I/F –R Receives data from the remote end and gives the data to the local relay CB Disconnects the protected line from other system Circuit breaker Use cases: Data sampling and filtering
General
For the purpose of communication between substations, the following functions are considered
Conventional current transformers (CTs) and voltage transformers (VTs) are typically used as inputs to relays in various applications However, these traditional devices can be effectively replaced by advanced technologies, such as digital inputs utilizing process bus systems, without altering the fundamental operational descriptions.
Distance line protection with permissive overreach tele-protection scheme
When a distance relay identifies a forward fault within the overreach zone, it transmits a permissive signal to the remote end If the remote relay receives this permissive signal, it subsequently sends a trip signal to the local circuit breaker (CB).
RO Overreaching trip function, must be set to reach beyond remote end teminal
Teleprotection equipment Duplex communication link TX
Figure 1 – Distance line protection with permissive overreach tele-protection scheme [1] 3)
3) Figures in square brackets refer to the Bibliography
The permissive signal requires a minimum of 1 bit, increasing to 3 bits for phase segregated signals, and up to 6 bits when both phase-to-phase and phase-to-earth are independent Additionally, directional earth fault detection may necessitate an extra bit Data transmission occurs solely upon the detection of a forward fault, and contingency plans must be in place for communication channel failures To ensure fast tripping, the propagation delay should be minimal, ideally under 5 ms Furthermore, high reliability is essential, with a bit error rate (BER) of less than 10^{-6}, and provisions for alternative routes and duplication are recommended.
Measuring equipment Measures current and voltage from protected line
The Comm I/F –S interface collects data from the local relay and transmits it to the remote end, while the Comm I/F –R interface receives data from the remote end and delivers it to the local relay.
CB Disconnects the protected line from other system
Name Services or information provided
Data sampling and filtering Samples current and voltage data from measuring equipment and filters them Data sending Calculates a distance to the fault using filtered data
When a distance protection detects a forward fault, the distance protection sends the permissive signal to Comm I/F –S (the remote end) Data receiving Receives the permissive signal from Comm I/F –R
(the remote end) Relay decision When the distance protection detects the forward faults and receives permissive signal from remote end, the distance protection issues a trip command to the CB
Distance line protection with permissive tele-protection scheme
Distance protection begins by receiving current and voltage measurements from specialized equipment It then samples these analog values and converts them into digital data To ensure accuracy, distance protection employs a digital filter to eliminate any unwanted frequency components from the sampled data.
Step 1 Distance protection stores the filtered instantaneous data
Distance protection utilizes filtered data to calculate the distance to a fault Upon detecting a forward fault within a predetermined distance, it sends a permissive signal to the Communication Interface - S, which then transmits the information to a remote end relay.
Step 1 Comm I/F –R receives the data from the remote end
Step 2 Comm I/F –R gives the received data to distance protection
Step 3 Distance protection receives the data
Step 1 When the distance protection detects the forward faults in a predetermined zone, and receives a permissive signal from the remote end, the distance protection issues a trip command to the CB
Distance line protection with blocking tele-protection scheme
A distance relay sends a blocking signal to the remote end upon detecting reverse faults Conversely, if it identifies a forward fault without receiving a blocking signal, it triggers a trip signal to the local circuit breaker.
A variant of the system utilizes directional comparison blocking (DCB) with a non-directional element to transmit a blocking signal for any detected fault, effectively initiating the carrier The operation of the forward element subsequently cancels the blocking signal, thereby halting the carrier and dispatching a trip signal to the local circuit breaker (CB).
RO Overreaching trip function, must be set to reach beyond remote end of line
B Blocking function, must be set to reach beyond overreaching trip function at remote end of line
C Coordinating time, required to allow time for blocking signal to be received (set equal to channel time plus propogation time plus margin)
Simplex or duplex communication link RO
Figure 2 – Distance line protection with blocking tele-protection scheme [1]
Constraints / Assumptions / Design considerations: z The blocking signal is a minimum of 1 bit If it is phase segregated signal, it needs
To ensure effective signal transmission in phase-segregated systems, a total of 6 bits is required, accounting for independent phase-to-phase and phase-to-earth signals, with an additional bit for directional earth fault detection Data transmission occurs upon the detection of a reverse fault or, alternatively, any fault, where the blocking signal is lifted once a forward fault direction is identified In cases of communication channel failure, the blocking signal is generally removed For rapid tripping, it is crucial to maintain a propagation delay of less than 5 ms, while ensuring high reliability with a bit error rate (BER) of less than \(10^{-6}\), along with alternative routing and duplication measures.
Measuring equipment is essential for monitoring current and voltage from the protected line The Communication Interface - Sender (Comm I/F –S) collects data from the local relay and transmits it to the remote end, while the Communication Interface - Receiver (Comm I/F –R) receives data from the remote end and relays it back to the local relay.
CB Disconnects the protected line from the other system (circuit breaker)
Name Services or information provided
Data sampling and filtering Samples current and voltage data from the measuring equipment and filters them Data sending Calculates a distance to the fault using filtered data
When a distance protection detects a reverse fault, the distance protection sends the blocking signal to Comm I/F –S (the remote end)
Data receiving Receives the blocking signal from Comm I/F –R
When distance protection identifies forward faults and does not receive a blocking signal from the remote end, it triggers a trip command to the circuit breaker (CB).
Distance protection begins by receiving current and voltage inputs from measuring equipment It then samples these analog values and converts them into digital data Finally, the system utilizes a digital filter to eliminate any unwanted frequency components from the sampled data.
Distance line protection with blocking tele-protection scheme
Step 1 Distance protection stores the filtered instantaneous data
Distance protection measures the fault distance using filtered data Upon detecting a reverse fault within a specified range, it transmits a blocking signal to the Communication Interface - S, which then relays the information to the remote end relay.
When distance protection identifies a forward fault within a specified zone and does not receive a blocking signal from the remote end, it triggers a trip command to the circuit breaker (CB).
Directional comparison protection
A directional relay, often a directional overcurrent relay, identifies a forward fault and transmits a permissive signal to the remote end Upon receiving a permissive signal from the remote end, the relay activates a trip signal to the local circuit breaker.
