Caltex Process Plant Corrosion

SECTION 3

PROCESS PLANT CORROSION

REFINERY MATERIALS MANUAL

October 1999

SECTION 3 PROCESS PLANT CORROSION TABLE OF CONTENTS 1.0

ABSTRACT ................................................................ ................................................................................................ ............................................... ............... 1

2.0

INTRODUCTION ................................................................ ................................................................................................ ...................................... ...... 1

3.0

REFINERY OPERATING OPERATING OBJECTIVES ................................................................ ............................................................................ ............ 1

3.1 3.2 3.3 3.4 3.5 3.6

SAFETY, THE ENVIRONMENT, AND RELIABILITY............................................................................2 REFINING PROCESS OVERVIEW.....................................................................................................3 REFINERY PROCESS FLOW ............................................................................................................5 PROCESS INTERACTIONS WITH CORROSION.............................................................................11 ROLE OF PERSONNEL IN EQUIPMENT INTEGRITY.......................................................................11 CONCLUSION............................................................................................................................12

4.0

CRUDE UNIT................................ UNIT ................................................................ ................................................................ .......................................... .......... 13

4.1 4.2 4.3 4.4

CRUDE UNIT CORROSION AND CORROSION CONTROL ...........................................................13 CRUDE UNIT PROCESS DESCRIPTION.........................................................................................13 CRUDE DESALTING ....................................................................................................................17 MATERIALS OF CONSTRUCTION................................................................................................19 4.4.1 Columns .............................................................................................................................19 4.4.2 Exchangers and Piping........................................................................................................20 4.4.3 Fired Heaters.......................................................................................................................21 4.5 MATERIALS AND CORROSION PROBLEMS..................................................................................22 4.5.1 Inorganic Salts ....................................................................................................................22 4.5.2 Sulfur Compounds ..............................................................................................................22 4.5.3 Organic Acids .....................................................................................................................23 4.5.4 Organic Chlorides ...............................................................................................................24 4.5.5 Corrosion Control Measures................................................................................................24 4.5.6 Corrosion Monitoring .........................................................................................................27 4.6 INSPECTION...............................................................................................................................29

5.0 5.1 5.2 5.3

FLUID CATALYTIC CRACKING UNIT ................................................................ ......................................................................... ......... 31

ABSTRACT ..................................................................................................................................31 INTRODUCTION ........................................................................................................................31 FLUID CATALYTIC CRACKING UNIT PROCESS DESCRIPTION ......................................................31 5.3.1 Cracking Reaction ...............................................................................................................31 5.3.2 Catalyst / Catalyst Circulation .............................................................................................32 5.3.3 Cat Cracker Hardware / Process Flow ..................................................................................32 5.3.4 Riser/Reactor.......................................................................................................................33 5.3.5 Regenerator ........................................................................................................................34 5.3.6 Catalyst Transfer System .....................................................................................................34 5.3.7 Flue Gas System ..................................................................................................................35 5.3.8 Main Fractionator ...............................................................................................................35 5.4 MATERIALS OF CONSTRUCTION................................................................................................41 5.4.1 Reactors..............................................................................................................................41 5.4.2 Regenerator ........................................................................................................................43 5.4.3 Catalyst Transfer Piping System...........................................................................................45

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5.4.4 Reaction Mix Line, Main Fractionator and Bottoms Piping...................................................45 5.4.5 Flue Gas System ..................................................................................................................46 5.5 CORROSION / METALLURGICAL DAMAGE MECHANISMS AND CONTROL MEASURES...............46 5.5.1 High Temperature Oxidation ..............................................................................................47 5.5.2 High Temperature Sulfidation .............................................................................................48 5.5.3 High Temperature Carburization.........................................................................................49 5.5.4 Polythionic Acid Stress Corrosion Cracking (PASCC)............................................................49 5.6 CATALYST EROSION ...................................................................................................................50 5.6.1 High Temperature Graphitization........................................................................................51 5.6.2 Sigma Phase Embrittlement ................................................................................................51 5.6.3 885oF Embrittlement...........................................................................................................52 5.6.4 Creep Embrittlement...........................................................................................................52 5.6.5 High Temperature Creep ....................................................................................................53 5.6.6 Thermal Fatigue ..................................................................................................................53 5.7 INSPECTION/MONITORING METHODS .....................................................................................53

6.0

6.1

CATALYTIC LIGHT ENDS RECOVERY UNIT ................................................................ ................................................................ 59

ABSTRACT ..................................................................................................................................59 6.1.1. CLER Process Description ....................................................................................................59 6.2 MATERIALS OF CONSTRUCTION................................................................................................59 6.2.1. Columns .............................................................................................................................59 6.2.2 Exchangers .........................................................................................................................60 6.2.3 Piping .................................................................................................................................60 6.3 CORROSION PROBLEMS ............................................................................................................60 6.3.1 Hydrogen Induced Damage ................................................................................................61 6.3.2 Ammonia Stress Corrosion Cracking....................................................................................62 6.3.3 Carbonate Stress Corrosion Cracking ..................................................................................62 6.3.4 Fouling/Corrosion of Reboiler Circuits .................................................................................62 6.4 CONTROL MEASURES ...............................................................................................................62 6.4.1 Water Washing ...................................................................................................................62 6.4.2 Polysulfide Injection ............................................................................................................64 6.4.3 Corrosion Inhibitors ............................................................................................................64 6.4.4 Corrosion Monitoring .........................................................................................................64 6.4.5 Corrosion Probes ................................................................................................................65

7.0

7.1 7.2

CATALYTIC REFORMING REFORMING UNIT ................................................................ ................................................................................ ................ 69

CORROSION ..............................................................................................................................69 MATERIALS .................................................................................................................................70

8.0

HYDROPROCESSING UNITS ................................................................ .................................................................................... .................... 75

8.1 8.2 8.3 8.4

ABSTRACT ..................................................................................................................................75 INTRODUCTION ........................................................................................................................75 PROCESS DESCRIPTIONS............................................................................................................76 MATERIALS SELECTION ..............................................................................................................76 8.4.1 Reactor System ...................................................................................................................76 8.4.2 Reactor Feed System ...........................................................................................................77 8.4.3 Reactors..............................................................................................................................77 8.4.4 Reactor Effluent System.......................................................................................................78 8.4.5 Reactor Effluent - Distillation Feed Exchangers.....................................................................78 8.4.6 Effluent Air Coolers .............................................................................................................78 8.4.7 Effluent Air Cooler Inlet and Outlet Piping...........................................................................79 8.4.8 Separator Vessels.................................................................................................................80 8.4.9 Recycle Hydrogen System ...................................................................................................80 8.4.10 Distillation Section ..........................................................................................................80

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8.5

CORROSION PHENOMENA IN HYDROPROCESSING UNITS........................................................81 8.5.1 High Temperature Hydrogen Attack....................................................................................81 8.5.2 High Temperature Hydrogen Sulfide / Hydrogen Corrosion ................................................82 8.5.3 High Temperature Hydrogen Sulfide Corrosion in Areas with Negligible Hydrogen .............82 8.5.4 Naphthenic Acid Corrosion .................................................................................................83 8.5.5 Ammonium Bisulfide Corrosion...........................................................................................83 8.5.6 Chloride Stress Corrosion Cracking .....................................................................................85 8.5.7 Polythionic Acid Stress Corrosion Cracking (PASCC)............................................................86 8.5.8 Wet H2S Cracking ...............................................................................................................86 8.5.9 Material Property Degradation Mechanisms ........................................................................88

9.0

ALKYLATION UNIT ................................................................ ................................................................................................ .................................. 95

9.1 9.2

ABSTRACT ..................................................................................................................................95 PROCESS DESCRIPTION..............................................................................................................95 9.2.1 Reaction Section .................................................................................................................95 9.2.2 Treating Section..................................................................................................................96 9.2.3 Fractionation Section ..........................................................................................................96 9.2.4 Refrigeration Section...........................................................................................................96 9.3 MATERIALS OF CONSTRUCTION..............................................................................................101 9.4 MATERIALS AND CORROSION PROBLEMS................................................................................101 9.4.1 Sulfuric Acid Corrosion......................................................................................................102 9.4.2 Acid and Neutral Esters .....................................................................................................103 9.4.3 Acid Carry-over .................................................................................................................104 9.4.4 Corrosion Under Insulation ...............................................................................................104 9.4.5 Fouling Problems ..............................................................................................................105 9.5 CORROSION CONTROL MEASURES..........................................................................................105 9.5.1 Reactor Section Corrosion .................................................................................................105 9.5.2 Tower Overhead Corrosion ...............................................................................................105 9.5.3 Reboiler Corrosion and Fouling Control ............................................................................106 9.5.4 Acid Tanks ........................................................................................................................106 9.5.5 Corrosion Control During Unit Shutdowns........................................................................107 9.5.6 Corrosion Under Insulation ...............................................................................................107 9.5.7 Corrosion Monitoring .......................................................................................................107

10.0 AMINE TREATING UNIT ................................................................ ........................................................................................ ........................ 111 10.1 10.2 10.3

ABSTRACT ................................................................................................................................111 INTRODUCTION ......................................................................................................................111 TYPES OF AMINES USED...........................................................................................................111 10.3.1 Monoethanolamine (MEA) ............................................................................................111 10.3.2 Diethanolamine (DEA)...................................................................................................112 10.3.3 Methyldiethanolamine (MDEA) .....................................................................................112 10.3.4 Diisopropanolamine (DIPA) ...........................................................................................112 10.3.5 Diglycolamine Agent (DGA) ..........................................................................................112 10.3.6 Specialty Amines ...........................................................................................................112 10.4 REFINERY AMINE UNIT PROCESS DESCRIPTION .......................................................................113 10.5 CORROSION PHENOMENA ......................................................................................................117 10.6 CORROSIVE SPECIES.................................................................................................................118 10.7 AMINE DEGRADATION.............................................................................................................121 10.8 CRACKING PHENOMENA .........................................................................................................122 10.9 CORROSION INHIBITORS .........................................................................................................122 10.10 MATERIALS OF CONSTRUCTION..............................................................................................123 10.11 CORROSION MONITORING .....................................................................................................123 10.12 CORROSION CONTROL MEASURES..........................................................................................124

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11.0 MEROX TREATING UNITS ................................................................ ..................................................................................... ..................... 126 11.1 11.2

MEROX EXTRACTION...............................................................................................................126 MEROX LIQUID/LIQUID SWEETENING......................................................................................126 11.2.1 Merox Solid Bed Sweetening.........................................................................................126 11.2.2 Merox Minalk Sweetening.............................................................................................127 11.2.3 Pretreatment.................................................................................................................127 11.2.4 Post Treatment..............................................................................................................128 11.3 MATERIAL OF CONSTRUCTION................................................................................................128 11.4 TYPES OF CORROSION.............................................................................................................128 11.5 CORROSION CONTROL MEASURES..........................................................................................129 11.5.1 Corrosion Monitoring ...................................................................................................129 11.6 INSPECTION.............................................................................................................................129

12.0 SOUR WATER STRIPPING STRIPPING UNIT ................................................................ .............................................................................. .............. 133

12.1 12.2 12.3 12.4

PROCESS ..................................................................................................................................133 CORROSION PROBLEMS ..........................................................................................................133 CORROSION CONTROLS .........................................................................................................133 MATERIALS SELECTION ............................................................................................................133

13.0 SULFUR RECOVERY UNITS................................ UNITS ................................................................ ..................................................... ..................... 137 13.1 13.2

PROCESS ..................................................................................................................................137 MATERIALS ...............................................................................................................................137

14.0 SELECTION OF CORROSION CORROSION MONITORING METHODS -REFINERY APPLICATIONS.... APPLICATIONS .... 141

14.1 14.2 14.3

ABSTRACT ................................................................................................................................141 INTRODUCTION ......................................................................................................................141 TYPES OF CORROSION MONITORING TECHNIQUES................................................................141 14.3.1 Corrosion Coupons .......................................................................................................142 14.3.4 Electrochemical Methods ..............................................................................................144 14.3.5 Linear Polarization Resistance Method ...........................................................................144 14.3.6 Other Types Of EC Monitoring......................................................................................145 14.3.7 Hydrogen Flux Monitoring ............................................................................................146 14.4 CORROSION MONITORING .....................................................................................................148 14.4.1 Chemical Injection ........................................................................................................148 14.4.2 Dewpoint......................................................................................................................149 14.5 SUMMARY OF CORROSION MONITORING CONSIDERATIONS IN REFINERY UNITS .................149 14.5.1 Atmospheric Distillation Unit.........................................................................................149 14.5.2 Vacuum Distillation Unit................................................................................................150 14.5.3 Fluid Catalytic Cracking Unit .........................................................................................150 14.5.4 Amine Treating Unit......................................................................................................150 14.5.5 Sour Water Stripping Units............................................................................................151 14.5.6 Sulfuric Acid Alkylation Unit ..........................................................................................151 14.6 AUTOMATED ON-LINE MONITORING AND DATA ANALYSIS ...................................................151 14.7 NDT and Corrosion Monitoring Techniques..............................................................................152 14.8 CONCLUSIONS ........................................................................................................................152

TABLE OF TABLES Table 3-1 Table 3-2 Table 3-3 Table 3-4 Table 3-5

Related Standards and Regulations ........................................................................................2 Common Refining Processes ..................................................................................................4 Typical Refinery Process Selection ..........................................................................................5 FCC Unit Reactor, Regenerator & Main Fractionator Damage Mechanisms ..........................47 Inspection & Control Measures for FCCU Reactor, Regenerator & Main

REFINERY MATERIALS MANUAL

Table 3-6 Table 3-7 Table 3-8 Table 3-9 Table 3-10 Table 3-11 Table 3-12 Table 3-13

Fractionator Damage Mechanisms (1) ...................................................................................57 Common Corrosion Probe Locations in Sulfuric Acid Alkylation Units.................................108 Common Stream Analyses for H2SO4 Alkylation..................................................................108 Acid Gas Absorption Reactions...........................................................................................117 Chemical Data on Selected Substances ..............................................................................118 Corrosion Reactions in Amine Systems ...............................................................................119 Activity of Sweetening Catalyst ..........................................................................................127 Matrix of Available Corrosion Monitoring Techniques ........................................................153 Application of NDT Techniques to Detect and Monitor Corrosion......................................154

TABLE OF FIGURES Figure 3-1 Figure 3-2 Figure 3-3 Figure 3-4 Figure 3-5 Figure 3-6 Figure 3-7 Figure 3-8 Figure 3-8 Figure 3-9 Figure 3-10 Figure 3-11 Figure 3-12 Figure 3-13 Figure 3-14 Figure 3-15 Figure 3-16 Figure 3-17 Figure 3-18 Figure 3-19 Figure 3-20 Figure 3-21 Figure 3-22

October 1999

Simplified Refinery Flow Diagram………………….………………………………………………. 9 Generic Crude Unit…………………………………………………………………...……………. 15 Generic Fluid Catalytic Cracking Unit - Process Flow Diagram………………………………. 37 Generic Fluid Catalytic Cracking Unit - Materials of Construction Diagram……………… 39 Generic Fluid Catalytic Cracking Unit - Inspection Summary Diagram……………………….55 Catalytic Cracking Light Ends Recovery Unit…………………………………………………..…67 Semi-Regenerative Catalytic Reforming Unit………………………………………………….….73 Page 1 Hydrodesulfurizers and Hydrofiners………………………………………………….….91 Page 2 Hydrocracking……………………………………………………………………………..93 Typical Auto-Refrigeration Alkylation Plant with Stirred Reactors …………………………..…97 Typical Effluent Refrigeration Alkylation Plant with Contactor-Type Reactor………………....98 Typical Caustic and Water Wash Facility……………………………………………………….…99 Typical Fractionation Facility…………………………………………………………………….…99 Refinery Primary Amine Systems with Multiple Absorbers………………………………….... 115 Quench Tower and Tail Gas Unit ……………………………………………………………….116 Merox Mercaptan Extraction Unit ………………………………………………………………131 Liquid-Liquid Merox Sweetening Unit …………………………………………………………..131 Conventional Fixed-Bed Merox Sweetening Unit……………………………………………. 132 Minalk Fixed-Bed Merox Sweetening Unit …………………………………………………… 132 Sour Water Strippers (Acidified)………………………………………………………………… 135 Sour Water Strippers (Non-Acidified)……………………………………………………………135 Typical Conventional Refluxed Sour Water Stripper……………………………………………136 Sulfur Plant………………………………………………………………………………………….139

REFINERY MATERIALS MANUAL

October 1999

REFINERY MATERIALS MANUAL

1.0

October 1999

ABSTRACT Optimization of corrosion control in petroleum refineries, which includes metallurgical upgrading, addition of corrosion inhibitors or water washing, and other operational or maintenance procedures, is a function of a variety of factors. A number of these factors relate to the basic operating objectives of the individual refinery and what processes and feed stocks are used to achieve those objectives. Maintaining the integrity of process equipment and achieving safe and profitable operations, requires a balance of these objectives and an understanding of operations and corrosion interactions. Inspection, engineering, operations and maintenance personnel all play roles in maintaining equipment integrity and implementing corrosion control measures.

2.0

INTRODUCTION The purpose of this overview of refinery operations is to put in perspective for both technical staff and operations personnel how refineries operate and how these operations may influence corrosion control. This section discusses the general aspects of refinery operations as an introduction to the more detailed process unit reviews in the following sections. An overview of the interaction of refinery objectives, safety, process change and various refinery personnel with corrosion control is covered.

3.0

REFINERY OPERATING OPERATING OBJECTIVES Individual oil companies and refineries have individual operating objectives that are major considerations when determining what feed stocks to run, which processes to employ and what products to produce. However, in a broad sense, a petroleum refinery's fundamental goal is to maximize its contribution to corporate profitability consistent with safe, environmentally responsible operations. These goals can be achieved in many ways. In some cases, the use of light, clean feed stocks may provide the correct product blend required for a target market. This could minimize capital investment as sophisticated upgrading and cleanup processes would not be needed. In a market with a high demand for motor gasoline and distillate fuels, higher-investment and more complex upgrading facilities are often justified. Where the investment in such upgrading is made, heavy, low-quality, low-cost feed stocks are economically attractive. These feed stocks are often corrosive and may require the use of high alloy materials or other costly corrosion controls. A company's marketing goals establish the extent to which they refine crude oil. A refinery committed to the lubricating oil business requires specialized processing. Other companies may produce and sell unfinished products which can be used by others in fuels or lubes upgrading, the production of petrochemicals, and so forth. All such decisions are driven by economic considerations which ultimately influence the level of investment in equipment, the process employed, the feed stocks to be processed, the products made and the design basis of equipment.

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REFINERY MATERIALS MANUAL

3.1

October 1999

SAFETY, THE ENVIRONMENT, ENVIRONMENT, AND RELIABILITY Operating safety and the protection of the environment are critical concerns to all refiners and impact how plants are designed and operated. The costs and risks associated with a safety-related incident and the increasing legislation and industry standards surrounding protection of employees, neighboring citizens and the environment, all have an impact on how refineries operate. The condition of operating equipment can have major impact on the reliability and operational integrity of a plant as they impact safety and the environment. Table 3-1 lists several of the regulations and standards which are important in this regard. TABLE 3-1

RELATED STANDARDS AND REGULATIONS

REGULATION/STANDARD

SUBJECT

OSHA 1920.119j

Mechanical integrity programs

API 510

Inspection, repair and re-rating of pressure vessels

API 570

Inspection and repair of piping

API 650, 651, 652, 653

Design, inspection, repair, cathodic protection of tankage

API RP 530

Design of fired heaters

NBIC

National Board code covering inspection and repair of pressure vessels

ASME Boiler and Pressure Vessel Code

New pressure vessel design, fabrication and inspection

ASME Piping Code

New piping design, fabrication and inspection

NACE RP0170

Prevention of polythionic acid stress corrosion cracking

NACE RP0472

Prevention of cracking of CS welds

NACE RP0296

Inspection, fabrication and repair of equipment in wet H2S service

South African Standards

New vessel design, fabrication and inspection

Australian Standards

New vessel design, fabrication and inspection

Japanese high Pressure Gas Law

New vessel design, fabrication and inspection

Korean High pressure Gas Law

New vessel design, fabrication and inspection

British Standard 5500

New vessel design, fabrication and inspection

Corrosion and materials problems are important contributors to equipment condition. The role of the inspector and the materials, corrosion, equipment or facilities engineer is to take an understanding of these problems and develop it into monitoring, inspection and corrosion control programs which comply with the prevailing regulatory requirements and refinery objectives. These programs can then be used to identify problems before they affect safe operations or the environment. The reliability of equipment may be an important factor impacting operations even though it may not directly impact safety or the environment. Companies or operating plants which strongly depend upon a high and predictable service factor of equipment, low operating costs, and/or a high level of process integration may be unable to afford an unplanned shutdown due to an equipment materials or corrosion problem. Such operating demands may warrant the use of higher alloys, increased monitoring, and/or the use of process additives in order to ensure reliable operations. In other cases, however, pressures to minimize capital investment, the

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availability of spare capacity, and/or the influence of cyclical business environment may warrant the acceptance of somewhat lower reliability. In order to address these kinds of issues, it is necessary to develop an understanding of the factors which influence equipment reliability.

3.2

REFINING PROCESS OVERVIEW Petroleum refineries vary widely in complexity and processes employed in order to manufacture the required products. Table 3-2 lists many of the various processes employed in the refining industry. Simple refineries may produce fuels from basic crude distillation and limited upgrading and product clean-up. Complex refineries may utilize various conversion and upgrading processes to make larger quantities of valuable lighter fuels from relatively heavy, low-cost streams. Other specialty processes are used to manufacture lubricating oils in some plants. Nearly all refineries operate supporting utilities processes which provide steam, cooling water and clean fuels for internal use, such as for firing process heaters, as well as disposal of waste waters. Feed stocks and products are handled in what are often a complex arrangement of tankage and piping.

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TABLE 3-2 COMMON REFINING PROCESSES

Basic Distillation Atmospheric Distillation Crude Light Ends Separation Vacuum Distillation

Light Product Upgrading Catalytic Reforming Alkylation Isomerization

Desulfurization Hydrotreating Naphtha Distillates Gas Oils Residuum

Heavy Oil Upgrading Hydrockracking Fluid Catalytic and Light Ends Separation Coking and Light Ends Separation Thermal Cracking Visbreaking

Supporting Processes Amine Treating Caustic Treating Sour Water Stripping Sulfur Recovery H2 Manufacture (Steam Reforming), partial oxidation Pressure Swing Absorption MTBE Production

Utilities Cooling Water Boiler Feed Water Treatment Steam Generation Waste Water Treatment Flare Systems Cogeneration Facilities

Lube Processing Lube Extraction Dewaxing Deasphalting Lube Hydrotreating

Oil Movement and Storage Product Blending Piping Tanks Pressurized Spheres

A refinery which uses only limited processes to produce basic fuels (gas, LPG, motor gasoline, distillates) is called a 'hydroskimming refinery'. Hydroskimming refineries do not upgrade heavy residual oils to lighter products, and they generally endeavor to limit the production of heavy fuel oils by running lighter crude feeds which are often higher cost. Table 3-3 lists the common refinery process found in a hydroskimming refinery. A refinery which has more complex processes to convert heavy oil fractions to more valuable lighter products is often referred to as a 'conversion refinery'. Conversion refineries usually run heavy, lower quality crudes or crude blends. They not only require special heavy oil upgrading processes, but they also generally operate additional light product upgrading processes for increasing the octane of motor gasoline blending components. Several product cleanup facilities are provided as the crudes they run are generally high in sulfur and other contaminants. Table 33 lists refining processes common to conversion refineries. Some conversion refineries may not operate cokers. Others may use thermal crackers or Visbreakers in their place.

