PHEONWJ-W-PRC-0011~0 (Guidance on Offshore Pipeline Installation)

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PT. PHE ONWJ Guidance on Offshore Pipeline Installation

PHEONWJ-W-PRC-0011 Rev.0 of 27

Paper Copies are Uncontrolled

Revision Log Register

Revisions had been performed on following pages:

Page Date Revision

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Table of Content

Revision Log Register ........................................................................................................................... 2

Table of Content .................................................................................................................................... 3

1. Scope ............................................................................................................................................. 5

2. References .................................................................................................................................... 5

2.1 Local Regulation and Standards ............................................................................................. 5

2.2 Company Specification ........................................................................................................... 5

2.3 International Standards and Codes ........................................................................................ 6

3. Definition of Terms ......................................................................................................................... 6

4. Abbreviations ................................................................................................................................. 6

5. Health, Safety and Environment .................................................................................................... 6

6. Competence Assurance ................................................................................................................ 6

7. Operational Organization ............................................................................................................... 6

8. Design Data ................................................................................................................................... 7

9. Installation Equipment ................................................................................................................... 7

10. Construction Engineering and Procedures .................................................................................... 7

10.1 Engineering ......................................................................................................................... 7

10.2 Procedures .......................................................................................................................... 9

11. Pre-lay Survey ............................................................................................................................. 10

11.1 General .............................................................................................................................. 10

11.2 Scope Considerations ....................................................................................................... 10

12. Pipe Lay ....................................................................................................................................... 10

12.1 Transportation ................................................................................................................... 10

12.2 Alignment .......................................................................................................................... 10

12.3 Shallow Water Pipelines.................................................................................................... 11

12.4 Lay Operations .................................................................................................................. 11

12.5 Pipelay Equipment Check ................................................................................................. 11

12.6 Tension Control ................................................................................................................. 12

12.7 Monitoring and Control of Pipe Configuration ................................................................... 12

12.8 Strip Chart Records ........................................................................................................... 13

12.9 Abandonment and Recovery of Pipeline ........................................................................... 13

12.10 Wet and Dry Buckle Repair ........................................................................................... 14

12.11 Diving ............................................................................................................................. 14

12.12 Pipeline Initiation and Termination ................................................................................ 14

12.13 Pipe Laying Records ...................................................................................................... 15

13. Crossing ....................................................................................................................................... 15

14. Welding ........................................................................................................................................ 15

14.1 General .............................................................................................................................. 15

14.2 Equipment ......................................................................................................................... 15

14.3 Welding Consumables ...................................................................................................... 16

14.4 Welding Procedure Specification (WPS) ........................................................................... 16

14.5 Welding Procedure Qualification (WPQ) ........................................................................... 16

14.6 Qualification of Welders .................................................................................................... 16

14.7 Production Welding ........................................................................................................... 16

14.8 Repair Welding .................................................................................................................. 17

14.9 Non-Destructive Testing (NDT) ......................................................................................... 18

14.10 Field Joint Coating ......................................................................................................... 18

15. Anodes ......................................................................................................................................... 18

16. Protection Coatings—Inspection and Repair .............................................................................. 18

17. Field Joint Coating ....................................................................................................................... 18

17.1 Properties .......................................................................................................................... 18

17.2 Storage and Handling of Material ...................................................................................... 19

17.3 Surface Preparation .......................................................................................................... 19

17.4 Application of Heat Shrink Sleeves & In-Fill Material ........................................................ 19

17.5 Inspection, testing and Repair ........................................................................................... 20

18. Risers ........................................................................................................................................... 21

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18.1 Installation ......................................................................................................................... 21

18.2 Testing ............................................................................................................................... 21

19. Pipeline Stabilization and Burial .................................................................................................. 21

19.1 Procedures ........................................................................................................................ 21

19.2 Rock Dumping ................................................................................................................... 22

19.3 Inspection/Testing ............................................................................................................. 22

20. Shore Approach ........................................................................................................................... 22

20.1 Included Activities .............................................................................................................. 22

20.2 Welding and Coating Requirements ................................................................................. 22

20.3 Documentation .................................................................................................................. 22

20.4 Trenching and Burial ......................................................................................................... 22

21. Post Lay Survey ........................................................................................................................... 23

21.1 Accuracy ............................................................................................................................ 23

21.2 Survey Vessel ................................................................................................................... 23

21.3 Documentation Requirements ........................................................................................... 23

22. Maximum Span Lengths and Span Correction ............................................................................ 24

23. Hydrostatic Testing ...................................................................................................................... 24

23.1 General .............................................................................................................................. 24

23.2 Material and Equipment .................................................................................................... 24

23.3 Filling the Pipeline ............................................................................................................. 25

23.4 Restriction Test ................................................................................................................. 25

23.5 Hydrostatic Pressure Test ................................................................................................. 25

23.6 Test Records ..................................................................................................................... 26

23.7 Repair of Defects ............................................................................................................... 26

23.8 Sealing the Pipeline ........................................................................................................... 27

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1. Scope

This specification specifies requirements for the installation of offshore pipeline. It applies to

rigid metallic pipeline on offshore, and shore approach where applicable.

2. References

Design, manufacture, performance and testing shall be in compliance with the following codes

and standard, except where otherwise specified. The following documents shall form an

integral part of this specification:

2.1 Local Regulation and Standards

Peraturan Menteri ESDM

No.15 Tahun 2008

Pemberlakuan Standar Nasional Indonesia Mengenai

Sistem Transportasi Cairan Untuk Hidrokarbond dan

Standar Nasional Indonesia Mengenai Perpipaan

Transmisi dan Distribusi Gas Sebagai Standar Wajib

Decree of Mines and Energy

300.K/38/M.PE/1997

Work Safety of Oil and Gas Distribution Pipelines

Decree 84.K/38/DJM/1998 Inspection Guidelines for Safety on Facilities, Equipment

and Technology Used in Oil and Gas and Geothermal

Activity

Regulation

06P/0746/M.PE/1991 Safety Audit to Inspection, Equipment and Technique

used In Oil and Gas Mining and geothermal Activities.

Regulation Number 11-

Year 1979

Working safely on Refinery and Processing Oil and Gas

Decree of Transportation

PM No. 68 year 2011

Alur-Pelayaran di laut

SNI 3473: 2011 Sistem Transportasi Pipa Penyalur untuk Cairan

Hidrokarbon dan Cairan Lain

SNI 3474: 2009 Sistem Penyaluran dan Distribusi Pipa Gas

2.2 Company Specification

The following COMPANY Specifications shall be applied to the subject work.

x PHEONWJ-W-PRC-0005 Pipeline Welding

x PHEONWJ-W-PRC-0012 Offshore Pipeline Design

x PHEONWJ-W-PRC-0013 Offshore Pipeline Surveying

x PHEONWJ-W-PRC-0014 Pipeline Test and Pre-commissioning.

x PHEONWJ-W-SPE-0001 Pipeline Induction Bends

x PHEONWJ-W-SPE-0003 Offshore Pipeline Crossing

x PHEONWJ-W-SPE-0005 Line Pipe

x PHEONWJ-W-SPE-0006 Pipeline Corrosion Protection Coating

x PHEONWJ-W-SPE-0007 Offshore Pipeline Weight Coating

x PHEONWJ-W-SPE-0009 Riser Corrosion Protection Coating

x PHEONWJ-W-SPE-0010 Pipeline Clamp

x PHEONWJ-W-SPE-0012 Pipeline Cathodic Protection

x PHEONWJ-W-SPE-0014 Pipeline Flanges and Fittings

x PHEONWJ-W-SPE-0015 Subsea Ball Valve

x PHEONWJ-W-SPE-0016 Field Joint Coating

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2.3 International Standards and Codes

