Every fluid catalytic cracking (FCC) corrosion-control problem is different, but several basic principles should be understood and applied as needed.
These principles were used effectively to solve corrosion problems in some refineries.
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CORROSION-CONTROL METHODS
The corrosion-control method chosen for any system will depend on both the chemical nature of the corrosion and the physical characteristics of the system. A good water wash system is the key to any FCC corrosion-control program.
Ideally, an effective water wash will at least move vapor-phase corrosive materials into the liquid phase, where they are more easily treated.
If the water wash does not provide complete protection, polysulfides and filming inhibitors can be added.
WATER WASH
An effective water wash dilutes and scrubs corrosive species-such as hydrogen sulfide, ammonia, chlorides, and cyanides-from the FCC offgas. The water wash rate, location, water quality, and injection equipment are critical to an effective program.
It may be necessary to inject wash water at several points, because of the limitations imposed by liquid route preference and flow regimes.
Corrosive gases are more soluble in water at high process pressures. Therefore, the best location for a water wash is downstream of each stage of gas compression, ahead of the coolers.
If there are multiple banks of compressor aftercoolers, a water wash must be added to all exchanger banks.
A water wash in the main fractionator overhead vapor line can also be useful as a first step in removing volatile acid gases. Although the solubility of these gases may be low at the fractionator pressure, the ability to add a high volume of water for the relatively low cost of recycling the water from the reflux drum boot makes this an attractive option.
The conventionally recommended water wash rate into the gas compression stages is 1.0-1.5 gpm/1,000 bbl of oil feed to the FCC unit (FCCU). This rate, which translates to about 2 gpm/MMscf of gas, should be verified through flow regime calculations.
The objective is to create a stable mist for maximum surface-to-volume ratio of the water droplets and, hence, maximum contact efficiency. The wash water rate should be reliable and easily measured.
The water should be injected through a spray nozzle that can aid the flow kinetics required to achieve maximum surface-to-volume ratio. If the vapor and liquid rates are not in the correct range, the liquid will return to a stratified or wave flow.
The feed system should be designed for continuous water flow. Recommended wash water sources include boiler feed water (before alkalinity adjustment), steam condensate, and stripped process condensates.
Recycling from high to low pressure, also known as cascading water washes, is not recommended because it may create a "champagne effect," concentrating the corrosive species in the water and thereby aggravating corrosion.
A water wash alone does not always protect completely against hydrogen activity in FCCU fractionation trains. It is often necessary to supplement the water wash with chemical additives, such as ammonium or sodium polysulfide and filming inhibitors.
POLYSULFIDES
Polysulfide is injected into a water wash to react with hydrogen cyanide, producing thiocyanate. Because thiocyanates do not react with the protective sulfide film on metal surfaces, as cyanide does, hydrogen penetration is reduced.
Either sodium or ammonium polysulfide can be used, but ammonium polysulfide is most common. Concentrated solutions are red, while dilute solutions are yellow.
A number of considerations affect the use of polysulfides, including their susceptibility to oxidation, their instability at low pH, and their thermal instability.
Exposure to air oxidizes polysulfide to thiosulfate and sulfate, neither of which forms the desired thiocyanate. A change from red or yellow to colorless suggests oxidation of the polysulfide.
Based on their potential for oxidation, care should be taken to prevent polysulfides from being contaminated with oxygen. The polysulfide solution should be blanketed with hydrocarbon both to prevent odor problems and to reduce oxygen contamination.
Concentrated ammonium polysulfide is soluble in alkaline sour water. If the pH drops below 8, the polysulfide will decompose into ammonia, hydrogen sulfide, and sulfur. The formation of sulfur fouls the equipment.
Ammonium polysulfide is thermally unstable and very difficult to handle and pump in cold weather. Care must be taken when the solution temperature falls below 38 F. because the polysulfide precipitates at this temperature and at temperatures above 250 F., causing precipitation of excess sulfur.
