I have a good experience (6+ years in Instrumentation) in thermal power plant, and now i got a chance to work in 6FA machine with MARK V control system. I need clear guidance to under the system in better way.
Need more clarity about instruments connectivity.
Tell us what have you learned from studying the P&IDs?
Have you read the System Descriptions in the Operations & Service Manuals provided with the turbine and auxiliaries? There are individual sections which correspond to each of the P&IDs.
The turbine control system includes the Mark V and the field devices and instruments shown on the P&IDs. One can't work without the other.
The Mark V is the turbine governor (fuel control, which ultimately controls speed AND limits exhaust temperature to protect the combustors, turbine nozzles, turbine blades (GE calls them blades; many other manufacturers call them buckets), and exhaust components (diffuser, and HRSG (Heat Recovery Steam Generator; "boiler"), and it is also the sequencer that controls the operation of the auxiliaries (L.O. Pumps; Hydraulic Pump(s); cooldown equipment (hydraulic ratchet or turning gear); vent fans; etc.).
To do the above, the Mark V needs inputs from speed pick-ups (passive, or inductive, self-powered speed pick-ups), thermocouples, often RTDs (Resistance Temperature Devices), vibration pick-ups ("seismic" or velocity pick-ups, and sometimes proximity pick-ups or even accelerometer pick-ups, pressure switches, temperature switches, pressure transmitterers, differential pressure transducers, sometimes temperature transmitters, sometimes level switches, limit switches, position feedback devices (usually LVDTs (Linear Variable Differential Transducers), and so on. The Mark V also drives outputs including solenoids (most often 125 VDC solenoids), motor starters (to start and stop motors of pumps and fans and the like), sometimes indicating lights, sometimes motor-operated valves and controls, sometimes valve positioners (such as Inlet Bleed Heat control valve actuators positioners), and electro-hydraulic servo-valves (those mysterious, magical and often (incorrectly) blamed valve control devices that convert an electrical signal to a device position (such as for fuel control valves or IGVs (Inlet Guide Vanes).
The Mark V often provides analog and discrete (contact closure/opening) signals to other control systems including generator excitation systems (sometimes called AVRs (Automatic Voltage Regulators), and plant control systems, often called DCS (Distributed Control Systems), or BOP, Balance-of-Plant control systems. Sometimes the Mark V tells a natural gas compressor when to start and stop, or liquid fuel forwarding systems when to start and stop.
MOST all of these input and output devices are shown on the P&IDs--the major exceptions being the motor starters and generator protection and generator interface devices, and interface signals to/from other control systems.
The operator monitors turbine operations, sends commands to and manages alarms (Process- and Diagnostic Alarms) of a Mark V and auxiliaries using an operator interface, which is a IBM-compatible PC running either MS-DOS and a proprietary disk-based operating system called IDOS or some version of MS-Windows and a graphical user interface (usually a program called CIMPLICITY, or the newer version called PROFICY Machine Edition) and a proprietary service called TCI (Turbine Control Interface). The thing to recognize about most all operator interfaces (often called HMIs (Human-Machine Interfaces) is that they do NO turbine protection or control. (There are some exceptions to this rule, but no critical control or protection is accomplished by the operator interface--that is, the control which might be done by some special bit of programming on the HMI only automates something which could be or is typically done by the human operator monitoring parameters and sending commands to the Mark V.) All protection functions of the turbine and auxiliaries are performed in the Mark V (some are performed by generator relaying and protection which send signals to the Mark V to indicate what is operating to protect the turbine, and sometimes even to trip the turbine, or initiate an automatic shutdown).
There are conditions which must be satisfied to be able to initiate a START of the turbine; these are called Start-Checks, or Start-Check Permissives. For EVERY condition which prevents a START (with one exception!) there is or should be a Process Alarm to indicate what condition is not satisfied. (The single start-check permissive which is NOT alarmed is when OFF mode is selected. To START a GE-design heavy duty gas turbine, some operating mode OTHER THAN OFF must be selected and active--so in other words, CRANK, or FIRE, or AUTO or some remote mode (REMOTE, or SERIAL REMOTE or CABLE REMOTE, etc.) must be selected, which means the operator is intending to initiate a unit START. OFF mode means the operator is NOT intending to initiate a START, and so for this reason if OFF is selected and active it is NOT an alarmed start-check permissive). There should be a display on the operator interface which lists all of the various Start-Check Permissives and the status of every permissive--including whether or not OFF is selected.
