Review of Canadian Smart Grid Initiatives -...

Review of Canadian Smart Grid Initiatives

Chad AbbeyCanmetENERGY, Natural Resources CanadaJuly 1, 2009

EPRI Power Quality Applications (PQA) and Advanced Distribution Automation (ADA)

2009 Conference and Exhibition

2Copyright © Her Majesty the Queen in Right of Canada, as represented by the Minister of Natural Resources, 2009. PQA/ADA Conference & Exhibition 2009

Overview

• Overview of industry activities

• Specific Smart Grid initiatives

• DER and the Smart Grid

• Testing facilities

• Perspective from regulators

• Summary


Smart Canadian Utility Projects

Smart Grid Technology Utilities/Region

AMR/AMI BC Hydro, Ontario, Hydro-Quebec

Automatic Fault Location Hydro-Quebec

Fast Reconfiguration (e.g. S&C’s IntelliTEAM) BC Hydro, ENMAX, Burlington, Toronto Hydro

Voltage Reduction Schemes BC Hydro, Hydro-Quebec

Remote monitoring Hydro-Quebec

Planned Islanding BC Hydro, Hydro-Quebec


New New TechnologyTechnology –– KinectsKinects Feeder Feeder CurrentCurrent Monitoring (FCM)Monitoring (FCM)

• The feeder current meter primary measurement and reporting is the line current of the HV side (max, min, accumulated)

• Granular data to be consolidate into one central repository.

• Need to add analytical to improve operation and planning (optimize decision-making based on data)

Source: Leveraging Smart Meter Technology at Milton Hydro, R. Brajovic, presented at EDIST 2009 Conference, Markam, Ontario


Leveraging Smart Meter Technology Leveraging Smart Meter Technology Milton Hydro ExampleMilton Hydro Example



Comparing Smart Meter Customer Data and Comparing Smart Meter Customer Data and Distribution Transformer MeasurementsDistribution Transformer Measurements



Transformer Monthly Loading Transformer Monthly Loading using hourly interval data from each customerusing hourly interval data from each customer



New Engineering Planning Tool (needs AMI) New Engineering Planning Tool (needs AMI) Energy Profile ManagerEnergy Profile Manager

• Metered load and generator profiles •Meter demand and network demand profiles

Source: Leveraging Smart Meter Data, CYME International, St-Bruno, Quebec.


CEATI Smart Grid Working GroupCEATI Smart Grid Working Group

• Centre for Energy Advancement through Technological Innovation (CEATI) International

• Objectives– Definition of Smart Grid– Action plan for development of the Smart Grid– Identify technology gaps– Share successful strategies for implementation of

the Smart Grid• Initiated in 2008


Ontario Smart Grid ForumOntario Smart Grid Forum

• Participation– Led by IESO– Utilities, suppliers, government

• Objectives– Develop a high level vision of Ontario Smart Grid– Educate industry leaders on drivers, technologies,

and opportunities– Identify enablers and barriers

• Outputs– Report on findings and recommendations– Website:

www.theimo.com/imoweb/marketsandprograms/smart_grid.asp


Utilities Telecom Council (UTC) Canada Utilities Telecom Council (UTC) Canada request dedicated spectrumrequest dedicated spectrum

• Spearheaded by 5 Canadian utilities– Intelligent grid = Large data transfers– Rural networks requires spectrum with good

propagation• Industry Canada proposal

– Consultation process – Gazette Notice SMSE-008-08: http://www.ic.gc.ca/epic/site/smt-gst.nsf/en/sf08972e.html• 30 MHz contiguous frequency block in the 1.8 GHz band• relax the SRSP (Standard Radio System Plans) 301.7 to

accommodate point-to-multipoint topologies• Widely supported by respondents


Smart Grid and DG Drivers

• Distribution System Automation– Smart meter initiatives– Reliability– Ageing infrastructure – grid modernization

• Distributed Generation– Predominantly policy push– Secondary drivers: reliability, capacity


Distributed Generation in Canada

• Technologies– Wind, small hydro, PV, biogas

• Regions– BC – small hydro, request for proposals– Alberta – Distributed wind, biogas– Manitoba – Distributed wind– Ontario – Green Energy Act– Québec – small hydro, wind, programs coming


Example - Impact of SOP

West of Toronto (2005)Location of Transformer Stations TS +

Source: M.Dang, Hydro One, March 25, 2008


Example - Impact of SOP

West of Toronto (2007)

Source: M.Dang, Hydro One, March 25, 2008

Orangeville

Goderich


Issues and Barriers

• Drivers don’t encourage coordination between DG and smart grid technologies

• Smart applications and DG compatibility• DA is not necessary implemented where DG is

interconnected• Standards and application guides needed that foster

integration of DG as opposed to simply connection (in progress)


