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A novel inlet air cooling system based on liquefied natural gas cold energy utilization for improving power plant performance
Energy Conversion and Management 187 (2019) 41–52
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Energy Conversion and Management journal homepage: www.elsevier.com/locate/enconman
A novel inlet air cooling system based on liquefied natural gas cold energy utilization for improving power plant performance
T
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Zuming Liua, Iftekhar A. Karimia, , Tianbiao Heb a b
Department of Chemical & Biomolecular Engineering, National University of Singapore, 4 Engineering Drive 4, 117585, Singapore Department of Gas Engineering, College of Pipeline and Civil Engineering, China University of Petroleum (East China), Qingdao 266580, China
A R T I C LE I N FO
A B S T R A C T
Keywords: Inlet air cooling Liquefied natural gas Power plant Off-design performance Optimization
The performance of gas turbine-based power plants decreases significantly as ambient temperature increases. For improving power plant performance, this paper proposes a novel inlet air cooling system based on liquefied natural gas cold energy utilization. The novel system consists of two organic Rankine cycles in series and a mechanical vapor compression chiller. A simulation-based optimization method is developed to optimize its design parameters for maximizing the power plant performance. Moreover, the off-design performances of the proposed system and the power plant with and without inlet air cooling are evaluated under different ambient conditions. The results show that the novel inlet air cooling system gives larger air temperature drop (2.1–5.3 °C) and higher cooling duty (6.9–7.3 MW) than a literature design. Furthermore, for 28–40 °C ambient temperatures, the power plant with the novel inlet air cooling produces 1.83–14.4% (6.4–52.6 MW) higher power output than that without inlet air cooling. Importantly, the novel cooling system improves the plant power output by 0.79–3.04% (2.8–11.1 MW) when compared with the literature design. Finally, the economic analysis shows that the proposed system is economically viable with a net present value of $1.6–34.4 million higher than the literature design.
1. Introduction Natural gas is now quickly replacing coal and oil as the preferred fossil fuel for power generation due to its cleaner nature and lower carbon emissions. Some countries like Singapore produce more than 96% of their electric power using natural gas [1]. Natural gas is normally condensed into liquid form, namely liquefied natural gas (LNG) for easy storage and long distance transportation. Before sent to the end-users, LNG has to be regasified (converting LNG to natural gas), which releases 830–860 kJ kg−1 cold energy in terms of −162 °C LNG temperature [2]. How to reasonably utilize this LNG cold energy is an important topic and has gained great scientific attention. LNG cold energy has been used for air separation, seawater desalination, dry ice production, and electric power generation. Since electric power is indispensable in modern society, constructing low-temperature power generation cycles using LNG as heat sink is being studied for LNG cold energy utilization. Querol et al. [3] proposed a combined cycle using a gas turbine and a pure ammonia organic Rankine cycle (ORC) coupled with LNG vaporization process in LNG terminals. Rao et al. [4] developed a combined cycle consisting of a low-temperature solar-driven ORC with LNG direct expansion for power generation.
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Corresponding author. E-mail address: [email protected] (I.A. Karimi).
https://doi.org/10.1016/j.enconman.2019.03.015 Received 23 November 2018; Accepted 8 March 2019 0196-8904/ © 2019 Elsevier Ltd. All rights reserved.
Ferreiro et al. [5] studied a new combined cycle composed of three ORCs using seawater and residual heat as heat sources and cold LNG as heat sink. Sun et al. [6] carried out process simulation and optimization for four schemes of power generation with and without LNG direct expansion. Xue et al. [7] proposed a three-stage ORC for LNG cold energy utilization and performed a stage-wise composition optimization for maximizing its performance. Kanbur et al. [8] presented a micro-cogeneration system combining a stirling engine and a micro gas turbine and found that their new system produced higher power output but lower carbon dioxide (CO2) emissions. Bao et al. [9] proposed a two-stage condensation combined cycle and showed that its net power output and efficiency were significantly higher than the conventional power generation cycles. Badami et al. [10] developed three combined cycles for power generation including ORC with single LNG direct expansion, ORC with LNG double expansion and reheating and regeneration, and parallel ORCs. Their results showed that the parallel ORCs produced higher specific power output. Gas turbine performance varies significantly with the ambient temperature [11]. Gas turbine power decreases by as much as 16.8% when the ambient temperature increases from 15 °C to 45 °C [12]. Hence, in hot weather, gas turbine power decreases significantly and
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Nomenclature
II
Symbols
Acronyms
ce cf LT m NPV P PR RH r T tax W Z
CAPEX CCGT CEPCI COMB COMP DESHT ECON EVAP GEN HP HPP HPST HRSG IACS IP IPP IPST LNG LP LPP LPST MTA NG OPEX ORC REVEN RHT RP SPHT TET TURB
electricity price, $/(kW h) fuel price, $/GJ lifetime, year mass flow rate, kg/s net present value, $ pressure, bar pressure ratio relative humidity interest rate temperature, K tax rate power, kW purchased-equipment cost, $
Greek letters
τ υ ψ
operating hours, h/year vapor fraction maintenance factor
Subscripts a c C1 C2 C3 cw f min I
air compressor methane ethylene propane cooling water fuel minimum ORC-I
ORC-II
capital expenditure combined cycle gas turbine Chemical Engineering Plant Cost Index combustor compressor desuperheater economizer evaporator generator high pressure high pressure pump high pressure steam turbine heat recovery steam generator inlet air cooling system intermediate pressure intermediate pressure pump intermediate pressure steam turbine liquefied natural gas low pressure low pressure pump low pressure steam turbine minimum temperature approach natural gas operating expenditure organic Rankine cycle revenue reheater recirculation pump superheater turbine exhaust temperature turbine
compressor inlet air cooling and found that the compressor inlet air temperature could be reduced by 4–25 °C while the gas turbine efficiency could be improved by 1.5–5%. Kim and Ro [22] analyzed the feasibility of using inlet air cooling by LNG cold energy from direct evaporation to improve power plant performance during warm seasons. They observed that the relative increase in plant power output reached 8% for dry air conditions (relative humidity lower than 30%) and 6% for normal humidity condition (60% relative humidity). Shi et al. [23] proposed an advanced power system in which LNG cold energy was directly utilized for compressor inlet air cooling, inter-cooling and steam condensation [24] to improve conventional combined cycle performance. Their results showed that the power output and thermal efficiency of the advanced power system were 76.8 MW and 2.8% higher than those of the conventional combined cycle. Kanhur et al. [25] studied a microturbine system with inlet air cooling by direct LNG evaporation and showed that the power output and thermal efficiency increased by 7.7% and 3.2%. Zhang et al. [26] developed a new process of utilizing LNG cold energy for gas turbine inlet air cooling to improve power plant performance. The process comprised a CO2 Rankine cycle and a CO2 compression-refrigeration system. They found that the plant power output increased by 1.6% and 11.6%, respectively, under 90% and 30% relative humidity. The above discussion showed that LNG cold energy was used for gas turbine inlet air cooling. The common option has been to cool down gas turbine inlet air via direct LNG evaporation [22–25]. This causes large cold exergy destruction as the maximum temperature approach reaches 184 °C and thus results in an inefficient LNG cold energy utilization. Some researchers [26] employed a CO2 Rankine cycle to recover LNG
gas turbine-based power plants may not meet the peak power demand. A solution is to use the electric power generated from LNG cold energy utilization to drive a mechanical vapor compression chiller for gas turbine inlet air cooling. In this way, gas turbine and power plant performance can be improved significantly. Alhazmy et al. [13] studied the effect of inlet air cooling on gas turbine performance under hot and humid conditions and showed that direct mechanical refrigeration increased gas turbine daily power by 6.77%. Al-Ansary et al. [14] analyzed the impact of a hybrid cooling system consisting of vapor compression cooling and evaporative cooling on gas turbine performance in arid climates. Their hybrid system was capable of boosting gas turbine power by more than 10% with good economic performance. Mohapatra and Sanjay [15] integrated a vapor compression chiller into a gas turbine combined cycle and observed that gas turbine efficiency and combined cycle power increased by 4.88% and 14.77%, respectively. Comodi et al. [16] applied vapor compression cooling to enhance micro gas turbine performance in hot climates and found that the power output and efficiency improved by 8% and 1.5%, respectively, when the inlet air was cooled down to 15 °C. Baakeem et al. [17] studied several prevailing inlet air cooling technologies for a gas turbine and found that multi-stage vapor compression system with cooling tower had better energy and economic performance. Moreover, gas refrigeration system [18] and earth-to-air heat exchanger [19] for inlet air cooling improved gas turbine performance. Several works have utilized LNG cold energy for compressor inlet air cooling and inter-cooling and steam condensation. Farzaneh-Gord and Deymi-Dashtebayaz [20,21] proposed a new approach to utilize the potential cooling capacity from natural gas pressure reduction for 42
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(counter-flow heat exchanger) via Pump-1. The ORC-I working fluid enters a multi-steam heat exchanger (HEX-1) after exchanging heat with the ORC-II working fluid in Condenser-2. The ORC-II working fluid is condensed by the ORC-I working fluid in Condenser-2 and then pumped to HEX-1 via Pump-2. The pressurized working fluids in ORC-I and ORC-II exchange heat with the hot air in HEX-1 and then expand in Turbine-1 and Turbine-2, respectively. The exhaust vapor from Turbine-1 and Turbine-2 then returns to their respective condensers. The power generated by Turbine-1 and Turbine-2 is used to drive LNG Pump, Pump-1 and Pump-2, and Compressor in the mechanical vapor compression chiller. The compressed working fluid is cooled by cooling water in Cooler and then passes through a throttling valve (Valve), where its pressure is reduced to produce a desired cooling temperature. The cold fluid from Valve and the LNG from Condenser-1 enters a multistream heat exchanger (HEX-2) and further exchange heat with the air from HEX-1. The air from HEX-2 then enters a knock-out drum (Drum), where the condensed water is drained. Finally, the cooled air and natural gas (NG) are supplied to a triple-pressure reheat combined cycle gas turbine (CCGT) power plant, as shown in Fig. 2. The novel IACS can be deployed very close to or within the air-filter house supplying air to the power plant. If it is near the air-filter house, then no equipment changes are required in the power plant. If it is in the air-filter house, then the air-filter house must be enlarged to accommodate the extra equipment. This upgrade is minor with limited investment, because only steel, bricks, and concrete are needed. The CCGT plant comprises a compressor (COMP), a combustor (COMB), a turbine (TURB), a triple-pressure reheat heat recovery steam generator (HRSG), three steam turbines (HPST, IPST, and LPST), four water pumps (HPP, IPP, LPP, and RP), and two generators (GEN). The cooled air compressed in COMP enters COMB, where natural gas as a fuel is burnt. The hot gas from COMB expands in TURB to produce power. The exhaust gas from TURB passes through HRSG before being vented as flue gas. The HRSG comprises three steam generation subsystems: high-pressure (HP), intermediate-pressure (IP), and low-pressure (LP). Each subsystem has one feed water pump, one or more economizers, one evaporator, and one or more superheaters. The feed water from each pump is preheated in the economizers, boiled in the
cold energy for gas turbine inlet air cooling; however, CO2 could hardly match LNG temperature profile during evaporation, and the maximum temperature approach between CO2 and LNG still reached 100 °C. Hence, more efficient ways of utilizing LNG cold energy should be explored for gas turbine inlet air cooling. Moreover, installing LNG coldbased inlet air cooling in power plants incurs extra capital and operating expenditures. Thus, a proper economic analysis lacking in the literature is necessary to justify its installation. In this paper, a novel inlet air cooling system (IACS) based on LNG cold energy utilization is proposed for improving power plant performance. The IACS comprises two mixed working fluid ORCs in series and a mechanical vapor compression chiller. Compared with the existing LNG cold energy utilization for gas turbine inlet air cooling, the innovations of the proposed IACS are summarized as follows: (1) Two mixed working fluid ORCs are installed between gas turbine inlet air and LNG to utilize their temperature potential for power generation. The mixed working fluid can match LNG temperature profile well, and hence the temperature approach between mixed working fluid and LNG is small and LNG cold energy is efficiently utilized. (2) The mechanical vapor compression chiller driven by the power generated from ORCs can significantly increase the IACS cooling duty in comparison with direct LNG evaporation. (3) A simulation-based optimization method is developed to fine tune the IACS design parameters for maximizing plant performance. (4) An economic analysis is presented to justify the IACS installation under different plant lifetime. The remainder of this paper is organized as follows. A description of the novel IACS and power plant is first presented. Then, the detailed methodology is given. Next, results and discussion are presented. Finally, conclusions are drawn.
