Value-Added Applications of Supplementary Firing in Gas Turbine Based Cogeneration Plants

Presented at the ABMA Industrial Boiler Systems Conference
September 17 – 19, 1997
West Henrietta, New York

Jonathan C. Backlund, Stephan C.G. Bergmans, Coen Company, Inc.


In the past decade, cogeneration (the sequential production of electrical and thermal power from a single fuel source) using gas turbines and heat recovery steam generators, has seen significant growth as a power production method. There have been many new installations in the industrial sector (chemical processing, refining, pulp & paper etc.), and more recently “Independent Power Producers” (IPP’s), third parties who build plants to sell power to utilities and thermal power to an industrial host plant. In those geographic areas where utilities need additional generating capacity, the economic incentives to construct new projects can be attractive. The availability and competitive pricing of natural gas for the foreseeable future has encouraged the installation of combustion turbines with exhaust heat recovery as the most popular type of cogeneration plant. The short lead time, large degree of modularity, wide choice of electrical and thermal capacities, reasonable costs, minimal environmental impact, and high energy efficiency have also contributed to the rapidly growing demand for combustion turbine based plants. A schematic of a typical supplementary fired gas turbine cogeneration plant, consisting of a combustion turbine, exhaust bypass, duct burner, and heat recovery boiler is shown in Figure 1.

Figure 1, Typical Supplementary Fired Gas Turbine Cogeneration System

Supplementary firing in cogeneration systems is applied where system economics justify the additional equipment and costs. This is the case in industrial plants with significant steam loads, as addition of supplementary firing in a given plant is a more economical way to increase steam production and has many more advantages.


A. Benefits of applying a supplementary firing system in a cogeneration plant.

Supplementary firing directly into the turbine exhaust gases (TEG) yields important advantages. The most important advantages are listed here:

  1. Increased amount and better control of system thermal output
  2. More efficient process steam production than with a conventional boiler.
  3. Steam production can be maintained at lower GT load or GT shut down
  4. Compensation for changing ambient conditions
  5. Ability to burn fuels not suitable for gas turbines

1. Increased amount and better control of system thermal output
Supplementary firing provides a means to increase and control the thermal output of the system (e.g., steam flow, superheat temperature, etc.) so that an optimum match can be made between engine and process needs.

2. More efficient process steam production
Compared with conventional, direct fired steam generators it is almost always more efficient to generate steam in an HRSG. (Ganapathy, [1]) The main reason for this phenomena is that a supplementary firing system is using the preheated oxygen that is available in the turbine exhaust gases. In a conventional, direct fired steam generator ambient air is used which has to be heated and therefore requiring additional energy. In a HRSG all energy added by the burner is extracted by the heat recovery equipment. See Figure 2.

Figure 2, Cogeneration Plant Efficiency with Supplementary Firing (From [3])

Overall system energy efficiency is increased, since as mentioned 100% of burner heat input is available for heat recovery. Typically when supplementary firing is added, the HRSG exit-gas temperature will decrease as the load increases. This will consequently decrease stack losses and increase system efficiency. The reason for this is that while the gas flow will remain nearly constant at all loads, the steam production and consequently the flow through the economizer will increase and more heat from the exhaust gases can be recovered. In such an operation, the stack temperature will drop as supplementary firing is increased. (Ganapathy, [1]) See Figure 3.

Figure 3, Efficiency Increase at Higher Load in HRSG (from [1])

3. Steam production can be maintained at lower GT load or GT shut down
A lower load of the gas turbine, e.g. at lower demand of electrical or shaft power, will result in less TEG flow and/or lower TEG temperature. In an unfired HRSG the steam production will be decreased as less heat is available. A supplementary firing system is able to compensate for the difference.

In addition, at a gas turbine trip or shut down, a supplementary firing system is able to maintain the steam production at a certain level, provided that a fresh air fan is available. This change over to fresh air firing (FAF) can take place without a large dip in steam production. An even more rapid, reliable changeover to FAF mode, in case the steam needs are very critical, can be ensured by employing an induced draft fan. (Froemming, [2])

4. Compensation for changing ambient conditions
Gas turbine performance is to a certain extent dependent on the ambient conditions. This will effect the mass flow and temperature of the exhaust gases and therefore the heat available for steam production in the HRSG. Supplementary firing can completely offset this effect.

5. Ability to burn fuels not suitable for gas turbines
Some burners can fire a wider range of fuels than those suitable for combustion turbines (e.g., residual oil and low-BTU gas). This capability adds flexibility to the system, and can greatly improve operating economics.

In addition, as environmental legislation on emissions and waste becomes more strict it becomes attractive to burn or incinerate vent gases and waste streams to non polluting CO2 and H2O. Supplementary firing systems can be designed to incinerate both liquid and gaseous waste streams, regardless of the calorific value.

