Fluctuating (Hunting) of SRV valve at MS6001 B Gas Turbine Power Plant With Triconex Controller

Hi, everyone. If you have some insight about this problem I describe below, please respond.

We have a unit of Gas Turbine model MS6001 B that in the recent year its controller has been replaced from Mark 5 into Triconex.
I have asked many people in the other site about this controller replacement and they said that they haven't encountered any case of replacement like ours.

So after changing the controller, we faces some problem. But the most concerning one among the problems, is that the SRV valve is fluctuating, while the load and the GCV is stable. What things do you think can cause this kind of problem? What output from the controller that we can measure to better investigate the problem?

Really hope I can show our decision makers here that changing the controller has been a major bad decision and hoping they want us to replace it back again to Mark 6e perhaps.

Looking forward to hearing some respons from this community.

It's the engineering and engineering support for this kind of turbine control upgrade that usually suffers--meaning if (when) there are problems, it's the Customer left to try to get things fixed with little or no support from the control system integrator (the one that purchased the control system equipment and packaged it and installed it and commissioned it), and the OEM (Original Equipment Manufacturer) who usually just sold the equipment to the integrator and doesn't have any margin for support (meaning, little or no money to provide any support when problems arise).

We don't know if the integrator used TMR servo-valves, or, possibly dual redundant servo-valves, or what the configuration of the control system driving the SRV is. GE's heavy duty control philosophy regarding the SRV is that it serves two purposes: 1), to serve as the gas fuel stop valve (it's primary purposed), and, 2) to control the pressure (called the P2 pressure) between the SRV and the GCV based on turbine speed. We also don't know how the integrator is controlling the GCV, which is pretty important to know, too.

I recommend you start by checking to find out how the SRV is being controlled. Is it being used to control the P2 pressure upstream of the GCV by developing a P2 pressure reference based on turbine speed, or, ??? If it's based on turbine speed, then you need to know if the speed feedback signal(s) being used for the P2 pressure reference are stable, and if they are fast enough to allow the regulator being used to position the SRV (to control the P2 pressure--in the GE world, the SRV is moved to whatever position it need to be at in order to make the P2 pressure equal to the P2 pressure reference; in other words, it doesn't just go to some position, it goes to whatever position it needs to be in to make the actual P2 pressure equal to the P2 pressure reference).

It's also just possible that the "gain" being used on the SRV control loop (the regulator gain) is simply too high or too low. Has anyone tried adjusting that to see what effect it has on the problem/SRV stability?

Finally, was the polarity of the servo current(s) being applied to the SRV verified during commissioning? The Moog servos used on most GE-design heavy duty gas turbines are bi-polar devices. That means that the polarity of the current being applied by the control system determines if the servo moves the device its controlling to open or close, and the magnitude of the current being applied from the control system determines how fast the servo moves the device it's controlling. So, polarity--first and foremost--is very important. If there are three coils, and one of the coils is getting the wrong direction signal, that can set up a "fight" with the other two. So, it's very important to be certain all of the coils (and we don't know how many coils are being powered by the new control system) are getting the proper polarity to make the SRV move in the proper direction.

In general, GE control system philosophy also uses position feedback from the SRV in the control loop. It really confuses people (using BOTH position and pressure feedback) but it's really just to try to make sure the valve operates stably (presuming the servo currents are correct!). Think about it like this: When the actual P2 pressure is equal to the P2 pressure reference, the valve doesn't need to move--it just needs to stay in the position it is presently in. So, the regulator subtracts the P2 pressure reference from the actual P2 pressure, and when they are equal the difference will be equal to zero--so the regulator output basically tells the servo, "Keep the valve just where it is, thank you, very much."

But, when the actual P2 pressure is higher than the P2 pressure reference, then the difference is negative and the regulator tells the SRV servo, "Please close the SRV to lower the actual P2 pressure reference, thank you, very much." And, the opposite happens of the actual P2 pressure is lower than the P2 pressure reference. So, that's how it works in the Mark*. What we don't know is: How does it work in the Triconex? So, without that knowledge we really can't tell you how to troubleshoot the problem.

