novel process named ACAP utilizing acoustic cavitation in order to stabilize the plasma generation and to enlarge the plasma processing region.This work continues our investigation regarding the ACAP treatment process focusing on effects of gas injection. Experiments were performed using an ultrasonic installation equipped with a specially designed sonotrode (Diam. 48 mm) operated at a frequency of 20 kHz and acoustic power of 120 W. The results revealed that the degradation efficiency of Rhodamine B, which was used as a model wastewater pollutant, remains almost unchangeable in the case of air injection, but it is doubled when argon is injected into the ACAP reactor. It was found that the argon injection enhances the degradation efficiency significantly even without ultrasound irradiation. Results of additional measurements suggest that the effect of argon is attributed to its ability to yield high temperature during cavitation, comparatively good solubility in water and a better ability to reduce the breakdown voltage in water compared to the air case.

Abstract Gas injection in the tundish has been considered as an alternative to optimizing inclusion removal from steels. In the present study, physical and mathematical modeling were used to investigate the effect of gas injection in the tundish on the inclusion removal efficiency. The physical model is a 1/3 reduced scale of an industrial two-strand tundish of 40 tons. The inclusion removal efficiency was quantified using the APS III probe, which counts particles leaving the tundish during the test. Different locations for the gas injection plug were evaluated. Additionally, a mathematical model was developed using commercial CFD software CFX. The predictions of the mathematical model were validated by the physical model results, comparing the efficiency of inclusion removal. The proposed model includes a new boundary condition to describe the behavior of the particles at the free surface, implemented by a special subroutine. The model enabled the identification of appropriate conditions: plugs located at 0.56 or 0.84m from the tundish inlet with gas injection with the flow rate of 3NL/min.

Gas injection is a frequently used method for artificial lift and flow regime rectification in offshore production and transportation flowlines. The flow behaviour in such flowlines is complex and a better understanding of flow characteristics, such as flow patterns, void fraction/hold up distributions and pressure gradient is always required for efficient and optimal design of downstream handling facilities. Injection method and location have been shown to strongly affect downstream fluid behaviour that can have important implications for pumping and downstream facility design, especially if the development length between pipeline and downstream facility is less than L/D = 50 as reported by many investigators. In this article, we provide the results of an experimental investigation into the effects of the gas injection position on the characteristics of the downstream upwards vertical gas flow using a vertical riser with an internal diameter of 52 mm and a length of 10.5 m. A horizontal 40-m-long section connected at the bottom provides options for riser base or horizontal flow line injection of gas. The flowline gas injection is performed 40 m upstream of the riser base. A 16 by 16 capacitance wire mesh sensor and a gamma densitometer were used to measure the gas-liquid phase cross-sectional distribution at the riser top. A detailed analysis of the flow characteristics is carried out based on the measurements. These include flow regimes, cross-sectional liquid holdup distributions and peaking patterns as well as analysis of the time series data. Our findings show that flow behaviours differences due to different gas injection locations were persisting after a development length of 180D in the riser. More specifically, core-peaking liquid holdup occurred at the lower gas injection rates through the flowline, while wall-peaking holdup profiles were established at the same flow conditions for riser base injection. Wall peaking was associated with dispersed bubbly flows and hence non-pulsating as against core-peaking was associated with Taylor bubbles and slug flows. Furthermore, it was found that the riser base injection generally produced lower holdups. It was noted that the circumferential injector used at the riser base promoted high void fraction and hence low liquid holdups. Due to the bubbly flow structure, the slip velocity is smaller than for larger cap bubbles and hence the void fraction is higher. The measurements and observations presented in the paper provides valuable knowledge on riser base/flowline gas introduction that can directly feed into the design of downstream facilities such as storage tanks, slug catchers and separators.

