Friday, June 6, 2014

Why most people think that -0.9 Kg/cm2 gauge is the correct value of Condenser Vacuum?

Most Steam Turbines in India are designed considering Cooling Water Inlet Temperature of 33 degC and temperature rise of 9 degC through the Condenser.

Assuming Terminal Temperature Difference (TTD) of 4 degC the saturation temperature at Turbine exhaust works out as follows
CW Inlet Temperature + Temperature rise through Condenser + TTD
=33+9+4 = 46 degC

Turbine Back Pressure corresponding to 46 degC is 0.101 Bar and 0.103 Kg/cm2

Most Thermal Power Stations are located at Mean Sea Level (MSL) between 200 to 250 Metres and the Barometric Pressure corresponding to these elevations are 1.003 Kg/cm2 and 1.009 Kg/cm2.

If you subtract 1.003 from 0.103 you get -0.9 Kg/cm2.

That is why most people think that -0.9 Kg/cm2 gauge is the correct value of Condenser Vacuum.

There is one more problem. The above are the design parameters for NTPC's flagship Thermal Power Station at Singrauli even when it has once through Cooling Water System where the Cooling Water Temperature hardly touches 27 degC. Therefore the actual Condenser Vacuum used to be much better than -0.9 Kg/cm2 not because of any achievement by the flagship station but because of once through Cooling Water System.

People not only think that -0.9 Kg/cm2 is the correct Condenser Vacuum they also think that they need to add 1 Kg/cm2 to get the absolute value of Back Pressure i.e. -0.9 + 1 = 0.1 ata  assuming Barometric Pressure as 1 Kg/cm2.

Today I am dealing with one person at 2x500 MW Durgapur Steel Thermal Power Station at DVC who is getting 0.1077 ata by adding 1 Kg/cm2 and thinks that it is correct and apparently there is no vaccum problem although the LP Turbine exhaust and Hotwell Temperatures are indicating 50 to 51 degC.

The Mean Sea Level at the Power Station is 73 Metres and the Barometric Pressure corresponding to it is 1.024 Kg/cm2.

Therefore the correct Turbine Back Pressure would be
= 0.1077-1.0+1.024 = 0.1317 ata which is very poor vacuum.

When I am delivering lectures on Turbine Efficiency my first lesson is to show the variation of Barometric Pressure with altitude of the place.

There is another interesting incidence of JSW Energy at Vijaynagar (Torangallu).

The Mean Sea Level at Torangallu is 520 M and the Barometric Pressure corresponding to it is 95.22 Kpa. The design back pressure is 10.05 Kpa but the station people are using 100 Kpa as Barometric Pressure and saying that design value of Condenser Vacuum is 10.05-100 = -89.95 Kpa.

In fact they were not believing what I was teaching till I pointed out to them that the Barometric Pressure recorded in the PG Test Report was 95.193 Kpa so close to the value I told.

One should say that the design value of Turbine Back Pressure is 10.05 Kpa and if you convert it to Condenser Vacuum it will be -85.17 Kpa valid only for Torangallu and not for Ratnagiri the other Power Station of JSW Energy where the Barometric Pressure is 100.7 Kpa and the Condenser Vacuum should be -90.65 Kpa (Notice the difference of 5.48 Kpa).

Update on 14th July 2014
Although the Condenser Vacuum should be generally -83 to -87 kPa at Torangallu it was actually in the range of -87 to -91 kPa.

Today I checked in the DCS Engineering Room and found that DCS was adding -4 kPa to what was coming from the transmitter as follows:

The transmitter has the range 0 to -100 kPa for 0 to 4 ma but the DCS was converting 0 to 4 ma into -4 to -104 kPa thereby adding  -4 kPa.

When I asked whether Chinese advised to add -4 kPa the Engineer replied that BHEL had set it like this in 130 MW Unit and same was adopted in 300 MW Units for uniformity.

