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Ensuring a secure, reliable and efficient Power System in a Changing Environment Delivering a Secure Sustainable Power System 17 th August 2011 Outline Agenda Chair: Dick Lewis, Manager, Grid Operations Planning 10.00 a.m. Registration (Tea

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SLIDE 1

Ensuring a secure, reliable and efficient Power System in a Changing Environment Delivering a Secure Sustainable Power System

17th August 2011

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SLIDE 2

Outline Agenda

10.00 a.m. Registration (Tea and Coffee) 10.30 a.m. Introduction and welcome Fintan Slye, Director Operations 10.40 a.m. Overview of previous studies – Context Jon O’Sullivan, Manager, Sustainable Power Systems 11.00 a.m. Report on “Ensuring a Secure, Reliable and Efficient Power System” Shane Rourke, Sustainable Power Systems 11.40 a.m. Programme & Advisory Council Yvonne Coughlan, Sustainable Power Systems 12.00 a.m. Questions from Audience 12.20 a.m. Closing comments followed by Lunch Chair: Dick Lewis, Manager, Grid Operations Planning

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SLIDE 3

European NREAP 2020 Wind Figures

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SLIDE 4

Delivering a Secure Sustainable System

All Island Grid Studies Systems Report

  • Infrastructure Requirements

and Resource Assessment All Island Grid Studies

  • Power System Operational

Needs Facilitation of Renewables Studies

  • Ensuring the needs of the

future power system Sustainable Power Systems Report

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SLIDE 5

Ireland and Northern Ireland Wind Statisitcs

20% 22% 24% 26% 28% 30% 32% 34% 2002 2003 2004 2005 2006 2007 2008 2009 2010

Wind Capacity Factor

Capacity Factor

Ireland Northern Ireland

Installed 1425 MW 314 MW Maximum Output 1259 MW 314 MW Highest Instantaneous % 52.3 % 50 % Highest Daily Energy 37% 29% Annual Output % 2010 10% 7.2%

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SLIDE 6

Operational Boundaries

WMAX SMAX WMIN SMIN W0 W25 W50 W75 W100
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SLIDE 7

Operational Boundaries

WMAX SMAX WMIN SMIN W0 W25 W50 W75 W100
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SLIDE 8

Key findings

RoCoF capability and protection Conventional Generator Reserve performance Windfarms controllability and reactive power capability New operating procedures including embedded windfarms

Fundamental issues Loss of largest infeed Issues that can be mitigated Voltage Stability Transient Stability Network Loading Fundamental issues that need further analysis Non-issues according to modelling Voltage Control Fault Levels Small Signal Stability Temporary loss of wind power due to network faults Frequency Stability Short term frequency variations Power balance fluctuations and frequency regulation Frequency Stability

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SLIDE 9

Impact on Renewable Targets and Individual Wind Curtailment - 6000 MW Installed

34 38 42 46 50 60% 70% 80% 90% No Limit Wind+Import/ Demand+Export % 0MW Exports 610MW Export 1000MW Export

% Annual Energy from Wind % Individual Wind Curtailment

5 10 15 20 25 60% 70% 80% 90% No Limit Wind+Import/ Demand+Export % 0MW Exports 610MW Export 1000MW Export
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SLIDE 10

Follow Up Analysis – System Services

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SLIDE 11

Methodology

Analysis builds on the results of the FoR

– Using out-turn data and observed behaviour

Three type of analysis carried out

– Portfolio capability (theoretical maximum) – Actual availability (dispatch dependent) – Performance analysis

Two timeframes considered:

– Current: 2010 – Future: 2020

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SLIDE 12

Portfolio evolution

2010 portfolio – 2011 GCS 2020 portfolio – credible evolution of current portfolio

– Complementary to renewables targets – Sufficient investment to ensure capacity adequacy

Technology Net capacity change (MW) Wind + 4400 Interconnection + 500 CCGT + 700 OCGT + 800 Conventional thermal

  • 2000
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SLIDE 13

9,044 8,325 450 1,000 1,731 6,113

  • 2,000

4,000 6,000 8,000 10,000 12,000 14,000 16,000 2010 2020 Installed Capacity (MW)

Portfolio breakdown - by generation type

Wind Interconnection Conventional

Portfolio evolution

19% 46%

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SLIDE 14

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services

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SLIDE 15

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services

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SLIDE 16

49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50.0 50.1 50.2 1 2 3 4 5 6 7 8 9 10 Frequency (Hz) Time (mins)

Example of Incident

Recovery Period Normal Operating Period

50.0

Generator Trip

Reserve

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SLIDE 17

Frequency Response: Inertia (daily range)

