We are upgrading from Mark V to MarkVIe and the preparation of specification Is ongoing. Can you forward me the specification for the same upgrade if you have prepared for my reference only.
Please forward to firstname.lastname@example.org.
I recommend you read a reply written by CSA in "Control System Upgrade" thread on 30 May 2018. Look closely at the complaints he has about GE documentation on these upgrades, and include requirements in your specification that these issues be addressed to your satisfaction. There must be a significant monetary penalty for failure to comply. Make sure it is brought to the supplier's attention during a meeting and documented in the minutes. And good luck!
Are you getting a full "rip-and-replace" Mark VIe upgrade, or the Mark V-to-Mark VIe "Life Extension" upgrade? There is a HUGE difference.
In the former, you would have to remove the Mark V, by disconnecting all of the wires, and replace it with a new Mark VIe. This takes longer, and usually requires loop-checking to verify inputs and outputs are properly terminated and providing the desired signals--something that is ALWAYS good to do when upgrading a turbine control system.
In the latter, you will be retaining the Mark V panel and cores and plastic card carriers (with upside-down cards and ribbon cables) and the current I/O terminal boards and wiring. A LOT of people desperately want to clean up their field wiring in the Mark V, which won't happen with the "Life Extension" upgrade.
If you think that by upgrading the Mark V to a Mark VIe (of any variety) will solve operation issues, you are mistaken. The field devices and instruments (the inputs and outputs) don't change with a turbine control system upgrade. And, as has been mentioned before on control.com: GE will give you more than you paid for (hard to believe--but it's true!), and they WILL NOT be able to tell you what they have given you.
The new HMIs using ActivePoint are very difficult for many operators to adapt to, as are the Alarm Displays (and Alarm Rationalization). Expect a long learning curve with everything--from the application code (the "CSP" in the Mark VIe) to the HMIs and operations. Functionally, the unit will still produce power--but it's going to do so in ways GE can't even tell you how it will be different or how it will affect your operations (start times; reliability; etc.).
Yes--the Mark VIe (in either form) is a good control system, purpose-built (for controlling turbines and auxiliaries). But, the way it's being packaged and sold is not good. Not good at all. Again, expect to have different problems in addition to whatever problems you were already experiencing and expecting the new control system to alleviate. Much of the new application code will impact the way your unit operates--and so the way you operate your units. And, again--GE WILL NOT be able to tell you what to expect. You will learn as you go, and they will just respond, "Functionally--it's exactly like your unit with the Mark V!" And, technically, they will be correct--it will start and synchronize and load and unload; it will just do it in new ways and new times (some better; some not).
You would do well to fully understand what GE is supplying--they are saying that this is a Mark VIe, and if it's the Mark V-to-Mark VIe Life Extension (or whatever they're calling it) MANY PEOPLE are very disappointed in what they "get"--because they will really be keeping some of the things they didn't like about the Mark V (field wiring terminations on I/O terminal boards; card carriers with upside down cards; ribbon cables; etc.). Yes, you will be able to use ToolboxST (which has its own learning curve!) and new HMIs (which have their own learning curve!). And, you will get much more, too--it's just that GE won't be able to tell you what they'll be giving you. Just that it's new and improved, and you're going to love it. Once you learn about all the new things they can't tell you about, or how they'll impact your operations.
I'm sure this is a "done deal" and you can't go back and renegotiate the contract, but if you can you should start the discussions with GE RIGHT NOW about exactly what hardware and software they will be supplying. And, if they can't tell you what all the new software does and how it will impact your operations, you need to write in the contract that it must duplicate the existing software UNLESS APPROVED IN WRITING BY SITE PERSONNEL. And, if they sign the contract without exception to this (which they probably will) the contract should, as otised says, have stiff monetary penalties for including any unapproved software.
Hope this helps! A Mark VIe is a very fine control system, when it's properly configured and packaged and everyone knows what they are getting and how it will work and impact their operations. When it's not understood, well, ..., it's not a good experience. It will still be a good control system--it just won't be a good experience, and the control system will get blamed for what is poor configuration and implementation, and poor expectations. And, it's NOT the Mark VIe's fault.
We are going for a full rip and replace Mark Vie upgrade. I will look into the points you highlighted. As part of upgradation, any existing field instruments or valves like GCV, SRV or IGV requires re-calibration. GE had mentioned in their offer that the black start functionality is not considered. Actually, is this facility existing in MarkV. What is actually black start functionality?
Also, do you think DLN tuning is necessary as part of this upgrade? GE has mentioned that DLN tuning will be done by others if applicable.
