integrating variable generation task force … · within the next five to fifteen years. work plan...

Integrating Variable Generation Task ForceSummary of IVGTF Phase II Findings & Recommendations

Charlie SmithUtility Variable-Generation Integration Group

Mark AhlstromWindLogics Inc. (a NextEra Energy subsidiary)

Drivers

Drivers of Variable Generation Growth

• Public policy

• Incentives

• Economics

• Diversity and risk

A majority of states/provinces now have renewable portfolio standards, with many requiring that over 20% of electricity sales be generated by renewable energy sources within the next five to fifteen years.

Work Plan Organization

Planning Tasks (Daniel Brooks, EPRI)

♦ Task 1.1 – Generic Wind Turbine Models

♦ Task 1.5 – Incorporating PHEV, Storage, DR into Planning Process

♦ Task 1.8 – Incorporating Variable DER into the Planning Process

Interconnection Tasks (Charlie Smith, UVIG)

Task 1.3 – Interconnection Requirements

Task 1.7 – Reconciliation of Order 661-A and IEEE 1547

Task 2.2 – BA Communication Requirements

Work Plan Organization

Operations Tasks (Steve Beuning, Xcel Energy)

♦ Task 2.1 – VG Power Forecasting for Operations

♦ Task 2.3 – Ancillary Service and BA Solutions to Integrate VG

♦ Task 2.4 – Improved Operating Practices with VG

Probabilistic Tasks (Milligan/NREL, O’Malley/UCD)

Task 1.2 – Capacity Value Methods

Task 1.4 – Flexibility Requirements and Metrics

Task 1.6 – Probabilistic Methods

PLANNING TASKS

Task 1.1 – Generic Wind Turbine Models

Task 1.5 – Incorporating PHEV, Storage, DR into Planning Process

Task 1.8 – Incorporating Variable DER into the Planning Process

Planning - Task 1.1Generic Wind Turbine Models

Summary of Conclusions

There is an urgent need for standard models that:

Provide a defined model structure used by all commercial software tools

Are publicly available

Are not specific to any particular design

i.e. are generic

are able to reasonably represent key performance relevant to bulk power system studies


Recommendations

Improved variable generation models need to be developed to ensure that high levels of variable generation can be simulated and appropriately addressed through the existing standards

Models should be routinely validated to ensure proper representation of variable generation power plants in bulk power system studies


NERC Implications - Possible Reviews or Updates

♦ MOD-011 Steady-State Data Requirements and Reporting

♦ MOD-013-1 Dynamics Data Requirements and Reporting

♦ MOD-024-2 Verification of Generator Real Power Capability

♦ MOD-025-1 Verification of Gen. Reactive Power Capability

♦ MOD-026-1 Verification of Gen. Excitation System Functions

♦ MOD-027-1 Verification of Turbine/Governor and Load Control

Planning - Task 1.5Incorporating PHEV, Storage, DR into Planning Process


1. Pursue research and development activities to assess system flexibility needs, as well as evaluate the benefits of flexible resources and technologies such as demand response (DR), distributed energy storage, and plug-in electric vehicles (PEVs)

2. The capability of each of the identified emerging resources to provide system flexibility/reliability functions and services was qualitatively evaluated for ten specific characteristics

3. There are numerous challenges to quantifying the potential impact of these emerging flexible resources on bulk system reliability including:

a) Lack of flexibility metrics

b) Uncertainty in quantifying future system flexibility needs

c) Uncertainty due to the availability of emerging flexible resources and other conventional resources that can supply flexibility


Recommendations

1. Development of an operational infrastructure that provides visibility and control (direct or indirect) of distributed resources such as DR, distributed energy storage and PEVs

2. Adjust market rules that unnecessarily limit the types of resources for providing specific reliability functions

3. Adjust regional or federal reliability standards that limit resources that can be used for providing specific reliability functions

4. Provide advances and enhancements that inform all resources of the value of needed flexibility services and incent desired response while discouraging undesired response

5. Market and institutional barriers and limitations identified in this report must be addressed



Review the NERC glossary definitions for unintended consequences, i.e. the definition of spinning reserve references “unloaded generation”, which has been interpreted as prohibiting load from participating in providing spinning reserves

Review definitions of all ten flexibility / reliability considerations evaluated with above goal in mind:

– Inertial Response, Primary Frequency Response, Regulation, Load Following/Ramping, Dispatchable Energy, Spinning Reserve, Non-Spinning Reserve, Replacement Reserve, Variable Generation Tail Event Reserve, Voltage Support

Planning - Task 1.8Incorporating Variable DER into the Planning Process


The following potential bulk system reliability impacts of high levelsof distributed energy resources (DER) have been identified:• Non‐dispatchability and ramping/variability of certain DER• Lack of low voltage fault ride-through, lack of frequency ride‐through and

coordination with the IEEE 1547 interconnection standards for DER• Potential system protection considerations• Under Frequency Load Shedding (UFLS) and Under Voltage Load Shedding

(UVLS) disconnecting generation and further reducing frequency and voltage support

• Visibility/controllability of DER• Coordination of system restoration• Scheduling/forecasting impacts on baseload/cycling generation mix• Reactive power and voltage control• Impacts on forecast of apparent load seen by the transmission system


General Recommendations 1. NERC, state regulators, and/or industry should develop an analytical

basis for understanding the potential magnitude of adverse reliability impacts and how that magnitude changes with penetration of DER and system configuration/composition

2. Based in part on the analytical results from #1 and the broad experience of generation, transmission and distribution owners and operators, develop specific recommendations for changes to operating and planning practices, state programs, and pertinent NERC Reliability Standards

3. NERC should work with the affected entities in the different regions, including state agencies having jurisdiction over DER, RTOs, and vertically integrated utilities, to develop appropriate guidelines, practices, and requirements to address issues impacting the reliability of the BES resulting from DER



The level of DER which will cause issues in BAs will vary by BA and DER technology, so there may not be a ‘one‐size‐fits‐all’ solution

Specific recommendations for guidelines or standards are not provided

INTERCONNECTION TASKS

Task 1.3 – Interconnection Requirements

Task 1.7 – Reconciliation of Order 661-A and IEEE 1547

Task 2.2 – BA Communication Requirements

Interconnection - Task 1.3Interconnection Requirements


The following areas need to be addressed in NERC standards:

Reactive Power and Voltage Control

Performance During and After Disturbances

Active Power Control Capabilities

Harmonics and Subsynchronous Interaction

Models for Facility Interconnection Studies

Communications between Variable Generation Plants and Grid Operators


Recommendations NERC should promote greater uniformity and clarity of reactive power

requirements contained in connection standards that Transmission Operators have issued pursuant to FAC-001. NERC, FERC and other applicable regional standards should be reconciled

NERC should consider initiating a Standards Authorization Request (SAR) to establish minimum reactive power capability standards for interconnection of all generators, and provide clear definitions of acceptable control performance

Variable generation plants should be required to have the capability to limit the rate of power increase

Encourage the provision of droop control similar to synchronous machines

Consider requiring inertial response from wind plants in the near future

Variable generation plants should send data to, and receive and execute command signals (power limit, voltage schedule, ramp rate limit, etc.) from the grid operator


NERC Implications - Possible Reviews or Updates Consider adding a clarification to FAC-001 expanding R.2.1.3 or as an

Appendix, stating that interconnection standards for reactive power must cover specifications for minimum static and dynamic reactive power requirements at full power and at partial power, and how terminal voltage should affect the power factor or reactive range requirement

Consider modifying VAR-001 to include the term “plant-level volt/var controller” (in addition to “AVR”), which is more appropriate for variable generation

The scope of PRC-024-1 should be broadened to cover smaller plant sizes

PRC-024 should define the performance required during and after disturbances and should make clear and unambiguous statements as to what remaining “connected” entails

FAC-001 could be modified to include a facility connection requirement to address generator facility restarting

FAC-001-0 should be revised to recognize the differing data requirements for interconnection of variable generation

Interconnection - Task 1.7Reconciliation of Order 661-A and IEEE 1547


Recommended ride-thru and must trip requirements for DER


Recommendations

In the short-term, NERC should engage in current efforts to revise DER interconnection standards by providing information, raising awareness and encouraging the adoption of VRT and FRT for DERs. The initial focus should be on identifying the need for adopting minimum tolerance thresholds for VRT and FRT in the IEEE Standard 1547 and, then, establishing those minimums

In the longer-term, NERC should establish a coordination mechanism with IEEE Standard 1547 to ensure that BPS reliability needs are factored into future DER interconnection standards revision efforts. To date, BPS stakeholders have participated only sporadically in the IEEE Standard 1547 process. As a result, VRT and FRT concepts receive limited consideration and may have been outweighed by distribution system protection concerns. This liaison process would be too late for the P1547a amendment, but it would be timely for the full revision to begin in December 2013



