-
Post-Combustion NO, Control for Fired Equipment in General
Refinery Services
API RECOMMENDED PRACTICE 536 FIRST EDITION, MARCH 1998
American Petroleum
1_ Institute
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
Post-Combustion NO, Control for Fired Equipment in General
Refinery Services
Manufacturing, Distribution and Marketing Department
API RECOMMENDED PRACTICE 536 FIRST EDITION, MARCH 1998
American Petroleum Institute
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD-API/PETRO RP 53b-ENGL L97h 9 1732270 Ob08505 37
SPECIAL NOTES
API publications necessarily address problems of a general
nature. With respect to partic- ular circumstances, local, state,
and federal laws and regulations should be reviewed. API is not
undertaking to meet the duties of employers, manufacturers, or
suppliers to
warn and properly train and equip their employees, and others
exposed, concerning health and safety risks and precautions, nor
undertaking their obligations under local, state, or fed- eral
laws.
Information concerning safety and health risks and proper
precautions with respect to par- ticular materials and conditions
should be obtained from the employer, the manufacturer or supplier
of that material, or the material safety data sheet.
Nothing contained in any API publication is to be construed as
granting any right, by implication or otherwise, for the
manufacture, sale, or use of any method, apparatus, or prod- uct
covered by letters patent. Neither should anything contained in the
publication be con- srued as insuring anyone against liability for
infringement of letters patent.
Generally, API standards are reviewed and revised, reaffirmed,
or withdrawn at least every five years. Sometimes a one-time
extension of up to two years will be added to this review cycle.
This publication will no longer be in effect five years after its
Publication date as an operative API standard or, where an
extension has been granted, upon republication. Status of the
publication can be ascertained from the API Authoring Department
[telephone (202) 682-8000]. A catalog of API publications and
materials is published annually and updated quarterly by API, 1220
L Street, N.W., Washington, D.C. 20005.
This document was produced under API standardization procedures
that ensure appropri- ate notification and participation in the
developmental process and is designated as an API standard.
Questions concerning the interpretation of the content of this
standard or com- ments and questions concerning the procedures
under which this standard was developed should be directed in
writing to the director of the Authoring Department (shown on the
title page of this document), American Petroleum institute, 1220 L
Street, N.W., Washington, D.C. 20005. Requests for permission to
reproduce or translate all or any part of the material published
herein should also be addressed to the director. API standards are
published to facilitate the broad availability of proven, sound
engineer-
ing and operating practices. These standards are not intended to
obviate the need for apply- ing sound engineering judgment
regarding when and where these standards should be utilized. The
formulation and publication of API standards is not intended in any
way to inhibit anyone from using any other practices.
Any manufacturer marking equipment or materiais in conformance
with the marking requirements of an API standard is solely
responsible for complying with all the applicable requirements of
that standard. API does not represent, warrant, or guarantee that
such prod- ucts do in fact conform to the applicable API
standard.
All rights reserved. No part of this work may be reproduced,
stored in a retrieval system, or transmitted by any means,
electronic, mechanical, photocopying, recording, or otherwise,
without prior written permission from the publisher: Contact the
Publishel; API Publishing Services, 1220 L Street, N.W, Washington,
D.C. 20005.
Copyright Q 1998 American Pemleum institute
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
FOREWORD
API publications may be used by anyone desiring to do so. Every
effort has been made by the Institute to assure the accuracy and
reliability of the data contained in them; however, the Institute
makes no representation, warranty, or guarantee in connection with
this publication and hereby expressly disclaims any liability or
responsibility for loss or damage resulting from its use or for the
violation of any federal, state, or municipal regulation with which
this publication may conflict.
Suggested revisions are invited and should be submitted to the
director of the Manufactur- ing, Distribution and Marketing
Department, American Petroleum Institute, 1220 L Street, N.W.,
Washington, D.C. 20005.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
CONTENTS
Page
...............................................................
1 SCOPE 1
2 APPLICABLE ENVIRONMENTAL REGULATIONS AND REFERENCES . . . . .
1 2.1 Environmental Regulations
.......................................... 1
U.S. Federal Regulations
............................................ 1 Environmental
Protection Agency (EPA) References ...................... 1
National Ambient Air Quality Standards
............................... 1 National Standards &
Publications .................................... 2
2.2 2.3 2.4 2.5
3 DEFINITIONS AND ABBREVIATIONS
................................... 2
Units of Reporting Emissions
........................................ 3
GUIDELINES FOR SELECTION
......................................... 3 Selective Non-Catalytic
Reduction (SNCR) ............................. 3 Selective
Catalytic Reduction ........................................ 4
4.4 Applications
...................................................... 5
.......................................................
.....................................................
3.1 Definitions 2 3.2 Abbreviations 2 3.3
4 4.1 4.2 4.3 Considerations 5
....................................................
5 DESIGN CONSIDERATIONS
........................................... 6
SNCR Systems Overview
........................................... 6 SCR Systems Overview
............................................ 17 Reactant Control
and Dilution System Components ..................... 17 Reactant
Injection System .......................................... 18
5.6 CatalystlReactor
.................................................. 18 Structures
and Appurtenances ....................................... 19
Refractories and Insulation
......................................... 19 Instrumentation and
Electrical Systems ............................... 19
Instrument and Auxiliary Connections
................................ 20 5.12 Shop Fabrication and Field
Erection .................................. 20 5.13 Inspection.
Examination and Testing .................................. 20
.......................................................... 5.1
General 6 5.2 5.3 5.4 5.5
5.7 5.8 5.9 5.10 Induced Draft Fan (IDF)
.......................................... 20 5.1 1
6 OPERATIONS DESCRIPTION
.......................................... 20 Selective
Non-Catalytic Reduction ................................... 20
Selective Catalytic NOx Reduction
................................... 21
6.1 6.2
APPENDIX A APPENDIX B
POST-COMBUSTION NO, CONTROL DATA SHEETS . . . . . . . . . .
25
NO, MEASUREMENT ...................................... 41
CALCULATION METHOD FOR CORRECTING
Figures 1 2 3 4 5
SNCR System Schematics Aqueous Ammonia
............................ 7 SNCR System Schematics Anhydrous
Ammonia .......................... 9 SNCR System Schematics Urea
Injection ............................... 11 SCR System Schematics
Aqueous Ammonia ............................. 13 SCR System
Schematics Anhydrous Ammonia ........................... 15
V
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD-API/PETRO RP 53b-ENGL 1798 M 0732270 Ob08508 54b
6
7
8
9
10
Formation Temperature of Ammonium Sulfate and Ammonium Bisulfate
for Various Concentrations of NH, and SO3
................................ 21 Catalyst Activity Profile
versus Time -An Example for a Paricular Situation
................................................. 22 NO, Reduction
versus Temperature for Different SCR Catalysts- Typical Example
................................................... 23 NO,
Reduction Efficiency versus Catalyst Space Velocity- An Example
Situation. .............................................. 23
?Lpical NO, Reduction Efficiency and Ammonia Slip
..................... 24
Tables 1 Comparison of Typical SNCR and SCR Systems
.......................... 1
vi
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD*API/PETRO RP 53b-ENGL 1778 R 0732270 0b085[17 482 I
Post-Combustion NO, Control for Fired Equipment in General
Refinery Services
1 Scoee ing of the reactant, but is often suitable for
retrofitting existing - . equipment for low or moderate NO,
reduction. SCR systems operate at a high reduction efficiency at a
lower temperature window than a SNCR system and are usually
selected for lowest NO, emission.
'" description, operation, maintenance, and test procedures of
post-combustion NO, control equipment for fired equipment in
general refinery service. It does not cover reduced NO, for-
This recommended practice covers the
mation through burner design techniques, such as flue gas
recirculation (FGR) and staged combustion. 2 Applicable
Environmental Regulations
and References 1.2 This document covers two of the methods of
post com- bustion NO, reduction: 2.1 ENVIRONMENTAL REGULATIONS
a. Selective Non-Catalytic Reduction (SNCR). b, Selective
Catalytic Reduction (SCR).
1.3 SNCR is a process where the addition of ammonia or urea into
the flue gas stream causes the oxides of nitrogen to convert to
nitrogen and water vapor. The basis for the selec- tion and
limitations of the SNCR systems are described in Section 4.1.
a. Local. b. State. c. National.
2.2 u.s. FEDERAL REGULATIONS a. CleanAirAct. b. Code of Federal
Regulations (CFR).
1.4 SCR is a process where the addition of ammonia into the flue
gas stream in the presence of a suitable catalyst causes the oxides
of nitrogen to convert to nitrogen and water vapor,
2.3 ENVIRONMENTAL PROTECTION AGENCY (EPA) REFERENCES
I
The basis for the selection of the variois catalyst types-are
described in Section 4.2.
1.5 Table 1 indicates the typical operating performance and
Units* limitations of both types of NO, duct ion systems. The
gas temperature range and difficulty in achieving proper
mix-
a. New Source perfomance Standuds 40 CFR 60 SubPm Db, Industrial
Commercial-Institutional Steam Generating
b. Alternative Control Techniques Documents 1993 NO, k~iss ions
from Process I-katers- c. National Ambient Air Quality
Standards.
1 reduction efficiency of SNCR is limited because of the
flue
Table 1 -Comparison of Typical SNCR and SCR Systems
Design Criteria SNCR SCR NO, Reduction Efficiency 40 - 75% O-%%
Temperature Window 870" - 1200C 165" - 600C
(1 600" - 2200F) (325" - 1100F) Reactant Ammonia or Urea Ammonia
Reactor None Catalytic Waste Disposal None Spent catalyst Therma
Efficiency Debit O - 0.3% 0% Energy Consumption LOW High-I.D. fan
Capitai investment Costs LOW High Plot Requirements Minor Major
Maintenance LOW 3 to 5 years Ammonia 1 NO, (Molar Ratio)
Urea / NO, (Molar Ratio) 0.5 - 0.75 Not applicable Ammonia Slip
5 to 20 ppmvd 5 to 10 ppmvd
Mechanical Draft Not required
1.0 - 1.5 (typical catalyst life) 0.8 to 1.2
Remfit E=Y Difficult Required
1
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD-API/PETRO RP 53b-ENGL L77 E 073227 Ob08510 I T 4 9
2 API PUEUCATION 536
2.4 NATIONAL STANDARDS & PUBLICATIONS
API Std 560 Pub1 534 Pub1 535
ASME Section V U B 31.3
Fired Heater for General Rejnery Services Heat Recovev Steam
Generators Burners for Fired Heaters
Boiler & Pressure Vessel Code Chemical Plant & Petroleum
Refinery Piping
3 Definitions and Abbreviations 3.1 DEFINITIONS
3.1.1 ammonium bisulfate and sulfate: Injecting ammonia or urea
into a flue gas stream containing sulfur tri- oxide forms these
compounds and causes fouling of heat transfer surface and increases
particulate emissions.
