1 Introduction
With the environmental problems caused by climate change becoming increasingly prominent, increasing attention has been given to reducing greenhouse gas emissions. The Intergovernmental Panel on Climate Change (IPCC) Special Report on Global Warming of 1.5 °C highlighted the importance of reaching net-zero emissions by the middle of the century [1]. By the end of 2020, some main economies pledged targets for reaching carbon neutrality (2050 in the EU and 2060 in China) [2,3]. These ambitious goals suggest that the challenge of reducing CO2 emissions will not vanish in the following 30 years. The development of sustainable, clean and renewable energy of the power industry is believed to exhibit the potential to meet the challenging goals of carbon neutrality [4]. It is predicted that the share of renewable energy will be increased to approximately 50% in 2050 [5]. However, with this increase in renewable energy in the power sector, the security and stability of the power grid are threatened because of the intermittent nature of most renewable energy sources [6]. In China, the wind curtailment rates in Gansu and Xinjiang were 33% and 29% in 2017, and these values were reduced to 8% and 4%, respectively, in 2021 [7,8]. This occurred because most thermal power units are operated for a long time under low loads. For example, in China, the average utilization duration of power generation plants reached only approximately 2589 h in the first half of 2021 [9]. With increasing renewable energy penetration, the situation will remain challenging. Therefore, to address the impact of renewable energy on the grid, two primary approaches can be adopted. One approach is to install electricity energy storage systems, which can store excess energy during periods of a low demand and generate power during peak periods. Specific main electrical energy storage technologies are promising for future applications, including pumped hydroelectric storage, compressed air energy storage, flywheel energy storage and rechargeable batteries [10,11]. The main challenges of the deployment of energy storage systems include size matching design, high capital cost and operation of large-scale energy storage systems [12].
Another method is to utilize conventional coal-fired power plants to regulate the mismatch between the supply and demand of power. In China, to dispatch more renewable energy, many coal-fired power plants are operated under low loads, which leads to an increase in the production cost of these power plants [13]. In addition, off-design operation of power plants often leads to safety and economic degradation issues. Therefore, with the above increase in renewable energy and decrease in the capacity of coal-fired power plants, new alternative peak regulation systems should be installed.
Cau and Cocco et al. investigated the energy and economic performance of coal gasification power plants integrated with a syngas storage section [14,15]. The results indicated that the operating flexibility and load modulation capability of the system were enhanced, but the energy production costs increased by approximately 5-20%. In fact, the syngas storage process functioned as an energy storage unit, which could decouple the dynamic characteristics of the gasification unit and power generating unit. Based on this concept, a novel hydrogen and electricity polygeneration system equipped with a syngas storage tank was proposed, and flexible operation strategies of the novel system were suggested in this paper. The dynamic characteristics of the novel system in the peak regulation process were investigated, and the role of each unit was examined. Finally, the risk and economy of this system were further analyzed. By improving the dynamic characteristics of the peak regulation system, more energy could be saved in renewable energy, and fossil energy could be utilized with low carbon emissions.
2 Problems and challenges of deep peak regulation technology in thermal power
2.1 Inflexible operation of conventional IGCC power plants
For traditional power plants, the overall dynamic characteristic is usually limited by a process with a low variable load change rate. Table 1 summarizes the variable load characteristics of different systems. The load depths of the gas turbine (GT), gas turbine combined cycle (GTCC) unit and integrated gasification combined cycle (IGCC) unit are not very different, but the load regulating rates greatly differ. Regarding the GT, the load regulating rate can reach 10%/min, but regarding the GTCC and IGCC, the load regulating rate can reach only approximately 5.5%/min and 1-3%/min, respectively, which indicates that the high dynamic performance of the GT or GTCC cannot be fully utilized in the IGCC. Therefore, to improve the variable load performance of the GTCC and IGCC, the isolation of lagging units is meaningful. For example, the load change rate of the IGCC ranges from only approximately 1-3%/min, which is far lower than that of gas turbines. This occurs because the load regulating rate is mainly limited by the dynamic characteristics of the air separation unit (ASU) [16,17]. Guo et al. investigated the characteristics of the cryogenic rectification column of the ASU and evaluated a multivariable predictive control strategy for the column [18]. Yang and Omell et al. proposed a process modification to improve the dispatch capability of the IGCC, which included an air storage unit and hydrogen unit. Therefore, independent manipulation of air separation, gasification and power generation could be realized [19,20].
