Naphthenic Acid Corrosion

NAPHTHENIC ACID CORROSION

FIELD EVALUATION AND MITIGATION STUDIES

D. Johnson

Ondeo Nalco Energy Services

PO Box 123

4600 Parkway, Fareham, Hampshire

United Kingdom

G. McAteer H. Zuk

Ondeo Nalco Energy Services Norsk Hydro A.S

PO Box 87 Kjørbov16

1501 Hwy 90-A Sandvika N-0246

Sugar Land, TX 77487 Oslo

USA Norway

ABSTRACT

Opportunity crudes – normally discounted – usually contain one or more risks for the

purchaser, such as high naphthenic acid content. As the availability and volume of highly

naphthenic crudes processed increases the risk of experiencing high temperature corrosion on

refinery equipment must be considered.

This paper details studies carried out during various laboratory and field evaluations utilising

on-line monitoring systems. Associated problems noted while processing naphthenic acid

crudes are also studied, such as desalting and fouling, in addition to the corrosivity studies.

The corrosivity studies determined the effect of various crude oils of relatively high

naphthenic acid content on various metallurgies. Corrosion rates were evaluated through the

use of corrosion probes and coupons. Finally, the use of high temperature corrosion

inhibitors was successfully evaluated as a means to mitigate naphthenic acid corrosion.

KEYWORDS

Naphthenic Acid, Naphthenic Acid Titration (NAT), Inhibitors, Field Evaluation, Hot Fast

Loop, Grane Crude Oil.

ERTC 2002, Paris, France Page 1 of 1 Ondeo Nalco

INTRODUCTION

Many opportunity crudes are known to contain naphthenic acids, which can cause corrosion

in high temperature regions within the refinery normally around the crude and vacuum

towers. These opportunity crudes, also known as high acid crudes (HAC), high neutralization

number crudes (HNN), are often discounted due to the added risks associated with processing

these crudes. Because of the economic advantages [5], many refiners are looking increasingly

at processing high levels of naphthenic crude oils in their crude slates. The properties of

crude oils rich in naphthenic acid species vary. Table 1 shows some of the properties of

several heavy acidic North Sea crude oils.

Table 1 Properties of selected North Sea Crude Oils

Captain Alba Gryphon Harding Heidrun

Density – kg/litre 0.94 0.93 0.93 0.92 0.88

Total Acid Number mg KOH/g 2.5 2.0 4.1 2.1 2.6

Sulphur content wt% 0.77 1.3 0.4 0.5 0.5

Kinematic Viscosity Cst 40ºC 163 100 55 103

These variations allow refiners to find high acid crude oils that are suitable for their product

profile. Over the next five years it is forecast that High Acid Crude supply (crudes having a

TAN > 1.0) will continue to increase significantly, with production rising across the world.

All of these crude oils have significant acid numbers, therefore corrosion management is of

vital importance to ensure (i) that the corrosion risk to the plant is minimised, (ii) that a

proper inspection system is in place to identify the corrosion which might occur, (iii) that

areas of the plant that might be subject to severe corrosion are identified so that the need for

more corrosion resistant alloys can be predicted.

In addition to high temperature corrosion management, many of these high acid crudes can be

harder to desalt and lead to increased overhead corrosion, fouling, and product stability

issues. This paper will attempt to outline the proper evaluation techniques and safe

management of naphthenic acid crudes. Actual crude analysis, laboratory and field study

results are included as examples of how to manage opportunity crudes.


RISK ASSESSMENT

To safely run such crude oils in the refinery it is important to first assess the susceptibility of

plant and equipment to undergo naphthenic corrosion. Typically, data is reviewed to establish

potential corrosion rates which could be used to estimate the remaining life on the refinery

process, pressure pipelines, pumps and vessels.

Literature reviewed and experience indicates that pipelines and equipment containing crude,

light diesel, heavy diesel, atmospheric residue, light and heavy vacuum gas oil and vacuum

residue operating at temperatures higher than 200°C were possible areas for naphthenic acid

attack. [1] Areas are highlighted in the basic schematic provided in Figure 1.

AtmosphericColumn

VacuumColumn

Figure 1. Areas prone to Naphthenic Acid Corrosion

Unfortunately, experience has shown that it is difficult to correlate corrosion rates for

particular crudes from refinery to refinery. This is due to the differences in equipment design,

operating temperatures, flow velocities and other crudes present, which may provide a natural

passivating effect to the system.

