Copyright 1991 by ASME

Transcription

1 THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS 345 E. 47 St., New York, N.Y G'T-26 05) The Society shall not be responsible for statements or opinions advanced in papers or in d cession at meetings of the Society or of its Divisions or Sections. or printed in its publloations Discussion is printed only if the paper is published in an ASME Journal Papers are available from ASME for fifteen months after the meeting. Printed in USA. Copyright 1991 by ASME Design and Operating Experience of Selective Catalytic Reduction Systems for NO X Control in Gas Turbine Systems S. M. CHO and A. H. SELTZER Foster Wheeler Energy Corporation, U.S.A. and Z. TSUTSUI Ishikawajima-Harima Heavy Industries Company, Japan Abstract The design and operating experience of the Selective Catalytic Reduction (SCR) systems for denitrification of flue gas in utility and industrial gas turbine applications is presented. The paper will discuss the general SCR design approaches and the effects on the NOx removal efficiency of various design and operating parameters such as gas temperature, velocity and composition, NOx content, catalyst material and type, quantity of ammonia injected, acing, and pressure drop limitation. Two different types of ammonia injection methods (namely, anhydrous and aqueous ammonia injections) and attendant ammonia injection control schemes are described. A brief summary of SCR operating experience with power-generating gas turbines and process heaters/boilers concludes the paper. Nomenclature DH = hydraulic or equivalent diameter f K m Re SV V n p p = Fanning friction factor = activity constant = molar ratio of ammonia to NOx = Reynolds number = space velocity = gas velocity = NOx removal efficiency = gas viscosity = gas density Introduction The combustion of fossil fuels such as coal, oil, industrial or natural gas, produces environmentally hazardous substances including nitrogen oxide (NO) and nitrogen dioxide (NO 2 ). Nitrogen oxide and nitrogen dioxide are collectively called NOx. In the normal combustion process of fossil fuel, the major portion of NOx is NO. Selective Catalytic Reduction (SCR) is a process in which NOx is removed from the flue gas stream by the injection of ammonia (NH ) into the flue gas and subsequent cheftical reaction in the presence of catalyst; namely, 4NO + 4NH N 2 + 6H2 0 (1) 6NO + 4NH 3 ; 5N 2 + 6H 2 0 (2) 2NO 2 + 4NH N (3) 6NO 2 + 8NH 3-7N H 2 O (4) NO + NO 2 + 2NH 3-2N (5) The results of SCR performance tests in real applications indicate that the first chemical reaction is the dominant reaction process. Ishikawajima-Harima Heavy Industries Company (IHI) of Japan has developed various types of SCR catalysts which are mostly based on titanium, tungsten and vanadium elements. IHI has successfully applied their SCR denitrification systems in Japan and Europe over the past decade. In the United States, Foster Wheeler Energy Corporation (FWEC), under a license agreement with IHI, has been marketing SCR systems. FWEC designs and supplies the entire SCR system except for the catalyst which is supplied by IHI. Presented at the International Gas Turbine and Aeroengine Congress and Exposition Orlando, FL June 3-6, 1991

2 The primary factors that affect the SCR design are types of fuel and dust loading, flue gas conditions, and NOx removal efficiency requirement. Depending upon dust loading, the flue gas is classified as either "clean" or "dirty" gas. Natural or industrial gas is considered as a "clean" gas. FWEC/IHI have designed SCR systems for both clean and dirty gas applications. However, since FWEC/IHI gas turbine appli- FLUEC^, cations have been mostly with clean gases, emphases are placed on the design and operating experience of clean as SCR systems in this paper. The paper will discuss general SCR design approaches, effects of major design and operating parameters, ammonia injection and control schemes, and actual operating experience. ELEMENT SCR Reactor Design The SCR reactor is a container that houses catalysts. It is an assembly of catalyst baskets, each basket consisting of squareshaped elements that are made of homogeneous ceramic honeycomb catalyst cells. Typical IHI catalyst baskets, elements and cells are shown in Figure 1. The standard cell sizes are a 3.7 mm cell pitch with wall thickness of 0.5 to 0.65 mm, a 5.0 mm cell pitch with wall thickness of 0.8 to 1.0 mm, and a 7.5 mm cell pitch with wall thickness of 1.05 