Inn nil

Fig. 2.19 Levelized cost of electricity for newly-built coal-based and biomass-based power generation technologies at study point-design conditions and zero price on CO2 emission. Natural gas combined cycle generation with two natural gas prices included ($100/MWe-h equals 100/ kWe-h.) (Courtesy Williams et al. [11])

Fig. 2.20 Levelized cost of electricity for newly-built coal-based and biomass-based power generation technologies at the study point-design conditions with a $50 per tonne price on CO emitted to the atmosphere. Natural gas combined cycle generation with natural gas is included for comparison ($100/MW-h equals 100/kW-h) (Courtesy Williams et al. [11])

Fig. 2.20 Levelized cost of electricity for newly-built coal-based and biomass-based power generation technologies at the study point-design conditions with a $50 per tonne price on CO emitted to the atmosphere. Natural gas combined cycle generation with natural gas is included for comparison ($100/MW-h equals 100/kW-h) (Courtesy Williams et al. [11])

Figure 2.20 shows the impact of a $50/tonne price on CO2eq vented. This tends to level the COE of many of the technologies and makes IGCC with CCS the most economically attractive of the coal technologies. The COE of biomass to power with venting (BTP-V) is about $9/MWe-h cheaper then IGCC-CCS and would have no tax imposed on it because the life-cycle CO2eq is essentially zero due to the fact that the CO2 emitted is recaptured in the next plant growth cycle. Biomass to power with CCS (BTP-CCS) is about $2/MWe-h cheaper than BTP-V because of payment for the CO2 removed from the atmosphere and geologically stored (negative bar on the graph). These payments more than offset the added capital and feedstock costs associated with CCS. Under these conditions, biomass to power is economically favored over coal to power.

Figure 2.21 provides key information on the impact of an increasing life-cycle Green House Gas (GHG) emission (CO2eq) price on the COE for several power generating technologies, from the work of Williams and coworkers at PEI [11]. This plot is based on their single design-point study using a consistent database. Included is the impact of GHG emissions price on the cost of average grid power and on the cost of power from existing, fully paid-off, coal plants. Crossover points are the CO2eq price at which economics would induce a shift from one technology to the other for new power plants. For example, the CO2eq cost that would induce a shift from IGCC venting (CTP-V) to IGCC with CCS^CTP-CCS) is $38/tonne

Fig. 2.21 Cost of Electricity (COE) as a function of GHG emissions price. Crossover points are the CO2 prices required to economically induce a shift from one technology to the other. Also indicated is the impact of CO2 price on the average cost of grid power today and the cost of power generated by existing coal plants (Courtesy Williams et al. [11])

Fig. 2.21 Cost of Electricity (COE) as a function of GHG emissions price. Crossover points are the CO2 prices required to economically induce a shift from one technology to the other. Also indicated is the impact of CO2 price on the average cost of grid power today and the cost of power generated by existing coal plants (Courtesy Williams et al. [11])

CO2eq (Fig. 2.21). The CO2eq emissions price required to induce a shift from newly designed PC venting (PC-V) to newly designed IGCC with CCS (CTP-CCS) is about $50/tonne CO2eq and to drive a shift from PC-V to PC-CCS requires a CO2eq price of about $73/tonne. This is the situation which would exist when the demand for electric power is growing and new coal-based power plants are being designed and built. It would also be the situation for repowering old, obsolete power plants.

In the case of existing coal-based plants that are fully operational where there is insufficient growth in electricity demand to warrant new plants, as might be the case in the U.S., the relevant crossover point is between existing, venting PC plants and new IGCC with CCS (CTP-CCS). Under these conditions, a CO2eq price of over $75/tonne would be required to induce the construction of a new IGCC plant with CCS (CTP-CCS). This approach would also apply to repowering existing PC plants with IGCC with CCS.

These CO2eq price cross-over points suggest that significant shifting to IGCC or other coal-based power plants with CCS would occur at a relatively low CO2eq price (less than ~$40/tonne) in economies that have growing electricity demand, i.e. are building new plants. In economies with stagnant electricity demand, because of conservation efforts, etc., the CO2eq price to induce a shift would have to be much higher (more like $75/tonne), to induce a switch from existing, venting PC plants to new IGCC plants with CCS (or whatever is the lowest coal-based generating technology with very low carbon emissions).

