By Tom Guenther, Carbon Capture Service Area Leader, Black & Veatch
Over the last 10 years, much time and money has gone into the development of numerous carbon capture technologies, as well as the study of the costs and impacts of utilizing these technologies. Many owners would like their plants to be “capture ready,” or would like to know what it would take to make them capture ready. But with a technology that is still evolving, on what definition is “capture ready” based?
For example, the plant requirements and modifications for oxy-combustion capture are very different than for post-combustion capture. Even different post-combustion technologies require different proportions of energy from steam and electricity (for example, amine vs. chilled ammonia). Perhaps the only hard requirements for capture readiness are simply whether there is enough physical space to locate the new equipment and a place to put the captured CO2. Whether to include equipment connections and modifications in a definition of capture readiness just boils down to the cost of the necessary modifications and how they fit into the overall project economics.
The costs for retrofitting an existing plant with carbon capture have been well publicized. For a plant designed to capture 90 percent of CO2 emissions using current technology, the capital cost approaches the capital cost of the power plant itself and the energy penalty (reduction of plant output) is in the range of 20 to 30 percent. In addition to these costs, there are many other plant impacts to consider when evaluating a plant for carbon capture retrofit.
Currently, post-combustion capture using an improved amine solvent is one of the most developed technologies available for retrofit to a coal-fired power plant. If an owner were required today to add carbon capture to an existing large generating facility, this technology is one that likely would be used. The balance of this article will focus on the impacts and considerations for retrofitting a coal-fired power plant with an improved amine capture system.
Figure 1 (pg. 76) shows a simplified flow diagram for a typical improved amine capture process. The typical process uses a large absorber vessel which contacts an amine based solvent with the power plant flue gas, absorbing most of the CO2 into the solvent. The CO2- rich solvent is then circulated to a regenerator (sometimes referred to as a stripper), where the solvent is heated using steam from the power cycle to liberate the CO2. The CO2 is then compressed for pipeline transport and eventual sequestration. A cooler is usually included to cool the flue gas before absorption takes place. Existing plant equipment is shaded in the figure.
The plot space required for new equipment is substantial. The absorber is typically a large cylindrical or rectangular vessel with a large enough cross sectional area to pass the total flue gas flow; up to 50 feet in diameter for a cylindrical vessel and a height that exceeds 100 feet. Multiple vessels in parallel may be required for larger generating stations. The regenerator typically has a smaller diameter than the absorber(s), but with similar height. In addition to these large pieces of equipment, space is also needed for:
- Racks for the amine solution and other piping
- Fans and ductwork from the take-off point to the capture system and back to the stack
- Additional cooling tower (or additional cells on existing towers)
- Numerous heat exchangers and pumps, and
- CO2 compressor(s).
The location of CO2 capture equipment needs to be as close to the existing flue gas ductwork as possible to minimize capital and operating costs, including costs for the ductwork itself, fan capacity, pressure drop and so on. The new equipment can be divided into separate areas if the total area required is not available in one location. The length of steam and condensate return piping to/from the main power cycle area is also a factor to consider when locating the new equipment.
All this translates into a minimum equipment area requirement of approximately five acres for a typical 500 to 600 MW coal-fired power plant. The area requirement may be greater if a new wet flue gas desulfurization (FGD) system is needed to meet the SO2 inlet limits for the specific amine technology.
Ductwork Modifications and Additions
Ductwork modifications are necessary to connect new flue gas ductwork to the existing ductwork and to provide damper isolation to allow bypass of the capture system. Two connections to the existing ductwork would generally be required: One connection downstream of the existing air quality equipment to supply the flue gas to the capture plant and one connection just before the stack to return the flue gas after it has been scrubbed of CO2. This is generally not a major issue, although some plants may not have a sufficient length of ductwork available to accommodate the connections. In this case a new stack could be added, either a full stack or possibly a small stack on top of the absorber vessel.
Air Quality Control Equipment Modifications
SO2, NOX and particulates are absorbed by the amine-based solvents and can degrade the solvent. For most plants, it makes economic sense to reduce SO2 concentrations below 10 to 20 parts per million (ppm) to minimize solvent replacement costs. This necessitates either the addition of a polishing scrubber, modification of the existing flue gas desulfurization (FGD) system or a completely new wet FGD system. The polishing scrubber can sometimes be incorporated into the flue gas cooling system, which would not impact the existing plant equipment.
Modifications to an existing wet FGD to lower outlet SO2 concentrations could potentially include addition of perforated tray, modification of headers or upgrade of pump capacity, addition of a new spray header or addition of dibasic acid injection. Additional fan power may be necessary if the pressure drop through the FGD system is increased. The need for air quality control equipment modifications is very site-specific and should be carefully evaluated.
Steam Cycle Modifications
Steam is required by the amine-based capture systems to heat the CO2 -rich solvent in the regenerator, liberating it from the solvent for compression and transport to sequestration. Typical requirements for the best solvents are in the range of 1.2 to 1.5 pounds of low pressure (50 to 75 psig) steam per pound of CO2 captured. On the low end of the range, this translates into a low-pressure (LP) steam flow on the order of 40 percent of the total steam flow to the LP turbine for 90 percent capture. One option for providing this LP steam is to tap directly into the IP/LP turbine crossover piping. Removing that much steam from the crossover will obviously impact operation of the intermediate pressure (IP) and LP turbines and may necessitate modifications such as LP turbine de-blading or removing one complete LP turbine. In addition, operating the unit at lower loads may be restricted with the CO2 capture plant running due to the decrease in the crossover steam pressure at lower loads.