There are several important variables to consider while performing a risk assessment on a

unit: stream analysis, temperature, velocity, metallurgy, flow regimes, etc. Every piece of the

puzzle must be analyzed before the best mitigation strategies can be developed. In this

section highlights of each variable will be discussed.

Stream Analysis: The TAN and naphthenic acid content (from the Naphthenic Acid Titration

test, or NAT) for most crude oils varies with the temperature of distillation fraction. NAT

represents only the naphthenic acids within the TAN. There are many different naphthenic


acid species, and some are more corrosive than others. Testing the whole crude and the side

cuts shows where the different naphthenic acids will concentrate.

It is wise to conduct such testing on the anticipated blends that could be encountered to ensure

the contributions of other crudes to TAN and NAT are captured. Table 2 shows the TAN vs.

NAT for Captain Crude oil as a whole crude and typical fractions.

Table 2 – TAN vs. NAT Captain Crude oil and Fractions (glass distillation apparatus)

Boiling Range Total Acid Number

(TAN) mg KOH/g

Naphthenic Acid Titration

(NAT) mg KOH/g

Whole Captain Crude 2.5 2.2

IBP – 260 deg C 0.25 0.3

260 – 302 deg C 0.9 0.85

302 – 343 deg C 2.1 2.0

343 – 390 deg C 2.8 2.5

390 – 482 deg C 3.8 2.6

482 – 565 deg C 3.8 2.0

565 – deg C + 2.5 0.6

Figure 2 shows the same TAN vs. NAT profile, this time for a crude blend consisting of 37%

Heidrun crude. Notice that for the whole crude, NAT represents only 60% of the TAN, while

at the vacuum gas-oil temperatures the NAT numbers are concentrated and much closer to

90% of the TAN at those temperatures. Proprietary analysis techniques for naphthenic acid

content were conducted at Ondeo Nalco laboratories to develop Figure 2.


Figure 2 TAN and NAT profiles for crude slate containing 37% Heidrun

Temperature: The relationship between temperature and corrosion rate at a constant TAN is

fairly linear – to a point. Naphthenic acid corrosion is normally not a concern much below

200 oC (392 oF). As temperature increases the corrosion rates may increase until the

temperatures are hot enough to break down the naphthenic acids to lower organic acids. The

differential between TAN and NAT then begins to widen with the NAT decreasing. This

usually starts to happen at above 420 oC (788 oF).

Velocity: Critical areas where velocity exceeded 2.7 m/sec (9 ft/sec) in liquid service are

normally identified [1] and highlighted for closer inspection.

Two Phase Flow: Locations of two phase flow should also be identified for closer inspection.

Especially interface areas where hot hydrocarbon liquids will “wet” a surface, wash off, and

then “rewet” repeatedly. Corrosion has been found in these areas.

Areas of high turbulence: Related to increased velocity – more likely to find more aggressive

corrosion in areas of high turbulence.

Predictable zones of first vaporisation or condensation: In the case of the trays and packing, it

is generally assumed that corrosion monitoring of the heater transfer lines and analysis of the

metal content / pickup of the products would be the only effective way to identify a corrosion

problem inside the towers. Monitoring the tower internals is not direct; indirect iron

measurements on side stream and residue samples provide the best data for corrosion activity

on tower internal surfaces.

Reactive sulphur content of the various side cut oils: Also requires investigation as this can

help inhibit the possible naphthenic acid attack (with possible decreased corrosion rate).


Higher sulphur level is generally considered to be beneficial for the inhibition of naphthenic

acid attack [2]. However, increased concentrations of reactive sulphur may trigger high

temperature sulphidic corrosion. It is important to note that traditional metallurgies that are

resistant to high temperature sulphidic corrosion are not very resistant to high temperature

naphthenic acid corrosion attack.

Metallurgy: Based on field experience and laboratory experiments, molybdenum content of an

alloy plays an important role in naphthenic acid corrosion mitigation. It has been

documented[1,4] that 2.5% of Mo in an alloy is enough to mitigate most naphthenic acid

corrosion. 317SS have 3-4% Mo content. If this alloy is purchased with the purpose of

mitigating naphthenic acid corrosion, the refiner should specify a minimum of 3.5% Mo in the

alloy. It should be noted that if naphthenic acid corrosion is aggressive, then 317SS may not

be completely corrosion resistant.

