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Development Operations & Production Enhancement

Material Selection Report Sheet No.

Project Facility Discipline Document Seq. Rev. Page 1 of 32

FD534 0000 MW RT 1001 D0 OUQ108

D0 14-10-2013 ISSUED FOR COMMENTS J.H.JEONG RANGA AK

REV DATE DESCRIPTION

PREPARED CHECKED APPROVED APPROVAL

Oceanus Co. Ltd. Approved by:

MATERIAL SELECTION REPORT

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TABULATION OF REVISED PAGESRev.

Page

Rev.

D0 D1 D2 D0 D1 D2

1 X 512 X 523 X 534 X 545 X 556 X 567 X 578 X 589 X 5910 X 6011

X 61

12 X 6213 X 6314 X 6415 X 6516 X 6617 X 6718 X 6819 X 6920 X 7021 X 7122 X 7223 X 7324 X 7425 X 7526 X 7627 X 7728 X 7829 X 7930 X 8031 X 8132 X 8233 8334 8435 8536 8637 8738 8839 8940 9041 9142 9243 9344 9445 9546 9647 9748 9849 9950 100

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REVISION RECORD SHEET

Rev. No. Purpose List Of Updated Modified Sections If Any

D0 Issued For Comments First Issue

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INDEXSECTION PAGE

1. INTRODUCTION 61.1 SCOPE 61.2 ABBREVIATIONS 61.3

DEFINITIONS 6

2. REFERENCES 73. MATERIAL DEGRADATION PHENOMENA 83.1 CO2 CORROSION IN AN AQUEOUS PHASE 83.1.1 Presence of Heavy Hydrocarbon Liquids 83.1.2 Condensation Factor 83.1.3 Effect of Hydrogen sulfide 83.1.4 Effect of Glycol 93.1.5 CO2 corrosion rate calculations, availability model 93.2 WET H2S CORROSION 93.2.1 General H2S Corrosion 103.2.2 Sulfide Stress Cracking 103.2.3 Hydrogen Induced Cracking (HIC) 103.2.4 Design Philosophy 113.3 CHLORIDE INDUCED CORROSION 113.4 ATMOSPHERIC CORROSION 114. GASOIL RECEIVING EQUIPMENT AND PIPING 124.1 FX AREA 124.1.1 Existing Test Separator 03-C-04 (system AA) 124.1.2 Existing (Sour) Primary Separator 03-C-01B (system AB) 124.1.3 Existing Sweet Primary Separator 03-C-01A (system AC) 134.1.4 Sour Transfer Pump P-100 A/B (system AF) 134.1.5 Sweet Transfer Pump P-101 A/B (system AF) 144.2 FZ / FZA AREA 144.2.1 Existing Sweet Fuel Separator 04-C-02B (system FG) 144.2.2 Existing Sour Separator 04-C-02A (system BG) 144.2.3 Existing (Sweet) Primary Separator 04-C-01 (system BG) 154.2.4 Inlet Heaters E-105 and E-106 164.2.5 FZ Crude Dehydrator V-100 (system AK) 164.2.6 Existing Test Separator 04-C-04 (system CJ) 164.2.7 Test Inlet Heater E-107 174.2.8 HP Gas Separator V-103 (system AM) 17

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4.2.9 Sour Slug Catcher V-202 (system AY) 184.2.10 FX Crude Dehydrator V-102 (system AZ) 194.2.11 FX Inlet Heater E-108 (system DJ) 194.2.12 Produced Water Degasser V-306 (system AL) 194.2.13 Water Treatment Package U-311 194.2.14 Existing Intermediate Separator 04-C-03 (system AL) 204.2.15 Crude Booster Pumps P-100 A/B/C (system AS) 204.2.16 First Stage Suction Drum V-206 A/B (system CG) 204.2.17 1st Stage Gas Lift Compressor U-217 A/B and 1st Stage Cooler (system DG) 214.2.18 Gas Dehydration Package U-218 214.2.19 2nd Stage Suction Drum V-207A/B (system EG) 214.2.20 2nd Stage Gas Lift Compressor U-217 A/B 224.2.21 2nd Stage Cooler E-215 A/B 224.2.22 Closed Drain Vessel V-309 224.3 UTILITY SYSTEMS 224.3.1 Chemical Injection Piping 224.3.2 Chemical Injection Package 224.3.3 Diesel System 234.3.4 Domestic water System 234.3.5 Fire Water and Utility Water System 234.3.6 Fuel Gas Package 234.3.7 Hypochlorite Injection Package 234.3.8 Instrument Air System 234.3.9 Open Drain System 234.3.10 Closed Drain System 244.3.11 Flare System 244.3.12 Hot Water system 244.3.13 Nitrogen System 244.4 CORROSION MONITORING 255. NEW MECHANICAL EQUIPMENT SUMMARY 265.1 FX AREA 265.2 FZ AREA 265.3 UTILITY SYSTEMS 286. ADDITIONAL SERVICE REQUIREMENTS 307. APPENDIX A: CORROSION CALCULATIONS 318. APPENDIX B: CORROSION INHIBITOR PHILOSOPHY 32

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1. INTRODUCTION1.1 SCOPE

The material selection report describes the corrosion control and the material selection of thenew top side piping and equipment of Foroozan Development Operations and ProductionEnhancement Project.

This document should be read in conjunction with the Material Selection Diagram FD534-0000-MW-DG-1001.

The selection of material and the applied corrosion allowance is based on a 25 years design life.

1.2 ABBREVIATIONSCA Corrosion AllowanceCAT Cathodic ProtectionCC Corrosion Coupon

CP Corrosion ProbeCR Corrosion RateCRA Corrosion Resistant AlloysCS Carbon Steel

DSS Duplex Stainless SteelGRE Glass fiber Reinforced EpoxyHIC Hydrogen Induced CrackingHRC Hardness Rockwell CHV Hardness Vickers

NACE National Association of Corrosion EngineersPVDF PolyVinyliDene FluorideSS Stainless SteelSSC Sulfide Stress Cracking

1.3 DEFINITIONSFor this specification, following definitions are applicable:

OWNERShall mean Iranian Offshore Oil Company

EPCI Contractor:Shall mean Iranian Offshore Engineering and Construction Company (IOEC)

EPCI Subcontractor:Shall mean Oceanus Co. Ltd.

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Supplier or Vendor:Any supplier or vendor, who is appointed by the EPCI Contractor and who is respon-sible for the supply of materials or equipment and/or services.

Subsupplier:Shall mean any person or Purchaser (other than Purchaser) having a contract withVendor or Supplier for the manufacture and/or supply of the Goods a part of the Goods

Approved, Approve, Approval:Means approved, approve, approval in writing by Purchaser

Purchase OrderShall mean the written Purchase Order agreed between PURCHASER and VENDORtogether with any appendices or attachments thereto.

Goods:Shall mean any and all of the design, engineering, services, warranty related services,labor, assistance, articles, materials, equipment, spare parts, other supplies includingbut not limited to manuals, operating instructions, reports and drawings and all other

documents to be supplied or performed by Vendor or Supplier as described in (or to beinferred from) the Purchaser Order.

Paint Contractor:The person or Purchaser identified as the party which apply paint and coating on the

structural parts, decks, piping, equipment etc.

Purchaser:Shall mean the person or Purchaser, and where the context so admits, include the

Purchasers workmen, employees, agents and/or representatives, successors andpermitted assigns.

2. REFERENCESFD534-0000-PR-DB-1001 Basic Design Data ReportFD530-0000-PR-DB-1003 Heat and Mass BalanceFD530-0000-PR-DG-1002-01 System Diagrams ProcessFD534-0000-MW-DG-1001 Material Selection DiagramFD534-0000-MW-SP-1002 Requirements for Materials in Wet H2S Service

NACE MR0175/ISO15156 (2003) International Standard, Petroleum and Natural GasIndustries - Materials for use in H2S containing

environments in Oil and Gas Production

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3. MATERIAL DEGRADATION PHENOMENA3.1 CO2 CORROSION IN AN AQUEOUS PHASE

In an aqueous phase CO2 dissolves and lowers the pH, this and other side reactions are the causeof a higher corrosion rate in the presence of CO2. Corrosion rates in these cases can be estimatedusing the De Waard/Milliams nomogram. De Waard, Lotz and Milliams state in their article onthis subject "Predictive Model for CO2 Corrosion Engineering in Wet Natural Gas Pipelines" inCorrosion, December 1991, that the De Waard/Milliams equation, which is the "worst case"corrosion rate prediction (V mm/y), is specified as follows:

Log V = 5.8 - 1710/T + 0.67*log (PCO2)

Where T = temperature in K and PCO2 is partial pressure of CO2 in bar.

