Protection and Control System Utilization of NCIT & Process Bus
Digital substations are gaining traction, with real world commercial installations being accepted among utilities. Main enablers for this technology are the non-conventional instrument transformers and standalone merging units, utilizing IEC 61850 process bus communication. IEC 61850 offers to improve the overall reliability and resiliency of the 21st century substation using digital communication. High voltage measurement and control has recently been improved to offer easily installed sensors with direct digital outputs that have excellent accuracy stability and faster frequency response. By going directly to digital, these state-of-the-art sensors preserve signal integrity and ease of connections by using fiber communications. Unlike previous optical sensors that had some reliability concerns, the introduction of a new Fiber Optic Current Sensor (FOCS) design combines the inherent isolation of the optical current sensor with redundant systems to power, accurately process, and output signals capable of directly supporting substation automation. These modern optical sensors embedded in free-standing form using modern polymer insulators free of oil or SF6 gas, or integrated into other power equipment such as live or dead tank breakers and gas insulated substations, can be used to simplify the merging unit architecture and deliver the full promise of 61850 to utilities and their customers.
The introduction of stand-alone merging units provides an equivalent approach to digitizing the secondary signals available in the switchyard. This approach also, simplifies the mode of communication between the equipment in the switchyard to the relays in the control panel. In coherence to the IEC61850 standard, the merging units easily virtualizes any CT or PT signal available today from a conventional sensor. By implementing these merging units in the so called process bus, the complete potential of adhering to the IEC61850 standard can be envisioned.
This session discusses basic application variants, results and field experiences involving the NCIT, combined with the flexibility and modularity of the stand-alone merging units for process bus IO system. As well, the paper covers field installations of the GIS sensor technology and the availability of 61850-9-2 implementation.
An overview will be provided to show the digital substation’s key benefits highlighting safety, reliability, functional consolidation, and cost drivers leading to customer savings. Utilities are facing an increased demand on substation information and the digital substation opens the door for real time data exchange. The Digital Substation solution’s key technologies (relays, advanced substation automation and modern instrument transformers) are the advantages where IEC 61850/Ethernet are positioned as technology enablers and not obstacles.
2.0 Digital Substation and the Industry Challenges
Digital substations has evolved over the past two decades. The introduction of the microprocessor into substation automation, protection and control has revolutionized the utility industry for the good and the bad. The push from a dumb grid to a “Smart Grid” has enabled the digital world to expand well beyond the traditional scope of protection, control and SCADA. The ideal vision of knowing all aspects of every substation networked into an intelligent grid opens the opportunity to have information at our finger tips. The challenges continue to be the strangle hold from regulatory standards for reliability and security when in reality, a smarter and highly intelligent automation system can in fact make the grid much more reliable and dependable. The other challenge results as utility personnel struggle to find adequate time to research and explore new technologies that could change the landscape of the power system protection and control network. Our younger and upcoming generation of system and protection engineers have lived in the digital world their entire life. As the aging infrastructure continues to feebly perform, the system has very little knowhow on whether it is working or not, on the ability to take proactive decision to limit outages or damage, restore consumer much faster and provide the post mortem information to make necessary improvements.
The last challenge is our aging and retiring workforce. The amount of knowledge leaving our industry annually is mind blowing. Reverting back to the point on the younger generation, another challenge is the company loyalty or should we say lack of company loyalty. This has flown out the window long ago, where today’s younger employees have no concept of a lifetime at a single employer and likewise, companies with the increasing business pressure on performance, have also lost the ability to retain the younger employee in dire times. From a technology perspective, the younger generation has grown up in the digital world. Try taking their iPhone or Droid away from them as it will cause a meltdown. In all seriousness, the digital world in the society has only been possible with the tight integration of information, resources on a common platform (open standards) and Moore’s Law continuing to prove that if it is not possible today, technology will continue to advance making it practical tomorrow.
The digital substation is no different. Open standards are now in place and have matured to the point of different manufacturers (some more than others) interoperating on common platform. Technology for the complete digitization of the power system information as well the speed and performance of the information exchange allow real-time performance at a better accuracy and open up the possibilities for the digital substation to be embraced. To that point, who will be embracing this new technology? You do not have to look far as our younger generation has the capability and oh by the way, they have spent their entire lives in the digital era so they are also fearless to these new technology advances and are the key to pushing this new technology to revitalize the protection, control and automation into the modern era.