Once a START is possible and initiated and the Auxiliary L.O. Pump is running and supplying the minimum allowable pressure to the turbine and generator bearings and the unit starts accelerating from zero speed there are various speed levels which are detected. The ANSI device number for a speed level is 14, and the most important speed levels are usually L14HR, L14HM, L14HA and L14HS. (The L in the first position of most every signal name (but not all signal names!--more on that later) means it is a logic signal, it is either a "1" or a "0", True or False. When the turbine is at rest (zero speed), speed level L14HR is a logic "1" (True), and all other speed levels are a logic "0" (False). As the unit breaks aways from zero speed L14HR changes to a logic "0" (False). As the unit accelerates above minimum firing speed, L14HM becomes a logic "1" (True). As the unit accelerates above 50- or 60% speed (it varies with different sized of GE-design heavy duty gas turbines) the L14HA changes to a logic "1" (True) (and L14HM remains a logic "1" (True)). And, as the unit nears synchronous speed (usually at approximately 95% speed) L14HS becomes a logic "1" (True) (and L14HM and L14HA remain logic "1" (True)).
All of these speed signals cause various things to happen in the programming of the Mark V (called the Control Sequence Program, or the CSP). Some pumps and fans may be started when the unit breaks away from zero speed (when L14HR goes to a logic "0" (False)). For example, in order to admit fuel to the turbine the turbine speed must be above the L14HM speed level, which also usually starts the turbine "vent" (or purge) timer. As the unit accelerates to L14HA speed level usually the starting means is de-energized (for most non-F-class machines, but not usually for 6FA machines....). And, as the unit reaches the L14HS speed level some auxiliary motors are either stopped or started, and this is also a major permissive for being able to synchronize the generator to provide electrical power to the plant and/or grid.
When the unit reaches Full Speed-No Load (100% rated speed; also called synchronous speed), the Mark V is in Droop Speed Control Mode (automatically), and remains in Droop Speed Control Mode under normal operating circumstances until the unit reaches Base Load (CPR-biased exhaust temperature control). There is a display on the operator interface, the "FSR Display" (FSR means Fuel Stroke Reference, or fuel control valve position reference) which shows all of the various FSRs which are all simutaneously being calculated). They all feed into what's called a Minimum Select function, and the lowest value is the one that's actually being used to control fuel flow-rate into the turbine combustors. The various FSRs are Manual Control FSR, Acceleration Control FSR (used primarily during starting and acceleration to Full Speed-No Load (FSNL)), Droop Speed Control FSR, and Temperature Control FSR. (There is a value called Minimum FSR, but it is only used to set the absolute minimum FSR during transient conditions, including starting and shutdown, and load rejections, etc.)
The governor function of the Mark V is what controls the fuel flow-rate, and the maximum fuel flow-rate can never exceed a certain gas turbine exhaust temperature--or if it does by more than 40 deg F then the turbine will be tripped.
A turbine trip means some condition has been detected which requires immediate shut-off of the fuel flow-rate to the turbine. This in turns results in opening of the generator breaker (when synchronized to a grid and producing electrical power), and the unit then coasts down to zero speed and cooldown.
A trip is VERY different from a shutdown, which is an orderly reduction of load, opening of the generator breaker, and a fired shutdown of the unit until finally fuel flow is shut off (usually at about 20% speed if the unit is running on natural gas fuel; often higher if it is running on liquid fuel). Don't say "trip" when you mean "shutdown", and vice versa. They mean two entirely different things, and can cause a great deal of confusion when talking to people knowledgeable about GE-design heavy duty gas turbine operation.
Now, many GE-design 6FA heavy duty gas turbines have what are called DLN (Dry Low NOx) combustion systems. Some don't, and some even have what are called MNQC (Multi-Nozzle Quiet Combustors). Those without DLN combustors have conventional combustors, which means all of the fuel burns in a diffusion flame inside each combustor. It's simple, BUT it also produces a LOT of harmful exhaust emissions--hence the reason for DLN combustor. Why DLN? Well, because prior to DLN combustion systems the only way to reduce exhaust emissions was to inject water or steam into the combustor--and that water or steam was then exhausted to the atmosphere through the exhaust stack, lost and gone forever to the environment. And the water or steam has to be treated to make it boiler-quality water, which is not cheap--and often the water itself is costly, too. So, DLN combustion systems were developed--and they require a good deal of control interaction.
