What Drives the Business Case for IEC 61850?

Author: Eric Udren, Quanta Technology, USA

New parts are continuously being published as 61850 reaches across the transmission grid to generation sources, and out onto today’s DG-equipped distribution feeders.  I’m not being profound in forecasting that IEC 61850, as opposed to eventually being finished, must grow and branch forever to support the operation of our rapidly-evolving grids and businesses.

To grasp the business case and to succeed with the required organizational transformation we’ll highlight below, one must first understand that IEC 61850 is not just a communications protocol.  Its facets include all the elements listed in Figure 1:

  • Communications protocol layers and data configurations.
  • The modeling of each utility application as it interfaces to others.
  • Architecture of the ensemble of applications.
  • Architecture of communications layers on which models exchange information.
  • Engineering process that interconnects modeled applications on the modeled architecture with automated computing tools.
  • The elimination of long lists of individual signal points and unique behaviors.
  • Ethernet and optical fiber based communications network carries all operational exchanges.
  • GOOSE high-speed mission critical protection and control traffic to eliminate wiring.
  • A list of services to handle various utility PAC needs.
  • Coexistence of IEC 61850 and other applications on Ethernet networks.

While we discuss economic advantages below, IEC 61850 brings major changes in how the utility designs installations and conducts business.  Experience in North America has already shown how, without attention to the transformation, the benefits won’t be achieved.  Internationally, manufacturers with 61850 product lines have already fielded multiple generations and thousands of installations of substation P&C systems based on 61850.  Many of these are in turnkey substations where a single manufacturer has taken total responsibility for design, integration, and commissioning; and supports the purchasing utility through the life of the installation.
Utilities in North America have taken a more deliberate approach.  Most are accustomed to designing, integrating, and maintaining their own standard designs.  Risks and process change requirements of such a dramatically new technology clashed with inertial challenges of large established organizations. 

There were problematic trials in which imperfect first-generation IEC 61850 products showed interoperability challenges and were not well fitted to the old methods of P&C design and support.  At that time, IEC 61850 had its own problems - crudeness or malfunctions of integration tools; shortcomings of the Edition 1 standard, varying vendor implementations of specified application models (the logical nodes and their process interfaces), and unspecified implementation details of specified functions that were not interoperable. 

These issues had to be overcome - they occurred for reasons we understand and have been fixing.
Now senior management at an increasing number of companies want their conservative organizations and team members to plow ahead, solve the problems, and work to achieve the benefits.  As old designs become more costly and as the industry faces cost and revenue pressure, potential savings are hard for business leaders to ignore.  At the same time, IEC 61850 sees more acceptance at the engineering and first line management level due to generational change.

We have to face the business case question now.  The electric utility industry ultimately can’t support multiple design paths that are fundamentally incompatible. We’re talking no longer about competing vendor-specific protocols; the issue now is cost and difficulty of maintaining traditional and network-based P&C in the same organization. 
It’s not only that 61850 can be cheaper - although it has cost advantages - as that the way we have done P&C will become too expensive to sustain in parallel.

Physical Installation Cost Savings

Perhaps the most widely cited benefit is elimination of most point-to-point wiring - the visible change is dramatic, as shown in the example of Figure 2.  Every vendor presents before-and-after images like this.  The cost savings are calculated according to total construction costs, which vary among projects and locations.  Don’t count only the wiring cost itself – the ease of work and construction error reduction in low-density panels also help during construction, throughout the service life of the system, and at time of next replacement.  We’ll say more about that next replacement below.

In determining cost impacts, it is important to recognize that IEC has multiple services, each with its own impact on costs.  The following are some of the variations that have been used:

1. Station bus with MMS and discrete control wiring - With this first use of Ethernet networking, the user already achieves a big wiring reduction cost compared to the old fully discrete design with separate SCADA RTU.  However, compared to a networked integration solution using Modbus, DNP3, or IEC 60870-5 protocols and a station data concentrator, there is no wiring cost saving.  IEC 61850 does promise engineering cost reduction if smoothly-functioning automated 61850-6 based integration tools eliminate the hand mapping of legacy protocol points.  The development of point mapping and settings for each communicating IED with legacy protocols is a lot of work and expense.  Highly standardized conventional designs help to control this cost, but IEC 61850 aims to transform the configuration process to a high-level specification of functions to integrate along with a listing of devices and substation or installation configuration – the automated configuration process and tools handle the connection details for the points specified in IEC 61850 functional models.

