Optimal neutral ground resistor rating of the medium voltage systems in power generating stations

Transcription

1 Journal of International Council on Electrical Engineering ISSN: (Print) (Online) Journal homepage: Optimal neutral ground resistor rating of the medium voltage systems in power generating stations Choong-Koo Chang To cite this article: Choong-Koo Chang (2015) Optimal neutral ground resistor rating of the medium voltage systems in power generating stations, Journal of International Council on Electrical Engineering, 5:1, 55-63, DOI: / To link to this article: The Author(s). Published by Taylor & Francis Published online: 20 Nov Submit your article to this journal Article views: 3909 View related articles View Crossmark data Full Terms & Conditions of access and use can be found at Download by: [ ] Date: 26 December 2017, At: 02:16

2 Journal of International Council on Electrical Engineering, 2015 Vol. 5, No. 1, 55 63, Optimal neutral ground resistor rating of the medium voltage systems in power generating stations Choong-Koo Chang* Professor, Department of Nuclear Power Plant Engineering, KEPCO International Nuclear Graduate School (Received 25 August 2015; accepted 19 October 2015) Neutral grounding resistors (NGRs) are used to protect insulation breakdown in faulty electrical equipment. These faults are caused by transient over-voltages produced by arcing ground on ungrounded systems. NGR also reduces mechanical stresses in circuits and apparatus carrying fault currents in solidly grounded systems. In the medium voltage auxiliary power systems of power generating stations, low resistance grounding system is widely used with a NGR. The purpose of this paper is to present the method determining optimal NGR size for the medium voltage systems in power generating stations. Keywords: system grounding; impedance grounding; neutral grounding resistor; phase to ground fault 1. Introduction To determine optimal neutral grounding resistor (NGR) size, many items should be considered. The maximum ground fault current allowed by the resistor has to be large enough to actuate the applied ground fault protection relay. The allowable fault current must be decided in accordance with the protection scheme and nominal current of equipment (generator or transformer). However, the most of literatures related to resistance grounding system design describe only the approximate range of the NGR rating for low and high resistance grounding system. And the only existing standard specific for NGR is the IEEE 32 standards where the allowed temperature rise and time rating are defined. Sophisticated NGR sizing and verification method is not introduced in any literature. Therefore, design, construction and operation engineers in the job field experience difficulties due to the mismatch of NGR rating and ground protection system during commissioning and operation. Throughout this study a procedure for the determination of optimal NGR will be proposed, and it will be verified through a case study. 2. System grounding Power system grounding is very important, particularly because the majority of faults involve grounding. Thus, it has a significant effect on the protection of all the components of the power system. The principal purpose of grounding is to minimize potential transient overvoltages to comply with local, state, and national codes for personnel safety requirements; and to assist in the rapid detection and isolation of trouble or fault areas. In general, system grounding is practiced based on past experience or an extension to the grounding methods in existing installations. There are three types in system grounding: (1) ungrounded, (2) resistance or impedance, and (3) effective or solid grounding. Each has its application in practice, along with advantages and disadvantages. The recommendations are based on general practices and some personal preferences. [1] 2.1. Ungrounded systems An ungrounded system is one in which there is no intentional connection between the conductors and the ground. However, in any system, a capacitive coupling exists between the system conductors and the adjacent grounded surfaces. Consequently, the ungrounded system is, in reality, a capacitively grounded system by virtue of the distributed capacitance. This is shown in Figure 1.[2,3] The voltages and impedances indicated in Figure 2 are as follows: V PN : the applied phase to neutral system voltage (infinite source) Z 1(sys), Z 2(sys), Z 0(sys) : the equivalent positive, negative, and zero sequence source impedance values, respectively Z TX : the transformer impedance (since the return path for the transformer has negligible impedance, the positive, negative, and zero sequence impedance values, for the transformer are all the same) Z 1(line),Z 2(line),Z 0(line) : the impedance values for the line between the transformer secondary terminals and the PG (phase to ground) fault. * ckchang@kings.ac.kr 2015 The Author(s). Published by Taylor & Francis. This is an Open Access article distributed under the terms of the Creative Commons Attribution License ( which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

