“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuels“Ship Carbon Recycling Working
Group” inside Japan Association of Carbon
Capture & Reuse (JACCR)* Launches Initiative for Zero-emission Ship Fuels
Naohiro Murata*＊，Yugo Kohno*＊*，Yasuhiro Mogi*＊*＊, Hirohiko Oyabu＊*＊*＊, Kai Shiraishi*＊＊＊*＊，Atsunori Sato*＊*＊*＊*，Junichi Hirata*＊*＊*＊*＊, Katsunori Sakaguchi*＊*＊*＊*＊*，Kenji Nakao*＊*＊*＊*＊*＊

1. Introduction
The United Nations Framework Convention on
Climate Change (UNFCCC) discusses measures to betaken by the entire world to prevent global warming. The
Paris Agreement, which was adopted at the 21stConference of the Parties to the United Nations
Framework Convention on Climate Change (COP21) inDecember 2015, states the aim of “holding the increasein the global average temperature to well below 2°C
above pre-industrial levels and pursuing efforts to limit
the temperature increase to 1.5°C.”
Meanwhile,intheinternational
maritimetransportation field, the International Maritime
Organization (IMO) adopted the “Initial IMO Strategy
on Reduction of GHG Emissions from Ships”1) in April
2018, and specified its vision for achieving the following
targets with the year 2008 designated as the reference
year: (1) Reduction of CO2 emissions per transport workby at least 40% by 2030, (2) Reduction of total GHG
emissions by at least 50% by 2050, and (3) Efforts
towards phasing out GHG emissions as soon as possible
in this century.
While the international maritime transportationindustry introduced the Energy Efficiency Design Index(EEDI) even before the above initial strategy was created,and made efforts to reduce CO2 emissions from ships,
including raising the regulatory values in stages, it isconsidered that reinforcing the EEDI regulations will not
be sufficient and that it is necessary to switch from＊accepted date April 28th, 2021＊＊JIME Member, Hitachi Zosen Corporation＊＊＊ EX Research Institute Ltd.
＊＊＊＊ JFE Steel Corporation＊＊＊＊＊ Mitsui O.S.K. Lines, Ltd＊＊＊＊＊＊ Shin Kurushima Sanoyas Shipbuilding Co., Ltd.
＊＊＊＊＊＊＊ JGC Corporation＊＊＊＊＊＊＊＊ Nippon Kaiji Kyokai (Class NK)＊＊＊＊＊＊＊＊＊ Nihon Shipyard Co.,Ltd.
＊＊＊＊＊＊＊＊＊＊ Nippon Steel Corporation－1－

conventional fuels, which are mainly fossil fuels, to lowcarbon or decarbonized fuels in order to achieve theobjectives of the strategy.
Based on this movement by the IMO, the Shipping
Zero Emission Project was established in April 2018with the collaboration of industry, academia andgovernment. This project is led by the Japan Ship
Technology Research Association (JSTRA), cosponsored by the Ministry of Land, Infrastructure,
Transport and Tourism, and assisted by the Nippon
Foundation to help maritime transportation, shipbuilding
and craft machinery corporations, universities, research
institutes, and so forth to study ways to reduce GHG anddevelop scenarios. In March 2020, the “Roadmap to
Zero Emission from International Shipping”2) wasannounced, stating “LNG to carbon-recycled methanetransition scenario” as one of the scenarios fortransitioning to alternative fuels in order to achieve the2050 objectives.
In November 2016, a group including the National
Institute of Advanced Industrial Science and Technology(AIST), Hitachi Zosen Corporation, JGC Japan
Corporation, INPEX Corporation, and EX ResearchInstitute Ltd. established the Japan Association of
Carbon Capture & Reuse (JACCR)3) for the purpose ofeffectively achieving carbon neutrality by providing analternative energy involving combining the CO2 emitted
from the industry and hydrogen produced through theuse of renewable energy.
In August 2019, Mitsui O.S.K. Lines, Ltd., a memberof the association, launched the Working Group for Zero
Emission Alternative Fuel4) within the JACCR.
In July 2020, Mitsui O.S.K. Lines was joined by EX
Research Institute Ltd., Sanoyas Shipbuilding
Corporation (currently Shin Kurushima Sanoyas
Shipbuilding Co., Ltd.), JFE Steel Corporation, Japan
Marine United Corporation, JGC Corporation, Nippon
Kaiji Kyokai (Class NK), Nippon Steel Corporation, andHitachi Zosen Corporation, which agreed with the above
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purpose, and the nine companies together established theShip Carbon Recycling Working Group5) to start
examining the feasibility of zero-emission fuels.
This article introduces the results of this Working
Group so far.

