How to Coordinate AC Protection with PV Side Protection

The $50,000 Mistake That Could Have Been Avoided

Last month, I received a frantic call from a solar installer in Arizona. His 500kW commercial rooftop system had just experienced a grid disturbance—nothing unusual. But here’s what went wrong: when a minor fault occurred on the AC side, the entire DC array remained energized while the inverter shut down. The uncoordinated protection scheme allowed a secondary fault to develop, and within minutes, the inverter was destroyed. The replacement cost? Over $50,000, plus three weeks of downtime.

This wasn’t a component failure. It was a coordination failure—a preventable mistake that costs the solar industry millions every year.

If you’ve ever wondered why your PV system trips unexpectedly, why upstream breakers fail to isolate faults properly, or why your expensive inverter keeps getting damaged, you’re facing the same challenge: improper coordination between AC-side and DC-side protection devices.

In this guide, I’ll walk you through the exact methodology I’ve used over 15 years to design bulletproof protection coordination schemes for solar PV systems—from residential rooftops to utility-scale solar farms. You’ll learn the critical differences between AC and DC protection, how to select and coordinate devices properly, and most importantly, how to avoid the costly mistakes that plague this industry.

Key Takeaway: Protection coordination isn’t about buying the most expensive devices—it’s about ensuring that when a fault occurs, only the device closest to the fault operates, leaving the rest of your system running safely. This is called selective coordination, and it’s your first line of defense against catastrophic system failures.

Why AC and DC Protection Are Two Different Animals

Before we dive into coordination strategies, you need to understand a fundamental truth that many engineers overlook: DC protection is not simply AC protection with a different voltage rating.

The DC Arc Challenge

When you open an AC circuit breaker under load, the alternating current naturally crosses zero 100 or 120 times per second (depending on your grid frequency). This zero-crossing gives the breaker a natural opportunity to extinguish the arc between contacts.

DC circuits don’t have this luxury. A DC arc, once established, wants to continue indefinitely. It’s like trying to stop a river that never stops flowing—you need significantly more arc-quenching capability built into the breaker mechanism. This is why you’ll see DC-rated breakers with larger arc chutes, magnetic blow-out coils, and specialized contact materials.

Pro-Tip: Never, under any circumstances, use an AC-rated breaker on a DC circuit, even if the voltage and current ratings seem adequate. The breaker may close and carry current normally, but when you need it to interrupt a fault, it will fail—often catastrophically, with sustained arcing that can start fires.

The Current-Limited Source Problem

Here’s another critical difference: PV arrays are current-limited sources. Unlike the utility grid, which can deliver fault currents 10 to 50 times the normal operating current, a PV array’s short-circuit current (Isc) is typically only 10-25% higher than its maximum power point current (Imp).

Think of it this way: the utility grid is like a fire hydrant that can blast water at tremendous pressure when you open the valve. A PV array is more like a garden hose with a flow restrictor—no matter how much you open the valve, you’re only getting a limited flow.

This has profound implications for protection coordination. Traditional overcurrent protection schemes designed for grid-connected systems assume high fault currents will quickly trigger protective devices. In PV systems, fault currents may be barely above normal operating levels, requiring different protection strategies: ground-fault detection, arc-fault detection, and time-delayed coordination schemes.

Inverter-Based Fault Current Contribution

On the AC side, modern inverters don’t behave like traditional synchronous generators. When a fault occurs on the AC side, the inverter’s control electronics limit fault current contribution to approximately 1.1 to 1.25 times the rated current—far below what traditional protection schemes expect.

This means your standard instantaneous trip settings, designed for high fault currents from rotating machines, may never operate. Instead, you need protection schemes that account for controlled current sources: residual current devices (RCDs), ground-fault relays, and carefully coordinated time-delayed elements.

Key Takeaway: Successful PV protection coordination requires abandoning many assumptions from traditional electrical design. You’re not protecting a conventional power system—you’re protecting a hybrid system with current-limited DC sources feeding electronically-controlled AC conversion equipment.

The Three-Zone Protection Philosophy for Solar PV Systems

Over my 15 years designing protection schemes for PV installations ranging from 5kW residential to 50MW utility-scale, I’ve developed a three-zone protection philosophy that ensures comprehensive, coordinated protection:

Zone 1: DC Array Protection (String to Combiner)

This is your first line of defense, protecting individual strings and string combiners from:

• String-to-string faults
• Module-level ground faults
• Reverse current from parallel strings
• Lightning-induced surges on DC conductors

Primary Protection Devices:

• DC-rated MCBs (Miniature Circuit Breakers) or fuses at each string input
• Type 2 DC SPDs (Surge Protection Devices) in combiner boxes
• String-level monitoring for ground-fault detection

Coordination Strategy: String-level protection must be selective with combiner-level protection. If one string develops a fault, only that string’s breaker should trip, leaving other strings operational.

