Giap Prd 1000 Pipelay Rev c

Global Industries Title: SUBSEA PIPELINE CONSTRUCTION Asia Pacific Region Doc: GENERAL P ROCEDURE

Document No: GIAP – PRD – 1000 Rev: C Date Revised: 22 April 2004 Page: 1 of 67

Filename: GIAP PRD 1000 Pipelay Rev C.doc Date Printed: 17-Sep-04

GLOBAL INDUSTRIES

OPERATIONS

SUBSEA PIPELINE CONSTRUCTION GENERAL PROCEDURE

GIAP – PRD – 1000

Copyright

Unless signed and stamped ‘controlled’ this document is current only for two weeks after latest revision date.

Rev Description By Chk Appr Date

A Initial Document – Issued for Review & Comments RGM LK - 22 Jan 04

B Comments Incorporated – Issued for Approval RGM VA 06-Feb -04

C Issued for use in Tenders RGM GD DT 22 Apr 04

O

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SUBSEA PIPELINE CONSTRUCTION GENERAL PROCEDURE

TABLE OF CONTENTS

1.0 PURPOSE ................................................................................................................... 2

2.0 RESPONSIBILITIES.................................................................................................. 2

3.0 ACRONYMS AND ABBREVIATIONS..................................................................... 2

4.0 PIPELAY PROCEDURE ........................................................................................... 2

4.1 Pipe Lay Overview ..........................................................................................2

4.2 Lay Barge Description ....................................................................................2

4.3 Moving the Barge on Anchors.......................................................................2

4.3.1 Anchor Patterns...................................................................................2

4.3.2 Moving the Barge ................................................................................2

4.3.3 Anchor Handling..................................................................................2

4.4 Pipe Delivery and Preparation ......................................................................2

4.4.1 Line Pipe Material................................................................................2

4.4.2 Field Joint Coatings ............................................................................2

4.4.3 Cathodic Protection.............................................................................2

4.4.4 Line Pipe Delivery to the Barge ........................................................2

4.4.5 Preparation for Welding......................................................................2

4.5 Pipeline Fabrication ........................................................................................2

4.5.1 Fabrication Work Stations..................................................................2

4.5.2 Alignment of the New Joint ................................................................2

4.5.3 Welding .................................................................................................2

4.5.4 Inspection and NDT ............................................................................2

4.5.5 Weld Repairs........................................................................................2

4.5.6 Field Joint Coating and Infill ..............................................................2

4.5.7 Concrete Coating Damage ................................................................2

4.6 Pipelay Operations..........................................................................................2

4.6.1 Overbend Control ..................................................................................2

4.6.2 Sagbend Control..................................................................................2

4.6.3 Buckle Detector...................................................................................2

4.7 Initiation of Pipelay..........................................................................................2




4.7.1 Pipelay Start-up Overview .................................................................2

4.7.2 Dead Man Anchor Start -up ................................................................2

4.7.3 Platform Bowstring Start-up...............................................................2

4.7.4 Beach Crossings / Shore Start-up ....................................................2

4.7.5 Beach Crossings / Horizontal Directional Drilling...........................2

4.8 Completion of Pipelay and Tie-in ..................................................................2

4.8.1 Lay Down..............................................................................................2

4.8.2 Riser Stalk-on ......................................................................................2

4.8.3 Spool Tie-in ..........................................................................................2

4.8.4 Mid-Line Tie-in .....................................................................................2

4.9 Abandonment and Recovery .........................................................................2

4.9.1 Preparations For Abandonment........................................................2

4.9.2 Barge Pull .............................................................................................2

4.9.3 Pipeline Lowering ................................................................................2

4.9.4 Recovery Operations – General.........................................................2

4.9.5 Preparations for Recovery..................................................................2

4.9.6 Pipeline Recovery Operations ............................................................2

4.10 Contingency Operations .................................................................................2

4.10.1 Buckled Pipe – Dry Buckle..................................................................2

4.10.2 Recovery of Abandoned Wet Buckled Line......................................2

4.10.3 Weld Repair Cut-out............................................................................2

4.11 Flooding, Cleaning, Gauging, Testing and Pre-Commissioning..............2

4.11.1 Flooding, Cleaning and Gauging ......................................................2

4.11.2 Pressure Testing .................................................................................2

4.11.3 Pre-Commissioning.............................................................................2

4.12 Surveys, Spans and Route Selection ..........................................................2

4.12.1 Initial Route Surveys ...........................................................................2

4.12.2 Spanning: Avoidance and Correction ..............................................2

4.12.3 Pipeline Survey Equipment and Methods .......................................2

4.12.4 Route Survey Prior to Pipeline Installation......................................2

4.12.5 Survey Operations During Lay..........................................................2

4.12.6 Post Lay / As -built Surveys ................................................................2

4.12.7 Survey Activities on the Barge ..........................................................2

4.12.8 Final Documentation Package..........................................................2




4.13 Job / Activity Safety Analysis .........................................................................2

5.0 RELATED DOCUMENTS AND REFERENCES................................................... 2

5.1 Typical Project Procedures ............................................................................2




1.0 PURPOSE

This is a general procedure providing an overview of activities related to subsea pipeline construction (pipelay) using the "S"-Lay method from a moored construction barge. The information presented in this document is related to Global's derrick lay barge "DLB-264". The same principles apply to Global's "DLB-332" and similar lay barges. This general procedure is intended to be amended and developed as necessary to be project specific during the initial phase of each subsea pipeline construction project so as to properly reflect the scope of work, contract requirements, projec t specifications and codes, etc. This document may be subject to change without notice and it is not intended nor is it provided to be contractually binding.

2.0 RESPONSIBILITIES

Implementation of this procedure will come within the responsibilities of the following individuals / positions within the organisation of each project, as appropriate to their job descriptions (roles and responsibilities) and as delegated by these individuals to their subordinates. − Project Director − Project Manager − Project Engineer − Operations Manager − General Superintendent − Offshore Superintendent All personnel involved are responsible for following all the health, safety and environmental procedures applicable to this procedure and for observing in particular the safety notes highlighted herein.

3.0 ACRONYMS AND ABBREVIATIONS

Acronym Meaning A & R Abandonment and Recovery AHT Anchor Handling Tug ASNT American Society for Non-destructive Testing BMS Barge Management System CTE Coal Tar Epoxy (anti-corrosion coating) CSWIP Certification Scheme for Welding Inspection Personnel (UK) D-GPS Differential Global Positioning Satellite (system) DLB Derrick Lay Barge DMA Dead Man Anchor FBE Fusion Bonded Epoxy (anti-corrosion coating)




Acronym Meaning FEED Front End Engineering Design GMAW Gas Metal Arc Welding HDD Horizontal Directional Drilling HSE Health, Safety & the Environment ITP Inspection and Testing Plan MAOP Maximum Allowable Operating Pressure NDT Non-Destructive Testing ROV Remotely Operated Vehicle UT Ultrasonic Testing UTM Universal Transverse Mercator

(A global navigation position co-ordinate system)




4.0 PIPELAY PROCEDURE

4.1 Pipe Lay Overview

This general procedure deals with the S-lay method of construction for subsea pipelines. The name is taken from the shape of suspended pipe from the barge to the seabed as shown in the following diagram.

The pipeline is normally heavy in water and could bend or buckle under its own weight if simply fed off the stern of the barge. However the S-lay method controls the critical curves in the pipeline profile between the barge and seabed. The upper curve of the "S" is known as the overbend. Here the curve of the pipeline is controlled by supporting it on rollers in a "stinger" mounted on the stern of the barge. The lower curve of the "S" is known as the sagbend. This is kept in a smooth gentle curve by applying tension from the lay barge where the pipe is gripped by one or two tensioning machines. This tension is maintained by the barge's anchors. The pipeline is assembled on the barge from standard 12 meter (40-foot) lengths of line pipe. These are continually supplied to the barge from support vessels and loaded on to the barge by its deck crane.

Overbend

Sagbend

Tension

Stinger on Laybarge




Along the side of the barge are several work stations for welding, inspection (NDT) and joint coating. This is also known as the "firing line" or "pipe tunnel." Once the operations at all the stations have been completed, the barge moves forward 12 meters (40 feet) by hauling on its forward anchors and paying out on its stern anchors. At the same time, the tensioner(s) is/are operated and the pipe is moved along the barge toward the stern by 12 meters (40 feet.) This process is repeated, typically every 4 to 8 minutes, although the range can be wider depending on the diameter of the pipeline and its wall thickness, type of steel, NDT and field joint fill requirements, etc.

4.2 Lay Barge Description

The lay barges covered by this general procedure include the DLB-264 and DLB-332. These are not self-propelled but are either towed or they move using anchors and winches. They each have a heavy lift rotating derrick crane aft, a central open deck area and helideck and accommodation forward and below deck. Pipelay construction equipment (the "firing line") is located along their starboard sides, consisting of four to six welding stations, one X-ray station, one or two field joint in-fill or general purpose stations and one or two tensioning machines. A crawler crane operates on the port side open deck for general-purpose lifts including bringing pipe and materials onto the barge from vessels moored alongside. There are also over-side lifting davits. This table gives data for the key equipment. The following elevation and plan drawings illustrate the DLB-64.

Feature DLB-264 DLB-332 Barge Length 400ft (122m) 352ft (107.2m) Barge Breadth 100ft (30.4m) 100ft (30.4m) Accommodation 275 personnel 224 personnel Working deck area 17,700sqft (1,644m2) 11,400sqft (1,026m2)

Anchors 8 x Delta Flipper 25,000lb (11,340kg)

8 x Delta Flipper 25,000lb (11,340kg)

Anchor Cables 2-inch dia (50mm) x 3,300ft (1,006m)

1? -inch dia (48mm) x

4,000ft (1,220m)




Feature DLB-264 DLB-332 Anchor Winches (Single Drum)

8 x 200,000lbs (90,720kg)

8 x 130,000lbs (58,980kg)

Pipelay Capacity (OD with coating) 60-inches diameter 60-inches diameter

Over-side davits 6 x 50-s.ton (45.4te) 5 x 40-s.ton (36.3te) Abandon/Recovery (A/R) Cable

2.5-inch dia x 3,000ft (915m)

2.5-inch dia x 2,500ft (762m)

A/R Winch 300,000lb (136,054kg)

200,000lbs (90,720kg)

Main Crane (fixed) 1,100-s.ton (988te) 800-s.ton (725te)

Deck Crane Manitowoc Crawler, 90-s.ton (82te)

Manitowoc Crawler, 90-s.ton (82te)




4.3 Moving the Barge on Anchors

4.3.1 Anchor Patterns During subsea pipeline construction activities, the barge is moored using eight anchors. Each anchor cable typically consists of 1? -inch or 2-inch diameter wire rope over half a mile (one kilometre) long carried on eight single drum winches. The anchors are set out in a star pattern. During pipelay operations, normally six anchors (1,2 and 3, 6, 7 and 8) are pulling anchors set ahead of the barge, while the remaining two stern anchors are set out towards the sides to provide lateral position control.

The actual positions of the anchors will be defined during the engineering phase determined by the pipe route, other installations in the vicinity of the route, water depths and environmental conditions, etc. The required positions are plotted on anchor pattern drawings. Proposed anchor patterns will normally be submitted to the client for his review and approval prior to mobilisation of the laybarge to the field.

Anchor exclusion zones will be defined in accordance with project and client requirements. Typically, alongside an existing pipeline, no anchor would be placed closer than 650-ft (200-meters) where the anchor wire will pull towards and across the existing line or 330-ft (200-meters) where the anchor wire pull will be parallel to or away from the existing line. When anchor wires cross other pipelines or cables, then pipeline protection buoys (sometimes known as "parachute buoys") can be attached to the anchor wire to provide buoyancy and so lift the anchor wire clear of the seabed and the existing pipeline or subsea cable. The catenary profile of the anchor cables for such circumstances will be calculated during the engineering phase.

BARGE

Forward Pipeline STINGER

7

8

1

2

3 4

5 6

Typical Anchor Layout for Pipelay




4.3.2 Moving the Barge

To move the barge forward, the pulling anchor winches haul in their anchor cables while the trailing anchor winches pay out. By maintaining tension on the anchor cables, the barge is securely held in a controlled position and heading. The barge has a comprehensive computerised survey and positioning system, normally based on two differential global positioning satellite (D-GPS) systems together with gyro-compass(es), such that its heading and absolute global co-ordinate position are accurately known and can be displayed, monitored and recorded at all times. Alternative radio positioning systems than D-GPS may also be used for greater accuracy, such as when operating close to existing platforms.

