Transient stability of conventional generating stations ...

Transient stability of conventional generating stations during times of high wind penetration

on the Island of Ireland Marios Zarifakis, Electricity Supply Board, Dublin, Ireland

Stockholm 24.11.2016

www.esb.ie

TCD

© 2016 ESB, TCD

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Real Frequency Event, 27.04.2014, DBP

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Contents 1.  Introduction of the Irish Grid and ESB

2.  Government targets and policies

3.  Rate of Change of Frequency (RoCoF) and the Grid Code Definition

4.  Mathematical models

5.  Impact to generating plant and grid

6.  RoCoF impact studies with manufacturers

7.  Frequency oscillations

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ESB – Electricity Supply Board •  Vertically Integrated Utility

•  Involved in most types of generation

•  The first ESB generation plant (in 1927) was a hydro station at Ardnacrusha

•  The ESB group is one of the largest wind generators in Ireland, and ESB has been involved in development, construction and management of Irelands wind resources since the 1980s.

•  Large international business.

•  ESB owns a number of international power stations and has O&M contracts for several other generation stations.

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Transmission System Ireland

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European Transmission System

ROCOF Project Board Meeting

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Increase of sustainable energy sources

EU 2020 Policy

20% of the EU’s energy demand to be from renewable sources by 2020

Irish Government Targets

40% of Ireland’s total electricity consumption to be met by renewables

TSO’s DS3 Programme Safe and secure power system with high levels of renewable generation

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Operating Zones

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System and Wind Generation

Areas where Wind Generation had to be curtailed

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Timeline

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ESB Generation Focus

Perspectives and Dependencies

EirGrid & SONI Focus

Mechanical Issues

Turbine Integrity

Generator Integrity

Security of supply

Voltage Stability Loading of Lines

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Frequency Scale

50Hz 49Hz 51Hz

Generation Consumers

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Generation-Load Balance

Generation

Load

Frequency falls if

is smaller than

48,5 49,0 49,5 50,0 50,5 51,0

-2 -1 0 1 2 3 4 5 6 7 8

Freq

uenc

y (H

z)

Time (s)

Sample Low Frequency RoCoF

Frequency (Hz)

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Frequency and the Rate of Change of Frequency

Frequency

RoCoF= 𝑑𝑓/𝑑𝑡 

RoCoF

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Proposed Definition of RoCoF The new definition by both TSOs, EirGrid and SONI, for the Grid Code is:

“remain synchronised to the Transmission System for a Rate of Change of Frequency up to and including 1 Hz per second as measured over a rolling 500 millisecond period”

Mathematical Definition of RoCoF

𝑹𝒐𝑪𝒐𝑭𝑨𝑽𝑬𝑹𝑨𝑮𝑬= ∆𝒇/∆𝒕 

𝑹𝒐𝑪𝒐𝑭𝑰𝒏𝒔𝒕𝒂𝒏𝒕𝒂𝒏𝒆𝒐𝒖𝒔= 𝒅𝒇/𝒅𝒕 

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RoCoF Trace

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Definition of RoCoF (500ms window)

Ardnacrusha (AA), Aghada (AD), Cathaleen’s Fall (CF), Louth (LOU), Carrickmines (CKM), Great Island (GI), Ballylumford (BALLY) and Poolbeg (PB) (*1)

Maximum RoCoF measurements for different time windows

RoCoF values at various substations (trip of EWIC) (Eirgrid Study 2012)

Problem: Generator sees actual values…

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RoCoFAverage with Δt = 100ms and Δt = 500ms

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Magnetic Field in a Synchronous Generator

Stable conditions: Tel=Tmech

or 0=Tmech - Tel Dynamic conditions: J𝛼= Tmech-Tel

J𝜔  = Tmech-Tel - KD𝜔 J𝜔  = Tmech - kBSBRsin𝛿 - KD𝜔

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Conventional Swing Equation

𝜏 ↓𝑎 = 𝜏 ↓𝑚 − 𝜏 ↓𝑒𝑙 =0

𝐽↓𝑔𝑒𝑛 𝜔 ↓𝑚 (𝑡)= 𝜏↓𝑚 − 𝜏↓𝑒𝑙 

with 𝜔↓𝑚 (𝑡)= 𝛿 (𝑡)

