A 35-kv System Voltage Sag Improvement

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A 35-kV System Voltage Sag Improvement M. Stephen Daniel, Senior Member, IEEE

Abstract—Electric utilities began to operate distribution systems at 35 kV about 20 years ago. Experience soon revealed that some unique conditions existed as the distribution voltage was increased to this level. Customers served by a substation feeder complained of blinking lights and equipment problems when a fault occurred on the adjacent feeder of the same substation. A comparison can be made between the voltage sag that occurs on a 12-kV and 35-kV system using system impedance and symmetrical component calculations. Most of the 35-kV voltage drop, during a fault, occurs in the substation power transformer. The low voltage appears at the substation low side bus. This paper includes field test data that verify the symmetrical component calculations for existing system conditions. It explains how lower impedance power transformers and special considerations for 35-kV system design will make improvements in voltage sag of up to 20%.

lems are experienced to a lesser degree on the higher impedance 12-kV and 13-kV distribution systems. This paper utilizes the Computer & Business Equipment Manufacturer’s Association acceptable voltage curve to evaluate the resultant voltage sags on the 12-kV and 35-kV systems. The CBEMA curve has been used by many to consider acceptable voltage for most equipment. This paper will utilize the CBEMA curve to illustrate that most equipment will operate properly at a 40% voltage drop for less than three cycles. The system conditions during a fault and the duration of typical faults will also be analyzed to determine possible solutions.

Index Terms—Fault currents, fault location, impedance, power distribution, power transformer, substation, voltage control.

II. SYSTEM SUMMARY A. Distribution System

I. INTRODUCTION

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HE NOMINAL transmission system voltages used by Alabama Power, A Southern Company, are 500, 230, 161, 115, and 44 kV while distribution voltages are 35, 22, 13, 12, and 4 kV. As load growth continues at rates of 2 to 8% per year, converting 4 to 12-kV distribution is an ongoing economic decision. About 20 years ago, economic studies indicated the need to convert the 12-kV system to a 25- or 35-kV system. The decision was made to begin converting to 35 kV in high growth areas south of Birmingham, Alabama. The growth continued and the 35-kV system today serves over 50,000 customers from 13 substations rated at 60 MVA. The design of the 35-kV distribution system is very similar to the design of lower voltage distribution systems. It was assumed that operating characteristics would also be similar. After operating the system for almost ten years, several operating problems began to occur with no apparent solutions. Switching underground cable utilizing elbows on dead front equipment resulted in unexpected faults. This problem was addressed with special “switchable transformers.” Another “surprising” problem was the severe voltage sag occurring on the transmission system and at the substation bus during a distribution feeder fault. This paper will address the system characteristics and solutions that have been implemented by Alabama Power. The low impedance of 35-kV distribution feeders is the most substantial factor that causes voltage sag problems. These prob-

Manuscript received August 26, 2002. The author is with Alabama Power, A Southern Company, Birmingham, AL 35203-2200 USA. Digital Object Identifier 10.1109/TPWRD.2003.820170

Alabama Power utilizes 397-kCM ACSR or 795-kCM AAC feeder conductors for both the 12- and 35-kV systems. This practice allows loading of 600 or 900 A on both systems. But the impedance of these almost identical feeders on the two systems is very different. One kilometer of a 12-kV feeder has a per unit impedance 7.65 times greater than a 1-km 35-kV feeder of the same conductor. This characteristic causes more voltage drop to occur within the feeder conductor on the 12-kV system during a fault. This results in less voltage drop in the substation and transmission system. B. Total System Impedance A voltage divider calculation indicates the voltage drop occurring in the transmission system, the substation power transformer, and 1 km of 35-kV distribution feeder. All system calculations below are on a 100-MVA base. These results (Fig. 1) indicate the voltage drop across the generation and transmission system is 11.13% of the total. The voltage drop across the substation power transformer is 71.10% of the total and the feeder voltage drop is 17.76% of the total. The voltage drop to the low side substation bus excludes the feeder voltage drop. Other feeders attached to this bus will experience the same voltage sag even though the fault occurs under separate protective devices. The bus voltages of phases that do not experience the fault are affected minimally. The magnitude of the 35-kV voltage sag problem is reduced some as the distance to the fault from the substation bus increases, but the problem is significant for faults occurring up to 7 km from the substation bus. Figs. 2 and 3 illustrate the significant difference in performance of the 12- and 35-kV systems during a fault on the distribution feeder (100-MVA base calculations).

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Phase-to-ground fault voltage sag

(6) (7) Power Transf

(8) (9) (10)

Fig. 1. Voltage divider of 35-kV system components showing the percentage drop within system during a fault 1 km from bus. (Z p:u: impedance).

