A Novel Integrated System for Coupling an Externally Compressed Air Separation Unit with Liquid Air Energy Storage and Its Performance Analysis

Abstract

Air separation units (ASUs) are power-intensive devices on the electricity demand side with significant potential for large-scale energy storage. Liquid air energy storage (LAES) is currently a highly promising large-scale energy storage technology. Coupling ASU with LAES equipment can not only reduce the initial investment for LAES, but also significantly lower the operating electricity costs of the ASU. This study proposes a novel modular-integrated process for coupling an externally compressed ASU (ECAS) with LAES. The core advantages of this integrated process are as follows: the liquefaction unit’s storage capacity is not constrained by the ASU surplus load capacity and it integrates cold, heat, electricity, and material utilization. Taking an integrated system with 40,000 Nm³/h oxygen production capacity as an example, under liquefaction pressure of 90 bar and discharge expansion pressure of 110 bar, the system achieves its highest electrical round trip efficiency of 55.3%. Its energy storage capacity reaches 31.32 MWh/10⁴ Nm³ O₂, exceeding the maximum capacity of existing energy storage systems of the ECAS by 1.7 times. Based on a peak-flat-valley electricity price ratio of 3.4:2:1, an optimal economic performance is attained at 100 bar liquefaction pressure, delivering a 7.21% in cost saving rate compared to conventional ASUs. The liquefaction unit’s payback period is 6.39 years—68.1% shorter than conventional LAES. This study aims to enhance both the energy storage capacity and economic performance of integrated systems combining ECAS with LAES.

1. Introduction

As global energy systems progressively transition toward low carbon development, large-scale high efficiency energy storage technologies emerge as pivotal enablers for supporting high penetration integration of renewable energy, ensuring grid stability and safeguarding energy security. Particularly against the backdrop of rising penetration rates of intermittent renewable sources such as wind and solar power, electrical power systems face intensified regulation pressures. While traditional fossil fuel peaking systems can rapidly respond to grid peak demands, their intense short-term emissions, detrimental impacts on the environment and public health, and climate consequences have raised serious concerns about their sustainability [1]. The International Energy Agency (IEA) forecasts that the global energy storage market will exceed 620 GW by 2040, with annual investment requirements approaching USD 50 billion [2]. Liquid air energy storage (LAES), as a mechanical energy storage technology combining technical maturity with deployment flexibility, has garnered significant attention in recent years [3].

Since companies like Highview Power pioneered the construction of commercial scale pilot LAES systems, LAES technology has progressively transitioned from laboratory research to practical deployment [4]. LAES offers higher energy storage density, making it particularly suitable for space constrained locations such as urban areas and industrial parks [5]. Krawczyk et al. [6] conducted a comparative analysis of LAES and compressed air energy storage (CAES) under comparable power output conditions, demonstrating that LAES achieves higher efficiency (approximately 55% vs. 40% for CAES) with a more compact system layout. Compared to various battery energy storage systems (BESSs) with higher energy density, LAES demonstrates stable operation for >30 years, far exceeding the service life of most BESS solutions [7,8,9]. However, standalone liquefied air energy storage systems exhibit limitations such as low round trip efficiency and high levelized cost of storage [10]. To address these challenges, researchers are actively exploring thermal management strategies and structural optimizations to enhance system performance. Manassaldi et al. [11] developed an integrated LAES process flow incorporating multi-stage compression, regenerative heat exchange, and expansion, demonstrating that this configuration achieves a round trip efficiency of 69.64% while maintaining stable operation under medium-to-high load ranges. Liu et al. [12] proposed integrating high temperature heat pumps into LAES systems to achieve deep recovery of compression heat. Simulation results demonstrated a round trip efficiency of 58.30%, exceeding that of conventional LAES systems without heat pump integration by 3.7 percentage points, while validating the thermo-economic advantages of the integrated heat pump pathway [13]. Zhang et al. [14] integrated LAES with an organic Rankine cycle, demonstrating that cascaded thermal storage of compression heat substantially elevates thermal storage temperatures by 10.90–19.50% compared to conventional configurations. Liang et al. [15] evaluated the thermo-economic performance of LAES through a dual cost-efficiency metric, indicating that a 1% increase in round trip efficiency incurs a capital cost increase of 0.5–1%. Whereas for investment budgets exceeding GBP 47 million, an LAES system with three-stage compressors and four-stage expanders delivers optimal performance. Vecchi et al. [16] conducted a quantitative assessment of LAES systems under various integration pathways. By integrating electrical energy with compression heat and evaporative cooling to simultaneously meet power, heating, and cooling demands for district energy networks, the system demonstrated significantly enhanced operational flexibility and round trip efficiency, peaking at 72.80%. Synergistic integration of LAES systems with other energy systems through thermal and cryogenic boundaries substantially enhances its performance capabilities. Existing research predominantly focuses on thermal boundary integration to improve power generation capacity and boost round trip efficiency. However, cryogenic boundary integration represents another critical pathway for optimizing LAES performance. Future research should prioritize three key areas: utilization mechanisms for cryogenic boundary integration, advanced control strategies, and economic optimization models. Such advancements will accelerate the large-scale deployment of LAES in high renewable penetration scenarios.

ASUs are large-scale electricity consumer side devices that exhibit resource complementarity with LAES at cryogenic energy levels. Their integration not only reduces equipment investment costs, but also enhances economic viability through commercializing air separation products [4,17]. The ECAS features a structurally straightforward design and finds extensive application in metallurgical, chemical engineering, and related fields. Key research focuses on ECAS are summarized in

Table 1. Current research in ECAS.

Reference	Compression Type	Main Advantages	Main Disadvantages
Smith, 1960 [24]	ECAS	Simple configuration; suitable for direct gaseous product supply	Higher safety risk in oxygen compression
Van der Ham et al., 2011 [25]	ECAS	High potential for heat integration; waste heat can be recovered to improve efficiency	Requires stringent process control; complex initial design
R Singla et al., 2019 [26]	ECAS	Mature technology; easier maintenance	Higher safety risk
Zhao et al., 2020 [27]	ECAS	Compressors can be expanded in stages	Higher energy consumption; more cold energy losses
Liu et al., 2023 [23]	ECAS + LAES	Enables energy storage and peak-shaving; improved economic performance	Higher initial investment