to 1.40 mm. For gas-fired turbine applications, a 3.7 mm pitch size is usually used to minimize the overall reactor size. In most applications, the reactor sizes are larger than the duct sizes and therefore transition diverging/converging ducts are used around the reactor. A typical SCR configuration is also shown in Figure 1. For given gas conditions, the performance of an SCR system depends upon the choice of catalyst, the area of catalyst surface exposed to the flue gas, the residence time of the gas in the reactor, and the amount of ammonia injected upstream of the reactor. Table 1 presents different types of IHI catalysts with their compositions and principal application areas. For gas-fired turbine applications, H-T, L-A, and L-T catalysts are normally used, and their characteristics are shown in Table 2. The H-T catalyst is for a high-temperature application which is perhaps suitable immediately downstream of the turbine exhaust, the L-A catalyst is for an intermediate-temperature application which is normally used downstream of a heat recovery boiler bank, and the L-T catalyst is for a low-temperature application which may be used downstream of a heat recovering economizer. The major components of the IHI catalysts are titanium dioxide (TiO ), tungsten trioxide (W0 1 ) and vanadium pentoxide (V 0 ). Vanadium pentoxide is very effe9t 5lve in maintaining high denitrification efficiency at low temperatures, however it causes thermal deterioration by enhancing titanium dioxide sintering at high temperatures. For this reason, as the gas temperature increases, the V O content is decreased and a substit>1ta active catalyst component, tungsten trioxide (WO 3 ), is Fuel Gas, oil CELL Fig. 1 SCR System Configuration and Catalyst Geometry Table 1 IHI Catalysts, Compositions and Applications Catalyst Type H-T L-A L-T Catalyst Composition Ti02-WO3 Ti02-W03-V205 Ti02-WO3-V205 Main Applications Gas, Low Sulfur Oil M-lA Ti02-W03-V205 Low Sulfur Oil M-2A Ti02-W03-V205 Medium and High Sulfur Oil Coal CH-1A Ti02-W03-V205 High-Dust SCR CH-2A Ti02-WO3-V2O5 High-Dust SCR, High Sulfur Oil CL-3 Ti02-WO3-V205 Low-Dust SCR Table 2 Clean Gas Catalyst Characteristics Catalyst Type H-T L-A L-T Shape Gas Conditions Honeycomb (pitch 3.7 mm, 5 mm) Temperature C C C Dust Loading SO x Content Catalyst Compositions Applications Applicable Immediate) After Gas Turbines Negligible Negligible TiO2 W03 Others V205 Applicable to Heat Recovery Steam Generator Systems

3 increased. Note that no vanadium pentoxide is contained in the H-T type high temperature catalyst. EFFICIENCY Once the catalyst is chosen, the performance of the SCR reactor depends significantly upon the "diffusion" surface area of the catalyst known as a specific surface area. This area is usually specified in square meters of surface per gram of catalyst mass. The larger the specific surface area, the better the SCR performance. Since the specific surface area is all areas of the catalyst for gas diffusion including those areas of all pores, it is characteristic of the catalyst, but not a convenient design parameter. More practical design or performance parameters are those that combine the specific surface area with the residence time of the gas through the catalyst layer. They include the following parameters: Area velocity (AV) that is the volumetric gas flow rate divided by the geometric catalyst contact surface area (m/hr); Space velocity (SV) that is the volumetric gas flow rate divided by the "supgrficial" volume of the catalyst (hr ); and Linear velocity that is the volumetric gas flow rate divided by the flow area of the gas through the catalyst (m/hr) which is inversely proportional to the residence time of the gas through the catalyst. As is expected, the above velocity parameters are related to one another. The most "popular" and convenient velocity parameter for SCR reactor design and performance evaluation is the space velocity (SV). As indicated in Equations (1) through (5), the denitrification of flue gas requires the supply of ammonia. According to the most dominant reaction process, Equation (1), one mole of ammonia is required for one mole of nitrogen oxide (NO) for stoichiometric reaction. Therefore, the larger the ammonia injection, the higher the probability of denitrification reaction and consequently the better the SCR performance, although excessive ammonia injection may result in deleterious side effects as will be discussed later. The