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U.S. Investor-Owned Utility Automation Market

  • ID: 4746635
  • Report
  • Region: United States
  • 43 Pages
  • Newton Evans
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FEATURED COMPANIES

  • ABB
  • Consumers Energy
  • Eversource Energy
  • Intergraph
  • Oracle
  • PSE&G
  • MORE

“U.S. Investor-Owned Utility Automation Market: Opinions from 30 U.S. Investor-Owned Utilities Collected from Four Survey-Based Reports” is a 43-page compilation of findings from some of the researcher's largest flagship studies.

A recently published compilation of survey findings highlights electric power automation trends among investor-owned utilities (IOUs).

  • For control systems, IOUs tend to use more OMS analytics, are more likely to have an advanced DMS (or have plans for one), use synchrophasors for wide area monitoring, and want cybersecurity features designed as an integrated part of the control system rather than added on.
  • For system protection and control, IOUs are capable of budgeting more for protective relay hardware; half of IOUs surveyed budgeted over $2.5 million for the years 2016-2018.
  • For substation automation, IOUs use more encryption on data sent from the substation to the external host than within the substation; 75% of respondents indicated that no encryption is used for communication within the substation.

There are fewer than 200 IOUs in the U.S. comprising less than six percent of all electric utilities. However, IOUs account for providing electricity to just over two-thirds (102 million) of the 151 million U.S. end-use customers while more than 1,800 public power utilities account for about 15% and 834 electric distribution cooperatives account for another 13% of customers.

Note: Product cover images may vary from those shown
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FEATURED COMPANIES

  • ABB
  • Consumers Energy
  • Eversource Energy
  • Intergraph
  • Oracle
  • PSE&G
  • MORE

1. Introduction

2. Overview of U.S. Investor-Owned Utilities

3. Power Generation

4. Power Transmission

5. Power Distribution

6. Operational Technology

7. Control Systems

8. Substation Automation

9. Protection and Control

10. Distribution Automation

11. EMS/SCADA/DMS/OMS

  • Which of these systems does your company use? (Check all that apply)
  • What vendors do you use for the systems you have?
  • Do you plan to add any new/replacement or upgraded/retrofitted systems by 2019?
  • What is your planned estimated budget range from 2017 to Year End 2019 for EMS?
  • What is your planned estimated budget range from 2017 to Year End 2019 for SCADA?
  • What is your planned estimated budget range from 2017 to Year End 2019 for DMS/ADMS and/or OMS?
  • Do you have an Advanced DMS (ADMS)? (i.e. does it provide SCADA, DMS, and OMS together in one user interface)
  • If you have an ADMS, does the SCADA functionality and network modeling include Distributed Energy Resources?
  • What applications do you use as part of your DMS or ADMS?
  • Does your utility currently have real-time linkages between SCADA and GIS or OMS?
  • Is the support group for EMS/SCADA/DMS part of a corporate IT department or managed by the line of business?
  • Has your utility converged SCADA/DMS and OMS functions?
  • What types of networks do you use for communication from the substation to the external EMS/SCADA/DMS host/network?
  • For communication from the substation to the external EMS/SCADA/DMS host/network, do you use an “in-house” network or rely on a commercial carrier network?
  • Current and planned use of communication protocol(s) within the substation, and from the substation to external EMS/SCADA/DMS host/network.
  • Reasons for NOT using or planning to use IEC61850
  • Communications method(s) used for connecting SCADA substations
  • External assistance or third-party services needed for control center activities
  • Number of currently installed RTUs, PLCs, substation platforms, etc. on EMS/SCADA/DMS
  • Number of RTUs, PLCs, substation platforms, etc. on EMS/SCADA/DMS planned for installation from 2017-2019
  • Use of analytics
  • Agree or disagree
  • Open-ended comments regarding the statements/topics in the previous “agree/disagree” question.
  • For which of the following applications does your utility use synchrophasors?
  • What are the Operating System preferences for the platforms on your system?
  • Latest technologies incorporated into EMS/SCADA/DMS platforms
  • With experienced personnel leaving the workforce due to retirements, how is your utility able to maintain a “Qualified Support Staff” for EMS/SCADA systems?
  • How are distribution circuit designs captured and transferred?
  • How are distribution circuit designs updated?
  • What standard is used to update distribution circuit designs?
  • What system is master?
  • How are distribution circuit designs captured and transferred?
  • When distribution circuit designs are captured and transferred, how are they updated?
  • When distribution circuit designs are captured and transferred, what standard is used?
  • When distribution circuit designs are captured and transferred, which system is master?

