Electric Service Continuity in Major Events

With the latest super storm hitting the Northeast  in October, the discussions began anew on how electric distribution systems can be made robust to withstand storms.  At its core, this type of event is not new – it’s been repeated time and time again, since the first distribution systems went into service in the 18880’s.  Is there anything new to discuss?

One topic that always receives more discussion after major events is undergrounding the system.  One does not have to look far to see many studies and analyses that have been done, showing the high expense in undergrounding distribution facilities en masse.  Undergrounding isn’t without its faults as well – higher O&M costs, its susceptibility to events such as flooding, and longer restoration times in some cases all have to be considered.  Underground entire systems just isn’t practical.

Another topic that is now frequently discussed in whether smart grid investments should be increased to help withstand storms.  Depending on what you call “smart grid”, many of these investments help in system restoration efforts, not as much as in enhancing the robustness of the system.  This particularly includes distribution automation, whose effectiveness, it can be argued, isn’t as nearly as strong when the large amounts of system damage de-energize widespread areas.  Other “smart grid” investments, particularly the IT systems that are used in outage restoration – the outage management system (OMS), mobile workforce management, GIS, distribution operations analytics, and customer communications tools -  improve situational awareness and provide tools for improved coordination of restoration resources, reducing restoration times.

Personally, I think changes in the discussion on service continuity has to flow from the policy and regulatory level.  First, a more comprehensive effort has to be done to look at the value of electric service during major events.  The value of electric service is different for different end users, and it has to be treated as such.  Distribution companies have taken this into account for years – service continuity is more important for critical customers such as hospitals, nursing homes, police and fire stations, and water pumping stations.  Other loads aren’t as critical.  One question to be considered is whether our way of living, and society’s values, have increased the value of electric service to other loads.   Namely, the importance of loads such as gas stations and cell-phone charging were evident when watching the video coming from New England after Hurricane Sandy.  These are just examples – the question is, for what specific loads has the value of service continuity changed, and in particular, increased due to changes in our world?

Second, in line with revisiting the value of service continuity to particular loads, the economic costs of increasing the reliability to those loads needs to be considered. Undergrounding may be a part of this solution, but we are not talking about undergrounding large parts of the system, or the whole system, as many studies have analyzed.  Instead, a focused analysis on the costs of different alternatives for maintaining service continuity to different loads is called for.  Alternatives could be hardened overhead lines, undergrounding in selected locations, mobile generation, and many more, some enabled by new technologies.

Outage Response and Storm Restoration Conference

This month I attended the 12^th Annual Marcus Evans Outage Response and Restoration Management conference in Atlanta, GA.   It was an excellent forum, with 160 attendees focused on finding better ways to prevent and respond to electric system outages.

Typical for this conference, there were engaging and very useful presentations on events that the speakers had worked through:  hurricanes and tropical storms, blizzards, floods, and wild fires.  At times, the presentations turned personal, and the emotional impact on the audience was almost palpable. The speakers had been through the events, and they shared stories, photographs, and videos of the tremendous impact of the events on the people and their communities. 

Certainly there was a lot of sharing of best practices, in terms of continuous storm planning, immediate event preparation, activities during the storm, and post-event restoration. 

It’s particularly interesting to see how technology advancements get adapted for storm preparation and response.  This includes:

Weather forecasts and damage prediction – The sophistication of weather forecasting has grown over the last thirty years, particularly with the advances in computer modeling of meteorology.    More efforts are being made, including my company, to take the weather forecasts and predict the amounts and types of damage that will occur, based on weather forecasts and past records of damage with similar storms.  This feeds directly into forecasts of required resources, materials, and the Estimated Times to Restore, which are so important to customers.

GPS/AVL for tracking resources – GPS and Automatic Vehicle Location, while not new, continues to gain acceptance as a more effective way to track resources over a wide area.

E-mailing of work packages – This is an interesting one, in the sense that it is relatively simple, from a technology standpoint, but saves so much time and effort during storm restoration.   Typically, in a paper-based system, work package materials such as work orders and circuit maps were printed out, assembled, and then driven over in large stacks to the staging area to be given out to the work crews.  This typically would take hours.  With electronic documents and e-mail, if the crews have a mobile device with an e-mail address, the work packages can be e-mailed to them directly, saving time and resources.

Mobility packages, given out to mutual aid crews and contractors - Some utilities assemble mobility packages, which might consist of a laptop computer, GPS,  and other materials in something like a Rubbermaid bin.  This provides the mutual aid crews and contractors with tools to access the utilities’ IT infrastructure. 

But the topic that received the most amount of new discussion was the use of social media in storm events.  Utilities described how they are increasingly devoting more resources to the use of applications such as Facebook and Twitter, as more and more people use them with regularity.  And because of the strong linkage between social media and mobile technologies like smart phones, it means everyone gains an improved awareness of conditions, even during the storm, that is almost instantaneous, distributed throughout a service territory, and not dependent upon having power from the grid (at least until the batteries are discharged in the mobile devices.)   Utilities are already using these tools to collect outage reports, gather photos of damage from customers and employees, and communicate pictures of system damage and restoration efforts to a wide audience.  Challenges remain:  how to separate fact from fiction on the social networks, how to manage “trolls” that want to use social media to make destructive and unhelpful positions on every topic imaginable, and how to make use of all the unstructured data and knowledge that is coming from the social network.   But that will be the subject of much future development, and the topic of a future blog.

