Establishing links between COMTRADE, IEC 61850 and CIM

1 Overview

1.1 Scope of Report

- Scope of report- Introduction to the principle use cases of the report (Alex Apostolov)

1.2 References

[1] IEEE Standard Format for Transient Data Exchange, IEEE Std. C37.111, 1991.[2] IEEE Standard Format for Transient Data Exchange, IEEE Std. C37.111, 1999.[3] Electrical relays - Part 24: Common format for transient data exchange (COMTRADE) for

power systems, IEC Std. 60255-24 ed1.0, 2001.[4] IEEE Recommended Practice for Naming Time Sequence Data files, IEEE Std. C37.232,

2007.[5] IEEE Standard Format for Transient Data Exchange, IEEE Std. C37.111, 2013.[6] Measuring Relays and Protection Equipment - Part 24: Common format for transient data

exchange (COMTRADE) for power systems, IEC Std. 60255-24 ed2.0, 2013.[7] IEEE Standard for Synchrophasors for Power Systems, IEEE Std. C37.118, 2005.[8] IEEE Standard for Floating Point Arithmetic, IEEE Std. 754, 2008.[9] IEEE Report: Schema for Phasor Data Using the COMTRADE File Standard

2 Use cases

Describe the use cases – what shall be achieved

2.1 Principle use case – post event analysis

(Deepak Maragal / Mansour Jalali)

- of events that require records from one location- of events that require correlation (including time) of records from geographically

dispersed locations (note that for this, the direction of the power flow needs to be defined; this needs to be captured by the use case)

2.2 Backfilling of lost information due to communication outage

In a hierarchical architecture of a Synchrophasor data collection and analysis system, Synchrophasor data is typically archived in 3 locations, namely:

1. The PMU itself – typically trigger based storage with record size being a function of available memory in the PMU

2. Intermediate Phasor Data Concentrators (PDC). The PDC should typically be able to archive 30 days of streaming Synchrophasor data

3. Super PDC – typically located at Energy Management System locations (EMS)

In the hierarchical flow of synchrophasors, data is sent from the PMU to the PDC and then from the PDC to the the Super PDC. Given a communication failure between the PDC and the Super PDC, as may occur during a disaster scenario, the dynamic state of the power system may not be communicated between the PDC and the Super PDC. In as much as it is desirable to know the state of the power system during this outage time, a mechanism is desired to recover the missing data stream items. Of note, the existing IEEE C37.118.2 Data Streaming protocol does not presently have a mechanism to request the streaming of old data.

It is proposed that missing data in the Super PDC due to a communication failure be made up via a File Transfer from the PDC to the Super PDC via a COMTRADE file per the Schema defined in [9] above. The process would be one of:

Identifying the time range of the missing data Creating the COMTRADE file over the identified range Transferring the file via an agreed-to file transfer mechanism (e.g. – FTP, SFTP, MMS)

Note that is it also possible to create a client-server/SQL based mechanism to retrieve missing records. Agreement on the access method between the PDC and the Super PDC is required to enable this functionality.

2.3 Power system model validation (dynamic, static and transient)

(Alex Apostolov / Deepak Maragal)

2.4 Post Event Analysis of synchrophasor data (visualization, …)

Synchrophasors provide a dynamic view of the performance of the power system and, as such, can provide valuable insight into the performance of the grid during a disturbance. Some of the various display and analysis options are presented here:

Since a Synchrophasor is a complex number, the display of the value can be decomposed into Magnitude and Angular strip charts (see figure 1). View of the magnitude can indicate voltage depressions or overcurrents.

Mapping the data to a physically-based contour surface can provide a wide-area view of the performance of voltage, current, power, and frequency over a wide area. An example of such is shown below. Note that the relative angle of the data is depicted through the use of color. (see figure 2)

Figure 1: Strip View of Synchrophasor Data

Figure 2: Example of Contour Mapping of Synchrophasor Data

The magnitude and angle of a Synchrophasor can be easily visualized through the use of a Polar Plot (see figure 3). Most specifically, the voltage and current values from multiple locations can be seen on a single polar plot. Animation of the synchrophasors during a disturbance can provide intuitive insight into how the power system changed during a disturbance as well as details on the length of the disturbance. Mathematical analysis of the Synchrophasor angles and rate of change of angle can provide additional insight to a disturbance

Conditions and disturbances on the electric power grid can result in oscillations due to either resonance or mechanical generator swings (see figure 4). Visualization tool can be

used to display these oscillations and analytical tools (such as Fourier Analysis) can compute the frequencies of oscillation, the magnitude of the oscillation, and the damping constants related to the oscillation. There are conditions where there is negative damping of oscillations and early detection of such will be required in the future.

Figure 3: Visualization of Power System Oscillation

2.5 Fault location based on COMTRADE file analysis

Power quality monitors, digital fault recorders, digital relays, and other Intelligent Electronic Devices (IEDs) in transmission and distribution substations are able to trigger on fault events and record voltage and current waveforms. There may be an automated substation data management or data concentration system that gathers data from multiple intelligent devices in the substation. Many of these systems may provide the measurements in a common data format interface such as COMTRADE for the central system. Collection of the COMTRADE files is typically performed via TFTP, 61850 GetFile, or SFTP.

The central monitoring data management system communicates with the individual IEDs or the substation aggregators to gather the voltage and/or current waveform samples and related disturbance information such as breaker positions and time stamps. The central monitoring system may be triggered to download COMTRADE files because of a notification from the remote system, or the central system may be programmed to poll for new COMTRADE files on a regular schedule (for example, once every ten minutes or once per hour).

The fault analysis application queries the operations database, which may be stored using the Common Information Model (CIM) to identify line breaker operations that could be related to the fault. The application therefore attempts to identify the specific line that was faulted.

If the fault is a transmission event, the fault analysis application may interrogate the lightning detection system database to identify lightning events in the timeframe of the fault event. Lightning events with appropriate time stamps and within a geographic window of transmission lines could be identified for possible correlation with the fault. This requires coordination with the GIS database of transmission lines in CIM.

If the fault is on a transmission system, such as in Figure 4, the fault analysis application may obtain an extract from the real-time SCADA representation of the system (CIM) and uses this to update a short circuit model of the transmission system. An iterative solution of the updated short circuit model may be performed to identify the most likely fault type and location (along the specific line identified above if available). If this model is not available, then the fault analysis application may perform a single-ended or double-ended fault location estimate using methods described in IEEE Std. C37.114, IEEE Guide for Determining Fault Location on AC Transmission and Distribution Lines. Note that P-Class Synchophasors can be used in the computation of fault location via double-ended fault location algorithms.