One of the challenges for the LVRT requirements is that the BES connected VERs are under FERC jurisdiction, and FERC and NERC standards are applicable that address their performance requirements (e.g. FERC Order 661A for LVRT requirements)

On the other hand, distribution system connected VERs in most cases are under the state utility commission jurisdictions, and in most cases their performance requirements are dictated by IEEE Standard 1547

Therefore, a closely coordinated and cooperative effort between NERC and IEEE is proposed in this area

Interconnection - Task 2.2BA Communication Requirements


For wind generation to provide power plant control capabilities, it must be visible to the system operator and be able to respond to dispatch instructions during normal and emergency conditions

Accordingly, enhanced communication protocols will be needed to ensure wind resources can continue to become a more significant part of the North American generation mix without compromising grid reliability

Real-time communication capabilities for system operators will continue to play an instrumental role, especially during system restoration efforts that require increased coordination between a given Balancing Area and the Transmission System Operator (TSO)


Recommendations All generators 10 MW or greater within a BA, regardless of interconnection point,

shall provide:

Breaker status to the BA/TOP (FAC-001)

Current MW and MVAR output (FAC-001)

Voice circuit for communication of real time instruction (COM-002)

Coordination of under-frequency relay settings (FAC-001)

The following should also be required for all generators 10 MW or greater within a BA, regardless of interconnection point, if a significant impact has been identified in an interconnection study:

Resource schedules with outage information (FAC-001)

Meteorological data for forecasting (FAC-001)

Availability (FAC-001)

High and Low Sustained Limit (FAC-001)


NERC Implications - Possible Reviews or Updates FAC-001: TO lists specific requirements for all generation in the footprint

COM-002: Apply the standard to all generation facilities 10 MW or greater

PRC-001: Make this requirement applicable to facilities 10 MW or greater

TOP-001: Require all generation facilities 10 MW or greater to comply with reliability directives from the BA or TO, and to provide notice to the BA and TO before removing generation facilities from service

TOP-002-2b: Require all generation facilities 10 MW or greater to provide current, next day, and seasonal operations information to the host BA and TP

TOP-003-1: Require all generation facilities 10 MW or greater to coordinate outage of generation facilities including telemetering equipment and voltage regulation equipment

OPERATIONS TASKS

Task 2.1 – VG Power Forecasting for Operations

Task 2.3 – Ancillary Service and BA Solutions to Integrate VG

Task 2.4 – Improved Operating Practices with VG

Operations - Task 2.1VG Power Forecasting for Operations


1. Aggregation across broad geographical regions reducesforecast error, variability & operating reserve requirements

2. Large system/market size and flexibility improves the operator’s ability to deal with variability

3. Methods for clear & efficient prioritization are needed for curtailment

4. Power forecasts in multiple time frames are critical

5. Value of forecast depends on operating state of bulk power system

6. Ramp event forecasting is important but challenging, and must be balanced with improvements in system operations and flexibility

7. Electrical (power, availability, curtailment) and meteorological data from wind and solar plants, delivered on a timely and reliable basis, are critical for forecast accuracy.


Recommendations

1. Require real-time meteorological and electrical data through SCADA systems using standard protocols

2. Wind plant output forecasts, often several of them, should be standard system and market operation tools for economic operation and system reliability purposes

3. Using forecasts by reliability coordinators is a logical first step, but use in unit commitment planning is also very important for both economic & reliable operations

4. Overwhelming benefits from adjusting rules & practices: Larger balancing areas with fewer transmission constraints

Dispatch generation closer to real time with sufficient flexibility

5. Ongoing innovation needed with government, private industry, system operators & stakeholders



♦ FAC-001 Facility Connection Requirements

♦ TOP-002 Normal Operations Planning

♦ TOP-006 Monitoring System Conditions

♦ BAL-002 Disturbance Control Performance

♦ COM-002 Communication and Coordination

♦ IRO-005 Reliability Coordination - Current Day Ops

Investigate developing a new NERC Reliability Standard that provides for regional forecasts and local wind/solar facility wind forecasts to schedule variable generation

Operations - Task 2.3Ancillary Service and BA Solutions to Integrate VG


1. Provides a survey of regional ancillary products and operating reserve practices

2. Looked at specific questions around ancillary services for loss of wind generation, use of contingency reserve for wind, and ramping issues

3. Found that Balancing Authority Areas that can access sufficient maneuvering capability of generators and loads through sub-hourly markets, scheduling and economic dispatch may not require additional load-following reserves to support VG, but that introducing a load-following (or ramping) ancillary service may augment flexibility in some situations


Recommendations

1. Each region or reserve-sharing group should permit Contingency Reserve deployment under imbalance energy circumstances

2. Dispatchable control capability should be required in generator interconnection requirements for new variable generators

3. Regional market operators and other grid operating entities should consider transmission service when curtailing variable output resources during reliability-limited operating conditions (i.e., include wind generators in security constrained economic dispatch)



♦ BAL-001-0.1a♦ Supported the concept that increased Balancing Authority collaboration

reduces cost overall, and is valuable for VG integration.

♦ BAL-002-0♦ Allow use of Contingency Reserves to meet DCS requirements for wind-

related events. Require communication of variable generation derates.

♦ TOP-002-2&a♦ Enhance the standard to provide guidance on incorporation of variable

energy resource events into the planning process.

♦ TOP-006-1&2♦ Expand R4 to require forecasting information needed for near-term

prediction of variable generation output.

Operations - Task 2.4Improved Operating Practices with VG


Looks at operating practices, procedures and tools for situational awareness, real-time risk assessment and operator decision support

Increasing system variability increases the importance of visibility, tools and clear operating rules

Operating with larger geographic regions improves VG forecast accuracy and reduces output variability with associated operating reserve requirements

Allowing negative pricing in regional markets may be important for both reliability and economics during curtailment conditions

Supported findings and recommendations of Task 2-1 report with regard to forecasting data and approaches


Recommendations

Tools, including visualizations, are needed to process and present information to system operators

Changes to operating rules and practices are critical: Dispatching the system closer to real time can very effectively deal

with the variability and uncertainty of VG

Incorporating VG forecast into unit commitment and dispatch is important for economic and reliable operation

Adjust reserve requirements based on VG output level

Incent dispatch behavior consistent with system needs

Benefits of larger balancing areas with fewer transmission constraints are overwhelming


NERC Implications - Possible Reviews or Updates BAL-002: Include sudden changes in wind output as “credible

contingencies” (Section 3.1), and view with various reserve sharing groups

BAL-005: Include controlled and uncontrolled ramp rates (from VG) in the various types of ramp rates that a BA may need to use to calculate ACE

COM-002: Clarify “voice and data links” to mean those identified in Interconnect Agreements between TO and the variable generator

EOP-002: Reflect curtailment capabilities of various generator types as one of the possible remedies available to the BA

IRO-004/005: Reflect VG forecasting information needed for day-ahead and current-day operations

TOP-002/006: Reflect reasonable VG forecasting data needs

PROBABILISTIC TASKS

Task 1.2 – Capacity Value Methods

Task 1.4 – Flexibility Requirements and Metrics

Task 1.6 – Probabilistic Methods

Probabilistic - Task 1.2Capacity Value Methods

Summary of Conclusions1. Comparison of reliability-based approaches used to calculate the

effective load-carrying capability (ELCC) of variable generation is needed. (Consider more than just peak hours.)

2. Alternative LOLP, LOLE, or related approaches for determining variable generation capacity contributions towards availability and adequacy should be considered.

• Unless the Planning Reserve Margin is derived from a LOLP study, there is no way to know what true level of system risk is present (even with the same reserve margin).

3. There appears to be variations in the way that imports, exports, and emergency measures are handled in reliability calculations.

4. It will be critical to provide ongoing evaluation of the potential impacts of new variable generation resource on the grid.

5. Industry education on metrics and calculation used for capacity contributions will provide a better outlook on the true nature of variable generation.

6. Performance tracking of variable generation is needed for the understanding of various technologies’ resource adequacy contributions.


Recommendations

Metric• Research to equate reliability targets to alternative metrics• Use LOLP/LOLE to calculate generation adequacy and capacity contributions• Planning reserve margin becomes less meaningful with higher VG penetrations

Multi-area Reliability Adequacy• Develop common approaches for reliability assessment of interconnected systems

Alternative Approaches• Benchmark (or derive) planning reserve margins with LOLP/ELCC approaches

Data Collection• Collect high-quality VG data to inform capacity value calculations• Work with DOE, etc., for developing high-resolution wind and solar power datasets

Education• Facilitate dissemination of information about LOLP-related methods and meaning



None specifically provided

Probabilistic - Task 1.4Flexibility Requirements and Metrics


1. High penetrations of VG will result in the need for more flexibility, which will require appropriate planning study methods.

2. Power systems that already have high levels of VG are adjusting operating practices and market structures in response to the increased variability.

