Corrosion and fouling control in process equipment
Effective chemical treatment programmes can help to prevent plant damage and financial losses arising from corrosion and fouling
BERTHOLD OTZISK and MICHAEL URSCHEY
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Corrosion attack is an omnipresent threat in oil refineries and petrochemical plants. It may lead to loss of production, cost of maintenance and repairs, replacement cost for equipment, safety aspects and potential environmental impact. If corrosion is slow and well identified, costs can be controlled and planned years in advance.
General corrosive species which are observed in the chemical processing industry and occasionally present in oil refining plants are: organic acids, hydrogen chloride, hydrochloric acid, hydrogen sulphide, hydrogen cyanide or cyanides, ammonia, sulphuric and nitric acid, hydrogen fluoride, hydrofluoric acid, chlorine, alkali and hypochlorite. In aqueous environments, these corrosive species can attack the metal surface.
Chemical treatment programmes with corrosion inhibitors such as neutralising amines or film forming amines are the methods of choice when non-metallic materials, corrosion resistant alloys (CRA), coatings or cathodic protection are considered economically unfeasible to protect the process equipment. Modern neutralising amine blends have a very good buffering capacity and neutralise the acidic species by forming liquid salts that can be removed with water. These neutralising amines shift the pH from very corrosive conditions to levels which are easier to control. Ammonia is an inexpensive product and widely available amine, but there are a number of drawbacks. It is an extremely volatile amine and will not provide safe neutralisation during condensation.
Corrosion is an electrochemical process comprising two half cell reactions, which requires an anode, cathode, metallic conductor and electrolytes. If one of these is missing, aqueous corrosion will not occur. Film forming amines are corrosion inhibitors, which form a thin monomolecular or polymolecular film. The film acts as a protective layer that stops the function of a corrosion cell. Figure 1 shows the difference between oil-soluble and water-soluble filming amines. Oil-soluble filming amines require hydrocarbons to form a protection layer. This type of filming amine is well established and commonly used in hydrocarbon systems with lower water content. Areas of applications for water-soluble filming amines are systems with high water content such as sour water strippers, vacuum overhead systems or water quench columns.
Having a high steam demand, refineries and petrochemical plants also need to take care in protecting their boiler systems from corrosion. Blends of alkalising amines with specific film forming amines provide a safe and modern method to protect boiler installations both in the water and in the steam phase.1 Even demanding HP steam generators such as the transfer line exchangers (TLE) in ethylene plants can be treated with this chemistry.2
Such products can not only protect the boiler and steam distribution system from corrosion efficiently, they can also lead to significant improvements in heat transfer3, thereby helping to improve the energy efficiency of plants. Ever increasing demands on flexibility regarding various feedstock uses and production regimes may also lead to strongly fluctuating steam demand for refinery and petrochemical units. This in turn necessitates flexible boiler operation regimes and may require temporary shutdown of boilers using wet or dry lay-up procedures. Special film forming, amine based products are also an excellent choice for lay-up protection of these systems.4
Regarding monitoring, a desirable objective is to monitor the corrosivity in order to intervene when a defined critical level of corrosivity is achieved. Versatile monitoring tools are available to control the corrosion with the option to optimise the chemical treatment programme. Particularly suitable are electrical resistance probes (ER), polarisation resistance probes (LPR) or non-destructive testing equipment such as hydrogen flux monitoring (hydrosteel), ultrasonics (UT), acoustic emission (AE), eddy current, radiography, thermography, and so on.
A number of factors require consideration before a corrosion inhibitor programme is selected. Laboratory screening may be required in the selection process in order to find the best performing filming amine apart from economics and environmental aspects, process conditions such as temperature, flow rates, metallurgy, clean or fouled conditions, other chemical programmes present, pH conditions, and so on. Various test regimes using electrochemical methods are used to determine the corrosion protection rates and the best performing corrosion inhibitors. The ‘Bubble test’ described in detail by D. Harrop is a screening method for filming amines involving both static and dynamic tests.5 The standard Bubble test uses a series of LPR tests, giving corrosion rate results. The data are collected over a period of about 24 hours, where carbon dioxide is purged into the liquid. Figure 2 shows modified kettle test equipment with pH and temperature controller and coupons instead of LPR probes.
One standard element of any treatment control is also the measurement of product concentrations or their active components in the treated media. While the measurement of ppm concentrations of film forming amines is quite difficult in organic media (and thus not widely practised), this can be achieved in water and steam systems using photometric methods.6
Fouling control programmes
Fouling is a serious problem in oil refineries and petrochemical plants besides unwanted corrosion. It may lead to insecure operational conditions with high production losses. Shortened run time is the consequence of fouling, which requires cleaning operations and in some cases material exchange. The economic implications are often tremendous and can cost billions of dollars. The rate of fouling is a complex function of time, often with an induction period before fouling begins. Many factors influence fouling rates, such as mechanical conditions, fluid velocity, concentration, surface material and temperature.
In oil refining processes the fouling phase may be wax, coke, asphaltenes, stable emulsions or inorganic solids. Most organic fouling is caused by precipitation of asphaltenes, including coke formation. Asphaltenes are partly dissolved in the oil and partly in a colloidal and/or micellar form. Relatively large asphaltene particles can flocculate in the presence of excess amounts of resins and paraffin hydrocarbons. Destabilised asphaltenes act as glue and mortar in hardening the deposits; this is why destabilisation should be necessarily avoided. Highly effective antifoulant programmes stabilise the asphaltenes and act as a dispersant. Already-formed asphaltenes and coke particles are kept small to be transported with the feed stream. This helps to keep the process conditions in a safe state.
In petrochemical plants, fouling can be severe when unsaturated monomers convert to polymers. This may happen in process streams with very reactive compounds such as ethylene, acetylene, propylene, butadiene, styrene or other unsaturates. Trace amounts of oxygen or oxygen containing compounds promote formation of gums and polymers. Butadiene fouling with formation of ‘popcorn’ polymers is a common problem in ethylene plants. Butadiene is a highly reactive molecule and the dimerisation of two molecules will make C8 compounds or higher molecular weight compounds. Figure 3 shows such polymer fouling material, which has a rubbery texture with a low specific weight. The fouling material was taken from a heat exchanger.
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