10,000 20,000 30,000 40,000 50,000 60,000 01-Jan-10 01-Feb-10 01-Mar-10 01-Apr-10 01-May-10 01-Jun-10 01-Jul-10 01-Aug-10 01-Sep-10 01-Oct-10 01-Nov-10 01-Dec-10 Synchronous Inertia (MWs)

Daily Synchronous Inertia range (2010)

Max Daily Inertia Min Daily Inertia
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SLIDE 18

Frequency Response: Inertia

10,000 20,000 30,000 40,000 50,000 60,000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Synchronous Inertia (MW s) Percentage of hours in the year

Inertia Duration Curves

Inertia 2010
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SLIDE 19

Frequency Response: Inertia

10,000 20,000 30,000 40,000 50,000 60,000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Synchronous Inertia (MW s) Percentage of hours in the year

Inertia Duration Curves

Inertia 2010 Inertia 2020

Insecure region

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SLIDE 20

49.2 49.3 49.4 49.5 49.6 49.7 49.8 49.9 50.0 50.1 50.2 1 2 3 4 5 6 7 8 9 10 Frequency (Hz) Time (mins)

Example of Incident

Recovery Period Normal Operating Period

50.0

Generator Trip Inertia

Reserve

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SLIDE 21

Frequency Response: Operating Reserve

Automatic generator response to frequency deviation

– Timescales: Primary, Secondary, Tertiary … – Primary the most onerous

Grid Code requirement (Primary): at least 5% Reg Cap Portfolio has 8% capability overall

– Some generators with >> 5% – Other generators with < 5%

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SLIDE 22

Operating Reserve – Capability

19 27% 5 7% 21 30% 25 36%

Number of generators: contracted POR vs GC required POR

Zero POR POR < 5% POR = 5% POR > 5%
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SLIDE 23

Operating Reserve – Capability (Ireland only)

0.00% 5.00% 10.00% 15.00% 20.00% 25.00% 30.00% 35.00% * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * 1970s 1980s 1990s 2000s 2010s Primary Opearting Reserve (% Registered Capacity)

Primary Operating Reserve capability (by date of commissioning) - Ireland

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SLIDE 24

Operating Reserve – Performance

Performance improvements observed since the introduction of HAS Preliminary analysis of 2010 low frequency disturbances

– Generators in Ireland classified based on Primary Operating Reserve performance vs declared capability

Achieved 80% response No of generators Good: > 80% events 7 Average: > 40%, < 80% events 10 Poor: < 40% events 11 Unknown / limited data 23

Note: Ireland only

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SLIDE 25

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services Key Findings Reduced Synchronous Inertia Reserve capabilities less than Grid Code Poor Generator Reserve Performance

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SLIDE 26

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services

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SLIDE 27

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services

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SLIDE 28

Source NGT UK

Voltage Control – Reactive Power

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SLIDE 29

Reactive Power – Portfolio Capability

1,000 2,000 3,000 4,000 5,000 6,000 7,000 Lagging Leading

Synchronous Reactive Power

"Required" Contracted
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SLIDE 30

Reactive Power Availability – Synchronised

1,000 2,000 3,000 4,000 5,000 6,000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Reactive Power Capability (Mvar) Percentage of hours in the year

Reactive Power Duration Curves (Lagging)

2010 outturn 2020 base case
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SLIDE 31

Reactive Power Availability

1,000 2,000 3,000 4,000 5,000 6,000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Reactive Power Capability (Mvar) Percentage of hours in the year

Reactive Power Duration Curves (Lagging)

2010 outturn 2020 base case 2020 with wind contribution
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SLIDE 32

Reactive Power Available – 2010 vs 2020

Table shows average Mvar availability (i.e. from on-line generation) in 2010 and 2020 (with percentage increase/decrease)

Lagging Mvar Leading Mvar 2010 3510 1570 2020 (conventional) 2650 (-24%) 1310 (-16%) 2020 (Tx wind) 3240 (-8%) 2000 (+21%) 2020 (all wind) 3830 (+9%) 2480 (+58%)

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SLIDE 33

Reactive Power – Windfarm Control

302 168 274 40 947

Wind Generation (MW) with voltage control from Control Centres

Yes Yes - derogation No Not required Not required (DSO)

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SLIDE 34

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services Key Findings Portfolio shortfall for leading RP (30%) Synchronous RP will reduce (25%) Only ¼ of windfarms provide RP control Dynamic RP is critical for stability

