2. Power-System Fault Analysis for Protection

Introduction and context

A protection system can operate correctly only when the electrical conditions produced by a fault are understood. Fault analysis provides the currents, voltages, phase relationships, and sequence quantities required to select relay settings, interrupting ratings, instrument-transformer ratios, grounding arrangements, and circuit-breaker duties. It is therefore not merely a network-calculation exercise; it is the analytical link between power-system physics and protection performance.

Fault studies are commonly performed at planning, design, commissioning, and operating stages. A planning engineer may calculate the maximum three-phase short-circuit current to specify switchgear, while a protection engineer may calculate a minimum remote-end single-line-to-ground current to verify relay sensitivity. The same network can produce substantially different results depending on fault type, fault location, prefault loading, source strength, transformer connections, grounding impedance, fault resistance, and the contribution of inverter-based resources (IBRs).

The principal analytical tools in this chapter are the per-unit system, network equivalents, symmetrical components, and sequence networks. Their use makes complex three-phase problems manageable and permits systematic treatment of both balanced and unbalanced faults.

Learning objectives

After studying this chapter, the reader should be able to:

1. Construct and interpret per-unit models for generators, transformers, lines, grounding impedances, and sources.

2. Calculate balanced three-phase fault currents using Thevenin equivalents.

3. Apply symmetrical components to single-line-to-ground, line-to-line, and double-line-to-ground faults.

4. Incorporate fault resistance, source impedance, transformer phase shifts, and grounding arrangements into fault calculations.

5. Distinguish the assumptions behind subtransient, transient, and steady-state fault-current calculations.

6. Interpret fault-current results for relay coordination, circuit-breaker duty, and system design.

7. Explain how inverter-based resources alter conventional fault-analysis assumptions.

The analytical foundation: per-unit quantities and network equivalents

The per-unit system

In a per-unit system, an electrical quantity is expressed as a fraction of a selected base quantity:

Per-unit quantity = actual quantity / base quantity.

For a three-phase system, select a common apparent-power base S_base and a line-to-line voltage base V_LL,base. The corresponding base current and impedance are

I_base = S_base / (sqrt(3) V_LL,base)

Z_base = V_LL,base^2 / S_base.

If phase voltage is used instead, Z_base = V_phase,base^2 / S_base and I_base = S_base/(3V_phase,base). Both conventions are equivalent when used consistently.

The same MVA base is normally used throughout a network, while voltage bases are related by transformer ratios. Thus, a 1.0 per-unit voltage on one side of an ideal transformer corresponds to 1.0 per-unit voltage on the other side when the voltage bases are selected in the transformer ratio. This eliminates the need to refer impedances through every transformer.

When changing an impedance from old bases to new bases,

Z_pu,new = Z_pu,old (S_base,new/S_base,old)(V_base,old/V_base,new)^2.

If the voltage bases are in the transformer ratio, the voltage factor is unity. A frequent error is to change the MVA base but neglect the voltage-base factor when the voltage bases are not appropriately related.

Sequence impedance conventions

Generator and motor impedances are often given as subtransient reactances, X_d'', because the initial current following a fault is governed by the subtransient internal emf. For protection studies, the appropriate model depends on the time interval being examined:

• Subtransient calculations describe the first cycles and are important for interrupting duty and instantaneous protection.
• Transient calculations describe the following period as damper effects decay.
• Steady-state calculations describe the longer-term current after transient effects have disappeared.

A synchronous generator is commonly represented by an internal voltage behind X_d'' for an initial fault calculation. In a balanced three-phase fault, positive-sequence quantities alone are required. In unbalanced faults, positive-, negative-, and zero-sequence impedances must be considered. Negative-sequence impedance is associated with currents rotating opposite to the normal phase sequence, and zero-sequence impedance describes three equal in-phase currents whose return path is through the neutral, ground, cable sheath, or other network paths.