12. Protective Relays

  • Number of Protective Relay Systems to be Purchased: 2016-2018
  • Average % of microprocessor relays among the installed base
  • Estimated Annual Budget Allocation for Protective Relay Hardware
  • Estimated Annual Budget Allocation for Protective Relay Hardware
  • Approaches used for operating WAN remote access to relays
  • Relay Protocols Used for SCADA
  • Relay Protocols Used for Substation Automation
  • Relay Protocols Used for Controlling Actions Issued Externally To or Through the Relay
  • Relay Protocols Used For Communications-Assisted Protection and/or Automation
  • Relay Protocols Used for Engineering Access
  • Ranking of “top three” relay manufacturers from 1-3
  • 11 & 12. Types of Relay Redundancy Schemes CURRENTLY USED for microprocessor-based relaying terminals
  • Uses of IEC 61850
  • Use of IEC-61850 Process Bus (Analog values) or Goose Messages (Digital values) among 61850 users
  • Features of IEC 61850 to be used in new projects
  • Planned level of implementation of IEC 61850 in substations by YE 2018
  • Use of PMUs
  • Where PMUs are used on the system
  • Time Synchronization Methods CURRENTLY USED for PMUs by location
  • Time Synchronization Methods PLANNED for PMUs by location
  • Please indicate your level of agreement with the following statements:
  • Number of Relays Currently Installed, and Number of Relays >15 Years
  • Percent of installed relays that have been in service for more than 15 years
  • Percentage of relays to be replaced in the next 3 years
  • Use of CT sensors instead of traditional CT to eliminate saturation concerns
  • Use of VT sensors instead of traditional Voltage Transformers
  • Ethernet topologies used for redundancy
  • Management of IT and OT Ethernet Networks separately
  • If so, what department in your organization is responsible for the design, performance, and maintenance of your OT networks?
  • Who in your organization monitors, diagnoses, and troubleshoots OT Ethernet networks to verify their real-time performance and identify and correct communications systems misoperations?
  • Who in your organization detects, alerts, reports, and records communications systems misoperations?
  • The demarcation between physical IT and OT networks
  • For reliability & availability of Ethernet OT networks, which methods do you use to avoid a single point of failure?
  • Maximum signaling times

13. Substation Automation

  • “potential obstacles” to implementing substation automation and integration “1 = don’t stand in our way” to “5 = formidable obstacle.”
  • External spending estimates for new and retrofit substation automation and integration programs between 2017 and 2020 - NEW SUBSTATIONS
  • External spending estimates for new and retrofit substation automation and integration programs between 2017 and 2020 - RETROFITTED SUBSTATIONS
  • Number of substations in operation, to be retrofitted, planned to be built, and levels of automation
  • Percent of substations in operation, to be retrofitted, and planned to be built by their levels of automation
  • Are you currently using or planning to implement control logic in your RTUs?
  • If you are either currently using or planning to use control logic in RTUs, how is it used?
  • Are you planning to replace your legacy hardwired I/O?
  • If you are planning to replace your hardwired I/O, what will you replace it with?
  • Reasons for replacing legacy hardwired I/O
  • Need for Analog Outputs
  • Substation Protocols in use and planned for use by year end 2020
  • Encryption of substation communication data
  • What are your alternate methods of communication with the remote site in the event of loss of the routine communications pathways?
  • Substation Ethernet LAN architectures in use and planned for use by YE 2020
  • Routable paths to end devices in 2017
  • Communication architectures used within substation and for communicating to the substation
  • Types of communications links used
  • How primary information processing tasks “inside the fence” are handled
  • Do you have (or plan to have) a Vendor Security Certification Program?
  • If you currently have/plan to have a Vendor Security Certification Program, what does it involve?
  • Applications for substation-based computing platforms
  • External assistance needed for substation automation and integration related activities
  • Please indicate your utility’s preferred vendors for each equipment type.