Except where otherwise noted, the latest edition of the following codes and standards

should apply:

x API RP 1111 Design, Construction, Operation, and Maintenance of

Offshore Hydrocarbon Pipelines (Limit State Design)

x ASME B31.4 Pipeline Transportation Systems for Liquid

Hydrocarbons and Other Liquids

x ASME B31.8 Gas Transmission and Distribution Piping Systems

x DNV OS-F101 Submarine Pipeline Systems

x DNV-RP-F105 Free Spanning Pipelines

x DNV-RP-F109 On-Bottom Stability Design of Submarine Pipelines

x DNV-RP-F204 Riser Fatigue

x ISO 13623 Pipeline Transportation Systems

3. Definition of Terms

COMPANY PT. Pertamina Hulu Energi Offshore North West Java

CONTRACTOR The party that carries out all or part of the design, engineering,

procurement, construction, commissioning or management of a

project.

VENDOR The party that manufactures or supplies equipment and/or services

to perform the duties specified by CONTRACTOR.

4. Abbreviations

API American Petroleum Institute

ASME American Society of Mechanical Engineers

DNV Det Norske Veritas

ISO International Organization for Standardization

SNI Standar Nasional Indonesia

5. Health, Safety and Environment

The work shall be such that the risk to personnel and environment is as low as is reasonably

practicable.

6. Competence Assurance

The work shall be carried out by suitably qualified and competent persons.

7. Operational Organization

Operational organization shall be limited to the parties actually involved and be consistent with

the size or complexity of the project. The responsibilities and duties of each function shall be

clearly defined and published to minimize uncertainties and overlapping responsibilities. The

organization chart shall indicate, as appropriate, the functional links among the following:

a) COMPANY’s representative; b) Project and Operational management;

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c) towing vessels, mooring systems and marine spread

d) weather forecasting and support services;

e) advisory panel providing expertise as required;

f) HSE;

g) Statutory, regulatory and approving bodies.

Where transfer of responsibility to another organization (e.g. from fabrication to marine

operation, or onshore to offshore), smooth hand-over shall be carried-out. Changes of

personnel during critical stages of the operation shall be avoided. Personnel as a result of shift

changes shall be identified.

8. Design Data

Pipeline design data are given on the part of Project Design Basis. Environmental data are

given to CONTRACTOR for information only. CONTRACTOR shall obtain any verification or

additional data necessary to perform installation engineering and install the pipeline(s).

9. Installation Equipment

CONTRACTOR shall provide the number, type and capacity of equipment sufficient to install

the pipeline(s) in a safe and expedient manner.

CONTRACTOR shall demonstrate in the bid the adequacy of the equipment based on the

preliminary engineering analysis. Engineering shall take into account physical conditions,

including water depth, bottom soil properties and maximum environmental conditions

anticipated during installation. Pipeline stresses during installation and testing shall not exceed

those given in Section 10.1.3 of this Guidance.

CONTRACTOR shall clearly state all environmental criteria and stresses used in the

engineering. This shall include safety factors for equipment capacity and pipeline stresses.

Following completion of detailed installation engineering, CONTRACTOR shall review all these

safety factors and demonstrate their adequacy. Should any safety factor(s) prove to be

inadequate, CONTRACTOR shall upgrade equipment as necessary.

CONTRACTOR shall ensure that all equipment proposed in the project is adequate for the use

intended and will meet or exceed any and all applicable governmental, industry, environmental,

safety and health standards and regulations. It is CONTRACTOR’s responsibility to determine

existing regulatory requirements and ensure compliance.

COMPANY reserves the right to audit all marine vessels and other construction equipment

proposed for use by CONTRACTOR. Any equipment failing to comply with either the job

specifications or environmental or safety requirements, as determined by COMPANY, shall be

replaced or modified by CONTRACTOR prior to use.

10. Construction Engineering and Procedures

10.1 Engineering

Engineering shall demonstrate the feasibility, adequacy and safety of the intended

installation methods. It shall include the preparation of the following:

x Procedures

x Manuals

x Calculations

x Descriptions and drawings

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10.1.1. Covered Activities

The following activities (where applicable) shall be covered:

1. Pre-survey engineering (detail pre-survey for subsea positioning)

2. Survey and position fixing (including subsea positioning)

3. Seabed preparation

4. Pipeline crossing preparation and completion

5. Storage, handling and transportation of materials supplied by COMPANY

and CONTRACTOR

6. Pipe tracking

7. Pipelay (including start-up, laydown, temporary protection of existing

pipelines/cables and temporary installation aids)

8. Pipelay over crossings

9. Pipelay abandonment/recovery

10. Onshore approach installation method.

11. Riser Installation

12. Pipe welding (automatic and/or manual), including weld repair

13. Welder/welding machine operator qualification

14. Radiography

15. Radiographer qualification

16. Ultrasonic examination

17. Field joint coating and protection (HSS & In-fill material)

18. Corrosion coating repair

19. Concrete coating repair

20. Span correction

21. Trenching

22. Rock dumping

23. Flooding, cleaning and gauging

24. Hydrostatic testing

25. Dewatering

26. Anchor handling and anchor patterns (including layaway pipeline/crossings

and laydown)

27. Anchoring-up at any location (e.g., commencement of operations)

28. Dynamic positioning

29. Installation of mechanical subsea connection tools

30. Spool piece installation

31. Diving operations

32. ROV operations

33. Contingency operations

a) Wet/dry pipeline buckle

b) Incorrect positioning of line

c) Anchor wire failure or jettisoning

d) Pennant failure and buoy loss

e) Damage repair to existing pipelines/cables

34. Post / As-Build Survey

10.1.2. Analysis and Calculation

As a minimum, analyses and calculations for the following activities shall be

prepared by CONTRACTOR:

1. Detail route survey to determine the requirement (if any) for seabed

preparation

2. Pipelay static and dynamic stresses to determine operating pipelay

configurations, pipe stresses and lay tensions for all pipelay conditions

(including abandonment/recovery and startup/laydown)

3. Riser and subsea spool installation

4. Pipeline trenching

5. Allowable span

6. Rock dump installation design

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7. For the bottom pull method: pull forces, buoyancy, anchor forces,

equipment capacity and safety factors

8. For the tow method: pull, buoyancy, alignment and final positioning forces,

equipment capacity and safety factors

10.1.3. Stresses and Design Formulae

Allowable stresses and design formulae for installation shall be in accordance

with the equations and limits given in Table 10.1

Table 10.1 Allowable criteria for design and installation

Activities Maximum allowable criteria

Handling, shipping, storing

Static load stress ≤ ;

as per SNI 3474:2009 and SNI 3473:2011

Overbend while Pipelaying

inc. start-up, abandonment &

recovery*

Calculated strain ≤ 0.205 % ;

as per DNV OS F-101

Sagbend while Pipelaying

inc. start-up, abandonment &

recovery*

0.87 x SMYS ;

as per DNV OS F-101

Riser

Hoop stress ≤ 0.5 SMYS for Gas

Hoop stress ≤ 0.6 SMYS for liquid

Longitudinal stress ≤ 0.8 SMYS

Combined stress ≤ 0.9 SMYS

as per SNI 3474:2009 and SNI 3473:2011

Pipeline

Hoop stress ≤ 0.72 SMYS

Longitudinal stress ≤ 0.8 SMYS

Combined stress ≤ 0.9 SMYS

as per SNI 3474:2009 and SNI 3473:2011

10.2 Procedures

CONTRACTOR shall develop all procedures required for the installation, inspection and

testing of the pipeline system.