Thevenin and source equivalents

For a fault at a specified bus, the network can be reduced to a Thevenin equivalent: a prefault voltage source behind an equivalent impedance. For a three-phase fault, the initial current is approximately

I_f = E_th / (Z_th + Z_f),

where E_th is the prefault phase voltage, Z_th is the positive-sequence Thevenin impedance, and Z_f is the fault impedance. In a per-unit calculation with E_th approximately 1.0 pu, the current is determined directly by the equivalent impedance.

For an unbalanced fault, the network is reduced separately into positive-, negative-, and zero-sequence equivalents. The fault conditions then determine how these sequence networks are interconnected. This is the central advantage of symmetrical components: a coupled three-phase problem becomes a set of single-phase sequence-network problems.

Symmetrical components as a protection model

Any unbalanced set of three phasors can be represented as the sum of three balanced sets:

• Positive sequence: three equal phasors, 120 degrees apart, with normal phase order.
• Negative sequence: three equal phasors, 120 degrees apart, with reverse phase order.
• Zero sequence: three equal, in-phase phasors.

Let a = 1∠120 degrees. If [V_a V_b V_c]^T is the phase-voltage vector and [V_0 V_1 V_2]^T is the sequence-voltage vector, then

[V_a V_b V_c]^T = A[V_0 V_1 V_2]^T,

where

A = [[1,1,1],[1,a^2,a],[1,a,a^2]].

The inverse transformation is

[V_0 V_1 V_2]^T = (1/3)[[1,1,1],[1,a,a^2],[1,a^2,a]][V_a V_b V_c]^T.

The same transformation applies to currents. In particular,

I_a = I_0 + I_1 + I_2,

and the current in a neutral or grounding conductor is

I_n = I_a + I_b + I_c = 3I_0.

This last relationship is especially important for ground-fault protection: zero-sequence current is one-third of the residual current measured by summing the three phase currents.

The sequence networks have different physical meanings. Positive-sequence impedance represents normal forward energy transfer; negative-sequence impedance produces heating and torque pulsations in rotating machines; zero-sequence impedance depends strongly on grounding, transformer winding connections, core construction, cable screens, and overhead-line geometry. Consequently, zero-sequence data cannot safely be inferred from positive-sequence data.

Fault types and their sequence-network connections

Three-phase fault

A solid three-phase fault is balanced. Only the positive-sequence network is involved:

I_1 = E_1/(Z_1 + Z_f),

with I_2 = I_0 = 0. For a solid fault, Z_f = 0. The three phase currents have equal magnitudes and are separated by 120 degrees. The fault current in actual units is obtained by multiplying the per-unit current by the current base.

Although three-phase faults are often the most severe, they are not necessarily the most common. A protection design must therefore consider both maximum three-phase current and minimum unbalanced fault current.

Single-line-to-ground fault

Suppose phase a is connected to ground through impedance Z_f. The fault conditions are

I_b = I_c = 0,

V_a = Z_f I_a.

Because I_b and I_c are zero,

I_0 = I_1 = I_2 = I_a/3.

The three sequence networks are therefore connected in series, giving

I_1 = E_1/(Z_1 + Z_2 + Z_0 + 3Z_f),

and

I_a = 3E_1/(Z_1 + Z_2 + Z_0 + 3Z_f).

The factor 3 multiplying fault impedance is a direct consequence of the relationship I_a = 3I_0. Omitting this factor is a common source of error. The ground-fault current is strongly influenced by Z_0, which in turn depends on the grounding method and transformer connections.

Line-to-line fault

For a fault between phases b and c without ground,

I_a = 0,

I_b = -I_c,

and the zero-sequence current is zero. The positive- and negative-sequence networks are connected in parallel at the fault, while the zero-sequence network is absent. For a solid fault,

I_1 = E_1/(Z_1 + Z_2),

I_2 = -I_1,

and the current in the faulted phases is related to the sequence current by the component transformation. With equal sequence impedances, the line-to-line fault current is lower than the corresponding three-phase fault current, although unequal impedances can modify this relationship.

