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2 General revision CESCOR STIN CORM 15.06.95REV. DESCRIPTION
COMP. VERIF. APPR. DATE
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DESIGN CRITERIA
INTERNAL CORROSION
MATERIALS AND CORROSION CONTROL METHODSIN GATHERING AND
TREATMENT OIL AND GAS PLANTS
08053.MAT.COR.PRG
Rev.2
June 1995
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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.
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been sent.
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
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been sent.
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
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been sent.
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
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been sent.
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.
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parties nor used for purposes other than those for which it has
been sent.
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.
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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).
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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).
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been sent.
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
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Steel containing enough chromium (usually above 11%) to give
steel asufficient corrosion resistance. Other elements may be added
to secure specialproperties.
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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.
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been sent.
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.
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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.
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parties nor used for purposes other than those for which it has
been sent.
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.
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parties nor used for purposes other than those for which it has
been sent.
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.
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parties nor used for purposes other than those for which it has
been sent.
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
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been sent.
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.
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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.
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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).
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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.
A minimum corrosion allowance of 2 mm is 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.
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08053.MAT.COR.PRGRev.2 June 1995Sheet 22
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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.
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.
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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.
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).
3.3.2.1 Carbon and low alloy steels
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.
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08053.MAT.COR.PRGRev.2 June 1995Sheet 24
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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.
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.
3.3.2.2 Stainless steels
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).
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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.
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.
A minimum corrosion allowance of 1 mm is required.
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).
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parties nor used for purposes other than those for which it has
been sent.
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.
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parties nor used for purposes other than those for which it has
been sent.
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
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parties nor used for purposes other than those for which it has
been sent.
(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
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parties nor used for purposes other than those for which it has
been sent.
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.
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parties nor used for purposes other than those for which it has
been sent.
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).
4.5.1 I.L.N. Fluid class - Non containing CO 2 and H2S
The recommended material is carbon or low alloy steel.
A minimum corrosion allowance of 2 mm is required.
4.5.2 I.L.C. Fluid class - Containing CO 2
The materials to be used are:- carbon or low alloy steel;- 22%
Cr austenitic-ferritic type stainless steel.
4.5.2.1 Carbon and low alloy steels
A minimum corrosion allowance of 3 mm is required.
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
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08053.MAT.COR.PRGRev.2 June 1995Sheet 31
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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.
in offshore plants or in hazardous areas with risks for
environment orpopulation.
4.5.3 I.L.S. Fluid class - Containing H 2S
The recommended material is carbon or low alloy steel, SSC and
HIC resistant.
A minimum corrosion allowance of 2 mm is required.
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.
4.5.4 I.L.CS. Fluid class - Containing CO 2 and H2S
The materials to be used are:- carbon or low alloy steels-
austenitic-ferritic stainless steels- nickel alloys.
4.5.4.1 Carbon and low alloy steels
The recommended material is carbon or low alloy steel, SSC and
HIC resistant.
A minimum corrosion allowance of 3 mm is required.
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.
Stress relieving heat treatment of circumferential welding is
required.
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.
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parties nor used for purposes other than those for which it has
been sent.
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.
4.8.1 I.L.N. Fluid class - Non containing CO 2 and H2S
The recommended material is carbon or low alloy steel. A minimum
corrosionallowance of 3 mm is recommended.
4.8.2 I.L.C. Fluid class - Containing CO 2
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)
4.8.2.1 Carbon and low alloy steels
It is the recommended option.
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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.
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.
4.8.3 I.L.S. Fluid class - Containing H 2S
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.
4.8.4 I.L.CS. Fluid class - Containing CO 2 and H2S
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.
4.8.4.1 Carbon and low alloy steels
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.
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08053.MAT.COR.PRGRev.2 June 1995Sheet 34
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.
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).
4.8.4.2 Stainless steels
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.
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parties nor used for purposes other than those for which it has
been sent.
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.
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parties nor used for purposes other than those for which it has
been sent.
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).
5.3.1 I.G.N. Fluid class - Non containing CO 2 and H2S
The recommended material is carbon or low alloy steel.
A minimum corrosion allowance of 2 mm is required.
5.3.2 I.G.C. Fluid class - Containing CO 2
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
A minimum corrosion allowance of 3 mm is required.
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.
5.3.2.2 Stainless steels
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).
5.3.3 I.G.S. Fluid class - Containing H 2S
SSC and HIC resistant carbon and low alloy steels are
required.
A minimum corrosion allowance of 2 mm is 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.
Stress relieving heat treatment of circumferential welding is
required.
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08053.MAT.COR.PRGRev.2 June 1995Sheet 37
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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.
5.3.4 I.G.CS. Fluid class - Containing CO 2 and H2S
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.
A minimum corrosion allowance of 3 mm is 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.
Stress relieving heat treatment of circumferential welding is
required.
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.
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08053.MAT.COR.PRGRev.2 June 1995Sheet 38
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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.
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.
5.9.1 I.G.N. Fluid class - Non containing CO 2 and H2S
Carbon or low alloy steel (seamless or welded pipes, according
to API 5L)
5.9.2 I.G.C. Fluid class - Containing CO 2
Carbon or low alloy steel (seamless or welded pipes, according
to API 5L),with an optional 1 mm corrosion allowance.
5.9.3 I.G.S. Fluid class - Containing H 2S
Carbon or low alloy steel (seamless or welded pipes, according
to API 5L) SSCresistant, according to NACE MR0175.
5.9.4 I.G.CS. Fluid class - Containing CO 2 and H2S
Carbon or low alloy steel (seamless or welded pipes, according
to API 5L),SSC resistant, according to NACE MR0175, with 1 mm
corrosion allowance.
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08053.MAT.COR.PRGRev.2 June 1995Sheet 39
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.
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.
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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.
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.
6.3.2 I.L.C. Fluid class - Containing CO 2
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.
6.3.3 I.L.S. Fluid class - Containing H 2S
The material recommended is carbon or low alloy steel.
A minimum corrosion allowance of 6 mm is required.
SSC and HIC resistant materials are always required. Stress
relieving heattreatment of welding is also required.
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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.
6.3.4 I.L.CS. Fluid class - Containing CO 2 and H2S
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.
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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.
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.
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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.
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.
COMPONENTS CLASSES OF CORROSIVITYI.L.N. I.L.C. I.L.S. (1)
I.L.CS. (1)
delivery nozzlecolumnbody
- c-steel - ss 316- ss duplex
- ss 316- ss duplex
- 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- bronze
- ss 316- ss duplex
- ss 316- ss duplex
- ss 316- ss duplex
liner shaftcone conveyor
- c-steel - ss 316- ss duplex
- 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.
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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.
Table 7.3 - Materials recommended for the vertical submersible
centrifugalpumps.
COMPONENTS CLASSES OF CORROSIVITYI.L.N. I.L.C. I.L.S. (1)
I.L.CS. (1)
discharge curveriser, body
- c-steel - ss 316- ss duplex
- ss 316- ss duplex
- 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- 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 duplex- ss 316- ss duplex
- 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
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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.
Table 7.4 - Materials recommended for the rotary pumps.
COMPONENTS CLASSES OF CORROSIVITYI.L.N. I.L.C. I.L.S. (1)
I.L.CS. (1)
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 duplex- ss 316- ss duplex
- ss 316- ss duplex
recycle valve(safety valve)
- c-steel - ss 316- ss duplex
- c-steel - ss 316- ss duplex
base - 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
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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.
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
- c-steel - ss 316- ss duplex
- 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 duplex- ss 316- ss duplex
- 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
(1)All materials for corrosivity classes I.L.S. and I.L.CS.
shall be SSC resistant