Benefit may be drawn from the following factors:

Nonideality of the Gas High-temperature Protective Films Contamination of the CO2 Solution with Corrosion Products Solution pH Presence of Heavy Hydrocarbon Liquids Effect of GlycolIf the environment contains no free water, then there is no risk of CO2 corrosion. In gas piping,there may be a risk of condensation of water if the temperature of the line drops below thewater dew point. Therefore, if possible, in these cases the piping should be sloped and withoutpockets.

3.1.1 Presence of Heavy Hydrocarbon LiquidsThe presence of crude oil can have a beneficial effect, in case of CO2 corrosion, by oil-wettingthe steel surface. However, if the flow rate of the oil is too low, water can separate and causecorrosion on the bottom of the line. This critical flow velocity is 1 m/s. At higher flow rates the

water will be dispersed in the oil. If the water cut, however, is more than 30 wt% the steelsurface will be water wetted and corrosion takes place.

For light hydrocarbon condensates (less than 50 wt% C5+), water wetting and corrosion may

Occur at any velocity and any water content.

3.1.2 Condensation FactorCorrosion rates of steel exposed to only a condensing water phase in a CO2 containingatmosphere quickly decreases with time.For wet gas transport piping, cooling rates and flow rates are such that condensation rates arelow and the average corrosion rates will be approximately 1/10 of the calculated corrosion rat

3.1.3 Effect of Hydrogen sulfideIn sour gas pipelines and flow lines, H2S can have an effect on the formed corrosion productsand stability of the FeCO3 corrosion films. Depending on H2S / CO2 ratio and temperature, the

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formation of FeS corrosion products can have an inhibitive effect as well as an acceleratingeffect on the wet CO2 corrosion rate. The total corrosivity, however, has been assessed based onCO2 corrosion only. It is recognized that H2S can have an inhibitive effect and may reduce thepredicted corrosion rate to about one third, due to the better protective properties of the formedcorrosion scale. However, locally the scale may not adhere, or breakdown and full CO 2corrosion may occur. The calculated CO2 corrosion rates give the worst case scenario.

3.1.4 Effect of GlycolIn wet CO2 containing gas pipelines and flow lines glycol is often added to prevent hydrateformation. Glycols have a significant inhibitive effect on corrosion.

3.1.5 CO2 corrosion rate calculations, availability modelThe basis for corrosion prediction is the corrosion resulting from wet CO2 corrosion. Thecorrosiveness is depending on the CO2 partial pressure, and is further affected by temperature,flow regime, oil wetting, water condensation, pH, presence of H2S, chlorides, etc.

For corrosion rate calculations, the following assumptions are made:The effect of H2S on the general corrosion rate caused by wet CO2 can be inhibitive, up to theorder of magnitude of 1/3 due to a possible increase of pH and formation of FeS scale.

However, the scale is not continuous, and locally higher corrosion rates can occur. Therefore,H2S is typically neglected in the (worst-case) corrosion rate calculations.

The calculated total corrosion over piping design life is based on the followingassumptions:

The corrosion mechanism is wet CO2. The corrosion rate when inhibition is available is 0.1 mm/yr. The corrosion inhibitor availability is 98%. Always flowing conditions are assumed. Design life is 25 years. CA = 25 x (0.98 x 0.1 + 0.02 x CR),Where CA = Corrosion allowance and CR = Corrosion rate without inhibition.

For the inhibited corrosion rate it is frequently shown, that the corrosion rate under inhibition isnot as sensitive to operational parameters as is the corrosion rate without inhibition. Since itbetter represents the real operation situation, the inhibitor availability concept is nowadays thetrend to be used.

The general inhibited corrosion rate is in the order of 0.1 mm/y. When based on actual fieldexperience, another value will come available, this experienced inhibited corrosion rate can betaken instead of the default value of 0.1 mm/y.

3.2 WET H2S CORROSIONAqueous hydrogen sulfide corrosion and sour water corrosion will occur at temperatures nearambient.Sour water corrosion consists of the following main three types:

General corrosion (including erosion-corrosion) Sulfide Stress Cracking (SSC)

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Hydrogen Induced Cracking (HIC)3.2.1 General H2S Corrosion

H2S is corrosive to steel and forms a FeS scale.However, CO2 is the dominant corrosion mechanism. Refer to section 3.1.3 and 3.1.5 for moreinformation concerning H2S and CO2 corrosion.

3.2.2 Sulfide Stress CrackingAs a by-product of the corrosion reactions between H2S and Fe, nascent atomic hydrogen isabsorbed by steel. This hydrogen will diffuse to places as notches and other high-stress areas

where it can contribute to crack growth.

For stress cracking, a critical combination of the following factors is required:

Absorption of sufficient hydrogen. A total tensile stress (applied plus residual) of critical magnitude. A susceptible metallurgical condition in the steel. Time.From a practical standpoint, only the metallurgical conditions can be controlled. In this respect,the NACE International published the specification NACE MR0175/ISO15156, which basicallylimits the hardness of ferritic steels to 22 HRC (248 HV10).

This specification is generally accepted to prevent sulfide stress corrosion cracking and allmaterials in H2S service shall therefore be ordered in line with this specification.

Further, since especially welds and heat-affected zones are susceptible to high hardness andstress corrosion, hardness testing shall be included in all welding procedure qualifications.

Also spot checks shall be made on each piece of fabricated equipment. Dissimilar welds are notallowed because local hard zones will be formed which are more susceptible to SSC.

3.2.3 Hydrogen Induced Cracking (HIC)Similar to sulfide stress cracking, also hydrogen induced cracking is the result of atomichydrogen diffusing into the material as a result of the corrosion reaction between H2S and Fe. Inthis case, however, tensile stresses are not required.

Furthermore, this type of corrosion affects only plate and pipe materials with elongatednonmetallic inclusions, such as MnS. Atomic hydrogen will diffuse to these inclusions andrecombine to molecular hydrogen with a subsequent bigger volume. This will result in highpressures at these spots. Near the surface this will lead to blistering. In deeper zones, materialseparation in the form of stepwise cracking occurs.

As the threshold value, below which no hydrogen induced cracking will occur, 50 ppmwt H 2S

has been established for low pH and neutral aqueous solutions.

To prevent hydrogen induced cracking, clean and homogenous carbon steel materials shall beused, free from inclusions. Especially the presence of elongated sulfides shall be prevented. HICfailures have mainly been reported for welded pipe, not for seamless pipe.

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Therefore, it is recommended to use seamless pipe as much as possible.The Sour Service and HIC requirements are given in the project specification Requirements forMaterials in Wet H2S Service, (FD534-0000-MW-SP-1002).

3.2.4 Design PhilosophyEquipment, piping and pipelines which contain H2S and are continuously water wet or may bewater wet during an up-set condition, e.g. as a result of malfunctioning of TEG dehydration,

shall comply with the materials and manufacturing requirements of NACE MR0175/ISO15156.Even for items operating below the NACE MR0175/ISO15156 SSC risk curves, shall complywith these guidelines. Since these are basically only a limitation of the hardness, this does notresult in a significant cost addition if normal material requirements (e.g. carbon equivalent

limited to 0.43 0.42) and normal fabrication procedures are applied.

Equipment, piping and pipelines which contains H2S and can be water wet for prolonged timesand the water phase will contain more than ~ 50 ppmwt H2S, shall have additional HICrequirements on top of the NACE MR0175/ISO15156 requirements.

3.3 CHLORIDE INDUCED CORROSIONProduced water from wells typically contains chloride salts. The effect of the chloride ions is

that they can be incorporated into and penetrate the steel corrosion films, leading todestabilization of the corrosion film. This can lead to increased corrosion of both carbon steels

and stainless steels.This phenomenon increases with chloride concentration and with temperature, but only occurswhen oxygen (air) is present.Since the production water streams are deaerated environments, chloride stress corrosion ofaustenitic materials is suppressed. This means that austenitic stainless steels, e.g. SS 316L canbe applied as long as the environment is oxygen free, or the temperature is always below 6560 C. The temperature of 60 C is threshold value below which stress corrosion of AISI 300

series austenitic stainless steel does not occur.

