Optimising combustion operations through monitoring

In the scramble to prepare for a new regulatory regime, the owners of large combustion plants should not forget the vital role that good monitoring can play in helping them meet both their production and their emissions targets.

The race is on for the UK power generation industry and other operators of major combustion plant to ensure they have the measures in place to comply with the Government’s National Emission Reduction Plan (NERP). The NERP is the British interpretation of the country’s obligations under the revised Large Combustion Plants Directive (2001/80/EC).

Although the deadline for the Directive to be implemented throughout Europe is 2008, the latest UK guidance sets out a clear timetable for national action, with all the mechanisms needed for industry to comply to have been in hand by the end of 2006. This gives the regulators time to get their act together in terms of monitoring and enforcement by the end of 2007 and should ensure that the country can meet its obligations by the 2008 deadline. Both the Large Combustion Plants Directive (LCPD) and Waste Incineration Directive (WID) stipulate the use of emissions monitoring equipment certified to MCerts especially in the UK as this is a requirement by the UK Environment Agency.

The requirements under the new regime are complex, involving a novel emissions trading scheme between power plants, as well as some major investments in technology such as flue gas desulphurisation. Yet amongst all this high-profile novelty, the potential impact of what might be called ‘good housekeeping’ should not be overlooked. Running and maintaining combustion plant at optimum efficiency can have a huge impact on its performance and significantly reduce operating costs.

Strike a balance

To start with a simple example, let’s look at the potential impact of monitoring the flue gas to check combustion efficiency. By measuring the level of oxygen present in a boiler flue or furnace, it is possible to obtain data that can be used to optimise the air to fuel ratio to ensure maximum heat is extracted from the fuel. With the development and refinement of oxygen monitoring instrument technologies, it is now possible to test flue gas emissions with even greater accuracy.

Achieving efficient combustion

In a perfect world, all operators would be able to achieve stoichiometric combustion, the ideal combustion process whereby all fuel is completely consumed. In reality, however, many operators can only typically achieve between 30-50% efficiency at best.

The potential energy (heating value) of fuel varies according to the type of fuel being used. In burning any fuel, considerable energy is lost. Most of this lost heat is in the stack gases leaving the furnace. The lower the temperature of the exit gases, the higher the efficiency will be and the lower the extent of any pollution.

Too little air in the combustion process leads to incomplete combustion, encouraging problem emissions such as soot, smoke, carbon monoxide, NOx and SOx. However, heating extra air just to send it up the flue stack is a waste of fuel. Reducing the excess air through a system by 15% can increase the efficiency of the whole process by 1%, as does reducing the stack gas temperature by 22°C.

The optimum level of excess air depends on the fuel, but it ranges from between 5 and 10% for gas and 10-15% for fuel oil, all the way to 20-30% for stoked coal. Using instruments such as a Zirconia oxygen monitor and a temperature probe in the flue stack can help ensure the plant is burning fuel optimally. These monitors typically consist of an electronic transmitter/indicator used in conjunction with an in-situ Zirconia sensor inserted directly into the flue or furnace. This removes the need for a costly extractive sampling system.

If the oxygen level rises in the stack-gas over time, it can also indicate the need for minor adjustments or repairs, while a rising stack-gas temperature can indicate the need for tube cleaning, since fouling may be hampering heat transfer.

Oxygen monitoring through the whole flue gas path at strategic points can enable predictive (not planned) maintenance, for example, either side of air reheaters to detect leakage of air due to wear. An additional way of optimising air flow from a pulverising mill to the boiler is to use electric actuators to regulate damping equipment. Scottish Power’s Longannet power station consumes up to 40 tonnes per hour of pulverised coal. Each of the station’s four generating units is fed by coal from eight pulverising mills. Two dampers on each mill control the airflow that both conveys the coal to the boiler and then provides combustion air.

The mill dampers are controlled by part-turn electric actuators, which regulate the air flow by turning the dampers through a range of 90°. Linear electric actuators are also used for two other applications at the site. Some control the feed regulating valves, which control the flow of water to the boilers. The others control the ‘de-sup’ spray, which injects water into the boiler to prevent the steam temperature rising above the 565°C required by the turbines.

A question of chemistry

It’s not just on the gas side that fouling can be a problem. Silica is a major culprit behind the build up of hard and dense scales inside the boilers and turbines of power generation plants. At a time when power companies are anxious to optimise their operations in line with business and environmental pressures, they can ill afford to operate plants suffering from the impaired heat transfer that results from this type of fouling. Although boiler feed water is treated to remove silica and other ionic contaminants, effective long-term control of silica can only be maintained by using the correct monitoring system.

Silica forms a dense porcelain-like scaling that cannot be removed with acid. Silica scaling also has a very low thermal conductivity. Because of its low thermal conductivity, a 0.5mm build up of silica can reduce thermal transfer by 28%, reducing efficiency, leading to hot spots and ultimately ruptures.