Zone 2: DC Main Protection (Combiner to Inverter)

This zone protects the main DC conductors and the inverter DC input from:

• Combiner box output faults
• Main DC cable faults
• Insulation failures in long DC runs
• Direct lightning strikes

Primary Protection Devices:

• DC-rated MCCBs (Molded Case Circuit Breakers) sized for total array current
• Type 1+2 or Type 2 DC SPDs at inverter DC input
• Insulation monitoring devices (IMDs) for ground-fault detection
• DC disconnect switches for isolation

Coordination Strategy: Main DC protection must coordinate with both upstream string protection and downstream inverter protection. Time-current curves must be analyzed to ensure selectivity across the full fault current range.

Zone 3: AC Output Protection (Inverter to Grid)

This zone protects the AC side from:

• Inverter output faults
• AC cable faults
• Grid disturbances and voltage transients
• Harmonic currents and resonance conditions

Primary Protection Devices:

• AC-rated MCBs or MCCBs at inverter output
• Type A, F, or B RCDs (depending on inverter topology)
• Type 2 AC SPDs at inverter output and main distribution board
• Grid-tie protection relays (voltage, frequency, anti-islanding)

Coordination Strategy: AC protection must coordinate with utility grid protection and comply with interconnection requirements. The protection scheme must ensure the PV system disconnects before utility protective devices operate during system faults.

The Four-Step Coordination Method: From Theory to Practice

Now let’s get practical. Here’s the exact four-step method I use to design coordinated protection schemes for every PV project:

Step 1: Calculate System Parameters and Fault Levels

You can’t coordinate protection devices without knowing the fault currents and operating conditions at every point in your system. Start by calculating:

DC Side Calculations:

• Maximum string short-circuit current: $I_{sc,max} = I_{sc,STC} \times 1.25$ (NEC safety factor)
• Minimum string short-circuit current: $I_{sc,min} = I_{sc,STC} \times 0.85$ (low irradiance condition)
• Maximum system voltage: $V_{oc,max} = V_{oc,STC} \times (1 + \beta_{Voc} \times (T_{min} – 25°C))$
• Continuous operating current: $I_{continuous} = I_{mp} \times 1.25$

AC Side Calculations:

• Maximum inverter output current: $I_{inv,max} = \frac{P_{inv,rated}}{\sqrt{3} \times V_{L-L} \times \cos\phi} \times 1.25$
• Available fault current at PCC: Obtain from utility or calculate based on transformer impedance
• Inverter fault current contribution: Typically $I_{fault,inv} = 1.1 \text{ to } 1.25 \times I_{inv,rated}$

Pro-Tip: Always design for worst-case conditions. Use maximum Isc for device breaking capacity calculations and minimum Isc for protection sensitivity calculations. Temperature extremes dramatically affect PV performance—a cold, clear morning can push Voc 20-30% above STC ratings.

Step 2: Select Protection Devices with Proper Ratings

Device selection is where most coordination failures originate. Here’s what you need to verify for each device:

For DC Circuit Breakers:

• Voltage Rating: Must exceed maximum system Voc under coldest conditions (typically Voc × 1.15 to 1.25)
• Continuous Current Rating: $I_{rated} \geq I_{continuous} = I_{mp} \times 1.25$
• Breaking Capacity: Must exceed maximum available short-circuit current at that point
• DC Rating Certification: Look for IEC 60947-2 Annex B or UL 489 DC rating

For AC Circuit Breakers:

• Voltage Rating: Must match system voltage (230V, 400V, 480V, etc.)
• Continuous Current Rating: $I_{rated} \geq I_{inv,output} \times 1.25$
• Breaking Capacity: Must exceed available fault current at PCC plus inverter contribution
• Curve Type: Typically Type C or D for inverter inrush currents

For RCDs/RCCBs:

• Type Selection: Type A for standard inverters, Type B for transformerless inverters with DC injection risk
• Sensitivity: Typically 30mA for personnel protection, 300mA for equipment protection
• Time Delay: Coordinate with upstream devices to prevent nuisance tripping

For Surge Protection Devices:

• Voltage Protection Level (Up): Must be below equipment withstand voltage
• Maximum Continuous Operating Voltage (Uc): DC side: $U_c \geq 1.2 \times V_{oc,max}$; AC side: $U_c \geq 1.1 \times V_{nominal}$
• Discharge Current Rating: Type 1: Iimp ≥ 12.5kA (10/350μs), Type 2: In ≥ 20kA (8/20μs)
• Coordination: SPDs must coordinate with backup overcurrent protection (fuses or MCBs)

Step 3: Analyze Time-Current Curves for Selectivity

This is where engineering meets art. Selectivity analysis ensures that downstream devices always operate before upstream devices across the entire fault current range.

