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Influence of different sulfur compounds on corrosion
due to naphthenic acid
Omar Yepez*1
Department of Chemistry, Memorial University of Newfoundland, Prince Philip Drive, St John’s, Nfld, Canada A1B 3X7
Received 15 October 2003; revised 21 June 2004; accepted 12 August 2004
Available online 9 September 2004
Abstract
The influence of different sulfur compounds on corrosion due to naphthenic acid was studied by means of the new method FeNCORe. It
was found that such influence occurs after the reduction of the given sulfur compound by the cathodic reaction of the overall process of
naphthenic acid corrosion. When the reduction product is H2S the formation of a potentially protective layer of FeS occurs, whereas when the
reduction product is H2O, coming from the reduction of sulfoxides, the naphthenic acid corrosion is enhanced. These findings help to
understand crude oil corrosivity behavior and serve as a warning for blending.
q 2004 Elsevier Ltd. All rights reserved.
Keywords: Sulfur compounds; Naphthenic acid corrosion; Mechanism
1. Introduction
The mechanism of corrosion due to naphthenic acids is
still a question mark in the material science agenda. The
corrosion by the naphthenic acid occurs via the chemical
reaction with the iron, and sulfur limits corrosion through
formation of a surface film. Other chemical factors that
could influence this reaction are simply unknown. There-
fore, plant engineers are concerned with the total acid
number (TAN) of the crude oil, but the naphthenic acid
problem remains and it is not likely to be associated with
the TAN.
On the other hand, crude oil related corrosion due to
naphthenic acids is quite complicated, due to multiple
factors. When a crude oil or its distillates corrode the steel, it
is not possible to separate which factors; such as the sulfur
amount and/or the TAN, are determinant in the corrosion
process. Therefore, the fundamental study of the corrosion
of iron by the naphthenic acids and their relationship with
0016-2361/$ - see front matter q 2004 Elsevier Ltd. All rights reserved.
doi:10.1016/j.fuel.2004.08.003
* Tel.: C1 7097374005; fax: C1 7097373702.
E-mail address: [email protected] American Chemical Society Active Member.
the kinds of sulfur compounds (which may be present with
the crude oil) is of a paramount importance.
The Iron Powder Test, FeNCORe [1,2], appears as a
unique method to assess naphthenic acid corrosion activity.
Therefore, it can be used to explore the influence of other
sulfur-based compounds (with different reactivities) that
may be present, since an increase or decrease in the amount
of dissolved iron by the naphthenic acid, will depend on the
inhibitory or catalytic effect that such sulfur-based com-
pound may have on the naphthenic acid attack.
The naphthenic acid corrosion accepted mechanism
(which produces an oil soluble corrosion product, iron
naphthenate) involves the presence of hydrogen sulfide
(which produces an oil insoluble corrosion product, iron
sulfide) as follows [3,4],
Fe C2RCOOH/FeðRCOOÞ2 CH2 (1)
Fe CH2S/FeS CH2 (2)
FeðRCOOÞ2 CH2S/FeS C2RCOOH (3)
Reaction (1) produces the oil-dissolved iron, reaction (2)
inhibits dissolved iron production and reaction (3)
Fuel 84 (2005) 97–104
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O. Yepez / Fuel 84 (2005) 97–10498
destroys the oil dissolved iron amount in solution. Since the
dissolved iron quantity will be affected by all three
reactions, the Iron Powder Test can be used to verify this
mechanism.
According to the sulfur compound functionality, they
may: (1) inhibit, (2) assist or (3) do not affect, the
naphthenic acid corrosion. In the first case the amount of
oil-dissolved iron will diminish with respect to the
control experiment. In the second, it will increase and in
the third case, the amount of oil-dissolved iron will remain
constant.
