Search Results (124)

The increasing penetration of variable renewable energy sources intensifies grid imbalance and challenges the reliability of small-scale power systems. This study addresses these challenges by developing and analyzing a fully integrated hybrid energy system that combines biogas upgrading to biomethane, photovoltaic (PV) generation, hydrogen production via alkaline electrolysis, hydrogen storage, and a gas-steam combined cycle (CCGT). The system is designed to supply uninterrupted electricity to a small municipality of approximately 4500 inhabitants under predominantly self-sufficient operating conditions. The methodology integrates high-resolution, full-year electricity demand and solar resource data with detailed process-based simulations performed using Aspen Plus, Aspen HYSYS, and PVGIS-SARAH3 meteorological inputs. Surplus PV electricity is converted into hydrogen and stored, while upgraded biomethane provides dispatchable backup during periods of low solar availability. The gas-steam combined cycle enables flexible and efficient electricity generation, with hydrogen blending supporting dynamic turbine operation and further reducing fossil fuel dependency. The results indicate that a 10 MW PV installation coupled with a 2.9 MW CCGT unit and a hydrogen storage capacity of 550 kg is sufficient to ensure year-round power balance. During winter months, system operation is sustained entirely by biomethane, while in high-solar periods hydrogen production and storage enhance operational flexibility. Compared to a conventional grid-based electricity supply, the proposed system enables near-complete elimination of operational CO₂ emissions, achieving an annual reduction of approximately 8800 tCO₂, corresponding to a reduction of about 93%. The key novelty of this work lies in the simultaneous and process-level integration of biogas, hydrogen, photovoltaic generation, energy storage, and a gas-steam combined cycle within a single operational framework, an approach that has not been comprehensively addressed in the recent literature. The findings demonstrate that such integrated hybrid systems can provide dispatchable, low-carbon electricity for small communities, offering a scalable pathway toward resilient and decentralized energy systems. Full article

Crude distillation units operate as the most energy-intensive refinery operations and generate substantial carbon dioxide emissions. This research models the crude distillation system through its three main components: the atmospheric distillation unit, the naphtha stabilisation unit, and the vacuum distillation unit. The simulation platform Aspen HYSYS version 14.1 enabled optimisation of the preflash drum under product quality constraints, and the analysis included pinch analysis techniques and techno-economic evaluation. The optimisation results demonstrated an 8.95% reduction in atmospheric furnace duty, a 7.38% decrease in total hot utility consumption with the crude distillation system, and an increase in heat recovery capability from 35.57% to 42.71%. Although the preflash process alone decreases profitability because of increased steam demand, combining preflash operation with heat recovery measures maintains both energy conservation and favourable economic performance. The study shows that refinery optimisation requires treating the crude distillation system as a fully integrated process. This approach offers effective strategies to improve energy performance and reduce carbon dioxide emissions while sustaining economic viability. The work differs from previous studies by evaluating the entire distillation system as an integrated sequence and demonstrating how preflash optimisation affects overall energy demand, heat-recovery potential, and economic outcomes while maintaining product quality. Full article

This study presents an integrated Life Cycle Sustainability Assessment (LCSA) of the Natural gas-to-methanol (NGTM) and methanol-to-gasoline (MTG) pathways using Aspen HYSYS process modeling, Environmental Life Cycle Assessment (LCA), Social Life Cycle Assessment (SLCA), and Life Cycle Costing (LCC). The results reveal significant variability in sustainability performance across process units. The DME and MTG Reactors Section generates the highest direct greenhouse gas (GHG) emissions at 0.86 million tons CO₂-eq, representing 54.9% of total global warming potential, while the Compression Section consumes 2717.5 TJ/year of energy, making it the dominant source of electricity-related indirect emissions. Distillation and Purification withdraws 31,100 Mm³/year of water—approximately 99% of total demand—yet delivers 86.6% of the overall economic surplus despite high operating costs. Social impacts concentrate in the Methanol Reactor Looping and DME and MTG Reactors Sections, with human health burdens of 305.79 and 804.22 DALYs, respectively, due to catalyst handling and high-pressure operations. Sensitivity results show that methanol purity rises from 0.9993 to 0.9994 with increasing methane content, while gasoline output decreases from 3780 to 3520 kg/h as natural gas flow increases. The findings provide process-level evidence to support sustainable development of natural gas-based fuel conversion industries, aligning with Qatar National Vision 2030 objectives for industrial diversification and lower-carbon energy systems. Full article