Probably foremost in DLN controls is IGV (Inlet Guide Vane) control. This is similar to the throttle body of a carburetor or fuel injection system in an automobile or lorry (diesel truck) in that the IGVs control (limit) the air flow into the turbine, which in turns affects how much fuel can be burned and in a DLN system the mode of combustion. (DLN combustion systems have various modes which are also controlled by the Mark V based on a calculated temperature value, TTRF or TTRF1--the Turbine Temperature Reference, Firing, or the Firing Temperature.
[Have you seen how the characters in GE-design heavy duty gas turbine control systems all have meaning? The one I didn't explain previously was the "H" in L14Hx, which stands for the High-pressure shaft of a turbine (some turbines may have a second shaft, called the LP, or low-pressure shaft; 6FAs only have a single shaft, the high-pressure (HP) shaft). And the L in the first position of a signal name almost always means the signal is a logic signal (it can only be a logic "1" or a logic "0", and, if written correctly (and most signals are written correctly) the signal name tells you when the signal will be a logic "1". For example, L14HR is a logic "1" when the unit is at rest (zero speed). L14HM is a logic "1" when the unit is above minimum firing speed. L14HS is a logic "w" when the unit is near or at synchronous speed. And, the 14 indicates a speed level. A 63 indicates a signal from a pressure switch. A 33 indicates a signal from a limit switch. And so on. You can find lists of ANSI device numbers by using your preferred World Wide Web search engine. You need to have one, and commit the device numbers to memory since they are key to understanding the signals in the CSP (Control Sequence Program). And, signals other than logic signals, well, as with FSR and TTRF/TTRF1, well they also have meaning too. For example, CPD means Compressor Pressure, Discharge, or the Axial Compressor Discharge Pressure. TTXD1 means Turbine Temperature eXhaust Discharge #1, or the #1 thermocuple signal from the gas turbine exhaust. And so on. There is a file on the operator called LONGNAME.DAT, which has most of the signal name descriptions for most of the signals in the CSP. And they are mostly correct--but beware, not every signal name description in LONGNAME.DAT is 100% correct. Use it a guide, but remember it can sometimes (though not often) be misleading. But, it's the best place to start. LONGNAME.DAT is a basic, ASCII text file. It can be formatted and printed using MS-Word or any ASCII text editor. You should have your own printed copy of it, and make notes on it when you find any errors.]
There have been MANY threads on control.com in the past about how to "read" (interpret) GE-design heavy duty gas turbine programs (CSPs, or applicaton code for Mark VI and Mark VIe). The basic premise of any GE-design heavy duty gas turbine control logic and sequencing (EXCEPT Mark II SpeedTronic control systems!) is relay-ladder diagram style logic. If you search on control.com for "L4" you will find a series of threads which explain in some detail how to interpret relay ladder diagram rungs and GE-design heavy duty gas turbine control signal names.
The last thing I want to mention about GE-design heavy duty gas turbine control is: Alarm Management. The Mark IV has the capability to have more than 500 Process Alarms (alarms related to the turbine, auxiliaries, and generator) and more than a thousand Diagnostic Alarms (alarms related to the "health" of the Mark V hardware and any software issues the hardware might be having). For this reason, and because many turbines were not commissioned properly, the Mark V (or Mark VI or Mark VIe, as the case may be) can be, and is, thought of a giant alarm annunciator, and that it is normal and accepted practice that many nuisance and erroneous alarms are continually being annunciated by the Mark V (or Mark VI or Mark VIe, as the case may be). This is simply NOT TRUE. Proper commissioning and proper maintenance and proper Alarm Management should only result in true alarms being annunciated by the Mark V (or Mark VI or Mark VIe, as the case may be). It IS possible for any Mark* control system to be properly configured and maintained so that only meaningful and true alarms are annunciated. As a C&I (or I&C) technician, it should be the goal to work to get the Mark* configured so that ONLY meaningful alarms are annunciated when they are actual true alarm conditions. ONLY by doing this will the operators, their supervisors and other control technicians be able to properly troublehsoot and maintain a GE-design heavy duty gas turbine with a Mark* control system.
