Increasing flexibility while reducing costs – is it possible?

1 March 2014



It sounds like something of a paradox, but relatively simple and cost effective upgrade technologies are available that can increase operational flexibility and improve the economics of the existing coal fleet. Examples include adding thermal storage, which can be used to steepen load gradients, combustion stability monitoring to safely reduce the lower load limit and decrease auxiliary fuel requirements, and the use of hot water recirculation to maintain effective SCR operation at low load.


Today's operators of coal fired power plants face a challenging environment. In Britain, for example, wind power production has increased almost 5 times in the last 5 years. Reserve margins above 30% indicate a power oversupply even when non-dispatchable assets like wind & solar are de-rated and operating margins are very low, with clean dark spreads currently around €2/MWh.

Although the UK is phasing out coal plants as a result of the Industrial Emissions Directive and therefore reserve margins will decrease over the next three years, the outlook is gloomy when it comes to power plant operating margins. The slow economic recovery combined with the move over the last decade of manufacturing industry to low cost countries, means power demand at night and over weekends is low.

Against this background, there are potential benefits in deploying technologies that can maximise operational flexibility while at the same time reducing operating costs. Three examples are discussed here: deployment of a water based thermal storage system; use of combustion stability monitoring to reduce coal and support energy requirements at low load; and hot water recirculation to maintain adequate emissions control at low load.

Thermal storage

"Water is stored when power demand decreases and released when demand rises."

The addition of thermal storage is an innovative and effective, yet simple, concept. Hot water storage tanks are installed in parallel with the low pressure feedwater preheaters and the feedwater tank. The water is stored when power demand decreases and released when demand rises.

The possibility of storage enables the plant to increase positive (discharging) and negative (charging) load gradients (Figure 1). Such applications can be realised by relatively small storage systems (duration <30 min) and are financially attractive.

Larger storage systems are useful for temporarily reduced low load operation and peak load generation. The ability to charge the storage tanks during low load reduces the minimum load of the plant and improves the economics of low load operations. When electricity demand and prices rise, the energy stored in the water tanks can be immediately discharged in a response that is faster and easier to control than making boiler adjustments.

The thermal storage solution is therefore suitable also for providing primary and secondary frequency control response. During periods of low electricity prices, cold water is heated to the maximum achievable feedwater tank temperature (eg, about 180°C), see Figure 2a. This diversion of energy decreases the turbine power output. When electricity prices rise, the low pressure feedwater preheaters can be partly bypassed and the stored hot water returned into the feedwater tank, see Figure 2b. Little or no extraction steam is needed, and the power output increases immediately. These changes are made independently of the boiler control system, which makes the solution precise and responsive.

Depending on the system configuration (see Figures 3a and 3b), this approach can, for a 350 MW hard coal plant, give an incremental reduction in low load of up to -32MW or an increase in peak power of up to +17 MW:

 
 Low loadPeak power
Configuration 1-9 MW+15 MW
Configuration 2-32 MW+17 MW


Depending on the market conditions and the plant modifications needed, such a solution can be implemented during a normal outage and with a payback period of less than 2 years.

Combustion stability monitoring (RSS2/3)

Combustion stability monitoring technology allows power plant operators to: extend low load range safely; and improve operating margins by reducing auxiliary fuel (oil or gas) consumption at start up and low load.

"Alstom's RSS-3 combustion stability monitoring system comprises four optical sensors"

Alstom's RSS-3 combustion stability monitoring system comprises four optical sensors (Figure 4) for flame monitoring in the visible and infrared spectra and an evaluation unit that processes the flame fluctuation data and computes the instability value for display on the local unit or the plant DCS.

The instability readings provided by the RSS-3 allow the operator and DCS programs to make confident operational control decisions. Also, significant amounts of auxiliary fuel (gas or oil) can be saved during low load, start-ups and extraordinary events on the basis of RSS-3 information that flame stability is good. At the same time the RSS-3 system reduces the likelihood of boiler trips and also ensures a master fuel trip to protect the boiler and plant personnel when the flame stability fails.

The system enables typical start-up savings of 0.5 to 1 hour of full auxiliary fuel flow, meaning around 10% to 15%, and in some cases up to 25% auxiliary fuel savings (dependent on duration of the turbine start).

Operational experience plays a significant role in reaping the full benefits of the technology. Figure 6 shows average auxiliary fuel consumption per start before and after one particular RSS2 installation. The technology allowed the operators to eventually reduce start up gas consumption to nearly half of the original gas consumption.