CONTRACTOR shall ensure that no damage is done to existing pipelines and cables by

submitting and following fully developed installation procedures and installing temporary

protection where necessary. Specific anchor patterns and placement procedures shall

be developed.

10.2.1. Installation Manuals

CONTRACTOR shall prepare and submit installation manuals to cover all

aspects of the installation. These manuals shall incorporate all engineering

calculations and procedures required to define the proposed method of

installation and to demonstrate compliance.

CONTRACTOR shall prepare and submit a full index of the installation manuals

for Company review and approval.

The manuals shall include the following elements:

1. Quality plan

2. Diving manuals

3. Safety manuals

4. Document and report formats

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5. Record and inspection forms

6. Calibration procedures and certificates

7. Equipment, rigging and material certificates

8. Final documentation formats

Individual Installation Manuals shall be prepared for the following, as applicable:

1. Pre-survey

2. Shore approach preparation and landline installation

3. Pipelay

4. Assemblies installation and tie-in

5. Post trenching and rock dump

6. Cleaning, gauging and hydrotest

7. Precommissioning

8. Shore makeup yard and facilities for bottom-pull and tow methods

9. Post Survey

11. Pre-lay Survey

11.1 General

Pre-lay Survey shall be in accordance with COMPANY specification PHEONWJ-W-PRC-

0013 Guidance on Offshore Pipeline Surveying clause 5.1

11.2 Scope Considerations

The scope of the prelay survey shall be determined by specific job site conditions.

Various factors shall affect the extent of prelay survey required along the proposed

pipeline route.

These include:

x Seabed contour & conditions

x Existing obstructions (such as foreign pipelines, cables, structures, etc.)

x Archeological features

x Government regulations

x Lay techniques

x Anchor patterns

12. Pipe Lay

12.1 Transportation

Company –furnished line pipe and materials transportation shall be in accordance with

COMPANY specification, PHEONWJ-W-PRC-0009 Guidance on Pipe Handling, Storage

and Transportation section 7.

CONTRACTOR shall assume responsibility and custody for all COMPANY-furnished

materials and shall develop and maintain an inventory and tracking system for these

items.

12.2 Alignment

The final on-bottom position of the pipeline shall be located within ±10 m (33 ft) of the

approved route centerline.

The pipeline shall be laid along the predetermined route except in the vicinity of the

platform approaches and crossings. There, the on-bottom placement of the pipeline

shall have a nominal spacing of 90 m (300 ft) from other objects and shall not be closer

than 30 m (100 ft) to any adjacent pipeline. Separation between a pipeline and a

platform to which the pipeline does not have a connection is 90 m (300 ft) minimum.

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The minimum on-bottom lateral radius shall be determined and analyzed for COMPANY

review and approval.

If the sea floor is too congested to adhere to these requirements, COMPANY shall be

advised in writing and a proposed pipeline alignment shall be presented to COMPANY

for approval.

12.3 Shallow Water Pipelines

On shallow water pipelines installation, CONTRACTOR shall install and maintain lighted

buoys marking the pipeline alignment at intervals of 305 m (1000 ft) or less to drive post

laying survey.

Coordinates locating each buoy to within a 3 m (10 ft) radius circle shall be provided to

COMPANY by CONTRACTOR.

CONTRACTOR shall install and maintain buoys to locate the exact positions of all

existing pipelines, cables, obstructions or obstacles within 305 m (1000 ft) in any

direction of the pipeline right-of-way and other activity areas.

All information obtained by CONTRACTOR on the location of the various obstructions

shall be made available to COMPANY.

In lieu of buoys, CONTRACTOR may use on-board real time positioning/navigation

systems, subject to Company approval. If used, such systems shall be operational

during the entire installation period.

12.4 Lay Operations

CONTRACTOR shall perform the following as applicable:

1. Provide temporary protection, as approved by COMPANY, to existing pipelines and

structures at startup, during lay and at lay down.

2. Identify and remove obstructions within the pipelay corridor. Seabed preparation

may be required, such as boulder removal and sand wave sweep.

3. Continuously monitoring barge movement and considering marine traffic during lay

operation to avoid clashing with another boat/barge

CONTRACTOR shall provide, for COMPANY review and approval, details of all buckle

detection methods, including internal buckle detectors, diver / ROV inspection beyond

the touchdown point or constant tension monitoring and recording.

Buckle detectors shall have a diameter 95% of the minimum internal diameter of the pipe

and shall be designed to ensure that no damage is caused to the internal surfaces of the

pipelines. The buckle detector shall be pulled continuously through the pipelines on a

cable of sufficient length to ensure the pipelines are in the final configuration on the

seabed when the buckle detector passes.

CONTRACTOR shall immediately notify COMPANY if the buckle detector system fails or

is suspected to have failed and when buckle detector loads are higher than expected. In

such circumstances, CONTRACTOR shall remove the buckle detector for inspection.

12.5 Pipelay Equipment Check

CONTRACTOR shall demonstrate to the satisfaction of COMPANY that all equipment,

including associated instrumentation and controls on the lay vessel, are of a proven

design, in good condition and in full working order. The equipment capabilities shall be

demonstrated prior to leaving base and at other such times as required by COMPANY.

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CONTRACTOR shall demonstrate the accuracy of tensioner and constant tension winch

load cells prior to lay. The tension control systems shall be shown to be accurate,

efficient and reliable.

Prior to start of pipelaying, CONTRACTOR shall check the height, location and condition

of each roller support on the pipelay vessel for adherence to drawings and installation

procedures.

Rollers shall be soft-faced with molded polypropylene or similar material. Worn rollers

and tensioner shoes shall be replaced.

The rollers on the stinger shall be inspected and tested (but not limited to be witnessed

by COMPANY) prior to the start of the pipe lay and at regular intervals thereafter. No

additional inspections may be required if the job is short in duration; e.g., one week.

The inspection may be conducted by ROV (Remote Operated Vehicle) or by air divers.

Deepwater stingers, which tend to be exposed to high environmental loadings, shall be

inspected regularly.

Prior to the start of pipelay, CONTRACTOR shall check and demonstrate that the

tensioners and roller supports are precisely aligned on the centerline of the pipe ramp.

CONTRACTOR shall demonstrate the operability of the pipelay stinger prior to the

commencement of pipelay. This shall include testing loadcells, cameras and other

monitoring equipment.

All testing and checking of installation equipment shall be witness by COMPANY.

12.6 Tension Control

The force applied by the pipe tensioning equipment for control of the suspended pipe

configuration shall satisfy the following requirements:

The lowest and highest level of tension in dynamic conditions, including environmental

loading on the suspended pipe length, shall be sufficient to keep the pipe stresses within

limits prescribed in Section 10.1.3 of this Guidance.

The tensioner squeeze pressure on the pipe shall be kept below a level where the pipe

coating or anodes may be damaged.

Prior to commencement of the pipelaying, CONTRACTOR shall provide COMPANY with

a schedule of proposed tensioner settings for application along the pipeline route.