In the GE world, it's also common to use two (2) LVDTs to provide the position feedback from devices that are positioned/controlled with a servo. And, GE's control philosophy is to do a high-select of the two feedbacks (which should be identical, but are usually never exactly equal to each other--and if one or both LVDTs is not working properly or the LVDT feedback wasn't calibrated properly, then there can be some minor to serious problems. We don't know how many LVDTs are being used in the Triconex system, how multiple LVDT feedbacks are being used (high-selected, or ???) and how they were calibrated.

LVDTs are not very common outside of GE-design heavy duty gas turbines in the industrial world. They are used EXTENSIVELY in the aerospace industry--because they are non-contact devices, they use low voltages, and they are usually not subject to problems caused by vibration or high temperature. In the industrial world, most position feedback is done using 4-20 mA feedback methods, because they are inexpensive, readily available--and did I mention they are cheap??!?! BUT, they are generally not very good when there is high temperature in the area where the sensors will be mounted, or if the vibration in the area where the sensors will be mounted is high. LVDTs also require an AC excitation source, which 4-20 mA sensors don't, which makes them kind of unwelcome in the industrial world. So, we really don't know how Triconex is exciting or using the LVDT position feedback--or even if they are (I have heard of sites that replaced the existing LVDTs with something else (that usually didn't work so well) because the control system being applied couldn't easily power or use the LVDT feedback. OR, they had to use an intermediate device to excite the LVDTs and convert the LVDT output to 4-20 mA (because the new control system couldn't do it without a converter)--which adds another point of potential failure to the system (or two, if there are two LVDTs on a servo-operated device)--and complicates position feedback calibration and adjustment.

As for your hope, that's a pretty bad hope in my personal opinion--wanting to "disqualify" one control system to go to another. Expensive and time-consuming, as well. I know of several Triconex turbine control upgrades that were pretty successful, so it would seem it should be possible to determine what's supposed to be happening, and if that is happening or not--and ultimately to be able to fix the problem. AND, I can tell you that GE or BH or whomever might provide a Mark VIe has been doing an absolutely horrible job of installing and commissioning Mark VIe's--and the HMIs that are provided with them. So, you would most likely be just changing one set of problems for another. And, finding people in GE (or their sub-contractors) that will actually help to resolve any Mark VIe or HMI issues is getting harder and harder and harder. Especially since they are not training people and they are reducing their field workforce. And, there is so much misunderstanding about the BH divestiture and who is doing what, well, it's just horrible. And, the Singapore offices of the GE turbine control retrofit business are just about as bad as it gets when it comes to any kind of quality control or supervision or experience or field support. None of it exists.

So, you should really reconsider working with the control system integrator who installed and commissioned to get this problem (and any other problems) resolved. And not just trade one set of problems for another. Sure, GE has "deep pockets" but their willingness to spend money to get problems resolved just isn't there anymore--and they don't have much money to spend these days. And, they don't have experienced people, nor are they training people, to solve problems--even if they had money to spend to fix them, or were inclined to spend it. It's gotten pretty bad there.

But, we simply don't have enough information--and it would probably take a LOT of back and forth on this World Wide Web forum to get the information and to provide enough direction to help solve the problem. You haven't told us what has been done to try to solve this problem, and what the results were--and that's pretty key to solving any problem: Understanding what's been done in the past to try to resolve the problem, and what the results were.

So, as much as I would really, Really, REALLY, REALLY like to help resolve this problem--and I would!!!--without a LOT more information and drawings and answers to questions it's not going to happen easily or simply. I wish you the best of luck; I know I haven't provided much in the way of information or troubleshooting suggestions--but there's just a lot we don't know, and it would take a LONG time to get the answers.

