Transformers and Equipment

EPRI Underground Distribution Systems Reference Book CHAPTER 16 Transformers and Equipment Authors: Stephen L. Cress, Kinectrics. Inc. Ali Naderian, Kinectrics, Inc. Reviewers: Gordon Hayslip, Snohomish PUD John Igielski, Northeast Utilities Ken Ochs, We Energies Joseph Somma, Consolidated Edison Abstract: This chapter reviews several aspects related to transformers, including transformer losses, loading characteristics, selection criteria for pad-mounted transformers, transformer cooling, interpretation of tests on transformers and oil, and capacitors. Stephen L. Cress graduated in 1976 from The University of Toronto with a Bachelor of Applied Science in Electrical Engineering. He is currently Department Manager – Distribution Asset Management at Kinectrics Inc. Stephen has over 33 years’ experience in specialized technical investigations, research, testing, and applications in the power distribution field based on his work at Federal Pioneer, Ontario Hydro Research Division, and Kinectrics Inc. He has conducted major projects for North American distribution utilities dealing with: transformer loading and sizing, transformer losses and efficiency, asset management, asset condition assessment, life extension, distribution protection, equipment failure analysis (transformers, switchgear, fuses, capacitors), standard testing, distribution modeling, and development of utility-oriented engineering software. Stephen is the holder of a U.S. patent on high-voltage current limiting fuses. He is a co-author of the CEATI reference books Application Guide for Distribution Fuses and Engineering Guide for Distribution Overcurrent Protection. Stephen’s work in the development of probabilistic methods for calculating transformer loss evaluation, loss-of-life, and loading have been incorporated in the commercially available CEATI TRANSIZE TM computer program. He has published papers with international organizations such as IEEE, CIRED, and INTER-RAM, and articles in power industry magazines. He is the Chair of the harmonized CSA and CNC\IEC TC32 Committees dealing with High Voltage Fuses, and a Professional Engineer in the Province of Ontario. Ali Naderian received his B.Sc. and M.Sc. degrees from Sharif University of Technology in 1998 and the University of Tehran in 2000, respectively. During his studies, his part-time employment experience included ISC (1997-1999) for testing of switchgear and circuit breakers, and ITS (1999-2000) for designing and manufacturing of HV power transformers. He was co-designer of a 3*300-kV cascade HV testing transformer. He compared commercially available RTV coatings for outdoor insulators in his PhD thesis during his research at the University of Waterloo, Ontario (2003-2006). He has been a project manager of high-voltage testing at Kinectrics, Inc. (formerly Ontario Hydro Research) since 2007, working on diagnostics of power transformers, high-voltage cables, and outdoor insulators. He performs on-line and offline PD measurements for HV apparatus. His research interests include high-voltage test techniques, dielectric frequency response, and partial discharge. He has published several papers, is actively involved in IEEE transformer working groups, and is a registered engineer in the Province of Ontario. 16-1 Chapter 16: 16.1 Transformers and Equipment INTRODUCTION This edition of the Bronze Book covers only a subset of what will be a comprehensive look at underground distribution transformers. Included here are sections on transformer losses, loading characteristics, padmounted transformer selection criteria, interpretation of tests on transformers and oil, as well as a discussion on capacitors. The next edition will also include an overview of transformer types by application, unit components and core construction, installation options, and insulation types. Additional topics will be transformer cooling, testing and monitoring, and typical examples of failure root causes. The reader is encouraged to refer to other sources more broadly covering this topic, including the Electric Power Distribution Handbook by Tom Short (2004), Power Transformers, Principles and Applications by John Winders (2002), and the ABB Distribution Transformer Guide (2002). 16.2 TRANSFORMER LOSSES Losses in distribution transformers are categorized as load and no-load losses. Load losses vary with the square of the load on the transformer, whereas no-load losses are continuous and constant regardless of load. 16.2.1 No-Load Loss No-load losses (or excitation losses, iron losses, or core losses) are inherent to the excitation of the transformer. No-load losses are associated with the core design. They include core loss, dielectric loss, and the loss in the windings due to exciting current. For distribution transformers at 27.6 kV and below, the dielectric loss is negligible. The no-load loss in the transformer core is a function of the magnitude, frequency, and wavefor m of the impressed voltage. No-load losses are affected by voltage fluctuations. When an AC voltage is applied to the terminals of the transformer, magnetizing current flows through the winding, and a magnetic flux appears in the core. The predominant component is core loss, which is composed of hysteresis and eddy current losses. The hysteresis loss is proportional to the frequency and dependent on the area of the hysteresis loop in the B-H diagram, and, therefore, characteristic of the material and a function of the peak flux density. The variable magnetic flux induces current running in paths perpendicular to the direction of the flux. The 16-2 EPRI Underground Distribution Systems Reference Book induced current, called eddy current, produces losses in the core plates. The eddy current loss can be calculated by Equation 16.2-1 Peddy = π2 6 σ f 2 d 2 B 2V 16.2-1 Where: σ is the core conductivity. ƒ is frequency. d is the core thickness. B is the peak value of the flux density. V is the core volume. As per Equation 16.2-1, eddy current is controlled by using laminated core to cut large current loops at the cross section of the core. The no-load loss is the sum of hysteresis and eddy current losses, as shown in Equation 16.2-2. P0 = Peddy + Ph 16.2-2 16.2.2 Load Losses Load losses (or copper losses or resistive losses) are primarily a function of the winding design of the transformer. They result from the load current flowing in the primary and secondary windings. Components of load loss are I2R and stray losses. For a distribution transformer, I2R is in the range of 92-99% of the load loss. The proportion is lower for larger kVA sizes. Load loss is affected by: • • • • number of turns of winding mean length of the primary and secondary turns conductor cross section material of the conductor—i.e., copper or aluminum Stray losses vary inversely as the temperature, thereby making necessary the calculation of load loss at a specific temperature such as 85°C. Stray losses have three components: conductor eddy currents, conductor circulating currents, and stray currents in the core wall and core clamps. The current, which is applied to the windings, creates losses due to the winding resistance. The losses of a transformer are losses incident to a specified load carried by the transformer. Load losses in distribution-class transformers mainly include I 2 R loss in the windings due to load current. Load loss follows Ohm’s law and can be decreased by reducing the number of winding turns, by increasing the cross-sectional area of the turn conductor, or by a com- EPRI Underground Distribution Systems Reference Book bination of both. However, reducing the number of turns requires an increase of the flux—i.e., an increase in the core cross-section, which increases the iron weight and iron loss. Therefore, a tradeoff has to be made between the load loss and the no-load loss. Chapter 16: Transformers and Equipment Transformer efficiency (η) is the ratio of a transformer’s useful power output to its total power input as indicated in Equation 16.2-3 (IEEE 2006). Pout Pin − Ploss = Pin Pin η= 16.2-3 16.2.3 Total Loss The following summarizing relationships are useful when considering the losses in distribution transformers: No Load Loss α Flux Density α 1/# Turns α 1/ Core Cross Section Load Loss α # Turns Where: η is the efficiency. Pin is the input power. Pout is the output power. Ploss is the total power loss of the transformer to be introduced. Impedance α Reactance α (# Turns)2 Initial Cost α Core Material α Winding Material Table 16.2-1 summarizes the components of load and no-load losses. In many jurisdictions, government energy agencies have mandated minimum efficiency levels for liquid-filled and dry-type distribution transformers (DOE 2007; NEMA 2002). Table 16.2-3 provides an example of the accepted efficiency levels for liquid-immersed distribution trans- Figure 16.2-1 and Table 16.2-2 provide some typical load and no-load loss values for distribution transformers. Figure 16.2-1 illustrates how load losses vary with load on the transformer. 16.2.4 Transformer Efficiency Transformer efficiency is related to the amount of watts losses that occur when the transformer is in operation. Table 16.2-1 Components of Transformer Load and NoLoad Loss Type No-Load Lossa Load Lossa I2R from No-load I I2R from load I I2R from I supplying Losses Magnetic Core Hysteresis Loss Core Eddy Current Loss Stray Eddy Current Loss in Internal components Conductor Eddy Current from Leakage fields Dielectric Dielectric Loss Electric a. Where I represents current, and I2R is the current squared times the conductor resistance. Figure 16.2-1 Typical load and no-load losses of distribution transformers. Table 16.2-2 Typical Losses for Power Distribution Transformers No-Load Loss Watts Efficiencya at 50% load Rating KVA Load Loss Watts 250 3800 880 0.9925 400 5500 1200 0.9932 667 7900 1700 0.9941 1000 11000 2300 0.9945 1500 15000 3000 0.9950 2500 23000 5000 0.9954 a. Calculated using Equation 16.2-4. 16-3 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book formers. An example of the minimum efficiency for drytype distribution transformers is shown in Table 16.2-4 (DOE 2007). These efficiency values are computed at 50% of nameplate-rated load. Efficiency can be expressed directly as a function of the load and no-load losses as in Equation 16.2-4 (NEMA 2002). The efficiency values computed using this formula are provided alongside the load and no-load losses in the examples in Table 16.2-2. η= KVA × Lp.u. KVA × Lp.u. + P0 + Lp.u.2 × PL 16.2-4 Where: KVA is the transformer rated power. PL is the load loss. P0 is the no-load loss. Lp.u. is the per-unit load (the ratio of actual load to the rated full load). Present distribution transformers are, for the most part, between 98% and 99.5% efficient. For the new transformers, the guideline from (DOE 2007), presented in Tables 16.2-3 and 16.2-4, should be followed. Because virtually all-electric energy passes through distribution transformers, losses in these devices, though small, are estimated to constitute as much as 2 to 3% of all energy generated. Generally transformers are at maximum efficiency when they are 50% loaded. When transformers are lightly loaded, the no-load losses form a large percentage of the power utilized, and therefore, the efficiency is low. As the transformer is loaded to higher levels, the load losses dominate the efficiency. The maximum efficiency point is the optimal point of lowest load and no-load losses. It is determined by the design of the transformer and theoretically could be designed to occur at any load percentage. It typically is designed to occur at 50%, because the average load tends to be about 50% of the peak load. However, transformers with high no-load losses are Table 16.2-3 Standard Levels of Efficiency for Liquid-immersed Distribution Transformers (DOE 2007) Table 16.2-4 Standard Levels of Efficiency for Dry-type Distribution Transformers (DOE 2007) 16-4 EPRI Underground Distribution Systems Reference Book most efficient at 60%-80% load, and transformers with low no-load losses are most efficient at about 40% load. (See Figure 16.2-2.) 16.2.5 Reduction of Transformer Losses Reduction of transformer losses and improvement in efficiency can be achieved by reduction of either load or no-load losses. For any given set of core and winding materials, reduction of load losses often leads to an increase in no-load losses and vice versa. Many factors of core design affect no-load losses and can be altered to reduce these losses. Higher magnetic flux density leads to higher losses. Larger gaps in cut cores lead to higher losses. These gaps can be reduced by manufacturing techniques. The thickness of the enamel insulation on the winding conductors affects the size of the core. High-quality enamel can be used in very thin layers to reduce core size and no-load losses. Mechanical arrangement of the windings and taps also affects the efficient use of space and the size of the core. Traditionally cores have been made from grain-oriented silicon steel formed into thin sheets and wrapped into a rectangular shape. The loss decreases as the thickness of the sheets decrease. Standard grades are M-2 at 0.18 mm, M-3 at 0.23 mm, M-4 at 0.27 mm, and M-6 at 0.35 mm. Losses also depend on the permeability of the steel alloy. Higher permeability leads to lower losses. The permeability depends upon the alloy and the orientations of the grains. A large advance in technology occurred in the 1980s with the development of amorphous steel cores. These cores are also built up by wrapping thin sheets or ribbons, but the steel itself (such as Co-Fe-Si-B alloy) is quenched during manufacture to ensure that no grains are formed in the steel. This process increases the effec- Chapter 16: Transformers and Equipment tive permeability of the steel, thus reducing the losses, but it also decreases the saturation magnetic flux density, which increases the amount of material required in the core. Together, these effects reduce the no-load loss of the core, but the amorphous steel cores are larger, heavier, and more costly to produce. (Permeability increases by a factor of 4, but saturation flux density decreases by a factor of 0.75, requiring 1.3 times as much material in the core, so overall loss is lower by a factor of 3.) On average, amorphous core loss values are about 30% of that for high-efficiency silicon steel, and only 15% of that for older, less efficient steels. Numerous questions have arisen regarding the mechanical robustness and long-term mechanical performance of amorphous metals. Short-term testing programs have not substantiated these beliefs, but the concern persists. More recently nano-crystalline steel has become available for use in transformer cores. The best are based on an Fe-Zr-B alloy that is formed in an amorphous state and then annealed to produce very small grain sizes. This approach makes the material less brittle and thereby decreases production costs. This steel has even higher permeability and also higher saturation induction than the amorphous materials, but it is not yet available in manufactured transformer cores. The new steel has 17 times the permeability of steel and 0.89 of the saturation flux density; so losses should be reduced by a factor of 15. Load losses are caused primarily by the heating of the windings by the passage of current (I2R losses). The current is determined by the impedance of the load on the transformer and the voltage levels and so is not under the control of the transformer designer. The resistance depends on the material used in the winding, the crosssectional area of the wires, and the number of turns. Transformer windings are made of either copper or aluminum in round wires, square wires, or flat sheets. The resistivity of aluminum is about 1.6 times larger than that of copper, but aluminum has a lower cost. Many different alloys of aluminum and copper are available. In general, the lower resistance alloys are more expensive and harder to work with in the manufacturing processes, leading to higher initial costs. Figure 16.2-2 Transformer efficiency as a function of load. In addition to choice of material, load losses are affected by the cross-sectional area of the wire used. Larger wires produce lower load losses, but then the windings are larger, and this requires a larger core, which increases the no-load losses. 16-5 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book Some load loss is caused by induced currents from adjacent windings. These currents can be reduced by using continuously transposed conductor in the winding and thus reducing load losses. This approach also leads to higher initial costs. 16.2.6 Transformer Short-circuit Impedance When provided a customer’s cost of no-load and load losses, transformer manufacturers will use software that performs hundreds of iterations, varying core, winding, and tank options, to arrive at a transformer with an optimal balance of losses and initial cost. The short-circuit impedance of a transformer is used to calculate the maximum short-circuit current and is needed for sizing circuit breakers, fuses, cables, and other equipment connected to the secondary of the transformer. Transformer impedance (or short-circuit impedance or impedance voltage) is the percent of per unit voltage that must be applied to the primary side of a transformer, so that the rated current flows when the secondary terminals are short-circuited. This impedance is formulated as Equation 16.2-5. U Z % = Z × 100 ZP 16.2-5 As the no-load test result is available, the ohmic part of the impedance can be calculated using Equation 16.2-6, and therefore, the inductive part of the impedance can be derived by Equation 16.2-7. R% = P3ϕ − load − loss MVA3ϕ .106 × 100 X % = Z %2 − R%2 16.2-6 16.2-7 In a transformer having a tapped winding, the short-circuit impedance is referred to a particular tap. Unless otherwise specified, the nominal tap applies and is the impedance (Z%) that is marked on the nameplate. The impedance voltage of distribution transformers with rated power below 630 kVA is usually 4% or less, and this value is usually around 6% for 630 kVA up to 2.5 MVA distribution transformers. For parallel operation of two or more transformers, short-circuit impedance is critical. If paralleled transformers do not have the same short-circuit impedance, the load will be shared in an unbalanced way such that one transformer can be overloaded and the transformer can be underloaded. 