3.0 The Standard – IEC 61850
Without standards, we revert back to the 1990s when proprietary solutions resulted in an Hitachi Energy system not communicating to a GE System or back then, GEC products all being installed with network interface modules (NIMs) to at least try to have minimal information available to the Network Control Centers. The industry today can be appreciative of the John Burger vision from American Electric Power who started the movement in the US market to migrate the industry to a common standard. The history of the EPRI LAN Initiative to UCA to IEC 61850 is a paper in itself but what has transitioned in the last twenty years changed the landscape for today and tomorrow’s modern control systems.
The second communication hierarchy introduced in the 2004 standard was the process bus as defined in IEC 61850-9-1 (point to point unidirectional) and IEC 61850-9-2 (multipoint bidirectional) for the purpose of communication between the protection and control bay level devices and modern instrument transformers installed at the primary apparatus in the switch yard. Edition 2 of IEC 61850 released over the past two years, IEC 61850-9-1 has been removed as its usefulness and application where limited. IEC 61850-9-2 for process bus communications main attributes are the streaming Sampled Measure Values (SMV) where the modern sensor digitalize the power system current and/or voltage measurements into a package of synchronized measurement values communicated to the protection and control devices. The standard does not define the type of sensor or the means for the digital transformation but rather it defines a merging unit that collects the sensor information and prescribes a standard means to package and communicate the output.
The exchange of sampled values between these modern sensors or non-conventional instrument transformers (NCIT) and intelligent electronic devices (IED) devices for protection functions and other purposes allows for the real-time digital information exchange. The interconnection between the sensors and actuators, which are physically connected to the power system process, is why the term “process bus” has been used as the interface to the protection and control systems. This enables the standard-compliant digitalization of the last mile in substation automation, and brings with it a wide range of benefits in The Digital Substation.
4.0 Non-Conventional Instrument Transformer Types for Gas Insulated Substations
The NCIT and process bus technology has experience from a series of six outdoor gas insulated substations (GIS) with process bus and NCIT technology installed and commissioned in 1999. As the IEC 61850-9 part of the standard was not released until 2004, these early installation were based on proprietary communication architectures. That notwithstanding, the sensor and digitalization technology experience was invaluable and is still utilized today with modern merging units supporting IEC 61850-9-2. The use of fiber-optic networks not only eliminates vast parts of the copper cabling, it also increases operational safety by isolating the primary from the secondary process.
The NCIT sensor families cited above are based on a redundant sets of Rogowski coils for current measurement and two independent capacitive dividers for voltage measurement. The Rogowski coil is a device used to measure alternating current. It comprises a toroidal winding where the current carrying conductor passes through the center of the toroid. The current output of the sensor is a voltage, which is proportional to the derivative of the current. The Rogowski coil has superb performance and improves linearity over a wide dynamic range from metering to protection and address the main issues of the traditional CTs from the inductive open circuit as well saturation performance during fault conditions. The modern sensor also contains no oil, so this equipment is both environmentally friendly and extremely safe.
Designed with fully redundant design of the sensors (including the associated electronics), this allows two completely independent and parallel protection systems, boosting the availability of the entire secondary protection system. As sensor electronics can be replaced independently and without requiring a shutdown of the entire protection system, maintenance and repair activities require less time and because there are no live parts need to be handled, it makes these maintenance activities much safer. The GIS Sensor also saves significant space as it mounts on the gas insulated bus or on the hybrid breaker bushing compared to requiring a free standing or integrated current and potential transformers which are much larger in size as well additional space required in the substation switchyard layout.
Since the first installation in 1999, more than 300 such non-conventional instrument transformers and their electronics have been installed in Powerlink Australia’s substations. Notably, in more than 10 years of service, none of the primary converters has failed. Based on experience values, the mean time between failures (MTBF) of the sensor electronics is over 300 years. This demonstrates the extreme reliability and high availability of the sensors, even in the very demanding environmental conditions of the Australian climate.
