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

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Background Info Power Industry Structure in Alberta

Electric Utilities Act

Market Surveillance Administrator (MSA)

Balancing Pool

Alberta Utilities Commission (AUC)

Transmission Facility Owners

Distribution Facility Owners Retailers

Independent System Operator

(AESO)

Minister of Energy Appoints AESO Board Members, MSA & AUC Chair

Generators

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Background Info The AESO’s Core Functions

System Operations

Direct the reliable 24/7 operation of

Alberta’s power grid

Market Services Develop and operate

Alberta’s real-time wholesale energy market to facilitate fair, efficient and open competition

Transmission System Development

Provide continued reliability and facilitate the

competitive market and investment in

new supply

Transmission System Access

Provide access for both electricity

generators and large industrial customers

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.

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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

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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.

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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.

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WECC Region

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… shown in green below

The requirements and obligations described here are contained in Alberta versions of NERC/WECC reliability standards

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.

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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

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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

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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 resource-

to-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).

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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.

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Frequency Bias

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• 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.

Frequency Bias

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Frequency Event with Ideal Resource Response

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Frequency Event, Ideal Frequency Response Vs. Actual

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Good response from an actual unit

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Withdrawal of response from actual units

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Countering response from actual units

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SCADA Latency or slow response? SCADA latency or slow response

No Response & Outer Control Loops

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Slow response

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Current OR Rules

• Current Rules include: – Section 205.4 Regulating Reserve Technical Requirements and

Performance Standards • http://www.aeso.ca/downloads/Division_205_-_Section_205-

4_Regulating_Reserve_Tech_Req_and_Performance_Standards_(Dec_23_2014).pdf

– Section 205.5 Spinning Reserve Technical Requirements and Performance Standards

• http://www.aeso.ca/downloads/Division_205_-_Section_205-5_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_205-6_Supplemental_Reserve_Tech_Req_and_Performance_Standards_(Dec_23_2014).pdf

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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”

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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.

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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.

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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.

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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.

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Performance standard proposed change #3 – Coordination with AGC (cont’) From NERC (reference 1)

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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

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Performance standard proposed change #4 - Resource Initial Response (cont’)

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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

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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

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Performance standard proposed change #5 – Resource Total Response (cont’)

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Performance standard proposed change #6 – Facility Response Withdrawal

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• 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

Performance standard proposed change #7 – Resource Response Withdrawal

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• 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

Performance standard proposed change #8 – Combined Cycle Plants Response

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• 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

Performance standard proposed change #9 – Multiple Resources with One Governor System

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• 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.

Performance standard proposed change #10 – Point of Measure

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(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.

NERC References

1. Reliability Guideline: Primary Frequency Control - December 15, 2015 http://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Primary_Frequency_Control_final.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-2015-02-05-01%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

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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 kevin.wiens@aeso.ca by June 30, 2016

• At this time one further meeting is planned to discuss the results of this review. Please stay tuned for notice.

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Thank you