capability to electromechanical network relays. In the past, these sup- plemental relays had minimum time delays of 1 s or more since their mission was to wait for the elevator to descend. However, not all util- ities endorse this low-current, time-delay technique. Some feel that any time delay in opening the network protectors degrades the high service quality that the network system is intended to provide. The load-generation control and DG tripping schemes mentioned above are intended to ensure that the network protectors are never opened by exported power. As long as the schemes work properly, the network protectors are never exposed to the out-of-phase voltage con- ditions that may exceed the switch capability. However, because of the potentially catastrophic consequences of causing a network protector failure, it is prudent to provide a backup. An interlocking scheme that trips the DG instantaneously when a certain number of network pro- tectors have opened ensures that the network protectors will not be exposed to out-of-phase voltages for more than a few cycles. The deci- sion as to how many protectors must open before the DG is tripped (one, two, or all) is a tradeoff between security of the protectors and nuisance tripping of the DG. Note that this scheme does not relieve the DG installer from the responsibility of providing stuck-breaker backup protection for the DG’s switching device. An even more secure approach to avoiding overstressing the network protectors is to replace existing protectors with new designs that are capable of interrupting fault currents from sources with higher X/R 422 Chapter Nine Time Adjustable delay time Time delay for low currents Adjustable instantaneous trip threshold Instantaneous trip for higher currents 100 Current (% of transformer rating) Figure 9.32 Adjustable reverse-power characteristic. Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. ratios and of withstanding out-of-phase voltages across the open switch. One major U.S. manufacturer of network protector units has recently introduced such high-capacity protectors in 800- to 2250-A rat- ings and plans to introduce them in ratings up to 6000 A. These pro- tectors are designed to be retrofitted in many existing types of network units. A possible DG interconnection problem exists that would involve net- work protectors without a network bus interconnection. If a DG is interconnected on a feeder that also supplies a network unit, then if its feeder breaker is tripped and the DG is not rapidly isolated, it may impact one or more of the network units as if it were isolated on the net- work bus. For this type of event to occur, the DG output does not have to be matched to the feeder load. For the excess generation case, it only has to be momentarily greater than the load on the network bus. Under this condition the power continues to flow to the network bus from the feeder with the interconnected DG, which keeps that protector closed. However, the excess power flows through the network back to the other feeders, resulting in the opening of the protectors connected to those feeders. Once open, these protectors will be separating two indepen- dent systems. For the case of less generation than load, the protector connecting to the feeder with the generation may trip. Again, such a condition would have a protector separating two independent systems. Therefore, such DG applications should be avoided unless the DG breaker is interlocked with the feeder breaker with a direct transfer trip scheme. 9.7 Siting DG The value of DG to the power delivery system is very much dependent on time and location. It must be available when needed and must be where it is needed. This is an often neglected or misunderstood concept in discussions about DG. Many publications on DG assume that if 1 MW of DG is added to the system, 1 MW of additional load can be served. This is not always true. Utility distribution engineers generally feel more comfortable with DG installed on facilities they maintain and control. The obvious choice for a location is a substation where there is sufficient space and com- munications to control centers. This is an appropriate location if the needs are capacity relief on the transmission system or the substation transformer. It is also adequate for basic power supply issues, and one will find many peaking units in substations. However, to provide sup- port for distribution feeders, the DG must be sited out on the feeder away from the substation. Such generation will also relieve capacity constraints on transmission and power supply. In fact, it is more effec- Distributed Generation and Power Quality 423 Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. tive than the same amount of DG installed in the substation. Unfortunately, this generation is usually customer-owned and distrib- ution planners are reluctant to rely on it for capacity. The application of DG to relieve feeder capacity constraints is illus- trated in Fig. 9.33. The feeder load has grown to where it exceeds