NEW INHIBITOR REDUCES CRUDE-UNIT CORROSION PROBLEMS AT LOWER pH

Eddie C. French
Petrolite Corp.
St. Louis

The crude-unit overhead at a commercial refinery operated for more than 1 year at Ph levels of about 5.0-5.5 with very low corrosion. About 20% of this time, the pH was less than 5.0.

During this period, a water-soluble inhibitor was added to this large recirculated water wash.

The low corrosion rates observed during the test period indicate that, in contrast to conventional wisdom, the inhibitor is effective at pH levels less than 5.0.

Furthermore, a reference case study at a commercial refinery demonstrated, more than 30 years ago, that operation of the crude-unit overhead at an average pH of 4.3, in combination with an inhibitor, eliminated failures for 5 years.

Current state-of-the-art, water-soluble inhibitors-such as the one used in the first example-are more effective under these more-acidic conditions than the inhibitor used in this older case study.

BACKGROUND

Corrosion-control technology in the crude-unit overhead has not changed significantly during the past 40 years. Corrosion control consists of adding a neutralizer to adjust the pH to nearneutral and adding an oil-soluble filming inhibitor.

As a result of this approach, underdeposit corrosion has become the major cause of equipment failures today and accounts for approximately 80% of failures. (Underdeposit corrosion, and other corrosion mechanisms, are explained in an accompanying sidebar in this article.)

In an attempt to reduce deposits, neutralizing amines that form lowmelting-point chloride salts were introduced. These amines have been only marginally successful in preventing failures because they do not address the primary cause of underdeposit corrosion-iron sulfide (FeS) deposition. Typical neutralizer/filmer programs are effective at reducing general corrosion caused by acid, but have not been successful in preventing failures. This type of treatment usually reduces the corrosion-probe readings to 5 mils per year (mpy) or less, vet failures occur in about a year.

This suggests that the failures are not caused by generalized acid corrosion, but by a mechanism that results in localized corrosion. The emphasis in corrosion-control programs needs to be shifted from reducing corrosion rates as measured by probes to increasing the time between equipment failures.

To limit underdeposit corrosion to a minimum, operating conditions that keep all salts in solution must be maintained. Iron sulfide is the least soluble salt commonly found in crudetower overhead systems.

If conditions that keep FeS soluble are maintained, then FeS and other salt deposits will not form. By maintaining conditions so that deposits are not formed, underdeposit pitting corrosion can be effectively controlled.

Controlling Ph property can achieve conditions under which FeS and other salts in the overhead do not form deposits. For most systems, this pH range is 5.0-5.5. The precise pH for deposit-free operation, however, is dependent on the concentration of sulfur species.

To have a comprehensive corrosioncontrol program, general corrosion must also be controlled under these pH conditions. New inhibitor chemistry that effectively controls corrosion at pH 4.0 and less has recently been developed for this application.

UNDERDEPOSIT CORROSION

Underdeposit corrosion caused by neutralization salts is well-recognized as the cause of many corrosion problems in crude overheads. Hydrolysis of these acid salts produces a corrosive solution with a pH of about 4.0.

The "differential potential cell" mechanism, however, although seldom recognized as a cause of pitting, is responsible for many of the failures in overhead systems.

This mechanism is caused by the difference in surface potential under a deposit, relative to the surface potential on a clean surface. It is analogous to corrosion caused by coupling dissimilar metals together.

The rate of any reaction occurring on the surface is different under the deposit than it is on a clean or lightly covered surface. This results in different potentials on the surface.

And because steel is a good conductor and cannot support two different potentials, electrons flow to equalize the surface potential. The results are dissolution of iron underneath the deposit and pitting at an accelerated rate.

Further explanation of corrosion mechanisms is given in the box on p. 50.

Fig. 1 shows the typical heavy deposits that lead to this "galvanic" mechanism. Analyses of the deposits shows them to be 70-80% FeS, along with some coke and heavy hydrocarbon (tar).

There are frequently trace amounts of amine hydrochloride in the deposits, but its presence is not required to explain the underdeposit failures. Any deposit (FeS, in this case) can cause accelerated underdeposit corrosion by the differential potential cell mechanism.

RELATIVE MAGNITUDE

Most failures occur in much less time than would be predicted by general-corrosion rates, as measured by electronic resistance (ER) probes and coupons. Most refiners require a corrosion-control program to limit corrosion rates to less than 5 mpy, yet failures frequently occur in about 1 year.

