1、 1 Item No. 24240 NACE International Publication 34109 (2009 Edition) This Technical Committee Report has been prepared by NACE International Task Group 342,*“Crude Unit Distillation Column Overhead Corrosion.” Crude Distillation UnitDistillation Tower Overhead System Corrosion December 2009, NACE I
2、nternational This NACE International (NACE) technical committee report represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone from manufacturing, marketing, purchasing, or using products, p
3、rocesses, or procedures not included in this report. Nothing contained in this NACE report is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protect
4、ing anyone against liability for infringement of Letters Patent. This report should in no way be interpreted as a restriction on the use of better procedures or materials not discussed herein. Neither is this report intended to apply in all cases relating to the subject. Unpredictable circumstances
5、may negate the usefulness of this report in specific instances. NACE assumes no responsibility for the interpretation or use of this report by other parties. Users of this NACE report are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determinin
6、g their applicability in relation to this report prior to its use. This NACE report may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this report. Users of th
7、is NACE report are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this report. C
8、AUTIONARY NOTICE: The user is cautioned to obtain the latest edition of this report. NACE reports are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACE reports are automatically withdrawn if more than 10 years old. Purchasers of NACE reports may recei
9、ve current information on all NACE International publications by contacting the NACE FirstService Department, 1440 South Creek Drive, Houston, Texas 77084-4906 (telephone +1 281-228-6200). Foreword This state-of-the-art report describes the associated corrosion mechanisms in refinery crude distillat
10、ion unit (CDU) distillation tower overhead systems and current industry practices for mitigating or controlling this corrosion. Distillation towers in a typical CDU may include a preflash tower, an atmospheric tower, and a vacuum tower. Feedstock, unit configurations, and associated process variable
11、s are addressed, from the crude oil storage tanks to the distillation tower overhead drums. This report is intended as a technical resource for materials and corrosion specialists, process engineers, and operators at oil refining companies; chemical-treatment suppliers; and other companies involved
12、in analyzing and preventing CDU distillation tower overhead corrosion. This technical committee report was prepared by NACE International Task Group (TG) 342, “Crude Unit Distillation Tower Overhead Corrosion.” TG 342 is administered by Specific Technology Group (STG) 34, “Petroleum Refining and Gas
13、 Processing.” This technical committee report is issued by NACE International under the auspices of STG 34. _ * Chair Michael S. Cayard, Flint Hills Resources, LP, Saint Paul, MN. NACE International 2 NACE technical committee reports are intended to convey technical information or state-of-the-art k
14、nowledge regarding corrosion. In many cases, they discuss specific applications of corrosion mitigation technology, whether considered successful or not. Statements used to convey this information are factual and are provided to the reader as input and guidance for consideration when applying this t
15、echnology in the future. However, these statements are not intended to be recommendations for general application of this technology, and must not be construed as such. Table of Contents Contents Foreword 1 Overview of Corrosion Mechanisms . 5 Acid Corrosion 5 Hydrochloric Acid 5 Other Acids . 6 Eff
16、ect of Oxygen 7 Salts 7 Ammonium Chloride 7 Amine Hydrochloride Salts 9 Wet H2S Cracking 10 Feedstock Issues 10 Salt Content . 10 API Gravity . 10 Sulfur Content . 10 Total Acid Number 11 Tramp Contaminants 11 Nonextractable Chlorides 11 Amines 12 Slops and Wild Naphtha 13 Upstream Additives . 15 St
17、orage Tank Influences. 17 Tankage Dehydration 17 Chloride Control Strategies . 17 Desalting 17 Single-Stage Desalting 19 Two-Stage Desalting . 21 Wash Water Quality 22 Chemical Addition . 24 Caustic 24 Other HCl Reduction Additives . 26 Preflash Tower Overhead System Considerations . 27 Hot Preflash
18、 Tower . 27 Warm Preflash Tower . 28 Corrosion Concerns and Control 29 Typical Materials of Construction 30 Atmospheric Tower Overhead System Consideration 30 Single-Stage (Single-Drum) Overhead System 31 Additional Design Considerations . 32 NACE International 3 Typical Materials of Construction 32