NRCan DG Study Group

• Membership– Utilities: BC Hydro, Hydro Quebec, NB Power– Manufacturers: GE Multilink, SEL– Private producers

• Activities– Review of utility interconnection guidelines (Hydro

One)– Provide advice on cost effective DG interconnection

technology– Linking Smart Grid with DG

• Remote monitoring and control, advanced protection


Canadian Test Facilities

Low voltage test facility (CanmetENERGY):– Multiple inverters and interconnection testing

ØMedium voltage test facility (IREQ-HQ):– Distribution automation network testing

• A radial 25-kV feeder (20 poles, 370m)

• 300-kW, 600 V, resistive, inductive and motor loads

• Induction and synchronous generators

• 120-kVA, 3ph Grid simulator

• 5kW/15kW Solar Simulator• Adjustable RLC loads


IREQ Voltage Regulator Testing

• In-line VR control modes• Real and reactive power flow• DG location

Substation125/25 kV

25/0.6 kV

DG1

VR

25/0.6 kV

X2

RL Load0 - 200 kW

Synchronous Generator0 - 200 kW

X1

2 3

1


Canadian Association of Members of Public Utility Tribunals (CAMPUT)

• CAMPUT purposes: – to improve public utility regulation in Canada; and

improve education of commissioners and staff of public utility tribunals

• Provinces at various stages– Automated meter reading (AMR) and Automated

meter infrastructure (AMI) – Distribution automation – Link to improving integration of renewable energy

through legislation (eg. Green energy act, Ontario).• Increasing interest in CAN-USA regulators working

together– US FERC-NARUC established a collaborative on

Smart Grid


Survey of Regulators (NARUC and CAMPUT)

• Background: – Regulators are guided by legislation– Utilities are guided by regulations

• Survey conducted by Capgemini between Sept.-Nov. 2008

• Results show that regulators are at the very early stages of an education and valuation process.

• When under legislative and or regulatory mandated renewable targets – then smart grid investments had more appeal if direct links can be made (eg. portfolio standards)

• “Goalpost” keeps moving from AMR to AMI to Smart Grid


Ontario – Encouraging Smart Grid and Renewables

• Smart Grid Forum releases its finding – February 2009• Green Energy Act created – feed-in tariffs for renewables

– May 14, 2009• Ontario Energy Board (OEB) - draft guidelines on

planning for smart grid architecture - June 16, 2009• Important elements:

– Creation of new deferral accounts for capital investments incurred related to the development of a smart grid or the accommodation of new renewables.

– Introduction of a mechanism to provide advance funding for expenditures to accommodate new renewables or develop a smart grid.

– Initial guidance to distributors on planning to accommodate new renewables and a smart grid.


Summary

• Canada’s existing electricity infrastructure was designed prior to advances of the information age.

• The “smart grid” includes improvement in metering, monitoring and control technologies

• Smart Grid is needed for future operation and management of electricity networks and for the integration of renewable and distributed energy.

• Coordinated research and demonstration projects required to support the transition towards a smarter grid

• Shared knowledge and progress reported


1615, Lionel-Boulet, Varennes, Québec, Canada

Smart Grid contact: David BeauvaisEmail: [email protected]

Tel. +1 450-652-5995Website: http://canmetenergy.nrcan.gc.ca

Questions?

Future of Fault Location and

Data Integration

Cristiana Dimitriu & George BaroudiCon EdisonJuly 1, 2009

EPRI Power Quality Applications (PQA) and Advanced Distribution Automation (ADA)

2009 Conference and Exhibition

2 Copyright © 2009 Electric Power Research Institute, Inc. All rights reserved. PQA/ADA Conference & Exhibition 2009

Future of Fault Location and Data Integration

• Reactance-to-Fault Overview

• Relay Data Integration

• Other SCADA Data Integration

• Looking Forward



27,13, 4 kV

13 kV

27, 4 kV

33,13, 4 kV

Con Edison Company of NYNYC and Westchester3.2 million electric customersSystem peak load 13,141 MW



• Beginning in the early 90’s, power quality monitors (PQ Nodes) were placed in secondary networks to monitor voltage.

• Monitors and software were developed by EPRI and co- funded by Con Edison to measure power quality.

• The high-definition data was also useful in analysis of system events, and PQNodes were placed in substations to capture additional data.

Power Quality History



PQView

PQTR #1 TR #2 TR #3 TR #4 TR #5



Regions Networks Substations

Manhattan 37 26

Brooklyn 12 7

Queens 6 5

Bronx 6 6

Westchester 3 12

Staten Island 2 5

Total 66 61

PQ Monitors Coverage



• In 2005, engineers from Distribution Engineering, Power Quality and R&D envisioned a further use of the stream of high- definition data

• Working with Electrotek engineers, they developed computer algorithms and graphical interfaces to locate faults on network feeders

• This is the Reactance-To-Fault (RTF) system

• First applied in Manhattan, where it reduced fault locating time during the first summer (2006) by more than one hour, it is now used by all operating regions in Con Edison.