2. Carbon recycled methane
The stated purpose of this Working Group is to pursue
the feasibility of carbon recycled methane produced bymethanation, which is considered to be one of thecandidates for zero-emission fuel for ships. To achieve
this purpose, the following six main issues are to beaddressed:
I. Evaluation of feasibility as a zero-emission fuelII. Large CO2 transport ships
III. Supply of renewable energy-derived hydrogen
IV. Methane slip
V. Supply infrastructure
VI. Economic efficiency
For Issues II to VI, the major premise is that carbon
recycled methane is considered as a zero-emission fuelin Issue I, and therefore it was decided to work on Issue
I first.
To evaluate whether carbon recycled methane can beconsidered as a zero-emission fuel in Issue I, we
assumed a supply chain consisting of (1) Separation,
recovery and liquefaction of CO2 emitted from domestic
factories, etc., (2) Marine transport of liquefied CO2 to alocation where renewable energy-derived hydrogen is
supplied on CO2 transport ships, (3) Methane synthesis
from CO2 and hydrogen by methanation, and (4)Liquefaction of methane and utilization as a ship fuel, as
shown in Fig. 1, and estimated the energy balance ofeach process.

Fig. 1 Assumed supply chain and processes to be evaluated－2－

Specifically, the annual amount of 150,000 t CO2
emitted from domestic factories, etc. is separated andrecovered by a chemical absorption or physicaladsorption method, then converted into the liquefiedstate at 0.7 MPaG and −46°C (hereafter referred to asliquefied CO2 conditions) to transfer it by sea on 11,000
t CO2 transport ships. The transferred liquefied CO2 isunloaded at a location where renewable energy-derived
hydrogen is supplied, and methane is synthesized
through the methanation reaction after re-vaporization.
This synthesized methane is liquefied to be used as a ship
fuel.
Prior to trial calculation, we specified the boundary
conditions for handing over the intermediates andproduct substances between processes. We also
specified the transport volume and distance conditions asfollows:
Condition 1: CO2 is put into the liquid state at 0.7
MPaG and −46°C for transport.
Figure 2 shows the state diagram for CO2. We selected
the transport conditions in Condition 1, as the IMO
International Code for the Construction and Equipmentof Ships Carrying Liquefied Gases in Bulk stipulates“the pressure shall be maintained at 0.05 MPa above
higher than the triple point for CO2 during international
marine transport.”
Condition 2: The marine CO2 transport distance was set
to 5,000 nautical miles (1 nautical mile = 1,852 m).
Condition 3: The annual amount of CO2 separation,
recovery and transport is set to 150,000 t.
Condition 4: The calculation for each process isconducted by using publicly known technologies andinformation at present.
Condition 5: We assumed the year 2030, when theachievement of zero-emission ships is expected, 0.370
kg-CO2/kWh, which is the value published6) by theFederation of Electric Power Companies of Japan(September 2015) based on the “Long-term estimate ofelectricity demand” for Japan as the CO2 emission factor
for electricity, and the Phase 3 regulatory values as theEnergy Efficiency Design Index (EEDI) used in marinetransport. In addition, we used 0.060 t-CO2/GJ, which isthe value for industrial steam in “List of calculation
methods and emission factors in calculation, reportingand publication systems”7) by the Ministry of theEnvironment, as the CO2 emission factor for steam.

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Fig. 2 Temperature and pressure for marine transport of CO2

The items to be evaluated to calculate the CO2
emissions are described below.
We calculated the CO2 emitted within the supply chain
for CO2 separation, recovery and transport, and synthesis
and liquefaction of carbon recycled methane that was
described previously.
We set the CO2 emission factor for hydrogen, which isderived from renewable energy and supplied, to zero.
In addition, there is the issue of “allocation,” whichmeans which country should be responsible for counting
the CO2 emitted, including international maritime
transportation, as our assumed supply chain would cover
multiple countries. However, we decided not to handle
this issue, as no international framework or agreement
has yet been established.
The energy balance results for each process that we
calculated based on the above conditions are describedin Chapters 3 to 6, and the results of tabulation for eachprocess and its analysis in Chapter 7.