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TABLE 3-3 TYPICAL REFINERY PROCESS SELECTION Hydroskimming Refinery

Conversion Refinery

Atmospheric Distillation

Atmospheric Distillation

Crude Light Ends Separation

Crude Light Ends Separation

Vacuum Distillation

Vacuum Distillates

Hydrotreating

Hydrotreating

Naphtha

Naphtha

Distillates

Distillates

Catalytic Reforming

Gas Oils

Merox Treating

Catalytic Reforming

Amine Treating

Caustic Treating

Sour Water Stripping

Fluid Catalytic Cracking

Sulfur Plant

Coking

Utilities

Alkylation

Oil Movement and Storage

Hydrocracking Steam Reforming Partial Oxidation Amine Treating Sour Water Stripping Sulfur Plant Utilities Oil Movement and Storage

3.3

REFINERY PROCESS FLOW Figure 3-1 is a flow diagram showing an overview of a full conversion refinery operations. It illustrates how processes are typically inter-linked and what products they produce. The processes illustrated in this flow diagram are the principal ones utilized to produce the basic petroleum products of such a refinery. Utility units are not shown. The types and order of processes used will vary from refinery-to-refinery, and this process selection will dictate the kinds of products obtained. Crude oil or blends of crudes are first fractionated at elevated temperature in atmospheric distillation units which separate them into basic products such as gas, naphtha, light distillates (diesel and kerosene), light gas oils and atmospheric residuum. The residuum from the atmospheric distillation unit is usually sent to a vacuum distillation unit which primarily separates a range of heavy gas oils or lube feed stocks. As their names imply, atmospheric and vacuum distillation take place at pressures slightly above atmospheric and at vacuum respectively. The light streams from the crude distillation unit are separated in light ends facilities into fuel gas (methane and ethane), LPG, butane and a variety of other hydrocarbons such as C3, C4 and C5 products. Some of these streams are used as feeds to petrochemical plants. The fuel gas is often

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used within the refinery as fuel for the plant's fired process heaters and boilers. The fuel gas may be used in cogeneration operations to generate steam and electric power. The naphtha stream is often processed in a catalytic reforming unit following hydrotreating to reduce sulfur which is a reforming catalyst poison. Reforming processes increase the octane value of these fuels. A by-product of catalytic reforming is hydrogen which is used in hydrotreating processes as they consume hydrogen as part of their reactions. In refineries which have a high hydrogen demand due to sulfur removal (i.e. hydrodesulfurization) and hydro-conversion needs, hydrogen is produced in steam reforming units or, in some cases, partial oxidation units. In hydrogen plants, a light hydrocarbon, such as methane, natural gas or naphtha, is reacted with steam in catalyst-filled fired heater tubes to produce hydrogen and carbon dioxide as a by-product. Gas treating or Pressure Swing Absorption (PSA) processes are used to remove the CO2 from the hydrogen produced to provide higher purity hydrogen for hydrotreating and hydrocracking processes. Partial oxidation units use gas, heavy gas oils, resid and coke or coal plus oxygen to produce a synthesis gas which is water gas reaction shifted to produce hydrogen. The hydrogen clean up is similar to the clean up facilities on a steam methane reformer except that H2S must be handled. Distillate fuels, which are heavier than naphtha, from both crude distillation and upgrading processes, are usually hydrotreated to reduce their sulfur content. They are then blended to produce kerosene, diesel and jet fuels. The gas oil streams from atmospheric and vacuum distillation may be blended into fuel oils at refineries which have no further processing. In some cases, these fuels will be hydrotreated to reduce the level of sulfur present. Many refineries, however, use these gas oils as feeds to catalytic cracking units and hydrocracking units to produce additional gasoline and middle distillate fuels. Many refiners also charge reduced crude to the FCC’s. Catalytic cracking unit feeds are sometimes hydrotreated. Products from catalytic cracking units are 'unsaturated' or hydrogen deficient, meaning they have fewer hydrogen atoms per carbon atom which results in undesirable properties. The lightest products are separated and blended into fuel gas. Gasoline-range materials may be reformed by processing in alkylation, polymerization or isomerization units to provide octane-improving blending components for motor fuel. Heavier products may be hydrotreated, used as hydrocracker feeds or blended into fuel oil. Vacuum fractionator bottoms may be blended into fuel oils or upgraded in coking processes. Coking processes are thermal cracking processes which operate on the principal of carbon rejection in which the coking process releases excess carbon in the form of coke. Coker feeds are not desulfurized prior to processing. In coking, heavy hydrocarbons are cracked producing lighter hydrocarbons and petroleum coke. This coke is essentially carbon which contains some concentration of metals like sodium and vanadium which occur naturally in crude oil. This coke is also a saleable product. Coker products are usually processed in fractionation and light ends facilities similar to those used for fluid catalytic cracking unit products. Vacuum distillation unit products may also be used as feed stocks for lube oil production. The high value lube base stocks (raffinate) are extracted from these streams using solvent extraction. The low value extract is often used as feed to catalytic cracking units while the raffinate is hydrotreated, dewaxed and then blended with various additives to make a range of lubricating oils with a variety of properties.

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Hydroprocessing is widely used throughout refineries and covers two basic types of operations: (a) hydrodesulfurization (and denitrification) (b) and hydroconversion. In both types of processes, the stream being processed and hydrogen are heated, combined and reacted in a catalyst-filled vessel or reactor. The hydrogen and sulfur react to form hydrogen sulfide which ends up in both the recycle hydrogen stream and the sour water streams as well as the main reactor effuent stream. Generally, heavier oil streams are processed at higher pressures and temperatures than lighter oil streams. Nitrogen removal is also accomplished to some extent in heavy oil desulfurization. Hydrocracking is the most common hydroconversion process. In hydrocracking, not only is sulfur removed, but heavier oils are also converted to lighter, higher value products. A number of supporting processes are part of the basic operation in most refineries. One such process is amine treating which removes hydrogen sulfide (H2S) from fuel gas, recycle hydrogen gas from hydrotreating units, and LPG. Sour water strippers are used to reduce the H2S and ammonia contents of refinery process condensates so these waters can be re-used in the plant or discarded. The H2S recovered in these units is converted to elemental sulfur in sulfur plants. This sulfur is often sold to manufacturers of sulfuric acid or fertilizers. Refineries also operate a number of important utilities units. Cooling water systems consisting of one or more cooling towers, water treatment facilities and a network of piping distribute water throughout the plant to supply some of the needed process cooling capacity. Steam generation facilities, although sometimes integrated with the major process units, often consist of fired boilers although co-generation facilities using gas turbines to generate steam and electricity are becoming common. Steam is used throughout refineries to aid distillation and product stripping, to drive pump and compressor power turbines and for other purposes. In order to provide high quality water for the boilers, water treatment plants are usually part of the boiler plant. These units provide demineralized, deaerated and chemically treated water necessary for high quality steam without boiler fouling and corrosion problems. A flare system collects and burns process releases from pressure relief systems. Waste water from the plant is treated in a series of steps to remove environmental pollutants prior to discharge.

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FUEL GAS

LIGHT ENDS RECOVERY

AMINE TREATING

LPG SULFUR PLANT

H2S

CRUDE OIL

CATALYTIC REFORMING

HYDROTREATING

NAPHTHA

SOUR TREAT GAS

ATMOSPHERIC DISTILLATON

HS2O4 /HF ALKYLATION

SOUR TREAT GAS

KEROSENE HYDROTREATING

MIDDLE DISTILLATES

MOTOR GASOLINE

AMINE TREATING

H2 CRUDE DESALTING

SULFUR

FCCU FRACTIONATION & LIGHT ENDS

HYDROCRACKING NATURAL GAS STEAM

HYDROGEN PLANT/CO2 REMOVAL

KEROSENE H2

JET FUEL DIESEL FUEL HEATING OIL

ATMOSPHERIC GAS OILS

CATALYTIC CRACKING

HYDROTREATING LUBE EXTRACT OILS

REDUCED CRUDE

VACUUM DISTILLATION

LUBE EXTRACTION VA C U U M GASOILS

FUEL OIL

LUBE RAFFINATE

HYDROTREATING LUBE BASE STOCKS

DEWAXING DEASPHALTING

WAX

VACUUM RESUDUUM

ASPHALT

COKER FRACTIONATION & LIGHT ENDS

SIMPLIFIED REFINERY FLOW DIAGRAM Figure 3-1

DELAYED COKING/ FLUID COKING/ FLEXICOKING

COKE

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3.4

October 1999

PROCESS INTERACTIONS INTERACTIONS WITH CORROSION As Figure 3-1 illustrates, refinery processes are closely linked to each other. Such a high level of process integration carries with it potentially far-reaching effects when feed or process changes are considered or when corrosion control measures are being evaluated. Changes in feed stocks can have effects in many units. A refinery can not arbitrarily elect to run crude oil feeds higher in sulfur, for example, without considering the broad process and corrosion design issues. From a process standpoint, higher sulfur levels may risk overloading the sulfur removal capabilities of hydrotreating, amine treating and sulfur recovery plants. Such a change also has far reaching corrosion implications. Corrosion can increase in the distillation units and downstream processes like hydrotreaters, amine treating units, catalytic crackers, cokers and sour water strippers due to the increased loads of corrosive sulfur compounds like H2S. Even a slight increase in feed chlorides can result in increased corrosion, not only in the crude distillation area, but also in downstream reforming and hydrotreating processes. Changes in process operating conditions are often a source of corrosion problems. Gradual changes are often the most troublesome since, based on small incremental step changes, the impact can go unnoticed. For example, a gradual increase in fired heater temperatures in crude distillation units to improve product cut points can ultimately have a dramatic influence on corrosion rates. Increased pressures may increase the solubility of corrosive species in water or raise hydrogen partial pressures to the point where high temperature hydrogen attack becomes a concern in hydrotreating units. Periodic reviews of operations are warranted to ensure that the operating limitations of materials of construction are not exceeded unknowingly. As corrosion develops in processes, it is important to recognize that corrosion control measures also can not be arbitrarily applied without considering the effects throughout the refinery. For example, if not carefully applied, use of a neutralizing amine to control corrosion by acidic chloride condensates may result in fouling and corrosion of equipment by the neutralized salt. Filming inhibitors which successfully arrest a corrosion problem in one unit can become a serious catalyst poison in downstream processes due to the high nitrogen content of most of this kind of inhibitor. The use of water wash to mitigate sour water corrosion is a common practice. However, if the water is oxygenated, corrosion can be made worse. Also, water which can not be adequately disengaged can be carried into downstream units and cause corrosion there. Process improvements can also have an important impact on corrosion. An improved catalyst in a hydrotreating process can increase the amount of H2S and ammonia which affects corrosion in both the high temperature systems and in the sour water systems. Operational changes and catalyst improvements can also increase the denitrogenation of the feeds resulting in a drastic increase in corrosion due to the higher ammonium bisulfide levels in the sour water system. For example, increasing sour water corrosion in diesel oil hydrotreating unit effluent systems has occurred as a result of process improvements and more severe operations which reduce the sulfur and nitrogen contents of the product stream. This sulfur and nitrogen is converted to higher ammonium bisulfide levels in the sour water system.

3.5

ROLE OF PERSONNEL PERSONNEL IN EQUIPMENT INTEGRITY Equipment integrity affects refinery operations in a number of ways. Reliable equipment results in a safer working environment, prevention of environmental releases and ultimately impacts unit

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service factor and profitability. Similarly, refinery operations affect equipment integrity. The quality of feed stocks and the operating conditions at which they are processed influence the measures used to control corrosion, such as chemical treatment and alloy selection, and ultimately the deterioration rate of the equipment. It is clear that a petroleum refinery can be a complex entity influenced by many operating objectives. As such, the need to maintain ongoing communications among all plant personnel is essential in support of these objectives to ensure that the impact of changing operations can be evaluated and programs developed to address concerns. The roles of equipment engineers such as metallurgists, inspectors and corrosion and mechanical engineers include the following: • • • • •

Understanding the factors which affect reliability and equipment degradation Ensuring materials are selected and installed correctly Establishing corrosion monitoring and control programs Assessing and reporting equipment condition Ensuring compliance with codes and standards

Plant operators and supporting process engineers also have roles in equipment integrity. These responsibilities include the following: • • • • •

Identifying operating unit operating basis and constraints Operating within equipment design limits Operating within agreed conditions established by materials degradation concerns (which are often more restrictive than mechanical design limits) Communicating changes in operating conditions, feed stocks, etc. Carrying out necessary corrosion monitoring and control measures

Maintenance personnel also have critical responsibilities to ensure overall equipment integrity. These responsibilities may include engineering repairs to overcome problems related to equipment design, carrying out repairs and maintenance according to specifications and providing information on equipment failures.

3.6

CONCLUSION By understanding the relationships between refinery operations and the important materials and corrosion issues in specific processes, engineers, inspectors, planners, operating and maintenance personnel can all be important contributors to safe, reliable and profitable refinery operations.

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4.0

CRUDE UNIT

4.1

CRUDE UNIT CORROSION CORROSION AND CORROSION CONTROL This section reviews fundamental corrosion issues concerning the Crude Unit process. It contains, in concise form: • • •

4.2

a description of the process and major equipment found in the Crude Unit; types of corrosion and where they occur; corrosion monitoring and inspection advice.

CRUDE UNIT PROCESS PROCESS DESCRIPTION In the petroleum refining process, the Crude Unit is the initial stage of distillation of the crude oil into useable fractions, either as end products or feed to downstream units. The major pieces of equipment found on crude units will vary depending on factors such as the assay of the design crude, the age of the refinery and other downstream units. The unit discussed in this paper has all of the major pieces of equipment found on crude units including double desalting, a preflash section, an atmospheric section, a vacuum section and a stabilization section. Cold crude from storage is transferred from tankage by the unit charge pump and is preheated in a series of heat exchangers. It then passes through the desalters and another series of heat exchangers. The operation of the desalter is special enough to warrant a separate section following this crude unit process overview description. There may be a flash drum in the middle of the desalted crude preheat, which will allow lighter vapors and water to be removed from the crude and sent into the upper part of the crude tower. This design helps to prevent accumulation of water hardness on the preheat tubes as a precursor to fouling. If there is no flash drum, at 230oC to 285oC (450oF to 550oF) the crude may enter a Preflash Column. The Preflash Column typically has no reboiler section or bottoms stripping steam, so with no upward moving vapors from any source other than the crude preheat, the crude will enter below the bottom tray. In the Preflash Column, most of the light naphtha and all of the lighter components are removed from the crude oil, yielding a 'flashed crude'. Preflashing the crude unloads the top of the Atmospheric Column and the Crude Heater, thus increasing throughput and reducing heater coking. A Preflash Column will often operate at a temperature low enough that condensation of water can occur inside the tower, which often leads to corrosion of the tower internals. Some units process a crude heavy enough that they do not have a Preflash Column, and crude is directly fed to the Atmospheric Column following the preheat and crude heater. In a Preflash Column, butane and lighter fractions will go overhead. Liquids which distill overhead are most often sent to a Debutanizer and the gases are sent to the Saturate Gas Plant or plant fuel gas. Light naphtha may be drawn off the side of the Preflash Column, or taken overhead, depending on the refinery configuration. The light naphtha and naphtha from the atmospheric column overhead may be combined and sent to a Naphtha Splitter. On units which do not include a Preflash Column or Flash Drum, it is common for the unit design to include a Stabilizer Column which will remove pentane and lighter material from the Atmospheric Column naphtha product.

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The flashed crude from the bottom of the Preflash Column or Flash Drum is passed through a series of heat exchangers and enters the Atmospheric Heater at about 260oC to 285oC (500oF to 550oF.) Leaving the heater at 345oC to 380oC (650oF to 720oF), it enters the Atmospheric Column flash zone. Naphtha vapors off the top of the tower are condensed and the naphtha liquid may combine with either a light or heavy naphtha and then go to the Splitter. The flow plan, shown in Figure 3-2, shows a simplified single stage overhead system with one set of condensers and a reflux drum. The tower top temperatures of this type of system are typically in the range of 120oC to 140oC (250oF to 285oF). While somewhat uncommon, there are units with the Atmospheric Column top temperature near or below the water dew point and hence water condensation occurs in the tower. Some units have a two stage overhead system with tower top temperatures above 140oC (285oF). Often, these two-stage systems will condense part of the naphtha in the first stage and the remaining naphtha plus the water in the second stage. The first stage of such a unit may have problems related to shock condensation, due to low tube-wall temperatures, and salt deposition in the absence of a bulk water phase. The second stage of a two-stage system has similar types of corrosion problems to a single stage overhead. To maximize heat recovery, some units may have a more complex three- or four-stage condensation scheme. The process and design variations described above make universal corrosion control schemes impractical. Kerosene is drawn off the upper part of the column, sent to a stripper and then to hydrotreating or #2 fuel oil product storage. Diesel is drawn off the middle of the column, sent to a stripper, and then to hydrotreating, Hydrocracker feed, or diesel or #2 fuel oil product storage. Atmospheric gas oil is drawn off the lower portion of the column, stripped, and sent to Fluid Catalytic Cracking (FCCU) feed or Hydrocracker feed. The atmospheric residuum from the bottom of the column is sent to the Vacuum Heater. The residuum enters the Vacuum Heater 10oC to 20oC (15oF to 30oF) below the temperature that crude enters the Atmospheric Column, leaves at about 370oC to 395oC (700oF to 740oF), and is fed to the flash zone of the Vacuum Column. The vapor off the top of the column goes to a series of vacuum condensers which provide the necessary vacuum for column operation. Light vacuum gas oil is drawn off the upper portion of the column and goes to FCCU feed or Hydrocracker feed. Heavy vacuum gas oil is drawn off the lower part of the column, is combined with the light vacuum gas oil, and sent as feed to the Cat Cracker. The column bottoms residuum is sent to a Coking Unit or to plant fuel oil. Vacuum towers may also be used to produce feedstocks for lube oil plants. In the stabilization section, the Naphtha Splitter bottoms go to the Catalytic Reformer and the overhead liquid to the Debutanizer Column. From the Debutanizer Column, the overhead liquid goes to the Saturate Gas Plant or to plant fuel and the bottoms to the Isomerization Unit.

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GENERIC CRUDE UNIT Figure 3-2

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4.3

October 1999

CRUDE DESALTING Crude oils are complex mixtures obtained from many parts of the world and all crudes contain varying degrees of impurities. These impurities consist of naturally occurring water, salts, solids and metals as well as added contamination from well stimulants, gathering methods, storage and transportation. Adverse effects of these impurities are excessive corrosion, fouling and unit upsets. These effects can result in shortened unit run lengths and reduced equipment reliability. To minimize these effects, the refiner often washes the crude oil with water, and uses a desalting vessel to remove the added water and most of the inorganic contaminants from the crude prior to distillation in the crude unit. Common desalter types and a brief description of them are given below: •

Electrical desalting

an electric field is induced by AC or DC current in the oil and water mixture to enhance water coalescence.

•

Chemical desalting

surfactant chemicals are used to aid water coalescence

•

Chemical and electrical desalting

a hybrid of electrical and chemical methods

•

Gravitational separation

typically a large tank or drum which allows water and water borne contaminants to separate due to density difference between the water and oil phases.

The type, size and series stages of desalting facilities chosen is dictated by the individual refiner based on refinery specific requirements and limitations. The fundamental functions of desalters are: 1. Remove chloride salts - typically calcium, magnesium, and sodium - to minimize corrosion in the crude unit overhead system. This corrosion is caused by hydrochloric acid which is formed by hydrolysis of the magnesium and calcium salts during the distillation process. 2. Remove solids and sediment that cause erosion or abrasion of equipment. Deposition of solids in the preheat exchanger train can lead to plugging of tubes or fouling which results in reduced heat transfer and higher energy consumption. 3. Minimize unit upsets by preventing water slugs from tankage to be charged directly to the distillation column. A detailed description of how desalters operate is beyond the scope of this section. However, a summary of the major variables and their expected effect on the desalter operation follows: (i) Crude oil properties Because desalters rely on the density difference between oil and water, lower gravity (higher density), higher viscosity crudes make it more difficult to separate water from the crude, and hence more difficult to desalt. (ii) Desalting temperature and pressure

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Generally desirable desalting temperatures are in the range of 121o to 149oC (250o to 300oF). The upper temperature limit is to avoid vaporization of the crude oil in the desalter, or to prevent damage to the electrical grid insulator bushings. (iii) Residence time Adequate residence time is essential for oil-water separation. Heavier crudes require longer residence time because the gravity difference between the oil and water is reduced. For low gravity crudes, the required water residence time can be 2 hours. Chemical emulsion breaker selection may have a significant effect on oil undercarry in the water which is caused by inadequate residence time. (iv) Wash water quality and rate Variables in water quality, particularly pH can affect the effectiveness of desalting and the transport of water and ammonia into the crude or oil into the desalter brine water. Sufficient added water must be provided to ensure good coalescence of the water in the crude. (v) Wash water mixing To ensure the added water is dispersed well so that it can be available to combine with the contaminants in the crude, a controllable mixing is required. This is typically accomplished by a mixing valve with adjustable pressure drop. Location of the wash water injection may vary, normally into one or more places between the raw crude charge pump and the mix valve. Injecting desalter water into the suction of a crude pump is not recommended because this mixing can not be controlled. Over mixing can prevent adequate water coalescence. Some of these items are discussed in more detail in the paragraphs which follow. •

The source of desalter wash water is governed by the refiner's needs, environmental requirements and availability of reusable process waters. However, the purer the water, the easier it is to wash the crude. The volume of water can be from 3 -10% with typical usage at 5% based on total crude charge. Lowering the wash water rate below 3% of total charge reduces the rate of coalescence and often makes water removal more difficult. A low water rate in conjunction with high mixing energy will likely further degrade desalter performance.

•

For the wash to be effective in removing the impurities from the crude, it must make good contact with the crude. Controlled mixing is achieved most often by use of a mixing valve which permits varying degrees of water/oil contact. The higher the pressure drop (^P) across the mix valve, the greater the mixing energy. However, if the ^P is excessive, a tight emulsion will form which cannot be easily resolved in the desalter. Poor water separation increases the BS&W (Basic Sediment and Water) carryover with the crude and high oil entrainment in the effluent brine. If the ^P is too low, the crude/water contact will be insufficient for good desalter efficiency. Typical mixing valve ^P is 10 to 20 psi. The only sure method for determining the optimum ^P for operation is by testing and adjusting while monitoring the desalter. Many variables dictate mixing valve ^P requirements and must be considered before adjustments are made.

•

To minimize fouling in the raw crude preheat train from the deposition of salts in the crude, it is advisable to utilize a portion of the wash water for injection immediately downstream of the crude charge pump. This water is referred to as 'primary' water. While testing and adjusting to find and maintain the optimum primary water rate is advisable, a good starting point is an even split. For example, 5% (v) wash water would be split into 2.5% each for primary and secondary locations, with an injection at the desalter mix valve as the most common secondary location. Tighter control on mixing valve adjustments is required while in this mode of operation.

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4.4

October 1999

•

Another item that may improve desalting is wash water pH control. Chemical desalters are more efficient with high pH water, somewhere around 8.0 - 9.5. While electrical desalters function much better in the 5.5 - 7.0 pH range. Low pH's result in excessive corrosion while high pH permits ammonia to migrate into the crude. Excessively high pH can aid in stable emulsion formation. Typical pH control, if required, is done with sulfuric acid or caustic into the water as far upstream as possible, with pH controllers monitoring results. Quills for injection of the acid or caustic are necessary to avoid mix point corrosion. Spent acids and caustic are not advisable. They may return impurities to the crude stream that can promote equipment fouling and corrosion.

•

Chemical assistance is extremely important for the desalting operation. Chemicals, when properly applied, will not only enhance the speed of separation, but will assist residence time, improve solids removal, minimize water carryover/oil undercarry, and reduce the emulsion layer (cuff, or rag) to a manageable thickness. The chemicals used are termed emulsion breakers, wetting agents, and/or demulsifiers. They can be oil soluble, water soluble, or water/oil dispersible and in varying forms of chemistry. However, they all serve a common goal, to enhance separation of impurities from the crude. The chemicals are surfactants which migrate to the oil/water interface to rupture the stabilizing film around the water droplets that allows them to merge and coalesce.