RTF History



A-Ph

Va Bus Voltage Sags on faulted phase

In = 8kA

Total CurrentIn = 4x2 = 8kA

In = 2kATR Bus Current

In = 2kA

In = 2kA

In = 2kA



Feeder trips

RTFmatches

reactance to feeder

model

PQNode captures

amps/voltsat S/S bus

PQView software

calculates reactance

Display asmap andtabulation

Display on VDIS

Present RTF Application



Present RTF Application



Visual Distribution Information System (VDIS)



Working Progress and Future Enhancements

PQTR #1 TR #2 TR #3 TR #4 TR #5

PQ PQ

• Expand substation monitoring capabilities



Relay / Comtrade Data

• Microprocessor Relay Data:- Feeders- Cap Banks- Bus Sections- Power Transformers- Light & Power

• Recent Development- All Relays Targets and Pickups (Digital Channels) are now stored in PQView, along with fault waveforms and RMS data.

• Analog relay data (channels) provide info for:Fault Locating (RTF), Inrush, and Sub-Cycle events.



Relay / Comtrade Data• Relay Types:

- GE F60 - 32 samples/cycle- Schweitzer SEL 351 - 4 samples/cycle- Bassler (1 substation) - 24 samples/cycle

• 10 Substations equipped with Microprocessor Relays (New, Retrofit)

• Relay Data Integration issues:

- Date format in *.cfg file not per IEEE 1159 Standard and Comtrade version not consistent (1997 vs. 1999)

- Data not being saved to folder with correct Date Modified

- Microprocessor Relays not equipped with voltage input

- Microprocessor Relays not equipped with LAN Lines



1C

-15000

-10000

-5000

0

5000

10000

15000

-20000

-10000

0

10000

20000

0.50 0.52 0.54 0.56 0.58 0.60 0.62

Murray Hill 12M77 - 9/10/2008 08:07:15.6374

Vol

tage

(V)

Cur

rent

(A)

Time (s)

Va Vb Vc Ia Ib Ic Ires

Feeder Fault – GE F60 Relay Targets

C-Phase Fault



Feeder Fault Digital Relay Targets/Pick-up

C-Phase Fault

C-phase Instantaneous-Over-Current Op



PHASE IOC1 OP C On PHASE IOC1 OP C Off

-15000

-10000

-5000

0

5000

10000

15000

-20000

-10000

0

10000

20000

0.50 0.55 0.60 0.65 0.70

Murray Hill 12M77 - 9/10/2008 08:07:15.6374

Q

Digital ChannelOsc Trig OnPHASE IOC1 OP CPHASE TOC1 PKP CGROUND TOC1 PKPTrip On

Vol

tage

(V)

Cur

rent

(A)

Time (s)


Feeder Fault – GE F60 Relay Targets



Feeder Fault – GE F60 - Reactance Calculation

1C 0.05351 (k1=3.800)

5000

10000

0

5000

10000

15000

0.0

0.5

1.0

0.50 0.52 0.54 0.56 0.58 0.60 0.62 0.64

Murray Hill 12M77 - 9/10/2008 08:07:15.6374Reactance to Fault

Vol

tage

(V)

Cur

rent

(A)

Rea

ctan

ce (O

)

Time

Va Vb Vc Vab Vbc Vca Ia

Ib Ic Iab Ibc Ica Ires XTF

C-Phase Fault



Feeder Fault – SEL (Schweitzer) – Relay Targets & Reactance Calculation

1B|Rs0=0.1246|Xs0=0.42370.3906 (k1=1)

4000

6000

8000

0

2000

4000

6000

1

2

2 4 6 8 10 12 14

White Plains 8W70 SEL - 5/21/2009 10:13:23.7138Reactance to Fault

Vol

tage

(V)

Cur

rent

(A)

Rea

ctan

ce (O

)

Time (c)

Va Vb Vc Vab Vbc Vca Ia

Ib Ic Iab Ibc Ica XTF

OUT1 On50B1 On 50B1 Off50B On 50B Off51P On 51P Off51PR Off51N On 51N Off51NR Off 50P1 On 50P1 Off67P1 On 67P1 Off67P1T On 67P1T Off50QF On 50QF Off50QR On 50QR Off50GF On 50GF Off50GR On 50GR Off50L OffSV1 On SV1 OffFSB On FSB Off52A Off3PO OnTRIP On IN1 Off

