Aspen HYSYS Research Articles

Exergy efficiency improvement by compression heat recovery for an integrated natural gas liquefaction-CO2 capture-NGL recovery process

For liquefied natual gas production, cryogenic distillation offers lower thermal energy consumption and a more compact footprint for carbon capture unit than the widely used chemical absorption. However, the reduction in thermal energy consumption comes at the cost of increased power consumption. To reduce the power consumption of cryogenic distillation based natural gas lqiuefaction plants, an integrated process for liquefied natual gas production, cryogenic CO2 capture and natural gas liquids recovery is proposed, which is called the base process. This base process is further integrated with a heat recovery unit (Organic Rankine cycle or Kalina cycle) to investigate the optimal utilization of compression heat in the system. The proposed processes are modeled in Aspen HYSYS and optimized using a genetic algorithm installed in Matlab. The results show that specific power consumption of the base case is 0.385 kWh/Nm3 NG. Due to the lack of compression heat recovery, significant exergy loss occurs at the water coolers, accounting for approximately 37 % of the total system exergy destruction. Among the evaluated methods, the supercritical Organic Rankine cycle, using R1234ze as the working fluid, recovers approximately 60 % of the exergy from compression heat with an 8.7 % improvement in system exergy efficiency. The subcritical Organic Rankine cycle, using R600a as the working fluid, achieves a slightly lower exergy efficiency improvement of 7.1 %. The Kalina cycle, while less efficient, still improves the system’s exergy efficiency by 6.3 %. Economic analysis reveals that the total annualized cost of the base process is $8,441,416, with a levelized cost of $0.1411/kg. The subcritical Organic Rankine Cycle provides the most cost-effective solution, with the lowest total annualized cost of $8,305,154 and a levelized cost of $0.1402/kg. The Kalina cycle ranks second in cost-effectiveness, with a total annualized cost of $8,345,914 and a levelized cost of $0.1405/kg NG. Although the supercritical ORC requires the highest capital investment, it proves more cost-effective than the base process due to its reduced annual operating costs.

Diagnosis of GHG Emissions in an Offshore Oil and Gas Production Facility

This work presents a diagnosis of greenhouse gas (GHG) emissions for floating production storage and offloading (FPSO) platforms for oil and gas production offshore, using calculation methodologies from the American Petroleum Institute (API) and U.S. Environmental Protection Agency (EPA). To carry out this analysis, design data of an FPSO platform is used for the GHG emissions estimation, considering operations under steady conditions and oil and gas processing system simulations in the Aspen HYSYS® software. The main direct emission sources of GHG are identified, including the main combustion processes (gas turbines for electric generation and gas turbine-driven CO2 compressors), flaring and venting, as well as fugitive emissions. The study assesses a high CO2 content in molar composition of the associated gas, an important factor that is considered in estimating fugitive emissions during the processes of primary separation and main gas compression. The resulting information indicates that, on average, 95% of total emissions are produced by combustion sources. In the latest production stages of the oil and gas field, it consumes 2 times more energy and emits 2.3 times CO2 in terms of produced hydrocarbons. This diagnosis provides a baseline and starting point for the implementation of energy efficiency measures and/or carbon capture and storage (CCS) technologies on the FPSO in order to reduce CO2 and CH4 emissions, as well as identify the major sources of emissions in the production process.

Modeling of Liquefied Natural Gas Cold Power Generation for Access to the Distribution Grid

Cold energy generation is an important part of liquefied natural gas (LNG) cold energy cascade utilization, and existing studies lack a specific descriptive model for LNG cold energy transmission to the AC subgrid. Therefore, this paper proposes a descriptive model for the grid-connected process of cold energy generation at LNG stations. First, the expansion kinetic energy transfer of the intermediate work mass is derived and analyzed in the LNG unipolar Rankine cycle structure, the mathematical relationship between the turbine output mechanical power and the variation in the work mass flow rate and pressure is established, and the variations in the LNG heat exchanger temperature difference, seawater flow rate, and the turbine temperature difference in the cycle system are investigated. Secondly, based on the fifth-order equation of state of the synchronous generator, the expressions of its electromagnetic power, output AC frequency, and voltage were analyzed. Finally, the average equivalent models of the machine-side and grid-side converters are established using a direct-fed grid-connected structure, thus forming a descriptive model of the overall drive process. The ORC model is built in Aspen HYSIS to obtain the time series expression of the torque output of the turbine; based on the ORC output torque, the permanent magnet synchronous generator (PMGSG) as well as the direct-fed grid-connected structure are built in MATLAB/Simulink, and the active power and current outputs of the grid-following-type voltage vector control method and the grid-forming-type power-angle synchronous control method are also verified.

