6.41 Materials Selection and Integrity Protection Report for Offshore

7/30/2019 6.41 Materials Selection and Integrity Protection Report for Offshore

1/22


2/22

KCP-GNS-PLD-REP-0009

Revision: 03

Project Title: Kingsnorth Carbon Capture & Storage Project Page 2 of 22

Document Title: Materials Selection and Integrity Protection Report for Offshore Infrastructure

Kingsnorth CCS Demonstrat ion Project

The information contained in this document (the Information) is provided in good faith.

E.ON UK plc, i ts subcontractors, subsidiaries, aff i liates, employees, advisers, and the Department of Energy and Climate Chan ge(DECC) make no representat ion or warranty as to the accuracy, rel iabil i ty or completeness of the Information and neither E.ON UKplc nor any of i ts subcontractors, subsidiaries, aff i l iates, employees, advisers or DECC shall have any l iabil i ty whatsoever for anydirect or indirect loss howsoever arising from the use of the Information by an y party.

Table of Contents1. Scope and Functional Requirements ................................................................................ 4

1.1. Scope of Document ................................................................................................. 4

1.2. Definitions ............................................................................................................... 4

1.3. Abbreviations .......................................................................................................... 5

2. Material Selection Process ............................................................................................... 7

2.1. General ................................................................................................................... 7

2.2. Technical Compliance ............................................................................................. 7

2.3. Economic Considerations for Material Selection ...................................................... 8

3. Material Selection Considerations .................................................................................... 9

3.1. General ................................................................................................................... 9

3.2. Internal Corrosion .................................................................................................... 9

3.3. External Corrosion ................................................................................................... 9

3.4. Internal Erosion ....................................................................................................... 9

3.5. Microbial Induced Corrosion (MIC) .......................................................................... 9

3.6. Dissimilar Metal Combinations ................................................................................ 9

3.7. Dissimilar Material Combinations ............................................................................ 93.8. Localised Corrosion ............................................................................................... 10

3.9. External Surface Protection ................................................................................... 10

3.10. Corrosion Under Insulation .................................................................................... 10

3.11. Internal Cladding ................................................................................................... 10

4. Operational Considerations ............................................................................................ 12

4.1. Corrosion Allowance and Service Life Corrosion ................................................... 12

4.2. Inspection and Corrosion Monitoring ..................................................................... 12

4.3. Corrosion Management Framework ...................................................................... 13

5. Material Properties ......................................................................................................... 14

5.1. Carbon Steel ......................................................................................................... 14

5.2. Austenitic Stainless Steel ...................................................................................... 14

5.3. Duplex Stainless Steel........................................................................................... 14

5.4. Nickel Alloys .......................................................................................................... 16

5.5. Non-metallic Materials ........................................................................................... 16

6. Material Selection ........................................................................................................... 17

6.1. Process Pipework .................................................................................................. 17


3/22


Revision: 03






6.2. Pressure Vessels and Heat Exchangers ............................................................... 17

6.3. Valves ................................................................................................................... 18

6.4. Seals ..................................................................................................................... 18

6.5. Pumps ................................................................................................................... 18

6.6. Instrumentation ..................................................................................................... 18

6.7. Typical Services .................................................................................................... 19

7. Mandatory References ................................................................................................... 20

7.1. American Standards .............................................................................................. 20

7.2. European Standards ............................................................................................. 20

7.3. International Standards ......................................................................................... 20

7.4. Norwegian Standards ............................................................................................ 20

8. Project References ......................................................................................................... 22

8.1. Project References ................................................................................................ 22

Table of Tables

Table 6.1 Process Material and Limitations ......................................................................... 17

Table 6.2 Topside Services ................................................................................................. 19


4/22


Revision: 03






1. Scope and Functional Requirements

1.1. Scope of Document

This document has been produced to outline the philosophy for the material engineering forthe offshore facility at the Hewett gas reservoir. The scope of this philosophy for KingsnorthFEED covers the following equipment:

process pipe work;

pressure vessels and heat exchangers;

valves;

seals;pumps;

instrumentation;

topside services.

