Russell C. Strong, Veronica K. Majestic
Nalco Chemical Co.
Sugar Land, Tex.
S. Mark Wilhelm
Cortest Laboratories Inc.
Cypress, Tex.
Corrosion in unsaturated gas separation processes continues to be a problem for the refining industry. Before any corrosion-control monitoring or improvement program can be set up, it is essential to understand the chemical and physical nature of the problem.
Accurate monitoring programs can then be implemented, and corrosion abatement programs can be developed that work within the framework of conditions found in the affected unit.
The concluding article in this two-part series will address specific corrosion-control methods, and their successful application in three refineries.
Engineers have recently focused on trying to better understand the basic causes of fluid catalytic cracking unit (FCCU) corrosion. The industry's efforts have included aggressive inspection programs at various refineries, National Association of Corrosion Engineers and American Petroleum Institute surveys of causes and effects, and many personal communications between companies.
Despite the attention paid to reducing corrosion by mechanical and chemical means, major vessels are still being condemned. Some of these failures are the result of poor corrosion-control technology and could have been avoided by applying sound corrosion-control principles.
FCC CORROSION CHEMISTRY
The only metallic alloy at risk in FCC gas separation processes is mild steel. Higher alloys are not reported to be susceptible to aqueous corrosion in this environment.
In the FCC, aqueous corrosion is commonly divided into two major classes: corrosion resulting from hydrogen charging of the steel, and corrosion from other causes. Hydrogen charging causes by far the most FCC corrosion damage.
HYDROGEN CHARGING
Hydrogen charging in gas separation units requires water, H2S, and a corrosion promoter, such as hydrogen cyanide or organic acids. The accepted chemical reactions are:
(1) Corrosion caused by H2S
2 H2S yields 2 H+ + 2 HS- 2 HS- + Fe - FeS + S-2 + 2 H0
(2) Cyanide reaction with FeS
FeS + 6 (CN)Fe(CN)6-4 + S-2
Reaction 2 allows Reaction 1 to recur on newly exposed metal, and the presence of cyanide on the metal surface prevents atomic hydrogen (H0) from combining to form gaseous H2. H0 is a very small atom that can move into the steel and lodge between the steel molecules. This process is called hydrogen charging.
In FCC corrosion without cyanide, HO readily combines to form H2, which is too large to diffuse through the steel. Therefore, without cyanide, very little hydrogen charging corrosion occurs.
On exposure to air, any leaks containing the water-soluble ferrocyanide complex will react with rust (ferric oxide) to form the dark blue or Prussian blue ferric-ferrocyanide complex seen on units with active corrosion:
(3) 4 Fe+3 + 3 Fe(CN)6-4 yields Fe4(Fe(CN)6)3
The reaction rates for Reactions 2 and 3 increase with increasing cyanide concentration, and at pH levels greater than 9.
CARBONATE CRACKING
The only other corrosion reported to be widely harmful to FCC units is carbonate cracking.
Carbonate cracking has been increasing in the past decade because of changes made in FCC process operations to increase yield and selectivity. When these changes increase the production of CO2, the potential for carbonate cracking increases.
The mechanism of carbonate cracking is not fully understood, but it does not appear to be related to hydrogen charging. Instead, it appears to be caused by a high-CO2 environment, aggravated by high pH and cyclical stresses on the equipment.
As with hydrogen charging, carbonate cracking is more active at pH levels greater than 9.
TYPES OF CORROSION
Both hydrogen charging and carbonate cracking occur in different forms that are known by different names. Different names are also often used for the same forms of corrosion, causing confusion in the industry.
There are four types of hydrogen-charging corrosion: Sulfide cracking, blistering, hydrogen-induced cracking, and stress-oriented hydrogen-induced cracking.
The following descriptions should clarify the most common types of corrosion.
- SULFIDE CRACKING: Sulfide cracking is commonly known as sulfide stress cracking (SSC) or sulfide stress corrosion cracking (SSCC). Under the generic title of wet H2S cracking, sulfide cracking is the subject of much study and debate in the industry.
In FCCUs, SSC generally occurs when there are more than 50 ppm of H2S dissolved in the water, when pH is elevated, and when some form of chemical accelerator is present. Atomic hydrogen, formed on the steel surface by corrosion, diffuses into the steel, concentrating at regions of high residual stress.
With a high concentration of hydrogen atoms in the steel crystalline structure, the metal is not easily deformed, resulting in what is known as hydrogen embrittlement. As more hydrogen enters, the steel may finally begin to crack.
The higher-strength steels, and welds with hard heat-affected zones (HAZs) are most susceptible to this form of attack.
Cracks caused by SSC are generally detectable with surface analysis and do not readily propagate away from the hard HAZs of welds into the softer base metal. Cracks in lower-strength steels are typically transgranular, i.e., cracks migrate through the metal grains.
In higher strength (or hardness) steels, cracks are often intergranular, i.e., cracks propagate between metal grains.
