How to Set Overcurrent Protection Trip Settings on an ACB: Engineer Guide

What are overcurrent protection trip settings on an ACB? Overcurrent protection trip settings on an air circuit breaker (ACB) are the configurable thresholds and time-delay parameters — spanning long-time, short-time, instantaneous, and ground-fault functions — that govern how a device rated up to 6300 A under IEC 60947-2 responds to overload and fault conditions. Misconfigured settings, such as an Ir pickup set above the cable's rated current or miscoordinated short-time delays, cause either nuisance tripping under motor inrush or dangerous fault energy accumulation that destroys downstream equipment. This guide covers calculating long-time pickup (Ir), setting long-time delay (tr) for motor and transformer loads, coordinating short-time and instantaneous settings for selectivity, configuring ground-fault protection, and comparing settings across real industrial applications.

What Are the Four Trip Functions on an ACB and Why Do They Exist?

Before turning a single dial to configure ACB Trip Settings, an engineer needs a clear mental model of what each protection function actually does. Modern electronic trip units — Ekip on ABB, Micrologic on Schneider, ETU on Siemens — implement up to four distinct overcurrent protections, commonly abbreviated LSIG.

Long-Time (L) — The Thermal Overload Protector

The L function emulates the I²t heating curve of a cable or transformer winding. It is slow on purpose. A typical L pickup (Ir) sits between 0.4 and 1.0 of the breaker's rated current In, with a time delay (tr) measured at 6×Ir, usually adjustable from 3 s to 144 s. Why so slow? Because cables have thermal mass. A 240 mm² XLPE cable can absorb 1.5×its rated current for several minutes without insulation damage, and tripping prematurely on legitimate load swings — say, a 1 MW chiller starting in a hospital plant room — costs operators uptime and money.

Short-Time (S) — The Selectivity Workhorse

The S function exists almost entirely for one reason: time-graded selectivity between upstream and downstream breakers. Pickup (Isd) is typically 1.5–10×Ir with delays from 0.05 s to 0.8 s. Engineers often overlook that S can be either fixed-time (definite time) or I²t-shaped (inverse), and that choice changes how it coordinates with downstream MCCBs and fuses.

Instantaneous (I) — The Last Line of Defense

I trips with no intentional delay (typically <40 ms total clearing time) at currents from 1.5 to 15×In. It catches bolted faults close to the busbar where short-circuit currents may exceed the cable's adiabatic withstand. Some applications — main-tie-main schemes, generator breakers — deliberately switch I off (set to OFF or "∞") to maintain selectivity, relying on S alone.

Ground-Fault (G) — The Arc-Flash Mitigator

G detects residual current (vector sum of three phases plus neutral). In a TN-S system, even a 200 A ground fault on a 2000 A feeder won't move the L or S elements, but G picks it up at 0.2–1.0×In within 0.1–0.4 s. In our experience, G is the single most important setting for arc-flash incident energy reduction — a fact NFPA 70E and IEEE 1584 calculations make brutally obvious.

How Do You Calculate the Long-Time Pickup (Ir) Setting?

The L pickup is the foundation of all ACB Trip Settings. Get this wrong and everything downstream is wrong.

Step 1: Establish the Maximum Continuous Load Current

Pull the actual load schedule, not the connected load. For a motor control center feeding eight 75 kW motors at 400 V, the calculated full-load amps (FLA) sum to roughly 1080 A, but applying a 0.85 diversity factor (typical for non-simultaneous starting in process plants) gives a design current Ib of about 920 A. Add a 25% margin for future load growth — most clients ask for this, even when they don't say so out loud — and the protected circuit current becomes 1150 A.

Step 2: Match the Breaker Frame

For 1150 A continuous load, the ABB 1SDA070821R1 E1.2B 1250 with In = 1250 A is the natural choice. The Ir setting then becomes:

For our example: Ir = (920 × 1.25) / 1250 = 0.92, so set the dial to 0.92 (giving 1150 A pickup). The L curve will trip in 6×Ir = 6900 A within the configured tr.

