GR Frame 9e Compressor Efficiency Become Little Less as Compare to Another Operational Units

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Deleted member 3303

WE HAVE GE FRMAE 9E 6 OPERATIONAL UNITS .

TWO UNITS OPERATION ON LIQUID FUEL OIL AND 4 UNITS ON GAS FUEL OIL.WE DID THREE MONTHS BEFORE HGPI OF BOTH LDO FUEL TURBINES.
THIS TIME WE REQUEST GE TO DO SOME MODIFICATION ON AIRINLET CMPRESSOR INLET INSTRUMENT LOCATION.

BEFORE ALL UNITS CTIM(COMPRESSOR INLET TEMPREATURE SENSOR) IS A RTD SENSOR signal rtd_ctif3r , NOW DURING HGPI , LDO RUNNING TURBINES WE CHANGE CTIM SENSOR AND USE THERMOCOUPLE AS A CTIM SENSING signal tc_ctif1 and tc_ctif2 .

NOW GT OPERATING ON GAS FUEL CTIM is sensing by RTD and have less temperatures 2 Celsius BUT LIQUID FUEL OPERATING TURBINES CTIM SENSING BY THERMOCOUPLE AND TEMPRETURE 6 CELCIUS.

LAST YEAR WHEN ALL GTS CTIM SENSING BY RTD , ALWAYS LDO OPERATING TURBINES HAVE MORE MW YOU CAN ALWAYS 2 MW ABOVE PRODUCTION.

AS LAST MODIFICATION NOW 2 MW LESS BOTH LDO OPERATING MACHINES.
 
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Deleted member 3303

you have a question why we do this? we do this in summer as you know we have evaporative cooler sytem at all gas turbine for cooling inlet air system , when we use this so another GTS WHISH WE USE RTD EVAPORATIVE COOLER ON AND OFF AS PER SET TEMPREATURE BUT BY THIS MODIFICATION OF THERMOCOUPLE WE HAVE CONTINOUSLY RUNNING EVAPORATIVE COOLER AND WE GET MORE PRODUCTION , DUE TO THERMOCOUPLE IS SENSING AND RTD SENSING DIFFERENCE.

THERMOCOUPLE TEAKES MORE TIME FOR CHANGE IN TEMPREATURES AS COMPARE TO RTD INSTANT SENSING CHANGES.
 
OH, AND NOW YOU TELL US THAT "...AS YOU KNOW WE USE RTD EVPORATIVE COOLERS ON AND OFF ...."

NOPE; NOT GONNA TOUCH THIS ONE. GET THE SUPPLIER TO HELP WITH THE PROBLEMS.

(CAPS DON'T HELP GET BETTER ANSWERS ANY FASTER.)
 
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Deleted member 3303

dear CSA already we did this modification , now winter , we got benefit in summer but in winter is different its little oposite , so what we can do now ?
 
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Deleted member 3303

MY QUESTION IS THAT IS COMPRESSOR INLET TEMPREATURE EFFECT FUEL INJECTIONS PARAMERTS MEANS VC3 , FUEL SUPPLYING?

CTIM EFFECTS FQLM1 ? ITS HAVE ANY EFFECTS ASI READ YOUR PREVIOUS POST CTIM IS A PART OF TTRF LOGIC BLOCK CALCULATION?
 
Amen, Curious_One. Out near Proxima Centauri.

It would be great to hear what GE says about this problem. But we'll never know. This is most likely one of those threads where the original poster is looking for confirmation of HIS theory of the problem, so the only information being shared is that which the original poster feels is relevant and supports HIS theory of the problem, hence the use of all capital letters for emphasis.

Omega is a great reference for temperature measurement applications!

"...as you know we have evaporative cooler system at all gas turbine for cooling inlet air system ..." Because ALL GE Frame 9E heavy duty gas turbines have evaporative coolers so it wasn't necessary to tell that in the original post. As I know CTIM is only used for biasing FSR during starting. But, as I don't know if the original poster's units have MBC (Model-Based Control) or ARES (Adaptive Real-time Engine Simulation)--which is very possible since it sounds like the owners have more dollars than sense--it's impossible to say any more. And I'm staying on Planet Earth in the Milky Way today.
 