Advanced Exergy-Based Optimization of a Polygeneration System with CO2 as Working Fluid.

Using polygeneration systems is one of the most cost-effective ways for energy efficiency improvement, which secures sustainable energy development and reduces environmental impacts. This paper investigates a polygeneration system powered by low- to medium-grade waste heat and using CO2 as a working fluid to simultaneously produce electric power, refrigeration, and heating capacities. The system is simulated in Aspen HYSYS® and evaluated by applying advanced exergy-based methods. With the split of exergy destruction and investment cost into avoidable and unavoidable parts, the avoidable part reveals the real improvement potential and priority of each component. Subsequently, an exergoeconomic graphical optimization is implemented at the component level to improve the system performance further. Optimization results and an engineering solution considering technical limitations are proposed. Compared to the base case, the system exergetic efficiency was improved by 15.4% and the average product cost was reduced by 7.1%; while the engineering solution shows an increase of 11.3% in system exergetic efficiency and a decrease of 8.5% in the average product cost.

Comparative Hydrogen Production Routes via Steam Methane Reforming and Chemical Looping Reforming of Natural Gas as Feedstock

Hydrogen production is essential in the transition to sustainable energy. This study examines two hydrogen production routes, steam methane reforming (SMR) and chemical looping reforming (CLR), both using raw natural gas as feedstock. SMR, the most commonly used industrial process, involves reacting methane with steam to produce hydrogen, carbon monoxide, and carbon dioxide. In contrast, CLR uses a metal oxide as an oxygen carrier to facilitate hydrogen production without generating additional carbon dioxide. Simulations conducted using Aspen HYSYS analyzed each method’s performance and energy consumption. The results show that SMR achieved 99.98% hydrogen purity, whereas CLR produced 99.97% purity. An energy analysis revealed that CLR requires 31% less energy than SMR, likely due to the absence of low- and high-temperature water–gas shift units. Overall, the findings suggest that CLR offers substantial advantages over SMR, including lower energy consumption and the production of cleaner hydrogen, free from carbon dioxide generated during the water–gas shift process.

Comprehensive technical analysis of post-combustion carbon capture and storage based on monoethanolamine absorption for petrochemical industry in Indonesia

Abstract The implementation of carbon capture and storage in the petrochemical industry is one of the means of decarbonization. This research focuses on a comprehensive technical analysis of the deployment of post-combustion carbon capture and storage based on monoethanolamine absorption in the petrochemical industry. The olefin complex petrochemical industry in Tuban, Indonesia, is the basis for the analysis, which includes a steam cracker, polyethylene, polypropylene, and raw pyrolysis gasoline hydrotreating units, with capacities of 1000, 940, 600, and 570 kilotons/year, respectively. The total energy consumption is about 16 024.53 GJ/h, and the CO2 emissions are about 1.6 megatons/year. Based on these plant systems, comprehensive technical analyses of the implementation of carbon capture and storage in that industry were performed using Aspen HYSYS® simulation software. Sensitivity analysis was carried out to determine the total CO2 captured, energy intensity, monoethanolamine consumption, and net CO2 captured in various scenarios based on the number of absorber column stages, absorption pressure, and desorption temperature. The CO2 storage site is about 100 km away and is transported by an onshore pipeline with a supercritical phase of CO2. The optimal net CO2 capture value is achieved by setting up a 50-stage absorber column with a pressure of 1 barg and a temperature of 110°C at the top of the desorber column, resulting in a CO2 capture yield of 86.4% and an energy intensity of 12.6 GJ/ton CO2. Under these conditions, the net CO2 captured in the scenario based on gas power plants’ electricity is 0.225 megatons/year, while in the scenario based on gas power plants incorporating 30% biomass electricity, it is 0.544 megatons/year. With increased use of renewable energy in carbon capture and storage facilities, more net CO2 is captured. This study can be applied to various cases of post-combustion carbon capture and storage implementation in the industrial sector, especially in the petrochemical industry.