Information Technology Trends

InformationWeek published results from its annual survey of 500 executives in its September 17 edition.   In an article titled  “The IT Rules Have Changed”, the first sentence was “Mobile devices, cloud computing, and big data analytics are blowing the old IT rules to pieces.”   So are these trends also prevalent in distribution operations?  In my view,  2 of 3 are top trends in distribution operations.

In distribution operations, I think we’re just starting to see an acceleration in mobile capabilities.   While many organizations have been using mobile systems for tasks such as service orders and outages, and to view maps in some cases, I believe that we are going to see many more types of information flowing both to and from the field.  This includes data related to infrastructure condition and system operations.  And we’re just staring to see applications of social media technologies, which go hand-in-hand with mobile, in distribution operations. 

Cloud computing for distribution operations still doesn’t have wide application in distribution operations yet.  While other parts of the electric utility are using the cloud more often, there are obstacles to overcome in distribution operations – namely, with respect to the high system performance requirements, system reliability, and evolving security measures in distribution operations.  The many interfaces that typical distribution operations systems have, including GIS, CIS, IVR,  and AMI/MDM, may also make it tougher for cloud computing.  Certainly there is a trend, however, in increased use of server virtualization in distribution operations.

Big data analytics is just starting.  In my view, this may be next big thing (or buzz word, if you prefer) in the industry,;  we had  re-engineering, de-regulation, asset management, smart grid, and now big data.   Successful development and application of analytics poses a particular challenge for the industry, since many analytics will require successful teamwork among those with expertise in mathematics/statistics, IT, and distribution equipment/ operations domain expertise.

So are there areas in distribution operations that weren’t covered are these big three?  I believe system integration technologies, coupled with data modeling, will continue to see a very high level of development.  System security will also continue to receive a high amount of attention, as  security regulations continue to evolve, and technologies change with it. 

More Perspectives on Distributed Generation

Back in February of this year, I wrote about an analysis that I had done on the long-term forecast for different types of generation in the US.  I used the most recent data that was available from the US Energy Information Administration’s Annual Energy Outlook.  Using their forecast of electric generation over the next 25 years, some of my findings were:

1.       The continued impact that natural gas will have on our energy supply is forecast to be very significant.  Of the 196 GW of new generation to be built, it is forecast that natural gas will account for 119 GW (61%).  

2.       Large generation technologies that utilize economies of scale are still dominant.   This is evident by the amount of centralized generation to be added (86%) versus the amount of distributed generation (14%).

3.       If only 14% of new capacity additions will be on the distribution system, does this mean you don’t have to worry about distributed generation on your distribution system? It depends.  Regional policies such as renewable portfolio standards, tax incentives, rebates, grants, etc. will still lead to significant amounts of distributed generation in some locations.  For other locations, the environment won’t be nearly as conducive to strong growth.  Just as higher penetrations of distributed generation are already creating issues for some distribution organizations, there will continue to be significant increases in the amounts of distributed generation in some locations.   As a whole, solar photovoltatics are forecast to increase seven times, and they will be largely connected at distribution level. Technologies are certainly changing, and the amount of investment is still substantial.  Even though the percentage of new capacity additions that will be connected at distribution level is relatively small, they will still have significant impacts on distribution in some locations.

Since this topic interests me quite a bit, I took particular notice of the cover of IEEE Spectrum magazine in July 2012.  On the cover was a title of one of the articles inside.  It said “Commentary - Alternative Energy is a Mirage”.    Contained in the well-respected Spectrum magazine, I had to take a look.

In the article, Vaclav Smil makes various points that the only way that renewable generation, except for hydro and geothermal, has made any headway at all is through government subsidies.   Low capacity factors, high installation and interconnection costs, and new technologies to economically recover natural gas make renewable generation, such as solar and wind, uncompetitive compared to other generation types.   And the tremendous investment and inertia that is built into our existing energy infrastructure means that even if renewable energy reaches economic partity, it will take many, many decades to switch society over to renewables in substantial quantities.

Of course, common prevailing thought is that we must invest in renewables, or run the possibility of increasing global temperatures due to the emissions of greenhouse gases.  However, if global warming is real, then it is a global problem, and not a national problem.  We share the earth’s atmosphere with all other countries on earth.  And Dr. Smil makes this eye-opening comparison:  Between 2004 and 2009 the US added about 28 GW of wind turbines.  If we account for the low capacity factor of wind, this is comparable to 10 GW of coal-fired capacity.  The US should pat itself on the back and rest assured that it is making a significant contribution to the reduction in global warming, right?  Well, during that same period, China installed 30 times as much coal-fired generating capacity.   Through 2015, it is projected that China will add another 200 GW of coal-fired generation, or another 200 large coal plants.

It begs the question – is the investment in renewable energy really the most-cost effective use of the US’s research and development funding for reducing generation’s environmental impacts?  Or are there other alternatives, such as carbon capture technologies, that should be getting more funding?   You can read Dr. Smil’s commentary in Spectrum here   http://spectrum.ieee.org/energy/renewables/a-skeptic-looks-at-alternative-energy/0.