Biomass to power plants (BTP) using biomass gasification both with CCS and without CCS would economically replace existing coal plants at an emissions price of about $50/tonne CO2eq. For new plants, biomass to power (BTP-V) is projected cheaper than IGCC withCCS (IGCC-CCS) for all CO2eq prices, and the crossover point for biomass to power with CCS (BTP-CCS) is less than $30/tonne CO2eq for IGCC-CCS. If the estimated COE is low because of a low capital cost estimate or low biomass cost estimate, the appropriate curve shifts upward by that amount, but the crossover points remain within a relatively small CO2eq price range.

Combined coal and biomass (~60%/40% on an energy basis) - based power generation (CBTP) without and with CCS have low crossover CO2eq prices with the conventionally considered all-coal based power generation. These are basically all less than $40/tonne CO2eq for new plants. However, to replace existing PC plants, the existing emissions price would have to exceed $55/tonne CO2eq. The challenge with the biomass and the combined coal and biomass cases is the lack of experience with biomass gasification, and the availability of biomass. Biomass gasification is technologically feasible and has been commercially demonstrated, but it is not yet a really robust commercial technology. Biomass is a dispersed resource, and thus supplying large quantities of it to a given site on a continuous basis is a challenge. Because it is less dense and typically contains significant water, collection and transport over long distances is not economically attractive. This limits the size of potential plants. This makes coal plus biomass configurations more attractive because it provides economies of scale, and reduces CO2eq emissions, while coal supplements available biomass. In addition, small amounts of biomass with coal (around 10% on an energy basis) in IGCC with CCS (CTP-CCS) can produce zero life-cycle GHG electricity.

The estimates developed here are all based on bituminous coal, for which the COE favors IGCC with CCS in a CO2-constrained environment. Although, about 50% of U.S. coal reserves are bituminous, the remaining 50% are sub bituminous coal and lignite. Lower rank coals and higher elevation plant locations narrow the cost difference between IGCC and PC with CO2 capture [10, 49]. Cost improvements for PC capture could make it economically competitive with IGCC in certain applications, and Oxy-fuel PC looks potentially competitive also. Thus, it is too early to decide which technology will be cheapest for coal-based power generation with CO2 capture. All technologies need to remain under development and demonstration until there is sufficient commercial-scale experience to decide.

There is always a need for innovative technology in coal-based power generation to improve operations, increase generating efficiency, and to reduce emissions and CO2 capture costs. A number of technologies are being developed to reduce cost and improve performance at the bench and pilot scale. However, it is important to note that conventional coal-based power generation is a mature technology, and PC units have been highly optimized. Technology already exists to capture CO2 from PC and IGCC units, although it is typically applied at smaller scale in other applications. These technologies need to be commercially demonstrated, integrated, and optimized on the scale of power generation. Waiting for research to provide that "unique solution" is not a rational approach if there is any urgency to the CO2 emissions issue. The rational approach is to put available commercial technology into practice, integrate it into the full generating and emissions control system, and begin to move along the learning-by-doing curve. This typically results in significant cost reductions, improved effectiveness and efficiency, and increased operability, reliability, and robustness. Rubin and coworkers at Carnegie Mellon University have studied the impact of learning-by-doing on cost for a number of technologies, including the power industry (e.g. see [50]). From the historical experience curves for a range of power generation technologies, LNG plants and oxygen and hydrogen production, Rubin et al. [50] estimated that for the generating technologies considered above, the CO2 capture cost could undergo a 13-15% capital cost reduction and a 13-26% total cost reduction with 100 GWe of new installed capacity. This is in addition to the cost reductions that will also be taking place in the base plant, such as IGCC which will be undergoing learning-by-doing cost reductions with increasing commercial applications. The same can be said for the CO2 transport and storage component of the total generating and CCS chain.

Commercial technologies exist that can be utilized and integrated to achieve effective power generation with CCS today. These have been applied in commercial operation but frequently at a smaller scale than required for power generation. Application of these technologies at commercial power-plant scale will ultimately result in significant improvements in them and in significant cost reductions. Similarly, CO2 sequestration (geologic storage) is commercially demonstrated at the 1 million tonnes per year at several locations in the world, and more demonstrations are planned internationally. The DOE Regional Partnership program has started to develop a geologic database but needs to accelerate and expand in scale.