3. This report begins the challenging effort of developing a metric for flexibility (including mention of an Effective Ramping Capability that is analogous to ELCC), but further development is needed.

4. This report did not identify specific changes to planning practices, but believes that a set of best practices to account for flexibility in planning studies now can be developed.

• The starting point is a number of excellent integration of VG studies that have been conducted in the recent past.


Recommendations

1. Probabilistic planning methods being developed in the ongoing work of NERC’s IVGTF Task 1.6 will be a vital improvement to assess required flexibility.

2. As part of developing the Variable Generation Reference Guide (Task 3.1), a set of best planning practices to design systems with sufficient system flexibility to accommodate targeted levels of variable generation should be documented.

3. NERC Reliability Metrics Working Group (RMWG), after provision of metric templates, should work to develop agreed upon metrics:

• Develop and collect metrics that measure flexibility needs for variable generation. For example, calculating a set of ramp and intensity metrics can provide insights on flexibility trends.

• Compare projected and actual annual energy levels from variable generation• Measure variable generation performance factors such as capacity factors and

peak coincidence factors

Probabilistic - Task 1.6Probabilistic Methods


1. Probabilistic methods for integrating VG in power systems are largely in the research domain - not yet widely adopted by industry.

2. Many power system planning and operating problems are implicitly probabilistic - it is very likely that probabilistic methods will be required in the future, with VG being an additional driver for adoption.

3. Challenges remain for widespread deployment of probabilistic methods - complexity, computation, skills gap, fuller understanding and appreciation of benefits, data acquisition, etc.


Recommendations

1. The paper provides detailed recommendations for the six classes of decision problems associated with VG: reserves, dispatch, commitment, maintenance, generation planning, and transmission planning

2. More general recommendations:• Grow appreciation how the future power system will change. VG is a catalyst, but

consider other challenges to traditional assumptions and practices.

• Work to develop and demonstrate efficient probabilistic techniques and solutions that are capable of addressing full-scale industry problems.

• Improve the understanding of probabilistic methods within the industry. Cooperative efforts of the research and industry communities are needed.

• More and better data are needed to allow the research and demonstrations to be meaningful and realistic – from real power systems, VG resources and future scenarios.

• Recommends that NERC perform a bi-annual assessment of development in this area, and that the IVGTF would be an appropriate home for this work.

Questions

Frequency Response

Robert W. CummingsNERC Director of Reliability Initiatives and System AnalysisERSTF MeetingJune 11-12, 2014

RELIABILITY | ACCOUNTABILITY2

NERC Frequency Response Initiative

• Work dates back to 1991 – EPRI/NERC collaborationFrequency Response Initiative • Kicked off in March 2010• Targeted research needed for Standard BAL-003 – Frequency

Response• Address confusion between Frequency Response and Frequency

Bias• Determine methodology for calculating Interconnection

Frequency response Obligations (IFROs)• Methods for detection of frequency events• Methods for measuring Primary Frequency Response Performance


Frequency Response Initiative

Frequency Response Initiative Report• Published in November 2012• Available at:http://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/FRI_Report_10-30-12_Master_w-appendices.pdf

http://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/FRI_Report_10-30-12_Master_w-appendices.pdf


FRI Recommendation 1

1. Develop Frequency Response Resource Guidelines to define the performance characteristics expected Existing Conventional Generator Fleet

o ±16.67 mHz deadbandso 3% to 5% droop – depending on turbine typeo Continuous, proportional (non-step) implementationo Appropriate operating modes to provide primary frequency responseo Appropriate outer-loop controls modifications to avoid withdrawal


FRI Recommendation 1

Other Frequency-Responsive Resources – to augment response with high-speed energy injection from electronically-coupled loads and resourceso Contractual high-speed demand-side responseo Wind and photo-voltaic – particularly for over-frequency responseo Storage – automatic high-speed energy retrieval and injectiono Variable speed drives – non-critical, short-time load reduction


Frequency Response Basics

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

Time (Seconds)

Gov

erno

r/Loa

d Re

spon

se (M

W)

59.60

59.65

59.70

59.75

59.80

59.85

59.90

59.95

60.00

60.05

60.10

Freq

uenc

y (H

z)

Governor Response

Load Response

Frequency

A

B

C

NERC Frequency Response =

Generation Loss (MW) FrequencyPoint A-FrequencyPoint B

Slope of the dark green line illustrates the System Inertia (Generation and Load). The slope is ΔP/(D+2H)

Pre Event Frequency

Frequency Nadir:Generation and Load Response equals

the generation loss

Settling Frequency: Primary Response is almost all deployed


Frequency Response Control Continuum

Secondary Control

(AGC)

Recovery of Reserves

SpinningReserves

Primary Control

(Gen. Response)Seconds to 1-2 minutes

Minutes

Minutes to Hours

Non-Spinning Reserves

Inertial Response Milliseconds


Typical Frequency Responses


59.94

59.95

59.96

59.97

59.98

59.99

60

60.01

60.02

0 6 12 18 24 30 36 42 48 54 60

Seconds

No “Point C” to “Point B” Recovery

Response “Withdrawal”

Typical EI Frequency Excursion


Function of dispatch – what types of units are on line and responding

Typical causes: Plant outer-loop control systems – driving the units to MW set points Unit characteristics o Plant incapable of sustainingo Governor controls overridden by other turbine/steam cycle controls

Operating philosophies – operating characteristic choices made by plant operatorso Desire to maintain highest efficiencies for the plant

Frequency Response Withdrawal


Sustained Governor Response Example


Squelched Governor Response Example


Negative Governor Response Example


EI Frequency Response Trend 2009-2014


EI Frequency Response Statistics 2009-2013

Year Number of Events

MW/0.1 Hz Events with FR below

IFRO (1,014

MW/0.1 Hz)

Mean of Frequency Response

Std. Dev. of Frequency Response

Min. Max.

2009–2013 259 2,339.3 603.0 698.7 4,335.9 3 2009 44 2,258.4 522.5 1,404.8 3,625.0 0 2010 49 2,335.7 697.6 1,102.5 4,335.9 0 2011 65 2,467.8 593.7 1,210.0 3,815.2 0 2012 28 2,314.3 523.6 1,374.0 3,921.4 0 2013 71 2,171.9 596.5 698.7 3,696.3 3


Future Frequency Response Work

• Analysis of outlier events• Annual verification of IFROs through modeling• Frequency Response Sensitivities and trending

• Starting Frequency• Event crossing 60 Hz• Seasonal variance• Time-of-day variance

• Analysis of linear regression versus median in performance measurement

• Develop Frequency Perturbation Index – better event tracking metric


• BA responsibility for Frequency Response Obligation (FRO) allocation

• Refines Frequency Bias Setting Implementation • Appropriate Frequency Bias Setting for those providing Overlap

Regulation Service, • Minimum Frequency Bias Setting• Minimum Bias Setting modified• Clarified the event selection process• Defined Frequency Response Sharing Groups

BAL-003 Frequency Responseat a Glance


IFRO Tenets

1. Should not trigger first stage of regionally-approved UFLS Systems

2. Unavoidable local tripping of first-stage UFLS systems for severe frequency excursions

– Protracted faults– Systems on edge-of the interconnection

3. Some frequency-sensitive loads may trip4. Other frequency-sensitivities have to be

considered– PV inverters tested trip at 59.4 Hz instead of 59.2 Hz

specified in IEEE Standard 1547– Electronically coupled loads with

common-mode frequency sensitivities


2014 Recommended IFROs

Eastern (EI)

Western (WI)

ERCOT (TI)

Québec (QI) Units

Starting Frequency 59.974 59.971 59.964 59.968 Hz

Max. Allowable Delta Frequency 0.444 0.261 0.449 0.947 Hz

Resource Contingency Protection Criteria 4,500 2,626 2,750 1,700 MW

Credit for LR – 150 895 – MW

IFRO1 -1,014 -949 -413 -180 MW/0.1Hz

Absolute Value of IFRO 1,014 949 413 180 MW/0.1Hz

Absolute Value of Current Interconnection Frequency Response Performance2

2,314 1,467 586 593 MW/0.1Hz

% of Interconnection Load3 0.16% 0.58% 0.60% 0.48%


IFRO Allocation Methodology

• Determine FRO based on the historic annual average monthly peak load and generation (FERC Form 714)

• Formula:

FROBA = IFRO x


EI Governor Response Survey

East

No Response, 159.9, 38%

Online, No Data on

Response, 53.2, 13%

Expected Response, 124.7, 30%

Opposite of Expected Response, 77.6, 19%


Governor Deadband Settings (2009 Survey)

5402000700

0

50

100

150

200

250

300

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400

<500 MW 500-1000MW

>1000 MW <500 MW 500-1000MW

>1000 MW <500 MW 500-1000MW

>1000 MW

East West Texas

Unit Size

Dea

dban

d Se

tting

(mH

z)

700


ERCOT Frequency Profile

0

5000

10000

15000

20000

25000

30000

35000

40000

59.9

59.91

59.92

59.93

59.94

59.95

59.96

59.97

59.98

59.99 60

60.01

60.02

60.03

60.04

60.05

60.06

60.07

60.08

60.09 60

.1

One

Min

ute

Occ

uran

ces

2010 2008

January through September of each Year


±0.036 Hz Vs ±0.016 Hz Deadband

0

20000

40000

60000

80000

100000

120000

140000

59.9

59.91

59.92

59.93

59.94

59.95

59.96

59.97

59.98

59.99 60

60.01

60.02

60.03

60.04

60.05

60.06

60.07

60.08

60.09 60

.1

MW

2008 MW Response of 0.036 db 2010 MW Response of 0.0166 db

545670.0

404989.0 2010 MW Response of 0.0166 db 25.78% Decrease in MW movement with lower deadband.

