Economic Process Selection of Liquefied Natural Gas Regasification

Article Cite This: Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

pubs.acs.org/IECR

Economic Process Selection of Liquefied Natural Gas Regasification: Power Generation and Energy Storage Applications Jinwoo Park,† Inkyu Lee,‡ Fengqi You,*,‡ and Il Moon*,† †

Ind. Eng. Chem. Res. Downloaded from pubs.acs.org by UNIV OF CAMBRIDGE on 03/19/19. For personal use only.

Department of Chemical and Biomolecular Engineering, Yonsei University, 50 Yonsei-ro, Seodaemun-gu, Seoul 03722, Republic of Korea ‡ Robert Frederick Smith School of Chemical and Biomolecular Engineering, Cornell University, Ithaca, New York 14853, United States ABSTRACT: Liquefied natural gas (LNG) demand has been rapidly increasing due to the global need for clean energy resources. This study analyzes and compares LNG regasification processes and technologies from the technoeconomic perspective and focuses on utilizing LNG cold energy as an economically beneficial option. The comparative technoeconomic analyses focus on the following three process: (1) a simple LNG regasification process, which wastes LNG cold energy; (2) an LNG regasification power plant (LPP) process, which utilizes LNG cold energy to generate electricity; (3) an LNG regasification power plant integrated with a cryogenic energy storage (LPCES) process, which utilizes LNG cold energy to store electricity. The results indicate that the LPP process has the highest net present value of $215 million for 1 MTPA LNG regasification, whereas the simple LNG regasification process and the LPCES process are valued at $210 million and $188 million, respectively. Sensitivity analysis results show that the relative rank of profitability of these three technologies varies according to discount rates, electricity prices, and carbon tax. This study not only revealed that LNG cold energy use can be an economically beneficial option but also helped determine the most profitable LNG regasification process under varying regional and market conditions. energy.11−13 Gomez et al. did several thermodynamic analyses of LNG regasification power plants.14−16 They also proposed that power plants should utilize LNG cold energy with CO2 capture.17 Szczygiel and Szargut studied cryogenic exergy of LNG for production of electricity.18 Pattanayak and Padhi studied combined cycle power plants, which showed significant power output.19 In contrast, some recent studies investigated the integration of cryogenic energy storage (CES) with LNG cold energy. CES is a technology that uses a cryogenic fluid as an energy storage medium, and it can be applied to the cryogenic process.20 It generally operates using liquid air as a cryogenic fluid that stores energy by compressing and liquefying air. Energy is recovered by gasifying the liquid air and discharging it to operate turbines.21 CES has a higher energy storage capacity, which can replace existing bulk power management systems.22 According to Zhang et al., CES has a relatively high energy density (100−200 Wh/ kg), a low-capital cost-per-unit energy, a benign effect on the environment, and a relatively long storage period.23 CES has been integrated with various thermodynamic cycles already and

1. INTRODUCTION Natural gas is the fastest-growing energy resource in the world because of its low greenhouse gas emissions with efficient energy conversion to power generation.1 Natural gas, which has a boiling point below −160 °C at atmospheric pressure, is generally transported as liquefied natural gas (LNG) over long distances.2 Natural gas demand has been forecast to increase by 45% from 2015 to 2040, and LNG demand was expected to increase by more than 2.5 times during the same period.3 LNG global trade is continuously growing and reached 293.1 million tons in 2017.4 For long-distance shipping, LNG has a decreased volume of more than 600 times compared to its gaseous phase counterpart.5 Therefore, transported LNG must be regasified to its gaseous state for commercial use.6 For LNG regasification, several process technologies exist: open rack vaporizer, submerged combustion vaporizer, ambient air-based heating vaporizer, and intermediate fluid vaporizer.7 More than 95% of commercial LNG regasification is done with open rack vaporizers using seawater.8 These operations generally discharge LNG cold energy into seawater because cold energy has only limited usage such as cooling foods or buildings.9 However, it is desirable to utilize its tremendous wasted cold energy to minimize overall energy losses.10 Thus, the most recent research has focused on electricity generation from LNG cold energy. Garcia et al. applied various types of organic Rankine cycles to make electricity from LNG cold © XXXX American Chemical Society

Received: Revised: Accepted: Published: A

January 10, 2019 March 8, 2019 March 11, 2019 March 11, 2019 DOI: 10.1021/acs.iecr.9b00179 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

Article

Industrial & Engineering Chemistry Research

Figure 1. Concept of the LPCES process.26

Figure 2. Three different LNG regasification processes for the economic feasibility study.12,26

cold energy.37 These technoeconomic studies were limited to power generation applications and did not include energy storage. Thus, a comparative technoeconomic study is required to compare these two different LNG cold energy utilization technologies. Accordingly, this study focused on the economic aspect of the LNG regasification process with its different cold energy utilization technologies. The research compared and analyzed economic values for different LNG regasification processes. Also, economic characteristics of each process were discussed with the results. Finally, the study found that the LNG cold energy utilization is not always the economically better option compared to wasting. This is significant, since it indicates that the most energy efficient process does not always result in the most economically profitable process. Economic rank of the various LNG regasification processes varies under different scenarios, and this study reveals the main factors that determine the profitability of each process.