Refinery blending is a routine operation, yet small changes in crude mix can strongly affect product yield and fuel quality. In this work, Aspen HYSYS v12.1 was used to model and optimize the blending of four Nigerian crude oils—Antan, Usan, Bonga, and Forcados—processed at about 150,000 barrels per day. The study examined how adjustments in blend ratio and feed temperature influence gasoline output and energy use in the distillation unit. The best result was obtained at a blend of Antan 10%, Usan 37.45%, Bonga 10%, and Forcados 42.55%, where gasoline yield increased by roughly 5.6% compared with the equal-blend case. Product properties remained within Nigerian fuel standards (RON ≈ 92, sulphur ≈ 0.038 wt%), showing that quality was not affected by the optimizations. Economic estimates also indicated higher annual revenue and a modest reduction in furnace heat duty, suggesting lower fuel consumption. Although the work was limited to steady-state simulation without plant-scale validation, it provides practical evidence that systematic crude blend optimizations can deliver measurable gains in yield and energy efficiency for refineries using mixed feedstocks. Full article

The increasing share of renewable energy sources (RES) in modern power systems necessitates the development of efficient, large-scale energy storage technologies capable of mitigating generation variability. Liquid Air Energy Storage (LAES), particularly in its adiabatic form, has emerged as a promising candidate by leveraging thermal energy storage and high-pressure air liquefaction and regasification processes. Although LAES has been widely studied, the impact of ambient temperature on its performance remains insufficiently explored. This study addresses that gap by examining the thermodynamic response of an adiabatic LAES system under varying ambient air temperatures, ranging from 0 °C to 35 °C. A detailed mathematical model was developed and implemented in Aspen Hysys to simulate the system, incorporating dual refrigeration loops (methanol and propane), thermal oil intercooling, and multi-stage compression/expansion. Simulations were conducted for a reference charging power of 42.4 MW at 15 °C. The influence of external temperature was evaluated on key parameters including mass flow rate, unit energy consumption during liquefaction, energy recovery during expansion, and round-trip efficiency. Results indicate that ambient temperature has a marginal effect on overall LAES performance. Round-trip efficiency varied by only ±0.1% across the temperature spectrum, remaining around 58.3%. Mass flow rates and power output varied slightly, with changes in discharging power attributed to temperature-driven improvements in expansion process efficiency. These findings suggest that LAES installations can operate reliably across diverse climate zones with negligible performance loss, reinforcing their suitability for global deployment in grid-scale energy storage applications. Full article

The commitment to the Sustainable Development Goals and the need for increasing the circularity of industrial processes call for the exploitation of byproducts to generate value-added chemicals in cost- and energy-advantageous processes. In this process simulation-based research, two technologies were evaluated for the synthesis of isoamyl acetate from fusel oil: (A) an indirect process, and (B) a direct process using reactive distillation. Aspen Hysys v14.0 was used for simulation. A sensitivity analysis was performed to identify the influence of operating parameters on product purity, isoamyl acetate recovery and productivity, and energy consumption. Technology B was found to be the most favorable, obtaining 22.27 kg/h of isoamyl acetate with a purity of 98%. The total consumption values of cooling water and heating were 24.33 kW and 24.50 kW, respectively. Based on the best conditions, a technical–economic analysis was performed that demonstrated the viability of the process, obtaining a net present value (NPV) of US$3,587,110/year, an internal rate of return (IRR) of 38.95% and a payback period (PP) of 5.05 years. If acid recirculation is considered in the process, an NPV of US$7,232,950, an IRR of 56.34%, and a PP of 3.56 years are obtained. Full article