Since difficulties are faced in the analysis of the different
sulfur compounds within a crude oil, corrosion engineers
tend to use the total sulfur as a measure of the reactivity of
the sulfur compounds in the crude, when, at best, that is a
poor method for estimating the probability of the presence
of a corrosive sulfur compound. The amount of sulfur in a
crude oil (total sulfur) says nothing about its reactivity. For
example, H2S and mercaptans (R-SH) are very reactive
toward iron, producing a FeS protective layer. By contrast,
organic sulfur compounds such as thiophene family have
little reactivity toward iron. In this sense, another possibility
is the presence of sulfur-based compounds containing
oxygen, such as sulfoxides, because its reduction product
is water [5,6] and the presence may influence naphathenic
acid corrosion:
R2S Z O CRSH/R2S CRSSR CH2O (4)
R2S Z O CH2/R2S CH2O (5)
The occurrence of reactions (4) and (5) and the
subsequent enhancement of naphthenic acid corrosion, due
to in situ water formation could explain exceptional cases of
naphthenic acid corrosion, which contradicts previous
theories. For example, severe naphthenic acid attack has
been detected in carbon steels when processing sweet crude
oils from western Africa, even though these crude oils have
a low TAN (less than 0.5 mgKOH/g) and a low sulfur
content (less than 0.5%) [7].
The presence or absence of protecting sulfur compounds,
could explain also why TAN is not a good measure of the
crude oil corrosivity [8]. Therefore, the combination of two
factors, the presence of the right sulfur compound and
naphthenic acids, may trigger the naphthenic acid attack. In
the particular case of the presence of sulfoxides and
naphthenic acids, for example, the by-product of the
reduction of such sulfur compound is water, which may
trigger the naphthenic acid corrosion by providing a
medium where the naphthenic acid can dissociate easily.
Therefore, the naphthenic acid corrosion process, in the
presence of sulfoxides, becomes autocatalytic. This, of
course, will prevent the formation of a protective layers and
a severe naphthenic acid corrosion will occur.
Crude oil sulfoxides have been intensively studied by
Okuno et al. (1967) [9], whom reported the elemental
formulae C13H24SO (a saturated heterocyclic compound for
the major component found). Using ionic exchange
chromatography on the distillation fraction between 250
and 500 8C, these sulfoxides were isolated. Its presence was
established by the use of the S–O stretch infrared band at
1030–1070 cmK1. Finally, it was determined that such
compounds will not occur naturally in oil, but they are the
result of a mild oxidation in air at relatively low temperature
(85 8C) during the storage of the crude oil [9].
This oxidation had been extensively reviewed in the
literature [10].
In this paper, a study of the influence of different types of
sulfur compounds on the naphthenic acid corrosion process
is reported. Enhancement, inhibition and inactivity toward
the naphthenic acid corrosion were observed, depending on
the kind of sulfur compound present. In particular, the case
in which the enhancement occurs is of interest, since it had
been found that TAN does not determine crude oil
corrosivity.
2. Experimental
2.1. Influence of sulfur compounds on naphthenic
acid corrosion
The Iron Powder Test [1,2] was used to measure the
amount of dissolved iron by naphthenic acid solutions in
liquid paraffin. The method consists of allowing the
reaction between a stoichiometric excess of iron powder
and the naphthenic acids present in a sample. This is done
in a 50 ml reactor, where 25 g of the sample and 2.5 g of
iron powder (0.1 m2/g) are allowed to react during 1 h at
100 rpm, at different temperatures, namely, 140, 180, 220,
260, 300, 340 and 380 8C. After reaction, the reaction
mixture is filtered and the filtrate is sent to measure the
dissolved iron by Inductively Coupled Plasma (ICP)
emission spectroscopy, using the ASTM-5708-95. A plot
of [Fe] in ppm (weight by weight, w/w) versus temperature
can be created, a four degrees polynomial fit is used with
these data. Most of the time a volcano plot results, the
value of the maximum amount of dissolved iron given by
this plot, regardless the temperature of the maximum, is the
final result. This was used with the control experiment,
which in most cases was Naphthenic acid Fluka 0.14 M in
liquid paraffin (just in the case of butylmercaptan
experiment, 0.07 M naphthenic acid was also used). In
the case of the reaction between naphthenic acids with
iron, in the presence of hydrogen sulfide (H2S), after the
control experiment sample was located in the reactor,
200 psi of pure H2S and/or its solutions in nitrogen 10, 7.5,
6, 5, 1 and 0.1% were loaded to the reactor. The others
sulfur-based compounds were obtained from Aldrich. The
direct effect of different sulfur compound functionalities on
the naphthenic acid reaction with iron can be observed by
measuring the variations on the iron amounts in the 0.14 M
naphthenic acid in liquid paraffin, which typically was
O. Yepez / Fuel 84 (2005) 97–104 99
3000 ppm of dissolved iron. Therefore, the results could be
any of the following:
(1)
Tabl
Satu
this
Crud
A
B
C
D
E
F
To show the same iron levels as in the blank, i.e. this
sulfur compound has no effect in the naphthenic acid
reaction toward iron.
