30.99.37.1607 r1 (material selection and corrosion control philosophy)

DOCUMENT TITLE:

MATERIAL SELECTION AND CORROSION CONTROL PHILOSOPHY

ADCO DOC. NO. 30.99.37.1607

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ORIGINATOR No. 130710-G-GE-PR-PH-0010

ADCO Project No. P44010

Rev 1 Date : 21.OCT.2014

gWorks/Design Document/4 Engineering/410 Process/415 Specification and Procedure/30.99.37.1607.1

CONTENTS

1 PROJECT SCOPE .............................................................................................................. 4

2 DEFINITIONS & ABBREVIATIONS .................................................................................... 4

2.1 DEFINITIONS ........................................................................................................ 4

2.2 ABBREVIATIONS .................................................................................................. 5

3 PURPOSE OF THIS DOCUMENT ....................................................................................... 5

4 REFERENCES .................................................................................................................... 6

4.1 PROJECT DOCUMENTS ...................................................................................... 6

4.2 COMPANY SPECIFICATION AND DOCUMENTS ................................................ 6

4.3 SHELL DEP STANDARDS .................................................................................... 6

4.4 INTERNATIONAL CODES AND STANDARDS...................................................... 7

4.5 ORDER OF PRECEDENCE .................................................................................. 8

4.6 OTHER REFERENCES ......................................................................................... 9

5 PROJCET DESCRIPTION ................................................................................................ 10

5.1 EXISTING FACILITIES ........................................................................................ 10

5.2 NEW WELLS AND CLUSTERS ........................................................................... 11

5.3 NEW PIPELINES ................................................................................................. 11

5.4 NEW PROCESS FACILITIES AT CPP ................................................................ 12

5.5 UTILITIES ............................................................................................................ 13

5.6 FLUID COMPOSITION ........................................................................................ 13

5.7 DESIGN LIFE ...................................................................................................... 15

6 MATERIAL SELECTION AND CORROSION CONTROL BASIS ..................................... 15

7 ASSUMPTIONS AND UNCERTAINTIES .......................................................................... 16

8 CORROSION AND MECHANISMS ................................................................................... 17

8.1 EXTERNAL CORROSION ..................................................................................... 18

8.2 INTERNAL CORROSION ...................................................................................... 21

8.3 APPLICABLE CORROSION MODELS .................................................................. 30

9. MITIGATION AND CONTROL STRATEGIES .................................................................... 31

9.1 CONTROL OF EXTERNAL CORROSION ............................................................. 31

9.2 CONTROL OF INTERNAL CORROSION .............................................................. 33

9.3 GUIDELINES FOR SELECTION OF VALVES ....................................................... 41

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9.4 GUIDELINES FOR SELECTION OF PUMPS ........................................................ 42

9.5 GUIDELINES FOR SELECTION OF BOLTING ..................................................... 42

10 CORROSION MONITORING............................................................................................... 42

10.1 INTERNAL CORROSION MONITORING .............................................................. 42

10.2 EXTERNAL CORROSION MONITORING ............................................................. 43

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1 PROJECT SCOPE

Abu Dhabi Company for Onshore Oil Operations (ADCO) intends to proceed with phase III of the North East Bab (NEB) development as part of ADCO’s program to add an additional 400 MBOPD sustainable capacity. New processing facilities will be required to handle the additional oil, gas and water production from Al-Dabb’iya and Rumaitha field, located approximately 50km south west from Abu Dhabi. Water and gas injection facilities will also be required to provide pressure support and enhanced oil recovery.

The Project scope of CONTRACTOR covers the Engineering, Procurement and Construction (EPC) of Rumaitha / Shanayel Facilities - Phase III Development Project to handle an additional production of 39 MBOPD Rumaitha and Shanayel fields by 2016. The Contract is as below :

EPC for Rumaitha / Shanayel Phase III Development considering the scenario of Hydrocarbon (HC) Water Alternating Gas (WAG)

2 DEFINITIONS & ABBREVIATIONS

2.1 DEFINITIONS

The following definitions description shall be used where applicable:

CONTRACT : Contract No 15678.01/EC10884 ENGINEERING PROCUREMENT & CONSTRUCTION FOR RUMAITHA / SHANAYEL FACILITIES – PHASE III

COMPANY : Abu Dhabi Company for Onshore Oil Operations (ADCO)

CONTRACTOR : The Consortium of GS E&C – DODSAL

PROJECT : EPC for Rumaitha/Shanayel Facilities – Phase III

SERVICES : All services to be performed or provided by CONTRACTOR under this CONTRACT and such other SERVICES as are related to or incidental to it

VENDOR / SUPPLIER : The person, firm, company or Corporation to whom the Purchase Order is placed including their assignees.

Shall : The word “shall” is understood to be mandatory to comply with the requirements

Should : The word “should” is understood to be strongly recommended to comply with the

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requirements

2.2 ABBREVIATIONS

BTEX Benzene, Toluene, Ethylbenze and Xylene CA Corrosion Allowance CP Cathodic Protection COMPANY ADCO CPP Central Processing Plant CRA Corrosion Resistant Alloy CSCC Chloride Stress Corrosion Cracking CUI Corrosion Under Insulation ECE Electronic Corrosion Engineer FBE Fusion Bonded Epoxy (coating or internal lining) FEED Front End Engineering Design GOR Gas to Oil Ratio HC Hydrocarbon HIC Hydrogen Induced Cracking H&MB Heat and Material Balance KOD Knock-Out Drum LCC Life Cycle Cost MIC Microbiologically Induced Corrosion MBOPD Thousand Barrels of Oil Per Day MBWPD Thousand Barrels of Water Per Day MMSCFD Millions of Standard Cubic Feet Per Day PFD Process Flow Diagram PROJECT Rumaitha – Shanayel Phase III Development SCC Stress Corrosion Cracking SOHIC Stress-Orientated Hydrogen Induced Cracking SSC Sulfide Stress Cracking TDS Total Dissolved Solids UNS Unified Numbering System (of metals and alloys) WAT Wax Appearance Temperature

3 PURPOSE OF THIS DOCUMENT

The purpose of this document is to present the materials selection and corrosion control measures that have to be adopted for the Rumaitha / Shanayel Phase III Development.

The document considers the potential damage mechanisms applicable and describes the philosophy to be adopted to deal with them. It states the methods to be used in calculating corrosion rates, selecting the materials of construction, explains the factors limiting their suitability and discusses other control measures necessary to limit the effects of corrosion, such as the use of coatings and corrosion inhibitors.

It includes also an overview of the corrosion monitoring system to be implemented in order to verify the suitability of the corrosion control measures.

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The philosophy described here is applicable to all pipelines, processing facilities and utility systems included within the Package.

4 REFERENCES

4.1 PROJECT DOCUMENTS

30.99.37.0607 (by FEED)

Material Selection and Corrosion Control Philosophy

30.99.91.1646 Process Design Basis - Package 1 30.99.91.1651 Process Simulation Reports for CPP 30.99.91.1613 Flare, Relief, and Blowdown Study Report for CPP 30.99.37.1610 Painting and Coating of New Equipment 30.99.12.2663 External Pipeline Coatings 30.99.12.2649 Field Joint Coating 30.99.11.2650 Steady State Hydraulics Report for Rumaitha &

Shanayel Oil Gathering Network 30.99.37.1608 Corrosion Monitoring Philosophy 30.99.37.1609 Corrosion Inhibition and Chemical Treatment

Philosophy 30.99.37.1612 Cathodic Protection Systems – Design Basis

4.2 COMPANY SPECIFICATION AND DOCUMENTS

ADCO ES 30-99-00-0102 Corrosion and Materials Selection Philosophy ADCO ES 30-99-00-0107 Chemical Injection Skid ADCO ES 30-99-37-0013 Painting and Coating of New Equipment ADCO ES 30-99-37-0017 External Pipeline Coatings ADCO ES 30-99-37-0001 Cathodic Protection Design ADCO ES 30-99-37-0003 Cathodic Protection Materials and Equipment ADCO ES 30-99-37-0004 Cathodic Protection CIPS and DCVG Surveys ADCO ES 30-99-37-0005 Cathodic Protection Construction, Installation,

Testing and Commissioning ADCO EP 30-99-90-0279 Site Applied Coatings and Cathodic Protection

for Pipeline Sections at Road / Track / Fence Crossings.

