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SABP-A-016 25



Crude Unit Corrosion Control

Document Responsibility: Materials and Corrosion Control Standards Committee


Table of Contents


1 Purpose and Scope 4

2 Conflicts with Other Standards 4

3 References 4

3.1 Saudi Aramco Mandatory Engineering Documents 4 3.2 Saudi Aramco Engineering Reports and Best Practices 5

3.3 Saudi Aramco On-line Resources 5

3.4 Industry Codes and Standards 5

4 Abbreviations 6

5 Overview of Principal Corrosion Mechanisms 7

6 Process Considerations 8

6.1 Process Flow Diagram 8

6.2 Crude Oil Supply 9

6.3 Recirculation of Slops 10

6.4 Tank Handling 12

6.5 Desalting 12

6.6 Caustic Addition and Downstream Equipment 14

6.7 Fired Heaters and Transfer Lines 15

6.8 Distillation 16

6.9 Overhead System 20

6.10 Wash Water 21

6.11 Coolers and Fin Fans 22

6.12 Overhead Receiver 23

7 Damage Mechanisms 23

7.1 Hydrochloric Acid Corrosion 26

7.2 Salt Formation 28

7.3 Shock Condensation Corrosion 28

7.4 Sulfidation 29

7.5 Fuel Ash Corrosion 29

7.6 Carburization 29

7.7 Creep 29

7.8 Sulfur Oxy-acids 32


7.10 Sodium Hydroxide (Caustic) 32

7.11 Caustic Stress Corrosion Cracking 33

7.12 Chloride Stress Corrosion Cracking 33

7.13 Wet H2S Damage 35

7.14 Downtime Corrosion 36

8 Control of Corrosion by Chemicals 36

8.1 Chemical Injection 36

8.2 SARCOP 36

8.3 First Fill Chemicals 37

8.4 Tank Aids and Desalter Aids 37

8.5 Caustic Upstream of the Desalter 37

8.6 Caustic Treatment between the Desalter and Heater 37

8.7 Caustic Treatment Downstream of the Heater 39

8.8 Caustic Quality 39

8.9 Neutralizing Amine 39

8.10 Filming Amine 41

8.11 Automatic pH Control 42

8.12 Fireside Additives 42

8.13 Inhibitors for Naphthenic Acid Corrosion 43

9 Materials 43 9.1 Vessels 43 9.2 Trays 44 9.3 Pipework 44 9.4 Quills 45 9.5 Coatings 45

10 Corrosion Management Program 45

10.1 Responsibilities 46

10.2 KPIs, Example Corrosion Rates, and Reporting Schedule 46

10.3 Data Storage and Processing 47

10.4 On-Stream Inspection (OSI) Program and Inspection Methods 47

10.5 Injection Point Inspection 49

10.6 Corrosion Monitoring Systems 49

10.7 Laboratory Testing 50


1 Purpose and Scope

This SABP provides guidelines that will improve the integrity of crude units through a fundamental understanding of the damage mechanisms, process parameters, inspection techniques, corrosion monitoring, analytical needs, and corrosion control options. The Best Practice updates and replaces the previous Best Practice published in SAER-5941 in March 2004. All the content of the previous best practice is incorporated in the present document. SAER-5941 included industry experiences and assessments of crude units in Saudi Aramco. This Best Practice is summarized as a table in Appendix 1, Crude Unit Best Practice Limits, at the end of this document.

2 Conflicts with Other Standards

2.1 If there is a conflict between this Best Practice and other Saudi Aramco standards and specifications, please contact the Coordinator of Materials Engineering and Corrosion Control Division, Consulting Services Department, for clarification.

2.2 This document is a minor update on the Saudi Aramco Crude Unit Overhead Corrosion Control Best Practice originally published as part of SAER-5941. If there are any conflicts between the recommendations of this document and SAER-5941, this document shall govern.

2.3 This document and SAER-5941 supersede SAER-5573 and will govern in any cases of conflict with SAER-5573.

3 References

3.1 Saudi Aramco Mandatory Engineering Documents

All Saudi Aramco mandatory engineering documents apply to crude units. However, the following merit specific mention.

Saudi Aramco Engineering Standards

SAES-A-301 Materials Resistant to Sulfide Stress Corrosion


SAES-F-001 Design of Fired Heaters

SAES-L-132 Material Selection for Piping Systems

SAES-L-133 Corrosion Protection Requirements for Pipelines,


SAES-N-140 Installation Requirements – Refractory Ceramic Fiber

SAES-W-010 Welding Requirements for Pressure Vessels

SAES-W-011 Welding Requirements for On-Plot Piping

Saudi Aramco Engineering Procedure

SAEP-1135 On-Stream Inspection Administration

Saudi Aramco Materials System Specifications

01-SAMSS-016 Qualification of Pipeline, In-Plant Piping, and

Pressure Vessel Steels for Resistance to Hydrogen Induced Cracking

32-SAMSS-020 Manufacture of Trays and Packing

Saudi Aramco Inspection Procedure

01-SAIP-04 Inspection of Injection Points

3.2 Saudi Aramco Engineering Reports and Best Practices

SAER-5573 Crude Distillation Unit Overhead Corrosion Study

SAER-5941 Final Report and Guidelines on Crude Unit

Overhead Corrosion Control

SABP-A-015 Chemical Injection Best Practice

3.3 Saudi Aramco On-line Resources

Engineering Encyclopedia AGE-105

Chevron Corrosion Manual CSD/ME&CCD Knowledge Management LiveLink site

3.4 Industry Codes and Standards

NACE MR0103 Materials Resistant to Sulfide Stress Cracking in

Corrosive Petroleum Refining Environments

NACE PUBL 34101 Refinery Injection and Process Mixing Points

NACE PUBL 24226 Effect of Non-extractable Chlorides on Refinery

Corrosion and Fouling

NACE RP 0403 - 2003 Avoiding Caustic Stress Corrosion Cracking

NACE Crude Unit Corrosion Control Best Practice, to be


API RP 570 Inspection, Repair, Alteration and Re-rating of In-Service Piping Systems

API RP 571 Damage Mechanisms Affecting Fixed Equipment

in the Refining Industry

API RP 580 Risk Based Inspection

API RP 581 Risk-Based Inspection Base Resource Document

ASTM D 473 Standard Test Method for Sediment in Crude Oils

by the Extraction Method

ASTM D 664 Acid Number of Petroleum Products by

Potentiometric Titration

ASTM D 974 Acid Number by Color Indicator Titration

ASTM D 3230 Standard Test Method for Salts in Crude

ASTM D 3948 Determining Water Separation Characteristics of

Aviation Turbine Fuels by Portable Separometer

ASTM D 4006 Standard test Method for Water in Crude Oil by


ASTM D 4007 Standard Test Method for Water and Sediment in

Crude Oil by the Centrifuge Method

ASTM D 6470 Standard Test Method for Salt in Crude Oils

(Potentiometric Method)

ASTM D 4928 Standard Test Methods for Water in Crude Oils by

Coulometric Karl Fischer Titration

ASTM D 5863 Standard Test Methods for Determination of

Nickel, Vanadium, Iron, and Sodium in Crude Oils and Residual Fuels by Flame Atomic Absorption Spectrometry, Revision A

4 Abbreviations

API American Petroleum Institute

ASTM American Society for Testing and Materials International BS&W Bottom sediment and water also Basic sediment and water. CRA Corrosion resistant alloy