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Deleted member 3303

Dear CSA , thanks for your comments and feedback , your all comments and feedbacks it’s really very meaningful and guidance for me .

I learn many things after reading your comments and feedbacks on different threads .

as above comments about signals and positions I shall tell you tonight .

I was in night shift and due to internet issue I unable to reply your feedbacks.

thanks again I shall update you tonight
 
Irfan ahmed qureshi,

I realize English is not your native language, so part of the issue with your posts in this thread is probably related to our misunderstanding. If you will take the time to answer the following questions, we may be able to help. BUT, I caution you NOT to make any assumptions about the cause(s) and effects of this drop in output until we have more information.

1) What turbine control system is used on each one of the six units?

2) Do any of the units have DLN combustion systems?

3) Where are the RTD inlet temperature sensors physically mounted?

4) Where are the thermocouple (T/C) inlet temperature sensors physically mounted?

5) Did GE add the new T/C inlet temperature sensors, or did they just substitute the signals from existing T/C inlet temperature sensors (in place of the RTD inlet temperature sensors) to start/stop the evaporative coolers?

6) Do you have any data from the same ambient conditions in summer prior to the change? If so, can you tell us--with the evap coolers running and the units AT BASE LOAD (not any other part load condition--but Base Load with the IGVs at maximum operating angle) what the following values were for at least ONE gas fuel-fired unit and at least ONE liquid fuel-fired unit:

SUMMER WINTER
FSR
CPD
Load (MW)
IGV Angle
FQG
FQLM1
TTRX
TTRXP
TTRXS
TTXM
CTIFR*
CTIM*

*
CTIFR and CTIM are typically the median values of the CTIFRn RTD values (from redundant RTDs) and CTIFn T/C values (from redundant T/Cs).

In my experience, RTDs were mounted on the turbine inlet air filter modules--usually UPSTREAM of the filters (before the filter), meaning they were sensing the temperature of the air being drawn into the filters. T/Cs were used on the upstream wall of the inlet plenum at the 9:00 o'clock and 3:00 o'clock positions and sensed the actual air temperature being drawn into the axial compressor bellmouth/inlet. The RTDs on the turbine air inlet filter modules were used to start/stop the evap coolers (or other inlet cooling system) because they were sensing actual ambient temperature UPSTREAM of the inlet cooling equipment. The T/Cs mounted on the inlet plenum wall directly across from the axial compressor bellmouth/inlet were NOT typically used for starting/stopping the inlet cooling system because they measured the temperature DOWNSTREAM (after) the inlet cooling system.

But WAIT--there are more questions!!!

7) When the HGPI was done, were any modifications done to the cooling and sealing air system--such as brush seals, for example?

8) When the HGPI was done, were any modifications done to the turbine firing temperature control curves?

9) MBC (Model-Base Control) and ARES (Adaptive Real-time Engine Simulation) are two options GE offers which, by using a lot of additional sensors and some proprietary algorithms, the turbine control system can monitor how the turbine is operating versus how a new and clean version of the turbine would operate. For example, it can help determine when is the best time to perform water-washing (on-line or off-line), or it can help with identifying axial compressor issues (loss of efficiency; IGV issues; etc.), or exhaust issues (high back-pressure; failing exhaust T/Cs; exhaust frame cooling issues (on some machines); etc.). It's VERY sophisticated stuff, and there is usually one HMI display which is dedicated to displaying SOME (but not ALL) of the sensor values used for the calculations/algorithm. So, if your units have either of these options, you should be able to find a related HMI display to answer the question: Do any of the units have MBC or ARES?

10) When was the last off-line water wash done on the machines (all of them)?

11) When was the last time the calibration of the CPD pressure transmitters verified (usually device numbers 96CD-1A, -1B & -1C)?

12) When was the last time the the calibration of the ambient pressure transmitters verified (usually device numbers 96AP-1, -2 and 3)?

13) When was the last time the turbine inlet air filters were changed (on each of the units)?

14) Do the gas turbines exhaust into HRSGs (Heat Recovery Steam Generators) or just to atmosphere? And, do the units have bypass stacks to allow direct exhaust to atmosphere, bypassing an HRSG?

15) Have the fuel supplies changed in the last year--meaning is the gas fuel coming from a different source/field, and/or is the liquid fuel coming from a different supplier/source?