ADNOC-COPV6-01 Code of Practice on Identification and Integrity Assurance of HSE Critical Equipment and Systems

4.3 SHELL DEP STANDARDS

DEP 30.10.02.15 Gen Materials For Use In H2S-Containing Environments In Oil And Gas Production

DEP 30.10.02.17 Gen Wet H2S Requirements For Downstream Pressure Vessels And Piping

DEP 30.10.02.11.Gen Metallic materials - Selected standards

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DEP 30.10.02.13 Gen Non-Metallic Materials - Selection and Application DEP 30.10.02.31.Gen Metallic Materials - Prevention Of Brittle Fracture In

New Assets DEP 30.48.00.31.Gen Protective Coatings For Onshore Facilities DEP 31.29.02.30 Gen Centrifugal Pumps (Amendments/Supplements To

ISO 13709:2009) DEP 31.38.01.10 Gen Piping Class- Basis Of Design DEP 31.38.01.11.Gen Piping- General Requirements DEP 31.38.01.15.Gen Piping Classes - Exploration And Production DEP 31.40.10.19 Gen Glass-Fibre Reinforced Plastic Pipeline and

Systems DEP 31.40.20.37 Gen Line Pipe For Critical Service

(Amendments/Supplements To ISO 3183:2007) DEP 39.01.10.11 Gen Selection Of Materials For Life Cycle Performance

(EP) DEP 61.40.20.30 Gen Welding Of Pipelines And Related Facilities

(Amendments/Supplements To ISO13847:2000)

4.4 INTERNATIONAL CODES AND STANDARDS

NACE MR0175/ ISO 15156

Materials for use in H2S-containing environments in oil and gas production

NACE SP-0106 Control of Internal Corrosion in Steel Pipelines and Piping Systems

NACE SP-0169 Control of External Corrosion on Underground or Submerged Metallic Piping Systems

NACE SP-0572 Standard Practice Design, Installation, Operation and Maintenance of Impressed Current Deep Groundbeds

NACE TM-0177 Testing of Metals for Resistance to Sulfide Stress Cracking at Ambient Temperature

NACE TM-0187 Evaluating Elastomeric Materials in Sour Gas Environment n- Item No 21220

NACE SP-0177 Mitigation of Alternating Current and Lightning Effects on Metallic Structures and Corrosion Control Systems

NACE SP-0186 Application of Cathodic Protection for External Surface of Steel Well Casings

NACE RP-0193 External Cathodic Protection of On-Grade Carbon Steel Storage Tank Bottoms

NACE RP-0198 The Control Of Corrosion Under Thermal Insulation And Fireproofing Materials - A Systems Approach

NACE RP-0491 Worksheet for the Selection of Oilfield Non-metallic Seal Systems – Item No 2105

NACE SP-0286 Standard Practice Electrical Isolation of Cathodically Protected Pipelines

NACE RP-0775 Preparation and Installation of Corrosion Coupon and Interpretation of Test Data in Oil Production

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Practice NACE TM-0284 Evaluation Of Pipeline And Pressure Vessel

Steels For Resistance To Hydrogen-Induced Cracking

ASTM A320 Standard Specification for Alloy-Steel and Stainless Steel Bolting for Low Temperature Service

ASTM A193 Standard Specification for Alloy-Steel and Stainless Steel Bolting for High Temperature or High Pressure Service and Other Special Purpose Applications

ASTM A194 Standard Specification for Carbon and Alloy-Steel Nuts for Bolts for HP or HT Service or Both

ASTM D4541-02 Standard Test Method for Pull-Off Strength of Coatings Using Portable Adhesion Testers

ISO 21809-1 Petroleum and Natural Gas Industries – External Coatings for buried or submerged pipelines used in pipeline transportation system – Part 1: Polyolefin Coatings (3-layer PE and 3-layer PP)

ISO 21809-2 Petroleum and Natural Gas Industries – External Coatings for buried or submerged pipelines used in pipeline transportation system – Part 2: Single layer Fusion Bonded Epoxy coatings

ISO 15589-1 Petroleum and Natural Gas Industries – Cathodic protection of pipeline transport systems Part-1: On-land pipelines

SSPC Vol.1 Painting Manual SSPC Vol.2 Systems and Specifications EN ISO 1462 Petroleum and Natural Gas Industries – Glass-

reinforced Plastics (GRP) Piping – Part 3 – System Design (ISO 14692-3)

EFC Publication No. 16 Guidelines on materials requirements for carbon and low alloy steels for H2S-containing environments in oil and gas production.

EFC Document No. 23 CO2 Corrosion Control in Oil and Gas Production ISO 21457 Petroleum, Petrochemical and Natural Gas

Industries – Materials Selection and Corrosion Control for Oil and Gas Production Systems

4.5 ORDER OF PRECEDENCE

All detail design and construction shall be performed in accordance with the Specifications, Standards, Codes, Regulations, Shell DEPs, etc.

In any areas of conflict, detail design and construction shall be performed to the following Regulations, codes and standards, which are in order of precedence:

• The Laws, Standards and Regulations of the United Arab Emirates.

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• ADNOC Codes of Practice.

• Technical Deviations.

• Project Specific Specifications and data sheets, philosophies, Design basis, etc.

• ADCO Procedures and Codes / Standards.

• ADCO Specifications and Engineering Practices.

• ADCO amendments and supplements to Shell DEPs.

• Shell DEPs (Version 32)

• International Codes, Standards and Recommended Practices.

• Internationally recognized Oil and Gas Industry sound practices.

In case of conflict between documents in the same level of hierarchy the most stringent requirement shall apply.

In such cases VENDOR/CONTRACTOR shall provide its interpretation in writing of the most stringent requirement for COMPANY’s approval.

Note: the chemical composition requirements of SHELL DEP 30.10.02.17 (normally applicable to downstream equipment) shall take precedence for the design of Pressure Vessels of the Project, in accordance with Shell DEP 31.22.20.31-Gen (Pressure Vessels-Based on ASME Section VIII).

4.6 OTHER REFERENCES

a. BFM Pots et al, Improvements On De Waard-Milliams Corrosion Prediction And Applications To Corrosion Management, NACE Corrosion 2002, Paper 02235

b. Srdjan Neši , A Multiphase Flow And Internal Corrosion Prediction Model For Mild Steel Pipelines NACE Corrosion 2005, Paper 05556

c. Rolf Nyborg, Overview of CO2 Corrosion Models for Wells and Pipelines NACE Corrosion 2002, Paper 02233

d. Bill Hedges et al., A Prophetic CO2 Corrosion Tool – But When Is It To Be Believed?, NACE Corrosion 2005, Paper 05552

e. Rippon, Carbon Steel Pipeline Corrosion Engineering: Life Cycle Approach, Corrosion 2001, Paper 01055

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f. B Craig, Selection Guidelines For Corrosion Resistant Alloys In The Oil And Gas Industry, Nickel Institute Publication 10073, 2000

g. Michael Swidzinski et al., Corrosion Inhibition Of Wet Gas Pipelines Under High Gas And Liquid Velocities, NACE Corrosion 2000, Paper 00070

h. B Pots et al, Field Study Of Corrosion Inhibition At Very High Flow Velocity, NACE, Corrosion 2003, Paper 03321

i. I Rippon et al, How To Design Corrosion Inhibition Systems For Sour Wet Gas Service, NACE Corrosion 2008, Paper 08643

j. M. Hay, Hydrogen Induced Cracking in Low Strength Steel, ADCO International Corrosion Conference, 2004

k. M. Hay, Environmental Cracking Mechanisms In Sour Service (Sulfide Stress Cracking, Hydrogen Embrittlement Cracking, Synergistic Sulfide-Halide Ion Stress Corrosion Cracking), ADCO International Corrosion Conference, 2004

l. P.R Rhodes, Environment-assisted Cracking of Corrosion-Resistant Alloys in Oil and Gas Production Environments: A Review, Corrosion, Vo. 57, No 11.

m. Yoon- Seok Choi, S. Nesic, Corrosion Behavior of Carbon Steel in Supercritical CO2 – Water Environments, Paper No. 09256, NACE International Corrosion 2009.

n. R.Thodla, F. Ayello, N. Sridhar, Materials Performance in Supercritical CO2 environments, Paper No 09255, NACE International Corrosion 2009.

o. F. Ayello, K. Evans, R. Thodla, N. Sridhar, Effect of Impurities on Corrosion of Steel in Supercritical CO2, Paper 10193, NACE International Corrosion 2010.

p. Yoon-Seok Choi, Srdjan Neši , Effect of Impurities on The Corrosion Behavior of Carbon Steel In Supercritical CO2 – Water Environments, Paper 10196, NACE International Corrosion 2010.

5 PROJCET DESCRIPTION

5.1 EXISTING FACILITIES

The existing development scheme for Rumaitha includes a standalone Central Processing Plant (CPP) along with one centralized gas injection system located at Al-Dabb’iya CPP.

Crude oil is processed independently at CPP. Crude oil processing consists of three phase separation, dehydration and desalting, stabilization, cooling and storage prior to export. Testing is achieved on several clusters by means of test separators.

The produced gas is dehydrated and compressed; the associated gas

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separated is compressed in LP and MP compressors, dehydrated and routed to Al-Dabb’iya. At Al-Dabb’iya the gas from Rumaitha is commingled with:the associated gas from Al-Dabb’iya CPP and the required make-up from off shore gas producer wells and/or lean gas. The gas is then compressed to the injection pressure at Al-Dabb’iya CPP.

WAG (Water Alternate Gas) is implemented at number of injection clusters.

Gas lift is used as an artificial lift method to produce oil from low pressure wells and is mainly required for LP oil producers at Rumaitha.

Utilities are either imported (electricity / fuel gas / diesel / potable water) or generated on site for each CPP (heating medium / air / nitrogen). For clusters, electric power is imported from the CPP. The remote wells are either fed electric power from the CPP or from local solar panels.

5.2 NEW WELLS AND CLUSTERS

The NEB fields (Rumaitha and Shanayel) will be developed by means of clusters, comprising Oil Production Wells, Water Alternating Gas (WAG) Injection Wells and Water Injection (WI) Wells.

In total, there will be 49 new Rumaitha Wells and 19 new Shanayel Wells for a total of 68 wells.

Field No of Producers

No of Injectors

Total no of wells

Rumaitha 25* 24 49 Shanayel 9 10 19

Total 34 34 68 (Note 1) * Including 1 existing well, Ra-40

Note1: Water supply Wells & Water disposal Wells are not included.

