Grid Modernization Distribution System Concept of · PDF fileEnhanced Monitoring 4 Real Time Situational Awareness 5 ... distribution grid infrastructure that supports high levels

Grid Modernization Distribution System Concept

of Operations Version 1.0

January 17, 2016

- i -

Acknowledgment and Disclaimer Statement

This technical report was prepared by Southern California Edison Company (SCE) and is based on a project

undertaken by SCE to address ways of modernizing SCE’s grid to meet emerging needs, including those associated

with the use of distributed energy resources (hereafter, the “Project”). SCE acknowledges the contributions of a

team of individuals as participants in this Project, including:

Employees of the SCE Advanced Technology group

Employees of the SCE Transmission & Distribution Planning group

Employees of the SCE Information Technology group

This Project was undertaken using reasonable care and in accordance with professional standards. However,

neither SCE nor any individual or entity involved with this Project is making any warranty or representation,

expressed or implied, with regard to this report, the merchantability or fitness for a particular purpose of the

results described herein, or any analyses, information, or conclusions contained in this report. The results

reflected in this report are generally representative of the operating conditions on SCE’s electric grid; however,

the results in any other situation may vary depending upon particular operating conditions.

This report is copyrighted by SCE. SCE hereby grants other electric utilities, and those advising or regulating such

entities, with a limited license right to review this report, make limited copies related to such review, and use the

report to evaluate whether the approach used by SCE, as described herein, is likely to be useful to them in the

performance of their own independent grid assessment. SCE does not, however, accept any liability for any use

of this report or information contained in this report. Other uses of this report require permission from SCE.

© 2016 Southern California Edison Company

- ii - © 2016 Southern California Edison Company Neither SCE nor any individual or entity involved with this Project is making any warranty or representation, expressed or implied, with regard to this report. See full disclaimer statement on page i.

Table of Contents

Introduction 1

Current State of the Distribution System 1

Concepts of the new Distribution System 3

New Distribution System Capabilities 4

Enhanced Monitoring 4

Real Time Situational Awareness 5

Power Quality (PQ) Awareness 5

Distribution Load Flow Analysis 5

Automation of Circuit Reconfiguration 5

Accurate Impedance Modeling 5

Prediction 6

Asset Pairing & Modeling 6

Near-Term DER Forecasting 6

Long Term DER forecasting (DER Dependability) 6

DRP to leverage DERs for Grid Benefit 7

Fast DER Interconnection Process 7

Control 7

Voltage Optimization 7

Power Flow Optimization 7

Highly Reconfigurable Protection 7

Bi-Directional Protection 8

Remote communication with relays 8

Advanced Automation 8

Desired Grid Applications 9

Field Area Network (FAN): Faster Wireless Communication (monitor, control) 9

Automatic Phase Identification (monitor, predict) 9

DER Forecasting/ Management system (monitor, predict, control) 9

Detailed Impedance Models (monitor, predict) 10

Distributed Intelligence (monitor, control) 10

Advanced Metering Infrastructure (monitor, control) 10

Power Quality Monitoring (monitor, predict, control) 10

DER Telemetry (monitor, control) 10

Remote Line Monitoring / Remote Circuit Telemetry (monitor) 11

Geographical weather data subscription (predict) 11

Distribution Management System State Estimator (monitor, predict, control) 11

Beyond the Meter (Wi-Fi Gateways) (monitor, control) 11

Distributed Generation/DER Interconnection Tool (monitor, predict) 11

Ramp Rate Management of DERs (control) 11

-iii- © 2016 Southern California Edison Company Neither SCE nor any individual or entity involved with this Project is making any warranty or representation, expressed or implied, with regard to this report. See full disclaimer statement on page i.

Remote Fault Detection and Location (monitor) 11

System & DER Modeling Tool (predict) 11

Long Term Planning tool with DER integration (predict) 12

Volt/VAR Control (DVVC/IVVC) (control) 12

Third Party Aggregated Demand Response (control) 12

Grid Management System (monitor, predict, control) 12

Utility Controlled Demand Response (control) 12

Advanced Protection (monitor, predict, control) 12

Conservation Voltage Reduction (CVR) (control) 12

Power Line Communication (monitor, control) 12

Remote Sectionalizing (control) 13

Variable VAR Output (control) 13

Dynamic Power Factor Control (control) 13

High speed VAR injection (Power Electronics) (control) 13

Grid Modernization Architecture 13

Advanced Automation and System Reliability 13

Optimization and Management 14

Market Integration 14

Communications for Distribution 14

Computing Infrastructure for Distribution 15

Integration Services for Distribution 15

Security Controls for Distribution 16

Additional Resources 16

Appendix A: Summary of Business Requirements 17

Appendix B: Definition of Acronyms 23

-1- © 2016 Southern California Edison Company Neither SCE nor any individual or entity involved with this Project is making any warranty or representation, expressed or implied, with regard to this report. See full disclaimer statement on page i.

Introduction Energy policy, customer choices and needs, and aging infrastructure are driving Southern California

Edison (SCE) and utilities across the world to modernize their distribution grids. Over the last decade,

advancements in distributed generation, energy storage, electric transportation, and micro grid

technologies, known collectively as Distributed Energy Resources (DERs), have made it feasible for

customers to use these technologies to locally generate, store, and manage power at their premises.

They also use DER to increase the reliability and, in some cases, quality of their service, while receiving

benefits in reducing their electric bill through tariffs and programs designed to incent the adoption of

DER technologies.

Other strategic forces at work in the utility industry further are propelling the adoption and potential

uses of DER and applying pressure on traditional utility business and operational models. These forces

include emerging competition, progressive energy policy, changing customer expectations, and supplier

bargaining power.

Today, rigid processes and management structures, compartmentalized by specific functions, operate

and support a stable distribution system; however, in an uncertain future, agility and flexibility will be

required. The eventual state and transition path to the future grid remains uncertain. SCE’s grid

modernization strategy embraces that uncertainty by keeping our energy and environment goals and

customer enablement objectives at the forefront while maintaining fundamental principles ensuring grid

safety and reliability.

This document starts by describing the current and then future states of the distribution system

followed by needed capabilities. These capabilities inform architecture and design, and provide

guidance to the vendor community to drive product development roadmaps. Many of these capabilities

are foundational while others will be driven by the rate of DER adoption and regulatory policy evolution.

Even though the required capabilities will be needed over time, it is essential to start with the holistic

vision to ensure SCE is positioned to quickly adapt and add capabilities when needed.