•

Chemical usage rates vary widely with crude type, equipment and operating parameters. It is usually in the range of 1 pint (3v ppm) to 1 gallon (25v ppm) per thousand barrels of crude. Several test methods are available for chemical selection on a cost/performance basis. Chemical vendors are best equipped to assist with these evaluations, as refinery laboratories are not normally equipped for these tests.

•

For the chemical to be effective, it must be well dispersed before it arrives in the desalting vessel. The oil soluble/dispersible types are normally injected into the crude charge pump suction or upstream of the wash water inlet point. Water soluble/dispersible chemistry injection is preferred with the wash water, in the wash water pump suction, or before the flow controller.

MATERIALS OF CONSTRUCTION CONSTRUCTION The majority of the equipment in a Crude Unit is made of carbon steel regardless of whether the crude slate is 'sweet' or 'sour'. The term 'sour' refers to the release of H2S, but is often applied to a crude oil based on its sulfur content, with less than 0.5 wt% sulfur called 'sweet' or greater than 1.0% called 'sour'. This use of carbon steel is possible because at temperatures below about 230oC (450oF), except for the preflash and atmospheric column overhead systems, the streams are essentially non-corrosive to carbon steel. Where temperatures exceed 230oC (450oF), problems with high temperature sulfur attack and naphthenic acid corrosion may begin. In the overhead system, the formation of acidic deposits of condensates occurs below about 120oC (250oF) and often necessitates the use of one or more highly alloyed materials. The purpose of this section is to point out where problems occur in major equipment and systems, and to discuss the materials commonly used to alleviate those problems.

4.4.1

Columns In a Crude Unit, the Preflash Column will typically have Monel 400 cladding in the top zone which operates near or below the dew point. The remainder of the shell will be bare carbon steel.

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This Ni-Cu alloy will be corroded by sulfur compounds above about 177o to 204oC (350oF to 400oF). Since the inlet temperature is about 260oC (500oF), crude units typically have a 12% chrome lining in the bottom to protect against sulfur corrosion. The Atmospheric Column is commonly lined more extensively than the Preflash Column because the feed, at about 365oC (690oF), is not only hotter, but also contains larger amounts of HCI and H2S. The top of the column is often lined with Monel to protect against condensing HCI. Even though the top temperature may be above the water dew point, the addition of 'cold' reflux can cause localized condensation and conditions extremely corrosive to carbon steel. Typically, the lower two-third to three-fourth of the column will be lined with 12% chrome cladding to protect against high temperature sulfur corrosion. In the area of the feed inlet, or flash zone, Type 316L stainless steel may be required in those plants processing crudes high in naphthenic acid content. It is important to make sure that the nozzles in each area are lined with the same material as the shell. After exposure to service, the shell immediately above and below the cladding should be closely monitored for wall loss. It is not uncommon to find that the original clad areas need to be extended. For that reason most new units will have the 12Cr or 316L cladding extend up the column to the 232o to 260oC (450o to 500oF) temperature. In the absence of naphthenic acids, the Vacuum Column is typically lined with 12% chrome, with the exception of the top few feet and head. The flash zone is often one of the worst naphthenic acid problem areas. For highly naphthenic crudes, Type 316L or 317L stainless steel cladding may be required in all areas of the column operating above 230oC (450oF). For very high TAN crudes, higher molybdenum alloys may be required. In sweet crude plants, the side-stream strippers are usually unlined even though the diesel and atmospheric gas oil feeds are 285oC (550oF) and 345oC (650oF). In plants running sour crude, these hot strippers might require a 12% chrome lining. The Naphtha Splitter and Debutanizer are normally not lined. While many units were built with a sweet-sour crude distinction, most modern units have to be materialed to handle almost any kind of crude oil. This is to take advantage of opportunity crudes which may be difficult to process from a corrosion standpoint. It is not uncommon to use 316L cladding for the major columns and the vacuum transfer line in order to be able to run some of the market crudes that have naphthenic acid corrosion problems. There may be considerable cost advantage to be able to run some opportunity crudes.

4.4.2

Exchangers and Piping Heat exchanger metallurgy varies with stream composition and temperature. The majority of the exchangers are 100% carbon steel. In fresh water cooled exchangers, admiralty brass tubes have been used to prevent water-side fouling and corrosion. Due to the cost of the brass bundles and improvements in cooling water treatment, many brass bundles are being replaced with carbon steel. Where seawater or brackish water are used, admiralty, aluminum brass, cupro-nickel, Monel, titanium, and some of the super ferritic (e.g., 26 Cr-l Mo) and duplex stainless steels have been used successfully where carbon steel failed to perform. The use of austenitic stainless steels has been limited in water service due to their susceptibility to chloride stress cracking and underdeposit pitting. In hot hydrocarbon service, the use of 5% chrome materials in heat exchangers is common. As the sulfur content in the crude increases, the use of high chrome tubes and 12% chrome shell

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and channel linings becomes necessary. Austenitic stainless steels are also used to great advantage in this service. Generally, the most severe corrosion problems are in the areas of initial condensation in the atmospheric column and preflash column overhead systems. This may include the top of the column, the overhead vapor line, the naphtha exchangers, coolers and interconnecting piping. As mentioned previously, these are the areas where HCl vapor, formed by the hydrolysis of the magnesium and calcium chloride salts in the preheat, dissolves in the condensing water to form hydrochloric acid. HCl, along with hydrogen sulfide which is also present, creates a very corrosive environment. Usually the Monel lining and trays in the tops of the columns are effective in resisting the acid attack unless chloride salt deposits form. The overhead vapor line, which is typically carbon steel, can be severely attacked if unneutralized condensate is present. A good pH control program in conjunction with corrosion inhibitors can be very effective in protecting the bare steel line. The chlorides in the overhead receiver water should be kept below 25 WPPM, which can usually be accomplished with effective desalting of the crude oil and judicious use of caustic addition to the desalted crude. This will go a long way toward solving the acidic condensate corrosion problems. However, if the chlorides exceed about 30 PPM, the solution to the problem may be quite difficult. It is sometimes necessary to install a Monel, or Monel clad, vapor line. The heat exchangers closest to the point of initial condensation or chloride salt deposition may require alloy tubes, ranging from admiralty brass to titanium. Where chloride salt fouling and corrosion occurs, titanium exchanger tubes have worked well. The unlined carbon steel exchanger shells may be attacked, particularly around the inlet nozzles. This may require Monel cladding or weld overlay in this area. If the pH of the system is well controlled, as measured at the overhead receiver, and inhibitors are properly used, the remainder of the piping and exchangers downstream can be carbon steel with few serious problems. The overhead vacuum condensers may have admiralty brass tubes and Type 316 stainless steel lined shells and Type 316 SS outlet lines. The stainless steel may be needed because of CO2 and H2S in the condensing vapors. However, carbon steel is often used successfully. 90-10 or 70-30 copper-nickel tubes are sometimes used in the vacuum condensers as part of standard vendor steam ejector packages. In some cases, 90-10 can experience accelerated corrosion since coppernickel alloys are not highly resistant to H2S. Materials such as Admiralty or Aluminum brasses may be considered, although the Cu-Zinc alloys are susceptible to ammonia stress corrosion cracking.

4.4.3

Fired Heaters The fired heaters have corrosion and material problems due to the elevated temperatures experienced both on the process side and in the fire-box. The Atmospheric Heater receives flashed crude at about 260oC (500oF) and sends it to the Atmospheric Column at about 365oC (690oF). For sweet crude, the radiant tubes and lower rows of convection tubes are typically 5% chrome with carbon steel in the upper rows of the convection section. In the Vacuum Heater, with a 360oC (680oF) inlet and 380oC (720oF) outlet the radiant tubes and convection tubes would be 5% chrome for sweet, 9% chrome for sour crudes. Some plants running very sour crudes have Type 316 austenitic stainless steel radiant tubes. This material would also be used where naphthenic acid attack is severe. High fire-box temperatures of >815oC (1500oF) also create materials problems. Tube supports and hangers suffer excessive oxidation and premature failure if they are not sufficiently alloyed. Historically, HH casting alloy (25% chrome - 12% nickel) was the industry standard. This material did well in the cooler convection section, but failed in the radiant section. The substitution of HK alloy (25% chrome - 20% nickel) added extra life in the hot areas. Higher nickel materials give

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excellent service where low sulfur fuel is burned. However, where sulfur is high, these alloys suffer from sulfidation. This is also true for the high nickel welding electrodes commonly used to fabricate or repair the Cr-Ni castings. Units which burn fuel oil high in sodium and vanadium may have refractory lined HK alloy or solid stabilized 50 Cr-50 Ni supports to resist fuel ash corrosion. The transfer lines from the heaters to the columns are usually alloyed much the same as the heater tubes. The vacuum heater outlet piping and transfer line may be severely attacked by naphthenic acid, requiring the use of Type 316 stainless steel.

4.5

MATERIALS AND CORROSION CORROSION PROBLEMS Crude oil is a mixture of many different chemical compounds, generally combinations of carbon and hydrogen, all with their own unique physical properties. Crude oil as such is not considered to be corrosive to carbon steel. However, crude oils all contain some impurities, several of which can be extremely corrosive under crude unit operating conditions. The more common of these potentially damaging impurities are: • • • •

4.5.1

Inorganic Salts Sulfur Compounds Organic Acids Organic Chlorides

Inorganic Salts Inorganic salts are present in brine produced with the crude oil or picked up as a contaminant from tanker ballast. The bulk of the salts present in the water are sodium chloride (NaCl), magnesium chloride (MgCl12) and calcium chloride (CaCl12), commonly reflecting the composition of sea water (85%, 10%, 5%, respectively). However, these ratios can vary widely. The total salt content by weight can vary from less than three pounds per thousand barrels of crude oil (PTB) to 300 PTB or more. When the crude oil is preheated, most of the MgCl12 and a small amount of the CaCl12 begin to hydrolyze at about 120oC (250oF) and form hydrogen chloride (HCl) vapor. At 370oC (700oF), approximately 95% of the MgCl12 and 15% of the CaCl12 have hydrolyzed. (Refer to Section 3 §5.2.9.) A similar reaction occurs for the CaCl12. The NaCl, being more temperature stable, does not hydrolyze to any appreciable extent.

4.5.2

Sulfur Compounds Some forms of sulfur are found in virtually all crude oils. Sulfur contents up to 6 wt% are not unusual, but most crudes fall within the range of 0.5 - 3.0 wt%. The most important sulfur related corrosion problems are caused by hydrogen sulfide (H2S), both below the water dew point (aqueous) and above 260oC (500oF). While small amounts of naturally occurring H2S may survive the journey to the crude unit in some crudes, the bulk of the H2S present in the unit is the

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result of the thermal decomposition of reactive organic sulfur compounds which occurs in the heaters between 260oC (500oF) and 480oC (900oF). It is difficult to predict the corrosivity of a crude oil based entirely on its sulfur content. Generally, the dividing line between non-corrosive and corrosive crudes lies somewhere between 0.5% and 1.0%. However, the determining factor is quite often not the amount of sulfur compounds, but rather the extent to which these compounds thermally decompose to form H2S. This phenomenon requires evaluating each crude individually. At temperatures in excess of about 260oC (500oF), H2S reacts with iron to form iron sulfide scale. The rate at which this reaction occurs is dependent on the H2S concentration, the temperature, the stream velocity, and the composition of the material. Generally, an increase in sulfide concentration, temperature, or velocity will increase the rate of metal loss. An increase in the chromium content of the material will decrease the rate, with 5% chromium being a practical minimum threshold level required for corrosion protection. Lower chrome alloys like 1-1/4Cr1/2Mo and 2-1/4Cr-1Mo do not have significantly enhanced corrosion resistance to justify their increased cost over carbon steel. High temperature sulfur attack is a serious problem in the hot portions of the atmospheric column, preflash column, the vacuum column, fired heater tubes, hot heat exchangers and associated piping. The problem is alleviated by the use of proper alloy materials. Aqueous phase H2S corrosion is widespread in the predominantly carbon steel equipment where water can condense. While a specific mechanism to cover all situations is not available, it is known that three important variables in determining its severity are pH, chloride ion concentration, and sulfide ion concentration. The types of corrosion control programs described in the discussion on inorganic salts also apply to corrosion control in H2S containing sour water. (Refer to Section 2 §5.1.5 and § 5.3.6)

4.5.3

Organic Acids Many crude oils contain organic acids, but seldom do they constitute a serious corrosion problem. However, a few crudes contain sufficient quantities of organic acid, generally naphthenic acids, to cause severe problems in those parts of the crude unit operating over 230oC (450oF). Thus, naphthenic acid attack often occurs in the same places as high temperature sulfur attack such as heater tube outlets, transfer lines, column flash zones, and pumps. In sour crude units a crude TAN (Total Acid Number) of 1.0 (mg KOHg) is sufficient to be concerned about potential naphthenic acid corrosion. In sweet units, a TAN of 0.5 may be high enough to cause corrosion. Some light southeast asian crudes with very low sulfur contents have naphthenic acid corrosion problems at TAN’s as low as 0.1. Both high temperature sulfur and naphthenic acid mechanisms are strongly affected by velocity. Whereas sulfur corrosion is characterized by a smooth surface with a sulfide scale deposit, naphthenic acid corrosion results in sharp edged, smooth grooves, gouges, or holes with no corrosion scale or deposit. Those materials commonly used to prevent high temperature sulfur corrosion, primarily 5 - 12% Cr steels, can be severely attacked by naphthenic acid. The most commonly used material is type 316 stainless steel, which does well because of its molybdenum content. Type 304, which contains no molybdenum, has some resistance to lower levels of naphthenic acids, but in most cases it is no better than carbon steel. Higher TAN crudes/cuts may require higher molybdenum alloys to resist corrosion. (Refer to Section 2 §5.2.11)

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4.5.4

October 1999

Organic Chlorides Organic chlorides constitute a contaminant in crude oil, often resulting from the carry-over of chlorinated solvents which are used in the oilfields. They can also be picked up by the crude during transportation in contaminated tanks or lines. Organic chlorides are not removed in the desalters. Some of them can decompose in the heaters, forming HCl, causing erratic pH control and accelerated corrosion in the crude unit overhead system as well as in downstream units. (Refer to Section 2 §5.2.12)

4.5.5

Corrosion Control Measures The crude unit overhead system can benefit from corrosion control measures other than materials selection as described earlier. Several steps can be taken to reduce the severity of acid attack in the crude unit overhead circuit: • • • • • •

Blending Desalting Caustic addition Overhead pH control Use of corrosion inhibitors Water washing

(i) Blending Perhaps the most commonly used technique for corrosion control is the blending of problem crudes with nonproblem crudes. Sometimes the flexibility may not exist, or blending may not provide enough reduction of the problems, and in those cases more attention needs to be placed on the following options. (ii) Desalting As the name implies, the primary purpose of a desalter is to reduce the amount of salt in the crude oil, less than 3 ppm (1 PTB) being a commonly targeted level. Removal of the salt reduces the amount of HCl produced from hydrolysis in the preheat and flash zone of the crude tower. In addition to salt removal, the desalting process also removes entrained solids such as sand, salt, rust, and paraffin wax crystals which may be present in the crude. Removal of these contaminants helps decrease plugging and fouling in heaters and preheat exchangers. (iii) Caustic Addition The addition of a small amount of dilute caustic (NaOH) to the desalted crude is often an effective way to reduce the amount of HCl released in the preheaters. The caustic converts the HCl to thermally stable NaCl, thus reducing the amount of free HCl produced. While the results of caustic addition can be quite beneficial, there is a risk of crude preheat train fouling, accelerated atmospheric, vacuum, and visbreaker or coker coking, caustic stress corrosion cracking, and catalyst contamination problems in downstream units, like FCC's, if it is not controlled properly. A typical limit for avoiding coking problems in furnaces is to inject no more than necessary based on downstream chloride (20 to 30 ppm in the Atmospheric Column overhead water) or sodium limits (20-50 wppm in the Vacuum Tower bottoms). Fresh caustic is preferred over spent caustic for two major reasons. Spent caustic tends to have variable amounts of free or available NaOH to neutralize the HCl formed. As a result, proper control is very difficult. Also, spent caustic, depending on its source, can be a significant promoter of preheat exchanger fouling.

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To minimize the negative effects of caustic injection and maximize its efficiency, thorough mixing is necessary. To achieve good mixing, the caustic is often added to suction of the crude booster pumps after desalting. Some refineries will mix by injecting the dilute caustic into a slipstream of desalted crude oil prior to its injection into the main process. Injection of caustic upstream of the desalters is not recommended because high desalter water pH can result in the formation of emulsions and can drive ammonia into the crude. Also, the caustic will be unavailable to react where the salt hydrolysis takes place since it will typically be removed in the desalter brine. For units without a desalter, to minimize potential for caustic cracking, if possible caustic should be added to the preheat train at or about desalter outlet temperature. (iv) Overhead pH Control The desired result of an overhead pH control program is to produce an essentially non-corrosive environment by neutralizing the acidic components in the overhead liquid. This is done by injecting ammonia, an organic neutralizing amine, or a combination of the two. The desired pH control range depends on the concentrations of the various components of the corrosive environment. Usually, this range is 5.5 to 6.5. However, it is important to recognize that neutralizers may have a different effect on the pH at the initial condensation point. At this point, the pH could be higher or lower, depending on the product selected. A pH above 8 must be avoided if brass alloys are used in the overhead system as they are vulnerable to stress corrosion cracking and accelerated corrosion at high pH. The preferred injection point for the neutralizer is the subject of some debate. In single overhead drum systems, some chemical vendors advocate injecting the neutralizer into the column reflux stream to help protect the tower internals. Others discourage this practice because neutralizerchloride salts, similar to ammonia salts, that form in the tower may be corrosive especially to copper bearing alloys such as Monel, and may be trapped in a section of the tower. Because stability of neutralizer-chloride salts vary depending on the type of neutralizer used, the various options and their risks should be discussed with the chemical vendor prior to implementing a chemical treatment program. In two-stage overhead systems, the neutralizer or ammonia (or both) is normally injected upstream of the second stage condensers. Generally neutralizers are not used in the first stage if it operates without water condensation due to concerns with forming corrosive neutralizer-chloride salts which may also be refluxed to the tower. Wet first stage systems, however, may benefit from neutralizer addition if there is a continuous water draw from the first stage drum. Neutralizers are sometimes used in vacuum tower overhead systems as well, using an application point that minimizes or eliminates the possibility of introducing neutralizer-chloride salts into the tower. A variety of neutralizers and blends of neutralizers are available for pH control. Some neutralizer components in widespread use today include an aqueous solution of ammonia (NH3), morpholine, ethylene diamine (EDA), monoethanolamine (MEA), and methoxypropylamine (MOPA). All of the neutralizer salts are water soluble. MOPA and MEA form liquid neutralizer salts with chlorides at elevated temperatures. NH3, morpholine and EDA form solid salts. Liquid salts may be less prone to fouling, but they may also flow better and result in more widespread salt corrosion if they are returned to the atmospheric tower. (v) Corrosion Inhibitors Most overhead corrosion control programs include the injection of proprietary film forming organic inhibitors, commonly referred to as filmers. These inhibitors establish a continuously

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replenished thin film which forms a protective barrier between acids in the system and the metal surface underneath the film. For maximum results, proper pH control of the system is essential. Filming inhibitor injection rates will vary with time and between refineries. There is a surface adsorption/desorption steady state established which varies based on the aggressiveness of corrosion in the system, and the inhibitor concentration. Factors which affect inhibitor solubility in the liquids, such as pH, and affect the inhibitor's ability to adsorb onto the surface, such as temperature, will affect the effective dosage for a given situation. A typical injection rate is of the order of 3 to 5 vppm for normal operations. During startups or unit upsets, injection rates may be temporarily increased to levels such as 12 vppm to help establish or re-establish the protective film. Inhibitors also could have a cleaning effect so they may remove some iron sulfide deposits, particularly at the higher injection rates. Because these inhibitors have high molecular weights, they are non-volatile and will follow the path of other liquids present following their injection. Therefore, they must be independently injected into both stages of a two-stage overhead system. Filming inhibitors should normally not be injected in concentrated form. Inhibitors are noncorrosive to equipment at treatment dosage dilutions, but near 100% concentration they may be corrosive to injection equipment. This should be kept in mind when designing an injection system. Typically, naphtha dilution is provided to help the dispersion at the injection point. In the feed to the Atmospheric and Vacuum Columns, as well as in the columns themselves, naphthenic acid corrosion can occur. There has been some success with the use of corrosion inhibitors purported to be effective in the 260oC (500oF) to 370oC (700oF) temperature range and for this type of corrosion. These inhibitors may offer some economic advantage over alloy when the acidic crudes are charged intermittently, but their effectiveness is hard to determine. Additionally, most of the inhibitors available contain phosphorus, which may be considered to be a poison to some hydrotreating catalysts. (vi) Water Washing Since the products of the above discussed neutralization reactions, ammonium chloride or amine chloride, can be highly corrosive and also cause fouling, it is common practice to recirculate water from the overhead receiver back into the column overhead vapor line. Stripped sour water and/or other water condensates are also recirculated by some refineries. Water which contains dissolved oxygen, however, can dramatically accelerate corrosion and should be avoided. Water washing can be quite effective, but must be carefully engineered to prevent the creation of more corrosion problems and cause significant loss of heat exchange in the overhead naphtha coolers. Water washing the vapor line can prove to be beneficial or disastrous. Too little water can just add to the acid-making process; too much can cause grooving of the line. The path of the grooves can be unpredictable and difficult to locate with normal U.T. surveys. A proper spray nozzle is necessary to prevent impingement corrosion of the pipe downstream of the injection point. When the wash water is injected directly upstream of the condensers, a good distribution system is necessary to ensue evenly divided flow among the different banks of exchangers. An intermittent wash is difficult to optimize, may be neglected, and may actually increase corrosion of otherwise dry and non-corrosive salts. Therefore, use of water on an intermittent basis should be considered only when a continuous wash is not possible due to process constraints, or when a continuous wash has been shown to create erosion problems. The ideal water injection rate is 5 -10% of the overhead stream. Excessive water rates, however, can result in poor water separation in the overhead drum. Poor separation can result in water being returned to the tower in the reflux and resultant corrosion both in the tower and the

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overhead line. With the proper mechanical design and chemical balance, the water wash can be an important part of the overhead corrosion control program.

4.5.6

Corrosion Monitoring Several methods of evaluating the effectiveness of crude unit corrosion control programs are employed: • • •

•

Water analyses - for pH, metals, chlorides, and hardness Hydrocarbon analyses - Inhibitor residual and metals Corrosion rate measurement by: − Electrical resistance probe − Weight loss coupon − Linear polarization resistance probe On stream non-destructive examination by UT or RT

(i) Water Analyses (Overhead Corrosion Control) The most important monitoring parameter for good overhead corrosion control is receiver pH. The system pH can shift from an acceptable pH to an aggressively corrosive pH in a matter of minutes, so the overhead receiver pH should be measured as frequently as possible on the Atmospheric Column. The Preflash Column and Vacuum Column pH will usually not shift as rapidly. Continuous pH monitor reliability is poor relative to most other instruments used in refining, and so most refineries still rely on manual readings. Although pH measurements can capture a corrosive event and prevent extended damage, even holding the pH in an acceptable range does not always assure the lowest possible corrosion rate. See the section on Corrosion Control Measures, Overhead pH Control for more information. Routine analysis of the overhead receiver water for metals can be of value in some cases, particularly when used in conjunction with other methods of measurement. Iron, copper and zinc are typically measured, but this depends on the materials used in the overhead system. If no brass, copper, nickel or Monel alloys are used, for example, there is little value in determining copper, nickel or zinc concentrations. Much reliance has been put on the iron content of the water and very often the results are misleading. Since iron solubility is quite dependent on pH, the iron concentration in the receiver water may not be indicative of the amount of iron going into solution somewhere upstream where the pH may be lower. The only source of copper and zinc in a typical system would be brass or Monel exchanger bundles. If their levels increase in the water (particularly zinc in brass containing systems), there probably is a corrosion problem. This has been seen very dramatically in the FCCU and cokers. Overhead receiver water chlorides are a very useful parameter to measure. Since aqueous corrosion is almost always related to the quantity of hydrochloric acid or chloride salts, measuring chlorides can help to confirm when a corrosion event began, and how long it was sustained. A regular measurement of chlorides can also be used to optimize caustic addition or blending of crudes which result in minimum corrosivity. An often overlooked measurement which can be useful for corrosion control measurement is hardness. The hardness of water condensing in an overhead should be zero. If any hardness is detected, it generally will mean that a leak has occurred in a cooling water exchanger. If a recycled water wash is in use, a cooling water leak means that oxygenated water is being recycled. Oxygen can accelerate corrosion. Additionally, the hardness from the water can

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precipitate when the water is injected into the overhead, causing severe fouling. If hardness is detected, it is possible that adjustments will need to be made to the corrosion control program, and that repairs need to be scheduled.