When moving the barge steadily in one direction while laying pipe, the anchors are sequentially moved forward.

The anchor patterns are designed such that the barge position ensures that the laid pipe accurately follows the planned route for the new pipeline. Each anchor is moved whenever convenient so that limiting conditions are not reached. The shortest length for the anchor cables is determined by the catenary profile for the cable for the water depth. Tables based on the catenary profile for each cable related to tension and water depth are used which ensure that an appropriate length of cable will remain on the seabed. In this way, the anchor is never subjected to a force with a vertical component that would tend to lift it from the seabed. The maximum length for the anchor cables is the length of cable available on each winch.

1.

Moving the Barge ahead on its anchors. (Only four of eight anchors shown for clarity.)

1 & 2. Move barge on its anchor cables 3 & 4. Move the anchors, one at a time.

BARGE

2.

3.

ii

4.

iii

iv

BARGE

i

BARGE

BARGE




4.3.3 Anchor Handling

Anchor handling tugs (AHT) are used to relocate the anchors, one at a time, known as running the anchors. During anchor movements, the position of the tug and its anchor is plotted in real time and controlled using two interfaced survey and positioning systems: the Barge Management System mentioned above, which is linked by radio telemetry with the tug's positioning system. It is important that the "drop" point of anchors is known and controlled, particularly when operating the barge close to existing pipelines, structures and/or cables on the seabed. Anchors are broken free from the seabed and lifted by the anchor handling tug using pennant or pendant cables. The bottom end of each such cable is attached by a suitably rated shackle to its anchor, usually at the fluke end, and at the upper end to a buoy.

Global prefers generally to handle anchors using a pennant cable and pennant buoy. In this method, the buoy has a pipe fixed through it and the cable runs free through this pipe and the buoy. The eye and shackle at the top of the cable will not pass through this pipe. The anchor is lifted by the pennant cable "through" the buoy (which remains in the water.) Sometimes a pendant system is required. In this case, the buoy has a bar through it with an eye at the top and bottom. The cable to the anchor is shackled to the bottom of the buoy and always hangs there ("pendant".) To retrieve an anchor, the buoy must first be lifted onto the stern deck of the anchor handler, and then the pendant cable can be pulled in. The pendant system is not as

Pennant (runs through)

Pendant (attached /

hangs)

TYPES OF ANCHOR BUOYS




easy to use and is more time consuming than the pennant system. Once the AHT carrying an anchor has reached the new position, this is checked with the barge's navigation control. If correct, the tug is cleared to drop the anchor using a free-fall winch, so that the anchor lands quickly on the seabed with minimum change in position. The AHT then checks the drop position again before releasing the buoy. (Please refer to the Anchor Handling General Procedure and related survey and positioning procedures listed in Section 5.)

4.4 Pipe Delivery and Preparation

4.4.1 Line Pipe Material

The subsea pipeline is constructed from lengths of steel pipe, each normally about twelve meters / forty feet long, which are welded together on the barge into a continuous pipeline. Each length (or joint) of line pipe normally will have been coated on the outside with anti-corrosion coating. Typically this will be asphalt or coal tar enamel (CTE) or a fusion bonded epoxy (FBE) coating.

Larger diameter thin wall subsea pipelines will be buoyant in water. To counter this and to provide on-bottom stability, concrete weight coating is applied. The concrete is made denser than normal by using high density aggregate materials (such as iron ore) and is reinforced with steel mesh, which is fixed round the pipe before the concrete is sprayed on, building to the required thickness as determined by the pipeline design engineering.

4.4.2 Field Joint Coatings

The coatings at the ends of each length of pipe are cut back to allow for welding. After welding and NDT has been completed, the bare steel pipe at each of the field joints will be protected from corrosion by the application of cold-wrap tape and/or heat-shrink sleeves.




Inspection is carried out using a high-voltage (typically 10kV) holiday detector. Any breaks in the existing or new coating (holidays) will be suitably repaired and re-inspected.

For weight-coated pipe, the cut-back in the concrete coating is normally filled with either a hot-poured mastic or dense polyurethane or polyethylene foam. PU and PE foams are becoming the preferred field joint filling materials, being easier and more controllable in application, having equal or better properties in use and are more environmentally friendly. For all the in -fill materials, a mould is used. A thin steel sheet is wrapped around the pipe over the field joint and is band-strapped to the concrete on either side of the joint. A filling flap is left open at the twelve o'clock position. The banded sheet metal forms a mould into which the hot mastic is poured or the PU Foam is injected. Re-usable moulds may also be employed. The method of field joint coating will be selected according to the pipeline and its coating(s). Detailed procedures will be prepared based on manufacturers' recommendations. These procedures will be submitted to the client for approval during the engineering phase of the project. The in-fill of field joints is usually the last operation carried out before the pipe leaves the barge and this final in-fill station is also known as the "dope station".

Concrete Weight Coat

Anti-corrosion Coat

Steel Pipe Weld

Preparation

Elevation

Cross Section

C / L

End Detail Typical of Weight & Co rrosion Coated Pipe Joint




4.4.3 Cathodic Protection

Steel subsea pipelines are normally also provided with added corrosion protection by means of sacrificial anodes (cathodic protection). The anodes are usually made in a bracelet to be clamped around the pipe. They are made from an alloy mainly composed of zinc and/or aluminium. The anodes may have been fitted to a pre-calculated number of the joints during the coating process or the anodes may be attached during construction on the laybarge. Each anode will have a cable or strap welded to the steel of the pipeline to ensure electrical continuity. The number, type, size and spacing of the anodes will have been defined during the pipeline design engineering work.

4.4.4 Line Pipe Delivery to the Barge

The forty-foot lengths of coated line pipe material are transported to the construction barge by pipe haul barges or offshore support vessels. The derrick and/or deck cranes are used to lift each length on board using padded slings, typically wire slings with heavy duty hydraulic hose covers in the lifting bights. A spreader beam is also frequently used. Each joint will always be handled gently and carefully.

(Please refer to the Pipe Haul General Procedure listed in Section 5.0.)

crane hook

6 meter spreader beam, supported by light

lines to hook

coated pipe joint

padded slings

Typical Rigging Assembly for Handling Coated Pipe Joints

Pipe Haul Barge Alongside




Other construction material, such as anodes, field joint in-fill material, etc., loaded on suitable pallets or crates, is also normally delivered to the construction barge on the pipe haul barges along with the line pipe.

Relatively thin wall pipe with heavy concrete weight coating is susceptible to damage. Stress levels during handling and stacking will be checked during engineering to ensure these are within safe limits for the methods planned. Stacking and moving coated line pipe will always be undertaken with great care so as not to damage either the coatings or the machined ends of the pipe. If protective end-caps are used, then these must be kept in place until the joint is taken out of stock for use on the construction barge. Used end protectors should always be disposed of by returning them to shore. Sufficient pipe joints are stock piled on the laybarge to allow construction operations to proceed during periods where sea conditions prevent pipe transfer from the transport barge or during change out of the transport barge. On delivery to the barge, each pipe length shall be visually inspected. The following checks are typically carried out. i. Pipe Joint Identification Number and Heat Number ii. Weight coating damage iii. Anti-corrosion (CTE or FBE) coating damage iv. Joint out of roundness (measure diameters or using gauge) v. Bevel damage vi. Exposed steel surface for damage, scars, corrosion, pitting,

etc. vii. Internal debris or any corrosion pitting, scars or other

damage

Pipe Haul Barge

Deck Crane

Pipe Conveyor

Ready Rack Inspection & preparation

Stinger

Tensioner 1

Tensioner 2

1 2 3 4 5 6 7

Line-up station

Line pipe stock

8




4.4.5 Preparation for Welding

The line pipe is stock piled on the deck of the lay barge in storage areas. The deck crane then loads the pipe, joint by joint using padded slings, into the loading station. This has rubber-padded bumpers and guides to protect the pipe sections as they are lowered by the crane, particularly during bad weather. The loading station comprises fore-and-aft conveyor sections and rollers such that the pipe joints are moved axially towards the bow of the barge and the ready rack. In the ready rack, the pipe sections come to rest on horizontal beams, each joint separated by rollers in a conveyor system. This moves the joints across the barge towards the welding line on the starboard side. As the pipe joints are moved through the system, they are cleaned internally by manual brushing, by compressed air or by cleaning pigs, which are blown or pulled through the joint. Each pipe length is thoroughly inspected, as listed above. This will also include checking with a Gaussmeter that the inherent magnetism of the pipe is within limits. Steel pipe picks up magnetism from the earth's magnetic field. Magnetised pipe, above certain limits, distorts welding arcs and causes weld defects. The magnetism can be reduced to acceptable levels by applying de-gaussing coils at the pipe ends. Any damaged or defective pipes are moved to a segregated quarantine area. Damaged coatings can be repaired and re-inspected and other defects can be made good, all in accordance with the appropriate project procedures. Repaired pipe that is fully acceptable after inspection can be reintroduced into the ready stock. Inspection records of the repair history and inspections are maintained. For manually welded pipelines, the ends of each joint will be already machined with a suitable profile (also termed bevel or preparation) suitable for the welding process. Any rust or dirt on

Ready Rack




pre-bevelled pipe ends is removed by buffing and/or power wire brushing. For automatic welding, the weld profile normally has a "J" cross-section, and the root area at the bottom of the "J" is susceptible to damage. Hence it is usual to have the pipe delivered with square ends and to cut the bevel profile on the barge just prior to welding. Two bevelling (also called facing) machines are normally provided to work on both sides of the ready rack. As each length of pipe is taken from the ready rack, records are kept of the pipe identification and heat number for that joint and its relative position in the pipeline. A sequential joint number will normally be painted on each joint of pipe in accordance with project procedures. The length of the pipe from end preparation to end preparation is measured so that an accurate record can be maintained of the actual physical length of the pipeline being constructed. The pipe sections are moved from the ready rack pipe conveyor by transfer carts, which lift the joint from the ready rack into the supports in the welding line (or "firing line") at the line-up station, to be made ready for welding.

Safety Notes: − Pipe joints are heavy and great care must be exercised when

moving them or working around them. − Personal protective equipment will be worn at all times. − The numbers of riggers on a pipe haul barge during off-loading will

be kept to the minimum. − Personnel shall never get underneath any lifted loads. − There will be a nominated rigger foreman appointed to every lifting

operation who will be solely responsible for giving instruction signals to the crane operato r.

− Personnel on deck must avoid working in or walking into an area where any pipe may roll.

− If you notice anyone putting himself at risk, point out the danger to him and report any incidents appropriately to your supervisor.

4.5 Pipeline Fabrication

4.5.1 Fabrication Work Stations

The fabrication firing line or pipe tunnel along the starboard side of the barge consists of up to eight workstations. There is flexibility as to the functions of each workstation depending




mainly on the diameter and wall thickness of the pipe and on the type of welding employed (manual or automatic or both) and the field joint coating method to be used. The work stations are arranged approximately every forty feet (twelve meters) along the side of the barge, matching the length of individual pipe sections such that a welded joint can be found in every station. Typically the stations are used for the following functions. 1. Alignment and fit-up followed by welding of root bead and

first hot pass 2. Welding fill passes 3. Welding fill passes and/or final capping 4. Welding fill passes and/or final capping 5. NDT / spare 6. Spare / NDT / repair 7. Field Joint In-fill ("Dope Station") 8. Field Joint In-fill ("Dope Station") If there is a "piggy-back" small diameter pipeline or cable to be laid with the pipeline, this will be introduced at the last station and strapped to the line in accordance with the approved project engineering procedures. The pipeline is supported on pipe shoes, consisting of either caterpillar tracked "rollers" or hourglass roller assemblies. These are located between each work station. The supports are adjustable for height so that the vertical profile of the pipeline can be controlled and to ensure that the pipe is properly supported along its length. There are one or two pipe tensioning machines. On the DLB-264, one is located between work stations 3 and 4 and one between work stations 6 and 7. The tension machines securely grip the pipeline between opposed, hydraulically driven caterpillar tracks, profiled to centralise on the pipe. By applying tension to the pipeline, its profile between the barge and the seabed is controlled. See Section 4.6 Pipelay Operations. Once the work on the pipeline joints is complete in each workstation, the barge moves ahead on its anchors by 40 feet (12-meters or one joint length.) At the same time, the tensioning machine(s) is/are operated and the pipeline is moved longitudinally towards the stern of the barge and onto the stinger. A new joint of pipe is then added to the open end of the pipeline at the bow of the barge, and the fabrication process continues, one joint at a time.




