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Development of CO2 terminal and CO2 carrier for future commercialized CCS market
International Journal of Greenhouse Gas Control 12 (2013) 323–332
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International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
Development of CO2 terminal and CO2 carrier for future commercialized CCS market Byeong-Yong Yoo ∗ , Dong-Kyu Choi, Hyun-Jin Kim, Young-Sik Moon, Hee-Seung Na, Sung-Geun Lee DAEWOO Shipbuilding & Marine Engineering Co., Ltd., 85, Da-Dong, Jung-gu, Seoul 100-180, Republic of Korea
a r t i c l e
i n f o
Article history: Received 2 July 2012 Received in revised form 20 October 2012 Accepted 6 November 2012 Available online 21 December 2012 Keywords: CCS CO2 carrier CO2 shipping CO2 liquefaction CO2 terminal CO2 transport
a b s t r a c t So far CO2 shipping has only been introduced as a secondary option for long distances and small amounts because of the prevailing idea that CO2 shipping is more expensive than CO2 pipeline for transporting large amount CO2 . This paper shows that CO2 terminal and large CO2 carrier can play a role of collecting CO2 from several sources and transporting CO2 in large volume so transport cost per tonnage of CO2 can be reduce in commercialized CCS market. Multi-stage CO2 liquefaction processes are developed to reduce total cost of CO2 compression and transport. For high pressure CO2 inlet stream, newly developed multistage liquefaction process with serial flash tanks enables power consumption reduced to 44% compared to single stage liquefaction process. By adopting new design concept of very large CO2 Carrier more than 40,000 m3 , optimal size of CO2 carrier can be provided for each voyage route and total cost of CO2 compression and transport is reduced. The results of economic assessment of CO2 transport show that CO2 shipping is economically competitive to CO2 pipeline even in the distance of 200–300 km for large amount of CO2 transport such as 10 Mt CO2 /year or 20 Mt CO2 /year. CO2 transport by ship should be seriously re-considered as an effective transport method for commercialized CCS projects as well as early demonstration projects. © 2012 Elsevier Ltd. All rights reserved.
1. Introduction Intergovernmental Panel on Climate Change (IPCC) (2005) introduced CO2 shipping was typically cheaper than pipelines for distances greater than approximately 1000 km and for amounts smaller than a few million tones of CO2 per year. Chiyoda Corporation et al. (2011) estimated total CO2 shipping cost with 200 km transport distance but the amount of CO2 was limited as 1 Mt CO2 /year. Barrio et al. (2004) and IPCC (2005) assessed CO2 transport cost with single-source and single sink connection. However, in commercialized CCS market, it would be more probable that multi-sources and/or multi-sinks network was utilized to transport large amount of CO2 cost-effectively. Recently, Global Carbon Capture and Storage Institute (GCCSI) (2011) published a knowledge sharing report on complete logistical transportation solution for Rotterdam area and introduced liquid logistics shipping concept (LLSC) to provide CO2 emitters with a complete logistical transport solution from several CO2 sources to offshore storage location. The LLSC adopted the concept of CO2 hub or terminal, which included compression facility, liquefaction facility and temporary storages.
∗ Corresponding author. Tel.: +82 2 2129 3609; fax: +82 2 2129 3670. E-mail address: [email protected] (B.-Y. Yoo). 1750-5836/$ – see front matter © 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.ijggc.2012.11.008
About 3 Mt CO2 /year of CO2 from Rotterdam area was expected to be transported by ship to offshore storage. The European Technology Platform for Zero Emission Fossil Fuel Power Plants (ZEP) (2011) published a report on CO2 transport, which included transport networks consisting of pipeline, ships, and terminal. Although CO2 shipping was considered as a part of the transport network in these reports, CO2 shipping was still considered only for long distance and small amount of transport. This paper seeks to introduce the concept of CO2 terminal and large CO2 carrier available for commercial CCS market. The aim of this paper was to evaluate the feasibility of CO2 shipping as a solution of CO2 transport in commercial project as well as demonstration project.
2. CO2 shipping chain description 2.1. CO2 transport scenario Fig. 1 shows the assumed scenario in this study, which is similar to CO2 network models in ZEP (2011). CO2 cluster A comprises 5 Mt CO2 /year CO2 source and 2.5 Mt CO2 /year CO2 source, which is located near offshore storage so CO2 at cluster A is to be injected into the offshore storage directly. CO2 cluster B is connected with several CO2 sources and collecting point of CO2 cluster B is located
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CO2 cluster A Source A.1
2.5 MtCO2
/year Source A.2
Land or Sea CO2 cluster B
5 MtCO2
/year
Sea 20 MtCO2 /year 30 MtCO2 /year 180 km 500 km 750 km
offshore storage
10 MtCO2 /year 20 MtCO2 /year
0 km 100 km
750 km
2.5 MtCO2
/year Source C
Fig. 1. Distribution of CO2 sources and sink in the assumed scenario.
away from the offshore storage. CO2 source C is located 750 km away from the CO2 cluster A. Captured CO2 at source A.1 is transported by pipeline to the source A.2, which is located in coastal area. Captured CO2 at the cluster B are all transported to a collecting point on the shore through each pipeline. In this paper, 180 km, 500 km and 750 km are considered as the distance between cluster A and B, which could be separated by either land or sea. Since there is no offshore storage near the cluster B, 10 Mt CO2 /year or 20 Mt CO2 /year of CO2 captured at cluster B is transported to cluster A. Three alternatives of transport solutions are considered connecting cluster A with B; onshore pipeline, offshore pipeline and shipping. For pipeline transport, backbone pipeline is installed between cluster A and B. For shipping, CO2 terminals are installed on the shore at cluster A and B, which includes CO2 storage tanks, loading and unloading system and, if necessary, CO2 liquefaction plant. Since CO2 source C is located 750 km away from the cluster A, 2.5 Mt CO2 /year of CO2 captured at source C is shipped to cluster A. Totally 20 or 30 Mt CO2 /year of CO2 collected at cluster A is injected into offshore storage through backbone pipeline or large CO2 carrier (Fig. 2). 2.2. CO2 transport chain CO2 transport between cluster A and B is from the outlet of capture and CO2 conditioning process to the inlet of the booster pump or injection pump of CO2 terminal at the cluster A. Four (4) cases of CO2 transport methods are considered. • Case 1. Onshore pipeline and Case 2. Offshore pipeline CO2 gas at each source at cluster B is compressed and transported to CO2 terminal through pipeline. If necessary, booster
pump is installed in the CO2 terminal at the cluster B and CO2 is compressed again and transported to CO2 terminal A through onshore/offshore backbone pipeline. The captured CO2 , at 0.1 MPa and 35 ◦ C, is compressed to 11 MPa in this study (Fig. 3). Supercritical pipeline has a benefit of avoiding phase transient problem and using small size pipeline without booster compression stations. It requires more compression power at the emitter site but it could be more economical for long distance transportation than transportation in subcritical regime. • Case 3. CO2 shipping from onshore CO2 sources close to CO2 terminal. When CO2 terminal can be constructed near CO2 emission, captured CO2 would be immediately liquefied, transported into temporary storage tanks and then loaded into ship (Fig. 3). This case could be applied into some of CO2 sources such as coal power plant, LNG power plant and steel industry, because some of them are located in coastal areas to receive fuels or raw materials by ships. As the volume of liquefied CO2 is about one-600th the volume of gaseous CO2 in the standard condition, substantially CO2 is to be liquefied first and it should be temporarily stored in large storage tanks before loading. For continuous injection, unloaded CO2 at CO2 terminal A also should be temporarily stored in large tanks. The captured CO2 , at 0.1 MPa and 35 ◦ C, is initially compressed to 0.683 MPa and then liquefied to −50 ◦ C. • Case 4. CO2 shipping from inland CO2 sources away from the CO2 terminal. Captured CO2 in land is to be compressed and transported to onshore CO2 terminal. In this study, captured CO2 is assumed to be compressed to 11 MPa and depressed by 1 MPa through pipeline to the liquefaction plant onshore. For CO2 shipping, supercritical CO2 at 10 MPa is depressurized and liquefied at
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325
CO2 cluster A Source A.1 2.5 MtCO2
/year Source A.2
Land or Sea
5 MtCO2
CO2 cluster B
/year
CO2 Terminal
Ship
Sea 20 MtCO2 /year 30 MtCO2 /year
180 km 500 km 750 km
Ship
10 MtCO2 /year 20 MtCO2 /year
0 km 100 km
CO2 Terminal
Ship
offshore storage
750 km
2.5 MtCO2
/year Source C
Fig. 2. CO2 transport network model in the assumed scenario.
−50 ◦ C to be stored in storage tanks at CO2 terminal and then loaded into ship.
