This issue pertains to establishing the feasibility of using an autosychroniser to reverse synchronise two GTG's (Frame-5, site rated for 19MWe electrical) with a running load of about 15MW to a grid. We are building a new co-generation power plant involving 2 nos frame-5 Gas Turbines with Mark-Vi controller complete with auto synchroniser.

The normal operation is to operate the two units in parallel at 33kV using a GSU Transformer. The two units would be snychronised either in auto mode or manual mode. One additional requirement is to sychronise these two units in parallel feeding a load of about 15MW with the grid automatically, after a grid islanding situation and grid needs to be restored, normally with little power export.

When the GTG manufactrer was approached, it was informed that the auto synhronsing through the Mark-Vi when the units already in parallel with the grid is not possible. So the question is as follows:

a) Can a seperate auto synchroniser be used for reverse sycnhronising?

b) What should be the prefered mode of operation of the running GTG's (Base Load, Part Load, Pre set Load) Isochronous or Droop.

c) What precautions need to be taken to prevent system out of step operation (GTG's tripping due to large power swings)

 

What do you mean by "reverse synchronize"? Are you referring to synchronizing to the grid after being separated from the grid and operating while in "island" mode?

By using the appropriate equipment (which sometimes includes phase-shifting transformers and interposing relays), the Mark VI can synchronize across more than one breaker, such as the normal generator breaker and a tie-line breaker, such as between a plant and grid. So, if the tie-line breaker were open and the generator breaker were closed (as would be the case during "island" mode operation), an interposing relay could be used to switch one or more PTs to the Mark VI inputs and the autosynchronizing function could be used to close the tie-line breaker.

It would take some engineering to develop a scheme that could be employed to use the Mark VI of one turbine to auto synch the tie-line breaker. With a little more engineering, either Mark VI could be used. But it's not a function of whether or not the Mark VI can do it, it's how the PTs and the breaker close circuits are connected to the Mark VI(s). Because the Mark VI has been used many times to auto synch two breakers on many units. It doesn't care what breaker is being synchronized across, as long as the phasing of the PT inputs is correct. There would be some minimal logic changes which would be required, but it's been done before.

It would seem the only difference here is that from what can be understood from this post is that the two Frame 5s are paralleled with each other upstream of a single step-up transformer, and the high side of the transformer can be connected to the grid through a tie-line breaker. Unless there's something we're not aware of, this is not unheard; unusual, but not impossible to deal with.

But, if the question was asked of the GTG manufacturer like it was here, it's likely the GTG manufacturer just said no because they couldn't understand the question either. It's hoped that a drawing of the power system was provided with the question for the GTG manufacturer to try to understand what was being asked.

When units are running in "island" mode, no unit can be operated in Base Load if the total load on the "island" is less than the Base Load rating of either unit. Well, I take that back, someone could select Base Load on a unit operating in droop speed control mode and the frequency would go high. And, then ask why that happened.

If two units are paralleled to each other in "island" mode, and if the load is not very stable and changes when large motors are started and stopped and load is added or subtracted from the "island", then one unit should be in Isochronous mode and the other should be in Droop mode. Or, you could use Isochronous Load Sharing mode, or some form of Isochronous Load Sharing, But, if both units are operated in Droop mode, the operators will have quite a job trying to control frequency.

'Out of step' operation with respect to large load swings? Huh? If one unit is in Isochronous mode, it should be able to respond to most load swings *if the load is properly balanced between the two units if two units are being operated in parallel with each other in "island" mode*. But, today, most operators just don't understand how to balance loads between multiple units during "island" mode operation. Isochronous Load Sharing schemes can help with this, but operators must be properly trained. I've seen a lot of attempts at using PMS (Power Management Systems) to try to automate what human operators should be able to do (but don't seem to be able to very well) and they have all been pretty much failures.

 

Thank you CSA for some valuable insights. However, please note some of the points which were misunderstood, may be poor communication from my end!

a) Reverse sychronsing: Your interpretation is correct!

b) Each GT is connected to the 33kV Bus through a dedicated GSU transformer and common three winding GSU (as interpreted by you) is not provided.

c) However, my main query has not been answered! While, I do agree that suitable control wiring hardware can be configured in the control panel for PT switching (In this case phase shifting transformer is not required, as we are talking of synchronising at 33kV!). What should be the operating position of the Mark-VI and the AVR when two GTG's which are running in parallel have to be synchronised with the grid using an autosynchroniser. (For example: To which Mark-Vi or the AVR would the autosychrniser send the raise/lower command, or, should we have suitable interposing relays to multiply the raise/lower contact and route them to the governer and AVR of both the units simulataneously?

Also what should be the mode of operation Droop or isochronous or does not make any difference? Appreciate if you could clarify this.

 

Thanks for some of the clarifications. However, pl note the folowing:

a) Your interpretation of reverse synchronsing is correct.

b) While I have read though your clarification, my main question is still not answered. When the two GTG's are in parallel thorugh their respective GSU's (the GSU is not common!) and now we need to use an autosychroniser to close the line breaker, then what should be the governor operating mode of the GTG's, ie should it be Droop mode or Ischo. Also, Should the autosynchroniser send corrective raise/lower signals/command to both the units or to one only. If only one, then should it be for the isochornous generator?.

MM

 

If you have two turbines running in parallel in "island" mode, whether or not they have separate GSUs or a common GSU, and you want to have good frequency control one of the units will need to be in Isochronous control. When the "island" is resynchronized to a larger grid, that unit will have to change to Droop control, either automatically (by some interlock from the tie-line breaker), or prior to synchronizing by the operator.

In general, most sites seem to try to stabilize the "island" load, and then manually switch the Isoch unit to Droop, and then re-synchronize to the grid. Either unit can be used to do that, and when you change the speed setpoint of one unit the other will follow (because they're synchronous generators operating in parallel whether or not one is in Isoch or both are in Droop).

 

It bears clarification per your original post, question 'b': Base Load and Pre-Selected Load are load control selections, not modes of operation. Part Load operation is Droop speed control when no load control is selected. Isochronous and Droop control are governor modes. Your original question asked what should be the preferred mode of operation, and there was no direct mention of AVR.

The response to how the units should be operated was that for the most stable and easiest operation (for the operators) would be to have one unit in Isoch mode and the other in Droop, or to have some form of Isoch Load Sharing. It was also stated that in the scenario you described, it was not possible to operated either unit in Base Load and maintain stable frequency.

I wish to add that when a unit is in Isoch control, it cannot be operated in any kind of load control because the load will change in response to the load of the "island". If someone wants to increase or decrease the load on the Isoch unit when it's being operated in parallel with a Droop unit, one has to decrease or increase the load on the Droop unit, respectively.

Again, there was never any mention of AVR control in the first post. As long as the exciter regulators are properly adjusted, there shouldn't be any problem.

I want to also point out that it's *typical* for the generator PT to be used for synchronizing across both the generator breaker and the tie-line breaker. So, unless a third set of PTs was added and both sets of PTs were switched when synchronizing across the tie-line breaker (which could be done), it would likely be required to have some kind of phase-shifting transformer.

 

Thanks CSA, for your clarifications.

Have a nice day