Boiler Control Notes

Instrument Technician - Boiler Control 310401f

Objective One: Boilers

A boiler is a closed vessel that heats water, generates steam, or superheats steam by applying heat from combustible fuels in a self-contained furnace. In water tube boilers, combustion gases surround the tubing, and the tubes contain water.

Boiler Components and Functions (Table 1)

Windbox: Receptacle for mixing fuel and air for combustion.
Downcomer: Metal tubes circulating boiler water down to the mud drum, not directly exposed to combustion gases.
Riser: Metal tubes circulating boiler water and steam bubbles up to the steam drum, directly exposed to hot combustion gases.
Steam Drum: Large metal cylinder at the top of the boiler, providing space for steam separation and water storage.
Mud Drum: Large metal cylinder at the bottom, equalizing water distribution and collecting loose scale deposits.
Superheater: Heat exchanger that heats saturated steam to superheated steam by exposing it to hot combustion gases.
Economizer: Heat exchanger that heats boiler feedwater by exposing it to hot combustion gases as they leave the furnace.
Induced Draft Fan: Fan drawing flue gases from the furnace and driving them up the stack.
Forced Draft Fan: Fan providing combustion air from outside to the windbox.
Attemperator/Desuperheater: Device injecting boiler feedwater into superheated steam to control its temperature.
Air Preheater: Heat exchanger transferring waste heat from flue gases to incoming combustion air to increase efficiency.
Flue Gas: Gaseous product of combustion.
Stack: Structure discharging flue gases to the atmosphere.
Furnace: Enclosed space where combustion takes place.
Steam Consumption: Amount of steam used for process heating, power generation, mechanical drive, component separation, or as a water source for process reactions.
Condensate Recovery: System collecting condensed steam and returning it to the boiler for reuse.
Water Treatment: Ensures the feedwater meets the boiler manufacturer's standards.

Boiler Control Points (Figure 2)

Four main control points:

Steam Pressure (PC-1)
Steam Temperature (TC-1)
Steam Drum Level (LC-1)
Furnace Pressure (PC-2)

The primary purpose of boiler control is to manipulate the firing rate (fuel combustion rate) to balance steam supply with steam demand.

Steam pressure controller output dictates the firing rate demand by controlling fuel flow and forced draft fan speed.
Steam drum level control maintains the boiler's steam mass balance by manipulating boiler feedwater (BFW) flow.
Induced draft fan speed controls furnace pressure.
BFW flow into superheated steam controls steam temperature.

Boiler controls have evolved from mechanical to analog to digital, introducing terms like "plant master" and "boiler master".

Plant Master

The plant master is the steam header pressure controller, setting the master firing rate demand. It's applicable when multiple boilers supply a common plant steam header (Figure 3).

In a single boiler plant, the plant master manipulates combustion controls to maintain constant boiler steam pressure.
In a multi-boiler plant, the plant master manipulates combustion controls of all boilers to maintain constant pressure in the plant steam header.

Boiler Master

The boiler master is an auto/manual transfer station with biasing. Its input is the master firing rate demand signal, and its output is the firing rate demand for the specific boiler it controls (Figure 4).

In manual mode, the boiler master allows adjusting the boiler's firing rate to a specific percentage.
In automatic mode, the boiler master allows biasing the master firing rate demand by adding or subtracting a percentage.

Boiler masters facilitate load distribution among boilers, allowing options like:

Shutting down boilers (manual mode with zero output).
Base loading boilers (manual mode with a constant output).
Allowing remaining boilers to adjust firing based on master firing rate demand (automatic mode with bias).

Scientific Apparatus Makers Association (SAMA) Diagrams

SAMA diagrams provide functional control diagrams for boilers, conveying the logic behind boiler control strategies (Figure 5).

Enclosure Symbols: Represent elements or functions (measuring, logic, processing, final controlling).
Signal Processing Symbols: Tie together enclosure symbols (continuously variable signal, incremental change signal, on-off signal) (Figure 6).
Processed Signal Symbols: Describe functions within each enclosure (summing, averaging, logical operations, proportional, integral, derivative, limiting, etc.) (Table 2).

SAMA symbols offer more detailed functional information than ISA symbols, which are more instrument-specific (Figure 7).

ISA diagrams indicate instrument types, mounting, and signal types.
SAMA diagrams detail control logic, algorithms, and operator adjustments.

SAMA symbols allow variations in drawing style (Figure 8) and can represent detailed operations like bumpless transfer (Figure 9).