3.1.2 ammonia breakthrough: The point at which increasing the
NHJNO, molar ratio does not significantly reduce the amount of
NO,.
3.1.3 ammonia/NO, ratio: The molar ratio indicating the amount
of injected ammonia required to reduce the inlet NO, in the flue
gas stream.
3.1.4 ammonia slip: The amount of unreacted ammonia in the flue
gas stream after the reduction of the NO,, mea- sured in ppmvd
corrected to the standard oxygen level.
3.1.5 catalyst activity: Measurement of the NO, reduc- tion
performance (with time).
3.1.6 catalyst handling facilities: Device used for loading and
unloading of catalyst modules, usually a mono- rail and hoist.
3.1.7 catalyst matrix or substrate: Device coated or impregnated
by the active ingredients of the catalyst. The cat- alyst matrix
can be made from ceramic honeycomb, pellets, metal plates or
mesh.
3.1.8 catalyst module: A number of catalyst elements make up one
module.
3.1.9 catalyst space velocity: The quantity of flue gas (at
standard conditions) flowing per volume of catalyst per hour.
3.1.10 catalyst support: Structure within the reactor housing to
support the catalyst modules.
3.1.11 catalyst types: Active ingredients are vanadium oxide,
titanium oxide, platinum, or zeolite.
American Society for Mechanical Engineers, 345 East 47th Street,
New York, NY 10017.
3.1.12 cell density: Measurement of hole density in a honeycomb
catalyst matrix (cells per sq. cm [sq.ins.]).
3.1.13 dilution medium: Fluid (usually air, steam, or water)
used to disperse the reactant within the flue gas stream-also
referred to as a carrier.
3.1.14 injection grid: Consists of a series of distribution
pipes and injection nozzles located in the flue gas stream to
permit the correct mixing of the reactant and flue gas.
3.1.15 injection skid: Contains the equipment necessary for the
control and injection of the reactant (ammonia or urea), including
vaporizer or atomizer, dilution air fan, mixer, and control
valves.
3.1.16 NO,: General term used to describe all oxides of nitrogen
including nitric oxide (NO), nitrogen dioxide (NO,), and nitrous
oxide (N,O) For the purpose of emission calcula- tions NO, is
assumed to be nitrogen dioxide MW = 46.01.
3.1.17 reactant-ammonia anhydrous or aqueous: Used in the
majority of post combustion NO, reduction sys- tems. Industrial
anhydrous ammonia contains 99.5%.mini- mum by volume ammonia and is
injected as a vapor. Aqueous contains about 20 to 30% by weight
ammonia solution mixed with water and has to be vaporized or
atomized before inject- ing into the gas stream.
3.1.18 reactant urea: Used in some SNCR processes. Urea is
normally used as an aqueous solution containing about 50% urea by
weight.
3.1.1 9 reactor: The equipment housing including the cat- aiyst
modules and support structure.
3.1.20 reduction efficiency: The percentage of NO, removed from
the flue gas by the reduction process.
3.1.21 residence time: The time period the reactant is in
contact with the nitrogen oxides or catalyst.
3.1.22 temperature window: The flue gas temperature range that
is most effective for NO, reduction for a given process.
3.1.23 trilobe: A pellet type catalyst substrate used in low
flue gas temperature applications.
!
3.2 ABBREVIATIONS
ACDS AIG AIS BACT CEMS JXS FGR IDF IGCI
Ammonia Control and Dilution System Ammonia Injection Grid
Ammonia Injection System Best Available Control Technology
Continuous Emissions Monitoring System Distributed Control System
Flue Gas Recirculation Induced Draft Fan Industrial Gas Cleaning
Institute
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD-APIIPETRO RP 53b-ENGL L77a 0732270 Ob085Li O30
POST-COMBUSTION NO, CONTROL FOR FIRED EQUIPMENT IN GENERAL
REFINERY SERVICES 3
ppmvd RCDS RIS Reagent Injection System RMS Root Mean Square SCR
Selective Catalytic Reduction SIP State Implementation Plans SNCR
Selective Non Catalytic Reduction
parts per million by volume (dry) Reactant Control and Dilution
System
3.3 UNITS OF REPORTING EMISSIONS
3.3.1 Analysis of NO, and other emissions are normally measured
in ppmvd. Since some sampling instruments mea- sure the wet sample,
care should be taken when analyzing results.
3.3.2 The performance of equipment must be compared on a common
basis. The amount of NO, and ammonia slip should be corrected back
to the standard oxygen levels. For boilers and fired heaters the
standard is 3 percent oxygen (volume dry) in the flue gas, and for
gas turbines the standard is 15 percent oxygen (volume dry). The
calculation method for correcting the NO, values is given in
Appendix B.
3.3.3 In the United States, the most common unit of report- ing
emissions is lb/MM Btu liberated. The heat liberation is based upon
the Higher Heating Value (HHV) of the fuel. As API standard basis
for heat liberation in process heaters is the Lower Heating Value
(LHV) of the fuel, care should be used in expressing the emissions
on the correct basis.
3.3.4 In other countries, the units of reporting emissions can
be milligrams per Normal cubic meter (mg/Nm3) or parts per million
(ppmvd) based on a different flue gas oxygen ref- erence. See
Appendix B for methods of converting the vari- ous units.
4 Guidelines for Selection 4.1 SELECTIVE NON-CATALYTIC
REDUCTION
(SNCR)
4.1.1 General Description
These processes use a reactant (ammonia or urea) to react with
NO, to form water and inert gas (nitrogedcarbon diox- ide). To be
effective in reducing NO, emission, the reducing agent must be
injected into the fired equipment at a desired temperature point.
Although the NO, reduction takes place in the 870"-1200C (
1600"-2200"F) temperature range, the temperature window in the SNCR
process can be extended down to approximately 700C (1300F) by the
injection of hydrogen or enhanced chemicals along with the reducing
agents. The complex fluid dynamics and chemical reactions involved
generally limit the SNCR process to less than 75% NO, reduction in
the fired equipment application.
At least two SNCR technologies are commercially avail- able. One
is an ammonia-based process, the other is a urea-
based process. Both processes require a series of injector noz-
zles and a reducing agent distribution and storage system. The
following are general considerations for selecting a SNCR process
for a specific NO, reduction requirement:
a. NO, reduction efficiency required. b. Allowable NH, slip to
meet requirements. c. Physical configuration of the fired equipment
and the flue gas temperature profiles at various loads. d.
Available potential location for injection. e. Performance at
various loads and different modes of operation. f. Side reactions
and corrosiodfouling on the downstream equipment. g. Safety hazards
on storage, processing, transportation and distribution of the
reactants and enhancers. h. Operating cost, as well as the initial
capital investment.
In general, the NO, reduction efficiency decreases as the
initial NO, value decreases. High NO, reductions become more
difficult to achieve when the initial NO, value is below 1 O0
ppmvd.
4.1.2 Ammonia-Based Process
In this SNCR process, ammonia vapor carried by an air stream or
steam is injected into the flue gas at the appropriate temperature
zone 870"-1200C ( 1600"-2200F) effecting a reduction of NO, to
nitrogen and water.
The injection of ammonia into flue gas leads to a complexity of
intermediate chain branching reactions. The following two
simplified chemical equations summarize the overall process:
2N0 + 4NH, + 20, + 3N2 + 6H20 (1) 4NH, + 50, + 4NO + 6H20
(2)
Equation (1) is the NO, reduction reaction which occurs in the
870"-1200"C (1600"-2200F) temperature range by the injection of
ammonia alone. NO, reduction effectiveness can be enhanced down to
700C (1300F) by injection of hydro- gen (H2 along with NH,).
However, as indicated by Equation (2), the injection of NH, into
high temperature flue gas results in increased NO, formation and is
thus counterproductive.
For initial NO, levels of 200 ppmvd or less, " 0 0 , molar
ratios of about 1.5 are commonly used.
4.1.3 Urea-Based Process
This SNCR process uses urea, CO (NH,), as a reducing agent. it
injects an aqueous urea solution into the path of the NO, laden
combustion products. The urea thermally decom- poses to produce
chemical species which react with NO, to form nitrogen, carbon
dioxide, and water.
CO ("~, + 2N0 + I/, O, + 2N, + CO, + 2H20 (3) 4NH, + 50, +4NO
+6H20 (4)
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
.. ~~
STD.API/PETRC RF 53b-ENGL 1998 E 0732290 b08512 T77
4 API PUBLICATION 536
From Equation (3) it follows that the stoichiometric molar rate
of urea relative to NO in the combustion products is 0.5 since one
mole of urea potentially has two moles of NH, available to react
with NO. The urea injection process for NO, control is also
temperature sensitive. The urea solu- tion, therefore, must be
injected in the temperature range of 870"- 1200C (
1600-2200"F).
4.1.4 NO, Reduction Efficiency Factors
depends on the following factors:
a. Flue gas temperature in reaction zone. b. Uniformity of flue
gas temperature in the reaction zone. c. Normal flue gas
temperature variation with load. d. Residence time. e. Distribution
and mixing of ammonidurea into the flue gases. f. Initial NO,
concentration. g. Arnmonidurea injection rate. h. Heater
configuration, which affects location and design of injection
nozzles.
