# Conventional fuels with indirect CCS

The refining of crude oil produces the current transportation fuels of choice, gasoline and diesel. The existing transportation infrastructure is built around these fuels and their use in the immediate future is likely. Under these circumstances, CO2 emissions would be neutralized using indirect methods. The cost of neutralizing oil can be estimated using equation (7.3) and Table 7.2; the symbols used are described in the discussion below.

COStfuel ^GJ) = Coil X fo/G + (CcO2 + 1-5 X Cstorage) X fc/E X /lc- (7.3)

The cost per unit energy of neutralizing conventional fuels is determined, in equation (7.3), by adding the energy cost of the fuel to the cost of offsetting the resultant emissions through CCS. The energy cost of oil is the product of the cost per barrel and a conversion factor fo/G) that translates the cost into the appropriate units. The conversion factor fO/G), relating the cost of a gallon of gasoline from the refinery to a barrel of oil, was obtained by comparing the price data over the last

14 years and using a value of 130.8 MJ gal-1 of gasoline (Keith & Farrell 2003). The cost of offsetting the emissions is the cost of capture and storage multiplied by the emissions per GJ of energy. The cost of capture (CCO2) refers to the cost of removing CO2 from the atmosphere. Underground geological storage is projected to cost \$1-8 tCO-1 with transportation of the compressed CO2 by pipeline costing \$2-4 tCO-1 for a 250-km run with an annual flow rate of 5 Mt CO2 (IPCC 2005). The cost of storage is multiplied by a factor of 1.5, as air capture produces an amount of CO2 equivalent to 50 per cent of the amount captured if coal is used in the regeneration phase (Zeman 2007). The use of other methods of producing high-temperature heat, e.g. nuclear, would reduce this factor. The tonnes of CO2 released per unit energy contained in gasoline (/C/E) are derived using an emission factor of 8.8 kg CO2 gal-1 (EPA 2005). The final coefficient (/Lc) relates the life-cycle CO2 emissions to the energy content of the final fuel, gasoline. In this manner, we include the process CO2 emissions associated with converting oil to gasoline.

Using the values listed in Table 7.2 and the values of \$100-200tCO-1 for air capture, the fuel cost is in the range \$24-44 GJ-1. The cost of conventional gasoline is in the range \$13-24 GJ-1 as oil prices fluctuate between \$50 and \$100 per barrel. Given the assumptions above, air capture increases the cost of fuel by \$10-20 GJ-1; alternatively, with oil at \$100 per barrel and air capture at \$100 tCO-1, the cost of vehicle fuel increases by 42 per cent.

### 7.3.2 Synthetic fuels using atmospheric CO2

Producing synthetic fuels from CO2 requires hydrogen and a high-pressure catalytic reactor to synthesize the fuel. The cost of producing hydrogen with CCS on an industrial scale has been estimated at \$7.5-13.5 GJ-1 (IPCC 2005). The cost estimates for hydrogen vary depending on the price of natural gas, as steam reforming of methane is the dominant method for H2 production (Ogden 1999; Galindo Cifre & Badr 2007). Thermochemical methods for production are expected to be more economical than electrolysis except under circumstances where electricity is available at prices below \$0.02 (kW h)-1 (Ogden 1999; Sherif et al. 2005) combined with a 50 per cent reduction in electrolysis capital costs (Ogden 1999). Conditions favourable to renewable electrolytic hydrogen may exist, e.g. excess wind power during early morning hours, but any gains from low electricity costs must eclipse increased capital costs associated with intermittent use of the electrolysers. We believe that only under exceptional circumstances would one form of secondary energy (electricity) be converted to another (hydrogen). We use a representative value of \$10.5 GJ-1 for carbon neutral hydrogen. The CO2 resulting from the

Table 7.3 Coefficients for synthetic fuels from atmospheric CO2

Coefficient C

Coefficient C

Units Value Source

- EPA (2005) IPCC Lide (2000) Michel (1999) IPCC (2005)

and Gustavsson et al. (2007)

production of hydrogen is stored underground with any CO2 produced during the regeneration phase of air capture.

