distribution automation –smart feeders in a smart …grouper.ieee.org/groups/td/dist/da/members...

© 2010 Quanta Technology LLC

Distribution Automation – Smart

Feeders in a Smart Grid World

UU208Presented by:

Bob UluskiHahn Tram

Dr. Farid KatiraeiQuanta Technology, LLC


UU208: Distribution Automation

Smart Feeders in a Smart Grid World

Presented by:Bob UluskiHahn Tram

Dr. Farid Katiraei

Introduction


Bob Uluski

• DistribuTECH DA/SA Instructor for past 10 years

• 35 years electric utility experience

• Distribution management systems, substation and feeder automation, developing the business case

• Recent DA Projects:

– BC Hydro (Advanced DMS)

– ENMAX (Fdr Auto - Pennwell 2004 Automation Project of the Year)

– Duke Energy (Integrated Volt VAR control)

• Principal author of Down Line Automation Guidebook prepared for NRECA Cooperative Research Network

• Secretary of IEEE PES Smart Distribution Working Group and Task Force on Volt VAR Control

• Registered professional engineer


Hahn Tram

• Executive Advisor & VP Enterprise with Quanta Technology

• 30+ years in technology solutions for energy utilities

– Helped successful launch of Smart Metering initiatives at Sempra,

BGE, CPS Energy, HECO, etc.

– Supported DMS/OMS implementations at utilities worldwide,

including Cinergy, LGE, Alliant, PG&E, Iberdrola, Korea Electric, etc.

– Helped develop Smart Grid application strategies at Oncor, PHI, etc.

– Helped launch Field Force Automation programs at Exelon, Oncor…

– Careers before joining Quanta:

• Westinghouse, ABB, Convergent Group, SchlumbergerSema, Enspiria

• Industry Activities

– DistribuTECH Advisory Committee Member

– Senior Member of IEEE; Member of Utilimetrics, GITA…

– ~100 publications, short courses, panels and presentations


Farid Katiraei, PhD

• Senior Advisor of Protection and Automation for Quanta

Technology

• Over 7 years of experience working directly with electric

utilities, governmental research labs and standard committees

• Involved in study and commissioning of several pilot projects in

the area of DG interconnection and renewable energy sources

• Ph.D. in Electrical Engineering, Senior member of IEEE, Several

journal/conference papers and articles

• Member of IEEE P1547.7 and IEA PVPS Task 11 working groups

• Steering committee member of International Microgrid annual

symposium


Participant Introductions

• Name and Company Affiliation

• Job Responsibilities

• Why did you take this workshop?

• What specific topic(s) do you want covered in

the workshop?

• Other comments?

6


Agenda

• Introduction

• Feeder automation applications (remote controlled switching, volt-VAR control)

• Distribution management systems and interactions with other enterprise systems

• System components and architecture

• DA Communications

• DA/DMS Role in the “Smart Grid”

• Developing the business case

• Implementation strategies & case studies

• Open Q/A


Distribution Automation

Not a New Concept?

Many existing examples of automation on the distribution system

Protective Relays

Reclosers, Sectionalizers

Switched Cap Banks

Fully automatic – no man in the loop

Load Tap Changer


Distribution Automation

The Latest ViewMicroprocessors provide more

information and more intelligent control

Protective Relays

Reclosers, Sectionalizers

Switched Cap Banks

Dispatchers kept informed

Load Tap Changer


“Official” Definition of DA

• Significant differences from traditional

definition of automation:

– Remote monitoring and control included

– Human intervention is included!

“a set of technologies that enable an electric utility to

remotely monitor, coordinate, and operate distribution

components in a real time mode from remote

locations”. (IEEE PES DA Tutorial, 1998)


Driving Forces for DA

• Address needs of the 21st Century customer

(the “Smart Grid”)

– Growing customer expectations

– Computers and electronics everywhere

– Service interruptions and power quality

problems unacceptable

• Regulatory “Incentives” (+ and -)

– Economic stimulus funds

– Performance based rates (PBR)

• Pressure to cut costs


Some Key Definitions

• Supervisory Control and Data Acquisition (SCADA)– a computer and communication system that provides remote

monitoring and remote control of field equipment

– The basic building block for Distribution Automation

• Distribution Automation (DA)– A set of software/hardware applications that use SCADA to control

distribution equipment in an optimal fashion

• Distribution Management System (DMS)– A system with numerous software applications to assist control room

dispatchers in managing the distribution network

– DA is one of these applications, another DMS application is Switch Order Management


Categories of Distribution Automation


Primary

Topic for this

seminar

Categories of Distribution Automation


Distribution System Under Smart Grid

Drawing by General Electric


Questions?


Bob Uluski

UU208: Distribution Automation –


Automatic Feeder

Switching


Introduction

• Distribution Feeder Automation is the monitoring

and control of devices located out on the feeders

themselves

– Line reclosers

– Load break switches

– Sectionalizers

– Capacitor banks

– Line regulators


Main Feeder Automation Applications

• Automated Line Switching (ALS)

• Volt/VAR Control (VVC) (Discussed in next Seminar Module)


The Value proposition

• Reduce system SAIDI & SAIFI significantly

– Show the concept with a simple illustration

• Accommodate distributed energy resources

• Optimal network reconfiguration

– Reduce peak loading and total technical losses via

load balancing


Primary ALS Application – “FLISR”

• Fault Location, Isolation, and

Service Restoration

• Use of automated feeder

switching to:

– Detect feeder faults

– Determine the fault location

(between 2 switches)

– Isolate the faulted section of the

feeder (between 2 feeder switches)

– Restore service to “healthy” portions

of the feeder


Nature of the Problem

• When a permanent fault occurs, customers on “healthy”

sections of the feeder may experience a lengthy outage

• FLISR provides the means to restore service to some

customers before field crews arrive on the scene

FAULTOCCURS

CustomerReportsOutage

FieldCrews

On-Scene

Travel Time

FaultLocated

Fault Investigation& Patrol Time

POWER RESTOREDTO CUSTOMERS ON HEALTHY SECTIONS

OF FEEDERTime to Perform

Manual Switching Repair Time

FeederBack toNormal

5 – 10 minutes

15 – 30 minutes

15 – 20 minutes

10- 15 minutes

45 – 75 minutes


Time Line Without and With FLISR

FaultOccurs


FieldCrews

On-Scene

Travel Time

FaultLocated

Fault Investigation& Patrol Time


OF FEEDER

Time to PerformManual Switching Repair Time

FeederBack toNormal

5 – 10 minutes

15 – 30 minutes

15 – 20 minutes

10 - 15 minutes

45 – 75 minutes

FAULTOCCURS

FeederBack toNormal


OF FEEDER

Travel Time

15 – 30 minutes

1 - 4 Hours

Repair Time

1 - 4 Hours

1 to 5 minutes

5 - 10 minutes

PatrolTime


5 – 10 minutes

Without FLISR

With FLISR


Terminology – Sample Feeder

Substation #2

Substation #1 Substation #3

1 2

3

4

5

6 7 8


Terminology – Automated Switches

Substation #2


1 2

3

4

5

6 7 8

Normally closed (line)

switch

Normally open (tie)

switch

• All switches must be electrically operable

• Can be load break or fault interruptingdevices


Terminology – Fault Detector (FD)

Substation #2


1 2

3

4

5

6 7 8

FD installed on every switch

FD indicates whether fault current has passed through the switch

NoFault

NoFault

FaultFault

Fault Current


Terminology – Feeder Sections

Substation #2


1 2

3

4

5

6 7 8

Fault

Faulted Feeder Section

“Healthy”Feeder Section

Section: a portion of the feeder between two automated switches


Terminology – Sources

Substation #2


1 2

3

4

5

6 7 8

“Strong” Source – Capable of

carrying a significant part of

feeder 1 if necessary

“Weak” Source – Capable of

carrying only a small part of

feeder 1

• Alternate sources required

for maximum DA benefit

• Strong or Weak Source


FLISR Operation – A Fault Occurs

Substation #2


1 2

3

4

5

6 7 8

Permanent fault occurs in section surrounded by switches 2, 3 and 6

FDs at switches 1 and 2 detect the fault

FLISR stores value of load through each switch just prior to the fault (usually a fifteen minute average).