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SLG Fault Measured in a Transmission Substation

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Figure 4: SLG Fault Measured in a Transmission Substation

If the fault is on a distribution system, then the fault analysis application will perform an estimate using a single-ended impedance or reactance calculation based on the measurement recorded by an IED at the substation. See Figure 5, which presents waveform samples recorded from a substation bus that shows significant zero-sequence current during the fault. Figure 6 presents waveform samples for the same fault measured on the feeder itself.

Some systems attempt to perform a distribution fault location estimate using a circuit simulation.

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SLG Fault in a Distribution SubstationBus Current

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Figure 5: Single-Line-to-Ground Fault Measured in a Distribution Substation – Bus Current

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SLG Fault in a Distribution SubstationFeeder Current

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Figure 6: Single-Line-to-Ground Fault Measured in a Distribution Substation – Feeder Current

A message can be sent to the transmission or distribution operator and other parties with the estimated fault location and fault type.

Figure 7: Example Fault Location Map showing Estimated and Actual Fault Location for a Distribution Line Fault. Map courtesy of United Illuminating Company

Through a web-based link, the operator can view the expected fault location as a layer on a GIS map of the transmission or distribution line, illustrating most likely location for the fault, such as the map shown in Figure 7. If the event is related to transmission, the display also indicates lightning events that could have been related to the fault with their data.

2.6 Condition monitoring / Analysis based on COMTRADE records of condition related information

In order to monitor the condition and performance of the circuit breaker in the power system, important information such:

- Breaker contact travel - Hydraulic pressure - SF6 gas density - Trip1,Trip2 and Close coils status and actual currents

- Auxiliary DC supply voltage - Trip/Close commands - AC 3 phase currents - Spring charge if (applicable)- Ambient temperature- Local control cabinet temperature - Contact wear- Aux Contact mismatch

An anslysis of the IEC 61850 models finds these data items modeled in:

XCBR (Circuit Breaker) SCBR (Cikrcuit Breaker Supervision) SIMG (Insulation Medium Supervision Gas) SIML (Insulation Medium Supervision Liquid) SOPM (Swich Operation Mechanism).

One specific item is interest is the integral of the arcing current across the contacts of the circuit breaker The method is commonly known as I 2t or contact breaker wear is equal to =

∫t=tarcing

t=currnet extiguis h

I 2dt.

The I 2t calculation is rough approximation of the actual interrupter wear, especially if the start of the integration is not accurately determined. This value is typically computed inside the IED but is may be externally estimated byt using the information available in the COMTRADE file for the event. In as much as the start of arcing current in not known, an estimate should be provided to the IED when calculated therein.

As breaker actuator monitors evolve, it is expected that sample value datasets from an operation would be included in the output COMTRADE file from an IED.

Figure 8 presents an overview of the logical relation between an arbitrary condition monitoring device and disturbance recorder and protection logical devices.

Figure 8: Utilizing COMTRADE file in the CB Condition Monitoring

This diagram model the contact wear calculation is performed by using the information obtained from the COMTRADE file generated by configured disturbance recorder.

It should be noted that the information recorded by disturbance recorder can also contain other CB condition information such as number of operation (as an XML Data Item in the Header area, and coils current and mechanism motion information. The model presented in figure 1 is limited to the main I^2.t .

2.7 System simulation and testing replaying COMTRADE information

Given that event information and data samples are captured in a COMTRADE file, the ability to analyze results of that event can now proceed through several means:

1. Test Set Analog Playback: In this mode, a test set with analog amplifiers is connected to test inputs (1A/5A/120V) inputs of the IED or Merging Unit. This test mode would be used when looking to validate the complete path of an analog signal. When testing in this manner, the IED should be placed in Test Mode to identify the data accordingly and to prevent unintended trip outputs (unless connection to the trip coil is part of the test)

2. Dataset Playback – as migration to Merging Unit technology becomes more pervasive, Sample Set playback units will be used to interface with the IED and to re-transmit samples of data through the Process Bus. Again, marking the data as Simulation is required

3. Virtual Analysis – as protection and control algorithms are developed today, they are typically tested in simulation programs such as Matlab. Captured COMTRADE datasets can be interfaced with Matlab and fed into the respective algorithms and results analyzed.

2.8 Correlate COMTRADE data with any information recorded elsewhere like e.g. weather data

(Arvind Chaudhary)

2.9 Use of COMTRADE files for analysis of voltage sag

A voltage sag is a short duration voltage variation associated with a reduction in voltage that may cause disruption of the operation of certain types of equipment. Voltage sags are due to short-duration increases in current, typically due to faults, motor starting, or transformer energizing. Voltage sag events occur at any location in the power system with a frequency of occurrence between several times to hundreds of times per year.

IEEE Std. 1159-2009, Recommended Practice on Monitoring Electric Power Quality, provides definitions for five terms related to rms variations: voltage sags (which also known as voltage dips), voltage swells, voltage interruptions, undervoltages, and overvoltages. IEEE 1159 suggests that voltage sag, voltage swell, and voltage interruption events should usually be used in conjunction with a modifying prefix to signify the duration of the event (i.e., instantaneous, momentary, or temporary).

Figure 9 presents the voltage and current waveform samples for a voltage sag measurement recorded during a two-phase fault that evolves into a three-phase fault. The waveform samples were recorded at a sampling rate of 128 points per cycle by a power quality monitor. The waveform samples were stored in an IEEE COMTRADE file by the software used to download the measurement from the power quality monitor. Figure 10 presents the rms values derived from the waveform samples. Most voltage sag analysis focuses on characteristics that can be derived from the rms values such as minimum rms voltage, maximum rms voltage, and duration of samples below voltage sag thresholds. Figure 11 presents a voltage sag measurement recorded during a two-phase fault. This measurement was recorded by a relay digital protection relay that did not provide waveform samples as well. The relay provided rms voltage and rms current samples four times per cycle.