3. Chain components 3.1. Initial compression
Fig. 3 shows simple diagram of the composition of each CO2 transport chain. For all the cases, cooling water temperature is 7 ◦ C and the temperature at the discharge of inter-cooler is assumed to be 20 ◦ C. Case 1 0.1 MPa 35˚C
11 MPa
compression
pipeline
Case 2 compression
Case 3
pipeline
To injection pump
Backbone pipeline sea
CO2 terminal at cluster A
ship
temp. storage
Sea
CO2 terminal at cluster A
-50 ˚C
liquefaction
CO2 source at cluster B
temp. storage
CO2 terminal at cluster B
Case 4 0.1 MPa 35˚C
CO2 terminal at cluster A
11 MPa
CO2 source at cluster B
0.1 MPa 35˚C
To injection pump
Backbone pipeline land
CO2 source at cluster B
0.1 MPa 35˚C
For the cases 1, 2 and 4, two different options are considered to compress CO2 into 11 MPa. One option is to compress CO2 by
-50 ˚C
11 MPa
compression
CO2 source at cluster B
To injection pump
pipeline
liquefaction
temp. storage
CO2 terminal at cluster B
Fig. 3. CO2 transport chain for four (4) cases.
ship
temp. storage
Sea
CO2 terminal at cluster A
To injection pump
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100.0
100.0
Pressure (MPa)
1000.0
Pressure (MPa)
1000.0
10.0
1.0
1.0
0.1
10.0
0.1 0.00
200.
400.
0.00
600.
200.
Enthalpy(kJ/kg)
400.
600.
Enthalpy(kJ/kg)
(a) Compression only option
(a) Liquefaction option Fig. 4. Compression path on P-h diagram.
5-stage compressor and inter-stage cooling and the other option is to compress CO2 to 5.84 MPa by 4-stage compressor, liquefy CO2 by water cooling and then finally compress liquid CO2 to 11 MPa by high pressure pump. Fig. 4 shows the P-h diagram of both compression options. Table 1 shows power consumption of both two compression options for transporting 10 Mt CO2 /year of CO2 . The liquefaction option consumes less power and less number of compressors, which is same as the result of Botero et al. (2009). This study adopts the liquefaction option for the cases 1, 2 and 4. For the case 3, CO2 at atmosphere pressure is compressed to the saturation pressure at the liquefaction temperature −50 ◦ C using 2-stage centrifugal compressors with inter-stage cooling. 3.2. Liquefaction The efficiency of CO2 liquefaction process is dependent on CO2 inlet stream condition and CO2 outlet stream condition. Since the CO2 inlet condition of cases 3 and 4 is quite different, liquefaction processes optimized for each case are developed in this study and the liquefaction temperature of CO2 outlet stream is fixed at −50 ◦ C. 3.2.1. Liquefaction process for case 3 The CO2 inlet stream of liquefaction process is at atmosphere pressure and 35 ◦ C. CO2 inlet stream is compressed to 5.8 MPa by multi-stage compressor and inter-coolings. At the highest pressure, CO2 is liquefied by seawater cooling. Liquid CO2 is depressurized by expansion valve and separated in serial flash tanks. Flash gas is recycled to the forward stage of multi-stage compressor. Liquid CO2 is drained to another expansion valve and flash tank. Three serial steps of flash process are applied for liquefying CO2 at
−50 ◦ C. For transporting 10 Mt CO2 /year of CO2 , calculated power consumption for the initial compression is 49.9 MW and that of liquefaction process is 71.4 MW. 3.2.2. Liquefaction process for case 4 In case 4, captured CO2 is already compressed to 11 MPa and it is assumed that the pressure is decreased to 10 MPa through pipeline. The CO2 inlet stream of liquefaction process is 10 MPa and 20 ◦ C. The Fig. 5 shows the newly developed process model to liquefy high pressure CO2 using CO2 feed as the refrigerant. CO2 inlet stream is depressurized to the saturation pressure at the liquefaction temperature of −50 ◦ C through serial flash tanks. Flash gas is recompressed and recycled by additional compressors. Liquid CO2 is drained to next flash tank. Serial three steps of flash process are applied for liquefying CO2 at −50 ◦ C. Fig. 5 shows schematic diagram of the liquefaction process for the case 4. For transporting 10 Mt CO2 /year of CO2 , calculated power consumption of liquefaction process is 19.7 MW, which is much less than that of the case 3, but 105.8 MW is already consumed for initial compression stage for transporting CO2 to the liquefaction plant through pipeline. Yoo et al. (2010a) insisted that CO2 liquefaction process, making total CO2 shipping more expensive with large power consumption, was another form of CO2 compression so CO2 transport technology should be assessed with CO2 compression technology and total CO2 shipping cost would be evaluated competitive to pipeline. Fig. 6 shows total power consumption of liquefaction and compression process for transporting 10 Mt CO2 /year of CO2 . CO2 liquefaction process, including initial compression in cases 3 and 4, consumes more power than compression process in cases 1 and 2. However, the gap of power consumption is calculated about 15%, which is
Table 1 Power consumption of compression process. Scenario
Temperature [◦ C] Pressure [MPa]
CO2 inlet
1st stage
2nd stage
3rd stage
4th stage
5th stage
Total power [MW]
Cases 1, 2 and 4 (compression only option)
Temperature [◦ C]
35
124.1
106.3
107.0
108.6
107.8
113.4
Pressure [MPa] Temperature [◦ C]
0.1 35
0.25 131.8
0.65 113.7
1.68 114.7
4.29 116.7
11 n/a
105.8a
0.1
0.27
0.76
2.10
5.84
n/a
Cases 1, 2 and 4 (liquefaction option)
Pressure [MPa] a
Pump power, consumed to compress liquefied CO2 to 11 MPa, is also included in the total power.
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5.8 MPa -55.09 ºC
10 MPa 20 ºC
5.8 MPa 15.15 ºC
5.8 MPa 17.86 ºC
2.82 MPa -7.73 ºC
327
5.8 MPa 20 ºC
2.82 MPa --7.722 ºC
1.368 MPa -30.82 ºC
2.817 MPa 27.53 ºC
1.368 MPa -30.82 ºC
1.368 MPa 4.02 ºC
0.665 MPa -50 ºC 0.665 MPa -50 ºC
Fig. 5. Schematic diagram of the liquefaction process for the case 4.
not so large that additional cost of CO2 liquefaction process does not result in significant cost increase of CO2 shipping not to be competitive to pipeline transport. Fig. 6 also shows that the total power consumption of the case 4 is similar to that of the case 3, which implies that CO2 shipping could be considered as one of potential solutions of transporting CO2 even for inland CO2 source located away from a coast. When CO2 source is located away from the coast, CO2 should be initially compressed to high pressure like 10 MPa. Compared to the case of onshore CO2 source, it results more power consumption in initial compression but, since the CO2 inlet stream to liquefaction process is already at high pressure, it consumes significantly reduced power. In addition, in this study, CO2 liquefaction process, using serial flash tanks and compressors, is newly developed suited for liquefying at high pressure. The power consumption of newly developed liquefaction process is about 44% of one of singe stage CO2 liquefaction process in Fig. 7. 3.3. Temporary storage as CO2 export terminal
Power consumption [MW]
In total CCS system, CO2 is captured continuously from CO2 emission sources but CO2 shipping is discrete process. Therefore
temporary storage as CO2 terminals would be located between liquefaction plant and ships, which functions as buffer tank before loading CO2 into a ship. Table 2 shows the size of CO2 carrier and temporary storage in CO2 terminal for each CO2 flow rate and distance between cluster A and B. The size of the temporary storage, which was expressed as buffer storage by ZEP (2011), was 100% of ship size. Barrio et al. (2004) and Berger et al. (2004) assumed the capacity of temporary storage was 150% of the ship capacity. Bliault et al. (2000) assumed the capacity of floating LNG storage was about 118–148% of LNG carrier capacity to have operational margins. Since CO2 is more non-hazardous fluid than LNG, less or equal margin is enough for buffer volume of temporary storage. 120% of ship capacity was considered in this study, which provided more operational margins than CO2 storage assumed by ZEP (2011) and more cost-effectiveness than CO2 storage assumed by Barrio et al. (2004) or Berger et al. (2004). Temporary storage as CO2 terminal could be installed on land. When land space is limited near liquefaction plants or the cost for land-based plant installation is relatively expensive, floating barge type temporary storage or shore-mounted temporary storage could be adopted. Fig. 8 is a conceptual drawing of barge-type temporary storage adopted in this study. Furthermore, if necessary, liquefaction plant or capture plant would be constructed on the deck of temporary storage to provide new plants the region of limited land space.
Table 2 Size of CO2 carrier and temporary storage for each case.
Case 1 & 2
Case 3
Case 4
Fig. 6. Power consumption of compression and liquefaction process for each case (10 Mt CO2/year).
CO2 volume flow [Mt CO2 /year]
Distance [km]
10
180 500 750
23,000 36,000 46,000
28,000 44,000 56,000
20
180 500 750
46,000 71,000 91,000
56,000 86,000 110,000
a
Size of CO2 carriera [m3 ]
Two (2) CO2 carriers were utilized for each case.