Step 3: Cross-Check Against Cable Ampacity

This is where junior engineers get burned. The L pickup must also be ≤ the cable's continuous ampacity Iz. If the feeder is a 2×185 mm² Cu XLPE in trefoil, derated for 35 °C ambient and ladder tray installation, the IEC 60364-5-52 ampacity might be around 1180 A. Our 1150 A pickup fits — but barely. Had the cable been 2×150 mm² (Iz ≈ 980 A), the breaker frame and load would not match the cable, and either the cable or the load schedule must change.

How Do You Set the Long-Time Delay (tr) for Motor Loads and Transformers?

Within ACB Trip Settings, the L time delay determines how the breaker tolerates inrush and starting transients. The standard convention is to specify tr at 6×Ir.

Motor Starting

A typical squirrel-cage induction motor draws 6–7×FLA for 5–15 seconds on direct-on-line start. For a soft-starter or VFD application, inrush is limited to 2–3×FLA, so tr can be shorter. In practice, what we typically see in the field is tr = 12 s on motor feeders, which provides margin for restart sequences without compromising cable thermal protection.

Transformer Inrush

Liquid-filled distribution transformers exhibit magnetization inrush of 8–12×FLA decaying over 100–500 ms. The L function's I²t curve almost always rides above this inrush at 6×Ir, but the S and I settings must be checked carefully. We will return to this in the selectivity section.

Thermal Memory

Modern Ekip Dip and Micrologic units include thermal memory — the trip unit "remembers" recent overload heating for several minutes. This matters when a motor restarts after a brief overload trip; without thermal memory, repeated near-trip events can overheat windings undetected. Verify thermal memory is enabled on critical feeders. For a deeper look at trip-unit behavior under transient conditions, see our analysis of ACB nuisance tripping causes and fixes.

How Do You Coordinate Short-Time (S) and Instantaneous (I) Settings for Selectivity?

Selectivity — the principle that only the breaker nearest the fault should trip — is where most ACB commissioning meetings get heated, and ACB Trip Settings are at the centre of the argument. The S and I functions are the levers.

The Time-Grading Principle

Between two series breakers, the upstream device must wait long enough for the downstream device to clear the fault. The minimum grading interval per IEEE 242 §15.10 is 100 ms for two electronic ACBs in series, or 150–200 ms when an MCCB is downstream. So if a downstream MCCB clears in 60 ms total, the upstream ACB's S delay should be set to at least 160 ms (let's say 0.2 s).

Setting Isd (Short-Time Pickup)

Set Isd above the largest legitimate transient — usually motor starting or transformer inrush — but below the minimum bolted fault current at the next downstream bus. A common rule:

Isd ≥ 1.25 × (largest motor LRA + sum of running loads) / Ir

For a 1600 A feeder with one 250 A motor (LRA = 1500 A) and 1100 A of other running load, Isd should be ≥ 1.25 × (1500 + 1100) / 1600 = 2.0×Ir. Round up to 2.5×Ir for margin.

Should I Function Be Enabled or Disabled?

Some engineers argue I should always be on. In my experience, on the main incomer of a critical bus — say the ABB 1SDA071021R1 E2.2B 2000 feeding a hospital main switchboard — disabling I and relying on S with a 0.4 s delay gives full selectivity with downstream 800–1250 A feeder breakers. The trade-off: the busbar must withstand the prospective short-circuit current Icw for the full S delay, so verify the breaker's short-time withstand rating Icw covers it. The Emax 2 E2.2B has Icw = 42 kA for 1 s, which is generous.

For a deeper treatment of breaker selection and selectivity logic, the step-by-step ACB sizing calculator walks through frame selection in parallel with trip settings.

How Do You Set Ground-Fault (G) Protection on an ACB?

