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Abstract—Many electric utilities are investigating or

implementing a Smart Grid. Smart Grid is expected to be the new industry platform. Since this is a work in progress it is in the industry’s interest to discuss not only achievements but also the vision for this new platform. In this way industry norms for Smart Grid can be allowed to develop in an efficient and collective manner.

This paper describes National Grid’s vision for Smart Grid in its franchise area, implementation to date of that vision, and its achievements to date.

Index Terms— Power distribution control, Intelligent systems, Intelligent networks, Intelligent control, SCADA systems, Distribution Automation, Smart Grid.

I. NOMENCLATURE Smart Grid refers to a system that comprises intelligent

electricity distribution devices, two-way communications, advanced sensors, automated metering, and specialized computer systems to enhance reliability performance, enhance customer awareness and choice, encourage greater efficiency decisions of the customer and of the utility provider. This system commonly known as Smart Grid will facilitate greater penetration of distributed generation including renewable sources, plug in electric hybrid vehicles, micro-grids, and other technologies that may be enabled by the core functionality.

II. INTRODUCTION Smart Grid is a new and currently developing platform for

the electric power industry. Many electric utilities are investigating or implementing this new platform in various ways. It is to the industry’s advantage to discuss achievements and also vision and strategy for implementation in order to collectively optimize the Smart Grid. In this way industry norms for Smart Grid can be allowed to develop in an efficient manner.

This paper describes National Grid’s vision for Smart Grid in its franchise area, implementation of that vision, and its achievements to date. It will also discuss how we measure success.

III. NATIONAL GRID’S VISION

A. What is included National Grid’s vision includes a robust, two-way wireless

V. J. Forte, Jr. is with National Grid, which is headquartered at 40 Sylvan

Road, Waltham, MA, 02451-1120 USA.

communication system for both data and control of the distribution system as well as for metering and integration with residential customers. Automated metering will connect to this communication system providing a two-way exchange of information that enables interval measurements, energy consumption and price information that will empower the customer through greater awareness and allow them more choices and flexibility to manage their energy consumption. Also supported by this communication system will be a distribution automation (DA) system that will remotely monitor and control substation feeder breakers, line reclosers, automated switches, switched capacitor banks, line voltage regulators, and fault indicators.

National Grid expects this new automated environment to facilitate greater penetration of distributed clean energy technology such as photovoltaic and wind power, as well as plug-in hybrid electric vehicles (PHEV), energy storage, micro-CHP, and micro-grids.

B. Business Case Issues National Grid has chosen to implement Smart Grid in a

unified manner rather than in incremental steps such as automated metering infrastructure (AMI) first followed by DA, etc. In this manner it will be positioned to measure the integrated benefits and take advantage of common infrastructure (such as communications) supporting the various applications. Sharing the cost of common infrastructure across the benefits derived from various applications will provide a more realistic cost / benefit ratio for each application in an integrated system for full roll out beyond the pilot stage. It also reduces the risk of selecting common technologies that may be limiting to future applications.

IV. SMART GRID PROCESS National Grid began with an incremental approach before

deciding on an integrated solution. In the late 1990’s a supervisory control and data acquisition (SCADA) pilot was conducted on the distribution system. This SCADA used analog and later digital cell phone communication technology and gathered limited data from line reclosers only. It allowed centralized control operators to remotely switch line reclosers and to obtain information about reclosers which operated through their traditional local controls.

In 2003 through 2006 DA was investigated and a pilot begun in mid 2007. In early 2009 the first DA was activated. This was the first National Grid control system to allow computers to control line reconfiguration without first being

Smart Grid at National Grid Vincent J. Forte, Jr., Member, IEEE

978-1-4244-6266-7/10/$26.00 ©2010 IEEE

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reviewed by a human being. The DA pilot used 900 MHz spread spectrum radio for

peer to peer communications between line devices and for its back haul to the nearest substation with existing communication to the Control Center.

In late 2008 Smart Grid was investigated. This early Smart Grid investigation showed that an incremental approach would show the value relationship of component applications but not the value relationship of the integrated whole. Since the vision was to develop a whole Smart Grid we needed to implement our pilots to demonstrate that value relationship. The integration of Smart Grid components creates a cost / benefit ratio that will be more accurate to disaggregate should roll out beyond the pilot need to be implemented in steps rather than to aggregate the step value for a full roll out.

V. DA PILOT The DA pilot was the first step toward a Smart Grid. It

will be the self healing portion of the new platform with a few adjustments for better integration with the whole.

