Search Results (12)

To enhance the steam parameters of steam injection boilers during the thermal recovery of heavy oil while ensuring the safe and stable operation of boiler pipelines, this study conducted two-phase flow boiling numerical simulations in a horizontal heated tube with an inner diameter of 65 mm, using water and water vapor as working fluids. The analysis focused on the gas–liquid phase distribution, temperature profiles, near-wall fluid velocity, and pressure drop along both the axial and radial directions of the tube. Furthermore, the effects of heat flux density, mass flow rate, and inlet subcooling on these parameters were systematically investigated. The results reveal that higher heat fluxes intensify the velocity difference between the upper and lower tube walls and enlarge the temperature gradient across the wall surface. A reduction in mass flow rate increases the gas phase fraction within the tube and causes the occurrence of identical flow patterns at earlier axial positions. Additionally, the onset of nucleate boiling shifts upstream, accompanied by an increase and upstream movement of the wall’s maximum temperature. An increase in inlet subcooling prolongs the time required for the working fluid mixture to reach saturation, thereby decreasing the gas phase fraction and delaying the appearance of the same flow patterns. Finally, preventive and control strategies for ensuring the safe operation of steam injection boiler pipelines during heavy oil recovery are proposed from the perspective of flow pattern regulation. Full article

The CO₂ injection technology for replacing CH₄ to enhance coalbed methane (CBM) recovery (CO₂-ECBM) offers dual benefits, i.e., reducing CO₂ emissions through sequestration and increasing CBM recovery, thereby leading to economic gains. However, there is no clear consensus on how temperature and pressure affect the competitive adsorption characteristics of CO₂ and CH₄ mixed gases in coal. Therefore, the competitive adsorption behavior of CO₂ and CH₄ mixed gases at various pressures and temperatures were investigated using the breakthrough curve method. Anthracite was selected for the adsorption experiment conducted under three gas injection pressure levels (0.1 MPa, 0.5 MPa, and 1 MPa) and at three temperature levels (20 °C, 40 °C, and 60 °C). This study showed that, when the temperature remained constant and the pressure ranged from 0.1 to 1 MPa, the adsorption rates of CO₂ and CH₄ increased as pressure rose. Additionally, the selectivity coefficient for CO₂/CH₄ decreased with an increase in pressure, suggesting that higher pressures within this range are not conducive to the replacement efficiency of CH₄ by CO₂. As the temperature increased from 20 to 60 °C under constant pressure conditions, both the selectivity coefficients for CO₂/CH₄ and the adsorption rates of CO₂ and CH₄ exhibited a downward trend. These findings imply that, within this temperature range, a reduced temperature improves the ability of CO₂ to efficiently displace CH₄. Moreover, CO₂ exhibits a higher isosteric heat of adsorption compared to CH₄. Full article

Accurate prediction of the temperature and pressure fields in carbon dioxide (CO₂) injection wells is critical for enhancing oil recovery efficiency and ensuring safe carbon sequestration. At present, the prediction model generally assumes that CO₂ is pure and does not consider the influence of impurities in CO₂ components. This study takes into account the common impurities, such as air and various alkanes in CO₂, and uses Refprop 9.0 software to calculate the physical parameters of the mixture. A comprehensive coupling model was developed to account for axial heat conduction, convective heat transfer, frictional heat generation, the soup coke effect, pressure work, and gas composition. The model was solved iteratively using numerical methods. We validated the accuracy of the calculated results by comparing our model with the Ramey model using measured injection well data. Compared with the measured bottom hole temperature and pressure data, the error percentage of our model to predict the bottom hole temperature and pressure is less than 1%, while the error percentage of Ramey model to predict the bottom hole temperature and pressure is 5.15% and 1.33%, respectively. Our model has higher bottom hole temperature and pressure prediction accuracy than the Ramey model. In addition, we use the model to simulate the influence of different injection parameters on wellbore temperature and pressure and consider the influence of different gas components. Each injection parameter uses three components. Based on the temperature and pressure data calculated by the model simulation, the phase state of CO₂ was analyzed. The results show that the impurities in CO₂ have a great influence on the predicted wellbore pressure, critical temperature, and critical pressure. In the process of CO₂ injection, increasing the injection pressure can significantly increase the bottom hole pressure, and changing the injection rate can adjust the bottom hole temperature. The research provides valuable insights for CO₂ sequestration and enhanced oil recovery (EOR). Full article

