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.

IT/OT Integration for Improved Storm Response

In the last couple of months, I’ve written about the impacts of Hurricane Irene and the Halloween nor’easter on electric service, particularly for people in the northeast US.

It is natural that after a major storm, people express comments and questions such as “We’re living in the digital age – why doesn’t the utility know which customers have lost power?  What can be done to improve restoration times?  What can be done to keep customers and other stakeholders informed during the outage?”

Utilities have long used different operational technology (OT) and information technology (IT) systems to improve storm response.   Some of the primary systems used by utilities during storms are Supervisory Control and Data Acquisition (SCADA),  Distribution Management System (DMS), Outage Management System (OMS), Interactive Voice Response (IVR), Customer Information System (CIS), Mobile Workforce Management (MWM), and Business Intelligence dashboards and reporting (BI).  What’s changing is not only the increasingly functionality in those different systems, but probably even more importantly, is the integration of those systems to each other.

Integration of these systems is sometimes called “IT/OT Integration” in the utility industry, meaning that different OT systems (SCADA, DMS, OMS) are integrated with the IT  systems (MWFM, GIS, CIS, BI, for example).   The IT/OT integration permits data and information to flow freely between the system devices, work crews in the field, people in the operations centers, and storm-support personnel throughout the organization.  Even external stakeholders, including customers, government and public safety authorities, and regulators, are provided selective access to more accurate and timely information about the numbers and locations of customers out, the number and status for restoration resources, and estimate restoration times for different locations.

Examples of integrated IT/OT that improve the storm restoration process are:

Integration of AMI with OMS

The capability of some smart meters and AMI systems permit transmittal of a “last-gasp” message, or outage notification message, to the OMS when a meter loses voltage.  This permits the creation of an AMI-trouble call in the OMS, so that if a customer is delayed in calling to report an outage due to not being home or being asleep, for example, the outage is still noted and processed in the utility’s control systems.  In addition, with some AMI systems, the OMS can ping meters to determine if they are with voltage or not with voltage.  This can improve field resource efficiency, providing dispatchers and crews up-to-date information on the present location where fixes are still required.

Integration of SCADA, DMS, and OMS

Having a single integrated distribution operation system for these three operational systems, instead of three disparate, independent systems, improves operator efficiency during storms, data maintenance, and operator training.  With integrated SCADA, DMS, and OMS, available functionality now includes the transfer of status/analog points from SCADA to the DMS and OMS; the sending of supervisory control and manual override commands from the DMS and OMS to the SCADA; an integrated user interface running on the same operator console, and integrated single sign-on for users.

In addition, the integration of DMS applications in the OMS has proven to improve outage performance. For example, a fault location algorithm uses the as-operated electric network model, including the location of open switches, along with an electrical model of the distribution system with lengths and impedances of conductor segments, to estimate fault location.  This can get customers restored faster and direct crews to fault locations faster.   A Restoration Switching Analysis application evaluates the possible isolation and restoration switching actions that can be done upon occurrence of a permanent fault. The application executes an unbalanced load flow to determine overloaded lines and low-voltage violations for each switching action, and the operator is provided with a listing of recommended switching actions.  The switching actions can also be executed automatically, so that customers outside the fault zone can be restored in a matter of minutes.

Integration of MWM and OMS

Interfaces between the outage management system have the mobile workforce management system have become increasingly mature.  This enables improved communications between the control center and the field resources, and reduces the time for radio communications and manual research.   Crews can report their status, outage status, update estimated times to restore, and more functions through their field devices.    This functionality will continue to grow as mobile technologies and integration technologies evolve.

Integration of BI with All the Different Systems in the Utility

The integration of BI to all the different systems, including OMS and MWM, provide dashboards, reports, and queries, configured specifically for persons depending upon their roles and responsibilities.  A set of operational dashboards enables a near real-time display of summary views that support the ability to drill into outage event details.  Dashboard sutilizes an organizational hierarchy to filter the date by service center, district, geographic location, and additional spatial or organizational criteria.  The outage events are displayed by the Total Number of Outages, Number of Dispatched Outages, Number of Non Dispatched Outages, Device Outages, Customers Out, Priority Customers Out, Locked out Feeders, Active Storm Status, Expired Estimated Restoration Times (ERT), Wires Down, and Configurable ERT thresholds.

The integration of these different IT/OT systems permits storm responders to restore power more quickly and safely than ever before - which means life can return to normal more quickly for all of us.

East Coast Outages - Again

Two months after Irene knocked out power to millions of customers on the East Coast, the Halloween nor'easter of 2011 left millions of homes and business dark again.  In some places in Connecticut, Pennsylvania, and New Jersey, patience is wearing thin with the pace of electric restoration.  But what's causing this, and is it justified?