𝐽↓𝑔𝑒𝑛 𝛿 (𝑡)= 𝜏↓𝑚 –𝜏↓𝑒𝑙 

Introducing 𝐻= 1/2 𝐽𝜔↑2 /𝑆↓𝑁  

2𝐻/𝜔↓0  𝛿 (𝑡) + 𝐾↓𝐷 /𝜔↓0  𝛿 (𝑡) = 𝜏 ↓𝑚 − 𝜏 ↓𝑒𝑙 

And with 𝜏 ↓𝑒𝑙 = 𝑘/𝜔↓0  𝐵↓𝑅 𝐵↓𝑆 sin 𝛿(𝑡) 

2𝐻/𝜔↓0  𝛿 (𝑡) + 𝐾↓𝐷 /𝜔↓0  𝛿 (𝑡) + 𝑘/𝜔↓0  𝐵↓𝑅 𝐵↓𝑆 sin 𝛿(𝑡) = 𝜏 ↓𝑚 

2𝐻/𝜔↓0  𝛿 (𝑡) + 𝐾↓𝐷 /𝜔↓0  𝛿 (𝑡) +𝑘𝐵↓𝑅 𝐵↓𝑆 𝛿(𝑡)= 𝜏 ↓𝑚 

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Negative ROCOF, Steam Turbine 0.25 Hz/s & 4 s 0.5 Hz/s & 2s 1 Hz/s & 1s 2 Hz/s & 0.5s

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RoCoF mathematical definition (simplistic view)

𝒅𝒇/𝒅𝒕 = 𝒇↓𝒏 𝑷/𝟐 𝑯↓𝒔𝒚𝒔𝒕𝒆𝒎 𝑺↓𝒃   With:

𝑓↓𝑛 = System Frequency

𝐻↓𝑠𝑦𝑠𝑡𝑒𝑚 = System Inertia

𝑃 = Lost load or generation

𝑆↓𝑏 = MVA rating of the system

Generation Consumers

50Hz

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Real Frequency Event, 27.04.2014, DBP

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BR BS

No gravity!!!

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G1 G

2 Grid Turbine Torque Sum of all loads (Torque)

Electromagnetic Torque

In the air gap of the generator

Turbine Torque

To create the equation of motion using Lagrange

Damping depends on speed deviation! Asynchronous effect!

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Frequency trace depends on system inertia

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System oscillations depend on grid inertia

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Behaviour of small inertia grids

𝒅𝒇/𝒅𝒕 = 𝒇↓𝒏 𝑷/𝟐 𝑯↓𝒔𝒚𝒔𝒕𝒆𝒎 𝑺↓𝒃  

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Swings depend on electromagnetic torque

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Shaft line, exact modelling required for all stations

Analysis for impact at turbine and generator components

Torsional oscillations can create stresses to:

•  Couplings

•  Rotors and shafts

•  Turbine blades and roots

•  Generator rotor end bells

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Risks related to mechanical integrity

Torsional oscillations can create stresses to: •  Couplings

•  Rotors and shafts

•  Turbine blades

•  Generator rotor end bells

•  Generator stator end windings

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Mech/Elec Integrity Consequences RoCoF Event

Reduced Component Life Time

Consequential Machine Damage

Decreased overhaul intervals and

Increased Inspection Requirements

Forced Outage

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Impact on lifetime is unknown

Life time and maintenance analysis to be undertaken

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Technical Risks

Technical Risks •  Controller & Operational Issues

•  Turbine/Governor Controller •  AVR/PSS Controllers

•  Protection Systems •  Turbine Protection •  Generator & Transformer

Protection •  Mechanical Integrity

•  Turbine Components •  Generator Components •  Lifetime Assessments

•  Electrical Integrity •  Impact of Auxiliary Systems

•  Motors, Fans, Pumps

Action •  Studies to be completed to assess

impact (OEM’s, TUV)

•  Modelling Scenarios •  Rotor Dynamic Analysis •  Operational Analysis

•  Internal Modelling work •  Torsional Probes •  Matlab/Simulink Model Build

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Operational Consequences ROCOF Event

Further loss of Electrical Power Generations

Cascade Tripping Event

Load Shedding in the system

System Brown/Black Out

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Calculations with parameters ± 1Hz/s & 1.2s Operational Point RoCoF,

duration Remarks

1.) P=305 MW; Q=180Mvar -1Hz/s; 1.2s The generated active power increases to 540MW. Generator experiences 150% of rated stator current. The stator current limiter in the AVR is triggered.

