FREQUENCY CONTROL

ARTHUR GARDINER

Frequency Control What is the goal of Frequency control What causes Frequency to change What happens if Frequency is not controlled within limits What is Primary Frequency Response How is Primary Frequency Response ensured What is Secondary Frequency Response How is the Secondary Frequency Response achieved What are the roles and responsibilities of ERCOT and

other market participants How Grid Frequency is controlled during Emergencies

Balancing energy generated to demand

POWER SYSTEM INERTIA

Inertia is defined as the property of a mass that resists changes in speed. The inertia of a turbine generator refers to the turbine generators resistance to changes in its speed of rotation. When a large turbine generator is rotating, whether it is a slower speed hydroelectric unit or a higher speed steam unit, it is not a simple matter to change the speed of the turbine generator. To change its speed you must either add energy (to speed up the rotation) or remove energy (to slow down the rotation).

AC generators are usually synchronous generators. Synchronous means they are locked in synchronism with the frequency of the grid to which they are connected.

A small steam turbine that is connected in parallel with other generators on a grid with lot of generation isn't going to make all the other turbines speed up or slow down detectably as the prime mover's energy is increased or decreased--there's just too much inertia to overcome.

Frequency Control When the unit is not connected to a grid (particularly a large,

or infinite, grid) increasing the energy being admitted to the prime mover will cause the prime mover to increase speed.

When the unit is connected to a grid, increasing the energy being admitted to the prime mover will NOT result in a speed increase. It WILL result in an increase in the amperage of the generator.

In other words, the power output of the generator will increase. The extra torque which would cause the unit to increase its speed when not connected to the grid gets converted by the generator into additional power output.

Effects of frequency on motor load Motor load

An approximate rule of thumb is that the connected motor load magnitude decreases by 2% if the frequency decreases by 1%.

Non Motor load It is a reasonably accurate statement to say that non-motor load magnitude does not vary as

frequency is varied.

Composite Load/Frequency Effect

A good rule of thumb to remember is that within a typical utility system, a 1% change in frequency will lead to a 1% change in load. For example, if you have a 1000 MW load and frequency drops by 1% to 59.4 Hz, the load will also reduce by 1%, that is by about 10 MW to 990 MW.

Primary Frequency Response Primary Frequency Response is the instantaneous

proportional increase or decrease in real power output provided by a Resource and the natural real power dampening response provided by Load in response to system frequency deviations. This response is in the direction that stabilizes frequency.

Turbine Governors are the main source of primary frequency response.

The Primary Frequency Response is generally delivered completely within 12 seconds to 14 seconds.

Secondary Frequency Response ERCOT is a single Balancing Authority ERCOT is responsible for maintaining Frequency within

limits to meet or exceed NERC standards requirement Executed by Automatic Generation Control (AGC) Also referred to as Load Frequency Control (LFC) Part of the SCADA/EMS systems

Frequency control

Load Frequency control

Security-Constrained Economic Dispatch (SCED)

ERCOT SCADA AGC

QSE SCADA

AGCICCP LINK

QSE Resources

Gas TurbineDCS LDC

Gas Steam unitDCS LDC

Coal unitDCS LDC

Transmission SCADAICCP

LINK

Frequency control Regulation Reserve (REG)

REG UP Reserve Generation resources that increase generation Controllable load resources that reduce load

REG DOWN RESERVE Generation resources that decrease generation Controllable load resources that increase load

Responsive Reserve (RRS) Arrest frequency decay within the first few seconds of a significant

frequency deviation on the ERCOT Transmission Grid using Primary Frequency Response and interruptible Load;

Provide backup regulation.

Frequency control 6.5.7.6 Load Frequency Control The function of LFC is to maintain system frequency

without a cost optimization function. ERCOT shall execute LFC every four seconds to reduce system frequency deviations from scheduled frequency by providing a control signal to each QSE that represents Resources providing Regulation Service and RRS service

ERCOT LFC operates in constant frequency

Frequency control

Frequency control BAL-003-0 R2. Each Balancing Authority shall establish and maintain a

Frequency Bias Setting that is as close as practical to, or greater than, the Balancing Authoritys Frequency Response. Frequency Bias may be calculated several ways: R2.1. The Balancing Authority may use a fixed Frequency Bias value

which is based on a fixed, straight-line function of Tie Line deviation versus Frequency Deviation. The Balancing Authority shall determine the fixed value by observing and averaging the Frequency Response for several Disturbances during on-peak hours.

