Synchronous Generator: Will these loops interact? 5

[williamlove]

I am tasked with designing a PID control strategy for a system that will use fluid power to turn the shaft of a synchronous generator. My question is whether my planned control strategy will work, and specifically, will my two PID loops interact and therefore not work well.

The generator will be connected to the local grid. The fluid power will be created by a new innovative system that extracts energy from the temperature differential of hot water heated by a massive solar array and cold sea water and creates pressured flow of hydraulic oil. The fluid power from the hydraulic oil will be transferred by using it to spin the shaft of a synchronous generator. Before turning the shaft it passes through a control valve.

There are two measured variables: Kilowatts (kW) and power factor (PF) are measured at a control device where the power is transferred to the grid and are available to our control system as 4-20mA input signals. There are two control variables our control system can manipulate with analog outputs: the position of the control valve that regulates flow of the hydraulic oil, and the excitation current to the synchronous generator.

CONTROL LOOPS:
1. Kilowatt (kW) controller whose PV is kilowatts (available as an analog input from the device connecting the generator to the grid) and whose CV is the position of the valve allowing fluid power to be delivered to the generator shaft. (The setpoint is 250kW which is what the generator is designed to produce.) This will be a relatively slow acting loop.
2. Power Factor (PF) controller whose PV is the power factor (available as an analog input) and whose CV is the excitation current to the synchronous generator. This will be a relatively fast acting loop.

CONTROL STRATEGY:
• Ramp open the valve until the generator RPM is at the design point (1800). No excitation is applied to the generator and the generator is not connected to the grid yet.
• Apply a specified excitation and put the generator online.
• With the kW controller in manual, ramp open the valve slowly to a specified value (say 80%) that is known from design and experimental confirmation to result in 250kW. During this time the excitation controller is allowed to operate in auto. It is expected that it will raise the excitation current as valve opens and kW increases. So in effect, both the valve position and excitation are ramped up.
• The kW controller is placed in auto. When cloud cover results in slowly dropping kW, the KW controller will slowly open the valve. When fluid power recovers due to restored sunlight the KW controller will slowly close the valve. It is expected that the PF controller will not interact with the kW controller since the latter is slow acting.
• Additional algorithms will determine when to take the generator offline, usually due to nightfall.

 

[waross]

You don't need much control at 250 kW. Once on the grid you don't even need a governor. Whatever you do, don't try to use integral or derivative on the controller.
The grid will set the speed and the power input to the prime mover will control the kW output. Your voltage setting relative to the grids voltage will determine the power factor.
You only need a governor to make synchronizing easier and to protect your set from overspeed in the event the connection to the grid is lost.
Dialing offset into the governor or speed controller is an easy, dependable, proven way to control the power output of a small generator that is running in parallel with the grid or a larger generator.
One thing concerns me. On a diesel set the governor controls the fuel rack and the mass of fuel injected into the engine. No problem. On a steam driven set, the governor controls the steam feed valve, but it also indirectly controls the fuel feed to the boiler. As the steam valve opens up and starts to supply more steam to the turbine, the boiler pressure drops. Another control loop is watching the boiler pressure. As the boiler pressure drops, the controls increase the fuel feed to the boiler to maintain the boiler pressure. As the load drops off, the valve throttles the steam and the boiler pressure rises. The controls reduce the fuel fed to the boiler.
The governor gives fine control and the boiler fuel feed gives coarse control. The slightly varying pressure in the boiler acts as a buffer.
If you are using a control valve to throttle your input fluid, be sure that your system is capable of either absorbing the extra energy or capable of cascading back and controlling the energy input to the system.
If your system is such that the input power to the generator prime mover is not proportional to the position of the control valve, you will need a kW control loop as well to avoid overloading your alternator.
A small set such as this will have an AVR with Under Frequency Roll Off protection. One of the advantages of UFRO is that both the sense and power supply to the AVR may be permanently connected. The output voltage will build as the frequency increases when the set is started.
You may be able to use a quadrature CT to provide acceptable power factor control.


Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[ScottyUK]

Bill,

For once I'm going to disagree - a well-implemented PI controller will give better control than a simple proportional controller. The key words being 'well implemented'.


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If we learn from our mistakes I'm getting a great education!

