CorrosionCorrosion is the deterioration that occurs when a metal reacts with its environment.It is impractical to eliminate corrosionEffective engineering is to control corrosion rather than to prevent corrosionAll metals and alloys are susceptible to corrosion

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Consequences of CorrosionSafety : Sudden failure may cause fire, explosion, release of toxic products, construction collapse Health : Pollution due to escaping or corrosion products.Shut down Loss of efficiencyLoss of valuable product

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CDU overhead CorrosionMajor reason - Presence of acidic species in crudeAcids commonly encountered . Hydrochloric acid . Hydrogen sulphide . Carbonic acid . Organic acids . Acids derived from Sulphur Oxides viz. Sulphuric & Sulphurous acids

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Corrosion due to HClComes from incomplete desalting

Calcium & Magnesium chlorides not removed get hydrolyzed to form HCl in presence of heat and water especially at temperature higher than 122 deg C

HCl , a strong acid lowers the pH of water by several units leading to severe corrosion

In the presence of H2S corrosion of iron due to HCl increases substantially

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Chemical Reactions of corrosionPrimary Corrosion Fe + 2HCl -------- FeCl2 + H2

Regeneration of HCl FeCl2 + H2S ------- 2 HCl + FeS

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Overhead corrosion due to HCl can be reduced by

Proper salt removal in the desalting operation

Addition of caustic to the crude charge

Injecting Ammonia or neutralizing amines & Filming amines in the overhead system

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Corrosion due to H2SH2S itself is present in the crude and gets generated due to decomposition of organic sulphur compounds

In presence of H2S corrosion potential due to HCl increases substantially

Corrosion potential due to H2S is minimum in the pH range of 5.5 to 6.5

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Mechanism of H2S Corrosion

The reaction representing the corrosion mechanism is : H2S (H+) + (HS-) (Fe++) FeSH+

The FeSH+ further reacts to form a complex sulphide scale.

The dissociation of H2S is minimum at a pH of 5.0. As pH increases towards neutral region, the bisulphide ion concentration increases.

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An increase in corrosion rate is the result of faster reduction of bisulphide ion from scale lattice and solution.

As the scales lattice is altered, FeS is released, exposing the unreacted Fe.

This FeS thus released enters into the water phase.

This phenomena in CDU is referred as Black Water

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Corrosion due to Carbonic acid

Carbon Dioxide is released from crudes with high content of Naphthenic acid.

Carbon Dioxide is a weakly acidic gas and becomes corrosive when it dissolves in water to form Carbonic Acid.

The primary cause corrosion is the formation of HCO3- which acts as a buffer for H2CO3 corrosion, the source of FeCO3 precipitation(insoluble corrosion product) and product of cathodic protection.

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Mechanism of Carbonic Acid Corrosion

The reactions can be represented as following CO2(g) + H2O == H+ + HCO3- Fe + 2HCO3- == FeCO3 + H2O + CO2

The FeCO3 formed is an insoluble corrosion product which forms a film on the carbon steel surface. This helps in inhibiting corrosion.

Conditions favoring the formation of the FeCO3 film are elevated temperature, increased pH and lack of turbulence.

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In areas of high velocity, the corrosion rates are increased as high turbulence prevents the formation of the preventive FeCO3 film.

This further exposes fresh surface for further corrosion attack.

The corrosion is generally localized in nature.

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Can be reduced by

pH control with caustic soda.

Continuous injection of corrosion inhibitors in the overhead system.

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Corrosion due to Organic acids1Organic acids - acetic acid, propanic acid, butyric acid etc.

Organic acids change pH in the CDU overhead system

Increase demand of neutralizer

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Corrosion due to Naphthenic acids2

Naphthenic acid attack often occurs in the parts operating over 230 deg C such as heater tubes, transfer lines, column flash zones and pumps.

In sour crude units a crude TAN (Total Acid Number) of 1.0 is sufficient to be concerned about Naphthenic acid corrosion, in sweet units TAN of 0.5 may be high enough to cause corrosion

Naphthenic acid corrosion results in sharp edged, smooth grooves, gouges or holes with no corrosion scales or deposits

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Isolated deep pits in partially filmed areas and impingement type attack in film free areas are typical type of Naphthenic Acid Corrosion attack.

SS316 or SS 317H has good resistance for Naphthenic acid corrosion with TAN no. greater than 0.5.

Above 288C and low Naphthenic acid content 5 Cr or 12 Cr cladding are recommended.

When H2S is evolved an alloy with 9 Cr is preferred.

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Factors affecting Naphthenic Acid Corrosion

Naphthenic acid chemistry Crude oils with TAN no. higher than 0.5 and cuts with TAN no. higher 1.5 are considered corrosive between 230 C and 400 C.

Sulphur Compounds A level of 0.2% and above is considered corrosive between 230 C and 455 C

Temperature Occurs primarily in the range of 220 C and 400 C. Above 400 C, no corrosion is observed because of decomposition of Naphthenic acids.

Velocity High velocity results in higher corrosion rates.

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Mitigation measures to be adopted

Blending to reduce the Naphthenic acid content of the feed by diluting a high TAN crude with a low one.

Injection of corrosion inhibitors.

Process control changes to provide adequate corrosion control if there is a possibility to reduce charge rate and temperature.

Upgrading the material of construction to higher chrome and/or molybdenum alloy.