19、 Atmospheric TowerTop Internal Concerns 33 Atmospheric TowerTop Pumparound 33 Atmospheric TowerOverhead System Concerns 34 Water Wash 34 Unit Throughput Considerations . 37 Neutralizer Injection 40 Filming Inhibitor Injection 41 Two-Stage (Double-Drum) Overhead System 43 Additional Design Considerat
20、ions . 45 Typical Materials of Construction 45 First-Stage Concerns 47 Second-Stage Concerns . 48 Water Wash Considerations for a Two-Stage Overhead System 49 Neutralizer Injection 49 Filming Inhibitor Injection 49 Vacuum Tower Overhead System Considerations 50 Vacuum Tower System Configuration 50 P
21、recondensers 51 Steam Eductors and Vacuum Pumps . 52 Vacuum Tower Overhead Corrosion Concerns . 52 Typical Materials of Construction for Vacuum Tower Overhead Systems . 52 Corrosion Control Strategies . 53 Water Wash 53 Neutralizer Injection 53 Filming Inhibitor Injection 54 Diagnostic Tools . 54 An
22、alytical Testing . 55 Water Analyses . 55 Scale Analyses 57 Process Analyses 59 Modeling Technology . 60 Steam Tables 60 Simulation-Based (Corrosion) Models 61 Corrosion Monitoring Program . 65 Inspection 65 Online Corrosion Monitoring . 65 Coupons 66 Electrical Resistance Probes 67 Long-Range Guide
23、d UT 68 Electrochemical Techniques . 68 Hydrogen Permeation . 68 Pulsed Eddy Current Techniques . 69 Process Stream Analysis . 69 Overhead Sour Waters . 69 Process Samples 70 References 70 Appendix AAvailable Electrolyte Models 77 Appendix BCorrosion Rate Models . 80 Appendix CModel Validation Again
24、st Controlled Environments . 82 FIGURES Figure 1: NH4Cl formation temperature 8 Figure 2: Ethanoltriazine reaction with H2S. . 13 Figure 3: Methyltriazine reaction with H2S. . 13 Figure 4: Increase in NH4Cl salt formation temperature . 15 NACE International 4 Figure 5: Schematic of a typical desalte
25、r vessel . 19 Figure 6: Schematic of a typical single-stage desalter . 20 Figure 7: Schematic of a typical two-stage desalter . 21 Figure 8: Schematic of a typical hot preflash tower system 28 Figure 9: Schematic of a typical warm preflash tower system 29 Figure 10: Schematic of a typical single-sta
26、ge (single-drum) atmospheric tower overhead system . 31 Figure 11: Schematic of an ideal two-stage water wash injection system 36 Figure 12: Typical water wash injection nozzle 37 Figure 13: Overhead condenser inlet impingement plate detail . 38 Figure 14: Overhead condenser inlet impingement rod as
27、sembly detail 39 Figure 15: Additional wash water injection nozzles in a condenser shell . 40 Figure 16: Schematic of a typical two-stage (double-drum) atmospheric tower overhead system . 44 Figure 17: pH vs. temperature plot for simulated atmospheric tower overhead system (C = 5/9 F 32) 45 Figure 1
28、8: Schematic of typical vacuum tower system . 51 Figure C1: Calculated and experimental VLE in the NH3H2SH2O system: total pressure and partial pressures of components at 40 C (104 F) 82 Figure C2: Calculated and experimental VLE in the NH3H2SH2O system: total pressure and partial pressures of compo
29、nents at 120 C (248 F) 83 Figure C3: Calculated and experimental SLE in the NH4Cl-H2O system . 84 Figure C4: Calculated and experimental corrosion rates of carbon steel and UNSS31600 at 93 C (200 F) as a function of NH4HS concentration 85 TABLES Table 1: Hydrolysis Reactions 5 Table 2: Commonly Used
30、 Additives in Oil Production 16 Table 3: Typical Materials of Construction for Hot and Warm Preflash Tower Overhead Systems . 30 Table 4: Typical Materials of Construction for Single-Stage Atmospheric Tower Overhead Systems . 32 Table 5: Typical Materials of Construction for Two-Stage Atmospheric To
31、wer Overhead Systems . 46 Table 6: Typical Materials of Construction for Vacuum Tower Overhead Systems . 53 Table 7: Overhead Conditions Used for Example 61 Table 8: Estimated Aqueous Dew Point Temperatures from Process Simulators . 61 Table A1: Summary of Representative Thermodynamic Models for Mix
32、tures Containing Electrolytes, Water, and Nonelectrolytes 79 NACE International 5 Overview of Corrosion Mechanisms Acid Corrosion Hydrochloric Acid Crude oils contain varying amounts of chloride salts (sodium chloride NaCl, magnesium chloride MgCl2, and calcium chloride CaCl2), and these salts gener
33、ally account for the bulk of the hydrogen chloride (HCl) formation and corrosion in CDUs. The respective ratio of these salts to each other depends largely on the geologic formation from which the crude oil and its connate water were produced. The composition of the water associated with a crude oil
34、 can be affected by the use of secondary or tertiary oil recovery methods that may include seawater injection, aquifer water injection, gas injection, fire flood, and steam flood. Variations in salt content can also occur as a result of various shipping and handling methods used during transportatio
