Frequency Response – Issue Paper
California ISO
Frequency Response
Issue Paper
August 7, 2015
Market and Infrastructure Policy
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August 7, 2015
Frequency Response – Issue Paper
California ISO
Table of Contents
1.
Purpose of this initiative .................................................................................................................... 3
2.
Background ......................................................................................................................................... 4
2.1.
Primary Response to a Frequency Disturbance........................................................................ 4
2.2.
Frequency Response Trend in North America .......................................................................... 7
2.3.
ISO Frequency Response Capabilities ....................................................................................... 9
3.
Details of ISO Frequency Response Obligation under BAL-003-1 .......................................... 11
4.
Considerations for the ISO.............................................................................................................. 12
5.
Initiative Schedule ............................................................................................................................ 14
6.
Next Steps ......................................................................................................................................... 14
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1. Purpose of this initiative
On January 16, 2014, the Federal Energy Regulatory Commission (FERC) approved1 Reliability
Standard BAL-003-12 (Frequency Response and Frequency Bias Setting), submitted by the
North American Reliability Corporation (NERC). With the approval of this standard, NERC
created a new obligation for balancing authorities including the ISO to demonstrate sufficient
frequency response to disturbances in system frequency. The purpose of this initiative is to
ensure that the ISO can comply with the new NERC requirements.
NERC’s BAL-003-1 Frequency Response and Frequency Bias Setting
Purpose: To require sufficient Frequency Response from the BA to maintain Interconnection
Frequency within predefined bounds by arresting frequency deviations and supporting frequency
until the frequency is restored to its scheduled value. To provide consistent methods for
measuring Frequency Response and determining the Frequency Bias Setting.
Requirement R1 of BAL-003-1 requires that each BA or Frequency Response Sharing Group
(FRSG) must achieve an annual Frequency Response Measure that is equal to or more negative
than its “Frequency Response Obligation” to ensure sufficient Frequency Response.
To assess each balancing authority’s performance, on an annual basis NERC will select
between 20 and 30 disturbance events within the year and measure the balancing authority’s
response to each disturbance.3 In 2013, there were 25 such events.
Compliance with BAL-003-1 will begin December 1, 2016.4 NERC has established a
methodology for calculating frequency response obligations. NERC determines a balancing
authority’s obligation by first determining the obligation for the interconnection as a whole and
then assigning a share to each balancing authority based on its share of the total generation
and load of the interconnection. As a balancing authority in the Western Electricity Coordinating
Council (WECC), the ISO will have between 24% and 30% of WECC’s total frequency response
1
See FERC Order No. 794 Docket No. RM13-11-000
See Reliability Standard BAL-003-1
3 Event selection details are covered within this NERC filing.
4 The standard goes into effect on April 1, 2016, but NERC will not begin measuring compliance until
December 1, 2016.
2
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Frequency Response – Issue Paper
California ISO
obligation. WECC’s obligation5 is 906 MW/0.1 Hz and therefore the ISO’s obligation is
218 MW/0.1 Hz.
Compliance with the frequency response obligation is based on actual performance, rather than
procurement of frequency response capability. Accordingly, this standard requires the ISO to
demonstrate that resources provided sufficient frequency response during frequency
disturbance events. At the same time, in order to be prepared for unpredictable frequency
events, the ISO will need some procedure to ensure that sufficient frequency response is
available to meet the ISO’s share of WECC’s obligation whenever such an event occurs. This
paper summarizes the ISO’s current capability to respond to frequency response events and
considers whether this capability will enable the ISO to comply with the new standard. The ISO
seeks stakeholder input on how best to meet the new requirement and on the frequency
response capabilities of emerging technologies such as wind, solar and energy storage devices.
2. Background
This section provides general background on frequency response and the difference between
primary, secondary and tertiary frequency controls. The new NERC standard addresses the
primary frequency control referred to as “frequency response.” This section also describes the
ISO’s current capabilities for primary, secondary and tertiary response.
2.1.
Primary Response to a Frequency Disturbance
Frequency response is the initial or primary response of resources and load to arrest and
quickly recover from changes in system frequency. During normal operating conditions, system
frequency is close to scheduled frequency (typically 60 Hz) and is essentially the same
throughout an interconnection. All balancing authorities within an interconnected electric
