Like other electric utilities in the mid-1990s, Northeast Utilities (NU, Hartford, Connecticut, U.S.) recognized that the significant changes occurring in our industry — such as ever-increasing customer expectations, restructuring and performance-based rates — required a critical reassessment of existing organizational structure and strategy.

Starting with a “clean sheet of paper,” NU reinvented itself with a comprehensive re-engineering effort during 1995 and 1996. NU's new organizational philosophy featured separating decision from action, and incorporating operational and financial performance of its distribution assets. These two defining principles led to the new organizational structure, which features an asset-management process.

Asset-Management Philosophy

While still fairly new in the United States, other industries such as transportation (air, rail), telecommunications and electric utilities in the United Kingdom, Australia and New Zealand have employed the asset-management concept.

NU defines asset management as the process that studies the physical transmission and distribution system and initiates changes to help the system operate reliably and economically. Asset management develops projects as well as strategic guidelines, which the other organizational units use to construct, operate and maintain the distribution system. The asset-management process generates and justifies the budgets to support the system projects and maintenance processes.

Why implement the asset-management concept? Simply put, NU classifies assets as both financial and operational. Improved financial performance benefits NU customers by reducing the energy-delivery portion of their kilowatt-hour costs. Improved operational performance meets the needs of customers for a more reliable electric supply system. Both will result in improved customer satisfaction and increased shareholder value.

The distribution assets are managed using guidelines, strategies, investment and decision models, and design and protection standards developed by NU's corporate Asset Strategy and Distribution Engineering groups.

One of the most important aspects in asset management is the cost/benefit analysis. This process collectively considers all the options and alternatives for modifying/maintaining the physical plant. It is the selection of those choices that optimizes financial performance and defines this new thought process.

Managing the Assets

The Distribution Asset Management group is a field-based organization with separate organizations for each of NU's three electric operating companies. A separate Transmission Asset Management group is responsible for all NU transmission facilities.

At Connecticut Light and Power (CL&P, Hartford), NU's largest distribution company, the Distribution Asset Management group is staffed by employees with an engineering degree or other professional status (such as a degree in finance) or extensive field experience. Each employee is fully accountable for the financial and operational performance of several distribution circuits, typically 25. To underscore the “ownership” concept of their role, the job title for this position is circuit owner. The circuit owners work in small teams, typically three to five per team, to foster team-based decisions and accountabilities.

Circuit owner teams report to the circuit zone manager whose primary responsibility is to provide guidance and training to the circuit owner teams.

One of the first projects that fell upon the circuit owners was the implementation of a continuing recloser installation program.

Recloser History at NU

Electric utilities use recloser technology on their distribution system as a mechanism to improve system reliability. CL&P employed reclosers as the mainstay for improving operational performance beginning in the 1960s.

Originally, the recloser performed the basic overcurrent functions through hydraulic activators located in the poletop recloser. However, implementing changes to the protection settings was difficult because the poletop recloser had to be removed from the pole. Subsequent enhancements separated the operational intelligence from the poletop recloser via an electronic control cabinet. These enhancements made it easy to change to the protection settings. In 1986, a new control logic called “loop scheme” became available. This scheme provides sectionalizing and restoration capabilities without human intervention using local intelligence at the switching device. Three-phase voltage monitoring on the load and source side of each recloser is required to augment phase-current monitoring to determine the location of fault sections on the distribution system. Based on these combined inputs, the recloser isolates these sections and restores service to the non-faulted sections.

CL&P embraced the loop-scheme philosophy to minimize the number of customers affected by an outage. Today, CL&P attempts to segment customer load into 500 customer blocks.

Combinations of up to five unique recloser control device types implement the auto-loops. Each recloser type operates based on the following rules:

• Radial Recloser (RR). A RR is normally in the closed position. It functions strictly as an overcurrent device.

• Sectionalizer Recloser (SR). A SR is normally in the closed position. It functions as a normal radial recloser for any event causing overcurrent on its load side. Additionally, the SR will lock open upon loss of either single- or three-phase source voltage after a programmed time delay, thus isolating any fault between it and the substation or the next source-side protective device.

