Alternative

ARTICLE pubs.acs.org/EF

Experimental Study on Co-Firing of Syngas as a Reburn/Alternative Fuel in a Commercial Water-Tube Boiler and a Pilot-Scale Vertical Furnace Won Yang,*,† Dong Jin Yang,† Sin Young Choi,† and Jong Soo Kim‡ † ‡

Energy System R&D Group, Korea Institute of Industrial Technology, Korea Global Environment Center, Korea Institute of Science and Technology, Korea ABSTRACT: Co-firing synthesis gas (syngas) with conventional fuels within a conventional boiler is an effective method that partially replaces the use of fossil fuels with low-grade fuels or renewable energy sources such as waste or biomass. This study investigates the characteristics of syngas cofiring and reburning in a commercial oil-firing boiler and a pilot-scale vertical combustion chamber with refractory. Syngas cofiring was tested in two separate apparatus. The first was a commercial water-tube boiler containing one heavy oil burner of 0.7 MWth (for 1 ton steam/h). The second was a vertical furnace with 4 heavy oil burners, for various heat replacements by syngas cofiring at various heating values. Temperature distributions and the gas composition at the exit of the combustion chamber were measured for all cases and the thermal efficiencies under various cofiring conditions were evaluated through heat and mass balance calculations. Combustion stability remained unaffected if less than 20% heat was replaced by syngas cofiring; this was true for syngas of low calorific values (3.7 MJ/Nm3), and especially in vertical furnaces with horizontally installed multiburners. The reburning effects induced by syngas cofiring were confirmed by testing two reburning conditions in the vertical chamber: reburning only and reburning in combination with air-staged combustion of which the total thermal input was 2 MWth. These conditions reduced NOx emission by 30
50%, indicating that high temperatures of the radical production are essential for reducing NOx emissions. Meanwhile, syngases containing low-calorific values yielded heat efficiency losses. Conversely, heat efficiency increased when syngases possessing higher heating values were applied to the boiler.

’ INTRODUCTION Securing fuel flexibility in industrial and power boilers has become an important issue in industry for saving costs of conventional fossil fuel. Additionally, fuel flexibility can reduce carbon dioxide emissions when renewable energy sources such as waste and biomass replace the main fuel. Co-firing of low-grade solid fuels such as solid waste and biomass is one of the important options applicable currently and in the short- and medium-term. Two methods of cofiring exist: direct cofiring and indirect cofiring. Direct cofiring feeds low-grade solid fuel directly into the boiler. Conversely, indirect cofiring supplies syngas from the gasification process as the low-grade fuel. Direct cofiring yields higher thermal efficiency in comparison to indirect cofiring; however, the cofiring ratio should be limited in order to prevent several operational problems, including slagging, fouling, and corrosion in the boiler. Indirect cofiring resolves those problems because only cleaned syngas is supplied to the host boiler, even if 30
40% thermal loss during the gasification process is unavoidable. Additionally, syngas can be efficiently used as a reducing agent with overfire air for reducing NOx emission, a process known as reburning. Figure 1 shows the concept of syngas cofiring in an existing boiler and how syngas cofiring reduces NOx through the reburning process. A gasification process for solid fuel is required to establish a syngas cofiring system for an existing boiler. Low-grade fuels such as solid waste or biomass are fed to the gasifier. The syngas from the gasification process is mainly composed of carbon monoxide, hydrogen, and some light hydrocarbons together with carbon r 2011 American Chemical Society

dioxide and nitrogen. For an air-blown gasifier, most of the syngas is composed of nitrogen; therefore, the calorific value of the syngas is usually less than 4 MJ/Nm3, while the value for syngas from an oxygen-blown gasifier is 4
12 MJ/Nm3 or more. The syngas produced from the gasifier needs to be cleaned, but the requirement of cleanness for syngas cofiring is not as high as it is for other applications when producing electricity with a gas engine. The cleaned syngas is then introduced to the host boiler through a gas burner or nozzles. Injecting syngas above the burner establishes conditions for reduction. In other words, a substoichiometric condition will be set up in the “reburning” zone. Subsequently, when flue gas mixes with the syngas in the reburning zone, NOx undergoes a reduction. The combustible species in the mixed gas are completely burnt-out by overfire air in the burn-out zone. Many experimental and simulation studies have been conducted in regard to reburning hydrocarbon gas fuel through which its reaction mechanisms have been well established. Wendt et al. successfully reduced NOx by injecting secondary fuel downstream of the primary combustion zone.1 Takahashi et al. applied the method to an industrial furnace and reported that NO was significantly reduced.2 Folsom et al. reburned hydrocarbon fuel in a lab-scale combustion system and reported that NOx emission was reduced by 60%.3 Furthermore, they successfully reduced Received: February 16, 2011 Revised: May 4, 2011 Published: May 17, 2011 2460

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Figure 1. Diagram of the syngas cofiring and reburning in an existing boiler.