(2)
To show less dissolved iron than in the blank, i.e. thissulfur compound may inhibit the reaction, which could
occur by forming a FeS protective layer.
(3)
To show more dissolved iron than in the blank, i.e. thissulfur compound assists the naphthenic acid corrosion.
Fig. 1. Iron Powder Test results for [RCOOH]Z0.14 M in the presence of
different concentrations of H2S in nitrogen as a gas solvent. The square
points are the expected amount according with the mechanism depicted in
Eqs. (1)–(3).
2.2. Crude oil studies
The stage of sulfur (either elemental sulfur or sulfate)
observed on the iron powder after reaction, only in the case of
crude oils A and D were determined by X-ray photoelectron
microscopy (XPS). Crude oils A–D and F were separated in its
saturates, aromatics, resins and asphaltenes (SARA), with an
extra procedure, which separates resins in strong and weak
[11]: a sample of an desasphaltated crude oil was injected and,
initially, it was eluted with cyclopentane through a cyan–silica
column, SiO2–CN, where the most polar compounds (strong
resins) were retained. The others compounds continued to
another silica column, where the less retained compound
(saturated) were eluted. Aromatics and weak resins were
maintained on the second silica column, SiO2. Once the
saturated were eluted, the solvent flux was inverted through
the cyan column and by changing the solvent polarity to
chloroform–methanol strong resins were separated. To
separate the weak resins in the silica column, pure chloroform
was used. Within Table 1, the different concentrations (w/w)
of the oil fractions described, are shown. Infrared spectra were
performed on these strong resins. TANs were determined with
the ASTM-D664. The sample total sulfur, %S, was deter-
mined with the ASTM-D2622.
3. Results and discussion
3.1. Influence of sulfur compounds on naphthenic
acid corrosion
On Fig. 1, it is observed how the dissolved iron produced
by the controlled experiment, which is typically 3000 ppm
e 1
rated, aromatics, strong and weak resins for different crude oils used in
paper
e oil Saturated %
(w/w)
Aromatics
% (w/w)
Strong resins
% (w/w)
Weak resins
% (w/w)
26 48.8 20.2 5.0
70.5 23.4 5.9 0.2
29.1 46.8 20.8 3.3
33.3 44.4 19.5 2.8
29.2 50.1 18.1 2.6
12.7 42.2 29.9 15.2
in a H2S free environment, is influenced by the different
starting H2S concentrations in nitrogen at 200 psi and 25 ml
of gas reactor volume. These conditions produce a starting
mole amount, which in the case of 100% H2S is
14,100 mmol. As the percentage of H2S is decreased, this
initial mole amount decreases accordingly. As was
expected, there are H2S concentrations where there is no
dissolved iron: 100% H2S, concentrations where the amount
of dissolved iron is very little: 10 and 7.5% H2S. And when
the starting H2S concentration is diminished to 6%, which is
846 mmol of H2S, the dissolved iron began to be appreciable
(w1000 ppm, one third of the typical amount).
The amount of iron for this reaction was 44,800 mmoles
(2.5 g), which is three times more than the H2S mole amount
used in the case of 100% H2S. It is therefore impossible that
the hydrogen sulfide consumes the iron totally, in any of the
concentrations used. Moreover, X-ray dispersion of the iron
powder after reaction showed elemental iron and the
formation of FeS in the reactions with H2S 100% at 220,
260 and 300 8C, which corroborates that the amount of iron
is not consumed. Given this, it is most probable that the
reaction between iron and the H2S produces a surface layer
of FeS.
The number of moles of superficial iron (2.5 g iron,
0.1 m2/gZ2500 cm2) in these reactions is 7 mmoles. Even
the minimum amount of hydrogen sulfide used, 14 mmoles
(0.1%), is doubled the number of moles of surface iron.