2008 MW Response of 0.036 db

MW Minute Movement of a 600 MW Unit @ 5% Droop


For Further Information

Frequency Response Initiative Report, October 30, 2012 at:http://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/FRI_Report_10-30-12_Master_w-appendices.pdf

Standards Project 2007-12 (BAL-003-1 Frequency Response and Frequency Bias Setting ) at:http://www.nerc.com/pa/Stand/Pages/Project-2007-12-Frequency-Response.aspx

http://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/FRI_Report_10-30-12_Master_w-appendices.pdf

http://www.nerc.com/pa/Stand/Pages/Project-2007-12-Frequency-Response.aspx

Essential Reliability Services Task Force

Clyde Loutan, Senior Advisor Renewable Energy Integration

June 11, 2014Orlando, Florida

California ISO by the numbers

60,703 MW of power plant capacity 50,270 MW record peak demand

(July 24, 2006) 26,024 circuit-miles of

transmission lines 246 million megawatts of

electricity delivered (2012) $8.5 billion annual market

(2012) 30 million people served One of 9 ISO/RTOs in North

America

Slide 2

• Greenhouse gas reductions to 1990 levels by 2020

Limits on availability of air emission credits for replacement generation

• 33% of load served by renewable generation by 2020

• Possibly 12,000 MW of distributed generation by 2020

• Less predictable load patterns – rooftop solar, electric vehicles, and smart grid

• Scheduled phase out of approximately 12,000 MW of once-through cooling in coastal power plants

• Delta bay plan managing water flow affecting hydro availability

California ISO faces unique challenges driven by success of state initiatives and environmental policies

• Increased requirements for regulation up and down

• Need to manage increased intra-hour flexibility and multiple hour daily ramps Approx. 3,000 MW of intra-hour load-following

Approx. 13,000 MW of continuous up-ramp within a 3 hour time period (almost double current up-ramps)

• Non-dispatchable resources serving load varies between 10,000 MW to 12,000 MW based on maximum capability of resources

• Increased instances of over-generation conditions

• Need to comply with a frequency response obligation following a disturbance (Compliance with BAL-003-1)

• Impact of DER resources on the BES is still not fully understood

Summary of future grid operations to manage a more complex grid

The ISO has already begun to experience the need for flexible resources

Slide 5

Load

& N

et L

oad

(MW

)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

30,000

32,000

34,000

Load, Wind & Solar Profiles --- Base ScenarioJanuary 2020

Net_Load Load Wind Total Solar

Win

d &

Sol

ar (M

W)

6,700 MW in 3-hours

7,000 MW in 3-hours

12,700 MW in 3-hours

Net Load = Load - Wind - Solar

The ISO faces four related planning challenges

1. Downward ramping capability Thermal resources operating to serve loads at night must be ramped downward and potentially shut down to make room for a significant influx of solar energy after the sun rises.

2. Minimum generation flexibilityOver-generation may occur during hours with high renewable production even if thermal resources and imports are reduced to their minimum levels. A system with more flexibility to reduce thermal generation will incur less over-generation.

3. Upward ramping capabilityThermal resources must ramp quickly from minimum levels during daytime hours and new units may be required to start to meet high net peak demand occurring shortly after sundown.

4. Peaking capabilityThe system will need enough resources to meet the highest net-loads with sufficient reliability

6

Non-Flexible resources creates dispatch issues and potential over-generation conditions

Slide 7IOU – Jointly Owned Units

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

30,000

Potential Over-generation ConditionsBase Load Scenario

Oth QFs Gas QFs Nuclear Geothermal Imports S_Hydro CCGT & Hydro LF Down Reg. Down Net Load

Qualifying Facilities (QFs)

Gas (QFs)

NuclearGeothermal

Small Hydro (RPS)Minimum Dispatchable Thermal & Hydro Resources

Load Following DownRegulation Down

CAISONet Load 2020

Imports (JOU & Dynamic Schedules)

CAISONet Load 2020

ISO’s net-load vs. actual RTD energy prices for April 12, 2014

Energy prices were zero or negative for 43% of the 5-minute RTD intervals

Slide 8

-40

-20

0

20

40

60

80

14,000

15,000

16,000

17,000

18,000

19,000

20,000

21,000

22,000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

5-M

inut

e En

ergy

Pric

es ($

)

ISO

's N

et L

oad

(MW

)

ISO's Net Load vs. Average 5-Minute Energy PricesApril 12, 2014

Net Load MCP_RTD 5-Min_Prices<=Zero 5-Min_Prices>$100

Negative energy prices indicating over-generation risk start to appear in the middle of the day during high renewable production days.

0

20

40

60

80

100

120

140

160

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

# of

Occ

urre

nces

Distribution of Negative Prices - March, April & May (2012 vs. 2013)

2012 2013

Increase in real-time negative prices during some hours due to load and supply variability.

Slide 9

• Four essential characteristics of conventional generation needed from VERs for stable and reliable BPS operations:

Capability to provide reactive power support;

Capability to increase or reduce energy output automatically, in response to system frequency;

Ability to limit power production as needed for the promotion of reliability; and

Capability to provide inertial/frequency response.

CAISO proposes to require VERs to contribute to essential reliability services due to its unique operating challenges

Market Enhancements Help the Integration of Variable Resources

CAISO Market Enhancements Active flexible capacity procurement Dynamic transfers Lower bid floor to incentivize economic curtailment Pay-for-performance regulation FERC 764, intra-hour scheduling Proposed enhancements to the California Public Utilities Commission’s

(CPUC) resource adequacy program Energy Imbalance Market (Regional Coordination) Dispatchable VERs Reliability Tools

o Load Following Requirement Toolo Regulation Prediction Toolo VER Forecast Improvements

Slide 11

All of the above including regional coordination

Generation Storage

DemandResponse

DispatchableQuick Start

Wider Operating Range (lower Pmin)

Load Shift

Over Generation Mitigation

Voltage Support

Peak Load Reduction

Dispatchable Wind/Solar

Fast Ramping

Regulation

Frequency Response

Slide 12

Coal Retirement and VG Integration in OntarioDave Devereaux, Control Room SupportNERC ERS Task Force June 11, 2014

Ontario

2

An Evolving Landscape

2003 Ontario government commits to coal closures

2006 First wind farms commissioned2009 Ontario announces Feed-In-

Tariff program2009 Demand decreased 6.1% compared to

previous year 2010 Long-term Planned renewable targets2011 4500 MW new gas since 2006

3.6 million Ontarians on Time of Use2014 Coal retirement complete

3

Ontario’s Installed Capacity

4

Considerations

• Performance:– Frequency control & governor

response– Ride through– Voltage Control

• System Balance:– Displacement of the historical

fleet– Surplus Baseload Generation– Operating reserve– Load following, Ramping

5

Our Response

What We Had: What We Did:

Market Entry/ Registration Process

Connection Requirements

Performance Requirements

Connection/Performance:• The “equivalent machine”

Renewable Integration:• Visibility• Central forecast• Dispatch – Wind and Nuclear• “Floor” Pricing

Load flattening:• Time of use pricing, Uplift

allocation6

What we have seen

• Challenges:– Surplus Base Load Generation– Operability – fewer mid-range resources on-line, new

operating characteristics– Importance of imports/exports– Operating Reserve – shoulder seasons– High Voltage

• Good:– Load pattern shifting

7

References

IESO Connection Requirements

Performance Validation

Questions?

