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2 General revision CESCOR STIN CORM 15.06.95

REV. DESCRIPTION COMP. VERIF. APPR. DATE ––––––––––––– ––––––––––––– –––

Il presente documento è RISERVATO ed è di proprietà dell'AGIP. Esso non sarà mostrato a Terzi né sarà utilizzato per scopi diversi da quelli per i quali è stato inviato.This document is CONFIDENTIAL and the sole property of AGIP. It shall neither be shown to third parties nor used for purposes other than those for which it has been sent.

DESIGN CRITERIA

INTERNAL CORROSION

CORROSION PARAMETERS AND CLASSIFICATION OF THEFLUIDS

02555.VAR.COR.PRG

Rev. 2

June 1995

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02555.VAR.COR.PRGRev.2 June 1995Sheet 2

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FOREWORD

Rev. 2 No. Sheets 47June 1995

The type of document has been changed from “GENERAL SPECIFICATION”to “DESIGN CRITERIA”.

The Normative References chapter has been revised and updated.

It has been deeply revised the paragraphs concerning the corrosion parametersand the corrosion forms; corrosion evaluation criteria have also been updated.

With respect to the previous revision, it has been completely eliminated theclassification by corrosion environments. In this revision, fluids are definedonly in terms of “type of fluid” and “corrosivity class”.

A detailed list of definition has been introduced.

Definition of sour conditions in accordance to EFC - European Federation of Corrosion, has been introduced.

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CONTENTS

1 GENERAL

1.1 Scope1.2 Normative references1.2.1 European normative references1.2.2 Normative references of ISO, IEC and national organizations1.2.3 Normative references of other organizations

1.3 Definitions1.4 Abbreviations and conversion factors

2 FLUID TYPES AND CO RROSIVITY CLASSES

2.1 Fluid types2.1.1 Liquid hydrocarbons and multiphase2.1.2 Gas and gas condensate2.1.3 Glycol2.1.4 Waters

2.2 Corrosivity classes

3 CORROSION PARAMETERS

3.1 Foreword3.2 Temperature3.3 Pressure3.4 Water content3.5 Gas Oil Ratio3.6 Hydrodynamic conditions3.7 CO 2 molar fraction3.8 H 2S molar fraction3.9 API Grade3.10 Water chemical analysis3.11 Sulphates-reducing bacteria3.12 Sand and suspended solids

4 CORROSIVITY CLASSES

4.1 Liquid hydrocarbons and multiphase systems (I.L.)4.1.1 Corrosion parameters4.1.2 Corrosivity classes

4.2 Gas hydrocarbons and gas with condensates4.2.1 Corrosion parameters4.2.2 Corrosivity classes

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4.3 Glycol

4.3.1 Corrosion parameters4.3.2 Corrosivity classes

4.4 Waters4.4.1 Corrosion parameters4.4.2 Corrosivity classes

5 CORROSION FORMS5.1 General5.1.1 Foreword5.1.2 Materials5.1.3 Corrosion morphologies

5.2 Water wetting conditions5.2.1 Liquid and multiphase systems5.2.2 Gas and gas with condensates system

5.3 O 2 corrosion5.4 H 2S corrosion5.5 Elemental sulphur corrosion5.6 CO 2 corrosion5.6.1 Effects of chemical species in solution5.6.2 De Waard and Milliams model.5.6.3 Top of line corrosion5.6.4 Prediction rules for CO 2 corrosion (Crolet Model)5.6.5 Corrosion products

5.7 Galvanic corrosion5.8 Pitting and crevice5.8.1 Susceptible materials5.8.2 Initiation conditions

5.9 Stress Corrosion Cracking (SCC)5.9.1 Chlorides stress corrosion cracking5.9.2 Polythionic Acids Stress Corrosion Cracking

5.10 Sulphide Stress Cracking (SSC)5.10.1 Sour service conditions according to NACE5.10.2 Sour service conditions according to EFC

5.11 Stepwise Cracking5.11.1 Limits for initiation

5.12 Erosion corrosion5.13 Sand erosion

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1 GENERAL

1.1 Scope

Scope of this document is provide criteria to classify, from the corrosionviewpoint, the main fluids encountered in plants for oil and gas production.

The plants covered in this document are those ones from well head, excluded,to the delivery of treated gas and stabilised oil. Refining plants are outside thescope of this document.

For each type of fluid the parameters are indicated to be gathered to allow thecorrosion experts to assess the corrosivity and to select materials and corrosioncontrol methods.

The most common corrosion forms in oil and gas industry are reviewed and proved criteria for corrosion prediction are indicated.

This document does not cover the corrosivity of the external environmentwhich the plant components are in contact with, as soil, sea water; also nonmetallic materials such as elastomeric, ceramic, composites are not dealt with.

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1.2 Normative references

1.2.1 European normative references

No European normatives exist on the argument of this specification.

1.2.2 Normative references of ISO, IEC and national organizations

ISO 8044 “Basic Terms and Definitions on Corrosion”.

1.2.3 Normative references of other organizations

EFC O&G 93-1 “Guidelines on Material Requirements for Carbonand Low Alloy Steels for H 2S Containing Oil andGasfield Service”

NACE MR0175 “Sulphide Stress Cracking Metallic Material for Oil Field Equipment”

NACE TM0284 “Evaluation of Pipeline Steels for Resistance toStepwise Cracking”

API RP-14E “Design and Installation of Offshore Production

Platform Piping System”

ASTM 287-92 “Standard Test Method for API Gravity of CrudePetroleum and Petroleum Products (Hydrometer Method)”

ASTM G 78-46 “Standard Test Method for Pitting and CreviceCorrosion Resistance of Stainless Steels andRelated Alloys by the Use of Ferric ChlorideSolutions”

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1.3 Definitions

Chloride Stress Corrosion Cracking - CSCCFormation of cracks caused by stress corrosion in a water- and chloride ions-containing environments (NACE MR0175).

CorrosionPhysicochemical interaction between a metal and its environment that results inchanges in the properties of the metal and which may often lead to impairmentof the function of the metal, the environment, or the technical system, of whichthese form a part (ISO 8044).

Corrosion productSubstance formed as a result of corrosion (ISO 8044).

Corrosion rateCorrosion effect on a metal per unit of time.

Corrosion resistanceAbility of a metal to withstand corrosion in a given corrosion system (ISO8044).

Corrosion systemSystem consisting of one or more metals and all parts of the environment whichinfluence corrosion (ISO 8044).