Therefore, a FeS layer should appear preventing the
naphthenic acid attack. The fact that this is not happening
up to H2SZ1057 mmol (7.5%, 150 times more than the
needed), implies that another reaction is consuming H2S.
Assuming that, in all the H2S concentrations, the amount of
iron naphthenate would arrive to 3000 ppm (i.e.
1342 mmol), the difference between this amount and the
number of H2S moles would be the remaining iron
naphthenate concentration. The square points in Fig. 1 are
Fig. 3. Dissolved iron versus temperature for [RCOOH]Z0.14 M in liquid
paraffin (circles and line) and the effect of butylmercaptan [BM], 0.14 and
0.28 M, in that solution.
O. Yepez / Fuel 84 (2005) 97–104100
the dissolved iron amount that would be expected after
reactions (1) and (3), happens. Regardless of the high
dispersion found, the fact that such theoretical points are
very near to the experimental ones, at lower concentrations
of H2S, possibly indicates that the iron naphthenate
produced through (1), is reacting with the hydrogen sulfide
through (3). Only at higher H2S concentrations (i.e. 7.5%)
does reaction (2) prevails over reaction (1). In other words,
reaction (1) is faster than (2) at relative lower H2S
concentration, whereas reaction (2) is faster than (1) at
higher H2S concentrations. As a consequence, hydrogen
sulfide has no inhibitor effect toward naphthenic acid
corrosion at lower H2S concentrations. On the contrary,
lower H2S concentrations consume iron naphthenates,
accelerating (1). At higher H2S concentrations, there is a
deviation from the behavior where reaction (3) predomi-
nates. In this sense, at 7.5% of H2S, the theory predicts
638 ppm of dissolved iron, but just 50 ppm were found (see
Fig. 1), which corroborates that reaction (2) is faster than
(1), a protective layer of FeS is formed and this prevent
further attack by the naphthenic acid.
On Fig. 2 butylmercaptan [BM] is added instead of
hydrogen sulfide in the same kind of experiment. In this case
two sulfur compounds concentrations, 0.14 and 0.28 M, and
the naphthenic acid was 0.07 M in liquid paraffin. At lower
temperatures (140–180 8C) and either any concentration of
the sulfur compound, there is no major inhibition and the
dissolved iron levels are similar to the blank, whereas at
220 8C and higher there is a progressive reduction in the
amount of dissolved iron. If the mercaptan concentration is
increased to 0.28 M, the amount of dissolved iron behaves
in the same way as the previous concentration of such sulfur
compound. This may indicate that the amount of acid, and
not the amount of mercaptan, is controlling the corrosion
inhibition and/or the destruction of iron naphthenate. If the
acid concentration is increased to 0.14 M (see Fig. 3),
Fig. 2. Dissolved iron versus temperature for [RCOOH]Z0.07 M in liquid
paraffin (circles and line) and the effect of butylmercaptan [BM], 0.14 and
0.28 M, in that solution.
protons availability is increased and, therefore, the surface
inhibition is more noticeable. To show this effect more
quantitatively, in Table 2, the difference between the
dissolved iron (in ppm), with or without the mercaptan at
260 8C is shown for both acid concentrations (cf. Figs. 2
and 3). Therefore the mercaptan, to be active toward the
mechanism of reactions (1)–(3), first needs to be reduced to
H2S (i.e. it needs hydrogen). The cathodic reaction of the
naphthenic acid corrosion process is the source of this
hydrogen. The same will be produced on the iron, which
serves as a catalyst for the sulfur compound reduction
process [6] through,
Fe C2RCOOH/FeðRCOOÞ2 CH2 (6)
RSH CH2/RH CH2S (7)
At lower temperatures, there is not enough hydrogen to
reduce the mercaptan, there is no H2S and the effect of the
mercaptan on the dissolved iron is low. At higher
temperatures, there is enough hydrogen produced by the
naphthenic acid corrosion process to reduce the mercaptan,
producing more H2S and, therefore, diminishing the
dissolved iron amounts either through reaction (2) or (3).