3.4 ATMOSPHERIC CORROSIONExternal corrosion is related to the atmospheric conditions, such as humidity and salts.

Since carbon steel can corrode due to atmospheric corrosion, a suitable coating system shall beapplied. Also austenitic stainless steel may corrode at atmospheric conditions, particularly

chloride pitting may occur in an offshore environment. Austenitic stainless steel is susceptibleto chloride stress corrosion cracking at temperatures above 60C. All austenitic steels shall beexternally coated to minimize the risk at SCC and pitting. Furthermore, if applied, duplexstainless steel does not corrode at atmospheric conditions. It has a high chloride resistance.Duplex stainless steels do not require external coating.

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4. GASOIL RECEIVING EQUIPMENT AND PIPING4.1 FX AREA4.1.1 Existing Test Separator 03-C-04 (system AA)

The gas outlet piping of the existing test separator 03-C-04 has a normal operating temperatureof 28C. The normal operating pressure is 25 Bara. The maximum CO2 content in the gas phase

is 4 mol%. Also maximum 4.7 mol% H2S can be present.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate for carbon steel is 0.13 mm per year. The maximum expectedtotal corrosion for carbon steel in 25 years lifetime is expected to be 3.3 mm. Therefore therecommended material of construction is carbon steel with 6 mm corrosion allowance. Sourservice and HIC requirements shall be fulfilled.

The test separator has separate water and hydrocarbons bottom outlet piping. These separatedstreams are combined again in one common pipe further downstream the test separator. Theestimated water cut in the mixed hydrocarbon and water stream is 32wt%. Therefore the mixedhydrocarbon and water piping are assumed to be fully water wetted. The maximum expected

corrosion rate is 0.12 mm/yr with corrosion inhibitor injection downstream wells heads. Then,the total required corrosion allowance in 25 years is 3.1 mm. Therefore the recommended

material selection is carbon steel with 6 mm corrosion allowance. Sour service and HICrequirements shall be fulfilled.

The upstream crude piping from wells has an estimated water cut of 38wt%. Therefore the crudepiping is considered to be water wetted. Corrosion inhibition is foreseen. The recommendedmaterial selection is CS + 6 mm CA. Sour service and HIC requirements shall be fulfilled.

Due to the large amount of wells, which can be connected to the test separator, the test separatoris considered to be in (almost) continuous operation.It is assumed that the existing test separator is suitable and fit for the purpose condition forfuture 25 years operation.

4.1.2 Existing (Sour) Primary Separator 03-C-01B (system AB)The gas outlet piping of the existing (sour) Primary Separator 03-C-01B has a normal operatingtemperature of 33C. The normal operating pressure is 25 Bara. The maximum CO2 content inthe gas phase is 3.8 mol%. Also 3.2 mol% H2S can be present.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate is 0.17 mm per year. The maximum expected total corrosionfor carbon steel in 25 years lifetime is expected to be 4.14 mm. Therefore the recommendedmaterial of construction is carbon steel with 6 mm corrosion allowance. Sour service and HICrequirements shall be fulfilled

The separated oil has a water cut of 19wt%. Therefore the oil is considered to be mildlycorrosive to carbon steel. The recommended material selection is carbon steel with 3 mmcorrosion allowance. Due to the possible presence of H2S, the piping shall fulfill sour service

and HIC requirements.

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The piping containing separated water is fully water wetted. Corrosion inhibitor is injecteddownstream wells heads. The total expected corrosion, based on the availability modelcalculations, for carbon steel is 3.3 mm. The recommended material selection is CS + 6 mm CA+ sour service + HIC requirements.

The upstream crude piping from wells has a maximum estimated water cut of 56 wt%.Therefore the crude piping is considered to be water wetted. Corrosion inhibitor is injected

downstream wells heads. The recommended material selection is CS + 6 mm CA. Sour serviceand HIC requirements shall be fulfilled.

It is assumed that the existing separator is suitable and fit for the purpose condition for future 25years operation

4.1.3 Existing Sweet Primary Separator 03-C-01A (system AC)The gas outlet piping of the existing sweet primary Separator 03-C-01A has a normal operatingtemperature of 42.7C. The normal operating pressure is 25 Bara. The maximum CO2 content in

the gas phase is 2.9 mol%. Also 1.65 mol% H2S can be present.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, the

maximum expected corrosion rate is 0.2 mm per year. This would give a total corrosion of 4.94mm for carbon steel. Therefore, the recommended material of construction is carbon steel with 6mm corrosion allowance. Sour service and HIC requirements shall be fulfilled.

The separated oil has a water cut of 18wt%. Therefore the oil is considered to be mildlycorrosive to carbon steel. The recommended material selection is carbon steel with 3 mm

corrosion allowance. Due to the possible presence of H2S, the piping shall fulfill sour serviceand HIC requirements.

The piping containing separated water is fully water wetted. Corrosion inhibitor is injecteddownstream wells heads. The total expected corrosion, based on the availability modelcalculations, for carbon steel is 3.4 mm. The recommended material selection is CS + 6 mm CA+ sour service + HIC requirements.

The upstream crude piping from wells has a maximum estimated water cut of 34wt%. Thereforethe crude piping is considered to be water wetted. Corrosion inhibitor is injected downstream

wells heads. The minimum recommended material selection is CS + 6 mm CA. Sour service andHIC requirements shall be fulfilled.

It is assumed that the existing separator is suitable and fit for the purpose condition for future 25years operation.

4.1.4 Sour Transfer Pump P-100 A/B (system AF)The sour oil from the existing (sour) Primary Separator 03-C-01B has an estimated water cut of19wt%. Therefore the oil is considered to be mildly corrosive to carbon steel. The recommended

material selection is carbon steel for casing and 12%Cr for impeller. Due to the presence of H2S,

the pump material shall fulfill NACE MR0175/ISO15156 requirements.

Piping upstream and downstream the sour transfer pump can be CS + 3 mm CA. Sour serviceand HIC requirements shall be fulfilled.

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4.1.5 Sweet Transfer Pump P-101 A/B (system AF)The sweet oil from the Primary Existing Sweet Separator 03-C-01A has an estimated water cutof 18wt%. Therefore the oil is considered to be mildly corrosive to carbon steel. Therecommended material selection is carbon steel for casing and 12%Cr for impeller. Due to thepresence of H2S, the pump material shall fulfill NACE MR0175/ISO15156 requirements.Piping upstream and downstream the sour transfer pump can be CS + 3 mm CA. Sour service

and HIC requirements shall be fulfilled.

4.2 FZ / FZA AREA4.2.1 Existing Sweet Fuel Separator 04-C-02B (system FG)

The Sweet Fuel Separator vapour outlet piping has a normal operating temperature of 28C. Thenormal operating pressure is 19 Bara. The maximum CO2 content in the gas phase is 0.7 mol%.No H2S is or will be present, because the dedicated wells are sweet and without gas lift, thus nosouring of the well will occur.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate for carbon steel is 0.03 mm per year. The maximum expectedtotal corrosion for carbon steel in 25 years lifetime is expected to be 0.85 mm. This is based on

worst case conditions. Therefore the recommended material selection is CS + 3 mm CA. Thevapour outlet piping shall be slope and without pockets. This is applicable for all vapour

containing carbon steel piping. However, since all carbon steel piping classes will fulfill sourservice requirements, also the vapour overhead piping shall fulfill sour service requirements.

The bottom outlet oil piping of the Sweet Fuel Separator has a maximum estimated water cut of44wt%. Therefore the oil piping is assumed to be water wetted. The maximum expectedcorrosion rate for carbon steel is 0.1 mm/yr. Corrosion inhibition is foreseen. Based on theavailability model calculations, the total required corrosion allowance in 25 years is 2.6 mm.

The recommended material selection is CS + 3 mm CA. However, since all carbon steel pipingclasses will fulfill sour service requirements, also the oil piping shall fulfill sour servicerequirements.

The material selection recommendation for sweet crude piping upstream the Sweet Fuel

Separator is CS + 3 mm CA. Corrosion inhibitor is injected downstream wells heads. However,since all carbon steel piping classes will fulfill sour service requirements, also the sweet crude

piping shall fulfill sour service requirements.


4.2.2 Existing Sour Separator 04-C-02A (system BG)The Existing Sour Separator vapour outlet piping has a normal operating temperature of 50C.The normal operating pressure is 18 Bara. The maximum CO2 content in the gas phase is 5.1mol%. Also 3.9 mol% H

2S can be present.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate is 0.3 mm per year. This would give a total corrosion of 7.6

mm for carbon steel. Therefore carbon steel cannot be considered as material of construction. In

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the mixed crude 210000 ppm salts are present. Due to the high design temperature of 93Caustenitic stainless steel should not be used, because carryover of some chlorides would bepossible, which gives a possibility of chloride stress cracking and pitting corrosion. Duplexstainless steels should also not be considered as material of construction due to the large amountof H2S (0.7 Bara partial pressure) in the hydrocarbon vapour.