5.0 Non-Conventional Instrument Transformer Designs for Air Insulated Substations
In today’s electrical systems, currents in high voltage equipment are measured using bulky and heavy current transformers (Photo shows 420kV oil-filled CTs) in oil insulated or SF6 insulated designs. These use the principle of electromagnetic induction to generate a small secondary current, typically 5A or 1A nominal at rated current, from a primary current, which then serves as an input for protection relays or energy meters. Such transformers have represented the state of the art for many decades and they operate reliably under the harsh conditions found in an outdoor substation.
However, besides their size and weight, they have a number of additional shortcomings - the most important of which is that, as a result of magnetic saturation and limited bandwidth, the waveform of the secondary current is often not a true image of the primary current. Over 40 years ago, it was recognized that the Faraday Effect could be the basis of a new, and better, technology for current measurement. But it is only in the last 20 years that appropriate technology has become sufficiently mature to allow it to be used as a commercially attractive basis for fiber optic current sensor (FOCS) applications. The remarkable progress made by the optical communications business has provided many components that can be re-used for the FOCS - such as light sources, fiber-optics, modulators and photodetectors.
Optical current and voltage sensors have found significant interest in recent years for use in electric power transmission [1-3]. Particularly, fiber-optic current sensors have become rather mature and have been finding commercial applications not only in high voltage systems but also in industry, e.g., in the measurement of high direct currents (dc) in the electro-winning of metals (aluminum, copper, etc.) . Optical sensors offer considerable benefits over conventional instrument transformers. They are inherently free of magnetic saturation and typically have a measurement bandwidth in the range of kilohertz (determined by the data rate). But also bandwidths in the range of tens or hundreds of kHz are feasible. As a result fiber-optic current transformers deliver within their measurement range a true image of the primary current, also in case of fast transient currents, short circuit currents, and alternating current (ac) with dc offset. Furthermore, optical CTs are lightweight and of small size. This makes it possible to operate them not only as freestanding devices but one can easily integrate them into other power products. Substation footprint and installation costs are reduced. Other advantages are enhanced safety (no risk from open secondary CT circuits or catastrophic failure) and environmental friendliness (no oil). Optical current sensors are immediately compatible with modern digital substation communication, which helps to eliminate large amounts of copper cabling.
Modern fiber-optic current sensors have been developed for use in electric power transmission as well as for the measurement of high dc in industrial applications. Fiber Optic Current Sensors use light to deduce the precise magnitude of current that is creating the magnetic field. FOCS designs for high-voltage substations includes FOCS integrated with DCB (Disconnecting Circuit Breakers), FOCS kits for integrating with other high-voltage equipment such as gas-insulated switchgear and generator circuit breakers, and the free-standing fiber optic current sensor (FOCS-FS) that have been more recently offered in the market. The major difference is that these new modern sensors now are providing direct to digital outputs, and not analog outputs as earlier designs had offered.
5.1 FOCS Design and How it Works
FOCS designs exploit the Faraday Effect, which defines that left and right circularly polarized waves propagate at slightly different speeds when they travel in a medium that is subject to a magnetic field [4-8]. The main components of the FOCS are an optoelectronics (OE) module or sensor electronics module at ground potential and a coil of sensing fiber, which is wound around the current conductor.
The OE module includes a semiconductor light source and a closed-loop detection circuit with a fiber-optic polarizer, an optical phase modulator and a digital signal processor. The module sends two light waves with orthogonal linear polarization to the sensing fiber coil. At the coil entrance a fiber-optic polarization converter transforms the linear waves into left and right circularly polarized light waves. These waves travel at different speeds through the sensing fiber in the magnetic field (caused by the current) as a result of the Faraday Effect, and this in turn creates an optical phase difference. The waves are reflected at the end of the fiber and they retrace their optical path back to the optoelectronics module where they interfere at the polarizer.