(11)

Fig. 2. Voltage divider-12 kV and 35 kV. Compare voltage sag (percentage drop) within system components for 12 and 35 kV with a fault occurring 1 km from the substation bus. Note the significant difference in power transformer and feeder portions of the two systems.

The system impedance calculations on a 100-MVA base take into consideration items 1, 2, and 3 as follows. 1) Generation and transmission system impedance are made up of A, B, and C A) The generating plant. B) The 230-kV transmission lines to a 230/115-kV transmission substation. C) The 115-kV transmission lines from a transmission substation to each 115/35-kV substation. 2) Substation power transformer impedance (60 MVA 115/35 kV). 3) Distribution system feeder conductor impedance (397-kCM ACSR or 795-kCM AAC).

=

Fig. 3. Compare the voltage sag (percentage drop) at a 12- and 35-kV substation bus for faults at 1-km intervals along the feeder.

III. SYSTEM IMPEDANCE A. Symmetrical Component Evaluation Three-phase fault voltage sag A

(1) (2) (3) (4) (5)

Even though all three systems components’ impedance are used in the calculations, the voltage drop of interest is at the power transformer low side bus. These calculations use the positive, negative, and zero sequence system impedance, per unit base ohms, and per unit base current to determine the threephase and phase-to-ground fault currents at the substation bus and at 1-km intervals along the distribution feeder. The voltage sag calculation utilizes the fault current for a particular fault location and the system impedance from the generation plant to the substation power transformer low side bus. A fault at the bus is a short circuit at that point which yields a voltage sag of 100% drop while a fault about 7 km from the substation bus results in voltage sag of 40% drop for a (8.3% on a 30-MVA base) 60-MVA power transformer with a 397-kCM ACSR feeder. Fig. 3 indicates voltage sag for phase-to-ground faults occurring at the substation bus and at 1-km intervals along a 12-kV and a 35-kV distribution feeder. Three-phase and phase-to-phase faults are not addressed for clarity. The substation selected here is Inverness Substation, a 115/35-kV 60-MVA substation located near Birmingham, AL. The main distribution feeders are 397-kCM ACSR 35 kV. Voltage curves for the faults at 1-km intervals are shown, indicating decreasing voltage sag as faults occur farther from the substation low side bus. Alabama Power studied the possible use of feeder reactors during 1993. The benefits of reactors were being investigated by several utilities operating 35-kV systems in the US. Reactors

DANIEL: 35-kV SYSTEM VOLTAGE SAG IMPROVEMENT

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do not totally solve the problem and require major capital investments. Another disadvantage of reactors is the physical size with limited space in existing substations. Alabama Power does not recommend the installation of feeder reactors. B. Transmission System While the low impedance of the 35-kV distribution feeder is a contribution to fault voltage sag, the high impedance of the substation power transformer, generation, and the transmission system also is a contributor. Any increase in the distribution feeder impedance or decrease in the generation, transmission system, and power transformer impedance will offer some fault voltage sag improvement. Reduced transmission system impedance can be demonstrated by the new South Jefferson Transmission Substation installed during 1997 near Birmingham, AL. The new 230/115-kV transmission substation offers a new strong 115-kV source for the 35-kV system. Compare the generation and transmission system impedance on a 100-MVA base before the installation of South Jefferson to the improved impedance after installation . For example, a fault 3 km from the substation bus prior to the installation of the South Jefferson 230/115-kV Transmission Substation would cause a voltage sag of 62% drop. The same fault after the installation of South Jefferson would improve to 60% drop. Viewing the change another way, the 62% voltage sag fault location on the feeder moves from 3 km to an improved location of 2.8 km from the substation. The movement of the 35-kV fault locations curve (Fig. 3) toward the 12-kV curve is considered an improvement. Although an improbable result, moving the 35-kV curve to the 12-kV curve would be a 100% improvement. C. Power Transformer The portion of the system offering the most significant contribution to voltage sag is the 115/35-kV substation power transformer. As shown earlier, the (8.3% on 30-MVA base) 60-MVA power transformer offers 71.10% of the total system voltage drop during a fault occurring 1 km from the substation bus on a 397-kCM feeder. It seems the easiest solution would be to lower the impedance of the power transformer, thus dropping less voltage from the source to the bus. The proposal to lower the impedance was investigated to determine the advantages and the disadvantages. The goal was to come as close as possible to 12-kV system results. A very low impedance power transformer could be manufactured, but cost adders may be required and fault currents would increase above the 8000-A rating of some line devices. So it was necessary to determine the appropriate lower impedance value for the best overall results. IV. IMPROVEMENT GOALS A. CBEMA and Voltage Sag of 40% Drop Figs. 2 and 3 confirm that even the 12-kV system experiences voltage sag. Utilities know from recent experience that customer complaints also result from voltage sag occurring on the 12-kV system, but not as often as on the 35-kV system. The reason for customer equipment problems becomes clear with