. Wang et al. [18] proposed a novel polygeneration system integrating LNG regasification, LAES, and ASU (LNG-LAES-ASU). This system utilizes the ASU to recover LNG cold energy during the power discharge phase while accommodating vaporization rate fluctuations, achieving an ASU energy consumption of 0.14–0.15 kWh/Nm³ O₂. The thermodynamic round trip efficiency reaches 91.07% with a dynamic payback period of 3.23 years. This study provides a groundbreaking approach for efficient cryogenic energy utilization in air separation processes. Zhang et al. [19] proposed a novel liquid air energy storage-ammonia synthesis integrated system (LAES-NH₃) to achieve resource cycling and cost optimization. During off-peak periods, the ASU supplies nitrogen for both ammonia synthesis and LAES charging. During peak periods, nitrogen released from LAES discharge is recycled for ammonia production. This system reduces ASU operating costs by 38% and decreases LAES capital investment by 11.3%. For an ammonia plant with daily production of 500 tonnes, coupling with a 38 MWh LAES system delivers optimal economic performance, shortening the payback period to 6.9 years. However, the aforementioned integrated systems force the ASU into a non-continuous operation mode, conflicting with requirements for continuous industrial processes. Li et al. [20] proposed a novel system integrating dual-column air separation with LAES. By utilizing gaseous products from the LAES separator as ASU feedstock and employing stored liquid air for ASU cooling, the system achieves performance optimization with a round trip efficiency of 31.12%, energy efficiency of 56.60%, and ASU specific energy consumption of 10.624 kg/kWh. Wang et al. [21] developed an ASU-LAES system employing two energy utilization pathways: power generation through rewarmed liquid air expansion, and direct participation of liquid air into air distillation to reduce ASU energy consumption. The system achieves a comprehensive round trip efficiency of 52.10–69.2% (significantly exceeding conventional LAES averaging 49.1%), dynamic payback period of 3.25–6.72 years, and ramping capability of 25.50–50.10 MW, substantially outperforming standalone LAES systems. However, in both systems, the liquid air energy storage capacity is constrained by competing thermal utilization demands that prioritize liquid air production over storage scale. He et al. [22] optimized the integration process of internally compressed ASU with LAES, designing two novel processes for supplementary air recovery during energy storage: pre-compressor recovery and post-compressor recovery. The pre-compressor recovery process achieves up to 76.38% electrical round trip efficiency by recycling supplementary air to the compressor inlet through multi-stage expansion and reheating. The post-compressor recovery process forms an air refrigeration cycle downstream of the compressor, attaining 72.9% electrical round trip efficiency with a 13.23% reduction in electricity costs compared to conventional air separation. While significantly enhancing energy storage capacity and economic benefits, this configuration is exclusively applicable to new internally compressed ASU designs or retrofits of existing facilities. In practical industrial applications, spanning metallurgy, chemical processing, and petroleum refining, externally compressed air separation (ECAS) units maintain substantial market presence comparable to internally compressed systems. Crucially, however, externally compressed ASUs fundamentally differ in their distillation dynamics: the separation process exclusively yields gaseous products, eliminating the need for liquid air feedstock input into the distillation column. This inherent characteristic prevents direct utilization of liquid air in such systems, necessitating innovative integration pathways for coupling externally compressed ASUs with LAES. Liu et al. [23] proposed a system integrating ECAS with LAES, fully recovering cold energy from liquid air and utilizing air after expansion power generation. The system achieves a roundtrip efficiency of 54.52%, with a minimum investment payback period of 4.7 years. At scale, it could reduce CO₂ emissions by 12.87 million tonnes. However, the system’s energy storage capacity is constrained by the surplus load capacity of the air compressor, limiting further expansion of storage scale.

Therefore, this study proposes a novel modular-integrated system for coupling ECAS with LAES. By investigating the impacts of air liquefaction pressure during energy storage, expansion pressure for power generation during discharge, and heating temperature for power generation (i.e., waste heat utilization methods) on system energy efficiency and economic performance, an optimized process flow with superior performance has been determined. This design achieves both significant expansion of system storage scale and simplification of process. Compatible with both newly constructed air separation facilities and retrofits of existing plants, it maintains stable operation at full design load and under partial load conditions. This research employs retrofit schemes to conduct process design, simulation modeling, and feasibility analysis for modular-integrated systems. Key parameters investigated include liquefaction pressure (90–110 bar), discharge expansion pressure (80–120 bar), and waste heat utilization temperature (120–200 °C), with their effects on system efficiency and economic viability systematically evaluated.

2. Establishment of the ECAS-LAES Modular-Integrated System

Figure 1 presents the basic conceptual schematic of the ECAS-LAES modular-integrated system. The system consists of two segregated units: an air separation unit and a liquefaction unit. For retrofitted air separation plants, the integrated system’s air separation unit adopts a conventional ECAS, comprising compression, precooling, purification, refrigeration and heat exchange, distillation, gas product compression, and liquid product storage subsystems. The liquefaction unit is completely newly added and incorporates multiple subsystems: compression, precooling, purification, pressurization, heat exchange, liquid air storage, liquid air pressurization, liquid air regasification and reheating, cold storage, power generation, and gas recovery.

Compared to conventional LAES systems, the liquefaction unit in this configuration eliminates thermal storage equipment, resulting in streamlined operations. During the energy storage process, the air separation and liquefaction units operate synchronously: the air separation unit produces gaseous and liquid products (oxygen, nitrogen, argon), while the liquefaction unit generates and stores liquid air. During energy release, stored liquid air undergoes pressurization, regasification, reheating, and power generation before being recovered into the distillation system. Crucially, the distillation system maintains operation at its targeted operating level, while loads on the air compression, precooling, purification, refrigeration, and heat exchange subsystems proportionally decrease.

2.1. The Technical Process of the System

Figure 2 shows the technological process diagram of the ECAS-LAES modular-integrated system. The air separation unit follows a conventional externally compressed air separation process. The liquefaction unit contains the following equipment: one compressor unit, one booster compressor unit, a purification system, one plate-fin heat exchanger, three cryogenic expanders, one liquid air tank, one cryogenic pump, one propane heat exchanger, one methanol heat exchanger, two propane tanks (T1, T2), two methanol tanks (T3, T4), four liquid pumps, one expansion power unit, and six air heat exchangers (C1–C3, H1–H3).

Figure 3 presents the energy storage process of the ECAS-LAES modular-integrated system. During the storage period, both the air separation and liquefaction units operate synchronously. The air separation unit maintains standard externally compressed air separation operation. Ambient air is compressed, precooled, and purified before splitting into two streams. The first stream enters the main heat exchanger, cools to saturation temperature, and feeds into the high-pressure column of the distillation system. The second stream enters the booster-turbine expander, where it is pressurized and cooled before passing through the main heat exchanger. It then expands in the turbine section of the expander. The expanded air undergoes further cooling in subcooler 2 before entering the low-pressure column of the distillation system. High purity nitrogen from the top of the low-pressure column sequentially warms through subcooler 1 and the main heat exchanger, then enters the nitrogen compressor for final delivery as medium and high pressure nitrogen products. High purity oxygen from the bottom of the low-pressure column sequentially warms through subcooler 2 and the main heat exchanger before entering the oxygen compression system for product output. Waste nitrogen gas is extracted from the upper section of the low-pressure column. After sequential warming through subcooler 1 and the main heat exchanger, it splits into two portions: one enters the precooling system, while the other serves as regeneration gas for heater 1 in the purification system.

In the liquefaction unit, ambient air undergoes four-stage compression and cooling in the compressor unit before entering the purification system. The dried air from purification feeds into the booster compressor unit for another four-stage compression and cooling, then enters heat exchanger 1 (HX1). After cooling in HX1, the air splits into two streams. The first stream extracts from the mid-section of HX1 and expands through cryogenic expander 1, then returns to HX1 for rewarming before expanding via cryogenic expander 2 to atmospheric pressure. This low temperature atmospheric air undergoes secondary rewarming in HX1, with one portion entering the heater of the purification system and another recycling to the compressor unit. The second stream (high pressure air exiting HX1) is liquefied through cooling by counter flow air, propane, and methanol. The resulting liquid air flows through cryogenic expander 3 into the liquid air tank for storage. Air from the tank passes through heat exchangers for rewarming and ultimately enters the heater of the purification system, while the liquid content in the tank constitutes the stored liquid air inventory.

