Grid Modernization Distribution System Concept of Operations. Version 1.0

Transcription

1 Grid Modernization Distribution System Concept of Operations Version 1.0 January 17, 2016

2 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 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 Southern California Edison Company - i -

3 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 - ii -

4 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 -iii-

5 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) -1-

6 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. -2-

7 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

8 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. -4-

9 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. -5-

10 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. -6-

11 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 dayto-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, -7-

12 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. -8-

13 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 -9-

14 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. -10-

15 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, timeseries analysis. It can also be used for disaggregating load profiles into load, generation, and other DER profiles (i.e. "hidden load") -11-

16 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. -12-

17 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 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 -13-

18 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 -14-

19 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 -15-

20 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 SCE looks forward to a successful collaboration with industry on the Grid Modernization program. Please direct any questions or feedback to John.H.Bubb@sce.com. -16-

21 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, statefull, 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 predefined 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 -17-

22 # Requirement ID Business Requirement Description: 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 3 rd 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 3 rd 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 -18-