as a hybrid power plant represents a remarkable solution as an energy storage system.24,25 Park et al. first introduced the concept of the LNG regasification process with CES.26 The concept of this integration is important for further energy savings, considering the substantial electricity demand differences between day and night times. The concept of an LNG regasification power plant integrated with a CES (LPCES) process is described in Figure 1. The LPCES process comprises power plant and CES units, which use two different routes to regasify LNG for electricity demand. In the case of off-peak times, where electricity demand is low, it stores electricity from the grid using LNG cold energy. In the case of on-peak times, where electricity demand is high, it generates electricity from the power plant and releases electricity from the CES unit. Recently, Lee et al. introduced the continuous energy storage concept using LNG cold energy.27,28 In summary, LNG cold energy utilization technologies can be represented as power generation or energy storage applications. Most of the studies introduced above were based on thermodynamics including energy analysis. It is important to analyze the energy aspects of the process, which results in a different perspective of fundamental energy flows. Additionally, economic analysis is also important regarding the limitation of the LNG import capacity. Determining the most profitable process for the same amount of LNG regasification is a crucial issue. Only a few studies have been conducted on comparative economic analysis of the LNG regasification processes, although several economic studies were conducted for other natural gas fields.29−35 Dutta et al. analyzed the economic feasibility of power generation using an organic Rankine cycle with LNG cold energy.36 Ghaebi et al. performed a thermoeconomic analysis for their proposed combined cooling and power cycles using LNG

2. PROCESS DESCRIPTION Three representative LNG regasification processes are selected to identify economic feasibility. Figure 2 describes three different LNG regasification processes. The first model is a simple LNG regasification process, which wastes its cold energy. The second model is the LNG regasification power plant (LPP) process that uses LNG cold energy to generate electricity.12 The last model is the LPCES process that has a CES unit to store and release electricity.26 All processes are simulated with the same design basis by Aspen Hysys V10, which is presented in Table 1. Power results of processes are based on the underlying models12,26 that pressure ratios of compressors and turbines are optimized using methodologies of a preceding study.38 B

DOI: 10.1021/acs.iecr.9b00179 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

Article

Industrial & Engineering Chemistry Research Table 1. Design Basis26 LNG mass flow LNG inlet pressure LNG inlet temperature LNG mass composition nitrogen methane ethane propane n-butane i-butane natural gas outlet pressure natural gas outlet temperature isentropic efficiency of air compressors isentropic efficiency of air turbines isentropic efficiency of working fluid turbines isentropic efficiency of natural gas expanders isentropic efficiency of pumps minimum temperature approach in heat exchangers pressure drop in equipment ambient temperature maximum compression ratio in compressors

configuration of the LPCES process adopted in this study. The process can be operated in two different modes in terms of electricity demand. In off-peak times, LNG is regasified by heat exchange with air. At the same time, LNG cold energy is utilized to liquefy air. Liquid air is used as an energy storage medium for air compressors that consume electricity from the grid. Therefore, LNG cold energy is stored in liquid air storage. In on-peak times, LNG is regasified using the LPP process, which generates electricity. Also, stored liquid air is discharged to the atmosphere where air turbines generate additional electricity. Figure 8 depicts cold energy utilization of the CES unit in the LPCES process. For 1 MTPA LNG regasification, 14.05 MW of LNG cold energy is utilized to store 25.54 MW of electricity. As a result, the CES unit releases 25.10 MW of electricity in on-peak times. The LPCES process shows a 95.2% round trip efficiency by utilizing LNG cold energy. It has a much higher efficiency than the other bulk power management systems, which has up to 75% efficiency.23 The LPCES process has distinctive features for storing and releasing energy according to variances in electricity demand. However, it has more equipment units than other LNG regasification processes, making capital costs and operating costs higher. The concept of the LPCES process was proposed only recently, and it might have more potential to save overall costs in the future.

1 million ton/yr 1.3 bar −162 °C 0.0019 0.8182 0.0933 0.0532 0.0167 0.0167 70 bar −10 °C 0.90 0.92 0.92 0.90 0.90 5 °C negligible 15 °C 3