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SLIDE 35

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services

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SLIDE 36

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services

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SLIDE 37

System Ramping Requirements

Variability

  • Demand
  • Wind
  • Interconnector
  • Disp Generation

Forecast Error

  • Demand
  • Wind
  • Interconnector
  • Disp Generation

Ramping Requirement

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SLIDE 38

System Ramping Requirements

Variability

  • Demand
  • Wind
  • Interconnector
  • Disp Generation

Forecast Error

  • Demand
  • Wind
  • Interconnector
  • Disp Generation

Ramping Requirement Ramping Duty Forecast Error

+ =

Illustration

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SLIDE 39

Wind Variability (1 hour)

  • 500
  • 400
  • 300
  • 200
  • 100
100 200 300 400 500 200 400 600 800 1,000 1,200 1,400 Maximum daily 1 hour wind variation (MW) Maximum daily wind generation (MW) Max Increase Max Decrease
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SLIDE 40

Ramping Requirement

200 400 600 800 1,000 1,200 1,400 1,600 1 hr 2 hr 3 hr 4 hr 8 hr 12 hr MW

Average Ramp Up Requirement (Total)

2010 - Full Year (Jan-Dec) 2020 - Base Case

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SLIDE 41

Generator Ramping Availability

Ramping deficit = requirement - availability 2010: system is dispatched to ensure requirement is met

– Deficits arise following disturbances

2020: few instances of deficit

– Due to assumed portfolio evolution (additional “flexible” generation) – Sensitivity studies illustrate potential issues

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SLIDE 42

Wind – Ramping Capability

Wind generation can contribute to ramping requirement

– Capable of being curtailed → can ramp down – When being curtailed → can ramp up or down

Wind contribution to ramping requirement reduces requirement from conventional generation

– Lower curtailment

Reliable active power control is essential

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SLIDE 43

Wind – ramping capability

61% 14% 25%

Active Power Control (by TSO) - 1,730 MW wind

Yes No (not required)

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SLIDE 44

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services Key Findings Ramping requirement will increase with increasing wind Both variability and uncertainty influence ramping requirement Active Power Control

  • f windfarms is

essential

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SLIDE 45

Areas of analysis

  • Synchronous Inertia
  • Operating Reserve

Frequency Response

  • Reactive Power Capability
  • Dynamic Reactive Power

Voltage Control

  • Generator Ramping
  • Wind Variability & Forecasting

Ramping Services

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SLIDE 46
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SLIDE 47

DS3 – Delivering a Secure Sustainable System

  • Reduced Synchronous Inertia

Poor Generator Reserve Performance

  • RoCoF Protection Relays

Frequency Response

  • Portfolio Reactive Power Capability

Wind farm Controllability

  • Type of Reactive Power Capability

Voltage Control

  • Windfarm active power control
  • Need for Ramping Capability
  • Forecast and Variability of portfolio output

Ramping Services

System Issues Key Action Areas

System Performance System Tools System Policies

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SLIDE 48

System Performance

Grid Code Generator Performance Incentives Ancillary Services Performance Monitoring Knowledge of System Performance Enforcement of performance standards Incentivise greater performance capability Management of complexity, uncertainty

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SLIDE 49

System Performance

Grid Code Generator Performance Incentives Ancillary Services Performance Monitoring

DS3

electricity

Delivering a Secure Sustainable Electricity System

Knowledge of System Performance Enforcement of performance standards Incentivise greater performance capability Management of complexity, uncertainty

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System Performance

Grid Code Generator Performance Incentives

Ancillary Services Performance Monitoring

Programme Key Actions Timeline Actor(s)

Commercial Design Consultation paper on Ancillary Services

2011 EirGrid & SONI

Financial valuation of system services

2011/12 EirGrid & SONI

Commercial Mechanisms

2011/12 EirGrid & SONI

All island consultation on proposed ancillary services payment structures

2012 EirGrid & SONI

Decision on future ancillary services funding

2012 Regulatory Authorities

Decision

  • n

ancillary services implementation methods

2012 EirGrid & SONI / Regulatory Authorities

Implementation

  • f

new ancillary services arrangements

2013 EirGrid & SONI

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SLIDE 51

Reserve Capability of Generators (Ireland only)

0.00% 5.00% 10.00% 15.00% 20.00% 25.00% 30.00% 35.00% * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * 1970s 1980s 1990s 2000s 2010s Primary Opearting Reserve (% Registered Capacity)

Primary Operating Reserve capability (by date of commissioning) - Ireland

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SLIDE 52

Generator Performance Incentives

Improvements observed since the introduction of GPIs

– Particularly in Ireland (see table)