So that is one example of how BHEL cheats. Off course I can write many articles about how BHEL cheats in various ways.

Instead of teaching that the Vacuum indication will be different considering the Barometric Pressure of Torangallu they have simply made the DCS to add -0.04 Kg/cm2 (BHEL still uses MKS units) to the value coming from the transmitter.

Thursday, May 22, 2014

Primary Flow Measurement for modelling of Thermal Power Stations using EBSILON Professional Software.

I am involved in implementation of Phase II - Output 2 of Indo German Energy Program (IGEN) where we have to introduce Model Power Plant Concept in identified Thermal Power Generating Units. In this phase of the program we have to demonstrate the improvements in Energy Efficiency in these Units.

During IGEN Phase II - Output 1 the licenses for EBSILON Professional Software were provided to the State Utilities and Training was also provided to use the software for identification of areas and components having major Heat Rate deviations.

The Steam Flow entering the Steam Turbine is most important input for modelling the plant using the software and since there was direct measurement available the same was used during the initial phase.

Since I was associated with Performance Guarantee Tests of similar Units in India I knew that the direct measurement of Main Steam Flow was not accurate and this flow used to be much higher than the computed Main Steam Flow during the tests. The other option was to use Feed Water Flow but I also knew that this flow also used to be always higher than the computed Feed Water Flow during the tests.

During Performance Guarantee Tests we were using special Flow Nozzle confirming to ASME PTC-6 installed to measure the Condensate Flow entering the Deaerator. The Feed Water Flow was then computed by calculating the extraction flows to High Pressure Heaters and Deaerator and adding them to Condensate Flow also considering the change in Deaerator level. This Nozzle was removed after Performance Gurantee Tests and used in other Units of the Station.

In May 2014, I went to Mettur Thermal Power Station to assist the Station for modelling of Unit no 1 which was selected for IGEN Phase II -Output 2.

Fortunately, the Condensate Flow to Deaerator measurement was available in this Unit. When we considered the data for modelling we were not getting sufficient output from the Turbine since the measured Condensate Flow was 5% lower than the expected flow. After checking we found that the Station had done modification in the Spray line to PRDS and Condensate Flow at CEP discharge was being used as spray. We considered this in the model but the spray flow was coming only 2.4 T/hr (0.5% of Condensate Flow).

Reluctantly I agreed to use Feed Water Flow for the Modelling but with a rider that we shall reduce the measured Feed Water Flow by 1.5% (based on my experience of Performance Guarantee Tests of similar units) for accurate modelling.

PCRA team was doing Energy Audit in the Station at the same time and we asked them to measure the spray flow to PRDS by using portable Ultrasonic Device and it was found as 2 T/hr i.e. nearly same as predicted by the model.

I was not happy with the measured Condensate Flow and insisted on measurement of Differential Pressure. When the Differential Pressure was measured the calculated flow from its reading was 5% higher than indicated reading in the DCS. The C&I Maintenance Engineer corrected it.

Thus we could do accurate modelling of the Unit by using Condensate Flow to Deaerator at Unit 1 of Mettur Thermal Power Station. The computed Feed Water Flow was lower by 1.5% compared to measured Feed Water Flow confirming my previous experience.

Friday, August 30, 2013

Comments on Press Reports comparing Chinese Power equipment with BHEL supplied equipment.

I have started my career as Engineer Trainee in BHEL Haridwar in 1973. I was Erection Engineer and erected 4 out of 5 Turbines of 200 MW at Obra from 1977 to 1982.

Later on I joined NTPC Corporate Office and was involved in Performance Guarantee Tests of Steam Turbines of 200 MW of Singrauli, Korba and Ramagundam. We use to discuss the gap between the Design Heat Rate and actual Station Heat Rate extensively. Being pioneer in India in acceptance testing of Steam Turbines I claim a proficiency and expertise in this area which very few people could match.