2.1. Simple LNG Regasification Process. The conventional simple LNG regasification process used in this study is illustrated in Figure 3. The process comprises only the pump and required heater. It has the minimum number of equipment units compared to other processes. Therefore, such simple processes have merits in terms of relatively low capital cost. However, cold energy from LNG is discharged into the heating utility in the process. Figure 4 shows the exergy flow diagram in which LNG cold energy is merely wasted through heating. From this simple process, regasified natural gas is supplied at 70 bar to a pipeline for further commercial use. 2.2. LPP Process. The LPP process used is described in Figure 5 and is based on the model by Garcia et al.,12 which showed improved results compared with recent studies. The LNG is pressurized to 300 bar and regasified by two heat exchangers. In this process, LNG cold energy is discharged to working fluids with different temperature ranges. Then, the working fluids run with the organic Rankine cycle to generate electricity. After utilizing LNG cold energy, natural gas is depressurized by a series of expanders. This direct expansion generates additional electricity. Finally, natural gas at 70 bar was transported for commercial use. A number of LPP processes have been commercialized in Japan since the late 1970s.16 Figure 6 describes cold energy utilization of LNG in the LPP process. The process utilizes cold energy to generate electricity through the organic Rankine cycle and direct expansion of natural gas. As a result, the LPP process generates 5.04 MW electricity per 1 MTPA LNG regasification. From the energy perspective, it is a more desirable process because cold energy waste is reduced. 2.3. LPCES Process. The LPCES process model by Park et al.26 integrates the LPP process with CES. Figure 7 illustrates the

3. TECHNOECONOMIC ANALYSIS MODEL A rigorous technoeconomic analysis model is required to systematically compare these three different types of LNG regasification processes. On the basis of the cost data of simulated models in Aspen Hysys, a cost model is established for each of the processes. Table 2 shows the economic assumptions for a process cost evaluation. Most of the assumptions are based on relevant references, and the utility cost is derived from AspenTech.39 Moreover, South Korea is designated as the plant area due to its regional characteristics. According to the Energy Information Administration of the United States, South Korea relies on imports to meet about 98% of its fossil fuel consumption as a result of insufficient domestic resources and ranks among the world’s top five importers of LNG.40 Net present value (NPV) was set as the main cost index for comparing these processes. Its equation is as follows:42 PL

NPV = − CC +

∑ p=1

(STot − CO − Dep) × (1 − Φ) + Dep (1 + i) p

(1)

where CC denotes the capital cost, STot denotes the annual sales, CO denotes the annual operating cost, Dep denotes the annual depreciation cost, Φ denotes the tax rate, PL denotes the plant life, and i denotes the discount rate. The straight-line method is used for the depreciation calculation.46 To calculate NPV, capital cost, operating cost, and sales must be calculated first. 3.1. Capital Cost. Capital cost included various cost factors. In this study, a bare module factor is used to calculate capital costs, considering equipment life expectancy and discount rate. Table 3 displays cost parameters for the equipment. The capital cost equation is expressed as follows:

Figure 3. Process description of the simple LNG regasification process. C


Article


Figure 4. Exergy flow diagram of the simple LNG regasification process.

Figure 5. Process description of the LPP process.12

Figure 6. Exergy flow diagram of the LPP process.

D


Article


Figure 7. Process description of the LPCES process.26

Figure 8. Exergy flow diagram of the CES unit in the LPCES process.

Table 2. Economic Assumptions plant operating life41 plant operating hours42 plant operating hours (off-peak) plant operating hours (on-peak) discount rate43 tax rate44 utility price heating cooling electricity (off-peak)45 electricity (on-peak)45

Table 3. Cost Parameters for the Equipment 25 yr 8000 h 4000 h 4000 h 7% 25%

equipment life expectancy compressor48 turbine49 other equipment discount rate bare module factor50 compressor and turbine pump heater, cooler, and heat exchanger cryogenic tank

1.900 × 10−6 $/kJ 2.125 × 10−7 $/kJ 0.06091 $/kWh 0.11818 $/kWh

E

50 000 h 100 000 h 200 000 h (same as plant operating life) 7% 2.15 3.30 3.17 4.16


Article

Industrial & Engineering Chemistry Research Table 4. Overall Energy Results

heat flow (kW)

power consumption/generation (kW) compressor simple LPP LPCES (off-peak) LPCES (on-peak) n

CC = 1.18 ×

9396 25 632 36 024 h

∑ ∑ MFj × CE,j × j=1 k=1

×

turbine

pump

net power consumption/generation

heater

576 4361 576 5576

576 (consumption) 5035 (generation) 26 208 (consumption) 30 448 (generation)

23 815 28 917

1

CEPCI 2018 CEPCI 2016

Elec C Elec = OH × Priceavg. × W Net,C

CEPCI 2018 CEPCIBase, j

(2)

CComp = 7.90 × (1.3405 × WComp)0.62

(3)

C Turb = 0.378 × (1.3405 × WTurb)0.81

(4)

C Tank = 0.32 × SF × VTank

(5)

(6)

CMaint = 0.02 × CC

(7)

CCool = OHoff × PriceCool × HFCool ×


(11)

C Heat = OHon × Price Heat × HFHeat ×


(12)

Elec Net,C C Elec = OHoff × Priceoff × Woff

(13)

where OHoff denotes the plant operating hours for off-peak times, OHon denotes the plant operating hours for on-peak times, PriceElec off denotes the electricity price for off-peak times, and WNet,C off denotes the net plant power consumption for off-peak times. 3.3. Annual Sales. Annual sales include LNG regasification sales and electricity sales: STot = SReg + SElec

