Power Plant Systems Notes (Fuel, Water, and Emissions)
Fuel Oils: essential concepts
Fuel oils: lighter oils for diesel engines/turbines; heavier oils heated for boilers. Derived from crude oil; residua after distillation/cracking. Distillation separates into distillates; cracking increases light hydrocarbons yields.
Key properties to know: specific gravity, heating value, viscosity, flash point, fire point, pour point, sulfur content. API gravity relates to specific gravity as:
Heating value (kJ/kg) relates to SG; for a representative formula used in the course:
Grade range (ASTM fuel oils No. 1–No. 6): No. 1 and 2 are distillates; No. 4–6 are heavier distillate/residual blends. Sulfur content generally increases from No. 1 to No. 6 (approx. 0.01%–3.5%).
Viscosity is temperature dependent; standard viscometers include Saybolt (Universal/Furol), Saybolt at specified temp; specify both scale and temperature when reporting viscosity.
Impurities: water/sediment (non-economical to remove completely; keep impurities low, e.g., <2%), ash (abrasive), and sulphur influence corrosion and SOx emissions.
Fuel Oil Supply Systems: design and operation ( sketch-based )
Storage tanks: carbon steel, vented to atmosphere; flame arrestor on vent; steam smothering line to blanket tank; dual-suction pumps (low suction for normal use; high suction for sludge/water removal).
Sludge management: water/sludge can settle; switch pumps to high suction when water/sludge reach suction; return to low suction after cleanup.
Suction strainers (duplex): two filters; one in service, one standby; switch without pressure loss; differential filter switch at ~10–15 kPa.
Fuel oil pumps: usually positive-displacement gear/rotary screw pumps; include discharge pressure relief valves back to storage tank; a downstream PSV prevents downstream overpressure; two pumps: electric for start-up, steam-driven for in-service operation; provide required burner pressure: mechanical atomization needs ~345–1725 kPa; steam atomization needs ~15–860 kPa.
Oil heaters: shell-and-tube exchangers; heat oil to ~85–104°C depending on atomization method; heaters and pumps may be separate or skid-mounted.
Oil handling and discharge strainers: duplex suction strainers and duplex discharge strainers; mesh sizes depend on fuel oil grade (e.g., 100-mesh for No. 2; 10-mesh for No. 6).
Automatic regulation: automatic control valves regulate oil to burners; proportional to combustion air for stable firing; excess oil returned via constant-flow-cycle valve when pumps deliver more than required.
Burners: can be dual-fuel (oil/gas); oil gun/atomizer; gas header with inner/outer spuds; pilot lighter for any fuel; steam or mechanical atomization differences drive heater temp targets: steam-atomized oil ~104°C; mechanical ~85–104°C depending on system.
Steam-atomizing burner: steam flows through center in oil gun to atomize; nozzle tip photo shown; the steam path surrounds the fuel path.
Safety/controls: discharge regulators, flow proportioning between burners; open/close valves to individual burners via remote shut-off stations.
Fuel Gas Supply Systems: design and operation ( sketch-based )
Gas composition: methane is main combustible; natural gas may contain H2S (sour gas) and mercaptans; sweetening removes H2S/CO2/mercaptans; water content in gas is normalized; odorants added for safety.
Transmission/conditioning: remove water, liquids, H2S; remove dirt; add odorant; ensure gas reaches customer nearly pure fuel.
Plant entry and pressure reduction: plant inlet valve; downstream twin pressure reducing stations reduce to plant design pressure (e.g., from ~700 kPa to ~280 kPa). A downstream shut-off isolates the regulator in case of major leaks.
Pilot and main burner lines: pilot off-take reduces 280 kPa to ~20 kPa for pilots; remote shut-off for pilots arranged with two shut-off valves and vent valve; main burner control valve varies gas flow from ~7–70 kPa depending on boiler load.
Piping considerations: slope ~2.5 cm per 15 m; drip legs; expansion bends; branch connections on top/sides; external shutoffs near buildings; lockable valves above 35 kPa; ensure valves accessible for emergency.
Safety interlocks: manual shut-offs; automatic shut-off stations; pilot take-off; burner control valve; furnace venting.
Solid Fuels: design and operation ( sketch-based )
Types: coal (several grades), biomass (wood, bark, chips, sawdust), refuse-derived fuel (RDF), waste incineration with heat recovery.
Biomass specifics: lower NOx/SO2 emissions than fossil fuels; grating systems for feeding biomass: travelling gratings, pinhole furnaces, vibrating grate systems; fluidized bed biomass boiler shown; two- to multi-fuel feeders.
Coal properties: carbon, hydrogen, oxygen, sulfur, nitrogen, moisture, ash; coal is categorized by fixed carbon/volatile matter content and heating value (Anthracite, Semi-anthracite, Bituminous, Sub-bituminous, Lignite).
Pulverized fuel systems: coal is pulverized to fine powder for burners; coal is transported from storage via unloaders to breakers, conveyors, weigh belts, and into bunkers; coal feeders feed pulverizers; pulverizers include ball-race mills and ring-roll (bowl) mills; air supplies the pulverized coal to burners; classifiers control fineness (80% through 200 mesh, 95–99% through 50 mesh is common).