16) What does GE say about the drop in output? THIS IS THE MOST IMPORTANT QUESTION AT THIS TIME.

17) What alarms (Process and Diagnostic) are annunciated when the units are not making as much power as you believe they should be making? List ALL alarms--not just the ones someone deems relevant. I know that getting Diagnostic Alarm information is difficult for some people (they were never taught how to do it; they never tried to learn how to do it; and, there's that tribal knowledge thing that says, "Diagnostic Alarms won't trip turbines, so they can be ignored." (Which is sort of true--a single Diagnostic Alarm won't result in a turbine trip--but there are combinations of Diagnostic Alarms that WILL result in a turbine trip--so it's best to keep the Diagnostic Alarms to a minimum by troubleshooting and resolving them quickly when they are annunciated. And, no; there is no table or list of which combinations of Diagnostic Alarms will result in a turbine trip--there are literally hundreds, and into the low thousands, of Diagnostic Alarms--it's not possible to create any kind of list that can be used at every site to consult to understand which combinations of all the possible Diagnostic Alarms will result in a turbine trip.)

GE will do just about anything for money these days--they need it. While they weren't so quick to do some Customer-requested modifications, they seem to be much more agreeable these days. And, if they see a chance to make even more money to come back and troubleshoot any knock-on problems and fix them, well, for them it's a winning situation. AND, if you're dealing with the GE engineering group in Belfort, France, well they ... they ... will do anything that GE USA wouldn't do--just because GE Belfort believe they have a better way and a better understanding of the machines and they can engineer their way out of anything (and into a lot of messes, too--many that the Customer paid them to engineer their way out of). I will say this about GE Belfort--in general, but not all the time, they seem to be much more communicative than GE USA. That doesn't mean they are correct or more knowledgeable, they just seem to allow their engineers to communicate more directly with Customers. Sometimes that's good; sometimes that's bad.

So, answer ALL of the questions above as best as you can--not just the ones you or someone at the site deem relevant. What you are attempting to ascribe to a change in inlet temperature sensor types is very unlikely--unless there's some other strange evap cooler sequencing and MBC/ARES stuff we don't know about. (And, if the units were engineered by GE Belfort, it's definitely possible that there is some unusual application code (sequencing) we don't know about. That's they way they roll.)

Take your time, answer ALL the questions--especially Number 17 and Number 18. If you need help in determining what Diagnostic Alarms are active, let us know (and tell us which Mark* is being used to control the turbines--all of them). And, maybe, if you will keep an open mind and answer the questions asked we can be of help. No promises; we need good information to be of help. And, the answers to the above questions are a very good start.

Lastly, every GE-design Frame 9E heavy duty gas turbine IS NOT like every other GE-design Frame 9E heavy duty gas turbine. Yes, they all suck and squeeze and burn and blow. But they do it with a wide variety of different combustion systems, fuel nozzles, hot gas path parts, and fuels and systems. Most of the system function similarly (until GE Belfort gets involved), but we can't know what's at your site on your turbines--without your input and information.

Help us to help you!
 
One more thing, Irfan ahmed qureshi,

The Subject of the thread is about compressor efficiency decline, yet you haven't provided any information on why it's thought the compressor efficiency has declined. On a typical GE-design Frame 9E heavy duty gas turbine with conventional combustors (and we don't know if the unit has conventional combustors or DLN combustors--you mentioned TTRF, but that's not usually a control parameter unless the unit has DLN combustors and in some cases versions of MBC/ARES.) axial compressor inlet temperature is usually used to bias the amount of fuel admitted during starting and warm-up and maybe acceleration--because if the ambient is really cool it may take a little more fuel to establish and maintain flame during starting, warm-up and acceleration, or if the ambient is really hot it might not take as much fuel to establish and maintain flame during starting, warm-up and acceleration, hence the compressor inlet temperature bias. (And inlet cooling should NOT normally be running during firing, warm-up and acceleration.))

As was mentioned above, the causes and effects you have alleged in this thread are really just random and don't make a lot of sense. Again, that's why you have been asked to keep an open mind and provide the requested data and answers. But, if you insist on holding on to these theories about sensor differences causing compressor inefficiency or fuel biases or similar assumptions we just are not going to be able to be of much help.