5.3 NEW PIPELINES

The scope of NEB3 Package 1 includes gathering pipeline system (flow lines) from Wells to Clusters, Infield Trunk lines taking Rumaitha and Shanayel Wells product from Clusters to CPP, Hydrocarbon Gas Injection pipelines from CPP to Rumaitha & Shanayel Wells, Water Injection pipelines from water producing wells and pumping facilities in CPP to Rumaitha and Shanayel Wells and a CO2 pipeline from CPP to Cluster N to convey the recovered CO2 to the CO2 injection wells.

It also includes Oil Export Pipeline and Water Disposal Pipelines for Produced Water from CPP to Water Disposal Wells.

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5.4 NEW PROCESS FACILITIES AT CPP

Rumaitha / Shanayel Phase III CPP will involve crude oil processing including:

Three–Phase Separation,

Desalting,

Stabilization Unit,

Oil Storage and Export facilities,

Gas Compression Units

Dehydration Unit

CO2 Separation and Compression Units (For Future)

The block flow diagram is shown below.

Additional Water Supply Wells are considered for the required water for injection via water injection surface pumps. Additional Disposal Wells are

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considered for the disposal of produced water.

5.5 UTILITIES

The major utility systems considered under the Rumaitha / Shanayel Phase III project are:

Plant Air & Instrument Air System

Nitrogen Generation System

Potable Water System

Vapour Recovery System

Fuel Gas Import and Distribution System

New HP & LP Flare System and Inter connection between the existing HP / LP Flare system

New Tank Flare System & Inter connection between the existing Tank Flare System

Heating Medium System

Closed Drain & Open Drain System

Fire water system

5.6 FLUID COMPOSITION

The Tables below summarize the available production data and fluid composition.

Producing wells: Although compositional data from individual wells is not available, average values can be derived from Subsurface and Production Basis of Design (ADCO Doc. P44010-44-99-00-0001-1).

Parameter Unit Value Wellhead Flowing Pressure (WHFP) (upstream of choke) barg 25-32

Wellhead Flowing Temperature (WHFT) (downstream of choke) °C 105

Wellhead Closed in Pressure (WHCIP) barg 290 Flow rate per producing well (Mini/Maxi) BOPD 500/4000

CO2 in gas phase (*) (mole %) 2.45 to 5.33% Design: 10%

H2S in gas phase (*) (mole %) 0 to 0.52% Design: 3%

Mercury ppm Nil

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Organic acid ppm No data, assumed Nil

Sand Nil (*) The wells of Package 1 are not expected to see any CO2 breakthrough. The CO2 and H2S contents are taken from the bottomhole sampling from the different production zones as per below Table.

Field Producing zone CO2 (mol %) H2S (mol %)

Rumaitha

Zone BIII 4.27 0.00 Zone BIIIU 2.45 1.3 x 10-4 Zone C 4.10 0.00 Zone D 3.75 0.00 Zone F 4.48 0.52

Shanayel

Zone B 4.27 0.00 Zone C 4.10 0.00 Zone D 5.33 0.03 Zone F 5.26 0.00 Zone G 4.80 0.00

Gas-Lift 4.70 (initial) 5.0 (future)

0.065 (initial) Unknown (future)

CPP Facilities

The new CPP facilities will be exposed to the well fluids as per above Table and to the production of the 8 wells from Package 3. After CO2 breakthrough and after completion of the CO2 Separation Unit, the composition of the fluids shall be modified. Based on H&MB data for years 2043-2044, covering various process alternatives (method of CO2 separation, total or partial separation), the CO2 content (gas phase) shall be taken at 21 mole % and the H2S content (gas phase) at 0 to 325 ppm.

Produced water (typical)

Na+ 61,300 ppm Cl- 130,100 ppm Ca++ 18,100 ppm HCO3

- 200 ppm Mg++ 1,600 ppm SO4

- 150 ppm Fet 18 ppm TDS 212,300 ppm Diss. CO2 1,235 ppm pH 6.12 Diss. H2S 32 ppm

Supply / Injection water

(from representative Ru 064 well)

Wellhead Flowing Pressure : 35 barg

Wellhead Closed in Pressure : 152 barg

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Na+ 72,000 ppm Cl- 162,200 ppm Ca++ 22000 ppm HCO3

- 63 ppm Mg++ 4250 ppm SO4

- 250 ppm Fet 5 ppm TDS 260,800 ppm Diss. CO2 634 ppm pH 5.52 Diss. H2S 51 ppm

Gas Injection (at wellhead)

Parameter HC Gas Injection Max WHIP, barg 379 (5500 psig) Min WHIP, barg 310 (4500 psig) Max flow per well, MMSCFD 10 CO2 (design) (mole %) 10% H2S (design) (mole %) 3 Water (lbs/MMSCF) < 3 Note: The WAG cycle is 6 months gas injection followed by 6 months water injection. Other cases are considered, with 3 months gas injection followed by 15 months water injection or 3 months gas injection followed by 6 months water injection.

Gas Lift (same gas as injection gas)

Lift Gas Duty Unit Value Design lift gas range per well MMSCFD 0.5 to 2.5 Injection pressure (unloading mode) psig Up to 3500

(241 barg) Injection pressure (normal operation) psig 2000 to 2500

(138 to 172.3 barg) CO2 (design) mole % 10 H2S (design) mole % 3 Water lbs/MMSCF < 3

Lean Gas (import)

Component Unit Value N2 Mole % 0.2 CO2 Mole % 2 H2S ppm 50-250

5.7 DESIGN LIFE

A design life of 30 years shall be applied to all surface facilities.

6 MATERIAL SELECTION AND CORROSION CONTROL BASIS

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The present report shall proceed according to the following steps:

Listing the assumptions and uncertainties regarding the fluid composition and other process parameters (see Clause 7, “Assumptions and Uncertainties”).

Assessing the corrosion-related damage mechanisms and likelihood of corrosion failure. (see Clause 8, “Corrosion Damage Mechanisms”). The applicable corrosion models are analyzed as a conclusion of Clause 8.

Evaluating the possible mitigation strategies (use of inert materials and/or coatings and/or cathodic protection and/or inhibition) and the specific monitoring systems to be implemented (see Clause 9, “Mitigation and Control Strategies”). When several solutions are technically acceptable and viable, the candidate solutions are quantitatively evaluated by Life Cycle Cost Analysis (LCC).

7 ASSUMPTIONS AND UNCERTAINTIES

The material selection and corrosion control options for this project have been evaluated on the following assumptions:

• The gas for gas-lift and gas injection is dry. The water content is less than 6 lbs/MMSCF.

• The CO2 content of the well fluids is expected to be higher than given at Clause 5.6 (based on Schlumberger bottomhole data). The current value at Rumaitha is in the range 4-7% (taken at the gas phase of separators).

• The H2S content of the well fluids is expected to vary from nil to 3%. Currently, the H2S content of the gas phase at Rumaitha 1st stage separator is 640 ppm (average for Year 2011), but may change in future, depending on the option retained for the CO2 extraction unit.

• It is assumed that there will be no sand or solids in flow lines, headers, piping and pipelines, which could lead to erosion-corrosion or corrosion under deposits.

• No elemental sulfur has been identified so far in the producing reservoirs. It is hence assumed that there will be no elemental sulfur present in the produced fluids and no elemental sulfur deposition in any of the facilities or assets.

• It is assumed that the produced fluids will not contain organic acids (acetic acid in particular) that will increase substantially the corrosivity of the environment or affect the suitability of materials.

• The Wax Appearance Temperature (WAT) of Rumaitha Thamama B fluids is known to be 28.3 °C. This is not considered to impact the corrosion characteristics of the streams and no credit shall be taken for a possible positive impact of wax.

• Similarly, the asphaltene content of Rumaitha crude oil is in the range 0.14 to

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0.43%. No credit shall be taken for a possible positive impact of asphaltenes.

• No analysis has been undertaken to evaluate the possible effect of BTEX (Benzene, Toluene, Ethylbenzene and Xylene) content on the behavior of materials.

• Carbonate scales are experienced in some wells at Rumaitha & Shanayel. With increasing water cut and gas injection / lift rates, scale deposition rates are expected to increase. However, the localization of scale deposits is not expected to be uniform and no positive impact of scaling on corrosion rates shall be considered.

• It is assumed that the well stimulation procedures are such that spent acid returns do not enter the production system.

• The liquid carry over at separators, scrubbers KO vessels and similar static equipment is limited to 0.1 USG / MMSCF as per API 12J-89.

• The liquid water streams at the outlet of separators, scrubbers, etc… contain the same amount of chlorides (by carryover) as the upstream vessel.

• Gas streams shall be considered dry when the water dew point at the operating pressure is at least 10 °C lower than the actual operation temperature for the system.

All gas streams from the first stage separator to the dehydration unit are wet with the exception of the compressor discharge streams.

Gas downstream of the dehydration unit is dry in normal operation

• The inhibitor efficiency in near-stagnant conditions (dead legs, separators, scrubbers, knockout vessels and similar static equipment) is low and is not appropriate for corrosion control.

• The efficiency of corrosion inhibitors in stagnant conditions (static vessels, dead legs, nozzles) is poor and cannot be relied on for long-term corrosion protection.