2. Station bus with added GOOSE messaging - This yields the massive reduction in control building wiring cost that Figure 2 shows.  Switchyard wiring still lands on control house panels and connects to front-line relays and process IEDs.  While the Figure 2 installation looks impressively simpler, vendors often fail to point out that the application complexity of the old wiring has not gone away.  It moves to the configuration or mapping of hundreds or thousands of GOOSE messaging bits.  To avoid work and errors, the user needs both a good automated configuration tool and a tightly-managed setting or configuration storage archive to get all the work reduction benefit and to avoid “moving connections” problems during maintenance.

3. Station bus with GOOSE messaging and binary I/O extension to switchyard - Figure 3 shows how a number of utilities have installed binary I/O IEDs or relays in weatherproof switchyard cabinets or in apparatus control cabinets with optical fiber connections and GOOSE messaging. This arrangement replaces all of the switchyard wiring for status point state reporting and for apparatus control including breaker tripping.  Some control relays also accept inputs from tap position indicators and similar non-protection analog sources.  This may eliminate 70% to 80% of the total switchyard wiring, leaving only instrument transformer and switchyard auxiliary power wiring.

4. Full process bus including sampled values service - Figure 4 shows a full IEC 61850 installation with merging units (MUs) distributed around the switchyard, for which the only remaining yard wiring is for station service and auxiliary energizing power.  While Figure 4 shows a single bus for all merging units and protection IEDs, the author prefers a more conventional separation of zones and of redundant systems.  The new IEC 61869-9 merging unit standard employs the IEC 61850-9-2 sampled values service in such a way as to support a variety of process bus architectures, from a station-wide bus with big multi-input MUs at one extreme to individual, granular MU modules with only one signal input and connection to only one or a limited number of the relays.  Sample-timing signals are conveyed over existing data fiber connections to MUs via IEEE 1588 precision time protocol and IEC 61850-9-3 timing profile.  The granularity of MU sizes – the availability of MUs with just one or two three-phase input sets versus those with more inputs – plays a role in calculating the cost savings.  Granular MUs require more fiber runs and fiber connections in the control building.  The cost of more MUs versus the price of each must be determined.  However, small MUs enable installation as close as possible to the signal source or control points with minimum switchyard cross-wiring.  They can also reduce maintenance cost, simplifying replacement of failed units in service.  If the mechanical installation is carefully planned for maintenance, it may be possible to replace a failed MU without an outage of power apparatus.

5. Full process bus plus switchgear integration and/or optical instrument transformers (OITs) - Once the user has architected an IEC 61850 installation with process bus and MUs of moderate to fine granularity, it’s a straightforward step to install MUs inside apparatus or IT connection enclosures to limit wiring to just direct interface connections.  This opens the door for users and apparatus manufactures to have MUs installed and wired at the apparatus factory.  The field installation then simplifies to installing the apparatus as before and connecting the fibers that route back to the control building or relay location.  This can cut installation costs to the minimum and can greatly speed up construction while reducing wiring errors.  Points of technician exposure to hazardous wired IT secondary circuits are minimized.  This safety enhancement has a soft but huge business case benefit that may sell process bus on its own.  While optical instrument transformers have found only limited acceptance to date, they can directly incorporate the MU functionality to bring even more construction cost savings benefits, along with improved signal accuracy, and the unique property of completely eliminating hazardous wired IT secondary circuits. 

IEC 61850 Lifecycle Cost Savings

In actual business case evaluations, wiring cost savings have varied substantially among users.  However, when a potential 61850 user looks forward over the life of the installation and beyond, the cost savings mount.  Here are a few of the major opportunities:

1. Condition-based maintenance - Utilities allocate huge budgets for protection system maintenance testing. When the products and the PAC system are both properly designed for gapless monitoring of performance and failures, time-based maintenance testing is almost fully eliminated.  All system interconnections needed for protective relaying are inherently and continuously monitored and will alarm the moment they cease to function.  GOOSE messaging and sampled values services monitor interconnecting wiring in a way that wasn’t possible with conventional wiring.  The author’s June 2010 PACworld article on maintenance alternatives explains the concepts.  Only certain unmonitored peripheral connections – notably breaker tripping capability – need occasional testing.  With correct design, the residue of required time-based testing can be carried out by a normal operational trip, or by natural operations of or fault exposures of the PAC system.  In North America, the opportunity for condition-based maintenance (CBM) has been included in the NERC reliability standard for protection system maintenance, PRC-005-6 (the current version of what was PRC-005-2 in the 2010 PACWorld article).

Be careful about eliminating the entire maintenance budget - relays and IEDs will still fail and need troubleshooting and replacement.  Technicians will remain occupied in any case with sustainment work - replacements of obsolete PAC systems – for the foreseeable future.