(14)

where SReg denotes the annual LNG regasification sales and SElec denotes the annual electricity sales. In this study, LNG regasification sales are considered instead of LNG import prices and natural gas sales prices. LNG regasification sales are assumed as $0.5/MMBtu of LNG.53 Since the LPP and LPCES processes operate differently at different times, the annual electricity sales are set differently. Moreover, a simple LNG regasification process does not have electricity sales due to the simple way it operates. For the LPP process, Elec SElec = OH × Priceavg. × W Net,G

(15)

Net,G

where W denotes the net plant power generation. For the LPCES process,

where CMaint denotes the annual maintenance cost, CCool denotes the annual cooling cost, CHeat denotes the annual heating cost, and CElec denotes the annual electricity cost. The annual maintenance cost is assumed as 2% of the capital cost.41 Simple regasification and LPP processes operate continuously, while the LPCES process operates differently in off-peak and on-peak times. Therefore, utility costs are set differently with respect to the operating features of each process. For the simple LNG regasification process and LPP process, CEPCI 2018 CEPCI 2016

(10)

where OH denotes the plant operating hours, Price denotes the cooling price, HFCool denotes the heat flow for cooling, PriceHeat denotes the heating price, HFHeat denotes the heat flow for heating, PriceElec avg. denotes the average electricity price for offpeak times and on-peak times, and WNet,C denotes the net plant power consumption. For the LPCES process,

where CComp denotes the purchase cost of the compressor, WComp denotes the power consumption of the compressor, CTurb denotes the purchase cost of the turbine, WTurb denotes the power generation of the turbine, CTank denotes the purchase cost of the cryogenic tank, SF denotes the safety factor for the cryogenic tank volume, and VTank denotes the volume of the cryogenic tank. 3.2. Annual Operating Cost. Annual operating cost includes the maintenance cost and utility cost according to the following equations: CO = CMaint + CCool + C Heat + C Elec

(9)

Cool

where 1.18 is the coefficient for contingency and contractor fee,47 MF denotes the equipment bare module factor, CE denotes the equipment purchase cost, L denotes the equipment life expectancy, CEPCI denotes the chemical engineering plant cost index, h denotes the required number of equipment units considering equipment life expectancy, and n denotes the equipment type. For estimating the purchase cost of each equipment, two different methods are used depending on the equipment type. The cost of pumps, heaters, coolers, and heat exchangers are estimated using the Aspen capital cost analyzer.39 Capacities of a few compressors and turbines are out of its evaluation range. Moreover, the cryogenic tank cannot be evaluated using the Aspen capital cost analyzer. Thus, the cost of compressors, turbines, and cryogenic tanks are estimated using the following equations:51,52

CCool = OH × PriceCool × HFCool ×

25 945 74 626

C Heat = OH × Price Heat × HFHeat ×

(1 + i)Lj(kj − 1)

cooler

Elec Net,G SElec = OHon × Priceon × Won

(16)

where PriceElec on denotes the electricity price for the on-peak times and WNet,G denotes the net plant power generation for the onon peak times.

4. RESULTS AND DISCUSSION The objective of this research is to systematically perform comparative technoeconomic analyses of LNG regasification processes. Therefore, simple LNG regasification, LPP, and

(8) F


Article

Industrial & Engineering Chemistry Research Table 5. Overall Cost Estimation Results capital cost (k$) compressor simple LPP LPCES

34 779

turbine

heater

1455 247 4694 12 701 1206 9998 16 166 2202 annual operating cost (k$/yr)

maintenance

heating

34 560 1716

1384 1684 2173

simple LPP LPCES

pump

cooling

electricity 413

84 NPV (k$)

simple LPP LPCES

6384

209 700 214 612 188 296

cooler

heat exchanger

1060

9412 12 424 total

1831 2244 10 358 IRR (%) 1066 74.32 27.34

regasification 25 998 25 998 25 998

cryogenic tank

9189 annual sales (k$/yr) electricity 3607 14 394 PBP (yr)

total 1702 28 014 85 818 total 25 998 29 605 40 392

0.10 1.46 4.36

Figure 9. Annualized cost indexes of each process.