Worldwide practices have proven that gas-assisted gravity drainage can obviously enhance oil recovery, and this technology can be especially effective for reservoirs with a thick formation and large inclination angle. For the successful implementation of this process, a key technology is the stable control of gas–oil interface during gas injection. For a detailed exploration of this technique, a three-stage permeable visual model was designed and manufactured, with permeability decreasing from top to bottom, thus, a reverse rhythm reservoir was effectively modeled. Then the experiment concerning CO2-assisted gravity drainage was carried out with the adoption of a self-developed micro visual displacement device. This study mainly focused on the micro migration law of gas–oil interface and the development effects of CO2-assisted gravity drainage. According to the experiments, CO2 fingering somewhat happens in the same permeable layer from the beginning of gas injection. However, phenomena of “wait” and “gas–oil interface self-adjustment” occur instead of flowing into the next layer when the injected CO2 reaches the boundary of the next lower permeability layer through the dominant channel. By the “gas–oil interface self-adjustment”, the injected CO2 first enters into the pores of the relative higher permeability layer to the greatest extent, and thus expands the sweep volume. Futhermore, in the process of CO2 injection, obvious gas channeling occurs in the low permeability layer directly connected to the outlet, resulting in low sweep efficiency and poor development effect. After connecting the core with lower permeability at the outlet, the development indexes of the model, such as the producing degree of the low permeability layer, the oil recovery before and after gas breakthrough, are significantly improved, and the recovery degrees of the medium permeability layer and the high permeability layer are also improved, and the overall recovery factor is increased by 12.38%. This “gas–oil interface self-adjustment” phenomenon is explained reasonably from the two scales of macroscopic flow resistance and microscopic capillary force. Finally, the enlightenments of the new phenomenon are expounded on the application of gas-assisted gravity drainage on site and the treatment of producers with gas breakthrough in gas injection development.

Cap rocks are dams which can prevent the upward movement of hydrocarbons. They have disparities and weaknesses including discontinuities, crushed areas, and faults. Gas injection is an effective mechanism for oil recovery and pore pressure. With increasing pore pressure, normal stress is reduced, and the integrity of impermeable boundaries (cap rock, fault, etc.) becomes instable. A successful strategy for reservoir development is the inevitable necessity of conducting geomechanical studies and modeling the reservoir. The construction of a comprehensive geomechanical model, including the stress state is a function of depth (direction and amount), physical properties of the reservoir rock and its formations (rock resistance and elastic moduli), pore pressure estimation, and description and distribution of fractures and faults. In this work, analytical and numerical methods have been used in geomechanical modeling, and the data used for modeling and petrophysical information are downhole tests. The geomechanical modeling of gas injection into the reservoir and, simultaneously, the operation of Asmari reservoir and Marun oilfield cap rock in the southwest of Iran were carried out. The threshold of reactivating faults and the critical pressure of induced fracture were calculated, and the results were presented as analytical and numerical models. Moreover, in addition to analyzing the stress field at depths, the resistance parameters of the formations were determined. The results showed that the most changes and instabilities were around the wellheads, fractures, and the edges of the field.

Abstract Reservoir fluid characterization is one of the most important steps in hydrocarbon reservoir engineering calculations and studies. The reservoir fluid composition is not constant along the entire hydrocarbon column and varies along the vertical and horizontal directions. In most cases, such variations have been observed along the vertical direction. This is known as compositional grading phenomenon and has a strong impact on the calculation of original hydrocarbon in place, reservoir development, and oil recovery factor. In this paper, a simulation study was carried out to investigate the effects of compositional grading on reservoir fluid properties and the injection of various gases such as carbon dioxide (CO2), nitrogen (N2), associated petroleum gas (APG), N2–CO2 mixture, and water-alternating-CO2 injection into different depths of a conventional black oil reservoir in the southwest of Iran in order to detect the best injection depth and achieve the highest oil recovery factor. Due to increase in minimum miscibility pressure (MMP) with depth in compositionally grading reservoirs, MMP variations with depth is one of the main challenges in determining the optimal gas injection depth in such reservoirs. The results showed that N2, APG and N2–CO2 mixture were immiscibly injected into all depths of the reservoir due to their high miscibility pressures. The occurrence of gas override and channelling phenomena during the course of immiscible gas injection significantly reduced oil displacement efficiency. On the other hand, CO2 was miscibly injected to all reservoir layers and revealed a higher efficiency in comparison with the injection of N2, APG and N2–CO2 mixture. In fact, better miscibility development was observed in upper reservoir parts, as compared to the lower parts. Through completing injection wells at upper reservoir parts and then injecting gas into these parts, one can thus further enhance oil recovery and extend production plateau. Moreover, the results confirmed that water-alternating-CO2 injection into all reservoir depths, compared to other gas injection scenarios, was associated with increased macroscopic sweep efficiency as well as enhanced oil recovery factor.