4.5.2 Alignment of the New Joint

The first welding station or bead stall has powered roller support assemblies, which are adjustable vertically, from side to side and longitudinally. These are used to align the new joint with the open end of the pipeline. A similar powered assembly supports the open end of the pipeline, providing some movement here as well. An internal line up clamp is used. This was last used in the previous weld, which is now inside the last joint to be welded, some 40-feet (12-meters) along the firing line. A reach rod and tugger are used to pull it to the open end of the pipeline, where it is adjusted and clamped into position. The powered supports in the line-up station are used to move the newly loaded pipe joint aft until its end butts gently against the bevelled end of the pipeline. The support assemblies are then adjusted as required, to move the pipes relative to each other until joint alignment, and specifically the root gap around the circumference of the joint, are within the specified tolerances for welding. Once acceptable alignment is achieved, the internal line-up clamp is clamped to the new pipe joint.

4.5.3 Welding

The task of welding each complete butt-weld is divided between several (up to six) consecutive workstations. The welding process is sequentially completed in accordance with the approved welding procedure(s) for the project. These will have been prepared based on the pipeline material and service, etc. and submitted to the client for approval during the engineering phase of the project. The first welding station on a laybarge is commonly known as bead stall. This is located where the new length of pipe has just been aligned and clamped to the open end of the pipeline being fabricated. The welders will complete the critical root pass (or stringer bead) and the hot pass in this first welding station.

Line up Clamp




Global frequently utilises the Serimer-Dasa semi-automatic welding process. A band is clamped alongside the weld and two welding heads (or bugs) travel simultaneously around the weld. This system is capable of depositing the bead and hot pass in a single run. Each bug will travel 180o or half the circumference of the joint. Due to the welding speed that can be achieved with this process, there is possibility that even a portion of the first fill pass after the hot pass can be deposited in the bead stall. While the newly loaded pipe joint is being aligned and welded in the bead stall, successive layers of the butt weld are added at weld stations 2 through 4 or 5. Stations 4 and 5 are where the final capping for the weld is usually completed. Brushing, grinding, chipping and MPI inspection of each completed pass may be carried out, in accordance with the requirements of the welding procedure, before the next pass is deposited. Only qualified welders for the welding process in use may perform welding operations.

Automatic Welding

Completed Weld




4.5.4 Inspection and NDT a. Welding Quality Control and Inspection Quality control inspection will be carried out in accordance with the approved procedures and the applicable codes and specifications for the project. Inspection personnel will be appropriately experienced, qualified and will hold current certification according to their duties. Certification will be typically issued by PCN (previously CSWIP), ASNT, etc. Prior to the start of welding operations the welding equipment, welding consumables, storage and operating conditions, and welder or operator qualifications shall be verified for validity, currency and conformance with the project specification, welding procedure(s) and codes. Selected pipe end bevels shall be inspected prior to fit-up to ensure compliance with requirements for bevel angle, land width, surface roughness and bevel area surface preparation requirements. Bevels that are outside specified limits shall not be allowed to progress into the fitting and welding operation. The fit-up for each weld will be initially assessed by the welder(s) however the inspector should confirm fit up dimensions are within specified limits on a minimum number of joints per shift. If called for by the welding procedure, inter-pass inspection will be carried out as required. Typically this could include visual inspection and magnetic particle inspection (MPI) using a dry powder technique on the hot metal surface. During welding, the inspector should monitor and record on a regular basis the pre-heat and inter-pass heat temperatures and the welding currents and voltages being used. Upon completion of welding, each weld shall be subjected to a thorough visual inspection. Such inspection shall include the entire visible weld surface as well as the adjacent parent material. The inspection shall be performed as soon as practical after welding is completed and the weld has cooled. If necessary, the weld area shall be cleaned by power brushing or other suitable means first. Attention will be paid to weld size and profile and to note any undercutting. b. NDT Every weld in the pipeline will be subjected to 100% volumetric non-destructive testing (NDT) in accordance with the approved




welding and inspection procedures. Such inspection takes place in the designated NDT workstation, and may be either radiographic inspection or automated ultrasonic inspection. Radiographic inspection is carried out for larger diameter pipelines using x-rays or gamma-rays produced from a battery-powered crawler machine inside the pipe. This type of system enables the full circumference and weld to be radiographed in a single exposure (single wall, single image technique.) Gamma-ray crawlers normally use a source radioisotope of Iridium 192 and are of smaller diameter than x-ray machines, down to 6-inches. Small diameter pipe can be radiographed with both the source and film external to the pipe, using the double wall, single image technique. This method takes at least three shots, usually more, to achieve adequate distortion-free cover of the whole circumference and consequently is more time consuming and not preferred. Internal radiographic crawler machines are remotely controlled from outside the pipe using a small control source (normally about 10 millicuries of typically Caesium 137). This passes signals through the wall of the pipe to a detector system on the crawler, which instruct the crawler to be drive backwards or forwards. The crawler is stopped at the weld to be inspected by placing the control source on the pipe at a predetermined distance from the weld. Once the crawler has stopped in the correct position, removal of the control source will trigger the x-ray or gamma ray exposure from the crawler. The progress of the crawler inside the pipeline can be monitored by attaching a small tracker source to the crawler. Radiation emitted from this is detected by an external monitor, indicating the exact position of the crawler. A "stopper trolley" may be pulled along inside the pipe by a rope attached to the alignment clamp at the first welding station. The rope is long enough such that the trolley is further down the pipe than the NDT station. The trolley acts as a safety device in case the crawler malfunctions and tries to drive away down the pipeline. It can also be useful to retrieve a broken down crawler if necessary.

Safety Notes:

X and Gamma Radiation is dangerous but you can't feel it. − All personnel involved in radiography shall wear personal dosimeters to

monitor the total amounts of radiation to which they have been exposed. − At the start of the project and from time to time thereafter, radiation levels

at the outside of the NDT workstation, including above and below, shall be




measured during radiographic exposures typical for the project and screening (lead or steel) and barriers shall be used to ensure that levels are safe for other personnel.

− Only approved radiographic personnel shall enter the NDT bay during production. Radiation monitors and alarms, warning signs and flashing lights should be used and all personnel will be clear of the radiation area immediately prior to and during any exposure.

− All radioisotope sources will be stored and used in lockable shielded containers and when not in use will be held in a special locked store fitted with warning signs. Radiation monitoring will be used every time a source is moved and used to ensure that it is safely inside its container and that the radiation around the storage area is within the maximum allowable level.

Exposed radiographic film is promptly developed using automatic processing equipment in a dedicated darkroom located close to the NDT workstation. A qualified radiographic interpreter will interpret the radiograph in accordance with the applicable code to determine the absence of significant defects and the acceptability of the weld. Automatic ultrasonic inspection (ultrasonic testing or UT) is becoming an accepted alternative to radiography, particularly for the inspection of automatic welding. With mechanised UT, an array of shear wave (angle) probes and compression wave (0º) probes are moved around the girth weld by a carrier moving on a track. The track can be the same one as was used for the original automatic welding. The electronic signals from the probes are digitised, displayed and recorded in real-time. Normally, electronic "gates" are pre -set such that signals indicating the presence of defects exceeding acceptance levels will trigger an alarm automatically. The equipment must be regularly calibrated against test-pieces containing artificial defects of specific sizes in accordance with the welding codes.

4.5.5 Weld Repairs

If any weld is not acceptable within the welding code or project specification requirements following inspection, pipelay operations will be suspended and the weld repair procedure will commence. The NDT technician will review the radiograph and identify the specific defect and location thereof. Depending on the location of the weld defect, the lay barge may be required to back-up in order to position the specific weld in front of the tensioner. The defect area of the weld is marked by the welders, followed by grinding of the welded metal until the defect is exposed and removed. The welders will then perform repair welding in accordance with the approved repair welding




procedure. The repaired area of the weld will be re-examined using the same radiographic process as was used originally, and the radiograph(s) will be interpreted accordingly. If the repair is acceptable, normal pipelay operations will proceed. If the repair is not acceptable, the weld may be re-repaired a second time, which is usually allowed by most clients. If the re-repair is still not successful, normally the weld will then be removed by cutting out. See below, Contingency Operations, Section 4.10.3, Weld Repair Cut-out.

4.5.6 Field Joint Coating and Infill

Care will be exercised in handling pipe to preserve the original coating intact during pipeline installation. Steel slings or chains will not be used in direct contact with the pipe coating. Damage or holidays occurring in the pipe coating will be repaired following approved procedures. Suitable materials, including shrink sleeve tape, and primer for coal tar enamel coated pipe or repair sticks for fusion bonded epoxy coated pipe will be available on the barge. a. Field Joint Anti-corrosion Coating The most common method of applying anti -corrosion coat to field joints is by using Serviwrap (or equivalent) proprietary shrink sleeve tape. This general procedure will describe the process of applying such a typical tape. However, a detailed procedure for the actual material and method to be employed for a specific project will be prepared during the engineering phase and submitted to the client for his review and approval. The dry exposed steel is first thoroughly cleaned by power wire brushing to remove dirt, scale and weld spatter and any oil and grease is removed by solvents. Any existing anti-corrosion coating not firmly bonded to the pipe will be cut away and the cut edges will be uniformly tapered. The Serviwrap tape should be supplied in a roll with width just less than that of the exposed steel between the edges of the existing yard-applied coating. Once applied, this will leave a narrow gap at each end of the new tape. Six-inch wide tape is then applied over each gap, overlapping both the existing coating and the new tape, so that the joint is completely covered. The wraps should be pre-cut to a length at least some 6-inches longer than the circumference of the line pipe so that when it is




applied, a good overlap is achieved. The tape has a thick adhesive coating on one side, protected by a backing paper. Once the joint has been cleaned, the riggers applying the tape remove the backing paper and hold the length of wrap taut under the pipe, adhesive side up. They lift the wrap and maintaining tension, bring it smoothly over each side and then overlap it at the top. The tape adheres strongly to itself. The remaining heat in the pipe from the welding process causes the tape to shrink slightly. If the pipe heat is not sufficient, additional heat maybe supplied using a butane torch. Any trapped air bubbles should be squeezed out. There shall be no wrinkles or sags. In the event of improper application, the tape shall be removed and the process repeated. Once the centre wide section of tape has been applied, the narrower tape at each side shall be applied in a similar manner to that described above.

