Manitoba Hydro's Multiple Distribution Supply Centers

Manitoba Hydro's Multiple Distribution Supply Centers

Subdivision developers had expressed concerns about how Manitoba Hydro was going to supply the new subdivision. They were especially concerned about the visual impacts of traditional substations.

Waverley West subdivision conceptual plan map.

The Waverley West subdivision was announced in 2005 as a new 13,000-lot subdivision for the city of Winnipeg (Manitoba, Canada). It encompasses 2,600 acres (1,052 hectares) and, on completion in 18 to 30 years, is expected to support a population of 40,000 with 13,000 homes. Economic conditions created load forecast uncertainty, specifically whether the entire development would be completed quickly or in the more typical 30-year scenario. This uncertainty increased the risk of significant stranded assets as a result of the high probability of error between the anticipated and actual loads.

Manitoba Hydro's planners considered three options for the supply of this large subdivision. The first option, a traditional design, would have called for a new 100-MVA substation or two 60-MVA stations — each station requiring 3 acres to 5 acres (1.2 hectares to 2 hectares) of property — feeding 25-kV distribution feeders that supply the subdivision through single-phase, looped networks. The second option was the expansion of an existing station. The third option was to use high-voltage padmounted transformers (HVPTs) in multiple distribution supply centers (DSCs).

The last option would supply the proposed subdivision by installing 10 or 12 10-MVA, 66/24 kV DSCs, as loading required. Using this approach, it was expected the capital requirements for the life of this project would remain relatively low and flat.

Addressing Concerns

A typical 10-MVA, 66-24-kV distribution supply center installation.

Subdivision developers had expressed concerns about how Manitoba Hydro was going to supply the new subdivision. They were especially concerned about the visual impacts of traditional substations. If the traditional station approach was to be used, then it was the subdivision developers' preference that it be placed underground or be moved outside the subdivision limits, in the countryside somewhere.

The idea of providing a 3-acre to 5-acre site for a new conventional station was rejected. In meetings with senior managers, the primary development companies insisted on an outright ban for a conventional station. They were adamant that whatever Manitoba Hydro installed should complement the subdivision surroundings and, with proper landscaping, be a seamless blend of natural beauty and modern living.

The solution was to use, in a new way, the Manitoba Hydro-developed HVPT in a DSC concept. With a 10-MVA capacity, it would require 10 to 12 sites interconnected on the perimeter of the subdivision. The minimal footprint of the DSC — typically measuring about 100 sq (9.3 sq m) with a low overall height of about 10 ft (3.1 m) — offered such a substantial aesthetic improvement over the traditional substation that, when developers of the subdivision were shown this option, they responded with an offer to provide 10 sites at no cost.

Flexibility Is Key

The flexibility offered by the DSC concept permitted the supply infrastructure to be staged to meet the progress of the subdivision development, with changing load profiles, rather than installing a complete traditional station, with redundant transformer capacity, and having to wait for 10 years to 30 years for the homes to be built and the load to materialize.

The second option was eventually ruled out because the existing station was too far from the subdivision to permit the installation of sufficient distribution feeders. While that approach was theoretically possible, it was practically impossible, given the limited right-of-way capacity. With everything considered, the DSC concept was expected to save between CDN$13.8 million and $14.6 million net present value (NPV) in capital infrastructure costs.

The 10-MVA, 66-24-kV DSC long-term supply schematic for Waverley West.

It must be noted the DSC scheme included a new distribution system, which called for an interconnected, automation-ready 25-kV three-phase network between DSC sites operated by S&C Electric's IntelliTeam smart grid system. Developers received service on time with enhanced aesthetics; the utility received a lower-cost installation; the customers received service with greater reliability. This was a true win-win-win.

Another real benefit is the use of the installed transformer capacity. In a traditional station, a redundant transformer is required at the outset and always resulting in 50% usage of installed transformer capacity for the life of the station. With the DSC concept, the spare transformation capacity is actually built into each part. The plan for phased capacity additions has the usage of the installed capacity ultimately rising to more than 90% while still providing a redundant transformer. For the same reason, a mobile substation and the provision of the connection itself is not required.

