Alternate Fuels for Supplementary Firing Add Value and Flexibility

Alternate Fuels for Supplementary Firing Add Value and Flexibility to Combined Cycle and Cogeneration Plants

Presented at Power-Gen International 2001

Las Vegas, NV
December 11-13, 2001

Atallah E. Batshon, Jonathan C. Backlund, Coen Company, Inc

ABSTRACT:

Nearly all new U.S domestic power plants are natural gas fired combined cycle. Cogeneration and thermal power, also known as combined heat and power, or CHP, is also popular. Supplementary firing systems, using the hot turbine exhaust gases as the oxygen source, have proven to be an economically attractive means to increase system output, flexibility and (in the case of CHP) efficiency. In addition to matching steam production to process needs independently of ambient conditions or GT availability, an advantage of supplementary firing is the possibility to fire a much wider range of fuels than those suitable for gas turbines. This provides both economical and environmental advantages.

There are many non-conventional fuels that have been successfully utilized in supplementary firing applications. Examples are hydrogen gas from chlor-alkali production, digester gas from sewage sludge, biogas from the brewing process, blast furnace gas from steel making, landfill gas from decomposing municipal solid waste, and gas from coal gasification. For some of these alternate fuels, case histories of projects are presented, including some design details, a discussion of emissions, and technical challenges and solutions.

CONVERSION FACTORS

MMBTU/hr = MW x 3.41
°F = 9/5 x °C + 32
lb = kg x 2.20
ft = m x 3.28
inch = mm x 0.0394
psi = bar x 14.5 I.

INTRODUCTION:

In recent years, the power generation industry has had to face major structural changes following ongoing deregulation. This new business environment has led to major investment in gas fired combined cycle plants, and also cogeneration plants. In addition to having higher efficiency [nominally 55% vs. 40%], combined cycle plant construction cost is about half that of a conventional fossil steam power plant. Further, combined cycle power plants are built in shorter time. Gas turbine based cogeneration plants are attractive due to their low capital investment, shorter gestation period, reduced fuel consumption, and low environmental impact.

A schematic of a typical small supplementary fired gas turbine cogeneration plant, consisting of a combustion turbine, duct burner, and heat recovery steam generator is shown in Figure 1.

Supplementary firing in combined cycle systems is applied where system economics justify the additional equipment costs. Duct burners add 10-15% to the HRSG cost. Approximately 75% of the new combined cycle plants in the U.S. include duct burners. Even though duct burners decrease the efficiency of a combined cycle plant, very often the price of power makes supplementary firing a moneymaker. This is especially true in the hot summer months when power prices peak and combined cycles without supplementary firing produce less power. In cogeneration plants, the addition of supplementary firing gives more economic ways to increase their steam production than conventional boilers and has many more advantages. Supplementary firing is a proven technology that increases profit and saves fuel resources. Capable of firing a wider range of fuels than those suitable for turbines, duct burners add another economical and sometimes environmental advantage.

Figure 1, Typical Supplementary Fired Gas Turbine Cogeneration System

II. TYPICAL GT-SUPPLEMENTARY FIRING APPLICATIONS

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 a 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. 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 exhaust 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], Backlund [2]). See Figures 2 and 3.


Figure 2, Cogeneration Plant Efficiency with Supplementary Firing (From [1])


Figure 3, Efficiency Decrease at Higher Load in Conventional Boiler with Economizer (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. a 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 shutdown, 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, [3])

4. Compensation for changing ambient conditions

Gas turbine performance is to a certain extent dependent on the ambient conditions. This will affect 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

Duct 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.

For example, natural gas prices fluctuate depending on demand and availability while non-conventional fuels such as digester gas from sewage sludge, biogas from brewing process and blast furnace gas from steel making are gases that are available as by products of an existing process. These gases are “free” and the ability to utilize them in supplementary firing to produce additional power or steam can yield significant financial benefit.

In addition, as environmental legislation on emissions and waste becomes stricter 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. Benefits of applying a supplementary firing system in a combined cycle system

Supplementary firing in a combined cycle system can provide additional means to generate more electricity when the market is tight and wholesale prices are peaking.

