6.7 Pipeline Material Selection Corrosion Protection and Monitoring Philosophy

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy

Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy Table of Contents 1 

SCOPE AND FUNCTIONAL REQUIREMENTS ...................................... 3  1.1  1.2  1.3  1.4 

2 

ASSUMPTIONS ....................................................................................... 5  2.1 

3 

SCOPE OF DOCUMENT .................................................................................... 3  DEFINITIONS................................................................................................... 3  ABBREVIATIONS.............................................................................................. 4  SYSTEM OF UNITS .......................................................................................... 4 

GENERAL ....................................................................................................... 5 

DESIGN REQUIREMENTS ...................................................................... 6  3.1

INTERNAL CORROSION.................................................................................... 6

3.1.1 3.1.2 3.1.3

3.2  3.3  3.4  3.5  3.6  3.7  3.8 

4 

LINEPIPE MATERIAL ........................................................................................ 9  CORROSION RESISTANT ALLOYS ..................................................................... 9  NON-METALLIC MATERIALS............................................................................. 9  EXTERNAL CORROSION PROTECTION .............................................................. 9  CONDITION MONITORING .............................................................................. 10  LOW PIPELINE TEMPERATURES ..................................................................... 10  PROPAGATING FRACTURE HOLD 3 ............................................................... 10 

MANDATORY REFERENCES ............................................................... 11  4.1  4.2  4.3 

5 

Hydro-Testing .................................................................................................... 7 Operation-CO2 Corrosion ................................................................................... 7 Mothballing-MIC ........................................................................................................... 8 

REGULATIONS AND STATUTES....................................................................... 11  PROJECT DOCUMENTATION .......................................................................... 12  DESIGN CODES ............................................................................................ 12 

SUPPORTING REFERENCES............................................................... 13  5.1  5.2 

PROJECT DOCUMENTATION .......................................................................... 13  DESIGN CODES ............................................................................................ 13 

Table of Figures Figure 1-1: Outline System Schematic.................................................................. 3 

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy

Table of Holds HOLD No.

Description

Section

1

FEED Full system commissioning philosophy document No.

4.2

2

Low Pipeline Temperatures

3.7

3

Propagating fracture

3.8

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy

1

SCOPE AND FUNCTIONAL REQUIREMENTS

1.1

Scope of Document

This document presents the design philosophy, assumptions and design guidelines to be developed during FEED for the material selection, corrosion protection and monitoring of the CO2 pipeline from the Kingsnorth Power Station to the Hewett field. Figure 1-1 is an outline schematic of the overall system. The limits for the application of this document are defined as follows: •

Kingsnorth pipeline ESD valve;

•

Riser ESDV at Hewett platform topsides.

Figure 1-1: Outline System Schematic

1.2

Definitions

COMPANY

E.ON UK or its nominated representative.

CONTRACTOR

The companies designated on the purchase order form as being the selected Contractor of materials and services.

WORK

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

Shall

Indicates mandatory requirement

Should

Indicates preferred course of action

May

Indicates optional course of action

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy

1.3

Abbreviations

BLEVE

Boiling Liquid Expanding Vapour Explosion

BS

British Standard

CMP

Corrosion Management Programme

DNV

Det Norske Veritas

FEED

Front End Engineering Design

FGD

Flue gas desulfurization

FJC

Field Joint Coating

HSE

Health and Safety Executive

IID

Intelligent pipeline Inspection Devices

IVI

Internal Visual Inspection

ISO

International Standardisation Organisation

MIC

Microbiologically Influenced Corrosion

MMscmd

Million Standard Cubic Metre per Day

Mt

Million Tonnes

N/A

Not Applicable

NII

Non-Intrusive Inspection

NPS

Nominal Pipe Size

ppbv

Parts Per Billion by Volume

ppmv

Parts Per Million by Volume

PWA

Pipeline Works Authorisation

PWHT

Post-Weld Heat Treatment

SI

System International

SRB

Sulphate Reducing Bacteria

1.4

System of Units

Units to be used throughout the FEED design are defined in ref. [M29], Overall Project Units. During the injection and production regimes, the CO2 may exist in the gas, liquid or dense phases with varying densities. As a result, the flow rate in this report is given in tonne/day and Mt/year (as opposed to MMscmd). Specific assumptions made to adapt this mass flow rate to its equivalent volume flow rate will be clearly stated in the relevant reports.