DF Directional relay to detect forward faults
Figure 3 – Directional comparison with permissive scheme [1]
Constraints / Assumptions / Design considerations: z The permissive signal is a minimum of 1 bit If it is phase segregated signal, it needs
To ensure effective fault detection, a total of 6 bits are required for phase segregation, with an additional bit for directional earth fault detection Data transmission occurs solely upon the detection of a forward fault In the event of a communication channel failure, alternative actions must be implemented For rapid tripping, it is crucial to maintain a propagation delay of less than 5 ms Additionally, high reliability is essential, targeting a bit error rate (BER) of less than \(10^{-6}\), with provisions for alternative routes and duplication.
Directional relay with permissive scheme
Measuring equipment is designed to monitor current and voltage from a protected line The Communication Interface - Sender (Comm I/F –S) collects data from the local relay and transmits it to the remote end, while the Communication Interface - Receiver (Comm I/F –R) receives data from the remote end and relays it back to the local relay.
CB Disconnects the protected line from another system
Name Services or information provided
Data sampling and filtering involves capturing current and voltage data from measuring equipment and applying filters to refine this information The data sending process determines the direction of a fault; when a directional relay identifies a forward fault, it transmits a permissive signal to the remote end via the Comm I/F –S.
Data receiving Receives the permissive signal from Comm I/F –R
(the remote end) Relay decision When the directional relay detects a forward fault and receives a permissive signal from remote end, the directional relay issues a trip command to the
In the first step, measuring equipment supplies current and voltage to the directional relay Next, the directional relay samples the analog value and converts it into digital data Finally, the directional relay utilizes a digital filter to eliminate unwanted frequency components from the sampled data.
Step 1 Directional relay stores the filtered instantaneous data
In Step 2, the directional relay determines the fault's direction by analyzing filtered data In Step 3, upon detecting a forward fault, the relay transmits a permissive signal to the Communication Interface - S, facilitating the transfer of data to the remote end relay.
Step 4 Comm I/F –S sends the information to remote end
Step 1 Comm I/F –R receives the data from the remote end
Step 2 Comm I/F –R gives the received data to the directional relay Step 3 Directional relay receives the data
Step 1 When the directional relay detects a forward fault and receives a permissive signal from the remote end, the relay issues a trip command to the CB
Transfer/Direct tripping
Local equipment sends a trip command to the remote equipment This function is sometimes called inter-tripping as well See Figure 4
The trip signal requires a minimum of 1 bit, increasing to 3 bits for phase segregated signals, and may need additional bits if multiple remote devices are involved Data transmission occurs solely upon the issuance of a trip command In the event of a communication channel failure, alternative actions must be implemented To ensure rapid tripping, the propagation delay should be minimal, ideally under 5 ms Additionally, high reliability is essential, with a bit error rate (BER) of less than 10^{-6}, and provisions for alternative routing and duplication should be in place.
The commander initiates a trip command to the remote equipment by requesting local equipment The Communication Interface (Comm I/F – S) receives data from the local relay and transmits it to the remote end Conversely, the Communication Interface (Comm I/F – R) receives data from the remote end and forwards it to the local relay.
CB Disconnects the line from the other system (circuit breaker)
Name Services or information provided
Trip command issuing Issues a trip command to the local equipment
Data sending Sends the trip command to Comm I/F –S (the remote end) Data receiving Receives the trip command from Comm I/F –R Tripping Issues the trip command to the CB
Step 1 Issues the trip command to local equipment
Step 2 Local equipment receives the trip command
Step 1 Local equipment sends the trip command to Comm I/F –S (in order to send the data to the remote equipment) Step 2 Comm I/F –S sends the information to the remote end
Step 1 Comm I/F –R gives the received command to the remote equipment Step 2 Remote equipment receives the data
Step 1 Remote equipment issues a trip command to the CB
Interlocking
The interlocking of the line earth switch is contingent upon the presence of voltage on the line To detect this, it is essential to monitor the states of both the earthing switch and the line disconnector switch from the opposite side Additionally, under-voltage measurement serves as a backup function in the event of a communication link failure.
The design considerations include timing requirements of 100 ms or less, with each switch state change being transmitted The system accommodates two switch states, with a maximum of approximately 10 switch states from the opposite side Additionally, communication channel failures may be interpreted as either intermediate or failed switch states.
Pos Switch position Itl Interlocking logic
The switch state acquisition involves monitoring switch states from the line, specifically the earth switch and line disconnector The communication interface (Comm I/F –S) collects data from local acquisition and transmits it to the remote end, while the communication interface (Comm I/F –R) receives data from the remote end and relays it to the local interlocking controller The interlocking controller utilizes the remote switch states to implement local interlocking logic effectively.
Name Services or information provided
The switch state acquisition process captures switch states from the line, specifically the earth switch and line disconnector It then receives data from local acquisition and transmits this information to the remote end Additionally, it receives data from the remote end and forwards it to the local interlocking controller Finally, the interlocking calculation utilizes remote switch states to inform local interlocking logic.
In the first step, the system acquires the switch states from the line, ensuring that both the switch and the line disconnector are properly earthed In the second step, it collects data from the local acquisition and transmits this information to the remote end.
Step 3 Receives data from the remote end and gives the data to the local interlocking controller Step 4 Uses the remote switch states for local interlocking logic
Correct interlocking – no line disconnector closes on earthed line, no earthing switch closes on active (disconnector closed) line
Multi-phase auto-reclosing application for parallel line systems
Multi-phase auto-reclosing, which includes 1-phase, 2-phase, and 3-phase schemes, is utilized in double line circuits This method determines its actions based on the circuit breaker status at the remote end, a feature not commonly found in other auto-reclosing techniques.
This article discusses the transmission of circuit breaker (CB) status information specifically for multi-phase auto-reclosing, excluding the standard auto-reclosing processes such as dead time checks Refer to Figure 6 for visual representation.