CSCC In Table 1, meaning is: caustic stress corrosion cracking KPI Key performance indicator


mpy mils per year (thousandths of inches of wall loss, per year) mmpy millimeters per year (1 mmpy = 40 mpy)

OSI On-stream inspection

OSPAS Oil Supply, Planning, and Scheduling Department PTB pounds of salt per thousand barrels of crude oil

SAIF System Assurance and Inspection for Facilities data management system SARCOP Saudi Aramco Refining Chemical Optimization Program

TAN Total Acid Number, see ASTM D 664 and D 974 5Cr1/2Mo 5% chromium, ½% molybdenum steel

9Cr1Mo 9% chromium, 1% molybdenum steel

5 Overview of Principal Corrosion Mechanisms

The corrosion mechanism of greatest concern in the crude unit is hydrochloric acid condensation in the overhead system. Significant portions of the crude processing and corrosion control program are aimed at reducing this “overhead corrosion.” Target chloride levels measured in the overhead receiver are less than 30 ppm. The target pH is 5.5 to 6.5. Corrosion inhibitor and neutralizer are added to the system to minimize corrosion. Without adequate corrosion control, corrosion rates could be as high as 1,000 to 2,000 mpy which is 1 – 2 inches per year (25-50 mmpy). Under deposit corrosion from the reaction between hydrochloric acid and ammonia or neutralizing amines is another major source or corrosion. The chloride salts are hydroscopic and attract moisture resulting in heavy under-deposit corrosion. These salts can deposit on trays and walls.

The crude unit also involves high temperature processing and heaters, and the next most important corrosion mechanism is sulfidation which occurs due the direct reaction of alloys with hydrogen sulfide formed from sulfur in the fuel at temperatures in excess of about 260ºC (500ºF). Sulfidation is controlled by material selection at the design stage for the required surface temp-eratures in the heater and crude tower. Common materials used in the heater are 5% chromium, ½% molybdenum steel (5Cr1/2Mo), and 9%

chromium, 1% molybdenum steel (9Cr1Mo).

Naphthenic acid corrosion has been a major problem in refineries around the world but has not been reported as a problem in Saudi Aramco refineries due to the low acid content of produced crudes. This can always change in the future as new fields are discovered and included in the crude slate.

All Saudi Aramco crude units operate at higher than design capacity. This in itself is a major cause of corrosion due to reduced separation times and efficiencies, greater


velocities in pipework, and higher firing rates required on heaters, all of which increase corrosion damage.

Recommendations to minimize corrosion damage are summarized in Appendix 1 at the end of this best practice. The reader is also referred to SABP-A-015, the Chemical Injection Best Practice for specific information on chemical injection design and equipment.

6 Process Considerations

The primary function of the crude unit is to separate crude oil into useful fractions by distillation. Crude oil supplied to the distillation column must have impurities removed prior to processing, so extensive pretreatment is performed. The products produced by fractionation in the crude column are further processed in downstream units to increase the value of the product streams. This involves removal of additional impurities such as sulfur or modification of the hydrocarbon molecules.

6.1 Process Flow Diagram

Figure 1 shows a typical process flow diagram for a crude unit in a refinery. There are variations within Saudi Aramco facilities. Heat exchangers improve the efficiency of the crude unit, incoming crude to the desalter and after the desalter to the furnace being heated by exchange with various crude column product outputs. This can involve a large number of heat exchangers.


6.2 Crude Oil Supply

Crude is supplied to the refinery either by pipeline or sea-tanker. Crude can contain both inorganic and organic contaminants that can be a direct cause of corrosion.

Inorganic contaminants include produced brines and solids. Chlorides in brine are a major cause of corrosion because if they are able to reach downstream of the desalter to the heaters, they will be converted to hydrochloric acid which will condense in the overhead system.

Organic contaminants include organic acids, sulfur, and nitrogen complexes, all of which may contribute to corrosion. Some African crudes contain organic calcium which must be converted to be water soluble for removal in the desalter, in order to prevent contamination of downstream units such as a fluid catalytic cracking (FCC) process.

Chemical additives may be added intentionally to the upstream production system to help cure an upstream problem, yet result in downstream corrosion and fouling problems in the crude unit. Biocides are used in the East West Pipeline that delivers crude oil to the West Coast Refineries. Typically, biocides contain quaternary ammonium chlorides that may contribute to the corrosion problems in the crude column and overhead system. Some hydrogen sulfide scavengers form amines in the crude column and can result in the formation of corrosive amine chloride deposits. The referenced NACE PUBL 24226, Effect of Non-Extractable Chlorides on Refinery Corrosion and Fouling, provides additional details on possible sources of contaminants in crude units.

Impurities need to be separated to the greatest extent possible before crude is fed to the distillation column. The first stage of this separation is field desalting in gas oil separation plants. This limits the amount of contaminants. Further separation occurs in stabilization facilities such as Abqaiq Plants. Saudi Aramco pipeline specifications call for pipeline crude to have less than 10 PTB (pounds per thousand barrels) of chloride, less than 0.2 volume percent BS&W (bottom sediment and water) and less than 70 ppm H2S. However, it should be noted that with recent increases in crude production, equipment operates at near the limit of its capacity resulting in reduced separation efficiency, and ideal pipeline specification are sometimes not achieved. A level of 150 PTB chlorides has been reported reaching refineries from time to time.

Saudi Aramco refineries currently process Arab Light and Arab Heavy crudes. Previously, Arab Extra Light has been fed to some refineries. Test runs have also been performed with Arab Medium at some refineries. The choice between crude or crude blends is determined by Oil Supply, Planning, and Scheduling Department (OSPAS).


Moving from Arab Light to 100 percent Arab Medium or Arab Heavy increases the corrosion rate in the overhead system and requires an increase in the

neutralizer dosage, even with well controlled chlorides. No definitive analyses have been performed, but the presence of carbonates in the produced brine associated with Arab Medium and Heavy has been suggested.

Increasing the charging rate of Arab Medium or Heavy also increases the risk of fouling in downstream units making decoking of heaters more problematic. The basic properties of crude oil that affect it corrosivity in processing are the Total Acid Number (TAN), the percentage of sulfur, and its API gravity. TAN is a measure of naphthenic acids, organic acids, inorganic acids, phenolic compounds, dissolved H2S and CO2.

The interpretation of TAN numbers is somewhat open to question. Various experiences are reported by other companies. One company reports that TAN numbers in any side-cut greater than 0.3 indicate that naphthenic acid corrosion may become an issue, particularly at velocities over 30 m/s (100 f/s). The same company reports that for Californian crudes, a TAN number in excess of 1.5 is required before naphthenic acid corrosion becomes problematic. Another company reports that naphthenic acid corrosion can be expected when the whole crude TAN exceeds 0.5. Saudi Aramco crudes are border line versus this

categorization. Increased charging of Arab Heavy might result in the

development of naphthenic acid corrosion. To date, Saudi Aramco refineries have not reported naphthenic acid corrosion.

The scatter in interpretation of TAN data arises because the TAN number

derived from ASTM D 664 combines the effects of sulfur and naphthenic acids. Actual organic acid levels will be considerably lower. (Reference: Tebbal et al., Corrosion 2004, Paper 04636, NACE International).

Some high TAN crudes have higher conductivity and are therefore more difficult to desalt. Low API gravity indicates higher viscosity also making a crude harder to desalt.

Sulfur in crude oil may be present in various forms including mercaptans. Sulfur is converted to hydrogen sulfide in the heater and direct high temperature sulfidation occurs. Wet hydrogen sulfide corrosion mechanisms are possible in cooler downstream equipment.

