Southern Illinois Power Co-operative (SIPC), established in 1948, is a generation and transmission co-operative serving three distribution co-operatives. The co-operative supplies power to southern Illinois, to an area south of Mount Vernon. The service area covers about 170 square miles and includes about 840 miles of transmission lines. SIPC operates four units at Marion station. Units 1-3 were commissioned in 1963 and are B&W cyclone fired boilers rated at 33 MW each. Unit 4 was commissioned in 1978 and is a 173 MW B&W cyclone fired boiler.
SIPC initially requested from Sargent & Lundy an economic study to determine the most economic approach to meet current and future power requirements and the impacts of the NOx emission reductions expected to be required by Title I of the 1990 US Clean Air Act Amendments. Units 1-3 were well into their fourth decade of operation and were experiencing reduced reliability. The following repairs were deemed necessary to improve reliability and performance of these three units:
• new digital control system (DCS);
• new pendant superheater tube loops;
• new tubes in the first four rows of generating tubes;
• new cyclone burner tubes;
• new furnace wall tubes;
• balanced draft conversion;
• rebuilt boiler feed pumps;
• refurbished coal conveyors; and
• new demineraliser.
All four units had high NOx emissions due to their cyclone burners. SIPC peak demand had been increasing steadily and in approximately 2003 would start to exceed their generating capacity.
To select the best course of action the following were the major generating alternatives identified for study:
• Refurbishment, no emission modifications & buy emission credits – four alternatives.
• Refurbishment & emission modifications – four alternatives.
• Convert units 1-3 to natural gas or seasonally burn natural gas – six alternatives.
• Replace small boilers & burn waste coal – five alternatives.
• Repower with combustion turbines – one alternative.
• Install combustion turbines – three alternatives.
• Install combined cycle power plant – two alternatives.
• Power purchase agreements – four alternatives.
Numerous combinations of these alternatives were evaluated for a 30-year period. Not all the alternatives were capable of meeting the expected NOx emission allocations and the cost of purchasing NOx allowances was considered for these cases. The evaluation considered the annual fixed operating and maintenance costs and performed a sensitivity analysis of interest rates, fuel costs, allowance costs and load growth. The results for Marion units 1-3 are summarised in Table 1.
The optimum combination of alternatives for the projected load growth was found to be the following:
• Replace units 1,2 & 3 with a fluidised bed unit.
• Add SCR to unit 4 (see diagram, for cost comparison of emissions options) .
• Add 140 MW of combustion turbine in 2003.
• Add 70 MW of combustion turbine in 2007.
• Total generation in 2003 = 470 MW
• Total generation in 2007 = 540 MW
• Capital cost 2000-2003 = $178 million
• Capital cost 2006-2007 = $33 million
The output and heat rate for the existing units and new circulating fluidised bed units can be compared in Table 2.
Air permitting
For air permitting of the new units a netting calculation which considered the new circulating fluidised bed boiler (and retirement of units 1-3), the combustion turbine (CT) and the selective catalytic reduction system (SCR) was prepared.
The emission netting calculation had the following steps:
Step 1Determine emissions increases for proposed modifications.
Step 2Determine beginning and ending dates of modification period.
Step 3Determine which emissions change during contemporaneous period.
Step 4Determine which emission changes are creditable.
Step 5Determine on a pollutant-by-pollutant basis emissions the decreases and increases.
Step 6Sum all the increases and decreases to determine if significant net emissions increases will occur.
The proposed increases in pollutants shown in Table 3.
The proposed decreases shown in Table 4:
The resulting net changes were estimated as shown in Table 5.
The only emission increase that exceeded the prevention of significant deterioration (PSD) major modification threshold, was carbon monoxide. On that basis, the necessary Best Available Control Technology (BACT) analysis and emission modeling was preformed for CO emissions.
An additional feature of the project will be the use of dry handling for both the CFB project and the unit 4 fly ash systems. This will result in a significant decrease in water usage and effluent streams for the site.
Currently the PSD air permits applications have been submitted to the Illinois Environmental Protection Agency and are in the final draft stage.
Engineering aspects
Based on the results of the generation alternative and site study SIPC decided to proceed with the detailed engineering. An island approach based on including the steel, ductwork and fans was selected for the circulating fluidised bed boiler. The following major engineering activities were identified for the CFB project:
• Environmental permitting (PSD permit, NPDES permit, CEMS, acid rain compliance etc).
• Environmental report, construction work plan and associated interface with rural utilities service.
• Procurement services for approximately 26 specifications.
• Piping design and analysis for high energy piping.
• Balance of plant piping design.
• Coal and limestone handling design.
• Electrical and control design.
• Startup test procedures.
• System descriptions.
As with most repowering projects, the interface with the existing unit has proven to be a challenging process. The condition of the plant and of the existing drawings has required careful design review.
The electrical system for the old units was based on 2200 volts. To improve efficiency and provide a more reliable power supply it was decided to upgrade the auxiliary power system of units 1-3 to 4160 volts.
The available area for the CFB is limited and the interface with the existing circulating water bus duct made the development of the plant arrangement difficult.
The mine waste is prone to plugging the material handling equipment. To minimise plugging at the transfer chutes S&L has made use of steep angle transfer chutes and is using reversible feeders where possible. The major modifications required are listed below:
• CFB island, by Foster Wheeler Energy.
