Use of frame agreement to standardize Protection in Digital Substation Automation Systems, Cooperation between Statnett and ABB

Use of frame agreement to standardize Protection in Digital Substation Automation Systems, Cooperation between Statnett and ABB R. Loken*, R. Mangelrød*, M.M. Saha, A. Ling *Statnett, Norway, Rannveig.Loken@statnett.no, ragnar.mangelrod@statnett.no ABB AB,Substation Automation Products,Sweden, Murari Saha murari.saha@se.abb.com, Anders Ling anders.ling@se.abb.com Keywords: Frame agreement, specification, cooperation, protection, acceptance procedure. Abstract Statnett use frame agreement with a few vendors to ensure uniform protection and control systems on a proven basis of a pilot project. Statnett have requirements to protection in the specification that the vendor must fulfil. The vendors adapt their protections to fulfil the requirement from the specification. Statnett use a control server where documentation for all the plants are stored. The control server is developed in cooperation with the vendor for each frame agreement. During the frame agreement period, the software and hardware version for protection and control units are fixed to simplify the operation and maintenance for Statnett. This paper describes Statnett and ABBs experience and benefits using a frame agreement for our Digital Substation Automation Systems (DSAS) deliveries. It focuses on the protection requirement and the acceptance test process of vendor products with the purpose to standardise the technical solutions for the DSAS. 1 Introduction For several years, Statnett have used frame agreement with a few vendors to ensure uniform protection and control systems on a proven basis of a pilot project. The DSAS is based on IEC 61850 standard. The system allows interoperability between Intelligent Electronic Devices (IEDs) of different vendors in one utility DSAS. The IEC 61850 standard is not a plug and play system where a new part can be adopted without engineering. To avoid problems regarding changes in the DSAS in the future, the utility must ensure a robust specification and a unique cooperation with the vendor during the engineering of the system development. This paper presents some of the requirement for the protection in the specification, and how the vendor solve these requirements in their system. It also addresses the use of acceptance test to evaluate the functionality of new protection functions. 2 Specification from utility side 2.1 Technical Specifications for DSAS [1] The technical specifications describe Statnett's requirements for the control system's functionality and equipment. The technical specifications refer to Statnett's applicable documentation of principles. The documentation of principles provides a detailed representation of the control system's functionality, connections and signal exchange. The control system includes all necessary functions such as protection, control, regulation, measurement, indications and communication. These features are necessary to ensure safe and optimized grid operations, to protect life and property, and to collect data for use in analyses, billing and statistics. Statnett have based the requirement in the specification for the frame agreement on experience from previous projects. 2.2 General line protection requirements [2] Total fault clearing time including opening time of the circuit breaker must not exceed 100 ms for faults on transmission lines in the solidly grounded system. To achieve this requirement Statnett uses two separate protection systems (Main1 and Main2) with two fully independent fiber optic communication channels, one for Main1 and one for Main2, for signal transmission between teleprotection functions. Tripping arrangement is one out of two. Both Main1 and Main2 release trip commands (single- or three-phase trip) to each trip-coil at each circuit breaker. Each circuit breaker has separate autoreclose (AR) and synchronising function and circuit breaker failure relay included in the busbar protection. Trip command from short-circuit protection functions in Main1 and Main2 starts both AR-functions and both circuit breaker failure relays. To have two fully independent protection systems, each protection system also have independent DC-supply. A principle drawing of a 2 CB / 2CT line bay is shown in Figure 1. In general, all protection functions shown in Figure 1 must be in separate devices, but the non-directional earth-fault overcurrent protection (3I0>) shall be integrated in both Main1 and Main2. The AR- and 1

synchronising function for both circuit breakers can be integrated in the bay control unit. A B Trip M1 (1Ph or 3Ph) Open Close Trip M2 (1Ph or 3Ph) Start M1 x Trip M1 (Phase Start M2 AR & Sync Async Trip M2 (Phase Trip M1 (1Ph or 3Ph) M1, Start M1 3Io> Trip M1 (1Ph or 3Ph) Open Close Trip M2 (1Ph or 3Ph) Start M1 x Trip M1 (Phase AR & Sync Async Trip M2 (1Ph or 3Ph) M2, Start M2 3Io> Start M2 Trip M2 (Phase To busbar and CB failure protection Figure 1: Protection layout for transmission lines in solidly grounded systems in a 2 CB / 2 CT arrangement 2.3 Requirements to Distance Protection function [3] To achieve the 100 ms requirement, maximum operating time from distance protection function including transmission time delay for carrier send/receive (Teleprotection, echo, WEI-trip and current reversal) must not exceed 40 ms. Independent of system grounding distance protection