08053E02 Internal Corrosion

2 General revision CESCOR STIN CORM 15.06.95REV. DESCRIPTION COMP. VERIF. APPR. DATE

Il presente documento RISERVATO ed di propriet dell'AGIP. Esso non sar mostrato a Terzi n sar utilizzato per scopi diversi da quelli per i quali 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

MATERIALS AND CORROSION CONTROL METHODSIN GATHERING AND TREATMENT OIL AND GAS PLANTS

08053.MAT.COR.PRG

Rev.2

June 1995

08053.MAT.COR.PRGRev.2 June 1995Sheet 2


FOREWORD

Rev. 2 No. Sheets 44June 1995

The type of document has been changed from GENERAL SPECIFICATIONto DESIGN CRITERIA.

The Normative references chapter has been revised and updated.

The content of the document has been revised in accordance with the followinggoals:- define the corrosivity class and the type of the fluids in the main components

in gathering and treatment oil and gas plants;- characterize applicable materials and corrosion control methods, specifying

the minimal technical requirements that shall be observed.

A detailed list of definition has been introduced.



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 organizations1.2.4 Internal normative references

1.3 Definitions

2 GATHERING AND TREATMENT PLANTS

2.1 Gathering and treatment plants2.1.1 Oil and gas gathering plants2.1.2 Oil treatment plant2.1.3 Gas treatment plants

2.2 Corrosivity classes2.2.1 Liquid hydrocarbons and multiphase systems (I.L. fluid types)2.2.2 Gas and gas condensates hydrocarbons (I.G. fluid types)

2.3 Metallic materials2.4 Corrosion control methods

3 OIL AND GAS GATHERING PLANTS

3.1 General3.2 Oil and multiphase flowline3.2.1 I.L.N. Fluid class - Non containing CO 2 and H2S3.2.2 I.L.C. Fluid class - Containing CO 23.2.3 I.L.S. Fluid class - Containing H 2S3.2.4 I.L.CS. Fluid class - Containing CO 2 and H2S

3.3 Gas flowline3.3.1 I.G.N. Fluid class - Non containing CO 2 and H2S3.3.2 I.G.C. Fluid class - Containing CO 23.3.3 I.G.S. Fluid class - Containing H 2S3.3.4 I.G.CS. Fluid class - Containing CO 2 and H2S

3.4 Separated water flowline3.5 Wellhead separators3.6 Glycol lines3.7 Manifold3.8 Bolts



4 OIL TREATMENT PLANTS

4.1 General4.2 Multiphase Lines from the manifold to separators4.3 Heat exchanger4.3.1 Material selection for pipes and tube sheets4.3.2 Material selection for the shell

4.4 Air cooler4.5 Separators (I, II, III phase)4.5.1 I.L.N. Fluid class - Non containing CO 2 and H2S4.5.2 I.L.C. Fluid class - Containing CO 24.5.3 I.L.S. Fluid class - Containing H 2S4.5.4 I.L.CS. Fluid class - Containing CO 2 and H2S

4.6 Oil lines between separators4.7 Gathering gas lines4.8 Separated water lines4.8.1 I.L.N. Fluid class - Non containing CO 2 and H2S4.8.2 I.L.C. Fluid class - Containing CO 24.8.3 I.L.S. Fluid class - Containing H 2S4.8.4 I.L.CS. Fluid class - Containing CO 2 and H2S

4.9 Stabilizer4.10 Oil flowlines4.11 Oil line

5 GAS TREATMENT PLANTS

5.1 General5.2 Water saturated gas lines5.3 Separation plant5.3.1 I.G.N. Fluid class - Non containing CO 2 and H2S5.3.2 I.G.C. Fluid class - Containing CO 25.3.3 I.G.S. Fluid class - Containing H 2S5.3.4 I.G.CS. Fluid class - Containing CO 2 and H2S

5.4 Separated water lines5.5 Condensates lines5.6 Wet gas preheaters5.7 Dehydration columns5.8 Dry gas lines5.9 Depressurization lines and collectors5.9.1 I.G.N. Fluid class - Non containing CO 2 and H2S5.9.2 I.G.C. Fluid class - Containing CO 25.9.3 I.G.S. Fluid class - Containing H 2S5.9.4 I.G.CS. Fluid class - Containing CO 2 and H2S



6 VALVES

6.1 Designations6.2 Valve components6.3 Recommended materials6.3.1 I.L.N. Fluid class - Fluid class - Non containing CO 2 and H2S6.3.2 I.L.C. Fluid class - Containing CO 26.3.3 I.L.S. Fluid class - Containing H 2S6.3.4 I.L.CS. Fluid class - Containing CO 2 and H2S

7 PUMPS

7.1 Designations7.2 Pump components



1 GENERAL

1.1 Scope

This document defines the materials and the corrosion control methods for bothonshore and offshore oil and gas production, gathering and treatment plants,with regard to the corrosivity characteristics of the main process fluids based, inparticular, on CO2 and H2S content and on the operating conditions.

Oil and gas production plants are here intended as the plants between wellhead(not included) and the delivery lines. The following plants are not considered inthe present specification:- glycol regenerating plants;- gas sweetening plants;- compressors.

The procedures concerning corrosion control in the following conditions arenot included in the scope of this specification:- conditioning before start-up;- hydraulic tests;- plant shutdowns.

Corrosion and corrosion control methods relevant external corrosion (includingpaints, coatings, cathodic protection) are out of the scope of the presentspecification.

Criteria and specified requirements are intended for a design life equal to 20years. In case of different design life, criteria and requirements may not resultadequate.



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 H2S Containing Oil andGasfield Service.

NACE MR0175 Sulphide Stress Cracking Metallic Material forOil Field Equipment.

NACE RP0575 Design, Installation, Operation, and Maintenanceof Internal Cathodic Protection Systems in OilTreating Vessels.

NACE RP0181 Liquid Applied Internal Protection Lining andCoating for Oil Field Production Equipment.

API 5L Specification for Line Pipe.

API 5LC Specification for CRA Line Pipe.

API RP14E Design and Installation of Offshore ProductionPlatform Piping System.

1.2.4 Internal normative references

02555.VAR.COR.PRG. Design criteria. Internal corrosion. Corrosionparameters and classification of the fluids.

