Chevron 2012-2014 Installation Campaign Platforms & Pipelines Installation

 

COMPANY: EMAS-AMC

PROJECT TITLE: Chevron 2012-2014 Installation Campaing Platforms & Pipelines Installation

CLIENT: Chevron Thailand

LOCATION: Thailand

YEAR: 2012

VESSEL: Derrick Lay Barge (DLB) Lewek Champion

SCOPE OF WORK:

MY INVOLVEMENT:

INTRODUCTION

EMAS-AMC (Thailand) Co., Ltd. hereafter referred to as “Contractor” has been contracted by Chevron Thailand to perform the installation of platforms and pipelines as part of the 2012 – 2014 Chevron Installation Campaign. The works involve installation of wellhead platforms and associated pipelines for the further continuous development of the Chevron Thailand Oil and Gas fields in the Gulf of Thailand.

Contractor shall mobilize its installation barge, the Lewek Champion, to complete a minimum of 180 – 200 days of installation activities on an annual basis. The annual work scope varies but will typically include 8-12 wellhead platforms and associated in-field pipelines plus other special installation projects. The installation program shall be split between pipeline installation phases and platform installation phases. A mode change involving mobilization of specific equipment and personnel will be required when switching between pipelay and platform installation mode.

Objective

This document shall provide a guideline for the installation of the pipelines under EMAS-AMC contract. The installation methodology for pipeline startup, normal lay, lay down, abandonment, recovery; pre-commissioning and tie-in are described herein. The details specific to the individual pipeline installations, pre-commissioning and tie-in within the campaign will be covered in Installation Work Packs issued as separate documents to this manual. Any variation from this procedure shall also be captured in Installation Work Packs.

Note: This manual shall be read in conjunction with the Installation Work Packs.

Sequence of Activities and Scope of Responsibility

The sequence of installation activities for a typical pipeline is listed below.

1. Receipt of material on a material transportation barge at site (Provided by COMPANY’s EPC Contractor)
2. Install Temporary sleeper for pipeline startup, (If required)
3. Startup of pipeline using DMA or Hold Back Wire to Jacket Leg or Bowstring method
4. Lay pipeline
5. Install Permanent sleepers for pipeline / cable crossings (If required, concurrently with lay pipeline)
6. Install in-line flange/dummy spool, (If required, concurrently with lay pipeline)
7. Laydown pipeline
8. Recover DMA/ Hold Back Cable/ Bowstring Cable
9. Removal of Temporary sleeper,(If required)
10. Release of Material transportation barge
11. Perform flooding and gauging of pipeline (if required, from new platform end meanwhile to new platform installation)
12. Perform tie-in of pipeline to new platform (if required, at new platform location meanwhile to new platform installation)

ENGINEERING

Pipeline Installation Data

Installation engineering for the particular pipeline will have been completed and approved to allow development, reviews and approvals of subsequent documents such as Installation Work Packs at least 30 days prior to installation. Pipelay analysis for the pipeline shall be completed using the same conditions that would be experienced during actual installation.

The outputs from either static pipelay analysis or dynamic pipelay analysis will include the following;

• Barge Roller and Stinger Roller Height
• Stinger tail depth
• Reaction Force
• Stress Level
• Lay Tension
• Touch down length
• Pipe Gain Length
• Startup configuration  (DMA  or  Hold  Back  Cable  to  Jacket  Leg  or  Bowstring method)
• Limiting weather criteria (Dynamic Analysis)

The outputs will be compiled into a Pipelay Analysis Report which will be referenced offshore during actual pipeline installation. Where possible and applicable, Pipelay Analysis Reports shall cover multiple pipelines. Applicable Pipelay Analysis Reports shall be referred to in Installation Work Packs.

Limiting Weather Criteria

Limiting weather criteria for all critical lifts and normal operations are as follows:

Condition	Normal Pipelay	Normal Operations (Lifting)	Critical Operation (Lifting)
Significant Wave Height	2.4 m	1.5 m	1.2m
Wind Limitations	20 knot	20 knot	18 knot
Current Limitations	0.5 knot	1 knot	0.8 knot

However barge operation shall remain the discretion of the Offshore Construction Manager (OCM), in consultation with CAR.

PIPELINE INSTALLATION EQUIPMENT AND MATERIALS

Marine Spread

The LCP is a non-self-propelled DP2 combination Heavy lift pipelay barge, designed to effectively operate in hostile weather conditions.  The barge measures 143m long by 40m wide, with mean operating draft of 6.5m. The pipe lay ramp is located on the center of the barge and runs the entire length of the barge.

The barge has four (4) welding stations arranged for 40 ft line pipe. There are five (5) additional stations available for NDE, repairs, field joint coating and anode installation.

The line pipe is loaded onboard at the port side of the barge using either the port pedestal crane or the main crane. The line pipe is stacked on deck between portable stanchions and is transported into the pipelay tunnel via a system of longitudinal and transverse conveyors.

The barge is equipped with two Amclyde pedestal cranes. These cranes have a maximum capacity of 68MT with a boom length of 48m. The main crane is a 900 MT Huisman crane with boom length of 70m, and a main block capacity of 900 MT.

LCP is equipped with two 100 MT capacity track type tension machines, giving a total of 200 MT of pipelay tension. The pipelay tension is controlled by a computerized PLCP system with one redundant automatic mode as well as full manual control.

Pipelaying operations are controlled from the Bridge of the vessel where the DP operations take place. The tensioner controls are located here, together with the survey systems. A fully computerized barge management system (BMS) running on DGPS is installed for the whole duration of the job. This allows real time monitoring and tracking of the lay barge as well as the attending AHT.

The LCP will have on board air diving support as well as a work class ROV.

All of the barge accommodation is located above the main deck, and is fully air conditioned with a mess hall and recreational facilities. A helideck is located over the bow superstructure and is capable of accommodating an S61 helicopter.

Refer C4006/G1-1& G1-2 and 31039801-1-DRW-01-002/1 in Section 14.2 for general arrangement drawings and stinger section details of the Lewek Champion.

Following are the anticipated support vessels assisting the Lewek Champion during pipelaying operation:

• Lewek Champion Tow Tug (Lewek Kestrel) – by CONTRACTOR
• Contractor Material Barge and Tow Tug (Lewek Lea and Tango 7) – by CONTRACTOR
• Pipehaul Barge and Tow Tug – by COMPANY
• Supply Boat – by COMPANY
• Crew Boat (Sarah Pearl) – by CONTRACTOR

Pipeline Installation Equipment

The following is the particulars of pipeline installation equipment onboard DLB Lewek Champion:

Equipment	Particulars	Quantity
Stinger	Type           : Truss stinger No. rollers   : 6 Dimension  : 49.60 m x12.35 m x 11.07 m Weight(air) : 340 MT	1 x section
Tensioner	Type           : Horizontal track grip Make          : SAS Length        : 7 m Capacity     : 100 MT	2 x unit
A&R Winch	Type           : Electric driven winch Make          : SAS Capacity     : 220 MT	1 x unit
Davit	Type           : Pipeline Handling System Make          : SAS Dimension  : 2.45 m x3.24 m x 7.55 m Capacity     : Max. 50 MT @ 3 m. : Min. 12.5 MT @ 12 m.	5 x unit (3 units preinstalled on LCP, 2 units stored on material barge)
ROV Spread (24 hr operation)	Type           : Subsea Vehicles   Make          : EMAS XLS Dimension  : 1.80 m x3.23 m x 2.13 m Capacity     : 150 HP Work Class	1 x LARS 1 x Control Container 1 x Workshop Container
Air Diving Spread (12 hr operation)	Type           : Air Diving System	2 x LARS 1 x Control Container 1 x Decompression Chamber Container 1 x Workshop Container Ancillary items asmrequired
Survey Equipment	Type           : Vessel Based DGPS + Heading + USBL+Tug Management System	2 x DGPS (LCP) 2 x Heading Sensors (LCP) 1 x DGPS (LKT) 1 x Heading Sensors (LKT) Navigation Computer System (LCP and LKT) 2 x USBL Transceivers / Transducers 8 x USBL Beacons

 

Equipment	Particulars		Quantity
Welding Machine	Type Dimension Output	: Manual Welding : 0.36 m x 0.61 m x 0.52 m : 10-500 A	14 x units (within pipe tunnel) + 4 spares 2 x gouging units + 1 spare
Swabbing rabbit	Type Size	: Static, wire brush : 8”,10”,16”	1 x unit + 1 x spare for each pipeline size
Internal line up clamp	Type Size	: Pneumatic engage & release : 8”,10”,16”	1 x unit + 1 x spare for each pipeline size
External line up clamp	Type Size	: Clamp : 8”,10”,16”	1  unit  +  1  x  spare  for each pipeline size
PAUT Equipment	Type Range Size	: Pulse Echo Phase Array : 1-10 MHz : 8”,10”,16”	1  unit  +  1  x  spare  for each pipeline size
Holiday Detector	Type Range Size	: Battery powered : 10kV & 15kV : 8”,10”,16” (1 unit can cover all pipeline sizes)	2 x sets
Line Pipe Handling Rigging c/w spreader bar and pipe handling hooks	Type Size	: Aluminum shoed handling hook : 8” to 12” hooks : 14” to 18” hooks : 6” Hooks	2 x sets per pipeline size range
Pneumatic Wrench c/w socket	Type Size	: Pneumatic Impact : Suitable for nut size 30 mm – 70 mm	2 unit + 1 x spare
Hydratight Tool for Flange Connection	Type Pressure Size	:  Subsea  Hydraulic  Bolt  Tension Tool : Up to 1500 Bar : Suitable for each pipeline	1 x set
Rabbit (Spool Fabrication)	Type Size	: Static, steel gauge plates : 10”,16”	1 x unit + 1 x spare for each pipeline size
External Pipe Cutter c/w cutting torches (Spool Fabrication)	Type Size	: Manual Cutter : 10”,16”	1 x unit + 1 x spare for each pipeline size

Pipeline Installation Materials and Installation Aids

This section detail the project material and installation aids required for pipeline. The following table details the list of materials and installation aids:

	DESCRIPTION	SUPPLIED BY
1	Permanent Installation :
	40’ Coated Linepipe joints*	COMPANY
	Field Joint Coating**	COMPANY
	Inline flange spool or dummy spool components, if required	COMPANY
	Crossing Sleeper c/w lifting sling	COMPANY
	Pin c/w bolts for Crossing Sleeper	COMPANY
	Anode	COMPANY
	Pre-fabricated spools and Metrology spool components for Tie-in Sections (new platform end)	COMPANY
	Stud Bolts and Gaskets for Spool tie-in with spare (new platform end)	COMPANY
	Start up and laydown flanges	COMPANY
	Flange Protector for spool flanges (new platform end)	COMPANY
2	Temporary Installation Aids :
	Deadman Anchor x 2	CONTRACTOR
	Start Up Head	COMPANY
	Laydown Head	COMPANY
	Emergency Head	COMPANY
	Stud Bolts and Gaskets for Subsea Flanges with spare	COMPANY
	FBE Repair kit	COMPANY
	Batch Pig, Brush Pig and Gauge Pig c/w Pinger	COMPANY
	Contingency BiDi Dewatering Pig	COMPANY
	Flange guards c/w stud bolts	COMPANY
	Temporary Sleeper for startup cable crossing c/w lifting sling	COMPANY
	Pipeline Certified Start Up Rigging	CONTRACTOR
	Pipeline Certified Laydown Rigging	CONTRACTOR
	Emergency Certified Laydown Rigging	CONTRACTOR
	Stinger Certified Lift Rigging	CONTRACTOR
	Spool Lift Rigging	CONTRACTOR

* Refer Pipeline Installation Work Packs for specific pipeline coating details

** Refer Pipeline Installation Work Packs for specific field joint coating details

EQUIPMENT SET UP FOR PIPELAY

Barge Trim and Draft

During the pipelay operation, barge trim is to be set to 0.5 deg by stern. The drafts after trim will be as below;

Description	Barge Parameters
Barge Midship Draft (Indicative)	6.500 m
Forward Free Board (Indicative)	4.121 m
Aft Free Board (Indicative)	2.879 m
Trim by Stern	0.5 degrees

Note: draft values are indicative only and may vary as long as 0.5 degree trim is achieved.