denitrification, or NOx removal, efficiency (n ) of an SCR reactor is defined as the quantity of NOx removed divided by the quantity of NOx in the inlet gas stream. This efficiency depends upon various parameters as mentioned previously. Based on reaction kinetics and laboratory and field test data, one may express the NOx removal efficiency in terms of the space velocity (SV) and the molar ratio of ammonia to NOx (m) as follows: n = in (1 - e-k/sv )(6) where K is an activity constant which is a function of many factors including the catalyst composition, diffusion characteristics of ammonia and NOx in the gas stream and catalyst layer, oxygen concentration, moisture concentration, gas temperature, gas velocity, and catalyst aging. Figure 2 shows typical characteristic curves for the NOx removal efficiency in terms of the SPACE VELOCITY SING Fig. 2 Typical Performance Characteristics of Catalyst: NOx Removal Efficiency vs. Space Velocity With NH 3/NOx Mole Ratio as Parameter. space velocity and the molar ratio of ammonia to NOx. In general the less the space velocity and the larger the molar ratio of ammonia to NOx, the higher the denitrification efficiency. From the curves of the type shown in Figure 2, the SCR reactor can be sized. The NOx removal efficiency is usually determined based on the customer specification for the SCR performance requirements. The molar ratio of ammonia to NOx is set to be larger than the NOx removal efficiency value, but not too large to exceed the specification limit of residual ammonia present in the downstream flue gas. Knowing the values of n and m, one can read the required value of the space velocity (SV) from the curves of Figure 2. The superficial volume of the catalyst is then determined by the volumetric gas flow divided by the required space velocity. Care should be exercised in preparing the physical design of the SCR reactor, particularly for the gas-stream pressure drop. The linear velocity and the length of the catalyst layer should be sized in such a way that the most economical system is obtained. A typical SCR system pressure drop is in the order of 50 mm to 100 mm water. Because of relatively small catalyst cell dimensions, the state of gas flow inside the reactor is typically laminar flow. The Fanning friction factor (f) for laminar flow through a square-shaped honeycomb cell may be obtained from the following formula of Kays and London (1964): f = 14.2/Re (7)

4 where Re = Reynolds number = P VD H /A p = gas density V = linear velocity of gas DH= hydraulic or equivalent diameter of flow cross-section p = gas viscosity If the state of flow is turbulent, one may resort to the Moody diagram for friction factors (Streeter and Wylie, 1975). EFFICIENCY m= 1. 0 ^^^ m= 1. 2 m=1.0 m=1. 0 ^\ L T I. A Fi T Effects of Operating Parameters The characteristic curves shown in Figure 2 are corrected for the effects of various operating parameters. Only significant parameters are discussed in the following. Flue Gas Temperature: This is perhaps the most important operating parameter that influences the choice of the catalyst. Figure 3 shows the qualitative effect of gas temperature on the NOx removal efficiency for the L-T, L-A and H-T catalysts. Note that the NOx removal efficiency peaks at a certain temperature for each of these catalysts and therefore the choice of the catalyst must consider the range of operating load temperatures in the plant. Oxygen Concentration: As indicated in Equations (1) and (3), oxygen is needed in the flue gas. Figure 4 shows the general effect of oxygen concentration on the catalyst volume. The effect is significant only when the oxygen content in the flue gas is less than approximately 2 to 3%. Water Vapor Concentration: The water vapor content in the flue gas has an adverse effect on the NOx removal efficiency as shown in Figure 5. The more the water vapor content, the less the catalyst performance. Aging Effect: The performance of catalyst tends to deteriorate with time. Figure 6 presents a typical efficiency-vs-time history curve. The rate of deterioration is large in the beginning of operation and becomes rather gradual after initial settlement. Ammonia Slip: Theoretically, the quantity of ammonia to be injected in the SCR system should be based on a molar ratio of ammonia to NOx, which is numerically the same as the NOx removal efficiency. However, since ammonia is not completely uniformly mixed with NOx, more than the theoretical