Size of temporary storage in CO2 terminal [m3 ]
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5.8 MPa 135.3 ºC
10 MPa 20 ºC
5.8 MPa 15.15 ºC
5.8 MPa 17.97 ºC
5.8 MPa 20 ºC
0.665 MPa -50 ºC
0.665 MPa -50 ºC
Fig. 7. Reference schematic diagram of the liquefaction process for the case 4.
Horizontal type tanks are installed in the temporary storage when the capacity is relatively small, and vertical type tanks, which are more flexible in arrangement of tanks in barge, are installed for large size temporary storage (Fig. 8). The storage tank is designed to satisfy IGC code (2000), DNV-Rule (2011) and ASME code (2010). The maximum diameter of one tank is 11 m and the maximum length is 36 m. The selection of tank material is significantly affects the cost of temporary storage tanks and this study adopts low temperature carbon manganese steel to save CAPEX of CO2 storage tank. The boil-off gas (BOG) could be increased by heat ingress through the wall and support structure of tanks but the vapor pressure in tanks is designed to maintain constant pressure by re-cycling BOG into CO2 liquefaction process. 3.4. CO2 carrier To commercialize CO2 shipping, it is important to reduce total cost of CO2 shipping, including liquefaction plant, CO2 carrier and temporary storage. The cost of CO2 carrier is dependent on the number and the size of CO2 carriers. The number and the size of ship can be determined considering the voyage distance, voyage time, speed, amount of total cargo for transport in a year and other factors. In addition, for CO2 shipping, additional cost for temporary storage also should be considered together and it affects the number and the size of CO2 carrier suited for a specific CCS project.
Since the size of temporary storage is proportional to the size of CO2 carrier and large pressure tanks, main equipment of temporary storage, are relatively expensive, increase of the size of CO2 carrier results in cost increase in temporary storage. This study considered two kinds of design concept for CO2 carrier and capacity ranges from 23,000 m3 to 91,000 m3 as shown in Table 2. The design speed of CO2 carrier is 15.0 kts in laden voyage and 16.0 kts in ballast voyage. The density of liquid CO2 at −50 is 1.150 ton/m3 and cargo tanks are assumed to be filled by 95% for laden voyage. Two (2) ships are used for each voyage route. Voyage time is calculated for each voyage distance including 4 h for harbour manoeuvring, 12 h for loading operation, and 12 h for unloading operation. For example, voyage time for 500 km is estimated at 2.66 days. One CO2 carrier could travel 129 times for a year, 345 days. Therefore the minimum capacity of a CO2 carrier for transporting 10 Mt CO2 /year is estimated using simple calculation: 10 Mt ÷ two (2) ships ÷ 129 times ÷ 1.150 ton/m3 ÷ 95% = 35,477 m3 . 3.4.1. Conventional large CO2 carrier Yoo et al. (2010b) introduced that CO2 carrier with a capacity of 20,000 m3 or 30,000 m3 was to be semi-refrigerated type and were expected to be very similar to that of semi-refrigerated type LPG carrier. In this study, this design concept, conventional large CO2 carrier concept, is adopted to CO2 carriers with a capacity of 23,000 m3 and 36,000 m3 . Fig. 9 shows a conceptual drawing of CO2
(a) A sketch of midship and section view of floating barge type temporary storage with capacity of 28,000 m3
(a) A sketch of midship and section view of floating barge type temporary storage with capacity of 110,000 m3 Fig. 8. A sketch of a floating barge type temporary storage.
B.-Y. Yoo et al. / International Journal of Greenhouse Gas Control 12 (2013) 323–332
Fig. 9. Conceptual drawing of conventional large CO2 carrier.
Fig. 10. Conceptual drawing of newly developed very large CO2 carrier.
carrier with the capacity of 23,000 m3 , which included horizontal cylindrical type tanks. Six tanks are located in the cargo hold and one tank dimension is maximum 35 m (length) and 11 m (diameter). A cross section of tanks in ship is basically circular in shape, enabling them to withstand strong internal pressure, thus making them ideal for high pressure environments. Since theoretically the more pressure a tank is under, the thicker it needs to be, the size of tank that can be manufactured for this purpose is limited, resulting in an expected large CO2 carrier size of less than 40,000 m3 with current designs for transporting CO2 at −50 ◦ C. The material is same as the one of temporary storage tanks. 3.4.2. Newly developed very large CO2 carrier Yoo et al. (2010b) also described a different type of CO2 carrier with a capacity of 100,000 m3 . In this study, CO2 carriers, with a capacity of 46,000 m3 , 71,000 m3 and 91,000 m3 , adopt newly developed very large CO2 carrier design to transport large amount of CO2 for CCS application. They contain vertical tanks instead of horizontal tanks. As shown in Fig. 10, vertical cargo tanks are more flexible in tank arrangement in a ship so there is no limit in the capacity of ship. Fig. 10 shows newly developed CO2 carrier with the capacity of 91,000 m3 , which includes 91 tanks of 1000 m3 . Unlike other liquefied gas carriers, which installed submerged type pumps in each tank, it is assumed that liquid CO2 will be transported into a pump out of tanks in a separate pump room. Utilization of common pumps enables cost saving by reducing the number of offloading pumps and easier installation, operation and maintenance. 3.5. CO2 Offloading and CO2 temporary storage as an import terminal
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result in cost increase for CO2 shipping with more number of CO2 carriers. Another solution is increasing more number of injection wells even though it also causes cost increase from developing large number of injection wells. Therefore, the number of wells and offloading flow rate could be optimized based on the characteristics of underground storage and shipping conditions. In this study, however, CO2 is injected from another temporary storage as CO2 import terminal near injection site instead of directly injecting CO2 from a ship. Liquid CO2 cargo transported by ship is to be offloaded to the temporary storage and liquid CO2 is continuously injected into underground storage with relatively slow speed. Therefore injection rate would be similar to the flow rate of liquefaction process and CO2 offloading time is relatively short similar to that of existing LNG or LPG carriers. Another benefit of adopting temporary storage as CO2 import terminal is eliminating potential risk of CO2 leak or CO2 hydration during replacing CO2 carriers connected to injection pipeline. When the injection site is near shore, temporary storage as CO2 import harbour could be installed on the shore and relatively short injection pipeline would be connected between temporary storage and underground storage. When injection site is offshore, floating type, submerged type or fixed type such as gravity based structure (GBS) type could be a candidate of temporary storage and the most cost-effective and safe solution should be selected based on accurate data of injection site and project conditions. Temporary storage as CO2 import terminal includes reliquefaction equipment when liquefaction plant is located far from the injection site so gaseous CO2 could not be returned to the liquefaction plant. Boil-off-gas (BOG) of CO2 is compressed to 5.8 MPa by two-stage compressor and CO2 is liquefied by seawater cooling and serial two flash tanks. With the assumption of boil-of-gas rate (BOR) as 0.15%, same as the one of conventional LNG carrier, the power consumption of re-liquefaction facility ranges from 78 to 309 kW according to the capacity of temporary storage. High pressure pump and CO2 heater are main equipments of CO2 injection system. GCCSI (2011) suggested the reservoir inlet (bottom well) should remain above 15 ◦ C to prevent hydrate formation. Assuming that the bottomhole pressure of the reservoir in this study is 10 MPa, Fig. 11, quote from GCCSI (2011), indicated that injection temperature should be kept above about −8.5 ◦ C. For this study, the CO2 stream after injection pump discharge is heated to −7 ◦ C using sea water to avoid hydrate formation at the reservoir inlet. Inland CO2 storage tank would receive necessary power through existing power grid in land. For offshore temporary storage, electric generation equipments would be additionally installed. For transporting 10 Mt CO2 /year of CO2 , power consumption of CO2 injection pump is 3.4 MW and that of sea water pump for heating is 0.6 MW. 3.6. CO2 pipeline There have been several techno-economic models for estimating pipeline sizes and costs, but there is a large degree of variability between the output of the different models. In this study, CO2 transport scenario is developed similar to CO2 networks assumed by ZEP (2011). The diameter and estimated cost of onshore and offshore pipelines adopted by ZEP (2011) is listed in Table 3. 4. Cost comparison study
CO2 offloading and injection is very complex process because they are related with the characteristics of underground storage, site condition, CO2 carrier and injection facilities. CO2 could be directly injected from a CO2 carrier into underground storage. The simplest solution would be injecting CO2 from a ship with slow speed. However, offloading time would be increased and it would
4.1. General assumptions for cost comparison study Pipeline cost was estimated based on the results of ZEP (2011). The construction cost of CO2 carrier and temporary storage was estimated based on concept design by DSME, a shipbuilding
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Fig. 11. Bottomhole temperature as a function of injection temperature, quote from GCCSI (2011).
company, which has been used to design and build similar liquefied gas carriers such as LNG carriers and LPG carriers. For CAPEX calculation, project lifetime and depreciation period was 40 years and interest rate was 8% in this paper, which was same as that of ZEP (2011). Since large size of compressors shared most of cost for initial compression and liquefaction process, CAPEX and OPEX of compressors without other equipments were considered for the cost comparison study on liquefaction/compression technology. The cost was calculated using equations in McCollum’s (2006) study on techno-economic models for carbon dioxide compression. The capital cost of compressor was calculated by following equation and, mtrain is mass flow rate through each compressor train, Ntrain is the number of compressor trains, Pinitial is the inlet pressure of the compressor and Pcut-off is the outlet pressure. The annual operation and maintenance cost and total electric power costs of the compressor were considered for OPEX.