The intention of this document is to provide guidelines that help narrow down a list of suitablematerials aiming for the highest technical integrity whilst being cognisant of CAPEXconstraints and operational practicality.

Structural steel for the complex items, superstructures and pipelines are outside the scope ofthis document. It should be noted that the Onshore and Offshore Pipeline Material Selection,Corrosion Protection and Monitoring Philosophy (KCP-GNS-PLD-DPR-0002) section from theonshore Kingsnorth pipeline emergency shutdown valve (ESD) to the riser ESD valve at theKingsnorth offshore platform is outside the scope of this document. However, due note has

been taken of the corrosion management strategy being considered.

1.2. Definitions

COMPANY E.ON UK or its nominated representative

CONTRACTOR The companies designated on the purchase order form as being theselected Contractor of materials and services

VENDOR The companies designated to supply materials and services

WORK The task, process or operation being conducted by theCONTRACTOR on any tier on behalf of COMPANY.

Shall Indicates mandatory requirementShould Indicates preferred course of action

May Indicates optional course of action


5/22


Revision: 03






1.3. Abbreviations

ALARP As Low As Reasonably Practical

ASME American Society of Mechanical Engineers

API American Petroleum Institute

CA Corrosion Allowance

CAPEX Capital Expenditure

CMM Corrosion Management Manual

CO2 Carbon Dioxide

CP Cathodic ProtectionCRA Corrosion Resistant Alloy

CS Carbon Steel

CUI Corrosion Under Insulation

EN Euro Norm

FEED Front End Engineering Design

FMEA Failure Mode and Effect Analysis

GRP Glass Reinforced Plastic (Fibre Glass)

HDG Hot Dipped Galvanised

HE Hydrogen Embrittlement

HIC Hydrogen Induced Cracking

HSE Health and Safety Executive

LCC Life Cycle Costing

MIC Microbial Induced Corrosion

MRP Maintenance Reference Plan

NACE National Association of Corrosion Engineers

NPT National Pipe Thread

OD Outside Diameter

OPEX Operating Expenditure

PED Pressure Equipment DirectivePFD Process Flow Diagram

P&ID Piping and Instrumentation Diagram

PPM Parts per million

PSV Pressure Safety Valve

RBI Risk Based Inspection

SCC Stress Corrosion Cracking

SLC Service Life Corrosion

SWC Step Wise Cracking

SSC Sulphide Stress Corrosion


6/22


Revision: 03






SRB Sulphide Reducing Bacteria

TSA Thermo Sprayed Aluminium


7/22


Revision: 03






2. Material Selection Process

2.1. General

The material selection process should be based on narrowing down a list of technicallycompliant materials for a specified purpose. The most economical option shall then beselected for the 40 years operational life within the constraints of health, safety, environmentaland sustainable development. Large sections of the plant will be operating above 1.5 bara,hence the requirements of the European Pressure Equipment Directive (PED) shall apply.

Internal and external environments shall be defined for normal and abnormal conditions. Areview of the process conditions, associated failure modes and the likelihood of their

occurrence shall be considered. The consequences shall be assessed by considering themanning levels and the frequency of access by personnel, etc.

The material selection process starts with a high level CAPEX & OPEX estimate (+50%/25%) aimed at identifying unusually high cost material options. Then initial materials selectionfor the primary process stream items is carried out during the concept selection stage. Forlong-lead and/or bulk items (e.g. down-hole tubing and line pipe), key materials decisionsshould be made during this stage.

It is possible that more than one technically suitable material may be taken forward for furtherconsideration. If so, the total lifecycle cost of each alternative shall be calculated, includingthe quantification of the risks and uncertainties. This process may require several iterationsbefore a solution is reached.

When materials selection for secondary process streams is carried out, more refinedjudgements on corrosion rates, life predictions, and risk assessments should be used toensure that the proposed materials will be fit for purpose. Then optimal selections can bemade to minimise cost whilst keeping within specific project parameters and risk philosophy.