20197.VAR.COR.SDS. Company specification. Internal corrosionmonitoring. Typical corrosion control.

15801.PIP.MEC.STD. General specification. Intercepting, regulating andretaining hand-activated valves .

01205.MAC.MEC.SPC. General specification. Centrifugal pumps forgeneral services.



01582.MAC.MEC.SPC. General specification. Centrifugal process pumps(API 610).

01581.MAC.MEC.SPC. General specification. Vertical submersiblecentrifugal pumps.

03590.MAC.MEC.SPC. General specification. Alternate pumps (API674)

03690.MAC.MEC.SPC. General specification. Rotary pumps (API 676).



1.3 Definitions

Austenitic stainless steelStainless steel whose microstructure at room temperature consist predominantlyof austenite (NACE MR0175).

Austenitic-ferritic (duplex) stainless steelStainless steel whose microstructure, at room temperature, consists primarily ofa mixture of austenite and ferrite (NACE MR0175).

Carbon steelAn alloy of carbon and iron containing up to 2% carbon and up to 1.65%manganese and residual quantities of other elements, except those intentionallyadded in specific quantities for deoxidation (usually silicon and/or aluminium).The carbon steels used in oil industry usually contain less than 0.8% carbon(NACE MR0175).

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

Cobalt alloyMetallic alloy with prevailing high cobalt content.

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 resistanceProperty of the metal to resist corrosion in a certain environment (ISO 8044).

Corrosion resistant alloys - CRAWith the term Corrosion Resistant Alloy - CRA the following materials areintended: stainless steels; nickel alloys; titanium alloys; cobalt alloys.

Corrosive agentSubstance that reacts with a specific metal when they are in contact (ISO 8044).

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

CorrosivityProperty of an environment to cause corrosion in a certain corrosion system(ISO 8044).



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 following corrosivityclasses are defined:- N. non containing CO2 or H2S- C. containing CO2- S. containing H2S- CS. containing CO2 and H2S

Hydrogen Induced Cracking - HICStepwise cracking phenomenon, that happens typically in carbon steelsmanufactured by hot rolling procedure; cracks on the same layer tend toconjunct with cracks on nearby layers forming steps through the metallic wallthat reduce mechanical resistance (ISO 8044).

Low alloy steelSteel with a total alloying element content of less than about 5%, but more thanspecified for carbon steel (NACE MR0175).

Martensitic stainless steelStainless steel in which a microstructure of martensite can be attained byquenching at a cooling rate fast enough to avoid the formation of othermicrostructure (NACE MR0175).

Nickel alloyMetallic alloy with austenitic microstructure, with the characteristic presence ofa high nickel content above the content of every other element.

Predicted corrosion rateIt is the corrosion rate, usually expressed quantitatively (in mm/y) and/orqualitatively, 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.

Residual corrosion rateCorrosion rate after injection of corrosion inhibitors .

Sour conditionsConditions, usually with H2S presence, that cause Sulphide Stress Crackingoccurrence in susceptible materials. The definition is according to NACEMR0175 or EFC O&G 93-1.

Stainless steel



Steel containing enough chromium (usually above 11%) to give steel asufficient corrosion resistance. Other elements may be added to secure specialproperties.



Stepwise Cracking - SWCFormation of cracks, even in absence of mechanical solicitations, as aconsequence of diffusion of atomic hydrogen, produced in the cathodic reactionin H2S containing environments, and the successive recombination to molecularhydrogen inside the metallic lattice near microcracks, inclusions or defects.Stepwise Cracking includes: Stress Oriented Hydrogen Induced Cracking,Blistering, Hydrogen Induced Cracking.

Stress Corrosion Cracking - SCCProcess resulting from the combined action of corrosion and a state of tractionmechanical solicitation caused by applied or residual tension; it causessuperficial cracks that diffuse in a direction perpendicular to the tractionsolicitation.

Sulphide Stress Cracking - SSCFormation of cracks caused by stress corrosion, with a significant contributionof H2S as a corroding agent.

Titanium alloyMetallic alloy with prevailing high titanium content.

Type of fluidThe following types of fluid are considered: liquid hydrocarbons (I.L.); gas andgas with condensates hydrocarbons (I.G.); glycol (G.); sea water (A.M.); freshwater (A.D.); brackish water (A.S.); formation water (A.F.).

WettabilityTendency of a fluid to disperse or to adhere to a solid surface in presence ofanother insoluble liquid. Wettability is a measure of the preference of corrosionproducts or metallic surfaces for water or oil.

Water wettingWetting of exposed surfaces by the water phase; this happens when water ispresent in liquid state and water is even temporarily in contact with the metallicsurface.



2 GATHERING AND TREATMENT PLANTS

2.1 Gathering and treatment plants

In the present specification oil and gas gathering and treatment plants aredivided into:- oil and gas gathering plants, from wellhead (not included) to manifold;- oil treatment plants, from manifold to stabilized oil tank and dehydrated gas

transporting lines;- gas treatment plants, from manifold to dehydrated gas transporting lines.

2.1.1 Oil and gas gathering plants

These plants include the following main components:- oil and multiphase flowlines;- gas flowlines;- separated formation water flowlines;- glycol lines;- wellhead separator;- manifold;- bolts.

Typical plant drawings for oil and gas gathering plants are reported in figures 1and 2 respectively.



separator

gas

water

oil well

wellhead

manifold area

oil

to the treatmentplant

wellhead area

choke valve

well head

Figure 1 - Typical oil gathering plant.

gas

wellhead

condensates

glycol line

water

gas well

separatorwellhead

manifold area

to the treatmentplant

wellhead area

Figure 2 - Typical gas gathering plant.



2.1.2 Oil treatment plant

These plants include the following main components:- oil line from manifold to separators;- heat exchanger;- air cooler;- separators (I, II, III phase);- oil lines between separators;- separated gas gathering line;- separated water line;- desalination unit;- gathering and distribution lines of separated water;- oil line;- pumps;- valves.

Typical plant drawing for oil treatment plants is reported in figure 3.

gas

oil

water

degassing column

S=separators

S1

S2

S3

stabilized oil,steam or water

Figure 3 - Typical oil treatment plant.



