Tuning Package-Type Natural Gas-fired Power Boilers

Introduction

The following is a basic process to tune the controls for a natural gas-fired package water-tube boiler or smaller utility type field erected boiler for saturated steam supplied to a plant's common header distribution. The boiler has a forced draft fan and a pressurized furnace. The boiler example chosen uses steam and gas flows typical for the example size. This example can be scaled to fit other capacities of boilers.

The boiler is supplied with a modern DCS and BMS for a reliable and safe operation. The instrumentation listed uses a generic tag description numbering method. The control configuration for the combustion control is a metered parallel cross-limiting strategy (high/low selectors) (see ISA 77-41-01). The firing rate demand signal acts as a common set point for the fuel flow controller and the air flow controller. The air flow will always lead the gas flow on load increases and lag the gas flow on load decreases. This cross limiting adds the safety constraints to the control strategy, never resulting in fuel rich conditions.

If there is more than one boiler in the plant supplying steam to a common distribution system then there will be a plant master steam pressure controller. This controller will set the demand for each individual boiler's pressure controller, which sets the individual boiler's firing rate to maintain the system header steam pressure.

The steam drum level measurement should have two level transmitters located on separate taps on the steam drum head for increased reliablity. A three-element control configuration is a cascaded feedforward loop with drum level as the primary variable, steam flow as the feedforward input, and feedwater flow as the secondary variable. This control configuration provides effective compensation for drum level shrink and swell (see ISA 77-42-01).

The power boiler in this example has a maximum steam flow (MCR) of 150,000 kg/hr (330,000 lbs/hr). Equipped with either a single burner or dual burners fired together as a single burner mode. A maximum gas input of 418 GJ/hr (395 mmBTU/hr), or 11,350 m3/hr (400,000 SCFH). The excess air at 50% load and above is to be 12%, or O2 of 2.0%.


Basic method for the initial set-up and tuning of the controls

1. The first step requires the calibration of all the boiler’s instruments. Ensure data sheets have been supplied and are correct for this application.

    Verify the correct calibration of the following instruments:
  1. Air flow, 100FE-air
  2. Natural Gas flow, 100FE-gas
  3. Oxygen Analyzer, 100AE-O2
  4. Drum level, 100LT-levelA
  5. Drum level, 100LT-levelB
  6. Steam flowmeter, 100FE-steam, to a range of 0–160, 000 kgs/hr.
  7. Feedwater flowmeter, 100FE-bfw, to a range of 0–200,000 kgs/hr (MCR plus 1 safety valve or 133% of max steam)
  8. Steam drum pressure, 100PI-steam
  9. Gas header pressure, 100PI-gas 1
  10. Gas burner pressure, 100PI-gas 2
  11. Furnace pressure, 100PI-furnace
2. Tune the feedwater control loop to have slight overshoot or even a damped response. Do a bump test and find the loops dynamics and calculate the tuning parameters. Check valve’s mechanical parts to ensure valve moves without binding and/or sticking. Linearize the feedwater control valve to give a consistant response over its flow range.


3. Tune the drum level control loop by the following method.

  1. Set the feedforward gain at 0.80 into steam flow transmitter output (flowmeter limits of: 160,000 steam/200,000 water =0.80)
  2. The tuning for the drum level is best accomplished by a dynamic load change. Find the boiler drum level swell (in inches) as the steam load is rapidly increased by 10% (15,000 kg/hr) or 15% (22,500 kg/hr) of full range.
    3. 

  3. Drum level controller gain = % Δ steam flow ( kg/hr increase/ kg/hr transmitter range) divided by
 % Δ drum level ( inches swell/inches transmitter range)
    4. 

  4. Controllers integral action set at about 0.1 to 0.2 repeats per minute to slowly bring drum level back to set point.

4. Combustion calibration

If gain blocks are configured on the high/low selects, set these to ± 25%. This will remove the limiting control effect during tuning of the air flow and fuel flow control loops. Be sure to reset these gain values when tuning completed.

