optimal recloser placement in radial distribution systems 1

[farshid]

What is the practical way for optimal recloser placement in radial distribution systems? Although many methods such as Genetic and PSO algorithms have been introduced in academic papers, since unfortunately the real and practical data of the distribution network does not exist, none of them can be employed. A simple and practical (even approximate!) way which does not need much data (and tough simulations) is of great interest. Any help is appreciated.

 

[Desrod2]

Some software can do just that based on network topology, customer locations and alternate sources of supply (load block transfers to adjacent feeders). Optimization function could be performed either on max kW supplied or minimum customer-minutes of interruption. Simple rule of thumb for 1 recloser: split your feeder in 2 based on customers number or load kW and fuse correctly all your lateral. If you have possibility of transfer with adjacent feeders, split you feeders in 3-4 load blocks of the same size, load feeders at ~75% max capacity and have N.O. switches to be able to transfer non faulty load blocks on the backup feeders. We had good performances in the past in medium & high density network. We were configuring sets of 4-5 feeders.

 

[Mbrooke]

Which segment faults the most or is most likely to fault the most? Which segment has the most critical customers? Generally re-closers are placed after the most critical customers are covered and right before the most trouble prone segment start- at least thats how I've seen it done. In general when all is equal reclosers are placed 1/2 way down the line.

 

[farshid_imported]

Thank you Desrod2 for your comments.
Could you please explain more about your method and your rule of thumb? Unfortunately I do not understand completely what you mean.

 

[farshid_imported]

Dear all
Some say that it is better to locate the recloser near the substation; because as you know, 70-80 percent of the faults in electrical distribution networks are of transient (not permanent) type and so by doing this, most of the faults are cleared by the recloser in several seconds. The disadvantage of this placement is that when a permanent fault occurs, because the load of the recloser and the substation are almost the same, even if the fault is cleared by the recloser (recloser lockout), the longer part of the line is de-energized. But as mentioned before, since the nature of the most faults in distribution networks are transient, the beneficial of this method seems to be more than its drawbacks. What is your comments? Is this true? Why or why not?

 

[Mbrooke]

Substation breakers are normally programmed to reclose so temporary faults before the recloser are a none issue. Think of a reclosers as nothing more than a fuse or circuit breaker. It simply isolates permanently faulted segments of the line. Unless you have something like a hospital on the first 5% of the line with no auto throw over or you are "splitting" the circuit in two, having a recloser near the substation is of little gain.

 

[Mbrooke]

Also to add- don't forget to account for the time spent patrolling the feeder. A recloser placed at half point (just as an example) will reduce line crew patrol time in half. You immediately know which segment has faulted based on where the outage has taken place. Whole feeder means you patrol just the first section, half outage means you patrol the last half.

 

[farshid_imported]

Thank you

 

[Mbrooke]

Welcome

Also, don't be afraid to deploy recloser loops if you ever need them. In some system recloser loops actually give tremendous savings. I've actually seen recloser loops used to postpone the construction of new substations and delay overhauling of existing ones- by decades if load growth is gradual.

 

[farshid_imported]

What do you exactly mean by recloser loops? Could you explain more or introduce a reference so that I can be aware of this topic. Thanks again.

 

[Mbrooke]

Sure, no problem. Here is the basic concept:

https://www.youtube.com/watch?v=2VGs7FdrSIE

Here are some more basic links:

http://www.tdworld.com/distribution/know-your-non-conventional-instrument-transformers

http://www.schneider-electric.us/documents/customers/utility/br-us-loop-automation.pdf

http://www2.schneider-electric.com/...r-brands/nulec-loop-automation-datasheet.page

http://slideplayer.com/slide/10541318/

http://www.transmission-line.net/2012/05/power-transmission-and-distribution.html

But to boil all that down: basically the segment after the recloser can be connected to another normally open recloser bridging from another circuit. When the fault is between the substation and normally closed recloser, that particular recloser can be opened and power back fed from another circuit via the normally open recloser. The idea is that instead of loosing the whole feeder, you only loose part of it for a fault on any portion. For some utilties this concept is gaining immense popularity and paying back for itself. A few utilties in the US have been using this technology for 30 years now.


