b5_118_2012_performance assessment of an iec 61850-9-2 based protection scheme

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Performance assessment of an IEC 61850-9-2 based protection scheme for the mesh corner of a 400kV transmission substation

P. A. CROSSLEY*, L. YANG, H. Y. LI, U. ANOMBEM A. WEN The University of Manchester National Grid Co. U.K. U. K. R. CHATFIELD, J. WRIGHT M. REDFERN, X. SUN ALSTOM Grid University of Bath U.K. U.K. SUMMARY The primary plant and instrument transformers used in transmission substations generally remain in-service for many decades, typically 40 – 70 years, and are renewed only when physically or mechanically life-expired. However, the secondary systems, which include protection and control, are changed significantly more frequently. The current replacement rate for protection and control on the UK transmission network is about 5% per annum, i.e. it take approximately 20 years to complete the replacement cycle. However, the asset life of numerical protection and control is often considered to be 15 years, although 10 years may be more realistic due to declining technical knowledge and support, product obsolescence and difficulties in obtaining spares. One way to overcome the problem is to develop a new architecture for substation secondary systems by deploying technologies such as standard interface modules, the bay process bus and the IEC 61850 communication protocol. IEC 61850-9-2 Process Bus proposes a local communication network that replaces traditional hard-wiring with serial communication of analogue and binary signals using Ethernet messages. A Process Bus solution reduces the life-time cost of the system, improves flexibility and functionality and allows substation secondary equipment retrofitting to proceed without the long circuit outages normally required. Once the new technology is installed, secondary equipment renewals, particularly those occurring mid-life in the primary plant lifecycle, can be undertaken in a safer, quicker and easier way with reduced or no outages of primary systems. This enables vendor interoperability and provides easier modification and extension of the secondary schemes; particularly those related to reconfiguration and feature enhancement by software means, rather than the hardwiring changes required in the past. As a precursor to the widespread deployment of IEC 61850 technology within the UK utility AS3 (Architecture of Substation Secondary System) project, it must be ensured that the reliability and performance of IEC 61850 based protection and control schemes meets or

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exceeds that of its hardwired SICAP (Substation Information, Control and Protection) predecessors. The aims of the AS3 Architectures are to allow the replacement of faulty Intelligent Electronic Device (IED) without outages; enable the refurbishment of bay level secondary systems with minimal disruption to the primary system; simplify the isolation procedures between the primary and secondary systems; and reduce the risk of mal-operation. This paper presents the research outcomes of two industry-university projects (Working Stream 1 & 2) aligned to the AS3 project- WS 1: Evaluation of the IEC 61850 Process Bus Architecture and Reliability. This was designed to study the AS3 generic architecture, the process bus reliability and the optimal architecture when considering the life cycle costs and the design of a testing system; WS 2: Protection Performance Study for Secondary Systems with IEC 61850 Process Bus Architecture. The objective was to design and evaluate the performance of a prototype protection scheme, implemented using the Process Bus architecture and applicable to the corner of a mesh transmission substation. The scheme was evaluated in a laboratory, using a series of test scenarios designed to verify the operating performance, and the results are reported in this paper. KEYWORDS Substation Automation System (SAS) – Protection - IEC 61850 - Process Bus – Architecture -Intelligent Electronic Device (IED) - Merging Unit (MU) – Reliability – Performance Testing 1. INTRODUCTION The IEC 61850 standard on “Communication Networks and Systems for Power Utility Automation” ushers in a new era in substation design. It offers new possibilities for maximising the economic and effective utilisation of the transmission assets and the network topology. The 61850-9-2 sub-set of the IEC 61850 standard, referred to as Process-Bus, allows the replacement of conventional analogue and binary signals with Ethernet messages and enables the use of a digital communication link between Merging Units (MUs), which provide the interface between the current & voltage transformers and the switchgear, and the bay devices, such as the protection relays, bay controllers or meters [1]. Sufficient confidence must be demonstrated in the application of this new technology before it can be widely applied on a transmission network. The projects aim to investigate, quantify and optimise the level of security, dependability and operating speed of secondary schemes, implemented using the IEC 61850 process bus architecture and operating within a UK utility’s mesh topology substation. Prototype protection schemes were evaluated for practical use, including actual interoperability between different manufacturers, degree of maturity, robustness, and other operating advantages and disadvantages. The paper describes how a comprehensive test and validation facility, based on multiple test-sets, can assess the

