Important Feed back for KN series Steam Turbines of BHEL.

As per Report of BHEL the KN series Steam Turbines were introduced in 1997. As per the Report there were lot of problems initially and combined HP IP modules called K Turbine were sent back to works and LP Turbine called N turbine were also rectified at site. Thus the KN series.

Recently the combined HP IP module had to be reopened after overhauling due to suspected leakage from Balancing Leak off pipe.

By the way there is a Balance Drum on HP Rotor rear side and a steam pipe called balancing leak of is connected between IP 6th stage and the Balance Drum. There is a sliding joint in the pipe to take care of expansion of inner casing.

The space between inner and outer casing of K Turbine is filled with IP Turbine exhaust steam which is at 302 degC.

Due to leakage in the sliding joint of balancing leak off pipe high temperature steam at 465 degC (full load parameter) was heating the space between inner and outer casing during the cold start causing high HP Top, Bottom and Flange Temperatures, high expansion of HP Outer casing and Rotor expansions. The Top Bottom temperature differential was also high (37 degC).

This is an important feed back for these machines. In case the extraction steam temperature to Deaerator (which should be equal or 1 degC lower than IP Turbine exhaust temperature) is higher than IP Turbine exhaust it indicates leakage in these joints and should be attended by opening the K Turbine.

There are two pipes in lower half of the inner casing and the same has to be removed to attend the leakage.

 

Pump assisted Siphon in CW System of Turbine.

To understand the content of this post please read Wikipedia Page on Siphon.

Once through CW systems are relatively unknown in Thermal Power Plants being constructed today but there are many old ones. Let us look at following image on Wikipedia page.

From Wikipedia

B can be the top point of Condenser Water Box and C the end of the outlet pipe.

The Siphon works on the basis of height difference hc. In CW System hc may be zero but the CW Pump Head equal to hc will simulate it.

In case of Siphon both inlet and outlet pipes are under vacuum. In CW System the outlet pipe will be under vacuum but inlet pipe may be under positive pressure or slight vacuum at Condenser inlet.

Since the Cooling Water picks up heat in the Water Box the pressure in Water Box should be higher than Vapour Pressure of Water at Outlet Temperature with some margin.

During Start up Vacuum is created by Condenser Water Box Priming Ejector or Vacuum Pump.

The Priming Ejector/Vacuum Pump needs to be run periodically to remove liberated dissolved gases from Cooling Water from Condenser Water Box.

Recently I visited one Thermal Power Station where I had to tell them the importance of running Water Box Priming Ejector periodically.

Beware! Steam Turbine Deposits of 1929 to 1936 have surfaced once again.

At one IPP in India H. P. Heater Safety Valve blew when the machine suddenly touched 103.6% of rated load. Maintenance Engineer thought that the original Safety Valve setting could have been disturbed but on checking the data in DCS it was found that the extraction pressure had actually reached the set value of Safety Valve to blow.

Now this is not a simple matter. The set pressures of Heater Safety Valves are such that the Turbine could never provide steam at that pressure i.e. the set pressure is higher than the extraction pressure under Turbine VWO (Valve Wide Open) condition. The blowing of the Safety Valve indicates restriction in the Turbine Casings.

On further analysis the Turbine First Stage Pressure was also found very high and higher than the value recorded during VWO test on Turbine. In spite of more than 6% capacity over TMCR under VWO condition established during Performance Guarantee Test the load had to be restricted at 98% of TMCR due to high First Stage Pressure. Analysis of all extraction pressures revealed restriction limited to High Pressure Turbine.

Restrictions may be caused by the deposits on Turbine Blading but Power Station Boiler Water Chemistry is very advanced since 1960's and deposits in high pressure zones are unknown.

I had to dig out a paper published in May 1936 by University of Illinois
Engineering Experiment Station. It was possible to get this paper because University of Illinois had undertaken Large-scale Digitization Project in 2007 at at Urbana-Champaign Library.


The title of the paper is The Cause and Prevention of Steam Turbine Blade Deposits and download link is here.


Prior to 1936 the Power Station Water Chemistry was evolving in USA. In fact the author of the paper was Special Research Assistant Professor of Chemical Engineering at University of Illinois.


I am taking liberty to quote from this paper:

"Purpose of Investigation.-Steam electrical generating stations

have encountered difficulty in the form of fouling of turbine blades.

