PHOSPHATE ESTER INHIBITORS SOLVE NAPHTHENIC ACID CORROSION PROBLEMS

Elizabeth Babaian-Kibala
Nalco Chemical Co.
Sugar Land, Tex.

Crude oils containing naphthenic acids can C cause a variety of corrosion problems in any of several process areas. But because of the complexity of naphthenic acid corrosion, no routine technique is available for predicting corrosion from this source.

Certain high-temperature corrosion inhibitors with a general phosphate ester structure have shown good mitigation of naphthenic acid corrosion in commercial applications. A descriptio of two such cases will help refiners know what to look for to prevent similar occurrences in their plants,

NAPHTHENIC ACID

Naphthenic acids are a class of carboxylic acids derived from petroleum during the refining process. Naphthenic acids consist of one or more saturated cyclic rings, alkylated at various positions, and a straight-chain carboxylated alkyl group.

Some crude oils have been found to contain numerous acids of this type, which are classified according to general ring structure.1 Because of the high boiling points of naphthenic acids (400-7000 F.), they are present in the hotter parts of refinery equipment. Naphthenic acids therefore cause high-temperature, nonaqueous corrosion in many areas of the refinery.

Regions where naphthenic acid attack is observed include:

Atmospheric and vacuum furnaces and transfer lines
Atmospheric and vacuum tower bottoms
Transfer lines from cuts distilled at 4000 F.

Moreover, naphthenic acid corrosion is substantially accelerated in high-velocity environments and, locally, in areas where liquid impingement occurs (return bends, elbows of transfer piping, etc.). Any object that disturbs the flow of liquid, such as welded seams or thermowells, also will accelerate naphthenic acid corrosion in these zones.

Based on experience, it appears that heavier crudes have higher naphthenic acid contents. This is shown by the occurrence of greater corrosion during the processing of those crudes. Fig. 1 shows typical corrosion caused by naphthenic acid attack.

CORROSION

The details of the corrosion mechanism for naphthenic acid attack on metal surfaces are unknown. It has been postulated that naphthenic acids react with iron species on the metal surface forming iron naphthenates.

These compounds are soluble in oil and are easily detached from the metal surface. This process exposes more of the bare metal for further acid attack.

After the metal is exposed to the acids for an extended period, considerable metal loss is observed.

Iron naphthenates can react further with hydrogen sulfide in the system to form iron sulfide and release the acid. The liberated acid causes additional corrosion downstream, in a sort of "recycling" process.

A concentration effect of iron naphthenates also can be a possible source of acid corrosion.2 If the solvent carrying iron naphthenates evaporates, the metal naphthenates, which are nonvolatile, will form a residue.

This residue is noncorrosive; however, if hydrogen sulfide is present and the naphthenic acid "recycling" process takes place, large amounts of acid are concentrated on the metal surface, which can cause severe local corrosion.

ANALYSIS

There is no routine procedure for quantifying naphthenic acids in crude.

The current industry procedure, for lack of a better one, is a total acid number calculation.

The crude or cut of interest is titrated with KOH to an end point. The total acid number is then used to approximate the amount of naphthenic acids in the crude.

This titration unfortunately, measures naphthenic acids as well as other acidic species. Further, the technique does not distinguish between various types of naphthenic acids.

A new technique for isolating and quantifying naphthenic acids was recently published.3 This technique has allowed laboratories to conduct experiments using pure naphthenic acids.4 In this work, no correlations were observed between naphthenic acid concentration and total acid number.

Also investigated were corrosion rates in some of the streams typically high in naphthenic acid. Results of these experiments show no correlation between corrosion rate and concentration of acids. These findings reveal the immense complexity of predicting the corrosivity of crudes containing naphthenic acids.

Further compounding the complexity is the fact that hydrogen sulfide can play an important role in mitigating naphthenic acid corrosion. Studies demonstrate that, if hydrogen sulfide is present in a system containing naphthenic acids, corrosion rates can be reduced substantially.4

CORROSION CONTROL

Refineries have used several traditional approaches for controlling naphthenic acid corrosion.

Each of these approaches has advantages and disadvantages:

Metallurgy upgrade. Published literature and field experience conclude that alloys containing 2.5% molybdenum or more, such as 317 stainless steel (SS), are resistant to naphthenic acid corrosion.5 6 Because corrosivity of acids changes as the source of acid is varied, upgrading metallurgy may address the corrosion problem for a short time. But when the source of the acid - the crude slate - is changed, the problem can recur.
Blending. Blending the corrosive feedstock with a less corrosive crude will dilute the amount of acid being processed, thereby decreasing the possibility of severe corrosion. In many cases, however, this may not be economically feasible.
Extraction. Extracting the acids from crude oil with caustic has been reviewed as an option. But sodium naphthenates, the salts of the acids formed by this process, cause severe emulsions that are difficult to resolve.