The NO, reduction efficiency of both SNCR processes
4.2 SELECTIVE CATALYTIC REDUCTION 4.2.1 Process Description
Selective Catalytic Reduction Process removes nitrogen oxides
(NO,) from flue gases by injecting ammonia (NH,) into the flue gas
and passing the well mixed gases through a catalyst bed. NO, reacts
with NH, in the presence of the cata- lyst to produce nitrogen (N2)
and water (H20) as shown in the following equations.
4NO + 4NH3 + O2 + 4N, + 6H,O (5) 6N0 + 4NH3 + 5N, + 6H20 (6)
2N02 + 4NH, + O, + 3N2 + 6H20 (7) 6N02 + 8NH, + 7 N , + 12H2O (8)
NO + NO, + 2NH, + 2N2 + 3H20 (9)
Note that the first reaction for refinery applications gener-
ally dominates since 90% of the NO, is NO.
A wide variety of available cataiysts can operate at flue gas
temperature windows ranging from 165"-600C (325"- 1 lOO"(F). High
NO, reduction efficiencies can be achieved if the parameters such
as residence time, space velocity, and the correct temperature
window are controlled. For SCR technol- ogy, the NHJ NO, molar
ratio of 1 .O is commonly used.
4.2.2 Catalyst Types
4.2.2.1 Low Temperature Catalysts
effect when using platinum catalysts is that a significant part
of the SOz is converted to SO3.
SO, combines with water vapors, forming acid which is corrosive
to the downstream equipment. Vanadium-based cat- alysts also
convert SO, to SO, but to a lesser extent.
The ideal temperature range for the platinum-based cata- lyst to
effect optimum NO, reduction is 230"-285C (450"- 55Oo(F).
For lower temperature applications, vanadium-titanium catalyst
or trilobe substrate is available. The temperature range for this
substrate is 165"-345"C (325"-65OoF).
4.2.2.2 Medium Temperature Catalyst
Vanaium-titanium-based catalysts use a vanadidtitania catalytic
coating on a ceramic honeycomb or metallic plate substrate. They
can also be a homogeneous monolithic hon- eycomb. The cell density
of the honeycomb and the plate spacing can be varied to meet the
application requirements.
The ideal temperature range for this catalyst to effect opti-
mum NO, reduction is 290"40O"C (550"-750"F).
4.2.2.3 High Temperature Catalyst
Zeolite catalysts use zeolitic materials rather than heavy
metals for their catalytic activity. These catalysts have opti- mum
performance at a higher temperature range than the heavy metal
catalysts.
The ideal temperature range for this catalyst to effect opti-
mum NO, reduction is 455"-51 1C (850"-950"F).
4.2.2.4 Efkct of Flue Gas Temperature and Effect of Catalyst
Poisons
A platinum-based SCR system will generate proportion- ally more
nitrous oxide (N,O) at lower temperatures than other types.
Depending on the caaiyst substrate material, the cataiyst may be
quickly damaged due to thermal stresses at temperatures in excess
of 450C (850F). It is also important to have stable operations and
uniform flue gas temperature across the catalyst.
'Avo general classes of poisoning, selective and non-selec-
tive, can result in catalyst deactivation.
Selective poisoning occurs when a component of the flue gases,
such as SO, or SO,, gets adsorbed on the active sur- faces of the
catalyst and renders it inactive. SO, gets selec- tively absorbed
on platinum.
Non-selective poisoning is caused by the accumulation of foreign
substances on both the carrier and the catalytic com- ponent. Dust,
soot, oil mist, and phosphorous components forming a polymeric
glaze can ail block the pres . "Masking" is the term used when the
outer surfaces of the cataiyst are
Platinum based catalysts can be used for NO, reduction in lower
temperature applications. Platinum catalysts are also used to
oxidize unbumt hydrocarbons and CO. One side
covered with such foreign material rendering the inner active
surfaces inaccessible for NO, reduction. Pellet-type catalysts
aremorepronetomasking.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
~
STD-APIIPETRO RP C3b-ENGL i778 W 0732270 ObD85I.13 703 D
POST-COMSUSTION NO, CONTROL FOR FIRED EQUIPMENT IN GENERAL
REFINERY SERVICES 5
Arsenic compounds and heavy metal compounds, such as zinc
dithiophosphate, tend to accumulate on the periphery of the
catalyst. They tend to decompose with time, producing Eree heavy
metals, which then react with the catalytic com- pounds to produce
less active material.
4.3 CONSIDERATIONS
4.3.1 Effect of Flue Gas Components
The dominant factors for NO, reduction utilizing either of these
processes are the flue gas temperature and temperature profile,
rather than the fuel type or its products of combustion. However
the SNCR process is affected by the concentrations of O,, H,O, and
CO in the flue gas. High CO concentrations are reported to shift
the temperature window at the low end, so that NO, removal is
effective at relatively lower tempera- tures, Le., 800C (1470F).
Conversely, the SNCR process may retard the oxidation of CO in the
flue gas, resulting in slightly higher CO emissions.
The presence of HCl or HF in the flue gas in excess of 500 ppmvd
may also retard the effectiveness of the SNCR pro- cess. The other
flue gas components, such as CO,, N,, SO,, etc., appear to have no
effect on the NO, reduction process.
4.3.2 NO, Reduction from Initial NO, Values
4.3.2.1 SNCR Technology
Whether urea or ammonia based, SNCR is most cost effec- tive in
achieving moderate NO, reduction in the 40-75% range from initial
NO, values of 100 ppmvd or greater.
The ammonia slip in either of these process technologies
typically ranges between 5-20 ppmvd.
4.3.2.2 SCR Technology
Applications of SCR NO, reduction are reported for each of the
catalyst types listed above for inlet NO, concentrations up to 300
ppmvd. However, most applications of SCR are for inlet NO,
concentrations in the range of 50 to 150 ppmvd. In this range, NO,
reductions of 90% or more are possible with an ammonia slip of no
more than 5 ppmvd.
While very high NO, reduction is possible (approaching loo%),
this is likely to be at the expense of increasing the ammonia slip
(above 5 ppmvd) which adds to the operating costs and may be
unacceptable for environmental reasons.
4.3.3 Excess Reactants
Some NH, exits the reaction zone unreackd. This is refend to as
ammonia slip. As a result of the complexity of the reactions,
ammonia slip must be evaluated for each indi- vidual application;
so very few generalizations can be made. Because slip is linked to
a certain degree to NO, reduction per- formance, fired equipment in
which the time-temperature rela-
tionship is favorable to achieving high NO, reduction will also
exhibit low NH, slip. in cases where favorable conditions exist, it
has been possible for NH, slip to be held below 5 ppmvd. The
placement of the injectors and injection mixing effectiveness are
of prime importance in minimizing NH, slip.
Other than the reactions outlined in equations earlier in this
section, there are no significant reactions between ammonia and
other compounds in high temperature flue gas. However, at low
temperatures, ammonia can combine with sulfur or chlorine compounds
to form complex salts. These reactions can be minimized, in many
cases to negligible amounts, by limiting the ammonia slip level
from the process.
Depending on the process, as combustion gases cool, ammo- nia
can react with sulfur trioxide (SO,) and water vapor to form
ammonium bisulfate and ammonium sulfate. Ammonium bisulfate is a
sticky corrosive liquid which can foul heat transfer surfaces.
Ammonium sulfae, on the other hand, is a dry solid, forms as solid
particles, and may increase particulate emissions.
At flue gas temperatures below 120C (25OoF), ammonia can react
with hydrochloric acid (ici) to form ammonium chloride (&I).
,Cl is a dry, neutral white salt, which can contribute to a visible
plume if present in sufficient quantities.
4.4 APPLICATIONS
4.4.1 SNCR PROCESSES
SNCR processes are effective at relatively high tempera- tures,
so their applications are more numerous with industrial and power
boilers. SNCR also finds extensive applications in units with
relatively high residence times (e.g., 2 to 3 sec- onds), such as
incinerators. These processes are more effi- cient in reducing NO,
from high levels to moderate levels (i.e., 200 to 50-75 ppmvd).
These processes do not find many applications in gas fired
process heaters where modem burner technology offers extremely low
NO, emissions. Refer to API Publication 535, Burners for Fired
Heaters.
4.4.2 SCR Processes
The SCR processes find ideal application in heaters, boil- ers,
and gas turbine exhaust heat recovery equipment where the initial
NO, levels are in the moderate range of 50 to 150 ppmvd and the
permit requirements demand a reduction by 80 to 90% of such
values.
4.4.3 Combination of SNCR, SCR, and Low NO, Burner
Technologies
Each of these technologies has its ideal range for achieving NO,
reduction. There may be industrial applications where ail three
technologies can be combined to bring the NO, level from initial
values in the 200 ppmvd range to final values in the 5 ppmvd
range.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD-API/PETRO RP 53b-ENGL 1598 0732270 Ob08514 8qT D
6 API PUBLICATION 536
5 Design Considerations 5.1 GENERAL 5.1.1 Typical Design
Considerations
The SNCWSCR System design should yield an Industrial Quality
system with the flexibility and reliability to operate continuously
between unit turnarounds (typically 2-3 years). Such expectations
will q u i r e the equipment supplier to con- sider (at least) the
following in the system design:
The codes, industry standards, and reference publications noted
in Section 2.
All appropriate site specific seismic, wind, snow, and ther- mal
loading conditions.
All appropriate job specific operating and environmental
requirements.
The peculiarities of operation, maintenance and perfor- mance in
the selection of injector location, orientation and design (SCR and
SNCR Systems), and in the selection of reactor location,
orientation, and design (SCR Systems).
Provisions for one future layer of catalyst (SCR Systems). Such
provisions should include the incremental system pres- sure drop in
the system process design, and the incremental system loadings in
the mechanical design.
Insulation and heat tracing should be provided as required on
vaporized ammonia systems to avoid condensation upstream of the
injectors.
Freeze protection may be required for aqueous ammonia and
urea-based systems, depending on location.
5.1.2 Typical Purchasing Considerations
should be addressed
a. Adequate system definition and scope delineation. b. System
commissioning advisor from equipment supplier. c. Spares for
commissioning and two-year operation. d. Performance Guarantee(s)
for NO, reduction efficiency. e. Catalyst life.