16-6 16.2.7 Cost-of-Losses Formula The lifetime cost of a transformer depends on the capital cost of the transformer and the cost of the load and no-load losses during its lifetime. The present value method is often employed to express the lifetime cost in terms of a dollar value in the present year. Losses from distribution transformers are a significant contribution to distribution system losses, and their reduction represents an opportunity for improving energy efficiency A cost-of-losses formula for purchasing purposes is often employed to determine the lifetime costs for various transformer options available to utilities. Comparisons can then be made between more capital intensive low-loss transformers and less expensive higher-loss transformers. The following paragraphs describe the general formulation of a cost-of-losses formula. Table 16.2-5 defines the quantities used in these equations. Table 16.2-5 Definition of Symbols for Cost of Losses Formula CAP Capital cost ($) CLL Present value of cost of load losses ($/W) CLL(m) Cost of load losses for month “m” ($/kW) CLY(y) Cost of load losses for year “y” ($) CNLL Present value of cost of no-load losses ($/W) CNLL(m) Cost of no-load losses for month “m” ($/kW) D Demand charge, monthly ($/kW) D(m) Demand charge for month “m” ($/kW) E Energy charge, monthly (¢/kWh) EOP(m) Energy charge off-peak for month “m” (¢/kWh) EP(m) Energy charge on-peak for month “m” (¢/kWh) FYG(y) Factor for yearly load growth accumulated to year “y” g(y) Growth of load for year “y” (%/100) HOP(m) Hours off-peak for month “m” (h) HP(m) Hours on-peak for month “m” (h) i(y) Interest rate for year “y” (%/100) j(y) Inflation rate for year “y” (%/100) PVLC Present value of lifetime cost ($) LL Load losses (W) LSF Loss factor (average loss/peak loss) NLL No-load losses (W) NY Number of years in economic study period p(y) Growth of power costs for year “y” (%/100) PVF Present value factor for a period of years PVF(y) Present value factor for year “y” RATL Rated load for transformer (kVA) RF Responsibility factor (load at system peak/peak load)2 UF Utilization factor (peak load/rated load) EPRI Underground Distribution Systems Reference Book Chapter 16: The basic form of the cost of losses formula, providing the present value of the lifetime cost (PVLC) of a transformers, is as expressed in Equation 16.2-8. CLL = 1 ⎛ E ⎞ ∗ LSF ⎟ ⎜12D ∗ RF + 8760 1000 ⎝ 100 ⎠ NY PVLC = CAP + NLL ∗ CNLL + LL ∗ CLL y =1 Common cost-of-losses equations use flat-rate demand and energy charges and fixed annual economic factors, such as interest rate, to evaluate the lifetime costs of load losses (CLL) and cost of no-load losses (CNLL). The concepts of load factor, loss-factor, utilization factor, and responsibility factor are used to describe the loads on the transformer. A load growth factor can be used to include the influence of rising loads on the transformer losses over the transformer’s lifetime. Note that the load growth factor is 1 in the first year, and then changes to a fixed factor at the start of the second year. The present value factor includes the influence of economic factors such as inflation of the cost of power and interest rates. The growth in power costs factor is 1 in the first year and then changes to a fixed factor in the second year. The rate of interest starts in the first year. Note that there are 8760 hours in a year. CNLL = 1 ⎛ E ⎞ ⎜12D + 8760 ⎟ ∗ PVF 1000 ⎝ 100 ⎠ 16.2-9 { } 16.2-10 ∗∑ [UF ∗ FYG ( y )] ∗ PVF ( y ) 16.2-8 Where: CAP is the capital cost or initial purchase price of the transformer. NLL is the no-load losses that occur continuously when the transformer is energized, regardless of the loading. CNLL is the cost of no-load losses and is independent of the loading and dependent on the demand and energy charges. Time-ofuse energy charges can be considered by using on-peak and off-peak energy charges, and considering the hours that the transformer is on-peak or off-peak. LL is the load loss at rated load. The value of load loss at rated load is a measured parameter, and load losses at other loadings are derived from this value. CLL is the cost of the load losses, and depends on the demand and energy charge rates as well as on the loading of the transformer throughout its life. Transformers and Equipment PVF ( y ) = 2 (1 + p ) y −1 (1 + i ) y 16.2-11 NY PVF = ∑ PVF ( y ) 16.2-12 FYG ( y ) = (1 + g ) y −1 16.2-13 y =1 Where: UF, the utilization factor, is defined as the ratio of the peak load to the transformer rated load. It represents the portion of the transformer rated load that is utilized when the transformer is at its highest loading. UF = peak load rated load 16.2-14 RF, the peak responsibility factor, is used to adjust the load to reflect the proportion of the asset load that actually contributes to the peak load of the utility as a whole. That is, it indicates how much the lo ad lo ss of the particu lar transformer contributes to the total demand. The responsibility factor is the ratio of the transformer load at system peak to the peak load, all squared. ⎛ load at system peak ⎞ RF = ⎜ ⎟ peak load ⎝ ⎠ 2 16.2-15 LSF, the loss factor, is the ratio of the average loss to the peak loss. The loss factor can be derived from the load factor. The load factor is a single value that characterizes the load profile. The load factor is the ratio of the average load to the peak load. Load and loss factors are dependent on the shape of the load profile. Loading profiles are different for industrial/commercial, urban residential, and rural residential transformers. Industrial/commercial loads are steadier both over the day and over the week. A typical load factor is 0.85. Residential loads are more variable, with typical load factors of 0.4 for a single transformer. Urban residential transformers tend to be more heavily loaded than rural transformers. Theoretically the loss factor may have a value between the value of the load factor and the load factor squared, depending on the load profile shape. A common for- 16-7 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book mula that has been used to calculate loss factor from load factor is as shown in Equation 16.2-16. NY PVF = ∑ PVF ( y ) 16.2-23 FYG ( y ) = [1 + g ( y )] ∗ FYG ( y − 1) 16.2-24 FYG (1) = 1 + g (1) 16.2-25 y =1 LSF = 0.85 * LDF 2 + 0.15 * LDF 16.2-16 Where LDF is the load factor of the daily load profile. PVF, the present value factor, accounts for the changing value of money and expresses the present worth of dollars spent in the future. Economic factors, of course, are generally not fixed over long time periods of time. Further, there is considerable utility interest in applying variable or time-of-use rates. With addition of several parameters, the cost of losses formula can be modified to consider these variable economic inputs. Energy and demand charges can be expressed as being dependent on the time of use, either on-peak or offpeak. Economic factors and the load growth can be allowed in the equation to vary from year to year. Note that either p(y) or j(y) must be set to zero for all years y. To use the initial cost of power in the first year, set p(1) to zero [or j(1) to zero, if you are not using p(y)]. Where the variables are as defined in Table 16.2-5. With computer assistance the cost of losses formula can be further expanded to replace the use of the load factor concept and determine loads directly from daily and monthly profiles. Figure 16.2-3 shows a general graph of costs versus transformer mass for a typical distribution transformer. There is an optimum value for total cost. If the loss evaluation figures are submitted to the transformer manufacturers in the request for quotation, they can design a transformer with an optimal cost from the end user point of view. The result of this process should be the cheapest transformer in the useful life period—i.e., with the lowest total owning cost, optimized for a given application. Therefore the components of the cost of losses formula can be further expressed as: 12 ⎡ 1 ⎤ CLL = ⎢ ∗ ∑ CLL( m ) ⎥ ⎣1000 m =1 ⎦ { NY } 16.2-17 ∗∑ [UF ∗ FYG ( y )] ∗ PVF ( y ) y =1 2 CLL( m ) = D( m ) ∗ RF EP ( m ) EOP ( m ) ⎤ ⎡ + ⎢ HP ( m ) ∗ + HOP ( m ) ∗ 100 100 ⎥⎦ ⎣ ∗LSF 16.2-18 ⎡ 1 ⎤ CNLL = ⎢ ∗ ∑ CNLL( m ) ⎥ ∗ PVF ⎣1000 m =1 ⎦ 12 16.2-19 CNLL( m ) = D( m ) + HP ( m ) EP ( m ) + HOP ( m ) 100 EOP ( m ) ∗ 100 ∗ PVF ( y ) = [1 + p( y )] ∗ [1 + j ( y )] ∗ PVF ( y − 1) [1 + i ( y ) PVF (1) = [1 + p(1)] ∗ [1 + j (1)] [1 + i (1)] 16-8 16.2-20 16.2-21 16.2-22 Figure 16.2-3 Transformer mass vs. transformer lifetime cost. EPRI Underground Distribution Systems Reference Book 16.3 LOAD CHARACTERISTICS FOR TRANSFORMERS One of the main considerations for selecting the appropriate transformer is the characteristic of the load. Not only the number and type of loads, but the load pattern needs to be considered. Because load is a function of human behavior and lifestyle variables, as well as the type and size of electric equipment and weather changes, load forecasting has some level of uncertainty. 16.3.1 Load Types Chapter 16: 24-hour load profile is modeled by a series of constant loads of a short duration, usually 1 hour. The equivalent load during the short time steps is determined by using the maximum peak load during the short-time period under consideration. An equivalent two-step overload cycle can be used for determining emergency overload capability, as shown in Figure 16.3-1. The equivalent two-step load cycle consists of a prior load and a peak load. A constant load that generates total losses the same as a fluctuating load is assumed to be an equivalent load from a temperature standpoint. Equivalent load for a specific part of daily load is expressed by Equation 16.3-1. Several types of loads occur on a distribution systems: • Domestic (residential): Mainly lights, fans, heaters, refrigerators, air conditioners, ovens, small pumps, and other household appliances. • Commercial: Lighting of shops, air-conditioning, heating, and shop appliances. • Industrial: Medium and large motors. • Municipal (Public): Street lights, and traffic signals. • Agricultural: Motors and pumps. Commercial loads typically have a dedicated transformer; however, multiple residences are usually served by a single or three-phase transformer. Public loads usually need their own dedicated transformer due to the load size. The daily load profiles of these three load categories are not usually matched. Commercial and industrial loads may at times e served on a spot network of multiple transformers in parallel. Some service areas, mainly in metropolitan areas of loads including residential and commercial loads are serviced from distributed grids of many transformers in parallel via network protectors. Distribution transformers serving primarily residential loads regularly carry average loads that are only 15 to 25% of the transformer's rated capacity but also must be designed to support peak morning and evening loads. Because of the wide gap between peak and non-peak loads, and the relatively limited amount of time that the transformer is peak-loaded, average transformer loading tends to be fairly low. Transformers and Equipment N Leq = ∑L t i =1 N 2 i i 16.3-1 ∑ ti i =1 Where: Li is various load steps in% or per unit. N is the total number of load steps. ti is the duration of each load step. 16.3.3 Peak Load Equivalent peak load is the rms load obtained by Equation 16.3-1 for the limited period over which the major part of the actual peak exists. If the peak load duration is over-estimated, the rms peak value may be considerably below the maximum peak demand. To protect against overheating due to high, brief overloads during the peak overload, the rms value for the peak load period should not be less than 90% of the integrated ½ hour maximum demand. Besides daily peak load, seasonal peak load needs to be taken into account. Depending on the geographic location, and due to weather conditions, a winter peak or summer peak can be expected. An example of a daily load profile with two peak loads is given in Figure 16.3-2. 16.3.2 Load Profiles Transformer loads generally follow cycles that repeat daily, and may have seasonal variation during the year and yearly growth. The daily load variation for many utilities repeats every 24 hours and has two common forms: a single hump shape (as shown in Figure 16.3-1) or a double hump shape. A multistep load cycle calculation can be used to describe the load (IEEE 1995b). The Figure 16.3-1 Example of actual load cycle and equivalent load cycle of IEEE C57.91. 16-9 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book the actual maximum demand on the system as described in Equation 16.3-4. Load Diversity = ∑ Individual Maximum Demands − System Maximum Demand 16.3-4 Diversity factor in a distribution system is the ratio of the sum of the individual maximum demands of the various subdivisions of a system to the maximum demand of the whole system under consideration (see Equation 16.3-5). Loads do not normally all peak at the same time. Therefore, the sum of the individual peak loads is greater than the peak load of the composite system. Therefore, diversity factor is usually more than one. Figure 16.3-2 Morning and evening peak loads (from Pabla 2004). DF = 16.3.4 Average Load According to IEEE C57.91, the average continuous load is the rms load obtained by Equation 16.3-1 over a chosen period of the day. A period of 12 hours preceding and following the peak is suggested to be considered for the time interval of average load calculation. Time intervals (t) of 1 hour are suggested as a further simplification of the equation, which for a 12-hour period becomes Equation 16.3-2. The dashed line in Figure 16.3-2 shows the average load cycle constructed from the actual load cycle. Laverage (12h ) = 0.29 12 ∑L i =1 2 i 16.3-2 In fact, the average load determines the kWh billing revenue that will be obtained from serving the load, whereas peak load determines how much system capacity is required to serve that particular load group. 16.3.5 Load Factor The ratio of the average demand over a time interval to the maximum demand over the same time interval is the load factor. LDF % = Average Demand Power( kW ) × 100 Peak Load ( kW ) 16.3-3 Load factor can be calculated daily, monthly, and annually based on the load profile. 16.3.6 Load Diversity, Diversity Factor, and Demand Factor Load diversity is the difference between the sum of the individual maximum demands of loads on a system and 16-10 ∑ Individual Maximum Demands 16.3-5 System Maximum Demand Demand factor is the ratio of the maximum demand of a system, or part of a system, to the total connected load on the system. Demand factor is always less than one. “Demand factor” is a percentage by which the total connected load on a service or feeder is multiplied to determine the greatest probable load that the feeder will be called upon to carry. For example, in hospitals, hotels, apartment complexes, and dwelling units, it is not likely that all of the loads are connected to every branch-circuit served by a service or feeder would be “on” at the same time. Therefore, instead of sizing the feeder to carry the entire load on all of the branches, a percentage can be applied to this total load, and the components sized accordingly. Equation 16.3-6 formulates the size of a distribution transformer considering the incorporated factors: M S ( kVA) = ∑ i =1 N i × kWi × DFi × LFi PFi DivF 16.3-6 Where: S is the rated power of transformer. N is the number of loads (appliances) of the same type. kW is the rated power of each load. DF is demand factor. LF is the load factor. PF is the power factor of each load. M is the number of different type of loads. DivF is the diversity factor. Table 16.3-1 suggests typical values for load factor, diversity factor, and demand factor of loads (Pabla 2004). EPRI Underground Distribution Systems Reference Book Chapter 16: 16.3.7 Load Growth Estimating load growth includes an element of speculation. Load growth for each year into the future may be estimated from known factors such as planned installation and geographically related load patterns. If the annual rate of load growth is available, the load growth can be calculated for the transformer useful lifetime interval. The modified transformer rating is as shown in Equation 16.3-7. Transformers and Equipment In general, the method to determine the maximum diversified load of a number of houses consists of the following steps: • Define the type of houses based on major electrical usage, such as space heating, water heating, and air conditioning. • Identify all loads in the type of home being considered. • Determine the value of all Connected Loads (Lk) and the Maximum Non-Coincident Demand (MNCD). ST = S (1 + i )n 16.3-7 Where: S is the calculated power from Equation 16.3-6. i is the annual growth rate. n is the typical expected transformer life. • Determine the maximum peak load for each house type. • Use demand factors to determine the Maximum Coincident Demand (MCD) for groups of similar types of houses. • Develop charts of number of kW per home vs. number of homes, and total kW vs. number of homes. 16.3.8 Load Diversity Charts Load diversity considerations account for the fact that not all loads connected to the distribution transformer will be drawing power at the same time. Many individual loads are thermostatically controlled or cycling and therefore are not likely to be turned on at the same time—that is, not coincident. Transformer loading needs to accommodate the diversified or coincident load as opposed to the total connected load. For the purpose of characterizing loads on a distribution transformer, it is useful to determine the maximum peak load that is likely to occur when a group of similar load types are connected to the transformer. For instance, in practice, it is useful to know the ultimate peak load that will result from connecting a number of similar electrically heated residences to a distribution transformer. The total diversified or coincident load on the transformer will be less than the sum of the maximum peak demand of all the residences. Table 16.3-1 Typical values for Demand Factor, Diversity Factor, and Load Factor Diversity Factor Load Factor% Domestic 70-100 1.2-1.3 10-15 Commercial 90-100 1.1-1.2 25-30 Industrial (less than 500 kW) 70-80 - 60-65 Industrial (Above 500 kW) 85-90 - 70-80 Agricultural Based on the electrical energy equipment and load, houses can be classified into different major categories such as: • Natural gas heated with no air conditioning • Natural gas heated with air conditioning • Natural gas heated with air conditioning and electric water heating Demand Factor% Municipal Residential loads can be analyzed to determine the type of electrical equipment and its electrical load that would be connected in typical homes. Electrical equipment used in residential homes may be general (e.g., clothes washer, microwave oven, stereo, hair dryer, etc.), highenergy consuming (e.g., electric clothes dryer), or thermostatically controlled (e.g., refrigerator, air-conditioning, heating). For an average home, major appliances consume the most electrical energy (10.3-kWh/day). Lighting would consume an average of 4.1-kWh/day. Homes with air-conditioning units would utilize 7.3-kWh for cooling and motor blower. Houses with electric heating use, would utilize on average about 120 kWh/day, and average houses with electric water heating consume 14.7-kWh/day. • Natural gas heating and cooking with air conditioning • Central electrical heating, electrical water heating 100 1 25-30 15-20 1-1.5 90-100 with no air conditioning The definitions and relations for maximum coincident load, maximum noncoincident load, connected loads, 16-11 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book diversity factor, and demand factor are expressed in Equations 16.3-8 and 16.3-9. Maximum Coincident Demand ( MCD ) = DF . Lk A second method for developing diversity charts is using the “diversity factor” and the relation as shown in Equation 16.3-10. Maximum Diversified 16.3-8 ( DF1 ) . ⎡⎣1 − P N ⎤⎦ ( DF )N = N [1 − P ] ( Coincident ) Demand = 16.3-9 Where: DF is the demand factor. DF1 is the demand factor for one house (ratio of Maximum Demand to Total Connected Load for one house). Lk is the total connected load. N is the number of houses. P is the probability that one house has the same Coincident Loads as other houses within the same time period. With these relations, demand factors for different conditions can be established. ΣkWn Div ( Fact )n 16.3-10 Where: Σ kWn is the sum of the maximum non-diversified load. Table 16.3-2 is an example of a diversity chart for 1 to 20 houses for different scenarios including air conditioned, electric heating, natural gas appliances, etc. The reference size of the house is a range of 1250 to 1750 square feet. Larger or smaller homes or with a mix of loads would require appropriate adjustments to these load factors. Utilities should develop their own diversity charts based on their regional loading data. The demand factor approach was used in Table 16.3-2, where: Demand factor for N = 1 is 0.64. Probability factor is 0.7. Table 16.3-2 Diversity Chart for 1 to 20 Detached Houses Transformer Peak Load (kW) for Detached Houses (1250 to 1750 ft2) Peak Season Number of Houses 1 2 3 4 5 6 7 8 9 10 Demand Factor 0.64 0.55 0.47 0.41 0.36 0.31 0.28 0.25 0.23 0.21 Natural Gas Summer Heated – No A/C 8.6 14.9 19.4 22.7 25.2 27.1 28.6 29.9 30.9 31.8 Natural Gas Heated – Central Summer A/C 10.2 17.9 23.9 28.9 32.9 36.4 39.4 42.1 44.8 47.2 Natural Gas Heated – Natural Gas Stove Central A/C Summer 8.8 15.5 20.9 25.2 28.9 32.2 35.0 37.7 40.2 42.5 Natural Gas Heated – electric Water Heater Central A/C Summer 12.8 22.9 31.2 38.1 44.1 49.5 54.4 59.0 63.4 67.6 Electric Space and Water Heat Winter 14.8 27.7 39.1 49.6 59.4 68.8 77.8 68.6 95.2 103.7 16-12 EPRI Underground Distribution Systems Reference Book 16.4 Chapter 16: PAD-MOUNT TRANSFORMER SELECTION Transformers and Equipment been used for transformers with 65°C average winding temperature rise. 16.4.1 Loading Criteria and Transformer Rating The rated kVA of a transformer is the output that can be delivered for the time specified at rated secondary voltage and rated frequency without exceeding the specified temperature-rise limitations and within the limits established in the design spec. Selection of a transformer with an appropriate rating to serve to load should be done by considering several factors, including: • Transformer internal temperatures, such as hottest spot in the winding, top oil temperature, and average winding temperatures, • Transformer loss of life, and • Total lifetime cost of the transformer Two characteristic modes of operation can be identified with respect to the aging of insulation: Hottest-spot, Top Oil Temperatures, and Average Winding Temperature Transformer loading causes heat to be generated due to the winding and core losses, which results in a temperature rise of the oil and solid insulation. In addition, elevated loading increases the presence of oxygen, moisture, and their byproducts, and will accelerate the process of insulation aging. It is, therefore, important to ensure that the temperature rise is kept within the design limits. It is possible to relate normal and abnormal loading to the transformer hottest-spot temperature in order to understand how loading affects the life of the insulation. The hot-spot winding temperature is the principal factor in determining the degradation of the transformer due to loading and hence has major bearing on the transformer life. The hottest-spot temperature can be considered as the sum of the temperature of the cooling medium, the average temperature rise of the copper, and the hot-spot allowance. It is given by Equation 16.4-1 θ H = θ A + ΔθT + Δθ H ΔθT = θT − θ A Top oil temperature alone should not be used as a guide in loading transformers, because the difference between top oil and hot-spot copper temperatures varies with different designs and with load. Transformers may be operated above average continuous hottest-spot temperatures (95°C for 55°C rated transformers and 110°C for 65°C rated transformers) for short times, provided they are operated over much longer periods at temperatures below 95°C and 110°C, respectively. According to Equation 16.4-1, 110°C is the sum of the following: average winding rise (65°C), ambient (30°C), and hot spot rise (15°C). 