Duct burners increase the plant output. 100 MM BTU burners produce about 13 MW additional. However, duct burners decrease combined cycle efficiency, or raise the heat rate that is expressed in BTU/KWH. For example, using two 400 MM BTU duct burners in a typical nominal 500 MW “2 on 1” block increases the power output by 102 MW, and increases the heat rate from 6714 BTU/KWH to 6909 BTU/KWH. In terms of efficiencies, it decreases by about 1 1/2%. This is due to the fact that much of the duct burner heat input is “rejected” when the steam from the steam turbine is condensed. This is a thermodynamic fact in all Rankine cycle steam plants. However, during summer peaks the price of power can rise to 30 times of the average price. Combined cycles with a lot of supplementary firing maximize their profit potential (Backlund, [4]).

III. VALUE ADDED APPLICATIONS – CASE HISTORIES

A. Waste Gas Incineration Addition to an Existing HRSG

Situation

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 7EA / Vogt HRSG system. They had been 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 consists 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

Solution

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 sectional drawing of the duct burner is shown in Figure 4.

Results

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 has minimized this problem.

Figure 4, Section Waste Oxidation Duct Burner

B. Blast Furnace Gas Firing at a Combined Cycle Plant in Italy

Situation

In 1995, ISE (Iniziative Sviluppo Energia) started construction of a new “clean” power plant, called CET3, at ILVA Taranto, Italy. The plant consisted of three identical combined cycle units capable of producing 530 MW of electrical power. The plant was designed to utilize Blast Furnace Gas (BFG) and Linz Durer Gas (LDG) (Thoraval, [5]). dejong Coen was contracted to design and provide the supplementary firing system to produce steam at 540 C. The burners were to utilize BFG and LDG gas supported by natural gas.

Location: Taranto, Italy.
Turbine GE PG9171E
Fuels: Natural Gas, BFG and LDG

Burner Capacity:
Total: 170 MMBTU/ hr
N.G 30.7 MMBTU/ hr
BFG 165 MMBTU/ hr

Emissions Guarantees:
NOx < 0.10 LB/MMBTU
CO < 0.05 LB/MMBTU

Gas composition, mole percent:

BFG
LDG
H2
4.53
0.96
CH4
<0.003
CO
22.38
69.15
CO2
23.19
23.19
N2
48.60
14.89
O2
0.25

Solution

A special supplementary firing system was designed for this project. Two 30” O.D. headers, one on each side of the duct, were used to supply BFG/LDG gas to 23 vertical burner elements. A horizontal natural gas burner was provided to sustain the flame (See Figure 5). A set of heat resistant intermediate/end supports was designed to allow free expansion of the burner elements within the burner frame. To maintain adequate (high) combustion temperature to assume full oxidation of the CO, only part of the gas turbine exhaust passes through the burner, with the remainder bypassing the combustion zone.

Results

The system was reliable and the flame was stable at turn down. The combustion of NG, BFG and LDG was complete under the designed conditions and emission guarantees were met.

Figure 5, BFG/LDG Duct Burner

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

Situation

Coen received an order to supply the duct burner system to burn low BTU gas from a gasification facility in Hazleton, Pennsylvania in January 1988. The duct burner system operates behind an ABB Type 11D5 gas turbine rated at about 75 megawatts, with 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.

Location: Hazleton, Pennsylvania
Fuel: Natural Gas and Low BTU Coal Gas

Output

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.

Solution

The coal gas is a low BTU fuel and has a high volumetric flow, combined with the elevated temperature and low supply pressure to the burner 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

Results

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

Situation

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

Location: Newark, New Jersey
Fuels: Natural Gas, #2 Oil and Biogas

Output:
Nat. Gas and #2 Oil: 94.9 MMBTU/hr (Net LHV)}
Biogas: 54.0 MMBTU/hr (Net LHV)

Solution

A duct burner installation was designed with dual fuel elements for the natural gas and oil, and separate elements for biogas. See Figure 7.

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

The high inert gas content of the biogas makes it difficult to combust stably in an oxygen-depleted environment such 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 with the gas turbine shut down.

Results

The installation has proven to operate reliably 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 economically attractive.

E. Sewage Sludge Digester Gas in Municipal Utility

Situation

In 1994, a municipal utility in Elk Grove, California planned to incinerate 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 remainder 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)
Digester Gas: 81.0 MMBTU/hr (Net LHV)

Solution

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 that maintains a stable flame front.

Results

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 must produce electricity for municipal use is also successfully used to dispose of a waste stream in an economical way.