Pressurized chemical looping combustion (PCLC) provides the benefit of simplifying the carbon capture process by generating a flue gas stream with high CO₂ concentration. However, flue gas polishing is required to remove the residual impurities for pipeline transport. The intensified heat exchanger reactor (IHXR) is a promising method for flue gas polishing while maximizing useful heat recovery that incorporates alternating catalytic packed beds with interstage cooling via printed circuit heat exchangers (PCHE). This work offers a design process for an IHXR capable of polishing a flue gas stream from a 100 MWth natural gas-fired PCLC unit while recovering 1.6 MW of useful heat in the form of saturated steam at 180 °C. Simulation work performed in Aspen HYSYS was used to determine the polished flue gas outlet species concentrations as well as the required number and size of the packed bed sections. The PCHEs for interstage cooling were sized via a thermal circuit approach. The final IHXR consists of six packed beds at 0.06 m in length and five PCHEs at 0.265 m in length, combining to a total IHXR length of 1.685 m. The height and width of the IHXR is shared between the packed beds and PCHEs at 0.91 m and 0.45 m, respectively. The resulting IHXR is capable of recovering heat at a rate of approximately 2.3 MW/m³. Full article

Triazine solvent desulfurization is a highly efficient technology for removing hydrogen sulfide from natural gas. In this study, we used ASPEN HYSYS V11 with the Peng-Robinson (PR) equation to investigate the triazine consumption under different natural gas flow rates and hydrogen sulfide concentrations, as well as the sulfur capacity resulting from the reaction between triazine and H₂S at varying solution concentrations. Additionally, CFD simulations were employed to optimize the injection process of the triazine solvent by examining four key factors: gas flow velocity, injection volume, injection angle, and injection method. The results indicate that the required triazine dosage follows an exponential model, with a margin of error within 10%. A triazine mass fraction between 0.4 and 0.6 was found to be optimal. Among the factors studied, gas flow velocity has the most significant influence on desulfurization efficiency, while the injection rate plays a secondary role. An injection angle of 45° proved most effective, and the use of dual vertical symmetric nozzles achieved more uniform mixing between the natural gas and triazine solvent. Full article

The gas oil hydrocracking process is a cornerstone of modern refining, enabling the conversion of heavy fractions into high-value fuels such as diesel, kerosene, LPG, and naphtha. However, despite its economic significance, its considerable water requirements for cooling, washing, and steam generation lead to high utility costs, which may undermine profitability, representing the problem of the study. This study addresses the issue through a techno-economic assessment and resilience analysis of an industrial-scale, mass and energy-integrated gas oil hydrocracking process, utilizing the novel FP²O methodology. The process was modeled in Aspen HYSYS^® V14.0 with a capacity of 1.94 Mt/year, assuming a feedstock cost of USD 350/t and a primary product (diesel) price of USD 1539/t. The total capital investment (TCI) was estimated at USD 175.68 million, while utility expenses reached USD 1312.18 million/year, representing nearly half of the total product cost (TPC) of USD 2692.20 million/year. A set of twelve techno-economic and three financial indicators was determined, yielding a gross profit (GP) of USD 97.69 million, profitability after tax (PAT) of USD 64.96 million, and a net present value (NPV) of USD 229.62 million. The payback period (PBP) was 1.41 years, with a depreciable payback period (DPBP) of 2.99 years. The return on investment (ROI) was 36.97%, and the internal rate of return (IRR) reached 44.81%, evidencing strong profitability relative to comparable petrochemical operations. Resilience analysis highlighted sensitivities to fluctuations in product prices, feedstock costs, and normalized variable operating costs (NVOC), identifying a critical NVOC of USD 1435/t against the current operation at USD 1384.74/t, which suggests a narrow buffer before profitability deteriorates. Overall, the findings confirm that mass and energy integration enhances resource efficiency but does not fully mitigate exposure to feedstock and utility price volatility. This work constitutes the first application of FP²O to a mass and energy-integrated gas oil hydrocracking facility, establishing a benchmark for holistic techno-economic and resilience assessments in complex petrochemical systems. Full article