The design considerations for the system include the requirement for the CB status to utilize either 3 bits or 6 bits, ensuring efficient data representation Additionally, a small propagation delay of approximately 10 ms is preferred to facilitate quick operations High reliability is essential for the system's performance, and it is crucial to have alternative actions in place to address potential communication channel failures.
The protection relay provides tripping information essential for the auto-reclosing scheme The Communication Interface - Sender (Comm I/F –S) collects data from the local relay and transmits it to the remote end Conversely, the Communication Interface - Receiver (Comm I/F –R) receives data from the remote end and relays it to the local relay.
CB Disconnects the protected line from another system
Name Services or information provided
Protection relays are designed to trip the faulted phase and communicate this information to the auto-reclosing scheme Additionally, local circuit breakers (CBs) in both the protected line and the parallel line relay their status to the auto-reclosing system.
Data sending Sends the local CB status to Comm I/F–S
Data receiving Receives the remote CB status from Comm I/F –R
Relay decision If the auto-reclosing scheme decides to trip other phases, it sends a trip signal to the local CB
Step 1 Auto-reclosing scheme sends the local CB status to
Comm I/F –S (in order to send the data to the remote end relay)
Auto-reclosing scheme also passes the information to the auto- reclosing scheme of the parallel line to share the information Step 2 Comm I/F –S sends the information to the remote end
Step 1 Comm I/F –R give the received data to auto-reclosing scheme Step 2 Auto-reclosing scheme receives the data from comm I/F-R and from the auto-reclosing scheme of the parallel line
When a fault is detected in the protected line, the protection relay activates, tripping the affected phase This action initiates the auto-reclosing scheme for both the faulted line and the adjacent line at the local substation.
Step 2 Auto-reclosing scheme receives the data
Step 1 By using the CB status of both ends of both lines, the auto- reclosing scheme checks which phases are alive
The auto-reclosing scheme determines whether additional phases should be tripped or if the relay should continue counting dead time by assessing the auto-reclosing conditions against the status of the live phases If the scheme concludes that other phases need to be tripped, it transmits a trip signal to the local circuit breaker.
[2] K.KASUGA, Y.SONOBE, “Multi-phase Autoreclose Function Installed in Line Differential Relay”, 61st Annual Georgia Tech Protective Relaying Conference, May 2-4, 2007, Atlanta, Georgia.
Current differential line protection
Current differential relays monitor the current at both ends of a protected line, with a local relay transmitting current data (I A ) to the remote end and receiving data (I B ) in return These relays identify internal faults by comparing the currents from both terminals Upon detecting an internal fault, they promptly send a trip signal to the local circuit breaker.
SA Signal adapter (filtering, mixing circuit, A/D conversion, etc.)
RX Receiver lop Operation threshold according to stabilizing characteristic DEL Delay compensation
TPF Teleprotection function i D Differential current
Figure 7 – Current differential line protection [1]
When designing systems for measuring currents, it is essential to ensure accurate representation of the measured data and any supplementary information Synchronization of data between substations is critical, with required accuracy typically less than 0.1 ms, and even below 0.01 ms for applications demanding high fault current sensitivity Additionally, the frequency of periodic data exchange should align with the design philosophy, with an example being 12 exchanges per power cycle, equating to 600 times per second.
In 50 Hz systems, a design utilizes four data exchange telegrams per power cycle, allowing for the transmission of instantaneous values, phasors, and other measured quantities The system provides sufficient data bandwidth, capable of transmitting three-phase current data, additional information, and, if necessary, residual current data at rates such as 64 kbps However, a failure in the communication channel can obstruct the current line differential protection, making it crucial for the propagation delay to be minimal, typically around 5 ms for extra-high voltage (EHV) applications.
Propagation delays in high voltage (HV) and medium voltage (MV) systems range from 10 ms to 40 ms, but are negligible with direct fiber communication High reliability is essential, targeting a bit error rate (BER) of less than 10^{-6}, and implementing alternative routes and duplication can enhance this reliability Various telecommunication media, including direct fiber, Synchronous Digital Hierarchy (SDH), and Plesiochronous Digital Hierarchy (PDH), can be utilized in these systems Synchronization can be achieved through external signals like GPS or by accounting for propagation delays during signal exchanges between relays in applications with nearly equal send and receive delays.
The measuring equipment is designed to measure current and voltage from a protected line The Communication Interface - Sender (Comm I/F –S) receives data from the local relay and transmits it to the remote end, while the Communication Interface - Receiver (Comm I/F –R) receives data from the remote end and relays it to the local relay.
CB Disconnects the protected line from other system
Name Services or information provided
Data sampling and filtering involves capturing and refining current and voltage data from measuring equipment The filtered instantaneous data is then stored and transmitted to the communication interface at the remote end Additionally, the system is responsible for receiving the sampled current data.
Comm I/F –R (the remote end) Relay decision Calculates the differential current etc If a fault in the protected line is detected, a trip command is issued to the CB
Step 1 Current (and voltage, when charging current compensation is needed) are given to the current differential protection by the measuring equipment
Current differential protection first samples an analogue value and converts it into digital data It then utilizes a digital filter to eliminate unwanted frequency components from the sampled data.
Current differential protection (peer to peer)
Current differential protection first stores the filtered instantaneous data It then formats this data for transmission, incorporating additional information bits Finally, the system sends the prepared data for further processing.
Comm I/F –S (in order to send the data to remote end relay) Step 4 Comm I/F –S sends the information to remote end
Step 1 Comm I/F –R receives the data from the remote end
Step 2 Comm I/F –R gives the received data to the current differential protection Step 3 Current differential protection stores the received instantaneous data
Step 1 Current differential protection calculates the differential current and the restraining current, using local data and remote end data which were sampled at the same time
Step 2 Current differential protection judges whether a fault exists in the protected line or not by comparing the calculated value with a threshold
Step 3 When current differential protection judges that a fault exists in the protected line, current differential protection issues a trip command to the local CB
Synchronisation of the data between current differential relays must be established
Phase comparison protection
A phase comparison relay activates an "on" signal to the remote end when it detects a positive current exceeding a predetermined threshold It compares the local data signal with the remote signal; if both signals are "on" for a brief duration, it indicates that the phases of the currents are opposite, leading to the relay being restrained Conversely, if the duration is sufficiently long, the relay identifies an internal fault and issues a trip signal to the local circuit breaker.
