Frequency Response for Technology Neutral OR Rules Technical Workshop June 6, 2016

Frequency Response for
Technology Neutral OR Rules
Technical Workshop June 6, 2016
Presented by: Will Chow and Kevin Wiens
Agenda
1. What are the AESO’s core functions?
2. Reasons for proposed changes
3. Purpose of Frequency Response workshops
4. Why are operating reserves required?
5. Proposed performance standard changes
6. Next steps
1
Background Info
Power Industry Structure in Alberta
Minister of Energy
Appoints AESO Board Members, MSA & AUC Chair
Electric Utilities Act
Balancing
Pool
Independent
System Operator
(AESO)
Generators
Alberta Utilities
Commission (AUC)
Transmission
Facility Owners
Market Surveillance
Administrator (MSA)
Distribution
Facility Owners
Retailers
2
Background Info
The AESO’s Core Functions
System
Operations
Transmission
System Development
Direct the reliable
24/7 operation of
Alberta’s power grid
Provide continued
reliability and
facilitate the
competitive market
and investment in
new supply
Market Services
Develop and operate
Alberta’s real-time
wholesale energy
market to facilitate
fair, efficient and
open competition
Transmission
System Access
Provide access for
both electricity
generators and large
industrial customers
3
Reasons for Proposed Changes
• With the announced climate change policy by the Alberta government, the
AESO anticipates a much higher volume of renewable energy resources
to be connected to the Alberta electric system.
• As indicated in Energy Storage Integration Recommendation Paper dated
June 18, 2015, the AESO recommended that:
The AESO will revise, where appropriate, ISO Rule 205.4 Regulating Reserve Technical
Requirements and Performance Standards, ISO Rule 205.5 Spinning Reserve Technical
Requirements and Performance Standards and ISO Rule 205.6 Supplemental Reserve
Technical Requirements and Performance Standards and other rules as may be
incidentally impacted to reflect how energy storage technology will participate in operating
reserve products (RR, SR) and Supplemental Reserve (SP).
• Upon further consideration, the AESO has determined that the revisions
to the ISO rules described above should allow all technologies to
participate in the operating reserves market provided that the required
performance standards are met.
4
Purpose of Frequency Response Workshops
• Explain the reasons for frequency response
• Illustrate desired frequency response performance and some observed
performance problems
• Explain the proposed changes to OR performance standards
• Seek input from Market Participants to ensure that the proposed changes
are reasonable and generally achievable
– Today is about presenting the proposed concepts and why we are proposing
them
– A second workshop will be held after the Market Participants have had an
opportunity to review the proposed performance standard to discuss the
capabilities of the various resources
5
Operating Reserves - Definitions
• Operating Reserves
– means the real power capability above system demand required to provide for
regulation, forced outages and unplanned outages.
– Regulating Reserves
means the component of operating reserve:
(i) responsive to automatic generation control; and
(ii) frequency responsive;
that is sufficient to provide normal regulating margin.
6
Operating Reserves - Definitions
• Contingency Reserves
– means the component of operating reserve used to recover the area control error in
accordance with reliability standards.
– Supplemental Reserves
means contingency reserve that is
(i) generation capable of being connected to the interconnected electric system
and loaded within ten (10) minutes; or
(ii) load connected to the interconnected electric system which can be reduced
within ten (10) minutes.
– Spinning Reserves
means contingency reserve that is immediately and automatically responsive to
frequency deviations through the action of a governor or other control system.
7
WECC Region
… shown in green below
The requirements and obligations described here are
contained in Alberta versions of NERC/WECC reliability
standards
8
Applicable Reliability Standards (ARS)
• In Alberta currently we have adopted the following ARS’s
•
•
•
•
•
•
•
•
BAL-001 Real Power Balancing Control Performance
BAL-002 Disturbance Control Performance
BAL-002-WECC Contingency Reserves
BAL-003 Frequency Response and Bias
BAL-004 Time Error Correction
BAL-004-WECC Automatic Time Error Correction
BAL-005 Automatic Generation Control
BAL-006 Inadvertent Interchange
– For the most part these ARS’s apply only to the AESO.
– As the AESO does not own any generating or load resources
these requirements fulfilled through the third party resources by
market mechanisms.
