GLIMPSES OF IMPROPER WATER CHEMISTRY IN A SUBCRITICAL PULVERIZED COAL FIRED BOILER AT A THERMAL POWER PLANT

By K.K.Parthiban / Venus Energy Audit System & Sri Devi Boiler Equipment and Spares.

Introduction

Boilers suffer forced outages when there is a deviation in plant water chemistry. Power plant steam generators are more sensitive to water chemistry deviations as they operate at high pressures. Even few hours of compromise in water chemistry can cause tube failures. At times, this can cause deposition of solids in turbine blades. Recently we conducted a shut down audit of a 300 MW PF boiler at African continent. In this article, we bring out interesting observations on water chemistry.

About the steam generator

The steam generators are designed with controlled circulation for an evaporation rate of 992 TPH, at a superheater outlet pressure of 173.9 bar and temperature of 540 deg C. The feed water temperature input to steam generator is at 258 deg C. The unit has reheater steam flow of 914 TPH, coming in a pressure of 41.3 bar, 335.6 deg C and leaving at 39 bar at 540 deg C.

Sea water is used in condenser. The feed water is treated with ammonia for pH correction. 1-2 ppm of Trisodium phosphate is used for boiler water pH maintenance.

The boiler had been in operation for almost 15 years. The plant is taken for a major overhaul every eight years. This year, we were invited for detailed inspection of the plant. Though we had several observations in the plant on boiler pressure parts, erosion protection system, coal burner system, Ljungstrom airheater, flue gas and air ducting, we bring out our observations in the steam drum, deaerator, turbine and the water chemistry in this article.

Observations in steam turbine

The turbine showed signs of carryover of boiler water. The backup data on SWAS parameters were available only for 1 month. It did not show up deviations at any point of time. Earlier data was available only with one average data representing 24 hrs. Hence occasion of carryover could not be pin pointed.

Photo 1- HP stage turbine blades showing deposition of solids. This is due to carry over of solids along with boiler water. This photo is at inlet end.

Photo 2: This photo shows the deposits in the outlet end of HP stage. The deposits can be seen over the blades.

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Figure 1: The above is the guideline for tube sample removal for deposit estimation. High heat flux area, steaming point, change of direction, tubes with more bends are the criteria for selection.

Inspection of tube inside

Photo 13- furnace sloped tube sample inside is seen. There was no ongoing corrosion.

Photo 14: furnace sloped tubes at another location also confirmed that there is no on going corrosion.

Photo 15: Tube at burner level - ribbed tube was found to be free from corrosion. The pH of boiler water must have been OK during the past few days.

Photo 16: Another tube at burner level - ribbed tube was found to be free from corrosion. The pH of boiler water must have been OK during the past few days.

Photo 17: Observation inside by borescope inspection revealed that there is no ongoing corrosion

Photo 18: Another tube sample inside view by borescope inspection revealed that there is no ongoing corrosion

The inside tube inspection did not show any pH deviation prior to shutting the unit. However the ring

header inspection door was opened. Some floor tubes were cut and borescope inspection was done to ensure that there is no choking of orifices at the inlet stubs.

Photo 19- Small amount of dirt is seen at the orifice area in one of the sample. However choking is not seen around the orifice.

Photo 20: The ring header was seen with mild reddish tint. However this cannot be considered as pH corrosion.

Photo 21: The steam drum here shows the color of internal surface when the feed water / boiler water pH are maintained as per requirement, say 9.2 to 9.8 ( non copper system.

Photo 22: The steam drum here shows the improper pH maintained. The photo is taken immediately after opening the steam drum for inspection. This kind of appearance was not found at this plant

The SWAS panel parameters were reviewed by us. However detailed data in shorter intervals were not available for review. It was seen that there was large scale variation in feed water flow. The unit had a tube failure in LTSH area prior to shut down. High make up water requirement was there.

Photo 23: Screen shot showing the wide variations in feed water flow 3 days prior to shut down.

Photo 24: Boiler water conductivity rises after the boiler is shut. Boiler water pH rise informs that the HP dosing pump is not switched off in time.