Figure 10. Capital cost, annual operating cost, and annual sales portions of each process.

deterministic optimization approach and allows easier optimization in the future, should it prove necessary.54,55 Table 4 shows overall energy results for three different LNG

LPCES processes are evaluated on the basis of the capacity of 1 MTPA natural gas supply. The established cost model is applied to commercial software gPROMS, which is specialized for the G


Article


Figure 11. NPV results for various discount rates.

needing a low capital cost. Meanwhile, the LPCES process, as a recently proposed concept, should be further optimized, as has been the case with other energy storage systems.56 However, the results are varied by various factors that were revealed from several sensitivity analyses. First, the results are sensitive to the discount rate used. The discount rate, which includes both interest and inflation, could change depending on the particular investment situation. Figure 11 depicts the NPV results over a range of discount rates. At over 9%, the simple LNG regasification process shows the highest NPV. Moreover, the LPCES process achieves a higher position than simple LNG regasification in low discount rates. Thus, we find that different discount rates can affect investment priorities among the three processes, which result from different levels of profit. Furthermore, the results are affected by the price of electricity. Figure 12 shows the most profitable process at various electricity prices based on NPV results. When both off-peak and on-peak electricity prices are low, the simple LNG regasification process is the most profitable process because the other two processes lose competitiveness in electricity sales. When the on-peak electricity price is much higher than the off-peak electricity price, the LPCES process ranks as the most profitable process due to electricity sales. Also, the LPP process and the LPCES process mainly uses a clean energy source: LNG cold energy. Thus, these two processes have strengths compared to power generation systems with carbon dioxide emissions. Carbon tax is imposed to reduce carbon dioxide emissions and prevent global warming. When one considers the carbon tax of conventional power plants and the affect on profit, it can change the NPV ranks among the three processes. Figure 13 shows the economic effect of carbon tax variation. Carbon tax is assumed to be from 0 to 3 ¢/kWh for electricity generation. According to Jeong et al., carbon tax was calculated as 1.01 ¢/kWh for an LNG combined cycle power plant and 2.38 ¢/kWh for a coal-fired power plant when the government charged 100 $/ton-carbon.57 As a result, the LPP

regasification processes. Features of each process can be shown in this way: The simple LNG regasification process consumes energy, the LPP process generates energy, and the LPCES process stores and releases energy. Table 5 shows overall cost estimation results, and Figure 9 shows annualized cost indexes. Significant capital cost differences are observed among the three processes. The annual operating cost indicates an approximately 20% difference between the simple LNG regasification process and the LPP process. However, the LPCES process requires a 4−6 times higher annual operating cost compared to other processes. On the other hand, the LPCES process shows far higher sales and profits owing to its larger electricity sales. Moreover, the internal rate of return (IRR) and payback period (PBP) are described in Table 5. The simple LNG regasification process has the highest IRR and the lowest PBP due to its far lower capital cost. Superior IRR and PBP does not guarantee the best option in the LNG regasification process because the LNG import capacity is limited. NPV shows the total outcome, which is an appropriate comparison indicator in limited investment chance. Overall, the results indicate that all processes are profitable and show the differences in NPV being less than 15%, with the LPP process the highest of the three. Figure 10 describes the capital cost, annual operating cost, and annual sales portions of each process. For the capital cost, the compressor accounts for the largest portion, while the cooler and heater account for smaller portions. For the annual operating cost, the heating cost occupied the largest portion among all three processes, excluding electricity cost. For the annual sales, regasification is responsible for over half of the total, especially in the LPP process, where regasification sales are seven times higher than for electricity. The results indicated that all processes mainly get income from LNG regasification. Considering the limited capacity of LNG imports, the LPP process is the most profitable investment, although the simple LNG regasification process is a good alternative for those H


Article


significant factor for both the simple LNG regasification process and the LPP process while it was ranked fourth for the LPCES process. Although the change of electricity prices leads to a dramatic NPV change in the LPCES process, it shows only a slight effect for the simple LNG regasification process and the LPP process. Overall, NPV fluctuation indicates that the simple LNG regasification process is the least sensitive to most factors while the LPCES process is highly sensitive to multiple factors, while the LPP process is located in between.

5. CONCLUSIONS In this study, three different LNG regasification processes were economically evaluated to observe which ones wasted or utilized LNG cold energy. All processes showed profitability due to their regasification sales, with the most profitable being the LPP process. However, the results were sensitive to various factors, especially electricity prices. When LNG cold energy was used in the regasification process, the following observations were made: • The simple LNG regasification process would be recommended if low capital cost with stable profit is preferred. • The LPP process is the most profitable option for regions where the average electricity price is high. • The LPCES process is appropriate for regions where electricity prices significantly differ during off-peak and on-peak times. In conclusion, LNG cold energy can be economically profitable depending on the electricity price and the demand flexibility. Moreover, as global cleaner energy economies are growing rapidly, this study would help the environment by illuminating the economic aspects of clean energy sources.58 Future work will focus on optimizing process operations and economic aspects based on the significant cost factors derived from this study.

Figure 12. Most profitable process for various electricity prices.

■

Figure 13. NPV results considering carbon tax.