Ground-fault protection on a 1000 A+ feeder is mandatory in many jurisdictions, and it directly shapes the ACB Trip Settings you can legally apply. NEC 230.95 requires GFP on solidly grounded wye services rated >1000 A at 480Y/277V, set no higher than 1200 A pickup with a maximum 1 s delay at 3000 A. IEC has no equivalent blanket rule, but IEC 60364-4-41 and the project's earthing arrangement (TN-S, TN-C-S, TT, IT) drive the requirements.

Pickup (Ig) Selection

For a TN-S system on a 1600 A main feeder, set Ig to 0.3–0.5×In. Lower is better for arc-flash mitigation but invites nuisance trips from the natural ground current of long cables (capacitive leakage of perhaps 3–5 A per km of XLPE). Our usual default on the ABB 1SDA070981R1 E2.2B 1600 is Ig = 0.4 (640 A pickup).

Time Delay (tg)

Use 0.2 s on the main, 0.1 s on a feeder, and instantaneous (off) on a final branch — provided the downstream device also has G or RCD protection. This three-level grading typically holds up well in audited switchboards.

Source-Ground vs Residual Sensing

A common mistake is wiring the neutral CT incorrectly. On a four-pole ACB with internal residual sensing, the trip unit sums the three internal CTs plus the neutral CT — if the neutral CT is reversed or the wrong polarity, ground-fault protection will trip on normal unbalanced load. Always verify with primary injection during commissioning.

How Do Settings Differ Across Real Industrial Applications?

ACB Trip Settings are not universal. The same 1600 A frame in different installations gets very different programming.

Data center mains run lower Ir and aggressive G to minimize incident energy at the IT load — the engineering team is often willing to accept slightly higher nuisance-trip risk in exchange for arc-flash safety. For a deeper case study, see ACBs in Data Centers: Selection and Design Best Practices.

Process plants — petrochemical, pulp and paper, cement — prioritize keeping production running. Settings tolerate the largest motor's locked-rotor inrush and accept higher Ig pickup to avoid spurious trips from cable capacitive currents on long horizontal runs.

Generator breakers are special. The generator's fault current decays over the sub-transient (10–30 ms), transient (0.1–2 s), and steady-state (>2 s) periods. A bolted three-phase fault that starts at 8×FLA may decay to 3×FLA within a second. The Ii function is typically disabled because the prospective fault current is below the instantaneous threshold by the time the breaker would clear. Instead, S is set with a 0.4 s definite-time delay above 4×Ir, with an additional Voltage-Restraint or Voltage-Controlled Overcurrent function (51V) on dedicated generator protection relays.

How Do Brand Differences Affect Trip Setting Procedure?

ABB Ekip, Schneider Micrologic, and Siemens ETU each implement LSIG slightly differently in user interface and parameter granularity when applying ACB Trip Settings, even though the underlying IEC 60947-2 protection logic is identical.

ABB Ekip Dip (E1.2/E2.2/E4.2/E6.2)

The Ekip Dip series found in the E1.2B 630 1SDA070701R1 and E1.2B 800 1SDA070741R1 uses physical DIP switches for Ir, Isd, tsd, Ii — no display, no software. This is intentional: it is robust, panel-engineer-friendly, and tamper-evident. The trade-off is granularity: Ir steps are 0.05, not continuous.

ABB Ekip Touch / Hi-Touch

The touch-screen variants on Emax 2 add continuous parameter adjustment, IEC 61850 communications, and waveform capture. They cost more and add a learning curve for technicians.

Schneider Micrologic 5.0/6.0

Micrologic uses rotary encoders and a small LCD. The settings are more granular, and the X variant adds zone-selective interlocking (ZSI) wiring through dedicated terminals.

Siemens ETU 25B/45B/76B

The ETU on 3WL/3WT series is similar in concept; the 76B adds full metering and waveform recording. For a side-by-side comparison see our ABB vs Schneider vs Siemens ACB brand comparison.

How Do You Verify Settings After Commissioning?

Entering ACB Trip Settings on a switch is not the same as a working protection scheme. Three verification steps separate professionals from amateurs.