• Midpoint Reclosers (MR). A MR is normally in the closed position and is normally located between a SR and a tie recloser (TR). The MR functions as a normal radial recloser for overcurrents on its load side. It will change its operating characteristics upon loss of three-phase source voltage after a time delay longer than that of the upstream sectionalizer recloser or other upstream reclosing devices or reclosers. Under these conditions, its minimum trip setting will be reduced and the number of operations to lockout will be reduced to one for a preset time period. After this preset time expires, and if the midpoint recloser did not lockout for an overcurrent, the midpoint recloser returns to its original programmed number of operations, and the midpoint will coordinate with the tie recloser after the tie recloser closes.

• Tie Reclosers (TR). A TR is required for all auto-loops and is used at normally open points to tie two circuits together upon loss of three-phase voltage from either source after a time delay longer than that of the SR and MR. After closing, the number of operations to lockout is reduced to one for a preset time period. After this preset time expires, and if the TR did not lockout for an overcurrent, the TR will return to its original programmed number of operations. A TR can be configured for either one-way or two-way tie operation. A two-way TR requires six auxiliary single-phase transformers (to establish two-way, three-phase sensing), while a one-way TR requires three auxiliary single-phase transformers.

• Voltage Sectionalizers (VS). A VS has no overcurrent function and therefore, does not interrupt fault current. It relies on an upstream device to clear faults. Its main purpose is to provide an isolating point on a circuit. The VS operates on loss of single- or three-phase voltage.

Today, CL&P has more than 2500 reclosers, including single and three phase, on its distribution system. A large majority of its three-phase reclosers have auto-loop capability. However, as the number of reclosers installed on the CL&P system increased and its operational performance improved, a new set of problems became apparent:

• The proliferation of reclosers substantially increased maintenance and inspection costs.

• Recloser status was unknown (open/close, reclosing and loop reconfigured).

• Switching on circuits equipped with a loop scheme became time consuming.

• Complex “restoration switching” became a typical scenario that had to be dealt with to restore the loop to “normal” configuration.

To address these concerns and others, CL&P formed a cross-functional team in 1997 to develop future distribution-automation strategies. This team made two key recommendations:

• Continue installing reclosers with auto-loop capability to minimize the number of customers in each protective zone.

• Supplement existing recloser auto-loop schemes and all new recloser loop-schemes with DSCADA functionality.

According to Mike Costa, senior engineer, the rational behind these recommendations was that “NU has relied upon an aggressive program to install recloser loop-schemes as a primary means to improve system reliability. Such schemes effectively minimize the number of customers affected during an outage. Yet, as efforts to further reduce the extent of outages become impractical, it's logical to start looking towards techniques for reducing the duration of outages. This is where we feel the installation of DSCADA equipped reclosers will be an effective and natural progression for our company.”

Additionally, this team identified several tangible benefits associated with DSCADA. These benefits include:

• Minimizing outage duration.

• Isolating downed conductors in remote areas.

• Providing automated switching and tagging in areas remote from service areas.

• Providing the ability to remotely switch critical customers.

Though all four benefits are important, the ability to isolate downed conductors to improve public safety has become an essential DSCADA feature. This feature has become the driving force for NU's DSCADA program.

DSCADA

In the early days of DSCADA (1996), a typical DSCADA-ready recloser installation included the recloser control cabinet connected to a separate remote terminal unit (RTU) via multiple interconnecting cables.

Because of the three-phase voltage sensing required for implementation of loop scheme, a typical installation required line work on three poles — one pole for the recloser, control and RTU; and two additional poles (one on each side of the recloser pole) for the voltage-sensing transformers. This three-pole installation was not aesthetically pleasing, and was costly; however, it had the required functionality.

Unfortunately, the supplier for the recloser control had several technical difficulties, which ultimately led to a temporary halt to the DSCADA project. During this hiatus, NU began searching for an alternate supplier. It found that several recloser manufacturers had vastly improved and enhanced their recloser controls to include the RTU function as part of the recloser control. Additionally, NU discovered other suppliers had implemented loop-scheme functionality.