FREEDM Center Visit at NC State

I recently had lunch with Dr. David Lubkeman, Research Professor and Instructor at North Carolina State University and the FREEDM.    The FREEDM Systems Center, which is the Future Renewable Electric Energy Delivery Systems and Management Center, is funded by multiple parties, including the National Science Foundation and industry sponsors.  NC State has a long tradition in electric power systems engineering, with many of today’s power engineers having used the classic textbook Elements of Power System Analysis, authored by the late Dr. William Stevenson of NC State, and later updated by Dr. John Grainger at NC State.  I was fortunate to have worked with Drs. Stevenson, Grainger, and Lubkeman during my graduate studies at NC State, and it is great to see Dave as part of the successful FREEDM Systems Center project - http://www.freedm.ncsu.edu/

The FREEDM center was started in 2008, with an $18.5 million dollar grant from the NSF.  The FREEDM’s center has multiple goals that include the performance of fundamental breakthrough technology in energy storage and power semiconductor devices, developing enabling technologies for subsystem and system demonstrations, and developing a one-megawatt FREEDM green energy hub system to power the Engineering Research Center’s headquarters and other buildings on NC State's Centennial Campus

The FREEDM Center has multiple university partners, including Arizona State University, Florida State University, Florida A&M, and Missouri Science and Technology University.  It also includes universities in Germany, Switzerland, and New Zealand.  ABB, parent company of my employer Ventyx, is an industry partner with the FREEDM Center.

Among the many FREEDM projects and graduate student projects that Dave showed me was the prototype of a power electronic distribution transformer that was being designed and assembled.  Most of the hundreds of millions of distributions transformers in service around the world today are constructed with components such as iron cores, paper insulation, and mineral oil.  The power electronic distribution transformer would replace all these components with solid-state semi-conductors.  Maybe even more interesting, the FREEDM system is working on a distribution transformer that not only converts medium-voltage to the low-voltage ac power that is universal on electric utility secondary systems today, but it would also have a low-voltage DC bus.  This would permit the increasing amounts of dc loads that are present today, such as computing equipment power supplies, renewable energy sources such as solar, and energy storage devices to plug directly into a DC bus,  eliminating their need for their own ac-to-dc power converters.  (On a separate note:  ABB, which has long been the leader in DC power applications, including high-voltage DC (HVDC) for power transmission, is now providing DC data center solutions, which offer the advantages of higher efficiencies, less space, and reduces equipment and installation costs.   http://www.abb.com/cawp/seitp202/187b2f29acaea090c1257a0e0029fb1a.aspx)

The “War of the Currents” was declared by many to be over in the 1890’s, when the ac technology systems supported by Westinghouse and Tesla proved superior to Edison’s dc technology systems.  Low-voltage dc technology may be able to borrow from Mark Twain, who said “Reports of my death have been greatly exaggerated.”

For electric distribution engineers such as myself, it is wonderful to see such innovative R&D being performed on the electric power distribution system, as the FREEDM center is doing.

Be Prepared

I spent a half a week recently at a Boy Scout camp in North Carolina called Camp Raven Knob.  It was a good opportunity to spend time with my two sons, and a chance for some hiking, fresh air, and R&R.   Plus an opportunity to briefly visit Mount Airy, the closest town, and hometown of Andy Griffith, the actor who played Andy Taylor on “The Andy Griffith Show”.

The first night we were there, a thunderstorm came barreling through camp just after midnight, with heavy rain and high winds.  Since Raven Knob is a scout camp, none of the scout tents or three-sided shelters called “Adirondacks” officially have electric service, although Scout Masters have been known to run extension cords several hundred feet, for a few necessities and some not-so-necessary necessities for themselves!  However, there are facilities at the camp that make extensive use of electricity – the health center, the dining hall, the trading post, administration and meeting buildings, and the water pumps.  When the storm came through, much of the camp lost power – I heard it was a transformer serving the campground that failed.   It had been extremely hot in the days before the storm, and a friend that works for a utility had just reminded me that it’s not really the heat that often kills a transformer, but the through-fault or voltage surge that happens after the heat wave, when a thunderstorm comes through.  That might have done the trick.

So most of the campground was without service for the next day.  That meant eating breakfast and lunch in the dining hall in the dark, with no air conditioning, lights, fans, stoves, or ovens.  It also meant that everyone was asked to conserve water as much as possible until the power came back on.

So how can such outages be avoided, with minimum cost to develop a solution?  With the camp being in a rather rural area, I’m guessing that it is either at the end of a feeder or close to it, and the nearest substation is at a minimum of 8 – 10 miles.  I’m also speculating that the closest adjacent feeder might be at least that far from the camp.  Also consider that while there is some small amounts of year-round residential load close to the camp entrance, the camp is only heavily populated for about 10 weeks in the summer.   Given these assumptions, could a feeder extension be done economically, to loop the camp feeder with another feeder and provide a back-up path?  Probably not, if it assumed that that 5 miles of feeder are needed, at a cost of $150,000/mile.  How about undergrounding the entire feeder, or parts of the feeder?  Installation costs are going to prevent that.  Could distributed generation be placed economically at the camp, assuming $500/kW, and a 1000 kW load, with additional  fuel and O&M costs?  Maybe, but still not economically justified.  How about a microgrid, complete with solar panels and battery energy storage?  I don’t even have to make cost assumptions there to know that won’t make sense in this particular case (unless there are some government incentive dollars!)

So what are the Boy Scouts to do?  What about all the other electric loads located in rural areas everywhere, that are in the same situation?  What about the millions of customers that were without power for over a week on the East Coast of the US, when a huge line of thunderstorms (a “derecho”) came through?  With all the technology we have, can’t we fix this by investing more in infrastructure, or building the Smart Grid in these areas?

