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GE Grid Solutions

Integrating DA with AMI May Be

Challenging for Some UtilitiesJohn D. McDonald, P.E.Smart Grid Business Development Leader – North AmericaGlobal Smart Grid Strategy Group

IEEE FellowIEEE PES President (2006-2007)IEEE Division VII Director (2008-2009)IEEE-SA Board of Governors (2010-2011)IEEE Smart Grid Steering CommitteeCIGRE USNC VP, Technical Activities

IEEE Galveston Bay Section PES Joint ChapterSeptember 16, 2016

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Introduction

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IntroductionThe many benefits of distribution automation (DA) – visibility,

fault detection and isolation, energy efficiency and asset management – are creating a “second wave” of smart grid investments and integrations, following the widespread adoption of advanced metering infrastructure (AMI)

The business case for DA is better than for any other single solution in the phased steps of grid modernization

In those phased steps, typically AMI comes first, followed by DA. DA relies on AMI’s end-of-line sensors (“smart” meters) to enable its benefits

Key Requirement => The fundamental AMI system must accommodate DA functionality

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Introduction (2)

AMI choices of a few years back may not have been made with future integrations in mind

Need an industry standard that defines the architecture of communications infrastructure within the meter so it can send “last gasps” to the outage management system (OMS), voltage data to the distribution management system (DMS), and serve other functions to systems other than AMI

Some AMI systems do not lend themselves to DA integration and may require replacement or a laborious, expensive, inefficient workaround

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Introduction (3)

For utilities that have not yet embarked on an AMI implementation, looking ahead to future systems integration can avoid duplicative efforts and costly mistakes

A successful DA integration with AMI unlocks the value in both systems

The creation of a technology roadmap and adoption of these and other technologies should drive organizational change toward a more holistic approach to smart grid

De-siloing will bring efficiencies and further unlock the value in technology adoption, something regulators will increasingly demand as they scrutinize cost recovery and rate cases

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Demand Optimization

Distribution

OptimizationAsset

Optimization

Transmission Optimization

Workforce & Engineering

Design Optimization

Smart Grid Holistic Solutions

Smart Meter

&

Comms

Shared Services & applications

Interoperability Framework

Transitioning from products/systems to holistic solutions

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Data

Residential,Commercial& Industrial

Substations

Consumers

HA

N

Real-Time Communications

Backhaul

Comms

Backhaul

Comms

Smart

Grid Base

Backhaul

Comms

NMS

Smart

Router

Internet

Smart

Meter

Internet

Gateway

MDMS

Fir

ew

all

EMS OMSDMS GIS

Office

Devices

Smart

Router

Utility

Owned

Generation

& Storage

Gen &

Store

Distributed Energy Resource Manager

HA

N

Station

Controller

Other

IEDs & I/O

Volt Reg,

LTC, Caps

Apps

Local

HMI

Protection

RelaysSmart

Router

Volt/VAR

Devices

Volt Reg

& Caps

Smart

Router

Switches &

Breakers

Reclosers &

SwitchesPMU

Transformer

M&D

Mobile

Router

OFR DPA DRIVVCFDIR WAMS Hist

MobileFFA

Model

MgrAsset Services

SecurityApps

BizToolsDesign

EnterpriseOperations Bus – Software Services Infrastructure

Workforce & Engr Design

Software Services Infra

Distribution

Optimized Solutions

Transmission

Smart Meter Systems

Demand

Asset

Wired/Wireless Substation Communications

Smart Grid Technology RoadmapSmart Grid Technology Roadmap

Communications

Infrastructure

Microgrid

Controller

Generation

& Storage

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The Market and the Business Case

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The Market and the Business Case

Of the approximately 48,000 distribution substations in the US, fewer than half have any sort of automation

Of the automation installed, only half are utilizing the two way communications (i.e., operating standalone as with electromechanical devices)

Very few distribution feeders send any kind of real-time information upstream

This creates large areas of “unobservability”- we don’t know what’s happening on the system

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The Market and the Business Case (2)

Drivers to know what’s happening on the system and to support a variety of data streams from the field and route them efficiently

• As more distributed, renewable energy is integrated into the grid

• As the utility copes with two-way power flows, will face new safety and protection challenges

• As a DMS is implemented need real-time information to populate the network model to drive the software applications

• As additional two way data flows accompany dynamic pricing and the interaction of that signal with a home energy system

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The Market and the Business Case (3)

Utilities being driven to implement a DMS to manage increasing complexity of the distribution system

The DMS is only as good as the information coming from the field

Distribution automation, or distribution optimization, currently represents the most cost effective step and the best business case of all smart grid solutions

An enormous challenge – the distribution substations and feeders without automation - big operational and organizational payoffs for utilities

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First, Break Down the Walls

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First, Break Down the Walls

The holistic approach to smart grid, and grid modernization, requires strong executive leadership to break down the walls between groups

AMI implementations are under the purview of the metering group while DA is under a distribution engineering group in operations

The two systems share a need for service territory-wide communications systems

Too often, a siloed utility builds two systems, side by side, when a single, well-vetted system could be built to serve both purposes

