Journal of International Council on Electrical Engineering Vol. 2, No. 4, pp.409~414, 2012 http://dx.doi.org/10.5370/JICEE.2012.2.4.409

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Advanced Practical Considerations of Fault Current Analysis in Power System Grounding Design

Yexu Li† and Farid Dawalibi*

Abstract – Advanced practical considerations for fault current split calculations used in power grounding studies are presented. Scenarios, such as modeling transformers to account for local circulating fault currents, analyzing underground distribution cables, considering tower line faults, and estimating the return current to remote source contributions by means of shield wires, cable sheaths, etc., are analyzed. It is shown that fault current going into the grounding system and the grounding grid safety evaluation can be overestimated or underestimated if the actual situation is not modeled correctly or considered appropriately. Proper examination of various fault scenarios involving circulating current, line fault, and underground cable is also presented. The considerations given in this paper can provide an advanced guideline or reference for power engineers to carry out fault current distribution calculations accurately and therefore avoiding inappropriate designs in grounding studies. Keywords: Fault currents, Ground potential rise, Touch voltage, Step voltage, Transformer, Power cables, Power distribution lines, Transmission lines

1. Introduction

Phase to ground faults in high voltage substations often introduce large fault currents that cause ground potential rises (GPR) of the grounding system, ground potential difference (GPD) between different points of the grounding system and large step voltages and touch voltages at the surface of substation. The normal operation of low voltage facility and relay system may be affected by the GPRs and GPDs and will be damaged under serious conditions. High step voltages and touch voltages at the surface of substation may be dangerous to personnel in the substation and public outside the substation. These risks must be eliminated using adequate designs of the substation grounding system.

The total fault current in the substation grounding system is typically larger than the current discharged in the soil by the grounding system. Part of the total fault current, will return to remote sources and local transformer neutral through the shield wires of transmission lines, neutral and shields of distribution feeders and conductors of the grounding system. Only the current discharged into the soil will affect the grounding grid GPRs. The currents flowing in the conductors only and therefore will have significant contribution, mainly, as GPDs and will distort the GPRs of

the grounding system conductors. Therefore, the computation of these currents is very important for the evaluation of a substation grounding system performance and its design.

The fault current analysis can be overestimated or underestimated if the actual situation is not modeled correctly or the scenario is not considered completely. For example, a local fault current contribution is systematically assumed to be a circulating current problem, since the source location and the fault location are both in the same substation. It is then concluded that a local fault current has no contribution to the grounding design. However, this current flows from one point to another inside the grid, resulting in differential GPR, i.e., a GPD. Therefore, not taking into account this local fault current may result in an optimistic GPR and touch and step voltages. Another common mistake is the perception that the fault at the substation is the worst scenario for a grounding study. While this is often the case, there can be exceptions. As will be demonstrated in this paper, in some cases, the fault occurring outside the substation (tower line fault) can actually produce larger earth fault currents at the substation.

There are many publications describing methods for fault current split calculations [1-6]. The main objective of this paper is to present typical cases of fault current analysis used in grounding studies rather than focusing on the computation methods. Scenarios, such as modeling transformers to account for local circulating fault currents, analyzing underground distribution cables, considering

† Corresponding Author: Engineering Safe Engineering Services & technologies ltd, Canada (yexu.li@sestech.com)

* Engineering Safe Engineering Services & technologies ltd, Canada (farid.dawalibi@sestech.com)

Received: August 29, 2012; Accepted: Sepember 15, 2012

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tower line faults, and estimating the return current to remote source contributions by means of shield wires, cable sheaths, etc., are analyzed. Practical case examples are also presented. The examples given in this paper can help electrical engineers to carry out fault current distribution calculations accurately, thereby resulting in appropriate grounding designs.

2. Modeling Transformer

For a substation that has many source terminals at different voltage levels, for instance, 500kV, 230kV and 35kV (three voltage levels) in a 500kV substation fed by several source terminals at 500kV and 230kV, when a single-phase-to-ground fault occurs on a 230kV bus, the 500kV side will supply fault currents through the 500kV transformers and part of the fault current will return to the transformer neutral through the grid conductors (circulating current). Because of the low impedance path provided by the ground conductors, only a small amount of this current is leaking out from the ground conductors to earth. As a result, the circulating current does not contribute to the

average grid GPR. However, for a large substation or power plant, the distance between the fault location and the transformer neutral point can be quite large. As a result, high potential differences due to this large circulating current may exist within the grounding grid (circulating current). In another words, the circulating current contributes to the ground potential differences (GPD) between various locations of the grid and results in higher maximum touch and step voltages, especially for a large grounding system at low soil characteristics environment.

Obviously, ignoring modeling transformer circulating current in a grounding system study can potentially lead to inappropriate dangerous under-design.

Fig. 1 shows a one-line diagram of an actual power net-work, with fault current values for a 230kV single-line-to-ground fault. The fault current level is 49.883kA, but only 13.46kA is from remote sources. The rest of the current, 36.452kA, is from the local transformers, synchronous condensers and valve groups inside the substation, forms in circulating current form. It will have no contribution to the average grid GPR but will have great impact on the grid local GPR, touch and step voltages.