The answer for these electric customers – Be Prepared.  For the foreseeable future, we don’t have a way to economically reach 100% reliable service, or even close to 100% reliable service, for loads such as these.  Certainly there are good engineering practices that distribution organizations universally follow to improve reliability, and it could be economically advantageous in this case to apply some.  But almost universally, until someone invents a wireless way to transmit large amounts of electrical power, then the distribution system will be prone to faults and customers will be prone to interruptions.  And even if wireless power transmission should ever become a reality, there still may not be a way to guarantee 100% service.

So what did the Scouts do?  We saw a couple of portable generators role into camp that morning.  One was being pulled by a truck that had the county’s name and “emergency response” written on it.  One of these generators was connected to the dining hall, to run the refrigerators and freezers.  The camp served cereal for lunch, and peanut butter and jelly sandwiches for lunch.  If the scouts thought about taking a shower (yeah right), then they would have been discouraged due to the low water pressure.  I’m sure there were other things that were built into the camp contingency plans for a power outage, and that were done in this event.  In short, the scouts had contingency plans for this event.

Bottom line:  yes, there are infrastructure improvements and smart grid technologies that are commonly used to improve reliability.  But for right now, no amount of improvements will get everybody to 100% reliability.  Just like the scouts, the motto “Be Prepared” is something that everyone still needs to heed, with respect to power outages, for the foreseeable future. 

Influential People in the History of Electric Power

With it being Memorial Day weekend in the US, I had some spare time to review some of my books on the history of electric power.  Here is my list of some of the most influential people in the history of electric power.

Faraday – Michael Faraday was one of the greatest experimental scientists ever.  Among other findings, he discovered the principle of electromagnetic induction , in which a changing magnetic field induces a voltage in a loop of wire.  This led to the eventual development of the ac transformer, generator, and motor that we know today.  The measurement of capacitance, the Farad, was named after him.

Tesla – Nikola Tesla expanded the principles established by Faraday, and performed work in the areas of electromagnetic fields, communications, and radio.  He worked for both Edison and Westinghouse at different points in his career.  His work on rotating magnetic fields led to the eventual development of the induction motor.  Working for George Westinghouse, he developed patents for equipment in the modern polyphase ac power system.  The measurement of magnetic flux density, the tesla, was named in his honor.  Tesla died alone and in poverty in the New York City in 1943.

Edison – The Wizard of Menlo Park, Edison’s inventions of the light bulb and the phonograph were among his 1,093 US patents.  He was the driving force behind the creation of the first investor-owned utility (the Edison Illuminating Company), and the installation of the first central station (Pearl Street) and electric distribution system in 1882.  The systems were dc, and he eventually lost the “War of the Currents” to Westinghouse.

Westinghouse – George Westinghouse led the drive to develop ac systems in the US. He purchased patents from Nikola Tesla, and employed George Stanley, who put in the first practical multi-voltage ac system in the US in Great Barrington, MA in 1886.  He had the vision and began the development of the modern economic ac power system, using large centralized generating stations with high-voltage, long-distance transmission lines.

Steinmetz – Charles Proteus Steinmetz mathematically described the “Law of Hysteresis” in the early 1890’s, and improved the design of electric motors.  He later worked at General Electric with Thomas Edison, and developed methods to reproduce lightning in an electric laboratory. 

Fortescue – Charles Legeyt Fortescue spent his entire career with Westinghouse.  In 1918, he  published a paper on symmetrical component theory, showing that any set of N unbalanced phasors can be expressed as the sum of N balanced phasors.  This facilitated the analysis of unbalanced electric power systems, and symmetrical components are still used today.

Implementation of Advanced Distribution Management Systems

I spent some time at ABB’s Automation and Power World in Houston, Texas last week.

The vast amount of  technology that is within ABB’s businesses was evident from first walking into the exhibit hall.   While there was plenty of hardware – breakers, transformers, switches – the presence of software solutions was also prominent.  There was a dedicated Software Pavilion, where the all the Ventyx software was showcased.

I chaired a session on “Experiences in Implementing Distribution IT/OT, a Key Component of the Smart Grid.”   Walter Bartel of CenterPoint Energy and Charlie Schaeffer of Ameren were presenters at the session.  Both presented on the status of their companies’ projects, in which new SCADA, DMS, and OMS systems are being implemented.

It’s fairly easy to do a presentation on what things might look like in the future.  You just need an awareness of the present state of things and the direction that things are headed.  If you’re reasonably realistic, then it’s difficult for anyone to dispute what you’re saying with any certainty.  After all, it’s the future, and no one can tell exactly what’s going to happen.

It’s also fairly easy to do a general presentation on what has occurred in the past.  Particularly if it’s a subject that you know reasonably well, and or has been covered in the industry before, then it’s pretty easy to find material on the subject and present it.

The most interesting type of presentation for many people is one describing how a complex project has been done.  This is particularly true of projects that involve a great deal of change.  It is quite interesting to see the planning and execution of a project that impacts and involves a great number of people, as well as new IT systems.  At large investor owned utilities, the implementation of new Distribution Management Systems, including SCADA, OMS, and DMS, can be such projects.  It is interesting to see the differences, as well as the commonalities, in how different organizations handle the different elements of the project  -  project planning, change management, project tracking, changes of scope, successes and failures, and assessment of results.

Both Charlie and Walter did excellent jobs describing their project implementations.  Both are leaders in their projects and heavily immersed in them.  They know what it takes to do one of these projects.