The recommended material of construction is alloy 825. NACE MR0175/ISO15156

requirements shall be fulfilled.

The bottom outlet piping of the Existing Sweet Separator containing separated oil has anestimated water cut of 18wt%. Therefore the oil is considered to be mildly corrosive to carbonsteel. Therefore the recommended material selection is CS + 3 mm CA. Sour service and HIC

requirements shall be fulfilled due to the presence of H2S.

The bottom outlet piping containing separated water is fully water wetted. Corrosion inhibitor isavailable. The total expected corrosion, based on the availability model calculations, for carbon

steel is 4 mm in 25 years. Also some H2S is present. Therefore the recommended materialselection is CS + 6 mm CA + sour service + HIC requirements.

The upstream crude piping has a maximum estimated water cut of 34wt%. Therefore the crudepiping is considered to be water wetted. Corrosion inhibition is foreseen. The total expectedcorrosion, based on the availability model calculations, for carbon steel is 3.5 mm in 25 years.The recommended material selection is CS + 6 mm CA. Sour service and HIC requirementsshall be fulfilled.


4.2.3 Existing (Sweet) Primary Separator 04-C-01 (system BG)The Existing (Sweet) Primary Separator vapour outlet piping has a normal operatingtemperature of 50C. The normal operating pressure is 18 Bara. The maximum CO2 content inthe gas phase is 1.6 mol%. Also 0.3 mol% H2S can be present.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate for carbon steel is 0.14 mm per year. The maximum expected

total corrosion for carbon steel in 25 years lifetime is expected to be 3.6 mm. Therefore therecommended material selection is CS + 6 mm CA. Sour service and HIC requirements shall befulfilled.

The bottom outlet piping of the Existing (Sweet) Primary Separator containing oil has amaximum estimated water cut of 20wt%. Therefore the oil is considered to be mildly corrosive

to carbon steel. The recommended material selection is CS + 3 mm CA. Sour service and HICrequirements shall be fulfilled due to the presence of H2S.

The bottom outlet piping containing separated water is fully water wetted. Corrosion inhibitor isavailable. The total expected corrosion, based on the availability model calculations, for carbon

steel is 3.1 mm for 25 years. Also some H2S is present. Therefore the recommended materialselection is CS + 3 mm CA + sour service + HIC requirements.

The crude piping from wells, upstream the separator has a maximum estimated water cut of

60wt%. Therefore the crude piping is considered to be water wetted. Corrosion inhibitor is

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injected downstream wells heads. The recommended material selection is CS + 3 mm CA. Sourservice and HIC requirements shall be fulfilled.


4.2.4 Inlet Heaters E-105 and E-106The process side of the inlet heater E-106 is crude from wells, containing 0.3 mol% CO 2 and0.06 mol% H2S. The normal operating temperature is 50C. The recommended materialselection for process side is CS + 3 mm CA. Sour service and HIC requirements shall befulfilled.

The process side of the inlet heater E-105 is crude from wells, containing 3 mol% CO 2 and 2.4mol% H2S. The normal operating temperature is 50C. The recommended material selection forprocess side is CS + 6 mm CA. Sour service and HIC requirements shall be fulfilled.

As no corrosion allowance could be applied on tubes of heat exchangers, CRA shall be selected.Thus alloy 825 shall be selected for inlet heaters E-105 and E-106 tubes.The tube sheet for inlet heaters E-105 and E-106.is recommended to be made from CS + alloy

825 overlay. If more economic the tube sheet can be made from solid alloy 825. Sour servicerequirements shall be fulfilled.The hot water side is connected to the closed Hot Water System. This hot water is assumed tobe properly treated and thus mildly corrosive. Therefore the recommended material selection for

the hot water side is CS + 3 mm CA.

4.2.5 FZ Crude Dehydrator V-100 (system AK)The Booster pumps P-109 A/B and P-108 A/B upstream the FZ Crude Dehydratorrecommended material selection is carbon steel for casing and 12%Cr impeller. NACE

MR0175/ISO15156 requirements shall be fulfilled.The piping upstream the FZ Crude Dehydrator V-100 can be made from CS + 3 mm CA + sourservice + HIC requirements.The oil containing piping downstream the FZ Crude Dehydrator V-100 has a water cut of 1wt%.Therefore the piping is considered to be oil wetted. Therefore the recommended materialselection is CS + 3 mm CA. Due to the possible presence of H2S, sour service requirementsshall be fulfilled.

Water containing piping downstream the FZ Crude Dehydrator shall be made from CS + 3 mmCA. Due to the possible presence of H2S, sour service and HIC requirements shall be fulfilled.

The recommended material selection for the new FZ Crude Dehydrator V-100, based on thegiven process conditions, is CS + 3 mm CA + glass flake lining and shall be cathodically

protected by anodes. Sour service and HIC requirements shall be fulfilled.

4.2.6 Existing Test Separator 04-C-04 (system CJ)The Existing Test Separator vapour outlet piping has an estimated operating temperature of50C and a normal operating pressure of 18 Bara. When sour wells are connected, the CO 2content in the gas phase is 5.1 mol%. Also 2.8 mol% H2S can be present.Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate for carbon steel is 0.29 mm per year.

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When sweet wells are connected to the existing test separator the vapour outlet piping has thesame operating temperature and pressure. The CO2 content in the gas phase is 2.1 mol%. Also0.5 mol% H2S can be present.Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate for carbon steel is 0.16 mm per year.

Assumed is, that the sour and sweet wells are connected for almost the equal amount of time tothe existing Test Separator. The anticipated total corrosion over 25 years, based on 50% timereceiving sour and 50% of time receiving sweet crude is 5.7 mm. Therefore the recommendedmaterial selection is CS + 6 mm CA. Sour service and HIC requirements shall be fulfilled.

Bottom outlet piping of the Existing Test Separator containing oil has an estimated water cut of22wt%. Therefore the oil piping is considered to be mildly corrosive to carbon steel. Therecommended material selection is CS + 3 mm CA. Sour service and HIC requirements shall befulfilled due to the presence of H2S.

The bottom outlet piping containing separated water is fully water wetted. Corrosion inhibitionis foreseen. The total expected corrosion, based on the availability model calculations, forcarbon steel is 3.9 mm. Also some H2S is present. Therefore the recommended materialselection is CS + 6 mm CA + sour service + HIC requirements.

The crude piping from wells upstream separator has an estimated water cut of 77wt%. Thereforethe crude piping is considered to be water wetted. Corrosion inhibition is foreseen. The

recommended material selection is CS + 6 mm CA. Sour service and HIC requirements shall befulfilled.

It is assumed that the existing test separator is suitable and fit for the purpose condition forfuture 25 years operation.

4.2.7 Test Inlet Heater E-107The process side of the test inlet heater E-107 is crude from the wells, containing 5.1 mol% CO2and 2.75 mol% H2S. The normal operating temperature is 50C. The recommended materialselection for process side is CS + 6 mm CA. Sour service and HIC requirements shall befulfilled.

The hot water side is connected to the closed Hot Water System. This hot water is assumed tobe properly treated and thus mildly corrosive. Therefore the recommended material selection forthe hot water side is CS + 3 mm CA.The tubes are recommended to be made from alloy 825. Sour service requirements shall befulfilled.

The tube sheet is recommended to be made from CS + alloy 825 overlays. If more economic thetube sheet can be made from solid alloy 825. Sour service requirements shall be fulfilled.

4.2.8 HP Gas Separator V-103 (system AM)The HP Gas Separator vapour outlet piping has a normal operating temperature of 39C. Thenormal operating pressure is 50 Bara. The maximum CO2 content in the gas phase is 0.9 mol%.No H2S is or will be present, because the dedicated wells are sweet and without gas lift, thus nosouring of the well will occur.

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Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate for carbon steel is 0.12 mm per year. The maximum expectedtotal corrosion for carbon steel in 25 years lifetime is expected to be 3.1 mm. Therefore therecommended material selection is CS + 3 mm CA. However, since all carbon steel processpiping classes will fulfill sour service requirements, also the vapour overhead piping shall fulfillsour service requirements.