  1. Put the O2 trim on manual at 50% output (nulled).
  2. Tune the natural gas flow, 100FIC-gas, control loop. Use the open loop reaction curve method or lambda tuning method. The closed loop or ultimate cycle method may be too dynamic for the gas valve. The gas flow control valve should be linearized, as best as possible. This will result in the best control response over the full flow range.
  3. Set a maximum limit on the gas flow controller so the boiler will not produce more than 340,000 Lbs/hr (155, 000 kgs/hr) steam flow. This can be found during the combustion tests when the boiler is run up to 100% MCR. Most control valves are, or can be, supplied with a mechanical stop that will limit the valve's opening to ensure the gas flow does not exceed the boiler design safe rated input.
  4. Tune the air flow control loop.
    5. Both the air flow control loop and the gas flow control loop should have the same dynamic response. This will provide the best boiler response over all load ranges.
  5. Set the minimum air flow to 25%. This is the NFPA code defined minimum allowable air flow for boilers.
  6. Return the gain block values to initial values or slowly reduce the gain values from the ±25% until the point of interaction to find the best values.

5. Characterize the fuel-air ratio
Set the tuning of the Oxygen trim to a gain of 0.1 and reset to 0.1 rpm. The O2 controller modifies the characterized combustion air controller's output at a ± 10% maximum trim, (a multiplier limit of 0.9 to 1.1). O2 trim is used to correct for long-term variables, not to control the air flow. The oxygen analyzer has a time constant and dead time that will actually degrade the air flow control. The O2 trim corrects for changes in gas heating value, combustion air temp, ambient air density and meter errors.

  1. Place the O2 trim on manual mode at 50% output. (nulled)
  2. Reduce firing rate to minimum and put the air flow controller and gas flow controller into manual control mode.
  3. Use the following table:

Steam Flow, kgs/hr Oxygen, % Gas flow Gas % Air flow Actual air % Characterized air
Minimum fire 8.0%
15,000, 10% 7.0%
30,000, 20% 6.0%
45,000, 30% 4.5%
60,000, 40% 3.5%
75,000, 50% 2.5%
90,000, 60% 2.0 %
Increasing steam flow 2.0%
150,000 2.0%

  1. Slowly increase the firing rate. Making sure air flow is always increased before gas flow on increasing loads and gas flow is reduced before reducing air flow on decreasing loads.
  2. Adjust air flow controller to obtain correct oxygen at corresponding steam flow using above table.
  3. Allow combustion to stabilize for 5 to 10 minutes at each load.
  4. Record the actual gas flow, gas flow percentage, actual air flow, and percentage air flow. The actual percentage air flow must be characterized in the function generator so that the air flow output matches the gas flow. Example, if the gas flow is at 50% and the actual air flow is at 40% to obtain the correct steam flow to O2 ratio, the characterizer output must be changed to 50%. If the gas flow is at 65% and the actual air flow is at 58% to obtain correct steam flow to O2 ratio, the characterizer output must be changed to 65%.
  5. This procedure is continued over the complete load range in the 10% increments. Plot the recorded values in a table and make the corrections.


6. Boiler Control

A Plant Master controller maintains the steam pressure on the plant’s common steam header. The output of the Plant Master controller will be fed in parallel to all individual Boiler Master controllers in the plant. The Boiler Master controller can be run in manual mode to set the steam flow at a desired rate. In automatic mode, the Boiler Master will vary the boiler's firing rate to satisfy the Plant Master. The individual Boiler Master can be biased, in automatic mode, to change the boiler's desired steam output load sharing.

7. Operating Limits

The Power Boiler shall have alarm and trip values that require annual calibration and proof testing. These settings should be provided by the boiler and burner suppliers. The basic alarms and trips for a safe and reliable operation include, but not limited to the following.

Typical values for drum level alarms will be ± 4" to 6" of the NWL.
High/low drum level trip values will be ± 8" to 10" of the NWL.
High steam pressure alarm and trip values which should be set below the safety valve levels
High natural gas header pressure alarm and trip values
Low natural gas header pressure alarm and trip values
High burner gas pressure alarm and trip values
Low combustion air flow alarm and trip values
High furnace pressure alarm and trip values