• The inhibitor distribution within separators, scrubbers, knockout vessels and other static equipment is such that no carryover of inhibitor into overhead gas streams will reliably occur

8 CORROSION AND MECHANISMS

The list of corrosion damage mechanisms considered for the development of this study is as follows:

External corrosion:

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a. Atmospheric corrosion

b. Corrosion by soils

c. Corrosion Under Insulation (CUI)

d. Pitting and crevice corrosion of stainless steels

e. Chloride Stress Corrosion Cracking (CSCC) of stainless steel

f. External Stress Corrosion Cracking

Internal corrosion:

a. General (metal loss) corrosion by acid gases (CO2 / H2S)

b. H2S-related Cracking (SCC, HIC, SOHIC, SSC)

c. Microbiologically Induced Corrosion (MIC)

d. Galvanic corrosion / Flange Face Corrosion

e. Internal erosion

f. Brittle Fracture

The likelihood and extent of possible corrosion damage shall be evaluated quantitatively and/or qualitatively with a view to explore the possibility of using carbon steel as the base material wherever technically and economically possible. Relevant details of corrosion mechanisms and recommendations for avoidance of corrosion cracking are found in ADCO document ES 30-99-00-0102-1 (Corrosion and Materials Selection Philosophy).

8.1 EXTERNAL CORROSION

Although no specific difficulties are anticipated for the long-term behaviour of structures, pipelines and vessels, the likelihood of corrosion damage (before mitigation by coatings and/or cathodic protection) is considered high for carbon steel and for stainless steels.

8.1.1 Atmospheric Corrosion

The process facilities shall be exposed to aggressive environmental conditions, classified as C4-M as per ISO 12944-2. The combination of salt-laden air with ambient temperature varying widely throughout the year from 5 to 50 °C (extremes), the solar radiation reaching temperatures of 80 up to 85 °C maximum, the average minimum humidity of 70% for most of the year, the temperature drop below dew point at nightfall and the early morning mists create severe conditions where the corrosion rate of carbon steel can vary from 0.1 to 1 mm/year.

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8.1.2 External Corrosion of Buried Items

Some sandy (sabkha) areas have proved very corrosive to the buried sections of piping and to the rebar of foundations. The main corrosion factor shall be the unavoidable presence of high level of chlorides and the high temperatures reigning in the area. The risks of interference with the cathodic protection of the well casings in the neighbourhood need to be addressed in priority.

As a general rule, the low-pressure piping of underground facilities (drain lines, firewater lines) shall be made of inert materials wherever mechanically and economically feasible.

All underground piping in Rumaitha shall be subjected to severe corrosion. Protective coating and cathodic protection shall be applied to mitigate this corrosion..

8.1.3 Corrosion Under Insulation (CUI)

Corrosion under insulation and fireproofing is a major integrity threat particularly for austenitic and duplex stainless steels as well as carbon and low alloy steels. The CUI threat is influenced strongly by the external metal surface temperature, the presence of chlorides and local condensation conditions.

CUI is reported to occur on system operating between -5°C and 175°C for carbon steel and between 50°C and 175°C for stainless steel.

8.1.4 External Pitting and Crevice Corrosion of Stainless Steels

Stainless steels (austenitic 300 series, Duplex steels, superaustenitic) are not immune to corrosion with a risk of crevice and pitting corrosion.

Pitting is a well-documented localized attack due to the invasion by chlorides and subsequent breakdown of the protective (passive) layer created on stainless steels. Crevice corrosion is basically the same phenomenon occurring when the metal is in close contact with any solid material creating a tight crevice, such as a washer or a scale deposit, with a restricted Oxygen access.

For each material, there is a "critical pitting temperature" (CPT), which is the minimum temperature at which pitting is first observed, and similarly a “critical crevice temperature” (CCT). CPT and CCT depend on the pH and chloride concentration of the environment. A ranking can be established based on ASTM tests G48 (test in 4% NaCl + 1% Fe 2 (SO4)3 + 0.01 M HCl), as per the Table below. The critical temperatures given in the Table are indicative only, but give an order of magnitude of the corrosion resistance of some usual materials.

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Material Critical Pitting Temperature (°C)

Critical Crevice Temperature (°C) PREN

304L (UNS S30403) - 2 Below -2 18/20 316L (UNS S31603) 0 - 2 23/28 317L (UNS S31703) 32 0 28/33 904L (UNS NO8904) 35 12 31/38 Duplex SS (UNS S31803) 30 17 31/38 6 Mo (UNS S31254) 70 37 42/45 Nickel alloys Alloy 825 (UNS NO8825) Alloy 625 (UNS NO6625)

30

>85

5 30

N/A N/A

The pitting and crevice resistance of austenitic stainless steels is correlated to their composition by the Pitting Resistance Equivalent Number (PREN):

PREN = (%Cr) + 3.3 (%Mo + 0.5%W) + 16 (%N)

The role of molybdenum is essential to ensure a better resistance to both pitting and crevice corrosion.

Considering the high temperature – up to 85°C – due to solar radiation in the Gulf area, it is clear that the usual stainless steels are not resistant to pitting/crevice corrosion and require extra protection (coatings).

Welding of Duplex SS may lead to serious pitting corrosion in local conditions and should be avoided where possible. Super Duplex SS has generally good weldability. However, welding should be done not to impair their corrosion resistance characteristics. This result can be obtained by avoiding intermetallic precipitation and obtaining the proper balance of ferrite to austenite in the HAZ and weld metal. For Rumaitha / Shanayel Phase III project, no DSS and SDSS equipment which require welding during fabrication and connection on either shop or field site is used.

8.1.5 External Chloride Stress Corrosion Cracking (CSCC)

Stainless steels are very sensitive to external chloride-induced stress corrosion cracking (CSCC) if exposed to a saline environment or chloride containing oxygenated fluids or other chloride containing atmospheric environments, as reported by the COMPANY learnt lessons.

The main parameter of CSCC is the threshold temperature above which cracks are developing. Note that exposure to higher temperature during short periods or upset conditions not exceeding 3 – 4 hours may be acceptable, provided a short duration is ensured (e.g., by automatic shutdown of compression systems if the cooling water fails). The

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threshold temperatures for the susceptibility of CRAs to CSCC are listed below:

60°C for AISI 300 series austenitic stainless steel (SS 316, 316L, 317, 321, 347 etc.).

100°C for 22% Cr duplex stainless steel (DSS)

120°C for 25% Cr super duplex stainless steel (SDSS)

130°C for 6Mo stainless steel

It is clear that the exposure of austenitic SS to solar radiation with temperature up to 85°C induces a risk of CSCC. See Clause 9.1.1 for the possible use of coatings to control the risk of CSCC.

8.1.6 External Stress Corrosion Cracking

CS pipelines may be subject in certain conditions to high-pH Corrosion Cracking (pH 9 to 13) or near-neutral Corrosion Cracking (pH 5 to 7). These types of cracking appear mainly in gas transmission lines under CP near the compression stations. Such cases are not anticipated in the project conditions.

8.2 INTERNAL CORROSION

8.2.1 “Sweet” and “Sour” Corrosion Mechanisms

Corrosion primarily caused by dissolved carbon dioxide is commonly called "sweet" corrosion, whereas corrosion due to the combined presence of dissolved carbon dioxide and hydrogen sulfide is referred to as "sour" corrosion.

a. For CO2 /H2S ratio < 20, the corrosion is fully governed by H2S. For Carbon Steels, the primary corrosion product is a non-stoechiometric iron sulfide (FexSy), with varying protective properties depending on its crystallographic structure.

b. For high CO2 /H2S ratio, the corrosion rate is fully governed by CO2. The primary corrosion product is iron carbonate (FeCO3). The limit ratio is generally taken as 500, but depends on environmental variables.

c. For intermediate ratios, the corrosion regime is complex and difficult to anticipate.

The main features of the sweet and sour corrosion are summarized in the Table below.

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Controlling factor CO2 (sweet)

(ratio CO2/H2S high)

H2S (sour)

(ratio CO2/H2S < 20)

Main Corrosion Product / Scale FeCO 3 FexSy Main Corrosion Damage Metal loss Cracking Typology of metal loss corrosion Uniform in principle Localized

Effect of velocity on corrosion rate Increased rate Uncertain

Effect of Chloride content Neutral Increased pitting risk

Effect of temperature Increased rate up to 60°C, decreased above Increased pitting risk

The fluid composition mentioned in Clause 5.3 shows that all cases (sweet corrosion – as observed today in Rumaitha field-, sour corrosion, mixed regime) may be encountered during the lifetime of NEB 3 facilities.

8.2.2 General (Metal Loss) Corrosion by Acid Gases

The main factor of metal loss for the process facilities is the presence of acid gas (mainly, but not exclusively, CO2 and H2S). Very high CO2 contents (up to 40% and more) are expected in the production facilities (flow lines, trunk lines, wet gas lines) after the CO2 injection breakthrough. It is not known at this time which producing wells will be subject to breakthrough. However, the material selection will be based on the worst case corrosion-wise, that is the very high CO2 content induced by CO2 injection.

8.2.2.1 CO2 -Controlled Corrosion (“Sweet” Corrosion)

Considerable work has been done to determine the mechanism and rate of CO2 corrosion of carbon steel pipeline, casing, and tubing, taking into account the pressures and temperatures typical of Oil and Gas process environments. In particular, the studies by DeWaard and Milliams in the 70s have led to the development of equations for predicting the corrosion rates of steels exposed to water saturated with natural gases containing CO2. The initial equations developed in 1975 have been transferred into commercial or proprietary models along the years to include the effect of organic acids or buffering species (such as bicarbonates), of the non-ideality of gases and of the influence of the corrosion scale products. The “historical” DeWaard and Milliams equation was semi-empirical and developed for flow rate of 1m/s at the metal surface. It has the following form:

log (CR) (mm/year) = 5.8 – 1780/T + 0.67 log (PCO2) Among the different corrosion models available today, some are

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based on the initial semi-empirical DeWaard and Milliams equation, such as HYDROCORR (SHELL), CASSANDRA (BP), PREDICT (now HONEYWELL), FREECORP and MULTICORP (OHIO University) or ECE-4/ECE-5 (INTETECH). Others include internal empirical corrosion databases such as M-506 (NORSOK), CORRCAST (EXXONMOBIL) or CORPLUS (TOTAL). In general, the models based on equations are more conservative. Each model has definite advantages and drawbacks, but it is important to stress the limitations to the use of these models, in particular the assumptions regarding the influence of H2S and the consideration of pitting risks. With regard to the metal loss of carbon steel and the corrosion allowance, the results can differ by 500% in certain conditions.