Charlie presented Ameren’s project to implement an Advanced Distribution Management System (ADMS).  One of the topics that Charlie discussed was “Why a commercial solution?”  If you think about it, one of the strategic decisions that companies make in starting a smart grid project is whether to develop the solutions themselves, perhaps buying parts from various vendors, creating parts of the solution in-house, and performing all the integration themselves, or whether to obtain a commercial offering from a vendor.  The reasons that Ameren decided for a commercial solution were:

•       Completely Integrated Solution required.

•       Applications are complex and still evolving.

•       Desire to receive regular upgrades as Smart Grid evolves.

•       Ameren participate in user groups/product direction.

Another big part of Charlie’s presentation was just how much these projects are not all about new technology.   New technologies are an enabler, but the majority of the tasks require a lot of good old-fashioned project planning, execution, and change management.  Ameren divided their project into two phases:  Phase 1 – Planning/Design, which was completed in 2011, and Phase 2 – Implementation, which is ongoing.  Their Phase 2 is further split into SCADA, Maps/Switching, Outage/Mobile, and Reports.  Charlie explained how Ameren reviewed a PowerPoint slide completely full of business process areas, and identified the system requirements, system changes, process requirements, organization impacts, IT impacts, and implementation tasks. 

Walter presented on the implementation of the Intelligent Grid at CenterPoint Energy.  From a technical standpoint, CenterPoint has doing a tremendous amount of work the last several years:  AMI implementation, communications system installation, ADMS implementation, installation of remote monitoring at approximately 30 substations, and installation of approximately 600 automated field switching and monitoring devices.  But Walter also emphasized the business transformation that is taking place, and particularly discussed that success factors needed:

•       Strong Governance Processes

§  Risk Management, Change Management & Financial Management

§  Project Planning/Scheduling & Metrics/Benefits Reporting

§  Technical Architecture, etc.

•       Integration & Alignment of Project Team, Vendors & Support Functions

•       Product Standardization

•       Installation Standards & Procedures

•       Improved QA Processes

•       Deployment Strategy

•       Monitoring & Exception Management

•       Leveraging of Existing Infrastructure

Both Charlie and Walter are leading in projects that rank with the biggest projects in their careers.  They both know that while the technology plays an important part, the human element of projects is either as important, or more important, than the technology implementation.  It’s not just buying some technologies, installing them, and getting to the Smart Grid – it’s also about having a Smart Project Execution, complete with the human element involved.

Integrating AMI and Distribution Operations in the Smart Grid

Last week I attended an Elster User’s Group Meeting in Pinehurst, NC, and co-presented on the topic of the convergence of distribution automation and AMI (Advanced Metering Infrastructure).  Elster Group is a leading provider to electric, water, and gas utilities of communications, networking, and software solutions.  They supply AMI meters and systems.  It’s a good time to reflect upon the growing integration, and in some cases the convergence, of distribution operations and AMI in three different areas:

1.       Communications between the control center and feeder devices

2.       Outage detection, prediction, and restoration

3.       Electrical analysis of the network

1.       Communications between the control center and feeder devices

Last year, Elster launched its IP AxisLink platform, for AMI and DA convergence.  The platform consists of the IP AxisLink Router/Gatekeeper/Gateway and the IP AxisLink secure tunnel server.  The concept is that this platform enables a utility to use much of the same infrastructure that it uses for AMI for distribution automation and distribution operations purposes.  The AxisLink Router, which is installed in the field, provides parallel paths for AMI and SCADA operations.  The router can contain an Elster gateway, which is used to provide the path between the meshed network of revenue meters and the WAN communicating back to the Elster head end.  At the same time, the router can provide access to distribution IED’s using IP-based protocols (such as DNP) over the EnergyAxis communications network.  The IP AxisLink secure tunnel server, located at the control center, provides VPN tunneling of the SCADA communications between the SCADA front-end and the router.

The value provided is that at particular locations, a single box can be installed that will communicate both AMI and SCADA messages over the utility’s WAN.   This avoids the need to install separate hardware for these two purposes, while utilizing the same WAN connection.  In this way, controllers for reclosers, switched capacitors, voltage regulators, and switches can communicate with the SCADA/DMS leveraging the AMI infrastructure.  Elster is not the only AMI supplier with solutions for using AMI for distribution automation.  It is an alternative to traditional SCADA communications that bears evaluation from feeder device communications.

2.       Outage detection, prediction, and restoration

Interfaces between AMI/meter data management (MDM) and the outage management system (OMS) are becoming more common.  Efforts continue to enhance the functionality, but already there are several ways AMI data can improve the outage management process.

First, if the AMI meters and communications contain the capability, the OMS can receive a last-gasp or outage notification message from the meter when it loses voltage, indicating a customer outage event has occurred.   Customer outages are automatically reported to the OMS, even if the customer doesn’t call its supplier.  Receiving outage notification messages is in addition to phone calls from customers reporting outages.  These outage notification messages are particularly useful when no one is at a property where an outage occurred or when people there are asleep. The outage notification message can reduce customer interruption times and result in a more efficient dispatch of repair crews.

Second, with the proper interface between the OMS and AMI system and the right communications infrastructure and meter, a message can be sent from the OMS to query if a meter is in service. This is often referred to as “pinging the meter.” The meter can be pinged directly, assuming the AMI communications permits it, or the MDM can be pinged to determine the status of a meter. The meter can be pinged either by a customer service representative or an operator.

The value in pinging is that many customer outage reports are results of problems on customer sides of meters. Utilities commonly report that 50 to 67 percent of single-customer-call outages are results of problems on the customer side of meters and not the responsibility of distribution organizations. If a meter can pinged to determine it has voltage, despite a customer’s reports of service issues, responding troubleshooters and crews can save labor costs and vehicle miles.