Barge Roller & Tensioner Profile Set Up

Barge Roller Profile Set Up

Prior to pipelay operation at site, barge rollers & tensioners will be set as listed in below table. These settings shall be consistent with all pipeline installations for 2014 installation campaign.

Rollers/Tensioners	R1	R2	R3	R4	R5	T1	T2	R6	R7	*R8
Distance from stern (m)	109.35	97.15	84.95	72.75	60.55	48.35	36.15	24.40	12.20	3.00
Bottom of Pipe Elevation (m)	1.89	1.89	1.89	1.89	1.89	1.89	1.89	1.84	1.46	0.74

Notes:

1. Barge trim angle is set to 0.5 degrees w.r.t center of laybarge
2. The barge B.O.P elevations are measured from the main deck level to the bottom of pipe (with no barge ramp considered).
3. “R” refers to barge rollers, whilst “T” refers to barge tensioners.
4. *R8- refers to the barge roller nearest to the stern of the barge.

Stinger Profile Set Up

The Stinger will be set up to suitable/sufficient for pipeline installation as listed in below table. These setting shall be consistent with all pipeline installations for 2014 installation campaign.

Rollers	S1(1)	S2	S3	S4	S5	S6
Distance from Hitch (m)	8.50	16.50	24.50	32.50	40.50	48.50
Bottom of Pipe Elevation B.O.P (m)(4)	3.62	3.98	4.06	3.80	3.35	2.63

Notes:

1. S1 refers to the first stinger roller nearest to the hitch of the stinge
2. The stinger B.O.P elevations are measured from the location of the stinger hitch at the stern of the barge.
3. The bottom of the pipe elevations presented in the table are based on actual elevations of the roller boxes available in the stinge

SITE SPECIFIC SURVEY

General

The primary survey system used through the pipelay for barge positioning and vessel tracking is DGPS. A computerised barge navigation system will be utilised to graphically display the current location and heading of the laybarge in relation to the permanent structures and pipelines in the vicinity. The position and heading of the anchor handling tug will also be displayed. The tug will also have a telemetry system on board, which is interfaced with the LCP navigation computer.

This section outlines the survey procedures to be used to perform the required surveying before, during and after the pipelay. Further technical specifications on the above mentioned systems can be found in Survey Procedure for Offshore Installation. Refer 16002-CNC-OP-GEN-0001 for project specific survey procedures

Pre-Installation Survey

The pre-installation route survey for the pipeline will be supplied to the CONTRACTOR by COMPANY. COMPANY will furnish the CONTRACTOR with the pipeline alignment sheets, containing the location of the pipeline within the corridor and as-built of drawings of existing facilities. No additional pre-installation surveying shall be performed by the LCP prior to pipeline installation unless specifically requested by COMPANY.

Installation Surveying

During the course of the pipelay, the main survey activities will consist of barge track control, pipeline touchdown tracking and pipeline profile checks. Pipeline touchdown monitoring and profile checks shall be performed in general 4 times per day (2 times per shift) when pipelay occurs in open water. Pipeline route fixes of pipeline touchdown shall be taken each dive, i.e. 4 times per day. During pipelay around a curve and when laying near existing subsea or surface facilities, the frequency of diving shall be increased to 6 dives per day to ensure accurate monitoring of the pipeline position. During pipeline startup and laydown, the ROV shall be used to monitor touchdown of the pipeline and record a fix of the startup and laydown heads. ROV may remove the beacon from the pulling head prior to laydown, if the startup or laydown head is significantly rotated. ROV shall also take fixes of inline flanges and dummy spools after touchdown. The as-laid positions for the Inline Flange and Dummy Spool shall be taken by the ROV during transit back to the DMA recovery. During laying over a crossing support, the ROV shall be deployed to provide continuous monitoring of the pipeline touchdown. If required, ROV shall inspect free spans and sleeper touchdown point during transit back to recover DMA. Additional ROV Survey may also be carried out at the request of the CMR. If ROV maintenance is required the dive may be postponed in agreement with CMR. Refer 16002-CNC-OP-GEN-0001 for project specific survey procedures.

All significant debris within 25m of the pipeline route, as shown on the pipeline alignment sheets, shall be plotted in the navigation computer and inspected by the ROV to determine if the debris may pose a hazard to pipe laying operations. If it found that it may interfere with pipeline installation, the CMR / CAR will be consulted and a decision made whether to recover or shift the debris. If the ROV is unable to recover / shift the debris then the pipeline may be laid on a deviated route as agreed by CMR / CAR.

Underwater Positioning

Underwater positioning will be done using an Ultra Short Base Line (USBL) acoustic tracking system. The system consists of acoustic beacons which will be attached to the ROV, handling frames, divers and tie-in spools during installation to provide positional data to the vessel. The beacons are interrogated by a transducer suspended under the vessel. The return signals are then used to generate a distance, heading and depth from the transducer.

The system is interfaced to the barge or vessel navigation system, and the positions of the beacons are graphically displayed on the computer monitor, overlaid on the pipeline and barge / vessel locations. This allows accurate underwater positioning for ROV’s, handling frames, tie-in spools during installation and divers. This system is further supplemented by the ROV’s sector scan sonar, and enhances performance where visibility is limited. Refer 16002-CNC-OP-GEN-0001 for project specific survey procedures, 16002- EMA-OP-ROV-0001 for ROV Procedures and 16002-OWA-OP-GEN-0001 for Diving Procedures

As-Built Survey

As-built surveys shall be completed by others

PIPE RAMP ACTIVITIES

Pipe Ramp & Stinger Setting

Prior to barge’s departure to the field, both the Barge and Stinger roller heights will be accurately set to obtain required ramp profile as specified in Section 8, Equipment Setup for pipelay. Pipe ramp and stinger settings shall remain consistent for all 2014 pipelines. Tuning of the roller heights shall be made by lifting or lowering the roller and inserting pins at the correct position.

Installation engineering will also assume the barge attitude for the pipelay activities. This will help optimize laying configuration and reduce pipeline stress.

Pipe Ramp & Stinger Setting Preparation

This section outlines the preparations required primarily for pipeline startup activities.

Note: this section assumes that the pipe ramp and stinger setting has been completed and checked during mobilization of the barge.

• Condition of each roller support on the pipelay vessel shall be checked before the start-up of each pipeline
  Note: The roller on the stinger shall be inspected at regular intervals thereafter.
• Function test of the line-up system (from ready rack to bead stall) for rotating/moving machinery.
• Function test for the tensioner (set tension machine dead-bands as required) and A/R system (winch), diving system, pipeline tunnel light, camera and alarm system.
• Ensure all materials and equipment for field joint coatings are readily available at Station 8.
• Check pipe rack, line-up station and pipeline internal equipment are functioning including load cell/gauge, PAUT, internal line-up clamp, bevelling machines and etc.
• Prepare swabbing rabbit/brush for line pipe cleaning and gauging.
• Insert pigs into the start up head. Refer to Appendix 1 Pig Launcher Check Lis
• Ensure sufficient quantity of white marine paint is available for marking join
• Test all NDE equipment i.e. PAUT Equipment, high temperature couplant running by water portable, consumables and etc. Ensure sufficient supplies, chemicals, consumable and etc. are available.
• Test and calibrate survey control system. The position of the barge will be monitored during pipelay by Surveyor onboard using survey system.
• Prepare linepipe handing sling.
• Function test hydratight equipment i.e. pressure pump, jacks, hoses, etc. and calibrate pressure gauge to be used.

Line Pipe Handling

Upon arrival of the pipe material barge in the field, the material barge will be brought alongside and offloading the pipe in the order required for normal pipelay will be commenced. The pipe joint length typically is 11.9 to 12.4 m. The joint length is longer than 12.4 m, it shall be rejected and listed in QA/QC report. The pipe shall be handled with aluminum shoed pipe handling hooks. The pipe shall be stored in storage racks on the portside until needed. Refer 16002-EMA-OP-PL-DWG-0010 for typical pipe handling spreader bar.

Aluminum shoed pipe hooks shall be used to load the pipe into the longitudinal conveyors and whenever the pipe is to be moved using the crane. Once in the transverse conveyors, the pipe is transferred forward via powered rollers into the ready rack. At this point the pipe shall be transferred transversely by the pipe handling equipment.

Damage to the bevels shall be repaired at this point using buffing discs and grinding discs as required. In the event of significant damage, weld metal may need to be introduced to the damaged section and then ground back to provide a suitable pipeline end preparation for normal welding. The pipe is then transferred forward into the stalking shoes and aligned for welding.

A small stockpile of pipe joints will be established on the deck of the laybarge. Portable stanchions will be used to restrain these pipes. The maximum stacking height of the stock pile will be limit to 1.8m height from the LCP deck. As the pipe joints are loaded into the first set of longitudinal conveyors, a swabbing rabbit messenger wire shall be passed through the pipe. This messenger wire will be connected to a swabbing rabbit and positioned at the end of the pipe joint. As the pipe joint is transferred forward by the longitudinal conveyor, the rabbit is pulled through the joint.

During the inspection process at ready racks, damage to the pipe coating and bevels shall be noted. Any damage to the coating which is outside of the acceptable range shall be repaired as the pipe is assembled. If the damage is assessed as major, the pipe joint may be placed aside and repaired at a later time. If COMPANY considers that the damage is beyond repair, the joint must be rejected or cut out the damage section. If a bevel is found to be in need of repair, the end shall be repaired at ready racks.

Pipe Welding

The linepipe is transferred laterally into the line-up station and aligned with the last joint of the pipeline in station one (bead stall). Welding, NDE and weld repair procedures will have been prepared in accordance to COMPANY Specification for Pipeline Installation, Tie-In and Hydrotesting, SP0603-PPL-CS-001.

Fit-up will be performed using an internal line up clamp. Hydraulic rams will be used to move the new joint of pipe on the line up rack in three dimensions to align the bevels. When a good fit up is achieved, the internal line up clamp will be engaged and welding will commence.

Four welding stations can be used to complete the weld. Following is an indicative weld pass sequence for each station; the passes are as shown in below table. Any other “Optional Process” which is an alternative process will be decided offshore if required while performing pipeline repair, laydown head installation, etc.

Station No.	Main Processes
1 (Beadstall)	Fit up, root pass, hot pass
2	Clean, fill pass
3	Clean, fill pass, stripper
4	Clean, cap, touch up
5	PAUT
6	Repair, PAUT
Tension Machine #1
7	Not in use
Tension Machine #2
8	Corrosion wrap (HSS) and Anode installation

N.D.E

All pipeline welds shall be subjected to 100% PAUT inspection which will be carried out in Station No.5 or No. 6. A semi-automated pipe scanner shall be utilized; the scanner is capable of holding two or more phased array probes. Once fastened to the pipe the scanner is rotated by hand, scanning travel shall not exceed 15 mm/second. Once scanning has been done, final analysis shall be completed using Tomoview software. The screen layout for analysis shall be conducted in accordance PAUT procedure for pipeline and platform installation, 16002-EMA-QA-GEN-0020.

