ARTICLE pubs.acs.org/IECR
CO2 Storage Terminal for Ship Transportation Ung Lee, Youngsub Lim, Sangho Lee, Jaeheum Jung, and Chonghun Han* School of Chemical and Biological Engineering, Seoul National University, Gwanak-ro 599, Gwanak-gu, Seoul 151-742, South Korea ABSTRACT: In this article, an intermediate CO2 storage system for long-distance ship transportation was modeled. The storage terminal links the continuous CO2 liquefaction process to discrete marine ship transportation and performs as a buffer between them. It is composed of four distinct processes: a CO2 input process, a storage tank and loading process, a recirculation process, and a BOG (boiled-off gas) reliquefaction process. The entire system should be operated as a liquid phase. Consequently, operation conditions, tank capacity, insulation specification, and streamflow rates play a major role in operating the storage terminal securely. The goal of this study is to design a base case of the storage terminal and propose its appropriate operation condition which makes the terminal operate with minimum operation energy. Results of the base case simulations are compared with improperly insulated systems on the pipeline and tanks that generate more BOG than the base case. The total operation energies of the base case and case studies are presented, and it turns out that approximately three times the operation energy is required if the system is not properly designed.
1. INTRODUCTION In response to the challenges posed by global warming and the Kyoto protocol, carbon dioxide reduction technology has attracted worldwide attention. Among the proven carbon dioxide reduction technologies, carbon capture and sequestration (CCS) technology is considered the most appropriate CO2 reducing option due to its capability of processing large amounts of carbon dioxide and its economic feasibility. Such CCS technology is generally composed of three compartments: carbon dioxide capture, transportation, and sequestration. Most research to date has focused on the capture and sequestration processes because the transportation process is being considered the least technologically challenging part. However, the transportation process also requires advanced technologies. For example, the BOG (boiledoff gas) reliquefaction system and pipe and tank insulation system can require a large amount of energy depending upon the operation process. Additionally, if the storage terminal is operated at improper condition, the operation costs may exponentially increase and even result in a serious safety incident. Consequently, the transportation phase of CCS should not be overlooked but instead requires careful research and design. CO2 transportation includes all processes receiving CO2 from the capture process to its injection into a reservoir.1 The CO2 transportation chain is usually categorized into two distinct processes (Figure 1). The upper stream of Figure 1 shows transportation of supercritical CO2 using a pipeline. For supercritical CO2 pipeline transportation, the conditioned gas is compressed up to a pressure of 150 bar, either directly or indirectly. Indirect gas compression can include multistage compression, condensation using cooling water, and a liquefaction cycle.2 Up to the 1990s, pipe transportation was the most commonly used method, but more recently focus has shifted to transportation by ship as longer distance transportation is now often required. The bottom stream indicates such a ship transportation process with an intermediate storage terminal. For transportation by ship, the gas is compressed at a pressure of 67 bar and cooled down to near 52 °C. Multistage liquefaction cycles using either CO2 r 2011 American Chemical Society
itself as coolant or an external cooling media have been researched.2 The liquid CO2 resulting from the liquefaction process is subsequently sent to a CO2 intermediate storage terminal.3 Within the CO2 ship transportation process, the intermediate storage terminal serves as a port for CO2 carriers and storage tank. The storage terminal is required within the ship transportation process since it performs as a buffer between the continuous CO2 liquefaction process and discrete marine ship transportation. As discussed in the MHI report, ship transportation is often deemed advantageous when the transportation distance is more than 700 km.4 In many cases, there is insufficient qualified CO2 storage capacity available within 700 km of capture plants. Therefore, ship transportation is typically considered preferable to pipeline transportation for most plants. Although the intermediate storage terminal design is one of the most technologically challenging parts of the ship transportation chain, a detailed storage terminal process has not yet been proposed, with most CO2 transportation studies primarily covering the connection between transportation and sequestration. A pipeline transportation and cost analysis depending upon the pipe diameter has been published by Skovholt5 and Vandeginste et al.6 Aspenlund et al.2 and Umberto Desideri et al.7 each provided general guidelines for the ship transportation process. However, none of these publications has offered a detailed CO2 transportation process for ship transportation. In this paper, a temporary CO2 storage terminal with a ship loading system is simulated with Aspen Hysys. The storage terminal is mainly composed of four distinct processes: a CO2 input process, a storage tank and loading process, a recirculation process, and a BOG reliquefaction process. The operating conditions for each process and its optimum design specification are investigated throughout the paper. Finally, BOG generation Received: April 10, 2011 Accepted: November 3, 2011 Revised: October 24, 2011 Published: November 03, 2011 389
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Figure 1. CO2 transportation chain.
