NIULPE Class 1 cheat sheet

ASME Section I governs power boilers over 15 psig; Section IV governs heating boilers at or below 15 psig and 250 °F water service.

Maximum allowable working pressure uses t = PD/(2SE + 2yP) + corrosion allowance for drum shells, where S is allowable stress from Section II Part D at design temperature.

SA-516 Grade 70 carbon steel plate is the standard drum and shell material; SA-106 Grade B seamless pipe is standard for headers and tubes.

Longitudinal welded seams require full radiography or joint efficiency E of 1.0 only when radiography is performed; non-radiographed seams use E as low as 0.70.

Postweld heat treatment is required for carbon steel welds over 1.5 in thick and for all joints in certain alloy steels to relieve residual stress.

Safety valve capacity must equal or exceed the maximum evaporating capacity of the boiler; the set pressure plus accumulation must not exceed MAWP by more than 10 percent.

Staybolts carry load in firebox and flat-plate construction; maximum staybolt spacing is governed by plate thickness and pressure per Section I rules.

Hydrostatic test pressure is 1.5 times MAWP; the test verifies tightness and strength but does not substitute for the required pressure-relief capacity.

Theoretical (stoichiometric) air for natural gas is about 10 ft³ air per ft³ gas; for fuel oil it is about 3,200 lb air per 100 gal of No. 6 oil.

Excess air targets: 3–5 percent O2 for gas firing, 3–6 percent for oil, higher for coal; stack O2 above target signals excess air and heat loss.

Flame failure response time must not exceed 4 seconds for burners over 400,000 Btu/hr; pilot and main flame are proven by flame scanners.

Pre-purge must equal at least 4 volume changes of the furnace and passes, or the manufacturer's requirement, before light-off.

Low-water fuel cutoff must be tested by slow drain (evaporation test) to confirm the burner trips before the water level leaves the gauge glass.

Combustion efficiency rises as stack temperature falls; each 40 °F reduction in stack temperature raises efficiency roughly 1 percent.

Furnace draft on a balanced-draft unit is held slightly negative (about −0.05 to −0.10 in. w.c.) at the furnace outlet to prevent leakage and flame impingement.

Feedwater pumps must deliver at least 1.15 times the boiler's maximum evaporating capacity; two feed sources are required for units above 100,000 lb/hr.

Deaerator reduces dissolved oxygen to about 0.005 cm³/L (7 ppb) and heats feedwater to within 2–3 °F of saturation to limit oxygen pitting.

Boiler feedwater regulator holds drum level within the gauge glass; a three-element control uses steam flow, feedwater flow, and drum level.

Economizer recovers heat from flue gas to preheat feedwater; bypass and safety valves protect it from overheating on low feedwater flow.

Air preheater raises combustion air temperature and improves efficiency; soot blowers and dew-point control prevent cold-end corrosion.

Steam header and piping must be supported and drained; expansion loops and anchors accommodate thermal growth of about 0.8 in. per 100 ft per 100 °F.

Forced-draft and induced-draft fans must be interlocked so ID fan starts before FD fan and FD stops before ID fan to prevent furnace pressurization.

Rankine cycle efficiency = (h1 − h2) − (h4 − h3) divided by (h1 − h4), where h1 is throttle enthalpy and h2 is exhaust enthalpy.

Turbine heat rate (Btu/kWh) = 3,413 divided by cycle thermal efficiency; lower heat rate means better plant performance.

Impulse stages drop pressure across stationary nozzles; reaction stages drop pressure across both fixed and moving blades, with 50 percent reaction typical.

Overspeed trip must operate at 110 percent of rated speed; governor and trip mechanisms are tested before every start.

Steam turbine gland seals and vacuum systems maintain condenser pressure near 1–2 in. Hg absolute; air in-leakage raises back pressure and reduces output.

Generator output in kW = (voltage × current × power factor × √3) / 1000 for three-phase machines.

Synchronous speed = 120 × frequency / number of poles; a 4-pole generator at 60 Hz runs at 1,800 rpm.

First Law: Q − W = ΔU for a closed system; steady-flow: q − w = Δh + Δke + Δpe.

Sensible heat Q = m·cp·ΔT; latent heat of vaporization of water at atmospheric pressure is 970 Btu/lb.

Steam table saturation temperature at 100 psig is about 338 °F; superheat adds enthalpy above the saturation value at the same pressure.