a limit on the feeder. This limit could be imposed by either current rat- ings on lines or switchgear. It could also be imposed by bus voltage lim- its. There is DG on the feeder at a location where it can actually relieve the constraint and is dispatched near the daily peak to help serve the load. The straightforward message of the figure is that the load that would otherwise have to be curtailed can now be served. Therefore, the reliability has been improved. This application is becoming more common as a means to defer expansion of the wire-based power delivery infrastructure. The gener- ation might be leased for a peak load period. However, it is more com- mon to offer capacity credits to customers located in appropriate areas to use their backup generation for the benefit of the utility system. If there are no customers with DG in the area, utilities may lease space to connect generation or, depending on regulatory rules, may provide some incentives for customers to add backup generation. There is by no means universal agreement that this is a permanent solution to the reliability problem. When utility planners are shown Fig. 9.33, most will concede the obvious, but not necessarily agree that this situation represents an improvement in reliability. Three of the stronger arguments are 1. If the feeder goes out, only the customer with the DG sees an improvement in reliability. There is no noticeable change in the ser- vice reliability indices. 424 Chapter Nine Feeder Limit DG Dispatched ON Daily Load Profile DG Sited to Provide Feeder Relief Figure 9.33 DG sited to relieve feeder overload constraint. Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. 2. Customer generation cannot be relied upon to start when needed. Thus, the reliability cannot be expected to improve. 3. Using customer-owned generation in this fashion masks the true load growth. Investment in wire facilities lags behind demand, increasing the risk that the distribution system will eventually not be able to serve the load. It should also be noted that the capacity relief benefit is nullified when the distribution system is upgraded and no longer has a con- straint. Thus, capacity credits offered for this application generally have a short term ranging from 6 months to 1 year. If one had to choose a location on the distribution feeder, where should the DG be located? The optimal DG siting problem is similar to the optimal siting problem for shunt capacitor banks. Many of the same algorithms can be used with the chief difference being that the object being added produces watts in addition to vars. Some of the same rules of thumb also apply. For example, if the load is uniformly distributed along the feeder, the optimal point for loss reduction and capacity relief is approximately two-thirds of the way down the main feeder. When there are more generators to consider, the problem requires computer programs for analysis. The utility does not generally have a choice in the location of feeder- connected DG. The location is given for customer-owned generation, and the problem is to determine if the location has any capacity-related value to the power delivery system. Optimal siting algorithms can be employed to evaluate the relative value of alternative sites. One measure of the value of DG in a location is the additional amount of load that can be served relative to the size of the DG. Transmission networks are very complex systems that are sometimes constrained by one small area that affects a large geographical area. A relatively small amount of load reduction in the constrained area allows several times that amount of load to be served by the system. This effect can also be seen on distribution feeders. Because of the simple, radial structure of most feeders, there is generally not a con- straint so severe that DG application will allow the serving of addi- tional load several times greater than the size of the generator. However, there can be a multiplying effect as illustrated in Fig. 9.34. This example assumes that the constraint is on the feeder rather than on the substation. If 1 MW of generation were placed in the sub- station, no additional load could be served on the feeder because no feeder relief has been achieved. However, if there is a good site on the feeder, the total feeder load often can grow by as much as 1.4 MW. This is a typical maximum value for this measure of DG benefit on radial distribution feeders. Distributed Generation and Power Quality 425 Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. Another application that is becoming common is the use of DG to cover contingencies. Traditionally, utilities have built sufficient wire- based delivery capacity to serve the peak load assuming one major fail- ure (the so-called N-1 contingency design criterion). At the distribution feeder level, this involves adding sufficient ties to other feeders so that the load can be conveniently switched to an alternate feeder when a failure occurs. There must also be sufficient substation capacity