Electrical Coordination Calculator: Screen Ground-Fault Pickup vs Downstream Breakers

This article analyzes electrical coordination for ground fault pickup versus downstream circuit breakers and settings.

Engineers require precise calculation methods, algorithms, and standards to ensure selectivity and safety performance metrics.

Electrical Coordination Calculator – Main Ground-Fault Pickup vs Downstream Breakers

Maximum downstream ground-fault pickup (A)

Minimum line-to-ground fault current at main device (A)

Coordination margin between pickups (%) 25% (typical) 20% (tight) 30% (conservative) Custom

Custom coordination margin (%)

Advanced options

Additional downstream ground-fault pickup 2 (A) [optional]

Additional downstream ground-fault pickup 3 (A) [optional]

Sensitivity factor on minimum ground-fault current (pu)

Maximum allowable main ground-fault pickup (A) [device limit]

You may upload a nameplate or coordination diagram photo to suggest typical pickup and fault-current values.

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Enter downstream pickups and minimum ground-fault current to evaluate the recommended main ground-fault pickup.

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Formulas used in this calculator

• Effective maximum downstream ground-fault pickup: I_down_max = max( I_down_basic, I_down_2, I_down_3 ) [A]
• Coordination margin in per unit: margin_pu = margin_percent / 100
• Main ground-fault pickup for coordination: I_main_coord = I_down_max × (1 + margin_pu) [A]
• Sensitivity limit based on minimum line-to-ground fault current: I_main_sensitivity_limit = sensitivity_factor × I_fault_min [A]
• Device limit (if specified by user): I_main_device_limit = main_max [A]
• Allowable maximum pickup considering sensitivity and device limits: I_main_max_allowable = min( I_main_sensitivity_limit, I_main_device_limit if provided )
• Coordination feasibility condition: Coordination is feasible only if I_main_coord ≤ I_main_max_allowable.
• Recommended main ground-fault pickup: I_main_recommended = I_main_coord [A], provided the feasibility condition is satisfied.
• Coordination ratio: Coordination ratio = I_main_recommended / I_down_max [dimensionless]
• Utilization of minimum ground-fault current: Percentage of minimum fault at pickup = 100 × I_main_recommended / I_fault_min [%]

Parameter	Typical range	Comment
Coordination margin (main vs downstream pickups)	20–30 %	Higher margins improve selectivity but may reduce sensitivity.
Sensitivity factor (I_main / I_fault_min)	0.7–0.85 pu	Lower factors give better detection of low ground-fault currents.
Main ground-fault pickup (LV mains)	400–1600 A	Depends on CT ratio, sensor rating and system fault levels.
Downstream feeder ground-fault pickup	150–800 A	Typically set lower than the main to achieve selective tripping.

How is this calculator used in ground-fault coordination studies?

The calculator estimates a main ground-fault pickup that remains higher than downstream breaker pickups by a defined coordination margin, while still being low enough to detect the minimum line-to-ground fault current. It is intended as a quick screening tool before detailed time–current curve coordination.

What does it mean if the calculator reports that coordination is not feasible?

If the main pickup for coordination exceeds the allowable limit derived from minimum fault current and device constraints, there is no setting that simultaneously provides selectivity and sensitivity. In that case, you may need to adjust downstream settings, change CT ratios, or accept reduced selectivity.

Can I evaluate several downstream breakers with different ground-fault pickups?

Yes. You can enter up to three downstream ground-fault pickup settings in the advanced options. The calculator uses the highest of these values as the governing downstream pickup for the coordination check.

Does this replace a full time–current curve coordination study?

No. The calculation is based only on pickup levels and simple margins. A complete coordination study must also include time-delay settings, relays or trip-unit characteristics, and manufacturer curves to verify selectivity over the full range of ground-fault currents.

Fundamental concepts of ground fault pickup and selective coordination

A ground fault pickup is the threshold current value at which a ground-detection element (residual, zero-sequence, or neutral overcurrent) asserts a trip decision or initiates timing. Selective coordination requires that for any given fault on a distribution system, the protective device immediately upstream of the fault clears the fault without unnecessary operation of upstream protective devices. For ground faults this often involves coordination between residual ground relays, upstream feeder relays, and downstream overcurrent devices such as molded case circuit breakers (MCCBs), insulated-case circuit breakers (ICCBs), and fuses. Key objectives when coordinating ground fault pickup versus downstream breakers:

• Maintain safety and minimize customer interruption by enforcing selectivity.
• Prevent nuisance tripping caused by temporary unbalance or inrush currents.
• Ensure upstream protection covers faults not cleared by downstream devices.
• Comply with relevant codes and utility requirements (e.g., NFPA 70, IEEE coordination guides).