3. Energy balance in the CO2 separation andrecovery process
Techniques to separate and recover CO2 include
chemical absorption, physical adsorption, andmembrane separation, and many other separation
techniques are being developed. In this chapter, we
calculated the energy balance for the chemical
absorption method and the physical adsorption method
assuming CO2 recovery from the exhaust gas at
steelworks.
Chemical absorption method:
The chemical absorption method refers to thetechnique of separating CO2 by utilizing the chemical
reaction of CO2 absorption solution. In this method, asolution that can dissolve a large volume of CO2
selectively is brought into contact with the blast furnace－3－

gas to capture the CO2 into the solution by the reactive
absorption principle to subsequently separate andrecover the CO2 gas in a high concentration. The method
is suited to separating and recovering large volumes of
CO2 from process gas, etc. at normal pressure.
Physical adsorption method:
The physical adsorption method refers to the CO2
separation technique in which CO2 is adsorbed to a solid
adsorbent such as activated carbon and zeolite underhigh pressure or low temperature, to be desorbed at low
pressure or high temperature. The Swing method, whichuses multiple adsorption towers filled with adsorbent
and changes the environment such as pressure andtemperature, is often used. There are the Pressure Swing
Adsorption (PSA) method to swing the pressure, theThermal Swing Adsorption (TSA) method to swing thetemperature, and the Pressure Thermal Swing
Adsorption (PTSA) method, which combines the PSA
and the TSA methods.
Dehumidification may be necessary before CO2
separation and recovery, depending on the type ofadsorbent.
3.1 CO2 separation and recovery by the chemical
absorption method
The chemical absorption method selectively separates
and recovers CO2 from combustion exhaust gas or blast
furnace gas by using the chemical reaction between abasic substance such as an amine and CO2, which is anacidic substance. Figure 3 shows the concept of thechemical absorption method8).
A plant employing this method consists of anabsorption tower, regeneration tower, reboiler, etc. The
gas that contains CO2, such as combustion exhaust gas
and blast furnace gas, is pressurized in blower (B1) in
Fig. 3, supplied to the bottom of the absorption tower,
and travels upward inside the tower. The chemical
absorption solution is dripped from the top of the tower
at the same time and moves to the bottom along thesurface of the filler inside the tower. The CO2 in the
supplied gas reacts selectively with the chemical
absorption solution and is absorbed through gas-liquidcontact during this process. As a result, approximately
90% of the CO2 contained in the supplied gas is absorbedby the absorption solution and recovered by the time thegas reaches the top of the tower.

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“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuels

Fig. 3 Conceptual drawing of a plant employing the chemical
absorption method

As the chemical absorption solution, amine solution ismainly used for CO2 recovery from combustion exhaustgas, blast furnace gas, etc.
The chemical absorption solution that has reacted withand absorbed CO2 is called the rich solution. This richsolution is extracted from the bottom of the absorption
tower, fed by Pump P1 to be introduced at the top of theregeneration tower via a heat exchanger. The richsolution is heated inside the regeneration tower to 100–
120°C and releases the CO2. This CO2 is then recoveredfrom the top of the regeneration tower with aconcentration of 99% or higher. The absorption solution
after releasing CO2 is called the lean solution, and it isrecovered from the bottom of the regeneration tower.
The lean solution is fed by Pump P2 and is dripped fromthe top of the absorption tower again after passing
through a heat exchanger.
The CO2 absorption reaction in the chemical
absorption method is exothermic, and so the energy
corresponding to this reaction heat needs to be suppliedin order to desorb the CO2 in the regeneration tower. In
addition, energy must be supplied to increase thetemperature of the absorption solution and provide thethermal energy that is lost at the top of the tower for CO2
recovery. The sum of these heats—reaction heat for
absorption solution, heat for temperature increase, andheat lost at the top of the tower—is the energy required
for CO2 separation and recovery. The chemical
absorption solution offers higher performance as thisCO2 recovery energy is smaller. The reboiler supplies
this CO2 recovery energy as steam.