Selectivity Verification Process:

1. Obtain manufacturer time-current curves (TCCs) for all protective devices in the coordination chain
2. Plot curves on log-log paper with current on the x-axis and time on the y-axis
3. Verify non-intersection: Downstream device curves must lie entirely to the left of upstream curves
4. Check selectivity margin: Maintain at least 200ms time separation or 2:1 current ratio between adjacent devices
5. Validate at critical points: Minimum fault current, maximum fault current, and inverter rated current

Common Coordination Challenges:

• Insufficient separation at high fault currents: Instantaneous trip regions may overlap, causing loss of selectivity
• Inverter inrush currents: May cause nuisance tripping if breaker curves aren’t properly selected
• Low DC fault currents: May not reach the magnetic trip region, relying only on thermal trips with poor selectivity

Solution: Use adjustable MCCBs with electronic trip units when possible. These allow fine-tuning of trip curves to achieve selectivity that’s impossible with fixed thermal-magnetic breakers.

Step 4: Validate Coordination Under All Operating Conditions

A protection scheme that works at noon on a sunny day may fail at dawn or during partial shading. You must validate coordination under:

Operating Condition Matrix:

• High irradiance (1000 W/m²): Maximum current, standard voltage
• Low irradiance (200 W/m²): Minimum fault detection sensitivity
• Cold temperature (-20°C): Maximum voltage, affects breaker calibration
• Hot temperature (+70°C): Reduced breaker capacity, thermal derating
• Partial shading: Unbalanced string currents, potential reverse current
• Grid disturbances: Voltage sags, swells, frequency deviations

Validation Checklist:

• ✓ String breakers clear string faults without tripping combiner breaker
• ✓ Combiner breakers clear DC main faults without tripping inverter DC disconnect
• ✓ AC breakers clear inverter faults without tripping utility service entrance
• ✓ RCDs detect ground faults without nuisance tripping from inverter switching noise
• ✓ SPDs coordinate with backup protection (fuses/MCBs) without cascading failures
• ✓ All devices remain selective across temperature range and fault current variations

Key Takeaway: Coordination isn’t a one-time calculation—it’s a systematic validation process that considers the full operating envelope of your PV system. Document your coordination study with annotated TCC plots and keep them with the system O&M manual.

AC-DC Protection Coordination: Critical Comparison Table

Understanding the differences between AC and DC protection requirements is essential for proper coordination. Here’s a comprehensive comparison based on 15 years of field experience:

Pro-Tip: Print this table and keep it in your design toolkit. I reference it on every project to ensure I haven’t overlooked critical differences between AC and DC protection requirements. The “Coordination Implication” column is where most design mistakes happen—these are the lessons I’ve learned from troubleshooting failed installations.

Protection Coordination Architecture: System Overview

To visualize how all these protection zones work together, here’s the complete protection coordination architecture for a typical commercial PV system:

graph TB
    subgraph "Zone 1: DC Array Protection"
        A[PV String 1<br>Voc: 800V, Isc: 12A] -->|DC MCB 16A| B[String Combiner Box]
        A1[PV String 2<br>Voc: 800V, Isc: 12A] -->|DC MCB 16A| B
        A2[PV String 3<br>Voc: 800V, Isc: 12A] -->|DC MCB 16A| B
        A3[PV String N<br>Voc: 800V, Isc: 12A] -->|DC MCB 16A| B
        B -->|DC SPD Type 2<br>40kA, Uc: 1000V| B
    end

    subgraph "Zone 2: DC Main Protection"
        B -->|DC MCCB 125A<br>Breaking: 10kA| C[DC Main Disconnect<br>1000V, 125A]
        C -->|DC SPD Type 2<br>40kA, Uc: 1000V| C
        C -->|IMD Ground Fault<br>Detection| D[Inverter DC Input<br>100kW, 800Vdc]
    end

    subgraph "Zone 3: AC Output Protection"
        D -->|3-Phase AC<br>400V, 150A| E[Inverter AC Output]
        E -->|AC MCCB 200A<br>Type C, 25kA| F[AC Distribution Board]
        E -->|RCD Type B<br>300mA, 0.1s| F
        F -->|AC SPD Type 2<br>40kA, Uc: 460V| F
        F -->|Grid Protection Relay<br>V, f, anti-islanding| G[Point of Common Coupling]
    end

    subgraph "Utility Grid"
        G -->|Utility Breaker<br>Coordination Required| H[Utility Transformer<br>& Service Entrance]
    end

    style A fill:#FFE6CC
    style A1 fill:#FFE6CC
    style A2 fill:#FFE6CC
    style A3 fill:#FFE6CC
    style B fill:#FFF4CC
    style C fill:#FFE6E6
    style D fill:#E6F3FF
    style E fill:#E6F3FF
    style F fill:#E6FFE6
    style G fill:#F0E6FF
    style H fill:#F0E6FF

Understanding the Protection Cascade:

This diagram shows the hierarchical protection structure where each zone has primary and backup protection. Notice how:

1. String-level MCBs (16A) protect individual strings and coordinate with the combiner MCCB (125A)
2. DC SPDs are placed at both the combiner box and inverter input for coordinated surge protection
3. Insulation monitoring device (IMD) provides ground-fault detection that overcurrent devices can’t detect
4. AC-side protection is completely separate with its own coordination chain
5. RCD Type B is specified because this is a transformerless inverter that can inject DC residual current
6. Grid protection relay ensures the PV system disconnects before utility protection operates

Key Takeaway: Notice the defense-in-depth strategy—multiple layers of protection with clear coordination between layers. If one device fails to operate, the next layer provides backup protection. This is the hallmark of a professional protection design.