B. Typical Configurations

Following are three examples of very typical applications:

  1. 40 MW industrial GT, 250 MMBTU/HR duct burner firing refinery gas.
  2. 3-5 MW industrial or aero derivative GT with 100 MMBTU/HR dual register burner, gas & oil in water cooled furnace.
  3. 100+ MW GT in power plant with 400 MMBTU/HR gas duct burner between superheaters.

A. Waste Gas Incineration Addition to an Existing HRSG


In 1992, Coen was contacted by a large petrochemical plant in Texas, concerning the possibility of incinerating their VOC (Volatile Organic Compounds) laden off gases in their existing GE Frame Seven / Vogt HRSG system. They had been currently venting these gases to the atmosphere, and the Texas Air Control Board were mandating that they collect these gases and destroy the organic components.

The waste gas flow of 70,657 LBS/HR consisted 94 vol.% of nitrogen, the remaining being CO (2.9 vol.%), H2O (1.2 vol.%), CO2 (0.8vol.%) and various hydrocarbons.

Location Texas
Output 154 MMBTU/hr (Net LHV)
Fuel Natural Gas and Waste Gas
Incineration effectiveness CO > 50%
Hydrocarbons > 99%
NOx limit Contribution of duct burner < 5 ppm by volume wet.


The burner design consists of five gas duct burner elements with four waste gas burner elements in between. The waste gas elements were provided with gas jets drilled and aimed to inject the waste gas into the natural gas flames, to assure the oxidation of the combustible components of the waste gas stream. A schematic drawing of the duct burner is shown in Figure 4.

Figure 4, Section Waste Gas Oxidation Duct Burner


After a smooth startup it appeared that CO and hydrocarbon destruction were well below the guaranteed values. Also the NOx limit was met, but a slightly brown colored plume was identified as the result of conversion of NO to NO2 in the TEG by the cold waste gases. A modification of the waste gas jets trajectory will probably eliminate this problem.

B. TEG and Fresh Air Firing of Oil and Gas at Small Gas Turbine Based University Steam Plant


In 1990, a new cogeneration plant was to be constructed at a university steam plant. A Solar gas turbine was applied in combination with a Deltak HRSG. Typical for cogeneration systems with relatively small gas turbines is the large supplementary firing heat release to exhaust gas flow ratio. This means that the oxygen content had to be decreased from a 14 vol.% to 3 vol.%. Grid type duct burners are not able to achieve this low excess air amount.

Another requirement was to maintain steam production. During gas turbine trip or shut down, the installation should be able to rapidly switch to fresh air operation. The main fuel was natural gas with full back up capacity of #2 oil.

Location Mount Pleasant, Michigan
Fuel Natural Gas and #2 Oil
Output on Fresh Air 120 MMBTU/hr (Net LHV)

on TEG

88 MMBTU/hr (Net LHV)


Applied was a Low NOx Coen Parallel Flow burner (CPF). The CPF is designed for low NOx combustion with extreme low excess air ratio’s. A schematic drawing of the system is shown in Figure 5. The combustion installation consisted of two CPF’s in a combined windbox. The burners were fabricated using stainless steel to handle the high temperature turbine exhaust gas. For firing the #2 oil the burners were equipped with two air atomized oil guns.In addition the burners were designed to operate on fresh air. A fresh air fan and a gas turbine isolation damper were added to the installation for this purpose.

Figure 5, Dual Fuel TEG and Fresh Air “Fully Fired” Cogeneration System (from [2])


The system performs well and ensures a reliable steam supply, both when firing gas and oil. At a trip of the gas turbine, it takes ten seconds for the installation to switch over to full fresh air operation.

C. Supplementary Firing of Low BTU Coal Gas in Power Plant.


Coen received the order to supply the duct burner system for the Continental Energy Cogeneraton Plant, Hazleton Pennsylvania back in January 1988. The duct burner system operates behind an ABB Type 11D5 gas turbine rated at about 75 Megawatts, and has an exhaust mass flow of 2,200,000 LBS/HR. At the job site fifteen coal gasifiers produce the low BTU coal gas from anthracite culm. The HRSG make is NEM.

Name Continental Energy Cogeneration Plant
Location Hazleton, Pennsylvania
Fuel Natural Gas and Low BTU Coal Gas

on TEG

88 MMBTU/hr (Net LHV)

Natural Gas

360 MMBTU/hr (Net LHV)
Coal Gas 350 MMBTU/hr (Net LHV)
Combination 410 MMBTU/hr (Net LHV)

The coal gas composition is as follows:H2 22.0% by Volume.CO 18.0% by Volume. CH4 1.0% by Volume.N2 59.0% by Volume. H2S 0.14% by Volume or 1400 PPMV. The coal gas has a calculated heating value of 2191 BTU/LB (LHV) or 130 BTU/SCF, resulting in a mass flow of 159,770 LBS/HR at capacity. Sufficient levels of H2 and CO results in a fuel that is readily combustible in the TEG stream. However the coal gas is supplied at a very low pressure of 3 PSIG and a temperature of 350 °F.


