Behind upgrading the 50+ years old 132/11 kV substation

Refurbishing an Old Substation

Let’s look at the 50+ years old 132/11 kV substation that needs refurbishing and uprating as an illustration of the complicated mix of concerns that need to be considered. It shows that there are more than just financial factors to think about, including things like site suitability, equipment condition, projected loading, resource requirements, how feasible it is to work in an in-service substation, and how well the project fits in with the development of the surrounding networks.

Additionally, this example shows how important it is to have a thorough and precise strategy outlining the steps for each option before making a decision. Otherwise, the project can hit a snag in the middle. Furthermore, the time needed to implement each alternative will be drastically understated.

It takes a lot of engineering and planning to make significant changes to an old substation.

Table of Contents:

1. Description of an old substation
2. Breakdown of substation new needs: What are the key issues:
   1. Bad substation condition
   2. Outdated rating
   3. Questionable reliability
   4. Serious safety concerns
3. Additional issues with the substation
4. Condition of major substation equipment:
   1. Power Transformers
   2. 132 kV switchyard and switchgear
   3. 33 kV switchyard and switchgear
   4. Obsolete protection and relay panels
   5. Earthing condition
   6. Ancient SCADA capabilities
   7. Nonoperational tapchanger control
   8. Inadequate auto–closing
5. Compromised reliability performance
6. The refurbishing concept
7. Other options considered:
   1. Build a new substation on a different site
   2. Re-build the outdoor 33 kV switchyard
   3. Replace the 132 kV switchyard
   4. Establish a 132/11 kV zone substation
8. Layout and transformer bays & buses
9. Completely new protection
10. Auxiliary systems
11. Enhanced substation safety
12. BONUS (PDF) 🔗 Download ‘Best practice in construction of a high-voltage power network’

1. Description of an old substation

Fifty years ago, the substation was originally created. It is a 132/33 kV substation that was supplied by four 132 kV feeders on two 132 kV double circuit steel tower lines. At the time, it contained four 60 MVA transformers. Today, 10 outgoing 33 kV feeders are used to supply nine 33/11 kV zone substations.

It had four outdoor 60 MVA transformers, an outdoor 132 kV switchyard with an antique Merlin Gerin circuit breaker, and an outdoor 33 kV switchyard with duplicate busbars and selectable 33 kV oil circuit breakers. Its protection, control, batteries, and auxiliaries were housed in a tiny control structure.

An increase in capacity was necessary since the substation was loaded close to its firm N-1 rating and a significant load increase was expected.

It was necessary to undertake a large-scale capacity upgrade and renovation project.

Figure 1 – Layout of the site before to reconstruction. In order to prepare for the new building, take note of the relocation of three 33 kV feeders and 33 kV capacitors

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2. Breakdown of substation new needs: The key issues

Major work at the substation was obviously necessary and consisted of four main parts:

2.1 Bad substation condition

Extensive testing and evaluations of condition, together with visible rusting and degradation, proved that many items were nearing the end of their useful life. Numerous things were at least half a century old.

2.2 Outdated rating

The load had already reached 180 MVA, which is the maximum rating of the transformers (on an N-1 basis). The goal was to add a 13–15 MVA spot load to the pumping load at a large sewage treatment plant.

The regional average load growth rate persisted at around 3%. This meant that two of the four 60 MVA transformers needed to be replaced with 120 MVA ones. The other two will eventually need to be replaced.

Further Study – Providing technical documentation for a turnkey substation

Technical Documentation for a Turnkey Substation

2.3 Questionable reliability

In the past few years, the outdoor 33 kV switchyard has been the main source of unreliability in the substation’s supply. Birds, small animals, and wind-blown debris were causing the switchyard to be vulnerable to flashovers due to congestion and substandard clearances.

Factors also included the area’s very remote location and the absence of substantial 33 kV connections to nearby load centers.

2.4 Serious safety concerns

At the substation, we found the following safety concerns:

1. The 33 kV outdoor switchyard has congestion and below-standard section safety clearances.
2. The risk of explosions on the 33 kV circuit breakers is known and has been controlled by DDF and PD testing, as well as the replacement of bushings when needed.
3. Nevertheless, there is a risk that must be addressed through labor-intensive activities.
4. The 132 kV switchyard is vulnerable to explosions of CVTs and post-type CTs.

Further Study – Electrical Safety Practice – Lockout Before Work, Test Before Touch!

Electrical Safety Practice – Lockout Before Work, Test Before Touch!

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3. Additional issues with the substation

As we considered our options, we noticed that the substation had a number of additional issues that needed addressing. The following were:

1. Incomplete protection in some areas such as non-duplicated 33 kV busbar protection;
2. Many old protection relays showing deficiencies and high maintenance;
3. Common negative used between the A and B protection schemes;
4. The 33 kV switchyard configuration was a duplicate busbar, selectable arrangement where busbar protection CTs, tripping, and transfer tripping had to be switched through auxiliary switches of the selecting isolating switches, causing many maintenance and adjustment problems and impossible complications with functional proving tests ;
5. The 33 kV switchyard had 4 sections of busbar – however the major 33 kV feedernetwork which it supplied is a 6-feeder closed network, which meant that there were two busbars which supplied two feeders each and where a single busbar failure would interrupt 2 feeders;
6. Both batteries in a common battery room;
7. Rudimentary SCADA with very limited facilities;
8. Noise issues from air blast 132 kV breakers;
9. High maintenance on high pressure air system for 132 kV breakers (compressors, air leaks, etc.);
10. Earth grid. Severe corrosion of steel star stakes;
11. Severe rust of some of the switchyard steelwork;
12. Unreliable tap changer control system to the extent that it had to be left non-auto for several years;
13. Unreliable scheme for auto-closing of the standby transformer;
14. Extreme congestion of outgoing 33 kV overhead feeders in the terminating span areas and in the adjacent high traffic density roads;
15. Below standard switchyard security fencing;
16. 33 kV capacitor banks used PCB filled capacitors. These were replaced on a system wide program but in the same time frame as this project;
17. Oil containment. This was addressed by installation of an oil interception tank a year or so earlier as part of a separate program;
18. The 33 kV circuit-breakers, isolators, and busbars all had a 1200 A rating which matched the output of a 60 MVA transformer, but was only half that required to match the intended 120 MVA transformers;
19. The 33 kV circuit-breakers had a fault interrupting rating of only 1000 MVA which was insufficient to allow all 4 x 60 MVA transformers to be switched in parallel and insufficient for the intended 120 MVA transformers; and
20. The transformer 33 kV connections were by strung bus running over the duplicate 33 kV busbars. Failure or work on the strung bus connections therefore required an outage of two of the four busbars and two of the four transformers. Loading was such that this could only be permitted from about midnight to 6 am on a Saturday or Sunday.

Figure 2 – An older power substation that needs upgradation

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4. Condition of major substation equipment

The degraded state of numerous 50-year-old plant equipment was a significant element influencing the decision about the substation. The following is a summary of the important substation equipment. Many ‘hidden’ features of the condition were not immediately evident and required comprehensive testing, meticulous analysis of test data, internal inspections, feedback from maintenance and operational personnel, and investigations into the reasons of equipment failures.

The accumulation of this type of information required several years. In some instances, the accessibility of spare components was challenging or nonexistent.