Analytical basis: currents, transformer contribution, and pickup relationships

Nominal current and available bolted fault current

To evaluate coordination, compute the transformer secondary nominal current (I_nom) and the available three-phase bolted fault current at the secondary terminals (I_sc). Use these standard formulae:

I_sc ≈ I_nom * 100 / %Z

Explanation of variables and typical values:

• S — transformer apparent power in VA (e.g., 750000 for 750 kVA).
• V — line-to-line voltage on the secondary in volts (e.g., 480 for 480 V).
• %Z — transformer percent impedance (typical values 4%–6% for distribution transformers).
• I_nom — nominal secondary current in amperes (calculated).
• I_sc — approximate available short-circuit current at the transformer secondary (amperes).

Typical example values:

• 750 kVA, 480 V, %Z = 5% → I_nom ≈ 903 A, I_sc ≈ 18.05 kA.
• 1500 kVA, 480 V, %Z = 5% → I_nom ≈ 1806 A, I_sc ≈ 36.12 kA.

Ground fault pickup (I_pickup) and setting philosophy

Ground fault pickup (I_pickup) can be specified in several ways:

• Absolute current in amperes for residual/ground relays.
• Percentage of transformer rated current or of device full-scale.
• Multiple of phase instantaneous pickup for devices using phase-to-phase sensing.

A common design goal is:

I_pickup_upstream > I_fault_cleared_by_downstream

or alternatively ensure timing such that:

t_upstream(at I_fault) ≥ t_downstream(at I_fault) + Δt_margin

Where Δt_margin is the minimum coordination time margin required by practice or by equipment manufacturer guidance (typical margins 0.2–0.5 s for electronic relays versus breakers; shorter margins may be accepted for fuse-breaker coordination).

Time margin and coordination criteria

Time margin requirement: Where:

• t_upstream(I) — operating time of the upstream device at fault current I.
• t_downstream(I) — operating time of the downstream device at fault current I.
• Δt — coordination margin, required to prevent upstream operation.

Typical recommended margins:

• MCCB vs MCCB: Δt ≥ 0.2 s.
• MCCB vs relay: Δt ≥ 0.3 s to 0.5 s depending on relay type and communication-based protection.
• Fuse vs relay: upstream relay should typically have long time delay to allow fuse melting; Δt depends on fuse melting time characteristics.

Time-current characteristics and practical formulas

Most devices follow an inverse-time relationship. Representative generic inverse-time expression (simplified) for an adjustable overcurrent element: A commonly used functional form for IEC moderately inverse curves (illustrative, manufacturers use their specific constants): Parameters and typical values:

• t — operating time at current I (seconds).
• TD — time dial or time multiplier setting (dimensionless multiplier chosen by the engineer).
• k, α — curve-specific constants (examples: for IEC standard inverse, long-time inverse, very inverse, extremely inverse curves — consult manufacturer).
• I / I_pickup — multiple of pickup current.

Manufacturers publish proprietary curves; always use exact manufacturer constants for accurate coordination calculations. For conceptual calculations one may use typical curve behavior:

• At 2× pickup: long-time element might operate in several seconds (e.g., 2–5 s depending on TD).
• At 10× pickup: instantaneous or short-time elements often operate in under 0.1–0.5 s.

Common device characteristic table

Procedural workflow for setting ground fault pickup versus downstream breakers

Follow an ordered process:

1. Gather system data: transformer kVA, voltage, %Z, conductor impedances, breaker/fuse types, available fault current at points of interest.
2. Calculate I_nom and available I_sc at the device locations using the formulas above.
3. Collect manufacturer time-current curves for all protective devices (downstream breakers, upstream relays, fuses).
4. Establish coordination criteria (Δt margin, relay zones, neutral/grd sensitivitiy, service continuity requirements).
5. Choose initial pickup values: set downstream breakers for equipment protection and set upstream ground pickup higher or with appropriate time delay to allow downstream clearing.
6. Plot time-current curves (log-log plot) for each device and verify time margins at several multiples of expected fault currents.
7. Adjust settings iteratively, verifying both phase and ground coordination and maintaining code compliance.
8. Document settings, rationales, and perform commissioning tests (primary injection where possible).