Figure 4 shows the scope of examination in thischapter. We examined the processes to liquefy the CO2
recovered from the blast furnace gas with the chemical
absorption method, store it for a certain period in thestorage tank, and transfer it to the CO2 transport shipwith a transfer pump. We set the CO2 concentration in
the blast furnace gas at 22%, and the conditions ofliquefied CO2 to be loaded onto the CO2 transport ship
at 0.7 MPaG and −46°C.
In the chemical absorption method, the energy of thesteam used in the reboiler accounts for more than 90%of the total energy consumption. We therefore calculated
the CO2 emissions for the amount of steam consumption
in the reboiler. In this trial calculation, we used the valueof 2.3 GJ/t-CO2, the CO2 recovery energy value for
ESCAP®, which was commercialized by Nippon SteelEngineering Co., Ltd.9) This value is a world top classvalue among the amine absorption solutions that havebeen commercialized. Assuming that the thermal
efficiency of the reboiler is 80%, the steam energy
required for recovering CO2 from the amine absorption
solution with CO2 recovery energy of 2.3 GJ/t-CO2 iscalculated as 2.9 GJ/t-CO2. Therefore, it is calculated
that 0.17 t of CO2 is emitted when recovering 1 t of CO2
assuming the CO2 emission factor stated in Chapter 2.
Meanwhile, amine absorption solutions are still being
researched. For example, a NEDO project10) is
developing an amine solution with CO2 recovery energyof 1.6 GJ/t-CO2 as a target to be achieved by the end of
fiscal 2022. By using this absorption solution, it iscalculated that 0.12 t of CO2 would be emitted whenrecovering 1 t of CO2.

Fig. 5 CO2 liquefaction process

Figure 5 shows the process flow for producingliquefied CO2 under liquid CO2 conditions from the CO2

Fig. 4 Scope of examination－4－

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“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuels

gas at the temperature of 40°C and pressure of 0 MPaG
that was recovered by the chemical absorption method.
The figure also shows the state and processed amount of
CO2. The CO2 that is recovered by the chemical
absorption method is pressurized to 0.6 MPaG byCompressor 1. Its temperature increases toapproximately 200°C under this pressurization, and it ismixed with the liquefied CO2 that is being circulated
after being cooled to 40°C while consuming little energy
by using seawater, etc. This gas mixture is thenpressurized to 1.7 MPaG by Compressor 2, allowed toswell and decompress to 0.6 MPaG, and heated slightly
to obtain liquefied CO2 in the intended state.
Energy is mainly consumed by the compressors in thisliquefaction process, and the theoretical values under theprocessing conditions shown in Fig. 5 are 39 kWh forCompressor 1 and 35 kWh for Compressor 2. Based onthese values, the theoretical electric energy required to
produce liquefied CO2 in the liquid CO2 conditions from
1 t of CO2 gas that is recovered is 74 kWh/t-CO2.
Assuming that the efficiency of the compressor is 0.7,
the electric energy required to liquefy 1 t of CO2 isapproximately 104 kWh/t-CO2.
Table 1 shows the energy consumption and CO2
emissions of each process for CO2 recovery, liquefaction,
storage and transfer when 150,000 t of CO2 is recovered.
We calculated CO2 recovery by the chemical absorption
method and CO2 liquefaction by using the unit amounts
described above, and the energy consumption for eachprocess was calculated as 431,000 GJ for CO2 recovery
and 15,600 MWh for CO2 liquefaction.
For storage of CO2, we assumed that 10,000 t of CO2
is stored at a temperature of −46°C and pressure of 0.7
MPaG in two tanks each with a capacity of 5,000 m3,
which are thermally insulated with polyurethane foam.
As we specified that the CO2 evaporating due to thermal
conduction from outside the tank during storage is reliquefied and recovered, CO2 is generated due to the useof electricity by the cooling device for this process. Here,estimating that the amount of heat infiltrating into theCO2 storage tank is 100 kW, we specified 170 kW as thepower required for the cooling device to be used forliquefaction of the CO2 that evaporates under the
infiltrating heat in consideration of device efficiency.
Using this value and assuming that 10,000 t of CO2 isstored for an average period of 20 days and replaced 15
times, we calculated 1,220 MWh as the electric energy
necessary for storing a net CO2 amount of 150,000 t.
－5－

