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A Closer Look at the Changing Russian Electric Power Industry

Russia is the world’s third largest consumer of energy, and as such the country has announced plans and programs to modernize its energy infrastructure, especially for the nation’s power sector. Currently, the Russian national power grid includes more than 230 GW of production capacity. The country’s utilities are known as energos. These energos operate more than 31,000 T&D substations located throughout multiple regions and time zones. There are almost 800 large scale power plants in the country, including 15 nuclear sites operating some 35 reactors. Seven new nuclear units are now under construction as of mid-2017.

The world’s Tier One power equipment manufacturers each have a position in the Russian market for generation transmission and distribution. Each has made significant multi-hundred million-dollar (and some, multi-billion dollar) investments in the country. Cumulatively, the Tier One providers along with other very large equipment manufacturers from Asia and a few non-Russian Eastern European suppliers account for as much as 75% of all capital equipment used in the electricity sector today (Newton-Evans estimate). However, for lower cost MV equipment and for automation components, there is a growing presence of in-country manufacturers and suppliers, as well as important roles being played by market participants from China, India and other Asian countries, especially for electronic devices.

In terms of smart grid computer applications, there are a host of Russian companies providing integration and installation services, as well as developing a wide range of smart grid applications either to work in conjunction with systems being provided by the likes of ABB, GE-Alstom, Siemens and Schneider Electric.
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Midpoint Of 2017 North American Study Finds Increase In Substation Construction And Retrofit Plans Over 2014 Findings

The Newton-Evans Research Company has reached the midpoint of its triennial tracking study of change and automation occurring in the world’s electric power substations.

As of August 7, more than 50 major US and Canadian utilities have submitted their survey responses to Newton-Evans staff. A summary of some key interim findings in this 30-part survey process are as follows:

Impediments to Substation Automation
There are no impediments currently being viewed as major hurdles to implementing substation automation for either new or existing HV and MV substations. Most respondents at the midpoint of the North American study have indicated some mild-to-moderate concerns with eight of the “potential obstacles” listed on the survey form, including security concerns, insufficient staffing levels, lack of funding and not having a solid business case for further substation automation

Substation Construction Plans
North American respondents to date have indicated plans for construction of hundreds of new HV and MV substations in their service areas by 2020. Hundreds more substation are planned for retrofits over the same outlook period. The findings surpass the outlooks of earlier Newton-Evans tracking studies.

Control Logic in RTUs
About 30% of North American respondents to date have indicated some use of control logic in their substation RTUs. Another 14% plan to have control logic integrated into RTUs by 2020. Control logic is currently being used among North American utilities for alarm logic and transfer trip schemes – important for renewables power flows, opening and closing breakers and operation of field devices.
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Upcoming Early Autumn Conference Participation

After a brief summer hiatus, away from energy industry events, with the successful IEEE Power and Energy Society event recently completed, and this not being a CIGRE year, the summer lull in conferences has taken hold until early September.

Then things start getting busy, with dozens of electric power and related energy conferences scheduled for the September-November months.

Newton-Evans’ Chuck Newton has speaking roles at three upcoming conferences over a three-week period on three different – but related – topics.

First, at the upcoming EMMOS (Energy Management and Market Operations Systems) conference being held in New Orleans (September 17-20) Chuck will brief attendees on “Grid Modernization from an Energy Policy Perspective” on Monday, September 18. http://emmos.org/

Two days later (September 20) Chuck will speak in Auburn, Alabama on “Communications Trends in Utility Operations” at the annual “Auburn Conference” (aka the Southeast Distribution Apparatus School and Conference). http://utilitytech.org

On October 4, speaking at the SCADA Technology Summit in Denver, Colorado, Chuck will keynote the conference with a talk on “North American Market Trends and Technology Advances in SCADA, Substation Automation and Protection and Control.” www.scadatechsummit.com

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Early Survey Findings Indicate Continuing Growth in Substation Modernization Investment

Substation Data Communications Protocol Usage Continues to Find Heavy Reliance on DNP3 in North America

July 18, 2017, Ellicott City, MD. The Newton-Evans Research Company is well underway with its triennial tracking study of change occurring in the world’s electric power substations entitled: The World Market for Substation Automation and Integration Programs in Electric Utilities: 2017-2020. The study will compare the new round of research findings with several earlier substation modernization tracking studies conducted by the company since 1986. More than 75 large and mid-size North American electric power utilities will be participating in this multi-part study, before the focus turns to surveying the International community of electric power utilities in August.

Newton-Evans Research will estimate and forecast the 2017-2020 outlook for North American spending for substation automation and integration programs. Earlier estimates derived from the similar 2013 study stood at $690 million, with an overall potential North American market size of nearly $10 billion. Global potential spending for substation modernization programs had been estimated at about $38-$40 billion. This amount includes spending for a wide range of intelligent substation-resident equipment and devices and the manpower to undertake the systems integration efforts required.