8

http://www.ieso.ca/Documents/marketRules/mr_chapter4appx.pdf

http://www.ieso.ca/Documents/marketAdmin/ma_PerformanceValidation.pdf

N E R C E R S T F | O R L A N D O , F L

ISO New EnglandOperating Procedure 17

Load Power Factor Correction

John M SimonelliD I R E C T O R

O P E R A T I O N S S U P P O R T S E R V I C E S

Objective of Presentation

• Describe ISO-NE’s Load Power Factor (LPF) Correction Program- Why have a LPF Correction Program- Administrative Structure- Determining LPF Standards New England LPF Areas Study Methodology Example

- Load Power Factor Standards and Audits

2

What is the ISO LPF Correction Program

• Program consists of the following:- Perform Annual Load Power Factor Studies

Revising the LPF metrics used to measure performance Performed to establish local LPF standards for use with the

annual LPF surveys Performed as system condition changes warrant, i.e., changes

- Conduct Annual LPF Survey Audit of LPF performance Identification of non-compliance by entity, with required

reporting on remediation- Report LPF Survey Results

Reporting of performance Provided to stakeholders Allows continuous feedback on system voltage / reactive needs

as conditions evolve

3

Why have a LPF Correction Program

• Reactive resources for transmission system operation must be sufficient to deal with:

- A wide range of system load levels- A wide range of power transfer levels- Transmission and/or generator contingencies during a

planned, forced or emergency outage condition - Charging from high voltage transmission cables (acute

during light loads)- etc

4


• Voltage/Reactive (V/R) performance of the transmission and sub-transmission systems are not independent - In general, VARs are best supplied/absorbed locally, which

is the genesis of New England LPF correction requirements- Load should not over-rely on reactive support (lagging or

leading) from the transmission system, while the transmission system should not solely depend on the load for reactive support (lagging or leading)

- Potential cost of compensation can be significantly higher on the transmission side

5


• Establishes acceptable operating range of LPFs for distribution companies based on worst operating conditions for low or high voltage conditions

• Failure to maintain that operating range can result in:- Voltages that appear adequate but may not be sustainable

if reactive resources are depleted post contingency- Overhead circuits and/or underground cables may have to

be opened (balance system needs with equipment LOL)- Inability to maximize thermal and stability transfer limits

due to V/R shortcomings

6

Administrative Structure

• ISO-NE Operating Procedure - 17, Load Power Factor Correction, documents the program

• Roots traced back to New England V/R issues in the 1980’s, renewed focus during New England build out

• Administered with input from all major Transmission Owners through the Voltage Task Force (VTF)- Maintenance/evolution of OP-17- Annual updates to the LPF standards- Annual survey and reporting of actual LPFs with warranted

Participant remediation

7

Administrative Structure

• The VTF is chaired by the ISO to ensure independence- VTF reviews changes in New England operating practices

and/or procedures which affect transmission network V/R performance including: changes in generator voltage schedules, reactive resource use and/or availability, load-tap changer schedules, etc.

- Annual reports on updated LPF requirements and annual audit results given to the New England Stakeholders

- OP-17 modifications when required, are “reviewed” by the New England Stakeholders

8

Reasons for Updating LPF Standards

• Changes in area voltage/reactive performance due to transmission changes:- New transmission lines- New bulk transformers - Generation Retirement - Changes in generator reactive capability- Additional static or dynamic reactive compensation- Changes in transfer conditions- Load growth since last Area LPF study- Change of Area definition- Revision of “Testing Criteria” assumptions

9

Determining Load Power Factor Standards

• New England is divided into 11 LPF study areas based on their reactive characteristics, performance and operating footprint, based in part on one or more of the following characteristics:- Import or export area- Constrained by Limiting Transmission interface- Charging from cables or long overhead lines- Location of reactive resources with respect to interfaces

and load – shunts, SVCs, STATCOMs, DVARS, generators, HVDC terminals

- Etc. (you know your system)

10

Graphical Representation of the 11 LPF Areas

11


• For each area, minimum and maximum LPFs are determined at three specific load levels (light, intermediate, peak)

• Based on the three load levels, ranges of acceptable LPFs through load level are established for each area based on uniform (by bus) LPF Criteria

12


• Each LPF area is assessed individually to ensure its own reactive security as well as that of the neighboring LPF areas- N-1-1 philosophy- Low/High voltage limits respected- The golden rule: zero net VAR interchange criteria which

ensures area independence while minimizing the impact on neighboring areas

13

Study Methodology

• Minimum Allowable Load Power Factors (Based on Low Voltage Bias followed by the most critical contingency )– Low voltage bias: Create conditions conducive to high reactive losses and low

voltage, i.e., bias case with heavy transfers and a reasonable conservative local area dispatch Utilize all transmission capacitors and maximize unit voltage

schedules to increase lagging output without exceeding voltages limits contained in Operating Procedure #12 Decommit the local generator with the largest lagging

reactive capability

14

Study Methodology

• Minimum Allowable Load Power Factors (Based on Low Voltage Bias followed by the most critical contingency )

– Most critical contingency: Screen all “normal” contingencies defined in ISO Operating

Procedure #19 (basically NERC Category A and B) Determine the transmission line or generator contingency

that will maximize reactive losses in the area thereby depressing overall area voltage Apply this contingency

15

Study Methodology

• Minimum Allowable Load Power Factors (Based on Low Voltage Bias followed by the most critical contingency )

– With the most critical contingency applied, scale LPF down until:

A significant collection of buses are below voltage criteria of .95% or Any further reduction in LPF requires net MVAR import on

area boundary tie lines

16

Study Methodology

• Maximum Allowable Load Power Factors (High Voltage Bias with both N-1 and N-1-1 testing) – High Voltage Bias:

Create conditions conducive to low reactive losses and high voltage, i.e., bias case with light transfers and a reasonable conservative local area dispatch

Utilize all transmission reactors, minimize unit voltage schedules to increase leading output without exceeding voltage limits contained in Operating Procedure #12

Decommit the local generator unit with largest leading reactive capability,

17

Study Methodology

• Maximum Allowable Load Power Factors (High Voltage Bias with both N-1 and N-1-1 testing) – N-1 testing:

Screen all “normal” contingencies defined in ISO Operating Procedure #19

Determine the transmission line, reactor or generator contingency that will minimize leading reactive capability within the area

Apply this contingency

– With the most critical contingency applied, scale LPF up until: A significant collection of buses are above voltage criteria of

1.05% or Any further reduction in LPF requires net MVAR export on

area boundary tie lines

18

Study Methodology

• Maximum Allowable Load Power Factors (High Voltage Bias and both N-1 and N-1-1 testing) – N-1-1 Testing (accounts for maintenance outages

conducted during light and shoulder load levels): Pre N-1

Starting from the high voltage biased case described above Determine the transmission line, generator or dynamic

reactive (SVC, STATCOM, etc.) resource that will further minimize leading capability

Take this facility out of service (note this creates a case representative of typical maintenance periods with multiple facilities out)

Note: shunt reactors are not taken out of service in this testing. These facilities will not be taken out of service for maintenance during light or shoulder load levels.

19

Study Methodology

• Maximum Allowable Load Power Factors (High Voltage Bias and Contingency N-1-1)

Post N-1 Screen all “normal” contingencies defined in ISO Operating

Procedure #19 Determine the next transmission line, reactor or generator

contingency that will further minimize leading capability in the area

Apply this contingency

– With these N-1-1 conditions, scale LPF up until: A significant collection of buses are above voltage criteria of

1.05Note: 0-MVAR net interchange criteria is not respected under this N-1-1 testing. When in these N-1-1 conditions, Areas are allowed to lean on their neighbors, within reason.

20

Study Methodology

• Maximum Allowable Load Power Factors (High Voltage Bias and both N-1 and N-1-1 testing)

– Finally, all maximum Load Power Factor values found in the N-1 and N-1-1 testing are reviewed and the appropriate LPF standard is selected

– The N-1-1 is a verification test to ensure the N-1 LPF value will support a robust system during light and should load maintenance periods where we do allow for some reactive assistance from neighboring areas

21

Study Methodology

• A sample Area LPF Standard curve, developed through an Area LPF study, is shown on the next slide. The Area Standard is used as a measure of compliance.

22

Load Power Factor Standards (General Concept)

0.7000

0.7500

0.8000

0.8500

0.9000

0.9500

1.0000

1.0500

Light Intermediate Peak

LO

AD

PO

WE

R F

AC

TO

R

New England LOAD LEVEL

Minimum PF

Maximum PF

Lead

ing

Lagg

ing

0.9500

23

Annual Load Power Factor Survey• ISO-NE and VTF are responsible for:

– Administering the annual LPF survey– Evaluating and reporting results– Requesting remedial action plans from Market Participants

• Each year specific historical hours are selected from the previous year

• Each load serving Participant ( as defined in OP17) is tasked with submitting LPF data for the selected historical hours

• Participant’s surveyed LPFs are compared to the corresponding Area’s LPF Standard for the specified hours

• The degree of noncompliance for each Participant is identified in terms of surplus or shortfall of reactive capability– Changes in the underlying networks (i.e. adding caps) can impact

compliance with survey requirements

24

Example of Load Power Factor Standard and Survey

25

Annual Load Power Factor Survey

• The annual LPF Survey Program accomplishes two goals:– Audit Market Participants’ compliance with the current

LPF standards – Forecast Market Participants’ compliance with the new

standards if the current standards are revised/updated for any of the reasons specified in the previous slide

26

NERC

OP17 program cited in previous

NERC readiness audits as an Example

of Excellence

27

NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Operating Reserve, Frequency Response,

Ramping Capability and Active Power Control

NERC Essential Reliability Services Task Force

Michael Milligan

Orlando, FLJune, 2014

2

Revision history

• Original number of slides = 31• Deemed “too long”• Shortened to 60 slides (22 + “appendix”)

3

Theme: Smart grids need smart incentives – or at least no dis-incentives• If a service is important for reliability – it should be

incentivized – and not dis-incentivized• Technical capability to perform most/all of these functions

exists today in resources such aso Old and new generationo Demand responseo Storage

• Incentives don’t exist for many crucial reliability services and that will impede progress

• Therefore: reliability will depend, to some extent, on markets and/or incentives

• Rules can replace markets and economic incentives, but will generally result in higher costs

4

Topics

• Services neededo PFCo Inertiao Rampingo (Others covered elsewhere)

• APCo This is a source for services such as those above

• Takeaway:o We don’t know whether there is an emerging

reliability issue resulting from a combination of retirements and new technologies

o As an empirically-based industry, we need to figure it out based on sound engineering and analysis

5

High-level questions

• Should NERC specify unit capabilities that apply to all generators?