If anyone had done upgradation from Mark V to MarkVie, I would like to know the problems faced and lessons learned during engineering, installation, commissioning and start.
Kindly share your experience.
Black start most often refers to the ability to start a GE-design heavy duty gas turbine when there is NO AC (Alternating Current) available from the grid in the plant, or from a suitably-sized emergency diesel generator which can temporarily supply power for the auxiliary motors and the operator interface computers/computer monitors AND the turbine ignitors (the "spark plugs" used to initiate flame in the combustors during starting--they require AC (Alternating Current) power). The Auxiliary L.O. Pump motor requires AC for operation, and the Aux. Hydraulic Oil Pump motor (if the unit has one--some Frame 6Bs do not) requires AC power. And, cooling water pump motors, and cooling fans, usually require AC. So, to start a turbine and its auxiliaries AC power is required--even though the Mark* typically does NOT require AC power (it runs off 125 VDC, usually). AND, most importantly the operator interface (<I>, HMI) AND the ignitors DO require AC (though on a Mark V you could use the <BOI> on the door of the turbine control panel to start and synchronize the unit IF it were properly configured AND the operators were experienced in using it--both HUGE if's!).
I believe you said you are working on GE-design Frame 6B turbine-generators. Those units typically use a diesel engine starting ("cranking") motor when they are required to have black start capability. But, some sites use large diesel generators which can be temporarily connected to the turbine auxiliaries--including an electric starting ("cranking") motor for black start capability.
GE uses a lot of what's called "boiler plate" information in their proposals. ("Boiler plate" is a colloquialism that means "standard contract verbiage"--the stuff most people never read (but should!). Couple that with the fact that most GE salespeople these days have very little if any experience with what they're selling and the proposals they are producing can be very misleading.. With word processing software today, standard proposal templates are very generic in the beginning, and a knowledgeable salesperson and application engineer should work together to understand exactly what the Customer has and needs and delete the generic stuff and edit the proposal template to make it site-specific. BUT, since most companies don't win every proposal they prepare many don't edit them properly in the beginning--which leaves errors and omissions to be handled by the people actually performing the work of installation and commissioning in the field. Which can be a VERY bad place to hash out terms and conditions and options which should have been sorted BEFORE the contract was signed.
If the unit(s) at your site have DLN (Dry Low NOx) combustors, then, yes--it will be prudent and probably necessary to tune the DLN combustion system after a control system upgrade. I would think GE would be clamoring to do the DLN tuning, but they are probably not including it in the price because it will add to the amount--considerably. And, if they aren't lucky enough to be able to commission the unit with the new control system and it's required to have to send someone to site--well, then, that will be an "extra" the Customer will have to pay for, and GE will gladly take the money. They are getting VERY BAD about not including such things in their proposals, because they increase the cost of the total job so much in some cases that the Customer will not buy the control system. But, the Customer ends up paying in the end--and GE makes more money.
You have only mentioned SRV and GCV--a DLN combustor-equipped unit will also have at least a GSV (Gas Fuel Splitter Valve), and may also have a GTV (Gas Fuel Transfer Valve). If the unit(s) only have an SRV/GCV, they likely don't have DLN.
HOWEVER, many units use water- or steam injection for emissions control. And, if the unit(s) at your site do, then it will likely be necessary for the injection to be tuned after the upgradation.
Tuning for emissions control (DLN, or water- or steam injection) requires a good, working, calibrated emissions monitoring system. Usually, in many parts of the world, an outside company is brought in to measure emissions during the testing--to validate any in-situ emissionins monitoring systems as well as to ensure the tuning meets emissions compliance guarantees. That may be what that bit of "boiler-plate" in the proposal is referring to....
And, yes, any device with LVDTs will need to have the LVDT feedback calibrated during a control system upgrade--from all LVDTs.
As otised said above, you really need to understand exactly what GE is going to be giving you (and MOST times the salesperson CAN'T say exactly what you will be getting--except that "it's the latest and greatest!!!" and you won't find out until after it's installed and during or after commissioning that some parts of the operation have changed GREATLY and will actually prevent the unit from starting). It's a VERY BAD problem. The problem with that is: You won't be able to get that information from GE. We are just trying to make you aware of what you will be getting--in addition to what's been promised.