“Other” – Overhead Corrosion, Desalting, and Fouling Variables

Corrosion: Above 420°C naphthenic acids decompose at an increasing rate but concern has

been expressed that the light organic acid compounds generated end up in distillation

fractions and they could be corrosive [3]. Our observations are that this can occur for the

Visbreaker and Vacuum unit fractionator overheads. This may require a change in approach

to the traditional techniques of corrosion control applied in these areas.

Corrosion mitigation changes due to the light organic acids depend on whether the new acids

are strong acids or weak acids. The more cost effective approach if the weak acid content

increases is to increase or choose a more tenacious overhead filming amine. If the overhead

organic acids are strong acids, a neutralizing amine should be enlisted to protect against low

pH dew point corrosion.

In addition, the recycling of wash water from such units back to the crude desalters has been

noted to carry light organic acids back to the crude and subsequently the atmospheric

distillation unit overheads. All wash water stream routings should be reviewed to define

potential areas of concern and corrosion inhibitor program (if required).

Desalting: Naphthenic acid crudes have natural emulsification tendencies. As the pH of the

water inside the desalter increases, the sodium naphthenates can form very stable emulsions.

Maintaining an acidic effluent desalter water is important to combat the role sodium

naphthenates play in desalter upsets.

Asphaltene destabilisation can also lead to desalter upsets. If asphaltenes become unstable

ahead of or within the desalter they can act as emulsion stabilisers, causing the emulsion layer


to grow inside the desalter until water is shorting out the grids, oil leaves with the effluent

brine, or both. Ondeo Nalco has resolved these emulsions in several locations with an

asphaltene stabiliser injected ahead of the desalters. In every case the primary demulsifier

was reduced after the asphaltene stabiliser brought the system under control.

Another desalter concern when processing opportunity crudes is the natural conductivity of

the crude. Some heavy opportunity crudes have high enough natural conductivity they have

been known to increase the amps across the desalters to the point where the dehydration

suffered.

Fouling: In addition to the fouling potential due to asphaltenes in the crude, fouling can also

occur in downstream units due to corrosion by-products. The corrosion by-product of

naphthenic acid corrosion is iron naphthenate. Corrosion mitigation is required to prevent

premature fouling/cleanings due to the buildup of naphthenic acid corrosion by-products.

Side-cut Stability

In some circumstances processing high levels of naphthenic acid crudes has led to oxidation

of the VGO causing it to turn black within hours. Ondeo Nalco has treated this condition

successfully with a chemical stabiliser.

Another common side-cut problem when processing naphthenic acid crudes is a lower diesel

cetane number. Naphthenic acid crudes typically have a low cetane number. Allowance

should be made either for the use of a cetane improver or an amount of higher cetane gas oil

available in the refinery pool for blending.

LABORATORY STUDIES – GRANE CRUDE

Typical analysis of new opportunity crude – Grane crude was recently analyzed by Ondeo

Nalco Energy Services to assist the producers, Norsk Hydro, in defining the crude

characteristics specific to concerns relating to processing as a high acid crude. The process

includes testing for naphthenic acid concentration, corrosivity, desalting difficulty and fouling

potential. Comparisons are then made on performance to other crudes available on the market

to better evaluate the results as a whole.


Naphthenic acid content / distribution

The

in t

sho

How

pro

ERTC

Figure 3 Grana Crude - TAN / NAT Analysis

0

0.5

1

1.5

2

2.5

3

3.5

4

WholeCrude

C5 -165

165-250 250-320 320-350 350-375 375+ 375-420 420-525 525-565 565+

Temperature Range (Centigrade)

mg

KOH

/ g

distribution of naphthenic acids is provided in Figure 3. Note the NAT numbers

he 320-350 and 350-375 oC cuts represent almost all the TAN, whereas the hotter cuts

w the NAT becoming a smaller percent of the TAN.

Naphthenic Acid Distribution Profiles

250

300

350

400

450

500

550

600

650

700

750

0 20 40 60 80 100

% Distilled

Tem

pera

ture

(Cen

tigra

de)

Gryphon

Grane

Heidrun

Figure 4

120

does this compare to other crudes? A Figure 4 (above) shows the distribution

file for Grane, Heidrun and Gryphon.

2002, Paris, France Page 8 of 8 Ondeo Nalco

The main difference between Grane and the other crudes is that it seems to have a heavier

“Tail” of naphthenic acids. On the plus side is the fact that the acids are more evenly

distributed across cuts than Heidrun and so larger concentrations could be run of the crude

before the same level of naphthenic acids were encountered in the various cuts.