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operating performance of a system that integrates merging units, accurate time synchronisation, process communication buses and IEDs. The operating characteristics of conventional hardwired relays and IEC 61850-9-2LE relays were verified individually and the complete system performance further evaluated under various process bus architectures and test scenarios. MUs from different manufactures were wired into the protection schemes to assess system compatibility and interoperability. The worst case scenario of process bus traffic based on the current 100Mbps network was simulated and the system response investigated. Recommendations for process bus architectures and the corresponding communication requirements are presented and analysed, one of the priorities is to avoid degradation of system performance. Evaluation of the reliability and performance of a process bus based protection and control scheme, applied to the mesh-corner of a transmission substation, is a significant step towards increasing the acceptance of IEC 61850 and the implementation of “copper-less” secondary systems. 2. IEC 61850-9-2 PROCESS BUS BASED PROTECTION SCHEMES In conventional hardwired substations, primary voltages and currents are measured and scaled-down using voltage and current transformers. The analogue outputs of these transformers are then connected to protective relays using copper “hardwired” cables. The secondary voltages and currents are processed in a suite of relays using various protection algorithms designed to detect and locate faults or abnormal conditions. Appropriate commands (e.g., trip, block and reclose) are then issued and disseminated to the switchgear via hardwired cables. Recent development of non-conventional instrument transformers (NCIT), Merging Units (MUs) and the widespread deployment of processor based relays permits truly effective implementation of all-digital protection and control system. The concept of a “digital” substation is based on the use of intelligent primary equipment and networked secondary devices, which share digital information and realise distributed protection and control functions via a common Ethernet network implemented according to IEC 61850. Figure 1 illustrates the conceptual architecture of a digital substation. The process bus increases the possibilities for using radical and new substation designs and the associated protection and control solutions. The utilisation of high-speed peer-to-peer Ethernet communications of Generic Object Oriented Substation Event (GOOSE) messages and multicast Sampled Analogue Values (SV) from Merging Units allows for future introduction of distributed and wide area protection and control. Such applications deliver significant advantages as compared to a conventional system, but do require an assessment of how they impact on the operating performance of the overall protection and control scheme; since a novel implementation must not degrade the system performance.

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Figure 1 Architecture of IEC 61850 Substation Automation System

The reliability and operating performance study into a complete protection system implemented using IEC 61850-9-2 process bus architecture and applied to the mesh-corner of a UK 400kV transmission substation, is presented in this paper, as shown in Figure 2. The local substation (A) uses process bus architecture and the remote conventional “double busbar” substation (B) uses traditional hardwired protection.

Figure 2 Schematic diagram of a mesh substation

Different configurations for the bay and inter-bay process bus architectures are discussed and the results of laboratory trials presented with respect to reliability, security, dependability, interoperability and operating speed. The performance is compared with that of a similar protection system implemented using traditional hard-wiring. 3. PROCESS BUS ARCHITECTURE AND RELIABILITY 3.1 Architectures Figure 3a shows a simplified version of the National Grid connectivity diagram for a mesh corner transformer bay. This diagram shows the hard wired copper connections between the Current Transformers (C10, C11, C13, C14, C15, C18 and C19), Voltage Transformers (V2 and V3) and the Transformer Protection. The Transformer protection is represented by the

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Intelligent Electronic Device(s) - IED(s) - which perform main and backup protection functions for this bay. A. Scenario 1 Figure 3b shows the bay after the implementation of the process bus. Each CT and VT is connected to a merging unit (MU) and each circuit breaker is connected to a circuit breaker controller (CBC). The MUs and CBCs are connected to an Ethernet switch (SW1). These new connections are made using fibre optic cables (FIOC). This scenario is based on a star topology.