Abstract Experimental work has been conducted to study the influence of gas injection on the phase inversion between oil and water flowing in a vertical pipe. A vertical transparent pipe test section line of 40 mm ID and 50 cm length was used. The test fluids used were synthetic oil and filtered tap water. Measurements were taken for mixture velocity, superficial water velocity, superficial gas velocity, and input superficial oil velocity ranging from 0.4 to 3 m/s, 0.18 to 2 m/s, 0 to 0.9 m/s, and 0 to 1.1 m/s. Most of the experiments were conducted more than two times, and the reproducibility of the experiments was quite good. Special attention was given to the effect of oil and water concentration where phase inversion took place with and without gas injection. The results showed that the phase inversion point was close to water fraction of ~ 30%, for both water friction direction changes (from water to oil or from oil to water) and that the effective viscosity increases once the mixture velocity increases. On the other hand, the results with gas injection showed that gas injection had no effect on the oil or water concentration where phase inversion occurred. Furthermore, the study investigated the effect of gas–oil–water superficial velocity on the total pressure gradient in the vertical pipe. It was found that the total pressure gradient was fast and increased at high superficial gas velocity but was slow at low superficial gas velocity. When the superficial oil velocity increased, the total pressure gradient approached the pressure gradient of an oil–water two-phase flow. The obtained results were compared with few correlations found in the literature, and the comparison showed that the uncertainty of the flow pattern transition peak in this study is very low.

Poor solubility of high protein milk powders can be an issue during the production of nutritional formulations, as well as for end-users. One possible way to improve powder solubility is through the creation of vacuoles and pores in the particle structure using high pressure gas injection during spray drying. The aim of this study was to determine whether changes in particle morphology effect physical properties, such as hydration, water sorption, structural strength, glass transition temperature, and α-relaxation temperatures. Four milk protein concentrate powders (MPC, 80%, w/w, protein) were produced, i.e., regular (R) and agglomerated (A) without nitrogen injection and regular (RN) and agglomerated (AN) with nitrogen injection. Electron microscopy confirmed that nitrogen injection increased powder particles’ sphericity and created fractured structures with pores in both regular and agglomerated systems. Environmental scanning electron microscopy (ESEM) showed that nitrogen injection enhanced the moisture uptake and solubility properties of RN and AN as compared with non-nitrogen-injected powders (R and A). In particular, at the final swelling at over 100% relative humidity (RH), R, A, AN, and RN powders showed an increase in particle size of 25, 20, 40, and 97% respectively. The injection of nitrogen gas (NI) did not influence calorimetric glass transition temperature (Tg), which could be expected as there was no change to the powder composition, however, the agglomeration of powders did effect Tg. Interestingly, the creation of porous powder particles by NI did alter the α-relaxation temperatures (up to ~16 °C difference between R and AN powders at 44% RH) and the structural strength (up to ~11 °C difference between R and AN powders at 44% RH). The results of this study provide an in-depth understanding of the changes in the morphology and physical-mechanical properties of nitrogen gas-injected MPC powders.

This paper presents a basic study for developing a new adhesion improvement method for railway vehicles, focusing on the tangential force characteristics between wheels and rails. In our previous studies, the following phenomena have been confirmed. First, the tangential force of the wheel/rail is increased by repeated rolling and sliding frictional force, and the tangential force is stabilized by the oxide film covering the contact surface. In addition, the tangential force under the condition where the humidity around the contact surface is low tends to be larger than that under high humidity condition. And finally, these phenomena indicate that the friction coefficient of wheel/rail can be increased by instantaneously reducing the humidity around the contact surface. Therefore, in this paper, we propose a method for improving the frictional force that reflects the above-mentioned results in our previous studies. In the proposed method, assuming that it is applied to re-adhesion control of railway vehicles, the frictional force of the wheel/rail contact is temporarily increased by lowering the humidity around the contact surface by injecting dry nitrogen gas less than 30% humidity. To verify the proposed method, using a pair of the small cylindrical specimen, tangential force was measured under the conditions with different humidity. In addition, in order to confirm the effect on the braking performance of actual railway vehicle, numerical analysis was carried out. As a result, the experimental result showed the frictional force is increased by up to approximately 40% under high humidity condition, and it was confirmed by the numerical analysis that the proposed method has an improvement effect on the reduction of braking distance during dry nitrogen gas injection even if the humidity condition around the contact surface is high.

