Corrosion 98 Paper No. 576

NAPHTHENIC ACID CORROSION IN SYNTHETIC FUELS PRODUCTION

Hendrik J. de Bruyn Mossgas (Pty) Ltd Private Bag X 14

Mossel Bay 6500, South Africa

ABSTRACT Serious corrosion damage to carbon steel piping in a fractionation unit associated with synthetic fuels production has been ascribed to the presence of naphthenic acids. Investigation of the problem revealed total acids numbers (TAN) ranging fro m 8 - 12mg KOH/g in the feed to the unit. Damage typically occurred in the temperature range 180 - 240'C and manifested as localized pitting, preferential weld corrosion, general wall thinning and end-grain attack. Filming amine corrosion inhibitors designed for refinery overhead systems have been proven ineffective and high temperature phosphate-based inhibitors could not be used due to potential catalyst poisoning in downstream refinery units. Coupon exposures indicated corrosion rates in the order of 2 mm/y on carbon steel in a reboiler line as well as pitting to austenitic stainless steel type UNS S30403. Line replacement in austenitic stainless steel UNS S31603 has been proven effective. The performance of this alloy is mainly ascribed to its molybdenum content. The absence of sulfur in the feed to the unit is also contributing to the alloy performance despite the extremely high total acid numbers. Keywords: naphthenic acid, refining, oil fractionation, materials selection, austenitic stainless steel

INTRODUCTION The synthetic production of automotive fuels from coal-derived gas basically entails methane reforming to produce syngas and Fischer-Tropsch synthesis of the produced syngas. Fractionation of the light oil yield and subsequent refining processes are used to produce the required product blends. A new synthetic fuels plant utilizing offshore natural gas resources was commissioned in South Africa during December 1992. Ale project was wholly government owned and an operating. company did not exist during the early stages of the project. Critical decisions taken by the managing contractor during some design and construction phases have resulted in serious operating problem due to corrosion. Potential naphthenic acid corrosion in the light oil fractionation unit was identified during design of the unit. All the distillation columns were constructed in carbon steel clad in austenitic stainless steel UNS S31603. Most piping was however provided in carbon steel. Total acid numbers in the light oil feed to the unit ranged between 8 - 12 mg K0wg. Sulfur is not present in the feed as levels higher than 100 ppb are detrimental to the synthesis catalyst. Serious naphthenic acid corrosion occurred during 1994 and 1995, causing frequent unexpected production disruptions. Mitigation of the corrosion problems included seriously considering acid removal, the use of corrosion inhibitors and investigation of alternative materials of construction. Equipment and process line replacements in austenitic stainless steel LTNS S31603 proved to be the only long term solution. The performance of this alloy is mainly ascribed to its molybdenum content, as well as the absence of sulfur in the feed to the unit. The purpose of this paper is to review the corrosion damage that has occurred as well as mitigation of the problem. A discussion of organic acid corrosion with specific reference to naphthenic acid corrosion will also be provided.

NAPHTHENIC ACID CORROSION General The term "naphthenic acid", as commonly used in the petroleum industry, refers collectively to all of the organic acids present in crude oil'. The name is derived from the early discovery of monobasic carboxylic acids, based on a saturated single-ring structure, in petroleum. Most crude oils can however contain a large variety of organic acids that includes low molecular weight fatty acids, as well as saturated and unsaturated acids based on single and multiple five and six-membered rings. The term "organic acid" therefore applies to a broad range of organic compounds which contain the organic acid radical COOH. The hydrocarbon part of the compounds can be one of the following:

• Aliphatic (fatty) acids: R.COOH (where R is a straight or branched chain) • Aromatic acids: AR.COOH (where Ar is a benzene ring or substituted benzene rings) • Naphthenic acids: X.COOH (where X is a cycloparafinic ring)

Fischer-Tropsch synthesis has been shown to produce a variety of organic acids. These are present in the derived synthetic oil and reaction water. The acids are mostly aliphatic, but the presence of aromatic and naphthenic acids have been confirmed. Organic acids present after synthesis fall into three groups:

• Water soluble acids - acetic C2 - propionic C3 - butyric C4 - valeric C5

• Gasoline cut - C5 to C11 acids • Diesel cut - C12 to C18 acids

Of these C, to C, are present in the highest concentrations, with C, by far the most abundant. Synthesis reaction water contains as much as 7000 ppm water soluble organic acid. Laboratory investigations have confirmed that the synthetic oil contains aliphatic, aromatic and naphthenic acids. Corrosion of steel by organic acids' produces a corrosion product, iron-naphthenate in the case of naphthenic acids, which is extremely soluble in oil. This leaves a corroded surface which is typically without any corrosion products or films. The corrosion reaction with iron can be written as: Fe + 2Z.COOH = Fe(Z.COO)2 + H2

Where Z represents any of the hydrocarbon radicals (aliphatic, aromatic or naphthenic). Controlling Parameters The radical COOH is common to all organic acids while the hydrocarbon part of the organic acid (aliphatic, aromatic or naphthenic) influences the chemical reactivity (corrosivity) of the acid. As a rule the chemical reactivity decreases with increasing molecular weight. This generally means that light acids are more corrosive than heavy acids. Heavy organic or naphthenic acids (> C,) are generally only corrosive near their respective boiling points. Compared to this the lighter organic acids tend to exhibit damage over a larger temperature range (boiling point down to 60'C). Figure 1 graphically describes the temperature range over which various organic acids are corrosive. Organic acid concentrations are typically measured by titrating witb. potassium hydroxide (KOH), The resulting “neutralisation numbers” or "acid numbers" are expressed numerically as milligrams of KOH required to neutralise the acidity in one gram oil'. There are two standard ASTM tests for determining the acidity of an oil. ASTM D974 is a calorimetric procedure and ASTM D664 is potentiometric. Either test permits determination of a Strong Acid Number and a Total Acid Number (TAN). Carboxylic acids show up in the Total Acid Number but not the Strong Acid Number. Since the Strong Acid Number for most crude oils are zero, the Total Acid Number is generally taken to be a measure of naphthenic acids. The terms "acid number" and "neutralisation number" are sometimes used, but in essence they all mean Total Acid Number. Experience with crude oil distillation has indicated that organic acid corrosion is not usually encountered at total

acid numbers below 0,5 mg KOH/g. Attempts to correlate acid number with the occurrence and extent of corrosion damage has proven to be very difficult and unreliable. In general the corrosion rate will rise with an increase in acid number, but different oils with the same Total Acid Number may exhibit different corrosivities due to differences in acid type and concentration.

Naphthenic acid corrosion in crude distillation units has been observed in transfer lines, tower internals and side-cut piping'. Enrichment of the acids into the gas oils makes these cuts particularly corrosive. The characteristic attack is frequently observed in locations of high shear stress, such as elbows and downstream of thermowells. In general, the corrosion problem is more severe where the physical state of the acids is changing, i.e. vaporising or condensing. The corrosion rate in organic acids is always highest just below the boiling point of the acid. Light organic acids (< Cs) are corrosive from their respective boiling points to as low as 60'C. The onset of naphthenic acid corrosion is at temperatures above 220'C. The corrosion rate generally peaks in the temperature range 260 - 290'C and diminishes above 370 - 400'C, probably because the acids are unstable at these temperatures'.'. In synthetic oils, naphthenic acid corrosion may occur below 220'C due to the lighter, more reactive, acids (C, to C,8) formed by Fischer-Tropsch synthesis. It has been recognised for many years that high velocities or turbulence can accelerate naphthenic acid corrosion'.'. nis phenomenon does not appear to be important in single-phase liquid flow, but is extremely important for equipment where two-phase flow is present. Fluid flow has long been used as the parameter for comparing flow among refineries and between laboratory-field correlations. However, this concept was found to lack predictive capabilities and was replaced by data related to fluid flow parameters such as wall shear stress and Reynolds number. Recent research has indicated that the flow regime and the degree of vaporisation have a significant effect on naphthenic acid corrosion'. Sensitivity to velocity also appears to increase with an increase in acid content of the oil. Results showed that the wall shear stress changes drastically with degree of vaporisation and that identical fluid flow in the laboratory and the field do not correspond to the same level of shear stress. Carbon dioxide (C02) is frequently present in Fischer-Tropsch synthesis streams where corrosion is encountered. Synergistic effects between CO, corrosion and water soluble organic acids at temperatures below 100'C are suspected. Corrosion damage is probably increased by an increase in the total acidity of the electrolyte. Sulfur is corrosive to ferrous materials at temperatures above 260'C by sulfidation. This will produce a protective film on the steel surface: Fe + H2S = FeS + H2 There is however competition between the two reactions and soluble iron-naphthenate will react with hydrogen sulphide to form iron-sulphide and to regenerate naphthenic acid.