2.1.3 Gas treatment plants

These plants include the following main components:- wet gas lines;- separation equipment;- separated condensate lines;- separated water lines;- wet gas pre-heaters;- dehydration tower;- dry gas lines;- depressurization lines and collectors;- valves;- pumps.

Typical plant drawing for gas treatment plants is reported in figure 4.

dehidrationcolumn

wet gaspre-heater

degassing column

water trapglycol

dry gas

glycol

Figure 4 - Typical gas and gas with condensates treatment plant.



2.2 Corrosivity classes

2.2.1 Liquid hydrocarbons and multiphase systems (I.L. fluid types)

The following corrosivity classes are considered:

I.L.N. non containing CO2 and H2SpCO2 < 0.001 bar (0.0001 MPa) and pH 2S < 0.0035 bar (0.00035 MPa)

I.L.C. containing CO2pCO2 > 0.001 bar and pH2S < 0.0035 bar

I.L.S. containing H2SpCO2 < 0.001 bar and pH2S > 0.0035 bar

I.L.CS. containing CO2 and H2SpCO2 > 0.001 bar and pH2S > 0.0035 bar

2.2.2 Gas and gas condensates hydrocarbons (I.G. fluid types)

I.G.N. non containing CO2 and H2SpCO2 < 0.001 bar (0.0001 MPa) and pH 2S < 0.0035 bar (0.00035 MPa)

I.G.C. containing CO2pCO2 > 0.001 bar and pH2S < 0.0035 bar

I.G.S. containing H2SpCO2 < 0.001 bar and pH2S > 0.0035 bar

I.G.CS. containing CO2 and H2SpCO2 > 0.001 bar and pH2S > 0.0035 bar



2.3 Metallic materials

Metallic materials used in oil production plants and mentioned in this documentare the following:- carbon or low alloy steels;- stainless steels;

- martensitic;- austenitic;- austenitic-ferritic (duplex);

- nickel alloys;- nickel iron chromium molybdenum;- nickel chromium molybdenum;- nickel copper;

- cobalt alloys;- cobalt nickel chromium molybdenum;- cobalt nickel chromium tungsten;

- titanium alloys.

2.4 Corrosion control methods

The applicable internal corrosion control methods are:- corrosion allowance;- continuous injection of corrosion inhibitors;- corrosion resistant materials - solid;- corrosion resistant materials - cladded;- flexible (metallic reinforced) plastic pipes;- fiberglass pipes;- coatings;- paintings;- cathodic protection;- heat treatments.



3 OIL AND GAS GATHERING PLANTS

3.1 General

Gathering plant components operate in contact with non treated fluids, comingdirectly from wellhead, showing large composition variability.

Options with carbon or low alloy steels, for pipelines and equipment, require acorrosion allowance. In the present specification the minimum value isindicated; however in every situation corrosion allowance shall withstand thepredicted corrosion rate and the design life.

When applicable, stainless steels or nickel alloys options are preferable when ahigh reliability is required, such as in submarine applications or in plantslocated in high risk areas.

For pipelines (oil and multiphase flowlines, gas flowlines) stainless steels ornickel alloys can be applied as either solid or cladded pipes.

In offshore gathering systems, flexible pipes made of plastic reinforced materialcan be used depending on installing aspects and on fluid corrosivity.

For fluids containing sand, corrosion-erosion has to be verified in accordancewith API RP14E standard.



3.2 Oil and multiphase flowline

3.2.1 I.L.N. Fluid class - Non containing CO 2 and H2S

The recommended material is carbon and low alloy steel (seamless pipesaccording to API 5L).

In presence of prevalent water wetting conditions, 1 mm corrosion allowancecan be designed. No corrosion prevention method is required in absence ofaggressive species other than CO 2 and H2S, such as oxygen and elementalsulphur; otherwise specific corrosion control methods shall be applied.

In presence of H2S traces (pH2S < 0.0035 bar = 0.00035 MPa), SSC resistantmaterials are recommended.

3.2.2 I.L.C. Fluid class - Containing CO 2

The materials to be used are:- carbon and low alloy steel (seamless pipes according to API 5L);- austeno-ferritic 22% Cr stainless steel (seamless pipes according to API

5LC, LC65-2205 grade).

3.2.2.1 Carbon and low alloy steel

When CO2 corrosion rate is lower than 0.1 mm/y, a minimum corrosionallowance of 1 mm shall be foreseen, and however shall be in accordance withthe projected corrosion rate and to the design life.

For CO2 corrosion rate between 0.1 and 0.5 mm/y, the design shall includeaccess fittings for continuous injection of corrosion inhibitors in the flowline atthe wellhead area. Inhibitor type and injection rate shall be based on themonitoring data, with attention to eventual inhibitor injection in well. Aminimum corrosion allowance of 2 mm is required.

When the estimated corrosion rate is above 0.5 mm/y a minimum corrosionallowance of 2 mm and the continuous injection of corrosion inhibitor arerequired.

3.2.2.2 Stainless steels

The use of austenitic-ferritic stainless steel, 22% Cr type, has to be consideredwhen the expected corrosion rate is above 1 mm/y and CO 2 partial pressure,pCO2 , is above 5 bar (0.5 MPa).



3.2.3 I.L.S. Fluid class - Containing H 2S

SSC resistant carbon and low alloy steels are requested (seamless pipesaccording to API 5L).

A minimum corrosion allowance of 1 mm is required.

For H2S partial pressures above 0.1 bar (0.01 MPa), the design shall includeaccess fittings for continuous injection of corrosion inhibitors in the flowline atthe wellhead area. The use of a corrosion inhibitor and the injection rate shallbe based on the monitoring data, with attention to eventual inhibitor injection inwell.

HIC resistant steels is recommended. For H 2S partial pressures above 0.1 bar(0.01 MPa) HIC resistant materials are always required.

Heat treatment (stress relieving) of circumferential welding after construction isrequired.

While carbon or low alloy steels are the recommended materials in I.L.S.environments, the use of stainless steels can be considered in extreme cases,when H2S content is very high (H2S molar fraction above 1%).

3.2.4 I.L.CS. Fluid class - Containing CO 2 and H2S

The materials to be used are:- carbon or low alloy steel (seamless pipes in accordance with API 5L)- austeno-ferritic stainless steel (seamless pipes in accordance with API 5LC,

LC65-2205 and LC65-2506 Grades) or superduplex- nickel alloys (seamless pipes in accordance with API 5 LC, LC30-2242

Grade or equivalent).

