Category: SCADA

A Newton-Evans survey of 53 Distribution Electric Utilities shows that the overwhelming majority of respondents are notified of a feeder main fault via SCADA/DMS.

How are you notified of a feeder main fault event? (Check all that apply)
Ninety-four percent of respondents reported that they are notified of a feeder main fault event via SCADA/DMS. Forty-two percent said OMS is the source of this notification, and 25% indicated their DA system provides notification of a feeder main fault event. Many respondents indicated that more than one system – sometimes as many as four – all provide feeder main fault event notification.
Continue reading 94% of Electric Utilities Surveyed are notified of a feeder main fault event via SCADA/DMS

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.