Yes; the Mark VIe is an improvement over the Mark V. But the Mark V--even though GE doesn't support it any longer--is a fine turbine control system though with a less-than-stellar reputation (some of it deserved; much of it not deserved). There are LOTS of GE Mark V parts available in the aftermarket (from other than GE), and lots of people in the world who can and do still work on Mark Vs. But, because GE doesn't want to train people to work on the Mark V, AND because they want to sell NEW turbine control systems, they have "obsoleted" the Mark V and that scares many people into buying their NEW Mark VIe.
The other problem I alluded to above is really serious. GE will put all kinds of new logic and sequencing into the Mark VIe they will install and commission--on your OLDER turbine. And, one of the new bits of software they will be installing will be some that checks to see if the SRV and GCV leak--and many older SRVs and GCVs do leak, some more than others. BUT, because the Mark V didn't have this leak-checking software most owners weren't aware of the leakage, and even if they were aware of it the Mark V didn't trip the unit during starting (or even stopping from what I hear on the newest software!) and they could ignore the problem (if they knew about it).
BUT, now with this new software, if the leakage is "excessive" then the unit will not be allowed to start--and that can mean serious problems. GE will say it's the gas valves--and they will be right. Site personnel (technicians, operators and Management) will say, "It worked fine with the Mark V!"--and they will be right. Technically, there are some regulations in some parts of the world that mandate the gas valve leak checks--but not everywhere! BUT, GE puts the functionality in ALL the software they sell. Why? Because they are worried about lawsuits, liability and public image if they put a new turbine control system on a turbine and it has a serious problem and someone gets maimed or killed. Their lawyers require them to put that in the software.
And, many of the commissioning personnel don't know it's there--or how to work to resolve the problem. And it just becomes a HUGE argument during and after commissioning. Site personnel will say, "The turbine started and ran just fine before you installed the Mark VIe!!!" GE will say, "The problem isn't the Mark VIe--it's the gas valves!!!"
And BOTH are technically correct. And, it just goes on and on and on. Should the gas valves have been inspected and repaired if necessary, before or during the upgradation? Yes--but if GE would have put the inspection/repair into the proposal it would have cost more money--which might make the contract too expensive.
Should GE have told the Customer about this new bit of functionality--which is part of "the latest and greatest software" the salesperson was bragging about? Yes. But, then there would be LOTS more questions the salesperson couldn't answer, and GE may have lost the contract.
Should the Customer have known if their gas valves leaked and repaired them? Yes, but most Customers don't really understand the turbine and the auxiliary systems and don't properly check for these kinds of problems--before they cause bigger, worse problems.
This is just ONE example--but a very common problem on a LOT of upgradations. You, as an operator/technician/supervisor/manager/owner just want the newest turbine control system to operate your turbine exactly the way it's currently being operated. To your way of thinking, there's nothing wrong with the way the turbine and auxiliaries are operating now--and you THINK and EXPECT you are going to get exactly the same sequencing and logic and that very little, if anything, is going to change. And, the salesperson--who doesn't know any better--is helping to encourage those thoughts and expectations. It's not till after the fact that you discover--not once, but maybe several times, that there were some major changes made to the sequencing and logic they are impacting the ability to reliably start and operate the unit.
It's a very difficult thing--to try to explain this to people. GE doesn't want to service or support the Mark V--even though it's a fine turbine control system and it does have its issues and poor documentation (but then most GE turbine control systems are poorly documented). GE WILL give you the "latest and greatest" turbine control and protection software with the Mark VIe, the newest and most modern turbine control hardware and operator package they have. BUT, they WILL NOT tell you exactly what is going to change, or how it's going to change the way the turbine and auxiliaries operate--before you buy it and before it's installed and commissioned.
They SHOULD have a list of all of the options available to make the unit safer and more reliable--and a description of them and how they will change the operation of the unit, if at all. Some don't, some don't immediately (say, the gas valves leak a little bit now, but not so much that the Mark VIe aborts the start), but that after a few months the leak(s) become severe enough that the Mark VIe aborts starts. It's going to look like the problem was caused by the Mark VIe--after all, The Mark VIe annunciates the alarm (with a cryptic message with NO written description!) and it trips the unit and prevents the start-up. Site personnel will think it's the Mark VIe that's causing the problem--but it's really the gas valve(s). But, the gas valve(s) never exhibited any problem before the Mark VIe was installed. And, the Mark VIe gets a bad name; and it is getting a bad name and this is one of the reasons--it's NOT a bad control system, it's just the way it's being programmed and commissioned and installed.
