Presentations:

Smart Grid 101 – An Introduction to Smart Grid
Presented by Erich Gunther

Smart Grid 201- A Deeper View of Smart Grid
Presented by Doug Houseman

Smart Grid 301 – Security
Presented by Bobby Brown and Slade Griffin

“Analysis of the Effect of Distance on the TRV Waveform for a Short-Line Fault”
Presented by Grazia Todeschini

Want to know more about our Power Systems Studies work?  Click here to see the presentation from last week.

We look forward to the next show in 2014 in Chicago, Illinois – see you there.

Today, the ANSI Electric Vehicles Standards Panel (EVSP) concluded a year-long effort and published a “Standardization Roadmap for Electric Vehicle Deployment”.   The Roadmap is important because it identifies grid-related gaps and underlines the need for coordinated action to fill these gaps.

Originally convened in March of 2011, the EVSP is a coordinating body geared to foster collaboration on standardization matters among relevant stakeholders in the electric vehicle sector.  The goal is the safe, mass deployment of electric vehicles and associated infrastructure.  The Roadmap focuses primarily on products and systems for light duty, on-road plug-in electric vehicles (PEVs).

EnerNex presented to the EVSP on behalf of NIST and the Smart Grid Interoperability Panel (SGIP).  The Panel’s Roadmap highlighted the role of SGIP’s V2G Domain Expert Working Group (DEWG), particularly the Group’s strategic focus on interoperability and gap analysis, and the addition of SAE standards J1772^TM, J2836-1 and J2847-1 to the SGIP’s Catalog of Standards.  This is a compendium of standards and practices important to the development and deployment of a robust and interoperable Smart Grid.

Since most EVs have limited range because of battery capacity, the Roadmap identifies charging infrastructure as a critical need.  Most of us are aware of this issue, but the Panel adds that the infrastructure must be interoperable and independent of the vehicle and EVSE (electric vehicle supply equipment).  This was named as one of the five significant challenges EVs must face to be broadly adopted.  Currently, only a few EVSE vendors are interoperable and infrastructure owners are quickly realizing the benefits of using multiple vendors for procurements.

The Roadmap is comprehensive.  It provides requirements or standards for Communication, First Responders/Repair Technicians and Vehicle as Supply in one place.  The Roadmap was designed to be a living document, as the technology evolves, but even now it is an important resource for stakeholders working in the domains of vehicle, infrastructure and support services.  For example, the Roadmap describes the relationship between ANSI and the SGIP V2G to identify gaps and develop standards.  This is an effective relationship because members are active in both groups including notably Hank McGlynn, Adam Langton, Rich Scholer, Ed Eckert, Zafer Sahinoglu, Mary Reidy, Mark Klerer, Josh McDonald, Jose Salazar, Mike Coop and Wayne Dennison.

More than 50 gaps/recommendations are found in the Roadmap.  The Panel prioritized them and assigned potential developer(s) and labeled Grid-Related issues.  Identifying these gaps is important because PEV infrastructure developers can synchronize their efforts to the Roadmap and this will accelerate progress.  Some of the notable Grid Related Gaps (and associated standards) are listed below:

By identifying gaps such as these Grid Related ones, the ANSI Electric Vehicle Standards Panel is providing coordinated technical input publishing the Roadmap efforts to identify what standards and conformity programs are needed, and the effects will be leveraged by collaborations such as the SGIP V2G focusing on interoperability.

There’s one part of the smart grid that some utilities don’t like to talk much about.  No, I’m not suggesting shady accounting practices; I’m talking about network topology.  In other words, which customers are connected to which phases of which distribution transformers, on which feeders, connected to which substations?  And while we’re at it, where’s the customer physically located and where is the meter physically located on the building?

There are a whole pile of smart grid applications that require an up-to-date picture of exactly what the transmission and distribution networks look like.  These include:

• Volt/VAR control
• Automated planning and forecasting
• Integrated outage management
• Auto-restoration
• Transformer load optimization
• Asset management
• Automatic load shedding
• Microgrids

The problem, strange as it may seem, is that many utilities don’t have this information.  Or at least, it’s not up to date.  Or perhaps it’s on paper records and isn’t searchable.  Or it doesn’t include the phase of the transformer.  Or it doesn’t include the feeder segment.  Or the geographic location. Or the information is in six different databases.  And so on…

Utilities don’t like to talk about this problem because it really seems like the kind of thing they ought to know, and they don’t like to air their dirty laundry in public. To be fair, until some of these smart grid applications came along, they were probably doing just fine with the information they had.  And it’s actually a great opportunity.  Several utilities have taken advantage of the fact that they were upgrading to Advanced Metering Infrastructure (AMI) to finally align and sanitize all their entire geographic, customer, and equipment databases. It makes a lot of sense.  According to our experience here at EnerNex, it costs something like $4.45 a suburban customer to send someone into the field specifically to  update topology information, while doing it as a part of an AMI deployment costs less than a dollar per customer.