must have minimum 5 fully independent full-scheme quadrilateral zones with independent settings for zone direction, reach in resistive and reactive direction and time delay. Statnett use single-phase trip/ar for single phase faults and three-phase trip/ar for multi-phase faults. Therefore, the distance protection function must have a phase selection logic and trip logic which clearly discriminate between single-phase and multi-phase faults. The directional determination logic must be able to decide correct direction to both single and multiple faults even in case of CT-saturation in inductive as well as in series compensated transmission systems. Statnett do not use any vendor-specific switch onto fault logic (SOTF). Instead Statnett use a SOTF-logic as shown in figure 2 below. This SOTF-logic is included in both Main1 and Main2. Figure 2: Statnett standard SOTF-logic Pole discordance protection function and logic for tripinitiated system protection is always included in both Main1 and Main2. Distance relays used in non-earthed systems must have functionality to be used also in solidly grounded systems in case of future change of system grounding to solidly earthed system. In addition, distance protection used in nonearthed systems must have logic for suppression of trip command in case of single phase to ground faults and a phase preference logic for detection and correct release of trip command in case of cross-country earth-faults must be included. Line bays in compensated/isolated network shall have transient earth fault relay (Wischer-relay) for detection of the direction to permanent earth faults. The relay shall have indication signals for earth faults in both forward and backward direction. There is an advantage if the Wischerfunction is included in the line protection. 2.4 Requirements to Line Differential Protection [4] Protection of transmission lines in areas with HVDCinterconnections with long DC-cables, both Main1 and Main2 have to be line differential protection relays from different vendors. The line differential protection device must always include a distance protection function. Statnett requirements to the distance protection functions is the same as described in chapter 2.3. CTs close to HVDC-interconnections with long DC-cables are, during power system faults exposed to current waveforms, which may result in CT-saturation 5 7 ms after the fault appear due to potential high pre-fault level of remanence as shown in figure 3 below. Therefore, special focus regarding fulfilment of vendors CT-requirements is needed in co-operation with vendor. Statnett owns and operates a large fibre network, which includes two independent access points to all substations. The line differential protection will be using Statnett fibre network with 2Mbit fixed or symmetric routes, i.e. no need for GPS synchronisation. Bit errors may appear in data packages that are transmitted using telecommunication systems. Therefore, validation routines in the line differential protections must be robust enough to detect any changes in the received data and reject them if irregularities are detected, to eliminate risk of unwanted action from the line differential protection. Also the line differential protection function must have functionality to clearly discriminate between single-phase and multi-phase faults and release single-phase trip for singlephase faults and three-phase trip for multi-phase faults. The line differential protection function must have a robust calculation principle for the restrain current for all power system phenomena to avoid false release of trip command. Restrain current based on fundamental frequency component only may in some cases result in lack of stabilisation. In such cases additional stabilisation must be included. The chosen trip characteristic must properly define the restrain and trip area to achieve fast release of trip command for all internal faults and reliable stability for all external faults. 2

The trip characteristic and calculation principle for the restrain current must clearly distinguish between external and internal faults, and block trip command for that or those phases with detected external fault in case of heavy CTsaturation. 3 Offer from vendor side The paper as an example will only consider, Requirements to the Distance Protection Function and Requirements to Line Differential Protection from Statnett and will describe How ABB handle these requirements and offers the required functions to satisfy the Protection Family. 3.1 ABB Solution for the requirements to Distance Protection All the requirements to Distance Protection from Statnett could be supported by the standardized product REL 670 [5]. This paper will mention the main functionality in brief. The line distance protection is a, up to five zone full scheme protection with three fault loops for phase-to-phase faults and three fault loops for phase-to-earth fault for each of the independent zones. Individual settings for each zone resistive and reactive reach give flexibility for use on overhead lines and cables of different types and lengths. Both Quadrilateral and Mho characteristics are available in REL 670. Figure 4 shows typical quadrilateral distance protection zone with load encroachment function is activated. ZMCPDIS function has functionality for load encroachment which increases the possibility to detect high resistive faults on heavily loaded