Current State of the Distribution System SCE’s current distribution system and service model are characterized by the following features:

Radial circuits with voltage and VAR control automation (bandwidth settings on capacitor banks)

An interconnection process that is evolving to manage the significant increase in distributed

generation interconnection (primarily solar PV) requests

A rate structure that attempts to reduce energy usage through an increasing cost tier structure

for increasing usage

A rate structure that creates incentives to increase adoption of distributed generation (primarily

solar PV) including Net Energy Metering that provides an additional incentive to increase

adoption by reducing Transmission and Distribution embedded costs (typical Solar Customer

reduces 50% consumption with solar PV installation)


Federal Investment Tax Credits in effect through the end of 2016 that create a further incentive

for Solar PV adoption

A variety of energy efficiency and demand response programs created through a regulatory

process not connected to the residential rate structure or a market price signal

An aging infrastructure with significant need for capital improvements

A high latency/low bandwidth telecommunications system

Recent system wide deployment of smart meters

Figure - 1

Without substantial changes, this current environment will not be able to manage an emerging

distribution grid infrastructure that supports high levels of distributed energy resource penetration.


Concepts of the new Distribution System Technology is changing, the energy industry is changing, and today’s energy customer is changing.

At SCE, we will enable transformation by designing a next generation grid that will address the

evolving needs of our customers, and at the same time continue to provide safe, reliable, and

affordable electricity.

Distributed resources, which can be defined as energy efficiency, demand response, renewable

generation, energy storage, and electric vehicles play a key role in these industry trends. We are

moving toward a future where distributed resources are integrated into the distribution grid at

unprecedented levels.

The grid of tomorrow looks very different from the grid of today. Power will come from multiple

sources, flow in multiple directions, and be more environmentally friendly. Yet, intermittency of

renewable generators will create voltage and power quality issues, the ability to adequately protect

against system events may be compromised, and maintaining reliability for customers will need

more focus. Figure-2 below depicts a high-level visualization of this new distribution environment:

Figure - 2


We must address these challenges and prepare for renewable and distributed energy resource

integration by modernizing the electric grid and streamlining customer processes while enhancing

safety, reliability, and affordability. Our three primary objectives are:

1. Modernize how we plan for, design, and operate the grid

2. Create an investment road map that will evolve the system to allow for interoperability

among distributed resources, utility assets, and customers

3. Leverage regulatory requirements, such as AB327, as a vehicle for transformative changes to

planning processes and long term investment strategies

To address these objectives, we must evaluate new ways in which we plan for the distribution grid

including integrating supply resources into traditional asset planning. New design standards must be

developed to support enhanced technology deployment and new operating methods should be

considered to leverage distributed resources.

We need to evolve the system such that it enables interoperability between distributed resources,

traditional utility equipment, and customers. The utility will act to orchestrate and coordinate DERs in a

manner such that they not only offer benefit to customers and resource owners, but also act as a grid of

assets providing positive value in a safe, reliable, resilient, flexible, and affordable manner.

New Distribution System Capabilities Over the past few years, SCE has invested significant efforts to assess and identify the set of new

capabilities required for a modernized grid of the future. The results of such efforts have been

summarized by the Distribution Grid Readiness team and are being presented below under the relevant

system categories.

Enhanced Monitoring To maintain a safe and reliable grid, the utility must have expanded visibility of the distribution system.

We need to collect more frequent data at a variety of points that communicates asset status and

performance, enabling timely visibility to grid problems. This is true for both real time operations and

long term system planning.

Our current practices of real time monitoring must expand beyond the substation circuit breaker to

strategic circuit locations including mainline infrastructure and major DER installations. As more devices

are connected to the grid, the complexity will continue to rise. This need for data will transition into a

need for “Big Data”, processing extremely large amounts of information to assess the state of an

increasingly complex distribution grid.

Our ability to detect issues directly supports safety, including the identification of virtual or physical

tampering with the distribution system and any asset performance or grid conditions that may jeopardize

public and company personnel. It supports reliability in that comprehensive, real time visibility provides

the utility with pertinent information to assess outages and maximize restoration of service faster than

previously possible.


The detection of grid troubles early on allows time to respond before these weaknesses escalate to larger

safety or reliability problems. We plan to enhance our resiliency as we improve our visibility to local and

transient conditions. Finally, additional data increases our flexibility to support multiple future scenarios.

More data improves our ability to operate, plan, and maintain the grid today and to meet the data

necessities of a highly distributed grid.

Desired Enhanced Monitoring Capabilities

Real Time Situational Awareness The first step to modernization is visibility of all steady state grid conditions that may need to be

addressed, including criteria violations, equipment failures, customer outages, cybersecurity, etc. Visibility

by itself is not sufficient; recognition of issues requiring attention is the critical second half, and for this,

hardware components that gather data from the field must be combined with software tools to analyze

this data simultaneously. Real-time situational awareness will directly address the challenge we will face

with bi-directional power flows and minimal or delayed visibility of the distribution system beyond the

substation breaker.

Power Quality (PQ) Awareness Operators and planners also require visibility to transient grid conditions affecting power quality for

customers. PQ awareness differs from real-time situational awareness because of different types of grid

conditions not previously monitored on a regular basis. With the potential ubiquity of power electronics

interconnected to the grid, new PQ conditions that have never resulted into issues are expected to

materialize. Having this capability addresses technical challenges associated with ubiquitous power

electronics connected to the distribution grid.

Distribution Load Flow Analysis Distribution load flow analysis provides a visual load flow tool that assesses all points on the distribution

grid for criteria violations in real time. This tool would respond to criteria violations by providing

recommended options for mitigation to system operators. It enhances and expands our situational

awareness by automatically identifying all criteria violations for distribution system operators. A

complement to real time situational awareness, it allows us to assess considerably more field telemetry,

and optimizes usage of available assets on the distribution grid. It will also provide system planners a

simplified means to analyze impacts of grid changes and third party interconnections.

Automation of Circuit Reconfiguration Operations engineering needs automatic notification of permanent circuit reconfigurations to review

protection settings. More frequent and timely review of protection settings will become increasingly

important as distribution topology changes, including more fault contributing sources. Automating certain

steps of this process will help overcome the challenges tied to more frequent review.

Accurate Impedance Modeling Accurate impedance modeling involves circuit maps that have phase, impedance, utility asset, and DER

characteristics modeled for use in advanced tools. This capability is of high importance as next generation

modeling and analysis tools will utilize distribution system models. It addresses the data integrity

challenges of our models today and will directly impact the value of the future software tools.


Prediction Raw data is important, however, is not enough to maintain the grid. Cleaning, validating, and interpreting

this data is and will continue to be a vital step. As grid complexity rises with higher DER penetration, so

will the need for more sophisticated tools to assist in understanding and making decisions using that

information. Tools that leverage more data sets such as automation and advanced metering infrastructure

will play a greater role in the planning process. Forecasting with better accuracy about DER adoption and

performance, in both the near term and long term, will be essential to an efficient grid.