Table 1, below, presents typical properties for stabilized crude oils fed to the refineries. These data are measured infrequently. TAN numbers have not been measured in the past for the whole crude but rather determined for each side cut. Numbers reported for TAN represent the highest number reported for any


TAN numbers reported are low to borderline which agrees with the Saudi Aramco experience of no significant naphthenic acid attack.

Table 1: Stabilized Crude Oil Typical Properties

Crude Type API Sulfur, wt % Mercaptan Sulfur, wt %

Highest side-cut TAN

Arab Super Light 50 – 52 0.02 - 0.06 n/a 0.12

Arab Extra Light 39 0.8 n/a 0.18

Arab Light 31 – 34 1 - 3 0.014 0.06

Arab Medium 31 2.6 n/a 0.33

Arab Heavy 27 - 28 3 0.001 0.48

6.3 Recirculation of Slops

Refineries collect and reprocess waste streams and drainage systems. These systems are usually routed to the API Separator. Recovered oil is returned to the crude feed for reprocessing from the API Separator. This has the potential to introduce contaminants back into the crude charge that may originate in a process unit that is actually downstream of the crude unit. These contaminants include oxygen which is obtained from surface run-off water to the oily water sewer. Zinc chloride is a chemical sometimes used as a dewatering aid in waste streams. Some of this may travel with the slop oil. Waste oils may be oxidized into fatty acid esters resulting in a TAN greater than 20.

Column upsets may occur from periodic wash downs of certain areas charging large volumes of contaminants to the API Separator.

Tramp amines may be fed in from gas sweetening systems.

Recirculated streams may be sent direct to the crude tanks. This provides the opportunity to blend a relatively small volume of contaminated stream with a large volume of diluent. However, it also provides the opportunity to

contaminate a large volume that needs to be processed. The preferred

alternative is direct feeding of API slops upstream of the desalter, blending the slops with the main crude oil flow. This provides the opportunity to stop the flow of slops in the event of a major column upset. An even better option is find an alternative use for slops that does not result in feeding them to the crude tower.


6.4 Tank Handling

Most Saudi Aramco refineries run crude oil into storage tanks on-site. Storage tanks provide a settling opportunity to remove additional water and sludge. Adequate settling time is the primary parameter for effective separation in tankage, though Saudi Aramco facilities are generally limited by available number of tanks and by increased throughput. Water settlement can be assisted by chemical aids that improve water separation, though chemical treatments have only been used on a trial basis in Saudi Aramco facilities. Storage tanks provide protection from abnormal flows in the pipeline including the occasional water slug. Water must be drained from the tanks on a regular basis.

Automation of this function would reduce work load on tank operators. Sludge can accumulate over time in the bottom of the tank which creates operational problems, such as poor water drainage. The build up of sludge within a crude tank can also result eventually in a cleaning problem and

environmental disposal problem. The build up of sludge within tanks can result in pickup of water and sludge at tank change-over when the tank level is low. The use of mixers in crude oil storage tanks during the filling operation helps to re-dissolve heavier sediment and reduces sludge accumulation at the bottom of the tank. Various chemical additives are available to help re-dissolve sludge if the problem is severe.

Ras Tanura Refinery follows a different approach and tight-lines Arab Light crude to the crude unit. In this case, there is no opportunity for major upsets occurring as a result of tank changes. This provides for a very stable operation, which allows for easier control of overhead corrosion problems.

6.5 Desalting

Figure 2 shows a typical desalter. In Saudi Aramco refineries, there are single desalter systems (e.g., Jeddah—one for each crude unit), double desalters with two desalters in sequence (e.g., Yanbu and Rabigh). There can be multiple parallel trains of desalters. The primary purpose of the desalter is to remove salts and solids from the crude oil. The crude oil stream is washed with water containing fewer impurities, and then the water is separated out again. Any water remaining in the crude then has a much lower concentration of salt. This is achieved in a two step process. In order for the wash water to disperse

intimately throughout the crude, a fine emulsion must be formed between the oil and water. This is achieved through the mix valve. The second part of the process is to separate the emulsion using an electrostatic desalter. Chemical may be added to aid the separation process if required. Optimizing desalter performance will reduce chloride content of desalted crude oil. This will reduce the acidity of the crude overhead system, which will reduce corrosion and


fouling in the crude overhead line and fin fans. Optimizing desalter operation will reduce neutralizer cost for the overhead system.

Effective desalting is enhanced by factors that include elevated temperatures, effective mixing on entering the mix valve, sufficient residence time, the use of electrostatic plates to enhance water droplet settling, and continual removal of sludge from the desalter. Ideal wash water properties are high purity and zero oxygen. Stripped sour process water or vacuum section overhead condensate is frequently used in the industry. Too alkaline a pH results in poor desalter efficiency and tramp amines partition more into the oil phase.

The common deficiencies in Saudi Aramco refineries are the use of too small an amount of wash water and too low a temperature. Five to six percent wash water by volume of the crude oil charge is required. Some companies add this in about equal proportions upstream of the crude charge pump and upstream of the mix valve. A temperature between 120-150ºC (250-300ºF) is optimum for desalting. The upper limit is dependent upon the temperature limits of electrical equipment installed in the particular desalter.

Overhead water is a common source of water for desalters. However, the use of overhead water streams introduces the probability of recirculating back to the crude column neutralizing amine that is injected into the overhead for pH control. With this recirculation of amines comes the possibility of salt formation, especially in cooler crude columns.

The continual use of an effective mud wash system in a desalter is important in maintaining desalter performance. Deposits in the bottom of the drum reduce volume size and, therefore, decrease residence time, which is bad for separation of the phases. Similarly, increased unit throughput will also decrease residency time. A typical mud washing program followed by other companies is to mud wash every shift for 15 minutes each time at a rate of 35 m³/hr (154 gpm).


Figure 2 – Typical Desalter System

Caustic is added to adjust the pH of the desalter water in three out of five Saudi Aramco refineries. Operating a desalter at a pH between 5.5 and 6.5 helps break the emulsions and limits iron sulfide solubility.

Desalters are customarily made from carbon steel with either a heavy corrosion allowance (3/4 inch), lined with gunite in the salt water zone, or clad with alloys such as alloy 825 such as in J-64 and Plant 15 at Ras Tanura.

6.6 Caustic Addition and Downstream Equipment

Sodium hydroxide is added downstream of the desalter to further reduce chloride damage in the overhead system. The location of this injection point varies from refinery to refinery in Saudi Aramco’s operations. It may be

injected immediately downstream of the desalter or immediately upstream of the heaters. The recommended location is immediately downstream of the desalters. Further details are provided in Section 8. Correct caustic solution strength, and injection point design, fabrication, installation, and subsequent inspection are critical to the safe operation of the caustic injection system and crude unit. Improperly designed, fabricated, or installed systems have resulted in at least three major fires in Saudi Aramco, including one that resulted in loss of a unit. Over-treatment with caustic immediately downstream of the desalter has resulted in severe fouling of heat exchangers and, at two refineries (Ras Tanura and Riyadh), caustic stress corrosion of carbon steel pipework. Over-treatment is prevented by close control of the caustic injection system. However, in the case of Ras Tanura, dead spaces in the heat exchanger design contributed to the

Possible demulsifier injection Optional caustic injection Desalted crude out


collection and concentration of caustic. Caustic stress corrosion cracking is reduced by stress relieving all welds.