Figure 4 presents the energy discharge process flow diagram of the ECAS-LAES modular-integrated system. During discharge, liquid air from the liquid air tank is pressurized by a cryogenic pump and sequentially vaporized in heat exchanger 2 and heat exchanger 3, releasing cold energy. This released cold energy is absorbed and stored by propane and methanol acting as cold storage media, which ultimately provides the primary cold source for air liquefaction during subsequent energy storage phases. The vaporized air is first heated by circulating water return flow (42 °C) before entering the expansion power unit for primary expansion. The low temperature air discharged from this primary expansion cools the intake air upstream of the compressor in the air separation unit. The air is then reheated by circulating water return flow for secondary and tertiary expansion stages. Ultimately, the air after power generation enters the air separation system, merging with purified air from the air separation unit’s purification system. This combined stream flows into the main heat exchanger and booster-turbine expander of the air separation unit, undergoing cooling and refrigeration before finally feeding into the distillation system. While maintaining constant load operation of the distillation system, the feed air volume processed through the compression, precooling, and purification subsystems proportionally decreases. All other equipment in the air separation unit operates identically to the energy storage process.

2.2. System Operation Scheme

This study employs a 40,000 Nm³/h oxygen production ECAS-LAES modular-integrated system as its benchmark case. The air separation unit is designed based on operational data from an existing 6500 Nm³/h conventional externally compressed air separation plant. Both the air compressor and distillation system can operate either at full design capacity or under reduced load conditions at specified capacity rates.

Table 2. Operation schemes of the process.

Process	Operating Hours	Air Separation Unit		Liquefaction Unit
		Air Compressor	Distillation System
Energy storage	Off-peak hours	75–100%	75–100%	Operation
Energy release	Peak hours and flat hours	≥75%	75–100%	Shutdown

details the operational scheme for the ECAS-LAES modular-integrated process. The energy storage process operates during off-peak periods over an 8 h cycle, with the air compressor and distillation system running at either full design load or reduced capacity. The energy discharge process functions during peak and flat periods for 16 h, maintaining identical distillation system operating loads as during storage. The air separation unit’s compressor operates at no less than 75% of its design capacity.

Under the determined load rate of the air separation unit, the distillation system maintains constant operational load during both energy storage and discharge periods. This necessitates that the total feed input mass flow rate and enthalpy into the distillation system remain identical across both periods. The liquefaction unit’s energy storage capacity is calibrated to ensure that during discharge, the air separation unit’s consumption of liquid air meets or exceeds the minimum air compressor load threshold (75% design capacity).

This study employs Aspen Plus V10 software for system modeling and simulation. The Compr module models compressor units, the MHeatX module handles multi-stream heat exchanger modeling, and the RadFrac module simulates distillation columns. The Pump and Flash 2 modules model cryogenic pumps and separators, respectively. The Peng-Robinson-Boston Mathias (PR-BM) equation of state is adopted for fluid property calculations, with default simulation parameters detailed in

Table 3. Parameter setting of the ECAS-LAES modular-integrated system.

Parameter	Unit	Value
Ambient temperature	K	298
Ambient pressure	bar	1
Oxygen/nitrogen/argon components in ambient air [31]	mol%	20.96/78.11/0.93
Total number of stages of the air compressor	-	4
Isentropic efficiency of the compressor [32]	-	0.85
Isentropic efficiency of the expander [28]	-	0.87
Pump efficiency [32]	-	0.75
Average inlet water temperature of the compressor interstage cooler	K	305
Average return water temperature of the compressor interstage cooler	K	315
Output temperature of the interstage cooler of the compressor	K	313
Pinch temperature of the phase-change heat exchanger [33]	K	≥1.50
Pinch temperature of the non-phase-change heat exchanger [34]	K	≥2
Pressure of the cryogenic storage tank	bar	1
Daily loss rate of liquid in the tank [35]	%	0.20

. While PR-BM provides reasonably accurate results for cryogenic air separation systems, typical deviations in property predictions range from ±2% for vapor-liquid equilibria and densities to ±10% for specific heats and enthalpies, especially under deep cryogenic and high-pressure conditions. Additionally, the simulation was conducted with convergence tolerances of 10⁻⁶, which generally ensure mass and energy balance residuals within 0.1–0.5%. PR-BM is a recommended option in Aspen Plus for cryogenic and non-ideal gas systems, ensuring seamless integration with the compressor, heat exchanger, expander, and distillation column models used in this work, and avoiding numerical instability associated with switching property methods. Although sensitivity analysis regarding property method selection was not conducted, extensive literature review confirms that this approach is widely adopted in existing studies [28,29,30]. This study assumes quasi-steady operation during mode transitions. Dynamic effects including equipment ramp constraints and stabilization delays require further investigation.

Key streams of simulation results for the system operating at full design load during both storage and discharge periods are presented in

Table 4. Key streams of energy storage process simulation results for the 40,000 Nm³/h O₂ production system (design load).

Stream	Flow Rate (Nm3/h)	Pressure (bar)	Temperature (K)	Medium
1	200,692	1.00	298.15	Air
4	180,956	5.20	288.15	Air
5	180,956	5.20	99.00	Air
8	19,736	8.50	313.15	Air
9	19,736	8.50	162.00	Air
12	97,813	5.20	198.72	Mainly liquid air
23	86,012	1.26	96.00	N2 products
24	86,012	1.26	291.46	N2 products
28	71,050	1.26	96.00	Waste N2
29	71,050	1.26	285.5	Waste N2
33	40,000	1.32	92.55	O2 products
34	40,000	1.32	285.50	O2 products
39	158,448	1.01	298.15	Air
42	158,448	80.0	313.15	Air
48	23,043	1.10	303.19	Air
49	129,811	80.0	108.15	Air
50	129,811	1.25	81.20	Air
51	29,831	1.25	81.20	Air
52	29,831	1.25	303.19	Air

and

Table 5. Key streams of energy release process simulation results for the 40,000 Nm³/h O₂ production system (design load).

Stream	Flow Rate (Nm3/h)	Pressure (bar)	Temperature (K)	Medium
1	150,829	1.00	242.36	Air
4	181,082	5.20	288.15	Air
5	181,082	5.20	99.00	Air
8	19,736	8.50	313.15	Air
9	19,736	8.50	167.00	Air
12	99,705	5.097	98.59	Mainly liquid air
23	86,012	1.26	96.00	N2 products
24	86,012	1.26	291.46	N2 products
28	71,050	1.26	96.00	Waste N2
29	71,050	1.26	285.57	Waste N2
33	40,000	1.32	92.55	O2 products
34	40,000	1.32	285.57	O2 products
54	49,890	120.0	85.83	Liquid air
55	49,890	120.0	293.15	Air
56	49,890	120.0	313.15	Air
61	49,890	5.20	237.82	Air
62	49,890	5.20	288.15	Air

, respectively, with corresponding stream identifiers shown in Figure 3 and Figure 4. The complete simulation results are provided in Appendix A, as shown in

Table A1. Energy storage process simulation results for the 40,000 Nm³/h O₂ production system (design load).