NOx in a pulverized coal boiler by 55
65%.3,4 Additional research entails parametric studies on the reburning process and mechanisms related to conventional hydrocarbon gas fuel.5
9 Recently, studies on direct applications of solid fuels as a reburn fuel have been performed10
16 in the laboratory and on pilot-scale combustion systems. However, syngas cofiring results or the application of the syngas as a reburning fuel to combustion systems are insufficient.17 Further research reported the cofiring and reburning of various gases, including COG (coke oven gas), BFG (blast furnace gas), and biogas.18,19 Certain negative effects result when syngas cofiring is applied to commercial boilers. Combustion instability can occur because the heating value of syngas is much lower than that of conventional gas fuel and solid fuels. Consequently, the thermal efficiency of the boilers decreases due to the decrease in radiative heat transfer in the furnace. Furthermore, CO and H2, which are the major constituents of the syngas, less effectively reduce NOx during the reburning process. The CO reburning mechanism impacts NOx reduction more weakly than when hydrocarbon fuel is used. Moreover, hydrogen as a reburn fuel is known to be ineffective in NOx reduction because only hydrocarbon radicals are involved in the reburning process.20 Authors of this paper previously studied syngas cofiring.21,22 And in these studies, the NOx levels were not significantly lowered because the experimental conditions surrounding the NOx levels were irrelevant to the reburning process. This study focused on the possible application of syngas cofiring and reburning to industrial and/or power boilers. Syngas cofiring and reburning was applied to pilot- and commercial-scale combustion systems. Subsequently, effects of syngas cofiring on combustion characteristics, thermal efficiency, and NOx reduction were evaluated for the systems. Previous syngas cofiring studies were incorporated in this paper to complement the current work.21,22 Experimental results were analyzed in detail in order to evaluate the effects of syngas cofiring and reburning on combustion performance, thermal efficiency, and emissions of pollutants formed during the combustion process.

’ EXPERIMENTAL APPARATUS Figure 2 shows the diagrams of the experimental rigs: a watertube boiler with a single heavy oil burner and a vertical furnace

Figure 2. Schematic of the test facilities: (a) single burner test facility (a commercial water-tube boiler); and (b) multiburner test facility (a vertical furnace with refractory).

with multi heavy oil burners. All test rigs contained a fuel supply system for kerosene and heavy oil. In addition, an electric heater was installed in each system to lower the viscosity by preheating the heavy oil. The water-tube boiler was scaled at 0.7 MWth. Twelve holes for syngas injection were installed and several ports among those were selected for cofiring the syngas. A commercial heavy oil burner was used for the experiment. The air fan was separated from the burner in order to control the air flow rate more easily. Four R-type thermocouples were installed in the center of the flame along the axial direction to measure temperature distribution in the boiler, and a K-type thermocouple was installed to monitor temperature at the exit of the boiler. The vertical furnace contained 2  2 commercial heavy oil burners, which were installed horizontally in an opposite firing mode. A small gap existed at the burner in order to avoid direct interference of the opposite flames at the front and rear walls. Ports for syngas cofiring were installed just above the burner. Nozzles for overfire air injection were installed considering the residence time of the syngas in the reburning zone. The reburning zone is defined as the zone between syngas injection and overfire air. Three R-type thermocouples were installed to measure the vertical temperature distribution in the boiler, and a K-type thermocouple was installed to monitor temperature at the exit of the boiler. Primary air and overfire air flow rates were 2461

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Table 1. Compositions of the Main Fuel and the Co-Fired Syngases main fuel wt %

syngas

heavy oil

vol (%)

syngas 1

syngas 2

syngas 3

C

85.50

H2

7

27

34

H

11.67

CO

15

23

22

O N

0.12 0.20

CH4 N2

3 75

10 22

3 33

S

2.43

CO2

0

18

others

0.08

LHV (MJ/Nm3)