The increasing global demand for clean energy highlights hydrogen as a strategic energy carrier due to its high energy density and carbon-free utilization. Currently, steam methane reforming (SMR) is the most widely applied method for hydrogen production; however, its high CO₂ emissions undermine the environmental benefits of hydrogen. Blue hydrogen production integrates carbon capture and storage (CCS) technologies to overcome this drawback in the SMR process, significantly reducing greenhouse gas emissions. This study integrated a MATLAB-R2025b-based plug flow reactor (PFR) model for SMR kinetics with an Aspen HYSYS-based CCS system. The effects of reformer temperature (600–1000 °C) and steam-to-carbon (S/C) ratio (1–5) on hydrogen yield and CO₂ emission intensity were investigated. Results show that hydrogen production increases with temperature, reaching maximum conversion at 850–1000 °C, while the optimum performance is achieved at S/C ratios of 2.5–3.0, balancing high hydrogen yield and minimized methane slip. Conventional SMR generates 9–12 kgCO₂/kgH₂ emissions, whereas SMR + CCS reduces this to 2–3 kgCO₂/kgH₂, achieving more than 75% reduction. The findings demonstrate that SMR + CCS integration effectively mitigates emissions and provides a sustainable bridging technology for blue hydrogen production, supporting the transition toward low-carbon energy systems. Full article

Digital Twin (DT) technology has rapidly matured from pilot projects to integral components of advanced asset management and process optimization in the oil and gas (O&G) industry. This review provides a structured synthesis of the current state of digital twin frameworks, with a focus on offshore and topside gas-processing systems, such as those found on Floating Production Storage and Offloading (FPSO). Emphasis is placed on high-fidelity process simulations and scalable architectures integrating real-time data with advanced analytics. Drawing on over 85 peer-reviewed sources and industrial frameworks, the paper outlines modular DT architectures, encompassing steady-state and dynamic process simulations (e.g., Aspen HYSYS), reduced-order and hybrid machine learning models, co-simulation environments, and advanced equation-of-state packages (e.g., GERG-2008). Special attention is given to compressor map integration, Equations of State (EOS) selection, ISO/IEC standard compliance, and digital thread continuity. Additionally, the review explores economic and sustainability-driven DT implementations, including flare and methane mitigation, ISO 50001-aligned energy optimization, and lifecycle/decommissioning strategies. It concludes with a technical and economic assessment of DT maturity for gas compression facilities, identifying research gaps in standardization, long-term validation, and cybersecurity integration. The insights provided are intended to support decision-makers, engineers, and researchers in deploying scalable, auditable, and high-impact DT solutions across the O&G value chain. Full article

The flaring of associated gas in oil and gas operations contributes significantly to greenhouse gas emissions and represents a loss of valuable hydrocarbon resources. While amine absorption is widely applied for acid gas removal, the use of supercritical carbon dioxide (sc-CO₂) for flare gas treatment remains largely unexplored, despite its proven selectivity for hydrocarbons in other industries such as natural product extraction and polymer processing. Conventional flare gas treatment methods face trade-offs: amine absorption achieves high acid gas removal efficiency but offers limited selectivity for heavier hydrocarbons, whereas sc-CO₂ extraction enables efficient recovery of higher hydrocarbons but does not fully remove acid gases. This study addresses these gaps by evaluating three two-stage flare gas treatment configurations—dual-stage amine absorption, dual-stage sc-CO₂ absorption, and a hybrid of sc-CO₂ followed by amine absorption—using Aspen HYSYS V12.1 simulations, with recycling processes considered in each case. The dual-stage sc-CO₂ process achieved nearly complete hydrocarbon recovery (100%) and complete H₂S removal, but CO₂ remained at elevated concentrations in the treated gas. The dual-stage amine process completely removed CO₂ and H₂S, though with higher energy demand for solvent regeneration. The hybrid configuration combined the advantages of both approaches, achieving complete H₂S removal, 100% hexane recovery, 95.02% methane recovery, and a drastic reduction in CO₂ concentration (to 0.0012 mole fraction). These results demonstrate that integrating sc-CO₂ with amine absorption resolves the trade-off between hydrocarbon selectivity and acid gas removal, establishing a technically viable pathway for flare gas utilization with potential application in gas-to-liquids (GTL) and carbon management strategies Full article