8.2.2.2 Corrosion in Pure CO2 systems It is noticeable that the models above are not valid for pure CO2 conditions, which shall be encountered at the discharge of the CO2 recovery plant. The handling of supercritical CO2 fluids can be summarized as follows: The pure (dense phase) product is non-corrosive to carbon steel. CS is thus perfectly suitable, provided the metallurgical constraints (not in the scope of this report) are properly addressed.

If moisture (free water) is allowed into the system, the product is extremely corrosive to CS, The most applicable data from the literature (m) refers to CS exposed to CO2 and water at 40 to 60 bars and 50°C, resulting in corrosion rates of approx. 20 mm/year, or 0.05 mm/day.

If Oxygen is allowed into the system, the effect on CS corrosion rate is nil in the absence of free water. If free water is present, O2 shall increase the corrosion rate, but not in excessive proportions.

Other contaminants, such as acids, SO2 or NO2 may lead to very high corrosion rates, even at very low concentrations (see references n, o, p). Although some kind of inhibition by mono-ethanol-amine has been envisaged, the only practical solution in case of such contamination is the use of CRAs. Austenitic stainless steels – martensitic or austenitic and all Nickel alloys are suitable, provided CO2 is the only corrosion agent. Martensitic SS (13Cr) should be restricted to mildly corrosive environment (water and O2 ingress, without SO2)

Nitrogen or HC gases (which may be used for start-up and depressurizing) are not expected to have an influence on the water solubility in CO2 dense phase and hence on the corrosion rates.

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8.2.2.3 H2S-Controlled Corrosion (“Sour” Corrosion) Although the presence of H2S adds to the acidity of the water, its main effect on the overall metal loss is to decrease the uniform corrosion rate, following the formation of a protective FeS layer. The effect is difficult to quantify accurately. For example, the ECE corrosion models are using a corrective factor FH2S based on a simplified absorption model:

FH2S = 1/(1 + 10 x H2Sdiss/CO2diss) where H2Sdiss and CO2diss are the concentrations of the gases dissolved in water. This model can be considered acceptable as long as a coherent FeS layer is present. In case of breakdown of the FeS layer by erosion, or by dissolution in chloride-rich waters, the corrosion mechanism may degenerate into localized corrosion (isolated pitting), more difficult to assess and to mitigate after it has started (see section below). Localized Corrosion (Pitting) due to H2S and Chlorides: The likelihood of the FeS layer destruction and pit formation in H2S-containing production fluids is extremely difficult to predict and subject to controversy. The experience shows that gentle flow rates (in the absence of sand or debris) and low temperatures are favorable to the persistence of a coherent layer and that stagnant areas and dead legs are the locations with the highest probability of failure in sour environments. It is suggested to adopt for this Project the quantitative guidelines defined by Pots and al. [ref. a], that is: For CO2/H2S < 20, the pitting rate is a function of the chloride

content and presence of elemental Sulphur or Oxygen. The pitting rate is obtained by multiplying the sweet corrosion rate by a “Pitting Factor” Fp as per the Table below.

Chlorides Multiplying (Pitting) Factor

Without Oxygen or elemental S

With Oxygen or elemental S

Cl- < 500 ppm 0.73 1.7 500 ppm < Cl- < 5000 ppm 1.1 3.8 Cl- > 25000 ppm 2.6 6.1

Pitting Factor Fp in H2S-controlled conditions For CO2/H2S > 20, it has been shown by elaborate testing that the highest pitting rate is never worse than the sweet corrosion rate.

Role of Oxygen: O2 is not normally present in the produced fluids,

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but may ingress the facilities e.g. thru O2-saturated wash water into desalters, through leaking valves or seals, or through chemicals injected without blanketing. The result in presence of H2S may be catastrophic, due to the formation of allotropic Fe-S-O components, extremely corrosive to steel. Under typical inhibitor dosing rates (less than 25 ppm), the dissolved O2 concentration would not warrant inert gas blanketing of the storage tanks. For high dosing rates (e.g. batch bactericide treatments at 500 ppm), gas blanketing of the tanks is recommended.

8.2.3 H2S-Related Cracking (SSC, HIC, SOHIC, SCC)

Carbon Steels and Low Alloy Steels:

The presence of H2S may be beneficial in terms of metal loss for CS and Low-Alloy Steels, due to formation of iron sulfide films. It can however have adverse effects, leading to the increase of the flux of H (atomic) or H2 (molecular) into the steel. The increased flux may embrittle the steel and induce a risk of metal cracking without metal loss. These failure modes are termed Sulfide Stress Cracking, Hydrogen Induced Cracking and Stress Orientated Hydrogen Induced Cracking (SSC, HIC and SOHIC). The susceptibility of materials to SSC, HIC and SOHIC is described in detail in ADCO Engineering Standard ES 30-99-00-0102-1 (Corrosion and Materials Selection Philosophy).

SSC may occur on susceptible materials at relatively low temperatures, usually less than 70°C. NACE MR0175/ISO 15156 defines 4 levels of SSC risk, depending on the partial pressure of H2S (based on H2S design content) and pH of the water phase, from Area 0 (sweet service) to Areas 1 to 3 (sour service with increasing environmental severity). The graph below shows that the process fluids of Package 1 are located in Area 2 or 3 of the NACE/ISO diagram.

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Level of sourness of NEB 3 fluids

HIC susceptibility is a concern for carbon steel and low alloy steel in presence of H2S. HIC is reported to occur on flat rolled steel products even in presence of trace amounts of H2S. It is noteworthy that HIC is time-dependant and usually not associated to short-term excursions. Cleanliness of steel is the key factor of mitigation.

SOHIC is thought to be a combination of SSC and HIC coupled with applied and/or high residual stress. SOHIC has not been reported to occur in seamless pipes.

Sulphide Stress Cracking of carbon and low alloy steels, as well as HIC to a lesser extent, is a damage mechanism that cannot be tolerated in sour oil and gas systems. In consequence, the risk, in all cases, irrespective of the level of sourness, has to be reduced to zero. In consequence, in accordance with ADCO ES 30-99-00-0102-1, the following applies to all process facilities.

Resistance to SSC: all process items shall be compliant to NACE/ISO 15156 for resistance to sulphide stress cracking. SSC tests (NACE TM-0177 Solution A) are applicable for API 5L X60 and higher grades. Sour service requirements do not apply for atmospheric tanks and handling facilities with absolute pressure < 0.4 MPa, but hardness limitations are still applicable.

Resistance to HIC: HIC requirements shall apply for all process items. The maximum acceptable level of sulphur in steels shall be 0.003% for flat-rolled products, and 0.01% for seamless products. CRA materials are not susceptible to HIC. If vessels are internally clad with a CRA

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layer, the base material shall be SSC resistant but requirements for HIC may be waived.

HIC testing: HIC testing (NACE TM 0284 Solution A) is mandatory for all flat-rolled CS products exposed to process fluids, in accordance with NACE/ISO 15156-2, and for all sour service line pipes, in accordance with ES 30-99-00-0102-1. HIC testing of forgings with less than 0.025% sulphur and castings is not required.

PWHT: all vessels are to be PWHT’d regardless of wall thickness. PWHT is applicable to CS pipes for wall thicknesses above 19 mm as per ASME code. The welding procedure is subject to qualification as per NACE MR-0175. When the hardness is exceeding NACE limitation, PWHT shall be performed to reduce the residual stresses and to reduce the hardness level below 22 HRC. For piping, the material shall have the carbon equivalent (CE) not exceed 0.43% based on the formula:

CE = C + Mn/6 + (Cr+Mo+V)/5 + (Ni+Cu)/15

Chemical composition: the requirements of SHELL DEP 30.10.02.17 (normally applicable to downstream equipment) shall take precedence for the design of Pressure Vessels of the Project, in accordance with Shell DEP 31.22.20.31-Gen (Pressure Vessels-Based on ASME Section VIII).

Corrosion Resistant Alloys

CRAs are also susceptible to environmental cracking in the form of Stress Corrosion Cracking, in presence of H2S at defined temperature with chloride containing fluids. NACE MR0175 / ISO15156 provides fully comprehensive tables, detailing the risk of cracking and the range of application (regarding PH2S, Cl- and temperature) of CRAs exposed to production fluids. The DEP amendments as per DEP 30.10.02.15 do not modify the NACE/ISO limits of use in the conditions of Package 1.

- Martensitic Stainless Steels 13%Cr: the use of 13%Cr (mainly as tubing material or pump casing) is restricted to partial pressure of H2S < 1.5 psi (0.1 bar) and pH > 3.5. No limit is set for the temperature and the chloride content. The Super13 (with 4-6% Ni and 1-3% Mo) is marginally better, with the same operational limits. These limits are not compatible with the project facilities, where PH2S (design) ranges from 14 psi (well fluids) to 167 psi (gas injection).

- Austenitic Stainless Steels (type 316/316L) and Superaustenitic Stainless Steels: The Table below summarizes the acceptable limits for the use of common austenitic stainless steels, in accordance with NACE MR0175 / ISO 15156.