Responding to low-carbon shipping via a novel BOG-ORC-CCS system onboard LNG carrier: 4E analyses and optimization

As the international LNG trade market is booming, the LNG carrier fleet has expanded year after year. How to reduce energy consumption in boil-off gas (BOG) re-liquefaction process and CO2 generated during transportation has become a hot topic. This paper obtains ideas from the LNG cold energy contained in LNG carriers, and proposes a novel BOG-ORC-CCS system for direct BOG re-liquefaction, Organic Rankine cycle (ORC) and carbon capture and storage (CCS). The BOG-ORC-CCS system recycles waste heat from the ship while realizing the LNG cold energy gradient utilization. The reference ship (Q-Flex) is specified under the framework of Energy Efficiency Design Index (EEDI) phase Ⅲ requirement and the BOG-ORC-CCS system is simulated by Aspen HYSYS software. A comprehensive evaluation of the system performance is carried out under the guidance of energy, exergy, economic and environment (4E) modeling. The results of the 4E analyses show that the proposed BOG-ORC-CCS system has the advantage of low energy consumption and good economic performance. Finally, a multi-objective optimization of the system performance in 4E aspects: system energy and exergy efficiency (ηen,sys×ηex,sys), payback period (PBP) and primary energy saved (PES) are carried out by the third-generation non-dominated sorting genetic algorithm (NSGA-Ⅲ). As a result, the optimal solutions are as follows: ηen,sys is 50.91%, ηex,sys is 54.00%, PBP is 1.55 years and PES is 1.32 MWh, while Load of 75%, TL5 is −136.01 °C, pB5 is 1.82 MPa and ScrL2 is 99.88%. Additionally, SEC is 0.20 kWh/kg, which is much lower than that of conventional indirect re-liquefaction. This demonstrates the feasibility of the BOG-ORC-CCS system on LNG carriers.

CH4 and CO2 Reductions from Methanol Production Using Municipal Solid Waste Gasification with Hydrogen Enhancement

This study evaluates the greenhouse gas (GHG) impacts of converting municipal solid waste (MSW) into methanol, focusing on both landfill methane (CH4) emission avoidance and the provision of cleaner liquid fuels with lower carbon intensity. We conduct a life cycle assessment (LCA) to assess potential GHG reductions from MSW gasification to methanol, enhanced with hydrogen produced via natural gas pyrolysis or water electrolysis. Hydrogen enhancement effectively doubles the methanol yield from a given amount of MSW. Special attention is given to hydrogen production through natural gas pyrolysis due to its potential for lower-cost hydrogen and reduced reliance on renewable electricity compared to electrolytic hydrogen. Our analysis uses a case study of methanol production from an oxygen-fired entrained flow gasifier fed with refuse-derived fuel (RDF) simulated in Aspen HYSYS. The LCA incorporates the significant impact of landfill methane avoidance, particularly when considering the 20-year global warming potential (GWP). Based on the LCA, the process has illustrative net GHG emissions of 183 and 709 kgCO2e/t MeOH using renewable electricity for electrolytic hydrogen and pyrolytic hydrogen, respectively, for the 100-year GWP. The net GHG emissions using 20-year GWP are −1222 and −434 kgCO2e/t MeOH, respectively. Additionally, we analyze the sensitivity of net GHG emissions to varying levels of fugitive methane emissions.