Fig. 4. CBEMA curve. Voltage sag inside the envelope is acceptable for most electronic equipment. Note the 60% resultant voltage (40% drop) is acceptable for a duration of 1/2 to two cycles.

the information provided by the Computer Business and Equipment Manufacturers Association (CBEMA) curve referred to by IEEE 446–1995 [1]. This study provides information about various electronic equipment tolerances of voltage variations for short periods of time. The curve is helpful in determining the effects of various power system disturbances on electronic equipment. Large power transformers and longer distribution feeders are common with higher voltage systems [2]. Therefore, more customers are exposed to a single fault current event. Customers continue to report increased costs associated with voltage sags caused by faults on distribution systems. Even though utilities economically justify utilizing higher voltage systems, studies have shown there may be no economic advantage in these systems [3]. These systems may result in economic disadvantages for both the customer and the utility. While economic studies may indicate 35 kV reduces substation and transmission expenses, the distribution system incurs extra cost for equipment and the severe voltage sag causes customer complaints that will not occur as frequently with a 12-kV or even a 25-kV system. B. Power Transformer Impedance Improvement If the 35-kV system is to operate with voltage sag similar to the 12-kV system, the 40% voltage sag fault location must be brought closer to the substation. The 7.0 km mentioned above can be reduced to 5.0 km with a 6.0% (on 30-MVA base) power transformer and to 4.1 km with parallel 8.3% (on 30-MVA base) units. Either of these options would bring the 35-kV voltage sag closer to the 12-kV performance. However, the parallel transformer arrangement may allow fault currents that exceed equipment ratings. To improve the voltage sag condition, this study has resulted in a recommendation that the power transformer impedance is reduced from the value that has been specified for the past 20 years. Also, at two locations, 25-MVA power transformers with twice the impedance of the 60-MVA units had been installed and another was planned for 1997. It was recommended that no additional 25-MVA units are specified and that a 60-MVA unit replace the planned 25-MVA unit. Beginning in 1997, the 60-MVA power transformer load rating was upgraded before the addition of fans and forced oil cooling such that the base rating of 30 MVA was increased to 36 MVA. With this new rating in consideration, the 20–year old

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Fig. 5. Compare the resultant voltage sag (percentage drop) within system. Note the 35-kV 6.64% power transformer results in less drop within the power transformer.

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Fig. 6. Compare voltage sag (percentage drop) at the bus of a 12-kV and 35-kV substation with the old 8.3% power transformer impedance and the new 6.64% impedance. The 40% fault location is reduced from 7 to 5.6 km, 24% closer to the 12-kV 40% fault location.

35-kV impedance specification at Alabama Power was revised to consider voltage sag improvement while limiting maximum actual fault currents to near 8000 A. To reduce voltage sag, an impedance of 8.0% will be specified for all future power transformers. This specification requires no additional manufacturing cost. The new 8.0% impedance on a 36-MVA base is equivalent to 6.64% on a 30-MVA base. Comparing the 6.64% unit to the 8.3% unit results in a 20% impedance reduction. The resultant maximum fault current on the 35-kV system will be 7274 A; a value that should not frequently damage existing 35-kV equipment rated at 8000 A. The impedance reduction will move the 40% voltage sag fault location approximately 20% closer to the 12-kV 40% fault location. The improvements are shown in Figs. 5 and 6. C. Reduce Fault Duration The results of voltage sag tests under actual fault conditions on the Alabama Power 35-kV system are shown in Fig. 7. The fault was set up by closing a 10-A fuse and a 100-A fuse at the 2800-A fault location 4.8 km from the Elliotsville Substation. The results indicate that a voltage sag of 50% occurs for 1/2 cycle and 2(1/2) cycles for the 10-A and 100-A fuses, respectively. The 50% voltage sag field test at 4.8 km verifies the 35-kV curves of Figs. 3 and 6. Note that the smaller fuse interrupts the fault in less than one cycle, thus reducing the voltage sag duration. Tests utilizing 30- and 50-A fuses also resulted in fault interruption times of approximately one cycle. The field tests verified calculated values and show improvements are possible by reducing fuse sizes. Current limiting fuses tested at the field site reduced the 2800-A fault current to 300 A, eliminating voltage sag. However, the cost and limited size availability of current limiting fuses does not justify their use when compared with a 30-A fuse that clears a fault within one cycle [4]. As shown in Fig. 6, the location on each feeder that a fault will cause a voltage sag of 40% or less is 5.6 to 7.0 km from the substation bus. The 35-kV feeder voltage sag for faults beyond this distance should not cause customer complaints. The results are the same as voltage sag for faults that occur beyond 1.8 km on a 12-kV feeder. Therefore, the need to improve phase-to-ground

Fig. 7. Field test fault 4.8 km from bus. Fault current of 2800 A resulted in a voltage sag of 50% drop for a duration of 1/2 to 2(1/2) cycles for 10- and 100-A fuses, respectively.

