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4. CORROSION

4.1. Corrosion allowance

When there is a risk of a specific corrosion, the corrosion allowance can be determined from the corrosion tables available at the Documentation Department. Some of these tables are attached in this chapter.

This corrosion allowance will be determined for a minimum life span of the equipment, generally fixed for 10 years.

In several cases and especially when it is for a fluid difficult to characterise or with variable quality of fluid (crude oil for example), there is no reference table and the corrosion allowance is determined experimentally.

In this case normally, carbon steel is used with corrosion allowance of 3 mm for the moderately corrosive fluids (crude oil, non desulphurised cut, etc...).

The corrosion allowance is reduced to 1.5 mm when the risk of corrosion is low (for example, propane, butane, light gasoline after desulphurisation).

It is increased to 6 mm and even greater for the services particularly corrosive (H2S + water at the condensation), no other economically and technically acceptable solution can be proposed.

To be noted that it is general practice to take no corrosion allowance when designing a hydrocarbon storage tank unless there is a possibility of water decantation together with the presence of H2S (general case for hydrocarbon tanks or hydrocarbon slop tanks).

Finally, different corrosion allowance may be specified for a given fluid depending on the equipment maintainability. For example, for boiler type equipment, the corrosion allowance is 3 mm where else 1.5 mm for the line that the maintenance is done or even changed frequently, the operation that is not been normally done on the principal material.

When stainless steel type 18/8 is used, the phenomenon of corrosion is not to be worried, a zero corrosion allowance can be used.

It is also possible to limit the corrosion in certain part of an equipment by application of coating : u Synthesis coating : plastic or paint u Concrete lining u Metallic pla ting.

Precaution shall be taken when using the first two type of coating because they are very fragile and the basic metal can get corroded very fast. They are not suitable for the security system in case of coating deterioration. It is advisable in this case to foresee an admissible corrosion allowance to minimise this risk.

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Somehow, when metallic plating is used, this will substitute the corrosion allowance. However, one has to verify, especially for an equipment with a small thickness, that the cost of basic metal + plating is cheaper than the cost of having the massive metal at the same grade as the plating for the equipment. Nevertheless, certain plating grades might have welding problems with the basic metal. The faisability of this will have to be verified with the Boilermaking Department.

4.2. Hydrogen corrosion

4.2.1. Corrosion at high temperature

Steels are sensitive to hydrogen corrosion at elevated temperature. It is due to the property of monoatomic hydrogen to diffuse into the metal and then to react with the carbon, which :

u Reduce their mechanical properties u Leads to the formation of methane gas that produce blisters and cracks.

Hydrogen corrosion is well known phenomenon that refer to Nelson graphs published in API 941 (see figure 1).

A fifth edition published in January 1997 confirms the deletion of graphs related to carbon steel 0.5 Mo. Utilisation of this steel beyond the limits acceptable for carbon steel is not advisable.

On the graphs, zones which are delimited by the discontinued lines, correspond to hydrogen corrosion that leads to surface decarburisation. (modification from late edition of April 1990).

The new edition of January 1997 supersede the graph of 3.0 Cr - 0.5 Mo. Utilisation of 3.0 Cr-0.5 Mo steel is replaced by the graph 3 Cr-1 or 2.25 Cr-1 Mo-V.

1997 edition specifies that the temperatures indicated on the graphs represent the average operating values around which a fluctuation of +20ºF (+11ºC) is to be considered. User may or may not include this range when selecting the steels.

When this range is used, it is applicable only for the operating conditions.

This decarburisation does not lead to cracking but lead to a reduction of allowable constraint, of hardness and to the increase of steel ductility.

Zones which are delimited by the continue lines correspond to an internal decarburisation in the heart of the metal with the formation of methane that lead to the formation of cracks and blisters.

Graphs of API 941 are applicable also for the equipment functioning in liquid phase with dissolved hydrogen, the partial pressure of hydrogen to be considered as the partial pressure of the vapour at the equilibrium state with the liquid.

Hydrogen corrosion at high temperature will only appear after certain period of incubation related to the nature of the steel and to the utilisation condition. Graph 2 can be used as refference for actually limited utilisation in time of carbon steel, beyond its normal limit of utilisation. This constraint will be clearly specified in the issued document (specification, PID, operating manual).

However, it is preferable to choose noble metal that has no constraint of exposition limitation to hydrogen at high temperature.

Finally, the implementation of thermal treatment of the equipment limits the risk of hydrogen corrosion at high temperature. However, this implementation does not allow the derogate the limit specified by the graphs published in the API.

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4.2.2. Hydrogen embrittlement

This phenomenon is due to the decrease of solubility and the diffusivity of hydrogen in steel when the temperature decrease.

In normal operation, steel is charged with hydrogen and if precaution has not been taken, there will be :

u A formation of internal cracks, blisters or plating detachment during a rapid depressurisation.

u A rupture during the repressuring, due to the drop of mechanical properties of hydrogen charged steel.

So, it would be advisable to :

u During the shut-down, to reduce progressively and in stages the temperature to allow hydrogen outgassing.

u To put on pressure at a certain temperature in which the hydrogen is dissolved again in the steel, during the start-up.

4.3. Temperature embrittlement

This type of corrosion is the most difficult to be taken into consideration.

It corresponds to the modification of temperature of soft/fragile transition zones for the equipment that use 2¼ Cr and 3 Cr grades and operating at 343ºC to 528ºC (650-1000ºF). When the equipment is brought down to this transition zones, i.e. between ambient temperature and 100ºC, it leads to fragile ruptures.

