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COPYRIGHT, 2010 GE PACKAGED POWER, L.P., ALL RIGHTS RESERVED. THIS DRAWING IS THE PROPRIETARY AND/OR CONFIDENTIAL PROPERTY OF GE

PACKAGED POWER, L.P., AND IS LOANED IN STRICT CONFIDENCE WITH THE UNDERSTANDING THAT IT WILL NOT BE REPRODUCED NOR USED FOR ANY PURPOSE

EXCEPT THAT FOR WHICH IT IS LOANED. IT SHALL BE IMMEDIATELY RETURNED ON DEMAND, AND IS SUBJECT TO ALL OTHER TERMS AND CONDITIONS OF ANY WRITTEN AGREEMENT OR PURCHASE ORDER WHICH INCORPORATES OR RELATES TO THIS DRAWING.

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Primary Frequency and Regulating Margin Controls

Introduction

PFC (Primary Frequency Control) and RMC (Regulation Margin Control) controls have recently become a requirement for many transmission grid authorities throughout the world for gas turbine generators that connect to utility grid. The GE Energy LM product line control system has PFC (Primary Frequency Control) and RMC (Regulating Margin Control) provided as standard offering for all new gas turbine packages. Existing units in the field may require upgrade to comply with these new grid control requirements. Description

PFC and RMC controls have now become very common features required by utility grid systems. Specific settings of these controls can vary from site to site, due to grid code transmission authority and geographic location. GE control system provides standard control provisions for accommodating PFC and RMC with HMI control interface screens and standard digital and analog outputs to and from customer DCS. This position paper is intended to describe PFC and RMC controls in detail. Definition of Terms

• Governor Speed Droop. Speed droop is a governor function, which reduces the gas turbine speed reference as load increases. Governor droop functions provide stable operation of the gas turbine when connected to utility grid or other turbine generators when not connected to grid. The governor speed droop setting is typically configured 4% to 5% for normal operation. GE control system provides typical tunable range of 0% to 10% for specific site requirements and accommodating testing in the field.

• PFC, Primary Frequency Control. PFC control will control the gas turbine unit to a pre-selected load set point, such that it will respond to frequency excursions that exceed the hysteresis deadband setting by adjusting load in response to frequency change in order to help maintain the grid frequency. PFC can increase the GT output to maximum control limit, but would not allow over-fire or over-load condition to occur.

• RMC, Regulation Margin Control. RMC control permits the gas turbine to

operate at an output power close to its maximum output without being driven to base load throughout the day as the ambient temperature changes. The RMC

GE Energy Aero Energy Division

Position Paper #59

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January 4, 2010

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set point is selected as function of percentage from 0% to 3% below maximum output base load capability of the gas turbine.

• Hysteresis Deadband (Insensitivity). The governor system deadband or insensitivity is the frequency range set point that would not induce change in output power of the gas turbine during frequency variation. A frequency variation outside the deadband range would induce an automatic change in output power that is proportional to the frequency delta and would ramp at a certain rate. Setting for governor frequency deadband is typically set for 10 mHz to 36 mHz. GE control system provides deadband tunable range from 0 to 500 mHz for project specific requirements and site testing, as needed.

• ILF Function, (Local Frequency Integrator). ILF function drive control system

digital outputs to plant control DCS based on specific frequency magnitude variations.

• Self-Test for Governor Response Testing. Built in control system software provides testing that allows the injection of a predefined function into the control system logic that ultimately influences the governor speed input in order to simulate grid frequency change. The purpose of this self-test feature is to accommodate PFC and RMC testing and validation in the field while connected to utility grid. This simulation would demonstrate PFC actions resulting in output power of the gas turbine increasing or decreasing, over specified time, when the frequency variation is outside the governor deadband. This self-test function eliminates the need to inject external speed signals into the control system during operation, which is not a recommended test.