Stream	Flow Rate (Nm3/h)	Pressure (bar)	Temperature (K)	Medium
1	200,692	1.00	298.15	Air
2	200,692	5.20	359.63	Air
3	200,692	5.20	288.15	Air
4	180,956	5.20	288.15	Air
5	180,956	5.20	99.00	Air
6	19,736	5.20	288.15	Air
7	19,736	8.50	339.97	Air
8	19,736	8.50	313.15	Air
9	19,736	8.50	162.00	Air
10	19,736	1.30	101.41	Air
11	19,736	1.30	95.00	Air
12	97,813	5.20	198.72	Mainly liquid air
13	39,909	5.20	96.21	Mainly liquid air
14	39,909	1.35	83.52	Mainly liquid air
15	57,904	5.09	96.21	Mainly liquid air
16 + 17	57,904	1.37	86.78	Gas−liquid mixture
18	193,239	5.01	94.15	N2
19	83,143	5.01	94.15	N2
20	83,143	5.01	81.15	N2
21	83,143	1.32	79.80	N2
22	86,012	1.26	79.36	N2 products
23	86,012	1.26	96.00	N2 products
24	86,012	1.26	291.46	N2 products
25	39,582	10.0	313.15	N2 products
26	46,430	20.0	313.15	N2 products
27	71,050	1.26	79.67	Waste N2
28	71,050	1.26	96.00	Waste N2
29	71,050	1.26	285.5	Waste N2
30	45,552	1.26	285.5	Waste N2
31	45,552	1.26	448.15	Waste N2
32	40,000	1.32	92.55	O2 products
33	40,000	1.32	92.55	O2 products
34	40,000	1.32	285.50	O2 products
35	40,000	1.32	313.15	O2 products
36	750	1.26	79.36	Liquid N2
37	1400	1.32	92.54	Liquid O2
39	158,448	1.01	298.15	Air
40	158,448	5.20	357.4	Air
41	158,448	5.20	313.15	Air
42	158,448	80.0	313.15	Air
43	28,637	80.0	208.15	Air
44	28,637	6.50	102.06	Air
45	28,637	6.50	163.15	Air
46	28,637	1.10	103.25	Air
47	28,637	1.10	303.19	Air
48	23,043	1.10	303.19	Air
49	129,811	80.0	108.15	Air
50	129,811	1.25	81.20	Air
51	29,831	1.25	81.20	Air
52	29,831	1.25	303.19	Air
65	63,818	1.20	91.93	Propane
66	63,818	1.20	214.00	Propane
69	34,085	1.20	213.82	Methanol
70	34,085	1.20	303.19	Methanol

and

Table A2. Energy release process simulation results for the 40,000 Nm³/h O₂ production system (design load).

Stream	Flow Rate (Nm3/h)	Pressure (bar)	Temperature (K)	Medium
1	150,829	1.00	242.36	Air
2	150,829	5.20	359.63	Air
3	150,829	5.20	288.15	Air
4	181,082	5.20	288.15	Air
5	181,082	5.20	99.00	Air
6	19,736	5.20	288.15	Air
7	19,736	8.50	345.85	Air
8	19,736	8.50	313.15	Air
9	19,736	8.50	167.00	Air
10	19,736	1.30	104.69	Air
11	19,736	1.30	95.00	Air
12	99,705	5.097	98.59	Mainly liquid air
13	41,901	5.097	96.07	Mainly liquid air
14	41,901	1.35	83.52	Mainly liquid air
15	57,804	5.097	96.07	Mainly liquid air
16 + 17	57,804	1.37	86.93	Gas−liquid mixture
18	191,478	5.097	93.92	N2
19	81,377	5.097	93.91	Liquid N2
20	81,377	5.097	80.91	Liquid N2
21	81,377	1.32	79.80	Liquid N2
22	86,012	1.26	79.36	N2 products
23	86,012	1.26	96.00	N2 products
24	86,012	1.26	291.46	N2 products
25	39,582	10.0	313.15	N2 products
26	26,028	20.0	313.15	N2 products
27	71,050	1.26	80.17	Waste N2
28	71,050	1.26	96.00	Waste N2
29	71,050	1.26	285.57	Waste N2
30	33,956	1.26	290.72	Waste N2
31	33,956	1.26	448.15	Waste N2
32	40,000	1.32	92.55	O2 products
33	40,000	1.32	92.55	O2 products
34	40,000	1.32	285.57	O2 products
35	40,000	30.0	313.15	O2 products
36	750	1.26	79.36	Liquid N2
37	1400	1.32	92.55	Liquid O2
53	49,890	1.10	79.66	Liquid air
54	49,890	120.0	85.83	Liquid air
55	49,890	120.0	293.15	Air
56	49,890	120.0	313.15	Air
57	49,890	44.46	239.84	Air
58	49,890	44.46	313.15	Air
59	49,890	15.20	236.44	Air
60	49,890	15.20	313.15	Air
61	49,890	5.20	237.82	Air
62	49,890	5.20	288.15	Air
63	31,909	1.20	214.00	Propane
64	31,909	1.20	91.93	Propane
67	17,042	1.20	303.15	Methanol
68	17,042	1.20	206.14	Methanol

. Figure 5 displays the composite temperature curves for hot and cold streams in heat exchanger 1, revealing a minimum pinch temperature of 1.56 K, which conforms to the design specifications for heat exchangers outlined in Table 3.

3. Feasibility Analysis of the ECAS-LAES Modular-Integrated System

The 40,000 Nm³/h conventional air separation unit described in this study is based on the externally compressed design of Chengde Iron and Steel Group’s 40,000 Nm³/h ASU in China. Key parameters, including compressor stages, output pressure load, temperature difference in the main heat exchanger, and temperature difference in the main condenser-evaporator, were referenced to industrial standards.

Table 6. Product component purity comparison: integrated system vs. conventional air separation.

Parameter	N2 Purity	O2 Purity	Waste N2 Purity	Ar Fraction Concentration
Unit	mol%	mol%	mol%	mol%
Case 1	99.991	99.606	98.564	9.956
Case 2	99.987	99.704	95.984	8.812
Case 3	99.991	99.703	95.986	8.833

compares product component purity in the low-pressure column during discharge for the 40,000 Nm³/h oxygen production ECAS-LAES modular-integrated system operating at design load versus a conventional air separation system. For the conventional system (Case 1) without liquid air recovery, the overhead nitrogen stream concentration is 99.991 mol%, the bottom oxygen product purity is 99.606 mol%, and the argon-rich fraction concentration measures 9.956 mol%.

For the integrated system during discharge (Case 2), vaporized liquid air recovered into the air separation unit elevates the oxygen concentration in the feed air from 20.95 mol% (conventional baseline) to 21.88 mol%. This increases oxygen product purity in the low-pressure column from 99.606 mol% to 99.704 mol% while decreasing the argon-rich fraction concentration from 9.956 mol% to 8.812 mol%, both remaining within conventional specifications. However, overhead nitrogen purity declines from 99.991 mol% to 99.987 mol%, falling below the conventional standard of 99.9906 mol%. Increasing the high-pressure column reflux ratio by 0.44 percentage points (Case 3) restores nitrogen purity to conventional levels while maintaining compliant oxygen and argon concentrations, confirming the technical viability of the modular-integrated system.