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Voltage Sag Measurement Recorded during a Two-Phase Fault that Evolves into a Three-Phase FaultWaveform Samples

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Figure 9: Waveform Samples for Voltage Sag Measurement Recorded during a Two-Phase Fault that Evolves into a Three-Phase Fault

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Voltage Sag Measurement Recorded during a Two-Phase Fault that Evolves into a Three-Phase FaultRMS Samples

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Figure 10: RMS Samples for Voltage Sag Measurement Recorded during a Two-Phase Fault that Evolves into a Three-Phase Fault

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Voltage Sag Measurement Recorded during a Two-Phase Fault RMS Samples

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Figure 11: Voltage Sag Measurement Recorded during a Two-Phase Fault

IEEE P1564, Draft Guide on Voltage Sag Indices, provides methods for computing voltage sag indices and characteristics. This guide provides equivalent methods for computing indices and characteristics concerning voltage swells. Methods are presented for quantifying the severity of individual rms variation events, for quantifying the performance at a specific location (i.e., single-site indices) and for quantifying the performance of the whole system (i.e., system indices). Different methods are presented for each of these. This guide does not recommend the use of a specific set of indices, but instead presents the method for calculating specific indices when such an index is used. The large variation in customers sensitive to voltage sags and network companies supplying them makes it impossible to prescribe a specific set of indices. Instead this guide aims at assisting in the choice of index and ensuring reproducibility of the results after a certain index has been chosen.

To give a value to the performance of a power system in terms of voltage sags, IEEE P165 recommends a five-step procedure:

1. Obtain voltage waveform samples.2. Calculate characteristics as a function of time from the sampled voltages, such as rms

voltage versus time. 3. Calculate single-event characteristics from the event characteristics. Examples include

retained voltage and duration, voltage sag energy, voltage sag severity, and characteristic voltage.

4. Calculate site indices from the single-event indices of all events measured during a certain period of time. Examples include SARFI indices, voltage sag tables, voltage sag energy, and voltage sag severity.

5. Calculate system indices from the site indices for all sites within a certain power system. System indices an be computed

These five steps are discussed in more detail in IEEE P1564 and are summarized in Figure 12. In the previous list, IEEE COMTRADE can be used to provide either the voltage waveform samples required for Step 1 or the rms samples computed in Step 2.

Figure 12: The IEEE P1564 procedure for obtaining voltage sag system indices

2.9.1 SARFI Indices

SARFI is an acronym for the System Average RMS Variation Frequency Index. It is a power quality index that provides a count or rate of voltage sags, swells, and/or interruptions for a system. The size of the system is scalable; IEEE P1564 indicates that it can be defined as a single monitoring location, a single customer service, a feeder, a substation, a group of substations, or for an entire power delivery system. There are two types of SARFI indices: SARFI-X and SARFI-Curve. The index basically provides the rate of events where the minimum rms voltage of a voltage sag is below a specified threshold.

SARFI-X corresponds to a count or rate of voltage sags, swell and/or interruptions below a voltage threshold. For example, SARFI-90 considers voltage sags and interruptions that are below 0.90 per unit, or 90% of the reference voltage. SARFI-70 considers voltage sags and interruptions that are below 0.70 per unit, or 70% of the reference voltage. In contrast, SARFI-110 considers voltage swells that are above 1.1 per unit, or 110% of the reference voltage. The SARFI-X indices are meant to assess short-duration rms variation events only, meaning that only those events are included in its computation with durations less than the minimum duration of a sustained interruption as defined by IEEE Std 1159 which is one minute.

SARFI-Curve corresponds to a rate of voltage sags below an equipment compatibility curve. For example SARFI-CBEMA considers voltage sags and interruptions that are below the lower CBEMA curve. SARFI-ITIC considers voltage sags and interruptions that are below the lower ITIC curve. Lastly, SARFI-SEMI considers voltage sags and interruptions that are below the lower SEMI curve. These curves again limit the duration of an rms variation event to the minimum duration of a sustained interruption as defined by IEEE Std 1159, which is one minute.

Figure 13 presents an example chart showing a trend of SARFI-70 at a single substation monitoring location. It shows the rate of voltage sags in which the remaining voltage was 70% of nominal or below. The rate shown for each month is an average for that month and the eleven months that preceded it. It demonstrates the cyclical nature of voltage sag rates from year-to-year. Figure 14 presents a trend of SARFI-70 for another substation showing a downward trend in the one-year moving average.

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SARFI Event Rate by Month (One-Year Moving Average)From 1/1/2006 to 1/1/2012

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Figure 13: Example SARFI-70 Chart Showing Annual Variation

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Figure 14: Example SARFI-70 Chart Showing Downward Trend

2.9.2 Voltage Sag Tables

A commonly used method of presenting the performance of a site is by means of a voltage sag table. The columns of the tables represent ranges of voltage sag duration and the columns represent ranges of retained voltage. Each cell in the table gives the number of events with the corresponding range of retained voltage and duration. Each event (that is, each combination of retained voltage and duration) is tabulated in only one cell of the table. Different values are in use for the boundaries between the cells.

A voltage sag table can be used as a system index as well as a site index. Strictly speaking, a voltage sag table is not an index but a way of presenting a set of indices. Each element in the table can be used as an index, just like there are multiple choices for the SARFI indices.

A distinction between short-duration interruptions and other voltage sags is made already when defining the range of retained voltages. In case short-duration interruptions are treated differently from other voltage sags, the lower row of the table should start at 1% or 10%.

IEC 61000-4-11 Ed. 2.0 recommends the following duration values for the testing of equipment against voltage sags and short interruptions: 0.5 cycle, 1 cycle, 10/12 cycles (200 ms), 25/30 cycles (500 ms), 250/300 cycles (5 seconds), and the following magnitude values: 0%, 40%, 70%. Use of these values as the borders between cells results in the voltage sag table shown in Table 4. Note that 0% has been replaced by the more practical value of 10%. Table 1 presents the rows and columns of the summary table.

Table 1: Example Voltage Sag Table Defined in IEC 61000-4-11

Retained RMS Voltage

Duration of the Voltage Sag

< 1 cycle 1 cycle-200 ms

200-500 ms

0.5-5 s 5 s

70-80%

40-70%

10-40%

10%

3 Introduction to the relevant standards and reports

3.1 COMTRADE

3.1.1 Evolution of comtrade standard

3.1.1.1 1991 Standard

The need for a common format for transient data exchange became clear in the late 1980s, as different providers of digital fault recorders (DFRs) continued to develop proprietary formats, programs, and methods of operation. The COMTRADE standard developed in 1991 specifically aimed to realize a common format for all providers to benefit the users. After COMTRADE was published, most of the major providers developed programs for converting their own proprietary data into COMTRADE. This was a considerable step forward but resulted in more programs for users to operate and produced new compatibility issues depending on the interpretation of the requirements of the standard.