Fe(Z.COO)2 + H2S = FeS + 2Z.COOH

Extensive studies of the above phenomena have led to the classification of naphthenic acid corrosion into three Type I - Pure naphtenic acid corrosion where sulphur compounds have little or no effect, if they are Present. Type II - Sulfidic corrosion, accelerated by the presence of naphthenic acids. Type III - Naphtenic acid corrosion, inhibited by hydrogen sulphide. Type I corrosion produces a relatively film-free surface and extremely high corrosion rates on carbon steel. In Type II attack, damage is largely controlled by the sulphidation reaction (high concentrations of H,S) with deterioration of the protective sulphide film providing access to bare metal for naphthenic acid corrosion to enhance the overall rate of deterioration. In the presence of low sulphur (H,S) concentrations (Type Ill attack), naphthenic acid corrosion is suppressed by the formation of stable sulphide surface films. Control Methods Organic acid corrosion can be controlled by blending, neutralisation and removal of acids, altering the form of the acids, use of corrosion inhibitors and changing equipment metallurgy'. Refineries that process different crude oils reduce the naphthenic acid content by simply blending oil with high total acid numbers with "better" crude oils

containing less acid. This approach is preferred by many as it involves no extra expense or capital investment. This option is however beyond the reach of many refineries that process feed stock from a single source. One of the earliest methods employed to control naphthenic acid corrosion was the addition of lime or caustic soda in crude distillation unit pre-heat sections with subsequent removal of sodium-naphthenate from the column. Overdosing of caustic has however resulted in caustic embrittlement (stress corrosion cracking) of downstream heat exchangers and equipment. Incomplete removal of sodium-naphthenate from the column can also result in downstream process difficulties. Organic amines have also been used for neutralising naphthenic acid but the cost of the amines used might be prohibitive. The predominant commercial methods available for extraction of naphthenic acids from oil use an aqueous solution of caustic soda to pull the acids into the water phase. This is accomplished by converting the acid into a caustic salt (sodiumnaphthenate) that is preferentially water soluble. The aqueous solution is forced into intimate contact with the oil to form the salts and then allowed to separate from the oil. Successful commercial applications have been limited to the diesel and lighter fractions from crude distillation due to problems with emulsification of heavier fractions. Heavier fractions have been extracted with only limited success. The acid salt has the tendency to promote emulsification, which inhibits a clean separation of the water and oil. The success with lighter fractions occurs because they contain less naphthenic acid. Even if emulsion problems are solved, residual sodium may still prevent the stream from being used as feed for any catalytic process. Anhydrous sodium hydroxide and proprietary solvents have also been used to extract naphthenic acids from crude oil'. Naphthenic acids may be reacted with organic amines to form an amide product with low corrosivity. This process will however require temperatures as high as 340'C at atmospheric pressures. Catalytic hydrotreating will also alter the from of naphthenic acids but the costs involved often excludes this option. Traditional filming amine corrosion inhibitors are ineffective in naphthenic acid corrosion. This stems from inadequate thermal stability and the absence of surface films required by the filming amines to be effective. Inhibitors which have been found to be successful can be divided into two broad categories, i.e. phosphorus-containing and non-phosphorus. The phosphorus-containing formulations are generally more effective than the non-phosphorus, but are limited by concerns about downstream catalyst poisoning'. The phosphorus-based inhibitors which have been reported in the corrosion literature and/or disclosed as patents use either phosphate esters, phosphite esters, or phosphonate-phenate sulphides as the phosphorus source.