This difficulty has become of major importance in many large stations,

whereas it has only meant annoyance in other stations.

There are several types of deposits which form on the turbine

blading and cause this fouling. One type is that which is apparently

caused by a deposition of solids carried in the steam from the boiler

water, and another is that caused by a chemical reaction between

chemicals in the steam and the material in the turbine blades. The

first type is the most common, and is readily distinguished from the

other in that it is largely soluble in water, and is washed off with comparative ease, whereas the other type of deposit adheres to the blades very tenaciously.

The deposition of solids carried in the steam appears to be the

major cause of difficulty. The efforts of this research have been directed entirely toward a study of this type of deposit, and no study

has been made of the other type.

The purpose of the present investigation has been to assemble

data relative to the occurrence of this type of deposit on steam turbine

blades in order to determine the cause of the difficulty and to devise

methods of preventing it."

Resume of Central Station Experience.-The following extract
from a letter serves to illustrate very clearly the difficulty caused by
this kind of turbine blade fouling.
"The operating records show the machines can only be kept in service for a matter of 3 to 4 weeks before the effective output of the machine drops about 20 per cent. The deposit is easily removed by washing, but of course this necessitates shutting down and leaving machine cool off, with a subsequent loss in the overall station efficiency as well as temporary reduction in the plant availability. The washing process adopted does not involve anything more than allowing the machine to cool down for 36 hours, and then starting up in the normal way, the condensation produced being sufficient to clear the fouling."

Although Power Station Water Chemistry is very advanced in India there is a reason to believe that Boiler Feed Water got contaminated with Cooling Water at this IPP and the conditions similar to pre 1936 in USA got created inadvertently.

Moreover when the unit was down for Annual Overhauling for more than 30 days the restriction due to high First Stage Pressure had vanished after Overhauling and there is no need to get surprised if you read the bold sentences in the above quotation from the research paper.

This post is to caution the new IPPs coming up in our country.

Comparison of Condenser Vacuum in Cooling Tower versus once through Cooling Water System.

I am going to mostly write about condensing, reheat turbines with regenerative cycle. Condenser Vacuum is the vital parameter of such machine and let us talk about what is achievable today compared to old power stations.

Once again my memory takes me to Obra. On local panel we use to have a mercury tube indicating as much as 712 mmHg vacuum in December/January. In summer it use to be around 690 mmHg.

Our competitor was Badarpur where it hardly touched 690 mmHg in winter.

I asked the Engineering Department in BHEL Haridwar and they told me that Badarpur Station had Cooling Tower whereas Obra was having once through Cooling Water System and our Cooling Water temperature was very low compared to what the Cooling Tower would give.

After joining Operation Services Department at NTPC Corporate Centre in 1983 and studying the Acceptance Test Codes of Steam Turbine as well as Cooling Tower I realised the real difference.

The temperature of Cooling Water in once through system can be as low as the Wet Bulb Temperature but the Cooling Tower has to be infinitely large to equal that temperature. We had Induced Draft Cooling Towers designed to deliver 33 degC temperature at 27 degC Wet Bulb Temperature. The difference in the two temperature is called approach. The approach was 6 degC at design point but it was increasing as much as 12 degC at 15 degC wet bulb temperatures.

Without the technical jargon it meant that the max temperature in once through system was 27 degC and in Cooling Tower it was 33 degC. In winter the once through system could be lower than 12 degC but in Cooling Tower it hardly went below 25 degC.

The flagship station of NTPC is Singrauli Super Thermal Power Station (SSTPS) and it has once through Cooling Water system. In modern times there is hardly any station with once through system, therefore, it is my advice that you don't compare the Condenser Vacuum of your station with SSTPS unless you have similar Cooling Water System.

At Jharsuguda we have Natural Draft Cooling Towers. This tower is also built to deliver 33 degC at design point but its performance depends upon both the Dry Bulb and Wet Bulb temperatures. The reason being variation in air flow which is constant in Induced Draft Cooling Towers unless you touch the fan.

In worst weather i.e. both Dry and Wet Bulb Temperatures on higher side the Natural Draft Cooling Tower delivers higher temperature compared to Induced Draft Cooling Tower but in Winter it delivers lower temperature due to increased air flow.

But the most important aspect of Cooling Tower System is fouling in Condenser Tubes unless you religiously maintain residual Chlorine.