A New Recloser Supplier

Searching for a new recloser supplier can be an arduous task. However, one critical factor that drastically increases the likelihood of success is selecting the right people for the project team. For this project, NU formed a cross-functional team consisting of both field and staff personnel. Members of this team represented protection engineering, distribution standards, system engineering, regional test, work methods, process improvement, training and information technology. These members were all subject matter experts in their respective field.

Because of the requirement for loop-scheme application with DSCADA functionality, the team was quickly able to narrow down a potential recloser supplier selection list.

The team also developed a comprehensive performance specification that became the basis for evaluation, testing and ultimately approval of a new recloser for use on NU's system.

The NU/Siemens Partnership

While searching for a new recloser supplier, the team established cost, quality and speed as the key measures for selection of a new supplier. In addition, the functionality as provided for in the performance specifications would insure that the new recloser would perform exactly as intended, along with providing the requisite product quality and reliability of operation.

The “cost” measure required competitive purchase pricing, lower total owning cost, lowest cost for taking advantage of advances in technology, and upgradeable and scaleable technology.

“Quality” was measured by compliance with NU performance specifications; superior quality assurance and quality control prior to product delivery; dedicated, visible technical support for problem resolution; and environmentally friendly products.

“Speed” was measured by the capability to deliver products on a schedule that met NU's customers' needs rather than the supplier's convenience. NU was seeking a supplier that featured a committed, visible sales organization with a solid understanding of NU and its needs.

In addition to these requirements, NU defined a list of key attributes that would clearly determine a “best-in-class” supplier. These attributes were:

• Safety as an absolute top-priority
• Trustworthiness
• Well-managed
• Innovation
• Ingenuity
• Results oriented
• Can-do attitude
• Flexibility to accommodate customer requirements
• Integrity
• Performance-driven culture.

NU selected the Siemens Centurion 27-kV vacuum recloser and control for its many benefits. The recloser uses vacuum bottle interrupters and epoxy bushings, making it environmentally friendly because there is no fluid or SF6 gas. This recloser has three-phase integral voltage sensors and the capability to add three additional external voltage sensors to the mounting frame. This feature allowed NU to move from a three-pole installation to a single-pole installation, resulting in significant cost savings for each recloser installation.

The recloser uses 316 marine-grade stainless steel, which eliminates potential corrosion problems and saves costs. The recloser control also has many unique benefits. The control cabinet was large enough to support the 40-W radio required for the DSCADA system. The battery hold time after auxiliary supply failure is guaranteed for five days from a fully charged battery.

Additionally, the control logic allowed the implementation of a fuse savings strategy or “lightning mode.” With this feature, personnel remotely turn on “lightning mode” prior to thunderstorms to add an initial fast trip, which attempts to clear a temporary fault and prevent the downstream fuse from opening. This feature reduces the probability of a permanent outage at the expense of the entire circuit experiencing a momentary outage. Because NU prefers to isolate line faults to mitigate unnecessary momentaries, lightning mode activates only during an imminent severe weather event.

According to Dana Louth, vice president, Energy Delivery Services, “The lightning mode feature will allow us to reduce primary fuse blowing for temporary faults due to lightning flashover. Additionally, we expect to save some main line burn downs during lightning storms.”

Another feature of the new recloser control is an auto-restore feature, useful at midpoint applications. It allows the control logic to match its settings to the direction of current flow. This logic provides the ability to not only switch to reverse settings when the loop operates but to automatically return to normal when the loop is restored, making it unnecessary to manually reset the control.

Another added benefit to working with the manufacturer was the ability to affect future product design changes. For example, NU wanted to reduce the time required to install the recloser on the pole by doing as much work as possible in the shop. This feat was accomplished by jointly designing a new recloser mounting bracket that allowed for mounting the recloser, associated external voltage sensors and other hardware to the bracket while in the shop.

Once assembled, the recloser is tested and shipped to the appropriate field location for installation as a pre-assembled unit. From the line-worker's point of view, installing this recloser is now a one-lift operation. Dick Gagnon, manager of system projects, stated “Installation time is cut in half when comparing the Siemens installation versus our previous supplier.”