Corrosive agentSubstance which when in contact with a given metal will react with it (ISO8044).

Corrosive environmentEnvironment that contains one or more corrosive agent (ISO 8044).

CorrosivityAbility of an environment to cause corrosion in a given corrosion system (ISO8044).

Corrosivity classIn the present document, it is an attribute conventionally assigned to each typeof fluid in order to point out the most significant corrosivity features. For thefluid designed: liquid hydrocarbons and multiphase (I.L.), gas and gas withcondensates hydrocarbon (I.G.) and glycol (G.), the corrosivity class is definedon the base of CO 2 and H 2S partial pressures as follows:

– N. non containing CO 2 and H 2S – C. containing CO 2 – S. containing H 2S – CS. containing CO 2 e H 2S

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Crevice Corrosion

Corrosion associated with, and taking place in, or immediately around, anarrow aperture or clearance (ISO 8044).

Dew point temperatureIt is the temperature, below which liquid condensation starts from gas phase ata given pressure. On the state diagram condensation conditions are indicated bythe dew point curve. In particular the water dew point refers to condensationconditions of water from gas.

FugacityIt is thermodynamic function, in pressure units, that, when used in a

thermodynamic equation of an ideal gas in substitution of pressure, allows toapply the same function to a non-ideal gas.

Hydrocarbon−− Gas: a mixture of hydrocarbons with 1 to 4 carbon atoms at a temperature

above the critical temperature. Gas can be in form of dry gas or gas withcondensates depending on thermodynamic conditions.

−− Liquid: a mixture of hydrocarbons whose temperature is below the criticaltemperature of the particular system of natural hydrocarbons that the mixturecontains; in the mixture the liquid phase, always present, can be combinedwith a gas phase or an aqueous phase or both; in this cases the system is

called multiphase.

Hydrogen embrittlementA process resulting in a decrease of the toughness or ductility of a metal due toabsorption of hydrogen. (ISO 8044).

Hydrogen Induced Cracking - HICA type of "stepwise cracking" in steels for pipes, or laminated products; crackson the same plane have the tendency to join with cracks in near levels formingsteps through the metallic wall, reducing its mechanical resistance.

Ionic strengthThe ionic strength of a solution, µ, is defined asµ = ∑

12

C Zi i2

where C i is the concentration of i -th ion with Z i charge.

Microbial CorrosionCorrosion associated with the action of micro-organism present in the corrosionsystem (ISO 8044).

Molar fractionMeasurement of the concentration of a chemical species expressed as ratio

between the number of moles of the given chemical species and the totalnumber of moles.

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Oil

In the present specification the terms oil and crude are considered synonymousto indicate liquid hydrocarbons.

Passivity (passive state)State of a corrosion system characterised by a reduced corrosion rate of a metalas a consequence of the formation of corrosion products on its surface.

Pitting CorrosionCorrosion resulting in pits, i.e. cavities extending from the surface into themetal (ISO 8044).

Predicted corrosion rateIt is the corrosion rate, usually expressed quantitatively (in mm/y) and/or qualitatively, determined: (a) after the corrosion study, applying all theavailable knowledge and tools; (b) through laboratory tests, simulating the realconditions; (c) on the base of field corrosion monitoring data applicable to thecase under study. The following categories are recommended to express in aqualitative way the penetration rate for general corrosion forms: negligible,low, moderate, severe, very severe.

Reservoir−− Dry gas: reservoir whose temperature is above the cricondetermical

temperature of the particular system of natural hydrocarbons that it contains.The cricondetermical temperature is the highest temperature at which thecoexistence between liquid and gas phase is still possible.

−− Gas with condensates: reservoir whose temperature is between critical andcricondetermical temperatures of the particular system of naturalhydrocarbons that it contains. The condensation of the liquid phase from gastakes place by reverse condensation, that is the phenomenon by whichdecreasing the pressure below the dew point, there is initially an increase of the liquid phase percentage and eventually a partial or total ri-evaporation of the latter.

−− Crude oil: reservoir whose temperature is below the critical temperature of the particular system of hydrocarbons that in contains.

Residual corrosion rateIt is the corrosion rate after treatments with corrosion inhibitors.

Sour conditionsConditions, usually with H 2S presence, that cause Sulphide Stress Crackingoccurrence in susceptible materials. The definition is according to NACEMR0175 or EFC O&G 93-1.

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Specific gravity

It is the ratio between the weight of a given volume of liquid and the weight of the same volume of water; for a gas it is the ratio between the weight of a givenvolume of gas and the weight of the same volume of dry air in the samestandard conditions.

Stepwise Cracking - SWCFormation of cracks, even in absence of mechanical solicitations, as aconsequence of diffusion of atomic hydrogen, produced in the cathodic reactionin H 2S containing environments, and the successive recombination to molecular hydrogen inside the metallic lattice near microcracks, inclusions or defects.Stepwise Cracking includes: “Stress Oriented Hydrogen Induced Cracking”,

“Blistering”, “Hydrogen Induced Cracking”.

Stress Corrosion Cracking - SCCA process resulting from the combined action of corrosion and tensionmechanical solicitations due to residual or applied stresses; it causes theformation of surface stress corrosion cracks; cracks are usually perpendicular tothe stress direction.

Sulphide Stress Cracking - SSCFormation of cracks caused by stress corrosion, with a significant contributionof H 2S as a corroding agent.

Type of fluidIn the present document the following types of fluid are considered: liquidhydrocarbons (I.L.); gas and gas with condensates hydrocarbons (I.G.); glycol(G.); sea water (A.M.); fresh water (A.D.); brackish water (A.S.); formationwater (A.F.).

WettabilityTendency of a fluid to disperse or to adhere to a solid surface in presence of another insoluble liquid. Wettability is a measure of the preference of corrosion

products or metallic surfaces for water or oil.

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1.4 Abbreviations and conversion factors

Table 1.1 shows the corrosivity parameters mentioned in this document withtheir abbreviations and measure units. Table 1.2 shows the main conversionfactors.

Tab. 1.1 - Corrosion parameters, abbreviations, and units.