An American survey by the Electrical Power Research Institute found that 50% of the forced outages in US power stations are due to corrosion. In fact, a boiler with the wrong internal chemistry can fail in as little as 1,000 hours of operation – that’s just six weeks.

The two main sources of contamination are the feed make-up water and the returning condensate. Condensate returns to the boiler from the condenser, which has cooled it down using locally-sourced, lower quality water. Condensers are notoriously prone to leaks, however, so cross contamination is common.

Feedwater on the other hand, is normally de-ionised, pre-heated, deaerated and chemically treated before it makes it to the boiler. A failure in any one of these processes can lead to contamination problems.

Regular boiler blowdown is the obvious way to control contamination, although dosing the feed with chemicals such as ammonia or hydrazine also stops some chemicals getting that far. Careful, continuous monitoring also plays a vital role in ensuring good long term boiler chemistry and particular areas should be considered.

Controlling contamination

To keep the steam raising process running at peak efficiency, the following parameters should be monitored constantly:

Dissolved oxygen: Even small parts per billion concentrations of oxygen dissolved in the feedwater stream can cause pitting in the boiler, drastically reducing its operating life. The concentration of dissolved oxygen therefore needs to be checked throughout the feedwater loop, from the extraction pump through to the deaerator and the boiler inlet.

One way to control dissolved oxygen levels is by dosing boiler feedwater with hydrazine. Hydrazine is a colourless liquid, which is highly soluble in water. It is a powerful reducing agent that reduces oxygen to form nitrogen and water. At high temperatures and pressures, it will also form ammonia, which increases the feedwater pH level, reducing the risk of acidic corrosion. As an oxygen scavenger, hydrazine is widely used to remove trace levels of dissolved oxygen in the boiler feedwater.

Hydrazine is also ideal as it reacts with soft haematite layers on the boiler tubes to create a hard protective magnetite layer which acts to protect the tubes from further corrosion.

Placing a hydrazine monitor at the feedwater inlet will help check that feedwater is being dosed with the correct amount of hydrazine. Too much hydrazine is both wasteful and costly, whilst too little will not be able to adequately control dissolved oxygen levels and will prevent the formation of magnetite. Typically, the most effective dosage of hydrazine is 3:1 parts hydrazine to the expected level of dissolved oxygen.

pH & Conductivity: pH is an extremely important parameter to measure, as it gives an indication of the degree of acidity or alkalinity of the feedwater.

Measurement of conductivity in the feedwater and steam loops provides an indication of water and steam purity. By measuring the electrolytic conductivity of the feedwater (that is, the ability of the feedwater to pass an electrical current), it is possible to ascertain the level of contamination present, which can then be used to dictate the level or duration of treatment required. For example, where boiler blowdown is used, conductivity will be one of the main parameters used to control the frequency of the blowdown process.

Silica: As mentioned previously, the formation of silica can severely impair boiler effectiveness, hampering heat transfer efficiency and increasing the risk of mechanical failure such as turbine blade malfunction. Silica entering a high-pressure boiler can concentrate very quickly.

As dissolved silica is only weakly ionised, it is difficult to detect by conductivity measurement. For this reason, dedicated silica analysers are necessary if accurate information is to be obtained.

Depending on the type of power plant, typical sampling points for silica monitoring include the water treatment plant, the boiler drum and the saturated steam.

Sodium: Sodium is one of the most important parameters to measure on a boiler plant. Although conductivity measurement is typically used to indicate total dissolved solids or chemical conductivity, it lacks adequate sensitivity. As sodium is present in the critical dissolved compounds, it can be detected with on-line sodium monitors, which are very sensitive.

Other parameters that operators may also wish to monitor include phosphate, ammonia and chloride, using sensors that offer quick response times, are temperature tolerant and require minimal maintenance.

Sound principles

While the technologies used to make the different measurements outlined above vary, there are certain generic principles that it’s always sensible to follow when choosing and installing instruments to monitor boiler chemistry. Using instruments that can respond rapidly to any changes in the chemistry will help provide as accurate as possible a picture of current conditions.

The location of monitoring equipment is also a vital component in ensuring the best return on investment in a power plant. Ideally, monitoring equipment should be situated in an environment that has less potential for damage, has easy access for maintenance and allows for enhanced measurement accuracy.

Sampling instruments should also be located together, where possible, in a clean and accessible environment. The sample conditions, such as temperature and pressure, should also be suited to the requirements of the measurement sensor.

One way to achieve this is to use pre-manufactured packaged monitoring stations. Incorporating a full array of sampling instruments, including coolers and pressure reducers, these stations can be built to an operator’s requirements and can simply be connected up to the power plant’s existing sampling lines, greatly reducing the time, cost and disruption typically associated with installing and commissioning sampling systems.