Objective Two: Boiler Control Strategies

Boiler control strategies ensure the safe and efficient operation of single or multiple boilers. A multiple boiler system has five main control points:

Firing Rate Demand Control
Boiler Combustion Control
Furnace Draft Control
Boiler Feedwater Control
Steam Temperature Control

Firing Rate Demand Control

Firing rate demand sets the fuel combustion rate, which in turn sets the steam production rate. It's determined from an energy balance. The Plant master controls the steam header pressure with its output the master firing rate demand.

Small boilers use on/off or high/low/off control systems based on temperature or pressure switches.
Large boiler systems use a pressure controller with PI feedback control. Feedforward control and boiler master controls are added for improved performance and multiple boilers.

Steam Pressure Feedback Control (Figure 10)

Pressure transmitter (PT) measures steam header pressure.
PI controller (plant master) compares PV with adjusted SP and computes a firing rate demand signal.
In a single boiler system, the firing rate demand signal manipulates the combustion control system.

Steam Pressure Feedforward Control (Figure 11)

Pressure transmitter measures steam header pressure.
PI controller (plant master) compares PV with adjusted SP to compute its output.
Total steam flow is calculated and fed to a multiplier.
The multiplier's gain is calculated so that a change in the steam flow produces the necessary feedforward steady-state change in the firing rate demand.
The bias summer adds the feedforward signal with the PI controllers feedback signal and biases it so that the feedforward adds nothing at normal load conditions.

This links the firing rate demand with steam flow and improves performance to steam load changes.

Steam Pressure Manual Boiler Masters (Figure 12)

Feedforward-feedback control strategy calculates the master firing rate demand signal.
The master firing rate demand signal goes to the boiler masters.
The boiler master's bias summer adds or subtracts the operator adjusted bias from the master firing rate demand to calculate its specific firing rate demand.

Allows operators to manually select higher firing rates from more efficient boilers.

Boiler Combustion Control

Combustion control strategies maintain the required air-to-fuel ratio for optimal efficiency and safety.

Single-Point Positioning Control (Jackshaft Control) (Figure 13): Fuel and air flows are mechanically linked and not measured. The air-to-fuel ratio is mechanically set.
Parallel Positioning Control (Figure 14): Fuel and air flows are not measured. The firing rate demand signal goes in parallel to both the fuel control valve and the air damper.
Parallel Metered Control (Figure 15): Fuel and air flows are measured, and the firing rate demand signal goes in parallel to both the fuel controller and the air controller.

Parallel Metered Cross-Limited Combustion Control (Figure 16)

Includes active safety constraints to maintain safe fuel/air mixtures or minimum air flow requirements.

Air flow characterization and fuel/air ratio adjustment fine-tune the fuel-to-air ratio.
Cross-limiting ensures an air-rich mixture is always maintained on load or steam pressure SP changes.

Excess Air

Too little excess air results in carbon monoxide formation, sooting. Too much excess air reduces boiler efficiency because the extra nitrogen and oxygen not consumed absorbs otherwise useable heat and are carried away in the form of stack loss.

Optimal Oxygen Levels (Figures 17, 18, 19)

Optimal % of oxygen depends on boiler load.
Best efficiency is achieved with approximately 2% oxygen in flue gas at full load or 150 ppm CO.

Furnace Draft Control

Furnace draft control manages the pressure differential between gases inside and outside the furnace.

Natural Draft Furnace: Uses the stack effect, operating below atmospheric pressure.
Induced Draft Furnace: Uses an induced draft fan, operating slightly below atmospheric pressure.
Forced Draft Furnace: Uses a forced draft fan, operating slightly above atmospheric pressure.
Balanced Draft Furnace: Uses both forced and induced draft fans, operating at slightly negative pressures to prevent flue gas leakage (Figure 20).

Balanced Draft Control Strategy (Figure 21)

Forced draft fan is manipulated by the firing rate demand.
Induced draft fan is manipulated by the furnace pressure controller.
Feedforward minimizes pressure disturbances.

Boiler Feedwater Control

Manipulating boiler feedwater (BFW) flow into the drum controls the steam drum level.

Maintaining constant drum level is critical for plant protection and equipment safety.

Drum Level Pressure Compensation (Figures 22, 23, 24)

Accounts for density changes that can affect drum level measurement.
$\Delta P = [P<em>0 + \rho</em>s g (X - H) + \rho<em>w g H] - [P</em>0 + \rho_o g X]$

Pressure compensation is important for boilers operating at varying pressures.
Median select systems enhance transmitter signal reliability.

