Many power generation companies are beginning to conduct studies to identify how they will cope with Green House Gas (GHG) emissions, if and when state and/or federal regulations are enacted. Most pundits predict that legislation will be passed in the next year to 18 months with initial reductions required as early as 2012.
This paper focuses on post combustion capture from flue gas or CO2 scrubbing technology. Amine scrubbing is the only technology that has been operated commercially. In addition, an amine-based CO2 scrubbing process has not operated at a utility coal plant scale, which is greater than 50 MW. There are several vendors that are offering advanced technologies that are in the pilot stage of testing, but test data is still not widely available, and it is difficult to conduct preliminary studies based on these systems.
S&L prepared this paper based on work performed for a confidential client. The client was interested in understanding the cost and balance of plant (BOP) impacts of installing an amine-based
This study presents some general information about amine-based CO2 scrubbing systems, and specific findings from the study on the impact of the amine CO2 scrubbing system when integrated into an existing coal-fired power plant.
Site specific study basis - CO2 retrofit of 650 MW Unit
The objective for this study was to understand the costs and impacts of installing amine-based CO2 scrubbers on one of their large, base-load coal-fired units. They selected a 650 MW plant that was already equipped with selective catalytic reduction (SCR) and limestone forced oxidation (LSFO) FGD systems. The client contracted with the CO2 capture technology vendor to develop a capital cost estimate and to develop a general arrangement drawing for the process located at the plant. S&L was provided with input and output requirements (auxiliary power, ductwork design, water supply, etc.) to interconnect with the existing plant infrastructure. S&L developed capital costs for the BOP modifications and new equipment based on the information provide by the technology supplier.
S&L developed the integration requirements of the CO2 removal system with the plant. Figure 1 identifies each party's scope of work.
Because of the high energy demand of the process and the burden this would put on the existing steam turbine, and the net MW plant output, the basis for the study for CO2 removal was targeted to use only one-half of the flue gas to achieve approximately 50 percent CO2 removal for the plant. Under this design scenario, the client was interested in the operability of the plant at less then full load. Under this scenario, a higher percentage of flue gas (more than 50 percent) could be scrubbed during part load operation of the power plant to achieve relatively higher capture rates of CO2.
Several key issues were identified that needed to be addressed in the BOP evaluation:
- The plant must deliver steam at the minimum (pressure) levels specified for the amine system
- These conditions resulted in IP/LP crossover steam as the preferred source for solvent regeneration
- HP steam is an alternate source for solvent regeneration if LP/IP steam is not available above the minimum pressure
- IP/LP crossover steam not diverted from the LP Turbine must be sufficient for proper LP Turbine Operation
- Turbine blade temperatures cannot get too high
- Turbine back pressure must be sufficient for condenser
- Cooling water from the condenser inlet is a potential coolant source for the solvent regeneration system
The technology supplier provided S&L with a list of their utility requirements for steam, cooling water, instrument and service air, process water makeup, inert gas and auxiliary power.
The impact on the steam turbine was developed using GATE CYCLE. A model of the plant system was developed. The model showed that at full load the plant could be successfully integrated and operated with the amine process to remove about one-half of the CO2 produced from the unit. Additional test runs were conducted to evaluate the performance of the plant under various alternative load conditions.
The plant performance is greatly impacted by extracting significant quantities of steam from the IP/LP input to the LP steam turbine. Cooling water also is required and can be extracted from the cooling water supply system. A preliminary analysis determined that extraction of steam associated with scrubbing just one-half of the flue gas could be accomplished without detrimental impacts to the steam turbine.
A GATE CYCLE model was developed to identify the performance of the plant under varying operating conditions and to determine the impact on the plant. Care was used to ensure that the steam pressure delivered to the CO2 system did not fall below the process requirements and that the steam pressure to the turbine did not fall below its needs. Key issues for the turbine are sufficient steam to adequately cool the turbine and to meet the pressure requirements at the condenser. In the event the LP steam cannot meet these criteria, HP steam must be used to operate the CO2 system. Figure 2 provides a diagram of the integration of the CO2 system with the steam cycle.
The following series of graphs provide the results of the modeling effort associated with the operation of the CO2 system at varying loads. Each graph compares both the heat rate of the unit and the emissions on a pound per MW net basis against the "X" axis, which shows the relative output of the unit compared to full load net output. Figure 3 indicates the performance of the plant without the CO2 system in service. The plant heat rate is just under 9,990 Btu/kW and the emissions are about 2,255 lb/MW at full load.
Next, in Figure 4, we show the impact of turning the CO2 capture system on at full load. Note that the plant output drops by about 14 percent (with one-half the unit being scrubbed, which is typical of the reported 25-30 percent penalty reported in other studies). Plant heat rate increases to 10,925 Btu/kW while CO2 emissions are reduced about 1,310 lb/MW.
Figure 5 shows what happens as the plant is turned down with IP/LP steam, which must be used to supply the stripper to regenerate the CO2 solvent. In order to maintain a safe operation of the steam turbine, the CO2 system must also be turned down. Operation points at 0 percent turndown (full load) 25 percent, 50 percent and 60 percent (40 percent throughput) turndown are indicated. At the 60 percent turndown or 40 percent throughput, we are at the minimum operating point for the CO2 scrubbing system. Under these conditions, the boiler's operating load has been reduced to only 80 percent of net output. This represents an 8 percent operating range from full removal to 40 percent removal. Although the heat rate improves during these conditions from the full load operation, CO2 emissions increase to 1,710 lb/MW.
The next issue is the impact on the plant of maintaining full flow through the CO2 system. This is shown in Figure 6. At the 82 percent load condition, the steam pressure and flow is no longer acceptable from the IP/LP. Now the steam supply must be switched to main steam. The use of main steam imposes a huge penalty on the power plant. The heat rate skyrockets, and the emissions of CO2 increase dramatically. At about 50 percent net output, the emissions exceed 2,200 lb/MW and are about the same as the emissions from the plant if no CO2 were captured at all. This outcome was not expected when we began the study.
The overall impact is summarized in Figure 7 which compiles the data from each step into one picture.
These impacts suggest that it will be necessary to run the plant at nearly full load at all times to have any benefit from a CO2 capture system. This is obvious since reducing plant load only increases the relative emissions on a pound per MW basis rather than further reducing the impact. Removing the CO2 just to send it to a disposal site is not the goal, rather the goal is to reduce the "footprint" or CO2 emissions per MW dispatched. This is the true measure of the technology since MW not generated (consumed in the process) must be made up someplace else.
The overall capital costs for amine-based CO2 capture systems are greatly dependent upon the site specific aspects of the installation. In general, the DOE reported costs can be used as a guide for general planning purposes.
Since no commercial utility scale plants have actually been designed, detailed cost estimates for the technology are very speculative.
The impacts of CO2 capture systems can greatly limit the degrees of freedom associated with the operation of a specific generating plant. A plant with these systems retrofit will likely need to operate at near full capacity in order to optimize the capture from the facility. The use of high-pressure steam is impractical due to the severe penalties imposed on the plant performance.
Therefore, turndown of the plant needs to be carefully studied to fully evaluate the impacts on the overall operations. This may be true for complete scrubbing of the flue gas or even with partial scrubbing of the flue gas, as was the case in the example presented here. Turning down the CO2 capture system at partial load can mitigate heat rate concerns to some extent, but should be studied in detail for each specific retrofit application.
It must be remembered that these findings are applicable only to the specific amine-based technology studied and the plant to which the technology is retrofit. Other CO2 capture technologies might have a broader leeway on steam specifications and demand, which would expand the operating window for turndown.
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