When there is large variance in feed water flow, there can be disturbance in pH in feed water and boiler water. The ammonia requirement would have increased. If the dosing rate is not adjusted with due care, there can be shift in pH in feedwater chemistry.

UNDER DEPOSIT CORROSION FAILURES IN ANOTHER UNIT AT THE SAME PLANT

There had been an incident of condenser tube leakage in another unit in the same plant about 12 months back. There had been under deposit corrosion in the next 2 months leading to hydrogen cracks in sloped tubes at furnace bottom. Many tubes were changed and boiler was pressure flushed to get rid of loose deposits which were generated due to low pH situation during the condenser tube failure.

Nearly 12 months later there had been tube failures at burner level. There were two failures within a time gap of 15 days. Plant engineers were of the opinion that it is the after effect of the condenser tube failure which occurred 12 months back. This cannot be true as under deposit corrosion would occur in few days time.

One of the failed tube was sent to lab. Another failed tube sample was available at the plant. The photo of the tube inside can be seen below.

Photo 25- Tube showing under deposit corrosion crack.

Photo 26: Tube showing the deposits inside.

Photo 27- The boiler water pH meter was not functional for a long period ( more than 1 year. The reading was hunting between 4 & 10.37 almost every 2 seconds.

Photo 28: HP dosing system area showing signs of pumping problem / strainer choking incidents.

Under deposit corrosion occurs quite fast. The lowering of boiler water pH to 7.5 leads to dissolving

of the magnetite layer immediately. The boiler fire should be put off immediately and the unit should have been flushed out, as the boiler water is contaminated. Failure to do show will lead to development of sites wherein the under deposit corrosion begins. depending on the boiler water treatment regime, the tube failure can be due to hydrogen crack or due to caustic corrosion.

A deposit site created 12 months back, would not be failing now. We explained there is fresh deposit occurring. This can be due to pH deviation. If the deposits contain Iron and phosphate, it can be due to boiler water pH deviation. If it contains chlorides, it would be due to condenser tube leak. There were evidences that the boiler water pH may not be properly being maintained. There are two conductivity meters available at condenser. We recommended that it shall be provided with cation conductivity columns so that sea water ingress can be identified easily. Transport of corrosion product from pre boiler system can be identified by SDI test. We had used SDI test elsewhere to check ACC tube corrosion during start up.

CONCLUSION

Contamination of condensate can occur due to condenser tube leak. Boiler water contamination can occur due to pH deviation. Condensate contamination can be identified by cation conductivity monitors. As it is an important parameter, even 2 of 3 logic can be used. Cation conductivity of saturated steam would reveal foaming situations, caused by low boiler water pH. Low boiler water pH can occur not only due to condenser tube failure. It can be due improper HP / LP chemical dosing practice. Deviations in water chemistry can result in SH tube failures / Deposition of solids at the turbine blades / furnace tube failures. Trending of SWAS parameters need to have proper back up for analysis. It cannot be stored as averaged parameters. Fundamental of cation conductivity column Ammonia or amines that are intentionally present at ppm levels are

removed. This eliminates their high conductivity. The lower ppb concentrations and conductivity of contaminants can then be “seen” by the measurement.

Contaminant corrosive salts are converted to their respective acids which are typically three times as conductive as the original salt because of the highly conductive hydrogen ion.

This simplicity and detection sensitivity have made cation conductivity the most widely used measure of contamination in the power plant cycle. Refer ASTM D6504, standard Practice for on-line determination of cation conductivity in High Purity Water.

Engineers from our company, Venus energy audit system, conduct annual inspection of power boilers and process boilers. Boiler problems related to tube failures, efficiency issues, under capacity problems, vibration problems, perennial nagging design issues have been resolved by us. We attend to PF boilers, CFBC and AFBC boilers and grate fired boilers. Our sister concern Sri Devi Boiler Equipment and Spares meet the customer needs for spare pressure parts. Visit our web site for interesting technical articles - www.venus-boiler.com.

K.K.Parthiban