Of course, a good system design would put all this information in one place where any application could get ahold of it, and update it whenever something changed. And the best way to determine whether two points are electrically connected is to send a message down the wire.  If it gets there, you’re connected.  This technology has been around a long time and is known as Power Line Carrier (PLC), or its newer and much speedier cousin Broadband Over Powerline (BPL).There are AMI products available that use this technology to read meters, so perhaps it could also be used to update a database of topology information.

But deciding whether or not to use power line communications technologies for AMI is a decision that requires looking at all aspects of the business requirements.  You would want to consider the cost per endpoint, decide whether you are going to do distribution automation and metering on the same network, decide whether you want to use “last gasp” messages in your outage management scheme, and look at the full lifecycle costs of installation and maintenance all around, among many other factors.  Traditional PLC is too slow for a lot of the smart grid applications utilities want to deploy, and BPL tends to be transmitted on multiple phases for reliability of communications, which would make it not as useful for topology generation.  And some people just don’t like the idea of depending on communications they will lose when the power goes out.

So I personally would like to see someone deploy a technology that uses power line communications just to update topology information.  Ideally it would be a cheap, simple signaling device that could be added onto any meter, transformer, or substation, and build a network map by figuring out who is adjacent to whom.  See the figure below. The standard method of communication could be some other technology:  wireless mesh, say, or cellular, or a different form of PLC.  But this application would require only a few bits to be transmitted, maybe a few times a day: “This is me, I am electrically connected to you”.  Then each meter or other endpoint could send the information back to a central location where it could be compiled into an accurate map.

Hand-held power-line communcations devices for verifying topology exist today; they’re called “toners” because they essentially listen for constant “tones” of a particular frequency transmitted on a particular phase.   But they cost hundreds of dollars and aren’t left in place. It is likely that including a PLC device as a part of a meter or other utility equipment would add less than a dollar to the cost of the equipment. That would be the best solution. Or perhaps some kind of cheap “clip-on” device might be an in-between method. But it hasn’t happened yet.  It’s likely waiting on a common open standard to be developed.

Anyway, if you build one, call me.  Or better yet, call a few utilities that need their laundry done.

Development of a global network of Smart Grid test beds was the primary topic of discussion at the APEC-ISGAN Smart Grid Test Bed Networks workshop that took place in January in Washington, DC.  A broad international representation of over fifty experts and officials from laboratories and government agencies around the world made presentations on their programs and capabilities to set the stage for discussions on collaborative opportunities. ISGAN is the International Smart Grid Action Network, essentially a forum with government members cooperating on Smart Grid development and deployment initiatives, and APEC is the Asia-Pacific Economic Cooperation, a broad economic forum that has a Smart Grid initiative as well. The US DOE participates in each and put together this workshop, as test bed cooperation is one of the areas of focus in the ISGAN vision. Essentially, their goal is to have “test bed” labs in the US and global test/research organizations cooperating through shared facility use and research for efficiency, avoidance of duplication, and to provide access for those economies that lack test bed capabilities.

This first meeting on the test bed topic had two elements: 1) presentations by numerous organizations about their facilities and capabilities, and 2) open “brainstorming” discussions on how to facilitate collaboration and develop a path forward.

NIST and EnerNex delivered the first invited presentation at the workshop providing an overview of the US role in Smart Grid, drilling down through NIST’s specific role and a high level description of the SGIP. In particular, the work of the SGIP’s testing and certification committee (SGTCC) was a focus, particularly the activities of the SGTCC end to end test workgroup activities.

US National Labs each gave presentations on their capabilities – presenters represented: Sandia, Oak Ridge, PNNL, NREL, Argonne and Brookhaven. Internationally, there was a presentation from Europe’s DERlab (DER is Distributed Energy Resources ) – DER is a collaboration of 21 organizations (mostly in Europe, but a few others as participation is not restricted to European labs). There were also presentations from the Japanese Institute of Energy Economics, Australia, Finland, ITRI (Taiwan), Swedish Civil Contingencies Agency (mostly cybersecurity initiatives), and Korea.