FLISR logic does not yet open/close any switches

Fault Fault No Fault

No Fault

Fault Current

Fault


CB Trips – Feeder Deenergized

Substation #2


1 2

3

4

5

6 7 8

Circuit breaker trips

Entire circuit de-energized (dotted line)

FDs at switches 1 and 2 remain picked up

Still no FLISR control actions


No Fault

Fault


Line Recloser Trips –

Portion of Feeder Deenergized

Substation #2


1 2

3

4

5

6 7 8

If line reclosers are used instead of load break switches, only a portion of the feeder is interrupted


No Fault

Fault

Line Recloser


CB Trips – Feeder Deenergized

Substation #2


1 2

3

4

5

6 7 8

Circuit breaker trips





No Fault

Fault


CB Recloses – Fault Still There

Substation #2


1 2

3

4

5

6 7 8




No Fault

Fault Current

Fault


CB Trips Again – Feeder Deenergized

Substation #2


1 2

3

4

5

6 7 8

Circuit breaker trips and locks out



FLISR open/close logic triggered


No Fault

Fault


FLISR Step 1 – Identify Faulted Section

Substation #2


1 2

3

4

5

6 7 8

FDs 1 & 2 saw a fault

FDs 3 and 6 did not see the fault

Fault must be in section between switches 2,3, & 6


No Fault

Fault

Faulted Feeder

Section


FLISR Step 2 – Isolate Faulted Section

Substation #2


1 2

3

4

5

6 7 8

Automatically open switches 2,3, & 6


No Fault

Fault

Faulted Feeder

Section


FLISR Step 3 – Restore “Upstream” Section

Substation #2


1 2

3

4

5

6 7 8

FLISR closes CB

No need to check load –we know CB can carry the first section

FD at switch # 1 resets

Fault No Fault

No Fault

Fault

Faulted Feeder

Section

““““UpstreamUpstreamUpstreamUpstream”””” =

between

substation and

faulted section


FLISR Step 4 – Restore “Downstream” Load

Substation #2


1 2

3

4

5

6 7 8

Substation #2 is a “strong”source – it can carry additional load

Close switch 4 to pick up part of faulted feeder

Fault No Fault

No Fault

Fault

“Downstream”

= between

faulted section

and end of

feeder

(This is the tricky part)


FLISR Step 5 – Restore “Downstream” Load

(continued)

Substation #2


1 2

3

4

5

6 7 8

Substation #3 is a “weak”source – can’t carry additional load at this time

Switch 7 remains open

Feeder section between switches 6 and 7 remain de-energized

End of FLISR operation

Fault No Fault

No Fault

Fault


FLISR Benefits

• Reliability Improvement - Significant portion of

customers restored quickly (1 minute or less,

versus 45 – 75 minutes without FLISR)SAIDI Improvement Versus Baseline

52%52%

33%

0%

10%

20%

30%

40%

50%

60%

Conventional recloser 1 load break w ith

Intelliteam II

1 Intellirupter w ith

Intelliteam III

SAIFI Improvement Versus Baseline

42%42%

18%

0%

10%

20%

30%

40%

50%


Intelliteam II


Intelliteam III

SAIFI(MI) Improvement Versus Baseline

21%

-25%

6%

-30%

-20%

-10%

0%

10%

20%

30%


Intelliteam II


Intelliteam III

CAIDI Improvement Versus Baseline

17.9%17.9%18.3%

10.0%

12.0%

14.0%

16.0%

18.0%

20.0%


Intelliteam II


Intelliteam III

DA With Load Break

Switches

DA With Reclosers DA With

Load Break Switches

DA With Reclosers

DA With Load Break

Switches

DA With Reclosers

DA With Load Break

Switches

DA With Reclosers


Other FLISR Benefits

• Labor Savings – Less fault investigation and patrol

time because fault location is narrowed down

considerably

• Reduction in Unserved Energy – Get some meters

turning sooner


Feeder Load Balancing

• Objective: Reduce peak demand on

feeders/substations by periodically shifting load

between connected feeders to achieve better balance

• Must have significant diversity between feeders

• “Make before break” to avoid momentary outages

0

1

2

3

4

5

6

7

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27


Load Balancing – Normal Configuration

Substation #2


Sub #1 at Peak Load


Load Balancing – Sub#1 At Peak Load

Substation #2


Load TransferredTo Sub #3

Sub #1 at Peak Load


Load Balancing – Sub#3 At Peak Load

Substation #2


Load TransferredTo Sub #1

Sub #3 at Peak Load


Load Balancing - Benefits

• Reduction of Peak Demand on individual

substation

– Defer capacity addition

– Reduce individual substation demand charges

• Reduction of Electrical Losses

– Total losses with balanced load < Total losses

with one heavily loaded feeder and one lightly

loaded feeder


Cold Load Pickup

• Objective: Reduce the time to restore load

following extended outage for which cold load

conditions apply

• Restore service a section at a time via remote

control


Cold Load Pickup Example

Substation #2




Substation #2


Open all switches via

remote control



Substation #2


Restore one section

at a time



Substation #2


Restore one section

at a time


Cold Load Pickup Benefits

• Reliability Improvement Benefit: Faster overall

service restoration

• Labor Savings: Fewer manual switching

activities, less travel time


Emergency Load Shedding

• Some utilities are limited in amount of load

shedding that is possible due to presence

of critical (non-interruptible) loads

• Automated switches can be used to shed

load on such feeders without impacting

non-interruptibles


Load Shedding Using Line Switches

Substation #2

Substation #1Substation #3

Open This Switch

Non-Interruptible Customer in this section


Use of Faulted Circuit Indicators

Substation #1

1 2

3

4

6 7

Remotely monitored faulted circuit indicator can assist in pinpointing fault location


Benefits of FCI Monitoring

Fault Prediction by OMS/AMI


Benefits of FCI Monitoring

Fault Prediction by OMS/AMI & FCI


System Components

Distribution SCADA system

– Remote controlled feeder switches

– Feeder RTU or Controller

– Fault detectors

– Two-way communication facilities

(Sp.Spectrum

MAS


Distribution SCADA System

• Supervisory Control and Data Acquisition (SCADA) system:

– Minimum requirement: Allow distribution system operator to monitor and oversee operation of the feeder automation facilities

– May also perform the bulk of the feeder automation processing (centralized scheme only – more on this in Module 5)


Feeder Automation Switches

• All switches must be electrically

operable

• Can be load break or fault

interrupting devices

• Can be overhead or underground

(padmount) switches

Kyle® Type NOVA™ Recloser(Fault Interrupting Device).

Photo courtesy of Cooper Power Systems

Load Break Switch.