For each completed weld inspection, the following information (as a minimum) shall be recorded;

• Procedure Identification and revision.
• Ultrasonic instrument number (and manufacturers serial number).
• Search unit(s) identification (including manufacturer’s serial number, frequency, pitch and gap dimension).
• Focal law arrangement including, as applicable, angle or angular range and start and stop element numbers.
• Wedge refracted angle.
• Focal depth.
• Angle incremental change.
• Aperture size (Number of element used).
• Scan Plan.
• Technique sheet identification.
• Couplant used.
• Search unit cable length.
• Details of special equipment used (scanners)
• Computerised program identification and revision numbe
• Calibrations block (s) Identification.
• Simulation block (s) Identification where used.
• Instrument reference gain and reject level where used.
• Calibration data, electronic data and reference reflection, amplitude and distance readings.
• Identification of weld scanned.
• Surface(s) from which the inspection was conducted.
• Restricted areas.
• Technicians name and qualification.
• Date of examination.

Weld Repair

The designated weld repair station is located at station 6. Weld repair may however commence immediately after the defect is detected in station 5 if welding in stations 1 to 4 is still ongoing. PAUT of the repair will be performed in station 6. If the repair is not complete before the next pull or re-repair is required, the repair will be continued at station 6. Repair  of visually identified defects can also be completed at stations 1 to 4. The pipe pull will wait until this complete. If required, joint cut out may be performed at station 6 since it is located before the tension machine. Full joint cut out will be subject to CAR and Offshore Construction Manager (OCM) approval.

As a good industry practice, if not limited by the stresses in the pipe, the maximum length of cut allowed for the repair is 30% of the pipe circumference. Weld repair analysis and the allowable length to cut for repair will be provided in the Installation Work Packs.

Internal Pipeline Equipment

The following internal pipeline equipment will be used during pipeline installation:

• Pneumatic internal line-up clamp.
• Reach Rods

Anode Installation

The Cathodic Protection of subsea pipelines is accomplished by the use of sacrificial anodes. Concrete coated linepipe will be supplied with bracelet anodes pre-installed and thus require no additional anode activities during pipelay. Non concrete coating linepipe requires the installation of half-shell Galvalum III type anodes. To attach the anodes the anode packer plate (pre-welded to anode brackets) will be fillet welded to the pipe surface all around and will be inspected using MPI. Conductivity of the anode to the pipeline shall be confirmed by MPI result and visual inspection. After the anode is installed, FBE repair kit shall be applied to any damaged coating during welding. Refer Section 14.1 for typical anode drawings for 8”, 10” and 16” pipelines.

The below sequence describes the activities to be followed for installation of anodes.

1. Anode will be installed according to requirements as stated in the pipeline alignment sheet.
2. Each anode set will be installed in the middle of the pipe joint at station #8.
   Note: Heavier anodes will be moved into pipe tunnel with mechanical aids.
3. The anode will be installed with all clip plates located at the 3 o’clock and 9 o’clock positions of the pipelines for easy inspection.
4. Using the overhead gantry lift the anode onto the pipeline. Ensure the anode sits firmly on the pipe.
5. Weld the anode clip plates on the pipeline.
   Note: Welders shall maintain close communication with field joint coaters prior commence welding.
6. Visually  inspect  the  clip  plate  welds  and  perform  MPI Inspection.
7. Apply FBE repair kit around the clip plate weld area as required.
8. Record anode identification.

Field Joint Coating

After welding and NDE is completed and approved, the field joint coating operations will commence. The field joint coating will be performed in Station #8. This section describes the field joint corrosion coating application procedure using heat shrink sleeve. Application procedure for the field joint coating shall be as per manufacturer’s application instructions.

• Following preheating as recommended by the manufacturer, a single layer of anti-corrosion heat shrink sleeve of sufficient width to cover the exposed pipe steel shall be applied ensuring that a minimum overlap of 50mm on each side of the original pipeline protection coating. Refer as Appendix 4
• The heat shrink sleeve shall overlap itself at the joint by a minimum of 150mm with the overlap layer pointing downwards.
• Gently heat by using appropriate torch, begin at the center of the sleeve and heat circumferentially around the pipe. If utilizing two torches, operators should work opposite sides of pipe by proper hand signal and communication between the operators
• Holiday detection will take place after the completion of heat shrink sleeve application.
• The overlap axis of the sleeve shall be parallel to the axis of the pipe to avoid being caught and pulled off by the roller on the lay barge.
• The field joint surface shall be evenly heated to a temperature of 100° The adjacent coating surface shall be heated to a maximum of 100° C, in order to obtain a good bond. A pyrometer or temple stick shall be used to ensure proper heating.
• Rolling on the field joint shall be applied to exclude trapped air and also to provide good bond.
• An aluminum sheet shall be applied over the completed field joint corrosion coating and secured in place using bandit straps at three locations. Duct tape shall be applied to sharp edges of the aluminum sheet to prevent damage to ROV umbilical during pipelay.

While the above describes the generic approach to be followed when applying field joint coating, specific cases may require variation from the above procedure depending on the field joint coating to be applied. In case of variation from this generic heat shrink sleeve field joint coating, vendor specific procedures shall be followed and included in relevant Pipeline Work Pack.

Linepipe Traceability / Tally Sheets

1. Pipeline traceability database will be maintained for the entire pipelay duration. Pipe traceability / pipe tally sheets are to be in spreadsheet/ database format and signed scanned copies.
2. As a minimum, joint number, pipe number, heat number length and anode joint (joint no. with anode) need to be written in the pipe tally sheet.
3. At each welding station, record of weld joint number, welder number, batch number of welding rods used, and WPS used shall be maintained at all times during pipelaying operations.
4. Each weld is subject to NDE requirements in accordance with Radiography & NDE Procedure, 16002-EMA-QA – GEN-0002 and PAUT for pipeline and platform installation, 16002-EMA-QA-GEN-0020. Pass / fail results will be included in traceability record. If repair is required, details of repair shall also be provided.
5. Field joint application will be recorded with the following information as a minimum: joint number, batch number, voltage of holiday detectionNote: Survey will also record the joint no., barge heading and coordinates of each joint at the beadstall and touchdown and OT & KP at touchdown & Beadstall. All required data will be shown in the pipe tally sheet.
   Note: Refer Appendix 3 for Survey Pipe Tally Sheet Format and QC Pipe Tally Format.

General

Pipe Material Barge Arrival and Demobilization

The LCP OCM in conjunction with CAR will give instruction by sending an email to tug few days in advance to give ample time to transit to rendezvous point. The instruction shall include essential information like the point of contact, radio frequency, field entrance protocol and etc. LCP admin, Ship Master, Offshore Construction Manager (OCM) & Field Engineers should be included in the distribution list for Tug’s DPR. Tow tug shall contact to Satun Marine Control, before entering to COMPANY Concession and upon arrival at the final location.

A standing instruction will also be provided by COMPANY’s EPC Contractor to inform the Tug Master of their responsibilities offshore. The Tug’s main responsibility is to tow the pipe material barge to site and back, and it’s the responsibility of the LKT to bring the material barge alongside the LCP during installation. However, if site condition requires, the Tug will assist LKT in bringing the pipe material barge alongside.

Upon arrival of the pipe material barge at site, the tow master will report immediately to LCP and should not approach within 8 km of any vessel or structure in the area before contacting the Offshore Construction Manager (OCM).

The Offshore Construction Manager on LCP will take control of the tow within 8 km of the Derrick Barge and instruct the Tug Master accordingly.

Upon completion of installation and approval from CAR, the Tug Master will receive instruction from LCP admin that the barge spread can be released from field. A cargo manifest detailing the balance materials on board the barge spread will be forwarded to COMPANY’s EPC Contractor yard engineer, and at the same time notifying COMPANY’s EPC Contractor of the release of the barge spread. A typical cargo manifest is provided in Appendix 5, photos of materials being returned will also be attached to the cargo manifest package

Satun Marine Control shall be informed when the tug departs COMPANY field (Area of Operational Control).

Permit to Work System

When the barge is working within 500m of any existing platform, COMPANY PTW system will be used for all pipelay and associated operations. The COMPANY PTW system will be administered and implemented by CAR and shall be in place before the barge enters the 500 m exclusion zone of the existing platform. Each COMPANY PTW shall be open for 12 hrs after which a new COMPANY PTW shall be required to be opened.

Following approval of relevant COMPANY PTW, the LCP and/or AHT’s will request permission from the relevant Field OIM / Radio Room to enter the 500 m exclusion zone.

In addition to the COMPANY PTW being in place, the following shall be completed before any vessels enter the 500 m exclusion zone of an existing facility.

• Completion of DP Check List
• Confirmation with CMR / CAR
• Additional measures to be followed onboard LCP:
• Non-Essential hot works on deck are to cease.
• Smoking to be performed in isolated smoking area on B-deck
• Relative to works within exclusion zone of flare

Refer 16002-EMA-OP-GEN-0002, Lewek Champion Barge Instruction Manual and 16002-EMA-OP-GEN- 0003, Lewek Champion DP Operating Procedure for complete field and facility entry procedures. All works onboard the barge or works in green field areas will be performed using the LCP’s existing PTW systems.

Logistic Management

Effective management of material control throughout the campaign is required to ensure pipelay operations can proceed without hold up or delays resulting from lack of appropriate materials. The following provides some guidelines for effective material management. In general, project permanent materials shall be managed by the Field Engineers while project installation materials including installation aids, riggings, consumables, etc, shall be managed by Storeman.

• The Field Engineer will monitor the amount and balance of project permanent materials and report any deficiency to CA
• The Storeman onboard will monitor the balance and usage of the project installation material, and report it to the Field Engineer on daily basis.
• The Field Engineer, based on the report from Storeman for installation material and his own findings for permanent material will forecast the usage of the project permanent and installation materials and make material orders as necessary.
• Storeman is responsible to check the incoming project installation materials. Field Engineer is responsible to check the incoming project permanent material. Any discrepancies in quantity or specification of the items from the original order, shall be reported to Field Engineer or CAR respectively
• Field Engineer is responsible to follow up and clarify with the related onshore personnel, for any important discrepancies from the material orde

Pig Launcher and Pig Receiver

Flooding and pigging may be executed by CONTRACTOR while hydrotesting will be executed by COMPANY. The pig launcher/receiver will be free issued by COMPANY.

Where possible, pig launchers will be installed at the pipeline initiation location and pig receivers will be installed at pipeline laydown location. Using this approach, the pipeline startup head will incorporate pig launching facilities which can also be used for contingency dewatering of the pipeline in the event of a wet buckle. If this configuration is not possible and a pig receiver is required at the initiation location, an emergency pig shall be required to be installed in the pig receiver for contingency dewatering.

In general, the following pig configuration (1) will be installed in the launcher at either initiation or laydown locations. Specific details are included in the pipeline specific work packs.

Specific drawings for each location should be referenced and followed in case of discrepancy from the below configuration.

• 1 x Batch Pig
• 1 x Brush Pig
• 1 x Gauge Pig c/w Pinge

The following shall be completed and confirmed prior to installation of pig launchers and pig receivers.

