###### Abstract  
Liquid air energy storage (LAES) technology is helpful for large-scale electrical energy storage (EES), but faces the challenge of insufficient peak power output. To address this issue, this study proposed an efficient and green system integrating LAES, a natural gas power plant (NGPP), and carbon capture. The research explores whether the integration design is theoretically feasible for future adoption in operating the LAES system and NGPP. The effect of the charging pressure, the number of air expansion stages, and electricity prices on the overall thermodynamic and economic characteristics are investigated. The round-trip efficiency and the exergy round-trip efficiency of the proposed system are 47.72% and 69.74%, respectively. The calculations show that the minimum dynamic payback period for such a project is 3.72 years, and the lowest levelized cost of electricity is 0.0802 USD-kWh\({}^{-1}\). This work provides a reference for peak-shaving power stations with energy storage and carbon capture. liquid air energy storage; gas power plant; carbon capture; thermodynamic analysis; economic analysis +
Footnote †: journal: Applied sciences  
consumption. Ref. [6] used a combustion chamber (CRV) with hot thermal energy storage (HTES) to recover the waste heat from LAES. An investigation based on the first and second laws of thermodynamics showed that the RTE and ERTE of the system were 65.7% and 49.7%, respectively. The investment cost for such an LAES system (5.3 MW) was USD 3.68 million. Ref. [7] found that a baseline LAES system had 20-40% of excessive compression heat, thus an organic Rankine cycle (ORC) combined with a vapor compression refrigeration cycle was adopted to generate additional electricity by using waste heat. The RTE of the coupled LAES was reported to be higher than 60%. Again, in order to fully utilize the compression heat, ref. [8] recommended a nitrogen power plant with a Brayton cycle. Still, the industrial feasibility of the system was not optimistic due to the wide temperature range (from \(-160\)\({}^{\circ}\)C to 200 \({}^{\circ}\)C). Power plant integration, compression waste heat utilization, and cold energy recovery have proved to be effective methods for improving the LAES system's performance. The increased power output and efficiencies of LAES allow it to support grid operations and provide opportunities to increase economic revenues. Liquefied natural gas (LNG) cold energy has emerged as an option for improving the overall performance of LAES systems [9]. Refs. [10; 11] contributed to the idea of loading LA as the cold energy carrier in the LNG supply chain. The optimized design reduced both the energy consumption and total expenses for LNG liquefaction by more than 25% [12]. Ref. [13] combined an existing LNG regasification plant with a conventional LAES system. LNG was gasified directly through two regenerative Rankine cycles during peak times, while the LNG cold energy was used to liquefy the pressurized air during off-peak times. The results showed that the involvement of the LNG regasification process in the LAES system was beneficial for the RTE. To meet the bidirectional peak electricity and natural gas (NG) requirements, ref. [14] established an integrated LAES system combining an LNG regasification terminal and an NG power plant. LNG cold energy was used in the pre-cooler and inter-cooler for air cooling during the LAES charging process. After desorbing the cold energy, the gasified NG was delivered from the pipeline network to the CRV during peak periods. The mixed gas produced by combustion was exhausted without decarbonization. Ref. [15] studied an LAES system utilizing LNG to cool the compressed air, and the surplus compression heat and LA cold energy was used to drive a two-stage ORC system. The RTE was found to be 45.44% when the liquefaction pressure was 7 MPa and the expansion pressure was 8 MPa.