F. Hydrogen Gas from Chlor-Alkali Production

Situation

In January of 2000, Vogt-Nem (HRSG manufacturer) contracted Coen Company to retrofit an existing duct burner at a chlor-alkali plant in McIntosh, Alabama. The existing burner had eight runners of which four were used to fire hydrogen and four fired natural gas. The hydrogen was a by-product of the electrolysis of brine to produce HCl and NaOH. It is basically pure hydrogen saturated with water vapor and trace of salt. The existing burner had a stability problem and did not meet emissions guarantees. The plant utilized a GE frame 7EA turbine which generated 2,351,100 lb/hr exhaust at 1000 F.

Location: McIntosh, Alabama

Output:
130 MMBTU/hr (Natural gas)
100 MMBTU/hr (Hydrogen)

Emissions:

Type of fuel/Mixture NOx-LB/MMBTU (HHV Basis)
100% Natural Gas 0.08
90% N.G and 10% H2 0.09
10% to 50% H2 & Balance NG 0.12
50% to 100% H2 and Balance NG 0.15

Solution

Coen installed their latest duct burner design. The burner design maintained four elements for hydrogen and four elements for natural gas firing. Further, baffles were added to optimize TEG flow velocity through the burner. During start up, the hydrogen elements failed to produce the designed capacity. Investigating the problem, it was determined that the hydrogen fuel was hotter than design, and being saturated with water therefore contained a higher mole percent of water, increasing the volume and specific gravity. As a result, the holes were drilled to increase their area by 50%. This allowed more fuel to pass through the holes under the available pressure and temperature and the burners were able to fire up to the designed capacity.

Results

The retrofit was successful and the new burner proved to be stable and reliable. Further, the NOx limits were met for all mixtures of natural gas and hydrogen.

G. Landfill Gas (LFG) Fired Duct Burners.

Situation

One pound of landfill refuse waste can produce approximately 3.6 SCF of LFG. The heating value of LFG ranges between 300 and 500 Btu/SCF and is classified as a medium Btu-gas. Recently, Environmental Protection Association (EPA) regulations, tax credits, and global warming has lead more resourceful power producers to turn to landfill gas for fuel (Giovandi, [6]). In the early 1990’s Coen Company was contracted by two HRSG suppliers, ERI and ATS, to design a total of eight burners for three projects burning LFG in small combined cycles. After detailed analysis, Coen determined that even though LFG will burn in air it will not burn in normal turbine exhaust without augmenting air. The duct burners were to operate behind E.G.T Typhoon turbines each with an exhaust mass flow of 153,000 lb/hr and 13.42% by volume oxygen content.

Locations:
Northville, Michigan
Pine Bend, Minnesota
Hanover , Illinois

Fuel: LFG (393 Btu/SCF HHV)

Burner output: 15 MMBtu/hr

Emissions:

Expected Actual
CO 100 PPM 70 PPM
NOx 84 PPM 34PPM

Solution:

The burner system consisted of two elements. Augmenting air was added to ensure complete combustion of LFG. The system included an augmenting air fan that provided 290 SCFM of augmenting air (11% stoichiometric). The air was injected to the burner utilizing a 4” header on the opposite side of the main gas header.

Results:

The landfill gas burned successfully and the emissions were lower than expected.

Figure 8, Landfill Gas Duct Burner

IV. CONCLUSIONS

Application of supplementary firing systems in gas turbine based cogeneration plants and combined cycle plants to augment the steam production has strong economic advantages. In addition, the capability of firing a wide range of non-conventional fuels has made supplementary firing even more attractive for both its environmental and economical advantages. In cogeneration plants, supplementary firing will improve the control of plant output and can ensure the steam production at gas turbine trip or shut down. Further, supplementary firing will generate high revenues for combined cycle plants when power prices peak.

REFERENCES:


  1. Ganapathy, V., “Efficiently Generate Steam from Cogeneration Plants”, Chemical Engineering, May 1997.
  2. 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.
  3. Froemming, J., L. Hjalmarson and M. Houshmand. “Ensure Cogen Steam Supply with Fresh-Air-Fired HRSG’s”, Power, August 1993.
  4. Backlund, J.C., and Froemming, Jim, “ Thermal and Economic Analysis of Supplementary Firing Large Combined Cycle Plants”, Paper presented at Power Gen International, Orlando FL, November 2000.
  5. Thoraval, G., and Simonetti, S., “Blast Furnace Gas: an Incentive for Italy”, Industrial Cogeneration, 1997
  6. Giovando, C., and Jones, C., “Resourceful Power Producers Turn to Landfill Gas for Fuel”, Fuel, July/August 1998.