2. Interoperable replacements - When it becomes necessary to replace a failed or obsolete product having IEC 61850 communications, the functional interfacing becomes more straightforward and the new integration may be largely automated.  The physical interfacing is simple as explained below.  This can eliminate major reengineering work. 
Note that the demand for this capability puts great pressure on the manufacturers to create carefully compliant interoperable implementations of functions; users can demand that the compliance of each product type or platform be demonstrated with a conformance test by a certified laboratory, according to the requirements of IEC 61850-10, and using the testing procedures developed by the UCA International Users’ Group Test Procedures Working Group.
The TC 57 WG 10 writers of the 61850 standard parts have been embracing the need to create clearly stated requirements with minimum interpretation variations.  Major recent standards development projects, including the creation of functional definitions in machine-readable UML format, move the industry in this helpful direction.

3. The most sustainable installations - Any new PAC installation, whether built around IEC 61850 or a legacy means of functional interconnection, is designed with products using multiple types of microprocessors and interface communications with relatively short technical lives.  The products have typical rated technical lives of 15 years or less, and the trend is to a shorter life.  Battleship-rugged electromechanical relay panels with lives of 50 years or more are no longer functionally acceptable, or affordable. If the new relays must be replaced far more often, we can at least recognize that the constant-currency prices of modern microprocessor and IEC 61850 relays are in the range of 2% to 5% of equivalent protection components with far less capability.  Utility organizations must get into the habit of planning sustained future capital allocation to carry out required replacement programs.  Once the sustainment painting of the bridge is completed, it will soon be necessary to return to the other end and begin painting again.

Accordingly, new PAC panels must be designed with physical and interconnection features to support easy replacement of a particular protection element - protection for one zone, with separated redundant systems that are easily replaced individually without disturbing any other part of the installation.  The author maintains that, with the increased stress on the electric grid and the difficulty of obtaining maintenance outages, the PAC system must be designed for live replacement and commissioning of zone elements without an outage. 

Designing to these requirements in legacy PAC systems calls for special wire routing, terminal blocks, and multiple tandem test switch and link arrangements to enable such zone element swaps.  Even then, generational changes in wiring approach may foil the design and require some redesign and rewiring that calls for an outage.  By contrast, IEC 61850-based PAC designs with a few fiber connections minimize this risk and the cost of the panel design; and accelerate the replacement work.  Replacement without an outage is practical if testing and commissioning features in Edition 2 of IEC 61850 parts are generously used.
In any case, test the sustainable panel design thoroughly in a lab before deployment, and train field personnel there, so that the design is debugged and the sustainment team is ready to routinely and safely carry out this work.

4. Practical distribution integration on a large scale - Modern distribution applications with distributed generation and customer load control will require integration of huge numbers of intelligent communicating devices installed all along the circuits and throughout the system.  Substation controllers and circuit-wide PAC IEDs will exchange PAC information, some at high speed, to control voltage, to protect selectively for faults, and to reconfigure the circuit for minimum outages or for compliance with equipment ratings.  Controllable inverters, generation sources, energy storage systems, and controllable loads all need to communicate with controllers for specific circuits and for the system at large.  The cost of integrating all this apparatus by custom engineering for each circuit is difficult to fathom and is ultimately unaffordable.  For distribution applications with massive counts of devices to integrate, IEC 61850 functional interface definitions and automated integration capability makes special sense.  This is why government agencies have been promoting this single international multivendor standard aimed at easing these massive integration challenges. (Figure 5).

5. Enterprise value of real-time and historized information – A standard Ethernet network based PAC system design, deployed across the transmission and/or distribution system, collects massive data that can improve the operation of the utility business.  If the enterprise adds the information extraction and presentation systems that utilize all the new data, there can be huge business benefits.  As the industry moves towards a more difficult to control, distributed generation and resource model it may in fact be impossible to run the business without this information.  Regulatory requirements may be met only with full information collection.   In listing the enterprise applications and calculating their value, include those that are not based on IEC 61850 per se but are enabled by the data communications infrastructure that supports IEC 61850.

