Although carbon dioxide (CO2) emissions are not yet regulated in the U.S., at least one coal-fired plant, proposed for Kansas, has already been denied a construction permit because the project would have produced too much of the greenhouse gas (GHG). Technologies for “carbon capture and sequestration” (CCS) from power generation sources soon will be required in some form or other. Currently, the timing and extent of upcoming regulations are only speculative. The most recent effort in Congress—the Moratorium on Uncontrolled Power Plants Act of 2008, introduced this March—will require plants to permanently sequester 85% of their CO2 emissions.
Any new project that intends to burn coal, petroleum coke, or synthetic gas derived from coal will soon have to meet such a requirement. Although implementation of any legislation for CO2 may take several years, in the present climate of uncertainty it behooves owners and planners of new plants to consider all options for accommodating CCS in their designs. The variety of CCS technologies currently under development makes that a very challenging task. So far, no existing technology has emerged as the most promising solution, and many new and innovative alternatives are in various stages of research, development, or pilot-scale testing.
For plants currently in the planning or design stage, owners, EPC (engineering, procurement, and construction) contractors, and equipment suppliers are trying to determine which features need to be applied today to minimize the impact of future technologies on plant layout, performance, and operability. Given those circumstances, perhaps the best strategy for reducing a coal plant’s carbon footprint is to consider using several complementary methods simultaneously, rather than wait for a single “silver bullet” technology solution that may never be developed.
Part I of this article addresses the impact that various postcombustion carbon capture techniques have on a coal plant’s design, performance, and complement of equipment. Part II will explore a variety of non-postcombustion carbon capture and reduction methods. Unfortunately, cost comparisons of the various technologies and approaches (Figure 1) can not be included, due to the high volatility of labor, material, and equipment prices.
1. Available CO2 capture options. Source: Bechtel Power Corp.
What “capture-capable” means
A capture-capable coal plant is defined as one that provides for future incorporation of a CO2 capture technology. Beyond the technical challenges of carbon capture, the commercial investment in specific features aimed at future CCS must be justified.
There is significant risk in selecting a specific carbon capture technology because it could become obsolete. At this point in time, a pragmatic approach to coal plant design requires evaluating all known factors of existing carbon capture technologies, considering ways to add CCS systems later, and laying out a plant to facilitate the incorporation and/or modification of hardware sometime in the future. Because carbon capture is an energy-intensive process, the discussions below include the impact on plant performance of large steam extractions for CO2 capture processes and of the use of electric power for CO2 compression.
Postcombustion CO2 capture processes
The technologies available for removing CO2 from a coal plant’s flue gas rely on the use of distillation, membranes, adsorption, or physical or chemical absorption of the gas. They are equally applicable to postcombustion capture of the CO2 produced by a natural gas–fired plant with a simple-cycle or combined-cycle configuration. Other than the amine-based processes discussed below, all the candidate technologies are in various stages of concept validation or small-scale demonstration.
Absorption of CO2 in chemical solvents such as amines is a technology with an excellent track record in many applications within and beyond the field of power production. It is used, for example, in the petrochemicals industry for natural gas sweetening and hydrogen production. The reaction between CO2 and amines currently offers a cost-effective solution for directly obtaining high-purity CO2.
Amine-based processes. Figure 2 is a schematic of a typical amine-based process for postcombustion CO2 removal. The flue gas is cooled and treated to reduce its levels of particulates, SOx, and NOx. Then, boosted by a fan to overcome pressure drops in the system, the flue gas is passed through an absorber. In it, a lean amine solution, typically monoethanolamine (MEA), is pushed in a countercurrent to the flow of the gas, and the interaction absorbs the CO2.
2. A typical postcombustion amine-based CO2 removal process. Source: Bechtel Power Corp.
The clean flue gases continue to the stack. Meanwhile, the amine solution, now rich in CO2, is pumped into a stripper (regenerator) to separate the amine from the gas. Steam provides the energy needed to desorb the CO2 from the solution. The CO2-rich solution at the top of the stripper is condensed, and the CO2 phase is removed and sent off for further drying and compression. Table 1 summarizes the advantages and limitations of this process.
Table 1. The advantages and limitations of amine scrubbing. Source: Bechtel Power Corp.
Chilled ammonia processes. Ammonia is the lowest form of amine. Like other amines, it can absorb CO2 at atmospheric pressure, but at a slower rate than that of MEA.
The chilled ammonia system shown in Figure 3 uses a CO2 absorber similar to an SO2 absorber and is designed to operate with a slurry. The process requires the flue gas to be chilled to 35F before entering the cleanup system. The cooled flue gas flows upward, against the current of a slurry containing a mix of dissolved and suspended ammonium carbonate (AC) and ammonium bicarbonate (ABC). The absorber captures more than 90% of the CO2 in the flue gas.