The signal that results from the interference depends on the phase difference and is measured by a photodiode. The closed-loop control circuit reverses the current-induced phase shift by means of a phase modulator so that the phase difference of the waves when they interfere at the polarizer is always kept at zero. The feedback signal to the modulator is then essentially an image of the primary current and the digital sensor output is derived from this signal. A particular advantage of this closed-loop detection scheme is that the signal is perfectly in proportion to the primary current over the entire measurement range. The roundtrip phase difference of the two light waves is proportional to the number of fiber loops and the line integral of the magnetic field along the closed path described by the sensing fiber. Geometrical parameters such as the coil diameter or the position of the conductor inside the fiber coil do not affect the signal. Currents outside the coil have also no influence.
Operation of the sensing fiber in reflection mode has the advantage that the sensor becomes immune to mechanical disturbances. The mirrored coil end swaps the polarization states of the light waves. As a result, vibration-induced phase shifts cancel each other out over one roundtrip of the waves while the non-reciprocal magneto-optic phase shifts double. The basic concept of the sensor was invented at Hitachi Energy in 1992 and has been later adopted by others.
By appropriately selecting the number of fiber loops, the measurement range can be optimized for specific applications. The typical sensor as made for power transmission applications has a range of ±180kA. The operating temperature range of the sensor head is from below -40 °C to 105 °C. The OE module is designed for operation in a heated outdoor cubicle. It can be operated with three fiber coils in parallel to cover all three phases normally found in a high-voltage installation.
5.2 Ascertaining accuracy and stability
The FOCS system is designed to meet the requirements for metering and protection in electric power transmission systems according to IEEE Class 0.15s, IEC classes 0.2s and 5P, 5TPE. In order to achieve such performance, it is essential that the circular polarization states of the light waves in the fiber coil are well maintained under all conditions of operation and not disturbed, e.g., by mechanical stress acting on the fiber. Furthermore, the temperature dependence of the Faraday Effect (0.7% per 100°C) must be taken into account.Techniques have been developed that allow packaging the sensing fiber in a stress-free manner, and to inherently compensate the variation of the Faraday Effect from temperature by means of the fiber retarder which generates the circular light waves . The two lower right illustrations graphically represent the method of the temperature compensation.
As mentioned, the polarization converter (fiber retarder) at the entrance to the fiber coil converts the two linearly polarized light waves coming from the opto-electronics module into left and right circularly polarized waves before the light enters the fiber coil. The scale factor (sensitivity to current) of the sensor varies with the phase retardation ρ introduced by the polarization converter in a parabolic manner illustrated here. The red heavy curve segment indicates the scale factor decreasing at increasing retarder temperature, which balances the opposite change of the Faraday Effect with temperature.
If the room temperature retardation of the polarization converter is set to about 100° instead of 90° the scale factor decrease at rising temperature stemming from the retarder (along the red heavy curve segment shown above) just balances the increase in the Faraday Effect as shown in the lower right illustration. The theoretical scale factor versus temperature curve is calculated neglecting bend-induced birefringence in the fiber coil. Some modifications apply in case of non-negligible birefringence.
As shown below, with these measures, the sensor output becomes independent of temperature well less than ±0.1% over a range of at least from -40 to 85°C without the need of an extra temperature compensation using additional T-measurement. Even at 105°C, the sensor coil is still within the requirements of IEEE metering class 0.15 and IEC metering class 0.2.
The physical principle used and the proper choice of materials, coupled with absence of any non-linear effects defines excellent predictability and perfectly linear relationship of the FOCS signal to the applied current, shown in the following curves.
The FOCS overall system accuracy is independent on the measurement current range, so the same sensor may be designed and used for protection and measuring in the whole dynamic range of common power devices. Further on, the system measures only the instantaneous values of a current (more precisely, in the case of Hitachi Energy’s FOCS it is measured average current during 700-800 nanoseconds), without any effects of “current history” curve. Therefore, the same system can be used for measurement of AC and DC currents, as well as for AC with DC offset.
5.3 Applications of FOCS
1. FOCS three-phase sensor kit
FOCS for applications in high voltage substations may be designed as a standard redundant 3-phase sensor kit shown here consisting of two optoelectronic modules, three sensor heads, and the connecting fiber cables. An opto-electronic module (sometimes also called a sensor electronics module or secondary converter) houses the light source and opto-electronics to interrogate a set of three fiber coils (3 phases). Each sensor head (primary converter) of a given phase contains two fiber coils. The two fiber links of each sensor head are protected by a common robust and rodent proof fiber cable. Fiber connectors at the optoelectronic modules facilitate the FOCS installation as there is no the need of fiber splicing in the field.