Photo courtesy of Bridges Electric

Pad Mounted Switch

ABB OVR Recloser


Retrofit Motor Operators

Retrofit Motor-Operator

Retrofit Padmount. Photo Courtesy of S&C Electric

Co

Retrofit Pole Mounted SwitchPhoto Courtesy of Cleaveland Price, Inc

may be able to save money by

retrofitting a motor operator

on an existing manual switch


DA Switch Vendors

Ve ndor Name W ebsite Recloser

Loa d

Break

ABB

www.abb.com /produc t/us /9AAC

720078.aspx X X

Cooper Power Systems www.cooperpower.com X X X X

S&C Electric Company www.sandc .com X X X X

Joslyn Hi Voltage www.joslynhivoltage.com X X X

G&W www.gwelec.com X X X X

Bridges Electric www.bridgeselec tric.com X

Cleaveland Price www.cleavelandprice.com X

Turner E lectric Co. LLC

http://www.turnerswitch.com/ins

tallation/operators.html X

Federal Pacific http://www.federalpac ific .com/ X X

Current Interrupting

Pole

Mount Pa dmount

Retrofit

Kit

Soon?Soon?Soon?Soon?

Siemens

FaultFaultFaultFault

InterruptingInterruptingInterruptingInterrupting

NOJA Power (Australia) www.nojapower.com.au X

Update the slide


Feeder RTU or Local Controller

• Acquires data from FD or local

sensors

• Executes control commands

• May perform bulk of feeder

automation processing

(distributed architecture)

• Provides interface to

communication facilities

S&C 5800

DAQ Polaris Pole-Top RTU

Cooper Form 6 Controller

SEL 451S&C UIM


Fault Detector (FD)

• Determines that a fault has occurred

“downstream” (further from the

substation)

• Basic Requirements

– Must be able to identify and “capture” the fault

information before fault is cleared (in a few

cycles)

– Must be able to detect all kinds of faults

• Phase faults

• Ground faults – current may be less than

normal load – must use “residual” current


Two Ways to Accomplish FD

• Faulted Circuit

Indicator (FCI)

• Current/Voltage

Sensor


Faulted Circuit Indicators

– Clamp on style

– Current inrush restraint

– Must work in either direction

– Reset conditions

• Time

• Restoration of voltage or current

– Local indicator visible from ground level

– Output signal to feeder RTU

• Radio signal

• Fiber optic/metallic cable

Edison Controls FD

Photo Courtesy of Horstmann/Power Delivery Products

Faulted Circuit Indicator (FCI)Close a contact when pre-established ampere threshold is exceeded


Radio Transmitter Style Fault Indicator


Current & Voltage Sensors

– Perform basic current & voltage measurement

– Provide measurement to a separate device for analysis (“does measurement exceed threshold?”)

– Doubles as data acquisition unit for feeder monitoring (SCADA) system

– Voltage sensor may also serve as a power source for DA feeder equipment

– Basic requirements• Accuracy at least + or - 3%

• Suitable for measuring fault current (should not saturate)

• Can be standalone unit(s) or integral part of switch itself

Lindsey Current

Sensor

Fisher Pierce Line

Post Sensor


Current & Voltage Sensors

Can be an integral part of the DA switch

Current-

Voltage

Sensor

“ScadaMate” by S&C Electric


Bidirectional Fault Indicators

• Useful for – Systems with DG

– closed loop, paralleled or networked distribution systems

Power Delivery Products

http://www.powerdeliveryproducts.com/directionalfaultindicator.htm


Communication Facilities

• System requires reliable 2-way communication

facilities to feeder locations

• Common approaches:

– Licensed UHF MAS radio

– Unlicensed Spread spectrum radio

– Cellular telephone & other commercial services

– Power line carrier

More details on DA Communications laterMore details on DA Communications laterMore details on DA Communications laterMore details on DA Communications later


Control Panels

• Open/Close Pushbuttons

• Switch status (open/closed) indicators

• Alarm indicators

• Local/remote switch

• Operations counter

– Electrical operations

– Mechanical operations?


Switch Power Supply (SPS)

• Key Point: Most switch operations run

off the SPS with the line dead!

– Should specify a required number of

operations with the power off (biggest power

drain is radio transmitter)

– As an absolute minimum, must be able to

open switch and close switch once without

recharging (with the line dead)

• Power Source

– Voltage sensor may provide all the power

needed by the switch, controller, and radio

– If not use dedicated voltage transformer or

connect to local secondary circuit


Categories for Automated Line Switching

• Approaches categorized on how control is

performed:

– Supervised

– Semi-Automatic

– Fully Automatic


Feeder Automation Categories

• Supervised• No automatic control – “person in the loop”

• System delivers information (recommendations) to Dispatcher

• Dispatcher initiates remote control actions

– Pro’s• Simpler than fully automatic

• Good “starter” approach until confidence is built up

– Con’s• Takes longer to restore service (3 – 5 minutes)

– Communication time (both ways)

– Dispatcher decision time

• Difficult for dispatcher to manage many switches during emergencies involving multiple disturbances



• SEMI-AUTOMATIC

– Mix of automatic and supervised control

– Example– DA system automatically isolates fault and performs “upstream”

restoration (the “easy” part)

– Dispatcher supervises “downstream” restoration activities based on DA system recommendations (the “hard” part)

– Pro’s

• Simpler than fully automatic

• Natural progression from supervised approach

• Where many utilities end up

• “Upstream” customers restored in less than 1 minute

– Con’s

• Takes longer to restore “downstream” service (3 – 5 minutes)

• Difficult for dispatcher to manage many switches during emergencies involving multiple disturbances

• Not supported by some DA vendors



– FULLY AUTOMATIC

– All fault isolation and restoration activities performed automatically

– Current state of the art

– No dispatcher intervention

• Pro’s

– Possible to restore all service in less than one minute

– Less burden on Dispatcher to manage the switching activities

• Con’s

– Most complex approach

– Acceptance difficulties

» Ranges from “Why not?” to “Over my dead body”


Practical Matters to Consider


• Tradeoff: “Permanent” vs.

“Momentary” Outages

• Definitions:

– Permanent: Duration > threshold

– Momentary: Duration < threshold

• Use of FLISR will:

– Improve permanent outage statistics

• SAIDI, SAIFI, CAIDI

– Make momentary outage statistics worse

• MAIFI

• Most utilities are willing to accept this

tradeoff!


• Limitations on Transferring Load

to Adjacent Feeders– It is often difficult to transfer all the “healthy” load

to adjacent feeders without causing overloads

and/or voltage problems

– Especially true during peak load period

– May need to split load being transferred to

alternative sources

– May require additional automated switches to

accomplish FLISR objectives at certain times of the

day

– Key Point: Must have backup source to get

incremental reliability improvement beyond

simple recloser!


Diminishing Returns

• Additional reliability improvement benefit

declines dramatically as more switches are added

• Usually 2 ½ switches is best for reliability

improvement BFTB – more switches added due

to load transfer constraints, critical customers,

and unusual feeder configuration

Reliability Improvement vs. Cost

0

500

1000

1500

2000

2500

3000

0 20000 40000 60000 80000 100000

Cost ($)

Cu

st O

uta

ge

Min

ute

s

Imp

rove

me

nt


Importance of Switch Placement• Predicted reliability improvement varies widely with

switch placement strategy

• KEY POINT!: Splitting customer count into equal parts is only best when customers and fault exposure are evenly distributed across the feeder

• Variation observed for sample case:

– SAIDI - 22%

– SAIFI - 31%

– MAIFI - 23%

• Small change in placement (a few hundred feet) produced a 5% change in SAIDI!

• Switch placement analysis is not trivial – should use engineering analysis tool!


Single Phase Tripping• Some newer line reclosers support single phase

tripping

• Can perform FLISR operation on only the faulted phase – avoid service interruption on unfaulted phases (SAIDI, SAIFI benefit)

• Issues:– Adverse impact on 3 phase loads

– Remaining two phases may trip ground relay on load imbalance

• Typical solution:– Trip and reclose single faulted phase for temporary fault

– Trip and lockout all three phases for permanent fault


Faults on Fused Laterals

• No incremental benefit for permanent

faults on fused laterals

– Must take this into account when computing

potential benefits

• For temporary faults:

– Can apply fuse saving

– New S&C “TripSaver”


First Segment Fault Detection• Always an issue!

