Punjab PSEB Sr. Sec. NSQF Electronics (Solar Panel Installation Technician) common mistakes
Punjab PSEB Sr. Sec. NSQF Electronics (Solar Panel Installation Technician) · Understand the traps and how to avoid them.
Using Voc and Isc from the datasheet as if they were the module's operating voltage and current, then computing array power as Voc × Isc (or multiplying Vmp × Isc) instead of using Vmp × Imp and applying the temperature-corrected Voc for string sizing.
Candidates memorise the four datasheet numbers but never link them to the IV curve; the open-circuit and short-circuit points are the easiest to remember and look like 'the' ratings, so they get substituted into P = V × I. The Voc in a datasheet is at STC, and candidates forget that Voc rises as cell temperature falls, which is exactly the condition that destroys an inverter's input stage.
What to do instead
Drill the four points on a drawn IV curve: Voc at I = 0, Isc at V = 0, and the knee at (Vmp, Imp) where the module actually delivers power. For every string-sizing question, compute the cold-condition Voc using the datasheet temperature coefficient of Voc (about −0.3 %/°C for crystalline silicon) and compare it against the inverter's maximum DC input voltage; compute the hot-condition Vmp against the MPPT window's lower limit. Practice with numbers: a 41 V Voc module at −5 °C with −0.30 %/°C becomes 41 × (1 + 0.30 × 30/100) ≈ 44.7 V, so 25 in series exceeds a 1000 V inverter limit.
Treating 'efficiency' as a synonym for 'rated power' and answering that a 400 W module is more efficient than a 330 W module, or comparing modules of different areas by wattage alone.
Wattage is the number printed largest on the label and in quotations, so it dominates attention; area and irradiance are treated as background. Candidates also forget that efficiency is defined at STC (1000 W/m², 25 °C, AM 1.5) and therefore is not the same as real-world yield.
What to do instead
Force the formula η = Pmax / (area × 1000 W/m²) into every comparison. A 400 W module of 2.0 m² is 20 % efficient; a 330 W module of 1.6 m² is 20.6 % efficient, so the lower-wattage module is actually the better use of roof area. Pair this with a worked example showing that two modules of equal efficiency but different area differ in total energy, and that STC is a laboratory reference point, not an outdoor operating condition.
Recommending a module technology by habit ('mono is always best') without matching it to the site constraint, and misidentifying defects such as snail trails, PID, hotspot burn marks, micro-cracks, delamination, browning/EVA discolouration, or bypass-diode failure by name and cause.
Marketing language around mono/poly has been absorbed from advertising, and thin-film's temperature coefficient and low-light advantages are rarely taught. Defect identification is usually studied from photographs only, so candidates memorise appearance without linking it to the electrical or environmental cause, and then confuse snail trails (a cosmetic, moisture/acetate-related discolouration along busbars) with actual cell failure.
What to do instead
Build a three-column table: technology (mono PERC, poly, CdTe/CIGS thin-film) versus space efficiency, temperature coefficient, low-light and shading behaviour, and cost per watt, and answer from the table. For defects, learn cause → symptom → test: PID shows as voltage loss to earth with power degradation and is checked by an insulation/leakage test; a hotspot shows as a localised burn or discolouration and is confirmed by IR thermography or a bypass-diode check; micro-cracks appear as dark line patterns under electroluminescence and are caused by handling or foot traffic. Practise naming the defect from a written description, not a picture.
Sizing the array from the load list without applying a system loss factor and a temperature/irradiance derate, and sizing the battery in Ah without converting through depth of discharge, inverter efficiency and autonomy days.
Candidates add up appliance wattages, divide by a panel wattage, and stop. Losses (soiling, cabling, inverter, mismatch, temperature) and battery usable capacity are invisible in the arithmetic, and the difference between Ah and Wh is blurred because both appear on battery labels.
What to do instead
Use a fixed, ordered method every time: daily energy in Wh = Σ (watts × hours); divide by 0.75–0.80 for system losses; divide by the site's peak sun hours to get array kWp. For batteries: usable Wh = nominal Wh × DoD × inverter/charge efficiency; then Ah = usable Wh / system voltage. Work through one full numerical case (e.g. 3 kWh/day load, 4.5 peak sun hours, 24 V battery, 50 % DoD, 2 days autonomy) until the sequence is automatic, and always state the assumed loss factor and DoD explicitly in the answer.
Answering tilt and orientation questions with a single national rule ('always face south at 30°') instead of adjusting for latitude, hemisphere, season and the load profile, and confusing magnetic south with true south when reading a compass.
Textbook summaries compress to one rule, and Punjab's latitude (about 30–32° N) happens to make 30° look correct, so the reasoning behind the rule is never learned. Magnetic declination is a small number that candidates do not think applies to a site survey.
What to do instead
Learn the principle, not the number: fixed tilt near latitude for year-round yield, latitude minus 10–15° for summer-heavy loads, latitude plus 10–15° for winter-heavy loads, and true south in the northern hemisphere (north in the southern). Correct compass readings for local magnetic declination before marking a roof. For shading, practise the solar path concept: a December noon sun is much lower than a June noon sun, so inter-row spacing must be calculated for the worst (winter) shadow, using spacing ≈ row height × (cos azimuth factor) with a shadow-angle rule, not the summer case.