The Advantages

Actual experience to date, now three years into the project, has proven the capital requirements for this project have remained relatively low and flat. The DSC concept used is a completely scalable, just-in-time supply-system approach that minimizes the utility financial impact. The homeowners and land developers are pleased with a supply that is virtually invisible inside the subdivision. Eventually, the automated distribution network will improve the reliability of the electric supply to all of the customers, providing satisfaction to them and the utility's operating staff.

The DSC solution application to this large new subdivision offers a significant cost reduction. A 40% capital cost savings is expected. The distribution system will have state-of-practice reliability and be visually pleasing. This approach offers greater transformer capacity usage rates and better control of equipment obsolescence. More asset usage translates to more revenue for the utility.

There is a considerable reduction in the risk of stranded assets by using 10-MVA capacity blocks instead of large, 30-MVA to 100-MVA blocks. Arguably, this also provides for better asset management through controlled obsolescence, as not all units will reach the end of life at the same time. And, since typical installations can be readily completed in less than 12 months, there is virtually no downside to having the flexibility of rapidly adjusting the rate of installing capacity to meet changing load requirements.

Expected Summer and Winter Load Growth

Scenario Summer load growth
per year (MVA)
Total MVA Year
High conventional gas-electric, 18 years 3.9 70 2024
Low conventional gas-electric, 30 years 2.3 71 2037
Scenario Winter load growth per year (MVA) Total MVA Year
High conventional gas-electric, 18 years 3.5 63 2024
Low conventional gas-electric, 30 years 2.1 65 2037

Waverley West Long-Term Electric Supply Costs

Scenario DSC scheme Mohawk Bank 3
addition
New 115/24-kV
station
18-year rapid growth $21,545,000 $31,527,000 $35,871,000
NPV $13,845,600 $22,191,000 $27,709,000
30-year slow growth $23,907,100 $34,627,000 $39,154,000
NPV $12,268,500 $21,590,000 $26,297,000
30-year slow growth with 5-year stall $24,879,000 $35,670,000 $39,459,000
NPV $11,572,200 $21,168,000 $26,176,000

DSC Usage Rates

Number of DSC
installed
Total capacity
(MVA
Firm limit
(MVA)
Utilization rate
(%)
2 20 10 50.00
3 30 20 66.67
4 40 30 75.00
5 50 40 80.00
6 60 50 83.33
7 70 60 85.71
8 80 70 87.50
9 90 80 88.89
10 100 90 90.00
11 110 100 90.91
12 120 110 91.67

Acknowledgement

The author thanks Erni Wiebe of both Innovative Solutions Engineering Inc. and Partner Technologies Inc. for his invaluable assistance in the preparation of this article.


W.W. (Wally) Rzeszutek ([email protected]) is the senior distribution planning officer for Manitoba Hydro. He has 27 years of electrical field experience in advance and long-term distribution systems planning. Prior to entering distribution planning, his career at Manitoba Hydro consisted of 15 years as a protection and control technician, charged with commissioning and maintaining generation and transmission protection systems. He is a graduate of Red River College of Applied Arts, Science and Technology with diplomas in electrical and electronic engineering technology.

Expected Summer and Winter Load Growth

Waverley West Long-Term Electric Supply Costs

DSC Usage Rates

Companies mentioned:

Manitoba Hydro | www.hydro.mb.ca

Partner Technologies | www.partnertechnologies.net

S&C Electric Co. | www.sandc.com

Thomas & Betts | www.thomasbetts.com

SIDEBAR: High-Voltage Padmounted Transformer

As part of a cost review of the distribution business at Manitoba Hydro, an integrated gas and electric utility in the center of Canada, a desire for a simpler and more cost-effective distribution station led to the invention of a high-voltage padmounted transformer (HVPT) by Manitoba Hydro and its manufacturing partner, Partner Technologies Inc. They share the U.S. and Canadian patents and have developed the original concept from a live-front 5-MVA, 66-kV design to a dead-front design with a range of products up to 15 MVA and 138 kV primary, with any distribution voltage as the secondary.