Alarm Logs--printed or electronic--are also CRITICAL to troubleshooting a GE-design heavy duty turbine. They are often overlooked until the unit trips (usually for an "unknown" reason--though there is RARELY a true unknown turbine trip, because, as with Start-Check Permissive EVERY condition that results in a turbine trip should have a Process Alarm associated with it), and then without a printed or electronic list of alarms prior to and when the turbine tripped it is virtually impossible to say for sure what happened, and when it happened. And, yet many plants do not maintain the Alarm Printers (simple, dot matrix printers) and do not know how to access the electronic alarm logs (only available on MS-Windows-based operator interfaces).
Alarm Management involves these very important functions:
Every alarm (even Diagnostic Alarms) should result in the sounding of an audible alarm horn. (Because of the problem with commissioning and configuration and maintenance of many Mark V (or Mark VI or Mark VIe, as the case may be) control systems, the audible alarm horn has been diasbled). The purpose of the audible alarm horn is to get the operator's attention. Once that's done, the operator needs to silence the audible alarm horn.
The next thing the operator needs to do is to read the alarm text message. Once the operator has read the message and has decided what action to take, the alarm needs to be acknowledged--meaning that the operator has read the message and is deciding on the action to take to resolve the alarm message.
Next, the operator needs to take appropriate action. If that means the unit needs to be unloaded to some lower load level, then that's what needs to be done. If the operator is unsure about the message and what it's trying to alert the operator to (which should NEVER happen because operators should be trained to respond to all alarms, Process or Diagnostic--think about it, the operator is responsible for a multi-million USD (US Dollar) machine burning highly explosive fuel!!!) the operator should summon a C&I (or (&C) technician and/or an operations supervisor to help with deciding the proper course of action to resolve the alarm--to make the alarm condition "stop" or "go away."
Finally, once the alarm condition has been resolved, the alarm needs to be "reset" to clear it from the Alarm Display. NO ALARM CAN BE RESET IT HASN'T BEEN ACKNOWLEDGED.
Silence. Acknowledge. Resolve. Reset. Alarm Management. If the same alarm always occurs at the same time during starting or stopping, then it should be investigated and resolved. It IS NOT acceptable to have repeated alarms which are not real and true and which, if true, may lead to eventual damage and failure of some part of the turbine or the auxiliaries. The operator's job is NOT simply to push START or STOP or to enter a load command reference. The most important part of the operator's job is properly manage alarms--to take appropriate action whenever an alarm is annunciated. And, that means the operators and C&I (or I&C) technicians and operation supervisors and plant managers and mechanical department personnel all need to work together to resolve nuisance and erroneous alarms--no matter how arduous the task.
Now, you should be able to find somewhere on site a copy of a training manual which was probably provided during the initial training which almost every site gets prior to commissioning (which is the WRONG time to get training, by the way!). Find that manual, and you will (should) find more useful information.
If you have specific questions--feel free to ask here. But, also use the 'Search' feature of control.com to look for answers to prior questions, and you will also likely find information you didn't even know you needed. If you need clarification, we are here to help. But, if you think someone is going to send you a detailed written description or video of how a Mark V-controlled GE-design 6FA heavy duty gas turbine is operated, controlled and protected and how the Mark V works--just get that thought out of your head. No such thing exists.
Let's just say the OEM has basically dropped support for the Mark V, including most training. There are a couple of third-party training course providers, but really only one (that I'm aware of) that actually has a Mark V to give hands-on training with.
One of the things that happens in today's power generation environment is that technicians have responsibility for many different control systems. The Mark* line of GE turbine control systems is very reliable and for the most part reasonably robust. So, even if one gets factory training it may be two, three or more years before one has to use the training and it's usually forgotten by then. I've personally been to sites to assist with issues where Management belittled the technician for not being able to solve a problem after having been sent to factory training more than three years ago--and that same Manager was angry at me because he had to pay for me to solve the problem. (Sometimes it's a no-win situation for everyone.)