We determined that the electric power required for thetransfer pump to transfer the CO2 from the storage tankto the CO2 transport ship would be 250 kW. If it takes 20
hours for one transfer and the transfer is performed 15
times, the electric energy required for CO2 transfer is
75,000 kWh.
We calculated the CO2 emissions in Table 1 bymultiplying the energy consumption by the CO2
emission factor for the energy source in Chapter 2. As
shown in this table, the CO2 emissions from each process
are 25,900 t for CO2 recovery, 5,770 t for liquefaction,
453 t for storage, and 27.8 t for transfer. The total CO2
generated in all four processes we examined wasapproximately 32,200 t for the amount of CO2 handled,which was 150,000 t. Of this value, CO2 recovery
accounted for 80.4%, and CO2 liquefaction for 17.9%.
While the results show that the CO2 emissions were highfor the CO2 recovery process, it is expected that the CO2
emissions would decrease from 25,900 t to 18,000 t if
the new absorption solution with CO2 recovery energyof 1.6 GJ/t-CO2, which is being developed by a NEDO
project,10) can be used, and that the total CO2 emissions
in Table 1 can also be reduced from approximately
32,200 t to 24,300 t.
Table 1 Energy consumption and CO2 emissions

3.2 CO2 separation and recovery by the physicaladsorption method
In this trial calculation, we adopted the PSA separation
and recovery method11).
For the raw material gas, we assumed combustion
exhaust gas with CO2 concentration of 24% and moisture
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“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuels

of 3%. Figure 6 shows the configuration of the process.

Fig. 6 Separation and recovery process flow by physicaladsorption method

Moisture is removed with a dehumidifier, and gas issupplied to the adsorption tower with a blower. The CO2collected by a vacuum pump is liquefied by theliquefaction equipment and stored in the tank. In
addition, we specified that a steam heater would be used
for regeneration in the dehumidifier.
Based on our assumed annual transport amount of
150,000 t, we specified the CO2 production amount as 18
t/h, and the raw material gas supply volume asapproximately 64,000 m3/h in consideration of theseparation and recovery efficiency, etc. We selectedmodels that suited these assumptions for the devices
used in the process such as blower and vacuum pump,and made a simple estimation of the required energy
based on their rated power values.
The heat quantity necessary for regeneration at thedehumidifier is calculated as 42 kJ, and the annual CO2
emissions are calculated as 2,500 t when using the CO2
emission factor for the steam that is used, as indicated in
Chapter 2.
When the power for other devices is electric energy,
the total required energy is estimated as 64.5 GWh.
Assuming the CO2 emission factor for electric power
given in Chapter 2, the annual CO2 emissions arecalculated as 23,865 t.
Therefore, combining steam and electric power, theannual overall CO2 emissions of the CO2 separation andrecovery process by the physical adsorption method are
calculated to be 26,365 t.

4. Energy balance in the CO2 transport process
The transport process is the process of transporting theliquefied CO2 from where it is recovered to where themethane is produced, by sea. Unlike other processes,
there is no energy balance due to a change in material
state such as chemical reaction, pressure or temperature.
The energy balance of this process is therefore mainly－6－

due to the operation of the CO2 transport ship.
The objects of the energy balance calculation due tothe operation of the CO2 transport ship include thepropulsion plant of the ship including the main engine,
equipment used for CO2 cargo handling and maintaining
the state of the conditions of CO2 during transport, theaccommodation facilities for the crew, and other mattersrelated to operation of the ship. The power and electricity
required for the operation of the transport ship is
obtained from the main and auxiliary engines, and theCO2 emissions from these engines were calculated basedon using of low-sulfur fuel oil as its energy.
As described above, the various conditions such as theoperating conditions, cargo-related facilities, andaccommodation facilities have a significant impact on
CO2 emissions from transport ship operations. On theother hand, new ships engaged in international shipping
are subject to CO2 emission regulations using the Energy
Efficiency Design Index (EEDI)12) 13).
In thisexamination, we calculated the CO2 emissions based onthese regulatory values, and added the consideration for
the re-liquefaction equipment and liquefied CO2 pump,which have large effects on the CO2 emissions duringtransport and cargo-handling of liquefied CO2, toestimate the CO2 emissions in the transport process.
Furthermore, we took into consideration the ballast
voyage for the CO2 transport ship to return to the loading
location in addition to the laden voyage from the loading
location for transporting liquefied CO2 to the unloading
location. We also considered the operation of theauxiliary engines during the loading or unloading in theterminal in the CO2 emissions calculation.
The conditions for examining the CO2 emissions are
as follows:a) Total annual transport amount: 150,000 tb) Net annual number of times of transport: 15c) Distance for one transport: 5,000 nautical mile/oneway
The particulars of the CO2 transport ship are as
follows:a) Deadweight: 11,000 tb) Cargo capacity: 10,000 m3c) Vessel speed during voyage: 10 kt(1 kt is the speed of a ship which moves 1 nautical milein 1 hour.)d) Number of ships in operation: 2
We examined the CO2 emissions by dividing thetransport process into the following four modes:
Journal of The Japan Institute of Marine Engineering
Vol.56, No.4 (2021)