At npower’s 1500MW coal-fired Aberthaw Power Station in Wales, three analytical equipment systems are ensuring continuous monitoring of feed and boiler water chemistry. The make-up water is abstracted from a nearby borehole and is de-ionised by the station’s on-site water treatment plant. Ammonia and hydrazine are dosed into the feed system and caustic soda is dosed into the boilers to help regulate the boiler chemistry.

If applied in overly-high quantities, these dosing chemicals can actually accelerate boiler corrosion, potentially resulting in premature boiler or condenser tube failure. If the de-ionisation plant is not working well, the feed water will also contain high levels of contaminants such as silica and sodium, which could impair efficiency.

Cabins were installed to replace the station’s old monitoring laboratory, which had to be demolished as part of an upgrade of the site. Measuring 3.25 metres long, 1.2 metres wide and 2.2 metres high, each cabin is situated adjacent to one of the station’s three boilers, thus allowing shorter sample lines.

The shorter sample lengths between the boiler, generator plant and the cabins will cut the delay in obtaining samples for analysis. In addition, the new instruments include alarms for low flow, plus an automatic temperature alarm and shut-off should there be a failure in the cooling system which could damage the monitoring equipment.

Together, the cabins will provide a total boiler chemistry control system aimed at optimising the efficiency of the station’s boiler and generator plant. With the high temperatures and pressures in the boilers, any contaminant ingress could become highly corrosive, which could lead to a boiler tube leak and result in costly and disruptive unplanned downtime. The cabins will help make sure the levels of contamination are as low as possible and that the chemical balance is ideal to prevent corrosion.

Make the most of the data available

Choosing instruments with self-diagnostic capabilities will make it easier to identify any issues, while equipping them with an output to a central control room makes it more likely that data will be seen and acted upon appropriately.

Ferrybridge C power station in West Yorkshire uses 24 SM series videographic data recorders to monitor and collect data on a range of processes within the power station. The units are installed at each of four 500MW generating control panels within the control room, each comprising of five large screen recorders and one small screen unit. At each station, the large screen units are used to collect data on boiler emissions and for turbine and boiler feed pump monitoring. The smaller units are used to monitor boiler performance and collect data on parameters including pressure, temperature, feedwater and steam and air flows.

For operators, the main benefit has been the ability to be able to immediately access both current and historical information on plant performance, rather than having to search through paper charts.

Although this new breed of electronic data recorders promise remote supervision and access to data, plant operators will only benefit if the instrumentation on the plant floor is providing the right information.

Keeping an eye on the performance of temperature and pressure equipment can play a major role in identifying potential room for improvement. Temperature and pressure are the most commonly measured parameters in any combustion plant. Pressure is typically measured at up to 150 points for each generator set. With anything up to 200 measuring points per set, temperature is monitored even more closely.

Raising the temperature by just 10°C doubles the rate of chemical reactions, which is commercially important across a range of industries. In fact, around half of all industrial measurements are for temperature. In the case of boiler tubes, however, it can halve their life expectancy as the reactions that lead to corrosion go into overdrive.

Measuring pressure ensures that the plant is operating safely within its design limits. Differential pressure can also provide a useful indirect way of measuring mass flow, which is an ideal solution in conditions where the flow features low conductivity samples that rule out other methods.

At Scottish Power’s 1200 MW coal-fired Cockenzie Power Station, in Prestonpans East Lothian, differential pressure transmitters play a vital role in optimising combustion efficiency. Pulverised fuel is produced on site in a grinding mill. Air blows through the mill from a primary air fan to pick up coal dust and deliver it to the boiler, where it burns to produce the heat energy for steam generation. To optimise the efficiency of the process, it is vital that the air picks up fragments of coal at just the right size. If the air flow through the mill is too low, it will not pick up enough pulverised fuel and insufficient fuel will reach the correct area of the furnace. If the air flow is too high, it will pick up Large Combustion Plant Directive oversized particles that will not have time to burn completely in the furnace.

With even a very small incremental change in differential pressure making a big difference to the way the system feeds the coal, pressure transmitters are used to ensure the automated control system keeps the fans working at precisely the right rate. To ensure close control of the process, Cockenzie stipulated that the transmitters had to operate over a differential pressure range of just 0-5mbar (0-0.5kPa). 2600T differential pressure transmitters more than surpassed this, offering an accuracy of 0.04% over a span from as little as 0.5mbar (0.05kPa), right up to 100bar (10 000kPa).

With rising fuel costs and changing environmental legislation, the pressure to optimise the operation of large combustion plant can only increase. The right monitoring schemes can improve combustion efficiency, reduce pollution, extend the life of equipment and reduce the frequency of unplanned stoppages. As the power generation industry busies itself with radical emissions trading schemes and grand projects, it also essential to remember not to overlook the basics.

Published: 10th Jun 2007 in AWE International