These early failures suggest that pitting rates are about 20-30 times general-corrosion rates. This correlates with observed pitting rates obtained during many years of field experience and by measuring pitting rates relative to general-corrosion rates on numerous corroded specimens.

Observed pitting (failure) rates range from 10 to 100 times generalcorrosion rates. A very conservative average is 20 times the general-corrosion rate.

On a typical 1/8-in. thick exchanger tube with deposits, a general-corrosion rate of 5 mpy, combined with the 20 x pitting factor, would result in failure in about 1 year, Without deposits, the tube would last more than 10 years, even if the general-corrosion rates were doubled.

CONTROLLING DEPOSITION

To keep underdeposit corrosion at minimum levels, operating conditions that keep salts in solution must be maintained. This can be done by maintaining the overhead, pH in a range in which FeS is soluble.

The FeS deposits typically cause accelerated-pitting corrosion and failures via the differential potential cell mechanism.

Ironically, the overuse of neutralizers to maintain a higher pH can cause FeS deposits and, ultimately, overhead failures.

A fine balance must be struck between acid corrosion and failures resulting from underdeposit pitting. The operating conditions that will produce minimum corrosion fortunately can be accurately determined. These conditions will reduce underdeposit corrosion and achieve maximum time until failure.

MAINTAINING SOLUBILITY

The following equation was derived from the two-step ionization of H2S and the solubility product of FeS. The derivation is shown of the solubility equation on p. 50.

The hydrogen ion and sulfur species concentrations are in moles/l. Comparison to more than 100 examples of field data confirmed the equation, which was found to be correct well within experimental error of the analysis.

The solubility of FeS is proportional to the square of the hydrogen ion concentration (which is used to calculate pH) and inversely proportional to the total sulfur species concentration.

Note that in this equation, "sulfur species" is used in place of "H2S," as in the final equation in the derivation.

In the crude overhead at the pH levels of interest, nearly all of the sulfur is present as H2S; however, analytical results are typically reported as H2S, HS-, or S-2. Because the molecular weights of these species are similar, the concentration of any one of them can be used in place of the concentration of H2S.

The total sulfur species is the sum of the H2S, HS-, and S-2 concentrations. Fig. 2 shows the solubility of FeS vs. pH at varying sulfur concentrations. These are typical concentrations found in overhead-accumulator water.

TARGET pH

The selection of the target pH for operating the overhead thus correlates to the solubility of the least-soluble salt commonly present (FeS). The critical portion of the target pH range is the maximum value, termed phmax. This value is the maximum pH at which FeS will remain soluble.

(Units have been converted from moles/l. to ppm.)

The pHmax is therefore the highest pH at which ferrous ions are soluble to 1.0 ppm at the sulfur species concentration in the system. Every effort should be made to keep the pH less than this maximum level.

The lower end of the pH range is less critical. A lower limit of 0.5 units less than pHmax is ideal and will keep the system safely away from severe acid corrosion.

Fig. 3 is a plot of the equation, which shows the pH vs. the sulfurspecies concentration that allows ferrous ion solubilities of 1, 3, and 5 ppm. The 3 and 5 ppm solubilities are included in case these solubilities are required to maintain a deposit-free system.

The pHmax can be determined from these curves and an analysis of H2S, HS-, and S-2 in the accumulator water.

Based on this approach, the target pH range will be lower than the commonly recommended range of 5.5-7.0 for overhead systems (Table 1).

For example, for systems having 50 ppm sulfur species, the pHmax would be 5.4. For most systems, the pHmax will be between 5.6 and 5.5.

Operating at these conditions will control deposit formation, reduce neutralizer consumption, and significantly increase time until equipment failure. At the same time, these conditions will improve exchanger heat transfer and pressure drop.

These benefits translate into longer run lengths and reduced operating costs, which will improve refinery profitability.

CORROSION AT LOW pHs

The discussion to this point has concerned how deposits that form at pHs greater than pHmax can cause accelerated time to failures. The potential for acid corrosion at the lower end of the target range must now be examined.

Can corrosion be controlled to an acceptable level in this lower pH range? The answer is yes, and both test data and field results support this conclusion.

OIL-SOLUBLE INHIBITOR

Fig. 4 shows data from an overhead side-stream field test in which vapor from the overhead line was condensed into a corrosion cell. Measurements of pH and instantaneous corrosion rates were used to determine corrosion rates and evaluate inhibitors.