• Inspect and verify a gauge plate as per the pipeline specific work pack prior to inserting into the pig launcher (Witness by COMPANY’s inspector)
• Valves status will be documented by FE and valve handles shall be tied off on the pulling head.
• Survey Beacon installed in the bucket provided
• All launcher ball valves, check valves and plugs are to be CLOSE All valve handles shall be removed and tied with valve protection frame
• All receiver ball valves for pig receiver are to be OPENE Check valve shall be installed on the outlet of the valve manifold and allowed to release pressure from internal pipeline. All valve handles shall be removed and tied with valve protection frame. Ensure the 4” blind flange forward of the check valve has been REMOVED (this blind flange is used for leak testing for check valve integrity check).
  Note: Refer to each pipeline specific work pack for pig details as well as the required pig launcher / receiver configurations and locations including gauge plate diameter

Site Memo

Site memo will be provided by CONTRACTOR to inform the COMPANY of the installation completion of the pipeline installation. Information contained within the site memo is as below.

• Name of Pipeline
• Date of Completion.
• Pig launcher and pig receiver check list
• Flange tightening data sheet
• As-built coordinates of pipeline startup head, laydown head, temporary sleeper, pipeline crossing sleeper, inline flange, etc. provided by Survey Subcontractor
• Survey pipe tally sheet by Survey Subcontractor
• QA/QC pipe tally sheet
• Photo of pig launcher and pig receiver
• Punch List, e.g., A survey beacon left in bucket due to pig launcher is rotated into seabed.

Refer Appendix 6 for a typical pipeline installation completion site memo.

Installation Tolerance

The lay tolerance is as follows;

• +/- 10 m in open water
• +/- 5 m within 1000 m of an existing platform or other facility. This includes existing pipelines & etc.
  • 5 m x 5 m target box at start up position
  • 12 m x 5 m target box at lay down position

The DMA drop tolerance is as follows;

• 5 m Radius of DMA drop location The spool installation tolerance is as follows;
• Tie-in spool shall be installed such that any part of the spool will be no more than 0.6m (2’) from the design route

The spool piece dimension tolerance is as follows;

• Length and other linear dimension s: ±5 mm (±0.2 inch)
• Bolt hole location: Deviation from centerline ±1.5 mm (±1/16 inch)
• Alignment of bore holes (line joints): ±1.5 mm (±1/16 inch)
• Flange face alignment before bolt tension: The plan across the gasket seating surface shall be perpendicular and horizontal to the theoretical centerline of the pipe to within ±0.25 degrees.

Initiation of pipeline

The initiation location and method will be selected on a case by case basis to minimize installation risk and improve installation efficiency for each pipeline initiation. Locations and methods for initiation of pipeline will be described in work packs for specific pipelines.

There are two common start-up methods for infield pipelay, namely dead man anchor start up and bowstring or tether startup.

Dead man anchor start up involves the use of an anchor to hold the pipeline in the designed/target position while tension is applied to the pipeline string. This method normally applies in a new field or if there is no other obstructing subsea facility nearby. Dead man anchor positions are described in specific installation work packs. 2 drums of wire of length 800m and 600m are available to CONTRACTOR as DMA start up wire. The sacrificial slings will be used to eliminate the need for cutting and socketing of either the DMA or extension wires if used and to adjust length to ensure the head hits the target box. The cutting of the DMA wire will be subject to an MOC.

A target box for DMA drop location is typically 5m radius, and it is along the run line of the pipeline route. In the case of a different drop location being required a site memo will be raised to inform COMPANY personnel if change in DMA position is required due to offshore decision. The new DMA anchor drop location will be approved by the CMR.

Bowstring or tether startup up involves installing a specific length of rigging connected to an existing jacket structure. These activities will normally involve air divers although saturation divers may be required in some cases (depending on the water depth or air diver’s bottom time).  Typically, the bowstring rigging will have one end tied above the waterline and another end below waterline, while tether rigging will only have one sling from the start up head connected to the jacket.

Pipeline initiation using Dead Man Anchor (Using Crane for tensioning)

1. DMA, DMA wire, DMA spooler and sacrificial wires shall be arranged at the port-stern of the LCP. Minimum DMA wire diameter and length will be derived from Installation Work Pack. DMA wire is generally 2 1/4” dia, 600 m to 1400 m long depending on the pipeline startup tension and existing facilities. 12MT Delta Flipper DMA shall be used for pipeline startups.
   NOTE:Actual DMA wire length on the drum shall be marked or identified to avoid confusion prior to commencement of operation. Furthermore when there is a change to the DMA wire length, the previous number on the drum shall be crossed out and the revised length with date shall be provided.
   DMA and DMA wire details shall be specified in Installation Work Packs. In case of deviation between Installation Manual and Installation Work Packs, information in Installation Work Packs shall govern.
   If the pipeline DMA wire crosses existing subsea pipelines, temporary sleepers shall be pre-installed by LCP to avoid contact between the DMA wire and the existing subsea pipeline. The locations of temporary sleepers will be contained in the Installation Work Pack. However the installation of the Temporary Sleeper will be the same as Section 11.3.5 Pipeline Crossing Support Installation.
   If Sleepers are required to be removed (typically removed by DSV) recovery requirements are to be included in relevant work pack.
   In the event utilizing the temporary sleepers for DMA wire crossing, ROV to monitor during deploy and recovery of the DMA wire.
2. Set up LCP stern approximately 50-60 m. forward of anchor drop location and hand over the DMA, Pennant Wire and DMA wire to AHT by Huisman Crane. Refer 16002-EMA-OP-PL-DWG-0119 Step 1
3. AHT will proceed to DMA dropping location and wait for instruction from Barge Foreman. Barge Foreman will confirm drop location with Surveyor and AHT Master to ensure DMA will be dropped in the correct location. Refer 16002-EMA-OP-PL-DWG-0119 Step 1.  Barge Foreman will instruct AHT master to drop the DMA as per approved specific DMA startup drawing included in Installation Work Packs. If anchor drop location is within 500 meters of existing facilities, approval to drop the DMA shall be obtained by CMR before the anchor is placed on the seabed
   NOTE:
   1. AHT crews shall keep clear of back deck where DMA pennant wire is being run.
   2. PA announcement on back deck of AHT prior to splashing of buoy.
4.  Once DMA is on the seabed, and position accepted by CMR, LCP shall proceed to startup location paying out on DMA wire as required along pipeline route. When DMA wire is completely spooled off the reel, stop LCP and dog off the DMA wire at Port-Stern. Refer Appendix 9 – DOG OFF details
   NOTE:
   1. Barge Foreman shall continue monitoring of spooler / DMA wire catenary to avoid overloading at Barge stern.
   2. Non- essential personnel shall keep clear while running out the DMA wire.
5. The DMA wire will then be passed through a snatch block which is installed at the Port-Stern of LCP, and hooked up to Crane (Huisman or Port). NOTE:
   1. The tail of DMA wire shall be 20-30 meter to sufficient length of crane hook height during DMA tensioning.
   2. Crane shall hold tension on the DMA wire prior release dog off on DMA wire.
6. LCP proceeds to start up location and snatch block is positioned in line with pipeline route. Stern of the barge should be at the required distance “E” from the pipeline start up coordinate. Refer 16002-EMA-OP-PL-DWG-0118. Distance “E” shall be the addition of the following
   – DMA wire gain length (calculated from catenary theory)
   – Extension sling length
   – Shackle length
   – Startup head length
7. A pre-tension equal to 1.2 x startup tension will be applied to the DMA using the Crane. Load will be applied, removed, and applied again to ensure the DMA has been set properly.   Load will be maintained until there is no more movement in the anchor then a 5 min holding time will begin. When 5min of holding time is achieved, lower tension to start up tension and paint a mark on the DMA Wire where it touches at stern main deck.
   NOTE:
   1. Anchor drag shall be monitored from LCP after removing slack from DMA wire by monitoring movement of the barge between commencement and completion of the pre-tensioning activity. If anchor drag is greater than 50 meters, the anchor shall be re- set by AHT.
   2. AHT will also monitor the position of the anchor by holding the pennant buoy on deck and adjusting its position as required by the pennant wire position.
   3. ROV shall monitor the DMA wire where it crosses the temporary sleeper, If required.
8. Reduce tension to zero; recover DMA wire until paint marking is on deck. Compare the length between the paint mark and DMA wire end socket with the distance from stern of barge to target box. Add in sacrificial slings as required to make up for the short fall of wire length to reach the target box. Sacrificial slings as provided should be able to reach the target box. In the case of DMA having excess drag, anchor should be picked up and reset. In the event of needing to cut and put a socket on the end of either an extension or the DMA wire, the MOC is to be raised. Note: ROV shall monitor the DMA wire where it crosses the temporary sleeper, If required.
   The work sequence to connect the sacrificial sling as below;
   · Raise Stinger out of water
   · Push pipeline to end stinger tip
   · Deselect  thruster  prior  to  connect  the  DMA wire and sacrificial sling
   · With sacrificial sling already connected to the DMA wire, connect sacrificial sling to crane
   · Using Main Crane, transfer sacrificial sling to stinger tip
   · Inform to the Bridge when people are working at the stinger
   · Connect sacrificial sling to startup head using riggers
   · Lower Stinger to design angle
9. Perform pipeline initiation check list as Meanwhile activity. Pigs shall have been packed into initiation head, Field Engineer to ensure correct orientation and sequence following approved drawings. Valves to be positioned as per the requirements of the specific work pack. USBL beacon shall be installed into Bucket holder at start up head Field Engineer to document valve status and takes photos for inclusion in site memo. Refer Appendix 1 for Pig Launcher Checklist
10. Start pipelay operation with tension and stinger elevation according to Installation Work Pack
    Note: ROV shall monitor the DMA wire where it crosses the temporary sleeper, if required.
11. ROV to check the coordinate, KP and offset of startup flange for reference. ROV will also survey the condition of the pulling head. Fix shall also be taken 3 joints behind the startup head to check alignment of the pipeline
    Note: ROV may require removing the Beacon from pulling head when it is 2 meter above the seabed, if the startup or laydown head is significant rotating. Depending on the actual site condition, it is possible for ROV to remove the beacon from pulling head with the distance greater than 2 meter above the seabed.
12. Continue pipelaying with tension and stinger elevation as stated in the Installation Work Pack

Pipeline Initiation using Bowstring Method

The pipeline initiation using Bowstring method will be selected on a case by case basis to minimize installation risk and improve installation efficiency for pipeline initiation. Below is the description for the LCP to Install the bowstring, however this may be done by DSV, in this case LCP will retrieve the pre-installed bowstring, specific details for initiation of pipeline will be described in work packs for specific pipeline.

A site visit will be performed prior to LCP arrival to ensure that bowstring locations are as per drawings and suitable for the works.