Table 1 Variable load characteristics of the different systems |
| System | GT | GTCC | IGCC |
|---|---|---|---|
| Load range/% | 30-100 | 40-100 | 40-100 |
| Load regulating rate/%/min | 10 | 5.5 (up)/4.1-4.8 (down) | 1-3 |
2.2 High efficiency penalty of peak regulation power plants
Although coal-fired power plants can operate between loads of 30% and 100%, the system efficiency and power generation cost are greatly affected. As shown in Fig. 1, with decreasing power output load, the coal consumption of both 200-MW and 600-MW power plants considerably increases. In addition, off-design operation of a power plant can increase the cost of power generation [13]. In China, to promote the development of renewable energy, many coal-fired power plants are operated under low loads for a long period, regardless of the cost. Therefore, to maintain the sustainable development of renewable energy, more attention should be given to the peak regulation cost of power plants.
Fig. 1 Coal consumption rate of 200-MW and 600-MW coal fired power plants under different loads [13] |
2.3 Mismatch between low carbon emissions and flexibility of peak regulation power plants
As described above, peak regulation of renewable energy will be of great importance in the future, and fossil power plants can play a key role in this process. However, this requires retrofitting of traditional power plants to capture CO2 to achieve carbon neutrality, which can result in a notable efficiency penalty (approximately 7.7 ~ 11.9%) [21]. Furthermore, for conventional post-combustion capture systems, there occur strong interactions between the power plant and CO2 capture unit. When the operation load of the power plant changes, the flue gas flow rate changes, which can impose a great effect on the power output. The steam flow also varies and further influences the capture performance of the CO2 capture unit [22].
In fact, power plants with post-combustion capture are not suitable choices for peak regulation. On the one hand, retrofitting existing power plants is a notable challenge because of the high cost and efficiency penalty. On the other hand, it is possible that the operation cost of retrofitted power plants during peak regulation exceeds the wind/solar curtailment. In addition, off-design operation of a power plant often results in a decrease in safety and economy.
Based on the analysis above, to achieve carbon neutrality, the contradiction between peaking regulation and low carbon emissions will become increasingly prominent. Therefore, it is very important to develop a new low-carbon and flexible peak regulation system based on fossil energy.
3 Proposal of a flexible peak regulation system integrating hydrogen and power production
3.1 System description
To solve the problems faced by traditional coal-fired power systems in deep peak regulation, a new system is proposed based on the concept of dynamic characteristic decoupling. As shown in Fig. 2, the system mainly consists of gasification, syngas storage, hydrogen production and power generation units. Coal is first gasified with an oxidant (H2O/O2) to produce raw syngas. Then, the raw syngas is cooled via a waste heat boiler and further purified (dust, sulfide and nitrogen oxides are removed), after which the produced syngas is sent to the syngas storage tank. One stream of syngas in the storage tank is sent to the hydrogen production unit, in which hydrogen is produced after water gas shift and CO2 separation processes. Another stream of syngas enters the power generation unit and drives the gas turbine combined cycle power generation system to produce electricity. The heat of flue gas originating from the gas turbine is recycled by the heat recovery steam generator (HRSG), which can generate steam for the steam turbine. Furthermore, the steam turbine can supply steam for the hydrogen production unit, which can constitute a method of moderately regulating the power output.
Fig. 2 Schematic diagram of the novel low carbon and flexible peak regulation system |
Theoretically, battery packs can also be applied in energy storage in power grids, and the energy density of battery packs can reach as high as 200-800 kWh/m3, which is higher than the 73.7 kWh/m3 energy density of syngas at 25 bar and 25 °C. Therefore, batteries occupy less space than the syngas storage tank at the same scale. However, the cost of battery packs is higher than that of syngas storage when syngas is stored under a pressure higher than 25 bar [23,24]. The higher the storage pressure of syngas is, the lower the installation cost of storage tanks, although the associated compression work and operation cost can increase. In addition, batteries can usually be operated for approximately 6-10 years, which is highly related to their operation conditions, while syngas storage tanks can be operated over 15 years [24]. Furthermore, one of the difficulties of the existing IGCC system is that the flexibility of its gas turbines is not fully utilized, while the installation of syngas storage tanks can decouple the dynamic characteristics of each unit. Therefore, the syngas storage tank was selected in this system.
3.2 Flexible operation strategies of the new system
Based on the dynamic characteristics of each unit of the novel system, the control strategies for peak regulation differ for different peak regulation requirements. As indicated in Table 2, scenarios 1-3 are applicable for the peak regulation process with different power demand. If the syngas storage tank can meet the load variation requirements, then scenario 1 should be adopted for peak regulation. If scenario 1 cannot meet these requirements, scenarios 2 and 3 should be considered. The power output range of the system can be increased by adding a syngas storage tank, which is equivalent to a chemical energy storage unit. The dynamic characteristics of the different systems are also decoupled. During peak regulation, the gas storage unit can adjust the syngas flow to the power generation unit in a timely manner, and the power generation unit can quickly meet the variable power demand by taking advantage of the favorable response characteristic of the gas turbine.
