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Multi-Part Newton-Evans Research Study Reveals Significant Growth Likely for Advanced DMS Systems and Applications

The Newton-Evans Research Company continues to assess its findings from the firm’s comprehensive 2017 study of EMS, SCADA, DMS and OMS usage patterns among utilities from more than 30 countries.

Current status of Advanced DMS (ADMS)
The Newton-Evans’ survey asked respondents to indicate whether their DMS installation provided SCADA, DMS and OMS functionality together in one user interface and this served as our definition of ADMS for this study.

Overall, 69% of international electric utilities who responded to the survey either currently have or plan to have an Advanced DMS that provides SCADA, DMS and OMS together in one user interface. Thirty-five percent currently have ADMS, and 34% plan to implement ADMS in the near future.

This contrasts with only 9% of North American survey respondents who reported having an ADMS as of the first quarter of 2017. Twenty percent of North American respondents indicated they will have an ADMS by the end of 2019, and another 17% indicated plans for implementing an ADMS sometime after 2019. Overall, 46% of the North American sample either currently has or plans to have an ADMS. Some of the North American sample included “transmission-only” utilities/ISOs.

fig. 1

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Newton-Evans Study Finds Heavy Use of IP/MPLS and Continued Reliance on Utility-Operated Telecommunications Networks for EMS/SCADA and DMS Systems

The latest findings from the Newton-Evans Research Company study of control systems used in the electric power industry point to heavy reliance on IP/MPLS networks for wide area communications from substations and other field locations to central site control systems.

Reliance on IP/MPLS Networks
Sixty-seven percent of international respondents use Internet Protocol/Multi-Protocol Label Switching (IP/MPLS) technology for communication from the substation to the external host/network. Thirty percent use a mix of T1/E1 and/or SONET/SDH and packet networks. It is likely that MPLS-TP (Transport Profile) will see increased use in the next Newton-Evans control systems study scheduled for 2019.

Forty-nine percent of North American respondents use IP/MPLS network technology for communication from the substation to the external host/network. Thirty-seven percent use T1/E1 and 33% use SONET/SDH, followed by 27% who use Carrier Ethernet. Often, more than one type of network is used. Half of North America’s investor owned utilities in the survey continue to use T1/E1, and over half of them use IP/MPLS as well.

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Findings from International Study of EMS, SCADA, DMS, and OMS Indicate Differences in Usage Patterns and Development Priorities When Compared to North American Companies

The Newton-Evans Research Company has published report findings from the company’s recently completed study of EMS, SCADA, DMS and OMS usage patterns in international electric power utilities. This is the second of four volumes of its 14th global market assessment of operational control systems – a survey-based study conducted by Newton-Evans since 1984.

Here are some observations gleaned from interviews and surveys with 31 utility participants from 25 countries:

Systems in Use
All utilities that participated in the survey are operating SCADA systems, and 74% also have an energy management (EMS) installation. Fifty-two percent use a distribution management systems (DMS) and 61% use an outage management system (OMS).

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Research Findings Point to Upgrade of EMS, SCADA and DMS Capabilities during 2017-2019 among North American Electric Power Utilities to Accommodate Renewables Integration and Demand Response

Emphasis Placed on Extending Applications and Expanding Roles of Distribution Management Systems and Outage Management Systems

Here are some observations based on interviews and surveys with 69 utilities from North America participating in our survey:

Almost one-half of all North America survey respondents (47%) plan to upgrade or retrofit their SCADA installations by 2019. Most respondents with such plans were mid-size and larger cooperatives and public power utilities.

Twenty-six percent of respondents plan to purchase a new or replacement DMS by 2019. Only six (major) utilities reported that they currently have an Advanced DMS, but 24 others will have an ADMS in the near future. Importantly, of the 30 respondents using or planning to use an ADMS, none indicated that their SCADA functionality and network modeling presently include distributed energy resources (DERs). However, most of this sub-group (82%) plans to include DERs in their ADMS functionality in the future.

Real-time network analysis and fault location were the prevalent applications being used as part of current DMS or ADMS installations. Plans are centered on supplementing these (where not yet implemented) and adding network optimization and distributed energy resource management capabilities. (See Fig. 1)

Figure 1. Applications used as a part of DMS/ADMS

Real-time linkages between SCADA and GIS or OMS were found in 44% of the utility sites. Forty-one percent reported having no real-time linkages among these systems.