Detailed example 1 — Feeder coordination: relay upstream vs MCCB downstream

Scenario summary:

• Transformer: 750 kVA, 480 V, %Z = 5% (480Y/277 V system).
• Downstream device: MCCB (rated In = 400 A), adjustable long-time and instantaneous features.
• Upstream device: Feeder relay with residual ground element, adjustable pickup and time delay.
• Objective: Set upstream ground relay so downstream MCCB clears ground faults located in its zone without upstream operation, preserving selectivity.

Step 1 — compute nominal and fault currents: Step 2 — determine typical MCCB behavior: Assume manufacturer’s published MCCB characteristics (representative):

• Long-time pickup set to 1.0 × In → 400 A
• Instantaneous trip set to 10 × In → 4000 A
• Instantaneous clearing time at 10× ≈ 0.05 s (representative)
• Long-time clearing at 2× In ≈ 3.5 s (depends on TD)

Step 3 — ground fault magnitude at downstream feeder locations: For a bolted ground fault close to the breaker, the fault current available is near transformer short-circuit current (approx 18.05 kA). The MCCB instantaneous threshold (4000 A) is lower than the available fault; thus the MCCB will operate instantly for a bolted fault, clearing in about 0.05 s. Step 4 — upstream relay setting: Design choice: set residual ground pickup to 5000 A with a definite time delay TD = 0.5 s (definite-time ground trip). Reasoning:

• 5000 A > 4000 A instantaneous threshold? It is slightly greater, but still less than available 18 kA; however, the MCCB will clear at 0.05 s before the upstream definite time of 0.5 s.
• Time margin Δt = t_upstream − t_downstream ≈ 0.5 − 0.05 = 0.45 s which meets a 0.3 s margin requirement.

Step 5 — verify at intermediate fault currents: Consider a ground fault of 6000 A (e.g., impedance-limited fault further downstream):

• MCCB instantaneous threshold 4000 A → MCCB will trip (since 6000 > 4000), clearing in ~0.05–0.1 s.
• Upstream relay at 5000 A pickup will see pickup (6000 > 5000) and start its 0.5 s timer; but since MCCB clears first, coordination preserved.

Step 6 — edge case: faults of magnitude 4500 A (between MCCB int threshold and relay pickup):

• 4500 A > 4000 A (MCCB instantaneous) → MCCB should trip; clearing ~0.05 s.
• Relay pickup 5000 A → relay will not pickup, so direct selectivity achieved.

Step 7 — adjustments and documentation: If field data or manufacturer curves indicate MCCB instantaneous clearing at higher times for some currents, increase upstream TD or set higher pickup to maintain Δt margin. Document all settings and the manufacturer curve references used. Conclusion for Example 1: With the selected settings (MCCB instantaneous 10× In, upstream residual pickup = 5000 A with 0.5 s definite delay), coordination is achieved for bolted and high-magnitude ground faults while permitting the downstream MCCB to clear first.

Detailed example 2 — Fuse-limited feeders and relay ground fault pickup

Scenario summary:

• Utility transformer: 1500 kVA, 480 V, %Z = 5%.
• Downstream device: current-limiting fuse protecting a distribution branch (fuse rating = 400 A, class RK1).
• Upstream device: feeder relay with sensitive ground detection; objective is to avoid upstream operation when branch fuse clears fault.

Step 1 — compute currents: Step 2 — fuse clearing behavior (representative/factory data required): Fuses are highly current-limiting. Representative approximate melting times:

• At 10× fuse rating (4000 A), melting time could be <0.02 s for RK class fuses.
• At 50× rating, basically instantaneous relative to protective relays.

Thus a bolted fault near the fuse will be cleared by the fuse in fractions of a cycle to a few cycles depending on the exact magnitude and fuse class. Step 3 — upstream relay considerations: Because fuses clear very quickly, the upstream relay must be set to avoid operation for faults that the fuse will clear. Two acceptable strategies:

1. Set upstream residual pick-up above the maximum current the fuse may pass before melting (i.e., above the minimum let-through current). This is difficult since fuses pass high peak let-through current; setting pickup > high current may compromise coverage for external faults.
2. Use an intentional time delay or definite-time setting that is longer than the maximum fuse melting time at expected fault currents, ensuring the fuse clears first. This is common in practice.