3.7

9.4

9 7.3

inner diameters of 25.4 mm (1 in.) each were installed in the water-tube boiler, as shown in Figure 2a. A maximum of six injection ports were used for the water-tube boiler’s syngas cofiring experiment because a single hole cannot accommodate the whole flow rate of syngas. Figure 2b shows the numbers and locations of the main burners, syngas injection ports, and overfiring air ports for the vertical furnace with multi burners. Syngas was injected through four holes with inner diameters of 100 mm during the opposite firing mode, and overfire air was supplied to the upper part of the furnace through five nozzles with inner diameters of 25.4 mm (1 in.) each, which were installed in a staggered array.

Figure 3. Locations of ports for syngas injection and temperature measurement: (a) single burner test facility (a commercial water-tube boiler); and (b) multiburner test facility (a vertical furnace with refractory).

controlled by inverters with reference of the flowmeter installed in each oxidizer stream. For all cases, a gas analyzer was used to monitor gas compositions, such as those of O2, CO2, CO and NOx, at the exit of the boiler and the furnace. All real-time temperature and gas composition data were collected by a data acquisition system. A gas mixture composed of CO, H2, CH4, and N2 was used during the low-calorific syngas cofiring experiment. A large-scale partial oxidization process without a catalyst was used for the simulation of high-calorific syngas (>6 MJ/Nm3). LNG was partially oxidized with pure oxygen and the produced syngas was transported and supplied to the boiler or the furnace, boosted by a ring blower after a cryogenic dehumidification process. A stream of the syngas was distributed to several streams in the manifold. Figure 3 shows the port locations for syngas injection, the temperature measurement for the single burner test facility and the multiburner furnace. For syngas injection, 4  3 holes with

’ EXPERIMENTAL CASES AND CONDITIONS Table 1 shows the syngas compositions and heating values cofired in this study. Syngas 1 had a low calorific value which can be produced from an air-blown gasifier (please refer to ref 6). H2, CO, and CH4 were the combustible components in the syngas. The mole fractions of these components were selected based on previous work.23 The mixed gas was contained in gas cylinders. Usually syngas contains CO2 but it was replaced by N2 in this study, which makes it easier to produce the mixed gas. The replacement does not affect the combustion characteristics in the boiler or the furnace. Syngas 2 had the highest heating value and simulated the syngas from the oxygen-blown gasifier. Safety concerns exist regarding high hydrogen content syngas contained in gas cylinders. Thus, the syngas was prepared using noncataytic partial oxidation of natural gas with oxygen-enriched air. Syngas 3 had a medium calorific value, and could also be produced from an oxygen-blown gasifier. It was also prepared by noncatalytic partial oxidation of LNG with oxygen-enriched air. Syngases 2 and 3 were dehumidified by a cryogenic demister; thus, the steam composition in the syngas was negligible. Table 2 shows syngas cofiring in the water-tube boiler and the vertical furnace. In essence, the cofiring was performed by varying the thermal input and heat replacement. The reference case for the water-tube boiler containing a single boiler entailed a 100% heat input through heavy oil. The total heat input was 698 kW for all cases. 10% Heat replacement and 20% heat replacement initiated by syngas cofiring were tested for both Syngas 1 and Syngas 2. Complete combustion of the syngas in a boiler or furnace also depended on the location of the injection port. Significant pressure drops limited the design of the tube diameters and the flow rates. Thus, three injection ports were used for 10% heat replacement experiment, and six injection ports were used for the 20% heat replacement experiment. Injection of the syngas to the various locations was tested before the experiments. We 2462

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Table 2. Descriptions of the Co-Firing and Reburning Experiments main fuel heat input (kW)

syngas no.