Please write back to let us know how you fare in resolving this issue!
I wanted to offer one more suggestion. I have seen several occasions when the gas fuel supply pressure regulator and the SRV got into a condition where they were fighting each other. This usually happened after the gas fuel supply pressure regulator was either changed or refurbished and was not re-installed correctly, on a couple of cases there were liquids in the gas fuel supply which got into the regulator and caused problems, and in one case they actually froze (because of cold ambients).

So, the problem could still be a tuning issue for the SRV regulator gain being incorrect, and interacting with the gas fuel supply pressure regulator.

What I find unusual is you say the GCV is stable and so is the load.... With an unstable SRV--and what one has to presume is an unstable P2 pressure. Usually even if the GCV is stable but the P2 pressure is unstable the load is also unstable. You have not told what the pressure swings are when the SRV is unstable--is it +/-0.5 barg, or more, and what is the period of the instability (1 sec between peaks, or more, or less)?

What does Triconex, or the control system integrator, say about the problem? That would be very interesting to hear their take on the problem? Do they say it's a problem with the SRV? Or??? What is happening with the hydraulic system pressure when the SRV is unstable?

Again, it's odd the GCV is stable and the load is stable when the SRV and P2 pressure are unstable. Very odd.

And, also, another thing. Since the SRV is (usually) trying to control the P2 pressure based on the P2 pressure feedback. So, is (are) the P2 pressure transmitter(s) working correctly? Are the valves on the sensing lines for the P2 pressure transmitter(s) in the proper positions? THIS is one thing that causes a LOT of problems after maintenance outages, and control system upgrades: valves not being in the proper position. The three most important things in any start-up/re-start after a maintenance outage or control system upgrade are: Valve line-up; valve line-up; and, valve line-up. And the three-way valves usually used on the P2 pressure transmitter sensing lines can pretty confusing. Also, is the 20VG-1 intervalve vent solenoid, closed when the turbine is running?

Finally, what is the L.O. condition? Is it clean? Has the pencil filter in the SRV servo been changed recently? Has the SRV servo been replaced--and if so, did it have any effect on the issue at all (did it make the problem worse or better or were other changes (regulator gain?) made to try to help with the problem)?

Just the last few things I can think of to check. Again, it would be great to hear back from you on how you are faring in resolving the problem, and how you resolve the problem. It would be great to get answers to the questions and the results of the checks which have been suggested, also.

Thanks! And good luck.
I wanted to add one more thing about turbine control upgrades--no matter the control system used. If a 20 or 25 year-old turbine is being upgraded to a new Mark*, well, unless the unit has been well maintained and serviced and device calibration verifications have been done regularly and there are no wiring issues (as there are on many older units), there WILL be problems. For example, if the unit starts on gas fuel, it's pretty likely that unless there is an automatic shut-off (stop) valve upstream of the SRV that there will be problems, particularly if the SRV hasn't been opened and inspected and cleaned in a few years. They develop leaks the older control system was NEVER designed to detect--BUT the new Mark VIe will find them and will not allow the unit to start if the SRV and/or GCV leaks. And, these new tests for leaking gas valves will ALSO add to the starting time, meaning that it will take longer for the unit to reach synch speed and be synched and loaded--AFTER the gas leaks are found and fixed.

Most commissioning field service personnel working on GE turbine control system upgrades are not very familiar with the control schemes in the Mark VIe, so when a gas valve leak is detected they are going to say, "It's a gas valve problem." But, the owners/operators of the turbine are going to say, "It worked just fine before you put that Mark VIe in there!" And, nothing will happen. Except when it's written in the contract (and it's usually not--written in the contract for the new turbine control system) it's not the installer's responsibility to find and fix existing problems, and no one knows to check for this (and other similar) issues before the unit is shut down to remove the old control system and install the new one. So, they aren't found until AFTER the new Mark VIe is installed and commissioned--until they try to start and run the unit. And, then a lot of finger-pointing goes on, with nothing getting done. For days, or week, or months.