Overall heat transfer coefficient U combines conduction and convection resistances: 1/U = 1/hi + t/k + 1/ho, with fouling factors added.

Conduction: Q = kAΔT/L (Fourier); radiation: Q = εσA(T1⁴ − T2⁴) (Stefan-Boltzmann).

Thermal efficiency of a boiler = (steam enthalpy gain × steam flow) / (fuel input × higher heating value) × 100.

Stress σ = F/A; thermal expansion ΔL = αLΔT; combined stresses in tubes include pressure hoop stress plus thermal gradient stress.

Three-phase power P = √3 × V × I × power factor; kW = kVA × power factor.

Motor full-load current rises with load; overload heaters are sized to motor nameplate current, and locked-rotor current is 5–7 times FLA.

Programmable logic controller scan cycle consists of input update, program execution, and output update; scan time affects response of burner management systems.

4–20 mA current loop uses 4 mA as live zero; a signal below 3.6 mA typically indicates an open circuit or failed transmitter.

Flame scanners detect ultraviolet or infrared radiation; UV scanners must be checked for tube fouling and sighting alignment.

Grounding and ground-fault protection are required on service equipment; a ground fault on a 480 V system trips the main or feeder protective device.

Safety instrumented functions for burner management must be independent of process control and fail safe on loss of power.

Scale forms when calcium and magnesium salts exceed solubility; softening and internal treatment keep hardness near zero in boiler feedwater.

Oxygen pitting is prevented by mechanical deaeration plus chemical scavengers such as sodium sulfite or hydrazine.

Caustic embrittlement (stress corrosion cracking) is controlled by maintaining boiler water pH near 10.5–11.5 and limiting caustic concentration.

Carryover and foaming are reduced by maintaining dissolved solids below the recommended limit and by blowdown control.

Conductivity is used to estimate dissolved solids; blowdown rate increases as conductivity approaches the control limit.

Condensate return corrosion is often caused by carbonic acid from CO2; neutralizing amines or filming amines protect the system.

pH below 8.5 accelerates corrosion of carbon steel; pH above 12.5 attacks copper alloys and promotes caustic cracking.

ASME Boiler and Pressure Vessel Code Section I covers power boilers; Section VIII covers unfired pressure vessels; Section IX covers welding qualifications.

National Board Inspection Code governs repairs, alterations, and inspection of in-service boilers; repairs require an authorized inspector's approval.

OSHA 29 CFR 1910.261 and 1910.263 address boiler and machinery safety in general industry; lockout/tagout falls under 1910.147.

Safety valve testing and setting are documented; valves are sealed and the seal broken only by authorized personnel.

Jurisdictional inspections are typically annual for power boilers; certificates of inspection are posted and records retained.

Confined-space entry requires atmospheric testing, attendant, and permit; boiler drums and furnaces are permit-required confined spaces.

The boiler operator must know emergency shutdown: cut fuel, stop combustion air, and maintain feedwater to protect tubes from overheating.

Preventive maintenance schedules follow manufacturer intervals; vibration analysis and oil analysis predict rotating equipment failure.

A work order system tracks labor, parts, and downtime; backlog and mean time between failures measure maintenance effectiveness.

Operator logs record drum level, steam pressure, stack temperature, and water chemistry at defined intervals for trend analysis.

Training and qualification records demonstrate operator competency and support regulatory compliance during inspections.

Root-cause analysis (5 Whys, fishbone) addresses repeat failures; corrective actions are tracked to closure.

Budgeting separates fixed costs (labor, insurance) from variable costs (fuel, chemicals, water) to support cost control decisions.

Shift turnover communication transfers abnormal conditions, open work orders, and safety concerns between crews.

NOx control methods include low-NOx burners, flue gas recirculation, overfire air, and selective catalytic reduction (SCR).

SCR uses ammonia or urea injection over a catalyst at about 600–750 °F to reduce NOx to nitrogen and water.

Sulfur dioxide is controlled by flue gas desulfurization (wet scrubbers) or by burning low-sulfur fuel.

Particulate matter is captured by baghouses, electrostatic precipitators, or mechanical collectors; opacity monitors track compliance.

Continuous emission monitoring systems (CEMS) measure NOx, SO2, CO, O2, and opacity and must be quality-assured per 40 CFR Part 60/75.

Combustion tuning lowers CO and unburned carbon while keeping excess air low enough to limit NOx formation.

Stack testing and recordkeeping demonstrate compliance with permit limits; exceedances trigger reporting requirements.