Fig. 8.

One-second duration of a voltage sag of 45% drop.

fault voltage sag conditions occurs less than 7 km from the bus.

DANIEL: 35-kV SYSTEM VOLTAGE SAG IMPROVEMENT

The single-phase protection on distribution feeder radial taps is typically a 100-A fuse, the maximum fuse size that coordinates with most substation breaker relays. Fuse clearing times may be three to six cycles, allowing voltage sag to remain for this time duration. Loading on single phase lines will allow 90% of these fuses to be reduced to 30 A or 50 A, allowing clearing times of one half to one cycle. The single-phase line loading was evaluated and 100-A cutout-type switches were refused only within 7.0 km of the substations. The connected kilovolt amperes (kVA) was determined, doubled for cold load pick up and 30- or 50-A fuses were installed where load allowed. Less than 10% required 75- or 100-A fuses. Current limiting fuses were deemed too costly for system-wide use. D. Lightning Fault Reduction Three-phase faults and the resultant voltage sag are not shown in Figs. 1–8, but are more severe than phase-to-ground fault voltage sags. The distance from the bus for a three-phase fault that results in a voltage sag of 40% drop is 12 km. The most likely cause of three-phase faults is lightning; therefore, additional lightning arrestors will be installed on all 35-kV feeders within 12 km of the bus and enhanced grounding methods will be utilized to reduce three-phase fault probability. E. Reduce Three-Phase Fault Duration An actual 2500-A phase-to-ground fault shown in Fig. 8 shows a voltage sag of 45% drop for 1 s before the substation breaker relay called for a trip. Customers served by other feeders of this substation also experienced the sag of 45% for 1 s. The customer complaints that result call for consideration of substation relay settings. During the early 1990s, substation breaker relay settings were revised to include a 12-cycle delay before tripping prior to the instantaneous reclose. A 12-cycle delay plus a five-cycle breaker operation time resulted in a 17-cycle voltage sag. The instantaneous trip is usually set as low as 1200 A which allows the breaker to trip for faults a great distance from the substation. Raising the instantaneous trip setting to (e.g., 3000 A) and installing a three-phase electronic line oil circuit recloser at the 3000-A fault location will reduce the frequency of trips at the substation. After consideration of the substation relay timing consequences, the 12-cycle delay was eliminated; the instantaneous relay settings raised and electronic reclosers were utilized as needed to accomplish the three-phase fault duration reduction.

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V. CONCLUSION The unique characteristics of 35-kV distribution cannot be eliminated, but a thorough understanding of the system will allow voltage sag to be reduced as much as 20% at Alabama Power. The impedance changes, fault duration reduction, and three-phase fault prevention measures can be accomplished at minimal cost. These improvements can be incorporated into standard system design and completed over a period of five years as resources allow. ACKNOWLEDGMENT The author gratefully acknowledges the contributions of P. Coleman, H. Gabriel, R. Murchison, K. Reed, G. Smith, and T. Wall. The technical expertise of these engineers made the results of this project possible. REFERENCES [1] IEEE Recommended Practice for Emergency and Standby Power, ANSI/IEEE Std. 446-1997, 1987. [2] L. Conrad, C. Grigg, and K. Little, “Predicting and preventing problems associated with remote fault-clearing voltage dips,” in Proc. Ind. Commercial Power Syst. Tech. Conf., 1989, pp. 74–78. [3] R. E. Clayton, J. M. Undrill, and E. L. Shlatz, “Case study of radial overhead feeder performance at 12.5 kV and 34.5 kV,” in Proc. Rural Elect. Power Conf., Scotia, NY, 1989, pp. 98–98. [4] L. Kojovic and S. Hassler, “Application of current limiting fuses in distribution systems for improved power quality and protection,” IEEE Trans. Power Delivery, vol. 12, pp. 791–800, Apr. 1997.

M. Stephen Daniel (SM’01) was born in Birmingham, AL, on May 12, 1952. He received the B.S. and M.S.E.E. degrees in engineering from the University of Alabama at Birmingham in 1974 and 1997, respectively. Currently, he is Principal Engineer at Power Delivery–Distribution Engineering Services, Birmingham. His work experience includes 29 years of distribution engineering for Alabama Power, A Southern Company. He served as Team Leader of the 35-kV Voltage Sag Study Committee in 1997, National Management Association Birmingham Division President in 1986, and Greater Birmingham United Way Loaned Executive in 1980. Mr. Daniel is a registered professional engineer and is the 2004 Chair of the IEEE Alabama Section.