Inhibitor A-an oil-soluble, filmingtype inhibitor-was tested at 5 ppm, based on the total volume of liquids. The pH in this test ranged from 4.0 to 4.5. The corrosion rate was near 100 mpy with no inhibitor. The addition of 5 ppm of Inhibitor A reduced the rate to about 2 mpy.

Tests at higher concentrations of inhibitor did not reduce corrosion rates, indicating that 5 ppm was sufficient. This concentration is comparable to inhibitor rates normally used in overhead systems.

WATER-SOLUBLE INHIBITOR

Even more-effective, water-soluble inhibitors are available for use in systems that have a recirculated water wash. Fig. 5 shows data from a lab test in which the pH ranged from 2.0 to 7.0.

The test conditions are:

• Continuous sparge with argon gas containing 1% H2S

• pH controlled within 0.1 units by a "pH Stat" to avoid changes in pH during the test. (A pH Stat is a controller that measures and adjusts the pH automatically.)

• 150 F.

Water-soluble Inhibitor B was tested at 100 ppm, based on the total volume of water. This concentration is equivalent to 4 ppm, based on the total overhead volume for a typical system containing 4% water. By using Inhibitor B, the corrosion rate without inhibitor of more than 1,000 mpy at pH 3.0 was reduced to 1.0 mpy.

Fig. 6 shows data from the overhead side-stream field test at pH 1.0-1.5. The maximum scale on the meter was 1,000 mpy, but the corrosion rate of a pH 1.5 solution at 150 F. is greater than 5,000 mpy, as shown in Fig. 5. Inhibitor B, as 100 ppm based on water volume, reduced the corrosion rate to 10 mpy.

Inhibitor B achieved a greater than 99.8% reduction in the corrosion rate. Because it is not necessary to maintain the pH at less than 4.5 to control deposit formation, this inhibitor,will provide the protection necessary to significantly reduce system failures.

FIELD RESULTS

This water-soluble inhibitor has been added to a large recirculated water wash in an operating unit for more than I year. The pH was typically 5.0-5.5, but was less than 5.0 about 20% of the time.

Even at a pH of less than 5.0, the four ER probes-at the inlets and outlets of two parallel exchangers-indicated near-zero corrosion for weeks at a time.

Fig. 7 shows data for a 60-hr period, Dec. 26-28, 1992, during which the pH was 5.0 or less for 32 of the 60 hr. The pH was measured every 2 hr. Table 2 shows the corrosion rates during this test.

These low rates show that Inhibitor B is effective at pH levels less than 5.0. This is not a case where the overhead is normally not corrosive. Three times in the past year, inhibitor was not added for 8-12 hr. Each time, all the ER probes responded with higher corrosion rates.

For most overheads, the recommended pH range will be about 5.05.5.

Even in the units with the highest levels of sulfur species, the lower limit will not be less than 4.5.

If a unit is operated at a pH less than 5.0, one should expect slightly higher general corrosion rates, as measured by probes and coupons. The maximum penetration rate, however, will be much lower at these higher general rates than with lower probe rates and pitting.

A second, much older, field case history shows strong evidence that operating a unit free of deposits reduces failures.

Two papers by Biehl and Schnake, presented in 1957 and 1959 at annual API meetings, describe how they increased run lengths from less than 9 months to more than 18 months without corrosion-related failures." This increase was achieved by changing the overhead pH from near 7.0 to 4.0-4.5.

From the abstract of one paper: 2

"Approximately 5 years ago, The Ohio Oil Co.'s refinery at Robinson, Ill., lowered the pH on crude oil overhead receiver waters from an average of 7.3 to 4.3, and increased the inhibitor injection into the vapor overhead from 6-10 ppm to 10-15 ppm. This change to lower pH operations resulted in excellent control of corrosion, cleaner equipment, and reduction of ammonia contamination in the hydrocarbon streams. Corrosion rates have been monitored by water analysis, hydrogen probes, electrical resistance probes, and corrosion test coupons. All methods have shown very acceptable corrosion rates. The clean equipment obtained at the low pH operation has greatly reduced maintenance costs at scheduled turnarounds and permitted longer runs at increased charge rates."

At the original high pH conditions, the refinery was unable to complete an 18-month run without replacing several exchangers.

"Since operating at low pH, turnaround inspections have been scheduled at 18 month intervals .... These inspections have indicated that all equipment was in excellent condition and nothing has had to be replaced as a result of corrosion in the overhead system."

This is an example of approaching the problem correctly. Exchangers were free of deposits at inspection and the acid corrosion-at an average pH of 4.3 for 5 years-did not result in any failures. The emphasis was to reduce failures rather than to concentrate solely on minimizing corrosion rates.