costfuel = CCO2 X /c/E + CH2 X fs/p + Csynthesis + O.5 X Cstorage X fC/E-

The cost of producing synthetic fuels from atmospheric CO2 is calculated from equation (7.4). The total cost is the sum of producing the CO2 and hydrogen added to the cost of the synthesis reactors along with storing fugitive CO2 emissions. Again, the cost of air capture is estimated while the emissions per GJ of fuel produced (fC/E) are equated to gasoline. The values of fC/E based on Table 7.1 are 4-10 per cent lower than that of gasoline, which is a small advantage. The cost of hydrogen, a representative value, is multiplied by a factor (fS/P) representing the efficiency of transferring the embedded energy to the fuel. The hydrogen usage factor is calculated as the average of the inverse of hydrogen energy efficiency in Table 7.1. It represents the extra cost associated with H2 feed lost to water formation, as shown in equations (7.1) and (7.2). The synthesis costs vary with the fuel produced as the operating conditions and choice of catalysts vary. We used a representative value for multi-reactor synthesis with CO2 as feedstock (Michel 1999; Gustavsson et al. 2007). Using the values given in Table 7.3 and air-capture costs of \$100-200 tCO-1, the production cost for synthetic fuels is in the range \$23.5-\$30 GJ-1. Mitigating the fugitive emissions from H2 production using air capture would add \$2-4 GJ-1 to the total cost, based on 0.3 tCO2 per tCO2 used in fuel production.

The use of hydrogen as a large-scale fuel for distributed road transportation requires a complete replacement of the associated infrastructure including production, distribution and fuelling stations. We consider only the cost to deliver hydrogen to the vehicle in \$ GJ-1. On the one hand, this neglects the cost reductions that will arise where hydrogen enables the use of fuel cells that are more efficient than the

7.3.3 Hydrogen use in transportation

Table 7.4 Coefficients for hydrogen transportation systems

Coefficient Ce2 Cdist Cation

Value 10.5 10-22.5 5

Source IPCC (2005) Yang & Ogden (2007) Ogden (1999)

conventional engines used with CNHCs, while on the other hand, it neglects the extra vehicle costs associated with hydrogen storage and hydrogen power plants.

Our hydrogen cost assumptions are based on large-scale central-station hydrogen production using fossil fuels with CCS, since this is the most immediately available technology. Currently, over 90 per cent of hydrogen production is derived from the steam reforming of methane at production scales of up to 100 million standard cubic feet of hydrogen per day (Ogden 1999; Sherif et al. 2005; Galindo Cifre & Badr 2007). The estimates often use a purchase price of less than \$6 GJ-1 for natural gas, which may not reflect prices for large-scale hydrogen production. Above this price point, production costs are similar for coal costing \$1.5 GJ-1.

The cost of hydrogen fuels delivered to the vehicle is estimated using

Using the values given in Table 7.4, the cost of hydrogen fuels delivered to the vehicle ranges from \$25.5 GJ-1 to \$38 GJ-1. The range is strongly dependent on the cost of distributing the hydrogen to fuelling stations, which is in turn dependent on market penetration of hydrogen vehicles (Yang & Ogden 2007). The range in Table 7.4 reflects penetration levels of 5 per cent (\$22.5 GJ-1) and 50 per cent (\$10 GJ-1) where market penetration is taken as the proportion of vehicles using hydrogen fuel. These values are taken from the 'base case' of Yang & Ogden; the cost of other scenarios varies from -22.5 to +37 per cent for the 50 per cent market penetration and -17 to +70 per cent for 10 per cent. Equation (7.5) does not include any CO2 removal from the air to compensate for the fugitive emissions associated with H2 production from fossil fuels, as mentioned in Section 7.2.1. Using an air-capture cost of \$100 tCO-1, the additional cost ranges from \$1 GJ-1 to \$3 GJ-1 including storage.