to serve the normal load and the additional load expected to be switched over during a failure. This results in substantial overcapacity when the system is in its normal state with no failures. One potentially good economic application of DG is to provide sup- port for feeders when it is necessary to switch them to an alternate source while repairs are made. Figure 9.35 depicts the use of DG located on the feeder for this purpose. This will be substantially less costly than building a new feeder or upgrading a substation to cover this contingency. The DG in this case is located near the tie-point between two feeders. It is not necessarily used for feeder support during normal conditions although there would often be some benefits to be gained by operating the DG at peak load. When a failure occurs on either side of the tie, the open tie switch is closed to pick up load from the opposite side. The DG is dispatched on and connected to help support the backup feeder. Locating the DG in this manner gives the utility additional flexibil- ity and more reconfiguration options. Currently, the most common DG technology used for this application is currently diesel gensets. The gensets may be mounted on portable trailers and leased only for the peak load season when a particular contingency leaves the system vul- nerable. One or more units may be interconnected through a pad- 426 Chapter Nine ⌬P load ⌬P gen = 0 ⌬P load ⌬P gen = 1.4 Figure 9.34 Ability of DG to increase the capacity of a distribution feeder is dependent on DG location. Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. mounted transformer and may also employ a recloser with a DG pro- tection relay. This makes a compact and safe interconnection package using equipment familiar to utility personnel. 9.8 Interconnection Standards Standards for interconnection of DG to distribution systems are exam- ined in this section. Two examples illustrating the range of require- ments for interconnection protection are presented. 9.8.1 Industry standards efforts There have been two main DG interconnection standards efforts in the United States. IEEE Standard 929-2000 5 was developed to address requirements for inverters used in photovoltaic systems interconnected with utility systems. The standard has been generally applied to all technologies requiring an inverter interface. One of the main issues this standard addresses is the anti-islanding scheme. The basic idea is to introduce a destabilizing signal into the switching control so that it will quickly drift in frequency if allowed to run isolated while the con- trol thinks it is still interconnected. Amid fears that vendors would independently choose schemes that might cancel out each other, agree- ment was reached on a uniform direction to drive the frequency. Another, more contested effort has been the development of IEEE Standard P1547, 10 which has not been approved as of the time of this writing. The intent is to develop a national standard that will apply to the interconnection of all types of DG to both the radial and network dis- tribution systems. Vendors, utilities, and end users have joined in this effort, which appears to be converging. This draft standard addresses many of the issues described in this chapter, and the approach taken here is largely consistent with the contents of this document. 9.8.2 Interconnection requirements The basic requirements for interconnecting DG to the utility distribu- tion system are listed here. Distributed Generation and Power Quality 427 Figure 9.35 DG sited near the tie-point between two feeders to help support contingencies. Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. Voltage regulation. DG shall not attempt to regulate voltage while interconnected unless special agreement is reached with the utility. As pointed out previously, this generally means that the DG will operate at a constant power factor or constant reactive power output acceptable to the operation of the system. Inverters in utility-interactive mode would typically operate by producing a current in phase with the volt- age to achieve a particular power output level. Anti-islanding. DG shall have relaying that is capable of detecting when it is operating as an island and disconnect from the power sys- tem. Inverters should be compliant with IEEE Standard 929-2000 such that they would naturally drift in frequency when isolated from the utility source. Relaying to detect resonant conditions that might occur should be applied in susceptible DG applications. Fault detection. DG shall have relaying capable of detecting faults on the utility system and disconnecting after a time delay of typically 0.16 to 2.0 s, depending on the amount of deviation from normal. DG should disconnect sufficiently early in the first reclose interval to allow tem- porary faults to clear. (The utility may have to extend the first reclose interval to ensure that this can be accomplished.) However, to prevent nuisance tripping of the DG, the tripping should not be too fast. The 0.16-s (10 cycles at 60 Hz) delay is to allow time for faults on the trans- mission system or adjacent feeder to clear before tripping the DG need- lessly. Settings proposed for voltage and frequency relays for this applica- tion are given in Table 9.1. 