There was also an introductory talk from the University of Pennsylvania which was tasked to develop a knowledge sharing platform (website) for APEC – it is called the Energy Smart Communities Initiative (ESCI) – (http://esci-ksp.org/) which should be an interesting information source to follow as it further develops.

The remainder of the workshop was the discussion on developing cooperative activities. It was observed that many of the labs have similar sounding capabilities/facilities and that an “inventory” was needed to assess what’s available and where there are gaps. Discussion on how business arrangement could be structured was also a topic – US labs have various mechanisms for establishing programs/projects but it was noted that it would be helpful to capture this more concisely as well – as with technical issues, today there’s no easy way to navigate options other than going through multiple layers of each organization’s individual websites. Funding of course was an issue where answers were in short supply, but there was a strong consensus that a Smart Grid test bed network will provide significant value to research, standardization and implementation. Plans are in the works for upcoming more targeted workshops, so stay tuned for developments in this initiative.

After working as a sub-contractor over the past year with many of EnerNex’s experts, I am happy that this relationship could be made ‘official’ allowing me to become a fully fledged family member!  I am looking forward to being EnerNex’s northern California presence, especially within Silicon Valley which will allow me to better serve local EnerNex clients as well as finding new ones.  By way of quick background, my education includes both an engineering and business foundation as I had always been interested in the creative and successful ‘marriage’ of technology and business opportunities.  I have now been in Silicon Valley for over 30 years and have been fortunate enough to have been able to participate in many of its exciting and riskier activities (my first job out of grad school was as a systems engineer at Livermore Labs magnetic fusion facility).  Since that first foray into the energy industry, my involvement has included starting several venture capital-backed companies (home automation, AMI, internet-based energy research, and product development consulting), independently consulting for both EPRI and the Gas Technology Institute, and assisting a variety of other start-ups and venture capitalists to create business plans, evaluate technology and competitive opportunities, perform due diligence, and recruit and build technology and management teams to pursue some of these opportunities.  I am looking forward to continuing to work with EnerNex’s world class caliber folks and our many innovative customers as we work together toward a smarter, more efficient energy future.

Since California now only has two full time employees (Kay Stefferud in the south), I am looking forward to assisting EnerNex in growing our California-based business.  Even within California’s budget woes, the state is still rich in energy-related opportunities and businesses including:  Energy Commission RFPs, assisting the state’s three IOUs and numerous public and municipal utilities in their grid modernization programs, cyber-security and privacy policies and designs, and business case evaluations in addition to the state’s highly pro-active roles regarding renewables growth and grid integration, electric vehicles, zero net energy buildings and communities (ZNE/RESCO), greenhouse gas generation, efficiency standards and building, appliance, and vehicle energy codes, and more.  In addition, I hope to be able to generate new or expanded relationships with some of Silicon Valley’s high technology companies, venture capitalists, universities, and government labs.

Since I am located just 5 minutes from EPRI in Palo Alto, I am centrally located in Silicon Valley and only 30 minutes from either SFO or San Jose airports, so I welcome any EnerNex employee or any of our current or future customers who would like to drop by.  I am also available through email and phone (650-947-8815) almost anytime….please call me or drop me a line!

Bob’s full bio can be found here

In 2006 and 2009, Southern California Edison (SCE) developed Use Cases that that describe a general vision for a smarter grid from SCE’s perspective. While these and other Use Cases have done a great job and provide high level use cases that describe the general vision for a smarter grid, each utility faces different challenges that can depend upon their geographic location, business priorities, as well as the vintage of their current infrastructure. Therefore, there is a need to take the existing high level use cases and review and evaluate them to determine:

• How they should be applied
• How they fit with a utility’s individual business drivers
• A personalized set of system requirements and priorities

The use cases are a tool and not the end goal. It is for each utility to take up the existing work and apply it to their own situation, accounting for their own regulatory situation, organizational structure and information system architecture.

The high level use cases are excellent for setting goals, performing business cases and creating roadmaps, but they do not provide the details necessary for a successful implementation.  Utilities should start with the existing use cases and apply the IntelliGrid methodology (IEC/PAS 62559) to add additional detail. The adapted use cases provide updated system requirements that the utility can be confident in and a “blueprint” that is used to communicate the vision to internal stakeholders and vendors.

The economic and physical security of the United States depends upon our ability to acquire natural resources in all forms, from iron and rare earths to oil and gas.