3.2.4.1 Carbon and low alloy steels

SSC and HIC resistant steels are always required.


For CO2 corrosion rates above 0.1 mm/y, the design shall include access fittingsfor continuous injection of corrosion inhibitors in the flowline at the wellheadarea. The use of a corrosion inhibitor and the injection rate shall be related tothe monitoring data, with attention to eventual inhibitor injection in well.

When corrosion rate is above 0.5 mm/y, continuous injection of corrosioninhibitors is always required.

Heat treatment (stress relieving) of circumferential welding after installation isrequired.



3.2.4.2 Stainless steels and nickel alloys

The use of stainless steel has to be considered when CO 2 corrosion rate is above1 mm/y and CO2 partial pressure is above 5 bar (0.5 MPa).

The selection of stainless steel type is based primarily on H 2S partial pressureand on temperature, beside of chloride ions concentration in water, according tothe Internal Normative document 02555.VAR.COR.PRG.

When pH2S is above 1 bar (0.1 MPa), nickel alloys shall be used.



3.3 Gas flowline

The prevalent phase is the gas phase, with the presence of a water phase, due towater condensation or dragged formation water. Condensates, glycol ormethanol (intentionally added to prevent hydrate formation) can be present.

In general, gas flowlines operate at temperatures below the dew pointtemperature (gas lines upstream the dehydration column). The criteria indicatedin this paragraph can also be applied to wet gas lines in oil treatment plants.

3.3.1 I.G.N. Fluid class - Non containing CO 2 and H2S

The recommended material is carbon or low alloy steel (seamless pipesaccording to API 5L).

Requirements for oil flowlines (paragraph 3.2.1, I.L.N. environments) areapplicable.

3.3.2 I.G.C. Fluid class - Containing CO 2

The materials to be used are:- carbon or low alloy steels (seamless pipes according to API 5L);- austenitic-ferritic 22% Cr stainless steels (seamless pipes according to API

5LC, LC65-2205 Grade).


When CO2 corrosion rate is below 0,1 mm/y, a minimum corrosion allowanceof 1 mm is required, properly dimensioned according to projected corrosionrate and design life.

For corrosion rates between 0.1 and 0.5 mm/y, the design shall include accessfittings for continuous injection of corrosion inhibitors in the flowline at thewellhead area. The use of a corrosion inhibitor and the injection rate shall bebased on the monitoring data, taking into account the downhole inhibitorinjection, if any.A minimum 2 mm corrosion allowance is required.

Continuous injection of corrosion inhibitors and a minimum corrosionallowance of 2 mm are always required when corrosion rate is above 0.5 mm/y.

When glycol injection is performed at the wellhead, it can be used as a carrierof corrosion inhibition.

The following values are assumed for the inhibitor efficiency, when not knownor not defined from the corrosion monitoring system:- 90% if gas velocity < 10 m/s and T < 100C;- 80% if gas velocity > 10 m/s and T < 100C.



For temperatures above 100C, inhibitor efficiency values guaranteed by thesuppliers have to be considered; in any case not higher than the abovementioned values.

In areas with high turbulence, such as elbows, fitting, etc. the opportunity ofusing stainless steel shall be considered case by case. In these situations, designshould specify the periodic thickness check (i.e. through ultrasounds).

In presence of H2S traces (pH2S < 0.0035 bar = 0.00035 MPa) the use of SSCresistant steels is recommended.


The use of austenitic-ferritic 22% Cr stainless steels has to be considered whenexpected corrosion rate is above 1 mm/y and CO 2 partial pressure is above 5bar (0.5 MPa).

3.3.3 I.G.S. Fluid class - Containing H 2S

The recommended material is carbon or low alloy steel (seamless pipesaccording to API 5L).

Requirements for oil flowlines (paragraph 3.2.3, I.L.S. environments) areapplicable.

3.3.4 I.G.CS. Fluid class - Containing CO 2 and H2S

The materials to be used are:- carbon or low alloy steels (seamless pipes according to API 5L);- austenitic-ferritic 22 or 25% Cr stainless steels (seamless pipes according to

API 5LC, LC65-2205 and LC65-2506 grade);- nickel alloys (seamless pipes according to API 5 LC, LC30-2242 grade or

equivalent).

Requirements for oil flowlines (paragraph 3.2.4, I.L.CS. environments) areapplicable.

3.4 Separated water flowline

This flowline transfers the separated water from the wellhead separator to theoil treatment plant.

Material requirements are the same specified for water flowlines of treatmentplants (see chapter 4.8).



3.5 Wellhead separators

Material requirements are the same specified for separators in oil and gastreatment plants (see chapters 4.5 and 5.3), taking into account the actualtemperature and pressure conditions.

3.6 Glycol lines

These flowlines are intended as the possible glycol transferring line from the oiltreatment plant to wellhead separator, for glycol injection in gas flowline.

The recommended material is carbon or low alloy steel.


3.7 Manifold

Requirements for oil flowlines (see chapter 3.2) are applicable.

Particular attention shall be paid to possible corrosion-erosion occurrence,caused by local turbulence.

In case of aggressive fluids the design shall include methods for periodiccontrol by ultrasounds.

When injection of corrosion inhibitors in the flowline is carried out at thewellhead, further injection access fittings upstream the manifold arerecommended. (see Internal Normative document 20197.VAR.COR.SDS.).

3.8 Bolts

Flange bolts do not operate in contact with production fluids and therefore therequirements specified for pipelines and vessels are not applicable. This isespecially for I.L(G).N. and I.L(G).C. corrosivity classes.

However, in I.L.(G.)S. or I.L.(G.)CS. fluids, SSC corrosion resistancerequirements shall be extended to flange bolts; this is because of possible leaksthrough the gasket, leading to temporarily sour conditions. For bolts in carbonor low alloy steel, as specified in NACE Standard MR0175, nuts and boltsClass I and II, with controlled hardness, not above 22 HRC, can be used; forother materials, relevant requirements are specified in NACE MR0175(hardness limits, heat treatments).



4 OIL TREATMENT PLANTS

4.1 General

In oil treatment plants, separation and stabilization of the present phases arecarried out. Corrosivity conditions are generally better defined than in gatheringplants, especially in absence of the wellhead separator.