C2

C3 C5

C6

X120 C7

V1X103

X420

C9

X428

X126

X124

C10

T1

X113

C11

C12

C4

C8

C1

C13C14

C16C17

C18

C19

C15

V3

V2

IED(S)

X110

a

Figure 3. Transformer bay (a) before and (b) after the introduction of the process bus

For system success the MU would need to be able to receive current and voltage information from the connected CT and VT and be able to send CT and VT sampled values to the appropriate IED(s) via the SW. In addition, the CBC should be able to receive trip signals from the appropriate IED(s). Figure 4 shows Figure 3b redrawn with the focus on the CBCs, MUs and SW.

Figure 4. Process Bus Scenario 1

B. Scenario 2 In scenario 2, as shown in Figure 5, each device is duplicated; for example, Circuit Breaker X110 is connected to both CBC1 and CBC2. If CBC1 fails, a trip signal from the bay level IED(s) can still be sent via CBC2. Each duplicated device is boldly outlined.

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C. Scenario 3 As in Scenario 2, each device is duplicated, but now each CBC and MU is connected to both SWs. Hence, if one SW fails, the connected CBCs and MUs still can be accessed via the other SW. Scenario 3 is shown in Figure 6.

CBC1MU1

MU2MU3

SW1

MU4MU5

MU6MU7

CBC2MU8

MU9MU10

SW2

MU11MU12

MU13MU14


3.2 Reliability and Life Cycle Cost Evaluation A. Reliability Analysis Device reliability is the probability that the device can perform its intended function for a specified interval under stated conditions. Equation (1) was used for the evaluation of device reliability [2].

Device Reliability r = t

expMTBF

(1)

where: t = period under consideration and MTBF= Mean Time Between Failures (years). An MTBF of 100 years means that in a statistical population of 100 devices, on average one device is expected to fail each year. It is assumed there is a constant failure rate and the period under consideration is the first year, thus t = 1. The process bus scenarios shown above are systems made up of a combination of devices and in order to evaluate the system reliability, the event tree methodology was used [2]. B. Life Cycle Cost Analysis The minimum life cycle cost can be used to determine an optimal solution. The life cycle cost was estimated as follows:

LCC (t) = CIRM(t) + CF(t) (2)

where: LCC: life cycle cost, CIRM: sum of investment cost, renewal cost and maintenance cost and CF: failure cost including replacement cost and penalty cost

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within the CIRM, the investment cost (CI) is the cost of acquiring the devices, the renewal

cost (CR) is the cost of replacing the devices at their end of useful life, and the maintenance cost (CM) is the cost of carrying out scheduled maintenance on each component/device. 3.3 Methodology Application In this paper, the device reliability and availability figures were calculated based on the MTBF data presented in [3], and engineering judgement (see Table 1 for the MTBF, Investment Cost and device lifetime estimates).

Table 1: Device MTBF, Investment Cost and Lifetime Data

Device MTBF (years)

Investment Cost

Lifetime (years)

SW MU CBC FIOC

106 57 57 30

1000 3500 3500 200

15 15 15 25

Table 2 shows the (investment, failure and life cycle) costs for each process bus scenario for the mesh corner transformer bay. Figure 7 shows the cost versus reliability curves for these scenarios.

Table 2: Reliability and Cost data for transformer bay process bus scenarios

Scenarios Reliability Investment Renewal and Maintenance

(IRM) Cost

Failure Cost Life Cycle Cost

1 2 3

0.859113 0.980151 0.993327

106180 212360 220680

185055 44469 48652

291235 256829 269332

It can be seen from both Table 3 and Figure 7 that the minimum LCC occurs in Scenario 2. Based on this, the proposed optimum architecture would be that of scenario 2.