The United States government is one of the most ardent supporters of both free trade and democratic government. Although many nations support democracy and competitive market economies, some nations do not. Instead some nations openly favor their own national interests over global fairness.

Some governments artificially control the supply of some natural resources. One such exploited resource is oil which directly impacts the price of energy.  We can argue endlessly that foreign governments are wrong to exploit oil prices, but our arguments are unlikely to change the actions of foreign governments.

As Daniel Fisher of Forbes Magazine eloquently states, oil prices are Iran’s real weapon of mass destruction http://www.forbes.com/sites/danielfisher/2012/01/04/irans-real-weapon-of-mass-destruction-is-oil-prices/

Kevin Kliesen of the Federal Reserve Bank of St. Louis states “sudden and sustained increases in oil prices increase the odds of recession by 50% in the first year, and 90% after three years.”  Iran’s recent threats to restrict access to the Strait of Hormuz pose a very real risk of another economic recession.  In addition to direct economic costs of oil price manipulation, the wars with Iraq and Afghanistan cost trillions of dollars. It’s not a coincidence that they were fought in the Middle East, the region whose governments are most likely to manipulate oil prices.

We must stop foreign government from threatening our economic security though manipulation of oil prices.   Further we need to reduce dependence on carbon-based fuels because of both soaring costs and global climate concerns. Environmentally as well economically renewable energy is the clear solution.  Economic and environmental progress is being made. The US government and many states actively seek to increase renewable energy with 29 states having renewable energy goals.

What else needs to be done to reduce the economic risk posed by foreign manipulation of oil prices as well as the environmental risk of carbon based fuels? Electrical power generation currently accounts for only 1% of oil usage, but carbon based fuels are used for 67% of electric generation.

Transportation accounts for a stunning 70% of oil use.  Clearly our #1 priority must be to convert transportation to renewable energy sources including electricity and biofuels.

The need to reduce resource imports of all types to sustain transportation in the US should be a key strategy for the US Government and the people of the United States. After more than a decade of war in the Middle East the last thing that the public wants is to return to the region and fight another war. Research in bio-fuels is making more options available to create fuel for conventional engines used in transportation.

Electric vehicles are in the teething stage of design and automotive companies are rapidly learning lessons to improve the vehicles. By 2015, the lessons learned in 2011/2012 will have made their way into the next generation of electric vehicles. The next-generation of electric cars will improve air quality in dense urban areas, reduce dependence on oil and gas, and help balance the increasing amount of renewable energy coming into the grid.

As an industry we need to be ready to electrify transportation. Adopting first generation vehicles into our fleets and feeding back information to manufacturers are good steps. Finding places to install public chargers is another good first step. But in the long term, we must rethink how we design the distribution grid so we are ready at the neighborhood level to support the ultimate goal which is millions of electric vehicles.

We should strive to never have to worry about a country threatening the economy of the United States by withholding a single resource.

With the upcoming tidal wave of both AMI and Distribution Automation data, focusing on how to manage (Meter Data Management & Data Warehouse) what to do (Analytics) with that data will be significant. A lot of the business case savings (theft detection, outage management, etc.) is related to the analytics part.

Think about grocery store price scanners. They have been collecting data for years and are only now realizing the inventory management and marketing potential of data mining. One of the reasons that Wal-Mart is the goliath that they are today is their early realization about the power of data analytics. Their 1980s strategic partnership with Proctor & Gamble for instant reordering upon checkout scan is indicative of this approach.

The true test of data analytics for grid modernization will be a shift from reactive system and infrastructure management to a proactive approach utilizing data to identify the highest risk and most likely points of failure.

In my last blog, http://www.enernex.com/blog/what%E2%80%99s-all-the-fuss-about-the-new-release-of-iec-61850-revision/#!/, I told you that there was lots of new stuff in IEC 61850 Edition 2. Now I’ve got some time to explain what’s new.

As a recap, let’s start with some history.  61850 is an evolution of ideas started in the early 1990’s by EPRI in their Utility Communications Architecture (UCA)  and later on UCA2 projects. The UCA projects attempted to define an “object-oriented” protocol for substation automation. What’s “object-oriented”? This means that the protocol dealt with paired concepts such as Get-Voltage or Control-CircuitBreaker, always in the verb-noun sense.  A limited number of verbs were defined and the nouns formed a hierarchy of items. Fast-forward to 1996 when the IEC groups were formed to define the substation protocol of the future. The IEC groups recognized the value of EPRI work and incorporated many of EPRI’s Utility Communications Architecture ideas into 61850. But the IEC wanted more than a protocol; they wanted “a way of life” and extended the EPRI concepts into a coherent set of 14 documents which defined the actual usage of devices within the substation.