Real-World Coordination Example: 100kW Commercial Rooftop System

Let me walk you through a real coordination study I performed last year for a 100kW commercial rooftop installation. This example will show you exactly how to apply the four-step method.

System Specifications

• PV Array: 250 × 400W modules, 25 strings of 10 modules each
• Module Specs: Voc = 49.5V, Isc = 10.8A, Vmp = 41.2V, Imp = 9.7A
• Inverter: 100kW three-phase transformerless inverter, 400V AC output
• Location: Phoenix, Arizona (high solar exposure, lightning risk moderate)

Step 1: System Parameter Calculations

DC Side:

• String Voc, max (at -10°C): $49.5V \times 10 \times 1.14 = 564V$
• String Isc, max: $10.8A \times 1.25 = 13.5A$
• Array total Isc: $13.5A \times 25 = 337.5A$
• Continuous current per string: $9.7A \times 1.25 = 12.1A$

AC Side:

• Inverter rated current: $\frac{100,000W}{\sqrt{3} \times 400V \times 0.98} = 147A$
• Inverter continuous current: $147A \times 1.25 = 184A$
• Available fault current at PCC: 15kA (from utility data)
• Inverter fault contribution: $147A \times 1.2 = 176A$

Step 2: Device Selection

String Protection:

• Selected: DC MCB 16A, 1000V DC, 6kA breaking capacity, Type C curve
• Rationale: 16A > 12.1A continuous, 1000V > 564V Voc, max, Type C handles inrush

Combiner to Inverter:

• Selected: DC MCCB 350A, 1000V DC, 10kA breaking capacity, adjustable electronic trip
• Rationale: 350A > 337.5A total Isc, adjustable trip allows coordination tuning

Inverter AC Output:

• Selected: AC MCCB 200A, 400V AC, 25kA breaking capacity, Type C curve
• Rationale: 200A > 184A continuous, 25kA > 15kA available fault current

Ground Fault Protection:

• DC side: Insulation monitoring device, 500kΩ threshold
• AC side: RCD Type B, 300mA, 0.1s time delay

Surge Protection:

• DC SPD: Type 2, 1000V Uc, 40kA (8/20μs), with 20A backup fuse
• AC SPD: Type 2, 460V Uc, 40kA (8/20μs), with 32A backup MCB

Step 3: Time-Current Curve Analysis

I plotted the TCCs for the string MCB (16A), combiner MCCB (350A), and inverter DC disconnect. Here’s what I verified:

At Maximum Fault Current (337A):

• String MCB: Trips in 0.8 seconds (thermal region)
• Combiner MCCB: Set to trip in 3.0 seconds (adjustable long-time delay)
• Selectivity margin: 2.2 seconds ✓

At Minimum Fault Current (150A, low irradiance):

• String MCB: Trips in 8 seconds
• Combiner MCCB: Set to trip in 30 seconds
• Selectivity margin: 22 seconds ✓

At Inverter Rated Current (147A AC side):

• Inverter AC MCCB: Continuous operation (below trip threshold)
• Utility service entrance breaker (400A): No operation
• Proper coordination with utility ✓

Step 4: Validation Results

I validated this coordination scheme under multiple scenarios:

Scenario 1: Single String Fault

• Fault: String 5 develops ground fault, 8A fault current
• Result: String 5 MCB trips in 12 seconds, other strings continue operating ✓

Scenario 2: Combiner Box Output Fault

• Fault: DC cable short circuit between combiner and inverter, 320A fault current
• Result: Combiner MCCB trips in 2.8 seconds, string MCBs do not trip ✓

Scenario 3: AC Side Ground Fault

• Fault: 400mA ground fault on AC side
• Result: RCD Type B trips in 0.08 seconds, DC side remains isolated ✓

Scenario 4: Lightning Surge

• Event: 30kA (8/20μs) surge on DC side
• Result: DC SPD clamps voltage to 1800V (below inverter withstand of 2000V), backup fuse does not operate ✓

Key Takeaway: This real-world example demonstrates that successful coordination requires detailed calculations, proper device selection, TCC analysis, and multi-scenario validation. The adjustable MCCB at the combiner level was critical for achieving selectivity—fixed thermal-magnetic breakers would not have provided adequate coordination margin.

Common Coordination Mistakes and How to Avoid Them

In 15 years of troubleshooting PV installations, I’ve seen the same coordination mistakes repeated across hundreds of projects. Here are the top five, and how to avoid them:

Mistake #1: Using AC-Rated Breakers on DC Circuits

The Problem: I’ve seen installations where contractors installed standard AC MCBs on DC strings because “the voltage and current ratings were adequate.” When a fault occurred, the breaker failed to interrupt the DC arc, resulting in a sustained arc that melted busbars and started a fire.

The Solution: Always verify DC rating certification. Look for “IEC 60947-2 Annex B” or “UL 489 DC” markings. If you can’t find explicit DC ratings, don’t use the device on DC circuits—period.