PARAMETER Abbreviation Unitoperating pressure P MPaoperating temperature T °Cminimum temperature T min °Cmaximum temperature T max °CH2S molar fraction yH 2S mole/mole%CO 2 molar fraction yCO 2 mole/mole%H2S partial pressure pH 2S MPaCO 2 partial pressure pCO 2 MPawater cut percentage WCUT m³/m³ %water oil ratio percentage WOR m³/m³ %gas oil ratio GOR Nm³/m³API grade API (-)total salinity in the water phase TDS g.l -1

water chemical analysis− chlorides concentration Cl - mg .l-1 (ppm)− bicarbonates concentration HCO 3- mg .l-1 (ppm)− acetates concentration HAC mg .l-1 (ppm)− sulphates concentration SO 4-- mg .l-1 (ppm)− sodium concentration Na + mg .l-1 (ppm)− potassium concentration K + mg .l-1 (ppm)− magnesium concentration Mg 2+ mg .l-1 (ppm)− calcium concentration Ca 2+ mg .l-1 (ppm)− iron concentration Fe 2+ mg .l-1 (ppm)oxygen in aqueous phase cO 2 mg .l-1 (ppm) or ppbwater pH in situ pH in-situ (-)water pH in air pH in-air (-)elemental sulphur S yes/nomercury Hg yes/noaverage flow rate v m/sapplied load σ MPayield strength σYS MPa

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Tab. 1.2 - Conversion factors

PARAMETER from to multiplyingfactor

concentrations:− bicarbonates mg .l-1 (ppm) meq .l-1 0.016− acetates mg .l-1 (ppm) meq .l-1 0.017− sulphates mg .l-1 (ppm) meq .l-1 0.021− sodium mg .l-1 (ppm) meq .l-1 0.043− potassium mg .l-1 (ppm) meq .l-1 0.026− magnesium mg .l-1 (ppm) meq .l-1 0.083− calcium mg .l-1 (ppm) meq .l-1 0.050− iron mg .l-1 (ppm) meq .l-1 0.036− chlorides mg .l-1 (ppm) meq .l-1 0.029

pressure psi MPa 0.006895 pressure bar MPa 0.1temperature oF oC (°F-32)/1,8volume barrel (US) m 3 0.1589gas/liquid ratio ft 3/barrel Nm 3/m 3 0.178

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2 FLUID TYPES AND CORROSIVITY CLASSES

2.1 Fluid types

The following types of fluids are considered in this specification:

fluid types abbreviation

liquid hydrocarbons and multiphase systems I.L.gas and gas with condensates I.G.glycol G.

sea water A.M.fresh waters A.D. brackish waters A.S.formation waters A.F.

The above listed types of fluids do not obviously cover the whole range of thefluids met in oil and gas production plants, but only the main categories.Particularly, all the fluids for decarbonation and desulphuration treatment areexcluded, as well as all chemical additives (corrosion inhibitors, fluidizers,etc.).

2.1.1 Liquid hydrocarbons and multiphase

These fluids include oil, alone or in combination with gas phase and water phase.

2.1.2 Gas and gas condensate

These fluids include gas, alone or in combination with condensates or water.Reference is particularly made to fluids coming from dry gas and gascondensate reservoirs.

2.1.3 Glycol

Reference is made to pure glycol, water and glycol mixtures, in gas dehydrationunits and injected to prevent hydrate formation in gas lines.

2.1.4 Waters

They include all types of industrial water met in oil and gas production, and in particular: fresh, brackish, formation and sea waters.

Fresh waters are usually shallow waters (from rivers or lakes) or waters from

shallow formations. Drinkable waters are characterised by a salinity below 1.5g/l.

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Sea water has a salinity of 35 g/l, but locally can assume very different values.

Formation waters (brines) produced along oil and gas, are characterised by highsalinity. Sometimes they require to be re-injected into the formation, often after an adequate corrosion control treatment.

The following criteria are used to define the different kinds of waters:

Fresh waters - A.D.− shallow waters− TDS < 2.0 g/l

Brackish waters - A.S.− shallow waters− TDS > 2.0 g/l

Sea waters - A.M.− TDS ≅ 35 g/l

Formation waters - A.F.− reservoir waters (deep formations)− TDS > 2.0 g/l

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2.2 Corrosivity classes

For each type of fluid, the following corrosivity classes are identified:

type class properties

I.L. I.L.N. non containing CO 2 or H 2SI.L.C. containing CO 2I.L.S. containing H 2SI.L.CS. containing CO 2 and H 2S

I.G. I.G.N. non containing CO 2 or H 2S

I.G.C. containing CO 2I.G.S. containing H 2SI.G.CS. containing CO 2 and H 2S

G. G.N. non containing CO 2 or H 2SG.C. containing CO 2G.S. containing H 2SG.CS. containing CO 2 and H 2S

For waters in general (A.), the following corrosivity classes are defined:

type class properties

A. deaerated non containing O 2aerated containing O 2

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3 CORROSION PARAMETERS

3.1 Foreword

Corrosivity assessment of the fluids is carried out considering a set of corrosion parameters regarding the fluid itself and the operating conditions.

3.2 Temperature

Temperature has a complex effect on corrosion rate, increasing or decreasingthe aggressiveness of a fluid in different ways; the following effects arementioned:− increase of the kinetics of corrosion reactions as the temperature rises;− inhibition, as temperature rises, of the susceptibility to hydrogen

embrittlement in presence of H 2S;− formation of protective corrosion products (for example FeS, FeCO 3 or

CaCO 3) at high temperatures. Operating temperature values, T, shall be collected, as well as maximum fluidtemperature, T max , and minimum temperature that the system or the examinedcomponent can reach, also considering temperature of external environment.

Minimum temperature, T min , can be a key factor in selecting the proper materials because of its effects on the resistance to brittle fracture.

3.3 Pressure

Partial pressure of gas corroding agents in water phase, as CO 2, H 2S, O 2depends on total pressure P.

3.4 Water content

Water content in production fluids is a key factor in determining the actualwater wetting conditions on metallic walls. It can be expressed as:− water cut percentage, WCUT, in m³/m³ %, that is water volume on total

volume of liquid phases,− water oil ratio percentage, WOR, in m³/m³ %, that is water volume on total

volume of hydrocarbons in liquid phase

In liquid hydrocarbons and in multiphase systems water is present as formationwater; in gas systems water can be present as condensation water or formationwater dragged from the reservoir. In the latter case water has a high salinity.

Water is always associated to gas from reservoir.

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3.7 CO 2 molar fraction

To evaluate the CO 2 corrosion, and to calculate the partial pressure, CO 2content in the gas phase expressed as molar fraction, yCO 2.

The CO 2 content in the gas phase can also be approximately expressed asweight percent.

The CO 2 partial pressure, pCO 2, is calculated as:

pCO 2 = P ⋅ yCO 2

For higher pressures, roughly above 100 bar (10 MPa), the fugacity, f, is usedto calculate partial pressure:

pCO 2 = f ⋅ yCO 2

3.8 H 2S molar fraction

The H 2S content is expressed as molar fraction in the gas. In ideal gas, molar fraction and volume percentage are the same.