9
How operating reserves help mitigate problems
– For loss of supply events experienced outside Alberta
• Initially all of WECC responds, including Alberta
– Automated response of spinning & regulating reserves
(Primary Frequency Control)
• Within 15 minutes, the balance has been restored by the area
that has had the issue (Secondary Frequency Control)
– With the WECC region being synchronously interconnected,
we all assist each other without placing undue burden on our
neighbors
10
How operating reserves help mitigate
problems (cont’)
• For a loss of supply events experienced within Alberta
– Initially all of WECC responds, including Alberta
• Automated response of spinning & regulating reserves
(Primary Frequency Control)
– Within 15 minutes, the balance has been restored
• Remaining spinning reserves plus supplemental directed to
respond (Secondary Frequency Control)
– Within 60 minutes, the reserves have been restored
• Re-dispatch of the energy market (Tertiary Frequency Control)
• Again, we all assist each other without placing undue burden on our
neighbors
• Of course for a loss of the tie lines we are on our own
11
NERC Terminology
• Primary Frequency Response
– Actions from uncontrolled (natural) sources in response to changes in
frequency: rotational inertia (H) response from resources and load response
from frequency dependent loads (e.g. motors). In addition, it can come from
Primary Frequency Control (as described below).
• Primary Frequency Control
– A subset of Primary Frequency Response actions provided by prime mover
governors in an interconnection to arrest and stabilize frequency in response
to frequency deviations. Primary Frequency Control comes from local control
systems.
• Secondary Frequency Control
– Actions provided by an individual Balancing Authority to correct the resourceto-load imbalance that created the original frequency deviation that will
restore both Scheduled Frequency and Primary Frequency Response.
Secondary Frequency Control comes from either manual or automated
dispatch from a centralized control system such as Automatic Generation
Control (AGC).
12
NERC Terminology
• Tertiary Frequency Control
– Actions provided by Balancing Authorities on a balanced basis that are
coordinated so there is a net-zero effect on area control error (ACE).
Examples of Tertiary Control include dispatching generation to serve native
load, economic dispatch, dispatching generation to affect interchange, and
re-dispatching generation. Tertiary Control actions are intended to replace
Secondary Control Response by reconfiguring reserves.
13
Frequency Bias
• NERC Definition
– A value, usually expressed in megawatts per 0.1 Hertz
(MW/0.1 Hz), associated with a Balancing Authority Area that
approximates the Balancing Authority Area’s response to
Interconnection frequency error.
• Required to be calculated and reported annually.
– NERC supplies events to be analyzed
• Typically only interconnected events
• The upcoming BAL-003 standard will place an obligation on
participants to meet a minimum requirement.
14
Frequency Bias
15
Frequency Event with Ideal Resource
Response
16
Frequency Event, Ideal Frequency
Response Vs. Actual
17
Good response from an actual unit
18
Withdrawal of response from actual units
19
Countering response from actual units
SCADA latency or slow response
SCADA Latency or slow response?
20
No Response & Outer Control Loops
21
Slow response
22
Current OR Rules
• Current Rules include:
– Section 205.4 Regulating Reserve Technical Requirements and
Performance Standards
•
http://www.aeso.ca/downloads/Division_205_-_Section_2054_Regulating_Reserve_Tech_Req_and_Performance_Standards_(Dec_23_201
4).pdf
– Section 205.5 Spinning Reserve Technical Requirements and
Performance Standards
•
http://www.aeso.ca/downloads/Division_205_-_Section_2055_Spinning_Reserve_Technical_Requirements_and_Performance_Standards_(
March_27_2015).pdf
– Section 205.6 Supplemental Reserve Technical Requirements and
Performance Standards
•
http://www.aeso.ca/downloads/Division_205_-_Section_2056_Supplemental_Reserve_Tech_Req_and_Performance_Standards_(Dec_23_
2014).pdf
23
Proposed Changes for Technology Neutral
OR Rules
• Proposed Changes to:
– Regulating Reserves
•
Allow all forms of technology to participate in Regulating Reserves if they can
meet performance criteria
•
Remove reference to “Generating Units” and replace with “Regulating Reserve
Resource”
•
Add greater clarity around frequency and AGC response
– Spinning Reserves
•
Allow all forms of technology to participate in Spinning Reserves if they can
meet performance criteria
•
Remove reference to “Generating Units” and/or “Load” and replace with
“Spinning Reserve Resource”
•
Add greater clarity around frequency response
– Supplemental Reserves
•
Already open to all technologies that can meet performance criteria
•
Remove reference to “Generating Units” and/or “Load” and replace with
“Supplemental Reserve Resource”
24
Performance standard proposed change #1
– Governor Behavior
• Each spinning reserve resource is equipped with governor system that has no
intentional or un-intentional time delays, ramp characteristics or other control
settings that prevent the spinning reserve resource from providing immediate,
automatic and sustained response to frequency deviations that assist in arresting
and stabilizing the frequency of the electric system.