Table 2 Operation strategies for the different power demand |
| Scenario | Power generating unit | Syngas storage unit | Hydrogen producing unit | Gasification unit |
|---|---|---|---|---|
| Scenario 1 | √ | √ | ||
| Scenario 2 | √ | √ | √ | |
| Scenario 3 | √ | √ | √ | √ |
Usually, when a unit is operated under a partial load, the thermodynamic performance of the unit decreases. Therefore, in the peak regulation process, minimizing the number of response units is significant for improving the system performance. Under scenarios 1 and 2, the hydrogen production unit or gasification unit can be maintained steady if not necessary, which could prevent part of the efficiency penalty during peak regulation. Moreover, CO2 can be captured in the hydrogen production unit and then compressed, transported and stored, which can utilize coal in a low-carbon way.
4 Analysis and evaluation of the system performance
In this section, the novel system of hydrogen and power polygeneration is compared to an IGCC plant to investigate its peak regulation performance.
4.1 Performance parameter definition
Because there are two products in the system, parameter definition is significant for performance comparison. The net electric efficiency (ηe) and net hydrogen efficiency (${\eta}_{{\textrm{H}}_2}$) of a polygeneration system are defined with Eqs. (1) and (2), respectively.
${\eta}_{\textrm{e}}=\frac{P_{\textrm{net}}}{\overset{\cdot }{m_{\textrm{coal}}}\cdot {LHV}_{\textrm{coal}}}\cdot 100\%$
${\eta}_{{\textrm{H}}_2}=\frac{{\overset{\cdot }{m}}_{{\textrm{H}}_2}\cdot {LHV}_{{\textrm{H}}_2}}{\overset{\cdot }{m_{\textrm{coal}}}\cdot {LHV}_{\textrm{coal}}}\cdot 100\%$
where Pnet is the net electricity output, and ${\overset{\cdot }{m}}_{{\textrm{H}}_2}$ is the mass flow rate of hydrogen. Because the energy levels of hydrogen and electricity are not thermodynamically equal, the definition of the overall efficiency is important for comparing systems with different products. The cumulative energy efficiency (ηtot, 60) has been applied in the evaluation of the performance of systems coproducing power and hydrogen, and this parameter can be defined as Eq. (3) [25].
${\eta}_{\textrm{tot},60}={\eta}_{\textrm{e}}+0.6\cdot {\eta}_{{\textrm{H}}_2}$
The CO2 emission intensity (${I}_{{\textrm{CO}}_2}$) refers to the CO2 emissions per unit electricity produced, which can be defined as:
${I}_{{\textrm{CO}}_2}\left(\textrm{g}/\textrm{kWh}\right)=\frac{M_{{\textrm{CO}}_2}}{E_{\textrm{electricity}}}$
where ${M}_{{\textrm{CO}}_2}$ denotes the CO2 emissions, and Eelectricity is the electrical energy generated. Under the condition of lacking peak regulation capability, the excess renewable energy is usually abandoned. Therefore, to evaluate the CO2 mitigation performance of a system, the energy saved in renewable energy should also be included to calculate the CO2 emission intensity, as described in Eq. (5). Esaved is the energy saved in renewable energy by implementing peak regulation.
${I}_{{\textrm{CO}}_2}^{\hbox{'}}\left(\textrm{g}/\textrm{kWh}\right)=\frac{M_{{\textrm{CO}}_2}}{E_{\textrm{electricity}}+{E}_{\textrm{saved}}}$
4.2 Analysis of the performance under the design conditions
In terms of products, the system is only a hydrogen and electricity polygeneration system. However, with the rapid increase in renewable energy, grid peak regulation will also be regarded as a product demand in the future energy market. Therefore, in terms of function, the system can not only produce hydrogen and electricity but can also meet the power dispatching requirements of the grid.
In this paper, the IGCC was selected for comparison rather than a system integrating the hydrogen combustion GTCC, hydrogen generation and hydrogen storage via coal gasification. This occurs because this new system solves the existing peak regulating problems encountered by the IGCC. In addition, compared to commercialized syngas storage and syngas combustion turbines, hydrogen storage and the hydrogen combustion GTCC are still in development. Technical difficulties must still be overcome, especially for hydrogen combustion turbines, such as flame stability and hydrogen embrittlement [26,27]. Therefore, no pure-hydrogen gas turbine system can currently be applied in large-scale commercial operation.