After each field joint has been coated and any damaged areas of existing pipe coating repaired, the surface will be visually inspected and tested for pin-holes or imperceptible damage using a high voltage electric holiday detector. The detector should be operated in accordance with the detailed procedure, but typically at a sufficiently high voltage to cause a spark to jump a gap equal to twice the thickness of the shrink sleeve or other coating (approximately 100 volts per mil thickness). The output voltage should be periodically measured with a meter to insure that it remains acceptable. b. FBE Coating If the pipeline does not have weight coating and has an FBE coating, then the field joints may be coated with fusion bonded epoxy instead of shrink sleeve tape. Any oil or grease contaminating the surface to be FBE coated will be removed with a suitable solvent cleaner applied with clean lint-free rags. The bare steel is grit blasted to the specified surface finish. The edges

Concrete Weight Coat

Existing Anti- corrosion Coat

Second Tape Wrap

Third tape wrap (still to be applied) First Tape Wrap

Wrapping Anti-corrosion Tape on Field Joints (Typical)




of the yard-applied parent coating will be feathered or roughened during blasting to provide for good adhesion of the new coating. The pipe in that area is heated using a clamp-on induction coil or coils. On completion of the heating cycle, once the correct temperature has been achieved as indicated by an infra-red radiation remote thermometer or using "Tempil" sticks, the heating equipment is removed and FBE powder is sprayed onto the surface. This is normally done using proprietary equipment including two applicator (flocking) guns on a motorised rotating ring, fed from a fluidised bed powder mixing reservoir. Once on the hot steel, the FBE powder fuses into a continuous coating and bonds closely to the steel. Spraying is carefully controlled to ensure the correct coating thickness is applied as subsequently measured by a suitable coating thickness gauge once the temperature has fallen. High voltage holiday detection inspection will be used to supplement close visual inspection and any defects will be repaired using hot melt sticks or the coating manufacturer's proprietary repair procedures. c. Field Joint In-fill For concrete weight-coated pipelines, hot-poured mastic or polyurethane / polyethylene foam in-fill will be applied to all field joints. Detailed field joint make-up procedures will be furnished during the engineering phase of any specific project as appropriate for the approved materials and based on the material manufacturer's methods and recommendations. Mastic is a bituminous material that can be poured when hot (between 170º C to 190º C) and sets solid once it has cooled. This material has been used very commonly for field joint filling. The application temperature will be as prescribed by the manufacturer. Care should be taken to check that this is not outside the temperature limits set by the anti-corrosion tape manufacturer to avoid damage to the anti-corrosion coating. Wire reinforcement will not be used with mastic filler. A sheet metal form will be installed around the field joint area and kept in place until the field joint filler material has hardened by band straps. This mould is normally made from sheet metal, generally 0.45-0.60mm thick. The metal sheet is wrapped around the pipe over the field joint area overlapping the concrete weight coating at the sides by approximately 6 inches. The mould is securely strapped and banded in place. A filling flap, approximately 8 inches deep by 12 inches wide, will have been pre-cut in the sheet. The mould is applied such that the flap is




located at the top of the mould (12 o'clock position.) The flap will be closed and banded shut after mastic filling is completed and inspection has been found satisfactory. The mastic is normally melted in a purpose designed kettle with electric heating and mechanically rotating paddles. The kettle shall have temperature gauge(s) and hand-held thermometers are also used to check the melted mastic temperature in the kettle and during pours. Kettle operations should avoid: − Overcharging higher than the top of the paddles (causes

incomplete mixing and insufficient heat at the top layers.) − Allowing the level to fall below the level of the central paddle

shaft or heater element (causes over heating, coking and is a possible fire hazard.)

− Leaving the lid open apart from during charging or temperature checks.

New mastic material added must be allowed sufficient time in the kettle to come up to application temperature before use. The kettle should be carefully cleaned before and after use to avoid contaminating the mastic mix with foreign matter or overcooked mastic residue from prior usage. Diesel, or similar hydrocarbon solvents, should never be used to clean kettle chutes or pipe surfaces. If it should be become necessary to hold the mastic in the kettle for more than two hours during breaks in production, the lids should remain closed, the heat decreased and the agitators left on. A small amount of new mastic should be added to the kettle to replace that driven off by the continued application of heat and thus return the mix to its normal application consistency. If production will be interrupted for more than six hours, the kettle should be drained. While the mould is being filled, the mastic in it should be agitated with a power vibrator to ensure complete filling and the elimination of voids or large air pockets. Water can be sprayed onto the completed filled joint to accelerate the cooling and setting time.

Mastic Kettle




4.5.7 Concrete Coating Damage

The purpose of the concrete coating is to provide weight to the pipe. Quite severe damage, such as stress cracks, spalling or mechanical damage causing surface areas to break away, will not appreciably affect the purpose of the weight coat. Such damage may appear dramatic, but it does not have any significance. Seawater penetrates the concrete and even exposure of the steel reinforcing cage (if any) is not important. Exposure of wire mesh reinforcement should be ignored, since it is only used to support the concrete during application before it has set. On individual joints, the loss of 10% to 20% of the total concrete can be readily tolerated.

4.6 Pipelay Operations

This section deals with the control of the pipeline between the barge and the seabed. Project-specific procedures will be developed for each job. This is general procedure providing an overview of the activities involved. The vertical profile of the pipeline in the water column is controlled by applied tension so that it takes up pre-determined curves. The pipelay engineering analysis uses proprietary computer programs employing finite element analysis to determine the proposed profiles for the pipeline such that the stresses in the steel are within acceptable levels. These analyses are carried out for all foreseeable conditions and phases of the operation. In addition, the analyses will determine the limiting parameters for environmental conditions after which pipelay must be stopped and the pipe set down on the seabed in a controlled manner. See the general procedure " Pipelay Installation Engineering Overview". The pipeline profile between the barge and seabed is in the shape of an "S". The upper curve of the "S" is the overbend and the lower curve of the "S" is the sagbend.

Overbend

Sagbend

Tension




4.6.1 Overbend Control

The overbend curve of the pipeline is controlled by supporting it on rollers mounted in the stinger and on the barge. The overbend curve extends onto the barge up the ramp and up to the tensioning machine. The stinger is attached to the stern of the laybarge with a hitch that allows it to pivot in the vertical plane. The stinger may be in one rigid piece, in which case the angle is adjusted and locked by the stinger adjustment mechanism. The DLB-264 has such a rigid stinger. Measuring the depth at the end of the stinger monitors the stinger angle. On the DLB-332, the stinger is articulated and is in two to five sections. Its angle and the amount of support it provides is adjustable by flooding and emptying the buoyancy compartments. In this case, the depth is measured at the roller at the end of the stinger and at three to four other roller positions along the stinger to monitor its profile. Before lay commences, the stinger is brought to the barge. The relative heights of the stinger support rollers will be initially adjusted so as to give the specified radius of curvature for the pipelay profile in accordance with the engineering lay analysis. It is then put in the water and attached to the stern hitch and the various connections made for flexible tubing and cables. For an articulated stinger, its buoyancy is adjusted remotely until each section is at the required angle to provide the overbend support. The angles are determined by measuring the pressure of water, and hence depth, at each measuring point using a "pneumo tube". This tube has just an open end at the measuring point. Air is slowly passed down the tube from the stinger control station. The pressure of the supplied air necessary to just maintain a steady slow rate of flow represents the pressure, and hence depth, at the open end of the tube. A compressed air supply is provided to displace seawater from the stinger sections to reduce ballast. Free flooding with seawater while venting air increases ballast. Flood and vent

Completed joint enters the stinger.




valves on the stinger are remotely operated by hydraulic means from the stinger control station. Once lay starts and the weight and tension of the pipeline come into play, the stinger angle will be monitored and its buoyancy will be adjusted until the desired conditions for continuous lay are achieved. Divers on the barge also inspect the stinger regularly, to check the pipe in relation to the rollers. Once continuous lay conditions are achieved, diver monitoring is carried out on a routine basis, normally once every 4 or 8 hours. Provision is also made for divers to operate the ballast system if needed. Normally an underwater video camera is also set up at the end of the stinger to monitor the relationship of the pipe to the last roller. Tension applied to the pipeline normally should be sufficient to keep the pipe just clear of the last roller at the end of the stinger, although this varies during each pipe pull.

4.6.2 Sagbend Control

Pipeline geometry is also controlled by the application of a horizontal force to the pipeline. This is accomplished by the hydraulically operated tensioning unit(s) on the lay barge. These apply a continuous tensioning force to the pipeline through the action of caterpillar tracks pressed against the pipeline. The tracks apply a continuous pulling force on the pipeline. Load cells are used in the tension machine to measure the applied tension and the operator continuously monitors the tension to ensure that tension levels are within the pre-defined limits. The barge anchors provide the reaction points to create the tension in the pipeline. Remote readouts in the control tower are also monitored and the anchor cables are adjusted to ensure that the required tension on the pipeline is applied.

4.6.3 Buckle Detector To ascertain that the pipeline is being laid on the seabed without any deformity and/or buckle, a buckle detector assembly may be pulled through the entire pipeline length. The buckle detector is a spring-loaded centralising device carrying an aluminium circular plate with a diameter just less than the internal diameter of the pipeline. Any significant ovality or deformation of the pipeline will be detected from the increased resistance when the plate is pulled through the pipe. The buckle detector is connected within the pipeline using a wire rope via the stop trolley to the line-up clamp at the first welding




station. The length of the wire rope depends on the distance between the bead stall (first welding station) and the touchdown point of the pipeline. The buckle detector generally trails a minimum of 80 feet (25 meters) behind touchdown. Each time the line-up clamp is pulled through the pipe to the next joint, a load cell and gauge measure the applied tension. Abnormal tension levels during pulling indicate a problem that will merit closer investigation, starting with the retrieval and inspection of the buckle detector.

4.7 Initiation of Pipelay

4.7.1 Pipelay Start-up Overview

As already described, the profile of the pipeline in the water between the end of the stinger and the seabed is controlled by applying tension. Too little tension and the radius of the curve of the overbend after the stinger, or of the sag bend by the seabed, will become too small and the pipe may become over-stressed and could buckle. Consequently, pipe lay start -up operations are designed to ensure that sufficient tension is maintained as the pipeline is produced from the laybarge until normal lay conditions are achieved. In open water, a start-up cable is anchored to the seabed with the other end leading over the stinger to a pulling head that is welded or flanged to the end of the new pipeline. The pulling head and first joints of the pipeline are fed down the firing line, completing welding, inspection and field joint coating, until there is pipe in one or both tension machines and the start-up pulling head is at the beginning of the stinger. The start-up cable is then attached by a suitably rated shackle to the pulling head and the barge moves ahead until the cable just becomes tensioned. See the first diagram below.

Tensioners

Start-up Anchor

Tension

Pulling Head

Target Box

1.




The required length of the start-up cable is a function of water depth and size of pipe. It will have been determined during the installation engineering for the pipeline. The cable must be long enough such that the tension from it will keep the pipeline in the required profile util it lands on the seabed. Start-up cables in open water can be 1,500 to 3,000 feet long (500 to 1,000 meters.) See diagram 2 below.

The barge continues to move ahead, increasing the tension gradually in the start-up cable which is monitored via the tension machines. During the pipelay engineering phase, the required tensions will have been calculated for each step of the initiation process. Once the tension in the pipeline is sufficient, it can be moved one joint down the stinger as the barge is moved ahead. More pipe is added to the pipeline, one joint at a time, and the barge moves ahead as the start up head moves down the stinger and into the water with each pull. Tension is continuously monitored and controlled to maintain the pre-determined tensions and hence the profile of the pipe in the water column. The relationship of the pipeline to the rollers on the stinger is also monitored.

The length of the start-up cable has been pre -set such that the start-up pulling head will land in the target box for the end of the pipeline. See the diagram3 above.

Tensioners

Start-up Anchor

Tension / Movemen

t

Pulling Head

Target Box

2.

Tensioners

Start-up Cable

Tension / Movement

Pulling Head

Target Box

3.




Once sufficient length of the pipeline is resting on the seabed, based on the calculated interaction between soil friction and pipeline, the lay tension can be increased to normal lay conditions. The laybarge will then lay away the remaining length of the pipeline. The start-up cable will be released and retrieved by divers.

4.7.2 Dead Man Anchor Start -up

The start-up initiation cable, described in the preceding section, must be attached to some anchor or structure capable of taking at least the maximum tension that the pipeline start -up and lay operations will require. These tensions were calculated during the initial engineering phase. If there is no suitable structure or existing facility available to which the start-up cable can be attached, then an anchor (or anchors) may be used. Such anchors are called "dead man anchors" (or DMA) to differentiate them from the barge's mooring anchors, storm anchors, etc. which all serve different functions. The anchors and rigging involved in a dead man anchor assembly are usually the same as the other anchors employed. Alternatively, a temporary anchor pile may be driven into the seabed and used as the tie -back for pipelay initiation. If the seabed soil conditions will not provide sufficient resistance to a single drag anchor for the maximum tension planned, then two anchors may be set in tandem. The type, size and number of anchors needed will have been determined during the engineering analysis phase, according to the seabed conditions, water depths, hold-back capacity required, etc. Dead man / start up anchors are set and handled as for normal mooring anchors, using an anchor handling tug, navigation and positioning systems to determine the drop points and a pendant wire and buoy. A typical two-anchor DMA arrangement is shown in the following diagram. The hold back cable between the anchors would be some 300 to 600 feet (100 to 200 meters) long. The start up cable length will be determined by the water depth and pipe size.




The barge is set up with its stern over the target box where the start-up head is to be landed. The DMA anchors are placed using an anchor handling tug (or tugs) at their required drop positions.

