BOILERS COGENERATION CORROSION FAILURE ANALYSIS GEOTHERMAL MONITORING POWER SAMPLING SCALING STEAM

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Abstract

The failure to accurately sample and analyze saturated, superheated, and reheated steam from boilers or heat recovery steam generators (HRSGs) can lead to significant deposition and corrosion related failures of the steam path in boilers, HRSGs, steam turbines, and any process equipment that comes into contact with the steam. The article discusses the minimum acceptable equipment standards for sampling and on-line analysis of steam from boilers and HRSGs, along with the need for routine carryover testing. Multiple real world case studies of steam sampling, analysis and purity issues are presented with key lessons identified.

Article Introduction

It should be appreciated that even the highest purity steam contains sufficient contaminants, ions, and oxides to result in deposition onto steam turbine surfaces in the phase transition zone (PTZ) of the turbine. In the case of elevated impurities in steam produced by a boiler or HRSG, these have the potential to cause additional deposits in the steam turbine as any elevation of the impurity levels will result in increases in concentration in the liquid films and deposits on these surfaces. 

These deposits increase the risk of corrosion in the steam turbine and also the superheater and reheater sections of the plant where they can form, adversely affecting their performance and reliability. Elevated impurities in steam can be due to steam contaminated because of carryover and/or substandard attemperator spray water. These affects can include the following:

1. Superheaters and reheaters:

Deposition during operation of impurities onto internal tube surfaces, which cause a restriction of steam flow. This steam flow reduction from the buildup of a deposit decreases the cooling of the tube and increases the tube metal temperature. This ultimately results in an in-service overheating failure of the tube because of creep.

Deposition during operation of impurities such as sodium sulfate, which become corrosive during repeated shutdown periods with ineffective layup and storage protection when the deposits are exposed to oxygen and moisture. This results in the growth of pits on the tube internal surfaces during shutdown periods and ultimately in an in-service through-the-wall failure.

2. Steam turbines:

Deposition during operation of impurities such as silica and copper onto steam turbine surfaces, which disrupt turbine steam flow and decrease turbine efficiency and output (1).

Deposition during operation of impurities such as sodium hydroxide and sodium chloride onto steam turbine surfaces during shutdown periods with ineffective layup and storage protection for when they are exposed to oxygen and moisture. This results in pitting in the turbine that then become the initiation locations for in-service cracking to take place, such as stress corrosion cracking and corrosion fatigue, which can then result in in-service failures of the steam turbine.

3. Process equipment:

Deposition during operation of impurities onto internal plant surfaces that cause an insulating effect, which can result in significant process efficiency losses.

Deposition during operation of impurities such as sodium sulfate, which can become corrosive during shutdown periods with inadequate layup and storage preparation. This can result in the growth of pits on the equipment internal surfaces during the shutdown periods and ultimately in an in-service through wall failure.

Contamination of final products where direct steam injection is carried out, such as can occur during the processing of milk products.

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