2.) P=305MW; Q=0Mvar The generated active power increases to 503MW. Generator experiences 140% rated stator current. The stator current limiter in the AVR is triggered.

3.) P=305MW; Q=-120Mvar The generated active power increases to 530MW. The stator current limiter in the AVR is triggered. The reactive power triggers the under-excitation limiter and under-excitation protection. I> protection picks up.

4.) P=100MW; Q=-160Mvar The reactive power triggers the under-excitation limiter and the under-excitation Protection.

1.) P=305 MW; Q=180Mvar +1Hz/s; 1.2s ΔP/Δt is substantial and can lead to trigger the “Remote Breaker Opening” logic which would close the control valves.

2.) P=305MW; Q=0Mvar ΔP/Δt is substantial and can lead to trigger the “Remote Breaker Opening” logic which would close the control valves.

3.) P=305MW; Q=-120Mvar ΔP/Δt is substantial and can lead to trigger the “Remote Breaker Opening” logic which would close the control valves.

4.) P=100MW; Q=-160Mvar ΔP/Δt is substantial and can lead to trigger the “Remote Breaker Opening” logic which would close the control valves. Reverse Power Pick up (-125MW). Torsional Oscillations become more evident on low loads.

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Real Event, Poolbeg CT 15 @ 65 MW

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Study Scope Type MW

(Exp) Unit #

Studies Required

Study Priority

CCGT 2094 4 4* 1 Peat 228 2 1 1 Coal 855 3 1 1 Gas 258 1 1 3 OCGT 517 6 2 3 Pump Storage 292 4 1 1 Hydro 206 17 2 3

12 studies to be completed Timeframe for Priority 1 Units 18 months

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Timeline going forward ●  Studies required to demonstrate compliance

–  High priority – 18 months - high run hours, frequently constrained on, frequently run during high wind

–  Mid priority – 24 months - units not in other categories

–  Low priority – 36 months - low run hours, infrequently constrained on, infrequently run during high wind

–  Exempt units – units soon to retire, very low runs hours or units which in EirGrid’s operational experience have ridden through high RoCoF events in the past

ESB will need to be compliant (or derogated/exempted) by these dates to ensure it incurs zero penalties.

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Project Timeline

2010 – 2012 Consultation Period • Risk Paper • OEM Engagement • Understanding & Education

• Financial Appraisal • Regulatory

2013 – 2014 CER ROCOF Paper • Consultation Paper • Decision Paper • KEMA Challenge Study • No Cost Recovery Position

• Procurement Strategy

2014 – 2016 Studies • Tender Process • Priorities 1 studies • Digsilent Study • Matlab/Simulink Model • Torsional Probe Analysis • Quality & Validation

2016 – 2018 Post Studies • Level of Compliance • Level of Investment • Development of individual Business Cases

• Implementation

That’s it??

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Real Event, DBP, 26.12.2014

•  C30 in Coolkeeragh Trip at 22:38 •  DB1 MW; Hz •  7 Min Oscillation •  Pk-Pk: ~0.3 – 0.4 Hz •  Period of Osc: 15 s (0.066 Hz)

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Typical Turbine Generator control circuit

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Response to a sinusoidal disturbance

Currently installed turbine controllers need major attention….

Output of controllers swing almost in phase with disturbance which amplifies the disturbance

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Questions? Fragen? Ερωτησεις;

Thank You

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Acknowledgements Models used:

Matlab from Mathworks with Simulink and SimPowerSystem

Literature:

“Power System Stability and Control”, Prabha Kundur

“Handbook of Electrical Power System Dynamics”, M. Eremia, M. Shahidehpour

“Elektrische Schaltvorgaenge”, Reinhold Ruedenberg

Various publications by Eirgrid and CER (www.eirgrid.com and www.cer.ie)

DNV GL Study on ESB Fleet

Some animations were used from www.wikipedia.de, Dreiphasenwechselstrom

Contributions by: Stephen Carrig, ESB GWM Manager C&I

Prof. Dr. William T. Coffey, Trinity College Dublin,

Transient stability of conventional generating stations ...

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