• Should NERC instead prescribe systemperformance and allowo Different technologies to compete (or not) depending

on their relative capabilitieso RTO and non-RTO areas to determine the mechanism

to secure needed performance (similar to CPS2 [BAAL])

o Contribution to DSC, CPS2/BAAL• Does a balancing metric at different time scales

supersede requirements for specific services (such as ramp, inertia, etc.)?

6

High-level questions (2)

• Should NERC rules provide maximum flexibility to system operators (RTO, non-RTO) to secure needed services?o Market provisiono Non-market

• Should NERC rules be technologically neutral to allow o Existing technologies to develop capabilities if

economic/if they are ableo New technologies to emerge to provide needed

services

7

Issues

Issues Source of need (2)

Today is supplied by (3)

Tomorrow supplied by

Potential Mechanism

Ramp Load, VG, Non-responsiveresources

Flexible resources (may include DR)

(3) + VG, storage Depends on definition – fast energy, ramp product

PFC Load, VG, non-responsive resources

Governor response

(3) + VG, storage Market or requirement

Inertia Stability requirements

Large rotating mass

(3) + wind (+ other syntheticsources?)

Market or requirement

Reserves Load,contingency (implicit load requirement

Various resources

(3) + VG + ? Market or requirement –better definitions needed

8

A look at the issues

• PFC• Inertia• Ramping• Reserves

9

Primary Frequency Control

• Decline in the Eastern Interconnection linked to lack of incentive to provide it – not VG

• System service – not all units need to provide it• How to quantify the need and the capability• How should it be incentivized (rule, market, other)• Performance criteria should be based on system need

vs. response – metrics TBD• Can be supplied by several technologies including DR,

Wind – and possibly new technologies• Retirements: negative impact• New technologies: positive impact• Net: Needs to be evaluated – may/may not be a

significant reliability impact

10

Inertial Response

• Important to arrest frequency decline after disturbance

• Should rules addresso Equivalent inertia in system (includes actual +

simulated response)o System performanceo Hybrid

• Retirements: negative impact• New technologies/simulated response: positive

impact• Net: Needs to be evaluated – may/may not be a

significant reliability impact if done correctly

11

Ramping needs in the future

• Unclear whether fast (5-min) economic dispatch is sufficient• …or whether ramp “product” is necessary as a supplement• NREL research indicates this need is a function of look-ahead

in the SCED• Need can be quantified• Multiple technologies can provide it• Do we need a standard? Or do we need a performance-based

metric such as CPS2, BAAL, that implicitly addresses ramping?

• Retirements: large base units generally don’t ramp well so minimal overall impacts

• New technologies (fast-ramping gas, VG) can (self-)mitigate or even improve capability

• Institutional constraints such as self-scheduling can inhibit• Net: need to be evaluated: likely improvement in capability

12

One way to categorize reserves

• Ela, E.; Milligan, M.; Kirby, B. (2011). Operating Reserves and Variable Generation. A comprehensive review of current strategies, studies, and fundamental research on the impact that increased penetration of variable renewable generation has on power system operating reserves. 103 pp.; NREL Report No. TP-5500-51978. Available at http://www.nrel.gov/docs/fy11osti/51978.pdf

Operating Reserve

Regulating Reserve

Contingency Reserve

Following Reserve

primary

Ramping Reserve

Non-event Event

Correct the current ACE

ManualPart of optimal dispatch

Instantaneous Non-Instantaneous

secondary tertiary secondary tertiary

Stabilize Frequency

Return Frequency to nominal

and/or ACE to zero

Replace primary and

secondary


and/or ACE to zero

Replace secondary

AutomaticWithin optimal dispatch

Correct the anticipated ACE

http://nrelpubs.nrel.gov/WebtopSecure/ws/nich/int/nrel/Record?rpp=25&upp=0&m=1&w=NATIVE('TITLE_V+ph+words+''Operating+Reserves+and+Variable+Generation''')&order=native('pubyear/Descend')

http://www.nrel.gov/docs/fy11osti/51978.pdf

13

Reserves for VG

• VG adds to the need for o Regulationo Spino Non-spin

• Typically in addition to contingency reserve, and contingency reserve is often “off limits” to deploy for VG event

• …therefore we refer to this reserve as “flexibility reserve” (although there is no standard term)

• VG movements are too slow for a contingency

14

Problems with “standard” reserve defs• All are linked to contingency only• No generally-accepted category

for VG-induced reserve• Spin, non-spin, supplemental• Based on historical knowledge of

implicit “reserve” for load pickup/falloff – changes with large levels of VG

• Minimum time-step is 10 minutes – many technologies can do better, but not recognized

• Can/should contingency reserve be deployed for “large” VG events? How much/how often and impact on system risk are unknown and un-studied

15

Example of underpinning of “flex” reserve

0

50

100

150

200

250

300

350

400

450

0 1000 2000 3000 4000 5000 6000 7000

Sigm

a of

For

ecas

t Err

or (M

W)

Wind Production Level (MW)

Hour-Ahead Forecast Error Sigma vs. Production Level

Dynamic reserves for VG becoming widely accepted/adopted.

16

Reserve can be reduced by changes in operating practice

Milligan, Kirby, King, Beuning (2011), The Impact of Alternative Dispatch Intervals on Operating Reserve Requirements for Variable Generation. Presented at 10th International Workshop on Large-Scale Integration of Wind (and Solar) Power into Power Systems, Aarhus, Denmark. October

Faster Faster Faster

Large Medium Small

17

Reserves summary

• New definitions may be needed• Current 10-min boundaries likely insufficient• VG can likely “self-supply” part of its

increased need• Slow-responding units that may retire may

not have large influence on supply of “flex”• Units dispatched down can provide up-

reserve if online• Net impact: likely increase, but ability to

respond is currently not widely known

18

Active Power Control

• Can be a supply of services: ramp, AGC, PFC, inertial response (synthetic)

• Current research is demonstrating this capability exists via power electronics of wind turbines

• This capability has been studies via simulations that have concluded that o “Although we found little risk of events causing the

need for under frequency load shedding without controls from wind power, the ability of wind power plants to provide PFR, and the combination of inertial response and PFR, gave a significant improvement in the frequency response performance of the system”

19

Wind APC is an active area of research

• See for example NREL’s Active Power Controls for Wind web page http://www.nrel.gov/electricity/transmission/active_power.html

0 s typically, 5 - 10 s

typically, 20 - 30 s

typically, 5 – 10 min

Initial slope of decline is determined by system inertia (or cumulative inertial response of all

generation)

Primary Freq. Control AGC

http://www.nrel.gov/electricity/transmission/active_power.html

20

Summary (1)

• One cannot conclude that the increase in VG and decrease in large rotating mass is a reliability threat without solid analysis

• The questions raised in the ERSTF staff report must be resolved in a solid empirical, engineering, scientific, and analytical framework

21

Summary (2)

• Reliability rules should be technology-neutral to encourage innovation

• Metrics for most of these services need development, as do performance metrics and criteria

• New technologies, and adaptations of existing technologies, are possible and should not be ruled out by technology-specific rules/standards – they should be performance-based and verifiable

• Many questions remain regarding the so-called “threat” to reliability because there are impacts on both sides of the equation

NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Questions/discussion

23

Appendix

24

Significant research is underway

• …some of which is described below

25

NREL Bulk Power Integration Research

Power System Operations

Power System Planning

Wholesale Electricity

Market Design

Operational Forecasting

Generator Modeling

Stakeholder Engagement

Testing

• Operational strategy modeling• Operating reserve requirements• Operations of emerging resources (e.g.