To simplify the advantage: In a radial feeder with a mid point recloser, the customers on the second half experience twice the outages. But by using a loop scheme, the customers on the second half have increased continuity of service by experiencing only half the outages. If the alternate supply feeder also has a mid section recloser that circuit can also be configured to have increased reliability by being back fed from your first circuit.

 

[farshid_imported]

I wanted to let you know how much I appreciated your help.I know how much time and effort you invested.You are a valued member. Could you please mention somewhere where this scheme is used (e.g. the mentioned utilities in the US and, if possible, the url of the websites to be more familiar with them)

 

[Mbrooke]

Thank you for the compliments, and an even bigger thank you for posting here All questions are of value.

One place where I know this has been in use for 30 years has been Eversource Energy (formerly Connecticut Light and Power; Massachusetts Electric and New Hampshire Public Service- all which merged into the name "Eversource") It was in longest use at the CL&P branch.

https://www.eversource.com/Content/ct-c

An old article describing one advantage:

http://www.energycentral.com/c/iu/dscada-talk

WHEN FIRE HIT A RURAL CONNECTICUT HOME AND A DOWNED POWER LINE endangered response teams, the actions of Connecticut Light & Power (CL&P) were anything but routine. With residents trapped inside the burning building, firefighters didn't have to wait the seemingly interminable minutes it would normally take for a utility crew to arrive and cut the electricity. Instead, in a control room nearly 80 miles away, technicians at a CL&P operations center were able to cut power to the structure less than a minute after receiving the emergency call.

That's because CL&P is about three-quarters of the way through an eight-year project to further automate the 17,000 overhead line miles of its distribution network. The distribution supervisory control and data acquisition (DSCADA) system, through a high-powered radio communications network, now enables a centralized operations center to talk to 1,731 of the 3,000 reclosers mounted on poles throughout Connecticut.

Reclosers—or switches that detect faults throughout the distribution system and automatically restore service—have been an essential part of distribution systems for decades. But having the ability to overlay DSCADA throughout the system happened serendipitously.

The ability to deploy a DSCADA system was enabled by decisions made 20 years ago to convert the entire system from lateral distribution to a series of thousands of interconnecting loops. ''In that way, a single customer on one section of a line could be energized from two different paths,'' said E. Bruce Roy, manager of distribution engineering and operations support for CL&P, the dominant utility in the Nutmeg State. The company has determined that the optimal setup in its protection scheme is for each recloser to serve about 500 customers with each recloser located a few dozen yards apart in densely populated cities to perhaps miles in the remotest regions.

Those paths are on display at its system operations center in Berlin, Conn., roughly the geographic center of the state. The system operation center has divided Connecticut into three regions—western, central and eastern—with 11 individual work stations that can be reoriented as the workload demands.

Each monitor can hone in on any color-coded recloser in the system, with red and green signifying those closed and open, and white designating those not yet enabled with DSCADA. In that instance, a truck would have to roll to the site to de-energize a line. A steady stream of single-line messages scroll down another screen, monitoring events in the systems, with bright pink ones indicating messages from 911 that warrant attention and may require immediate action. On routine spring day, the center is fairly quiet, but operators are poised to act, especially when storms gather and system events literally track from west to east in a storm's path.

And with the thunderstorm season upon us, the system is routinely used to cut power to downed lines that threaten trapped motorists and other people who may be endangered.

And there's also an operational benefit that occurs during storms. DSCADA also allows the utility to operate its system using a lightning protection mode. Normally, reclosers can be set to work extremely fast, as fast as one cycle, to detect a fault. But the operators have the ability to adjust a time delay intentionally. ''If we wanted to, we could set the reclosers to as fast as they are capable, but in any fault, that would cause the lights to flicker on and off, which would be a nuisance to our customers,'' said Roy. ''But in lightning mode you would want the reclosers to respond very fast.'' The company developed the logic so when storms occur, the system allows CL&P to reset the reclosers from its operations center in any or all areas of its service territory to prepare the system for lightning strikes—essentially protecting its fuses from blowing during these events. The cost benefit is real, but impossible to quantify. ''We know it's saving, but that's almost like asking for an answer of what didn't happen,'' he added.