The most severe corrosion conditions are usually encountered in separators andwet gas lines, from separators to the stabilizer.

Options with carbon or low alloy steels, for pipelines and equipment, require acorrosion allowance. In the present specification the minimum value isindicated; however in every situation corrosion allowance shall be inaccordance with the predicted corrosion rate and the design life.

The use of stainless steels or nickel alloys, when applicable, are preferred insituations where high reliability is required, such as in offshore plants.Moreover, safety requirements in treatment plants are generally more severethan gathering plants.

For pipelines (oil and multiphase flowlines, gas flowlines) stainless steels ornickel alloys can be applied as either solid or cladded pipes.

In offshore gathering systems, flexible pipes made of plastic reinforced materialcan be used depending on installing aspects and on fluid corrosivity.

In pipes for all corrosivity classes, corrosion-erosion has to be verified inaccordance with API RP14E standard and for fluids containing sand abrasionresistance has to be controlled.

4.2 Multiphase Lines from the manifold to separators

The same criteria are required as those ones prescribed for oil and multiphaseflowlines, in chapter 3.2.

When continuous injection of corrosion inhibitors is carried out at the wellhead,further injection access fittings upstream the manifold (or in an equivalentposition) are recommended.



4.3 Heat exchanger

The following combinations of fluids are considered for tube heat exchangers,for oil (thermovector) heating and cooling:- tube side: - process oil- shell side: - process oil,

- steam (saturated or superheated),- fresh water,- sea water (or brines).

In the following paragraphs the materials selection criteria for pipes and shellare specified on the base of the corrosivity of the oil phase and the coolingfluid.

4.3.1 Material selection for pipes and tube sheets

The selection of tubes and tube sheet materials is based on corrosivitycharacteristics of oil and thermovector fluid.

Recommended solutions of materials and pipes sheet are summarized in thefollowing table 4.1.

Table 4.1 - Recommended solutions for tube and tube sheet materialsaccording to thermovector fluid and oil corrosivity classes

Thermovector MATERIALS FOR TUBES AND TUBES SHEETSfluid CORROSIVITY CLASSES (TUBE SIDE FLUID)

(shell side) I.L.N. I.L.C. I.L.S. I.L.CS.stabilized oil steel + c.a. steel + c.a.

AISI 316duplex 22 Cr

steel + c.a.AISI 316duplex 22 Cr

steel + c.a.AISI 316duplex(1)

nickelalloys

steam steel + c.a. steel + c.a.AISI 316duplex 22 Cr

steel + c.a.AISI 316duplex 22 Cr

steel + c.a.AISI 316duplex(1)

nickelalloys

fresh water AISI 316 AISI 316duplex 22 Cr

AISI 316duplex 22 Cr

AISI 316duplex(1)

nickelalloys

sea water nickel alloystitanium

nickel alloystitanium

nickel alloystitanium

nickelalloystitanium



(1) sc is corrosion allowance according to heat transfer requirements; aminimum 1 mm value is usually adopted.

(2)Types 22% Cr, 25% Cr 3 superduplex are applicable



4.3.2 Material selection for the shell

The selection of shield materials is based on cooling fluid characteristics.

The main recommended solutions are the following:

Process Oil- carbon or low alloy steel with at least 3 mm corrosion allowance- in particular cases, oil with a significant (>5%) water content and high

levels of CO2 and H2S, the use of stainless steels, solid or cladded, can beconsidered.

Steam- carbon or low alloy steel with a minimum 3 mm corrosion allowance.

Fresh Water- carbon or low alloy steel with a minimum 3 mm corrosion allowance- austenitic stainless steel (AISI 316) solid or cladded.

Seawater or brines- painted carbon or low alloy steel with a minimum 3 mm corrosion

allowance; cathodic protection system with sacrificial anodes can beaccepted;

- austenitic or austenitic-ferritic stainless steel solid or cladded.

4.4 Air cooler

In air cooler process oil circulates inside the tubes and the cooling fluid is air.

The materials for tubes shall be chosen on the basis of the oil corrosivity,according to the criteria seen in paragraph 4.2.1 for tubes sheet exchangers.

The material for pipes-external surfaces and cooling fins shall be resistant to theatmosphere, especially during shutdown, when condensation is likely to occur.

Galvanized carbon steel and aluminium alloy fins can be used also in marineenvironments, standing long shutdown.

The most economical solution (carbon steel-aluminium alloy fins) isrecommended only for continuous operations in low chloride containingenvironments.

Galvanized steels are not recommended when H 2S in present.

The use of corrosion resistant materials is accepted without any restriction.



4.5 Separators (I, II, III phase)

The materials requirements, when not specified, refer to the shell.

Materials for internal components, such as divisors, bolts, etc. shall complywith the shell material (same material or superior).

When the shell material is carbon steel, stainless steels can be used for internalcomponents, i.e. austenitic types (AISI 316), provided that oxygen is notpresent (to minimize galvanic corrosion).





The materials to be used are:- carbon or low alloy steel;- 22% Cr austenitic-ferritic type stainless steel.



When continuous injection of corrosion inhibitors in carried out at the wellheador at manifold, the use of carbon or low alloy steel is recommended; furtherinjection access fittings upstream the manifold (or in an equivalent position )are recommended. The corrosion inhibitor shall be effective also in the gasphase, to protect the top of the separators and the gaslines. The inhibitor dosageshall be determined on the basis of the available monitoring data.

As an alternative to the use of corrosion inhibitors, or in combination with it, anadequate internal coating can be adopted (see NACE RP0181). The coatingtype shall be in accordance with the maximum operating temperature.

When the water cut is above 10%, a cathodic protection system with zinc (fortemperatures up to 50C) or aluminium anodes is recommended for theprotection of the bottom. Impressed current cathodic protection systems can beused, provided the full compatibility with safety regulations.

4.5.2.2 Stainless Steels

The use of 22% Cr austenitic-ferritic stainless steel, solid or cladded, has to beconsidered when the expected CO 2 corrosion rate is above 1 mm/y and CO 2partial pressure, pCO2 , is above 5 bar (0.5 MPa). Stainless steels are preferred



in offshore plants or in hazardous areas with risks for environment orpopulation.