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Material Chloride Acceptable limits

Type 316 (UNS S31600)

< 50 ppm No restriction on PH2S and Temperature < 1,000 ppm P H2S < 1.5 psi and T <149 °C, pH 4.0

< 5,000 ppm P H2S < 1.5 psi and T < 93 °C, pH 5.0 < 60,000 ppm P H2S < 0.22 psi and T < 60 °C

Type 904 (UNS NO8904)

< 50 ppm No restriction on P H2S and Temperature Any P H2S < 15 psi and T < 60 °C

Type 6Mo (254 SMo) (UNS S31254)

< 50 ppm No restriction on P H2S and Temperature

< 5000 ppm P H2S < 100 psi and T < 121 °C P H2S < 45 psi and T < 149 °C P H2S < 15 psi and T < 171 °C

Any P H2S < 15 psi and T < 60 °C Limits of use of common austenitic steels in H2S/Chloride environments

For the Package 1 fluids, the use of austenitic SS is thus restricted to the low temperature (< 60°C) or Chloride-free sections of Project facilities.

- Duplex (Type 22Cr) and SuperDuplex (Type 25Cr) Stainless Steels:

These alloys are very sensitive to H2S cracking. In presence of chlorides, the acceptable PH2S limit as per NACE MR 0175 / ISO 15156 standard is 1.5 psi (Duplex) or 3 psi (SuperDuplex) for temperatures up to 232 °C. No limit is set for the pH and Chloride content. SHELL DEP has set further limitations with regard to temperature (< 200°C), chloride content (< 150,000 ppm) and H2S partial pressure (0.15 and 0.3 psi resp.).

In consequence, DSS and SDSS are not considered suitable for handling the Project fluids (well fluids, gas lift, gas injection).

- Nickel-based alloys: The resistance to cracking of Ni-based alloys is summarized below:

Material P H2S Acceptable limits Alloy 825 (annealed condition) < 210 psi Chlorides < 150,000 ppm and T < 200°C

Alloy 625, (annealed condition) < 450 psi Chlorides < 150,000 ppm and T < 240°C

Copper –Nickel (UNS NO4400)

No restrictions on P H2S , chlorides and T (maximum hardness = 35 HRC)

Limits of use of Nickel alloys in H2S/Chloride environments

There is no restriction with regard to the pH and chloride content. Moreover, all these alloys are sulphur-resistant in the annealed condition. In the cold-worked condition, the alloy C-276 is sulphur-resistant up to 232 °C and the Alloy 625 up to 149 °C. Alloy 825 should be supplied with fully passivated external surfaces, in order to enhance

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its resistance to atmospheric exposure.

These alloys are suitable for all phases of the Project.

8.2.4 Microbiologically Induced Corrosion

Sulphate Reducing Bacterias (SRBs) and Thiosulphate Reducing Bacterias (TRBs) are the major contributors to microbiological induced corrosion for the inside of oil and gas producing and water injection facilities. The detailed mechanism is complex, resulting in the anaerobic reduction of sulphates to sulfides and the oxidation of Iron0 to Iron+2. The result can be severe localized corrosion.

The main factors for optimal bacterial growth are well known: temperatures in the range 30 to 50 °C, low flow rates < 1 m/s, total salinity < 120,000 ppm, presence of debris or deposits in the line are expected to increase the risk of MIC.

The different facilities of Package 1 should not realistically be subject to MIC. The risk is nil for the dry phases (gas injection and gas lift), low for the gas processing units and very low for the well products, due to the high salinity and temperature of the produced water.

8.2.5 Galvanic Corrosion

Galvanic corrosion is a phenomenon occurring at locations where two dissimilar metals come in contact in presence of an electrolyte. The less noble material shall corrode, while the more noble material shall be protected. A key factor is the ratio of the cathode / anode area, which has to be kept as large as possible.

This type of damage is encountered essentially in oxygenated environment and is thus not thought to be a major concern for the Project facilities, provided no oxygen ingress is allowed, in particular into the water injection system. The damage by galvanic corrosion in production (anaerobic) environment is very infrequent.

8.2.6 Corrosion by Oxygen

Oxygen is not normally present in the well fluids and in the water from deep supply wells. As such, no oxygen corrosion is anticipated for the Project facilities in normal conditions. The only possible source of O2 in process fluids is the wash water used in desalters, where oxygen scavenger injection shall be provided.

Any accidental ingress through leaking valves or seals or through injected chemicals can generate serious corrosion damages. In consequence, in addition to the normal inspection procedures, the Nitrogen or Fuel Gas blanketing of the chemical tanks is strongly recommended.

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8.2.7 Internal Erosion

Erosion is the progressive loss of material from a solid surface (pipe/valve/vessel) by the flowing process fluids or by particles carried with the fluid. Erosion-corrosion is the conjoint action of corrosion and erosion.

Sand production has not been advised for the NEB 3 Project. In consequence, the likelihood of erosion of Carbon Steel Piping is considered low.

The removal of protective inhibition layers by erosion has been historically referred to for restricting the flow velocities in production lines. Recent work [h] has shown that inhibition can be achieved in multiphase systems at high velocities in excess of 30 m/s, which cover all cases of the Project.

API RP 14E provides a general guidance on avoiding erosion and erosion-corrosion problems and is generally taken to be conservative.

8.2.8 Brittle Fracture

Low temperatures resulting from rapid depressurization (blowdown) of the facilities may lead to brittle fracture of the material. Mitigation of brittle fracture will be achieved by the combination of process engineering and selecting materials with appropriate minimum design temperatures and with the correct toughness requirements.

Low temperature design limits of materials for piping and vessels during normal operation shall be strictly as per SHELL DEP and ADCO ES-30-99-00-0102-1, Attachment 13.

No brittle fracture of pipes or vessels can be tolerated and no material shall be subject to temperatures below minimum recommended temperature during any depressurization sequence. Full compliance to ADCO Engineering Standard is assumed, which warrants a low likelihood of brittle fracture for all Project items.

8.3 APPLICABLE CORROSION MODELS

The different streams and phases of Package 1 shall be facing various corrosion situations:

streams with moderate CO2 and low H2S and without chlorides (current situation at Rumaitha gas lines)

streams with high CO2 and H2S without chlorides (design case for the gas after the 2029 breakthrough)

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streams with high CO2, high H2S with chlorides (well fluids, future)

cold gas streams due to depressurization.

Considering that the duration of each phase is not known accurately, the Material Selection shall be based on the worst case corrosion-wise, that is the case with highest CO2 content as given by H&MBs for the different streams, taking into account:

the start-up and upset conditions,

the Minimum Design Temperature of the stream

the mandatory codes and standards.

For the quantitative assessment of metal loss, the Cassandra and Freecorp models have been retained for the NEB 3 conceptual study. For the FEED study, the data from the ECE-5 and NORSOK shall be used for the corrosion by wet gas (low pH with no or little protective scale). For the corrosion by liquids, a less conservative approach shall be retained, to include the possible protective role of FeCO3 and FeS at higher pH.

Finally, the determining factor for the material selection of upstream facilities (flow lines and trunk lines) shall be the lessons learnt from the existing 7-years old NEB-I facilities. For the CPP facilities, the lessons learnt shall be extrapolated to higher acid gas content after CO2 breakthrough of the 8 wells of Package 3.

9. MITIGATION AND CONTROL STRATEGIES

9.1 CONTROL OF EXTERNAL CORROSION

The control of external corrosion of metallic items shall be ensured by a combination of coatings and cathodic protection, in accordance with ADCO Engineering Standards and Project Specifications.

9.1.1 Coatings

Coatings constitute the primary line of defence against atmospheric corrosion. All metallic surfaces exposed to atmosphere shall be coated according to ES-30-99-37-0013 with the exception of copper alloys (brass, copper-nickel) as listed in the Manual. The coating requirement is applicable to all usual stainless steels of the 300 and 400 series, to be painted, but not to the highly alloyed austenitic steels and Nickel alloys.

All buried piping and pipelines shall be coated according to ES-30-99-37-0017 and ES-30-99-90-0279, complemented by Cathodic Protection.

Mitigation of CSCC: For austenitic materials if they are specified for services where low temperature toughness is required (such as a flare

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system), an appropriate external coating shall be used in order to prevent CSCC in high-risk piping systems. The type of coating to be used for piping systems shall be in accordance with ADCO Specification ES 30.99.37.0013 “Painting and Coating of New Equipment”.

Subject to ADCO approval, external painting or coating may be considered on an exception basis for mitigation of CSCC for the following:

SS 316 and SS 317 piping if transporting H2S-free fluids

Instrument tubing at process operating temperatures up to 75°C

Mitigation of Corrosion under Insulation (CUI): Mitigation of CUI will be ensured by the following steps:

Limiting as much as possible the use of insulation

Installation of appropriate sealing systems to minimize water ingress

Use of cage type guards for personnel protection

Correct insulation selection (in particular chloride content of the insulation material), material specification, and quality control of installation

Application of correct coating system for under insulation service

Inspection & maintenance routines involving periodic removal of insulation

9.1.2 Cathodic Protection

9.1.2.1 Cathodic Protection Criteria CP systems shall be designed in accordance with Engineering Specification ES 30.99.37.0001 and Project Specifications. Impressed Current Cathodic Protection systems shall provide sufficient current to the structure over its design life to achieve “OFF” potentials, equal to or more negative than stated in Table below.