-5000

-0

5000

-5000

0

5000

0 2 4 6 8 10 12 14

White Plains 8W70 SEL - 5/21/2009 10:13:23.7138Duration: 4.500c

Digital ChannelOUT150B150B51P51PR51N51NR50P167P167P1T50QF50QR50GF50GR50LSV1FSB52A3POTRIPIN1

Vol

tage

(V)

Cur

rent

(A)

Time (c)

Va Vb Vc Ia Ib Ic

Relay Targets

RTF Calculation



Feeder Fault – GE & SEL - Reactance Calculation

GE RTF = 0.07 ohms

SEL RTF = 0.069 ohms

1B 0.07027 (k1=14.90)

6000

7000

8000

0

2500

5000

7500

0.2

0.4

0.76 0.78 0.80 0.82 0.84 0.86 0.88 0.90 0.92

White Plains 8W70 - 5/21/2009 10:13:22.9982Reactance to Fault

Vol

tage

(V)

Cur

rent

(A)

Rea

ctan

ce (O

)

Time

Va Vb Vc Ia Ib Ic XTF

1B 0.06934 (k1=14.90)

4000

5000

6000

0

2000

4000

6000

0.1

0.2

0.3

0.4

0.05 0.10 0.15 0.20 0.25


Vol

tage

(V)

Cur

rent

(A)

Rea

ctan

ce (O

)

Time


GE

SEL


1B|Rs0=0.1246|Xs0=0.42370.06934 (k1=14.90)

4000

5000

6000

0

2000

4000

6000

0.1

0.2

0.3

0.4

2 4 6 8 10 12 14


Vol

tage

(V)

Cur

rent

(A)

Rea

ctan

ce (O

)

Time (c)



Feeder Fault – GE & SEL - Reactance Calculation

K1 = 14.9

SEL RTF = 0.0703 ohms

GE RTF = 0.0693 ohms

PQNode RTF = 0.1898 ohms

Actual Fault = 0.24 ohms

1B|Rs0=0.1284|Xs0=0.42070.07027 (k1=14.90)

6000

7000

8000

0

2500

5000

7500

0.2

0.4

35 40 45 50 55 60 65

White Plains 8W70 - 5/21/2009 10:13:22.9982Reactance to Fault

Vol

tage

(V)

Cur

rent

(A)

Rea

ctan

ce (O

)

Time (c)




-15000

-10000

-5000

0

5000

10000

15000

-50000

0

50000

0.66 0.68 0.70 0.72 0.74 0.76 0.78

White Plains Cap_1 - 6/11/2008 05:23:44.6172

Vol

tage

(V)

Cur

rent

(A)

Time (s)


CAP Bank Fault – GE F60



1B 0.03507 (k1=1)

2500

5000

7500

0

20000

40000

0.0

0.5

1.0

0.65 0.70 0.75 0.80 0.85 0.90

White Plains Cap_1 - 6/11/2008 05:23:44.6172Reactance to Fault

Vol

tage

(V)

Cur

rent

(A)

Rea

ctan

ce (O

)

Time

Va Vb Vc Ia Ib Ic Ires XTF

CAP Bank Fault – GE F60 Reactance Calculation



PHASE IOC1 OP B On PHASE IOC1 OP B Off

-15000

-10000

-5000

0

5000

10000

-50000

0

50000

0.68 0.70 0.72 0.74 0.76

White Plains Cap_1 - 6/11/2008 05:23:44.6172

Digital ChannelOsc Trig OnPHASE IOC1 OP APHASE IOC1 OP BPHASE IOC1 OP CPHASE TOC1 PKP APHASE TOC1 PKP BPHASE TOC1 PKP CTrip OnTRIP IOnCB Status On

Vol

tage

(V)

Cur

rent

(A)

Time (s)


CAP Bank Fault – GE F60 - Relay Targets

Relay Targets



XFMR PCNT DIFF 2ND A OnXFMR PCNT DIFF 2ND A Off XFMR PCNT DIFF 2ND A OnXFMR PCNT DIFF 2ND A Off-20000

-15000

-10000

-5000

0

5000

10000

15000

0.55 0.60 0.65

WPlains Tr1 87-50 - 6/11/2008 05:23:44.7204

Digital ChannelTrig Osc OnXFMR PCNT DIFF 2ND AXFMR PCNT DIFF 2ND BXFMR PCNT DIFF 2ND C C

urre

nt (A

)

Time (s)

Ia Ib Ic Ires

CAP Bank Fault - Transformer 1 – GE T60 Relay Pickup – 3 Phases



GROUND TOC1 PKP OnGROUND TOC1 PKP Off

-15000

-10000

-5000

0

5000

10000

-1000

0

1000

2000

1.16 1.18 1.20 1.22 1.24 1.26

WPlains Tr1_ 51V-51N - 6/11/2008 05:23:44.1219

Digital ChannelPHASE TOC1 PKP AGROUND TOC1 PKPTrig Osc OnPHASE UV1 OP APHASE UV1 OP BPHASE UV1 OP C

