saer-5941

SAUDI ARAMCO ENGINEERING REPORT

SAER-5941

Final Report and Guidelines on Crude Unit Overhead Corrosion Control

March 3, 2004

ENGINEERING SERVICES

Ahmed M. Al-Zahrani, Team Leader Saleh A. Al-Amer

Khalid J. Al-Anazy Abdulkareem A. Al-Dabass

Wail M. Al-Gahwagi Faisal M. Al-Faqeer Adeeb N. Al-Hindas Yahya T. Al-Janabi Graham R. Lobley Khalid S. Al-Otaibi

Robert E. Palmer Rakan Al-Shammary

Hamad A. Al-Sobhi Robin D. Tems

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EXECUTIVE SUMMARY

Corrosion in the overhead system of crude units is a common problem in refineries worldwide. Crude unit overhead corrosion control is very closely related to the control of chlorides in the crude feed to the atmospheric column. Controlling chlorides in the crude unit starts in the tank farm with proper settling time and continuous water drainage. It continues with optimization of the desalter operation. Caustic injection is also used to convert chlorides to sodium chloride that is stable at high temperatures and therefore far less damaging to the overhead system. All Saudi Aramco refineries, except Ras Tanura Refinery, have partially or completely replaced crude unit overhead lines in the last five years. Yanbu Refinery replaced the overhead line in 1997 and again in December 2003. Jeddah Refinery replaced the overhead line of Crude Unit #2 in 1997 and resized it in 2003. Rabigh Refinery replaced the line in 1998 and will replace it in March 2004. Riyadh Refinery replaced the overhead line in 2003 after more than 20 years in service. Optimization of corrosion management programs can significantly reduce the investment in plant maintenance costs including replacement of overhead systems. Corrosion management programs track corrosion control actions versus their effects on the corrosion rate. Through close tracking, the effects of changes in chemical treatment or process operations can be evaluated. Also, the remaining life of overhead systems can be more realistically defined and replacement programs optimized. Crude Units in Saudi Aramco refineries have different configurations and capabilities. SAER-5941 summarizes major differences and findings in all Saudi Aramco refineries. It also includes a section presenting an operation guidelines “Best Practice” to control crude unit overhead corrosion. Successful control of corrosion in crude unit overhead systems requires:

• Control of acid-forming chlorides that enter the crude unit through proper settling time and periodic drainage in the tank farm, effective desalting, and conversion of calcium and magnesium chlorides to more stable sodium chloride by using caustic injection.

• Adequate neutralization of acids that do form through the addition of neutralizing chemicals into the overhead stream.

• Addition of film-forming inhibitors to the overhead to reduce corrosion. These adhere to the metal surfaces and minimize contact between the process stream and the metal.

• An effective corrosion management program to track system operation and corrosion control actions versus corrosion rate, allowing the system to be optimized.

• Control of velocity in the overhead system.

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MECHANISM OF OVERHEAD CORROSION Causes of Corrosion 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 pounds per thousand barrels ( PTB) and 0.05-0.2 % Basic Sediment & Water (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 Mg(OH)2 + 2HCl > 250ºF

CaCl2 + 2H2O Ca(OH)2 + 2HCl > 400ºF

NaCl + H2O NaOH + HCl > 450ºF Magnesium chloride starts to hydrolyze above 250°F and at fired heater exit temperatures about 650 to 700°F, the reaction is about 95 percent complete. However, only about 15 percent of calcium chloride will hydrolyze at these temperatures. Sodium chloride starts to hydrolyze at about 450°F but does not hydrolyze as effectively, as shown in Figure 1. Therefore, sodium chloride is considered to be essentially stable at fired heater

0 10 20 30 40 50 60 70 80 90

100

200 300 400 500 600 700 800

Temperature, oF

Percent Hydrolyzed

Magnesium Chloride

Calcium Chloride

Sodium Chloride

Figure 1: Hydrolysis of Chloride Salts to HCl

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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 dewpoint 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. Control of Corrosion The primary method of control is to remove magnesium and calcium chlorides to prevent their hydrolysis in the heaters. This is achieved by good 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 precipitating magnesium and calcium salts. 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.

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Other Factors Affecting Corrosion and its Control Velocity plays a significant factor in removing semi-protective ferrous sulfide corrosion product films in the overhead system. Inhibitor films can also be removed in higher velocity systems. Therefore, systems that run at higher velocities will be more prone to damage. Welds can result in added turbulence and therefore increased erosion-corrosion effects. For prefabricated pipe spools, this can be reduced by grinding weld profiles smooth during fabrication. This improvement is limited to larger pipe sizes with adequate access. Tests have shown that the grinding action has no bad effects on the pipe metallurgy. Sulfur present in the crude oil as inorganic or organic compounds converts to hydrogen sulfide which has a significant impact on corrosion. A hydrogen sulfide evolution test can be performed to determine the amount of hydrogen sulfide released by heating each crude type. Oxygen contamination of the process significantly increases corrosion due to the oxygen corrosion reactions, precipitation of elemental sulfur in the system, and reduced effectiveness of the film forming corrosion inhibitors in the oxygen containing environment. Oxygen may react with sulfur species to form SOx which can also contribute to the overhead corrosion processes.

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CORROSION CONTROL IN SAUDI ARAMCO CRUDE UNITS

Data Collection The data presented in the following sections were collected from the individual plants through survey forms and interviews on-site with operational and engineering personnel. As with any survey of this type, certain individual perceptions or recollections of operating practices may vary from others. Where possible, reported procedures were checked against refinery instruction manuals, though in many cases this was not possible. Crude Transportation All Saudi Aramco refineries receive crude oil from Abqaiq Plants. All refineries other than Ras Tanura receive their crude from Abqaiq via the East-West Pipeline system to Yanbu. From Yanbu, crude is shipped by sea tanker to Rabigh Refinery and Jeddah Refinery. Prior to 1999, contamination with seawater ballast was possible during this trans-shipping operation. Reportedly, this is no longer a problem due to changes in the shipping operation. The East-West Pipeline is used to ship multiple products and there have been some problems with microbially induced corrosion (MIC) so the stream is treated with biocide. Typically, biocides contain quaternary ammonium chlorides. These are organic chlorides that may impact corrosion in refineries taking feed from the East-West Pipeline. Ras Tanura Refinery receives about 200,000 barrels per day of Arab Light crude from Abqaiq through a dedicated pipeline. In addition, the plant runs crude following the monthly direction of OSPAS. Most commonly, the feed includes 100,000 barrels of Arab Extra Light from Berri. When increased asphalt production is required, 100,000 barrels per day of Arab Medium is supplied from GOSPs in Northern Area Production. Crude Unit Design Most of the crude units in Saudi Aramco are operated at rates higher than their original design capacities. While various modifications may be made to allow operation at higher throughputs, the effect of the increased throughput on corrosion control is often overlooked. Some areas of concern include the following:

• Residence time in crude tank farms and desalting operations may be reduced.