Some refiners make ammonium polysulfide in situ by injecting air into the wash water, forming polysulfide in a process similar to a Claus reaction.
This technique raises concerns about the contribution of oxygen from the air to corrosion activity. In addition, the oxygen could "vapor pool," creating a potential for explosion when the equipment is opened.
Polysulfide reacts with cyanide in an equimolar ratio. Unfortunately, cyanides are difficult to measure in process waters, making the dosage of polysulfide difficult to regulate.
The best standard for determining the dosage is the appearance of the process water from the water knockouts. It should have a distinct transparent, pale-yellow color. Excess polysulfide can increase corrosion at elevated temperatures and, because of its instability, can foul process equipment.
The reactions for the process may be shown, as follows:
2HCN+(NH4)2 Sx →2NH4 SCN+HS- +H+ +Sx-3 (x=3, 4, or 5)
NH4 SCN+2H2O→CO2 +H2S+2NH3
(NH4)2Sx →2NH3 +H2S+S(x-1)
CORROSION INHIBITORS
Most FCC corrosion inhibitors are filmers, which provide a thin barrier of organic material on the inside surface of the equipment at risk. Dosages are only a few parts per million, based on the mass flow rate of the treated process.
If effective, this thin barrier will prevent an aqueous phase from reaching the surface, thereby preventing the corrosion that can cause hydrogen permeation or carbonate cracking.
Some inhibitors are passivators, which interact chemically with the surface to anodically or cathodically inhibit the electrochemistry of corrosion. Passivators may not form a complete organic barrier, but eliminating the cathodic or anodic site interrupts the corrosion.
To date there are no commercially successful vapor-phase inhibitors.
The effectiveness of several inhibitors was evaluated by Cortest Laboratories Inc., an independent testing firm. The experimental procedure used an electrochemical cell divided into two compartments by a thin (0.03 in.) steel membrane.
One side of the membrane was exposed to a sour FCC environment. Hydrogen atoms resulting from the corrosion reaction diffused through the membrane and were electrochemically oxidized in the second compartment.
The amount of hydrogen permeating the membrane indicates the rate of corrosion and the efficiency of the permeation step.
The experimental data provide a measure of the rate of proton discharge (corrosion rate) and the ratio of atoms absorbed to atoms generated (permeation efficiency).
An effective inhibitor can function by reducing the corrosion rate, by lowering the permeation efficiency, or by doing both.
In a typical corrosion inhibitor evaluation, a range of concentrations is examined over a range of temperatures. The corrosion rates and permeation efficiencies in inhibitor solutions are compared with those in "blanks."
The tests are run in solutions containing ammonium, cyanide and sulfide ions, and trace impurities peculiar to the location of the sour process stream.
Tests were conducted on several proprietary FCC treatment formulations: two oil-soluble inhibitors, a water-soluble inhibitor, and a water-soluble passivator.
The four formulations are described as follows:
- Inhibitor A: Oil-soluble diamide inhibitor
- Passivator B: Water-soluble passivating inhibitor
- Inhibitor C: Oil-soluble imidazoline inhibitor
- Inhibitor D: Water-soluble quaternary amine inhibitor.
Most of the compounds tested lowered the corrosion rate substantially (Fig. 2). But not all produced interfacial conditions that reduced hydrogen absorption or permeation (Fig. 3).
This difference has important ramifications in selecting efficient treatment chemicals. Mixtures can be designed containing ingredients specific to both corrosion rate and hydrogen absorption.
Once the physical limitations of the system are established so that the chemical can be applied with maximum contact effectiveness, a product can be selected.
Factors that should be considered when choosing an inhibitor are:
- The nature of the problem (general corrosion or hydrogen permeation)
- The product's demonstrated ability to inhibit activity at high pH
- The product's oil or water solubility, depending on the primary phase in which the problem occurs
- The product's solubility in light ends, if oil based
- The product's emulsification or foaming tendencies.