Keep an open mind; answer the questions; provide the requested data--and you can help us help you!
 
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Deleted member 3303

Good Evening dear CSA,

HAPPY NEW YEAR and wish,hopeand pray this2021 brings a lot of blessings for all us and this pandemic uncertainty shall gone .

Thanks for follow-up my concerns about above thread .

CSA , I was in shift off days that why late reply , I shall update you tonight about all above questions regarding thread.
 
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Deleted member 3303

Good Afternoon,

Dear CSA below have all answer.

Ans#1: We have Control System mark6e.

Ans#2: All units have DLN combustion 2.1

Ans#3: RTD mounted upstream of Air inlet filters before evaporative coolers.

Ans#4: T/C mounted downstream of Air inlet filters after evaporative coolers, same as you said above wall of inlet plenum at 09:00 o'clock and 03:00 o'clock.

Ans#5: As I confirm with I&C control engineer, just they substitute signals for CTIM calculations before input thermocouples T/C and now only 1 fuel operated unit CTIM calculation by RTD. Engineers just substitute signals. Already I think

Ans#6:


BASELOAD OPERATION SUMMER FOR GAS FUEL TURBINE BASELOAD OPERATION Winter FOR GAS FUEL TURBINE

1# GAS FUEL TURBINE DATA AT BASELOAD.

SUMMER WINTER
FSR: 68% , FSR: 68%
CPD: 9.9bar , CPD: 10.6bar
MW: 108 , MW: 118
IGV: 86 , IGV: 86
FQG:6.4816 , FQG:6.912
TTRX: 564 , TTRX: 553
TTRXP:565 , TTRXP: 553
TTRXS:579 , TTRXS: 566
TTXM: 565 , TTXM: 553
CTIFR:20C , CTIFR:18C
CTIM:20C , CTIM: 18C

2# LDO FUEL TURBINE DATA AT BASELOAD.
BEFORE OUTAGE AFTER OUTAGE
SUMMER WINTER
FSR: 73% , FSR: 76%
CPD: 10bar , CPD: 10.7bar
MW: 107 , MW: 117
IGV: 85.9 , IGV: 86
FQLM1:8.2027 , FQLM1:6.912
TTRX: 556 , TTRX: 547
TTRXP: 556 , TTRXP: 547
TTRXS:578 , TTRXS: 567
TTXM:556 , TTXM: 547
CTIFR:21C , CTIFR:18C
CTIM: 21C , CTIM: 22C

CSA before all units LDO and GAS we use T/C which is downstream of air inlet filters after evaporative cooler.
But now only DURING HGPI of LDO operated turbine CTIM calculate by rtd_cif3r. For get more efficacy OF AIR FLOW cooling. (So for this upstream pressure is below inlet filters and continuously evaporative cooler in operation on this unit during summer.
Now winter situation change already ambient below 13 Celsius /56.3 Fahrenheit so as a operation crew we told operators for drain all evaporative coolers.
Currently all gas unit CTIM sensing by T/C CTIF1A and CTIF2A and current CTIM IS 8°C / 46.4 °F but LDO operated machine after substitute signals to rtd_CTIF3R 11°C / 51.8 °F . We loss 2.5 MW as compare to other units due to CTIM issue.
Ans#7:
Last outage HGPI, maintenance change all stationary and rotary blades of all three stages of turbine, also change all inners seals like brush seal and w seals and all shrouds.
Ans#8:

Last outage HGPI, GE personal on site just tunes machine NOX parameters.

Before HGPI water injection on base load operation 5kg/sec.
But after HGPI GE personal tune NOX parameters now 5.9kg/sec on base load operation.

Ans#9:

No CSA we don’t have any simulation and monitoring software like MBC or ARES. On second phase I try to communicate my manager if possible for ask GE regarding both these simulation software.




Ans#10:

Almost last 45 days before we performed water wash at this LDO unit right after HGPI and before HGPI. We newly performed HGPI

Ans#11:

During HGPI maintenance team performed preventive maintenance almost all instruments like 96CD.

Ans#12:

During HGPI maintenance team performed preventive maintenance almost all instruments like 96AP 1, 2, and 3.