• Residence time in preheaters may be reduced resulting in low desalting temperatures and less effective desalting.

• Availability of sufficient quantities of wash water for the higher production rates may be limited.

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• Velocities in the overhead piping may become excessive.

• The ability to effectively separate streams in the overhead hot receiver may be impaired resulting in stream contamination and recirculation of water to the crude column.

Table 1 compares the original design with the current operating capacity.

Table 1: Crude unit throughput changes from original design

Original Design (MBD)

Current Operation (MBD)

% Over Design

RTR 250 325 30

RR 100 113 13

YR 170 225 32

RBR 325 370 14

JR CDU2 33 43 30

JR CDU 3 20 19

JR CDU 4 20 19

Crude Handling and Dehydration Proper tankage dehydration is the first step in achieving good corrosion control in the crude overhead system. If water is not effectively removed from crude oil tanks, crude unit upsets may result. The upsets may take the form of water hits and/or chloride hits to the desalter. High water or salt content in the raw crude typically leads to higher water or chlorides in the desalted crude. This may then result in accelerated corrosion. Yanbu, Jeddah and Rabigh refineries’ crude tank system allows some time for gauging, settling and dewatering as shown in Table 2. On the other hand, Ras Tanura and Riyadh Refineries reported limited time for gauging, settling and dewatering. Yanbu and Rabigh refineries inject slop oil to the crude tanks. Other refineries inject slop oil to dedicated tanks or to sales tanks. Injection of slop oil into crude tanks leads to potential difficulties in corrosion control due to possible contaminants in the slop oil. Direct injection into the crude tank means that a large volume of crude can be contaminated by the slop oil, and therefore control becomes more difficult. It is possible to blend slop oil direct into the crude oil feed pipework to the unit. If a system upset

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occurs due to quality of the slop oil, the slop oil feed is isolated and the problem resolved quickly. Operations reports for Riyadh, Rabigh, Yanbu, and Jeddah Refineries show a significant fluctuation of chlorides when the unit charge is switched from one storage tank to another. Ras Tanura Refinery crude tank system has a running gage process where the crude enters and exits the tank without having a settling time. This gives RTR similar crude all the time. It is also noted that although the running gage system has generally worked well for RTR, this operation resulted in a one-day emergency shutdown in September 1998 due to a large water slug. Table 2 shows crude handling at the five refineries.

Table 2: Crude tank farm handling data

Crude Tank Settling Time (hrs)

Crude Tank Gauging Time (hrs)

Crude Tank Draining Time (hrs)

RTR 0 0 0

RR 0 0 0

YR 6 6 18

RBR 24 12 12

JR Up to 24 ? ?

The use of mixers in crude oil storage tanks during the filling operation helps to redissolve heavier sediment and reduce sludge accumulation at the bottom of the tank. Sludge layers at the bottom of the tank can affect water drainage. Dewatering chemicals are used in some refineries worldwide but not presently in Saudi Aramco refineries. Dewatering chemicals improve water settlement and reduce the load on the desalters. These products could be evaluated at selected refineries. Desalter The primary purpose of the desalter is to wash salts out of the crude oil using water. By effectively mixing the water with the crude then separating the water from the crude, the water-soluble salts are removed from the crude oil and flushed out of the system in the brine water. 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. Effective desalting is enhanced by factors that include elevated temperatures, effective mixing on entering the

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desalter, sufficient residence time, the use of electrostatic plates to enhance water droplet settling, and continual removal of sludge from the desalter. Table 3 shows the details of refineries’ desalter operations.

Table 3: Desalter data

No. of Desalter Trains No of Desalters Per Train

RTR 1 1

RR 1 1

YR 2 2

RBR 2 2

JR 1 for each crude unit (CDU2/3/4) 1

Caustic Addition Caustic is injected at one or two points in a crude system. Caustic may be injected upstream of the desalters. Additionally, it is always injected at a location between the desalter and the fired heaters. The location of this second 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. Over-treatment with caustic after the desalter can result in equipment fouling or 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 Nalco Best Practice limits sodium to 25 ppm in the Visbreaker feed. Others recommend a maximum of 50 ppm in the Visbreaker feed and a target of 25 ppm.

Injection Upstream of the Desalter: Caustic injection upstream of the desalter controls the pH of the brine. It may also contribute to corrosion control by converting CaCl2 and MgCl2 to insoluble hydroxides. However, this effect is considered to be small. Caustic injected upstream of the desalter can contribute to emulsions in the desalter.

Injection 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 before they enter the crude unit tower.

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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 undesalted crude from being reinjected 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 usually 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 Ras Tanura 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 preferred for caustic injection at this location. Such quills have an expected service life well in excess of ten years. 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. However, the injection rate is usually limited to a maximum of 2 PTB (pounds per thousand barrels) to prevent downstream fouling.

Injection Upstream of the Heater: Caustic injection upstream of crude heater is an alternative if heat exchangers downstream of the desalter experience severe fouling. However, there are increased risks from caustic injection at these higher temperatures. Therefore, within the industry, only about 20 percent of refineries have adopted this method of caustic injection. ChevronTexaco is the most significant proponent of this injection methodology. For contrast, Shell’s Best Practice specifically requires caustic

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injection at temperatures less than 350°F. Nalco’s best practice limits caustic injection to a temperature of less than 300°F.