• System requires a “lockout for fault”signal from the substation to trigger feeder switching activities

– Fault has occurred

– Feeder protection has completed its automatic reclosing cycle

• Works best if a protective relay IED is available in the substation and can be interfaced to the FLISR system


Non-Fault vs Fault Tripping

• System must be able to distinguish between “non

fault” and “fault” tripping of the substation circuit

breaker/recloser

• “Fault” Tripping

– A feeder fault has occurred or supply has been lost due to a

transmission substation fault

– FLISR should attempt to restore service

• “Non-Fault” Tripping

– Substation CB tripped for reasons other than a feeder fault

• Manual operation by switching personnel or supervisory

control from the control center

• Underfrequency/undervoltage load shedding

– FLISR should not attempt to restore service


Safety Issues

• Safety for workers and general public must

not be compromised!!!

• Operating practices and procedures must

be reviewed and modified if necessary to

address presence of automatic switchgear

• Safety related recommendations:

– Requirement for “visible gap”

– No automatic closures after two minutes have

elapsed following the initial fault

– System disabled during maintenance (“live

line”) work


Questions?


Bob Uluski

UU208: Distribution

Automation –

Smart Feeders in a Smart Grid

World

Volt-VAR Control


What is Volt-VAR control?

• The use of voltage regulating devices and reactive power

controls to…:

– Maintain acceptable voltages at all points along the feeder under all

loading conditions

– Operate the distribution system as efficiently as possible without

violating any load and voltage constraints

– Support the reactive power needs of the bulk power system during

system emergencies


How Is Volt-VAR Control Accomplished?

• General technique:

– Measure electrical and ambient conditions

– Analyze the measurements to determine if

electrical conditions are what we expect them to

be

– Determine what control actions (if any) are needed

to restore the desired conditions

– Send control signals to the voltage and reactive

power control devices


How Is Volt-VAR Control Accomplished?

• Traditional Devices for Volt-VAR Control– Fixed and switched capacitor banks (in substation and out on the

feeder)

– Substation transformers with Load Tap Changers (LTCs)

– Voltage regulators (in substation and/or out on the feeder)

• “Future” Devices for Volt-VAR Control– Distributed generating resources

– Static VAR compensators


Volt-VAR Control versus Volt-VAR

Optimization

• Principal Objective of Volt-VAR Control

– Maintain acceptable electrical conditions out on

the feeders (i.e., keep the voltage within

allowable limits at all points along the feeder)

• Objectives of VVO (aka IVVC)

– Maintain acceptable electric conditions…

– Reduce losses/improve efficiency

– Lower demand and energy consumption

– Respond to system emergencies


The Cycle of Interest in this Topic

1 4 7

10

13

16

19

22

25

-1

-0.5

0

0.5

1


Approaches to Volt VAR Control

• Traditional

Approach

• SCADA Controlled

Volt VAR

• Integrated Volt VAR

Control


Reqt’s for the “Ideal” Volt-VAR Control System

• Maintain Acceptable Voltage Profile at all points along the

distribution feeder under all loading conditions

• Maintain Acceptable Power Factor under all loading conditions

• Provide Self Monitoring – alert dispatcher when a volt-VAR device

fails

• Allow Operator Override during system emergencies

• Work correctly following Feeder Reconfiguration

• Take advantage of SmartGrid Devices (StatCOM, DG, etc.)

• Provide Optimal Coordinated Control of all Volt VAR devices

• Allow Selectable Operating Objectives as different needs arise


Traditional Volt-VAR Control

• Volt-VAR flows managed by individual, independent, standalone volt-VAR regulating devices:

– Substation transformer load tap changers (LTCs)

– Line voltage regulators

– Fixed and switched capacitor banks


Limitations of Traditional Volt-VAR Control

• The system is not continuously monitored

• The system lacks flexibility to respond to changing conditions out on the distribution feeders – can misoperate following automatic reconfiguration

• No effective way to do Conservation Voltage Reduction

• System operation may not be “optimal” under all conditions

• Cannot override traditional operation during power system emergencies

• System may misoperate when modern grid devices (e.g., distributed generators) are present – reverse power flow from DG can “trick” standalone controller to believe feeder has been reconfigured


Limitations of Traditional Approach

• Power factor correction/loss reduction

– Many traditional cap bank controllers have

voltage control (switch on when voltage is low)• Reactive power controllers available, but expensive (need to add CT)

• Good at maintaining acceptable voltage

• Good at PF correction during peak load seasons – may not come on at all

during off peak seasons

• Result is that PF is usually great (near unity) during peak load periods and

low during off peak seasons (higher electrical losses)


Monitoring of Switched Capacitor Bank Performance

• Switched capacitor banks are notorious for

being out of service due to blown fuses, etc.

• With traditional scheme, switched capacitor

bank could be out of service for extended

periods without operator knowing

– Losses higher if cap bank is out of service

– Routine inspections needed?


Voltage Regulation During Alternate Feed Configuration

• Older style voltage regulators were often designed to handle a purely radial situation – power flow always from the same direction (from the substation)

• Older style Vregs may not work correctly if power flow is from the opposite direction (see example)

– Could raise voltage when during light load, creating high voltage situation

– Could lower voltage when during heavy load, creating low voltage situation

• Feeder reconfiguration may become a more frequent occurrence due to

– Load transferred to another feeder during service restoration (FLISR)

– Optimal network reconfiguration to reduce losses (DMS application)

Incorrect Operation!

Vreg not bi-directional


Use of “Bidirectional” Voltage Regulator

• Can Use “Bidirectional” voltage regulator controller to handle feeder reconfiguration

• These make the opposite tap position movement when flow is from the reverse direction

Correct Operation!

Vreg bi-directional


“Scorecard” for Traditional Volt

VAR

Volt VAR RequirementsTraditional Volt-

VAR

Acceptable Voltage Profile X

Acceptable Power Factor X

Self MonitoringOperator OverrideFeeder Reconfiguration SmartGrid Devices

Optimal Coordinated ControlSelectable Operating Objectives


“SCADA” Controlled Volt-VAR

• Volt-VAR power apparatus and sensors monitored and

controlled by Supervisory Control and Data Acquisition

(SCADA)

• Volt-VAR Control typically handled by two separate

(independent) systems:

– VAR Dispatch – controls capacitor banks to improve power

factor, reduce electrical losses, etc

– Voltage Control – controls LTCs and/or voltage regulators

to reduce demand and/or energy consumption (aka,

Conservation Voltage Reduction)

• Operation of these systems is primarily based on a stored set

of predetermined rules (e.g., “if power factor is less than

0.95, then switch capacitor bank #1 on”)


VAR Dispatch Components

• Switched & fixed feeder capacitor banks

• Capacitor bank control interface

• Communications facility - one-way paging or load

management communications is sufficient

• Means of monitoring 3-phase var flow at the substation

• Master station running VAR dispatch software


Monitoring Real and Reactive Power Flow


VAR Dispatch Rules Applied


Real and Reactive Load Increases


Reactive Power Flow Exceeds

Threshold


Capacitor Switched On


Change in Reactive Power Detected


Change in Reactive Power Detected

Change detected

by Substation

RTU


Benefits of VAR Dispatch vs Traditional

• Self Monitoring

• Operator override capability

• Some improvement in

efficiency


Concept of Conservation Voltage

Reduction

Source: Tom Wilson PCS Utilidata


Benefits of Voltage Reduction

• Works best with resistive load (lighting and

resistive heating) because power drawn

decreases with the voltage squared .