As in CO 2 case, H 2S molar fraction is used to estimate the H 2S partial pressureas:

pH 2S = P ⋅ yH 2S

For higher pressures, roughly above 100 bar (10 MPa), the fugacity, f, is usedto calculate partial pressure:

pH 2S = f ⋅ yH 2S

3.9 API Grade

API grade, or API gravity, is a measure for fluid density (oil, water, natural gas)(ASTM D 287-92). It is calculated with the following expression:

° = −API141,5

131,5γ

with:γ = specific gravity at 15 °C.

Water has an API grade 10°, as raw oil's, while crude oil has values rangingfrom 6° (very heavy) to 60° (very light). Usually oils range from 25° to 35°

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API grade. Oils are considered light when they have API grade values between

35° and 45°, and heavy when API grade is below 25°.

3.10 Water chemical analysis

To correctly evaluate corrosivity, a complete chemical analysis of the water phase is required. Along the analysis all information regarding sampling procedures shall be retained.

Some chemical composition parameters have primary importance and arereviewed here below.

Total salinity

It is the solid residue after boiling, expressed in g/l.

High salinity, especially in presence of oxygen, enhances localised corrosionforms, promoting separation between anodic and cathodic areas, and galvaniccoupling effects.

pH

pH has a significant effect on water corrosivity, through the hydrogen evolutionreaction; precipitation equilibria of protective scales also depend on pH.

In aqueous phase associated with hydrocarbon production pH, is determined bythe solubility equilibria of acid gas as CO 2 and H 2S (and the followingdissociation and reaction equilibria). pH measurements at operating conditions,called pH in situ, pH in-situ , have intrinsic difficulties. To obviate to this problemsome software programs based on temperature, pressure and water compositionare available to calculate the pH in situ (for instance “ CORMED” programdeveloped by ELF).

Acid environments (pH < 6) are more corrosive than neutral pH (from 6 to 8) or alkaline (pH > 8) ones. Alkaline fluids with pH above 11-12 are not consideredcorrosive for carbon steel.

Chlorides

Chlorides concentration affects localised corrosion forms, mainly through thedepassivation effect caused by chloride ions, especially with stainless steels.

Oxygen

Oxygen is dissolved in waters contacting with the atmosphere. It is absent inreservoir fluids. Whenever oxygen is afterwards introduced into the fluid, i.e.

by contact with the atmosphere or through faulty seals or because it is

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contained in additives, its effect on corrosivity shall be carefully evaluated. In

H 2S containing fluids, oxygen may cause H 2S oxidation to elemental sulphur,tiosulphates etc., thus producing an aqueous phase acidification.

Organic acids

Organic acids (formic HCOOH, and acetic CH 3COOH) are often present in production fluids containing CO 2. Their presence shall be considered in water pH calculations.

Elemental sulphur

Elemental sulphur, that can be found in some reservoir, often in combinationwith H 2S, is a strong oxidant and it is extremely aggressive also for corrosionresistant alloys.

3.11 Sulphates-reducing bacteria

Sulphates-reducing bacteria (SRB) grow in anaerobic conditions in presence of sulphates ions, that are reduced to sulphides. The microbial corrosive attack ischaracterised by formation of black deposits of sulphides-containing corrosion

products on the metal.

Bacteria are present in soil, natural waters and mud; they are not normallyfound in hydrocarbon reservoirs, unless they are introduced there, for example,during drilling or through water injection systems.

3.12 Sand and suspended solids

The presence of sand and suspended solids in the fluid causes erosion of metallic surface, at a rate that depends on flow rate and density of the fluid andon quantity, density and morphology of the solids present in the fluid.

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4.2 Gas hydrocarbons and gas with condensates

4.2.1 Corrosion parameters

Gas hydrocarbons and gas with condensates are classified according to thefollowing parameters:− CO 2 partial pressure;− H2S partial pressure;− maximum and minimum operating temperature;− water cut percentage or water oil ratio percentage;− total salinity and/or chloride content of the aqueous phase;− elemental sulphur;− average flow rate of the fluids;− oxygen;− sand and suspended solids;− water chemical analysis;− water pH-in-situ;− water pH-in-air;− sand;− flow rate;− sulphates reducing bacteria.

4.2.2 Corrosivity classes

Gas hydrocarbons and gas with condensates are classified according thefollowing criteria:

Non containing CO 2 and H 2S, I.G.N. pCO 2 < 0.001 and pH 2S < 0.0035

containing CO 2 I.G.C. pCO 2 > 0.001 and pH 2S < 0.0035

containing H 2S I.G.S. pCO 2 < 0.001 and pH 2S > 0.0035

containing CO 2 and H 2S I.G.CS. pCO 2 > 0.001 and pH 2S > 0.0035

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4.3 Glycol

4.3.1 Corrosion parameters

Glycol are classified according to the following corrosion parameters:− water percentage;− operating temperature;− CO 2 partial pressure;− H2S partial pressure;− dissolved oxygen;− water salinity;− sand and suspended solids;− pH.

The eventual presence of oxygen, i.e. from contact between glycol andatmosphere, with water presence in glycol, causes a high corrosivity, evenwhen there is no CO 2 or H 2S.

4.3.2 Corrosivity classes

Similarly to gas hydrocarbons, liquids and multiphase systems, glycol areclassified according the following criteria:

Non containing CO 2 and H 2S G.N. pCO 2 < 0.001 and pH 2S < 0.0035

containing CO 2 G.C. pCO 2 > 0.001 and pH 2S < 0.0035

containing H 2S G.S. pCO 2 > 0.001 and pH 2S < 0.0035

containing CO 2 and H 2S G.CS. pCO 2 > 0.001 and pH 2S > 0.0035

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5 CORROSION FORMS

5.1 General

5.1.1 Foreword

In this section the most common corrosion forms occurring in oil and gas production are reviewed.

For each corrosion form, the relevant definitions are reported and the criteria to predict corrosivity are illustrated.

5.1.2 Materials

The main metallic materials families utilised in oil industry are the following:

− carbon steels− low alloy steels− stainless steels

− ferritic− martensitic− austenitic

− ferritic-austenitic (duplex)− nickel alloys− cobalt alloys− titanium and titanium alloys.

Stainless steels, nickel and cobalt alloys and titanium are generally definedCRA, which stands for “corrosion resistant alloys”.