Another thing that happens very frequently in both first-, second- and third-world countries is that when someone is sent to or receives factory training that individual quickly shops that training around to find an employer who will pay more than they are currently earning and they take that knowledge with them to a higher-paying job. There is little or no loyalty between employers and employees these days, and employers are often reluctant to send their employees for training because of the likelihood the employee will not stay for long.
There are many smart, motivated individuals who can dig in and solve problems and learn new systems. But that requires access to manuals which are often locked away in some Manager's office and a strong desire to dig and learn. Many Managers are quick to blame the control system and the OEM for poor maintenance and lack of training and knowledge and experience, some even realizing they are asking technicians to do a lot with very little (training and experience).
Finally, the factory training given by this OEM was usually very lacking in the fundamentals and didn't really cover basic necessities. And it was expensive. So, while this seems like a reasonable question and solution it's very complicated--more so than the control system.
If VJ can form the question better we can provide better responses. Unfortunately, the question is very vague and extremely broad. Field devices and instruments are connected to the control system by wires, but I don't think that's the answer the original poster is looking for. I'm always trying to remember how daunting this all seemed to me in the beginning and what the keys were for me to begin to grasp what was happening--and how. And when there's a language difference that can make things more difficult, too. Just asking a question can be intimidating and lead to misunderstanding and confusion.
Hopefully VJ will be patient and a lot more specific and we can go from there.
Maybe this will help....
One of the best ways to understand the I/O connected to the Mark V is to obtain a copy of the I/O Report. It is an ASCII text file located in the F:\UNIT1 directory named TC2KREPT.TXT. A printed copy is best, but it is a document that is formatted for landscape printing and a small, compressed font, and doesn't lend itself well to being printed (even though it is an ASCII text file). I'll try to look around to see if I can locate some instructions for printing the file more easily. ONE THING TO KNOW about the I/O Report: It was produced at the GE factory in Salem, VA, USA, and if any changes to I/O were made in the field by commissioning personnel or customer personnel the changes had to have been MANUALLY made (using an ASCII text editor) in the TC2KREPT.TXT file. So, it's not always up-to-date, but it should be fairly close and is still a good reference.
There is another ASCII text file in the F:\UNIT1 directory, IO.ASG. IT IS exactly reflective of how the I/O is currently connected to the Mark V, but it not very easy to understand or to use as a guide to understanding how I/O is connected. The I/O Report is better organized, but someone can use IO.ASG to make the necessary changes to the I/O Report (either in pencil on a printed copy, or using an ASCII text editor). But, these two files, which are usually present on every gas turbine Mark V operator interface, are the best information about how I/O is physically terminated--with the caveat above.
The Mark V Application Manual, GEH-6195, has an appendix, Appendix D, called the Signal Flow Diagrams. These are generic drawings, and include optional cards which are not always present in every Mark V panel, which show physical terminations and then how the input channel flows through the various cards ion the Mark V making its way into the CDB (the Control signal DataBase), and it shows for output signals the terminal board points and then how the signals flow from to the terminal board points from the other cards in the Mark V.
Using the I/O Report, IO.ASG, and the signal flow diagrams is the best way to get an understanding of how I/O is connected to the Mark V.
The I/O (instruments; field devices) connected to the Mark V are NOT done in a random manner. The Mark V has three redundant control processors (<R>, <S>, & <T>--collectively known as <Q>), and a single "communicator" processor called <C>. There is also a Protective core, <P>.
<Q> have one, sometimes two, digital I/O cores: <QD1>, and an optional <QD2>. <C> has it's own digital I/O core, <CD>. Digital I/O cores handle discrete (contact) inputs and discrete (contact outputs). Some of the contact outputs can be powered from the Mark V, and some are dedicated for particular functions and have some external devices in the circuit served by them.