The free end of the DMA start-up cable will be handed back to the lay barge. This cable will be pulled in until the anchors have "set." The anchors will be pre-tensioned to 1.25 x maximum lay tension for approximately 30 minutes to ensure the DMA assembly has dug into the soil and does not drag. This tension can be applied by the A&R winch, or the tensioner, etc. A start-up sling can be used to adjust the final length of the start-up cable assembly such that, once lowered to the seabed, the end of the start-up cable (and the pulling head) will land in the target box. The surface position of the pulling head will not be directly over the desired target position, as shown in the sketch below. As the cable is lowered (under tension) it will apparently "gain" length until it is on the seabed. This same factor is taken into account whenever a pipeline is laid down. In the case of a DMA start-up, the adjustment of the start -up cable assembly length is made after any movement of the anchors when they were pre-tensioned and set.

Pennant Lines

Pennant Buoys

Tandem Anchors

Hold-back cable

Start-up cable

Start-up Sling

Pulling head

Typical Two-anchor DMA Arrangement




As an alternative to making up a sling, if the start-up cable is over-long, the excess length can be cut-off and a socket connected to the cut end. This socket will be shackled to the pipeline start-up head.

4.7.3 Platform Bowstring Start-up

Most pipelines run between oil and/or gas production platforms and the shore or other platforms. Consequently it is often the case that an existing platform is at the start-up location. This presents an ideal hold -back structure as long as the forces applied during start-up can be safely accommodated by the platform. Engineering analysis will be carried out to ensure that this is the case. To avoid having a long start-up cable and to keep the end of the pipeline close to the jacket, the "bowstring" rigging method is commonly employed. This method has the added advantage that the rigging can normally be installed using air divers only, i.e. within 150-feet (50-meters) of the surface. The following figure illustrates a bow-string start up arrangement showing the new pipeline just at the end of the stinger. The pipeline firing line is filled with pipe in the normal way, except that this initiation string is pushed towards the stern of the barge. The pipeline start-up head is welded or flanged on to the start of the pipe string. Meanwhile the stinger will be hitched

"GAIN"

Start-up Cable, (initially)

Target Box

Surface Positio

n

Start-up Cable, (after start-up)




to the barge, which will be set up over the intended pipe route and with the stern towards the platform. The initiation string continues to be pushed towards the stern as more welds are completed. When the pipeline protrudes past the end of the stinger by approximately half a joint, the divers will be deployed to connect the bowstring rigging to the start-up head by means of an intermediate sling with a length determined from the engineering analysis. Once the rigging is completed, the laybarge will pull ahead gradually on its anchors, hence applying tension to the initiation string. The tension applied to the initiation string is read from the monitoring system in the barge's tensioner(s.) Tension is gradually increased until the bowstring start-up lay tension, much lower than normal lay tension, is achieved. The laybarge will then commence the initial stage of pipe laying. The tension applied will be constantly monitored and as the number of joints suspended between the stinger and the hold-back rigging increases, the tension will also be gradually increased.

The weight of the start-up pull -head and the pipeline causes the start-up cable to slide down the bowstring cable until the end of the pipeline is resting on the seabed. Laying is continued carefully away from the jacket maintaining tension levels that are lower than normal. Once sufficient length of the pipeline is resting on seabed, based on the calculated interaction between soil friction and pipeline, the lay tension can be increased to normal lay conditions. The laybarge will then lay away the remaining length of the pipeline.

Start-up Head

Stinger Start-up Cable

Bowstring Cable

Shackles

Laybarge

Typical Arrangements for Bowstring Start-up

Jacket

Post lay before rigging released




4.7.4 Beach Crossings / Shore Start -up

Many pipelines are required to bring hydrocarbon products to shore, necessitating a shore approach and beach crossing. When such a pipeline is constructed, the lay operations are normally initiated at the beach crossing and the pipeline is then laid away to deeper waters. The laybarge will set up over the right-of-way centreline with its stern towards the beach. Depending on the near shore seabed profile, this can be between a few hundred meters up to 1.5 or even 2 kilometres away. Dredging may be carried out to provide an approach channel for the barge so it can come closer to the shore. Special, shallow water anchor handling vessels may be used to set the barge's anchors. Normally the new pipeline will be buried under the seabed through the surf zone for protection from wave action. The line normally will be buried as it crosses the beach for environmental and safety considerations. This is achieved by initially digging a trench into which the pipe is laid and then back-filling it, or by post lay trenching and back-filling, or by using horizontal directional drilling (HDD) techniques (see next section). The choice will be driven mainly by the nature of the beach, near shore seabed and the sub-surface soils. Let us consider first the open pre-trench, pipelay and back-fill method for a typical installation. Sheet piling is driven into the beach around the pipeline end target area and along both sides of the right-of-way to beyond the low tide water line. The beach material is excavated from within the sheet piles to the design depth. Further offshore, the trench will be extended as required using a backhoe or bucket grab operated from a dumb barge and/or by a sub-contracted bucket or suction dredger.

Beach Pull




The pipeline will be constructed on the barge and pulled off the barge, over the stinger and along the trench to the shore target area using a winch located on the beach. This shore winch is normally a linear traction winch with a pull capacity of up to 300 or 400 tonnes. Lucker (manufacturer) winches are often used. This winch is mounted on a temporary foundation and is tied back to anchors or anchor piles installed further up the beach. The winch has to have a high pull force to overcome the drag friction between the pipeline and the seabed / trench bottom. Temporary floatation tanks may be attached to the pipeline as it leaves the barge to reduce this drag. The 2" or 2 ½" pulling cable is normally stored on a powered drum on the linear winch. A messenger line from a winch on the barge is taken ashore and fastened to the linear winch pulling cable. The pull cable is brought out to the barge under slight but constant tension to avoid twisting and kinks. It is lifted by the barge's crane onto the stinger and shackled to the pulling head that has been welded or flanged to the end of the new pipeline and is just entering the stinger. The stinger will normally be ballasted down such that its deep end rests on or close to the seabed. Tension in the pulling line from the beach is gradually increased. The tensioners on the barge are operated to allow one 40-foot (12-meter) length of pipe to be pulled down the stinger. The next joint is welded on and the lay operation continues, joint by joint. Close co-operation between the beach winch operations and the barge is achieved using radio communications. The tension applied by the beach winch will be monitored and recorded. The pipeline is incrementally pulled from the barge, along the shore approach trench and up the beach trench until the pulling head is in the shore target area. The pulling head is then tied back directly to the shore winch anchors and the linear winch is released. The barge then commences conventional lay operations, moving itself away from the shore on its anchors. Once pipeline flooding, cleaning, gauging, pressure testing and any other pre-commissioning operations have been performed, and any tie-in operations to an onshore pipeline completed, the beach equipment is removed, including the piling, the open trenches are back-filled and the beach is reinstated. Global normally employs subcontract c ivil construction companies to perform the onshore and near-shore operations related to beach crossings. Detailed procedures based on the engineering design will be prepared for each project.




4.7.5 Beach Crossings / Horizontal Directional Drilling

Horizontal directional drilling (HDD) can be used to avoid disturbing the beach area for a shore crossing. Specialist subcontractors perform these operations. A shallow angle drilling rig is used to drill initially a pilot hole from the shore behind the beach area to a target area in the seabed beyond the surf line. Instrumentation is used to monitor the drill head position and direction so as to ensure that the design route and depth are followed to the breakout point. The bore-hole is then enlarged to the diameter of the new pipeline. Depending on soil conditions, a liner pipe may be installed, although this is not normal. The barge's start-up cable is attached by divers to the just-protruding end of the HDD drill string and is brought back through the pre -drilled hole to the shore location, where a linear winch is utilised to pull the pipeline from the barge and through the HDD hole to shore. Other permutations may be employed depending on the specific local conditions.

4.8 Completion of Pipelay and Tie-in

4.8.1 Lay Down

The design of a new pipeline may require one end to be left on the seabed ready for a subsequent tie-in operation, either to a platform or other installation, to another pipeline or for the continuation of the same pipeline at a later date . In all such cases, a lay down procedure will be followed. This is similar in all intents and purposes to that used for contingency abandonment of the pipeline due to adverse weather conditions, which is described in detail in section 4.9 below. During a planned lay down, it is important to ensure that the end of the pipeline lands on the seabed at the target location. The engineering design and barge positioning systems will control the approach direction of the pipe route such that the heading of the pipeline at lay down is correct. It then remains to ensure that the length of pipeline laid is such that the end of the pipeline arrives in the right place. This is achieved by using the laybarge navigation and positioning systems to accurately monitor the location of the barge. As the barge approaches the lay down target area, the remaining length of pipe to be added to the pipeline is calculated, based on the survey data. A partial length final joint is prepared as necessary to achieve the desired length. Then the pipeline internal




equipment is removed and the lay down head is welded on. The A&R cable is attached to the lay down head and the tension in the pipeline is transferred from the tension machine(s) to the A&R winch and the lay down operation proceeds. When determining the final length of pipeline on the barge, the "gain" of the pipeline will be taken in to account. This is the allowance to be made between the actual position of the lay down head while it is on the barge (as monitored by the survey systems)

and the position that it will take up once laid on the seafloor. This will be predetermined during the engineering phase and is dependent on water depth. Once the pipeline has been laid down, fabrication has been completed and flooding and testing remains to be performed. See Section 4.11 below.

4.8.2 Riser Stalk-on

It is common practice to include the riser installation and tie-in with the subsea pipeline construction work. A pipeline system is designed and built to pipeline codes and specifications. These are different from those applicable to the topside piping systems. Once the subsea pipeline has been built and tied-in to the riser(s), it is normal to then flood, clean, gauge and pressure test the whole system in one go. Hence it is more practical for one contractor to take all this work in one package, avoiding work-scope division issues. Global Divers and Marine Contractor provide diving services in seamless support of Global's offshore construction activities. Where a riser is to be installed offshore as part of the subsea pipeline construction work, the "stalk-on" method may be employed. The suitability of this method depends on, amongst other factors, the water depth at the platform and the pipeline

Lay Down Head

Target Box

A&R Cable

"GAIN"




size. For each project, engineering will be carried out and detailed procedures will be prepared and approved prior to the offshore work starting. This section presents a brief overview of the stalk-on method. The pipeline will be completed and laid down adjacent to the platform, as previously described. The riser clamps may now be installed on the jacket by divers, unless these have been pre-installed from a separate diving support vessel (DSV). The riser clamps are secured to suitable jacket framing members. They are carefully aligned with each other using a taut line. The top clamp is also known as the hang-off clamp as it will take the weight of the riser. It is normally above water. The clamps are typically double-ended with hinged half-shells that are bolted closed. One end of each is clamped is around the jacket members and one end is left open to take the riser. The risers' clamps are normally lined with rubber (neoprene) both to protect the riser and to insulate it electrically from the platform, since the pipeline and riser will have a separate cathodic protection system to that of the jacket. The riser normally has external anti-corrosion coating and may be clad with neoprene rubber in the splash zone area (from just above and below sea level) where high rates of corrosion are particularly prevalent. At the bottom of the riser is a tube-turn, bringing the riser to the horizontal. This may have a temporary knee brace welded or clamped to it to provide additional strength during installation. This knee brace will be removed afterwards. Note that the bends in a pipeline system never have a radius less than five times the line's diameter, known as 5-D bends. This is to allow the free passage of pigs through the system. Once the riser clamps are installed, the divers, usually using a taut wire method, will carefully measure the distances and angles between the end of the pipeline and the jacket structure and/or bottom riser clamp. The pipeline is not flooded before the stalk on operation. The pipelay barge is repositioned and uses its side lift davits to raise the pipeline from the seabed in a controlled curve, following the project-specific engineering procedure. This will bring the lay down head above water, which is then removed. The riser, tube-turn and usually the first pipeline joint will have been prefabricated. The length of the first joint already welded to the tube turn will be cut back to suit the diver's measurements. The




riser assembly is lifted using the main crane and welded onto the end of the pipeline. All welds are fully inspected.

The pipeline and riser are then carefully lowered. The adjusted length of the pipeline will be such that the riser will fit directly into the open riser clamps. Divers close the clamps and bolt them up and remove the lift rigging from the riser and pipeline. Flooding, cleaning, gauging and testing for the whole line, including the riser, remains to be carried out.