3.1.1.2 1999 Standard

Other devices, like digital relays, became capable of recording transient data and the pure use of fault recorders began to decline. Subsequently, this broadened the use of COMTRADE and added to the variations in standard interpretation and indentified areas of needed improvement in the standard. Other industries were also found to be using COMTRADE for non-power system recordings and playback which put pressure on the standard to be improved.

The Power System Relaying Committee kept close track of this evolution and delivered a revised IEEE COMTRADE standard in 1999. The main objective of the revised standard was to reinforce the basic concepts of transient data representation and to accommodate a growing set of innovative discoveries such as “dynamic sampling” and “information files”. International acceptance of COMTRADE was achieved throughout the industry during this period and resulted in IEC adopting the revised COMTRADE standard in 2001.

3.1.1.3 2003 Northeast Blackout

On August 14, 2003, a large part of the northeastern United States and part of Canada experienced a blackout that affected over 50 million people and took many days to fully restore the system. NERC collected thousands of transient data files from many of the utilities involved. The collected files revealed two fundamental problems that seriously affected the investigative process:

- the collected files were in multiple formats, many of which were proprietary, and- the collected files did not share a common naming convention: which made it difficult

to discern both which files came from particular utilities and also which files were captured by particular devices.

Fortunately, tools were available to successfully convert the files into COMTRADE and to rename them under a common naming convention (as now defined in IEEE Std. C37.232, 2007) COMNAMES.

Today, both formats are required under NERC Std. PRC-002-2 (Standard for Disturbance Monitoring and Reporting Requirements). Nonetheless, the investigation did also expose a number of weaknesses in the COMTRADE-1999 standard. The main weaknesses are:

- the lack of a formatted field for specifying whether the time tags were based on local time or were based on UTC (Coordinated Universal Time or UTC without offset is called “Zulu” time),

- the lack of a common set of formatted fields for specifying whether the time tags were properly synchronized or not, and

- the lack of a combined file format resulting in added complications of managing and keeping track of up to 4 separate files for each COMTRADE record.

These weaknesses are addressed by the new 2013 IEEE/IEC Dual Logo COMTRADE Standard.

3.1.2 2013 IEEE/IEC dual logo COMTRADE standard

Since 2002, two Power System Relaying Committee working groups (H5D and H4) have been actively collecting lessons learned, developing solutions, and carefully revising the original text of the 1991 and 1999 standards, an effort which has resulted in the 2013 IEEE/IEC Dual Logo COMTRADE Standard. The standard contains a number of useful additions and revisions including:

- a number of new fields and data types designed to support the standard’s growing use and expanding scope specifically INT32 datatype which is supporting the output of IEC 61850 sampled values,

- a new single file structure designed to simplify the management and tracking of large quantities of COMTRADE records,

- revised text that removes a number of obsolete restrictions, such as on the restriction of filenames to 8 characters, Current naming practices, such as the COMNAMES format, allow for filenames of up to 253 characters in length but recommend the use of no more than 64 characters to ensure compatibility across various types of operating systems, and

- some of the non-crtical fields in the configuration section have been made critical for better conformity and use of the data in the COMTRADE file.

3.1.2.1 The New Fields in the Configuration File/Section

A number of new fields have been added to the configuration file. The new fields are:

Time Code: The Time Code field is used to specify the time difference between local time and UTC without offset. The field is restricted to a maximum of 7 formatted characters. The first character is a sign character and is followed by up to 5 characters for indicating the time difference (which includes up to 2 digits for the hours followed by the letter “h” followed by 2 digits for the minutes). A few examples are shown below: The time difference will also reflect whether standard time or daylight savings time was in affect at the time of the recording.

Local Code: In the event that the date and time stamps in the COMTRADE record are set to UTC without offset (meaning Time Code is 0), then the Local Code field can be used to identify the local time zone where the record was captured. The Local Code format is in the same format as the Time Code field. The code “x” means such information is not applicable.

Time Quality: The Time Quality field is used to indicate the maximum time error between the recorded time stamps and the time from the synchronizing source (such as a GPS clock). The field corresponds to the Time Quality indication code defined in IEEE Std. C37.118. The field is composed of a single hexadecimal digit.

Leap Second: The Leap Second field is used to indicate that a leap second may have been added or deleted during the recording resulting in either two segments of data having the same Second of Century time stamp or having a missing second:

3.1.2.2 The New Data Types

The standard supports two new types of binary data formats for use with the COMTRADE data file. The new data types are named “Binary32” and “Float32”. Characters from the Unicode UTF-8 Standard are also allowed. Any occurrence of the terms ASCII or Text in the standard also inherently implies Unicode UTF-8. The new data types are:

Binary32 Data: Is a new Binary data type format designed to represent 32 bit integer numbers according to the 2’s complement system.

Float32 Data: Is a new Binary data type format designed to represent 32 bit real numbers according to the IEEE Std. 754-2008 [8].

The additional data types represent a change that is in line with modern technologies and provide more flexibility in representing data in its original form, eliminating a conversion step.

3.1.2.3 The New File Structure

The 1999 COMTRADE standard file structure defines 4 types of files for each COMTRADE record. The 4 files are: header, configuration, data, and information. The files share the same name but have different extensions (HDR, CFG, DAT, and INF respectively). The header and

information files are optional, although the header file is frequently used. It is difficult to keep track of, manage or exchange, COMTRADE records when each record is composed of multiple files. It is especially difficult when dealing with massive amounts of records.

The 2013 IEEE/IEC Dual Logo COMTRADE standard file structure supports a single file for each COMTRADE record, although the four separate files are still maintained for backward compatibility. The single file structure combines the original 4 files (as is) under one file. The combined or single file format is identified by the CFF file extension. The use of the new CFF format is strongly recommended in the 2013 IEEE/IEC Dual Logo COMTRADE standard. The new file structure has a number of advantages including:

- simplifying the management, archiving, and exchange of COMTRADE records,- reducing the total number of files by an average factor of 3, and- allowing for the potential use of COMTRADE as a standard format for recording

transient records and not just for exchanging them.

The CFF format is composed of four separate sections. The sections are separated by ‘---‘ separator like XML tags (Extensible Markup Language). The sections are organized in the following order with ‘---‘ separator between sections:

--- file type: CFG ---The configuration file contents (.CFG file)--- file type: INF ---The information file contents (.INF file)--- file type: HDR ---The header file contents (.HDR file)--- file type: DAT ASCII --- OR--- file type: DAT BINARY:702 ---The data file contents (.DAT file)

The number ‘702’ after the word ‘BINARY’ indicates the number of bytes in the BINARY data.