SA Signal adapter (mixing circuit, filtering, etc.)
RX Receiver DEL Delay compensation Δϕ Coincidence angle θ Stabilizing angle
& Logical AND TPF Teleprotection function
Half-wave phase comparison a) External fault or normal load b) Internal fault i A and i B
Figure 9 – Principle to detect internal fault by phase comparison [1]
Constraints / Assumptions / Design considerations: z The “on” signal is a minimum of 1 bit If it is a phase segregated signal, it needs
The residual current phase comparison may require an additional bit if it operates as an independent signal, totaling 3 bits An "on" signal is activated when the detected current is positive In cases of communication channel failure, an "on" signal is typically sent to the local phase comparison function To ensure fast tripping, the propagation delay should be minimal, ideally around 5 ms High reliability is essential, with a bit error rate (BER) of less than 10^{-6}, and provisions for alternative routes and duplication.
Measuring equipment Measures current from the protected line
The Comm I/F –S interface collects data from the local relay and transmits it to the remote end, while the Comm I/F –R interface receives data from the remote end and delivers it to the local relay.
CB Disconnects the protected line from another system
Name Services or information provided
Data sampling and filtering Samples current from the measuring equipment, and filters them Data sending Checks whether the current is positive or negative
When the current is positive, the phase comparison relay sends the “on” signal to Comm I/F –S (the remote end)
The data receiving process involves capturing the signal from the remote end via the Comm I/F –R The phase comparison relay then analyzes the local signal against the remote signal If the duration of both signals being active is insufficient, the relay triggers a trip command to the circuit breaker (CB).
The phase comparison relay receives current from the measuring equipment, which it then samples and converts into digital data Subsequently, the relay utilizes a digital filter to eliminate any unwanted frequency components from the sampled data.
Step 1 Phase comparison relay stores the filtered instantaneous data Step 2 The relay checks whether the current is positive or negative
Step 3 When the relay detects that the current is positive, it sends the
“on” signal to Comm I/F –S (in order to send the data to the remote end relay) and to the local time delay compensation circuit
Step 4 Comm I/F –S sends the information to the remote end
A local time delay compensation circuit adjusts the local data to align with the remote data by compensating for propagation delays based on a predetermined setting This adjusted data is then forwarded to the decision circuit for further processing.
Step 1 Comm I/F –R receives the data from the remote end
Step 2 Comm I/F –R gives the received data to the phase comparison relay Step 3 The phase comparison relay receives the data
The phase comparison relay evaluates the local signal against the signal received from the remote end If the duration during which both signals are active exceeds a specified threshold, the relay triggers a trip command to the circuit breaker (CB).
Other applications
General
Several applications share communication requirements similar to those of current differential protection These include fault locator systems, typically involving two or three terminals, system integrity protection schemes (SIPS), real-time predictive generator shedding, out-of-step detection, remedial action schemes (RAS), and synchrophasors from phasor measurement units (PMUs).
The typical requirements for these applications include the representation of measured currents and voltages along with additional information, ensuring data synchronization between substations with a precision of less than 0.1 ms Sufficient data bandwidth is necessary to transmit three-phase current and voltage data, typically around 64 kbps In the event of communication channel failure, alternative actions must be implemented Propagation delay is often critical, with a maximum of 5 ms depending on the application Additionally, high reliability is essential, requiring a bit error rate (BER) of less than 10^{-6}, along with provisions for alternative routes and data duplication Further details on each application are provided in the subsequent subclauses.
Fault locator system (2, 3 terminals)
By using all terminal information, precise estimation of the fault location is possible The voltages and currents of all ends are necessary See Figure 10
Figure 10 – Fault locator system (2, 3 terminals)
The design considerations for the fault locator include the representation of measured currents and voltages, along with any supplementary information It is important to note that the propagation delay does not significantly impact the fault locator's calculations Additionally, if the communication channel fails, the fault locator will rely solely on data from the local line end for its calculations For further constraints, please refer to section 5.10.1.
Measuring equipment Measures current and voltage from the line
The Comm I/F –S interface collects data from the local relay and transmits it to the remote end, while the Comm I/F –R interface receives data from the remote end and delivers it to the local relay.
Name Services or information provided
Data sampling and filtering involves capturing current and voltage data from measuring equipment and applying filters to refine this data The sampled data is then transmitted to the central computer via the Comm I/F –S Subsequently, the system receives the sampled data through Comm I/F –R and calculates the location of any faults.
(from the network computing terminal)
Step 1 Currents and voltages are given to the local terminal by the measuring equipment Step 2 A network computing terminal samples the analogue values and converts them to digital data
Step 1 When a fault occurs, the local terminal freezes the sampled data Typically, the frozen data is measured from a few cycles before the fault until about 10 cycles after the fault
Step 2 The local terminal sends the frozen data to Comm I/F –S (in order to send the data to the remote end) Step 3 Comm I/F –S sends the information to the remote end
Data receiving and fault locating
Step 1 Comm I/F –R receives the data from the remote end
Step 2 Comm I/F –R gives the received data to the local terminal
Step 3 The local terminal estimates the location the fault It shows and stores the result
Data receiving and fault locating
Synchronisation of the data between the relays must be established
System integrity protection schemes (SIPS)
The integrity protection scheme involves remote terminal units (RTUs) and central equipment (CE) to monitor voltage at power stations RTUs periodically transmit voltage data to the CE, which calculates the voltage angle differences between western generators and other groups (northern, eastern, and south-eastern) If the CE predicts a loss of synchronisation among the generators, it triggers a trip signal to the tie line's circuit breaker.
Figure 11 – Example of a system integrity protection scheme
The design considerations for the system include the representation of measured currents and voltages, along with any supplementary information To ensure rapid tripping, it is essential that the propagation delay remains minimal, ideally under 5 ms Additionally, a failure in the communication channel could impede the SIPS functionality For further constraints, please refer to section 5.10.1.