Sophisticated tools with these abilities will help us recognize abnormal operation more quickly than with

our current tools and practices. Monitoring for criteria violations on the entire distribution grid

simultaneously will foster a more distributed grid without sacrificing safety. Customer minutes of

interruption should be improved with the application of fault detection and load restoration algorithms

that identify potential load rolls and circuit reconfigurations. Planning tools that factor in time series

analysis of asset operation should lead to refined detection of equipment near end of life. Software tools

and distributed intelligence can manage some aspects of DERs and other assets automatically without

human intervention. This gives the ability to predict and respond to not only real time, but also to even

transient conditions affecting grid operation. With planning tools that detect transient issues, anticipate

high DER adoption and other conditions that may drive volatility on line loading, the utility can strategically

upgrade locations of the grid in need of more resilience. Finally, more sophisticated forecasting and

analysis tools support the utility’s flexibility by enabling adaptability to changing business and system

models on the distribution system, ranging from vertical integration of delivery to potential distribution

markets.

Desired Predictive Capabilities

Asset Pairing & Modeling This capability associates customers and DERs with related utility assets (DER modeling/CYME) for state

estimation and detailed studies. Challenges with accurate impedance modeling, asset characteristics, and

DER attributes will need to be addressed as they are critical for future software tools to work effectively.

This includes accurate net load profiles of each service transformer. A technological means to accomplish

this pairing will help overcome the challenge of maintaining data integrity.

Near-Term DER Forecasting Near-term DER forecasting includes forecasting day-ahead capacity and the expected performance of

DERs for operations planning. This capability addresses an operational challenge of our limited ability to

optimize all of the available assets connected to the distribution grid.

Long Term DER forecasting (DER Dependability) Long-term DER forecasting provides the capability to evaluate dependability of all DERs to maximize grid

benefit and ability to offset or defer traditional capital projects. This tool will address the "hidden load"

challenge faced today which hinders our ability to distinguish between generation and gross demand to

accurately forecast DER dependability. Acquiring tools with this capability will address the limited ability

to optimize all of the available assets for planning the distribution grid by integrating DERs in to the

planning process.


DRP to leverage DERs for Grid Benefit When creating the Distribution Resources Plan (DRP) as part of the long term planning process, Planners

must have the ability to evaluate DERs as potential alternative capital solutions to traditional upgrades.

This capability in our planning tools directly addresses the upcoming challenges with integrating DERs into

our planning processes for traditional capital investment deferral.

Fast DER Interconnection Process SCE needs to streamline the interconnection process, and requires capabilities that minimizes human

resource impact for reviewing and processing DER interconnection applications. This process should

increase efficiency and track attributes without expanding needed manpower. As the quantity of DER

interconnection applications continue to rise, challenges will surface when it comes to delivering timely

and quality review of applications. A technological solution will help resolve the resource challenges that

will result from more interconnection requests.

Control With comprehensive data and a clearly formed course of action based upon that data, execution is the

final step. A grid with an abundance of DERs will likely encounter scenarios that require response times

much faster than our system is capable of today. Remote control will become necessary for normal day-

to-day operation rather than only for emergencies. Control of distributed assets should allow for quicker

response to and isolation of hazardous conditions, hastened restoration from outages, and swift

mitigation of criteria violations and power quality issues. High speed communication and defined

operating parameters for any grid-connected device will be essential in a modernized grid to support this

expanded remote control.

While there may likely be many more distributed power providers in the future, the dependability of their

power supply may not be held to the same standard as the utility. We will still be responsible for serving

power to any connected customers and must retain that ability under planned criteria. This responsibility

drives the need for supervisory control of any significant distributed asset should the utility need to step

in during an emergency.

Desired Control Capabilities

Voltage Optimization Voltage optimization capability provides automated and centralized control of volt/VAR support devices

to meet Rule 21 compliance and allow for the implementation of Conservation Voltage Reduction (CVR).

This capability addresses the challenges associated with integrating large quantities of intermittent DERs

into the distribution system.

Power Flow Optimization This capability enables automatic reconfiguration and remote control of grid connected equipment to

avoid utility asset overloads or criteria violations. This capability addresses an operational challenge of

our limited ability to optimize all of the available assets connected to the distribution grid.

Highly Reconfigurable Protection Reconfigurable protection provides the ability for field protection apparatus to enable appropriate

protective settings based on current configuration of distribution circuitry. In a dynamic distribution grid,


optimal circuit configurations can change throughout the day. Field protection will need to be as flexible

as the circuitry it protects.

Bi-Directional Protection The capability provides protection of bi-directional power flows at all points on the distribution circuitry

where appropriate. As the penetration of distributed generation increases, reverse power flow can

become a normal scenario. Protective equipment in any areas with high DER penetration must be

upgraded to handle bi-directional power flow.

Remote communication with relays Remote communication with relays provides the ability to download Digital Fault Recording (DFR) data

for post event analysis. Verification and updates to protection settings in substation and distribution

relays. Our ability to gather pertinent event and relay data remotely will become more important as the

distribution grid topology changes more rapidly with DER penetration.

Advanced Automation Advanced automation for fault detection and automated circuit reconfigurations provides the ability to isolate and restore interrupted load as quickly as possible and without human operator intervention. Distribution automation technologies will evolve and be widely included in distribution system design to extend intelligent control throughout the entire distribution grid and beyond, inclusive of distributed energy resources, buildings, and homes. Advances in distribution automation will be driven by:

The need to improve reliability, particularly as existing system components age. More flexible and intelligent switches and interrupters on distribution circuits will help to minimize the extent of outages and speed restoration through Fault Detection, Isolation, and Restoration (FDIR).

Increased penetration levels of distributed energy resources, most notably renewable distributed generation and energy storage. These resources can help achieve renewable portfolio goals and provide grid support capabilities, but can also destabilize the grid if not managed correctly.

Increased need for demand response and advanced load control to mitigate peak demand issues. Advanced distribution automation can offer a more precise level of control over demand side resources, allowing for increased levels of demand response to be achieved without significantly impacting the comfort or convenience of customers. Load control will be available to respond to various electric system needs, ranging from lack of generation resources to local distribution system overloads.

The need to limit distribution line losses and to operate circuits more efficiently in a future characterized by carbon constraints, increasing energy prices and customer requirements for improved power quality. We anticipate that this will be achieved in part through Advanced Volt VAR Control (AVVC), which maintains better Conservation Voltage Reduction (CVR) at the service point.