Caustic at elevated temperatures is extremely corrosive and can corrode the injection quill or the pipe wall itself if the quill is incorrectly positioned. Further, caustic may cause caustic embrittlement of non-stress relieved pipework and heater tubes. Injection of caustic at this location requires precision engineering and operation. Caustic of consistent strength and quality must be thoroughly mixed with a slip stream of crude, ensuring thorough mixing with the use of a static mixer. Injection is achieved via Monel 400 pipework, valves, and quill. The crude slipstream must be carefully monitored to ensure that the caustic stream is not injected un-mixed into the main crude line. The Monel 400 quill will experience some minor sulfidation on the process side at these temperatures, in the region of very approximately, 500°F. An Alloy 825 quill has also been used in this service but failed rapidly. The injection quill itself must be carefully aligned in the center-third of the pipe. The location of the quill must be checked by radiography and the radiograph stored as a permanent record. The nozzle must be oriented to discharge downstream. A match mark indicator must be part of the quill to aid alignment. Failure to correctly execute every detail at this injection temperature can result in a disaster. In Ras Tanura Plant 11, a long injection quill was inserted that resulted in caustic impinging on the opposite side of the pipe. The wall rapidly corroded and the resultant fire destroyed the crude unit. In Rabigh Refinery, a poorly engineered and constructed injection quill was modified on-site by cutting long slits in the quill. The caustic flowed along the pipe wall and perforated it. A small fire resulted. A replacement quill from Alloy 825 failed quickly. Table 4 shows the details of refineries’ caustic injection systems.

Table 4: Caustic injection systems

Upstream of Desalter

Downstream of Desalter

Upstream of Crude Heater

RTR No No Yes

RR No Yes No

YR Yes Yes No

RBR Yes No Yes

JR Yes Yes No

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Yanbu refinery is evaluating the relocation of the caustic injection from downstream of the desalter to upstream of the heater. Jeddah Refinery has previously considered relocation of caustic from downstream of the desalter to upstream of the heater. However, a more detailed investigation found that the heater tubes were not post weld heat treated, therefore making relocation unadvisable due to the high risk of caustic cracking. Preheat Exchanger A typical crude unit system has multiple sets of pre-heat exchangers. The first exchanger train heats the crude to the optimum desalting temperature while recovering heat from internal reflux and final product streams. The rest of the pre-heater trains are after desalters and before the fired crude heaters. These exchangers are primarily to recover heat from the final product, save fuel consumption in the furnaces and to reduce the heat load on the fin fan exchangers that cool the product streams to storage temperature. Usually the first set is before the crude desalter and the second and third (if present) are after the desalter. Caustic injection between the desalter and the second set of preheat exchangers can result in fouling of the exchangers. Jeddah and Yanbu Refineries have reported fouling difficulties. Clearly, fouling of preheaters could be reduced by adding the caustic immediately upstream of the heater, as is done at Rabigh and Ras Tanura. However, fouling can also be reduced by adequately controlling caustic injection downstream of the desalters more carefully. Jeddah Refinery has discovered wide variations in the concentration of caustic being delivered to the crude unit. This is the principal cause of fouling and also results in poor corrosion control. Crude Column The top dome of the crude unit column is usually clad with Monel 400 (or other corrosion-resistant) material that has good corrosion resistance. Also, the top trays in the column are often made of Monel 400 materials. Jeddah Refinery has experienced severe corrosion on the top dome and top trays in crude unit # 2. The probable cause of this was recirculation to the crude column of a high percentage of water (over 50%) in the naphtha reflux. Following correction of the water carry-over problem, corrosion of the Monel trays was eliminated. Rabigh Refinery also reported damage to the Monel-clad dome. Overhead Line Table 5 shows the recent replacement histories of the overhead lines in Saudi Aramco refineries. Overhead lines experience flow-enhanced corrosion (also known as erosion-

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corrosion) due to hydrochloric acid condensation. Such damage occurs because the flow effects help to remove loosely adherent semi-protective corrosion product films. This reveals fresh metal surfaces that continue corroding. Inhibitor films can also be removed. Corrosion losses are often not uniform within each system. Often problems are manifest at elbows or bends or immediately downstream of these features where flow effects are accentuated. Sometimes damage occurs downstream of poorly matched welds or high weld beads.

Table 5: Replacement histories for overhead lines

Overhead Line Replacement Overhead Line Diameter, inches

RTR Not replaced 48

RR Replaced in September, 2003 30

YR Replaced in 1997 and

Resized in December 2003

30

36

RBR Replaced in 1998 and it will be replaced on 2004

48

JR CDU2 Replaced in November 1997

Resized in April 2003

20

24

JR CDU 3 Parts of the line were replaced in 1997, 1999 and 2000 after

demothballing 1997

6

JR CDU4 Part of the line was replaced in November 2001 after demothballing

6

The decision to replace an overhead line may be taken with extremely limited information. There is resistance to collecting adequate inspection data during the period between T&Is. This is exacerbated by the inaccessibility of many overhead systems that makes evaluation of corrosion trends difficult. There is a tendency to be cautious and replace systems to ensure that a full run is obtained until the next T&I. Many Saudi Aramco refineries lack adequate or working corrosion monitoring systems that would help identify system upsets and allow more effective corrosion mitigation.

Effect of Velocity: Opinions vary in the industry as to the optimum fluid stream velocity in an overhead system. Generally, velocities less than 100 feet per second are deemed appropriate for carbon steel. Corrosion resistant alloys have been reported to be

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serviceable at velocities at least up to 150 feet per second. For carbon steel, lower velocities will be beneficial in minimizing damage from erosion-corrosion, so that velocities of 50 to 75 feet per second would be expected to result in a longer service life than for a system operating at 100 feet per second.

For a new crude unit, a target velocity of 75 feet per second would be a reasonable design maxim. For retrofitting existing crude units, certain compromises may be necessary. Maximum pipe sizes may be limited by factors such as nozzle diameters on the crude column or by structural aspects of pipe support, so less than optimum designs may be required.

Table 6: Overhead Line Velocities and Temperatures

Overhead Line Velocity, feet per second Overhead Top Temperature, oC

RTR 84 130

RR 65 122-132

YR 141 122-132

RBR 90-100 116-120

JR CDU2 20” line with water in naphtha reflux: 200 - 300

20” line with no water in naphtha reflux: 90

24” line with no water in reflux: 63

120

JR CDU 3 50 110-120

JR CDU4 50 110-120

Calculation of the velocities within an overhead system is also an area of some debate. Vendors and engineering organizations have proprietary programs to calculate overhead velocities which can lead to a range of answers. Further, real time current data are often not available to insert into the program. Calculations must include all feeds into the crude column, including intentional additions such as stripping steam and unintentional additions such as water carryover in the naphtha reflux.

Dew Point Temperature: Calculated water dew points are generally below the overhead line highest temperatures. However, a higher margin helps to eliminate the possibility of condensation prior to the water wash. Chevron specifies an overhead temperature of 132°C to avoid dewpoint corrosion. Also, liquid droplets may be entrained in the vapor stream leaving the crude tower especially under circumstances where the tower is operating above design capacity or is highly loaded with water, as was

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the circumstance in Jeddah Refinery until water was eliminated from the naphtha reflux. Further, all sources of water must be included in the calculation of dewpoint temperatures, including stripping steam and unintentional carryover.