12.7 Monitoring and Control of Pipe Configuration

The pipe tension, stinger depth and angle, pipe departure angle, maximum sagbend and

overbend stresses and the water depth shall be continuously monitored.

CONTRACTOR shall propose a procedure to determine the actual suspended pipe

configuration and location of the touchdown point. The determination shall consist of

graphs or tables prepared specifically for the pipeline and shall include the following:

x Effect of pipe tension and tension variation

x Effect of variation in submerged pipe weight including wet buckle

x Effect of current induced drag on the suspended pipeline for any direction of current

x Effect of changes in lay vessel attitude orientation and position

x Abandonment and recovery of pipe

x The effect of sea state

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The pipelay operation shall be monitored by ROV a minimum of twice per day,

depending on prevailing weather conditions. At critical locations, continuous monitoring

by ROV may be required.

12.8 Strip Chart Records

CONTRACTOR shall maintain a continuous paper strip chart record of the tension

applied to the pipe at all times during pipelaying abandonment and recovery operations.

The strip chart record shall be adequately marked with the time and date at periodic

intervals and indicate the operation being carried out.

The strip chart shall record the tension applied to the pipe by each of the tensioning

devices and the tension in the cable shall be used to tension the pipe during

abandonment and recovery operation.

Numerical tension values shall be recorded on the strip chart every hour.

12.9 Abandonment and Recovery of Pipeline

CONTRACTOR shall convey the limiting sea state and operational conditions at which

pipeline abandonment should commence as well as the elapsed time required to prepare

the pipeline for abandonment.

CONTRACTOR shall monitor deteriorating weather conditions and increasing sea states

when operating conditions may exceed the operational capabilities of the lay operation.

CONTRACTOR shall initiate procedures in time to complete abandonment before the

sea state reaches the limiting conditions for safety of the pipeline.

The operating sea state limitation for a lay vessel may not be representative of the

operating capabilities of the support vessels. For example, third generation North Sea

lay vessels can lay pipe in sea states in which the anchor handling tugs and pipe haul

vessels cannot operate.

12.9.1 Required Equipment

CONTRACTOR shall ensure that the pipelaying vessel is equipped to carry out a

pipeline abandonment and recovery procedure. The minimum equipment that

shall be carried in readiness is:

x Laydown winch

x Sufficient cable length

x Abandonment/recovery heads

x Instrumentation for monitoring the A/R winch tensions during abandonment

and recovery operations shall be provided and working properly. Subject to

be tested and witnessed by COMPANY.

12.9.2 Calculations

CONTRACTOR shall prepare abandonment/recovery calculations that determine

stress levels in the pipe on the barge, stinger and sagbend; the reactions on the

barge and stinger rollers; and the forces in the abandonment/recovery cable.

Abandonment/recovery calculations shall be performed for the most critical water

depth for each different pipe diameter/wall thickness/concrete combination.

The calculations shall indicate barge and stinger configuration, roller heights,

pipe profiles and the expected pipe tension for all stages of the

abandonment/recovery operations.

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All results shall be tabulated and presented in graphic form for ease of use by

field personnel and their subsequent usage shall become an integral part of the

approved procedures.

Stresses during abandonment and recovery shall comply with Section 10.1.3 of

this Specification.

12.9.3 Heads

Any pipe end lowered in the water shall have abandonment/recovery heads.

The installation and removal of abandonment/recovery heads shall be performed

by CONTRACTOR as part of the normal pipelaying operation.

Abandonment/recovery heads shall always be on board the pipe lay barge and

kept in ready status.

Abandonment/recovery heads shall be designed and fabricated by

CONTRACTOR and be subject to COMPANY approval.

The heads shall have all necessary contingency facilities required to flood and

dewater the pipeline. These facilities shall be protected from damage by a

protective cage or equivalent.

In addition, the heads shall be equipped with suitable Company-approved

marker systems to facilitate their relocation.

12.10 Wet and Dry Buckle Repair

Wet or dry repair shall follow approved procedures. CONTRACTOR shall make all

provisions to repair a pipeline in case of buckling by installing dewatering pigs, valves in

abandonment/recovery heads, etc. as required.

All buckles shall be repaired as soon as they are discovered, unless otherwise agreed by

COMPANY.

12.11 Diving

It shall be the sole responsibility of CONTRACTOR to ensure that all diving activities are

performed in accordance with statutory diving and COMPANY regulations.

12.12 Pipeline Initiation and Termination

At commencement and termination of laying, CONTRACTOR shall be required to

position the end of the pipeline within the target areas as shown on the contract

drawings. On completion of pipe lay down, CONTRACTOR shall accurately measure

the position of the pipe end. The method for taking these measurements shall be

reviewed and approved by COMPANY prior to its use.

1. CONTRACTOR shall move or adjust the length of the pipeline if the target area is

missed during pipeline initiation and termination operations. CONTRACTOR’s

proposed procedure for moving or length adjustment shall be reviewed and

approved by COMPANY prior to commencement.

2. Existing structures shall not be used for any purposes during pipeline initiation and

termination operations other than as specifically permitted by COMPANY.

3. During initiation and termination activities, CONTRACTOR shall use cables that do

not twist when tensioned. Alternatively, swivel connectors shall be used to prevent

the transmission of cable twist to the pipe.

4. The holding power of the deadman anchor or pile startup system shall be proved by

load testing to 1.5 times the maximum predicted load, holding for 30 minutes.

CONTRACTOR shall be responsible for clearing the seabed of deadman anchor or

pile startup system.

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12.13 Pipe Laying Records

At all times during pipelay operations, CONTRACTOR shall keep accurate pipe laying

records. These records shall contain the pipe as-laid sequential number with pipe

description data that include the following:

x Pipe identification number

x Length

x Wall thickness

x Negative buoyancy

x Whether an anode is fitted

x Any other information required by COMPANY

The records shall be kept in a neat and orderly manner on recording forms previously

approved by COMPANY as part of the pipeline installation procedures. At the end of

each day, the records, including the total length and number of pipes laid, shall be

tallied and two copies supplied to COMPANY.

The sequential pipe number, referring to the pipe and adjacent field joint, shall be

clearly painted in white on both sides of each pipe near the field joint. The paint shall

be suitable for long term immersion in sea water. The digits shall be a minimum of

150 mm (6 in) high.

13. Crossing

Installation for offshore pipeline crossing shall be in accordance with COMPANY specification

PHEONWJ-W-SPE-0003 Specification for Offshore Pipeline Crossing clause 8.

The following activities shall be undertaken:

1. A detailed survey of the crossing location shall be performed comprised of a bathymetric

and side-scan sonar survey, a sub-bottom profiling video survey and the procurement of

soil samples.

2. Contour plans and longitudinal sections shall be prepared, at scales to be approved by

COMPANY, displaying all pertinent data. These shall include the location of pipelines to

be crossed, depth of burial/degree of exposure, the condition of exposed pipeline and any

obstructions in the vicinity of the proposed crossing location.

3. Details of crossing design shall be finalized, based on detailed survey results and

calculated bearing pressure (including design of gravel and rock layers in rock dump) and

submitted for Company approval.

4. Obstacles shall be removed from the vicinity of crossings and the line to be crossed shall

be lowered if required.

5. After their installation, a survey of the installed mattresses shall be performed and "as-

installed" drawings submitted for Company approval. The separation between pipelines

shall be a minimum of 0.5 m (1.6 ft).