1

2

3

Weld

Lift

Lower

Diagram of Stalk-on Riser Installation Stages




4.8.3 Spool Tie-in

If the stalk-on method cannot be employed or the riser is already pre-insalled on the platform, then a subsea spool tie-in method will be used. One disadvantage of using a subsea spool tie-in is that the new pipeline has to be flooded before it can be tied-in. Some pipelines are made from or lines with corrosion resistant alloys (CRA) which must not be exposed to seawater due to chloride attack. Hence alternatives to a normal spool tie -in must then be used. The elements for a normal subsea spool tie-in are shown in the following diagram.

Detailed engineering design and procedures will be prepared for any riser installation and tie-in operations. The following is an outline of the method typically employed. The most common method of joining the spool piece to the riser and the pipeline is to use flanged joints. Underwater (hyperbaric) welding can be employed, but this is comparatively expensive and is not generally considered to offer any significant advantages over flanged joints. After flooding and any testing of the pipeline in accordance with project requirements, the flanged lay down head will be unbolted and recovered to the surface. Divers will take accurate measurements between the pipeline end flange and the riser bottom flange (dimension "x" in the diagram above.) From these

Riser Top Flange & Hang-off Clamp

x

Lay-down head removed

Tie-in spool piece

Riser clamps

Tie-in spools can be large




measurements, a closing spool piece will be fabricated, inspected and may also be pressure tested on the deck of the support vessel. Spools can be large and have complicated geometry to accommodate pipeline expansion and seabed irregularities (see photo.) The completed spool is lowered into place, a ring gasket inserted and the flanges made up by the divers. Hydraulic bolt tightening equipment is normally used to ensure sufficient and uniform tension is achieved in all the bolts around the flange.

4.8.4 Mid-Line Tie-in

Project requirements may dictate that the pipeline is laid from both ends which then have to be joined at some mid-line point. Typically this occurs for shore to shore pipelines, each beach pull-in requiring the initiation of lay away operations. The mid-line tie-in location will be arranged to be in shallow water, typically around 30 to 50-feet (10 to 20 meters), where the seabed is suitably smooth and where the pipeline route is straight, not curved. Each pipeline is laid down parallel and adjacent to each other with a slight overlap of a joint or so. With a 400-feet long lay barge in 50-feet of water, it is possible to lift both ends on davits at the same time while remaining well within the design stress limits for the pipelines. See diagram.

An access platform is erected over the side of the barge. The ends of the pipelines are cut back, prepared, brought together and fitted up for welding. Welding and inspection are then completed and the joint is wrapped and filled. As the pipeline is laid back down on the seabed, the barge will be moved sideways a little to accommodate the slight gain in length. The pipeline will rotate a little and will take up a slight curve in the pipe route. Stresses in the pipe during this operation will have been calculated so as to stay well within practical limits.

50 ft

400 ft

Mid-line, Above Water, Tie -in Method




4.9 Abandonme nt and Recovery

Adverse weather conditions, such as those encountered during a typhoon, may cause excessive motions of the barge, which could damage the pipeline. Consequently the pipelay operation may have to be interrupted. Weather forecasts are continuously monitored and the lay operation will be suspended in good time before the weather deteriorates such that the pipeline is at risk. Part of the engineering phase includes a determination of the limiting wind and sea-state conditions (wave height and period) that justify the abandonment of operations. The derrick pipelay barge Superintendent, at his sole discretion, will decide when conditions are no longer suitable for safe and productive work. In such circumstances, shutdown operations will commence and the pipeline will be laid down safely on the seafloor. The same procedure is followed if the pipeline design requires the pipe to be laid down ready for a subsequent tie-in operation, either to a platform or another pipeline or for the continuation of construction of the same pipeline at a later date. The following steps summarise the lay down operation. − A pulling head / abandonment head replaces the next normal pipe

joint that would have been used. − All welds in progress are completed, x-rayed and coated.

− The internal line-up clamps, x-ray crawler stop trolley are removed

from the pipeline.

− The abandonment head is aligned and welded on to the pipeline.

− The A&R cable is attached to the pulling head.

− The pipeline will be abandoned in accordance with the project procedure for Pipeline Abandonment and Recovery, outlined below.

The pipeline is laid dry. The lay-down pulling head seals the pipeline from water ingress. It has a large pad-eye at the closed end. The cable from the abandonment and recovery (A&R) winch is shackled to the pulling head pad-eye. In order to keep the desired curve in the sagbend, tension must be maintained in the pipeline as it is lowered to the seafloor. The A&R cable is tightened while the

Lay-down Head enters Stinger




pipeline is still being gripped by the tensioner(s) until it/they show no load. This means that all the tension being applied to the pipeline has been transferred to the A&R cable and winch. The tensioner machine(s) can now be released from the pipeline, which then is held on the A&R winch and cable. The A&R winch is a constant tension winch, which is set to maintain the tension needed to hold the pipeline in the required profile. The barge moves ahead on its anchors. This places slightly more tension on the A&R cable and the winch starts to pay out, so as to automatically maintain the constant tension in the pipeline. The barge continues to move forward and the A&R cable pays out a measured amount until the

end of the pipeline is at the transition point at the upper end of the sagbend. At this stage, the barge can be moved backwards, towards the pipeline, with the A&R winch stopped. The remaining part of the pipeline still suspended above the seabed is thereby lowered to the seabed. The barge continues to back-up until there is no tension in the A&R cable and the pipeline including the pull head is lying on the sea floor. There are several scenarios for dealing with the A&R cable, still attached to the lay-down head. (i) Normally divers will release the A&R cable, which is recovered to the barge. They will attach a line and buoy to aid future recovery operation, in addition to the navigation fixes taken of the lay-down head's location. The barge is then free to leave the location. (ii) In the case of a contingency lay-down for bad weather, the barge may ride out the adverse weather, with the A&R cable connected but slack. (iii) In rare circumstances, if there is no time to disconnect from the lay-down head, the whole A&R cable may be paid off its winch and left attached to the pull head at one end and to a pendent line and buoy at the other. This facilitates picking up the pipeline again using the connected A&R cable.

A&R Winch

Sagbend

TensionPulling Head




The following procedure is followed any time the pipeline is to be placed on the seabed.

4.9.1 Preparations For Abandonment

Once the decision is made by the Superintendent to abandon the pipeline, no further joints are loaded into the line-up station. The anchor foreman resets anchor positions as necessary for the abandonment. The abandonment/recovery pull-head is aligned with and welded to the end of the pipeline at the first welding station instead of a new joint of pipe. Welding continues at the remaining welding stations until all the pipeline welds, the NDT and field joint coatings are completed. The temporary weld between the pull head and the pipeline may not be inspected in the NDT station but is completed and inspected in the first welding stations. Ultrasonic inspection may replace radiography under such circumstances. The cable from the constant tension A&R winch is attached to the abandonment/recovery pulling head (lay-down head.) The tension is transferred from the tensioning unit(s) to the constant tension A&R winch, and the tensioning unit tracks are backed off of the pipeline. The whole tension keeping the pipeline off the seabed is now carried by the A&R winch and cable. Abandonment tension will be specified in the Installation Manual as part of the initial lay engineering carried out.

4.9.2 Barge Pull Once the tension is transferred, the A&R cable tension is maintained at the specified value and the barge is moved forward on its anchors. This slightly raises the tension in the cable, and the winch automatically pays out to compensate. The length of cable paid out from the constant tension winch is meas ured. The forward barge movement is continued until the pulling head reaches the top of the sagbend, at which point the barge may be stopped. The length of cable to be paid out to reach this point for the water depth will have been calculated. No adjustments to the stinger buoyancy are required during the barge pull.




4.9.3 Pipeline Lowering Once sufficient cable has been paid out due to advancing the barge on its anchors, barge movement is stopped. The pipeline is then lowered to the seabed by reducing the tension on the A&R winch and allowing it to pay out the cable until the tension represents only the cable weight in the water column.

4.9.4 Recovery Operations – General The recovery procedure is essentially the reverse of the abandonment procedure. The following outlined method is followed to retrieve the pipeline from the seabed. Note that different procedures are used in the event that the pipeline was abandoned because it was damaged. (See Section 4.10 below.)

4.9.5 Preparations for Recovery If the A&R cable was left connected to the lay-down head, then the laybarge is repositioned such that the stern end of the stinger is at a pre-determined minimum distance from the end of the pipeline on the seabed. These set-up distances for recovery are specified in the Installation Manual. If the A&R cable had been disconnected, then the barge is initially positioned with its stern over the lay-down head. The A&R cable is lead over the stinger and lowered to the seabed where the divers remove the marker buoy and connect it to the lay-down head pulling eye. The barge then moves ahead, paying out the A&R cable, to the predetermined distance as in the paragraph above. If the A&R cable had been paid off the winch, then the tag line and buoy attached to its free end are brought to the barge and the tag line is used to recover the A&R pull cable. The barge crane is used to lift the A&R cable into the stinger where it is lead along the barge rollers, through the firing line to the constant tension winch. The slack in the A&R cable is taken up on the A&R winch drum. The barge then moves to a position along the pipe route, until it is at the predetermined distance as in the first paragraph of this sub-section.

4.9.6 Pipeline Recovery Operations The pipeline is raised from the seabed by increasing tension on the A&R cable using the A&R winch. During this stage of the operation, the barge stays at the pre-determined position, holding on anchors, until the specified tension is achieved. During this and all subsequent operations, the stinger buoyancy is adjusted to




maintain the stinger angle / depth as specified in the Installation Manual. The applied tension and geometry of the A&R cable and pipeline will determine that pulling head has now been lifted into the transition area between the sagbend and the overbend. The barge is now moved backwards on anchors. The A&R cable will be hauled in as the A&R winch maintains a constant tension. Once the lay-down head nears the end of the stinger, the stinger angle is trimmed, if necessary, to the specified pipelay configuration and to accommodate bringing the pipeline on board the barge. T During all these operations, the condition of the pipeline is monitored using an ROV and/or divers. The recovery operation continues, moving the barge on anchors and allowing the A&R winch to take up, until the pull head has passed through the tension machine(s) and it reaches the line-up station. Barge movement is stopped and tension is transferred from the constant tension winch to the tensioning units. The recovery cable is removed. The pull head cut off. The end of the pipeline is re-bevelled and normal lay operations are resumed.

4.10 Contingency Operations

4.10.1 Buckled Pipe – Dry Buckle During the course of laying, abandoning or recovering of pipelines, a loss of tension in the pipeline will cause a change in the pipeline profile, which may over stress the steel, and could result in a wet or dry buckled condition. A wet buckle is one where the pipe wall has deformed so much as to split, allowing the ingress of seawater. This water also makes the pipeline much heavier, which aggravates the buckled condition. Situations that could lead to a potential pipeline buckle include unintentional loss of tension combined with, or separate from, a changed barge position from that planned. When used, a damaged or un-retrievable buckle detector will confirm if there is a potential problem. Also the pipeline may be resting hard on the last stinger roller, even with normal lay tension restored, indicating a change in geometry or that the pipeline has become heavy with water. Visual inspection of the submerged pipeline by diver(s) and/or ROV should follow. In particular, this inspection should observe




the profile of the line between the barge and the seabed and look for any ovality, or a folded dent or sharp bend in the line. Indications that the damage might be a wet buckle include an unexpected increase in the lay tension following the loss of tension, caused by the increased weight of water entering the pipeline. Another indication would be air discharging from the end of the pipeline at the bead stall, being displaced by seawater entering the pipe at the wet buckle. Should a buckle be found to have occurred, the divers/ROV will inspect the buckle and report their findings to the Barge Superintendent. The Barge Superintendent, at his sole discretion, will determine the course of action to be followed. In general terms, the possibilities are as follows. The preferred solution is for the buckled pipeline to be slowly recovered by backing the laybarge, reversing the tensioner(s) to recover the pipe and cutting off each joint in the bead-stall until the buckled joint is removed. The pipeline end is then re-bevelled for welding and normal pipe laying operations will re-commence. If the buckle is such that recovering the buckled joint by backing up the barge may cause a complete failure of the flooded line, then the pipeline is abandoned as described in section 4.9 above. The following section describes the action for de-watering and recovering such an abandoned line.

