gridtech subs auto smart

SESSION

4Emerging Trends in

Substation Technology - I

212

New Technologies in T & D, Renewable Energy Integration,Smart Grid, Energy Efficiency and Communication

5th International Exhibition & Conference, 2015

April 8-102015

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SUMMARY

GETCO network is expanding rapidly to meet thegeneration as well as demand requirements in thestate. Also due to non availability of gas,government policies in the benefit of REgeneration and implementation of merit orderdispatch, power flow pattern has changedcompletely in last few years and load pockets havebecome generation pocket also. Earliergeneration pockets in Gujarat were in southernregion and power was flowing towards central,western and northern region. But, now power isflowing from western region to central, southernas well as northern parts of the Gujarat.

Moreover, western and northern region is havingpredominant agriculture load. Hence, during non-agriculture season load consumption reducesconsiderably. In addition to that, transmission linesconnecting these regions with central Gujarat arequite long. These long lines are loaded below SILresulting in generation of excess reactive powercausing high voltage at 400KV Buses in theseareas. Because of Over Voltage, many 400KVLines are required to be switched off to maintainvoltage within acceptable limits. This, in turn, isjeopardizing grid availability and security.

To overcome Over Voltage, GETCO found theneed of Reactors at 400KV strategic location (7Places) based on system study. But, out of seven,four locations have the space constraint forproviding Reactor bay. After brain storming, itwas decided to utilize TBC bay as Bus Reactorbay by providing Bus reactor in Transfer buscoupler bay. The main consideration behind thisdecision was utilization of TBC bay on very fewoccasions in a year. On finalization of this

modality, there are challenges regarding (i) BusReactor arrangement in TBC Bay, (ii) Control &Interlocking philosophies, (iii) Protectionphilosophies, (iv) Whether to utilize TBC Bay asTBC as well as Bus Reactor or either of the two.Challenges become harder as each substation hasdifferent Make and Type of TBC Panels, DifferentTBC interface schemes and Different Bus barschemes. Also there are challenges regardingwhich type of panel is to be considered for Reactor.

The above scheme has really helped GETCO inmitigating Over Voltage problems substantiouslyand there-by strengthening security of grid. Thispaper shares the knowledge of implementing thescheme, issues & challenges faced and benefitsachieved.

Keywords: TBC, BCT, RADSS, PS class

1. INTRODUCTION

In recent years, power flow pattern has changed inGujarat state because of load growth in specificpockets and techno-economic considerations like:(a) Shutting down of Gas based power plants due tonon-availability of Gas (b) Government policiespromoting RE generation (c) Convergence of Loadinto Generation pockets and (d) Implementation ofmerit order dispatch.

Moreover, western and northern region is havingpredominant agriculture load and during non-agriculture season, load consumption reducesconsiderably. Moreover, transmission linesconnecting these regions with Central Gujarat arequite long. These long lines are loaded below SILresulting in generation of excess reactive powercausing high voltage at 400 kV Buses in these areas.Hence GETCO network started facing over voltage

Special Protection Scheme for Bus Reactor inTransfer Bus Coupler Bay

N.M. Sheth S.K. Jadav B.J. PatelGujarat Energy Transmission Corporation, India

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in non-agriculture period. Details are mentioned inTable 1.

Table 1

400KV Month wise Maximum Voltage (KV)Substation Apr May Jun Jul Aug

2011 2011 2011 2011 2011

Jetpur 432 429 429 430 431

Soja 421 418 417 417 419

Chorania 428 423 416 419 419

Kansari 420 415 414 423 423

Amreli 418 418 416 417 418

Vadavi 426 425 425 424 423

Hadala 430 427 428 431 431

To over come this issue, 400KV Bus Reactor isproposed at 7 strategic locations based on systemstudy. But due to space constraint, it is decided toprovide Bus Reactor in Transfer Bus Coupler bay atfour out of seven locations after reviewing historicaldata of utilization of TBC Bay.

This led to new challenges for Control, Interlockingas well as Protection philosophies including physicalconnection of Reactor Bay with TBC Bay.

All challenges are addressed iteratively and afterhaving lot of exercise, project specific solutions arederived and implemented for each substation.

2. PHILOSOPHIES ADOPTED

In order to consider Bus Reactor in TBC Bay,philosophies of TBC Bay as well as Bus Reactor Bay

are required to be integrated precisely withoutmaking any harm to existing TBC bay functionality.

(i) Switch Yard Arrangement

Bus Reactor is provided in front of Transfer BusCoupler bay (Fig.1). Now there were twooptions for connecting Reactor with TBC Bayas under.

z Connection through Transfer Bus

z Connection through bottom of Pantographisolator of transfer bus

In case of first option, issues would be as under:-

(a) Physical connectivity with Transfer Bus

(b) Bus Reactor will always remain connectedto Transfer Bus.

(c) Transfer Bus will unnecessarily remaincharged when Bus Reactor is in servicethough no bay is transferred on TransferBus.

(d) Additional CT is required for balancingZone-3 current of TBC CT in Bus barprotection when Bus Reactor is in service.As there is no CT core in Reactor in phaseside matching with TBC bay CT core.Hence this option is not considered.

Whereas second option looked more viable asclear demarcation of TBC functionality eitheras Transfer Bus Coupler bay or as Bus Reactorbay can be achieved easily. Accordingly secondoption is considered as shown in Figs.1&2.

Fig. 1: 400 kV Transfer BUS Coupler Bay with 400 kV BUS Reactor

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(ii) Bay Philosophy

With the arrangement finalized as above Bayequipment philosophy is considered as under:-

z Bus Reactor is to be connected to TBC Bay

through Bottom of TBC bay Transfer busPantograph isolator.

z Separate isolator with earth switch is to beprovided for Reactor.

z No separate CTs are to be provided for BusReactor as Reactor Bushing CTs and sparecore of TBC bay CT will suffice therequirement of metering as well asprotection of Reactor bay. (mentioned inprotection philosophy).

(iii) Control Philosophy

z No separate control for Reactor Bay isrequired as it is a part of TBC Bay. TBCBay control philosophy is applicable forReactor also except additional controls ofReactor Isolator & Earth switch.

z Annunciator in existing TBC Control panelis to be retrofitted with higher windowannunciator to include reactor bay troubles/ events.

(iv) Interlocking Philosophy

Main task was to decide and finalize interlockingscheme such that all operational requirementsget fulfilled.

Interlocking philosophy derived is as under:

z Reactor Isolator cannot be closed untilTransfer Bus Isolator is open.

z Transfer Bus Isolator of TBC cannot beclosed until Reactor Isolator is open.

z All bay Transfer Bus Isolator controlscheme (i.e. ladder network) DC supplycannot be extended until Reactor Isolatoris open.

z Circuit Breaker of TBC Bay can also beClosed and Opened when Reactor Isolatoris closed (existing logic is only whenTransfer Bus Isolator is closed).

z TBC bay PT selection scheme is alsorequired to be operated when TBC isworking as Bus Reactor Bay. Accordingly,Reactor Isolator close condition is alsoincluded in parallel to Transfer Bus Isolatorclose condition.

Fig. 2

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(v) Bus bar protection scheme Philosophy

z TBC Bay CT core is routed to Z-3 of RADSSBus bar scheme without CT switching.Hence it is required to be blocked whenTBC bay is working as Reactor Bay to avoidZ-3 operation.

z Accordingly, CT core is blocked throughReactor Isolator contacts (i.e. core shortedwhen Reactor Isolator is closed and routedto Z-3 module only when Reactor Isolatoris open.

(vi) CT Core utilization for Metering andProtection (Fig. 3)

z Metering: Reactor Bushing CT core isutilized (0.5 class, 200/1 Ratio).

z Reactor Differential Protection: TBC Bayspare PS class core and Reactor BushingCT Neutral side core (PS class) are utilized.(500/1 Ratio)

z Reactor Back-up Impedance Protection:Reactor Bushing CT Core is utilized (PSclass 200/1 Ratio).

z Reactor REF Protection:-

Reactor Bus side and Neutral side BushingCT cores (PS class, 200/1 Ratio) areutilized.

z Reactor Bus bar Protection:-

No need of separate CT core as it is not aseparate Bay. TBC bay CT cores routing toZ-1/Z-2 of Bus bar scheme is applicable toBus Reactor in TBC Bay also.

(Reactor Bushing CT cores towards Bus sidehas only 200/1 Ratio hence it can not beutilized for Bus Bar protection)

3. FINALIZATION OF PANELREQUIREMENT

As this is not being a regular Reactor bay, schemedesign is finalized based on philosophy andconsiderations mentioned in previous section andfollowing points are concluded:

z Separate Control Panel for Bus Reactor is notrequired. But, separate metering, Reactor isolatorcontrol, interlocking and Reactor OTI, WTImeasurements are required.

z All Reactor protection and Reactor Troublerelays are required.

z Trip circuit supervision relay, CVT selectionrelays etc. are not required as existing TBC Panelrelays are to be utilized for this.

z Separate energy meter is required for BusReactor as TBC Panel does not have energymeter.

z Modifications in existing TBC Panel are requiredfor interface with Bus Reactor Panel.