Of course, the IEC didn’t get it 100% right the first time. There were many new concepts and the IEC decided to publish the documents before full industry adoption. The publication of 61850 set off a flurry of activity by vendors and users as companies embraced the standard. But, the standard had some ambiguities, omissions, and outright errors. This was anticipated by the authors of 61850 who created a “technical issues resolution process” (TISSUEs) allowing anyone to provide comments and potential solutions to problems found. Over 800 TISSUEs were submitted against 61850 Edition 1 and it was decided to issue a complete revision to the standard as Edition 2. Revisions included error corrections, clarifications, some new functionality, and removal of obsolete features.

Here’s brief summary of the major changes:

• Device models – added hydro-electric, wind, distributed energy resource, and power quality
• Expanded the length of object names to 128 characters (64 was just too small)
• Allowed a hierarchy of logical devices
• Expanded use of the configuration language to allow bottom-up system design and multiple projects
• Added “service tracking” to replace monitoring of output changes
• Defined communication redundancy for systems which cannot endure any data loss upon failures
• Defined tests for clients, sampled-values, and the configuration language processors
• Defined security mechanism for 61850
• Clarified error responses when “things go wrong”
• Defined a mechanism to declare multicast subscriber information (GOOSE and sampled values)
• Added many mechanisms to deal with testing, simulation, and system maintenance
• Renamed the standard from “substation …” to “system …” to recognize use outside of substations
• Removed the old “UCA GOOSE” (IEC GSSE) from the standard
• Defined named enumerations distinct from countable integers (big step forward)
• Many other minor changes including data types and data objects
• Expanded the page count of the standard by almost 50%

This is just a brief summary of the changes. If you are at all curious, I invite you to dig into the full standard. But you had better hurry … the IEC folks are already working on Edition 3 with more exciting features.

61850 will continue to evolve because the world keeps increasing the expectations of automation systems. But, and this is really important, changes should be compatible with older equipment. If you’ve not already looked into 61850, then now is the time to begin that exploration.

EnerNex is committed to deploying a core multi-vendor based infrastructure of power systems equipment, supporting communications equipment, enterprise and diagnostic software as a platform for researching and evaluating hardware and software in end-to-end, real world application-based scenarios.  This platform is used to support research, engineering and consulting services performed for utilities, vendors, and other stakeholders for product development, product refinement, vendor qualification, pre-certification, and education.

The EnerNex staff have been furiously completing the build-out of the Smart Grid Labs (SGL) infrastructure. This infrastructure will support our six operational domains:

• Security
• Grid
• Metering
• Consumer
• Communications
• Command and Control

The infrastructure is composed of a power system circuit with actual poles (shorter than usual!) and field equipment such as capacitor bank controllers and relays. There is a substation server rack that contains the networking and command and control equipment typically in use at a utility. This rack is the eventual home of our simulation servers and distribution management system (DMS) software. Enterprise applications such as meter data management systems, data historians, and the like are part of a separate server rack, allowing the staff to operate this in a manner similar to many utilities. EnerNex has installed metering on their actual infrastructure for the lighting and loads in the lab, as well as for their photovoltaic (PV, or solar cell) array and electric vehicle service equipment (EVSE, or charging station), facilitating long term analysis of PV and EVSE operations. The PV installation contributes to the “greening” of the EnerNex Water’s Edge office campus complex and the EVSE installation to the local reduction of tailpipe emissions. In addition to the “EnerNex meters”, there is accommodation for quite a few (tens) of meters on a portable testing appliance. The lab contains a typical consumer utility room with two electric water heater connections, a clothes washer and a clothes dryer. There is a refrigerator connection in the consumer kitchen, which leads to the living room, both of which (in addition to the utility room) may be part of any home area network (HAN).

Overlaying all of the infrastructure is a commitment to security, both physical and cyber. The EnerNex security team has designed the cyber security to fit industry best practices as well as from our in-depth knowledge of what is needed beyond those practices. On the physical side, we have committed to practicing role-based access control, also in line with the industry. The security architecture will allow EnerNex staff to leverage the infrastructure in a manner that protects client confidentiality, our parallel corporate network, and our permanent and project equipment while offering on-site and virtual visitors the opportunity to “plug in” at the appropriate point and collaborate.

Click here to register for this exciting event!