Performance Evaluation of CO2 + SiCl4 Binary Mixture in Recompression Brayton Cycle for Warm Climates

This work demonstrates the potential of CO2 + SiCl4 binary mixture as a working fluid for power generation cycle. Recompression Brayton cycle configuration is considered due to its proven record of high performance for medium- to high-temperature sources. The objective of this study is to assess the thermodynamic performance of a recompression Brayton cycle using a CO2 + SiCl4 binary mixture as a working fluid, particularly under warm climate conditions. The cycle is simulated using the Peng–Robinson equation of state in Aspen Hysys (v11) software, and the model is validated by comparing VLE data against experimental data from the literature. The analysis involves the assessment of cycle’s thermal efficiency and exergy efficiency under warm climatic conditions, with a minimum cycle temperature of 40 °C. The results demonstrate a notable improvement in the cycle’s thermodynamic performance with CO2 + SiCl4 binary mixture compared to pure CO2. A small concentration (5%) of SiCl4 in CO2 increases the thermal efficiency of the cycle from 41.7% to 43.4%. Moreover, irreversibility losses in the cooler and the heat recovery unit are significantly lower with the CO2 + SiCl4 binary mixture than with pure CO2. This improvement enhances the overall exergy efficiency of the cycle, increasing it from 62.1% to 70.2%. The primary reason for this enhancement is the substantial reduction in irreversibility losses in both the cooler and the HTR. This study reveals that when using a CO2 + SiCl4 mixture, the concentration must be optimized to avoid condensation in the compressor, which can cause physical damage to the compressor blades and other components, as well as increase power input. This issue arises from the higher glide temperature of the mixture at increased SiCl4 concentrations and the limited heat recovery from the cycle.

Design, multi-aspect investigation and economic advantages of an innovative CCHP system using geothermal energy, CO2 recovery using a cryogenic process, and methanation process with zero CO2 footprint

The significance of devoting attention to environmental pollution control strategies is widely recognized as an effective means of mitigating the harmful environmental effects caused by fossil fuels in industrial and power plant sectors. Carbon dioxide (CO2) capture and recovery technologies have opened up the possibility of utilizing this pollutant gas. Hence, the current study suggests a methodology for the CO2 hydrogenation of the flue gas leaving a power plant. This approach facilitates methane generation via a methanation reactor, subsequently is utilized as fuel for a power plant. For this purpose, a cryogenic method using liquefied natural gas cold energy facilitates CO2 recovery. Moreover, the whole system utilizes geothermal energy to launch a power plant for power generation and supply the power demands of a hydrogen production unit, relying on a water electrolysis process. The hydrogen generated is employed for CO2 hydrogenation, while the oxygen produced is utilized for the combustion reaction. Heating provider units and an absorption chiller are also included in the design. The system is modeled utilizing Aspen HYSYS software. This study incorporates a sensitivity analysis alongside energy, exergy, environmental, and economic assessments. The energy and exergy efficiencies, as determined by the thermodynamic analysis, are 30.87% and 48.61%, respectively. Additionally, according to the economic study, the levelized energy cost amounts to 16.65 $/MWh, demonstrating a substantial reduction of 87.6% compared to the power generation mode. One notable merit of the suggested system lies in its zero CO2 footprint framework, showing a noteworthy supremacy when compared with previous studies.

Novel 2D Layered MXene Nanofluids for Enhancing the Convective Heat Transfer Performance of Double-Pipe Heat Exchangers.

This paper proposes a new class of novel 2D layered structured materials, such as MXene (MX), for the synthesis of innovative nanofluids as coolants to evaluate the convective heat transfer performance of a double-pipe heat exchanger (DPHE). Convective heat transfer experiments were successfully conducted in lab-scale fabricated DPHE using low-concentration MXene nanofluids by varying the volume concentration of MXene nanoparticles (0.01-0.05 vol %) in different base fluids. The influence of the MXene nanofluids on various convective heat transfer parameters, such as LMTD, Nusselt number, heat transfer coefficient, and heat transfer rate without using any inserts in the DPHE was experimentally investigated. The results of the experiments revealed that the heat transfer coefficient and Nusselt number increase with increasing Reynolds number (Re) and concentration of MXene nanoparticles in the base fluids. Maximum enhancement in heat transfer coefficient (126%) was achieved for methanol-based MXene nanofluids at 0.05 vol %. Moreover, the Nusselt number exhibits a maximum enhancement of ∼50% for methanol- and water-based MXene nanofluids. In contrast, the thermal performance factor was also estimated, and it was observed that water- and methanol- based MXene nanofluids showed higher values than castor oil- and silicone oil-based MXene nanofluids. Finally, the LMTD and heat transfer coefficients were successfully validated using Aspen HYSYS 12.1 software.

