*2.2. Description of Steam Methane Reforming-Based System*

Figure 1 shows the block diagram of the steam methane reforming system combined with HT-PEMFC and CCS on board ships. The integrated system consists of six main unit/systems: Reformer for producing reformate gas, combustor for providing heat to reformer, WGS reactor for conversion of CO to CO2, HT-PEMFC for power generation, CO2 capture unit, and CO2 liquefaction system for storage.

**Figure 1.** Block diagram of steam methane reforming-based system.

Natural gas is normally used as feedstock for steam methane reforming and it normally contains small amounts of sulfur compounds, which must be removed to avoid contamination of the catalyst in the reformer and low temperature shift reactor [50]. However, in the proposed system, LNG was considered as feedstock for reforming. As an industry practice, prior to liquefaction, natural gas is further treated to remove sulfur compounds along with water and any residual CO2 to avoid freezing [51]. Therefore, a desulfurization unit was not included in this study. As shown in Figure 2, liquefied from an on-board storage tank is pumped and vaporized by heat exchange with the captured CO2 in HEX-1. Then, the vaporized CH4 is divided into two streams: One as feedstock for reforming (stream F4), the other as fuel for the combustor (stream F7). The CH4 used as feedstock is mixed with high temperature steam (stream W3) and further preheated by heat exchange with the reformate gas stream from the reformer at HEX-2. Then, the steam methane mixture (stream F6) is supplied to the reformer, where the reforming reaction occurs as expressed in Equations (4) and (5), and converted to H2, CO, and CO2. The steam methane reforming reaction is highly endothermic; therefore, a large amount of heat must be supplied by the combustor by burning supplemental methane as fuel and by burning off-gas (mostly unreacted CH4 and unused H2) from the fuel cell. The operating temperature

and pressure for the steam methane reformer in this model were set as 700 ◦C and 3 bar, respectively. The steam to carbon molar ratio (S/C) of 3:1 was applied to avoid coke formation.

$$\text{CH}\_4 + \text{H}\_2\text{O} = \text{CO} + 3\text{H}\_2 \quad \Delta \text{H}\_{298} = 206.3 \text{ kJ} \text{mol}^{-1} \tag{3}$$

$$\text{CH}\_4 + 2\text{H}\_2\text{O} = \text{CO}\_2 + 4\text{H}\_2 \quad \Delta\text{H}\_{298} = 165 \text{ kJ} \text{mol}^{-1} \tag{4}$$

The reformate gas exiting HEX-2 (stream R2) is further used to preheat air entering to the combustor, and then enters the WGS reactor. The WGS reaction is moderately exothermic and it converts undesired CO in reformate gas to CO2 and H2, as shown in Equation (6). The WGS reactor is modeled as a single stage, and the reaction occurs at 250 ◦C. The heat produced during the WGS reaction is used for steam generation.

$$\text{HCO} + \text{H}\_2\text{O} = \text{CO}\_2 + \text{H}\_2 \quad \Delta \text{H}\_{298} = -41 \text{ kJ} \text{mol}^{-1} \tag{5}$$

**Figure 2.** Process flow diagram for steam methane reforming-based system.

The reformate gas leaving the WGS rector (stream R4), which has an acceptable level of CO content (<1%) for the HT-PEMFC, is firstly cooled down to 160 ◦C and then supplied to the anode side of the HT-PEMFC. Dry air is supplied to the cathode side and used for the fuel cell reaction, converting the chemical energy of hydrogen to electricity. Unreacted hydrogen is supplied to the combustor for heat generation. The exhaust gas from the combustor preheats the water supplied to the reformer and then is cooled down to 40 ◦C when exiting Cooler-1. After removing the condensed water at Sep-1, the exhaust gas stream (E4) enters the post combustion CO2 capture unit using aqueous MEA as solvent. As large quantities of heat are required to regenerate the solvent within the MEA CO2 capture process, the fractions of heat produced from the WGS reactor, HT-PEMFC, and HEX-4 are supplied to the CO2 capture unit. The MEA CO2 capture unit is modeled as a "black box" in the present study. The detailed explanation for the black box model of the MEA process is provided

in the next section. Then, the captured CO2 is compressed to 7 bar by two stage compressors with cooling in between and then partially liquefied by heat exchange with the LNG feedstock at HEX-1. The liquefied CO2 is separated in Sep-2 and stored at 7 bar, −48.5 ◦C in a temporary tank on board the ship. Noteworthy, although CO2 capture by using low temperature and vapor–liquid phase separation could be advantageous from the perspective of CO2 liquefaction, the capture ratio is significantly affected by concentration of other gases. Therefore, in this study, the MEA CO2 capture unit and CO2 liquefaction system are modeled separately.