Another value in meter query is in the ability to potentially perform intelligent outage scoping, or define the outage area by pinging select meters. This can lead to a faster definition of the outage area.

A third area in which interfaces between OMSs and AMI systems can provide value is through restoration notifications. They provide confirmation to distribution operators that customers have been restored downstream of a particular protective device. Restoration notification can be done through a restoration notification message transmitted from the restored meter to the OMS or through pinging of meters that presumably have been restored. The value of restoration notifications is that when all customers have not been restored because of a nested outage within the larger outage area, field personnel can be notified of additional problems before they leave the area.

3.       Electrical analysis of the network

The widespread use of AMI data to improve electric operations is frequently discussed, but actual implementations are not yet widespread.  One example is the use of load profile data from individual revenue meters to create distribution transformer load profiles for use in DMS applications.  Instead of having generic customer class type profiles for the loads, each distribution transformer has a set of load profiles that are reflective of the actual customer demands based on the AMI-reported demands.  Having load profiles for each individual distribution transformer provides more accurate calculation of the state of the network, including a better understanding of loading throughout the system.  This improves the accuracy of DMS load flow calculations, allows operators to load equipment closer to its limits, and results in more accurate calculations used in FLISR (fault location, isolation, and service restoration) and volt/VAR applications.

More experience is being gained with the creation of individual load profiles for each distribution transformer using AMI data.  Some distribution organizations are using funds from their ARRA stimulus grants to implement the interface to the meter data management (MDM) and the DMS.  In one case, an  XML interface using middleware messaging is being used to extract data from the MDM and consolidate the data into each distribution transformer load profile.  The load profile will then be used in the DMS applications.

Increasingly often, real-time or near-real-time electrical data from AMI infrastructure will be used in the operation of the network.  This includes both data from both revenue meters and data from feeder IED’s.  While the timeliness of the data from revenue meters must be considered, due to the latency of some AMI networks, an interface between an AMI head-end system and the DMS can be constructed, using web services or messaging.   The data from feeder IED’s can use the AMI communications infrastructure, as described in the first topic, in communications to the control center.   Examples of electrical data that can be transmitted over the AMI communications infrastructure are voltage limit alarms or voltage magnitude analogs.  Such data permits more precise control of the voltage in the network, permitting an organization to more effectively implement voltage conservation reduction.

How Much Distributed Generation?

On Feb. 9, the Nuclear Regulatory Commission approved the issuing of a combined construction and operating license for the addition of two 1,100 MW nuclear reactors at Southern Company’s Plant Vogtle in Georgia.  My first job out of college was doing generation planning studies, and I’m still intrigued by the economic analysis and comparison of different generation technologies, and which generation technologies will be installed in the future.  I’m quite aware of the economies of scale that still exist for centralized generation in most cases, even when other factors such as T&D costs are considered.

But being in the distribution field, we tend to be exposed to all the news (and in some cases, the hype) of distributed generation, as well as the falling costs and continued investments in technologies such as PV.   In reality, the evaluation of the amounts of different generating technologies that will be installed in the future is a complex task, and is based upon forecasts of future fuel prices, upcoming technology developments, load growth forecasts, impact of efficiency measurements, and regulatory, policy, and geo-political factors.    Just forecasting each of these individual factors is quite an involved exercise.  It’s not something that can be done in a spreadsheet over a couple of hours.

I decided to take a quick look at the long-term forecast of the amount of different types of generation to be installed in the US over the next twenty or so years.  The US Energy Information Administration, which is the statistical and analytical agency in the US Department of Energy, produces an Annual Energy Outlook (AEO) for the US.  In late January, they released an Abridged Version of the 2012 AEO.  The full AEO for 2012 will be available later this spring.

The chart below shows the forecasted amounts of generation capacity in the AEO reference case.   The chart includes both electricity-only and combined heat and power plants whose primary business is to sell electricity, or electricity and heat, to the public, as well as end use generators.

The US presently has about 1,038 GW of generation capacity.  The generation additions shown represent an average annual increase of 0.6% per year in the US, with a net increase of 158 GW over the next 25 years.  That’s a net increase, including the estimate that oil and natural gas steam plus coal will decrease by about 28 GW in this time frame.  The gross increase, or new generation to be built, is 196 GW.   The increase in nuclear generation is forecast to be approximately 11 GW, which includes capacity uprates of existing units.

What’s left is the amount of new generation to be powered by natural gas and renewables.  These total about 185 GW of new generation capacity.  Combined cycle, combustion turbine / diesel (which will be largely natural gas), and distributed generation (natural gas) make up about 64% (119 GW) of this amount, with renewables accounting for the other 36% (66 GW).

If you’re work in distribution, you’re concerned about the amount of distributed generation that could occur on your distribution feeders.    For the AEO forecast, a logical assumption is that the only generation that might be placed at distribution level voltages are renewables and distributed generation (natural gas).  The breakdown in renewables is shown in the chart below.

Wind generation makes the most significant contribution to renewable growth, but due to economies of scale, it is almost always connected at transmission level  If it is assumed that 95% of the wind generation, geothermal generation, and hydro is tied in at transmission level (and not distribution level),  and if you assume that 100% of the solar thermal and solar photovoltaic is connected at distribution level (which actually likely won’t be the case, because of larger solar farms), and assume that 50% of wood / other biomass is connected at distribution level, approximately 25 GW of renewable will be connected at the distribution level.  Adding the 2.8 GW of distributed generation (natural gas) from the first chart, the total connected at distribution level is around 28 GW, which is about 14% the total gross increase of 196 GW.