14. Distribution Automation

  • Total number of distribution feeders reported by utilities answering the survey
  • Average Percent of feeders with SCADA controlled sectionalizing switches that are manual only, semi-automatic (upstream restoration is automatic and downstream restoration is manual), fully automatic (upstream and downstream restoration are both automatic)
  • Approximately what percentage of all your feeders have Fault Detection Isolation Restoration (FDIR)/Fault Location Isolation Service Restoration (FLISR)? (Average)
  • Average percent of feeders equipped with VVC, VVO or CVR
  • What is driving your decision for VVO? Check all that apply.
  • Where are the controls located for FDIR/FLISR on your distribution system?
  • In the future, where do you anticipate the logic to be located for FDIR/FLISR?
  • Where are the controls located for Volt/Var control on your distribution system?
  • In the future, where do you anticipate the logic to be located for Volt/Var control ?
  • Does your utility use automatic fault sensing devices (hot line status, fault indicators) in your feeder design?
  • If you do use automatic fault sensing, do you utilize the status of the communicating automatic fault sensing devices in your distribution automation applications?
  • Have you integrated any communication/controls for distributed generation into your DA system architecture?
  • Are you considering a trial deployment to manage distributed energy resources (e.g. inverters, energy storage, EV chargers, etc.) within the DA system?
  • Does your utility integrate sensing and/or Volt/Var control at the LV side of the distribution transformer within the DA system?
  • Does your utility plan to use sensing and/or Volt/Var control at the LV side of the distribution transformer to support any of the following applications?
  • What other DA do applications use the same telecommunications infrastructure being used by feeder automation? (check all that apply)
  • How are you notified of a feeder main fault event?
  • Does your utility run distributed software applications (like S&C Intelliteam II, L+G Grid Stream; SCADA center product suite, Cooper/Yukon Feeder Automation, G&W/Survalent Lazer Automation)
  • Do you use a centralized (control center based) tool for communication network management and security management?
  • Please check any of the following functions you would like to have integrated into a communications/security management tool for MV Feeder Device management (like recloser controller, capacitor bank controllers, remote controlled switch)
  • Do you currently use (or plan to use) encryption on your communications network for distribution automation?
  • Do you plan to upgrade the existing Feeder Automation network to a newer, wireless technology that allows for features like higher bandwidth, IP enabled radios (i.e. 4G, LTE or WIMAX) by the end of 2020?
  • If you plan on upgrading your Feeder Automaton network, which wireless technology do you plan to use?
  • Three-year total budget for DA projects from 2018-2020 as indicated by the survey sample
  • Average % of DA budget
  • Allocation of DA expenditures by category
  • Do you currently use (or plan to use) bi-directional regulators on your system?
  • Do you currently use/plan to use bi-directional reclosers on your system?
  • Do you currently use (or plan to use) dynamic protection (real time modification of protection settings) on your system?

15. List of IOUs Surveyed

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  • ABB
  • ACS
  • American Transmission Company
  • Areva
  • Avista Utilities
  • Baltimore Gas and Electric
  • Central Hudson Gas and Electric
  • CGI
  • Commonwealth Edison Company
  • Consumers Energy
  • DTE Electric
  • Duke Energy Florida
  • Duke Energy Indiana
  • Duke Energy Progress
  • Empire District - Liberty Utilities Central
  • Eversource Energy
  • FirstEnergy
  • GE
  • Georgia Power
  • In house
  • Indianapolis Power and Light
  • Intergraph
  • ISO New England
  • ITC Midwest
  • Monarch
  • National Grid
  • Oracle
  • Orange and Rockland Utilities
  • OSI
  • Otter Tail Power Company
  • Pacific Gas and Electric Co.
  • PacifiCorp
  • Portland General Electric
  • PSE&G
  • San Diego Gas & Electric
  • Schneider
  • Siemens
  • Southern California Edison
  • The Empire District Electric Company
  • The United Illuminating Company
  • Unitil
  • Xcel Energy
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