AUTHOR INFORMATION

Corresponding Authors

*Tel.: +82 2 2123 2761. Fax: +82 2 312 6401. E-mail: ilmoon@ yonsei.ac.kr (I.M.). *Tel.: +1 607 255 1162. Fax: +1 607 255 9166. E-mail: fengqi. [email protected] (F.Y.).

process indicates the highest NPV until carbon tax is around 2.5 ¢/kWh. The LPCES process shows drastic NPV increases as carbon tax increases and displays the highest NPV when carbon tax is 3.0 ¢/kWh. Additional sensitivity analysis shown in Figure 14 compares various factors including capital cost, regasification sales, and utility prices. The values were perturbed by ±30% of the base values. Overall, regasification sales are the most dominant factor influencing the NPV results. Tax rate is the second most

ORCID

Fengqi You: 0000-0001-9609-4299 Il Moon: 0000-0003-1895-696X Notes

The authors declare no competing financial interest.

Figure 14. NPV differences due to sensitivity analysis: (left) simple, (middle) LPP, and (right) LPCES. I


Article


■

ACKNOWLEDGMENTS This work was supported by the Technology Innovation Program (10067793, Engineering Education System of Integrated Design by Case Based Plant Process and Safety) funded by the Ministry of Trade, Industry & Energy (MOTIE, Korea), Korea Evaluation Institute of Industrial Technology (KEIT, Korea), and by the BK 21 Program funded by the Korean Ministry of Education (MOE).

IRR = internal rate of return PBP = payback period

■

REFERENCES

(1) Mokhatab, S.; Mak, J.; Valappil, J.; Wood, D. Handbook of Liquefied Natural Gas, first ed.; Elsevier: 2014. (2) Pospisil, J.; Charvat, P.; Arsenyeva, O.; Klimes, L.; Spilacek, M.; Klemes, J. Energy demand of liquefaction and regasification of natural gas and the potential of LNG for operative thermal energy storage. Renewable Sustainable Energy Rev. 2019, 99, 1−15. (3) 2017 Outlook for Energy: A View to 2040; Exxon Mobil, 2017. (4) 2018 World LNG Report, 27th World Gas Conference Edition; International Gas Union, 2018. (5) Kumar, S.; Kwon, H. T.; Choi, K. H.; Lim, W.; Cho, J. H.; Tak, K.; Moon, I. LNG: An Eco-friendly Cryogenic Fuel for Sustainable Development. Appl. Energy 2011, 88, 4264−4273. (6) Lim, W.; Choi, K.; Moon, I. Current Status and Perspectives of Liquefied Natural Gas (LNG) Plant Design. Ind. Eng. Chem. Res. 2013, 52, 3065−3088. (7) Yu, H.; Kim, D.; Gundersen, T. A study of working fluids for Organic Rankine Cycles (ORCs) operating across and below ambient temperature to utilize Liquefied Natural Gas (LNG) cold energy. Energy 2019, 167, 730−739. (8) Agarwal, R.; Rainey, T.; Rahman, S.; Steinberg, T.; Perrons, R.; Brown, R. LNG Regasification Terminals: The Role of Geography and Meteorology on Technology Choices. Energies 2017, 10, 2152−2170. (9) Choi, I.; Lee, S.; Seo, Y.; Chang, D. Analysis and optimization of cascade Rankine cycle for liquefied natural gas cold energy recovery. Energy 2013, 61, 179−195. (10) Lee, I.; Park, J.; Moon, I. Key Issues and Challenges on the Liquefied Natural Gas Value Chain: A Review from the Process Systems Engineering Point of View. Ind. Eng. Chem. Res. 2018, 57, 5805−5818. (11) Garcia, R. F.; Carril, J. C.; Gomez, J. R.; Gomez, M. R. Power plant based on three series Rankine cycles combined with a direct expander using LNG cold as heat sink. Energy Convers. Manage. 2015, 101, 285−294. (12) Garcia, R.; Carril, J.; Gomez, J.; Gomez, M. Combined cascaded Rankine and direct expander based power units using LNG (liquefied natural gas) cold as heat sink in LNG regasification. Energy 2016, 105, 16−24. (13) Garcia, R. Efficiency enhancement of combined cycles by suitable working fluids and operating conditions. Appl. Therm. Eng. 2012, 42, 25−33. (14) Gomez, M. R.; Garcia, R. F.; Carril, J. C.; Gomez, J. R. High efficiency power plant with liquefied natural gas cold energy utilization. J. Energy Inst. 2014, 87, 59−68. (15) Gomez, M.; Garcia, R.; Gomez, J.; Carril, J. Thermodynamic analysis of a Brayton cycle and Rankine cycle arranged in series exploiting the cold exergy of LNG (liquefied natural gas). Energy 2014, 66, 927−937. (16) Gomez, M. R.; Garcia, R. F.; Gomez, J. R.; Carril, J. C. Review of thermal cycles exploiting the exergy of liquefied natural gas in the regasification process. Renewable Sustainable Energy Rev. 2014, 38, 781−795. (17) Gomez, M. R.; Gomez, J. R.; Lopez-Gonzlez, L. M.; LopezOchoa, L. M. Thermodynamic analysis of a novel power plant with LNG (liquefied natural gas) cold exergy exploitation and CO2 capture. Energy 2016, 105, 32−44. (18) Szczygiel, I.; Szargut, J. Utilization of the cryogenic exergy of liquid natural gas (LNG) for the production of electricity. Energy 2009, 34, 827−837. (19) Pattanayak, L.; Padhi, Bi. Thermodynamic Analysis of Combined Cycle Power Plant using Regasification Cold Energy from LNG Terminal. Energy 2018, 164, 1. (20) Zhang, Q.; Grossmann, I.; Heuberger, C.; Sundaramoorthy, A.; Pinto, J. Air Separation with Cryogenic Energy Storage: Optimal Scheduling Considering Electric Energy and Reserve Markets. AIChE J. 2015, 61, 1547−1558.