Phase change modeling in porous media is among the important challenges in many essential engineering problems, including thermal management, energy conservation or recovery, and heat transfer. One particularly efficient method of dissipating heat in a porous material is transpiration cooling with phase change. It is one of the most innovative cooling methods available for removing excessive heat flux from engine components such as combustors or gas turbine blades. There is, however, a lack of in-depth understanding of the interconnected mechanisms involved in such an application. In this work, an innovative numerical solver built on the OpenFOAM environment is constructed in order to explore the phase change process in a porous medium. The volume-of-fluid method and the Lee phase change model are applied in this numerical approach. The effects of coolant flow mass rate, heat flux, and porosity of porous structure on temperature and saturation distribution are investigated and discussed. The effects of both the external heat flux and the coolant mass flow rate under fixed porosity are also studied. The phase change is then delayed in the porous matrix when the amount of the injected coolant is increased. It reduces the area of two-phase and vapor regions. Also, a considerable rise in the upper surface temperature is obtained when the input heat flux or the porosity is separately enhanced. Full article

To promote energy conservation and a low-carbon approach in natural gas storage, efficient methods for utilizing waste heat during gas injection and maintaining adequate cooling rates are crucial. This study developed a three-dimensional model integrating the desorption process of hydrated salts to analyze temperature and flow fields within a moving bed during heat exchange. This study systematically evaluated the effects of operating parameters on key outcomes, including the outlet temperatures of hydrated salts and natural gas, as well as the waste heat recovery ratio. Results indicated that the outlet temperatures of natural gas and particles varied synchronously, while the waste heat recovery ratio exhibited an inverse relationship with the natural gas outlet temperature. Remarkably, incorporating a composite material comprising hydrated calcium chloride and hydrated magnesium sulfate into the moving bed reduced the natural gas outlet temperature from 60 °C to 47.5 °C. Concurrently, the waste heat recovery ratio improved substantially, rising from 66% to 90%. Furthermore, the proposed moving bed heat exchange system requires less than one-third of the volume of conventional natural gas air-cooled heat exchangers. These findings provide theoretical insights and robust data support for enhancing cross-seasonal waste heat utilization in natural gas storage facilities. Full article

The methods of increasing the efficiency of internal combustion engines through heat utilization are examined. A proposed classification of heat utilization systems for mobile energy vehicles is presented. External utilization harnesses the heat generated by a diesel engine to fulfill the needs of consumers not directly related to the engine, such as interior heating and air conditioning systems. Internal recycling focuses on enhancing the power, environmental performance, and economic performance of an engine and its related systems. Various heat utilization schemes are compared. For the economic conditions of the European Union (EU), a turbocompounding diesel engine is acceptable if its agricultural tractor rated power is more than 275 kW and its combine harvester rated power is more than 310 kW. Steam injection into the combustion chamber is utilized to improve the technical and economic performance of gas turbine engines. This technology is also produced in Ukraine and is proposed for use in internal combustion engines. It is suggested to inject water vapor into a turbocharger turbine. This approach reduces the number of components in the heat recovery system, thereby lowering its cost. A recycling chiller can be employed to cool the air after it passes through the air cleaner, enhance the efficiency of the air cooler, and improve the performance of the thermoelectric generators. This device is particularly effective at relatively high air temperatures and can be recommended for agricultural machinery that operates in such conditions, such as combines. With the application of this new technology, it is possible to increase the power of diesel engines by 15…20% and reduce fuel consumption by up to 14%. Further research will focus on substantiating the parameters of recycling systems for different classes of vehicles. Developing a methodology to justify the effective application of heat utilization systems in agricultural mobile energy vehicles is advisable. Full article

With the strategic goal of “carbon peaking and carbon neutral” in China, new requirements are also put forward for the thermal recovery of heavy oil. In view of the problems of excessive greenhouse gas emission, low steam utilization rate, poor economic efficiency, and limited reservoir application of steam stimulation replacement technology in China, the emerging technologies of medium- and low-temperature thermal fluid, solvent-assisted high-temperature steam injection, solvent-based medium- and low-temperature waterless recovery and in situ electric heating-assisted recovery are discussed in terms of technical principles, technical parameters, experimental/field effects, and technical and economic potential. The technical principles, technical parameters, experimental/field results, and techno-economic potential of low-carbon heavy oil recovery technologies are summarized and future development directions and trends are anticipated. The study’s findings indicate that some of the technologies that have been tested in the field, such as HWVP, EMVAPEX, AH-VAPEX, LASER, and ESEIEH, can be developed by relying on the original well groups for production and can reduce greenhouse gas emissions, such as CO₂, by about 80% and improve crude oil recovery by 5% to 10%, while the technologies concerned have outstanding effects on increasing oil production rate and lowering upfront capital investment. Some of the technologies that have been tested significantly increase oil production rate, lower initial capital expenditure, and enable solvent recycling, among other things. Among them, COBEEOR and N-SOLV technologies can also lower the amount of asphaltene in the output crude oil, enhance the API of the recovered crude oil, and provide strong economic advantages. CSP, CHSI, and hot water solvent injection were tested in indoor two-dimensional and three-dimensional experiments to validate their feasibility, while CO₂, propane, and butane solvents were initially screened and some of the technologies’ mechanisms were revealed to lay the groundwork for pilot projects. The executive summary of the research findings will serve as a guide for future low-carbon extraction technology research and development in China. Full article