Caustic injection must follow the requirements of this Best Practice and the Chemical Injection System Best Practice, SABP-A-015.

6.7 Fired Heaters and Transfer Lines

Fired heaters raise the temperature of the crude feed to the region of 360-380ºC (680-716ºF), depending upon the refinery, crude oil blend, etcetera, for entry into the crude distillation column. The more volatile components of crude oil are volatilized at this temperature and the crude vapor/liquid mix enters the column in the flash zone towards the bottom of the column.

At furnace temperature, process-side sulfidation is the main cause of concern. This is reduced by usage of low-alloy steels such as 5Cr1/2Mo or 9Cr1Mo. Process-side carburization can also occur above a surface temperature of about 500ºC (930ºF). This affects 5Cr1/2Mo to some extent and 9Cr1Mo to a greater extent. Carburization can be checked by removing a tube sample for

metallurgical analysis. Carburization becomes a problem during rapid start-ups and shutdowns when thermal stresses of sufficient magnitude are generated to cause cracking on the process-side surface of the tube.

Caustic cracking may also be of concern if any carbon steel heater tubes are not stress relieved and caustic is injected immediately upstream of the heater. Customarily, both 5Cr1/2Mo and 9Cr1Mo materials are stress relieved.

Naphthenic acid corrosion is reported in this temperature region in worldwide refineries but has not historically been an issue in Saudi Aramco refineries. Naphthenic acid corrosion may become an issue in the future if refinery crude slates are changed, especially if these changes include the import of opportunity crudes from other countries.

Coke can be a problem in furnaces; however, this is normally more common in vacuum distillation units. X-ray inspection during T&Is provides information on the extent of this problem.

Heater tubes fireside surface temperatures may be much higher than the nominal 380ºC, especially if heat transfer is impeded by coke or other deposits on the process-side surface.

Fireside corrosion is an issue if the furnace uses crude or fuel oil. Fireside corrosion occurs due to the presence of vanadium, sodium, and sulfur in the fuel oil. Severe fireside corrosion has been experienced in at least two Saudi


for fireside corrosion is the co-injection of magnesium oxide or magnesium carboxylate with the fuel.

Acid dew point corrosion can occur on cold spots in the furnace. This has been experienced by the heater casing in Saudi Aramco Refineries. If the inner refractory layer of the heater casing is damaged or imperfect, flue gases can condense sulfurous/sulfuric acids on the cooler metal surface of the wall. Saudi Aramco specifications now require a vapor barrier to be applied to reduce the risk of corrosion damage to the outer walls. Where free sulfur in the fuel exceeds 500 ppm, the vapor barrier must be Type 304 stainless steel per SAES-N-140, Installation Requirements - Refractory Ceramic Fiber, paragraph 9.4.4 (December 2006). Infra-red thermography is used to scan the casing for hot spots or refractory damage.

High fire-box temperatures greater than 815°C (1500°F) can create material problems. Tube supports and hanger suffer excessive oxidation and premature failure if they are not sufficiently alloyed. Typically, HH casting alloy (25Cr-12Ni) performs well in the cooler convection section, but fails in radiant regions. Usage of HK casting alloy (25Cr-20Ni) provides extra life in hot areas. Higher nickel materials give excellent performance where low sulfur fuel is used as firing medium. However, where sulfur is high, these alloys suffer from

sulfidation as do welds made with Ni-base consumables. Fired heaters burning fuel oil high in sodium and vanadium should be refractory lined HK alloy supports or supports made of solid 50Cr-50Ni to combat fuel ash corrosion. Transfer lines are usually made of low-alloy steels, such as 5Cr½Mo or carbon steel depending on temperature. For velocities exceeding 200 ft/s, transfer piping material shall be 5Cr1/2Mo minimum. In some cases, this is upgraded to 9Cr1Mo.

6.8 Distillation

The distillation process involves heating the crude at temperature and slightly elevated pressure, and then fractionating the product through use of bubble trays within the tower. Different side-cuts are removed from particular trays as product. Separation of side-cuts may be further refined in side-cut strippers, the reject being returned to the tower. The reject liquid also provides liquid

returning to the bubble cap trays, aiding the fractionation process. Steam is injected into side cut strippers to assist in stripping out light ends. Steam is also injected into the lower part of the tower. Heat sources include several heat exchangers which cool outgoing streams while incoming feed is heated. A fired heater is used immediately upstream of the distillation column.

The temperature in the distillation column ranges from the region of 380ºC (716ºF) at the bottom of the tower to about 130ºC (266ºF) or so at the top of the


tower, depending upon the tower design, the crude slate, and the product specifications. However, some of Saudi Aramco’s crude columns operate the tower top at lower temperatures closer to 115ºC (240ºF). Corrosion damage varies through the tower depending upon temperature. At lower temperatures below the acid dew point, aqueous corrosion occurs. At higher temperatures, sulfidation occurs. At higher temperatures, naphthenic acid corrosion could also occur but has not been found with typical Saudi Aramco crude slates.

Temperatures in the tower may vary considerably due to poor flow distribution across trays. In the top of the tower the injection of cold reflux streams or wild naphtha streams can significantly impact local temperatures and cause shock condensation of acid.

If the top of the tower is below the dew point temperature of any corrosive vapor, then acid condensation will occur. This is most commonly hydrochloric acid, but condensation of sulfur oxy-acids (sulfurous and sulfuric) and carbonic acid is also possible. Hydrogen sulfide forms in the heater through degradation of sulfur compounds in the oil. Hydrogen sulfide also participates in the aqueous corrosion reaction at this temperature and the dominant corrosion product film commonly found is iron sulfide. Iron chloride is 105 times more soluble and is not normally found as a corrosion product. The presence of chloride salts in the tower after opening is indicative of chloride salt deposition. Commonly, the inside of the crude column top dome is lined with Monel 400. This may take the form of a clad sheet, a weld overlay, or in case of temporary repairs, strip welded plate. The top three or four trays are normally Monel 400. Galvanic corrosion between the edge of the Monel lining and the carbon steel tower has generally not been a practical problem. In cases where some galvanic corrosion has shown up, other damage mechanisms have been dominant and required repair before galvanic corrosion became a serious issue.

Monel is quite resistant to H2S damage at this temperature but corrosion product films containing mixed copper and nickel sulfides are commonly found. Monel is fairly resistant to hydrochloric acid, but corrosion can be found in crude column domes with condensing HCl. Typical corrosion rates are on the order of 20 mpy.

One joint venture refinery uses a Hastelloy C-276-lined dome instead of Monel. It is critical that alloy cladding be run far enough down the tower so that

revaporization of condensed acid can occur on the alloy surface. Condensed acid progressing down the tower will be revaporized as it reaches hotter zones. In one joint venture refinery, acid condensing in the cooler alloy-clad regions of the tower ran down the alloy surface until it reached a carbon steel surface that was still cool enough to allow the presence of acidic liquid. Rapid corrosion of the carbon steel resulted.


Beneath the Monel lined section, Type 410 stainless steel bubble cap trays or better are now required by Materials Specification 32-SAMSS-020, paragraph 10.8 (March 2005). Previously, carbon steel was specified for intermediate trays and down-comers in the column. In the hotter regions of the tower, Type 316L stainless steel can be used as a tray material and as a cladding material to

provide protection against naphthenic acid corrosion. However, naphthenic acid corrosion has not been recorded in Saudi Aramco refineries with the present crude slates.

