Gas-fired Power Plants Research Articles

Energy and exergy analysis of the 1220 MW natural gas-fired Hamitabat combined cycle power plant

In this study, the energy and exergy analysis of the 1220 MW Hamitabat combined cycle power plant (CCPP) that was renovated in 2017 with a 520 million € project is carried out. A thermodynamic model is built by applying the conservation of mass and energy principles and operating data are obtained from the plant operators. Exergy analysis is performed with the exergy balance equation to determine the exergy efficiencies and improvement potentials of all components. Also, parametric analyses are carried out to investigate the methods to enhance the performance of the plant. The plant has thermal and exergy efficiencies of 59.70% and 58.52%, respectively and these values are 13.70% and 13.52% higher than the thermal and exergy efficiencies of the original plant, respectively. Results showed that the combustion chamber (CC) has the highest rate of exergy destruction, and it is responsible for 77.61% of the total irreversibilities. The improvement potential of the CC is found to be 67.992 MW, and the prevention of heat loss from CC can increase the thermal and exergy efficiencies of the plant by 3.88% and 3.80%, respectively. Parametric analyses showed that the plant performance can be enhanced by increasing the inlet temperatures of high- and intermediate-pressure turbines, and decreasing the pressures of condenser and high-pressure turbine.

Optimal self-unit commitment with shared asset ownership under realistic taxation in the current decarbonization framework

Energy, greenhouse gas emissions, or water taxes, are present in many power systems as available instruments to implement energy, environmental or climate policies. The goal of these taxes is to change producers’ optimal behavior and hence achieve a cleaner operation. However, these changes in operation are not straightforward to simulate when producers are price makers, or when assets are owned jointly by different agents. State-of-the-art models are unable to consider differentiated income taxes per technology or geographical region, in the case of price makers. In this paper, we present a novel formulation that models the individual market income of each unit using the binary-expansion technique to address the case of a price-maker agent. Unlike existing state-of-the-art formulations, our approach successfully accounts for differentiated income taxes per technology or geographical region and accurate market revenues of shared generators. The proposed model enables evaluating the rational behavior of a generation company confronting a complex yet realistic decision problem, under different types of taxes related to decarbonization or resource conservation policies. The case study incorporates the impact of the installation of carbon sequestration and storage equipment in a fleet of gas-fired power plants, yielding satisfactory numerical results.

Absolute Sustainability Assessment of Flue Gas Valorization to Ammonia and Synthetic Natural Gas.

Carbon capture and utilization has gained attention to potentially curb CO2 emissions while generating valuable chemicals. These technologies will coexist with fossil analogs, creating synergies to leverage circular economy principles. In this context, flue gas valorization from power plants can assist in the transition. Here, we assessed the absolute sustainability of a simulated integrated facility producing ammonia and synthetic natural gas from flue gas from a combined-cycle natural gas power plant based in Germany, using hydrogen from three water electrolysis technologies (proton exchange membrane, alkaline, and solid oxide cells), nitrogen, and CO2. For the first time, we applied the planetary boundaries (PBs) framework to a circular integrated system, evaluating its performance relative to the safe operating space. The PB-LCA assessment showed that the alternative technologies could significantly reduce, among others, the impact on climate change and biosphere integrity when compared to their fossil counterparts, which could be deemed unsustainable in climate change. Nevertheless, these alternative technologies could also lead to burden shifting and are not yet economically viable. Overall, the investigated process could smoothen the transition toward low-carbon technologies, but its potential collateral damages should be carefully considered. Furthermore, the application of the PBs provides an appealing framework to quantify the absolute sustainability level of integrated circular systems.

Thermoexergetic analysis and response optimisation of selective exhaust gas recirculation with solvent-based CO2 capture in a natural gas-fired combined cycle power plant

Thermoexergetic analysis and response optimisation of selective exhaust gas recirculation with solvent-based CO2 capture in a natural gas-fired combined cycle power plant

Evaluation of a tetramine-appended MOF for post combustion CO[formula omitted] capture from natural gas combined cycle flue gas by steam-assisted temperature swing adsorption