2. Novel inlet air cooling system and combined cycle gas turbine power plant The novel IACS is illustrated in Fig. 1. The system comprises two organic Rankine cycles (ORC-I and ORC-II) and a mechanical vapor compression chiller. LNG is pressurized by LNG Pump and then sent to Condenser-1 (counter-flow heat exchanger). The ORC-I working fluid is condensed by LNG in Condenser-1 and pumped to Condenser-2
Fig. 1. Schematic of the novel inlet air cooling system. 43
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Fig. 2. Schematic of the triple-pressure reheat CCGT power plant with inlet air cooling.
the working fluid for the vapor compression chiller. The Peng-Robinson fluid package is used for air and LNG, while the NIST REFPROP database is adopted for organic working fluids. The assumptions for IACS simulation are presented in Table 2 [26]. The isentropic efficiencies of the pumps, compressors, and turbines are set to commercially reasonable values of 80%, 85%, and 90%, respectively. The pressure losses for air, LNG, and organic working fluids in the heat exchangers are assumed to be 0.5%, 5.0%, and 5.0% respectively of their inlet pressures. Moreover, 5.0 °C is taken as the minimum temperature approach (MTA) for all heat exchangers to avoid excessively large heat transfer areas.
evaporator, and superheated in the superheaters. Two reheaters (RHT1 and RHT2) are located between the HP superheaters. Moreover, two desuperheaters (DESHT1 and DESHT2) in the middle of HP superheaters and reheaters moderate the temperatures of HP steam and reheat steam via injecting water for safe operation. A recirculation pump (RP) recycles some hot water from the LP economizer exit back as its feed to prevent low-temperature corrosion. The HP steam expands in HPST and mixes with the IP steam. The mixed steam enters the reheaters and then expands in IPST. The exhaust steam from IPST mixes with the LP steam and enters LPST. After expansion, the exhaust steam from LPST goes to a condenser, and the condensate is pumped back to the LP economizer.
3.2. Combined cycle power plant simulation 3. Methods The CCGT plant is simulated in Aspen HYSYS. Detailed simulation descriptions for the CCGT plant can be found in Liu and Karimi [28]. The design parameters and performance of the CCGT plant are shown in Table 3 [28–30]. In this paper, the focus is on studying the full-load operation of the CCGT plant with inlet air cooling under different ambient conditions. The full-load operation implies that the compressor inlet guide vanes remain fully open while the turbine inlet temperature is maintained at its design value. Moreover, since the cooling water temperature is usually affected by the ambient temperature, the change in ambient temperature has a great impact on the condenser operation. To account for the impact of ambient temperature on the condenser operation, the cooling water temperature (Tcw ) is assumed to be linearly proportional to the ambient temperature (Ta ) as follows.
This section aims to obtain a novel IACS for improving power plant performance and justify the IACS economic viability, and comprises inlet air cooling system and combined cycle power plant simulation, a simulation-based optimization, and an economic analysis as follows. 3.1. Inlet air cooling system simulation The IACS is simulated in Aspen HYSYS [27]. In order to fully utilize LNG cold energy, proper working fluids should be employed for ORC-I and ORC-II. Since single working fluid normally results in large temperature approach in the condensers, it is necessary to consider mixed working fluid for achieving better temperature matching by utilizing its temperature characteristic in two-phase region. The selection of mixed working fluid for ORC-I and ORC-II depends on LNG temperature, air temperature, as well as boiling and critical temperatures of the potential components of the working fluid. Hence, in this paper, a mixed working fluid comprising methane, ethylene, and propane is used for ORC-I and ORC-II after a careful investigation, and the mass flow rates of the three components are tuned to achieve optimal temperature matching. Table 1 shows the thermodynamic properties of the mixed working fluid for ORC-I and ORC-II. Moreover, R134a is employed as
Table 1 Mixed working fluid for ORC-I and ORC-II.
44
Name
Critical pressure (bar)
Critical temperature (°C)
Normal boiling temperature (°C)
Notation
Methane Ethylene Propane
46.0 50.4 42.5
−82.7 9.2 96.8
−161.6 −103.9 −42.1
C1 C2 C3
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stated as the following optimization problem.
Table 2 Assumptions for IACS simulation [26].
maxWCCGT (P2, P5, mC1, I , mC 2, I , mC3, I , P7, P9, mC1, II , mC 2, II , mC3, II , PR c )
Air pressure loss in heat exchanger (%)
0.5
LNG pressure loss in heat exchanger (%) Organic fluid pressure loss in heat exchanger (%) Minimum temperature approach (°C) Pump isentropic efficiency (%) Compressor isentropic efficiency (%) Compressor mechanical efficiency (%) Turbine isentropic efficiency (%) Generator efficiency (%)
5.0 5.0 5.0 80.0 85.0 99.0 90.0 98.5
(2) The following constraints have to be enforced during optimization.
• The minimum temperature approaches (MTAs) in Condenser-1 and Condenser-2 should be larger than 5 °C.
(3)
ΔTmin ⩾ 5 °C
• There should be no liquid in the inlet streams of Turbine-1 and Turbine-2.
Table 3 Design parameters and performance of the CCGT plant. Parameter/variable
Value
Gas turbine Air pressure (kPa) Air temperature (°C) Inlet air flow (kg s−1) Inlet air pressure loss (%) Compressor pressure ratio Compressor isentropic efficiency (%) Compressor mechanical efficiency (%) Fuel flow (kg s−1) Combustor efficiency (%) Combustor pressure loss (%) Combustor exit temperature (°C) Turbine inlet temperature (°C) Turbine exhaust temperature (°C)
101.3 15.0 635.0 0.5 15.4 88.0 99.0 14.74 99.5 3.5 1405.0 1328.0 615.0
Heat recovery steam generator (HRSG) HP/IP/LP steam temperatures (°C) HP/IP/LP pinch point temperatures (°C) HP/IP/LP approach point temperatures (°C) HP SPHT 1 steam outlet temperature (°C) RHT 1/2 steam outlet temperature (°C) HP ECON 1/2 water outlet temperature (°C) Pressure losses on gas/water/steam sides (%)
565.0/297.0/295.0 10.0/10.0/10.0 8.0/10.0/16.4 510.0 520.0/565.0 208.0/280.0 1.5/5.0/3.0
Steam turbines (STs) HP/IP/LP ST inlet pressure (bar) HP/IP/LP ST isentropic efficiency (%)
98.8/24.0/4.0 87.0/91.0/89.0
Condenser Pressure (kPa) Cooling water temperature (°C) Cooling water temperature rise (°C)
7.4 25.0 10.0
Generator Generator efficiency (%) Shaft speed (rpm)
98.5 3000
CCGT performance Gas turbine power (MW) Gas turbine efficiency (%) Steam cycle power (MW) Plant net power (MW) Plant efficiency (%)
253.2 36.17 139.8 393.0 56.14
Tcw = 0.375Ta + 17
υ4 ⩾ 1
(4)
υ8 ⩾ 1
(5)
• The turbine exhaust vapor fraction should be higher than 0.9 to avoid turbine blade erosion.
υ5 ⩾ 0.9
(6)
υ9 ⩾ 0.9
(7)
A simulation-based optimization method shown in Fig. 3 is developed to maximize the plant power output. The IACS and CCGT plant are simulated in Aspen HYSYS, while the optimization is performed in MATLAB [31] using Nonlinear Optimization by Mesh Adaptive Direct Search (NOMAD) algorithm [32,33] from OPTI Toolbox [34]. NOMAD is a global optimizer and thus gives us better confidence in optimal solutions. MATLAB is interfaced with Aspen HYSYS via ActiveX for direct two-way communication. The decision variables (design parameters of IACS) are initialized in MATLAB and then passed to Aspen HYSYS for simulation. If Aspen HYSYS simulation converges, the results are sent back to MATLAB for evaluating the penalties of constraint violations along with objective function. NOMAD terminates when the termination conditions are satisfied. Otherwise, NOMAD updates the decision variables, and the optimization continues. 3.4. Economic analysis An economic analysis is necessary to demonstrate the economic viability of installing the novel IACS in the CCGT plant. The parameters and cost functions for the IACS economic analysis are shown in Table 4 [35]. Net present value (NPV) is used as the economic indicator and computed as follows: LT
NPV = −CAPEX +
∑ t=1
(REVEN − OPEX ) × (1 − tax ) (1 + r )t
(8)
M
CEPCI2016 ⎛ ⎞ × 1.2 × ⎜∑ Zi⎟ CEPCIbase = i 1 ⎝ ⎠
(9)
OPEX = τ × cf × Δmf + ψ × CAPEX
(10)
REVEN = τ × ce × ΔWCCGT
(11)
CAPEX =
(1)
where, CAPEX is the capital expenditure for the IACS, OPEX and REVEN are the extra operating expenditure and revenue due to IACS installation, ΔWCCGT and Δmf are the changes in the plant power output and fuel flow, ce and cf are the prices of electricity and fuel, ψ is the maintenance factor, τ is the plant annual operating hours, tax is the tax rate, r is the interest rate, LT is the remaining plant lifetime, CEPCI is the Chemical Engineering Plant Cost Index (base = 2001), and Z is the purchased-equipment cost.
3.3. Simulation-based optimization The power output of the CCGT plant under full-load condition decreases significantly in hot weather. The IACS utilizes LNG cold energy to cool down the gas turbine inlet air so that the plant can produce more power in hot weather. The increase in the plant power output depends on the IACS design. Hence, various IACS design parameters [pump outlet pressures (P2 and P7 ), turbine outlet pressures (P5 and P9 ), mass flow rates of methane, ethylene, and propane (mC1, I , mC 2, I , and mC 3, I ) in ORC-I, mass flow rates of methane, ethylene, and propane (mC1, II , mC 2, II , and mC 3, II ) in ORC-II, and compressor pressure ratio (PR c )] need to be optimized for maximizing the plant power output. This can be
4. Results and discussion The IACS design parameters are determined by simulation-based 45
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Fig. 3. Simulation-based optimization using NOMAD.
