Island Mode Grid with all generators in droop mode 1

[electrocuted1]

Hi,

We have a manufacturing facility with our power generation through 15MW STG and multiple 2MW DGs. DGs are the only machines capable of providing black start, and the STG is then synchronized afterwards. All generators are running in droop mode (STG droop: 4%, DGs droop: 5%).

In the above scenario with no generator on frequency control, how is the grid frequency controlled at 50Hz?

 

[xnuke]

There could be an external controller providing an AGC signal to all generators, frequency could be controlled manually by adjusting generator no-load frequency setpoints, or there could be enough generation that the supply is fairly stiff and only small frequency variations normally occur which the facility tolerates. EPRI has a pretty good resource available for free: EPRI Power Systems Dynamics Tutorial

xnuke
"Live and act within the limit of your knowledge and keep expanding it to the limit of your life." Ayn Rand, Atlas Shrugged.
Please see FAQ731-376 for tips on how to make the best use of Eng-Tips.

 

[electrocuted1]

There is no external controller for frequency control. Total load of plant is 11.5 MW, and at times there are sudden load variations of up to 0.8 MW. Could this pose a problem to the frequency control?

 

[Compositepro]

I am simply using the principles of PID control to deduce that there does not need to be a master reference. Each generator has its own internal frequency reference called a setpoint. If one setpoint was slightly higher than that of another generator then the higher setpoint generator would assume more of the total load, depending on the tuning parameters. If the gain (inverse of the droop) is set too high, then that generator would go to full load before other generators would start to share that load. Even when there is only one generator, if the gain is set too high, there will be oscillation in the output frequency.

 

[Hoxton]

This how islands (real islands!) used to run their power generation.

The station operator would watch the frequency meter and trim the governor set points to keep near 50hz

This was in the days of mechanical governors.

Now we have electronic governors that can be remotely controlled to perform much the same function.

 

[xnuke]

Compositepro, I'm sorry to say your deduction based on your knowledge of PID control is not quite correct. You're close to understanding it, though. Generators in parallel are controlled much like VFD-driven pumps, fans, or compressors in parallel. We can have all but one operate at an externally-assigned load value with one machine allowed to swing to control the process variable to set point using a PID, or we can have all ramp up and down in unison to a set point provided by a single external PID or other reference signal. These methods using a single controller prevent individual controllers of paralleled equipment from fighting each other to control the system.

The first method I described above is the same as having all but one generator run as constant-load generators or droop generators with one isochronous generator providing frequency and voltage control.

Droop control is essentially the second method above, but with having a P-only controller set up in each of the VFDs as droop controllers. The droop controllers only control the gain of the process, not its set point. As load increases, the process variable drops somewhat but is controlled, and the drop is minimized by the P-only controllers. If the process variable remains low after a transient, the set points of the droop controllers are slowly adjusted by a single external controller providing automatic generation control (AGC), or by a person, as Hoxton stated. Droop control with AGC is essentially cascade control with a single master controller sending set points to multiple generator droop controllers.

Does that clear things up?

xnuke
"Live and act within the limit of your knowledge and keep expanding it to the limit of your life." Ayn Rand, Atlas Shrugged.
Please see FAQ731-376 for tips on how to make the best use of Eng-Tips.

 

[xnuke]

electrocuted1, your question about the load transient can't be answered easily without more information. How much total diesel generation is there? You didn't tell us. That enables prediction of the frequency drop during a load transient. You could calculate that since you know the droop values. It won't be a true transient stability study, but it'd be a start.

If all generators have the same droop percentage value, they will share load proportion to their ratings. I'm assuming the STG droop is set lower so it loads preferentially over the DGs. Is this correct? If so, what happens when it hits full load before the diesels do?

xnuke
"Live and act within the limit of your knowledge and keep expanding it to the limit of your life." Ayn Rand, Atlas Shrugged.
Please see FAQ731-376 for tips on how to make the best use of Eng-Tips.

 

[crshears]

What xnuke said.

In the above scenario with no generator on frequency control, how is the grid frequency controlled at 50Hz?

To answer the OP's original question: if I understand it correctly, absent any control system that shares loading information between the units and adjusts as programmed, nothing controls the frequency to 50Hz, which is why, except in the case of grid overload, the frequency will settle out somewhere near 50Hz with the interconnected units sharing load based upon their governor's setpoint when last adjusted, and any change in the total prevailing system demand since then.