It's GREAT that you are getting a rip-and-replace Mark VIe--but beware of what else you'll be getting. Most of the people commissioning GE turbine control systems DO NOT know how to properly loop-check I/O--and that WILL BE NECESSARY with a rip-and-replace Mark VIe upgradation. ("Loop-checking" is the process of verifying that EVERY input to and EVERY output from the turbine control system is providing the proper signal or receiving the proper signal, and hopefully operating as it should.) It could add days or even weeks to the outage.
And, if an input or output is discovered to not be working correctly, there begins yet another "discussion." "It was working fine before you installed the Mark Vie!!!" "GE doesn't fix broken inputs or outputs; that's the Customer's responsibility!!!" And, in some cases the wiring, over the years, has been modified or even been disconnected--and GE isn't responsible for fixing that either. And, the Customer will say, "It worked fine before you installed the Mark VIe!!!" And, just because they did or didn't know the device was broken, or out of calibration, or the wiring wasn't correct, they may or may not be correct--but, it wasn't covered in the GE proposal. This can lead to many heated "discussions." This is another VERY common problem. GE, unless it's covered in the proposal or contract, isn't responsible for non-working inputs or outputs, or for fixing wiring problems which existed before the upgradation began. And, in many cases, commissioning personnel do a poor job of communicating the issue, and they often times can't really help resolve the issue (if they have the time!) because they lack the experience. And, in many cases, the Customer personnel don't have the knowledge or experience and can't find the drawings and don't know how to troubleshoot wiring problems or don't have devices to replace failed instrumentation. It can be a VERY bad experience--and it has NOTHING WHATSOEVER to do with the Mark VIe. And it can cause all manner of delays to the completion of the project.
And, most site technicians will be expecting to learn something from the commissioning personnel--but they ARE NOT there to train anyone, and they will be working fast and furious to accomplish a task (loop-checking and commissioning) they have not been properly trained for, and they will likely not have enough time to do everything they should or do it properly. Why? Because to put a realistic estimate of the actual time required for an inexperienced and poorly trained person commissioning the Mark VIe it would make the cost of the Mark VIe upgradation too expensive.... Also, GE sells training, so why should they give it away for free?
I'm sorry; I don't have a lot of good things to say about Mark VIe upgradations. The Mark VIe is an excellent product. The Mark VIe documentation is in most cases better than the Mark V documentation--but it's still NOT what a technician with little or no training or experience needs to understand how a Mark VIe controls and protects a GE-design heavy duty gas turbine. (Though no turbine control supplier really does a proper job of that!) It's really the way the Mark VIe is being programmed for an upgradation job on an existing turbine--that is (seemingly!) running just fine--and the way that it's installed and commissioned that are the issues. If GE would (if they could) tell a Customer exactly what they will be getting and how it will affect their current operation, that would be one thing. Even if they had a written document they supplied just before the installation/commissioning that could be used to understand, anticipate and troubleshoot problems during or after the commissioning--that would be great. But they can't.
And, the people performing the installations and commissionings are, for the most part, not properly trained and do not have the required experience to do the job in a proper time frame and with the proper results.
I wish you the best of luck and success. But, you should be aware of exactly what you're getting, and we have tried to do that here. Again, the Mark VIe is a fine control system; it's more than adequate for the task and it has some excellent features. It's just not being properly programmed and presented, and the expectations are just not in line with the realities. It's a sad, sad situation. But, it's the business model that they are currently using--and it's seriously flawed.
Good day to you...I will look into the points you highlighted and be cautious during the clarifications and discussions with GE.
"I believe you said you are working on GE-design Frame 6B turbine-generators."
Yes our GT is Frame 6B. For starting means, we using AC electrical motor.
"If the unit(s) at your site have DLN (Dry Low NOx) combustors,"
yes, we are equipped with DLN combustors. Yes there is GSV but there is no GTV.
"SRV and GCV leak"-
You mean gas leak from both valves or the hydraulic oil leak?
We are equipped with gas detectors in auxiliary compartment near SRV and GCV. If any gas leaks occurs from GCV and SRV, it will detect and do alarm. But presently, we are not receiving any alarm, so can we make sure that it is not leaking. Please clarify.
Tuning for emissions control -
Our stack is equipped with analyzer for emission monitoring.
other than emission regulations, DLN tuning has any relation with firing modes?
For the wiring issued you mentioned above, we are keeping the existing terminations up to the marshaling panel and from marshaling panel to new MarkVie I/O terminal board and I/O cards , new cable will be laid and terminated. So if any issues happens, it may be due to wrong selection of terminal board or I/O card.
Waiting for your feedback.