The oil containing piping downstream the HP Gas Separator has negligible water cut. Thereforethe piping is considered to be oil wetted. However, due to the presence en CO2, therecommended material selection is CS + 3 mm CA. Since all carbon steel piping classes willfulfill sour service requirements, also the oil piping shall fulfill sour service requirements.The bottom outlet piping containing separated water is fully water wetted. Corrosion inhibition

is foreseen. The total expected corrosion, based on the availability model calculations, forcarbon steel is 2.5 mm. Therefore the recommended material selection is CS + 3 mm CAHowever, since all carbon steel process piping classes will fulfill sour service requirements, alsothe water piping shall fulfill sour service requirements.

The gas piping from wells upstream the separator has negligible water cut. Corrosion inhibitionis foreseen. The recommended material selection is CS + 3 mm CA. However, since all carbonsteel process piping classes will fulfill sour service requirements, also these piping shall fulfillsour service requirements.

The recommended material selection for the new HP Separator V-103, based on the givenprocess conditions, CS + 3 mm CA + Epoxy novolac lining and shall be cathodically protected.

Sour service requirements shall be fulfilled.

Internals of SS 316L to be used

4.2.9 Sour Slug Catcher V-202 (system AY)The Sour Slug Catcher vapour outlet piping has a normal operating temperature of 28C. Thenormal operating pressure is 18 Bara. The maximum CO2 content in the gas phase is 3.4 mol%.Also 2.5 mol% H2S can be present.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate for carbon steel is 0.1 mm per year. The maximum expected


The bottom outlet piping of the Sour Slug Catcher is fully water wetted. Corrosion inhibition isforeseen, then maximum expected corrosion rate for carbon steel is 0.12 mm per year. The

maximum expected total corrosion for carbon steel in 25 years lifetime is expected to be 2.6 mm.Therefore the recommended material selection is CS + 3 mm CA. Sour service and HICrequirements shall be fulfilled.

The upstream hydrocarbon vapour piping has a normal operating temperature of 28C. The

normal operating pressure is 18 Bara. The maximum CO2 content in the gas phase is 3.4 mol%.Also 2.5 mol% H2S can be present. Corrosion inhibition is foreseen.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, the

maximum expected corrosion rate for carbon steel is 0.1 mm per year. The maximum expected

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The recommended material selection for the new Sour Slug Catcher is CS + 3 mm CA + glassflake lining and shall be cathodically protected. Sour service and HIC requirements shall befulfilled.


4.2.10 FX Crude Dehydrator V-102 (system AZ)In the FX Crude Dehydrator water and oil are separated. The downstream oil piping has anestimated water cut of 1wt%. However, due to the presence en CO2 and H2S, the recommendedmaterial selection is CS + 3 mm CA + sour service + HIC requirements.

The downstream water piping material selection is CS + 3 mm CA + sour service + HIC

requirements. HIC requirements shall be fulfilled, because the piping is continuous water wettedand H2S is present.

The FX Crude Dehydrator material selection is CS + 3 mm CA + glass flake lining and shall becathodically protected. Sour service and HIC requirements shall be fulfilled.

4.2.11 FX Inlet Heater E-108 (system DJ)The process side of the test inlet heater E-108 is oil from the existing oil pipeline. The normaloperating temperature is 50C. The recommended material selection for process side is CS + 3mm CA. Sour service and HIC requirements shall be fulfilled.The hot water side is connected to the closed Hot Water System. This hot water is assumed tobe properly treated and thus mildly corrosive. Therefore the recommended material selection for

the hot water side is CS + 3 mm CA.

The tubes are recommended to be made from CS. Sour service and HIC requirements shall befulfilled. The tube sheet is recommended to be made from CS + 6 mm CA. Sour service andHIC requirements shall be fulfilled.

4.2.12 Produced Water Degasser V-306 (system AL)The piping containing water downstream the Produced Water Degasser material selectionrecommendation is CS + 3 mm CA. Sour service and HIC requirements shall be fulfilled.

The Produced Water Degasser material selection is CS + 3 mm CA + glass flake lining and shallbe cathodically protected. Sour service and HIC requirements shall be fulfilled.

Piping to flare can be made from CS + 3 mm CA + sour service and HIC requirements.


4.2.13 Water Treatment Package U-311The Water Treatment Package U-311 material selection shall be confirmed by Vendor. This

includes Sour Hydrocyclone X-302, Sweet Hydrocyclones X-300 A/B and X-301, Test

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Hydrocyclone X-303, Degasser Hydrocyclone X-304 A/B and Degasser Flotation Unit V-307.Due to the presence of H2S, all equipment shall fulfill sour service (NACE MR0175/ISO15156)requirements (and HIC requirements for carbon steel pressure parts).

The piping containing water, which will be discharged to sea, will be discharging waterapproximately 30 meters below seawater level. Thus the water will not come in contact with air.However, sour gas will be present in the discharged water. Therefore the recommended material

selection is GRE. Alternatively, CS + 3 mm CA and sour service requirements can be used.Assumed is that the carbon steel is suitably protected against seawater corrosion and pittingfrom the inside and outside.

Piping to the closed drain header can be made from CS + 3 mm CA. Sour service and HIC

requirements shall be fulfilled. For Equipment of the package (V-307), refer clause no. 5.2.

4.2.14 Existing Intermediate Separator 04-C-03 (system AL)The Existing Intermediate Separator vapour outlet piping has a normal operating temperature of

45.7C. The normal operating pressure is 15 Bara. The maximum CO2 content in the gas phaseis 4.7 mol%. Also 3.9 mol% H2S can be present.

Based on the DeWaard-Milliams nomogram and vapour under condensing conditions, themaximum expected corrosion rate for carbon steel is 0.22 mm per year. The maximum expectedtotal corrosion for carbon steel in 25 years lifetime is expected to be 5.3 mm. Therefore therecommended material selection is CS + 6 mm CA. Sour service and HIC requirements shall be

fulfilled.The downstream oil piping has an estimated water cut of 2.7wt%. However, due to the presence

en CO2 and H2S, the recommended material selection is CS + 3 mm CA + sour service + HICrequirements.

It is assumed that the existing test separator is suitable and fit for the purpose condition forfuture 25 years operation.

4.2.15 Crude Booster Pumps P-100 A/B/C (system AS)The oil, which is pumped by the Crude Booster pumps, has a water cut of 2.7wt%. Thereforethe oil is considered to be non-corrosive to carbon steel. Also H2S is considered to be present.The recommended material selection for Crude Booster pump is carbon steel for casing and

12%Cr impeller. NACE MR0175/ISO15156 requirements shall be fulfilled. Due to the presenceen CO2 and H2S, the recommended material selection for piping downstream the Crude BoosterPump is CS + 3 mm CA + sour service + HIC requirements.

4.2.16 First Stage Suction Drum V-206 A/B (system CG)The combined vapour outlet piping from the separators upstream the First Stage Suction drumhas a normal operating temperature of 45C and a normal operating pressure of 17 bara. TheCO2 content in the gas phase is 4 mol%. Based on the DeWaard-Milliams nomogram andvapour under condensing conditions, the maximum expected corrosion rate for carbon steel is

0.21 mm per year.

The recommended material selection for the upstream piping is CS + 6 mm CA. Sour serviceand HIC requirements shall be fulfilled. Piping shall be slope and without pockets. The

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corrosion allowance is selected, based on the vapour outlet piping of the existing separatorsworst case scenario.

The material selection for the First Stage Suction Drum is recommended to be CS + 3 mm CA +glass flake lining. Sour service and HIC requirements shall be fulfilled.

The vapour outlet piping downstream the First Stage Suction Drum can be made from CS + 6

mm CA. Sour service and HIC requirements shall be fulfilled.

The bottom liquid outlet piping recommended material selection is CS + 3 mm CA. Sourservice requirements shall be fulfilled. HIC is not required, because the piping will be usedintermittent.


4.2.17 1st Stage Gas Lift Compressor U-217 A/B and 1st Stage Cooler (system DG)The recommended material selection for the First Stage Gas Compressor is carbon steel forcasing. The material selection for impeller shall be stainless steel type 316. Due to the presenceof H2S the compressor materials shall fulfill NACE MR0175/ISO15156 requirements. Piping

downstream the compressor is considered to be dry. Therefore the corrosion is assumed to benegligible. The recommended material selection is CS + 1 mm CA + sour service requirements.

The first Stage Cooler headers shall be made from Alloy 825. The tubes shall also be made from

alloy 825. Due to the presence of H2S sour service requirements shall be fulfilled. Pipingdownstream the first stage cooler shall be made from alloy 825. Sour service requirements shall

be fulfilled.