16.4-1 Where: θΑ is the average ambient temperature. ΔθΤ is the top-oil rise over ambient temperature. ΔθΗ is the winding hottest-spot rise over top-oil temperature. It is not possible to measure the hottest-spot temperature directly in a traditional transformer because of the hazards in placing a temperature detector at the proper location. Standard allowances for hottest-spot rise over top-oil temperature have been obtained from laboratory tests. A hottest-spot allowance at rated load of 15°C has • Normal operation—corresponds to the normal life expectancy where the deterioration under varying conditions of load and ambient temperature is normal. • Overload operation—which is permitted when necessary without risking the reliability of the transformer. Loading of transformers above nameplate is a controversial subject. Transformers, at some time, may have to be overloaded during power system emergencies, in order to preserve system reliability. The maximum continuous load-carrying capacity of the transformer depends on its rating, on the temperature of the cooling medium, ambient temperature, and the level of accepted insulation aging governed by the effect of temperature and time. Overload capacity of a transformer is the maximum load for which the transformer can be subjected for a particular duration and considering a particular ambient temperature. The overload capacity depends on the average winding temperature rise that has been used to design the transformer. This temperature can be 55°C or 65°C, depending on the standard or request of end user at purchase time. When transformer purchase specifications include overloadability requirements for specific load profiles, in duration, frequency, and magnitude of overload, the manufacturer will adjust the design accordingly to guarantee such overload operation as normal, and can also do so with no loss of life as specified. This design adjustment usually results in a more substantial design and/or lower loss unit. 16-13 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book According to IEEE C57.91, normal life expectancy will result from operating continuously with hottest-spot conductor temperature of 110°C or with an equivalent daily transient cycle. Distribution transformer tests indicate that the normal life expectancy at a continuous hottest-spot temperature of 110°C is 20 years. bushings, leads, soldered connections, and tap changers; and heating of associated equipment such as cables, circuit breakers, fuses, disconnecting switches, and current transformers are examples of associated equipment. Any one of these may constitute the practical limit in load-carrying ability. Long-term and Short-time Emergency Overloads The permissible loading of transformers for normal life expectancy depends on the design of the particular transformer, its temperature rise at rated load, temperature of the cooling medium, duration of the overloads, the load factor, and the altitude above sea level if air is used as the cooling medium. ANSI-IEEE C57.92 (ANSI/IEEE 1981) has developed several permissible overload graphs for different types of transformers with respect to a number of factors. Figure 16.4-1 shows a typical overload capability curve for oil-immersed transformers from ANSI C57.92 for ambient temperature of 30oC and oil temperature rise of 65oC. For example, a liquid-filled transformer with a 50% continuous equivalent base load at 30°C ambient temperature could be loaded to 120% of full load nameplate rating for five hours without excessive loss of insulation life. If the loading strategy is based on the average winding temperature, as a typical value, for each degree Celsius in excess of 5°C that the average winding test temperature rise is below 65 °C, the transformer load may be increased above rated kVA by 1.0%. The 5°C margin is taken to provide a tolerance in the measurement of temperature rise. The load value thus obtained is the kVA load, which the transformer can carry at 65°C rise. Overloading of transformers should not be practiced without investigation of the various limitations involved, other than winding and oil temperature. Oil expansion; pressure in sealed- type units; heating of For a very short-time loading that is less than ½ hour, it is possible to load transformers up to 300%, with the maximum hottest spot of 200oC and top-oil temperature of 120oC. If the high loading factor continues more than ½ hour, the insulation aging takes place. It should be clearly understood that, while the insulation aging rate information is considered to be conservative and helpful in estimating the relative loss of life due to loads above nameplate rating under various conditions, this information is not intended to furnish the sole basis for calculating the normal life expectancy of transformer insulation. The uncertainty of service conditions and the wide range in ratings covered should be considered in determining a loading schedule. As a guide, utilities consider an average loss of life of 4% per day in any one emergency operation to be reasonable. Percent Loss-of-Life due to Loading Aging or deterioration of insulation is a function of time and temperature. When cellulose ages, the cellulose chains are cut in a process called chain scission, reducing the average length of the cellulose chains and resulting in shorter fibers. This can be measured by Degree of Polymerization, or so-called DP. The rate of degradation is very slow at room temperature. At elevated temperatures, however, the rate of degradation increases exponentially, effectively doubling for approximately every 8°C increase in temperature. Because the temperature distribution in most apparatus is not uniform, the part that is operating at the highest temperature will ordinarily undergo the greatest deterioration. Therefore, it is usual to consider the effects produced by the highest temperature, or the hottest spot. Figure 16.4-1 Permissible overload for varying periods of time for oil-filled transformers with 65oC rise based on the initial load, normal life expectancy, ambient = 30oC (ANSI C57.92). 16-14 Traditionally NEMA developed graphs of % of loss of life of transformers versus the hottest spot temperature, as shown in Figure 16.4-2. The basis of the aging factor modeled by IEEE is the exponential curve of aging versus temperature. EPRI Underground Distribution Systems Reference Book Chapter 16: IEEE C57.91-1995 (IEEE 1995) has a well-defined model for transformer aging and life of insulation. It includes a per unit life model to calculate the aging of transformers, as shown in Equation 16.4-2. Transformers and Equipment types. This standard defines “insulation aging rate”, FAA, as shown in Equation 16.4-3. ⎛ ⎜ ⎜θ FAA = e ⎝ ⎞ A A − ⎟ + 273 θ HS + 273 ⎟⎠ 16.4-3 HS ,R B PerUnit Life = Ae θH + 273 16.4-2 where θΗ is the winding hottest spot in °C, A = 2 × 10−18 and B is a constant equal to 15,000 for most insulation Where FAA is the insulation aging rate, θHS,R is the reference hot spot temperature for the insulation, and θHS is the hot spot temperature at which aging is evaluated. A curve of FAA versus hottest-spot temperature for a 65°C rise insulation system is shown in Figure 16.4-3. FAA has a value greater than 1 for winding hottest-spot temperatures greater than the reference temperature 110°C and less than 1 for temperatures below 110°C. Reduced Life Expectancy with Heavy Loading IEEE C57.91 has defined a method to calculate the reduced life expectancy based on “aging accelerated factor”, FAA as shown in Figure 16.4-3. The reduced life expectancy, RLF , is calculated from Equation 16.4-4. % RLF = Feq × t Normal Life × 100 16.4-4 N Feq = ( ∑ FAAn Δtn ) n =1 ∑ Δt n =1 Figure 16.4-2 Loss of life versus temperature for different time periods, 65oC rise time (NEMA TR-98-1964). 16.4-5 N n Where: Feq is equivalent aging factor for the total time period. N is the total number of intervals. FAAn is aging acceleration factor for the temperature that exists during the time interval Δ tn . t is the time period in hours. Figure 16.4-3 Insulation’s aging acceleration factor (IEEE C57.91-1995). 16-15 Chapter 16: Transformers and Equipment Normal Life is defined by manufacturer. As a benchmark for a distribution transformer, normal life is 20 years for a well-dried, oxygen-free 65oC average winding temperature rise insulation at a reference temperature of 110oC. Unusual Service Condition A number of factors related to transformer loading are considered unusual service conditions such as: • Increase of ambient temperature • Installation in a height more than 1000 m (3300 ft) The design of distribution transformers usually considers ambient temperature of 30oC. If the average of ambient temperature increases, the loading should be lowered to keep the normal life expectancy. A guideline provided by IEEE C57.91 suggests a load de-rating of 1.5% for each o C up to 50 o C. The load is allowed to increase by 1% for each oC lower than 30o C. Average ambient temperatures can be considered to cover 24-hour periods. The maximum ambient temperature in 24 hours should not be more than 10°C above the average temperature. The effect of the decreased air density due to high altitude is to increase the temperature rise of transformers, because they are dependent upon air for the dissipation of heat losses. If the transformer is installed at a height of 1000 m (3300 ft) above sea level, a de-rating factor needs to be considered as shown in Figure 16.4-4. Note that if enough information has been delivered to the transformer designer, the effect of de-rating due to high ambient temperature or high altitude level is usually considered by the designer. Therefore, the nameplate ratings do not need to be de-rated. For transformers installed in subsurface manholes and vaults of minimum size with natural ventilation through Figure 16.4-4 Permissible KVA loading and ambient temperature for altitude above 1000 m (ANSI C.57.12.00). 16-16 EPRI Underground Distribution Systems Reference Book roof gratings, a higher ambient temperature than the outdoor air is expected. The amount of increase depends on the design of the manholes and vaults, net opening area of the roof gratings, and the adjacent subsurface structures. Therefore, the increase in effective ambient temperature for expected transformer losses must be determined before loading limitations can be estimated. Total Lifetime Cost As discussed in Section 16.2.7, “Cost of Loss Formula,” the transformer cost has three components: capital investment, no-load loss, and load loss. If the end-user provides the energy price with the purchase request, the designer can develop a transformer design that will minimize the total lifetime cost including the cost of losses. The result of this process is the cheapest transformer in the useful life period—i.e., with the lowest total owning cost—optimized for a given application. The following considers the total cost of losses for transformers loaded at different fractions of their rating. Typically a transformer is designed to have a minimum loss when operated at about 50% of rating. However, a larger transformer operated at a lower fraction of rating, may have a smaller cost of losses than a smaller unit operated at 50% of rating. This circumstance will be particularly true in situations with significant annual load growth. The present value of the total cost of losses can be calculated by calculating the loss in each of the next 40 years and then applying a discount factor to account for inflation, and the cost of capital or the expected rate of return on capital investment. The losses in any one year are calculated as the sum of load and no-load losses. The no-load power loss is simply the no-load loss expressed as a percent of rating times the rating of the transformer. Because the no-load loss is constant, this power loss is simply multiplied by the hours in a year to obtain the energy loss. The load losses in a transformer vary with the load. The manufacturer usually states load losses at rated load as a percentage of transformer rating. The value of loss at other loads can be estimated by multiplying by the ratio of the loads squared, because the loss increases with the square of the current. This procedure ignores the decrease in loss at lower temperatures caused by the decrease in resistance as the temperature decreases (approximately 25% from 90ºC to 20ºC), because this decrease is small compared to the quadratic decrease. The peak power loss is calculated at the peak load, and the energy loss is calculated at the peak loss (at peak load) multiplied by the loss factor to give the energy EPRI Underground Distribution Systems Reference Book loss. The loss factor can be an input parameter, or it can be calculated from the load factor using an assumed load profile by the empirical equation LF = 0.85(LD2) + 0.15 LD, where LF is the loss factor and LD is the load factor. If the exact load profile of a transformer is known, such as hourly load for a year, then the loss factor can be calculated from the load data, and the loss calculation will be exact. Chapter 16: Transformers and Equipment on the time for which the peak load occurs, the previous load condition, and the thermal time constant of the transformer. Short time peaks of up to 200% of rating can be justifiable. The input parameters to the calculation procedure are: Optimal transformer sizing can be determined using the Diversity Chart and Figure 16.4-5. Using the peak load calculation from Table 7 of IEEE C57, the first vertical intercept with a transformer plot determines the most optimum size in terms of lifetime ownership cost. • • • • • • • Transformer size selection, at any specific load level, is controlled by the thermal load limit, not by the cost of losses. This conclusion depends on the ratio of no-load loss to load loss for the particular set of transformers. It will be true as long as the difference in no-load loss from one transformer size to the next is larger than the load loss of the smaller size transformer when loaded near its rating. Load loss for each transformer rating Noload loss for each transformer rating Cost of losses (kW and kWh) Real discount rate Annual load growth rate Load factor Loss factor Figure 16.4-5 shows the present value of the cost of losses over a 40-year life versus peak load in the first year. Single–phase, 4-kV polemount transformer data are used in this example for sizes ranging between 10 and 100 kVA to provide the widest data coverage. The lowest losses are often for a transformer that is severely undersized. To make a reasonable limit on the loading, the “thermal limits” are shown as vertical dashed lines based on IEEE C57 – Distribution, Power and Regulating Transformers (Table 7, 2-hour peak load duration at 10 °C and 30° C [winter and summer operation] 65 ° C rise.). For winter and summer operation, the peak limit was set at 1.87 and 1.57, respectively. This is not a firm limit, because the loss of life of a transformer depends The overall conclusion is that a utility cannot reduce transformer losses by going to a larger size transformer that will have lower load losses. The minimum loss costs are achieved if the smallest possible transformer is selected based on thermal loading limits. 16.4.2 Other Parameters for Transformer Selection Selection of the appropriate transformer should also include consideration of: • Preferred power ratings • Short-circuit capacity • Noise level Figure 16.4-5 Cost of ownership vs. initial load – 4 kV pole transformers – single phase. 16-17 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book Preferred Power Ratings Despite the selection of an exact power rating that may be optimal for an application, distribution transformers are generally produced in a number of preferred ratings. The symmetrical short-circuit current can be calculated as follows: I SC = Preferred continuous kVA ratings of single-phase and three-phase distribution and power transformers based on an average winding rise by resistance of 65o C are defined as following: IEEE Std C57.12.00 limits determine the short-circuit current duration of distribution transformers as shown in Equation 16.4-6. 1250 I2 ts = 2 ts = if if Based on IEEE Std C57.12.00, multi-winding transformers shall be considered to have system fault power supplied at no more than two sets of un-faulted terminals rated greater than 35% of the terminal kVA of the highest capacity winding. Noise Level Transformers in service cause sound, which may cause discomfort to people in the environment in the long term. This is mainly the problem of power transformers. However, it can be an issue for large distribution transformers too. Sound can be defined as the pressure variation in air that the human ear can detect. The normal range of hearing of a healthy young person is from approximately 20 Hz to 20 kHz. The weakest sound that an ear can detect is dependent on the frequency. Sound pressure level, LP, expressed in dB, is defined in Equation 16.4-8 S ≤ 500kVA 16.4-6 S > 500kVA LP = 10 log Accordingly, the above standard has determined the short-circuit withstand capability of distribution transformers based on the symmetrical short-circuit current shown in Table 16.4-1. p2 p02 Three Phase (kVA) Withstand Capability per Unit of Base Current (Symmetrical) 5-25 15-75 40 37.5-110 112.5-300 35 167-500 500 25 Single Phase (kVA) Above 500 kVA 16.4-8 Where: po is the reference level equal to 20μPa. p is the sound pressure measured by a microphone. Table 16.4-1 Short-circuit Withstand Capability (ANSI/IEEE C57.12.00) 16-18 16.4-7 Where: ISC is the symmetrical short-circuit current. IR is the rated current. ZS is the system impedance connected to the transformer. ZT is the transformer short-circuit impedance. Three-Phase (kVA): 15, 30, 45, 75, 112.5, 150, 225, 300, 500, 750, 1000, 1500, 2000, 2500, 3750, 5000 Short-circuit Capacity Another of the important factors for selecting a transformer is the short-circuit capacity. Transformers should be designed and constructed to withstand the mechanical and thermal stresses produced by external short circuits. The external short circuits shall include three-phase, single line-to-ground, double line-toground, and line-to-line faults on any one set of terminals at a time. 3( ZS + ZT ) IR I = ≅ R ZS % + ZT % ZT % Single-Phase (kVA): 5, 10, 15, 25, 37.5, 50, 75, 100, 167, 250, 333, 500, 800,1250, 1600, 2500, 3300 To reduce inventory, some utilities seek to further limit the ratings of the transformers that they purchase. U Should be calculated using transformer impedance only. EPRI Underground Distribution Systems Reference Book Chapter 16: To provide a feeling, a quiet living area has a sound pressure level of about 45 dB, and a city street with heavy traffic can have 95 dB sound pressure. The dominant generating source of transformer sound is core magnetization. When the magnetic flux changes, the magnetic domains change their directions. Therefore, when excited by a sinusoidal flux, the core sounds. In three-phase cores, the changes of magnetic domain for each core limb do not occur simultaneously, which means that the whole core is subjected to pulsating distortions. Comprehensive investigations are made to correlate human perception of loudness at various frequencies and sound pressure. To imitate the response curves of the human ear, three different filters are