1. Upon arrival of LCP at location, pre-installation survey of jacket leg will be completed by ROV to confirm connection points are free of obstructions or debris.
   Note: The maximum allowable load for the tie-off point on the Jacket leg will be calculated and included in the Installation Work Pack. During the pipelay, the tension will not exceed the designed value.
2. LCP  will  setup  on  location  for  deployment  of  air  or saturation divers to install the startup bowstring. Note: If the bow string pre-installed by DSV, Step 9 – 14 shall be followed.
3. Rigging team will lay out and join up bowstring bridle riggings on LCP deck. Meanwhile, a small rigging team will be sent over to the existing structure/jacket to install the top part of the bowstring rigging. If the crane cannot reach expected location for connection of top rigging, due to overhang, a longer doubled sling will be used at the top which will reach to the outer extremities of the platform for connection. Alternatively the top section can be transferred to a tugger on the platform. See specific work pack for details. Note: The detail of rigging arrangement refers as drawing no. 16002-EMA-OP-PL-DWG-0008
4. With the aid of LCP crane, the bowstring bridle rigging will be lowered down for installation at the bottom level by the divers.
5. Divers will be deployed to install the bottom part of the bowstring rigging. Note: Field Engineer and CAR will be in Divers Control Room during this stage. Field Engineer to confirm the attachment point and rigging are correct.
6. Once the bottom part of the bowstring is connected and the divers already recovered to the surface, rigging crew will install the top part of the bowstring
7. After all bowstring bridle riggings connected to the existing structure, secure connection point to topside structure (where appropriate)
8. Raise the Stinger out of water and push pipe string to end of the stinger
9. With the aid of Huisman crane, a pennant sling will be connected between the pulling head and the bow string bridle using a running shackling.
   Note: If bow-string pre-installed by DSV, the rigging team will be sent over to existing structure/ jacket for connecting a pennant sling with crane hook to bow string. Then a pennant sling will be transferred to the end of stinger tip.
10. Move LCP towards pipeline initiation position maintaining slack in the bowstring rigging
11. Perform pipeline initiation check list as Meanwhile activity. Pigs shall have been packed into initiation head, Field Engineer to ensure correct orientation and sequence following approved drawings. Valves to be positioned as per the requirements of the specific work pack. USBL Beacon will be installed in a beacon holder on the Startup head. Field Engineer to document valve status and takes photos for inclusion in site memo. Refer Appendix 1 for Pig Launcher Checklist.
12. Lower the Stinger to startup depth. Start pipelaying operation in accordance with the approved Installation Work Pack. ROV will monitor bowstring rigging/shackle tie-off location to ensure the rigging is not entangle/twist. When the pipeline initiation head approaches touchdown, ROV will move from rigging / shackle tie-off location to initiation head to monitor.
13. ROV to check the coordinates, KP and offset of startup flange for reference. ROV will also survey the condition of the pulling head. Fix shall also be taken 3 joints behind the startup head to check alignment of the pipeline. Note: If the startup head is not on the seabed, ROV to check the height of the startup head off the seabed by using altimeter/depth gauge and also a fix will be taken at the first joint on the seabed and a minimum of 3 joints from the touchdown point.
14. Continue normal pipelay with tension and stinger elevation as stated in the Installation Work Pack

Pipeline Initiation using Tether

1. Upon arrival of LCP at location, pre-installation survey of jacket leg will be completed by ROV to confirm connection points are free of obstructions or debris. Note:
   – The maximum allowable load for the tie-off point on the Jacket leg will be calculated and included in the Installation Work Pack. During the pipelay, the tension will not exceed the designed value.
   – The stinger will be removed prior to installing the tether line, if required.
2. Rigging team will prepare choking wire and tether on deck. Note:
   · The detail of tether rigging arrangement refers as drawing no. 16002-EMA-OP-PL-DWG-0009
   · If the tether pre-installed by DSV, Step 6 – 10 shall be followed.
3. Divers will be deployed to standby at required elevation for working on the jacket leg.
4. With the aid of LCP crane, the choking wire and tether rigging will be lowered down for installation by the divers. If there is too much overhang on the deck, divers will pull in the tail of the tether using lever blocks or taglines.
   Note: Field Engineer and CAR will be in Dive  Control Room during this stage. Field Engineer to confirm the attachment point and rigging are correct.
5. After all rigging connected to the existing structure as required level, recover the divers, raise up the Stinger out of the water and push up the pipe string to the end of Stinger. Then LCP will relocate to pipe initiation location. Note: The stinger will be re-installed once all rigging have been connected to the existing structure, if required
6. With the aid of Huisman crane, the pulling head end of tether will be transferred to the stinger tip and connected to the pulling head. During this phase, i.e deployment of tether cable, connecting of tether cable to pipeline pulling head and moving barge ahead. ROV will be required to monitor the clearance of the tether line and existing pipelines (if any).
7. Perform pipeline initiation check list as Meanwhile activity. Pigs shall have been packed into initiation head, Field Engineer to ensure correct orientation and sequence following approved drawings. Valves to be positioned as per the requirements of the specific work pack. USBL Beacon will be installed in a beacon holder on the Startup head. Field Engineer to document valve status and takes photos for inclusion in site memo. Refer Appendix 1 for Pig Launcher Checklist
8. Lower the Stinger to startup depth. Start the pipelaying operation in accordance with the approved Installation Work Pack. ROV will monitor the submerged rigging / shackle tie off location to ensure the rigging is not entangle/twist. ROV will be required to monitor the clearance of the tether line and existing pipelines (if any).
9. When it is expected for the pulling head to touch down on the seabed, ROV to check the coordinates, KP and offset of start up flange for reference. ROV will also survey the condition of the pulling head. Note: If the startup head is not on the seabed, ROV to check the height of the startup head off the seabed by using altimeter/depth gauge and also a fix will be taken at the first joint on the seabed and a minimum of 3 joints from the touchdown point.
10. Continue normal pipelay with tension and stinger elevation as stated in the Installation Work Pack

Pipelaying Operation

General

This section describes the methods used during pipelaying operations, including preparations, inspection and testing, linepipe handling, field joint coating, pipelay tolerances, diver/ROV inspection, traceability, laydown, etc.

Preparation Pipe Joints

1. Linepipe and consumables will be delivered to work site on a material transportation barge
2.  Remove end caps/bevel protector, inspect joint visually for any coating or bevel damage before. If coating or bevel damage is found, the following shall be performed
   a. Quarantine the item with clear label / ID ( pipe on hold)
   b. Inform to CAR
   c. Decide on disposition and agree action to be taken between all parties, i.e. rework, waive, scrap
3. Load pipe joints from pipe haul barge and transfer to LCP deck.
4. Load pipe joints from LCP deck into longitudinal conveyors
5. Using compressed air, blow rabbit messenger wire through pipe joint and connect to swabbing rabbit at the bow end of the pipe joint
6. Transfer pipe joint longitudinally forward. This will pull the swabbing rabbit through the pipe joint as it shall be secured to a fixed point on the barge at the stern end of the pipe joint. Refer 16002-EMA-OP-PL-DWG-0011 for typical swabbing rabbit details
7. Record pipe number, heat number, corrosion coating, whether plain or anode joint and any pertinent remarks on the pipe tally sheet, Refer Section 10.10 for pipeline traceability procedure
8. Clean & buff joint bevel and surface up to 2 inch from the end of the joint
9. Joint number will be painted on the opposite sides of the pipes so that ROV can identify during visual survey.

Pipeline Welding, Examination and Coating

1. Pull previous joint until bow end of joint is in station 1 and move ILUC half inside previous joint in retracted position Welding spacers are to halt the barge as required for lineup
2. Move subsequent  pipe joints forward, transverse and into the line-up station
3. Under instruction from spacer align pipe joint using lineup carts operated by line-up operator with direction by pipe fitters at station 1 of the pipelay tunnel
4. Once line-up is achieved, engage ILUC
5. Perform final fit-up of joint and commence pre-heating and welding
6. Complete route and hot pass at station 1 and activate green light.
   Note: pipe shall not be pulled with any red lights in pipeline tunnel
   If Pipe not pulled due to hold up, proceed onto filling if ready.
7. Pull pipeline joint from station 1 to station 2
8. Complete fill passes as per approved WPS and activate green light.
   Note:  If  pipe  not  pulled  due  to  hold  up,  proceed  onto capping if ready.
9. Pull pipeline joint from station 2 to station 3
10. Complete fill passes as per approved WPS and activate green light
    Note:  If  pipe  not  pulled  due  to  hold  up,  proceed  onto capping if ready.
11. Pull pipeline joint from station 3 to station 4
12. Complete capping passes as per relevant approved WPS and activate green light
13. Pull pipeline joint from station 4 to station 5
14. Perform NDE on pipeline joint as per Section 10.5 and activate green light after acceptance of results.
    Note: if a defect is detected and welding is on-going in station 1 to 4, repair of the defect may commence in station 5. When the pipe is ready to be pulled, the repair process shall be stopped (at a suitable stage to avoid compromising the repair) and continued in station 6 after the pull is completed. Refer Section 10.6 for pipeline repair
15. Pull pipeline joint from station 5 to station 6
16. Commence / Complete  pipeline  repair  if  required  as described in Section 10.6
17. Pull pipeline joint from station 6 to station 7
18. Station 7 not in use
19. Pull pipeline joint from station 7 to station 8
20. Perform  anode  installation  (mid  joint,  if  required)  as described in Section 10.8
21. Perform Field Joint Coating at station 8 as described in Section 10.9

Note: the sequence describes the progression of a single joint as it passes through the pipe tunnel. Activities described in each station are being performed simultaneously with activities performed in each respective station.

Inline Flange / Dummy Spool Installation

Inline flange or dummy spool installation will be completed using one tensioner open method. A Tensioner open at any time with the pipelay tension transferred from tensioner #2 (aft tensioner) to tensioner #1 (forward tensioner) as the inline flange or dummy spool passes through the tensioners. The one tensioner open method shall be commencing as following;

1. As LCP approaches within 20 joints of the KP of inline flange/dummy spool location, the pipeline gain and total joints to be installed shall be calculated by FE.
   Note:
   · Inline flange / dummy spool flanges shall have been already welded to a suitably sized pipe pup piece with overall length of 12 meters. The pup piece shall then be welded to the pipeline string.
   · The Inline flange/dummy spool shall have the flange shroud pre-installed prior lift into the Line-Up Station.
   · The inline flange/dummy spool will be assembly and hydratight at portside main deck of LCP.
2. FE will calculate that inline flange/dummy spool touchdown point to position the inline flange / dummy spool within the advised tolerance if required. Note:
   · The position and tolerance for inline flange/dummy spool shall be referred specific drawings/pipeline work packs.
   · The joint no. of inline flange/dummy spool to be installed shall be verified by CMR prior lift into the Line-up station.
3. Lift the inline flange / dummy spool into the Line-Up Station at the correct KP point of the pipeline and fit-up to the end of the pipe string.
4. Weld the inline flange / dummy spool pup piece (pre- welded to the inline flange / dummy spool where possible) to the pipe string. Move the LCP forward as per the normal pipelay operation.
   Note:
   · The top/bottom rollers shall appropriately move to allow the flange to pass through.
   · Barge Foreman shall visually watch the transfer process and maintain constant communication with Tensioner operator.
5. When inline flange / dummy spool reaches Station #5, LCP shall stop moving.
6. Transfer pipelay tension  to tensioner #2 (if  not already provided by tensioner #2) and open tensioner #1
   Note: Ensure the tensioner opens  wide enough for the flange pass through.
7. Move  LCP  forward  until  flange  has  passed  through tensioner #1
8. Transfer pipelay tension from tensioner #2 to tensioner #1 and open tensioner #2
9. Move  LCP  forward  until  flange  has  passed  through tensioner #2
10. When inline fitting / dummy spool has passed through tensioner #2, re-engage either one or both tensioners (as required) to take up the pipelay tension as per Installation Work Pack
11. Normal pipelay operations shall be continued
12. Fix to be taken by the ROV when the inline flange / dummy spool is on the seabed.
    Note: The final fixes shall be done by ROV during transit back to recovery the DMA at startup location.

Pipeline Crossing Support Installation

Pipeline crossing supports or pre-installed span correction supports shall be installed by Lewek Champion during pipelay operations. The support will be installed using the Huisman crane when the crossing location arrives at the stern of the barge. The barge will be shift towards the port or starboard side (depending on actual conditions and pipelay route summary) by approximately 5 – 10 meters or as required to allow installation of the crossing support. Support will be installed using ROV and sacrificial slings. Position of the support will be completed using USBL beacons mounted onto the spreader bar used to lift the support into position. The below should be read in conjunction with installation sequence drawing 16002-EMA-OP-PL-DWG-0020.

