Utility Communications in Regional Transmission Organizations - GDS Associates

Utility Communications in Regional Transmission Organizations

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As each RTO has evolved and matured its control and market models, the required quantity of data exchanged has grown and the accuracy and reliability requirements of that data have become increasingly important. Constructing a working, reliable, secure, and cost effective communications network that provides for the needs of the RTO, the Local Balancing Authority (LBA), generation power plants, and the electric utilities is a difficult task to accomplish. In some ways, communication systems have come a long ways from the early 1900’s “cordboard”; however, electric utilities face some complex RTO communications requirements in order to exchange data as well as developing and maintaining an integrated communications system.

Constructing a working, reliable, secure, and cost effective communications network that provides for the needs of the RTO, the Local Balancing Authority (LBA), generation power plants, and the electric utilities is a difficult task to accomplish.

 

What data needs to be exchanged between each utility and the RTO ?

In order to manage and keep its transmission network stable, each RTO now requires most or all of the following data to be exchanged – every two seconds – with every connected Utility, Power Plant (POI), and/or Substation (POD) in its region:

  1. Switching Device Status (Open/Closed)
  2. Line and Transformer flow (MW and MVAR)
  3. Circuit breaker flow (MW and MVAR)
  4. Net or Gross Generation (MW and MVAR)
  5. Generation Auxiliaries (MW and MVAR)
  6. Synchronous Condenser and SVC (MVAR)
  7. Load (MW and MVAR)
  8. Bus Voltage magnitudes (kV)
  9. Tap positions of transformers and phase shifters
  10. Type II DRRs (MW and MVAR)
  11. Plant Control Mode (0, 1, 2, or 3)
  12. Generator Voltage Regulation status (On AVR, Off AVR). AVR: Automatic Voltage Regulation (Optional)
  13. Power System Stabilizer software (PSS enabled, PSS disabled) (Optional)
  14. Synchronous Condenser status (On AVR, Off AVR) (Optional)
  15. Transformer status (On AVR, Off AVR) (Optional)
  16. Shunt Capacitor/Reactor status (On AVR, Off AVR) (Optional)
  17. Net Generation Set Point (MW) (five minute interval)
  18. Generator Ramp Rates (MW/minute)
  19. Raise / Lower Output of a Generator

In addition, accumulated hourly MWh and MVARh data and hourly offer curves must be submitted daily.

How is the data exchanged between a utility and a RTO?

Each RTO has developed a set of standards by which each connected utility is required to communicate. [see Figure 2] Usually the RTO will provide:

  1. Two, high speed, point-to-point network connections (T1’s or equivalent) via two different service providers (for reliability);
  2. An Internet link for 5-minute back-up and daily data submission to each utility, and;
  3. Defined communication protocols that are used to exchange data (often ICCP as primary and XML as back-up/daily submission).

Most power plants and substations are already interconnected to a utility-wide System Control and Data Acquisition (SCADA) system through that utility’s own communications infrastructure, so most additional network connections to the RTO and required protocols are just one more piece of an existing communications network; but some aren’t. Some electric utilities and/or IPP owned power plants are still receiving their run schedules by phone, fax, and email and, for them, operating in a new, integrated market environment brings new communication challenges.

Full service electric utilities effectively operate and maintain at least three separate, internal, data networks – a business Local Area Network (LAN), a generation control LAN, and a transmission control LAN. (For security, reliability, and competitive market issues, none of them are allowed to share data directly with the others.) Also, each RTO maintains at least four different business and control models (in addition to system models developed for long range planning) to balance loads, resources, and the transmission system: a Day-Ahead / Real Time model, a commercial model, a network model, and a Financial Transmission Rights (FTR) model. Each of these RTO models needs to exchange data with one or more of the utility networks throughout the day, every day, in order for 1) the RTO to maintain network stability, 2) the connected utilities to make the adjustments to their equipment as directed by the RTO and, 3) the RTO to calculate costs for settlements.

RTO Connection Requirements for Electric Utility, Power Plant, or Load

When an electric utility, power plant or load (that isn’t already connected to an RTO) chooses to (or is required to) connect to an RTO, it must set up a highly reliable data hub and network capable of accommodating at least two independent, point-to-point data paths and an Internet connection to the RTO and redundant, independent, network connections to each plant and/or load (if not already in place). Technically, this data hub will require separate routers, firewalls, and servers for each data path and Internet connection to the RTO, secure communications with each power plant and load and must be able to 1) gather all of the required data, 2) convert it into the format and protocol specified by the RTO (usually ICCP with XML back-up), 3) send it to the RTO over secure data lines, 4) receive control data from the RTO, 5) convert it to a format the utility, plant and/or load control system can understands, and 6) disseminate the information to the various controls systems so they can react to the orders from the RTO.

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Financially, this type of data hub communications system can require a significant investment (the costs vary based on a variety of factors and options chosen) but the risks of not “hardening” the data hub include missed opportunities, “failure to perform” costs, and even fines.

The challenges of installing or upgrading an existing electric utility communications network and data center include:

  1. Working with the service providers to balance connectivity speed, reliability, and cost.
  2. Compliance with existing and planned NERC requirements.
  3. Assurance that the chosen service providers don’t install their communications lines in one common right-of-way (thus risking disruption of all connections to the data center by one mistake).
  4. Forward consideration of analog vs. digital connectivity (e.g. the FCC is considering granting permission to service providers to shut down the existing switched (analog) networks around the year 2020).
  5. Surprises in existing POTS and network connections requiring repairs and upgrades. (i.e. finding solutions to previously unresolved problems as well as addressing updated codes)
  6. High Voltage Protection (HVP) – AT&T and other communication service providers now require that a ground fault study be performed and safety equipment installed to isolate their equipment and personnel in case of a fault at the power plant or substation site.

There are three IEEE standards that apply for HVP:

  • IEEE 367, Recommended Practice for Determining the Electric Power Station Ground Potential Rise and Induced Voltage From a Power Fault
  • IEEE Std 487, IEEE Recommended Practice for the Protection of Wire-Line Communication Facilities Serving Electric Supply Locations
  • IEEE Std 80, IEEE Guide for Safety in AC Substation Grounding

While these complex networks generally enhance reliability and efficiency, they do present challenges to utilities and an effective and integrated communications plan can help utilities meet those challenges.

 

Many mature RTOs (MISO, PJM, etc.) have already evolved to the integrated market model and issued communications protocols; however, there are many RTOs and potential RTOs in the process of developing communications requirements, so it will be important for utilities to stay abreast of and/or participate in the development of these requirements. The key issues for electric utilities that are going to be operating in an RTO environment are:

1) Evaluate their existing communications networks, 2) Develop transition plans the meet their current and foreseen needs, and 3) Support the implementation of these plans either by direct project management or oversight of contractors.

In the beginning (of the electrical industry evolution), power plants stood alone, fed some distribution lines, and customers had lights, fans, and pumps – and life was simple and good. Today, most of our load requirements and power supply arrangements are managed by RTO’s through a complex communications network owned and operated by a combination of the RTO’s, communications service providers, and electric utilities. While these complex networks generally enhance reliability and efficiency, they do present challenges to utilities and an effective and integrated communications plan can help utilities meet those challenges.


For more information or to comment on this article, contact:

Transactions 414 Pic 6Hunt Armistead, Senior Project Manager | CONTACT
GDS Associates, Inc. – Austin, TX
512.541.3165