Ans#13:

At last outage HGPI maintenance change all inlet air filters and install new filters sets.

Ans#14:

Yes CSA, now our power plant in operation with simple cycle and also we have by pass stacks to allow direct flue gasses to exhaust.

Ans#15:

No we don’t change any fuel oil and gas from last 3 years , same refinery and gas station we received fuel oil and our chemistry team weekly check all parameters of fuel oil.





Ans#16:


Dear CSA still I am shift team leader and communication with GE responsibility of control engineers and managers, still I not got any news about last update/communications, I try to get info then share with you .

Ans#17:

Really CSA I am one of those operation personal as you explain, I am not too much familiarize with all diagnostic alarms , as my observation no any suspicious alarms we received after this substitution of CTIM signals. If you can give any link for your explanation regarding diagnostic alarms, that I can improve my skill to familiarize as much as I can regard diagnostic alarms.

Kindly guide me self by reading and analysis how I can improve diagnostic alarms side.
As I told you, as per all review no any diagnostic special alarms appear at alarm page.

Ans#18:

Yes CSA we deal with GE Belfort France.

CSA currently in winter I share with you 4 units CTIM data for analysis.

UNIT#1

CTIM sensing with T/C

8°C / 46.4°F with 123MW.





UNIT#2

CTIM sensing with T/C

8°C / 46.4°F with 124MW.

UNIT#3

CTIM sensing with T/C

8°C / 46.4°F with 124MW.

UNIT#4

CTIM sensing with T/C

13°C / 55.4°F with 121MW.

This all above units data is live data I took .
 
Irfan ahmed qureshi,

Thanks for the information--and for providing most of the answers to the questions.

It's going to take me some time to review the data, and I will probably have some more questions (I am having a bit of a hard time with some of your comments.

Usually when a unit uses water injection for NOX emissions reduction the output of the unit when operating at Base Load (that distinction is VERY important) increases. By that I mean that if the unit were operating at Base Load without water injection and then water injection was enabled and reached stable water flow the power output of the unit will increase--and that's because of the addition of mass flow (the water--which flashes to steam before it passes through the turbine section). (A LOT of people think that's "free" power--but if you monitored fuel flow very closely before and after water injection was enabled and reached a stable flow the fuel flow would increase slightly also (that's because the water quenches (cools) the firing temperature and so to return to normal firing/exhaust temperature it's necessary to increase fuel flow slightly. So, SOME (most, I'm told--because there's a LOT of maths involved, and I'm not a high-level maths person) of the power increase is due to the water flashing to steam and flowing through the turbine section, and a small portion of the power increase is due to the increase in fuel flow to get the firing exhaust temperature back to parameters.)

As for having MBC/ARES for your the next phase of your power plant--I wouldn't recommend that, though I will bet a very high amount of money that GE will convince the financiers providing the capital (money) for the project AND the Corporate executives that having MBC/ARES is "in the best interest of the long-term operation and reliability of the high-tech units." (GE is VERY good at convincing bankers and Corporate executives of this--much to the displeasure of plant technicians and operations managers.) Both of these have promise--meaning the intent of them is very good, but the implementation is not so good. Usually, if a site has MBC/ARES, they will also have some kind of remoted monitoring and diagnostics capability (also provided by GE--also at a very high price). And, because GE deems MBC/ARES to be proprietary and a trade secret they do not allow any access to the sequencing and algorithms used in the control and simulation schemes. If anything goes amiss, you must almost ALWAYS get GE involved to understand the cryptic alarms messages and other issues which can arise (inabilities to get past a certain load, or automatic shutdowns (not trips--controlled shutdowns), and failures to START, etc.)--all of which adversely affect reliability. There are some glitches and bugs with the MBC/ARES software and it uses a LOT of additional sensors (which require maintenance and attention) and you can't "see inside" what's going on because GE prevents that (because they consider it proprietary). So, you have to get their help, usually from the Remote Monitoring and Diagnostics center(s) and while sometimes they can be informative and helpful usually they just give short and barely understandable answers which don't help site personnel very much, if at all. Again, the intent is very good--but the present-day implementation leaves a LOT to be desired, and if you think the documentation for your units is not very good now, there's almost NOTHING worthwhile written or documented about MBC/ARES. NOTHING. (It's proprietary and a trade secret.)