35、n of the produced crude oil from the oil field to the refinery. The HCl is evolved from the hydrolysis of MgCl2and CaCl2to form HCl during heating in the CDU preheat train and associated furnaces. NaCl does not hydrolyze to a great extent under normal CDU furnace conditions. Therefore, NaCl generall
36、y is not considered a significant contributor to CDU distillation tower overhead system corrosion. However, there is evidence that the presence of naphthenic acids in crude oils facilitates the hydrolysis of MgCl2and CaCl2, and potentially even NaCl, so their presence can influence the amount of HCl
37、 evolved from crude oil.1Table 1 details the hydrolysis reactions involved. Table 1 Hydrolysis Reactions Reaction(A)Approximate Starting Temperature, C (F) Approximate Degree of Hydrolysis at 340 C (650 F) MgCl2+ 2H2O Mg(OH)2+ 2HCl 120 (248) 90% CaCl2+ 2H2O Ca(OH)2+ 2HCl 210 (410) 10% NaCl + H2O NaO
38、H + HCl 500 ( 930) 2% (A)Mg(OH)2 = magnesium hydroxide; Ca(OH)2= calcium hydroxide; NaOH = sodium hydroxide Other sources of HCl are nonextractable chlorides either these same inorganic chlorides, which are organically bound and not removable in the desalter, or organic chlorides. A complete discuss
39、ion of nonextractable chlorides is in NACE Publication 34105.2Although it is believed that many of the organic chloride compounds do not hydrolyze during crude oil distillation, some hydrolysis of certain compounds occurs. Gutzeit3 reported on such a case at CORROSION/2000, and other instances are d
40、iscussed in NACE Publication 34105. In CDU distillation tower overhead systems, HCl does not cause corrosion problems at temperatures above the aqueous dew point. However, at temperatures equal to or below the aqueous dew point, HCl readily dissolves in water to form corrosive hydrochloric acid. At
41、temperatures above the aqueous dew point, HCl can react with some alkaline species to form corrosive salts. This salt-related corrosion is discussed at length later in this report. Because presence of a liquid water phase is required, hydrochloric acid corrosion is usually confined to the CDU distil
42、lation tower overhead equipment where water is condensed. Also, it sometimes occurs on cold surfaces where the bulk temperature is frequently above the dew point, but the metal surface is below the dew point. This condition is often referred to as shock condensation. This typically occurs on heat ex
43、changer tube surfaces, colder pipe wall surfaces, and even on internal surfaces at the top of the distillation towers, particularly in the vicinity where cold reflux is returned. The most corrosive conditions occur at the initial aqueous dew point, where the majority of the HCl readily enters the fi
44、rst water phase that forms. This effect is demonstrated by ionic modeling. The pH of the initial condensate is approximately 1 or 2, depending on the amount of HCl in the distillation tower overhead stream. As the overhead stream is cooled further and additional water condenses, the pH increases, in
45、 part because of dilution of the acid NACE International 6 by the additional water, and in part because the ammonia (NH3) that is normally present begins to dissolve in the cooler water phase. NH3does not readily dissolve at the elevated aqueous dew point temperature, so it has virtually no benefici
46、al effect on the pH at the dew point, and thus exhibits little if any corrosion reduction at these conditions. In addition, the amount of NH3naturally present in CDU distillation tower overhead systems is insufficient to fully neutralize the HCl formed. It is common for a CDU distillation tower over
47、head system with no other neutralizer added to have a natural pH of approximately 4. Materials selection and chemical treatment to control hydrochloric acid corrosion are discussed later in this report. Other Acids Four other principal acids are sometimes present in CDU distillation tower overhead s
48、ystems: hydrogen sulfide (H2S), light organic acids, carbon dioxide (CO2), and sulfur-oxide (SOx)-based acids. Testing for the presence of these acids is often performed, especially when corrosion has been difficult to control. Other acids are occasionally present in smaller concentrations, and typi
49、cally, when a survey for these principal acids is performed, other species are evaluated as well. These can include hydrofluoric acid (HF) (typically a concern at refineries operating HF alkylation units) and phosphoric acid (H3PO4). H2S is almost always present in some amount in the CDU distillation tower overhead systems, as it is formed by thermal decomposition of sulfur compounds in the crude oil. Some crude oils also contain dissolved H2S. H2S can accelerate hydrochloric acid corrosion in unneutralized or low pH conditio
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