Here are my thoughts on this:

1. First, my hedge.  Forecasts are almost always wrong. I’m not saying the EIA does a bad job – I’m sure they’re very good at what they do.  But remember that the AEO reference case is a base case type of forecast.  There are a lot of other scenarios, in which the contributing factors will be different, whether they are costs of generation technologies, governmental policy and regulation, rate of economic growth, and other things.  Could things turn out substantially different?  Absolutely. 

2. The continued impact that natural gas will have on our energy supply is forecast to be very significant.  Of the 196 GW of new generation to be built, it is forecast that natural gas will account for 119 GW (61%).  The recent natural gas price declines may be short term, but forecasts show that over the next few decades, supply will be abundant and prices will not escalate severely.   Technology advances and increasing levels of shale gas have greatly increased the amount of natural gas economically recoverable.  Should policy changes be enacted to lessen our dependence on natural gas, so we have a more sustainable future in the long run?  That would be the subject of another column.

3. Large generation technologies that utilize economies of scale are still dominant.   This is evident by the amount of centralized generation to be added (86%) versus the amount of distributed generation (14%).  Of course, the incremental costs of T&D, both capital costs and operating costs, still have to be considered.    And there will be some exceptions – off-grid applications, for example – where distributed generation will be required.  But centralized generation will still be the bulk of new generation capacity added.

4. If only 14% of new capacity additions will be on the distribution system, does this mean you don’t have to worry about distributed generation on your distribution system? It depends.  Regional policies such as renewable portfolio standards, tax incentives, rebates, grants, etc. will still lead to significant amounts of distributed generation in some locations.  For other locations, the environment won’t be nearly as conducive to strong growth.  Just as higher penetrations of distributed generation are already creating issues for some distribution organizations, there will continue to be significant increases in the amounts of distributed generation in some locations.   As a whole, solar photovoltatics are forecast to increase seven times in this time period, and they will be largely connected at distribution level. Technologies are certainly changing, and the amount of investment is still substantial.  Even though the percentage of new capacity additions that will be connected at distribution level is small compared to centralized generation, they will still have significant impacts on distribution in some locations.

IT/OT Integration – Smart Grid, Smart Workforce, Smart Customers

The  Distributech conference, which is geared toward utilities and is largely focused on the electric transmission and distribution industry, was held this week in San Antonio.   Amongst all the continuing “Smart Grid” presentations and discussions, there were also conversations about “IT/OT Integration” and “IT/OT Convergence”.   (“IT” is an abbreviation for Information Technology; “OT” is an abbreviation for Operational Technology.)   While it’s not a brand new topic, it’s still common to hear the questions “What  is IT/OT integration?”,  “Which systems are considered IT and which systems are considered OT?”, and probably most importantly,  “What is the value of IT/OT integration to a distribution organization?”  Let me address a few points.

First, there are different perspectives on what is IT and what is OT.   From my viewpoint, IT and OT can be defined in the table below.   

Table copyright of Ventyx, an ABB Company

There are other ways of dividing IT and OT.  Mine are based on personal observation and discussions with others in the power industry.

The use of IT and OT systems used in an electric distribution system is captured in the figure below.  The IT systems are located at the top of the figure.  The SCADA master is also located at the top, but I consider SCADA mostly an OT system.   The applications in the beige bubbles are made possible by IT/OT integration.

Figure Copyright by Ventyx, an ABB company

Second, one should realize that IT/OT integration, just for the sake of integration, doesn’t really buy much, if anything.  It’s when that integration affects the distribution organization - its way of working, its system performance, or its customer service – that IT/OT integration really brings value to an organization .  Three ways that IT/OT can impact a distribution organization include ongoing improvements in the development of 1) a smart grid, 2) a smart workforce, and 3) smart customers.

1.       Smart Grid

Distribution systems have been set up with some degree of OT intelligence for a long time, if you consider local equipment controls that have long been applied to voltage regulators, LTC’s (load tap changer), capacitor bank switches,  reclosers, sectionalizers, load-break switches, and perhaps even electromechanical relays as local intelligence.  It’s a fairly limited intelligence when compared to what can be done with today’s IED’s, two-way communications, and centralized controls systems, but when these types of local controls are coordinated in the systems design phase, they still result in system performance compared to a scenario in which these devices are not utilized.

However, with the increasing sophistication and application of smart grid technologies in the field, IT applications can now leverage the OT to increase system performance.

Voltage/VAR  optimization (VVO) is an example of how traditional OT, in the form of capacitor controllers, voltage regulator controllers, and load tap changers, along with wireless communications to these devices, is combined with advanced distribution management systems applications (IT) to increase system performance.  With a model-based VVO application in the distribution management system (DMS), system OT information, in the form of equipment loading, voltages, and statuses, for example, are passed to the DMS through SCADA channels or other communications channel.  The VVO application, which is part of the DMS and is considered IT, uses this OT input to calculate the device settings that best reduce system power losses and peak customer demand.  The Volt/VAR optimization then transmits the required control actions back to the OT for execution, such as capacitor switch status or voltage regulator tap position.   For the distribution organization, the benefits of this IT/OT integration include a reduction in the amount of generation capacity that must be built or bought on the market, and a reduction in the real energy losses on the system, which reduces the amount of procured energy along with environmental emissions reductions.