Purpose: To report the outcomes of pneumatic retinopexy (PR) performed as a primary surgical procedure for rhegmatogenous retinal detachment (RRD) or as a secondary procedure for recurrent RRD. Methods: We retrospectively analyzed case records of 54 patients (54 eyes) who underwent PR for RRD by injecting 0.3 ml of perfluoropropane (C3F8) in the vitreous cavity and cryopexy to break in the same sitting, followed by positioning. Results: A total 54 eyes of 54 patients aged between 17 and 84 years (mean - 51.3, median - 53 years) were included in the study. Except five eyes, all had breaks in the superior quadrants. The RRD ranged from 1 quadrant to 4 quadrants. Twenty-eight eyes (51.8%) were phakic and 26 (48.1%) were pseudophakic. The follow-up ranged from 6 to 144 months. In 25 eyes (46.2%), PR was the primary intervention and was successful in 15 (60%) eyes with a significant visual improvement (P = 0.023). Twenty-nine eyes (52.7%) with failed scleral buckle or failed pars plana vitrectomy underwent PR with a success rate of 65.5% and significant visual improvement (P = 0.0017). Progression of proliferative vitreoretinopathy changes (40%) was the most common cause of failure. The success rate was higher in phakic eyes, eyes with attached macula, superior breaks, superior RRD, and RRD limited to 3 quadrants or less. Conclusion: PR remains a minimally invasive procedure which can be used primarily or as a salvage procedure in failed surgery with moderately good success rate and minimal complications. One-step procedure reduces patient visits and ensures adequate treatment of the break.

Gas injection is one of the prospective methods in the development of unconventional oil reserves. Before implementation in the field, it is necessary to justify the effectiveness of using gas agents in specific object conditions. Experiments of oil displacement on physical models with subsequent numerical modeling can provide the information necessary to justify the feasibility of using gas injection in specific reservoir conditions. This work is devoted to a series of experiments determining the minimum miscibility pressure (MMP) on a slim tube model and the analysis of oil displacement dynamics for various gas compositions, as well as numerical modeling. Displacement experiments were carried out using a recombined oil sample from one of the fields in Western Siberia. The MMP was determined by the classical method of inflection point on the displacement efficiency versus injection pressure curve, which was 34.6 MPa for associated petroleum gas (APG) and 49.9 MPa for methane. The dysnamics of oil displacement for different gas compositions at the same injection pressure showed that APG and carbon dioxide (CO2) are the most effective in the conditions of the studied field. The influence of the gas composition on the gas breakthrough point was also shown. It is revealed that the change in the concentration of the displacing agent in the outgoing separation gas helps define in more detail the process of displacement and the processes implemented in this case for various displacing gas agents. Similarly, it is shown that the displacing efficiency of a gas agent in a miscibility injection mode is affected by the configuration of wells when it is necessary to achieve MMP in reservoir conditions. For the immiscible gas injection mode, no influence of the well configuration was observed.

In Colombia en paz Oil Field, the opportunity to increase productivity through the implementation of secondary recovery methods is visualized. The project aims at basal sands because the quality of its fluid is better compared to the upper sands (30 ° API vs 20 ° API, respectively). The main objective is to evaluate the effect of gas reinjection on oil production. Today, the field has a gas lift network (Gas Lift) with an available pressure of 1,200 psi. Which would be used for the implementation of the process both cyclic and continuous and with flow rates between 100 - 1,000 kscfpd (kilo standard cubic feet per day). Oil production is expected to increase due to pressurization in the well drainage area and increased mobility by partial solubility of the gas in the crude. At the Center of Innovation and Technology - Instituto Colombiano del Petróleo, the recovery of crude oil was measured by the injection of production gas. The technical standard GTN-I-009 was used to conduct runs with production gas. The tests were performed at 138 ° F reservoir temperature, 440 scf / STB Gas Oil Ratio and crude with Basic Sediments and Water (BS&W) less than 1% as required by the experimental protocols. At the laboratory, the total recovered crude with production gas was 18 % at the maximum operating pressure of 1,600 psi for the Gas Lift system. The Minimum Miscibility Pressure was estimated at 8,407 psi by linear extrapolation using experimental data taken from Slim Tube Equipment