Corrosivity of the Naphthenic Crudes

Further corrosion testing conducted on the Grane crude gives a fair representation of what

would happen in areas of single phase flow such as in the atmospheric crude residue and in

the lower pump around circuits / draws. The resid fraction was tested using a spinning

autoclave. The base (no inhibitor) corrosion rate was approximately 0.56 mm/y (22 mpy) for

carbon steel and 0.53 (21 mpy) for 5-Cr.

Application of Ondeo Nalco’s Phosphorus based inhibitor resulted in corrosion rates of

0.07mm/y (2.6 mpy) and 0.08 mm/y (2.9 mpy) respectively. The results obtained in the test

work correlates well with corrosion rates seen in the field for crudes such as Heidrun and

Captain. Typical corrosion rates for 40% of these crudes in an otherwise non-naphthenic

crude feed, and of low overall sulphur (<1%) are typically in the range 20 – 40 mpy.

Obviously there is always variation due to the orientation of equipment / temperature

variations and residue temperature.

Desalting Evaluation

Tests using a laboratory desalter showed Grane has a strong emulsifying tendency, very

similar to that of Harding.

In Figure 5 we have compared Grane to Harding and Forties with respect to water separation

Figure 5 Water Separation - Whole Crude NoDemulsifier

0

10

20

30

40

50

60

0 5 10 15 20 25 30 35 40 45Time (Mins)

% W

ater

Sep

arat

ed

Forties Harding Grane


without demulsifier.

With Forties, some separation is seen, even without demulsifier. Grane has some free water

and Harding the most emulsifying of the group.

Figure 6 Whole Crude - With Demulsifier

0

10

20

30

40

50

60

70

80

0 10 20 30 40 50 6

Time (Mins)

% W

ater

Sep

arat

ed

0

Forties Harding Grane

Figure 6 shows further comparisons are made with demulsifier. In this case we see that with

demulsifier, we do get separation, although performance is still behind that of Forties,

indicating that the naphthenic crudes form more stable emulsions.

Finally, we can compare a typical crude slate against a Forties standard and this is shown in

Figure 7;

Figure 7 Whole Crude - With Demulsifier

0

10

20

30

40

50

60

70

80

0 10 20 30 40 50 6

Time (Mins)

% W

ater

sep

arat

ed

0

Forties 30% Grane : 70% Ekofisk


In this case we compare a Forties blend against a 30% Grane: 70% Ekofisk blend. By use of

demulsifiers we see that we can obtain the same performance with respect to water separation.

This indicates that providing the correct demulsifier is selected that desalter operations should

not be detrimentally affected by the processing of Grane crude, despite its higher emulsion-

forming tendency.

Fouling Tendency

The test Ondeo Nalco uses for determining the fouling potential of a crude or stream is called

the Fouling Potential Analyser, or FPA. Flocculation can be detected by reflection of light on

flocculated asphaltenes. By making use of fiber optics light is transported into the test

solution. After flocculation has occurred, light is reflected and transported by separate fibers

to a detector, thus replacing the need for sampling and microscopic examination. The FPA is:

· A simple, high precision technique

· Results NOT operator dependant

· Runs at ambient conditions

· Relatively small and easy to transport

· Computer interfaced

The FPA value translates to a fouling potential that has been indexed so crudes can be

evaluated and refiners can be proactive when preparing to process these crudes.

FPA Value Index Predicted Fouling

<30 Severe

30-40 High

40-60 Medium

60-70 Low

70-100 Very low

Grane stability is similar to that of other North Sea crudes with respect to asphaltene

precipitation. i.e. it is very stable and unlikely to cause asphaltene precipitation on its own.

For comparison, FPA results for known fouling crudes are as follows: REB ~ 63, Kirkuk ~

45, Urals ~ 56, and Maya < 40. The fouling tendency of Grane crude is documented in Table

3 below.


TABLE 3 – Fouling Study

on Grane Crude

Crude ‘Major’ Flocculation

Point – FPA Value

100% Grane 77

70% Grane, 30% Ekofisk 75

30% Grane, 70% Ekofisk 76

FIELD STUDIES – the Fast Flow Loop

Based on our experience, heavy vacuum gas oil (HVGO) is the most common observed area

for naphthenic acid corrosion. This side stream, in most cases, tends to have a temperature

profile suitable for distilling a high proportion of acids while maintaining temperatures

necessary for promoting corrosion. Therefore, to allow dynamic testing on line a high

velocity flow loop has been developed for installation in such streams. A diagram of the unit

is provided in Figure 8.