Environment Instantaneous “OFF” Potentials (mV)

Reference Electrode Cu/CuSO4 Ag/AgCl Zinc

Protection potential for steel in aerobic soil environment -850 -800 +250

Protection potential for steel in -950 -900 +150

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anaerobic soil environment Over protection limit for carbon steel -1150 -1100 - 50

Addition: Steel rebars in concrete - 700 - 650 N/A

9.1.2.2 Cathodic Protection of Buried Items

All the buried metallic items of the Project – buried pipelines, buried piping if any, buried vessels and tank bottoms -– shall be protected by Cathodic Protection. Consideration shall be given to special monitoring and mitigation requirements along the pipeline to protect interference in case of pipeline crossings or paralleling, or in case of power cables and foreign pipelines. Interference with other buried pipelines or installations shall be measured while the CP system is energized. If exposed to severe corrosion conditions (such as continuous or intermittent exposure to the water table, or exposure to stray current from neighbouring structures), steel rebars of concrete foundations will require to be cathodically protected. This requires as a first step to ensure the electrical continuity of all reinforcement cages, which shall be connected to the earthing system of the plant. The electrical continuity of the cages is normally ensured by the redundant binding wires. As a general rule, the electrical resistance between any 2 points of a rebar cage shall not exceed 0.5 . In case this requirement is not met, the continuity shall be restored by electric cables as necessary. As a general rule, the plant structures shall be continuous, but isolated from the pipelines by monolithic insulating joints. The isolation requirements for the different pipes and pipelines of the Project are detailed in ADCO ES 30.99.37.0001.

9.1.2.3 Cathodic Protection of Well Casings Integrated CP systems are specified for the protection of well casings and flow lines (no isolating joint required). The possible interference between neighboring well casings shall be thoroughly evaluated at the design stage by suitable interference models and verified by site measurements at the commissioning stage.

9.2 CONTROL OF INTERNAL CORROSION

The control of internal corrosion shall be ensured by a combination of 3 approaches:

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Material Selection,

Internal linings and Internal Cathodic Protection where applicable,

Chemical Treatment.

The main guidelines are given below.

9.2.1 Material Selection Guidelines

The following steps shall be followed during the selection of suitable materials for the process or utilities of the Project:

Step 1: Sweet Service versus Sour Service

The first step for the selection of suitable materials is to determine the degree of sourness according to NACE MR0175 / ISO 15156. Three parameters are required to determine the level of sourness:

Partial pressure of CO2 (PCO2 = (mol% CO2) x Ptotal / 100)

Partial pressure of H2S (PH2S = (mol% H2S) x Ptotal / 100)

Bicarbonate content in mol%

For gas lines and vessels, the CO2 and H2S contents are given by the Heat and Material Balance. The salt content is generally 0, except in case of carry-over of the liquid phase at separators or manifolds.

For liquid lines and vessels, “virtual” CO2 and H2S partial pressures are calculated considering the bubble point of the liquid. A good approximation is to take the composition of the gas phase at the nearest upstream separator.

The NACE MR0175 / ISO 15156 graph (see clause 8.2.3) shows that all process phases are sour (are a 1 or 3 of sourness). All metallurgical requirements are described in Annex A of ISO 15156-2 are fully applicable for Carbon Steels; where Corrosion Resistant Alloys are specified, these shall be compliant with NACE MR0175 / ISO 15156-3.

Step 2: Carbon Steel versus Corrosion Resistant Alloys

Carbon Steel is the first choice material for the oil and gas production facilities, both in sour and sweet service, provided:

the residual (inhibited) corrosion rate is less than 0.2 mm/year, leading to a maximum corrosion allowance of 6 mm for the 30-year life time..

the risk of pitting, galvanic and other possible corrosion damages highlighted above is judged affordable.

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the Life Cycle Cost (LCC) of the CS + inhibition solution shows an advantage over the CRA (Corrosion Resistant Alloy) alternative.

LCC has been developed for identifying and quantifying all costs, initial and ongoing, associated with a project or installation over a given period of time. LCC uses the principle of discounted cash flow so that total costs incurred during the life cycle period are reduced to present day values. This allows a comparison to be made of the options available so that potential long-term benefits can be assessed more accurately.

The ECE-5 software contains a simplified LCC calculator, which includes the capital costs of construction and the operating costs (cost of chemicals, labor, inspection and maintenance). The simplified LCC calculator is generally considered adequate for the purpose of material selection, provided the cost of valves and appurtenances is correctly included in the estimation.

It is based on the following formula:

where:

LCC: Total Life Cycle Cost

AC: Initial acquisition cost of materials (at expenditure year), comprising the material itself, the initial cost of internal or external paint or coating system, the thermal insulation system and CP system if applicable, and associated equipment (e.g. inhibitor injection pump).

IC: Initial installation (fabrication) costs, including welding consumables, offshore laying, commissioning including start-up, installation and testing.

OC: Operating plus maintenance costs (including supply of inhibitor and other chemicals, corrosion monitoring, inspection, workovers).

LP: Lost production costs during downtime (e.g. periods of batch inhibition or intelligent pigging or other inspection, along with lost production from actual failures).

RC: Replacement material costs

SC: Residual value of replaced materials

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N: Design Life

i: Real interest rate

n: Year of the event

The comparison requires obviously updating the cost of different CRAs with proved references in the O&G industry, which may vary strongly depending on the current cost of raw materials on the world market – currently very volatile. The Table below gives the order of magnitude of material cost (base September 2010) in $/ton.

Material Estimated Cost ($/ton)

Piping Fittings Valves Carbon steel 1,800 4,000 6,000

Martensitic SS 4,000 AISI 316 (solid or clad) 11,000 35,000 38,000

22Cr Duplex 16,500 38,000 40,000 25Cr Duplex Assumed cost of 22Cr + 15 %

Alloy 825 solid 29,000 45,000 55,000 Alloy 825 clad 15,000 18,000 28,000 Alloy 625 solid 35,000 55,000 65,000 Alloy 625 clad Assumed to be similar to Alloy 825 clad Average cost of materials in $/ton – September 2010

All the listed CRAs have generally a satisfactory or acceptable resistance to uniform and pitting corrosion in oxygen-free O&G fluids, but have limitations with regard to their resistance to environmental cracking.

Step 3: Carbon Steel versus Plastic Materials

The use of plastic materials for buried pipes (GRP) shall be considered as an alternative to carbon steel, typically for low pressure applications such as drain lines and firewater lines. Plastic pipelines do not require external corrosion protection and are normally resistant to produced fluids.

Glass-reinforced Epoxy (GRE) is the first choice material in this category, supported by many successful applications by ADCO, in particular for firewater lines. GRE pipe (or “fiberglass”) is a composite material formed from thermosetting epoxy resins with continuous fiberglass filament reinforcements. It is used extensively in the oil, gas and chemical industry for low pressure transmission. Its resistance to chemical attack from any common oilfield chemicals offers users a complete solution against highly corrosive fluids application a various pressures, temperatures, adverse soil and weather conditions.

The obstacles to using GRE piping were related primarily to the lack of test data to support the material long-term durability. Engineers who

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were used to steel pipes were uncomfortable with GRE pipe as there wasn’t sufficient historical data of it long term application. Also GRE pipe fittings were expensive because they are labour-intensive to manufacture, and the methods used to join GRE-to-GRE piping and GRE-to-alloy piping were extremely unreliable.

Applicable temperature and pressure for GRE piping depends on applied resin type and thickness etc. For Rumaitha / Shanayel Phase III project, piping class 017015-X and 017015-Y using epoxy type resin is used as a GRE piping. Design condition of 017015-X and 017015-Y related temperature and pressure is barg 20 @ 85°C and barg 10 @ 85°C, respectively, based on piping class.

However, based on lessons learnt, it can be considered that Glass Reinforced Epoxy pipeline systems are now a mature solution for buried piping for fire waters, water disposal lines, and open and closed drain systems. The major factor to be considered for the possible use of GRE pipe remains the quality of installation, in order to avoid premature failure at field joints.

9.2.2 Internal Linings and Internal Cathodic Protection

For process vessels (separators, gas scrubbers, KO drums), the efficiency of the corrosion inhibition is questionable, due to the geometry and hydraulics of the system. In this case, the application of a suitable internal coating, supplemented with sacrificial anodes (generally Al-In anodes, or Zinc anodes below 50 °C) can be considered as an alternative to CRA-cladding.

For a standard vessel, the cost factor of the (coating + anodes) solution is marginal (up to 5% of the cost of the vessel), which compares favorably with the cost of CRA clad. This solution can be envisaged for all process vessels with operating pressure < 20 bars (300 psi), taking into account that the maximum temperature for organic linings. However, the final design shall take into account the lessons learnt as per COMPANY instructions. The case of the boots at the bottom of vessels, where dirt and debris can accumulate, will generally require the use of CRAs.

For pressures higher than 300 psi but less than 500 psi, internal linings may be considered provided the painting system is qualified by Vendor. The qualifying procedure shall include as a minimum, but not limited to, a pull-off test as per ASTM D4541-02.

For pressures > 500 psi, CRA-cladding shall be recommended for all process vessels handling corrosive fluids.

Internal epoxy (FBE) linings of pipelines may prove an economic alternative to the use of CRAs for handling corrosive fluids. Positive

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experience in NEB facilities has been reported for pipelines handling corrosive injection waters. However, based on company recommendation, all CS with FBE lining pipelines are replaced with CS with 6mm CA for all water injection, disposal and supply lines.

CS with FBE lining piping is used for firewater line which is above-ground and over 3”.