Anyway, let me have a longer look at the information/data and I will get back to you in a day or two.
 
Irfan ahmed qureshi, I have not had much time to contribute to Control for a while but your post is interesting. I am trying to understand your information and questions. To do this I will print out my thoughts, which may be scary for some.
You have 6 Frame 9E units.
2 units operating on Light Diesel Oil (LDO) using water injection for Nox reduction.
4 units operating on natural gas, you state dry low Nox DLN 2.1. I am familiar with DLN 1, DLN 1+, DLN 2.0 but not DLN 2.1.

Something I have learned in my short time in this industry. No two units operate exactly the same---period. You can compare unit performance from one machine to the other, each at the same site, same fuel etc, and they will each operate slightly different.

From what I gather from your posts you modified the compressor inlet temperature (CTIM) equipment on your machines. The machines I am most familiar with here in the USA use 3 thermocouple elements for CTIM measurement, and also a single RTD.
The single RTD in my experience is not used in logic. Your first post shows an inlet temperature of 3C as measured with an RTD, and another screenshot of 6C measured with TC. As stated in my experience, 3 thermocouples are used to measure the inlet ctif1a, ctif2a and ctif1b, and the average is taken and becomes CTIM. The RTD is measured, but not used, my understanding is because there is only 1 RTD and not 3, which is typically required for TMR, Triple Modular Redundancy. I have noted today that with our unit operating I am seeing a difference between the TC's and RTD of ~2 degf. The RTD reading lower than the TC's. Also the units I take care of also have 3 Ambient Temperature Inlet Duct (ATID) thermocouples that measure temperature of the air before the inlet filters and before the evaporative cooler. These ambient thermocouples help us monitor the efficiency of the evap coolers during operation.

In each of your posts you seem to ask some different questions.

dear CSA already we did this modification , now winter , we got benefit in summer but in winter is different its little oposite , so what we can do now ? What is your question??????????

now ambient is 0 celcius , no more evaporative cooler , its only use above 15 celcius ambient , so what we can do now ? Again what is your question????? With colder ambient temperatures you can't use the evap coolers which is normal.

we have almot 40 mw less production as compare to last year at same ambient due to thermocouple. Please explain this statement. I don't understand or see from your data how you have lost 40 mw.

MY QUESTION IS THAT IS COMPRESSOR INLET TEMPREATURE EFFECT FUEL INJECTIONS PARAMERTS MEANS VC3 , FUEL SUPPLYING?

Compressor inlet temperature is factored into the calculation for water injection when operating on LDO. Any mass flow increase into the machine will typically increase overall output of the machine. Water injection in this scenario is meant to reduce Nox formation, it is not designed as a power augmentation like fogging or evap cooling.

CTIM EFFECTS FQLM1 ? ITS HAVE ANY EFFECTS ASI READ YOUR PREVIOUS POST CTIM IS A PART OF TTRF LOGIC BLOCK CALCULATION?

CTIM does not effect FQLM1. Liquid fuel flow, or FQLM1, is used as part of the calculation to determine the amount of water injection needed to reduce Nox to guarantee levels when operating on LDO. The water injection curve is tuned to inject water to reduce Nox levels to guarantee throughout the operational range. The main input to the calculation is liquid fuel flow, which can also be biased by compressor inlet temperature and specific humidity for the most part, since inlet temperature and humidity will have an effect on Nox production.

I hope you continue to write in and provide information to us so we can try to help. It gets me thinking, and that's always a good thing.
 
MIKEVI,

Great to hear from you after a long absence, sir.

You are absolutely correct that two (or more) units built in the factory sequentially (one right after the other) and installed and commissioned at the "same" time will almost never have exactly the same outputs even when new. And after some years will also drift from each other because it's not common for units to all have the exact same number of starts or trips or fired hours and so the maintenance outages will usually not always occur at the same time(s) and the parts replaced will not always be the same parts. Internal clearances also change over time (such as compressor casing-to-compressor blade (the rotating compressor blade), and the exhaust frame will amost always deform somewhat over time (even with cooling--which is not always equal for all machines sitting side-by-side).