2.2. Technical Compliance

There are three groups of degradation: internal corrosion, external corrosion and mechanicaldegradation. At the material selection stage, the facilities (systems and sub-systems) shall beclassified by similar corrosion threats and similar corrosion failure probabilities. In addition,key threats and associated barriers for mitigation shall be identified for assessment.

Materials selection for metallic and non-metallic materials shall cover all key service elementsincluding assessment of:

1. internal corrosion;2. external corrosion;3. erosion;4. microbial induced corrosion;5. dissimilar metal combinations;6. dissimilar material combinations;7. long term coating performance including insulation;8. pressure containment;9. external loadings;10. elevated temperature performance;11. low temperature fracture resistance.12. fatigue and creep resistance


8/22


Revision: 03






It is imperative that interfaces are established between E.ON and all Contractors with designresponsibility in order to ensure a coherent materials selection philosophy across theKingsnorth development is established. The materials selection should consider commonalityand simplification of approach between existing and new build equipment, and betweentopside, sub-sea, and onshore work scopes.

Correct material selection will mitigate against the risks of catastrophic failure mechanismssuch as stress corrosion cracking, (corrosion) fatigue and low temperature embrittlement.Coatings and corrosion inhibition shall not be used as substitutes, except for externalcorrosion where coatings and cathodic protection (CP) will be used.

An exception to the rule is only for vessels. Protecting carbon and low alloy steels by means

of internal coatings and liners is acceptable if the integrity is ensured by means of a suitablemaintenance programme, which will include detection and monitoring of corrosion.

All threats to technical integrity shall be identified and quantified using failure mode and effectanalysis (FMEA) in terms of probability of failure and its consequences. This information shallbe used to populate a risk assessment matrix where they can be ranked in order ofconsequences for the life cycle of the plant. The aim shall be to mitigate where possible, elsepropose control and recovery measures to manage the risk to as low as reasonably practical(ALARP) levels.

It is inevitable that some materials selected (i.e. carbon steel) will be prone to internal andexternal corrosion risk, where degradation by corrosion can not be 100% mitigated. Thereforecorrosion has to be managed through addition of appropriate wall thickness corrosionallowances (CA) that take into account the expected service life corrosion (SLC). The CO2

corrosion rate is one example where this can be estimated using a proprietary corrosionprediction model.

Corrosion monitoring is proposed as a means of managing corrosion for both static androtating equipment during service life. Compliance checks and verifications will have to becarried out at regular intervals to confirm their effectiveness. Access for replacement ofcomponents such as elbows or piping downstream of flow restrictions should be taken intoconsideration during layout design.

A corrosion management manual (CMM) shall be developed. The CMM shall not only beused for a structured approach to corrosion management but also used to captureorganisational learning during the life cycle of the plant. The CMM shall define keyparameters to be monitored and controlled in order to ensure appropriate inspection andmaintenance regimes are put into action.

2.3. Economic Considerations for Material Selection

Technically acceptable materials shall be narrowed down through economic assessment oflife cycle costing (LCC) for each option. Typical factors for evaluation could include;

corrosivity of process fluid and surrounding environment (i.e. risk of failure);

frequency and cost of replacement of corroded parts and sections;

fabrication costs associated with selected material;

cost and probability of success of available corrosion monitoring and inspection techniques.


9/22


Revision: 03






3. Material Selection Considerations

3.1. General

Materials of construction selected for any mechanical component shall be suitable for thedesign conditions stated in the Basis of Design for Studies [Ref(1)]. The mechanicalequipment in direct contact with the transported fluid shall be designed for the stated CO 2properties, whilst all mechanical equipment exposed to atmospheric conditions shall bedesigned for the stated environmental conditions (i.e. ambient temperature).

The following assumptions have been made:

pipeline and offshore equipment will be required to cater for both gas and dense phase flow;dryness specification is 24 ppmv with 100 ppmv for short, upset conditions to ensure thatliquid water will not drop out in the line resulting in corrosion. However, the CO 2 specificationdelivered to the pipeline will ensure that no free water or hydrate potential will exist in thepipeline or CO2 transport system;

it is assumed that the pipeline system will have a design life of 40 years.