Pro-Tip: DC-rated breakers typically cost 20-30% more than equivalent AC breakers. Don’t let cost pressure tempt you into using AC devices on DC circuits. The liability exposure from a single arc-flash incident will dwarf any savings.

Mistake #2: Ignoring Inverter Fault Current Limitations

The Problem: Engineers design AC-side protection assuming traditional fault current levels (10-20× rated current), then wonder why their instantaneous trip settings never operate when inverter faults occur. The inverter’s current-limiting control keeps fault current at 1.1-1.25× rated current—far below instantaneous trip thresholds.

The Solution: Design AC-side protection for current-limited sources. Use time-delayed coordination, ground-fault relays, and RCDs rather than relying on instantaneous overcurrent trips. Verify coordination at 1.25× inverter rated current, not at theoretical short-circuit levels.

Mistake #3: Inadequate SPD Coordination

The Problem: SPDs are installed without proper backup overcurrent protection, or the backup protection is oversized. When a surge exceeds the SPD’s capacity, it fails short-circuit, and the backup protection either doesn’t operate (too large) or takes too long (poor coordination), allowing the SPD to explode.

The Solution: Every SPD must have coordinated backup protection. Follow manufacturer specifications exactly:

• DC SPD with 40kA rating: 20A gPV fuse or 25A DC MCB backup
• AC SPD with 40kA rating: 32A AC MCB backup
• Verify that backup protection operates before SPD reaches thermal failure (typically 1-2 seconds)

Mistake #4: Neglecting Temperature Effects on Coordination

The Problem: Coordination studies performed at 25°C look perfect on paper, but fail in the field when ambient temperatures reach 50°C in rooftop combiner boxes. Thermal derating reduces breaker capacity, and the carefully calculated selectivity margins disappear.

The Solution: Apply thermal derating factors to all protective devices:

• For every 10°C above 30°C ambient, derate breaker capacity by 5-10% (check manufacturer data)
• In hot climates, upsize breakers one frame size to maintain coordination margins
• Use electronic trip MCCBs when possible—they’re less sensitive to temperature than thermal-magnetic devices

Mistake #5: Failing to Coordinate with Utility Protection

The Problem: The PV system’s AC protection is beautifully coordinated internally, but when a grid fault occurs, both the PV breaker and the utility service entrance breaker trip simultaneously. The utility is not happy, and neither is the building owner who just lost all power.

The Solution: Obtain utility coordination requirements during interconnection application. Typically, you need:

• PV breaker sized at 1.25× inverter output current
• PV breaker trip curve must clear faults faster than utility service entrance breaker
• Grid protection relay with voltage and frequency trip settings per IEEE 1547
• Time delay of 0.16 seconds (10 cycles) before anti-islanding trip to ride through momentary grid disturbances

Key Takeaway: Most coordination failures aren’t due to lack of knowledge—they’re due to shortcuts taken under schedule or budget pressure. Resist the temptation to skip calculations, use non-rated devices, or omit coordination studies. The cost of getting it wrong is always higher than the cost of doing it right.

Advanced Coordination Strategies for Complex Systems

For large commercial and utility-scale PV systems, basic coordination techniques may not be sufficient. Here are advanced strategies I use for complex installations:

Strategy 1: Zone-Selective Interlocking (ZSI)

ZSI uses communication between protective devices to achieve instantaneous tripping without sacrificing selectivity. When a fault occurs:

1. All devices in the coordination chain detect the fault
2. Downstream device sends a “restraint” signal to upstream devices
3. Downstream device trips instantaneously (0.05-0.1 seconds)
4. Upstream devices remain restrained unless downstream device fails to clear the fault

Application: I use ZSI on systems above 500kW where fault clearing time is critical for equipment protection and where the cost of intelligent MCCBs with communication capability is justified.

Implementation: Requires MCCBs with ZSI capability (typically electronic trip units with communication modules) and proper wiring of restraint signals between devices.

Strategy 2: Differential Protection for DC Mains

For long DC cable runs (>100 meters) between combiner boxes and central inverters, traditional overcurrent protection may not detect high-impedance faults. Differential protection compares current entering and leaving the protected zone.

How It Works:

• Current sensors at both ends of DC main cables
• Relay compares input current vs. output current
• If difference exceeds threshold (typically 10-20% of rated current), fault is detected within the protected zone
• Relay trips DC disconnect in 0.1-0.2 seconds

Application: Essential for utility-scale systems with DC cable runs exceeding 100 meters, especially in areas with high lightning exposure.

Strategy 3: Arc-Flash Hazard Reduction

Arc-flash incident energy is proportional to fault clearing time. Reducing clearing time from 2 seconds to 0.1 seconds can reduce incident energy by 95%, dramatically improving worker safety.