The system allows for simultaneous monitoring of the streams with and without a naphthenic

acid corrosion inhibitor. Allowing a true base line and protection provided in situ. This is

important to eliminate potential differences arising from the processing of slightly different

crude slates. Each loop may contain probes and coupons of various metallurgies. Typically

Figure 8


Cr T20 tubular (or occasionally flush mounted) resistance probes, connected to a data logger

are installed to allow continuous monitoring of corrosion rates during the test runs.

For the period of testing, flow rates may be set to the required velocity set to provide a

velocity of 5 ms-1. Temperature is normally limited to that of the side stream under

evaluation. In practise this process has been defined as suitable for monitoring naphthenic

acid corrosion mechanisms.

The chemical selected for the study was Ondeo Nalco’s SCORPION EC1242A, a phosphorus

based material, which has been shown to provide excellent performance in the past for

mitigation of naphthenic acid based corrosion(4,10). Prior to processing naphthenic crudes,

metal surfaces are normally pre-passivated with a conditioning dosage of the chemical,

typically 20 - 30 ppm (by weight) of product, reducing to 5 - 15 ppm (by weight) for normal

control.

Examples of test results that have been obtained follow. Corrosion probe results for the

HVGO system under evaluation are detailed in graphical form in Figure 9. Temperature of

operation Ca. 290oC (554 oF).

TAN levels for this particular evaluation were recorded are ranged from 0.2 to almost 1.6

with an average TAN of 0.9. Note the benefit the on-line datalogger brings to the trial. The

untreated probe showed steady corrosion while the chemically inhibited probe showed almost

no corrosion.

The coupons were arranged as mirror images – four prior to the inhibitor and four after. The

metallurgies chosen were: 1018 carbon steel, A182F2 steel, L80-9Cr, and 316L SS. Coupons

were exposed for thirty days at temperatures Ca. 300 oC (572 oF) and naphthenic acid content

of up to 2 mg KOH / g hydrocarbon.

Inspection of unprotected and chemically treated coupons clearly reveal the protective layer

induced by the chemical inhibitor and the etching on the untreated carbon steel and untreated

A182F2 steel coupons. The L80-9Cr untreated coupon showed etching on the leading edge of

the coupon. The 316L SS untreated coupon was the most corrosion resistant and did not

show etching, but was discoloured compared to the treated 316L SS coupon.

Insertion of coupons into the flow loop or into the system allows rapid determination of the

resistance of a given metallurgy to naphthenic corrosion within the system and effectiveness

of the corrosion inhibition program when applied.


Figure 9. Corrosion monitoring results

mm

)

l Los

s (

Met

Figure 7. HVGO TAN levels

0/199

9/199

9/199

9/199

0

0.01

0.02

0.03

0.04

0.05

0.06

05/39

06/09

06/19

06/29

07/09/1999

07/19/1999

07/29/1999

08/08/1999

08/18/1999

08/28/1999

09/07/1999

09/17/1999

Date

a

With Inhibitor Untreated

Corrosion Rate for period = 0.11mm/yr (4.3 mpy)

Corrosion Rate for period = 0.0035 mm/yr (0.2 mpy) With Inhibitor

UNTREATED

Working with such a flow loop provides the opportunity to:

1. Easily change metallurgies on-line

2. Determine the effect of inhibitor on different metallurgies that may be present in the

system.

3. Compare probe types and performance. (Failure rates may be as high as one in three

under conditions encountered in systems installed.)

Generally, any movement on corrosion rate is indicative that corrosion will be occurring in

the system. Monitoring would be correlated to other types such as UT, Radiology, or Field

Signature Method (FSM), etc. However, for control purposes, chemical injection normally

commences when positive movement of the probe is observed.

Another measure of corrosion commonly used is the change in concentration of dissolved iron

and nickel produced by the corrosion process. Normally, various streams are measured for

Nickel and Iron content – this is correlated to corrosion coupon or probe activity with time.


An Fe concentration in the 3-5 ppm range for three consecutive samples is considered to

indicate an unexpected corrosion condition whereas values less than this indicate moderate

corrosion down to 0.4 ppm or less which is the value considered acceptable. [1,3]

Iron levels can also give a good indication of control within a system. Figure 10 details

results for a separate system (suffering vacuum tower corrosion) with and without chemical

inhibitor injection. Figure 11 details corrosion rates for the same system using a 9-Cr probe

obtained during initial response testing on injection of the corrosion inhibitor to the system.

