Introduction

The purpose of this document is to assist customers responding to a recent NERC frequency response initiative survey. Only questions for which GE has data are covered. Responses to questions that are left out should be obvious to the end user.

4. Prime Mover Combustion turbine

6. Unit Inertia constant (H) On most newer units, this specific information will be listed in the Generator Electrical data sheet supplied with the unit. If not available, please request the Model list C902 drawing from a GE representative. This drawing is part of the generator bill of materials. If we are unable to locate this (until recently this document was not always created for new units) use the standard values from the table below or consult GE for additional help

Turbine type Model number Generator Model H ( MW-sec/MVA)

7FA+e 7241 - 7FA.03 7FH2 234 MVA 4.85 7EA 7121 - 7EA.01 7A6 100.7 MVA 6.34 6B 6551B - 6B.03 6A3 45.7 MVA 6.28

7FA+ 7231 - 7FA.02 7FH2 204 MVA 5.55 7EA 7121 -7EA.01 7H2 91 MVA 5.75

If this is not directly applicable but total combined rotor train inertia is known, then the inertia constant can be calculated according to the formula:

MVA

xWRH

200299376.0

MVA = MVA rating of generator

WR2 = combined generator rotor load coupling gearbox (if applicable) inertia in Lb-ft 2 On units with a load gearbox between the turbine and the generator, this equation can only be applied if the total rotor train inertia referenced to the generator is known. Simply adding up the rotor train component inertias will not work in this instance. If the nameplate MVA differs from the table value for the generator (but generator is same basic type), then multiply the H number given in the table by:

Correction factor = MVANameplate

MVAforvalueTable

_

___. For a larger MVA rating, H constant should drop.

Consult GE for further help or if the calculated number falls outside the sensible range of 2 to 7

GE Energy - Product Service Data Sheet - GE Frame Heavy Duty Guidance on Responding to NERC Frequency Response Initiative Generator Governor Survey

10. Equipped with governor Yes

11. If yes, is it operational Yes (it is the fundamental control algorithm on GE Gas turbines) 11.a If yes, is the governor operational Yes (it cannot be disabled on GE Frame heavy duty gas turbines)

11.b What is the normal governor mode of operation? Droop

11.c Is Governor Response sustainable for more than 1 minute if conditions remain outside of dead-band? Yes

11.d Regulatory restrictions? None (unless the customer is aware of some specific unusual site arrangement)

11.e Does governor respond beyond the high/low operating limit (boiler blocks)? No (answer is really NA)

11.f Is the governor response limited by the rate of change? No

11.g Are there any other unit-level or plant-level control schemes that override or limit governor performance? Yes (if using Base-load / Preselect or AGC/ remote control of load target from DCS) No (if using manual raise lower buttons to adjust load target. Rare in practice. See 17 for details)

12 Governor Type For Mark 4 through Mark 6e answer is DEH For Fuel regulator, Mark 1 and Mark 2 answer is analogue (electro-hydraulic) It is possible some links and levers type mechanical governor systems are still in existence; these would be mechanical

13 Governor Manufacturer and Model GE Speedtronic Mark 1,2,4,5,6 as applicable GE Mark 6e

14.a Dead band setting For most units shipped since the mid-1990s with constant settable droop this will be 15 mHz (milli-Hertz) To verify this, search your control system for a constant TNKEDB. This should be set at 0.025% speed, which is 0.015 Hz. If this constant cannot be found, and you cannot find control constant DWKDG in your system, then the answer is 0. Older systems, units that share a common shaft line with the steam turbine or units with only one megawatt transducer generally used an FSR (Fuel Stroke Reference) based governor with no intentional dead band.

14.a Dead-band frequency reference Current frequency (Droop response will be from current operating speed) 14.b RPM Dead band Not used on GE units

14.c Basis for Dead-band Setting Load adjust occurs once speed error exceeds dead-band and stays on until error is back within the 15 mHz dead-band. Response will be linear and proportional.

14.d Governor action reset conditions None / Not applicable

15 Droop setting 4% is typical, however there may be some exceptions. For Mark 4 and later systems, one of the following methods can be used to determine it depending on the type and vintage of the system. For earlier systems consult controls specification for guidance. In some cases, a physical test may be required.