The DA pilot goal was to reduce our reliability metrics (SAIDI, SAIFI, CAIDI). We decided to use SAIDI as our measure since it incorporates both customers interrupted and interruption duration in the statistic. [1] [2]

A. Distribution Feeder Selection To identify the distribution feeders we would want to

automate we established the following criteria. The feeder had to have one or more existing manual tie points. We want quick wins and weren’t prepared for the time it would take to create new ties. Of course as DA matures on our system we will be eliminating this criterion. Existing ties to alternate feeders had to have reserve capacity in excess of 50 amps on peak. (This would mean we would have even more capability off peak.) We wanted feeders where we had experienced interruptions on the primary with in the last five years. This insures we are addressing our reliability issues with the pilot and that the pilot would be challenged to perform. We eliminated from consideration short 4 kV feeders not likely to benefit from further sectionalizing. [1] [2]

Using our criteria we identified 290 feeders as candidates for DA. Using dollars per delta CMI (CMI is proportional to SAIDI when the customer base is constant) we prioritized this list of feeders.

B. Subtransmission Circuit Selection We focused our Subtransmission review in our New York

territory because it contains about 90% of our subtransmission mileage and has not performed as well as we would prefer. Circuits with protective device to protective device exposure greater than ten miles were considered because less than this is very short exposure at this level in the system. Issues on short line exposures, less than ten miles, are usually best handled using root cause mitigation methods. Our list of potential candidates reached seventeen circuits.

We then prioritized these circuits based on expected reliability improvement using a similar process as that used

for the distribution feeder selection. As a final filter we eliminated those circuits where major remediation was in progress or budgeted. This work would improve the reliability performance of these circuits and thus there would be no benefit to adding DA to them at this time. [1] [2]

C. Pilot Circuits Six distribution feeders and two subtransmission lines were

selected for the DA pilot. An additional four subtransmission lines were selected for a reduced implementation that would allow us to test the communications in very difficult terrain while not overburdening our pilot work force.

The circuits that we piloted were: Boonville-Lowville 22 Line (23 kV) Lighthouse Hill-Mallory 22 Line (35 kV) Chestertown-Schroon Lake 3 Line (35kv) Battenkill-Cement Mountain 5 Line (35kV) Cement Mountain-Cambridge 2 Line (35 kV) Cambridge-Hoosick 3 Line (35 kV) Duguid 26551, 26552 and 26553 (all are 15kV) Bridgeport 16852, 16853 and 16854 (all are 15 kV) The location of the distribution circuits are highlighted in

Fig. 1. In addition to the selection criteria noted previously these feeders were located convenient for frequent access by the pilot team.

DA Pilot FeedersTo Eventually IncludeAMI / DSM

Fig. 1: DA Pilot Distribution Feeder Location

D. DA Results to Date Only a portion of the DA pilot has been activated at the

time of this writing. The majority of costs have been incurred and only a small percentage additional is expected for final testing. For the portion now in-service results for reliability performance have been dramatic.

Table I shows costs incurred for the pilot project normalized by controlled device (switch or recloser). We are currently under but near to our 2006 projections with most expenditure now completed.

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Table I: Cost Estimate versus Actual

per unit cost w/o adders

original unit cost estimate w/o adders

% actual spend compared to original estimate

Dist-Central 68,125.59$ 86,787.00$ 78%Subt-Central 69,668.84$ 61,762.00$ 113%pilot base total 68,897.21$ 77,218.00$ 89% Table II summarizes the equipment used in the pilot for the

automation.

TABLE II: HARDWARE SUMMARY

Circuit voltagenumber of reclosers

number of ScadaMate switches

number of ScadaMate tie points

number of radios

number of teams

Booneville-Lowville 22 23 kV 0 2 1 9 2Mallory-Lighthouse Hill 22 35 kV 0 5 1 21 5Chestertown-Schroon Lake 3 35 kV 1 0 0 8 0Battenkill-Cement Mountain 5 35 kV 0 1 0 4 0Cement Mountain-Cambridge 2 35 kV 0 1 0 4 0Cambridge-Hoosick 3 35 kV 0 1 0 12 0Duguid 26551 15 kV 3 1 2 *** 4Duguid 26552 15 kV 2 1 2 *** 3Duguid 26553 15 kV 0 1 1* *** 1Duguid - Dewitt for back haul -- 0 0 0 *** 0Bridgeport 16852 15 kV 2 1 2 **** 3Bridgeport 16853 15 kV 2 1 3* **** 3Bridgeport 16854 15 kV 1 1 2** **** 2TOTAL 11 16 9 153 23

* counted in another feeder** one counted on another feeder*** 48 radios for Duguid**** 47 radios for Bridgeport The DA on the subtransmission circuits was activated on

January 26, 2009. Actual interruptions experienced to date show there have been 4 interruptions in 2009 (permanent plus momentary). This is in line with the three previous years which experienced 4, 1, and 3 interruptions from 2006 through 2008. The average customer minutes interrupted (CMI) for the previous three year period is 320,030 versus only 12,048 after the DA was placed in service. The average duration for a permanent interruption for the three previous years was 101 minutes. After DA was installed interruptions that typically would have been permanent were reduced to below the 5 minute threshold and so were considered momentary. With costs on budget the resulting cost/benefit ratios are better than the anticipated $10-12/∆CMI.