3.2. Internal Corrosion

Internal corrosion is not anticipated since it is assumed that liquid water will not drop out.

3.3. External Corrosion

Providing protection from the elements for equipment located on the topside of the Kingsnorthoffshore platform will be extremely difficult in this highly saliferous marine environment. Theprobability of external corrosion damage is high. Coating of small bore/thin wall piping toprevent external corrosion is not recommended. This is due to the difficulties in ensuring100% coverage and implications for in service inspection and repair. Therefore materialsshould be selected that are resistant to chloride-induced corrosion without need for coating(i.e. corrosion resistant alloys (CRA)).

3.4. Internal Erosion

Internal erosion is not expected at the Kingsnorth offshore facilities because the CO 2velocities are low and entrained solids are not expected in the fluids.

3.5. Microbial Induced Corrosion (MIC)

Microbial-induced corrosion (MIC) is not expected for the Kingsnorth fluid streams.

3.6. Dissimilar Metal Combinations

Coupling of dissimilar metals shall be avoided if possible. However, if used then a suitableisolation strategy needs to be employed and the use of isolation joints must be considered.FEED contractor should produce material line diagrams to check such interfaces, particularlyat flanges or at points where design responsibility is handed over from one sub-contractor toanother.

3.7. Dissimilar Material Combinations

Care shall be taken to ensure the compatibility of coupling of dissimilar materials. Theproperties of one type of material shall not adversely affect the integrity of the other materialwhich is contact.


10/22


11/22


12/22


Revision: 03






4. Operational Considerations

4.1. Corrosion Allowance and Service Life Corrosion

The corrosion allowance is required to compensate for the service life corrosion (SLC) whichis the total estimated wall thickness reduction during the service life of the equipment.

The internal SLC shall be calculated by taking into account the duration expected in each typeof operating condition, whilst the external SLC shall be calculated by taking into account theduration expected in each type of environmental condition. Thus the corrosion allowance shallaccount for both internal and external corrosion.

If there is any possibility of corrosion cracking under the worst case design pressure andtemperature an alternative material shall be considered. Else the worst case design pressureand temperature shall be controlled within the capability of the available materials.

4.2. Inspection and Corrosion Monitoring

It is crucial to get early detection of corrosion that has taken place at any time. However, thehigher the expected SLC rate, the greater the uncertainty of the prediction, leading to higherfrequency and coverage of monitoring and inspection. Therefore OPEX tends to increaserapidly with SLC rate.

Monitoring should include surveillance of the active corrosion controls including monitoring ofkey process variables, analyses, corrosivity, or wall loss. Changes that influence theoperating envelope should be carefully noted and processed. Corrosion monitoring shall notrely on measurement devices and coupons alone, as they do not provide a complete pictureof the corrosion taking place. Therefore checks shall be made to ensure that the methodselected is functioning by monitoring and by planned inspection schedule at specifiedintervals. If this can not be done for any reason (i.e. inspection of subsea manifolds), then analternative form of corrosion control, such as selection of a CRA, shall be considered.

The main requirement for internal corrosion monitoring is the continuous water contentmonitoring via online dewpoint sampling or a moisture analyser. Control of temperature isrequired to eliminate the risk of fracture initiation and propagation. Leak detection issometimes used for monitoring corrosion failures. Real time transient modelling can be usedto implement the leak detection system.

Inspection and corrosion monitoring procedures shall be developed to ensure that thetechnical integrity of all equipment is maintained during the design life. The procedure shall

provide guidelines on frequency and locations of inspections. Ultrasonic wall thicknessinspection is recommended for the topside section and riser to ensure that no internalcorrosion has taken place. The ultrasonic wall thickness measurements need to be carriedout at the lowest position of the line.

As a minimum, inspection reports shall record operating conditions, criticality of individualsystems, corrosion and integrity related design information, and corrosion managementmanuals should be made available in electronic form. Preferably this information is enteredinto a database shared with operations staff, from which it can be readily accessed forcorrosion management purposes during the operations phase.