4.10.2 Recovery of Abandoned Wet Buckled Line The laybarge is repositioned over the damaged (buckled) part of the pipeline. Divers will remove the concrete and corrosion coating (as applicable) from a section of the line just beyond the buckle, i.e. towards the star-up end. They will cut off the bucked section and then cut two diametrically opposed holes in the pipe wall using oxy-arc cutting rods and insert a steel bar. De-watering will be carried out by driving a pig through the line with compressed air from the start-up end. The pig will be trapped by the steel bar inserted by the divers, where it is held by the over-pressure of the compressed air. If the pipeline was in itiated from a beach pull, the de-watering compressor and pig launcher will be run from the beach. If the pipeline initiated from open water, then divers will be needed to




support de-watering. In this case, the de-watering operations may be supported by moving the barge or, depending on availability amongst other circumstances, from a separate diving support vessel. A subsea start-up (pulling) head is designed to hold a pig for contingency de-watering. Prior to welding or bolting-up the start-up head to the pipeline string in the pipe ramp, the head will be loaded with this de-watering pig, normally a bi-directional ("bi-di") pig. The pulling head also incorporates a ball valve and plugged pipe to which a de-watering hose can be connected. Divers will connect an air hose from a compressor on the surface vessel to the start-up head. Compressed air drives the pig through the line, displacing the water. The steel bar inserted by the divers will trap the pig. Other trap arrangements may be employed, using the same principle.

Once the de-watering is completed, the pipeline is davit lifted or single point lifted to the surface, where it is cut back to the next welded joint and a standard pulling head is welded on. The pipeline is lowered back to the seabed, the davit / lift lines are removed and a standard recovery performed. Once the new pulling head reaches the bead stall, tension is transferred from the A&R winch to the tensioner(s), the pull head is cut off, the pipeline end is bevelled and normal pipe laying is continued.

4.10.3 Weld Repair Cut-out If a weld is found to have defects that cannot be repaired, or a series of repairs were not successful, a cut-out will called for in accordance with the welding procedures. Such a defective weld

start-up head

compressed air

flooded pipe pig

steel stop bar water

cut-off buckled section

De-watering After a Wet Buckle




will normally be at the NDT station (station number 5) or further along the firing line. It is brought back to the first welding station by backing the laybarge on anchors and operating the tensioner(s) to pull the pipe back on board the barge. As each joint is recovered, it is cut and removed at the first welding station. Once the defective weld is in the first welding station, it is cut away with a welding band and cutting torch.. The cut pipeline end is re-bevelled. A new joint is then be rolled back into the line-up station. The joint is aligned with the internal line-up clamp, spaced and welded, following the normal welding procedure. Regular pipelay operations resume.

4.11 Flooding, Cleaning, Gauging, Testing and Pre -Commissioning

4.11.1 Flooding, Cleaning and Gauging a. Flooding A subsea pipeline is laid dry. Following construction, pigs must be run through the new line to remove any debris (cleaning) and to determine the minimum diameter or presence of any obstruction (gauging.) These pigs are driven through the line using treated water. The pipeline system will also be pressure tested to check for leaks and pressure integrity (strength). The test medium is almost always water and hence pipelines must also be flooded for pressure testing. The line will normally be flooded using filtered, chemically treated seawater. The chemicals are added to the seawater in measured amounts related to the volume of water being pumped by dosing pumps. These chemicals are normally supplied in liquid form and typically will inc lude: − Oxygen scavenger, to remove dissolved oxygen from the

seawater so as to prevent corrosion inside the pipeline; − Biocide, to prevent the growth of organisms and bacteria; − Corrosion inhibitor(s), to prevent or reduce attack by

chlorides and other potentially harmful components of seawater related to the metallurgy of the pipe (or its lining);

− Dye, coloured and normally fluorescent under ultra-violet light (such as "fluoroscene") which aids divers in tracing the location of any leaks.

The flow rates and volumes pumped for each chemical is measured and recorded periodically, about every 30 minutes.




The pipeline is normally flooded using a bi-directional pig. This pig separates the air and the water and ensures that the whole volume of the pipeline is completely filled with water as it pushes the air ahead of it. Getting all the air out is important since residual air encourages corrosion and also is a store of energy during pressure testing that can lead to inconsistent results as well as being potentially dangerous in the unusual event of a catastrophic failure.

The volume and pressure of filtered treated water introduced into the pipe during flooding is measured using pressure gauges and a flow meter and recorded. These observations and data are used to monitor progress. The volume required to completely fill the pipeline is calculated. If considerably more water is pumped before the pig arrives at the receiver head, it indicates a problem. The volume pumped also provides an indication of the progress of the pig and its rough position in the event that it becomes stuck. A pressure / flow "blip" (short-term rise in pressure, decrease in flow rate) might occur on contact with a dent. The pressure gauge indication normally varies as the pig moves through the line. If it becomes completely steady, then this suggests that the pig might not be moving but is allowing the water to pass. The rate of flow of introduced water should be pumped at a rate sufficient to move the pig(s) at between 0.5 to 1.0 m/sec. This requirement drives the size of the filling and any disposal hoses and fittings, fill pumps, etc. A slug of water is often introduced ahead of the pig to prevent the seals running on the dry pipe walls causing high seal wear rates. Pigs are normally also fitted with a "pinger". This is a battery powered electronic device that produces an acoustic "ping". The sound travels through the water in the pipeline and then through the pipe wall into the sea. Detectors (essentially hydrophones) can be mounted beneath or over the side of ships (in shallower water) or can be carried by divers or mounted on an ROV moving along the pipe track, so that the location of the pig can be determined. Pinger battery life should not be less than about 7 days.

Bi-directional Pig

Gauging Pig




b. Cleaning The bi-directional pig used for flooding has the additional function of sweeping out debris from inside the pipe. It may be fitted with bypass ports to allow some flooding water to flow past the pig, so as to keep debris in a suspension rather than letting it form into a solid plug.

The pig is designed to be driven, by pressure, in either direction (bi-directional). In the event that it becomes stuck at a dent or blocked by debris, the pressure can be reversed and the pig can be driven in the opposite direction. Subsequent cleaning operations are carried out in accordance with particular project requirements. Foam pigs (made of polyethylene / polyurethane foam, also known as "poly pigs) and/or brush pigs can be run through the line to physically scrape the inner walls. These pigs are usually run in trains, each pig separated by a slug of water to prevent the pigs bunching up together. In special cases, the slug between the pigs may include chemicals, such as acid, to clean or treat the pipeline internal walls. During drying, the "plug" of liquid between the pigs can be glycol or other solvent to dilute or dissolve water clinging to the pipe wall.

Pipeline Launcher

Pipeline Receiver

Filling / Driving Water

Disposal

Typical Arrangements for Single Pig Launcher & Receiver




c. Gauging The minimum diameter of the pipeline is confirmed using a gauging pig. This is a pig fitted with an aluminium disk that is typically 12mm thick and has a diameter that is 90 to 95% that of the design internal diameter of the pipeline. The leading side of the plate is chamfered at 45º and it usually has radial cuts to divide it into sectors. The gauging plate can be incorporated in the flooding / cleaning bi-di pig. Once the pig arrives in the receiver it is recovered and the plate carefully inspected. A damaged gauge plate does not necessarily indicate a problem with the pipeline. For larger diameter lines, the buckle detector already pulled through the pipeline will have detected any significant damage. The pig may have been too long for the bends, bringing the gauge plate into contact with the inner radius of the bend. The riggers may have damaged the plate on recovery or it may have been damaged in the launcher or receiver. The first action if a plate is recovered damaged is to carefully repeat the gauging operation. The nature of the problem can often be interpreted from the type of indication on the gauge plate. However, minor indications must be allowed. The gauging operation rarely finds indications of diameter reduction that will affect the operation or integrity of the pipeline.

4.11.2 Pressure Testing The whole new pipeline system is pressure tested in accordance with specification and code requirements, normally to 1.5 times the maximum allowable operating pressure (MAOP) or 90% of the yield hoop stress, whichever is less. The pressure is normally held for a predetermined period, typically 24 hours. This "hydrotest" may be carried out separately on individual sections and components of the pipeline system, i.e. risers, spools and the subsea part of the line. Subsequently the whole system will only need to be subject to a leak test (typically 1.1 times MAOP for 1 to several hours) to check the integrity of the fittings, flange joints, etc. In preparation for the pressure test, any launchers and receivers are removed. Blind flanges are normally then installed at the inlet and outlet locations, the blind flange at the test end having a




typically a 1" diameter pressurising manifold. All valves in the pipeline system are opened. Set up the volume tank, pumps, calibrated instruments and recorders. Pressure gauges, pressure recorders, etc. will normally have their calibration checked against a dead-weight tester prior to each test, or the dead weight tester may be used to verify the test pressure. Connect the high-pressure flexible hose from the high-pressure pump to the test manifold. Safety Note: − Hoses will be properly tied down and secured where required

to avoid / minimise injury in the case of any fitting failing or hose bursting.

− Pressure pumps shall be fitted with calibrated full-flow pressure relief valves.

The pipeline system will be slightly pressurised to a few tens of pounds per square inch gauge (psig) and any residual air will be bled off through the end manifolds. Any particular high point(s) in the system that have residual air bleeding capabilities should also be considered. Ensure all valves closed and pump the pipeline system up to 50% of the test pressure. Then stop pumping and hold pressure for about 1 hour to allow for the pressure to stabilise and to check for leaks. Note: The pressure and volume pumped and temperature records will be plotted out to determine the volume entrapped air. An acceptable level is not more than 0.2%. Should the percentage of entrapped air be higher, the pressure will be released and the line vented at both ends to bleed off entrapped air before repeating the procedure to this point again. Should the pressure reading at 50% of test pressure indicate a tight system without any leaks, further pressurisation may continue until the test pressure is reached. Pressure and temperature will be continuously recorded. If necessary, additional volume will be added to top-up the line until the pressure stabilises. In practice, the test pressure may be exceeded by up to a maximum 5% over the hydrotest pressure to allow for any drop during the stabilisation period. Once the pressure is stable, the pressurising hose is disconnected and the test holding period will begin. Temperature of the surrounding seawater will be taken regularly and recorded. The




pressure readings will be recorded on a calibrated chart recorder continuously throughout the hold period. Variations in pressure due to temperature, air absorption or pipe elastic yield effects will be observed and justified. Once the hold period has been satisfactorily completed, the line will be slowly de-pressurised at a rate of 2.0 bar per minute. If there are pressure drops that cannot be explained and justified by changes in water temperature or other ambient changes, then this is indicative that there may be a slight leak or leaks. All flanges and fittings will be closely inspected while under pressure for weeping, presence of dye, etc. Once any leaks are discovered, the pressure must be released and the fitting or flange will be tightened. If no leak can be detected, all the flanges and fittings will be re-tightened with the pressure released. Then the system will be re-tested in accordance with the specifications. Witnesses to the test shall sign the records, which will become part of the pipeline completion documentation dossier.

4.11.3 Pre-Commissioning Pre-commissioning includes the activities carried out after pressure testing to prepare the pipeline system for the introduction of hydrocarbons. Most oil pipelines are left filled with treated filtered seawater on completion of hydrotesting and no further action is needed. For gas transmission pipelines, the project scope may require the line to be de-watered and possibly also to be dried to a specified dew point. De-watering is normally the removal of water by mechanical means, passing a series of high seal pigs through the line. Water removal may be enhanced by using a train of pigs with slugs of methanol between them. The final train may be driven by dry nitrogen, such that the line is left "packed" with nitrogen gas until commissioning. Alternately, a slug of nitrogen may separate the last two pigs and hydrocarbon gas can be used to drive the train. Introducing hydrocarbon gas is part of commissioning and start-up and not pre-commissioning. Doing the final drying during commissioning can be more cost-effective than having it as part of the construction pre -commissioning since overall fewer pigging runs are needed. For sour gas lines (H2S or CO2 content) or for some sales gas lines, then the pipe may need to be vacuum dried in accordance




with the scope of work. After de-watering, vacuum pumps are operated at both ends of the line, which lower the pressure until the residual water boils and the water vapour is drawn off by the vacuum pumps. This can take several weeks for a long line, since it is common for the low pressure boiling water to freeze and time must be allowed for it to thaw and the process to repeat until it stabilises. On completion, the vacuum is replaced by dry nitrogen gas or by production hydrocarbon gas.