Another option would be to take steam from a higher pressure location, such as hot reheat, and add a non-condensing steam turbine-generator (NCSTG) to let the steam down to the conditions needed by the CO2 capture system. This would improve the unit’s operating flexibility at the expense of the capital cost and space requirements for the additional steam turbine generator and associated balance-of-plant equipment. Either way, steam piping must be routed from the main plant area to the CO2 capture area and the resulting condensate returned to the main plant area.
Other options exist for steam supply, such as the use of main steam or cold reheat steam, but these would necessitate boiler modifications. The ultimate decision on how to provide the needed LP steam is highly plant-specific and must be carefully studied to minimize plant efficiency impacts. Input from the original turbine-generator equipment manufacturer and possibly the boiler manufacturer are recommended.
In addition to supplying steam for CO2 stripping and returning the resulting condensate, other heat integration between the steam cycle and capture process may be considered to reduce the impact on overall cycle efficiency, such as condensate/feedwater heating using waste heat from the capture process. This would result in additional piping between the main plant and the capture plant.
Water and Wastewater Impacts
The addition of CO2 capture will result in increased cooling requirements to support cooling of the flue gas, inter-stage cooling of the CO2 compressor, removal of the CO2 heat of absorption, as well as other process cooling needs. Cooling the flue gas to the optimum temperature for the specific amine solvent will usually result in a significant amount of water being generated by condensation from the flue gas. This water is generally of a good quality and can be re-used in other areas of the plant such as FGD makeup or cooling tower makeup. The net result of the addition of CO2 capture, however, is an increase in water usage overall. In most cases the makeup water is needed for cooling tower makeup, unless once-through or air cooling are used. The quantity of makeup water needed is plant specific, but a typical figure could be on the order of 2,000 gallons per minute (gpm) for a 600 MW plant with 90 percent capture. Wastewater produced would primarily be cooling tower blowdown (again highly plant specific) but on the order of 400 gpm for the same plant. Existing water and wastewater treatment equipment may not have enough capacity to absorb this additional requirement, necessitating the installation of additional treatment equipment.
The electrical power requirements for CO2 capture systems represent one-third to one-half of the overall energy penalty. The largest load will normally be the CO2 compressor, which could easily exceed 40 MW for a 600 MW power plant with 90 percent capture, depending on the CO2 pressure needed for transportation and sequestration. Auxiliary loads for a new flue gas fan, cooling tower fans and various process pumps could add an additional 20 MW or more. For most existing plants, the auxiliary transformer(s) will not be adequate to serve this additional load and a new auxiliary power transformer will be required. There are many options available for feeding the new auxiliary power transformer and these options are highly plant specific, but may require modifications/additions to the medium and high voltage auxiliary power systems.
For cases where an NCSTG is added, the electrical output from the new generator will depend upon the specific process and steam cycle parameters. The generator output would likely be used to power the capture equipment and would need to be in parallel with the grid and main generator when it is on line. The new generator would either offset some or the entire load on the CO2 auxiliary load bus. The generator could operate only when the main plant is in operation. Any power that is in excess of the power required by the CO2 capture process could be exported to the grid. Note that use of a NCSTG does not reduce the energy penalty, but only lessens the additional negative impact on the cycle of using a higher quality steam source (for example, hot reheat) than is needed by the capture process.
Additional electrical power impacts that may result from any required modification to the existing air quality control equipment are site-specific and will need to be considered as well.
Due to the size and complexity of carbon capture equipment, careful planning will be required to allow construction to proceed at a reasonable pace while minimizing impact to the operating power plant. In addition to the plot area needed for the new equipment, an area will be needed for crane placement to erect the absorber and regenerator towers and for equipment lay-down. Most of the equipment can be erected while the main unit is still operating, but a two to three week outage will be required to connect the new duct work to the existing ductwork.
The absorber and regenerator towers will likely be shipped in sections, depending on the size of the system. Pipe racks, rotating equipment skids and chemical feed/treatment skids are potential areas where modularization could be employed to help minimize capital costs and construction schedule. Generally speaking, there should be no equipment required for the construction of a CO2 capture system that is larger than what was required to build the original power plant.
The future is likely to see more plants retrofitted with carbon capture technology, whether using the currently viable post-combustion amine technologies, or other technologies under development or yet to be developed. Regardless of technology, all of today’s existing plants will require modifications to support carbon capture retrofits.
In addition to the energy penalty, capital costs, and operating costs associated with retrofitting plants with carbon capture technology, there are many other plant impacts that must be considered before a retrofit is performed. Upfront analysis and careful planning will help minimize these impacts.
Author: Thomas R. Guenther is the Carbon Capture Service Area Leader and a project manager within Black & Veatch’s global energy business, providing feasibility studies, technology characterizations and advanced technology assessments to energy companies, utilities, governmental agencies, industrials and entrepreneurs. His primary emphasis is on carbon dioxide capture and control, coal gasification, IGCC, pulverized coal, gas fired combined cycle and compressed air energy storage.
All this translates into a minimum equipment area requirement of approximately five acres for a typical 500 to 600 MW coal-fired power plant.More Power Engineering Issue Articles
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