>>"SRV and GCV leak"-
>You mean gas leak from both valves or the hydraulic oil leak?
A hydraulic oil leak from a valve actuator isn't going to be the same safety concern as if the SRV or GCV leaking internally ("passing") gas fuel. It's the valve(s) internally leaking gas fuel--not preventing the flow of gas fuel when the valve is closed/shut--that's the concern--not the hydraulic actuator of the valve leaking hydraulic oil. The internal leaking (passing) of either the SRV or GCV will allow gas fuel to flow into the piping that runs to the combustors and could cause an explosion.
The hazardous gas monitors you are talking about are primarily checking for gas leaks from flanges or valve packing--leaks that allow gas fuel to get out of the piping and pose an explosion hazard to the gas fuel module and environs.
>Tuning for emissions control -
>Our stack is equipped with analyzer for emission monitoring.
>other than emission regulations, DLN tuning has any relation
>with firing modes?
Yes; DLN tuning is important for Premix Steady-State Combustion mode operation to ensure the NOx emissions (primarily) are at or slightly below guarantee and compliance. In some parts of the world if emissions are above compliance level(s) operators and managers and ownership can be jailed, in addition to heavy fines for exceeding allowable emissions level(s).
The likelihood that DLN tuning will be required after the Mark VIe is installed is more than 50%, but probably only around 53% or 59%. Sometimes, the DLN tuning performed after an upgradation (I'm still not even sure that's really a word...) just proves the fuel splits and IGV curves and LVDT calibrations of the Mark VIe are good, and that emissions in the Premix Steady State Combustion operating range are all good and don't require any changes. Sometimes, the DLN tuning performed after an upgradation proves some small changes are required to maintain the emissions level(s) across the Premix Steady-State Combustion operating range. And, most often--in my personal experience--an outside emissions monitoring company is employed by the site receiving the upgradation to ensure the emissions level(s) are within compliance AND that the in-site stack emissions monitoring systems are also calibrated properly and providing the correct indications. (Just a few days ago, a site was trying to tune emissions using only the site emissions monitoring system but were having difficulties. When they brought in an outside emissions monitoring firm they learned the on-site O2 analyzer was off by more than 14%--which was causing the issues they were not able to solve. Fixing the O2 analyzer allowed them to properly complete the DLN tuning process. And, while this wasn't a turbine control system upgrade, the servo output cards of the turbine control system had been replaced and so DLN tuning was indicated. DLN tuning is usually performed after any mechanical outage where hot gas path parts are changed, and also recommended after a control system upgrade.)
You may get lucky and no DLN tuning is required--we don't know how serious the local air quality management agency/regulatory body is about compliance. (In some parts of the world, as long as the operators can spell DLN, everything is okay--but as was mentioned, in other parts of the world there can be criminal penalties for the operators as well as fines for the company if emissions are outside of guarantee/compliance.)
>For the wiring issued you mentioned above, we are keeping
>the existing terminations up to the marshaling panel and
>from marshaling panel to new Mark VIe I/O terminal board and
>I/O cards , new cable will be laid and terminated. So if any
>issues happens, it may be due to wrong selection of terminal
>board or I/O card.
So, the biggest problem with rip-and-replace upgrades is that in their haste to get started the electricians, under the "direction" of the field service personnel overseeing the demolition, installation and commissioning just go in and start disconnecting wires from the Mark* being removed, without checking to see that there are proper wire numbers/markings on every wire being removed and that every wire being removed is accounted for in the re-termination planning. This leads to huge problems during re-termination, loop-checking and commissioning.
This is because many Mark* panels DO NOT have Marshaling panels, and the field wiring is terminated directly to the Mark* I/O terminal boards. In your case, because new wires will be run between the Marshaling panel(s) and the Mark VIe that particular problem isn't such a concern--BUT, what someone should do is to ensure that every wire that gets removed from the Mark V is accounted for in the planning. But, similar things can happen when a Marshaling panel is used.
For example, let's say there were wires at <P> PTBA-3 & -4, -7 & -8, and -11 & -12 (which would be for the LP shaft emergency overspeed speed pick-up inputs to the <P> core--not necessary for a single-shaft GE-design Frame 6B heavy duty gas turbine). The other end of these wires might be terminated on some terminal board in the Marshaling cabinet--but they would probably NOT appear on any list of wires required for the Mark VIe. There likely wouldn't be any field wires on the other side of the Marshaling panel terminal board, but there may be.