5.1.3 Corrosion morphologies

Corrosion forms can be divided into the following fundamental types,

according to the morphology of the attack:

general corrosion: it occurs on the whole surface of the metal in contact withthe environment; it can be uniform, with a generalised and regular loss of metalon the exposed surface, or non uniform, with corrosion penetration varyingfrom area to area.

localised corrosion: it happens in a limited portion of surface in contact with theenvironment. The morphology of localised corrosion changes considerably,depending on material and environment. The entity of the damage does notdepend on the total quantity of oxidised metal.

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The following classes can be used for to express the penetration rate of general

corrosion forms:− negligible 1000 µm/y

5.2 Water wetting conditions

Below 400 °C corrosion can occur: – in presence of liquid water and – if water is, even only temporarily, in direct contact with the metallic

surface;those conditions define the water wetting of the metallic surfaces.

Water stabilises ionic species in solution that participate, as reagents, productsor intermediates, in the electrochemical corrosion reaction, and it activates localmicro cells on metallic surfaces. In particular situations, other solvents such asmethanol, can acquit a similar function, even if with different effectiveness.

5.2.1 Liquid and multiphase systems

In multiphase systems corrosion is directly proportional to the fraction of timethe metal is microscopically wetted by the aqueous phase. In multiphasesystems, water separation and transportation of the aqueous phase in contactwith the metallic wall (wetting), depend on:− nature of the phases and repartition;− phases composition;− hydrodynamics;− geometry.

The content of formation water in crude oil is quite variable. When water fraction is very low, below a few percents, the metallic walls are always oil-wetted; when water is the pre-eminent phase, water wetting conditions prevail;when water concentration is intermediate, there is an intermittent water wetting.

Local water wetting conditions can occur in presence of geometricaldiscontinuities, which cause turbulence and water separation from the oil phase,even if water content is quite low. Significant cases are extruding weld beads or valves. In stagnant conditions, as in tanks or in horizontal pipes in laminar regimen, where water phase spontaneously separates on the lower part of the

pipe or at the tank bottom, even a low percentage of water is enough to producewater wetting conditions.

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5.2.2 Gas and gas with condensates system

In gas and gas with condensates reservoirs, gas is saturated with water, inequilibrium with the liquid water in the reservoir. During production, the gasexpands and cools: when it reaches the water dew point, water starts tocondensate from gas; gasoline, when present, can condensate before or after water condensation.

Without reliable information on the presence of water or on condensationconditions, it is convenient to assume that an aqueous phase is always presentin contact with the metallic surface. On the contrary if operating temperature isat least 10 °C above the water dew point temperature, the presence of liquid

water can be excluded.

Beyond condensation water, also formation water, mechanically dragged by thegas can be produced. In case of condensation water, salinity is very low, whilein formation waters it can be quite high; usually the most common situation isan intermediate one, with a water composition diluted in comparison toformation water, due to condensation water.

Water is conventionally assumed to be a formation water when the ionicstrength is higher than 0.5.

Water, depending on hydrodynamic conditions, can be present as small dropsdispersed in the gas or as a liquid film that wets the walls while flowing,dragged by the gas. The thickness of the liquid film is tens or hundreds of micron class, and decreases as the quantity of liquid produced decreases and asthe gas flow rate increases. Corrosion rate presumably increases as thethickness of the liquid film and its flow rate increase.

The liquid film can be constituted by water, hydrocarbons or a mixture of both.In the last case, water wetting depends on the quantity of the produced water,and, in particular, by the water fraction in the liquid.

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5.3 O 2 corrosion

Oxygen corrosion of carbon and low alloy steels occurs in aeratedenvironments as general corrosion. Corrosion rate is directly proportional to theamount of oxygen available at the metal solution interface, i.e. the oxygen flux.This depends on:1. environmental conditions:

- oxygen concentration;- hydrodynamic conditions:- temperature.

2. the steel surface conditions.

In stagnant aerated water and at room temperature, corrosion rate, expressed inµm/y, is about 20 times the oxygen concentration expressed in ppm.

In non-stagnant conditions this value shall be multiplied by a factor approximately equal to the square root of the flow rate (in m/s) for laminar flow, and equal to the flow rate (in m/s) for turbulent flow.

In aerated waters with flow rate above 1 m/s and temperature above 30°C, thefollowing equation can be applied to predict corrosion rate of carbon and lowalloy steels:

vcorr = 0.020 ⋅ cO 2 ⋅ 2 (T-30)/30 ⋅ v n

where:− vcorr corrosion rate, µm/y− cO 2 oxygen concentration, ppb− v flow rate, m/s (it is assumed to be v=1 if v

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5.6 CO 2 corrosion

CO 2 is one of the main corroding agents in oil and gas production.

CO 2 corrosion occurs with quite different morphologies, often designed withspecific terms as: “mesa corrosion”, “pitting corrosion”, “ring worm corrosion”.

Prediction of CO 2 corrosion is based on the following parameters:− CO 2 partial pressure;− water phase composition;− pH;− temperature;− hydrodynamic conditions− presence of H 2S.

5.6.1 Effects of chemical species in solution

Chemical composition of the water phase in contact with steel, has a greatinfluence on CO 2 corrosion rate, especially through the modification of local

pH (pH in-situ ); corrosion rate, in fact, is negligible, or low, when pH in-situ is above5.5-5.6.

The effect of the main chemical species that influence the phenomenon are briefly reviewed here below.

Bicarbonates. In waters with high alkalinity (HCO 3- = 30 ÷150 meq/l), corrosionrate is low or moderate. Also the Ca 2+/HCO 3- ratio affects the water aggressiveness: in alkaline waters, with HCO 3->>Ca 2+ , corrosion rate is low or moderate as above said; when Ca 2+/ HCO 3- is high (>1000 meq/meq), pH islow, but corrosion results uniform, since separation of anodic and cathodicareas cannot occur. Furthermore, when the content of Ca 2+ ions in solution ishigh, precipitation of a protective layer of CaCO 3 can occur in relation to local

pH conditions.

Acetates. Several reservoir fluids contain volatile organic acids, in particular acetic acid (CH 3COOH). With the term “acetates”, the sum of all organic acidin solution, expressed as meq/l, is normally intended; when bicarbonates aredetermined through titration, a part of acetates is expressed as bicarbonates.