On Fig. 4 the influence of benzyldisulfide concentration
[BDS] can be observed. This presents more or less the same
performance given by the mercaptan at the same concen-
tration of naphthenic acid. However, at 0.28 M of this sulfur
compound, a stronger inhibition than the previous case is
observed, being 0 ppm of dissolved iron at all temperatures
Table 2
Dissolved iron amount difference ([Fe] from blank minus [Fe] from blank
with mercaptan) at 260 8C in the experiments of Figs. 2 and 3
[RCOOH]Z0.07 M [RCOOH]Z0.14 M
[RSH]Z0.14 M 447 1787
[RSH]Z0.28 M 509 2850
Fig. 4. Dissolved iron versus temperature for [RCOOH]Z0.14 M in liquid
paraffin (circles and line) and the effect of benzyldisulfide [BDS], 0.14 and
0.28 M, in that solution.
Fig. 6. Dissolved iron versus temperature for [RCOOH]Z0.14 M in liquid
paraffin and the effect of dimethylsulfoxide [DMS], 0.28 M, in that
solution.
O. Yepez / Fuel 84 (2005) 97–104 101
above 220 8C. Possibly, this is because the benzyldisulfide
has more sulfur by molecule than the mercaptan and
therefore, it will produce more H2S under the same
reduction conditions. Also the benzyl group will help this
compound toward reduction because it is a good leaving
group. This result could mean that polysulfides are good
inhibitors of the naphthenic acid corrosion. As a matter of
fact, the use of polysulfides as naphthenic acid corrosion
inhibitor has been reported [12,13]. Therefore, the ability of
H2S production and the amount of sulfur within the
molecule seems to be important factors for the inhibition
of naphthenic acid corrosion.
The influence of thiophene concentration [T] can be
observed on Fig. 5. This is a case where the sulfur
compound does not affect the iron-dissolved levels of the
blank. The same response was obtained by benzothiophene,
dibenzothiophene and sulfones (not shown). Continuing
with the reasoning previously described, the hydrogen
Fig. 5. Dissolved iron versus temperature for [RCOOH]Z0.14 M in liquid
paraffin and the effect of thiophene [T], 0.28 M, in that solution.
produced by the naphthenic acid corrosion and the
temperatures used are not enough to reduce this compound.
Therefore, no H2S will be produced and no effect on the
dissolved iron levels will be detected. This behavior is easily
understood in the case of thiophenes, since their aromaticity
make them stable enough to prevent them to undergo
reduction under these conditions. In the case of sulfones, it
is reported that they are more resistant to reduction, in
comparison with sulfoxides [14].
The influence of 0.28 M dimethylsulfoxide is observed
within Fig. 6. A maximum of dissolved iron is observed at
140 8C, where the maximum of the blank lies between 260
and 300 8C. At 140 8C, this compound increases the amount
of dissolved iron from a means of 122 ppm in the blank to
2133 ppm. This means that sulfoxides assist the naphthenic
acid corrosion process. The reduction of a sulfoxide
produces water [5] through,
R2S Z O CH2/R2S CH2O (8)
And this water will be produced in the worse place, the
cathodic reaction zones of the naphthenic acid corrosion
process. This water provides protons as well as helps the
acid to dissociate more easily, triggering the cathodic
reaction and, therefore, the overall corrosion process. In this
way, the dissolved iron at 140 8C increases to levels found in
the blank, but at higher temperatures (300 8C). As the
temperature is increased there is, however, a decrease of the
dissolved iron amount. Nevertheless, it is known that iron
naphthenate begins to decompose at temperatures higher
than 200 8C [15]. Further disappearance of dissolved iron
can be attributed to: (1) the water produced can react with
the iron naphthenate, destroying it, or (2) the sulfide
produced after the reduction of the sulfoxide react with
more hydrogen to produce H2S and it reacts to the iron
surface passivating it, or (3) both processes finish with the
iron dissolved at higher temperatures.
Scheme 1. Probable mechanism for the assistance and/or passivation of the
naphthenic acid corrosion.
O. Yepez / Fuel 84 (2005) 97–104102
In Scheme 1, the possible sulfur compound reactions that
possibly are occurring during the naphthenic acid corrosion
process are shown.