“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuelsa) Loading: Liquefied CO2 is loaded onto the CO2transport ship from the shore manifold at the loading
location.
b) Laden voyage: Liquefied CO2 is transported fromthe loading location to the unloading location.
c) Unloading: Liquefied CO2 is unloaded from theCO2 transport ship to the shore manifold at theunloading location.
d) Ballast voyage: The CO2 transport ship is takenfrom the unloading location to the loading location.
In calculating the CO2 emissions, we used the values
described in the EEDI Calculation Guidelines13) as theCO2 emission factor and the fuel consumption rates ofthe main engine and the auxiliary engines.
We set the output of the auxiliary engines that is used
to provide the electricity for services onboard while theship is moored (main engine is stopped) to 5% of the
rated output of the main engine. Since the EEDI is anindicator of the CO2 emissions of a new ship, estimatedin the number of grams emitted when carrying a cargo of
1 t over a distance of 1 nautical mile under certain
conditions at the stages of design and construction, it canalso indicate the ship’s performance.
The EEDI regulations stipulate that the Attained EEDIof a new ship must be less than the Required EEDI thatis determined by the type and capacity of the ship.
In this examination, we calculated the CO2 emissions
under the voyage mode while considering that theRequired EEDI determined based on the conditions of
the CO2 transport ship assumed above is equal to the
Attained EEDI of this ship, and added the emissions by
operating the re-liquefaction equipment under thevoyage mode, emissions by operating the CO2 pumpunder the unloading mode, and emissions from theauxiliary engines while the ship is moored, to calculate
the total CO2 emissions in the transport process asfollows:
I. Navigation days and cargo handling time
Navigation days: 42 days (per round voyage)
Cargo handling time: 20 hours (per round voyage)
Moored days: 4 days (per round voyage, includingcargo loading or unloading time)
II. Net number of days in each modea. Loading: 30 daysb. Laden voyage: 315 daysc. Unloading: 30 daysd. Ballast voyage: 315 days
III. EEDI for the CO2 transport ship (3rd level－7－

regulation)
EEDI: 11.257 g-CO2/t･nautical mile
IV. Total CO2 emissions: Approx. 20,500 t
There are many technical issues that need to be solved
regarding the liquefied CO2 transport ship described inthis chapter, including the development of devices suchas the re-liquefaction equipment. The energy balance
presented here is a rough estimate based on assumptions
for both the items described in this section and those thatare not.

5. Energy balance in the methanation reaction
process
As shown in Fig. 7, methanation is an exothermic
reaction which is given by:
CO2 + 4H2 → CH4 + 2H2O − △165 kJ/mol(1)This is commonly known as the Sabatier reaction. Since
the thermal energy of 4 mole of hydrogen, which is 967
kJ, is converted into the thermal energy of 1 mole ofmethane, which is 802 kJ, in this reaction, it istheoretically possible to convert hydrogen into methanewith more than 80% of the energy efficiency as follows:
802 kJ / 967 kJ × 100 = 82.9%
In addition, as it is an exothermic reaction, the reaction
proceeds autonomously without supplying externalenergy.
As shown by Eq. (1), a reverse reaction also occurs
whereby the water that is formed as the reaction proceeds
reverts to CO2 and hydrogen again. Therefore, thereactor has two stages as shown in Fig. 7 so that the water
generated in the first stage is removed before the gas is
introduced into the second stage of the reactor. This
allows conversion of approximately 96% in the firststage, and the remaining 4% is introduced into thesecond stage, achieving a conversion rate of 99% orhigher.