14. Welding

14.1 General

All welding and weld inspection shall be on accordance with COMPANY specification

PHEONWJ-W-PRC-0005 Site Technical Practice (STP) Pipeline welding

14.2 Equipment

Welding equipment specification shall be in accordance with COMPANY specification

PHEONWJ-W-PRC-0005 Site Technical Practice (STP) Pipeline welding clause 4.1

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14.3 Welding Consumables

Welding equipment specification shall be in accordance with COMPANY specification


14.4 Welding Procedure Specification (WPS)

WPS shall be in accordance with COMPANY specification PHEONWJ-W-PRC-0005

Site Technical Practice (STP) Pipeline welding clause 5.3

14.5 Welding Procedure Qualification (WPQ)

Procedure qualification tests shall be in accordance with COMPANY specification


14.5.1 Test Failures

Each test weld shall be non-destructively inspected in accordance with this

Specification. Should the soundness of the test weld fail to meet the

acceptance criteria, the weld shall not be submitted for mechanical testing.

Failures due to lack of fusion or due to cracking shall be investigated and

explained to the satisfaction of COMPANY. The WPS shall then be changed

to eliminate the problems before a new qualification test weld is made.

14.5.2 Specimen Requirements

Test specimen requirements and acceptance criteria for welding procedure

qualification shall be in accordance with API STD 1104 with the following

exception: pipe diameters 114 mm (4.5 in) OD and less shall require two

tensile strength tests and the additional requirements given on the Pipeline

Design. Failure shall require a change in the WPS unless a reason apart

from the WPS is accepted by COMPANY.

14.5.3 Hyperbaric Weld WPS

Welding procedure qualification for hyperbaric welding shall be conducted in

a pressure chamber using the equipment, gas composition and gas pressure

that accurately simulates both the equipment to be used and the anticipated

conditions during the actual tie-in.

14.5.4 Consumables

Welding consumables used for the procedure qualifications and production

welds shall be from the same batch. CONTRACTOR shall ensure that

sufficient welding consumables from a single batch are available for both the

welding procedure qualification and for production welding.

14.6 Qualification of Welders

Welder qualification shall be in accordance with COMPANY specification PHEONWJ-

W-PRC-0005 Site Technical Practice (STP) Pipeline welding clause 6

14.7 Production Welding

Design and preparation of a joint for production welding shall be in accordance with

COMPANY specification PHEONWJ-W-PRC-0005 Site Technical Practice (STP)

Pipeline welding clause 7

14.7.1 End Preparation

Pipe lengths shall be supplied with the standard API SPEC 5L, 30 degree

bevel configuration, unless otherwise specified on the Pipeline Design Basis.

For pipe-to-pipe welds where wall thickness changes are involved, the joint

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design shall be approved by COMPANY. The taper shall be 1:4 between

different wall thicknesses. Pipe bevels shall be checked by means of bevel

gauges at regular intervals to ensure uniformity in bevel profiles.

14.7.2 End Inspection

A visual inspection of the pipe ends, up to a distance of 50 mm (2 in) from the

ends, shall be carried out. Any pipe bevel showing harmful effects or

evidence of end area lamination exceeding the acceptance criteria in API

SPEC 5L, shall be cut back until the defect is removed and then re-bevelled.

After re-bevelling and removing 19 mm (3/4 in) or more from the pipe, the

pipe end shall be ultrasonically inspected using an approved procedure.

14.7.3 End Cleaning

All bevels shall be cleaned by power tools to a bright finish prior to lining up

the pipe.

14.7.4 Identification and Interior Cleaning

All welds shall be identified according to the sequential field joint number

painted on the pipe coating adjacent to the field joint.

Prior to pipe alignment, but after end beveling, the inside of each pipe shall

be cleaned to remove all debris and loose material.

Each joint shall be swabbed immediately prior to aligning with the pipeline to

remove all dirt, loose mill scale and other foreign substances inside the

pipeline.

The swab shall incorporate a steel ring, 6 mm (1/4 in) thick minimum, with a

diameter 3 mm (1/8 in) less than the nominal inside pipe diameter.

In the event that the support ring will not pass through a joint, that joint shall

not be incorporated in the pipeline. It shall be clearly marked as a reject, and

then removed from the work site.

14.7.5 Alignment

Pipe end alignment shall be in accordance with COMPANY specification


clause 7.2.

14.7.6 Pre- heat treatment

Pre-heat treatment shall be in accordance with COMPANY specification


clause 7.11.1. Preheat and interpass temperatures shall be in accordance

with COMPANY Approved WPS

14.7.7 Post-Weld Heat Treatment (PWHT)

Post-heat (including PWHT) shall be in accordance with COMPANY

specification PHEONWJ-W-PRC-0005 Site Technical Practice (STP) Pipeline

welding clause 7.11.2.

14.8 Repair Welding

Repair and defects removal shall be in accordance with COMPANY specification

PHEONWJ-W-PRC-0005 Site Technical Practice (STP) Pipeline welding clause 10.

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14.9 Non-Destructive Testing (NDT)

NDT procedures shall be in accordance with COMPANY specification PHEONWJ-W-

PRC-0005 Site Technical Practice (STP) Pipeline welding clause 10.

14.10 Field Joint Coating

Field joint coating material, minimum procedure requirements, joint preparation,

coating and application procedures, and testing shall be in accordance with

COMPANY specification PHEONWJ-W-SPE-0016.

15. Anodes

Anodes installation shall be in accordance with COMPANY specification PHEONWJ-W-SPE-

0012.

16. Protection Coatings—Inspection and Repair

The inspection and repair of corrosion protection coating from damage during all phase of the

installation and prior to lowering the pipe into the water shall be in accordance with COMPANY

specification PHEONWJ-W-SPE-0006 and accordance with manufacturer recommendation.

CONTRACTOR shall complete the repair by applying approved filler placed in a pre-installed

metal form to round out the joint coating to the dimensions of the concrete. These repairs shall

be completed prior to the overbend area with adequate curing time provided.

The decision to repair damaged pipe shall be taken on a case-by-case basis. Concrete weight

coating repairs shall be in accordance with COMPANY specification PHEONWJ-W-SPE-0007

and accordance with manufacturer recommendation. Repairs are not required on a joint if:

1. The total damaged area does not exceed 300 cm2 (46.5 in2)

2. The maximum depth of a damaged area does not exceed 25 percent of the total concrete

thickness

3. There is less than 20 total damaged areas

Repeated weight coating damage shall be immediately investigated so that the cause can be

identified and remedial action taken to COMPANY’s satisfaction.

17. Field Joint Coating

17.1 Properties

The VENDOR shall provide a heat shrink sleeve which has a proven track record in

offshore pipeline construction and suitable for a minimum 10 year design life which is

suitable for a sustained operating temperature of 200°F (93.33°C) in a subsea

environment. The VENDOR shall demonstrate the track record by submitting

performance test data, including but not limited to peel strength, cathodic disbandment

and ageing for CONTRACTOR evaluation order to have COMPANY approval.

With heat shrink sleeve as the infill system, the sleeve shall be demonstrated to be

compatible with the corrosion coating and its application procedure. The dimensions

and type of the shrink sleeve shall be proposed by the VENDOR for CONTRACTOR

evaluation in order to have COMPANY approval and shall be capable of completely

covering the exposed pipe and coating cut back with a minimum coating overlap at

each side of the joint of 150 +20/-0 mm.

The VENDOR shall carry out a procedure qualification test for COMPANY approval, to

meet the field joint coating requirements..