IRON COUNTS

Many refineries use accumulatorwater iron counts as one corrosion monitor. This can be a useful indicator under the right conditions, but can, also lead to a false sense of security.

Most iron-count data do not indicate the corrosion rate, but are simply a measure of the solubility of FeS in water at that pH. For iron counts to be a useful monitor, the saturation solubility of iron sulfide must not be reached.

Iron count data are meaningful only when the pH is low enough for all FeS to be soluble, as shown in Fig. 2. Most refiners have become accustomed to observing very low iron counts because the pH of the water is typically greater than 5.5, where FeS is insoluble. When the system is operated at conditions at which FeS is soluble-necessary for controlling deposits and pitting-higher iron counts should be expected.

These higher counts are an indication that FeS is in solution and not forming deposits. Good control is achieved when iron counts are constant at a few ppm, and less than the saturation level of FeS in the water.

Saturated iron counts are thus an indication that FeS deposition is occurring.

VAPOR-AREA CORROSION

Of major concern to many refinery corrosion engineers are vapor areas not contacted by the liquid phase, which contains the filming inhibitor. Many believe that the filming inhibitor will be effective in the liquid areas, but some neutralizer is needed to protect the vapor or "dead" zones.

Biehl and Schnake did not discuss this point specifically, but their results indicate that no corrosion resulting in failures occurred in the vapor phase during the 5-year period. This is true despite the fact that there was no significant neutralization in the vapor areas, and the pH averaged 4.3 during the period.

Vapor-phase neutralization may be, in fact, a contributor to failures. If neutralization occurs and insufficient water is available to wash away the neutralization salts, then underdeposit corrosion can lead to accelerated penetration rates.

In the Ohio Oil example, general corrosion was not severe at pH 4.3, but 18-month runs were not possible because of plugging and pitting when the pH was near 7.0. This is a strong argument against the need for vaporphase neutralization.

NEUTRALIZATION

There is a long-standing belief in the refining industry that neutralization to pH 7 is necessary. The logic is that if the pH is 7 then all the acid is neutralized and there will be no corrosion.

It is necessary, however, to determine the point at which all the HCI has been neutralized when a weak base like ammonia, or any of the commercially available neutralizing amines, is used.

The equivalence point is the pH at which there are equal numbers of equivalents of acid and base present. If HCI is neutralized with a strong base such as NaOH, the equivalence point occurs at pH 7.0. When a weak base is used, however, and an acid salt is formed, this pH will be less than 7.0.

The exact pH that results depends on the initial concentration of acid and the ionization constant of the weak base. If 100 ppm of HCI is neutralized with a weak base, 99% of the HCI has been neutralized at pH 5.5.

This near-neutralization at a pH less than 7.0 is caused by the hydrolysis of the acid salt. The degree of hydrolysis depends on the strength of the weak base. The weaker the base, the greater the degree of hydrolysis and the lower the pH at the equivalence point.

Commercial neutralizers, as shown in Table 3, have ionization constants the same order of magnitude as that of ammonia. Neutralization of HCI to its equivalence point with ammonia or any of the commercial amines will result in a pH near 5.5.

Thus, in a crude overhead, 99% of the Hcl has been neutralized at pH 5.5.,

RELATIVE CORROSIVITY

As shown in Table 3, there are no significant differences in the relative corrosivity of the amine hydrochloride salts formed from these amines.

Commercially available neutralizers have ionization constants approximately equal to ammonia; therefore the pH of a saturated solution (wet deposit) of any of the amine hydrochlorides will be approximately that of ammonium chloride.

A concentration of 4.0 moles/l. (4M) was assumed to represent a saturated solution.

If improperly used, neutralizers will form corrosive hydrochloride salts, which can lead to rapid pitting and failures.

Even liquid salts are corrosive when in contact with the metal. Any neutralization-salt deposit formed from the amines listed in Table 3 can hydrolyze to produce an acid solution that can be very corrosive.

The obvious conclusion is that the overhead must be operated at conditions under which neutralization-salt deposits cannot form.

REFERENCES

1. Biehl, J.A., and Schnake, E.A., "Corrosion in Crude-Oil Processing-Low pH vs. high pH," 22nd midyear meeting of American Petroleum Institute Division of Refining, Mar. 13, 1957, Philadelphia.

2. Biehl, J.A., and Schnake, E.A., "Processing Crude Oil at low pH," 24th midyear meeting of API Division of Refining, May 28, 1959, New York.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.