The ratio of the flow rates of syngas separated into hydrogen production units and power plants can be defined as the hydrogen-to-electricity ratio. The scale of the hydrogen-to-electricity ratio and the scale of the renewable energy system that should be matched are ultimately related to the cost. Generally, the higher the hydrogen-to-electricity ratio, the greater the peak regulation depth that can be managed by the power unit, but correspondingly, more fuel is consumed for hydrogen production. Therefore, when the demand for hydrogen production is not high, the scale of the hydrogen production unit should be reduced as much as possible. In this paper, a polygeneration system with a hydrogen-to-electricity ratio of 1 was investigated. The generation capacity of the new system was designed as 300 MW, and half of the syngas generated stemming from the gasification unit was used for hydrogen production under full-load conditions. Because the new system consumes extra coal for hydrogen production, the coal feed to the IGCC system is half of that to the polygeneration system, i.e., the power generation unit consumes the same amount of coal. The simulation parameters of the primary unit are listed in Table 3.
Table 3 Parameters for primary unit simulation |
| Gasifier | Slurry concentration | 63% |
|---|---|---|
| Temperature/pressure | 1400 °C/25 bar | |
| Water gas shift | Temperature/pressure | 300-400 °C/250 °C; 25 bar |
| Selexol | Temperature/pressure/CO2 recovery ratio | 30 °C/23 bar/90% |
| GTCC | Gas turbine: temperature/pressure ratio/isentropic efficiency/mechanical efficiency | 1360 °C/23/94.31%/98% |
| Three pressure levels and reheat | 156/32/7.5 bar; 565/565/331 °C | |
| Compressor | Isentropic efficiency/mechanical efficiency | 85%/98% |
| Pump | Efficiency | 82% |
Aspen Plus was applied to simulate the IGCC and the novel peak regulation system under the considered design conditions, and all the main input parameters are provided in Table 4. A simplified ASU was simulated, and the main parameters of the distillation tower were retrieved from the paper by Xiong et al. [28].
Table 4 Input parameters of the models under the design conditions |
| Unit | Parameters | Polygeneration system | IGCC |
|---|---|---|---|
| Gasifier | Oxygen input/kg/s | 27.8 (95% O2) | 13.9 (95% O2) |
| Slurry input/kg/s | 61.7 | 30.8 | |
| Water gas shift | Water input/kg/s | 20.5 | - |
| Selexol | Solvent/kg/s | 979.7 | - |
| GTCC | Air input/kg/s | 290.1 | 290.1 |
| Exhaust gas temperature/°C | 120 | 120 |
The static simulation results are listed in Table 5. The net electricity output of the polygeneration system is lower than that of the IGCC because part of the electricity in the polygeneration system is consumed for hydrogen production, including CO2 removal and hydrogen compression. The CO2 emissions intensity of the polygeneration system is slightly higher than that of the IGCC system. This occurs because more energy is consumed for hydrogen production, and the net electric output is reduced. The polygeneration system can capture approximately 43% of the total CO2 emissions via CO2 removal from the hydrogen production unit.
Table 5 Simulation results of the IGCC and polygeneration systems under the design conditions |
| Parameters | Polygeneration system | IGCC |
|---|---|---|
| Coal feed/MW | 1129.5 | 564.7 |
| Electricity gross output/MW | 301.9 | 288.9 |
| Auxiliary power consumption/MW | 43.5 | 12.7 |
| Net electricity output/MW | 258.4 | 276.2 |
| Hydrogen output (LHV based)/MW | 485.1 | 0 |
| Hydrogen-to-electricity ratio | 1 | 0 |
| Net electric efficiency/% | 22.9 | 48.9 |
| Net hydrogen efficiency/% | 39.2 | - |
| Cumulative energy efficiency/% | 46.42 | - |
| CO2 emission intensity/g/kwh | 715.4 | 669.1 |
| CO2 capture ratio/% | 43.0 | 0 |
The dynamic performance of the novel system was designed, as summarized in Table 6. The load change rates of the clean-up, water gas shift and CO2 capture units were all set to 2%/min due to the lack of literature data. The load change rate of the IGCC ranged from only approximately 0.25%-0.5%/min, which is mainly limited by the ASU [17]. Regarding the Nakoso 250-MW Air-Blown IGCC Demonstration Plant in Japan, the load change rate is 3%/min because part of the air in the compressor is extracted as an oxidant for gasification [29].