Preliminary Observations:

  • It is becoming more difficult to separate substation product classifications as equipment manufacturers tout their offerings as “multifunctional” and the product positioning of many intelligent electronic devices now cuts across multiple product classifications.
  • The outlook for increased reliance on commercial services providers working in substation modernization activities remains strongly positive. Third party engineering and integration service firms have continued to make significant strides in winning substation automation-related business, from planning to design to construction and to technical equipment installation.
  • Utility manpower shortages and funding issues continue to negatively impact the ability of technology supplier companies to engage utilities for other than short-term automation requirements. In states and provinces wherein regulators have approved strong incentives for reliability improvements or for transmission line extensions, the spending outlook is robust, despite a lack of clarity in some energy policy development activities of federal U.S. agencies.
  • In general, retrofit substations will be upgraded as warranted during the outlook period, based on regional load growth, load criticality to customers, and related distributed generation and renewables siting developments. New substations will increasingly be designed and constructed as integrated and automated remote assets for the utility. The current study finds the bulk of available substation automation budgets likely to be spent for new substations, with continued emphasis on the bulk power system.
  • The use of encryption techniques for transmission of substation data continues to grow, at least for wide area data exchanges between control centers and substations as evidenced by early survey returns received by Newton-Evans. This continues a long-term pattern of increased use of encryption for sensitive data communications between and among intelligent devices within the substation and from the substation to the control center.

Additional topics being covered in the four-volume series of substation automation studies include in-depth coverage of several data communications topics, vendor security certification requirements, external systems linkages to the substation, preferred equipment suppliers, substation timing requirements, and an assessment of how North America’s electric power substations are positioned along a three-step path to complete automation.

Additional information on the North American substation market report, and the other three reports comprising the four-volume study “Worldwide Market for Substation Automation and Integration Programs in Electric Utilities: 2017-2020” is available from Newton-Evans Research Company, 10176 Baltimore National Pike, Suite 204, Ellicott City, Maryland 21042. Phone 1-410-465-7316, email: info@newton-evans.com. For a brochure on this series, download our brochure: http://www.newton-evans.com/brochures/2017SSABrochure-June2017.pdf

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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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Newton-Evans Study Indicates Similarities in Plans for Full Digital Substations and Differences for Condition-Based Maintenance Programs Among Electric Utilities

Newton-Evans Research Company continues to assess findings from its six-month research study and survey of protective relay usage patterns in the world community of electric power utilities. Insights received from 114 large and mid-sized utilities in 28 countries point to some interesting differences in plans for implementation of the “full digital substation” concept and to increased use of condition-based maintenance (CBM) strategies for protective relays.

Implementation of the “Full Digital Substation” Concept:
Thirty-four percent of the survey respondents from the U.S. and Canada agreed with the statement, “By year end 2018, we will be well on our way toward implementing the full digital substation concept.” Thirty-seven percent disagreed with the statement. Forty percent of small North American utilities (fewer than 100,000 customers) agreed with the statement, but only 18% of large utilities (more than 500,000 customers) concurred.

Forty-three percent of the international respondents agreed with the same statement, which is slightly more than what was observed in North America (34%). Twenty-five percent had no opinion, and another 25% disagreed. Importantly, the typical international utility respondent was somewhat larger (in terms of customers served) than their North American counterpart.

“By year end 2018, we will be well on our way toward implementing the full digital substation concept”

Continue reading Newton-Evans Study Indicates Similarities in Plans for Full Digital Substations and Differences for Condition-Based Maintenance Programs Among Electric Utilities

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Newton-Evans Study Finds Differences in Spending Plans for Electric Utility Control Systems Over the 2017-2019 Years

Nearly half of North American electric utilities participating in the 2017-2019 Newton-Evans Research study plan to upgrade or retrofit their SCADA system by 2019. Twenty-two percent plan to upgrade or retrofit their energy management system (EMS), and twenty-five percent will upgrade or retrofit their outage management system (OMS). Twenty-six percent of North American utilities in the survey sample are adding a new or replacement distribution management system (DMS) or advanced DMS by 2019.

In comparison to the North America survey sample, a greater percentage of international utilities surveyed plan to install new or replacement systems for EMS, SCADA and OMS. A greater percentage also plan to upgrade and/or retrofit systems across the board. Twenty-nine percent of international survey respondents plan to replace or install new EMS or OMS systems by the end of 2019. Sixty-four percent will upgrade or retrofit their existing SCADA systems, and 36% will upgrade or retrofit their DMS or OMS systems by year end 2019.

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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.