Advanced Boiler (BA) cheat sheet

Thermal efficiency = (heat absorbed by steam) / (heat input from fuel) × 100%. Heat input = fuel mass flow × higher heating value (HHV) or lower heating value (LHV).

Boiler horsepower (BHP) = 33,475 Btu/h = 9.81 kW. One BHP evaporates approximately 34.5 lb of water per hour at 212°F into dry saturated steam at atmospheric pressure.

ASME Boiler and Pressure Vessel Code Section I applies to power boilers >15 psig; Section IV applies to heating boilers ≤15 psig and 250°F. Design calculations use allowable stress from Section II, Part D.

Furnace heat release rate (Btu/ft³·h) and plan area heat release rate (Btu/ft²·h) are key design limits to prevent slagging and tube overheating. Typical pulverized coal furnace heat release: 10,000–20,000 Btu/ft³·h.

Radiant superheater absorbs heat primarily by radiation; convective superheater by convection. Attemperation (desuperheating spray) controls final steam temperature within ±10°F of setpoint.

Drum internals: steam drum separates steam from water via gravity and mechanical separators (cyclones, chevrons). Carryover causes superheater fouling and turbine blade deposits.

Thermal expansion allowances: boiler tubes and headers expand when heated; sliding supports and expansion joints accommodate movement. Cold spring is used to offset thermal expansion in piping.

Water circulation: natural circulation relies on density difference between water in downcomers and steam-water mixture in risers. Circulation ratio = (steam-water mixture mass flow) / (steam mass flow).

Heat transfer equation: Q = U × A × LMTD, where U is overall heat transfer coefficient, A is surface area, LMTD is log mean temperature difference.

Stoichiometric (theoretical) air: minimum air required for complete combustion. Excess air = (actual air − theoretical air) / theoretical air × 100%. Typical excess air: 15–20% for coal, 5–10% for natural gas.

Combustion products: CO₂, H₂O, N₂, O₂, and possibly CO, SO₂, NOx. The air-fuel ratio (AFR) is mass of air per mass of fuel. For methane (CH₄), stoichiometric AFR ≈ 17.2 lb air/lb fuel.

Flame safeguards: flame scanner (UV or IR) must detect flame within 5 seconds (typical) or fuel safety shutoff valves close. Trial for ignition time is limited (e.g., 5–10 seconds for gas).

Furnace explosion prevention: purge furnace with air for at least 5 volume changes before ignition (NFPA 85). Pre-purge airflow typically 25–40% of full load airflow.

Combustion controls: fuel-air ratio control maintains proper mixture; oxygen trim adjusts excess air based on flue gas O₂ analyzer. O₂ setpoint typically 2–4% for gas, 3–6% for oil, 4–8% for coal (dry basis).

NOx control: low-NOx burners, overfire air (OFA), flue gas recirculation (FGR), selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR).

Fuel oil properties: viscosity affects atomization; preheat to achieve 100–150 SSU (Saybolt Universal Seconds) at burner. Flash point is minimum temperature for ignition; safety requires fuel oil flash point > 140°F (No. 2 oil).

Coal characteristics: proximate analysis (moisture, volatile matter, fixed carbon, ash) and ultimate analysis (C, H, O, N, S, ash). Grindability (HGI) affects pulverizer capacity; fineness typically 70–80% through 200 mesh.

Cold startup: purge furnace, establish ignition, warm up slowly (typical heating rate 100–200°F/h for thick-walled components). Drum level maintained at normal water level (NWL) ±2 inches.

Drum level control: three-element control uses steam flow, feedwater flow, and drum level. Single-element control uses drum level only. Low-water trip: typically at −6 inches from NWL; high-water trip: +6 inches.

Boiler trip conditions: low drum level, high drum level, high steam pressure, low air flow, flame failure, high flue gas temperature, high steam temperature, low fuel pressure, loss of forced draft fan.

Shutdown: reduce load gradually, purge furnace after fuel trip, maintain draft, allow cooldown at controlled rate (≤100°F/h for drum). Do not add cold feedwater to hot drum; maintain drum level.

Safety valve testing: test by lifting lever (try lever) at operating pressure; set pressure per ASME Code (typically 1.05–1.10 × design pressure). Accumulation test: safety valve must relieve capacity without exceeding 10% above set pressure.