quantity is injected. An excess residual ammonia in the downstream flue gas is known as an ammonia slip, usually specified in parts per million (ppm). The ammonia slip may be calculated as: Space Velocity. constant) GAS TEMPERATURE NH,/NOx mole ratio Fig. 3 NOx Removal Efficiency vs. Temperature CATALYST PERFORMANCE CORRECTION FACTOR OXYGEN CONCENTRATION IN FLUE GAS Fig. 4 Catalyst Performance Correction Factor for Oxygen Concentration in Flue Gas CATALYST PERFORMANCE CORRECTION FACTOR Ammonia Slip (ppm) = (m - n )- (Inlet NOx in ppm) (8) The above expression is valid when the gas temperature is below approximatey 370 C. At higher temperatures, ammonia tends to be oxidized. WATER VAPOR CONTENT Fig. 5 Catalyst Performance Correction Factor for Water Vapor Content in Flue Gas

5 The NOx removal efficiency increases with an increasing ammonia slip and reaches an asymptotic value after a certain quantity of ammonia slip as indicated in Figure 7. This means that there is a limit for the effect of excess ammonia in removing NOx. However, if the flue gas contains SO excess ammonia slip has a deteriorating effect; namely, SO 2 in the flue gas can be converted to SO based on the conversion rate which is dictated by the catalyst selection. When combined with ammonia and water vapor, SO may form ammonia sulfates as shown below: PERFORMANCE FACTOR SO 3 + NH 3 + H2 O -^ NH4 HSO4 (9) SO 3 + 2NH 3 + H 2 O (NH4)2SO4 (10) Temperature is an extremely important variable in the formation of sulfates. The lower the temperature, the higher the probability of sulfate formation. Ammonia sulfates are "sticky" substance which can deposit on the downstream equipment, causing pluggage and deteriorating equipment performance. Experience indicates that when the ammonia slip is less than 10 ppm and the SO concentration is less than 5 ppm, tha probability of ammonia sulfate formation is practically nil (unless the gas temperature is extremely low in the order of 200 C.) For gas turbine applications, one tends to use natural or industrial gas and low sulfur oil as the combustion fuel, and therefore the deteriorating effects discussed above are not expected to occur. Ammonia Injection Systems and Control Schemes The traditional method of ammonia injection into the flue gas stream utilizes anhydrous ammonia that is "pure" ammonia without being diluted with any other substance such as water. In the anhydrous ammonia injection system, liquid ammonia is normally stored in a pressurized tank. It is piped to a heater (typically, electric heater) where liquid ammonia vaporizes, and ammonia vapor is next routed into a mixing chamber where ammonia vapor mixes with ambient air supplied by a fan or blower in a pre-determined ratio between ammonia and air quantities. The ammonia-air mixture is then directed to the distribution grid system for subsequent injection into the flue gas stream at a location upstream of the selective catalytic reduction reactor. The above anhydrous ammonia injection system is schematically shown in Figure 8. However, anhydrous ammonia is toxic and hazardous. It has a high vapor pressure at ordinary temperature, and thus requires generally thick shell storage tank, piping and vessels. Its release to the atmosphere may create hazardous environment, which makes transportation of pure anhydrous ammonia less desirable from a safety standpoint. An alternative approach for ammonia injection into the flue gas stream is the utilization of aqueous ammonia (NH OH) which is a mixture of ammonia and wat er. Since ammonia is diluted with "benign" water, aqueous ammonia is less hazardous. A typi- OPERATING TIME Fig. 6 Typical Catalyst Performance Factor vs. Time EFFICIENCY f 43 SLIP (PPM) Fig. 7 Effect of Ammonia Slip on NOx Removal Efficiency cal industrial grade aqueous ammonia contains approximately 30% ammonia and 70% water. The ammonia-water mixture of the above percentages is safely transported on U.S. highways and it also has a nearly atmospheric vapor pressure at ordinary temperature. Figure 9 shows a schematic of the aqueous ammonia injection system. It contains the two trains of piping network; namely, one for aqueous ammonia and the other for air. They are joined in a vaporizer vessel. Aqueous ammonia that is stored at ordinary temperature in a tank is pumped, metered and sprayed into the vaporizer vessel. Ambient air is drawn by a blower, heated by a heater (typically, electric heater), and enters the same vaporizer.