Desired Grid Applications SCE grid modernization requires the following applications to enable the desired capabilities. Many of the

applications are required by multiple capabilities and are therefore prioritized by the level of dependency

of the desired capabilities on the implementation of each application. The color legend below is used:

Monitor

Predict

Control

These capabilities in turn drive business requirements. Appendix A provides a consolidated summary of

the business requirements identified as of the date of this document.

Field Area Network (FAN): Faster Wireless Communication (monitor, control) Significant expansion of distribution automation will drive the need for additional bandwidth and

expanded coverage to support increased automation presence. The number of automated devices in the

field may increase 4x-5x and the wireless network will need greater capacity for telecommunication

traffic.

New wireless networks are needed and must be capable of 30 second maximum round trip latency system

wide, reliable communication in underground settings with reliability of 99.99%, and 100mS maximum

round trip latency between neighboring field devices. Round trip latency is important for faster control

actions by operators. Control latency should be minimized in order to better respond to urgent system

conditions mandating supervisory control of major DERs. Increased reliability in underground

environments is important to minimize failed delivery of packets, which increases latency. High-speed

communication between neighboring devices provides flexibility for future dynamic protection schemes.

Automatic Phase Identification (monitor, predict) Automatic phase identification provides a technological solution for detecting which phase(s) customers,

transformers, and assets are connected to/fed from. This solution should not require human resources to

visit physical locations in question, but should be able to poll this information from a centralized/remote

location.

Phase imbalance on our distribution lines leads to great inefficiencies for capacity planning, loss of

operational flexibility, and high neutral current which can pose safety issues. Phase balancing is a time

intensive process that requires phase mapping of loads. The data captured in this process is inadequately

maintained, however, because it loses reliability once the circuit is inevitably reconfigured. A

technological and repeatable approach directly addresses this challenge of maintaining mapping and

modeling data integrity in a timely, cost-effective manner.

DER Forecasting/ Management system (monitor, predict, control) This application includes software tools that can track and predict capacity or performance of DER

including: Demand Response capacity on each distribution feeder, Distributed Generation output based

on weather forecasts and irradiance data, PEV demand/capacity based on customer and seasonal trends,

Energy Storage operation/capacity throughout the day based on historical 24-hour circuit load profiles


appropriate for time of year, and some useful way of accounting for Energy Efficiency as "capacity". Such

an application would provide our operators with a means for detecting “hidden load” when reconfiguring

circuitry. In addition to its present ability to track performance, it could also calculate dependability of

individual DERs to be leveraged in the planning process. As a management tool, it would implement any

supervisory control of these DERs when necessary.

Detailed Impedance Models (monitor, predict) SCE planners require an impedance-modeling database that houses comprehensive information about

distribution feeders including conductor segment size and lengths, phase information, and equipment

relationship(s). This database should be the central source for modeling, analysis, and operational

software tools. A central database would help to maintain data integrity and consistency between studies,

analyses, and reporting.

Distributed Intelligence (monitor, control) Distributed intelligence includes upgraded apparatus controllers capable of complex processing to

support future potential needs. New controllers would handle increased telemetry needs, capturing a

variety of steady state and PQ telemetry. Distributed intelligence would also be able to communicate

between field devices rather than through a central system, resulting in faster communication and thus

operation when necessary. It would provide locational awareness of apparatus so that equipment can

self-adjust settings or operation based on reconfigurations to distribution feeders. While unable to

function as protective equipment directly, distributed intelligence would also be able to capture data on

fault scenarios (digital fault recording) that can be used as templates for pre-fault detection abilities.

Advanced Metering Infrastructure (monitor, control) SCE can benefit from expanding utilization of smart revenue meters that communicate usage data to

centralized database for purposes of developing effective demand side management programs and real

time situational awareness. SCE is currently conducting work to build and maintain a repository for smart

connect meter data. The next step is leveraging this wealth of information for analysis to understand

customer usage patterns and predict DER adoption and criteria violations. Smart connect meters still have

the potential to serve as communication pathways for demand response applications, as well as to take a

more prominent role in early indication to isolated customer outages.

Power Quality Monitoring (monitor, predict, control) The Power Quality Monitoring application provides telemetry capable of sub-cycle monitoring for analysis

of Total Harmonic Distortion (I&V), Flicker, Power Factor, Voltage sags & surges, incipient equipment

failures or incipient system faults. Monitoring should be continuous and handled by distributed intelligent

devices in the field reporting unsolicited data only when accepted parameters are violated. Waveform

data should be stored locally for an adequate time frame (30-90 days) to allow for data requests and post

event analysis.

DER Telemetry (monitor, control) DER telemetry provides direct measurements of DER output and performance. Accomplished either by

utility installed telemetry or third party supplied gateway.


Remote Line Monitoring / Remote Circuit Telemetry (monitor) Remote line monitoring and remote circuit telemetry application captures 3-phase voltage, current, phase

angle, and power factor, with GPS time stamps; other direct measurements including temperature, phase,

and frequency.

Geographical weather data subscription (predict) Accurate forecasting requires weather and irradiance data on a more granular geographical level

compared with the utility’s resolution today.

Distribution Management System State Estimator (monitor, predict, control) The distribution management system state estimator application provides operations with a tool able to

calculate the status and power flow at any point on the distribution grid through a load flow analysis

simulation of an impedance model and real time telemetry from the field. This tool would also be capable

of identifying criteria violations and making recommendations to operators on how to reconfigure

circuitry to mitigate violations and recover from outages.

Beyond the Meter (Wi-Fi Gateways) (monitor, control) This application provides the ability to communicate with customer equipment through new

communication and protocol agnostic devices. SCE and third-party providers can benefit from customer

usage data to develop demand side management and Demand Response (DR) programs that can appeal

to more customers than the current, limited number of programs currently attract and retain.

Distributed Generation/DER Interconnection Tool (monitor, predict) This web-based software tool supports interconnection streamlining by enabling customers and

contractors to submit DER interconnection applications on-line. This tool incorporates business rules that

enables applications review and identification of deficiencies and errors/problems prior to forwarding to

engineer/planner for final review. It can provide customer updates when the application is in the review

process and should speed up interconnection time from submittal of the application to "permission to

interconnect" / “permission to operate” (PTO).

Ramp Rate Management of DERs (control) This application provides the ability to curtail DER output and control output ramp rates to avoid

undesirable voltage fluctuations and line overloads. The parameters can be pre-programmed based on

technical review and done in real time.

Remote Fault Detection and Location (monitor) Fault indicators need to contain wireless communications capability to assist in fault detection, isolation,

and restoration. Such devices can also be leveraged to provide real time telemetry to support operations

situational awareness.