Abstract Production optimization is defined as the process of maximizing oil production over the long term while minimizing total production costs. The overall goal is to achieve the optimum profitability from the well or field. In this process, the reservoir system can be considered as a multiple input–output system. In this complex system injection and production wells are known as inputs and outputs. The output of the system is often affected by various parameters consisting reservoir conditions, petrophysics, and PVT data. The optimization of the injector rates and number and installation of submersible pumps are the main issues which have been studied in this paper. Determining the factor with the highest influence on production is of great interest and value. The aim of this paper is to develop different scenarios until 2026 in which above factors are considered; therefore, by comparing these scenarios, the best plan can be selected according to these factors as a combination of different separate scenarios along with economical and other related issues. In this paper effect of drilling new wells is also studied. The optimized plan consisted of opening a certain producer after its work-over, performing work-over on two certain producers, installing down-hole pumps in five certain injectors, increasing and reducing the injection rates of two and three certain injectors, respectively, and drilling six new producers. This optimized plan shows a 13.44% increase in recovery factor in comparison with the plan in which there are no injectors in the field.

Pneumatic vitreolysis (PVL) is the intravitreal injection of a small quantity of expansile gas for the purpose of achieving focal vitreomacular traction (VMT) release for eyes with symptomatic VMT, or inducing VMT release and closure of the macular defect for eyes with a small stage-2 macular hole (MH). Initially, there was limited interest in this technique upon its introduction for clinical treatment in human eyes in 1993. With the advent of optical coherence tomography allowing detailed observation of vitreomacular interface changes and rising importance of medical economics in recent years, there has been increasing interest in PVL, a low-cost procedure for managing symptomatic VMT. The success rates of VMT release in the literature have ranged from 60% to 100% and the rates of closure of small macular holes have ranged from 50% to 80% following PVL. In a recent retrospective consecutive series of 56 eyes in two centers undergoing C3F8 gas injection, Chan and Mein reported an overall success of 86% in VMT release and 60% closure of small macular holes with few adverse events (7% with retinal breaks, retinal detachment, or progression of VMT). Multiple recent studies have shown superior outcome utilizing C3F8 gas compared with SF6 gas for PVL. In conclusion, PVL is a promising, low-cost therapeutic option, with the potential for managing symptomatic focal VMT on a global scale.

This paper is devoted to the analysis of the effect of gas injection on the efficiency of gaseous fuel burning. A coaxial burner with a perforated inner wall is presented in which the methane–air acceleration is observed. With the use of numerical analysis, it is demonstrated that the flame acceleration is related to the flow separation from the inner wall that, in turn, leads to the reduction in heat losses to the wall as well as to vortex formation and reduction in momentum losses. On the basis of the obtained results, a new technology of efficient burning of gaseous fuels can be proposed with the use of gas and/or liquid fuel injection.

The objective of this work is to analyze a gas injection borehole heat exchanger coupled with a desiccant assisted air conditioning system during cooling and heating operation. A common problem that occurs in air conditioning systems is peak loads, during which the cooling or heating power of the soil can be exceeded. To counteract this drawback, a gas injection borehole heat exchanger, which is capable of creating artificial groundwater flow along the heat exchanger by inducing a pressure difference inside the well, is used. Experimental results of the performance differences between a conventional and a gas injection borehole heat exchanger are presented. Under the same inlet conditions, a reduction in the outlet temperature of up to 2 °C is achieved compared with an equivalent conventional borehole heat exchanger in cooling mode. The maximum cooling power is increased by 26%. As a result, a fast and dynamic responding control of the heat transfer between the heat exchanger and the soil is possible. During winter operation, despite the lower drilling depth of the gas injection borehole heat exchanger system, the performance is within the range of a conventional system. The power increase is limited to around 0.2 kWth at a steady state. In conclusion, gas injection borehole heat exchangers can be promising in terms of reliable peak load handling within large geothermal fields.