Multi-variable optimization of a geothermal power plant integrated with water electrolyzer and methanol production

Renewable energy-based routes for methanol generation are recognized as essential strategies for eco-friendly energy conversion. Thus, the current study focuses on developing an innovative combined energy system for methanol production using direct carbon dioxide hydrogenation powered by geothermal energy. This is important because it addresses the need for sustainable and environmentally friendly methods of methanol production while also harnessing the potential of geothermal energy as a renewable resource. Therefore, in order to achieve multigeneration energy production, this work introduces and optimizes a novel configuration that benefits from an innovative heat design process. This configuration integrates an organic Rankine cycle, a single-flash geothermal power plant, an ammonia-water absorption chiller, a proton exchange membrane electrolyzer, and a methanol generation unit. Using the Aspen HYSYS tool, the multigeneration energy system is modeled and analyzed. As a result, the system is assessed using energy, exergetic, environmental, and economic evaluations. Furthermore, performance evaluations are carried out in the following modes: single generation, multigeneration, cooling, heat and power generation, and cooling. Furthermore, a genetic algorithm is employed to optimize the system in terms of economy and exergy. The energy and exergy efficiency are determined to be 32.57 % and 76.3 %, respectively, under the base case results. Furthermore, the rate of overall costs is 377.38 $/h. Furthermore, the precise output of carbon dioxide is −0.043 kg/kWh. The optimal unit cost and exergy efficiency for all items, taking into account the optimization scenario, are 3.34/GJ and 78.35 %, respectively. In addition, the optimum carbon dioxide and hydrogen rates for methanol generation are 92.49 mol/h and 200.51 mol/h, respectively.

Model-based fault detection algorithm for liquid hydrogen refueling system using CUSUM method

The global focus on the role of hydrogen energy in achieving carbon neutrality is increasing, particularly in transportation. Establishing and operating hydrogen refueling stations for fuel cell electric vehicles (FCEVs) are gaining prominence. This study proposes a model-based fault detection algorithm to enhance safety at large-capacity liquid hydrogen (LH2) refueling stations. First, the LH2 refueling system is modeled using Aspen HYSYS, estimating the heat transfer coefficient of the storage tank to meet the normal evaporation rate (NER) specification of 0.9 % per day. Second, diverse fault scenarios are identified via a Hazard and Operability Study (HAZOP), and simulation data are generated for the normal and fault scenarios. Finally, a fault detection algorithm utilizing the cumulative summation (CUSUM) is developed, with its threshold determined by risk levels analyzed in HAZOP. This allowed for tighter fault detection as risk levels increased. The algorithm successfully identified faults for all 11 scenarios.

Optimizing trigeneration energy systems: Biogas-centric methanol production via direct CO2 hydrogenation with advanced integration of PEM electrolyzer and LNG cold technology

Biogas, a sustainable alternative to fossil fuels, addresses issues of non-renewability and accessibility. Its structural similarity to fossil fuels makes it a potent option for energy systems. With this in mind, this paper discusses a novel trigeneration system that utilizes biogas and Liquefied natural gas cooling to produce methanol, electricity, cold water, hot water, oxygen, and natural gas. The system integrates various components such as a biogas burner, Kalina cycle, organic Rankine cycle, liquefied natural gas liquid gasification cycle, proton exchange membrane electrolyzer, and methanol synthesis unit. Simulation via Aspen HYSYS software includes an analysis of energy, exergy, economic, and environmental aspects. Efficiency assessment in single generation, cogeneration, trigeneration, and chemical trigeneration modes concludes chemical trigeneration as most efficient, with the proton exchange membrane electrolyzer being the most efficient subsystem. Key variables like Kalina cycle evaporator temperature, gas flow rate to the methanol reactor, and organic Rankine cycle working fluid pressure are assessed. Predictions on thermodynamic, environmental, and economic behaviors, along with their fluctuations, are made. Using a thermoeconomic approach, the economic analysis determines an exergy unit cost of 59.79 $/GJ and a total cost rate of 2764 $/h. Overall, this work presents a novel and efficient chemical trigeneration system that utilizes biogas and LNG cooling to produce multiple products.