Other cost benefits are easier to quantify. ''Historically, before DSCADA, trucks would roll and be sent from trouble spot to trouble spot. Planning would start before the day even began, and that meant overtime,'' Roy stated. ''Last year, there were 60,000 operations through the DSCADA system, which resulted in 10,000 to 12,000 trips by truck, so right there was a cost benefit of well over $1 million.''

The initial outlay for the system is fairly significant. About 1,700 units are installed, each serving about 500 customers. At about $20,000 a unit—essentially a computer installed on a pole—the company already has invested about $3.4 million. At the current rate of installation, CL&P expects to complete the project in about two years.

The overhead deployment started about six years ago with a pilot of about 45 locations in southwestern Connecticut. Around the same time, the accidental death of a firefighter who entered a building that did not have its power cut only underscored the safety benefits. After the pilot, and some improvements from equipment manufacturers, a decision was made with the Connecticut Department of Public Utility Control to introduce the technology statewide.

Deploying DSCADA in CL&P's 6,000 miles of underground distribution is still being contemplated, though not yet mandated by the state regulators. The utility is also looking at installing them in underground systems. Engineering work is now being done, with an assessment of costs and benefits to be made later.

 

[Mbrooke]

They talk about SCADA, because when they first deployed recloser loops around 1985 (after Hurricane Gloria), they were none communicating. They used simple Kyle controls which were cutting edge at the time:

http://www.cooperindustries.com/con...es/library/280_ReclosersControls/S2807710.pdf

http://www.cooperindustries.com/con...ces/library/280_ReclosersControls/S280771.pdf

http://www.cooperindustries.com/con...ces/library/280_ReclosersControls/S280774.pdf

http://www.cooperindustries.com/con...es/library/280_ReclosersControls/S2807912.pdf

Compared next to today's technology these are extremely primitive and mediocre in general. They used simple timing and voltage sensing set via dipswitches to "rewire" circuits. The source recloser would open say after 45 seconds of sensing missing loss of voltage caused by a feeder lockout, and the tie recloser would then close after sensing 90 seconds of no 3 phase power. Because there was no communications, they had several flaws:

1. Line crews had to drive around re-setting the loop back to normal once the fault was repaired. This was lengthy and pains taking- and as guessed didn't always happen.

2. If the source and the tie recloser could not remain closed for any length of time (such as phase angles being to great because the alternate source is another substation) customers had to experience a second, (some times longer outage) to open the tie and then manually close the source)

3. Because this was done all by stand alone timing logic, it was a very real possibility of loosing loss of voltage coordination when stacking recloser loops on top of one another. Further, each time-current curve needing to be stacked increased the length and pickup of the curves below increasing system stress and the amount of time faults remained.

4. The tie didn't know if the loss of 3 phase power was from a fault between the substation and source re-closer or the source and tie recloser. If between the source and tie, that segment would be re-energized up to a 5th time. 6th time if the segment has critical customers and the decision was made to have two alternate sources. In other words the possibility of a downed line reaming live shot way up.

5. You simply had no clue when a recloser did lock out. People still had to call in to report power outages.

6. You were also limited to simple loops- which sometimes was enough- but there was no logic to handle feeder loading and what station/line might have more available capacity.

As a result all new controls now have SCADA and advanced logic. Each recloser can be monitored, opened, closed and adjust from a remote location. Controls can be configured to "talk" to one another peer-to-peer, which allows them to make intelligent reconfiguration decisions where needed.

 

[farshid_imported]

It is helpful to have someone who has had experience with similar issues . I appreciate your taking the time out of your busy schedule to write to me. I have some other questions. The most important is that how much the time interval between a recloser open and close should be? Suppose that there are 4 shots (4 open and close operations)and so there is 3 time intervals. e.g. 2.5,10,20 sec or...?
If it is too long, then the fuse blowing may not occur because the fuse link may not melt,even in the case of a temporary fault. If it is too short, the fuse link is always saved and perhaps there is no chance for the temporary fault to be cleared. Is there any rule and criteria to determine these time intervals?

My less important questions:
Which parameters should be considered to choose a recloser and sectionaliser for buying? e.g. price, accuracy, maintenance,...
Which brands of reclosers and sectionaliser do you suggest?
Where should a sectionaliser be installed?