3 56 C.-K. Chang Figure 1. Ungrounded system Solidly grounded systems There is no intentional impedance between the system neutral and ground as shown in Figure 3. The voltage and impedance values indicated in Figure 4 are the same as those defined originally for Figure 2. In terms of the applied voltage and the system impedance values given, the bolted PG fault current magnitude would be determined as follows: I PG ¼ ½2Z 1ðsys 3V PN Þ þ 3Z TX þ 2Z 1ðlineÞ þ Z 0 line ð ÞŠ (3) Figure 2. Sequence network model for phase to ground fault on an ungrounded system. The equal positive and negative sequence components of the total distributed shunt capacitive reactance (X C1 and X C2 ), shown in Figure 2, are so large compared to the system impedances parallel to them that they can be neglected.[2] In terms of the applied voltage and the system impedance values given, the bolted PG fault current magnitude would be determined as follows: 3V PN I PG ¼ (1) ½2Z 1ðsysÞ þ 2Z TX þ 2Z 1ðlineÞ þ Z 0ðlineÞ þ X C0 Š Because X C0 dwarfs the other system impedance values, the simplified Equation 1 gives a close approximation: 2.3. Resistance grounding There are two broad categories of resistance grounding: low resistance and high resistance. In both types of grounding, the resistor is connected between the neutral of the transformer secondary as shown in Figure 5 or the generator winding and the earth ground. The voltage and impedance values indicated in the resistance grounding system are the same as those defined originally for ungrounded system except neutral ground impedance R N inserted between transformer neutral and ground. In terms of the applied voltage and the system impedance values given, the bolted PG fault current magnitude would be determined as follows: I PG ¼ ½2Z 1ðsys 3V PN Þ þ 3Z TX þ 3Z N þ 2Z 1ðlineÞ þ Z 0 line ð ÞŠ (4) In general, other impedances than the neutral impedance are negligible. Since the neutral impedance is in a residual portion of the zero sequence current circulation path, its impedance value is modelled as three times its actual value and X C0 is negligible in low resistance grounding system. For this reason, the PG fault current magnitude is determined by the neutral impedance value used: I PG ¼ 3V PN 3Z N ¼ V PN Z N ffi V PN R N (5) I PG ¼ 3V PN (2) X C0 As a result, the PG fault current on an ungrounded system has a very small magnitude, very small for overcurrent relaying to be used for detecting ground faults. Figure 3. Delta/grounded-wye transformer connection.

4 Journal of International Council on Electrical Engineering 57 To reduce the arc blaster flash hazard to personnel who may have accidentally caused or who happen to be in close proximity to the ground fault. High resistance grounding typically uses ground fault current levels of 10 A or less, although some specialized systems in the 15 kv voltage class may have higher ground fault current levels. On the other hand, low resistance grounding typically uses ground fault current levels of at least 100 A, with currents in the A range being more usual.[4,5] Figure 4. Sequence network model for a bolted PG fault on the solidly grounded system. 3. System grounding practice in a nuclear power generating stations The following is a brief description of the system grounding practice in nuclear power generating stations and Figure 6 shows the conceptual diagram of the system grounding Main generator and transformer The main generator should always be high resistance grounded and the main transformer for the generating plant should always be solidly grounded at the high side. Low side connected to the generator is always delta connected. No special equipment is required for high side grounding.[6] 3.2. Unit auxiliary transformers Unit auxiliary transformers (UAT) connected to the generator leads should always have the high side delta connected. Low side of the UAT is generally wye connection and should be low resistance grounded allowing a maximum of 2000 A ground fault current. Grounding resistor directly connected to the neutral should have a minimum of 10 sec rating. Figure 5. Resistance grounded system. The reasons for limiting the current by resistance grounding may be one or more of the following: To reduce the burning and melting effects in faulted electric equipment, such as switchgear, transformers, cables, and rotating machines. To reduce mechanical stresses in circuits and apparatus carrying fault currents. To reduce electric-shock hazards to personnel caused by stray ground-fault currents in the ground return path Standby auxiliary transformers Standby auxiliary transformers (SAT), when used, may have wye connection for high and low side winding with delta connection tertiary winding. For high side, wye connection, neutral should be solidly grounded. For low side wye connection, neutral should be low resistance grounded allowing a maximum of 2000 A ground fault current to flow. Rating of this equipment should have a minimum of 10 sec rating Load centre transformers Transformer feeding low voltage load centre should be delta/wye connection with neutral solidly grounded, unless specifically required by the client to be different.