3. A chilled ammonia process for CO2 removal. Source: Alstom
The CO2-rich spent ammonia then is regenerated under pressure to reduce the energy requirements of CO2 liquefaction and compression. The remaining low concentration of ammonia in the clean flue gas is captured by a cold-water wash and returned to the absorber. The clean flue gas—which now contains mainly nitrogen, excess oxygen, and a low concentration of CO2—flows to the stack. Table 2 summarizes the advantages and limitations of the process.
Table 2. Advantages and limitations of the chilled ammonia process. Source: Bechtel Power Corp.
As Table 3 shows, studies conducted by Parsons and Alstom indicate that equipping a supercritical pulverized coal–fired plant with a chilled ammonia CO2 capture system would give the plant an 8 percentage point efficiency advantage over an identical plant equipped with an amine-based process. Actual test results for the process are expected after Alstom and EPRI complete and operate a 2-MWth field pilot at Pleasant Prairie Power Plant in Kenosha, Wis. (POWER, February 2008, p. 38). This pilot project aims to capture CO2 emissions from a slipstream of less than 1% from one of the two boilers operating at the plant. Meanwhile, PowerSpan has upgraded its Electro-Catalytic Oxidation (ECO) nonchilled ammonia scrubbing process to include CO2 removal. The new process, called ECO2, is being planned by PowerSpan for demonstration at FirstEnergy’s R.E. Burger plant in Ohio (POWER, October 2007, p. 54).
Table 3. Impacts on plant performance of the chilled ammonia process. Source: Bechtel Power Corp.
Impacts of postcombustion capture on plant design
Incorporating CCS technologies into a coal-fired plant significantly affects the plant’s design, thermal efficiency, and turbomachinery. For example, the need to sequester the captured CO2 dictates considering the plant’s location. If it is located far from an adequate geological storage site or a site suitable for enhanced oil recovery, the cost of constructing a pipeline and the additional loads for pumping CO2 must be accounted for. Space requirements and plant layout should also be considered.
By itself, CO2 capture hardware has a large footprint. For amine scrubbing, CCS plant components (the absorber, stripper, compression stations, and various cooling and storage tanks) occupy a large area. In addition, the plant layout must provide large ducts for flue gas, which needs to be routed from the outlet of the block of air quality control systems to the amine scrubber without interfering with roads and buildings. As discussed in detail below, large low-pressure (LP) pipes in racks with adequate support also are needed to bring steam from the plant’s steam turbine to the amine scrubber.
Balance-of-plant equipment also must be augmented to meet CCS requirements. For example, the electrical design of transformers, transmission cables, and motor control centers may need to be enhanced. Particularly when an existing plant is being retrofitted for CCS, the ripple effect of adding a CO2 removal system requires detailed and careful review. A final consideration is the plant’s heat sink. It should be sized to allow the condenser and cooling tower to accommodate the extra, unneeded steam that’s routed through the plant when the postcombustion capture system is not in operation.
A significant amount of steam is required to regenerate the solvent of an amine-based postcombustion capture system. At 44 psi and 518F, it may take between 2.9 and 3.5 pounds of steam to recover the amine needed to remove 2.2 lb of CO2 from the flue gas. For a 90% CO2 capture level, that level would represent more than 50% of the LP steam turbine’s flow.
Accordingly, it is imperative to consider that the CO2 capture system might not be operational and, if so, would be unable to process all or part of the extraction steam it receives. This is especially important for plants whose steam turbine is permanently configured to operate with a reduced LP steam flow. Venting such large quantities of steam is not an option, so any design must enable rapid configuration changes that allow the LP modules to operate under zero-extraction conditions. There are four available options for extracting steam from the system: throttle LP, floating-pressure LP, LP spool with clutched LP turbine, and backpressure turbine.
Throttle LP. This configuration keeps the crossover pressure constant despite the fact that a large amount of steam is extracted. As Figure 4 shows, the arrangement requires the presence of a throttling valve downstream of the solvent steam extraction point. Although it would incur significant throttling losses, this setup is flexible enough to allow for the extraction of any amount of steam needed (to achieve less than 90% CO2 capture, for example), as well as for returning to full-power operation rapidly when the CO2 capture system is not in service. The type of throttling valve needed is commercially available for current LP crossover pipe sizes.
4. A throttle low-pressure arrangement for extracting the steam needed by a CO2 capture system. Source: Bechtel Power Corp.