system are responsible to provide frequency response capability to support system frequency in
the event of a disturbance. The loss of a major resource can cause system frequency to decline
to unacceptable operating levels, risking unintentional tripping of load and damage to large
steam turbines. Historically, frequency response – the primary and most immediate response to
the disturbance – has mainly been provided by the governor response of conventional turbine
generators, which comprised the vast majority of generating resources, and frequency
responsive loads. In contrast, resources such as wind and solar generating facilities, storage
devices and non-frequency responsive loads typically do not have the automatic governor
5
Subject to changes by NERC
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Frequency Response – Issue Paper
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response common to conventional generators. With modern inverters, however, these
resources can provide inertia6 and frequency response.
Following a disturbance, the total frequency response from all resources will support a
balancing authority’s ability to meet its frequency response obligation to the interconnection.
When a balancing authority loses a resource, it causes a sudden drop in frequency which is
detected by the governors on other resources within the interconnection. The governors then
provide immediate support to stabilize frequency by increasing the amount of energy their
respective resources deliver to the grid. Similarly, frequency responsive loads such as motors
and inductive loads consume less power in response to a frequency drop. Figure 1 illustrates
how primary frequency control (frequency response), in conjunction with secondary control (i.e.,
automatic generation control or regulation service) and tertiary control (i.e., market or operator
dispatch) work to restore scheduled frequency following a disturbance.
6
Inertia is a characteristic of massive spinning turbines, which has the effect of slowing or inhibiting a
change in frequency. Whereas frequency response can be thought of as the response of resources to a
change in frequency, inertia works to moderate the initial magnitude of the frequency change.
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Frequency Response – Issue Paper
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Figure 1 - Frequency Response
7
Source- NERC Frequency Response Initiative
An example of such a decline is illustrated in Figure 2, including points relevant to measuring
frequency response.
7
See NERC Frequency Response Initiative
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Figure 2 - Frequency Response
Frequency
FREQ
60.02
Point A
1-Minute
after T0
T0
60.00
Hz
59.98
59.96
Point B
59.94
Point C
59.92
59.90
0
4
8
12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72 76 80 84 88 92 96
Seconds
Point A indicates system frequency just prior to a disturbance, which occurs at time T 0. Within
the first 30 seconds following the disturbance, balancing authorities within the interconnection
provide frequency response to arrest system frequency (i.e., from T0 to point C) and stabilize the
system (i.e., between Point C and one minute after T0).
2.2.
Frequency Response Trend in North America
Since the 1960s generation technology has transitioned from almost exclusively hydro and
steam turbine generators to a more diverse fleet of resource types operating today. This
transition has contributed to the reduction of conventional governor response and as the
resource fleet undergoes a rapid transition the ISO expects governor response to continue to
decline. Different unit types exhibit different governing response characteristics8. Nuclear units
exhibit little to no governor response, while large hydro plants generally exhibit a significant
response in the correct direction. NERC published the Frequency Response Initiative Report
8
See IEEE Power & Energy Society’s PES-TR13 Report
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20129 with the intention of achieving a better understanding of the factors influencing frequency
performance across North America.
Apart from the change in generating resource mix to more non-conventional resources, several
economic reasons exist for conventional generating units to operate in ways that prevent
effective governor response. For example, if a unit operates at its maximum capability,
regardless of control mode the unit cannot provide additional power in response to a downward
disturbance in frequency. Another example is outer-loop megawatt control, which inhibits
governor response by slowly adjusting the governor load reference in order to maintain a preselected megawatt level, for example, to maintain the resource’s day-ahead energy schedule.
The National Renewable Energy Laboratory (NREL) has noted10 general concern exists among
power system operators and utilities regarding the degradation of frequency response in North
America over the past two decades. The decline is attributed to several factors. These factors
include the withdrawal of primary or governor response shortly after an event, insufficient inservice governors on conventional generation, and the unknown and changing nature of load
frequency characteristics. The NREL report also notes increased penetration of inverter-based,
or non-synchronous, generation technologies, which lack conventional governor controls. As a
result, dynamic performance changes due to increased wind and solar generation, combined
with reduced frequency response capability of the fleet, may further complicate integration of
renewable generation.
There are several logical reasons why frequency response is declining. Among them are:
9