A novel tetraamine-appended metal–organic framework (MOF), exhibiting double-stepped isotherm was explored in a 3-step steam-assisted temperature swing adsorption process (SA-TSA) for CO2 removal from dry flue gas emitted from natural gas-fired power plants (NGCC). The reported material exhibited properties highly suited for CO2 capture from dilute sources. Extensive numerical simulations were performed to comprehend the impact of isotherm shape, heat transfer coefficient, feed temperature and heat capacity of solid on adsorption and desorption dynamics in a fixed bed. A multi-objective optimization was performed to identify operating conditions that achieve low steam consumption and high productivity while maintaining high purity (≥95%) and high recovery (≥90%). It was found that high purity and high recovery are obtained only when the process is isothermal. Thermal fronts propagating through the column impact the process performance. We show that the process cannot achieve recovery targets, i.e., ≥90%, unless heat is removed from the system rapidly. The lowest achievable specific steam consumption is ≈45kgsteamkgCO2−1 and highest achievable productivity is ≈0.1molco2madsorbent−3s−1 in an isothermal scenario.

Fossil gas lock-in risks: analysis of Algeria’s electricity sector and implications for a renewable energy transition

Algeria's electricity sector is dependent on fossil gas. Domestic gas demand is growing, and gas-fired power plants are projected to make up 84% of total installed capacity by 2028. This brings the country into a Sustainability Nexus dilemma: on the one hand, Algeria is committed to reduce its greenhouse gas emissions and other environmental impacts of the gas sector, whereas on the other hand, the energy and export revenue derived from gas would need to be substituted in order to ensure social and economic development in the country. Socioeconomic tradeoffs and alternatives must therefore be understood and managed in a way that ensures continued political and public support for the country's energy transition and fossil fuel exit. This paper aims to (a) identify fossil gas lock-in factors and (b) explore the opportunities to overcome these obstacles in order to facilitate a transition into renewable energy. Using a deductive approach, we draw on theoretical assumptions regarding carbon lock-in theory and the 2020 framework of Trencher et al. to study (1) technological and infrastructural conditions, (2) actors and agency, (3) formal and informal institutions, knowledge and competences, and (4) exogenous context. Between November 2021 and March 2022, a total of 23 semi-structured interviews were conducted in Algeria with stakeholders from the government, power and industry organizations, civil society organizations, and scientific institutions. The interview transcripts were then thematically analyzed to get a picture of recurrent themes and patterns. Our analysis identified several factors contributing to the fossil gas lock-in in Algeria's electricity system: economic dependence on oil and fossil gas; the significant influence of oil and gas actors, and the governmental support for fossil gas; gas and electricity subsidies, which lock out all other energy alternatives; and an overall lack of attention to climate change in energy policy formulation and in political and societal debate, despite the major capacity expansion plans prompted by heatwaves. The paper ends with a brief discussion of how Algeria's gas lock-in may worsen due to the war in Ukraine.

Quantification of cogeneration vulnerability towards the climate change: framework development

Cogeneration is a vigorous measure to both decrease greenhouse gases emissions and improve an overall efficiency of the primary energy use. The climate change poses serious risks on operation of combined heat and power (CHP) plants due to the shifts in heating load patterns. This work investigates linking of the heating demand to the climate conditions and introduces a framework which can be used to develop an adaptation strategy for district heating systems. We demonstrate viability of the proposed approach by a case study assessing sensitivity of the CHP efficiency to the climate warming across China considering a modern combined-cycle gas-fired power plant with steam extraction. Outputs of the case study have demonstrated that CHP plants are generally more vulnerable towards the climate change in world regions with harsher climate conditions. An effective measure to increase resilience of the cogeneration sector is to account for anticipated climate change effects by applying adjustments to the reference climate inputs used when designing CHP plants.

Impact of load variation on power system stability and performance of power system stabilizers: A case study of Peerdawd gas power station, Iraq

<span lang="EN-US">Variable load on the station refers to the fluctuating load on a power plant due to erratic consumer demands. It is known to have an effect on the performance of power system stabilizers, particularly in damping inter-area oscillation. This paper examines how two power system stabilizer (PSS) models and various load conditions affect a power system's voltage and power stability. A dynamic model of the power system station, based on the real case study of the Peerdawd gas power station in north Iraq (PPGS), is utilized to investigate the response of both steady-state and transient-state models: the aggregated excitation control system (Ex2100) and the power system stabilizer (PSS2B). The impact of load variation on voltage stability under normal situations and during disturbances is discussed. Furthermore, the effect of reactive power support from the power plant on the input of the two PSS models is analyzed and discussed. The paper employs a MATLABTM/Simulink-based simulation program, and the results contribute to understanding how load variation influences system damping based on PSS.</span>