– As noted in the slides there are resources that do not provide frequency
response in a manner consistent with the response needed for providing
spinning reserves.
– The first step is to ensure that the governor system is free to respond.
• From NERC (Reference 2)
Recommendation:
•
appropriate outer-loop controls modifications to avoid primary frequency
response withdrawal at a plant level.
25
Performance standard proposed change #2
– Governor Sample Rate
• Each spinning reserve resource is equipped with governor system* that has a
sample rate of at least twenty (20) samples per second.
– It has come to the attention of the AESO that many governor systems have
sample rates less than the current requirement of thirty (30) samples per
second.
– The new proposed sample rate is less the known capability of current
governor systems but still allows for sufficient response to frequency
excursions.
* Remember existing analog governor systems are exempt.
26
Performance standard proposed change #3
– Coordination with AGC
• For spinning reserve resources providing both spinning reserve and regulating
reserve, the response of the governor system and the automatic generation
control system of the regulating reserve resource is coordinated to provide both
primary frequency control and response to the automatic generation control signal
from the ISO as per the requirements in rule regulating reserve rule.
– The regulating reserve rule will have a complementary section.
27
Performance standard proposed change #3
– Coordination with AGC (cont’)
From NERC (reference 1)
Primary Frequency Coordination
In order to provide sustained primary frequency response, it is essential that the prime mover governor, plant
controls and remote plant controls are coordinated. The lack of coordination between governor and load
control systems will reduce primary frequency response, increase generator movement, and could increase
grid instability.
Modern systems generally incorporate a form of plant or unit load control. These Load Control Systems can
be locally or remotely controlled and can be applied within the turbine control panel, the plant control panel or
even remotely from a central dispatch center. In each of these control systems, the primary frequency control
of the turbine governor must be taken into account to achieve sustained primary frequency response. Without
coordination of the turbine governor’s response to all speed changes, these additional control systems will
react to the primary frequency response as a control error and quickly reverse the action of the governor.
1. Use of a frequency bias in the plant level load controller would allow it to adjust individual load target in
harmony with the governor response.
2. Use of a frequency bias in the turbine level load controls in conjunction with open loop load control at the
plant level would allow the turbine control panel to adjust its internal load control target in harmony with the
governor response.
In both cases (1) and (2) the plant level load controls can adjust targets in response to external input, (e.g. a
revised AGC target). Coordination of plant, turbine and governor controls dead bands and droop settings
must also be coordinated as a system so as not to exceed the maximum recommended settings.
28
Performance standard proposed change #3
– Coordination with AGC (cont’)
From NERC (reference 1)
29
Performance standard proposed change #4
- Resource Initial Response
• For any change in frequency where the frequency goes outside the deadband
(0.036 Hz), the change in real power output of the spinning reserve resource
must :
– begin in less than 4 seconds;
– be continuously proportional to the measured frequency;
– in accordance with the droop setting
From NERC (Reference 1)
Primary Frequency Control is the first stage of overall frequency control and is the response of
resources to arrest the locally measured or sensed changes in frequency. The controlled
response of Primary Frequency Control is automatic, is not driven by any centralized system,
and begins within cycles of the frequency change rather than minutes.
Similarly, deadbands are recommended to be implemented without a step to the droop curve,
i.e. once outside the deadband the change in output starts from zero and then proportionally
increases with the input.