Fig. 1. One-line diagram of a system with transformer banks in a 500kV substation: fault on the 230kV transformer side.

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Fig. 2. 230kV fault current model. The fault current distribution is calculated with the

transformer modeled. The earth currents discharged by the grounding system is 11.1kA, that produces 455V average grid GPR provided the grounding resistance is 0.041 ohms. Fig. 2 shows the model for safety analysis, considering all current sources including circulating currents. The computed maximum GPR is 724V (Fig. 3), which is considerable higher than the case which the transformer circulating current is not modeled. The maximum GPD (ground potential difference), accounting for the phase angle, inside the station reaches about 900V.

Another common question also often arises regarding the fault location yielding the worst case (in the sense of having the largest earth current): is it on the high voltage side or on the low voltage side? Is a higher total fault current representing a worst fault case? Let’s have an example with a Δ-Y transformer bank substation. For a single-line-to-ground fault on the low voltage Y-side, a huge fault current (higher than a fault occurring on the high voltage Δ−side.) can be obtained. But there is no remote fault current contribution from the high voltage Δ−side, i.e., the fault currents all are from local sources – the transformer banks. As can be seen, it is simply a circulating current problem, resulting 0 Amp earth current. Consequently, a worst fault case (at least in the sense of average GPR) is on the high voltage side even it maybe has a lower fault current level.

Fig. 3. Conductor GPR, considering circulating current.

3. Considering a Line Fault

A line fault is a fault on a power line tower structure

outside the substation. In this case, a phase conductor is shorted to a neutral conductor outside the substation. The resulting fault current flows into the neutral conductor and the tower footings and then returns to the substation grounding grid and the transformer banks in the substation, as shown in Fig. 4. It is an inappropriate or incomplete study if only a fault occurring inside the station study is carried out. This is because the current flowing into the grounding grid from the earth can be large, potentially larger than for a fault inside the station. Therefore, a line fault should be always considered in order to determine a worst fault case.

One simple example that a line fault is worse than a fault inside the station is for a single-line-to-ground fault on the low voltage Y-side in the previous Δ-Y transformer bank substation case. As discussed, the total fault current for a fault on the low voltage bus is large but it is all from local sources, resulting in 0 Amp earth current and 0 V average grid GPR. However, the current flowing into the grounding grid from the earth, generating by a line fault can be large, potentially even larger than for a fault on the high voltage side simply because of a larger fault current level on the low voltage side.

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Fig. 4. Illustration of the current path for a line fault.

Fig. 5. Earth current for line faults. Fig. 5 shows the earth current for line faults from a

practical real case of a power system with a 500kV / 230kV auto-transformer bank. For an auto-transformer bank system, there is no simple answer to the question that what the worst case fault is: on the high voltage side or on the low voltage side? Inside the station or outside the station? General speaking, all possible fault locations should be

modeled. As shown in the figure, it is clear that the worst fault is the 230kV single-line-to-ground on the tower #3 of the “To Station #4” line. A 19.25kA of the maximum earth current is obtained.

Fig. 6. Touch voltages: fault occurring inside the station.

Fig. 7. Touch voltages: fault occurring at the worst tower structure outside the station.

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It should be emphazed that the worst fault case discussed above is in the sense of having the largest earth current or the largest average grid GPR. But it may not be the worst fault case in the sense of having the largest touch or step voltages. Although the earth current at the substation for the worst line fault is larger than the one for a fault inside the substation, it is possible that the worst touch voltage will be obtained from the fault inside the station, instead of from the worst line fault. This is because the total fault current, considering the transformer circulating current, at the fault location is much larger than any energized current injection points for a line fault, generating a large localized touch or step voltages. Fig. 6 and Fig. 7, using the same example of Fig. 5, show the touch voltages for a fault inside the station and at the tower #3 outside the station (the worst line fault), respectively. Although the earth current for the inside station fault (11.1kA) is lower than the earth current for the outside station fault (19.25kA), as can be seen, the worst touch voltage from the inside station fault, i.e., 133.7V, is higher than the one obtained from worst line fault, i.e., 61.5V.

4. Underground Distribution Cable

For an underground distribution cable, since strong mutual coupling between the core and the sheath (or armour) exists, more fault current will be carried back to the source through the sheath. A real practical underground cable network analysis is presented in the following. A 63.5/4.16kV with a Δ-Y transformer bank station is fed off 3 remote source 63.5 kV lines. Naturally, there is no fault current contribution (3I0) from the transformer banks during a single-phase-to-ground fault on the 63.5kV bus. As a result, modeling only the fault currents from the 63.5kV lines is appropriate. However, the sheath of the 4.16kV underground distribution should be modeled to count the current carrying back to the remote source.