Step 4 — calculation and selection: Assume the worst-case fuse melting time at a particular fault magnitude is 0.05 s (representative). Choose upstream residual ground relay definite time TD = 0.2 s. Then Δt = 0.2 − 0.05 = 0.15 s margin. If the project requires Δt ≥ 0.2 s, set TD = 0.3 s instead. Step 5 — adaptive/communications assisted solution: If selective coordination cannot be met by time delay without compromising sensitivity, consider:

• Zone-selective interlocking (ZSI) or breaker-to-breaker communications to reduce time margins while preserving selectivity.
• Directional ground elements to prevent upstream tripping for external faults.

Result for Example 2: With a 1500 kVA transformer and RK1 fusings, set upstream residual relay to a definite-time TD = 0.3 s (or higher as required) to allow fast-fusing elements to operate first, while maintaining sensitivity to system-wide faults not cleared by fuses.

Practical considerations, pitfalls, and mitigation strategies

Common issues and countermeasures:

• Over-sensitivity of ground protection — may trip for harmless leakage or inrush. Mitigation: raise pickup or employ inverse-time curves and restraining elements.
• Downstream device mischaracterization — if you use catalog times rather than manufacturer curves, you risk miscoordination. Mitigation: obtain device-specific time-current curves from manufacturer.
• Changing system conditions (future load additions, generator sources) — these alter fault currents. Mitigation: plan for worst-case and re-evaluate coordination after significant changes.
• Neutral grounding practices — solid vs impedance grounded systems change ground-fault currents materially; adjust pickup accordingly.

Best practices:

1. Always use manufacturer time-current curves for exact coordination plots.
2. Document coordination studies and assumptions (system one-line, X/R ratios, %Z values, device curves).
3. Consider the impact of synchronous generator contributions and distributed generation on available fault current.
4. Test protection settings via primary injection where practical to validate actual operation times.

Standards, guides, and authoritative references

Key normative documents and resources to consult:

• NFPA 70 — National Electrical Code: requirements for selective coordination in critical occupancies. (https://www.nfpa.org/)
• IEEE Std 242 — Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems (IEEE Buff Book). (https://standards.ieee.org/)
• IEEE Std C37 series — Switchgear and relaying standards for test procedures and definitions. (https://standards.ieee.org/standard/C37_2-2008.html)
• IEC 60909 — Short-circuit currents in three-phase AC systems (guidance for fault current calculations). (https://www.iec.ch/)
• Manufacturer technical guides — e.g., ABB, Siemens, Schneider Electric application notes on coordination and time-current curve libraries.

For accurate legal or code compliance, always read the full text of the referenced standards and consult local utility requirements.

Tools and techniques for coordination calculation

Useful tools and techniques:

• Time-current curve plotting tools (commercial software or spreadsheets) using manufacturer data.
• Short-circuit calculation tools that implement IEC 60909 or equivalent for fault currents.
• Primary injection test equipment to validate trip times on installed devices.
• Coordination study reports that include one-line diagrams, device priorities, settings tables, and TCC (time-current characteristic) plots.

Additional reference tables

Common ground pickup recommendations and typical breaker instantaneous multipliers:

Summary of engineering decision points

When defining ground fault pickup relative to downstream breakers, key engineering questions include:

• What is the maximum available fault current at each location?
• What is the clearing time of each downstream device at a range of fault currents?
• Which coordination margin is required by company standard, equipment manufacturer, or code?
• Is a sensitive ground protection requirement conflicting with selectivity needs?
• Is communication-assisted coordination (e.g., transfer trip, ZSI) warranted to reduce time delays?

Adopt an iterative approach: calculate currents, apply manufacturer TCC data, verify margins, and re-adjust settings. Validate with tests and re-evaluate whenever system topology changes.

Further reading and manufacturer resources

Useful links for additional detailed technical references:

• NFPA Standards and Codes: https://www.nfpa.org/
• IEEE Standards Catalog: https://standards.ieee.org/
• IEC Standards and Publications: https://www.iec.ch/
• NEMA and major OEM application notes (search Schneider Electric, Siemens, ABB protective device coordination guides).

Note: Use manufacturer-specific time-current curves for final coordination; the examples here used representative values for conceptual demonstration.