From NERC (Reference 2)
Recommendations
•
continuous, proportional (non-step) implementation of the response,
* Deadband is +/- 0.036 Hz
30
Performance standard proposed change #4
- Resource Initial Response (cont’)
31
Performance standard proposed change #4a
- SCADA
• Based on Proposal 4, the spinning reserve resources will need to provide 2
second SCADA
– Currently only required to have 15 second SCADA data
– As noted in previous slides it is difficult to determine resource response with
extended SCADA latency
32
Performance standard proposed change #5
– Resource Total Response
• For any change in frequency where the frequency is outside of the deadband*
and remains outside of the deadband for greater than 30 seconds the spinning
reserve resource must, within 30 seconds of the start of the event, achieve
either:
– a change in the total real power output proportional to the measured
frequency in accordance with the droop setting; or
– the maximum real power capability of the spinning reserve resource that is
available at the time of the frequency event
• 30 seconds is based on NERC (Reference 4)
A to C frequency response captures the impacts of inertial response, load response (load
damping) and initial governor response (governor response is triggered immediately after
frequency falls outside of a pre-set deadband; however, depending on generator technology,
full governor response may require up to 30 seconds to be fully deployed). This Measure is
calculated as the ratio of net megawatt lost to difference between Point A and Point C
frequency.
* Deadband is +/- 0.036 Hz
33
Performance standard proposed change #5
– Resource Total Response (cont’)
34
Performance standard proposed change #6
– Facility Response Withdrawal
• For any change in frequency where the frequency is outside the deadband*, other
generating, load or storage resources within the pool asset must not change their
real power load level as a direct or indirect result of the spinning reserve
resource’s change in real power unless such a change does not negatively impact
frequency response of the pool asset.
– Based on experience here in Alberta
– This is not intended to capture inadvertent start-up and shut-down of other
equipment not associated with the resource.
* Deadband is +/- 0.036 Hz
35
Performance standard proposed change #7
– Resource Response Withdrawal
• The change in real power output of the spinning reserve resource must be
sustained while the frequency remains outside the deadband*.
• From NERC (Reference 2)
Recommendations
•
appropriate outer-loop controls modifications to avoid primary frequency
response withdrawal at a plant level.
* Deadband is +/- 0.036 Hz
36
Performance standard proposed change #8
– Combined Cycle Plants Response
• For a combined cycle facility the aggregated real power output of all
generating units within the facility may be used to provide the appropriate
amount real power for a frequency event provided:
– each generating unit has a governor system; and
– the sum of the outputs as measured at each generating unit stator
winding terminals provides the same response as described for a
single spinning reserve resource
37
Performance standard proposed change #9
– Multiple Resources with One Governor
System
• For a resource consisting of multiple generating or load assets the
aggregated real power output of all the assets within the facility may be
used to provide the appropriate amount real power for a frequency event
provided all assets are:
– under the control of a single governor system; and
– the response is based on the total real power operating range of the resource
similar to the response of a single resource.
• EG. A facility consisting 10 x 2 MW generating units with a single
governor system would behave the same way as a single 20 MW
generating unit.
38
Performance standard proposed change #10
– Point of Measure
(a) stator winding terminals of each qualified generating unit;
(b) the circuit breaker or disconnection device that is electrically closest
to each qualified load.
(c) the alternating current terminal closest to each qualified inverter
based technology;
(d) the collector bus for qualified aggregated generating facilities; or
(e) a point designated by the AESO.
39
NERC References
1. Reliability Guideline: Primary Frequency Control - December 15, 2015
http://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Primary_Frequency_Control_fi
nal.pdf
2. Frequency Response Initiative Report – October 30, 2012
http://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf
3. Industry Advisory, Generator Governor Frequency Response – February
5, 2015
http://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015%20Alerts/NERC%20Alert%20A-2015-0205-01%20Generator%20Governor%20Frequency%20Response.pdf
4. Essential Reliability Services Task Force, Measures Framework Report November 2015
http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF%20Framework%20Report
%20-%20Final.pdf
40
Next Steps
• The AESO is requesting the Market Participants including
future/potential participants to review these concepts with the
technical personnel on staff and with their equipment
providers to determine if the performance criteria proposed is
reasonable and generally achievable.
– As part of this review the AESO recommends that Market
Participants review the references listed above.
– Please send your comments to [email protected] by June
30, 2016
• At this time one further meeting is planned to discuss the
results of this review. Please stay tuned for notice.
41
Thank you