Almost half of the survey respondents indicated that the operational systems support group is managed by the line of business, while 31% stated that such support is now part of corporate IT. (See Fig. 2)

Figure 2. How is OS Support Managed?

Third party services are being used and relied upon to assist with NERC CIP compliance issues and for the conduct of vulnerability assessments.

DNP3 continues to be the most prevalent operational data communications protocol throughout North American electric power utilities. Plans call for continuing the use of DNP3 for the foreseeable future among most of these utilities. Some planning for IEC 61850 is underway, but remains at a low level among these respondents.

More than a score of additional topics were surveyed in this new study including the impact of NERC CIP compliance on budgets and workloads; cyber security issues; telecommunications strategies and methodologies; distribution network model maintenance; changing organizational responsibilities for control systems; budget outlooks; and applications usage patterns.

Further information on this new series, “The World Market Study of SCADA, Energy Management Systems and Distribution Management Systems in Electric Utilities: 2017-2019” is available from Newton-Evans Research Company, 10176 Baltimore National Pike, Suite 204, Ellicott City, Maryland 21042. Phone: 410-465-7316 Email: info@newton-evans.com or visit us at www.newton-evans.com or to order any of more than 100 related reports. For readers interested in purchasing this new series please call or email the company for special introductory pricing.

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Coming Soon: The World Market Study of SCADA, EMS, DMS & OMS in Electric Utilities: 2017-2019

Here is a brochure and order form:
http://www.newton-evans.com/2017EMSSCADABrochure.pdf

Newton-Evans’ World Market Study of SCADA, Energy Management Systems, Distribution Management Systems and Outage Management Systems in Electric Utilities: 2017-2019 is a four volume, multi-client market report. Participants in this market study include utility engineers and managers from investor-owned utilities, municipal and provincial utilities, cooperative utilities within the United States and Canada, together with national power systems throughout the world.

The study will measure current market sizes and will contain projections on a world region basis for the next several years. The entire research program will define the product and market requirements which suppliers must meet in order to successfully participate in one or more of these diverse world market regions.

In the first quarter of 2013, Newton-Evans estimated a combined value of awards for EMS, SCADA, DMS, OMS and energy exchange and ISO/RTO systems at upwards of $6.5 Billion over 4 years. It will be important for electric utilities and control system vendors to learn how changes in the world market conditions since then will affect the outlook for 2017-2019.

Methodology
Field survey work is conducted using a mix of primary research methods including personal interviews, mail surveys, faxes, e-mail and follow-up telephone interviews. Over the past 15 years, more than 1,000 utility officials have participated in one or more Newton-Evans grid modernization and energy automation-related studies.

The survey-based findings in Volumes 1 (North American Market) and 2 (International Market) will discuss the following:
 Approximate number of Poletop RTUs, Feeder/secondary RTU’s/Smart DA devices, Substation RTUs, PLCs, SA platforms, Synchrophasor measurement units, and Substation level phasor data concentrators. Anticipated numbers planned for installation by year-end 2017, along with protocol requirements.
 Plans to implement IEC 61850
 Communications Methods in use and planned for use
 SCADA/EMS/DMS/OMS procurements, new, replacement and upgrade plans for SCADA/EMS/DMS/OMS
 External assistance and third party services requirements in control center operations

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Early Survey Findings Point to Continuing Development of EMS, SCADA, DMS and OMS Capabilities during 2017-2019 among North American Electric Power Utilities

The Newton-Evans Research Company has released preliminary findings from its current study of EMS, SCADA, DMS and OMS usage patterns in North American electric power utilities, one of four component reports of the company’s global market assessment series on operational control systems.

Among the initial observations gleaned from interviews and surveys with over 60 officials from a broad range of U.S. electric utilities:

  • Plans call for upgrades or retrofits to SCADA and OMS systems among a large percentage of these utilities
  • 20% of utilities sampled plan to purchase a new or replacement DMS. 30% indicated that they have or plan on having an Advanced DMS by year-end 2019.
  • Nearly one-half of the respondents reported having real-time linkages in place between SCADA and outage management systems.
  • Third party services are being used and relied upon to assist with NERC CIP compliance issues and for the conduct of vulnerability assessments.
  • DNP 3 continues to be the most prevalent operational data communications protocol throughout North American electric power utilities. Plans call for continuing the use of DNP 3 for the foreseeable future among most of these utilities.
  • The major use of analytics tools is in outage management activities such as fault location determination.
  • More topics surveyed in this new study include: the impact of NERC CIP compliance on budgets and workloads; cyber security issues; telecommunications strategies and methodologies; distribution network model maintenance; changing organizational responsibilities for control systems; budget outlooks; and, DMS applications usage patterns.