heat input (kW)

equivalence ratio flow rate (Nm3/h)

injection port (#)

burner zone

reburn zone

total

water-tube boiler with single burner S-ref

698

-

-

-

S1-1

628

1

70

135

-

1.20

-

5, 6, 7

1.21

-

1.20

S1-2

558

1

140

67

1.21

1, 2, 5, 6, 9, 10

1.23

-

1.23

S2-1

628

2

70

53

5, 6, 7

1.21

-

1.21

S2-2

558

2

140

27

1, 2, 5, 6, 9, 10

1.21

-

1.21

M-ref

847

1

-

-

1.18

-

1.18

M-1 M-2

762 678

1 1

85 170

all all

1.17 1.20

-

1.17 1.20

MR-ref

1580

3

-

-

all

1.13

-

1.13

MR-1

1580

3

550

886

all

1.13

0.84

1.13

MR-2

1580

3

550

886

all

1.08

0.79

1.13

furnace with multi- burners

observed that the syngas did not undergo complete combustion when injected downstream of the boiler (Ports 3, 4, 8, 11 and 12) or the furnace. Combustion was not completed because the injected syngas did not have enough time to mix and react with the combustion air. Regarding the cofiring experiment in the furnace with multiburners (Cases M-ref, M-1, and M-2), only Syngas 1 was used to investigate the combustion characteristics for the cofiring of low-calorific syngas. Heat replacements of 10% and 20% due to the syngas were also tested in the vertical furnace. The total heat input was also maintained constant (847 kW) and no overfire air was supplied. However, the total input was not maintained constant for the cofiring and reburning experiment in the furnace containing the multiburners (Cases MR-ref, MR-1, and MR-2) because we were concerned about the thermal damage of the furnace by heat concentration to the wall near the burners, in the reference case. Therefore, the heat input by the main fuel was maintained constant (1580 kW) and the heat input by syngas cofiring was 550 kW for the cofiring cases (Cases MR-1 and MR-2). In cases MR-ref, MR-1, and MR-2, the equivalence ratio in the burner zone was the same as the total equivalence ratio; but, the ratio in the reburn zone was substoichiometric. In other words, only the reburning effects were investigated in Case MR-1. Meanwhile, in Case MR-2, the equivalence ratio in the burner zone was smaller than the total ratio. In other words, the amount of combustion air supplied to the main burners also decreased, making the equivalence ratio in the reburn zone smaller than that of Case MR-1. Therefore, for Case MR-2, the effects of both air staging and fuel staging (reburning) were investigated. In all cases, the burners initially operated with kerosene as the main fuel. The fuel was subsequently switched to heavy oil after the kerosene flames were stabilized. Heavy oil was preheated to 90 °C; but, in cases MR-ref, MR-1, and MR-2, the preheating temperature was varied in a periodic manner because the heaters were operated by an on/off control logic, which can cause changes in the amount of the fuel supplied to the burners.

’ RESULTS AND DISCUSSION Effects on Temperature Distribution in the Combustion System. Figure 4 shows the time history of the centerline

-

Figure 4. Temperature distribution in the water-tube boiler containing the single heavy oil burner for various syngas cofiring heat replacements.22

temperatures for various heat replacements caused by syngas cofiring when the syngas with a low heating value (LHV: 3.7m MJ/Nm3) was injected into the water-tube boiler with a single heavy oil burner. Temperatures were measured at x = 1100, 1700, 2300, and 2900 mm along the burner centerline, and, in the reference case (Case S-ref), the temperature decreased as the measurement location continued downstream. The maximum temperature was ∼900 °C at x = 500 mm, which was the nearest point from the flame root. This implies that the reaction was most active at that point. Syngas injection was initiated at t = ∼2000 s and the temperature at x = 500 mm decreased sharply from ∼1000 to ∼700 °C for 10% heat replacement, and further to ∼600 °C for 20% heat replacement. At x = 1100 mm, the temperature was ∼850 °C for the reference case (Case S-ref). This temperature decreased to ∼750 °C for 10% heat replacement (Case S1
1) and to ∼650 °C for 20% heat replacement (Case S1
2). The temperature at x = 1100 mm during the 20% heat replacement experiment was higher than the temperature at the same point for the 10% heat replacement experiment. This indicates that the major reaction zone could be shifted downstream during syngas cofiring. The temperatures at 2463

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Figure 6. Time-averaged temperature distribution in the furnace containing 4 burners for various syngas cofiring heat replacements.21

Figure 5. Time-averaged temperature distribution in the water-tube boiler with single heavy oil burner for various syngas cofiring heat replacements: (a) co-firing of Syngas 1 (3.7 MJ/Nm3) and (b) co-firing of Syngas 2 (9.4 MJ/Nm3).