System & DER Modeling Tool (predict) This engineering modeling tool models characteristics of DERs on distribution circuitry for in depth, time-

series analysis. It can also be used for disaggregating load profiles into load, generation, and other DER

profiles (i.e. "hidden load")


Long Term Planning tool with DER integration (predict) The long-term planning tool is similar to SCE’s existing tool (Master Database Interface (MDI)) that tracks

distribution assets for criteria violations and houses capital project scope. This tool provides increased

functionality by incorporating DER into planning process for capital deferral consideration, as well as

forecasts adoption of DER and impacts to planning. This tool will assist in the development of future

Distribution Resource Plans (DRP).

Volt/VAR Control (DVVC/IVVC) (control) The centralized Volt/VAR control application incorporates algorithms that analyze current conditions to

determine optimal state of each VAR device (on/off) connected to a substation bus section. This tool

would operate VAR devices automatically and supersedes local bias control, which is reserved for back up

operation.

Third Party Aggregated Demand Response (control) This application enables interaction with third parties that enroll customers into their DR programs and

then sell DR capacity to the utility. This approach minimizes the number of communication channels the

utility has to manage. It maintains the current separation of utility from behind the meter.

Grid Management System (monitor, predict, control) The grid management system is a comprehensive operations tool that consolidates existing tools,

including OMS, EMS, DMS, and ALCS into one tool with seamless integration between functions. Such a

tool would limit data presented to operators to only what is relevant to pending system conditions,

minimizing "information overload" that will likely occur in a complex, high DER penetration grid.

Utility Controlled Demand Response (control) This application provides the means for the utility to directly control DR at an individual circuit level. The

ability to control DR at an individual circuit level enables the use of DR as a potential alternative to

traditional capital projects. It can be accomplished directly through utility supplied gateway devices at

customer locations, or via software vendors that enable this communication and implementation for us.

Advanced Protection (monitor, predict, control) The advanced protection application enables relays that support the capabilities identified including: High

impedance faults, self-adjusting settings based on current system configuration, Remote I/O of settings,

notification generation when permanent reconfigurations affect it, pre-fault detection, bi-directional

power flow monitoring, and digital fault recording.

Conservation Voltage Reduction (CVR) (control) This application provides Optimization or flattening of voltage profiles on distribution feeders so that

tighter, lower voltage bands can be leveraged. Lower voltages show correlation with reduction in energy

consumption, which translates to savings for customers and reduced operating losses for utility.

Power Line Communication (monitor, control) Power line communications includes high frequency communication on power lines enabling

communication between devices. This technology can be used for phase detection, fault locating, or

alternative communication paths.


Remote Sectionalizing (control) This application enables the operator to sectionalize circuitry (Load Break or Fault Interrupting) from a

remote location on command. This ability would be expanded for purposes of normal, daily operation

rather than emergency use.

Variable VAR Output (control) This application provides control of scalable VAR support devices such as a cap bank that provide between

0-1800 kVAR.

Dynamic Power Factor Control (control) This application includes devices capable of 4-quadrant control to operate at configurable Power Factor

ratings communicated by the utility to support the Volt/VAR needs at their physical location. These PF

ratings could be configurable based on a specific rating sent by the utility, or by creating a "Feed point" to

the device toward which to regulate.

High speed VAR injection (Power Electronics) (control) High speed VAR injection includes power electronics capable of high speed VAR support that can assist in

ride through of Voltage sag events and help stabilize voltage during PV output loss due to cloud cover.

Grid Modernization Architecture The capabilities described above coupled with the high-level business requirements are driving the

development of the Grid Modernization architecture at SCE. This effort focuses on the SCE electric

distribution system and the corresponding information technology assets used to operate and manage

it. The SCE team is developing the new architecture with a focus on seven main functional areas to

organize and align needed operations, functions, and behaviors of the various systems to satisfy

business needs. The new architecture vision is available in a separate document.

Advanced Automation and System Reliability

This area focuses on the needs of the distribution system relating to real-time operations. These functions need to be implemented quickly and likely without human intervention to maintain the stability of the electrical system (voltage, frequency, and load/generation balance). These functions become much more important as penetration levels of distributed generation and storage increase on the grid. Furthermore, it is equally important to recognize the relationship between automation and telemetry. Additional automated devices will serve a dual role of providing increased amounts of telemetry for an advanced grid management system with state estimation capabilities. Some examples of these functions include:

Protection in distribution substations and on circuits to account for high penetrations of DER (two-way power flow, high impedance faults, and microgrids)

Automatic circuit reconfiguration due to system faults or unexpected load shifts (e.g. responding to changing cloud cover with PV, wind variations)

Automatic power restoration following faults

Automatic management of generation, storage, and loads to maintain load/generation balance

Management of microgrid connection and disconnection from the grid

Management of microgrid resources while islanded to maintain stability


Optimization and Management

This area addresses the optimization of the electrical grid once stable operations are established. In this capacity, control actions will be taken on a time scale of minutes to hours to days. These functions ensure that the grid is operating in the most efficient manner. These functions can be accomplished by automated systems entirely or through automated recommendations made to human electrical system operators. Some examples of these functions include:

Volt/VAR control (with and without inverter control)

Circuit segment and phase balancing

Optimization of load/generation balance (including DR) for best system efficiency

Monitoring of system assets for preventative maintenance

Reconfiguration of circuit segments to optimize loading

Use of storage and generation to eliminate circuit overloads during peak periods

Use of forecasting to manage PV generation

Market Integration

This area addresses the interactions of market functions with the operations of the electrical grid. These functions will be implemented to encourage efficient operation of the grid through pricing or other market mechanisms. This area also considers various methods of integrating markets (e.g. rates, programs, incentives, price delivery). Some examples of these functions include:

Issuing of locational prices to improve grid efficiency or eliminate overloading

Interactions with third-party aggregators for load management, generation and storage

Interactions with the CAISO to support transmission system needs (e.g. transmission line load relief, congestion relief)

Use of pricing to influence operation of generation, storage, and load management capability to meet the distribution system needs

Reduction of peak loads through use of pricing

Communications for Distribution

This area addresses the end-to-end communications requirements associated with a next generation control system. The scope focuses on describing the capabilities associated with an enhanced and ubiquitous network which connects distribution devices, distributed energy resources, customers, and third parties. It will leverage a common infrastructure and allow for device-to-device communications across the network. The team’s work will focus on both private and public networks (Internet), as well as both wired and wireless networks. The team will detail the integration of the Field Area Network (FAN), the SCE Grid2 Network, and networks dedicated for third-party communications. Some examples of communications related capabilities include:

Interactions of the wired and wireless systems

End to end and dynamic routing

Prioritization and quality of service

Distribution control and the interaction with external networks

Performance expectations with low latency protection

The reach of the communication system (e.g., underground devices)

Expectations associated with unlicensed spectrum


Computing Infrastructure for Distribution This area focuses on the underlying computing infrastructure from a deployment and management

point of view. This area focuses on both general-purpose computing as well as special purpose

computing infrastructure. Typically, general computing infrastructure management has been restricted

to the control and switching centers. As devices in the field become more intelligent, many of the same

techniques used to manage the assets in the control centers will be needed for field devices. This area

will look at capabilities that extend the reliability or life of special purpose built devices, as well as

outline those capabilities that apply universally or apply to a specific class of asset. Some examples of

computing infrastructure capabilities:

High availability (percentage of time the computing infrastructure is available and usable)

Device monitoring and health

Virtualization

Data storage

Backup and recovery

Firmware Management

Patch Management

User Management

Integration Services for Distribution This area focuses on the integration of control applications and defines integration expectations for the

back office as well as the field. The integration area will look at typical integration approaches such as

enterprise bus and operational bus technologies as well as how it relates to legacy systems. This area

will define the capabilities associated with gateway applications as well as protocol translation

expectations. Some examples of Integration capabilities:

Service Oriented Architecture

Web services integration

Publish and subscribe expectations

Protocol translation

Transformation

Discovery and registration

Adapter expectations


Security Controls for Distribution This area focuses on the capabilities associated with securing the distribution control system. This area

will define the needs as it relates to assurance and trust. The area looks at detection and prevention

and defines the capabilities associated with securing data at rest, in transit and in process. This area will

define any overarching requirements, which are externally driven (e.g., regulatory expectations). Some

examples of these functions include:

Automatic device provisioning

Device credential management, including automatic key rollover and certificate renewal

Intrusion detection and prevention

Cryptographic protection of communication protocols

Cryptographic protection of data at rest

Ongoing penetration testing

Establishing and maintaining secure network partitions

User authorization and access management

Security event monitoring and analysis

Additional Resources This concept of operations document is being used by SCE to define the vision for our Grid

Modernization Initiative. Using this vision, SCE has also produced a Grid Modernization Architecture

Definition document which can be found at www.edison.com/home/innovation/smart-grids.html. SCE

looks forward to a successful collaboration with industry on the Grid Modernization program. Please

direct any questions or feedback to [email protected].

http://www.edison.com/home/innovation/smart-grids.html

mailto:[email protected]


Appendix A: Summary of Business Requirements The table below contains the consolidated summary of the high level business requirements identified as

of the date of this document.

# Requirement ID Business Requirement Description:

1 GM-DST-REL-001 Enhance the distribution system monitoring from the current reactive state to a real-time, proactive mode

2 GM-DST-REL-002 The monitoring capability shall provide end-to-end system and real-time situational awareness which entails visibility into all steady state grid conditions that may need to be addressed including criteria violations, equipment failures, customer outages, and cybersecurity events. Such real-time situational awareness shall provide visibility into system-wide voltage, power, phase angle, impedance, and frequency

3 GM-DST-REL-003 Provide the ability to identify violation conditions and recommend mitigation options

4 GM-DST-REL-004 Provide real-time power quality data: telemetry capable of sub-cycle monitoring for analysis of Total Harmonic Distortion, Flicker, Power Factor, Voltage sags and surges, incipient equipment failures, or incipient system faults

5 GM-DST-REL-005 Provide the ability to automatically detect a current fault occurrence

6 GM-DST-REL-006 Provide the ability to automatically identify and isolate the fault location

7 GM-DST-REL-007 Provide the ability to either manually or automatically take corrective action based on pre-defined business rules (restore power to a manually selected, state-full, or policy-based number of customers)

8 GM-DST-REL-008 Provide the ability to conduct FLISR functions centrally as well as in a distributed configuration (Back-office, substation, or near edge)

9 GM-DST-REL-009 Provide the ability for microgrids to perform FLISR functions autonomously as needed and in accordance with pre-defined business rules

10 GM-DST-REL-010 Provide a mechanism to enable and control the automated functions according to pre-defined business rules

11 GM-DST-REL-011 Identify and implement an adequate Distribution Operational Model and Grid Management System capable of accommodating the requirements above. Note: the Distribution Operational Model consists of the “as-built” model as well as the “as-is” (or existing condition) model

12 GM-DST-REL-012 Provide a mechanism for the implementation of pre-defined business rules relating to the restoration criteria/decision making

13 GM-DST-REL-013 Maintain compliance with SCE safety standards

14 GM-DST-REL-014 Provide the ability to execute circuit reconfigurations remotely and within the electrical constraints of the system (remotely means from a location that is not physically the same as the circuit’s actual physical geographic location)

15 GM-DST-REL-015 Provide the ability to automatically execute circuit reconfigurations based on pre-defined business rules and/or system integrity awareness. Such automated circuit reconfiguration shall be feasible for overhead, underground, and a combination of the two

16 GM-DST-REL-016 Provide the ability to use DER to perform power flow optimization

17 GM-DST-REL-017 Provide the ability to monitor the distribution grid system conditions using automatic state estimation



18 GM-DST-REL-018 Visually present system data for proactive grid operation functions

19 GM-DST-REL-019 Provide the ability to use advanced analytics. Advanced analytics refers to a grouping of data-oriented analyses used to assess system performance and help drive future improvements

20 GM-DST-REL-020 Provide the ability to implement emerging/new system protection schema resulting from high penetration levels of DER. Specific examples are the ability to manage multi-directional flows and to adjust to lower fault current thresholds

21 GM-DST-REL-021 Provide the ability to seamlessly manage the islanding and reconnection of microgrids either locally or remotely

22 GM-DST-REL-022 Provide the ability for autonomous adaptive protection at the microgrid level

23 GM-DST-REL-023 Provide the ability to perform predictive analytics for the following purposes: Asset Pairing & Modeling, Near-Term DER forecasting, Long-Term DER forecasting, Fast DER Interconnection Process

24 GM-DST-REL-024 Standardize protection criteria for interconnections to 3rd parties

25 GM-DST-OPT-001 Provide the ability for the distribution system to automatically switch capacitor banks both at the substation and downstream field locations

26 GM-DST-OPT-002 Provide the ability for the distribution system to automatically adjust inverter reactive power output in order to reduce energy usage and maximize Green House Gas (GHG) reduction

27 GM-DST-OPT-003 Provide the ability for the distribution system to automatically adjust inverter reactive power output in order to minimize VAR flow

28 GM-DST-OPT-004 Provide the ability to use inverters for phase balancing

29 GM-DST-OPT-005 Provide the ability for the distribution system to automatically adjust inverter reactive power output in order to maximize DER integration