400500 ppm, and Aspenlund et al.2 recommends water being removed to only 50 ppm. Several assumptions are made on the pipeline and storage tank system according to known geological information. The total length of the input pipeline from the liquefaction plant to the storage tank is assumed as 5 km based on the distance between the Young-Nam coal power plant and the East Sea in the Republic of Korea. The distance between the storage tank and the ship loading system is assumed to be 1 km. Consequently, the 1 km of loading pipeline length is adopted in this study. Both the elevation of input and the recirculation pipelines are assumed equivalent to the tank height as both streams enter the storage tanks at the top. The elevation of the loading pipeline is assumed to be 20 m including the loading arm height. The spherical storage tanks are assumed to be installed above the ground, so their elevation is equal to the diameter of the tanks. It is also assumed that the storage tanks are manufactured from carbon steel and have a thickness of 50 mm.4 Glass wool with high elasticity12 is used for the pipeline and tank insulation. The thermal conductivities of carbon steel and glass wool are directly taken from the literature.13 The surface temperature at the outer shell of both systems is chosen as 25 °C. Our model also assumes that the storage system is operated as CO2 storage and CO2 ship loading scenarios. In the former scenario, the liquid CO2 accumulates inside the storage tank owing to the continuous CO2 feed, and a small fraction of the liquid CO2 is recirculated to maintain cryogenic conditions inside the loading pipeline. In the case of the latter scenario, the stored CO2 is sent to the transportation ship while the liquid CO2 is continuously fed into tanks. For the ship loading scenario, the same amount of liquid CO2 is also recirculated in order to maintain the necessary cryogenic conditions inside the returning recirculation pipeline. The change in the convective heat transfer coefficient resulting from the level change inside of the tank is considered to be negligible. Operation parameters for the BOG reliquefaction system are taken from Aspenlund et al.2 The polytropic efficiency of compressors and adiabatic efficiency for the pumps are 82% and 85%, respectively. It is also assumed that seawater is available at 15 °C and the minimum internal temperature approach (MITA) is 5 °C for BOG gas stream cooler. Furthermore, no pressure drop is set for the flash separator. The BOG loss to the atmosphere is set at 0.1% of the molar flow rate of the input stream when the BOG is generated in any circumstances.
Figure 2. Experimental and simulated result of CO2 density change in the vapor phase.
cases featuring improper insulation are also researched, and their operation energy is compared with the normal condition operation energy requirements.
2. PROPERTY METHOD AND ASSUMPTIONS Herein, Aspen Hysys, commercially available software, is used as a process simulator. Since the liquid CO2 input stream is not a pure component but a mixture of CO2, H2O, and N2, the equation of state (EOS) is commonly used in order to predict a phase diagram of the CO2 mixture. The BWRS, PR, PR-BM, and SRK equations were evaluated at 220 K.8 With experimental data reported by Duschek et al.,9 the SRK equation predicted the phase behavior of pure CO2 most precisely (Figure 2). Furthermore, a number of previous reports dealing with a low-temperature and high-pressure CO2 mixture also use the SRK equation.2,10 Austegard et al. performed solubility modeling of H2O in CO2rich phase, covering pressure between 0 and 3500 bar, and the SRK model predicted H2O and CO2 mixture rigorously.11 Therefore, the SRK equation was employed for the entire storage terminal process simulation. The composition of the liquid CO2 input stream coming into the storage system was referred from that reported by Aspenlund et al., namely, 99.97% CO2, 0.03% of nitrogen, and 50 ppm water.2 It is assumed that most contaminants are removed before the CO2 liquefaction process. Water is usually removed before and during the CO2 liquefaction process in order to avoid gas hydrates, the freezing of water, and corrosion. Austegard et al.11 reported water contents should be reduced to levels of approximately
3. DESIGN BASIS The principle basis for the storage terminal design is that the CO2 stream should be kept in a liquid phase for the entire process. 390
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Cryogenic liquids such as liquid CO2 rapidly expand on evaporation; when CO2 expands at 220 K, the fully vaporized CO2 occupies approximately 80 times the volume of liquid CO2. This volume change can occur almost instantaneously, and such an expansion can result in serious damage to the storage system causing, for example, pipeline fractures and tank explosions. The operation pressure of the tank is set at a level at which the liquid state of CO2 can be securely maintained. Commercially available large capacity tanks are usually operated within the pressure range 57 bar.4 In order to maintain the CO2 in the liquid phase in the storage tank, pressure must be kept between the input stream pressure, 6.5 bar, and 7 bar. Operation pressures