Ccomp = mtrain Ntrain (0.13 × 106 )(mtrain )−0.71 +(1.40 × 106 )(mtrain )−0.60 ln
P
cut-off
Pinitial
compressor was annualized by applying a capital recovery factor (CRF) of 0.15. For long distance pipeline transport in case 1 or 2, booster compressor might be installed but the cost of the additional booster compressors is not reflected in the cost assessment in this study. High pressure CO2 is in supercritical state or liquid state, relatively cheap pump can be utilized to boost CO2 instead of expensive compressor. The CAPEX and OPEX of pump were relatively negligible compared to ones of compressor. The cost for loading/unloading facility and other equipments, which were negligible compared to ones of main equipments of liquefaction process and compression process, were not considered in the study as well. Assuming that construction cost of compression plant and liquefaction plant has the same order, construction cost for compression plant and liquefaction plant was assumed to be offset in the comparison study. In this study, electricity cost was assumed as 0.065 $/kWh and heavy fuel oil (HFO), which was used for CO2 carrier and electric generation in offshore temporary storage, was assumed as $500/tone. 4.2. Economic assessment on CO2 compression and transport strategies
Installation cost would share large portion in total cost of new plants for liquefaction or compression but it was neglected with assumption that installation cost of compression plant and liquefaction plant would have similar amounts. The capital cost for
Fig. 12 shows relative cost for transporting 10 Mt CO2 /year of CO2 . For short distance such as 180 km, onshore pipeline in case 1 and offshore pipeline in case 2 are more cost-effective than
Table 3 Diameter and cost of onshore/offshore pipeline. CO2 volume flow [Mt CO2 /year]
Onshore/offshore
Distance [km]
180
500
750
10
Onshore pipeline Offshore pipeline
Diameter [m] Cost [MUSD/year] Diameter [m] Cost [MUSD/year]
0.6096 26.3 0.8128 43.5
0.6096 70.1a 0.8128 97.8a
0.6096 104.1a 0.8128 142.5a
20
Onshore pipeline Offshore pipeline
Diameter [m] Cost [MUSD/year] Diameter [m] Cost [MUSD/year]
0.5588 33.1 0.6604 57.1
0.6604 89.3 0.8128 124.6
0.6604 132.6 0.8636 181.6
a All values were quote from ZEP (2011) except values with asterisk marks. McCollum (2006) showed that pipeline cost was proportional to the 0.35th power of the mass flow. The values were estimated by multiplying the cost of pipeline for transporting 20 Mt CO2 /year by (10 Mt CO2 /year ÷ 20 Mt CO2 /year)0.35 .
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Fig. 12. Relative cost of CO2 transport (10 Mt CO2 /year).
Fig. 13. Relative cost of CO2 transport (20 Mt CO2/year).
CO2 shipping in cases 3 and 4. For relatively longer distance such as 500 km and 750 km, CO2 shipping is more cost-effective than onshore pipeline as well as offshore pipeline. In addition, the cost difference, between CO2 shipping and offshore pipeline for the transport distance 180 km, is about 13% for 10 Mt CO2 /year transport. Considering large contingency of cost estimation at early stage of CCS technology and cost variability according to the real environmental condition, it would not be a proper approach to generalize the idea that pipeline is more desirable solution for all CCS projects with large amount of CO2 transport in short distance as well. Fig. 13 shows relative cost for transporting 20 Mt CO2 /year of CO2 . For the distance of 500 km, CO2 shipping is more costeffective than offshore pipeline but is not cost-effective than onshore pipeline differently from the case of transporting 10 Mt CO2 /year. It would be because pipeline transport could achieve more cost reduction by scale effect. CO2 shipping, however, as shown in Fig. 13(b) and (c), could be still competitive solution to pipeline even for 20 Mt CO2 /year of CO2 . Fig. 14 shows relative 10 Mt CO2 /year of CO2 transport cost according to the various distances. It is remarkable that the slope of shipping cost is relatively flat than that of pipeline cost. When
Fig. 14. Relative CO2 transport cost according to distance (10 Mt CO2/year).
CO2 is transported by pipeline, the cost increases rapidly according to the distance between CO2 source and sink so CO2 sinks with relative long distance is rarely considered as underground storage for CCS project. CO2 shipping, however, could enable development of reliable underground storage with relatively long distance. The break-even point, where the cost of shipping is same as the cost of pipeline, is calculated in the range of 200–300 km as shown in Fig. 14 but it should be stressed again that the political and environmental conditions significantly affects the cost of CO2 transport so accurate cost comparison study with detailed information of CAPEX and OPEX should be executed to develop CO2 transport solution suitable for real individual CCS project.
5. Conclusion This paper introduces newly developed each component technology for reducing total cost of CO2 shipping and compared total cost of CO2 shipping and pipeline to show CO2 shipping could be considered competitive solution in commercialized CCS market as well as demonstration project. Firstly, multi-stage CO2 liquefaction processes are developed to increase power efficiency compared to single-stage CO2 liquefaction process. Especially, multi-stage liquefaction process with serial flash gas tanks for high pressure CO2 inlet stream is newly developed and its power consumption is about 44% of single stage one. Newly developed process enables total power consumption of compression and liquefaction for high pressure CO2 inlet stream similar to that for atmosphere pressure CO2 inlet stream. Secondly, CO2 terminals and large size CO2 carriers are adopted for transporting large amount of CO2 volume in commercial CCS market. The concept of floating barge type CO2 terminal is introduced as CO2 collecting point in limited area of land space. Conventional large CO2 carrier and newly developed very large CO2 carrier are introduced to transport large volume of CO2 in a ship. It is shown that large size of CO2 terminal and CO2 carrier could play a role of collecting CO2 from separate CO2 emitters and transport
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in large volume, which would be similar to function of backbone pipeline. Finally, total cost of pipeline and CO2 shipping are evaluated for a scenario of transporting CO2 in large volume. The results of the cost comparison study indicate that CO2 shipping could be a competitive to pipeline in commercial CCS market as well as demonstration project. For a long distance over 500 km, CO2 shipping could be competitive to not only offshore pipeline but also onshore pipeline. In addition, since the slope of CO2 shipping cost according to distances is relatively small, underground storage located further than 500 km could be considered as one of potential site for CO2 storage with similar cost. The break-even point between CO2 shipping and offshore pipeline is calculated in the range of 200–300 km. When environment condition requires pipeline longer than about 200 km, CO2 shipping transport could be considered as cost-competitive solution. In spite of various attractiveness of CO2 shipping like flexibility in transport, less initial investment, and less stringent regulatory approval, CO2 shipping has been considered as only a temporary option for demonstration projects or supplement option for side effect like benefit from selling small amounts of CO2 for CO2 -EOR purpose. This study showed that CO2 shipping can be considered as one of CO2 transport solutions in commercialized CCS market as well as demonstration project. Therefore, when developing real individual CCS project, it is recommendable to evaluate various CO2 transport solutions without preconceived idea on them and develop an optimal CO2 network consisting of both or either of CO2 shipping and pipeline.