One reason that complaints are high with the Halloween storm is that this is the second event in a short amount of time.  People's patience wears thin the more times an aggravating event occurs.  When I'm in traffic and one guy cuts me off, I'm slightly annoyed.  A second car cuts me off, and I'm not getting disturbed.  A third guy does it and my fuse is gone.  I think a lot of people are like this, and this second event is wearing on their nerves.  If the East Coast gets another storm in the next couple of months, then people will be even more primed to react.

Obviously there is also a societal and economic factor in this.  Whenever a major event occurs that shuts down businesses, keeps people from shopping, and stops the flow of money, it has a high impact on people. No power for a small business that depends upon every day's receipts to stay afloat can be devastating.  The poor state of the economy only exacerbates this.

Another contributing factor to the severity of the storm appears to be the amount of advance warning that everyone had.  With Hurricane Irene, the attention the storm got as it approached the East Coast was enormous (I'm not saying unjustified), and everyone had days to prepare for the upcoming damage.  This includes the utilities, whose preparation work includes lining up crews from other utilities through pre-arranged mutual assistance agreement, placing resources in the right locations before the storms, insuring there is adequate inventory and spares for damaged equipment, and all of the logistics that go into preparing for the coming recovery over the next several days.  With the Halloween nor'easter, some are saying that the limited advance warning impacted the number of crews that were immediately available and ready to work, with the result being extended times for restoration compared to the restoration time with more advance warning.

In a future post, I'll describe how integration of the systems that utilities use in storm restoration assist with the getting the lights back on quicker.  That includes the outage management system, mobile workforce management system, interactive voice response, and situational awareness / dashboards / reporting.  But for now, let's hope Mother Nature gives us a break for a while.

Volt/VAR Control - Old Problem, New Solution

Volt/VAR Control.  Volt/VAR Optimization.  Real power and energy loss minimization.  Conservation voltage reduction.   Integrated volt/VAR control.  Model-based volt/VAR optimization.

Whatever you call it, one of the applications receiving the most attention in the smart grid world right now is volt/VAR optimization on distribution feeders.  Many folks, though, don’t realize that the problem of optimizing VAR flow, minimizing real power losses, and maintaining a target voltage level for electric loads has been around as long as the 130 years that electric power systems have been around.

In doing some reading about electric power industry pioneers the other day, I discovered that voltage drop and real power losses were a contributing factor to the invention of the incandescent light bulb.  It turns out that back in the late 1870’s, the majority of the research on suitable materials for the light bulb filament focused on low-resistance materials.  Thomas Edison chose to go down a different path instead.  He focused on high-resistance materials for the filament, and his reasoning was this:  in order to construct an economic power system, it would require small diameter conductors, because they were much less expensive than larger-diameter conductors.  (Imagine having to run 477 ACSR to every house!)  Edison knew if a system was going to be built with small conductors, then it would require low load currents so that excessive voltage drop and power losses would not be introduced.  And in order to get low currents, he knew that the light bulb, one of the “killer apps” of the electric world at that time, would have to have a high-resistance filament.

So evaluating the economics of the complete power system from the perspective of voltage drop and real power losses drove Edison to focus on high-resistance filaments, instead of low-resistance filaments.  This led to his eventual discovery of the carbonized cotton-thread filament, and subsequently the carbonized cardboard filament, that evolved into the commercially-viable incandescent light that changed the world.  Edison’s approach, looking to counter the still-present adversaries of voltage drop and real power losses, ultimately led to his finding the high-resistance filament for the first commercially-viable light bulbs. 

Now Edison was advocating a dc (direct current) system, and not the ac (alternating current) system that eventually proved to be the winner.  So he wasn’t even dealing with the reactive component of the current flows that typically produce the greatest amount of voltage drop and real power losses in distribution systems.   When the ac system of Tesla/Westinghouse eventually won “The War of the Currents”, then engineers had to deal with the reactive current flow creating voltage drop and real power losses as well.

Over the years, many solutions have been developed to deal with the effects of voltage drop and real power losses on distribution systems.  To produce VAR’s as close as possible to equipment requiring them, and minimize VAR flow on distribution lines, capacitors were developed.  Capacitors could be either fixed (connected to the system at all times) or switched on and off the system through the use of control variables such as time, current, VAR, voltage, or temperature.  The load tap changing transformer used in distribution substations for changing the voltage at the substation was developed.  Free standing voltage regulators, with the ability to be installed in either the substation or along the distribution lines, were developed.  Line drop compensation on voltage regulation equipment was developed for improved voltage control under variable load conditions. 