There are I/O terminal boards on each of <R>, <S> and <T>, in locations 6, 7, 8 & 9 on <R> and <S>, and in location 6 on <T>. These terminal boards are where the most important, and in some cases critical, analog inputs are connected. The terminal boards in location 6 are the QTBA terminal boards--they handle I/O that is triple redundant, or dual redundant, in nature, such as speed pick-ups (each of <R>, <S> & <T> gets its own individual speed pick-up, 77NH-1, -2 and -3), and servo-valve outputs. I don't have access to drawings at this time but if I recall correctly LVDT excitation is connected to the three QTBAs (generally there are only two LVDTs per device, these being dual redundant devices, and no two LVDTs from a single device (such as the IGVs) are connected to the same processor's LVDT excitation (if they were, and that processor failed or had to be powered-down while the unit was running, the feedback from both of the LVDTs excited by that processor would be lost to the other processors)).
I believe the TBQA is mounted on <R> and it handles the critical thermocouples (usually the exhaust T/Cs and gas fuel temperature monitoring T/Cs, and the axial compressor discharge temperature T/Cs, and often the inlet ambient air temperature monitoring T/Cs). This board has three groups of T/C input channels, one directly connected to <R>, the second directly connected to <S>, and the third directly connected to <T>. All of the three control processors know what the other processor's T/C values are, but critical T/C inputs are divided between the three control processors for redundancy purposes--in the event a single control processor fails or is powered-down when the unit is running there are still two control processors with working critical T/C inputs.
The other terminal boards on <R> and <S> mostly fan out the various analog signals to the three control processors, and in a couple of specific cases I believe one of the other I/O terminal boards on <R> also has some circuits which are directly connected to <R>, <S> & <T>.
The overspeed trip speed pick-ups (77HT-1, -2 & -3), flame detectors (as many as eight flame detectors), and fuel stop valve solenoids (electrical trip devices) are connected to the terminal board on <P> in location 6. There are three protective processors in <P>: <X>, in location 1, <Y> in location 3 and <Z> in location 5. There is a trip card in location 4 which has primary trip relays, emergency trip relays, and synchronization relays on it. And, there is an auxiliary signal conditioning board in location 2 of <P>.
This should be enough to get the original poster started on his journey about instrument connectivity. We can answer more questions if they are more specific. We cannot post drawings or sketches or files to control.com, so the original poster is going to have to do some digging to get the documents mentioned above to begin understanding the I/O connectivity in more detail.
Hope this helps!
Now, now. No need for all cap's. It was a fair question, and unless one is familiar with the line of control systems and the OEM's (lack of) support for "older" control systems a reasonable one.
It's been written many times before on control.com--if you want to learn about GE-design heavy duty gas turbine control and operation you have to be willing to dig into the manuals, find the P&IDs, and associated drawings and documents, and study. You can ask questions here and we will do our best to respond to clear and unambiguous requests.
To be a good GE-design heavy duty gas turbine control technician, one really needs to be a good GE-design heavy duty gas turbine operator. By that I mean that one needs to know what's supposed to happen when--and what's not supposed to happen when. The best way to "learn" that, because most operators of GE-design heavy duty gas turbines DON'T know those two things (all they know is how to click on START and change the Pre-Selected Load Control Setpoint (reference) and silence the audible alarm (if it's even working)) is to learn to "read" the CSP (the name for the Control Sequence Program, the "logic" program running in the Mark V). Because the CSP running in the Mark V at your site is how the turbine at your site is going to run--not what's written in some manual or some document. GE makes WAY too many changes between units and doesn't document them so you MUST learn to be able to read the CSP in order to figure out what's supposed to happen when, and what's not, so that when an operator says the "Mark V" isn't doing what it should, or is doing something different than it has ever done before, you can say, "No; it's doing EXACTLY what it should be doing," or, "You're right, it's not doing what it should be doing," or, "It's always done that."
"Learning the Mark*" is MUCH more than just learning the Mark V (or VI or VIe)--because it needs inputs and outputs to do it's job, and to know if the Mark* is doing it's job correctly one needs to be able to learn what it's supposed to be doing and when, and to be able to say with authority, "It's always done that," or, "It's never done that."
Let's try this another way. Can you please list the documents you have in your possession? For example, have you been able to obtain copies of the P&IDs (GE calls them "Piping Schematics" or "Schematic Piping Diagrams")?
Have you been able to find a printed copy of the I/O Report?
Do you have printed copies of the three main Mark V manuals:
Users' Manual, GEH-5979
Maintenance Manual, GEH-5980
Application Manual, GEH-6195
What operator interface do you have: an <I> (running IDOS and a proprietary graphical user interface), or, a GE Mark V HMI running some version of MS-Windows and a program called CIMPLICITY (with two background services, TCI and CIMBRIDGE)?