326.3 kW K−1, 363.6 kW K−1, and 130.2 kW K−1, respectively. The various stream parameters of the IACS under Ta = 40 °C and RH = 90% are shown in Table 6. The air (592.1 kg s−1) is cooled down to 32.2 °C in the IACS and then sent to the CCGT plant via Drum. The performance of the CCGT plant with and without inlet air cooling is shown in Table 7. The CCGT plant with the novel inlet air cooling produces higher gas turbine power and efficiency, but slightly lower steam cycle power and efficiency. Moreover, the novel inlet air cooling increases the plant power output significantly but decreases the plant efficiency slightly. Fig. 4 illustrates the hot and cold composite curves in Condenser-1 and Condenser-2. Obviously, the hot composite curve is close to the cold composite curve. Moreover, the minimum and maximum
optimization under a harsh ambient condition (Ta = 40 °C, RH = 90%), and their optimal values are shown in Table 5. The mass flow rates of methane, ethylene, and propane in ORC-I (ORC-II) are 1.41 kg s−1 (1.22 kg s−1), 7.80 kg s−1 (5.78 kg s−1), and 5.30 kg s−1 (5.58 kg s−1), respectively. The optimal pressure ratio for the compressor in the vapor compression chiller is 4.10. LNG (13.64 kg s−1) is pressurized to 30.0 bar by LNG Pump to condense ORC-I working fluid in Condenser1. The ORC-I (ORC-II) working fluid from Condenser-1 (Condenser-2) is pumped to 13.62 bar (31.29 bar) via Pump-1 (Pump-2) and then expands to 2.46 bar (8.03 bar) in Turbine-1 (Turbine-2). Moreover, R134a from Cooler is depressurized by Valve to 3.0 bar to produce a cooling temperature of 0.7 °C. The UA values for Condenser-1, Condenser-2, HEX-1, HEX-2, and Cooler are 710.7 kW K−1, 796.3 kW K−1, 46
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Table 4 Parameters and cost functions for economic analysis [35]. Parameters and cost functions
ce ($/(kW h)) cf ($ GJ−1) r (%) ψ (%) tax (%) τ (h/year) Pump ($) Compressor ($)
0.15 8.6 10 10 20 8000
1120W 0.8 71.1min (1/(0.91 − ηc )) PR c ln(PR c )
Turbine ($)
4405W 0.7
Heat exchangera ($)
2681A0.59
Condensera ($)
2143A0.514
a
U = 0.7kW/(m2K) is used for heat transfer area calculation.
Table 5 IACS optimal design (Ta = 40 °C, RH = 90%) .
parameters
and
lower
and
upper
bounds
Variable
Optimal value
Lower bound
Upper bound
P2 (bar) P5 (bar) mC1, I (kg s−1) mC 2, I (kg s−1) mC 3, I (kg s−1) P7 (bar) P9 (bar) mC1, II (kg s−1) mC 2, II (kg s−1) mC 3, II (kg s−1) PR c
13.62 2.46 1.41 7.80 5.30 31.29 8.03 1.22 5.78 5.58 4.10
11.0 1.5 1.0 6.0 4.0 26.0 7.0 1.0 4.0 4.0 3.0
18.0 3.0 3.0 9.0 7.0 35.0 9.0 4.0 8.0 8.0 6.0
Table 6 Stream parameters of the novel IACS (Ta = 40 °C, RH = 90%) . Stream no.
Mass flow rate kg s−1
Pressure bar
Temperature °C
Vapor fraction –
1 2 3 4 5 6 7 8 9 10 11 12 13 LNG NG Air Cooled air
14.51 14.51 14.51 14.51 14.51 12.58 12.58 12.58 12.58 52.5 52.5 52.5 52.5 13.64 13.64 592.1 584.9
2.34 13.62 12.94 12.29 2.46 7.63 31.29 29.73 8.03 2.85 11.70 11.11 3.00 1.013 27.07 1.013 1.003
−125.6 −125.2 −28.4 35.0 −39.3 −92.4 −92.2 35.0 −19.9 30.6 85.9 37.0 0.7 −165.5 10.0 40.0 32.2
0.0 0.0 0.68 1.0 1.0 0.0 0.0 1.0 0.95 1.0 1.0 0.0 0.26 0.0 1.0 1.0 1.0
Fig. 4. Hot and cold composite curves in Conderser-1 (a) and Condenser-2 (b).
Table 7 Performance of the CCGT plant (Ta = 40 °C, RH = 90%) . CCGT performance
No inlet air cooling
With inlet air cooling
Gas turbine power (MW) Gas turbine efficiency (%) Steam cycle power (MW) Steam cycle efficiency (%) Plant net power (MW) Plant efficiency (%)
217.3 34.17 133.9 30.12 351.2 55.20
224.0 34.57 133.6 30.06 357.6 55.18
Fig. 5. Exergy loss of each component in the IACS.
temperature approaches in Condenser-1 (Condenser-2) are 5.0 °C (5.0 °C) and 38.6 °C (32.8 °C), respectively. This implies low exergy losses in the condensers, as shown in Fig. 5. The exergy losses in water cooler, compressor and pumps, and throttling valve are very low and account for only 11.81% of the total exergy loss. Since the hot and cold composite curves are well matched, the exergy losses in the condensers and multi-stream heat exchangers are 25.54% and 22.09%,
47
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increase of the air relative humidity, more and more cooling duty is required for condensing the water vapor, leading to a gradual decrease of the air temperature drop in the IACS. For a given relative humidity, hotter air contains more water vapor. Hence, as the ambient temperature decreases, the air temperature drop in the IACS increases. Fig. 10 presents the cooling duty of the IACS under different ambient conditions. The cooling duty of the novel IACS is significantly higher than Ref. [26]. For 30–90% relative humidity, the differences in cooling duty between the novel IACS and Ref. [26] range from 7.0 MW (7.0 MW) to 7.3 MW (6.9 MW) when the ambient temperature is 40 °C (28 °C). This proves that the novel design utilizes LNG cold energy more efficiently. Moreover, the IACS is more sensitive to the ambient temperature than the relative humidity. As the ambient temperature decreases, the cooling duty of the IACS increases significantly. The reason is that the air mass flow increases with the decrease of the ambient temperature, thus incurring an increase in the fuel flow to maintain fullload operation. The latter directly results in an increase in the cooling duty. However, the cooling duty decreases slightly with the increase of the relative humidity. This is mainly because the fuel flow reduces when the relative humidity increases.
respectively. The ORC turbines are the most significant exergy loss contributors with 40.56% exergy losses. The reason is that the operating conditions of the ORC turbines (high pressure and low temperature) are away from the ambient conditions. 4.1. Parametric study on inlet air cooling system A parametric study is performed to evaluate the effects of the key design parameters on the IACS performance. Since methane, ethylene, and propane flow rates have similar effects on the performance, for brevity, this paper presents the effects of the working fluid flows in ORC-I and ORC-II as shown in Fig. 6, where the fluid composition is kept unchanged. Because HEX-1 duty and Turbine-1 (Turbine-2) power output increase with the ORC-I (ORC-II) working fluid flow, the cooling duty increases. The latter enables the vapor compression chiller to produce more refrigeration energy for air cooling in HEX-2. Moreover, as the ORC-I (ORC-II) working fluid flow increases, the MTA in Condenser-2 increases (decreases), since the ORC-I working fluid is able (unable) to provide sufficient cold energy for condensing the ORC-II working fluid. Furthermore, the MTA in Condenser-1 decreases with the increase of the ORC-I working fluid flow because of the inadequate LNG cold energy for condensation. However, the MTA in Condenser-1 remains unchanged regardless of the ORC-II working fluid flow, because its variation does not affect Condenser-1 operation. Fig. 7 illustrates the effects of pump and turbine outlet pressures on the IACS performance. As P2 (P5) and P7 (P9 ) increase (decrease), the power output of ORC-I and ORC-II increases (decreases), which directly causes an increase (decrease) in the cooling duty. The cooling duty first increases significantly, and then decreases slightly with the compressor pressure ratio, as presented in Fig. 8. Since the performance of ORC-I and ORC-II is not affected by the compressor in the vapor compression chiller, HEX-1 duty and the power output of the ORC turbines remain unchanged. Hence, the cooling duty only depends on the liquid-phase refrigerant flow in the vapor compression chiller. Fig. 7 shows that flow versus the compressor pressure ratio. This explains well why the cooling duty increases first and decrease later with the compressor pressure ratio.
4.3. Performance of combined cycle power plant with inlet air cooling Figs. 11–15 show how the performance of the CCGT plant with inlet air cooling changes under different ambient conditions. The performance parameters in Figs. 11–15 are normalized by the corresponding ones of the CCGT plant without inlet air cooling.
4.2. Performance comparison of inlet air cooling systems Zhang et al. [26] proposed an IACS using LNG cold energy to improve power plant performance. They compared their design with Kim and Ro [22] and showed that their IACS improved the plant power output and efficiency by 2.47% and 0.11%, respectively. In this paper, the novel IACS is compared with Ref. [26] under different ambient conditions to demonstrate its advantages. For this, the IACS from Ref. [26] is integrated with the CCGT plant shown in Fig. 2. Fig. 9 shows the air temperature drops in the IACS under different ambient conditions. Clearly, the novel IACS gives larger air temperature drops under all ambient conditions. For 30–90% relative humidity, the air temperature drops from the novel IACS are 3.7–2.1 °C (5.3–3.4 °C) larger than those from Ref. [26] when the ambient temperature is 40 °C (28 °C). This mainly results from the higher cooling duty of the novel IACS, as shown in Fig. 10. The cooling duty contains the sensible heat of the air and the latent heat of the water vapor. As a result, the air relative humidity has a great impact on the air temperature drop in the IACS. The air temperature drop in the IACS decreases significantly with the increase of the air relative humidity as can be seen in Fig. 9. For low relative humidity (e.g. 30%), the cooling duty is mainly used to reduce the sensible heat of the air, and thus the air temperature drop in the IACS is large. For high relative humidity (e.g. 90%), the water vapor in the air condenses in the course of heat exchange process, and the cooling duty is mainly used to condense the water vapor. Hence, the air temperature drop in the IACS becomes small. On the other hand, for a given ambient temperature (e.g. 40 °C or 28 °C), the water vapor in the air increases as the air relative humidity increases. Thus, with the
Fig. 6. Effects of working fluid flows in ORC-I (a) and ORC-II (b) on the IACS performance. 48
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Fig. 9. Air temperature drop in the IACS under different ambient conditions.
Fig. 7. Effects of pump and turbine outlet pressures on the IACS performance.
Fig. 10. IACS cooling duty under different ambient conditions.
Fig. 8. Effect of compressor pressure ratio on the IACS performance.
4.3.1. Gas turbine performance The gas turbine air mass flow under different ambient conditions is shown in Fig. 11. For 28–40 °C ambient temperatures, the air mass flow is 2.50–1.68% (1.44–0.91%) higher than Ref. [26] when the relative humidity is 30% (90%). This results from the larger air temperature drop (namely lower compressor inlet air temperature) in the novel
Fig. 11. Gas turbine air mass flow under different ambient conditions.