• Devices that operate using a thermostat

generally do not reduce energy – the devices

just run longer

P = (V / Vnom)2 ÷÷÷÷ R

Constant

Impedance

load


Benefits of Voltage Reduction

Efficiency improve for small voltage reduction

Incremental change in efficiency drops off and then turns negative as voltage is reduced

Negative effect occurs sooner for heavily loaded motors


Benefits of Voltage Reduction for Various Types of Loads

• Constant impedance (power consumed is proportional to voltage squared)

– Incandescent lighting, resistive water heaters, stovetop and over cooking

loads

• Constant power (demand is constant regardless of voltage)

– Electric motors, regulated power supplies

• Constant current (demand is proportional to voltage) (few of this type of load)

– Welding units, smelting, electroplating processes

• Feeder load is always a mix of the different

load types

• Rules of thumb:

– 60/40 split (constant power/constant

impedance) for summer peak loads

– 40/60 split for winter peak loads

– 80/20 for industrial areas

– 70/30 for residential load in residential with

summer peaking

– 30/70 for res load with winter peaking

– Commercial loads: 50/50 or 60/40

• Source: Power Distribution Planning

Reference Book”, H. Lee Willis


Time Decay of CVR Effects

• The most reduction occurs right when the voltage is

reduced and then some of the reduction is lost as

some loads just run longer


Voltage Control Components


Load Below Voltage Control Threshold (No Control Actions)

LTC

Substation

RTU

Voltage Control

Processor

Volt Meter

or AMRComm

Interface

Comm

Interface

OO

Reactive Power (MVAR)

Real Power (MW) End of

Feeder

OOOO

OOOO Voltage

Transformer

LTC

Controller

Substation

Transformer


Load Above Voltage Control Threshold

LTC

Substation

RTU

Voltage Control

Processor

Volt Meter

or AMRComm

Interface

Comm

Interface

OO

Reactive Power (MVAR)

Real Power (MW) End of

Feeder

OOOO

OOOO

LTC

Controller

Substation

Transformer


Load Above Voltage Control Threshold (lower tap setting)


Benefits of Voltage Control versus Traditional Volt-VAR

• Self Monitoring

• Operator override capability

• CVR function not available

with traditional


What SCADA Volt VAR Can’t Do

• Does not adapt to changing feeder configuration (rules are fixed in advance)

• Does not adapt to varying operating needs(rules are fixed in advance)

• Overall efficiency is improved versus traditional approach, but is not necessarily optimal under all conditions

• Operation of VAR and Volt devices is not coordinated

• Does not adapt well to presence of modern grid devices such as DG


SCADA VAR Dispatch (versus Traditional)

• Power factor correction/loss reduction

– Many traditional cap bank control have voltage

control (switch on when voltage is low)• Reactive power controllers available, but expensive (need to add CT)

• Good at maintaining acceptable voltage

• Good at PF correction during peak load seasons – may not come on at all

during off peak seasons

• Result is that PF is usually great (near unity) during peak load periods and

low during off peak seasons (higher electrical losses)

– SCADA VAR Dispatch addresses low power factor

as well as low voltage at the feeder level• Benefit is reduced electrical losses (e.g. reduced energy consumption)

over the year

• If PF is poor at peak load, loss reduction = demand reduction


Monitoring of Switched Capacitor Bank Performance

• Switched capacitor banks are notorious for being out

of service due to blown fuses, etc.

• With traditional scheme, switched capacitor bank

could be out of service for extended periods without

operator knowing

– Losses higher if cap bank is out of service

– Routine inspections needed?

• With SCADA VAR Control, can automatically detect

banks that do not respond to switching command

– Eliminate routine inspections (where applicable)

– Reduce incremental losses incurred when cap bank OOS


Lack of Coordination between Volt and VAR control

• Switching a capacitor bank on raises the

voltage, which:

– Increases no-load losses in distribution

transformers

– Increases energy consumption and possibly

demand

• Lowering the voltage through CVR:

– Makes the capacitor banks less effective (lower

voltage means less capacitive current delivered by

the cap banks


RealitiesRealities of SCADAof SCADA--ControlledControlled VVCVVC

• Simple but not fully effective.

• Hydro Quebec Demonstration project gained

only 30% of the estimated energy

consumption.

– Volt meters not really at the end of the feeders.

Volt meters installed only on 3 phases circuits.

Targets need to cover also the worst case voltage

drop of the single phase networks.

– Network topology during the demonstration

project (1 year average) was not in its normal

state 40% of the time.


Volt VAR “Scorecard”


VAR

SCADA Volt-

VAR

Acceptable Voltage Profile X X

Acceptable Power Factor X X

Self Monitoring X

Operator Override X

Feeder Reconfiguration SmartGrid Devices

Optimal Coordinated ControlSelectable Operating Objectives

Volt-VAR Approach


Integrated Volt-VAR Control (IVVC) System Config

Distribution

System Model

Geographic

Information

System (GIS)

Distribution

SCADA

Temp

Changes

Perm

Changes

Dynamic

Changes

On-Line Power

Flow (OLPF)

IVVC

Optimizing

Engine

MDMSAMILine

Switch

Substation RTU

Substation

Transformer

with TCUL

Substation Capacitor

Bank

Switched

Cap Bank

Line

Voltage

RegulatorDevelops a coordinated

“optimal”switching plan for all voltage control

devices and executes the plan


IVVC “Objectives”

• With IVVC, user can select an optimizing

objective:

– Reduce losses

– Reduce energy consumptions

– Reduce electrical demand

– Minimize “cost”

– Combination of the above



Distribution

System Model

Geographic

Information

System (GIS)

Distribution

SCADA

Temp

Changes

Perm

Changes

Dynamic

Changes

On-Line Power

Flow (OLPF)

IVVC

Optimizing

Engine

MDMSAMILine

Switch

Substation RTU

Substation

Transformer

with TCUL

Substation

Capacitor

Bank

Switched

Cap Bank

Line Voltage

Regulator

Switch StatusVoltage Feedback,

Accurate load data

Bank voltage & status, switch control

Bank voltage & status, switch control

Monitor & control tap position, measure load

voltage and loadMonitor & control tap position, measure load

voltage and load

IVVC requires real-time monitoring & control of sub & feeder devices


Distribution

System Model

Geographic

Information

System (GIS)

Distribution

SCADA

Temp

Changes

Perm

Changes

Dynamic

Changes

On-Line Power

Flow (OLPF)

IVVC

Optimizing

Engine

MDMSAMILine

Switch

Substation RTU

Substation

Transformer

with TCUL

Substation

Capacitor

Bank

Switched

Cap Bank

Line Voltage

Regulator

Permanent asset changes (line extension,

reconductor)

Cuts, jumpers, manual switching

Real-Time Updates

IVVC requires an accurate, up-to date

electrical model




Distribution

System Model

Geographic

Information

System (GIS)

Distribution

SCADA

Temp

Changes

Perm

Changes

Dynamic

Changes

On-Line Power

Flow (OLPF)

IVVC

Optimizing

Engine

MDMSAMILine

Switch

Substation RTU

Substation

Transformer

with TCUL

Substation

Capacitor

Bank

Switched

Cap Bank

Line Voltage

Regulator

OLPF calculates losses, voltage

profile, etc

Powerflow Results



Distribution

System Model

Geographic

Information

System (GIS)

Distribution

SCADA

Temp

Changes

Perm

Changes

Dynamic

Changes

On-Line Power

Flow (OLPF)

IVVC

Optimizing

Engine

MDMSAMILine

Switch

Substation RTU

Substation

Transformer

with TCUL

Substation

Capacitor

Bank

Switched

Cap Bank

Line Voltage

Regulator

Powerflow Results

Alternative Switching

Plan

Determines optimal set of control

actions to achieve a desired objective



Distribution

System Model

Geographic

Information

System (GIS)