13/22


Revision: 03






4.3. Corrosion Management Framework

If the selection of corrosion resistant material cannot be justified, the corrosion controlmeasures will have to be put in place to ensure that the corrosion is controlled over thelifetime of the facility.

A corrosion management strategy should be in place for all equipment, not just for carbonsteel items. Procedural documents shall be produced to underpin the strategy, including:

Corrosion Management Manual (CMM);

Maintenance Reference Plan (MRP);

Risk-Based Inspection (RBI) Plan.


14/22


Revision: 03






5. Material Properties

5.1. Carbon Steel

Although carbon steel is susceptible to a variety of internal and external corrosion risks, thesuitability of the potentially low cost carbon steel shall be evaluated as a baseline cost tocompare with more corrosion resistant alternatives. In the presence of free water, CO 2 isextremely corrosive to bare carbon steel. The feasibility of carbon steel as material ofconstruction for this application depends on a rigorous control of the dew point of the CO 2 andthe suitability of the material to resist the potential lower design temperatures duringdepressurisation.

Carbon steel welds can create risks to the material properties such as hardness andtoughness in the heat-affected zones. It should be noted that welds surrounding heat affectedareas may have a lower resistance to CO2 corrosion. This is known as preferential weldcorrosion (PWC). Therefore welding procedures shall be specified according to theappropriate standards to ensure that PWC is not a risk. These procedures shall take intoaccount geometrical, chemical and metallurgical factors.

Carbon steel shall not be used in any of the offshore facilities CO2 handling systems, mainlydue to the low temperatures that would be experienced during depressurisation in theoffshore piping and valving systems. The more complex nature of the piping componentsused on the facility, when compared to the pipeline, means that carbon steel is too great arisk to be used in the offshore high pressure CO2 systems.

5.2. Austenitic Stainless Steel

Although stainless steels are resistant to corrosion under certain conditions, their resistance isinvariably limited by a combination of such factors as temperature, pH level, salinity, etc.Stainless steels suffer both pitting/crevice corrosion and nickel containing stainless steels aresusceptible to chloride induced stress corrosion cracking (SCC) in marine atmosphere.Therefore selection has to consider both internal and external risks

Pitting and crevice corrosion in saline solutions depends on factors such as the compositionof the seawater, turbulence and metal surface condition. Critical crevice corrosiontemperatures (CCT) are lower than the critical pitting temperatures; the CCT decreases asthe crevice is narrower. The risk for SCC is reduced if the metal surface temperature is keptbelow 50C for AISI 316L. However a lower temperature limitation should be applied ifinsulation is proposed.

5.3. Duplex Stainless Steel

Both 22Cr duplex and 25Cr super-duplex stainless steels can be susceptible to SCC above80 C under drop evaporation conditions. This means that accumulation of salt depositsshould be avoided. Therefore it is recommended that valves and pump bodies be constructedfrom super duplex stainless steel.

Duplex stainless steels can also suffer from hydrogen induced cracking (HIC). The minimumdesign temperature for duplex stainless steel is approximately -50C.

Although welding procedures are well established, strict procedures should be carefullyapplied and suitably qualified technicians selected to control this activity. Any weldingprocedures require close scrutiny because of risk of a brittle zone forming immediately


15/22


Revision: 03






adjacent to the fusion boundary. This zone will be sensitive to hydrogen embrittlement(hydrogen induced stress cracking) and even brittle fracture if critical flaw sizes are exceeded.


16/22


Revision: 03






5.4. Nickel Alloys

Nickel alloys are known for their good performance at high temperatures and in corrosiveconditions. However, they can suffer from inter-granular corrosion as per the limitsdetermined by ASTM G 28.

90Cu-10Ni Cupronickel is acceptable for seawater systems provided flow rates do not exceed3.5 m/s continuous service or 8 m/s intermittent service. Use of this grade should be avoidedwhere stagnant seawater may accumulate.