Measuring equipment is responsible for monitoring current and voltage from the protected line The Comm I/F –S-RT interface collects sampled data from the remote terminal and transmits it to the central equipment Meanwhile, the Comm I/F –R-RT interface receives trip commands from the central equipment's Comm I/F –S-CE and relays these commands to the remote terminal.
Comm I/F –R-CE Receives sampled data from Comm I/F –S-RT (the remote terminal) and passes the data to the central equipment
Comm I/F –S-CE Receives a trip command from the central equipment and sends the command to the remote terminal
CB Disconnects the tie line, which is connected to the western generators, with other generator groups (circuit breaker)
Name Services or information provided
Data sampling and filtering Samples current and voltage data from the measuring equipment and filters them Data sending-RT Sends the sampled data and information bits to
The central equipment (CE) receives sampled data and information bits from the communication interface (Comm I/F –R) at the remote terminal Additionally, the CE sends trip information back to the remote terminal through the same communication interface The remote terminal (RT) is responsible for receiving this trip information from the CE via Comm I/F –R.
(from the central equipment) Tripping According to the trip information from the central equipment, the central equipment and/or remote terminal issues a trip command to the CB
Step 1 Voltage is given to remote terminals by measuring equipment current is given to central equipment by measuring equipment Step 2 Remote terminal and central terminal samples an analogue value and converts it to digital data Step 3 Remote terminal and central equipment removes the unwanted frequency components from the sampled data, using a digital filter
Step 1 Remote terminal put the sampled voltage data to sending data format with other information bits Step 2 Remote terminal sends the data to Comm I/F –S-RT (in order to send the data to central equipment) Step 3 Comm I/F –S-RT sends the information to the central equipment
Step 1 Comm I/F –R receives the data from the remote end
Step 2 Comm I/F –R-CE gives the received data to the central equipment Step 3 Central equipment receives the data
Step 1 Central equipment executes a calculation for the angle difference prediction between the western generator group and the other generator groups
Step 2 If the central equipment predicts that the generators will go to out-of-step, the central equipment sends a trip command to the Comm I/F –S-CE and/or the local CB
Step 3 Comm I/F –S-CE sends the information to the remote terminal
Step 1 Comm I/F –R-RT gives a trip command to the remote terminal Step 2 Remote terminal receives the data
Step 1 If the remote terminal B receives the trip command, it issues a trip command to the CB
Synchronisation of the data between the relays must be established
[3] Y.OHURA, M.SUZUKI, K.YANAGIHASHI, M.YAMAURA, K.OMATA, T.NAKAMURA, S.MITAMURA, H.WATANABE, “A Predictive Out-of-Step Protection System Based
On Observation Of The Phase Difference Between Substations”, IEEE Trans PWRD, Vol.5, No.4, November 1990.
Real time predictive generator shedding
The wide area protection system consists of remote terminals and central equipment that monitor power stations A and B by measuring voltage and current Remote terminals A and B periodically transmit calculated active power to the central equipment, while remote terminal C provides voltage data In the event of a fault, the central equipment can predict potential loss of synchronization in the generators and will send a trip signal to ensure safety.
The main area of network Current
Figure 12 – Real time predictive type generator shedding system
The design considerations include the representation of measured currents and voltages, ensuring a small propagation delay of less than 5 ms for fast tripping Additionally, alternative actions must be planned for communication channel failures, with further constraints detailed in section 5.10.1.
The measuring equipment is designed to measure current and voltage from a protected line The Comm I/F –S-RT interface receives sampled data from the remote terminal and transmits it to the central equipment Meanwhile, the Comm I/F –R-RT interface receives a trip command from the Comm I/F –S-CE and returns the results accordingly.
(the central equipment) and passes the command to the remote terminal
Comm I/F –R-CE Receives sampled data from the Comm I/F –S-RT
(the remote terminal) and passes the data to the central equipment
Comm I/F –S-CE Receives the trip command from the central equipment, and sends the command to the remote terminal
CB Disconnects the line which is connected to a generator from the power station (circuit breaker)
Name Services or information provided
Data sampling and filtering Samples current and voltage data from the measuring equipment, and filters them Data sending-RT Sends the sampled data and information bits to
Comm I/F –S (to the central equipment)
Data receiving-CE Receives the sampled data and information bits from Comm I/F –R (from the remote terminal)
Real time predictive type generator shedding
Data sending-CE Sends the trip information to Comm I/F –R (to the remote terminal)
Data receiving-RT Receives the trip information from Comm I/F –R
Tripping According to the trip information from central equipment, the remote terminal issues a trip command to the CB
Step 1 Current and voltage are given to the remote terminals by the measuring equipment Step 2 Remote terminal samples an analogue value, and converts it to digital data Step 3 Remote terminal removes the unwanted frequency components from the sampled data, using a digital filter
Step 1 Remote terminals A and B calculate the power, from the filtered current and voltage data Step 2 Remote terminal puts the electrical data (power for terminal A and B, current and voltage for terminal C) to sending data format, with other information bits
Step 3 Remote terminal sends the data to Comm I/F –S-RT (in order to send the data to central equipment) Step 4 Comm I/F –S-RT sends the information to the central equipment
Step 1 Comm I/F –R receives the data from the remote end
Step 2 Comm I/F –R-CE give the received data to central equipment Step 3 Central equipment receives the data
Step 1 Central equipment executes a calculation for the generator angle prediction Step 2 If central equipment predicts the generator will go to the out-of- step, it calculates the minimum number of generators which is necessary to be shed in order to stabilise the power system Step 3 Central equipment sends the trip information (the number of the generator to be shed) to Comm I/F –S-CE Step 4 Comm I/F –S-CE sends the information to remote terminal
Step 1 Comm I/F –R-RT gives the trip information to the remote terminal Step 2 Remote terminal receives the data
Step 1 According to the tripping information from the central equipment, the remote terminal issues a trip command to the
Synchronisation of the data between the relays must be established
[4] K.MATSUZAWA, K.YANAGIHASHI, J.TSUKITA, M.SATO, T.NAKAMURA, A.TAKEUCHI,
“Stabilizing Control System Preventing Loss Of Synchronism From Extension And Its Actual Operating Experience”, IEEE Trans PWRS, Vol.10, No.3, August 1995.