From the corrosion point of view, the minimum temperature in the tower should always be at least 15ºC greater than the highest dew point temperature of any condensable corrosive acid such as hydrochloric acid, sulfur-oxy acids, or carbonic acid. Towers with higher top temperatures such as Ras Tanura tend to experience far less corrosion problems than towers with cooler top temperatures such as Rabigh. Tower temperatures are always determined by process needs and the required end points of products, so in practice the corrosion engineer has little influence over these temperatures. Suggested changes in tower operating parameters can be supported by evaluating the cost of additional repairs and the downtime required to effect repairs versus possibly lower productivity but uninterrupted production. Cooler towers may experience localized corrosion over a limited area due mal-distribution of flows inside the tower or external heat sinks. In one such case, corrosion rates in the region of 1,600 mpy have been reported on the carbon steel tower wall.

Evaluation of tower tray performance using advanced inspection techniques such as gamma scans or linear accelerators can indicate flow distribution problems that may be result in temperature variations. An example is provided in Figure 3.

The dew point in the tower and overhead system depends upon the amount of water present, so there must be careful control of stripping steam into the tower and side strippers. Steam may also be a source of contamination by boiler water feed chemicals if volatile chemicals are carried through the system, or if liquid water is entrained with the steam. Higher pressure steam rather than saturated steam is preferred. Other water sources into the tower include the crude feed itself and any possible return in the reflux from the overhead accumulator. At least one refinery experienced severe corrosion problems when approximately 50% water was returned to the tower in the reflux due to inadequate separation in the overhead accumulator. Increased water in the column will also mean increased steam generation and greatly increased velocities in the overhead pipework. The refinery with water in the reflux was calculated to have overhead velocities in the region of about 90 m/s (300 feet per second).


Figure 3: Example of Gamma Scan Data to Detect Tower Abnormalities Crude columns and trays can occasionally experience severe fouling or

corrosion of trays and side-cuts. Leaking heat exchangers on side-cuts or poorly maintained pumps can be sources of problems. Condensation of amine

chlorides can be another source of deposits. Water soluble neutralizers that enter the tower or other tramp amines may precipitate amine salts within the tower. The first line of defense against this type of corrosion is to prevent the amine product entering the tower.

Nitrogen compounds in the crude feed form ammonia, and ammonia will react with chlorides to form ammonium chloride, a hydroscopic salt that can deposit on trays or pipes.

Wild naphtha streams from downstream processes are sometimes returned to the crude tower to provide improved separation of the wild naphtha stream

components. Such streams can be contaminated with water, ammonia, and other corrosives. If at all possible, wild naphtha streams should be routed to other units or sales. Depending upon stream temperature and injection location, they may also initiate shock condensation.

Potentially corrosive re-injected streams that enter at temperature locations where flashing can occur must be injected through adequately designed injection points using Alloy 625 or equivalent injection quills. Existing injection points of these types of streams should be carefully inspected during T&Is.


6.9 Overhead System

The overhead piping system conveys the lightest products of distillation

(gasoline, naphtha—depending on tower operation) and water as a vapor stream from the top of the tower. The normal configuration is for a pipe to exit

vertically from the center of the dome and pass through two bends to descend the outside of the tower. Other configurations may be found in some facilities. A joint venture refinery uses dual overheads. One refinery takes the exit from the side of the tower. The overhead descends to heat exchangers that condense liquids for separation in the overhead receiver (also called the overhead

accumulator) as shown in Figure 1, above. A portion of the liquid hydrocarbon is recirculated to the tower to aid in separation at the bubble trays. Water is usually sent to the sour water stripper and may be returned to the unit to serve as a wash water. Product streams are sent for further processing.

As the stream cools, acid components condense and cause corrosion. Hydrochloric acid is the most important of these, though sulfur-oxy acids, carbonic acid, hydrogen sulfide and other weak acids may also condense depending on stream composition.

Corrosion control is obtained through a combination of process control

(temperature, velocity), proper design, plus the use of corrosion resistant alloys and/or chemical treatments.

Process control means maintaining the tower top temperature at least 15 degrees centigrade above the highest dew-point temperature for any of the corrosive acids. It also means minimizing water injected into the tower and side strippers to the extent possible, and optimizing the velocity in the overhead pipework. Process control also means effective tank settling, desalting, and treatment with caustic upstream of the crude distillation tower, minimizing the formation rate of hydrochloric acid.

For overhead systems with severe corrosion problems, carbon steel internally clad with 3-mm Hastelloy C-276 has been used in Yanbu Refinery and in SAMREF, the joint venture refinery in Yanbu. While the carbon steel pipe thickness behind the cladding can be optimized to reduce weight and cost, this can only be done in cooperation with weld design, as thin carbon-steel clad material has presented welding problems in the past. Hastelloy C-22 clad carbon steel material is a preferred material for hot-formed elbows, in-order to avoid sensitization. Alternatively, weld-overlaid carbon steel can be used. In-Kingdom users on Hastelloy C-276 report corrosion rates of less than 1-mpy. Refineries planning to use Hastelloy or similar materials should be aware of the long lead times for specialty alloys and plan accordingly. Lead times may be in the region of one year or more.


Chemical corrosion control is applied in the overhead for any portion that is not constructed from Hastelloy or an equivalent material. Water soluble neutralizer is co-injected with steam to vaporize the neutralizer. Alternatively, neutralizer may be co-injected with the overhead wash water, providing that no acid condensation can occur on carbon steel upstream of the injection point. The object for the neutralizer injected with steam is to react in the vapor phase with HCl and also to co-condense in the first drops of acid that condense in the system. The target pH is 5.5 to 6.5, measured at the overhead receiver. It is important to select a neutralizer that partitions quickly into the condensing liquid phase. Ammonia is used by some companies for neutralization, but it partitions very slowly into the condensing acid. Ammonia has been found as an impurity in Saudi Aramco overhead systems, especially where hydrotreating or similar processes are used. The presence of ammonia will increase the pH of the overhead receiver water. Too high a pH may lead to instability of iron sulfide surface films on the pipework. This can be observed as “black water” in the water leg of the overhead receiver. Under these circumstances, it may be necessary to reduce neutralizer addition; however, this must be done only with careful monitoring on a frequent basis. Ammonia can also result in the

formation of ammonium chloride salt. Corrosion control is discussed further below.

6.10 Wash Water

Wash water is added to the overhead system to dilute condensing acids and to dissolve salts that form by reaction of hydrochloric acid with neutralizing amines and with any ammonia in the system. An ideal design would be to position the wash water injection so that no condensation occurs upstream of the wash water injection location. In Saudi Aramco refineries, wash water injection is placed as near to the crude tower exit as possible, often high up on the vertical downcomer from the top of the tower.

Sufficient wash water must be added to ensure that at least 25% of the water remains in the liquid phase after injection at each and every injection point. It is essential to correctly design the volume of water required for a water wash. Process simulations of the design must be run to verify adequate water wash. Injection of insufficient wash water may cause corrosion problems by creating an artificial dewpoint and possible salting out of corrosive chlorides. In order to assure this during operation, the system must include the capability to

definitively measure the amount of water going to each and every location. Single pump systems in Saudi Aramco where one pump provides wash water to several different locations with little ability to measure or control the water have experienced problems in the past. In one case where a single pump fed water to both the tower overhead pipework and to the fin-fans, it was found that all the water was going to fin fans and zero was going to the overhead line.