Drum Level Inverse Transient Response (Figure 25)

Shrink and swell complicate steam drum level control.

Swell: Increased steam demand causes pressure drop, forming more vapor bubbles and increasing drum level.
Shrink: Decreased steam demand causes pressure increase, collapsing vapor bubbles and decreasing drum level.

Boiler Feedwater Pressure Changes

Linear operation of the boiler feedwater (BFW) valve only occurs at one set of operating conditions.

Single-Element Boiler Feedwater Control (Figures 26, 27)

Uses feedback level control based on drum level measurement only. Does not compensate for shrink/swell or pressure fluctuations.

Two-Element Boiler Feedwater Control (Figures 28, 29)

Uses feedback level control with feedforward on steam flow to minimize shrink/swell effects. Still does not compensate for pressure fluctuations.

Three-Element Boiler Feedwater Control (Figure 30)

Measures drum level, steam flow, and feedwater flow. Uses feedback level control with feedforward on steam flow and cascade on boiler feedwater to minimize flow changes due to drum pressure fluctuations.

Steam Temperature Control (Figure 31)

Maintains constant steam temperature at all boiler loads, typically using an attemperator to spray boiler feedwater into the steam.

Objective Three: Boiler Safety

Safe operation and maintenance are critical for reliable boiler operation.

Boiler Operation Safety

Boiler control strategies integrate with shutdown systems.

Burner Management System (BMS) trips fuel flow in unsafe conditions and is integral for safe start-up.

Critical Safety Concerns

Steam Drum Level Safety: Level trips prevent damage from high or low levels.
Furnace Draft Safety: High-speed implosion control prevents furnace collapse from excessive vacuum.
Burner Management System: Minimizes the chance of fuel explosions.
Soot Blowing: Removes soot deposits to maintain efficiency and prevent tube damage.

Burner Management Systems (BMS)

Use permissives and interlocks to minimize fuel explosion risks.

Purging: Pre-ignition purging expels unburnt fuel (Figure 32).
Excerpt from CSA B194.3-05 Section 9.2 Pre-purge. 9. 2. 1: When either an intermittent or interrupted pilot or a direct transformer spark ignitor is used to light the main burner and the combustion air supply is by mechanical means, the appliance control system shall provide a proven purge period prior to the ignition cycle. This purge period shall provide at least four air changes of the combustion zone and flue passages at an airflow not less than 60% of that required at maximum input.
Ignitor Gas Pressure: Must be within required limits.
Burner Gas Pressure: Must be within required limits.
Gas Burner Logic: Follows specific sequences for ignition.

Soot Blowing

Removes soot deposits, the frequency depends on the fuel.

Boiler Feedwater Treatment (Figure 33)

Treats boiler feedwater mechanically and chemically.

Treatment Methods

Boiler Blowdown: Withdraws water to avoid impurity concentration.
Deaeration: Eliminates oxygen and corrosive gases.
Chemical Treatment: Adjusts feedwater chemistry.
External Treatment: Minimizes water contaminates.

Problems Addressed By Treatment

Solid deposit buildup.
Corrosion.
Embrittlement.
Foaming.

Deposit Control

Boiler deposits result from contaminants such as hardness salts, metallic oxides and silica

Internal Treatment: Chemicals precipitate impurities as sludge, removed by bottom blowdown; solubilizing programs keep impurities soluble, removed by surface blowdown.
External Treatment: Removes impurities before they reach the boiler. Hard water intended for low-pressure boilers is softened by using a sodium zeolite softener (Figure 34). Softening alone is insufficient for high-pressure boiler feedwater that typically requires water demineralized by distillation or ion-exchange.

Corrosion

Most significant contributors to boiler waterside corrosion are dissolved gas and acidic or caustic water.

Maintain BFW pH of 10.5-11.5.
Mechanical Deaeration (Figure 35): Removes O2 and CO2.
Chemical Oxygen Scavengers: Remove any last traces of oxygen that were not removed.

Embrittlement

Alkaline water enters miniscule holes and cracks in the boiler metal resulting in corrosion..

Internal treatment involves adding lignin, tannin or sodium sulphate to block hairline cracks.
Replacing sodium carbonates with sodium sulphates as softening reagents minimizes caustic embrittlement.

Foaming

Soluble salts create frothy bubbles and can cause water carryover.

Internal treatment consists of chemical treatment combined with continuous blowdown.
Typically, these anti-foam materials are polyalcohols and amines.