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Fig. 12. Turbine exhaust temperature (TET) under different ambient conditions.
Fig. 14. Steam cycle power (a) and efficiency (b) under different ambient conditions.
temperature constant at its design value. Hence, the fuel flow is 3.04–1.90% (1.57–0.76%) higher than Ref. [26] under the relative humidity of 30% (90%). Moreover, the higher air mass flow and constant turbine inlet air temperature render the pressure ratio 2.35–1.48% (1.28–0.67%) higher than Ref. [26]. The trends for the fuel flow and pressure ratio are similar to the air mass flow in Fig. 11. Because of the higher pressure ratio, the TET is 0.78–0.55% (0.52–0.34%) lower than Ref. [26] under 30% (90%) relative humidity, as shown in Fig. 12. Fig. 13 illustrates the gas turbine power and efficiency under different ambient conditions. For 28–40 °C ambient temperatures, the gas turbine power of the novel combined cycle is 4.42–2.92% and 2.37–1.26% higher than Ref. [26] under the relative humidity of 30% and 90%, respectively. This is because the novel IACS causes a lower compressor inlet air temperature, which leads to a higher air mass flow, fuel flow, and compressor pressure ratio. The lower compressor inlet air temperature reduces the compressor power consumption. Meanwhile, the higher compressor pressure ratio enables the turbine to expand to a lower TET, augmenting the turbine power output. Hence, the novel combined cycle produces a higher gas turbine power. Because of the higher gas turbine power of the novel combined cycle, the gas turbine efficiency is 1.09–0.84% (0.74–0.48%) higher than Ref. [26] under 30% (90%) relative humidity. Hence, it can be concluded from Fig. 13 that the inlet air cooling can significantly improve gas turbine performance. Moreover, the lower the compressor inlet air temperature, the higher the gas turbine performance.
Fig. 13. Gas turbine power (a) and efficiency (b) under different ambient conditions.
IACS, as illustrated in Fig. 9. Lower compressor inlet air temperature means higher inlet air density and hence higher air mass flow in the novel combined cycle (the CCGT plant with the novel inlet air cooling). A lower compressor inlet air temperature along with a higher air mass flow requires a higher fuel flow to maintain the turbine inlet
4.3.2. Steam cycle performance Fig. 14 presents the steam cycle power and efficiency under 50
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Table 8 Detailed economic performance under Singapore and Riyadh weather conditions. Economic performance
Singapore
Riyadh
Novel
Ref. [26]
Novel
Ref. [26]
Δmf (kg s−1)
0.64
0.45
1.66
1.41
ΔWCCGT (MW) CAPEX (million $) OPEX (million $ year−1) REVEN (million $ year−1)
17.1 3.51 7.90 20.53
11.63 2.06 5.46 13.95
44.70 3.51 19.88 53.63
37.72 2.06 16.77 45.26
efficiency under 90% relative humidity increases; however, the plant efficiency under 30% relative humidity decreases. The main reason for the latter is that under low relative humidity, the high gas turbine efficiency that results from inlet air cooling cannot compensate the low steam cycle efficiency. Hence, from Fig. 15, it can be concluded that the inlet air cooling improves the plant power output rather than the plant efficiency. 4.4. Economic performance To evaluating the IACS economic performance, the CCGT plant is considered at two locations: Singapore (Ta = 32 °C, RH = 80%) and Riyadh, Saudi Arabia (Ta = 40 °C, RH = 30%) A new CCGT plant is assumed to have a full lifetime of 20 years; hence, the remaining lifetime of an existing plant varies from 1 year to 20 years, namely 1 ⩽ LT ⩽ 20 The detailed economic performances under Singapore and Riyadh weather conditions are presented in Table 8. The capital expenditures of the novel IACS and Ref. [26] are $3.51 million and $2.06 million, respectively. Moreover, the novel IACS incurs a larger increase in fuel flow and power output than Ref. [26]. As a result, the operating expenditure and revenue of the novel IACS are higher than Ref. [26]. Although the novel IACS has higher capital and operating expenditures, the higher revenue from the novel IACS makes its NPV higher than Ref. [26], as shown in Fig. 16. Fig. 16 presents the NPV for installing the IACS under different plant lifetimes. Clearly, the ambient conditions (temperature and relative humidity) and the remaining plant lifetime have a significant effect on NPV. The lower the ambient relative humidity, the higher the ambient temperature; and the longer the remaining plant lifetime, the higher the NPV. Moreover, the NPV is always positive, which indicates that installing the novel IACS in CCGT plants is economically viable.
Fig. 15. Plant power (a) and efficiency (b) under different ambient conditions.
different ambient conditions. The steam cycle power of the novel combined cycle is 0.67–0.44% and 0.39–0.05% higher than Ref. [26] for 28–40 °C ambient temperatures under 30% and 90% relative humidity. The reason is that the novel combined cycle has a higher turbine exhaust flow, which enables the HRSG to produce more steam for power generation in the steam turbines. However, its steam cycle efficiency is lower than Ref. [26]. For 28–40 °C ambient temperatures, the steam cycle efficiency of the novel combined cycle is 0.56–0.22% and 0.17–0.09% lower than Ref. [26] under the relative humidity of 30% and 90%, respectively. This mainly results from the lower TET, which reduces the heat recovery from the turbine exhaust gas. Moreover, under low relative humidity (e.g. 30%), the low TET decreases the temperatures of HP steam and reheat steam. Consequently, the steam cycle efficiency under 30% relative humidity declines more rapidly than that under 90% relative humidity. Fig. 14 indicates that the inlet air cooling is advantageous for increasing steam cycle power, but disadvantageous for improving steam cycle efficiency. 4.3.3. Power plant performance The plant power output and efficiency under different ambient conditions are shown in Fig. 15. The power output of the novel combined cycle is 3.04–2.00% and 1.64–0.79% higher than Ref. [26] for 28–40 °C ambient temperatures when the relative humidity is 30% and 90%, respectively. This is because the gas turbine power and steam cycle power are augmented by the novel IACS. Moreover, with the decrease of the ambient temperature, the difference in the plant power output between the novel combined cycle and Ref. [26] increases due to the larger air temperature drop in the novel IACS. The plant efficiency is 0.01–0.07% and 0.06–0.04% higher than Ref. [26] under 30% and 90% relative humidity. As the ambient temperature decreases, the plant
Fig. 16. NPV for IACS installation under Singapore and Riyadh weather conditions. 51
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Aspen HYSYS and MATLAB under academic licenses provided to the National University of Singapore.
Furthermore, the NPV of the novel IACS is always higher than Ref. [26] under Singapore and Riyadh weather conditions. In Singapore, the novel IACS has an NPV of $1.6 million to $26.7 million higher than Ref. [26]. In Riyadh, it gives $2.4 million to $34.4 million more NPV than Ref. [26]. Hence, the novel IACS is economically more viable than Ref. [26]. Overall, the inlet air cooling is beneficial for improving the gas turbine power and efficiency, since it can reduce the compressor power consumption and increase the turbine power output. Moreover, it increases the steam cycle power owing to the higher turbine exhaust flow, but decreases the steam cycle efficiency due to the lower TET. By applying the novel inlet air cooling, the CCGT plant considered in this paper produces 1.83–14.4% (6.4–52.6 MW) higher power output. Furthermore, the novel IACS improves the plant power output by 0.79–3.04% (2.8–11.1 MW) when compared with Ref. [26]. However, the thermal efficiency of the CCGT plant remains nearly unchanged with inlet air cooling. Finally, the novel IACS is proved to be economically viable with an NPV of $1.6–34.4 million higher than Ref. [26] under various ambient conditions.
References [1] SLNG. Singapore LNG Corporation. https://wwwslngcomsg/website/indexaspx; 2018. [2] Zhang M-G, Zhao L-J, Liu C, Cai Y-L, Xie X-M. A combined system utilizing LNG and lowtemperature waste heat energy. Appl Therm Eng 2016;101:525–36. [3] Querol E, Gonzalez-Regueral B, García-Torrent J, Ramos A. Available power generation cycles to be coupled with the liquid natural gas (LNG) vaporization process in a Spanish LNG terminal. Appl Energy 2011;88:2382–90. [4] Rao W-J, Zhao L-J, Liu C, Zhang M-G. A combined cycle utilizing LNG and low-temperature solar energy. Appl Therm Eng 2013;60:51–60. [5] Ferreiro García R, Carbia Carril J, Romero Gomez J, Romero Gomez M. Power plant based on three series Rankine cycles combined with a direct expander using LNG cold as heat sink. Energy Convers Manage 2015;101:285–94. [6] Sun Z, Xu F, Wang S, Lai J, Lin K. Comparative study of Rankine cycle configurations utilizing LNG cold energy under different NG distribution pressures. 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[18] Najjar YSH, Abubaker AM, El-Khalil AFS. Novel inlet air cooling with gas turbine engines using cascaded waste-heat recovery for green sustainable energy. Energy 2015;93:770–85. [19] Barakat S, Ramzy A, Hamed AM, El Emam SH. Enhancement of gas turbine power output using earth to air heat exchanger (EAHE) cooling system. Energy Convers Manage 2016;111:137–46. [20] Farzaneh-Gord M, Deymi-Dashtebayaz M. A new approach for enhancing performance of a gas turbine (case study: Khangiran refinery). Appl Energy 2009;86:2750–9. [21] Farzaneh-Gord M, Deymi-Dashtebayaz M. Effect of various inlet air cooling methods on gas turbine performance. Energy 2011;36:1196–205. [22] Kim TS, Ro ST. Power augmentation of combined cycle power plants using LNG cold energy. Energy 2000;25:841–56. [23] Shi X, Agnew B, Che D, Gao J. Performance enhancement of conventional combined cycle power plant by inlet air cooling, inter-cooling and LNG cold energy utilization. Appl Therm Eng 2010;30:2003–10. [24] Stradioto DA, Seelig MF, Schneider PS. Performance analysis of a CCGT power plant integrated to a LNG regasification process. J Nat Gas Sci Eng 2015;27:18–22. [25] Kanbur BB, Xiang L, Dubey S, Choo FH, Duan F. Life cycle-based enviroeconomic and thermal analyses of the inlet air-cooled microturbine systems with liquefied natural gas cold energy. J Cleaner Prod 2018;174:1338–50. [26] Zhang G, Zheng J, Yang Y, Liu W. A novel LNG cryogenic energy utilization method for inlet air cooling to improve the performance of combined cycle. Appl Energy 2016;179:638–49. [27] Aspen HYSYS V9. www.aspentech.com; 2017. [28] Liu Z, Karimi IA. Simulating combined cycle gas turbine power plants in Aspen HYSYS. Energy Convers Manage 2018;171:1213–25. [29] Liu Z, Karimi IA. Simulation and optimization of a combined cycle gas turbine power plant for part-load opeartion. Chem Eng Res Des 2018;131:29–40. [30] Liu Z, Karimi IA. New operating strategy for a combined cycle gas turbine power plant. 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5. Conclusions A novel IACS based on LNG cold energy utilization was proposed in this paper for improving power plant performance. The system recovers LNG cold energy via organic Rankine cycles to produce power for driving a mechanical vapor compression chiller. A simulation-based optimization method was developed to optimize the novel IACS for maximizing the plant performance. A parametric study was performed to evaluate the effects of the key design parameters on the IACS performance. The performance of the CCGT plant with and without inlet air cooling was evaluated under different ambient conditions. Moreover, an economic analysis was performed to justify the IACS installation. The main conclusions were summarized as follows: (1) The proposed novel IACS utilized LNG cold energy more efficiently and thus produced 6.9–7.3 MW higher cooling duty and achieved 2.1–5.3 °C larger air temperature drop than the literature design. (2) The CCGT plant with the novel inlet air cooling produced 1.83–14.4% (6.4–52.6 MW) higher power output than that without inlet air cooling. (3) The novel IACS improved the plant power output by 0.79–3.04% (2.8–11.1 MW) when compared with the literature design. However, the thermal efficiency of the CCGT plant with and without inlet air cooling was nearly unchanged. (4) The economic analysis showed that use of IACS is economically viable. The NPV of the novel IACS was $1.6–34.4 million higher than the literature design. Notes The authors declare no competing financial interest. Acknowledgements Zuming Liu acknowledges ACTSYS Process Management Consultancy Company, Singapore, for hosting his industrial internship under a ring-fenced Graduate Research Scholarship from the National University of Singapore. The authors thank Mr. Norman Lee, MD of ACTSYS for inspiring them to work on GT modeling. They further thank Mr. Norman Lee, Dr. Yu Liu, and Mr. Weiping Zhang of ACTSYS for several enlightening discussions and preliminary information on the GT operation in a CCGT plant. They acknowledge the support from the National University of Singapore via a seed grant R261-508-001-646/ 733 for CENGas (Center of Excellence for Natural Gas). They also acknowledge AspenTech Inc. and MathWorks for allowing the use of
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Contents lists available at ScienceDirect
Energy Conversion and Management journal homepage: www.elsevier.com/locate/enconman
A novel inlet air cooling system based on liquefied natural gas cold energy utilization for improving power plant performance
T
⁎
Zuming Liua, Iftekhar A. Karimia, , Tianbiao Heb a b
Department of Chemical & Biomolecular Engineering, National University of Singapore, 4 Engineering Drive 4, 117585, Singapore Department of Gas Engineering, College of Pipeline and Civil Engineering, China University of Petroleum (East China), Qingdao 266580, China
