Different Options for Producing Hydrogen with Reduced CO2 Emission

390
377,43
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370
360
350
340
330
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1959196419691974197919841989199419992004
ye ar
 Figure 1.1: CO atmospheric concentration in the last 25 years [3] 
2
 5%
21%
35%
39%
Electric PowerResidential and IndustryTransportsOthers
 Figure 1.2: CO emission by sector in 1995 [4] 
2
 In this context, the use of hydrogen as energy carrier is very promising, as it can 
be used not only for power generation at large scale, but also for distributed 
generation and for transportation. In these fields the abatement of carbon emission is 
not pursuable through CO capture and alternative approaches have to be followed. 
2
If H i s b u r n e d C O is not emitted. Of course the net CO emission to the 
222
atmosphere is zero only if hydrogen is produced from a carbon-free source (e.g. 
renewables + electrolysis) or carbon is removed and stored during hydrogen 
production from fossil fuel. Figure 1.3 illustrates the possible sources for H supply 
2
and the different options for its application in satisfying energy demand. It is worth 
noting that the size of sectors has no connection with the expected market. 
2
 ppm
Figure 1.3: CO emission by sector in 1995 [5] 
2
 Various technologies for producing pure H have been proposed (see table 1.3 
2
[6]). Some of them are based on mature technologies, such as: 
• Steam Methane Reforming, SMR (from natural gas, or oil); 
• Partial Oxidation (from oil & derivatives); 
• Gasification followed by shift reaction (from coal); 
• Electrolysis (from water). 
Other technologies (such as biomass gasification) have never been applied to H 
2
production, even if there are several applications in other fields. In some cases 
research is focused on the optimization of existing technologies in order to make 
them more suitable to H production: for example, in the field of gas separation there 
2
is a lot of interest in inorganic membranes, which could be integrated in reforming 
and shift reactors. Some technologies, instead, are still at an early demonstration 
stage or their costs are currently too high (Biophotolysis, Thermo-chemical water 
splitting, High Temperature Electrolysis, Photolytical Water-Splitting). 
As it was pointed out earlier, the most used technologies for H production are 
2
based on thermo-chemical conversion processes of fossil fuels (Table 1.1). Those 
processes produce hydrogen but release CO in the atmosphere, and this has to be 
2
avoided in order to reach the goal of reducing greenhouse gases emissions, while 
producing a carbon free energy carrier. Currently, the processes that use renewable 
sources for H production are biomass gasification and electrolysis using wind or 
2
photovoltaic energy. Both these methods are characterized by the typical problems 
common to all renewable sources: discontinuity and high costs. Therefore, fossil 
3
 
fuels will necessarily be considered as the first choice in the pathway towards the 
hydrogen economy, as it is clearly pointed out in the road-maps prepared in Europe 
(figure 1.4) and in USA (figures 1.5 and 1.6). 
If we consider hydrogen as a fuel for transportation, other issues are to be 
solved: storage, infrastructure for distribution and final users. US DOE has planned 
the transition to the marketplace between 2009 and 2025 (the commercialization 
decision by industry is expected for 2015), while the phase of expansion of markets 
and infrastructure is foreseen between 2015 and 2035. In all cases, a key-role for 
hydrogen competitiveness in the transportation field is the development of low-cost 
and more efficient technologies for its delivery, storage and end-use. For example 
US DOE [7] has fixed the following milestones towards the hydrogen economy: (i) 
On-board hydrogen storage systems with a 9% capacity by weight to enable a 300 
mile driving range; (ii) hydrogen production from natural gas or liquid fuels at a 
price equivalent to $1.50 per gallon of gasoline at the pump at 5,000 psi; (iii) 
hydrogen delivery technologies that cost $1.00 per gallon of gasoline equivalent. 
Table 1.3: Hydrogen production technologies [6] 
4
 