 

[Mbrooke]

No issue

It is helpful to have someone who has had experience with similar issues . I appreciate your taking the time out of your busy schedule to write to me. I have some other questions. The most important is that how much the time interval between a recloser open and close should be? Suppose that there are 4 shots (4 open and close operations)and so there is 3 time intervals. e.g. 2.5,10,20 sec or...?

I am going to be honest: I don't know for sure. I know this is about the most arbitrary answer one can give, but I just do what "feels" right. Around here its typically 1 second open after trip, 10 seconds after trip and then 30 seconds after trip. But I have seen distribution guys do all sorts of open interval times like 30 seconds open on the first trip and then 60 seconds open. Heck I've seen 90 seconds on a first try. But, one thing that history and operating experience has taught POCOs is that in terms of customer satisfaction its best to have the first open interval as short as practicable; 1/4- 1/2 seconds has been done and tried with success to my knowledge. Reason being that roughly 2/3 of all temporary faults will clear and not re-strike when energized in this short amount of time. Yes a temporary fault is more likely to strike back up with a 1/2 second open time interval vs a 10 second open time interval -HOWEVER- for every temporary fault that could be cleared 100% of the time with a 10 second open there is a 65-70% chance a temp fault will be cleared with a 1/2 second open. A 1/2 second interruption often prevents blinking clocks and other noticeable events where a 10 cycle would become evident. Being able to eliminate 2/3 of all electronic resets on customer equipment is generally seen as good business. You would be surprised how many people do not have battery backup on their alarm clocks even though the capability is there. 1/2 second has also been known to work well for lightning strokes to my knowledge.

If it is too long, then the fuse blowing may not occur because the fuse link may not melt,even in the case of a temporary fault. If it is too short, the fuse link is always saved and perhaps there is no chance for the temporary fault to be cleared. Is there any rule and criteria to determine these time intervals?

There is an equation you can use, see this:

https://www.sandc.com/globalassets/...ormerprimary-sidefuseswithfeederreclosers.pdf

The longer the open time, the longer the fuse tube has to cool But, in general you do not worry about it. You trip fast enough when you want to save the fuse, to slow down long enough to blow the fuse when you want to. Its easier to ignore the fuse heating on the slow curves and just make sure they are more then enough to melt the link "pre-heated" or not.

Now, if you mean the speed of curves that will save a fuse and those that will blow a fuse that is different.

My less important questions:
Which parameters should be considered to choose a recloser and sectionaliser for buying? e.g. price, accuracy, maintenance,...

Lots, but basically select the model and control which gets the job done now and in the foreseeable future for the lowest cost. If however you use lots of sophisticated and expensive controls, sometimes its better to use the same control for the few basic applications that pop up. In genenral its better to have one or two models that serve the needs of the whole system then have a million different makes selected on a case by case basis.

Also take fault current into account as well. Most systems have about 10,000amps max short circuit current and most reclosers are rated as such. But still check none the less. 10,000 can be exceeded and system X/R ratios can play a role to my knowledge.

Which brands of reclosers and sectionaliser do you suggest?

Around here its Copper:

http://www.cooperindustries.com/con...overhead_distributionequipment/reclosers.html

Excellent record to my knowledge. FWIW thousands of these are on Eversource's system from personal observation. Now, whether or not there are better reclosers out there I have no idea as I don't know much past Copper. From the little I have heard avoid those "flower pot" reclosers, but that as thin for me to say as its rumors I've heard on electrical forums.

Where should a sectionaliser be installed?

No straight forward way to answer that, it varies based on many things. But basically anywhere you don't mind the segment before the sectionalizer blinking for faults after the sectionlizer. One of the best places where I can think of sectionlizers being used is as a low cost protection against single phasing. Yes a sectionalizer will not detect on an open (broken phase) conductor, but if a phase to ground fault occurs on one or two phases, a 3 phase sectionalizer will allow for line reclosing and then disconnect all 3 phases where fuses would leave one or two phases intact. Big no-no for some customers. In a radial system perhaps toward the end- maybe 1/4 down the feeder?