It's NOT uncommon these days to go to sites where critical pressure transmitters haven't had their calibration checked in years, and the site technicians have just been "tweaking" the old control system to get by. Then a new turbine control system gets installed, and all of a sudden, there are issues. Why? Because the new control system doesn't have the tweaks, and expects the critical pressure transmitters to be properly calibrated, properly connected (wiring), and the isolation valves in the sensing (impulse) lines to be properly set for starting and operation. And, when there's a problem (and there usually is), more finger-pointing starts immediately. "It worked fine before you put that Mark VIe in there!" "It's not the Mark VIe, it's the transmitters." And, again, it's not the installer's responsibility to perform calibration verifications--especially when a new turbine control system is being installed. One that expects the devices to be properly calibrated and valved-in. So, again, nothing gets done for too long.

Same goes for temperature switches, or T/Cs (thermocouples), or RTDs. It's not the installers' or the commissioning personnel's responsibility to find and fix the problems of neglected maintenance and non-working equipment. (Though, truth be told, they would be doing themselves--and the Customer--a great service if they found and work with Customer personnel to fix the issues BEFORE pushing the START button!!! But they just don't have the training or experience to do so, and that's not what their management tells them, or wants them, to do.)

Control system integrators are in just about the same position--it's not their responsibility to find and fix existing problems. And, the site owners/operators who expect them to are foolish and inconsiderate. While the commissioning field personnel for non-GE control systems might be a little more experienced with the controls and sequencing and there probably won't be any surprises as far as what's provided in the new control system (like GE's gas valve leak tests), there can still be lots of problems if the existing devices aren't working properly (have had their operation and calibration verified recently) or are broken, or are disconnected.

So, it's really about expectations. And, of course, the control system provider isn't going to point out what they're NOT responsible for, and the owners/operators so often just assume the installation and commissioning personnel will find and fix all the existing problems (for free!) during installation, loop-checking and commissioning. So, again, little problems become big problems. Because of incorrect expectations--on the part of both parties (the control system supplier and the site owners/operators).

And, it really doesn't matter which control system is the basis for the new turbine control system. Because what the owners/operators and their sourcing people SHOULD HAVE been checking on is whether the control system integrator has experience with the equipment and application (the control system and the turbine, generator and auxiliaries), AND checking references to see if past installations/commissionings were completed on time and without a lot of lingering problems. That's the hardest thing to do--ask for and check references. But, it happens so often--that when someone buys a new non-OEM control system and has problems, and then they start talking to other sites who had similar issues with the same control system integrator or control system or commissioning personnel THAT is when the second-guessing begins. But, if references had been received and checked--a LOT of past problems would be more widely known and others would be aware of it BEFORE they sign the contract, and get disappointed.

Do control systems, including Mark* control systems, have issues? Certainly, but if the control system integrators or the commissioning field personnel are familiar with the equipment AND the application, they should be able to deal with most of the issues and leave the site with a well-running unit with very few problems or nuisance alarms. But, there just isn't that many experienced people left working for the OEM or its wholly-owned subsidiaries.

And that's what site owners/operators should be looking for when they are choosing who will supply and commission their new turbine controls--knowledge and experience, of both the control system AND the application. Just about any PLC (or PAC) can be made to properly control a GE-design heavy duty gas turbine--but it takes someone who knows what's supposed to happen when, and what to do when it doesn't. And there are a few control system integrators who believe because they have some talented programmers they can make a PLC or PAC control a turbine and generator and auxiliaries. I have seen some very good and near genius programming on PLCs sold and installed on turbine control applications--but it just didn't do the job, because the programmers just didn't really understand the application (turbine, generator and auxiliaries). I'm NOT saying that is anything close to what happened in the original post of this thread, but it does happen.

So, turbine control upgrades go "sideways" and finger-pointing gets out of control. And, the control system gets the blame for the site owner/operators not doing their due diligence to ensure the control system supplier has the experience and knowledge and asking for and checking the references of past jobs the control system supplier has performed. And, both parties, again, have incorrect expectations. And, the control system (JUST LIKE in the original post of this thread!) gets the blame.

Undeservedly so.