3.1.2.4 Obsolescence

The text of the 2013 Dual logo standard is updated to match with technologies of today relating to digital data storage and transfer media. Also, restrictions related to the number of characters in filenames have been improved to match with the IEEE C37.232 standard of 2007.

3.1.3 Future Trends

In addition to the revisions described in the previous sections, the IEEE COMTRADE working group has considered a number of other suggestions, including support for Synchrophasors, support for user defined channels, and support for a new format based on XML descriptions of COMTRADE fields and data types.

The working group has produced a 25 page report listing the details for representing COMTRADE in XML. Initial attempts at using the new format exposed two basic concerns:

- The size of the resulting XML file is much larger than the size of an equivalent data file saved in the standard format. The difference in the data file size is more than 116 additional characters per line, and the difference in the total number of lines is 5 fold, and

- The readability and editability of the configuration file is substantially degraded when using an ASCII editor. However, if an XML editor is used, the opposite is true.

Defining an efficient and agreeable XML format requires an extensive effort and is best addressed by the formation of a new working group dedicated to this issue.

The development of the COMTRADE standard has spanned almost two decades of work and the standard is considered the premier format for exchanging transient data records. The 2013 IEEE/IEC Dual Logo COMTRADE standard provides a number of advantages over the earlier standard including the simplified management and tracking of COMTRADE records, due to the availability of single file format. Other advantages of the 2013 IEEE/IEC Dual Logo COMTRADE standard include the support for a wider range of applications, due to the new fields and data types. These new parameters may lead to the use of COMTRADE as a standard format for recording, and not only for exchanging, transient data records. In the future, more advantages will also be realized in a future standard for the global audience.

3.2 CIM

Energy Management Systems (EMSs) are used by utilities to analyze and control the reliability of the high-voltage electric transmission system. In order to accomplish this task knowledge of the power system topology is required. Typically, this information is stored in a proprietary format or database layout. In the interconnected “grid” environment, there is an ever increasing need for power companies to exchange power system topological information on a regular basis. This exchange facilitates the reliable operation, through appropriate power flow/state estimation calculations, of the interconnected power networks owned and operated by many different utilities. Initially, the Common Information Model (CIM) was developed to allow utilities to perform this type of information exchange between EMSs. This suite of standards was designated as IEC 61970.

Figure 15: General Topology Relationships of IEC 61970

The concept of CIM has been expanded beyond the original usage for transmission system model exchange for EMS and now includes:

- Distribution, Assets, and Back-Office Applications. The Back-Office Applications include, but are not limited to: Metering, Outage Management Systems (OMS); Customer Information Systems (CIS); Work Management Systems(WMS); and Geospatial Information Systems (GIS): This suite of standards is designated IEC 61968.

- Energy Markets: This suite of standards is designated as IEC 62325.

Additionally, the CIM standards go beyond information modeling and specify information exchange interface standards. These standards currently address standardization for: XML file exchange, XML message generation, and exchange implementation profiles for messages via Web Services or Enterprise Service Bus technology.

3.3 IEC 61850

3.3.1 Overview

IEC 61850 is a series of standards that consists of multiple parts. The title of IEC 61850 is “Communication Networks and Systems for power utility automation”. Currently, IEC 61850 applies to communication between equipment of the following domains:

- Substation protection, automation and control- Wind power plants- Hydro power plants- Distributed energy resources.

IEC 61850 specifies the communication interfaces, information models of the equipment and devices and a configuration language used to exchange configuration information between tools from different manufacturers.

The major documents of the IEC 61850 standard are shown in Figure 16. The semantic data model of a domain is standardized as logical nodes with data objects (IEC 61850-7-4xx). The structure of the data objects is based on common data classes (IEC 61850-7-3). The models and services for the information exchange are defined as abstract communication service interface (IEC 61850-7-2). In the mapping it is defined how these services are realized with communication protocols (IEC 61850-8-1 / -9-2). The system configuration is described with standardized files based on the system configuration language (IEC 61850-6).

Figure 16 – The major parts of the IEC 61850 standard

For the purpose of this report, two elements of IEC 61850 are of interest:

- The semantic data model defining standardized identifications and structures for any kind of information from the power system.

- The description of the power network topology of a substation including the possibility to link instances of information from the data model to the point in the power network where the information belongs to.

3.3.2 The semantic data model

The core element of the information model is the logical node (LN). A logical node can be considered as a basic container of related functional data of any definable element. Logical nodes represent a function’s information as defined by its data and data attributes. There are two basic kinds of logical nodes:

- Logical nodes representing information of the primary equipment (e.g. Circuit breaker – XCBR or current transformer – TCTR). These logical nodes implement the interface between the switchgear and the substation automation system.

- Logical nodes representing information of substation automation functions. Examples are any kind of protection functions (e.g. distance protection – PDIS) or the measurement unit – MMXU.

As an example of data, the logical node TCTR has a data attribute AmpSv representing the sampled value of the current waveform measured in a current transformer. Or another example, the LN MMXU has a structured data object A where the calculated RMS values for the phase currents are available; e.g. A.phsB is the current of phase B. The logical nodes are defined e.g. in

IEC 61850-7-4 as a class. For representing a concrete current measurement, an instance of a logical node MMXU needs to be created. This is done as part of the data model of the IED that provides the information.

To model a disturbance recorder, IEC 61850 defines three logical nodes. These LNs are used to configure the settings of the disturbance recorder; the recorded data shall be available as a COMTRADE file.

- RDRE: Disturbance recorder function- RADR: Disturbance recorder channel analog- RBDR: Disturbance recorder channel binary

With these logical nodes, a disturbance recorder can be modeled as shown in Figure 17. For each channel, an instance of the logical node RADR or RBDR is required. These logical nodes contain all channel specific settings and information if that specific channel has triggered. The logical node RDRE is required once. This logical node contains the global settings and information concerning the status of the recorder and the required control, e.g. to clear the memory of the recorder.

Figure 17 – principles of modeling a disturbance recorder in IEC 61850

3.3.3 The power network topology

The system configuration language described in IEC 61850-6 allows creating a standardized XML file that describes the configuration aspects of an IEC 61850 system. Such a file describes several elements:

- The electrical topology of the substation.

- The collection of all the IEDs in the system including the description of the data models of these IEDs. So basically, it describes a hierarchical list of all the information that is available from the system. The information is structured according to IEC 61850 in logical devices, logical nodes and data with the data attributes.

- The communication parameters and the configured information exchange.