One of my friends in the industry said he had actually seen equipment, on the system of the utility that he was working for, that were called “capaciformers”.  The capaciformer was a distribution transformer which also had capacitors that were contained in it.  The concept was that any time you needed to add a distribution transformer to serve new load on the system, you could add a capaciformer.  In this way, the capacitors and their VAR supply would be inherently added as the load grew, since it was known that the load was going to require a VAR supply anyway.  So instead of adding separate capacitors later, you could just add the capacitance when the transformer is installed.  Since today’s distribution systems aren’t blanketed with capaciformers (primarily because of their inflexibility in adapting to the large variability in VAR requirements, as well as the variations in real power load, on the system), they obviously didn’t work out.  But it does illustrate the effort that has gone into volt/VAR control over the years.

A review of the industry literature also shows that volt/VAR control in distribution systems has always been a popular subject.  It seemed to hit a peak in the late 1970’s and 1980’s, after the energy crisis in the mid-1970’s.  But then it seemed to be relatively dormant in the 1990’s and into the 2000’s. So why all the attention now, on a problem that has been around for 130 years?  Well, there are several reasons for this.

One, electric power system operating objectives have changed.  Over the last couple of years, minimization of customer demand and minimization of losses have become more important in many locales.  And improved volt/VAR control is typically a very cost-effective means to these goals.  Think about this – for at 5000 MW distribution organization, which has to pay an equivalent capitalized charge of $1000/kW for peak demand, a 1% reduction in peak demand is worth $50M.  And despite the lack of load growth in some locations due to the slow economy, the green/efficiency movement continues, increasing the value of energy reduction measures, even when demand reduction is not as critical.

Two, the methods developed for volt/VAR control in the past don’t work as well as the model-based volt/VAR methods that have been developed recently.   Figure 1 provides a brief history of volt/VAR control methods.  Older methods have a number of weaknesses, including the fact that they can’t keep up with the continuous changes that are made on a distribution system, including both the planning and design changes that happen year-to-year and the operating changes that occur day-to-day.  Loads and capacitor banks routinely get transferred between feeders, rendering the older volt/VAR control methods less effective.  The older centralized control methods were also based on heuristics, and not formal mathematical optimization – results were almost always less than optimal.  The model-based volt/VAR system of today considers the as-operated state of the distribution system, and can apply true mathematical optimization to achieve maximum reduction of real power losses and customer demand.

Third, leading distribution organizations have been implementing a technology platform, which volt/VAR is able to leverage while sharing the expense of that platform with other distribution processes.  The technology platform includes GIS (geographic information system), which distribution organizations typically use as their record of distribution assets and system connectivity.  The GIS also provides the basis of the operating model for DMS applications such as model-based volt/VAR optimization.  The technology platform also includes DMS and SCADA systems that provide centralized control applications for efficient management of the distribution system.  The technologies also include the improved communications systems that distribution organizations have been installing for communicating with field devices and customer AMI meters.   Other processes in the utility are able to leverage these investments, including outage management, feeder monitoring, fault location and restoration switching, work management, and equipment condition monitoring.   When a utility considers the benefits of all these processes, and the shared cost of the infrastructure among all these processes, then the business case for model-based volt/VAR economics is very strong.

More information on model-based volt/VAR optimization is contained in a white paper that can be downloaded free of charge from www.ventyx.com.

Hurricane Irene, Nikola Tesla, and Power Restoration

This post was originally written on September 8, 2011

On Sunday August 28, the center of the hurricane/tropic storm named Irene went about 30 miles west of Shoreham, NY, located on the Long Island Sound.  Being on the east side of the storm, Shoreham and the rest of Long Island were exposed to its greatest fury.  At its peak, 523,000 Long Island Power Authority customers were without power.

Irene had already plowed up the East Coast, wreaking havoc and creating power outages in every state it passed over.  According to the Department of Energy, 6.7 million customers had no power on that Sunday.  On the following Thursday, nearly 1 million customers still had no lights.  The primary reason that so many were without power were the overhead transmission lines and distribution lines that were taken down by the high winds and trees.

So what’s the significance of the storm blowing through Shoreham, NY?   In the early 1900s in Shoreham, Nikola Tesla performed electric power engineering research.  Tesla had already developed polyphase alternating current (ac) system of generators, motors and transformers and held 40 basic U.S. patents on the system.  George Westinghouse recognized the potential of Tesla’s inventions and bought his patents and commercialized the technology.  Tesla’s ac technology proved to superior to the direct current (dc) system that Thomas Edison argued for and eventually won the battle, just as VHS defeated Beta in the VCR wars of the 1980s. 1893 marked a milestone for the industrial world, with the huge demonstration of the Westinghouse/Tesla polyphase ac system at the World’s Columbian Exposition in Chicago.