Out-of-step detection
By analyzing the voltage angle between the two ends, it is possible to determine if the center of the out-of-step condition lies between them, as illustrated in Figure 13 An out-of-step situation arises when the two voltages are oriented in opposite directions, indicating that the center of the out-of-step is positioned between the two ends.
Figure 13 – Out-of-step detection
Constraints / Assumptions / Design considerations: z Representation of measured voltages and any additional information z For out-of-step detection a medium propagation delay is required (e.g.: 10 ms to
50 ms) z Communication channel failure may block this kind of out-of-step detection, alternative actions must be considered z Other constraints, see 5.10.1
Measuring equipment Measures voltage from protected line
The Comm I/F –S interface collects data from the local relay and transmits it to the remote end, while the Comm I/F –R interface receives data from the remote end and delivers it to the local relay.
CB Disconnects the protected line from another system
Name Services or information provided
Data sampling and filtering involves capturing voltage samples from measuring equipment and applying filters to them The out-of-step detection process transmits the sampled voltage data to the remote communication interface (Comm I/F –S) Additionally, the system receives a permissive signal from the remote communication interface (Comm I/F –R).
(the remote end) Tripping If required, out-of-step detection sends a trip signal to the local CB
Step 1 Voltage is given to out-of-step detection by measuring equipment Step 2 Out-of-step detection samples an analogue value and converts it to digital data Step 3 Out-of-step detection removes the unwanted frequency components from the sampled data, using a digital filter
Step 1 Out-of-step detection sends the sampled voltage data to
Comm I/F –S (in order to send the data to remote end relay) Step 2 Comm I/F –S sends the information to the remote end
Step 1 Comm I/F –R gives the received data to out-of-step detection Step 2 Out-of-step detection receives the data
Step 1 Compares the local voltage with the remote voltage and checks the angle difference between the two voltages Step 2 When the out-of-step is detected, and if required, out-of-step detection issues a trip command to the local CB
Synchronisation of the data between the relays must be established
Synchrophasors
Synchrophasors are obtained through phasor measurement units (PMUs), which deliver synchronized data for various applications One notable use of synchrophasors is in system integrity protection schemes (SIPS), as outlined in section 5.10.3 The specifics of these applications are not reiterated here.
Remedial action schemes (RAS)
Remedial action schemes (RAS) are essential for monitoring and safeguarding electrical systems They automatically execute switching operations to address unfavorable network conditions, thereby maintaining the integrity of the electrical system and preventing network collapse.
Typical automatic remedial actions include:
• generator tripping for reduction of energy input to the system;
• tripping of load, insertion of braking resistors, series capacitors, opening of interconnecting lines and system islanding
The RAS action is executed by a central controller that relies on data from field units, which measure currents, voltages, and transducer quantities (W, VAr) These field units transmit the collected data to the central equipment for evaluation and comparison with information from other locations in the power system Additionally, they function as remote controllers, enabling breaker operations through programmable logic and inputs/outputs upon receiving commands from the central equipment.
6 Communication requirements for substation-to-substation communication
NOTE This Clause 6 collects the requirements according to IEC 61850-5 but focussed on substation-substation communication.
General issues
Introduction
Substation-substation communication is a critical aspect of substation automation systems (SAS), enabling functions that are either shared between two substations or require information from one another Key examples include line protection and bay interlocking, which utilize position data from line isolators and earthing switches across substations Additionally, various automation processes involving multiple substations rely on this communication Supporting functions, such as time synchronization between Intelligent Electronic Devices (IEDs) on both sides of the substation link, are also essential for effective operation.
Logical allocation of functions and interfaces (5.2 in IEC 61850-5)
A substation automation system's functions can be logically categorized into three distinct levels: station, bay/unit, and process This classification is illustrated through the logical interpretation of Figure 14, which includes logical interfaces numbered 1 to 11.
Figure 14 – Logical interfaces between substation A and substation B
The substation automation system features several key interfaces: Interfaces 1, 3 to 6, and 8 to 9 facilitate internal connections within the substation Interface 10, known as the Telecontrol Interface (TCI), enables communication between the automation system and the remote control center, while Interface 7, the Telemonitoring Interface (TMI), supports communication with remote engineering, monitoring, and maintenance locations Additionally, Interface 2 serves as the Teleprotection Interface (TPI), handling protection-related functions between substations, and Interface 11 addresses control-related functions The relationships among these interfaces are detailed in Table 1.
Table 1 – Grouping of protection and control interfaces
Process interfaces Bay-station interfaces Substation-substation interfaces
IF1: protection-data exchange between bay and station level;
The IF2 interface facilitates the exchange of protection data between substations, encompassing both analog data for line differential protection and binary data for line distance protection Additionally, IF3 enables data exchange at the bay level, ensuring efficient communication and coordination within the substation infrastructure.
IF4: CT and VT instantaneous data transport (especially samples) from the process to the bay level This comprises in the reverse direction also the protection trip;
IF5: control-data exchange between process and bay level;
IF6: control-data exchange between bay and station level;
IF7: data exchange between substation (level) and a remote engineer’s workplace;
IF8: direct data exchange between the bays especially for fast functions like interlocking; IF9: data exchange within station level;
IF10: control-data exchange between the substation and remote control center(s);
IF11: control-data exchange between substations This interface refers to binary data e.g for interlocking functions or inter-substation automatics.
The role of interfaces
Interface 2 is dedicated to communication with a remote protection device in the adjacent substation and the interface 11 is dedicated in the same way to communication with the remote control device It should be noted that interfaces 2 and 11 may be interfaces to a communication network not according to IEC 61850 These networks are accepted if they allow tunnelling IEC 61850 messages and provide the requested performance between the functions running in IEC 61850 based SA systems on both sides
The message types outlined in Subclause 6.3 are allocated to various interfaces based on the communication performance requirements of application functions This flexible allocation of functions indicates that the assignment may vary across different substation automation systems and between substation-substation links.