Water wash injection sprays or quills should preferably be fabricated from corrosion resistant alloys. Cast spray heads have been made from a variety of alloys including stainless steels, though corrosion resistant alloys such as Incoloy 825 or Inconel 625 are preferred. CRA spray heads have limited

availability from manufacturers and sometimes have minimum order quantities. Stainless steel wash water quills in the Ras Tanura J-64 Khuff Gas Condensate Unit experienced chloride stress corrosion cracking and were temporarily replaced with carbon steel quills. These quills must be inspected on a much more frequent basis.

6.11 Coolers and Fin Fans

After water wash injection, the stream flows to coolers and an overhead receiver. The coolers are most commonly horizontal air coolers. The purpose of the overhead fin fans is to cool the overhead stream before it reaches the overhead receiver. Well designed and operated fin fans have a life expectancy of at least 15 years. Long banks of fin fans lead to poor distribution of wash water and insufficient neutralizer and inhibitor reaching some tubes. Improved fin fan life can be achieved by balanced piping systems that give even

distribution of all phases. In exiting systems, the installation of flow control valves may allow more effective balancing of heat exchanger flows. Some air coolers use a supplemental periodic wash of a bank of tubes at a sufficient velocity to remove tube deposits.

One source of the fouling and corrosion within the system which will also affect the fin fans is system pH. When systems are operated for periods of time in the pH range of 6.8 to 7.3, the semi-protective iron sulfide film is unstable and the tube material is more vulnerable to corrosion. Oxygen contamination has been shown to contribute to corrosion in some crude unit air coolers. Oxygen contamination results in the deposition of sulfur that interferes with the effectiveness of the corrosion inhibitor package.

One refinery uses a vertical heat exchanger rather than horizontal air cooler to cool the overhead flow. The vertical design is preferred as it is less prone to fouling deposits and corrosion.

The corrosives in the fin fans and coolers are the same as those in the overhead. Corrosion control is achieved by chemical neutralization, chemical inhibition, and water wash. Internal tube coatings offer an excellent means to extend tube life and may be applied to a new air-cooler bundle or to a bundle undergoing renovation. Internal tube coating has been adopted as a best practice by the Refining Corrosion Best Practices Team. Full length metallic inserts are also an effective repair method and have been used in Saudi Aramco.


6.12 Overhead Receiver

The overhead receiver is the last piece of equipment in the overhead system. The receiver separates hydrocarbon from water. Most of the separated hydrocarbon is used as naphtha but part of it is recycled (reflux) to the crude tower. The reflux should be dry to avoid corrosion in the crude tower. Provided that corrosion is adequately controlled within the system, the water accumulated in the water boot is low in total dissolved solids (TDS) and is a good source to be used as wash water in the overhead system.

The capacity of the overhead receiver has to be sufficient to handle and separate the overhead hydrocarbon. The residence time of water in the water boot should be 4 to 5 minutes. The capacity of the receiver has to be considered before increasing the unit’s charge rate.

Some overhead systems may actually be constructed with dual overhead receivers, where the vapor line from the first overhead receiver is taken to additional coolers and a second overhead receiver. Chemical injection for corrosion control must be done wherever condensation may occur, and chemicals injected ahead of the first receiver will be removed with the liquid phase. Therefore, supplemental injection may be required on the second overhead line.

7 Damage Mechanisms

Figure 4 shows the most common damage locations in a typical atmospheric crude dilation unit. At lower temperatures at the top of the column and through the overhead system, hydrochloric acid condensation is dominant. At higher temperatures,

sulfidation is the principle damage mechanism. Naphthenic acid corrosion can also occur in refineries around the world; however, it has not yet been discovered to be an issue in Saudi Aramco refineries.

Figure 5 shows a more detailed diagram of all recognized corrosion mechanisms based on API RP 571. Not all these mechanisms occur in Saudi Aramco Refineries, but many of them are possibilities.


Figure 4: Principal Damage Mechanisms in a Crude Unit


Figure 5: Recognized Damage Mechanisms for a Crude Unit, API RP 571


7.1 Hydrochloric Acid Corrosion

Hydrochloric acid corrosion occurs where liquid hydrochloric acid condenses in cooler parts of the crude distillation column, overhead pipework, or overhead system heat exchangers/coolers. Crude feeding the refineries contains water and inorganic salts (magnesium, calcium, and sodium chloride). Arabian Light crude usually has a salt content of 2-10 PTB and 0.05-0.2 % BS&W.

Hydrolysis of magnesium and calcium chlorides occurs while heating the crude unit in the pre-heat exchangers and fired heaters. This leads to the formation of hydrochloric acid (HCl) as in the following chemical reactions:

MgCl2 + 2H2O Î Mg(OH)2 + 2HCl > 120ºC (250ºF) CaCl2 + 2H2O Î Ca(OH)2 + 2HCl > 205ºC (400ºF) NaCl + H2O Î NaOH + HCl > 230ºC (450ºF)

Magnesium chloride starts to hydrolyze above 120ºC (250°F) and at fired heater exit temperatures about 360-380ºC (680-716ºF), the reaction is about 95 percent complete. However, only about 15% of calcium chloride will hydrolyze at these temperatures. Sodium chloride starts to hydrolyze at about 230ºC (450ºF) but does not hydrolyze as


Effectively, as shown in Figure 6. Therefore, sodium chloride is considered to be essentially stable at fired heater temperatures. HCl that forms will enter the overhead as vapor. In the overhead system, corrosion from HCl acid occurs as the first droplets of water condense from the vapor stream as it cools below the water dew point temperature. This water can have a very low pH and can result in high rates of corrosion.

In addition to corrosion caused by hydrolysis of inorganic chloride salts, organic chlorides may also contribute to corrosion. Organic chlorides are also called “undesaltable chlorides” because they are not removed in the desalting process. They are released by heating downstream of the desalter and cause corrosion and fouling. Sources of organic chlorides include oil field chemical treatments and recirculation of contaminants from refinery processes.

The primary method of control is to remove magnesium and calcium chlorides to prevent their hydrolysis in the heaters. This is achieved by effective crude management, minimizing the amount of field water in the crude, washing the crude with relatively fresh water in the desalter and then separating as much water as possible in the desalter. In some systems, caustic is added upstream of the desalter and may help in removing magnesium and calcium salts.

Demulsifier added to the desalter helps separate water and therefore reduces salt. The secondary method of corrosion control is to add caustic at a location

between the desalter and the heater. The exact mechanism is unclear but most authorities propose that caustic reacts with HCl as it is formed. Others propose several intermediate reactions. Another proposal is that caustic precipitates the calcium and magnesium salts preventing their hydrolysis.

The third method of corrosion control is to chemically treat any hydrochloric acid that is formed and condenses in the crude unit overhead system. A neutralizing amine is used to co-condense with the first droplets of acid in the overhead. The objective of the neutralizing amine is to raise the pH of these condensing droplets to about 5.5 to 6.5. At this pH, the liquid is less corrosive. Also at this pH, film-forming corrosion inhibitors can be used to further reduce corrosion.

The fourth method of corrosion control is to prevent under deposit corrosion through the continuous use of wash water to help carry solids through the system. The use of wash water also forces the condensation of hydrocarbon and water and dilutes the hydrochloric acid.

The addition of treating chemicals: caustic, neutralizing amine, and

film-forming inhibitors, means that for effective control, system operating conditions should fluctuate as little as possible. Fluctuating system conditions require


frequent adjustments to chemical additives. This is difficult to achieve in a timely fashion. Also, chemicals that are added to the system must be of consistent quality. Of particular concern is the caustic that is usually made up on a batch basis by the plant.