(ii) Hydrocarbon Analyses For filming inhibitors used in an overhead to control aqueous corrosion, depending on the inhibitor formulation, it is sometimes possible to run a 'residual test' on a stream to detect the presence of the corrosion inhibitor. As mentioned earlier, there is an adsorption/desorption steady state which is affected by the environment. There must be sufficient inhibitor present to continuously replenish the film. This is often seen as a residual of 3 - 5 ppm. However, for many inhibitors the nearest available test is total nitrogen which is not specific enough to quantify inhibitor residual. For naphthenic acid corrosion control measurement, sometimes the only tool for measuring the aggressiveness of the environment is metals analysis of the oils. For this measurement, historical data is very useful as a check on current conditions. The absolute value of the metals content will change when naphthenic crudes are processed. Some of that metal comes from 'tramp' metals in the crude oil. Some of these metal-naphthenates will distill, which can make even a relative determination of the rate of corrosion difficult. The ratio of iron to nickel has been used with some success as a relative measure of the effectiveness of naphthenic acid corrosion inhibitors. In most systems, the presence of nickel is from 'tramp' sources, because the nickel alloys which are used corrode very little. The measure of iron will include both the tramp iron and the iron from active corrosion. If the iron/nickel ratio declines, it is then assumed to be due to inhibitor effectiveness. What cannot be determined using this technique is the uniformity of the protection, and localized corrosion zones remain a concern.

(iii) Corrosion Rate Measurement Electrical resistance corrosion rate probes are widely used but with varied success. These devices measure the change of cross section of the measuring element by measuring the change in resistance to electric current flow. It is necessary to take a series of readings over a period of time to establish a curve, the slope of which is indicative of the corrosion rate. This device is used with good success in many instances. However, like all such devices, it is only indicating the corrosivity of the measured stream at the point where the probe is located. It is not always possible to relate the probe readings to a pipe wall or the condensing surfaces of exchanger tubes. They lend themselves well to the evaluation of a corrosion control program which changes the environment through pH control and inhibitor injection. They have the advantage of being read on stream. Also, they can be designed to be retracted through a packing gland and replaced on-stream. Electrical resistance probes are most commonly used in the tower overhead systems. They are often used at both the inlet and outlet of overhead exchangers and may also be installed in the bulk sour water draw-off from the overhead. There are high temperature electrical resistance probe designs which have been used to measure naphthenic acid corrosion. The same limitations with location exist for these probes. The biggest impediment to their use are the serious safety issues related to inserting and extracting an instrument at the temperatures and pressures involved. Weight-loss coupons yield a calculated corrosion rate based on initial surface area and weight. They lend themselves to visual examination as well as giving rate data. They have a disadvantage in that they must be removed to give information, and they can not represent heat transfer surfaces. They can often be replaced on stream and are used in high temperature sections of

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crude units with the same safety concerns as for electrical resistance probes. They are commonly used in overhead systems. Linear polarization resistance probes give an instantaneous corrosion rate based on a measurement of the probe element corrosion current. This type of probe will work only in a conductive medium. It is for on-stream measurements and lends itself well to bulk water systems like cooling water streams. Applications in the overhead receiver water drum are limited but feasible. These probes can be made retractable through a packing gland and replaced on-stream. NDE is normally not used for extensive routine corrosion monitoring because of its cost. It is most often used onstream on an exception basis, when there is a confirmed or suspected problem which is being watched closely. Since NDE is often used as an inspection tool, its use on and off line is detailed in §4.6.

4.6

INSPECTION Whenever possible, corrosion rate information should be verified by direct measurement of equipment. This may not be possible on-stream for items like tube bundles, but piping and vessels can be checked for changes in wall thickness using ultrasonics (UT) or radiography (RT). UT readings can be taken easily and quickly on most surfaces which can be reached by the inspector. These readings are accurate and reproducible when taken on clean, relatively smooth surfaces. Readings can be taken on-stream at metal temperatures as high as 400oC (750oF). This method allows the monitoring of a particular spot over a period of time, providing good data for corrosion rate calculations at that point. In this manner, the routine monitoring of a relatively few representative points in a large piping system may yield an accurate picture of that system. UT readings are the most important on-stream data obtainable on a plant-wide basis. The selection of representative UT points must consider differences in flow rates, turbulence and fouling tendencies which affect corrosion. Scanning UT methods are limited to lower temperatures than spot, manual UT measurements. However, they permit making a permanent record for future comparisons. These methods are particularly well suited to areas where localized corrosion can occur such as at high turbulence areas in the hot or overhead systems or in areas of the overhead system vulnerable to underdeposit corrosion or impingement. While sometimes limited by accessibility and geometry, RT is also an important on-stream inspection tool. It can be used to measure wall thickness, indicate the presence of pitting, and under some circumstances, show thickness of deposits on pipe walls. RT provides as permanent visual record, unlike some of the other measuring methods. Another useful on-stream inspection method is the use of infrared to measure temperatures of heater tubes, vessel shells, electrical equipment, heat exchangers, insulation damage, etc. The ability to perform reliable remote temperature measurement is extremely important both from the standpoint of equipment reliability and economy of energy. When the unit is shut down and equipment opened up, visual inspection can be performed. This includes not only looking, but also checking the depths of pits with pit gauges, calipering the O.D. and I.D. of exchanger tubes, looking for cracks using dye-penetrant or one of the several magnetic particle methods, plus extensive use of UT and RT methods.

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Since heat exchanger tubes, due to their geometry and arrangement in bundles, do not lend themselves to visual inspection along their full length, several inspection tools have been devised. The simplest is the borescope which allows visual examination along the I.D. of a tube. Since no measurement can be made, this is of limited value. Eddy-current equipment allows a record to be made of the ID of the tube wall, indicating cracks, pitting and general wall thickness. Equipment based on ultrasonic principles is also used for this purpose. Ultrasonic wall thickness measurements should be routinely made at predetermined points on all piping systems in the unit. UT measurements should also be taken at a number of representative points on vessel shells and nozzles, exchanger shells and nozzles and at one or more points along the length of each heater tube. If coking of heater tubes is a problem, radiographic techniques can be developed to evaluate this. While not as common as with FCC light ends, equipment in the overhead systems of the Preflash, Atmospheric Vacuum, and light ends towers are vulnerable to wet H2S cracking. Therefore this equipment should be included in a wet H2S inspection program.

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5.0

October 1999

FLUID CATALYTIC CRACKING UNIT REACTOR, REGENERATOR, AND MAIN FLUID CATALYTIC CRACKING UNIT CORROSION AND METALLURGICAL DAMAGE MECHANISMS: FRACTIONATOR

5.1

ABSTRACT This section describes the many types of corrosion and metallurgical damage that can occur in the hot sections of Fluid Catalytic Cracking (FCC) Units; both in service and during shutdowns. High temperatures, corrosive liquids and gases, and erosive solids create environments in which serious metal loss and metallurgical damage can occur. Primary areas of focus are the riser/reactor, regenerator, flue gas system and main fractionator. An overview of the process, general materials of construction, corrosion/metallurgical damage mechanisms, and monitoring /inspection techniques are presented. Wet corrosion associated with the main fractionator overhead and gas recovery section is discussed in a separate section entitled "Catalytic Cracking Light Ends Recovery Unit Corrosion and Corrosion Control" - Section 3 §6.0

5.2

INTRODUCTION Fluid Catalytic Cracking (FCC), is a refining process in which heavy oils or residuum feedstocks of little commercial value are broken down or cracked into lighter more useful products through the use of elevated temperature, relatively low pressure and catalyst. Although the exact composition of feedstocks processed in an FCC Unit varies from one refinery to another, it usually includes straight run heavy gas oils and Coker gas oils. Since the introduction of more advanced catalysts in the 1960’s, atmospheric residuum and vacuum tower bottoms have also been processed at an increasing rate. Generally, operating conditions, catalyst, and hardware design are varied to maximize production of high octane gasoline. The cracking process also yields useful quantities of isobutane and light olefins suitable for downstream production of premium gasoline blending components such as methyl tertiary butyl ether (MTBE) and alkylate. The evolution of the FCC, which began in the early 1940's, was initiated by the technological developments required to meet the demand for high-octane motor gasoline and alkylate feedstocks created by World War II.

5.3

FLUID CATALYTIC CATALYTIC CRACKING UNIT PROCESS DESCRIPTION

5.3.1

Cracking Reaction The cracking reaction, the key to obtaining desired yields, is accomplished by subjecting a vaporous feed stream or charge of heavy, long-chain hydrocarbon molecules to fluidized catalyst at 480oC (900oF) to 540oC (1000oF) for a matter of seconds. As the large molecules break or crack, a full range of smaller molecules are formed; including cracked paraffinic/olefinic gas, gasoline, and light cycle oil. More densely packed, higher boiling constituents such as heavy cycle oil, slurry recycle (or fractionator bottoms), and coke are also formed. However, because the catalysts are "selective," they promote desirable reactions to form valuable gasoline and

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olefins. This characteristic distinguishes the FCC process from "thermal cracking," which produces a significantly higher yield of light gas and coke.

5.3.2

Catalyst / Catalyst Circulation The FCC process presently relies on synthetic zeolitic catalysts, commercialized over 25 years ago. Individual composite catalyst particles consist of a mixture of fragile crystalline aluminosilicate materials, or zeolites, dispersed in an amorphous matrix of active alumina, silica, clays, etc. The zeolites provide the primary cracking function. The matrix offers desirable physical properties such as size, strength, hardness, and density; facilitates heat transfer during operation; and promotes some degree of added cracking of the heaviest feed components. Zeolites are effective in actively promoting cracking reactions because they have a highly porous structure and, therefore, a tremendous amount of internal surface area. Their numerous microcavities and channels facilitate intimate contact between vaporized hydrocarbon feed molecules and catalyst active cracking sites. It is for this reason, that zeolites are frequently referred to as 'molecular sieves'. Prior to the introduction of zeolites in the 1960's, the active ingredient in FCC catalyst was amorphous alumina. These early catalysts were temperature sensitive and, in comparison, suffered from low activity and poor gasoline selectivity. Moving to zeolitic catalysts permitted shorter cracking reaction times and eliminated the need to recycle unconverted reactor effluent back into the feed stream to obtain desired product yields. In effect, zeolitic catalysts revolutionized the FCC process, substantially increasing plant throughputs and markedly influencing hardware design/modifications. The name Fluid Catalytic Cracking Unit is derived from the manner in which the catalyst is handled in the process. FCC Unit catalyst consists of very fine 40 to 100 micron (0.0016" to 0.0039") diameter microspheres , resembling talcum powder, which move through the plant in a fluidized state. In fluidization, gas in the form of air, steam, or vaporized hydrocarbon, travels through the powdered catalyst at a velocity sufficient to suspend it. The aerated solid-gas mixture acts as a boiling, bubbling fluid that can he continuously circulated between the regenerator and reactor, greatly simplifying the equipment necessary for catalyst handling and the control of catalyst flow. Fluidized catalyst exhibits a hydrostatic or head pressure just as liquids do. However, unlike a true liquid, the density of fluidized catalyst depends on the velocity of the gas used to suspend it. Consequently, increasing the gas velocity decreases the density and head pressure exerted by a given height of fluidized catalyst. Catalyst transport, therefore, is controlled primarily by differential gas pressure between the regenerator and reactor, differential catalyst-gas mixture densities (through aeration) and slide valves.

5.3.3

Cat Cracker Hardware / Process Flow The four principal component systems in the hot section of the FCC Unit are the riser/reactor, regenerator, flue gas system, and main fractionator. The riser/reactor is the area in the cat cracker where the cracking reaction takes place. The regenerator restores catalyst activity by burning catalyst coke deposits, and provides the heat required by the endothermic cracking reaction. To maintain the process, continuous circulation of fluidized catalyst is needed from the reactor to the regenerator. The flue gas system is responsible for heat recovery, and purifies regenerator waste gas for discharge to atmosphere. The main fractionator cools the cracked reactor effluent

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gas and separates the light and heavy cycle oils from the lighter fractions (cracked gasoline, olefins, etc.). Figure 3-3 provides a simplified flow diagram for one possible FCC Unit configuration and is the basis for the detailed discussion below of each principal component system.

5.3.4

Riser/Reactor The riser/reactor is the area in the FCC where the cracking reaction takes place. Gas oil feed, preheated from 260oC (500oF) to 425oC (800oF) using heat exchangers and/or a feed furnace, is introduced at the bottom of the vertical riser through a single pipe inlet or multiple feed nozzles (atomizing steam is often introduced in conjunction with the feed to disperse it evenly throughout the riser). In the riser, intimate contact between the heated hydrocarbon charge and hot 675oC (1250oF) to 730oC (1350oF) regenerated catalyst causes the feed to vaporize rapidly and rise. The cracking reaction begins as soon as the vaporized hydrocarbon is adsorbed onto the catalyst and enters the pores to contact active cracking sites. The mixture of hydrocarbon charge vapors continues to crack as it moves up the riser, and can be assisted by lift gas (e.g. typically steam). During the cracking reaction, carbon is deposited on the catalyst in the form of coke. As the coke builds, it decreases the ability of the catalyst to crack hydrocarbon molecules, deactivating it. By the time the vaporized charge reaches the reactor, the cracking process is essentially complete and the catalyst is spent. This entire process occurs very rapidly, typically on the order of 2 to 5 seconds. Contemporary reactors, such as that shown in Figure 3-3, which typically operate in the 480oC (900oF) to 540oC (1000oF) range, do little more than separate cracked hydrocarbon vapors from the catalyst (hence, they are often much smaller than early reactor designs). Nearly all cracking takes place in the riser. In early designs, intended for use with lower activity amorphous alumina catalysts, very little cracking took place in the riser (the primary function of early risers was simply to mix and vaporize the catalyst and feed). Consequently, it was necessary for cracking to continue in the reactor. This was accomplished by maintaining a fluidized bed of fixed height in the reactor, termed the dense phase. The cracked gas/catalyst mixture above the dense phase was termed the dilute phase. Most commonly in bed cracking reactors, the aerated hydrocarbon stream entered the reactor through a plate grid which supported the fluidized bed. With the advent of zeolitic catalysts in the 1960s, riser cracking became the norm. Many fixed bed units were modified to permit riser cracking by extending the original vertical catalyst transfer line to increase residence time. Some units originally designed for riser cracking; however, continued to have the flexibility of bed cracking. Heat provided by the hot catalyst and continued contact between the catalyst and hydrocarbon gas keeps the cracking reaction going. To prevent over-cracking (e.g. of gasoline into lighter ends) in the dilute phase and carryover of catalyst downstream to the main fractionator, centrifugal separators known as cyclones are required. The cyclones separate the spent catalyst from the hydrocarbon vapors using centrifugal force. The catalyst is thrown against the cyclone walls and drops to the bottom of the reactor through an extended pipe called a dip leg. Cracked hydrocarbon vapors exit the top of the cyclones and are transported from the reactor to the main fractionator by way of the reaction mix line. The cyclones can be located either inside or external to the reactor and typically consist of two or more stages to improve separation efficiency. Before leaving the reactor, spent catalyst passes through a stripper section, where any remaining adsorbed hydrocarbon is separated from the catalyst using a combination of stripping steam and baffles/shed trays. Catalyst flow from the reactor is regulated by a slide valve in the spent catalyst transfer line. This slide valve also regulates the reactor pressure.

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5.3.5

October 1999

Regenerator The function of the regenerator is to burn coke deposits that have accumulated on the spent catalyst so that it can be reused. The regenerator can be located either adjacent to the reactor (often at different elevations), as shown in Figure 3-3, making it a side-by-side FCC Unit, or it can be mounted below the reactor (or vice versa), in which case it is called a stacked FCC Unit. The design of the initial FCC Unit regenerators was limited by the early amorphous catalysts, which were not capable of maintaining catalyst activity if heated above 590oC (1100oF). As catalyst quality improved, temperatures increased. With the high 650oC (1200oF) to 760oC (1400oF) regeneration temperatures currently employed, residual carbon on regenerated catalyst has been lowered to less than 0.1%, while catalyst holding times have improved to 3 - 4 minutes (as compared to 10 - 15 minutes for units which operated at 590oC (1100oF). The regeneration process begins when spent catalyst from the reactor enters the regenerator through the spent catalyst standpipe. It is propelled up the spent cat standpipe into the regenerator using lift gas (e.g. steam, air, etc.). Once in the regenerator, the hot catalyst is contacted by oxygen, supplied continuously through an air distributor (shown in Figure 3-3 to be a perforated grid) at the bottom of the regenerator, and combustion commences. Some units have pipe grids and others have an air ring/nozzle air distribution arrangement. Coke is consumed in the combustion (oxidation) process, producing regenerated catalyst, flue gas (e.g. CO, CO2, SOx, NOx, etc.) and heat. The major reaction is the coke plus air (oxygen) going to CO and then CO2. This reaction generates considerable heat. The heat is retained by the catalyst to sustain cracking in the reactor. The majority of combustion occurs in an area at the bottom of the regenerator above the air distributor, where catalyst concentration is greatest (called the dense phase). Little combustion occurs in the upper part of the regenerator (or dilute phase), which consists primarily of flue gas and entrained catalyst. The regenerator employs cyclone separators, similar to those previously described for reactors, to disengage catalyst carried upward by the rising flue gas. The flue gas escapes out of the top of the cyclones into the flue gas system, while the recovered catalyst is directed back down to the dense phase of the regenerator through the cyclone dip legs. Following regeneration, catalyst is directed to the regenerated catalyst standpipe and returned to the riser to again participate in the cracking reaction.

5.3.6

Catalyst Transfer System Catalyst transfer piping used to continuously carry fluidized catalyst from the reactor to the regenerator and back again can have one of two basic arrangements: U-shaped lines (U-bends) or vertical (possibly sloped) standpipes and risers. By far, the most common arrangement today consists of standpipes and risers. The application of the U-bend concept, used in conjunction with some fairly early fixed bed reactors, simplified catalyst circulation by eliminating the need for valve-controlled flow. Although valves were present to prevent potential catastrophic upsets such as catalyst flow reversal, normal catalyst flow was achieved by changes in differential pressure between the reactor and regenerator and by changes in the density of fluidized spent catalyst entering the regenerator (using aeration). Systems employing spent catalyst standpipes and regenerated catalyst risers use slide valves to control flow. The regenerated catalyst slide valve controls the amount of hot catalyst entering the

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reactor, and is, therefore, responsible for maintaining the appropriate reactor temperature. The spent catalyst slide valve controls the reactor catalyst level in the stripper.

5.3.7

Flue Gas System The flue gas system purifies regenerator waste gas for discharge to the atmosphere. This involves cooling the gas, removing catalyst fines and removing pollutants. Waste flue gas leaves the regenerator at 675oC (1250oF) to 760oC (1400oF) through cyclone separators, which are responsible for removing the majority of the entrained catalyst. In most units, the gas then passes through a steam generator or vertical shell and tube heat exchanger known as a flue gas cooler to produce additional steam for the refinery. After cooling, fine catalyst particles (known as fines), too small to be removed by the regenerator's cyclone separators, are typically removed by electrostatic precipitators or wet gas scrubbers. The precipitator imparts an electrical charge to the particles and then pulls them from the gas by way of magnetic attraction using oppositely charged plates. Stack scrubbers are used to remove pollutants (NOx, SOx, etc) in addition to fines. The flue gases are then either discharged to the atmosphere or burned in a CO (carbon monoxide) boiler for further heat recovery. Many newer units take advantage of the hot flue gas to generate power and drive the main air blower. The power recovery turbines take the hot flue gas off the regenerator after suitable catalyst removal and discharge it to the downstream cooldown and clean up system after extracting considerable horsepower.

5.3.8

Main Fractionator Cracked hydrocarbon gases exit the reactor cyclones between 510oC (950oF) to 540oC (1000oF). They pass, without cooling, into the main fractionator column where heavy cat cracked gasoline and light/heavy cycle oils are separated from the lighter fractions. (The fractionator functions much like an atmospheric crude distillation column in a Crude Unit). The cat cracked gasoline makes a good motor blending component, the light cycle oil makes a good blending stock for No. 2 domestic heating oil or diesel fuel, and the heavy cycle oil is fed to a Coker (thermal cracker), Hydrocracker or used as a residual fuel component. Unlike other refinery plants, the main fractionator does not require a reboiler. Heat can be supplied solely from the hot gas leaving the reactor. Stripping steam is often used at the fractionator inlet to drive the hydrocarbon molecules farther apart (making it easier to fractionate) and assist carrying the lighter gases up the tower. Most main fractionators have a bottoms temperature in the 340oC (650oF) to 400oC (750oF) range. The overhead stream from the fractionator, typically 95oC (200oF) to 120oC (250oF), is piped to a gas recovery section and subjected to further fractionation, caustic treating, and H2S removal. This yields both light and heavy gasolines, and considerable quantities of propane, butane and light gas. A detailed process description and discussion of aqueous corrosion mechanisms that occur in these sections is provided in a §6.0 - Catalytic Cracking Light Ends Recovery Unit.

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MAIN FRACTIONATOR

Paraffinic / Olefinic and Light Cracked Gasoline

Reaction Mix Line

o 200 -250 Fo

o

900 -1000 F

TO FRACTIONATOR OVERHEAD SYSTEM

o

Flue Gas Slide Valve

Reflux Treated Gas

Cracked Gas Outlet

Heavy Cracked Gasoline

Flue Gas Line o o 1275 -1425 F

o 275 -300 Fo

Reflux

o 900 -1000 F

Multistage Cyclone Seperators

o

LCO STRIPPER

o 500 -600 F

Heavy Cycle Oil (HCO) Reflux Light Oil Cycle (LCO) o o 375 -450 F

REACTOR

Trickle or Flapper Valve

Stripping Steam

RISER Feed Nozzle(s)

CHARGE TANK

Hot Feed o

450 F

Spent Cat Transfer Line (StandPipe)

Normal Cat Flow

o

2nd Stage 1st Stage

Electrostatic Precipitator

Dilute Phase

Fract. Bottom Pumps

650 -700 F

Plenum o 1250 -1400 Fo

STRIPPER

Bottoms

o

Diplegs

Cat Level

Baffle Plates

o

FLUE GAS COOLER

REGENERATOR

Air Grid Expansion Bellows

Spent Catalyst Slide Valve

Fract. Bottoms

Cold Feed

Charge Pump

Charge Preheat Exchanger

Regenerated CatSlide Valve

PREHEATER

Atomizing Steam GENERIC FLUID CATALYTIC CRACKING UNIT PROCESS FLOW DIAGRAM Figure 3-3

Lift Steam

Lift Air Main Air

Stack

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KEY 1 2 3 4 5 6 7

- Carbon Steel - 1 … Cr Low alloy Steel - 5 Cr Low Alloy Steel - 9 Cr Low Alloy Steel - 12 Cr Stainless Steel - 3xx Series Stainless Steel - 4xx Stainless Steel

= Bare Alloy = Internal Erosion Resistant Refractory Required in Conjunction with Metal (Hot Wall Design) = Internal Insulating / Erosion Resistant Refractory Required In Conjunction With Metal (Cold Wall design)

GENERIC FLUID CATALYTIC CRACKING UNIT MATERIALS OF CONSTRUCTION DIAGRAM Figure 3-4

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5.4

October 1999

MATERIALS OF CONSTRUCTION CONSTRUCTION FCC technology and design have evolved almost continuously since its initial introduction in the mid-1940's. Consequently, many of the over 350 FCC Units which are in operation today worldwide are essentially unique with their own set of design and materials problems. Most of these units were designed and run primarily on distillate feed with some resid. Some new units are designed to run primarily on resid feed and have a different design and materials problems. There is no such thing as a standard configuration in FCC Units. Despite the differences, however, certain basic principles provide a unifying materials philosophy. These principles, along with common materials of construction, are presented below. Figure 3-4 provides a graphical summary of FCC Unit materials of construction, using the simplified FCC Unit configuration discussed previously in Section 3 - §5.3.

