CBM-2010 Condition Monitoring Summit Join or Manage Your Profile Posting Boards Maintenance and Reliability Maintenance Connections (tm) Message Board steam turbine axial shift
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our steam turbine capacity is 250 mw. axial shift trip setting is + or - 0.8 mm. axial shift maintains -0.75 mm at full load. thrust bearing front temperature also rises sharply. why?
manikantan Manikantan M P |
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Is this a new turbine? Have you been trending axial shift? Axial shift increase indicates loss of babbit on thrust bearing. If it is an old turbine, seems, change of thrust pads is on the cards.
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Dear sir,
It is a new turbine. commissioned in the year 2002 december. During prolonged full load operation at 250MW axial shifts moves towards negative side and thrust bearing front temperature also rises. Manikantan M P |
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May be either the probes for thrust and surge pads have been interchanged. Or it is a calibration problem. By the way, what are the thrust and surge pads temp on full load? Regards Irshad |
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Dear sir,
please find attachement reagrding turbine. Manikantan M P Steam_Turbine_Axial_shift.doc (21 KB, 67 downloads) word |
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With the bearing configuration you have mentioned, I am unable to visualise the configuration of the turbine, i.e, how the different turbines are connected and how you have numbered the bearings? Pl. post one sketch showing relative positions of the turbine with bearings. Regards Akhtar |
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Dear Manikantan,
I used to work in KWU/SIEMENS type of steam turbine manufactured by BHEL as commissioning engineer. One word of advice before we start discussing. Never bypass the axial shift trip! Few questions: 1. Do you have one or multiple probes to measure axial shift? 2. Do you have electric trip alone? Or, do you have mechanical trip also? 3. Do you have Automatic Turbine Tester (ATT)? If you have, did you test the axial shift protection on line? 4. Regardless of the absolute value, does your delta in axial shift reading (at barring gear and at rated speed/load) is same? For example, in 200/210/250/500 MW turbines we used to see a delta of -0.2 mm 5. To me, your bearing temperature seems to be OK. BTW, what is your bearing temperature alarm value? Trip value? 6. Do you have thrust bearing babbit pitting problem? 7. If possible send your last calibration reading for the pickup. Do you calibrate using dial gauges/slip gauges? Regards. |
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Turbine
Live steam parameter - 175 bar/536 ºC/710 t/h Cold reheat to boiler - 36 bar /310 ºC Hot reheat from boiler - 34.5 bar/536 ºC Condenser vacuum at 250 mw - 0.130 bar abs TG bearing 1 - near HP turbine exhaust TG bearing 2 - combiner journal & thrust bearing TG bearing 3 - LP turbine exhaust TG bearing 4 - generator rear TG bearing 5 - excitation rear Axial shift trip value - ± 0.8 mm Extraction HP heater 6 - cold reheat HP heater 5 - IP turbine Deaerator - IP turbine LP heater 3 - IP turbine LP heater 2 - LP turbine LP heater 1 - LP turbine Present bearing temperature TG bearing 1 - 72 ºC TG bearing 2 - 88 ºC TG bearing 3 - 82 ºC TG bearing 4 - 79 ºC TG bearing 5 - 65 ºC 1. It is a 250 MW turbine commissioned in the year 2002 december. Now axial shift is maintaining at – 0.73 mm.[average value] 2. Axial shift is measured by three probes 3. Each showing -0.70/-0.75/-0.73 mm 4. Bearing 1 temperature has rised by 3 ºC 5. Bearing 2 temperature has rised by 2 ºC 6. Thrust bearing front temperature maintains at 86 ºC 7. Two thrust bearing front & rear temperature are available. a. Thrust front - 86/75 ºC b. Thrust rear - 65/65 ºC My question: Why axial shift is maintaining at 0.73 mm? 1. Do you have one or multiple probes to measure axial shift? Three probes are available for measuring axial shift 2. Do you have electric trip alone? Or, do you have mechanical trip also? Only electronic trip 3. Do you have Automatic Turbine Tester (ATT)? If you have, did you test the axial shift protection on line? We are not having axial shift trip testing online. 