By Charles W. Newton, Newton-Evans Research Co.
Nearly 150 major and mid-size electric power utilities from the United States and Canada participated in the 2008 North American control systems market study. Ninety-five percent of the respondents indicated that their respective utilities have at least one control system installed for use in operating the transmission network, distribution network, or both. More than 40 sites reported having a second control system and nine had three or more control systems installed.
Each of the investor-owned utilities (IOUs) reported having an energy management system installed as of mid-2008. Almost all utilities with 25,000 or more customers reported having a supervisory control and data acquisition (SCADA) or energy management system (EMS) in operation. A lower number of mentions were received for installations of stand-alone distribution management systems (DMSs), as most distribution utilities incorporate at least some distribution grid management functions within their SCADA systems. Only 17 percent of respondents reported having a stand-alone distribution DMS in operation.
In this study, 55 percent of respondents stated that their respective outage management systems (OMSs) are currently separate systems from EMS, SCADA or DMS. Sixteen percent stated that OMS is, or will be, integral to DMS/SCADA. Nine percent indicated plans to implement DMS as a separate system by 2010. One in five (20 percent) stated that his or her utility is not currently using and has no plans to use an OMS (see Figure 1).
IOUs likely have separate OMS installations, as indicated by 87 percent of that subgroup. This compares with 61 percent of the cooperatives, 41 percent of the public power operations and only 22 percent of the Canadian utilities. Canadian respondents, however, reported the most significant plans to offload the OMS functions from currently installed systems. Nearly one-third of the public power utilities indicated no use and no plans for use of OMS.
Protocol Usage within Substations
Nearly 80 percent of all North American participating utilities reported at least some use of distributed network protocol (DNP) serial communications protocol. DNP 3 local area network (LAN) use now stands at 38 percent among these survey participants. Modbus serial remains popular, with 36 percent making some use of this protocol, including a high 61 percent rate among IOUs. Half of the IOUs also reported some use of Modbus Plus. Legacy protocols developed mainly by EMS and SCADA vendors in years past continue to be used within the substation by about one quarter of the utilities participating in the study (and legacy protocols are still widely used for wide-area communications to and from the substation, as noted in the following section).
Plans for protocol change center on migrating from a serial to a LAN-based version of DNP 3. The outlook for field deployment or adoption of IEC 61850 is likely to remain at the “noise” level for North American utilities though 2010, based on feedback from these many utilities.
Protocol Usage Substation to External Host/Network
Protocol use for substation-to-control center and other systems continues to center on DNP 3 use, with nearly two-thirds of respondents citing use of DNP 3 serial, and now, 40 percent citing use of DNP 3 LAN. Legacy protocols remain widely deployed, with more than one-half (54 percent) citing some use of legacy protocols in their SCADA-related data transmission activities. Among IOUs, the rate of legacy protocol use is nearly 80 percent.
Transmission control protocol/Internet protocol (TCP/IP) continues to edge up in overall usage levels, with many using TCP/IP as a data transfer technology of choice.
[NOTE: TCP/IP is not a substation protocol but rather an underlying data transfer method composed of a suite of protocols for Internet/intranet use. TCP is responsible for verifying the correct delivery of data from client to server. Because data can be lost in the intermediate network, TCP adds support to detect errors or lost data and to trigger retransmission until the data is correctly and completely received. IP is responsible for moving packets of data from node to node. IP forwards each packet based on a four-byte destination address (the IP number). (See Figure 2.)
More than one-third (39 percent) suggested “maybe” in reply to whether they had plans to implement IEC 61850 beyond 2010. More than one-half (52 percent) indicated “no plans” for any of a number of listed reasons. Most important, 36 percent said they were going to continue to use other protocols. Fourteen percent indicated that the advantages of IEC 61850 were “not that great.” Seven percent replied that “some vendors have not implemented it.” Four percent considered the cost too high.
Procurement Plans for New and Replacement SCADA, DMS and EMS Systems during 2008-2010
A total of 86 sites in this survey were identified with some level of procurement activities for control system upgrades, add-ons or system replacements. A few of the respondents, however, identified recently completed procurements in their plans.
The total volume of recent or upcoming procurement activities released to Newton-Evans by this group of respondents is some $120 million. This amount represents a significantly higher level of planned spending and by more utilities than has been reported in recent surveys.
Requests for NERC CIP compliance features, tools and reports far outpolled mentions for other features, tools, applications and services mentioned by this large group of respondents. Inputs received in 2008 far outweighed in number and range the comments made in previous studies. The feedback was also clearly focused by the larger utilities as NERC compliance issues. Systems integration topics were also important to this group, with comments ranging from “true integration” to “seamless integration between our SCADA system and our new OMS” and “complete integration with OMS systems.”
There were also mentions related to service-oriented architecture (SOA), user-friendly interfaces, history data management and more information on IEC 61850 experiences.
Utility Focus on Intelligent Grid Components during 2008-2010
In a new question included in the 2008 Newton-Evans’ survey, utilities was asked to check the two most important components of near-term (2008-10) work on the intelligent grid. A total of 136 North American utilities indicated their two most important efforts during the planning horizon (see Figure 3).
Advanced metering infra-structure (AMI) led in mentions from 48 percent of the group. EMS/SCADA investments in upgrades, new applications, interfaces et al was next, mentioned by 42 percent of the group. Distribution automation was cited by 35 percent as a near-term thrust related to intelligent grid activities. GIS followed with a 30 percent mention rate. Fault detection, isolation and service restoration, a recently developed term, was mentioned by 20 percent of the group. Eleven sites (8 percent) indicated “no plans” for any near-term focus on intelligent grid activities.
There were substantial changes in intelligent grid priorities when the data was reviewed based on “numbers of customers served.” The largest utilities were likely to be investing in advanced metering infrastructure (AMI) and distribution automation in that order, while the utilities serving 100,000 to 250,000 customers placed slightly more emphasis on distribution automation than on AMI activities. Smaller utilities serving 10,000 to 100,000 customers were emphasizing GIS work during the 2008-10 periods.
Charles W. Newton is president of Newton-Evans Research Co. More information on Newton-Evans can be found online at www.newton-evans.com.
For the longer version of this article, visit www.utilityautomation.com.