Thermo-enviro-economic analyses of a landfill biogas-fed polygeneration process combined with a liquefied natural gas cold energy utilization unit

Landfill biogas offers a promising opportunity to supply society’s energy requirements, following the waste-to-energy approach, which issuitable for sustainable production. However, structural modification for its utilization is the main gap, requiring additional research efforts. Considering this issue, the current study aims to design an eco-friendly polygeneration method for landfill biogas utilization for a cutting-edge heat recovery system that integrates a cold energy recovery and utilization unit for liquefied natural gas. The liquefied natural gas recovery section, the organic Rankine cycle with a zeotropic mixture, and the Kalina cycle are all started using the flue gas from the combustion of biogas in a cascade process. In addition, the waste heat of the Kalina cycle is recovered by a single-effect desalination cycle and liquefied natural gas recovery section. Also, a water electrolysis process is integrated into the whole system. As a result, the products include hydrogen, electricity, natural gas, hot and cold water, and freshwater. The Aspen HYSYS software is utilized to design the system and investigate its thermodynamic, environmental, and economic aspects. The results demonstrate an energy efficiency of 57.54 % and an exergy efficiency of 18.78 %. Also, the carbon dioxide footprint associated with the system equals 0.34 kg/kWh, and the specific cost of products is 73.96 $/GJ. An optimal exergy efficiency of 25.8 % and a specific cost of products of 69.7 $/GJ are obtained by means of an intelligent optimization approach that ultimately makes use of non-dominated sorting genetic algorithm-II and artificial neural networks.

Simulation and Economic Analysis of Helium Extraction Process from Natural Gas

The investment estimation of the helium extraction project from natural gas is a crucial step in economically obtaining helium from both domestic and international projects. This article employs Aspen HYSYS to simulate the process and estimate the investment levels of Linde and Exxon Mobil integrated helium extraction processes. We investigate the influence of feed composition and processing capacity on investment costs and product returns. The results indicate that higher helium content of feed correlates with increased equipment investment costs and total capital cost (CAPEX), and that the Linde integrated process is significantly more sensitive to changes in helium content of feed than the Exxon Mobil integrated process. As the helium content of feed rises, the product returns of the two processes are evidently improved, leading to reduced investment payback periods. Both techniques exhibit favorable payback periods when the feed helium content exceeds 0.5 vol%. Nevertheless, elevated nitrogen content in the feed notably escalates the equipment investment costs and total capital costs. Furthermore, an increase in the processing capacity of feed gas leads to a nonlinear increase in total capital costs and annual operating costs. However, the cost per unit of helium extraction diminishes with increasing capacity. In general, the Linde integrated process requires higher separation energy consumption in comparison with the Exxon Mobil integrated process at similar processing capacities. Moreover, the sensitivity analysis shows that helium breakeven price is strongly affected by the price of both LNG and feed gas.

Modeling and simulation for the sustainable recovery of aromatics (BTX) from petrochemical industrial wastewater.

Petrochemical wastewater is a major industrial source of pollution that produces a variety of toxic organic and inorganic pollutants, naturally present or added during the process. These pollutants are a serious threat to the soil, water, environment, and human being due to their complex and hazardous nature. Glycols such as monoethylene glycol (MEG), diethylene glycol (DEG), triethylene glycol (TEG), and aromatics (BTX-benzene, toluene, and xylene) are the most common organic impurities present in petrochemical wastewater. The objective of this paper is to recover aromatics and water from petrochemical industrial wastewater. The reclamation process is used to remove inorganic impurities such as heavy metals Fe, Zn, Pb, Mn, Al, Ni, As, Cr, Cu, Cd, and K and salts. In the present work, 1% sodium bi-carbonate (NaHCO3) is used to precipitate the inorganic impurities present in the wastewater at 40°C atmospherically. Aspen Hysys simulation software is used for modeling and simulation for the treatment process using NRTL (non-random-two-liquid) thermodynamic model. The process generated from Aspen Hysys is validated with lab experiments. To support global sustainable development, this study is focused on reducing, reusing, and recycling separation techniques such as centrifuge separation and vacuum distillation have been used. The characterization of regenerated water was performed using ICP-OES (inductively coupled plasma-optical emission spectroscopy) to determine the reduction in heavy metals. It was found that > 99.5% of heavy metals were removed. The regeneration of these aromatics is necessary for economic and environmental reasons so that it can be reused to avoid its disposal in and contamination of natural environments.

