POWER TRANSFORMERS
Core and coil assemblies ofa three-phase 20.3 kVD/345kVY step-up transformer.This oil-immersedtransformer is rated 325MVA self-cooled (OA)/542MVA forced oil, forced aircooled (FOA)/607MVAforced oil, forced air-cooled(FOA) (Courtesy ofGeneral Electric)3POWER TRANSFORMERSThe power transformer is a major power system component that permitseconomical power transmission with high e‰ciency and low series-voltagedrops. Since electric power is proportional to the product of voltage andcurrent, low current levels (and therefore low I 2 R losses and low IZ voltagedrops) can be maintained for given power levels via high voltages. Powertransformers transform ac voltage and current to optimum levels for generation, transmission, distribution, and utilization of electric power.The development in 1885 by William Stanley of a commercially practical transformer was what made ac power systems more attractive than dcpower systems. The ac system with a transformer overcame voltage problemsencountered in dc systems as load levels and transmission distances increased.Today’s modern power transformers have nearly 100% e‰ciency, with ratings up to and beyond 1300 MVA.90
CASE STUDY91In this chapter, we review basic transformer theory and develop equivalent circuits for practical transformers operating under sinusoidal-steadystate conditions. We look at models of single-phase two-winding, three-phasetwo-winding, and three-phase three-winding transformers, as well as autotransformers and regulating transformers. Also, the per-unit system, whichsimplifies power system analysis by eliminating the ideal transformer winding in transformer equivalent circuits, is introduced in this chapter and usedthroughout the remainder of the text.CASES T U DYThe following article describes how transmission transformers are managed in thePennsylvania–New Jersey (PJM) Interconnection. PJM is a regional transmissionorganization (RTO) that operates approximately 19% of the transmission infrastructure ofthe U.S. Eastern Interconnection. As of 2007, there were 188 transmission transformers(500/230 kV) and 29 dedicated spare transformers in the PJM system. A Probabilistic Riskassessment (PRA) model is applied to PJM transformer asset management [8].PJM Manages Aging Transformer Fleet:Risk-based tools enable regionaltransmission owner to optimize assetservice life and manage spares.BY DAVID EGAN AND KENNETH SEILERPJM INTERCONNECTIONThe PJM interconnection system has experiencedboth failures and degradation of older transmissiontransformers (Fig. 1). Steps required to mitigatepotential system reliability issues, such as operationof out-of-merit generation, have led to higher operating costs of hundreds of millions of dollars fortransmission system users over the last severalyears.The PJM (Valley Forge, Pennsylvania, U.S.) systemhas 188 transmission transformers (500 kV/230 kV)in service and 29 dedicated spares. Figure 2 showsthe age distribution of this transformer fleet. Notethat 113 transformers are more than 30 years oldand will reach or exceed their design life over thecourse of the next 10 years. To address increasing(‘‘PJM Manages Aging Transformer Fleet’’ by David Egan andKenneth Seiler, Transmission & Distribution World Magazine,March 2007)Figure 1PJM is evaluating the risk of older transformers.The Probabilistic Risk Assessment also considers theeffectiveness of alternative spares strategies
92CHAPTER 3 POWER TRANSFORMERSfacilities. When congestion occurs, highercost generation on the restricted side of theconstraint must operate to keep line flowsunder specified limits and to meet customerdemand. The cost of congestion resultsfrom the expense of operating higher-costgenerators. Congestion and its relatedcosts exist on all electric power systems.However, in a RTO such as PJM, the costof congestion is readily knowable andidentified.The failure impact of certain 500-kV/230-kV transformers on the PJM systemcan mean annual congestion costs of hundreds of millions of dollars if the failurecannot be addressed with a spare. Leadtimes for replacement transformer units atFigure 2this voltage class can take up to 18 months,Age distribution of the PJM 500-kV/230-kV transformer fleet. Noteand each replacement unit cost is severalthat more than half of this population is over 30 years oldmillion dollars. These costly transformer-lossconsequences, coupled with the age districoncerns regarding potential reliability impacts andbution of the transformer population, have raisedthe ability to replace failed transformer units in aPJM’s concern that the existing system spare quantitimely fashion, PJM and its transmission-owningties could be deficient and locations of existing sparesmembers are establishing a systematic, proactivesuboptimal.transformer replacement program to mitigate negative impacts on PJM stakeholders, operations andDEVELOPING PRAultimately the consumers. PJM now assesses the riskexposure from an aging 500-kV/230-kV transformerPJM reviewed