Fig. 3

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4. PREPARATION OF OPERATIONPHILOSOPHY

It is necessary to prepare operation philosophy foreasy understanding to operating staff to avoid anymal operation. Accordingly; operation philosophyprepared as under and conveyed to respectivesubstation.

z Bus Reactor is connected to Transfer BusCoupler bay through Transfer Bus Coupler bayPantograph Isolator.

z Bus Reactor has its own Isolator with E/S.

z Remaining equipments of TBC bay shall beutilized for Bus Reactor.

z Separate Reactor protection panel is providedfor Bus Reactor whereas control will be throughTBC Control panel with required interface asper respective substations.

z Scheme will be such that; TBC Bay can eitherbe utilized as TBC Bay or as Bus Reactor Bay.Both functions simultaneously will not bepossible.

z No any other bay should be transferred on TBCwhen is it being utilized as Bus Reactor Bay

z Reactor Isolator can be closed only whenTransfer Bus Isolator of TBC bay and TBCBreaker is in open condition (also Line side E/Sof breaker if provided).

z TBC Bay Transfer Bus Isolator can be closedonly when Reactor Isolator is open.

z Other bays Transfer Bus Isolator supply throughladder network can be extended only when

Reactor isolator is open.

z TBC Panel scheme such as CB Close and Open,CVT selection, LBB Positive extension etc.works only when 89C is closed. Now with BusReactor in TBC all these functionalities are alsobe possible when Reactor Isolator is closed.

z When TBC Bay is to be utilized as Bus Reactorbay; Zone-3 of Bus bar scheme shall be keptOFF along with following modifications

1. In case of RADSS Bus bar scheme; TBC CTcore directly routing to Zone-3 shall berouted through 89CX such that;

z When 89C is closed (i.e. TBC bay isbeing utilized as Transfer bay) CTshould be routed for Zone-3measurement.

z When 89C is open (i.e. TBC Bay isworking as Reactor bay) CT should beshorted through 89CX contacts.

2. For Numerical Bus bar protection scheme;89R status inputs shall be routed to TBCBay unit and logic shall be prepared suchthat Zone-3 measurement shall be blockedwhen Reactor isolator is closed.

z Utilization of CT core for protection & meteringis as under.

Metering:Reactor BCT Phase side CT (200/1 ratio)

Differential Protection:TBC Bay PS class CT core & Reactor Neutral side CTcore (500/1 ratio).

The above requirements are summarized in Table 2.

Table 2

Sl. No. Items considered

1 Relay Panel for Bus reactor (with Energy meter, Indicating meters, WTI, Isolator control switch,necessary auxiliary / multiplication relays for Isolator & Earth switch etc.) including,z Related interface wiring & modification in existing TBC panel with required accessoires

and complete scheme testing.z Supply of 36 Window annunciator and retrofitting of same in existing TBC Panel with

related wiring and accessories.z Modification in Mimic Diagram of existing TBC panel as per revised bay configuration

along with required accessories and wiring.

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REF Protection:-Between Rector BCT (200/1) HV & Neutral side CT

Back-Up impedance protection:-Reactor BCT Phase side CT (200/1 ratio)

5. BENEFITS ACHIEVED

z Saving in bay equipment cost.

z Space optimization in switch yard.

z Space optimization in control room.

z No augmentation of Bus bar protection scheme,as it is achieved with modifications of TBCrelays.

z Reduced quantum of erection andcommissioning work.

z Saving of constructional cost (electrical as wellas civil).

z Reduced cabling as new cables from switchyardto C/R are required to be laid for Reactor andits Isolator only. For remaining schemeinterface, cabling is between TBC panel andReactor panel within Control Room.

6. LIMITATION & RISK FACTORSz Situation may arise when there is need to

Transfer bay on TBC as well as to put Reactorin service. Under such circumstances, either ofthem is to be selected on the basis of priority.

z Scheme requires extra care during testing as wellas O&M.

z Mal-operation of Reactor trouble relay maycause unnecessary tripping of TBC Bay andinterruption to transferred bay.

z When TBC Bay works as Reactor bay, Zonecovered by Bus bar protection is reduced. Anyfault beyond TBC CT is covered by ReactorDifferential Relay instead of Bus bar protection.

(This can be overcome by providing requiredBushing CT in Bus Reactor.)

7. CONCLUSION

Transmission network and substations have growngradually with increase in power demand and thereis hardly any space left over in substation to upgrade/accommodate new bays and support systems likeReactor, SVC, and STATCOM. Utilities have to find

out workable solution through innovative designthinking. GETCO has similar issue of space constraintfor providing Bus Reactors to control Over Voltage.

Out of the seven, four locations were having spaceconstraint. TBC bay was utilized for the new Reactorand whole scheme was commissioned with minimumtime and cost along with redundancy and betterflexibility.

But, there will be certain limitations so this type ofscheme should not be considered as regular scheme.Education and clear operation instructions arenecessary.

BIOGRAPHICAL DETAILS OF THEAUTHORS

N. M. Sheth Deputy Engineer: Obtained Graduationin Electrical Engineering from Saurashtra UniversityRajkot; and Qualification of Certified ProjectManagement Associate (Project Management Level-D, National Ranker) from International ProjectManagement Association (IPMA). Working inGETCO since 1994. Experience in the field ofSubstation Operation & Maintenance as well asCommissioning; Protection scheme design andcommissioning. Presently working in Engineeringdepartment and responsible for Design & Engineeringof Control, Protection, Automation, schemes &Philosophies and Substation secondary engineering.

S. K. Jadav Junior Engineer: Obtained Bachelor inElectrical Engineering from Saurashtra University,Rajkot and Masters in Electrical Power Engineeringfrom Maharaja Sayajirao University, Baroda. Workingin GETCO since 2009 and responsible for Design &Engineering of Control, Protection, Automation,Schemes & Philosophies and Substation secondaryengineering.

B. J. Patel Junior Engineer: Obtained Bachelor inElectrical Engineering from Saurashtra University.Joined Rajashree Polyfil (A division of Century EnkaLtd.) as a Trainee Engineer in year 2004. He alsoserved in Suzlon Infrastructure Ltd, SEZ, Vaododaraup to year 2011 and presently working in GETCOsince 2011. Experience in the field of SubstationOperation & Maintenance as well as Commissioning;and responsible for Design & Engineering of Control,Protection, Automation, Schemes & Philosophies andSubstation secondary engineering.

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SUMMARY

Furanic compound is generic name of chemicalcompounds produced from degradation ofinsulating paper in oil filled transformers. Theseare polar compounds which are, up to certainextend, soluble in transformer oil. Bymeasurement of Fufurals in oil it is considered tobe possible to estimate rate of aging of atransformer. Water, acids and carbon monoxideare also byproducts of paper aging and it has beenestablished that oil deterioration and acidformation also have effect on degree ofpolymerization of insulating paper.

In a laboratory study, of which this paper is basedon, Kraft paper was aged together with copper indifferent dielectric fluids, (including a vegetableester, a hydrocarbon fluid based on predominantlynoncyclic hydrocarbon chains and two differentnaphthenic oils). After conducted ageing watercontent, furfural content, and acid number wasmeasured in both paper and fluids. It wasdiscovered that fluids with high content ofdegradation products in oil not necessarycontained the most amounts of degradationproducts in paper. Hence the distribution offurfural/water/acids between paper and oil isdifferent for different oils.

The estimation on degree of paper degradationbased on paper degradation by products in oil iscomplicated and therefor need more study.

Keywords: Mineral Transformer oil, insulating paperaging, other insulating liquids, Fufural formation

1. INTRODUCTION

It is not an easy decision to choose the insulating

fluid for a transformer since there are manyparameters to take into consideration, such asenvironmental effects, price and function. Price ishandled during the sales process and is not a topicfor this paper. Environmental effects is a verycomplex topic since any comparison of products todetermine prefer ability must assess all the relevantenvironmental impacts across the full product lifecycle, including production, refining, duration of use,emissions from transportation, recycling etc. to makesure that the problem is not simply shifted elsewhere.It is complex and at the same time an important topicthat needs more attention. But the aim here is tocompare mineral oil and ester fluids with respect tofunction inside the transformer, focus will be onessential properties such as oxidation stability, firepoint, DGA and fluid-cellulose interaction.

1.1 Transformer Fluids

The transformer fluid is a vital part of a transformeras it serves several functions such as being a part ofthe electrical insulation, cooling of the windings andcore, and functions as a carrier of information. Thereare different alternatives on the market such asmineral oil, synthetic hydrocarbons, natural/synthetic ester and silicone oils, with varyingproperties. This paper will focus on mineral oil andester fluids.