But, that's life, folks!
"It's not the installers' or the commissioning personnel's responsibility to find and fix the problems of neglected maintenance and non-working equipment."

As an installer/commissioner, I'll echo that statement.

I've done recorder, data acquisition and SCADA projects, much smaller than a geneator controls retrofit, but my proposal/quote to the client always has a statement:

The installation, repair, configuration, programming or calibration or re-calibration of non-operating, dysfunctional, faulty, out-of-calibration, drifting, disconnected, not-yet-in-service, out-of-service field instruments or otherwise faulty devices whose signals are associated with this project is not covered by this proposal/quotation unless those devices are itemized by name/tag herein in Section F.

To me it is just the nitty gritty of establishing who is responsible for what, up front. Apparently this level of detail of "who is responsible for what" gets glossed over in the rush to get the contract signed on bigger controls jobs.

I'm going to pass that statement along to my Manager and the Proposal writer; it's VERY good.

Turbine-generator and auxiliary controls are not that much different from other processes and automation applications--with the exception that they are poorly understood, poorly documented (from a sequencing and philosophy perspective), and there are few people left that really understand them--and can explain it to others so they understand it.

SRV stands for Stop-Ratio Valve; it's primary purpose is to be the gas fuel shut-off valve. It has a very important (but, again, misunderstood) secondary function which is also poorly documented. The GCV is the Gas Control Valve, and on older units it is the valve that controls the amount of gas fuel which is sent to fuel nozzles of the gas turbine. It's operation is a little more understandable. But the thing about GE-design SRV/GCV systems is that they don't use positioners for control actuation. They are hydraulic actuators (mostly single-acting pistons, but most units have a double-acting piston as well (for the IGVs)), and GE has historically used electro-hydraulic servo-valves (servos) to convert a bipolar current signal into a hydraulic flow reference to the hydraulic actuator. And because it's not a "simple" I/P (current to pressure) 4-20 mA positioner, it just sends people off and they get all flustered and upset. (Westinghouse used to use pneumatic I/P positioners on their fuel control valves, and the few sites I visited with them all complained about intermittent instability and problems with instrument air supply (a maintenance issue that was also blamed on the control system...)

Anyway, the other issue with turbine control retrofits (upgrades) is that there is SO MUCH I/O (think more than 100 discrete inputs; 40 or so discrete outputs; those damn servo outputs and the associated LVDT position feedbacks; exhaust T/Cs; generator stator and exciter RTDs; pressure transmitters (many are redundant--and one or two drifting can cause problems); speed sensors (passive mostly); and vibration sensors (many of which look exactly alike but have very different temperature constraints and output scaling, but people see "the same" thing and just go and throw it in, and then wonder why the problems have gotten worse...). The scale of some of these jobs (I/O-wise) is pretty big, and since devices are scattered around the equipment (some on-base; some off-base; with different auxiliaries on most units) it just gets to be overwhelming. And if you price in the cost of making things work--when the owner/operators/technicians don't even know what's not working--well the costs can just get out of control in a hurry. And, when there is competition for these jobs (and there is!) there's always someone willing to do it really cheap with a PLC who doesn't really understand the I/O requirements (like those pesky biploar servo outputs and LVDT feedbacks--and 335 VDC flame detector inputs--and vibration sensor inputs--and high-speed speed sensors) and the jobs can just get so ugly and filled with converters for this and that and most of it ends up getting "fixed" on the fly, when the job is horribly behind schedule and there have been so many problems. It's no wonder some sites have asked the control system integrator to just remove their equipment, and pay another one to come in to install their equipment (at a huge cost--basically for two systems, plus all the lost generation, and the aggravation). You would really be surprised at what some people/companies will take on with little or no experience or turbine-generator and auxiliary knowledge.

