The World Market Study of SCADA, Energy Management Systems, Distribution Management Systems and Outage Management Systems in Electric Utilities: 2013-2015 (Volume 1) North American Market Survey and Analysis

  • ID: 2503355
  • Report
  • Region: Global, North America, United States
  • 138 Pages
  • Newton Evans
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This publication is Newton-Evans Research Company's tenth major in-depth international research program on supervisory control and data acquisition (SCADA) systems, energy management systems (EMS), distribution management systems (DMS), and Outage Management Systems (OMS).

The four volume series measures current market size and offer projections on a world region basis through the year 2015. It includes a North American Market Survey and Analysis, International Market Survey and Analysis, World Market Assessment and Forecast, and SCADA/EMS/DMS/OMS Supplier

Profiles for major companies.

The world regions included in the research publications are the North American, European, Latin American, Middle East, Mediterranean, African and Asia Pacific markets. The series provides a comprehensive and informative report on the control systems usage patterns and plans of electric utilities around the world.

Key Issues Addressed

- 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 2015, along with protocol requirements.

- Have utilities converged SCADA/DMS and OMS functions?

- Cyber security concerns if EMS/DMS or DMS/OMS are combined.

- Plans to implement IEC 61850 beyond 2015.

- Utility use of or plans to implement a separate outage management system (OMS) and/or a generation management system (GMS) by year-end 2015.

Sample Survey Topics

- Extent of use of SCADA, EMS and DMS systems by the world's electric power utilities.

- New applications of interest to electric power operations management teams.

- SCADA/EMS/DMS/OMS procurements. New, replacement and upgrade plans for SCADA/ EMS/DMS.

- External assistance and third party services requirements in control center operations.

- Choice of communications protocols within substation, & from substation to external EMS/SCADA/DMS host network.

- Current and planned external linkage requirements of for SCADA/EMS/DMS systems.

Research Methods

Chief operations and chief engineering personnel were the principal source of information for this program of the world electric power market for SCADA, EMS and DMS systems in electric utilities.

The field survey work is conducted using several primary research methods including personal interviews, e-mail, mail and fax surveys, with telephone follow-up conducted by Newton-Evans staff and research partners. Discussions and information exchanges with international suppliers provide additional market insight.

Newton-Evans has established business partner centers in Western Europe, Latin America, Russia, China and the Middle East. This development provides an ideal opportunity to conduct global research programs for the energy industry.

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VOLUME 1:

Introduction

Survey Findings

1. Current and future use of EMS, SCADA, DMS and OMS systems

2a. If your utility has a DMS, does your EMS/SCADA group also support DMS?

2b. If your utility has an OMS, does your EMS/SCADA group also support OMS?

3a. Do you have any interest in combining EMS and DMS on a common platform?

3b. Do you have any interest in combining DMS and OMS on a common platform?

3c. Do you have cyber security concerns if EMS/DMS are combined?

3d. Do you have cyber security concerns if DMS/OMS are combined?

4a. Has your utility converged SCADA/DMS and OMS functions?

4b. What functions have been converged/or plan to be converged?

5a. Does your utility currently have real-time linkages between SCADA and GIS or OMS?

5b. Are there any cyber-security concerns that you had to overcome?

6a-1. Current and planned use of protocol(s) within the substation

6a-2. Current and planned use of protocol(s) from the substation to external EMS/SCADA/DMS host/network

6b. Plans to implement IEC 61850 beyond 2012?

6c. If your utility isn't planning to implement IEC 61850, why not?

7. Communications method(s) used to connect SCADA system to substations

8. External assistance or third-party services needed for the following control center activities

9. Approximate number of RTUs, PLCs, etc. currently installed/planned to be installed

10. If your utility has a DMS/SCADA combined system, does the SCADA functionality and network modeling stop at the distribution substation level or does it reach all the way to the service transformers?

11. Number of points scanned by SCADA (Transmission, Distribution, and Generation)

12. Number of power flow buses in EMS systems

13a. With regards to As Is Engineering to Operations Integration (GIS to DMS/OMS) model maintenance, how do distribution circuit designs move from GIS to DMS in your current processes?