Vol

tage

(V)

Cur

rent

(A)

Time (s)


CAP Bank Fault - Transformer 1 – GE F60 Relay Pickup

Phase, Gnd TOC, Phase Undervoltage



-12000

-10000

-8000

-6000

-4000

-2000

0

2000

4000

6000

8000

10000

0.04 0.05 0.06 0.07 0.08 0.09 0.10 0.11 0.12

North Queens 1Q08 - 9/1/2008 23:23:09.5140

Cur

rent

(A)

Time (s)

Ia Ib Ic In Ires

Feeder Fault – Bassler Relay NO VOLTAGE Available at Station, No Reactance calculation



Feeder Fault – Bassler Relay - Relay Targets

• Relay digital channels (targets, and pick-up) are named differently in SEL, GE F60, this may create confusion.

• Relay digital channels (targets, pick-up) will display the type of relay that operated/picked-up but not the faulted phase.

50TPT On 50TPT Off-12000

-10000

-8000

-6000

-4000

-2000

0

2000

4000

6000

8000

10000

0.04 0.06 0.08 0.10

North Queens 1Q08 - 9/1/2008 23:23:09.5140

Digital Channel51NTTRIP150TPT150TPPU51PPUVO12_LABELINPUT_150TPT150TNT50TPPU150TNPU51NPUVO11_LABEL

Cur

rent

(A)

Time (s)

Ia Ib Ic In Ires

Relay Targets



Bassler Relay - How to Identify Faulted Phase?

• Relay Target Phases are available in a log file (txt) generated by the Bassler Relay.

• The log (txt) file should be integrated in PQView to automatically identify the faulted phase, and send a notification (Future Development).



Fault CIOA

PHASE IOC1 OP C OnPHASE IOC1 OP C OffPHASE TOC1 PKP A On PHASE TOC1 PKP A OffPHASE TOC1 PKP C OnGROUND TOC1 PKP OnTrip On OnTRIP IOn On TRIP IOn OffGROUND IOC1 PKP OnGROUND IOC1 OP OnPHASE IOC1 PKP C OnPHASE IOC1 PKP C OffPHASE IOC1 OP OnPHASE IOC1 OP OffPHASE TOC1 PKP On GROUND TOC1 DPO Off PHASE IOC1 PKP OnPHASE IOC1 PKP OffPHASE IOC1 DPO OffPHASE IOC1 DPO OnGROUND IOC1 DPO OffTrip IOff Off Trip IOff On

-2

-1

0

1

2

-15000

-10000

-5000

0

5000

10000

0.18 0.20 0.22 0.24 0.26

Seaport#1 40M43 (43A) - 1/4/2009 12:00:58.1925

Electrotek/EPRI PQView®

Digital ChannelPHASE IOC1 OP CPHASE TOC1 PKP APHASE TOC1 PKP CGROUND TOC1 PKPTrip OnTRIP IOnGROUND IOC1 PKPGROUND IOC1 OPPHASE IOC1 PKP CPHASE IOC1 OPPHASE TOC1 PKPGROUND TOC1 DPOPHASE IOC1 PKPPHASE IOC1 DPOGROUND IOC1 DPOTrip IOff

Vol

tage

(V)

Cur

rent

(A)

Time (s)

Va Vb Vc Ia Ib Ic



Inrush (Feeder Restoration)



Subcycle

Subcycle Event Feeder 8W64 - GE F60 Relay



Relay RTF Website - Development



Relay data RTF = 0.1747



Substation PQ Monitor data RTF = 0.1661



Working Progress and Future Enhancements

• Enhance Web PQView to allow intranet viewing of Digital Channels.

• Define and understand the functions of all the Relay Targets available especially for XFRs, and Bus Sections. Also standardize the Relay Naming convention between the Bassler, SEL, and GE F60.

• Integrate relay data (Analog, Digital Channels) into Visual Distribution, and other applications (FMS).

• Extend RTF application to the overhead distribution system

• Integrate SCADA from unit substations

• Integrate data from AMI’s

Relay Targets



Working Progress and Future Enhancements Multiple-feeder Outage



Thank you!

Questions?

Integrated Analysis of Power System Disturbances

Fred Elmendorf, Theo Laughner TVA

Mark McGranaghan, Chris Melhorn, Zhiming Dai, Paul MyrdaEPRI

2© 2009 Electric Power Research Institute, Inc. All rights reserved.