inserted in the measuring equipment, named Aweighted, B-weighted, and C-weighted filters. They imitate the curves going through 40, 70, and 100 dB, respectively. For transformers, the frequency spectra of the audible sound consists primarily of the even harmonics of the power frequency; thus, for a 60-Hz power system, the audible sound spectra consists of tones at 120 Hz, 240 Hz, 360 Hz, 480 Hz, etc. A transformer “hum” is usually in the range of 100 Hz to 300 Hz. Depending on other nearby ambient noise, the transformer sounds might not be noticeable. The noise of a transformer is defined as the A-weighted sound pressure level measured in dB at a specified measuring surface with a sound level meter, and then converted to a sound power, LW, with the formula shown in Equation 16.4-9. LW = LP + LS 16.4-9 Where: LS is the measuring surface level in dB. Transformers and Equipment option, it is suggested to order transformers designed at 3 dB below NEMA standard sound levels. Methods are available to the transformer designer to control the transformer noise: • Reducing the core flux density from 1.5 T - 1.6 T to a range of 1.2 T-1.3 T. This can be done either by increasing the core cross section, or by increasing the number of turns in the winding. • Making a heavier framework for the core • Inserting pad of damping material between core layers, or between active part and tank Dimensions and Relation between KVA and Size There is a certain fundamental relationship between the KVA rating of transformers and their physical size. A rather obvious relationship is the fact that large transformers of the same voltage have lower loss than smaller units. As a typical scaling rule, the length, width, and height are scaled as . Where D represents all directions of the dimension. To overcome the limitation of the transformer size, manufacturers have several options, some of which result in a tradeoff in transformer performance: • Reducing the size of core by using Hi-B material or changing the flux density design value, which results higher core loss and noise • Reducing the space between windings • Reducing the oil volume by using thermally upgraded insulation Table 16.4-2 can be used as a guideline for the noise level of distribution transformers up to 5 MVA. As an Each of the above solutions may affect other design parameters, which need to be fully evaluated before manufacturing. Table 16.4-2 Average Sound Power Level for Distribution Transformers (NEMA TR-1, 1993) Power(kVA)/Sound Power (dB) 0-50 51-100 101-300 301-500 700-1000 1600 2000 2500 3000 4000 5000 Oil-Type 48 51 55 56 57 60 61 62 63 64 65 Dry-Type Self-cooled (open) 50 55 58 60 64 66 66 68 68 70 71 Dry-type Self-cooled (sealed) 50 55 57 59 63 65 65 66 66 68 69 16-19 Chapter 16: 16.5 Transformers and Equipment EPRI Underground Distribution Systems Reference Book TRANSFORMER COOLING 16.5.1 Mineral Oils and Alternative Ester Oils Traditionally, transformer dielectric insulating fluid has been a refined naphthenic mineral oil that is stable at high temperatures and has excellent electrical insulating properties. Transformers for indoor use either have been a dry type, or have used a less-flammable liquid. Up to the 1970s, polychlorinated biphenyls (PCBs) were used as a dielectric fluid, because they are not flammable. PCBs are toxic, and under incomplete combustion, can form highly toxic products such as furans. Starting in the early 1970s, concerns about the toxicity of PCBs led to their being banned in many countries. Recently nontoxic, stable silicon-based or fluorinated hydrocarbons have been used, where the added expense of a fireresistant liquid offset the additional building cost for a transformer vault. In the early 20th century, there was interest in seed-oilbased coolants, but compared to mineral oils, these had a higher pour point and inferior resistance to oxidation. Synthetic esters found specialty applications where high flash point and lower pour point were desired. However, the high cost of synthetic esters limited widespread use. In the early 1990s, natural esters were revisited due to environmental regulations. The natural ester products developed, shared many of the desirable products of the synthetic esters, and were more economical. Combustion-resistant vegetable oil-based dielectric coolants and synthetic pentaerythritol tetra fatty acid esters are becoming increasingly common as alternatives to mineral oil. Transformer insulating fluids can be compared based on features such as: availability, their effect on losses, heat transfer properties, flash and fire points, dielectric breakdown, oxidative stability, decomposition, water solubility, long-term aging, sludging, climatic effects, economics, and maintenance relative to standard approved mineral oils. Table 16.5-1 provides a comparison of many of these parameters for mineral oils and natural ester oils. As is evident from Table 16.5-1, natural ester dielectric oils offer several advantages over mineral oils. These advantages include their availability from renewable domestic sources, their nontoxicity, their being readily biodegradable, and their being non-carcinogenic. Natural esters have a higher flash point (i.e., lower volatility), superior thermal conductivity, and no sulphur content, and offer a significant reduction in damage to cellulose insulation. Any two adjacent conductors form a capacitor. In an ideal capacitor, the phase difference between an applied AC voltage and the current is 90°, and the power dissipated is zero. If the dielectric between the conductors is less than ideal, the phase difference will be less than 90°, and some power dissipation will occur. To keep this loss low, it is desirable to have the dielectric as near to ideal as is practical. For insulating oils, the value for this characteristic is called the power factor or loss tangent (dissipation factor) and is expressed as a percentage at a specified temperature. These values are determined experimentally and represent trigonometric functions of the angle of phase difference. With the particular functions used, a value of zero would represent a 90° phase difference and the ideal condition; therefore, low values are desirable. In Table 16.5-1, it can be seen that the natural esters 16-20 0.003/0.06 0.885 330 ≥350 ≥30/≥20/NA ≤0.2/≤0.2 0.04 120%±33% after 28 days 75 20+ -18 0.45 @ 20oC 3.0 x10-4 145 160 >35/>28/>180 0.01/0.01 ≤0.03 28% to 49% after 28 days 45 20+ -47 Flash Point ASTM D93 (closed cup) oC Fire Point ASTM D92 (open cup) oC Climatic Effects, Pour Point ASTM D97 oC Mineral Oil Long Term Aging, Projected Life Years 4.0 x 10-4 Water Content ppm @ 15oC Thermal Conductivity cal/(cm.sec. oC 0.6 Aquatic Biodegradation Specific Heat Cal/g/oC @100oC 0.92 Neutralization Number ASTM D974 mg. KOH/g Specific Gravity 0.15/3.0 Sludging (Oxidation Stability) ASTM D2440 72 h/164h % Power Factor Dissipation Factor ASTM D924 % @ 25oC/100oC Natural Ester Oil Dielectric BreakdownASTM D1816 Minimum/gap/ impulse kV Type Table 16.5-1 Transformer Oil Comparison EPRI Underground Distribution Systems Reference Book have higher power dissipation factor values than the mineral oils. Other disadvantages of the natural esters are higher oxidation, pour points, and water retention. Oxidation and sludging are the weakest points of ester oils. Exposure to atmospheric oxygen can lead to sludging, acid by-products, and finally polymerization of the oils. Natural esters are often supplemented with anti-oxidants to address this limitation. In North America, transformers are normally sealed, which limits exposure to oxygen. Once manufactured, the oils are shipped with nitrogen blanketing in the container void to prevent oxidation during transport and storage. Oxidation and contamination of oil can cause the power factor of an oil to rise, so determination of this property may provide useful information about used electrical insulating oil. Because these values vary with temperatures, comparisons must always be made at the same temperature. When oils are applied properly, oxidation is a low concern. When specifying ester oils, one should confirm that the transformer is sealed. The higher temperature pour point is not deemed a problem for small, sealed transformers because the dielectric properties are maintained. As the oil warms up after the transformer is energized, its fluid properties are restored. For outdoor transformers, use in transformers with mechanical oil circulation or internal switches may be an issue in very cold climates. Indoor transformers with controlled ambient above the pour point do not have these restrictions. Water content is used to monitor a dielectric fluid’s quality. It is an indicator of possible oil deterioration, which could, for instance, lead to dielectric breakdown. The values used are based on the relative saturation of water in the dielectric fluid. The relative saturation is based on the amount of water dissolved in the oil divided by the total amount of water that the oil could hold at that temperature. The dielectric strength of oil starts to fall when saturation reaches about 50%. For petroleum-based oils, 50% at room temperature is 30 to 35 mg/kg. Esters hold 500-600 mg/kg water at room temperature. In a closed system, the affinity of the ester oils for water has been observed to be a desirable trait. Mineral oil lacks this property, leaving water to migrate to the kraft insulating papers. Moisture in the paper causes it to age. Residual acid in the paper catalyzes hydrolysis and degradation of the cellulose results. Chapter 16: Transformers and Equipment The natural ester oils may not meet some criteria of standards such as pour point, water content, and sludging. A separate set of acceptance criteria may be needed for these oils or limits of application (e.g., outdoor transformers not employing external cooling radiators, circulating pumps, etc.). Compared to standard mineral transformer oil, ester oils are more costly. The capital cost of a new transformer filled with the new oils is estimated at 1.25 to 1.30 times the same transformer containing mineral oil. For this price differential, a number of advantages are cited, usually the higher flash point and lower life cycle environmental cost (i.e., spills and end-of-life disposal). As with any transformer asset, periodic sampling and analysis of the oil are recommended as a preventative measure and would be part of the life-cycle cost. Even though toxicity of ester oils is low, the rules for cleanup of spills are the same as any other substance. The only difference is the cleanup cost should be lower because special precautions are not needed compared to hazardous substances. In terms of medical issues, the MSDS sheets call only for standard precautions when working with the eyes —to avoid getting oil in the eyes, inhaling the mists, or handling oil if hot. Information about long-term aging of the ester oils is not well known, because the products have not been on the market long. The longest time in service is about 10 years. However, some aging tests have been performed, and field-sampling tests have been conducted by the U.S. EPA. Since 1996, more than 17,000 transformers have been built with natural ester fluid, primarily distribution low-power, pad-mounted, and pole-mounted types, ranging from 10 kVA up to 10 MVA. In 2001, the first medium-power transformer (50 MVA) was retrofilled with natural ester oil. Accelerated aging tests per IEEE C57.100™ (IEEE 1999) show that the paperaging range is significantly slower when aged in natural esters vs. mineral oil. Full-scale tests per C57.100 resulted in units lasting between three and four times the required standard average life. Based on these results, it has been calculated that the natural ester tested has a 21oC higher thermal index than mineral oil. The improved thermal index means longer life at a given temperature or the ability to operate at higher temperatures for a given life. An ASTM standard and an IEEE maintenance guide have been developed for ester oils. 16-21 Chapter 16: 16.6 Transformers and Equipment EPRI Underground Distribution Systems Reference Book INTERPRETATION OF TEST RESULTS A number of measurements and tests can be performed on distribution transformers to assess the condition of the oil, the solid insulation, the windings, and the transformer internal construction. Though many of the tests are relatively simple to perform, interpretation of the meaning of the test results requires some expertise. 16.6.1 Oil Tests Interpretation Standard methods are available to assess the quality of oil; however, these oil tests are not commonly used on small rating distribution transformers. IEEE, ASTM, and other standards do not specify interpretation of the oil test results specifically for distribution transformers, such as pad-mounted or network transformers. The suggested numbers in Table 16.6-1 provide a guideline for interpreting oil test results. Table 16.6-1 summarizes the oil quality test standards and recommended limits according to the standards for “service-aged insulating oil.” Dissolved Gas Analysis A simple interpretation method for dissolved gas analysis (DGA) results is the “Key Gas Method,” as shown in Table 16.6-2. It should be noted that small amounts of H2, CH4, CO, and CO2 are generated by normal aging. IEEE Std. C57.104-1991, “IEEE Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers” (IEEE 1991) introduces a four-condition DGA guide to classify risks to transformers with no previous problems. This guide uses combinations of individual gases and total dissolved combustible gas concentration (TDCG). Table 16.6-3 summarizes the DGA key gas limits suggested by IEEE. However, these numbers have been generated based on power transformer units, and no data is available for distribution transformers in this or other standards. Table 16.6-3 assumes that no previous tests on the transformer for dissolved gas analysis have been made or that no recent history exists. If a previous analysis exists, it should be reviewed to determine if the situation is stable or unstable. Table 16.6-1 Recommended Oil Quality Tests for Service-aged Insulating Oil (IEEE Std C57.106-2006) Interfacial tension (IFT) Neutralization number (acidity) PCB ASTM D924-99 @ 25 0C [max] ASTM D-971-91 [min] ASTM D974-92 [max] ASTM 4059-91 [max] 1816:23kV 877: 26 kV 0.1% 35 mN/m 0.03 mg KOH/g 2 1mm gap:23kV 0.5% 24 mN/m 0.2 mg KOH/g 50 Test Dielectric Strength Dissipation Factor Standard ASTM D1816 -97 (1 mm gap) ASTM 877 [min] Limit (new oil) Limit (service aged oil) Table 16.6-2 Key Gas Interpretation Method Key Gas Secondary Gas Fault Pattern Possible Root Cause H2 CH4 and minor C2H6 and C2H4 Low-energy partial discharge Aging of insulation, possible carbon particles in oil, poor grounding of metal objects, loosed lead, floating metal, or contamination C2H4 CH4 and minor H2 and C2H6 Oil overheating Paper insulation destroyed, metal discoloration, oil heavily carbonized. C2H2 H2 and minor CH4 and C2H4 High energy Arcing Poor contacts in leads, weakened insulation from aging, carbonized oil. CO CO2 If the fault involves and oil-impregConductor overheating nated structure CH4 and C2H4 Overloading or cooling problem, bad connection in leads, stray magnetic flux, discoloration of paper. Table 16.6-3 IEEE Dissolved Key Gas Concentration Limits (in ppm) Status H2 CH4 C2H2 C2H4 C2H6 CO CO2 Condition 1 100 120 35 50 65 350 2500 720 Condition 2 101-700 121-400 36-50 51-100 66-100 351-570 2500-4000 721-1920 Condition 3 701-1800 401-1000 51-80 101-200 101-150 571-1400 4001-10000 1921-4630 Condition 4 >1800 >1000 >80 >200 >150 >1400 >10000 >4630 16-22 TDCG EPRI Underground Distribution Systems Reference Book Condition 1: TDCG below 720; satisfactory operation; any individual combustible gas exceeding specified levels should prompt additional investigation. Condition 2: Action should be taken to establish a trend quarterly. Condition 3: High level of decomposition; immediate action should be taken to establish a trend monthly. Condition 4: Continued operation could result in failure of the transformer. Immediate action required to remove the transformer from service. In interpreting DGA, relative gas concentrations are found to be more useful than actual concentrations. If a possible fault is suspected, a scheme developed by Rogers (IEEE 1991) and later simplified by the IEEE, can be used to define transformer condition. The three-ratio version of the Rogers Ratio Method uses the following ratios: R 1 = C 2 H 2 / C 2 H 4 , R 2 = CH 4 /H 2 , R 3 = C 2 H 4 / C 2 H 6. Figure 16.6-1 is the flowchart recommended by IEEE to interpret the Rogers Ratio Method. It is important to mention that the gas ratio method is for determining the possible fault type, not for detecting the presence of a fault. The validity of this method is based on correlation Chapter 16: Transformers and Equipment of the results of a number of failure investigations with the gas analysis for each case. Another ratio method is the “Doernenburg method,” which is very similar to the Rogers method with 5 ratios. Another DGA interpretation technique proposed by IEC 60599 is based on the Duval triangle. This method provides a coded list of faults detectable by DGA of a faulty transformer. CIGRE (International Council on Large Electric Systems), one of the leading worldwide organizations on electrical power systems, has reported phenomena called “stray gassing,” which occurs when some types of insulating oils are heated at relatively low temperatures (100 to 120°C), producing hydrogen or hydrocarbons. This gas formation seems to reach a plateau after some time and then stops. Under certain conditions, stray gassing may interfere with DGA evaluation. CIGRE has found that at 120°C, the main gas produced, in general, is hydrogen, followed by methane. The production of hydrogen is temperature dependent. Development of saturated hydrocarbons without fault is a common issue that can easily be misinterpreted using the Rogers or Duval methods. Typical for these cases is the production of ethane, ethylene, and methane in high amounts. The ratio of ethane to ethylene, and especially ethylene to propylene, may be higher than 10. Ethane, ethylene, and methane increase steadily in the first years Figure 16.6-1 IEEE recommendation for Rogers Ratio Method. R1= C2H2/ C2H4 , R2= CH4/H2 , R3= C2H4/ C2H6 16-23 Chapter 16: Transformers and Equipment after commissioning, while the amounts of hydrogen and ethylene stay constant and low. Such behavior has been observed in new transformers as well as in old ones. The interpretation of DGA usually indicates a hot spot below 150°C; however, the transformers are failurefree (Duval 2004). Dielectric Test The dielectric test measures the voltage at which oil breaks down electrically. This test can give a good indication of the amount of contaminants such as dirt, water, and oxidation particles. The IEEE guide for insulating oil equipment prefers the ASTM D-1816 (ASTM 2004) dielectric test method rather than the ASTM D877 (ASTM 2002), because the electrodes are closer to those in real application, and the test is more sensitive to moisture than the ASTM D-877. If ASTM D 877 is used instead of ASTM D1816 for dielectric strength, the limit is 26 kV rather than 23 kV. If a 2 mm gap is used for ASTM D1816, 40 kV is recommended. It should be noted, however, that high dielectric strength is no guarantee that the oil is not contaminated. Tests on oil from a failed transformer are not indicative of the oil quality just before failure, because carbon and debris from the failure will be suspended in the oil. Although rarely performed, carbon and other particulate matter can be removed by filtration methods prior to dielectric testing. Power Dissipation Factor The dissipation factor is a measure of the power lost when an electrical insulating liquid is subjected to an ac field. The power is dissipated as heat within the fluid. A low-value dissipation factor means that the fluid will cause little of the applied power to be lost. The test is used as a check on the deterioration and contamination of insulating oil because of its sensitivity to ionic contaminants. ASTM D924 (ASTM 2008a) is a reference for this test. This test may be satisfactorily performed in the field, as well as in a laboratory environment. A visual check should be performed to ensure that the sample does not contain air bubbles due to agitation during transport. The maximum recommended levels of percent power factor for different categories of new and service aged oils are shown in Table 16.6-4, according to IEEE Std 62-1995 (IEEE 1995a). High levels of power factor (>0.5% @ 25 °C) in oil are of concern, because contaminants can collect in areas of high electrical stress in the winding. Very high