A R T I C LE I N FO
A B S T R A C T
Keywords: Inlet air cooling Liquefied natural gas Power plant Off-design performance Optimization
The performance of gas turbine-based power plants decreases significantly as ambient temperature increases. For improving power plant performance, this paper proposes a novel inlet air cooling system based on liquefied natural gas cold energy utilization. The novel system consists of two organic Rankine cycles in series and a mechanical vapor compression chiller. A simulation-based optimization method is developed to optimize its design parameters for maximizing the power plant performance. Moreover, the off-design performances of the proposed system and the power plant with and without inlet air cooling are evaluated under different ambient conditions. The results show that the novel inlet air cooling system gives larger air temperature drop (2.1–5.3 °C) and higher cooling duty (6.9–7.3 MW) than a literature design. Furthermore, for 28–40 °C ambient temperatures, the power plant with the novel inlet air cooling produces 1.83–14.4% (6.4–52.6 MW) higher power output than that without inlet air cooling. Importantly, the novel cooling system improves the plant power output by 0.79–3.04% (2.8–11.1 MW) when compared with the literature design. Finally, the economic analysis shows that the proposed system is economically viable with a net present value of $1.6–34.4 million higher than the literature design.
1. Introduction Natural gas is now quickly replacing coal and oil as the preferred fossil fuel for power generation due to its cleaner nature and lower carbon emissions. Some countries like Singapore produce more than 96% of their electric power using natural gas [1]. Natural gas is normally condensed into liquid form, namely liquefied natural gas (LNG) for easy storage and long distance transportation. Before sent to the end-users, LNG has to be regasified (converting LNG to natural gas), which releases 830–860 kJ kg−1 cold energy in terms of −162 °C LNG temperature [2]. How to reasonably utilize this LNG cold energy is an important topic and has gained great scientific attention. LNG cold energy has been used for air separation, seawater desalination, dry ice production, and electric power generation. Since electric power is indispensable in modern society, constructing low-temperature power generation cycles using LNG as heat sink is being studied for LNG cold energy utilization. Querol et al. [3] proposed a combined cycle using a gas turbine and a pure ammonia organic Rankine cycle (ORC) coupled with LNG vaporization process in LNG terminals. Rao et al. [4] developed a combined cycle consisting of a low-temperature solar-driven ORC with LNG direct expansion for power generation.
⁎
Corresponding author. E-mail address: [email protected] (I.A. Karimi).
https://doi.org/10.1016/j.enconman.2019.03.015 Received 23 November 2018; Accepted 8 March 2019 0196-8904/ © 2019 Elsevier Ltd. All rights reserved.
Ferreiro et al. [5] studied a new combined cycle composed of three ORCs using seawater and residual heat as heat sources and cold LNG as heat sink. Sun et al. [6] carried out process simulation and optimization for four schemes of power generation with and without LNG direct expansion. Xue et al. [7] proposed a three-stage ORC for LNG cold energy utilization and performed a stage-wise composition optimization for maximizing its performance. Kanbur et al. [8] presented a micro-cogeneration system combining a stirling engine and a micro gas turbine and found that their new system produced higher power output but lower carbon dioxide (CO2) emissions. Bao et al. [9] proposed a two-stage condensation combined cycle and showed that its net power output and efficiency were significantly higher than the conventional power generation cycles. Badami et al. [10] developed three combined cycles for power generation including ORC with single LNG direct expansion, ORC with LNG double expansion and reheating and regeneration, and parallel ORCs. Their results showed that the parallel ORCs produced higher specific power output. Gas turbine performance varies significantly with the ambient temperature [11]. Gas turbine power decreases by as much as 16.8% when the ambient temperature increases from 15 °C to 45 °C [12]. Hence, in hot weather, gas turbine power decreases significantly and
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Nomenclature
II
Symbols
Acronyms
ce cf LT m NPV P PR RH r T tax W Z
CAPEX CCGT CEPCI COMB COMP DESHT ECON EVAP GEN HP HPP HPST HRSG IACS IP IPP IPST LNG LP LPP LPST MTA NG OPEX ORC REVEN RHT RP SPHT TET TURB
electricity price, $/(kW h) fuel price, $/GJ lifetime, year mass flow rate, kg/s net present value, $ pressure, bar pressure ratio relative humidity interest rate temperature, K tax rate power, kW purchased-equipment cost, $
Greek letters
τ υ ψ
operating hours, h/year vapor fraction maintenance factor
Subscripts a c C1 C2 C3 cw f min I
air compressor methane ethylene propane cooling water fuel minimum ORC-I
ORC-II
capital expenditure combined cycle gas turbine Chemical Engineering Plant Cost Index combustor compressor desuperheater economizer evaporator generator high pressure high pressure pump high pressure steam turbine heat recovery steam generator inlet air cooling system intermediate pressure intermediate pressure pump intermediate pressure steam turbine liquefied natural gas low pressure low pressure pump low pressure steam turbine minimum temperature approach natural gas operating expenditure organic Rankine cycle revenue reheater recirculation pump superheater turbine exhaust temperature turbine
compressor inlet air cooling and found that the compressor inlet air temperature could be reduced by 4–25 °C while the gas turbine efficiency could be improved by 1.5–5%. Kim and Ro [22] analyzed the feasibility of using inlet air cooling by LNG cold energy from direct evaporation to improve power plant performance during warm seasons. They observed that the relative increase in plant power output reached 8% for dry air conditions (relative humidity lower than 30%) and 6% for normal humidity condition (60% relative humidity). Shi et al. [23] proposed an advanced power system in which LNG cold energy was directly utilized for compressor inlet air cooling, inter-cooling and steam condensation [24] to improve conventional combined cycle performance. Their results showed that the power output and thermal efficiency of the advanced power system were 76.8 MW and 2.8% higher than those of the conventional combined cycle. Kanhur et al. [25] studied a microturbine system with inlet air cooling by direct LNG evaporation and showed that the power output and thermal efficiency increased by 7.7% and 3.2%. Zhang et al. [26] developed a new process of utilizing LNG cold energy for gas turbine inlet air cooling to improve power plant performance. The process comprised a CO2 Rankine cycle and a CO2 compression-refrigeration system. They found that the plant power output increased by 1.6% and 11.6%, respectively, under 90% and 30% relative humidity. The above discussion showed that LNG cold energy was used for gas turbine inlet air cooling. The common option has been to cool down gas turbine inlet air via direct LNG evaporation [22–25]. This causes large cold exergy destruction as the maximum temperature approach reaches 184 °C and thus results in an inefficient LNG cold energy utilization. Some researchers [26] employed a CO2 Rankine cycle to recover LNG
gas turbine-based power plants may not meet the peak power demand. A solution is to use the electric power generated from LNG cold energy utilization to drive a mechanical vapor compression chiller for gas turbine inlet air cooling. In this way, gas turbine and power plant performance can be improved significantly. Alhazmy et al. [13] studied the effect of inlet air cooling on gas turbine performance under hot and humid conditions and showed that direct mechanical refrigeration increased gas turbine daily power by 6.77%. Al-Ansary et al. [14] analyzed the impact of a hybrid cooling system consisting of vapor compression cooling and evaporative cooling on gas turbine performance in arid climates. Their hybrid system was capable of boosting gas turbine power by more than 10% with good economic performance. Mohapatra and Sanjay [15] integrated a vapor compression chiller into a gas turbine combined cycle and observed that gas turbine efficiency and combined cycle power increased by 4.88% and 14.77%, respectively. Comodi et al. [16] applied vapor compression cooling to enhance micro gas turbine performance in hot climates and found that the power output and efficiency improved by 8% and 1.5%, respectively, when the inlet air was cooled down to 15 °C. Baakeem et al. [17] studied several prevailing inlet air cooling technologies for a gas turbine and found that multi-stage vapor compression system with cooling tower had better energy and economic performance. Moreover, gas refrigeration system [18] and earth-to-air heat exchanger [19] for inlet air cooling improved gas turbine performance. Several works have utilized LNG cold energy for compressor inlet air cooling and inter-cooling and steam condensation. Farzaneh-Gord and Deymi-Dashtebayaz [20,21] proposed a new approach to utilize the potential cooling capacity from natural gas pressure reduction for 42
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(counter-flow heat exchanger) via Pump-1. The ORC-I working fluid enters a multi-steam heat exchanger (HEX-1) after exchanging heat with the ORC-II working fluid in Condenser-2. The ORC-II working fluid is condensed by the ORC-I working fluid in Condenser-2 and then pumped to HEX-1 via Pump-2. The pressurized working fluids in ORC-I and ORC-II exchange heat with the hot air in HEX-1 and then expand in Turbine-1 and Turbine-2, respectively. The exhaust vapor from Turbine-1 and Turbine-2 then returns to their respective condensers. The power generated by Turbine-1 and Turbine-2 is used to drive LNG Pump, Pump-1 and Pump-2, and Compressor in the mechanical vapor compression chiller. The compressed working fluid is cooled by cooling water in Cooler and then passes through a throttling valve (Valve), where its pressure is reduced to produce a desired cooling temperature. The cold fluid from Valve and the LNG from Condenser-1 enters a multistream heat exchanger (HEX-2) and further exchange heat with the air from HEX-1. The air from HEX-2 then enters a knock-out drum (Drum), where the condensed water is drained. Finally, the cooled air and natural gas (NG) are supplied to a triple-pressure reheat combined cycle gas turbine (CCGT) power plant, as shown in Fig. 2. The novel IACS can be deployed very close to or within the air-filter house supplying air to the power plant. If it is near the air-filter house, then no equipment changes are required in the power plant. If it is in the air-filter house, then the air-filter house must be enlarged to accommodate the extra equipment. This upgrade is minor with limited investment, because only steel, bricks, and concrete are needed. The CCGT plant comprises a compressor (COMP), a combustor (COMB), a turbine (TURB), a triple-pressure reheat heat recovery steam generator (HRSG), three steam turbines (HPST, IPST, and LPST), four water pumps (HPP, IPP, LPP, and RP), and two generators (GEN). The cooled air compressed in COMP enters COMB, where natural gas as a fuel is burnt. The hot gas from COMB expands in TURB to produce power. The exhaust gas from TURB passes through HRSG before being vented as flue gas. The HRSG comprises three steam generation subsystems: high-pressure (HP), intermediate-pressure (IP), and low-pressure (LP). Each subsystem has one feed water pump, one or more economizers, one evaporator, and one or more superheaters. The feed water from each pump is preheated in the economizers, boiled in the
cold energy for gas turbine inlet air cooling; however, CO2 could hardly match LNG temperature profile during evaporation, and the maximum temperature approach between CO2 and LNG still reached 100 °C. Hence, more efficient ways of utilizing LNG cold energy should be explored for gas turbine inlet air cooling. Moreover, installing LNG coldbased inlet air cooling in power plants incurs extra capital and operating expenditures. Thus, a proper economic analysis lacking in the literature is necessary to justify its installation. In this paper, a novel inlet air cooling system (IACS) based on LNG cold energy utilization is proposed for improving power plant performance. The IACS comprises two mixed working fluid ORCs in series and a mechanical vapor compression chiller. Compared with the existing LNG cold energy utilization for gas turbine inlet air cooling, the innovations of the proposed IACS are summarized as follows: (1) Two mixed working fluid ORCs are installed between gas turbine inlet air and LNG to utilize their temperature potential for power generation. The mixed working fluid can match LNG temperature profile well, and hence the temperature approach between mixed working fluid and LNG is small and LNG cold energy is efficiently utilized. (2) The mechanical vapor compression chiller driven by the power generated from ORCs can significantly increase the IACS cooling duty in comparison with direct LNG evaporation. (3) A simulation-based optimization method is developed to fine tune the IACS design parameters for maximizing plant performance. (4) An economic analysis is presented to justify the IACS installation under different plant lifetime. The remainder of this paper is organized as follows. A description of the novel IACS and power plant is first presented. Then, the detailed methodology is given. Next, results and discussion are presented. Finally, conclusions are drawn.