4. Regardless of the absolute value, does your delta in axial shift reading (at barring gear and at rated speed/load) is same? For example, in 200/210/250/500 MW turbines we used to see a delta of -0.2 mm There is variation in axial shift delta. 5. To me, your bearing temperature seems to be OK. BTW, what is your bearing temperature alarm value? Trip value? Alarm value:110ºC Trip value:120ºC 6. Do you have thrust bearing babbit pitting problem? We have inspected thrust bearing once. But I am not sure of babbit pitting problem. 7. If possible send your last calibration reading for the pickup. Do you calibrate using dial gauges/slip gauges? I will try to collect this datas. Manikantan M P |
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Dear Manikantan,
I had a quick glance at your reply. 1 & 2. You have 3-channels and all readings are very close. However, measurement error cannot be overruled yet. Did you have channel failures? Did you ask for 3-channel design or was it OEM decision? I worked on two projects with 3-tier arrangements and personally know it is hard to calibrate - bad design really! I like the 1-probe design with mechanical trip (no electrical trip, only high/very high alarm). 3. It is surprising that you do not have ATT for ETP! 4. Give me the 'value' please! This is the most important question of all. Also indicate your convention: whether + readings are towards the thrust rear. My experience: In one site, we were running Unit-1 close to the trip value for more than one year. Unit never tripped on thrust protection (1-Ch design). During each trip, the absolute value was getting shifted permanently to +ve side by a random amount, but the delta between barring gear & rated speed remained same (-0.2 mm). Our convention for AS: + is towards Generator. We used to confirm the electronic sensor accuracy many times by opening the inspection covers; this was a tough job. Funny thing was that opposite side pad temperature was the highest. It took about two years to solve the mechanical problem – electrical pitting & looseness (not on thrust pads). 5. Your bearing temperature trip values are matching with ours. The raising trend you were mentioning is small and is not a problem now. As long as you do not bypass the electrical thrust protection (ETP), things are OK. I know one Japanese m/c tripped on ETP in one site and because it tripped, m/c was brought back in about two months. Otherwise it might have taken an year or so! 6 & 7 Waiting for your reply ------------------------------------------------------------------------------------------- Why axial shift is maintaining at -0.73 mm? ------------------------------------------------------------------------------------------- I cannot answer this unless I get an answer for Q4, Q7 and the following questions: 8. What is the designed operating value for your machine? If you do not have this information, it will be better to compare similar units in your/nearby site. 9. What is the data recorded for AS & Thrust pad temperatures during 1st startup/commissioning? Please give me the barring gear, FSNL (rated speed) and full load values. If I remember correctly for 200/210/250/500 MW BHEL sets, the design values used to be -0.15 to -0.2 mm and the sets where I worked used to operate at these values. I must caution you, BHEL sets were of separate IP and 2-flow LP design. Have some operational records at my hometown, I can check when I visit India next time! BTW, who supplied your set? Regarding the vacuum problem, possible troubleshooting hints are: - Condenser fouling or circulating water system performance. One way is to watch the trend on condensor DP & DT (differential pressure and differential temperature) - HPT Blade deposit (can be ruled out in new m/c like yours). Watch the trend of HP 1st stage pressure for same load when extractions are normal (no feed water heaters out of service) - vacuum system problem. Do you have ejectors or vacuum pumps? Usually the local air flow indicator which can be taken into service momentarily can give a starting clue. Regards. This message has been edited. Last edited by: ganesh, v.j, |
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I looked at commissioning records of 664 MW steam turbine (Mitsubishi/Westinghouse, 2-flow HP, 2-flow IP, 2-flow double LP design) here.