5.4.1

Reactors The following damage mechanisms must be considered when designing, modifying or inspecting a FCC Unit reactor. A detailed explanation of each damage mechanism is provided in the Section 2 - Corrosion and Damage Mechanisms. • • • •

Materials exposed to full reactor temperatures must resist high temperature sulfidation and carburization. Some reactors are thermally insulated with refractory linings to avoid exposure of the shell to the process environment. Both metals and refractory linings must be capable of resisting catalyst erosion. The severity of erosion varies with location in the reactor. Metals must not suffer unacceptable metallurgical changes that would lead to embrittlement, deformation, internal fissuring or early failure. Design should account for thermal expansion to avoid mechanical distress/cracking of constrained components.

(i) Shells Historically, reactors have been divided into hot wall and cold wall designs. The hot wall reactors are typically constructed of low alloy steel, such as 1-1/4Cr-1/2Mo. This material is primarily selected over carbon steel for its improved high temperature strength and freedom from graphitization. However, low alloy reactors require pre and post heat treatment when welding repairs are made, which complicates any repair considerably. Many older hot shell reactors are carbon steel and some have been in service approaching 450,000 hours. These reactors operate in the creep range and are candidates for remaining life studies. Hot wall reactors may be refractory lined entirely or selectively for erosion resistance (i.e. only in the dense bed area). Erosion-resistant linings used in hot wall reactors consist of a relatively thin, hard, highly dense refractory (typical density is greater than 115 lb/ft3 or 1840 kg/m3). The linings, about 1in (25 mm) in thickness, are usually phosphate-bonded and hand-packed, and are anchored by 12 Cr stainless steel (Type 410) hexmesh that is welded directly to the shell. The choice of 12 Cr stainless steel is dictated by thermal expansion considerations, to prevent breaking the hexmesh-to-shell attachment welds. More recently, 'S-bar' anchors have been introduced. These anchors can be used where it would be difficult to properly install hexmesh; such as where the hexmesh must be forced to fit on extremely curved surfaces. Cold wall reactors are constructed with carbon steel shells. They have to be internally insulated to take advantage of the lower design temperature allowed by ASME Boiler and Pressure Vessel Code. As a result, they are thinner walled than a similar materialed hot wall reactor. Castable refractories with good insulating characteristics, however, are very soft and easily eroded. To

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achieve a combination of good erosion resistance and insulating properties, two cold wall refractory systems can be employed in the reactor: • •

dual layer (composite) linings or single-layer (monolithic) intermediate-density castables.

In the early years, dual-layer linings were used exclusively. The dual-layer linings consisted of a 4 in (100 mm) insulating layer of soft, less than 75 lb/ft3 (1200 kg/m3 ) density refractory, against the shell, protected from erosion by a 1 in (25 mm) thick, hard layer of high density refractory packed into 12 Cr stainless steel hexmesh. The hexmesh was attached to the shell by metal studs that extended the full thickness of the insulating layer. This type of lining, however, proved expensive to install and difficult to maintain. One of the major problems was coking between or behind the refractory. An alternative lining system, used more frequently today, consists of a single, thick layer of medium-weight, intermediate-density castable, supported by Type 304 stainless steel v-anchors rather than hexmesh. Refractory densities range from 75 lb/ft3 (1200 kg/m3) to 115 lb/ft3 (1840 kg/m3). This type of lining does not provide as much insulation as the light-weight insulating refractory nor as much resistance to erosion as the hard, high density refractory, but is generally proving to be satisfactory. The intermediate density castables, like the low density castables, are typically thick, on the order of 4 in (100 mm) to 5 in (125 mm). They are also hydraulically bonded (require dry-out) and gun-applied. Stainless steel fibers are often added to the refractory mix to hold it together should cracks develop as a result of thermal expansion. As previously noted, reactor shells are built of either carbon steel or 1-1/4Cr-1/2Mo low alloy steel. Although the question of which material to use is a factor of design, hot or cold wall, the 11/4Cr-1/2Mo does have some disadvantages. To achieve soft, ductile weldments bearing good toughness. 1-1/4Cr-1/2Mo usually requires postweld heat treatment (PWHT) following construction or repair. This involves heating the material to 730oC (1350oF) for a period of 1 to 2 hours, and can add significant cost, difficulty and time to a job. Although the hot reactor environment is very high in hydrogen sulfide (H2S), industry experience indicates a surprising absence of H2S corrosion on carbon steel and 1-1/4Cr-1/2Mo. The reason for this is not entirely clear, since both high temperature and H2S concentrations would lead one to expect relatively high corrosion rates. Case history data, presented as early as 1974, suggests that H2S corrosion rates rise with temperatures up to about 455oC (850oF) and then decrease. The low corrosion rates at very high temperatures in the reactor may be due to the formation of a protective coke layer. (ii) Internals Reactor internals such as cyclones, grids and stripping section baffles are typically constructed of carbon steel, which has generally proven to be satisfactory for distillate FCCU’s. The new purpose designed resid FCC’s generally require higher alloy internals to combat the higher design temperature. Carbon steel cyclones and dip legs characteristically suffer from erosion damage and must be internally protected by an erosion-resistant lining of hard, high density refractory supported using 12 Cr stainless steel hexmesh. Because cyclones have hot process gas on all sides, they cannot be kept cool using insulating refractory. Consequently, the carbon steel reactor cyclones can also suffer a slow metal loss due to carburization and to sulfidation. To prevent this, cyclones have been upgraded to 12 Cr stainless steel in some plants. However, although 12 Cr offers added

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resistance to carburization and to sulfidation, it may embrittle at the reactor operating temperature, making subsequent maintenance and repair very difficult. Reactor internals are often complicated in design, making it difficult to account for all needed allowances to permit free thermal expansion and contraction on heating and cooling. Resulting mechanical distress can cause cracking that can lead to rapid catalyst erosion if a pressure differential exists across the crack.

5.4.2

Regenerator In the early days, regenerator temperatures were low, around 620oC (1150oF), due to limitations with amorphous catalysts. With the advent of zeolitic catalysts in the 1960's and complete combustion some years later, regenerators began operating as high as 730oC (1350oF) to 760oC (1400oF). Higher demands have been put on construction materials as a result. Damage mechanisms which should be considered when designing, modifying or inspecting an FCC Unit regenerator follow. Detailed explanations of damage mechanisms are provided in Section 2 "Corrosion and Damage Mechanisms". • • • • •

Materials exposed to the full regenerator temperature and complete combustion must resist high temperature oxidation. Materials not having sufficient oxidation resistance must be thermally insulated with refractory linings. Materials exposed to the full regenerator temperature and partial combustion must resist high temperature carburization. Both metals and refractory linings must be capable of resisting catalyst erosion. The severity of erosion varies with location within the regenerator; typically most mild along straight vessel walls and most severe inside cyclones. Metals must not suffer unacceptable metallurgical changes that could result in embrittlement, internal fissuring, or early failure. Component design should include allowance for free thermal expansion to avoid mechanical distress/cracking.

(i) Shell Regenerator shells are commonly constructed of carbon steel. Internal refractory linings are used to keep the shell cool enough to avoid an unacceptable loss of strength, prevent the occurrence of graphitization and protect against erosion where needed. The linings also protect against oxidation and carburization, a factor that has become increasingly important as regenerator temperatures have risen over the years. The basic refractory systems used in the regenerator are similar to those used in the reactor (see §5.4.1). Either a dual layer refractory lining is used, where the light, soft inner layer acts as thermal insulator and the outer dense layer prevents erosion; or a single-layer, medium weight refractory is used with intermediate properties. In early plants, the dual layer lining was used exclusively. The studs which supported the 12 Cr (Type 410) stainless steel hexmesh were carbon steel. As regenerator temperatures rose, stud failures occurred by oxidation, causing loss of the entire refractory system. To solve this problem, stainless steel (Type 410) studs were specified in lieu of carbon steel. However, at the high operating temperatures 12Cr has marginal oxidation resistance. Today, intermediate-density refractories have become popular for use on regenerator shells. They do not insulate as well as the light insulating refractories, nor do they provide as good an erosion barrier, but they do represent a good compromise with substantial cost savings and ease of

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application. The typical system now used on regenerator shells is a single-layer intermediate refractory that is applied by gunning and supported by 304 stainless steel vee studs. (ii) Internals Cyclones in early plants were usually carbon steel (although C-1/2Mo steel was used in a few instances). These had reasonable life at regenerator temperatures up to about 620oC (1150oF), but had to be upgraded as operating temperatures rose for improved strength and oxidation resistance. The material of choice today for cyclones and the cyclone support structure is Type 304H stainless steel. Cyclones are internally protected by a 1 in (25 mm) thick erosion-resistant refractory linings, supported by Type 304 hexmesh (though gradual refractory thickness loss by erosion should almost always be anticipated). Recently, 'S-bar' anchors have begun to be used instead of hexmesh, especially for repairs. These offer an advantage on curved surfaces when bending hexmesh to fit is difficult. The top few feet of dip legs in the cyclones may also be lined with refractory. Many different systems have been employed to introduce catalyst and air into the regenerator. The predominant air distribution system used to be perforated grids. However, multi-nozzle air distributors and air rings are now common. Because grid temperatures are lower than those in the catalyst bed above the grid, due to the cooling effect of regeneration air introduced below the grid and the combustion of coke above it, lesser alloys can often be used for the grid than for some of the other internals. Plants commonly use grids of 1Cr-1/2Mo to 5Cr-1/2Mo low alloy steel. To accommodate thermal-expansion differences between the grid and shell and maintain a pressure drop across the grid (i.e. to prevent flue gases/catalyst from leaking by), flexible members called 'grid seals' are used. Grid seals are typically 13 Cr (Type 405) stainless steel. With respect to air ring or multi-nozzle air distributors, metal temperatures are hot enough to require the use of stainless steel (Type 304H). Because of the high thermal gradient between the air ring and the regenerator atmosphere, it is usually necessary to refractory line the OD of the air ring. In many FCC Unit designs, the spent catalyst enters through the bottom of the regenerator vessel and passes upward through the grid by way of an internal refractory lined low alloy (i.e. 1-1/4Cr1/2Mo) or 3xx Series stainless standpipe. Because thermal expansion considerations make it impractical to weld the spent and regenerated catalyst standpipes to the regenerator shell and grid, expansion bellows are used where these lines passed through the grid. Expansion bellows are typically 3xx stainless steel or nickel-base Alloy 625 (UNS N06625). Alloy 625 has more elevated temperature strength, but can embrittle at regenerator operating temperatures. It is often desirable to install refractory linings on the outside of the spent catalyst standpipe, in addition to its use inside, if it is exposed to turbulent catalyst flow inside the regenerator (i.e. it extends into the dense bed for the case of a regenerator with a grid air distribution system). In instances where air distribution rings are employed, external refractory linings are also common. In fact, much of the regenerator internals subject to erosion are lined using a intermediatedensity or phosphate-bonded castable. Such linings should contain metal fiber for reinforcement and are generally 1 in (25 mm) to 2 in (50 mm) thick. Although Type 304H is commonly used to construct regenerator internals in today's high temperature regenerators, it can become susceptible to polythionic acid stress corrosion during shutdowns from previous high temperature exposure during normal operation. Because experience has shown that polythionic acid cracking failures in the regenerator are rare, however, most refiners continue to view Type 304H as the material of choice for the regenerator environment. The Type 304H material becomes less sensitive to polythionic acid cracking problems with exposures of over 10,000 hours at greater than 621oC (1150oF).

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The regenerator environment, when cooled through the dew point, is a very potent polythionic acid stress corrosion cracker. Welded 304H or 304 that does not see sufficient time at temperatures >621oC (1150oF) will be vulnerable to cracking while in service. Typically, this would include the solid austenitic stainless steel slide valve bonnets and the catalyst withdrawal lines. The regenerator environment is also a potent carburizing environment. The more CO, the more potent the carburizing potential. The 2-1/4Cr-1Mo and the 5Cr-1/2Mo regenerator internals used in the transition from carbon steel to austenitic stainless steel in the 1960’s and 1970’s had major carburization problems. With modern FCCU operation, the regenerator environment will carburize the 304H internals currently in use.

5.4.3

Catalyst Transfer Piping System Catalyst transfer piping is usually constructed of carbon or low alloy (1-1/4Cr-1/2Mo to 9Cr1Mo) steel with an internal refractory lining. In the early days, a dual-layer refractory lining was used, supported by hexmesh. As refractory technology improved, the refractory of choice became the single-layer, intermediate-density refractory, supported by vee studs. The quality of this lining was further improved by reinforcing it with stainless steel (Type 304) needles. Many of the early regenerated-cat slide valves had cast or wrought Type 304 stainless steel bodies and erosion resistant refractory linings on parts exposed to flow. Steam was often used as a purge to keep catalyst from collecting in the valve body. If the valve body was not externally insulated to keep it hot, water condensation could form at the valve end remote from flow. The combination of water and sulfur oxides from the process gas created an aqueous acidic condition that often led to polythionic acid stress corrosion cracking of wrought 3xx Series stainless steel valve bodies. Cast stainless steel slide valves generally did not polythionic crack, but were susceptible to sigma phase embrittlement. These problems associated with stainless slide valves can be avoided by using internally insulated and erosion-resistant refractory-lined carbon steel or low alloy steel cold shell slide valves.

5.4.4

Reaction Mix Line, Main Main Fractionator and Bottoms Piping The reaction mix line, which carries cracked gas from the reactor to the main fractionator, has been constructed from a variety of alloys over the years, depending on perceived corrosion and metallurgical problems. Materials used in the past include internally insulated carbon steel or non-insulated 1Cr-1/2Mo, 1-1/4Cr-1/2Mo, 5Cr -1/2Mo and 3xx Series stainless steel. Materials selection is based primarily on the need for strength and resistance to high temperature graphitization. Localized attack by high temperature H2S is possible at 'cool' spots where heat is drawn away by external supports (i.e. a protective coke barrier does not form at the lower temperatures). However, the potential for H2S attack in this environment is not a strong driver for upgrading to more sulfidation resistant alloys. Although normally solved through design rather than materials upgrading, thermal fatigue cracking has occurred in reaction mix lines, especially at miters. The source of stress is the differential thermal growth between the reactor overhead and the fractionator inlet nozzle which can place high strains on the piping each time the reactor is cycled. Fractionator shells are typically carbon steel, clad with 12 Cr stainless steel (Type 405, 410 or 410S) in the areas hot enough to be susceptible to sulfidation corrosion above 285oC (550oF). Trays are typically 12 Cr (Type 405, 410 or 410S) stainless steel in the hotter areas and 12 Cr or carbon steel further up in the column. Fractionator maximum temperatures are usually less than 370oC (700oF) to minimize coking, however the inlet nozzle can run hot enough, at 480oC (900oF) to 540oC (1000oF), to be susceptible to high temperature graphitization. A concern has

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been the strength of carbon steel at the feed nozzle entry to the column. Some people have used clad low alloy steels in the feed area. The hot 340oC (650oF) to 370oC (700oF) oil fractionator bottoms system needs to resist erosion from catalyst slurry, as well as corrosion from high temperature H2S. Process fluids entering the main fractionator contain catalyst fines, which often cause local erosion in the column bottoms system. The erosion in the lower part of the main fractionator is generally minor (not a serious problem); however, higher velocity areas in downstream bottoms piping / equipment (i.e. pumps, ells, etc.) can be significant. Piping and valves are typically 5Cr-1/2Mo or 9Cr-1Mo for sulfidation resistance. Downstream heat exchanger shell / channel claddings and tubes are often 12 Cr or 3xx Series stainless steel. Hardfacing alloys/vapor diffusion coatings are often needed to resist erosion in pressure let down valves and bottoms pumps. Bottoms pump cases have ranged from carbon steel to 12Cr. High chrome, erosion resistant irons are also used for bottoms pumps. The bottoms pumps often suffer from erosion problems even when operated at slow speed. Carbon steel cases have the advantage of easier weld repair.

5.4.5

Flue Gas System With today's high temperature regenerators, flue gas exits the regenerator cyclones at 675oC (1250oF) to 775oC (1425oF). Erosion from catalyst fines, oxidation resistance, carburization resistance, and the need for high temperature strength are the primary concerns. In flue gas ducts, erosion is more of a problem at elbows than in straight runs. It is particularly severe in and just downstream of restriction orifices and the slide valve. Piping materials are typically refractory lined carbon steel. When a power recovery turbine is used, inlet piping is typically uninsulated 3xx stainless steel to avoid refractory particles entering the turbine. Flue gas coolers (a vertical shell and tube heat exchanger with boiler feed water shell side) have refractory lined carbon steel in the inlet to protect against erosion and overheating. Steam generation heat exchanger tubes are carbon steel and depend on the cooling from the boiler feed water to keep tube metal temperatures low.

5.5

CORROSION / METALLURGICAL METALLURGICAL DAMAGE MECHANISMS AND CONTROL MEASURES In FCC Units, high temperatures, corrosive liquids and gases, and erosive solids create environments in which serious metal loss can occur. High temperatures also result in metallurgical problems not often seen in most other refinery plants. This section discusses each corrosion/metallurgical damage mechanism in detail, provides plant equipment locations where material problems are likely to be encountered and offers solutions to prevent future problems. For reference, a summary of possible damage mechanisms for each FCC Unit component is provided in Table 3-4. Table 3-5 provides control measures to prevent damage. Figure 3-5 shows the probable location of some of these mechanisms.

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TABLE 3-4 FCC UNIT REACTOR, REGENERATOR & MAIN FRACTIONATOR DAMAGE MECHANISMS COMPONENT Feed Riser Reactor Shell

Reactor Internals

Reactor Cyclones

Reaction Mix Lines (overhead piping)

Catalyst Transfer Lines

Slide Valves

Regenerator Shell

Regenerator Internals

Regenerator Cyclones

Flue Gas Lines and Coolers

Fractionator and Side Cut Piping, Exchangers Fractionator Bottoms Piping, Valves, Exchangers

5.5.1

EXPECTED DAMAGE MECHANISM Catalyst erosion of feed nozzle and riser downstream of feed nozzle Catalyst Erosion Refractory Damage High Temperature Sulfidation High Temperature Carburization Creep Creep Embrittlement Catalyst Erosion Refractory Damage High Temperature Sulfidation High Temperature Carburization High Temperature Graphitization 885oF Embrittlement Catalyst Erosion Refractory Damage High Temperature Sulfidation High Temperature Carburization Creep High Temperature Graphitization Catalyst Erosion High Temperature Sulfidation Thermal Fatigue Catalyst Erosion Refractory Damage High Temperature Graphitization Catalyst Erosion Refractory Damage Sigma Phase Embrittlement Polythionic Acid Stress Corrosion Cracking Catalyst Erosion Regenerator Damage Creep High Temperature Oxidation (Complete Combustion) High Temperature Carburization (Partial Combustion) Catalyst Erosion Refractory Damage Sigma Phase Embrittlement Polythionic Acid Stress Corrosion Cracking High Temperature Oxidation (Complete Combustion) High Temperature Carburization (Partial Combustion) High Temperature Graphitization Catalyst Erosion Refractory Damage Creep Sigma Phase Embrittlement Polythionic Acid Stress Corrosion Cracking High Temperature Carburization (Partial Combustion) High Temperature Oxidation (Complete Combustion) Catalyst Erosion Refractory Damage Sigma Phase Embrittlement Polythionic Acid Stress Corrosion Cracking High Temperature Oxidation (Complete Combustion) High Temperature Carburization (Partial Combustion) High Temperature Sulfidation High Temperature Graphitization 885oF Embrittlement Catalyst Erosion High Temperature Sulfidation

High Temperature Oxidation In a FCC plant, air, at times oxygen enriched, is used in the regenerator to burn carbon (coke) off of the catalyst. During this process, oxygen at temperatures over 540oC (1000oF) reacts with steel and other iron-based alloys to form the iron oxide Fe3O4. Continued reaction of the iron with

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oxygen causes the formation of a hard, uniform, black metallic looking scale that tends to be quite smooth. When oxidation rates are low, it may be difficult to see that the scale is present. Although higher oxidation rates result in a thicker scale, it can still be difficult to tell that significant attack has occurred, unless the scale begins to crack and spall off as a result of thermal cycling or because of the internal stresses that build up in the scale as it forms (the scale is approximately 5 times more voluminous than the metal consumed). An energetic beating with a hammer to remove the oxide layer, followed by ultrasonic inspection reveals the thickness of the scale and the extent of the corrosion (but also exposes any fresh, non-scaled metal surfaces to accelerated oxidation rates on plant start-up). High temperature oxidation presents a potential FCC plant problem only in the regenerator and its flue gas system. As FCC technology has improved, oxygen concentrations and temperatures in FCC regenerators have increased, resulting in more severe service conditions. Protection against high temperature oxidation is achieved by either insulating metal surfaces to keep them cool or by using alloys with increasing chromium content. The shell of an FCC regenerator, for example, is kept cool and free of oxidation by using an insulating refractory. Internal parts of the regenerator that cannot be insulated are protected through the use of alloys. Although lowchrome steels, like 1-1/4Cr-1/2Mo, are not measurably better in oxidation resistance than carbon steel, 5Cr-1/2Mo oxidizes at somewhat reduced rates and 12 Cr is even better. However, for parts operating at full regenerator temperatures, austenitic (3xx Series) stainless steels such as Type 304 /304H which contain approximately 18 wt% chromium are needed. Cyclones and the hexmesh S-bars supporting refractory are typical examples of Type 304 stainless steel use in the regenerator. 5.5.2

High Temperature Sulfidation Hydrogen sulfide (H2S) is formed in the FCC preheater and reactor by thermal decomposition of organic sulfur compounds in the plant feed. It is corrosive to steel at a temperature above approximately 285oC (550oF) in concentrations greater than 1 ppm. The high temperature corrosion reaction of iron with H2S, known as 'sulfidation', produces a uniform, and sometimes tenacious, black iron sulfide (FeS) scale in the FCC Unit. High temperature sulfidation occurs mainly in the preheater, feed piping downstream of the preheater, reactor, reaction mix line (transfer line from the reactor to main fractionator), main fractionator, and fractionator bottoms /side cut piping and exchangers. Sulfidation corrosion is a function of temperature and H2S concentration. Changing to a high sulfur feed, for example, almost inevitably leads to higher corrosion rates. Raising temperature, however, does not always result in increased sulfidation. Industry experience indicates that sulfidation rates increase up to about 425oC (800oF) to 455oC (850oF) and then decrease with further increases in temperature. Sulfidation corrosion in FCC reactors occurs at even lower rates than one would normally expect using general industry H2S corrosion data, allowing many plants to use carbon steel cyclones in FCC reactors operating as high as 480oC (900oF) to 510oC (950oF). It may be that the sulfide scale layer becomes plugged with coke, which acts to retard sulfide diffusion through the scale. Resistance to high temperature sulfidation in iron-base alloys is achieved by chromium additions. Of the iron-based alloys, 5Cr-1/2Mo is the least alloyed to have significantly better resistance than carbon steel. For example, hot side cut/bottoms piping and heat exchanger tubing downstream of the main fractionator are 5Cr-1/2Mo steel. However, carbon steel reactor cyclones and 1-1/4Cr-1/2Mo reactor effluent lines/hot wall reactor shells have demonstrated acceptable sulfidation rates. The 12 Cr steels (Types 405 or 410) are corroded very slowly by H2S under any conditions likely to be encountered in an FCC Unit. Some clad reactors still have considerable clad left after 250,000 hours service. The clad loss seems due to sulfidation and erosion. Some plants have upgraded reactor cyclones to 12 Cr stainless steel. The main

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fractionator 'hot zone' cladding and internals are often 12 Cr (Types 405 or 410) to resist sulfidation. The 3xx Series stainless steels (Type 304, 321, 347) are also totally corrosion-resistant to high temperature H2S and are widely used in preference to 12 Cr for cyclones because of superior room temperature mechanical properties following periods of extended high temperature exposure. As with high temperature oxidation, in the absence of alloy, sulfidation resistance can be achieved by insulating metal surfaces internally to keep them cool. Cold wall reactors, for example, are internally insulated carbon steel. High temperature sulfidation corrosion does not occur rapidly enough in FCC Units to create the probability of a catastrophic failure. Attack is easily found during turnarounds by UT because rates are nominal and attack is generally quite uniform (although highly turbulent areas can aggravate corrosion).However, the combination of sulfidation and erosion in the slurry lines has caused some unanticipated failures. (Refer to Section 2 §5.1.5)

5.5.3

High Temperature Carburization Carburization in FCC Units involves a series of steps. Initially, carbon (coke) is deposited on the metal surface. The carbon then reacts with the metal to form metal carbides. Diffusion (interatomic movement) of carbon and/or metal atoms within the material control the extent to which the reaction product (metal carbide) penetrates the metal. As the metal carbide layer forms, it experiences a high compressive stress, since it occupies a greater volume than the unaffected metal. The metal carbide may bulge away from the unaffected substrate or simply flake off, gradually reducing the metal thickness. Coke formation followed by carburization appears to be the mechanism on the reactor and fractionator side of the reaction section. The regenerator environment has enough CO present to be carburizing to the low Cr-Mo steels and the austenitic stainless steels. Both 2 1/4Cr-1Mo and 304H will carburize under partial combustion operation. This has become more of a problem since resid is being fed to the distillate units and resid crackers have come onstream. In FCC units, carburization used to be classified as a phenomenon of minor concern and was largely ignored. For example, the slow thinning of carbon steel reactor cyclones was attributed to carburization, but material upgrades were generally not made for this reason. However, in recent years, a number of problems have been reported in regenerators operating at higher temperatures with partial combustion (excess CO). Under such circumstances, CO in the regenerator and flue gas system has carburized even 3xx Series stainless steel. As a general rule, chromium additions seem to retard carburization in oxidizing or sulfiding (where H2S is present) environments, but not in reducing environments. However, 1-1/4Cr1/2Mo reactor shells have not been found to carburize significantly.