lines. The independent measurement of impedance for each fault loop together with a sensitive and reliable built in phase selection makes the function suitable in applications with single phase auto-reclosing. Built-in adaptive load compensation algorithm for the quadrilateral function prevents overreaching of zone1 at load exporting end at phase to earth-faults on heavily loaded power lines. The distance protection zones can operate, independent of each other, in directional (forward or reverse) or non-directional mode. This makes them suitable, together with different communication schemes, for the protection of power lines and cables in complex network configurations, such as parallel lines, multiterminal lines. Figure 3 CT saturation caused by HVDC-interconnections All blocking methods/criteria's must have separate setting parameters, which decide if only the phase that has a block criterion shall be blocked, or if all phases shall be blocked (i.e. cross-blocking). The line differential protection must be provided with an unrestrained differential protection function for fast operation for heavy internal faults. The chosen characteristic must properly define the trip area to achieve fast release of trip command for heavy internal faults and at the same time avoid false release of trip commands for all external faults. The distance protection is equally suitable for the application of protection for series compensated lines. Distance measuring zone, quadrilateral characteristic for series compensated lines (ZMCPDIS) include six impedance measuring loops; three intended for phase-to earth faults, and three intended for phase-to-phase as well as, three-phase faults. The distance measuring zone operates according to the non-directional impedance characteristics. The phase-to-earth characteristic is illustrated with the full loop reach while the phase-to-phase characteristic presents the per-phase reach. For the Directional detection for series compensation, in the basic distance protection function, the control of the memory for polarizing-voltage is performed by an under voltage control. The polarizing voltage is a memorized positive sequence voltage. The memory is continuously synchronized via a positive sequence filter. The memory is starting to run 3

freely instantaneously when a voltage change is detected in any phase. A non-directional impedance measurement is used to detect a fault and identify the faulty phase or phases. A special feature with this function is that applications with small power transformers (rated current less than 50 % of the differential current setting) connected as line taps (that is, as "shunt" power transformers), without measurements of currents in the tap, can be handled. The normal load current is here considered to be negligible, and special measures need only to be taken in the event of a short circuit on the LV side of the transformer. IEC05000034 V1 EN Figure 4: Typical quadrilateral distance protection zone with load encroachment function activated 3.2 ABB Solution for the requirements to Line Differential Protection All the requirements to Line Differential Protection from Statnett could be supported by the standardized product RED 670 [6]. This paper will mention the main functionality in brief. Line differential protection applies the Kirchhoff's law and compares the currents entering and leaving the protected multi-terminal circuit, consisting of overhead power lines, power transformers and cables. It offers phase-segregated true current differential protection with high sensitivity and provides phase selection information for single-pole tripping. The three terminal version is used for conventional twoterminal lines with or without 1 1/2 circuit breaker arrangement in one end, as well as three terminal lines with single breaker arrangements at all terminals. Figure 6: Example of application on a three-terminal line with 1 1/2 breaker arrangements In this application, the tripping of the differential protection can be time delayed for low differential currents to achieve coordination with downstream over current IEDs. A line charging current compensation provides increased sensitivity of Line differential protection. Two two-winding power transformers, or one three-winding power transformer can be included in the line differential protection zone (Figure 7). Both two- and three winding transformers are correctly represented with vector group compensations made in the algorithm. The function includes 2nd and 5th harmonic restraint and zero-sequence current elimination. Figure 7: Example of application on a three-terminal line with a power transformer in the protection zone Figure 5: Example of application on a conventional twoterminal line The six terminal versions are used for conventional twoterminal lines with 1 ½ circuit breaker arrangements in both ends, as well as multi terminal lines with up to five terminals. The current differential algorithm provides high sensitivity for internal faults, at the same time as it has excellent stability for external faults. Current samples from all CTs are exchanged between the IEDs in the line ends (master-master mode) or sent to one IED (master-slave mode) for evaluation. Principle of operation In Line differential protection function, measured current values from local and remote line ends are evaluated in order to distinguish between internal or external faults, or undisturbed conditions. The local currents are fed to the IED via the Analog Input Modules and thereafter they pass the Analog to Digital Converter. The remote currents are received to the IED as samples via a communication link. When entering the IED, they are processed in the Line Differential Communication Module (LDCM) where they are time coordinated with the local current samples, and interpolated 4