    There have been some changes over the last few years in utility organizations with respect to control system support staff. IT departments are now the principal support group in nearly one-third of utilities sampled so far, while 47% report the “OT” organization continuing as the primary support unit. Eighteen percent indicated that both IT and OT staff share responsibility for supporting control systems. See Figure 1.

    The types of networks used for data communications from the substation to the control system vary widely, with most utilities reporting use of multiple networks for the mix of data acquisition requirements. See Figure 2.

    The North American market report is one of four volumes being produced for the company’s fifteenth series of EMS, SCADA and DMS studies published by Newton-Evans Research since 1984. Work on the other three volumes is underway; the entire series will be published during the first quarter of 2017.

    Further information on this new series The World Market Study of SCADA, Energy Management Systems, Distribution Management Systems and Outage Management Systems in Electric Utilities: 2017-2019 is available from Newton-Evans Research Company, 10176 Baltimore National Pike, Suite 204, Ellicott City, Maryland 21042. Phone: 410-465-7316. For readers interested in purchasing this new series please call or email info@newton-evans.com for special introductory pricing.

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Newton-Evans Surveys Underway

Outlook Study for HV and MV Equipment Purchasing Plans
Newton-Evans Research is conducting a study of U.S. electric utility plans for T&D equipment purchases over the coming 36 months. If you work in power transmission or distribution and specify or procure equipment, you can help the utility community by participating in the study. In turn, we will share back the findings and provide an honorarium as well. Aggregated equipment demand levels will have an influence on prices and options for capital equipment used in power transmission and distribution. The survey results will be reported only in aggregate form. Here is a link to the SM version of the survey:

https://www.surveymonkey.com/r/ElectricEquipmentPurchasePlansSurvey.

Thank You for your consideration of this request.

 

EMS/SCADA/DMS/OMS Usage Patterns and Plans – 2017-2019
Newton-Evans Research is underway with its 14th study of EMS/SCADA/DMS and OMS activities. If you are involved with utility systems operations technology and would like to participate along with more than 100 other leading utilities, please complete the online survey found here: https://www.surveymonkey.com/r/2016EMS-SCADA-DMS-OMS-Survey. In turn, we will share back the study’s findings with you, which will enable your utility to conduct internal benchmarking vis-a-vis the broader control systems user community – by type and size of utility. An honorarium will also be provided. Thank you for your consideration of this request.

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The Year in Summary (2015)

2015 was another busy year for Newton-Evans Research. Some of the studies conducted this past year covered new research topics. While our work was focused on client-commissioned studies, we obtained many insights from operational and engineering perspectives that will assist our research programs in 2016 as we once again conduct our flagship multiclient studies of protection and control, substation modernization, and operational control systems with utilities around the world. For over 30 years Newton-Evans has observed and reported on the fundamental shifts in operational systems and electric power infrastructure technology developments and usage patterns. In 2016, there will be additional changes in usage patterns, plans and outlooks among operational end engineering officials to note, both in North America and internationally.

Continue reading The Year in Summary (2015)

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The Role of ADMS/SCADA in Building a Resilient & Reliable Distribution Grid: Part 1

This is part one of a four part series on ADMS and Distribution Automation. Part one discusses Advanced DA, differences between Distribution SCADA and ADMS, market participants, usage patterns, challenges, priorities, and comments from users.

What utilities have said
Based on a mid-2014 study of the market for Distribution Automation (along with multiple earlier studies), increasing numbers of large utilities have indicated the following:

  • Integrated systems are becoming more desirable
  • Entrenched suppliers of large control systems (EMS primarily) have an “in” but often cannot provide the required component systems for an integrated approach to DMS-OMS-GIS.
  • Many mid-size utilities consider their DSCADA systems (primarily the ACS, OSI and Telvent communities) as suitable platforms for DMS/DA.
  • A high proportion of all respondents do not yet see a need for a separate DMS. This is especially true among the mid-tier utilities.
  • DMS systems can be (and most often are) implemented in a single control center that cuts across state lines in the United States.
  • Typically, operating companies under a large holding corporation operate their own DMS or DSCADA installations.