• Secondary Frequency Control. Secondary Frequency control feature consists

in restoring the frequency and powers exchanged by the local grid and other connected networks at their preset values. In order for Secondary Frequency Control to become active the gas turbine would be operated at a pre-determined margin below base load operation via RMC. This feature is activated from the utility grid dispatch center, which is then received by the power plant balance of plant DCS system. The plant balance of plant system would then pass on the utility command Secondary Frequency Control command via COM link or digital signal to the gas turbine control system(s) to take necessary action.

Governor Speed Droop

Governor speed droop is utilized to maintain stable operation of the gas turbine during operation when connected to grid or other turbines. Droop function also facilitates PFC operations, such that it automatically adjusts the output of the gas turbine proportional to the frequency deviation.

Summary

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Traditionally, speed droop response is characterized by a proportional drop in frequency as the GTG load increases. That is, speed droop is a governor response that allows a change in generator speed/frequency that is proportional to a change in the gas turbine output load. The droop function enables this operation by adjusting the speed set point in proportion to the change in speed/frequency. Droop mode is typically employed when the gas turbine is connected to a large power utility grid, therefore the generator frequency will be the same as the grid frequency, and will not drop or rise as a function of the gas turbine load. Droop response, is expressed as a percentage of the frequency change required for the governor to adjust the gas turbine output from no load to full rated load, or conversely, from full rated load to no load. The droop function’s response curve is linear, and expressed in % droop. For example, a system with a 5% droop curve would provide a 100% change in the GTG output for a 5% change in frequency/speed. Reference Figure 1 for illustration of gas turbine output power versus 5% droop curve for 60 Hz applications. Primary Frequency Control

The purpose of PFC is to help provide grid stability by allowing the gas turbine to automatically increase (or decrease load) load when a grid frequency deviation occurs outside of a frequency band, and maintain this increased (or decreased) load while the deviations persist. Reference Figure 2 for gas turbine response from various conditions during PFC and RMC events. Reference Figure 3 for gas turbine output verses response time during utility grid frequency deviation.

Summary When operating in PFC, the gas turbine generator load output would follow the assigned pre-selected load control set point, which is allowed to be set anywhere from zero load to base load. The unit will operate at its pre-selected load control set point until a disturbance results in grid frequency outside of a nominal frequency dead band with a default typical value of 20 mHz. When grid frequency disturbance occurs the GT load output would automatically react and increase or decrease as function of grid frequency sagging or expanding respectively. The amount that GT load output increases or decreases is based on its assigned droop schedule set point (configurable [0, 10]% (typically set 4 to 5%), but would not exceed GT temperature control - over fire condition. That is, If frequency sag of –0.2 Hz occurs, with droop set point at 5% and GT maximum load capability at 100 MW with 60 Hz application, the gas turbine reaction will be = + 6.67 MW. If frequency sag of -1 Hz occurs, with 5% droop the gas turbine reaction will be = + 33 MW (provided there is head room). Reference Figure 1 for gas turbine output versus frequency excursion. The rate at which the gas turbine ramps during frequency excursions is shown in Figure 3, where 100 mHz frequency deviation provides load reaction in 15 seconds and 200 mHz deviation provides load reaction in 30 seconds.

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Regulating Margin Control

The purpose of RMC is to allow the gas turbine generator to operate with some reserve load capacity remaining, which is adjustable and to be picked up automatically during specific conditions. Reference Figure 2 for gas turbine response from various conditions during RMC and PFR events.

Summary When operating in RMC mode the gas turbine generator will be used to facilitate operation at a load set point with a margin of [0, 3] % below the base load (maximum continuous output) during various grid frequency conditions and this regulating margin will allow the unit to be operated [97, 100] % of base load, so that when grid frequency event occurs the GT load output would automatically react and increase or decrease as function of grid frequency sagging or escalating respectively.