2. Novel inlet air cooling system and combined cycle gas turbine power plant The novel IACS is illustrated in Fig. 1. The system comprises two organic Rankine cycles (ORC-I and ORC-II) and a mechanical vapor compression chiller. LNG is pressurized by LNG Pump and then sent to Condenser-1 (counter-flow heat exchanger). The ORC-I working fluid is condensed by LNG in Condenser-1 and pumped to Condenser-2
Fig. 1. Schematic of the novel inlet air cooling system. 43
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Fig. 2. Schematic of the triple-pressure reheat CCGT power plant with inlet air cooling.
the working fluid for the vapor compression chiller. The Peng-Robinson fluid package is used for air and LNG, while the NIST REFPROP database is adopted for organic working fluids. The assumptions for IACS simulation are presented in Table 2 [26]. The isentropic efficiencies of the pumps, compressors, and turbines are set to commercially reasonable values of 80%, 85%, and 90%, respectively. The pressure losses for air, LNG, and organic working fluids in the heat exchangers are assumed to be 0.5%, 5.0%, and 5.0% respectively of their inlet pressures. Moreover, 5.0 °C is taken as the minimum temperature approach (MTA) for all heat exchangers to avoid excessively large heat transfer areas.
evaporator, and superheated in the superheaters. Two reheaters (RHT1 and RHT2) are located between the HP superheaters. Moreover, two desuperheaters (DESHT1 and DESHT2) in the middle of HP superheaters and reheaters moderate the temperatures of HP steam and reheat steam via injecting water for safe operation. A recirculation pump (RP) recycles some hot water from the LP economizer exit back as its feed to prevent low-temperature corrosion. The HP steam expands in HPST and mixes with the IP steam. The mixed steam enters the reheaters and then expands in IPST. The exhaust steam from IPST mixes with the LP steam and enters LPST. After expansion, the exhaust steam from LPST goes to a condenser, and the condensate is pumped back to the LP economizer.
3.2. Combined cycle power plant simulation 3. Methods The CCGT plant is simulated in Aspen HYSYS. Detailed simulation descriptions for the CCGT plant can be found in Liu and Karimi [28]. The design parameters and performance of the CCGT plant are shown in Table 3 [28–30]. In this paper, the focus is on studying the full-load operation of the CCGT plant with inlet air cooling under different ambient conditions. The full-load operation implies that the compressor inlet guide vanes remain fully open while the turbine inlet temperature is maintained at its design value. Moreover, since the cooling water temperature is usually affected by the ambient temperature, the change in ambient temperature has a great impact on the condenser operation. To account for the impact of ambient temperature on the condenser operation, the cooling water temperature (Tcw ) is assumed to be linearly proportional to the ambient temperature (Ta ) as follows.
This section aims to obtain a novel IACS for improving power plant performance and justify the IACS economic viability, and comprises inlet air cooling system and combined cycle power plant simulation, a simulation-based optimization, and an economic analysis as follows. 3.1. Inlet air cooling system simulation The IACS is simulated in Aspen HYSYS [27]. In order to fully utilize LNG cold energy, proper working fluids should be employed for ORC-I and ORC-II. Since single working fluid normally results in large temperature approach in the condensers, it is necessary to consider mixed working fluid for achieving better temperature matching by utilizing its temperature characteristic in two-phase region. The selection of mixed working fluid for ORC-I and ORC-II depends on LNG temperature, air temperature, as well as boiling and critical temperatures of the potential components of the working fluid. Hence, in this paper, a mixed working fluid comprising methane, ethylene, and propane is used for ORC-I and ORC-II after a careful investigation, and the mass flow rates of the three components are tuned to achieve optimal temperature matching. Table 1 shows the thermodynamic properties of the mixed working fluid for ORC-I and ORC-II. Moreover, R134a is employed as
Table 1 Mixed working fluid for ORC-I and ORC-II.
44
Name
Critical pressure (bar)
Critical temperature (°C)
Normal boiling temperature (°C)
Notation
Methane Ethylene Propane
46.0 50.4 42.5
−82.7 9.2 96.8
−161.6 −103.9 −42.1
C1 C2 C3
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stated as the following optimization problem.
Table 2 Assumptions for IACS simulation [26].
maxWCCGT (P2, P5, mC1, I , mC 2, I , mC3, I , P7, P9, mC1, II , mC 2, II , mC3, II , PR c )
Air pressure loss in heat exchanger (%)
0.5
LNG pressure loss in heat exchanger (%) Organic fluid pressure loss in heat exchanger (%) Minimum temperature approach (°C) Pump isentropic efficiency (%) Compressor isentropic efficiency (%) Compressor mechanical efficiency (%) Turbine isentropic efficiency (%) Generator efficiency (%)
5.0 5.0 5.0 80.0 85.0 99.0 90.0 98.5
(2) The following constraints have to be enforced during optimization.
• The minimum temperature approaches (MTAs) in Condenser-1 and Condenser-2 should be larger than 5 °C.
(3)
ΔTmin ⩾ 5 °C
• There should be no liquid in the inlet streams of Turbine-1 and Turbine-2.
Table 3 Design parameters and performance of the CCGT plant. Parameter/variable
Value
Gas turbine Air pressure (kPa) Air temperature (°C) Inlet air flow (kg s−1) Inlet air pressure loss (%) Compressor pressure ratio Compressor isentropic efficiency (%) Compressor mechanical efficiency (%) Fuel flow (kg s−1) Combustor efficiency (%) Combustor pressure loss (%) Combustor exit temperature (°C) Turbine inlet temperature (°C) Turbine exhaust temperature (°C)
101.3 15.0 635.0 0.5 15.4 88.0 99.0 14.74 99.5 3.5 1405.0 1328.0 615.0
Heat recovery steam generator (HRSG) HP/IP/LP steam temperatures (°C) HP/IP/LP pinch point temperatures (°C) HP/IP/LP approach point temperatures (°C) HP SPHT 1 steam outlet temperature (°C) RHT 1/2 steam outlet temperature (°C) HP ECON 1/2 water outlet temperature (°C) Pressure losses on gas/water/steam sides (%)
565.0/297.0/295.0 10.0/10.0/10.0 8.0/10.0/16.4 510.0 520.0/565.0 208.0/280.0 1.5/5.0/3.0
Steam turbines (STs) HP/IP/LP ST inlet pressure (bar) HP/IP/LP ST isentropic efficiency (%)
98.8/24.0/4.0 87.0/91.0/89.0
Condenser Pressure (kPa) Cooling water temperature (°C) Cooling water temperature rise (°C)
7.4 25.0 10.0
Generator Generator efficiency (%) Shaft speed (rpm)
98.5 3000
CCGT performance Gas turbine power (MW) Gas turbine efficiency (%) Steam cycle power (MW) Plant net power (MW) Plant efficiency (%)
253.2 36.17 139.8 393.0 56.14
Tcw = 0.375Ta + 17
υ4 ⩾ 1
(4)
υ8 ⩾ 1
(5)
• The turbine exhaust vapor fraction should be higher than 0.9 to avoid turbine blade erosion.
υ5 ⩾ 0.9
(6)
υ9 ⩾ 0.9
(7)
A simulation-based optimization method shown in Fig. 3 is developed to maximize the plant power output. The IACS and CCGT plant are simulated in Aspen HYSYS, while the optimization is performed in MATLAB [31] using Nonlinear Optimization by Mesh Adaptive Direct Search (NOMAD) algorithm [32,33] from OPTI Toolbox [34]. NOMAD is a global optimizer and thus gives us better confidence in optimal solutions. MATLAB is interfaced with Aspen HYSYS via ActiveX for direct two-way communication. The decision variables (design parameters of IACS) are initialized in MATLAB and then passed to Aspen HYSYS for simulation. If Aspen HYSYS simulation converges, the results are sent back to MATLAB for evaluating the penalties of constraint violations along with objective function. NOMAD terminates when the termination conditions are satisfied. Otherwise, NOMAD updates the decision variables, and the optimization continues. 3.4. Economic analysis An economic analysis is necessary to demonstrate the economic viability of installing the novel IACS in the CCGT plant. The parameters and cost functions for the IACS economic analysis are shown in Table 4 [35]. Net present value (NPV) is used as the economic indicator and computed as follows: LT
NPV = −CAPEX +
∑ t=1
(REVEN − OPEX ) × (1 − tax ) (1 + r )t
(8)
M
CEPCI2016 ⎛ ⎞ × 1.2 × ⎜∑ Zi⎟ CEPCIbase = i 1 ⎝ ⎠
(9)
OPEX = τ × cf × Δmf + ψ × CAPEX
(10)
REVEN = τ × ce × ΔWCCGT
(11)
CAPEX =
(1)
where, CAPEX is the capital expenditure for the IACS, OPEX and REVEN are the extra operating expenditure and revenue due to IACS installation, ΔWCCGT and Δmf are the changes in the plant power output and fuel flow, ce and cf are the prices of electricity and fuel, ψ is the maintenance factor, τ is the plant annual operating hours, tax is the tax rate, r is the interest rate, LT is the remaining plant lifetime, CEPCI is the Chemical Engineering Plant Cost Index (base = 2001), and Z is the purchased-equipment cost.