1. Prior the LCP stern is reaching the existing pipeline approximately 5 – 10 meters, survey the crossing point with the ROV to confirm location and absence of debris along existing pipeline, minimum 50m either side. If the existing pipeline is not visible, ROV may have to survey a greater distance than 50m to find visible pipe.
   If the pipe is still not visible a pipe tracker may be required to locate the existing pipeline before installing the sleeper.
   ROV is carried out the crossing support survey before the stern of barge reached to the existing pipeline.
   Note:
   · To ensure that the crossing sleeper is not lifted over the existing pipeline; the sleeper will be lifted and swung to stern of LCP before the stern of the barge reaching to the existing pipeline.
   · Specific requirement for the pipe tracker shall be referred to specific Pipeline Work Pack.
2. Stop pipelay and hold the pipe string at lay tension once the stinger tip is at the sleeper location. Move the LCP approximately 5 – 10 m to the starboard or port of the pipeline route once the crossing 10 to 20 meters past the stern of the LCP
3. Preparation work of Crossing Support
   · Lifting Sling to be paint white color
   · 6 x pins shall be installed on Crossing Support
   · 2 x USBL beacons shall be installed on the Handling frame (spreader bar)
   · FE to confirmed the crossing support to be installed
   · FE to check access of pin hole
   Lift the crossing support using handling frame (spreader bar) and main crane from Material barge.
   NOTE: To avoid working under heavy load, the crossing support shall have access of pin hole from outside the frame. Refer TH-CVXPL-56-602 for typical crossing sleeper general arrangement. 
4. Deploy the crossing support using the Huisman crane and lower to approximately 5m above the seabed ensuring crossing support is not lifted over existing facilities. (2 x USBL beacons will have been installed on the handling frame (spreader bar) to assisting in positioning.
   Note: Refer 16002-EMA-OP-PL-DWG-0018 for rigging arrangement and handling frame (spreader bar) for crossing support installation
5. Locate crossing support with ROV and obtain visual
6. Stabilize the crossing support using ROV and bring it near to the existing pipeline at the crossing location. Orientation control of the crossing support will be maintained by ROV. Orientation and position monitoring shall be by USBL beacons installed on the crossing support spreader bar
7. Lower  the  crossing  support  to  the  seabed  and  slack rigging with assistance of ROV
   Note:  CMR  shall  give  approval  before  the Sleeper  is placed on the seabed.
8. Once the crossing support on the seabed, a preliminary survey by the ROV will be carried out using both USBL and sector scan sonar. The following information shall be obtained.
   · Coordinates for both ends of the sleeper
   · Orientation of the sleeper
   · Perpendicular distance from the ends of the pipe support to the existing pipeline
   · Distance between sleepers when more than one sleeper is installed
9. ROV to cut the sacrificial sling located below the bottom of the spreader bar. Refer as drawing no. 16002-EMA-OP- PL-DWG-018. Approval from CMR is required before slings can be cut.
10. Move  LCP  back  onto  the  pipelay  route  and  continue pipelay.
11. ROV will monitor the pipe touchdown as it crosses over both the crossing support and the existing pipeline during and after the crossing.
    Note: As-laid survey of crossing support shall be performed on one time after completion of pipe laydown (During  transit back to DMA location). The following as built information will be obtained by the ROV.
    · Position of the pipe on the sleeper
    · Joint No. of the pipe on the sleeper
    ·Joint No. of touchdown on both sides of the sleeper
    · Joint No. at the pipeline crossing
    · Separation between the two pipelines
    Note: Recorded joint no. should be to the nearest half joint where possible.

Pipeline Laydown

1. As the barge approaches within 20 joints of laydown, the pipeline gain and remaining joints to be installed shall be calculated. FE shall calculate the final joint number for pipeline laydown within the target box. Final joint shall not be cut and have the laydown flange welded onto one end. In the event of platform shutdown which is related works within exclusion zone of flare, FE shall inform to CAR in advance prior approach to 500 m Zone. NOTE: To avoid miscommunication of final joint number, FE perform the following
   · Effective     handover     of     information     from previous shift
   ·Inform to key personal of last joint number to be welded
   · FE / Survey need to check when the last joint is fitted up, whether the distance bead stall to target box is correct.
   · FE shall verify the last joint no. with CMR prior lifting into the Line-up station.
2. Final joint shall be transferred into the pipe tunnel and welded to the pipeline end 
3. After last joint (with flange) is welded and all NDE cleared out, remove all internal pipelay equipment (reach rod and ILUC) 
4. Install laydown head to the pipeline end using flanged connection. Tensioning shall require hydraulic bolt tensioning tools (hydratight) 
5. Install flange protector underneath the flanges. 
6. Install a USBL beacon in the bucket provided and perform laydown head check list (including valve position etc.) 
7. Shackle A&R wire to sacrificial sling and then to the laydown head whilst the laydown head still forward the tension machine. 
8. If field joint application and anode installation is not completed by this time, the activities will be performed at the respective station. 
9. Transfer the load from tension machine to  A&R winch when the laydown head is just forward the tension machine. 
10. Pay out the A&R whilst moving the LCP to keep the constant tension until the laydown head is in between the two tension machine. 
11. Due to A&R wire construction, the pulling head may rotate during this operation. If this occurs, engage the aft tension machine and slack the A&R to transfer the load to the aft tension machine, and then rectify the laydown head rotation. 
12. Continue to move barge forward maintaining the A&R tension. ROV will be utilized to monitor the laydown process especially when the laydown head is in the stinger.
13. When the laydown head is at the stern of barge, Surveyor will take a fix to re-confirm the head location and gain during laydown against design by FE.
    Once the laydown head location and gain have been confirmed that are correct as per design, LCP will continue move forward to laying down the pipeline.
    Note: The location of the head and its projected touchdown location will be monitored throughout the laydown operation to ensure the pipeline is not being pulled out of position. If the pipeline is found to be outside of the target box then the decision to leave the pipeline or to recover and adjust the length will be taken by the OCM in consultation with the CMR and CAR.
14. LCP movement can be stopped when the pulling head is at the specific height from the seabed. This value can be found from the Installation Work Pack. The laydown head will then can be lowered down safely.
    Note: ROV may recover the beacon from laydown head at 2 meter above the seabed, if the startup or laydown head is significant rotating. Depending on the actual site condition, it is possible for ROV to remove the beacon from pulling head with the distance greater than 2 meter above the seabed.
15. ROV  will  take a more accurate fixes  of  laydown head flange coordinate at this stage
16. Using pre-attached shear cutter, ROV will cut the sacrificial sling attached to the laydown head.
    Note, approval from CMR must be obtained before cutting sacrificial wire.
    Final fix will be taken at minimum of 3 joints from laydown head after the sacrificial wire has been cut and the USBL Transducer is less than 30 m. from the laydown.
17. Recover A&R wire and ROV will recover the USBL beacon from laydown head to surface. 

DMA Recovery

1. After completion of pipeline laydown, LCP notifies LKT to relocate for recovery of DMA. 
2. LKT to spool in Pennant wire and recover Anchor Buoy to deck. When LCP arrives at DMA location the LKT will break out DMA anchor and recover to the LKT deck. 
   Note : LCP and LKT are to hold position at least 50m towards the pipeline pulling head from the anchor drop location   while recovering and transferring the DMA, this will ensure that there is no tension on the wire. 
3. Rigging crew transferred from LCP to LKT to disconnect the DMA wire. 
4. Transfer the DMA wire to the spooler on port-stern of LCP using port side crane or main crane. 
5. Transfer DMA to LCP
   Note: Riggers crews to be transferred back to LCP.
6. LKT clears away from LCP and proceed to standby area.
7. LCP adjusts heading to allow recovery of DMA wire.
   Note: LCP will slowly move and maintain the position where is correct heading to ensure that there is no tension on the DMA cable to avoid lift force on the initiation head.
8. LCP will slowly move backward to the initiation head location while spooling in the DMA wire.
   Note: ROV may be called to monitor the DMA wire during recovery operation if the DMA wire crosses a pipeline sleeper.
9. Once the LCP stern is approximately 50 m from initiation head, ROV will take a number of fixes at the flange end to confirm location of the pipeline flange end on pipeline route.
10. ROV to cut the sacrificial wire connected to the initiation head.
    Note: Approval from CMR must be obtained before cutting sacrificial wire
11. ROV to take the final fix on the pipeline flange end. Final fix will be taken at minimum of 3 joints from initiation head after the sacrificial wire has been cut and the USBL Transducer is offset less than 30 m. from the flange end.
12. LCP continues to recover the DMA wire. ROV will monitor recovery of DMA wire until clear of seabed to ensure there is no risk of snagging on any subsea features. 
13. ROV will recover the USBL beacon from start up head to surface. LCP will transit to new location. 

Contingency Procedures

Pipeline Abandonment Procedure

During pipelaying operation, if the environmental conditions are such that the LCP cannot hold the position, and/or excessive movements are caused in the pipe/stinger, and/or weather conditions exceed limiting weather criteria as specified in dynamic lay analysis, or for any other unforeseeable reason, it may be necessary to discontinue the pipelaying operation and abandon the pipeline.

Environmental condition for pipelaying abandonment is depend on barge motions (pitch, heave, and roll), taken into account other weather parameter such as wind speed, sea state condition etc. If a TRS (Tropical Revolving Storm) is developed within the location of works and head toward the LCP, the pipelaying operations must be stopped as soon as possible.

Decision to abandon the pipeline will be made by Offshore Construction Manager after consultation with CAR and onshore management wherever possible.

1. Remove all internal equipment from pipeline interior. 
2. Weld emergency laydown head onto the last welded joint and finish the weld at Welding Station # 1. 
3. Finish all remaining weld. Record the last joint number where NDE is performed.
4. Ensure  valve  on  the  emergency  laydown  head  is  fully closed and properly secured. Ensure plugs are installed.  
5. Connect emergency abandonment and recovery rigging to the A&R wire and to the emergency laydown head whilst the laydown head still forward the tension machine.
   Note: The detail of abandonment and recovery rigging arrangement refer as drawing no. 16002-EMA-OP-PL- DWG-0017.
6. Transfer the load from tension machine to  A&R winch when the emergency laydown head is just forward the tension machine. 
7. Continue  to  move  barge  forward  maintaining  the  A&R tension.
8. Record the barge stern position when the emergency laydown head is at the stern of the barge.
   LCP movement can be stopped when the emergency laydown head is at the specific height from the seabed. This value can be found from the Installation Work Pack. The emergency laydown head will then can be lowered down safely. Record position and heading of the barge.
9. Depending on the weather, ROV may be called to monitor the abandonment progress and take fix of the laydown flange. 
10. If ROV is unable to dive, the record of the barge stern position at steps no. 8 will serve as approximate position of the laydown head during recovery process. 
11. In case the LCP needs to leave from  site due to bad weather, ROV may call to make a cut on sacrificial sling. If ROV is unable to dive, the A&R wire can be cut as close to the spelter socket as practical. 