What really has to happen is that someone--and it's likely NOT going to be the field service person performing the work for GE--has to understand EVERY wire terminated in the Mark V, and determine if the other end of that wire is terminated in the Marshaling panel, AND if there are field wires on the other side of the terminal block in the Marshaling panel. AND, if there is a device or instrument that is being used by the Mark V at the field end of the wires in the Marshaling panel.
There will likely be some jumper wires in either or both the Mark V and the Marshaling panel. The purpose of these jumper wires MUST be understood BEFORE they are removed (or before the Mark V is removed) and it must be understood if those jumpers are required for proper operation of the Mark VIe.
It's also very likely that either during the original commissioning of the Mark V that inputs or outputs were moved (for one reason or another) either at the Mark V or in the Marshaling panel and those changes were NOT documented anywhere (except in IO.ASG). So, the I/O Report (TC2KREPT.TXT wasn't edited to reflect the changes; and any Marshaling panel schematics/diagrams weren't edited to reflect the changes). This can cause problems, too. If the wiring drawings/schematics/diagrams are not correct (and they are OFTEN not correct), this can lead to many problems during a turbine control system upgrade.
That's why it's important to sort out these issues before just going in and disconnecting wires. Because if you don't understand every wire that is terminated in the Mark V, and where it's also terminated in the Marshaling panel BEFORE you try connecting the Mark VIe to the Marshaling panel--there ARE GOING TO BE PROBLEMS. And those problems are going to delay the commissioning and start-up.
This IS NOT and easy task--but I can assure you, if you will do it before the outage when there is a little bit of time to work through issues, then you won't be doing it frantically during loop-checking and commissioning, when it will delay the start-up of the unit. Maybe even by several days, or weeks. Believe it or not, a single wire can sometimes take more than an entire day to sort out and understand. The wiring between a Marshaling panel can either be EXACTLY ONLY the wires required for the Mark* to control and protect the turbine, generator and auxiliaries--OR, it can have some unused wires which were terminated at either end (in the Mark* or in the Marshaling panel) which can cause confusion if not understood BEFORE the upgradation begins. Sometimes the packager of the Mark*, when providing a Marshaling panel, wires many input and output channels between the Mark* and the Marshaling panel--and some of those are not always necessary for the unit to work properly. And, if you are trying to reconnect those wires to the Mark VIe and they aren't necessary for the Mark VIe to operate properly, you are, one, wasting time and resources doing so, and, two, causing confusion for many people.
And, again--understanding ANY and ALL jumpers (physical wire jumpers) between terminals in the Mark V and terminals in the Marshaling panel is also VERY IMPORTANT. Some will be required in the Mark VIe; some will not. The Mark VIe might even require jumpers to be in slightly different terminals to work properly. But, having a list of the jumpers in both panels, and understanding the purpose of every jumper in the two panels is very helpful if you want to have the fewest problems and delays during loop-checking and commissioning and start-up.
This may seem unnecessary and time-consuming (and money-consuming)--but I can assure you, it's time well spent BEFORE the upgrade. Because if you have to spend the time during loop-checking or commissioning it's going to be very costly in terms of frustration and the project schedule. It may even cause printed circuit cards to be damaged, which can delay the project while waiting for replacements.
There's an old saying in North America: "You can pay me now; or you can pay me later." It essentially means, if you don't spend the time and money upfront to prepare for a project or task, you will spend it later when you have issues. And, there's another saying I've heard expressed similarly in several countries around the world: "A failure to plan is a plan to fail." If you don't anticipate problems and try to mitigate them to the extent possible, then they are going to mess up your project.
This is a big undertaking, one that GE doesn't usually execute very well. Yes; there are the exceptions to the norm--but they are few and far between. And, when re-wiring a control system--even if it's just between the Mark* and the Marshaling panel--there can be lots of problems. Some even caused by unnecessary, or abandoned, wires. When GE does train their field service personnel, they ONLY train them on the Mark* turbine control system software (Toolbox or ToolboxST), and the HMI software. And the training they do give them on those two software packages isn't really the training they need to execute a turbine control system upgrade. They don't train them about how inputs and outputs are to be connected to the Mark*, and they don't usually train them about the types of inputs and outputs and how they work and what signals they are supposed to provide to the Mark*. And, they don't train them how to perform loop-checks. And, most GE field service personnel performing turbine control system upgrades can't go to the field and find devices and instruments on the turbine and auxiliaries--which adds to the problems during loop-checking and commissioning. (If you don't know where a field device is, how it's supposed to be wired to provide the proper indication, and how to determine if it is properly wired and if it is providing the proper indication, ..., it's going to be a LONG upgrade. And, when it's over, not many people are going to be very confident about the new turbine control system.