existing methods for determiningfleet through its Probabilistic Risk Assessment (PRA)transformer life expectancy, assessing failure immodel.pacts, mitigating transformer failures, ensuringspare-quantity adequacy and locating spares. Eachof these methodologies has weaknesses when apCONGESTIONplied to an RTO scenario. In addition, no existingGenerally PJM’s backbone high-voltage transmismethod identified the best locations for sparesion system delivers lower-cost power from sourtransformers on the system.ces in the western side of the regional transmissionTransformer condition assessments are the priorganization (RTO) to serve load centers in themary means for predicting failures. Although techeastern side. Delivery of power in PJM includesnology advancements have improved conditiontransformation from 500-kV lines to 230-kV facilimonitoring data, unless a transformer exhibits signsties for further delivery to and consumption byof imminent failure, predicting when a transformercustomers.will fail based on a condition assessment is stillCongestion on the electric system can occurmostly guesswork. Traditional methods have quanwhen a transmission transformer unit must be retified the impacts of transformer failure based onmoved from service and the redirected electricityreliability criteria; they have not typically includedflow exceeds the capabilities of parallel transmissioneconomic considerations. Also, while annual failure
CASE STUDYrate analysis is used to determine the number ofspares required, assuming a constant failure ratemay be a poor assumption if a large portion of thetransformer fleet is entering the wear-out stage ofasset life.Recognizing the vulnerabilities of existing methods, PJM proceeded to develop a risk-based approachto transformer asset management. The PJM PRAmodel couples the loss consequence of a transformerwith its loss likelihood (Fig. 3). The product of theseinputs, risk, is expressed in terms of annual riskexposure dollars.PRA requires a detailed understanding of failureconsequences. PJM projects the dollar value of eachtransformer’s failure consequence, including costestimates for replacement, litigation, environmentalimpact and congestion. PJM’s PRA also permits theassessment of various spare-unit and replacementpolicies based on sensitivity analysis of these fourcost drivers.PRA MODEL INPUTSThe PRA model depends on several inputs to determine the likelihood of asset failure. One key input is the number of existing fleet transformers.Individual utilities within PJM may not have enoughtransformers to develop statistically significant assessment results. However, PJM’s region-wide perspectivepermits evaluation of the entire transformer population within its footprint.Second, rather than applying the annual failurerate of the aggregate transformer population, eachtransformer’s failure rate is determined as a functionof its effective age. PJM developed its own methodfor determining this effective age-based failure rate,or hazard rate. Effective age combines conditiondata with age-based failure history. By way of analogy, consider a 50-year-old person who smokes andhas high cholesterol and high blood pressure (condition data). This individual may have the same riskof death as a healthy 70-year-old non-smoker. Thus,while the individual’s actual age is 50 years, hiseffective age could be as high as 70 years.Third, the PRA model inputs also include transformers’ interactions with each other in terms of93Figure 3The PJM Probabilistic Risk Assessment model usesdrivers to represent overall failure consequences: costsof replacement, litigation, environmental and congestionthe probabilities of cascading events and largeimpact, low-likelihood events. For example, transformers are cooled with oil, which, if a transformerruptures, can become a fuel source for fire. Such afire can spread to neighboring units causing them tofail as well. PJM determined cascading event probability by reviewing industry events and consulting industry subject-matter experts. Further, the impactsof weather events also are considered. For example,a tornado could damage multiple transformer unitsat a substation. PJM uses National Oceanic and Atmospheric Administration statistical data for probabilities of such weather-related phenomena.The remaining PRA model inputs include thepossible risk-mitigation alternatives and transformergroupings. The possible risk-mitigation alternativesinclude running to failure, overhauling or retrofitting,restricting operations, replacing in-kind or with anupgraded unit, increasing test frequency to betterassess condition, adding redundant transformers orpurchasing a spare. The PRA model objective is toselect the appropriate alternative commensuratewith risk. To accomplish this objective, the PRAmodel also requires inputs of the cost and time toimplement each alternative. The time to implementan alternative is important because failure consequences accumulate until restoration is completed.