4.2.18 Gas Dehydration Package U-218The Gas Dehydration Package U-218 material selection shall be confirmed by Vendor. Thisincludes Gas Lift Glycol Contactors C-205 A/B and TEG Regeneration Unit U-211. Due to thepresence of H2S, all equipment shall fulfill sour service (NACE MR0175/ISO15156)requirements.

4.2.19 2nd Stage Suction Drum V-207A/B (system EG)The second Stage Suction Drum downstream the gas dehydration package has a normal

operating pressure of 54 Bara and a normal operating temperature of 49C. The hydrocarbongas is dried upstream in the gas dehydration package. Therefore the hydrocarbon vapour isconsidered to be dry and thus non-corrosive to carbon steel. The recommended materialselection for upstream and downstream piping is CS + 1 mm CA. Due to the presence of H 2S(2.7 mol%) sour service requirements shall be fulfilled.

The Second Stage Suction Drum V-207A/B recommended material selection is CS + 3 mm CA+ sour service requirements.

Assumed that the Gas Dehydration Package cannot and will not be by-passed. Thus only driedgas will enter the downstream piping and equipment.


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4.2.20 2nd Stage Gas Lift Compressor U-217 A/BThe second Stage Gas Lift Compressor material selection is carbon steel for casing. Thematerial selection for impeller shall be stainless steel type 316. Due to the presence of H2S, thecompressor materials shall fulfill NACE MR0175/ISO15156 requirements.

4.2.21 2nd Stage Cooler E-215 A/BThe second Stage Cooler material selection is CS + 3 mm CA for header. Due to the presence ofH2S sour service requirements shall be fulfilled. The tubes can also be made from CS.

Downstream piping containing lift gas can be made from CS + 1 mm CA. Sour service

requirements shall be fulfilled.

During blow down, the temperature of blow down piping can become as low as 90C (due tothe Joule-Thompson effect). At this low temperature carbon steel will be brittle. To prevent lowtemperature embrittlement, austenitic stainless steel shall be selected. Therefore the

recommended material for blow down piping is SS316L, which shall be sufficiently protectedagainst chloride corrosion from the outside. Due to the possible presence of H2S, sour servicerequirements shall be fulfilled.

4.2.22 Closed Drain Vessel V-309The recommended material selection for Closed Drain Vessel is CS + 3 mm CA + glass flake

lining and shall be cathodically protected. Sour service and HIC requirements shall be fulfilled.

For the for outlet oil piping of V-309 the water cut can be 15wt% and the CO2 mol% can behigher than 3.5%. Thus 3 mm of corrosion allowance shall be specified for this stream.

The Water Recycle Pump P-308 A/B shall be made from cast steel casing and Ni-resist impeller.

NACE MR0175/ISO15156 requirements shall be fulfilled.The separated oil piping routed to 04-C-03 has an estimated water cut of 6wt%. Therefore therecommended material selection is CS + 3 mm CA. Sour service requirements shall be fulfilled.

The Closed Drain Pump P-310 A/B shall be made from carbon steel casing and 12%Cr impeller.NACE MR0175/ISO15156 requirements shall be fulfilled.

Piping to flare can be made from CS + 3 mm CA + sour service requirements.

4.3 UTILITY SYSTEMS4.3.1 Chemical Injection Piping

For all chemical injection piping except hypochlorite injection, SS 316L is selected.

4.3.2 Chemical Injection PackageFor chemical injection packages, normally SS 316L is applied.If package suppliers have other standard materials, vendor proposed materials may be appliedinstead.

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4.3.3 Diesel SystemAll (clean) diesel piping and equipment can be made of CS with 1 mm corrosion allowance.

4.3.4 Domestic water SystemFor the domestic water systems, the recommended material selection for piping is SS316L.However, due to the high ambient temperature and sea climate, SS316L shall be painted to

protect SS316L from chloride attack from the outside.

The domestic water tanks are advised to be CS + 3 mm CA with Phenolic epoxy / Polyamineadduct, cured epoxy internal lining and shall be cathodically protected.

For the pumps stainless steel type 316 is selected.

The domestic water maker on FZ-A material selection shall be by Vendor.

4.3.5 Fire Water and Utility Water SystemThe fire water and utility water system will be seawater. The firewater piping, which will beconstantly under pressure, is advised to be made of GRE. Because of the high blackbody

temperature of 85 C, not all GRE types have a suitable pressure/temperature rating.Alternatively, Cu-Ni 90/10 (UNS C70600) or cement lined pipe can be applied. For the firewater pumps, Ni-Al Bronze can be applied (see note 4 in section 6).

The deluge systems can be made from Cu-Ni 90/10 (UNS C70600).The utility water piping system can be made from Cu-Ni 90/10 (UNS C70600).

4.3.6 Fuel Gas PackageThe purpose of the fuel gas package (FZ-A-U-402) is cleaning and superheating the watersaturated vapour so it can be used in power generating turbines. Materials are at manufacturers

proposal but general considerations are given. The inlet can be made of CS + 3 mm corrosionallowance providing it is made slope without any pockets. Fuel gas filters receive watersaturated vapor. To prevent condensation related corrosion the shell is advised to be made of CS+ 3 mm corrosion allowance with epoxy coating or SS316L. Internals can be made of SS 316L.Due to the possible presence of H2S, sour service requirements shall be fulfilled.

4.3.7 Hypochlorite Injection PackageHypochlorite is very corrosive to most metals. A non-metallic like PVDF may be used. Ifpackage suppliers have other standard materials, vendor proposed materials may be appliedinstead.

4.3.8 Instrument Air SystemAll wet air intake piping is advised to be made of galvanized CS, or alternatively SS 316L. Thedry instrument air piping downstream the instrument air package can be made of CS withminimum corrosion allowance of 1 mm. The instrument airreceivers material selection shall becarbon steel with 3 mm corrosion allowance.

4.3.9 Open Drain System

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The preferred material for the atmospheric, produced water piping, leading to the open drainsystem is GRE. GRE is fully corrosion resistant and has a long, maintenance free, life time.Alternatively, CS with 6 mm corrosion allowance could be applied. However, since the water issaline, some chloride pitting and general corrosion will occur.

4.3.10 Closed Drain SystemThe Closed Drain piping material selection recommendation is CS + 3 mm CA. Sour service

and HIC requirements shall be fulfilled.

The Closed drain Vessel material selection is CS + 3 mm CA + glass flake lining and shall becathodically protected. Sour service and HIC requirements shall be fulfilled.

4.3.11 Flare SystemThe flare system is destined for transient service of short duration. Whilst it is designed toaccommodate wet or dry gas, provision is available, by way of the KO drums, to remove liquidphases. Consequently, the time at risk from corrosion is limited. The recommended materialselection is CS + 3 mm CA. Sour service and HIC requirements shall be fulfilled.

Recommended Material of construction for TEG Acid Gas flare system shall be confirmed is as

follows:

Flare Piping MOC: Carbon steel is not recommended. Therefore the minimum corrosionresisting material will be SS 316 L. However solid stainless steel may be subjected toexternal chloride stress corrosion cracking. Therefore it should be externally protectedfrom marine (offshore) environment. To avoid SCC due to chloride (marine environment)the SS pipe may be coated with thermally spread aluminum or the pipe should be SS 316L clad (internally) Carbon steel.

Acid Flare KOD: SS316L Cladded Carbon Steel Acid Flare KOD Pump: Casing shall be Carbon steel and impeller will be SS316L. Flare Tip: Alloy Inconel 625 with SS310L section up to 5 meter below. Flare Structure: Coated carbon steel.

4.3.12

Hot Water system

The hot water system is a closed system and has a normal operating temperature of 160C. Thishot water is assumed to be properly treated and thus mildly corrosive to carbon steel. Thereforethe recommended material selection for the hot water system is CS + 3 mm CA for piping. Thehot water vessel can be made from CS + 3 mm CA. The hot water pump can be made fromcarbon steel casing and 12%Cr impeller. The dump cooler can be made from CS + 3 mm CA forheader and CS tubes.

4.3.13 Nitrogen SystemNitrogen is considered to be non-corrosive to carbon steel. Therefore piping shall be made from

carbon steel with 1 mm CA. Also nitrogen receivers shall be made from carbon steel with 1 mmcorrosion allowance.

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4.4 CORROSION MONITORINGBecause for the main piping within the scope of this project corrosion mitigation is based oninhibition, it is considered essential that corrosion monitoring is an integral part of the design.Monitoring of corrosion rates will reduce the overall risk by providing an early-warning of highcorrosion rates and is required to verify inhibitor performance. Also the results of the corrosionmonitoring program can be used as input for predictive maintenance. A corrosion assessment

should not be based on one single measurement technique. Data obtained by several methods,including direct wall thickness measurements, should be combined to complement each one andto filter out anomalies.