Inside the transformer is a standard stacked-core, circular-coil power transformer as used in traditional station transformers. What makes it unique is the outside and the way the electric system connects to it.

Initially, live 69-kV bushings were housed in a high-voltage compartment with sufficient room for a safe connection of high-voltage underground cables protected from public access by a series of lockable, expanded metal and solid metal doors. Today, this design has given way to dead-front cable terminations that are shielded and grounded behind tamper-resistant locked doors and, even at 138 kV, provide the same level of public safety as standard 35-kV and below padmounted transformers situated in the front and rear yards of North America.

Features

The HVPT's unique design results in a host of desirable features not common in the traditional station:

  • Dead-front design

    Pfisterer high-voltage primary and everyday standard medium-voltage secondary underground cable connections make this a completely dead-front transformer.

  • Small footprint and no need for overhead structures

    Because of the underground cable connections, the need for overhead station bus work and associated structures is eliminated, which, in turn, greatly reduces the amount of property needed for the station.

  • No exposed live parts

    The application of standard distribution padmounted reclosers and switchgear in conjunction with the HVPT results in a distribution station, commonly referred to as a distribution supply center at Manitoba Hydro, that is totally padmounted with no overhead or exposed live parts. Only the high-voltage cable connections to the transmission or subtransmission lines may be overhead.

  • Copper-theft resistant

    All the ground wires and connections are inside-locked, tamper-resistant enclosures, removing the temptation and ability to cut the copper wires.

  • Possibility of no fence

    Since all the electrical connections are dead-front, inside-locked and tamper-resistant enclosures, the traditional fence also can be eliminated, provided the transformer is specified as oil natural-air natural only and a well-designed ground grid, meeting the touch and step potential requirements of IEEE 80, is installed.

  • Higher reliability

    Manitoba Hydro has opted for a simple transformer design that relies on distribution voltage regulators rather than an on-load tap changer for voltage regulation. This eliminates the possibility of arcing byproducts contaminating the oil and allows for a much lighter transformer with a minimal maintenance requirement. Padmounted reclosers with modern, sophisticated electronic protection capabilities monitor and protect the transformer from the downstream distribution system. Recently developed Thomas & Betts' 69-kV and 138-kV current-limiting fuses ensure the transformer is protected from high fault current ruptures.

  • Shorter in-service dates

    With the ability of Partner Technologies to produce these transformers within a year of order and the simpler padmounted design of the station, Manitoba Hydro has reduced its lead time for a new station from three to five years down to one year.

  • Lower overall cost

    The reduction in property and the elimination of aboveground structures have offered Manitoba Hydro an opportunity to save up to $2 million relative to the cost of a new station.

All these features have resulted in safe, effective yet low-cost installations that have saved Manitoba Hydro and others millions of dollars with every deployment.

Flexibility in Application

The original intended application of the HVPT was as part of a new rural substation, especially where existing wood-pole stations needed to be replaced or new load required a quick and inexpensive supply. Interestingly, with its second installation, new applications became evident. HVPT has become a desirable option for larger commercial and smaller industrial customers since it provides an aesthetically appealing look that allows such customers more flexibility in locating their station.

It also offers an electric utility the opportunity to increase the supply from a station or nearby a station without disturbing the existing station, or requiring expensive retrofits and refurbishments. If located strategically with respect to an existing distribution system, the additional source can reduce the length of feeders, thereby improving voltage and losses. In combination with some foresight in sizing the station, such an addition improves the reliability to the customers by providing an alternate source.

To date, Manitoba Hydro has installed more than 30 HVPTs in a variety of applications and settings.

 

TAGS: Substations
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