High-temperature corrosion inhibitors show great promise in the prevention of naphthenic acid corrosion. There are a number of advantages in using inhibitors:

The inhibitor is injected where the corrosion occurs. Should changing conditions shift the corrosion to another section of the unit, the inhibitor injection can be moved to that area.
Proper chemistry and application of the inhibitors will allow a refinery to process more crudes containing high concentrations of acids.
Improving operation conditions can improve profitability.

CORROSION INHIBITION

Extensive laboratory experiments support field experience showing that certain phosphate esters effectively mitigate naphthenic acid corrosion. Fig. 2 shows the postulated mechanism by which phosphate esters interact with the metal surface, forming a protective film.

This mechanism interferes with the reaction of iron with naphthenic acids. Instead of forming the hydrocarbon-soluble iron naphthenate, insoluble iron phosphate is produced. The presence of more than one active site on the phosphorus atom enables one molecule to react with more than one iron molecule.

This interaction eventually results in the formation of a tenacious film on the metal surface, which prevents naphthenic acid attack on the metal. The two case histories to follow led to the development of Nalco Chemical Co.'s Scorpion line of corrosion inhibitors.

CASE 1

Heavy and light vacuum gas oil (HVGO, LVGO) samples were taken from the crude unit of a refinery on the U.S. East Coast. The crude slate at this refinery was similar to other local refineries, all of which were experiencing naphthenic acid corrosion.

Analyses of the gas oil samples indicated high levels of iron (2-4 ppm). The other refineries in the area that had identified naphthenic acid corrosion in their crude units had iron levels of 1-3 ppm in the gas oil draw samples.

Shortly after the refinery learned of possible naphthenic acid corrosion, the crude unit was shut down for a scheduled turnaround. Upon pulling the header plugs in the atmospheric furnace, severe metal loss was observed in several tubes and return bends (Fig. 1).

The metal loss was caused by naphthenic acid corrosion. It should be noted that metal loss had not been observed a year earlier.

Metal loss in some areas was as deep as 0.5 in., resulting in an average corrosion rate of 500 mils/year (mpy).

Further equipment inspection revealed additional naphthenic acid corrosion in the atmospheric furnace transfer lines.

TREATMENT

A phosphate ester corrosion inhibitor (N-5180) was injected into the heater charge line after the flash drum. To monitor the corrosion, electrical resistance probes were placed in the north and south transfer lines and the south header of the atmospheric furnace.

Velocities on the metal surface of the tubes and return heads were speculated to be as great as 150 fps. To form the protective phosphorous film at those locations, high initial dosages (80-90 ppm) of the corrosion inhibitor were injected. After the prepassivation period, this dosage was decreased to a maintenance dosage of approximately 25 PPM.

Shortly after the injection began, a substantial decline in corrosion rates was observed on the three probes. After close monitoring of the corrosion rate with and without the chemical, some variables that influence naphthenic acid corrosion rates were identified.

ANALYSIS

This refinery typically processes 185,000 b/d of crude. The crude slate changes on almost a daily basis.

The unit operating conditions are monitored closely. The refiner found that the corrosion rate had increased substantially, perhaps because the crude rate had been reduced to 150,000 b/d. The crude rate is not, however, the only factor that influences corrosion. Other factors are important or have synergistic effects.

For example, monitoring indicated that, without treatment, when the percentage of certain crudes was increased in conjunction with a reduced charge rate, probe activity increased to 700 mpy or more.

(Note: The refiner does not wish to divulge the specific crudes involved.)

The corrosion probes are monitored daily and the inhibitor dosage is adjusted accordingly.

Because some important variables of naphthenic acid corrosion have been identified in the refinery, the dos age adjustment is easily determined.

This process allows the refinery to prevent any uncontrollable corrosion problems caused by naphthenic acid attack. Figs. 3-5 summarize the corrosion rates and dosages of the inhibitor during 90 days of monitoring and control.

After 1 year of corrosion inhibitor application, the crude unit was inspected. Only small amounts of corrosion ia,ere found.

This program has allowed the refiner to keep naphthenic acid corrosion at a minimum while running crudes with substantial amounts of naphthenic acid.

CASE 2

Another refinery in the same region discovered during turnaround of the vacuum tower that the HVGO draw tray had suffered corrosion damage caused by naphthenic acid. The crude unit of this refinery has a capacity of 90,000 b/d and runs a blend of sweet crudes.

The corrosion damage was limited to a narrow zone in the tower with typical temperature ranges for naphthenic acid corrosion. The damage was repaired and the tower internals were replaced with 410 SS packing.

The new packing is a very thin-gauge, corrugated 410 SS sheet metal. After start-up of the vacuum tower after the turnaround, fragments of the packing were removed from the LVGO and HVGO pump suction strainers.

There was no evidence of a naphthenic acid corrosion problem before opening the vacuum tower at the turnaround. Past experience indicated that the sweet crudes did not cause naphthenic acid corrosion. As a result, the vacuum tower internal metallurgy had not been upgraded to resist naphthenic acid corrosion.

(The 410 SS is not resistant to naphthenic acid corrosion. As mentioned earlier, an alloy containing at least 2.5% molybdenum is required for protection from naphthenic acid corrosion.)