Flexible carbon capture using MOF fixed bed adsorbers at an NGCC plant

Novel carbon capture systems are necessary to help natural gas power plants approach net zero CO2 emissions. We propose a hybrid carbon capture system attached to a natural gas combined cycle (NGCC) power plant that consists of a membrane system and a solid sorbent system, with this work focusing on the design of the solid sorbent system. We modeled fixed bed adsorbers that are packed with metal-organic framework (MOF) solid sorbents that adsorb CO2 and undergo temperature swing desorption using steam from the power plant. Parametric simulation of adsorber conditions showed that ten 5-m diameter beds adsorbing in parallel with 4.9 bars inlet gas pressure and 1.5 bars of steam pressure at a flow rate of 0.15 kmol/s led to optimized performance. This study enabled us to determine that the MOF bed adsorber can attain 86.6 % and 85.4 % carbon capture during peak and off-peak operation, respectively. When combined with the membrane capture system, this results in overall capture rates of 98.4 % and 98.9 % during peak and off-peak operation, respectively. Although we were unable to attain net-zero or net-negative emissions in this study, we are confident that net-negative operation could be obtained in future work by selecting a solid sorbent better suited to direct air capture conditions so that more air could be processed by the solid sorbent system.

Optimization of a Natural Gas Power Plant with Membrane and Solid Sorbent Carbon Capture Systems

Carbon capture & storage (CCS) with high capture rates (90-99%) will be necessary to keep natural gas around in a low-carbon future. Furthermore, as intermittent renewable energy expands, natural gas power plants will have to operate at low-load conditions more frequently. To meet these demands, we propose a natural gas combined cycle (NGCC) power plant with a hybrid CCS system that can attain high capture rates and easily cycle between high-load and low-load conditions. More specifically, we propose an integrated system where natural gas exhaust is first processed by a membrane CCS system and then by a solid sorbent CCS system. We integrated models of an NGCC plant, a membrane carbon capture system and a solid sorbent carbon capture system into a single optimization platform to maximize the net present value (NPV) and carbon capture rate of the integrated system. The optimization results indicate a 99.3% carbon capture rate from the inlet natural gas stream at high-load conditions, and a 99.6% carbon capture rate from the inlet natural gas stream at low-load conditions. Compared to a baseline NGCC system without carbon capture, the integrated system has a higher NPV, which indicates that performing carbon capture is more profitable than operating an NGCC system without carbon capture in a future with CO2 taxes. Compared to a baseline NGCC system with an amine-based CCS system that performs 90.7% carbon capture, the proposed integrated system captures more carbon and emits less CO2, while still maintaining a competitive CO2 capture cost.

Optimal sizing toolbox for energy generation and storage for a nuclear hybrid microgrid

Background In recent years, renewable energy sources, such as wind, have contributed to a decrease in grid stability. This has created the need for flexible and reliable back-up energy generation. Currently this role is fulfilled by natural gas-fired power plants that are able to quickly adjust power output based on present needs. Nuclear power presents an option for a clean and reliable alternative to these natural gas-fired power plants. However, nuclear power alone is unable to provide flexible enough power generation to fill this role. Instead, nuclear power plants must be combined with strategically sized energy storage systems to effectively complement the renewable power generation. Grids such as these are generally simulated using deterministic models which are unable to account for quickly fluctuating wind power generation. This in turn creates unsafe ramp rates for the nuclear power plant. Methods The approach taken in this paper utilizes a continuous-time stochastic model to simulate a grid with wind generation, nuclear power, and an energy storage system as the only energy sources. This paper focuses on this model and a development of a GUI to form a grid sizing toolbox. This toolbox was then demonstrated with an isolated microgrid using year-long wind and load data. Wind penetration, nuclear ramp rate limitations, and storage types were all varied to observe different scenarios and determine optimal storage sizing. Results There were several outcomes from this study that can inform grid planning. Nuclear power plant size trends downwards with greater wind power generation. However, high variability of wind power limits the size reduction. Nuclear capacity factor is between 41% to 57%, dropping further as wind penetration was increased. This highlights the difficulty of maintaining high utilization in these scenarios. Conclusions All storage types had similar performance in all categories except size, in which pumped hydroelectric and compressed air storage required smaller storage sizes.