The file describes as well the link between an instance of a logical node from an IED to the topology of the substation. With this, it is possible to associate any information, e.g. a calculated rms value of the phase B current to the place in the substation, where it has been measured.

3.4 IEEE file naming convention C37.232

There are several types of files collected by IEDs that contain time stamps to identify “when” the contained data was captured. These types of files are collectively known as Time Sequence Data (TSD) files. With the knowledge that a Time Stamp exists in all these files, an IEEE standard has been created for the naming of these files. This Standard is called: C37.232- IEEE Recommended Practice for Naming Time Sequence Data Files. This Standard / Recommended Practice uses the time, date, and other information of the data and its source in the file to name the file. Specifically, a C37.232 file name is constructed as follows:Start Date, Start Time, Time Code, Station ID, Device ID, Company Name,User 1, User 2, User 3, and so on .Extension

Where:Start Date is the data on which the recording was started and is in the format: YYMMDD where YY is the year – starting at 2000 MM is a number from 01 to 12 and DD is the day of month from 01 to 31. Note that a recording can span multip days

Start Time is either the time of the first sample in the file or the trigger time (see Time Code below) and is in the format: HHMMssmmmuuu where HH is the hours from 00 to 23; MM are the minutes from 0 to 59 and ss are the seconds from 00 to 60 (to accommodate Leap Second); mmm are the milliseconds and UUU are the microseconds. The Time Stamp is given in Local Time

Time Code – is used to specify the offset from Local Time to UTC and whether the Time Stamp refers to the Start of the file or to the Trigger time stamp (the letter “t” is appended to the Time Code to indicate Trigger time. A “-5” Time Code would indicate UTC – 5 or typically Eastern US Standard Time.

Station ID – a UFT based8 name of the originating station of the data. The name should be unique within the utility

Device ID – a UTF8 based name for the recording device in the station

Company Name – a UTF8 name for the utilihy. Any combination of characters can be used for the name. In North America, the 4 character NERC Company Identifier is recommended

It is noted that the IEC61850 Device Naming Convention could be parsed to fill these categories. In the next revision of C37.232, it is recommended that the IED 61850 LD Name of the recording device be considered as an option for file naming.

User 1 to n – these are extended fields that can be used to describe additional information about the TSD file such as:

Location via Latitude and Longitude Event Duration

Initiating Event (e.g. A-G Fault)

The extension used on the file can be determined by the file creation tool. When used with COMTRADE files, the COMTRADE extensions of *.CFG, *.HDR, *.INF, *.DAT, and *.CFF should be used. Additionally, standard Windows file extensions such as *.exe, *.bat,*.dll and other known extensions should be avoided.

The total number of characters in the file name can be up to 253 characters on most operating systems, however, a practical limit of 64 characters is recommended as this is the maximum name size that can be created on a writable CD.

An example of a file created on August 9, 2000 at 17:52:15.183 Local Time in Station sta80 on device Ben717 on the NYISO system would be:

000809,175215183,-4,sta80,ben717,nyiso.cfg

3.5 IED Naming (H10)/ Delimiter issues

COMTRADE, IEC 61850, CIM and other standards require that devices have names, but offer little guidance in how the names should be determined. PSRC WG H10 proposed a naming convention for both the devices and their channels. The proposed format is composed of a sequence of fields using the underscore “_” as the delimeter between the fields. That naming convention is:

Company ID _ Station ID _ IED Type _ Voltage Level _ Equipment Type _ Relay Panel _ Relay House _ Function Type _ Phase ID _ Input Type

Where:

Company ID is the identification of the company owning the substation. Station ID is the identification of the substation containing the IED. IED Type is the type of the IED (such as a numerical relay, DFR, or data concentrator). It

should be unique within the substation or protection scheme. For instance, if two SEL421 relays are used to protect a feeder, one IED Type could be SEL421-A, the other SEL421-B.

Voltage Level is the kV or company identifier for the voltage level(s) of the item(s) being monitored by the IED channels.

Equipment Type is the item being protected or monitored by the IED or channel. This is typically a feeder, breaker, transformer, or generator name.

Relay Panel identifies the relay panel where the IED or channel is located. This is a physical location and is useful for protection and maintenance engineers.

Relay House identifies the relay house where the IED or channel is located. This is a physical location and is useful for protection and maintenance engineers.

Function Type is the C37.2 function designation for the protection scheme and may also include additional information such as first or second line protection (primary or backup).

Phase ID is the identification of the phase(s) or could be the identification of the control circuit being monitored.

Input Type is formatted as follows: A = alternating input such as three phase currents and voltages, and D = direct input such as frequency, temperature, and trip signatures.

The relationship between the device and its channels is dynamic. If the device is monitoring many different entities such as a DFR, then the device name would be at a fairly high level (through IED Type) and its channels would be more descriptive of the monitored entities. A relay on the other hand would have the monitored entity described in its name (through Function Type) and its channels would describe only the currents and voltages it monitored. Following are a couple of examples:

CoA_Stn42_321_345_Fdr42_12_A

(Company A, Station 42, 321 relay, 345kV, Feeder 42, Panel 12, House A)

CoA_Stn42_DFR72_345

(Company A, Station 42, DFR number 72, 345kV)

3.6 COMFEDE

COMFEDE (IEEE Std C37.239-2010) is a format for files containing event data such as sequence of events or fault summary reports collected from power systems or power system models. The format is declared as an XML schema. It has the following characteristics:

1 the format is compatible with the Log format defined in IEC 61850-7-22 it contains information, named Location, about where the recorded event(s) come from3 each recorded event has additional data (Payload data) associated with the event, .e.g. the

name of the recorded COMTRADE files that may have been trigged by the event

The "Location" element in COMFEDE identifies the IED that recorded the event(s). It consists of the IED name plate as well as the station name, the voltage level and the bay name the IED may be associated with. It means that an IED and its recorded events cannot be directly associated with a conducting equipment such as a breaker. It neither can be directly associated with a measurement point within the station such as a voltage transformer or a current transformer. Indirectly, the bay name can give an indication on the concerned equipment, e.g. Line 1.

3.7 Time stamping

3.8 H8 report "Schema for phasor data using the COMTRADE file standard", Approval Date May 13, 2010

Synchrophasor data is used both in real-time from direct transmission and after the fact as recorded data. The SYNCHROPHASOR standard, C37.118, describes a real-time data transmission format but does not define a format for recorded data exchange. Several formats have been used for exchange of such data, most notably the PhasorFile (also known as “dst”) data format pioneered in the WECC and supported by Bonneville Power Administration users. While a number of users have created recording and reading software for this format, it is not supported

as a recognized standard by a standards organization. It is preferable that data be recorded in a recognized standard format so that tools, methods, and data can be exchanged world wide.