Double-line-to-ground fault

For a fault involving phases b and c and ground, the phase-a current is zero, while phase-b and phase-c voltages are constrained by the fault. The positive-, negative-, and zero-sequence networks are interconnected in a mixed series-parallel arrangement. A convenient form for the positive-sequence current is

I_1 = E_1/[Z_1 + Z_2 || (Z_0 + 3Z_f)],

where || denotes parallel combination. The negative- and zero-sequence currents follow from the network connections. This fault is more involved because the ground path and the line-to-line path operate simultaneously.

Grounding, transformers, and fault resistance

System grounding

Grounding determines both the magnitude and distribution of zero-sequence current and the level of temporary overvoltage on unfaulted phases. In a solidly grounded system, the zero-sequence impedance is generally low enough to produce substantial ground-fault current. In a resistance-grounded system, a neutral resistor deliberately limits current. In a reactance-grounded system, the neutral reactor controls the ground-fault contribution. An ungrounded or resonant-grounded system may have very small sustained ground current but can experience significant transient or neutral-shift voltages.

For a neutral impedance Z_n, the zero-sequence network includes 3Z_n because the neutral current is 3I_0. This rule must be applied in addition to the zero-sequence impedance of lines, transformers, and machines.

Transformer connections

Transformer winding connections determine whether zero-sequence current can pass between voltage levels. A grounded wye winding provides a path for zero-sequence current; an ungrounded wye winding blocks it. A delta winding does not transmit line zero-sequence current to the external system, although circulating zero-sequence current may exist within the delta under suitable conditions. Thus a delta-wye transformer can isolate zero-sequence networks on its two sides even while allowing positive- and negative-sequence transfer.

Transformer phase shifts must also be considered when comparing phasor quantities across a transformer. For many protection applications, the relay algorithm or instrument-transformer compensation incorporates the transformer vector-group displacement. Incorrect treatment can produce false directional decisions or erroneous differential-restraint quantities.

Fault resistance

Arcs, tower footing, vegetation, conductors contacting earth, and imperfect metallic joints introduce fault resistance. Fault resistance reduces fault current and changes voltage distribution. It can cause a distance relay to underreach or a phase-overcurrent relay to fail to pick up, particularly for remote high-resistance ground faults. The resistance is not always purely resistive in practice, but a resistive approximation is often appropriate for first-order studies.

For a single-line-to-ground fault, the resistance appears as 3R_f in the sequence-network denominator. For a three-phase fault it appears directly as R_f in the positive-sequence fault path. Fault studies should normally include at least a solid-fault case and credible high-resistance cases when relay sensitivity is being assessed.

A systematic calculation procedure

A reliable fault study follows a disciplined sequence.

First, define the study purpose. Maximum current for equipment duty, minimum current for relay sensitivity, transient current for DC offset, and steady-state current for thermal loading may require different assumptions.

Second, select S_base and voltage bases. Convert all impedances to a common base and identify the prefault voltage model. For a preliminary study, 1.0 pu prefault voltage is often used; for detailed studies, an AC load-flow solution provides bus voltages and source angles.

Third, draw the sequence or phase network appropriate to the fault. Include generators, motors, grid equivalents, transformers, lines, grounding impedances, and relevant IBR models. Remove elements that cannot carry the required sequence current, such as zero-sequence paths blocked by transformer connections.

Fourth, reduce the network to the faulted bus or solve the network using an impedance matrix. The diagonal element Z_bus,kk gives the driving-point impedance at bus k, while off-diagonal terms describe transfer relationships between buses. For a bolted three-phase fault at bus k,

I_f = V_k,pre/Z_bus,kk.

For a fault through impedance Z_f, the denominator becomes Z_bus,kk + Z_f.