AKA - How to prepare for the impending Data Tsunami

http://www.bionomicfuel.com/wp-content/uploads/2008/10/energy-produced-by-tidal-waves_2.jpg


Background – PQ Monitoring Systems

Traditional Uses• Benchmarking

• Standards Compliance

• Consumer Issue Resolution

• Standalone

Potential Uses• Health Assessments

• Performance Analysis

• Fault Detection

• Integrated Information System

Requirements


Outline

• Concept of an Integrated Power Monitoring System• Applications• Integration Requirements• Important Concepts for System Events• Examples of System Event Analysis


Wide range of applications that can take advantage of integrated data• Fault analysis - fault location, fault cause identification, trends of

fault conditions indicating problems.• Incipient faults associated with arresters, cracked insulators,

cable splices, etc.• Evaluation of breaker and relay performance – timing, pole

spans, coordination, evaluation of fault duties, maintenance requirements.

• Capacitor application evaluations – identification of switching problems, can failure identification, harmonic resonance problems, restrikes, performance of synchronous closing control.

• Transformer assessments – loading evaluations, harmonic duty, fault duty, identification of possible problems from harmonics and unbalances.

• Tap changer and voltage regulator assessments – identification of problems from disturbance waveforms (see Figure 3), unbalanced conditions, voltage regulation assessments.

• Distributed generation applications – evaluation of performance with respect to interconnection requirements (e.g. wind farms).


Applications that can help improve reliability and security of the system


IED’s, DFRs, SERs, PMU’s, Remote video, Line monitors, smart sensors, Intelligent grid devices: switches, reclosers, cap controllers, etc., Cable monitors, Weather data, BPL as sensor, Meter as sensor

Grid Data Sources

Grid Data Sources

Data Communication

Data Integration

Analytics

Information

Smart Grid Monitoring System – Grid Data Sources

• Characterizing the grid in real time and for post event analysis is dependant upon a network of sensors, meters and devices providing data on regular basis.

LAN

SensorsDigital Relays

Automated Substations

Security

Equipment Monitoring

D A T A

D A T A

D A T A

D A T A

D A T A

D A T A

http://www.success-hk.com/welcome/security/bigimages/wooju_C103_Lq1i7.jpg


Smart Grid Monitoring System – Data Communication

• Open Standards based Digital Communication Networks allow devices to communicate securely with the Enterprise

Grid Data Sources

Data Communication

Data Communication

Data Integration

Analytics

Information

LAN



Security


D A T A

D A T A

D A T A

D A T A

D A T A

D A T A

Utility Applications

D A T A

•Extensive array of options available •Public and private digital networks•Wired, wireless, and optical



Pub/SubMiddleware

External Applications

CIM Based Analytics Data Warehouse

P

P

P

1

1

PP

P

P

P

P

Business UnitsBusiness Unit ID

Transmission LinesTransmission Line ID

SubstationsSubstation ID

Business Unit ID (FK)Central Station ID (FK)

Substation to Transmission LinesSubstation ID (FK)Transmission Line ID (FK)Segment ID (FK)

Central StationsCentral Station ID

Power TransformersPower Transformer ID

Substation ID (FK)

Hydran UnitsHydran Unit ID

Power Transformer ID (FK)

IEDsIED ID

Substation ID (FK)IED Type (FK)

Circuit BreakersCircuit Breaker ID

SensorsSensor ID

Sensor Type (FK)Substation ID (FK)IED ID (FK)Hydran Unit ID (FK)Weather Station ID (FK)

Sensor TypesSensor Type

Sensor Type DescriptionUOM (FK)

Weather StationsWeather Station ID

Substation ID (FK)

Sensor ReadingsSensor ID (FK)Timestamp

Sensor Reading Value

Units of UOM

Transmission Line SegmentTransmission Line ID (FK)Segment ID

IED TypesIED Type

IEDs to Circuit BreakersIED ID (FK)Circuit Breaker ID (FK)

Results in• Enterprise wide

information model• Assets defined one

time in the Network• Connect all types of

meta data with asset• No information silos

Smart Grid Monitoring System – Data Integration

• Utility Common Information Model (CIM) Analytics data warehouse• Integration Middleware allows data flow to Analytics Data Warehouse

Grid Data Sources

Data Communication

Data IntegrationData Integration

Analytics

Information

LAN



Security





Smart Grid Monitoring System – Analytics

Grid Data Sources

Data Communication

Data Integration

AnalyticsAnalytics

Information

• Analytics are dependant upon access to data• Higher levels of analytics require more access to data

Analytics Levels of Complexity1. Real time alarms, thresholds -

screen display, message, pager 2. Calculated metrics, trends -

tailored notifications3. Analysis of data, events

diagnostics, both real time and post event, data mining

4. Advanced optimizations, modeling, planning, decision supportPub/Sub

Middleware




P

P

P

1

1

PP

P

P

P

P








Substation ID (FK)