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy

2 2.1

ASSUMPTIONS General

The following assumptions have been made: • •

• •

Pipeline will be required to cater for both gas and dense phase flow; Dryness spec is 24 ppmv with 100 ppmv for short, upset conditions to ensure that liquid water will not dropout in the line resulting in corrosion. This figure is the minimum requirement and may change during FEED 1A. However, the gas specification delivered to the pipeline will ensure that no free water or hydrate potential will exist in the pipeline or CO2 transport system; Standard conditions that will govern the design flowrate are assumed as 1.01325 bara, and 15 °C; It is assumed that the pipeline system will have a design life of 40 years.

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy

3

DESIGN REQUIREMENTS

3.1

Internal Corrosion

With respect to internal corrosion, the initial design basis is that CO2 gas will be dehydrated to a level where condensation is avoided, otherwise severe corrosion problems would be expected even without the presence of oxygen 1 . If the oxygen level is reduced to 50 ppbv or less, as a result general O2 corrosion can’t occur. The anticipated high concentrations of CO2 (99.6 mol %) will give significant corrosion problems with carbon steel if there is liquid water present. Initial estimates have put the potential oxygen level in the CO2 to be as high as 200ppmv which also suggests high corrosion potential. However, as with CO2, if there is no liquid water present then no corrosion can occur. Clearly avoiding free water in the system is critical to avoid corrosion. The dryness spec detailed in Section 2.1 is an extreme case requirement to avoid hydrates at the offshore choke, and that temporary higher water content may be completely acceptable in the pipeline, subject to confirmation during FEED 2. As a result, the control and instrumentation system will be designed to monitor the water content of the export CO2 and will shut down export if the water content exceeds permissible levels. The possible responses to a "high water content" observation in the pipeline may be to set an alarm and require operator action. During FEED 2 consideration will be given to the need for oxygen stripping (or injecting scavengers) at Kingsnorth for planned shutdown activities. In the absence of production pressure and temperature profiles a preliminary corrosion allowance of 1.5mm may be assumed (for delivery/construction and upset conditions), as there should be no corrosion during operation. This assumption shall be validated during FEED 2, in particular due to 40 year design life. The potential internal corrosion threats and their means of control are summarized in Table 3.1.1-a.

Corrosion Threat

Control

Control Management

Oxygen corrosion

Oxygen scavenger Hydro-test water quality

Water quality specification

MIC

Biocides

Operation

CO2 corrosion O2 corrosion

Dewatering Dehydrating

Corrosion monitoring Gas dryness Inspection

Upset conditions

CO2 corrosion

Corrosion allowance

Corrosion monitoring Inspection

Mothballing

MIC

Biocides

Sampling Analysis

Phase

Hydrotesting

Table 3.1.1-a Internal Corrosion Threats

1

Similar work is required to determine the impact of SOX, NOX and H2S. It is presumed that the FGD plant will remove these to the required level.

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy

3.1.1

Hydro-Testing

3.1.1.1

Oxygen Corrosion

Oxygen corrosion poses a negligible risk to the pipeline during hydro-testing. If it is assumed that the hydro-test medium is seawater, with a dissolved oxygen content of 8-10 mg/l, then the total wall thickness loss due to the reduction of all the contained oxygen would be less than 10-3 mm. Nevertheless, even this low level of corrosion threat may be eliminated by treating the hydro-test water with an oxygen scavenger such as ammonium bisulphite. Potable water may however be adopted for hydrotesting. This will be confirmed during FEED 2.

3.1.1.2

MIC

Microbiologically Influenced Corrosion (MIC) is a greater potential threat than oxygen corrosion during hydro-testing. This is because natural seawater contains multitudinous micro-organisms, including sulphate reducing bacteria (SRB) which are the species frequently implicated in MIC. SRB are obligate anaerobes. That is to say that they do not metabolize in aerated seawater. However, seawater will contain SRB spores, and these may become active if anaerobic conditions developed during hydro-test, for example due to the application of oxygen scavengers. It is most improbable that MIC could develop to any noticeable extent during the time the pipe remains filled with hydro-test medium (less than 6 months). However, there is a risk that the introduction of SRB, combined with biofilm development during hydro-testing, will result in incipient MIC. This would continue to develop during the operational life. Thus, it is recommended that the hydro-test medium is dosed with a combination of oxygen scavenger and biocide. It is further advised that the length of time that the hydro-test medium is contained within the pipelines is kept to a minimum. Although potable water may be used as the hydrotest medium (to be confirmed during FEED 2) dosing will still be required to cater for small quantities of seawater introduced during tie-in activities.