COSTLY PROBLEMS

Here are the problems caused by naphthenic acid corrosion in the vacuum tower:

Crude unit rates were reduced while vacuum tower strainers were being cleaned of tower packing debris an average of once every 2-3 days.
Separation of HVGO from resid was poor. (Corrosion damage to tower internals resulted in excessive resid entrainment in HVGO and HVGO leaking into the resid.)
FCC feed quality was poor because of high metals concentrations, resulting in reduced unit throughput, decreased gasoline yield, and shortened catalyst life.

These problems were very expensive. The total eventual cost to the refinery was estimated to be $10-14 million/year if corrective measures were not taken.

TREATMENT

Five approaches were considered by the refinery for controlling naphthenic acid corrosion:

Processing crudes with low total acid number
Blending crudes with high neutralization numbers with those with low neutralization numbers
Upgrading metallurgy
Adding caustic to the desalted crude
Using a corrosion inhibitor.

The refinery chose a high-temperature corrosion inhibitor as the short-term solution to the problem. The long-term solution was to replace tower metallurgy with 316L SS during the next turnaround.

The corrosion inhibitor was chosen because no other corrosion-control approach offered the refinery as much operating flexibility with as few undesirable side effects at a lower cost.

The average charge rate to the vacuum tower was 27,000 b/d of reduced crude. An average of 10,000 b/d LVGO, 13,000 b/d HVGO, and 4,000 b/d of vacuum bottoms was produced. Injection of the inhibitor was started at a rate of 15 gpd into the HVGO return to control corrosion in the HVGO draw tray and the packing above it.

A second injection point was added, also at 15 gpd, at the spray oil return immediately below the HVGO draw tray. This injection was used to protect the tower packing and trays below the HVGO draw tray. The HVGO draw tray is a total draw tray, so the amount of inhibitor passing below this tray had been insufficient to provide protection beneath it (Fig. 6).

MONITORING

Program performance was monitored by:

Inserting an electrical-resistance corrosion probe in the HVGO run-down "ne.
Analyzing HVGO for nickel and iron daily, using inductively coupled plasma, or ICAP (nickel is contributed primarily by resid entrainment; iron is contributed by resid entrainment and corrosion).

Upon application of the inhibitor, the corrosion rate, as measured by the probe, decreased from 8-12 mpy to 0 mpy.

The corrosion rate has not changed since (Fig. 7). The other immediate effect was that the HVGO iron level decreased from 3-5 ppm to 0.2-0.4 ppm, with no effect seen on the nickel concentration (Fig. 8).

(Note: Several "spikes" in nickel and iron concentration were seen in the HVGO analysis. These spikes occurred when tower internal debris blocked the bottoms draw line and the bottoms level increased until the HVGO was contaminated. This problem was corrected and no further nickel or iron spikes have been seen in the HVGO.)

Longer-term advantages of the inhibitor injection were:

The HVGO pump-strainer cleaning frequency decreased from once every 2-3 days to a minimum of once even, 6 months.
The vacuum-heater outlet temperature was increased from 760 to 8000 F. without any deterioration of the corrosion-control program, and without any evidence of tower bottoms coking.

The inhibitor injection rates have been optimized to 10-12 gpd at both the HVGO and spray-oil returns, using ICAP analysis of HVGO. It was assumed that the spray-oil return injection rate needed to be the same as the HVGO-return injection rate to control corrosion effectively.

No direct corrosion measurement capability exists below the HVGO draw tray. Field experience has shown, however, that when injection of the inhibitor to the HVGO return is less than 10 gpd, the ICAP analysis of HVGO iron level win start to creep upward from an adequately treated iron level of 0.4 ppm.

The refinery considers the inhibitor-injection program a success. The program has been used consistently over the past year with no undesirable side effects noticed.

As an insurance policy, however, vacuum tower internal replacement parts made of 316L SS will be kept on hand in case of a vacuum tower failure, or for longer-term replacement of tower internals during a scheduled turnaround.

REFERENCES

Fan, T.P., "Characterization of Naphthenic Acid in Petroleum by Fast Atom Bombardment Mass Spectrometry," Energy & Fuels, Vol. 5, 1991, pp. 371-75.
Helle, H.P.E., Guideline for Corrosion Control in Crude Distillers, published by New Plantation, Holland, 1993, pp. 21-60.
Morrison, B.L., DeAngelis, D Bonnette, L., and Wood, S., "The Determination of Naphthenic Acids in Crude Oil," Pitt-Con '92, March 1992, New Orleans.
Babaian-Kibala, E., Craig, H.L. Jr., Rusk, G.L., Blanchard, K.V., Rose, T.J., Uehlein, B.L., Quinter, R.C. and Summers. M.A., "Naphthenic Acid Corrosion in a Refinery Setting," Corrosion '93, Paper No. 631.
Gutzeit, J., "Naphthenic Acid Corrosion in Oil Refineries," Materials Performance, Vol. 16, October 1977, pp. 24-33.
Piehl, R.L., "Naphthenic Acid Corrosion in Crude Distillation Units," Corrosion '87, Paper No. 196.