30 GM-DST-OPT-006 Provide the ability for the distribution system to automatically adjust inverter reactive power output in order to minimize switching (i.e. Cap Banks and LTCs)

31 GM-DST-OPT-007 Provide the ability for the distribution system to perform automatic configuration of the electrical system (e.g. automatically switching substation or line capacitor banks, automatically controlling smart inverters and batteries)

32 GM-DST-OPT-008 Provide a mechanism for standardized, plug & play interfaces to 3rd party aggregators and select C&I customers

33 GM-DST-OPT-009 Provide the ability to coordinate with the Transmission voltage schedule

34 GM-DST-OPT-010 Provide the ability for the distribution system to automatically establish DER groups based on a network model

35 GM-DST-OPT-011 Provide the ability for each DER group to optimize the active and reactive power locally at the sub-circuit level around set-points defined at the central controller

36 GM-DST-OPT-012 Provide the ability for DER groups to be aggregated to a regional group to provide reactive power, voltage, and active power support to the overall circuit or substation

37 GM-DST-OPT-013 Provide the ability to leverage mechanisms such as flexible demand, battery storage, and generation control

38 GM-DST-OPT-014 Provide the ability to have visibility and control of DER

39 GM-DST-OPT-015 Provide the ability for automated discovery and configuration of DER

40 GM-DST-OPT-016 Provide the awareness and ability to react to electrical topology changes



41 GM-DST-OPT-017 Ability to accommodate human operator action and manual intervention as necessary

42 GM-DST-OPT-018 Summary level data presentment with the ability to drill down to a more detailed level

43 GM-DST-OPT-019 Provide multiple levels of alarming based on pre-defined grid monitoring criteria

44 GM-DST-OPT-020 Provide the ability to implement control configurations and dynamic grouping based on pre-defined rules/policies

45 GM-DST-OPT-021 Provide standardized 3rd party aggregator interface definitions: Grouping by centralized controller. Clearly defined electrical areas for 3rd party aggregators

46 GM-DST-OPT-022 Provide the ability to extend computing infrastructure to the edge (downstream from the Substation)

47 GM-DST-OPT-023 Provide new distribution system tools (configuration, simulation, planning, asset management)

48 GM-DST-OPT-024 Provide connectivity and interaction with select external data systems such as the National Weather Service and emergency response systems

49 GM-DST-OPT-025 Provide the ability to support multiple modes of operation: - Operating in parallel with a (strong/weak) bulk system connection - Operating as an islanded microgrid (single or multiple sources) - Operating on a dynamically changing microgrid island; reconfiguring into sub-grids

50 GM-DST-OPT-026 Provide the ability to perform the following functions in islanding state: - Perform local reactive and real power balancing - Voltage and Frequency control - Phase balancing if applicable - Protection - Optimization

51 GM-DST-OPT-027 Provide the ability to perform the following functions in connected state: - Peer-to-peer interaction to ensure optimization and stability - Follow DSO/DMS control signals to manage generation/load at microgrid PCC

52 GM-DST-OPT-028 Provide the ability to complete transitions between connected and islanded states (Seamless, sub-cycle; Drop and Pick-up; Synchronization)

53 GM-DST-OPT-029 Provide the ability to handle multiple levels of microgrids namely single customer level, feeder level, or Substation level

54 GM-DST-OPT-030 Compliance with the approved Rule 21 Phase1 Criteria: - Voltage ride-through capable - Frequency ride-through capable - Expanded power factor capable (1.0+/-0.15) - Dynamic Volt/VAR operating capable - Ramp-Up control capable at 1% increments

55 GM-DST-OPT-031 Ability to accommodate the pending Rule 21 Phase2 (Communications) and Phase3 (Advanced Inverter Functions)

56 GM-DST-OPT-032 Provide the ability for the distribution control system to respond and perform automated control actions based on setpoint triggers (a setpoint is a defined setting/threshold configured on a grid asset device and beyond which action is necessary)

57 GM-DST-OPT-033 Develop unique identifier mapping circuits and line segments



58 GM-DST-OPT-034 Ability to support system loading, voltage control, power control

59 GM-DST-OPT-035 Awareness of device location within the electrical system topology

60 GM-DST-OPT-036 Ensure that all interconnections follow the same standards for access control and reliability

61 GM-DST-OPT-037 Provide dedicated data management/back-office infrastructure for Rule 21 compliance

62 GM-DST-OPT-038 Provide the grid operator with the ability to understand the DER function(s) and how they need to be managed

63 GM-DST-OPT-039 Provide grid operators visibility into the DER and the data associated with their role/behavior

64 GM-DST-OPT-040 Provide grid operators with proper system tools capable of advanced analytics on status, performance, control, and reliability

65 GM-DST-OPT-041 Provide grid operators the ability to select from either operator or automated response capabilities

66 GM-DST-OPT-042 Provide the ability to perform control actions on a circuit segment basis

67 GM-DST-OPT-043 Provide the ability to predict peak, abnormal, and contingency scenarios

68 GM-DST-OPT-044 Provide self-healing/automated control capabilities at a line section level

69 GM-DST-OPT-045 The distribution control system shall provide data to external systems such as the Transmission system, Workforce Management, GIS, Historian, and Customer Service systems (billing and outage management systems)

70 GM-DST-OPT-046 Provide the ability for manual over-ride of control functions (system operator can override automated control)

71 GM-DST-OPT-047 Provide customers, within constraints of contracts, the ability to opt out of utility control

72 GM-DST-OPT-048 The distribution control system shall have a user interface that provides the control capability, visualization capability, and optimization functions required for the autonomous and operator-enabled functions

73 GM-DST-MKT-001 Ability of DER resource to follow control signals from others: Explicit control vs. input-based control (e.g. price signal)

74 GM-DST-MKT-002 Ability of DER resource to provide “true” availability (machine only, excludes forecast)

75 GM-DST-MKT-003 Ability of DER resource to provide schedule

76 GM-DST-MKT-004 Ability of DER resource to provide environmental data

77 GM-DST-MKT-005 Ability of DER resource to perform autonomous energy functions based on grid conditions/needs

78 GM-DST-MKT-006 Ability to remotely configure/change device settings

79 GM-DST-MKT-007 Ability of various control systems to function together

80 GM-DST-MKT-008 Ability to have automated, centralized, and distributed control functionality

81 GM-DST-MKT-009 Ability to have equipment connectivity/situational awareness at feeder level (including scheduled outages)