### 7.3.4 Carbon neutral fuels from biomass

As discussed in Section 7.2.4, there are many ways to convert biomass to CO2 and fuels. We focus on fuel synthesis in a manner similar to that described in Section 7.3.2 using CO2 derived from a biomass power plant. The cost of CO2

derived from such a plant is a function of the cost of biomass and the difference between the balance of system costs for the biomass plant and the cost of a carbon neutral fossil plant. The cost for the balance of system is the difference between the cost of biomass electricity with CCS and the fuel cost. The fuel cost is obtained by dividing the biomass cost with the energy content; the result is then divided by the thermal efficiency of the plant. The cost of carbon neutral electricity was taken as \$0.073 (kW h)-1 (IPCC 2005).

The ideal case is where the revenues generated from the sale of electricity offset the cost of the plant and capture system. The cost of CO2 is then the cost of biomass divided by the tonnes of CO2 produced per tonne of biomass or \$tCO-1 = 0.59x(\$tonne-1), based on the chemical formula for woody biomass (Petrus & Noordermeer 2006). In practice, the relationship will depend on the capture efficiency and the specific technology. Using studies from the literature, we establish two relationships for the cost of CO2 and the cost of biomass based on steam gasification (Rhodes & Keith 2005), equation (7.6), and oxygen gasification (Audus & Freund 2004), equation (7.7). The CO2 and dry biomass costs are expressed in \$ tonne-1:

Steam gasification is the most cost-effective method for the biomass cost range used in this work. The resulting cost for CO2 is in the range \$27-\$70tCO-1. The cost of producing carbon neutral fuels by indirect methods, as per equation (7.3), using these values ranges from \$16.5 GJ-1 to \$31.5 GJ-1. By comparison, direct methods based on equation (7.4) produce a delivered cost of fuel ranging from \$18.5 GJ-1 to \$21 GJ-1. These costs are lower than the associated values for air capture using both indirect (28-33 per cent) and direct (23-30 per cent) methods.

Biomass can be converted directly to hydrocarbon via the F-T synthesis, labelled here as biomass F-T. This technology has reached the commercial stage with a plant in Freiburg, Germany, producing 15 k tonnes yr-1. The cost of these fuels has been estimated at \$21 GJ-1 (Fairley 2006). The process uses biomass residues and the sensitivity to increasing feedstock prices, owing to increased demand for biofuels, was not discussed.

### 7.3.5 Comparison of methodologies

A cost comparison of the various delivery methods for carbon neutral transportation fuels is presented in Figure 7.3. The figure contains the upper- and lower-bound estimates, based on the previous sections, for the different methods. The total cost Figure

H oil H air capture H biomass E3 hydrogen 0 synthesis 0 distribution □ others 7.3 Comparison of delivered costs for carbon neutral transportation fuels.

### Figure

H oil H air capture H biomass E3 hydrogen 0 synthesis 0 distribution □ others 7.3 Comparison of delivered costs for carbon neutral transportation fuels.

has been divided into subsections (oil, air capture, biomass, hydrogen, oxygen, fuel synthesis including reforming and fuel distribution including fuel stations) to illustrate the relative importance of each component.

Reviewing Figure 7.3, we observe that the cost of oil, ranging from \$50 to \$100 per barrel, has a strong effect on the cost of indirect methods. The cost of oil accounts for 56-55 per cent of indirect routes using air capture and 80-77 per cent of costs for biomass-based systems. Direct routes are characterized by the need for hydrogen. The contribution from hydrogen production ranges from 56 to 43 per cent for air-capture systems, 71 to 61 per cent for direct biomass systems and 41 to 28 per cent for hydrogen-based systems. The lower percentage for the hydrogen infrastructure highlights its dependence on a hydrogen distribution system and fuelling stations. At oil costs above approximately \$150 per barrel oil substitutes win out, and direct routes to CNHCs are uniformly preferred to indirect routes.

The choice of mitigation technology will not, of course, depend simply on cost due to the strong path dependency in the coupled development of vehicle technologies and refuelling infrastructures. Considering costs alone, and ignoring the large uncertainties in technology, we can nevertheless draw some interesting conclusions about how the relative cost competitiveness of various routes to CNHCs depends on the cost of carbon, biomass and crude oil.