In the development of a Job Scope, the following items
5.2 SNCR SYSTEMS OVERVIEW 5.2.1 Ammonia-Based SNCR Systems
There are two types of ammonia-based SNCR systems: Aqueous
Ammonia and Anhydrous Ammonia Systems. The difference between the
two systems lies in the processes used in the Reactant Control and
Dilution Systems (RCDS) to vaporize the ammonia and mix it with a
carrier gas to obtain the reactant charge. The primary components
of ammonia- based SNCR systems are (select either a or b):
through vaporizer before mixing with either an air or steam
carrier. The primary components in this system are as fol- lows,
and as illustrated on typical schematic (Figure 1).
1. Aqueous ammonia storage tank. 2. Carrier air supply: two air
blowers (or compressors) or one blower and a backup air source; or
a source of carrier steam. 3. Ammonia supply pump. 4. Two cartridge
filters and/or strainers. 5. Air heater with ammonia-air vaporizer
or ammonia vaporizer. 6. Insrumentation and interconnecting piping
for a fully functional system. 7. The recommended features noted in
Section 5.4.
b. RCDS-Anhydrous Ammonia: Vaporized anhydrous ammonia is mixed
directly with either an air or steam carrier. A vaporizer usually
supplies heat to the storage tank to main- tain pressure, and the
ammonia vapor is drawn from the vapor space in the tank. The
primary components in this system are as follows, and as
illustrated on typical schematic (Figure 2).
1. Pressurized anhydrous ammonia storage tank. 2. Carrier gas
supply: two air blowers, or one blower and a backup air source; or
a source of carrier steam. 3. Ammonia vaporizer. 4. A m m o n i a 4
static mixer (if required). 5. Instrumentation and interconnecting
piping for a fully functional system. 6. The recommended features
noted in Section 5.4.
1. How distribution manifold with a series of injector nozzles
that introduce the vaporized ammonidcarrier gas mixture to the flue
gas stream. 2. The recommended features noted in Sections 5.5 and
5.7.
d. System controls, provided by either a local control panel or
the plants DCS.
c. Reactant Injection System (RIS), consisting of:
5.2.2 Urea-Based SNCR Systems
The primary components of a urea-based SNCR system are as
follows, and as illustrated on typical schematic Figure 3).
a. Urea Reactant Control and Dilutions System (RCDS), consisting
of:
1. A reactant storage tank. 2. bo cartridge filters and/or
strainers. 3. A reactant metering pump. 4. A water pump, or
dilution water source connection. 5. An in-line static mixer as
required. 6. A series of flow indicators and regulating valves,
as
a. RCDS-Aqueous Ammonia: Aqueous ammonia is required, to balance
the flow of reactant to each reactant pumped from the storage tanks
and is commonly mixed with injector. a heated carrier air stream in
an ammonia vaporizer/mixer. 7. All pertinent instrumentation and
interconnecting p ip Alternatively, the ammonia can be vaporized in
a once- ing for a fully functional system.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
F-XAB E-X c-x T-X P- AQUEOUS AMMONIA FILTERS AQUEOUS AMMONIA
VAPORIZER AIR COMPRESSOR AQUEOUS AMMONIA TANK AQUEOUS A;
, - . . - , . - . . - . . - . . - . . - . . - . . - . . - . . -
. . - . . - . . - . . - . . - . . - I Process Signal >-----
(Note 2) I -@--
I
I 7-
U I F-XB
I I
I
I
Steam
I I : I
I
I
I
I
I L . .
I
E-X
c
-E-
& r
Notes: 1. May use steam in lieu of air compressor. 2. Process
signai for feed forward, as needed. 3. Either Zone 1 or Zone 2 in
operation.
This schematic is o used as a 5
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
:ONIA PUMP
I
I
I
I
I
I
I
- --
I Combustion Zone
I
N N * I I
I
I
I
Zone 2 1, ;:; ~
- E --
typical system and is intended to be de, actual design might
vary.
Figure 1-SNCR System Schematics Aqueous Ammonia
7
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
c-x T-X AIR COMPRESSOR ANHYDROUS AMMONIA TANK
Ammonia Con , - , . - . . - . . - . . - . . - . . - . . - . . -
. . - , , - , . - . . - . . - . . - . . - . . - . . - I
- TSO
I
I
I
I
I
I
I
I
I
I
I
I
I
o
'ri
I
r i
r'
v c-x SeeNote1
T-X
H-1 This schemati
used :
Notes: 1. May use steam in lieu of air compressor. 2. Process
signal for feed forward, as needed. 3. Either Zone 1 or Zone 2 in
operation.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
~
S T D * A P I / P E T R O R P 53b-ENGL 1778 0732290 Ob08518
'495
I
--
Zone 1 (Note 3) I
. . - .
I
I -@ --- NO,
L
I 7 LI .- Zone 2
J I
s of a typical system and is intended to be a guide, actual
design might vary.
L
/ Combustion Zone -
Figure 2-SNCR System Schematics Anhydrous Ammonia
9
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
F-1 A/B WATER FILTERS
I I
F-2A/B UREA FILTERS
T-X UREA TANK
(Note 3)
P-1 WATER PUMP
AtomizingX=ooling I
>-I Air
I
l
I F-1 B
P-1
I - - - A I
I r -
Y 1
1 P-3 Notes : 1. Static mixer, use as needed. 2. Process signal
for feedforward control. 3. Tank heat traced if urea is 50% or
greater solution 4. All urea piping to be stainless steel.
T-X
This schematir used E
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD*API/PETRO RP 53b-ENGL 1998 9
P-2 P-3 UREA PUMP CIRCULATION PUMP
Control A- i = I I
- - (Note 1)
. - . . - . . -
I
I ----
0732290 Ob08522 71b M
C
--@-
of a typical system and is intended to be a guide, actual design
might vary.
I Combustion Zone
I I
Figure 3-SNCR System Schematics Urea Injection
11
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
F-XA/B AMMONIA FILTER
v-x AMMONIA VAPORIZOR ELEC
I %
I F-XA {:I I
I %
F-XB
O
n
Atomizing Air Supply
Y
From Header '
To IA Users j l I
I
I
I
I . .
I - I v-x I
id I
IL I rn 1 I I
I 4 c
Notes: 1. Inlet NO, is optional and should be used when large
load variation on fired equipment is expected 2. Expanded view of
ammonia injection grid.
P-x - T-X
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD-APIIPETRO R P 53b-ENGL 1778 D 0732290 Ob08524 799
6-XA/B DILUTION AIR BLOWERS
P-x T-X AQUEOUS AMMONIA PUMP AQUEOUS AMMONIA TANK
API 620
i
9 +'V B-XA
Q +\I '
6-XB
3 Aqueous Ammonia Injection Skid
I
I
I
I
I
I
I
l
I
I
I
I
I
I
I
I
iis schematic is of a typical system and is intended to be used
as a guide, actual design might vary.
Figure 4-SCR System Schematics Aqueous Ammonia
13
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD*API/PETRO R P 53b-ENGL 1998 0732290 Ob08525 b25 W
B-XA/B DILUTION AIR BLOWERS
x-1 STATIC MIXER
. - . , - . . - . , - . . - , . - . , - . . - . . - . . - . . -
, , - , . - . . - . . - . . - . . -
(Note 1)
ANH
TSO
B-XA
I I Y
I W J M B-XB I
I
H-i Note 2
Notes: 1. Inlet NOx is optional and should be used when large
load variation on fired equipment is expected. 2. Thermosiphon
ammonia vaporizer. 3. Expanded view of ammonia injection grid.
. .. .. .gdrouc Ammonia In , - . . - . . - . . - . . - . . - .
.
Th
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD*API/PETRO R P 53b-ENGL 1778 0732270 ObOB52b 5bL = T- 1
!?OUS AMMONIA TANK
1
tion Skid . < - . .
schematic is of a typical system and is intended to be used as a
guide, actual design might vary.
Figure 5-SCR System Schematics Anhydrous Ammonia
15
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
S T D - A P I I P E T R O RP 53b-ENGL L77 I O 7 3 2 2 7 0 O b 0
8 5 2 7 4T
POST-COMBUSTION NO, CONTROL FOR FIRED EQUIPMENT IN GENERAL
REFINERY SERVICES 17
b. Reactant Injection System (RIS), consisting of: 1. An
atomizing chamber. 2. Interconnecting tubing. 3. Injector nozzles
that introduce the atomized reactanif carrier air mixture into the
flue gas stream.
c. System controls, provided by either a local control panel
and/or the plants DCS.
5.3 SCR SYSTEMS OVERVIEW
There are two major types of SCR systems: Aqueous Ammonia and
Anhydrous Ammonia systems. The differences between the two systems
lie in the processes used in the Reactant Control and Dilution
System @CDS) to vaporize the ammonia and mix it with the carrier
air stream to obtain the reactant charge. The primary components of
an SCR sys- tem are (select either a or b):
a. RCDS-Aqueous Ammonia: Aqueous ammonia is pumped from the
storage tanks and is commonly mixed with a heated carrier air
stream in an ammonia vaporizer/mixer. Alternatively, the ammonia
can be vaporized in a once- through vaporizer before mixing with
either an air or steam carrier. The primary components in this
system are as fol- lows, and as illustrated on typical schematic
(Figure 4).
1. Aqueous ammonia storage tank. 2. Carrier air supply: two air
blowers, or one blower and a backup air source; or a source of
carrier steam. 3. Ammonia supply pump. 4. Two cartridge filters
and/or strainers. 5. Air heater and ammonia-air vaporizer or
ammonia vaporizer. 6. All instrumentation and interconnecting
piping for a fully functional system. 7. The recommended features
noted in Section 5.4.
b. RCDS-Anhydrous Ammonia: Vaporized anhydrous ammonia is mixed
directly with carrier air or steam. A vapor- izer usually supplies
heat to the storage tank to maintain pressure, and the ammonia
vapor is drawn from the vapor space in the tank. The primary
components in this system are as follows, and as illustrated on
typical schematic. (Figure 5.)