As Turbine Maintenance In-charge at NTPC Vindhyachal Super Thermal Power Station (VSTPS) Stage 1 (6x210 MW) I could not maintain the Chlorination because it was 2 Km long underground pipe failing frequently.

This resulted into slime formation in Condenser Tubes which initiates fouling. I introduced tube cleaning with High Pressure Jet Pumps and got very good Condenser Vacuum but it used to deteriorate within three months in the absence of residual chlorine.

At Jharsuguda we have Sodium Hypo-chloride dozing system which is also having underground piping but thanks to the Chemistry Department which maintains residual chlorine by manual dozing if there are leakages in underground pipes.

Update on 27th May 2013
Since I had seen very good Vacuum at Obra and Singrauli I was under the impression that once through Cooling Water Systems provide better Vacuum but after visiting Tuticorin the belief is broken.

I was expecting better measured value of Condenser Vacuum at Tuticorin because at seashore the atmospheric pressure is maximum. What you see in the gauge or indication in Control Room is the difference between the Turbine Back Pressure and atmospheric pressure. Other things being equal i.e. for same absolute back pressure (say 0.09 ata) what you read at Singrauli (for atmospheric pressure of 1.0126 ata) will be -0.9226 Kg/cm2 and at Tuticorin (for atmospheric pressure of 1.033 ata) it should be -0.943 Kg/cm2.

Although I found my familiar mercury in glass Vacuum Gauge at Tuticorin and expected better than 690 mmHg, it was disappointing to see 660 mmHg.

On analysis I found CW Pump assisted Siphon formation in Condensers Water Box and the practice of not running Water Box Priming Ejector periodically to remove liberated dissolved gases.

Zero of Axial Shift Indicator.

What I learnt in the year 1977 while boxing up bearings of India's first 200 MW unit at Obra (Unit 11) was as follows:

You move the rotor towards the Generator side and the thrust pads which get tightened are called working pads. If the Millwright Fitter had no brains and scrapped the parting plane of the bearing and made it non perpendicular to vertical plane against which the pads are pressed the two halves of the pads will be in different planes, therefore, you must ensure that bottom half as well as top half pads get tightened.How? Measure the axial float with bottom half pads, press the rotor against working pads, put a dial indicator to fix the axial position of the rotor to zero, assemble the top half pads, measure the axial float again, press the rotor against the working pads and see whether you get the zero in the dial indicator and nearly the same axial float.

The activities in the previous paragraph are supposed to be done before the box up of the turbine casings because the reference point of steam flow path is  when the rotor is pressed against working pads. Since I was not present before box up I re-checked to confirm and to give clearance for final checking and calibration of Axial Shift Indicator which should also indicate zero with rotor pressed against working pads.

My curiosity was what position the rotor takes while the machine is on load. The unit was synchronized on 31st December 1977 and it was fulfilled. The rotor gets pressed towards the working pads and the axial shift indicator indicates negative value corresponding to the thickness of the oil film which also varies. What happens when the unit trips? The rotor moves towards the non working pads (also called surge pads) and indicates higher negative value. While rotating on Turning Gear (also called Barring Gear) sometimes it almost touches the surge pads and indicates a negative value equal to the axial float in the bearing and this is the acid test of the erection work.

My next curiosity was whether the Turbine trips on axial shift. The answer was it may never trip in 30 years life. Then why the axial shift indicator? To indicate:

• wear of thrust pads if it indicates zero or positive value and
• axial float in thrust bearing sometimes when on Turning Gear.

After many years I am associated with 600 MW Steam Turbines at Jharsuguda and the same holds good but people who have come from various power stations have doubts.

One person confidently says that my knowledge is obsolete and the steam flow path is adjusted with the rotor kept in the middle of the axial float and the axial shift indicator is set to zero at this position of the rotor. When I ask that person which way the rotor goes when the unit is on load he has no answer. He thinks it is the job of operation to see that. When I tell him that the axial shift indicator is not an important parameter for operation because the Turbine is not going to trip on axial shift for its entire lifetime he says then how does it matter what way he sets the zero.

It matters because if you set the steam flow path and the axial shift indicator zero in the middle of the float the Turbine will come on working pads on load and not operate at the intended position corresponding to steam flow path. In addition the axial shift indicator will not serve the purpose of indicating the wear of working pads accurately.

My only advice to such people is to observe what the axial shift indicates while the machine is on load and on Turning Gear and speak accordingly.