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17.2 Storage and Handling of Material

Sleeve storage and application shall be in accordance with Manufacturer’srecommendations with the following minimum requirements:

1. On delivery of the material packages, all packages shall be visually inspected for

absence of obvious damage, integrity and acceptance for use in the project.

2. The materials shall be stored is suitable covered warehouses, raised from the

ground in order to avoid flooding, sheltered from direct sunlight and rain and shall

be stored away from any external heat source.

3. Sleeve materials shall remain in their packaging until required and shall be stored

in a dry protective environment at less than 35°C.

4. All materials shall be stored at all times in accordance with the Manufacturer’srecommendations.

5. When the materials are removed from the warehouse and delivered on the work

site, the materials shall be kept under cover protected from rain and direct sunlight,

shall be kept well closed in their original packages and raised up from the ground.

6. Materials shall be used and applied before their expiry date otherwise they shall be

discarded.

17.3 Surface Preparation

1. Surface preparation shall be in accordance with the Manufacturer’s requirementsat the time of sleeve application. Level of surface preparation required to achieve

required sleeve properties once installed shall be confirmed based on pre-

qualified testing results.

2. Prior to the commencement of the surface preparation, a visual inspection shall be

performed in order to detect any presence of defects on the field joint coating area.

3. All weld spatter, weld slag, sharp edges, etc. shall be removed from the surface of

the pipe.

4. Any contamination, visually detected, such as grease, oil, and similar

contaminants, shall be removed prior to the cleaning using a suitable solvent

according to the SSPC SP 1 specification or any other suitable mean (detergents,

water, power brushes, etc.) depending on the convenience.

5. The surface of the field joints shall be cleaned by power tool cleaning as per the

SSPC-SP-3 specification in order to obtain a minimum finishing grade of St 3 as

per the ISO 8501-1 standard.

6. After cleaning, the cleaned field joint shall be thoroughly inspected for surface

imperfections such as slivers, scabs, burrs and sharp edged defects.

7. The total area of the corrosion coating to be covered shall be wiped clean and

abraded using emery cloth prior to application. Each end of the corrosion coating

adjacent to the weld shall be feathered to exclude air pockets as the sleeve and

tape is applied.

8. Following shrinking of the sleeve, and cooling to less than 95°C, the total surface

area shall be made free of wrinkles or voids with particular attention paid to the

weld seam, corrosion coating cutback and closure strip/ overlap areas.

17.4 Application of Heat Shrink Sleeves & In-Fill Material

Heat shrink sleeves shall be applied in accordance with Manufacturer’s instructionsand in accordance with approved procedure.

Application of the in-fill material shall be performed only on concrete coated pipes after

acceptance of installation of the heat shrink sleeve. Non-reusable metallic mould shall

be used for application of the in-fill material and minimum four bands shall be used to

fix the mould onto the field joint area. Application of in-fill material shall be performed in

accordance with approved procedure and/or in accordance with the polyurethane foam

Manufacturer’s instructions.

Contractor shall fully qualify field joint coating at the early phase of the detailed

engineering. The qualification shall include at least:

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x Qualification of product material

x Qualification of applicator

x Qualification of application procedure

x Qualification in condition of use of the field joint

If necessary, preheating can be used to heat the joint up. The steel temperature locally

on welds shall not exceed 1500C

The temperature of the joint shall be at least 3°C above the dew point. At the time of

application, the temperature at the surface of the joint shall be within the temperature

range specified by the MANUFACTURER. The temperature of the joint shall be

monitored using suitable means in order to make sure that the application conditions

are fully satisfied (steel substrate and plant applied coating). During bad weather (rain,

wind, etc.) cleaning operations may only continue if effective protective awnings are

installed.

17.5 Inspection, testing and Repair

The inspection, testing and repair of heat shrink sleeves shall be in accordance with

Table 12.1 and the following requirements:

1. Surface preparation shall be inspected visually to ensure compliance with section

12.2 of this specification.

2. The field joint surface area to be covered by the sleeve shall be uniformly

preheated, if required, to the Manufacturer’s temperature requirements. A suitabletemperature probe shall be used to verify that the required preheat condition has

been achieved.

3. Immediately after shrinking, the entire surface of the sleeve shall be inspected for

surface flaws. Where present, these shall be removed in accordance with a

procedure developed by VENDOR and approved by CONTRACTOR.

4. Adhesive flow shall be evident on both sides of the sleeve.

5. Applied sleeves shall be subjected to a standard Peel Test conducted in

accordance with ASTM D-1000. Repairs must be in accordance with the

Manufacturer’s instruction and to the satisfaction of COMPANY. 6. Field joints shall be holiday detected using approved holiday detector set to a test

voltage in accordance with manufacturer’s recommendations. 7. Calibration of the holiday detector shall be performed as necessary.

8. Heat shrink sleeves, once applied, shall not be repaired. In case one holiday is

detected with holiday detector or the application of the heat shrink sleeve did not

pass visual inspection in accordance with this specification, a new heat shrink

sleeve shall be applied

9. Repair of The Field joint in-fill material, Maximum two voids per each field joint

having 75 mm in diameter or less and whose depth at the same time does not

exceed 50% of the concrete coating thickness on that pipe shall not be repaired.

Other voids shall be repaired using the same in-fill material as during the

production.

10. In case the in-fill material is damaged in a manner that it cannot be repaired, the

in-fill material (and the heat shrink sleeve if damaged during the removal of the in-

fill material) shall be removed from the field joint area. In case the heat shrink

sleeve has to be removed together with the in-fill material, the field joint coating

area shall be re-cleaned and re-coated in accordance with this specification.

11. Inspection and testing equipment shall be calibrated as required by

CONTRACTOR.

12. The VENDOR shall submit equipment calibration procedures for CONTRACTOR

review in order to have COMPANY for approval.

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Table 17.1 Inspection and Testing of Heat Shrink Sleeves

ITEM TEST TEST LOCATION ACCEPTANCE

FREQUENCY CRITERIA

Surface Preparation:

Visual Each Field Joint

100% of Field Joint

Surface Area

Free of contaminates,

surface prepared to

Manufacturer’s requirement

Preheat Temperature Each Field Joint Check at 3,6,9,12

o’clock position

Uniform Temperature ≥specified manufacturer

minimum

Shrink Sleeve Bond

to Weld Margin Each Field Joint

100% of Field Joint

Surface Area

Uniform Shrinkage and

Free of Surface Flaws

Peel Test During Qualification

Test 12 o’clock Position 2.75N/mm(ASTM D1000)

Holiday Detection Each Field Joint 100 % of Field Joint

Surface Area

Absence of Holidays at test

voltage

18. Risers

CONTRACTOR shall fabricate risers in accordance with this Specification and the job

specifications. All riser bends shall have a minimum radius of five pipe diameters. Girth welds

shall be no closer than 1.5 m (5 ft) from the centerline of any riser clamp.

18.1 Installation

CONTRACTOR shall provide sufficient bracing at installation to prevent the cathodic

protection insulating flange from supporting the riser weight.

Riser clamps shall be installed in accordance with this Specification and the job

specifications. If the clamps are to be installed on an existing structure, all marine

growth on the structure shall be removed from the structure surface where the clamp is

to be located immediately before installation.

If the riser is installed offshore, it shall be installed in accordance with procedures

approved by COMPANY.

18.2 Testing

Each riser shall be hydrostatically tested in accordance with COMPANY guidance

PHEONWJ-W-PRC-0014.