References American Society of Mechanical Engineers (ASME), 2010. ASME Boiler and Pressure Vessel Code, Section VIII, Division 1: Rules for Construction of Pressure Vessels. Barrio, M., Aspelund, A., Weydahl, T., Sandvik, T.E., Wongraven, L.R., Krogstad, H., Henningsen, R., Molnvik, M., Eide, S.I., 2004. Ship-based transport of CO2 . In: 7th GHGT Conference. Berger, B., Kaarstad, O., Haugen, H.A., 2004. Creating a large-scale CO2 infrastructure for enhanced oil recovery. In: 7th GHGT Conference. Bliault, A., Reijnen, D., Runbalk, D., AKlein Nagelvoort, R., 2000. Shell’s floating LNG plant for the 21st century. In: IGU World Gas Congress. Botero, C., Finkenrath, M., Belloni, C., Bertolo, S., D’Ercole, M., Gori, E., 2009. Thermoeconomic evaluation of CO2 compression strategies for post-combustion CO2 capture applications. In: ASME Conference Proceedings. Chiyoda Corporation et al., 2011. Preliminary feasibility study on CO2 carrier for ship-based CCS, http://www.globalccsinstitute.com/ Det Norske Veritas (DNV), 2011. Rules for Classification of Ships/High Speed, Light Craft and Naval Surface Craft, Part 2, Chapter 2, Metallic Materials. Global Carbon Capture and Storage Institute (GCCSI), 2011. CO2 Liquid Logistics Shipping Concept (LLSC), Knowledge Sharing Report 4: Overall Supply Chain Optimization. Intergovernmental Panel on Climate Change (IPCC), 2005. Special Report on Carbon Dioxide Capture and Storage. International Maritime Organization (IMO), 2000. International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (IGC Code). McCollum, David L., Joan, M.O., 2006. Techno-Economic Models for Carbon Dioxide Compression, Transport, and Storage and Correlations for Estimating Carbon Dioxide Density and Viscosity. University of California Research Report UCDITS-RR-06-14. Yoo, B.Y., Lee, S.-G., Rhee, K.-P., Na, H.-S., Park, J.-M., 2010a. New CCS system integration with CO2 carrier and liquefaction process. Energy Procedia 4, 2308–2314. Yoo, B.Y., Lee, S.-G., Oh, Y.T., Han, J.H., Gang, H.D., Park, J.M., 2010b. Achieving viability: delivering an integrated shipping solution for CCS using CO2 shipping. In: CO2 Shipping Conference 2010. The European Technology Platform for Zero Emission Fossil Fuel Power Plants (ZEP), 2011. The Cost of CO2 Transport.
Contents lists available at SciVerse ScienceDirect
International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
Development of CO2 terminal and CO2 carrier for future commercialized CCS market Byeong-Yong Yoo ∗ , Dong-Kyu Choi, Hyun-Jin Kim, Young-Sik Moon, Hee-Seung Na, Sung-Geun Lee DAEWOO Shipbuilding & Marine Engineering Co., Ltd., 85, Da-Dong, Jung-gu, Seoul 100-180, Republic of Korea
a r t i c l e
i n f o
Article history: Received 2 July 2012 Received in revised form 20 October 2012 Accepted 6 November 2012 Available online 21 December 2012 Keywords: CCS CO2 carrier CO2 shipping CO2 liquefaction CO2 terminal CO2 transport
a b s t r a c t So far CO2 shipping has only been introduced as a secondary option for long distances and small amounts because of the prevailing idea that CO2 shipping is more expensive than CO2 pipeline for transporting large amount CO2 . This paper shows that CO2 terminal and large CO2 carrier can play a role of collecting CO2 from several sources and transporting CO2 in large volume so transport cost per tonnage of CO2 can be reduce in commercialized CCS market. Multi-stage CO2 liquefaction processes are developed to reduce total cost of CO2 compression and transport. For high pressure CO2 inlet stream, newly developed multistage liquefaction process with serial flash tanks enables power consumption reduced to 44% compared to single stage liquefaction process. By adopting new design concept of very large CO2 Carrier more than 40,000 m3 , optimal size of CO2 carrier can be provided for each voyage route and total cost of CO2 compression and transport is reduced. The results of economic assessment of CO2 transport show that CO2 shipping is economically competitive to CO2 pipeline even in the distance of 200–300 km for large amount of CO2 transport such as 10 Mt CO2 /year or 20 Mt CO2 /year. CO2 transport by ship should be seriously re-considered as an effective transport method for commercialized CCS projects as well as early demonstration projects. © 2012 Elsevier Ltd. All rights reserved.
1. Introduction Intergovernmental Panel on Climate Change (IPCC) (2005) introduced CO2 shipping was typically cheaper than pipelines for distances greater than approximately 1000 km and for amounts smaller than a few million tones of CO2 per year. Chiyoda Corporation et al. (2011) estimated total CO2 shipping cost with 200 km transport distance but the amount of CO2 was limited as 1 Mt CO2 /year. Barrio et al. (2004) and IPCC (2005) assessed CO2 transport cost with single-source and single sink connection. However, in commercialized CCS market, it would be more probable that multi-sources and/or multi-sinks network was utilized to transport large amount of CO2 cost-effectively. Recently, Global Carbon Capture and Storage Institute (GCCSI) (2011) published a knowledge sharing report on complete logistical transportation solution for Rotterdam area and introduced liquid logistics shipping concept (LLSC) to provide CO2 emitters with a complete logistical transport solution from several CO2 sources to offshore storage location. The LLSC adopted the concept of CO2 hub or terminal, which included compression facility, liquefaction facility and temporary storages.
∗ Corresponding author. Tel.: +82 2 2129 3609; fax: +82 2 2129 3670. E-mail address: [email protected] (B.-Y. Yoo). 1750-5836/$ – see front matter © 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.ijggc.2012.11.008
About 3 Mt CO2 /year of CO2 from Rotterdam area was expected to be transported by ship to offshore storage. The European Technology Platform for Zero Emission Fossil Fuel Power Plants (ZEP) (2011) published a report on CO2 transport, which included transport networks consisting of pipeline, ships, and terminal. Although CO2 shipping was considered as a part of the transport network in these reports, CO2 shipping was still considered only for long distance and small amount of transport. This paper seeks to introduce the concept of CO2 terminal and large CO2 carrier available for commercial CCS market. The aim of this paper was to evaluate the feasibility of CO2 shipping as a solution of CO2 transport in commercial project as well as demonstration project.
2. CO2 shipping chain description 2.1. CO2 transport scenario Fig. 1 shows the assumed scenario in this study, which is similar to CO2 network models in ZEP (2011). CO2 cluster A comprises 5 Mt CO2 /year CO2 source and 2.5 Mt CO2 /year CO2 source, which is located near offshore storage so CO2 at cluster A is to be injected into the offshore storage directly. CO2 cluster B is connected with several CO2 sources and collecting point of CO2 cluster B is located
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CO2 cluster A Source A.1
2.5 MtCO2
/year Source A.2
Land or Sea CO2 cluster B
5 MtCO2
/year
Sea 20 MtCO2 /year 30 MtCO2 /year 180 km 500 km 750 km
offshore storage
10 MtCO2 /year 20 MtCO2 /year
0 km 100 km
750 km
2.5 MtCO2
/year Source C
Fig. 1. Distribution of CO2 sources and sink in the assumed scenario.
away from the offshore storage. CO2 source C is located 750 km away from the CO2 cluster A. Captured CO2 at source A.1 is transported by pipeline to the source A.2, which is located in coastal area. Captured CO2 at the cluster B are all transported to a collecting point on the shore through each pipeline. In this paper, 180 km, 500 km and 750 km are considered as the distance between cluster A and B, which could be separated by either land or sea. Since there is no offshore storage near the cluster B, 10 Mt CO2 /year or 20 Mt CO2 /year of CO2 captured at cluster B is transported to cluster A. Three alternatives of transport solutions are considered connecting cluster A with B; onshore pipeline, offshore pipeline and shipping. For pipeline transport, backbone pipeline is installed between cluster A and B. For shipping, CO2 terminals are installed on the shore at cluster A and B, which includes CO2 storage tanks, loading and unloading system and, if necessary, CO2 liquefaction plant. Since CO2 source C is located 750 km away from the cluster A, 2.5 Mt CO2 /year of CO2 captured at source C is shipped to cluster A. Totally 20 or 30 Mt CO2 /year of CO2 collected at cluster A is injected into offshore storage through backbone pipeline or large CO2 carrier (Fig. 2). 2.2. CO2 transport chain CO2 transport between cluster A and B is from the outlet of capture and CO2 conditioning process to the inlet of the booster pump or injection pump of CO2 terminal at the cluster A. Four (4) cases of CO2 transport methods are considered. • Case 1. Onshore pipeline and Case 2. Offshore pipeline CO2 gas at each source at cluster B is compressed and transported to CO2 terminal through pipeline. If necessary, booster
pump is installed in the CO2 terminal at the cluster B and CO2 is compressed again and transported to CO2 terminal A through onshore/offshore backbone pipeline. The captured CO2 , at 0.1 MPa and 35 ◦ C, is compressed to 11 MPa in this study (Fig. 3). Supercritical pipeline has a benefit of avoiding phase transient problem and using small size pipeline without booster compression stations. It requires more compression power at the emitter site but it could be more economical for long distance transportation than transportation in subcritical regime. • Case 3. CO2 shipping from onshore CO2 sources close to CO2 terminal. When CO2 terminal can be constructed near CO2 emission, captured CO2 would be immediately liquefied, transported into temporary storage tanks and then loaded into ship (Fig. 3). This case could be applied into some of CO2 sources such as coal power plant, LNG power plant and steel industry, because some of them are located in coastal areas to receive fuels or raw materials by ships. As the volume of liquefied CO2 is about one-600th the volume of gaseous CO2 in the standard condition, substantially CO2 is to be liquefied first and it should be temporarily stored in large storage tanks before loading. For continuous injection, unloaded CO2 at CO2 terminal A also should be temporarily stored in large tanks. The captured CO2 , at 0.1 MPa and 35 ◦ C, is initially compressed to 0.683 MPa and then liquefied to −50 ◦ C. • Case 4. CO2 shipping from inland CO2 sources away from the CO2 terminal. Captured CO2 in land is to be compressed and transported to onshore CO2 terminal. In this study, captured CO2 is assumed to be compressed to 11 MPa and depressed by 1 MPa through pipeline to the liquefaction plant onshore. For CO2 shipping, supercritical CO2 at 10 MPa is depressurized and liquefied at
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325
CO2 cluster A Source A.1 2.5 MtCO2
/year Source A.2
Land or Sea
5 MtCO2
CO2 cluster B
/year
CO2 Terminal
Ship
Sea 20 MtCO2 /year 30 MtCO2 /year
180 km 500 km 750 km
Ship
10 MtCO2 /year 20 MtCO2 /year
0 km 100 km
CO2 Terminal
Ship
offshore storage
750 km
2.5 MtCO2
/year Source C
Fig. 2. CO2 transport network model in the assumed scenario.