As it could be seen, the sulfur compound reduction needs
hydrogen, which is generated by the naphthenic acid
corrosion process. Then, depending on the kind of sulfur
compound and its reactivity, it could either passivate the
surface by FeS formation through H2S attack, or accelerate
the cathodic reaction of the overall naphthenic acid
corrosion process by the formation of water within such
cathodic zones.
In the light of this discovery and depending on the
boiling point of the possible sulfoxides that may occur in
crude oil, such naphthenic acid cathodic corrosion reaction
triggering could happen at any temperature. Therefore, it is
necessary to determine what sulfoxides actually occur in
crude oils, because the presence or absence of this
compounds completely change the view of the naphthenic
acid corrosion. As a matter of fact, it has been reported the
presence of heterocyclic sulfoxides with the elemental
formulae C13H24SO [9]. Those sulfoxides could accumulate
in the distillation streams in the refinery process, where the
naphthenic acid actually accumulates and, therefore, a
severe naphthenic acid related corrosion would occur.
Table 3
Iron Powder Test results for different crude oils, plus its %S, TAN, maximum di
Crude oil % S Iron Powder Test (ppm) TA
A 3.66 64 0.3
B 0.05 12 0.0
C 2.56 33 1.5
D 2.19 25 1.5
E 2.41 38 2.0
F 5.70 50 1.3
[RCOOH]Z0.07 M 0.002 505 5.4
[RCOOH]Z0.14 M 0.003 3000 11.
3.2. Crude oil studies
Different crude oils and mixture therein were examined
with the Iron Powder Test. In Table 3 the maximum amount
of dissolved iron measured by the method is presented,
where the results include the amount that a given crude oil
could dissolve according to its TAN (assuming an average
molecular weight of 286 g/mol, which belongs to Fluka
Naphthenic Acid, for all cases) and the efficiency associated
with each crude oil.
As it is clear from the table, the sulfur free blanks used
(%Sw0.003) showed increased naphthenic acid efficien-
cies, as its concentration is increased. Crude oils A and B
with rather low TANs, have efficiencies higher than the
blank at 0.07 M. Nonetheless, their TANs are 15–63 times
lower. These crude oils also present the highest efficiencies
in the crude oil pool, whereas the other crude oils have very
low efficiencies in comparison with either that of the blanks
and/or crude oils A or B. Since the activity of sulfoxides has
been discovered during naphthenic acid related corrosion,
this high efficiency toward naphthenic acid corrosion could
be related to the presence of sulfoxides in these crude oils.
On Figs. 7 and 8 an XPS study of the iron powder after
reaction, at different temperatures, for crude oils A and D
only are presented. On crude oil A iron powder, it is clear
the presence of two kinds of surface sulfur compounds: (1)
elemental sulfur, which probably comes from the air
oxidation of FeS produced by the reaction of the likely
sulfur compound (present in this crude oil with iron) and (2)
iron sulfate, which could come from the direct reaction
between the crude sulfoxide and the iron, since sulfoxides
are Lewis bases (accept electrons) [16], and further
oxidation with air. If this sulfate is the result of the reaction
between the crude oil’s sulfoxides and iron (Fig. 7) at lower
temperatures (naphthenic acid attack is low), the sulfoxides
react directly with iron, and it finishes as iron sulfate. At
higher temperatures, where the naphthenic acid attack is
high and, as a consequence, there is hydrogen for sulfoxide
reduction (and an enhancement of the naphthenic acid
attack itself), the direct reaction between the sulfoxides and
iron decreases and, in the same way, so does the relative
amount of iron sulfate. Therefore, a reduction of the sulfate
signal coincides with the maximum of dissolved iron.
ssolved iron allowed by its TAN and its efficiencies
N (mgKOH/g) TAN allowed [Fe] (ppm) Efficiency %
7 184 35
9 43 28
1 753 4
1 753 3
9 1042 4
5 673 7
3 2078 19
58 5774 52
Fig. 7. Sulfur stages found in the iron powder after reaction with crude oil A
(secondary axis). Iron Powder Test results for that crude are also shown
(circles).Fig. 9. Infrared absorption at 1030/cm for the strong resin of crude oils A–D.
O. Yepez / Fuel 84 (2005) 97–104 103
On the other hand, crude oil D’s iron powder after
reaction only shows elemental sulfur and no traces of iron
sulfate (Fig. 8). In this case the naphthenic acid attack is not
assisted and the conventional mechanism (reactions (1)–(3))
dominating and probably producing a protective FeS layer.