5.5.4

Polythionic Acid Stress Corrosion Cracking (PASCC) Alkthough the modified 3xx Series do offer improved resistance to sensitization, they will eventually sensitize to some degree at following long term operation at regeneration temperatures. Although the potential exists for PASCC, standard Type 304 or 304H has been used successfully in the vast majority of plants for many years without cracking. Some laboratory studies, backed up by plant experience, indicate that service at >621oC (1150oF) for at least 10,000 hours tends to diffuse Cr back into the grain boundary areas and will minimize cracking problems. The experience with slide valve bonnet insulation seems to verify the same reasoning.

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The major area of concern for PASCC is the regenerator system where Type 304/304H has become widespread since the introduction of high temperature regeneration in the 1960’s. (Reactors generally do not contain much 3xx Series stainless steel). Although cracking of regenerator refractory anchors/hexmesh and cyclones has occurred, most reported PASCC cases have been in equipment external to the regenerator, such as in 3xx Series catalyst withdrawal nozzles, wrought slide valves, flue gas lines and expansion bellows. Most PASCC problems that have occurred have been solved by means other than alloying. For example, elimination of wet steam purges (or purging with nitrogen rather than steam) to prevent catalyst accumulation in slide valves, using internally insulated carbon steel slide valves rather than cast or wrought 3xx Series stainless steel, specifying packed and insulated expansion joints, and eliminating water washing during shutdowns to keep dust levels down have all proved successful. If water washing cannot be eliminated, sodium carbonate (soda ash) can be added to wash water to neutralize the polythionic acids as they form. 'NACE International Recommended Practice RP0170-93' provides guidelines for soda ash washing equipment. The addition of ammonia to susceptible areas during shutdown has minimized PASCC in some instances. The low carbon grades have a strength problem that usually prevents their use around the regenerators. (Refer to Section 2 §5.3.4)

5.6

CATALYST EROSION Erosion, the largest single problem in the hot dry sections of FCC Units, is defined as the loss of material due to the impact and cutting action of solid particles. Unlike corrosion, which is the loss of metal from chemical reaction, erosion does not involve any reaction of the metal or refractory with the environment. It is a mechanical phenomenon. Eroded surfaces typically appear bright (absence of corrosion product) with sharp edges and distinctive flow patterns. The rate of catalyst erosion is influenced by the properties of the material surface being eroded. With respect to metals, there is little practical difference in erosion resistance between carbon steel, alloy steels, Type 410 stainless steel or 3xx Series stainless steel. Attempts to increase surface hardness through heat treatment or cold work have not increased erosion resistance significantly. Hard facing materials, deposited by welding or vapor diffusion, can provide improved erosion resistance. However, if the hard facing alloy consists of hard particles (i.e. tungsten carbide) in a soft matrix, the fine FCC catalyst eventually erodes the matrix material between the hard particles allowing them to drop out. Concerning refractory materials, erosion resistance generally increases with increasing refractory density, though compressive strength, binder type/amount, and aggregate hardness/distribution are also important parameters. The rate of catalyst erosion is also influenced by catalyst particle size, hardness, velocity, loading/concentration and impingement angle. Particle size/hardness is normally outside an Inspector's and Corrosion/Materials Engineer's control. In theory, larger particles are more erosive than smaller ones because they strike the metal or refractory surface with more energy. In practice, the size of catalyst particles does not fluctuate widely. In theory, a harder catalyst causes more erosion than a soft one. In practice, refiners do not typically optimize hardness to prevent erosion when purchasing catalyst. A commonly accepted threshold below which experience indicates little or no erosion occurs is 50 ft/s (15 m/s) to 60 ft/s (18 m/s). Once this threshold is exceeded, metal loss can increase dramatically. Erosion is a function of dilute phase catalyst concentration (loading). The more particles that strike a surface per unit time, the more metal that will be removed. It is interesting to note that fluidized catalyst, which differs from a liquid in that it does not exert a constant density across its cross-sectional area, exhibits increased erosion (and particle concentration) toward the outside of a bend when making a turn. Most FCC Unit equipment is eroded most quickly when catalyst particles strike the surface at a 45o angle (in

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contrast, brittle materials would experience their worst erosion damage at a 90o impingement angle). Erosion is a potential problem in the reactor and regenerator vessels, particularly in: • • •

cyclones, cyclone dip leg flapper or trickle valves, and grid holes, catalyst and flue gas piping, primarily at ells, in slide valves, and surrounding feed/steam injection inlets, and in the main fractionator bottoms system (pumps, piping, heat exchanger tubes).

Protection, outside the fractionator bottoms system, is generally afforded using erosion-resistant refractories. Hard facings provide protection as needed in the main fractionator bottoms where carryover of catalyst fines causes most problems. They are also used on a limited basis to protect selected parts of the catalyst slide valves. Experience suggests that erosion is most prevalent at changes in direction (i.e. elbows), locations of pressure drop (i.e. control valves), or locations of extreme turbulence/velocity (i.e. pumps, thermowells, cyclones, feed/steam injection inlets in cat transfer lines). Mild to moderate erosion is generally experienced on vessel wall or pipe straights. Small cracks or gaps in reactor or regenerator internals warrant special concern, as differential pressure can propel catalyst through them at high velocity. This situation has caused many serious erosion incidents, including through wall vessel leaks. 5.6.1

High Temperature Graphitization Graphitization requires exposure from 440oC (800oF) to 700oC (1300oF) for long periods and is most rapid around 565oC (1050oF). To minimize the risk of graphitization, carbon steels are normally limited to a maximum temperature of 425oC (800oF) . These temperature limits are normally applied to pressure-containing parts. For vessel internals, graphitization is often risked, because cracking will not result in a leak to atmosphere, and plate steels used to fabricate much of the carbon steel internals (such as reactor cyclones, etc.) are typically not as susceptible to chain graphitization as pipe steels. This is due to differences in deoxidization practice during steel making. Besides reactor cyclones, graphitization is possible in the main fractionator inlet nozzle, shell immediately adjacent to the inlet nozzle, and any location where the internal thermal insulation for carbon steel is damaged. Chromium contents of 1/2% or greater provide immunity. Consequently, chrome-moly steels such as 1-1/4Cr-1/2Mo, are sometimes used for construction of FCC Unit reactor shells, do not graphitize. [Refer to Section 2 §5.5.1 (ii)]

5.6.2

Sigma Phase Embrittlement Sigma is a brittle intermetallic compound or phase that forms in stainless steels over long periods of time at temperatures above 590oC (1100oF), which are commonly experienced by the regenerator. It results in brittleness and loss of impact strength, most apparent when the plant is down and cool. The brittleness due to sigma phase formation tends to disappear when the metal is heated above approximately 260oC (500oF) and to reappear on cooling below this temperature depending on the amount of sigma formed. Consequently, embrittlement is not likely to cause an on-stream failure, but care should be taken when carrying out maintenance work to minimize shock loadings that might trigger a brittle fracture. Significant sigma phase, as can be experienced in high alloy castings, may seriously affect the high temperature properties of a piece of equipment or a component. Sigma, itself, is an iron-chromium intermetallic compound that can form in stainless steels containing more than approximately 17% chromium. Consequently, sigma embrittlement is

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primarily associated in FCC Units with 3xx Series (austenitic) stainless steels, which nominally contain about 18% chromium. It forms much more readily from a ferritic structure than an austenitic structure. ('Ferritic' and 'austenitic' refer to the arrangement or packing of iron atoms in a steel, with those in an 'austenitic' structure more closely spaced). As such, most problems are associated with austenitic castings, such as hot wall slide valve bodies or weldments, which contain about 3 to 10% ferrite to avoid hot cracking during solidification. It is for this reason that cast stainless steel slide valves should not be insulated [heat loss keeps the metal below the 590oC (1100oF) threshold for sigma embrittlement]. However, not insulating the austenitic slide valves may cause operational problems such a slide sticking due to expansion differences with normal valve clearances. Certain chemical elements tend to promote sigma embrittlement. For example, Types 316 and 347, which contain molybdenum and columbium, respectively, embrittle more rapidly than Type 304. However, Type 304 is not immune. Sigma embrittlement failures of Type 304 components in FCC regenerators have been reported. Sigma embrittlement can be controlled by limiting the ferrite content of weld metal or castings to 10%, avoiding shock loads when the metal is cold, and use of Type 304 stainless steel in the regenerator system in preference to other austenitic stainless steel grades (Type 321, 347). Type 304H will form up to about 10% sigma in the base metal away from the welds. The combination of sigma and carbide precipitation can result in a signification loss of room temperature ductility when compared to annealed Type 304H. This loss of ductility means that more care must be taken during weld repair. Unless there is significant carburization, there is usually enough room temperature ductility to successfully weld repair.

5.6.3

885oF Embrittlement 4xx Series stainless steels (Type 405 or 410), also known as the family of ferritic and martensitic stainless steels, are subject to embrittlement in the 370oC (700oF) to 540oC (1000oF) range. It is called 885oF embrittlement because it occurs most rapidly at this temperature. Like sigma phase, 885oF embrittlement is also caused by the precipitation of an embrittling constituent in the steel. This phenomenon prevents the use of 4xx series stainless steel for pressure containing components in the hotter locations of FCC units. The higher the chromium content, the more susceptible the alloy. For example, Type 410 (12% Cr) is marginally susceptible, Type 405 (13% Cr) is slightly more susceptible, and Type 430 (17% Cr) is very susceptible. Although most 3xx Series stainless steels do not suffer from 885oF embrittlement, the ferrite structure in 3xx Series weld metal and castings, necessary to avoid hot cracking during solidification, is subject to 885oF embrittlement.

5.6.4

Creep Embrittlement Embrittlement Creep embrittlement is a marked lowering of creep rupture ductility in the weld heat affected zone of highly stressed C-1/2Mo, 1 Cr-1/2Mo, and 1-1/4Cr-1/2Mo steel components (nozzles, etc.). This means that a material can fail by creep [refer to Section 2 §5.7.2 (i)] without the characteristic 'stretching' that normally occurs. During high temperature operation above about 455oC (850oF), the coarse grained heat affected zone has a tendency to crack at the weld fusion line. Although there is no metallurgical effect at room temperature, the fracture toughness at room temperature would be lowered proportionally to the size of the cracks that occurred at high temperature.

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Although the potential for creep embrittlement exists, it has not yet become an issue in 1-1/4Cr1/2Mo FCC components, presumably because they are not as highly stressed as low alloy steel components in other refinery plants. In other plants where creep embrittlement has been seen, use of higher purity steels or an alloy upgrade to modern high purity 2-1/4Cr-1Mo have been acceptable solutions.

5.6.5

High Temperature Creep Much equipment in a FCC Unit operates in the creep range: hot wall reactor vessels (1-1/4Cr1/2Mo), carbon steel reactor cyclones, stainless steel regenerator cyclones, feed preheater tubes, etc. Although internally insulated carbon steel reactors and regenerator shells do not operate in the creep range, creep failures can occur if the insulating refractory fails. FCC Unit creep failures can be prevented by proper equipment operation, surveillance (i.e. visual inspection for bulging and temperature surveying using infrared thermography), temperature reduction using thermal insulation, or alloy upgrades (creep limits generally increase with chromium content).

5.6.6

Thermal Fatigue In FCC Units, fatigue cracking is most prevalent in reaction mix lines, especially at miters. The source of the fatigue stress is the differential thermal growth between the reactor overhead and the fractionator inlet nozzle. A high stress is placed on the mix line each time the reactor temperature is cycled. After sufficient cycles, fatigue cracks initiate and grow.

5.7

INSPECTION/MONITORING INSPECTION/MONITORING METHODS The Inspection Summary Diagram provided in Figure 3-5 was developed to illustrate where FCC Unit corrosion and metallurgical damage mechanisms are likely to occur. Table 3-5 describes the inspection methods most successful in discovering problems. Used in conjunction, these tools provide the necessary guidance to assist in the development of more detailed inspection plans for the hot sections of the FCC Unit and offer a good quick overview of the material covered in this section. The majority of the inspections performed in the hot section of the FCC Unit occur during planned turnarounds. Of the shutdown inspections presented in Table 3-5, it is vital to assess refractory damage as near to the start of the shutdown as possible. Extensive repairs, which require curing and dry-out, can easily become critical path if not properly scheduled. It is also very important, when documenting refractory loss, to provide detailed descriptions of erosive patterns so that proper repairs, upgrades or design changes can be made. Between planned shutdowns, inspection efforts should focus particularly on the main fractionator bottoms piping system. Erosion and corrosion are common in bare alloy steel slurry systems due to the presence of catalyst fines and H2S. Inspection of this piping system for thickness on a regular planned frequency is a proactive way to prevent problems. Routine monitoring of critical process variables, primarily temperature, is also very important. Most corrosion and metallurgical damage mechanisms experienced by the FCC reactor, regenerator, main fractionator, as well as their associated piping, are highly temperature dependent. In most cases, damage worsens with temperature increases. Routine surveillance can identify when equipment is operating outside of normal parameters and prevent failures.

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Examples include monitoring critical board thermocouples (i.e. temperatures in vicinity of regenerator cyclones) in addition to regularly scheduled furnace tube and cold wall vessel/piping system infrared thermography.

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KEY

1 - Catalyst Erosion 2 - Refractory Damage 3 - High Temp Oxidation 4 - High Temp Sulfidation 5 - High Temp Carburization 6 - High Temp Creep 7 - High Temp Graphitization 8 - Sigma Phase Embrittlement o 9 - 885 F Embrittlement 10 - Creep Embrittlement 11 - Thermal Fatigue 12 - Polythionic Acid Stress Corrosion Cracking

= General / Applies to All Materials = Specific to 3xx Series Stainless Steel = Specific to Carbon / Low Alloy Steel = Specific to 4xx Series Stainless Steel

GENERIC FLUID CATALYTIC CRACKING UNIT INSPECTION SUMMARY DIAGRAM Figure 3-5

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October

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TABLE 3-5 INSPECTION & CONTROL MEASURES FOR FCCU REACTOR, REGENERATOR & MAIN FRACTIONATOR DAMAGE MECHANISMS (1) DAMAGE MECHANISM

INSPECTION (2)

LOCATION

CONTROL MEASURE

High Temperature Oxidation

Regenerator internals and flue gas system (e.g. where metal temperatures exceed 1000oF / 540oC)

Visual (use hammer test to remove oxide scales and revel damage). UT to determine remaining wall thickness.

Use a resistant alloy containing sufficient chromium (resistance improves from 5 Cr, 9 Cr to SS). Insulate the metal surfaces to keep them cool

High Temperature Sulfidation

Preheater furnace tubes, feed piping, reactor internals, reaction mix line, sections of main refractionator above 550oF (285oC), fractionator bottoms piping and pump, fractionator side cut piping and exchangers which experience a metal temperature >550oF (285oC)

Attack is quite easily found by UT or RT because rates are generally predictable and attack is quite uniform. Pay particular attention to hot areas of fractionator just beyond the 12Cr cladding.

Use a base metal or cladding/weld overlay with sufficient chromium (resistance improves from 5 Cr, 9 Cr to SS) to resist attack. Insulate the metal surfaces internally with refractory to keep them cool

High Temperature Carburization

Reactor and re-generator internals (with incomplete combustion, CO can exist above the dense phase in the regenerator)

UT to identify wall thinning.

Polythionic Acid Stress Corrosion Cracking

Regenerator internals, slide valves, refractory anchors, catalyst withdrawal lines, flue gas lines and expansion bellows constructed of 3xx Series stainless steel,

Cracking can occur online. Not normally part of routine inspection program. If detected visually, inspect other similar weld/base metal locations using PT.

Take precautions during shutdowns to prevent polythionic acid formation. Prevent water from condensing on 3xx Series stainless steel that exceeds 700oF (370oC) in service. Avoid water washing dust removal; use packed and insulated expansion joints; change to internally insulated carbon steel slide valves rather than stainless steel (or purge with nitrogen rather than steam). Use low carbon or stabilized varieties of 3xx Series stainless steel.

Catalyst Erosion

Reactor and regenerator shell and internals (especially cyclone separators); catalyst transfer lines; thermowells; slide valves; flue gas lines and coolers; and fractionator bottom pumps, heat exchangers, valves and piping

Visual for majority of equipment and internals. UT and RT thickness measurement for piping, tees, elbows, valves, reducers, pump, discharges, etc. Focus first on high velocity areas > 50 ft/s (15 m/s). Damage can be highly localized.

Design to minimize turbulence of catalyst and catalyst carryover. Use erosion resistant refractory linings and hardfacing. Use SS ferrules in inlet of flue gas coolers or fractionator bottom exchangers.

Feed Nozzle Erosion

Riser pipe downstream of the regenerated catalyst entry point and feed spray nozzles.

Visual or RT.

Design to minimize turbulence on the riser wall. Use erosion resistant materials to extend life of feed spray nozzles.

Refractory Damage

Reactor and regenerator systems, internals and associated piping (e.g. thermal cycling cracks; loss of anchors; spalling from poor installation;

Visual during shutdowns or survey cold wall equipment onstream using thermography (e.g. pyrometers or infrared analyzers) to

Proper refractory selection, application, dryout/curing, reinforcement (e.g. metal fibers) and anchoring.

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INSPECTION (2)

LOCATION

CONTROL MEASURE

insufficient dry out; coking)

identify failure of insulating refractory

High Temperature Graphitization

CS reactor cyclones; fractionator inlet nozzle and adjacent shell; and any location where the thermal insulation is damaged (e.g. reactor and regenerator internals, catalyst transfer lines) so that metal temperatures exceed 800oF/425oC (if carbon steel) and 850oF/455oC (if carbon-molybdenum steel)

RT, shear wave UT and field metallography of weldments

Use chrome-molybdenum steels rather than carbon steel or carbon-molybdenum steels for pressure containing components. Insulate the metal surface with refractory to lower metal temperatures.

Sigma Phase Embrittlement

Welded 3xx Series stainless steel regenerator internals or flue gas system components and cast 3xx Series stainless steel slide valves exposed to temperatures between 1100oF (590oC) to 1700oF (925oC).

PT for cracks of field metallography to identify presence and distribution of sigma phase.

Control ferrite content of weld metal to 3 to 10%. Exercise caution when performing maintenance work at ambient temperature. Minimize shock loading to potentially embrittled material. In the case of slide valves, move to internally-insulated carbon or low alloy steel.

885oF (475oC) Embrittlement

4xx Series stainless steels exposed to 700oF to 1000oF (370oC to 540oC). 3xx Series stainless steel weld and cast components can also experience embrittlement depending on ferritic content.

PT for cracks or field metallography to identify presence of and distribution of embrittling phase.

Do not use 4xx Series stainless steels in pressure-containing high temperature environments.

Creep Embrittlement

Highly stressed welded components constructed of C-½ Mo, 1 Cr and 1¼ Cr steels at > 850oF /455oC (e.g. nozzle welds)

PT or shear wave UT of highly stressed weldments for cracks in the base metal heat affected zone.

Creep embrittlement has not yet become an issue for 1¼ Cr components in FCCs. Specifying higher purity 1¼ Cr steel or 2¼ Cr steel are means to prevent embrittlement.

High Temperature Creep

Hot wall reactor vessels, carbon steel reactor cyclones and hangers, and stainless steel regenerator cyclones and hangers. Regenerators or cold wall reactors can experience creep if the insulating refractory fails.

Visual and PT to look for cracking and distortion in structural and pressure containing components;. Infrared thermography to check refractory integrity while on-line

Ensure actual service metal temperatures do not exceed design metal temperatures (e.g. prevent overheating). In areas which exhibit metal deformation, use stress-analysis techniques to ensure thermal expansion stresses are accounted for in design.

Thermal Fatigue

Reaction mix line; especially at miters.

Visual or PT for cracks and distortion.

Best to eliminate risk of cracking through design. Eliminate mitered joints where stresses concentrate.

(1)

CS = carbon steel; 1 Cr = 1 Cr - ½Mo alloy steel; 1¼ Cr = 1¼ Cr - ½Mo alloy steel; 2¼ Cr = 2¼ Cr -1Mo alloy steel; 5Cr = 5Cr - ½Mo alloy steel; 9Cr = 9Cr - 1Mo alloy steel, either 12% Cr (4xx Series) or 18%Cr - 8%Ni (3xx Series)

(2)

RT = Radiographic Testing, UT = Ultrasonic Testing, and PT = Dye Penetrant Testing

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6.0

CATALYTIC LIGHT ENDS RECOVERY UNIT

6.1

ABSTRACT This section reviews fundamental corrosion issues concerning the Light Ends Recovery section of a Fluid Catalytic Cracking Unit (FCCU). Cat Light-Ends Recovery (CLER) units process the material from the overhead system of the FCCU main fractionator to recover propane and heavier components and to separate light boiling fractions. This section summarizes: a description of the process, major equipment found in the CLER, types of corrosion and where they occur, corrosion control and monitoring used.