1.2 Mineral Oil

Mineral oil is the most commonly used insulatingliquid for transformer applications [1]. They consistof hydrocarbons organised in various molecularstructures, generally classified into three main types:paraffins, naphthenes and aromatics (Figure 1).

Mineral oils used for insulating purpose oftencontain high percentages of naphthenic molecules.

Degree of Oil Refining and its Effect onInsulating Paper Degradation

I. Crusell L. Bergeld B. PahlavanpourNynas AB, Sweden

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Generally, an oil with naphthenic characteristicsprovides good low temperature properties, a highsolvent power for polar substances and lowdviscosity index. Mineral transformer oil containsinhibitors which delay the aging of the oil. Theseinhibitors might be natural, as occur in uninhibitedmineral oils, or synthetic and added, as in inhibitedoils.

rather than refined from petroleum base stocks orsynthesized from organic precursors. With a highpercentage of unsaturated acids the viscosity is lower,the oxidation stability on the other hand is sufferingwith a high percentage of unsaturated acids [2].

1.4 International IEC Specifications

Mineral oils have been used for a long time and thishas given rise to many different national andinternational specifications and standards, one of themost common one is IEC 60296 [3]. Today there arealso specifications for both synthetic and naturalesters within IEC, IEC 61099 [4] and IEC 62770 [5]

respectively. There are differences between thesespecifications when it comes to required tests,methods and specified limits. Table 1 shows flashpoint and oxidation stability from thesespecifications, which will be related to in the comingdiscussion.

1.3 Esters

An ester (Figure 2) is either present in the rawmaterial, natural ester, or formed from the reactionof an alcohol and a fatty acid, synthetic ester.

Fig. 1: (a) iso paraffinic, (b) normal paraffinic, (c) naphthenic,(d) aromatic

Esters in general are used in application where firesafety is of primary concern. Both synthetic andnatural esters have a high fire and flash point, seethe specification requirement in Table 1 below.Additionally the synthetic esters show a goodoxidation and thermal stability [1]. Typical structuresof natural and synthetic esters can be seen in Figure3 and Figure 4.

Natural esters differ from mineral oil or other fluidsin that it is an agricultural product derived fromvegetable oils (soybeans, sunflower or rapeseed)

Fig. 2: Molecular structure of an ester

Fig. 3: Molecular structure of a synthetic ester

Fig. 4: Molecular structure of a natural ester

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2. TEST PARAMETERS AND METHODS

2.1 Oxidation Stability

The oxidation stability will indicate the life time ofthe fluid and the obvious target is to have a highoxidation stability meaning a long life time for thefluid. The base of the discussion about oxidationstability will be the different specificationrequirements for each fluid followed by an examplefrom an existing study [6].

2.2 Fire Point

A high fire point and flash point is important from asafety perspective, specifically in certain applicationssuch as indoor areas, mines and ships. There aredifferent requirements in each specification whichwill be highlighted in this paper.

2.3 DGA

Insulating material within electrical equipment breakdown with time and this generate gases within theunit. The distribution of these gases can also berelated to abnormal conditions such as electrical orthermal faults and the rate of gas generation canindicate the severity of the fault. Dissolved gasanalysis can therefore be used as a method toevaluate the condition of mainly the transformer butit can also give indications on the status of theinsulating material.

DGA diagnostics for mineral oils have a long historyand are today well established. When it comes tothe relatively new insulating liquids such as estersmany aspects of the thermal and electrical design oftransformers have to be considered. Additionally thediagnostic and condition monitoring methods,including DGA, have to be adjusted. The DGA resultscan be analyzed using various existing interpretationmethods such as the Duval triangle method and

Rogers. These methods apply to transformers filledwith mineral oil but not directly to equipment filledwith non-mineral oils and adjustments are needed[7]. The aim in this paper is to highlight differences inthe interpretation guides for different fluids, includingmineral oil, synthetic ester, and natural ester, andthe reference here would be the Duval trianglemethod.

2.4 Fluid-cellulose Insulating System

It is well known that moisture content has a largeimpact on the aging rate of the insulation system intransformers. Several significant experimental studieshave been made and show that water is one of themost negative factors affecting the life time of oil-paper insulation. It can reduce the degree ofpolymerization [8] [9] and lower the mechanicalstrength of the cellulose [10]. Earlier studies also showthat an increase of water content in the insulationmay have an impact on the electrical properties ofthe insulation [11].

Cellulose seems to be preserved better in ester liquidscompared to mineral oils. A common theory andprobable explanation to this is that an ester candissolve more water due to a higher polarity andtherefore extract it from the paper and reduce thedegradation thereof. However there is lessinformation available on how the properties of thedielectric fluids are affected when aged together withcellulose and how that will affect the overalltransformer operation. This study both look at theproperties of the paper but mainly the properties ofthe fluid, such as dielectrical dissipation factor (DDF),acid number and water content.

This was an in-house study performed by Nynas withthe following setup. Sealed glass flasks containingcopper, insulating paper with high initial watercontent and a dielectric fluid were aged at 120C in

Table 1: Specifications for different transformer fluids

IEC 60296 IEC 61099 IEC 62770

Flash point C min 135 250 250

Oxidation stability IEC 61125C, 164/ IEC 61125C, 164h IEC 61125C, 48h332 or 500h

Total acidity, mg KOH/g max 1.2 /0.3 0.3 0.6

Sludge, wt% max 0.8 /0.05 0.01 -

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a heating oven for 17 weeks. The study wasperformed using cellulose of a high initial watercontent to accelerate the aging. Changes in differentproperties of the liquid were observed for the periodof aging. The effects on DDF, acid number, coppercontent, and water content of the fluid were measuredduring the experiment. Also the acidity and watercontent of the paper were monitored during thestudy. The dielectric fluids used during theexperiment were a natural ester and an uninhibitedmineral oil complying with IEC 60296 [3].

3. RESULTS AND DISCUSSION

3.1 Oxidation Stability

As can be seen in Table 1 the specifications for therespective fluid have different limits for oxidationstability. For mineral oils you have differentrequirements depending on the quality of the fluid.Synthetic esters need to fulfill the lowest requirementfor mineral oil, but it is commonly known that thesefluids perform well when it comes to oxidationstability. The test set up for natural esters are thesame as for the mineral oil and the synthetic esterbut the test duration is 48 hours, to be comparedwith 164 hours which would be the lowestrequirement for the others. Due to these differencesit is difficult to compare the different fluids on aspecification level. But the duration of 48 hourssuggests that the oxidation stability for natural estersmight not be as good as for the other alternatives.

One example is the study 6 as can be seen in Figure5. Both the mineral oil and the synthetic ester showgood oxidation stability according to IEC 61125C(164 hours) which is the test indicated in thespecifications [3, 4, 5]. Three different natural esters

have here been evaluated and as the figure showthere is a big variation among the samples. But asexpected, and what will also be showed in the comingstudy, natural esters have a much weaker oxidationstability compared to mineral oil and synthetic esters.

3.2 Fire Point

As mentioned a high fire point is important from asafety point of view. Ester fluids are often preferredwhen looking at specific applications where thesafety is critical. The limits of flash point stated ineach specification can be seen in Figure 6. Asindicated the requirements for ester fluids is morestringent compared with the one for mineral oils.The high fire and flash point would be one of themain benefits with the ester fluids. How relevant250C is when it comes to a sever fault in atransformer could be a topic for another paper.

Fig. 5: Oxidation for 5 insulating fluids

3.3 DGA

Depending on what insulating material that is usedthere will be differences in the gas formation andrelation to a certain fault and the interpretation ofthe DGA results need to take this into consideration.The method to evaluate gas formation in mineral oilis well established and it has recently been studiedif new interpretation methods are needed for esterfluids or if existing methods can be slightly adjustedto serve the purpose. This study [7] is comparing 4fluids: 1 mineral oil, 1 synthetic ester and 2 naturalesters. A comparison of differences in gas formationbetween the 3 non-mineral oil fluids with the mineraloil have been used to adjust the zones in the Duvaltriangle leading to one triangle per fluid as can beseen in Figure 7.

Fig. 6: Flash point

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When comparing these triangles there are differencesmainly in the boundaries for the zones D1/D2, T1/T2, and T2/T3. It can also be seen that different typesof natural esters have different gas formationpatterns. A variation in chemical structure of thesefluids would be a possible explanation for the gasformation behavior 7.

The awareness of these differences is important tobe able to make correct actions from a DGAmeasurement. It is also important to have in mind ifand when there is a need to top up an ester filledtransformer with new ester. If the esters are not fromsame origin there might be a change in the Duvaltriangle that needs to be considered.

These triangles have been created based on testssimulated in a laboratory and they might have to bemodified when actual cases occur [7].