0

50000

100000

150000

200000

250000

300000

350000

0.850 0.875 0.900 0.925 0.950 0.975 1.000

Reliability

Co

st

IRM Cost Failure Cost Life Cycle Cost

Figure 7. Cost Versus Reliability

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4. PROTECTION PERFORMANCE TESTING The IEC 61850 based SAS is a viable solution for use in both new substations and in older/refurbished substations where it is necessary to integrate the IEC 61850 based solution into the legacy SAS. A typical application of process bus is a substation extension project, where a new line, capacitor bank or transformer needs to be added to an existing substation. Process bus based protection must integrate into a substation, where existing conventional relays are already in service and must remain in service during the upgrading process. Some of the advantages of a process bus based application are that they are able to:- achieve “plug and play” installation/replacement; realise vendor interoperability between MUs and IEDs; facilitate vendor inter-changeability to simplify Post Delivery Support Agreement (PDSA); and apply fibre-optic connections to reduce the EMC requirements. 4.1 Experiment platform and procedure This paper investigates the performance of the feeder protection schemes shown in Figure 8. The Local Top (LT) and Remote Top (RT) relays of the panels are configured as Feeder Main-1 current differential scheme while Local Bottom (LB) and Remote Bottom (RB) relays are configured as Feeder Main-2 distance scheme. Standard 100/1000TX electrical cables with RJ45 connectors have been used to connect the Local Panel’s IEC 61850 version protective IEDs to the Ethernet communication network. Test set A provides analogue signals to the remote hardwired relay and IEC 61850 SVs (direct injection or via Merging Unit) signals to the local 61850 relay. Test set B is able to generate up to 3 synchronised SV data streams. Ethernet switches from two suppliers are integrated into the system using “Star” and “Bridge” architectures and are then used to test the Ethernet switch inter-changeability and time offset and the delays associated with the MU. The packet delays of the SVs when using the three architectures (point-to-point, star and ring topology) are simulated and calculated in a dynamic communication network simulation tool. The operating performance and characteristics of the four relays are first tested and compared. Next the distance and differential scheme responses were evaluated according to four test scenarios and the detailed results reported in [4] and [5].

Figure 8 Test setup for feeder local (IEC 61850) and remote (hardwired) panels

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4.2 Dependability and stability test for current differential scheme The term reliability when applied to a protection system can be considered in terms of dependability and security. Dependability is defined as the probability that the protection operates satisfactorily when required, i.e. it does not fail to trip. Security is defined as the probability that the protection does not operate when not required to do so, i.e. it does not produce unwanted trips. For test scenario 1, the test set was configured to generate a pre-fault condition (nominal current, relays expected to remain stable) followed by an external fault (three times nominal current and the relays must not trip). The fault current was next switched off and finally the scenario was switched to an internal fault (3 x nominal current) and the relays were now expected to trip. Tests were repeated 100 times; the combined scheme remained stable during external faults and healthy conditions; the average trip time when the scenario was switched to an internal fault was 26.30ms. Figure 9 demonstrates an example for test scenario 1.

Figure 9 Example of scenario 1 test for current differential scheme.

For test scenario 2, the test set was configured to generate a pre-fault set of signals (nominal current and the relays were expected to remain stable). The scenario was then switched to an internal fault (3 x nominal current and the relays must trip) and after an appropriate delay the currents were switched off. The test set then waited for the close command of the relays and when received the scenario was switched to an external fault; note, the relays were expected to remain stable and not trip. Tests were repeated 100 times and the combined scheme remained stable during external faults and healthy conditions, the average trip time when switched to internal fault was 27.60ms. Figure 10 demonstrates an example for test scenario 2.

Figure 10 Example of scenario 2 test for current differential scheme.

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4.3 Overload test for IEC 61850 distance relay The need to restrict multicast traffic to specific subscribers and avoid overloading the network with an excessive numbers of data streams was investigated using multiple Merging Units and test sets. Figure 11 shows the SVScout capture of the SVs data stream traffic on a process bus with star topology when operating as a part of an IEC 61850 distance relay.