Effectiveness of phosphate ester plus amine inhibitor packages was demonstrated in laboratory and field applications 'Me proposed mechanism for inhibition is the formation of a phosphate comp lex with iron at the metal surface. Such complexes are very stable because of the strength of Fe-P bonds. The trialkylphosphate/alkaline earth metal phosphonate-phenate sulphide group of inhibitors mainly use calcium as the preferred alkaline earth. Start-up dosing of 2000 - 3000 ppm for short periods followed by maintenance dosing of 150 - 1500 ppm depending on the severity of conditions are generally recommended'. The presence of the alkaline earth phenates eliminates formation of solids that can cause downstream problems. Laboratory and field data were published in 1995 on the success of di- or tri-alkyl phosphates combined with thiazolines'. A reduction in corrosion rates from 3.58 mm/y to 0.13 mm/y was achieved in oil mixtures with a total acid number of 16 mg KOI-I/g at 315oC . The mechanism of inhibition by these inhibitors involves reaction with the metal surface to form protective iron/phosphorus compounds that prevent further attack. Non-phosphorus based inhibitors that can be used are thiazolines, organic polysulhides and sulphonated alkyl phenols. The use of thiazolines only achieved a reduction in corrosion rates of 50%. At 204'C in the absence of H,S, 67% protection with 1 000 ppm of an alicyclic polysulphide was demonstrated. This reduced to 3 1 % at half the dosage. In the presence of 4% H,S, 500 - 1000 ppm of an aliphatic or alicyclic polysulphide achieved a reduction in corrosion rate between 58% and 80%. The effectiveness of these inhibitors was lower at higher temperatures. Low effectiveness was also observed with the use of sulphonated alkyl phenols. The normal materials of construction in crude distillation units are carbon steel, alloys steels (5Cr & 9Cr), martensitic stainless steel AISI type 410 and austenitic stainless steel AISI type 316'. In the presence of more than 1% sulphur at temperatures above 288'C, 5Cr or 12Cr cladding is recommended for crude oil distillation.