power 16-24 EPRI Underground Distribution Systems Reference Book factor (>1.0% at 25 °C) in oil can be caused by the presence of free water, which could be hazardous to the operation of a transformer. Oxidation, free water, wet particles, contamination, and material incompatibility are all possible sources of high power factor in oil. Polychlorinated Biphenyl (PCB) According to IEEE Std 62-1995, low polychlorinated biphenyl (PCB) concentration (<50 ppm) generally indicates an extremely low risk (according to the U.S. EPA), and the oil is classified as noncontaminated. A moderate PCB concentration (50 ppm to 500 ppm) causes the oil to be classified as contaminated. Any concentration above 500 ppm is considered as if it were pure PCB. Local governmental regulations and environmental legislations may require specific values of even lower than 50 ppm. Some regulations do not allow moderate concentration (50 ppm to 500 ppm) near sensitive areas such as a hospital, food or feed processing plant, senior care facility, pre-school/daycare, or a school. The term “Non-PCB” means PCB free from origin of manufacture and tested out at less than 1 ppm PCB. If a high level of PCBs was detected, the oil needs to be retrofilled. To reduce the PCB concentration in the core and coil of a PCB-contaminated transformer, the contaminated oil is drained out, and new replacement oil is put in its place—a process called “retrofilling.” The only time that it would be logical to retrofill a transformer to reclassify it to non-PCB status is if the transformer has a reasonable life expectancy. As a routine, all transformers that come out of service should be sampled and analyzed for PCBs before they are repaired, disposed, or recycled. Retrofills cannot reach a level of 1 ppm; more likely, less than 50 ppm PCB is more reasonable due to leach-back from 10% typical retained oil volume in saturated insulation. Less than 50 ppm PCB is not the same as non-PCB, and in some ways is handled differently. Table 16.6-4 Maximum Suggested Dissipation Power Factors for Different Categories of New and Service Aged Oils (IEEE Std 62) Power Factor @25 oC Power Factor @100 oC New oil as received 0.05 0.3 New oil in new transformer 0.15 1.5 New oil after filling the transformer, prior to energizing 0.1 - Service-aged oil 0.5 - Type of Oil EPRI Underground Distribution Systems Reference Book Acid Number and Inter Facial Tension (IFT) ASTM D974 (ASTM 2008b) is the traditional colorchange indicator method of titrating the acids with a mild (0.1 N) KOH solution. On some service-aged liquids, the color may be so dark as to impair the ability of the technician to determine the indicator color change in ASTM D974, so ASTM D664 (ASTM 2009) is used instead. IEEE maximum acceptance value for acid number is 0.2 mg KOH/g. Acceptable limits for IFT vary with operating voltage. For a service-aged oil, the minimum acceptance value is 24 mN/m. For oils in service, a decreasing value indicates the accumulation of contaminants, oxidation products, or both. 16.6.2 Transformer Tests Interpretation Insulation Resistance and Polarization Index The purpose of the transformer insulation resistance test is to measure the condition of a “major” insulation system—i.e., the insulation between a winding and ground (core) or between two windings. IEEE C57.125-1991 recommends 500 V, 1000 V, or 2500 V DC to be applied to the transformer winding. The resistance of each mea- surement should not be smaller than R = 1.5UW . R is KVA in MΩ measured at 20 0C, and UW is the winding voltage in kV. If the winding is Y-connected, then UW is the phase-to-ground voltage. If it is Delta-connected, then UW is equal to phase-to-phase voltage. KVA is the rated power of the winding under the test. Megaohm meter test results below this minimum value would indicate probable insulation breakdown. If a transformer passes the insulation resistance test, before applying any overvoltage test, it is recommended to do a Polarization Index (PI) test. The polarization index is a ratio of the Megohm resistance at the end of a 10-minute test, to that at the end of a 1-minute test at a constant voltage. Another common way for PI calculation is the ratio of resistance readings that are taken 15 and 60 seconds after connecting the voltage. Table 16.6-5 is a guide to interpretation of the PI test results. Table 16.6-5 Test Interpretation Polarization Index Insulation Condition Less than 1 Dangerous 1.0 - 1.1 Poor 1.1 - 1.25 Questionable 1.25 - 2.0 Fair Above 2.0 Good Chapter 16: Transformers and Equipment Power Factor In general, power factor measurement equipment comes with three basic modes of operation: grounded specimen test, grounded specimen with guard, and ungrounded. The three measurement modes allow measurement of the current leaking back to the test set on each lead, individually and together. In general, a power factor of less than 1% is considered good; 1-2% is questionable; and if it exceeds 2%, action should be taken. Practically, the evaluation is not only based on a single power factor data point but is also based on the history of the change in power factor. Values obtained at the time of the original tests are used as benchmarks to determine the amount of insulation deterioration on subsequent tests. The power factor of an insulation system should not increase with an increase in applied ac voltage. If it does increase as the ac voltage is increased, there is a problem in the insulation system. Another value of the power factor measurement is that it will detect voids in the insulation system that may be causing high partial discharges. Table 16.6-6 is a guideline to interpret the insulation power factor test. The tests can be done, respectively, on high-voltage winding to ground, high- to low-voltage winding, and low-voltage winding to ground. Table 16.6-6 Power Factor Test Interpretation Power Factor Insulation Condition Above 2.0% Dangerous wet transformer 1.0 – 2.0 Investigate 0.5 – 1.0 Deteriorated Less than 0.5 Good Turns Ratio The purpose of a turn-ratio test basically is to diagnose a problem in the winding turn-to-turn or shorted multiturn insulation system in a transformer. This test detects primarily inner winding short circuits. A very low voltage ac source is used to determine the turn ratio. Two windings on one phase of a transformer are connected to the instrument, and the internal bridge elements are varied to produce a null indication on the detector, with exciting current also being measured in most cases. Measured ratios should compare with ratios calculated from nameplate voltage to within 0.5%, but should compare even closer to actual benchmark values. Outof-tolerance readings should be compared with prior tests. The turn-ratio test may also detect high-resistance connections in the lead circuitry or high contact resistance in tap changers by higher excitation current and a difficulty in balancing the bridge. 16-25 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book Winding Resistance Winding resistance is used to indicate the winding conductor and tap changer contact condition. The test requires an ohmmeter capable of accurately measuring resistance in the range of 20Ω down to fractions of an ohm. Resistance measurements can be used to check for proper connections and to determine if an open-circuit condition or a high-resistance connection exists in parallel conductor windings. On three-phase transformers, measurements are made on the individual windings from phase to neutral, when possible. On delta connections, there will always be two windings in series, which are in parallel with the winding under test. Therefore, on a delta winding, three measurements must be made to be able to calculate each individual winding resistance. Winding resistance varies with oil temperature. Because the resistance of copper varies with temperature, all test readings must be converted to a common temperature to give meaningful results. Most factory test data is converted to 85oC. This has become the most commonly used temperature. Variations of more than 5% may indicate a damaged conductor in a winding. former tank wall. If multiple sensors are used, the PD can be located based on the arrival time of the pulses at the sensors. Partial Discharge For large power transformers, the partial discharge (PD) test is performed in the laboratory as a routine test, although a PD test is not required for quality control of distribution transformers. However, the PD test is well known as a diagnostics tool and can be employed to detect minor and progressing problems leading to a catastrophic fault inside a transformer. The two commonly used PD detection methods are: detection of the acoustic signals, and measurement of the electrical signals produced by the PD. The acceptable PD limits for new transformers are dependent on the voltage and size of the transformers and range from 100 to 500 pC. PD pulses generate mechanical stress waves that propagate through the surrounding oil. To detect these waves, acoustic emission sensors are mounted on the trans- Loads on electric utility systems include two components: active power (measured in kilowatts) and reactive power (measured in kilovars). Active power is generated, whereas reactive power can be provided by either generation or capacitance. Distribution systems have VAR requirements, because distribution power lines and loads are primarily inductive. Uncompensated distribution systems operate at lagging power factor, drawing reactive power from generation. Figure 16.6-2 PD measurement using HFCT. 16-26 In the field, the test can be done on-line or off-line. For the off-line test, a three-phase source is required to apply the voltage. On-line PD measurement can be employed using acoustic sensors, via busing tap, or through high-frequency current transformers (HFCT) located either on bushing tap or in the neutral of transformer. Figure 16.6-2 shows a PD resolved pattern on the left, recorded using an HFCT sensor via neutral cable. A classification technique is employed to separate the contributions of PD from those generated by disturbances. Each PD pulse waveform is acquired, and the so-called equivalent time-length and bandwidth are evaluated and plotted on the TF map, as shown in Figure 16.6-2 (b). 16.7 CAPACITORS 16.7.1 Purpose of Capacitors Fixed and switched capacitors are inexpensive means of providing VAR compensation for distribution systems and thus correcting power factor and reducing system losses. Shunt capacitors supply reactive current to oppose the out-of-phase component of the current required by an inductive load. A shunt capacitor draws EPRI Underground Distribution Systems Reference Book leading current, which counteracts the lagging component of the current at the point of its installation. When shunt capacitors are applied, the magnitude of the source current can be reduced, the power factor can be improved, and the voltage drop can also reduced. Capacitors can provide effective cost-reduction by deferring or eliminating investment in new plant. Capacitors aid in minimizing operating expenses and allow utilities to serve new loads and customers with a minimum system investment Advantages of installing shunt capacitors in distribution systems are as follows: Chapter 16: Transformers and Equipment between the foil. Recently manufactured capacitors have all-film-insulating layers. The rolls are packed tightly in the can, and the can is filled with a dielectric fluid. The packs are connected in series and parallel using tabs connected to the foil to obtain the desired capacitance. Connection to capacitor elements is generally by means of mechanical crimps or ultrasonic welds. • Released system capacity. The installation of shunt Terminal leads are connected to the tabs and exit through the bushings to form the exterior connections. Capacitor bushings are generally processed porcelain and are welded to the top of the case and the hermetically sealed system. capacitors decreases the reactive power demand from the generation. Thus, generation, transmission, and distribution substation capacities are released. Capacitors nameplates generally include the following information: • Reduction in losses. The reactive components of line currents are reduced from the point of the capacitor installation back to the generator. Dollar savings are realized from peak power and energy loss reductions. • Improvement in voltage regulation. The demand capacity of distribution feeders is often limited by the voltage drop along the line rather than by the thermal ampacity of the conductor. The installation of shunt capacitors will improve the voltage profile of the feeder. An additional benefit from improving the voltage profile is the ability to practice conservative voltage reduction (CVR) or peak shaving from which further demand savings can be achieved. Depending on the uncorrected power factor of the system, the installation of capacitors can increase substation capability for additional load by as much as 30%, and can increase individual circuit capability, from the voltage regulation point of view, approximately 30 to 100%. Furthermore, the current reduction for transformers, distribution lines, and equipment can reduce the load on these kilovoltampere-limited apparatus and consequently delay new facility installations. The preceding benefits can be achieved by both fixed and switched capacitors. With a variable capacitor, the benefits can be further enhanced by closely matching the VAR requirements of the load. If control of a variable capacitor can be achieved quickly, transient-free switching and voltage flicker reduction are additional benefits. 16.7.2 Description of Capacitors Distribution capacitors are typically housed in rectangular, sealed, metal cans, which can be made of stainless steel. The cans contain rolled packs of aluminum foil, with layers of insulating paper, and/or plastic film, • • • • • • • • • Name of manufacturer Unique serial number Catalog number Year of manufacture Rated capacitance Rated rms voltage Number of poles Rated frequency Rated BIL Amount of fluid, indicate flammable or not flammable Capacitors are rated for line-to-line voltage in the event that they are applied on ungrounded or poorly grounded systems. Capacitor units are capable of continuous operation over an ambient range of -50°C to +55°C, provided that the following limitations are not exceeded: • 135% of nameplate KVAR • 110% of rated voltage rms, including harmonics • 180% of rated current rms, including fundamental and harmonic currents 16.7.3 Application of Capacitors at Stations and on Feeders Capacitors are used in distribution stations or on distribution feeders. Station capacitors are rack mounted in large banks. Capacitors installed on feeders are usually in pole-top banks with necessary group fusing. The maximum bank sizes are about 1800 KVAR at 15 kV and 3600 KVAR at higher voltage levels. Usually, utilities do not install more than four capacitor units on each feeder. Approximately 60% of capacitors are 16-27 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book applied to feeders, 30% to the substation bus, and 10% on the transmission systems. • On feeders with light load, where the minimum load Capacitors can be applied as fixed or switched units. Switched units have capacitor bank controllers that switch several capacitor banks. Such controllers can switch capacitor banks at the point of installation or based on a user-specified time schedule. There are also controllers that switch capacitors on the zero crossing of voltage in order to reduce transients. The components required for a switched capacitor installation operating on VAR conditions are as follows: • On feeders with single-phase breaker operation at the • • • • • • Capacitors Oil switch Surge arrester Current transformer Potential transformer Transducers to convert CT and PT values into suitable signals for capacitor controller • Capacitor bank status • Local/remote switch status • Local/remote relay control Capacitors can be applied at almost any voltage level. Individual capacitor units can be added in parallel to achieve the desired kilovar capacity and can be added in series to achieve the required kilovolt voltage. A three-phase capacitor bank on a distribution feeder c a n b e c o n n e c t e d i n d e l t a , g ro u n d e d - w y e, o r ungrounded-wye. The type of connection used depends upon: • System type—i.e., whether it is a grounded or an per phase beyond the capacitor bank does not exceed 150% of the per-phase rating of the capacitor bank sending end • On fixed-capacitor banks • On feeder sections beyond a sectionalizing-fuse or single-phase recloser • On feeders with emergency load transfers. Usually, grounded-wye capacitor banks are employed only on four-wire, three-phase primary systems. Otherwise, if a grounded-wye capacitor bank is used on a three-phase, three-wire ungrounded-wye or delta system, it furnishes a ground current source that may disturb ground relays. The optimum amount of capacitor kilovars to employ is generally the amount at which the economic benefits obtained from the addition of the last kilovar equals the installed cost of the kilovars of capacitors. The methods used by the utilities to determine the economic benefits derived from the installation of capacitors vary from company to company, but usually they all determine the total installed cost of a kilovar of capacitance. The economic benefits that can be derived from capacitor installation can be itemized as: • • • • • ungrounded system • Fusing requirements • Capacitor-bank location • Telephone interference considerations A res o na n ce c on di t i on m ay o c cu r i n de lt a a nd ungrounded-wye banks when there is one- or two-line open-type fault that occurs on the source side of the capacitor bank. The resonance occurs due to the maintained voltage on the open delta, which backfeeds any transformers located on the load side of the open condition through the series capacitor. As a result of this condition, the single-phase of distribution transformers on four-wire system s may be damaged. Therefore, ungrounded-wye capacitor banks are not recommended under the following conditions: 16-28 Released generation capacity. Released transmission capacity Released distribution substation capacity Reduced energy (copper) losses Reduced voltage drop and consequently improved voltage regulation • Released capacity of feeder and associated apparatus • Postponement or elimination of capital expenditure due to system improvements and/or expansions • Revenue increase due to voltage improvements The total yearly benefit due to the installation of capacitor banks can be summarized as ∑ Δ$ = Δ$G + Δ$T + Δ$DS + Δ$DF + Δ$LR + Δ$EC 16.7-1 Where: Δ$G = annual benefit from generation capacity released above capacity at original pf, ($/yr). Δ$T = annual benefit from transmission capacity released above capacity at original pf, ($/yr). EPRI Underground Distribution Systems Reference Book Chapter 16: Δ$DS = annual benefit from distribution station capacity released above that at original pf, ($/yr). Δ$DF = annual benefit from distribution feeder capacity released above that at original pf, ($/yr). Δ$LR = annual benefit from reduction in energy losses, ($/yr). Δ$CE = annual additional revenue from increased consumption by voltage improvement, ($/yr). The total benefits obtained should be compared against the annual equivalent of the total cost of the installed capacitor banks. The total cost of the installed capacitor banks can be found from $TIC = ΔQc ⋅ $IC ⋅ ic 16.7-2 Where: $TIC = annual equivalent of total cost of installed capacitor banks, $/yr. ΔQc = required amount of added capacitance, KVAR. $IC = cost of installed capacitor banks, $/KVAR. = annual fixed charge rate applicable to ic capacitors. If only fixed-type capacitors are installed, the utility will experience an excessive leading power factor and voltage rise at low-load conditions. Therefore, some of the capacitors should be installed as switched-capacitor banks, so they can switched off during light-load conditions. Thus, the fixed capacitors are sized for light load and connected permanently. Switched capacitors can be switched as a block or in several consecutive steps as the reactive load becomes greater from light-load level to peak load, and sized accordingly. A system analysis is required in choosing the type of capacitor installation. As a result of load flow program runs on feeders or distribution substations, the system’s lagging reactive loads (i.e., power demands) can be determined, and the reactive power in KVARs can be plotted against time of day. This plot is called the reactive load duration curve, and is the cumulative sum of the reactive loads (e.g., fluorescent lights, household appliances, and motors) of consumers and the reactive power requirements of the system (e.g., transformers and regulators). Once the daily reactive load duration curve is obtained, then the size of the fixed capacitors can be determined to meet the minimum constant reactive load requirements. The remaining kilovar demands of the loads are met by the generator or preferably by the switched capacitors. Switched capacitor sizes can be Transformers and Equipment selected to match the remaining load characteristics from hour to hour. A rule of thumb is often used to determine the size of the switched capacitors. Switched capacitors are added until: k var from switched + fixed capacitors ≥ 0.70 k var of peak reactive feeder load 16.7-3 The kilovars needed to raise the voltage at the end of the feeder to the maximum allowable voltage level at minimum load is the size of the fixed capacitors that should be used. On the other hand, if more than one capacitor bank is installed, the size of each capacitor bank at each location should have the same proportion, that is: k var of load center kVA of load center = k var of total feeder kVA of total feeder 16.7-4 The resultant voltage rise must not exceed the light-load voltage drop. The approximate value of the percent voltage rise is: % VR = Qc ⋅3ϕ Xl 10 ⋅VL2− L 16.7-5 Where: % VR = percent voltage rise. Qc⋅3φ = three-phase reactive power due to fixed capacitors applied, KVAR. X = line reactance, Ω. l = length of feeder from sending end to fixedcapacitance location, mile. VL-L = line-to-line voltage, kV. If the fixed capacitors are applied to the end of the feeder, and if the percent voltage rise is already determined, the maximum value of the fixed capacitors in KVARs can be determined from: Max Qc ⋅3ϕ = 10(%VR ) VL2− L Xl 16.7-6 The %voltage rise equation above can also be used to calculate the percent voltage rise due to the switched capacitors. Therefore, once the percent voltage rises due to both fixed and switched capacitors are found, the total percent voltage rise can be calculated as: 16.7-7 ∑ % VR = % VRF + %VRSW Where: Σ % VR = total percent voltage rise. % VRF = percent voltage rise due to fixed capacitors. % VRsw = percent voltage rise due to switched capacitors. 