94CHAPTER 3 POWER TRANSFORMERSAlso, transformers must be grouped by spareapplicability. Design parameters can limit the number of in-service transformers that can be served bya designated spare. Additionally, without executedsharing agreements in place between transmissionowners, PJM cannot recognize transformer sparesharing beyond the owner’s service territory.THE QUESTION OF SPARESPRA determines the amount of transformer-lossrisk exposure to the PJM system and to PJM members. To calculate the total risk exposure fromtransformer loss, each transformer’s risk is initiallydetermined assuming no available spare. This initialtotal-system transformer-loss risk is a baseline forcomparing potential mitigation approaches. For thisbaseline, with no spares available, US 553 million ofannual risk exposure was identified.A spare’s value is equal to the cumulative riskreduction, across all facilities that can be served bya given spare. The existing system spares wereshown to mitigate 396 million of the annual risk,leaving 157 million of annual exposure. The PRAshowed that planned projects would further mitigate 65 million, leaving 92 million of exposedannual risk.With the value of existing spares and plannedreliability upgrade projects known, the PRA canthen assess the value of additional spares in reducing this risk exposure. As long as the risk mitigated by an additional spare exceeds the paybackvalue of a new transformer, purchasing a spare isjustified. The PRA identified 75 million of justifiable risk mitigation from seven additional spares.PRA also specifies the best spare type. If a sparecan be cost justified, asset owners can use twotypes of spare transformers: used or new. As an inservice unit begins to show signs of failure, it can bereplaced. Since the unit removed has not yet failed,it can be stored as an emergency spare. However,the downsides of this approach are the expense,work efforts and congestion associated with handling the spare twice. Also, the likelihood of a usedspare unit’s success is lower than that of a new unitbecause of its preexisting degradation.PJM’s PRA analysis revealed that it is more costeffective to purchase a new unit as a spare. In thiscase, when a failure occurs, the spare transformercan be installed permanently to remedy the failureand a replacement spare purchased. This processallows expedient resolution of a failure and reduceshandling.Existing spares may not be located at optimalsites. PRA also reveals ideal locations for storingspares. A spare can be located on-site or at aremote location. An on-site spare provides thebenefit of expedient installation. A remote sparerequires added transportation and handling. Ideally,spares would be located at the highest risk sites.Remote spares serve lower risk sites. The PRAboth identifies the best locations to position spareson the system to minimize risk and evaluates relocation of existing spares by providing the cost/benefit analysis of moving a spare to a higher risksite.The PRA has shown that the type of spare (nospare, old spare or new spare) and a transformer’sloss consequence strongly influence the most costeffective retirement age. High-consequence transformers should be replaced at younger ages due tothe risk they impose on the system as their effective age increases. PRA showed that using newspares maximizes a transformer’s effective age forretirement.STANDARDIZATION IMPACTApproximately one-third of the number of currentspares would be required if design standardizationand sharing between asset owners were achieved.This allows a single spare to reduce the loss consequence for a larger number of in-service units.Increasing the number of transformers covered by aspare improves the spare’s risk-mitigation value.Having more transformers covered by spares reduces the residual risk exposure that accumulateswith having many spare subgroups.PJM transmission asset owners have finalized astandardized 500-kV/230-kV transformer design toapply to future purchase decisions. For the benefitsof standardization to be achieved, PJM asset owners
CASE STUDY95PJM BACKGROUNDFormally established on Sept. 16, 1927, thePennsylvania-New Jersey Interconnection allowedPhiladelphia Electric, Pennsylvania Power & Light,and Public Service Electric & Gas of New Jerseyto share their electric loads and receive powerfrom the huge new hydroelectric plant at Conowingo, Maryland, U.S. Throughout the years,neighboring utilities also connected into the system. Today, the interconnection, now called thePJM Interconnection, has far exceeded its originalfootprint.PJM is the operator of the world’s largestcentrally dispatched grid, serving about 51 millionpeople in 13 states and the District of Columbia.A regional transmission organization that operates 19% of the transmission