VI. SMART GRID The Smart Grid will encompass DA for the self healing

portion. Additional Smart Grid elements will include Advanced Metering Infrastructure (AMI), Demand Side Management (DSM) through customer awareness and in-home control, Volt / VAr control, and two way communication capabilities for all of these applications

It is the integration of these various elements and the common robust communication system that creates the Smart Grid. Thus the integration is very important. To that end we have set up a laboratory environment in order to demonstrate various vendor capabilities to become part of our integrated solution by participating in an end to end proof of concept (PoC).

A. Proof of Concept The proof of concept (PoC) was conducted in a laboratory

environment. Equipment and software were assembled from

the head end computer systems, such as SCADA control room computers, distribution management system (DMS) computers, meter data management system (MDMS) computers, outage management system (OMS) computers, communication hardware and monitoring software, grid facing devices such as automated switches and line reclosers, smart enabled meters, and home automation network (HAN) hardware and software. This process has demonstrated how well various vendors technologies and solutions will cooperate together and where care is required when integrating them. This has been an excellent experience for not only National Grid but also the participating vendors.

At the time of this writing the results from that PoC process are being summarized for reporting to management.

The PoC complex we constructed for this will be further developed into a Smart Grid Technology Centre (STC). This will become a site for demonstration, training, and future testing of new or upgraded equipment and software as Smart Grid continues to develop at National Grid.

B. Education National Grid is also reaching out to universities for new

curriculum development and enhancement in order to provide a flow of trained engineers, technicians, and linemen who are ready to support a Smart Grid. This cooperative and mutually beneficial collaboration will help to insure the workforce of tomorrow will be there when needed. The STC will also be used for some of this activity.

C. Smart Grid Feeder Selection Each application on the Smart Grid has a different set of

drivers for pilot feeder selection. The process for DA pilot feeder selection was used. However, other factors were added. For example, the need to understand customer acceptance and desires required a customer demographic similar to the entire franchise area. This resulted in some feeders not high in priority from a DA perspective being selected. In order to pilot the communication system in a manner that would inform for a full roll out pilot areas would need to be compact contiguous areas. The number of customers and the number of feeders had to be large enough to be representative of the system. There were many other factors. All of these were collaboratively discussed among the project team and the pilot areas developed by consensus. Fig. 2 shows the proposed pilot areas.

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Fig. 2: Smart Grid Pilot Feeder Locations Each pilot area ranges in size from 10,000 customers to

40,000 customers and collectively approaches 200,000 customers. This is enough to represent the diversity of our 3.3 million customers. There are 176 feeders out of our approximately 3,000 feeder system. This is enough to represent the physical and design variations throughout our system.

D. Smart Grid Next Steps Following acceptance of the PoC by management, design

will begin in greater detail. Also, the STC will be further developed for the uses described previously. Customer outreach programs will be developed. Purchasing and installation will begin. A host of other functions and most departments will be involved in supporting the effort.

VII. CONCLUSION Many electric utilities are investigating or implementing a

Smart Grid, which is expected to be the new industry platform. This is a work in progress for the industry and thus it is in the industry’s interest to discuss not only specific achievements but also the vision for this new platform. In this way industry norms for Smart Grid can be developed in an efficient and collective manner.

This paper described National Grid’s vision for Smart Grid in its franchise area. It also described achievements to date with the self healing (DA) portion of the Smart Grid. Finally it described the manner that National Grid is implementing its vision including a proof of concept process and pilot location considerations.

VIII. REFERENCES [1] V. J. Forte, Jr., D. Kearns, J. McDaniel, J. Jimenez, D. Pike, " National

Grid’s Visceral Approach to Distribution Automation", presented at the 2009 DistribuTech Conference, San Diego, California, February 2009.

[2] V. J. Forte, Jr., "National Grid Pilots DA," Transmission and Distribution World, pp. 40-46, Sept. 2009.

IX. BIOGRAPHY

Vincent J. Forte, Jr. is a Principal Engineer in Smart Grid for National Grid. Mr. Forte is a licensed professional engineer in New York State. He earned an A.S. in Engineering Science from Hudson Valley Community College in 1977 as well as a B.S. and a Master of Engineering in Electric Power Engineering from Rensselaer Polytechnic Institute in 1978 and 1979 respectively. In the electric utility industry he has held a number of engineering positions, including lead engineer for subtransmission planning and distribution planning, as well as holding management positions, including Manager of Engineering and Director of Electric Assets.

Mr. Forte has also co-authored papers and articles on customer valuation of interruptions, RF signal transmission over power distribution systems, and methods of targeting mitigation for efficient reliability improvement, and Distribution Automation. He is a member of IEEE, NSPE, and HKN.

Contact information: Vincent J. Forte, Jr. PE, Principal Engineer, Smart Grid, National Grid, 1125 Broadway, Albany, New York 12204, Vincent.Forte@us.ngrid.com.