Floating-pressure LP. In this arrangement (Figure 5), the turbine’s intermediate pressure (IP) module must be able to operate with a variable backpressure. When the CO2 capture system is operating, the crossover pressure is lower because the LP module’s last-stage loading and exit losses are higher. For retrofits, the IP section’s last stages can be replaced to match the desired operating conditions at both high and low steam flows, depending on the CO2 capture system’s steam demand. Obviously, additional valves in the extraction line and downstream of the extraction point in the crossover pipe facilitate operational control of the different steam flows required by variable CO2 capture rates.
5. A floating-pressure LP arrangement for providing extraction steam. Source: Bechtel Power Corp.
LP spool with clutched LP turbine. In this scheme, depicted in Figure 6, one of the steam turbine’s LP modules is connected via a clutch to the generator in an arrangement similar to that used by single-shaft combined-cycle plants. In this case, when the CO2 capture system is operating, only one LP module is in use and the other is disconnected. The inlet flow and pressure of the operating LP module must be designed to accommodate the steam conditions at the anticipated CO2 capture level(s).
6. The LP spool with clutched LP turbine extraction-steam configuration. Source: Bechtel Power Corp.
This option is costly (it requires additional structural pedestals and a longer turbine hall) and offers little flexibility for achieving various CO2 capture rates. However, restoring the full capacity of the module when the CO2 plant is not functioning is easy. In addition, the LP module that remains in operation performs at the design conditions, giving this option a higher efficiency than the other three.
One variant of this arrangement could even operate without a clutch. In this setup, the second LP module must rotate, so a minimum amount of steam (between 5% and 10% of its flow) must pass through the second module to prevent overheating or mechanical vibrations. The additional steam that is extracted without producing real power is an added loss for the system. A more permanent solution for the second LP module is to replace the bladed rotor with a dummy. In this scenario, when the CO2 capture system is not operational, the steam cannot be returned to the cycle to produce power; it must either be vented or condensed.
Backpressure turbine. If the extraction steam for the CO2 capture system is taken from the turbine’s IP/LP crossover pipe, its pressure and the temperature are too high for direct use by the sorbent regeneration process. One solution that would exploit the available energy is to add a noncondensing turbine to produce power (Figure 7). The power generated by the noncondensing turbine could then be used to reduce the auxiliary load of the carbon capture process.
7. Using a noncondensing, backpressure turbine to lower the temperature and pressure of extraction steam (and generate power). Source: Bechtel Power Corp.
Table 4 provides an example of the negative impacts of a CO2 capture system on the overall performance of an 800-MW (net) power plant. It should be emphasized that each project must conduct its own evaluation based on specific site conditions, the selected carbon capture technology, and the type of sorbent used. Because each steam turbine vendor uses a different cycle design with dissimilar IP module exhaust pressures, the output power of the noncondensing turbine varies accordingly.
Table 4. Comparing the performance of plants with and without carbon capture and sequestration (CCS) capabilities. Source: Bechtel Power Corp.
In the example given, it can be seen that the steam extracted for the CCS system reduces the steam turbine’s output by more than 23%. Because the system also contains a CO2 compressor, auxiliary loads increase by 95 MW. In this particular case, the noncondensing turbine produces 40 MW of power. Without this benefit, the increase in auxiliary loads would be even higher.
Figure 8 shows the thermal performance penalties of postcombustion CO2 capture by comparing the relative efficiency losses of the four extraction steam options. This comparison of plant output does not account for auxiliary power losses incurred by CO2 compression. As expected, the setup involving the addition of a noncondensing turbine has the lowest power loss (7%). Next is the clutch arrangement, which features the least steam throttling and the lowest LP turbine losses. However, both options require adding or making significant modifications to plant hardware. For a retrofit, these alternatives require substantial pre-investment and site preparation.
8. Comparing the power losses of the four extraction steam arrangements. Source: Bechtel Power Corp.
Finally, it is important to realize that operating a CO2 capture system at less than 95% capture rate could have a significant impact on the system’s parasitic loads, either in terms of steam flow or electric power. Figures 9 and 10 show how changing the target CO2 removal percentage affects the levels of steam and electricity required for carbon capture and compression. For example, reducing the CO2 capture level from 95% to 80% reduces steam consumption by 20% and electricity consumption by 5%.
9. Steam consumption vs. CO2 capture level. Source: Bechtel Power Corp.
10. Electricity consumption vs. CO2 capture level. Source: Bechtel Power Corp.
—Dr. Justin Zachary ([email protected]) is senior principal engineer for Bechtel Power Corp., an ASME fellow, and a contributing editor to POWER.