1. Pressurized anhydrous ammonia storage tank. 2. Carrier air
supply: two air blowers or one blower and a backup air source, or a
source of carrier steam. 3. Ammonia vaporizer. 4. AmmoniaAr static
mixer (if required). 5. Instrumentation and interconnecting piping
for a fully functional system. 6. The recommended features noted in
Section 5.4.
1. A flow distribution manifold with a series of flow indi-
cators and regulating valves. 2. A set of internal elements, with
injection nozzles, capa- ble of accommodating the entire range of
temperatures.
c. Reactant Injection System (RIS), consisting of:
d. A Selective Catalytic Reactor, consisting of:
1. Insulated housing, with at least one catalyst access door. 2.
Catalyst support structure. 3. Catalyst module(s). 4. Appropriate
ladders and platforms. 5. Recommended features noted in Sections
5.6 through 5.8.
e. Induced Draft Fan, if required, which should be designed and
purchased in accordance with Section 5.10. f. System Controls,
provided by either a local control panel or the plants DCS.
5.4 REACTANT CONTROL AND DILUTION SYSTEM COMPONENTS
5.4.1 Dilution Air Blower System
Dilution air blowers should be industrial quality and of a
design suitable for the intended application. The following
features should be included in the system:
a. An isolation valve downstream of each blower, to provide the
means to positively isolate either blower from the operat- ing
system, which permits the safe maintenance of the idle blower. b. A
check valve, to prevent the flow of air through the idle blower. c.
An inlet air filter-silencer. d. A ducting design, that may be
constructed of pipe, that allows the removal of either blower
without the removal of adjacent ducting.
5.4.2 Air Heater
a. Electric Air Heater-Heating elements will require peri- odic
replacement. The electnc air heater should be constructed for ease
of maintenance and long term reliability, and contain the following
recommended features:
1. Elements should provide a minimum mean-time between-failure
of 60 months. 2. Heating elements should be designed for easy
replacement. 3. The heater control should be a silicon controlled
recti- fied type, with a 4-20 mA control input.
b. Other air heater types, such as a once-through exchanger
heated by a fluid such as flue gas or steam, may be used.
5.4.3 Am mon ia VaporizerNlixer
Boiler and Pressure Vessel Code, Section VIII, Division 1. This
vessel should be designed in accordance with ASME
5.4.4 Filterfltrainers
Filters and/or strainers should be an industrial quality and of
a design suitable for the intended application. It is recom- mended
that two in-line cartridge filters and/or strainers be
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
~
STD.API/PETRO RP 53b-ENGL 1998 0732290 Ob08528 33Li m
18 API PUBLICATION 536
piped in parallel, and valved to permit quick and safe switch-
ing (on-line vs. off-line).
5.4.5 Skid Design
Some system components may be prefabricated and mounted on
skids. Based on industry experience, the follow- ing features are
recommended:
a. The skid should have a solid checker plate floor with a
minimum 50 mm (2") high curb seal-welded to the floor, and a drain
line connection. The floor should be sloped to the drain. b. The
skid equipment layout should provide easy access for operation and
maintenance. c. The design and placement of piping, conduit and
mechan- ical members should permit the removal of skid components,
without the removal of piping, conduit or members. d. The skid
structural design should be sufficient for a four- point lift
without temporary bracing.
5.4.6 Control and Dilution System Piping
It is recommended that the piping between the system inlet and
the RIS be in accordance with the foilowing minimum design
practices:
a. Piping design, fabrication, inspection and testing should be
in accordance with the job specifications and ASWANSI B31.3. b.
Skid piping should be properly supported and terminated with
flanged connections at the skid edge. c. Skid terminals should be
designed to accept reasonable forces, moments and movements from
the interconnecting piping per M I Standard 560. d. Piping should
not obstruct any access openings. e. Piping should be properly
supported and protected to pre- vent damage from vibration,
operation and maintenance. f. Piping should be designed to minimize
the use of flanges and fittings. g. All piping should be of
seamless construction. h. Corrosion allowances for carbon steel
materials should not be less than 3.0 mm (0.125"). Stainless steel
materiais may be designed without a corrosion allowance. i. Flange
bolt holes should straddle vertical centerlines. j. Connections
1.50" NPS and smaller should be socket welded. k. Connections 2"
NPS and larger should be butt-welded or flanged. 1. instrument
connections and stubs, including root valves, should not be less
than 3/4'' NPS. m. Vents and drains should be provided to
completely vent and drain pressure parts. High or low point pockets
should be avoided. n. Components made of, or containing, copper,
brass, and cast iron should be avoided.
o. Pressure part flange faces should be raised face with 125-
250 AARH concenic or spiral serrated finish suitable for metal
gaskets. p. Pressure part gaskets should be spiral wound metal
gaskets with retaining rings.
5.5 REACTANT INJECTION SYSTEM
The RIS design should be in accordance with the following:
5.5.1 Piping design, fabrication, inspection, and testing should
be in accordance with the RCDS piping requirements, as noted in
5.4.6, above.
5.5.2 RIS piping connections, inside the flue gas path, (Le.,
internal elements) should be socket or butt-welded.
5.5.3 Internal elements should be fed from a common external
header.
5.5.4 Each spray nozzle assembly should be removable for
maintenance. It is desirable to have the capability to remove
individual spray nozzles while system is operating.
5.5.5 Spray nozzles and other internal elements should be 300
series stainless steel material.
5.5.6 Internal supports and guides of the injection grid
components should be provided as required to prevent defor- mation
of the components.
5.5.7 Reactant Injection Grid design should accommodate the
entire range of possible operating temperatures. RIS design should
be based on "no flow" conditions.
5.6 C ATALY ST/R EACTOR
5.6.1 Catalyst
a. The catalyst should be suitable for treating the flue gases
specified on the data sheets. b. Au catalyst modules in a reactor
should be identical in size and interchangeable. This concept
should not prevent the use of test modules with coupons, or other
form of monitoring device. c. It is recommended that IGCI standard
catalyst module sizes be used whenever practical.
5.6.2 Reactor Housing
a. internal supports, bafes and other flue gas wetted compo-
nents should be in accordance with the applicable design criteria
of APT Standard 560. b. The reactor housing should be designed to
accommodate the appropriate number of catalyst modules, plus space
for one additional layer of catalyst modules. c. Sufficient
maintenance access should be provided for both the initial and
future catalyst layers, and associated equipment. d Provisions for
thermal expansion should take into consid- eration the operating
conditions specified on the data sheets.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD.API/PETRO RP 53b-ENGL 1998 = 0732290 Ob08529 270
POST-COMBUSTION NO, CONTROL FOR FIRED EQUIPMENT IN GENERAL
REFINERY SERVICES 19
e. Placement of access lanes and cleaning facilities should 5.8
REFRACTORIES AND INSULATION anticipate future catalyst
installation. f. A catalyst module support structure should be
provided in the reactor housing. It should be designed to support
and retain both initial and future catalyst modules. g. Internal
seals should be provided to prevent bypass of flue gas around the
catalyst modules. h. Provisions for catalyst module removal should
be included in the reactor housing design.
a. Refractories and insulation should be designed in accor-
dance with API Standard 560. b. ceramic and castable c. For floor
coverings, the design should enable the floor to be walked on
without damage. d. Ceramic fiber systems should be designed in
accordance with API Publication 534.
are prefesred,
i. The catalyst reactor housing should have a bolted access
SYSTEMS door sized to allow catalyst removal.
5.7 STRUCTURES AND APPURTENANCES 5.9.1 General
5.7.1 General
5.9 INSTRUMENTATION AND ELECTRICAL
a. The equipment supplier should provide a P&ID, with
a. Structural steel, reactor casing, and ducting should be
designed in accordance with API Standard 560. b. All loads from the
catalyst modules and connecting duct- ing should be supported by
the structural steel and should not be t ransmit ted by the
insulation system. External steel frames should carry the
structural loading. c. Metal casing may be used to provide lateral
bracing between the structural columns and to support the
insulation system. d. Structural steel should be designed to permit
lateral and vertical expansion of all SCR parts. e. Structural
supports should be designed to support ladders, stairs and
platforms in existing and future locations.
5.7.2 Ladders, Platforms, and Stairways
a. Platforms, with handrails and ladders, should provide access
to catalyst removal doors. Such platforms should not inhibit the
removal of catalyst. b. Platforms and/or ladders should provide
access to all instrumentation and controls, valves, dampers,
operators, and access doors not accessible from grade. c. Catalyst
access platform should be of sufficient size and strength to
accommodate at least one module.
5.7.3 Casing and Ducts
a. Ducts and reactor casing should be designed in accordance
with API Standard 560, Appendix E b. Casing plate should be
seal-welded to prevent air and water infiltration. c. Lifting lugs
should be provided on all ducting and reactor housing components.
d. Bolt spacing on all duct flanges should be 150 mm (6") maximum.
e. The transition angle from the upstream ducting to the SCR
reactor housing should not be greater than a 30" included angle,
unless flow distribution devices are provided. f. Expansion joints
should be provided as required to accom- modate system and/or
component expansion and contraction.
instrument symbols and identification in accordance with ISA
55.1. b. The equipment supplier should provide all instrumentation
and controls shown on the job P&D.
Wiring, calibration, and installation data should be pro- vided
by the equipment supplier for each instrument and/or panel.
5.9.2 Control and Dilution System
a. On skid-mounted systems, instrumentation and control wiring
should be terminated in junction boxes. b. Available instrument
power levels, and instrument air pressures should be specified on
the data sheets. c. The RCDS will have a local control panel for
the local start-up, shutdown, and annunciation of the system.
5.9.3 Control and Instrumentation Components
a. Each instrument should be documented on an ISA data sheet. b.
The reactant flow control valve should have ANSI RF flanges, an
integral UP convertor with filtedregulator, and gauges (to indicate
instrument air supply and outlet pressures). c. The reactant
shut-off valve should be rated ANSI Class V, with RF flanges, and a
filter/regulator with pressure indicator. d. Pressure, differential
pressure, and temperature transmit- ters should provide a 4-20 mA
output. e. Thermocouples should be either Type J or K, with
thermowell.