Characteristic Improvement (as of Dec 2010) Reactive Power (Leading) 100 Mvar Reactive Power (Lagging) 100 Mvar Primary Operating Reserve 25 MW Secondary Operating Reserve 40 MW Minimum load for reserve provision 50 MW

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SLIDE 53

System Policies

Frequency Control Voltage Control TSO/DSO Policies RoCoF Standards, Settings & Capabilities System Reserve System Ramping Less Synchronous Inertia Reserve Performance RoCoF protection relays Less dynamic reactive support

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SLIDE 54

System Policies

Frequency Control Voltage Control TSO/DSO Policies RoCoF Standards, Settings & Capabilities System Reserve System Ramping Less Synchronous Inertia Reserve Performance RoCoF protection relays Less dynamic reactive support

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SLIDE 55

System Policies

Frequency Control Voltage Control TSO/DSO Policies RoCoF Standards, Settings & Capabilities System Reserve System Ramping

Programme Key Actions Timeline Actor(s)

Frequency Control Review of RoCoF protection settings and capability 2011 EirGrid & SONI Engagement with the DSO

  • n

RoCoF protection settings 2011 EirGrid & SONI / DSOs Agree new settings for RoCoF relays/Agree to disable RoCoF relays 2011/2012 EirGrid & SONI / DSOs / Regulatory Authorities Implementation of changes to RoCoF settings 2012 Industry Review system reserve policy for Control Centres in the context of high levels of variable renewable generation 2012 EirGrid & SONI Investigate the system ramping requirements (long term reserve) and associated policy 2012 EirGrid & SONI

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SLIDE 56

Frequency Response: Inertia

10,000 20,000 30,000 40,000 50,000 60,000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Synchronous Inertia (MW s) Percentage of hours in the year

Inertia Duration Curves

Inertia 2010 Inertia 2020

Insecure region

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SLIDE 57

System Tools

Forecasting Control Centre Tools & Capabilities Studies & Model Development WSAT Wind Dispatch Tool Greater Embedded Generation Change in Generation Portfolio Controllability Model Refinement

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SLIDE 58

Delivering a Secure Sustainable Electricity System – DS3 Programme

System Performance System Tools System Policies Communications

  • Performance Monitoring
  • Grid Code Standards
  • Commercial Incentives
  • Wind Dispatch
  • Control Centre Capabilities/Controllability
  • Studies / model development
  • System Security
  • Voltage Control
  • RoCoF relays
  • Industry Forums
  • RAs/DSOs Engagement
  • Advisory Council
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SLIDE 59

Advisory Council

A forum to facilitate wide stakeholder input across the electricity sector in Ireland and Northern Ireland Independent panel of experts that help to guide the DS3 programme Members of the group participate as individuals and not as representatives of organisations Deadline for expressions of interest: 31 August 2011 Kick off meeting: October 2011

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SLIDE 60

System Policies System Tools System Performance

∫DS3

Delivering a Secure Sustainable Electricity System

Electricity

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SLIDE 61

System

Policies

System Tools System

Performance

∫DS3

Delivering a Secure Sustainable Electricity System

Electricity

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SLIDE 62

END

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SLIDE 63

Ramping illustration

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SLIDE 64

System Ramping: drivers

1000 2000 3000 4000 5000 6000 00:00 06:00 12:00 18:00 00:00 Demand / Wind (MW) Demand Wind Net Demand

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SLIDE 65

System Ramping: drivers

1000 2000 3000 4000 5000 6000 00:00 06:00 12:00 18:00 00:00 Demand / Wind (MW) Demand Wind Net Demand

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SLIDE 66

System Ramping: drivers

1000 2000 3000 4000 5000 6000 00:00 06:00 12:00 18:00 00:00 Demand / Wind (MW) Demand Wind Net Demand

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SLIDE 67

Ramping Duty

  • 1000
  • 500

500 1000 1500 00:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 00:00 2 hour ramp (MW) Requirement Demand Ramp Net Demand Ramp

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SLIDE 68

Ramping Duty

  • 1000
  • 500

500 1000 1500 00:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 00:00 2 hour ramp (MW) Requirement Demand Ramp Net Demand Ramp

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SLIDE 69

Ramping Duty

  • 1000
  • 500

500 1000 1500 00:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 00:00 2 hour ramp (MW) Requirement Demand Ramp Net Demand Ramp

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SLIDE 70

Ramping Requirement = Duty + Errors

  • 1000
  • 500

500 1000 1500 00:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 00:00 2 hour ramp (MW) Requirement Demand Ramp Net Demand Ramp