lower than 6.5 bar may not secure the liquid phase through small disturbances, and higher operating pressures increase the tank construction costs significantly.14 The corresponding operation temperature is selected at the equilibrium temperature of the phase diagram. Figure 3 shows the CO2 phase diagram with 0.03 mol % of N2. The dashed line inside of the liquid phase indicates the operation limits of the storage terminal. The operation pressure is bounded by the liquid CO2 input pressure to the highest pumping out pressure of the pipeline system. Barrio et al. indicated that a CO2 liquefaction plant delivers CO2 at 6.5 bar.15 The pumping out pressure is decided on the input pump, which compensates for both pressure drops along the loading pipeline and pressure differences between the input pipeline and the tanks. The operation temperature limits for the pipeline are chosen to maintain a 5% safety margin, and those of the tanks are found on the equilibrium line. The operation temperature ranges at the corresponding pressures are given in Table 1.
4. PROCESS DESIGN The liquid CO2 storage tank design is carried out by the following procedures: tank and pipe design, total heat flow calculation, insulation thickness calculation, pump operation, recirculation process design, and reliquefaction process design. 4.1. Tank Capacity and Pipe Design. The tank specifications, such as diameter and thickness, are presented based on those known in the literature.4 The maximum capacity of a single tank which withstands the inner pressure of 7 bar may reach approximately 20 000 m3 with current manufacturer’s capability.4 The number of required storage tanks is calculated according to the shipping schedule and the liquid CO2 input flow rate. The liquid CO2 input flow rate, 20 000 ton/day, is used for the storage tank quantity calculation. This is equivalent to the output from about 1000 MW of the coal-fired power plant or 2200 MW of the natural gas combined cycle plant with postcombustion capture.4 The shipping schedule of CO2 carriers with 30 000 m3 capacity is indicated in Figure 4. In this figure, the required capacity for the storage tank reaches up to 40 000 m3 with seven transportation ships. Accordingly, two 20 000 m3 storage tanks are used for process simulation.
Figure 3. Phase diagram and operation limits of the storage terminal.
Table 1. Operation Limits of Storage Terminal lower bound
upper bound
storage tank
pressure
temperature
pressure
(bar)
(°C)
(bar)
temperature
(bar)
temperature
6.5
56.34
17.2
25.9547
7
49.51
51.63
pressure
54.99
Figure 4. Schedule of ship transportation (3000 km, 30 000 ton, 15/16 kn):4 (a) CO2 loading from the terminal to the ship, (b) CO2 unloading from the ship at the reservoir, (c) ship transportation from the terminal to the reservoir, and (d) ship returning from the reservoir to the terminal. 391
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the temperature increase due to the heat influx is used for the contiguous segment heat flux calculation. The convective heat transfer coefficient may change according to the operation scenario even though its variation should not be overly significant. For instance, when the ship loading is taking place, the liquid CO2 may flow through the storage tank faster than the CO2 storage scenario. The faster the liquid CO2 flow rate, the higher the convective heat transfer coefficient of the liquid CO2 inside the tank can be achieved. This higher convective heat transfer leads to a higher overall heat transfer coefficient and eventually results in more heat flux entering the storage tank. For safe operation of the storage terminal, a high convective heat transfer coefficient number is assumed. As a result, the convective heat transfer coefficient contribution on calculating the overall heat transfer coefficient can be ignored and the consequent maximum heat flow is used throughout the simulation. 4.3. Insulation Thickness Calculation. The tank and pipeline insulation values are computed based on the total amount of heat transfer. Since the overall heat transfer coefficients for both scenarios are assumed the same, the total amount of heat transfer is also considered the same for both. Additionally, a trade off exists between the pipeline and the tank insulation thicknesses. The thicker the pipeline insulation, the thinner the tank insulation is required to keep the total amount of heat transfer remaining constant and vice versa.