Results => redundant efforts, duplicative expense, two separate data streams

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First, Break Down the Walls (2)

Executive leadership, sometimes aided by a third party, should bring together the metering group and the distribution engineering group to jointly determine their mutual, functional requirements for a common communications network

Cooperation leads to a stronger business case for both systems

General rule of thumb for a technology roadmap and resulting utility investments => develop them with a horizontal organizational structure that results in cost effective investments and integration friendly systems

As this becomes a more widely recognized best practice in the smart grid era regulators will come to expect this approach and may base decisions on whether it’s being implemented

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Integrating the Acronyms

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Integrating the Acronyms

Many AMI technologies are designed for meter-related data output only – the 15-minute interval readings that flow upstream to the network management system (NMS) - which manages the communication network aspect of AMI and also feeds the data to the meter data management system (MDMS)

The meter’s “last gasp” when an outage occurs isn’t metering information; that signal needs to be routed to the OMS where it can be analyzed to determine the cause and extent of an outage

Some AMI systems cannot split off that last gasp to the OMS

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Integrating the Acronyms (2)

Another distribution automation function – voltage data coming back from the end-of-line sensor (in this case the meter) – needs to be routed to the DMS to ensure the utility is achieving the 114v to 126v ANSI standard at the customer premise

This is not easily accomplished with some AMI systems

Note – do not need voltage readings from every meter, just those at strategic points at the ends of selected feeders

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Integrating the Acronyms (3)

An AMI system is the glue between the meter and the utility

Functionality in the meter needs to be matched to functionality in the supporting systems, the “infrastructure” in advanced metering infrastructure

That means the communications network, among other things

An AMI system needs a certain flexibility to integrate properly with DA functions such as routing meter’s last gasps to the OMS and steering voltage information to the DMS

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Integrating the Acronyms (4)

For utilities that have installed AMI, this emphasizes the need to evaluate the underlying systems with DA integration in mind

A utility may have had the foresight to develop a carefully thought-through roadmap and be in a good position to reap the benefits of DA

If that foresight was lacking, the consequences can be laborious and expensive => AMI data can be routed through the NMS and MDMS to reach the OMS and DMS, but that’s a cumbersome route that challenges bandwidth and latency

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Integrating the Acronyms (5)

As meters gain functionality, they may be upgraded or swapped out for more advanced ones

The utility wants to avoid ripping out and replacing the underlying infrastructure

The AMI system should have enough flexibility to support the metering information going to the NMS and MDMS, but also support other data outputs on the smart meter and be able to route that to other systems

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Vetting the DMS

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Vetting the DMS

The DMS’ network model manager interfaces with the utility’s geographic information system (GIS) and knows what data to pull from the GIS how that information is stored, and how to retrieve the needed data for building the network model

As the data in the GIS changes incremental updates inform the network model in the DMS and keep it up to date

The OMS also has a network model for outage analysis that depends on the GIS

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The Network Model

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The Network Model

The network model consists two major sets of information

• The power system connectivity information, which includes the electrical characteristics of grid assets (e.g., the model for each transformer and its connection information) and the branches and nodes or buses

• The real-time information about the network, or the operational information – the voltage, current, real and reactive power flows, statuses of switches and circuit breakers, etc.

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DA Functions, Up Close and Personal

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DA Functions, Up Close and Personal

Primary DA Functions• Improving reliability with fault detection, isolation and

restoration (FDIR) for optimal feeder reconfiguration• Reducing losses with VAR control• Managing load or demand with voltage control

Today, with DA, the utility can combine voltage and VAR control with integrated volt/VAR control (IVVC)

To support these applications, the DMS requires real-time information, knowledge of what’s happening on the distribution system downstream of the substation

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DA Functions, Up Close and Personal (2)

Assess whether an AMI system will support DA functionality

• Response requirement of each DA application in seconds (FDIR requires 2-3 second response for rapid switching; capacitor controls require 30-60 seconds)

• Bandwidth requirements of each DA application in bytes per second (IEDs many need to send megabytes of data upstream at one time)

• Latency in seconds that can be tolerated for each DA application (note that implementing additional cyber security functionality may increase latency)

Many AMI systems are designed to support only interval reads

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Smart Grid Standards Vision

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Example: Standards FrameworkNational Institute of Standards and Technology (NIST)

… Smart Grid Conceptual Reference Model

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NIST- Recognized Standards Release 1.0

Following the April 28-29 Smart Grid Interoperability workshop, NIST deemed that sufficient consensus has been achieved on 16 initial standards

On May 8, NIST announced intention to recognize these standards following 30 day comment period

NIST’s announcement recognized that some of these standards will require further development and many additional standards will be needed.