6 The heart of the system is the vaporizer that has unique design features. It consists mainly of a central downcomer pipe and the shell section which is packed with metallic pall rinds. The air, heated typically to C, enters through the top of the central downcomer pipe and the aqueous ammonia is sprayed via a spray nozzle(s) into the air stream at the top of the central downcomer pipe. Air and ammonia flow co-currently down the central downcomer pipe, make a 180-degree turn, and flow upward through a bed of metallic pall rings. In this bed of pall rings, the cold aqueous ammonia and the hot air mix together, and direct-contact heat transfer takes place from the hot air to the cold aqueous ammonia, thus vaporizing liquid ammonia and water. The presence of the pall rings promotes the rate of the mixing and vaporizing processes. The conditions of the air entering the vaporizer are such that there is sufficient energy to bring the resulting temperature of the mixture (ammonia vapor, water vapor and air) to superheated state. The length of the pall ring bed is designed to provide sufficient residence time for the gases to mix and transfer energy among them so that the mixture exiting from the vaporizer is at a uniform, equilibrium temperature. The central downcomer pipe of the vaporizer is internally lined for corrosion, erosion and thermal-shock considerations. The pall ring bed is sandwiched between the upper and lower perforated plates. A diffuser is placed upstream of the aqueous ammonia spray, nozzle to eliminate the direct impact of air flow on the nozzle head. F FAN Fig. 8 Anhydrous Ammonia Injection System AQUEOUS AMMONIA AMBIENT AIR The ammonia vapor-water vapor-air mixture from the vaporizer is routed to the injection grid network for subsequent injection of the mixture into the flue gas stream. The injection grid network consists of a number of pipes connected in parallel with each pipe containing several orifice holes. The pipes and holes are sized to provide uniform ammonia flow distribution for the flue gas that is to be denitrified. BACK FLOW VALVE ^^ PUMP AL GIP. LOPE TANK FAN FILTER^ I L METEfl ^ FLOWI II ELECTRIC HEATER 1 _._.. CONTROL VALVE INJECTION GRID FLUF GAS PALL RINGS Fig. 9 Aqueous Ammonia Injection System (U.S. Patent Being Applied) J VAPORIZER The aqueous ammonia injection system with the pall ring vaporizer, as described above, provides a unique and safe way of injecting gaseous ammonia, originating from aqueous solution, into the flue gas stream for reduction of the NOx content. The ammonia injection process is regulated by a programmable controller. The controller regulates a flow control valve which adjusts the ammonia flow rate (either SCR SCR

7 anhydrous or aqueous). The base ammonia injection rate is set by feed-forward signals representing (turbine) load and SCR flue gas inlet temperature. This base ammonia injection rate is continuously updated. Fine tuning of the ammonia injection rate is accomplished via a feed-back signal measuring SCR outlet NOx concentration. Based on detailed knowledge of the catalyst performance, sophisticated control equations are used which integrate the feed-forward and feed-back signals. This results in the following benefits: minimum ammonia consumption and slip, fast accurate response to changing loads, No overshoot or undershoot, no system oscillation, and tunability to meet expected temperature and/or load swings. Operating Experience Originally IHI SCR systems were developed to serve large capacity utility boilers in Japan. Now, most of utility boilers in Japan have been equipped with SCR units and IHI has delivered them for as many as 36 domestic boilers since IHI SCR units have also been delivered to 26 West German sites since 1985 by L & C Steinmuller. In the United States, Foster Wheeler Energy Corporation, under a license agreement with IHI, has supplied 19 SCR systems since The combined IHI/FWEC experience includes over 80 SCR units for utility/process boilers, reformer/process heaters, and gas-turbine power generators. All types of fuels have been used including natural gas, industrial