infrastructure of theU.S. Eastern Interconnection on behalf of transmission system owners, PJM dispatches 164,634MW of generating capacity over 56,000 milesalso are developing a spare-sharing agreement.Analysis showed that 50 million of current sparetransformer requirements could be avoided bystandardization and sharing.The PRA model is a useful tool for managingPJM’s aging 500-kV/230-kV transformer infrastructure. While creating the PRA model was challenging, system planners and asset owners havegained invaluable insights from both the development process and the model use. Knowing and understanding risk has better prepared PJM and itsmembers to proactively and economically addresstheir aging transformer fleet. PRA results have beenincorporated into PJM’s regional transmissionexpansion planning process. PRA will be performedannually to ensure minimum transformer fleet riskexposure. PJM is also investigating the use of thisrisk quantification approach for other powersystem assets.Kenneth Seiler is manager of power system coordination at PJM Interconnection. He is responsible(91,800 km) of transmission. Within PJM,12 utilities individually own the 500-kV/230-kVtransformer assets.PJM system information breakdown and locationfor the interconnection coordination of generation,substation and transmission projects, and outageplanning. He has been actively involved in the PJMPlanning Committee and the development of thePJM’s aging infrastructure initiatives. Prior to working for PJM, he was with GPU Energy for nearly15 years in the Electrical Equipment Construction andMaintenance and System Operation departments.Seiler earned his BSEE degree from Pennsylvania StateUniversity and MBA from Lebanon Valley College,seilek@pjm.comDavid Egan is a senior engineer in PJM’s Interconnection Planning department, where he hasworked for three years. He earned his BSME degree from Binghamton University. Previously heworked at Oyster Creek Generating Station for13 years. During this time, he worked as a thermalperformance engineer and turbine-generator systems’ manager, and coordinated implementation ofthe site’s Maintenance Rule program, egand@pjm.com
96CHAPTER 3 POWER TRANSFORMERS3.1THE IDEAL TRANSFORMERFigure 3.1 shows a basic single-phase two-winding transformer, where thetwo windings are wrapped around a magnetic core [1, 2, 3]. It is assumedhere that the transformer is operating under sinusoidal-steady-state excitation. Shown in the figure are the phasor voltages E1 and E 2 across the windings, and the phasor currents I1 entering winding 1, which has N1 turns, andI2 leaving winding 2, which has N2 turns. A phasor flux Fc set up in the coreand a magnetic field intensity phasor Hc are also shown. The core has across-sectional area denoted Ac , a mean length of the magnetic circuit lc , anda magnetic permeability mc , assumed constant.For an ideal transformer, the following are assumed:1. The windings have zero resistance; therefore, the I 2 R losses in thewindings are zero.2. The core permeability mc is infinite, which corresponds to zero corereluctance.3. There is no leakage flux; that is, the entire flux Fc is confined to thecore and links both windings.4. There are no core losses.A schematic representation of a two-winding transformer is shown inFigure 3.2. Ampere’s and Faraday’s laws can be used along with the preceding assumptions to derive the ideal transformer relationships. Ampere’s lawstates that the tangential component of the magnetic field intensity vectorFIGURE 3.1Basic single-phasetwo-winding transformer
SECTION 3.1 THE IDEAL TRANSFORMER97FIGURE 3.2Schematic representationof a single-phase twowinding transformerintegrated along a closed path equals the net current enclosed by that path;that is,þð3:1:1ÞHtan dl ¼ IenclosedIf the core center line shown in Figure 3.1 is selected as the closed path,and if Hc is constant along the path as well as tangent to the path, then(3.1.1) becomesHc lc ¼ N1 I1 N2 I2ð3:1:2ÞNote that the current I1 is enclosed N1 times and I2 is enclosed N2times, one time for each turn of the coils. Also, using the right-hand rule*,current I1 contributes to clockwise flux but current I2 contributes to counterclockwise flux. Thus, in (3.1.2) the net current enclosed is N1 I1 N2 I2 . Forconstant core permeability mc , the magnetic flux density Bc within the core,also constant, isBc ¼ mc HcWb m 2ð3:1:3Þand the core flux Fc isFc ¼ Bc AcWbUsing (3.1.3) and (3.1.4) in (3.1.2) yields lcFcN1 I1 N2 I2 ¼ lc Bc mc ¼m c Acð3:1:4Þð3:1:5ÞWe define core reluctance Rc asRc ¼lcm c Acð3:1:6ÞThen (3.1.5) becomesN1 I1 N2 I2 ¼ Rc Fcð3:1:7Þ* The right-hand rule for a coil is as follows: Wrap the fingers of your right hand around the coilin the direction of the current. Your right thumb then points in the direction of the flux.