5.9.4 Electrical Components
a. Electrical enclosures in outdoor installations should be
weatherproof. b. Motors, electrical components, and electrical
installations should be suitable for the available utilities and
area classifi- cation specified by the purchaser. c. Components
with exposed copper part(s) should be avoided.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD*API/PETRO RP 53b-ENGL 1798 0 7 3 2 2 9 0 Ob08530 T92
20 API PUBLICATION 536
5.1 O INDUCED DRAFT FAN (IDF)
a. The KIF should be designed and manufactured in accor- dance
with API Standard 560, Appendix E. The IDF should be sizdrated in
accordance with API Standard 560, Appendix F. b. The iDF should be
capable, as purchased or- when retrofit- ted, of passing the Test
Block flow rate at the higher head value resulting from the
installation of a "future layer of catalyst."
5.1 1 INSTRUMENT AND AUXILIARY CONNECTIONS
a. Nozzles and connections should be designed in accor- dance
with API Standard 560. b. Sufficient connections should be provided
to permit traverses of velocity, NO, concentration, ammonia
concentra- tion, and temperature upstream and downstream of the
reactor.
5.12 SHOP FABRICATION AND FIELD ERECTION
a. Shop fabrication and field erection should be executed in
accordance with API Standard 560. b. Suitable lifting lugs should
be provided on all modules.
5.1 3 INSPECTION, EXAMINATION AND TESTING
a. inspection and testing of all mechanical components should be
in accordance with API Standard 560. b. Performance testing is not
included in this section, and should be performed in accordance
with Section 6 and/or the purchaser's specifications.
6 Operations Description 6.1 SELECTIVE NON-CATALYTIC
REDUCTION
6.1.1 General
The use of Selective Non-Catalytic Reduction (SNCR) units to
reduce NO, emissions was pioneered in the early 1970s. This process
does not require a catalyst. Flue gas tem- peratures should be in
the range of 87O0-120O0C ( 1 6 W 22"F), with the optimum usually
being 925"-1040"C (1700"-1900"F) depending on the reactant. Both
aqueous and anhydrous ammonia, and urea, have been used as the
reac- tant. NO, reduction is typically 40-75 '% with SNCR. The
efficiency of the process decreases with low inlet NO, con-
centrations (below about 100 ppmvd) making high NO, reductions more
difficult to achieve. The reactant to NO, operating ratio is 1-1.5
mole ammonia to 1 mole NO, for ammonia-based systems, and 0.5-0.75
mole urea to 1 mole NO, for urea-based systems. The injection rate
is usually con- trolled based on ring rate and NO, emission. The
ammonia slip is normally 5-20 ppmvd.
If urea is supplied in a concentrated liquid form (above 50%
urea), then it must be kept above 20C (65F) to avoid
6.1.2 Flue Gas Temperature
The NO, reducing reaction is temperature sensitive. Con- trol
over a range of operating conditions is difficult. Changes to the
firing rate affect the flue gas temperature and velocity profile.
If the temperature falls below or rises above the win- dow, NO,
emissions and/or ammonia slip will increase. Sometimes injectors
are placed at different locations to reach the optimum temperature
window over the operating range.
6.1.3 Reactant Injection
Ammonia injection uses a carrier such as steam or com- pressed
air. Hydrogen injection or enhancer may also be required for low
temperature applications. Urea-based sys- tems do not require a
carrier but use pressure atomizing to ensure aequate reactant
mixing with the flue gas. Urea injec- tion is pressure or air
atomized. Off-line injectors are purged to keep them from plugging
and overheating. Plugged injec- tors can cause erratic spray and
tube impingement, leading to tube failure.
6.1.4 Excess Reactant
As previously discussed, ammonia slip can combine with sulfur
tri-oxide and water vapor to form ammonium suifate ("4)zS0, and
ammonium bisulfate (NI&)HSO,, which can result in convection
coil surface fouling and visible stack plume.
Please refer to Figure 6 for formation of ammonium sulfate and
ammonium bi-sulfate for various concentrations of NH3 and SO3. The
area between the two lines indicate possible for- mation of both
ammonium suifate ("&30, and ammonium bisulfate (NHJHSO,.
Ammonium sulfates can deposit on surfaces below 235C (450"F), or
increase particulate emissions. Ammonium sul- fate is a dry
particulate that may contribute to plume forma- tion. Ammonium
bisulfate is highly acidic and sticky substance which can deposit
on downstream equipment such as convection coils and air heaters
causing pluggage and dete- riorating equipment performance.
Deposits can be minimized by keeping ammonia slip low and
monitoring downstream flue gas temperature. Deposits can be water
washed on-line if the provision exists.
6.1.5 Reactant Handling
Aqueous ammonia will typically be a mixture of approxi- mately
2630% ammonia and water, and is more commonly used. Demineralized
water should be used in aqueous ammo- nia solutions to minimize
fouling in the ammonia vaporizer. An alternative approach is
utilization of anhydrous ammonia Anhydrous ammonia is toxic. It has
a high vapor pressure at ambient temperature, and thus requires
pressurized storage. crystallization.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD-API/PETRO RP 53b-ENGL 1994 0732270 Ob06531 927 D
POST-COMBUSTION NO, CONTROL FOR FIRED EQUIPMENT IN GENERAL
REFINERY SERVICES 21
P a Q
O E
2 .- I
I c a, o c
O" r" z
100
10
1
o. 1 1 10 100 so, Concentration, pprnvd
lo00
Figure 6-Formation Temperature of Ammonium Sulfate and Ammonium
Bisulfate for Various Concentrations of NH, and SO,
6.1.6 Energy Use
Operating costs and reliability will depend on the utilities
required for reactant handling. SNCR systems employ pumps and
heaters to feed the reactant. Steam or compressed air is used as a
carrier for the ammonia-based system. For urea- based systems,
plant water is required as an in-line diluent for distribution
purposes.
6.1.7 Test Procedures
Emissions testing should follow EPA 40 CFR 60 subpart Db, unless
otherwise dictated by local regulations. NO, ana- lyzers will be
required. Ammonia analyzers may be required as well to detect NH,
slip.
6.2 SELECTIVE CATALYTIC NO, REDUCTION
6.2.1 General
The use of SCR systems to reduce NO, emissions was pio- neered
in the early 1970s. This process requires the use of a catalyst.
Flue gas could be in the range of 165"-OO"C (325"- 1 100F)
depending on the type of catalyst used.
Presently three types of catalysts are in use. They are low,
medium, and high temperature. Both aqueous and anhydrous ammonia
have been used as a reactant. NO, reduction can exceed 90% with
SCR. NO, levels below 10 ppmvd can be achieved. In general, the
ammonia-to-NO, ratio is 1.0 for
SCR. The injection rate is usually controlled based on the fir-
ing rate and NO, emissions. Ammonia slip is usually less than 5-10
ppmvd.
6.2.2 Catalyst Performance Versus Operating Hours
The performance of catalyst tends to deteriorate with time. The
initial rate of catalyst deterioration is high but slows and
becomes fairly steady as the catalyst ages. After the initial start
up, the performance of catalyst is stabilized. Figure 7 shows a
typical catalyst activity profile over a range of time. Main causes
of deterioration are the catalyst poisons, chemi- cal reactions
with aikali metals and halogens, and sintering at very high gas
temperatures, above 450C (840F) for vana- dium catalyst.
6.2.3 Flue Gas Temperature
Flue gas temperature is the most important operating parameter
that influences selection of the catalyst. Figure 8 shows a typical
qualitative effect of gas temperature on the NO, reduction
efficiency. The choice of the catalyst must consider the range of
operating temperatures in the system. The flue gas temperature
entering the catalyst bed should be uniform, preferably within i
l0"C (20F).
a. Effect of Low Flue Gas Temperature: Lower flue gas tem-
peratures reduce catalyst activity which may result in high
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
S T D * A P I / P E T R O RP 5 3 b - E N G L 1798 H 0732270 O b
0 8 5 3 2 Ab5
22 API PUBLICATION 536
O 1 2 3 4 5 6
Operating Time, Years
Figure 74ata lyst Activity Profile versus Time-An Example for a
Particular Situation
catalyst volume requirements. High efficiency, high surface
area, low temperature catalyst systems are available which will
perform down to 165C (325F). depending on the sulfur content in the
fuel. b. Effect of Medium Flue Gas Temperahire: Medium range
catalysts operate in the range of 29O040O0C (55O0-87O0F). At
temperature above 80O"F, the metal coating migrates and localizes
in spots, leaving the surface less reactive. Thermal shock can also
lead to flaking of the catalyst coating. It is caused by rapid
temperature changes, by excessive reaction temperature or from
normal operation over an extended period. Metal coating and
catalyst expand and contract at dif- ferent rates due to their
different thermal coefficients. c. Effect of High Flue Gas
Temperature: Zeolite based cata- lysts can operate at a temperature
range of 360-6000C (700-1100"F).
6.2.4 Flue Gas Flow Rates
NO, reduction catalysts are designed for certain flue gas
temperature ranges and flows. Lower firing rates can reduce NO,
reduction efficiency if flue gas temperature falls below design
parameters. The NO, reduction efficiency of the cata- lyst is
inversely proportional to space velocity. At flue gas flow rates
greater than design, NO, reduction efficiency will be reduced.
Figure 9 shows effect of space velocity on the performance of a
typical catalyst.
6.2.5 Flue Gas Composition
Oxygen is needed in the flue gas to complete the reaction. The
effect is significant only when the oxygen content in the flue gas
is less than 2%.
If the flue gas temperature is allowed to drift too low the
system tends to form suifates of ammonia which will deposit on the
catalyst bed and inhibit the catalytic action.
Water vapor has the effect of shifting the equilibrium of the
reaction so that with increasing water vapor, the catalyst per-
fonnance is decreased.