19. Pipeline Stabilization and Burial

Pipelines shall be placed below the seabed as required by applicable local marine pipeline

codes and COMPANY.

CONTRACTOR shall bottom-stabilize and/or bury the pipeline where required in accordance

with the job description and this Specification.

CONTRACTOR shall use sand/cement bags, rock dumping, grout mattresses, trenching,

jetting or other Company approved methods to fulfill the requirements of this Section.

Sandbags used for stabilization shall be 3:1 sand/cement mix. The ends of the bags shall be

folded and sewn.

19.1 Procedures

CONTRACTOR shall include detailed procedures, design drawings and calculations

relating to pipeline trenching, jetting, sandbagging or rock dumping operations in the

appropriate Installation Manual.

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Design and procedures for jetting and trenching operations shall ensure that excessive

stresses are not imposed on the pipeline due to the formation of unsupported spans or

contact between the pipeline and trenching/jetting equipment.

19.2 Rock Dumping

Rock dumping shall be designed so that impingement damage to the pipeline is

minimized. Where necessary, a sand pad shall be placed over the line prior to rock

placement.

Rock size shall be selected to ensure that the final cover profile over the pipeline and

the fill around or under the line can be achieved.

19.3 Inspection/Testing

Post-lay trenching and jetting operations shall be continuously monitored by ROV,

fixed video cameras or divers.

Inspection using ROV or other approved methods shall be made following

burial/stabilization activities to verify that the design requirements have been met.

Hydrostatic testing shall be accomplished after stabilization/burial is complete.

Verification of pipeline integrity after laying but before stabilization/burial shall be

performed as required by COMPANY.

20. Shore Approach

20.1 Included Activities

Shore approach activities shall consist of the following, as applicable:

x Pulling a section of pipeline to shore

x Trenching in foreshore including surf zone and beach

x Dredging

x Burial, using existing bottom soils or borrow materials, including rock protection

x Sheet piling, cofferdams and other temporary works

x Removal and replacement of existing shore rock protection

x Provision of signs marking onshore line route

x Fencing and securing on shore route and construction area

x Restoration of onshore facilities and topography to original conditions

x Other activities specific to the site and project

20.2 Welding and Coating Requirements

Requirements for field joint welding and coating shall be identical to the requirements

given for the offshore line unless otherwise specified.

20.3 Documentation

CONTRACTOR shall provide details of proposed equipment for pulling the shore

approach section of line in accordance with Section 4 of this Specification. Refer to

Section 7.11, Item 4 of this Specification for capacity of deadman anchors.

In addition to the procedures, installation manuals, etc. required by Section 5,

CONTRACTOR shall provide similar documentation for the shore approach as

applicable to the specific project and as required by the job specifications.

20.4 Trenching and Burial

Requirements for trenching, burial, rock protection and all other activities given in this

Section shall comply with the project specifications and drawings.

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Trenching and burial requirements shall strictly comply with applicable CFR and/or any

other authority having jurisdiction.

Any obstructions encountered shall be immediately brought to COMPANY’s attention

for resolution. CONTRACTOR shall take every precaution not to damage existing

obstructions, but in the event of their damage, shall replace or repair them at

contractor’s cost to COMPANY’s satisfaction.

21. Post Lay Survey

Post lay survey shall be in accordance with COMPANY specification PHEONWJ-W-PRC-0013

Guidance on Offshore Pipeline Surveying.

CONTRACTOR shall perform a post lay survey of the pipeline, risers, tie-ins, etc. in order to

document the as-built condition of the pipeline system. This survey shall use ROVs equipped’

with video and position-fixing equipment and/or divers where applicable. The activity shall

include, but not be limited to, the following:

x Perform a video survey of the pipeline and subsea assemblies to determine the as-built

condition.

x Determine any adverse condition such as spanning, proximity of obstructions, etc.

x Construct details of crossings.

x Remove all construction debris from the seabed.

x Perform an acoustic scanning survey of buried sections of the pipeline.

x Perform a final as-built survey and prepare as-built drawings for the entire pipeline route

showing all pertinent data and submit to COMPANY for approval.

21.1 Accuracy

x Accuracy of the survey shall be ±3 in (±1.0 ft) in the horizontal planes.

x CONTRCATOR shall resurvey any areas where post lay conditions such as

spanning or insufficient burial depth were previously identified to verify repairs.

21.2 Survey Vessel

x CONTRACTOR shall provide a survey vessel(s) to perform the as-built survey and

to assist the lay and support vessels during pipeline installation activities.

x The survey vessel shall be continuously on site during the specified operations to

monitor the as-laid position of the pipeline system; both in the horizontal and the

vertical plane.

21.3 Documentation Requirements

x As-built video surveys shall show both sides of the line and verify the on-bottom

conditions, crossing separation, joint markings where visible, etc. CONTRACTOR

shall document results of the survey activities and transmit them to COMPANY on

a daily basis.

x CONTRACTOR shall prepare scale drawings of all crossings, tie-ins, spans, etc.

showing final configuration, mat or rock dump profiles and other explanatory data.

x CONTRACTOR shall prepare as-built survey plots showing final horizontal and

vertical pipe positions, locations of important features such as anodes, crossings,

tie-ins, etc. and other information as requested by COMPANY or required by local

regulatory agencies.

CONTRACTOR shall provide COMPANY with two copies of all survey video tapes. The tapes

shall be annotated to show time, date, position and project name. Voice-over commentary may

be added to further describe the tape contents. Each tape shall be accompanied with a written

log describing contents and summarizing major conditions documented on the video.

CONTRACTOR shall also provide an index referencing the areas shown on each tape.

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22. Maximum Span Lengths and Span Correction

Design and Operation of Span correction shall be in accordance with COMPANY specification,

PHEONWJ-W-PRC-0010 Guidance on Pipeline free span correction. Maximum permissible

span lengths for pipelines shall be calculated in separate Pipeline Free span analysis.

CONTRACTOR shall be responsible for surveying the pipeline immediately after pipelay to

ensure that no freespan lengths exceed the maximum permissible after pipelaying.

All spans greater than maximum permissible span length shall be rectified prior to filling the

pipeline with water.

In the event that excessive spans are observed, CONTRACTOR shall rectify the spans by

"jetting-in" the pipeline, placement of inflating concrete bags or by suitably graded gravel/rock

dumping.

23. Hydrostatic Testing

23.1 General

Pipeline testing (including hydrostatic testing) shall be in accordance with COMPANY

guidance PHEONWJ-W-PRC-0014.

CONTRACTOR shall clean, gauge and hydrostatically test the pipeline and risers in

accordance with this Section. The test pressure shall be as specified on the Project

Design Basis at a test temperature between 2-38°C (40-100°F).

x CONTRACTOR shall submit for approval a detailed step by step procedure and

testing operations schedule a minimum of six weeks prior to the start of the test.

The procedure shall state the required equipment type and size, number and type

of pipeline pigs, inhibitor type and quantity and a description of the test monitoring

equipment.

x Prior to the start of the hydrostatic test, all riser clamp bolting shall be loose and all

riser elbow braces shall be removed. Following the completion of the test, all riser

clamps shall be tightened and the riser stop ring shall be in contact with the fixed

clamp.

x The testing operations shall be conducted diligently and thoroughly in a safe

professional manner in accordance with COMPANY approved pipeline testing

practices. Any work by CONTRACTOR or test conditions deemed by COMPANY

to be unsafe shall be corrected. The testing operations shall not continue until the

unsafe conditions have been corrected to the satisfaction of COMPANY. Nor shall

CONTRACTOR receive additional compensation for time lost due to unsafe

conditions.

x If testing is subcontracted, CONTRACTOR shall be responsible for supervising the

testing operations. COMPANY shall witness and approve all tests.

x The resulting stress from the hydrostatic test pressure, combined with other

relevant simultaneously acting stresses on the pipeline, shall not exceed 96

percent of SMYS.