Table 2. Parameters for Pipe Calculation flow rate,
density,
viscosity,
Q m (kg/h)
F (kg/m3)
μ (Pa 3 s) 0.23
input pipe
833 333
1157.7
loading pipe
3 531 127.2
1148.4
0.23
recirculation
436 807.6
1148.4
0.23
pipe
For the pipe diameter calculation, eq 1, proposed by Zhang et al. is used16 0:45 Qm Dopt ¼ 0:363 F0:13 μ0:025 ð1Þ F where Dopt, Q m, F, and μ are the optimized pipe diameter (m), mass flow rate (kg/s), liquid density (kg/m3), and viscosity (Pa 3 s), respectively. Equation 1 is the modified version of the optimum economic pipeline diameter calculation which was originally suggested by Peters et al.17 As the diameter of the pipeline increases, the pressure drop inside of the pipeline as well as the pumping energy decreases. Consequently, the cheapest pipe diameter is not the one with the smallest diameter but the economically calculated diameter with minimum capital and operation cost.6 With the calculated optimum pipe diameters, corresponding nominal pipe sizes (NPS)13 are selected, and these pipe sizes are used for terminal simulation. The parameters given in Table 2 are used in the pipe diameter calculation. The mass flow rate of the input, recirculation, and loading pipe flow rates are decided based upon the design specification. The density and viscosity of each stream in the pipe are calculated using Aspen Hysys. The recirculation flow rate is the minimum flow rate of which the vapor phase of CO2 does not generate inside of the recirculation pipe. The loading pipe flow rate is simply calculated by dividing the total volume of the tank on the ship by the loading time. 4.2. Total Heat Flow Calculation. Total heat flux is calculated over the pipe and storage tank. Equations 2 and 3 represent the overall heat transfer coefficient calculation for the pipe and storage tank, respectively 1 1 lnðr1 =r0 Þ lnðr2 =r1 Þ þ þ r0 h0 k01 k12
U0, pipe ¼ r0
U0, tank ¼ r0 2
1 1 ðr1 r0 Þ ðr2 r1 Þ þ þ r0 2 h0 k01 r1 r0 k12 r2 r1
dQ ¼ U0 ΔTdA
min Vtotal ðxÞ ¼ VP1 ðx1 Þ þ VP2 ðx2 Þ þ VP3 ðx3 Þ þ Vtank ðxtank Þ Sub: to x1 , x2 , x3 , xtank g 0 VP1 , VP2 , VP3 , Vtank g 0
ð5Þ
Equation 5 indicates that the objective function of calculating the optimum insulation thickness, where x1, x2, x3, and xtank and VP1, VP2, VP3, and Vtank represent the insulation thickness and its volume of the input pipe, loading pipe, recirculation pipe, and storage tank, respectively. In order to solve eq 5, the nonlinear programming algorithm solver with an external simulator was used. 4.4. Pump Operation. Input, loading, and recirculation pumps are used for the entire storage terminal process. The input pump compensates for both pressure drops along the 5 km pipeline and pressure differences between the feed and the storage tank. For the same reason, a loading pump is also installed at the beginning of the loading pipe. Since the elevation of the recirculation stream is equal to the storage tank height, while that of loading pipe is only about 2/3 of that, the pressure at the end of loading pump is not sufficient to overcome the recirculation stream elevation. Therefore, an additional recirculation pump needs to be installed at the end on the loading pipe (beginning of recirculation returning path). The pressure at the end of the recirculation pipe should be identical to the pressure at the end of the input pipe. 4.5. Recirculation Process Design. In order to maintain the CO2 mixture in the liquid phase throughout the process, both the pipeline and the tank temperature should be kept within the operating limits using the recirculation process. In most cases, when the liquid CO2 is loaded to the transportation ship, the temperature increase caused by heat flux from the environment is negligible due to its large flow rate. However, if the pipe is kept empty while the ship loading does not take place (idle interval), the temperature inside of the pipe can increase up to almost ambient temperature. Under these circumstances, the liquid CO2 can be vaporized rapidly on introduction to the loading pipe.