We first consider the comparison between direct and indirect routes as a function of the cost of petroleum. We previously established, in Section 7.3.2, that the cost of delivering synthetic fuel is approximately \$24 GJ-1 when air capture costs 0 25 50 75 100 125 150 175 200 cost of C02 emissions (\$ per tonne C02)

Figure 7.4 Mitigation options based on synthetic fuel production using \$100 tCO-1 air capture with \$10.5 GJ-1 H2.

0 25 50 75 100 125 150 175 200 cost of C02 emissions (\$ per tonne C02)

Figure 7.4 Mitigation options based on synthetic fuel production using \$100 tCO-1 air capture with \$10.5 GJ-1 H2.

\$100tc0-1 and H2 costs \$10.5 GJ-1. Using the correlation from Table 7.1 (/O/g), we can convert this value to an oil cost of \$96 per barrel. Thus, at higher oil prices, it is economical to produce synthetic fuels under the assumed conditions. This value does not include any price on C02 emissions. Based on the emission factor fC/E and the life-cycle factorfLC, the combustion of the gasoline produces the equivalent of 0.288 tC02 per barrel of oil. The values define a line with a negative slope, as shown in Figure 7.4, which also contains a vertical line whose abscissa represents the cost of air capture. Above the line, mitigation by direct air capture is the most economical option. At emission prices lower than the cost of air capture, the most economical option is to pay for the emissions, while at higher prices, indirect methods are preferable. The area bounded by low oil and emission costs refers to the 'business-as-usual' (BAU) scenario. A similar graph can be produced for CNHCs using biomass by drawing a parallel solid line with the y-axis ordinate at \$73.5 per barrel (\$18.5 GJ-1) and a vertical dashed line with the x-axis abscissa at \$27tC0-1 (\$40 tonne-1 biomass).

The balance between the cost of fuels using CO2 produced from biomass and air capture can also be measured in this manner. In this case, the common metrics are the cost of hydrogen and fuel synthesis. The comparison, as shown in Figure 7.5, contains curves for the 'ideal' case as well as steam reforming (Rhodes & Keith 2005) and oxygen gasification (Audus & Freund 2004). In the ideal case, the revenues from the sale of electricity exactly offset the capital and operating costs of the facility resulting in a direct relationship between the cost of biomass and C02. The area where air capture is economical is below and to the right of the gasification lines. The intersection of the gasification curves occurs at a biomass price of \$180 tonne-1, beyond which it is more economical to use oxygen 0 50 100 150 200 250 300

cost of biomass (\$ tonne-1)

Figure 7.5 Effect of biomass cost on the cost of producing CO2 for fuel synthesis (dashed line, ideal; solid line, Audus & Freund (2004); dot-dashed line, Rhodes & Keith (2005)).

0 50 100 150 200 250 300

cost of biomass (\$ tonne-1)

Figure 7.5 Effect of biomass cost on the cost of producing CO2 for fuel synthesis (dashed line, ideal; solid line, Audus & Freund (2004); dot-dashed line, Rhodes & Keith (2005)).

gasification owing to the higher capture rate (85 per cent as opposed to 55 per cent). The study area can expand to the right if the external costs of biomass are included. The threshold for \$100 tCO-1 air capture is if the total cost of biomass, including non-market costs, rises above \$105 tonne-1.

Similarly, a comparison can be made between fuels produced using CO2 from air capture with using hydrogen on-board vehicles. Given that the cost of producing the hydrogen is identical, the comparison is between producing the CO2 and synthesis for air capture and distributing the hydrogen to fuelling stations, as shown in Figure 7.6. We have not included the cost of fuelling stations, which would add \$15 tCO-1 for each \$1 GJ-1 of cost. The cost estimate for fuel stations used in Section 7.3 (\$5 GJ-1) would add \$75tCO-1 to the allowable cost of air capture. Even without the fuelling stations, the required cost of air capture to be competitive with a fully developed hydrogen economy is not unreasonable. We investigated the effect of a 50 per cent reduction in the cost of fuel synthesis, shown as the dashed line in Figure 7.6. 