23.2 Material and Equipment

CONTRACTOR shall furnish all materials and equipment for testing, including the

following items:

x Temporary pig launchers and receivers ® Cleaning and gauging pigs

x Chemicals and inhibitors

x Test instruments

x Water strainers and filters

x Fill and pressure pumps

x Meters

x Air compressors

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x Scrapers,. extra scraper brushes and cups

x All piping incidental to filling, sectionizing and transferring of water

x Portable communications equipment for use by CONTRACTOR and COMPANY

During the testing operations, CONTRACTOR shall furnish a weather proof enclosure

for pressure recorders, calibration equipment and test personnel at the data collection

site of each test section. CONTRACTOR shall also furnish sufficient lighting in the

compressor pump enclosure and test header areas. during periods of darkness when

testing operations are in progress.

23.3 Filling the Pipeline

All water injected into the pipeline shall be clean and free from suspended matter.

x A meter of sufficient size and accuracy shall be used to measure the :quantity of

water injected into the test section.

x Before water is injected into the pipeline, suspended matter in the water shall be

extracted by a filter capable of removing 99 percent of all particles 92 T (3.6 mil) in

diameter and larger or equivalent to using a 100 x 100 T (4 x 4 mil) wire-mesh

screen.

x If foreign material is pumped into the line because of faulty equipment or careless

work, CONTRACTOR shall flush the line with clean. water at no cost to

COMPANY.

x The test water may be analyzed by COMPANY to determine its suitability for use

in the testing operations and to. determine the water treatment requirements.

- Corrosion inhibitor, oxygen scavenger and biocide treatment may be used

except where environmental discharge problems of hydrotest water prevent

their use.

- Chemical treatments shall be reviewed and approved by a COMPANY early in

the project to facilitate timely injection of the chemicals into the system.

- The required chemical additives shall be injected with the water by

CONTRACTOR (immediately behind the gauging scraper pig) in

concentrations sufficient to protect the pipeline for a minimum of 6 months.

Any nearby offshore installations involved in water-making operations shall

also be notified.

23.4 Restriction Test

After running the cleaning scraper, a gauging scraper with an aluminium gauging plate

shall be forced through the line at a minimum velocity of 1 m/s (3 ft/sec).

x The gauging plate shall be no less than 6 mm thick with a diameter not over 95

percent of the minimum ID of the pipe to be tested.

x If the scraper becomes lodged and will not move by the water pressure,

CONTRACTOR shall repair the pipeline as needed to permit the scraper to make a

complete transit at the specified velocity.

Before CONTRACTOR can consider the line as having passed the test, the sizing

plate used shall be presented to COMPANY and written acceptance of the adequacy

of the restriction test shall be obtained. A deformed, bent or severely nicked plate shall

be evidence of test failure, at the discretion of COMPANY.

23.5 Hydrostatic Pressure Test

On satisfactory completion of the restriction test, CONTRACTOR shall hydrostatically

test each pipeline and riser in accordance with the following test procedures. Test

pressure and duration are given on the PHEONWJ Data Sheets for this Specification.

1. The pressure shall be raised to the test pressure specified on the PHEONWJ Data

Sheets for this Specification, allowed to stabilize then held for 15 minutes. The rate

of pressure increase shall not exceed 100 kPa (15 psi) per minute during all

operations.

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2. The pressure shall be lowered to approximately 25 percent of test pressure,

allowed to stabilize then held for 15 minutes. Rate of pressure decrease shall not

exceed 200 kPa (30 psi) per minute during all operations.

3. The pressure shall be raised to an amount approaching the test pressure and

again allowed to stabilize before it is finally raised to the test pressure. The

pressure shall not decrease more than 0.2 percent after compensating for

temperature. None of this or the foregoing shall be included in the test duration.

4. Water shall be injected or withdrawn from the test section to maintain pressure

within the specified limits. The volume of these injections and/or withdrawals shall

be measured and recorded.

5. Pressure-volume-temperature (PVT) calculations shall be performed to show any

observed pressure loss due to a temperature change or a leak.

6. A pressure recorder and temperature recorder shall be used to continuously record

the test pressure, fluid temperature and ambient temperature. In addition,

pressures shall be read and recorded to the nearest 7 kPa (1 psi), using a

deadweight tester furnished by CONTRACTOR. The pressure shall be recorded

every 15 minutes until it has stabilized; then it can be recorded every 30 minutes.

23.6 Test Records

CONTRACTOR shall furnish all testing equipment, 24 hour recording instruments and

all necessary supplies as well as maintain accurate and permanent records. The

testing and recording equipment shall be subject to Company approval. Pressure

recordings shall serve only as information data and may not be used to determine

pressure drop for pipeline leakage. Tests shall not be accepted until the specified test

duration can be recorded without pressure loss exceeding 0.2 percent of specified test

pressure.

x All recorders and dead weight testers shall be calibrated immediately prior to use.

Calibration certification shall be provided for each recorder and dead weight tester

used. Recorders shall have calibration verified following the hydrotest. Post-test

calibration failure for any recorder shall be grounds for the hydrotest to be rejected

by COMPANY.

x A time-pressure plot and pressure-volume plot shall be made during’, the pressure

test to visually record its progress. This record shall be made using the dead

weight pressure measurements and shall be used to determine if the test is

satisfactory.

x All records, data and charts clearly marked with the following information shall be

furnished to COMPANY:

- COMPANY authorized representative

- Testing contractor’s name and authorized representative

- Description of facilities tested

- Date and time of test

- Test pressure and duration Test medium used

- Explanation of any pressure discontinuities that appear on any chart

- Signatures of COMPANY’s and the testing contractor’s authorized

representatives

23.7 Repair of Defects

Failures in the line disclosed by the loss of pressure shall be located and repaired by

CONTRACTOR.

CONTRACTOR shall, at contractor’s expense, repair all defects found whether resulting

from inferior workmanship or from defective materials furnished by CONTRACTOR.

Repairs by CONTRACTOR on defective materials furnished by COMPANY shall be

compensated on a mutually acceptable basis.

After repairs have been made, the pressure test shall be repeated until the pipeline and

risers have been determined acceptable by COMPANY.

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23.8 Sealing the Pipeline

After acceptance of the hydrostatic strength and leak test, the pressure shall be released

until atmospheric pressure has been reached.

Reduction of pressure shall be conducted slowly (205 kPa [30 psi] per minute maximum) to

prevent severe piping vibration.

CONTRACTOR may be required to obtain samples of the test water to confirm that the

concentration of chemicals is adequate to protect the pipeline from internal corrosion for a

minimum of 12 months.

On Company approval of the chemical concentrations, CONTRACTOR shall seal the risers

with weld caps at the top of the jacket.

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PHEONWJ-W-PRC-0011~0 (Guidance on Offshore Pipeline Installation)

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Transcript of PHEONWJ-W-PRC-0011~0 (Guidance on Offshore Pipeline Installation)