• Coal & limestone handling, new conveyors and reclaim hoppers.
• Drag chain bed-ash conveyor and new silo.
• Vacuum fly ash system making use of rebuilt fly ash silo.
• New 195 ft clad steel stack.
• New distributed control systems.
• Upgrade of the electrical power supply. And
• New boiler feed pumps.
CFB design
In November of 1999 the CFB island was issued for bids. The island contract was issued to Foster Wheeler Energy Corporation in August 2000.
The CFB boiler for the SIPC project is shown in the diagram. It is designed to provide 1 140 000 lb/h (518 t/h) steam flow at 875 psig (60.3 bar) and 905°F (485°C). This new boiler replaces the older boilers for units 1-3 and supplies steam to the associated turbine-generators which will be re-used. This repowering with CFB technology will allow the owner to reduce fuel costs by enabling him to fire 100 per cent of a low-cost coal waste while at the same time significantly reducing emissions.
The unit is designed for maximum flexibility with the primary fuels being coal refuse (8235 Btu/lb, 21 per cent moisture) and several Illinois coals. The unit will also be capable of firing pet coke (up to 20 per cent heat input), wood refuse (up to 5 per cent heat input) and tyre derived fuel (up to 5 per cent heat input).
The SIPC boiler incorporates many proven design features which will reduce operating and maintenance costs. These include the following:
• Underbed start-up burners
The start-up burners are located in the ducts feeding air to the furnace floor, so that all the heat released in the burner passes through the bed. This minimises the amount of start-up fuel required to heat the bed material compared with overbed burners.
• In-furnace surface
Wingwalls in the furnace provide the additional heating surface needed to maintain the proper furnace temperatures, avoiding the need for an external heat exchanger and the corresponding auxiliary power (for fluidising air) and maintenance.
• Water-cooled cyclone
The cyclone separator is formed from tubing which is cooled with thermal circulation of water from the steam drum and lined with 1 in (25 mm) of refractory. This cyclone design minimises refractory and has proven to be essentially maintenance-free, a significant improvement over other designs which use thick refractory linings and so require extensive maintenance.
Fluidised ash cooler
Bottom ash from the furnace is cooled in a fluidised ash cooler, in which the hot ash is cooled with air from the primary air fan and the heated air passed to the furnace. There are no moving parts in the hot ash stream, which minimises maintenance. The ash heat recovery and minimal maintenance aspects are especially important when handling the relatively high-ash waste fuel planned for the project.
SO2 emission requirements call for 92 per cent sulphur removal, accomplished with limestone feed to the furnace. NOx emission levels are 0.10 lb/MMBtu (145 mg/Nm3), requiring an SNCR system which injects aqueous ammonia into the cyclone inlet in order to further reduce the already-low NOx levels from the furnace. Particulate emission levels are 0.011 lb/MMBtu (20 mg/Nm3) which are met with a baghouse.
Meeting the schedule
The primary challenge for this project has been getting the permits to allow start of construction this spring. It was very close. Another challenge has been to determine the best approach for the electrical improvements and the DCS tie in while minimising unit outages. A two phase DCS installation was selected. The first phase will be to transfer the unit 1-3 turbine controls to the new DCS system while operating the boilers on the existing analog/pneumatic system. The unit 1 turbine and boiler controls will then be tied in and complete DCS controls checked out before taking the final two units out of service. The project schedule can be summarised as follows:
• Initial long range generation study – Sept 1999.
• Engineering contract awarded – April 2000.
• CFB contract awarded to FWEC – August 2000.
• Start of construction – spring 2001.
• Initial CFB operation – October 2002.
• Commercial operation – February 2003.
As of the time of writing, the drum is on site and scheduled for raising in mid October. Steel has been going well and will support drum raising. The soil characteristics have necessitated drilled pile foundations and, with the high seismic loads, the largest was 8 ft in diameter.
The 195 ft steel stack was provided by Warren Environmental and is hastelloy clad, allowing SIPC to burn the wide variety of fuels envisaged. The stack was delivered in three pieces and erected in a week.
United Conveyor Corp is providing two drag chains for bottom ash going to a new bottom ash silo. The vacuum fly ash system will discharge to a rebuilt silo on site. Both the bottom ash and fly ash silos will discharge to trucks or an existing sludge conveyor on site.
The coal handling system was awarded to Roberts and Schafer and consisted of a new reclaim hopper feeding into the existing crusher house and new transfer conveyor to the CFB silo bay the silos will be fed with a shuttle conveyor.
A new Ovation DCS will control the CFB and upgraded turbine system.
On budget and on schedule
The Marion CFB repowering project continues to pose challenges. However, the selection of a circulating fluidised bed design will allow the Southern Illinois Power Co-operative to burn low cost mine waste. This is the key to the economics of the project. The low emissions from the CFB will meet the licensing requirements while minimising operating cost. There will be a net decrease in emissions of several major pollutants. The design will strive to make maximum use of existing equipment while providing a reliable low cost repowering of units 1-3. The project is currently on budget and schedule.
TablesTable 1. Results for Marion units 1-3 Table 2. Output and heat rate for the existing units and new circulating fluidised bed units Table 3. The proposed increases in pollutants Table 4. The proposed decreases Table 5. The resulting net changes