I was transferred to Vindhyachal STPS in 1987 and worked in O&M of 6x210 MW Units. In these units I discovered the importance of CW Chlorination in maintaining good Condenser Vacuum which is primarily responsible for Turbine Heat Rate.

I left NTPC in 1996 and worked in DLF Industries, ALSTOM and NASL.

I joined Steag after the company was entrusted with O&M of 4x600 MW IPP at Jharsuguda. I was entrusted with Turbine Maintenance but was also associated with Performance Guarantee Tests of Steam Turbines due to past experience.

My experience at Jharsuguda tells me that Dongfang Steam Turbines are no way inferior to BHEL Steam Turbines and I am shocked to read the following news reports:

I am quoting below from these reports and responding:
The Financial Express: The CEA report found that the operating heat rate of Chinese power equipment works out to 2,719 kcal/kWh compared to 2,520 kcal/kWh for Bhel gear.
The load factor of Chinese equipment averaged 57.2% during the study while it stood at 71.6% for Bhel gear.
Bhel equipment also outdid Chinese hardware on secondary fuel oil consumption. The fuel oil consumption of Chinese equipment was 6.13 ml/kWh while it was just 3.06 ml/kWh for Bhel gear.

The Operating Heat Rate mainly depends upon the Loading Factor. When the Loading Factors are different the comparison is unfair. The Loading Factor does not depend upon the machines but what Load Schedule you get from the grid. The Power Grids are under the control of Government Bodies and give less schedule to Private Companies who are operating the Chinese supplied power plants. Once again the Fuel Oil consumption parameter is based on units generated (kWh) which will be less and the specific fuel oil consumption is more.

As an expert in the field I can say that the report has been prepared just to blackmail the Chinese suppliers and please the Politicians who might be seeking such report.

I am waiting for the Report to be made public and examine it thoroughly.

Monday, August 12, 2013

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.


Wednesday, June 12, 2013

Effect of Atmospheric Pressure on measurement of Condenser Vacuum.

I have following measurements of Condenser Vacuum for 210 MW units in two locations:

Tuticorin TPS -662 mmHg CW Inlet 33.15 degC outlet 43.3 degC
Nasik TPS -658 mmHg CW Inlet 28.3 degC outlet 36.15 degC

It appears that there is not much difference between -662 and -658 mmHg in the two measurements the difference is actually much bigger considering that Tuticorin is located at sea level and Nasik at a height of 599 metres from MSL. The barometric pressures at these locations are as follows:

Tuticorin 760 mmHg
Nasik 712 mmHg

The absolute pressure for the measurement would be:
Tuticorin -662+760 = 98 mmHg = 130 mbar
Nasik -658+712 = 54 mmHg = 72 mbar

The mercury gauges are not found in the modern plant so let me convert the values to Kg/cm2 and Kpa for understanding by the new generation of engineers:

Tuticorin -662 mmHg = -0.8998 Kg/cm2 = -88.23 Kpa
Nasik -658 mmHg = -0.89436 Kg/cm2 = -87.7 Kpa

It appears that the difference is only 0.5 Kpa but the real difference when converted to absolute pressure would be 130 - 72 = 58 mbar = 5.8 Kpa

The best way to get the atmospheric pressure of your place is to use a Barometer. In case you don't have it you can know the atmospheric pressure approximately from the altitude of the place.
Altitude metres Atmospheric Pressure mbar
50 1007.27
100 1001.29
150 995.38
200 989.48
250 983.57
300 977.67
350 971.86
400 966.08
450 960.3
500 954.54
Source of the above data.

Please note that altitude of a place town/city also varies a lot e.g. if you read Wikipedia page about Nasik it gives the altitude as 560 m and it is true that the area around Godavari River is at 560 m but the Thermal Power Station is situated at 599 m. To get the correct altitude you should use the data of your power station or you can use Google Maps on this link.

Tuesday, May 14, 2013

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.

Wednesday, February 27, 2013

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.