16-29 Chapter 16: Transformers and Equipment Another rule of thumb sometimes used is that: The total amount of fixed and switched capacitors for a feeder is the amount necessary to raise the receiving-end feeder voltage to maximum at 50% of peak feeder load. 16.7.4 Capacitor Location Once the kilovars of capacitors necessary for the system are determined, the location of the capacitors needs to be determined. The rule of thumb for locating the fixed capacitors on feeders with uniformly distributed loads is to locate them approximately at two-thirds of the distance from the substation to the end of the feeder. For the uniformly decreasing loads, fixed capacitors are located approximately halfway out on the feeder. The location of switched capacitors is often determined by voltage regulation requirements, and they are usually located on the last one-third of the feeder away from the source. The best location for capacitors can be found by optimizing power loss and voltage regulation. A feeder voltage profile study is required to determine the most effective location for capacitors and a voltage that is within recommended limits. Usually, a 2-V rise on circuits used in urban areas and a 3-V rise on circuits used in rural areas are the maximum voltage changes that are allowed when a switched-capacitor bank is placed into operation. A general iteration process is summarized as follows: 1. Obtain circuit and load information: • kilovoltamperes, kilovars, kilowatts, and load power factor for each load • desired corrected power of circuit • feeder circuit voltage • a feeder circuit map that shows locations of loads and presently existing capacitor banks 2. Determine the kilowatt load of the feeder and the power factor. 3. Determine the kilovars per kilowatts of load necessary to correct the feeder-circuit power factor from the original to the desired power factor. 4. Determine the individual kilovoltamperes and power factor for each load or group of loads. 5. Determine the kilovars on the line. 6. Determine the line loss in watts per thousand feet due to the inductive loads determined in steps 4 and 5 above. Multiply these line losses by their respective line lengths in thousands of feet. Repeat this process for all loads and line sections, and add them to find the total inductive line loss. 7. If there are capacitors presently on the feeder, perform the calculation of step 6, but subtract the capac16-30 EPRI Underground Distribution Systems Reference Book itive line loss from the total inductive line loss. Use the capacitor kilovars determined in steps 3 and 6, and find the line loss in each line section due to capacitors. 8. To find the distance to capacitor location, divide total inductive line loss by capacitive line loss per thousand feet. If this quotient is greater than the line section length: • Divide the remaining inductive line loss by capacitive line loss in the next line section to find the location. • If this quotient is still greater than the line section length, repeat step 8a. 9. Construct a voltage profile for the feeder. If the profile shows that the voltages are inside the recommended limits, then the capacitors are installed at the location of minimum loss. If not, then use engineering judgment to locate them for the most effective voltage control applications. Some summary rules that can be used in the application of capacitor banks include the following: 1. The location of fixed shunt capacitors should be based on the average reactive load. 2. There is only one location for each size of capacitor bank that produces maximum loss reduction. 3. One large capacitor bank can provide almost as much savings as two or more capacitor banks of equal size. 4. When multiple locations are used for fixed-shuntcapacitor banks, the banks should have the same rating to be economical. 5. For a feeder with a uniformly distributed load, a fixed-capacitor bank rated at two-thirds of the total reactive load and located at two-thirds of the distance out on the feeder from the source gives an 89% loss reduction. 6. The result of the two-thirds rule is particularly useful when the reactive load factor is high. It can be applied only when fixed shunt capacitors are used. 7. In general, particularly at low reactive load factors, some combination of fixed and switched capacitors gives the greatest energy loss reduction. 8. In actual situations, it may be difficult, if not physically impossible, to locate a capacitor bank at the optimum location; in such cases, the permanent location of the capacitor bank ends up being suboptimum. 16.7.5 Capacitor Protection Considerations The main function of capacitor protection is to electrically remove failed capacitors from the distribution system. EPRI Underground Distribution Systems Reference Book The protection must isolate a faulted bank or individual shunt capacitors without interrupting service on the remainder of the circuit. When the capacitor does fail, the protection should rapidly remove it from the system to avoid case rupture. If the protection has been properly coordinated, it should also operate before any other upstream protective devices. While fulfilling this fault-clearing role, the capacitor protection must also remain immune to a number of “normal” transient conditions such as energizing inrush, discharging/outrush, parallel switching outrush, and lightning surges. To ensure that capacitor protection will fulfill these functions, a number of issues must be considered as outlined in the following sections. Location Constraints Within substations, capacitors are usually individually fused. Capacitor fuses will typically be installed on outdoor steel structures, which permits the use of any outdoor protection option. However, it is also possible to purchase capacitor banks with under-oil fuses installed inside each capacitor unit, and fuses available in encapsulated designs may be specified for this application. For feeder installations, capacitors are most often located on overhead systems, due to the inherent capacitance of underground cable systems, so the protection equipment can be located at a pole-top location. Outdoor protection options can, therefore, be specified, ranging from distribution cutouts through solid material power fuses to current-limiting fuses. Bank Configuration Although capacitor units can be connected in several different configurations, the majority of power capacitor equipment installed on primary distribution feeders is connected three-phase, either grounded-wye or ungrounded-wye (delta and single-phase connections are usually made only on low-voltage circuits). A number of advantages can be derived from the groundedwye type of connection. With the grounded-wye connection, tanks and frames are at ground potential, which provides additional personnel safety. Groundedwye connections facilitate faster operation of the series fuse in the event of a capacitor failure. Grounded capacitors can divert some line surges to ground and, therefore, exhibit a certain degree of self-protection from transient voltages and lightning surges. The groundedwye connection also provides a low-impedance path for harmonics. In general, phase-neutral rated capacitors should be used on grounded capacitor banks, and phase-phase rated banks should be used on ungrounded-wye or delta systems. Chapter 16: Transformers and Equipment The number of capacitor groups in series is an important factor in determining the appropriate type of fuse. The impedance of the series groups limits the current into a faulted unit and thus determines the magnitude of the available fault current into a single shorted can. As a general rule, the fault current through the fuse, when the unit that it is protecting becomes shorted, should not be less than 10 times the rated capacitor current. This available fault current is also affected by whether or not the neutral is grounded. The number of series units in a capacitor installation also affects the overvoltage that healthy units are exposed to after the short-circuit failure of one series unit. This factor is discussed later in the section entitled “Overvoltage Protection.” The number of cans in a parallel group is also an important consideration in choosing appropriate protection. Energy stored in the capacitors in parallel with a faulted will be discharged into the faulted unit. This discharge must be withstood by the fuses on the good cans. When a large bank is desired, it may be better to use a doubleY construction so as to retain the use of expulsion fuses. There is also a minimum number of capacitors that can be connected safely in parallel in a group. Below this critical number, individual capacitor fuses must be rated at such a large percentage of the total phase current that, in the event of failure of a unit, the magnitude of the fault current is insufficient to produce rapid fuse clearing. Figure 16.7-1 illustrates the effect of the number of series sections and the number of parallel units in a section on the available current through a shorted unit. Figure 16.7-1 Current through a shorted unit versus the number of units per section for a grounded-wye bank. 16-31 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book Individual versus Group Protection Capacitor protection practices at distribution voltages can be divided into two basic protection techniques: individual protection and group protection. Individual protection is commonly used for large capacitor banks, which are normally located at the distribution substation. In these installations, each capacitor unit is protected by its own individual fuse; backup protection in the form of a circuit breaker or higher-rated fuse is normally provided to protect capacitors against bus faults ahead of the individual fuses. Fuses in this case are of the bus-mounted type. Group protection is commonly used to protect polemounted capacitor banks, which are normally located on the primary feeders. In this case, only one fuse per phase is used, and each fuse protects all capacitor units that are located in that phase. Continuous Current Although capacitors are considered constant current devices, in actual operation they are subject to overcurrents. These are caused by overcapacitance, operation at higher than rated voltage, and system harmonics. ANSI/IEEE Standard C37.99 (ANSI/IEEE 1990) allows a manufacturing tolerance of +15% on the rated reactive power of capacitors at rated voltage and frequency at 25oC. Also, capacitor banks can be operated at up to 10% overvoltage (though typical system voltages do not exceed 6% of nominal voltage). These two factors may combine to increase continuous current by up to 25%. Harmonic currents depend on system conditions and are difficult to predict; however, practice dictates that an allowance of 5 to 10% of rated current should be used. Ungrounded-wye or delta connected capacitors need less margin for harmonic currents, because there is no path for third or multiples of third harmonic current. For a three-phase grounded-wye application, the continuous current will be: I C = 1.35 3ϕ kVAR 3 kV LL Whenever possible, the lowest rated fuse that can continuously carry this current should be selected, because this provides maximum sensitivity for high impedance faults and the greatest protection against tank rupture. However, a fuse selected in this way will be more vulnerable to transient surges. Note that the continuous current-carrying capability is not necessarily the same as the rated current of the fuse. Some fuses will continuously carry currents above their rating. K and T links, for instance, will carry 150% of their rated current. Transient Currents A capacitor fuse must withstand, without damage, the transient currents and voltages due to lightning surges, as well as transient currents during energization and deenergization of the capacitor bank. In addition, it must withstand discharge currents and parallel switching transients. Figure 16.7-2 illustrates the various types of transient currents and provides a reference for the symbols used in the equations that follow. Note that the capacitors on one phase are shown with individual protection. In capacitor application, it is common to consider that the continuous current may be equivalent to 135% of the capacitor rated current for grounded-wye connected banks, and 125% for ungrounded-wye banks. This accounts for the effect of overvoltage conditions, capacitance variations, and harmonic currents. The continuous current for an individual grounded-wye connected capacitor can be calculated as follows: I C = 1.35 1ϕ kVAR 16.7-8 kV LN Figure 16.7-2 Illustration of parameters used in capacitor transient current equations. 16-32 16.7-9 EPRI Underground Distribution Systems Reference Book Chapter 16: In individually fused substation capacitor banks, transients due to lightning surges will typically be of little concern, because of the reliable substation shielding and because the large number of capacitors in parallel will effectively share the transient current. Currents generated by switching transients are also controlled in substation applications through the use of current-limiting reactors and switch-closing resistors. Individually fused units are generally exposed to only one significant form of transient current—that is, discharge or outrush currents. For feeder capacitors, where group capacitor protection is typically used, a number of transient considerations are of concern, including energizing transients or inrush currents, parallel switching (outrush) transients, deenergizing transients, and transients due to lightning surges. The various forms of transient currents experienced by capacitors in normal operation are described in the following paragraphs. Discharge or Outrush Into Faulted Capacitor Discharge currents in capacitor banks occur when one parallel unit fails and the remaining good capacitors discharge into the faulted unit. To prevent spurious fuse blowing and the disruptive failure of the capacitor case, the fuses on the healthy units must be capable of withstanding these outrush currents. A typical discharge transient waveform is shown in Figure 16.7-3. The approximate I2t for the outrush current (Io in Figure 16.7-3) from a capacitor to a failed unit can be estimated by the following: 2 I t = 1 V 2C . 2 2 R1 16.7-10 Transformers and Equipment Where: R1 = resistance for an individually fused capacitor unit, (ohms). C = capacitance of a single unit, (F). V = voltage, (V). Table 16.7-1 provides some typical I2t values for single capacitors discharging from full voltage. When capacitors are connected in parallel, the actual discharge I2t from healthy units into a failed unit is typically 66% of the tabulated values. Table 16.7-1 I2t for Capacitor Discharge I2t (times 1000 A2s) Unit Volts 100 KVAR 150 KVAR 200 KVAR 300 KVAR 2400 10.4 18.6 25.0 - 4160 8.9 15.9 21.0 - 4800 8.5 15.0 20.2 - 7200 6.9 12.3 16.6 25.4 8320 6.3 11.1 15.4 23.2 12470 4.5 8.1 11.5 17.8 13280 4.2 7.5 10.9 17.2 13800 4.0 7.3 10.6 16.8 14400 3.9 6.9 10.3 16.2 16000 3.5 6.1 9.2 15.0 19920 2.5 4.5 7.2 12.5 To prevent excessive outrush into faulted capacitors, the total parallel-stored energy should not exceed the energy capability or joule rating of either the capacitor unit or the fuse. According to ANSI C37.99 and to manufacturing recommendations, the calculated energy of the bank must not exceed 15,000 Joules (4650 KVAR in parallel) for all-film capacitors or 10,000 Joules (3100 KVAR) for paper-film capacitors. In cases when the calculated value of the parallel-stored energy surpasses the limitation capability of expulsion fuses, two possible solutions are suggested: reconfiguration of the capacitor bank, or the use of current-limiting fuses (CLFs). Inrush Current When a capacitor is energized, there is an initial inrush current (Iin in Figure 16.7-3). This is a short-duration, high-frequency damped sinusoidal current whose characteristics depend on the capacitor size, the point on the voltage wave at which energization occurs, and the impedance of the supply circuit. Figure 16.7-3 Typical discharge transient waveform. For adequate protection, the melting I2t of the fuse must be higher than that of the capacitor inrush current. 16-33 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book With acceptable accuracy, the I2t of the inrush current can be calculated using the following relationship: 2 2 I t = 2.65 I L I sc 1+ K 2 A s 16.7-11 Where: Isc = fault current at capacitor bank location (kA). IL = capacitor bank line current (A). K = X/R at the bank location. As can be seen from this equation, the inrush I2 t is a function of capacitor phase current, available short-circuit current at the point of application, and the X/R ratio of the source impedance at that point. If N parallel capacitors on a phase are individually fused, then the inrush current through each fuse would be the value from the inrush I2t equation divided by N. Figure 16.7-4 shows graphically the inrush I2t as a function of capacitor phase current for a number of system short circuit currents and X/R ratios. Parallel Switching Transients Parallel switching transients, which are also commonly referred to as back-to-back switching transients, occur when de-energized capacitor banks are switched into service in the vicinity of a previously energized capacitor bank. The energized capacitors discharge high-magnitude, high-frequency currents (Ip) into the unit being switched on, over a period lasting several milliseconds after the parallel is established. These discharge currents are only significant when individual capacitor units are installed in close proximity on the same distribution feeder. The high-frequency transient outrush current from the already energized capacitor bank is solely dependent on the surge impedance of the discharge path, which is a function of the equivalent capacitance of the two banks, the total inductance of the discharge path (the inductance of the conductors between the two banks and the inductance of the capacitor banks themselves), and the magnitude of the voltage at the instant the second bank is energized. The minimum equivalent circuit inductance (inductance of the discharge path) L required between the two capacitor banks to prevent spurious fuse operation can be calculated using the expression shown in Equation 16.7-12. L= K 2 V 4 C e3 (I t ) 2 2 Henrys 16.7-12 Where: K = constant equal to 3.7, which represents a typical inrush damping factor of 0.81. V = peak value of the line-to-ground voltage when the capacitor bank is energized, (V). Ce = equivalent capacitance of the discharge path, (Farads). In Equation 16.7-12, the equivalent capacitance of the discharge path Ce may be derived from Equation 16.7-13. Ce = C 1 2.65 kVAR = • 2 2 2 V lg 16.7-13 Where: KVAR= single-phase KVAR. Vlg = line-to-ground voltage, (V). I2t= high-frequency surge withstand capability of the capacitor bank, defined in Equation 16.7-14. 