Boiler contaminants: jeopardising power plant operation

05 August 2014

Optimum positioning of analytical instruments at key points throughout the water and steam cycle and water treatment plant on modern power stations can provide operators with a valuable insight for improving plant efficiency and cost effectiveness. Les Slocombe, of ABB Measurement Products UK, explains the benefits of balanced boiler chemistry and how key contaminants can be kept in check to ensure a safe and efficient process.

Vast quantities of water are needed to produce steam for power generation. Achieving well-balanced water chemistry can optimise the efficiency of steam raising and distribution. 

The elevated temperatures and pressures inherent in power generation applications increase the speed of chemical reactions taking place in a boiler. The American Society of Mechanical Engineers (ASME) advises that to control deposition and corrosion in the boiler, plant operators should ensure effective monitoring of makeup water, condensate, feed water and boiler water qualities.

The absence of adequate monitoring and control is likely to lead to both increased costs and more frequent component failures.

However, by measuring and monitoring the water in the boiler and the steam distribution loop and other areas around a power plant, it is possible to obtain a better overview of current conditions. When incorporated into a planned preventative maintenance programme, this information can help to reduce the risk of unplanned outages.

Why measure boiler chemistry?
A culprit behind many boiler failures is the accumulation of scale and corrosion brought about by contaminated water entering the boiler. Even in a well-controlled regime, it is not possible to eliminate the presence of potential contaminants present in boiler feedwater. For example, in a 500 megawatt boiler, around 1,500 tons of water is boiled off per hour. Most of the resulting contaminants present in the water will remain in the boiler. Close monitoring and control can determine the optimum time for boiler blow down operations to bleed off a measure of the contaminated water. This helps to prevent precipitated scale deposits from thermally insulating the heat surfaces, which can decrease the rate of steam generation and reduce operating efficiency.

Extensive on-line chemical monitoring is now established practice in the power industry. Online monitoring enables careful control of the water chemistry to achieve peak efficiency and minimise down time caused by excessive boiler corrosion or scaling.

Controlling contamination
Online analysis of the key parameters that can affect boiler water and steam quality enables operators to achieve a continuous picture of conditions in and around the steam raising and distribution loop. The following is a breakdown of some of the key parameters that should be covered by online monitoring.

Dissolved oxygen
Dissolved oxygen is a major cause of corrosion in steam systems. Oxygen contamination of steam condensate can lead to inefficient or improper feedwater aeration, air leakage at pump seals, receivers and flanges, leaking heat exchangers and ingress into systems that are under vacuum. It can also promote localised pitting corrosion, which can cause rapid failure of critical equipment in the steam system. 

One way to control dissolved oxygen levels is by dosing boiler feedwater with oxygen scavenging chemicals, such as hydrazine. When these chemicals are used, operators can assess the efficiency of their dosing regime by measuring for dissolved oxygen at the economiser or boiler inlet, with any fluctuations able to be addressed by increasing or reducing the dose quantities.

The dramatic variations in oxygen levels during the load cycle of a plant, combined with the different levels required for different boiler chemistry regimes, require an analyser that offers a fast response across both high and low dissolved oxygen concentrations. 

Hydrazine is used to remove trace levels of dissolved oxygen in boiler feedwater, forming 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. It also reacts with soft haematite layers on the boiler tubes to create a hard protective magnetite layer, that protects 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. Typically, the most effective dosage of hydrazine is 3:1 parts hydrazine to the expected level of dissolved oxygen, which should result in a dissolved oxygen concentration level of five parts per billion.

Sodium is the root cause of many types of corrosion in boilers. Traditionally, conductivity measurement was used to indicate the total dissolved solids. However, it lacks the sensitivity to measure sodium at low levels.

A problem with sodium is the cycle it undergoes during hydrolysis. During this process, sodium carbonate is turned into sodium hydroxide, which then attacks iron in the boiler. As iron dissolves, it forms sodium ferroate, which under hydrolysis, regenerates into sodium hydroxide.

Prolonged exposure to this cycle will put boiler components such as bends and joints under constant attack, causing them to become embrittled and increasing the risk of leaks and cracks. If carried over in the steam, sodium can also build up on critical components as the steam condenses.

To safeguard against sodium operators should measure levels at key points in the steam generation and distribution loops. Sample points should include the water treatment plant, the condenser extractor pump, the polishing plant outlet and the saturated and superheated steam distribution loops. At the water treatment plant, monitoring for sodium can help identify any sodium breakthrough from the cation exchange and mixed bed outlets caused by exhaustion of the ion exchange beds.

Monitoring for sodium also acts as a useful measure of bed efficiency as well as a precursor measurement for potential sodium contamination further down the line.

On-line measurement of sodium after the extraction pump provides a useful indicator of condenser leaks. Operated under high vacuum, the condenser is prone to leaks that cause cooling water to become mixed with the condensate.

A key concern is the ingress of chloride and sulphate. As sodium monitors have 10 to 100 times the sensitivity of on-line chloride measurement techniques, measuring sodium levels provides a good way of detecting for the presence of chloride and sulphate.

Polishing plants can also use sodium monitors to detect ion exchange bed exhaustion as well as for monitoring water quality. In some power stations, the polishing plant is incorporated into the main water treatment plant. In high pressure boilers, any chemical contaminants present in the steam can quickly build up in the boiler drum and can be carried over in the steam to the turbine.

Monitoring for sodium in the saturated and superheated steam distribution loops helps to protect against corrosion and the formation of sodium salts on the superheater or turbines caused by steam carryover. Measuring the purity of the steam and comparing it to the measurements taken from the saturated steam before the superheater and condensate stages, operators can assess whether quality is being affected by issues such as deposition of sodium salts or condenser leaks. The same measurement can also be performed for Once-Through boilers. However, as these have no separate superheaters, the sample is taken from the superheated steam before the turbine.

Silica is the main culprit behind the build-up of dense scale inside the boilers and turbines of power generation plants. It has a low thermal conductivity and forms a dense scaling that cannot be removed even with acid. A 0.5mm build-up of silica reduces thermal transfer by 28%.

The only way to control silica build-up is through an effective monitoring regime. Silica should be measured at multiple points around the steam system, including the demineralisation plant, boiler feedwater, boiler drums, superheater and condenser outlets.

Measuring silica in the steam from the boiler, either at the superheater or at the entrance to the turbine, gives a good indicator of overall steam purity. Provided that the silica concentration remains below 20 parts per billion, the level of scale deposition should be minimal.

Dissolved silica is only very weakly ionised, so it cannot be detected using a simple conductivity measurement but instead requires a dedicated monitor.

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

Online monitoring
To cut the costs and maintenance effort, modern analysers for power plants should include:
• Carefully designed wet sections
• Remote management
• Automatic calibration and cleaning
• Diagnostic messaging
Any programme aiming to maximise the efficiency of online monitoring systems should include using instruments that can respond quickly to changes in boiler chemistry and offer self-diagnostic capabilities where possible. 

The location of monitoring equipment is a vital factor 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.

Incorporating digital communications technology, such as Ethernet, enables data to be relayed to a central control room, opening up the accessibility of the measurement data beyond the local operator.

Having the ability to gauge maintenance frequency, coupled with enhanced life cycle costs, offers a good opportunity to improve reliability of supply and minimise unscheduled disruptions.

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