3.1.2

Operation-CO2 Corrosion

3.1.2.1

Risks

CO2 corrosion of carbon steel is the dominant threat to the integrity of the pipeline over its operational life-time. The material selection made during the conceptual phase, ref. [S1], is made on the basis of the susceptibility of carbon steel to CO2 corrosion.

3.1.2.2

Management

Corrosion management is that part of the overall management system, which is concerned with the development, implementation, review and maintenance of the corrosion strategy. The corrosion strategy provides a structured framework for identification of risks associated with corrosion, and the development and operation of suitable risk control measures. It is stressed that the development of the CMP will need to progress in parallel with the design of the project. Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy A Corrosion Assessment needs to be performed as the fluid composition data or projected operating conditions for the line are confirmed. A well designed and implemented CMP will pay dividends in terms of the integrity of the line.

3.1.2.3

Corrosion Monitoring

A number of corrosion monitoring probes are likely to be installed immediately upstream and downstream of the pipeline system at accessible locations. In-line corrosion spools may also be considered. Coupons are expected to provide monitored information on any reactivity between the flowing fluid and representative material samples including: • • •

Line pipe material; Girth weld material; Seal materials (e.g. from valves seals).

3.1.2.4

Inspection

The pipeline system will be equipped with a pig launcher at the Kingsnorth pipeline inlet and a receiver at the inlet to the offshore platform. These vessels will be specified to accommodate intelligent pipeline inspection devices (IID) that will need to be designed specifically for use in the flowing CO2 pipeline. There also may be a requirement to provide pigging heads at the landfall location, HOLD 10. Studies shall be carried out during FEED 2 to develop tools that will be compatible with and reliable in the CO2 environment. The devices will be equipped with an ultrasonic inspection tool along with other equipment and will be run frequently. The device will be designed to seek any evidence of localised or general internal/external corrosion or damage to the pipe wall. An operating strategy will be agreed in consultation with the suppler of the IID inspection services during product development and this will generate recommendations for the frequency of IID use. The pipeline is required to undergo periodic, statutory inspection to ensure continued safe and reliable operation. There can be significant cost advantages if inspections are performed from the outside of the pipeline without breaking containment i.e. non-invasively. However, there needs to be a balance between achieving these benefits and obtaining the information required to ensure continued safe and reliable operation. While it may often be the preferred option, Non-Intrusive Inspection (NII) represents a relatively new approach by comparison to Internal Visual Inspection (IVI) and many engineers responsible for inspection planning have yet to build up experience with and confidence in its application. In addition, there are a wide variety of techniques available, each with its own specific capabilities and limitations and these require to be discussed further during later stages of the project. For more information on NII refer to DNV-RP-G103, ref. [S13]. Refer to Full System Commissioning Philosophy, ref. [M27] for more information on pipeline pigging philosophy.

3.1.3

Mothballing-MIC

During FEED 2 consideration will be given to the need for oxygen stripping (or injecting scavengers) at Kingsnorth for planned shutdown activities.

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy MIC becomes a risk for the production pipeline if SRB activity has previously been allowed to develop in the system. If it becomes necessary to mothball a line that is already infected with SRB then a very stringent biocide treatment package will need to be introduced. During temporary shut downs (1-3 months) pipeline shall be filled with dry pressurised (greater than 7 bar) CO2.

3.2

Linepipe Material

Carbon steel linepipe is the economical choice for CO2 transport. Subject to any additional requirements such as those discussed above with respect to low temperature capability/toughness and internal corrosion mitigation, a high strength grade of carbon steel is expected to be generally suitable for construction of the onshore and offshore pipeline. Direct depressurisation of dense phase could lead to temperatures lower than the minimum design temperature of carbon steel; hence this issue will need to be addressed as part of the pipeline depressurisation/blowdown studies.

3.3

Corrosion Resistant Alloys

Although the main pipeline is expected to be fabricated from carbon steel, there is likely to be a requirement for corrosion resistant alloys (CRA’s) at particular locations in the system, for example valve materials, or spoolpieces subject to particularly low temperatures. Selection of suitable CRA’s shall take into consideration all relevant aspects of the service environment, including the pre-commissioning and commissioning phases.