AND, then when all these "latest and greatest" software things start causing problems then people are going to really start doubting the Mark VIe--because the turbine ran pretty good before the Mark VIe was installed. So, the problem must be the Mark VIe--when in fact, the problem was the way the Mark VIe was configured and installed and commissioned. It can be done efficiently, or it can be done marginally and poorly. And, the likelihood of it being done efficiently is very low, based on the past few years of Mark VIe upgrades (both rip-and-replace, and "life extensions" or "platform upgrades"--both because of programming issues as well as wiring issues).
The rip-and-replace is the best option for upgrading a Mark V turbine control panel--far and away. BUT, there are things to be expected and to anticipate and to plan for. And, if you leave it entirely up to GE without any site personnel being involved in the planning, I think you're going to be disappointed.
Thanks CSA for the great information you shared. I will look into it. I would like to know more about DLN tuning. I searched here, but couldn't found. Appreciated if you can share me any threads.
The process of DLN tuning for GE-design heavy duty gas turbines involves measuring the oxygen content of the gases leaving the gas turbine exhaust as well as the NOx, and usually CO, contents of the exhaust gases leaving the gas turbine exhaust. Some gas turbines exhaust into an HRSG (Heat Recovery Steam Generator), and some HRSGs have auxiliary firing ("duct burner") capability. Usually, the auxiliary firing has to be turned off.
Usually, when using an outside vendor for the exhaust gas sampling/measurement it involves them taking samples at various ports around the exhaust stack in order to find the best sampling port with the least variance in measurements (called stratification). Some HRSGs also have various types of static exhaust emissions reduction and sometimes those prevent sampling only at the exit of the exhaust stack and so measurements have to be taken at the gas turbine exhaust.
Then, when the optimum sampling port is chosen the unit is usually loaded to or near Base Load (for a DLN-I combustor-equipped unit like a Frame 6B machine that means the unit has to be in Premix Combustion mode, sometimes called Premix Steady State Combustion mode). At that point a knowledgeable person, usually equipped with a special spreadsheet to record and analyze the data and often with a phone connection to a remote tuning resource (person or persons) then begins the process of changing the fuel splits between the Primary- and Secondary Combustion Zones (of a DLN-I combustor). (The fuel flow-rates to the two zones of the combustors are controlled by the Gas Fuel Splitter Valve, and so the position of the Gas Fuel Splitter Valve is changed to vary the fuel flow-rates, using the Mark* turbine control system). Usually this is done over a range of fuel splits (fuel splits are referenced to the amount of fuel flowing to the Primary Combustion Zone, with the remainder of the split flowing to the Secondary Combustion Zone). And it's often done at 0.5% increments between approximately 78% and 82% fuel splits, sometimes a little beyond the above min and max values. AND, it's necessary to wait for the emissions to settle after a fuel split change AND for the emissions monitoring equipment to purge the previous sample and draw a new sample and make the measurements. So, sometimes it can take as long as 15-30 minutes at each fuel split to get good measurements.
Then, the tuner (as the person is called) analyzes the data, and often in consultation with the remote tuning resource chooses the best fuel split to achieve the desired emissions values.
Sometimes, it's necessary to vary load over the range of the Premix Steady State Combustion mode because the IGV angles change, as well as the total fuel flow-rate, and that also can have an effect on the emissions and tuning (sometimes it's necessary to adjust the IGV control parameters as well--not always, but sometimes).
Now, some sites don't have strict emissions laws and requirements and so don't need a full and complete tune as described above. Some sites use only their on-site (in-situ) emissions monitors, and that's all the local regulatory agency or air quality agency requires--and frequent calibrations, and the records of same, are enough to certify the on-site emissions monitoring equipment is working properly and is properly calibrated.
Now, why might it be necessary to have to tune a DLN combustor-equipped unit if ONLY the turbine control system was replaced? Well, that's because the LVDT feedbacks from the gas fuel valves (the SRV, GCV and GSV in your case) and the IGVs have to be calibrated. Which really means scaled; the input to the Mark*, or the feedback from the LVDTs to the Mark*, has to be scaled correctly because the output from and LVDT is a voltage (technically it's a differential voltage) and the Mark* wants to know what percent of position ("stroke" in GE-speak) the SRV and GCV and GSV are at, and what angle (in degrees) the IGVs are at--and so the LVDT feedback has to be scaled to read in percent or degrees angle (DGA).