3.3. Simulation-based optimization The power output of the CCGT plant under full-load condition decreases significantly in hot weather. The IACS utilizes LNG cold energy to cool down the gas turbine inlet air so that the plant can produce more power in hot weather. The increase in the plant power output depends on the IACS design. Hence, various IACS design parameters [pump outlet pressures (P2 and P7 ), turbine outlet pressures (P5 and P9 ), mass flow rates of methane, ethylene, and propane (mC1, I , mC 2, I , and mC 3, I ) in ORC-I, mass flow rates of methane, ethylene, and propane (mC1, II , mC 2, II , and mC 3, II ) in ORC-II, and compressor pressure ratio (PR c )] need to be optimized for maximizing the plant power output. This can be
4. Results and discussion The IACS design parameters are determined by simulation-based 45
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Fig. 3. Simulation-based optimization using NOMAD.
326.3 kW K−1, 363.6 kW K−1, and 130.2 kW K−1, respectively. The various stream parameters of the IACS under Ta = 40 °C and RH = 90% are shown in Table 6. The air (592.1 kg s−1) is cooled down to 32.2 °C in the IACS and then sent to the CCGT plant via Drum. The performance of the CCGT plant with and without inlet air cooling is shown in Table 7. The CCGT plant with the novel inlet air cooling produces higher gas turbine power and efficiency, but slightly lower steam cycle power and efficiency. Moreover, the novel inlet air cooling increases the plant power output significantly but decreases the plant efficiency slightly. Fig. 4 illustrates the hot and cold composite curves in Condenser-1 and Condenser-2. Obviously, the hot composite curve is close to the cold composite curve. Moreover, the minimum and maximum
optimization under a harsh ambient condition (Ta = 40 °C, RH = 90%), and their optimal values are shown in Table 5. The mass flow rates of methane, ethylene, and propane in ORC-I (ORC-II) are 1.41 kg s−1 (1.22 kg s−1), 7.80 kg s−1 (5.78 kg s−1), and 5.30 kg s−1 (5.58 kg s−1), respectively. The optimal pressure ratio for the compressor in the vapor compression chiller is 4.10. LNG (13.64 kg s−1) is pressurized to 30.0 bar by LNG Pump to condense ORC-I working fluid in Condenser1. The ORC-I (ORC-II) working fluid from Condenser-1 (Condenser-2) is pumped to 13.62 bar (31.29 bar) via Pump-1 (Pump-2) and then expands to 2.46 bar (8.03 bar) in Turbine-1 (Turbine-2). Moreover, R134a from Cooler is depressurized by Valve to 3.0 bar to produce a cooling temperature of 0.7 °C. The UA values for Condenser-1, Condenser-2, HEX-1, HEX-2, and Cooler are 710.7 kW K−1, 796.3 kW K−1, 46
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Table 4 Parameters and cost functions for economic analysis [35]. Parameters and cost functions
ce ($/(kW h)) cf ($ GJ−1) r (%) ψ (%) tax (%) τ (h/year) Pump ($) Compressor ($)
0.15 8.6 10 10 20 8000
1120W 0.8 71.1min (1/(0.91 − ηc )) PR c ln(PR c )
Turbine ($)
4405W 0.7
Heat exchangera ($)
2681A0.59
Condensera ($)
2143A0.514
a
U = 0.7kW/(m2K) is used for heat transfer area calculation.
Table 5 IACS optimal design (Ta = 40 °C, RH = 90%) .
parameters
and
lower
and
upper
bounds
Variable
Optimal value
Lower bound
Upper bound
P2 (bar) P5 (bar) mC1, I (kg s−1) mC 2, I (kg s−1) mC 3, I (kg s−1) P7 (bar) P9 (bar) mC1, II (kg s−1) mC 2, II (kg s−1) mC 3, II (kg s−1) PR c
13.62 2.46 1.41 7.80 5.30 31.29 8.03 1.22 5.78 5.58 4.10
11.0 1.5 1.0 6.0 4.0 26.0 7.0 1.0 4.0 4.0 3.0
18.0 3.0 3.0 9.0 7.0 35.0 9.0 4.0 8.0 8.0 6.0
Table 6 Stream parameters of the novel IACS (Ta = 40 °C, RH = 90%) . Stream no.
Mass flow rate kg s−1
Pressure bar
Temperature °C
Vapor fraction –
1 2 3 4 5 6 7 8 9 10 11 12 13 LNG NG Air Cooled air
14.51 14.51 14.51 14.51 14.51 12.58 12.58 12.58 12.58 52.5 52.5 52.5 52.5 13.64 13.64 592.1 584.9
2.34 13.62 12.94 12.29 2.46 7.63 31.29 29.73 8.03 2.85 11.70 11.11 3.00 1.013 27.07 1.013 1.003
−125.6 −125.2 −28.4 35.0 −39.3 −92.4 −92.2 35.0 −19.9 30.6 85.9 37.0 0.7 −165.5 10.0 40.0 32.2
0.0 0.0 0.68 1.0 1.0 0.0 0.0 1.0 0.95 1.0 1.0 0.0 0.26 0.0 1.0 1.0 1.0
Fig. 4. Hot and cold composite curves in Conderser-1 (a) and Condenser-2 (b).
Table 7 Performance of the CCGT plant (Ta = 40 °C, RH = 90%) . CCGT performance
No inlet air cooling
With inlet air cooling
Gas turbine power (MW) Gas turbine efficiency (%) Steam cycle power (MW) Steam cycle efficiency (%) Plant net power (MW) Plant efficiency (%)
217.3 34.17 133.9 30.12 351.2 55.20
224.0 34.57 133.6 30.06 357.6 55.18
Fig. 5. Exergy loss of each component in the IACS.
temperature approaches in Condenser-1 (Condenser-2) are 5.0 °C (5.0 °C) and 38.6 °C (32.8 °C), respectively. This implies low exergy losses in the condensers, as shown in Fig. 5. The exergy losses in water cooler, compressor and pumps, and throttling valve are very low and account for only 11.81% of the total exergy loss. Since the hot and cold composite curves are well matched, the exergy losses in the condensers and multi-stream heat exchangers are 25.54% and 22.09%,
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increase of the air relative humidity, more and more cooling duty is required for condensing the water vapor, leading to a gradual decrease of the air temperature drop in the IACS. For a given relative humidity, hotter air contains more water vapor. Hence, as the ambient temperature decreases, the air temperature drop in the IACS increases. Fig. 10 presents the cooling duty of the IACS under different ambient conditions. The cooling duty of the novel IACS is significantly higher than Ref. [26]. For 30–90% relative humidity, the differences in cooling duty between the novel IACS and Ref. [26] range from 7.0 MW (7.0 MW) to 7.3 MW (6.9 MW) when the ambient temperature is 40 °C (28 °C). This proves that the novel design utilizes LNG cold energy more efficiently. Moreover, the IACS is more sensitive to the ambient temperature than the relative humidity. As the ambient temperature decreases, the cooling duty of the IACS increases significantly. The reason is that the air mass flow increases with the decrease of the ambient temperature, thus incurring an increase in the fuel flow to maintain fullload operation. The latter directly results in an increase in the cooling duty. However, the cooling duty decreases slightly with the increase of the relative humidity. This is mainly because the fuel flow reduces when the relative humidity increases.
respectively. The ORC turbines are the most significant exergy loss contributors with 40.56% exergy losses. The reason is that the operating conditions of the ORC turbines (high pressure and low temperature) are away from the ambient conditions. 4.1. Parametric study on inlet air cooling system A parametric study is performed to evaluate the effects of the key design parameters on the IACS performance. Since methane, ethylene, and propane flow rates have similar effects on the performance, for brevity, this paper presents the effects of the working fluid flows in ORC-I and ORC-II as shown in Fig. 6, where the fluid composition is kept unchanged. Because HEX-1 duty and Turbine-1 (Turbine-2) power output increase with the ORC-I (ORC-II) working fluid flow, the cooling duty increases. The latter enables the vapor compression chiller to produce more refrigeration energy for air cooling in HEX-2. Moreover, as the ORC-I (ORC-II) working fluid flow increases, the MTA in Condenser-2 increases (decreases), since the ORC-I working fluid is able (unable) to provide sufficient cold energy for condensing the ORC-II working fluid. Furthermore, the MTA in Condenser-1 decreases with the increase of the ORC-I working fluid flow because of the inadequate LNG cold energy for condensation. However, the MTA in Condenser-1 remains unchanged regardless of the ORC-II working fluid flow, because its variation does not affect Condenser-1 operation. Fig. 7 illustrates the effects of pump and turbine outlet pressures on the IACS performance. As P2 (P5) and P7 (P9 ) increase (decrease), the power output of ORC-I and ORC-II increases (decreases), which directly causes an increase (decrease) in the cooling duty. The cooling duty first increases significantly, and then decreases slightly with the compressor pressure ratio, as presented in Fig. 8. Since the performance of ORC-I and ORC-II is not affected by the compressor in the vapor compression chiller, HEX-1 duty and the power output of the ORC turbines remain unchanged. Hence, the cooling duty only depends on the liquid-phase refrigerant flow in the vapor compression chiller. Fig. 7 shows that flow versus the compressor pressure ratio. This explains well why the cooling duty increases first and decrease later with the compressor pressure ratio.
4.3. Performance of combined cycle power plant with inlet air cooling Figs. 11–15 show how the performance of the CCGT plant with inlet air cooling changes under different ambient conditions. The performance parameters in Figs. 11–15 are normalized by the corresponding ones of the CCGT plant without inlet air cooling.