Investigation and thermodynamic analysis of hydrogen liquefaction cycles: Energy and exergy study

The use of hydrogen as a clean fuel has drawn the attention of many scientists due to the problem of energy and environmental pollution caused by fossil fuels. One of the important requirements for expanding the use of hydrogen is the investigation and thermodynamic analysis of liquefaction cycle; this includes the thermodynamic investigation of different cycles of hydrogen liquefaction in pre-cooling and cryogenic cooling. Thermodynamic analysis comprises an examination of the cycle's energy and exergy, as well as the equipment employed. In this research, three liquefaction cycles with different pre-cooling cycle and cryo-cooling cycle have been evaluated. The use of organic Rankine cycle (ORC) and liquefied natural gas (LNG) has also been applied in the cycles and the arrangement of the equipment. Simulations and analyzes have been done in Aspen HYSYS V12. The results show that in the pre-cooling process of cycles 1, 2, and 3, the amount of useful exergy is 49.87 %, 58.87 %, and 61.21 %, respectively, which means that the third cycle uses the input exergy better. Also, in the pre-cooling process of cycles 1, 2, and 3, the amount of exergy loss is 33.86 %, 26.77 %, and 19.73 %, respectively, which means that the third cycle has less exergy loss in the pre-cooling process. The findings indicate that in each of the three cycles, over 50 % of the input exergy is wasted in the cryo-cooling process. Value of specific energy consumption (SEC) for cycle 1,2, and 3 is equal to 6.605 kWh/kgLH2 , 6.601 kWh/kgLH2 and 6.618 kWh/kgLH2, respectively. The three cycles under examination had COP values of 0.19945, 0.19936, and 0.19884, in that order. Also, the values for EXE cycles 1, 2, and 3 are 45.816 %, 45.883 %, and 45.797 %, respectively. Analyzing the energy and exergy of liquefaction cycles is a good step toward increasing cycle efficiency, identifying weak places, and altering cycles to improve efficiency.

Energy‐Efficient Hydrogen Liquefaction Process with Ortho‐Para Conversion and Boil‐Off Gas Recovery

AbstractHydrogen liquefaction is essential for the efficient storage and transportation of hydrogen. In the liquefaction process, catalytic ortho‐para conversion is crucial to achieve a product with at least 95 % para‐hydrogen to reduce boil‐off losses. The proposed hydrogen liquefaction process using a catalyst‐filled heat exchanger for continuous ortho‐para conversion is modeled through steady‐state thermal simulations in Aspen HYSYS. Additionally, an ejector is integrated to reliquefy boil‐off gas. The proposed design achieves a specific energy consumption (SEC) of 10.50 kWh ()−1 and an exergy efficiency (EXE) of 30.1 %, which is 18 % lower in SEC compared to processes with separate converters. The integrated approach enhances energy utilization and offers references for future hydrogen liquefiers.

Efficient Exergy Analysis of Chemical Processes through Process Engineering Software

In this work, authors present a simple methodology for computing physical, chemical and total exergies, and the exergy destruction and the exergetic efficiency of simple and complex processes by using the object linking and embedded (OLE) automation by connecting Aspen HYSYS to MS Excel VBA. For this purpose, a simple flowsheet was added to the main one with the same number of streams as that of the components. By introducing all these streams in a mixer and then consecutively conducted to a heater to condition the outlet stream, a separator and a mixer, the VBA application was able to compute the chemical exergy of the different streams of the main flowsheet. To demonstrate the procedure here described seven cases were considered: single streams, a CO2 mixer, a cooler, a distillation column, a reactor, a multiple recirculation process, and different configurations of separating components by distillation, which can be extended to very complex processes. The former was selected to validate the methodology here proposed whereas the rest of cases were used to demonstrate the potential of the tool here developed, which in turn could be used for discriminating among different process alternatives.