These materials are not recommended for duties where there are possibilities that two

surfaces could be rubbed together to cause high friction resulting in localised welding. If this isan unavoidable problem, then the specifications shall call for mitigation measures such asanti-galling compounds or electroplating.

5.5. Non-metallic Materials

Glass-reinforced plastics (GRP) consist of glass or carbon or aramid fibre matrix in a resin ofepoxy or vinyl ester or polyester, or phenolic.

In some cases glass fibres might be replaced by either carbon or aramid fibres. The fibrematerial and resin compound should be selected to suit the service conditions. GRP isparticularly suited for seawater duty.

Thermoplastics are not considered suitable for offshore duties as they are degraded by UVradiation. In addition, thermoplastics are unsuitable for large bore pipes (i.e. NB > 50mm).

Although the high pressure CO2 anticipated at the Kingsnorth offshore facilities will makethermoplastics unsuitable for process fluids, thermoplastics may be considered for utilitysystems.


17/22


Revision: 03






6. Material Selection

6.1. Process Pipework

The primary materials considered for process pipe work with their limitations are given belowin Table 6.1. It should be noted that seawater corrosion should be taken into account for therelevant sections of the down pipes.

It should be noted that these materials are not considered exclusive and other alloys may beselected for specific equipment when they can be shown to be more economical.

Where a corrosion resistant alloy has been selected to mitigate internal and external

corrosion alternatives may be considered. For example where 22Cr DSS is selected it may bepossible to use carbon steel with an internal cladding of type AISI 316L stainless steel.

Alternatively, where weight saving is a requirement the higher strength 25Cr sDSS or 6Mosuper austenitic stainless steel may be chosen.

Material

Minimum DesignTemperature

C

MaximumService

TemperatureC

Carbon Steel (CS) -20 200

Low Temperature CarbonSteel (LTCS)

-45.6 200

AISI 316(L)Stainless Steel (SS)

-105 60

22 Cr Duplex StainlessSteel (PREn35)

1(DSS)

-45.6 110

25 Cr Super DuplexStainless Steel (PREn40)

1

(sDSS)

-45.6 120

6 Mo Super AusteniticStainless Steel (PREn40)

1

(6 Mo)

-101 120

Titanium (Ti) -195 85

90/10 Copper Nickel (CuNi) -20 32

Table 6.1 Process Material and Limitations

Note

1. Pitting Resistance Equivalent (PREn) = %Cr + 3.3%Mo + 16%N

6.2. Pressure Vessels and Heat Exchangers

AISI 316L stainless steel is acceptable as an internal cladding up to a maximum servicetemperature of 93C (200F). Above this temperature, or where a low oxygen level cannot bemaintained a more corrosion resistant material such as 22Cr Duplex, Super Duplex, 904L(UNS N08904), nickel alloy 825 (UNS N08825), Solid 6Mo, or nickel alloy 625 (UNS N06625)may be required.


18/22


Revision: 03






6.3. Valves

Valve material selection will in general be the same as the piping line material specification.Exceptions may be made where, for example, weight saving can be made or the corrosivityrequires a higher grade material to minimise maintenance or downtime.

For large valves, carbon steel bodies with an internal CRA cladding may be a suitablesubstitute for solid CRA.

6.4. Seals

Compressed carbon dioxide has the ability to diffuse and dissolve in polymeric materialschanging their density. This ability is used in colouring and impregnating processes of

polymers. In elastomer seals these transport processes are unfavourable because theydestroy the structure of the material.

Elastomeric seal selection is based on key performance factors, such as;

high temperature and/or pressure;

presence of naturally occurring impurities;

difficult tolerances;

vibration;

low temperatures.

If metal-to-metal seals are required, galvanic corrosion shall be prevented by using noble sealsurface material.

6.5. PumpsPumps will also generally follow the piping specification. Exceptions, where a CRA isspecified, may be made for large components which may be made from carbon steel with aninternal CRA weld cladding.

6.6. Instrumentation

The first choice material for instrumentation shall be type AISI 316L stainless steel. Thepossibility of external pitting and crevice corrosion shall be considered for high ambienttemperatures.

