3

Combustion Air

Burnout Zone

• Normal Excess Air

Reburning Zone

• Slightly Fuel Rich

Primary

Combustion Zone

• Reduced Firing Rate

Fig. 17-12 Functional Diagram of Natural Gas Reburning Process. Source: GRI

fired by coal, oil, or gas are turned down by 10 to 20%. The burners or cyclones may be operated at the lowest excess air consistent with normal commercial operation to minimize NOX formation and to provide appropriate conditions for reburning.

• In the gas reburning zone, natural gas (between 10 and 20% of boiler heat input) is injected above the primary combustion zone. This creates a fuel-rich region where hydrocarbon radicals react with NOX to form molecular nitrogen. The natural gas may be mixed with recirculated flue gases prior to injection to promote better mixing within the boiler. Gas reburn-ing injectors require new boiler-wall penetrations on most units.

• A separate overfire air system redirects air from the primary combustion zone to a burnout zone downstream of the gas reburning reaction zone to ensure complete combustion of unreacted fuel and combustible gases. This separate overfire air system requires boiler penetrations and ducting.

Gas reburn can be applied to all types of utility boilers fired by coal (including wet-bottom and cyclone units), oil, or natural gas. The key requirement is adequate height above the main firing zone for reburning and burnout residence times. Boiler control system upgrades are usually included so that new parameters can be programmed into the boiler system for safe start-up, shut-down, and trip conditions. These control changes have been reviewed and approved by major boiler insurers.

Steam or water injection into the combustion zone can decrease flame temperature, thereby reducing the formation of thermal NOX. Because steam and water act as a thermal ballast, it is important that the ballast reach the primary flame zone. To accomplish this, the ballast may be injected into the fuel, combustion air, or directly into the combustion chamber.

Water injection is sometimes preferred over steam due to its availability, lower cost, and higher heat absorbing capacity. However, water injection may exhibit some undesirable effects, including decreased thermal efficiency, increased maintenance costs, and reduced service life in gas turbines. This technology exhibits high operating costs chargeable to emissions control, with a fuel and efficiency penalty typically about 10% for utility boilers and about 1% for gas turbines. Water injection has not, therefore, gained much acceptance as a NOX reduction technique for stationary combustion equipment, except for gas turbine applications where on-site steam is not available. Fuel-water emulsion (FWE) is a process that involves adding water to the liquid fuel used in stationary and marine Diesel engines. FWE reduces the peak temperature in the vicinity of the fuel droplets, and thus limits the formation of NOX.

Gas- or coal-fired boilers that are equipped for standby oil firing with steam atomization already have a simple means for steam injection. Other installations may require a developmental program to determine the required degree of atomization and mixing with the flame, the optimum point of injection, and the quantities of water or steam necessary to achieve the desired effect.

When steam is injected into a gas turbine's combustor for emissions control, the small increase in exhaust mass flow increases the power output, usually by 3 to 10%. Some gas turbine designs lend themselves to modifications that allow injection of significantly greater quantities of steam specifically for power augmentation, with capacity increases up to 50%. Refer back to Figure 12-12, which shows gas turbine capacity, in MW, as a function of inlet air temperature and steam injection rates, in Mlbm/h.

Water- or steam-to-fuel ratio is a key variable affecting NOx control in gas turbines. Typical steam-injection ratios are between 0.5 and 2.0 lbm steam per lbm fuel; water-injection ratios are generally below 1.0 lbm water per lbm fuel. Caution must be used with wet injection ratios, since higher ratios can increase CO and VOC emissions and reduce fuel efficiency. The quality of the water or steam is also an important consideration, since impurities may damage the combustion section and the turbine blades. The type of water treatment required will vary depending on the turbine design and the quality of the raw water, but can become a significant cost and reliability factor. Water treatment systems can include coagulation, filtration, absorption, ion exchange, reverse osmosis, or demineralization.

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