The IEEE COMTRADE standard is a file format designed for time series data that is established world wide and is supported by standards making bodies. It has a significant number of recording parameters that can be adapted for phasor data. The H8 Working Group of the IEEE Power System Relaying Committee (PSRC) developed a schema for using the COMTRADE format for recorded phasor data by making synchrophasor specific assignments to the standard COMTRADE parameters. The parameters are used in the standard, prescribed manner, but with specific uses which allow some automatic (machine) processing. This schema is available for use with the 1999 version of COMTRADE and has also been adapted to the new COMTRADE version currently near completion.  The schema is available as a PSRC working group report and can be accessed at:

http://www.pes-psrc.org/Reports/Schema_for_Phasor_Data_Using_the_COMTRADE_File_Standard.pdf

4 Relations between the standards

4.1 CIM/61850 – Need for harmonization / unification

CIM, specifically IEC 61970, has information that overlaps with information in IEC 61850. There are two (4) main areas where the overlaps occur:

- Electrical System Connectivity/Topology: Both IEC 61970 and IEC 61850-6 have information models that specify the topological connectivity of Power System Resources (PSRs).

Both use the concept of Terminals and Connectivity Nodes to establish the electrical connectivity between PSRs.

- Power System Resource (PSR) semantics and naming: In many instances, the names and semantics associated with those names are the same. However, in some cases there are differences:

o Semantic Differences (a limited list):

Current Transformers (CTs) are modeled as a one-port device (e.g. it is modeled to not conduct electricity. In 61850, a CT is modeled as a two-port device.

o Substation batteries are currently modeled as “loads” in CIM. In 61850, they are assumed to be power supplies.

Obviously, these semantic differences need to be reconciled. But do not impact the use of PSR usage in the naming of COMTRADE channel information.

o 61850 have more PSR definitions that CIM, although this is changing as CIM is being revised. The following diagram shows the overlap and the 61850 specific PSRs are shown in yellow.

o The CIM Dynamics package (e.g. the modeling construct that all Asynchronous/Synchronous machines are Rotating Equipment) creates issues for IEC 61850 and CIM usage for Distributed Energy Resources (DERs) such as Photo Voltaic (PV), Fuel Cells, and others. There is an effort ongoing to resolve this semantic issue.

- Measurements: Both CIM and 61850 have the logical construct of Measurements.

CIM has named Measurement instances are associated to PSRs. Each Measurement instance can have one or more named MeasurementValue (MV) instance associated to it. These MV instances represent the logical value that is the Measurement. The reason to allow multiple MVs is that CIM allows the modeling of multiple IED sources to provide the measurement of the same quantity. In CIM, the names of the Measurement and MeasurementValue instances are not standardized and are left to user definition.

61850 associates semantically rich Logical Node definitions/instances with PSRs. In general, the 61850 DataObject could be viewed as an equivalent naming construct to CIM Measurements. With the actual DataAttributes representing the naming construct to CIM MeasurementValues.

- Intelligent Electronic Devices (IED): Both CIM and 61850 have a concept of communicating field equipment. However, the SCADA package of CIM semantically

defines only a RemoteUnit (e.g. modeled as a Remote Terminal Unit). The semantic definition of IED, in 61850, is much richer. However, the harmonization activity allows an IED to be a specialization of RemoteUnit.

There is no naming convention specified in CIM. However, there are strong naming conventions specified in 61850:

Figure 18 appears to be becoming the recommended naming information for the North American Synchrophasor project. The information shown is useful to as a template of what information needs to be exposed when using CIM and 61850 to name synchrophasor COMTRADE channels.

Figure 18: Proposed Synchrophasor Information for NASPI (extracted from PNNL-SA-80496)

However, neither CIM nor 61850 has the concept of a Company. The closest construc that CIM supports is GeographicalRegion and SubGeographicalRegion. It is the SubGeographicalRegion that has a relationship to either Line or Substation.

Figure 19: CIM containership and measurement relationships

Based upon the information in Figure 19, the suggested information needed to name a synchrophasor would be based upon three distinct hierarchies: substations, lines, and plant related measurements.

Figure 20: Proposed Synchrophasor Namespace Hierarchy

When it comes to the Measurements and Measurement Values, it would be recommended to make use of IEC 61850 FCDA naming for the Measurement without the IEC 61850 LogicalDevice name being present. It is also recommended that Analog synchrophasor measurements be of the MMXU LogicalNode class per IEC TR 618509-90-5 as a basis. It would be also recommended that the LDName, for the MeasurementValues, be IED based.

Figure 21: LDName construction per IEC 61850-6

Based upon the namespace and Measurement/MeasurementValue naming, using the combination of CIM and 61850, the mapping to COMTRADE definitions would be as follows:

- “station_name”: It is recommended that the station name value be constructed from the CIM namespace that starts at GeographicalRegion through Substation, Line, or Plant. It is further recommended that each level of the namespace hierarchy be separated by a “_”

- “rec_dev_id”: Specifies the recording device. It is recommended that this be preferably the LDName from which the COMTRADE channels are generated.

- “ch_id”: The channel ID represents the actual measured value. Since the LDName can be found in rec_dev_id, the ch_id is recommended to contain the name of the FCDA.

- “ph”: The phase identification, if applicable should be one of the phase abbreviations from IEC 61850-6 (e.g. A, B, C, N, all, none,AB,BC, and CA).

- “ccbm”: The circuit component being monitored should start with a prefix of “Line_”, “Sub_”, or “Plant_” in order to indicate which namespace hierarchy is being employed. After the “_”, the name of the component, which is also in the “station_name” value, would be present.

The values used for the names GeographicalRegion and SubGeographicalRegion is flexible and may need to vary based upon country or other organization (e.g. the European Union). Therefore, there is a need in the COMTRADE configuration file to give an indication as to the naming hierarchy and naming authority that has assigned the names for GeographicalRegion and SubGeographicalRegion. Currently there is no mechanism to define the naming conventions/hierarchy being used within the *.CFG file. It is recommended that a mechanism similar to an XML namespace be utilized. It is also recommended that for standardized hierarchies, such as the one proposed, an XSD or CIM profile is provided to define the hierarchy of the namespace.

Additionally, in regards to the COMTRADE standard itself, the following recommendations need to be evaluated:

- The size of the station_name field should be increased and support UNICODE instead of ASCII. The recommended field size would be 255 UNICODE characters.