Fifth, calculate sequence currents and transform them into phase currents and voltages. Check that boundary conditions are satisfied: for example, unfaulted phase currents are zero in a single-line-to-ground calculation, and the sum of phase currents equals three times zero-sequence current.

Finally, convert results into amperes and engineering quantities. Compare currents with relay pickup, time-current curves, circuit-breaker interrupting and making ratings, conductor thermal limits, touch and step-voltage criteria, and coordination margins.

Worked analytical example

Consider a 100 MVA, 13.8 kV bus with a source whose sequence reactances are X_1 = 0.20 pu, X_2 = 0.20 pu, and X_0 = 0.10 pu. The source neutral is grounded through a reactance X_n = 0.05 pu. Assume 1.0 pu prefault voltage and neglect resistance.

The base current is

I_base = 100 x 10^6/(sqrt(3) x 13.8 x 10^3) = 4.184 kA.

For a solid three-phase fault,

I_1 = 1/0.20 = 5.0 pu,

so the fault current is approximately 20.92 kA.

For a single-line-to-ground fault, the zero-sequence impedance including the neutral reactor is

Z_0,total = j(0.10 + 3 x 0.05) = j0.25 pu.

Therefore,

I_1 = 1/[j(0.20 + 0.20 + 0.25)] = -j1.538 pu,

and the faulted-phase current is

I_a = 3I_1 = 4.615 pu.

In amperes, I_a is approximately 19.30 kA. In this example, the three-phase fault is more severe because the zero-sequence path is deliberately limited by the neutral reactor. If the neutral were solidly grounded, the single-line-to-ground current would increase substantially. The example also illustrates why a ground-fault study cannot be completed from positive-sequence reactance alone.

Inverter-based resources and changing fault behaviour

Traditional fault studies assume that generators behave approximately as voltage sources behind subtransient reactance and that fault current is predominantly sinusoidal, large, and sustained for several cycles. IBRs connected through power electronic converters do not necessarily follow this behaviour. Their current is controlled by software, semiconductor ratings, phase-locked-loop dynamics, current limits, and grid-code requirements.

During a fault, an IBR may provide positive-sequence current, negative-sequence current, or limited zero-sequence current depending on its control strategy and transformer grounding. Some controls prioritize active current, while others inject reactive current to support voltage. Current magnitude may be capped near a specified multiple of rated current, and the phase angle may change during the fault. Consequently, an IBR is often represented by a controlled current source or a positive-sequence current-injection model rather than a fixed internal emf behind an impedance.

This has important protection consequences. High-speed overcurrent elements may see less current than expected; directional elements may experience altered voltage-current angles; negative-sequence protection may depend on programmed unbalance control; and fault contribution can vary with operating point and control mode. Accurate studies may require electromagnetic-transient simulation, validated manufacturer models, and separate grid-following and grid-forming representations.

Grid-forming converters can provide voltage-source-like behaviour within their control and current limits, but they still cannot be assumed to reproduce the large subtransient current of a synchronous machine. Protection engineers must obtain model documentation, verify current-limiting behaviour, and assess weak-grid interactions rather than applying conventional short-circuit assumptions without qualification.

Applications in protection engineering

Fault-current calculations support several practical decisions. Overcurrent relay pickup must exceed maximum load and inrush but remain below the minimum credible fault current. Distance-relay reach depends on the apparent impedance measured during the fault; fault resistance and remote infeed can alter that impedance. Differential protection depends on the current contributions entering and leaving a protected zone and must account for transformer ratio, vector group, CT errors, and zero-sequence compensation.

Circuit-breaker selection uses the maximum asymmetrical current, which includes the DC component caused by the point-on-wave at fault inception and the X/R ratio of the network. A symmetrical RMS fault-current result is therefore not automatically the breaker interrupting current. Generator and motor contributions may decay differently, and breaker duties must be evaluated at the specified interrupting time.