82 GM-DST-MKT-010 Ability to forecast energy and demand

83 GM-DST-MKT-011 Provide the ability to align with Wholesale market policies (ISO, DSO, and interconnections)

84 GM-DST-MKT-012 Provide a means for correlation between reliability and market use



85 GM-DST-MKT-013 Provide access to external systems for advanced weather awareness

86 GM-DST-MKT-014 Provide access to external planning simulators with DER DMS/Market awareness

87 GM-DST-MKT-015 Standards compliance

88 GM-DST-MKT-016 Ability of DER to provide foreword forecasts of consumption (load behavior): - Given a forward forecast of price/cost of power - Independent of price (must include both elastic and inelastic components)

89 GM-DST-MKT-017 Ability of DER functioning as a supply to generate forward forecast of price for power from the DER

90 GM-DST-MKT-018 Advanced Control Logic: ability to have decision making algorithms for the DERs that enable a battery storage system, for example, to decide when to buy, sell, or do nothing based on inputs regarding forward forecasts of price, forward forecasts of potential load to be served, weather, or state of charge

91 GM-DST-MKT-019 Flexibility in allowing a hybrid control mechanism (SCE control vs. Customer/3rd party control)

92 GM-DST-MKT-020 Ability to accommodate 3rd party aggregation’s participation in Market interactions

93 GM-DST-MKT-021 Provide access to Wholesale Market published results

94 GM-DST-MKT-022 Maintain respect for ownership boundaries

95 GM-DST-COM-001 Provide ubiquitous connectivity throughout the distribution system territory

96 GM-DST-COM-002 Provide the ability to accommodate prioritization based on pre-defined business rules

97 GM-DST-COM-003 Provide real-time visibility of the end-to-end network infrastructure through advanced network monitoring and alerting capabilities

98 GM-DST-COM-004 Provide the ability to accommodate interconnections with 3rd party networks and/or infrastructure assets

99 GM-DST-COM-005 Ensure that the communications network is resilient, redundant, and available in accordance with the grid application requirements

100 GM-DST-COM-006 Ensure proper co-existence between legacy and net new communications infrastructure as required

101 GM-DST-COM-007 Ensure proper network capacity planning based on initial and projected device type and growth/deployment plans

102 GM-DST-COM-008 Provide the ability to reach all SCE distribution assets whether located overhead, underground, or pad mounted

103 GM-DST-COM-009 Provide a seamless transition from the current legacy communication system to the new one

104 GM-DST-COM-010 Provide Internet Protocol (IP) transport capability across the communications network infrastructure

105 GM-DST-COM-011 Provide the ability to remotely upgrade firmware for all devices

106 GM-DST-COM-012 Communication paths to Remote Controlled Switches (RCS) shall have battery backup power for up to 8 hours of operation following a loss of the main power source

107 GM-DST-COM-013 Provide the ability to perform remote diagnostics on devices to troubleshoot and determine the cause of failure/mis-operation



108 GM-DST-COM-014 The new distribution system shall have the capability to assign a group attribute to a device or a collection of devices. Devices shall be capable of being a member of up to 8 groups

109 GM-DST-SEC-001 Provide the ability to track and manage authorized devices connected to the Edison network and the removal of unauthorized devices connecting to the network

110 GM-DST-SEC-002 Provide the ability for automated device inventory

111 GM-DST-SEC-003 Provide the ability for device authentication

112 GM-DST-SEC-004 Ensure the implementation of network access control based on pre-defined rules

113 GM-DST-SEC-005 Provide the ability for the management and handling of unauthorized devices

114 GM-DST-SEC-006 Provide the ability for automated response to unauthorized devices

115 GM-DST-SEC-007 Provide the ability for the proper control of third-party devices

116 GM-DST-SEC-008 Ensure the ability to scale and the accommodation of the planned increase in the number and types of grid devices

117 GM-DST-SEC-009 Provide a mechanism that ensures proper levels of controls over the types of software authorized for installation, malware control, and secure configurations (anti-virus, application white-listing, application integrity checks for secure software distribution)

118 GM-DST-SEC-010 Provide an effective mechanism for security patch management

119 GM-DST-SEC-011 Provide the ability to discover known and unknown security vulnerabilities and threats

120 GM-DST-SEC-012 Provide the ability to conduct effective penetration testing

121 GM-DST-SEC-013 Ensure that SCE’s network perimeter and boundaries are properly protected and secure

122 GM-DST-SEC-014 Provide the ability for malicious communications detection and remediation

123 GM-DST-SEC-015 Ensure the use of secure configurations for the network infrastructure

124 GM-DST-SEC-016 Define a scalable/repeatable network segmentation architecture that allows the protection of demarcation points

125 GM-DST-SEC-017 Provide the ability to control the use of administrative privileges, account credential strength, access management and revocation, and nonrepudiation of system activity

126 GM-DST-SEC-018 Provide the ability to integrate new distribution system with identity management and multi-factor authentication applications

127 GM-DST-SEC-019 Ensure ubiquitous two-factor authentication

128 GM-DST-SEC-020 Ensure the safeguarding of SCE’s grid and asset data

129 GM-DST-SEC-021 Provide a mechanism for critical data identification and categorization

130 GM-DST-SEC-022 Provide the ability to encrypt Data-in-transit

131 GM-DST-SEC-023 Provide the ability to protect Data-at-rest

132 GM-DST-SEC-024 Provide the ability to identify critical data types and apply appropriate confidentiality and integrity protections


Appendix B: Definition of Acronyms

CAISO California Independent System Operator

CIEE California Institute of Energy and Environment

DER Distributed Energy Resource

DR Demand Response

DG Distributed Generation

DMS Distribution Management System

DVVC Distributed Volt/VAR Control

EE Energy Efficiency

EMS Energy Management System

ES Energy Storage

FAN Field Area Network

FERC Federal Energy Regulatory Commission

FLISR Fault Location, Isolation, and Service Restoration

GIS Geographic Information System

IED Intelligent Electronic Device

IEEE Institute of Electrical and Electronics Engineers

ISO Independent System Operator

IT Information Technology

IVVC Integrated Volt/VAR Control

KVA Kilovolt-ampere

NERC North American Electric Reliability Council

OMS Outage Management System

PEV Plug-in Electric Vehicle

PMU Phasor Measurement Unit

PV Photovoltaic

PQ Power Quality

QoS Quality of Service

RDBMS Relational Database Management System

SCE Southern California Edison

VAR Volt-ampere Reactive

VEE Validation, Editing, and Estimation

WAN Wide Area Network

WECC Western Electric Coordinating Council

WMS Work Management System


Documents

Grid Modernization Distribution System Concept of · PDF fileEnhanced Monitoring 4 Real Time Situational Awareness 5 ... distribution grid infrastructure that supports high levels