Condensation may also be triggered by the injection of cooler liquids into the overhead system. The filming inhibitor is injected in a naphtha slip stream and could promote condensation by cooling the total overhead stream. Table 6, above, shows the summary of crude units’ top temperatures.

Corrosion Control Program: The overhead corrosion control program consists of the following:

a) Neutralizing Amine: Nalco 5151 is introduced into the overhead line to neutralize the strong acids that cause very low pH and high corrosion rates at the water dew point. The objective is to control the pH in the overhead receiver water at a pH of 5.5 to 6.5. Nalco 5151 should be injected into the top of the crude column overhead vapor line through an injection quill with steam to distribute and atomize the neutralizing chemical. The target pH range of 5.5 to 6.5 is the range commonly used in the industry. However, some companies have adopted different ranges. NACE reports the range to be 5.0 to 7.5. Chevron uses a target range of 7.5 0-8.0. This higher pH is achievable in systems using ammonia for neutralization but is not cost effective in Saudi Aramco systems where a neutralizing amine is used.

b) Filming Amine: Nalco 5186 is added to provide a protective film, or barrier, between the metal surface and the corrosive liquids in the overhead system. Injection rates are set to add the filmer at 3-5 ppm based on total overhead naphtha rate. The product is injected into the overhead line through a quill with a naphtha slipstream with a dilution between 50 and 100 naphtha to 1 inhibitor. While many filming inhibitors perform well at the target pH of 6.5, there are some exceptions. As the pH becomes more acidic, these differences in inhibitor performance become even more extreme. Figure 2 shows a comparison of three overhead filming inhibitor packages over a range of pH. There is a clear difference in the performance of the products, with Product A being superior (ref: CSD/ME&CCD/C-04/99).

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Figure 3 shows the actual samples after testing at a pH of 5.5, which is still within our target pH operating range. Note the bright, undamaged coupon test with Product A. Product B resulted in extensive localized corrosion in this test.

Figure 3: Coupon tests at pH 5.5

Figure 2: Inhibitor Data, General Corrosion, 72 Hours

0

200

400

600

800

1000

1200

1400

2 3 4 5 6 7pH

Cor

rosi

on ra

te, m

py

A

B

A

B

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c) Wash Water: Continuous water wash is used in the overhead line to help quench and scrub the overhead vapors, dilute acids formed, and keep any salts or acids from accumulating in the system. Low water wash rates can be more harmful than beneficial. The water rate must be high enough so that the bulk of the water does not flash at system conditions when injected. The water wash rate must be sufficient to maintain at least 25 percent of the total water injected as liquid water. Typically a wash water rate of 4 to 6 percent of total naphtha stream volume is needed to meet this 25 percent liquid water requirement.

Overhead Fin Fans The purpose of the overhead fin fans is to cool the overhead stream before it reaches the overhead receiver. The estimated life of the fin fans in Yanbu Refinery, Riyadh Refinery, and Ras Tanura Refinery is 15 years. The Ras Tanura design is unusual in that a vertical heat exchanger and a knock-out drum are located ahead of the fin-fans. The estimated life of the fin fans in Jeddah Refinery and Rabigh Refinery ranges from 3 to 12 years because of fouling and corrosion. Poor flow distribution, where most of the hydrocarbon goes to the inner bundles and the outer bundles see low or no flow, is one major contributor to fouling and corrosion in these exchangers. At Jeddah Refinery, flow distribution has been improved by the installation of butterfly valves in the distribution header. The use of internal coatings on new tube bundles would be an excellent way to extend air cooler life. Another 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. 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.

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Provided that corrosion is adequately controlled within the system, the water accumulated in the water boot is low in 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. During the evaluation of all five refineries, the adequacy of the overhead receiver was calculated. It was found that the water boot size of Yanbu Refinery and Rabigh Refinery overhead receivers would need to be increased in order to provide 4 to 5 minutes residence time. Corrosion Management Program Corrosion management requires an integrated approach that combines inspection, monitoring, and system data to optimize the corrosion control program. While aspects of a corrosion management program were in place at each facility, nearly all facilities were lacking in one or more key areas. The corrosion management program should be under the direction of a fully qualified on-site corrosion engineer.

On Stream Inspection (OSI) Program: Inspection units at all refineries have an On Stream Inspection (OSI) program for crude overhead systems. At few plants, the OSI program was well documented and implemented in accordance with a planned program. Some units use the PIPE + program to record and analyze pipe wall thickness data while others use Ultra PIPE+ or IDDEAL. Another plant keeps a paper record of overhead wall thickness data. The average inspection (OSI) frequency on the overhead lines ranged between 3 and 5 years, though inspection frequencies as short as once per month have been used on accessible lines of particular concern.

One major difficulty with OSI programs is a lack of adequate access to critical locations such as the outside of elbows and even pipe adjacent to injection locations. The cost of erecting scaffolding to reach these non-inspectable locations can be of the order of $30,000, and construction of scaffolding during operation is restricted at some plants. Crane and personnel basket inspections are allowed by some plants, but not others. The possible benefits of completing an inspection activity must be carefully weighed against the possible hazards to man and process. Another major issue is that some refineries only monitor the remaining wall thickness in relation to tmin. There is no effort to track corrosion rates and predict remaining system life based on measured corrosion rates. Reviewing the current OSI programs on crude overhead lines, the following areas requiring improvement were identified:

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• OSI test point locations and the techniques may miss localized corrosion. The

OSI test point locations should cover all impingement locations (tees and elbows). • Some units were able to take OSI thickness readings at preferred locations.

Others were unable due to inaccessibility (no scaffolding or platform). • In some units, the OSI data management is still manual and data analysis and

corrosion rates are not properly documented. • Not all units are equipped to perform a thorough OSI program because of higher

temperatures (130 oC) and equipment limitations. • Some Plant Inspection Units performed close monitoring on the crude overhead

piping by conducting P&T-SCAN surveys on selected locations. • Some Plant Inspection Units performed infrared surveys on crude overhead lines

to check for cold spots. These can be used to indicate possible condensation areas due to inhibitor injection.