If hydrogen sulphide is present, a minimum of 9Cr steel is preferred. In contrast to high temperature sulfhidic corrosion, low-alloy steels containing up to 12% chromium provide no benefits over carbon steel in naphthenic acid service. Austenitic stainless steel AISI type 304 shows good resistance in light organic acid corrosion service (60 - 180'C) but suffers serious localised corrosion in naphthenic acid service above 220'C. Service experience with martensitic stainless steel AISI type 410 have indicated that this material often performs worse than carbon steel'. Many researchers claim that a molybdenum content of at least 2,5% is required to provide resistance to austenitic stainless steels in naphthenic acid service, hence the use of AISI types 316 and 317'.'. A recent publication suggests that austenitic stainless steels are protected from naphthenic acid corrosion by the formation of a stable protective film that may suffer breakdown under severe impingement conditions if the molybdenum content of the alloy is too low. Sensitised austenitic stainless steel is subject to intergranular corrosion by organic acid environments. The use of "L" grade material is therefore advocated where equipment is to be fabricated by welding. CORROSION DAMAGE IN FRACTIONATION UNIT A simplified process flow diagram for the fractionation of synthetic light oil is provided in figure 2, with equipment and vessel names cross-referenced in table 2. The summary below addresses these concerns and provides an overview of corrosion damage that occurred. Damage occurred only on carbon steel. Wall thickness surveys have proven to be unreliable to detect serious corrosion damage but is nonetheless useful to provide baseline data. Most leaks on carbon steel piping have occurred on welds where preferential weld corrosion has occurred. Exp osed end-grains on pipe and fittings have also suffered serious damage. A change from socket-weld fittings to butt-weld fittings has decreased the occurrence of leaks due to end-grain corrosion. Radiography was used extensively to detect corrosion damage since commissioning of the unit. Post weld heat treatment of carbon steel lines did not influence the occurrence of corrosion damage. Fractionation Unit Feed Feed to the fractionation unit has a TAN ranging between 8 - 12 mg KOH/g. Serious corrosion damage has not been detected on the carbon steel piping in this service. This feed was originally heated in three HVGO/Feed Exchangers (constructed in carbon steel and operated in series) and a Feed Preheater (austenitic stainless steel LTNS S31603). The feed temperature is raised from ambient to approximately 120'C in the HVGO/Feed Exchangers and to 130'C in the Feed Preheater. Statutory inspections conducted on the HVGO/Feed exchangers during October 1993 revealed superficial corrosion damage. Tube fa ilures were detected on the AHVGO/Feed exchanger during August 1994. A material change to austenitic stainless steel (UNS S30403 or S31603) was recommended. This exchanger was removed from service (by-passed) thus increasing the duty on the two remaining exchangers. The exchanger was retubed in carbon steel and returned to service during May 1995 when tube failures on the B HVGO/Feed exchanger were detected. Minor corrosion damage was detected on the C HVGO/Feed exchanger tubes using eddy current inspection techniques. A process decision was taken at that time not to replace the heat exchangers but to operate the unit without these exchangers. An austenitic stainless steel (UNS S31603) by-pass line was installed during October 1995. The Feed Preheater was constructed with a carbon steel channel (SA516 Gr.60) although the rest of the exchanger was supplied in austenitic stainless steel (UNS S31603). Corrosion damage to the carbon steel channel was detected during October 1993. This was mainly restricted to the machined gasket faces and some divider plate welds. Serious corrosion damage to these welds and the divider plate was detected during an outage in May 1995. Weld repairs were carried out and a decision was taken to replace the exchanger channel head in austenitic stainless steel (UNS S31603). The replacement channel head was installed during April 1996. Extensive investigations were conducted during 1994 into neutralising and/or removal of naphthenic acids from the unit feed. Caustic washing proved to be uneconomical due to the large percentage of the feed that would be lost. Extraction of the acids was considered capital intensive and the investment could not be justified at the time.