Table 6 Dynamic characteristics of the primary equipment |
| Equipment | Load range | Ramp rate |
|---|---|---|
| Gasification | ||
| ASU | 60%-100% [30] | 0.5%/min [31] |
| Gasifier | 70-100% [32] | 3.3%/min (up) /5%/min (down) [33] |
| Clean-up | - | 2%/min |
| Syngas storage | ||
| Storage tank | 0-100% | > 10%/min |
| Hydrogen production | ||
| Water gas shift | 60-100% | 2%/min |
| CO2 capture | 60-100% [34] | 2%/min |
| Power generation | ||
| Gas turbine combined cycle | 50-100% [35] | ~5%/min [36] |
| Generator | 10-100% [37] | > 5%/min |
The storage tank volume design was determined according to the actual peak regulation requirements and is highly related to the dynamic performance of the polygeneration system, which is described in Section 4.3.
4.3 Analysis of the dynamic performance under variable load operation conditions
In fact, the decrease in unit load limits the unit performance. For example, with the reduction in the fuel input of the gasifier and gas turbine combined cycle, the unit performance also decreases [38,39]. The decrease in system performance depends on the actual design parameters of the system itself. Therefore, some assumptions were made here. The efficiencies of the power generating unit, hydrogen production unit, and gasification unit do not vary with the system load; thus, the load of the power output is proportional to the syngas input of the power unit.
The simplified model of the gasification and power generation units can be described as Eqs. (6) and (7) respectively. f refers to the mass flow, kg/s; ηCGE is the cold gas efficiency of the gasification process; syn1 is the syngas produced by the gasification unit; LHVcoal and LHVsyn are the low heating values of coal and syngas respectively, MJ/kg; syn2 is the syngas sent to the power generation unit; ηGTCC is the efficiency of GTCC; PGTCC is the power output of GTCC, MW.
${f}_{\textrm{coal}}\cdot {\textrm{LHV}}_{\textrm{coal}}\cdot {\eta}_{\textrm{CGE}}={f}_{\textrm{syn}1}\cdot {\textrm{LHV}}_{\textrm{syn}}$
${P}_{GTCC}={f}_{\textrm{syn}2}\cdot {\textrm{LHV}}_{\textrm{syn}}\cdot {\eta}_{\textrm{GTCC}}$
$-{M}_{\textrm{R},{\textrm{t}}_1}\le {\int}_{{\textrm{t}}_1}^{{\textrm{t}}_2}\left({f}_{\textrm{syn}1}-{f}_{\textrm{syn}2}-{f}_{\textrm{syn}3}\right)\cdot \textrm{d}t\le {M}_{\textrm{V},{\textrm{t}}_1}$
${P_{\textrm{Aux},\textrm{t}}}_{\textrm{i}}={P}_{\textrm{Aux},\textrm{d}}^{\textrm{i}}\cdot {f}_{\textrm{in},\textrm{t}}^{\textrm{i}}/{f}_{\textrm{in},\textrm{d}}^{\textrm{i}}$
${P}_{\textrm{net},\textrm{t}}={P}_{\textrm{GTCC},\textrm{t}}-\sum {P_{\textrm{Aux},\textrm{t}}}_{\textrm{i}}$
The constraints on the tank can be expressed as Eq. (8). Syn3 is the syngas separated into the hydrogen production unit; ${M}_{\textrm{R},{\textrm{t}}_1}$ and ${M}_{\textrm{V},{\textrm{t}}_1}$ are the syngas reserves and the amount of the syngas can be stored by the remaining space of the tank at the time of t1. The power consumed by the auxiliary equipment was corrected over the mass flow of the stream input of each unit, as described by Eq. (9). ${P}_{\textrm{Aux},\textrm{d}}^{\textrm{i}}$ refers to the power consumed by the auxiliary equipment i under the design condition. PAux, ti is the actual power consumption at the time of t. ${f}_{\textrm{in},\textrm{d}}^{\textrm{i}}$ and ${f}_{\textrm{in},\textrm{t}}^{\textrm{i}}$ refer to the mass flow of stream input under the design and off-design conditions respectively. The net power output can be calculated by Eq. (10).
Due to the assumption that the performance of each unit does not change with the load, the output response can be realized by modulating the mass flow of each unit easily, as described by Eqs. (11) and (12). MATLAB was used for the modeling.
$\frac{\textrm{d}{f}_{\textrm{coal}}}{\textrm{d}t}\cdot {\textrm{LHV}}_{\textrm{coal}}\cdot {\eta}_{\textrm{CGE}}=\frac{\textrm{d}{f}_{\textrm{syn}1}}{\textrm{d}t}\cdot {\textrm{LHV}}_{\textrm{syn}}$
$\frac{\textrm{d}{P}_{\textrm{GTCC}}}{\textrm{d}t}=\frac{\textrm{d}{f}_{\textrm{syn}2}}{\textrm{d}t}\cdot {\textrm{LHV}}_{\textrm{syn}}\cdot {\eta}_{\textrm{GTCC}}$
The syngas storage tank is an important unit to decouple the dynamic characteristics of the gasification, hydrogen production and power generation units. Therefore, the factors that influence the design capacity of storage tank was investigated in this section.