■

NOMENCLATURE CC = capital cost (k$) CE = equipment purchase cost (k$) CO = annual operating cost (k$/yr) CComp = purchase cost of compressor (k$) CCool = annual cooling cost (k$/yr) CElec = annual electricity cost (k$/yr) CHeat = annual heating cost (k$/yr) CMaint = annual maintenance cost (k$/yr) CTank = purchase cost of cryogenic tank (k$) CTurb = purchase cost of turbine (k$) CEPCI = chemical engineering plant cost index Dep = depreciation cost (k$) HFCool = heat flow for cooling (kW) HFHeat = heat flow for heating (kW) L = equipment life expectancy (yr) MF = equipment bare module factor NPV = net present value (k$) OH = plant operating hours (h) OHoff = plant operating hours for off-peak times (h) OHon = plant operating hours for on-peak times (h) PL = plant life (yr) PriceCool = cooling price (k$/kJ) PriceHeat = heating price (k$/kJ) PriceElec avg. = average electricity price for off-peak times and onpeak times (k$/kWh) PriceElec off = electricity price for off-peak times (k$/kWh) PriceElec on = electricity price for on-peak times (k$/kWh) SElec = annual electricity sales (k$/yr) SReg = annual LNG regasification sales (k$/yr) STot = annual sales (k$/yr) SF = safety factor for volume of cryogenic tank VTank = volume of cryogenic tank (m3) WComp = power consumption of compressor (kW) WTurb = power generation of turbine (kW) WNet,C = net plant power consumption (kW) WNet,G = net plant power generation (kW) WNet,C = net plant power consumption for off-peak times off (kW) WNet,G = net plant power generation for on-peak times (kW) on h = required number of equipment units considering equipment life expectancy i = discount rate j, k, p = counters n = equipment type Φ = tax rate

Abbreviations

LNG = liquefied natural gas CES = cryogenic energy storage LPCES LNG = regasification power plant integrated with a CES LPP LNG = regasification power plant NPV = net present value J


Article


(43) Overview of business valuation parameters in the energy industry, edition n.3; Deloitte, 2017. (44) International Tax Korea Highlights 2018; Deloitte, 2018. (45) Korea Power Exchange. South Korea; http://www.kpx.or.kr/ (accessed Sept 2018). (46) Taxation and Investment in Korea 2017; Deloitte, 2017. (47) Feng, Y.; Rangaiah, G. P. Evaluating capital cost estimation programs. Chemical Engineering 2011, 22−29. (48) Neittaanmäki, P.; Repin, S.; Tuovinen, T. Mathematical Modeling and Optimization of Complex Structures; Springer: New York, 2016. (49) Slottner, P. Life Extension of SIMENS Industrial-sized Gas Turbines. In 18th Symposium of the Industrial Application of Gas Turbines Committee, Banff, Alberta, Canada, October 19−21, 2009. (50) Ulrich, G. D.; Vasudevan, P. T. Chemical Engineering Process Design and Economics: A Practical Guide, second ed.; Process Publishing: Durham, NH, 2018. (51) Couper, J.; Penny, W.; Fair, J. Chemical Process Equipment: Selection and Design, third ed.; Elsevier, 2012. (52) Hu, Y.; Li, X.; Li, H.; Yan, J. Peak and off-peak operations of the air separation unit in oxy-coal combustion power generation systems. Appl. Energy 2013, 112, 747−754. (53) The impact of US LNG on European gas prices; Charles River Associates, 2018. (54) Martin, M. Introduction to Software for Chemical Engineers, first ed.; CRC Press, 2014. (55) Park, J.; Cho, H.; Hwang, D.; Kim, S.; Moon, I.; Kim, M. Design of a Novel Process for Continuous Lactide Synthesis from Lactic Acid. Ind. Eng. Chem. Res. 2018, 57, 11955−11962. (56) Gong, J.; You, F. Sustainable design and synthesis of energy systems. Curr. Opin. Chem. Eng. 2015, 10, 77−86. (57) Jeong, S.; Kim, K.; Park, J.; Lim, D.; Lee, S. Economic comparison between coal-fired and liquefied natural gas combined cycle power plants considering carbon tax: Korean case. Energy 2008, 33, 1320−1330. (58) Shell LNG outlook 2018; Shell, 2018.