CR

"As iron sharpens iron, so one person sharpens another." [Proverbs 27:17, NIV]

 

[NCTHAI]

Quote:
In the above scenario with no generator on frequency control, how is the grid frequency controlled at 50Hz?

Based on information given, it is assumed that STG when running is not synchronized with grid essentially, this is islanding mode of operation. It is assumed that DG set are shutdown after
- STG is started,
- Is synchronized with bus where start up DG was running (CB closed)
- Minimum load + auxiliary load being supplied by STG (Self sustaining).

It is assumed that if available load before STG started is more than minimum load required by STG to run. Initially it is supplied by DG sets and when STG is started and synched, load is transferred to ST and DG is shutdown or offloaded.

Under this islanding operating conditions, machine will be controlled on speed (frequency). Whenever load is increased or decreased, the speed will change but controller (TCP) should bring the speed back to rated speed. If you increase the load beyond which STG can supply, the speed (frequency) will drop. The tripping of the machine will depend upon your protection setting in TCP / Exciter / GCP / GPP.

As mentioned in the earlier posts, if DG set has higher droop setting and all machines are synchrnozed, first DG sets will be loaded and then ST will be loaded unless you take manual action to intervene and increase the load on ST.

 

[davidbeach]

One generator in isosynchronous (sp?) mode or lots and lots of generators in AGC is how you get a constant, "steady", frequency. Two to a few generators in droop and you get something around where you want it to be. Add an outer control loop and you can keep pushing the set point back to where you want it.

Droop ensures even load sharing but does not maintain a constant/steady frequency. Can't have both, but with enough controls you can somewhat approximate both. The more stable the load the better the approximation. For almost any application, meeting the load demand is more critical than maintaining absolute frequency control.

 

[waross]

I was the system engineer for a small islanded island group of generators.
Each generator was under droop control.
We thought about using a swing set for better frequency control but the complications and probable issues were too great for a small system with the quality of operators available to us.
The swing set scheme works well for large systems with a central load dispatch manned by well trained, competent operators.
I respect Davidbeach's position while pointing out that David is an expert with major utilities while my experience is with much smaller systems.

Given my hands on experience with the island plant, I can not answer your question without making assumptions and or suggestions on how your operators run the plant.
Not only droop but the set points of the individual machines makes a difference.

Our system:
All machines at the same droop setting. (3% as I remember)
Frequency generally within 1 Hz. (59 Hz to 60 Hz)
Operating;
The operators checked and recorded all parameters of each machine online every 15 minutes.
kW output, Amps, Volts, Hz, Oil pressure, Temp, etc.
the operators may at that time adjust the Voltage and or Hz.
If the load was rising and getting close to 80% they would start and add another set to the lineup.
If the load was dropping and the total load could be carried by one less set, they would take a set off-line.

FREQUENCY: With operator intervention, the frequency will be much closer to nominal than would be expected by a calculation based on droop alone.
If one machine is at 3% droop it will be running at 61.8 Hz at no load. This is not uncommon on residential standby sets with a lot of A/C load. The set needs over capacity to start the A/Cs, but with no A/Cs online will be very lightly loaded.
The set may never get below about 61 Hz except when an A/C is actually starting. The customers never notice the difference.
Why not set the set point a little lower so that at normal loading, the frequency is 60 Hz?
Because of the Under Frequency Roll Off feature of the Automatic Voltage Regulator.
The UFRO becomes active during overloads which pull the frequency down below 60 Hz or 50 Hz.
Changing the frequency setpoint may compromise the action of the UFRO.