But, you're saying (if you're ONLY replacing the Mark* during the outage): "Why is it necessary to calibrate the LVDT feedback if the LVDTs weren't touched--and the devices which have LVDTs weren't touched?" Because, the voltage to the LVDTs (from the Mark*), and therefore the voltage feedback from the LVDTs to the Mark*, will likely change--if only by a small amount. (And, NOBODY doing a turbine control system upgrade EVER measures the LVDT excitation voltage and the LVDT feedback voltages before the old Mark* is removed.) ALSO, the components on the I/O terminal boards of the new Mark* will be different (I'm referring to the resistors and capacitors and such), as will the D/A (Digital-to-Analog) converters on the new Mark* (be different). And these little differences can add up to sometimes significant differences in percent or DGA.
Finally, the people doing the calibrations of the LVDTs will also likely NOT perform them exactly the same as the last person who performed the LVDT calibrations on the Mark* being removed. They will likely not measure the travels/positions the same as the previous person(s), nor will they use similar procedures and methods. (This is one of the maddening things about GE Mark* turbine control systems--GE does NOT provide site-specific, or even good generic, LVDT calibration procedures. And, many people (GE field service people, and site technicians) don't understand and weren't properly trained about WHAT is happening and WHY during a LVDT calibration (they think they are calibrating the SRV or the GCV or the GSV or the IGVs, and/or the servos of those devices--when really all they are calibrating is the LVDT feedback from those devices, and nothing else). So, there will be more differences in the feedbacks and scaling of the feedbacks.)
Now, you should be thinking, "If DLN tuning involves changes to the GSV position (specifically the GSV position reference), why is it necessary tune the emissions output of the gas turbine?" Because, the ACTUAL position of the GSV will be a function of the calibrated (scaled) LVDT feedback from the GSV LVDTs. And, if they weren't calibrated EXACTLY like they were when they were connected to the Mark V--then there are going to be differences. And, there's no "conversion" chart or app or program to convert Mark V LVDT calibration(s) to Mark VIe calibration(s). And, again, the individual components in the Mark VIe (the resistors and capacitors and D/A converters and such) will also be different than those in the Mark V.
So, in addition to calibrating LVDT feedbacks from all LVDTs connected to the new Mark VIe it will also be necessary to at least check/confirm/verify that the gas turbine exhaust emissions haven't changed and don't require modification to return to the same emissions as before the turbine control system upgradation (again, I'm still not sure that's even a word). (As an aside, DLN combustors can experience high pressure pulsations which can cause serious premature wear on combustor components--and that can be caused by incorrect fuel splits. It's not a common problem, but it can occur--and is another reason why DLN tuning is a good idea after a control system upgrade.)
And, now you have it: A description of DLN-I combustion tuning (generally applicable to your GE-design Frame 6B heavy duty gas turbine), as well as the reason why DLN tuning--or at least a check of the gas turbine emissions output after the outage hasn't changed and doesn't need adjustment--is required after a control system upgrade. As well as an explanation of why LVDT calibrations will be necessary after a control system upgrade.
The Mark VIe supplier will usually perform the LVDT calibrations, but they will not usually do the DLN tuning--UNLESS it's specified in the contract which they signed with your site. And, it may not even be necessary--but if it is, then they will usually specify that an emissions monitoring company be present to verify the accuracy of the on-site emissions monitoring equipment, or they should (but they rarely do) not take responsibility for the accuracy of any tuning done with Customer's on-site emissions monitoring equipment (because of the possibility of unknown inaccuracies).
And, no. We won't provide instructions or a procedure for commissioning or loop-checks or LVDT calibrations. While the general process is the same, EVERY site is different and has different expectations and different priorities and different assumptions (dangerous things those; assumptions!) and the schedule generally gets thrown out the window--except for the END date!!!--especially if there is a mechanical maintenance outage going on at the same time as the turbine control system upgrade. Which is a REALLY BAD idea--to perform a turbine control system upgrade during a mechanical maintenance outage. (The turbine control system--and it's inputs and outputs--should be powered-up for loop-checks and calibrations (the latter which require L.O. pumps and Hydraulic pumps to be running). And, the mechanics are terrified of getting shocked, and the mechanics don't usually think they have to be finished before loop-checking and commissioning begins, and so the control system upgrade falls behind schedule and gets squeezed and doesn't usually get completed correctly. And having controls technicians and mechanics working in the same area can get very crowded, and usually the mechanics get very upset about that. And, they usually win any argument or disagreement.)
Hope this helps!