When it comes to GE-design heavy duty gas turbine control retrofits (upgrades), there is the OEM and several competitors. And when it comes to choosing a provider, even though the OEM pricing is a little higher, most Corporate purchasing and middle management will always opt to choose the OEM. Why? Because no one ever lost their job for choosing the OEM's equipment/services. Even when the OEM's retrofit (upgrade) services can be pretty poor in terms of configuration/programming, installation and commissioning, they still choose the OEM. Because if they choose another provider and the job goes poorly, there's always the possibility they have damaged their promotion prospects at least and maybe even ultimately lose their job at worst. So, what would you choose? I know control system integrators who have worked with site personnel to write the request for proposal specification, basically to write the integrator's offering into the RFP, and when the OEM bids on the job and the proposals go to Corporate--Corporate Purchasing and Corporate Middle Management choose the OEM, much to the dismay of site personnel who did not want OEM equipment or services. It happens a lot. A LOT.

For some of the newer, high-tech units, there are other mitigating circumstances that can factor into the decision to choose a control system supplier. But, it's still very similar in most cases. The bias is to almost always choose the OEM--even if recent, past experience hasn't been good. "This is the Mark VIe--it is the best thing since sliced bread. It slices; it dices. And it will improve your unit's efficiency and reliability and protection." (Just don't ask the OEM salesperson how it does any of that--or the commissioning personnel sent to site.)

Anyway, sorry for not explaining mnemonics better (something I usually try to do, but I failed this thread).
Hello CSA, I am sorry for not responding earlier. You really showed your concern about our problem, and I really appreciate it. You are being so generous about your knowledge and experience to the community here.

It took us so much time to tackle the problem and I myself has proposed some solutions. We are currently doing my proposed solutions and hopefully can address the issue completely.

So, the LVDT as the feedback position of the SRV and the GCV got the excitation voltage from a GE module, TCQA, if I'm not mistaken. This module sent 7 Vrms AC at 3 kHz voltage as the excitation and will receive 0,7 Vrms for 0% and 3,5 Vrms for 100%. This is the main issue that somehow the Triconex engineers don't realize. Because their signal conditioners (the device that convert Vrms LVDT feedback to 4-20mA signal, because they have no module that can receive Vrms input directly) send only 3Vrms at 2,5 kHz. and so the linear output won't be 0,7 ~ 3,5 Vrms anymore.

In the beginning of the project they always wanted to adjust the LVDT so that the output will be around 0,7 Vrms at the minimum position (i.e. when the actuator has not touch against the spring yet), as the GE manual would say. So I proposed that they have to search for a new value because of the difference in the excitation voltage. They have to check the linearity and determine the range of which the LVDT will give an optimally linear Vrms output (which theoretically will be around 0,3Vrms - 1,5 Vrms for 0% and 100% with 3Vrms excitation voltage).

Another issue is that they also add dither to the current output to the servo, as to add some sinusoidal noise to the output on purpose. They did it because they think the valve is quite sticky, so by adding the noise they will fight the moment inertia first and the movement to another stroke position will be much smoother. So, i told them to replace the sealing to address the stick issue and reduce the dither magnitude. This solution has been quite useful as the fluctuaction is not that much anymore.

Lastly, I told them that the PID control of the SRV and the GCV should not have too high of overshoot. Because in their understanding, the control should be fast respond and high overshoot is not a problem. And to do this they just needed Proportional and Integral control. My proposed solution is to get a low overshoot percentage and medium response time. Either by changing the constant for P and I, or by adding the Derivative control. What do you think about these solutions?

Currently, they are implementing all of my suggestions, and hopefully we can get back to what we have when the controller is Mark V.
And to answer your previous questions, Yes, the servos are TMR and we have made sure the polarity of the servos are correct.
The control of P2 is also using the turbine speed TNH_RPM as the main data. The formula is exactly similar to what you have written somewhere in this forum. I can't remember where you post it, though. The turbine speed is measured by 3 redundant magnetic pickup coils and their respond time are quite fast. The voting method is to get the highest value between those 3.

Thanks very much for the feedback!!!