7.2 Salt Formation

Ammonia and amines will react with chlorides to form salts. Neutralizers containing amines are deliberately added to the overhead system to control pH. Amines may also be available from tramp or contamination sources. Ammonia can be fed to the crude column through sour water or wild naphtha or in some companies, may be fed deliberately as a neutralizing agent. These reactions can occur in the vapor phase at a higher temperature than the water dew point resulting in precipitation of ammonium or amine chloride salts. These salts may form in the overhead system or in the crude distillation tower.

The salts may form as solids or also as liquids which can be found on tower trays. The salts are hydroscopic and can absorb moisture from the vapor phase resulting high corrosion rates. Corrosion rates in excess of 100 mpy (2.5 mmpy) can result.

This type of damage can be minimized by the addition of appropriately placed water wash, increasing the system temperature above the salt point, or by limiting the concentrations of the critical reactants. Alloys may reduce the corrosion rate somewhat.

Salting can be predicted by the use of ionic modeling programs. Various programs are available through chemical vendors. Salting on trays may be indicated by mal-distribution found by gamma scans. Salting in heat exchangers may be found by abnormal pressure drops.

7.3 Shock Condensation Corrosion

Shock condensation corrosion can occur when cold streams are injected into hotter process streams containing water and other corrosives. Naphtha reflux from the overhead receiver can be significantly colder (by perhaps 50ºC (100ºF) or more) than the tower top to which it is re-injected. The cooling provided by the naphtha condenses water from the fluids in the crude distillation column and corrosion results. Localized wall temperatures may be significantly different to bulk fluid temperatures that are indicated by thermocouples that project deep into a stream through a thermowell. In one case, a flowing stream with a nominal 138ºC (280ºF) thermowell temperature was found to have wall surface temperatures on the order of 85ºC (185ºF).


Cold naphtha reflux may also be used as a source for dilution of overhead film forming inhibitors. Over -dilution of the inhibitor stream, which can happen if the flow rates of both the inhibitor or the diluents are not measured, can result in the injection of large quantities of a colder stream which again may result in shock condensation corrosion.

Wild naphtha streams reinjected from other process units may also cause shock condensation depending upon the temperature and exact injection location.

7.4 Sulfidation

Sulfidation is high temperature wastage of carbon steels and other alloys due to their reaction with sulfur compounds. It is accentuated by the presence of hydrogen or mercaptans. Figure 7 shows corrosion rate data due to sulfidation for carbon steel with increasing temperature in a number of different crude oils. Based on this data, there is a 100-times increase in corrosion rate between about 290ºC and 380ºC (560ºF - 720ºF) for Middle East crudes. Figure 8 presents the modified McConomy curves for sulfidic corrosion of carbon steel and stainless steels. These data predict an increase in corrosion rate more on the order of 10 times for the same temperature range. Selecting 5Cr1/2Mo or 9Cr1Mo steel grades reduces the corrosion rate significantly, as shown in Figure 8.

Sulfidation is caused by hydrogen sulfide that is formed on heating the crude to high temperatures. The amount of hydrogen sulfide formed is not linearly related to the sulfur content of the oil. Therefore, the true corrosiveness of a crude must be determined by laboratory tests. Recent data for carbon steel suggest that sulfidation can be accentuated by the presence of mercaptans. The temperature for the on-set of increased corrosion when mercaptans are present is approximately 50ºC (100ºF) cooler than would be predicted by the McConomy curve.


Figure 7: Corrosion Rate of Carbon Steel in Various Crudes with Increasing Temperature (ºF)

Figure 8: Modified McConomy Curves for Corrosion Rate of Various Steels and Stainless Steels in 0.6 weight % Sulfur Containing Environment

& Corrosion Rate Multiplier for Varying Sulfur Content


Fuel ash corrosion is accelerated high temperature wastage of materials that occurs when contaminants in the fuel form deposits and melt on the metal surfaces of fired heaters. Fuel ash corrosion has been a source of failure in at least two Saudi Aramco refineries. Liquid fuels containing vanadium, sodium, and sulfur form low melting point slags that cause damage at temperatures in the region of 500ºC (930ºF) and higher. Fuel ash corrosion can be controlled by magnesium oxide/carboxylate treatment, reduced excess air, and reduced temperature. Alloys can be used if necessary. An effective soot blowing program is essential.

7.6 Carburization

Carburization is the absorption of carbon into a metallic structure at elevated temperature caused by contact with a carbon-containing material. Typically this occurs typically above 590ºC (1100ºF) in a carbon rich environment such as a heavy crude oil. Carbon enters the matrix resulting in a change in mechanical properties. These changes may become most evident on rapid shutdown or start up. To evaluate the presence of carburization, a sample of tube must be cut out.

7.7 Creep

Creep is the slow continuous deformation of metal components that can occur at high temperatures when materials are stressed with loads less than their yield stress. Overheating heater tubes, supports, and related equipment can result in various types of permanent damage including creep. Initial damage morphology can only be detected by metallography. Later stages include bulging and


Figure 9: Creep Damage

7.8 Sulfur Oxy-acids

Sulfurous and sulfuric acids can form when the system upstream of the heater is contaminated with oxygen. Sources of oxygen include oxygenated desalter wash waters, or contaminated water returning to the API separator. Sulfurous and sulfuric acid typically have higher dew points and therefore can condense more readily than hydrochloric acid. This type of corrosion may be present in the top of colder crude towers and in the overhead system.

7.9 Carbonic Acid Corrosion

Carbonic acid corrosion is a potential cause of overhead corrosion, carbon dioxide originating from carbonates in the crude feed or from the decomposition of organic acids. It has been suggested that Northern Area Production contains some carbonates resulting in somewhat increased use of neutralizer with Medium and Heavy grades.

7.10 Sodium Hydroxide (Caustic)

Sodium hydroxide (caustic) can cause severe flow-induced corrosion of carbon steel at elevated temperatures. Corrosion rates on the order of 1,500 mpy have been experienced in Saudi Aramco facilities at about 260ºC (500ºF). Injection immediately upstream of the fired heater, therefore, is not the first choice location to inject caustic as any impingement on the pipe wall can lead to rapid failure. See the Saudi Aramco Chemical Injection Best Practice, SABP-A-015, and Section 8 and Appendix 1 of this document for further information on caustic injection. General corrosion will also occur if high concentrations are injected downstream of the desalter. Caustic also contributes to fouling if the injected stream is too high a concentration.

7.11 Caustic Stress Corrosion Cracking

Caustic also causes caustic stress corrosion cracking of carbon steels, austenitic stainless steels, and alloys including Incoloy 825. Caustic stress corrosion cracking of carbon steel has been reported when higher concentrations are injected even immediately downstream of the desalter. Therefore, for caustic injection, use Monel 400 or Inconel 625. Stress relieve all carbon steel pipework downstream of the caustic injection point. Caustic cracking regions for various alloys and various steel heat treatments are shown in Figure 10. NACE International’s Recommended Practice RP 0403 - 2003 addresses measures to avoid caustic cracking.