Figure 3 shows the syngas reserve change in the syngas storage tank with the various load change rates of the power generation unit and hydrogen production unit. With increasing power demand, the power output increases, and the syngas in the storage tank accordingly decreases. The higher the power ramp rate, the more syngas is consumed in the peak regulation process. As shown in Fig. 3a, when the power ramp rate is improved from 1%/min to 3%/min, the syngas reserve change increases by approximately 66.7%. However, the syngas reserve change is not that notable when the power ramp rate is further increased to 5%/min, which indicates that the syngas reserve variation is more sensitive to the power ramp rate when the power ramp rates are below 3%. A similar trend can also be found for the hydrogen production unit. As shown in Fig. 3b, with increasing load change rate of the hydrogen production unit, the required syngas reserves are reduced, and the syngas reserve change is more obvious when the load change rate is increased from 0.5%/min to 1.5%/min. Therefore, the increase in the response speed of the hydrogen production unit is conducive to reducing the dependence on the storage tank, thereby reducing the design capacity and installation cost of the storage tank. In the power output decrease process, as shown in Fig. 3c, d, with increasing ramp rate of the power unit, the amount of syngas in the storage tank rapidly increases. The increase in the load change rate of the hydrogen production unit can reduce the capacity requirement of the storage tank.
Fig. 3 Syngas reserve change with the various load change rates of the power generation and hydrogen generation unit (a results of the power output increase at the different ramp rates of the power generating unit; b results of the power output increase at the different load change rate of the hydrogen production unit; c results of the power output decrease at the different ramp rates of the power generating unit; d results of the power output decrease at the different load change rates of the hydrogen production unit; ag, ah and ap are the load change rates of the gasification, hydrogen production and power generating units, respectively) |
Therefore, to meet different power demand, the storage tank must simultaneously retain part of the syngas and reserve some storage space under the design conditions. The design capacity of the storage tank is highly related to the load change rates of the power generation unit and hydrogen production unit.
In regard to scenario 3 in Table 2, a gasification unit is also applied for peak regulation. Figure 4 shows the syngas reserve change with the different load change rates of the gasification unit. The load change rates of the power generation and hydrogen production units remain fixed at 5%/min and 1%/min, respectively. With increasing load change rate of the gasification unit, the syngas reserve change in the storage tank is rapidly reduced. Therefore, the load change rate of the gasification unit also imposes a great influence on the design capacity of the storage tank, thus affecting the investment cost and peak regulation performance of the whole system. For traditional power plants, all the equipment starts responding and stabilizes at the same time. However, for the new system, as shown in Figs. 3 and 4, the response time of the power generation unit is shorter than that of the hydrogen production unit and gasification unit, which fully reflects the decoupling function of the syngas storage tank. The response time of the overall system, i.e., the time needed by the system to respond to stability, is usually determined by the unit with the lowest load change rate. Therefore, the storage of syngas reduces the response time of the power output by decoupling the dynamic characteristics of each unit, although the response time of the whole system does not change.
Fig. 4 Syngas reserve change with the various load change rates of the gasification unit |
In general, the higher the ramp rate of the power generation unit, the higher the storage tank capacity needed is. The higher the load change rates of the hydrogen production unit and gasification unit are, the lower the design capacity of the storage tank. In fact, during actual engineering design of storage tanks, both the peak regulation demand and the response speed of the system should be considered. In addition, the efficiency change of each unit under a partial load also exerts a notable influence on the system scale design, which should be further studied according to the specific equipment parameters.
4.4 Performance comparison between the new system and IGCC system
To compare the peak regulation performance of the novel system to that of IGCC systems of the same power generation scale, a peak regulation process was assumed in this section: the power output must be reduced by 200 MW at a rate of 10 MW/min and maintained for hours. The load change rate of the IGCC is limited by the ASU and was set to 0.5%/min. The maximum load change depths of the gasification units of the IGCC system and the novel polygeneration system were all set to 50%. However, due to the different gasification unit scales, the syngas output of the novel system was approximately twice that of the IGCC system.
Figure 5 shows the variations of key parameters of each system during the peak regulation process. For the novel system, when the power demand declined, the power generation unit responded firstly, then the load of hydrogen production increased to consume the syngas in the tank. The syngas reserves in the tank were balanced by modulating the coal input of the gasification unit, thus the syngas reserve was reduced to the initial value after the regulating process. Compared to the IGCC, the load change rate of the polygeneration system could meet the requirements of peak regulation. Therefore, compared to the IGCC system, part of the energy savings (S1) occurs because of the increase in the load change rate of the novel system. The other part of the energy savings (S2) is due to the increase in the load change depth. During this process, the maximum syngas reserve in the tank is less than 45,000 kg. Furthermore, compared to the IGCC system, the energy savings of the new system linearly increase over time after both systems enter a steady state.