13b. With regards to DESIRED Engineering to Operations Integration (GIS to DMS/OMS) model maintenance, how do distribution circuit designs move from GIS to DMS in your current processes?

14. Usage and plans to deploy some form of analytics by YE 2015

15. Level of agreement/disagreement with the following statements

16. Fully integrated system with embedded applications, or third party applications ported onto system?

17. All applications provided up front, or only purchase needed applications and port others later?

18. Is your EMS/SCADA group responsible for hardware server maintenance?

19. For which of the following applications does your utility use synchrophasors?

20a. Significance of budget increases due to NERC CIP or other regulatory compliance efforts

20b. Significance of work load increases due to NERC CIP or other regulatory compliance efforts

21. With experienced personnel leaving the workforce due to retirements, how is your utility able to maintain a “Qualified Support Staff” for EMS/SCADA systems?

52 22. Comments, suggestions for new features, tools, applications or services needed or expected from EMS/SCADA/DMS vendors

57 Findings from Questions Asked on Previous EMS/SCADA/DMS Surveys

57 Use and plans to implement a separate generation management system (GMS) by Y-E 2012

58 Use and plans to implement a separate outage management system (OMS) by year-end 2012

59 Current/future plans for linking (via data link or RTU) your EMS, SCADA, and/or DMS to other systems

61 Does your utility plan to “self-fund” any Smart Grid initiatives?

61 Ranking of relative importance of Smart Grid components on a scale of 1-9, where 1=“most important” and 9= “least important”. Use each number only once.

63 Which of the following DISTRIBUTION MANAGEMENT SYSTEM functions and applications does your utility use or plan to bring on-stream by year end 2012?

66 Which of the following ENERGY MANAGEMENT SYSTEM functions and applications does your utility use or plan to bring on-stream by year end 2012?

66 Which of the following OUTAGE MANAGEMENT SYSTEM functions and applications does your utility use or plan to bring on-stream by year end 2012?

68 Which of the following DISTRIBUTION ANALYSIS functions and applications does your utility use or plan to bring on-stream by year end 2012?

69 Level of agreement/disagreement with the following statements relative to EMS/SCADA/DMS procurements/vendors

71 Detail Tables

List of Participating Utilities

Questionnaire

List of Figures

Fig. i – Utility Respondents by Type

Fig. ii – Proportion of Types of U.S. & Canada Electric Utilities According to the U.S. DOE and PLATTS Directory 2011

Fig. iii. Use and Plans for EMS, SCADA, DMS or OMS

Figure 1a-1 Types of Systems In Place

Figure 1a-2 Mentions of EMS/SCADA/DMS and OMS Vendors

Fig. 1a-3 Mentions of EMS/SCADA/DMS/OMS Vendors (Overall)

Fig. 1b Future needs for new, replacement systems and upgrades, retrofits to existing systems

Fig. 1c Estimated Budget Range for new, replacement systems and upgrades, retrofits to existing systems

Fig. 2a. If your utility has a DMS, does your EMS/SCADA group also support DMS?

Fig. 2b. If your utility has an OMS, does your EMS/SCADA group also support OMS?

Fig. 3a. Do you have any interest in combining EMS and DMS on a common platform?

Fig. 3b. Do you have any interest in combining DMS and OMS on a common platform?

Fig. 3c. Do you have cyber security concerns if EMS/DMS are combined?

Fig. 3d. Do you have cyber security concerns if DMS/OMS are combined?

Fig. 4a. Has your utility converged SCADA/DMS and OMS functions?

Fig. 5a. Does your utility currently have real-time linkages between SCADA and GIS or OMS?

Fig. 5b. Are there any cyber-security concerns that you had to overcome?

Fig. 6a-1. Current and planned use of protocol(s) within the substation

Fig. 6a-2. Current and planned use of protocol(s) from the substation to external EMS/SCADA/DMS host/network

Fig. 6b. Plans to implement IEC 61850 beyond 2014?

Fig. 6c. If your utility isn't planning to implement IEC 61850, why not?

Fig. 7. Communications method(s) used to connect SCADA system to substations

Fig. 8. External assistance or third-party services needed for the following control center activities

Fig. 10. If your utility has a DMS/SCADA combined system, does the SCADA functionality and network modeling stop at the distribution substation level or does it reach all the way to the service transformers?