Performance assessment of the proposed system facilitates the selection of application-specific technical pathways to enhance comprehensive utilization. Under varying operational scenarios, the system’s profitability under distinct pricing mechanisms and its grid response value serve as primary determinants for deployment feasibility. This study therefore conducts integrated analyses of both energy efficiency indicators and economic indicators.

• Energy efficiency indicators

This study employs five key energy efficiency indicators for the modular-integrated ECAS-LAES system: liquid storage capacity per unit oxygen production capacity over 8 h, specific liquefaction electricity consumption, discharge power, energy storage capacity, and round trip efficiency.

The liquid storage capacity per unit oxygen production capacity over 8 h ($\dot{M}$) refers to the cumulative liquid air storage volume corresponding to a unit of oxygen design production capacity, kg/10⁴ Nm³ O₂, with the following formulation:

$$\stackrel{•}{M}={\displaystyle \frac{m_{st,Lair}\cdot t_{st}}{v_{O_2}}}$$

(1)

where m_st,Lair is the liquid air production capacity, kg/h; t_st is the duration of energy storage, h; v_O2 is the designed oxygen production capacity per hour for ASU, 10⁴ Nm³ O₂. The 8 h energy storage duration was selected because time-of-use electricity pricing designates a cumulative eight-hour valley period daily, during which electricity rates are significantly discounted [36,37,38].

The specific liquefaction electricity consumption (${\dot{W}}_{ECAS-LAES,st}$) refers to the total electrical energy consumed during the storage period to liquefy and store liquid air, kWh/kg, with the following formulation:

$${\stackrel{•}{W}}_{ECAS-LAES,st}={\displaystyle \frac{(W_{ECAS-LAES,st}-W_{ECAS})\cdot t_{st}}{m_{st,Lair}\cdot t_{st}}}$$

(2)

where W_ECAS denotes the total electrical power consumption of the conventional ECAS, kW, expressed as follows:

$$W_{ECAS}=W_{ECAS,AC}+W_{ECAS,PS}+W_{ECAS,OC}+W_{ECAS,NC}+W_{ECAS,WS}$$

(3)

the subscripts AC, PS, OC, NC, and WS represent the power consumption of the air compressor, purification system, oxygen compressor, nitrogen compressor, and circulating water system, respectively.

The round trip efficiency (${\eta }_{RTE}$) is calculated as the sum of the electricity savings relative to conventional ASU during the discharge period and the electricity generated by expansion during the discharge period, divided by the additional electricity consumption of the modular-integrated system relative to conventional ECAS during the storage period, expressed as follows:

$${\eta }_{RTE}={\displaystyle \frac{(W_{ECAS}-W_{ECAS-LAES,re}+W_{AT})\cdot t_{re}}{(W_{ECAS-LAES,st}-W_{CASU})\cdot t_{st}}}$$

(4)

where t_re is the duration of energy release, h. The “electricity savings” referenced here is fundamentally a thermodynamic quantity, calculated from the difference in power consumption (kW) between the proposed system and the conventional air separation unit, based on detailed Aspen Plus simulations of mass and energy balances.

The energy storage capacity (ESC) is defined as the sum of the electricity savings relative to the conventional air separation unit during the discharge period and the electricity generated by expansion during the discharge period, divided by the hourly oxygen design production capacity, kWh/10⁴ Nm³ O₂, expressed as follows:

$$ESC={\displaystyle \frac{(W_{ECAS}-W_{ECAS-LAES,re}+W_{AT})\cdot t_{re}}{v_{O_2}}}$$

(5)

The discharge power (ERP) is calculated as the sum of the reduced power consumption relative to the conventional air separation unit during the discharge period and the output power of the expander during the discharge period, divided by the hourly oxygen design production capacity, kW/10⁴ Nm³ O₂, expressed as follows:

$$ERP={\displaystyle \frac{W_{ECAS}-W_{ECAS-LAES,re}+W_{AT}}{v_{O_2}}}$$

(6)

where W_AT denotes the output power of the expander, kW.

W_ECAS-LAES,st denotes the net power consumption during the energy storage process of the modular-integrated ECAS-LAES system:

$$W_{ECAS-LAES,st}=W_{AS\mathrm{U},st}+W_{LAES}$$

(7)

where W_ASU,st and W_LAES are the total power consumption (kW) of the ASU and liquefaction unit during the energy storage process, expressed respectively as follows:

$$W_{ASU,st}=W_{ASU,AC,st}+W_{ASU,PS,st}+W_{ASU,NC,st}+W_{ASU,OC,st}+W_{ASU,ws,st}$$

(8)

$$W_{LAES}=W_{LAES,AC}+W_{LAES,PS}+W_{LAES,AB}+W_{LAES,ws}-W_{LAES,EPU1}-W_{LAES,EPU2}-W_{LAES,EPU3}$$

(9)

where the subscripts AC, AB, OC, NC represent the Air Compressor, Air Booster, Oxygen Compressor, and Nitrogen Compressor, respectively, kW; the subscripts PS and WS denote the Purification System and Circulating Water System, respectively; the subscript EPU1-3 denotes the Expansion Power Unit 1-3 in the liquefaction unit, respectively. The power consumption of all the aforementioned compression equipment and the output power of the expansion equipment are calculated as follows:

The total power of the multi-stage compressor is calculated as follows [39]:

$$W_{com}={\displaystyle {\sum }_{i=1}^n{W}_{com,i}}={\displaystyle {\sum }_{i=1}^n{m}_s\left(h_{i,out}-h_{i,in}\right)}={\displaystyle {\sum }_{i=1}^n{m}_s{c}_p\left(T_{i,out}-T_{i,in}\right)}$$

(10)

where m_s represents the mass flow rate of the fluid entering the system, kg/s; h_in and h_out denote the specific enthalpy at the inlet and outlet of the fluid stream, kJ/kg; c_p denotes the specific heat capacity of the fluid medium, kJ/(kg·K).

The total output power of a multi-stage expansion turbine is calculated as follows:

$$W_{turb}={\displaystyle {\sum }_{j=1}^J{W}_{turb,j}}={\displaystyle {\sum }_{j=1}^J{m}_s\left(h_{i,in}-h_{i,out}\right)}={\displaystyle {\sum }_{j=1}^J{m}_s{c}_p\left(T_{j,out}-T_{j,in}\right)}$$

(11)

The expression for the power consumption of the purification system is as follows:

$$W_{PS}=m_{heater}\left(h_{heater,out}-h_{heater,in}\right)$$

(12)

where m_heater denotes the mass flow rate of fluid passing through the electric heater, kg/s; h_heater,in and h_heater,out denote the specific enthalpy at the inlet and outlet of the heater, respectively, kJ/kg.