IEDsIED ID



SensorsSensor ID





Substation ID (FK)



Units of MeasureUOM


IED TypesIED Type



P

P

P

1

1

PP

P

P

P

P








Substation ID (FK)



IEDsIED ID



SensorsSensor ID





Substation ID (FK)



Units of MeasureUOM


IED TypesIED Type


LAN



Security


LAN


Automated Substations LAN



SecuritySecurity

Equipment MonitoringEquipment Monitoring



Analytics Engine


Information

Smart Grid Monitoring System – Information

• Analytics generate actionable information • Analytics depend greatly upon observable level of

information and integration with other applications

Analytics support management of:

–Asset Lifecycle–Operations–Workforce–Planning –Customer

Cos

ts

Rel

iabi

lity

Ris

ks

Rev

enue

Grid Data Sources

Data Communication

Data Integration

Analytics

InformationInformation

Portal/Dashboards

OperationsMaintenanceFinancePlanningEngineering Customers

Informed Decision Making


Business Intelligence…Presented on Dashboards


System Event Concepts

• Requirements for coordinating system events– Information sources (coordinated data collection)– Time synchronization requirements– Data management requirements (common information model,

terminology)• Other integration requirements for analysis of system events

– Models (e.g. for fault location)– Model synchronization– SCADA/EMS/DMS – system operations, conditions– Asset databases– Customer Information Systems, Outage Management System– Other information systems (lightning, weather, traffic, etc.)


15

Event Count: 20Event Count ITIC Lower Curve: 9

0.0

0.5

1.0

1.5

2.0

10 -3 10 -2 10 -1 10 0 10 1 10 2 10 3

Total Bank Covington, from 05/01/2005 to 02/01/2009

EPRI/Electrotek PQView®

Vol

tage

Mag

nitu

de (p

u)

Duration (s)

The 26‐month study looks at 20 events with 9 events creating

voltage sags below 70% of nominal (VL‐GND).

More

importantly, there were 9 events where the VLL went below

70% of nominal at the 161‐kV bus.

These events (maybe all)

likely caused ASDs

(AC and/or DC) to shut down at industrial

locations. Customers likely called to complain.

Time Stamp

Worse VLL

Phase

VLL Magnitude

(pu)

Worse VLN

Phase

VLN Magnitude

(pu)Duration

(s)Duration

(cyc)10/17/2005 08:29:12.345 BC 0.884 B 0.778 0.075 4.511/15/2005 14:49:05.949 AB 0.687 B 0.725 0.075 4.511/15/2005 15:36:55.644 AB 0.828 A 0.780 0.042 2.512/31/2005 12:30:22.075 AB 0.655 B 0.763 0.158 9.502/21/2006 22:14:50.812 CA 0.744 C 0.651 0.050 3.003/13/2006 08:06:41.983 BC 0.847 B 0.797 0.033 2.004/02/2006 19:04:25.703 CA 0.693 A 0.773 0.042 2.504/02/2006 19:25:10.958 CA 0.683 C 0.646 0.058 3.504/02/2006 19:53:36.781 AB 0.696 A 0.744 0.042 2.504/02/2006 20:09:18.270 BC 0.648 B 0.715 0.042 2.504/07/2006 23:22:20.287 AB 0.814 B 0.780 0.042 2.504/12/2006 05:46:07.110 CA 0.791 C 0.562 0.067 4.004/15/2006 13:00:56.328 CA 0.832 C 0.639 0.083 5.005/21/2006 06:08:59.822 AB 0.676 A 0.511 0.092 5.508/20/2006 20:57:38.316 AB 0.787 A 0.559 0.075 4.510/01/2006 16:27:11.156 BC 0.663 B 0.697 0.083 5.007/09/2008 23:30:25.620 CA 0.812 C 0.582 0.058 3.508/15/2008 14:46:54.137 BC 0.619 B 0.709 0.092 5.510/07/2008 04:52:32.886 AB 0.707 B 0.599 0.042 2.511/06/2008 18:04:57.871 BC 0.816 C 0.770 0.042 2.5

Examples of System Event Data and Analysis

70%

Yellow – VL‐Gnd

<70%, VLL > 70% of

Nominal, Red – VLL < 70% of Nominal

ITIC – VL‐GND Only


From SE

Outside TVA in Yellow

From West –

Northern Route

From West –

Southern Route

From North East – Northern Route

From North East – Southern Route

500-kV

System


-150

-100

-50

0

50

100

150

0.00 0.05 0.10 0.15

g

% o

f N

om

inal V

oltage

Time ( s)

-150

-100

-50

0

50

100

150

100 150 200 250

y

Perc

ent

of

Nom

inal V

AB

Time (ms)

82% 68.7%

Time Stamp

Worse VLL

Phase

VLL Magnitude

(pu)Duration

(s)Duration

(cyc)

11/15/2005 14:49:06.000 AB 0.687 0.075 4.5

Simulated Fault

Actual DFR Shot

and

PQ Monitor Shot

DFR

Currents


18

-150

-100

-50

0

50

100

150

0.00 0.05 0.10 0.15 0.20 0.25

PE

RC

EN

T O

F N

OM

INA

L V

AB

TIME (MS)

65.5% ‐

Min.