in order to be comparable with the local samples. In the Pre- Processing Block, the real and imaginary parts of the fundamental frequency phase currents and negative sequence currents are derived. Together with the current samples, they are then forwarded to the differential function block where three different analyses are carried out. The first analysis is the classical differential and bias current evaluation with the characteristic as seen in figure 8. Line differential protection is phase segregated where the differential current is the vector sum of all measured currents taken separately for each phase. The bias current, on the other hand, is considered as the greatest phase current in any line end and it is common for all three phases. Differential protection function and restricted earthfault protection function for auto-transformers, two- and threewinding transformers and differential protection function for shunt reactors Distance protection function Line differential protection function for two or more line ends Automatic reclosing and manual closing device for lines, transformers, bay coupler, etc. Directional overload protection (system protection) Accomplishment of acceptance tests has shown that this is the most efficient method to obtain sufficient knowledge about actual performance for all relevant protection functions. The acceptance test focuses on the complete functionality of new numerical protection devices. With functionality we mean to what extend the different protection functions can be configured and set and as a result of this, be used as protection for critical components in our power system. Statnett has modeled different power systems in the wellknown transient simulation package PSCAD. The models cover actual power system phenomena s and relevant contingencies for evaluation of protection performance. At potential protection locations, outputs like voltages, currents and relevant set of binary signals are recorded and saved as COMTRADE files as shown in figure 9. Figure 8: Description of the restrained-, and the unrestrained operate characteristic The first The two slopes (SlopeSection1,SlopeSection2)and breakpoints (EndSection1, EndSection2) as shown in figure 7 can be set in PCM600 or via the local HMI. Current values plotted above the characteristic formed by IdMin and the dual slope will give a start in that phase. There is also an unrestrained high differential current setting that can be used for fast tripping of internal faults with very high currents. 4 Evaluation of new protections in acceptance test [7] During the past eight years Statnett has performed acceptance tests of new numerical protection functions. The purpose with these tests is to get sufficient information about the different functions to fully evaluate whether they are applicable or not as protection functions for critical components in our power system. To limit the number of acceptance tests, only new numerical protection functions that protects critical components in our power system (i.e. lines, transformers, shunt reactors and busbars) have to pass through a complete acceptance test. This includes the following protection devices: Busbar protection with integrated circuit breaker failure protection Figure 9 Simulation and test object set up For different types of protection, all important contingencies are simulated, including internal and external faults. Pre fault, fault, post fault and all types of re-closing sequences are simulated in detail. Saved COMTRADE files are then loaded into a numerical test device, and applied to test object exposed for acceptance testing as shown in figure 9 above. The actual protection performance is then evaluated in detail. The acceptance test includes four different steps. Statnett have a set of documents, which summarize Statnett requirements to the different protection functions mentioned. In the first step these documents are used when evaluating the functionality of actual protection functions by reading manuals, presentations and discussions with vendor.this step will also include an evaluation of the PC-software tool used for configuration, parameter setting, disturbance handling, 5

etc. based on Statnett requirements. If the overall information seems to fulfill Statnett requirements to the different protection functions Statnett continue with the next step, otherwise no acceptance test is performed. In the second step the vendor receives necessary power system data including data for the protected object, information about different types of faults and all type of reclosing, expected action from the test object, etc. from Statnett. Vendor is then responsible for parameterization and configuration of necessary protection functions within the test object and handed over to Statnett. During the third step, relevant sets of COMTRADE-files are applied to the test object. Vendor normally delivers the protection(s) to Statnett during this test phase. In some cases Statnett have used vendors test facilities. The