The recommended material is carbon or low alloy steel, SSC and HIC resistant.


For H2S partial pressure above 0.1 bar (0.01 MPa), the design shall includeinjection access fittings for corrosion inhibitors at the wellhead. Type ofinhibitor and relevant dosage will be based on the corrosion monitoring data.

Stress relieving heat treatment of circumferential welding is required.


The materials to be used are:- carbon or low alloy steels- austenitic-ferritic stainless steels- nickel alloys.


The recommended material is carbon or low alloy steel, SSC and HIC resistant.


When continuous injection of corrosion inhibitors in carried out at the wellheador at manifold, the use of carbon or low alloy steel is recommended; furtherinjection access fittings upstream the manifold (or in an equivalent position )are recommended. The corrosion inhibitor shall be effective also in the gasphase, to protect the top of the separators and the gaslines. The inhibitor dosageshall be determined on the basis of the available monitoring data.


4.5.4.2 Stainless steels and Ni base alloys

The use of solid or clad stainless steel and nickel alloys (such as Nickel-Iron-Chromium-Molybdenum alloys such as Inconel 825) has to be considered whenthe expected CO2 corrosion rate is above 1 mm/y and CO 2 partial pressure,pCO2, is above 5 bar (0.5 MPa).

The stainless steel type depends on H 2S partial pressure, temperature andchlorides concentration in the water phase.



4.6 Oil lines between separators

Materials and requirements for oil and multiphase flowlines (see chapter 3.2)are applicable.

4.7 Gathering gas lines

They represent one of the most critical components of the plant. Water wettingconditions (gas saturated with water) occur, without any filming protectiveeffect due to the oil phase; besides, condensed water phase is not buffered byany chemical species, which are practically absent.

When foreseen, injection of corrosion inhibitors has to be carried out upstreamthe separator (for instance, at the manifold), to protect the gas lines and the topof the separator. Accordingly, the inhibitor shall have a volatile component,active in the gas phase.

Requirements for gas flowlines (see chapter 3.3) are applicable.

4.8 Separated water lines

They are characterized by persistent water wetting conditions. Compared to thegas lines from separators, the corrosivity conditions can be less severe if thereservoir water contains buffering chemical species.

When foreseen, injection of corrosion inhibitors has to be carried out upstreamthe separator (for instance, at the manifold), to protect also the bottom of theseparator. Accordingly, the inhibitor shall have an active component in thewater phase.


The recommended material is carbon or low alloy steel. A minimum corrosionallowance of 3 mm is recommended.


The materials to be used are:- carbon or light-alloy steel (seamless pipes in accordance with API 5L)- austenitic-ferritic stainless steel (seamless pipes in accordance with API

5LC, LC65-2205 grades)


It is the recommended option.



When CO2 corrosion rate is below 0.2 mm/y, the only requirement is aminimum corrosion allowance of 3 mm..

For higher CO2 corrosion rates, inhibitor injection access fittings downstreamthe separators (or in equivalent location) shall be foreseen. Inhibitor modalitiesand dosage in addiction to the one injected upstream shall be evaluated on thebase of the monitoring data. However continuous injection is preferred.

4.8.2.2 Stainless steel

The use of stainless steel is limited to offshore plants.

The use of 22% Cr austenitic-ferritic stainless steel has to be considered whenCO2 corrosion rate is above 1 mm/y and CO 2 partial pressure, pCO2, is above 5bar (0.5 MPa).

When operating pressure in separated water lines is below 10 bar (1 MPa),fiberglass pipes can be used.


The recommended material is carbon or low alloy steel, with a minimumcorrosion allowance of 3 mm.

SSC and HIC resistant materials are mandatory.

When the H2S content in the water phase is below 400 ppm, inhibitor injectionis required only if corrosion rate above 0.1 mm/y, obtained from monitoring.

The injection of inhibitors is required when the H 2S content in the water phaseis higher than 400 ppm.


The materials to be used are:- carbon or light-alloy steel is required (seamless pipes in accordance with

API 5L)- austenitic-ferritic stainless steel (seamless pipes in accordance with API

5LC, LC65-2205 grades)- austenitic stainless steel.


SSC and HIC resistant materials are always required.

When CO2 corrosion rate is below 0.2 mm/y, the only requirement is aminimum corrosion allowance of 3 mm.



For higher CO2 corrosion rates, inhibitor injection access fittings downstreamthe separators (or in equivalent location) shall be foreseen. Inhibitor modalitiesand dosage in addiction to the one injected upstream shall be evaluated on thebase of the monitoring data. Continuous injection is preferred.

The injection of inhibitors is required when the H 2S content in the water phaseis higher than 400 ppm or H2S partial pressure is above 0.1 bar (0.01 MPa).


The use of stainless steel is limited to offshore plants.

The use of austenitic stainless steels (AISI 316 when applicable or highergrades) or 22% Cr austenitic-ferritic stainless steel has to be considered whenCO2 corrosion rate is above 1 mm/y and CO 2 partial pressure, pCO2, is above 5bar (0.5 MPa).

When operating pressure in separated water lines is below 10 bar (1 MPa),fiberglass pipes can be used.

4.9 Stabilizer

The criteria shown in chapter 4.5 are applicable.

4.10 Oil flowlines

The criteria shown in chapters 4.2 are applicable.

4.11 Oil line

The criteria shown in chapters 4.2 are applicable.



5 GAS TREATMENT PLANTS

5.1 General

Gas treatment plants deals with water and condensates separation and gasdehydration.

All lines and components upstream the dehydration unit are potentiallysubjected to corrosion because gas is water saturated, hence condensation onmetallic surface can take place. On the contrary, downstream dehydration, gascorrosivity is negligible.

Options with carbon or low alloy steels, for pipelines and equipment, require acorrosion allowance. In the present specification the minimum value isindicated; however in every situation corrosion allowance shall be inaccordance with the predicted corrosion rate and the design life.

When applicable, options with stainless steels or nickel alloys are favourable insituations where a high reliability is required, such as in offshore plants.Moreover, safety requirements in treatment plants are generally more severethan gathering plants.

5.2 Water saturated gas lines

Corrosivity conditions shall be determined taking into account the localtemperature, pressure and gas composition. Moreover, the corrosivity can varydepending on the absence or different content of condensates and glycol, thatexhibit a corrosion inhibition action.