When both RMC and PFC functions are enabled the unit will follow the pre-selected load control set point, which is allowed to be set anywhere from minimum load to maximum base load minus Regulating Margin set point 0% to 3%. If the pre-selected load control set point assignment from operator exceeds maximum output minus Regulating Margin set point, the GT load output would stay locked on the maximum output minus Regulating Margin set point curve. When grid frequency disturbance occurs the GT load output would automatically react and increase or decrease as function of grid frequency sagging or expanding respectively. Reference Figure 2 for GT load reactions during various type events. The amount that GT load output increases or decreases is based on it’s assigned droop schedule set point (configurable [0, 10]%), but the GT load output would not exceed maximum base load.

When PFC is disabled and RMC is disabled and ILF is disabled, the gas turbine generator load output would follow the assigned pre-selected load control set point, which is allowed to be set anywhere from zero load to base load. When grid frequency disturbance occurs the GT load output would not react to change in frequency and would stay locked on the pre-selected load control set point. During all operations the gas turbine will follow the pre-selected load control set point and ramp to the assigned set point accordingly. The gas turbine ramp rate is designed to reach new assigned set point within 10 to15 seconds when operating at ½ load of maximum capability, so as to reach full load in 30 seconds. These timing requirements are needed to achieve market load demands that are typically commanded with the gas turbine is operating from any where from 45% to 100% of maximum load. When the gas turbine is at zero load it’s understood that the ramp rate to reach full load is around 4 minutes in accordance to LM gas turbine no load to full load ramp rate. Local Frequency Integrator

The purpose of provide inter-plant controls with intelligence that frequency variation the utility has taken place, so that plant loads can be controlled to certain levels and/or load shed.

Summary

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ILF will drive digital outputs for set/reset local frequency control. These ILF function outputs will operate with PFC = ON or PFC = OFF. The assigned digital and Boolean outputs drive based on the following:

1. When the frequency is out of the range 50 Hz ± 300 mHz (latched) 2. When the frequency is in the range 50 Hz ± 100 mHz (non-latched) 3. When the frequency is in the range 50 Hz ± 30 mHz (non-latched)

These digital outputs will be only be able to be reset by User (manually) from HMI or by Plant digital input from DCS when the frequency value returns in the range 50 Hz ± 30 mHz.

Conclusion

PFC and RMC are standard controls offered in all GE LM gas turbine control systems. Special controls consisting of digital and/or analog inputs and outputs, or variation of the standard offerings can be provided to customer as requested.

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COPYRIGHT, 2010 GE PACKAGED POWER, L.P., ALL RIGHTS RESERVED. THIS DRAWING IS THE PROPRIETARY AND/OR CONFIDENTIAL PROPERTY OF GE PACKAGED POWER, L.P., AND IS LOANED IN STRICT CONFIDENCE WITH

THE UNDERSTANDING THAT IT WILL NOT BE REPRODUCED NOR USED FOR ANY PURPOSE EXCEPT THAT FOR WHICH IT IS LOANED. IT SHALL BE IMMEDIATELY RETURNED ON DEMAND, AND IS SUBJECT TO ALL OTHER TERMS AND CONDITIONS OF ANY WRITTEN AGREEMENT OR PURCHASE ORDER WHICH INCORPORATES OR RELATES TO THIS DRAWING.

Figure 1 – Governor Load Output Response Versus Frequency Excursion

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Figure 2 – PFC and RMC Margin Control Block Diagram Conditions:

1. PFC enabled (RMC may also be enabled). Unit output locked on pre-select load MW control set point.

2. PFC enabled (RMC may also be enabled). GT output increasing and reacting to sagging grid frequency event.

3. PFC and RMC enabled, Regulating Margin Set point at 3%. GT output ramps to RMC set point 3% and operates on RMC margin curve at 97% (-3%) of base Load.

4. PFC and RMC enabled, Regulating Margin Set point at 3%. GT output reacting to sagging grid frequency event. Output of GT ramp to

base load (MCO) - non-overfire condition.

5. PFC enabled (RMC may also be enabled). GT output locked on assigned pre-select load control set point that was decreased away from RMC margin curve.

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Figure 3 – PFC Response/Ramp Rate - Typical

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