NIST will recognize additional standards as consensus is achieved

Standard Application

AMI-SEC System Security Requirements

Advanced metering infrastructure (AMI) and Smart Grid end-to-end security

ANSI C12.19/MC1219 Revenue metering information model

BACnet ANSI ASHRAE 135-2008/ISO 16484-5

Building automation

DNP3 Substation and feeder device automation

IEC 60870-6 / TASE.2 Inter-control center communications

IEC 61850 Substation automation and protection

IEC 61968/61970 Application level energy management system interfaces

IEC 62351 Parts 1-8 Information security for power system control operations

IEEE C37.118 Phasor measurement unit (PMU) communications

IEEE 1547 Physical and electrical interconnections between utility and distributed generation (DG)

IEEE 1686-2007 Security for intelligent electronic devices (IEDs)

NERC CIP 002-009 Cyber security standards for the bulk power system

NIST Special Publication (SP) 800-53, NIST SP 800-82

Cyber security standards and guidelines for federal information systems, including those for the bulk power system

Open Automated Demand Response (Open ADR)

Price responsive and direct load control

OpenHAN Home Area Network device communication, measurement, and control

ZigBee/HomePlug Smart Energy Profile

Home Area Network (HAN) Device Communications and Information Model

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Identify user requirements and gaps in standards

Accelerate standards development and harmonization for interoperability of Smart Grid devices & systems

Identify necessary testing and certification requirements

Oversee the performance of these activities & continue momentum

Inform and educate Smart Grid industry stakeholders on interoperability

Conduct outreach to establish global interoperability alignment

What Does SGIP Do?

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SGIP Activity AreasStandards – More needed than ever

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SGIPAccelerating Grid Modernization

www.sgip.org

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Lessons Learned with Smart Grid Deployments

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Smart Grid Lessons LearnedTechnology:

• Challenge: “Hype” versus “Reality”• Utility expectations were that basic SG solutions were “shovel–ready”

• Reality - Component technology was not as mature as advertised when combined to create a Smart Grid Solution

• In many cases components were field re-engineered or upgraded to meet objectives and expectations

• Challenge: Integration / Interoperability• Integrating multiple supplier products to create a SG solution

• Lesson Learned: adopt and insist on standards and open architecture methodology – drive for plug and play solutions

• Test, Test, Test• Lesson Learned: Extensive lab testing for “SG Solutions” is mandatory

prior to implementation – understand the capabilities

• Re-do’s are expensive and time consuming!

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Smart Grid Lessons LearnedImplementation & Deployment:

• Challenge: Coordinating multiple suppliers

• Managing equipment, shipments & delivery – pieces and parts along with assembly required for implementation (e.g., radio, controller, AMI network, substation equipment with software)

• Coordinating software functionality with multi-supplier hardware and AMI

• Lesson Learned: Minimize niche suppliers – prefer alliance suppliers with strong engineering and solution teams

• Challenge: Coordinating multiple internal departments

• Managing Substation and Distribution Engineering, Protection and Control, Communications and Construction

• Lesson Learned: Engage 1 Project Manager for each Smart Grid solution with multi-discipline authority

• Prefer packaged solutions from fewer suppliers – minimize the finger-pointing

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Smart Grid Lessons LearnedProject Management:

• Establish Program Management Office• Multiple Project Managers reporting to the Program Manager

• Adhere to PM guidelines such as Communication, Status Reporting, Risk Management, etc.

• Build an “A” team with project and technical members – there will be challenges to collectively solve

• Establish Corporate Steering Committee• Key status meetings with Utility Executives and Alliance Suppliers

• Escalation and Risk Mitigation in timely manner is critical

• Build Strategic Alliances with Key Suppliers• Define, Engineer and Build the Smart Grid solutions collectively

• Alliance Supplier provides “On-site” management and technical support

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Smart Grid Lessons LearnedChange Management:

• Smart Grid solutions involve multiple stakeholders (actors)• Residential / Commercial customers are now a “Major Stakeholder”

• For example: PCT’s, In-home devices, utility incentivized customer programs, 2-way communication with the Utility

• Define and develop “Use-Cases” for each component of Smart Grid• Use-Cases provide – a scenario description, defines the benefits,

actors, functional requirements, and business rules and assumptions

• Lesson Learned: Use-cases form the basis for the benefits achieved, functional requirements, development, and training

• Smart Grid actors require “Significant Training” on the operation and maintenance of the deployed system (i.e., Operations Center, Communications, Customer Call Center, Engineering, Field Crews, etc.)

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Avoiding the Abyss and Stranded Assets

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Smart Meters/AMI Integration with GIS, OMS and DMSSmart Meters/AMI• Meter Readings• Voltage => DMS• Last Gasp Communication => OMS

GIS• Network Model Information => OMS, DMS

DMS• Status Changes => OMS

Customers• Phone Calls => OMS• Social Media => OMS

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Avoiding the Abyss and Stranded Assets

The utility needs to ask hard questions of its suppliers to avoid the downside of stranded assets – making a short-sighted investment in AMI

• Is there a migration path with your supplier?• What’s on that path – board swap or box swap, or no path?• Does the supplier support relevant industry standards – what is

the migration from DNP3 (IEEE 1815) to IEC 61850?• Is the technology field proven (serial #1 or many installations of

current models)?

Thinking through your technology roadmap with a good understanding of succeeding systems’ functional requirements will lead to better results and more cost effective investments

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Thank You!