3.4

Non-Metallic Materials

When operating in CO2 dense phase mode, the potential for leakage leading to temperatures below minus 70 ºC imposes onerous conditions on non-metallic materials such as seals. Due to liquid CO2 phase acting as a solvent swelling of elastomers may occur due to solubility/diffusion of the pressurised CO2 into the elastomer. With dense phase CO2 explosive decompression of the elastomer can occur if the system pressure is rapidly decreased. All non-metallic materials shall be tested in order to validate their suitability for the CO2 service under normal operating and transient/upset conditions.

3.5

External Corrosion Protection

The pipeline shall be protected against external corrosion using a standard anti-corrosion coating. Insulation is not required. Where the linepipe is to be subsequently concrete coated for hydrodynamic stability and/or protection, the anti-corrosion coating shall be compatible with the application of the concrete weight coating. Field joint coating (FJC) type shall be determined during FEED 2. The FJC including in-fill material shall provide an equivalent level of corrosion protection as the parent coating. The onshore pipeline will be cathodically protected using an impressed current system. Test posts will be located at a nominal spacing of 1km along the entire route of the onshore section. Isolating joints will be located at the shoreline and at Kingsnorth. The offshore pipeline shall be cathodically protected using Al-Zn-In sacrificial bracelet anodes. The cathodic protection design shall be primarily to DNV-RP-F103 supplemented by ISO 15589-2. Anti-corrosion and insulation coatings and anodes shall be compatible with the design temperatures. Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy

3.6

Condition Monitoring

The main focus of monitoring will be to identify conditions that could give rise to internal and external corrosion and to confirm that the operating conditions are being maintained in a way that corrosion is being successfully inhibited. The pipeline will also be monitored for leaks and a pipeline monitoring system should be considered so that the operating conditions can be compared continuously to expected behaviour (i.e. both simulations and historical). Particular care will be required when the system is taken from gas phase to dense phase operation. The pipeline will also be monitored for leaks (acoustic monitoring). The onshore section of the pipeline will be protected from external corrosion in its buried location by appropriate coatings and/or wrappings with holiday detection being used to confirm the coating integrity during the pipe laying process. A cathodic protection (impressed current) system will be used to inhibit external corrosion over the life of the onshore pipeline.

3.7

Low Pipeline Temperatures

When operating in dense phase mode, a leak from a CO2 transportation pipeline could chill the pipe material locally and or generally (dependent upon the type of leak) to temperatures below -70 ºC, and material selection will need to take this into account for fracture resistance. DNV is in the process of organising research into this subject as part of its CO2PIPETRANS initiative. In the event that material needs to be selected before focused research results are available, E.ON will make a selection based on advice from a number of pipe mills and fabricators that will be reviewed by E.ON and its advisors. The recommendations and decisions will be made in consultation with the HSE. HOLD 2

3.8

Propagating Fracture HOLD 3

Propagating fractures in pipelines may potentially initiate at sites where an initial flaw, most often the result of corrosion or impact damage has exceeded the critical length or crack tip opening displacement. Due to the phase change that occurs at the release point of a CO2 pipeline, the depressurization may be relatively slow therefore indicating that the distance a ductile failure may run before it arrests may be significant. Should a pipeline propagating fracture occur, the contents of a pipeline can be released within a very short period. Consequently, current CO2 pipelines are fitted with mechanical crack arrestors to address this issue; however fracture propagation control could also potentially be addressed by increased linepipe toughness and thickness. This feature of CO2 pipeline design shall be addressed during FEED 2.

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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4

MANDATORY REFERENCES

4.1

Regulations and Statutes

Pipeline construction and burial requirements shall comply with all related directives from the appropriate Port Authorities and Councils. In addition, the following acts and regulations shall be complied with: [M1]

Construction (Design & Management) Regulations 2007;

[M2]

Coast Protection Act 1974;

[M3]

Construction (Design & Management) Regulations 2007;

[M4]

Continental Shelf Act 1964;

[M5]

Environmental Protection Act 1990;

[M6]

Health and Safety at Work Act 1974;

[M7]

Offshore Installations (Safety Case) Regulations 2005;

[M8]

Offshore Installations and Wells (Design and Construction, etc.) Regulations 1996;

[M9]

Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999;

[M10]

Pipeline Safety Regulations 1996;

[M11]

The Chemicals (Hazard Information and Packaging for Supply) Regulations 1994 (SI 1994 No. 3247);

[M12]

Pressure Equipment Regulations 1996.