Segmented slug flow systems in capillaries have already shown good potential for process intensification, due to their symmetry in the characteristic flow pattern. However, several challenges remain in this technology. For instance, in gas-consuming reactions, like Aliq + Bgas→Cliq, the gas droplets shrink and may even disappear, limiting the conversions and throughputs of capillary reactor systems. To overcome such shortcomings, an intermediate gas feed was developed. In order to maintain the well-defined slug flow characteristics, it is necessary to introduce the gas rapidly and precisely, in small aliquots of

CO2 injection is an effective technique for improved oil recovery in light oil reservoirs, especially for water flooding abandoned reservoirs. In this study, the lower part of Es1 reservoirs in Pucheng oilfield was introduced as the target reservoir. By studying the minimum miscible pressure in CO2 flooding, the reservoir could achieve miscible flooding. Long core displacement experiments proved that water alternating CO2 flooding could significantly improve the recovery. For the reservoir characteristics, anti-corrosion technology in the process of injection was researched, and the H-20 inhibitor was screened. A channeling blocking agent in combination with the delayed expansion of gel particles and cross-linked copolymer was used to control the gas fluidity. The Pu 1-1 well groups were optimized to conduct a field trial. The cumulative injected liquid CO2 was 19219.95 ton, 0.248 PV and the cumulative increasing oil was 4520.9 t. The predicted recovery will increase by 8.3%. The successful implementation of the project can provide technical attempt for completion of energy to succeed and energy-saving emission reduction targets.

The paper presents CFD analysis of fuel flow in the CNG injector. The issues such a pressure drop along an injector channel, mass flow through the key sections of the injector geometry, flow rates, the impact of the needle shape on the deflection of the sprayed gas cone and the impact of the wall head are analyzed in the article. The simulation was made in the transient states conditions for full injection process, including the opening and closing of the injector. An injection time of 6 ms, velocity of 0.33 mm/ms and a lift of 0.5 mm were selected for opening and closing of injector based on experimental test. The simulation shows that the volume inside the injector is a kind of fuel accumulator, and the opening process of the needle influence the flow parameters in an inlet cross-section after a certain time, depending on a channel cross section. The calculations allowed to select the ratio of an injector duct cross sectional area to the aperture area of the injection capable of the reducing pressure loss. The unusual location of the injector in the socket of a glow plug in the Andoria ADCR engine makes a stream be impaired by a part of the head. This research result would be useful in developing an injector construction which will be used for an investigation of CNG addition into diesel engine.

Because of the strong adsorption capacity of meta-anthracite, the gas content of a meta-anthracite seam can be as high as 10 m3/t, with a gas pressure lower than 0.74 MPa; this results in low efficiency of gas extraction in underground mines. To enhance low-pressure methane extraction efficiency in meta-anthracite seams, a new approach – methane displacement by gas injection – has been developed, investigated in the laboratory, and then applied in the field in the Fuyanshan coal mine. Laboratory results show that when the gas content of the coal seam is high, methane displacement by nitrogen injection is difficult. The volume of methane displaced is directly related to the pressure difference between the coal seam gas pressure and the injection gas pressure. If the total gas pressure is greater than 0.5 MPa after nitrogen injection, then the methane displacement efficiency will be greatly enhanced. It is also confirmed that the displacement efficiency can be improved by injecting inert gas to change the partial pressure of the methane. Field test data show quite good methane displacement efficiency.