Fig. 13a. With regards to “As Is” Engineering to Operations Integration (GIS to DMS/OMS) model maintenance, how do distribution circuit designs move from GIS to DMS in your current processes?

Fig. 13b. With regards to DESIRED Engineering to Operations Integration (GIS to DMS/OMS) model maintenance, how do distribution circuit designs move from GIS to DMS in your current processes?

Fig. 14. Does your utility currently have or plan to deploy some form of analytics by YE 2015?

Fig. 15. Relative to your power delivery control systems, please check your level of agreement/disagreement with the following statements

Fig. 16. Does your utility prefer a fully -integrated system with embedded applications, or third party applications ported onto system?

Fig. 17. Does your utility prefer all applications to be provided up front, or only purchase needed applications and port others later?

Fig. 18. Is your EMS/SCADA group responsible for hardware server maintenance?

Fig. 19. For which of the following applications does your utility use synchrophasors?

Fig. 20a. Significance of budget increases due to NERC CIP or other regulatory compliance efforts

Fig. 20b. Significance of work load increases due to NERC CIP or other regulatory compliance efforts

List of Tables

Table i. Use and Plans for EMS/SCADA or DMS

Table 1a-1. Types of systems in place

Table 1a-2. Mentions of EMS/SCADA/DMS vendor (by type of system)

Table 1b. Plans for New/Replacement, Upgrade/Retrofit, or “No Plans”

Table 1c. Estimated Budget Range

Table 2a. If your utility has a DMS, does your EMS/SCADA group also support DMS?

Table 2b. If your utility has an OMS, does your EMS/SCADA group also support OMS?

Table 3a. Interest in combining EMS and DMS on a common platform

Table 3b. Interest in combining DMS and OMS on a common platform?

Table 3c. Concerns about cyber security if EMS/DMS or DMS/OMS are combined

Table 4. Has your utility converged SCADA/DMS and OMS functions?

Table 5a. Does your utility currently have real-time linkages between SCADA and GIS or OMS?

Table 5b. Are there any cyber-security concerns that you had to overcome?

Table 6a-1. Current and planned use of protocol(s) within the substation

Table 6a-2. Current and planned use of protocol(s) from the substation to external EMS/SCADA/DMS host/network

Table 6b. Utilities planning to implement IEC 61850 beyond 2012 (that have not already implemented it)

Table 6c. Reasons for not implementing IEC61850

Table 7. Communications method(s) used to connect SCADA system to substations

Table 8. External assistance or third-party services needed for control center activities

Table 9. Approximate number of RTUs, PLCs, bay controllers, etc. currently installed/planned to be installed in EMS/SCADA/DMS systems Table 10. If your utility has a DMS/SCADA combined system, does the SCADA functionality and network modeling stop at the distribution substation level or does it reach all the way to the service transformers?

Table 11. What is the (approximate) total number of points scanned by SCADA (includes Tx, Dx, and Gx)?

Table 12. What is the (approximate) total number of power flow buses in your EMS system?

Table 13a-1 through 13a-4. With regards to AS IS Engineering to Operations Integration (GIS to DMS/OMS) model maintenance, how do distribution circuit designs move from GIS to DMS in your current processes?

Table 13b-1 through 13b-4. With regards to DESIRED Engineering to Operations Integration (GIS to DMS/OMS) model maintenance, how do distribution circuit designs move from GIS to DMS in your current processes?

Table 14. Does your utility currently have or plan to deploy some form of analytics by YE 2015?

Table 15. Relative to your control systems, please check your level of agreement/disagreement with the following statements

Table 16. Preference for either a fully integrated system with the applications embedded in the control system platform, or the applications sourced from third parties and ported onto the base SCADA platform

Table 17. Preference for either all of the applications provided upfront, or the option of purchasing only the applications needed initially and port the others as needed

Table 18. Is your EMS/SCADA group responsible for hardware server maintenance?

Table 19. For which of the following applications does your utility use synchrophasors?

Table 20a. What level of budget increases has your utility experienced due to NERC CIP or other regulatory compliance efforts?

Table 20b. What level of work load increases has your utility experienced due to NERC CIP or other regulatory compliance efforts?
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