- BLISTERING: Blistering occurs when the atomic hydrogen moving through the steel encounters void spaces in the metal. These spaces are normally the result of a large inclusion or delamination present during plate fabrication.
In a void space, two atoms of hydrogen can combine to form molecular hydrogen. The larger hydrogen molecules become trapped, and the void space accumulates hydrogen, raising the pressure inside the void high enough to literally bulge the metal.
Eventually, steel plate affected by this type of corrosion looks like it has developed a large blister; hence, the name blistering.
Most refinery piping and the newer "killed" steels do not have as many inclusions that allow molecular hydrogen to accumulate; thus they are not as susceptible to blister formation. Many engineers consider blistering to be a special form of hydrogen-induced cracking.
- HYDROGEN-INDUCED CRACKING (HIC): HIC typically occurs under the same environmental conditions as SSC. However, unlike SSC, hydrogen-induced cracks will occur in the softer metals, and they may not be associated with cracks that originate at or show at the surface.
As with blistering, these cracks are caused by a buildup of hydrogen gas near inclusions in the steel.
The direction in which a hydrogen-induced crack grows is not definite. Such cracks commonly run in the direction the material was rolled and are not preferentially intergranular or intragranular. Some engineers classify all FCC cracking as HIC.
Stress-oriented, hydrogen-induced cracking (Sohic): Sohic is a special form of HIC and blistering, sometimes known as stepwise hydrogen-induced cracking. Sohic appears as a series of very small hydrogen blisters or HICs, commonly near the end of a larger hydrogen-induced crack.
By themselves, HICs are not dangerous because the individual cracks are not oriented in a through-thickness direction, and they are small enough that the hoop strength of the vessel is not compromised. They become dangerous when linked together by small hydrogen-induced cracks in the through-thickness direction to form Sohic.
Sohic is not easily detectable by analysis of the surface of the vessel.
In addition to hydrogen-charging corrosion, there are two other types of corrosion: General and carbonate cracking.
- GENERAL CORROSION: General corrosion not caused by hydrogen charging is not a common problem in the FCC, because of the naturally high pH and the normally low chloride levels. In rare instances, general corrosion can occur in higher-pressure systems, as will be shown by the first case history in the concluding article.
- CARBONATE CRACKING: Carbonate cracking, also known as intergranular stress corrosion cracking (SCC), has only recently been identified in the FCC, as reported by Exxon, Chevron, and others.
As mentioned previously, carbonate cracking occurs when CO2 is present in a high-pH environment. An oxide of the metal forms at the root of the crack, and cyclic stresses cause this brittle scale to crack, exposing more fresh metal to the corrosive environment. The cracks advance by repeating this cycle.
Carbonate cracks are typically intergranular.
Because of the brittle nature of the cracks and the influence of external, cyclic stresses, many believe that chemical inhibitors cannot protect against this form of corrosion. But if the mechanism turns out to be SCC, inhibitors are likely to be effective.
Carbonate cracks can be detected by surface inspection methods.
FCC CORROSION
All process areas in the FCC where water is present are susceptible to all these forms of corrosion. Studies are under way to identify the areas most likely to develop cracks.
Blistering is most likely to occur in the absorber tower, compressor coolers, and knockout pots. Carbonate cracking is likely to occur at any point in FCC fractionation trains.
Corrosion is generally more severe in the vapor phase than in the liquid-hydrocarbon and aqueous phases. However, corrosion monitoring and control should focus on both phases, because general rules do not always apply.
There are differences between corrosion in the liquid and vapor phases that must be understood. A corrosion problem in the vapor phase may require a different approach than a similar problem in the aqueous phase.
Corrosion in the liquid phase is more easily controlled than corrosion in the vapor phase, because treatment chemicals are more easily distributed in the liquid phase. There have been attempts to develop inhibitors that are effective in the vapor phase, but to date there is no technically successful product.
Given this consideration, the first step in corrosion control should be to move any vapor-phase problems into the liquid phase, if possible. As will be discussed later, this can often, but not always, be done with a water wash. If necessary, the water wash can be supplemented with various types of corrosion inhibitors.
PHYSICAL CONSIDERATIONS
Another factor affecting corrosion and its control is the way liquids distribute themselves in the FCCU and its piping network.
Liquid moving through a piping network with a flowing gas can assume several different distribution patterns. Generally, in an FCC gas plant the liquids will move in a stratified, wave, annular, or dispersed pattern. Piping, vessel design, and process throughput will limit the ability to control the flow regime.
The type of corrosion-control program being used will also affect the flow regime. Any of the previously mentioned flow regimes may occur when water washes are used, but annular and dispersed patterns are rare with the use of inhibitors.
Fig. 1 shows a graph of the more common stratified and wave-flow patterns, in terms of their characteristics. Successful water-wash applications require maximum contact between the water and the vapors; successful filming inhibitor applications require complete coverage of the surfaces of the equipment.