The circulating water system power consumption of the air separation unit and liquefaction unit is as follows:

$$W_{ECAS-LAES,ws}=W_{ASU,ws}+W_{LAES,ws}$$

(13)

where W_ASU,ws and W_LAES,ws denote the power consumption of the circulating water system for the ASU and LAES. The power consumption of the circulating water system is expressed as follows [40]:

$$W_{ws}={\displaystyle \frac{m_{ws}}{{\rho }_w}}{\dot{W}}_{e,ws}$$

(14)

The net electrical power consumption during the discharge process, W_{ASU-LAES, re}, is the sum of the power consumption of the air separation unit during discharge (W_ASU,re) and the power consumption of the liquid air pump (W_LAP), kW:

$$W_{ECAS-LAES,re}=W_{ASU,re}+W_{LAP}$$

(15)

$$W_{ASU,re}=W_{ASU,AC,re}+W_{ASU,PS,re}+W_{ASU,OC,re}+W_{ASU,NC,re}+W_{ASU,ws,re}$$

(16)

2.

Economic indicators

This paper provides a comprehensive economic evaluation of the ECAS-LAES modular-integrated system, based on the investment cost per unit energy storage capacity, the saving rate of operational electricity costs, and the static payback period of the liquefaction unit.

The investment cost per unit energy storage capacity [41] refers to the total initial investment cost C_inv of the LAES per unit of storage capacity, $/kWh. The expression is as follows:

$$C_{energy}={\displaystyle \frac{C_{inv}}{(W_{ECAS}-W_{ECAS-LAES,re}+W_{ECAS-LAES,AT})t_{re}}}$$

(17)

The operational electricity cost saving rate refers to the proportion of electricity cost savings achieved by the system compared to conventional ECAS. The expression is as follows:

$$\eta ={\displaystyle \frac{C_{ECAS}-C_{ECAS-LAES}}{C_{ECAS}}}$$

(18)

The static payback period refers to the length of time required for a project’s net cash flows to recover its total initial investment without considering the time value of money. The expression is as follows:

$$PB={\displaystyle \frac{C_{inv}}{365(C_{ECAS}-C_{ECAS-LAES})}}$$

(19)

In the calculation process, the electricity price is set at the off-peak rate of USD 0.042/kWh, with a peak-flat-off-peak price ratio of 3.40:2:1 [28], and the USD exchange rate during the study period is 7.04 CNY/USD.

4. Results and Discussion

For the ECAS-LAES modular-integrated system, this study investigates the impacts of air liquefaction pressure, expansion pressure for power generation, and energy discharge air heating methods within the liquefaction unit on system energy consumption characteristics, efficiency, and economic performance, to optimize overall system performance.

4.1. The Influence of Air Liquefaction Pressure on the Performance of Modular-Integrated System

Figure 6 illustrates the impact of air liquefaction pressure in the liquefaction unit on the power consumption during the energy storage process of the 40,000 Nm³/h oxygen production modular-integrated system under design load conditions. As the air liquefaction pressure increases, the system’s power consumption growth rate during the 8 h energy storage phase relative to conventional air separation initially decreases and then rises. At 90 bar liquefaction pressure, this growth rate reaches its minimum (94.76%). The power consumption during the energy storage process is mainly influenced by two factors: the pressure load and the airflow load of the compressors. When the air separation unit operates at full design load, its consumption rate of stored liquid air remains constant, and the liquid air production capacity is fixed. Increasing the air liquefaction pressure raises the system’s refrigeration expansion ratio; to maintain a constant refrigeration capacity, the air handling capacity of the compression and expansion equipment in the liquefaction unit is correspondingly reduced. As the liquefaction pressure increases from 70 bar to 90 bar, the effect of the compressor’s flow load on power consumption is more pronounced, leading to a slight decrease in the growth rate of power consumption during the storage process. When the liquefaction pressure is further increased from 90 bar to 120 bar, the impact of the compressor’s pressure load outweighs that of the flow load, causing the growth rate of power consumption to show a slight upward trend again.

Figure 7 demonstrates the influence of air liquefaction pressure in the liquefaction unit on the 8 h liquid storage capacity per unit oxygen production capability and the electricity consumption per unit air liquefaction for the 40,000 Nm³/h oxygen production integrated system under design load. As the liquefaction pressure increases, the system’s 8 h liquid storage capacity per 10⁴ Nm³ O₂ remains constant at 260 tonnes, while the electricity consumption per unit air liquefaction remains largely stable (approximately 0.22 kWh/kg) but exhibits a slight initial decrease followed by an increase. At 90 bar liquefaction pressure, the minimum electricity consumption of 0.22 kWh/kg is achieved. Under fixed air separation operating conditions, the liquid storage capacity is predetermined. The electricity consumption per unit air liquefaction depends on the hourly power consumption growth rate of the energy storage process relative to conventional air separation systems.

Figure 8 illustrates the impact of air liquefaction pressure in the liquefaction unit on the power consumption of the air separation unit and the power generation of the liquefaction unit during the energy discharge process for the 40,000 Nm³/h oxygen production integrated system under design load. At any liquefaction pressure, the system reduces power consumption by 30.31 MW (a constant 14.9% reduction relative to conventional air separation) after recovering stored energy, while the power generated from air energy discharge remains constant at 11.20% of conventional air separation’s power consumption. Consequently, the system’s 16 h discharge power is fixed at 1.98 MW/10⁴ Nm³ O₂, with an energy storage capacity of 31.69 MWh/10⁴ Nm³ O₂—representing a 1.73-fold increase over the maximum capacity (11.61 MWh/10⁴ Nm³ O₂) calculated from published external compression air separation data [23]. During discharge, the constant consumption of stored liquid air results in stable hourly power output from energy discharge and consistent power reduction in air separation. At fixed discharge power, the system’s round trip efficiency increases (or decreases) as the growth rate of power consumption during energy storage decreases (or increases). Thus, as shown in Figure 9, the round trip efficiency initially rises then declines with pressure, peaking at 55.17% at 90 bar, indicating optimal energy efficiency at this pressure.

Figure 10 demonstrates the effect of air liquefaction pressure on the initial investment cost of the liquefaction unit and the investment cost per unit energy storage capacity in the integrated system under design load. As liquefaction pressure increases, equipment investment for the liquefaction unit rises due to higher pressure requirements but decreases due to reduced air processing capacity. Consequently, the total initial investment and the unit energy storage capacity investment cost initially decrease then increase with rising liquefaction pressure.

At an air liquefaction pressure of 100 bar, the proposed system achieves the lowest initial total investment (USD 11.03 million) and specific investment cost (USD 87.03/kWh). Compared to conventional LAES systems (12 MW/50 MWh) with specific costs of USD 350–670/kWh, the proposed system demonstrates a cost reduction of 75.10–87.01%, equivalent to 1/4 to 1/11.5 of the benchmark value [41].