−50 ◦ C to be stored in storage tanks at CO2 terminal and then loaded into ship.
3. Chain components 3.1. Initial compression
Fig. 3 shows simple diagram of the composition of each CO2 transport chain. For all the cases, cooling water temperature is 7 ◦ C and the temperature at the discharge of inter-cooler is assumed to be 20 ◦ C. Case 1 0.1 MPa 35˚C
11 MPa
compression
pipeline
Case 2 compression
Case 3
pipeline
To injection pump
Backbone pipeline sea
CO2 terminal at cluster A
ship
temp. storage
Sea
CO2 terminal at cluster A
-50 ˚C
liquefaction
CO2 source at cluster B
temp. storage
CO2 terminal at cluster B
Case 4 0.1 MPa 35˚C
CO2 terminal at cluster A
11 MPa
CO2 source at cluster B
0.1 MPa 35˚C
To injection pump
Backbone pipeline land
CO2 source at cluster B
0.1 MPa 35˚C
For the cases 1, 2 and 4, two different options are considered to compress CO2 into 11 MPa. One option is to compress CO2 by
-50 ˚C
11 MPa
compression
CO2 source at cluster B
To injection pump
pipeline
liquefaction
temp. storage
CO2 terminal at cluster B
Fig. 3. CO2 transport chain for four (4) cases.
ship
temp. storage
Sea
CO2 terminal at cluster A
To injection pump
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100.0
100.0
Pressure (MPa)
1000.0
Pressure (MPa)
1000.0
10.0
1.0
1.0
0.1
10.0
0.1 0.00
200.
400.
0.00
600.
200.
Enthalpy(kJ/kg)
400.
600.
Enthalpy(kJ/kg)
(a) Compression only option
(a) Liquefaction option Fig. 4. Compression path on P-h diagram.
5-stage compressor and inter-stage cooling and the other option is to compress CO2 to 5.84 MPa by 4-stage compressor, liquefy CO2 by water cooling and then finally compress liquid CO2 to 11 MPa by high pressure pump. Fig. 4 shows the P-h diagram of both compression options. Table 1 shows power consumption of both two compression options for transporting 10 Mt CO2 /year of CO2 . The liquefaction option consumes less power and less number of compressors, which is same as the result of Botero et al. (2009). This study adopts the liquefaction option for the cases 1, 2 and 4. For the case 3, CO2 at atmosphere pressure is compressed to the saturation pressure at the liquefaction temperature −50 ◦ C using 2-stage centrifugal compressors with inter-stage cooling. 3.2. Liquefaction The efficiency of CO2 liquefaction process is dependent on CO2 inlet stream condition and CO2 outlet stream condition. Since the CO2 inlet condition of cases 3 and 4 is quite different, liquefaction processes optimized for each case are developed in this study and the liquefaction temperature of CO2 outlet stream is fixed at −50 ◦ C. 3.2.1. Liquefaction process for case 3 The CO2 inlet stream of liquefaction process is at atmosphere pressure and 35 ◦ C. CO2 inlet stream is compressed to 5.8 MPa by multi-stage compressor and inter-coolings. At the highest pressure, CO2 is liquefied by seawater cooling. Liquid CO2 is depressurized by expansion valve and separated in serial flash tanks. Flash gas is recycled to the forward stage of multi-stage compressor. Liquid CO2 is drained to another expansion valve and flash tank. Three serial steps of flash process are applied for liquefying CO2 at
−50 ◦ C. For transporting 10 Mt CO2 /year of CO2 , calculated power consumption for the initial compression is 49.9 MW and that of liquefaction process is 71.4 MW. 3.2.2. Liquefaction process for case 4 In case 4, captured CO2 is already compressed to 11 MPa and it is assumed that the pressure is decreased to 10 MPa through pipeline. The CO2 inlet stream of liquefaction process is 10 MPa and 20 ◦ C. The Fig. 5 shows the newly developed process model to liquefy high pressure CO2 using CO2 feed as the refrigerant. CO2 inlet stream is depressurized to the saturation pressure at the liquefaction temperature of −50 ◦ C through serial flash tanks. Flash gas is recompressed and recycled by additional compressors. Liquid CO2 is drained to next flash tank. Serial three steps of flash process are applied for liquefying CO2 at −50 ◦ C. Fig. 5 shows schematic diagram of the liquefaction process for the case 4. For transporting 10 Mt CO2 /year of CO2 , calculated power consumption of liquefaction process is 19.7 MW, which is much less than that of the case 3, but 105.8 MW is already consumed for initial compression stage for transporting CO2 to the liquefaction plant through pipeline. Yoo et al. (2010a) insisted that CO2 liquefaction process, making total CO2 shipping more expensive with large power consumption, was another form of CO2 compression so CO2 transport technology should be assessed with CO2 compression technology and total CO2 shipping cost would be evaluated competitive to pipeline. Fig. 6 shows total power consumption of liquefaction and compression process for transporting 10 Mt CO2 /year of CO2 . CO2 liquefaction process, including initial compression in cases 3 and 4, consumes more power than compression process in cases 1 and 2. However, the gap of power consumption is calculated about 15%, which is
Table 1 Power consumption of compression process. Scenario
Temperature [◦ C] Pressure [MPa]
CO2 inlet
1st stage
2nd stage
3rd stage
4th stage
5th stage
Total power [MW]
Cases 1, 2 and 4 (compression only option)
Temperature [◦ C]
35
124.1
106.3
107.0
108.6
107.8
113.4
Pressure [MPa] Temperature [◦ C]
0.1 35
0.25 131.8
0.65 113.7
1.68 114.7
4.29 116.7
11 n/a
105.8a
0.1
0.27
0.76
2.10
5.84
n/a
Cases 1, 2 and 4 (liquefaction option)
Pressure [MPa] a
Pump power, consumed to compress liquefied CO2 to 11 MPa, is also included in the total power.
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5.8 MPa -55.09 ºC
10 MPa 20 ºC
5.8 MPa 15.15 ºC
5.8 MPa 17.86 ºC
2.82 MPa -7.73 ºC
327
5.8 MPa 20 ºC
2.82 MPa --7.722 ºC
1.368 MPa -30.82 ºC
2.817 MPa 27.53 ºC
1.368 MPa -30.82 ºC
1.368 MPa 4.02 ºC
0.665 MPa -50 ºC 0.665 MPa -50 ºC
Fig. 5. Schematic diagram of the liquefaction process for the case 4.
not so large that additional cost of CO2 liquefaction process does not result in significant cost increase of CO2 shipping not to be competitive to pipeline transport. Fig. 6 also shows that the total power consumption of the case 4 is similar to that of the case 3, which implies that CO2 shipping could be considered as one of potential solutions of transporting CO2 even for inland CO2 source located away from a coast. When CO2 source is located away from the coast, CO2 should be initially compressed to high pressure like 10 MPa. Compared to the case of onshore CO2 source, it results more power consumption in initial compression but, since the CO2 inlet stream to liquefaction process is already at high pressure, it consumes significantly reduced power. In addition, in this study, CO2 liquefaction process, using serial flash tanks and compressors, is newly developed suited for liquefying at high pressure. The power consumption of newly developed liquefaction process is about 44% of one of singe stage CO2 liquefaction process in Fig. 7. 3.3. Temporary storage as CO2 export terminal
Power consumption [MW]
In total CCS system, CO2 is captured continuously from CO2 emission sources but CO2 shipping is discrete process. Therefore
temporary storage as CO2 terminals would be located between liquefaction plant and ships, which functions as buffer tank before loading CO2 into a ship. Table 2 shows the size of CO2 carrier and temporary storage in CO2 terminal for each CO2 flow rate and distance between cluster A and B. The size of the temporary storage, which was expressed as buffer storage by ZEP (2011), was 100% of ship size. Barrio et al. (2004) and Berger et al. (2004) assumed the capacity of temporary storage was 150% of the ship capacity. Bliault et al. (2000) assumed the capacity of floating LNG storage was about 118–148% of LNG carrier capacity to have operational margins. Since CO2 is more non-hazardous fluid than LNG, less or equal margin is enough for buffer volume of temporary storage. 120% of ship capacity was considered in this study, which provided more operational margins than CO2 storage assumed by ZEP (2011) and more cost-effectiveness than CO2 storage assumed by Barrio et al. (2004) or Berger et al. (2004). Temporary storage as CO2 terminal could be installed on land. When land space is limited near liquefaction plants or the cost for land-based plant installation is relatively expensive, floating barge type temporary storage or shore-mounted temporary storage could be adopted. Fig. 8 is a conceptual drawing of barge-type temporary storage adopted in this study. Furthermore, if necessary, liquefaction plant or capture plant would be constructed on the deck of temporary storage to provide new plants the region of limited land space.