Requirements for gas flowlines (see chapter 3.3) are applicable.

5.3 Separation plant

Separation plant includes equipment for water, gaslines and gas separation,such as:- scrubbers;- separator;- degasator.

Materials, when non differently specified, are intended for the shell.

Materials for internal component, such as septa, bolts etc., shall comply withthe shell material.



When the shell material is carbon steel, internal components material can bestainless steels, for example austenitic type (AISI 316), provided that oxygen beabsent (not present).





The materials to be used are:- carbon or low alloy steels;- 22% Cr austenitic-ferritic stainless steels.

5.3.2.1 Carbon or low alloy steels


When corrosion inhibitor is injected at the wellhead or at the manifold, the useof carbon or low alloy steel is recommended. Additional inhibitor injection atmanifold can be necessary. The corrosion inhibitor shall be effective also in thegas \phase, to protect the top of the vessels and the gaslines. The inhibitordosage shall be determined on the basis of the available monitoring data.

As an alternative to the use of corrosion inhibitor, or in combination with it,adequate internal coatings are applicable (see NACE RP0181). The coatingtype shall be in accordance with the maximum operating temperature.


The use of 22% Cr austenitic-ferritic stainless steel, solid or cladded, has to beevaluated when CO2 estimated corrosion rate is above 1 mm/y and CO 2 , pCO2,is above 5 bar (0.5 MPa).


SSC and HIC resistant carbon and low alloy steels are required.


For H2S partial pressure above 0.1 bar (0.01 MPa), at the wellhead injectionaccess fittings shall be foreseen for continuous corrosion inhibitors injection.The need of inhibitor injection and the dosage shall be based on monitoringdata.





The materials to be used are:- carbon or low alloy steels;- austenitic-ferritic stainless steels;- nickel alloys.

5.3.4.1 Carbon or low alloy steels

SSC and HIC resistant materials are always required.


When continuous injection of corrosion inhibitors in carried out at thewellhead, the use of carbon or low alloy steel is recommended; further injectionaccess fittings upstream the separator (or in an equivalent position) have to beconsidered. The corrosion inhibitor shall be effective also in the gas phase, toprotect the top of the vessels and the gaslines. The inhibitor dosage shall bedetermined on the basis of the available monitoring data.


5.3.4.2 Stainless steels and nickel alloys

The use of stainless steel or nickel alloys (for example Incoloy 825) has to beconsidered when estimated CO2 corrosion rate is above 1 mm/y and CO 2, pCO2,is above 5 bar (0.5 MPa).

The selection of stainless steel type is based primarily on H 2S partial pressureand on temperature, beside of chloride concentration in water.

5.4 Separated water lines

Aqueous phase is predominant, with different contents of glycol andcondensates. Water wetting conditions are always present.

Criteria defined in chapter 4.8 are applicable.

5.5 Condensates lines

The predominant phase consists of is liquid hydrocarbons, with differentcontents of water and gas.

Criteria defined in chapter 4.6 are applicable.



5.6 Wet gas preheaters

Pre-heaters usually consist of ovens, where the wet gas is at pipes side. Criteriadefined in chapter 4.3 are applicable.

5.7 Dehydration columns

Criteria for separators defined in chapter 5.3 are applicable.

5.8 Dry gas lines

Dry gas lines come from dehydration columns. Corrosion conditions arecharacterized by water absence.

The recommended material is carbon steel, with a minimum corrosionallowance of 3 mm, especially when the gas contains CO 2; in fact severecorrosion conditions can temporarily take place, if anomalies in dehydrationsystem occur, causing low efficiency.

When gas phase contains H2S (pH2S > 0.0035 bar = 0.00035 MPa), the use ofSSC resistant materials and stress relieving heat treatment of welding.

5.9 Depressurization lines and collectors

From fluid corrosivity standpoint, these lines are similar to wet gas lines, withlimited operating time; the corrosion prevention measures are of minorimportance.


Carbon or low alloy steel (seamless or welded pipes, according to API 5L)


Carbon or low alloy steel (seamless or welded pipes, according to API 5L),with an optional 1 mm corrosion allowance.


Carbon or low alloy steel (seamless or welded pipes, according to API 5L) SSCresistant, according to NACE MR0175.


Carbon or low alloy steel (seamless or welded pipes, according to API 5L),SSC resistant, according to NACE MR0175, with 1 mm corrosion allowance.



6 VALVES

6.1 Designations

All types of valves recommended for the plants considered in this specificationare described in the Internal Normative document 15801.PIP.MEC.STD.

Valve types:- gate (VS);- plug (VR);- ball (VB);- butterfly (VF);- disk, pin, angle (VD);- check (VDR);- membrane (VM);- piston (VP).

6.2 Valve components

Valve components in contact with fluids (or that may come into contact withfluids) are:- valve body ( including flanged joints, bottom valve, cap and stem seat);- stem (and threaded seat);- gate (plug, ball);- seats;- seat gasket;- stem gasket;- springs.

Body materials are individuated according to the materials groups discussed inthe previous paragraph, while materials for single component are reported inthe Internal Normative document 15801.PIP.MEC.STD. standardizationdocument as a function of body materials.



6.3 Recommended materials

The Internal Normative document 15801.PIP.MEC.STD. makes distinctionsbetween three corrosivity levels, based on the characteristics of the fluids:standard corresponding to corrosivity class I.L.N.corrosive corresponding to corrosivity class I.L.C.NACE corresponding to corrosivity class I.L.S.

Corrosivity class I.L.CS. is not covered, but it is specifically analyzed in thisdocument.

6.3.1 I.L.N. Fluid class - Fluid class - Non containing CO 2 and H2S

All the materials of the valve body and of the components are conform to"Standard" class of the Internal Normative document 15801.PIP.MEC.STD.


The materials to be used are:- carbon or low alloy steel;- austeno-ferritic stainless steel;- austenitic stainless steel.

Although the material of main plant components (for example lines, separators)is carbon or low alloy steel with corrosion allowance in combination withcorrosion inhibitors, for the selection of valve material it is recommended not tofollow the same philosophy. In fact, it has to be considered that within the valvebody higher turbulence conditions are established, leading to more severecorrosion conditions and reduced corrosion inhibitor efficiency.