The values in mm are: Unit No. BG 3600 rpm 30% Load 5 -0.07 +0.12 7 0.03 0.21 0.23 6 -0.25 -0.05 -0.03 As you can see the delta between BG and FSNL is about 0.18 to 0.20. Probably zero setting for Unit-6 was incorrect, but still the delta was 0.20 mm. This is one of the reasons why I was aksing delta readings. Regards. This message has been edited. Last edited by: ganesh, v.j, |
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Dear sir,
i am collecting datas. after collecting datas i will contact u. thank you
Manikantan M P |
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Dear sir,
Please find the excel file for turbine and bearing position regards
Manikantan M P turbine.xls (20 KB, 26 downloads) excel |
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Dear sir,
please find the word document regards
Manikantan M P turbine1.doc (35 KB, 17 downloads) turbine |
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Dear Manikantan,
Your delta readings between BG (Barring Gear) and FSNL (Full Speed No Load) is -0.06, -0.10, -0.08 mm respectively, with an average of -0.08 mm. That is quite normal. But it is a different story with loading the set. At 250 MW load, the delta is -0.59, -0.65, -0.62 mm. It is not normal as compared with other designs. M/S Alstom sets are new to me. When AS is reaching -0.73 mm? During transients? If you cannot send design values, send the commissioning protocol readings. Check whether your load sharing between HP and IP/LP is OK. For some designs (KWU/Mitsubishi) IPCVs (IP Control Valves) are fully open after about 35% load. Check your current readings of IPCV & HPCV openings for a particular load with commissioning protocal readings to see whether any major difference has cropped up in relative readings of HPCV/IPCV (EHC characteristics). Also noticed that you are running on low frequencies (less than even 49 HZ)! Prolonged low frequency operation (there is a low frequency operation totalizer/counters in some sets) is prohibited in most sets as it is harmful for the last stages of LPT rotor. Some manufacturers say you should not exceed 2 hours (CUMULATIVE) of low frequency operation below, say, 48.8 HZ, during the entire life of LP Rotor Regards. This message has been edited. Last edited by: ganesh, v.j, |
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Dear Sir,
Low frequency: In India presently freequency is low due to high demand. specially Southern grid is facing problem. here daily 8 hours of load shedding is done by electricity boards. axial shift moves towards neagative side during prolonged full load operation. [250 MW]. Average axial shift moves to -0.73 mm during prlonged full load operation. we dont why this is happening.. does axial shift has any direct relation with turbine expansion? [Diff expansion/Total expansion] for us total expansion varies with prolonged full load operation.. Regards MP Manikantan
Manikantan M P |
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Dear Manikantan,
I am very familiar with Indian grid scenario. Look into your OEM manual for Turbine: there will be a finite limit to prolonged low frequency operation (unless you have got a LP rotor specifically designed for low frequency operation)! The on-line vibration indicators may or may not even reveal problem. Inspection of last 2 or 3 stage blades during overhaul will reveal it. Did you carry out LP overhaul? Axial shift can be simply visualized as a rotor movement due to difference in thrust created by steam flowing through HP and combined IP/LP (in your case). The movement is kept very less (0.15 mm to 0.2 mm) by design. It is measured where the thermal expansion of rotor is zero, i.e., at rotor 'anchor' point. Hence, axial shift is not affected by thermal expansions of casing/rotor. Reading may be affected by lub oil/housing temperatures, but this error will be noticed only during cold startups. If you have specific problems like restrained casing expansions (or restricted shperical seating of bearings), then axial shift can get affected. I have heard of axial shift momentarily going high during rolling (in units with combined HP/IP but separate LP) but it comes down after rolling. I have not come across much change in AS readings with loading. The delta remains more or less same at FSNL, low loads or at full-load. But in your case, did it change with load during first commissioning? If so, by how much? You need to look into protocol readings/commissioning records. I asked you to look into current load sharing (i.e., HPCV/IPCV openings) because it will give a rough idea of any change in thrust forces. Prolonged full-load operations (250 MW) should not result in any change in total expansion. Total expansion (casing expansion) is a function of temperature and not load! I think you have a mechanical problem. Check whether this problem vanishes during normal frequency (i.e., whether the problem is due to prolonged high load or low-frequency) operation. This message has been edited. Last edited by: ganesh, v.j, |
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Dear Manikantan,
Following information can be of interest to you. ‘Abnormal Operation’ section of an OEM Instruction Book for Steam Turbines operating at 60 HZ frequency states that: ‘Off-frequency operation: Operation at low frequency is to be avoided, due to the possible occurrence of blade resonance. However, there is generally little likelihood of developing excessive vibratory stress at frequency down to 58-1/2 cycles. Should frequency drop below 58-1/2 cycles, vibratory stresses are more likely to increase to a point when fatigue cracks could be generated. Therefore unit is interlocked to trip at less than 58-1/2 cycle frequency’ Regards. |
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Dear sir,
I have read your message. I have learnt about steam turbine. I wish to know your email Id for future correspondance. my email ID : manikantanparam@yahoo.co.in Thank you Regards MP Manikantan Manikantan M P |
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Dear Mr Manikanthan,
pl see the file attached . PN Pavankumar,NTPC axial-shift-mforum-1.doc (32 KB, 8 downloads) |
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