3.4 Fluid-cellulose Insulating System

To verify the test setup blank samples without paperand copper was first evaluated. As expected the initialwater content of the natural ester was higher (about10 times) than that in mineral oil. That is becausethe water saturation of the ester is higher than thatof mineral oil. It can also take in water in chemicallybounded form while in mineral oil water is onlydissolved [12]. The water content of the natural esterdecreased during the time of the experiment whereas

for the mineral oil the water content slowly increased.The decrease of water in the natural ester is thoughtto be due to hydrolysis of the ester to thecorresponding acid, which is a reaction consumingwater. It was also expected to see that the acidityand DDF increased more for the natural estercompared to the mineral oil due to the differentoxidation stability behaviours.

In the paper-fluid-copper system, the water contentof the fluids was observed to increase during thefirst week followed by a decrease to finally level offin a low water content in both fluid (Figure 8a) andpaper (Figure 8b). This initial increase is probablydue to a shift of water from paper to the fluid for thesystem to reach equilibrium.

Fig. 7: Duval triangle for transformer filled with a) mineral oil(Duval triangle 1), (b) synthetic ester (Duval triangle 3), (c)

natural ester (Duval triangle 3), (d) natural ester (Duval triangle 3)

The decreasing water content could be an indicationof that water is used in the mechanism of paperdegradation and then mainly hydrolysis by cleavageof the inter-unit linkages. The acidity of the paper,in the case with natural ester, was lower than for themineral oil, this could indicate that the decrease ofwater in the ester-fluid system could be an effect ofthe consumption of water through hydrolysis of theester rather than the cellulose.

Fig. 8: (a) water in fluid over 17 weeks, (b) water in paperover 17 weeks

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In Figure 9 it can be seen that the natural ester yieldshigh number of total acids when aged compared tothe mineral oil that show a more modest change.The acidity of the fluids corresponds well withinsulation fluids expected stability towardsoxidation. The fluids were in this study aged in aclosed environment with a low oxygen content,giving different test conditions compared to the IECoxidation stability test (IEC 61125C) where there isa full access of oxygen. This indicates that thedegradation of esters is highly dependent on bothoxygen and water content present in the system. Oneexplanation to the higher acidity for the natural estercould be a hydrolysis reaction of the natural esterresulting in increased number of acids. The acidsformed in the natural ester via hydrolysis are of highmolecular weight. In comparison to low molecularweight acids, acids of high molecular weight are notthought to have any significant effect on the acidcatalysed degradation of paper [11,13]. This studyindicates that there is no correlation between theacid numbers in the fluid compared with the acidnumber in paper. Hence a high acid number in thefluid will not necessary be equivalent a high acidnumber within the paper.

copper content, since a high copper content wouldaffect the insulating properties. Both un-aged samplesand samples of fluids aged for 17 weeks were sentto an external laboratory. The results are reported inTable 2 below.

Table 2: Specifications for differenttransformer fluids

Initial copper Copper contentcontent in in fluid after

fluid (ppm) 17 weeks (ppm)

Natural Ester,

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results it is important to be aware of the differentgas formation patterns among the fluids. Today manyof the interpretation guides are based on mineral oilbut there are guides for non-mineral oil fluids as wellwhich should be used when appropriate. Care shouldbe taken when mixing different natural ester productssince this can affect the interpretation.

The conclusion of the study of the fluid/paperinsulating system when focusing on the propertiesof the fluids are that ester fluids degraded much fasterwhen evaluating DDF and acid number and the releaseof copper into the fluid seems to be higher; affectingthe dielectrical properties. It has earlier been shownthat the paper is preserved when ester is being usedas insulating fluid but it seems to be at the expenseof a very fast degradation of the ester.

BIBLIOGRAPHY

1. CIGRE working group A2.35, (2010) CIGRE 436,experiences in service with new insulating liquids

2. American Society for Testing and Materials,ASTM D6871-03 (2008), StandardSpecification for Natural (Vegetable Oil) EsterFluids Used in Electrical Apparatus.

3. International Electrotechnical Commission, IEC60296 ed 4 (2012), Fluids for electrotechnicalapplications - Unused mineral insulating oils fortransformers and switchgear.

4. International Electrotechnical Commission, IEC61099 ed 2 (2010), Insulating liquids -Specifications for unused synthetic organic estersfor electrical purposes.

5. International Electrotechnical Commission, IEC62770 (2013), Fluids for electrotechnicalapplications- unused natural esters fortransformers and similar electrical equipment.

6. A. Darwin, C. Perrier, P. Folliot, The use of naturalester fluids in transformers, MatPost 07

7. Duval M., The Duval Triangle for Load TapChangers, Non-Mineral Oils and LowTemperature Faults in Transformers, IEEEElectrical Insulation Magazine, Vol. 24 Issue 6pp. 22-29, Nov.-Dec. 2008

8. Hohlein, I. Kachler, A.J., Influence of moistureand temperature on degree of polymerizationand formation of furanic compounds in free-breathing systems, Electrical InsulationMagazine, IEEE 2005, 21 (5), 20-24

9. Junru Xiang, Jian Li*, Zhaotao Zhang, Influenceof Water Content on the Aging Performance ofNatural Ester-paper Insulation, State KeyLaboratory of Power Transmission Equipment& System Security and New Technology,Chongqing University, Chongqing, China

10. Lars E. Lundgaard, Walter Hansen, DagLinhjell, and Terence J. Painter, Aging of Oil-Impregnated Paper in Power Transformers,. IEEETransactions on Power delivery 2008, 15, (2),540-546

11. Lundgaard, L. E.; Hansen, W.; Ingebrigtsen,S.,Aging of mineral oil impregnated cellulose byacid catalysis, IEEE Transactions on Dielectricsand Electrical Insulation 2004, 19, (2), 230-239

12. A. Kalantar*,t and M. Levin, Factors affectingthe dissolution of copper in transformer oils,Lubrication Science 2008; 20: 223-240

13. Ruijin Liao, Shuaiwei Liang, Caixin SUN, LijunYang, Huigang Sun, European transactions onelectrical power 2010; 20:518-533, Acompeditive study of thermal aging oftransformer insulation paper impregnated innatural ester and in mineral oil

14. International Electrotechnical Commission, IEC60422 ed 4 (2013), Mineral insulating oils inelectrical equipment - Supervision andmaintenance guidance

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Dale Finney Mangapathirao V. Mynam Marcos Donolo Amy SinclairSchweitzer Engineering Laboratories, Inc.

Design of a Centralized Substation Synchronizing System

ABSTRACT

Large substations often have complex and dynamictopologies. The voltage available on either sideof an open breaker may originate from a numberof sources. This has led to the development ofcentralized systems to carry out synchronism-check functions to synchronize all breakers withinthe substation. Such a system uses the status ofbreakers and disconnects to identify a voltagesource for each side of the breaker that is to besynchronized. Custom logic is required toaccommodate the topology of a particularsubstation. In the past, these systems have beenrealized using custom hardware or programmablelogic controllers (PLCs) and significant amountsof wiring. This paper describes in detail asynchrophasor-based approach that provides asignificant reduction in the effort and cost requiredto design, build, and test a centralizedsynchronizing system. Phasor measurement andcontrol units (PMCUs) transmit voltage phasorsand breaker and disconnect status to a centralcontroller. The central controller time-aligns thedata and selects the correct voltages to use forsynchronizing according to the present status ofthe breakers and disconnects. Once theappropriate checks of the voltages are made, aclose command is sent from the central controllerto the PMCU responsible for the breaker that isto be closed. A primary objective is to reduce therequirement for custom logic as much as possible.The design relies heavily on using the programorganizational units (POUs) described in IEC61131. These can be developed, tested, write-protected by passwords, and easily reused insubsequent projects.

The synchrophasor-based approach proposed inthis paper is also applicable when synchronizingtwo power sources. This usually entails controlling

voltage magnitude and frequency in one island,whereas synchronism check does not carry outvoltage or frequency control. The schemedescribed in this paper is applicable tosynchronism check and can be extended to supportsynchronizing two islands.

1. INTRODUCTION

This paper describes the implementation of acentralized synchronizing scheme for substationswith complex topologies. Substation configurationsexist that present challenges for synchronizing. Onesuch configuration is shown in Fig. 1. Assume thatBreaker 2 is to be closed. A synchronizing voltagesource for the top of Breaker 2 is provided byPotential Transformer A (PT A) when Breaker 1 isclosed and by PT B if Disconnect 4 is closed. A similarsituation exists for sources on the bottom of Breaker2. A distributed scheme can be implemented with adedicated synchronism-check device for eachbreaker. In this case, each device needs to select thevoltage source from four sources based on breaker

Fig. 1: Substation Showing Available Synchronizing Sources

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and disconnect status. The logic for the voltageselection is unique for each breaker.