5 58 C.-K. Chang Figure 6. System grounding of a nuclear power generating station Diesel generators Diesel generators, when provided, should be low resistance grounded at the medium voltage and solidly grounded at low voltage distribution. Low resistance grounding should allow a maximum of 1000 A ground fault current. Grounding resistor directly connected to the neutral should have a minimum of 10 sec rating. 4. Determination of NGR rating for medium voltage network For the purpose of this study, a design and verification process of Figure 7 has been developed. Every factor affecting the rating of NGR are reviewed and cross checked in the process to confirm the suitability of NGR rating. In the last, the NGR ratting is verified through the ground fault protection relay coordination check. The line-to-ground capacitance associated with system components determines the magnitudes of zero sequence charging current. The resistor must be sized to ensure that the ground fault current limit is greater than the system s total capacitance-to-ground charging current. If not, then transient overvoltages can occur.[3] Furthermore, NGR selection is a comprehensive task which involves many aspects of power system as shown in Figure 7. The following items are mainly considered when selecting NGRs:[7,8] Charging current Allowable maximum fault current for network Transient overvoltage and insulation level of equipment Fault current withstand time and temperature rise Ground fault protection and coordination Charging current and fault current level The charging current of a system can be calculated by summing the zero-sequence capacitance or determining capacitive reactance of all the cable and equipment connected to the system. The system charging current in normal operation condition is as follows, where C 0 is the zero-sequence capacitance in μf (microfarad) per phase and kv is the line-to-line voltage (see Figure 8): Capacitive reactance, X CO ¼ 106 xc o Ohm per phase, where x ¼ 2 p f (6) Charging current in Amps at 60 Hz: 3I CO ¼ x C 0 kv p 3 ¼ 0:652 C 0 kv (7) 1000 Typical values of system-capacitance data are available from the cable manufacturer catalogue or Westinghouse design guide [9] and the GE Data Book.[10] On the other hand, it is preferable to measure the magnitude of the charging current on existing power

6 Journal of International Council on Electrical Engineering 59 Figure 7. Flow diagram of NGR determination and ground fault relay setting. systems for correct grounding equipment selection. The measured values must be adjusted to obtain the maximum current if all the system components were not in operation during the tests.[3] For safe measuring of neutral point capacitor current, measurement from the secondary side of grid is proposed. Also different frequency injection method is widely used for the measurement of capacitive current.[8] In a resistance grounded system, the resistance must be low enough to allow the system capacitance to discharge relatively quickly. The level of fault current is commonly thought to be 10 A or less in ungrounded Figure 8. systems. Ground fault current path in resistance grounding systems. High resistance grounding systems are designed to meet the criterion of Rg Xco/3 or R O X CO to limit the transient overvoltages due to arcing ground faults. Where, Rg is the grounding resistance as seen from the system being grounded and R 0 is the per-phase zero-sequence resistance of the system. Xco is the capacitive reactance-to-ground per phase and includes the capacitance of all cables, motor windings, transformer windings, surge or shunt capacitors, and other equipment connected to the system.[5,11] Total fault current is the vector sum of capacitive charging current and resistor current: I f ¼ p fi 2 R þ ð 3I C0Þ 2 g (8) So, if I R =3I C0, then I F = I R Total fault current must not exceed the value for which the system is braced. However, in many cases, the system is already braced for the three-phase fault current which is much higher than the single line-ground fault current of a resistance grounded system.[12] In low resistance grounding, ground fault detecting current relays are sometimes connected in the common or residual circuit of current transformers. Where selective tripping is to be accomplished, the fault current is typically limited to a value equal to the primary current rating of the largest current transformers. This practice usually results in the maximum ground fault current being approximately equal to the full load rated current of the power supply transformer. Justification for this is based on the 5 A secondary rating of the current transformers. With an overcurrent relay having a minimum available setting of 0.5 A, the grounding resistance selected would permit 10 times the relay pickup current during a zero impedance fault. This will assure reliable relay performance.[11] Typical current values used range from 400 A on modern systems using sensitive toroid or core balance current transformer ground sensor relaying