Some 35 such systems have been installed around the world to date and have proven effective in supporting operators during start-ups and when encountering feeder issues, fuel quality variations, air distribution problems, tube leakages and clinker falls.

The modifications needed to install the combustion stability monitoring system can be done during a normal outage and based on the cost of auxiliary fuels, gas or oil, payback time is typically below 1 year.

Maintaining SCR performance at low load

"There is a risk of flue gas temperature declining below 300 degrees Celsius, significantly reducing SCR performance"

Some coal fired plants have installed selective catalytic reduction (SCR) systems to reduce NOx levels. Addition of an SCR system may require the economiser exit gas temperature be adjusted to optimise SCR performance for the desired control range. The need for further adaption and control of exit gas temperature increases if the unit operating regime has changed to low load. Typically the SCR requires a flue gas temperature after the economiser of 330-400 degrees Celsius. Most coal units designed and delivered during the 1970s and 1980s were designed to operate at >65% of full load, but anticipated coal plant loads can now be below 60%. This means that there is a risk of flue gas temperature declining below 300 degrees Celsius, significantly reducing SCR performance.

This problem can be addressed by installation of a hot water recirculation system (Figure 7) that allows the operators of natural and controlled circulation (subcritical pressure) boilers to control the exit gas (ie, economiser outlet) temperature at loads below MCR so that the SCR equipment can continue to operate in a gas temperature range that allows good performance, see Figures 8a and 8b.

In the hot water recirculation system water at, or slightly below, saturated water temperature from the downcomer system is sent through a recirculation pump so it can be injected into the economiser inlet. The increased temperature at the economiser inlet decreases its ability to absorb energy (which depends on mean temperature difference). The result is an increase in economiser exit gas temperature.

The cost of the hot water recirculation system for subcritical boilers is very competitive with an economiser flue gas bypass system.

The control philosophy for the recirculation system is based on the economiser inlet temperature requirements. As noted, the pumped hot water flow is used for control of the average economiser exit gas temperature by recirculation from the downcomers to the economiser inlet. The final pump head and flow requirements are specified to provide enough flow and head for the economiser recirculation duty for the desired control range. The pump head is selected to accommodate the requirement for a flow control valve in the pump discharge/hot water recirculation line. The control valve modulates the hot water flow within the required performance range, as needed to attain the proper exit gas temperature.

When the pump is de-energised at higher loads, it is isolated by the stop-check valve in the new recirculation link located near the economiser inlet. During such pump shutdowns, warming boiler water flow is used to minimise any thermal differential temperature upon pump restart. The differential temperature between the boiler water and pump volute casing must be less than 100°F. This warming flow is supplied through a small diameter pipe from the existing economiser startup recirculation line. Approximately 5 to 10 gallons per minute of boiler water from the main circulating pumps via the lower rear drum and economiser startup line flows through the recirculation link and the pump to the downcomers. The recirculation pump and control valve are designed for this condition without damaging the pump parts.

As is the case with existing wet motor boiler water circulation pumps, the new hot water recirculation pump motor requires cooling water flow to an externally mounted cooler that is sized to maintain motor cavity water temperature at less than 130°F under all conditions. This is necessary to prevent overheating and premature failure of the wet motor.

The hot water recirculation system has been installed in two units to date and has successfully helped operators to maintain SCR performance at reduced loads.

Depending on the scope of planned boiler outages the required modifications can be performed during a routine boiler outage. The pay back period is highly dependent on local conditions but can typically be less than three years.

Building on experience

The portfolio of upgrade technologies described above can help coal plant operators meet current challenges by simultaneously reducing operating costs and improving operational flexibility. They build on a combination of owner/operator experience and supplier experience from various installations around the world.


Author notes

William R Miller, Volker Schuele and Karin Dahlström, Alstom Thermal Services, Baden, Switzerland

Figure 1. How addition of thermal storage increases load gradient (secondary load control (SLC) range)
Figure 2a. Load reduction by charging the storage, during periods of low electricity price
Figure 2b. Load increase by discharging the storage, during periods of high electricity price
Figure 3a. Thermal storage installation, configuration 1
Figure 3b. Thermal storage installation, configuration 2
Figure 4. RSS-3 optical sensor
Figure 6. Average auxiliary fuel consumption (gas) per start-up
Hot water recirculation system, subcritical steam Figure 7. Hot water recirculation system, subcritical steam
SCR operation without hot water recirculation system Figure 8a. SCR operation without hot water recirculation system
SCR operation with hot water recirculation system Figure 8b. SCR operation with hot water recirculation system


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