x = 1700 mm and x = 2300 mm were not noticeably influenced by the syngas cofiring. Figure 5 shows the time-averaged temperature distribution in the water-tube boiler for various heat replacements by cofiring of Syngas 1 (a) and Syngas 2 (b). In the reference case, the temperature decreased as the measurement points moved downstream, indicating that the main reaction zone formed upstream from the combustion chamber. However, during syngas cofiring, the distribution yielded different profiles. Figure 5a illustrates the cofiring of the syngas with the low calorific value. During this case, the temperature distribution was flat for both 10% and 20% replacements, and the temperature near the exit of the chamber was higher during syngas cofiring than in the reference case (Case S-ref) as shown in Figure 4. This phenomenon seems to be more noticeable when the high heating value syngas was cofired. The temperature at x = 500 mm during syngas cofiring was much lower than that of the reference case. Furthermore, as the cofiring ratio increased, the temperature at that point significantly decreased. Meanwhile, the temperatures downstream of the boiler were much higher during syngas cofiring, indicating that the main combustion zone in the boiler shifted downstream. This shift potentially affects combustion stability.

The combustion zone shift seems also to be related to the aerodynamics of the boiler. When Syngas 1 was cofired, the flow rate of the syngas was higher by ∼2.5 times than that of Syngas 2 injection, implicating that the injection velocity was also higher. This causes very different mixing behaviors in the combustion chamber. The possibility of bad mixing exists for Cases S2-1 and S2-2 because of the injection velocity at points 2, 6, and 10 in Figure 3a. Further investigation of the flow and mixing characteristics in the combustion chamber are required. Such studies may be conducted through computational fluid dynamics (CFD) simulations. The experiments in the water-tube boiler revealed that the location of syngas injection should be selected very carefully in the design of a syngas cofiring system, with considerations of aerodynamics and mixing in the chamber. Figure 6 shows the time-averaged temperature distribution in the vertical furnace containing the refractory for various heat replacements by cofiring Syngas 1 (3.7 MJ/Nm3) in Cases M-ref, M-1, and M-2 (total heat input of 847 kW). The temperature profile along the vertical direction did not vary significantly. The temperature upstream of the furnace was ∼1050 °C and it gradually decreased because of the heat loss to the refractory wall. This was observed for all cases. This shows that the syngas cofiring did not significantly affect the temperature in the vertical furnace, even if the syngas had a very low calorific value. Figure 7 shows the difference in the configurations of the two combustion systems based on the aerodynamics in the chamber. As described in the previous section, vertical furnaces with burners generally have different configurations from the water-tube boiler used in this study. First of all, the flow patterns in the cofiring zone (or the reburn zone) are relatively simple because the direction of the flames is horizontal, but the main flow in the cofiring zone is vertical. For the water-tube boiler, recirculation zones exist that can be entrained to the flame as shown in Figure 7a, and the syngas completely burns out if it is injected to the recirculation zone. However, if it is injected downstream and directed to the exit of the chamber, the chance of the injected syngas mixing with the oxidizer significantly decreases. Therefore, the size of the recirculation zone must be carefully considered for the syngas injection points. Furthermore, the injection velocity for mixing is also an important parameter to be considered. Meanwhile, in the vertical furnace, the major stream traveled upward in a 2464

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Figure 8. CO and NOx concentrations at the exit of the water-tube boiler and the vertical furnace for various heat replacements by syngas of high heating value and low heating value.

Figure 7. Conceptual streamlines in the combustion chamber: (a) water-tube boiler with single burner, and (b) vertical furnace with multi horizontal burners.

manner similar to a plug flow in the region above the main burners. The injected syngas mixed with the mainstream. In this case, the possibility of a shift occurring in the main reaction zone was less possible because the main burners were stably operated. Effects on CO and NOx emission. Figure 8 shows timeaveraged CO and NOx concentrations at the exit of the combustion system for various ratios of syngas cofiring (Cases S-ref, S1-1, S1-2, S2-1, S-2, M-ref, M-1, and M-2). In this graph, results of the reburning experiments in the vertical furnace (Cases MRref, MR-1, MR-2) were not included because the NOx concentration showed different behaviors. In all the experiments the trend was stable and the time-averaged concentrations exhibited meaningful trends. First, the concentration of CO slightly increased during the water-tube boiler experiments, but remained in a tolerable range (