This of course assumes you mean typical (classical) sectionlizers:

http://www.cooperindustries.com/con...ead_distributionequipment/sectionalizers.html

And not motor operated gang switches sectionlizers

https://www.youtube.com/watch?v=WfOD1KGNZGw

These sectionlizers can be applied to recloser loops (as well as radial lines) which further sub-divided. Ie, say if you have 1000 customers between a source and tie recloser, these can be used in peer-to-peer sub-pairs in conjunction with the SCADA reclosers further sub-divding the feeder. Adding two on the 1000 customer segment will break things into 333 customers. Because these are not a full recloser and only a simple gang switch, cost savings could be realized.

...................


Of course I have been talking about the most technologically exotic distribution systems. Whether your system is this complex or a simple radial line depends on many, many factors. Cost, outage tolerance, repair time, size, weather, loads being served, trees, ect, ect ect. There is no one size fits all and systems are generally handled on a case to case basis dictated by their environment and desired performance.

For example, one of the reasons why Eversource uses SCADA and recloser loops to such a degree is because they are one of the most heavily wooded service territories on earth. Typical summer thunderstorms results in dozens of downed trees and many feeder segments affected all at once in any particular service area. If they were a mid-western utility with no tree there is a good chance most of their feeder would all still be radial. Another example: in areas where there are frequent ice storms, wind or narrow easements spacer cable is selected over bare wire.

 

[Mbrooke]

Also if you would like I can clarify what I meant by delaying new substations or using smaller substations:

In general failure of power transformers today is much less frequent then decades past. Multiple failures at once are rare. Thus as a result any particular system with multiple transformers theoretically only needs one spare.

Picture a typical 180 MVA load pocket fed by 3 different 138kv-25kv substations with 25kv overhead distribution feeders. Each substation supplies 60MVA of peak load. In a none looped system each substation will have two 60MVA transformers. Load is normally evenly split between the two transformers, so for the failure of either transformer results in the full 60MVA being placed across the remaining unit. Hence the selected MVA rating. This is the typical design and mode of operation for most US utilities. Any further increase in load will require more transformers or replacing the existing units with larger ones.

Now, picture a system with recloser loop automation on each feeder circuit. The system can be programmed so that the loss of any 60MVA transformer results in automatic "load rolling". When a transformer fails at substation #1 (for example), the source reclosers on various feeders attached to the substation with the failed transformer open, and the tie reclosers from feeders emanating from other substations close. 12 MVA of load is transferred to substation #2 (6 MVA across each of two transfomer) and another 12 MVA is transferred to substation #3. In total 24 MVA of load is removed from the 60MVA load chunk normally served by substation #1. Thus, when the feeders that were normally being supplied by the failed transformer are picked up by the remaining working unit, it will only see 36MVA of load.

Therefore we have two options:

1. Assuming no load growth will take place in our 180MVA load pocket we can select 6 25/30/36 MVA transformers instead of 6 40/50/60MVA transformers. This greatly saves cost, space and reduces fault current. In systems where larger transformers force short circuit currents to exceed 10,000amps being able to get at or below 10ka is a huge blessing and cost savings on many levels. Not having to consider reactors alone is a blessing.

2. Lets say your 180MVA load pocket was designed as a radial system, 60MVA units. In the next 5-10 years peak load is projected to increase to 250MVA but not beyond that for 25 years. In a radial system you will need larger transformers at each substation (85MVA) or an extra 60MVA at each substation. You could in theory only add a transformer on one or two of the subs instead of all 3 by redistributing the load (feeder size) so the sub that can accommodate the extra transformer sees more loading... but that means some feeders will loose more customers for any fault and still anything that involves substation expansion or renovation costs millions. However, by adding recloser loops and a simple SCADA system over those 5 years you can delay substation expansion for 30 years by investing peanuts. Peanuts that may even pay for themselves in keeping customers on when a car hits a pole or bad whether strikes. For some utilites being able to re-use existing substations alone has justified recloser loops.

 

[farshid_imported]

Dear Mr. Mbrooke
I’d like to take this opportunity to thank you for the valuable assistance you’ve given me. You have generously shared your expertise and experience with me, and I truly appreciate the support. I sincerely appreciate the time you spent.

 

[Mbrooke]

Thank you, this means a lot to me But I think you deserve even more recognition for asking in the first place. Every question asked as equal to the answer answer given. And the only bad questions are those which are never asked. Never stop learning.