4.12 Surveys, Spans and Route Selection

4.12.1 Initial Route Surveys Initial route planning will normally be done by the pipeline or field operator (client) as part of his front end engineering design (FEED.) This will be based on existing hydrographic charts and historical environmental data, supplemented by additional detailed surveys to determine the seabed profile (bathymetry) and morphology along the route. Detailed data for shore approach areas and beach crossings will also be gathered. The route will be planned with a view to providing the safest and most cost-effective solution for construction, while minimising environmental impacts.

4.12.2 Spanning: Avoidance and Correction Undulations of the seabed may lead to the pipeline not being supported continuously, causing spans between the high points. Engineering analysis of the detailed hydrographic survey data will identify the probability and location of critical spans for the planned pipeline.

Critical span length occurs when the unsupported weight of the pipeline may cause it to bend and become over-stressed, possibly leading to buckling damage. During lay, the pipeline is subjected to axial tension, which allows a long section of the pipeline to be safely suspended. However, once laid on the seabed, only the inherent strength of the pipe wall offers resistance to bending under its own weight.

Span 1 Span 2

Span Height




The pipeline is laid dry. Once liquid is introduced, the submerged weight increases significantly. Critical span lengths are therefore much shorter for the flooded condition. The line can be laid dry with span lengths considerably exceeding the flooded critical span length. However, it is important that such spans are corrected (supported) before the line is flooded. Route planning will avoid such undulating seabed areas as far as possible. If the best route available still incurs potential critical spans, then post lay video survey by side scan survey or ROV is normally carried out to identify the actual occurrence of such spans. Critical spans exceeding design are then corrected before the line is flooded. Divers or ROV can do the span correction. Various solutions may be used, such as introducing grouted fabric formwork supports under the line. Alternatively, divers can build supports using sandbags, or mattresses or pipeline sleepers can be put under the line or the high points of the line can be trenched. If the seabed is relatively flat such that no spans are anticipated, then surveys during lay will not be necessary and only the final as-built survey will be carried out once the lay has been completed.

4.12.3 Pipeline Survey Equipment and Methods Specialist subcontractors, who will produce specific procedures for their activities related to any project requirements, normally perform route and post-lay surveys. Consequently, survey methods and activities are only briefly summarised here. Typically, the width of a pipeline corridor to be investigated for a pipeline pre-lay survey will be around 500m to 700m. Post-lay surveys concentrate on the immediate vicinity of the new pipeline and only where there are other pipelines, cables, installations, etc. will this be extended from about a 50m width. All survey techniques rely on computerised electronic navigation and positioning systems so that the position, depth and heading of the survey sensors are accurately known. This data is continuously recorded along with the sensor information plus time and date. Side-scan surveying involves towing a vehicle (or "fish") behind the survey vessel that carries sideways looking sonar. This produces a morphology map of the seabed to either side of the fish. The area immediately under the fish is not surveyed. It is therefore normal to make two or more passes along the route to




ensure that full coverage of the corridor is obtained. The height of the tow-fish above the seabed affects the results. Low altitude gives better resolution and more details but covers only a narrow swathe of the seabed. Multiple passes will be needed to provide full cover. Higher altitudes cover a wider swathe per pass but lose resolution and detail. The specification of the survey requirements will depend on the seabed general condition and the level of detail required. Transverse passes across the route can also be made at regular intervals along the route. These are especially useful for post-lay surveys, since transverse passes give the relative position of the pipeline most accurately at each crossing. Bathymetric surveys involve the use of an echo-sounder to obtain a complete representation of the depth of the sea bottom along the track of the survey vessel. Multi-beam echo sounders are nowadays commonly used to provide depth data over a swathe of the seabed both under and to the sides of the vessel's track. The objective is to produce charts that define contours on the seabed with a vertical relative height of between them of typically 1-meter. Wide-band bathymetric surveys will give contours with a 2-meter interval or greater. Sub-bottom profiling can be used to establish the geometry, structure and configuration of the shallow geological strata along the pipeline corridors. In effect, this is high-power echo sounding with the sensor carried close to the seabed such that sub-bottom penetration is achieved. Normally such data is gathered for the route planning phases of a project. The presence of any metal objects on the sea floor, such as existing pipelines and communication cables, etc. can be determined with a magnetometer survey. Again, such data is normally gathered for the route planning phase during the line operator's FEED. Video pictures of the seabed, pipeline, etc. can be provided by ROV surveys. These may be useful if free-spanning is anticipated or there are other subsea construction activities related to the pipeline construction, such as crossing preparation, installation of protective mattresses around platforms for dropped object protection, etc. An ROV may be used to monitor and touchdown location during lay.




4.12.4 Route Survey Prior to Pipeline Installation

A pre-lay survey is normally carried out just prior to (i.e. a few days or weeks before) pipelay to identify any new obstructions or changed conditions along the route. The route planning already carried out should have optimised the route to avoid such problems. Usually the pre-lay survey will consist of a bathymetric and side scan sonar survey of the pipe route The route can be adjusted to avoid significant obstructions that may affect the integrity of the pipeline, or if this is not possible, then consideration will be given to their removal. The pre-lay survey may also include the use of an ROV to give video pictures and more detailed survey data of any abnormalities found. Preliminary interpretation of the side-scan and echo-sounder (bathymetry) results will be performed on board the survey vessel to determine the acceptability of each of the proposed pipeline route.

4.12.5 Survey Operations During Lay Surveys of the pipeline are only normally carried out during pipe lay if spanning is anticipated or there are specific close tolerance lay operations, such as convergence with and/or crossings of other pipelines or cables. A side-scan survey carried out immediately after pipelay will determine the as-laid location of the pipeline, its relationship with the seabed (in particular with regard to spanning) and the general condition of the laid line. In addition, an ROV video survey of the pipeline may be made to ensure that installation has been performed in accordance with requirements, to the extent visually possible including the identification of discernible damage and free-spans.

4.12.6 Post Lay / As -built Surveys Post lay surveys will normally be performed by side-scan and transverse echo-sounding. These will establish the final position of the pipeline and enable as-built charts to be produced. If there are special requirements, then an ROV post lay survey may be carried out. Generally, a fully instrumented post-lay ROV survey will obviate the need for separate side-scan and bathymetry since this data will be gathered by the ROV. Final post lay surveys will only be completed once all post lay activities have been carried out as part of the contract, such as span corrections, crossing protection installations, trenching and/or burial. In areas where there has been no further




intervention, the data from any survey performed during lay survey will also serve for the as-built survey. Where diver intervention has been involved, such as for tie-ins, the divers will also perform a video survey of their completed work.

4.12.7 Survey Activities on the Barge Surveyors and equipment on the barge will provide continuous information regarding position and heading. Typically, pre-plot charts on a scale of 1:2000 will be prepared showing the required barge course and the design pipe route. Barge position and heading will be continually monitored. After each pipe pull, a fix will be taken giving joint number, heading, and UTM co-ordinates for the bead-stall or any other point, as required. The survey computer system will provide a continuous graphics display of barge outline and pipeline route, which is also recorded. . The survey operators will advise the tower foreman of any necessary changes in barge position and heading. The barge systems will be interfaced with navigation and positioning systems on each AHT to control the placing of anchors.

4.12.8 Final Documentation Package Throughout the course of pipeline construction, data is recorded for inclusion in the final documentation package. This data is also available or presented to the client representative(s) on the barge during the work. Depending on project and contract requirements, the following information is normally part of the final as-built documentation package (document deliverables) for the new pipeline.

− Pipeline route charts − Hydrostatic testing and pigging details, leak testing − Field joint numbers for anodes − Spanning of pipelines, if any, including remedial measures

taken (if applicable) − Pipeline installation record showing the line pipe material,

diameter, wall thickness, coatings, etc. for each section of the line plus the pipe tally data (length of each pipe joint, cumulative length, weld joint number, NDT results and reference).

− Trenching or Burial Report (if applicable) − Barge Daily Job Reports and Safety Reports The project procedures, engineering analyses, etc. will also form part of the project documents handed to the client. The complete deliverables package will be in accordance with client requirements.




4.13 Job / Activity Safety Analysis

Well before offshore mobilisation, Job Safety Analyses will be performed for all anticipated activities. All steps recommended to be taken to improve safety and reduce risk will be implemented in the planning for the work. Global's activities for subsea pipeline construction are relatively repetitive from project to project. Global has already carried out Job Safety Analyses for its routine operations including many of the construction activities described in this general procedure. These also include routine barge marine operations and maintenance activities. The requirements and parameters of work and required activities for each project shall be reviewed from a Job Safety Analysis viewpoint to ensure that these all fall within the limits of the analyses already carried out. Any activity that is new or outside the parameters already covered shall be subject to a new Job Safety Analysis. All findings and recommendations from such new Job Safety Analysis shall be implemented before the related activities are undertaken. From a safety standpoint as well as for customer satisfaction, all equipment and materials used for pipeline construction will be from proven suppliers, will be fabricated to established designs and will be kept and used in good condition. Methods employed will be in accordance with prudent engineering, fabrication and standard construction practice

5.0 RELATED DOCUMENTS AND REFERENCES

5.1 Typical Project Procedures The procedures and documents listed in the following table are typical for a subsea pipeline construction project. These documents comprise both general procedures applicable to the project performance, and project-specific procedures that are prepared during the initial phases of the project. This list is not exhaustive and is included as a guide for the performance of specific projects. The actual documents to be produced will be determined for each project in accordance with the project and client requirements.

Document Title

GENERAL PROJECT MANAGEMENT PROCEDURES

Project Master Document Register




Document Title

Project Document Control Procedure

Project Management & Interface Procedure

Project Procedure for Daily, Weekly & Monthly Reporting

Project Scheduling and Control Procedure

Project Procurement Procedure

Sub-Contracting Procedure, including Subcontractor Scope of Work, Safety Plans & Quality Plans

Project Inspection and Testing Plan

Technical Specifications for Project Materials

Control of Customer Property Procedure

HEALTH, SAFETY & ENVIRONMENT

Project Health & Safety Management Plan.

HSE Management System.

Safety Manual (Health, Safety & Environmental Manual)

Emergency Response Procedure.

Vessel Inspection Report.

Vessel Medivac Procedure.

Standard Operating Emergency Procedures.

QUALITY CONTROL

Project Quality Plan – QA/QC Plan

Monitoring, Control and Inspection Procedure

Dimensional Control Procedure.

Control of Monitoring and Measuring Devices BKK-PRD-2401

Non-Conformance Reporting and Disposition Procedure

NON DESTRUCTIVE TESTING

Non Destructive Testing Procedures

NDT Procedure Qualifications.

NDT Personnel Qualifications




Document Title

WELDING

Offshore Welding Procedure with Specifications and Codes References

Welders List.

Welding Procedures Qualification Tests.

Welder Qualification Tests.

Control of Welding Consumables Procedure.

FIELD JOINT COATING

Field Joint Coating Procedure

Concrete Weight Coating Procedures

CTE Coating Procedures

Neoprene Coating Procedures

ITP for CTE & Concrete Coating Processes

TRANSPORTATION

Procedure for Linepipe Load-out and Transportation

MARINE EQUIPMENT / OPERATIONS

Operations Manual

Marine Standard Operating Procedure

Anchor Handling Procedure

Construction Barge Operations Manual.

Construction Barge Statutory Documents / Certificates.

Support Vessel Statutory Documents / Certificates.

Vessel Movement Activity Logs and Reports.

SURVEY & POSITIONING

Survey and Positioning Equipment and Procedures

Pre & Post Survey Procedures

Surveying Crew Personnel Qualifications




Document Title

INSTALLATION

Pipeline Installation Procedures.

Mid- Point Tie-in Procedure.

Riser Installation and Tie-in Procedure

Procedure for Shore Pull

Diving Procedure.

Cable Installation Procedure.

Cable Transfer Procedure

INSTALLATION ENGINEERING

Pipelay Installation Engineering Overview (General Procedure)

Pipeline Installation Analysis.

Beach-Pull Start-Up Analysis

Mid- Point Tie-in Analysis.

Trim and Stability Analysis for DLB.

Pipe Joint Lift Rigging Analysis, Lay-down and Recovery Head Design

Riser Design, Installation and Tie -in Analysis

PRE-COMMISSIONING PROCEDURE

Flooding, Cleaning, Pigging & Hydrotest General Procedure .

Hydrostatic Testing Procedure (PRD-BKK-5047)

De-watering Procedures