Prefractionator Section The Prefractionator is operated with a bottom temperature of 210 - 215'C and an overhead temperature of 90 - 95'C. This means that most water soluble organic acids (< C,) will be collected in the column overhead system. The Prefractionator overhead system comprises of a Prefractionator Receiver Drum, Prefracfionator Overhead Pumps , Water Wash Feed Cooler and a Water Wash Column. This system was constructed in austenitic stainless steel (UNS S31603) and has not suffered any corrosion damage. C5/C6, product rundown to a storage tank was constructed in carbon steel. Typical TAN in this product stream is varying between 0.001 and 0.004 mg KOH/g. Waste water from the Water Wash Column has a TAN of approximately 2.5 mg. KOH/g and is carried in an austenitic stainless steel line. Corrosion coupons exposed on the top tray in the Prefractionator suggested a corrosion rate of 0.3 mm/y on carbon steel and extremely low corrosion rates on austenitic stainless steel UNS S30403 and S31603 (see table 1). Inspection of the Prefractionator during October 1993 and October 1995 did not reveal any corrosion damage to the cladding (LJNS S31603) inside the vessel. AB small bore nozzles on the vessel were constructed in solid austenitic stainless steel (UNS S31603), while larger nozzles were provided in carbon steel with austenitic stainless steel weld-overlay. Vessel trim on the column was unfortunately constructed in carbon steel. Pinhole leaks occurred on carbon steel level glass assemblies during 1993. Figure 3 shows typical damage that has occurred inside such a level glass assembly. A recommendation to change these assemblies in austenitic stainless steel was proven to be too expensive. As an alternative, all the level glass assemblies were fitted with austenitic stainless steel (UNS S31603) block valves. This will enable production operators to isolate leaks on the carbon steel parts. The Prefractionator Reboiler was constructed with austenitic stainless steel LTNS S31603 tubes and cladding on carbon steel (SA516 Gr. 65) tubesheets. Slight weld corrosion was detected during October 1993 on the reboiler channel head and flange gasket surfaces. This deteriorated to serious pitting and end-grain corrosion of nozzles during the next two years. Extensive weld repairs and nozzle replacement were carried out during October 1995. An inspection of the carbon steel channel heads during June 1996 revealed that corrosion is still active in this area and that serious damage could be expected in future. A pinhole leak on a start-up bypass line on one of the Prefractionator Bottoms Pumps was investigated during November 1994 (see figure 4). Corrosion damage was ascribed to naphthenic acid corrosion and replacement of the stubs with a buttweld configuration was recommended. Carbon steel corrosion coupons were exposed in the Prefracfionator Bottoms Transfer Line, close to the Light Oil Splitter. The first of these coupons was lost while the second coupon exhibited an estimated corrosion rate in excess of 1.10 mm/y. Estimated corrosion rates from wa ll thickness measurements of the Prefractionator Bottoms Transfer Lines are presented in table 1. The Prefracfionator Bottoms Transfer Lines were replaced in austenitic stainless steel (UNS S31603) during October 1995. Light Oil Splitter Section The Splitter Column was constructed in carbon steel (SA516 Gr.60) and clad with austenitic stainless steel (LTNS S31603). All small bore nozzles on the vessel were constructed in solid austenitic stainless steel (LTNS S31603), while larger nozzles were provided in carbon steel with austenitic stainless steel weld-overlay. The Prefractionator Bottoms Stream (> C6) is fed to the Light Oil Splitter at an average temperature of 185'C. Unsaturated naphtha is separated from heavier fractions in this column. The naphtha fraction is carried overhead (temperature 155 16OOC) in UNS S31603 piping from the Light Oil Splitter Receiver via the Light Oil Splitter Overhead Condenser. Both the Light Oil Splitter Overhead Condenser and the Light Oil Splitter Receiver were constructed in austenitic stainless steel (UNS S31603). The piping carrying unsaturated naphtha to intermediate storage is only changed to carbon steel downstream of the last cooler, where the naphtha temperature is below 40'C. TAN numbers in this system ranged between 14 and 23 mg KOH/g. No corrosion damage could be detected in the stainless steel equipment during October 1993 and October 1995. The Light Oil Splitter overhead system was provided with a corrosion inhibitor dosing system. A filming corrosion inhibitor, was initially dosed to this system. It was decided to stop this inhibitor dosing based on inspection results during October 1993. It was reasoned that an inhibitor is most probably not required as all the high temperature areas were constructed in stainless steel. Serious corrosion damage later occurred detected in downstream equipment pumps and inhibitor dosing was reinstated. Corrosion coupon exposure in the naphtha rundown line