Another example is how a FLISR (fault location, isolation, and service restoration) IT application, residing in the DMS, can leverage OT information (such as fault current, faulted circuit indicator status, and switch status) to determine the optimal way to isolate a fault and restore service quickly to as many customers as possible.  Once the FLISR application has determine the proper selection of switching actions after a fault has occured, the FLISR can then pass those switching applications back to the OT (the SCADA and the switch operations) for execution.  Benefits for the distribution organization include improved reliability performance and higher customer satisfaction.

Another example is that the load data from an AMI system (OT) can be used in the form of load profiles for a DMS load flow application (IT).  Having load profiles for each individual distribution transformer provides more accurate calculation of the state of the network, including a better understanding of loading throughout the system.  The result of more accurate DMS load flow calculations include improved operator knowledge of system loading, improved efficiency and better switching.

2.       Smart Workforce

Anyone that works in, or works with, a distribution organization knows that Smart Grid is only one way to improve distribution organization performance.  Having a Smart Workforce, or well-informed Workforce, is a key to organizational success.  The use of data from OT systems, like automation and SCADA systems, for workforce process efficiency improvements and better decision-making, is an increasing trend in the industry. 

As an example, consider the process of using a DMS to locate faults that have caused device lockouts.  Fault data, including magnitude, affected phases, and type of fault is extracted from the relay or RTU (OT) and sent to the DMS (IT).  The DMS uses this data to estimate the location of the fault on the system, and provide this information to the control room operator or dispatcher within minutes.  The dispatcher can then inform the crew of the approximate fault location, so they can identify the fault and perform restoration switching much quicker, if needed.  The result is quicker restoration times, and lower SAIDI and CAIDI values.  In this case, the OT data is fed to the IT system, is processed, and makes the operator and crew smarter and more informed to perform their jobs more efficiently.

eMobility, which provides two-way data and information flows to the mobile workforce via mobile devices, is making the workforce smarter.   Just in the outage management process alone, the outage management system (OMS) is an IT system that can use AMI outage notifications from meters (OT), process that information, and directly supply field workers with outage assignments and predicted protective devices that opened.  In turn, crews can enter their present status, provide updated estimated times to restore, and additional data through a mobile data terminal or handheld device.  The sophistication and types of data exchange between field resources, others in the organizations, and OT systems will only increase with time.

Data from various OT systems can also be sent to the back office IT systems, such as a business intelligence tool or Enterprise Asset Management system, to make better decisions related to longer-term asset management processes.  Data from sensors and on-line monitoring equipment, that can include temperature, pressure, historic equipment loading, duration and frequency of short-circuits and through-faults, number of operations, and other OT quantities, can all be used to make in the IT environment by asset managers to make better decisions about maintenance programs and asset replacement.  Increasingly more often, the industry is referring to this as “Analytics” or “Big Data”, in which intelligence can be gleaned through data mining, pattern recognition, and statistical analysis.  The use of the OT data, within this type of IT environment, produces benefits such as the conversion of unplanned outages into planned outages (if economically practical to do so), reduction in the number of catastrophic outages, and better allocation of capital and maintenance budgets.

An increasing trend is also the application of business intelligence software that can extract data from AMI, OMS, WMS, SCADA, and other systems to provide dashboard information and querying capabilities for the entire workforce.  The dashboards, which are now available as cost-effective pre-packaged (or out-of-the-box) solutions, can also be tailored to the specific job function in the organizations; that is, different dashboards can be created for operations, for customer service representatives, for senior management, etc.  Users can drill down and drill across data to get more details if needed.  The end result is providing the workforce the right information at the right time to make the right decision, and hence, a smarter workforce.

3.       Smart Customers

By the term smart customers, I’m not implying that customers aren’t smart already. (You see, if I named this section “Smarter Customers”, it would have ruined the catchy little phrase for the title of this post.)  I’m really referring  to a process of making customers better informed about their electric service, through different communications and media that a distribution organization or retailer can use to transmit and receive information to its customers.  That could be related to service outages, power pricing as a function of time or usage, special offers and programs, as well as other information about its electric power service that a distribution organization wishes or needs to share.

Business intelligence portals for customers are now providing more information about the status of electric service to customers and other stakeholders.  A prime example is outage maps placed on the utility web site, that show number of outages, number of customers-out, and the general locations of outages.  Based on forecasted network loading (of which past and present loads, collected from OT systems, are a key determinant), distribution organizations or power retailers can let customers know if a demand response event will be held that day.  Information portals between utilities and other external stakeholders, such as public safety, regulators, and local government officials, are becoming more common.

The integration of IT/OT is particularly effective during major events like storm restoration, when information about outages, network loading and status, field resources, damage assessment, must all be coordinated in a short time frame.  This needs to be done to provide information to customers, government officials, and regulators regarding estimated times to restore (ETRs), for example.  Much work on improving ETR’s and effectively communicating those outside of the distribution organization still needs to be done by many distribution organizations, but IT/OT integration provides a foundation for this.

Summary

IT/OT integration in the electric distribution industry is providing a means to improve distribution organizational performance.  The purpose of this post was to describe how it can result in a smarter grid, smarter workforce, and smarter customers.   Benefits include improved system efficiency and reliability, lower operating and capital costs, and enhanced customer satisfaction.  Since IT and OT systems continue to evolve, and the level of OT data continues to increase as more intelligent devices and communications are added to the grid, IT/OT integration is a key enabler of present and future performance improvements.