Steam turbine-generators operating on traditional “sliding pressure” control;

Significant penetration of non-traditional generation, primarily wind and solar generation;

Proportionally fewer frequency-responsive large motor loads, as the US becomes less of
an industrial economy;

Variable speed drives on motors do not provide traditional load damping;

Some combustion turbine generator designs actually have a positive frequency
characteristic, i.e., their output MWs go down when frequency drops. As frequency
drops, turbine and compressor speeds drop, airflow decreases, with correspondingly
less available for combustion. The manufacturer intentionally reduces fuel input when
frequency drops to prevent overheating. This phenomenon reportedly contributed to a
blackout in Malaysia in 1996;

Generators having less inertia (less mass per MW of output);

Fewer resources are carrying frequency responsive spinning reserves as the rules for
the distribution of reserves have been relaxed; and
See NERC Frequency Response Initiative Report 2012
See Western Wind and Solar Integration Study Phase 3 – Frequency Response and Transient Stability
10
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
Power plant control interaction removing or withdrawing governor action due to outer
loop control which may be due to focus on plant performance with generation set points.
The automatic generation control (AGC) function can also reduce the frequency response of a
resource. If AGC perceives a resource’s response to a frequency excursion as a deviation from
an economic or market-determined set-point, it would attempt to reverse the frequency
response and return the resource to its economic target.
2.3.
ISO Frequency Response Capabilities
The ISO currently meets frequency response through various system characteristics and
products as summarized in the table below. For example, inertial response is a characteristic of
the system typically provided by the rotating mass of conventional generation. During a
frequency disturbance, the inertia of these resources naturally counteracts and thus reduces the
magnitude of the deviation in frequency. This does not require action by either the system
operator or a governor; it is inherent to the nature of the unit characteristics. Over time, as
nonconventional generation replaces conventional generation, the ISO fleet as a whole may
lose natural inertial response.
Primary response is provided by governor control of synchronous generators and frequency
responsive loads. Currently, the WECC has specified “droop” settings for conventional
generators. The droop setting of the governor determines the MW amount a generator
responds for each unit of frequency change. This response is instantaneous and automatic
from each resource and does not require operator action. However there is no corresponding
requirement for non-conventional generators. For primary response, the ISO currently does not
have a procurement target. Generators can provide primary frequency response if they are
operating below their maximum operating capacity and have available headroom. The ISO’s
procurement of spinning reserves ensures that generators have headroom in case of a
contingency.11
Secondary response is provided by resources under automatic generation control. The
response is slower than primary response, but still may occur within seconds to minutes. The
ISO procures regulation up and down to maintain balance between supply and demand within
each 5 minute dispatch interval. These resources are on automatic generation control and can
also serve as secondary frequency response.
Tertiary response requires system operator dispatch control. This occurs within minutes after
the start of the event. The ISO deploys spinning and non-spinning reserves to address
contingencies and frequency disturbances.
11
See ISO tariff Appendix K for spinning reserve minimum governor characteristics.
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Frequency Response – Issue Paper
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Response
Type
Inertial response
Provided by
• Comes from
motors, pumps,
and
conventional
generators
• It is more a
characteristic of
the system
• As the ISO loses
more
conventional
generator, will
have less inertial
response
Primary response
• Comes largely
from
conventional
generators
with governor
response
installed and
tuned based
on WECC
requirements
Secondary
response
Tertiary
Response
• Comes from
generation
under
automatic
generation
control
• Comes from
generators
dispatched
through
operator
control.
• Most
intermittent do
not have
technology
Response
Time
• Response in
seconds
• Autonomous
(not ISO
controlled)
response in
seconds
• ISO
controlled
response in
minutes
• ISO controlled
response in
minutes
The ISO
Procurement
• The ISO does
not explicitly
procure
• The ISO does
not explicitly
procure, but
resources with
available
headroom may
respond, such
as spinning
reserves
• Upward and
downward
regulation
• Dispatch of
real-time
imbalance
energy and
deployment of
spinning and
non-spinning
reserves
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3. Details of ISO Frequency Response Obligation under BAL-003-1
Currently, the ISO does not explicitly procure frequency response capability. The ISO assumes
it is provided through adherence to the WECC standard for governor droop settings and the
automatic governor response of interconnected generating resources.12 Compliance with the
new standard will be measured based upon actual response of generators and load. Therefore,
any solution adopted by the ISO and stakeholders must ensure obligated units respond
appropriately.
If the standard were in place today, the ISO’s 2016 share of frequency response for the loss of
two Palo Verde units would be approximately 775 MW of upward response. Every year NERC
will establish each BA’s frequency response obligation, which is an all hours (24x7)
requirement.13 The ISO has therefore opened the present initiative to determine how best to
meet the new obligation.
Figure 3 compares the ISO’s frequency response performance with the new obligation had this
been in place for 2013.
Figure 3 - 2013 Frequency Response
12
13
Automatic response by generator governors is different from AGC.
See BAL-003-1 Attachment A for NERC’s methodology
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4. Considerations for the ISO
Compliance with NERC BAL-003-1 will begin on December 1, 2016. Therefore the ISO will
need to implement any changes proposed in this initiative that require market software changes
by the ISO’s fall 2016 software release.
The ISO has several tariff provisions relating to frequency response. These tariff provisions
include



