Journal of Chemical Engineering and Energy Materials

Abstract Supercritical units usually work at a pressure of 24 MPa and above, which is higher than the critical water pressure of 22.09 MPa. A subcritical cylindrical steam generator usually works at about 13 MPa or 18 MPa. Many of the steam generators purchased in the 1970s and 1980s are cylindrical water tube types that operate at 18 MPa, produce superheated steam at 540°C, and have one or two stages of steam reheating. These generators have the ability to burn pulverized coal and petroleum fuels, although petroleum fuels gradually abandoned due to the increase in price and problems related to their supply. Although natural gas still used in power plants in some parts of the world, due to its high cost, it now mostly used for domestic purposes in the United States of America. Anyway, natural gas is a clean burning fuel and relatively pollution free. The steaming capacity of modern power plant steam generators is high and its value can vary from 125 to 1250 . Power plants are between 125 and 1300 megawatts. On the other hand, industrial steam generators are those that used in industrial companies and other institutions and include different types. These generators can be pulverized coal-fired water tube type steam generators, although they are powered by lump coal, oil or natural gas, and often a combination of them, as well as municipal waste, process waste energy, or other by-products also be used. In some of them even electric heating is used. Some of them are of the heat recovery type, in which the waste heat of industrial processes is used. These generators can also be of the fire tube type. Industrial steam generators usually do not produce superheated steam, but produce saturated steam or even only hot water.

Abstract In 2020, Cheng and his colleagues presented a paper entitled Al/Al2O3 direct bonding using transient eutectic liquid phase. In this research, they stated that ceramic base layers used in applications such as integrated circuit boards and diodes with high light emission. Directly bonded copper (DBC) layer is a ceramic layer that is widely used in electronic circuit boards for semiconductor modules, but the formation of CU2O at the interface causes a large deposition pressure. Therefore, the DBC layer has little strength against thermal cycling. Direct bonded aluminum (DBA), which uses aluminum as the metal circuit, used for ceramic layers. Although this combination not formed at the interface of ceramic and metal, but the bonded sample has good strength against thermal cycle. Khazaka et al. showed that in the work environment with thermal cycling, the DBA layer achieves better performance compared to the DBC layer. During thermal cycling tests from 55 to 250°C after 1500 cycles, no delamination of aluminum from the ceramic base metal plate observed. For conventional DBC technology, cracking or delamination occurs in DBC after 20 to 30 cycles. This improvement is due to the different plastic hardening behavior between aluminum and copper. To increase aluminum-ceramic bonding, the annealing temperature increased above the melting point of aluminum rather than the soaking effect. Increase and decrease the contact angle between aluminum and ceramic.

Abstract During the heating stage, the entire assembly placed in a furnace and its temperature increased from room temperature to below the eutectic temperature. When the assembly is heated, some solid-state penetration occurs between the interface layer and the base metal. The amount of penetration depends on several factors, including the surface roughness and cleanliness of the surface and the pressure exerted on the surface. In most cases, it expected that the amount of particle penetration of this stage is low. However, the amount of mass transferred in this step depends on the eutectic temperature, heating rate and diffusion coefficient. The longer the heating stage, the more penetration of elements that reduce the melting point in the base metal. If the heating rate is too low and the heating step is too long, the maximum concentration of the soluble element in the interlayer may be lower than its required value for melting, and therefore, by increasing the heating step too much, there may be no Do not form a liquid. After the dissolution and expansion phase, the melting point lowering elements permeate across the solid/melt interface in the base metal during an isothermal holding period. This infiltration process is similar to multiphase infiltration coupling. To maintain thermodynamic equilibrium, the melt composition at the solid/melt interface remains constant at CLα. Therefore, the composition of the melt assumed uniform throughout the width of the liquid. Since diffusion is faster in the melt than in the solid, the thickness of the melt is too thin for this assumption to consider accurate. The direction and rate of movement of the solid/melt interface should create a mass balance in the solid/melt interface, so that the direction of movement of the two solid/melt interfaces is towards the center of the connection.

Abstract The two combustion chambers are located vertically around the turbine and are connected to the turbine housing by side flanges. This type of design makes it possible to keep the inlet air from the compressor to the combustion chamber and from the combustion chamber to the turbine in one direction and causes the least relative pressure drop and relative velocity. Compressed air from the compressor entering the combustion chamber cools the outer shell of the hot gas. In addition, the symmetrical inlet and dual variable airflow results in a symmetrical temperature distribution with minimal pressure change in front of the first row of rotating vanes. Each combustion chamber consists of 8 burners (BURNER) designed for both gas and diesel fuel. Fuel burners operate in accordance with the law of reverse flow. This arrangement of the combustion chamber creates a great flexibility in the dimensions as well as the shape of the combustion system and provides a good possibility for inspection as well as the possibility of easy assembly and disassembly. Combined burners 1 cause diffusion as well as premixing of the flame and produce nitrous oxide and low carbon monoxide without spraying water and steam injection. However, a gas turbine engine can use a water or steam injection system to reduce pollution.