Heavy oil resources are attracting considerable interest in terms of sustaining energy demand. However, the exploitation of such resources requires deeper understanding of the processes occurring during their development. Promising methods currently used for enhancing heavy oil recovery are steam injection methods, which are based on aquathermolysis of heavy oil at higher temperatures. Regardless of its efficiency in the field of in situ upgrading of heavy oil, this technique still suffers from energy consumption and inefficient heat transfer for deeper reservoirs. During this study, we have developed a molybdenum-based catalyst for improving the process of heavy oil upgrading at higher temperature in the presence of water. The obtained catalyst has been characterized by a set of physico-chemical methods and was then applied for heavy oil hydrothermal processing in a high-pressure reactor at 200, 250 and 300 °C. The comparative study between heavy oil hydrothermal upgrading in the presence and absence of the obtained molybdenum-based oil soluble catalysts has pointed toward its potential application for heavy oil in situ upgrading techniques. In other words, the used catalyst was able to reduce heavy oil viscosity by more than 63% at 300 °C. Moreover, our results have demonstrated the efficiency of a molybdenum-based catalyst in improving saturates and light hydrocarbon content in the upgraded oil compared to the same quantity of these fractions in the initial oil and in the non-catalytically upgraded oil at similar temperatures. This has been explained by the significant role played by the used catalyst in destructing asphaltenes and resins as shown by XRD, elemental analysis, and gas chromatography, which confirmed the presence of molybdenum sulfur particles in the reaction medium at higher temperatures, especially at 300 °C. These particles contributed to stimulating hydrodesulphurization, cracking and hydrogenation reactions by breaking down the C-heteroatom bonds and consequently by destructing sphaltenes and resins into smaller fractions, leading to higher mobility and quality of the upgraded oil. Our results add to the growing body of literature on the catalytic upgrading of heavy oil in the presence of transition metal particles. Full article

Heat treatment on shale reservoirs can promote the development of secondary fractures in a matrix on the basis of hydraulic fracturing, forming multi-scale gas–water seepage channels and strengthening the gas desorption. Experimental evidence shows that heat treatment can enhance gas recovery in the same mining life. Heat treatment on a shale gas reservoir is a multi-physical and multi-phase coupling process. However, how the thermal stimulation interacts with nonlinear two-phase flow in heterogeneous shale volume fracturing has not been clear. In this paper, a fully coupled THGM model for heating-enhanced shale-gas recovery in heterogeneous shale reservoirs is proposed. First, the governing equations are formulated for the shale-reservoir deformation involving both gas adsorption and thermal expansion, the permeability evolution model for the cracking process of fractured shale, the gas–water two-phase continuity equation considering the effects of gas solubility and the heat transfer equation for heat conduction and convection. The interactions among stress, temperature and seepage in a heterogeneous shale reservoir were studied. Secondly, a test on shale permeability after 50 °C temperature treatment was conducted. The evolution of temperature, capillary pressure, water and gas saturation and the permeability of shale during the heat treatment of the reservoir were numerically analyzed. Finally, the gas production from a shale gas reservoir was numerically simulated with this THGM model. The numerical results indicated that the thermal-induced fracturing, gas desorption and separation from water make predominant contributions to the evolution of permeability. The heat treatment can enhance cumulative gas production by 58.7% after 27.4 years of heat injection through promoting gas desorption and matrix diffusion. Full article