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“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuels

methane is manufactured annually.
Table 2 Material balance in methanation

Fig. 7 Flow of methanation

5.1 Energy consumption by CO2 vaporization
Since the liquid CO2 transported by a CO2 transport
ship is vaporized to supply into the methanation plant inthis process, energy to maintain the temperature in thestorage tank and energy to vaporize it are needed.
The liquefied CO2 in the transportation is at 0.7 MPaG
and −46°C, and the energy necessary to maintain thetemperature in a tank is 170 kWh, which indicates that
1,489,200 kWh is required each year.
Next, as the vaporization energy from the liquid CO2
into gas at 0.7 MPaG and 20°C, the electric power
consumption is calculated based on the enthalpy
difference between the two phases, which is 400 kJ/kgCO2, as follows:
150,000 t-CO2 × 400 kJ/kg-CO2 / 3,600 s= 16,667 MWh
The annual electric power consumption is thus
calculated as
1,489 + 16,667 = 18,156 MWh.
Multiplying this by the CO2 emission factor for electric
power, 0.370 kg-CO2/kWh, we obtain
18,156 MWh × 0.370 kg-CO2/kWh = 6,718 t-CO2
as the annual CO2 emissions.
5.2 Material balance in the methanation process
Table 2 shows the material balance in the process
shown in Fig. 7 when 150,000 t of CO2 is methanizedunder the assumed conditions for 8,000 hours operation
annually.
The CO2 flow rate supplied from the CO2 tank iscalculated as
150,000 t × 22,400/44 Nm3/t / 8,000 h = 9,545 Nm3/hand it is supplied into the reactor in combination withfour times the amount of renewable energy-derived
hydrogen. By this methanation reaction, 54,458 t-CH4 of－8－

5.3 Energy consumption by the methanation process
Since the methanation process is an exothermic
reaction, no external energy is required for carrying out
the reaction, and electric power consumption consists ofthe power for auxiliary machines such as pumps, control
panel and startup heater (cooling water andinstrumentation air are not taken into consideration as
supplied utilities).
Assuming that the process start/stop occurs 15 times
per year, the electric power consumption by the process
for startup operation and 8,000 h of rated operation is
calculated as 2,042 MWh, which results in annual CO2
emissions as follows by multiplying by the CO2 emission
factor of 0.370 kg-CO2/kWh:2,042 MWh × 0.370 kg-CO2/kWh / 1,000 = 755 t-CO2.
5.4 CO2 emissions from the methanation process
Table 3 shows the electric power consumption andCO2 emissions that occur due to the operations of there-liquefaction facility to maintain the liquid CO2 in theCO2 tank at 0.7 MPaG and −46°C, the heater toevaporate it, and other equipment in the methanation
process.
Based on these results, the annual CO2 emissions fromthe methanation process are calculated as follows:(551 + 6,167 + 755) t-CO2 = 7,473 t-CO2.
Table 3 CO2 emissions results

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“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuels

6. Energy balance in the carbon recycled methaneliquefaction processThis process includes the facilities to liquefy themethane gas synthesized in the methanation reaction
process, store the liquefied methane and supply it toships as ship fuel.
Figure 8 shows the configuration of the main facilities
and equipment in this process. The synthesized methanegas, which becomes the feed gas, is pressurized, andimpurities such as CO2 and moisture which would cause
solidification and clogging at low temperature areremoved to ppm order during the stage before theliquefaction facilities.
The chemical absorption method using an amine
solution as the absorbent is used to remove CO2.
Next, moisture is removed by a dehydration facility
using molecular sieves. By installing two dehydration
towers in the dehydration facility and conducting
operation and regeneration alternately, the facility can be
operated continuously. The synthesized methane fromwhich impurities have been removed to levels that would
cause no problem is pressurized and fed to theliquefaction facilities.
In the methane liquefaction facility, methane isliquefied through a liquefaction system by refrigerant toremove the heat from the methane gas by thevaporization heat of the circulated refrigerant. Whilevarious liquefaction methods for the liquefaction
refrigerant process are possible, we adopted the propane
precooling/mixed refrigerant method with the highest
thermal efficiency in this study.
Liquefied methane is stored in a tank, pressurized after
going through a cryopump and supplied to the LNG fuelship as ship fuel.
The product gas from the methanation facility contains
a small amount of hydrogen, and it is not efficient tocompletely liquefy it. It is therefore accumulated at the
top of the liquefied methane tank as vaporized gas, andthe gas is continuously released from the top of the tank.
The vaporized gas in the tank contains methane for
equilibrium composition in addition to hydrogen, andour system effectively utilizes it as fuel for in-house
power generation.
Table 4 shows the results of estimating the energy
consumption and CO2 emissions for each facility. The
major energy consumption by facilities other than thegenerator is for rotary machines such as compressors and－9－pumps, and is in the form of electric power. The CO2
emissions were calculated from electric power
consumption by using the CO2 emission factor in
Chapter 2.
Electric power is consumed mainly by the refrigerant
compressor in the liquefaction facility, followed by thefeed gas compressor. The dehydration facility conducts
dehydration by heating the gas in the tank and aerating
it, and we neglected the CO2 emission from this facility
as its energy consumption is quite small. The CO2
emissions were calculated by subtracting the electric
power generated by the gas turbine generator using thegas in the tank as the fuel from the overall electric power
consumption for this process. We counted the CO2
emissions from the gas turbine generator by combustion
as the CO2 emissions from this process.