Techniques:

• Use instantaneous trip settings where selectivity allows
• Implement ZSI for fast clearing with maintained selectivity
• Use arc-flash relays that detect light and pressure signatures of arcing faults
• Design maintenance procedures with equipment de-energized whenever possible

Calculation: Arc-flash incident energy (cal/cm²) at working distance of 18 inches:\
$E = \frac{4.184 \times C_f \times E_n \times t}{D^2}$

Where: Cf = calculation factor (1.5 for open air), En = normalized incident energy, t = arc duration (seconds), D = working distance (inches)

Pro-Tip: On systems above 100kW, perform an arc-flash hazard analysis per NFPA 70E or IEEE 1584. Label equipment with incident energy levels and required PPE. This isn’t just good engineering—it’s a legal requirement in many jurisdictions and essential for worker safety.

Protection Coordination Checklist: Your Pre-Commissioning Verification

Before you energize any PV system, run through this comprehensive coordination checklist. I’ve used this on over 200 installations, and it’s caught critical errors before they became expensive failures:

DC Side Verification

• [ ] All DC breakers are DC-rated with proper voltage and current ratings
• [ ] DC breaker breaking capacity exceeds maximum available short-circuit current
• [ ] String breakers sized at 1.56 × Isc (minimum) per NEC 690.8
• [ ] Combiner/array breakers coordinate with string breakers (TCC analysis performed)
• [ ] DC disconnects are load-break rated and properly located
• [ ] DC SPDs installed at combiner boxes and inverter DC input
• [ ] DC SPD Uc rating ≥ 1.2 × Voc, max
• [ ] DC SPD backup protection properly sized and coordinated
• [ ] Insulation monitoring device installed and threshold properly set
• [ ] All DC conductors sized for 1.25 × Isc continuous current
• [ ] Temperature derating applied to all DC devices

AC Side Verification

• [ ] AC breakers properly rated for voltage, current, and breaking capacity
• [ ] AC breaker sized at 1.25 × inverter output current (minimum)
• [ ] RCD/RCCB type matches inverter topology (Type A, F, or B)
• [ ] RCD sensitivity appropriate for application (30mA or 300mA)
• [ ] AC SPDs installed at inverter output and main distribution board
• [ ] AC SPD Uc rating ≥ 1.1 × nominal voltage
• [ ] AC SPD backup protection properly sized and coordinated
• [ ] Grid protection relay programmed per utility interconnection requirements
• [ ] Anti-islanding protection verified (passive and active methods)
• [ ] Coordination with utility service entrance breaker verified

System-Level Verification

• [ ] Complete time-current curve analysis performed for all protection devices
• [ ] Selectivity verified at maximum, minimum, and rated current levels
• [ ] Temperature effects considered in coordination study
• [ ] Ground-fault protection coordinated between DC and AC sides
• [ ] Surge protection coordinated across all zones
• [ ] Arc-flash hazard analysis performed (systems >100kW)
• [ ] Protection coordination study documented and included in O&M manual
• [ ] Single-line diagram shows all protective devices with ratings
• [ ] Commissioning test plan includes protection device verification
• [ ] All devices labeled with ratings, settings, and coordination information

Key Takeaway: Print this checklist and use it on every project. I keep a laminated copy in my site inspection kit. The 15 minutes you spend on this checklist can prevent months of troubleshooting and tens of thousands in equipment damage.

Frequently Asked Questions (FAQ)

Q1: Can I use standard AC circuit breakers on the DC side if I derate them significantly?

Absolutely not. This is the most dangerous misconception in PV protection. AC breakers are fundamentally not designed to interrupt DC arcs. Even if you derate an AC breaker to 50% of its rating, it will still fail catastrophically when attempting to interrupt a DC fault. The arc chutes, contact materials, and interruption mechanisms are completely different. Always use DC-rated breakers certified to IEC 60947-2 Annex B or UL 489 DC standards. The cost difference is minimal compared to the liability exposure from using improper devices.

Q2: What’s the difference between Type A, Type F, and Type B RCDs, and which do I need for my PV system?

The RCD type determines what kinds of residual (ground fault) currents it can detect:

• Type A: Detects AC residual currents and pulsating DC residual currents. Suitable for inverters with galvanic isolation (transformer-based).
• Type F: Detects Type A currents plus higher-frequency AC currents up to 1kHz. Suitable for some modern inverters with high-frequency switching.
• Type B: Detects all Type A/F currents plus smooth DC residual currents. Required for transformerless inverters that can inject DC current into the AC ground path.

How to choose: Check your inverter datasheet. Most modern transformerless inverters explicitly require Type B RCDs. Using Type A on a transformerless inverter is a code violation and safety hazard—the RCD may not trip during a ground fault, leaving the system energized and dangerous.

Q3: How do I coordinate DC SPDs with backup overcurrent protection?