According to some authors, CO 2 corrosion depends on the acetate concentrationin solution; in particular CO 2 corrosion is predicted to be low when the acetatescontent is low (

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Fe 2+ ions. The contamination of Fe 2+ ions, coming for instance from steel

corrosion, causes an increase of pH (compared with the pH determined by CO 2dissolution alone) due to the formation of FeCO 3 and Fe 3O4. Corrosion

products, through the modification of pH, affect corrosion rate, with a decreaseeffect.

Variation of pH, when Fe 2+ saturation conditions are reached, is between 0.5and 1.6. The saturation pH for FeCO 3 and Fe 3O4 can be calculated as a functionof temperature and CO 2 partial pressure data.

H 2S. Presence of H 2S in solution, even in very small quantities, highly modifiesthe chemistry of the solution and the corrosion behaviour of steels. Theformation of a protective film of iron sulphide, FeS, passivates the steel thusreducing its corrosion rate. However the risk of localised corrosion (pitting ) ishigher: iron sulphide, in fact, is an electronic conductor and causes an increaseof free corrosion potential.

5.6.2 De Waard and Milliams model.

Base equation. In presence of water with a very low salt content (i.e.condensation water) CO 2 corrosion rate can be calculated with the De Waardand Milliams base equation.

Log vT

Log pCOcorr ( ) . . ( )= − + ⋅5 81710 0 67 2

where:− vcorr corrosion rate in mm/y;− T temperature in °K;− pCO 2 CO 2 partial pressure in bar;− Log logarithms are decimal.

At high pressure, approximately above 100 bar (10 MPa), the ideal gas modelis not applicable and fugacity shall be used instead of pressure in calculatingthe CO 2 partial pressure.

Fugacity is calculated from pressure through the fugacity coefficient “a”:

f = a ⋅ P

The values of corrosion rate predicted by the base equation are often muchhigher than the corrosion rates actually observed. For this reason, somecorrection factors have been introduced to take into account of specific effectson corrosion rate.

Formation of protective corrosion products . Above a certain temperature,named scaling temperature (T scale ), the actual corrosion rate is lower then

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predicted by the base equation due to formation of protective corrosion

products effects, provided that hydrodynamic conditions do not cause their removal.

The scale temperature, T scale , is given by the following equations:

Tscale K Log fCO

( ). . ( )

=+ ⋅

24006 7 0 6 2

and the correspondent multiplying factor, F scale , is:

Log F T Log fCOscale( ) . ( ) .= − −2400

0 6 6 72

The new corrosion rate, v’ corr , is:

v’ corr = v corr ⋅ F scale

Fe 2+ and pH effect. As previously seen, in absence of other buffering chemicalspecies, contamination of the solution with Fe 2+ ions causes, at constanttemperature and CO 2 partial pressure, a reduction of corrosion rate, connectedto a local pH variation.

When the scaling factor, F scale , is not applicable to modify (i.e. reduce) thecorrosion rate calculated by the base equation (T < T scale or F scale = 1), the pHeffect is considered as shown here below.

The saturation pH, pH sat , for Fe 3O4 and FeCO 3, is calculated with the followingequations:

pHT

Log fCOsat = + −1361307

017 2. . ( )

corresponding to the formation of Fe 3O4, and:

pH Log fCOsat = −5 4 0 66 2. . ( )

corresponding to the formation of FeCO 3.

The corrosion product with the lowest saturation pH is the most stable and thatone with the highest probability of formation.

The following parameter is then defined:

∆ pH = pH sat - pH in-situ

and the correction factor F pH is calculated through the following procedure:

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if: pH sat ≥ pH in-situ :

Log F pH pH pH sat insitu( ) . ( )= −0 32

if: pH sat < pH in-situ

Log F pH pH pH insitu sat( ) . ( ) .6= − −0 13 1

In fluids containing CO 2 and small quantities of H 2S, the following expressionhas been proposed for F pH :

F pH = 1 -0.34 ⋅ ∆ pH

The new corrosion rate, V” corr , corrected for pH is then calculated as:

V” corr = V corr ⋅ F pH

Effect of glycol. In presence of glycol and in oxygen free environments, asignificant reduction of corrosion rate is observed, as a consequence of aninhibition effect.

The relevant correction factor for the corrosion rate calculated from the baseequation A.1. is given by the following formula:

Log F A Log Wglyc( ) ( ( %) )= ⋅ − 2

where:− W% is the weight percentage of water in the glycol;− A is a constant which depend on type of glycol; it is

normallyassumed A=1,6.

The correction is applicable for a water content above 10% in weight; thecorrected corrosion rate, V’” corr , is given by:

V”’ corr = V corr ⋅ F glyc

5.6.3 Top of line corrosion

It can occur in pipes where the gas phase flows over a liquid water vein. On theupper side, condensing water is saturated by CO 2 eventually present: corrosionrate in this situation, where the efficiency of corrosion inhibitor may resultlimited, depends on the rate of water condensation from gas.

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If the fluid flow in the conduct is slug type, the passage of liquid slugs modifies

favourably the pH of water (removing or diluting the condensation water film)and eventually filming the metallic wall with liquid hydrocarbons.

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5.6.4 Prediction rules for CO 2 corrosion (Crolet Model)

A completely different approach to predict the corrosivity of CO 2 containingfluids has been proposed by Crolet for corrosion in oil and gas wells. The

predictive model is part of a software program, named “ CORMED”, (by thesame author) for the calculation of in-situ pH.

Prediction of corrosivity is expressed using the following classes of corrosion-risk:− very low;− medium;− high.

No corrosion rate values are associated to such classes, but reference is made toan approximate operating life, which is considered acceptable, equal to 8-10years.

The rules to predict the risk of CO 2 corrosion consider the following parameters:− type of produced water, formation or condensation;− CO 2 partial pressure;− in-situ pH;

− potential corrosivity (PC): it is a parameter which can be calculated with“CORMED” program; alternatively, corrosion rate calculated with the baseequation of De Waard and Milliams model can be used;

− in situ acetic acid content;− Ca 2+/HCO 3- ratio.

The prediction rules are reported here below.

Condensation water

corrosion risk is very low if:− pCO 2 < 0.05 bar (0.005 MPa) or − PC < 0.2 mm/y or − pCO 2 < 0.2 bar (0.002 MPa) and in situ acetic acid < 0.1 meq/l

corrosion risk is medium if:− 0.2 < pCO 2 < 5 bar (0.02

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− in situ pH > 5.6 or − 0.05 < pCO 2 < 10 bar (0.005

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magnetite scales or of iron sulphide corrosion products, both showing a

cathodic behaviour with respect to carbon or low alloy steel.

