Rsrc TEL Making Substations Presentation

8/8/2019 Rsrc TEL Making Substations Presentation

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MAKING SUBSTATIONS MORE INTELLIGENT BY DESIGNA United Illuminating Case Study

2007 WESTERN POWER DELIVERY AUTOMATION CONFERENCE

Craig Preuss Black & Veatch Corporation

Bob Pellegrini United Illuminating Company


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MAKING SUBSTATIONS MORE INTELLIGENT BY DESIGN

Safety Tip for the Day

A Brief History of United Illuminating

Substation Integration

Functional Requirements

IED Selection Security

Architecture Selection

Protocol Selection Performance

Progress

Conclusion


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SAFETY TIP OF THE DAY

SAFETY TIP OF THE DAY


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A BRIEF HISTORY OF UIA BRIEF HISTORY OF UI


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A Brief History of UI

UI doesnt generate electricity

Purchases, transmits, distributes and sells itto residential, commercial and industrialcustomers

Regional distribution utility 335 square miles in Connecticut

17 towns

320,000 customers

26 Bulk Electric substations

115 and 345 kV transmission


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115

kV

115

kV

115

kV

115

kV

115

kV

115 kV

Trumbull

Substation

A Brief History of UI

Trumbull Substation

New substation

Located in Trumbull, CT

Purpose

Increased distribution system capacity Improve reliability

Two 24/32/40 MVA 115/13.8 kV LTC

transformers Three 115 kV transmission lines with ring

bus configuration

Distribution switchgear for 10 distributionfeeders


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SUBSTATION INTEGRATIONSUBSTATION INTEGRATION


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Substation Integration

What to do with a blank sheet of paper

Update to IEEE C37.1 includes substation

integration process1. Define near term and long term system

functionality (functional requirements)

2. Protocol selection (both inside and outside thesubstation)

3. IED selection

4. Architecture selection5. Secure the system

6. Define performance requirements


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Step 0 Training

Introduced UI personnel from across the enterprise

Equipment, concepts and issues, reasons, costs,

risks, benefits, and process of substation integration Who to invite?

Protection and control

SCADA

IT

Operations

Metering

Maintenance

Substation engineering, planning, technicians,engineering management


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Step 1 Functional Requirements

I/O

Analogs

Status

Control

Protection Time synchronization

Programmed logic Ancillary services


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I/O Scheme

Functional requirements were realized by creating anI/O scheme for the substation

All equipment included


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Measurements Analog

Metering Relays accurate

enough for distribution

and one transmissionline Revenue meters

already required for

transformers and twotransmission lines Other

LTC tap position (IED)

Transformer windingtemperature (IED) Transformer gas (IED) Inside temperature

(Transducer) DC battery voltage

(IED)


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Measurements Status

Hard-wired status

No RTU means distributed I/O

~ 270 hard-wired status points Breaker and switch status

SCADA enable/disable

Breaker alarms Transformer alarms

IED status (failure contact)

Security status More than traditional SCADA values

Relay targets (IED)

Communication status (IED) Breaker monitoring (IED)


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Measurements Control

Control

Original scheme

SCADA control through primary relays

Local control through backup relays

What happens when relay is not in service? Control through dedicated distributed I/O

HMI local control

Backup control switches


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Protection

Protective functions remain in relays

Interest in IEC 61850

Primary relays can support

Data concentrator can support

HMI can support Substation network can support


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Time Synchronization

Three methods to time synch in substation IRIG-B, NTP/SNTP, and DNP IEEE 1588 not implemented by IED vendors

IRIG-B design Fiber to substation yard Overloading of satellite clock drive outputs by IEDs Relays, meters, distributed I/O, substation

computer, and data concentrator NTP/SNTP

Ethernet equipment from time server on substationPC

DNP Transformer LTC controller and temperature monitor

None Transformer gas monitor, Battery monitor


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Programmed Logic

Basis for substation automation

IEC 61850

DNP report by exception to multiple masters Differentiator

Data concentrator

Distributed I/O

Supported in data concentrator but not yetimplemented


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Ancillary Services

Services left over:

IED configuration

File transfer Log and data capture

Diagnostic observation

Requires a high-speed network that supports morethan two simultaneous connections.