Figure 1.4: European Road-Map [5] 
5
 
Figure 1.5: Transition to Hydrogen Economy in USA [7] 
6
 
Figure 1.6: Government-Industry Roles in the Transition to a Hydrogen Economy [7] 
In the present work however the attention was focused on the technologies for 
hydrogen production no matter how it is stored, transported and used. In particular 
the aim of the present work is to assess the techno-economic feasibility of different 
hydrogen plants (see section 1.1), which can be considered as a near-to-mid term 
step in the route of hydrogen economy: (i) conventional steam methane reforming; 
(ii) coal gasification; (iii) biomass gasification; (iv) sorption enhanced steam 
reforming. The simulations were focused both on system-optimization of existing 
hydrogen plants (i, ii ,iii) and on the analysis of emerging and not commercially 
ready technologies (iv). In all the cases CO capture has been considered, so that the 
2
hydrogen plants investigated can be really included in the path towards hydrogen 
economy. 
Finally a comparison of plant performance and hydrogen cost obtained in the 
different configurations has been carried out, to determine the possible economic 
scenarios in the near-to-mid term. Recent estimations of H cost (see table 1.4 and 
2
figure 1.7) vary in a wide range, due to different assumptions in plant performance 
and especially in feedstock cost. Besides the rapid increase in the price of, oil, 
natural gas and electricity (see figure 1.8 and 1.9) makes the estimations of two 
years ago quite out-of-date. For example in table 1.4 (2003) oil cost is 25-29 $/bbl, 
while natural gas is 3-4 $/GJ. In the last two years the cost of oil is doubled (figure 
1.8), and the price of gasoline (figure 1.10) has exceeded the value of 2.5 $/gallon 
(~0.7 $/l), thus the value of 0.2 $/l indicated in figure 1.7 (2002) is more than three 
times lower than the current value. Therefore the price of hydrogen and gasoline are 
not so distant as they appeared in 2002 (figure 1.7). On the other hand the cost of 
feedstock should be carefully taken into account, if a correct estimation of the H 
2
7
 
cost is required. Therefore in this work (chapter 2 and 4) sensitivity analysis have 
been carried out for determining the influence of feedstock on the final cost of 
hydrogen. The economic analysis is deliberately simple e detailed, so that 
modifications to the assumptions can be made quickly and easily. 
Table 1.4: Expected cost of hydrogen production and total supply cost [8] 
H from H from H On-H Off-H H 
222222
COST Gasol./ Natural HfromH from 
22
NG coal shore shore Solar Solar 
[$/GJ] DieselGas biomassNuclear 
no CO no CO Wind Wind ThermalPV 
22
Fuel/Electr $25-29 3-4 3-5 1-2 2-5 3-4 4-5.5 6-8 12-20 2.5-3.5 
LNG LNG 
/bbl imp. imp. ¢/kWh ¢/kWh ¢/kWh ¢/kWh ¢/kWh 
Feedstock 4-5 3-4 3.8-6.3 1.3-2.7 2.9-7.1 10-13 13-18 20-26 39-65 8-11 
Process 2 NA 1.2-2.7 4.7-6.3 5-6 5 5 5 5 5 
Production 6-7 3-4 5-9 6-9 8-13 15-18 18-23 25-31 44-70 13-16 
Distribution <1-1 <1-1 2 2 2-5 2-5 2-5 2-5 2-5 2 
Refueling 2 4 5-7 5-7 5-7 5-7 5-7 5-7 5-7 5-7 
Total Supply
Cost 8-10 7-9 12-18 13-18 15-25 22-30 25-35 32-43 52-82 20-25 
Figure 1.7: Cost of H dispensed at the fuelling station forecourt (€/liter gasoline 
2
equivalent) [9] 
8
 
Figure 1.8: Summary of natural gas border prices 2004-2006 [10] 
Figure 1.9: Summary of electricity average wholesale and retail prices 2004-2006 in Italy 
[10] 
9
 
Figure 1.10: U.S. Retail Gasoline Prices, 1990-2006 [11] 
1.1 Thesis outline 
Chapter 2 presents a detailed study of a plant based on steam methane 
reforming (SMR), which represents the most mature and widespread technology for 
hydrogen production. This plant represents the state of art of H production and can 
2
achieve an efficiency of approximately 75%, i.e. the final hydrogen has an energy 
content equal to 75% of the initial fuel [12,13]. However hydrogen plants based on 
SMR are characterized by a strong economy of scale, thus they are the preferable 
3
choice for capacity higher than 1,000-5,000 Sm/hr [14,15]. Furthermore in these 
plants there is usually a lot of heat available from syngas cooling. These two 
characteristics make attractive the possibility of cogenerating power, in order to 
decrease the cost of hydrogen and improve performance. In this work the integration 
with a steam-turbine, a gas turbine and a combined cycle has been investigated. Few 
studies have previously investigated the feasibility of cogenerating power in SMR 
based hydrogen plants. Terrible et al. [16] proposed four main schemes similar to the 
ones studied in this work, but the analysis was not detailed and all the plant schemes 
were investigated without considering CO separation. Consonni and Viganò [13] 
2
performed a detailed thermodynamic and exergetic analysis of Steam and Gas-
Steam Combined Cycles integrated with Tubular Reformers and Auto-Thermal 
Reformers with carbon capture. The plant schemes are different from those analyzed 
in this work, since in [13] the gas turbine is not used ahead of the reformer, but 
rather at the end of the syngas processing, as it is fuelled by PSA off-gas. 
Furthermore in Chapter 2 an economic analysis has been carried out, to 
determine the cost of hydrogen not only in the reference plant, but also in the plants 
cogenerating power. According to [17] the cost of hydrogen produced through SMR 
10