Can anybody describe how the set point for supplementary duct firing is calculated?

Regards
SSV

 

SSV... I suggest you get a copy of the Power Magazine "How to" article published in their May 2006 issue!

Regards, Phil Corso

 

Not without a whole lot more information than you have provided!

Supplemental duct firing control (at least on GE turbines) is custom designed for each project according to customer specification (contract) requirements. You might try reading your configuration software documents and system descriptions.

 

I am looking for duct firing control in a combine cycle plant with 2 GTs and 1 ST. In this configuration how the load setpoint has to be calculated for the duct firing control?

Regards,
SSV

 

We have just commissioned a combined cycle gas fired station with three GE gas turbines, a steamer and 90 MW of supplementary firing on the HRSG's. We can input any MW demand from 315 MW to 630 and our megawatt demand takes us there within 1 MW.

Let me know your configuration and I'll detail the logic

 

Duct burner setpoint in combined cycle power plant is calculated by heat balance calculation. Input heat are GTG Exhaust (Calculated by mass flow of flue gas, Specific heat & Exhaust Temp), duct burner load (unknown ?), outputs are ST load, ejector steam & Dev from HP unit pressure control.

 

otised,

I'm pasting this from a previous posting from SSV:

>Fourthly, I am working on retrofit of GE steam
>turbine (from MARK III control to Ovation DCS).
>So are these gas turbine droop control
>fundamentals applicable to steam turbine also ?
>(obviously not exhaust temp. control) I am
>asking only for droop speed control / preselect
>load control.

It was posted to thread:

http://control.com/thread/1271996295#1272180843

 

I am not entirely sure what you are looking for. For steam turbine control, for a straight steam plant, the fundamentals of droop control for gas turbine and steam turbine would be similar, assuming the boiler control can react quickly to the response of the steam turbine inlet control valves.

For a combined cycle unit, the fundamentals are still generally applicable, especially over the range of the supplemental firing - the duct burners can respond quickly to steam turbine demand changes. Further, if the steam turbine generator and the gas turbine generators are all connected to the same outgoing transmission line, then the gas turbines would be changing load along with the steam turbine in a similar fashion, and this would probably work correctly. If the steam turbine generator is feeding a different transmission line than the gas turbine generators, and the duct burners are off, then there may be some response time issues. If the impact is to decrease load, then the bypass valves may open until the GT load is decreased. If the impact is to increase load, there will be a longer delay on the steam side as it will have to wait for gas turbine load increase or for duct burner firing to take place.

Whatever load control for the combined cycle plant is in place will impact this, as well. You could need to have a power system stability study done - a lot of interesting things (academically speaking) can happen when multi-shaft combined cycle generators are operated as individual generators rather than as a single generator.

 

A Combined-Cycle plant is a multi-variable process so there are a few control strategies that will work when one wants to control MW at setpoint.

If you want to increase MW production, you can increase your duct firing setpoint or you can increase your GT load:

- Increasing your duct firing setpoint will results in a gradual increase in MW since the process dynamics of the water cycle are slow. So increasing duct firing is great but will results in a slower MW response

- Increase GT Load will result in an immediate MW response.
Typically, your MW Controller would be similar to a split-range logic where GT load is increased first followed by duct firing when GT Load is maxed. Also don't forget that the maximum load on the burner in GT dependan.

Ben

 

Dear CSA,

Actually I am working on multiple projects. And the content which you pasted here are for some other project. It would be good to delete what you have pasted in this thread because this thread is meant for duct firing control otherwise people might get confused. Thanks in advance!

Ok, I have found now how the SP is calculated for duct firing and the overall control, which I want to share but its a bit long concept which uses 4 PID loops. Here is the concept:

One PID (PID no.1) ensures that the HP drum startup temperature rate is not violated by restricting the output to the control valves should the other PIDs request a faster ramp rate. The other PIDs are used to control either steam turbine megawatts or the steam turbine throttle pressure depending on the duct burner mode of operation, which is described below.

When the duct burner is in megawatt control mode, SP will be from the operator or from AGC/ Station Master and the PV will be steam turbine actual MW. This PID (PID no.2) will distribute to each duct burner fuel gas flow contol valve via (PID no.4).

Now when the duct burner mode is boiler follow-up mode then setpoint (SP) is calculate as a function of HP steam flow whereas the steam turbine throttle pressure as the process variable (PV)for PID no.3. Moreover the duct burner boiler follow up mode is not allowed if the turbine is in inlet pressure control mode (IPC).

Whether the mode is MW control or boiler follow, the output of the respective control loop becomes the SP for the duct burner fuel gas flow control valve loop (PID no.4) that uses the corrected duct burner flow as the PV. And the output of this loop is compared to the HP drum startup temperature ramp rate PID (PID no.1) output and the smaller of the two is passed to the fuel gas control valves.

Thanks! guys for your replies.
Regards,
SSV