Distribution

SCADA

Temp

Changes

Perm

Changes

Dynamic

Changes

On-Line Power

Flow (OLPF)

IVVC

Optimizing

Engine

MDMSAMILine

Switch

Substation RTU

Substation

Transformer

with TCUL

Substation

Capacitor

Bank

Switched

Cap Bank

Line Voltage

Regulator

Optimal Switching

Plan

Determines optimal set of control

actions to achieve a desired objective


IVVC Benefits

• Dynamic model updates automatically when reconfiguration occurs

• Volt – VAR control actions are coordinated

• System can model the effects of Distributed Generation and other modern grid elements

• Produces “optimal” results

• Accommodates varying operating objectives depending on present need


Reduced “Wear and Tear” on Vreg

Equipment

• Experience with advanced VVO programs

indicates that:

– Switched capacitor banks switch less often

(extends life of switch, reduces PQ affects of cap

bank switching)

– Tap changers change taps less often (Can bias

recommended control actions to choose switching

scenarios that do not move the taps much)


Lower Revenue – A Negative Benefit

• Operating with lower voltage on a 7 x 24 basis

results in considerable lost revenue

• In most cases, other benefits outweigh the

lost revenue

Lost Lost revenue revenue

from kWh from kWh

SalesSales

Lower losses, Lower losses, lower demand, lower demand,

extended extended

equipment lifeequipment life


Impact of Voltage Reduction on Customers

• In most cases, voltage reduction does not

impact customer equipment, but…..

• Some customers are aware of the principle of

voltage reduction and gave already taken

steps to lower their voltage via individual

service voltage regulators

• When utility lowers the voltage on the feeder,

customers who are already lowering their

own voltage will go below the minimum


Voltage Reduction Limitations

• Feeders voltage limited?

– May not be able to reduce voltage at all

– May need to “flatten” the voltage profile

(Progress Energy, Georgia Power, etc)


Current Technologies, LLC


PCS Utilidata – Adaptivolt – VVO without Rules or Models


Final Volt-VAR “Scorecard”


VAR

SCADA Volt-

VAR

Integrated Volt-

VAR

Acceptable Voltage Profile X X X

Acceptable Power Factor X X X

Self Monitoring X X

Operator Override X X

Feeder Reconfiguration X

SmartGrid Devices X

Optimal Coordinated Control X

Selectable Operating Objectives X

Volt-VAR Approach


Questions?


Bob Uluski



DA System Architecture


Objective of this Presentation

• Provide an overview of various approaches to DA system architecture

• Identify key issues to consider

• List pro’s and cons of each approach

• Provide guidance on determining which approach work best under what circumstances

• Identify vendors that support each architecture


Centralized Architecture

Control

Center

Feeder

Locations

DA Logic

Resides here

• Main logic resides in control center servers

• Logic can be “rule based” or “model based” (model maintained via GIS)

• Usually part of a distribution SCADA, EMS or DMS – can be a third party add-on server

• Many use “dumb” field devices, but some use IED for backup/failsafe

• Numerous communication strategies

• Direct (MAS radio, cellular, etc)

• Flow through substation

• Use AMI “back haul”infrastructure


Centralized Architecture

Control

Center

Feeder

Locations

DA Logic

Resides here

• With purely centralized approach, nothing happens without the main computer and control center

– Some see this as a disadvantage

– Some see this as an advantage


Localized, Peer-Peer Approach

– A feature of this approach is that it doesn’t absolutely require a

distribution SCADA system

– Intelligence resides in local processors located out on the feeders –

– Local processors make switching decisions based on local measurements and information acquired from “peers”

– Also have localized automation in the form of standalone IED


Substation Centered

• Main DA logic runs on a processor located in the substations

• One of the earliest approaches to DA

• Substation processors getting more powerful

• This approach is gaining in popularity

Control

Center

Feeder

Locations

Substation

DA Logic

Resides Here

Drawn by R. Uluski, EnerNex

Substation

Master


Criteria for Selecting

The Ideal DA Architecture

• Dispatcher Issues

• Ability to handle reconfiguration

• Ability to handle a flexible set of applications

• Scalability

• Performance (the “need for speed”)

• Maintainability

• Support for Smart Grid applications


Operator Visibility• Operators want to know what’s going on at all times

– Concern about feeders being reconfigured

– Automatic trip and isolate (recloser/sectionalizer) generally not a problem

– Volt-VAR control generally not a problem

• Can be a very passionate issue, especially for utilities that have limited or no experience with feeder automation. This objection tends to soften through periods of successful operation

• Comparison of DA Architectures – Operator Visibility– Centralized approach shines!

• Nothing happens without control center knowing

– Substation centered

• If substation-CC communication circuit fails, operations not reported to CC

• If substation-feeder communication fails, can disable DA (Workaround)

– Localized, peer-peer

• If substation-CC communication circuit fails, operations not reported to CC

• If substation-feeder communication fails, can disable DA (Workaround)

Issue Centralized Substation Centered Localized, Peer-Peer

Operator VisibilityScorecard


System Performance

• DA system performance must be fast enough to satisfy the most stringent system requirement

– Volt-VAR applications generally are not too time critical

– Fault detection isolation restoration (FDIR) performance requirements vary

• 5 minute momentary/sustained threshold (fast)

• 1 minute momentary/sustained threshold (very fast)

– “Bumpless” transition to microgrid (Extremely fast)

• Comparison of DA Architectures – System Performance– Centralized approach

• Connection back to control center adds latency (delay)

• With high bandwidth fiber optic connection via the substation, delay tolerable for most applications

• With lower bandwidth connection (e.g., 1200 - 4800 baud leased line) delay can be excessive


• Application uses high speed communications (> 100 kbps) over relatively short distances

• Possible latency through substation processor


• Application uses high speed communications (> 100 kbps) over relatively short distances

Scorecard Issue Centralized Substation Centered Localized, Peer-Peer

Performance

`

Event occurs

10:30:00

Event reported

10:30:30

(30 second latency)


Scalability• In most cases, DA is not deployed at all locations – usually done on worst performing feeders

• Ideally, should be able to handle small and large quantities of feeders, with various “densities”

– “Density” = # feeders per substation

– System cost affected by # units and substation density

– Control center costs are shared by all feeders

– Substation costs are shared by “N” feeders per substation

60

70

80

90

100

0 100 200 300 400

# Feeders to automate

% r

ed

uc

tio

n i

n S

AID

I


1 Feeder per Substation

$0

$5,000,000

$10,000,000

$15,000,000

$20,000,000

$25,000,000

$30,000,000

$35,000,000

$40,000,000

$45,000,000

1 8 15 22 29 36 43 50 57 64 71 78 85 92 99

# Feeders

Centralized

Substation

Distributed

Number of feeders being automated


3 Feeders per Substation

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

$16,000,000

$18,000,000

1 8 15 22 29 36 43 50 57 64 71 78 85 92 99

# Feeders

Centralized

Substation

Distributed




$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

1 8 15 22 29 36 43 50 57 64 71 78 85 92 99

# Feeders

Centralized

Substation

Distributed




$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

1 8 15 22 29 36 43 50 57 64 71 78 85 92 99

# Feeders

Centralized

Substation

Distributed




$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

1 8 15 22 29 36 43 50 57 64 71 78 85 92 99

# Feeders

Centralized

Substation

Distributed




$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

1 8 15 22 29 36 43 50 57 64 71 78 85 92 99

# Feeders

Centralized

Substation

Distributed



Scalability

• Comparison of DA Architectures – Scalability

– Centralized approach• Lower cost SCADA type interface at each switch

• Big up front investment in control center

• Moderate investment in substation

• Generally not very scalable– Best application is large number of feeders

– Generally not justifiable for small number of feeders

– Substation centered• Lower cost SCADA type interface at each switch

• Significant investment in each substation

• Somewhat scalable– Can do a single substation

– Economics best with high “substation density”