Tesla was the mastermind behind the ac power system that has transformed the world from the 1880s until today.  His impact was so great that, in 1997, Tesla was named one of the 100 most important people in the last 1,000 years.  So Irene essentially knocked out large parts of the ac power system that Tesla, who spent much of life in the New York City, had done so much to develop and invent.  For more than a week, many customers would not be able to turn on their lights, refrigerators, air conditioners, and even the induction motors that Tesla had invented.

But the irony doesn’t stop there.  From 1901 to 1905, Tesla built the Tesla Laboratory and the Wardenclyffe Tower in Shoreham, using funds from the financial titan J.P Morgan.  Besides serving as a communications broadcast center, the tower was also designed to deliver electric power without wires.   The energy would be transmitted through the ionosphere and the ground to the whole planet.  It would behave much like radio transmission.  Essentially, Tesla wanted to saturate the surface of the globe with electricity for global use, without the use of wires.

The Wardenclyffe Tower and the Tesla Laboratory in Shoreham, NY

Photo from the web site of the Tesla Memorial Society of New York, www.teslasociety.com.

But it never worked out, and the tower was torn down in 1917.  But think how much the electric power world would have been different if the concept had proved successful.  No electric lines costing billions of dollars to construct.  No periodic costly tree trimming to undertake.  The huge electric power disruptions, like those caused by Irene, might be greatly minimized.   But, without that successful technology development in Shoreham, Irene charged through Long Island almost 100 years later, turning off the lights for days for so many people.

After such storms, there are always those who ask, “Why don’t we just make all the electric power facilities underground?”  Study after study has shown that economically, it just isn’t feasible.  While the expense is justified in certain cases—for example, where it is decided that aesthetics are of driving importance—the cost of burying existing electric facilities on a large scale is an amount that society is not willing to bear.

So then people ask, “Why can’t the power be fixed any faster?”  They look out the windows and see the storm is long gone.  “It’s been sunny now for three days, four days, a week, and the power still isn’t on.  Why?  The power companies aren’t prepared to deal with this!  They’re not doing their jobs!  Certainly we should be able to restore power quicker with all the technology available to us!”

The answer is that utilities and distribution organizations have long focused on storm response and getting the lights back on quicker.  There are already many things being done, and more that technology providers and utilities are working on.

·         Modern geographic information system (GIS)-based outage management systems have been around since the early 1990s and are in common use throughout the power industry.  They assist electric distribution organizations with predicting where outages have occurred, based on the location of customer phone calls and indications from their automated monitoring systems (commonly called SCADA – supervisory control and data acquisition).  The outage management systems assist the power providers by providing them a visualization of where the outages have occurred, and with managing the crews and resources to get power restored.  Utilities are able to manage their own crews, as well as crews that come into the storm area from other areas and states.  The outage management systems also assist with prioritizing the outages, which is typically based on restoring service to critical customers like hospitals and emergency response providers first and giving higher priority to outages affecting larger numbers of customers.

·         Over the years, outage management systems have changed their computing architectures as information technologies have evolved.  They have evolved from mainframe systems to distributed client-server systems that are capable of handing millions of customer outages during a storm.

·         Improved interoperability between the outage management system and other utility systems has also evolved.  This includes automated interfaces between the outage management system and the mobile workforce management system, which is how many electric power providers communicate with the field crews during storms.  Just as mobile computing technologies have changed the world in just the last five years,  the mobile systems that utilities use are constantly improving so that crews can work more efficiently and get the lights back on quicker.

·         The interoperability between systems also includes interfaces between the smart meters that are being installed for many electric customers.  Many of the smart meters have the capability to communicate their status to the electric provider, indicating if power has been lost or if it has been restored.  This can improve the efficiency of the provider, and lead to less outage times for customers.

·         Advances in information technologies now provide utilities with improved situational awareness during storms.  The use of business intelligence tools permits utilities to extract information from all their available IT systems, including outage management, mobile workforce management, smart metering systems, geographic mapping systems, etc.  All of this information is used to provide dashboards, trends, and geographical depictions of what is happening to utility management and personnel on a near real-time basis.  The result is that the utility has a much better understanding of the problems on the systems and the resources at their disposal to fix the problems.  They able to respond much quicker to large-scale events like Irene.

So  even though it may have seemed to some of us that Irene mockingly drove through the site of Tesla’s laboratory on wireless power transmission on Long Island last month, we continue to use technology to get the upper hand on storms and get power restored quicker.  There is always room for improvement in getting the lights back on, and even though we don’t have wireless power transmission available to us, we will continue to use the technologies available to us in battling the forces of nature.