Ground-fault protection also requires attention to sensitivity and safety. A resistance-grounded system may intentionally limit current below the pickup of phase overcurrent relays, requiring sensitive residual or neutral protection. At the same time, touch and step voltages, transferred potentials, and ground-grid performance must be assessed. Protection speed reduces equipment damage and arc-flash energy, but settings cannot be selected without considering selectivity and system stability.

Digital substations increasingly use synchronized measurements, numerical relays, disturbance records, and automated model validation. Fault records can be decomposed into sequence quantities to determine whether a relay saw the expected network condition. Analytics can identify changes in source strength, transformer status, or DER penetration that invalidate an old coordination study. AI may assist with event classification, but engineering decisions require explainable models, validated data, cybersecurity controls, and human review.

Illustrative case study: high-resistance ground fault in a renewable collector system

Background

This illustrative case concerns a medium-voltage collector system connecting several inverter-based solar plants to a substation. The collector transformer has a grounded-wye high-voltage winding and a delta-connected low-voltage winding. The substation protection was originally designed using conventional source assumptions and solid-fault calculations.

Situation and problem

A conductor contacted dry ground near the remote end of a collector feeder. The resulting current was substantially below the phase-overcurrent pickup, and the feeder distance element measured an impedance outside its intended ground-fault zone. The fault persisted until an upstream backup element operated.

Analysis

The feeder zero-sequence path was limited by the transformer connection and grounding resistor. The fault also had significant resistance. In addition, the inverter controls limited current to approximately a controlled fraction of rated current and contributed little zero-sequence current. A study using only a strong synchronous equivalent predicted a much larger and more directional current than was observed in the relay record.

The engineering team reconstructed the event using the actual transformer vector group, grounding impedance, feeder zero-sequence parameters, estimated fault resistance, and an IBR current-injection model. Sequence analysis showed that the measured residual current was small, while voltage displacement at the substation was sufficient to indicate a ground fault.

Approach and solution

The protection scheme was revised to include sensitive directional ground overvoltage and residual-current elements, with settings coordinated against feeder charging current and healthy-system unbalance. The IBR model was validated against recorded current limits. A communications-assisted permissive scheme was added for selected feeder faults, and the grounding design was reviewed for personnel safety.

Outcome

The revised arrangement improved sensitivity to remote high-resistance faults without sacrificing selectivity for feeder energization and external faults. The case demonstrated that a low measured current does not imply a low hazard or an absence of a fault, and that IBR fault behaviour must be represented explicitly.

Learning points

1. Minimum-fault studies are as important as maximum-fault studies.

2. Zero-sequence current depends on grounding and transformer connections.

3. Fault resistance can defeat conventional overcurrent and distance assumptions.

4. IBR current limits and control modes must be included in protection models.

5. Relay records are valuable for validating analytical and simulation models.

Common mistakes, limitations, and professional controls

The most frequent mistakes are mixing line and phase quantities, using inconsistent bases, omitting the factor 3 in neutral or fault impedance, assigning zero-sequence current through a blocked transformer connection, and using a steady-state model for an interrupting-duty problem. Another error is assuming that the largest fault current is always the worst protection case. A high-current close-in fault challenges equipment, whereas a low-current remote fault may challenge sensitivity and selectivity.

Sequence-network methods rely on assumptions such as linear impedances, balanced prefault conditions, known network topology, and adequate source models. Saturation, arc dynamics, frequency dependence, mutual coupling, transient control behaviour, and breaker timing may require more advanced methods. Short-circuit software does not remove the need for engineering judgment: incorrect topology or model data produces precise but misleading results.

Professional practice requires traceable assumptions, version-controlled network models, documented data sources, independent checks, and review of abnormal configurations. Studies should consider normal and credible contingency configurations, maintenance outages, distributed generation dispatch, transformer tap positions, and grounding changes. Results should be communicated with both per-unit values and actual ratings so that protection, planning, operations, and safety personnel can interpret them consistently.