– Localized, peer-peer• Higher cost per switch controller

• Most highly scalable – can do a single worst performing feeder or a few widely dispersed feeders

ScorecardIssue Centralized Substation Centered Localized, Peer-Peer

Scalability


Support for

Multiple Applications• DA applications are interrelated

– For example, automatic line switching may relocate a capacitor bank and change the whole way in which the cap bank should be operated

• Ideally, the system should support multiple DA applications so that all interactions are properly accounted for

– Fault location, isolation, and service restoration

– Volt-VAR control

– Optimal Network Reconfiguration (loss reduction, load balance, etc)

– Others

• Comparison of DA Architectures – Support for Multiple Applications– Centralized approach

• Full suite of DA applications available and supported

• Applications can run off the same dynamically operable model

– Substation centered• Possible to rehost key DA applications (FLISR, VVO) to substation processor, along with

relevant portion of models

– Localized, peer-peer• Generally limited to single key function such as FLISR

• S&C DESS microgrid is an exception (possibly others)


Support Multiple Applications

Distribution

SystemManagement

Automatic

ServiceRestoration

Fault

Location

Volt-VAROptimization Optimal

NetworkReconfig

EmergencyLoad Shed

Switch Order

Management

DistributionSCADA


Operation Following

Feeder Reconfiguration• DA applications should be able to handle changing feeder configuration

• Changes can occur through automated/remote controlled switching or field switching

• DA applications should produce the best possible control actions given the current configuration

• Comparison of DA Architectures – Support for Feeder Reconfiguration– Centralized approach

• Reconfiguration reflected in dynamic models used by centralized approach

– Substation centered• Changes reflected in application with model based solution

• Rule based solution may not work correctly following reconfiguration


• Approach usually does not adjust to reconfiguration




Maintainability• System must be maintainable, hopefully centralized maintenance is possible

– Need convenient mechanism for making permanent and temporary updates

• Line extensions, new equipment

• Temporary: cuts, jumpers, field switching

– Network management capability – must be able to view the health of components and communication network

• Comparison of DA Architectures – Maintainability– Centralized approach

• Temporary changes handled though dispatcher user interface

• Permanent changes handled via GIS (assuming GIS data is correct)

• GIS interface process not easy, but a well known process


• Vendor specific software for centralized maintenance

• Concern about remote setting changes on control equipment (similar concern to remote relay setting changes)


• Vendor specific software for centralized maintenance

• Relatively straightforward process for reconfiguring system

• Concern about remote setting changes on control equipment (similar concern to remote relay setting changes)


Maintainability


SG: Support for Microgrid

Operation• Support for microgrid and DER operation is clearly a key SmartGrid requirement

• Key requirements:– High speed control actions for coordinated operation of static devices

– Reduced reliance on communication facilities

• Comparison of DA Architectures – Support for Microgrid Operation

– Centralized approach• Connection back to control center adds latency (delay)

• Reliance on communication facilities over long distances

– Substation centered• Some delay possible as controllers communicate via the substation

• Reliance on communication facilities over moderate distances

– Localized, peer-peer• Minimal delay

• No “indirect” communication “hops”


Support for Microgrid Operation


SmartGrid: Data Concentration

and Preprocessing

• A number of advanced applications (fault anticipator, HQ fault locator) require ability to:

– Acquire large quantities of data from the field (current and voltage waveform data)

– Store and Process the data

– Send simple English language results to the dispatcher (“Device “X” is broken”)

• Comparison of DA Architectures – Data Concentration and Pre-Processing– Centralized approach

• Need to transport large volume of data to the central location – this can heavily burden the communication facilities

• Once the data gets to the control center, plenty of storage and processing capability


• Substation processor able to store and pre-process the raw data from sensors and IEDs

• Communicate concise info (“Device “A” Broken!”) upstream to control center

• No need to burden upstream communications

– Localized, peer-peer• Ok if entire function is packaged in a single IED

• If not, approach is not well suited for this application


Data Concentration & Preprocessing


Summary Scorecard

Issue Centralized Substation Centered Localized, Peer-Peer

Operator Visibility

Operating Modes

Performance

Scalability


Support Feeder Configuration

Maintainability

Data Concentration & Preprocessing

Support for Microgrid Operation


Centralized Approach – Sample

Architecture

Database Servers

DMS Application

Servers

DMS Data CenterLocal Area Network

`

Programmer Console

Operator Consoles

Database Servers

DMS Application

Servers

DMS Data CenterLocal Area Network

`

Programmer Console

Operator Consoles

Firewall

Outage Management

System

Geographic Information

System (GIS)

SCADA/DMS LAN

Front End Processors

Secure Substation Network

AMI Network

DMSHistorian

Distribution Control Center (Site One)

DMS FEP Servers

Distribution Feeder Devices

(Line reclosers, switched capacitor banks, voltage

regulators)

IPP

Substation RTUs or Data Concentrators

Corporate LAN

Distribution Control Center (Site Two)


Some Vendors That Support the

Centralized DA Approach

• ABB (Network Manager)

• Advanced Control Systems (PRISM)

• AREVA (eterradistribution)

• DigitaLogic (IAR)

• GE Energy (ENMAC system)

• Hitachi

• Open Systems International (OpenDNA)

• Siemens-Intergraph

• SNC Lavalin (GENe)

• Survalent (former Quindar)

• Telvent/Abengoa-DMS Group (OASys)


A Variation of the Centralized Approach• SCADA system resides on one central platform

• DA/DMS functions reside on a second system

• The two independent systems communicate via a data link (e.g., ICCP)

Oracle Utilities NMS, PCS Utilidata, UCI

Supplied By Vendor 2

Supplied By Vendor 1


DA Vendors That Support Substation

Centered Approach

Substation Automation

ApplicationACS

AREVA

T&D

BOW

NETWORKS

GENERAL

ELECTRICNOVATECH SEL

SIEMENS

PT&DTELVENT

Automatic feeder reconfiguration: � � � � � � � �

Volt/var optimization� � � � � �

Simple cap bank control � � � � � � �

FACTS SCADA or control � � �

Remote fault location � � � � � �

Equipment condition

monitoring � � � � � �

Distributed Energy Resource Mon & control

� � � �

IEC 61131 support � � � � � �

IEC 61850 8-1, 9-2, 9-2 � � � � �

Synchrophasor handling � �

AMI network interface �

Source: Survey of SA Vendors conducted by Bob Uluski, Quanta Technology, October 2008


ACS “FASTapps” Substation

Centered DA

Master Slave

Slave

Alternative “Peer-Peer” approach offered by DC Systems, Inc


S&C IntelliTEAM IIIntelliTEAM II Capabilities:

– Detect faults using fault detectors and loss of voltage

indication

– Locate faults by comparing information from team

members

– Open suitable switches to isolate fault

– Automatically restore power using available sources

that have sufficient capacity


Example Peer-to-Peer Architecture

Jungle Mux

Terminal Server

D20

Spread Spectrum Radio

Substation

S&C 5800

Switch

Controller

S&C 5800

Switch

Controller

S&C 5800

SwitchController

Jungle Mux

Terminal Server

D20


Substation

S&C 5800

Switch

Controller

S&C 5800

Switch

Controller

S&C 5800

SwitchController

Survalent Master Proxy Server

Jungle Mux

Firewall

Logic Module

Jungle Mux

Terminal Server

D20


Substation

S&C 5800

Switch

Controller

S&C 5800

SwitchController

Control Center

S&C 5800

Switch

Controller

Broadband Fibreoptic Network

System Architecture


Schweitzer (SEL)