Pipeline Works Authorisation shall comply with all related Pipeline Inspectorate (Department of Energy) directives. In addition, the following guidelines and regulations shall be complied with: [M13]

Department for Business Enterprise and Regulatory Reform (BERR), Petroleum Act 1998: Offshore Pipelines, Guidelines for the completion of pipeline works authorisations (PWA's);

[M14]

EIA Offshore Petroleum Production and Pipe-lines (Assessment of Environmental Effects) (Amendment) Regulations;

[M15]

EPC-2002 The Offshore Installations (Emergency Pollution Control) Regulations;

[M16]

EU ETS-2005 Greenhouse Gas Emissions Trading Scheme Regulations 2005 (as amended);

[M17]

FEPA Part II (as amended) – 1985 Food and Environmental Protection Act 1985, Part II Deposits in the Sea (as amended);

[M18]

Habitats-2001 Offshore Petroleum Activities (Conservation of Habitats) Regulations;

[M19]

OCR – 2002 Offshore Chemicals Regulation;

[M20]

OPRC-1998 The Merchant Shipping (Oil Pollution Preparedness, Response Co-operation Convention) Regulations;

[M21]

PPC Offshore Combustions Installations (Prevention and Control of Pollution) (Amendment) Regulations 2007;

[M22]

OPPC-2005 Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations;

[M23]

ODS-2008 The Environmental Protection (Controls on Ozone-Depleting Substances) (Amendment) Regulations;

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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Document Title: Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy [M24]

4.2

F-Gases 2008 The Fluorinated Greenhouse Gases Regulations 2008.

Project Documentation

[M25]

FEED Health and Safety Plan, KCP-GNS-SHE-PRO-0001;

[M26]

FEED Offshore Pipeline Design Data, KCP-GNS-PLD-DPR-0005;

[M27]

FEED Full System Commissioning Philosophy HOLD 1;

[M28]

FEED Offshore Pipeline Testing and Drying Philosophy, KCP-GNS-PLD-DPR-0003;

[M29]

FEED Overall Project Units, KCP-EEN-PCD-DPR-0001.

4.3

Design Codes

[M30]

BS PD 8010:2004 Code of Practice for Pipelines Part 1: Steel Pipelines on Land and Part 2: Subsea Pipelines;

[M31]

DNV OS F101: 2008 Submarine Pipeline Systems;

[M32]

ASME B31.4 Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids;

[M33]

ASME B31.8 Gas Transmission & Distribution Piping Systems;

[M34]

DNV CO2 Pipeline Transmission Guidelines (CO2PIPETRANS) (In preparation);

[M35]

BS EN 14161 Petroleum and Natural Gas Industries Pipeline Transportation Systems;

[M36]

DNV RP J202 Design and Operation of CO2 Pipelines.

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

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5

SUPPORTING REFERENCES

5.1

Project Documentation

[S1]

Kingsnorth Phase II CO2 Pipeline Project, Pipeline Design Basis, 80011-BOD-PL-001;

[S2]

Kingsnorth Phase II CO2 Pipeline Project, Transport of CO2 by Pipeline, 80011-RPT-EN-001;

[S3]

Kingsnorth Phase 80011-RPT-PL-001;

[S4]

Kingsnorth Phase II CO2 Pipeline Project, Project Summary Report, 80011-RPT-PM-003;

II

CO2

Pipeline

Project,

Offshore

Pipeline

Routing

Report,

[S5] Submission D168, ‘Basis of Design for the Offshore Installation‘; [S6] Overall Offshore Route Map Sheet 1 of 4 (General Restriction Areas), 80011-PL-3-011.

5.2

Design Codes

[S7]

BS EN ISO 16708 Petroleum and Natural Gas Industries- Pipeline Transport SystemsReliability-based Limit State Methods;

[S8]

BS 7361-1:1991 Cathodic Protection. Code of Practice for land and Marine applications;

[S9]

DNV-RP-F109:2007 On-Bottom Stability Design of Submarine Pipelines;

[S10] DNV-RP-F105:2006 Free Spanning Pipelines; [S11] DNV-RP-F103:2003 Cathodic Protection of Submarine Pipelines by Galvanic Anodes; [S12] ISO 15589 Petroleum and Natural Gas Industries-Cathodic Protection of Pipeline Transportation Systems-Part 1: On-Land Pipelines (2003), Part 2: Offshore Pipelines (2004); [S13] DNV-RP-G103:2007 Non-Intrusive Inspection.

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.