6.1.1. CLER CLER Process Description Gases from the FCCU main fractionator are condensed to allow collection and separation of light cracked naphtha and off gases. The off gases from the main fractionator reflux drum are then compressed and cooled in one or more stages. The hydrocarbon liquid condensate streams go to a stripper (deethanizer) tower while the remaining non-compressed gases are typically sent to an absorber tower. In many cases these are combined as one tower structure. The deethanizer removes fuel gas components (C1's and C2's). The absorber uses chilled condensate from the main fractionator reflux drum (wild gasoline) as lean oil to absorb remaining C3's and heavier components allowing the fuel gas components to go overhead. The resulting rich oil is combined with the stripped condensate from the deethanizer and sent to a debutanizer and depropanizer (or naphtha splitter). These towers separate these streams into propane, butane, light cracked naphtha and heavy cracked naphtha. (Figure 3-6)

6.2

MATERIALS OF OF CONSTRUCTION All components in CLER units are usually made from carbon steel. Carbon steel can be used because essentially all the hydrocarbon streams are below 150oC (300oF) and because carbon steel forms a semi-protective sulfide film when exposed to ammonia bisulfide containing sour waters. Fractionator internals are thinner and corrode from both sides, so they are typically constructed of 405 or 410(S) stainless steels. Tubes for overhead condensers and compressor aftercoolers can be admiralty brass, Monel, duplex stainless steel or titanium depending on cooling water corrosion considerations. In recent years, special Hydrogen Induced Cracking (HIC) resistant steels have been used to mitigate hydrogen induced damage concerns. Stainless steel clad equipment has also been used to remove the risk of hydrogen induced damage altogether. The purpose of the following section is to point out where problems occur in major equipment and systems, and to discuss the materials commonly used to alleviate those problems.

6.2.1. Columns Most columns (absorber, deethanizer, debutanizer, depropanizer, naphtha splitter) are constructed of carbon steel. As discussed in §4.5, the most common problem is hydrogen induced cracking and blistering due to exposure to active ammonia bisulfide and cyanide solutions. Many columns are therefore constructed of special carbon steels (HIC resistant) that

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improves the resistance to hydrogen damage. In some cases, due to the size and complexity of the columns, stainless steel cladding (typically 304L) is used. Tray internals of the columns can be carbon steel particularly in the drier back end towers. Stainless steel (400 Series) is often used in the wetter first columns to provide alkaline sour water corrosion resistance for these thinner components.

6.2.2

Exchangers The majority of exchangers in these units are either coolers, condensers or tower reboilers. Carbon steel is the material of choice for the process (usually shell) side of the coolers but the cooling water medium may dictate other needs. Given the alkaline, (NH3 or rich sour water), the use of copper based alloys (admiralty brass, aluminum brass, copper-nickels) may have a risk of corrosion or possibly ammonia stress corrosion cracking. Therefore, other water and sour water resistant alloys such as Titanium (Grades 2,12) and duplex stainless steels are often used. The carbon steel shells of these exchangers are subject to the same hydrogen induced cracking and blistering risk as are columns so HIC resistant steels or even stainless steel clad shells have been used. Reboilers are also usually all carbon steel unless dictated by the corrosivity of the tubeside heating medium (steam, hot fractionator streams). The primary problem with reboilers is the collection of upstream corrosion products in the bottom of the exchanger that cause under deposit corrosion. Some users have removed the bottom rows of tubes to allow for this.

6.2.3

Piping It is unusual to have any piping metallurgy other than carbon steel.

6.3

CORROSION PROBLEMS Corrosion is caused by a combination of aqueous hydrogen sulfide, ammonia and hydrogen cyanide (sour water corrosion). The rate of corrosion can vary extensively, depending on the concentration of the above compounds and on process specifics. The amount of H2S, NH3 and CN formed in the FCCU is usually a function of the amount of S and N in the FCCU feed. In addition, the actual operation of the FCCU reactor system (reactor temperature, extent of catalyst burn) may affect the amount formed of H2S, NH3, and CN for a given feed. In the absence of hydrogen cyanide, aqueous sulfide solutions with pH values above 8 do not generally corrode carbon steel because a protective iron sulfide film will form on the surface. This iron sulfide, however, is soft and can be disrupted by flow effects such as turbulence or very high velocities. Hydrogen cyanide, if present in significant quantity, destroys this protective FeS film and converts it into soluble ferrocyanide [Fe(CN)6-4] complexes. As a result, the now unprotected steel can corrode very rapidly. The corrosion rate depends primarily on the bisulfide ion (HS) concentration and, to a lesser extent, on the cyanide (CN) concentration. For practical purposes, the bisulfide and cyanide concentrations found in CLEF units, usually do not cause severe corrosion of carbon steel. Units with excess amounts of chlorides in the fractionator (enough to cause ammonia chloride salting) may have acidic shock condensation occur in the first condensation zone of the fractionator overhead.

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If excess NH3 is generated and the pH rises above 8 to 8.5, copper based alloys are subject to accelerated corrosion and/or ammonia stress corrosion cracking. Corrosion is also caused by the formation of soluble cyanide complexes that react with the Cu based materials. Monel has been successfully used in these services, generally since the temperatures are low enough to sustain protective sulfide scales. Cr containing materials generate more stable complex sulfide films and hence improve the resistance against sour water corrosion. For this reason various forms of stainless steels have been used subject to fabrication and cooling water considerations. At very high ammonia bisulfide levels, complexing by CN's can be a problem even for the stable Cr based sulfide scale and corrosion of stainless steel can occur. Generally the levels of ammonia bisulfide found in the CLER are not high enough to cause this. Titanium generates a very stable oxide that is virtually immune to sulfides and hence has been used particularly in conjunction with sea water cooling. Titanium, however, can become embrittled due to hydrogen generated as part of ongoing system corrosion reactions. The hydrogen reacts directly with titanium to form hydrides that reduce the toughness of the material substantially. This damage is accelerated by temperature and galvanic coupling with other metals.

6.3.1

Hydrogen Induced Damage The amount of hydrogen penetrating in ammonia bisulfide solutions into the steel is typically a function of pH. Acidic solutions will generate higher hydrogen permeation, while a neutral pH will show a decrease. Excessive pH's though above 8 will show a steady increase in permeation. Alone at typical CLEF pH's, ammonia bisulfide would generate nominal hydrogen damage potential. The HCN, disrupts the FeS scale and increases corrosion and, as a result, greatly increases the hydrogen available for damage. The effect is so great that apparent corrosion rates may still be quite low but sufficient hydrogen enters the steel to cause extensive damage. Hydrogen damage of carbon steel has caused damage to coolers, separator drums, absorber/stripper towers and overhead condenser shells. Usually, the attack occurs in interstage and high-pressure separator drums and in absorber/stripper towers. Vapor/liquid interface areas often show most of the damage, probably because ammonia, hydrogen sulfide and hydrogen cyanide concentrate in thin water films or in water droplets that collect at these areas. As a result of the extensive experience with hydrogen induced cracking (HIC) in CLER units, inspections are generally carried out to monitor for this problem. Common techniques include Wet Fluorescent Magnetic Particle inspections for surface cracking on equipment interiors and ultrasonics used to detect both subsurface blistering and cracking. Acoustic emission may be used to screen vessels for cracking activity during pressurization cycles. Blistering can be vented to prevent crack growth. Cracks can be ground out and weld repairs are performed as needed. The extent of repairs is assessed by appropriate engineering support and code requirements. Heat treatment prior to welding to bakeout absorbed atomic hydrogen to prevent further cracking during repairs is often done. Post weld heat treatment to temper hardenable welds and heat affected zones and to reduce residual stresses are also often used. In severe cases of hydrogen induced damage, equipment replacement may be required. Special carbon steels with lower S levels, inclusion shape controlling of the remaining S, normalized heat treatment and hardenability limits are often specified for this service. In some cases, the use of stainless steel cladding is specified to totally eliminate the problem by stopping the corrosion.

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More detailed information on hydrogen induced damage, inspection practices, repair techniques and construction practices have been well summarized in Section 2 §5.3.6.

6.3.2

Ammonia Stress Corrosion Cracking Admiralty or aluminum brass tubes in overhead condensers are exposed to high levels of NH3. As a result, it is not uncommon for tubes to fail as a result of ammonia stress-corrosion cracking. Admiralty metal tubes also can corrode by severe localized attack. Admiralty tubes in compressor aftercoolers have lasted only a few months on some units. For improved service life, replacement with duplex stainless steel or titanium tubes is often necessary.

6.3.3

Carbonate Stress Corrosion Cracking The FCCU generates CO2 with small amounts being carried through with the light ends into the Catalytic Light-End Recovery (CLER) unit. The CO2 is soluble in the condensing waters and can result in carbonates in the solution. A carbonate rich solution when exposed to the residual stresses usually associated with welds can cause intergranular stress corrosion cracking of the heat affected zone. This has been reported in vessels and piping in CLER. Since post weld heat treatment reduces welding residual stresses considerably, it is effective in reducing this problem.

6.3.4

Fouling/Corrosion of Reboiler Circuits It is commonly reported that reboiler exchangers accumulate upstream corrosion products. This leads to under deposit corrosion on the tube surfaces in particular. The tube surface tends to evaporate the water present and to concentrate and precipitate ionic species causing the under deposit corrosion.

6.4

CONTROL MEASURES MEASURES Certain process modifications have been found to effectively reduce or prevent corrosion and hydrogen induced damage in CLER units. These include water washing of certain process streams to dissolve and dilute corrosives (H2S, NH3, CN), polysulfide injection into wash water to lower HCN content, and corrosion inhibitor injection. While these measures are useful in reducing blistering, none of these measures will significantly reduce or prevent stress cracking of hard welds and heat affected zones. High strength bolting, used typically in floating head covers of exchangers, will also be susceptible to stress cracking. The hard welds and heat affected zones must be addressed and minimized during fabrication. The bolting problems can be minimized by using lower strength bolts but they may be a problem to maintenance in tightening up to set gaskets.

6.4.1

Water Washing Considering extensive field experience, continuous water washing of sour gas/vapor streams can be an important method of controlling corrosion and hydrogen entry into steel. Water washing can be done by contacting the gas/vapor with water in a scrubbing tower, or injecting the water directly into process piping. The most efficient method of contacting the gas is a scrubbing vessel. However, many plants use a combination of large water volume rates and a distribution nozzle to wash the gas in-line. Water washing primarily dilutes the concentration of NH3 and HCN in process water. The greatest benefits of water washing are seen in the high-pressure

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section where the partial pressures and hence, the concentration of dissolved NH3 and HCN are highest. Water is generally injected into the main fractionator overhead, upstream of intermediate compression stage coolers and/or upstream of the final compression stage coolers. It is important that the process water, including wash water, not be returned from the highpressure section to the main fractionator reflux drum at the FCCU prior to disposal. This would cause H2S, NH3 and HCN to flash off as the pressure was reduced at the reflux drum and cause their concentration to build up in the compression loop. It is also important that carry-over of corrosive water into downstream equipment be minimized. This means that sufficient cooling capacity needs to be provided for compressor aftercoolers to maintain separator drum temperatures as low as possible. On some units, additional drum capacity may be needed, along with water draw facilities for certain fractionator towers. Wash water should be injected through a Type 304 or 316 stainless steel distributor or quill that is located at the center of the piping. There should be at least 15 ft (4.6 m) of piping downstream of the injection point to ensure proper mixing ahead of coolers and condensers. The same applies to piping bends, elbows and tees that otherwise would experience impingement attack. Where parallel heat exchanger banks are being washed, care must be taken to ensure even water distribution either with balanced piping or individual controlled injections into each bank of exchangers. Only high quality water, with a low solids content, should be used. Water quality should be balanced against availability and cost. Typical water sources are one or more of the following, listed in order of increasing cost: • • • •

Sour Water Condensate (pH 6 to 8.5) Stripped Sour Water Boiler Feeder Water Demineralized Water, Steam Condensate or Steam

If water washing is to be combined with polysulfide injection, alkaline sour water is preferred. The wash water pH should then be 8. It is common to cascade waters from the main fractionator through the intercoolers and the aftercoolers. Since the water is pumped to higher pressures it can absorb more of the corrodents while at the same time minimizing the net quantity of sour water made. The amount of wash water depends on the gas/vapor flow rate, the amount of water vapor present, and the amount and type of corrosives present. Ideally, the amount of wash water should be the minimum needed to meet one or more of the following typical criteria, listed in order of decreasing importance: • • •

HCN content of all water draws less than 20 to 25 ppm by weight pH value of all water draws between 6.2 and 8·5 76 l/m (20 gpm) or 1545 kg/h (10,000 lb/hr) per MSCF/SD of vapors from the top of the main fractionator of the FCCU.

Depending on the system, several different types of wash water may have to be injected to meet these criteria. For example, a slightly acidic sour water stream may be required to depress pH values. Polysulfide may have to be added to the wash water to decrease HCN levels.

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6.4.2

October 1999

Polysulfide Injection Continuous injection of polysulfide solution into the wash water lowers the HCN content of sour water condensate by forming harmless thiocyanates (SCN). Polysulfide also reacts with sulfide corrosion products to produce a more protective film on steel surfaces. Polysulfide injection should be considered if water washing by itself does not decrease the HCN content below the recommended 20 to 25 ppm by weight. While several types of polysulfide solutions are available, most refiners prefer to use commercial 55% by weight ammonium polysulfide ([NH4]2Sx) solution containing 35% by weight polysulfide sulfur. Sodium polysulfide solution is not recommended because it increases the pH of sour water condensate and reacts more slowly with HCN in comparison to ammonium polysulfide. It is also considerably more expensive than ammonium polysulfide solution. Polysulfide solution should be stored and handled in carbon steel equipment. To avoid sulfur deposition, the solution should be diluted by a factor of ten with a slipstream of alkaline sour water. The diluted polysulfide solution is then injected into the various wash water streams, using a simple T-connection. As a rule, the injection rate is designed so that the amount of polysulfide sulfur added is 50 percent more than the stoichiometric amount required for conversion of CN to SCN. Actual injection rates are adjusted to ensure some excess polysulfide that is usually monitored by observing the color of the condensed waters. A straw yellow color indicates excess polysulfide. The actual amount of free HCN and thiocyanates (with a target to reach the free HCN of 20 to 25 wppm) can also be measured. Most analytical techniques though, tend to be either inaccurate or imprecise.

6.4.3

Corrosion Inhibitors Commercial film-forming amines have reduced hydrogen blistering of steel provided the inhibitor concentration was sufficiently high. In practice, this means at least 30 ppm by volume versus the normal 10 ppm. For this reason, inhibitor injection is relatively uneconomic and recommended only for problem areas and short-term protection until other measures, such as water washing or polysulfide injection, can be implemented.

6.4.4

Corrosion Monitoring Hydrogen-activity probes and periodic chemical tests are recommended for monitoring the effectiveness of corrosion control measures. Hydrogen-activity probes use a pressure gauge to measure the amount of hydrogen that has diffused through a tubular carbon steel specimen. Recommended key locations for hydrogen-activity probes include different elevations of the absorber/stripper tower, and the vapor/liquid interface area of the high-pressure separator drum. To avoid faulty readings due to leaks, hydrogen-activity probes must be pressure-tested with hydrogen or helium gas and a residual pressure of hydrogen gas should be maintained in the probes at all times. Changes in pressure due to hydrogen activity are of greater interest than the actual pressure itself. To facilitate reading and adjusting, pressure gauges and bleed-off valves of elevated probes may be kept at ground level and connected to the probes by stainless steel capillary tubing. Depending on the sensitivity of the hydrogen-activity probes used, increases in reading of less than 1 to 2 psig/day indicate satisfactory control. Other hydrogen activity measurement techniques are also available. For example, a sealed patch can be mounted on the exterior surface of the equipment item in areas of suspected high hydrogen rates. The hydrogen passes through the steel wall and is collected within a sealed patch. Measurement of the hydrogen build-up can be by various means including vacuum loss or by reactions with solid state or wet chemistry detectors.

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Chemical tests for cyanide and thiocyanate content of waste-water streams should be carried out to determine if any changes occur due to feed and operations change. They can also be used to monitor water wash and polysulfide injection systems. As indicated above, the actual chemistry analysis may be a difficult technique and care must be taken to account for air exposure to obtain consistent results. Air will convert ever-present sulfides to polysulfides and then gradually convert CN to thiocyanates. As a result, particularly in polysulfide injected systems, the color monitoring on a shift or daily basis is a simple sampling test often used. Water pH sampled from high pressure condensates is also commonly used to monitor water wash rates as indicated above. Care must also be taken since H2S and NH3 will flash off when depressurized and affect the pH readings. Samples should be collected in pressurized sample bombs to obtain meaningful results.

6.4.5

Corrosion Probes Corrosion probes can be used to monitor ongoing corrosion in CLER units. The probes are especially useful for monitoring high pH corrosion when Cu-based alloys are used in condenser/cooler bundles.

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GAS COMPRESSION

Low Pressure Water Wash

Water Wash

PRIMARY FRACTIONATOR

High Pressure Water Wash

ABSORBER DEETHANIZER DEBUTANIZER

To Fuel Gas

NAPHTHA SPLITTER

Lean Oil

DISTILLATE TO TREATING

LCN TO CATALYTIC REFORMING

HCN TO BLENDING SOUR WATER TO RECYCLE OR DISPOSAL

C3 / C4 PRODUCT TO POLY OR CHEM PLANT

LEGEND

H P

Hydrogen Probe Location

Corrosion Probe Location

CATALYTIC CRACKING LIGHT ENDS RECOVERY UNITS Figure 3-6

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7.0

October 1999

CATALYTIC REFORMING REFORMING UNIT Catalytic reforming is a process that employs a platinum plus other usually noble metal chloride activated catalyst. The catalyst converts low quality naphtha in the presence of hydrogen into high grade motor fuel or aviation gasoline blending stocks. Reforming also produces an aromatic rich feed stock for extraction and excess hydrogen. The noble metal catalyst is sensitive to lead from rerun leaded gasoline, sulfur and nitrogen. As a result, the feed is hydrotreated to minimize sulfur and nitrogen. The hydrotreating is run at roughly 371oC (700oF) and at pressures from 150-900 psi, depending on the unit design. Typically, the older catalytic reformer units were built when the motor fuel demand was rapidly increasing. Higher octane motor fuels were required by the higher horsepower automobiles. The old units were designed to run at roughly 482o-524oC (900o-975oF) end of run and in the 500 psi pressure range. Newly designed catalytic reformers may run 538o-543oC (1000o-1010oF) at a total pressure of 150 psi because of better catalysts and a changing product demand. UOP, IFP, and Chevron used a semiregenerative radial downflow fixed bed, three or four reactor in series system. The reactors are regenerated when activity decreases significantly because of accumulated carbon blocking the active catalyst sites. The regeneration essentially burns off the carbon and the catalyst is reactivated with chloride. Exxon and Amoco used a swing reactor when the online reactors began to loose activity so that the required number of reactors was onstream to keep the throughput up. UOP then introduced a continuous regeneration stacked reactor unit that regenerated a slipstream of catalyst and returned it to the reactor stack. This setup allowed the operators to run the unit at high activity producing maximum octane without having to shutdown and regenerate. A typical catalytic reformer may contain a feed pretreat section such as an oxygen stripper to remove oxygen from stored feed, a reaction section that includes feed/effluent exchange, charge and intermediate furnaces, reactors, interconnecting piping, an effluent cooling system and a product separator. In addition, there is a fractionation section and a recycle gas compression section. The excess hydrogen is sent to the refinery hydrogen system for use in hydroprocessing units.

7.1

CORROSION The early units used a more sulfur tolerant catalyst and, in fact, some had no upstream hydrotreater. The result was significant H2/H2S corrosion on the 1-1/4Cr-1/2Mo, 2-1/4Cr-1Mo and C-1/2Mo piping, exchangers, furnace tubes and reactors. These units suffered high metal losses and rapidly plugged the fixed bed reactors with sulfide scale. After hydrotreating was added upstream, the major catalytic reformer materials problem was High Temperature Hydrogen Attack (HTHA). The alloys that were used were C-1/2Mo, 1-1/4Cr-1/2Mo, and 21/4Cr-1Mo. The early reformers had considerable problems with chloride being stripped off the catalyst and causing corrosion anywhere downstream of the reactors where water condensed out. The loss of chloride caused some catalyst activity problems that could be solved by rechloriding the catalyst onstream. Enough chloride was in the system that some refiners found it necessary to change out some carbon steel piping in areas and replace it with Monel. After several years, the operation was improved and chloride corrosion problems were minimized. For several years, the refiners had no chloride corrosion problems until the continuous units began to operate. Because the new units require continuous chloriding to keep the catalyst activity high, there is considerable chloride in the system to cause corrosion.

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7.2

October 1999

MATERIALS The reactor section of the catalytic reformers has hydrogen up to about 536oC (1000oF) and partial pressures up to about 28 kg/cm2 (400 psi). The hydrogen attack situation has dictated use of 1-1/4Cr-1/2Mo for the hotter areas of the reactor section. The older units used both hot shell and cold shell reactor designs. The new continuous units use stacked hot shell reactors. Some of the early hot shell reactors were 1Cr-1/2Mo. At end of run conditions, some of these reactors were marginally over the "API 941" curve for the material. Considerable inspection effort by UT and surface inplace metallography has, in general, found no attack other than some decarburization. It is difficult to tell whether the decarburization was due to hydrogen attack or was a result of heating during fabrication. Blistering on shell and/or head plates has been fairly common. It does not seem to be hydrogen attack but from hydrogen diffusing through the wall, recombining and building up pressure at inclusions in this older normally fairly dirty steel. Later hot shell reactors have been made from 1-1/4Cr-1/2Mo until the creep embrittlement problems became fairly common. The replacement reactors have been low impurity 1-1/4Cr-1/2Mo or low impurity 2-1/4Cr-1Mo. The 2-1/4Cr-1Mo tends to have considerably better rupture ductility. Recently there have been a few instances of hydrogen attack on 1-1/4Cr-1/2Mo reported to the API 941 Panel. The cold shell reactors are refractory lined with an internal stainless steel shroud. A least part of the nozzles are 1-1/4Cr-1/2Mo or higher alloy for hydrogen attack resistance. The shells have been C-1/2Mo or carbon steel depending on the specific refiners safety factor in case of gas bypassing or refractory problems producing hot spots. A typical problem area that causes bypassing and hot spots is at the shroud to nozzle tie in. Many of the earlier units used considerable C-1/2Mo for hydrogen attack resistance. Numerous failures have resulted in the recommendation not to use C-1/2Mo. The problem appears to be due to the formation of attack prone carbides during steel processing and/or fabrication. Hydrogen attack on C-1/2Mo can be very spotty and difficult to find. Some advanced UT methods, such as velocity ratio/backscatter combination, seem to work fairly well but are slow and, therefore, expensive. The C-1/2Mo situation continues to be a major industry problem since there is considerable equipment in service and the replacement cost is very high. Some refiners have replaced piping in high risk (of hydrogen attack) areas because it is cheaper to replace than to inspect. In general, this does not hold true for exchangers and vessels. The rest of the unit, outside the reaction section, is generally carbon steel. The major problem has been migrating chlorides throughout the effluent and fractionation section. Some of the newer continuous units use chloride traps on both the liquid and gas streams to minimize downstream equipment chloride corrosion problems. The charge and intermediate furnaces have typically used 2-1/4Cr-1Mo tubes with years of successful service. Many of the furnaces are low pressure drop parallel pass designs. Typical problems have been an occasional ruptured tube due to a low flow, hot spots during startup or an occasional burner problem. When the continuous units became popular, the tube material was changed to 9Cr-1Mo to give some added oxidation resistance and therefore allow a higher limiting skin temperature. As the skin temperatures went from the 593o-621oC (1100o -1150 oF) range to 621o-649oC (1150 o -1200 oF), the 9Cr-1Mo tubes began to have carburizing problems that the lower alloy tubes operating at somewhat lower temperature did not have. The carburization has made the 9Cr-1Mo tubes very sensitive to low flow/startup problems and has resulted in a number of tube failures. Some of the failures have been primarily operational but others have been due to some complex carburization and even in some cases metal dusting problems.