Designing Sustainable Domestic Electricity Supply from Renewable Energy Mixes: Application to Java and Bali, Indonesia

Many countries, including Indonesia, have abundant renewable energy sources (RES), but the share of RES in the current national energy supply is still insignificant. The study aimed to investigate and provide the most feasible combinations of RES that meet domestic electricity demand. For Java and Bali, Indonesia, initially, 35 scenarios, given 4 primary RES (solar, wind, hydropower, geothermal) and municipal solid waste, were assessed based on economic and environmental indicators. This explorative data-driven study found that the existing capacity could only meet 51% of the electricity demand. However, the proposed energy mixes could cover 100% of the electricity demand in 2020 with a required capacity of 8.32–19.10 GW, varying on each scenario. The feasible energy mixes can reduce CO2 emissions by 90–94% compared to a fossil energy mix with gas-fired power plants. The installation, and operation and maintenance costs per life cycle can range from 29–50 and 4–16 billion dollars. The wind-based energy mix, with installed capacities of geothermal (1.16 GW), hydropower (2.87 GW), solar (0.003 GW) and municipal solid waste (0.18 GW) in 2020, showed the highest return on investment (139% ROI) and smallest CO2 emission with highest CO2 reduction (94%). This study provides a scientific method of selecting, projecting, and evaluating viable RES combinations for generating electricity without using fossil fuels.

Advancing power plant decarbonization with a flexible hybrid carbon capture system

Carbon dioxide capturing from natural gas-fired power plants is challenging due to high flow rate and the low carbon dioxide concentration of flue gas. This is an emerging field where many concepts and scientific principles are still in development. In this paper, a novel design is proposed for decarbonizing a natural gas-fired combined cycle power plant using a solar-assisted hybrid membrane-amine carbon capture and storage system. The design incorporates a solar field with thermal energy storage integrated with the capture plant reboiler along with multi-stage carbon dioxide selective membrane modules for selective exhaust gas recirculation (SEGR) combined with exhaust gas recirculation (EGR) to increase the concentration of Carbon dioxide in the flue gas. It is hypothesized that the proposed design could enhance the performance of the power plant integrated with carbon capture in terms of flexibility and sustainability. In this regard, a comprehensive process modeling and simulation framework is developed to accurately investigate the interactions between different components of the integrated process. The results show that the carbon dioxide concentration in the flue gas increases from 3.9 mol% in the conventional power plant to 10.87 mol% in the EGR + SEGR case (26 % of flue gas to EGR and 50 % to SEGR) and increases to 18.08 mol% by the SEGR case (76 % of flue gas to SEGR). Solar thermal energy is an efficient solution for reducing or eliminating the need for steam extraction for the stripper reboiler, resulting in a significant increase in net power output compared to the non-solar cases. The proposed designs lead to a 19.4 % increase in system power output in the SEGR case and a 13.8 % increase in the EGR + SEGR case compared to the baseline case. Also, the specific reboiler duty and required packing material volume in the absorber and stripper are significantly improved in the proposed designs. Moreover, the power plant carbon intensity in the proposed designs can be reduced by up to 10.3 %. The EGR + SEGR case offers an optimal solution as it requires a significantly smaller membrane area, approximately 71 % smaller membrane area compared to SEGR. The proposed designs and analysis have the potential to contribute significantly to the decarbonization of fossil-fueled power plants and enhance the sustainability and flexibility of the power sector.

Performance Evaluation of Olorunsogo Gas-Fired Power Plant Phase I

Aim: The aim of this research is to evaluate the performance of the Olorunsogo gas-fired power plant phase 1, examines the reason(s) for not operating at full capacity, and proffers possible solution(s).
 Study of the Design: The power plant comprises of eight (8) numbers of 42MW unit gas turbine capable of evacuating 277MW.
 Methodology: To obtain electrical parameters from the gas turbine, a mathematical model for pressure using a simple open-cycle gas turbine was developed. The pressure was further converted to energy using principles of kinetic theory of gases. Hence, the efficiency and other performance indicators were calculated.
 Results: The study revealed an average operating capacity of 31.28MW. The average efficiency of the power plant in the period under review was 50.88%, as compared to the international standard practice of 65% and above. The average load factor and capacity factor was 11.25% and 11.54% respectively as compared to international standard practice of 50-80%, while the average reliability was 55.79%, as compared to international standard practice of 95%.
 Conclusion: The study further reveals that wastage of gas, downtime, and inadequate gas supply are the major factors against the full capacity operation of the power plant. The proffered possible solutions articulated in this study if implemented, will optimize the power plant's full-capacity operation.