Boiler water level: normal operating range is ±2 inches from center of gauge glass. Gauge glass blowdown: open drain, then lower and upper valves in sequence to clear connections.

Hot standby: maintain drum level, keep furnace purged, maintain slight positive pressure. For quick restart, keep boiler warm and pressurized.

Load change rate: limit to 5–10% of rated capacity per minute for drum boilers to avoid thermal stress and carryover.

Feedwater treatment: remove hardness (Ca²⁺, Mg²⁺) via softening or demineralization; maintain pH 8.5–10.5 (for carbon steel) to minimize corrosion; oxygen scavenging with sodium sulfite or hydrazine (or DEHA) to <7 ppb O₂.

Boiler water limits: total dissolved solids (TDS) controlled by blowdown; typical maximum TDS 3,500 ppm for drum boilers (varies with design). Silica limit depends on pressure: at 900 psig, <40 ppm SiO₂; at 1500 psig, <10 ppm.

Blowdown: continuous blowdown removes dissolved solids from steam drum; bottom blowdown removes sludge from mud drum. Blowdown rate = (feedwater TDS / boiler water TDS) × 100%.

Carryover: steam contamination by boiler water droplets. Causes: high water level, high TDS, foaming, sudden load changes. Prevention: maintain TDS, use steam separators, avoid rapid load swings.

Deaerator: removes dissolved oxygen by heating feedwater to saturation temperature (typically 5°F below saturation) and venting non-condensable gases. Operating pressure 5–15 psig; oxygen outlet <7 ppb (0.007 ppm).

Steam purity: measured by conductivity or sodium concentration. For turbine steam, sodium <2 ppb, cation conductivity <0.2 µS/cm.

Condensate return: monitor for contamination (hardness, conductivity). Contaminated condensate is dumped to prevent boiler fouling.

Chemical feed: phosphate (for scale control), amine (for pH control in condensate), oxygen scavenger. Avoid overfeeding; maintain residual in boiler water.

Centrifugal pump affinity laws: flow ∝ speed; head ∝ speed²; power ∝ speed³. For fan: flow ∝ speed; pressure ∝ speed²; power ∝ speed³.

Pump cavitation: caused by insufficient NPSH available (NPSHa < NPSHr). NPSHa = (pressure at pump suction + velocity head − vapor pressure) / specific weight. Maintain NPSH margin >3 ft.

Fan types: forced draft (FD) supplies combustion air; induced draft (ID) removes flue gas. Balanced draft maintains furnace pressure slightly negative (−0.1 to −0.5 in. w.c.).

Air preheater: recovers heat from flue gas to preheat combustion air. Types: tubular, regenerative (Ljungström). Improves efficiency by 1% for every 40°F reduction in flue gas temperature.

Economizer: recovers heat from flue gas to preheat feedwater. Bypass required for startup and low-load operation to prevent dew point corrosion.

Instrumentation: pressure transmitters, temperature elements (RTD, thermocouple), flow meters (orifice, venturi, ultrasonic). Calibration ensures accuracy; loop checks verify wiring and response.

Soot blowers: remove ash deposits from tubes. Operated periodically (steam or air). Sequence: start from furnace to economizer to avoid ash carryover.

Pump seals: mechanical seals require clean cooling water. Gland packing requires slight leakage for lubrication (60–80 drops/min).

Burner management system (BMS): per NFPA 85, provides purge, ignition, flame monitoring, and fuel trip. Safety shutoff valves (SSOV) must close within 1 second of trip signal.

Flame detection: UV scanners respond to ultraviolet radiation; IR scanners to infrared. Flame failure response time ≤4 seconds (typical) for main flame; pilot flame ≤5 seconds.

Interlock logic: low drum level trips feedwater and fuel; high drum level trips feedwater; high steam pressure trips fuel; low air flow trips fuel; loss of flame trips fuel.

Fuel trip valves: double block and bleed arrangement for gas fuel; two safety shutoff valves in series with vent valve between. Leak test before light-off.

Purge interlock: purge must be proven (air flow >25% of full load for 5 minutes) before ignition. If purge fails, no ignition.