Response behaviour requirements
Interoperability is essential for the effective functioning of distributed applications, necessitating careful consideration of the receiving node's response The reaction of this node must align with the overall requirements of the distributed function Additionally, it is crucial to define the basic behavior of functions in degraded scenarios, such as erroneous messages, communication interruptions, or resource limitations, as these factors can hinder the successful completion of tasks Furthermore, the external communication system must also meet the overall requirements of the distributed function to ensure seamless operation.
This communication standard does not address function-related local issues; however, it does emphasize the importance of ensuring that quality attributes are included with the data being transferred.
Functions based on substation-substation communication
Protection functions
Tables 2 gives the protection functions using substation-substation communication
Table 2 – Protection functions using substation-substation communication
Function IEC 61850 IEEE Description or comments
PSCH 21 Distance relay is a relay that functions when the circuit admittance, impedance, or reactance increases or decreases beyond a predetermined value
A fault causes a change in the impedance observed by PDIS, represented as a closed line in the complex impedance plane Distance protection is typically divided into multiple zones, such as zones 1 to 4, for effective monitoring and response.
1 backward) represented by dedicated characteristics
Function IEC 61850 IEEE Description or comments
87 Differential protective relay is a protective relay that functions on a percentage or phase angle or other quantitative difference of two currents or some other electrical quantities
Control functions
Tables 3 gives the control functions using substation-substation communication
Table 3 – Control functions using substation-substation communication
Function IEC 61850 Description or comments
Interlocking function at station and/or bay level
CILO Interlocking can be either fully centralized or fully decentralized The interlocking rules remain consistent at both bay and station levels, relying on all relevant position indications Consequently, various interlocking logic networks (LNs) can be viewed as examples of the same class of interlocking (IL) Specifically, this applies to the interlocking of switchgear at the bay level.
This LN encompasses all interlocking rules related to a bay, including the issuance of releases or blockings for requested commands In the event of status changes that impact interlocking, appropriate blocking commands are also issued Additionally, it addresses the interlocking of switchgear at the station level.
All interlocking rules referring to the station are included in this LN Releases or blockings of requested commands are issued Information with the LN bay interlocking is exchanged.
Message performance requirements
Transfer time definition (13.4 in IEC 61850-5)
Transfer time is defined from the perspective of the user or application, encompassing the duration from when the sending application transmits data to when the receiving application retrieves it This includes the complete message transmission process, which involves coding, decoding, and media access at both ends For instance, in physical device PD1, application function 1 sends data to application function 2 in physical device PD2 The transfer time begins when the sender places the data on its transmission stack and ends when the receiver extracts it from its receiver stack Overall, the total transfer time \( t \) comprises the individual times for coding \( t_a \), decoding \( t_c \), and the network transfer time \( t_b \), regardless of whether dedicated communication processors are used.
Physical link Wire, fiber etc
Physical device PD1 Physical device PD2
Figure 15 – Transfer time for binary and other signals over a serial connection
For binary signals, conventional output and input relays replace the coding and decoding (see Figure 16) These output and input relays have response times of around 10 ms
Physical link (wire circuit) Application function 2
Figure 16 – Transfer time for binary signal with conventional output and input relays
If there is only one direct link, the time t b is for distances in substations and in power systems negligible referring to the speed of light
Active components in the communication path, like routers and switches, significantly impact the network transfer time, denoted as \$t_b\$ Additionally, any necessary compensations for collisions or losses, such as retransmissions, further contribute to this time It is essential to conduct testing and verification of transfer times during site acceptance testing, as the physical devices and network equipment may come from various manufacturers.
Physical device PD2 Gate-way
Output/input relays Gate-way
Figure 17 – Definition of transfer time t for binary signals in case of line protection
The time delay in the interconnecting network, which is included in the total time \( t_b \), also applies to links beyond the substation boundary Figures 17 and 18 illustrate various dedicated times that contribute to \( t_b \) In Figure 17, relay times are depicted, while Figure 18 shows these times replaced by coding and decoding durations In the case of full serial communication, as illustrated in Figure 18, the coding and decoding processes for the wide area communication system (represented by the gateway in Figure 17) are substituted with recoding for the local area communication.
Non IEC 61850 wide area comm system
Figure 18 – Definition of transfer time t over serial link in case of line protection
The teleprotection operating time T A in Figure 2 of IEC 60834-2 is defined in nearly the same way as the transfer time t in this document
All requirements reflect the needs of the application function and, therefore, are valid in any case under normal conditions without disturbed communication links
Disturbances may require a logical reconnection of the communication link, message repetition, or other methods that can delay transfer times This behavior is governed by the services outlined in IEC 61850-7-2 and their implementation within Intelligent Electronic Devices (IEDs) It is essential to define and consider any potential delays in the transfer time, as the acceptability of these transfer times is specific to each project.
The introduction and use of message performance classes
General
To accommodate varying functional requirements within and between substations, message types are categorized into performance classes These classes are divided into two main groups: one for control and protection applications, where transfer times are the primary criterion, and another for metering and power quality applications, which prioritize accuracy The performance classes are determined by the specific functions they serve, making them independent of substation size and primarily related to voltage levels Raw analog data for voltage and current is transmitted over serial links as synchronized streams of samples To ensure timely execution of dependent actions, such as necessary protection trips, both accuracy and sample rate are crucial, alongside transfer time.
Not all communication links within and between substations are required to support identical message performance classes Due to the flexible allocation of functions, there is no fixed assignment of these classes, which means that nearly all links may need to accommodate all performance classes Consequently, it is essential that all supported classes, particularly the most demanding one, are included in the IED specification.
To achieve optimal performance in message transmission over a single link, it is essential to implement a system that adheres to the highest performance class Additionally, to accommodate varying requirements, prioritization support is necessary.
The typical use of the performance classes is indicated below but it may be overwritten by dedicated function requirements or customer specifications.
Control and protection
The transfer time requirements, which pertain to communication performance, are consistent across a single bay, between different bays, and between substations Consequently, a uniform classification scheme must be applied to all links in accordance with IEC 61850 standards.