- If UNICODE support is supported, the file(s) where Unicode is present need to be able to specify the UTF format being utilized.

Definitions

Term Definition from IEC 61970

GeographicalRegion A geographical region of a power system network model.

SubGeographicalRegion

A subset of a geographical region of a power system network model.

Substation A collection of equipment for purposes other than generation or utilization, through which electric energy in bulk is passed for the purposes of switching or modifying its characteristics.

VoltageLevel A collection of equipment at one common system voltage forming a switchgear. The equipment typically consist of breakers, busbars,

instrumentation, control, regulation and protection devices as well as assemblies of all these.

Line Contains equipment beyond a substation belonging to a power transmission line.

Plant A Plant is a collection of equipment for purposes of generation.

4.2 Report H5c – Link between COMTRADE and IEC 61850

In January 2008, the WG H5c published "Report on a common data format for IED sampled data". In this report, definitions of "sampled data" from three international standards have been compared and the relations between the standards have been shown. These standards are: COMTRADE - IEEE Std C57.111-1999, PQDIF - IEEE Std 1159.3-2002, and IEC-61850.

As part of this report, relations between COMTRADE and IEC 61850 are described. The models for disturbance recording have been designed taking into considerations COMTRADE. IEC 61850 defines logical nodes (LN) for the configuration of a disturbance recorder (see chapter 3.3.2). The data attributes in these logical nodes reflect the configuration parameters from the COMTRADE configuration file. There are two different ways to have the information from a COMTRADE configuration file in IEC 61850 available:

(1) The information is contained in a data attribute of a LN. In that case, the information can be read and optionally be written while the device is in operation using the communication services of IEC 61850-7-2. The values of the data attributes can as well be available in the SCL.

(2) The information is only available in the SCL file of the substation. In that case, the information cannot be retrieved at run time from the device using communication services defined in IEC 61850-7-2.

Currently, the IEC 61850 LNs only configuration parameters; descriptive information that is available as well in COMTRADE configuration file is not yet available. However, in the report from H5c, extensions have been proposed to the IEC 61850 LNs for that purpose. The following table extracted from the H5c report provides an overview on the information in the COMTRADE configuration file and the place where that information can be found in IEC 61850 taking into consideration the proposed extensions.

COMTRADE configuration file

IEC 61850 data model

Station name The information can currently not be directly found in the data model. However, it can be retrieved from the substation section of the SCL file.

Identification of device The information can currently not be directly found in the data model. However, it can be retrieved from the IED section of the SCL file.

Revision A new attribute in the RDRE logical node is proposed to handle the year of COMTRADE standard used, e.g. 1991, 1999, etc.

Number and type of channels Indirectly through the number of instances of LNs RADR and RBDR.

Line frequency From one of the related LN TCTR/TVTR. The related LN TCTR/TVTR can be found through the substation section of SCL.

Sampling rate Sample Rate in Hertz. (If zero, time stamp of ChTrg is used for COMTRADE conversion.)

Time stamp of first data value and trigger point

Use time stamp of ChTrg of the individual channel LN that triggered together with PreTmms of that channel; if no individual PreTmms per channel, use PreTmms of LN RDRE

Data file type New data proposed: Ft in RDRE LNTime stamp multiplication factor for data file

New data proposed: TmMult in RDRE LN

For each analogue channelChannel no RADR.ChNum.setValPhase The information can currently not be directly found in the

data model. However, in the substation section of the SCL file, the association between a logical node instance (i.e. the channel) and the single line diagram can be made.

Circuit component Same as phaseUnits and scaling New data proposed: AnVal in RADR LNSkew New data proposed: AnSkew in RADR LN.Min / max values In the data type of RADR LNPrimary / secondary ratio DO Rat and VRtg/ARtg of related LN TCTR/TVTR. The

related LN TCTR/TVTR can be found through the substation section of SCL.

Indication if value is primary IEC 61850 assumes that values are always primary values

For each binary channelChannel no RBDR.ChNum.setValPhase See above for analogue channelCircuit component Same as phaseNormal state of channel New data proposed: ActSt in RBDR LN

With the proposed extensions of IEC 61850, a lossless data conversion between IEC 61850 and COMTRADE would be possible.

5 Implementing the use cases

5.1 Requirements analysis of the use cases

This chapter analysis the use cases from chapter 2 with regard to the information requirements related to IEC 61850, COMTRADE and CIM.

Process Info IEC 61850 COMTRADE CIM

2.5 Fault locationCurrent / Voltage measurements for a particular line

Samples for current and voltage associated to the line; Channel configuration for analog disturbance recorder channels associated to the current and voltage samples

COMTRADE files with these analogue channels

Waveforms stored and associated to the substation / line

Breaker positions Breaker position SOE associated to the breaker in the single line; Channel configuration for binary disturbance recorder channels associated to the current and voltage samples

COMTRADE file with these binary channels

SOE for position stored and associated to the substation / breaker

Geographical routing of line

Geographical information of line segment

- How can the use cases be realized with the standards

- What needs to be added to the standards

6 XML version of COMTRADE config file including the topology information

As the use of COMTRADE grows, additional features and functions have been identified and are summarized here for future consideration in the next revision of the standard:

Support for variable size fields

o The transmission of Sample Values from Merging Units typically includes a 13 bit Quality flag whereas the data samples are transmitted in 32 bit Integer format. Optimztion of the COMTRADE file format is needed in order to be able to optimize the storage of (effective) 16 bit and 32 bit integers in the same file

XML data support.o As identified in this report, it is desirable to include report items in a

COMTRADE file (e.g. – breaker operation count). This can be accomplished by establishing an XML data section in the document (e.g. an XCT section for XML COMTRADE)

COMTRADE Schemao Provide the ability to detect file format errors

Identification of the Active Setting Group Support for Digital Signal quality

o Quality flag attached to a Digital Input Multi-language support

o Unicode-based descriptions Support for Sparse Data

o Define the ability to integrate sample data and measured data at different rates True XML format

o Support for Bast64 in the data file Support for Complex numbers

o Synchrophasors Incorporation of the IEEE Synchrophasor Schema report

o Harmonic Integrationo Other complex numbers

7 Migration

- A COMTRADE revision is needed to implement the identified upgrades- A report is needed on how to integrade COMFEDE with 61850

8 Recommendations for further work needed

- Recommendations on new standards development or on extensions to existing standard (Alex Apostolov)

- Recommendations on best practice in applying these standards