7 60 C.-K. Chang and up to perhaps 2000 A in the larger systems using residually connected ground overcurrent relays.[4] 4.2. Transient overvoltage and insulation level An ungrounded system with no intentional conductive path to ground has a path for alternating currents to flow between the phase conductors and ground through the distributed capacitance to ground of circuits and equipment windings and any surge capacitors or power factor correction capacitors connected to ground. This capacitance is a significant factor in the generation of transient overvoltage during an arcing ground fault. Restriking arcs after current interruption in the breaker or in the fault can result in large destructive overvoltages in ungrounded systems. This phenomenon is illustrated in Figure 9. In the capacitive system, the current leads the voltage by nearly 90. When the current is interrupted or the arc is extinguished at or near its zero value, the voltage will be at or near its maximum value. With the breaker open, this voltage remains on the capacitor to decay at a time constant of the capacitive system. In the source system, it continues as demonstrated by V S. Thus, in a half cycle, the voltage across the open contact is almost twice the normal peak value. If a restrike occurs (switch closed in Figure 9), the basic +1 pu voltage of the capacitive system will shift to the system voltage of 1 pu, but because of the system inductance and inertia, it will overshoot to a maximum possibility of 3 pu. If the arc goes out again near current zero (switch open) but restrikes (switch closed) again, the system voltage will try to shift to +1 pu, in succession another time overshoot, this time to a potential maximum of +5 pu. This could continue to 7 pu, meanwhile, the system insulation would no doubt break down, causing a major fault. Thus, ungrounded systems should be used with caution, and applied at the lower voltages, where the system insulation levels are higher.[1] For resistance grounding systems at 15 kv and below, such overvoltages will not ordinarily be of a serious nature if the resistance value lies within the following boundary limits: R 0 X C0, R 0 2X 0. Where, X 0 is zero-sequence reactance. The corresponding ground-fault current is far less than is normally used for low-resistance grounding, but is the design criterion for high-resistance grounding.[5] 4.3. Fault withstand time and temperature rise Normally, protective relaying will trip within a few cycles. IEEE 32 defines standard resistor on times. Lowest rate is 10 seconds, but could potentially go less in order to save material/space. It can go as high as 30 or 60 seconds as required (rare). Extended or continuous ratings are almost never used in this application due to the relatively high fault currents. Coefficient of resistivity typically increases with temperature of the material, thus resistance of the NGR increases while the unit runs. As resistance increases, current decreases.[12] Therefore, the time rating and resistivity coefficient of resistor should be confirmed when make a ground fault relay setting calculation. Figure 9. Transient overvoltage on an ungrounded system. Figure 10. Ground fault protection scheme of the class 1E MV switchgear fed from unit aux. transformer.

8 Journal of International Council on Electrical Engineering (a) Lack of coordination (b) Better coordination Figure 11. Ground fault protection coordination curve for MV switchgear. 61