Pipeline Recovery Procedure

1. Position the barge such that the expected emergency laydown head location is about 5 – 10m from the stern of the barge as per 16002-EMA-OP-PL-DWG-0007 Step 1.
2. Launch the ROV to subsea marker buoy location for hook up the recovery sling. Refer 16002-EMA-OP-PL-DWG- 0007 Step 2. 
3. Connect the ROV hook friendly which is connected A&R wire to recovery sling with aid of main crane and ROV. Refer 16002-EMA-OP-PL-DWG-0007 Step 2. 
4. Position the barge heading and location the same as per Step 8 of the abandonment process. The A&R wire must be slack at all time during this operation. Strip out block may be used if necessary to guide the A&R wire from outside the stinger to inside the stinger. 
5. Gradually increase the tension in the A&R winch in accordance with the recovery tension stated in Installation Work Pack. Refer 16002-EMA-OP-PL-DWG-0007 Step 3. 
6. Move back the barge whilst the A&R winch paying in so that the tension in the A&R wire is constant. ROV to monitor the recovery process. Refer 16002-EMA-OP-PL- DWG-0007 Step 4.
7. When the emergency laydown head pass the aft tension machine, activate the aft tension machine. Refer 16002- EMA-OP-PL-DWG-0007 Step 5.  
8. Transfer the load from A&R winch to aft tension machine.
9. Continue to move barge backward maintaining the tension in the tension machine until the pulling head pass the fwd tension machine. Activate the tension machine. Continue to pull in on the A&R winch maintaining zero tension on the wire.
10. When the emergency laydown head is at the bead stall, barge movement can be stopped. Remove   the   A&R   wire   and   the   shackle   from   the emergency laydown head.
11. Cut the emergency laydown head.  Re-bevel the pipe, and continue with normal pipelay. 

Pipeline Dry Buckle

During pipelay operation, the ROV will be utilized to monitor the condition of the pipeline from stinger to touchdown. If the dry buckle has been found over the stinger section or between stinger tip and touchdown, a decision will be made by Offshore Construction Manager after consulting with CAR to either recover the pipeline over the stinger and past the tensioners or to lay down.

Note: If the pipeline will be laid down on the seabed, Wet buckle procedure will be applied. If the damaged section can be safely recovered over the Stinger and into the tensioners, the following procedure will be applied.

1. Remove internal pipeline equipment from pipeline interior. 
2. Tension machines will be used to pull the pipeline back whilst the barge is being backed until the buckled joint is just aft of the tensioning machines. Successive joints from the pipeline to be removed and re-beveled. 
3. Emergency laydown head will be welded to the pipeline and connected to the A&R winch. 
4. Pipeline tension will be transferred from tensioner to A&R winch 
5. A&R winch will pull the pipeline damaged section through the tensioners until damaged  section is forward  of tensioners 
6. Transfer pipelay tension from A&R winch to tensioner and disconnect A&R winch wire from emergency head 
7. Remove emergency laydown head, cut and remove the damaged pipeline section and re-bevel pipeline end
8. Internal pipeline equipment will be re-inserted and normal pipelay operations will commence. This is only permissible if agreed to by CAR
   Note: Undamaged pipe joints can be re-beveled and re- used

Pipeline Wet Buckle

During pipelay operation, ROV also be utilized to monitoring the condition of the pipeline from the Stinger tip to touchdown point. If the wet buckle occurs, a sudden increase in tension and stinger load will be experienced. The severity of the wet buckle will be evaluated using the ROV and a decision will be made to either lay the pipeline down, or recover the pipeline over the stinger in flooded or partially flooded condition. If recovery is considered safe, dry buckle procedure shall be applied. If the pipeline is to be abandoned, the below procedure can be applied.

The preliminary method need to be confirmed wet buckle as following;

• FE will check the analysis to confirmed
  • Water Depth
  • Lay Tension
  • Maximum Load on the Stinger Roller
  • Pipeline Stresses

Upon completion of preliminary check that the wet buckle has occurred, the pipeline needs to be abandoned.

In the event of an abandoned pipeline due to wet buckle, the following steps shall be followed to recover the pipeline. Note that the below steps shall serve as a guideline only and a specific detailed recovery procedure will be developed for pipeline recovery for wet buckle condition.

The below step will be taken after wet buckle recovery equipment & personnel are mobilized.

1. When a wet buckle is experienced and it is determined that the pipeline needs to be laid down, abandonment procedure as outlined in section 11.4.1 shall be applied to abandon the pipeline.
   Note: Upon completion on incident investigation associated with wet buckle, LCP will proceed to next installation activity in the program. Meanwhile onshore team will mobilize the saturation diving team and necessary equipment to recover the pipeliine.
2. Relocate LCP to the damage pipeline location and deploy ROV to inspect the extent of the damage
3. Deploy saturation diver to cut out the buckle section of pipeline.  
4. The abandon pipeline section (with the damaged joints) will be recovered from seabed. 
5. Divers shall cut padeye holes in pipeline end for connection to A&R winch wire and insert a pig stopper pin bar through pipeline.
6. DSV shall be mobilized to launch bi directional pigs located in startup head to dewater the pipeline. Once pigs are launched and reach the damaged end of the pipeline, pumping of air by DSV will continue throughout the recovery process to avoid ingress of water from the damaged end.
   Note: if pipeline was initiated using laydown head, DSV shall launch emergency dewatering pig pre-installed into laydown head for contingency dewatering.
7. Connect A&R winch wire to pipeline recover the pipeline in accordance with procedure stated in 11.4.2
   Note: When pipeline end has been recovered to LCP and tensioner engaged, pumping of air by DSV may be stopped.
8. Continue normal pipelay 

Tensioner Failure

The pipe-lay shall be suspended in case of any failure of the tension machine; brake set mode will automatically set in and the pipe shall be fixed in position. When the tension machine has been rectified and repaired the pipe-lay may re-commence.

If the tensioner track is required to be opened/ lifted to facilitate repair, all internal equipment in the pipeline shall be removed and the contingency laydown head shall be welded to the pipeline. A&R winch wire shall be attached to the emergency laydown head to take up the pipeline tension; the Offshore Construction Manager shall make the decision with consultation with CAR whether the pipeline will be abandoned.

Failure of DP Positioning

In the event of failure of the positioning system on the LCP, pipelay shall be suspended and corrective action shall be undertaken. The procedure for failure of positioning shall follow as Barge Instruction Manual; 16002-EMA-OP-GEN-0002 and DP Operational Procedure; 16002-EMA-OP-GEN-0003. The Offshore Construction Manager (OCM) with consultation with CAR shall decide on subsequent action base on extent of failure DP system.

ROV may be used to assist in evaluation of situation after failure of positioning system.

Failure of Survey Positioning System

The survey positioning system equipment on LCP is supplied with full back-up and spares as described in Survey Positioning Procedure; 16002-EMA-OP-GEN-0001. In the event of system failure, the back-up system will be engaged.

Excessive Dragging of Start-up Anchor during Pre-Tensioning

In case of excessive dragging (more than 50 meters) of, the anchor shall be re-deployed and tested again.

Position of the Pipeline Flange Connection Falls outside the Target Box

If the pipeline initiation / laydown head falls longitudinally outside the target box, an assessment of  remedial action to be taken will be performed by field engineers and CAR. If a revised spool approach to the platform is acceptable to COMPANY, spool lengths shall be adjusted to suit the laydown position of the pipeline.

If spool piece adjustment is not possible or not acceptable to COMPANY, the pipeline shall be recovered to surface for length adjustment.

• For recovery of laydown head, A&R winch shall be used to recover the pipeline as per Section 11.4.2
• For recovery of startup head, DMA wire will be recovered to LCP and re-terminated at approximately 80 meters from the startup head. Recovery of pipeline shall be as per Section 11.4.2

If the initiation or laydown head falls laterally outside the target box, then the derrick crane and/or A&R winch shall be utilized to lift and relocate the pipeline head into the target box.

Decision to recover the pipeline or to lift the pipeline will be carried out in consultation with CAR/CMR.

Damage to Existing Facility

In the event that any offshore pipelay activities cause a breach or rupture to an existing subsea pipeline then COMPANY emergency response procedures will be put in place. Any damage to an existing subsea pipeline which does not cause a breach or rupture shall be surveyed in detail and the results passed to the pipeline owner, who will in turn advise of any remedial actions. Damage to any other subsea facilities, such as telecommunication cables, manifolds, etc, shall be handled in a similar way

Pipe rides up and out of Tensioner

The LCP is set up with breakover or overbend of the pipe into the Stinger located stern of the tensioners resulting in low vertical forces exerted on the tensioners and hence low chance of the pipe riding out of the Tensioners. Furthermore, the tensioner pads are designed to grip the pipe not only horizontally but to also provide vertical stability. However attention must be paid during initial setup of tensioners to ensure the tensioners are in the correct position for running pipe.

In the event of incorrect equipment alignment and set-up causing the pipe to ride up and out of the tensioner, a vertical push down roller is installed to prevent the condition from becoming critical, i.e. the pipe coming completely out of the tensioner pads but it can still walk to the edge of the pad in a critical postion. Particular attention should be paid while laying 8”, 10” and 16” pipes as they do not have Weight coating and therefore have a much lower Friction running through tensioners.

Notwithstanding the above, if pipe walks out of one tensioner the following steps shall be taken.

• Barge movements shall be stopped upon detection of pipeline misalignment in the tensioner
• Return tensioners to manual and apply brakes to stop pipe from moving in the tensioner
• Place choker slings on pipe astern of station #9 and secure to barge for contingency purposes
• Check tensioner  under  rollers,  Lower  tensioner  under  rollers  if  required  to  correct  pipeline misalignment
• If using only one tension machine to maintain pipelay tension, engage the second tensioner with pipeline at correct alignment and open first tensione When alignment is corrected, first tensionercan be re-engaged.
• If using both tensioners to maintain pipelay tension, an emergency head may be required to be welded to the pipeline so that tension can be transferred to the A&R winch while the pipeline tensioner alignment is corrected.

Concrete coating slippage

Concrete coating is Slip tested to destruction on production pieces in yard and is not expected to slip, however, concrete slippage occurs the following steps will be applied

• Clear personnel from pipeline tunnel
• Reduce pipelay tension to as low as possible considering actual water depth, sensitivity, tension variance, etc
• If pipelay is being performed using one tensioner, transfer tension to second tensioner unit
• Commence welding emergency laydown head onto pipeline
• Abandon pipeline to seabed as per section 11.4.1Pipeline Abandonment Procedure.

PIPELINE FLOODING AND GAUGING

General

Pipeline flooding will be a controlled flooding by pigging. The pig train containing 3 pigs will be launched through a subsea pig launcher from LCP. The purpose of the flooding is to equalize pressure in pipeline for subsea tie in works. Note: pipeline flooding and gauging is not performed in the same phase of work as pipeline installation. Typically pipeline flooding and gauging is performed during structure installation mode.

This section details the methods for pipeline flooding, including equipment, launcher/receiver preparation, flooding procedure, and the pigging operation procedure.

Installation Work Packs for each pipeline will be prepared where specific details will be provided.

Pig, Pig Launcher and Pig Receiver

Flooding, cleaning, and gauging will be a combined operation carried out by pushing a pig train through the pipeline. A pig train containing three pigs including a batching pig, a brush pig, and a gauging pig. The gauging pig is equipped with an acoustic pinger that can signal the approximate location of the pig in case the pig is entrapped somewhere along the pipeline.

The gauging pig is fitted with one gauging plate. The gauging plate needs to be examined and signed off before insertion into the pig launcher. A photograph shall be taken for record.

The pigs will be loaded into the launcher (depending on the setup, the pig launcher can be either a start up head or laydown head). Location and direction of pig and gauging plate shall be inspected by Field Engineer and CAR (or his appointee).