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If the refinery cooling water system requires copper based alloys, like aluminum brass or admiralty, they may be very vulnerable to ammonia stress corrosion cracking and must be thoroughly water washed before the bundles are pulled or exposed to air. The Cu-Ni alloys are not susceptible to ammonia stress corrosion cracking and have worked for many years as effluent coolers and or trim coolers. Most modern units use carbon steel air fans instead of shell and tube condensers/coolers. There may be some risk of hydrogen embrittlement of hardened compressor parts due to ammonium chloride or iron chloride exposure. Some refiners use the same restrictions as for wet sulfide. Keep the hardness below HRc22 and the tensile strength below 90 ksi (620 mPa). Compressor cracking problems did occur in the early units when migrating chlorides were a problem. Based on that experience, it would seem prudent to apply the same groundrules to the new continuous units. With the semi-regenerative units, a major problem is controlling the corrosion that occurs during regeneration. Very specific procedures have been written to minimize these corrosion problems by proper neutralization. The other more recent problem with the semi-regenerative units is the need to regenerate frequently in order to keep octane up in competion with the continuous units. The quick carbon laydown and subsequent carbon burning can cause serious internal distress and result in operational problems and possible long downtime replacing the internals.

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NET HYDROGEN

CW GAS HYDROGEN RECYCLE COMPRESSOR 250 to 500 psig

350 to 650 psig

100 Fo

o

925 to o 975 F

925 too 975 Fo

925 too 975 Fo

STEAM OR HOT OIL

o

100 F

CW CW

HEATERS AND REACTORS

REFORMATE

HYDROGEN SEPARATOR STABILIZER

NAPHTHA CHARGE

SEMI-REGENERATIVE CATALYTIC REFORMING UNIT Figure 3-7

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October 1999

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8.0

October 1999

HYDROPROCESSING UNITS CORROSION IN HYDROPROCESSING UNITS

8.1

ABSTRACT This section contains an overview of hydroprocessing unit design and operations followed by descriptions of the corrosion mechanisms and other materials degradation problems associated with these processes. The mechanisms include high temperature hydrogen attack, high temperature H2S corrosion, stress corrosion cracking by chlorides, sulfur acids, and sulfides, aqueous corrosion by ammonium bisulfide and others. For each mechanism, a description of the conditions causing or accelerating attack, the locations within the unit where attack may occur, and the methods of prevention are discussed. A walk-through of a materials selection guide is also given.

8.2

INTRODUCTION INTRODUCTION Hydroprocessing units are used in a refinery to upgrade hydrocarbon feedstocks by removing undesirable constituents and/or converting heavier feeds into more valuable, lighter products. The feedstocks range from naphtha to vacuum residuum. The reactions occur under a hydrogenrich environment at elevated temperatures and high pressures, in the presence of catalysts. Types of hydroprocessing units and their primary purposes are: • • • •

Hydrotreaters including hydrodesulfurizers - remove sulfur and/or nitrogen Hydrocrackers - crack heavier feeds into lower boiling point products Hydrogenators - add hydrogen to unsaturated or other hydrogen-deficient hydrocarbons Hydrofiners - remove color bodies

The chemical reactions which accomplish these objectives all occur more or less simultaneously, but processing conditions are varied somewhat, in order to maximum the rate of the primarily desired reaction. Some units consist of two stages with the first stage completing the hydrotreating reactions and the second stage doing the hydrogenation and cracking. From the corrosion viewpoint, the important distinction between these stages, is that the feed to a hydrotreater contains appreciable amount of sulfur and nitrogen while the feed to the second stage hydrocracking section may not. Sulfur and nitrogen react with hydrogen to form hydrogen sulfide and ammonia within a hydrotreater reactor system. These compounds have a significant effect on corrosion and materials selection regardless of whether the hydrotreater is a separate plant, the first stage of a two-stage hydroprocessing unit, or a single-stage hydrocracker. Since sulfur, nitrogen and ammonia typically reduce the activity of second stage catalyst, most are removed in the hydrotreating stage. Hence, there are fewer corrosion considerations and less upgraded materials in second stage hydrocrackers compared to first stages or single stage designs. Single stage hydrocrackers are a high pressure operation that not only hydrotreats, but also converts heavier hydrocarbons into lighter products and hydrogenates the converted hydrocarbons.

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8.3

October 1999

PROCESS DESCRIPTIONS DESCRIPTIONS A simplified flow diagram of one type of a typical hydrotreater is shown in Figure 3-8 Page 1. The reactor contains catalyst(s) and typically operates between 42 to 141 kg/cm2 (800 to 2000 psi) and 371 o to 454 oC (700 oF to 850 oF). Hydrogen is injected into the feed which is heated in feed/effluent exchangers and a furnace. In the reactor(s), sulfur and nitrogen compounds are converted to hydrogen sulfide and ammonia. The reactor effluent is cooled through various heat exchangers and typically one or more air coolers, and then is sent to the separator vessels. Water is typically injected for fouling/corrosion control upstream of the air coolers. The gas phase from the separators consists primarily of hydrogen with some very light hydrocarbons and a high percentage of the H2S generated in the reactors. Gas from the separator is recycled back to the feed through a compressor, with some make-up hydrogen also being added. The liquid hydrocarbon phase from the separators is sent through pressure letdown valves to the fractionation section of the unit. The water phase from the separators contains almost all of the ammonia formed in the reactors. The dissolved H2S in this water combines with the NH3 to form ammonium bisulfide (NH4HS) as well as inorganic salts,. such as ammonium chloride. Traces of cyanide may also be present. In a single stage Hydrocracking Unit (see Figure 3-8 page 2), the feed is mixed with hydrogen, heated, and passed through catalyst-filled reactors. The reactor effluent is cooled, the gas phase (consisting mostly of hydrogen) is recycled back to the feed, and the liquid hydrocarbon phase is sent to the distillation section. Typically, reactor pressures are between 106 to 211 kg/cm2 (1500 to 3000 psi) and temperatures are from 343oC to 454oC (650oF to 850oF). There are several common variations in flow scheme. In some vacuum resid desulfurizers, the reactor effluent enters the separator vessels directly from the reactor with only a small amount of prior cooling. Hot vapor and liquid streams are separated and individually cooled. Another common process variant is that some units use a high pressure amine absorber to remove H2S from the recycle hydrogen stream while others units do not. Distillation systems can vary substantially in flow scheme. Some units have an H2S stripper column before the fractionator. The essential differences in configuration that influence corrosion will be discussed later.

8.4

MATERIALS SELECTION SELECTION

8.4.1

Reactor System The materials of construction used in the reactor system of a hydrotreater, single stage hydrocracker or the first stage of a two stage unit must be resistant to the following forms of corrosion damage: • • • • •

High temperature hydrogen attack High temperature H2-H2S corrosion Aqueous corrosion by ammonium bisulfide Stress corrosion cracking by chorides, sulfur acids or sulfides Naphthenic acid corrosion (if feed has a high neutralization number)

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8.4.2

October 1999

Reactor Feed System Up to the point of recycle hydrogen addition, the hydrocarbon feed to the plant is generally noncorrosive to carbon steel, except when the feed contains H2S at >260oC (500oF) or naphthenic acid at >232oC (450oF). In those cases where the plant feed is corrosive because of high temperature and dissolved H2S, corrosion can be minimized by using alloys containing 5% chrome or better. Naphthenic acids may necessitate the use of Type 316 or 316L. After the point of recycle hydrogen addition, progressively higher alloys are required as the stock is heated. This is to resist both hydrogen attack and high temperature H2/H2S corrosion. The threshold temperature for H2/H2S corrosion depends on the amount of H2S introduced with the recycle gas, but in most plants it is on the order of 232oC (500oF). Above this temperature, austenitic stainless steels are typically used for piping and exchangers to provide corrosion resistance. Hot piping is commonly constructed of Type 321 as Type 347 piping is more costly, generally less available, and somewhat more difficult to weld than Type 321. Exchanger bundles are typically Type 321 and the shells and channel sections are clad with Type 321 or Type 347. However, Type 347 is normally used for cladding or weld overlay on thick-walled components. Hydrogen attack becomes a materials consideration in the reactor feed system when above about 232oC (450oF). Above this temperature threshold, carbon steel cannot be used, even as base metal on stainless steel clad components. Although stainless steels are immune to hydrogen attack under plant conditions, hydrogen can diffuse through stainless cladding to attack the base metal. Based on these considerations, the reactor feed system is normally built of carbon steel where temperatures are below about 232oC (450oF). Above this temperature, piping will generally be Type 321 steel to prevent H2/H2S corrosion, and exchanger channel sections and shells will be stainless clad with 1 1/4Cr-1/2Mo or 2 1/4Cr-1Mo base metal used as needed for protection from hydrogen attack. The role of corrosion products in plugging catalyst and reducing run lengths may also provide economic justification for upgrading alloys in feed exchangers, piping and furnace tubes. Even acceptable corrosion rates can generate large volumes of corrosion products. Corrosion products can be a cause of plugging in downflow reactors, but rarely cause problems with radial flow reactors. Heater tubes and return bends are commonly constructed of Type 347 stainless steel, although Type 321 has also been used. Return bends should be wrought rather than cast, both to obtain superior quality and because castings tend to develop sigma embrittlement above 538oC (1000oF).

8.4.3

Reactors Reactors are constructed of low alloy steel for hydrogen attack reasons and are protected against H2/H2S corrosion by austenitic stainless steel roll-bond cladding or weld overlays. The most common base metal for reactors is 2 1/4Cr-1Mo although 3Cr-1Mo has also been used. Alloys lower than 2 1/4Cr-1Mo are occasionally used when temperature and hydrogen partial pressure permit. Reactor internals are constructed of an austenitic stainless steel, typically Type 321 or 347. Aluminizing or aluminum diffusion coatings are sometimes specified for catalyst support screens

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October 1999

to help prevent corrosion which could result in plugging from scales. Aluminum is essentially immune to H2S corrosion.

8.4.4

Reactor Effluent System In the reactor effluent system, from reactor to the reactor effluent/stripper feed exchanger, materials selection is based on the same criteria as in the reactor feed system. Stainless steels should be used for corrosion protection until the stock is cooled below the threshold for high temperature H2/H2S corrosion [about 232oC (450oF)]. Alloys resistant to hydrogen attack must be used down to about the same temperature. The exact threshold temperatures for H2/H2S corrosion and hydrogen attack vary somewhat as a function of the partial pressures of H2S and hydrogen. On surfaces such as exchanger tubes and tube sheets which are exposed to two-side attack, the conditions existing on both sides must be considered. From the reactor outlet temperature down to about 232oC (450oF) (the H2/H2S corrosion threshold), piping and exchanger bundles are generally Type 321 and exchanger shells are Type 321 or Type 347 clad. Base metals used for exchanger shells may again be 2 1/4Cr-1Mo or 1-1/4 Cr-1/2Mo, depending on the alloy content required to provide resistance to hydrogen attack. Below the 232oC (450oF) hydrogen attack threshold, carbon steel is generally used.

8.4.5

Reactor Effluent - Distillation Feed Exchangers Many, but not all plants, use an exchanger that cools the reactor effluent stream by exchanging it with the separator liquid on its way to the first distillation column after the reactor system. Such exchangers pose special corrosion problems. One problem is entrainment of small quantities of salt-containing water in the separator liquid. As this stock is heated, the water evaporates, leaving salt deposits on the tubes. Carbon steel tubes may corrode in the presence of these deposits. Tube life is highly variable, depending primarily on temperature and the amount of salt entrained into the exchanger. Chrome-moly steels perform no better than carbon steel in this instance. Austenitic stainless steels are likely to fail by chloride stress corrosion cracking or underdeposit ammonium chloride pitting. In general, austenitic stainless steel tubes should not be used in this exchanger except in existing plants where good performance has been proven. This results in the materials selection for these tubes being a choice between carbon steel and very expensive alloys such as Alloy 825, AL6XN or Alloy 625. For new plant construction, carbon steel is generally specified. The exception is when reactor effluent-side temperatures are so high that a better alloy is required to resist high temperature H2S corrosion. Under these conditions and for replacement of existing exchanger bundles where carbon steel shows inadequate life, an alloy with very high resistance to chloride corrosion and SCC should be used.

8.4.6

Effluent Air Coolers This is probably the piece of equipment most vulnerable to ammonium bisulfide corrosion. Most plants initially install carbon steel tubes for effluent air coolers, however, some units with high Kp values have installed duplex stainless steel or Alloy 800 or 825. In other cases, carbon steel has experienced corrosion failures due to excessive velocities, oxygen in the injection water, maldistribution of flow or other causes. Where such problems have occurred and tube materials have been upgraded, Monel, Alloy 800 or 825 have been used for tube replacement. The Alloy 800 series provide resistance to high concentrations of ammonium bisulfide. However, in recent years, there have been cases of polythionic SCC of Alloy 800 piping and equipment.

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Alloy 825 is stabilized and contains molybdenum and, hence, has superior resistance to polythionic and chloride SCC, as well as NH4HS corrosion. It is generally the preferred alloy over Alloy 800. However, if due to cost or availability, Alloy 800 is selected, care should be exercised to avoid purchasing high carbon, coarse grain material to minimize sensitization during fabrication and welding. Current experience indicates that fine grained material may be impossible to obtain. Duplex stainless steels such as Type 2205 are increasing in use for tubes and header boxes. Numerous special requirements should be imposed on the materials and fabrication and welding practices. Welds or heat affected zones that do not have the proper ratio of austenite/ferrite in their microstructure can be susceptible to hydrogen embrittlement and SSC. Both positive and negative experiences, with regards to obtaining acceptable fabrications have been reported. Although they should have good NH4HS corrosion resistance, austenitic stainless steel tubes have seldom been used in this service due to the risk of chloride stress corrosion cracking. In the past, several companies have used Type 410 or Type 430 stainless steel tubes in effluent air coolers but failures have occurred by isolated pitting. Alloy 400 (Monel) has been used successfully for a few air coolers in the past, but may not be suitable for units with high levels of NH4HS. In some plants, effluent air coolers have been constructed with stainless steel ferrules at both inlet and outlet ends of the steel tubes. This provides increased protection against tube end erosioncorrosion. Ferrules have also been installed with good results in existing steel air coolers where tube end attack had occurred. When ferrules are used, the ends of the ferrules must be tapered to provide a smooth flow transition. Carbon steel header boxes may also experience corrosion if velocities or turbulence are excessive. Industry experience indicates that the majority of those effluent air coolers experiencing tube corrosion will also suffer attack on header boxes. For this reason, alloy header boxes should be used with alloy tubes. Although ammonium bisulfide corrosion is the major concern, failures can also occur from NH4Cl corrosion. Units with two air coolers in series, with the water injection downstream of the first air cooler, may experience NH4Cl deposition and pitting at the outlet ends of the first air cooler. This generally occurs when the air cooler's outlet temperature is relatively low. NH4Cl sublimes at temperatures above the NH4HS sublimation temperature. The deposits are hygroscopic and often provide enough cooling of the metal to result in water condensation and acid formation beneath the deposit. No practical materials upgrade will resist this problem, hence, it is usually avoided by raising the process temperature.

8.4.7

Effluent Air Cooler Inlet Inlet and Outlet Piping The piping upstream (from the water injection point) and downstream of the effluent air cooler is often subject to the same NH4HS erosion-corrosion problem as the air cooler. Corrosion is typified by highly localized metal loss at bends, tees and other points of local turbulence. Such corrosion is most likely to occur when the process fluid is high in NH4HS concentration and where fluid velocities are high. Carbon steel piping should be designed with a 6 m/s (20 ft/s) maximum limit. Special attention must be given to areas downstream of any injection lines or even small branch connections in this service. When new units are predicted to be extremely corrosive, when high reliability is desired, when periodic rigorous inspection is considered difficult or uneconomical, or when corrosion occurs in existing plants, alloy piping is often installed. Alloy 800, Alloy 825, Type 316L [for application below 60oC (140oF)], Alloy 20 and Alloy 2205 have been used. SCC failures have occurred on

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Alloy 800 when it was supplied with high carbon contents and large grain sizes as discussed in §8.5.6. The upper velocity limit for alloy piping can be raised to 9 m/s (30 ft/s). When carbon steel is used, it generally has a high corrosion allowance of 6.4 mm (1/4 in). Balanced inlet and outlet piping is also typically specified. NH4HS corrosion can also occur downstream of the separators in lines handling wet hydrocarbons or foul water and in other piping where the process fluid contains appreciable quantities of H2S and ammonia, and any quantity of liquid water. For example, lines handling separator vapor could corrode if the vapor were further cooled to condense out additional water. In many but not all plants, the wet, sour process fluids which are present downstream of the effluent air cooler are capable of causing rapid SSC of high strength steels. Valve stems and trim are the components most likely to suffer damage. In new plant construction, Type 316 trim is typically specified for services where SSC appears likely to occur.

8.4.8

Separator Vessels Except for units operating with greater than 10% NH4HS, separator vessels normally have very low corrosion rates. The major concern is that the incoming process fluid may impinge on the shell or heads, causing localized NH4HS corrosion at that point. Typically, installing a stainless steel impingement baffle or wear plate of adequate size to shield the entire impingement area avoids the problem. The only major exception is the hot separator in a hydrotreater designs where the first separator operates at or near the full reactor outlet temperature. Accordingly, stainless-clad construction is used to provide resistance to high temperature H2/H2S corrosion. The base metal is chosen to resist hydrogen attack at operating temperature. Cold separators containing sour water may be subject to severe HIC and SOHIC. On recent units, these vessels have been built of HIC resistant steel or entirely clad with a 300 series stainless steel.

8.4.9

Recycle Hydrogen System Significant corrosion is seldom encountered in this part of the system. The only potentially serious materials problem is SSC of the recycle gas compressor, as it typically contains materials like 4330 or 4140 steel, which can be susceptible to SSC if too strong or too hard. To avoid this problem, it is common practice to limit the strength and hardness of compressor materials. However, for additional protection against SSC, precautions should be taken to keep the compressor dry by methods such as maintaining the mist eliminator in the compressor knock out drum in good condition and by steam-tracing the compressor suction line from the knock out drum. Keeping the system dry also protects against NH4HS erosion-corrosion. Valve trim is also typically 316.

8.4.10 Distillation Section Construction materials used in the distillation section are chosen on the basis of the need to resist high temperature H2S corrosion. Where H2S is present at temperatures above 232oC to 316oC (500oF to 600oF) (depending on H2S concentration), alloy is required. Where H2S is absent, or where temperatures are below 232oC (500oF), carbon steel is generally adequate. Where the temperature exceeds 316oC (600oF), corrosion may occur at H2S levels as low as 1 ppm.

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If the transfer line temperature were as high as to 316oC (600oF), carbon steel would be expected to corrode rapidly in the transfer line and column flash zone. A new plant designed for such conditions would use 5 Cr for the transfer line and 12 Cr cladding in the flash zone of the column. If the transfer line temperature were well over 316oC (600oF), furnace tube corrosion could occur even on 5 Cr. It would then be necessary to use 9 Cr or Type 321 tubes, depending on the H2S content of the stock, the stock temperature and fumace design. 12 Cr tubes are not recommended because they cannot be readily welded and have embrittlement problems when used as pressure parts. In the bottom half of many fractionator columns, corrosion of carbon steel is often minimal despite the high temperature because H2S has been stripped out of the hydrocarbon. The same is true for the fractionator column reboiler. The key factors are the H2S content of the bottoms and effectiveness of H2S stripping. At temperatures over 316oC (600oF), corrosion of carbon steel can occur if the H2S content exceeds about 1 ppm. Under these conditions, corrosion of carbon steel could occur in the bottom of the fractionator column, the reboiler, the bottoms line to the splitter and the flash zone of the splitter column. Corrosion would not be expected in the bottom of the splitter column or in its reboiler because H2S should be stripped out. Aside from the possibility of high temperature H2S corrosion, the only other corrosion concern is in the overhead of the distillation column. Overhead condensers and drums exposed to both water and H2S may experience moderate corrosion, but this is rarely a serious problem and may be further controlled by injection of a filming amine inhibitor. In the overhead systems, many refiners may apply materials and fabrication controls to minimize wet H2S cracking, however, HIC steels are not typically used in this location.

8.5

CORROSION PHENOMENA PHENOMENA IN HYDROPROCESSING UNITS

8.5.1

High Temperature Hydrogen Attack Hydrogen at >232oC (>450oF) and partial pressures >7 kg/cm2 (>100 psi) can cause hydrogen attack of carbon and low alloy steels. It results in decarburization which weakens the metal. In addition, methane forms at the interstices and builds up internal pressure which induces fissuring, blistering and possible failure. Alloying with chromium and molybdenum reduces the degree of attack because of their strong carbide-forming characteristics. All hydroprocessing units involve the use of hot, high pressure hydrogen in the reactor systems. Therefore, it is essential to use construction materials which are resistant to hydrogen attack at the operating conditions. Hydrogen attack is not a consideration in the distillation systems, since hydrogen partial pressures are very low. API 941, "Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants", contains operating limits for steels in hydrogen service. The API 941 curves are also referred to as the "Nelson Curves" as they were originally developed by G.A. Nelson. The axes are hydrogen partial pressures and operating temperature and the area below a given material's curve is considered acceptable operating conditions for that material. The common upgrades for cases when carbon steel is not acceptable, are 1 1/4 Cr-1/2 Mo and 2 1/4 Cr-l Mo alloys. Historically, many oil companies apply a 28oC (50oF) safety factor when using these curves to select materials (except for reactors, for which a 14oC (25oF) safety factor is typically used).

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C-1/2 Mo was commonly used for equipment and piping in the past, but due to failures at conditions where it had been predicted to be acceptable, it is no longer used for new construction in hydrogen service. Its design curve has been removed from the Fourth Edition of API 941 which recommends rigorous inspection of existing C-1/2Mo equipment. A new Fifth Edition of API 941 was published in January, 1997. Hydrogen can diffuse through overlays and attack the underlying base material, so regardless of the type of overlay, the base material should satisfy the API 941 requirements for the operating conditions. (Refer to Section 2 §5.4)

8.5.2

High Temperature Hydrogen Sulfide / Hydrogen Corrosion Hydrotreater feedstocks typically contain sulfur compounds, such as mercaptans, sulfides, disulfides, thiophenes and others. Under the reactor conditions, most of these compounds are converted to hydrogen sulfide (H2S). H2S reacts with metals at high temperatures >232oC (450oF) by direct sulfidation. The presence of hydrogen typically increases H2S corrosion rates on carbon steel and low alloy steels. Areas of hydroprocessing units susceptible to H2-H2S corrosion are the reactor feed downstream of the hydrogen mix point, the reactor, the reactor effluent and the recycle hydrogen gas including the exchangers, heaters, separators, piping, etc. in these systems. A reasonably good estimate of corrosion rates in H2-H2S systems can be made from data commonly known as the "Couper-Gorman Curves." Most refiners have found that under H2-H2S corrosive conditions, alloys with up to five percent chromium offer no significant improvement over carbon steel, and nine percent chromium alloys provide only marginal improvements and are thus considered ineffective in resisting corrosion. While some 12% Cr stainless steels are resistant to most H2S ranges, corrosion may occur on materials with chromium contents on the low end of the acceptable range or where service conditions are severe. Also, the 12% Cr alloys are not a commonly used material for this service due to fabrication difficulties and possible embrittlement problems. Even in cases where Cr-Mo or 12%Cr alloys would have acceptable lives, if they are predicted to have moderate corrosion rates, there may be economic justification to upgrade to reduce fouling or plugging from corrosion products. Austenitic stainless steels (18% Cr) are generally required to meet the corrosion and plugging resistance requirements. (Refer to Section 2 §5.1.5)

8.5.3

High Temperature Hydrogen Sulfide Corrosion Corrosion in Areas with Negligible Hydrogen In the some feed systems upstream of the hydrogen injection point, and in some fractionator sections after the majority of hydrogen has been separated out, another form of H2S corrosion can occur in areas >288oC (550oF). In these cases, the hydrogen partial pressures are typically