Current developments and best practices

Modern fault analysis is moving from a single deterministic short-circuit number toward scenario-based assessment. Studies increasingly examine changing inverter dispatch, network reconfiguration, weak-grid conditions, battery storage, grid-forming controls, and fault-current contribution that varies with control mode. EMT simulation is used where converter controls, protection interactions, or fast transients dominate, while phasor-domain methods remain efficient for broad screening and coordination studies.

Best practice is to:

• define the decision and time frame before selecting the fault model;
• use a common, documented per-unit base;
• separate maximum equipment-duty and minimum protection-sensitivity cases;
• model zero-sequence paths and transformer vector groups explicitly;
• include realistic fault resistance and IBR controls;
• validate models against commissioning tests and disturbance records;
• check phase quantities against sequence quantities;
• report assumptions, uncertainty, and model limitations;
• reassess studies after major topology, grounding, or generation changes.

Chapter Summary

Fault analysis supplies the electrical evidence on which power-system protection is designed. Per-unit quantities simplify networks and permit impedances to be combined across voltage levels. Thevenin equivalents provide an efficient basis for calculating fault current, while symmetrical components convert unbalanced three-phase faults into positive-, negative-, and zero-sequence networks. Three-phase faults use only the positive-sequence network; single-line-to-ground faults connect all three sequence networks in series; line-to-line faults use positive and negative sequence; and double-line-to-ground faults require a mixed connection.

Grounding, transformer winding connections, neutral impedance, and fault resistance strongly influence ground-fault current. Maximum and minimum fault cases serve different engineering purposes. Circuit-breaker duty requires attention to asymmetry and DC offset, whereas relay sensitivity requires credible low-current faults. IBRs challenge the conventional voltage-source model because their current is controlled and limited. Consequently, protection studies increasingly combine sequence methods, validated inverter models, disturbance records, and, where necessary, EMT simulation. Sound professional practice depends on consistent bases, explicit assumptions, model validation, and engineering interpretation.

Key Terms

Per-unit quantity: An electrical quantity expressed as a fraction of a selected base value.

MVA base: The common apparent-power reference used to establish per-unit quantities.

Thevenin equivalent: A voltage source behind an equivalent impedance representing a network at a specified terminal.

Sequence network: A network model representing positive-, negative-, or zero-sequence behaviour.

Positive sequence: Balanced three-phase quantities having normal phase rotation.

Negative sequence: Balanced quantities having phase rotation opposite to the normal sequence.

Zero sequence: Three equal phasors that are in phase with one another.

Subtransient reactance: The effective machine reactance governing the initial cycles after a disturbance.

Fault resistance: Resistance associated with an imperfect fault path, including an arc or earth contact.

Solid fault: A fault idealized as having zero fault impedance.

Single-line-to-ground fault: A fault connecting one phase to ground.

Line-to-line fault: A fault connecting two phases without a ground connection.

Double-line-to-ground fault: A fault connecting two phases and ground.

Zero-sequence impedance: Impedance encountered by zero-sequence current, including grounding paths.

Neutral impedance: Impedance between a system neutral and ground or the grounding source.

Residual current: The sum of the three phase currents, equal to three times zero-sequence current.

Inverter-based resource: A generation or storage resource interfaced to the grid through power electronics.

Driving-point impedance: The equivalent impedance seen looking into a network at a specified bus.

X/R ratio: The ratio of network reactance to resistance, influencing asymmetrical fault current.

Electromagnetic-transient simulation: Time-domain simulation that represents fast electrical and control transients.