Injection Point Inspection: Plant Inspection Units perform injection point

inspection programs as per inspection alert 001/97 and API 570 on all chemical injection points, including the wash water injection point. The inspection of injection points includes removal of injection quills for visual inspection and UT readings during scheduled T&I shutdowns. This was not done routinely at every refinery due to T&I time limitations. The UT readings are done on the injection lines and main lines at area starting upstream of the injection points and extended up to second elbow downstream of the injection points.

Inspection programs on caustic injection quills installed immediately upstream of the heater were not always performed as directed. Inspection during installation requires on-site verification of quill metallurgy and post-installation radiography of the quill to ensure correct positioning. This is not always done.

Corrosion Monitoring Systems: Jeddah and Yanbu Refineries have non-functioning corrosion monitoring systems. Rabigh Refinery has eleven electrical resistance probes at the air coolers. Presently, data is collected manually once per month. Riyadh Refinery has made improvements to its corrosion monitoring system, but much of it is still a manually operated system. Ras Tanura uses electrical resistance probes in Plant 15. This system was automated under BI-3717 by a general contractor rather than a specialist company and has not worked as well as expected. Plant J-64 at Ras Tanura has an automated electrical resistance probe corrosion monitoring system that was installed by a specialized contractor and works well.

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Other Data Sources: All refineries are provided weekly reports by the chemical vendor that present system data. Refinery Laboratories perform per shift analyses of critical measures. Process data are available from Operations staff.

Recommendations

• A comprehensive documentation management system should be used in order to keep records of the probe readings, locations, and injection quill materials. Data must be evaluated to determine present corrosion rates and to isolate system variables that may affect those corrosion rates.

• Data provided from the chemical vendor should be reviewed by the plant Corrosion Engineer on at least a weekly basis in conjunction with process, monitoring, laboratory, and inspection data. Causes of system variations should be investigated.

• Chemical vendor data must be permanently stored in a readily accessible and retrievable location.

• Corrosion monitoring systems should be upgraded to allow automated data collection and processing.

Crude Unit Test Methods and Sampling Procedures The test methods and sampling procedures used in all Saudi Aramco refineries were reviewed as part of the team activities. The crude oil is analyzed for total salts, water and sediment and hydrogen sulfide. Water samples are analyzed for chlorides, iron and pH. In general, the test methods adopted in the refineries are similar. The following general recommendations are applicable to all laboratories.

• Perform Round-Robin Testing among the five laboratories to ensure accuracy, reproducibility as well as consistency.

• For sediments in crude, a more accurate method than ASTM D4007 can be used. This is ASTM D473, “Standard Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction Method”-API Designation: Chapter 10-1 (MPMS); IP Designation: 53/82. The current test method should be checked against this method at least on a monthly basis.

• For water in crude, more accurate methods than ASTM D4007 are available. These are: ASTM D4006, “Standard Test Method for Water in Crude Oil by Distillation”-API Designation: Chapter 10.2 (MPMS); IP Designation: 358/97; E1-2000; or ASTM D4928, “Standard Test Methods for Water in Crude Oils by Coulometric Karl Fischer Titration”-API Designation: MPMS Chapter 10.9; IP Designation: 386/99. The current test method should be checked against this method at least on a monthly basis.

• For salt in crude, a more accurate method than ASTM3230 can be used. This is ASTM D6470, “Standard Test Method for Salt in Crude Oils (Potentiometric

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Method)”. The current test method should be checked against this method at least on a monthly basis. At low ppm levels, the accuracy of the potentiometric method is ±0.5 ppm. At 25 ppm the accuracy is ±1.5 ppm. Where equipment is available, ion chromatography (IC) is the best method. IC typically yields slightly lower measurements than those obtained with potentiometric methods (ref: NACE TG 274).

• Iron in crude can also be measured following ASTM D5863A, “Standard Test Methods for Determination of Nickel, Vanadium, Iron, and Sodium in Crude Oils and Residual Fuels by Flame Atomic Absorption Spectrometry”. The current test method should be checked against this method at least on a monthly basis.

• It should be communicated clearly to laboratory personnel that their work is extremely important to the proper and safe operation of the Refinery.

• It should be emphasized that as far as laboratory personnel are concerned there is no good or bad result. Instead, the target is obtaining accurate results.

• It is extremely important to completely comply with ASTM D4007. For example, the temperature must be controlled during centrifuging at 60 ± 3ºC.

• Calibration of pH meters should be performed at least once a day using buffer solutions. Dry pH electrodes must be avoided at all the times.

• In the case of dissolved hydrogen sulfide, it is recommended to perform the test at the sampling location close to the source.

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SAUDI ARAMCO OVERHEAD CORROSION CONTROL

GUIDELINES

Introduction This document draws together experience from field operations, Engineering Services, and the industry to provide a “Best Practice” for Saudi Aramco. Words such as “Typical” or “Target” indicate desirable but not mandatory items. Words such as “Limit,” “Required,” “Shall,” and “Must” indicate mandatory items. This is a guideline rather than a standard. Specific circumstances at a plant may mean that it is impractical or un-helpful to apply a particular item in the guidelines. Seek consultation from Consulting Services Department and Process and Controls Systems Department under these circumstances. A guideline is not retroactive. It does not require an operating plant to make changes. Rather the document provides guidance to plants and Engineering Services in how to optimize operations in the future.

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LOCATION/ VARIABLE

TARGET OR LIMIT

COMMENT

1.0 Tank Farm

1.1 Mixers Use while filling tank

1.2 Settling time > 24 hours desirable

1.3 Salts Measure

1.4 BS&W Measure

1.5 API slops None Keep slops separate from crude tanks. Feed directly to process if needed so that problem slops can be quickly identified and isolated.

1.6 Organic chlorides Avoid

1.7 Tank dewatering chemicals

Could be evaluated site by site for economic benefit.

2.0 Desalter

2.1 Temperature 120 to 150°C Target. Temperatures lower than 120°C result in less effective desalting.

Limit: Temperatures higher than 150°C damage equipment.

2.2 Residence time 15 minutes for oil Typical value. Longer residence times such as 30 minutes better.

60 minutes for water

Typical value. Longer residence times would be better.

2.3 Mixing valve ∆P 5 to 28 psi (0.35 to 2 kg/cm2)

Typical values. Mixing valve adjusted on-site to optimize desalting efficiency. Re-evaluate with each crude tank switch or crude slate change. High ∆P gives more efficient mixing (good) but if too high can result in tight emulsions (bad).

