Copyright © SEL 2010

Remedial Action Schemes:Practical Solutions for Power System

Stability Problems

Scott Manson, PE

March, 2011

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

0.000 2.000 4.000 6.000 8.000 10.000 12.000 14.000 16.000 18.00091.000

92.000

93.000

94.000

95.000

96.000

97.000

98.000

57.00

58.00

59.00

60.00

61.00

62.00

63.00

Time (Secs)

Po

we

r (M

W)

Blue – Mechanical Power

Black –Speed

Note lag in response

Red – Electrical Power

Typical Governor Controller

+

+–

s1

1.0

vmin

–

+

Cf

+

Cp

Generator Power

Pmwset

Nset

Turbine Speed

Nref

Kimw

s

1

R

Kigov

Kpgovs

1

1 sTelec

1

KturbKjrl

Pjrl

wfnl Mjrl

Rate Limited Tracking

Rjrl

1

1 sTjrfPgen

s3

1.0

0

KijrlKpjrl

s

s2

1.0

0

KiloadKpload

s

Plimwfnl

Kturb

1

1 sTth1 sTsa

1 sTsb

s7 s8

Plim

1

1 sTact

s4

1 sTfa

1 sTfb

s5

1 sTc

1 sTb

s6

wfnl

Pmech

fn

ft

fj

Low

Val

ue S

elec

t

X

Speed**Dm

–+

++

–

–+

+

+

+

++

–

–

+

+

–

s9

s10

s0

WGOV1

Frequency Depressions

J=

Power In –

wS Power OutSDf/dt

• 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

frequency decay rate proportional to the magnitude of the power deficit

300002500020000150001000050000

Time (ms)

45

46

47

48

49

50

Mag

nit

ud

e (M

ag)

Case 1 Case 2

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 OverviewBoise

Midpoint

Portland

GoshenKinport

Borah

Adel

Hunt

Salt Lake

Jim Bridger

500 kV345 kV230 kV138 kV

Legend:

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 inputde-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.

Oregon

Idaho

Wyoming

Utah

Nevada

Montana

California

Portland

BoisePath 17

J

Substation A

B CD

EG

Salt Lake City

Washington

380-mile drive between Substation A and Substation J

138 kV230 kV345 kV500 kV

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

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

Generation Station No. 1

Production Plant No. 1 Load ~ 120MW

Generation Station No. 2 & Prod. Plt 2 Load ~ 40MW

Generation Station No. 3 & Prod. Plt. No. 3 Load ~ 60MW

Fig. 1 – Simplified One-Line Asian Oil Production Complex

Asian Electrical Operating Company (National Grid)

4 x 32 MW ea 3 x 34.5 MW ea.

2 x 105 MW ea.

Potential for power system collapse

Generation Tripping Remediated by sub-cycle load shedding Techniques

Invented at SEL

Crosspoint Switch

f

tCB

Opens

Tripping Outputs

TriggerInputs

X

Trip G2

N5

N4

XN3

XN2

N1

Trip G1

Output RemediationContingency

Trip G3

X

Trip G4

X

Bypass C1

X

Bypass C2

X

X

X XX

X

Preloaded and Ready to Go

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

11

12

13

14

15

16

0 100000 200000 300000 400000

13.8kV Motor Bus Voltage (Starting Motor Bus Only)

Electrotek Concepts® TOP, The Output Processor®

Mag

nitu

de (

Mag

)

Time (ms)

MBUS2V - VAR Control MBUS2V - Voltage Control Only

MBUS2V - Voltage Control plus Gen

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 (%)

Time (Seconds)

100 %

500 0

0 %

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?