R2.2. The Balancing Authority may use a variable (linear or non-linear) bias value, which is based on a variable function of Tie Line deviation to Frequency Deviation. The Balancing Authority shall determine the variable frequency bias value by analyzing Frequency Response as it varies with factors such as load, generation, governor characteristics, and frequency

Frequency control Frequency Bias

The number of MWs change in generation in the system for each 0.1 Hz frequency deviation

ACE = (NIA - NIS) - 10b (FA - FS) + IMEWhere,NIA represents actual net interchange (MWs)NIS represents scheduled net interchange (MWs)b represents the control area's frequency bias setting (MW/0.1 Hz)FA represents actual system frequency (Hz)FS represents scheduled system frequency (60.0 Hz in America)IME represents a manually entered amount to compensate for known equipment error (MWs)

Frequency control 6.5.7.6.1 LFC Process Description 6-46 (1) The LFC system corrects system frequency based on the Area Control Error (ACE) algorithm

and Good Utility Practice. (2) The ACE algorithm subtracts the actual frequency in Hz from the scheduled system

frequency (normally 60 Hz), and multiplies the result by the frequency bias constant of MW/0.1 Hz. The ACE algorithm then takes that product and subtracts a configurable portion of the sum of the difference between the Updated Desired Base Point and Real-Time net MW output as appropriate. LFC shall ensure that the total reduction will not exceed the system-wide regulation requirement. This calculation produces an ACE value, which is a MW-equivalent correction needed to control the actual system frequency to the scheduled system frequency value. ERCOT shall develop a methodology, subject to Technical Advisory Committee (TAC) approval, to determine the optimal frequency bias for given system conditions.

(6) If all Reg-Up capacity has been deployed, ERCOT shall use the LFC system to deploy Responsive Reserve on Generation Resources and Controllable Load Resources. Such Responsive Reserve deployments by ERCOT must be deployed as specified in Section 6.5.7.6.2.2, Deployment of Responsive Reserve Service.

(9) If system frequency deviation is greater than an established threshold, ERCOT may issue Dispatch Instructions to those Resources not providing Reg-Up or Reg-Down that have Base Points directionally opposite ACE, to temporarily suspend ramping to their Base Point until frequency deviation returns to zero.

Frequency control

Load Frequency control

Security-Constrained Economic Dispatch (SCED)

ERCOT SCADA AGC

QSE SCADA

AGCICCP LINK

QSE Resources

Gas TurbineDCS LDC

Gas Steam unitDCS LDC

Coal unitDCS LDC

Transmission SCADAICCP

LINK

Frequency control

Frequency control 6.5.7.3 Security Constrained Economic Dispatch

The SCED process is designed to simultaneously manage energy, the system power balance and network congestion through Resource Base Points and calculation of LMPs every five minutes.. The SCED process evaluates Energy Offer Curves and Output Schedules to produce a least cost dispatch of On-Line Generation Resources to the total current generation requirement determined by LFC, subject to power balance and network constraints.

Frequency control 6.5.7.4 Base Points

ERCOT shall issue a Base Point for each On-Line Generation Resource on completion of each SCED execution. The Base Point set by SCED must observe a Generation Resources HDL and LDL. Base Points are automatically superseded on receipt of a new Base Point from ERCOT regardless of the status of any current ramping activity of a Resource. ERCOT shall provide each Base Point using Dispatch Instructions issued over Inter-Control Center Communications Protocol (ICCP) data link to the QSE representing each Resource that include the following information:

Frequency control

Load Frequency control

Security-Constrained Economic Dispatch (SCED)

ERCOT SCADA AGC

QSE SCADA

AGCICCP LINK

QSE Resources

Gas TurbineDCS LDC

Gas Steam unitDCS LDC

Coal unitDCS LDC

Transmission SCADAICCP

LINK

Frequency control ICCP

Inter-Control Center Communications Protocol This communication protocol ensures that all data coming to and

from ERCOT is in the same secure format.