4.2. Performance comparison of inlet air cooling systems Zhang et al. [26] proposed an IACS using LNG cold energy to improve power plant performance. They compared their design with Kim and Ro [22] and showed that their IACS improved the plant power output and efficiency by 2.47% and 0.11%, respectively. In this paper, the novel IACS is compared with Ref. [26] under different ambient conditions to demonstrate its advantages. For this, the IACS from Ref. [26] is integrated with the CCGT plant shown in Fig. 2. Fig. 9 shows the air temperature drops in the IACS under different ambient conditions. Clearly, the novel IACS gives larger air temperature drops under all ambient conditions. For 30–90% relative humidity, the air temperature drops from the novel IACS are 3.7–2.1 °C (5.3–3.4 °C) larger than those from Ref. [26] when the ambient temperature is 40 °C (28 °C). This mainly results from the higher cooling duty of the novel IACS, as shown in Fig. 10. The cooling duty contains the sensible heat of the air and the latent heat of the water vapor. As a result, the air relative humidity has a great impact on the air temperature drop in the IACS. The air temperature drop in the IACS decreases significantly with the increase of the air relative humidity as can be seen in Fig. 9. For low relative humidity (e.g. 30%), the cooling duty is mainly used to reduce the sensible heat of the air, and thus the air temperature drop in the IACS is large. For high relative humidity (e.g. 90%), the water vapor in the air condenses in the course of heat exchange process, and the cooling duty is mainly used to condense the water vapor. Hence, the air temperature drop in the IACS becomes small. On the other hand, for a given ambient temperature (e.g. 40 °C or 28 °C), the water vapor in the air increases as the air relative humidity increases. Thus, with the
Fig. 6. Effects of working fluid flows in ORC-I (a) and ORC-II (b) on the IACS performance. 48
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Fig. 9. Air temperature drop in the IACS under different ambient conditions.
Fig. 7. Effects of pump and turbine outlet pressures on the IACS performance.
Fig. 10. IACS cooling duty under different ambient conditions.
Fig. 8. Effect of compressor pressure ratio on the IACS performance.
4.3.1. Gas turbine performance The gas turbine air mass flow under different ambient conditions is shown in Fig. 11. For 28–40 °C ambient temperatures, the air mass flow is 2.50–1.68% (1.44–0.91%) higher than Ref. [26] when the relative humidity is 30% (90%). This results from the larger air temperature drop (namely lower compressor inlet air temperature) in the novel
Fig. 11. Gas turbine air mass flow under different ambient conditions.
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Fig. 12. Turbine exhaust temperature (TET) under different ambient conditions.
Fig. 14. Steam cycle power (a) and efficiency (b) under different ambient conditions.
temperature constant at its design value. Hence, the fuel flow is 3.04–1.90% (1.57–0.76%) higher than Ref. [26] under the relative humidity of 30% (90%). Moreover, the higher air mass flow and constant turbine inlet air temperature render the pressure ratio 2.35–1.48% (1.28–0.67%) higher than Ref. [26]. The trends for the fuel flow and pressure ratio are similar to the air mass flow in Fig. 11. Because of the higher pressure ratio, the TET is 0.78–0.55% (0.52–0.34%) lower than Ref. [26] under 30% (90%) relative humidity, as shown in Fig. 12. Fig. 13 illustrates the gas turbine power and efficiency under different ambient conditions. For 28–40 °C ambient temperatures, the gas turbine power of the novel combined cycle is 4.42–2.92% and 2.37–1.26% higher than Ref. [26] under the relative humidity of 30% and 90%, respectively. This is because the novel IACS causes a lower compressor inlet air temperature, which leads to a higher air mass flow, fuel flow, and compressor pressure ratio. The lower compressor inlet air temperature reduces the compressor power consumption. Meanwhile, the higher compressor pressure ratio enables the turbine to expand to a lower TET, augmenting the turbine power output. Hence, the novel combined cycle produces a higher gas turbine power. Because of the higher gas turbine power of the novel combined cycle, the gas turbine efficiency is 1.09–0.84% (0.74–0.48%) higher than Ref. [26] under 30% (90%) relative humidity. Hence, it can be concluded from Fig. 13 that the inlet air cooling can significantly improve gas turbine performance. Moreover, the lower the compressor inlet air temperature, the higher the gas turbine performance.
Fig. 13. Gas turbine power (a) and efficiency (b) under different ambient conditions.
IACS, as illustrated in Fig. 9. Lower compressor inlet air temperature means higher inlet air density and hence higher air mass flow in the novel combined cycle (the CCGT plant with the novel inlet air cooling). A lower compressor inlet air temperature along with a higher air mass flow requires a higher fuel flow to maintain the turbine inlet
4.3.2. Steam cycle performance Fig. 14 presents the steam cycle power and efficiency under 50
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Table 8 Detailed economic performance under Singapore and Riyadh weather conditions. Economic performance
Singapore
Riyadh
Novel
Ref. [26]
Novel
Ref. [26]
Δmf (kg s−1)
0.64
0.45
1.66
1.41
ΔWCCGT (MW) CAPEX (million $) OPEX (million $ year−1) REVEN (million $ year−1)
17.1 3.51 7.90 20.53
11.63 2.06 5.46 13.95
44.70 3.51 19.88 53.63
37.72 2.06 16.77 45.26
efficiency under 90% relative humidity increases; however, the plant efficiency under 30% relative humidity decreases. The main reason for the latter is that under low relative humidity, the high gas turbine efficiency that results from inlet air cooling cannot compensate the low steam cycle efficiency. Hence, from Fig. 15, it can be concluded that the inlet air cooling improves the plant power output rather than the plant efficiency. 4.4. Economic performance To evaluating the IACS economic performance, the CCGT plant is considered at two locations: Singapore (Ta = 32 °C, RH = 80%) and Riyadh, Saudi Arabia (Ta = 40 °C, RH = 30%) A new CCGT plant is assumed to have a full lifetime of 20 years; hence, the remaining lifetime of an existing plant varies from 1 year to 20 years, namely 1 ⩽ LT ⩽ 20 The detailed economic performances under Singapore and Riyadh weather conditions are presented in Table 8. The capital expenditures of the novel IACS and Ref. [26] are $3.51 million and $2.06 million, respectively. Moreover, the novel IACS incurs a larger increase in fuel flow and power output than Ref. [26]. As a result, the operating expenditure and revenue of the novel IACS are higher than Ref. [26]. Although the novel IACS has higher capital and operating expenditures, the higher revenue from the novel IACS makes its NPV higher than Ref. [26], as shown in Fig. 16. Fig. 16 presents the NPV for installing the IACS under different plant lifetimes. Clearly, the ambient conditions (temperature and relative humidity) and the remaining plant lifetime have a significant effect on NPV. The lower the ambient relative humidity, the higher the ambient temperature; and the longer the remaining plant lifetime, the higher the NPV. Moreover, the NPV is always positive, which indicates that installing the novel IACS in CCGT plants is economically viable.
Fig. 15. Plant power (a) and efficiency (b) under different ambient conditions.
different ambient conditions. The steam cycle power of the novel combined cycle is 0.67–0.44% and 0.39–0.05% higher than Ref. [26] for 28–40 °C ambient temperatures under 30% and 90% relative humidity. The reason is that the novel combined cycle has a higher turbine exhaust flow, which enables the HRSG to produce more steam for power generation in the steam turbines. However, its steam cycle efficiency is lower than Ref. [26]. For 28–40 °C ambient temperatures, the steam cycle efficiency of the novel combined cycle is 0.56–0.22% and 0.17–0.09% lower than Ref. [26] under the relative humidity of 30% and 90%, respectively. This mainly results from the lower TET, which reduces the heat recovery from the turbine exhaust gas. Moreover, under low relative humidity (e.g. 30%), the low TET decreases the temperatures of HP steam and reheat steam. Consequently, the steam cycle efficiency under 30% relative humidity declines more rapidly than that under 90% relative humidity. Fig. 14 indicates that the inlet air cooling is advantageous for increasing steam cycle power, but disadvantageous for improving steam cycle efficiency. 4.3.3. Power plant performance The plant power output and efficiency under different ambient conditions are shown in Fig. 15. The power output of the novel combined cycle is 3.04–2.00% and 1.64–0.79% higher than Ref. [26] for 28–40 °C ambient temperatures when the relative humidity is 30% and 90%, respectively. This is because the gas turbine power and steam cycle power are augmented by the novel IACS. Moreover, with the decrease of the ambient temperature, the difference in the plant power output between the novel combined cycle and Ref. [26] increases due to the larger air temperature drop in the novel IACS. The plant efficiency is 0.01–0.07% and 0.06–0.04% higher than Ref. [26] under 30% and 90% relative humidity. As the ambient temperature decreases, the plant
Fig. 16. NPV for IACS installation under Singapore and Riyadh weather conditions. 51
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Aspen HYSYS and MATLAB under academic licenses provided to the National University of Singapore.
Furthermore, the NPV of the novel IACS is always higher than Ref. [26] under Singapore and Riyadh weather conditions. In Singapore, the novel IACS has an NPV of $1.6 million to $26.7 million higher than Ref. [26]. In Riyadh, it gives $2.4 million to $34.4 million more NPV than Ref. [26]. Hence, the novel IACS is economically more viable than Ref. [26]. Overall, the inlet air cooling is beneficial for improving the gas turbine power and efficiency, since it can reduce the compressor power consumption and increase the turbine power output. Moreover, it increases the steam cycle power owing to the higher turbine exhaust flow, but decreases the steam cycle efficiency due to the lower TET. By applying the novel inlet air cooling, the CCGT plant considered in this paper produces 1.83–14.4% (6.4–52.6 MW) higher power output. Furthermore, the novel IACS improves the plant power output by 0.79–3.04% (2.8–11.1 MW) when compared with Ref. [26]. However, the thermal efficiency of the CCGT plant remains nearly unchanged with inlet air cooling. Finally, the novel IACS is proved to be economically viable with an NPV of $1.6–34.4 million higher than Ref. [26] under various ambient conditions.
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5. Conclusions A novel IACS based on LNG cold energy utilization was proposed in this paper for improving power plant performance. The system recovers LNG cold energy via organic Rankine cycles to produce power for driving a mechanical vapor compression chiller. A simulation-based optimization method was developed to optimize the novel IACS for maximizing the plant performance. A parametric study was performed to evaluate the effects of the key design parameters on the IACS performance. The performance of the CCGT plant with and without inlet air cooling was evaluated under different ambient conditions. Moreover, an economic analysis was performed to justify the IACS installation. The main conclusions were summarized as follows: (1) The proposed novel IACS utilized LNG cold energy more efficiently and thus produced 6.9–7.3 MW higher cooling duty and achieved 2.1–5.3 °C larger air temperature drop than the literature design. (2) The CCGT plant with the novel inlet air cooling produced 1.83–14.4% (6.4–52.6 MW) higher power output than that without inlet air cooling. (3) The novel IACS improved the plant power output by 0.79–3.04% (2.8–11.1 MW) when compared with the literature design. However, the thermal efficiency of the CCGT plant with and without inlet air cooling was nearly unchanged. (4) The economic analysis showed that use of IACS is economically viable. The NPV of the novel IACS was $1.6–34.4 million higher than the literature design. Notes The authors declare no competing financial interest. Acknowledgements Zuming Liu acknowledges ACTSYS Process Management Consultancy Company, Singapore, for hosting his industrial internship under a ring-fenced Graduate Research Scholarship from the National University of Singapore. The authors thank Mr. Norman Lee, MD of ACTSYS for inspiring them to work on GT modeling. They further thank Mr. Norman Lee, Dr. Yu Liu, and Mr. Weiping Zhang of ACTSYS for several enlightening discussions and preliminary information on the GT operation in a CCGT plant. They acknowledge the support from the National University of Singapore via a seed grant R261-508-001-646/ 733 for CENGas (Center of Excellence for Natural Gas). They also acknowledge AspenTech Inc. and MathWorks for allowing the use of
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