Also, as we all know, IGV LVDT calibration can be substantially different between machines, as can backlash and hysteresis on the actuator ring and blade pinion gears. If the people performing the IGV LVDT calibration checks (or calibrations) don't always follow the same procedures and use a standard procedure there can be 2-4 DGA differences in actual IGV positions versus tge calibrated IGV feedback displayed on the HMI--AND used in the control and protection of the unit(s).

Something which is unclear is: Do the liquid-fueled units have DLN combustors that are gas fuel capable, or are they just simple liquid fuel-only units with water injection for NOx emissions reduction? I ask because I wonder if they have the same fuel control algorithms and application code as the gas fuel units, or ??? Which brings up the question of whether the liquid fuel-only units also have the TTRF1 combustion reference temperature calculation or not.

After a quick couple of glances at the data (which has prompted several more questions, actually), I don't see anything like the units (for which data was provided) running on back-up FSR control to cause a difference in output. I typically see that a LOT at most sites. It looks like one of the units is close to back-up FSR control, and maybe at the instant the data was taken it wasn't, but we don't have enough data, really, to know for sure.

One thing I am kind of surprised to see is the large difference between outputs with the evap cooler running (at least I hope he supplied data during the summer with the evap cooler running) and the outputs during the cooler winter ambient (when the evap coolers should NOT be running). I'm accustomed to the output in summer with the evap cooler running being closer to nameplate rating (which we also don't know is for these machines--I'm guessing it's more like 35 or 40 deg C than 15 deg C (59 deg F). And the winter ambient is pretty low, 2 deg C, for such a high (possibly) nameplate of 35 or 40 deg F (maybe).

So, I'm officially asking the following of Irfan ahmed qureshi:

1) What is the nameplate ratings for the:
a) Liquid fuel-only machines
b) Gas fuel machines

2) Do the liquid fuel-only machines have the TTRF1 combustion reference temperature calculator?

3) Do the liquid fuel-only machines have DLN combustors capable of possibly running on gas fuel at some time in the future, or are they just conventional liquid fuel combustors with water injection for NOx emissions reduction?

4) What, if any, is the difference in water injection flow-rates for the two liquid fuel-only machines:
a) During summer
b) During winter

5) Do all six units have humidity sensors, or only the liquid fuel-only machines, and are all of the humidity sensors working properly--especially on the liquid fuel-only machines?

Now, with regard to the Diagnostic Alarms, on the Mark VIe I believe it's not possible on early versions of the WorkstationST Alarm Viewer to see Diagnostic Alarms on individual Mark VIe cards or I/O Packs. One has to use ToolboxST to connect to the Mark VIe(s) and then go to the Hardware tab and look for exclamation point icons (yellow or orange or red) on any pack/processor and double-click on the pack/processor with the exclamation point icons and click on the Status tab (I think it's the Status tab) to see what Diagnostic Alarms are present/active. I believe one has to write down the Diagnostic Alarms for each pack/processor because there's no way to print them (but newer versions of ControlST/WorkstationST or possibly WorkstationST Alarm Viewer might have this capability now).

Anyway, you, MIKEVI, can probably suggest an easier way to check and record Diagnostic Alarms than I can.

That's about all I can add at this point, except to say, again, I'm happy to see MIKEVI contributing again to Control.com!
 
Dear CSA, thank you it is nice to have some spare time to read and reply after a long year of outages.

I hope that we can all learn something from this thread, but it will be a challenge I think.
In your words, "There is a lot we don't and may never know" about this site.
I am still not clear on exactly what happened at this site with changes to what I would call ambient temperature measurement, and compressor inlet temperature measurement. I am also not clear on what Irfan means by "Substituted signals".
In Irfan's last reply he provided "Live data I took". So why is the inlet for unit #4 almost ~10 degf hotter than unit 1-3?
UNIT#1
CTIM sensing with T/C
8°C / 46.4°F with 123MW.
UNIT#2
CTIM sensing with T/C
8°C / 46.4°F with 124MW.
UNIT#3
CTIM sensing with T/C
8°C / 46.4°F with 124MW.
UNIT#4
CTIM sensing with T/C
13°C / 55.4°F with 121MW.

Lots and lots of questions. Somehow if we can focus on small steps we may get somewhere. I will do my best to stay tuned in. Happy New Year.
 
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