Primary Injection Testing

Inject current at the breaker's primary terminals using a high-current test set (Omicron CPC 100, Megger SVERKER, or equivalent). Verify L pickup at 1.05×Ir (must not trip in 2 hours) and 1.30×Ir (must trip within the conventional time per IEC 60947-2 Table 6, typically <1 hour for In ≤ 63 A, <2 hours for higher). Verify S and I pickup with stepped current injection. Record clearing times — they should fall within the trip unit tolerance band, typically ±10% on pickup and ±20% on time.

Secondary Injection Testing

Where primary injection is impractical (a 4000 A frame on a live switchboard, for instance), use the trip unit's test port — Ekip T&P for ABB, Micrologic Test Kit for Schneider. This verifies trip unit logic but not CT polarity or wiring; only primary injection catches a reversed neutral CT.

Coordination Curve Verification

Plot the actual configured settings against downstream devices using ETAP, SKM PTW, or DOC Web (ABB's free coordination tool). The plotted curves must show a clear vertical gap (selectivity) at the maximum prospective fault current, not just at moderate overloads. Engineers often overlook the high-current end of the curve, where I functions overlap and selectivity collapses.

Document and Seal

Final settings should be photographed, recorded in the commissioning report, and the cover sealed with tamper-evident tape. We have walked into facilities five years after commissioning to find DIP switches inexplicably changed — sometimes by a contractor "investigating" a trip, sometimes for reasons no one can explain. A sealed cover and a labeled setting sheet inside the panel door save grief.

What Are the Most Common Trip Setting Mistakes in the Field?

After years of audits on ACB Trip Settings, the same errors keep surfacing. Here are the ones worth flagging.

Setting Ir at Frame Rating "Just to Be Safe"

Ir = 1.0 means the breaker provides no overload protection above the frame rating. If the load is 800 A on a 1600 A frame, the cable can carry 1500 A indefinitely before tripping — long enough to destroy insulation. The fix is calculating Ir from actual load, not picking the maximum.

Identical Settings Copied Across Identical Breakers

Twelve identical 1600 A feeders in a switchboard do not have identical loads. Copying settings from breaker 1 to breakers 2–12 produces overprotection on lightly loaded feeders and underprotection on heavily loaded ones. Each feeder needs its own load calculation.

Disabling I Without Checking Icw

Disabling instantaneous to gain selectivity is fine — provided the breaker's short-time withstand current Icw covers the prospective fault for the full S delay. On older Emax 1 frames or smaller E1.2 breakers, Icw may only be 36 kA for 0.5 s. If the prospective Isc is 40 kA and S delay is 0.4 s, the breaker may fail destructively before clearing.

Forgetting Generator Mode

When a switchboard runs on standby generator, the prospective fault current drops by 5–10×. Settings tuned for utility supply may not pick up at all on generator. Modern trip units (Ekip Hi-Touch, Micrologic 6.0X) support dual setting groups switched by a digital input from the ATS — use this feature.

Neglecting Harmonic Distortion

VFD-rich loads produce true RMS currents 5–15% higher than fundamental-only readings. Trip units with peak-sensing rather than true-RMS sensing can trip on harmonic distortion at currents below the displayed Ir. Verify the trip unit is true-RMS — all current Ekip, Micrologic, and ETU electronic units are, but some legacy thermal-magnetic ACBs are not.

How Do IEC 60947-2, IEEE, and NEMA Standards Compare on Trip Settings?

The three standards bodies overlap considerably on ACB Trip Settings but differ in details that matter for procurement.

IEC 60947-2 defines the testing and tolerance requirements for trip functions in Annex F. It specifies conventional non-tripping (1.05×Ir) and tripping (1.30×Ir) currents, but leaves the actual setting selection to the application engineer. Selectivity is addressed in IEC TR 61912-2.

IEEE C37.13 and IEEE 242 ("Buff Book") provide the protection coordination methodology used predominantly in North America. IEEE 242 §15 has the canonical curves and grading interval rules.