DR, Storage)• Integration Studies

• ELCC, LOLP, with renewables• Transmission Expansion Planning• Policy issues, Order 1000, etc.• Flexibility needs of the future

• Flexibility market designs• Revenue sufficiency• Ancillary service market designs,

primary frequency response market

• Error characteristics of wind, solar, load forecasts

• Economic and reliability metrics of forecasts

• Probabilistic forecasts

• Generic wind and solar models• Three phase and positive sequence• Validation using PMUs• Update models to include new

freuqency, voltage controls, damping controls, etc.

• Wind, solar frequency and voltage controls• Controllable Grid Interface

• NERC IVGTF, FERC, IEEE PES, International, utility technical review committees, WECC, universities, RTO

26

Reliability Requirement & Tools to Achieve it

• Reliability requiremento Balancing energy over time frames from cycles to

hours• Historic parsing based partly on incumbent

technologyo Inertia

– Recognized but not explicitly specified– Assumed characteristic of the historic generation fleet

o Autonomous governor/frequency response– Partly specified– Assumed characteristic of the historic generation fleet

o UFLS & some demand response– Reserve requirement (frequency & time)

27

Reliability Requirement & Tools to Achieve it (2)o Regulation

– Performance requirement (CPS or BAAL)o Contingency reserves: spin/non-spin/supplemental

– Performance requirement (DCS)– Reserve requirement

o Ramping– Recognized but not specified. Operator actions modify economic

dispatcho Energy transactions: 5-minute/hourly/…

– Facilitated resource with performance requirements• Historically we have parsed the time domain based on the

characteristics of the generation fleet and have used a mixture of assumed characteristics, performance requirements, and reserve requirements to maintain reliability

• New technologies may change both the parsing & the available response but not the underlying reliability balancing requirement

28

What do inertia, PFC, and ramping have in common?

• The need is a system need, not an individual (load or resource) need

• They do not scale linearly• Therefore – not all resources must provide

these services for the system to achieve prescribed reliability level

• Exampleso AGCo Ramping (in today’s system)

29

New Technologies Offer Challenges and Solutions

• Wind & solar displace conventional generatorso Concern

– Reduced inertia & changed frequency responseo Potential solutions

– Synthetic inertia from wind– Very fast over frequency response from wind and solar – Very fast demand response – Storage

• Reliability rules need to change to address both the challenges and opportunitieso Historic assumptions need to be examinedo Forcing new technologies to emulate historic

technologies is inefficient at best

30

Not All Reliability Challenges Result From New Technologies

• Decline in PFR in the East is tied to lack of incentiveso Historic resources will only support reliability if

compelled or provided with incentiveso Very little new VG relative to load, and likely an

insignificant contributor to PFR decline (LBNL report)

31

Guidance for ERS can be found elsewhere

• A system requirement is consistent with system response

• AGCo Total is nonlinear sum of individualso Not all units do (or can) provide AGC

• CPS2 requirementso Total system; is not tied to individual resources

• Different technologies have different strengths – no one-size-fits-all

• Markets may be able to elicit needed service

32

Advantages for a system approach

• Allows for the acquisition of the needed level of response – not too much (expensive) but sufficient (maintain reliability)

• Recognizes different resources’ capabilities• Requirements are tied to physical

requirements• Allows for technological advancements and

competition between resource types

33

Examples

• Wind technology can now provide synthetic inertial response, AGC response

• Can provide up- and down-ramp (subject to economics)

34

Questions

• What metric(s) for inertia?• How much is needed?• What performance standard and how

enforced?

35

Primary frequency response and inertia

• Concern regarding high levels of VG and reduction in spinning mass – will it impact reliability?

• Decline in PFR in the East is tied to lack of incentives

• Thus there is a key link between market structure and reliability

36

NREL’s Active Power Control Project

37

What is Active Power Control?f

60 Hz

0 s typically , 5 - 10 s

typically, 20 - 30 s

typically, 5 – 10 min

Initial slope of decline is determined by system inertia (or cumulative inertial response of all

generation)

Primary Freq. Control AGC

• Control of active (real) power to balance generation and load

• Required at multiple timescales to maintain reliability and security

• During events (e.g., large generator faults)

• During non-events (i.e. continuous control)

38

Questions & Objectives for NREL project

• What is the technical feasibility of wind power plants providing APC?

• How does it affect the dynamic system response?• How will it its provision change the steady-state

operations?• Will its provision be economic for consumers? Will it

be economic for wind plant providers?• How will it impact the loading on the turbines and

components? Will it affect the life of the turbine?• How will policies and standards affect the designs?• Are there advanced designs that can provide the

tradeoff between structural loading and response performance?

39

Power System Reliability

• What other strategies improve frequency response?

• Study the Eastern and Western Interconnections.

• Up to 50% penetrations.

59.55

59.6

59.65

59.7

59.75

59.8

59.85

10% 20% 30% 40% 50% 60%

FREQ

UEN

CY N

ADIR

(Hz)

WIND POWER PENETRATION (%)

Base Case

Inertia only

PFC only

Inertia + PFC• How does greater penetrations of

nonsynchronous wind power affect the frequency response of an interconnection?

• How does wind providing APC improve these results?

40

Control Design and Testing, and Loading Impacts

• What designs can improve response performance while limiting loading impacts??

• Design Simulation?

41

NREL PFR-related simulations

• Simulations on the Western Interconnection have shown PFC and inertial control of wind plants can improve frequency response performance of the system

• http://www.nrel.gov/docs/fy13osti/58995.pdf

If appropriately equipped with the necessary control features, inverter-coupled wind generation technologies are capable of contributing to PFR and inertia. This capability can help alleviate those concerns. However, these responses differ from those supplied by conventional generation, and it is not entirely understood how they will affect the system response at different penetration levels. The focus of the simulation work presented in this paper is to evaluate the impact of wind generation providing PFR and synthetic inertial response on a large interconnection. All simulations were conducted on the Western Interconnection system with different assumptions of wind power penetration levels. It should be noted that the results presented here are hypothetical, so they do not claim to demonstrate the actual present of the North American Western Interconnection. Although we found little risk of events causing the need for under frequency load shedding without controls from wind power, the ability of wind power plants to provide PFR, and the combination of inertial response and PFR, gave a significant improvement in the frequency response performance of the system; providing inertia alone did not improve performance. The simulation results also showed how other individual responsive units are affected by different levels of wind power and various control strategies. Last, we provided a case study with the realistic assumption that not all conventional units would be providing PFR; whereas the provision of wind power providing PFR in high wind power penetrations actually avoided triggering under frequency load shedding. The simulation results provide insight in designing and operating wind generation active power controls to facilitate adequate PFR of an interconnection.


42

NREL PFR-related research

• Market or other economic incentives can improve PFR of the system by incenting resources to provide it

• Ela, E.; Gevorgian, V.; Tuohy, A.; Kirby, B.; Milligan, M.; O'Malley, M. (2014). Market Designs for the Primary Frequency Response Ancillary Service - Part II: Case Studies. IEEE Transactions on Power Systems. Vol. 29(1), January; pp. 432-440; NREL Report No. JA-5D00-55357. Available at http://dx.doi.org/10.1109/TPWRS.2013.2264951

•• Ela, E.; Gevorgian, V.; Tuohy, A.; Kirby, B.; Milligan, M.; O'Malley,

M. (2014). Market Designs for the Primary Frequency Response Ancillary Service -- Part I: Motivation and Design. IEEE Transactions on Power Systems. Vol. 29(1), January; pp. 421-431; NREL Report No. JA-5D00-55356. Available at http://dx.doi.org/10.1109/TPWRS.2013.2264942

http://nrelpubs.nrel.gov/WebtopSecure/ws/nich/int/nrel/Record?rpp=25&upp=0&m=1&w=NATIVE('AUTHOR+ph+words+''milligan''')&order=native('pubyear/Descend')

http://dx.doi.org/10.1109/TPWRS.2013.2264951

http://nrelpubs.nrel.gov/WebtopSecure/ws/nich/int/nrel/Record?rpp=25&upp=0&m=2&w=NATIVE('AUTHOR+ph+words+''milligan''')&order=native('pubyear/Descend')

http://dx.doi.org/10.1109/TPWRS.2013.2264942

43

APC Project issues

• Markets and incentives• Additional simulation, testing, analysis• Questions:

o What is economic mix of AGC, simulated inertia, other controls from wind and other?

o What is impact on wind turbine wear and tear?o What incentives are appropriate to elicit these

services across the entire fleet?