Abstract KKS identification codes used to identify various components in the P&I diagram, equipment list, electrical load list, instrumentation list, function diagrams, terminal diagrams, system descriptions, and other documents. In this regard, the specification of power plant units not recounted in general. In addition, as a simple rule, the 4 digits of the equipment key (for example "-S01") are not listed in P&ID. Most valves, precision measuring instruments, etc. have a NAME PLATE installed on which the complete KKS code of the instrument inserted, which also includes the unit number of the power plant. The KKS technical issues in question fully recounted to determine which equipment discussed. For example, the phrase "solenoid valve" MBA41AA010A should be used instead of the phrase "solenoid valve" operating BLOW OFF 1.2, 1.1. KKS coding used to order spare parts. The uniaxial arrangement of the turbine allows the compressor to operate directly and independently of the generator. Combustion of gas or liquid fuel done in two symmetrical combustion chambers with several burners located on both sides of the turbine. Each combustion chamber has 8 burners. Air enters the compressor through the suction channel and through filters and mufflers. In the compressor, the air pressure increases by almost 11 times. Compressed air directed to the burners (above each combustion chamber) and burned in the combustion chambers. Hot gases burned and converted into mechanical power through a turbine. The generator connected to the turbine compressor through the shaft. The electrical power generated by the generator delivered to the transformer through the generator terminals. Exhaust gases reach atmospheric pressure at an approximate temperature of 545 C through an axial diffuser. Exhaust gas enters the open air through a vertical exhaust.

Abstract Corrosion in Vacuum Distillation Units (VDUs) represents a significant challenge for refinery operations due to the complex nature of the feedstocks and extreme operating conditions. The VDU is responsible for processing heavy atmospheric residue under vacuum conditions to recover valuable products such as light and heavy vacuum gas oils. However, the presence of sulfur compounds, naphthenic acids, chlorides, and high temperatures promotes multiple corrosion mechanisms that can severely impact the reliability and lifespan of the unit. This paper provides a comprehensive review of the most common corrosion types in VDUs, including high-temperature sulfidation, naphthenic acid corrosion, chloride-induced corrosion, and erosion-corrosion. It identifies critical areas prone to degradation such as the furnace tubes, flash zone, vacuum tower internals, and overhead lines. Monitoring techniques such as corrosion probes, ultrasonic thickness measurements, and infrared thermography are discussed for early detection and control. Furthermore, the paper outlines key mitigation strategies including material upgrades, chemical injection programs, enhanced crude desalting, and operational improvements. A case study from a Middle Eastern refinery is presented to demonstrate the practical application of these strategies and the measurable reduction in corrosion rates. The findings emphasize the importance of integrating proactive corrosion management into the overall maintenance and reliability programs of refineries to enhance safety, reduce downtime, and improve economic performance.

Abstract Corrosion in refinery units, particularly in Naphtha Hydrotreating (NHT) and Continuous Catalytic Reforming (CCR) units, represents a significant threat to operational reliability, safety, and economic efficiency. This study presents a comprehensive data-driven analysis of corrosion behavior in NHT and CCR units based on real-time plant data, historical maintenance logs, and process parameters. Using statistical and machine learning methods, we identify key operational factors contributing to corrosion rates, including temperature, pressure, hydrogen partial pressure, and contaminants such as chlorides and sulfur compounds. Furthermore, the study evaluates the effectiveness of different mitigation strategies such as corrosion inhibitors, metallurgy upgrades, process optimization, and vapor phase conditioning in various sections of the units, including reactors, heat exchangers, furnaces, and piping systems. It investigates how operating envelopes and process excursions influence the onset and progression of localized corrosion phenomena such as pitting, erosion-corrosion, and stress corrosion cracking. The findings aim to provide actionable insights for refining operators, integrity managers, and process engineers involved in asset management and corrosion control. The study further evaluates the effectiveness of various corrosion mitigation strategies including material upgrades, corrosion inhibitors, process control optimization, and predictive maintenance protocols. The findings aim to support refinery operators in making informed decisions to extend equipment life, reduce downtime, and enhance safety in high-temperature, hydrogen-rich environments.

Abstract In the present study, while identifying potential risks and classifying them according to the Risk Breakdown Structure (RBS), we determine the criteria for identifying and assessing risks qualitatively, and then by converting qualitative criteria into quantitative ones and using the FMEA technique and calculating the Risk Priority Number (RPN) and responding to high-priority risks, we control the obstacles to achieving the project goals. By carrying out this process in the oil processing unit construction project, which was carried out using the EPC method, important and risky risks were identified and controlled based on the project phases, and precise control was exercised to prevent imposing additional and possible costs on the project and creating defects in its other objectives, so that important and influential risks on key project activities were organized in the form of a risk management plan, and their future and possible consequences, which could be one of the most important factors in the failure to comply with the project implementation plan, were minimized. The results of the present study showed that approximately 43% of the losses were due to mechanical integrity failure, and this percentage was higher for losses caused by oil refinery. Of these mechanical failures, 70% were identified as a result of corrosion of process pipes, mainly due to internal corrosion. In cases where external corrosion was the cause, the cause was insulation corrosion.

