Droop vs isochronous explained 4

[profrooky]

Hello: is there a simple explanation of these two governor terms as they relate to reciprocating engine driven gensets?

Thanks in advance.

 

[JohnMcNutt]

Isochronous normally means an electronic throttle control. It is constantly adjusting throttle position to attempt to maintain 60 Hz exactly and is accomplished by a computer.

Droop usually means a mechanical governor. It is flyweights working against a spring. The faster the engine runs the farther out the weights go and the tighter the spring is pulled. This type of system will typically run something like 61 Hz at no load to 59 Hz at full load.

 

[IBRCAN]

In simple terms, droop basically means that the more load that is placed on an engine, the slower it will run (for a given throttle setting). Droop is expressed as a percentage and found by the formula: No Load Speed-Full Load Speed/No Load Speed. It is an inherent characteristic of most mechanical governors, however there are many available with adjustable droop, down to 0%. Precise droop control is one way to facilitate proportional kw load sharing of gensets in parallel.

Isochronous is basically zero droop ie engine speed (and therefore generator output frequency) is kept constant from no load to full load. Sudden load changes can cause speed to deviate, however the governor will always work to bring speed back to the same value. Isochronous governing is usually achieved with electronic controls, although many electronic governors can also be set up to run in droop. From a reciprocating engine genset perspective, isochronous is pretty much the standard for new equipment these days. Load sharing in parallel is usually achieved through the use of isochronous load sharing controls. As noted before, it is important to remember that generator frequency is directly proportional to engine speed. Some electrical loads are very sensitive to frequency.

I attached some literature from Woodward that may assist with your understanding.

 

[profrooky]

Great info, Thank You!

 

[waross]

Droop provides stability and control by increasing the fuel or steam feed as the prime mover slows down under load.
Typical droop setting for almost all diesel generators is 3%.
If the target frequency is 60 Hz, the 3% droop will be 1.8 Hz. The no-load speed will be 61.8 Hz. The full load frequency will be 60 Hz.
In control terms this is proportional control. (The P part of a PID controller.)
Classical isochronous adds integral control to proportional control. (The PI part of a PID controller.)
The first response to a load change is proportional. If Integral (isochronous) control is active, the controller detects that the frequency is no longer exactly 60 Hz and makes an adjustment to return the frequency to 60 Hz.
Life is generally simpler if you stick with droop control.
If you go onto the websites of the major gen-set builders and start checking the specs of the various sets you will find that 3% droop is almost universal. The 3% droop is implemented with 61.8 Hz no-load frequency and 60 Hz full load frequency.

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

 

[crshears]

The old Ontario Hydro standard was 4% speed droop...I don't know whether that still applies, though.

CR

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

 

[GTstartup]

The standard (FERC) for large utility units in the US is 5%. The simple definition is that % deviation in frequency that will result in a 100% change in load. In some definitions the 100% increase in load is replaced by 100% opening/closing of the main control valve.

 

[waross]

A comment on droop settings greater than 3%:
3% droop gives good control and is invisible to most customers and equipment. A possible exception is small UPS units that do not like to see anything other than 60 Hz.
When running on droop control, you must have a setting that is usable and user invisible from no load to full load.
The load on a large typically does not change that rapidly. Also, even though the individual governors may be droop controllers (in very old systems) there will be some means to adjust the frequency to maintain 60Hz.
As an example, at one time a large system would have a swing generator that handled small load changes while most generation would be at fixed capacity. The sets other than the swing set may be run at either 10% output or 90% output. As the load on the swing set was increasing, the load control dispatchers would call up individual sites and command the operators to increase from 10% to 90%.
When the load on the swing set was dropping the reverse procedure would be followed.
The swing set would be operated in droop/isochronous control and the other sets would be on manual control.
Manual control may be implemented by adjusting the set point high on a droop controller. This has the advantage of preventing runaways in the event that the load is lost.
Even though 5% or even 10% droop may be used on a large grid, the mode of operation is such that the system frequency will never see that much variation.
With an islanded diesel set, a 3% system frequency variation over the load range is common.
With grid connected machines, the maximum frequency variation seen by the end users will typically be much less than 3% even though the base droop setting may be more than 3%.


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

 

[GTstartup]

This is from NERC Training Document "Understand and Calculate Frequency Response" I think it pretty much says it all for Units >10MW in North America (an exception is the Maritimes where droop is 4%. As an interesting point NERC has been pushing a deadband of 0.018Hz now which pretty much results in Units responding continously

"What actually controls governor response is the generator’s “droop setting.” This is the governor function that dictates the relationship between speed and power output. NERC Policy says all generators over 10 MW will have governors and that these governors are set to a 5% droop. That means the governor is set to respond through the full range of unit capability for a 5% (3 Hz) change in frequency. That is, for a unit operating at 60 Hz and no load, a 3 Hz drop in frequency would cause the governor to attempt to take the unit to full load. For smaller changes, it responds proportionately less, but always on the 5% droop curve"

 

[waross]

The OP asked about reciprocating engine driven sets. What is appropriate for a diesel set at less than 10 MW may not be appropriate for a grid connected machine rated greater than 10 MW.
On a small machine the end user may see the full 3% drop in frequency as the machine loads up.
The droop on a large grid connected machine is not the only factor in frequency control.
The final frequency control of a large grid connected machine may be under the control of a very sophisticated load control panel or device.
In the grid, the droop may describe the set response to block loading and block unloading on the system as a whole. The droop also controls the speed in the event that the loses its load.
I am not arguing the NERC standard of 5% droop for grid connected machines where the governor droop is one component of a very sophisticated control scheme that limits system frequency excursions to much less than 5%.
I am suggesting that the NERC standard of 5% droop may not be a suitable setting for the hundreds of thousands of smaller, diesel driven sets that are typically set to 3% droop.
I think that 5% droop is probably the best setting for a large, grid connected machine, but the end user experience of smaller, diesel driven machines is better with a 3% droop setting.

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

 

[crshears]

Quite correct, Bill; in Ontario, for example, entire hydraulic generating stations are routinely used as the frequency control "swing units." Plus, since the entire Eastern Interconnection is rather huge, frequency control includes the adjustment of phase shifters along with generating units [and possibly, in the future, an asynchrounous tie across Lake Erie] to maintain the loadings of the tie lines to other entities as scheduled, et cetera and so forth.

Given the foregoing, unit governors on what is, if not an "infinite bus," a finitely huge one, respond only very minutely to the more-or-less continuous changes to Interconnection frequency, and will only make gross changes in response to major system disturbances...and, generally speaking, anything less than that, commonly described as a "limited system contingency," won't cause much wiggle at all on the vast majority of the governors on said interconnected units.

CR

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

 

[waross]

Thank you to both GTstartup and crshears for adding to my personal knowledge base regarding larger systems.

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

 

[crshears]

My pleasure, Bill...and not that I'm keeping score, but I'm pretty certain you've increased my knowledge and understanding base far more than I have yours...

CR

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

 

[waross]

Thank you CR.
Yours
Bill

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

 

[low1]

Manitoba is 4% as well. I'm at the Northern end of the Nelson River Bipole HVDC system. Our units are 100MW minimum in the Gillam area.