2.4 Salts-out < 1PTB Target. However, consistent performance with stable salt-out essential.

2.5 BS&W < 0.2 % Target. Saudi Aramco crude streams gain water through the desalter.

2.6 Desalting efficiency ≥ 95% Target. Consistent operation essential. Desalting efficiency can be lower if it still results in a low salt content of < 1PTB.

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2.7 Wash water feed rate

4-6 % of crude charge

Higher wash water rates are usually uneconomic in Saudi Arabia. Rates lower than 3 % will result in very poor desalting efficiency.

2.8 Wash water pH-in 5.5 to 8.0 Electrical desalters function best in the pH range 5.5 to 7.0. Chemical desalters function best at higher pH.

2.9 Wash water pH-out 5.5 to 6.5 Target.

2.10 Wash water O2 < 20 ppb Target. Highly desirable to limit corrosion but difficult to achieve due to limited water sources.

2.11 Wash water Cl- < 15 ppm Target.

2.12 Wash water NH3 < 20 ppm Target.

2.13 Source of wash water

Good water sources include crude overhead receiver boot, recycled desalter water, condensate or stripped water from sour water stripper. Water streams from other refinery sources must be used with caution as they may result in corrosion or fouling.

2.14 Demulsifiers 3 to 25 ppmv Chemical additives are not presently used in Saudi Aramco desalters. If used in the future, treatment rates would be expected to range from 1 pint to one gallon per thousand barrels of crude.

3.0 Caustic Quality

3.1 Source Fresh caustic only Spent caustic results in tramp compounds entering the system and causing corrosion, fouling, emulsions, and foaming.

3.2 Concentration 1 to 5 wt % (2 to 7° Baume)

Typical values. Dilute caustic aids mixing. Identical concentration must be provided. Variation in caustic strength injected to process stream is a major cause of preheater fouling.

3.3 Measurement Each batch Essential. Measure the concentration of each and every batch of caustic to be used in the plant prior to use. Data must be stored in a permanent record. Injection of off-specification caustic at one plant caused stress corrosion cracking and an economic loss of over $1 million. Injection of off-specification caustic at another plant caused excess fouling.

3.4 Dilution water O2 < 20 ppb Stripped sour water is a good source.

3.5 Dilution water Cl- Zero Target.

3.6 Storage tank Target. The larger the better to minimize batch make-up operation and variation. Nitrogen blanket to exclude oxygen. Mechanical mixers.

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3.7 Caustic delivery to unit

Dedicated line Strongly preferred. A dedicated line from the bulk caustic tank to the unit day tank facilitates the correct dilution of caustic. At least two plants that uses a complex caustic header system have experienced major problems with cross contamination and delivery of out-of-specification caustic that resulted in major operational problems.

4.0 Caustic Injection

4.1 Injection location NACE recommends and 80% of the industry injects caustic downstream of the desalter. The suction of the crude booster pump is the normal location and assists efficient caustic mixing. In cases where preheater fouling is an issue, then caustic injection upstream of the heater is allowable. Ras Tanura Plant 15 has had good long term success with this latter methodology.

4.2 Injection temperature

Maximum 350°F Best practice of the majority of the industry. Shell restricts caustic injection temperature to 350°F. Nalco’s Best Practice restricts caustic injection to 300°F. Higher temperatures can be used but only if fouling of preheat exchangers or some other site specific need makes it essential. Fouling can be readily detected by measurement of pressure drop across the preheater. Higher temperature injection requires careful and continuing attention to every detail as failures at higher temperatures can be catastrophic.

4.3 Quantity injected Salt < 2 PTB, add 1 PTB NaOH.

Salt 2-5 PTB, add 1.5 - 2 PTB NaOH.

Maximum 2 PTB

Caustic injection rates are fine tuned based on overhead chloride levels. Initial rates for a new unit follow the rules of thumb provided. The maximum amount injected is limited to less than 2 PTB NaOH. Amounts injected may be limited further due to effects on downstream process such Visbreakers, FCCUs, and hydrocrackers.

4.4 Injection quill material

Monel 400 Saudi Aramco experience has demonstrated that this material serves well whether the injection point is located downstream of the desalter or upstream of the heater. Injection quill design shall follow the intent of Figure G-4.4

4.5 Injection quill length To allow injection in the center third of the pipe.

Injection quills must be the correct length to allow injection in to the center third of the pipe.

4.6 Injection slip stream Dilute caustic 1:100 with crude slip stream

Use of a slip stream aids dispersion of the caustic and helps to minimize caustic-caused corrosion problems. Slip stream is effectively mixed prior to injection using a Monel 400 static mixer. All caustic pipe and fittings shall be Monel 400. The design of the slip stream is shown in Figure G-4.4.

4.7 Injection orientation Co-current with crude flow.

Nozzle discharges downstream.

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4.8 Quill installation PMI Positive Materials Identification of the injection quill and all slip

stream pipe and fittings must be performed on site to verify metallurgy. Incorrect materials shall not be fitted.

Radiography Location of quill tip shall be proved after installation by radiography of the crude pipe. A permanent record of the radiograph will be retained by the refinery.

4.9 Quill design Non-retractable with match-mark indicator

Correct positioning of the quill is critical. Therefore, a non-retractable design shall be used. A match-mark indicator is used to show the orientation of the nozzle.

4.10 Crude pipework upstream of the injection point

PWHT for minimum of 3 diameters upstream

Required that the pipework, fittings, etcetera, be post weld heat treated to prevent caustic stress corrosion cracking. Failures due to CSCC have occurred in Saudi Aramco plants.

4.11 Crude pipework downstream of the injection point

PWHT all piping systems and equipment.

Required that the pipework, fittings, etcetera, be post weld heat treated to prevent caustic stress corrosion cracking. Failures due to CSCC have occurred in Saudi Aramco plants .

5.0 Overhead

5.1 Velocity 75 feet/second Target optimum value for carbon steel systems. Since corrosion is enhanced by velocity, lower velocities will provide lower corrosion rates. Velocity control in existing plants is usually a compromise between what is mechanically achievable and required system throughput.

< 100 feet/second Mandatory limit for carbon steel systems. Velocities in excess of this value will be a major contributor to premature failure.

< 150 feet/second Allowable velocity for corrosion resistant alloy systems. Higher velocities are probably achievable as industry knowledge with alloy systems develops. For mixed metal systems with some carbon steel pipework and some alloy pipework, ensure that the velocity limits for carbon steel are not exceeded.