Generally a complete picture with respect to the corrosiveness of a system shall be obtained by

combining the results of:

direct (wall thickness) measurements analysis of produced fluids analysis of the operating conditions monitoring of corrosiveness (by probes or coupons)A major contributor to the actual value of corrosion monitoring is the monitoring and analysisof actual operating data. Only interpreted in conjunction with the operating data, the corrosionmeasurements become valuable. Furthermore, the produced fluids shall be analyzed regularly.

A series of corrosion monitoring stations will be set up involving the use of corrosion coupons

(CC) and corrosion probes (CP) at the following locations:

Platform Location Type Quantity P&ID

F15 Lift Gas CC + CP 3 FD530-FX00-PR-PI-1001-08

FX FX Sour Gas CC + CP 1 FD530-FX00-PR-PI-1001-01

FZ FZ Manifold CC + CP 1 FD530-FZ-A-PR-PI-1001-04

FZ Lift Gas CC + CP 3 FD530-FZ-A-PR-PI-1001-16

FZ Export Gas CC + CP 1 FD530-FZ-A-PR-PI-1001-17

FZ FZ Sour Gas Pig Receiver CC + CP 1 FD530-FZ-A-PR-PI-1001-20

F2F-2 Satellite WellheadManifolds

CC + CP 1 FD530-F-02-PR-PI-1002-01

F2, F8, F9,F14, F17

Pig Launcher CC + CP 1 FD530-0000-PR-PI-1002-03


CC + CP 1 FD530-F-14-PR-PI-1002-01


CC + CP 1 FD530-F-08-PR-PI-1003-01


CC + CP 1 FD530-F-09-PR-PI-1003-01

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5. NEW MECHANICAL EQUIPMENT SUMMARY5.1 FX AREA

Tag numberEquipment

NameMaterial Selection

FX-00-P-100A/B

Sour TransferPumps

Casing: CS (Note 3)Impeller: 12%Cr (Note 3)

FX-00-P-101

A/B

Sweet Transfer

Pumps

Casing: CS (Note 3)

Impeller: 12%Cr (Note 3)

FX00-L-200

Sour Gas pig

Launcher CS + 6 mm CA (Note 2)

5.2 FZ AREATag number

Equipment

NameMaterial Selection (Note 7)

FZ-A-V-100FZ Crude

DehydratorCS + 3 mm CA + glass flake lining + CAT (note 2)

FZ-A-V-103 HP Gas SeparatorCS + 3 mm CA + epoxy novolac lining + CAT(note 1)

FZ-A-V-102FX CrudeDehydrator CS + 3 mm CA + glass flake lining + CAT (note 2)

FZ-A-V-202 Sour Slug Catcher CS + 3 mm CA + glass flake lining + CAT (note 2)

FZ-A-V-306Produced WaterDegasser

CS + 3 mm CA + glass flake lining + CAT (note 2)

FZ-A-V-309Closed Drain

VesselCS + 3 mm CA + glass flake lining + CAT (Note 2)

FZ-A-V-206 A/B1st Stage SuctionDrum

CS + 3 mm CA + glass flake lining (note 2)

FZ-A-V-207 A/B2nd Stage SuctionDrum

CS + 3 mm CA (Note 1)

FZ-A-V-602FZ-A Flare K.O.

DrumCS + 3 mm CA (Note 2)

FZ-A-E-105 Inlet Heater

Process side: CS + 6 mm CA (Note 2 & 3)

Hot Water side: CS + 3 mm CATubes: alloy 825 (Note 1)Tube sheet: CS + Alloy 825 weld overlay (note 1),if more economic solid alloy 825 (Note 1)

FZ-A-E-106 Inlet Heater


Hot Water side: CS + 3 mm CATubes: alloy 825 (Note 1)Tube sheet: CS + Alloy 825 weld overlay (note 1),

if more economic solid alloy 825 (Note 1)

FZ-A-E-107 Test Inlet Heater


Hot Water side: CS + 3 mm CATubes: alloy 825 (Note 1)Tube sheet: CS + Alloy 825 weld overlay (note 1),if more economic solid alloy 825 (Note 1)

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Tag number EquipmentName

Material Selection (Note 7)

FZ-A-E-108 FX Inlet Heater

Process side: CS + 3 mm CA (Note 2 & 3)Hot Water side: CS + 3 mm CATubes: CS (Note 2)Tube sheet: CS + 6 mm CA (Note 2 & 3)

FZ-A-E-214 A/B 1st Stage CoolerHeader: Alloy 825 (Note 1)Tubes: Alloy 825 (Note 1)

FZ-A-E-215 A/B 2nd Stage CoolerHeader: CS + 3 mm CA (Note 1)Tubes: CS (Note 1)

FZ-00-P-108 A/B Booster Pump Casing: CS (Note 3) Impeller: 12%Cr (Note 3)

FZ-00-P-109 Booster Pump Casing: CS (Note 3) Impeller: 12%Cr (Note 3)

FZ-00-P-100A/B/C

Crude BoosterPump

Casing: CS (Note 3) Impeller: 12%Cr (Note 3)

FZ-A-P-308 A/BWater RecyclePump

Casing: CS (Note 3) Impeller: Ni-resist (Note 3)

FZ-A-P-310 A/BClosed DrainPump


FZ-A-P-602 A/BFZ-A Flare KODrum Pumps


FZ-A-U-218 Gas DehydrationPackage

Manufacturers Proposal (Note 1). However, it shallsatisfy below mentioned minimum requirement:

ContactorCS + 3 mm SS316L cladding frombottom of vessel to chimney tray & CS + 3 mmCA from chimney tray to top of vessel

(provided CS =SA 516 Gr. 70).

Reflux Coil - SS 316L Flash DrumCS + 3 mm CA + Glass flake

vinyl ester lining.

FilterAs per client MOC shall be SS 316 L,vendor to confirm.

Lean rich exchangersSS 316 L (Note: Gasketshall be metal reinforced flexible graphite

type).

Still ColumnSS 316 L Re-boiler - SS 316 L cladded Carbon Steel (SA

516 Gr70).

Stripping Column - CS + 3 mm CA Surge DrumCS + 3 mm CA Glycol Circulation PumpCasing: CS;

Impeller / Plunger : SS

Lean Glycol Cooler -: Tube: SS 316 L withextruded fin of aluminum (Al 3003Not

accepted)

Still Column CondenserTube: SS 316 L withextruded fin of aluminum

Drain PotCS + 3 mm SS 316 L cladded Storage TankCS + 3 mm CA BlowerSS 316 L Condensate Pump - Casing: CS; Impeller: SS

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316 L

Chemical Storage Tank & PumpSS 316 L

FZ-A-U-311Water TreatmentPackage

CS + 1 mm CA + internal lining + CAT orManufacturers Proposal (Note 2, 7)

Hydrocyclones - CS (Note 2 & 3)+ 6 mm CA +Internal Lining (note 7)IGF (V-307) - CS + 1 mm CA + internal lining +CAT (note 7)or For Item no- X-301/302 CS + DSS Cladding

(Note 1) & for Item no.X-300/303/304/305/306CS + Alloy 825 Cladding (Note 1)or Manufacturers Proposal (Note 2)

FZ-A-L-201Sour Gas PigReceiver

CS + 6 mm CA (Note 2)

FZ-A-L-208Export Gas Pig

LauncherCS + 6 mm CA (Note 2)

U-2171

stand 2

ndStage

Gas LiftCompressor

Casing: Carbon SteelImpeller: SS316L(Note1)

5.3 UTILITY SYSTEMSTag number

Equipment

NameMaterial Selection (Note 7)

FZ-A E-508Hot Water DumpCooler

Header: CS + 3 mm CATubes: CS

FZ-A-P-509 A/B Hot water pump Casing: CS Impeller: 12%Cr

FZ-A-V-511 Hot water vessel CS + 3 mm CA Internals of SS 316L to be used

FZ-A-T-609Open DrainVessel

CS + 3 mm CA + glass flake lining + CAT (Note 2)

FZ-A-P-608 A/B Open drain pump SS316 or Manufacturers Proposal

FZ-A-T-404Diesel storage

tankCS + 1 mm CA + internal lining

FZ-A-U-403Diesel SupplyPackage

CS or Manufacturers proposal

FZ-A-U-402 Fuel gas PackageCS + 3mm CA + epoxy coating or SS316Lor Manufacturers proposal (Note 1)