Ash handling: two ash streams – bottom ash (coarse) and flyash (fine). Bottom ash collected in hoppers; fly ash removed by baghouse or electrostatic precipitator (ESP). Wet bottom ash systems use water quenching; dry bottom ash uses mechanical handling.
Dust collection: baghouses (fabric filters) provide high efficiency; cleaning methods include reverse air, shaker, and pulse-jet; bag life 3–5 years; moisture/acid dewpoint considerations.
Electrostatic precipitators (ESP): charged discharge electrodes; plates collect flyash; high voltage DC (30–75 kV); periodic rapping to loosen ash; back corona and resistivity issues addressed by design; maintenance of hoppers and ash conveying.
Coal and Fuel Handling Components (core flow)
Coal storage → unloading (ships/trains) → reclaiming → breakers (to reduce lump size) → magnetic separators to remove tramp metal → belt weighing → bunkers/hoppers → coal feeders → pulverizers → burners.
Pulverizers: types include tube mills, ball-and-race mills, impact mills, hammer mills, bowl mills; primary air for drying/transport; classifiers to meet fineness; sometimes supported by external exhauster or forced-draft fans.
Flow control: feeders (gravimetric or volumetric); belt feeders or overshot roll feeders; load control linked to boiler demand.
Power Plant Water and Steam Systems: design and operation (sketch-based)
Overall water cycle: makeup water → feedwater heating → boiler economizer/steam drum → steam distribution to process heaters/turbines → condensate return to deaerator; condensate polishing for high-purity feedwater.
Feedwater systems:
Condensate is purified makeup water; preheated in multiple stages: LP heaters, HP heaters; deaerator removes O2/CO2; open (deaerator) heater is common; HP heaters are downstream of boiler feedwater pumps.
Boiler cycles: utility plant with six or eight stages of feedwater heating; bleed steam heats feedwater; condensate drains cascade through heaters; deaerator storage serves as suction for feedwater pump.
Closed feedwater heaters: U-tube design; shell-side heated by low-pressure steam; bypass valve to protect shell in leaks; trip gear to avoid overpressure.
Steam distribution: high-pressure superheated steam from boiler to topping turbine; process heating and utility steam use; pressure reductions via stations; steam traps and condensate return; LP/MP/HP headers; return condensate to deaerator.
Condensate systems: condensate return tank; flash losses; amines added to control pH; condensate polishing to recover as feedwater.
Cooling water systems:
Open circulating (wet) system: cooling water from tower to heat exchangers, then back to tower; two cooling modes: evaporative cooling and air contact; typical outlet temps ~40–45°C; inlet ~20°C.
Closed recirculating system: chiller or cooling tower alternative; reduced makeup and blowdown; lower chemical load when closed.
Makeup water quality and blowdown: conductivity control to maintain cycle concentration; softened makeup reduces blowdown.
Wastewater handling: plant wastewater flows to treatment (oil/water separation tank, primary sludge), stabilization lagoon with aeration, activated sludge, clarifier, polishing tank; discharge with QA parameters (pH 6.5–8.5; BOD/COD; temperature; suspended solids).
Measurement, Control & Instrumentation (highlights)
Pressure measurement: transducers (electrical/ electronic) convert mechanical pressure (Bourdon, diaphragm, bellows) to electrical signal; transducers include voltage divider, variable resistance, inductance, reluctance (magnetic pickup), capacitance, strain gauges, and piezoelectric transducers. Commonly used in boiler control loops.
Temperature measurement: RTD (platinum, nickel, copper; 3- or 4-wire), thermocouples (types B,E,J,K,R,S,T), thermistors; radiation pyrometers for non-contact temp; thermowell protection; RTD three-wire/ four-wire compensation.
Level measurement devices: ball-float, displacement-type, hydrostatic head, capacitance, multi-probe conductivity columns, nucleonic gauges, ultrasonic, remote water-level indicators; open/closed-loop level control in deaerator, boiler drums.
Flow measurement: differential-pressure meters (Venturi, orifice plate, flow nozzle, Dall tube, Gentile flow tube, Pitot tubes); Q = A v relationships; need straight-pipe runs; importance of proper tapping locations to avoid disturbances.
Liquid level and flow-indicating devices: manometers (U-tube, mercury-filled, bell-type, spring-balanced), square-root vs linear scale (square-root compensation for DP meters); ring balance; force balance transmitters; electric flow indication (electro-mechanical and mag meters).
Valve actuation options: solenoid, pneumatic-diaphragm, power cylinder, electric motor; positioners to provide high-gain control; open-loop vs closed-loop control of final control elements.
Automatic Control Theory for Boilers (summary)
On/Off (two-position): simple, uses cut-in/cut-out pressure setpoints; poor for stable control; used where load changes are small.
Proportional (P) control: output proportional to error; reduces offset but cannot eliminate it; risk of oscillation if gain is too high.