5.2 Velocity calculation Various There are many proprietary programs available. The results are only as good as the data that is fed into the program. Remember to include all water sources including stripping steam and carryover of water in naphtha reflux, if any.

5.3 Dewpoint > 15°C lower than line temperature

Target is for the vapor dewpoint to be at least 15°C lower than the operating temperature before the water wash. Various computer programs are available from vendors or engineering services to estimate dewpoint. Must be sure to include all stream components.

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5.4 Salt point > 15°C lower than

line temperature Target. The salt point is the temperature at which neutralizer /ammonia chloride products condense and can cause fouling and corrosion. Water wash removes these deposits. Vendors provide proprietary programs to calculate salt points for their specific products.

5.5 Pipe metallurgy Carbon steel Carbon steel is the standard material for overhead systems. Usually, hydrogen sulfide levels are below the minimum necessary to mandate hydrogen induced cracking resistant steel, but must be examined on a case by case basis versus SAES-L-133.

Hastelloy C-276, and C-22

For critical systems where other control measures have been unsuccessful, alloy systems present an option that must be evaluated based on system economics.

5.6 Thermal insulation Thermal insulation up to the water wash reduces premature condensation but can hamper OSI programs.

6.0 Corrosion inhibitor

6.1 Pump Positive displacement metering pump

Ensure that the size is appropriate.

6.2 Filter Strainer Required on naphtha slip stream, preferred on inhibitor line. 100 mesh typical.

6.3 Type Oil dispersible film former. Presently Nalco 5186.

Typical. Presently used in all Saudi Aramco crude unites. An option is to evaluate water soluble products co-injected with the water wash.

6.4 Treatment rate 3 to 5 ppmv of total naphtha product and naphtha reflux.

Typical. Depends on product used.

6.5 Injection location After 1st elbow Typical. Most Saudi Aramco crude units inject corrosion inhibitor downstream of the 1st elbow and downstream of the neutralizer injection point. Ras Tanura primary injection point is at the fin fans. Secondary injection at the fin fans may be appropriate for refineries with flow distribution problems.

> 5 diameters from neutralizer injection

Rule-of-thumb but difficult to achieve with present physical layouts.

> 5 pipe diameters from downstream elbow.

Strongly preferred to minimize damage on downstream elbow but difficult to achieve with present physical layouts..

6.6 Slip stream 100 naphtha to 1 inhibitor.

Dilute inhibitor in naphtha stream. Flow measurement on inhibitor and naphtha streams essential. 100 mesh screen required.

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6.7 Quill design Retractable Mandatory. Allows maintenance on-stream.

12 o’clock Normal orientation.

Inject in center third of stream

Preferred to inject in the center third of the stream to ensure even distribution away from pipe walls. In large systems it may be impossible to obtain a quill that can be retractable, i.e., removed on-line and meet this criteria. In this case, the minimum insertion into the pipe flow must be no less than 6 inches.

6.8 Quill metallurgy Hastelloy C-2000, B-2

Nalco provide Hastelloy C-2000 quills. Hastelloy B-2 that was supplied previously is also a good choice. Monel shall not be used for inhibitor service. Any existing stainless steel quills should be replaced at the next T&I.

7.0 Neutralizer

7.1 Pump Positive displacement metering pump

Ensure that size is appropriate.

7.2 Filter Strainer Preferred. 100 mesh typical.

7.3 Treatment rate Treatment rate is adjusted to give required overhead receiver pH. The Nalco Strong Acid Test (Attachment 1) provides a method to calculate the target injection rate that will assure neutralization of the first drops of condensing acid.

7.4 Injection location After 1st elbow Neutralizer must be injected into the overhead system. Injection into the reflux is bad practice.

> 5 pipe diameters from downstream elbow.

Strongly preferred to minimize damage on downstream elbow.

7.5 Steam co-injection Required. Use steam co-injection to ensure neutralizer is vaporized and adequately dispersed. Use lowest pressure steam that meets design need. Inject into the overhead at no more than 5 psi over stream pressure.

7.6 Quill design Retractable Mandatory. Allows maintenance on-stream.

12 o’clock Normal orientation.

Inject in center third of stream.

Preferred to inject in the center third of the stream to ensure even distribution away from pipe walls. In large systems it may be impossible to obtain a quill that can be retractable, i.e., removed on-line, and meet this criteria. In this case, the minimum insertion into the pipe flow shall be no less than 6 inches.

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7.7 Quill metallurgy Hastelloy C-2000, B-2

Nalco provide Hastelloy C-2000 quills. Hastelloy B-2 that was supplied previously is also a good choice. Monel shall not be used for neutralizer service. Any existing stainless steel quills shall be replaced at the next T&I.

8.0 Wash water

8.1 Source Overhead receiver Recycle water from the overhead receiver makes an excellent choice.

8.2 Quality O2 < 20 ppb Required. Oxygen in wash water results in major corrosion damage.

TDS Total dissolve solids typically are in the region of 160 ppm in Saudi Aramco operations. Low figures are preferable but not controllable.

Tramp amines Avoid the presence of tramp neutralizing amines if at all possible. Neutralizers introduced with the wash water help to control overhead receiver pH but do not help control pH in the first condensing drops of acid in the overhead, if condensation occurs upstream of the water wash.

8.3 Injection location Downstream 2nd elbow

Preferred location is immediately downstream of the second elbow after the crude column.

8.4 Injection rate 5 % volume of overhead naphtha

Target is to maintain at least 25% of the injected water in the liquid phase after injection, so that solids may be washed through the system and the condensing hydrochloric acid diluted. This water wash rate may not be achievable with undersized or poorly designed overhead receivers.

8.5 Measurement and control

Accurate measurement and control of wash water flow is essential especially in locations where on water feed is used to supply different parts of the system, such as the overhead and the fin fans.

8.6 Nozzle design Spraying Systems Company, Wheaton, Illinois, (www.spray.com) “Whirljet-CX” design, standard hollow cone nozzle has been used in Ras Tanura and Riyadh Refinery.

8.7 Nozzle metallurgy Type 316 L and 316 F stainless steels

Inconel 600

Corrosion resistant alloys such as Hastelloy C-276 or Inconel 625 are the materials of choice for this service but only available in batches of 25 or more from the manufacturer. Therefore, Type 316L or 316F stainless steel which are available “off-the-shelf” have been accepted as a compromise. There is a small potential for crevice corrosion and stress corrosion cracking with these materials. Rabigh Refinery specified Inconel 600 wash water pipe and spray nozzle which will have improved resistance to chloride stress corrosion cracking over the Type 316 alloys.