6.2.6 AmmoniaNO, Ratio
The NO, removal efficiency increases with an increasing ammonia
slip and reaches an asymptotic value after a certain quantity of
ammonia slip as indicated in Figure 10. This means that there is a
limit for the effect of excess ammonia in removing NO,. There is
also a limit on ammonia slip usually set by local pollution
authorities.
Failure to properly distribute NH, and NO, will result in
selected areas of the catalyst bed not having sufficient ammo- nia
to reduce NO, level of desired amount. In other areas, the ammonia
will totally reduce the NO, and the excess ammonia will pass out
the back of the catalyst as ammonia slip. Thus, NO, will not be
sufficiently reduced and the ammonia slip will be higher than
predicted
6.2.7 Ammonia Injection
The ammonia should be vaporized and mixed with air in the proper
proportion prior to entry to the ammonia injec- tion system. The
mixture should contain less than 8% by volume to avoid lower
explosive limit of 15.7% in the air. If the flue gas is used as the
carrier, the SCR vendor should be referenced.
The ammonia injection should be uniform throughout the cross
section of flue gas flow to insure uniform mixing of ammonia
Typically, a mixing time of 0.5 to 1.0 second is provided.
Alternately, mixing bafes are installed to insure uniform mixing.
The concentration of ammonia at the cata- lyst face should not vary
more than f10% RMS.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
POST-COMBUSTION NO, CONTROL FOR FIRED EQUIPMENT IN GENERAL
REFINERY SERVICES 23
I I
I
I
I f (= LowTemperature Medium Temperature
O 100 200 300 400 Temperature (C)
Notes: T = 360C ",/NOx= 1.0
Figure &NO, Reduction versus Temperature for Different SCR
Catalysts-Typical Example
O loo00 15ooo 20000
sv value (lh)
Figure +NO, Reduction Efficiency versus Catalyst Space
Velocity-An Example Situation
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
~
STD-APIIPETRO RP 53b-ENGL L998 = 0732270 0b0853' i b38 D
24 API PUBLICATION 536
a9 % U c P) U
w
.- E
.- 8
2 c U 3 U
s)"
98
96
94
92
90
88
86 O 10 20 30 60
NH, Slip(ppmvd)
Figure 1 &Typical NO, Reduction Efficiency and Ammonia
Slip
6.2.8 Start-up
The manufacturer of the catalyst should supply start-up, nor-
mal operating and normal and emergency shut-down inshuc- tion and
these instructions should be foilowed closely. The temperature of
the catalyst bed should be raised at a predes- tined rate according
to the manufacturer's recommendations.
6.2.9 Catalyst Replacement
'Ifipicaily catalyst will have 3-5 years guaranteed life.
However catalyst life may be longer and is dependent on a number of
parameters. It could be shorter due to any number of abnormal
operating conditions. The manufacturer will dic- tate limits on
operating temperature and pressure, as well as potential catalyst
poisons. When the catalyst activity is depleted, another module
could be added if room was left in the original design, or the
existing modules could be replaced. Catalyst disposal should be in
accordance with local regula- tions and manufacturer
recommendations.
6.2.10 Catalyst Poisoning
Poisoning of catalyst leads to irreversible degradation of NO,
reduction activity. Poisoning element (F', S , Pb, Zn, C1,
As, Hg) reacts with the metal catalyst surface, producing a
non-reactive catalyst surface. It is mostly caused by dirty fuels.
SCR specifications should contain fuel analysis, which includes
trace elements.
6.2.1 1 Cataiyst Fouling
Catalyst bed pressure drop should be monitored to detect any
signs of fouling. Catalyst fouling increases back pressure and
reduces activity. Fouling can occur h m the following maioperation
of the catalyst:
a. Burningdirty fuel. b. Sulfae deposition. c. Excessive fuel
rich operation.
Operation with extremely bad combustion or smoking for long
periods of time should be avoided. During such condi- tions unburnt
hydrocarbons could deposit on the catalyst and cause performance
degradation and require cleaning. Certain catalysts could oxidize
the unbumt hydrocarbon, causing cat- alyst damage from localized
hot spots. Vacuum cleaning of catalyst is recommended if fouling
is
caused by surface dirt.
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD*API/PETRO RP 53b-ENGL 1778 0732270 Ob06535 5 7 9
APPENDIX A-POST-COMBUSTION NOx CONTROL DATA SHEETS
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
_
STD.API/PETRO R P S3b-ENGL 1778 W 0 7 3 2 2 7 0 Clb0853b 400
American Petroleum Institute JOB NO. ITEMNO. ___ PURCHASE ORDER
NO.
SPECIFICATION NO. __ ~-
__ ~~
- 1
'2 '3 *4
*5 6 7 8 9
10 11 1: 1: 11
1:
1f l i 11 15 2( 21 2: 2. 24 2: 2f 27
2f 2E
3c 31 32 33 34 35 3c 37 38
3s 10
Il 12 13 44 15 16 17 48 49
50
51 52
53 54 55 56
-
_ _ ~
POST-COMBUSTION NOx CONTROL (API-RP536) SELECTIVE CATALYTIC NO.
REDUCTION
DATA SHEET-CUSTOMARY UNITS
DATE ___ ~ ____ REVISION NO PAGE 1 OF 4 ~ ~ BY _ _ ~ _
___~___.~
PROCESS DESIGN CONDITIONS
OPERATING CONDITIONS : EQUIPMENT FIRING RATE, mm Btulhr (LHV)
(HHV) FLUE GAS FLOW TO BE TREATED, WET BASIS, Ibhr FLUE GAS
TEMPERATURE ENTERING AIG, "F FLUE GAS TEMPERATURE ENTERING REACTOR,
"F
FUEL DESCRIPTION FLUE GAS COMPOSITION:
OXYGEN (O,) (%volume, wet) NITROGEN (N,) (%volume. wet) WATER
(H,O) (36 volume, wet)
CARBON DIOXIDE (CO,) (%volume, wet) ARGON (Ar) (?? volume, wet)
PARTICULATES, Ibhr INLET NO,, (ppmvd) (Ib/hr) CORRECTED INLET NO,
AT % O, (ppmvd) (Ibhr) INLETCO (ppmvd) (ibhr) INLET SO,, (ppmvd)
(Ibhr) TRACE ELEMENTS, (ppmvd) (Ibhr):
FLUE GAS FLOW (veiticakipkiown) (horizontal) TO SCR AMMONINNO,
MOLE RATIO (NHJNOJ TYPE OF AMMONIA (ANHYDROUS) (AQUEOUS) AMMONIA
CONCENTRATION IN AQUEOUS SOLUTION, wt % DILUTION MEDIUM (AIR)
(STEAM)
FLOW RATE, Ibhr TOTAL DILUTED AMMONIA FLOW RATE TO SCR, IWhr
REQUIRED NO, REDUCTION EFFICIENCY, % SCR PERFORMANCE: POLLUTANT
CONCENTRATION AT REACTOR EXIT:
CORRECTED NO. AT % O2 (ppmvd) (Ibhr) NO, I (ppmd) (ibnir)
SO, I (ppmvd) ( IbW CO, (ppmd (Imr)
SO, TO SO, OXIDATION RATE, % CALCULATED NO, REDUCTION
EFFICIENCY, 36 GUARANTEED NO, REDUCTION EFFICIENCY, %
MINIMUM NORMAL MAXIMUM DESIGN
* DATA TO BE PROVIDED BY BUYER
REV
03/96
27
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD*API/PETRO RP 53b-ENGL L97d 0732290 Ob08537 347
POST-COMBUSTION NO, CONTROL (API-RP536) SELECTIVE CATALYTIC NO,
REDUCTION
DATA SHEET4USTOMARY UNITS
I JOB NO. ITEM NO.