SPD coordination is critical but often overlooked. Here’s the step-by-step process:

1. Select SPD discharge current rating based on exposure: Type 2 SPDs typically 20-40kA (8/20μs)
2. Determine SPD maximum backup protection from manufacturer datasheet (e.g., “max backup fuse: 20A gPV”)
3. Verify backup device operates before SPD thermal failure: SPD can typically withstand follow-current for 1-2 seconds before thermal damage
4. Check backup device breaking capacity: Must be able to interrupt maximum available short-circuit current at that location
5. Verify selectivity: Backup protection must not operate during normal surge events, only during SPD failure

Example: For a DC SPD rated 40kA (8/20μs) with max backup protection of 20A:

• Use 20A gPV fuse or 25A DC MCB as backup
• Verify that at maximum DC short-circuit current (e.g., 300A), backup device clears in <1 second
• Confirm SPD can withstand 300A follow-current for 1 second without thermal failure

Q4: My system trips randomly during high solar production. How do I troubleshoot coordination issues?

Random tripping during high production usually indicates one of these coordination problems:

Diagnosis Process:

1. Identify which device is tripping: String breaker, combiner breaker, inverter AC breaker, or RCD?
2. Check current levels at trip time: Compare to device rating and trip curve
3. Verify temperature effects: Combiner box temperatures can reach 60-70°C, causing thermal derating
4. Check for harmonic currents: Inverter harmonics can cause RCD nuisance tripping
5. Review time-current curves: Device may be marginally coordinated, tripping under worst-case conditions

Common Causes:

• String breaker tripping: Breaker undersized for cold-weather Isc increase
• Combiner breaker tripping: Thermal derating in hot combiner box reduces capacity below operating current
• AC breaker tripping: Inverter inrush or harmonic currents exceed breaker tolerance
• RCD tripping: High-frequency switching noise from inverter exceeds RCD immunity, or wrong RCD type

Solutions:

• Upsize breakers to provide margin for temperature and aging effects
• Use Type B RCDs with time delay (0.1s) to ride through transient noise
• Install harmonic filters if THD exceeds 5%
• Verify all devices are properly derated for ambient temperature

Q5: Do I need separate SPDs on both DC and AC sides, or can one SPD protect the entire system?

You absolutely need separate DC and AC SPDs—one cannot protect the other. Here’s why:

DC Side SPDs:

• Protect against surges on PV array conductors (lightning, switching transients)
• Must be rated for DC voltage (Uc ≥ 1.2 × Voc, max)
• Typically 1000-1500V DC rating for utility-scale systems
• Installed at combiner boxes and inverter DC input

AC Side SPDs:

• Protect against surges from utility grid (lightning, switching, capacitor bank operations)
• Must be rated for AC voltage (Uc ≥ 1.1 × Vnom)
• Typically 275-460V AC rating depending on system voltage
• Installed at inverter AC output and main distribution board

Why Both Are Needed:\
The inverter provides galvanic isolation (transformer-based) or electronic isolation (transformerless) between DC and AC sides. A surge on one side doesn’t directly couple to the other side, so each side needs its own protection. Additionally, DC and AC SPDs have completely different voltage ratings and cannot be interchanged.

Cost-Benefit: DC and AC SPDs together typically cost $300-800 for residential systems, $2,000-5,000 for commercial systems. Inverter replacement costs $5,000-50,000+. The SPD investment is always justified.

Q6: How often should I test and verify protection coordination after installation?

Protection coordination isn’t a “set and forget” system. Here’s my recommended testing schedule:

Initial Commissioning (Day 1):

• Verify all device ratings and settings
• Perform insulation resistance testing (DC and AC sides)
• Test RCD trip function (test button and external test device)
• Verify ground-fault detection systems
• Document baseline measurements

First Year (Quarterly):

• Visual inspection of all protection devices
• RCD trip test (test button)
• Review monitoring system for any nuisance trips or alarms
• Verify no unauthorized modifications to protection settings

Years 2-5 (Semi-Annual):

• Visual inspection and cleaning
• RCD trip test with external test device (verify trip time and sensitivity)
• Thermographic inspection of all connections
• Review and update coordination study if any components changed

Years 5+ (Annual):

• Complete protection system verification
• Insulation resistance testing
• Contact resistance testing on all breakers and disconnects
• RCD trip time and sensitivity verification with calibrated test equipment
• Consider updating aging devices (thermal-magnetic breakers drift over time)

After Any System Modification:

• Re-verify coordination if any protection devices changed
• Update coordination study documentation
• Perform commissioning-level testing on modified circuits

Pro-Tip: I recommend installing a monitoring system that logs all protection device operations. This provides invaluable data for troubleshooting coordination issues and identifying devices that may be failing or improperly set.

Q7: What’s the best way to achieve selectivity when DC fault currents are only slightly above normal operating current?

This is one of the most challenging aspects of PV protection coordination. Here are the strategies I use:

Strategy 1: Electronic Trip MCCBs\
Replace fixed thermal-magnetic breakers with adjustable electronic trip units. These allow you to:

• Set precise trip thresholds (e.g., 1.15× rated current vs. 1.3× for thermal-magnetic)
• Adjust time delays independently of current setting
• Create custom trip curves optimized for PV current profiles

Strategy 2: Time-Graded Coordination\
Since current-graded coordination is difficult with limited fault current, rely on time delays:

• String breakers: Standard trip curve (no delay)
• Combiner breakers: 2-3 second time delay
• Main DC breakers: 5-10 second time delay

This ensures downstream devices always trip first, even if fault current is barely above pickup.