2 2 I t = ( I t ) 60 Hz • F PLD • F HFSW 16.7-14 Where: FPLD = preload adjustment factor. FHFSW = high-frequency surge-withstand I2t factor. For a specific conductor size and configuration, with a known inductance per unit length, the corresponding minimum line length between the two capacitor banks can be calculated as shown in Equation 16.7-15. Distance = Figure 16.7-4 Energizing inrush I2t for grounded-wye banks. 16-34 L - Lb Lc 16.7-15 Where: Lb = self inductance of the two banks in parallel supplied by the capacitor manufacturer, (H). Lc = conductor inductance per foot (H/ft). EPRI Underground Distribution Systems Reference Book Chapter 16: When capacitor banks are separated by several polespans, nuisance operation of capacitor fuses due to parallel switching is not a major concern, and the calculation shown in Equation 16.7-15 can be used to confirm this. Figure 16.7-5 provides an example of the capacitor discharge I 2 t for various KVAR units that are spaced a varying number of 150-foot spans on a line with 795 ACSR conductor. De-Energizing Transients De-energizing transient currents (Id) can occur when opening a capacitor switch. When the capacitor switch is being opened, the capacitor tries to maintain the potential that it had before the contacts where opened. If the switch restrikes, the oscillatory current discharge has a high peak value. De-energizing transients are more likely to occur in circuits with voltages above 25 kV. In these cases, restrike-free switches must be installed. De-energizing transients can be estimated with Equation 16.7-16. 2 2 I t = 10.6 I L I sc 1+ K 2 A s 16.7-16 Where: Isc = fault current at capacitor bank location (kA). IL = capacitor bank line current (A). K = X/R at the bank location. High-Frequency Transients Capacitor fuses are commonly exposed to high-frequency transients due to lightning surges. These surges are more likely to damage low-current rated links. When group protection is employed, spurious fuse blowing can be reduced by utilizing a slow-clearing T tin link of up Transformers and Equipment to 25 A. In addition, the location of the arrester between the fuse cutout and the capacitor must be avoided. Available Fault Current The system fault current available at the capacitor location, the type of connection (such as delta or wye, neutral grounded, or ungrounded), the number of series groups, kVA rating of the bank, and the number of capacitors in parallel are all factors that should be taken into consideration by the protection engineer when determining the proper protection for the capacitor bank. When capacitors are connected grounded-wye or delta, any capacitor failure will cause the system fault current to flow through the faulted capacitor. The capacitor must withstand the short-circuit current flow until the circuit is interrupted by the fuse. When multiple-series groups of capacitors are used, as a general rule system fault current will not flow through a faulted capacitor, and expulsion fuses can be employed. With the wye configuration, the neutral can be either grounded or floating. When grounded, the fault current through a failed capacitor is the available system line-toground fault current. For the delta connection, line-toline system fault current will flow through the failed capacitor. In an ungrounded-wye capacitor bank, the fault current is limited to three times normal line current. Available fault current to the failed unit and interrupting duty on the fuse are, therefore, reduced. The fuse, however, must be small enough to detect this low-level fault current. Furthermore, while the faulted capacitor is in the circuit, the neutral shift causes the voltage across the capacitor in the unfaulted phases to increase to 1.73 times the rated voltage. Operation under these conditions will result in failure of the healthy capacitors in a short time. The fuse must operate as quickly as possible to remove this overvoltage. It must be ensured that the available fault current does not exceed the interrupting rating of the selected fuse. The available fault current, along with the following considerations of capacitor rupture hazard, are used to determine whether CLFs are required for an application. Figure 16.7-5 I2t from parallel switching of capacitors on a distribution feeder. Capacitor Case Rupture Hazard Capacitor case rupture will occur if the total energy applied to the capacitor under short-circuit conditions is greater than the ability of the capacitor case to withstand such energy. 16-35 Chapter 16: Transformers and Equipment A capacitor unit internally consists of a number of series groups of parallel-connected packs. Capacitor failure usually starts with the breakdown of one pack, which then shorts out the group. The capacitor current increases, as does the voltage in the remaining series groups. This increased voltage will eventually lead to the dielectric failure of another pack, causing another increase in current and voltage across the remaining good groups. This process will continue until all the groups have failed, and the capacitor acts as a bolted fault. The process may take hours or longer, during which time current escalates in discrete steps. It is desirable that the capacitor fuse operate before all the series groups have failed, because the then remaining good groups will limit the fault current and the possibility of case rupture will be minimized. The cause of capacitor case failure is attributable to the development of excessive internal pressure sufficient to stress the capacitor case beyond its mechanical limits. When a capacitor dielectric fails, the resulting arc creates internal pressure from heat and a gas generated in the liquid dielectric of the unit. The pressure varies depending on the magnitude of the fault current to the failed unit and the time that it is allowed to flow. This force can swell the sides of the capacitor case or rupture the case—that is, anything from opening a seam or bushing seal, to violent bursting, endangering adjacent equipment. EPRI Underground Distribution Systems Reference Book through I2t of the fuse must always be less than the minimum rupture I2t of the capacitor. I2t coordination of the capacitor minimum rupture I2t curve and the fuse total clearing I2t curve will determine whether expulsion fuses are suitable to protect against case rupture at high fault levels, or whether CLFs are necessary. Capacitor manufacturers supply the minimum rupture I2t information for their units. Some typical values are provided in Table 16.7-2. Comparison of the tabulated values with I2t curves for expulsion fuses, as illustrated in Figure 16.7-7, can be used to determine the fault current limit for expulsion fuse protection. If a capacitor minimum rupturing I2t is about 1,000,000 A2s, as illustrated in Figure 16.7-7, then expulsion fuses will provide protection with fault currents up to 8000 A. For a capacitor with a lower minimum rupturing I 2 t of 100,000 A2s, expulsion fuses would only provide protec- Case-rupture curves are essential to the correct selection of fuse links for overcurrent protection of any capacitor installation. These curves, which are available from capacitor manufacturers and standards, illustrate the probability of case rupture for various time and current relationships. Capacitor case rupture for newer all-film capacitor designs is generally defined by a single-case rupture curve (see Figure 16.7-6). This is possible, because allfilm units fail to short circuit in a more predictable manner, and thus have a more well-defined rupture threshold than older paper-film capacitors. Capacitor fuses must have a time-current clearing characteristic that will ensure rapid isolation of a faulted capacitor without case rupture. For adequate protection, the fuse total-clearing time current curve (TCC) must lie to the left of the single case-rupture curve of the capacitor. For high fault currents, case-rupture curves must be compensated for asymmetry. Capacitor case rupture must be considered, not only by using the TCCs, but by ensuring that the maximum let- 16-36 Figure 16.7-6 Case-rupture curves for shunt capacitors (150, 200, and 300 KVAR all-film capacitors). Table 16.7-2 Typical All-film Capacitor Minimum Rupture I2t Capacitor Unit Voltage All-film Units 100 KVAR All-film Units 150, 200, 300 KVAR Above 9000 V 112,500 A2s 450,000 A2s Below 9000 V 250,000 A2s 1,000,000 A2s EPRI Underground Distribution Systems Reference Book Chapter 16: tion to about 3000 A. Note from Figure 16.7-7 that a CLF can be used for protection at higher fault levels. Overvoltage Protection The fuse link must protect healthy capacitors against the possibility of being operated at excessive overvoltage during failure of an adjacent unit. Capacitors are designed to operate normally at specific 60-Hz nominal voltage, which is listed on the unit nameplate. However, a 10% overvoltage is allowed without causing any damage to the capacitor. Table 16.7-3 illustrates the overvoltage that is experienced by good units during the failure of a capacitor on another phase. The table illustrates that the overvoltage is also a function of the number of units in series on the faulted phase. In ungrounded-wye installations consist- Transformers and Equipment ing of a single capacitor per phase, a failure on one phase increases the voltage on the other phases to 1.73 times the rated voltage. If the faulted capacitor is not removed promptly, this overvoltage can cause a second capacitor failure. IEEE Standards 18 and 1036 provide recommended limits for the duration of power frequency overvoltages on capacitors in service. These limits range from a duration of six cycles for an overvoltage 2.2 times rated voltage, to a duration of 30 minutes for an overvoltage of 1.25 times rated voltage. The fuse on a faulted unit must operate fast enough to limit the duration of an overvoltage on the healthy units. One general rule for selecting fuses is to require the fuse to operate within 5 minutes at 95% of the fault current. K-type links operate more quickly at high currents than equally rated T-links and thus offer reduced overvoltage durations. Fuse manufacturers generally publish selection tables that reflect consideration of all the factors mentioned above, and permit the direct selection of the capacitor bank fuse, thereby eliminating the need to perform complex calculations or graphical studies. However, for the purpose of explanation, a step-by-step procedure to select fuses for capacitor protection is provided in the following section. 16.7.6 Application of Capacitor Fuses In summary of the preceding sections, a capacitor fuse must be selected to: • • • • Figure 16.7-7 Limit for capacitor protection by expulsion fuse. Table 16.7-3 Overvoltage on Healthy Capacitor Units During Short-Circuit Failure of a Series Unit Number of Voltage on Each Phase During a Short-Circuit Series Failure of One Series Unit on Phase "a" (per-unit Groups nominal phase voltage) Grounded Wye 1 2 3 4 5 Ungrounded Wye Va Vb Vc Va Vb Vc 2.00 1.50 1.33 1.25 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.50 1.29 1.20 1.15 1.73 1.15 1.08 1.05 1.04 1.73 1.15 1.08 1.05 1.04 carry continuous capacitor current, isolate a faulted capacitor, withstand transient currents, have sufficient interrupting capacity to interrupt the maximum fault current at the point of application, • limit the energy let-through to a faulted unit to minimize the possibility of capacitor case rupture, • protect healthy units against prolonged overvoltages. Fuse Type The required interrupting duty of the protection device can be established through an assessment of the available system fault current and the capacitor bank configuration. Reviewing the available fault current and the appropriate case-rupture curves for the capacitor units will dictate whether 1/2-cycle fault clearing is adequate or if fractional-cycle clearing is necessary. The fuse-interrupting duty is established based on the phase configuration (grounded wye versus ungrounded wye versus delta), the capacitor unit arrangement 16-37 Chapter 16: Transformers and Equipment (series-parallel combinations), and the protection arrangement (group versus individual). The phase configuration determines the maximum level of fault current that will flow for the condition where all series branches of a bank phase are shorted. The capacitor unit arrangement is used to determine the proportion of this fault current that will flow for the failure of a single capacitor unit (impedance divider principle), along with the total I2t discharged into a single unit from the unfaulted parallel units. If the total I2t available from the system and from parallel units over the first half-cycle is found to exceed the case-rupture I 2 t, then current-limiting fuses will be required. This step will, therefore, determine whether a distribution cutout, a solid-material power fuse or a current-limiting fuse is to be used. EPRI Underground Distribution Systems Reference Book In parallel with selecting the fuse speed is selection of the fuse rating. This step is completed by comparing the TCCs of short-listed fuses with the fuse withstand characteristics for outrush into faulted units, parallel switching outrush, and energizing inrush as appropriate, and with the case-rupture curves for the specified capacitor units. Where current-limiting fuses are specified, the minimum-melting I2t of the various fuse ratings can be compared directly with the relevant withstand values, and the total let-through I2t of the fuses can be compared directly with the case-rupture I2t. The fuse-melting TCC must remain above and to the right of the relevant withstand curve throughout the current range, and should be selected to stay as close as possible to this curve. By virtue of this selection preference, the designer can ensure that the probability of case rupture is as low as possible. Example Capacitor Protection Fuse Current Rating and Speed The idealized goal for capacitor fuse application is the selection of the fastest fuse that will avoid damage from the range of transient conditions. It is evident that these are conflicting requirements that must be reconciled when choosing the fuse rating and speed ratio. Withstanding continuous current and transients would suggest use of a slow speed fuse, whereas reducing case rupture and overvoltage require a fast fuse. Some typical practices are provided as examples in the following paragraphs. In group protection applications requiring high continuous current ratings (above 25 A), K-type links provide adequate withstand to transient currents, while keeping the melting time as short as practical and providing maximum protection against case rupture. Good coordination is obtained using a K fuse link having continuous current capability of at least 165% of the capacitor current rating for grounded-wye banks and 150% capacitor current rating for ungrounded-wye banks. In group protection applications where a fuse with a low current rating is required (below 25 A), slower T-links may be preferred. The small T-links have higher immunity to transients and lightning surges and may be particularly advantageous in areas with exposure to lightning activity (rural areas with little tree shelter and high iso-keraunic levels). If power fuse or current-limiting protection is required, the slowest available E-rated or C-rated fuses should be used. For individual capacitor protection, where low-currentrated links are generally required, T-links have the advantage of withstanding greater outrush current. Where higher current ratings are required, K-links offer faster clearing for improved case-rupture protection. 16-38 A three-phase, 600-KVAR, grounded-wye connected capacitor bank is installed in a pole-top configuration. The capacitor bank is configured with two single-phase, all-film construction, 100-KVAR capacitor units in parallel connected in each phase. The capacitor units have voltage ratings of 7.2 kV. Assume the maximum line-toground fault current is 800 A rms symmetrical. The perphase load current of the capacitor bank is 27.8 A. Select a primary protective device for this application. According to the capacitor manufacturer, the capacitor bank can be adequately protected with expulsion fuses if the maximum available fault current does not exceed 3.1 kA rms symmetrical, which is the case. To accommodate the highest anticipated capacitor bank current, the fuse continuous current is selected based on the following bank tolerances: 10% overvoltage, 15% in capacitance, and 10% in harmonics. Consequently, the minimum continuous current that the fuse must carry is determined as shown in Equation 16.7-17. I c = 1.35 x 27.8 = 37.53 A 16.7-17 Because K and T links are 150% rated, the continuous current value must be divided by 1.5. As a first approximation, a 25T fuse link mounted on a 200 A distribution cutout is selected to protect each group of capacitors. The cutout has a rated voltage of 7.2 kV, and an interrupting capability of 10 kA rms symmetrical (based on X/R ratio of 4), which exceeds the maximum available short-circuit current at the capacitor bank location. The ability of the fuse to withstand the energizing inrush currents associated with the capacitor bank is EPRI Underground Distribution Systems Reference Book Chapter 16: determined by comparing the unloaded high-frequency surge-withstand I2t capability of the fuse with the I2t of the transient inrush current. The I2t of the inrush current when the capacitor bank is energized is calculated as shown in Equation 16.7-18. 2 2 2 I t = 2.65 • 27.8 • 0.793 • 1+ 4 = 241 A s 16.7-18 Transformers and Equipment • Use a partial-range CLF in series with the expulsion fuse, or use a full-range CLF. Table 16.7-4 provides some examples of fuse link ratings selected for individual protection of all-film capacitors with expulsion fuses. Table 16.7-5 provides some examples of CLFs selected to protect individual all-film Data available from the fuse manufacturer indicates that the unloaded high-frequency surge-withstand I2t for silver-copper eutectic element links is approximately 45% of the 60-Hz minimum melting I2t value. Using the minimum-melting TCC of the selected fuse (25T), the current at 1 second is 200 A, which gives a minimummelting I2t of approximately 40,000 A2s. The fuse highfrequency, surge-withstand I2t is calculated as shown in Equation 16.7-19. I 2 t hf = 0.45 x 40,000 = 18,000 A 2 s 16.7-19 This means that the transient inrush current associated with energizing an isolated capacitor bank will not cause nuisance blowing of the expulsion link selected. The next step is to verify that the selected fuse can effectively protect the individual capacitor units against case rupture. This step is accomplished by comparing the total-clearing TCC of the fuse with the case-rupture curve of the capacitor unit. Figure 16.7-8 shows a plot of the case-rupture curve of a 100-KVAR all-film capacitor unit along with the fuse total-clearing TCC. The fuse total-clearing TCC lies below and to the left of the capacitor case-rupture curve for all current values up to approximately 3900 A. This crossover point indicates the maximum short-circuit current for capacitor bank protection. Because the maximum available fault current at capacitor location (800 A) is lower than the fault-current value at the point of intersection of the two curves, the fuse will always clear the circuit prior to case rupture. The selected fuse will clear the fault current in approximately 0.07 seconds. If the maximum available fault current was greater than the maximum fault-current for capacitor protection, the selected expulsion fuse would not provide adequate protection to the capacitor bank, and one of the following alternatives would be considered: • Move the capacitor bank to a location where the available fault current is lower. • Use larger capacitor units. • Individually fuse the capacitor units. Figure 16.7-8 Example of capacitor protection. Table 16.7-4 Typical Individual Expulsion Fuse Ratings for All-Film Capacitors Capacitor Unit Voltage Rating Fuse Voltage Rating (kV) Capacitor Unit Rating (KVAR) 50 100 150 200 300 400 Fuse Link Rating 2400 8.7 20T 40K 65K 80K - - 4800 8.7 12T 20T 30T 40T - - 7200 8.7 10T 15T 20T 25T 40T 50T 7960 8.7 10T 15T 20T 25T 40T 50T 8320 8.7 10T 15T 20T 25T 40T 50T 14400 15.0 10T 15T 20T 25T 30T a a. For high-voltage 50-KVAR units, fuses with appropriate current ratings will not withstand the outrush I2t. 16-39 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book Table 16.7-5 Typical Individual CLF Ratings for All-Film Capacitors Capacitor Unit Fuse Voltage Voltage Rating Rating capacitors. Table 16.7-6 provides examples of expulsion fuses for group protection of all-film capacitors. 