This kit format (especially the sensor head design and dimensions) can be provided for installation inside of power equipment such as dead and live tank breakers, and potentially built into disconnect switches and into power transformers to provide current sensing.
2. FOCS three-phase free-standing sensors
Fiber Optics Current Sensor- Free Standing (FOCS-FS), example pictured below, is meant to mount in substations similar to traditional current transformers (CTs), but offers significant improvements over CTs.
The free-standing sensor system FOCS-FS is available from 245 kV to 800 kV voltage ratings for various applications, and is designed using a redundant 3-phase sensor kit (shown above) with pre-packaged sensors embedded onto sealed polymer insulators. The two fiber leads to the coils are protected in a special cable placed inside the hollow insulator volume that is filled with low pressure nitrogen gas to maintain a clean environment. The cable runs to ground through the gas volume and leaves the insulator pole through a gas-tight feed-through. The opto-electronic modules are mounted in a cubicle along with redundant power supplies that is shielded for EMF immunity. This enclosure can be attached to the support frame of one of the three insulator poles or can be free-standing on a foundation.
This new design exceeds magnetic CT technology in safety of operation, and offers accurate current measurement and wider frequency response, footprint and weight savings, as well as environmental friendliness. The fast response of FOCS and precise measurement of both ac and transient dc results in improved substation protection and monitoring functions. The digital interface of FOCS-FS is designed for IEC 61850-9-2LE communication for direct integration into digital substation automation systems.
3. FOCS in Live Tank Circuit Breakers
The theoretical results did predict the performance of the FOCS design in a real-world application test where the FOCS was used within a Hitachi Energy live tank breaker (LTB). This excellent performance stability of the FOCS was verified in a field test at a 420 kV substation over a period of more than five years (shown in diagrams to the right are the result after first 3.5 years). The test set-up consisted of a redundant 3-phase FOCS system (FOCS 1, FOCS 2) connected via IEC61850-9-2LE links to digital relays and a conventional CT with protection and metering cores that was used for reference. The optical sensors were integrated in the HPL 420 kV live tank breakers (see below photo from site).
The small and easily adaptable size of a current sensor fiber coil makes it possible to integrate the sensor into power products such as the LTB, for a redundant three phase FOCS system. Each of the three ring-shaped sensor head housings contains two fiber coils and is mounted into the upper end of the corresponding breaker pole. The current path is modified in such a way that the current flows through the coils. The two fiber-leads to the coils are in a special protective cable that is suited for the live tank breaker (LTB) SF6 gas atmosphere. The cable is taken to ground through the gas space, and leaves the breaker pole through a gas-tight feed-through. Two three-phase OE modules are mounted in a cubicle near the breaker or are attached to the breaker support frame. Redundant IEC61850-9-2LE links connect the sensors to protection relays in the control housing as shown here.
This solution has many benefits:
- In-factory installation: The integration of the sensor heads and OE modules into the LTB is done in the factory. The only remaining installation work to be done in the field is to set up the cubicle for the OE modules and deploy the fiber cables.
- The sensor head is part of the LTB pole and does not interfere with the LTB assembly in the field. In fact, only minor changes in the LTB assembly procedures are needed.
- There is no need for an extra insulator to bring the fiber from high voltage to ground.
- Zero footprint: The space required for a conventional CT or standalone optical CT is eliminated. This reduces the substation size and saves real-estate costs, particularly when the sensors are combined with disconnecting circuit breakers. This can eliminate almost ½ of the footprint of a conventional installation.
- The CT foundation and support structures are no longer needed.
- The outdoor placement of the optoelectronics modules near the LTB minimizes the length of sensor fiber cable required.
- The transmission of digital optical signals from the sensor electronics to the substation control function via the redundant IEC61850-9-2LE links is immune to disturbance. The design of the LTB with an integrated FOCS was verified to be in compliance with the relevant type tests as defined by IEC standards. The tests included high voltage tests, T100 tests (i.e. verification of breaker operation at high current and voltage), temperature rise tests (temperature rise at a current of 4,000 Arms) as well as mechanical endurance tests consisting of over 10,000 breaker open-and-close operations.