Table 2 Size of CO2 carrier and temporary storage for each case.
Case 1 & 2
Case 3
Case 4
Fig. 6. Power consumption of compression and liquefaction process for each case (10 Mt CO2/year).
CO2 volume flow [Mt CO2 /year]
Distance [km]
10
180 500 750
23,000 36,000 46,000
28,000 44,000 56,000
20
180 500 750
46,000 71,000 91,000
56,000 86,000 110,000
a
Size of CO2 carriera [m3 ]
Two (2) CO2 carriers were utilized for each case.
Size of temporary storage in CO2 terminal [m3 ]
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5.8 MPa 135.3 ºC
10 MPa 20 ºC
5.8 MPa 15.15 ºC
5.8 MPa 17.97 ºC
5.8 MPa 20 ºC
0.665 MPa -50 ºC
0.665 MPa -50 ºC
Fig. 7. Reference schematic diagram of the liquefaction process for the case 4.
Horizontal type tanks are installed in the temporary storage when the capacity is relatively small, and vertical type tanks, which are more flexible in arrangement of tanks in barge, are installed for large size temporary storage (Fig. 8). The storage tank is designed to satisfy IGC code (2000), DNV-Rule (2011) and ASME code (2010). The maximum diameter of one tank is 11 m and the maximum length is 36 m. The selection of tank material is significantly affects the cost of temporary storage tanks and this study adopts low temperature carbon manganese steel to save CAPEX of CO2 storage tank. The boil-off gas (BOG) could be increased by heat ingress through the wall and support structure of tanks but the vapor pressure in tanks is designed to maintain constant pressure by re-cycling BOG into CO2 liquefaction process. 3.4. CO2 carrier To commercialize CO2 shipping, it is important to reduce total cost of CO2 shipping, including liquefaction plant, CO2 carrier and temporary storage. The cost of CO2 carrier is dependent on the number and the size of CO2 carriers. The number and the size of ship can be determined considering the voyage distance, voyage time, speed, amount of total cargo for transport in a year and other factors. In addition, for CO2 shipping, additional cost for temporary storage also should be considered together and it affects the number and the size of CO2 carrier suited for a specific CCS project.
Since the size of temporary storage is proportional to the size of CO2 carrier and large pressure tanks, main equipment of temporary storage, are relatively expensive, increase of the size of CO2 carrier results in cost increase in temporary storage. This study considered two kinds of design concept for CO2 carrier and capacity ranges from 23,000 m3 to 91,000 m3 as shown in Table 2. The design speed of CO2 carrier is 15.0 kts in laden voyage and 16.0 kts in ballast voyage. The density of liquid CO2 at −50 is 1.150 ton/m3 and cargo tanks are assumed to be filled by 95% for laden voyage. Two (2) ships are used for each voyage route. Voyage time is calculated for each voyage distance including 4 h for harbour manoeuvring, 12 h for loading operation, and 12 h for unloading operation. For example, voyage time for 500 km is estimated at 2.66 days. One CO2 carrier could travel 129 times for a year, 345 days. Therefore the minimum capacity of a CO2 carrier for transporting 10 Mt CO2 /year is estimated using simple calculation: 10 Mt ÷ two (2) ships ÷ 129 times ÷ 1.150 ton/m3 ÷ 95% = 35,477 m3 . 3.4.1. Conventional large CO2 carrier Yoo et al. (2010b) introduced that CO2 carrier with a capacity of 20,000 m3 or 30,000 m3 was to be semi-refrigerated type and were expected to be very similar to that of semi-refrigerated type LPG carrier. In this study, this design concept, conventional large CO2 carrier concept, is adopted to CO2 carriers with a capacity of 23,000 m3 and 36,000 m3 . Fig. 9 shows a conceptual drawing of CO2
(a) A sketch of midship and section view of floating barge type temporary storage with capacity of 28,000 m3
(a) A sketch of midship and section view of floating barge type temporary storage with capacity of 110,000 m3 Fig. 8. A sketch of a floating barge type temporary storage.
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Fig. 9. Conceptual drawing of conventional large CO2 carrier.
Fig. 10. Conceptual drawing of newly developed very large CO2 carrier.
carrier with the capacity of 23,000 m3 , which included horizontal cylindrical type tanks. Six tanks are located in the cargo hold and one tank dimension is maximum 35 m (length) and 11 m (diameter). A cross section of tanks in ship is basically circular in shape, enabling them to withstand strong internal pressure, thus making them ideal for high pressure environments. Since theoretically the more pressure a tank is under, the thicker it needs to be, the size of tank that can be manufactured for this purpose is limited, resulting in an expected large CO2 carrier size of less than 40,000 m3 with current designs for transporting CO2 at −50 ◦ C. The material is same as the one of temporary storage tanks. 3.4.2. Newly developed very large CO2 carrier Yoo et al. (2010b) also described a different type of CO2 carrier with a capacity of 100,000 m3 . In this study, CO2 carriers, with a capacity of 46,000 m3 , 71,000 m3 and 91,000 m3 , adopt newly developed very large CO2 carrier design to transport large amount of CO2 for CCS application. They contain vertical tanks instead of horizontal tanks. As shown in Fig. 10, vertical cargo tanks are more flexible in tank arrangement in a ship so there is no limit in the capacity of ship. Fig. 10 shows newly developed CO2 carrier with the capacity of 91,000 m3 , which includes 91 tanks of 1000 m3 . Unlike other liquefied gas carriers, which installed submerged type pumps in each tank, it is assumed that liquid CO2 will be transported into a pump out of tanks in a separate pump room. Utilization of common pumps enables cost saving by reducing the number of offloading pumps and easier installation, operation and maintenance. 3.5. CO2 Offloading and CO2 temporary storage as an import terminal
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result in cost increase for CO2 shipping with more number of CO2 carriers. Another solution is increasing more number of injection wells even though it also causes cost increase from developing large number of injection wells. Therefore, the number of wells and offloading flow rate could be optimized based on the characteristics of underground storage and shipping conditions. In this study, however, CO2 is injected from another temporary storage as CO2 import terminal near injection site instead of directly injecting CO2 from a ship. Liquid CO2 cargo transported by ship is to be offloaded to the temporary storage and liquid CO2 is continuously injected into underground storage with relatively slow speed. Therefore injection rate would be similar to the flow rate of liquefaction process and CO2 offloading time is relatively short similar to that of existing LNG or LPG carriers. Another benefit of adopting temporary storage as CO2 import terminal is eliminating potential risk of CO2 leak or CO2 hydration during replacing CO2 carriers connected to injection pipeline. When the injection site is near shore, temporary storage as CO2 import harbour could be installed on the shore and relatively short injection pipeline would be connected between temporary storage and underground storage. When injection site is offshore, floating type, submerged type or fixed type such as gravity based structure (GBS) type could be a candidate of temporary storage and the most cost-effective and safe solution should be selected based on accurate data of injection site and project conditions. Temporary storage as CO2 import terminal includes reliquefaction equipment when liquefaction plant is located far from the injection site so gaseous CO2 could not be returned to the liquefaction plant. Boil-off-gas (BOG) of CO2 is compressed to 5.8 MPa by two-stage compressor and CO2 is liquefied by seawater cooling and serial two flash tanks. With the assumption of boil-of-gas rate (BOR) as 0.15%, same as the one of conventional LNG carrier, the power consumption of re-liquefaction facility ranges from 78 to 309 kW according to the capacity of temporary storage. High pressure pump and CO2 heater are main equipments of CO2 injection system. GCCSI (2011) suggested the reservoir inlet (bottom well) should remain above 15 ◦ C to prevent hydrate formation. Assuming that the bottomhole pressure of the reservoir in this study is 10 MPa, Fig. 11, quote from GCCSI (2011), indicated that injection temperature should be kept above about −8.5 ◦ C. For this study, the CO2 stream after injection pump discharge is heated to −7 ◦ C using sea water to avoid hydrate formation at the reservoir inlet. Inland CO2 storage tank would receive necessary power through existing power grid in land. For offshore temporary storage, electric generation equipments would be additionally installed. For transporting 10 Mt CO2 /year of CO2 , power consumption of CO2 injection pump is 3.4 MW and that of sea water pump for heating is 0.6 MW. 3.6. CO2 pipeline There have been several techno-economic models for estimating pipeline sizes and costs, but there is a large degree of variability between the output of the different models. In this study, CO2 transport scenario is developed similar to CO2 networks assumed by ZEP (2011). The diameter and estimated cost of onshore and offshore pipelines adopted by ZEP (2011) is listed in Table 3. 4. Cost comparison study
CO2 offloading and injection is very complex process because they are related with the characteristics of underground storage, site condition, CO2 carrier and injection facilities. CO2 could be directly injected from a CO2 carrier into underground storage. The simplest solution would be injecting CO2 from a ship with slow speed. However, offloading time would be increased and it would
4.1. General assumptions for cost comparison study Pipeline cost was estimated based on the results of ZEP (2011). The construction cost of CO2 carrier and temporary storage was estimated based on concept design by DSME, a shipbuilding
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Fig. 11. Bottomhole temperature as a function of injection temperature, quote from GCCSI (2011).