FZ-A-U-505Firewater pumppackage

Ni-Al Bronze (UNS C 95800) or ManufacturersProposal

FY-A-U-501Firewater pumppackage

Ni-Al Bronze (UNS C 95800) or ManufacturersProposal

FY-A-P-505 A/B Jockey pump Ni-Al Bronze (UNS C 95800)FY-A-P-508 A/B Open Drain Pump Casing & Impeller: SS316L

FZ-A-U-606 A/BNitrogengenerationpackage

CS orManufacturers proposal

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FZ-A-V-610 Nitrogen receiver CS + 1 mm CA

FZ-A-V-405Instrument airreceiver

CS + 3 mm CA

FY-A-V-405Instrument AirReceiver

CS + 3 mm CA

FY-A-U-406Instrument airpackage

CS + 3mm CA orManufacturers proposal

FY-A-P-502

A/B/C

Domestic water

pumpSS316

FY-A-T-503 Domestic watertank

CS + 3 mm CA + Phenolic epoxy / Polyamine

adduct, cured epoxy internal lining + CAT orManufacturers proposal

FY-A-T-509 Open Drain Tank CS + 3 mm CA + glass flake lining + CAT (Note 2)

FY-A-U-500Domestic water

maker

Manufacturers proposal However, it shall satisfybelow mentioned minimum requirement:

Filters25% Cr Duplex SS High Pressure PumpImpeller, shaft and casing

all shall be 25% Cr duplex SS.

Chemical injection packageSS 316L. Cleaning in place unit - Pump: SS 316L; Tank:

SS 316 L / Carbon Steel + glass flake vinyl ester

lining; Mixer: SS 316L; Filter housing: SS 316L

RO membranesVessel: Carbon Steel + glassflake vinyl ester lining; Membrane: Polyamid /

PolySulfon

FY-A-U-504 Sterilizer PackagePVDF or HDPE or PVC-C or Manufacturersproposal

FY-A-U-507Hypochloriteinjection package

PVDF or HDPE or PVC-C or Manufacturersproposal

FY-A-U-600Sewage watertreatment package

CS or Manufacturers proposal

FY-A-U-701 AFFF Package GRE or Manufacturers proposal

U-613Chemicalinjection package

SS 316L or Manufacturers proposal

F-02-V-301Closed DrainVessel

CS + 3 mm CA + internal lining + CAT (Note 2,7)





F-14-V-301 Closed DrainVessel




F-02-L-201 Pig Launcher CS +1.5 mm, (Note 2 & 3)

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FY-A-E-607Cold & freezerroom condenser

Condenser Tubes / Fin : Copper / CopperFrame: SS316L

FY-A-U-421Emergencygenerationpackage

As per Manufacturers Proposal but subjected to itssuitability in offshore marine environment.

FY-A-U-633 A/B HVAC UnitCoil Tube / Fin: Copper / CopperFrame: SS316L

FZ-A-E-508WHRUExchanger

Coil Tube / Fin: A335P11 / 409SS (1113 Cr)Casing: S275

FZ-A-U-400Gas TurbineGeneratorPackage

Compressor Casing: BS2789 Gr 420/12Combustor Casing: BS2789 Gr 420/12Turbine Casing: BS2789 Gr 420/12

FZ-A-E-400Lube oil coolergenset

As per Manufacturers Proposal but subjected to itssuitability in offshore marine environment.

6.

ADDITIONAL SERVICE REQUIREMENTS

Note 1: Equipment is subject to Sour Service requirements.

Note 2: Equipment is subject to Sour Service and Hydrogen Induced Cracking (HIC)requirements.

Note 3: Materials will be exposed to sour environment, and shall be in accordance with NACEMR0175/ISO15156.

Note 4: for seawater pumps the following materials can be used: Ni-Al Bronze UNS C 95800;or super duplex with a PRE -Resist A439-D2 heat treated.

Note 5: DELETED.

For Sour Service and HIC requirements, see project specification Requirements for Materialsin Wet H2S Service, document numberFD534-0000-MW-SP-1002.

Note 6: All package equipment material including but not limited to equipment material,piping material and instrument material shall be proposed by the vendor. The sameshall be used only after confirmation / approval from IOEC/ PEDCO.

Note7: Refer document number FD534-0000-MW-SP-1027for suitable internal lining materialand paintings detail.

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7. APPENDIX A: CORROSION CALCULATIONS

Strea

m

T

(C)

P

(Ba

ra)

CO2

(Mol

%)

Conde

nsation

factor

Inhibitio

n

efficienc

y (%)

Vcorr

(mm/

yr)

Desig

life

(yrs)

Total

Corrosi

on (mm)

Selecte

d

Materi

al

NACE

MR

0175 /

ISO

15156

HI

C

108 33.9 25 3.8 0.1 0.16 25 4.1CS + 6

mm

CA

y y

112 33.9 253.8

(*)

1 98 0.13 25 3.3CS + 6

mm

CA

y y

102 42.7 25 2.9 0.1 0.19 25 4.9CS + 6

mmCA

y y

106 42.7 252.9(*)

1 98 0.13 25 3.4CS + 6

mmCA

y y

202 28.2 19 0.25 1 98 0.10 25 2.5CS + 3

mmCA

y y

208 50.0 18 0.25 1 98 0.11 25 2.7CS + 3

mmCA

y y

209 50.0 18 1.6 0.1 0.14 25 3.5CS + 6

mmCA

y y

213 50.0 181.6(*)

1 98 0.13 25 3.1CS + 3

mmCA

y y

246 28.4 19 3 1 98 0.12 25 2.9

CS + 3

mmCA

y y

247 50.0 18 3 1 98 0.14 25 3.5

CS + 6

mmCA

y y

250 50.0 18 5.1 0.1 0.30 25 7.6Alloy825

y y

254 50 185.1(*)

1 98 0.16 25 4.0CS + 6

mmCA

y y

272 28.0 19 0.7 1 98 0.1 25 2.6CS + 3

mmCA

y

275 28.0 19 1 0.1 0.03 25 0.85CS + 3

mm

CA

y

300 45.4 17.7 4 0.1 0.21 25 5.3CS + 6

mmCA

y y

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Strea

m

T

(C)

P

(Ba

ra)

CO2

(Mol

%)

Conde

nsation

factor

Inhibitio

n

efficienc

y (%)

Vcorr

(mm/

yr)

Desig

life

(yrs)

Total

Corrosi

on (mm)

Selecte

d

Materi

al

NACEMR

0175 /

ISO

15156

HI

C

307 51.2 49.5 3.89 0.1 0.52 25 13.0Alloy825

y y

310 39.0 50 1 1 98 0.12 25 3.1CS + 3

mmCA

y

314 39.0 50 0.90 0.1 0.12 25 3.1CS + 3

mm

CA

y

409 27.9 18.4 3.46 0.1 0.10 25 2.9CS + 3

mmCA

y y

420 45.7 15 4.7 0.1 0.22 25 5.3CS + 6

mmCA

y y

(*) For water piping, the corrosion rate calculation was calculated according the mol % CO2 ingas phase above water in separator

8. APPENDIX B: CORROSION INHIBITOR PHILOSOPHYIt has been common practice for many years to inject corrosion inhibitors into CO2 containingproduction tubing and process streams carried by carbon steel. In exceptional cases inhibitorsare applied as the first line of defense against corrosion in CS lines carrying wet gas fromsatellite well-heads to central gathering facilities where bulk drying can been carried out.Temperature drops can be considerable over such intra-field lines so that condensation of waterand hence corrosion will taken place.For inhibitors to be effective they must be able to contact the internal surface. For tubular whichoperate in the annular flow regime this can be readily achieve using a continuous injectionprocess. For the lines which exhibit stratified flow, however, continuously injected inhibitorsmay only be fully effective along the bottom part of the line. If the estimated corrosion rate for

the top of the line is so high that inhibition is required at the top surface then batch inhibitionhas to be adopted.At design stage an assumption may be made that inhibition can decrease the corrosion rate to0.1 mm/year. This inhibited corrosion rate shall, however, be documented by corrosion test atthe actual conditions are by relevant field or other test data. It should be noted that to achievethe target residual corrosion rate, high dosages of inhibitor may be required.The inhibitor availability to use in design calculation depends on the plan corrosionmanagement program, including corrosion monitoring and corrosion inhibition. Maximuminhibitor availability requires that a qualified inhibitor is injected from day 1 and that a

corrosion management system is inplace to actively monitor corrosion and inhibitor injection.

fd534-0000-mw-rt-1001_d0.pdf

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