Complexity can be reduced by adding or relocatingPTs. For instance, in Fig. 1, if PT B and PT C weremoved to the left-hand sides of Disconnect 4 andDisconnect 5, respectively, then the need for voltageselection logic would be eliminated. However, it isnot always practical to place PTs in the optimumlocation for synchronizing. For instance, placing aPT on a gas-insulated switchgear (GIS) bus is likelyto be more expensive than placing it at the lineterminal air-to-gas bushing.

It is possible to implement a distributed schemewherein an intelligent electronic device (IED) isdedicated to synchronizing each breaker. Each IEDwould either have to measure voltages from allrequired PTs (often not possible) or switch PTsexternally. The wiring and logic associated with eachdistributed scheme when taken as a whole wouldlikely be more complex than a centralized scheme.

2. CONVENTIONAL CENTRALIZEDSYNCHRONIZING SCHEME

Centralized schemes have been implemented toaddress the issue described previously. Conventionalimplementations are composed of two main modules,as shown in Fig. 2.

could also be implemented using an off-the-shelfprogrammable logic controller (PLC) and asynchronism-check relay.

The advantage of a centralized scheme is that itconcentrates the hardware and associated logicfunctionality in one location. A disadvantage is thesignificant amount of wiring required to bring all ofthe voltage and status signals to a central location.In implementations where a supervisory control anddata acquisition (SCADA) control to close the breakeris provided by a central remote terminal unit (RTU),the synchronizing scheme could be located in thesame cabinet. Because the RTU usually requires thesame signals as the synchronizing scheme, this allowssignals to be shared.

Another disadvantage of the centralized scheme isthat a single point of failure impacts thesynchronizing capability of the entire substation.

3. SYNCHROPHASOR-BASED CONTROL

Time-synchronized phasor measurements, alsoknown as synchrophasors [1], have been widely usedfor visualization and postmortem applications suchas power system model validation [2] [3]. Phasormeasurement and control units (PMCUs) provide thesynchronized measurements. These time-synchronized measurements, complemented withthe advent of synchrophasor-based controllers(SBCs), allow users to implement closed-loopsynchrophasor-based control schemes.

Closed-loop control schemes using synchrophasorshave been applied in the power system. Some of theimplementations in service today are the following:

z Islanding detection in distributed generation(DG) applications uses phase anglemeasurements at the DG location and the pointof common coupling and calculates the rate ofchange of angle difference (slip) and the rate ofchange of slip [4].

z Remedial action scheme based on low-frequencyoscillations uses the power measurements fromtwo intertie transmission lines and measures thelow-frequency oscillations. The scheme sendsa command to disconnect the intertieconnection when the oscillations are associatedwith negative damping [5].

Fig. 2: Block Diagram of Centralized Synchronizing Scheme

The logic module performs voltage selection.Depending on the breaker to be closed, the logicmodule selects two voltage measurements (Voltage1 and Voltage 2) and passes them to thesynchronism-check module. The synchronism-checkmodule sends a SynchOK signal back to the logicmodule if the conditions for synchronism check aremet. The logic module then routes a close permissionto the particular breaker to be closed.

In present implementations, both modules have beenimplemented using custom hardware. The scheme

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SBCs mainly provide the following functions: timealignment (TA), built-in logic functions, and user-programmable logic functions.

A. Time Alignment

Time alignment is a key function in the design ofsynchrophasor data concentrators and controllers.It allows for communications latencies between thephasor measurement units (PMUs) and the controlleror data concentrator. The measurements are time-tagged with a common time reference (typicallyGlobal Positioning System [GPS]). The TA functionopens a time window (message wait time) where itexpects all the measurements with the same timetag to arrive, independent of their location. Someimplementations force the device measurements thatarrive outside the message wait time to zero and flag

these measurements to represent bad quality. Thiswait time is typically configurable and should be setbased on the communications latencies andapplications. For example, a smaller message waittime is applicable for closed-loop controlapplications, whereas for postmortem or dataarchiving applications, a longer message wait timemay be acceptable.

B. Built-in Logic FunctionsSpecifically for SBCs, the capability to performcalculations or mathematical operations on the time-aligned phasor measurements is critical. Additionally,more advanced built-in functions are made availablein some controllers, and some of these functionsinclude the following:

z Three-phase real and reactive power

Fig. 4: Synchrophasor-based Centralized Synchronizing System

Fig. 3: Processing Latencies

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z Phase angle difference

z Modal analysis

z Substation state and topology processor (SSTP),as described in Subsection B of Section IV

Processing the available logic functions atdeterministic low computation times is another keyrequirement for SBCs, as it is for any controller.Today, SBCs are available that can achievecomputation times in the order of 4 milliseconds.The low processing time of the controllers allowsthe implementation of closed-loop synchrophasor-based control schemes that require strict responsetimes (in the order of 100 milliseconds). Based onthe output of the control schemes, SBCs are capableof sending a control command to the appropriatedevice to take a control action. In someimplementations, the PMCUs provide synchrophasormeasurements and are capable of receiving thecontrol commands from the SBCs and takingappropriate action. Figure 3 shows the potentiallatencies that are involved in a synchrophasor-basedcontrol scheme. Users must compare these latencieswith the timing requirements of the application forany critical control scheme using synchrophasors.

C. User-Programmable Logic Functions

Some of the SBCs available today provide users withIEC 61131-3-compatible support for multipleprogramming languages [6]. These languages includethe following:

z Structured text (ST)

z Function block diagram (FBD)

z Ladder diagram (LD)

z Continuous function chart (CFC)

z Instruction list (IL)

The standard provides the syntax and semantics forthe programming languages. Depending on userfamiliarity with a particular language and thecomplexity of the program, users can choose aparticular programming language.

4. CENTRALIZED SYNCHRONIZINGSYSTEM USING SYNCHROPHASORS

The system shown in Fig. 4 consists of PMCUs, anEthernet network, and a central SBC. The SBC

consists of two functions that are built-in features(time alignment and an SSTP) and several programorganizational units (POUs) that have beenconstructed using IEC 61131 programminglanguages.

PMCUs located in each bay are responsible formeasuring the voltage and frequency andtransmitting synchrophasors to the SBC. Note thatin Fig. 4, each voltage source has a dedicated PMCU.Connecting multiple voltage sources to the samePMCU requires a PMCU that can measure multiplefrequencies. PMCUs are also responsible for sendingbreaker and disconnect status and receiving closecommands.

Using the time alignment of the data from multiplePMCUs, the SSTP module constructs the topologyof the substation based on the user configurationand the existing state of the breakers anddisconnects.

When a user chooses a particular breaker to beclosed, the voltage selection block selects incomingand running voltages for synchronization using thepresent topology. One key advantage of this systemis the capability to select the best available voltagemeasurements based on the topology of the systemas determined by the SSTP to run the synchronizinglogic. The synchronism-check module checks thatthe incoming and running sources are in phase andthat the magnitudes and frequencies of the twosources are within limits (typically close to nominal).The scheme then generates the close command,which is routed to the breaker that is to be closed.

The SBC can receive synchrophasor data at up to 60messages per second. The SBC can process logic atrates of up to 240 Hz or four times per cycle at 60Hz. In a synchronizing application, for a maximumslip of 0.067 Hz, as specified by IEEE C50.12 andIEEE C50.13 [7] [8], a 240 Hz processing rate equatesto a shift of 0.1 degree per logic scan. Thus, 100milliseconds of latency represents 24 logic scans at0.1 degrees of travel per scan, which is 2.4 degreesof error in the actual angle difference. In applicationswhere synchronizing is carried out at a much higherslip rate, the additional latencies introduced by thisscheme could hinder performance [9].

The example substation shown in Fig. 5 is used todescribe the new scheme. In this substation, PTs are

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located only at the line terminals. Each line terminalcan be connected to either bus. Buses can besectionalized using disconnect switches.

The controller logic is subdivided into severalmodules, which are described in the followingsubsections.

A. Time Alignment

Time alignment is described in detail in Section III.It is carried out automatically and ensures that alldownstream operations are made using time-coherent measurements.

B. Substation State and Topology Processor

The SSTP gathers time-aligned synchrophasor dataalong with the status of breakers and disconnectswitches from PMUs and PMCUs for substation stateand topology assessment. The SSTP uses these datato identify measurement errors and improvemeasurement accuracy.

(1) SSTP Structure

The SSTP module is organized into three mainprocessors (Fig. 6): the topology processor (TP); the

current processor (CP), which is not used for thisapplication; and the voltage processor (VP). Thetopology processor processes breaker and disconnectswitch status to obtain the substation topology andthen makes this information available to the currentand voltage processors. The current and voltageprocessors use the substation topology and thesynchrophasor data to detect measurement errorsand refine the current and voltage measurements inreal time.