9.2.3 Chemical Treatment

The injection of suitable chemicals - corrosion inhibitors, bactericides, oxygen scavengers, and neutralizer for gas dehydration & glycol regeneration system– is in general necessary to control the corrosion of carbon steel during the full lifetime of the facilities. The main features of the chemical treatments are described hereafter.

9.2.3.1 Corrosion Inhibitors A corrosion inhibitor is defined by NACE as a substance, which reduces the metal corrosion rate when added to an environment in a small concentration. The inhibition process is the result of the following mechanisms, alone or in combination: Adsorption of the substance as a thin film onto the surface of

corroding metal. Formation of a protective corrosion layer (passivation layer)

enhanced by the inhibitor. Modification of the characteristics of the corrosive environment.

Corrosion inhibitors can be classified into two generic categories, organic and inorganic. Inorganic inhibitors have been most often used in cooling towers, heaters and coolers, glycol units and sweetening amine solutions. They are generally constituted of metal salts, which act by passivating the corroding metal surface. They have limited use today because they require high dosage rates to be effective, because they induce a risk of pitting corrosion if the concentration falls below threshold values and because of environmental concerns for their handling and disposal. Organic (film forming) inhibitors have gained wide acceptance in oil and gas applications. The active inhibitor components are usually nitrogen compounds such as amines, imidazoline or ammonium salts. These chemicals have a polar head (R-NH) and a long hydrocarbon (HC) tail with hydrophobic properties. The polar head is bonded to the metal surface, while the HC chain acts as a repellent to prevent water from reaching the metal. In practice, the formulation of a

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commercial inhibitor includes also other active chemicals, including solvents to improve the solubility and availability of the product and possibly surfactants to remove or prevent the formation of scale and improve the accessibility to the metal surface. Inhibitors can be classified also as per their solubility or dispersability in the Water and Oil phases. Both oil and water-soluble formulations have advantages and limitations. Oil soluble inhibitors (amines, imidazolines, fatty acids, phosphate esters) are generally more effective, particularly at high temperature and high velocities. However, they need to reach the corroding surfaces to be effective, which can be a problem in stratified or annular flow. Water soluble inhibitors (quaternary amines, amine salt, salted imidazoline) can prove more appropriate, although they may desorb and lose effectiveness at high temperatures. The selection of corrosion inhibitor(s) shall be made considering the following order of precedence:

Performance of the chemical injection already in use in the field on the same or similar fluids, as evidenced by corrosion monitoring and inspection programmes;

Physico-chemical properties (in particular solubility and

compatibility with the other chemicals in use, such as aldehyde base biocides, demulsifiers, hydrate control chemicals and concentrated brines);

Anti-corrosion efficiency, commonly expressed by:

Inhibitor Efficiency (%) = 100 x ·(CRuninhibited - CRinhibited) / CRuninhibited

where: CRuninhibited is the corrosion rate of the uninhibited system

CR inhibited is the corrosion rate of the inhibited system The efficiency of an inhibitor injection increases with an increase of concentration. A good inhibitor is expected to reach an efficiency of 99% if correctly applied. It is noticeable however: That corrosion inhibition is largely ineffective in stagnant conditions or very low flow rates (less than 0.5 m/s)

That corrosion inhibition is largely ineffective when the mixed fluid velocity exceeds 30 m/s because of shear stress applied to the pipe wall. In such instances, higher concentrations of inhibitor (100 ppm or more) in the aqueous phase may be required.

That corrosion inhibition has in all a positive effect to reduce the risks of pitting corrosion, by enhancing the protective properties of the corrosion scale (FeCO3 and/or FeS).

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That the treatment of gas phases is difficult in a plant configuration with elbows and risers, because there is no suitable vector to carry the inhibitor everywhere where required. The use of spraying injectors (atomizers) is expected to improve the product spread.

The concept of “inhibitor efficiency” is not considered valid for field applications, as it doesn’t take into account the periods without inhibition, due to pump failures, or logistics problems, or any other reason. The new approach consists in considering the “availability” A of the inhibitor at any point of the facilities during the lifetime of the installation. For design purposes, the inhibited corrosion rate shall be given by:

CR inhibited = 0.1 x A + CR model x (1-A) Based on these considerations, the following design basis is targeted for the inhibitor availability requirement of NEB 3 phases:

CS Pipelines: 90% (dictated by the risks of pitting corrosion)

CS Piping, 3-phase and liquid: 90%

CS Piping, gas streams: 80% (due to piping layout)

Separators, vessels: 0 % (no reliance on inhibition) If the residual corrosion rate of CS (CRinhibited) is higher than 0.2 mm/year (corresponding to a total consumption of 6 mm for the design life), then the use of CRA shall be mandatory. If CR inhibited is less than 0.2 mm/year, the following approach shall be considered for the treatment:

Three-phase and liquid lines: a water-soluble compound shall be used. The product is expected to be available in the water phase all along the processing chain, up to and including the water disposal wells and the export pipelines.

Wet gas lines: it shall be necessary to inject inhibitor at each

stage of separation, as no carry-over is expected at the different separators or scrubbers. An oil-soluble product shall be used.

Dry gas lines: no treatment shall be considered for the dry

gas lines. However, a provisional injection system (access fitting with atomizer, without connecting tubings) shall be provided at the departure of each dry pipeline as a precautionary measure.

9.2.3.2 Bactericides

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The injection of bactericides is the most appropriate method for controlling the bacterial growth and the associated corrosion development. There are many biocides available for applications in oilfields but they are based upon relatively few basic active agents. They include chlorine as hypochlorite, aldehydes, quaternary ammonium, diamines and chlorinated phenols. The recommended injection is by batches at high concentration – typically during 4 to 6 hours at 100 to 400 ppm versus the total liquid flow. The formulation of biocides may require review and variation during the field life as the bacteria adapt and build up resistance and immunity. The usual technique to prevent immunity build-up is to alternate the use of two biocides, typically glutaraldehyde + quaternary ammonium. Bacterial growth can result from accidental contamination during the hydrotest of facilities, or during pigging operations. For this reason, it is highly recommended to carry out a 4 to 6-hours batch treatment of bactericide (+inhibitor) after each pigging operation, unless the results of bacterial tests prove consistently negative. The presence and number of bacteria shall be monitored by bioprobes or water sample analysis. Serial dilution tests allow the accurate estimation of the number of viable bacteria by statistical techniques.

9.2.3.3 Oxygen scavengers Although the NEB 3 streams are Oxygen-free in normal conditions, the installation of injection systems of oxygen scavenger at each water supply wellhead is recommended. The systems shall comprise a storage tank, pump and injection quill. Oxygen scavengers available in disposal water, wash water and water injection systems at following locations:

Upstream of Desalter in wash water system Suction line of three injection pumps in disposal water system Suction line of three injection pumps in water injection system

In accordance with ADCO ES 30-99-00-0102-1, the preferred chemical shall be saturated ammonium bisulphite.

9.3 GUIDELINES FOR SELECTION OF VALVES

Valve materials shall comply with the requirements of the relevant Shell DEP’s and NACE MR0175 / ISO15156.

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See ADCO ES 30-99-00-0102-1 (Corrosion and Materials Selection Philosophy) and ES 30-70-12-0002 (Specifications of Ball Valves for Gas Gathering Systems), last revisions, for the details of ball valves material specifications.

9.4 GUIDELINES FOR SELECTION OF PUMPS

Pump materials shall be in accordance with the ADCO amendment to the Shell DEP 31.29.02.30 (Centrifugal Pumps)

Attachment 7 of ADCO ES 30-99-00-0102-1 (Corrosion and Materials Selection Philosophy) inventories the specified pump materials for specific pump services.

9.5 GUIDELINES FOR SELECTION OF BOLTING

Guidance for the material selection of bolting is given in ADCO ES 30-99-00-0102-1 (Corrosion and Materials Selection Philosophy), as a complement to EEMUA 194. The main relevant features for Package 1 of the Project are:

All CS or Low Alloy Steels nuts and bolts must be coated by a fluoropolymer-based coating.

CRA piping, difficult-to-access bolting and instrument bolts shall be made of 25Cr Duplex (SDSS)

The maximum hardness of CS and Low Alloy Steel bolting subject to CP is 34 HRC.

10 CORROSION MONITORING

10.1 INTERNAL CORROSION MONITORING

The corrosion monitoring programme is aimed primarily at assessing the corrosivity of the process streams, confirm performance and effectiveness of the chemicals injected and at optimizing the chemical injection rates.

The applicable techniques to Package 1 are the following:

Weight-loss coupons for the visual evaluation and average assessment of the corrosion rates;

Provision for Electrical Resistance Probes for the continuous on-line monitoring and early detection of corrosion upsets.

Linear Polarization (LPR) probes for the corrosion rate in conductive environments, particularly in water.

Bioprobes for the detection of sessile bacterias.

Fluid sampling and analysis of process parameters;

Corrosion inspection (UT measurement).

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The document “Corrosion Monitoring Philosophy” shall detail the type and location of the corrosion monitoring devices to be installed.

10.2 EXTERNAL CORROSION MONITORING

The external corrosion monitoring is limited to the following:

Coating condition surveys, in order to determine the routine maintenance of painting and interval between major refurbishment.

Cathodic protection monitoring of buried structures, pipelines and well casings as per COMPANY existing Guidelines and Contracts.

The Cathodic Protection Monitoring of Well casings shall be addressed in a separate specific document, to be provided by Vendor.

30.99.37.1607 r1 (material selection and corrosion control philosophy)

Documents

external corrosion

internal corrosion

corrosion control basis

applicable corrosion

adco project

project documents

material selection

project scope