Table 4 Estimation of CO2 emission from methaneliquefaction process

The annual CO2 emissions calculated by multiplying theelectric power supplied from an external source by theCO2 emission factor are approximately 7,840 t, and theannual CO2 emissions from this process are estimated as
approximately 17,360 t by adding the annual CO2
emissions of approximately 9,520 t from the gas turbine
generator.

Journal of The Japan Institute of Marine Engineering
Vol.56, No.4 (2021)

“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuels

Fig. 8 Configuration for methane liquefaction process

7. Overall evaluation of the supply chain
8. Conclusion
As shown in Fig. 9, dividing the energy balance for theentire supply chain, accumulating the processes whichwere calculated in Chapters 3 to 6, by the lower calorificvalue of methane gives approximately 27 g-CO2/MJ.

Fig. 9 CO2 emissions per unit calorific value of zero-emission
methane fuel for ships

In addition, it is expected that the CO2 emissions perunit calorific value for the entire supply chain can be
reduced to approximately 20 g-CO2/MJ by improving
the efficiency of the separation and recovery technique,and using electric power derived from renewable energy
and methane as the fuel for the CO2 transport process.
The CO2 emissions per unit calorific value(approximately 27 g-CO2/MJ) for the amount of energy
input in each process estimated by our Working Groupare comparable with the CO2 emissions of biodiesel,hydrogen refined from methane, and hydrogen formedby electrolysis of water using renewable energy, which
are considered zero-emission fuels in general (see Fig.
10). It is also worth noting that the Working Groupconsidered the allocation of the recovered CO2 and theCO2 generated in the production of H2 that is input into
the methanation reaction process outside the boundary.

In order to verify whether synthetic methane, which isone of the alternative fuel candidates for reducing GHG
in marine transport, can be considered a zero-emission
fuel, the Ship Carbon Recycling Working Group
conducted a trial calculation on the energy balance ineach process of the assumed supply chain.
We were able to confirm that its value (approximately
27 g-CO2/MJ) is comparable with those of otheralternative fuel candidates by comparing it with the CO2
emissions per unit calorific value of main alternative
fuels published by DNV14) as shown in Fig. 10, since the
IMO has not given a definition of zero-emission fuel. We
found that the methane synthesized by methanation
could be deemed a zero-emission fuel.

Fig. 10 CO2 emissions per unit calorific value for majoralternative fuels by DNV

In the future, we plan to continue examining thefeasibility of the remaining Issues II to VI (large CO2transport ships, supply of renewable energy-derived
hydrogen, methane slip, supply infrastructure, economic
feasibility, etc.) and keep promoting carbon recycled
methane fuel.

－10－

Journal of The Japan Institute of Marine Engineering
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“Ship Carbon Recycling Working Group” inside JACCR Launches Initiative for Zero-emission Ship Fuels

Acknowledgements

14) Assessment of selected alternative fuels andtechnologies， DNV-GL， 2019

We sincerely thank Professor Emeritus Koji Takasaki,
Kyushu University, who provided advice on theexamination and evaluation of trial calculation results by
the Ship Carbon Recycling Working Group, and also
thank all other parties who assisted us.

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Journal of The Japan Institute of Marine Engineering
Vol.56, No.4 (2021)