Figure 11 presents the influence of air liquefaction pressure on the electricity cost saving rate and the payback period of the liquefaction unit for the integrated system under design load. Both the system’s electricity cost saving rate relative to the conventional air separation unit and the liquefaction unit’s payback period exhibit minimal sensitivity to liquefaction pressure (70–120 bar). At 90 bar, the cost saving rate peaks at 7.30%, while the payback period reaches its minimum (6.44 years) at 100 bar due to variations in total initial investment. These results are calculated using an off-peak electricity price of USD 0.042/kWh and a peak-flat-off-peak price ratio of 3.40:2:1 [28]. The payback period of 6.44 years is significantly shorter than conventional standalone LAES systems (typically >15 years). This enhances attractiveness for industrial investors seeking mid-term returns. For energy-intensive industries (e.g., steel, chemicals), integrating LAES with existing air separation units reduces upfront costs by sharing infrastructure, accelerating return on investment. The integrated system represents a utility-scale long-duration energy storage solution.

4.2. The Influence of Expansion Pressure for Power Generation on the Performance of External Integrated System

Section 4.1 demonstrates that the system achieves round trip efficiency at 90 bar air liquefaction pressure. Consequently, this section investigates the impact of expansion pressure for power generation (equivalent to liquid air pump discharge pressure) on system energy efficiency using 90 bar as the reference. Figure 12 illustrates the effect of expansion pressure for power generation on power consumption during the energy storage process of the ECAS-LAES modular-integrated system under design load conditions.

Under a fixed air liquefaction pressure (90 bar), the growth rate of power consumption during the energy storage process relative to conventional air separation gradually increases with rising expansion pressure for power generation. As this pressure increases from 70 to 130 bar, the power consumption growth rate rises from 88.13% to 96.16%. Elevating the expansion pressure for power generation, equivalent to increasing the discharge pressure of the liquid air pump, raises the vaporization temperature of liquid air in heat exchanger 2 (Figure 4, propane heat exchanger), reducing its latent heat of vaporization. This decreases the stored high grade cold energy in the low temperature section, thereby diminishing the high grade cold energy available for the air liquefaction process. As the discharge pressure increases from 70 bar to 130 bar, 11.44% of the cold energy is lost. To maintain constant liquid storage capacity, the liquefaction unit must increase its own refrigeration output, resulting in higher power consumption during energy storage.

Figure 13 illustrates the effect of expansion pressure for power generation on both the 8 h liquid storage capacity per unit oxygen production capability and electricity consumption per unit air liquefaction for the integrated system under design load. As expansion pressure for power generation increases, the 8 h liquid storage capacity remains unaffected (constant at 260 t/10⁴ Nm³ O₂), while electricity consumption per unit air liquefaction rises due to the increased growth rate of power consumption during energy storage. Higher expansion pressure for power generation elevates per unit liquefaction electricity consumption, which increases from 0.21 kWh/kg at 70 bar to 0.22 kWh/kg at 130 bar.

Figure 14a,b, respectively, demonstrate the impact of expansion pressure for power generation on system power consumption, 16 h discharge power, and energy storage capacity for the integrated system under design load. Increasing expansion pressure for power generation elevates both the reduced power consumption proportion of the air separation unit relative to conventional systems (from 14.20% at 70 bar to 15.10% at 130 bar) and the power generated by expansion (rising from 9.90% to 11.30% of conventional consumption), thereby increasing discharge power from 1.82 to 2.00 MW/10⁴ Nm³ O₂ and storage capacity from 29.18 to 32.02 MWh/10⁴ Nm³ O₂. With constant pre-expansion air heating at 42 °C via recycled water, higher expansion pressure increases the expansion ratio to boost power output while amplifying cold energy release (interstage air temperature drops from −24 °C to −38 °C). This enhanced cold energy reduces compressor inlet air temperature through heat exchangers C1, C2, and C3, further decreasing air separation power consumption and augmenting discharge power and storage capacity.

Figure 15 demonstrates the effect of expansion pressure for power generation on the round trip electrical efficiency of the integrated system under design load. As expansion pressure for power generation varies from 70 to 130 bar, its influence on round trip electrical efficiency (approximately 55%) remains limited but exhibits a slight initial increase followed by a decrease, peaking at 55.30% at 110 bar. Higher expansion pressure for power generation reduces stored high grade cold energy during the energy storage phase, increasing refrigeration power consumption in the liquefaction unit. Concurrently, discharge power rises due to increased expansion ratios for both power generation and refrigeration. The differential growth rates between these two factors—increased power consumption during storage and enhanced net power reduction during discharge—cause round trip efficiency to rise from 54.63% at 70 bar to 55.24% at 110 bar, then decline to 54.94% at 130 bar.

Figure 16 illustrates the effect of expansion pressure for power generation on both the total initial investment cost of the liquefaction unit and the investment cost per unit energy storage capacity for the integrated system. As expansion pressure for power generation increases, the total initial investment cost of the liquefaction unit gradually rises, while the unit energy storage capacity investment cost first decreases then increases due to the growing storage capacity. At expansion pressures of 110 bar and 120 bar, the minimum unit energy storage capacity investment cost reaches USD 88.10/kWh, with the total liquefaction unit investment cost approximating USD 11 million. This represents a 4.30% increase compared to the investment at 80 bar and a 2.30% decrease relative to 130 bar. Higher expansion pressure for power generation increases power and heat exchange loads on the liquid air pump, heat exchangers 2 and 3, and the expansion power generation unit. Simultaneously, greater refrigeration capacity during energy storage elevates power loads on compressors and expanders, progressively raising the system’s overall initial investment cost.

Figure 17 demonstrates the effect of expansion pressure for power generation on the electricity cost saving rate relative to conventional air separation and the payback period of the liquefaction unit in the integrated system under design load. As expansion pressure for power generation increases, the system’s operational electricity cost saving rate gradually rises while the liquefaction unit’s payback period first decreases then increases, reaching its minimum of 6.46 years at 110 bar with a corresponding cost saving rate of 7.25% calculated using an off-peak electricity price of USD 0.042/kWh and a peak-flat-off-peak price ratio of 3.40:2:1 [28]. Compared to standalone CAES (11.86 years) [42], the integrated system achieves a 45.5% reduction in payback period. Similarly, compared to standalone PHS (28.39 years) [43], the payback period of the integrated system is reduced by 77.25%.

Increasing expansion pressure for power generation elevates system discharge power, thereby boosting electricity cost savings during peak periods and raising the overall operational electricity cost saving rate relative to conventional air separation. However, due to progressively higher initial investment costs, the payback period increases between 80 bar and 110 bar expansion pressure, then decreases above 110 bar.

The above economic analysis is based on Shanghai’s industrial time-of-use electricity pricing. However, significant variations exist in electricity price levels across different regions. Therefore, it is necessary to investigate the impact of different peak-to-off-peak price ratios on the system performance. Figure 18 illustrates the trends in the electricity cost saving rate and investment payback period for the integrated system under varying peak-to-valley price ratios.

Illustratively, for the integrated system employing recycled water waste heat for heating, a peak-to-valley price ratio of 2.5:1 yields an operational electricity cost saving rate of 3.0% relative to conventional air separation unit. When implemented across diverse regions, the system achieves electricity cost saving rates ranging from 7.21% to 9.64%, with liquefaction unit payback periods spanning from 6.39 to 4.16 years, demonstrating significant economic viability.