revealed low corrosion rates (see table 1). Serious corrosion damage has not been detected inside the Light Oil Splitter Column during October 1993 and October 1995. Martensitic stainless steel AISI type 410 tray fasteners (accidentally installed) suffered serious damage during the first year of operation and were replaced in October 1993. Carbon steel corrosion coupons exposed in the bottom of the column disappeared completely. LTNS S30403 coupons exhibited pitting that resulted in measurable corrosion rates. No corrosion could be measured on U'N'S S31603 coupons (see table 1). Vessel trim on the Light Oil Splitter Column was constructed in carbon steel. A pinhole leak occurred on a carbon steel block valve of a level glass assembly during August 1993. Serious naphthenic acid corrosion was noted during the investigation and it was recommended that the assemblies be changed in austenitic stainless steel. The cost of such a replacement proved to be too expensive. To manage the risk, all similar level glass assemblies were fitted with austenitic stainless steel (UNS S3 1603) block valves. This will enable production operators to isolate leaks on the carbon steel parts. The Light Oil Splitter Bottoms product is handled using carbon steel lines to and from the Light Oil Splitter Reboiler Heater. The line taking this product to the Vacuum Column Feed Surge Drum was also constructed in carbon steel. Potential naphthenic acid corrosion was identified in these bottoms product lines during 1993. Typical TAN for the Splitter Bottoms product ranged between 8 mg KOH/g and 15 mg KOH/g. The Light Oil Splitter Column bottom temperatures are 230 240'C with the Reboiler Heater outlet temperatures at 245 - 255'C. The October 1993 shutdown revealed some end-grain corrosion damage to control valve trim and serious corrosion damage to a corrosion monitoring access fitting (see figure 5). This carbon steel access fitting was located on the Reboiler return line elbow next to the Light Oil Splitter Column. The corrosion coupon in this position was lost, probably due to very high corrosion rates. Damage to the access fitting was ascribed to naphthenic acid corrosion. Another coupon was installed in this line at the reboiler heater outlet. Very high corrosion rates were measured in this position (see table 1). Most coupons exposed here revealed extensive end-grain damage. Wall thickness measurements of carbon steel lines in Light Oil Splitter Bottoms service confirmed these high corrosion rates (see table 1). The feed lines to the Light Oil Splitter Reboiler Heater and the Vacuum Column Feed Surge Drum were replaced in austenitic stainless steel (UNS S31603) during 1995. The Reboiler Heater return line was replaced in carbon steel during May 1995 and in UNS S31603 during March 1997. Examination of the original lines revealed extensive corrosion damage (see figure 6) as well as preferential weld corrosion (see figure 7). Corrosion inhibitors were considered to control naphthenic acid corrosion in the Light Oil Splitter bottoms system. Experiments with the filming amine inhibitors dosed to the Light Oil Splitter top section indicated no improvement in the bottom system corrosion rates. This was ascribed to the lack of thermal stability of these inhibitors at the high operating temperatures (230 - 260'C) of the bottom system. Candidate inhibitors for inhibition of naphthenic acid corrosion were identified. Both these inhibitors are phosphorus based and were as such rejected in fear of downstream catalyst poisoning. The Light Oil Splitter Reboiler Heater was thoroughly inspected during October 1993 and October 1995. No corrosion damage could be detected inside the austenitic stainless steel (UNS S31603) heater tubes and elbows. Vacuum Column System Light Oil Splitter Bottoms and Decant Oil were originally fed to the Vacuum Column Feed Surge Drum using carbon steel lines. The temperature in the drum is typically controlled at 210'C. Wall thickness measurements (see table 1) indicated high corrosion rates in the Light Oil Splitter Bottoms line and insignificant corrosion rates in the Decant Oil line upstream of the point where these two lines merge. It should be noted that the Decant Oil has lower total acid numbers (TAN = 2 - 5 mg KOH/g) and will therefore be less corrosive than the Light Oil Splitter Bottoms. The Decant Oil will therefore dilute the naphthenic acids present in the Light Oil Splitter Bottoms. The Light Oil Splitter Bottoms line and Vacuum Column Feed Surge Drum feed lines were replaced in UNS S31603 during 1995. Examination of the Vacuum Column Feed Heater outlet line during October 1995, confirmed the relatively low corrosion rates measured with wall thickness monitoring and carbon steel coupon exposure (see table 1). A possible explanation of this is the single phase (vapour) flow and higher operating temperatures (290 - 295'C) downstream of the Vacuum Column Feed Heater.