Performance improvements

Prioritizing these services

Limiting bandwidth usage by lower priority tasks(given that IEDs generally do not supportprioritization).


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Step 2 Protocol Selection

DNP3

Previously used between RTUs and SCADA

master

IEC 61850

Discussed Decided to support it

Too much of a paradigm shift at this point

Integration level does not decrease becausetoo many substation IEDs do not support it


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Step 3 IED Selection

Protection

Primary

UI had piloted and tested relays thatsupport Modbus, DNP, and IEC 61850

Ethernet Backup

UI had no interest in connecting to backup

relays

Keep integration simple

Lower cost backup relays


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Breaker monitor

Previous monitor did not support integration

Primary relays are used

Transformer temperature monitor

Previously used IED supports DNP but notEthernet

Serial device server

Transformer gas monitor

Previous monitor did not support integration

Another monitor selected that supports DNP Serial device server


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RTU

Existing RTU could not meet several requirements

Evaluated data concentrators and RTUs No RTUs made final cut

Hard to differentiate data concentrators

Surprising details that made the difference

No support for analog deadbands

Interpreted protocol analyzer

Support for IEC 61850

Polling support over Ethernet

NERC CIP compliance for remote access

Requires use of distributed I/O


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Distributed I/O

Ubiquitous in industrial environment.

Industrial devices have temperature, powersupply, and surge protection issues

Not many available for substation environments

Limited form factor for two of them (combinationof I/O)

No support for fiber optic Ethernet

Capability to trip and close breakers directly


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HMI

Original approach

Use SCADA master software for substation HMI Not possible due to technical limitations of system

architecture

Revised approach Evaluate competing HMI products

Substation products may be simpler but not

flexible enough to support customization Major vendor selected for HMI

Used by other utilities and vendors


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Networking Equipment

Meets IEEE 1613

Fiber optics used to improve performance and makeIEC 61850 possible

Switches, router, serial device servers from samevendor

Revenue meters

Meter already being used supports DNP3, Ethernet,and IRIG-B.

Battery chargers Charger already being used supports DNP3 and

Ethernet.

Battery monitor Not connected only hard-wired contact


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Substation Computer

Meets IEEE 1613 (mostly)

Major contribution for why SCADA mastersoftware could not be used in substation

Operating system was workable SCADA HMI RAM requirements were

greater than available for operating

system


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Step 4 Security

NERC CIP requirements are an enterprise issue

Requires an enterprise solution standardized across

substations Design system to promote NERC CIP compliance

Physical security perimeter monitored

Electronic security perimeter established at router SCADA network separated from corporate network

Critical cyber assets are locked in a cabinet

Future project to add in remote access

S A hi S l i


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Step 5 Architecture Selection

Why based upon Ethernet

Corporate WAN and SCADA WAN to

substations

Experience with relays that support Ethernet

More than SCADA data requires more thantwo serial connections

Eventual migration to IEC 61850

Application of IEEE 1615 prior to publishing asa recommended practice

St 6 P f


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Step 6 Performance

Substation hardened All Ethernet networking equipment meets IEEE

1613 except Fiber optic cables used inside and outside the

control house Exceptions

Monitor for substation converter required DC-DCconverter designed to meet IEEE C37.90 Some ports on some IEDs

Changeability

Distributed I/O is key Ease of expansion Provision for spare capacity

Ease of replacement Ease of maintenance


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PROGRESSPROGRESS

P


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Progress

September 2005

Training completed

April 2006

Conceptual design begins

February 2007 Conceptual design completed

March 2007

Control house awarded

December 2007

Project completion


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CONCLUSIONSCONCLUSIONS

Conclusions


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Conclusions

Making substations intelligent by design requires

Use of techniques being included in the newupcoming revision to IEEE C37.1

Not part of IEC 61850

Other standards/recommended practices can help

IEEE 1615

IEEE 1613

Many IED vendors do not support

Ethernet

Fiber optic ports

DNP3

IEC 61850

Selecting IEDs can be difficult


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MAKING SUBSTATIONS MORE INTELLIGENT BY DESIGN

A United Illuminating Case Study

QUESTIONS?Craig Preuss [email protected] (913)-458-7781

Documents

Rsrc TEL Making Substations Presentation