Referring to Fig. 5, assume we are trying tosynchronize Node N4 to the rest of the substationthrough Breaker B3. The incoming voltage ismeasured by the PT at Node N4, and for the runningvoltage, the SSTP takes the median of the voltagesmeasured at Nodes N6, N10, and N12. If one of thevoltage measurements is bad (e.g., the PT fuse hasfailed), the median discards the bad measurement,making the synchronizer more robust than whenusing traditional methods. Note that averaging thetwo good voltage measurements with a badmeasurement will not produce a quantity suitablefor synchronization.

The topology processor uses branch statusinformation to provide topology information for thecurrent processor (not used in this application) andthe voltage processor. The topology processordetermines the current topology and the voltagetopology by merging busbar nodes to create nodegroups according to the closed status of the branchesin the busbar arrangement. To create the currenttopology, the topology processor merges nodes whenthe nonmetered branches are closed or when thebranch close status quality of the nonmetered branchis false. To create the voltage topology, the topologyprocessor merges nodes when branches are closed.

Fig. 5: Example Substation

Fig. 6: SSTP Includes Topology, Current, and Voltage Processorsto Refine Measurements and Identify Measurement Errors

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The current processor uses the current topology forcurrent measurement checks and refinement. Thevoltage processor uses the voltage topology forvoltage measurement checks and refinement.

(2) Node Merging Process Example

As stated previously, the topology processor usesbranch status to merge nodes. This allows nodevoltages to be combined. To illustrate the nodemerging process, consider Fig. 5. The busarrangement has 14 nodes numbered N1 to N14 and17 branches numbered B1 to B17 in Fig. 5. Thereare five metered branches (B3, B6, B9, B14, and B17).Only Nodes N4, N6, N10, and N12 include voltagemeasurements. The topology processor considers allbranches as merging branches to create the voltagenode groups. Table I shows the branch-to-node dataarray for the voltage processor when all branchesare open. The array shows the From and To nodeidentification for each branch.

After a branch closes, the topology processorreplaces all instances of the To node ID with the Fromnode ID in the branch-to-node data array. Forexample, Table II shows the new array after Branch2 merges Node 2 and Node 3. In this case, the Tonode ID is 3 and the From node ID is 2, as shown inTable I. In Fig. 5, Branch 2 is connected from N2 toN3. Thus, when Branch 2 closes, all entries that werea 3 in Table I become a 2 in Table II (highlighted inyellow).

When this topology is passed to the voltage processor,it combines the voltage measurements available atboth Node 2 and Node 3. No other voltagemeasurements are combined.

Without the SSTP, custom logic would be requiredto determine the voltages on either side of a breaker.For example, the pseudo code in Fig. 7 presents thelogic required to determine the voltage at N3 in Fig.5 (the running voltage needed to synchronize B3).

Table 1: Branch-to-Node Data Array for the Topology Processor when all Branches are Open

Table 2: Branch-to-Node Data Array for the Voltage Processor when all Branche 2 Merges Node 2and Node 3

Fig. 7: Custom Logic Required for N3 if the SSTP Is Not Used

Unique logic would be required for each of thebreakers, and this logic would be specific to theparticular substation.

The SSTP logic can also be used as a front end to aload-shedding logic application, where a particularload can be automatically selected to be shed basedon the dynamically changing topology.

C. Arming Logic

Referring once again to Fig. 4, the arming logicprocesses close requests. The logic, shown in Fig. 8,is responsible for opening a window for synchronizingand for rejecting close requests if synchronizing isin progress on another breaker.

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Fig. 8: Arming Logic

Fig. 9: Voltage Selection Logic

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The arming logic resets after a fixed delay (30 secondsin this example). In a practical implementation, thislogic may also be subject to site-specificrequirements regarding situations such as failed closeattempts or station-wide interlocks.

For our example substation, a PMCU is dedicated toeach breaker in Fig. 5. The output of the logic,CB_TO_CLOSE, is a number ranging from 0 to 5 thatindicates the breaker to be closed.

In this example, close requests originate from thePMCU associated with a particular breaker but couldalso originate from another source such as an RTUor local human-machine interface (HMI).

D. Voltage Selection Logic

The voltage selection logic chooses the incoming andrunning voltages for the particular breaker to be

closed. This logic is shown in Fig. 9. The IEC 61131ST programming language is chosen for this modulebecause it is more appropriate for this application.Note that this logic is very simple because it isreceiving the node voltages from the SSTP. The nodeson either side of a breaker are always the same. Forexample, if Breaker B3 is to be closed(CB_TO_CLOSE=1), then the node for the incomingvoltage (NI) is N4 and the node for the runningvoltage (NR) is N3. N4 has a physically connectedvoltage source. On the other hand, N3 does not havea physically connected voltage source but derivesits voltage through the process of node merging.

E. Synchronism-Check Logic

The synchronism-check logic shown in Fig. 10receives the incoming and running voltages andchecks that the difference in angle, magnitude, and

Fig. 10: Synchronism-Check Logic

Fig. 11: Time-Advanced Closing Logic

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frequency is within limits. The first input to the ANDgate asserts when the absolute angle between theincoming and running voltages is less than a pickupthreshold (10 degrees in this example). The remainingthree inputs to the AND gate assert when themagnitudes and slip of the incoming and runningvoltages are within a set band. If the limits aresatisfied, the logic gives permission (SynchOK) tothe close command logic. In Fig. 10, an additionallogic function (INBAND) has been developed tofurther streamline the logic.

The closing logic is shown in Fig. 11. This logicincludes a feature to provide a time-advanced closecommand based on angle difference and slipfrequency and the circuit breaker close time. First,slip is calculated by subtracting the incoming andrunning frequencies. The advance angle is equal toslip 360 CBCT (circuit breaker close time inseconds). This angle is compared with the actualangle between the two sources (DeltaAng). Thecomparison is less than or greater than, dependingon whether the slip is positive or negative.Accounting for circuit breaker close time ensures thatangle difference is minimized at the instant thebreaker primary contacts close.

Although intended to address circuit breaker delays,this feature could also be used to accommodate othersources of delay.

F. Breaker Selection Logic

The breaker selection logic routes the close commandto a particular breaker, as shown in Fig. 12.

As mentioned at the beginning of this paper, thescheme is applicable both to synchronism check andsynchronizing. In a synchronizing scheme, similarselection logic would also route raise/lowercommands (not shown) to particular generatorcontrols in the same manner. A PMCU would belocated at the generator controls in this case totranslate raise/lower commands to electrical contactclosures.

5. ADVANTAGES

The proposed scheme has significant advantages overthe conventional scheme described in Section II. Allsignals are exchanged over the substation local-areanetwork (LAN), so most hard-wired connectionsdisappear. Today, many modern protective relayssupport synchrophasors and are wired to all of the

Fig. 12: Close Selection Logic

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voltage sources throughout the substation. Thesesame relays are also often wired with breaker andswitch status throughout the substation. Thus, insubstations where relays supporting synchrophasorsare applied, the need for additional hardware andwiring is minimal. A redundant LAN architecturecoupled to redundant central controllers removessingle points of failure. The proposed scheme canmore easily be applied than a hard-wired scheme inlocations where voltage sources and breakers areseparated by long distances, such as the case of agenerator power house that connects to the gridthrough a remote switchyard.

The proposed scheme can be designed for easymodification and maintenance. The scheme logic canbe initially designed taking into consideration theultimate size of the substation. The logic intendedfor future devices would initially be unassigned. Ifthe substation were subsequently extended toinclude a new circuit and associated breakers, thena PMCU could be added to include new voltage andstatus signals. These new signals would be routed tothe SBC and assigned to unused logic inputs. Changeswould be required for the SSTP; however,configuration of this module is more akin to settinga protection function than to developing logic. Mostlogic modules would require no modification. Thesemodules can be locked against editing after initialdesign and testing.

The features described in this paper also make thisscheme easily adaptable to a different substation witha different topology. Most of the effort is restrictedto configuration of the SSTP.

The SSTP also improves the quality of the voltagemeasurements. When several voltage sources areconnected to a node, the SSTP calculates the nodevoltage as the median of the available measurements.

6. CONCLUSION

The scheme described in this paper performed asexpected during bench testing, showing that it is aviable alternative to existing centralized approaches.

This paper demonstrates that the inherent time-stamping provided by synchrophasor measurementsallows them to be effectively applied for criticalcontrol functions in the power system.

The approach makes extensive use of IEC 61131

programming features. This results in simpler, moremodular code.

In a conventional application, considerable effortwould be required to develop the voltage selectionlogic for each breaker. This logic would be uniquefor each breaker. If the scheme was reapplied to adifferent substation, then this logic would have tobe rewritten. This paper shows how the SSTP can beused to replace custom logic. Configuration of theSSTP amounts to defining nodes and branchesarguably a much simpler process with less potentialfor error. This results in applications that are moregeneric and thus more easily adaptable.