Proper sensor operation before, during and after the tests was verified.
The curve data shown to the left shows an actual fault detected by the installation that was measured by FOCS 1 shown in curve (a). Curve (b) defines the relative signal difference between the FOCS system (FOCS 1) and the conventional CT protection and metering core over this same period.
This data illustrates the superior performance of FOCS in case of fault currents with a DC offset with both FOCS systems on that phase showing the same response with their signal difference remains essentially zero (black solid curve (b). In contrast the responses of the protection CT and metering CT differ significantly. The maximum transient error of the metering CT, at about 200 ms on the time scale of (b) corresponds to about 90% of the actual instantaneous current. This is seen in the corresponding signal differences between FOCS 1 and the protection and metering CT (red dotted and blue dashed curves, respectively).
5.4 Ascertaining reliability
Robustness and reliability requirements apply to new technologies such as fiber-optic current sensors. So whether packaged as an installable kit, free-standing HV system, or embedded into HV Circuit Breakers, the FOCS technology has already been proven in the harsh environments of the electro-winning industry and breaker use over a period of several years. The demands on reliability in high-voltage substations are some of the most stringent – with little or no maintenance or re-calibration expected during a lifetime in the field. Reliable systems provided to the market place today have been verified on the FOCS and its components by accelerated aging and long-term performance tests in-house. Multiple self-diagnostic functions within the Opto-Electronic Modules continuously monitor the operation of the sensor to insure the output information is valid. Furthermore, pre-commercial field installations serve to gather experience of installation and commissioning of the new technology and to prove its reliability under substation conditions.
5.5 FOCS benefits
Keeping in mind the use in the power transmission business, particular benefits of FOCS systems are:
A. High accuracy
Within the bandwidth determined by the output data rate, the sensor delivers a true image of the primary current waveform that is not affected by magnetic saturation or remanence. The DC contents of a current are correctly recorded. The sensor targets both protection and metering applications.
B. Reduced environmental impact
The FOCS saves the aluminum, copper, insulation materials and transformer oil that constitute a corresponding conventional CT. A 550 kV CT, for example, can have a weight of about 3.5 tons, which may include 500 kg of oil.
C. Zero footprint capability
The sensor need not be a standalone device, but may be integrated into or added to other power products such as in circuit breakers or on bushings shown here.
D. Safety of operation
Risks of catastrophic failure are minimized or eliminated due to the inherent isolating nature of the optical cables and the use of polymer insulators on free-standing designs. Safety is assured by eliminating concerns due to an open secondary CT circuit as all outputs are optical digital signals and the electronics are galvanically separated, and therefore isolated from high voltages.
E. Digital communication
A fiber-optic IEC61850-9-2LE process bus connects the FOCS to bay-level control and protection devices and replaces large amounts of copper cable - as much as several tens of kilometers per substation. It also provides more flexibility in the configuration or later reconfiguration of a substation. The communication data rate is 4 or 4.8 kHz at line frequencies of 50 or 60 Hz, respectively. Higher data rates with 256 sampled values per power cycle (which is 12.8 or 15.36 kHz at line frequencies of 50 or 60 Hz, respectively) are also implemented and, it use of some alternative interface options is desired, even data rates of several hundreds of kilohertz are technically feasible (this may be of interest in other applications).
5.6 Looking ahead
The FOCS technology will serve as a platform for other high-voltage applications. The variable diameter of the sensing head allows the sensor to be easily adapted to high-voltage equipment such as gas-insulated switchgear (GIS) or generator circuit breakers. By choosing the fiber loop number appropriately, high accuracy can also be achieved at low currents, e.g. in zero sequence current measurements. New or improved substation protection and monitoring functions may follow from the fast response of the FOCS and its precise measurement of both AC and transient DC.