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Areas prone to Naphthenic Acid attack

Furnace Tubes and Transfer LinesAccelerated corrosion due to velocity and two-phase flow.Factors affecting this are temperature, velocity and degree of vaporization.High temperature activates even small amount of Naphthenic acid in oil thereby increasing corrosion significantly.

Vacuum ColumnPreferential vaporization and condensation of Naphthenic acids increase TAN of the condensates.Velocity has little effect.

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Naphthenic acids are most active at their boiling point but the severe corrosion occurs on condensation. Corrosion mechanism is mainly a condensate corrosion and related to content, molecular wt and boiling point of the Naphthenic acid.

Side Cut PipingFactors affecting corrosion are medium fluid velocity, low vaporization and Naphthenic acid and H2S content. Increase in velocity increases the corrosion rate upto the point where the impingement starts and then corrosion is further accelerated.

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CDU overhead Corrosion Control MethodsBlending

Proper desalting

Caustic Injection

Ammonia injection

Neutralizing & Filming amine injection

Water washing

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CDU overhead Corrosion Control MethodsBlending Most commonly used technique Blending of problem crudes with non-problem crudes Sometimes the flexibility may not exist or blending may not provide enough reduction of the problem

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CDU overhead Corrosion Control MethodsDesaltingCrude oil contains varying degrees of impurities like naturally occurring salts, water, solids etc.The total salt (NaCl, MgCl2 and CaCl2) content in crude varies from 3 to 300 ptb Wash water is employed to wash out these impuritiesDesalter removes the added water and most of the the inorganic salts

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Desalter operating conditions

Addition of wash water - 3 to 10 % on total crude chargeResidence time ~ 2 hrs.Temperature - 120 to 150 deg CMixing valve delta P - 10 to 20 psi

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Caustic InjectionAddition of small amount of dilute caustic (NaOH) to the desalted crude is often an effective way to reduce the amount of HCl released in the preheaterCaustic converts the HCl to thermally stable NaCl, thus reducing the amount of free HClDisadvantages of caustic Crude preheat train fouling Stress Corrosion cracking Catalyst contamination problems In d/s units Furnace coking problems

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Ammonia injection in overhead systemTo control pH of the overhead accumulator water (pH range 5.5 to 6.5)DisadvantagesInability to reliably control pH within the water dew point rangeIts salt, NH4Cl causes fouling and under deposit corrosion

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Neutralizing AminesNeutralizing amines are nitrogen containing organic compounds which are weak bases

Morpholine, Ethylene diamine (EDA), Monoethanolamine (MEA), Methoxypropylamine (MOPA)

Propietary formulations of amines by vendors

All of the neutralizer salts are water soluble

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Filming AminesFilming amine provides a barrier between the metal surface and the corrosive aqueous environment by providing micro-molecular film.For effectiveness proper pH control is necessaryEffectiveness of the filmer gets diminished as pH of the overhead system dropsTypical injection rate is 3 - 5 ppmv during normal operationTypically naphtha dilution is provided

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Water washingProducts of the neutralization reactions, amine chlorides or ammonium chlorides can be highly corrosive and fouling

Stripped sour water, water condensate or overhead receiver water recirculation to overhead vapour line

Water containing dissolved oxygen should be avoided as it can accelerate corrosion

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Engineering of Water injection systemToo little water can add to the acid making process and too much can cause grooving of overhead lineA proper spray nozzle is necessary to prevent impingement corrosion of the pipe d/s of injection pointGood distribution system to ensure evenly divide flow among the different banks of the condensersIdeal water injection rate - 5 - 10 % of the overhead stream

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Corrosion MonitoringWater analyses - Overhead receiver water

Hydrocarbon analyses

Corrosion rate measurement

On stream non-destructive examination

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Overhead receiver Water analysespH - System pH can change from acceptable pH to aggressively corrosive pH in matter of minutes so the pH should be measured as frequently as possibleMetals - Fe, Cu, Zn are typically measured but depends on material of constructionChlorides - Aqueous corrosion is always related to the quantity of HCl or chloride salts. Measurement of chlorides confirm when the event of corrosion began and how long it sustained. Regular measurement helps in optimizing caustic addition or blending of crudes which result in minimum corrosivityHardness - Hardness detected means leak in cooling water exchanger. If recycled water wash in use, it means oxygenated water wash I.e. increased corrosion so adjustments in corrosion control programme

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Hydrocarbon AnalysesInhibitor residual - To detect the presence of inhibitor (Filmer)

Metals - The only tool for naphthanic acid corrosion measurement is metal analyses of oils. For this historical data is useful as a check on current conditions.

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Corrosion rate Measurement1Weight Loss Coupons - Calculated corrosion rate based on initial surface area and weight. Visual examination Can be replaced on stream Commonly used in overhead systems ER Probes - Change in x section of measuring element is measured in terms of change in its electrical resistance On stream measurement can be retracted also Used in tower overhead systems ---------2

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Corrosion rate Measurement 2Linear Polarization (LPR) Probes - Instantaneous corrosion rate based on measurement of corrosion current of the probe element - Works only in conductive medium - Used in cooling water systems, application in overhead receiver water is feasible but limited - On stream measurement - Can be retracted also

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On stream non-destructive examinationUltrasonic (UT) & Radiography (RT)

NDE normally not used for extensive routine corrosion monitoring because of its cost

Often used as inspection tool

Used on exception basis for corrosion monitoring when there is a confirmed or suspected problem which is being watched closely

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