_ - ~ _~ SPECIFICATION NO
REVISION NO _ -_- DATE ~ PAGE - 2- OF 4 BY - _
~~~
American Petroleum Institute
1
2
3 4
5
6 7 8
9 10
11 12
13 14 15 16
17 18 19 20
21 22 23
PROCESS DESIGN CONDITIONS (CONTINUED) REV
SCR PERFORMANCE (CONTINUED) : MINIMUM NORMAL MAXIMUM DESIGN
PREDICTED AMMONIA SLIP, ppmvd _ GUARANTEED AMMONIA SLIP, ppmvd
PREDICTED REACTANT CONSUMPTION , Ib/hr GUARANTEED REACTANT
CONSUMPTION, Ibihr CATALYST SPACE VELOCITY. l h r CATALYST AREA
VELOCITY, nBr
FLUE GAS PRESSURE DROP ACROSS AIG, in H,O FLUE GAS PRESSURE DROP
ACROSS REACTOR, in H,O CATALYST CATALYST TYPE
CATALYST COMPOSITION
DESIGN TEMPERATURE LIMIT, MIN /MAX, "F _ ~ INSTALLED CATALYST
VOLUME, cubc feet EXPECTED CATALYST LIFE, years GUARANTEED CATALYST
LIFE, years CATALYST POISONS (LIST ELEMENTS /COMPOUNDS) METHOD OF
DISPOSALOF SPENTCATALYST ENVIRONMENTAL IMPACT OF SPENT CATALYST
-
_ ____- __ - _ _ ~_ ~~
~ ~ ~ - -
~ _ - _ -~~
~ _~ _ ~ __
_ - _ _ _ - _ - _ _ - __ __ _~ _ _
___ _ ~ ~~
_ _ _ _ _
_ _ _ _ _ _ _ - __ - - _ _ _~ _ _ -
_ _ _ _ _ _ _~ ~_ _. - _- ~
_ _-_ _
_ _ _~ ~~
MECHANICAL DESIGN CONDITIONS REACTOR HOUSING AND CATALYST
24
25 26
27
28 29 30 31 32
33 34
35
36 37 38
39
40 41
42 43 44
45 46 47
CATALYST
MANUFACTURERIIYPE CONFIGURATION (PLATE. HONEYCOMB. ETC)
MODULE SIZE, L x W (cmss section) x H (flow direetion), ft
MODULE FRAME MATERIAL MODULE WEIGHT, Ib QUANTITY OF CATALYST
MODULES NUMBER OF MODULE LAYERS/MODULES PER LAYER PROVISION FOR
FUTURE LAYER OF CATALYST (YES) (NO)
REACTOR ORIENTATION (vertica!-up/down) (horizontal) SIZE (L x W
x H). ft CASING MATERIALfHICKNESS, in. REFRACTORY LINING : SIDWEND
WALLS
ROOF FLOOR
REACTOR HOUSING
DESIGN HOT FACE TEMPERATURE, (OF) DESIGN COLD FACE TEMPERATURE,
(OF)
CATALYST LOADINWNLOADING FACILITIES REMOVABLE PANELS ,
NOILOCATIONSISIZES *. ACCESS EOORS, NOJLOCATIONSISIZES **
INSTRUMENT CONNECTIONS :
FLUE GAS PRESSURE-NOJLOCATION/SlZE
FLUE GAS TEMPERATURE-NO./LOCATION/SIZE
03/96
48 49 50 51 52
28
_ _ _ - -_____ _ _ _ _ SAMPLING PORTS-NO./LOCATION/SIZE REACTOR
WEIGHT (WITHOUT MODULESMIITH MODULES), Ib ___ _ ~ _ _ _ _ ____ ~
-
NOTES **VENDOR TO FILLOUT DETAIL INFORMATION UNDER
'MISCELLANE0US'~PAGE 4-OF 4- _ _ __ _ _ -_ _
* DATA TO BE PROVIDED BY BUYER
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
STD-API/PETRO RP 53b-ENGL 1958 B 0732270 0b08538 283 D
American Petroleum Institute _~ ITEMNO _ _ JOB NO
PURCHASE ORDER NO _~ ~ ~_
SPECIFICATION NO -
-
1
2
3 4 5 6
7 8 9
10 11 12 13 14 15 16 17 1s 19 20 21 22 23 24 25 26 27 2a 29 30
31
32 33 34 35 36 37 38 39 4c 41 4:
43 44 45 4e 47 4E 4s
5c 51 5: 52 54 5E
-
DATE ..______~__. ._ ~ POST-COMBUSTION NO, CONTROL (API-RP536)
REVISION NO. SELECTIVE CATALYTIC NO. REDUCTION PAGE --3-. OF
>-BY _ _ _ _ _ ~ _ ~
DATA SHEET-CUSTOMARY UNITS MECHANICAL DESIGN CONDITIONS
(CONTINUED)
AMMONIA INJECTION SYSTEM MANIFOLD
SIZE, OD x THICKNESS, inches MATERIAL (ASTM SPECIFICATIONS AND
GRADE) PIPING DESIGN CODES DESIGN TEMPERATURE (F) AND PRESSURE
(pig) CORROSION ALLOWANCE, inches HYDROTEST PRESSURE, p i g
TERMINAL CONNECTION, (FLANGED) (WELDED)
NO. OF BRANCHED PIPE PIPE SIZE, OD x THICKNESS, inches MATERIAL
(ASTM SPECIFICATIONS AND GRADE) TOTAL NO. OF ORIFICES, ORIFICE SIZE
PIPING DESIGN CODES DESIGN TEMPERATURE (F) AND PRESSURE (pig)
CORROSION ALLOWANCE, inches HYDROTEST PRESSURE, pSig CONNECTION TO
MANIFOLD, (FLANGED) (WELDED)
INJECTION GRID
AMMONIA CONTROL AND DILUTION SYSTEM EQUIPMEM INCLUDED ON
SKID
O DILUTION AIR BLOWERS O AIRHEATER O AMMONIA VAPORIZER O MIXING
VESSEUDEVICE O FILTERSSTRAINERS
INSTRUMENTATION INCLUDED: PRESSURE INDICATORS PRESSURE
TRANSMITTERS PRESSURE SWITCHES FLOW INDICATORS TEMPERATURE
INDICATORS TEMPERATURE TRANSMITTERS FLOW CONTROL VALVES PRESSURE
REGULATORS ANALYZERS
PIPING PIPING CODE MATERIAL (ASTM SPECIFICATIONS AND GRADE)
CORROSION ALLOWANCE, in
DILTION AIR BLWERS: QUANTITY MANUFACTURER AND TYPE FLOW RATE,
scfh, DESIGNNORMAL STATIC PRESSURE, inches wc MOTOR MANUFACTURER
HORSEPOWER
O LOCAL CONTROL PANEL O LOCAL STOP/EMERGENCY STOP SWITCHES O
INTERCONNECTING PIPING & DUCTING O ELECTRICAL & INSTRUMENT
WIRING O FLANGED CONNECTIONS SKID EDGE O DRAIN
* DATA TO BE PROVIDED BY BUYER
03/98
29
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
- ~ _-
STD*API/PETRO RP 53b-ENGL 199d 111 0732270 Ob08537 LIT m
American Petroleum Institute SPECIFICATION NO -.
REVISION NO DATE -- POST-COMBUSTION NO. CONTROL (API-RP536)
- 1
2 3 4
5 6 7 8
9 IC Il
1;
I: I 4
I:
If l i I f I' !C !1 !Z
!$
!4
!e !f !i ?f !S c
1
1; E M 1: If 17
19 S It Il li I: 14 4!
If I 7 II I S 5l 5 5: 5: i s! 5(
-
SELECTIVE CATALYTIC NO. REDUCTION PAGE DATA SHEET-CUSTOMARY
UNITS
MECHANICAL DESIGN CONDITIONS (CONTINUED) REV
DILLITION AIR BLOWERS (CONTINUED) POWER: VOLTAGUHERTUPHASE
ISOLATION AND CHECK VALVES INCLUDED (YES) (NO) INLET AIR
FILTEWSILENCER TYPE SPECIAL REQUIREMENTS
&MMONIA TANK MANUFACTURER CONFIGURATION (VERTICAUHORIZONTAL)
DESIGN CODE ASME CODE STAMP (YES) (NO) DESIGN TEMPERATURE,
"FAIESIGN PRESSURE, psig MATERIAL (ASTM SPECIFICATION AND GRADE)
CAPACITY, gal SIZE (OD/ID x LENGTH Trr) in CORROSION ALLOWANCE,
inches
MANUFACTUREFKWPE CONFIGURATION (VERTICAUHORIZONTAL) HEAT INPUT,
(mmthr) (kW)/HEATING MEDIUM POWER : VOLTAGEIHERTUPHASE DESIGN CODE
DESIGN TEMPERATURE, "FAIESIGN PRESSURE, psig MATERIAL (ASTM
SPECIFICATION AND GRADE) CORROSION ALLOWANCE, inches VAPORIZER
SIZE
AMMONIA VAPORIZER
AIR HEATER MANUFACTURER AND TYPE DESIGN HEAT INPUT, (mmthr) ( kW
)/HEATING MEDIUM POWER: VOLTAGWERNPHASE SIZE
MISCELLANEOUS : PUTFORIS:
LOCATIONINO. WIDTH LENGTH/ARC
PIPE OF FLOORING, ETC.
DOORS NUMBER RCCESS DBSERVATION CATALYST REMOVAL INSPECTION -
PAINTING AND GALVANIZING REQUIREMENTS
-_
ACCESS BY FROM
STAIRCRADDER GRADEIPLATFORMROCATION
LOCATION SIZE HINGED OR BOLTED
UTILTTY DATA
POWER VOLTAGEWERNPHASE INSTRUMENT POWER VOLTAGEIHERTUPHASE u n u
n AIR PRESSURE NORMALIDESIGN. pslg INSTRUMENT AIR PRESSURE
NORMAUDESIGN, psig STEAM PRESSURE NORMAUDESIGN, psig _ REACTANT
PRESSURE NORMAUDESIGN, psig ELECTRICAL AREA CLASSIFICATION ' DATATO
BE PROVIDED BY BUYER
_
- - TEMPERATURE NORMAUDESIGN, 'F - - TEMPERATURE NORMAVDESIGN,
OF __._ -
__ .
03/90
30
COPYRIGHT 2002; American Petroleum Institute
Document provided by IHS Licensee=Sincor Venezuela/5934214100,
User=, 08/14/2002 11:31:03 MDT Questions or comments about this
message: please callthe Document Policy Management Group at
1-800-451-1584.
-
~
STD.API/PETRO RP 53b-ENGL. 1998 W 0732270 O b 0 8 5 ~ O 931
=
American Petroleum Institute
POST-COMBUSTION NO, CONTROL (API-RP536) SELECTIVE CATALYTIC NO,
REDUCTION
DATA SHEET-SI UNITS
ITEM NO - ~ JOBNO ~~
PURCHASE ORDER NO
SPECIFICATION NO
REVISION NO
PAGE 1 OF -4-- BY
~-
~- _ - ___ ____ - DATE . ~ _ _ _
~ _ _ _ _ _ _ ~ - 1 '2 '3 '4
'5 6 7
8 9
10
'1 1 '1 2 '1 3 '1 4
'1 5 '1 E '1 7 '1 a '1 9 '20 '21 '22 '23 '24 '25
'27 '28 '29
'30 '31
33 34 35
37
40
41
42 43 44
46 47
49
51 52 53 54 55 56
-
OPERATING CONDITIONS: EQUIPMENT FIRING RATE, MW (LHV) (HHV) FLUE
GAS FLOW TO BE TREATED, WET BASIS, kg/s FLUE GAS TEMPERATURE
ENTERING AIG, "C FLUE GAS TEMPERATURE ENTERING REACTOR, "C
FUEL DESCRIPTION FLUE GAS COMPOSITION:
OXYGEN (03 (%volume, wet) NITROGEN (N,) (%volume, wet) WATER
(H,O) (%volume, wet) CARBON DIOXIDE (COJ (%volume, wet) ARGON (Ad
(%volume, wet) PARTICULATES, kg/s INLET NO,, (ppmvd) (kgs)
INLETCO (ppmvd) (kgis) INLET SO,, (ppmvd) (kgis) TRACE ELEMENTS,
(ppmvd) (kg/s):
CORRECTED INLET NO, AT% 0, (ppmvd) (kg/s)
FLUE GAS FLOW (vertical-upidown) (horizontal) TO SCR AMMONINNO,
MO