The ISO tariff section 4.5.6.1 states: “Participating Generators shall, in relation to each of
their Generating Units, meet all Applicable Reliability Criteria, including any standards
regarding governor response capabilities, use of power system stabilizers, voltage
control capabilities and hourly Energy delivery. Unless otherwise agreed by the ISO, a
Generating Unit must be capable of operating at capacity registered in the ISO
Controlled Grid interconnection data, and shall follow the voltage schedules issued by
the ISO from time to time.”
Appendix A to the ISO tariff defines Applicable Reliability Criteria to mean: “The
Reliability Standards and reliability criteria established by NERC and WECC and Local
Reliability Criteria, as amended from time to time, including any requirements of the
NRC.”
o Considerations for the ISO: These two tariff provisions refer to the WECC
standard on governor droop settings for synchronous generators; they do not
address non-synchronous generators.
Appendix K to the ISO tariff requires resources certified to provide spinning reserve to
respond immediately and automatically in proportion to frequency deviations through the
action of a governor or other control system in accordance with the minimum governor
performance requirements.14
o Considerations for the ISO: This addresses primary frequency response but
does not quantify amount of frequency response to address the new NERC
standard
The ISO will therefore need to develop procedures and associated tariff provisions to ensure
that sufficient frequency response capability is available in each operating hour to enable the
ISO to demonstrate compliance with the new obligation.
14
See ISO tariff Appendix K
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The ISO is analyzing 2013 and 2014 events to identify gaps within present capabilities in
meeting the frequency response obligation. This includes examining actual governor response
and breaking out this analysis by (1) generators providing spinning reserves, and (2) other
generators that are online.
In addition, the ISO is evaluating whether our current procurement of spinning reserves can
meet the new frequency response obligation. One consideration is that a generator may not be
capable of providing as much frequency response capacity as spinning reserve capacity.
Consequently, the ISO may have to modify spinning reserve procurement to ensure it obtains
an adequate quantity of frequency response. Another option could be for the ISO to develop a
separate market product to explicitly procure frequency response and ensure generator
headroom. However, the ISO likely cannot implement a separate frequency response product
by December 1, 2016. It would still have to implement another measure, such as using spinning
reserves, as an interim solution.
The ISO seeks stakeholder input on the following questions:
1. How should the ISO ensure there is sufficient frequency response capability on the
system in all hours to satisfy the new requirement?
2. Should the ISO develop a market product to procure frequency response?
3. If the ISO cannot develop a product in time for the fall 2016 release, what interim
solution would be appropriate? For example, using existing or modifying spinning
reserve procurement.
4. WECC standards apply only to synchronous generators. Should the ISO explore a
requirement that non-synchronous generators have primary frequency response
capability?
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5. Initiative Schedule
Date
Fri 8/7/15
Thu 8/13/15
Thu 8/27/15
Mon 9/14/15
Tue 9/22/15
Tue 10/06/15
Wed 10/30/15
Early November
Mid November
Mid to Early
December
Mid December
Early January
Wed 2/3/2016
Thu 2/4/2016
Event
Issue paper posted
Stakeholder call
Stakeholder comments due
Straw proposal posted
Stakeholder meeting
Stakeholder comments due
Revised straw proposal posted
Stakeholder call
Stakeholder comments due
Draft final proposal posted
Stakeholder call
Stakeholder comments due
Board of Governors meeting
6. Next Steps
The ISO will discuss this issue paper with stakeholders on a conference call on August 13,
2015. Stakeholders should submit written comments by August 27, 2015 to
InitiativeComments@caiso.com.
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