Shale oil and gas resources contribute significantly to the energy production in the U.S. Greenhouse gas emissions come from combustion of fossil fuels from potential sources of power plants, oil refineries, and flaring or venting of produced gas (primarily methane) in oilfields. Economic utilization of greenhouse gases in shale reservoirs not only increases oil or gas recovery, but also contributes to CO2 sequestration. In this paper, the feasibility and efficiency of gas injection approaches, including huff-n-puff injection and gas flooding in shale oil/gas/condensate reservoirs are discussed based on the results of in-situ pilots, and experimental and simulation studies. In each section, one type of shale reservoir is discussed, with the following aspects covered: (1) Experimental and simulation results for different gas injection approaches; (2) mechanisms of different gas injection approaches; and (3) field pilots for gas injection enhanced oil recovery (EOR) and enhanced gas recovery (EGR). Based on the experimental and simulation studies, as well as some successful field trials, gas injection is deemed as a potential approach for EOR and EGR in shale reservoirs. The enhanced recovery factor varies for different experiments with different rock/fluid properties or models incorporating different effects and shale complexities. Based on the simulation studies and successful field pilots, CO2 could be successfully captured in shale gas reservoirs through gas injection and huff-n-puff regimes. The status of flaring gas emissions in oilfields and the outlook of economic utilization of greenhouse gases for enhanced oil or gas recovery and CO2 storage were given in the last section. The storage capacity varies in different simulation studies and is associated with well design, gas injection scheme and operation parameters, gas adsorption, molecular diffusion, and the modelling approaches.

A typical Iranian carbonate matrix block surrounded by an open fracture was modeled in order to understand the fracture-matrix interaction and realize how to model the interaction best. The modeling was carried out by using a fine-scaled Eclipse model in the single porosity mode (the fractures were explicitly modeled). The model was extended to a stack of 6 matrix blocks to understand block-to-block interaction under both water and gas injection scenarios. The results and conclusions obtained from the single porosity single block and 6-block model were used in order to optimize the full field model. The simulation results showed that gas injection worked as a major recovery mechanism for medium and good rock types at all block heights and for poor rock type with block heights of more than 2 meters. The oil recovery results were in the same range for the single and six-stack block model, but the delay of oil recovery by gas gravity drainage is clearly seen in the six-stack block results indicating a period of at least 8-10 years required for reaching ultimate oil recovery for typical block heights. The water injection simulations showed that water imbibes drained the matrix block in a short time dependent on water front advancement in the fracture system surrounding the block. From the simulation results, it was concluded that the water imbibition process was a fast recovery mechanism for all block heights dependent on injection rate and fracture volume which had to be flooded to achieve full recovery of the block. The expected recovery factor of drained oil to initial oil in place after water injection was in the range of 15-35 % for poor to good rock types and different block sizes in the range of 1-5 meters. The results were highly influenced by wettability conditions in the reservoir

The development of yielded or failure zone due to an engineering construction is a subject of study in different disciplines. In Petroleum engineering, depletion from and injection of gas into a porous rock can cause development of a yield zone around the reservoir. Studying this phenomenon requires elasto-plastic analysis of geomaterial, in this case the porous rocks. In this study, which is a continuation of a previous study investigating the elastic behaviour of geomaterial, the elasto-plastic responses of geomaterial were studied. A 3D finite element code (FEM) was developed, which can consider different constitutive models. The code features were explained and some case studies were presented to validate the output results of the code. The numerical model was, then, applied to study the development of the plastic zone around a horizontal porous formation subjected to the injection of gas. The model is described in detail and the results are presented. It was observed that by reducing the cohesion of rocks the extension of the plastic zone increased. Comparing to the elastic model, the ability to estimate the extension of the yield and failure zone is the main advantage of an elasto-plastic model.

For technical and economic success of miscible gas injection projects, an accurate laboratory measurement of Minimum Miscibility Pressure (MMP) at reservoir conditions is essential. On the other hand, compositional reservoir simulator is a useful tool in gas injection studies and prediction of MMP. The main goal of this paper is to describe a procedure to generate a three phase sequential type of compositional reservoir simulator. The solution method is completely addressed. A compositional thermodynamic program for equilibrium calculation, and pseudo-component determination was developed. Another purpose of this study is to prepare an experimental setup for investigating the effect of CO2 concentration in injecting gas on oil recovery and MMP.Some displacement tests using slim tube apparatus were performed and recoveries and MMPs were measured. Finally, experimental results were compared with the model predictions. A good agreement was achieved between the experimental data and model predictions.