All the Mark* cares about from an LVDT is that the feedback is linear as the device moves from mechanical stop to mechanical stop. And, the GE specifications say that with an excitation voltage of approximately 7.0 VAC RMS at approximately 3.0 kHz (older Mark*'s used 2.8 kHZ and 3.2 kHz), the output voltage will be linear between 0.70 VAC RMS, +/- 0.20 VAC RMS up to 3.500 VAC RMS. In other words, when the excitation is per spec, and the zero stroke voltage (usually the fully closed mechanical stop) is 0.700 VAC RMS, +/- 0.20 VAC RMS when the device the LVDT is attached to is at the other mechanical stop (usually fully open) the LVDT output voltage will not exceed 3.50 VAC RMS, +/- 0.20 VAC RMS. The output for a particular device might be 0.69 VAC-2.76 VAC RMS, and for another device it might be 0.75 VAC RMS-3.39 VAC RMS, and for another device it might be 0.689 VAC RMS- 2.31 VAC RMS. When the zero stroke voltage is at 0.70 VAR RMS, +/- 0.20 VAC RMS, the output voltage DOES NOT have to be 3.50 VAC RMS, +/- 0.20 VAC RMS--it just should not exceed 3.50 VAC RMS, but it could be anything less than 3.50 VAC RMS.

Actually, the output of some RVDTs used by GE on rotary SRVs is not linear when the zero stroke voltage is 0.70 VAC RMS. It has to be 0.5 VAC RMS to get a linear output over 90 degrees of rotation. And, that causes a LOT of problems because GE never documented that anywhere....

That's a common misconception--that the feedback MUST be 0.70 VAC RMS at minimum stroke and 3.50 VAC RMS at maximum stroke. I have watched people spend hours and hours and hours over days trying to get those values and they just lose their mind when it can't be done--and, of course it's the Mark*'s fault, right? (NOT!!!)

It should be possible to plot voltage versus position from fully open to fully closed to find the linear range with the converter's excitation voltage output. Which is I think what you have described. However, it just might not be possible to find a linear output range for those LVDTs with the converter's excitation voltage output.... It would just be a trial and error situation.

Next, GE has stated very clearly in some of their recent product service bulletins and/or technical information letters that for most GE-design heavy duty gas turbines there should be NO dither. Dither is primarily for steam valves, and not generally for gas turbine control devices (control valves; IGVs).

Anyway, it sounds like you are making progress--and that's good to hear, very good!

Thanks, again, for the feedback! Best of luck getting things corrected and getting the unit running smoothly.
Dear CSA,

Thankyou very much as well for all of the free information.

I didn't know that we should not put any dither in the control. As I said in our conversation, I'm still new here.
And this information is really precious for me and I will pass it to our team. Thankyou very much.
Anyway, if you have any link to that product bulletin or news from GE, please let me know.

I agree with you. The difference in excitation voltage is quite of a dilemma. Cause we might not find a linear output.
But I am planning on doing linear regression to find the best linear output range for our LVDTs. FYI, we also have 2 LVDTs for each valves (2 for SRV and 2 for GCV).

Anyway, what do you think about my last solution. Should we reduce the overshoot or just let it be?
All that's required is typical tuning--a small overshoot, a smaller undershoot and and easy transition to steady-state. No overshoot could make for problems during high speed transient conditions.

This LVDT dilemma is typical of many PLC-based turbine control systems--the need for converters because the platform being used does not have the capability to handle turbine I/O. I've seen converted used for speed sensing, for flame detection, for vibration detection, for LVDT feedback. And in almost every instance the control system integrator doesn't provide proper drawings for the wiring (because sometimes the converters are added during commissioning)not proper calibration information (not that GE's calibration information is better).

Anyway, I'm not saying that's happened at your site, richatpurba, but it happens a lot with PLC-based systems for turbine control. (And I'm sure Triconex doesn't think their control system is a PLC, but it's being applied like it is.)

I don't have access to GE PSBs or TILs; sorry. Perhaps someone reading this can help with that.

(GE put dither in the Mark V, and it should have been selectable--but it wasn't. It was small, but at a high rate. On later Mark*'s it was selectable and configurable.)