ð2Þ
ð3Þ
ð4Þ
where U, h, and k represent the overall heat transfer coefficient (W/(m2 3 K)), convective heat transfer coefficient (W/(m2 3 K)), and thermal conductivity (W/(m 3 K)). Radii of the pipe and spherical tanks are indicated in Figure 5. The heat flow into the spherical tank can be calculated by simple integration using the overall heat transfer coefficient. However, the heat flux of the pipeline calculated through simple integration at constant temperature differences can be inappropriate because the temperature gradient gradually decreases as the pipe length increases. In order to solve this problem, the pipeline is segmented and the new temperature gradient reflecting 392
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Figure 5. Structure of the pipe and storage tank.
Figure 6. Process flow diagram of the intermediate CO2 storage terminal system.
This BOG generation inside of pipelines may bring both the operation energy increments and the safety problem such as pipe fracture or explosion. Additionally, the frequent temperature change of the pipeline can also reduce the structural durability. As a consequence, the recirculation process, which pumps a small fraction of cryogenic liquid to the loading pipe, is required to keep the pipe temperature within the operation limits. Not only the CO2 storage scenario but also the ship loading scenario require recirculation flow of liquid CO2 through the recirculation pipe. The recirculation flow rate is calculated based on the amount of transferred heat which makes the pipe temperature fall inside the operation limits. As long as the operation temperature of the pipe falls within the operation limits, minimum recirculation is preferred to keep energy usage as low as possible. 4.6. BOG Reliquefaction Process Design. The storage terminal requires a BOG reliquefaction system to control the amount of gaseous CO2 generated from the storage tank. Insulation failure or sudden increases in the atmospheric temperature can cause larger heat flux entering the system than the total bearable heat for the system, eventually generating BOG in the storage tank. When the BOG generation is higher than that permissible under environmental regulations, a reliquefaction
process is required to capture the vaporized CO2. In this process, the BOG is captured at the top of the tank and sent to compressors. Using multistage compressors, the CO2 gas is compressed to near the critical pressure and cooled to room temperature using an ambient or seawater cooling cycle. The product stream is, then, sent to the JouleThomson valve and expended to the pressure inside of the tank, 7.5 bar. A flash column is used for phase separation. The liquid stream from the flash is recycled to the storage tank, and the gas stream is recycled back to the compressor until the flow rate of the stream reaches 0.1% of the CO2 input stream.
5. RESULT AND DISCUSSION 5.1. Base Case Design. Figure 6 indicates the base case process flow diagram of the liquid CO2 storage terminal. Both ship loading and storage scenarios operate under the same process structure. The storage terminal is mainly composed of four distinct processes: a CO2 input process (1, Figure 6), a storage tank and loading process (2, Figure 6), a recirculation process (3, Figure 6), and BOG reliquefaction process (4, Figure 6). Calculation and design for each part is presented below. 393
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in Figure 7), most of the CO2 flows into the ship through the loading arm (point 7b in Figure 7) and the rest of the CO2 stream is pumped (point 7a in Figure 7) and recirculated (point 8 in Figure 7) through the elevated pipeline (point 9 in Figure 7). The total amount of CO2 loading stream coming out of the tanks is 3209 ton/h. The recirculation flow rate is decided based on the amount of transferred heat into the recirculation. The recirculation streamflow rates are calculated at 115 ton/h. In this scenario, no compression work is required for the BOG reliquefaction system as the amount of BOG generation is less than the reliquefaction criteria. 