For every three people on the planet, there are approximately two Tonnes (Te) of plastic waste. We show that carbon recovery from polystyrene (PS) plastic is enhanced by the coaddition of solvents to grow carbon nanotubes (CNTs) by liquid injection chemical vapour deposition. Polystyrene was loaded up to 4 wt% in toluene and heated to 780 °C in the presence of a ferrocene catalyst and a hydrogen/argon carrier gas at a 1:19 ratio. High resolution transmission electron microscopy (HRTEM), scanning electron microscopy (SEM), thermogravimetric analysis (TGA) and Raman spectroscopy were used to identify multiwalled carbon nanotubes (MWCNTs). The PS addition in the range from 0 to 4 wt% showed improved quality and CNT homogeneity; Raman “Graphitic/Defective” (G/D) values increased from 1.9 to 2.3; mean CNT diameters increased from 43.0 to 49.2 nm; and maximum CNT yield increased from 11.37% to 14.31%. Since both the CNT diameters and the percentage yield increased following the addition of polystyrene, we conclude that carbon from PS contributes to the carbon within the MWCNTs. The electrical contact resistance of acid-washed Bucky papers produced from each loading ranged from 2.2 to 4.4 Ohm, with no direct correlation to PS loading. Due to this narrow range, materials with different loadings were mixed to create the six wires of an Ethernet cable and tested using iPerf3; the cable achieved up- and down- link speeds of ~99.5 Mbps, i.e., comparable to Cu wire with the same dimensions (~99.5 Mbps). The lifecycle assessment (LCA) of CNT wire production was compared to copper wire production for a use case in a Boeing 747-400 over the lifespan of the aircraft. Due to their lightweight nature, the CNT wires decreased the CO₂ footprint by 21 kTonnes (kTe) over the aircraft’s lifespan. Full article

The adsorption of CO₂ and CO₂/CH₄ mixtures on kaolinite was calculated by grand canonical Monte Carlo (GCMC) simulations with different temperatures (283.15, 293.15, and 313.15 K) up to 40 MPa. The simulation results show that the adsorption amount of CO₂ followed the Langmuir model and decreased with an increasing temperature. The excess adsorption of CO₂ increased with an increasing pressure until the pressure reached 3 MPa and then decreased at different temperatures. The $S_{C{O}_2/C{H}_4}$ decreased logarithmically with increasing pressure, and the $S_{C{O}_2/C{H}_4}$ was lower with a higher temperature at the same pressure. The interaction energy between CO₂ and kaolinite was much higher than that between CH₄ and kaolinite at the same pressure. The interaction energy between the adsorbent and adsorbate was dominant, and that between CO₂ and CO₂ and between CH₄ and CH₄ accounted for less than 20% of the total interaction energy. The isothermal adsorption heat of CO₂ was higher than that of CH₄, indicating that the affinity of kaolinite to CO₂ was higher than that of CH₄. The strong adsorption sites of carbon dioxide on kaolinite were hydrogen, oxygen, and silicon atoms, respectively. CO₂ was not only physically adsorbed on kaolinite, but also exhibited chemical adsorption. In gas-bearing reservoirs, a CO₂ injection to displace CH₄ and enhance CO₂ sequestration and enhanced gas recovery (CS-EGR) should be implemented at a low temperature. Full article

Depleted gas reservoirs are appealing targets for carbon dioxide (CO ${}_2$ ) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO ${}_2$ and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO ${}_2$ injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO ${}_2$ within the wellbore. When the reservoir pressure is below the CO ${}_2$ bubble-point pressure, and CO ${}_2$ is injected in its liquid or supercritical state, CO ${}_2$ will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance, when CO ${}_2$ transitions from the dense-state to the gas-state, CO ${}_2$ density drops sharply, affecting the wellhead pressure control and the pressure response at the well bottom-hole. As CO ${}_2$ expands with a lower phase viscosity, the flow velocity increases abruptly, possibly causing erosion and cavitation in the flowlines. Furthermore, CO ${}_2$ expansion is associated with the Joule–Thomson (IJ) effect, which may result in dry ice or hydrate formation and therefore may reduce CO ${}_2$ injectivity. Understanding the transient multiphase phase flow behavior of CO ${}_2$ within the wellbore is crucial for appropriate well design and operational risk assessment. The commonly used approach analyzes the flow in the wellbore without taking into consideration the transient pressure response of the reservoir, which predicts an unrealistic pressure gap at the wellhead. This pressure gap is related to the phase transition of CO ${}_2$ from its dense state to the gas state. In this work, a new coupled approach is introduced to address the phase behavior of CO ${}_2$ within the wellbore under different operational conditions. The proposed approach integrates the flow within both the wellbore and the reservoir at the transient state and therefore resolves the pressure gap issue. Finally, the energy costs associated with a mitigation process that involves CO ${}_2$ heating at the wellhead are assessed. Full article