Severe situations of galvanic contact can be observed in salt waters, with highconductivity and aerated, as for instance sea water.

Negative effects can be observed also on the more noble metal. This is the caseof coupling between CRA (stainless steel or nickel alloy) with carbon or lowalloy steel in deaerated environments, where the main cathodic reaction ishydrogen evolution: hydrogen embrittlement is possible on the more noblemetal if it is susceptible; low temperatures and presence of H 2S promote thesesituations.

The following table summarises the different situations.

environment (T) galvanic coupling effects

carbon steel - anode

E corr less noble

CRA - cathode

E corr more noble

low temperature(< 60 °C)

− general corrosion− pitting and crevice

− hydrogenembrittlement

medium-hightemperature(> 60 °C)

− general corrosion− pitting and crevice− stress corrosion

− cathodic protection

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5.8 Pitting and crevice

Pitting and crevice are localised corrosion forms typical of metals showing anactive-passive behaviour, characterised by formation of a galvanic macro-cell

between a passive area of the metal, where the cathodic process takes place,and an active one, where anodic dissolution occurs.

The surface fraction interested is always very low, compared to the totalexposed area.

In pitting corrosion, the anodic area is the bottom of the pit, while in crevicecorrosion it is the shielded metal surface within the crevice.

5.8.1 Susceptible materials

The susceptible materials are those ones that normally operate in passiveconditions; in particular:− stainless steels;− nickel alloys;− copper alloys;− titanium alloys (crevice corrosion).

To express comparatively the pitting resistance of nickel alloys and of stainless

steels, in particular the austenitic and austenitic-ferritic types, specific indexeshave been proposed, based on alloy composition.

The index named P.R.E. (Pitting Resistance Equivalent) is calculated accordingto the chemical composition, and in particular to the content of Cr, Mo and N,as:

P.R.E. = Cr% + 3.3 Mo% + 16N%

Another formula has also been proposed which takes into account of the presence of tungsten in the alloy:

P.R.E. = Cr% + 3.3 (Mo% + 0.5W%) + 16N%

For crevice corrosion, the following index, named “Critical Crevice Index”,C.C.I., has been proposed:

C.C.I. = Cr% + 4.1Mo% +27N%

The pitting and crevice indexes are often utilised as absolute values, but themost appropriate use is as ranking parameters of different materials.

Another evaluation parameter is the critical pitting temperature (C.P.T.)experimentally determined by immersion tests in FeCl 3 (see ASTM G48-76) or

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by electrochemical methods. A good relationship between C.P.T. and P.R.E.

has been found for austenitic and austenitic-ferritic stainless steels.

In the same way, critical crevice temperature (C.C.T.) is determined for crevicecorrosion.

5.8.2 Initiation conditions

Initiation of pitting and crevice corrosion occurs in presence of chloride ions insolution. 200 ppm is the threshold for chloride ions concentration to avoid risksof pitting or crevice initiation of austenitic stainless steels (types AISI 304 and316).

Availability of a cathodic process, i.e. oxygen reduction; hydrogen evolution;elemental sulphur reduction, is needed for propagation to occur.

Hydrodynamic conditions have a great influence on pitting initiation: AISI 316stainless steel, for instance, is resistant to pitting corrosion in sea water

provided that flow rate is above 1.5 m/s, while in stagnating conditions pittingcorrosion occurs.

Temperature has a strong influence too: tendency to pitting and creviceincreases as temperature increases.

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− alloying elements: the nickel content (above 10%) has a beneficial effect;

other beneficial elements are: silicon (the effect is quite evident above 2%)and carbon (above 0.10%); the harmful elements are: phosphorus andnitrogen, which that have a synergetic negative effect; their content shall belimited: P < 0.005% and N < 0.02%;

− welds are preferential sites for SCC initiation because of residual stressconditions and because of their own criticality.

Ferritic and martensitic stainless steels. Stainless steels with ferritic or martensitic microstructure are less susceptible to stress corrosion, although notimmune, because of the low nickel content (Ni < 1%). The low nickel content,in fact, leads to a lower stability of the passive film and promotes uniformcorrosion.

Austenitic-ferritic (duplex) stainless steels . Biphasic austenite-ferrite stainlesssteels offer higher resistance to SCC, compared to ferritic and austenitic types.The optimum resistance conditions are obtained when the two phases are

present in balanced quantities an for the highest nickel contents.

Nickel alloys . Nickel alloys are quite resistant to chloride stress corrosion;alloys with nickel contents above 45% are practically immune.

5.9.2 Polythionic Acids Stress Corrosion Cracking

In correspondence to the periodical shut down of the plants, because of entrance of air and humidity, polythionic acids (H 2SxO 6 with x = 3, 4 or 5) canform by oxidation of iron sulphide:

8FeS + 11O 2 + 2H 2O = 4Fe 2O3 + 2H 2S4O6

Polythionic acids stress corrosion has been found mostly in refinery plants, and particularly in desulphuration units. Austenitic stainless steels, especially if sensitised, are quite susceptible. Failure occurs by crack formation, mostlyintergranular; transgranular cracks may be present, caused by chlorides.

Austenitic-ferritic stainless steels are more resistant than austenitic types; nickelalloys (800 and 600 series) do not seem to be prone to the phenomenon.

Prevention is based on operation control in correspondence to the plant shutdowns, for instance foreseeing nitrogen conditioning of the equipment to

prevent sulphide oxidation.

Recommended materials are stabilised stainless steels (AISI 321 and 347) andweld stabilisation heat treatments (900 oC for at least 20 minutes).

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5.10 Sulphide Stress Cracking (SSC)

Sulphide Stress Cracking (SSC) occurs on susceptible materials when specificenvironmental conditions are met, characterised by presence of H 2S andmechanical stresses, applied or residual.

In oil and gas production, sour service are defined those conditions that give place to SSC on susceptible materials, in particular carbon or low alloy steels.

In sour service conditions SSC resistant materials shall be selected.

5.10.1 Sour service conditions according to NACE

With reference to the NACE MR0175 Standard, sour conditions are defined asfollows:

gas systems (see also fig. 1)− P > 5 bar (0.5 MPa) and− pH 2S > 0.0035 bar (0.005 MPa)

multiphase systems (see also fig. 2)− P > 20 bar (2 MPa) and pH 2S > 0.0035 bar (0.00035 MPa)− 5 < P < 20 bar (0.5 0.15

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1

10

100

1000

0.0001 0.001 0.01 0.1 1 10

H2S molar fraction (yH 2 S) in gas fase (%)

T o

t a l P r e s s u r e

( b a r

) Sour Service

Fig. 1. - Sour service conditions for gas systems according to NACE.