5.1.2. CO2 Storage Scenario. The CO2 storage scenario also shows the same behavior as the previous scenario until the input stream reaches the storage tank (points 15, Figure 8). For the recirculation, part of the stored CO2 flows out of the tank and is pumped to 13 bar (point 6, Figure 8). The CO2 loading stream to the transportation ship does not flow through the loading pipe in this scenario. As a result, a comparably smaller amount of the liquid CO2, 480 ton/h, is circulating through the loading pipe. The recirculation flow rate difference comes from the difference of the temperature increment of the end of the loading pipe. The temperature at the end of the loading pipeline is about 1 °C higher than that of the liquid CO2 ship loading scenario (point 7, Figure 8). The recirculation stream subsequently flows into the recirculation pipe (point 8, Figure 8) and is sent back to the tank through the elevated pipeline (point 9, Figure 9). 5.2. Case Studies. The BOG generation cases, which are caused by increased heat flux entering the terminal, are performed as a separate case study. The heat flux can be increased by changes in ambient temperature or insulation failure. In our case study, insulation failure on both the pipe and the tank is researched. 5.2.1. One Percent BOG Generation Due to Thin Pipeline Insulation. The behavior of the storage terminal when an insulation failure occurs on the pipelines is researched as this case study. Figure 9 indicates the operational limits and simulated operation pathway of the terminal. For this scenario the insulation thickness along the input pipe is set as 1.26 cm and total heat flow into the pipeline increases to 5.0 GJ/h. As a result, about 1% of input CO2 stream is vaporized as BOG inside of the tank. The liquid CO2 stream from the liquefaction plant pumps to the same pressure as the base case (points 1 and 2). However, with the higher heat flux the temperature increases to 48.4 °C (point 3). Through the elevated pipeline (point 4) the CO2 stream flows into the pressurized tank and the corresponding operation temperature falls on the equilibrium line (point 5). BOG generation affects both the CO2 loading stream composition and the recirculation conditions. The composition of the CO2 loading stream changes due to the different solubility of H2O and N2 in liquid CO2. Since N2 has lower solubility in liquid CO2, the mole fraction of the N2 in BOG is higher than that of the input stream. Consequently, the CO2 concentration of the loading stream increases to 200 ppm. This composition change eventually causes the vapor liquid equilibrium line to shift to the right-hand side. Therefore, the operation limits from 7 bar (pressure of the tank) to the upper bound are different from the base case. More pumping energy is required for the recirculation pipeline than in the base case as a larger amount of recirculation stream is essential to maintain the temperature within the operation limits. For CO2 loading and recirculation, a similar procedure is performed to the base case. The loading stream pumps to 13.1 bar (point 6) in order to compensate for pressure drops along both the loading and the recirculation pipe (points 79). The
Figure 7. Operation path of the storage terminal of the liquid CO2 ship loading scenario: (a) overall CO2 flow path during the liquid CO2 ship loading scenario and (b) operation path along the loading and recirculation pipe.
Table 3. Pipe Diameters and Corresponding Pressure Drop along the Pipes diameter corresponding
insulation
pressure
from
NDS diameter
thickness
drop
eq 1(m)
(m)
(cm)
(bar)
input pipe
14
14
4
9.6
loading pipe recirculation pipe
26.9 10.53
28 10.75
3 4
0.41 3.9
5.1.1. Liquid CO2 Ship Loading Scenario. The input stream from the CO2 liquefaction process supplies at 6.5 bar, 52 °C15 (point 1 in Figure 7), and then the stream pumps to 17.1 bar (point 2 in Figure 7) to compensate for both the pressure drop along the input pipeline and the pressure differences between the pipeline and the storage tank. The calculated diameters using eq 1 and the corresponding pressure drop are listed in Table 3. After passing the pipeline (point 3 in Figure 7), the input stream splits into two streams and flows into storage tanks through elevated pipeline (point 4 in Figure 7). The storage tanks are maintained at 7 bar throughout the process (point 5 in Figure 7), and the optimum insulation thickness is 11 cm. For CO2 ship loading, the loading stream from the tank is pumped to 10.17 bar (point 6 in Figure 7). At the end of the loading pipeline (point 7 394
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Figure 8. Operation path of the storage terminal for the CO2 storage scenario.