Despite growing interest in carbon capture and utilization (CCU), the transformation of captured CO₂ into dry ice remains poorly studied, particularly from a systems integration and energy optimization perspective. While previous works have examined individual components such as CO₂ absorption, liquefaction, or refrigerant evaluation, no existing study has modeled the full dry ice production chain from capture to solidification within a unified simulation framework. This study presents the first complete simulation and optimization of a dry ice production process, incorporating CO₂ absorption, solvent regeneration, dehydration, multistage compression, ammonia-based external liquefaction, and expansion-based solidification using Aspen HYSYS. The process features ammonia as a working refrigerant due to its favorable thermodynamic performance and zero global warming potential. Optimization of heat integration reduced total energy consumption by 66.67%, replacing conventional utilities with water-based heat exchangers. Furthermore, solvent recovery achieved rates of 75.65% for MDEA and 66.4% for piperazine, lowering operational costs and environmental burden. The process produced dry ice with 97.83% purity and 94.85% yield. A comparative analysis of refrigerants confirmed ammonia’s superiority over R-134a and propane. These results provide the first system-level roadmap for producing dry ice from captured CO₂ in an energy-efficient, scalable, and environmentally responsible manner. Full article

To enhance the energy efficiency of liquefied natural gas (LNG) terminals, this study developed a full-process dynamic simulation model using Aspen HYSYS (hereinafter referred to as HYSYS) to accurately replicate the time-varying energy consumption characteristics of key processes, including unloading, tank boil-off gas (BOG) management, recondensation, and vaporization for send-out. Through dynamic analysis of the impact of different operating conditions on the energy consumption of critical equipment, methane content and compressor outlet pressure were identified as sensitive factors, and multivariable interaction effects were quantified. Combining the Particle Swarm Optimization (PSO) algorithm to optimize equipment operating parameters and incorporating constraints such as equipment start-stop frequency and flare emissions, process improvements were achieved, including intelligent pre-cooling during unloading, multi-mode vaporization coupling, and model predictive control for storage tanks. Safety response logic under extreme conditions was also enhanced. Field validation results show that the optimized system reduces total energy consumption by 18.5%, with a relative error between simulated and field data of ≤13%. Daily equipment start-stop cycles decreased from five to two times, and flare emissions were reduced from 25 kg/h to 12 kg/h. Within a 95% confidence interval, the total energy consumption prediction fluctuated by ±4.2%, demonstrating good model stability. This study provides reliable technical support for energy-efficient operation of LNG terminals. The proposed multivariable interaction analysis and safety control strategies under extreme conditions further enhance the engineering applicability of the optimization framework. Full article

Hydrogen energy is valued for its diverse sources and clean, low-carbon nature and is a promising secondary energy source with wide-ranging applications and a significant role in the global energy transition. Nonetheless, hydrogen’s low energy density makes its large-scale storage and transport challenging. Liquid hydrogen, with its high energy density and easier transport, offers a practical solution. This study examines the global hydrogen liquefaction methods, with a particular emphasis on the liquid nitrogen pre-cooling Claude cycle process. It also examines the factors in the helium refrigeration cycle—such as the helium compressor inlet temperature, outlet pressure, and mass—that affect energy consumption in this process. Using HYSYS software, the hydrogen liquefaction process is simulated, and a complete process system is developed. Based on theoretical principles, this study explores the pre-cooling, refrigeration, and normal-to-secondary hydrogen conversion processes. By calculating and analyzing the process’s energy consumption, an optimized flow scheme for hydrogen liquefaction is proposed to reduce the total power used by energy equipment. The study shows that the hydrogen mass flow rate and key helium cycle parameters—like the compressor inlet temperature, outlet pressure, and flow rate—mainly affect energy consumption. By optimizing these parameters, notable decreases in both the total and specific energy consumption were attained. The total energy consumption dropped by 7.266% from the initial 714.3 kW, and the specific energy consumption was reduced by 11.94% from 11.338 kWh/kg. Full article