1

10

100

1000

0.0001 0.001 0.01 0.1 1 10 100

H2S molar fraction (yH 2 S) in gas fase (%)

T o

t a l p r e s s u r e

( b a r

)Sour Service

Fig. 2. - Sour service conditions for multiphase systems according to NACE.

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5.10.2 Sour service conditions according to EFC

Definition of sour service conditions according to EFC takes into account alsothe in-situ pH of the water phase; in-situ pH values can be calculated usingalgorithms, nomograms or software programs, based on chemical analysis of the aqueous solution.

According to EFC, the following fields are defined (see also fig. 3):

sour conditions− pH ≤ 3.5− pH 2S < 0.01 ÷1 bar (0.001 ÷0.1 MPa) and pH ≤ 5.5 + log pH 2S (bar)− pH 2S > 1 bar (0.1 MPa) and pH ≤ 5.5

sour / non-sour transition zone pH 2S = 0.001 ÷0.01 bar (0.0001 ÷0.001 MPa) and 3.5 < pH ≤ 5.5 + log pH 2S(bar)

pH 2S > 1 bar (0.1 MPa) and pH = 5.5 ÷ 6.5

Conditions outside these ones are defined non-sour and also susceptiblematerials can be used.

In sour service conditions, materials resistant to SSC shall be used.Sour / non sour transition conditions are considered as sour.

2.5

3.5

4.5

5.5

6.5

7.5

0.0001 0.001 0.01 0.1 1 10

Hydrogen Sulphide Partial Pressure (pH2S - bar)

S o

l u t i o n p

H

"Non Sour Service" Transition Region

Sour Service

Fig. 3. - Sour service conditions according to EFC

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5.11 Stepwise Cracking

The term Stepwise Cracking refers to metal damages which occur as surface blistering or as formation of internal stepwise microcracks, even in absence of mechanical solicitations. Other terms are often used, as “Stress OrientedHydrogen Induced Cracking”, “Blistering”, “Hydrogen Induced Cracking” todescribe the same phenomenon.

Formation of microcracks or blisters is caused by atomic hydrogen produced onthe corroding metal surface which, in presence of H 2S, diffuses into the metallattice. The atomic hydrogen eventually gathers in correspondence of inclusionsor segregation bands of the microstructure and recombines to molecular

hydrogen, producing a very high internal pressures and the mentioned metaldamages.

Materials susceptible to Stepwise Cracking are carbon and low alloy steels produced by lamination and containing inclusions, and in particular C-Mnsteels with manganese sulphide inclusions, MnS type II.

5.11.1 Limits for initiation

The following limits are applicable for stepwise cracking initiation:− pH 2S > 0.1 bar (0.01 MPa);− T < 80°C;− pH in-situ < 6. In case of fluids containing both CO 2 and H 2S, the following limits applies (seealso fig. 4):− pH 2S > 0.1 bar (0.01 MPa) if pCO 2 < 0.5 bar;− pH 2S > 0.1107-0.0214 ⋅ pCO2 (bar) if 0.5 < pCO 2 < 5 bar;− pH 2S > 0.0035 bar (0.00035 MPa) if pCO 2 > 5 bar.

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0.0001

0.001

0.01

0.1

1

0.01 0.1 1 10

CO2 partial pressure (bar)

H 2 S p a r

t i a

l p r e s s u r e

( b a r

)

"Stepwise Cracking"(T < 80°C - pH < 6)

Fig. 4 - Limits for initiation of Stepwise Cracking.

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5.12 Erosion corrosion

It is a corrosion form where there is the concurrence of electrochemicalcorrosion with mechanical removal of the corrosion products caused by thehigh flow rate.

It occurs on all the metallic materials. Whenever the aggressiveness conditionsare particularly severe it becomes necessary to make use of hard coatings withhigh corrosion resistance, such as stellites or ceramics.

In absence of solid particles, corrosion-erosion initiates if the fluid velocity isabove a critical value. In API RP-14E the following formula is given for the

calculation of critical rate v c:

vC

cm

=ρ

where:− vc = erosion critical velocity− C = erosion constant− ρm = fluid density at operating conditions

The erosion constant can take different values depending on the material(carbon steel or CRA), the type of service (continuous or intermittent) and theinhibitor injection.

In the S.I. system, the units for the C constant are (kg/ms 2)1/2 , while in theAmerican system units are (lb/fts 2)1/2 ; the conversion factor from the Americansystem to S.I. is 1.22.

The following values for the C constant, expressed here in the S.I. units, arerecommended:

− C = 122 carbon steel, corrosive fluids, continuous service;− C = 152 carbon steel, corrosive fluids, intermittent service;− C = 183-244 carbon steel, non corrosive fluids, continuous service;− C = 305 carbon steel, non corrosive fluids, intermittent service;− C = 183-244 carbon steel, corrosive fluids, continuous service,

continuous corrosion inhibitors injection;− C = 305 carbon steel, corrosive fluids, intermittent service,

continuous corrosion inhibitors injection;− C = 183-244 CRA alloys, continuous service;− C = 305 CRA alloys, intermittent service.

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5.13 Sand erosion

The API formula for predicting corrosion-erosion rate shown in previous paragraph is not applicable when sand or solid particle are present in the fluid.

Sand erosion rate is related to the following parameters:− content of solid particles in the fluid;− flow rate;− fluid density;− fluid viscosity;− density of solid particles;

−dimension of solid particles;

− morphology of solid particles;− dimensions and geometry of the metallic component.

The calculation of sand erosion rate can be estimated by the use of algorithms based on the influence parameters previously seen.

According to a model proposed by “Erosion Corrosion Research Centre” of theTulsa University, the ratio between mass of metal lost by erosion and the massof the solid particles produced, defined as “base erosion rate”, ER b (kg m/kg p), isgiven by the following formula:

ER b = 1.73 ⋅ 10 -7 ⋅ VL 1.623

where:VL = impingement rate of particles; it depends on system geometry, on fluid

and particles density, and on flow rate; it is expressed as m/s.kg m = eroded mass of metal, in kg.kg p = mass of sand produced, in kg.

The calculated value for ER b shall be further corrected by multiplying factors totake into account of the other parameters reported above.

To carry out the calculation procedure a software program, E/CRC SoftwareVersion 1.0, prepared by Erosion/Corrosion Research Centre, is available.

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