Specifying cable cross-section from current-carrying capacity alone, ignoring voltage drop over the run length, and using the same size for the DC string run and the AC output.
Ampacity tables are the visible, memorised part of cable selection; voltage drop is a percentage that feels like a refinement rather than a requirement. Long DC runs from roof to inverter are exactly where drop matters, and candidates forget that DC drop also shifts the operating point away from the MPPT window.
What to do instead
Always run two checks in order: ampacity with derating (ambient temperature, conduit grouping, continuous-load 1.25 factor for the DC circuit), then voltage drop using Vdrop = 2 × L × I × ρ / A for DC (factor 2 because both conductors count) and confirm under about 2–3 % for DC and 3–5 % for AC. Memorise copper resistivity ≈ 0.0175 Ω·mm²/m and practise a 30 m, 10 A, 4 mm² run: drop ≈ 2 × 30 × 10 × 0.0175 / 4 ≈ 2.6 V, which is over 7 % of a 36 V string voltage and therefore unacceptable.
Describing earthing, lightning protection and surge protection as one item, or omitting the separate DC and AC sides, the equipotential bonding of the module frames and mounting structure, and the difference between a lightning air terminal and a surge protective device.
The three systems share the word 'protection' and are taught together, so candidates merge them. The functional earth of the inverter, the DC surge arrester, the AC surge arrester and the external lightning protection system each solve a different problem, and exam questions probe exactly that separation.
What to do instead
Learn a four-part checklist for every installation: (1) equipotential bonding - module frames, rails and structure bonded to earth with the correct conductor; (2) DC side - surge protective device at the combiner/inverter DC input, with DC-rated devices; (3) AC side - surge protective device at the AC distribution board and correct neutral/earth arrangement for the inverter type; (4) external lightning protection - air termination, down conductor and earth termination, kept within the separation distance from the PV array. Be able to state the purpose of each in one sentence, and note that a surge arrester limits overvoltage while a lightning protection system diverts the strike current.
Choosing a PWM charge controller for a system whose array voltage is well above battery voltage, or pairing an MPPT controller without checking its maximum PV input voltage and current, and mismatching battery chemistry with the controller's charging profile.
PWM is cheaper and simpler, so it is chosen by default; candidates do not visualise that a PWM controller effectively clamps the array to battery voltage and wastes the rest. The MPPT input limits are on a datasheet line that is easy to skip, and equalisation/float voltages differ between flooded lead-acid, AGM/gel and lithium, which changes the answer.
What to do instead
Apply a decision rule: PWM only when array Vmp is close to battery voltage (e.g. a 36-cell '12 V' module on a 12 V battery); MPPT whenever the array voltage is higher, and then verify Voc(cold) < controller max PV voltage and array Isc < controller max input current. Learn the three-stage charge profile (bulk, absorption, float) and note that lithium generally needs no equalisation and uses a BMS. Practise choosing the controller for a stated array and battery pair and justify it in one line.
Testing a string with the inverter or load still connected, or measuring Isc with a multimeter on the current range, and reporting a fault as 'no output' without having measured Voc, Isc, insulation resistance and continuity in a defined sequence.
Candidates know the meters but not the safe order of operations, and a multimeter's 10 A fuse looks like it can take a string's short-circuit current. Commissioning is studied as a list of tests rather than a diagnostic logic, so a failed reading leads to guessing instead of the next measurement.
What to do instead
Memorise the commissioning sequence and the instrument for each step: visual and torque check; polarity and continuity with a multimeter (power isolated, lockout/tagout applied); Voc per string and per module with a multimeter on the DC voltage range; Isc with a DC clamp meter around a single conductor, never by breaking the circuit with a multimeter; insulation resistance with an insulation tester at the specified test voltage, with surge arresters and inverter disconnected; then energise and verify against expected values. For fault-finding, use the split-half method: compare string Voc to the sum of module Voc to locate the faulty module, then check its connectors and bypass diode.
Answering safety scenarios by listing PPE generically, without applying lockout/tagout to the DC side, without recognising that a PV array is live whenever it is illuminated, and without distinguishing rescue/first-aid steps for DC shock and for battery acid or thermal runaway.
PPE is the visible, examinable part of safety, so it crowds out procedure. The critical PV-specific fact - that you cannot 'switch off' the sun, so the DC side remains energised - is counter-intuitive to candidates trained on AC isolation, and battery hazards are treated as a disposal topic rather than an emergency-response topic.
What to do instead
Learn three PV-specific rules and apply them to every scenario: (1) DC conductors are live whenever irradiated, so isolate, lock and tag the AC and DC isolators, then verify absence of voltage and, where required, cover the array; (2) never work alone on an energised DC system, and use DC-rated gloves, tools and meters; (3) for a DC shock casualty, isolate before touching, call for help, and begin CPR if unresponsive and not breathing normally. For batteries, learn acid spill neutralisation, eye flush and the fact that lithium thermal runaway needs specific extinguishing media and evacuation. For work at height, name the anchor point, harness and edge protection, not just 'wear a helmet'.