Service history and current performance in the field shall be taken into account.

Where the operating temperature is above 60C a more corrosion resistant material may berequired. Materials selected are nickel alloy UNS N4400 and UNS N08825. Duplex stainless

steel UNS S31803 and super austenitic material UNS S31254 are also considered asalternatives.


19/22


Revision: 03






6.7. Typical Services

Material selection for topside services shall be based on Table 6.2.

System MaterialCorrosionAllowance Comments

Aviation fuel AISI 316L SS Nil

Diesel Oil Carbon Steel

AISI 316L SS

3 mm

Nil

Use stainless steel where cleanlinessis important.

Fresh (Potable)Water

Copper/Nickel

Copper

AISI 316L SSPlastic piping

Nil 90/10 Cu/Ni > 40 mm. (1.57)

Copper to Hard

specification.400 ppm chlorides maximum.

Hydraulic Oil AISI 316L Nil

Instrument Air AISI 316L SS Nil

Plant Air CS, HDG

Alt: 316/316L SS

3 mm

Nil SS may be cost effective.

Seal / lube Oil AISI 316L SS Nil

Seawater DSS Nil

Table 6.2 Topside Services

CS : Carbon Steel

DSS : Duplex Stainless Steel

SS : Stainless Steel


20/22


Revision: 03






7. Mandatory References

7.1. American Standards

Recommended practice for design and installation ofoffshore production platform piping systems

API RP 14E

Process piping ASME B31.3

7.2. European Standards

Metallic industrial piping EN 13480

Thermal Spraying - Wires, Rods and Cords for Flame andArc Spraying - Classification - Technical Supply Conditions

EN ISO 14919

Specification and qualification of welding procedures formetallic materials

EN 15614-1

Plastics piping systems for industrial applications Polybutene (PB), polyethylene (PE) and polypropylene(PP) Specifications for components and the system Metric series

EN ISO 15494

Directive 97/23/EC of the European Parliament and of theCouncil of 29

thMay 1997 on the approximation of the laws

of the Member States concerning pressure equipment

PED

7.3. International Standards

Petroleum and natural gas industries Steel pipe forpipeline transportation systems

ISO 3183

Specification and qualification of welding procedures formetallic materials Welding procedure test Part 1: Arcand gas welding of steels and arc welding of nickel andnickel alloys

ISO 15614-1

Petroleum and natural gas industries Cathodic protectionof pipeline transport systems Part 2: Offshore pipelines

ISO 15589-2

Petroleum and natural gas industries Glassreinforced plastics (GRP) piping

ISO 14692

7.4. Norwegian Standards

Design of duplex stainless steel subsea equipmentexposed to cathodic protection

DNV RP-F-112

Surface Preparation and Protective Coating NORSOK M-501

CO2 Corrosion Rate Calculation Model NORSOK M-506

Welding and inspection of piping NORSOK M-601


21/22


Revision: 03







22/22


Revision: 03





E.ON UK plc, i ts subcontractors, subsidiaries, aff i liates, employees, advisers, and the Department of Energy and Climate Chan ge(DECC) make no representat ion or warranty as to the accuracy, rel iabil i ty or completeness of the Information and neither E.ON UK

8. Project References

8.1. Project References

1. Genesis Report No.J71584-GEN-0001 Rev A1 Kingsnorth Carbon Capture & StorageProject Basis of Design for Studies.

2. Utility Flow Diagram Sea Water System - KCP-GNS-PCD-PFD-0001.

3. P.F.D Offshore & Transport System CO2 Process System Demo Phase (Base Case)KCP-GNS-PCD-PFD-0003.

4. Pipeline Material Selection, Corrosion Protection and Monitoring PhilosophyKCP-GNS-PLD-DPR-0002.

5. Material Selection Report for HSE Submission KCP-GNS-OPM-REP-0001

6. Corrosion Assessment and Cathodic Protection Design ReportKCP-GNS-CPT-DRP-0001

Documents

6.41 Materials Selection and Integrity Protection Report for Offshore