As shown in Fig. 2, the piping layout and flow regime also affect the distribution of liquids in vapor piping. With either a stratified or wave-flow pattern, all liquids tend to follow one path at a tee branch, while gas splits evenly, or unevenly, in a different direction from the liquid.
A basic understanding of liquid route preference and the flow regimes of a system should be supported by calculations when possible. These factors will often dictate the proper application rate and location for corrosion-control liquids.
A review of the bibliography will help the reader obtain a basic understanding of the calculations for flow regime and liquid-route preference.
CORROSION MONITORING
After the physical and chemical characteristics of FCC corrosion are understood, the next crucial step in corrosion control is proper application of monitoring techniques. The most valuable methods are those that illustrate the actual corrosion activity occurring on the equipment at risk.
Because general corrosion is rarely a factor, methods that measure hydrogen permeation or its direct effects are the most useful. There is no proven method for monitoring carbonate cracking online.
DIRECT-PROBE METHODS
The hydrogen probe, developed in the 1950s, continues to be the most widely used technique. Available from several instrument companies, this device traps atomic hydrogen in a void space of known volume. The rate of pressure increase is proportional to the rate of hydrogen permeation at that point.
The hydrogen patch probe is a potentially more flexible monitoring method. This device measures the rate of hydrogen permeation electrochemically. With care, the hydrogen patch probe can be attached to the outside of equipment to measure the atomic hydrogen passing through the steel at that location.
Various slipstream monitoring devices use either hydrogen probes or coupons.
The use of acoustic emissions (AE) is a relatively new technique now being used. AE works by increasing the pressure on a vessel (much like inflating a balloon) and using special sensors to identify regions that generate noise from stretching cracks (see OGJ, June 17, p. 47).
INDIRECT METHODS
Any technique that measures the effects of corrosion at some location other than the point of corrosion provides less reliable, but useful, information. These methods include the spot test, paint can test, and measurements of iron and cyanide concentrations in process water.
The spot test uses process water to produce the Prussian blue color on a piece of filter paper previously treated with ferric chloride. The intensity of the color produced indicates qualitatively the severity of corrosion occurring somewhere in the system.
The paint can test involves evaluating the number and size of blisters that form under the paint on a steel can containing process water. This test has lost favor over the years because it is not a good quantitative method for reporting and tracking corrosion.
Soluble iron measurements are preferred to total iron measurements because the iron-cyanide complex likely to indicate current activity is soluble in the high-pH water of the FCC. Insoluble iron is just as likely to be corrosion product from another time, dislodged by physical changes in the system.
Measuring the cyanide in the system is the most desirable indirect method. However, to date no publicly available procedure can measure cyanide concentration in FCC tail waters accurately, because H2S interferes.
Al] current procedures compare the measurements to previous measurements using the same procedure, as a relative indicator of changes in the system.
BIBLIOGRAPHY
Neumaier, B.W., and Schilmoller, C.M., "Deterrence of Hydrogen Blistering at a Fluid Catalytic Cracking Unit," API Publication, Vol. 35, 1955, pp. 92-108.
Gutzeit, Joerg, "Corrosion of Steel by Sulfides and Cyanides in Refinery Condensate Water," Materials Protection, Vol. 7, No. 12, Dec. 1968, pp. 19-23.
Skei, T., Wachter, A., Bonner, W.A., and Burnham, H.D., "Hydrogen Blistering of Steel in Hydrogen Sulfide Solutions," Corrosion, May 1953, pp. 163-72.
Merrick, R.D., "Refinery Experiences with Cracking in Wet H2S Environments," Materials Performance, Jan. 1988, pp. 30-36.
Kmetz, J.H., and Truax D.J., "Carbonate Stress Corrosion Cracking of Carbon Steel in Refinery FCC Main Fractionator Overhead Systems," NACE Paper 206, Corrosion/90, Apr. 23-27, 1990, Las Vegas.
Baker, O., "Designing for simultaneous flow of oil and gas," OGJ, July 26, 1954, pp. 185-195.
Oranje, L., "Condensate behavior in gas pipelines is predictable," OGJ, July 2, 1973, pp. 29-44.
Fortuin, J.M.H., Hamersma, P.J., Hart, J., Smit, H.J., and Baan, W.P., "Calculations predict condensate movement at 'T' junctions," OGJ, Jan. 21, 1991, pp. 37-40.
Fortuin, J.M.H., Hamersma, P.J., Hart, J., Smit, H.J., and Baan, W.P., "Experiments verify predictions of condensate movements," OGJ, Jan. 28, 1991, pp. 91-93.
Kane, R.D., Wilhelm, S.M., and Oldfield, J.W., "Review of Hydrogen Induced Cracking of Steels in Wet H2S Refinery Service," International Conference on Interaction of Steels with Hydrogen, Mar. 2830, 1989, Paris.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.