10 The cutoff voltages are nominal guidelines and may have to be modified for some applications. A common adjust- ment is to decrease the voltage trip levels to avoid nuisance tripping for faults on parallel feeders. For example, faults on parallel feeders will sometimes give voltages less than 50 percent, requiring the setting on 428 Chapter Nine TABLE 9.1 Typical Voltage and Frequency Relay Settings for DG Interconnection for a 60-Hz System Condition Clearing time, s V Յ 50% 0.16 50% Ͻ V Յ 88% 2.0 110% Ͻ V Յ 120% 1.0 V Ͼ 120% 0.16 f Ͻ 59.3 Hz 0.16 f Ͼ 60.5 Hz 0.16 Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. the 10-cycle trip to be reduced to perhaps 40 percent. The frequency trip settings may be adjusted according to local standards. Some utili- ties may want larger DG to remain connected to a much lower fre- quency (e.g., 57 Hz) to help with system stability issues following loss of a major generating plant or a tie-line. Direct transfer trip (optional). For applications where it is difficult to detect islands and utility-side faults, or where it is not possible to coor- dinate with utility fault-clearing devices, direct transfer trip should be applied such that the DG interconnect breaker is tripped simultane- ously with the utility breaker. Transfer trip is usually advisable when DG is permitted to operate with automatic voltage control because this situation is much more likely to support an inadvertent island. Transfer trip is relatively costly and is generally applied only on large DG systems. Two relaying schemes for meeting these requirements are presented in Secs. 9.8.3 and 9.8.4. 9.8.3 A simple interconnection The protection scheme shown in Fig. 9.36 applies to small systems that are not expected to be able to support islands by themselves. There is not universal agreement on what constitutes a “small” DG system. Some utilities draw the line at 30 kW, while others might restrict this to less than 10 kW. Some may allow this kind of interface protection for Distributed Generation and Power Quality 429 SERVICE TRANSFORMER ? ? LOAD DR 27/59 81 O/U Figure 9.36 Simple interconnection protection scheme for smaller generators. Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. sizes up to 100 kW, or more. The two relaying functions shown are expected to do most of the work even for large DG systems. Large sys- tems have additional relaying to provide a greater margin of safety. Small DG systems would commonly be connected to the load bus at secondary voltage levels. There would not be a separate transformer, although there may be separate metering. Overcurrent protection is provided by molded case circuit breakers. The main DG interface pro- tection functions are 1. Over/under (O/U) voltage (27/59 relay) 2. Over/under frequency (81 O/U relay) These relays can be used to trip either the generator breaker or the main service breaker, depending on the desired mode of operation. Tripping only the generator leaves the load connected, and this is prob- ably the desired operation for most loads employing small cogeneration or peaking generators. However, the utility may require the main breaker to be tripped if the DG system is running when a disturbance occurs. The main service breaker would also be tripped if the DG system is to be used for backup power so that the DG system can continue to sup- ply the load off-line. It should be noted that special controls (not shown in Fig. 9.36) may be required for this transfer to occur seamlessly. It is not always easy to accomplish. The over/under voltage relay has the primary responsibility to detect utility-side disturbances. There should be no frequency deviation until the utility fault interrupter opens. If the fault is very close to the gen- erator interconnection point and the voltage sag is deep, the overcur- rent relaying may also see the fault. This will depend on the capability of the DG system to supply fault current. The overcurrent breakers are necessary for protecting the DG system in case of an internal fault. Once the distribution feeder is separated from the utility bulk power system, an island forms. The voltage and frequency relays then work in concert to detect the island. One would normally expect the voltage to collapse very quickly and be detected by the undervoltage relay. If this does not happen for some reason, the frequency should quickly drift outside the narrow band expected while interconnected so that the 81 O/U relay would detect it. 9.8.4 A complex interconnection The second protection scheme described here represents the other extreme from the simple scheme presented in Sec. 9.8.3. Figure 9.37 shows the key functions in an actual distribution-connected DG instal- lation that employs a primary-side recloser. This is a relatively complex 430 Chapter