• Basic Building Block Approach

– SCE, PSE&G, others


Comparison of System Architecture


DA System Vendors

Vendor Name FLISR

VAR

Dispatch

Voltage

Control IVVC Centralized

Centralized

Variation

Substation

Centered Distributed

ABB X XUnder

development XUnder

development

Advanced Control Systems X X X X X X

AREVA T&D X X X X X

Cooper/Cannon TechnologyUnder

development X X X X X X X

DAQ Electronics X X X X X

General Electric (GE Energy) X X X X X X

Novatech X X X X

Oracle Utilities XUnder

development X

S&C Electric Company X X

Siemens/ Integraph X X X X X

SNC Lavalin X X X X X

Survalent Technologies X X

Telvent-Abengoa X X X X X

Applications Supported Architecture Supported


DA Vendor Websites Vendor Name Website

ABB http://www.abb.com/cawp/GAD02181/C1256D71001E0037C1256

D1F004C79B6.aspx

Advanced Control

Systems (ACS)

www.acsatlanta.com

Areva TD http://www.areva-td.com/static/html/TDE-AGF_ProdFamily-

ProductFamily_Detailsv2_1080218383387.html?&productline=111

4091350220

Cooper Power/Cannon

Technologies

http://www.cooperpower.com/peercomm/

DAQ Electronics www.daq.net

General Electric http://www.geindustrial.com/cwc/solutions?id=37

Novatech, Inc http://www.novatechweb.com/electric.html

S&C Electric Company http://www.sandc.com/products/distributionautomation.asp

Siemens Power T&D https://www.energy-portal.siemens.com/

SNC Lavalin http://www.snclavalin.com/ecs/En/dmsproj.htm

Survalent Technologies www.survalent.com

Telvent http://www.telvent.com/products/electric/dms.pdf


Conclusions

• There is no ideal approach that fits all

circumstances

• Many current system are centralized, but

growing trend toward distributed processing

• Most likely, a hybrid approach that has

elements of the three categories will evolve


Questions?


Hahn TramBob Uluski



Distribution Management

Systems


DMS Defined

• Distribution Management System

A Decision Support System to assist the

control room and field operating personnel with the monitoring and control of the

electric distribution system Note: Not to be confused with Demand Side Management (DSM)!


DMS Defined – What’s included?

• Basic operating tools

– Distribution SCADA (DSCADA)

– “Person in Charge” software tools

• managing permits, clearances, safety

protection guarantees

• Generating switching orders



• Advanced Distribution Applications

– On line power flow

– Load forecasting (short and long term)

– State estimation

– Fault location

– Distribution contingency analysis

– Distribution “congestion management”

– System optimization (e.g. Optimal Network Reconfiguration)



• May be a host for DA

(feeder automation)

applications

– Fault location isolation

and service restoration

(FLISR)

– Volt-VAR optimization

(VVO)

Control

Center

Feeder

Locations

DA Logic

Resides here


The DMS Concept at BC Hydro

DMS Concept at BC Hydro


Topics

• DMS Functions pertaining to DA

– On-Line Power Flow (OLPF)

– State estimation

– Fault Location

– Switch Order Management (SOM)

– Contingency Analysis

– Congestion management

• System Integration (Hahn)


State Estimation

• Objectives– Topology verification

– Estimation of loads

– Validation of telemetered data

– Load calibration

• A Data Consolidation Process– Take the advantages of sufficient measurement redundancy (M/N

> 1.5)

– Correct data errors due to conflict/incorrect/inaccurate/asynchronous

– measurements

• Candidate State Variables (independent variables)– Voltages

– Branch Currents

– Nodal Injections


DMS State Estimation

• DMS State Estimation (SE) - a procedure used to

calculate the state of distribution system based on:

– distribution system configuration (topology),

– real time measurements and

– customer load profiles – pseudo measurement

• Consists of:

– Static state estimation

– Identification and re-estimation of bad measurements and

parameters


On-Line Power Flow (OLPF)• What is OLPF?

– A real-time version of the well known engineering power flow tool (“off line”power flow)

• What does it do?– Calculates electrical conditions

(voltage, current, real/reactive power) at all points along the feeder.

• OLPF objectives:– Provide operators with nearly

continuous “visibility” of all points along the feeder where no SCADA measurements exist (“state estimator”for distribution circuits)

– Provide feeder electrical information needed by other DMS applications (FLISR, IVVC, Switch order management, etc)


On-Line Power Flow• How does it work?

– Works in much the same way as the engineering tool

– Uses one of the many available iterative solution techniques:

• Newton Raphson, YBus, ZBus, Forward/Backward “Sweep”

– Must be able to handle radial circuit and “weakly meshed” circuit

• Note: “Weakly meshed” means there may be a few loops

– Unlike off-line engineering tool, OLPF results are scaled to match available real-time measurements

• Substation end of feeder (breaker via DSCADA)

• Mid line measurements (recloser via feeder SCADA)

• Handful of AMI measures from strategically-placed measurements (distribution transformer, voltage at feeder extremities)


How DG is Modeled By DMS Vendors• Variations exist in the way the DMS vendors handle DG resources:

– Full regulating model• Generally the best approach fo modeling the dynamic behavior of the dg units under normal and

emergency

• PQ type (fixed real and reactive power) or PV type (fixed real power and target regulating voltage)

– Negative Load Model• Can be profiled, such as CHP (combined heating and power) units.

• Fault current contribution is not accounted for in fault-level calculations

• Cannot be the only source of power for de-energized island

– No model – DER outputs captured by SCADA in real-time• No guesswork regarding generator status and output

• May not be able to determine fault current contribution without dynamic model

• Not really suitable for outage planning and engineering analysis (study mode)

– Three phase and single phase models• some vendors cannot handle single phase DER units, others can

• Some require balanced 3 phase generator output, other models support unbalanced performance

• Conclusion:– Regulating Model (PQ or PV) is needed to properly model the effects of DG units under normal

and emergency conditions (e.g. fault contribution)

– Not all DMS vendors support the necessary facilities for handling DG

– Need to ask detailed questions; and make decisions accordingly


On-Line Power Flow Models

• Feeder electrical model

– Unbalanced 3-phase representation

– Some DMS applications (especially IVVC) require modeling from substation transformer high side to distribution service transformer

– Handle radial and weakly meshed circuits

– Modeling of distributed generating resources

• Fully regulating model

• Negative load

– Creating and maintaining the model

• Via Geographic Information System (GIS) for large systems

• Via existing engineering model or OMS

• Manually (small systems only)


On-Line Power Flow Models• Load models

– OLPF solution requires load approximation for each distribution

service transformer – Load Estimator function handles this

– Conventional approach – use load profile obtained via statistical load

survey

– “Smart” approach: Use near real time AMI data from representative

distribution transformers instead of load profile.


Viewing OLPF results• Tabular display (SNC Lavalin)


Viewing OLPF results• Graphical display (Telvent)


Viewing OLPF results• Abnormal conditions (Areva)


Fault Location• Objective: Assist field crews in pinpointing fault location

• Fault distance provided by protective relay IEDs not accurate:

– Assumes homogeneous wire size/arrangement

– Fault impedance unknown

• DMS Approach:

– “Reverse short circuit” analysis

• Obtain fault magnitude and type (A, B, C, A-B, etc) fro

relay IED

• Determine possible fault locations using DMS short

circuit analysis tool and associated feeder model

• Determine electrical distance using reactance to fault –

eliminate effects of mostly resistive fault impedance


Fault Location – DMS Reverse SCA

Approach

distribution automation –smart feeders in a smart …grouper.ieee.org/groups/td/dist/da/members...

Documents