Proportional-Integral (P+I) control: adds integral (reset) action to eliminate offset; improves steady-state accuracy.
Proportional-Integral-Derivative (P+I+D): adds derivative (rate) action to improve transient response.
Single-element vs multi-element feedwater control:
Single-element: drum level control only; adequate for small boilers with limited load changes.
Two-element: adds steam flow as a feedforward signal to anticipate drum level changes (reduces swell/shrinkage).
Three-element: adds feedwater flow measurement; maintains best drum level under wide loading by comparing steam and feedwater flow plus drum level.
Turbine-following vs boiler-following vs integrated control: coordination between boiler firing and turbine load with megawatt signals; integrated control provides flexible performance.
Distributed Control Systems (DCS): centralized computer-based control with operator interfaces, alarms, and data history; network protocols (Fieldbus, HART, Ethernet/TCP-IP); advantages include better trend analysis, alarm management, and remote operation; disadvantages include vendor lock-in and higher cost; modern systems use glass displays and historian data.
Programmable Logic Controllers (PLC): modular, field-programmable control with I/O racks; simple logic with timers and counters; PLCs used for sequencing startups and safety interlocks.
Combustion, Emissions & Environmental Control (brief)
Combustion chemistry: complete vs incomplete combustion; formation of CO2, CO, H2O, SO2, NOx; elemental balances (C, H, O, S) govern emissions and energy yield.
NOx control: multiple approaches—flue-gas recirculation (FGR/IFGR), air staging, fuel staging, burner out-of-service (BOOS), low-NOx burners, and, where appropriate, SNCR/SCR (catalytic/ non-catalytic reduction of NOx).
Flue Gas Desulfurization (FGD): wet scrubbers (lime/limestone slurries) and dry/wet combinations to remove SO2; gypsum byproduct; lime/lime-slurry regeneration considerations; acid dew point management; corrosion control.
SCR: catalytic reduction of NOx using ammonia, NOx converted to N2 and H2O; concerns: ammonia slip, catalyst life, space requirements; alternatives include SNCR (ammonia/urea without catalyst).
Mercury control & other pollutants: measurement and control as part of CEMS; use of baghouses and ESPs for particulates; chemical conditioning of flue gas to improve collection efficiency; ozone/or other methods for NOx and CO2 reductions where applicable.
Water, Wastewater & Environmental Monitoring (highlights)
Wastewater treatment in plants: oil/water separation, primary/secondary treatment, aeration, clarifier, polishing, disinfection (chlorine/chlorine dioxide) before reuse or release.
Cooling water chemistry: corrosion inhibitors, scale inhibitors, anti-foaming agents; blowdown to control conductivity; makeup water quality; water treatment strategies for open and closed systems.
CEMS: Continuous Emission Monitoring Systems for stack emissions; components: sampling system, gas analyzers, data acquisition; extractive vs in-situ analyzers; data handling and QA requirements; monitoring of opacity (PM) and various gas species (SO2, NOx, Hg, O2, CO2, hydrocarbons).
Environmental data usage: real-time adjustments, trend analysis, regulatory reporting, and QA; uptime/availability targets (often 90–95% monthly) and backfill data strategies if data is invalid.
Fuels and combustion planning to minimize emissions: selection of fuels, ash fusion temperature management, and slag control to avoid deposition on heat transfer surfaces.
Quick reference equations and concepts
API gravity relation to SG:
Fuel oil heating value (example from course):
Air for combustion (typical coal example):
Theoretical air for complete combustion is composition dependent (typical coal ~9.2 kg air per kg coal).
Gas to plant entry pressure and reduction: gas entry ~700 kPa; downstream regulators to ~280 kPa; pilot gas to ~20 kPa.
Basic differential pressure flow principle: flow meter output is proportional to sqrt of differential pressure (for DP meters).
Open vs closed cooling water: open uses evaporation; closed uses chillers; blowdown concentrates dissolved solids.
Exam-ready tips
Be able to sketch fuel oil, fuel gas, and solid fuel supply systems and label major components (tanks, strainers, pumps, heaters, burners).
Memorize grade ranges and key properties: viscosity ranges, flash points, sulfur content, and typical heating values.
Understand boiler feedwater heating sequence (LP/HP heaters, deaerator, economizer) and the role of bleed steam.
Distinguish open vs closed cooling systems; know why condensate polishing matters for high-pressure feedwater.
Recognize major control strategies: On/Off, P, PI, PID; single/2/3-element feedwater control; turbine-following, boiler-following, integrated control.
Know primary NOx and SO2 control methods (FGR, staging, SCR/SNCR, FGD, dry scrubbers) and the concept of ammonia slip.
Understand basic waste management: bottom vs fly ash, baghouses vs ESPs, and why cleaning cycles matter.
Be able to identify key instrumentation types and where they’re used (pressure, temperature, flow, level, and corresponding transducers).
Know the purpose and basic arrangement of a Packaged Boiler Control System startup sequence (purge, pilot, main flame proving, firing rate control).
If you’d like, I can tailor a condensed one-page reference card with only the most essential bullets and a couple of mini-sketch prompts for quick recall.