This effort represents a further step in the transitionto substation automation designs that leverageadvanced IEDs and communication to reduce costand complexity.

REFERENCES

1. A. Guzmn, S. Samineni, and M. Bryson,Protective Relay Synchrophasor MeasurementsDuring Fault Conditions, proceedings of the32nd Annual Western Protective RelayConference, Spokane, WA, October 2005.

2. E. O. Schweitzer, III, D. Whitehead, A. Guzmn,Y. Gong, and M. Donolo, Advanced Real-TimeSynchrophasor Applications, proceedings of the35th Annual Western Protective RelayConference, Spokane, WA, October 2008.

3. IEEE Power System Relaying Committee,Working Group C-14, Use of SynchrophasorMeasurements in Protective RelayingApplications, 2013. Available: http://www.pes-psrc.org/.

4. J. Mulhausen, J. Schaefer, M. Mynam, A.Guzmn, and M. Donolo, Anti-Islanding Today,Successful Islanding in the Future, proceedingsof the 63rd Annual Conference for ProtectiveRelay Engineers, College Station, TX, March2010.

5. J. V. Espinoza, A. Guzmn, F. Calero, M. Mynam,and E. Palma, Wide-Area Measurement andControl Scheme Maintains Central AmericasPower System Stability, proceedings of thePower and Energy Automation Conference,Spokane, WA, March 2013.

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6. IEC 61131-1, Programmable Controllers Part3: Programming Languages.

7. IEEE Standard C50.12-2005, IEEE Standard forSalient-Pole 50 Hz and 60 Hz SynchronousGenerators and Generator/Motors for HydraulicTurbine Applications Rated 5 MVA and Above.

8. IEEE Standard C50.13-2005, IEEE Standard forCylindrical-Rotor 50 Hz and 60 Hz SynchronousGenerators Rated 10 MVA and Above.

9. M. J. Thompson, Fundamentals andAdvancements in Generator SynchronizingSystems, proceedings of the 38th AnnualWestern Protective Relay Conference, Spokane,WA, October 2011.

BIOGRAPHICAL DETAILS OF THEAUTHORS

Dale Finney received his BSEE from LakeheadUniversity and his MSEE from the University ofToronto. He began his career with Ontario Hydro,where he worked as a protection and control engineer.Currently, Mr. Finney is employed as a senior powerengineer with Schweitzer Engineering Laboratories,Inc. His areas of interest include generator protection,line protection, and substation automation. Mr.Finney holds several patents and has authored morethan 20 papers in the area of power systemprotection. He is a member of the main committeeof the IEEE PSRC, a member of the rotatingmachinery subcommittee, and a registeredprofessional engineer in the province of Ontario.

Mangapathirao (Venkat) Mynam received his MSEEfrom the University of Idaho in 2003 and his BE inelectrical and electronics engineering from AndhraUniversity College of Engineering, India, in 2000.He joined Schweitzer Engineering Laboratories, Inc.(SEL) in 2003 as an associate protection engineer inthe engineering services division. He is presentlyworking as a senior research engineer in SEL researchand development. He was selected to participate inthe U.S. National Academy of Engineering (NAE)15th Annual U.S. Frontiers of EngineeringSymposium. He is a senior member of IEEE.

Marcos Donolo received his BSEE from UniversidadNacional de Ro Cuarto, Argentina, in 2000 and hisMSEE (2002), his master of mathematics degree(2005), and his Ph.D. in electrical engineering (2006)from the Virginia Polytechnic Institute and StateUniversity. Since 2006, he has been with SchweitzerEngineering Laboratories, Inc., where he is presently alead research engineer. He is a senior member of IEEE.

Amy Sinclair received her BSEE degree from QueensUniversity, Kingston, in 1989. She joined OntarioHydro in 1989, working for ten years as a protectionand control engineer in the areas of design,operations, and project management. In 2000, shejoined ELECSAR Engineering as a project managerwith a focus on protective relaying and substationdesign. Since December 2006, she has beenemployed with Schweitzer Engineering Laboratories,Inc. as a field application engineer located inChatham, Ontario. She has been registered as aProfessional Engineer of Ontario since 2001.

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Redundancy in Digital SubstationsD.L.P. Jenkins S. Richards S. Vigouroux E. Avinash

Alstom Grid Alstom Grid Alstom T&DUnited Kingdom France India

SUMMARY

The introduction of the process bus and stationbus to modern digital substations has raised manyquestions and concerns. Protection Engineers areresponsible for ensuring that protection andautomation systems have an adequate level ofredundancy to be considered suitable for criticalpower system applications.

Many new methods and technologies are nowavailable that offer the means of providing thisredundancy; however the temptation to introducemany of these at once could lead to a design thatis unnecessarily complex, difficult to test andunreliable in practice as a result.

For example it is now possible to design a processbus architecture whereby protection relayssubscribe to multiple sampled value streams fromredundant merging units. However the questionof whether this is actually necessary is a validone. In a conventional substation such a designphilosophy would equate to protection relaysbeing wired to multiple redundant instrumenttransformers, which is not common practice norindeed desirable.

This paper will review the contemporaryprotection engineering principles that have beenused for many decades to engineer redundantsystems and then seek to establish how these sametechniques can be applied to new digitalsubstation architectures.

Methods and technologies that will be reviewedinclude:

z Network redundancy protocols such as IEC62439 Parallel Redundancy Protocol (PRP)and High-availability Seamless Redundancy(HSR).

z The architecture of the process bus, stationbus and time synchronisation network. Forexample how merging units are connected toIntelligent Electronic Devices (IEDs) and howconnections are made between substationbays to share sampled values and GOOSEmessages.

z Where protection and automation functionsare distributed across the IEDs, merging unitsand other devices in the substation.

The objective of this review is not to propose anideal or target architecture, since the design ofsuitable solutions depends on the application inquestion. Instead, it will seek to identify how thesemethods need to be considered and what trade-offs exist from their use.

Keywords: IEC 61850, Station Bus, Process Bus,Merging Unit, IEC 62439, Time Synchronisation

1. INTRODUCTION HOW HAVE WEPREVIOUSLY ACHIEVEDREDUNDANCY?

The principle of redundancy is a long establishedrequirement for substation protection systems inorder to achieve reliable power systems.

A definition in the context of protection andautomation is the provision of sufficient duplicatecomponents so there is at least two independentprotection functions, each of which is sufficientlycapable of carrying out the required function on theirown. We often refer to these two systems as Main1 and Main 2 (see Figure 1) [1].

This architecture is provided because 100% perfectreliability of any single device is not possible toachieve in the real world, therefore to improvereliability of the complete systems to an acceptable

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level, we design so that the failure of a componentdoes not disable the overall protection system.

Although redundancy and backup are often confusedas the same thing, they are actually two distinctlydifferent properties; a redundant system will providea duplicate function that is of equal performance tothe primary, whereas a back-up system may stillprovide protection but be of inferior performance.One example of a redundant protection systemwould be a Main 1 distance pilot scheme with a Main2 stepped distance scheme. A back-up to Main 1could be simple overcurrent protection, which doesnot provide the same level of sensitivity or speed asa redundant Main 2 system [2].

Some designs in a conventional protection systemthat will achieve this redundancy would include:

z Duplicated circuit breaker trip coils

z Duplicated DC power supplies for IEDs andtripping circuits

z Separate current transformers, or duplicatedsecondary cores

z Minimising potential for common mode failurebetween Main 1 and Main 2 systems, such asmaintaining physical isolation, and by usingdifferent operating principles (this ensures thatthe two systems are truly independent to oneanother)

As will be discussed in this paper, we can often accepta lower level of redundancy where back-up isprovided and we then assess that this will result in asufficiently reliable overall protection system.

Sometimes a lower level of redundancy would beaccepted where the consequence of failure is lesssevere. For example, it is common for somedistribution systems to provide backup protection,but not redundant Main 1 / Main 2 systems. Such anassessment however is very subjective which is whyit is common for different design philosophies to beused between different end users.

2. DIGITAL SUBSTATION ARCHITECTURE NEW CONSIDERATIONS

When we look at the architecture of a digitalsubstation, it is apparent that many new technologies

Fig. 1: Fully Redundant Main 1 / Main 2 Line Protection Scheme [2]

Fig. 2: Digital Substation Architecture

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are available. However, the overall principle ofprotection redundancy must be maintained even withthis new architecture as it cannot be allowed thatthe failure of a single device results in the completeloss of system protection. For example IEDs can nowsend commands to circuit breakers through theprocess bus rather than with copper connections,but the process bus should incorporate sufficientredundancy so that the failure of a single Ethernetswitch does not result in the failure of a GOOSE tripsignal being transferred.

As an example of how some Engineers haveapproached this problem, consider the conceptualdesign of the first example in Figure 3.