Since the activity found by dimethylsulfoxide toward the
naphthenic acid corrosion, the difference in the kind of
sulfur compounds between crude oil A and D, probably
would explain why the efficiency of crude A is 10 times
higher than the crude D’s. Another way to look at the
presence of sulfoxides in crude oil is through the
characteristic infrared absorption band at 1030 cmK1
[9,17] due to the stretch of the S–O bond. On Fig. 9 such
infrared band for the strong resins of the different crude oils
studied are shown.
As it can be confirmed, a strong sulfoxide absorption
band is shown by the crude oils with the highest naphthenic
acid corrosion efficiency (see Table 3), whereas crude oils D
Fig. 8. Sulfur stages found in the iron powder after reaction with crude oil D
(secondary axis). Iron Powder Test results for that crude are also shown
(circles).
and C show a rather low (or non-existence) sulfoxide band.
A direct consequence of these findings is that a high
efficiency crude oil should not be mixed with a low
efficiency one.
Since crude oils has a complex mixture of different sulfur
compounds. The naphthenic acid efficiency depicted in
Table 3, provides the overall trend produced by such a
mixture. Given that the difference in efficiencies between
crude oils with or without sulfoxide are very high (28–35%
versus 3–7%), this efficiency could indicate if such trend is
controlled by sulfoxides or by protective sulfur compounds.
If crude oil A, with its low TAN but presence of
sulfoxides, is blended with a higher TAN oil such as D or C,
naphthenic acid related corrosion will become more likely
to occur, because sulfoxides will go to a high TAN crude oil,
which did not have it. This, therefore, increases the
efficiency of the blend. On Fig. 10, the Iron Powder Test
result of such blends is shown for two crude oils with low
efficiency, namely blending crude E and C with the high
Fig. 10. Blending between the high efficiency crude oil A with a low
efficiency crude oil E or C.
O. Yepez / Fuel 84 (2005) 97–104104
efficiency crude A. Contrary to what is expected, an increase
of the dissolved iron amount is observed in both cases, when
crude oil A is 30% of the blend. This happens because, in
that proportion, the highest amount of sulfoxides coming
form crude A is blended with the highest amount of
naphthenic acid coming from the crude E or C. At crude
AZ15% of the blend, there is more acid but less sulfoxides.
At crude AZ50% and higher of the blend, there is more
sulfoxides but less acid and the mixture tends to behave like
pure crude A.
Given the importance of sulfoxides in the naphthenic
acid corrosion, it is a must to know the sulfoxide content in a
crude oil and/or its distillates, in order to forecast possible
naphthenic acid corrosion problems. Since it looks like
these sulfoxides are produced in certain crudes, by a mild
oxidation with air during storing [9], setting an inert and/or
reduction atmosphere in the storage vessels could avoid its
formation. Also, these findings could justify the neutraliz-
ation of naphthenic acids [18], the thermal destruction of
such acids [19,20] and/or the use of an appropriate
metallurgy for a service where the corrosion process is no
longer aprotic (i.e. there will be protons for the cathodic
reaction of the naphthenic acid corrosion attack).
4. Conclusions
The effect of sulfur compounds in the naphthenic acid
corrosion involves reduction by the protons provided by the
corrosion process. When the reduction product is H2S, the
production of FeS layer could prevent the naphthenic acid
attack. However, when the reduction product is H2O at the
naphthenic acid corrosion cathodic zones, further dis-
sociation of the acid becomes possible and the fuel for the
cathodic reaction increases, and therefore the overall
naphthenic acid corrosion.
The analysis and quantification of sulfoxides in a crude
oil is, therefore, of a paramount importance to determinate
the potential for corrosion due to naphthenic acids. The
naphthenic acid efficiency appears as the first alert of the
possible presence of such sulfur compounds.
Acknowledgements
The author is deeply thankful to L. Torres and J. Hau for
fruitful discussions, as well as to A. Gonzalez and H. Jaspe
for Iron Powder Test experiments. Also, to the Department
of Chemistry of the Memorial University of Newfoundland,
for assistance in the publication cost of this article.
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