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.

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.