Review Questions

Short Answer Questions

1. Why are voltage bases selected in transformer ratios in a per-unit network?

2. State the relationship between residual current and zero-sequence current.

3. Which sequence networks are involved in a line-to-line fault?

4. Why is the neutral impedance multiplied by three in a zero-sequence network?

5. Distinguish subtransient and steady-state fault-current calculations.

Long Answer Questions

1. Explain the symmetrical-component transformation and its significance in protection engineering.

2. Derive the single-line-to-ground fault-current expression including fault impedance.

3. Discuss how transformer connections affect zero-sequence current transfer.

4. Describe a systematic procedure for conducting a protection-oriented fault study.

5. Explain why inverter-based resources require models different from conventional synchronous generators.

Analytical / Application Questions

1. A 50 MVA, 11 kV bus has a positive-sequence Thevenin reactance of 0.25 pu. Calculate the solid three-phase fault current using a 1.0 pu prefault voltage.

2. A grounded system has X1 = X2 = 0.20 pu and X0 = 0.15 pu, with a neutral reactance of 0.05 pu. Compare the per-unit single-line-to-ground current with and without the neutral reactance.

3. A remote feeder fault produces low residual current but substantial phase-voltage displacement. Identify two physical causes and propose a protection approach that could improve detection without losing selectivity.

22. Multiple Choice Questions with Answers

Question 1

For a solid three-phase fault at a bus with a 1.0 pu prefault voltage and a Thevenin reactance of j0.20 pu, what is the initial fault current?

A. 0.20 pu

B. 2.0 pu

C. 5.0 pu

D. 10.0 pu

Correct Answer: C. 5.0 pu

Question 2

In a single-line-to-ground fault, why does the fault impedance appear as 3Zf in the sequence-network denominator?

A. There are three faulted phases

B. The phase current equals three times the zero-sequence current

C. The positive-sequence impedance is tripled

D. The neutral voltage is three times the phase voltage

Correct Answer: B. The phase current equals three times the zero-sequence current

Question 3

Which sequence networks are connected in series for a single-line-to-ground fault?

A. Positive sequence only

B. Positive and negative sequence only

C. Negative and zero sequence only

D. Positive, negative, and zero sequence

Correct Answer: D. Positive, negative, and zero sequence

Question 4

A line-to-line fault without ground has zero zero-sequence current primarily because:

A. The positive-sequence impedance is zero

B. The fault has no return path involving ground

C. The negative-sequence impedance is infinite

D. The prefault voltage is zero

Correct Answer: B. The fault has no return path involving ground

Question 5

A neutral grounding reactance of 0.05 pu contributes what impedance to the zero-sequence network?

A. 0.0167 pu

B. 0.05 pu

C. 0.10 pu

D. 0.15 pu

Correct Answer: D. 0.15 pu

Question 6

Which transformer arrangement can block external zero-sequence current from passing through the transformer to the other voltage level?

A. Grounded-wye to grounded-wye only

B. Delta-connected winding in the transfer path

C. Solidly grounded neutral on both sides only

D. Identical positive-sequence reactances

Correct Answer: B. Delta-connected winding in the transfer path

Question 7

Increasing fault resistance in a remote ground fault generally causes:

A. Higher fault current and relay overreach

B. Lower fault current and possible relay underreach

C. No change in measured impedance

D. Zero-sequence current to become infinite

Correct Answer: B. Lower fault current and possible relay underreach

Question 8

Why can a conventional synchronous-generator fault model be unsuitable for an inverter-based resource?

A. An inverter has no electrical terminals

B. Its fault current is controlled and limited by converter controls

C. Its positive-sequence current is always zero

D. It cannot contribute any current under any condition

Correct Answer: B. Its fault current is controlled and limited by converter controls

Question 9

Which result is most directly associated with circuit-breaker interrupting duty?

A. Only the nominal load current

B. The maximum asymmetrical fault current at the specified interrupting time

C. The minimum high-resistance ground current

D. The zero-sequence voltage alone

Correct Answer: B. The maximum asymmetrical fault current at the specified interrupting time

Question 10

For a 100 MVA, 13.8 kV base, which approximate current is the base current?

A. 0.418 kA

B. 4.18 kA

C. 13.8 kA

D. 100 kA

Correct Answer: B. 4.18 kA