is to be captured and stored, this trend will complicate the process. Similarly, fuel cells require high-purity hydrogen. Plants built to produce this hydrogen and to capture and sequester CO2 will require equipment and processing not used in current plants. The joint goals of high-purity hydrogen and low-cost CCS may demand new capture technology.
Two CCS demonstration projects are currently under way, one in Norway and one in Canada:
At the Sleipner gas field in the North Sea off Norway, natural gas is produced containing about 10 percent CO2. The CO2 concentration exceeds the concentration allowed in the European natural gas grid by about a factor of 4. Normally in such cases, CO2 is stripped from the gas onshore and vented to the atmosphere. Since 1996, motivated by a carbon tax of about $140/t C (in U.S. dollars), the field operators are stripping CO2 offshore and injecting it into the nearby Utsira formation, a very large saline aquifer that does not contain hydrocarbons.
At the Weyburn oil fields in Saskatchewan, Canada, CO2 captured at a coal-to-methane plant in North Dakota and piped across the border is being injected, with the joint objective of enhanced oil recovery (EOR) and CO2 storage.
Both projects store about 0.3 Mt C/yr.
Several additional CCS demonstration projects are being planned at roughly the same scale. Notable among them is the FutureGen Project, proposed in the spring of 2003 by the Bush administration. In this project, a 275 megawatt (MW) coal-fired power plant would produce both electricity and hydrogen and would capture CO2 for offsite storage. Announced at the same time and coupled with FutureGen is the U.S. Carbon Sequestration Leadership Forum, aimed at developing international partnerships for the commercialization of CCS technology.
In addition to demonstration projects, experience bearing on CCS technologies is being gained through EOR projects that inject CO2 into partially depleted oil fields. The first EOR project was in West Texas in 1972, and most of the EOR in the world today is still concentrated there.
Only about one-quarter of the CO2 used in EOR is derived from industrial sources (Hill, 2003, p. 25). Most is extracted from natural CO2 formations. The value of CO2 for EOR has been sufficient to warrant the construction of several multi-hundred-kilometer (km) CO2 pipelines, including one of 800 km from the McElmo Dome in southwest Colorado to the Permian basin oil fields in West Texas.
Until recently, EOR was not thought of as a carbon storage strategy. Once the CO2 has done its work and production is concluded, EOR project managers have not considered whether the CO2 would remain belowground for decades, centuries, or millennia. Joint optimization of EOR and long-term CO2 storage could lead to revisions in EOR practices. Thus, EOR to date provides only partial precedents for CCS.
Hydrogen production involves the transfer of most of the energy from the feedstock chemical compound to the product molecular hydrogen. Adding the objective of CO2 capture complicates the design of the equipment and increases the costs of production. However, most of the plant components required to capture CO2 are already required to produce hydrogen, so the fractional increment in the cost of hydrogen owing to CO2 capture is not large: in the committee’s estimates (see below), between 10 and 20 percent for natural gas and less than 10 percent for coal. The fractional increment is substantially smaller than would be incurred if CO2 capture were added to electricity production.
An intriguing concept is that of the co-capture and co-storage of impurities with the CO2, saving the costs currently incurred to prevent these impurities from becoming air or water pollutants. For example, sulfur in coal can be co-captured with the CO2 (as either hydrogen sulfide [H2S] or sulfur dioxide [SO2], depending on the plant configuration), piped with the CO2 to a storage location, and co-stored as a single fluid.
Table 7-2 shows estimated hydrogen production costs for large-scale plants.5 The “with carbon capture and storage” cases also show the estimated costs of storage. Both sets show an imputed cost of CO2 emissions on a $50 per metric ton (tonne) C basis.6
The estimated cost of carbon associated with either type of plant—natural gas or coal—is calculated as the sum of storage costs plus capture costs: the storage costs are shown in Table 7-2, and capture costs are defined as the difference between the plant production costs with and without CCS. It is interesting to note that the assumed cost of carbon emissions is insufficient to justify CCS for natural gas plants, whereas it approximately balances the additional costs for CCS in a coal plant. The capture costs for coal are a smaller percentage of the plant costs for the technologies assumed in this report (see Chapter 8); for example, the CO2 in this study’s coal gasification plant is available for capture at a higher partial pressure, which reduces the cost of capture. The capture costs, as a percentage of the cost of production at the plant without CCS, are 18 percent and 11 percent for
The scale of this study’s large plants is 1200 t H2/day, or 2.0 GW H2 (higher heating value), or 1.7 GW H2 (lower heating value).
The fuel costs assumed (see Chapter 5 and Appendix E) are as follows: $4.50 per million Btu (higher heating value) for natural gas; $1.22 per million Btu (higher heating value) for coal; and 4.5 cents/kWh for electricity. The cost of storage is highly uncertain at this time and has not been a focus of this committee’s analysis. The committee assumed $37/t C, which is consistent with the range of current estimates. The imputed cost of CO2 emissions is even more uncertain. The $50/t C cost arbitrarily chosen in this report is a point of departure for many analyses (see Chapter 5).