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9.0 Air coolers

9.1 Flow distribution Poor flow distribution due to long headers will result in high velocity flow and possible erosion corrosion in the fin fans nearest to header inlet and low velocities and possible under deposit corrosion in low flow air coolers. Measure outlet temperatures of fin fans to indicate variations in throughput. Use values on inlet lines to fin fans to control flow distribution.

9.2 Internal coating Internal coating of new air coolers will reduce fouling and corrosion. It is an economic method to extend cooler life.

9.3 Water wash If poor distribution or low flow is a problem, supplemental wash water can be injected into fin fans to remove deposits. Continuous water washing is strongly preferred over intermittent water washing that may increase corrosion.

9.4 Inhibitor injection Secondary corrosion inhibitor injection may be necessary at the fin fans in systems with mal-distribution.

10.0 Overhead receiver

10.1 pH limit 5.5 to 6.5 Limit. Adjust pH value by adjusting neutralizer addition.

10.2 pH measurement 1 per shift Operators should measure pH on-site a minimum of once per shift using narrow range pH paper and also a well maintained and calibrated pH meter. These measurements are in addition to regular laboratory based measurements. All pH records must be permanently recorded.

On-line pH meters have proved very hard to maintain and calibrate in the Saudi Aramco environment.

10.3 Iron < 1 ppm Limit. Higher levels indicate excessive corrosion which must be rectified.

10.4 Chlorides 10 to 30 ppm Limit. Too low a value results in high caustic use and possible sodium contamination of downstream processes. Too high a level results in corrosion damage. Adjust chloride level by adjusting caustic treatment.

10.5 Strong acid test See 7.3

10.6 Water boot residence time

4 to 5 minutes minimum

Short residence time will result in poor separation and possible entrainment in reflux naphtha.

10.7 Water chemistry Measurement of hardness will show presence of leaks and cross contamination from any upstream water-cooled heat exchangers in the overhead system.

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11.0 Naphtha reflux

11.1 Water content <0.1 % Limit. Water in the naphtha reflux causes significant corrosion in the tower and overhead. Measure water content once per shift. Ideal is zero percent water.

11.2 Neutralizer or inhibitor injection

None allowed Mandatory.

12.0 Corrosion monitoring

12.1 Corrosion management program

Essential. Should include operations data, laboratory results, chemical injection rates, OSI, and monitoring results. Good information management is vital.

12.2 Injection point inspection

API-570 & Inspection Alert 001/97

Essential.

12.3 Probes, mpy < 5 mpy Corrective action required if value exceeded. Electrical resistance or MicroCor probes in retractable fittings are useful especially in the region of the air coolers and overhead receiver.

12.4 Coupons, mpy < 5 mpy Corrective action required if value exceeded. Coupons may be used in the overhead system or in the same locations as probes.

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Figure G-4.4: Caustic injection with slip stream

CrudeMain Line

Crude Slipstream

Velocity 2-4 feet/sec

Carbon steel

Carbon steel--PWHT for minimum 3 diameters upstream and all downstream pipe

Monel 400 quill with match mark indicator to show orientation of nozzle

In-line static mixer, Monel 400

Carbon steel

Carbon steel PWHT

Caustic feed 1 – 5 wt%

Pipe & valves Monel 400

Pipe & valves Monel 400

Most valves not shown for simplicity.Drawing for illustration only—not a detailed design drawing.Not to scale.

Quill: Monel 400, closed end, side hole, oriented downstreamExample dimensions 0.5 inch nozzle in 1.5 inch diameter quill. Must inject in center third of pipe.

Check valves

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ATTACHMENT 1: NALCO STRONG ACID TEST METHOD RPC Total Acid Test: Kit No. C0280

PROCEDURE 1. Pull approximately 50 ml of distilled water into a 60 ml graduated syringe. Pull

another 10 ml of air into the syringe.

2. Attach the cation trap to the syringe and – holding the syringe down - expel the distilled water through the cation trap first, then the air to clear the trap.

3. Remove the cation trap and pull approximately 60 ml of sample water into the syringe. Re-attach the cation trap and holding the syringe upwards displace all air pockets with sample from the syringe.

4. Continue discharging sample through the cation trap into the sink until the syringe stopper reaches the 50-ml mark.

5. Put 5ml (0.1 milli-equivalent, or meq) of 0.02 NaOH into 250 ml beaker.

6. Add two drops of P Indicator to the beaker – the 5-ml of caustic will turn pink.

7. Discharge the sample from the syringe through the cation trap into the beaker until the color disappears. The pH should be around 8.2. Record the amount of sample discharged as P.

8. Add 5-10 drops of Special Indicator solution to the beaker.

9. Continue discharging sample from the syringe through the cation trap into the beaker until the blue color changes to a clear of light gray color of a pH of 4.5 – 4.7. Record the total amount of sample used (including the amount to the “P” endpoint) as the “M” endpoint.

10. Strong Acid Calculation (“S”) (0.1 meq/”M” ml) X 1000 = “S” meq/L Therefore S = 100/M

11. Weak Acid Calculation (“W”) (100/P – 100/M) = “W” meq/L

12. Expressing measure equivalents of strong acid as ppm of chloride: “S” meq/L X 35.5 mg Cl-/meq = S as ppm Cl.

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13. Nalco 5151 requirement: (“S” meq/L) X (Kg/hr of total overhead water) X 1.92 = Nalco 5151, ml/min 1,000

The total overhead water in kg/hr must be calculated by adding the total stripping steam to the column plus any side strippers, and any water coming in as BS&W with the crude.

This is the minimum amount of Nalco 5151 required to neutralize the acids in the overhead water assuming 100% contact efficiency between the neutralizer and the acid, and assuming the steam and bs&w numbers are correct. To be safe, the minimum Nalco 5151 target should be 10% greater than the minimum required calculated above.

Equation balance example:

(“S”) (5151)

240,000# stm * L * 1.2 meq * eq * 115 g * lbs. = 33.1 #/day day 2.205 # L 1000 meq eq 454 g Nalco 5151

or

(“S”) (5151)

4,535 Kg stm * 1 L * 1.2 meq * eq * 115 g * 1 ml * hr = 10.4 ml/min hr Kg L 1000 meq eq g 60 min Nalco 5151

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Documents

present physical

standard test

saudi aramco

saudi aramco

longer residence

current test

corrosion

ras tanura