company, which has been used to design and build similar liquefied gas carriers such as LNG carriers and LPG carriers. For CAPEX calculation, project lifetime and depreciation period was 40 years and interest rate was 8% in this paper, which was same as that of ZEP (2011). Since large size of compressors shared most of cost for initial compression and liquefaction process, CAPEX and OPEX of compressors without other equipments were considered for the cost comparison study on liquefaction/compression technology. The cost was calculated using equations in McCollum’s (2006) study on techno-economic models for carbon dioxide compression. The capital cost of compressor was calculated by following equation and, mtrain is mass flow rate through each compressor train, Ntrain is the number of compressor trains, Pinitial is the inlet pressure of the compressor and Pcut-off is the outlet pressure. The annual operation and maintenance cost and total electric power costs of the compressor were considered for OPEX.
Ccomp = mtrain Ntrain (0.13 × 106 )(mtrain )−0.71 +(1.40 × 106 )(mtrain )−0.60 ln
P
cut-off
Pinitial
compressor was annualized by applying a capital recovery factor (CRF) of 0.15. For long distance pipeline transport in case 1 or 2, booster compressor might be installed but the cost of the additional booster compressors is not reflected in the cost assessment in this study. High pressure CO2 is in supercritical state or liquid state, relatively cheap pump can be utilized to boost CO2 instead of expensive compressor. The CAPEX and OPEX of pump were relatively negligible compared to ones of compressor. The cost for loading/unloading facility and other equipments, which were negligible compared to ones of main equipments of liquefaction process and compression process, were not considered in the study as well. Assuming that construction cost of compression plant and liquefaction plant has the same order, construction cost for compression plant and liquefaction plant was assumed to be offset in the comparison study. In this study, electricity cost was assumed as 0.065 $/kWh and heavy fuel oil (HFO), which was used for CO2 carrier and electric generation in offshore temporary storage, was assumed as $500/tone. 4.2. Economic assessment on CO2 compression and transport strategies
Installation cost would share large portion in total cost of new plants for liquefaction or compression but it was neglected with assumption that installation cost of compression plant and liquefaction plant would have similar amounts. The capital cost for
Fig. 12 shows relative cost for transporting 10 Mt CO2 /year of CO2 . For short distance such as 180 km, onshore pipeline in case 1 and offshore pipeline in case 2 are more cost-effective than
Table 3 Diameter and cost of onshore/offshore pipeline. CO2 volume flow [Mt CO2 /year]
Onshore/offshore
Distance [km]
180
500
750
10
Onshore pipeline Offshore pipeline
Diameter [m] Cost [MUSD/year] Diameter [m] Cost [MUSD/year]
0.6096 26.3 0.8128 43.5
0.6096 70.1a 0.8128 97.8a
0.6096 104.1a 0.8128 142.5a
20
Onshore pipeline Offshore pipeline
Diameter [m] Cost [MUSD/year] Diameter [m] Cost [MUSD/year]
0.5588 33.1 0.6604 57.1
0.6604 89.3 0.8128 124.6
0.6604 132.6 0.8636 181.6
a All values were quote from ZEP (2011) except values with asterisk marks. McCollum (2006) showed that pipeline cost was proportional to the 0.35th power of the mass flow. The values were estimated by multiplying the cost of pipeline for transporting 20 Mt CO2 /year by (10 Mt CO2 /year ÷ 20 Mt CO2 /year)0.35 .
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Fig. 12. Relative cost of CO2 transport (10 Mt CO2 /year).
Fig. 13. Relative cost of CO2 transport (20 Mt CO2/year).
CO2 shipping in cases 3 and 4. For relatively longer distance such as 500 km and 750 km, CO2 shipping is more cost-effective than onshore pipeline as well as offshore pipeline. In addition, the cost difference, between CO2 shipping and offshore pipeline for the transport distance 180 km, is about 13% for 10 Mt CO2 /year transport. Considering large contingency of cost estimation at early stage of CCS technology and cost variability according to the real environmental condition, it would not be a proper approach to generalize the idea that pipeline is more desirable solution for all CCS projects with large amount of CO2 transport in short distance as well. Fig. 13 shows relative cost for transporting 20 Mt CO2 /year of CO2 . For the distance of 500 km, CO2 shipping is more costeffective than offshore pipeline but is not cost-effective than onshore pipeline differently from the case of transporting 10 Mt CO2 /year. It would be because pipeline transport could achieve more cost reduction by scale effect. CO2 shipping, however, as shown in Fig. 13(b) and (c), could be still competitive solution to pipeline even for 20 Mt CO2 /year of CO2 . Fig. 14 shows relative 10 Mt CO2 /year of CO2 transport cost according to the various distances. It is remarkable that the slope of shipping cost is relatively flat than that of pipeline cost. When
Fig. 14. Relative CO2 transport cost according to distance (10 Mt CO2/year).
CO2 is transported by pipeline, the cost increases rapidly according to the distance between CO2 source and sink so CO2 sinks with relative long distance is rarely considered as underground storage for CCS project. CO2 shipping, however, could enable development of reliable underground storage with relatively long distance. The break-even point, where the cost of shipping is same as the cost of pipeline, is calculated in the range of 200–300 km as shown in Fig. 14 but it should be stressed again that the political and environmental conditions significantly affects the cost of CO2 transport so accurate cost comparison study with detailed information of CAPEX and OPEX should be executed to develop CO2 transport solution suitable for real individual CCS project.
5. Conclusion This paper introduces newly developed each component technology for reducing total cost of CO2 shipping and compared total cost of CO2 shipping and pipeline to show CO2 shipping could be considered competitive solution in commercialized CCS market as well as demonstration project. Firstly, multi-stage CO2 liquefaction processes are developed to increase power efficiency compared to single-stage CO2 liquefaction process. Especially, multi-stage liquefaction process with serial flash gas tanks for high pressure CO2 inlet stream is newly developed and its power consumption is about 44% of single stage one. Newly developed process enables total power consumption of compression and liquefaction for high pressure CO2 inlet stream similar to that for atmosphere pressure CO2 inlet stream. Secondly, CO2 terminals and large size CO2 carriers are adopted for transporting large amount of CO2 volume in commercial CCS market. The concept of floating barge type CO2 terminal is introduced as CO2 collecting point in limited area of land space. Conventional large CO2 carrier and newly developed very large CO2 carrier are introduced to transport large volume of CO2 in a ship. It is shown that large size of CO2 terminal and CO2 carrier could play a role of collecting CO2 from separate CO2 emitters and transport
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in large volume, which would be similar to function of backbone pipeline. Finally, total cost of pipeline and CO2 shipping are evaluated for a scenario of transporting CO2 in large volume. The results of the cost comparison study indicate that CO2 shipping could be a competitive to pipeline in commercial CCS market as well as demonstration project. For a long distance over 500 km, CO2 shipping could be competitive to not only offshore pipeline but also onshore pipeline. In addition, since the slope of CO2 shipping cost according to distances is relatively small, underground storage located further than 500 km could be considered as one of potential site for CO2 storage with similar cost. The break-even point between CO2 shipping and offshore pipeline is calculated in the range of 200–300 km. When environment condition requires pipeline longer than about 200 km, CO2 shipping transport could be considered as cost-competitive solution. In spite of various attractiveness of CO2 shipping like flexibility in transport, less initial investment, and less stringent regulatory approval, CO2 shipping has been considered as only a temporary option for demonstration projects or supplement option for side effect like benefit from selling small amounts of CO2 for CO2 -EOR purpose. This study showed that CO2 shipping can be considered as one of CO2 transport solutions in commercialized CCS market as well as demonstration project. Therefore, when developing real individual CCS project, it is recommendable to evaluate various CO2 transport solutions without preconceived idea on them and develop an optimal CO2 network consisting of both or either of CO2 shipping and pipeline.
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