Using the FOCS in HV Substations means the measurement is digitized right at the source and transmitted as a digital signal, via the process bus, to the protection and control IEDs, as well as the revenue meters. This eliminates copper runs from the substation back to the control room. Coupling the benefits of fiber-optic current sensor solution with direct to digital capability will facilitate the development of digital substations and enable the grid to get smarter. It is also more eco-efficient and is designed to minimize footprint and enhance safety. New FOCS designs address demanding performance requirements for accuracy across a wide temperature range. It is inherently free of magnetic saturation, making it ideal for capturing fast transient currents, short circuit currents. The compact design helps achieve reduced substation footprint as it requires much smaller space compared to conventional instrument transformers. It is also an eco-efficient solution that uses no oil or gas, eliminating the risk of explosion.
The FOCS is one of a range of non-conventional instrument transformers (NCITs) that can make substations entirely digital. These NCITs have to be every bit as reliable as the equipment being replaced – and they are: Over the past 30 years of real work experience, companies like Hitachi Energy working to improve Optical Sensors have gained a unique perspective of how to make these systems more reliable. Specifically in recent years, Hitachi Energy alone has supplied more than 650 installations of the FOCS in various industries with excellent field reliability performance. Extensive use of NCITs makes a substation simpler, cheaper, smaller and more efficient.
6.0 Stand Alone Merging Unit (SAM) for the Conventional Sensors
While NCITs are ideal solutions for new installations, however it is also important to provide retrofit solutions for brownfield upgrades. To provide a bridge between traditional and digital technology, stand-alone merging unit (SAM) is used. The SAM is used to digitize potential transformer and current transformer analog signals into digital communications. AA SAM is functionally shown in the figure below.
A SAM600 system combines voltage and current measurements, which are available on the SAM600 system bus, into an IEC 61850-9-2LE compliant stream. This combined IEC 61850-9-2LE stream is available on all IEC 61850 access points on all SAM600 modules. The stream merging on the IEC 61850 access points is enabled by default and can be set via configuration parameters. Stream merging requires certain quality criteria to be met of the streams available on the SAM600 system bus. If those criteria are not met, then the stream merging is disabled.
For maximum flexibility, the SAM is modular. Key components of the SAM include: CT interface, VT Interface, and a Time Sync module.
The SAM600-CT interfaces any conventional current transformer with a 1A or 5A secondary interface. Interposing CTs are not required, as different ratios are set by parameters using theSAM600 configuration tool. The neutral current as provided in the IEC 61850-9-2LE stream can either be measured directly or calculated as a sum of the three phase values. A binary input is provided to signal a test condition in the IEC 61850 9-2LE stream via a corresponding quality bit in order to allow for blocking conditions in the IEDs receiving the 9-2LE stream. The input can be wired to an existing test switch. The polarity of the binary input is configurable.
SAM600-VT interfaces any conventional voltage transformer with a configurable input voltage between 100V – 125V AC (line-line) on the secondary interface. The measurement chain is calibrated and temperature compensated. The neutral voltage as provided in the IEC 61850-9-2LE stream is calculated as the sum of the three phase voltages. Binary inputs are provided to signal test conditions in the IEC 61850 9-2LE stream. Three inputs, which can be wired to the secondary contacts of MCBs, are pre assigned to signal a fuse failure per phase. A fourth input is provided to signal a test condition in the stream. This input can be wired to an existing test switch. The polarity of the binary inputs is configurable.
SAM600-TS provides time synchronization and IEC 61850 access point functionality. A SAM600 system can run in a free-running mode, or can synchronize against a Pulse per Second (1PPS) signal. Conversely, SAM600 can synchronize through SAM600-TS other merging units or IED devices through the five 1PPS outputs. SAM600-TS includes two additional IEC 61850 access points which provide IEC 61850-9-2LE streams from the SAM600 system to bay level protection and control.
SAM modules may be mounted using a DIN-rail and are typically placed in a station panel or marshalling kiosks near the primary equipment. A marshalling kiosk with redundant SAMs is shown in the figure below.
By adhering to the same 61850 standard, these merging units have the ability to seamlessly integrate with any other Non-Conventional instrument transformer that is compatible with the same standard. This natural blend opens up the application possibilities of these devices.
Such a modular approach to integrating IEDs in the process bus provides the additional flexibility of routing the sensor signals to the protection IED in the most optimized way. It opens up various new engineering solutions to implement our existing protection philosophies. One best example is the implementation of decentralized bus bar protection.