4.3. The Impact of Waste Heat Utilization Methods on the Performance of the Integrated System

At 90 bar air liquefaction pressure and 110 bar expansion pressure for power generation, the system achieves optimal energy efficiency with a round trip electrical efficiency of 55.30%. When operating at 100 bar air liquefaction pressure and 110 bar expansion pressure for power generation, the system attains peak overall economic performance. This study previously analyzed economic metrics under three scenarios: expansion pressure for power generation at 120 bar with air liquefaction pressure in the range of 70–120 bar, and fixed air liquefaction pressure at 90 bar with expansion pressure for power generation varying in the range of 80–130 bar. Here, we specifically calculate energy efficiency and economic performance under optimal operating points and evaluate how utilizing waste heat at different temperatures to heat air for expansion power generation affects these parameters.

Table 7. Performance metrics of waste heat recovery for variable temperature sources.

Operation Indices	Circulating Water 42 °C	Compression Waste Heat 120 °C
ASU design load	100%	100%
Air compressor load during energy storage process	100%	100%
Air compressor load during energy release process	75%	75%
Energy storage duration/h	8	8
Energy release process/h	16	16
Air liquefaction pressure/bar	100	100
Expansion pressure for power generation/bar	110	110
Performance Parameters	Circulating Water 42 °C	Compression Waste Heat 120 °C
Conventional ASU power consumption/kW	30,310	30,310
Power consumption of energy storage process/kW	58,689	58,689
Increase in fraction of power consumption	93.63	93.63
Liquid storage capacity/(t/104 Nm3 O2)	260	260
Unit power consumption of liquefied air/(kWh/kg)	0.22	0.22
Power consumption of ASU during energy release process/kW	25,812	26,609
Power generation during energy release process/kW	3331	4107
Energy release power consumption/(MWh/104 Nm3 O2)	1.96	1.95
Energy storage capacity/(MWh/104 Nm3 O2)	31.32	31.23
Round trip efficiency/%	55.18	55.03
Initial investment cost of liquefaction unit/$	1.09·107	1.08·107
Unit cost of energy storage capacity/($/kWh)	86.76	86.34
Electricity cost saving rate/%	7.21	7.15
Liquefaction unit payback period/year	6.39	6.40

presents key performance indicators of the 40,000 Nm³/h oxygen production ECAS-LAES modular-integrated system under optimal operating conditions when utilizing waste heat at different temperatures for heating. For systems using recycled water return (42 °C) as the heat source at 100 bar air liquefaction pressure and 110 bar expansion pressure for power generation, the power consumption growth rate during energy storage relative to conventional air separation is 93.63%, while the power reduction rate during energy discharge is 14.84%. Expansion power generation contributes 10.99% of conventional air separation’s power consumption, yielding a 16 h discharge power of 1.96 MW/10⁴ Nm³ O₂ and an energy storage capacity of 31.32 MWh/10⁴ Nm³ O₂, with a round trip electrical efficiency of 55.18%. Economic analysis shows an initial investment cost of USD 10.87 million for the liquefaction unit, a unit energy storage capacity investment cost of USD 86.76/kWh, an operational electricity cost saving rate of 7.21% compared to conventional systems, and a payback period of 6.39 years. Using Shanghai’s grid emission factor (0.42 tCO₂/MWh) [44], the system’s maximum energy storage capacity (31.32 MWh/10⁴ Nm³ O₂) translates to a direct CO₂ reduction potential of 13.15 t/10⁴ Nm³ O₂ annual output when displacing peak-grid power. For a 40,000 Nm³/h oxygen plant operating at 90% utilization, this equates to 46,000 tonnes CO₂ abated annually. Comparatively, lithium-ion batteries with equivalent capacity would incur about 4800 tonnes CO₂-eq in embedded emissions during manufacturing [45], while our system leverages existing ASU infrastructure, minimizing upfront carbon costs.

When utilizing waste heat from nitrogen compression above 120 °C instead of recycled water for heating air during energy discharge, the performance metrics of the energy storage remain unchanged, but power generation output reaches 4107 kW, 23.30% higher than with recycled water heating. However, elevated inlet temperatures at the expansion generator increase exhaust air temperatures at all stages, eliminating residual cold energy. This removal of cold energy consequently eliminates the need for heat exchangers C1, C2, and C3, allowing for ambient air to enter the air compressor without precooling. As a result, the reduced power consumption proportion of the air separation unit during discharge decreases from 14.84% to 12.21% relative to conventional systems. Combined effects of smaller power reduction in air separation and increased discharge power yield a round-trip electrical efficiency of 55.03%, comparable to the 55.18% efficiency of recycled water heating. Economically, reduced heat exchanger requirements lower initial investment costs by 0.77% and unit energy storage capacity costs by 0.5% versus recycled water heating. The operational electricity cost saving rate (7.15%) is marginally lower, while the payback period (6.40 years) remains equivalent. Consequently, integrating recycled water heating for expansion air delivers marginally superior overall performance in both energy efficiency and economic viability.

5. Conclusions

This paper proposes a novel modular-integrated system for externally compressed air separation and liquid air energy storage, featuring decoupled configurations of liquefied air storage and air separation equipment. This design significantly enhances the absorption capacity of externally compressed air separation systems for stored liquid air, with the following specific conclusions:

• The efficient utilization of internal waste heat and cold energy is achieved through integrated cascading. During energy discharge, heating expansion air for power generation using 42 °C recycled water return not only converts thermal energy into electricity but simultaneously generates −24 to −38 °C cold energy through expansion. This cold energy is then utilized to precool inlet air for the air compressor, significantly reducing compression work and enabling high efficiency cyclic recovery of both cold and thermal energy within the system.
• The system maximizes energy storage scale by leveraging the air separation unit’s absorption capacity for stored liquid air. While storage capacity increases with higher expansion pressure for power generation, round trip electrical efficiency (55.3%) occurs at 90 bar liquefaction pressure and 110 bar expansion pressure, delivering 1.96 MW/10⁴ Nm³ O₂ discharge power and 31.32 MWh/10⁴ Nm³ O₂ storage capacity over 16 h. This represents a 170% increase in maximum storage capacity compared to existing externally compressed air separation energy storage systems.
• The system eliminates the need for compressed heat storage, reducing investments in heat storage processes and equipment materials—particularly thermal oil. At 100 bar air liquefaction pressure, the liquefaction unit achieves the lowest unit energy storage capacity investment cost (USD 87.03/kWh), representing a 65.52–84.62% reduction compared to conventional 12 MW/50 MWh liquid air energy storage systems.
• At 100 bar air liquefaction pressure and 110 bar expansion pressure for power generation, the system achieves optimal economic performance. Under a peak-flat-off-peak price ratio of 3.40:2:1 (off-peak electricity price: USD 0.042/kWh), the electricity cost saving rate relative to conventional air separation reaches 7.21% during full load operation, with a liquefaction unit payback period of 6.39 years. Compared to existing externally compressed air separation energy storage systems under identical electricity pricing (3.90% saving rate), this represents an 85% improvement in cost savings.

This paper details the feasibility of the integrated system and its superior energy storage capacity. Future numerical simulations will incorporate synergies with waste heat sources from other plants to further enhance system efficiency; we will also accelerate construction of the pilot-scale demonstration plant specifically to address dynamic effects, including equipment ramp constraints and stabilization delays, through full-scale experimental validation.