98CHAPTER 3 POWER TRANSFORMERSEquation (3.1.7) can be called ‘‘Ohm’s law’’ for the magnetic circuit,wherein the net magnetomotive force mmf ¼ N1 I1 N2 I2 equals the productof the core reluctance Rc and the core flux Fc . Reluctance Rc , which impedesthe establishment of flux in a magnetic circuit, is analogous to resistance inan electric circuit. For an ideal transformer, mc is assumed infinite, w
THE QUESTION OF SPARES PRA determines the amount of transformer-loss risk exposure to the PJM system and to PJM mem-bers. To calculate the total risk exposure from transformer loss, each transformer’s risk is initially determined assuming no available spare. This initial total-system transformer-loss risk is a baseline for
applications including generator step-up (GSU) transformers, substation step-down transformers, auto transformers, HVDC converter transformers, rectifier transformers, arc furnace transformers, railway traction transformers, shunt reactors, phase shifting transformers and r
2.5 MVA and a voltage up to 36 kV are referred to as distribution transformers; all transformers of higher ratings are classified as power transformers. 0.05-2.5 2.5-3000 .10-20 36 36-1500 36 Rated power Max. operating voltage [MVA] [kV] Oil distribution transformers GEAFOL-cast-resin transformers Power transformers 5/13- 5 .
7.8 Distribution transformers 707 7.9 Scott and Le Blanc connected transformers 729 7.10 Rectifier transformers 736 7.11 AC arc furnace transformers 739 7.12 Traction transformers 745 7.13 Generator neutral earthing transformers 750 7.14 Transformers for electrostatic precipitators 756 7.15 Series reactors 758 8 Transformer enquiries and .
cation and for the testing of the transformers. – IEC 61378-1 (ed. 2.0): 2011, converter transformers, Part 1, Transformers for industrial applications – IEC 60076 series for power transformers and IEC 60076-11 for dry-type transformers – IEEE Std, C57.18.10-1998, IEEE Standard Practices and Requirements for Semiconductor Power Rectifier
Ex. 8-2 Transformers in Parallel . 347 Connecting transformers in parallel to supply greater load power. Measuring the efficiency of parallel-connected transformers. Ex. 8-3 Distribution Transformers . 355 Introduction to basic characteristics of distribution transformers.
- IEC 61558 – Dry Power Transformers 1.3. Construction This dry type transformer is normally produced according to standards mentioned above. Upon request transformers can be manufactured according to other standards (e.g. standards on ship transformers, isolation transformers for medical use and protection transformers.
Transformers (Dry-Type). CSA C9-M1981: Dry-Type Transformers. CSA C22.2 No. 66: Specialty Transformers. CSA 802-94: Maximum Losses for Distribution, Power and Dry-Type Transformers. NEMA TP-2: Standard Test Method for Measuring the Energy Consumption of Distribution Transformers. NEMA TP-3 Catalogue Product Name UL Standard 1 UL/cUL File Number .
Instrument . Transformers. 731. 736 737. 735. g. Multilin. 729 Digital Energy. Instrument Transformers. 738 739. 739 Instrument Transformers. Control Power Transformers 5kV to 38kV - Indoor type. Current Transducers 600 Volt Class IEC - Rated Instrument Transformers