 

[waross]

Hi Scotty;
With generators paralleled in droop mode (P) the machines will share the load and load changes well. If you go to isochronous mode, (PI) you have better frequency control but the machines don't work and play together well. Usually one is put in isochronous mode and the others are run in droop.
When paralleling with the grid, the grid assumes the position of the isochronous set and controls the frequency. Droop is an easy way to control the loading on the smaller sets. If a set is large enough to impact the system or grid frequency, then fixed capacity has to be adjusted as the load increases or decreases.
I think that the point is that when a small set is operated in parallel with the grid, the grid assumes control of the speed. The control scheme controls the loading and provides runaway protection.
If I am running on the grid at 50 hz and I want 80% loading, I will set my P controller to 50 Hz+(.8 x 3% droop) or 51.2 Hz. Now I don't want reset (I) trying to increase the output in a vain attempt to raise the frequency to the actual set point.
Other than that, I agree with you completely as to the implementation of integral on a controller.

Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[PHovnanian]

In the context of controllers, PID does not refer to droop vs isochronous control modes.

A PID, Proportional/Integral/Differential controller allows for compensation in a control loop to optimize settling times and eliminate overshoot or ringing. While a generator tied to a stiff system generally needs only proportional control, the throttle control needed to spin a machine up to synchronous speed may need finer tuning, depending on the characteristics of the prime mover. Since it appears that this isn't a typical turbine, hydro, diesel, etc. system, the designers will have to take the dynamics of the system into account when starting. Particularly if this is to be done unattended.

 

[ScottyUK]

Ah, I see. You're using the inherent error of the proportional controller to provide droop. On the slightly larger machines I work with the droop is a calculated trim function which modifies the MW setpoint based on shaft speed and target frequency. A PI controller holds the turbine tightly to the calculated setpoint through a closed loop from the MW transducers.

Different ways of dealing with the same problem!


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If we learn from our mistakes I'm getting a great education!

 

[waross]

Hi Scotty.
I always enjoy our discussions, and the contrasts we find between the small (less than about 1.5 MW) and the large machines that you work on.
Before our little system got the "big" 1.5 MW fuel efficient Cat we had a mix of 5 sets. 2 x 600 kW and 3 x 350 kW. The operators watched the load and manually added or dropped machines as needed. All machines ran in droop and worked well together. The operators had governor controls on the switchboard. Once they had a machine on line, they would advance the throttle until the load was proportionally balanced. The machines would then share load fluctuations quite well. I was involved in discussions as to the implications of going to isochronous control to avoid the small frequency excursions as the droop followed the load. The operating plan was such that no one machine could be depended upon to always be running. Hence the governors may have to be converted from droop to isochronos "on the fly". The droop control was not causing any problems, the system was "islanded" in both meanings of the term. Most of the users were not even aware that there were slight frequency shifts. We concluded that going to isochronous mode would increase the both complexity of the operators task and the possibility of expensive mistakes. We stayed with droop mode.


Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[waross]

Hi PHovnanian;
I understand from the original post that the system under discussion is about 250 kW.
For generatons, diesel generators in this size range and up to and beyond 1000 kW were controlled by mechanical droop governors. In the sizes from about 250 kW and up, hydraulic governors were available sometimes as an option. The more expensive hydraulic governors had isochronous mode available as well as droop. Many hydraulic governors had only droop mode.
Droop is proportional band (P) plus offset. 3% proportional band plus 3% offset is a standard droop setting.
Isochronous is droop plus reset or integral. (PI) The governor responds to load changes proportionally and then the integral or reset corrects back to the base speed.
With the advent of electronic governors in recent years pre-act or derivative is available, should you choose to implement it. The diesel machines are quite easy to spin up and synchronze. I agree with you completely that the designers of this non typical system may have issues getting synchronized.
I would strongly suggest that we add a reverse power relay to our recommendations. I don't think that it will be a good idea to allow a hydraulic driven set to motor.
If it were my project, I would consider a low power relay instead of or in addition to a reverse power relay, and close the breaker when the set is overtaking the grid. 60.25 Hz or so. Pick up some load and then enable the low power relay. I am sure that once this has been mentioned, the designers will discuss the implications and have the expertise to devise a control plan compatible with the dynamics of their system.


Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[catserveng]

This may seem a bit basic, but whenever I come across people new to power generation control, I have found this to be a good primer and reference resource, go to Woodward publications,

http://www.woodward.com/pubs/pubpage.cfm?web_section=power

and search for publication 26260, Governing Fundementals and Power Management, takes a lot of what is discussed above and provides some additional info you may find helpful. Also look at publication 83402-PID control and 1302-Speed Droop and Power Generation, expands on the information Bill and others provided above.

Basler also has some very good reference literature at,

http://www.basler.com/html/dwntech.htm

Some of my favorites,
Voltage Regulator and Parallel Operation
Parallel Operation with a Network System