Fig. 5 Key parameters of each system during the peak regulation process (a the power output of each system; b the mass flow of coal input and syngas flow in the poly-generation system; c the syngas reserves of the tank; d the energy saved in renewable energy of the new system versus the IGCC system) |
The peak regulation performance of each system is summarized in Table 7. Due to the installation of the syngas storage tank, the power generation unit can quickly respond to load fluctuations. The actual variable load depth of the power output is also increased because the system is integrated with the hydrogen production plant. Furthermore, in the peak regulation process, the IGCC system and the novel system save 436.7 MWh and 852.5 MWh of electricity, respectively. The CO2 emission intensity of each system in the peak regulation process was also investigated by including the energy saved in renewable energy, as determined with Eq. (5). The CO2 emission intensity of the novel system is 35.5% lower than that of the IGCC system because the novel system saves more renewable energy in the peak regulation process.
Table 7 Peak regulation performance comparison between the poly-generation system and the IGCC system |
| System | Variable load rate/%/min | Depth of net power output /% | Energy saved in renewable energy/MWh | CO2 emission intensity (including the energy saved)/g/kWh |
|---|---|---|---|---|
| IGCC | 0.5 | 55.2 | 436.7 | 370.8 |
| Novel poly-generation system | 5 | 22.7 | 852.5 | 239.3 |
5 Risk and economic analysis
5.1 Physical constraints and risk analysis
For the new system, the options for syngas storage include cryogenic liquid storage and compressed gas storage. Because liquid storage is expensive, compressed gas storage was studied in this paper [40]. However, the scale of the syngas storage vessel is highly related to the storage conditions, as shown in Fig. 6. Because the gasifier is operated under a high pressure to match the following gas turbine combined cycle system, the inlet syngas pressure of the syngas storage unit is 25 bar. With increasing pressure, the syngas volume gradually decreases, which can reduce the cost of installing a storage tank. However, with increasing storage pressure, the compression work also greatly increases; as a result, the operating cost increases. In addition, because syngas under a high pressure must be further expanded to match the pressure of the following unit, the storage conditions must be optimized to minimize the energy cost of syngas storage and release.
Fig. 6 Syngas volume and compression energy consumption under the different pressures (the storage temperature is 25 °C) |
Syngas storage still faces many problems, including security and technology. On the one hand, syngas is mainly composed of flammable gases under a high pressure, which may pose a hazard to humans. On the other hand, the high H2 concentration and impurities in syngas may result in metal embrittlement and corrosion [41]. Yang et al. also found that tars could be deposited on the inside wall of a storage cylinder, which could enhance corrosion [42].
5.2 Capital expenditure (CAPEX) estimation
${I}_i={I}_{i,r}\times {\left(\frac{S_i}{S_{i,r}}\right)}^{N_i}\times \left(\frac{CEPCI_{2018}}{CEPCI_{ref}}\right)\times f$
where f denotes the localization factor and S denotes the scale of the equipment. The subscripts i and r and superscript N denote the ith equipment of the system, the reference equipment, and the scale factor, respectively. CEPCI2018 is the chemical engineering plant cost index (CEPCI) in 2018, and CEPCIref is the value in the reference case. The reference cost of Selexol was retrieved from [46]. The estimation cost of each piece of unit is provided in Table 8. The syngas storage conditions were set as 35 bar and 25 °C, and the capacity was calculated according to the value shown in Fig. 4. If prestored syngas were considered, the maximum capacity would reach approximately 50,000 kg syngas, and the volume of the vessel would reach at least 1872 m3.
Table 8 CAPEX of the process units of the IGCC system and the novel system (M$) |
| IGCC | Novel system | |
|---|---|---|
| Coal pulverizer | 2.1 | 3.6 |
| Gasification | 64.6 | 105.0 |
| ASU | 13.9 | 21.1 |
| WGS | 0.0 | 7.0 |
| Selexol | 0.0 | 16.9 |
| PSA | 0.0 | 7.7 |
| Gas turbine combined cycle unit | 114.2 | 117.7 |
| Syngas storage tank [24] | 0.0 | 24.0 |
| Total installed cost | 194.8 | 302.9 |
| Contingency (15% of the total installed cost) | 29.2 | 45.4 |
| Land (5% of the total installed cost) | 9.7 | 15.1 |
| TCI | 233.8 | 363.4 |
The gasification and gas turbine combined cycle units of the new system account for 28.9% and 32.4%, respectively, of the total investment cost. The share of the hydrogen production units, including water gas shift, Selexol and pressure swing adsorption (PSA) units, is only 8.7%. In addition, the syngas storage tank investment accounts for approximately 6.6% of the total investment cost. Therefore, the installation of a syngas storage tank and hydrogen production unit increases the total capital investment (TCI) by only approximately 15.3%. Although the gasification scale of the new system is two times that of the reference system, the total capital investment increases by only approximately 55%. Furthermore, because the system can sell the hydrogen produced and regulate the power output more flexibly, the extra installation investment can be recovered.