Some classes may be not applicable for all application areas The use of an intermediate WAN not compliant with IEC 61850 may result in higher transfer times
The transfer time requirements are not influenced by voltage levels The fault clearance time, T_C, defined in IEC 60834-2, measures the duration from the onset of a fault to its resolution At the distribution level, longer fault clearance times may be permissible compared to the transmission level, which can be attributed to slower algorithms and less powerful circuit breakers However, these extended times do not stem from less stringent transfer time requirements.
6.4.2.1 Types of message performance classes
This type of message typically contains simple binary information like a short command or a simple message like "Trip", "Close", “Reclose order”, "Start", "Stop", "Block", "Unblock",
The "Trigger" and "Release" message types, along with "State change" and "State" for certain functions, are essential for optimal performance Upon receiving these critical messages, the IED must respond promptly according to the associated function.
The “trip” is the most important fast binary message in the substation Between substations
The terms "block" and "release" hold equal significance, necessitating more stringent requirements for this message compared to other fast messages Consistent performance is also essential for interlocking, intertrips (direct trips), and logical discrimination among protection functions Specifically, for trips occurring within a substation and within a single bay, transfer times must not exceed 4 ms For trips between bays within the same substation, transfer times should ideally be under 10 ms, although times not exceeding 4 ms may also be required Additionally, for trips to neighboring substations, such as those for line protection, a comprehensive range of transfer times must comply with the performance classes outlined in IEC 60834-1, ensuring that the defined transfer time requirements are met based on the necessary functional capabilities of the communication system.
NOTE In IEC 60834-1, only 10 ms are defined for digital networks
Fast messages play a crucial role in automation functions between Intelligent Electronic Devices (IEDs) and their interaction with processes, although they have less stringent requirements than "trip" messages For fast state-based applications, the transfer time must not exceed 20 ms, adhering to TR4 standards In contrast, normal state-based applications allow a maximum transfer time of 100 ms, in accordance with TR5, which specifies that times greater than 20 ms are acceptable but capped at 100 ms.
Therefore, these types of message performance classes are valid inside the substation and also for messages between substations
For effective communication from the process and bay level to the operator, only low-speed message performance classes are necessary, given the operator's response time exceeds 1 second These messages should not exceed 500 milliseconds and are intended for more complex tasks, such as updating the station-level database, refreshing the single line display, and managing alarm and event lists, as well as processing all operator commands However, this performance message class is not suitable for functions that rely on substation-to-substation communication.
The same is valid for file transfers which may exceed 1 000 ms depending on the size.
Metering and power quality
6.4.3.1 Types of message performances classes
The performance class M1 refers to revenue metering with accuracy class 0,5 (IEC 62053-22) and 0,2 (IEC 60044) and up to the 5 th harmonic
The performance class M2 refers to revenue metering with accuracy class 0,2 (IEC 62053-22) and 0,1 (IEC 60044) and up to the 13 th harmonic
The performance class M3 refers to quality metering (power quality) up to the 40 th harmonic
6.4.3.2.1 General requirements for raw data
This message type encompasses output data from digitizing transducers and digital instrument transformers, regardless of the transducer technology used, such as magnetic or optical It is essential to transfer current and voltage samples from the transducer to the processing unit, typically a protection IED For effective line differential protection, this data must be communicated across the line from one side to the other To prevent delays in protection due to sample transfer, the transfer time must adhere to the high-speed message classes outlined in section 6.4.2.1.1 Unlike binary messages, this data comprises a continuous stream of synchronized samples from the sending IED.
Phasors, utilized by certain functions as an alternative to samples, maintain identical performance requirements for transfer time However, they generate a lower volume of data or messages in the data stream, as phasors typically rely on multiple samples for angle definition.
Transferring current and voltage values as analogue signals over wires ensures uniform transfer times across all voltage levels, preventing delays in protection due to data communication Any variations in transfer times must be categorized according to the high-speed message classes outlined in section 6.4.2.1.1.
Analogue data have besides the transfer time additional features as amplitude resolution and sampling rate The required transfer time for protection and control is:
4,0 ms acc to Type 1A “Trip”
In digital communication beyond the substation, transfer times of 10 ms or less are acceptable under the message performance class TR2 For other communication systems, less stringent classes such as TR3 and TR4 can be utilized, provided that the application function can accommodate these longer transfer times.
6.4.3.2.2 Additional requirements for time synchronisation for line differential protection
To effectively compare samples or phasors from various locations and IEDs, synchronization within the microsecond range is essential This synchronization challenge can also arise within a single substation, which currently utilizes pulse per second (pps) signals and is expected to transition to IEC 61850 connections using IEEE 1588 in the future.
Table 4 – Change of transfer time and synchronisation method
Class Acceptable change of transfer time (Δ T A ) Applicable synchronisation method
TT1 0,2 ms External signal synchronisation or self synchronisation (self synchronisation is outside scope of IEC 61850 because this method is not standardised)
TT2 10 ms External signal synchronisation
TT3 20 ms External signal synchronisation
The communication path's asymmetry regarding transfer time between IEDs on either side of the line affects self-synchronization, as outlined in class TT1 (0.2 ms) in Table 4 If the transfer time asymmetry surpasses this limit, external synchronization becomes necessary.
Not applicable for functions based on substation-substation communication
Between substations the synchronisation takes place without dedicated time synchronisation messages as explained in 6.4.3.2.2 Nevertheless, the classes for time synchronisation according to IEC 61850-5 may be used if applicable
6.4.3.4.2 Standard IED synchronizing for control and protection events
The performance classes for the time tagging of control and protection events are applicable according to Table 5
Table 5 – Performance classes for time tagging of events
T2 ± 0,1 Time tagging of zero crossings and of data for the distributed synchrocheck Time tags to support point on wave switching
6.4.3.4.3 Standard IED synchronizing for instrument transformers
For instrument transformers, the time performance classes according to Table 6 are applicable
Table 6 – Time performance classes for instrument transformer synchronisation
6.4.3.5 Type 7 – Command messages with access control
Not applicable for functions based on substation-substation communication.