Chloride stress corrosion cracking may occur in systems where austenitic

stainless steels are exposed to chloride containing environments at temperatures, most commonly, in excess of 60ºC (140ºF).. Generally, chloride concentrations below 50 ppm are considered to be of little risk, except in circumstances where concentration may occur. Failures can be reduced by minimizing stress (higher wall thickness). The failure shown below in Figures 11 and 12 occurred in Type 316L stainless steel. Material upgrades or downgrades provide a permanent solution. The quill below will be upgraded to Inconel 625 as soon as material becomes available. Temporarily, carbon steel quills were installed; however, these require more frequent inspection. Connecting pipework was downgraded to carbon steel, and some general corrosion accepted as a result. The two photographs (Figure 11, Figure 12, below) are from a failure in a condensate distillation unit overhead system, where the quill was used to inject recirculated process water ahead of each fin fan cooler.

(Reference: Environmental Cracking: Learning from Failures—Graham Lobley & Robin Tems, 11th Middle East Corrosion Conference, Bahrain, February 2006, Bahrain Society of Engineers & NACE).


Figure 11: Chloride Stress Corrosion Cracking of a Water Injection Quill

Figure 12: Chloride Stress Corrosion Cracking of a Water Injection Quill

7.13 Wet H2S Damage

Wet H2S damage includes sulfide stress cracking (SSC), hydrogen induced cracking (HIC) and stress oriented hydrogen induced cracking (SOHIC). In general, these are minor have problems in crude units. NACE RP 0296 reports that only 18% of crude units experience wet H2S problems, the lowest


inhibited and neutralized to a neutral, pH, so little damage would be expected. However, any location that could experience wet sour service must use materials and welding procedures necessary to avoid each of the failure mechanisms. These are defined in SAES-L-133, SAES-A-301, 01-SAMSS-016, SAES-W-010, and SAES-W-011.

7.14 Downtime Corrosion

One joint venture refinery experienced very high corrosion rates of the crude tower when it was shut down, steamed out and left open to the atmosphere. It is postulated that ammonium or amine chloride deposits were wetted and became highly corrosive during the several week shut down. This has not been reported as a problem in Saudi Aramco refineries where salt formation has not been reported as being a major concern.

The corrosion product that forms during crude unit operation is most commonly iron sulfide. Iron sulfide can be pyrophoric, though this has not generally been a problem in Saudi Aramco crude units.

8 Control of Corrosion by Chemicals

8.1 Chemical Injection

Chemical injection must be performed following the requirements of Best Practice A-015 and the recommendations in this document. Errors in chemical injection can result in fires, inadequate chemical treatment, or corrosion damage to the system.


SARCOP, the Saudi Aramco Refineries Chemical Optimization Program, is the program that governs the purchase and application of corrosion control

chemicals in Saudi Aramco refineries. The form of SARCOP is a team building structure where vendor personnel, refinery personnel, Refining Planning and Technical Staff, and Engineering Services work in a cooperative environment to maximize refinery safety, profit, and reliability. The contract for each refinery is awarded for a term of three to five years on a competitive basis through normal Purchasing Department procedures but covering service aspects in addition to the supply of chemicals and equipment. Each refinery has its own SARCOP Team. SARCOP covers both water treatment chemicals and process corrosion control chemicals. All chemicals used in the crude unit for corrosion control must be supplied through the contracted agreements of SARCOP. All chemicals used must be approved by Consulting Services Department. New technologies available from alternate vendors may be used, but the procedures


of SARCOP must be followed. SARCOP does not cover catalysts or bulk chemicals such as amines for amine systems.

8.3 First Fill Chemicals

New construction projects developed by Project Management Teams provide chemicals for corrosion control for the initial operation of the new unit. All chemicals must be reviewed and approved by the refinery SARCOP team and CSD. Unless there are exceptional circumstances, the existing SARCOP chemical vendor for that refinery shall supply the first fill corrosion control chemicals.

8.4 Tank Aids and Desalter Aids

Tank aids may be used to assist in settling water or to assist in redissolving sludge. Desalter aids can be used to help break emulsions in the desalter. To date these have only been used on a limited trial basis in Saudi Aramco facilities.

8.5 Caustic Upstream of Desalter

Caustic may be added upstream of the desalter in the wash water feed to the desalter to adjust desalter pH. Caustic injected upstream of the desalter can contribute to emulsions in the desalter. Some of this caustic will be carried though with the crude charge but the great majority will be discharged with water from the desalter. Critical factors are (1) Excellent quality control on the concentration of caustic and the volumes injected including on-site tests of caustic strength, and (2) Elimination of oxygen through gas blanketing. Caustic is injected through a Monel 400 quill.

8.6 Caustic Treatment between the Desalter and Heater

Caustic is added between the desalter and the heater to help minimize hydrolysis of chloride salts remaining in the crude charge. Correct treatment with caustic will reduce overhead corrosion significantly. Incorrect treatment with caustic will cause significant problems. Over-treatment with caustic immediately after the desalter can result in fouling of the heat exchangers. Over-treatment in any location can result in and stress corrosion cracking of pipe and equipment. It may also result in excessive sodium in crude tower bottoms. Sodium can affect downstream catalysts in FCC and hydrocracker units. Sodium can cause coking and fouling in Visbreakers. The sodium content of the Visbreaker feed must be less than 50 ppm. A lower level below 25 ppm is preferred if achievable.

Injection immediately downstream of the desalter: Caustic injection

downstream of the desalter is an effective method to reduce overhead corrosion. Various reaction mechanisms have been proposed. Most commonly, it is


assumed that caustic reacts directly with HCl as it is formed. Others suggest that caustic converts undesirable salts (MgCl2 and CaCl2) to form less soluble hydroxides, which would provide an explanation of fouling that occurs after caustic injection.

Caustic injected at this location must be thoroughly mixed with the crude stream. This is best achieved by use of a crude slip stream and static mixer. The crude slip stream should preferably be obtained from a location after the desalter to eliminate un-desalted crude from being re-injected into the stream. In some cases, injection into the crude pump suction has had an equally effective mixing role as using a slip stream. Inadequate mixing can result in excessive fouling of heat exchanger trains.

Caustic is injected at a low concentration, of the order of 1 to 5 weight percent. This low concentration requires a greater volume, and this aids effective mixing with the crude stream. The injection of a low concentration also reduces the risk of caustic corrosion and caustic stress corrosion cracking. In order to minimize fouling of the heat exchangers, it is critical that caustic quality be strictly controlled. At refineries where there are large fluctuations in caustic quality, heat exchanger fouling and caustic stress corrosion cracking have occurred. Equipment immediately downstream of the injection location must be post weld heat treated (PWHT) to minimize the risk of caustic stress corrosion cracking. However, even PWHT pipework is not immune from cracking in high

concentration caustic streams. Caustic injected downstream of the desalter caused caustic cracking of three non-stress relieved heat exchanger shells and one pipe weld at one refinery. Subsequently, the injection location was moved to upstream of the fired heater. In a second refinery, two downstream bends in the crude line failed from caustic stress corrosion cracking following the

inadvertent injection of higher strength (14 Be) caustic for at least two months. The root causes of this failure included the use of too small a day tank and the use of a common caustic distribution header that allowed contamination with more concentrated caustic (ref: CSD/ME&CCD/L-1075/02). The

implementation of routine measurements of caustic strength in the unit day tank would also allow problems like this to be discovered immediately.

A Monel 400 quill is required for caustic injection. Such quills have an expected service life well in excess of ten years in this location. Alloy 625 would be an alternative but has not been used in Saudi Aramco refineries. The measured chloride content in the overhead accumulator water controls caustic addition downstream of the desalters. The target range is 10-30 ppm Cl- in the accumulator water. Currently, at most Saudi Aramco refineries, operators adjust the caustic rate when a chloride reading is out of specified limits.





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