Control loops: PID (proportional-integral-derivative) tuning. Proportional band, integral time, derivative time. Cascade control for drum level (steam flow to feedwater).

Safety instrumented system (SIS): independent from basic process control system (BPCS). SIL (Safety Integrity Level) rating based on risk assessment. Typical SIL 2 for boiler trips.

Alarm and trip setpoints: high steam pressure alarm at 90% of set pressure, trip at 95–100%. High steam temperature alarm at 1000°F, trip at 1050°F (typical for superheater).

ASME Code inspections: internal inspection required every 12 months for power boilers (varies by jurisdiction). External inspection annually. Hydrostatic test at 1.5 × design pressure (ASME Section I).

Non-destructive examination (NDE): visual, liquid penetrant (PT), magnetic particle (MT), ultrasonic (UT), radiographic (RT). UT measures wall thickness; RT detects internal defects.

Tube inspection: check for scaling, corrosion, erosion, cracking. Use borescope, ultrasonic thickness gauge. Replace tubes with wall thickness < minimum required by calculation.

Safety valve testing: bench test or online test. Set pressure verification, seat tightness, pop test. Test frequency: annually or per jurisdiction.

Boiler efficiency testing: ASME PTC 4 (performance test code). Use flue gas analysis (O₂, CO, temperature) to calculate losses. Typical efficiency: 80–85% (LHV basis) for older boilers, up to 90% for modern.

Preventive maintenance: lubricate bearings, check alignment, inspect refractory, clean burners, calibrate instruments, test interlocks, inspect safety valves.

Hydrostatic test: fill with water (treated), pressurize to 1.5 × MAWP, hold for 10 minutes, inspect for leaks. Do not exceed 1.5 × MAWP.

Record keeping: maintain inspection records, repair history, operating logs. Required by code and insurance.

ASME Boiler and Pressure Vessel Code (BPVC): Section I (power boilers), Section II (materials), Section IV (heating boilers), Section V (NDE), Section VII (recommended guidelines for care), Section VIII (pressure vessels), Section IX (welding).

NFPA 85: Boiler and Combustion Systems Hazards Code. Covers fuel systems, BMS, purging, ignition, flame monitoring, interlock systems.

OSHA 29 CFR 1910.261: safety requirements for boiler operation. Requires training, PPE, lockout/tagout, confined space entry.

EPA regulations: Clean Air Act (CAA), New Source Performance Standards (NSPS) for boilers (40 CFR Part 60), National Emission Standards for Hazardous Air Pollutants (NESHAP) for industrial boilers (40 CFR Part 63).

Jurisdictional inspections: state or local boiler inspection required for operation. Certificate of inspection must be posted. Operating permit may require emission limits and monitoring.

ASME PTC 4: performance test code for steam generators. ASME PTC 19.1: test uncertainty. ASME PTC 46: overall plant performance.

Welding qualifications: ASME Section IX covers procedure qualification (WPS/PQR) and performance qualification (welder). Welding symbols per AWS A2.4.

Pressure relief: ASME Section I requires safety valves sized per capacity. Set pressure not exceeding MAWP. Accumulation ≤10% of MAWP.

Emergency shutdown: trip fuel, maintain draft, purge furnace, do not feed cold water to hot boiler. Evacuate if major leak or explosion risk.

Low-water condition: if drum level not visible in gauge glass, secure fuel immediately. Do not add water until boiler cooled to prevent sudden steam generation and explosion.

Steam leak: isolate, barricade area, wear PPE. High-pressure steam is invisible; use acoustic or thermal detection.

Confined space entry: boiler interior requires permit, atmospheric testing (O₂ 19.5–23.5%, LEL <10%, H₂S <10 ppm), ventilation, attendant, rescue plan.

Lockout/tagout (LOTO): isolate all energy sources (fuel, steam, water, electrical) before maintenance. Verify zero energy state.

Environmental protection: control emissions (NOx, SO₂, particulate, CO, Hg). Use scrubbers, SCR, baghouses, electrostatic precipitators. Monitor and report per permit.

Spill prevention: fuel oil storage requires secondary containment, spill kits, and SPCC plan (EPA).

Personal protective equipment (PPE): safety glasses, face shield, heat-resistant gloves, hearing protection, steel-toe boots, hard hat. For boiler entry, use respirator if needed.