The Decant Oil contains a significant amount of solids (spent synthesis catalyst) which could cause erosion problems. Severe erosion damage was detected on a thermowell during March 1994. It was recommended that thermowells in Decant Oil service be provided with an erosion resistant coating. No erosion damage could be detected on the lines or vacuum column feed heater coils during October 1995. The Vacuum Column Feed Surge Drum is clad in austenitic stainless steel (LTNS S31603) while the Vacuum Column Feed Heater is provided with austenitic stainless steel (LTNS S31603) tubes. No corrosion damage could be detected during October 1993 and October 1995. The Vacuum Column is also clad in austenitic stainless steel (LTNS S31603). No corrosion damage could be detected in the column or on the column internals during October 1993 and October 1995. It is predicted that light organic acids present in the decant oil will collect in the Light Vacuum Gas Oil (LVGO). This product (TAN = 8 15 mg KOI-I/g) is rundown in an austenitic stainless steel (LTNS S31603) to a storage tank. Naphthenic acids present in the Vacuum Column could potentially report to the Vacuum Colunm Bottoms product at 2OOOC (HVGO; TAN = 5 - 8 mg KOH/g) which is used as Fuel Oil after cooling in the Vacuum Bottoms Decant Oil Exchanger and the Vacuum Bottoms/HVGO Cooler. Steam traced carbon steel is used for this purpose. Wall thickness surveys of these lines have to date not detected high corrosion rates, nor have any leaks occurred in this system. Serious corrosion damage have also not occurred in the Vacuum Colunm carbon steel LVGO and HVGO sidecut lines operating at 118 - 120'C and 185 - 195'C respectively. This phenomenon cannot readily be explained as these temperatures and acid numbers are similar to those on the Vacuum Column Feed system where serious carbon steel corrosion damage has occurred. CONCLUSIONS Serious corrosion damage has occurred in the Prefractionator Feed Exchangers and channel header on the Prefractionator Feed Preheater, the Prefractionator Reboiler channel headers, the transfer lines between the Prefractionator Column and the Light Oil Splitter Colunm, the Light Oil Splitter Reboiler Heater transfer lines and the Vacuum Column feed system lines. All the corrosion damage occurred on carbon steel and can, except for damage to the Prefractionator Feed Exchangers where light organic acid corrosion occurred, be ascribed to naphthenic acid corrosion. Damage has occurred in the absence of water at temperatures ranging between 180 and 240'C. Naphthenic acid corrosion has been observed as localized pitting, preferential weld corrosion, general wall thinning and end-grain attack. Post weld heat treatment has been observed not to be beneficial in mitigation of naphthenic acid corrosion. Filming amine corrosion inhibitors designed for refinery overhead systems have been proven ineffective in the mitigation of naphthenic acid corrosion. Phosphorus based corrosion inhibitors have not been tested due to potential catalyst poisoning in downstream refinery units. Replacement of damaged line and equipment in austenitic stainless steel (UNS S31603) has been proven to be the best long-term solution to naphthenic acid corrosion problems in the fractionation of Synthetic Light Oil. The absence of sulfur from the feed to the unit is most probably responsible for the excellent performance of UNS S31603 despite high the high Total Acid Numbers in the Light Oil feed. ACKNOWLEDGEMENT The author gratefully acknowledges management of Mossgas (Pty) Ltd for permission to publish the above work. REFERENCES 1. R.L. Piehl, "Naphthenic Acid Corrosion in Crude Distillation Units", CORROSION/87, paper no. 196, (Houston, TX : NACE, 1987).

2. E. Babaian-Kibala, et. al., "Naphthenic Acid Corrosion in a Refinery Setting", CORROSION/93, paper no. 631, (Houston, TX: NACE, 1993).

3. S. Tebbal & R.D. Kane, "Review of Critical Factors Affecting Crude Corrosivity", CORROSION/96, paper no. 607, (Houston, TX: NACE, 1996).

4. H.L. Craig-, "Temperature and Velocity Effects in Naphthenic Acid Corrosion', CORROSION/96, paper

no. 603, (Houston, TX: NACE, 1996). 5. M.J. Zetlmeisl, "Naphthenic Acid Corrosion and Its Control", CORROSION/96, paper no. 218, (Houston,

TX: NACE, 1996). 6. G.L. Scattergood & R.C. Strong, "Naphthenic Acid Corrosion, An Update of Control Methods", CORROSION/87, paper no. 197, (Houston, TX: NACE, 1987). ; 7. E. Babaian-Kibala, "Phosphate Ester Inhibitors Solve Naphthenic Acid Corrosion Problems", Oil & Gas Journal, 92, 9, p. 31 - 35 (1994). 8. M.J. Zetlmeisl, "A Laboratory and Field Investigation of Naphthenic Acid Corrosion Inhibition", CORROSION/95, paper no. 334, (Houston, TX: NACE, 1995).