actual protection performance for all protection functions are evaluated in detail with use of internal fault- and event recorder and compared with expected action. In the fourth and last step all results are studied in detail, and Statnett conclude whether or not the test object is applicable for use as protection for critical components in our power system. Statnett presents and discuss the test results with the vendor. If the acceptance test is successful, Statnett standardize the accepted firmware for the frame agreement period. During the frame agreement period vendor may discover the need for corrections in protection algorithms and release a newer firmware than accepted by Statnett. Before Statnett can accept use of a newer firmware version for an already accepted protection function it must receive documents from the vendor with a detailed description of the new functionality and why it has been implemented. Statnett then decide to continue using the already accepted firmware version or start using the latest firmware version with/without running through a limited or complete acceptance test. 5 Benefits and challenges when standardising the technical solution within the frame agreement period Benefits: A standardized configuration is a harmonized configuration when it comes to the protection and control functionality implemented. The most obvious standardization is to use protection functions configured in a specific way but also for example naming of disturbance recorder signals, hardware channels and LED s. From vendor side, there are several benefits that the utility uses standardized configurations; Tested configurations: The diversity of configurations is reduced. The ones used are uniform and tested meaning that the need for support is minimized. Uniform configurations: When support from vendor is requested, the standardized configurations are essential since fault tracing is kept simpler due to the fact that certain sources of the problem can be ruled out. For example vendor knows that the configuration is working and can focus on identifying hardware related or surrounding system problems. Product upgrades; since the vendor knows how their products are used and not only which products are used, recommendations when it comes to product upgrades are easier and safer to do. Perceived product quality; since the vendors products are used and configured in a standardized, tested way, the handling and perception of the products is easier making the perceived product quality higher. The vendor deliver the same versions of system software, firmware versions and configuration and parameterisation tools for all deliveries made during the term of the frame agreement. This makes the operation and maintenance easier for Statnett. If there is discovered a problem in the software that may affect the delivered system's functionality, the vendor will specify the need for and carry out testing in connection with upgrading software in already delivered systems. Statnett shall determine whether or not the upgrading shall be carried out. The control server is used as the maintenance portal to the control and protection system and for remote diagnosis. This makes it possible to locate the fault on a system down to e.g. the I/O card of a protection. The maintenance personnel can then more efficiently repair the system and regain operation. Challenges: Since different utilities normally uses different standard configurations, there is still a large amount of configuration alternatives to handle worldwide. The challenge for the vendor is to keep track of these configurations, keeping them up to date and matching them with the evolving requirements. Another challenge can be that product orders are not matching the standard configuration when it comes to for example hardware. The reason for this might be that EPC s (Engineering, Procurement and Construction) are not aware of the utilities standard configuration. One way to solve this is that the utility is alone responsible for their standard configurations and also provides them to the EPC s. 7 Conclusions This paper describes Statnett and ABBs experience using frame agreement for Digital Substation Automation Systems. It focuses on the protection requirement and acceptance of vendor product used to standardise the solutions for the Digital Substation Automation Systems (DSAS). The cooperation between Statnett and ABB have resulted in protection functions that are according to requirements and a success for both parties. 6

Acknowledgements The authors extend their sincere acknowledgements to the colleagues at Statnett and ABB (both in Norway and in Sweden) for their cooperation and supports. References [1] Statnett, Technical Specifications, Part 2, Inquiry No. 13/00568>, (GENERELL DOK-1264305-1-1), (2013) [2] Statnett, App_2_4_General Protection Requirements (GENERELL DOK - 1247526-1 - 2), (2013). [3] Statnett, App_2_7_Requirements to the Distance Protection (GENERELL DOK - 1247501-1 - 2), (2013) [4] Statnett, App_2_8_Requirements to Line Differential Protection, (GENERELL DOK-1247500-1-2), (2013) [5] ABB AB, substation automation products, Line distance protection REL670, Technical Reference Manual, (2013). [6] ABB AB, substation automation products, Line differential protection RED670, Technical Reference Manual, (2013). [7] Statnett, App_2_3_Statnett Acceptance Test Procedure (GENERELL DOK-1264305-1-1), (2013). 7