Detecting nitrogen oxide emissions in Qatar and quantifying emission factors of gas-fired power plants – a 4-year study

Abstract. Nitrogen oxides (NOx=NO+NO2), produced in urban areas and industrial facilities (particularly in fossil-fuel-fired power plants), are major sources of air pollutants, with implications for human health, leading local and national authorities to estimate their emissions using inventories. In Qatar, these inventories are not regularly updated, while the country is experiencing fast economic growth. Here, we use spaceborne retrievals of nitrogen dioxide (NO2) columns at high spatial resolution from the TROPOspheric Monitoring Instrument (TROPOMI) to estimate NOx emissions in Qatar from 2019 to 2022 with a flux-divergence scheme, according to which emissions are calculated as the sum of a transport term and a sink term representing the three-body reaction comprising NO2 and hydroxyl radical (OH). Our results highlight emissions from gas power plants in the northeast of the country and from the urban area of the capital, Doha. The emissions from cement plants in the west and different industrial facilities in the southeast are underestimated due to frequent low-quality measurements of NO2 columns in these areas. Our top-down model estimates a weekly cycle, with lower emissions on Fridays compared to the rest of the week, which is consistent with social norms in the country, and an annual cycle, with mean emissions of 9.56 kt per month for the 4-year period. These monthly emissions differ from the Copernicus Atmospheric Monitoring Service global anthropogenic emissions (CAMS-GLOB-ANT_v5.3) and the Emissions Database for Global Atmospheric Research (EDGARv6.1) global inventories, for which the annual cycle is less marked and the average emissions are respectively 1.67 and 1.68 times higher. Our emission estimates are correlated with local electricity generation and allow us to infer a mean NOx emission factor of 0.557 tNOx GWh−1 for the three gas power plants in the Ras Laffan area.

Long-term energy transition planning: Integrating battery system degradation and replacement for sustainable power systems

The transition towards sustainable energy systems has gained significant importance globally due to high levels of environmental pollution caused by the use of fossil fuels. This study addresses a critical aspect of the global transition towards sustainable energy systems. We emphasize the impact of considering energy storage system degradation and replacement in long-term energy transition planning. The importance of this lies in mitigating the challenges posed by the intermittency and variability of renewable energy sources, such as wind and solar, without failing to consider the negative effect that excessive use of batteries as a storage energy system would have. We propose an optimization model that integrates power systems generation and transmission infrastructure with strategic energy storage system implementation to optimize their size, operation, and location for maximum efficiency and benefits. This paper offers a comprehensive approach to take into account the environmental effect of the depth of the discharge and replacement of battery systems over a long-term planning horizon considering hourly operation of representative time periods. The electricity system of Baja California, Mexico, a region heavily reliant on fossil fuels, is presented as a case study to show the applicability of the model. Results demonstrate that continuous replacement of dispatchable generators (natural gas power plants) for non-dispatchable generators (variable renewable power plants) may cause an unexpected increase of indirect greenhouse gas emissions from the continuous replacement of batteries when degradation is not considered. The results of the case study show an average emissions factor of 0.325 Ton CO2eq/MWh, approximately 24 % lower than government expectations, using the proposed MILP model.

Numerical simulation and 4E analysis of a steam methane reforming-based multi heat recovery process, producing electricity, methanol, fresh water, heating, and coolant

Natural gas power plants play a pivotal role in power generation; nevertheless, their waste heat contributes to diminished thermodynamic efficiencies and the release of carbon dioxide emissions. One primary approach involves implementing effective heat recovery strategies to generate various products. The present study suggests a novel approach to heat recovery in different stages utilizing series and parallel arrangements within an environmentally friendly design to enhance controllability while expanding the range of products. The present study includes a steam methane reforming process, a Kalina cycle, a multi-effect desalination unit, a methanol synthesis unit, two organic Rankine cycles, and two ammonia Rankine cycles. The primary objective of this system is to efficiently and concurrently produce electricity, hot water, chilled water, fresh water, and methanol. The findings reveal that the newly devised process exhibits energy and exergy efficiencies of 47.55% and 50.58%, respectively, while the total unit cost of products amounts to 7.69 $/GJ. From an environmental perspective, the results indicate that the proposed structure exhibits a total net emission of 87.1 × 103 kg/h and a CO2 footprint of 0.22 kgCO2/kWh. Ultimately, the economic assessment elucidates that the fixed investment cost, total investment cost, total annual cost, and net present value are equivalent to 373.0 M$, 496.1 M$, 207.5 M$, and 598.6 M$, respectively.