7.0 Benefits of the digital process bus replacing copper
Every copper wire in a substation is a potential risk whether it is from a CT or PT circuit or a 125V DC control wire. The highly inductive current transformer secondary circuit poses the largest safety concern. The hazard results when an energized current transformer wire is unknowingly disconnected. From inductive circuit theory, current flowing through an inductive circuit cannot be instantaneously changed from
5 Amps to zero. A quick thanks to Wikipedia; the mathematics
formula implicitly states that a voltage is induced across an inductor, equal to the product of the inductor's inductance, and current's rate of change through the inductor. As the inductance does not change during the open circuit, the rate of change in current from 5 to 0 Amps instantaneously has the derivative (di/dt) resultant go to infinity. Thus, the formula’s product voltage is dominated by the derivative blowing up to infinity and produces a very large voltage across the open circuited wires. Related to the substation application, an open CT secondary is equivalent to the inductive current going to zero and depending on the secondary load, arcing will occur as these dangerously high voltages build putting field personnel at risk of serious injury or even fatality and equipment and the substation at risk from electrical fire. Minimizing copper leads to greatly improved safety.
The digital substation process bus for breaker status and control where replacing copper control wires with digitized binary information can alone justify the switch to digital. Going digital can cut the quantity of copper wires in a substation by upwards of 80% which is a substantial cost saving and, more importantly, a significant safety enhancement.
8.0 Benefits of the Digital Substation
A fully digital substation is smaller, more reliable, has a reduced life-cycle cost and is simpler to maintain and extend than an analog one. It offers increased safety and is more efficient than its analog equivalent. Not every substation needs to be catapulted into a wholesale digital world – it depends on the substation size and type, and whether it is a new station or a retrofit of the secondary system. Different approaches and solutions are required. Flexible solutions allow utilities to set their own pace on their way toward the digital substation.
- Increased system availability by replacing of electromechanical, static or old fashioned digital secondary equipment with modern numerical devices bundled to a real-time communication network and connected to a higher level system such as a substation automation system or SCADA, allows continuous monitoring of all connected secondary equipment.
- Increased system and personnel safety utilizing remote control combined with authority and rule-based access and remote testing, allows increased system safety and security. Personnel safety is increased since more tests can be done without putting the test personnel close to primary equipment or without the risk of inadvertently opening current transformer (CT) circuits.
- Increased functionality with a fully distributed architecture coupled with un-restricted communication and process capability enables the system to add new functions easily with zero or minimal outage time, giving the user additional benefit with respect to safe and secure system.
- Interoperability through deployment of IEC 61850 compliant solutions, interoperability with regard to communications with other manufacturer’s equipment can be achieved. The benefit is IEDs from different suppliers can be mixed on the same bus without concern for communication incompatibilities.
The introduction of the IEC 61850-9-2 process bus standard in substations has provided a platform that all manufactures can develop upon to achieve the overall goal of interoperability. John Burger’s visionary ideas are being realized with the technology available today. In addition to the interoperability benefits, footprint of primary switchgear reduction using sensors (NCIT) replacing conventional measuring transformers allows a much safer work environment. On the secondary system will also see massive reduction of cabling by going from a lot of copper cables to a few fiber optic communication cables will mean reduced costs for cables and associated equipment such as cable trenches and installation material. Also the improvements in fiber optic current sensors and the integration of the standalone merging units provide utilities and engineering firms with a great tool box for the future deployment of this maturing technology. For retrofit applications, the possibility of installing the new process bus system in parallel with the existing system will allow the substation to remain in service during the main part of the work. This will be a big advantage, reducing outages to a minimum, during the retrofit process.
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- IEC 61850-9-2 Communication networks and systems in substations – Part 9-2: Specific Communication Service Mapping (SCSM) – Sampled values over ISO/IEC 8802-3
- IEC 61850-8-1 Communication networks and systems in substations – Part 8-1: Specific Communication Service Mapping (SCSM) – Mappings to MMS (ISO 9506-1 and ISO 9506-2) and to ISO/IEC 8802-3
- IEEE 1588 Precision Clock Synchronization Protocol for Networked Measurement and Control Systems
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