Strategy 3: Dedicated Ground-Fault Protection\
Many DC faults are ground faults that don’t produce high overcurrent. Use insulation monitoring devices (IMDs) or residual current sensors that detect ground faults directly, independent of overcurrent magnitude.

Strategy 4: String-Level Monitoring\
Implement string-level current monitoring that can detect abnormal conditions (reverse current, low current, high imbalance) and send alarms or trip signals before thermal damage occurs.

Combination Approach: On systems above 250kW, I typically use a combination of all four strategies. The investment in electronic trip units and monitoring pays for itself in improved uptime and reduced equipment damage.

Q8: How do I coordinate PV system protection with existing building electrical protection?

Integrating PV protection with existing building systems requires careful analysis of the existing protection scheme:

Step 1: Obtain Existing Protection Data

• Building service entrance breaker rating and curve
• Feeder breaker ratings and curves
• Available fault current at PCC
• Existing coordination study (if available)

Step 2: Determine PV Interconnection Point

• Load-side connection: PV connects to existing distribution panel; must coordinate with panel main breaker
• Line-side connection: PV connects ahead of building main breaker; must coordinate with utility transformer protection
• Separate service: PV has dedicated utility connection; must coordinate with utility protection only

Step 3: Verify Backfeed Protection\
If PV connects to existing panel:

• Panel busbar must be rated for backfeed (most modern panels are)
• Sum of breaker ratings must not exceed panel rating: $I_{main} + I_{PV} \leq 1.2 \times I_{busbar}$
• PV breaker must be located at opposite end from main breaker (NEC 705.12(D)(7))

Step 4: Coordinate Trip Curves

• PV breaker must clear faults before building main breaker
• Typical approach: Size PV breaker at 1.25× inverter current, verify it trips faster than main breaker across full fault current range
• May require downsizing PV breaker or upsizing main breaker to achieve selectivity

Step 5: Verify Fault Current Ratings\
Adding PV increases available fault current at all downstream points:

• Calculate PV fault contribution (typically 1.1-1.25× inverter rating)
• Verify all existing breakers can handle increased fault current
• If existing breakers have insufficient breaking capacity, they must be replaced

Pro-Tip: Many coordination issues arise because the electrical contractor treats the PV system as completely separate from building electrical. Always involve the building’s electrical engineer in coordination studies, especially for load-side connections.

Conclusion: Protection Coordination Is Your System’s Insurance Policy

If you’ve made it this far, you now understand something that many engineers with decades of experience still get wrong: protection coordination isn’t about buying the most expensive devices or following prescriptive checklists—it’s about understanding the unique characteristics of PV systems and designing defense-in-depth protection that ensures only the device closest to a fault operates, leaving the rest of your system safe and operational.

The $50,000 inverter failure I described at the beginning of this article? It could have been prevented with a $500 investment in proper coordination study and correctly specified protection devices. The three weeks of downtime? Eliminated. The loss of revenue, the insurance claim, the damage to the installer’s reputation? All avoidable.

Here are the key principles I want you to take away:

1. DC and AC protection are fundamentally different. Never use AC devices on DC circuits. Always account for current-limited sources and inverter fault current limitations.

2. Coordination requires systematic analysis. Calculate system parameters, select properly rated devices, analyze time-current curves, and validate under all operating conditions.

3. Defense-in-depth is essential. Multiple layers of protection with clear coordination between layers ensures that if one device fails, backup protection is available.

4. Temperature, harmonics, and aging matter. Real-world conditions affect coordination. Design with margin and verify performance over the system lifetime.

5. Documentation is critical. A coordination study that isn’t documented might as well not exist. Future troubleshooting and system modifications depend on clear documentation.

The solar industry is maturing rapidly. The days of “install and hope” are over. Utilities, insurance companies, and building owners now demand professional-grade protection coordination studies. The engineers who master these skills will be the ones designing the next generation of reliable, safe, and profitable solar installations.

Your Next Steps:

1. Review your current projects against the coordination checklist in this article. Are there gaps?
2. Invest in coordination tools: Time-current curve analysis software (SKM PowerTools, ETAP, or even free tools like ETEK Solar’s coordination calculator)
3. Build a device library: Collect TCC data for the breakers, fuses, and relays you commonly use
4. Document everything: Create coordination study templates you can reuse across projects
5. Keep learning: Protection coordination is a deep field. Consider IEEE, IEC, and NEC training courses

If you have questions about coordinating protection for your specific project, or if you’ve encountered coordination challenges I didn’t cover here, leave a comment below. I read every comment and often write follow-up articles based on the questions I receive.

Stay safe, design smart, and remember: the best protection scheme is the one that never has to operate—but when it does, it works flawlessly.

About the Author: With over 15 years of experience in electrical automation and solar PV system design, I’ve designed protection coordination schemes for over 200 installations ranging from 5kW residential to 50MW utility-scale. I specialize in translating complex protection theory into practical, field-proven solutions that keep systems safe and operational.