9 62 C.-K. Chang 4.4. Ground fault relay coordination CTs and relays must be designed such that system will trip on a fault of the magnitude of the ground fault current, but not on transient events such as large motor startup. Figure 10 is an example of the ground fault protection scheme for the Class 1E 4.16kV Switchgear fed from Unit Auxiliary Transformer (UAT) in a nuclear power plant. Secondary side neutral of the UAT is grounded with the NGR. In this example system, NGR rating is Ω and maximum fault current is 1200 A. The maximum fault current was decided to a value equal to the rated current of X winding at ONAN rating. X and Y windings use the same size of resistance for the convenience of design and maintenance. Figure 11 is the time current characteristic curves of ground protection relays showing the coordination between upstream and downstream relays. The time overcurrent relay (51G) installed on the grounded neutral of a transformer is set to minimum values of current pickup but not less than 10% of NGR rating and time delay to be selective with downstream feeder ground fault relays. Accordingly, about 160 A is appropriate to set 51G relay to make coordination with the 4.16 kv SWGR branch feeder ground fault relays which are set at 20 A and 120 A as explained in below. The ground protection relays installed on the incoming feeder of switchgears are residual type (51N). In Figure 11(a), the 51N relay of the Class 1E 4.16kV SWGR was set at 120 A for the coordination with the transformer neutral ground protection relay 51G. In that case, 51N(R2) relay s setting value is only 4% of the CT rating (3000 A) and it may cause undesired tripping of the ground relay due to CT error. Relay must not be set to pick up at less than CT accuracy class. In general, accuracy of the IEEE type protection CT is 10%. Coordination between 51G(R1) of the UAT neutral and 51N(R2) of the 4.16 kv SWGR incoming feeder can be sacrificed. However, coordination between 51N (R2) and downstream relays (R3 and R4) should be maintained as shown in Figure 11(b). Motor feeders are protected with instantaneous ground overcurrent relay (50G) connected to a core balance CT. 50G(R4) for motor feeder is set at lowest tap and typical pick-up value is A. In the case of an outgoing feeder for subsidiary 4.16 kv Non Class 1E SWGR, 51N (R3) device is used and it must coordinate with upstream and downstream ground overcurrent relay. The 51N(R3) is set at 120 A. 120 A is 10% of the CT primary rating of 1200 A. As a result, the 51N(R3) relay properly coordinates with the upstream relays. Therefore, Figure 11(b) is better protection coordination than Figure 11(a). current and ground fault level, transient overvoltage and insulation level, fault withstand time and temperature rise, and ground fault relay coordination. In the high resistance grounding system, NGR must be sized to flow resistive ground fault current that is greater than capacitive charging current and the system is not subject to destructive transient overvoltage. On the other hand, in the low resistance grounding system, ground fault current level and selectivity of ground fault relays are more critical to determine NGR rating than other parameters. In the case study, system ground fault relay (51G) was set at 13.3% (160 A) of the NGR rating and selective tripping was possible through the coordination with branch feeder s relay of the 4.16 kv SWGR. Therefore, the NGR rating satisfies the requirements specified in Sections The transformer neutral CT is 1200/ 400 multi-ratio type and 400 A CT is preferred for reference system for more reliable protection. If the NGR rating is greater than 1200 A, it is inevitable to allow higher ground fault current in the circuit. However, if the NGR rating is smaller than 1200 A, coordination between downstream 51N relays are difficult or fault detection in high impedance ground fault is insensitive. 6. Conclusion Usually the importance of NGR rating is overlooked because NGR is ordered in the early stage of the project with the power transformer which is long lead time equipment. As a result, in many cases, the rating of NGR already installed is not suitable for the proper setting and coordination of ground fault protection relays. Consequently it results in unsatisfactory coordination of ground fault protection system. Optimal NGR rating determination procedure and verification method proposed in this paper will contribute to the design of the reliable and safe ground protection systems for power generating stations. Additionally, as the power system design progresses and data becomes available, the grounding system and NGR design should be reviewed and re-evaluated when necessary to ensure that the system will perform within the established criteria and design margins. This re-evaluation may be required when transformer with NGR proposal is evaluated to check whether the rating proposed by the manufacturer is acceptable. A final re-evaluation is necessary after NGR test data and ground protection relay information are available. Acknowledgements This research was supported by the 2015 Research Fund of the KEPCO International Nuclear Graduate School (KINGS). 5. Results and discussion NGR rating in a resistance grounding system must be decided considering the above mentioned charging ORCID Choong-Koo Chang

10 Journal of International Council on Electrical Engineering 63 References [1] Blackburn J. Lewis, Domin Thomas J. Protective relaying principles and applications. CRC Press Taylor & Francis Group, NW, 2007, p.221. [2] Johnson Gerald, Schroeder Mark, Dalke Gerald. A review of system grounding methods. Proceedings of the Protective Relay Engineers 61st Annual Conference; [3] Post Glover TM, Ground fault protection technical guide, converting ungrounded systems to high resistance grounding. 2013;2 6. [4] IEEE Std IEEE recommended practice for electric power distribution for industrial plants, pp [5] IEEE Std IEEE recommended practice for grounding of industrial and commercial power systems, pp [6] IEEE Std C IEEE guide for generator ground protection, pp [7] Izadfar Hamid R, Farsad MR, Davood Andavari, Shokri S. Design and calculation of 66 kv neutral grounding resistor for main transformers in Bandar Imam Petrochemical Complex (BIPC) power station located in south west of Iran. Electrical Machines and Systems, ICEMS Proceedings of the Eighth International Conference, 2005, September 27 29, pp [8] Siming Hua, Hua Zhang, Feng Qian, Chunjie Chen, Meixia Zhang. The research on neutral grounding scheme of Fengxian 35 kv and 10 kv power grid, Energy and Power Engineering. 2013;5:898. [9] Westinghouse. System neutral grounding and ground fault protection. Publication PRSC-4B-1979, Westinghouse, 1979, pp [10] General Electric Co. GE industrial power systems data book. Schenectady, NY: General Electric; [11] IEEE Std IEEE design guide for electric power service systems for generating stations, pp [12] GloverTM Post. Grounding for electrical power systems (low resistance and high resistance design). IEEE Baton Rouge May;8:11 16.