Figure 11 Overload test for IEC 61850 Distance relay (8 SV streams) Multiple tests were performed to verify the operating performance for three fault types, i.e. L-E (300 repeated shots), L-L (300 repeated shots), L-L-L (100 repeated shots), covering Zone 1 (tnom=0), Zone 2 (tnom=200ms), Zone 3 (tnom=600ms). The average trip times and standard deviations are shown in Table Ⅰ. The typical size of a SV data stream is about 5~6Mbps. The results prove that the distance relay’s operating speed performance is not degraded for L-E and L-L faults, but is slightly delayed and has higher standard deviations for three phase faults, when eight SV data streams are running along the current 100Mbps. Theoretically 20 SV data streams occupy the full network capacity, but normal expectations are around 12~14 streams when using a star architecture.

Table ⅠOverload test result for IEC 61850 distance relay (8 SV streams)

Fault Type

Zone 1 Trip time (ms) 4Ω tnom =0

Zone 2 Trip time (ms) 12Ω tnom =200ms

Zone 3 Trip time (ms) 20Ω tnom =600ms

Average Standard Deviation



L-E (300 shots)

19.697 0.8256 218.439 0.9965 618.256 0.9464

L-L (300 shots)

19.834 0.9140 218.591 1.2411 618.368 1.0132

L-L-L (100 shots)

23.644 4.7230 229.607 6.6208 628.692 7.2794

5. CONCLUSION A number of process bus architecture scenarios have been introduced for a UK utility’s mesh corner transformer bay. The methodology for evaluating the reliability has been discussed, and this methodology has been applied to the aforementioned architecture scenarios. The paper described how a prototype feeder protection scheme was designed and the operating performance evaluated when the process bus at the local terminal was heavily loaded with multicast traffic. The relay at the remote terminal was a part of a traditional hardwired protection scheme and was used as the reference with which to compare the local IEC 61850-9-2 distance relay. A

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comprehensive series of tests were used to evaluate the operating performance and characteristics of the hardwired, IEC 61850-9-2 relays and the combined current differential and distance schemes in terms of security, dependability and operating speed. Results indicate that given an appropriate network configuration, the performance of a process bus based protection scheme is comparable with a conventional hardwired scheme. The optimal application of a process bus based protection scheme can be achieved by close collaboration between protection specialists in academia and industry. These results provide a reference to help increase the acceptance of process bus application to provide reliable and cost effective protection applications. BIBLIOGRAPHY [1] INTERNATIONAL STANDARD IEC 61850-9-2, Communication networks and

systems in substations – Part 9-2: Specific Communication System Mapping (SCSM) – Sampled values over ISO/IEC 8802-3, First edition 2003-05.

[2] U. B. Anombem, H. Li, P. Crossley, R. Zhang and C. McTaggart, “Process bus architectures for substation automation with life cycle cost consideration”, in Conf. Rec. Managing the Change, 10th IET Int. Conf. on Developments in Power System Protection (DPSP), 2010, pp. 1 - 5.

[3] G. W. Scheer and R. E. Moxley, “Digital Communications Improve Contact I/O Reliability,” presented at the Power Systems Conf. Advanced Metering, Protection, Control, Communication, and Distributed Resources, March 2006.

[4] Li Yang, Peter Crossley. “Performance testing for a multivendor IEC 61850-9-2 process bus based protection scheme”. (International Protection Testing Symposium. Brand, Austria, October 4-5, 2011).

[5] Li Yang, Peter Crossley, Wen An, Ray Chatfield ， John Wright. “Performance assessment of a IEC 61850-9-2 based protection scheme for a transmission substation”. (The second European conference and exhibition on Innovative Smart Grid Technologies (ISGT-EUROPE 2011), December 5-7, 2011).

b5_118_2012_performance assessment of an iec 61850-9-2 based protection scheme

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