When estimated CO2 corrosion rate is below 0.2 mm/y, carbon or low alloysteel body is required.

For CO2 corrosion rate above 0.2 mm/y, the material of all parts of the valveshall be corrosion resistant material. The other components of the valve shallcomply the Corrosive category indicated in the Internal Normative document15801.PIP.MEC.STD.


The material recommended is carbon or low alloy steel.


SSC and HIC resistant materials are always required. Stress relieving heattreatment of welding is also required.




This environment is not mentioned in the Internal Normative document15801.PIP.MEC.STD.

The materials to be used are:- carbon or low alloy steel- austenitic-ferritic stainless steel- austenitic stainless steel- nickel alloys.

SSC and HIC resistant materials are always recommended.

A minimum corrosion allowance of 6 mm is required, for carbon and low alloysteels.

When estimated CO2 corrosion rate is below 0.2 mm/y, carbon or low alloysteel body. The use of corrosion inhibitor should depend on corrosionmonitoring data.

For CO2 corrosion rate above 0.2 mm/y, the material of all parts of the valveshall be corrosion resistant material (CRA).

Austenitic stainless steels, austenitic-ferritic stainless steels or nickel alloys aresuitable depending on CO2 and H2S content.



7 PUMPS

7.1 Designations

The considered types of pumps are described in the following InternalNormative documents:- 01205.MAC.MEC.SPC.- 01581.MAC.MEC.SPC.- 01582.MAC.MEC.SPC.- 03590.MAC.MEC.SPC.- 03690.MAC.MEC.SPC.

The following types of pumps are considered:

- horizontal centrifugal: (PCO)- vertical centrifugal: (PCV)- submersible vertical centrifugal: (PCV-S)- rotary: (PR)- alternative: (PA)

7.2 Pump components

The pump components in contact with the fluids (or that may come into contactwith the fluids) are reported in tables 7.1, 7.2, 7.3, 7.4, 7.5, where therecommended material options are also indicated.

Although the material of main plant components (for example lines, separators)is carbon or low alloy steel with corrosion allowance in combination withcorrosion inhibitors, for the selection of pump material it is recommended notto follow the same philosophy. In fact, it has to be considered that within thepump body higher turbulence conditions are established, leading to more severecorrosion conditions and reduced corrosion inhibitor efficiency.



Table. 7.1 - Materials recommended for horizontal centrifugal pumps.

COMPONENTS CLASSES OF CORROSIVITYI.L.N. I.L.C. I.L.S. (1) I.L.CS. (1)

case /barrel - cast iron- c-steel

- ss 316- ss duplex

- c-steel - c-steel- ss 316

impellers - cast iron- ss 316L

- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

wear rings - ss 316 - ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

shaft - c-steel (4140)

- ss 316- ss duplex

- c-steel- Ni base

alloy 718

- c-steel- Ni base

alloy 718internal parts - c-steel - ss 316

- ss duplex- c-steel - ss 316

- ss duplexbase - cast iron - cast iron - cast iron - cast iron

(1)All materials for corrosivity classes I.L.S. and I.L.CS. shall be SSC resistant.

Table 7.2 - Materials recommended for the vertical centrifugal pumps.


delivery nozzlecolumnbody

- c-steel - ss 316- ss duplex

- ss 316- ss duplex

- c-steel- ss 316


- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

wear rings - ss 316- bronze

- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

liner shaftcone conveyor


- ss 316- ss duplex

- ss 316- ss duplex

pump shaftintermediate shaft

- c-steel (4140)

- ss 316- ss duplex

- c-steel- Ni base

alloy 718

- c-steel- Ni base

alloy 718bolt case - c-steel - ss 316

- ss duplex- ss 316- ss duplex

- ss 316- ss duplex

filter - c-steel - ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

flange - c-steel - c-steel - c-steel - c-steel

(1)All materials for corrosivity classes I.L.S. and I.L.CS. shall be SSC resistant.



Table 7.3 - Materials recommended for the vertical submersible centrifugalpumps.


discharge curveriser, body


- ss 316- ss duplex

- c-steel- ss 316


- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

wear rings - ss 316- bronze

- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

linear shaft - c-steel - ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

pump shaft - c-steel (4140)

- ss 316- ss duplex

- c-steel- Ni base

alloy 718

- c-steel- Ni base

alloy 718bolt case - c-steel - ss 316


- ss 316- ss duplex

filter - c-steel - ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

joint - see shaft - see shaft - see shaft - see shaftnon valve - c-steel - ss 316

- ss duplex- c-steel - ss 316

- ss duplexbearing plate - cast iron - cast iron - cast iron - cast iron

(1)All materials for corrosivity classes I.L.S. and I.L.CS. shall be SSC resistant



Table 7.4 - Materials recommended for the rotary pumps.


body liner - c-steel - ss 316- ss duplex

- ss 316- ss duplex

- c-steel- ss 316

rotors - cast iron- ss 316L

- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

ring lantern - ss 316- bronze

- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

packing - c-steel - ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

pump shaft - c-steel (4140)

- ss 316- ss duplex

- c-steel- Ni base

alloy 718

- c-steel- Ni base

alloy 718safety valve - c-steel - ss 316


- ss 316- ss duplex

recycle valve(safety valve)



base - cast iron - cast iron - cast iron - cast iron




Table 7.5 - Materials recommended for the alternative pumps.

COMPONENTS CLASSES OF CORROSIVITYI.L.N. I.L.C. I.L.S.(1) I.L.CS. (1)

bodypiston rodscylinders


- ss 316- ss duplex

- c-steel- ss 316

shutters - cast iron- ss 316L

- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

rings - ss 316- bronze

- ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

seats - c-steel - ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

valve springs - c-steel (4140)

- ss 316- ss duplex

- c-steel- Ni base

alloy 718

- c-steel- Ni-base

alloy 718guide - c-steel - ss 316


- ss 316- ss duplex

crankconnection rodshaft

- see pistonrods

- see pistonrods

- see pistonrods

- see pistonrods

bolt case - c-steel - ss 316- ss duplex

- ss 316- ss duplex

- ss 316- ss duplex

base - cast iron - cast iron - cast iron - cast iron


08053E02 Internal Corrosion

Documents

Transcript of 08053E02 Internal Corrosion