Abstract Corrosion in Liquefied Petroleum Gas (LPG) units poses significant challenges to the safety, reliability, and efficiency of refining and petrochemical operations. These units operate under high pressure and varying temperature conditions, exposing metallic equipment to aggressive environments containing corrosive agents such as hydrogen sulfide (H₂S), carbon dioxide (CO₂), moisture, and trace acidic compounds. The interaction of these substances with carbon steel and other commonly used materials leads to various corrosion phenomena, including uniform corrosion, localized pitting, and stress corrosion cracking. Sweet corrosion, primarily driven by CO₂, results in the formation of iron carbonate protective scales under certain conditions, while sour corrosion induced by H₂S forms brittle iron sulfide layers that exacerbate metal degradation. Additionally, microbiologically influenced corrosion (MIC) caused by sulfate-reducing bacteria further complicates corrosion management in LPG storage facilities. Effective corrosion control requires a multifaceted approach involving material selection, chemical inhibitors, protective coatings, and rigorous operational monitoring. Electrochemical techniques such as Electrochemical Impedance Spectroscopy (EIS) and Linear Polarization Resistance (LPR) are widely employed for real-time corrosion rate assessment. Despite advancements in mitigation strategies, corrosion remains a critical concern due to its impact on operational costs, safety hazards, and equipment lifespan. Continued research and development are essential to optimize corrosion prevention methods and enhance the durability of LPG processing and storage infrastructure.

Abstract The production of polymers, particularly PVC and its related copolymers, requires stringent control of operating conditions to minimize occupational exposure to VCM. In industrial practice, VCM synthesis is typically conducted in fully closed systems, which effectively reduce atmospheric emissions and worker exposure. Nevertheless, due to its high flammability, VCM vapor poses a significant fire and explosion hazard. Accidental releases under pressure can also result in frostbite because of rapid depressurization. Furthermore, the potential for long–range vapor dispersion necessitates rigorous control of potential ignition sources and strict adherence to process safety protocols.
In this study, a comprehensive and rigorously validated process model for VCM production was developed using Aspen Plus. The balanced process, which integrates both direct chlorination and oxychlorination routes, was simulated to determine an optimized, energy–efficient, and industrially feasible configuration. Detailed molecular kinetic models were incorporated for all major reactor units, accounting for both primary and secondary reaction pathways. The thermodynamic framework was based on the modified SRK equation of state, ensuring accurate vapor–liquid equilibrium representation for multi-component systems. Model validation against published plant-scale data showed excellent agreement in conversion, selectivity, and yield predictions. The developed simulation framework provides a robust foundation for future work on process optimization, heat integration, and safety analysis in large-scale VCM production plants.

Abstract The relationship between industrialization and rural development in the texts of developing countries has different views, so that Rajesh Chandar has emphasized the role of industrialization in the development process by expressing these views and believes that the following views have made the role of industry in development more sensitive. Industrialization in developing countries is known as a historical necessity. In this regard, due to the lack of another provable model for development, historically this claim that development requires industrialization has been accepted. Due to the minimization of the competitiveness of the agricultural sector compared to the industrial sector and the significant reduction in the price of agricultural products compared to industrial products, the trade conditions in the agricultural sector are significantly limited and the tendency towards industrialization as it is an economic fact. Even if the manufacturing and production of goods in the process of industrialization is not considered as a desirable option for the development of the agricultural sector, the trend towards industrial activities can be a source of encouragement for the economic development process as a complement to the agricultural sector.

Abstract Corrosion in Naphtha Hydro treating (NHT) units poses a significant challenge to the long-term reliability and economic performance of petroleum refineries. These units operate under severe conditions—high temperatures, elevated hydrogen pressures, and the presence of corrosive species such as hydrogen sulfide (H₂S), organic acids, and chlorides—which create an aggressive environment for materials of construction. This study investigates the key operational factors that influence corrosion rates in an NHT unit using a six-month dataset from a hypothetical refinery scenario. Data collected includes reactor temperature and pressure, feed sulfur content, amine inhibitor dosage, and field-measured corrosion rates from corrosion coupons installed in critical locations. Statistical analysis revealed strong positive correlations between corrosion rate and both feed sulfur content (r = 0.81) and reactor temperature (r = 0.74), while amine inhibitor dosage showed a moderate inverse relationship (r = -0.66). A multiple linear regression model was developed to predict corrosion rate as a function of these parameters, with an R² value of 0.83, indicating high predictive accuracy. Corrosion hotspots were identified at the reactor inlet and in the cold zones of heat exchangers, suggesting the need for targeted monitoring and material upgrades in those areas. The study concludes that optimizing feed quality, maintaining appropriate inhibitor dosing, and deploying real-time corrosion monitoring can significantly mitigate corrosion risk. The findings provide a quantitative foundation for corrosion risk assessment in NHT units and offer actionable insights for improving operational safety and asset longevity in hydro processing environments.