10 attributes of advanced DA
Here are the 10 attributes of an advanced distribution automation capability based on Intelligrid’s definition:

  1. Real-time Distribution Operation Model and Analysis (DOMA)
  2. Fault Location, Isolation and Service Restoration (FLISR/FDIR)
  3. Voltage/var Control (VVC/VVO)
  4. Distribution Contingency Analysis (DCA)
  5. Multi-level Feeder Reconfiguration (MFR)
  6. Relay Protection Re-coordination (RPRC)
  7. Pre-arming of Remedial Action Schemes (PRAS)
  8. Coordination of Emergency Actions (CEmA)
  9. Coordination of Restorative Actions (CRA)
  10. Intelligent Alarm Processing (IAP)

While ADMS platforms are increasingly used by Tier One utilities, many other utilities continue to rely on their DSCADA system to manage a growing portfolio of ADA functions.

Use of DMS as of Mid-2014 (Participants in Newton-Evans’ Study)

  • Just over 40% of all respondents indicated use of a DMS as of June 2014.
  • IOUs were more likely to indicate having a DMS installation than were respondents from other utility types.
  • All of the surveyed utilities have a DSCADA capability and are likely to be applying SCADA control over basic DA functions such as capacitor bank control and recloser control.

ADMS and DSCADA market participants
The total North American DMS market is made up of ADMS and DSCADA, with some overlapping providers and some different market participants in each category. Among this North America sample of large utilities, GE and ABB/Ventyx led in mentions of current ADMS installations. OSI is also a major supplier of DSCADA and ADMS installations, but their clients tend to be mid-size utilities. All of the mentions for both GE and ABB/Ventyx were made by IOU respondents.

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Electric Utility SCADA/DMS and OMS Convergence Trends

Here are some more excerpts from our latest study of the World Market Study of SCADA, Energy Management Systems, Distribution Management Systems and Outage Management Systems in Electric Utilities: 2013-2015. The information below was collected from 101 electric utilities in the U.S. and Canada between the 4th quarter of 2012 and 1st quarter 2013. The survey sample consisted of Investor Owned utilities (21%), Public Power (35%), Cooperatives (44%), and Canadian Utilities (13%).

Has your utility converged SCADA/DMS and OMS functions?
A total of 35% of utility respondents either had already converged SCADA/DMS and OMS or planned to do so by the end of 2015. Only 6% of Public Power utilities surveyed had already converged these functions, but another 21% had plans in place to do this by 2015.

Has your utility converged SCADA/DMS and OMS functions? (as of Jan. 2013)
SCADA-OMS_convergence

What functions have been converged/or plan to be converged?
Eighteen respondents said they had either converged SCADA and OMS, or planned to. Some mentioned that their SCADA reported all operations and statuses of monitored devices to their OMS, and some indicated that SCADA and OMS were less tightly integrated (for example, in some cases SCADA might only report switch/breaker status to OMS.) Here are a few of the more specific comments that were mentioned on the survey:

  • AMI system will provide customer meters out to the OMS system on a limited basis.
  • All distribution SCADA functions have been integrated with OMS/DMS through interface applications.
  • SCADA reports all operations/statuses of monitored devices to OMS
  • One way interface from SCADA to OMS (breaker & switch status)
  • Integrated platforms – smart meter “last gasp” info feeding GIS & SCADA systems which then feeds Outage Notification system
  • Topology (coloring feeder); Load Flow; Real Time Metering; Volt-VAR Control; Outage Report
  • SCADA/DMS. SCADA provides the load data to operate the DMS.
  • Multispeak connections between SCADA and OMS
  • Predicted and actual outages
  • Telvent’s ADMS product (OMS&DMS) to be installed on top of upgraded Telvent OASyS DNA SCADA system.
  • Estimated restoration times, extent of outage, number of customers

Does your utility currently have real-time linkages between SCADA and GIS or OMS?
Sixty percent of utilities surveyed did not have any real-time linkages in place as of January, 2013. About one-third had real-time linkages in place between SCADA and OMS, while just 15% had real-time linkages between SCADA and GIS.

Larger Investor Owned utilities were more likely to have real-time communications linkages in these situations. Just over half of Investor Owned utilities (52%) had real-time linkages between SCADA and OMS, and 24% had real-time linkages between SCADA and GIS. Fifty-four percent of large utilities (i.e. serving more than 1 million customers) had real-time linkages between SCADA and OMS.

Does your utility currently have real-time linkages between SCADA and GIS or OMS? (as of Jan. 2013)
real-time_linkage

More details about the topics covered in this and other studies are available on our reports page.