16.8 Capacitor Unit Rating (KVAR) 50 100 150 200 300 400 CLF Current Rating 2400 8.3 30 65 90a - 4800 8.3 18 30 45 65 - - 7200 8.3 18 25 30 40 65 80a 7960 8.3 18 18 30 40 65 80a 8320 15.5 10 18 25 35 50a 80a 14400 15.5 - 10 18 25 30 50a - - a. Indicates parallel fuses. HIGHLIGHTS Efficiency and Components of Transformer Loss • Loss in transformers is due to two causes: load loss and no-load loss. Physically, two main components of transformer loss are: electric (I2 R) and magnetic (core hysteresis and core eddy current loss). Transformer efficiency is related to the amount of watts losses that occur when the transformer is in operation. The percentage of power that is available on the secondary side of the transformer, as a percentage of the power input on the primary, is termed the efficiency. Table 16.7-6 Typical Group Protection for All-Film Capacitors System Line-to-Line Voltage 4160 8320 12480 13800 24900 16-40 Capacitor Line Voltage ThreePhase-Bank KVAR Rated Line Current in Amperes Typical Link Size Grounded Wye Ungrounded Wye 2400 150 300 450 600 20.8 41.6 62.5 83.3 20 T 40 K 65 K 80 K 20 T 40 K 65 K 80 K 4800 150 300 450 600 900 1200 1350 10.4 20.8 31.2 41.7 62.5 83.3 93.8 10 T 20 T 30 K 40 K 65 K 80 K 80 K 10 T 20 T 30 K 40 K 65 K 80 K 80 K 7200 150 300 450 600 900 1200 1350 1800 2400 6.9 13.9 20.8 27.8 41.7 52.5 59.0 78.7 105 8T 15 T 20 T 25 T 40 K 50 K 65 K 80 K 100 K 6T 12 T 20 T 25 T 40 K 50 K 65 K 80 K 100 K 7960 150 300 450 600 900 1200 1350 1800 2400 6.3 12.6 18.8 25.1 37.7 50.2 56.5 75.4 100.5 6T 12 T 20 K 25 K 40 K 50 K 50 K 80 K 100 K 6T 12 T 20 K 25 K 40 K 50 K 50 K 65 K 100 K 14400 300 450 600 900 1200 1350 1800 2400 2700 3600 6.9 10.4 13.9 20.8 27.8 31.2 41.7 55.6 62.5 83.3 8T 10 T 15 T 20 T 25 K 30 K 40 K 50 K 65 K 80 K 6T 10 T 12 T 20 T 25 K 30 K 40 K 50 K 65 K 80 K EPRI Underground Distribution Systems Reference Book • Generally transformers are at maximum efficiency when they are 50% loaded. When transformers are lightly loaded, the no-load losses form a large percentage of the power utilized, and, therefore, the efficiency is low. As the transformer is loaded to higher levels, the load losses dominate the efficiency. The maximum efficiency point is the optimal point of lowest load and no-load losses. It is determined by the design of the transformer and, theoretically, could be designed to occur at any load percentage. It typically is designed to occur at 50%, because the average load tends to be about 50% of the peak load. • Regulations by Energy Departments often mandate minimum efficiency levels for liquid-filled and drytype distribution transformers. Reduction of Transformer Losses • Reduction of transformer losses and improvement in efficiency can be achieved by reduction of either load or no-load losses. For any given set of core and winding materials, reduction of load losses often leads to an increase in no-load losses and vice versa. • More recently, nano-crystalline steel has become available for use in transformer cores. The best of these steels are based on an Fe-Zr-B alloy that is formed in an amorphous state and then annealed to produce very small grain sizes. This process makes the alloy less brittle and, thereby, decreases production costs. The alloy has even higher permeability and also higher saturation induction than the amorphous materials, but it is not yet available in manufactured transformer cores. • Transformer windings are made of either copper or aluminum in round wires, square wires, or flat sheets. The resistivity of aluminum is about 1.6 times larger than that of copper, but aluminum has a lower cost. Many different alloys of aluminum and copper are available. In general, the lower-resistance alloys are more expensive and harder to work with in the manufacturing processes, leading to higher initial costs. • In addition to choice of material, load losses are affected by the cross-sectional area of the wire used. Larger wires produce lower load losses, but then the windings are larger, and this requires a larger core, which increases the no-load losses. Long-term and Short-time Emergency Overloads • The permissible loading of transformers for normal life expectancy depends on the design of the particular transformer, its temperature rise at rated load, temperature of the cooling medium, duration of the overloads, the load factor, and the altitude above sea level if air is used as the cooling medium. ANSI- Chapter 16: Transformers and Equipment IEEE C57.92 has developed several permissible overload graphs for different types of transformers with respect to a number of factors. For example, a liquidfilled transformer with a 50% continuous equivalent base load at 30°C ambient temperature could be loaded to 120% of full load nameplate rating for five hours without excessive loss of insulation life. Total Lifetime Cost • The transformer cost has three components: capital investment, no-load loss, and load loss. If the enduser provides the energy price with the purchase request, the designer can develop a transformer design that will minimize the total lifetime cost, including the cost of losses. The result of this process is the cheapest transformer in the useful life period— i.e., with the lowest total owning cost, optimized for a given application. • Typically a transformer is designed to have a minimum loss when operated at about 50% of rating. However, a larger transformer operated at a lower fraction of rating may have a smaller cost of losses than a smaller unit operated at 50% of rating. This latter case will be particularly true in situations with significant annual load growth. • Transformer size selection, at any specific load level, is controlled by the thermal load limit, not by the cost of losses. This conclusion depends on the ratio of no-load loss to load loss for the particular set of transformers. It will be true as long as the difference in no-load loss from one transformer size to the next is larger than the load loss of the smaller size transformer when loaded near its rating. • The overall conclusion is that a utility cannot reduce transformer losses by going to a larger size transformer that will have lower load losses. The minimum loss costs are achieved if the smallest possible transformer is selected based on thermal loading limits. Polarization Index Test • If a transformer passes the insulation resistance test, before applying any overvoltage test, it is recommended to do a Polarization Index (PI) test. The polarization index is a ratio of the Megohm resistance at the end of a 10-minute test, to that at the end of a 1-minute test at a constant voltage. Another common way for PI calculation is the ratio of resistance readings that are taken 15 and 60 seconds after connecting the voltage. The following table is a guide to interpreting the PI test results. 16-41 Chapter 16: Transformers and Equipment EPRI Underground Distribution Systems Reference Book Application of Capacitors at Stations and on Feeders Polarization Index Insulation Condition Less than 1 Dangerous 1.0 - 1.1 Poor 1.1 - 1.25 Questionable 1.25 - 2.0 Fair Above 2.0 Good Power Factor Test • In general, power factor measurement equipment comes with three basic modes of operation: grounded specimen test, grounded specimen with guard, and ungrounded. The three measurement modes allow measurement of the current leaking back to the test set on each lead, individually and together. In general, a power factor of less than 1% is considered good; 1-2% is questionable; and if a power factor exceeds 2%, action should be taken. Practically, the evaluation is not only based on a single power factor data point, but is also based on the history of the change in power factor. Values obtained at the time of the original tests are used as benchmarks to determine the amount of insulation deterioration on subsequent tests. Purpose of Capacitors • Fixed and switched capacitors are inexpensive means of providing VAR compensation for distribution systems and thus correcting power factor and reducing system losses. • Advantages of installing shunt capacitors in distribution systems are as follows: —Released system capacity —Reduction in losses —Improvement in voltage regulation • Depending on the uncorrected power factor of the system, the installation of capacitors can increase the substation capability for additional load by as much as 30%, and can increase individual circuit capability, from the voltage regulation point of view, approximately 30 to 100%. Description of Capacitors • Distribution capacitors are typically housed in rectangular, sealed metal cans, which can be made of stainless steel. The cans contain rolled packs of aluminum foil with layers of insulating paper, and/or plastic film, between the foil. Recently manufactured capacitors have all-film-insulating layers. • Capacitors are rated for line-to-line voltage in the event that they are applied on ungrounded or poorly grounded systems. 16-42 • Capacitors are used in distribution stations or on distribution feeders. Station capacitors are rack mounted in large banks. Capacitors installed on feeders are usually in pole-top banks with necessary group fusing. Capacitors can be applied as fixed or switched units. Switched units have capacitor bank controllers that switch several capacitor banks. • A three-phase capacitor bank on a distribution feeder can be connected in delta, grounded-wye, or ungrounded-wye. The type of connection used depends upon: — System type—i.e., whether it is a grounded or an ungrounded system — Fusing requirements — Capacitor-bank location — Telephone interference considerations • Ungrounded-wye capacitor banks are not recommended under the following conditions: — On feeders with light load, where the minimum load per phase beyond the capacitor bank does not exceed 150% of the per-phase rating of the capacitor bank — On feeders with single-phase breaker operation at the sending end — On fixed-capacitor banks — On feeder sections beyond a sectionalizing-fuse or single-phase recloser — On feeders with emergency load transfers • Usually, grounded-wye capacitor banks are employed only on four-wire, three-phase primary systems. Otherwise, if a grounded-wye capacitor bank is used on a three-phase, three-wire ungrounded-wye or delta system, it furnishes a ground current source that may disturb ground relays. • The optimum amount of capacitor kilovars to employ is generally the amount at which the economic benefits obtained from the addition of the last kilovar equals the installed cost of the kilovars of capacitors. • The economic benefits that can be derived from capacitor installation can be itemized as: — Released generation capacity — Released transmission capacity — Released distribution substation capacity — Reduced energy (copper) losses — Reduced voltage drop, and consequently, improved voltage regulation EPRI Underground Distribution Systems Reference Book — Released capacity of feeder and associated apparatus — Postponement or elimination of capital expenditure due to system improvements and/or expansions — Revenue increase due to voltage improvements • If only fixed-type capacitors are installed, the utility will experience an excessive leading power factor and voltage rise at low-load conditions. Therefore, some of the capacitors should be installed as switchedcapacitor banks so they can switched off during lightload conditions. • A rule of thumb is often used to determine the size of the switched capacitors. Switched capacitors are added until: k var from switched + fixed capacitors ≥ 0.70 k var of peak reactive feeder load • The kilovars needed to raise the voltage at the end of the feeder to the maximum allowable voltage level at minimum load is the size of the fixed capacitors that should be used. On the other hand, if more than one capacitor bank is installed, the size of each capacitor bank at each location should have the same proportion—that is: k var of load center kVA of load center = k var of total feeder kVA of total feeder • The resultant voltage rise must not exceed the lightload voltage drop. The approximate value of the percent voltage rise is: % VR = Qc ⋅3ϕ Xl 10 ⋅VL2− L Where: % VR = percent voltage rise. Qc⋅3φ = three-phase reactive power due to fixed capacitors applied, KVAR. X = line reactance, Ω. l = length of feeder from sending end to fixedcapacitance location, mile. VL-L = line-to-line voltage, kV. • Another rule of thumb sometimes used is that: The total amount of fixed and switched capacitors for a feeder is the amount necessary to raise the receivingend feeder voltage to maximum at 50% of peak feeder load. Capacitor Location • The rule of thumb for locating the fixed capacitors on feeders with uniformly distributed loads is to locate Chapter 16: Transformers and Equipment them approximately at two-thirds of the distance from the substation to the end of the feeder. For the uniformly decreasing loads, fixed capacitors are located approximately halfway out on the feeder. The location of switched capacitors is often determined by voltage regulation requirements, and they are usually located on the last one-third of the feeder away from the source. • The best location for capacitors can be found by optimizing power loss and voltage regulation. A feeder voltage profile study is required to determine the most effective location for capacitors and a voltage that is within recommended limits. Usually, a 2-V rise on circuits used in urban areas and a 3-V rise on circuits used in rural areas are the maximum voltage changes that are allowed when a switched-capacitor bank is placed into operation. • Some summary rules that can be used in the application of capacitor banks include the following: — The location of fixed shunt capacitors should be based on the average reactive load. — There is only one location for each size of capacitor bank that produces maximum loss reduction. — One large capacitor bank can provide almost as much savings as two or more capacitor banks of equal size. — When multiple locations are used for fixed-shuntcapacitor banks, the banks should have the same rating to be economical. — For a feeder with a uniformly distributed load, a fixed-capacitor bank rated at two-thirds of the total reactive load and located at two-thirds of the distance out on the feeder from the source gives an 89% loss reduction. — The result of the two-thirds rule is particularly useful when the reactive load factor is high. It can be applied only when fixed shunt capacitors are used. — In general, particularly at low reactive load factors, some combination of fixed and switched capacitors gives the greatest energy loss reduction. — In actual situations, it may be difficult, if not physically impossible, to locate a capacitor bank at the optimum location; in such cases, the permanent location of the capacitor bank ends up being sub-optimum. Capacitor Protection Considerations • The main function of capacitor protection is to electrically remove failed capacitors from the distribution system. 16-43 Chapter 16: Transformers and Equipment • The protection must isolate a faulted bank or individual shunt capacitors without interrupting service on the remainder of the circuit. When the capacitor does fail, the protection should rapidly remove it from the system to avoid case rupture. If the protection has been properly coordinated, it should also operate before any other upstream protective devices. While fulfilling this fault-clearing role, the capacitor protection must also remain immune to a number of “normal” transient conditions such as energizing inrush, discharging/outrush, parallel switching outrush, and lightning surges. • A capacitor fuse must be selected to: — carry continuous capacitor current, — isolate a faulted capacitor, — withstand transient currents, — have sufficient interrupting capacity to interrupt the maximum fault current at the point of application, — limit the energy let-through to a faulted unit to minimize the possibility of capacitor case rupture, — protect healthy units against prolonged overvoltages. • To ensure that capacitor protection will fulfill these functions, of the following issues must be considered: — Location constraints — Bank configuration — Individual versus group protection — Continuous current 16-44 EPRI Underground Distribution Systems Reference Book — Transient currents, including discharge or outrush into faulted capacitor, inrush current, parallel switching transients, de-energizing transients, and high-frequency transients — Available fault current — Capacitor case-rupture hazard — Overvoltage protection Application of Capacitor Fuses Selection of the appropriate fuse involves consideration of the following: • Fuse Type. Through an assessment of the available system fault current and the capacitor bank configuration, the required interrupting duty of the protection device can be established. Reviewing the available fault current and the appropriate case-rupture curves for the capacitor units will dictate whether 1/2-cycle fault clearing is adequate or if fractional-cycle clearing is necessary. This review will also determine whether an expulsion of a current-limiting fuse is required. • Fuse Current Rating and Speed. The idealized goal for capacitor fuse application is the selection of the fastest fuse that will avoid damage from the range of transient conditions. These conflicting requirements must be reconciled when choosing the fuse rating and speed ratio. Withstanding continuous current and transients would suggest use of a slow speed fuse, whereas reducing case rupture and overvoltage require a fast fuse. EPRI Underground Distribution Systems Reference Book REFERENCES ABB. 2002. ABB Distribution Transformer Guide. ABB Distribution Transformer Division. ABB. 2007. ABB Transformer Handbook. ABB Management Services Ltd. ANSI/IEEE 1981. ANSI/IEEE Std C57.92-1981. “IEEE Guide for Loading Mineral-Oil-Immersed Power Transformers Up to and Including 100 MVA with 55 Degree C and 65 Degree C Average Winding Rise.” ANSI/IEEE. 1990. ANSI/IEEE C37.99. “Guide for Protection of Shunt Capacitor Banks.” ANSI/IEEE. 2000. ANSI/IEEE C57.12.00-2000. “General Requirement for Liquid-Immersed Distribution, Power, and Regulating Transformers.” ASTM. 2002. ASTM D877. “Standard Test Method for Dielectric Breakdown Voltage of Insulating Liquids Using Disk Electrodes.” ASTM. 2004. ASTM D1816-04. “Standard Test Method for Dielectric Breakdown Voltage of Insulating Oils of Petroleum Origin Using VDE Electrodes.” ASTM. 2008a. ASTM D924-08. “Standard Test Method for Dissipation Factor (or Power Factor) and Relative Permittivity (Dielectric Constant) of Electrical Insulating Liquids.” ASTM. 2008b. ASTM D974-08. “Standard Test Method for Acid and Base Number by Color Indicator Titration.” ASTM. 2009. ASTM D664-09. “Standard Test Method for Acid Number of Petroleum Products by Potentiometric Titration. Chapter 16: Transformers and Equipment Duval, M. 2004. “Recent Developments in DGA Interpretation.” CIGRE TF 15/12-01-11. IEEE. 1991. C57.104-1991. “IEEE Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers.” IEEE. 1995a. Standard 62-1995. “Guide for Diagnostic Field Testing of Electric Power Apparatus, Part 1: Oil Filled Power Transformers, Regulators, and Reactors.” IEEE. 1995b. C57.91-1995, “IEEE Guide for Loading Mineral-Oil- Immersed Transformers.” IEEE. 1999. IEEE C57-100. “Standard Test Procedure for Thermal Evaluation of Liquid-Immersed Distribution and Power Transformers.” IEEE. 2006a. C57.106-2006. “IEEE Guide for Acceptance and Maintenance of Insulation Oil in Equipment.” IEEE. 2006b. C57.12.90–2006. “IEEE Standard Test Code for Liquid-Immersed Distribution, Power and Regulating Transformers.” NEMA. 1964. TR-98-1964. “Guide for Loading OilImmersed Power Transformers with 65°C Average Winding Rise.” NEMA. 1993. NEMA TRI-1993. “Transformers, Regulators, and Reactors. NEMA. 2002. NEMA Standards Publication TP 12002. Guide for Determining Energy Efficiency of Distribution Transformers. Pabla, A. S. 2004. Electric Power Distribution. McGrawHill. Short, T. 2004. Electric Power distribution Handbook. CRC Press. DOE (Department of Energy). 2007. 10 CFR Part 431, Part III, 2007. “Energy Conservation Program for Commercial Equipment: Distribution Transformers Energy Conservation Standards; Final Rule.” Winders, J. 2002. Power Transformers, Principles and Applications. Marcel Dekker. 16-45