NEMA AB 4 covers field testing of MCCBs primarily, but its principles transfer to ACBs. UL 489 is the U.S. listing standard for the breaker itself, while UL 1066 covers low-voltage power circuit breakers — most North American ACBs are dual-listed.

For European and most international projects, IEC 60947-2 governs. For North American projects on mixed UL/IEC equipment, expect to satisfy both — the full IEC 60947-2 standard breakdown covers utilization categories (Category B is required for any ACB used as a main breaker with selectivity).

Practical Worked Example: 2000 A Main Breaker in a Manufacturing Plant

To pull this all together, consider a real scenario: a 2000 A main incomer feeding an 800 V switchboard at a tier-1 automotive parts plant in Mexico. Source is a 2500 kVA 13.8 kV/480 V transformer with 5.75% impedance. Prospective Isc at the LV bus is 52 kA symmetrical.

Loads: 6 × 1500 A MCC feeders, mixed with welding (high harmonic content) and stamping presses (high inrush). Continuous load measured at peak shift = 1620 A.

Selected breaker: ABB E2.2B 2000 Ekip Dip LI — note this is LI only; for ground fault and selectivity options we would specify E2.2B 2000 LSIG instead. For the example, assume the LSIG version.

Settings:

L: Ir = (1620 × 1.15) / 2000 = 0.93. Set Ir = 0.95 (1900 A pickup), tr = 18 s at 6×Ir.

S: Largest downstream MCCB is 800 A with instantaneous at 8×, clearing in 50 ms. Required grading interval 0.15 s. Set Isd = 4×Ir (7600 A), tsd = 0.2 s, I²t curve ON for better coordination with downstream MCCB thermal-magnetic curves.

I: Disabled (OFF). Bus Icw = 65 kA for 1 s on E2.2B, which covers the 52 kA prospective for the full S delay with margin.

G: Ig = 0.4 (800 A pickup), tg = 0.3 s. Above the residual current expected from the welding harmonic content (estimated 200–300 A on this size of installation).

Verification: primary injection at 1.95 kA must not trip within 2 hours. Injection at 7600 A must trip within 0.2 s ± 20%. Injection at 800 A residual must trip within 0.3 s. Coordination plot in DOC Web confirms 0.15 s minimum grading at all current levels up to 52 kA.

This is a complete, defensible commissioning package. The same logic — adapted to load profile and downstream coordination — applies to any ACB from the 630 A E1.2B 630 Ekip Dip LSI up to 6300 A frames.

Related Reading

• What Is an Air Circuit Breaker? Working Principle Explained
• How to Size an Air Circuit Breaker: Step-by-Step Selection Calculator
• IEC 60947-2 for Air Circuit Breakers: Full Standard Breakdown
• Air Circuit Breaker Nuisance Tripping: Causes, Diagnosis and Fixes

Conclusion: Trip Settings Are Engineering, Not Configuration

Setting overcurrent protection on an ACB is not a checklist exercise. It is a design decision that balances cable thermal limits, load behavior, downstream selectivity, and arc-flash exposure — and the right answer changes every time the load changes. The L function protects the cable, S enables selectivity, I protects the switchgear, and G protects people. Each must be calculated, set, verified by primary injection, and documented before the breaker is considered commissioned.

For procurement managers specifying ACBs across a project portfolio, the trip unit choice (LI vs LSI vs LSIG, DIP vs Touch, with or without ZSI) should be made up front based on the protection scheme — not retrofitted later. Stoklink stocks the full ABB Emax 2 range at competitive lead times, from the E1.2B 1000 through 6300 A frames, alongside the broader air circuit breakers collection, complementary miniature circuit breakers, residual current devices, and protection relays for downstream coordination.

For the full selection methodology, fault calculation procedures, and maintenance practices that complete the protection lifecycle, see our Air Circuit Breaker Engineering Guide — the pillar reference that ties trip setting, sizing, standards compliance, and field maintenance into one coherent workflow.