Nine Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. interconnection protection scheme for a large synchronous generator. There are many other variant schemes that may also be applied, and the reader is referred to vendors of DG packages whose literature describes these in great detail. A large DG installation on the distribution system would typically correspond to generators in the 1- to 10-MW range. Most generators larger than this will be interconnected at the transmission level and have relaying similar to utility central station generation. Figure 9.37 shows the relays necessary for interface protection as well as some of the relays necessary for generator protection. Not all Distributed Generation and Power Quality 431 Figure 9.37 Protection scheme for a large synchronous generator with high- side recloser. 81 O/U 27/59 47 59 I 59 N 25 46 50/51V DG 87G 32R 40 46 50/51 (GENERATOR PROTECTION) 51G UTILITY BREAKER OR RECLOSER GENERATOR TRANSFORMER ANOTHER GENERATOR Distributed Generation and Power Quality Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. [...]... Transactions on Power Apparatus and Systems, Vol 86, No 10, October 196 7, pp 1258–1265 9 D R Smith, S R Swanson, J D Borst, “Overvoltages with Remotely-Switched Cable-Fed Grounded Wye-Wye Transformers,” IEEE Transactions on Power Apparatus and Systems, Vol PAS -94 , No 5, September/October 197 5, pp 1843–1853 10 IEEE Standard P1547, Distributed Resources Interconnected with Electric Power Systems, Draft... 142- 199 1, IEEE Recommended Practice for Grounding of Industrial and Commerical Power Systems, copyright © 199 1 by the Institute of Electrical and Electronics Engineers, Inc The IEEE disclaims any responsibility or liability resulting from the placement and use in this publication Information is reprinted with the permission of the IEEE †Reprinted with permission from NFPA 70- 199 3, the National Electrical. .. concerns for power quality Power quality considerations associated with wiring and grounding practices are covered in Federal Information Processing Standard (FIPS) 94 , Guideline on Electrical Power for ADP Installations ( 198 3) This is the original source of much of the information interpreted and summarized here The IEEE Emerald Book (ANSI/IEEE Standard 1100- 199 2, IEEE Recommended Practice for Powering... 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Institute of Electrical Engineers, London, U.K., 2000 3 W E Feero, W B Gish, “Overvoltages Caused by DSG Operation: Synchronous and Induction Generators,” IEEE Transactions on Power Delivery, January 198 6, pp 258–264 4 R C Dugan, D T Rizy, Harmonic Considerations for Electric Distribution Feeders, ORNL/Sub/81 -95 011/4, Oak Ridge National Laboratory, U.S DOE, March 198 8 5 IEEE Standard 92 9-2000, Recommended... Protection of Low Voltage Systems, IEE Power Series 12, Peter Peregrinus, Ltd., London, 199 2 Mardiguian, Michael, A Handbook Series on Electromagnetic Interference and Compatibility, Vol 2, Grounding and Bonding, Interference Control Technologies, Inc., Gainesville, Va., 198 8 Morrison, Ralph, and Warren H Lewis, Grounding and Shielding for Facilities, John Wiley & Sons, New York, 199 0 Ott, Henry W., Noise... Reduction Techniques in Electronic Systems, 2d ed., John Wiley & Sons, New York, 198 8 Downloaded from Digital Engineering Library @ McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2004 The McGraw-Hill Companies All rights reserved Any use is subject to the Terms of Use as given at the website Source: Electrical Power Systems Quality Chapter 11 Power Quality Monitoring Power quality monitoring is... conducting ground current to and from the earth (or the conducting body) IEEE Green Book (IEEE Standard 142) definitions* *Reprinted from IEEE Standard 100- 199 2, IEEE Standard Dictionary of Electrical and Electronic Terms, copyright © 199 3 by the Institute of Electrical and Electronics Engineers, Inc The IEEE disclaims any responsibility or liability resulting from the placement and use in this publication... Distribution Systems, EPRI Final Report, TR-1055 89, November 199 5 Integration of Distributed Resources in Electric Utility Systems: Current Interconnection Practice and Unified Approach, EPRI Final Report, TR-1114 89, November 199 8 “Interconnecting Distributed Generation to Utility Distribution Systems, ” Short Course, The Department of Engineering Professional Development, University of Wisconsin— Madison, 2001 . and Grounding 4 39 *Reprinted from IEEE Standard 142- 199 1, IEEE Recommended Practice for Grounding of Industrial and Commerical Power Systems, copyright © 199 1 by the Institute of Electrical and. Louisville, Ky., May 7 9, 2000, pp. C4-1–C4-7. Engineering Handbook for Dispersed Energy Systems on Utility Distribution Systems, EPRI Final Report, TR-1055 89, November 199 5. Integration of Distributed. Chapter Ten *Reprinted from IEEE Standard 100- 199 2, IEEE Standard Dictionary of Electrical and Electronic Terms, copyright © 199 3 by the Institute of Electrical and Electronics Engineers, Inc. The