Remedial Action Schemes: Practical Solutions for Power System Stability Problems

Scott Manson, PE March, 2011

Copyright © SEL 2010

What Dictates Power System Stability?

• • • • • • Frequency Response Characteristic Major Disturbances Volt/MVAr Margins Frequency/MW Margins Economics Undesired Oscillations

Governors/Turbines Simply Can’t Respond Instantly

98,000 63,00 Red – Electrical Power 97,000 96,000 95,000 94,000 93,000 92,000 91,000 0,000 5,000 Note lag in response Black –Speed 10,000

Time (Secs)

15,000 61,00 60,00 59,00 58,00 57,00 20,000

Typical Governor Controller

Generator Power – Pmwset + + + Cp Cf Kimw s s10 Plim P lim Kturb  wfnl 1 + 1 R – + s0 1.0

Kpgov  Kigov s vmin s1 + – + Nset – Turbine Speed Nref – + Pjrl wfnl Pgen 1 Kturb 1 s9 + + – + Kjrl + Mjrl Rate Limited Tracking Rjrl + + – 1.0

Kpload  Kiload s 0 s2 ft 1 s7 1 sTsa 1 sTsb s8 X Speed**Dm 1.0

Kpjrl  Kijrl s 0 s3 fn fj 1 s4 1 sTfa 1 sTfb s5 1 sTc 1 sTb WGOV1 wfnl s6 – Pmech +

Frequency Depressions

• Most turbines control packages trip off at ~ 57.5 Hz to protect themselves from damage • Large, Expensive Motors trip for same reason • Will Cascade into uncontrolled blackouts Df/dt = S Power In – w J S Power Out

frequency decay rate proportional to the magnitude of the power deficit

Case 1 Case 2 50 49 48 47 46 45 0 5000 10000 15000

Time (ms)

20000 25000 30000

Frequency Response Characteristic

• Many different definitions and names throughout the world • ♦ R, FRC, dF/dP, etc • Some countries (not US) define generator FRC requirements ♦ ♦ ♦ Effects Dominated by: Load composition System Inertia Generator Tuning

Frequency Response Characteristic (FRC) Example for large offshore NGL plant

Sudden increase of 0.3 pu load

Three common FRC Variants

• • • Point A ‘Transient’ FRC = 50 (0.3)/ (50-48.7) = 11.5

Point B – Locked Rotor FRC = Extraction mode FRC = 50 (0.3)/ (50-48) = 7.5

Point C – ‘System Long Term FRC’ = ‘System Droop Characteristic’ = 50 (0.3)/ (50-49.4) = 25

• •

What does FRC tell you about a Power System?

A quantity of ‘stiffness’ ♦ ♦ Example: Long Term FRC 25*150 MW/50Hz = 75 MW/Hz 75 MW of load will reduce system frequency by 1 Hz • • Extraction Mode FRC = 22.5 MW/Hz Transient FRC = 34.5 MW/Hz

Solutions for a Poor FRC

• • • • • • • Governor tuning Add Inertia Limit electronic loads More Synchronous Machines BIG Battery Backed Statcom Load Shedding Generation Shedding/Runback

SEL Project to improve Power Quality Presidio, TX (By Controlling Some Big Batteries)

Power Corridor Transport Limits

• Out of Step (OOS) Behavior Lethal to machines and power systems • Thermal limits must be obeyed to prevent conductor damage

Jim Bridger Power Plant – Long History of Severe Faults and OOS behavior

Power System Overview

Boise Midpoint Kinport Goshen Borah Portland Adel Jim Bridger Hunt Legend: 500 kV 345 kV 230 kV 138 kV Salt Lake

SEL RAS Protection Required

• ♦ ♦ ♦ Prevent loss of stability caused by Transmission line loss Fault types Jim Bridger Plant output levels • WECC requires Jim Bridger output reduced to 1,300 MW without RAS

Stability Studies Determine RAS Timing Requirements

• Total time from event to resulting action must not exceed 5 cycles • 20 ms available for RAS, including input de-bounce and output contact

JB RAS Also protects against…

• • Subsynchronous resonance (SSR) protection – capacitor bypass control Transmission corridor capacity scheduling limits

Dynamic Remedial Action for Idaho Power Co.

Portland Washington Oregon Idaho Boise Path 17 Montana E Wyoming G Substation A B C D J California Nevada Salt Lake City Utah 138 kV 230 kV 345 kV 500 kV 380-mile drive between Substation A and Substation J

Idaho Power System Conundrum

• • • • • • Maintain the stability, reliability, and security Operate system at maximum efficiency Prevent permanent damage to equipment Minimal Capital expenditures Maximize Revenue Serve increasing load base

RAS Was Lowest Cost Solution

• • New transmission line: $100s of millions New transmission substation: $10s of millions • This project: approximately $2 million

RAS Functional Requirements

• • • • • Protect lines against thermal damage • Optimize power transfer across critical corridors Predict power flow scheduling limits dynamically Follow WECC requirements Track Changing power system topography 20 ms response requirement

RAS Actions Based on Combinations of Factors

• • • • • • N events (64) J states (64) System states (1,000) Arming level calculation Action tables combinations (32) Crosspoint switch (32x32)

Gain Tables Allow Operations to Adjust RAS Performance for Any System Event

• ♦ ♦ ♦ ♦ 7 gain entries used in arming level equation 64 N events 32 actions 1,000 system states 4 seasons • • 8,192,000 possible gains per gain entry 57,344,000 total gains

RAS Gains Configured From HMI

Most Sophisticated RAS in the World exists in South Idaho

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• • •

Major Disturbances Put Power Systems at Risk

Faults ♦ ♦ ♦ ♦ Critical Clearing Time to prevent OOS Fault Type Protection speed Fast breakers Load startup or trip (FRC problem) Generator trip (FRC problem)

Generator Trip at Chevron Refinery Cause Massive Financial and Environment Problems

4 x 32 MW ea

Generation Station No. 1 Asian Electrical Operating Company (National Grid)

3 x 34.5 MW ea.