The coal gas is a low BTU gas and has a high volumetric flow, combined with the elevated temperature and low supply pressure to the burner skid at about 3 PSIG a special duct burner system was needed. The burner elements were designed with a 10″ internal manifolds and a 42″ external header. The duct burner assembly had a total of ten natural gas burner elements, and eleven coal gas burner elements. See Figure 6. For a detail of the low BTU gas burner.

Figure 6, Low Pressure Coal Gas Duct Burner Detail


The coal gas combustion is stable and complete. The system has been in operation for several years and proven to be reliable on both natural gas and coal gas.

D. Biogas Combustion in Brewery


A by-product of the fermentation process is a biogas consisting of methane and carbon dioxide. This gas can not be vented into the atmosphere in many plants. The composition of the gas, 29 vol.% CO2 and 70 vol.% of CH4, with a calorific value of 635 BTU/SCF (Net LHV) makes this suitable as fuel gas. The brewery decided to combust the gas in their cogeneration plant based on a EGT type Tornado turbine and ERI HRSG, two identical trains.

Location Newark, New Jersey
Fuel Natural Gas, #2 Oil and Biogas
Output, Nat. Gas and #2 Oil 94.9 MMBTU/hr (Net LHV)


54.0 MMBTU/hr (Net LHV)


A duct burner installation was designed with dual fuel elements for the natural gas and oil, and separate elements for biogas. See Figure 7. The high inert gas content of the biogas makes it difficult to combust stable in an oxygen poor environment as turbine exhaust gas. Nevertheless it was decided that a special design of the stabilizer elements would be sufficient, rather than applying augmenting fresh air.In addition the supplementary firing installation is provided with a fresh air fan, to continue steam production at gas turbine shut down.

Gas/Oil Elements 5 places

Biogas Elements 3 places

Figure 7, Natural Gas / #2 Oil / Biogas Duct Burner


The installation has proven to operate reliable on all fuels. The brewery solved a disposal problem of the biogas and will instead save on fuel costs of natural gas and oil making this solution economical attractive.

E. Sludge Digester Gas in Municipal Utility


In 1994, a municipal utility in Elk Grove, California planned to incinerate a digester gas in their GE LM-6000, Deltak HRSG based cogeneration plant. This digester gas is a product from a sewage sludge digester. The composition of the gas is; 60 vol.% CH4 , 39 vol.% CO2 the remaining being N2 , O2 and traces of VOC and H2S. The heating value is 550 BTU/SCF (LHV).

The supplementary firing installation was designed to fire independently on both the digester gas and natural gas.

Location Elk Grove, California
Fuel Natural Gas, Digester Gas
Output, Natural Gas 81.0 MMBTU/hr (Net LHV)

Output, Digester Gas

81.0 MMBTU/hr (Net LHV)


The large inert content of the digester gas in combination with the low oxygen content and temperature of the TEG does not allow stable combustion. The combustion velocity is below critical limits and does not provide sufficient heat to maintain a stable flame front. Coen designed a duct burner system in which, next to the natural gas elements, the digester gas elements were provided with augmenting fresh air. Although the augmenting air flow is relatively low compared to the combustion air needs of the digester gas, it provides a hot nucleus of the flame which maintains a stable flame front.


The solution of providing augmenting air to fire this difficult to combust gas at low temperature and low oxygen TEG conditions worked out well. Plant operation is reliable and CO and VOC emissions are below permitted values. A utility plant that has as major task to produce electricity for municipal use, is successfully applied to dispose a waste stream in an economical way.


Application of supplementary firing systems in gas turbine based cogeneration plants to augment the steam production has strong economical advantages. In addition, supplementary firing will improve the control of plant output and can ensure the steam production at gas turbine trip or shut down.

Environmental problem waste streams can be incinerated by supplementary firing burners and contribute to more economical operation of the plant.

  1. Ganapathy, V., ‘Efficiently Generate Steam from Cogeneration Plants’, Chemical Engineering, May 1997.
  2. Froemming, J., L Hjalmarson and M. Houshmand. ‘Ensure Cogen Steam Supply with Fresh-Air-Fired HRSG’s’, Power, August 1993
  3. Backlund, J.C., and E.E. Fiorenza ‘Experience with Supplementary Combustion Systems to Maximize Steam Production in Gas Turbine Cogeneration’. Paper presented at the Gas Turbine and Aeroengine Congress, Amsterdam, The Netherlands, June 1988.