Frequency control

Load Frequency control

Security-Constrained Economic Dispatch (SCED)

ERCOT SCADA AGC

QSE SCADA

AGCICCP LINK

QSE Resources

Gas TurbineDCS LDC

Gas Steam unitDCS LDC

Coal unitDCS LDC

Transmission SCADAICCP

LINK

Frequency control Automatic/Manual Constant frequency

ERCOT will designate a QSE to take the responsibility of controlling the frequency during the event when ERCOTs AGC stops working

Scheduled Control error Constant Net Interchange Control

Frequency control

Load Frequency control

Security-Constrained Economic Dispatch (SCED)

ERCOT SCADA AGC

QSE SCADA

AGCICCP LINK

QSE Resources

Gas TurbineDCS LDC

Gas Steam unitDCS LDC

Coal unitDCS LDC

Transmission SCADAICCP

LINK

Frequency control Governor

The electronic, digital, or mechanical device that implements Primary Frequency Response of a Resource

Governor Dead-Band The range of deviations of system frequency (+/-) that produces no

Primary Frequency Response

Governor Droop Droop is turbines response to Changes in Interconnection Frequency

(Speed) Droop distributes Frequency regulation to all generators in the interconnect Recommended droop settings of 2 to 5% with a maximum dead band of +/-

0.036 Hz

Remember: NERC requires all generators greater than 10 MWs to have an operating governor.

Frequency control 8.5 Primary Frequency Response Requirements and Monitoring 8.5.1.1 Governor in Service

At all times an All-Inclusive Generation Resource is On-Line, its Governor must remain in service and be allowed to respond to all changes in system frequency except during startup, shutdown, or testing

8.5.1.3 Wind-powered Generation Resource (WGR) Primary Frequency Response

Wind-powered Generation Resources (WGRs) with Standard Generation Interconnection Agreements (SGIAs) signed after January 1, 2010 shall provide Primary Frequency Response to frequency deviations from 60 Hz. The Primary Frequency Response shall be similar to the droop characteristic of 5% used by conventional steam generators.

Frequency control Energy Source for Generators Types of Prime Movers

Thermal Coal Nuclear Natural gas steam Natural gas (Gas Turbine) Natural gas (combined cycle)

Hydro Wind Solar

Frequency control Normal Ramp Rate

The rate of change in MW per minute of a Resource

Emergency Ramp Rate The maximum rate of change in MW per minute of a Resource to provide Responsive Reserve

Frequency control

Natural gas combustion turbine

Natural gas steam unit

Frequency control

Natural gas combined cycle unit

Coal unit

Frequency control Ensuring Primary Frequency Response

Make sure to keep the Governors in service at all times Test the governors on regular basis and tune them as needed Measure the response from the governors for all frequency events

and adjust the settings if needed

Frequency controlGenerating Unit Under frequency Relaying

Ensuring Primary Frequency Response

ERCOT Manual and automatic actions as function of frequency decay

Governor respond

60 Hz

59.5 Hz EEA level 3 mandatory

59.3 Hz UFLS Step 1

58.9 Hz UFLS Step 2

58.5 Hz UFLS Step 3

59.8 Hz EEA level 3 @ ERCOTs discretion

LCRA Hydros autostart59.75 Hz

Scheduled Frequency

59.964 Hz

LAARs Trip 59.7 Hz

LFC Responds and deploys Reg up, RRS 59.964 Hz

Frequency control

Advisory, Watch, and EEA levels

Advisory issued3000 Mw reserves

59.8Hz

2500 Mw reservesWatch issued

2300 Mw reservesEEA Level 1 Declared

EEA Level 2A Declared1750 Mw reserves

0 Mw reserves -60 HZEEA Level 2B Declared

EEA Level 3 Declared

Frequency control

Stable Frequency is achieved through Ensuring that AGC systems are operational 24/7 at ERCOT

and all Market participant sites Have redundant systems including communications Properly Maintain all AGC systems and communication systems Have proper controls in place to make changes to these systems Properly tune the parameters

Ensuring that all generators above 10MW have their Turbine Governors in service at all time while online Regularly test and maintain the Governors to ensure that desired

response can be provided as designed and needed Ensuring that all Loads with UFRs are always armed and all

associated relay components are properly maintained through scheduled maintenance

Ensuring that both ERCOT and market participant operators are trained to understand their roles during emergency operations and appropriately deploy the available reserves or call for additional reserves to restore the frequency