Geologic storage still needs full-scale, well-monitored demonstrations at several locations and in different geologies in the U.S. to develop the needed site choice, permitting, monitoring and closure procedures and to gain needed public and political support for the more widespread application of the technology. These are large-scale, expensive activities, which if successfully demonstrated and applied are mainly aimed at benefiting society, and thus, society has a stake in supporting them. The can also be said in support for combined demonstration programs among several countries that depend heavily on coal-based power generation (such as India, China, and the US) and are likely to remain heavily dependent on coal-based power generation for the foreseeable future. Such demonstrations can take up to a decade to plan, build, and operate to gain desired learning. Thus, there is urgency to start down the path.

In addition to CO2 emissions, criteria emissions from coal-based power generation can be very low if the available control technologies are applied. When CO2 capture is applied, these criteria emissions can be expected to be even lower, resulting in a small environmental footprint for clean coal technology. With CO2 capture and sequestration, "clean coal" can provide base-load electricity that is cost competitive with wind and new nuclear and can continue to help maintain our energy diversity. Thus, "clean coal" would appear to continue to be an economic choice for base-load power generation of very low emissions electricity, including low CO2 emissions.

In summary with respect to the path forward:

• The technologies required for CO2 capture with power generation are commercial and can be expected to improve in cost and performance from operation at scale and learning-by-doing. Major R&D developments are not needed to begin applying them now. However, major R&D will be needed to support their application and to help drive improvements in them and the development of new and improved technologies. The order of commercial readiness is: (1) IGCC-CCS, (2) PC with post capture, and (3) oxy-fuel.

• It is technically feasible to safely and effectively store large quantities of CO2 in deep saline aquifers, and the U. S. storage capacity in such reservoirs appears very large. This needs to be clearly demonstrated on a commercial scale and some technical issues need resolution. Improved storage capacity estimates need to be made by country. The U.S. appears to have storage capacity potential in excess of several hundred to over a 1,000 gigatonnes of CO2. China appears to have large storage capacity close to with much its coal use, but India may have a more limited storage potential [10].

• A broad range of regulatory issues, including: permitting guidelines and procedures, liability and ownership, monitoring and certification, site closure, remediation, require resolution so that projects can proceed forward in a smooth, efficient manner.

• For CCS to be available to apply on a large scale, it is critical to gain political and public confidence in the safety and efficacy of geologic storage.

To resolve these issues and establish CCS as a viable technology for managing CO2 emissions, it is necessary to carry out 3-5 large-scale CCS demonstration projects in the U.S. and 7-12 globally at the 1 million tonnes CO2 per year scale, using different generation technologies, focusing on different geologies, and operated for several years [10]. Effective demonstration of technical, economic, and institutional features of CCS at commercial scale with coal combustion and conversion plants, will: (1) give policymakers and the public confidence that a practical carbon mitigation option exists, (2) shorten the deployment time and reduce the cost for carbon capture and sequestration when a carbon emission control policy is adopted, and (3) maintain opportunities for the lowest cost and most widely available energy form to be used to meet the electricity needs of the U.S. and the developing world in an environmentally acceptable manner. If completed expeditiously, this program can provide the U. S. and the rest of the world with robust technical options for addressing CO2 emissions from power generation and for liquid transportation fuels production from coal as discussed in Chap. 3. If the U.S. took the lead in these activities, it could also provide a broad technology base for U.S. companies to apply globally and would also strengthen our engineering and technology base to deal with other energy/technology issues in the future.

With a robust set of technology options, it is in theory feasible to markedly reduce CO2 emissions from coal-based electric power, but to drive this, the price set on CO2eq emissions will have to be high. This is particularly the case if power demand does not grow and the activity focuses on replacing units in the existing fleet. With growth in power demand and with the end-of-life retirement of existing units the emissions reduction will occur at a lower emissions price. IEA projects in the World Energy Outlook 2008 that the GHG emissions price will have to be about $90/tonne CO2eq by 2030 to realize the 550 stabilization trajectory [51]. EPRI gives a detailed analysis of reductions potential in the generating portfolio including the role of coal with CCS [52]. Chap. 3 presents an important route for achieving significant reduction in emissions associated with coal-based power generation at a significantly lower cost.

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