Have you been able to find a copy of the Device Summary? (This lists the device calibration information for most, BUT NOT ALL, of the I/O which is present on the turbine and most of the auxiliaries, but not generally including the generator protective relaying and metering in the Generator Protection Panel (GPP).)
Have you been able to find a copy of a training manual which might have been used when the unit was first installed/commissioned? (Usually, there are "extra" copies of the initial training manuals which end up on some bookshelf/bookcase with the Operations & Service Manuals.)
Have you been able to get access to the Operations & Service Manuals?
You say you have power plant instrumentation experience; can you say specifically what kind of information you are looking for? Are you only working on the instrumentation--performing device operation verification (sometimes called "calibration") and repair/replacement? Are you responsible for troubleshooting turbine and auxiliary operation?
The more specific you can be, the more concise and responsive we can be. The temperature switches and pressure switches and pressure transmitters and thermocouples and RTDs and speed pick-ups used on a GE-design Frame 6FA heavy duty gas turbine and auxiliaries are extremely similar to those used on many other power generation equipment (boilers; reciprocating engines; etc.). The devices you may not have encountered previously would likely include vibration sensors (proximity type and velocity ("seismic") type), LVDTs (Linear Variable Differential Transducers), flame sensors (the Mark V REQUIRES flame sensing to interface with 335 VDC input channels; many Mark Vs use a 4-10 mA flame sensor called a Flame Trakker manufactured by Reuter-Stokes (a GE company) and interfacing through a 4-20 mA to high voltage pulse rate converter), and electro-hydraulic servo valves (usually ones manufactured by Moog). None of these devices/instruments are magical or mysterious, but there is not much written about them and not much in the Operations and Service Manuals (unfortunately).
Control.com has a very fast and excellent 'Search' feature, cleverly hidden at the far right of the Menu bar at the top of every control.com webpage (unless you are using the mobile version, in which case it's even more cleverly hidden under the 'control.com' tab on the Menu bar...). It is HIGHLY recommended to use the Search 'Help' the first couple of times you use the Search feature because the syntax of search commands is probably not like the one in your preferred World Wide Web search engine--but it is just as, if not more, powerful than your preferred World Wide Web search engine. The GE-design heavy duty gas turbine controls community here at control.com has been very active for more nearly 15 years, if not longer. And, in that time we have covered a LOT of various topics, most having to do with GE-design heavy duty gas turbine control systems and GE-design heavy duty gas turbine operation, but also with some mechanical issues related to GE-design heavy duty gas turbines and auxiliaries. So, there are a LOT of threads with a LOT of information, if you're willing to search for them in what are called the control.com Archives.
Happy searching! And, again--the more specific you can be, the more concise and prompt our responses will be. Help us to help you! It's all free. All we ask is that if you find the information provided to be helpful (either in threads you originate, or in past threads) that you either click on the 'Thumbs up' icon or reply to let others who read these threads that the information was helpful and how you used it to solve your problem. On the other hand, if you find the information not useful, you are also encouraged to send a reply to tell us how the information could have been more useful or why it wasn't useful to you. (You can also click on the 'Thumbs down' icon if you're not happy with the information provided, but if you only do that when you're unsatisfied with the information provided we won't know how it could have been better or more helpful. Again, help us to help you. It's all free.)
There are various companies who provide MKV Training, try Googling around, I'm sure you can find them.
I just googled GE Mark V Training. Looks like there is a class in Houston on September 17-28.
I took the GE Mark V training class when it was in Salem. It is good. You need to be familiar with the equipment and documentation before taking it.
I have taken three GE offered training courses. They were using retired GE persons at the time, to teach the classes.
If you do choose to take a GE training or any training for that matter, don't take it easy on the instructors. Make sure they teach you what you want to know. If you don't understand something, stop them. I guarantee you will not be the only one who doesn't understand what is going on.
I have sat in too many training classes where students will not understand a more advanced topic, because when the basics were being taught they just sat their nodding their heads.
When I was took the class, HPC technical and Gas Turbine Controls were also offering it.