Method A. For nearly all units shipped since 1990 Constant Settable Droop Extract the value of control constant DWKDG from the control system. Also check for constant FSKRN2 and if it exists in your configuration, consult GE to determine which of the two types you have. If the value you calculate falls outside the range 4 to 5%, consult GE service representative for additional help.

Take the inverse of the DWKDG value. This will be the megawatts per percent speed value. Divide this value into the rated power of the turbine and this will give the droop in %.

Example: 7FA+e unit rated 172.4 MW and DWKDG set at 0.0232 % speed / MW. Rated output can be obtained from the turbine nameplate

Droop = rated load x DWKDG = 172.4 x 0.0232 = 4.0%

The droop response is fixed and does not vary with ambient air conditions. Base-load capability will vary with ambient conditions. The droop is a linear response and the MW response per percent speed change can be determined by taking the inverse of DWKDG. The load gain is therefore 1/DWKDG or 43.1 MW/% speed change in this instance If you use this method your dead band in part 14 will be TNKEDB, converted to units of mHz, typically 15.

Method B. FSR based droop -- for single shaft units and many older units, in particular those with Mark 4, many retrofits and all units with only a single non-redundant megawatt transducer You will have to determine the relationship between FSR (fuel stroke reference) and DWATT (power). If you have control constant FSKRN2 in your system and it is used in software then this method might apply. Determine: FSR load gain = (Load A Load B) / (FSR A FSR B)

Load A and Load B will need to be reasonably far apart to get an accurate number, suggest at least 25 % of unit capacity or greater. Ideal data taken at spinning reserve for FSR/ Load B and data taken at base load for FSR / Load A. This will create a number in MW per % FSR. Now obtain control constant FSKRN2 from your control system. Expect the value to be somewhere between 10 and 19%. Load gain = FSR Load gain x FSKRN2 Now droop = (Rated load) / (Load gain) Example: 7EA unit at 8 MW has an FSR of 22 %. Same unit at 80 MW has an FSR of 76 %. Unit is rated for 84 MW. FSKRN2 found to be set at 15% FSR Load gain = (80-8) / (76-22) = 1.33 MW per % FSR Load gain = 1.33 x 15 = 19.95 Droop = rated load / load gain = 84 / 19.95 = 4.2% If you use this method your dead band in part 14 will be 0

15.a Basis for droop setting Droop as calculated above is given on the basis of ISO MW rating of the unit. Unit should respond proportionally and linearly at {insert load gain as calculated above} between 0 MW and the current rated machine base load capability. 16 Does the unit frequency response step into the droop curve or is it linear from the dead-band? Look at answer to 15. If Method A was used to determine droop, the answer is linear. If method B was used, then the answer should be Other and under description just state No intentional dead-band in control algorithm

17 Normal Prime Mover Control Mode For AGC control, GE recommends using MW Set point (AGC). Suggest adding a brief description of your AGC algorithm and whether it contains a frequency bias or not. Alternately add explanation to box 18 if appropriate, for example if a third party sets plant load target. For Base load operation, select Other. Recommend using the following text in the Other column:

Base load mode, unit runs at its current maximum capacity. Unit will respond to high frequencies with its standard droop settings and a small additional time delay. Unit will be unresponsive to low frequencies. Base load power output will change with ambient conditions.

For Preselect load (from HMI) suggest adding the following explanation in the other column:

Unit will operate to an operator defined load target. The unit will respond to system transients with its normal speed droop characteristic, however the preselect control will slowly override any speed governor response at the auto loading rate.

Turbine manual (Raise-lower buttons on Mark controller used to raise / lower load) Suggest adding the following to Other please explain box:

Unit operates in manual mode with speed droop fully active and only manual operator adjustment of the speed load target.

Useful references GEK-111085 Control and protection article Speed Control (Method A Q15) GEK-111368 Standard droop (Method B Q15) Further help For basic queries related to this survey, please contact your local GE service representative. For detailed power system, modeling and governor testing queries, please contact the GE Energy Applications and Systems Engineering group.

http://www.gepower.com/prod_serv/serv/energy_consulting/en/index.htm

Revision Date Purpose Changed by

1 9/29/2010 Initial version W. McEntaggart/ D. Leonard