Response for the application was found to be immediate. Corrosion inhibitor injection rates

were in the range 6 – 25 ppm.

Figure 10. Iron Levels and in-line probe – HVGO draw

Readings From Chrome Probe In Vac Unit HVGO Draw Off

2.15

2.16 2.17

2.18

2.19

2.2

30-May 19-Jun 09-Jul

Rs/

Rr

SCORPION Injection

Commenced

Note the steady corrosion rate prior t

“levelling off” of the corrosion rate

turned off there is a gradual increas

same rate as prior to chemical treatm

interruptions in chemical injection

rates/failures.

This test loop data was at a relativel

film persistency would tend to be we

ERTC 2002, Paris, France

SCORPION Injection Ceased

29-Jul 18-Aug 07-Sep 27-Sep 17-Oct Date

o chemical injection commencement, then the immediate

while the inhibitor is injected. After the inhibitor is

e in corrosion rate (slope) until corrosion is back to the

ent. A good inhibitor film will release slowly, so short

(pump failures) will not lead to catastrophic corrosion

y constant velocity. It should be noted that the inhibitor

aker in high velocity and turbulent areas, so care should

Page 15 of 15 Ondeo Nalco

be taken to reduce the amount of time an inhibitor pump is out of service. A high temperature

corrosion inhibitor pump failure should be a high priority item for maintenance.

Figure 11. In-line corrosion probe results – HVGO draw

In practise the effectiveness of the inhibitor has found to provide typically 90% corrosion

inhibition against the base level of naphthenic corrosion. World Wide there are currently over

40 successful applications in place using Ondeo Nalco naphthenic acid corrosion inhibitors,

treating streams with NAT levels from as low as 0.2 to >6.5 and system velocities as high as

100ms-1. Where Ondeo Nalco naphthenic acid inhibitors have been used, no failures due to

naphthenic corrosion have ever been recorded.

SUMMARY

Risk based assessment of the Refinery facilities clearly defines areas for concern if blends of

crudes containing naphthenic crudes were to be processed. Analysis will identify all areas

exposed to risk of corrosion and requirements to be considered / analysed prior to processing

naphthenic crudes.

High temperature Fast Flow Loop studies can be used to more accurately define the corrosion

potential of susceptible areas.

Analysis using the Fast Flow Loop provides information on the order and magnitude of

corrosive attack by naphthenic species in the absence of corrosion inhibitors under conditions

anticipated in refinery equipment. It can also be used to conduct metallurgy studies and the

effectiveness of corrosion inhibitors applied to the system.


Studies and field experience have shown that corrosion inhibitors can be highly effective for

the control of naphthenic corrosion in high temperature, high NAT and high velocity

conditions.

Corrosion probe analysis can be used to confirm results obtained with corrosion coupons (or

vice versa).

Opportunity crudes can have associated processing problems in addition to naphthenic acid

corrosion. Desalter upsets, preheat and reactor bed fouling, side-cut stability and cetane

issues can all be present. Mitigation strategies exist for all ancillary problems and can be

addressed in a timely manner if the refiner is prepared.

Norsk Hydro’s new Grane crude was shown to be a very good opportunity crude. The

Grane/Ekofisk blend dehydrated with equal efficiency to a know crude. The fouling potential

was analysed and shown to have a low fouling potential. The corrosivity was analysed and

chemical inhibitors were shown to effectively reduce the corrosion rate by 90%.

With metallurgy and/or application of naphthenic corrosion inhibitor, naphthenic crudes can

be safely processed on the unit to higher levels today than was possible in the past.

REFERENCES

[1] National Petroleum Research Association - Questions and Answers Session on Refining

and Petrochemical Technology - Houston - March 1994

[2] E. Babian-Kibala et al, Naphthenic Acid Corrosion in A Refinery Setting”, Paper

number 631, The NACE Annual Conference, March 1993.

[3] J.Gutzeit, Naphthenic Acid Corrosion in Oil Refineries, Materials Performance, 16

(10), 24-35, October 1977.

[4] National Petroleum Research Association, Questions and Answers Session on Refining

and Petrochemical Technology, Houston, March 1992

[5] J. Skippens, D. Johnson, R. Davies, Evaluation of the economics for the processing of

Naphthenic Crudes. International Conference for Corrosion in Refinery Petrochemical

and Power Generation Plants. Venice 18 – 19 May, 2000.


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Naphthenic Acid Corrosion