Organizational Transformation Challenges

In the opening section of the article, we asserted that it’s not practical to support widespread deployment of IEC 61850 PAC systems with an organization descended from older PAC design regimens.  While many users will create a bridge with a trial or pilot installation of IEC 61850 before making the complete commitment, the business case can only be built with the assumption of complete commitment.  The work focus of the engineering, asset management, business management, financial management, maintenance, construction, and compliance personnel all change.  After the initial experimentation, the organizations must make a full-fledged commitment so new tools and processes really take over as rapidly as possible.  Here are a few examples of the organizational changes and business benefits; some were mentioned above:

1. Capital planning must change to recognize the shorter asset life of IEC 61850 based PAC – we estimated 10 to 15 years above.  As we explained above, the high cost of keeping the old course is not an option – we mentioned a cost reduction to 2% to 5% of the cost of the old, less intelligent designs that ran for decades.  Think of the problems today with microprocessor relays from the 1990s with PC support software and hardware failure challenges.  If the engineering team adheres to the sustainable-design guidance of the last section, the generational replacement costs per turnover will be far less than those of any of the preceding replacements.

2.  The PAC engineering standard development team must develop a new mind set for sustainability, including easy IED and protection zone replacement, virtual testing and isolating facilities, and how to design so technicians can troubleshoot routine failures and problems without bringing engineers into the job.

3. Field construction and maintenance personnel must have the opportunity to learn how to test and troubleshoot new PAC designs built around Ethernet optical fiber communications networks.  Many of the most often used tools must comprise monitoring and alarming features included in the PAC design by the engineering team.  The avoidance of most apparatus or system outages for PAC failure or sustainment replacements can have a large value driven by replacement power costs or customer minutes without power.

4. The same field construction and maintenance personnel and their management must foresee that transition from time-based maintenance testing to sustainable replacement activities and troubleshooting of failures.  In industry experience to date, the number of knowledgeable personnel has not decreased - IEC 61850 PAC changes the nature of the work.

5. Engineering and maintenance personnel together must embrace tight configuration or settings management tools and systems as a live-or-die process.  Without rigid control of product versions and setting files, maintenance replacements risk breaking of functions and disrupting operation of the PAC system. With such tools and systems, information management is easier than it is today at many utilities, and the risk of setting errors drops.  NERC has documented setting errors as a major cause of protection system misoperations.

 

Conclusions
This article has explained how PAC hardware and networking technology and economics point inescapably to use of IEC 61850 products and methods.  Business drivers reach beyond wiring cost savings or ease of functional integration to major organizational impacts and business savings opportunities we have listed.  It will become increasingly difficult to carry on with traditional PAC designs.  Still, the transition can be tough without a holistic plan.  The following action items can help the utility to achieve technical success and lowest life cycle costs:

  • Develop requirements for and relationships with product vendors, who must commit to support interoperable and sustainable products and designs over the service life of the PAC design.
  • Apply the sustainable design principles of the previous sections.  If some of these seem unfamiliar, get expert help from vendors and from vendor-independent industry experts with experience in PAC system design and integration.
  • Create strong, rigid design standards; develop broadly useable documentation for new PAC design features like network configuration, data flows, and GOOSE messaging connections of functional points.
  • Set up rigid documentation and configuration management systems.  With IEC 61850, much of the PAC design is no longer evident in the physical installation – this managed design information is the only tool to maintain the system.
  • Create a development laboratory to validate the performance of the design.  Keep the laboratory throughout the installation life to train personnel, to troubleshoot bugs that arise in the field, and to test new product or firmware insertions in the existing design before authorizing those for field use.
  • Develop and run training programs for field maintenance personnel, including hands-on participation and feedback during the design and laboratory test phases.
  • Develop and run training programs for other enterprise stakeholders, including system planning, capital planning, purchasing, and operations teams.
  • After the pilot or trial phase, plan a crisp organizational transition to the new design at the fastest sustainable rate.   

Biography

Eric A. Udren has a 47-year distinguished career in design and application of protective relaying, substation control, and communications systems.  He began his career at Westinghouse, and held technical leader and manager positions at ABB, Eaton Electrical, and KEMA.  He programmed the world’s first digital relay, and led development of the first LAN-based substation P&C system. He works with major utilities to develop new substation protection, control, communications designs and remedial action schemes based on Ethernet, IEC 61850, and synchrophasor techniques. Eric is IEEE Life Fellow, and twice the former chair of the RCS of the IEEE Power System Relaying Committee.  He is US Technical Advisor for IEC TC 95 relay standards; and is member of the IEC TC 57 WG 10.  Eric serves on the NERC System Protection and Control Subcommittee (SPCS) and the NERC Rely Maintenance Standard Drafting Team.  He has written and presented over 90 technical papers and book chapters and has 7 patents. Since 2008 he has served as Executive Advisor with Quanta Technology, LLC of Raleigh, North Carolina; with his office in Pittsburgh, Pennsylvania.

 

BeijingSifang June 2016