Figure 9. Operation path of the storage terminal with the pipeline insulation failure scenario.
pressure drop which occurs along the loading and recirculation pipe is higher than the base case due to the flow rate increase. However, the pressure at the end of the recirculation pipe and temperature drop is different from the base case. The pressure at the end of the recirculation pipe is 7.5 bar (point 9), and the corresponding temperature is 47.9 °C. The quantity of evaporated gas is 1 mol % of the input stream. As it is assumed that only 0.1% of BOG can be purged as BOG, additional compression work is required. The total multistage compressor work is calculated to be 2.21 KWh/Ton CO2. 5.2.2. One Percent BOG Generation Due to Thin Storage Tank Insulation. The BOG generation incident which is caused by more heat coming into the storage tank is also performed as a case study. In this case, the pipeline is properly insulated but the heat flow into the storage tank increases owing to the thin tank insulation. The insulation thickness of the tank is set at 8.12 cm, and with these insulation parameters the total heat flow into the tank is 3.8 GJ/h.
Figure 10 indicates the operation line and the simulated operation pathway of the terminal of case study 2. Up to the end of the input pipeline the operation pressure and temperature is the same as the base case (points 14). As the heat flux into the storage tank is far greater than that of the base case, approximately 1% of the input stream evaporates as BOG. The same phase diagram shift also occurs at the storage tank owing to the BOG generation. Using the loading pump the recirculation stream is pressurized to 13.7 bar (point 6). The temperature change along the loading pipe is similar to that of case study 1 owing to the same amount of heat flow coming into the system. The recirculation flow rate is also the same as in case study 1, and the pressure at the end of the recirculation is calculated in order to satisfy operation limits (7.5 bar, point 9). 5.2.4. Total Work Based on the Case Study. The total energy required for case studies with improper insulation is about three times that of the base case CO2 storage scenario. Figure 11 shows 395
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Figure 10. Operation path of the storage terminal process with tank insulation failure.
Figure 11. Total operation energy according to the operation scenarios.
the total energy consumption on each simulation case. Between the base cases only loading pump duty is different because of the CO2 loading flow rate differences. Since the BOG generation is negligible, no compression work is required for the base cases. The net work increment of loading pumps for the pipe insulation and tank insulation failure cases is negligible. Since the amount of the BOG generation is the same for both study cases, the compression works are the same for both cases (0.89 KWh/Tonne CO2).
6. CONCLUSION In this study, an intermediate liquid CO2 storage terminal for the CO2 ship transportation system is designed. The storage terminal is composed of four distinct processes: the CO2 input process, the storage tank and loading process, the recirculation process, and the BOG reliquefaction process. The sizes of the pipeline and spherical storage tank are calculated based on the 20 000 ton/day liquid CO2 input. In order to maintain CO2 in a liquid phase throughout the terminal, the storage tank and
pipeline should be insulated based on the operation limits. The operation pressure of the pipeline and tank should be kept within 6.517.2 and 6.57 bar. Furthermore, the loading pipe is kept under necessary cryogenic conditions by continuously recirculating stored liquid CO2. Throughout this study the gas CO2 purge ratio is kept at less than 0.1 mol % of the liquid CO2 input. The base case scenarios generate BOG less than the design criteria, and their operation energy consumption is the lowest among the cases. The use of inappropriate insulation on the system may cause a dramatic increase in operation energy demands owing to large amounts BOG generation and consequent compression work in the reliquefaction system. With 1% of input stream BOG generation owing to insufficient insulation, the total operation work increases 3-fold that of the base case.
’ AUTHOR INFORMATION Corresponding Author
*Tel.: 82-2-880-1887. E-mail:
[email protected]. 396
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’ ACKNOWLEDGMENT The authors gratefully acknowledge the Korea Science and Engineering Foundation provided through the Advanced Environmental Biotechnology Research Center (No2011-0001114), the Brain Korea 21 Project initiated by the Ministry of Education of Korea (ME), the Energy Efficiency & Resources and Human Resources Development of the Korea Insitute of Energy Technology Evaluation and Planning (KETEP) grant funded by the Ministry of Knowledge Economy (MKE), the Industrial Strategic Technology Development Program Design of topside LNG regasfication plant of LNG FSRU (10031883) by the MKE, and the LNG Plant R&D Center funded by the Ministry of Land, Transportation and Maritime Affairs (MLTM) of the Korean government.
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dx.doi.org/10.1021/ie200762f |Ind. Eng. Chem. Res. 2012, 51, 389–397