The architecture of the first example may in fact notbe any more reliable than the second whenconsidering a single device failure scenario, and it isalso probably more difficult to commission,troubleshoot and maintain. In both cases there is nosingle point of failure but the first example issignificantly more complex. This illustrates a keypoint that although it is possible to implement moresophisticated designs to add redundancy with newdigital substation technology, it does not necessarilymean that it is always appropriate to do so [3].

What then are the key new components to a digitalsubstation that will need to have redundant designs?Referring back to the conceptual architecture inFigure 2 we can see new points of common modefailure that require consideration and will now beanalysed in detail:

1. The Ethernet network (both station bus andprocess bus)

2. The time synchronisation network

3. The functional architecture of protectionfunctions, since these may now be distributedacross the substation within different IEDs

3. SUBSTATION ETHERNET NETWORKREDUNDANCY

Logically, we can group the two Ethernet networksin a digital substation into two buses; the stationbus and the process bus. Though these are separatedas logically distinct systems they can be made ofdifferent components with varying levels ofredundancy. For example the process busconnections between some merging units and IEDscould be point-to-point with no network redundancywhereas others could make use of a redundantprotocol like PRP. There may even be componentsthat are used for both the process and station buses,for example in the figure below GOOSE signals areused in both process and station level signalexchange from the protection IEDs.

The types of network redundancy technology thatcan be used for the substation Ethernet network canbe grouped into three categories:

3.1 No Automatic Redundancy (point-to-point link)

In this case the Ethernet connection is a point to

Because any device can potentially subscribe to anymerging unit on the process bus, it is possible for adesign architecture like this first example wherebythe protection IEDs subscribe to multiple instrumenttransformer sampled value streams via redundantmerging units. However the question of whether thisis actually necessary is a valid one. In a conventionalsubstation such a design philosophy would equateto protection IEDs being wired to multiple redundantinstrument transformers, which is not commonpractice nor indeed desirable, as it is accepted thatif one of the instrument transformer circuits were tofail that the Main 2 system will provide sufficientbackup. Often the sampled values from the mergingunit do not need to be shared to other devices,therefore a point-to-point connection could beentirely suitable as shown in the second example ofFigure 3. This also aligns with the principle of thetwo main protection systems being independent ofone another.

Fig. 3: Options for Protection IED Subscriptions to Merging Units

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point link only. In the event of failure the connectionmust be manually repaired to re-establishcommunication. This could take the form of a singleEthernet connection from an IED to a networkswitch, or a single connection between merging unitand an IED as in Figure 4.

Another example of passive redundancy is hotstandby, which is a term used for devices with aback-up network interface that is only activated inthe case of the primary interface failing.

The advantage of these technologies is theirsimplicity; they require very little configuration andtraining to staff who may be new to networking anddigital substation principles. However they are nota suitable choice where system down time is an issue,for example an application that requires a consistentsampled value stream, or a transmission applicationwhere a few hundred milliseconds of protectionunavailability would pose an unacceptable threat togrid stability.

3.3 Active Network Redundancy

The international standard IEC 62439 defines twonetwork redundancy protocols that can be used forsubstation Ethernet networks; PRP and HSR [5]. Someother protocols do exist but are not interoperablesolutions and not considered in this paper.

These two technologies differ to other protocols inthat they are termed as bumpless whereby recoverytime in the case of failure is zero.

PRP (Parallel Redundancy Protocol) uses a double-star architecture. Two messages are sent to twodifferent networks simultaneously. HSR (HighAvailability Seamless Ring) as the name suggests usesa ring architecture. Like PRP two messages are sentfrom each device, but these traverse the same LANin opposite directions.

Compared to HSR, PRP has the advantages of:

z It can support twice as many devices for thesame network bandwidth

z It does not require that all devices in the system

Such architecture relies on back-up devices (Main2) to provide redundancy to the system, rather thanredundancy of the Ethernet network. But thisapproach could be perfectly acceptable since a failurewould have to occur on both the Main 1 and Main 2simultaneously for the complete system to bedisabled.

3.2 Passive Network Redundancy

Some networking technologies offer redundancy butwill cause system outages for a certain period of timewhile communication is re-established. For exampleRapid Spanning Tree Protocol (RSTP) which is verycommonly used in substation LANs, may takehundreds of milliseconds to reconfigure when a linkis broken [4], during which time no signals such asGOOSE can be exchanged between the isolated partsof the network (Figure 5).

Fig. 4: Point-to-Point Network Connection

Fig. 5: Spanning Tree Protocol

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support PRP or HSR (devices can be singlyattached to only one network if full redundancyis not required)

z Flexibility of LAN structure since it is possiblefor the two LANs to have different architecturesand use different technology

The disadvantage of PRP is that it requires moreinvestment in network components compared to HSRsince the network must be duplicated.

It is entirely possible and indeed recommended thatPRP and HSR networks are mixed with one anotherdepending on the application. For example LAN-Ashown in Figure 6 may actually be formed using a

HSR ring, or it may use another redundancytechnology such as RSTP. It is recommended to notrestrict the networking technologies that can be used,so that Engineers may select the optimum solutionfor the application.

The application requirement is the determinant factorfor what level of network redundancy is required. Insome systems there may be a high risk of Ethernetnetwork failure, or a separate Main 2 system maynot be provided, in which case a bumpless redundantnetwork protocol such as PRP might be required. Inother cases a simple point-to-point link could becompletely sufficient.

Fig. 6: Parallel Redundancy Protocol

Fig. 7: High Availability Seamless Ring Protocol

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4. TIME SYNCHRONISATION SIGNALREDUNDANCY

One new consideration with the introduction of theprocess bus is the provision of accurate timesynchronisation signals. Process bus applicationsrequire sampled value measurements to besynchronised very accurately. If an IED receivessampled values from different sources, for instancevoltage measurements from one merging unit andcurrent measurements from another, then protectionmaloperation could occur if these samples are notproperly synchronised. Because of this risk, the sameredundant design principles also apply to the timesynchronisation network.

z Redundant time sources

Currently the most popular means of providing asource of global time synchronisation is usingsatellite signals from the Global Positioning System(GPS). This is a very accurate and cost effectivesolution but has some disadvantages, namely it is asingle source of failure. In addition to the risk ofGPS system failure, there is the potential threat ofGPS signals being jammed or spoofed for maliciouspurposes [6].

However not all applications require time signals tobe globally synchronised, so long as all samples aresynchronised to the same local clock. For example,in applications that are limited to within thesubstation such as bus bar protection, there is norisk if communications to GPS satellites are lost asthe function can still continue to operate as normal.

In such scenarios redundant time sources may notbe necessary. This situation is even simpler in casessuch as feeder protection where all samples mayemanate from the same merging unit, so real time isirrelevant to correct operation.

In the case where the samples being compared aregeographically dispersed, such as line currentdifferential, then global synchronisation is veryimportant. If the clocks at either end of the line arenot synchronised to one another then a differentialcurrent may be wrongly observed resulting in mal-operation, unless the relay scheme offers suitablemitigation.

In such a situation it is necessary rely on back-upprotection functions in the case of time source failureor to provide a redundant global time source. Onemethod is to use provide a diverse satellitetechnology not linked to GPS. Currently the RussianGLONASS system is the only commercially availabletechnology worldwide for such purpose, but in futurethe European Galileo and other regional systems mayprovide suitable alternatives. However commonmode failure is still possible, for example solar flarescan affect all satellite systems equally [7].

An accurate time source can also be providedwithout a satellite based system by using a Caesiumatomic clock (Figure 8). This is a very expensivesolution but has been demonstrated as technicallyfeasible for situations that require extremely highlevels of redundancy, as the chance of common modefailure is reduced by providing diversity in thetechnology used.

Fig. 8: Redundant Time Source System Example

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z Redundant time signal distribution

For the distribution of time synchronisation signalsthere are two main methods; to use separate physicalcabling such as 1 Pulse Per Second (1PPS) signals, orto make use of the existing station bus and processbus Ethernet network infrastructure and transmit timesynchronisation signals via a packet basedtechnology such as IEEE 1588 PTP.

Packet based technology can offer a lower costsolution if it can make use of the existing processand station buses, but this can require that a greatdeal of devices in the substation support the IEEE1588 C37.238 Power Profile to maintain the requiredlevel of accuracy of less than 1 microsecond,including boundary clock devices such as baycontrollers. At present this can be difficult to achievebut will improve as support for the Power Profilegrows.

Signal distribution via physical cabling methods suchas 1PPS have been in use many for many years andare well proven. To minimise single points of failurethe time signalling for Main 1 protection devicesshould ideally not be the same as for Main 2. Ifeconomically justifiable this would entail theconstruction of two separate time sync signaldistribution networks within the substation so thatthe failure of one does not affect both systemssimultaneously. Where two time sources areprovided, this could be achieved with opticalmultiplexers (Figure 8).

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