(21) Sciacovelli, A.; Vecchi, A.; Ding, Y. Liquid air energy storage (LAES) with packed bed cold thermal storage − From component to system level performance through dynamic modelling. Appl. Energy 2017, 190, 84−98. (22) The Liquid Air Energy Network. Energy storage systems according to form of energy stored; http://www.liquidair.org.uk; 2014. (23) Zhang, H.; Baeyens, J.; Caceres, G.; Degreve, J.; Lv, Y. Thermal energy storage: Recent developments and practical aspects. Prog. Energy Combust. Sci. 2016, 53, 1−40. (24) Antonelli, M.; Barsali, S.; Desideri, U.; Giglioli, R.; Paganucci, F.; Pasini, G. Liquid air energy storage: Potential and challenges of hybrid power plants. Appl. Energy 2017, 194, 522−529. (25) Li, Y.; Cao, H.; Wang, S.; Jin, Y.; Li, D.; Wang, X.; Ding, Y. Load shifting of nuclear power plants using cryogenic energy storage technology. Appl. Energy 2014, 113, 1710−1716. (26) Park, J.; Lee, I.; Moon, I. A Novel Design of Liquefied Natural Gas (LNG) Regasification Power Plant Integrated with Cryogenic Energy Storage System. Ind. Eng. Chem. Res. 2017, 56, 1288−1296. (27) Lee, I.; Park, J.; Moon, I. Conceptual design and exergy analysis of combined cryogenic energy storage and LNG regasification processes: Cold and power integration. Energy 2017, 140, 106−115. (28) Lee, I.; Park, J.; You, F.; Moon, I. A novel cryogenic energy storage system with LNG direct expansion regasification: Design, energy optimization, and exergy analysis. Energy 2019, 173, 691−705. (29) Lee, I.; Moon, I. Total Cost Optimization of a Single Mixed Refrigerant Process Based on Equipment Cost and Life Expectancy. Ind. Eng. Chem. Res. 2016, 55, 10336−10343. (30) Lee, I.; Moon, I. Economic Optimization of Dual Mixed Refrigerant Liquefied Natural Gas Plant Considering Natural Gas Extraction Rate. Ind. Eng. Chem. Res. 2017, 56, 2804−2814. (31) Lee, I.; Moon, I. Strategies for Process and Size Selection of Natural Gas Liquefaction Processes: Specific Profit Portfolio Approach by Economic Based Optimization. Ind. Eng. Chem. Res. 2018, 57, 5845− 5857. (32) Dutta, A.; Karimi, I.; Farooq, S. Heating Value Reduction of LNG (Liquefied Natural Gas) by Recovering Heavy Hydrocarbons: Technoeconomic Analyses Using Simulation-Based Optimization. Ind. Eng. Chem. Res. 2018, 57, 5924−5932. (33) Gong, J.; Yang, M.; You, F. A systematic simulation-based process intensification method for shale gas processing and NGLs recovery process systems under uncertain feedstock compositions. Comput. Chem. Eng. 2017, 105, 259−275. (34) He, C.; You, F. Toward More Cost-Effective and Greener Chemicals Production from Shale Gas by Integrating with Bioethanol Dehydration: Novel Process Design and Simulation-Based Optimization. AIChE J. 2015, 61, 1209−1232. (35) Gao, J.; You, F. Shale Gas Supply Chain Design and Operations toward Better Economic and Life Cycle Environmental Performance: MINLP Model and Global Optimization Algorithm. ACS Sustainable Chem. Eng. 2015, 3, 1282−1291. (36) Dutta, A.; Karimi, I.; Farooq, S. Economic Feasibility of Power Generation by Recovering Cold Energy during LNG (Liquefied Natural Gas) Regasification. ACS Sustainable Chem. Eng. 2018, 6, 10687−10695. (37) Ghaebi, H.; Parikhani, T.; Rostamzadeh, H. Energy, Exergy and Thermoeconomic Analysis of a Novel Combined Cooling and Power System Using Low-Temperature Heat Source and LNG Cold Energy Recovery. Energy Convers. Manage. 2017, 150, 678−692. (38) Lee, I.; Tak, K.; Kwon, H.; Kim, J.; Ko, D.; Moon, I. Design and Optimization of a Pure Refrigerant Cycle for Natural Gas Liquefaction with Subcooling. Ind. Eng. Chem. Res. 2014, 53, 10397−10403. (39) Aspen Icarus Reference Guide-Icarus Evaluation Engineer (IEE) V10.0; AspenTech, Inc.: Burlington, MA, 2017. (40) Country Analysis Brief: South Korea; Energy Information Administration, 2018. (41) Criteria for technical and economic assessment of plants with low CO2 emissions; International Energy Agency, 2009. (42) Peters, M.; Timmerhaus, K.; West, R. Plant Design and Economics for Chemical Engineers, fifth ed.; McGraw-Hill, 2003. K


Economic Process Selection of Liquefied Natural Gas Regasification

Recommend Documents