Based on the analysis above, an IGCC system can also be combined with an existing hydrogen production unit by installing a storage tank as a connection. This not only increases the flexibility of the IGCC system but also greatly reduces the installation cost.
6 Conclusions
A novel hydrogen and electricity polygeneration system equipped with a syngas storage unit was proposed in this paper to address the high renewable energy penetration of the electricity grid. Operation strategies for peak regulation of the novel system were designed in this paper according to different power demand. The influence of the dynamic characteristics of the different units on the syngas reserve change in the storage tank was also investigated. The main conclusions are as follows:
(1) The scale of the syngas storage tank can be reduced by decreasing the ramp rate of the power generation unit and increasing the load change rates of the gasification unit and hydrogen production unit.
(2) Compared to the IGCC system, the load change rate of the novel system is increased to 3-5%/min from 0.5%/min. The dynamic performance is improved without further retrofitting specific units, such as ASUs or gasifiers, and unnecessary efficiency penalties can be avoided via flexible operation. This provides a new direction to solve the contradiction between variable load operation and performance degradation.
(3) In the long-term peak regulation process, the novel system can save more renewable energy over IGCC systems of the same power generation scale. When the energy saved in renewable energy is included in the CO2 emission intensity calculation, the CO2 emission intensity of the novel system is lower than that of the IGCC system.
(4) For a system with a power output of 300 MW, the required syngas storage tank capacity is only approximately 1872 m3 at 35 bar and 25 °C. Furthermore, the syngas storage tank investment accounts for only approximately 6.6% of the total investment cost.
By coupling the power generation unit and hydrogen production unit, the overall thermodynamic performance is improved, and by decoupling the dynamic characteristics of each unit, the overall dynamic performance is improved at the same time. To a certain extent, the method of decoupling and coupling can integrate energy systems to meet energy requirements in the future. In general, the system proposed in this paper can be operated more flexibly with low carbon emissions, and the method of integrating existing technologies to improve the dynamic performance can be of significance for the development of low-carbon energy systems in the future.
Abbreviations
Integrated gasification combined cycle
GT: Gas turbine
GTCC: Gas turbine combined cycle unit
ASU: Air separation unit
HRSG: Heat recovery steam generator
WGS: Water gas shift
P net, MW: Net electricity output
MH2, kg/s: Mass flow rate of hydrogen
I CO 2, g/kWh : CO2 emission intensity
M CO 2, kg/s: The CO2 emissions
E electricity, MW: Electrical energy generated
E saved, kWh: Energy saved in renewable energy
a, %/min: Load change rate of the unit
LHV: Low heating value
f, kg/s: Mass flow
CGE: Cold gas efficiency
M, kg: Mass of syngas in the storage tank
S : Scale of the equipment
CAPEX, M$: Capital expenditure
CEPCI: Chemical engineering plant cost index
PSA: Pressure swing adsorption
TCI, M$: Total capital investment
η, %: Efficiency
e: Electricity generated
g: Gasification unit
h: Hydrogen production
p: Power generating unit
i: The ith equipment of the system
r: Reference equipment
N: Scale factor
R: Syngas reserve
V: Vacant space
d: Design conditions
Aux: Auxiliary equipment
syn: Syngas
Authors’ Contributions
CWW: Investigation, Methodology, Resources, Writing—original draft, and Writing—review and editing; YBW: Investigation, Data curation, and Validation; LG: Writing—review and editing, Conceptualization, Methodology, and Supervision. The author(s) read and approved the final manuscript.
Funding
Open access funding provided by Shanghai Jiao Tong University. This work was funded by the Beijing Municipal Science and Technology Commission (No. Z211100004521006).
Availability of data and materials
The datasets used and/or analyzed in the current study are available from the corresponding author upon reasonable request.
Declarations
Ethics approval and consent to participate
Not applicable.
Consent for publication
All authors agree to the publication of this manuscript.
Competing interests
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.
Publisher’s Note
Springer Nature remains neutral with regard to jurisdictional claims in published maps and institutional affiliations.
