Experience from Statnett R&D Digital Substation Project

Authors: Rannveig Loken and Nargis Hurzuk, Statnett, Norway


Traditional philosophy for transmission systems where protection and control functions are divided in separate hardware units was challenged by a more compact hardware design. The Digital Substation pilot includes protection and control functions for two 300 kV transmission lines in the same IED hardware (hereafter named Protection and Control Unit - PCU).

The objective of this compact solution in the Digital Substation pilot was to investigate if the PCUs are capable of processing two bays in parallel and if it is possible to test protection for one line without affecting the operation of the other line.  Further, if controlling two line bays from one common PCU is manageable from an operation point of view.

To achieve this, it was necessary to define the bay controller and protection functionalities of the PCU as independent and separate logical devices, each of which consists of a number of logical nodes.

Using equipment from several vendors in the Digital Substation pilot enabled evaluation of fundamental aspects like capabilities and technological readiness level of components from various suppliers, as well as issues related to multivendor interoperability.

A crucial characteristic of the digital substation was the level of interoperability between IEDs from different vendors. Normally Statnett uses two main protections for a 300 kV bay, but in the Digital Substation pilot this has been increased to include investigations of interoperability between equipment from more vendors.

Figure 2 shows the simplified topology of the Digital Substation pilot project. On the right-hand side, a simplified single line diagram of the primary equipment is shown. The conventional current and voltage measurements were connected to the Digital Substation pilot from the existing Frame Agreement 3 SAS system. The Digital Substation pilot was located in the same control room as the existing SAS system. The Non-Conventional Instrument Transformer (NCIT) was connected in series with the existing conventional current transformer in the overhead line, and was the only new part of the Digital Substation pilot that was placed outdoor. The rest of the equipment was located in four new cabinets in the existing control room as shown in Figure3. Figure 2 shows only a few of the Cisco switches used in the pilot, one for the station bus and two for the process bus.

It is possible to operate and monitor the Digital Substation pilot through the dispatch center. The connection to dispatch center from the Gateway, and the topology of the station bus (green) is similar to the architecture of the normal SAS used in Frame Agreement 3 in Statnett. GOOSE is used for interlocking between bays on the station bus instead of hardwired connections.

Time synchronization is an essential aspect of process bus applications and the system is synchronized from two time sources, GPS1 and GPS2, using the Precision Time Protocol (PTP) v2 to ensure 1µs accuracy. GPS1 and GPS2 are connected directly on the process level.  The merging units on the process bus need the most accurate timing because they have to sample measurements with a high sample rate (4000 samples per second). In addition, some functions (e.g. synchro check) require measurements from several MUs. The time stamps of these measurements must correspond to within a maximum allowed time difference (~1µs), otherwise the PCU may block the function due to inconsistency.  

The required accuracy is achieved by the IEEE 1588 precision time protocol and is the chosen solution for this project. When using PTP all devices in the network have to support PTP.

The PTP Best Master Clock Algorithm is implemented in the IEDs and they selected the “best” timeserver for synchronization.

The approach in the Digital Substation pilot has been to combine many functions in a restricted number of PCUs. With reference to Figure 2, the main Protection and Control Unit (PCU1) is a Siemens 7SA87, configured with both the Bay Control Unit (BCU) and the protection functionality for two separate lines.

Each of the bay control parts includes breaker closing functions such as synchro check, dead bus/dead line logic, and Automatic Reclosing (AR). Control of both lines are realized in the same display of the PCU, and there is no control from the Human-Machine Interface (HMI) panel in this project. The HMI panel is used to get an overview of the full digital substation.

Traditionally backup operation of breakers and disconnectors has been achieved using a conventional mimic in the relay cabinets with pushbuttons, switches, and indicators to perform direct hardwired commands. This is not possible in a fully digital substation, instead redundant BCUs provided the back-up control in the pilot station.

Control of the breaker and disconnectors (incl. bay interlocking), and auto-reclose of the CB, are normally performed exclusively by the main bay controller - BCU1 for a given line. BCU2 for the same line then simply follows the control level and Auto Recloser (AR) status of BCU1. When BCU1 is active, an “Active” GOOSE is sent on the Process Bus (PB) to BCU2, and status is reported to the Gateway via the station Local Area Network (LAN).

The back-up PCU2 is based on the SPRECON-E protection firmware from Sprecher implemented on a Linux based industry computer. PCU2 is similarly configured with control and protection for the same two bays, but is active as the bay controller only when the main PCU1 is in one of several failure modes. Although PCU2 is active as the bay controller only when PCU1 fails, protection functions from all the PCUs are of course active and operating in parallel at all times.

PCU3 (Prot 3 in Figure 2) is an ABB REL 670 device, configured with distance protection for lines 1 and 2, as well as Phasor Measurement Unit (PMU) functionality for line 1, and PCU4 (Prot 4 in figure 2) is a Sprecon E-P embedded solution and contains distance protection for line 1. A teleprotection Unit (TPU) from ABB was also included in the Digital Substation pilot.

DANEO 400 is used as protection unit in the pilot installation for differential protection. The purpose of the differential protection is to test the combination of analogue and digital measurements in the same unit.

The DANEO compares and triggers (in case when the delta value exceeds a pre-set limit) of 2 different channels for example 1 analog input channel with 1 digital input channel from the process bus and between two digital channels one connected to MU and one to the SAMU. DANEO 400 also has a fault recording feature and is used for analyzing purposes with remote access.

Redundancy for tripping and operation of the breaker is ensured by two Switchgear Control Units (SCU). With the exception of the trip commands, which are always sent to both SCUs, PCU1 and PCU3 rely on SCU1 for operation and indications, whereas PCU2 and PCU4 rely on SCU2. PCU2 and PCU4 are fully independent from PCU1 and 3, and have auxiliary voltages from different circuits.

The Sampled Values (SV) streams from the Merging Units (MU) and Stand-Alone Merging Unit (SAMU) are currents and voltages measured on a real transmission line and bus bar, but the station control units are operating only on a process simulator. SV streams according to IEC61850-9-2LE with 80 samples per cycle (F4000S1I4U4) are used for metering, protection and control functions.

The energy meter is delivered by Landis and Gyr and was able to use SV streams for the metering. We are still in discussion about how the qualification of the metering chain can be fulfilled with the process bus approach.

In this project, Line 1 and Line 2 are in reality the same line (see on the right-hand side of Figure 2). With both an optical and a conventional current transformer measuring on the same, real transmission line, it is possible to see if there is a difference in protection response to the two measuring methods. Therefore, the different PCUs were configured to use SV streams from optical and conventional current transformer for the two lines in a PCU.

An additional benefit is that this distribution of SV streams also ensures redundancy in the measurement chain, and hence a single failure of an IED, SCU or merging unit does not lead to any restriction for the control (or protection) of the lines - control is available either via PCU1 or PCU2. In case of a double failure in both chains (MU/SAMUs/SCUs) the control and protection functionality is lost (as is the case in the current conventional solution with main 1 and main 2 protection system).

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