gas, crude oil, heavy oil, and a variety of coal. Table 3 presents a partial list of the SCR units that are applicable to clean-gas, gas-turbine/heater applications. Units 1 through 11 are U.S. installations (all in the State of California) and have been operating trouble-free since initial startups. As a matter of fact, most of these units are overperforming so that the NOx contents at the reactor outlets are much lower than originally designed, and furthermore, the original catalysts have not been replaced. Note that Units 6 to 8 are for gas turbine systems and that, in Units 10 and 11, the traditional anhydrous ammonia injection system is replaced by the aqueous ammonia injection system. Units 12 through 20 are Japanese installations. Unit 12 is for a gas turbine in cogeneration application and characterized by the feature that ammonia solution is injected instead of ammonia gas and that catalysts are formed of corrugated plates coated with catalyst material on them. Table 3 Clean Gas SCR Operating Experience Unit No. Plant Location Process Type Startup Date Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Calif. Reformer Process Reformer Heater Coker Gas Gas Gas Process Boilers Heater Heater Heater Heater Turbine Turbines Turbines Heater (4 units) 11/82 8/83 1/86 7/86 8/86 2/88 3/89 2/90 10/90 9/91 Fuel Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Fuel Gas Clean 11ppm SO 2 Clean 17ppm 1ppm S0 3 SOx Clean Clean Clean Clean 23ppm 12ppm SOx SOx Gas Flow 44,000 (Nm /hr) 12, ,000 25,000 55, , , , ,000 93, ,000 Gas Temp 360 ('C) Flow Vertical Direction Upward Vertical Vertical Vertical Downward Upward Upward Vertical Hori- Upward zontal Horizontal Horizontal Vertical Vertical Downward Downward Pressure Drop (mm Water) Catalyst Pitch (mm) Ammonia Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Aqueous Injection System Inlet NOx (ppmvd) 160 NOx Removal Eff. (%) 7

8 Table 3 - Continued Unit No Plant Location Calif. Japan Japan Japan Japan Japan Japan Japan Japan Japan Process Heater Gas Gas Gas Gas Gas Gas Gas Gas Gas Type Turbine Turbine Turbine Turbine Fired Fired Fired Fired Fired Cogenera- Cogenera- Cogenera- Boiler Boiler Boiler Boiler Boiler tion Plant tion Plant tion Plant (2 units) Startup 5/91 12/90 1/91 6/91 6/93 7/81 7/83 11/83 12/87 3/91 Date 7/88 Fuel Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Fuel Gas 7ppm SOx Clean Clean Clean Clean Clean Clean Clean Clean Clean Gas slow 52,000 48, , , ,000 1,700,970 1,603,000 2,401, ,000 1,600,000 (Nm /hr) Each Gas Temp ('C) Flow Vertical Vertical Hori- Hori- Hori- Hori- Hori- Hori- Hori- Hori- Direction Downward Upward zontal zontal zontal zontal zontal zontal zontal zontal Pressure Drop (mm Water) Catalyst N/A Pitch (mm) (Pellet Type) Ammonia Aqueous Aqueous Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Anhydrous Injection System Inlet NOx (ppmvd) NOx Removal Eff. (%) Unit 13 is for the workshop of a gas turbine manufacturer where the flue gas from gas turbine is first cooled by means of water spraying prior to the SCR unit. Units 14 and 15 are also for gas turbine coveneration plants and allowed to have a quite limited length of suction flue duct. Special consideration in design of flue is taken to obtain uniform distribution of ammonia gas in the flue section at the SCR reactor inlet. Units 16 through 20 are for gas-fired boilers that have been operating successfully. the determination of the catalyst volume were discussed. The traditional anhydrous ammonia injection scheme is being replaced by a more benign aqueous ammonia injection method utilizing a mixer/vaporizer vessel filled with metallic pall rings. All SCR units installed in the United States and Japan have been operating free of any significant problems. References Summary and Conclusions Kays, W. M., and London, A. L., 1964, The general design approaches for the SCR systems supplied by the Foster Wheeler-IHI Compact Heat Exchangers, McGraw-Hill Book Company team were described. The general effects of various design and operating parameters on Streeter, V. L., and Wylie, E. B., 1975, Fluid Mechanics, Mcgraw-Hill Book Co. 8