-150

-100

-50

0

50

100

150

250 300 350 400 450 500

VAB JOHNSONVILLE DFR (FAULT LOCATION)

PE

RC

EN

T O

F N

OM

INA

L V

AB

Time (ms)

5% ‐

Min.

-150

-100

-50

0

50

100

150

250 300 350 400 450 500

PE

RC

EN

T O

F N

OM

INA

L V

AB

Time (ms)

35% ‐

Min.

-150

-100

-50

0

50

100

150

100 200 300

V S 6

PE

RC

EN

T O

F N

OM

INA

L V

AB

Time (ms)

65% ‐

Min.

-150

-100

-50

0

50

100

150

200 250 300 350 400 450

PE

RC

EN

T O

F N

OM

INA

L V

AB

Time (ms)

25% ‐

Min.

-150

-100

-50

0

50

100

150

200 250 300 350 400 450

PE

RC

EN

T O

F N

OM

INA

L V

AB

Time (ms)

50% ‐

Min.

Ph‐Ph

Arcing Fault

-150

-100

-50

0

50

100

150

100 150 200 250 300 350

PE

RC

EN

T O

F N

OM

INA

L V

AB

Time (ms)

68% ‐

Min.

500‐kV Network

In Blue

All Data Actual DFR and PQ VAB Waveforms From Event

19

Fault on 500-kV System – ArkansasTime Stamp Worse VLL Phase VLL Magnitude (pu) Duration (s) Duration (cyc)

04/02/2006 19:04:25.703 CA 0.693 0.042 2.5

High Winds/Tornado

Impact 500‐kV

System in Arkansas


-150

-100

-50

0

50

100

150

100 150 200 250 300

Per

cent

of N

omin

al V

CA

Time (ms)

67.7%

-150

-100

-50

0

50

100

150

0.00 0.02 0.04 0.06 0.08 0.10 0.12

PE

RC

EN

T O

F N

OM

INA

L V

CA

Time ( s)

69.3%

Case #6 ‐

Fault at 19:04 on April 2, 2006

Occurred Off TVA System ‐

Probably on 500‐kV System in

Yellow Block Area Located in Arkansas


21

500‐kV Ph‐Ph‐Gnd

Fault on Weakley Lagoon Creek 500‐kV Line

Towers Down and Line Locked Open ‐

Both 500‐kV Paths From

Johnsonville 500 to Memphis Area Out of Service

20.6%

Tornado Path

-150

-100

-50

0

50

100

150

0.00 0.02 0.04 0.06 0.08 0.10 0.12

PE

RC

EN

T O

F N

OM

INA

L V

BC

Time ( s)

VBC

-150

-100

-50

0

50

100

150

100 150 200 250 300

PE

RC

EN

T O

F N

OM

INA

L V

BC

Time (ms)

64.8%

62.0%


DFR:

Fault Occurred: 19:28:42.876 CDT

Duration: 23 cycles

Bus Voltage: Dipped to 60% of Nominal


PMU

500 kV Bus Voltages

70% Nominal

Took about 7 seconds for the

voltage to recover back to

nominal value


25

LSC Sites Sagging Below

70% of Nominal Voltage

Ground

Switch

Event

Three Phase Fault

30% of Nom. For 3

Cycles

4


Web-Based Application Integration


Substation A

Substation B

Fault Location

Str

14

Line L5934


In Summary…What is Key about this Project?

• Taking advantage of sensors throughout the system• Many applications can use advanced monitoring

information (PQ, waveforms)• Integration is required for the functionality of these

applications• System event concept requires synchronization of data

and common terminology• Effective utilization of Industry Standards

– IEC 61850 in substations– Common Information Model for Enterprise Integration

• Web-Based Services to make applications available to wide range of users with simple interfaces


…wax your digital surf board and get ready for a wild ride!

www.savvyminds.com/SamplesSubpages/Tsunami.htm

http://www.savvyminds.com/SamplesSubpages/Tsunami.htm


Questions?

Review of Canadian Smart Grid Initiatives -...

Documents

Transcript of Review of Canadian Smart Grid Initiatives -...