44

Ramping and Reserves with VG

45

Ramping – and turn down – needs increase

46

Need for ramping can be mitigated by large balancing regions

• This means:o Overall variability (per unit) of net load declineso Operating reserve (required generation flexibility) requirements

are reduced, saving money

-3000

-1000

1000

3000

1 25 49 73 97 121 145 169

Redu

ctio

n in

Ram

p De

man

d (M

W/h

r)

Hours

Unnecessary ramping of generation can be minimized with a larger market area

Net

Load

47

Ramping needs can be characterizedAverage Timimg of Net Ramps in Footprint EIM

Hourly average over the weeks of the yearAverage net ramp in MW

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23Hour

0

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Wee

k of

the

Yea

r

5614

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720

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-20000

0

20000

40000

60000

0 2 4 6 8 10 12

Ram

p M

agni

tude

(MW

)

Ramp Duration (Hours)

Probability of Net Ramp Magnitude and Duration

100% Prob.99.9% Prob.99% Prob.95% Prob.90% Prob.

M. Milligan, J. King, and B. Kirby (2011). Flexibility Reserve Reductions from an Energy Imbalance Market with High Levels of Wind Energy in the Western Interconnection. 100 pp.; NREL Report No. TP-5500-52330. http://www.nrel.gov/docs/fy12osti/52330.pdf

http://nrelpubs.nrel.gov/Webtop/ws/nich/www/public/Record?rpp=25&upp=0&m=29&w=NATIVE('AUTHOR+ph+words+''milligan''')&order=native('pubyear/Descend')

48

Does technical capability to ramp exist?• Hydro – if not constrained• Some thermal units• Demand response• Market response from wind, solar, such as thru MISO’s

Dispatchable Intermittent Resource (DIR) program• Self-schedules reduce the available flexibility and can

drive the need for more expensive solutions (NREL report forthcoming)

49

Does technical capability exist?

• Note: 10-minute spin product leaves some flexibility on the table – only access is from PFC and AGC, limiting response

Technology Unit Size

(MW)

Plant Size (MW)

Efficiency /Heat Rate (Btu/kWh,

LHV)

Start Up Time (minutes)

Ramp Rate(% of

capacity/min)

Minimum Load (%

of capacity)

Gas

Engi

ne Wartsila 50SG 18.76 18.76 –300+ 45.6% 7 mins to full load 70% 30%

Wartsila 34SG 9.34 9.34 – 200+ 44.6% 5 mins to full load 70% 30%

Com

bine

d Cy

cle

Wartsila 50SG w/ Steam Turbine 20.2 100 – 500+ 48.7%

7 mins to 90% power; 45 mins to

full output30%

GE FlexEfficiency60 7F 5-series

(2x1)655 655 >59% / <5,781

10 mins to 49.5%, 33 mins to full load

(hot start)

12.2% (80 MW/min)

22% base (145 MW)

GE FlexEfficiency60 7F 7-series

(2x1)750 750 >61% / <5,592

10 mins to 66.7%, 30 mins to full load

(hot start)

13.3% (100 MW/min)

14% base(105 MW)

Sim

ple

Cycl

e GT GE Flex 7F 5-series 216 216 >38.6% / 8,830 10 mins to 75%

load18.5% (40 MW/min)

36% base (78 MW)

FE Flex 7F 7-series 250 250 >40% / 8,530 10 mins to 100% load

20% (50 MW/min)

20% base (50 MW)

Aero

-de

rivat

ive GE LMS100 PA 105 105 7,900 10 mins to full load 47.6% (50

MW/min) <25%

GE FlexAeroLM6000 PC Sprint 49 49 8,500 10 mins to full load 34% (16.7

MW/min) <25%

50

Incentives for resources to ramp?

• 5-minute dispatch provides incentive; self-scheduling may inhibit this incentive

• Is there need for a new ramp product?o CAISO – yes – working on flexi-ramp

– Has lots of self-scheduled generation, which reduces available flexibility and drives the need to secure additional flexibility

o NREL research – multi-period look-ahead function in the dispatch, with binding advisory prices, can provide the same dispatch and incentives for units to provide ramping reserve – thus there may be alternatives to defining a new product

• Ramp-reserve product – or other reserve needed?

51

Flexiramp or multi-period look-ahead SCED

• Simple example from NREL’s FESTIV model

Flexiramp Multi-period Lookaheadintervals advisory

Multi-period LookaheadIntervals Binding

G1 cost $22,000 $22,000 $22,000G1 revenue $27,000 $24,500 $27,000G1 profit (rev – cost)

$5,000 $2,500 $5,000

G2 cost $3,900 $3,900 $3,900G2 revenue $4,150 $3,700 $4,150G2 profit (rev – cost)

$250 $-200 $250

52

Reserves

53

One way to categorize reserves

• Ela, E.; Milligan, M.; Kirby, B. (2011). Operating Reserves and Variable Generation. A comprehensive review of current strategies, studies, and fundamental research on the impact that increased penetration of variable renewable generation has on power system operating reserves. 103 pp.; NREL Report No. TP-5500-51978. Available at http://www.nrel.gov/docs/fy11osti/51978.pdf

Operating Reserve

Regulating Reserve

Contingency Reserve

Following Reserve

primary

Ramping Reserve

Non-event Event

Correct the current ACE

ManualPart of optimal dispatch

Instantaneous Non-Instantaneous

secondary tertiary secondary tertiary

Stabilize Frequency


and/or ACE to zero

Replace primary and

secondary


and/or ACE to zero

Replace secondary

AutomaticWithin optimal dispatch

Correct the anticipated ACE

http://nrelpubs.nrel.gov/WebtopSecure/ws/nich/int/nrel/Record?rpp=25&upp=0&m=1&w=NATIVE('TITLE_V+ph+words+''Operating+Reserves+and+Variable+Generation''')&order=native('pubyear/Descend')


54

Reserves for VG

• VG adds to the need for o Regulationo Spino Non-spin

• Typically in addition to contingency reserve, and contingency reserve is often “off limits” to deploy for VG event

• …therefore we refer to this reserve as “flexibility reserve” (although there is no standard term)

• VG movements are too slow for a contingency

55

Example from ERCOT: Wind is not a contingency event

Source: ERCOT, WindLogics

56

NREL’s Flex Reserve based on variability/uncertainty of VG at different output levels

0

50

100

150

200

250

300

350

400

450

0 1000 2000 3000 4000 5000 6000 7000

Sigm

a of

For

ecas

t Err

or (M

W)

Wind Production Level (MW)

Hour-Ahead Forecast Error Sigma vs. Production Level

NREL’s flex reserve approach is now in use at WECC.

57

Type of reserve is a function of ramping potential

• King, J.; Kirby, B.; Milligan, M.; Beuning, S. (2012). Operating Reserve Reductions from a Proposed Energy Imbalance Market with Wind and Solar Generation in the Western Interconnection. 90 pp.; NREL Report No. TP-5500-54660. Available at http://www.nrel.gov/docs/fy12osti/54660.pdf(30% wind energy penetration)

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30000

40000

0 120 240 360 480 600 720

Ram

p M

agni

tude

(MW

)

Ramp Duration (Minutes)

90-Percentile Ramp Envelopes

Load

Net

Wind

http://nrelpubs.nrel.gov/WebtopSecure/ws/nich/int/nrel/Record?rpp=25&upp=0&m=18&w=NATIVE('AUTHOR+ph+words+''milligan''+and+PUBYEAR+%3E=+2012')&order=native('pubyear/Descend')


58

…and risk level

• King, J.; Kirby, B.; Milligan, M.; Beuning, S. (2012). Operating Reserve Reductions from a Proposed Energy Imbalance Market with Wind and Solar Generation in the Western Interconnection. 90 pp.; NREL Report No. TP-5500-54660. Available at http://www.nrel.gov/docs/fy12osti/54660.pdf(30% wind energy penetration)

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Ramp Duration (Hours)

Probability of Net Ramp Magnitude and Duration

100% Prob.

99.9% Prob.

99% Prob.

95% Prob.

90% Prob.

http://nrelpubs.nrel.gov/WebtopSecure/ws/nich/int/nrel/Record?rpp=25&upp=0&m=18&w=NATIVE('AUTHOR+ph+words+''milligan''+and+PUBYEAR+%3E=+2012')&order=native('pubyear/Descend')


59

Flex requirements depend on operating practice

Milligan, Kirby, King, Beuning (2011), The Impact of Alternative Dispatch Intervals on Operating Reserve Requirements for Variable Generation. Presented at 10th International Workshop on Large-Scale Integration of Wind (and Solar) Power into Power Systems, Aarhus, Denmark. October

0

1000

2000

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4000

5000

6000

7000

8000

9000

10000

Footprint Regional BAU

Aver

age T

otal

Reg

ulat

ion (

MW

)Average Total Regulation for 6 Dispatch/Lead Schedules by Aggegation (Dispatch interval -

Forecast lead time)

10-1030-1030-3060-1030-4060-40

Faster Faster Faster

Large Medium Small

60

Conclusions

• Some ERS functions can be supplied by VG if proper incentives exist

• Some ERS functions are not currently provided by some large rotating units because incentives do not exist

• Simulations show wind can improve PFR, inertial responseo Field testing/verification of modeling is needed

• Ramping and reserve impacts can be quantified• Institutional constraints should be examined