Because Siemens successfully integrated the RTU function into the control, CL&P didn't have to be concerned about point-to-point wiring issues — a reliability advantage and labor savings feature.

Pilot Project Overview

Like most equipment evaluations, NU established a pilot project to evaluate the performance of the new equipment. Yet, NU didn't want to take the typical approach whereby you install a few units and evaluate the performance over a long time period. Instead, NU decided to take a more aggressive approach. CL&P installed 50 units and evaluated the performance in a real world setting. These 50 units were installed over four months, and the evaluation period commenced after the first 20 units were installed.

NU used the following criteria to evaluate this equipment:

• Cause of failure or operation: testing, restoration, animal, lightning, storm, equipment failure, unknown.

• Pre-installation or post-installation failure.

• Protection operation type: protection trip, automatic reclose, loop scheme.

• Root cause of failure: equipment failure, improper settings, installation, operator error.

The six-month evaluation period identified some minor functionality problems that were resolved quickly, allowing CL&P to move forward with its DSCADA plans. In August 2001, NU declared the pilot project a success. The Siemens Centurion recloser became the sole product approved for DSCADA projects and for all new purchases for traditional overcurrent application installations as well.

Post-Pilot Project

During the evaluation project, it became clear that to install the required number of reclosers, NU would have to modify its work process to increase productivity. NU established a new work process that centralized the assembly and equipment testing for these reclosers. The equipment is fully assembled and tested, and is then delivered to the appropriate work center for installation.

Today, NU has about 200 Siemens reclosers installed. By the end of the DSCADA program, it will have replaced 1000 existing reclosers with Siemens units, and installed an additional 400 new Siemens reclosers.

Reflecting on the success of this project, Ray Litwin, NU's director of asset strategy said, “With their Centurion recloser, and especially the men and women of the Siemens Power T&D team, we've hit a grand-slam home run. Siemens is helping to dramatically improve the performance of our infrastructure, which will have a real positive impact on customer satisfaction; and to reduce our costs, which will increase shareholder value. In summary, it's been an exciting, magnificent success story.”

Wayne Merris is a senior process consultant in the Utility Group Process Improvement department at Northeast Utilities. He has been involved with both transmission and distribution SCADA for the past 15 years. During the last three years, he has been the team leader for the DSCADA project and for the Siemens Recloser Evaluation project.

Day in the Life of a Circuit Owner

7:30 a.m.	Review daily interruption reports for any trouble on 25 circuits.
8:30 a.m.	Download circuit data from GIS into PTI analysis computer program. Load forecasted circuit loads from circuit #24 into program. Run analysis program.
9:00 a.m.	Analyze deficiencies — voltage, overloads, etc. Determine number of overloaded line sections or voltage problems.
9:25 a.m.	Develop solution sets to improve reliability. Utilize maintenance criteria matrix.
10:00 a.m.	Access marketing information on customer contribution sensitivity to reliability.
10:15 a.m.	Perform cost/benefit analysis on circuit: Verify cost per customer minute saved — circuit level SAIDI Verify cost per customer minute saved — operating company level SAIDI Verify ranking — overall company priority level.
11:00 a.m.	Select $80k project from above economic evaluation that meets all criteria.
11:30 a.m.	Meet with team (teleconferencing in future state). Team consists of circuit owners and circuit zone managers. Review $80k project with team. Team approves project. Complete hi-level design package. Enter hi-level design into computer. Transmit hi-level design to system projects along with authorized dollars. Transmit revised maintenance specifications to the maintenance group.
12:30 p.m.	Lunch
1:00 p.m.	Meet with divisional manager and then with first selectman to explain project scope and schedule.
2:30 p.m.	Perform circuit patrol on one of the assigned feeders.
3:30 p.m.	Enter patrol results into circuit database.
3:35 p.m.	Learn new power-quality mitigation techniques from multimedia training.
3:45 p.m.	Review above project with assigned construction (system projects) project manager.
4:30 p.m.	Meet customer to take and explain EMF readings.
5:00 p.m.	Attend local planning and zoning meeting.
6:00 p.m.	End of day