Potential for power system collapse 2 x 105 MW ea.

Generation Station No. 2 & Prod. Plt 2 Load ~ 40MW Generation Station No. 3 & Prod. Plt. No. 3 Load ~ 60MW Production Plant No. 1 Load ~ 120MW Fig. 1 – Simplified One-Line Asian Oil Production Complex

Generation Tripping Remediated by Invented at SEL Trigger Inputs Contingency N1 N2 N3 N4 N5 Crosspoint Switch Preloaded and Ready to Go Output Remediation Trip G1 Trip G2 X Trip G3 X Trip G4 Bypass C1 X X X Bypass C2 X X X X X X X

CB Opens

Tripping Outputs t

Generation Tripping Problem Requires a sub-cycle Load Shedding Scheme

• • •

Three main techniques for Load Shedding

Contingency based (aka ‘FLS’) ♦ ♦ Tie line Bus Tie ♦ ♦ Generator Asset Overloads ♦ ♦ U/F based Traditional technique in relays (lots of problems) Enhanced SEL technique, generally a backup to contingency-based system U/V based

•

Contingency Based Load Shed Systems for Chevron Plant

Sub cycle response time prevent frequency sag • • • Advises operator of every possible future action Expandable to thousands of sheddable loads with modern protocols Tight integration to existing protective relays

•

Contingency Based Load Shed system for Chevron

Must have live knowledge of machine IRMs, Spinning Reserves, Power output • initiating event is the sudden loss (circuit breaker trip) of a generator, bus coupler breaker, or tie breaker.

• perform all of their calculations prior to any contingency event • System topology tracking

Typical Volt/VAR Stability problems

• • Typical problems ♦ ♦ ♦ ♦ ♦ Fault induced long term suppressed voltage conditions Large Motor Starting Risk Plant blackouts Typical Solutions Dynamic control of exciters on large synchronous motors FACTS devices Misc power quality improvement electronics

Low Cost Solution: Controlling Exciters on 15 MVA SM on a 700 MW GOSP preserves VAR margins

1 3 .8 k V M o to r B u s V o lta g e ( S ta r tin g M o to r B u s O n ly ) M B U S 2 V - V A R C o n tr o l M B U S 2 V - V o lta g e C o n tr o l p lu s G e n M B U S 2 V - V o lta g e C o n tr o l O n ly 1 6 1 5 1 4 1 3 1 2 1 1 0 E le ctr o te k C o n ce p ts® 1 0 0 0 0 0 2 0 0 0 0 0 T im e ( m s) 3 0 0 0 0 0 4 0 0 0 0 0 T O P , T h e O u tp u t P r o ce sso r ®

How to contain a Voltage Collapse?

• • • • Increase generation – reduce demand, match supply and demand Increase reactive power support Reduce power flow on heavily loaded lines (use Flexible AC Transmission Systems) Reduce OLTC at distribution level, to reduce loads and avoid blackouts (Brownout)

Frequency/MW Margins

• • Problem1: Long Term Problem. Caused by Insufficient Reserve Margins (RM) of generation. Solution: Add more generators.

♦ ♦ Problem2: Short Term Problem. Caused by insufficient Incremental Reserve Margin (IRM) of generators. Solution1: RAS load/generation shedding Solution2: Machines with larger IRM

Typical Steam Turbine IRM characteristic

Output (%) 100 % 0 % 0 500 Time (Seconds)

Typical IRM values

• • Steam Turbines: 20-50% ♦ ♦ Combustion Turbines Single Shaft Industrials: 5-10% Aero Derivatives: 10 – 50% • Hydro Turbines: 1 - 25%

Economics Affecting Stability

• • Danger: Fewer, larger generators ♦ ♦ Less expensive, more efficient More risk upon losing one generator Economic Dispatch Contradicting Stability Optimization ♦ ♦ NIMBY: Local Thermal/ Remote Hydro plants MW transactions across critical corridors put plants or system islands at risk

• • •

Solution: Active Load Balancing and Tie flow control for Optimal Stability

Economic Dispatch (Low Risk Scenarios) ♦ ♦ Tie line flows (MW) per contracted schedule Distributes MW between units per Heat Rate ♦ Tie-line closed (High Risk Scenarios): Control intertie MW to a user defined low value ♦ ♦ ♦ Distributes MW between units, equal % criterion Tie-line open (Islanded Operation – high risk) Control system frequency to a user defined set-point Distributes MW between units , equal % criterion

Common PowerMAX Screen: AGC/VCS Interface

Common PowerMAX Screen: ICS Interface

Unwanted Oscillations

• • • Explain Spectrum of a power system ♦ ♦ Sub Synchronous Resonance (SSR) First detected in 1970’s during commissioning of high speed/gain exciters Mechanical/Electrical Mode Interaction  Shaft oscillation modes  Heavily Series compensated lines Improperly Reactive Compensation in Exciters

Power System Stabilizers

• ♦ ♦ Provide Damping based on two possible input types: Frequency (Hz)/Speed (rpm) – US Power (MW) - Europe

Any Questions?