Steels that contain les than 2¼ % of Cr or more than 3% of Cr is not concerned by this phenomenon.

A relation has been established between this type of corrosion and the migration/diffusion of certain impurities from the metal to the grain boundaries.

This relation is shown by the following formula.

J = (% Si + % Mn) (% P + % Sn) 104

This factor is about 300 for the steel used in the past and had been brought to 100 in the steel used actually.

This precaution is not sufficient and generally, it is required to complement with a test for the steel used fro the construction of the equipment. This test is called “step cooling” or “step wise cooling”. This test has to be representative for a life span of 20 years.

4.4. Corrosion by sulphur

Sulphur compounds present in petroleum products generate corrosion that increases rapidly above 260ºC.

Its corrosivity depends on the of type of sulphur compounds, on the temperature at which they decompose and the nature of the products of the decomposition.

With the absence of hydrogen, the attached graphs III and IV can be referred to.

The graph III gives the foreseeable corrosion for the different grades of steel on the basis of TEXAS crude at 1.5% sulphur.

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The graph IV correspond to the foreseeable corrosion for petroleum products containing 0.6% sulphur.

These graphs are only indicative.

Generally, on crude units (atmospheric premium pipestills), for temperature higher than 260/280°C, 4/6 Cr for bundle and plating and 11/13 Cr for massive parts are selected. It can happen that massive chromium steel solution either in 4/6 Cr or in 11/13 Cr becomes cheapest that 4/6 Cr plated steel in some local conditions. So this choice will remain open on PDS (Process Data Sheets).

4.5. Corrosion by H 2S with the presence of hydrogen at high temperature (absence of

liquid water)

In these conditions, graphs VA to VE (COUPER AND GORMAN graphs) are to be used, which its usage is general. Graph VI can also be used, older document.

4.6. Corrosion by humid H 2S

This denomination imply the presence of water liquid. It happens at low temperature with or without hydrogen.

Three forms of this type of corrosion is to be known :

Generalised corrosion and by pitting

Sulfide stress cracking

Hydrogen induced cracking. This type of corrosion is due to atomic decomposition of H2S to H and HS and not to the presence of molecular hydrogen

4.6.1. Generalised corrosion and by pitting

The precaution can be taken against this type of corrosion :

u By having a sufficient corrosion allowance u By injecting a corrosion inhibitors u By applying an appropriate coating.

4.6.2. Sulfide Stress Cracking

Sulfide stress cracking will affect high elastic limit steel with the presence of water liquid (water liquid / gas diphasic or liquid / hydrocarbon liquid / gas triphasic) at normal temperature.

This type of corrosion, particularly studied for upstream installations, is subjected to NACE standard : MR01-75. To know whether the risk of corrosion exist, the attached graphs (graph VII) extracted from this standard can be used. If this risk exist a more precise standard to specify : u The acceptable materials u The acceptable annealing condition u The maximal admissible hardness after desstress treatment

shall be used.

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4.6.3. Hydrogen Induced Cracking

This corrosion is due to the dissociation of H2S to HS and H, with hydrogen atom migration in the steel then the reconstitution of molecular hydrogen, source of blisters.

Eventhough the exact conditions in which this corrosion might occur is not completely characterised, it seems that it affects particularly carbon steel with the presence of humid H2S at ambient temperature.

In this case, utilisation of this steel is advisable :

u Silicon half dead steel or dead steel u Low-sulfur steel (<0.003%) u Steel containing Cu or rare earth u Coated steel.

This information is only indicative.

4.7. Polythionic acid corrosion

This corrosion is for grade 300 steel used between 360 and 700ºC.

It is due to the precipitation of chromium carbide at the grain boundary. The content of chrome is reduced that induce a reduction of protection provided by chrome and a possible attack by polythionic acid.

This happens normally during the shut down operation when there is a presence of ferum sulphide, water and oxygen at the same time.

Two palliatives :

a. Use 321 or 347 plating. These stainless steels are stabilised with Ti for the first one and Nb for the second. These metals have the affinity with carbon, that prevent the precipitation of chromium carbide in the evoked conditions. It is said that they are insensitive to the phenomenon.

b. Neutralisation of polythionic acid by caustic solution, during the shut off.

4.8. Naphtenic acid corrosion

Hold.

4.9. CO 2 corrosion

Deward and Millians monogram (see figure XI) will be used. This monogram gives normally a conservative value of the corrosion rate because it has not taken into account the passivation coat at the surface of the metal when CO2 is associated with other components (for example H2S).

4.10. Corrosion by chlorides and sea water

Hold.

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4.11. Tables of corrosion graphs

GRAPHS I and II : Hydrogen corrosion. API 941 Ed. January 1997 (Nelson graphs)

GRAPH III : Crude oil corrosion at 1.5% of sulphur, NACE Data.

GRAPH IV : Hydrocarbon corrosion at 0.6% of sulphur, NACE Data. (Mac CONOMY graph)

GRAPHS VA to VE : H2S corrosion in presence of hydrogen at high temperature, NACE Data (COUPER/GORMAN graphs)

GRAPH VI : H2S corrosion in presence of hydrogen at high temperature, Corrosion Data Survey (Ed. 1967)

GRAPH VII : SSC corrosion limit by humid H2S, NACE MR 01-75.

GRAPH VIII : Corrosion by caustic solution, Corrosion Data Survey.

GRAPH IX : Sulphuric acid corrosion, Corrosion Data Survey

GRAPH X : Hydrochloride acid corrosion, Corrosion Data Survey

GRAPH XI : CO2 corrosion, DEWARD and MILLIANS.