Prior to start up/laydown, Field Engineer will perform the start up/laydown head check list to confirm valve positions and other appurtenances on the head. If the head is a pig launcher, photograph of hose connection is required for record and reference while undertaken the pigging operations.

During flooding operations, SAT diver will be deployed to install the pigging hose to the pig launcher and manipulate valves as required.

The pig receiver is normally equipped with a double check valve to ensure there is no water ingress from sea into the pipeline interior. The check valves need to be inspected prior installation of pig receiver.

Pigging Operation

Prior to launching the first pig (batching pig), a quantity of untreated seawater is introduced to the pipeline. This quantity is equal to the volume contained in 150 m linear length of pipeline or 4% of total pipeline volume (whichever is greater) of untreated seawater.

SAT diver will manipulate the valves on the pig launcher as outlined in the specific pigging & hydrotest procedure. Launching of the pigs will use untreated seawater. Chemical will be introduced to the pipeline soon after launching the last pig. After the last pig is launched approximately 100m away from the launcher, all launching valves on pig launcher will be opened.

Flooding operations with treated seawater will continue until there is positive indication that the last pig has arrived at the pig receiver. This is normally seen by a sudden pressure increase in the pressure gauge/recorder or a reduction in water flow. If no positive indication is observed, pumping operation will continue until about 1.4x of the required volume.

SPOOL INSTALLATION

Site Specific Survey

Pre-Installation survey

A Pre-engineering survey shall be completed by COMPANY and will be available for use. Upon setup of LCP, an ROV pre-installation debris  survey of spool installation site and surrounding area shall  be conducted to ensure installation site is free of debris & that there are no obstructions.

Seabed Debris and Clearance Survey

Upon installation of the spool pieces, an ROV debris survey will be conducted to ensure that the area has been covered and no items have been left at the vicinity of the respective installation site. The survey will extend over the entire length of the spool, and 5 joints of the pipeline. An as built survey will be carried out along with debris survey. This will include at a minimum as below;

• Flange/Bend position
• Burial/Span position
• Free span height
• Pipeline crossing, if required
• Pipeline support detail, if required

Spool Installation Procedure

Spool installation is required to connect an installed platform to an installed pipeline. Depending on the site layout, multiple spool sections may be required to complete the tie-in. If multiple spool sections are required for a particular site, pre-fabricated sections will be required together with a closing or metrology spool sections that will require field measurement and offshore fabrication from pre-fabricated sections of the closing spool. Where multiple spool section exist, the pre-fabricated sections shall be installed and bolt tensioning completed before metrology measurements are taken. This will ensure best possible accuracy of closing or metrology spool dimensions.

The following sections describe the pulling head and blind flange removal, spool measurement, fabrication, and installation. For installation  of pre-fabricated sections, relevant sections of the spool installation sections can be referenced. Note, the location of the metrology spool and the pre-fabricated spools shall dictate which tie-in end (pulling head or blind flange) will be worked on first.

Pulling Head and Blind Flange Removal

1. Note: the location of the metrology spool and the pre- fabricated spools shall dictate which tie-in end (pulling head or blind flange) will be worked on first 
2. The Offshore Construction Manager (OCM) will sign off an inspection test plan to confirm the status of the pipeline is flooded. 
3. Pig launching and receiving heads will have been attached using hydraulic bolt tensioning tools (hydratight) 
4. The Dive Team will have a tool box talk to ensure the procedure for pulling head removal is understood. 
5. The bell will be launched and lowered to the working depth. 
6. The diver will lock out and  attach a down  line to the pipeline just behind the flange of the pipeline. The down line will be attached loosely to the handrail of the LCP
7. For pipeline pig receiver removal, the diver will be instructed to close valves 1 to 5 (refer laydown head drawings) and remove the check valve. Diver will then open valve #1 and allow any residual pressure to equalize. If excessive suction / exhaust exist which does not dissipate rapidly, valve #1 shall be closed and the diver shall move clear of the laydown head. This will indicate that the pipeline is not fully flooded. The pipeline condition shall be further investigated and additional procedures developed.
   For pipeline pig launchers, diver will confirm all valves are in the open position after flooding operation is complete. If valves are found to be in the closed position, the diver will ensure valves 1 to 5 (refer start-up head drawings) are closed. Diver shall open flooding valve followed by valve #1 located the furthest distance from the flange in case of residual suction / pressure inside the pipeline.
8. When it is confirmed by the diver that the pipeline is free of Suction/Exhaust after performing the above valve actuation sequence, the diver will move onto diving bell clump weight.
9. The work basket complete with flange, flange protector removal tools and rigging for recovery of the pulling head will be lowered to the seabed by the crane whip block. The basket will be attached to the downline and fitted with a hanging light stick to aid visibility if no downline is available it will be guided down.
10. The crane will be controlled from the surface to 5m above seabed and clear of all assets by the diving supervisor. The crane will be stopped at 5m above the seabed or if the diver has a visual he will take control of the lowering and pass instructions to the crane via the supervisor.
11. The basket will be positioned clear of spool laydown area (2m along the pipeline for the pipeline side or behind the flange if at the riser side) and 1m to the side, with a tag line fitted to the pipeline. The crane will be disconnected and lifted 5m above the job and swung clear of the work site. 
12. The diver will remove the flange guard by removing the locking ring clamps on the pipeline and the pulling head
13. Providing the pipeline is either above the seabed or requires only minimal excavation to gain access. The diver will remove the pigging head from the pipeline using flogging spanners or impact wrench etc. If the pipeline is too buried to work on, an A-Frame will be lowered and installed on the pipeline one (1) joint from the flange. The chain falls will be used to lift the end clear of the seabed. 
14. The diver will remove all studs from the pigging head except for the 12-3-9o/c positions studs, which will only be loosened. 
15. The pulling head will be fitted with lifting rigging sling for recovery 
16. The crane whip block will now be attached to the lifting hook point and remain loose. The diver will work from the pipeline side. 
17. The 12o/c stud will be loosened with the stud having a full nut on one end ready for easy removal. The 9 & 3o/c studs will now be removed. 
18. After re-checking that the flange has no residual internal pressure /suction, the crane will be lifted so the weight is just off of the 12o/c stud. The stud will now be removed. 
19. The diver will instruct the Diving Supervisor to “come up easy on the load”, until the load (pigging head) is 1m plus off of the seabed. Once the pulling head is 1m clear off the seabed, the crane will slew the pulling head at least 5 m clear of the work site. 
20. The diver will move onto diving bell clump weight and the pigging head will be recovered to the surface. 
21. Meanwhile during pulling head removal, fire pumps of the LCP will be used to fill riser with water. This will equalize pressure in riser at the seabed. 
22. The diver will relocate to the riser flange 
23. The diver will crack the bleed valve on the blind flange, and move to a safe area while any remaining Suction/Exhaust is dissipated. The riser shall have already been flooded from the surface using fire hose.
24. The lifting sling will be lowered by the crane whip block and attached to the handling padeye on the blind flange. The diver will remove all studs from the blind flange  except for the 12-3-9o/c positions studs, which will only be loosened.
25. The 12o/c stud will be loosened with the stud having a full nut on one end ready for easy removal. The 9 & 3o/c studs will now be removed. 
26. After re-checking that the flange has no residual internal pressure / suction, the crane will be lifted so the weight is just off of the 12o/c stud.The stud will now be removed. 
27. The diver will instruct the Diving Supervisor to “come up easy on the load”, until the load (blind flange) is 1m plus off of the seabed. Once the pulling head is 1m clear off the seabed, the crane will slew the blind flange at least 5 m clear of the work site. 
28. The diver will move to onto the diving bell clump weight and the blind flange will be recovered to the surface.
29. The diver will be recovered into the bell. Recover the bell to the surface.  

Spool Metrology

1. A measuring table provided with horizontal and vertical protractor and a hard wire measuring system will be installed on top of the first tie-in flange location. The hand winch on the measuring table will be utilized to tension the wire for accurate measurement. The measuring table needs to be in a horizontal position confirmed by the inclinometer installed in the table
   NOTE: Field Engineer will be in SAT control van at all times during the measurement process.
2. Another measuring table (slave table) will be installed at the second tie-in flange location. The measuring table needs to be in a horizontal position confirmed by the inclinometer installed in the table
3. Run taut wire from the master table to the slave table and secure it on the slave table. 
4. When taut wire is connected to the slave table and clear of all debris, taut wire shall be tension up using hand winch 
5. Diver will swim from one end to another to confirm that the wire is straight, tension, not entangled anywhere in between. 
6. Diver will run a measuring tape between the master and the slave tables to measure the distance between the two tables. 
7. The divers will show both of the angles at both tables and distance between two tables to monitor screens and record by Diving Supervisor. If possible,  the Dive Supervisor will “Screen Capture” the measurements taken.
   NOTE: All the data which are recorded will be witness by FE.
8. The  taut  wire  will  be  de-rigged  and  the  table  will  be recovered to surface
9. Field Engineer will then calculate the required spool dimension and generate drawing to fabricate the spool using AutoCAD. The diver’s measurements, screen capture and the FE calculations will be given to the CMR for verification prior to commencement of spool fabrication

Spool Fabrication

1. The spool sections will be laid out on main deck port side such that there will be enough room for main crane or starboard crane to lift and overboard spool section. Layout also needs to ensure escape routes and walk ways are maintained and not blocked during the spool fabrication.
   Note:
   · Metrology spool sections will be provided in usually three sections. Each section will have an amount of “green” for field modification after metrology result is obtained. This green needs to be considered when establishing spool layout on port deck.
   · Note the use of mitered joints is to be minimized as far as practical
2. QC Supervisor will record all the info pertaining to the materials (pipe number, etc.) and welding (welder ID, WPS used etc.) and witness all welding activities. 
3. Spool “green” will be cut and prepared for welding according to metrology result and fabrication drawings provided by Field Engineer 
4. After the field joints are fit up and ready for welding, the complete spool section will be measured from flange to flange to verify the geometry of the spool 
5. After all welds are finished and pass all NDE requirements, run gauging rabbit through the entire length of the spool piece to verify internal geometry of the spool section. This activity needs to be witnessed by CAR or his appointee. 
6. As-built measurements are to be taken and recorded with the material data. An as-built drawing shall be produced and passed to CMR for review and witness. 
7. The finished spool will not subject to 2 hours hold period hydrotest as per COMPANY Instruction 881171-EMAS- ITC0052.
8. Install spool lifting rigging.
9. Install plywood protection on the flange face   together with 1” manila rope lacing between the flange bolt holes
   Note: Installation of metrology spool does not require the use of a USBL beacon.

Spool Installation (pre-fabricated and metrology spool)

1. Pick up the spool off the deck, slew over and lowered into the water. 
   Note: For pre-fabricated spool, a USBL beacon to be installed where is the free end, not the end that will be attached to the existing spool.
2. Lower down spool until it’s 3m off seabed while monitoring by Divers 
3. The crane operator will position the metrology spool as per Dive Supervisor’s instruction. 
4. Once the correct position is achieved, divers will align spool piece flanges using come-a-longs 
5. Using draw bolts or drift pins, bring both flanges together and start insert bottom bolts. 
6. Check  the  flange  gaps  at  four  locations,  and  confirm alignment 
7. Install the ring joint gasket. 
8. Install remaining bolts and tighten up the gap. 
9. Check   the   flange   gap   at   four   locations   and   confirm alignment.
10. Hydraulic bolt tensioning device will be used to tighten up the flange. Procedure in accordance with the Tie-In specific procedure, 16002-EMA-STR-OP-0003 to 0005  
11. For closing spool installation, repeat steps 4 to 10 for second tie-in location