Comprehensive technical study of a novel polygeneration arrangement using natural gas power plant and geothermal energy for producing electricity, heat, fresh water, and methanol

Structural modifications play a crucial role in enhancing the sustainability of natural gas power plants owing to their significant contribution to greenhouse gas emissions and irreversibility factors. One primary solution is using waste heat recovery systems integrated with these power plants, producing different products. Furthermore, integrating renewable energy resources into the entire system within a co-feed framework may be a viable method for further enhancements. The current study focuses on a novel heat integration process combined with a natural gas power plant, which uses geothermal energy as an auxiliary energy source. The newly designed system encompasses a gas turbine cycle, two modified geothermal power plants, a water electrolyzer unit, and a methanol synthesis unit. The process is simulated utilizing the Aspen HYSYS software, and to evaluate its viability, analyses are performed pertaining to energy, exergy, environment, and economics. Furthermore, a comprehensive parametric analysis is conducted on the primary performance indicators. The simulation results show that the process’s energy, exergy, and electrical efficiencies equal 53.85%, 47.30%, and 40.26%, respectively. The environmental evaluation demonstrates that the specific carbon dioxide emissions associated with the total energy produced and the sum of power and heating are 0.27 kg/kWh and 0.294 kg/kWh, respectively. From the economic aspect, the total unit cost of the products and the cost of energy of the system are 20.69 $/GJ and 0.086 $/kWh, respectively. Also, total annual cost, investment cost, and net present value of 222.81 M$, 1010.64 M$, and 1220.57 M$, respectively.

A new era for rural electric cooperatives: New clean energy investments, supported by federal incentives, will reduce rates, emissions, and reliance on outside power

This paper shows a least cost electricity generation portfolio for some of the largest rural electric cooperative utilities in the US. Due to the recent dramatic declines in renewable energy and battery storage costs, along with incentives under the federal Inflation Reduction Act (IRA) and excellent quality of renewable resource potential, we find that new investments in clean energy are significantly more cost-effective for most cooperative utilities than operating their existing coal and gas fired power plants. The study shows that rapid renewable energy (RE) deployment offers the rural cooperatives an opportunity to reduce their wholesale electricity costs by 10–20% compared with 2021 levels, while retiring their entire coal capacity by 2032. Most utilities could reduce their CO2 emissions by 80–90% relative to the 2021 levels, while also meeting load requirements at all hours, ensuring power supply reliability. While significant financing would be needed for such a transition to clean energy, we find that nearly half of the investments can be offset by the IRA tax credits. With bold and timely execution, cooperatives can reinvent their generation mix to provide affordable, reliable, and clean electricity that benefits rural communities.

Liquid Natural Gas Cold Energy Recovery for Integration of Sustainable District Cooling Systems: A Thermal Performance Analysis

This paper investigates the heat transfer properties of liquefied natural gas (LNG) in a corrugated plate heat exchanger and explores its application in cold energy recovery for enhanced energy efficiency. The study aims to integrate this technology into a 500 MW gas-fired power plant and a district cooling system to contribute to sustainable city development. Using computational fluid dynamics simulations and experimental validation, the heat transfer behaviour of LNG in the corrugated plate heat exchanger is examined, emphasising the significance of the gas film on the channel wall for efficient heat transfer between LNG and water/ethylene glycol. The study analyses heat exchange characteristics below and above the critical point of LNG. Below the critical point, the LNG behaves as an incompressible fluid, whereas above the critical point, the compressible supercritical state enables a substantial energy recovery and temperature rise at the outlet, highlighting the potential for cold energy recovery. The results demonstrate the effectiveness of cold energy recovery above the critical point, leading to significant energy savings and improved efficiency compared to conventional systems. Optimal operational parameters, such as the number of channels and flow rate ratios, are identified for successful cold energy recovery. This research provides valuable insights for sustainable city planning and the transition towards low-carbon energy systems, contributing to the overall goal of creating environmentally friendly and resilient urban environments.