For a 4.16kV single-line-to-ground fault inside the station, there is no remote fault contribution. Therefore, the worst case for a 4.16kV SLG fault obvious is a line fault outside the substation. For a SLG fault along a 4.16kV underground cable outside the substation, a computer model is built: a single-phase-to-ground fault occurs at different manhole. Fig. 8 shows the circuit model for the 4.16kV fault along the underground cables. The fault current magnitude and the target studying station earth current will be a function of the fault location relative to the station. The fault contribution from the station for a fault on a 4.16kV underground cable is represented by an equivalent source voltage and a source impedance which will produce a fault

current of 44.6kA for a fault at the substation. Advanced current distribution methods are used to model the 4.16kV faults along the underground cable manholes. The earth current returning to the source discharged by the station grounding system is computed for all faults at manhole locations. The worst fault location, considering the three 63.5kV lines (fault at inside and outside the station) and the 4.16kV underground cable (fault at the manholes outside the station) is identified and the station grounding performance is therefore analyzed based on the worst fault location.

Fig. 8. 4.16kV cable feeder manhole fault circuit model.

5. Conclusion

Advanced practical considerations regarding fault current

split calculations were presented. Scenarios, such as modeling transformers to account for local circulating fault currents, analyzing underground distribution cables, considering tower line faults, and estimating the return current to remote source contributions by means of shield wires, cable sheaths, etc., were analyzed. It was shown that the fault current analysis in the grounding system evaluation can result in overestimated or underestimated grounding system if the actual situation is not modelled correctly or considered appropriately. Proper analysis of various fault scenarios involving circulating current, underground cable and tower line fault were also presented. The examples given in this paper can help power engineers understand the advanced practical considerations rather than the classical ones in fault current split analysis for various cases and assist them in carrying out fault current distribution analysis for grounding designs properly and accurately.

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Acknowledgements

The authors wish to thank Safe Engineering Services & technologies ltd. for the financial support and facilities provided during this research effort.

References [1] Dawalibi, F.P., Ground fault current distribution

between soil and neutral conductors, IEEE Trans. Power App. Syst., vol. 99, no. 2, pp. 452-461, Mar./Apr. 1980.

[2] Dawalibi, F. P. Transmission Line Grounding, vol. 1, Chapter 6, EPRI Report EL-2699, Oct. 1982.

[3] Garrett, D., Mayers, J., and Patel, S., Determination of maximum substation grounding system fault current using graphical analysis, IEEE Trans. Power Del., vol. 2, no. 3, pp. 725-732, Jul. 1987.

[4] IEEE Guide for Safety in AC Substation Grounding, IEEE Std. 80-2000.

[5] Li, Y, Dawalibi, F. P., Li, C. and Wei, X., A parametric analysis of fault current division between overhead wires and substation grounding systems, Proceedings of the Seventh IASTED International Conference on Power and Energy Systems, Clearwater Beach, FL, USA, November 28 - December 1, 2004, pp. 48-53.

[6] Yu, G., Ma, J., and Dawalibi, F. P., Computation of return current through neutral wires in grounding system analysis, in Proc. of the Third IASTED International Conference on Power and Energy System, Las Vegas, Nevada, pp. 455-459, Nov. 8-10, 1999.

Yexu Li received the B.Sc. degree in Geophysics from Beijing University and the M.Sc. degree in Seismology from the Chinese Academy of Sciences in 1986 and 1989, respectively. She received the M.Sc. degree in Applied Geophysics from Ecole Polytechnique

of the University of Montreal in 1996 and the Graduate Diploma in Computer Sciences from Concordia University in 1998. From 1995 to 1998, she worked as a Geophysicist with the SIAL Geosicences Inc. in Montreal, and was involved in geophysical EM survey design, data acquisition and processing as well as interpretation. She joined Safe Engineering Services & technologies ltd. in Montreal in March 1998 as a scientific researcher and software analyst. Her research interests are in AC interference, power

grounding, transient phenomena and related software development. Ms. Li has coauthored (or coauthored) more than 40 papers on electromagnetic interference analysis, power system grounding, on lighting and geophysics. She is a member of the IEEE Power Engineering Society.

Dr. Farid Dawalibi was born in Lebanon in November 1947. He received a Bachelor of Engineering degree from St. Joseph's University, affiliated with the University of Lyon, and the M.Sc. and Ph.D. degrees from Ecole Polytechnique of the University of Montreal. From

1971 to 1976, he worked as a consulting engineer with the Shawinigan Engineering Company, in Montreal. He worked on numerous projects involving power system analysis and design, railway electrific ation studies and specialized computer software code development. In 1976, he joined Montel-Sprecher & Schuh, a manufacturer of high voltage equipment in Montreal, as Manager of Technical Services and was involved in power system design, equipment selection and testing for systems ranging from a few to several hundred kV. In 1979, he founded Safe Engineering Services & Technologies, a company which specializes in soil effects on power networks. Since then he has been responsible for the engineering activities of the company including the development of computer software related to power system applications. He is the author of more than three hundred papers on power system grounding, lightning, inductive interference and electromagnetic field analysis. He has written several research reports for CEA and EPRI. Dr. Dawalibi is a corresponding member of various IEEE Committee Working Groups, and a senior member of the IEEE Power Engineering Society and the Canadian Society for Electrical Engineering. He is a re-gistered Engineer in the Province of Quebec.