Mixing machines with different droops:
No load droops at 50 Hz; 4% = 2 Hz droop. 5% = 2.5 Hz droop.
If the machines are set for a nominal frequency 50 Hz, the no load frequency of the STg will be 52 Hz and the no load frequency of the DGs will be 52.5 Hz.
At no load, the DGs would be motoring the STG.
If the DGs are set to a no load frequency of 52 Hz, the STG will be at about 80% load when the DGs are at full load.
I don't think that either of these things happens.
It depends on how the operators manage the number of sets online and how what set points that they are actually using, and how often they adjust them.
There may be some reason that the output of the STG is intentionally limited to 80%
Continuing with guesses and assumptions;
There may be an issue with block loading and the setting lets the DGs take a greater share of block loading as the system stabilizes.
The ST may be a little over powered for the generator and 80% of the turbine output corresponds to 100% of the generator end rating.
Depending on the linkage between the governor and the steam valve, the actual droop may not be the same as the droop setting on the governor. eg: 80% output from the governor may be 100% opening of the steam valve.
Varying steam pressure may be a factor.
PID control: Proportional, Integral and Derivative.
Proportional control:- With no load the actual frequency is the set point frequency plus the droop. 50 Hz plus 4% or 2 Hz = 52 Hz.
As the load increases the set slows down and as it slows down the governor increases the fuel or steam to the prime mover.
At 100% load, the set prime mover is supplied enough fuel or steam to maintain 50 Hz.
This works well with sets in parallel and they share the load well.
With multiple sets it is unlikely that the system will be run with all the sets lightly loaded and so the frequency will stay close to 50 Hz.

For almost any application, meeting the load demand is more critical than maintaining absolute frequency control.

I agree completely.
Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[ScottyUK]

Davidbeach -

'Isochronous', at least on this side of the water.

 

[davidbeach]

Thanks. I had to go with something... spell check was being of no help what so ever. ;-)

 

[waross]

One isochronous (swing) and multiple machines in droop works well for large systems.
Consider a step change in load.
When a machine in droop mode is paralleled with a large stable system, it becomes a constant load machine.
The swing machine responds initially in droop mode and then corrects the frequency back to the set point.
A step change will affect the frequency and all the droop machines will respond together.
Then the reset or integral feature of the isochronous control takes over and the swing set increases its share of the load until the frequency is back at nominal.
In this way a large load is spread across the entire system and any frequency excursion is very small.
However for this to work, the swing set must have the head room to accept or reject additional loads.
This was done at one time by the load dispatch center where operators monitored the loading of the swing set and issued instructions to various generating stations on the system to increase or decrease their MW output.
In the event that the swing set reached 100% load and the load continued to increase the frequency would continue to drop, but usually only a small fraction of the 4% or 5% droop.
Now I imagine that most grids have automated the dispatch system.
For our small island plant (2.2 MW) with manual synchronization, we stuck with droop control on all machines.


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

 

[FreddyNurk]

All of the sites I've seen in recent times have had what is effectively parallel isochronous mode, provided by whatever make of controller is selected by the site owner. All of the sites have been islands though,i've not had much to do with embedded generation controls.

They generally use some sort of communications bus to coordinate the loading between the sets. Some, but not all sites, also allow for voltage / var control as well to balance the VArs between the parallel sets.
The latest iteration of such control equipment can generally automatically coordinate loading and number of sets without any operator intervention, previous versions still relied on some central dispatch management, whether manually or by a station controller.

EDMS Australia

 

[xnuke]

FreddyNurk, good point. I forgot about that; I'm used to older plants with older governors. Modern networked generator controllers can do exactly what you described - they basically have the AGC built into them and can coordinate the return to set point frequency following a load transient as a group. I just registered for a training class in November on a type of generator controller that can do that.

xnuke
"Live and act within the limit of your knowledge and keep expanding it to the limit of your life." Ayn Rand, Atlas Shrugged.
Please see FAQ731-376 for tips on how to make the best use of Eng-Tips.

 

[catserveng]

Here is a pretty good explanation from Woodward that does a nice job of explaining droop control and newer forms of load share management. This newer manual is a combination of some of their older manuals and some training info.

Hope it helps, MikeL.

 

[catserveng]

You may find this one helpful as well.

 

[catserveng]

XNuke, wouldn't be an EasyGen class at Woodward in Fort Collins would it? If so the instructor is one of the best, one of the few old timers left at Woodward these days.

MikeL.

 

[xnuke]

catserveng, thanks for sharing the info. Yes, that's the class I'll be in. I'm really looking forward to it.

xnuke
"Live and act within the limit of your knowledge and keep expanding it to the limit of your life." Ayn Rand, Atlas Shrugged.
Please see FAQ731-376 for tips on how to make the best use of Eng-Tips.