Petronas Turkmenistan Block 1 Gas Development Project

 

COMPANY: Sigur Ros Turkmenistan 

PROJECT TITLE: Petronas Turkmenistan Block 1 Gas Development Project 

CLIENT: PETRONAS Turkmenistan

LOCATION: Turkmenistan

YEAR: 2009-2011

VESSEL: Derrick Lay Barge (DLB) Armada Installer

SCOPE OF WORK: 

 

SUBCONTRACTOR will undertake the WORK for the following facilities to be developed under the PROJECT:

• Export submarine pipelines from Magtymguly (MCR-A) to Kiyanli OGT (separate gas and condensate pipelines, inclusive of pre-installed pipeline risers at MCR-A)
• 26” Æ gas export pipeline, approximately 73km in length.
• 12” Æ condensate export pipeline, approximately 73km in length.
• MEG supply pipeline from Kiyanli OGT to Magtymguly (MCR-A) (inclusive of the pre-installed pipeline riser at MCR-A)
• 4” Æ MEG supply pipeline, approximately 73km in length (this line will piggyback on the 12” Æ condensate pipeline).
• Condensate loading pipelines from the OGT to the SPM buoy
• 2 x 12” Æ condensate loading pipelines, approximately 7km in length each.
• SPM buoy, complete with mooring system, risers and PLEM (engineering and procurement by others).

The signing entities for the SUBCONTRACT are between MMHE and SGRSB.

MY INVOLVEMENT:

I was invlove for the following for this project:

12 x 4” piggy back including beach pull started

26” pipelay including beach pull

The above invovlment is detailed below

INTRODUCTION

Petronas Carigali (Turkmenistan) Sdn Bhd (COMPANY), a wholly owned exploration and production subsidiary of PETRONAS, has entrusted Malaysia Marine and Heavy Engineering Sdn Bhd (MMHE) and Technip Geoproduction (M) Sdn Bhd (CONTRACTOR) to undertake the development of the Onshore Gas Terminal (OGT) and Magtymguly field which are located in Block 1 offshore of Turkmenistan (referred to as PETRONAS CARIGALI TURKMENISTAN BLOCK 1 GAS DEVELOPMENT PROJECT – hereinafter referred to as the “PROJECT”).

The Turkmenistan Block 1 field is an elongated field approximately 50 to 60 km long and 10 km wide offshore Turkmenistan. The Block 1 deposits will be accessed using a phased development plan sufficient to maintain a substantial flow rate for a number of years.

CONTRACTOR has subcontracted part of the PROJECT to Sigur Ros Sdn Bhd (SGRSB) (SUBCONTRACTOR) to perform the “WORK” as specified in the subcontract.

FIELD LOCATION

 

MOBILIZATION

Vessel was constructed solely for this project. Built in Singapore It was charted by Petronas for 8 years.

26” GAS PIPELINE FROM MCR-A TO OGT

DESCRIPTION OF PIPELINE

The proposed 26” Ø Pipeline will be laid as follows:

• 26” Ø x 73 km pipeline from proposed MCR-A platform to Onshore Gas Terminal (OGT) will be laid in two portions. First portion of the pipeline, referred as Section A, will be laid from OGT (KP 73.0) to the Mid Point Tie-In (KP 66.0) location. The remaining portion, referred as Section B will be laid from the proposed MCR-A platform (KP 0.00) to Mid Point Tie-In location. Approximate number of joints to be laid for Section A is 328 joints and Section B is 5656 joints. These two sections will be joined up using above water Mid Point Tie-In at KP 66.0.

SCOPE / SEQUENCE OF WORK

This procedure is divided into Section A and Section B.  Section A covers the pipelaying activity from OGT (KP 73.0) to Mid Point Tie-In location (KP 66.0). The pipeline will be laid upon the completion of 2 X 12’’ Ø pipeline from OGT to SPM. The beach pull method will be utilized as a start-up for Section A. Refer to Document No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull.

Section B covers the pipelaying installation method from the proposed MCR-A platform (KP 0.00) to Mid Point Tie-In location. The pipe laying will commence after the completion of 12’’ & 4’’ Ø x 73km piggyback pipeline. The pipeline will be initiated using Deadman Anchor (DMA) start-up method at the proposed MCR-A platform.

SUBCONTRACTOR scope and work sequences of the 26’’ Ø pipeline x 73 km are summarized as follows:

• Transportation and installation engineering documents.
• Perform pre-lay survey of the 26’’ Ø pipeline (Refer to Document No. SR-TKM-OPR-GEN-02, Pre-Installation Survey Report for Proposed Pipelines and SPM/PLEM).
• Transport linepipes and other appurtenances. Refer to Document No. SR-TKM-OPR-GEN-14, General Loadout Coordination Manual for Pipelines.
• Set-up DLB Armada Installer at 400m from OGT for 12” x 4” Æ pipeline shore pull. Refer to Document No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull.
• Shore pull 12” x 4” Æ pipeline until pulling head reaches shore. Refer to Document No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull.
• Continue lay 12” x 4” Æ pipeline until KP 65 and laydown pipeline in designated target box 5m (lateral) x 5m (longitudinal). Refer to Document No. SR-TKM-OPR-OGT-MCRA-P102, Pipeline Installation Procedure 12” Condensate Pipeline MCR-A to OGT and 4” MEG Pipeline Piggy Back.
• Set-up DLB Armada Installer at 400 m from OGT for 26’’ Ø pipeline shore pull. Refer to Document No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull.
• Shore pull 26’’ Ø pipeline until pulling head reaches shore. Refer to Document No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull.
• Continue lay 26’’ Ø pipeline until 7 km (approximately 573 joints) from OGT and laydown pipeline in designated target box 5 m (lateral) x 5 m (longitudinal) at Mid Point (KP 66.00) Tie-In location.
• Set-up DLB Armada Installer at KP 68.50 for 12” x 4” Æ pipeline recovery. Refer to Document No. SR-TKM-OPR-OGT-MCRA-P102, Pipeline Installation Procedure 12” Condensate Pipeline MCR-A to OGT and 4” MEG Pipeline Piggy Back.
• Recover the 12” x 4” Æ pipeline and continue 12” x 4” Æ pipeline laying until laydown at proposed MCR-A platform. Refer to Document No. SR-TKM-OPR-MCRA-OGT-P102, Pipeline Installation Procedure – 12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked.
• Set-up DLB Armada Installer at proposed MCR-A platform for 26’’ Ø pipeline Deadman Anchor start-up. The target box for anchors deployment is 1.4 m (lateral) x 5 m (longitudinal).
• Lay approximately 5409 joints of concrete coated linepipes onto proposed pipeline route
• Lay down pipeline in designated target box, 5 m (lateral) x 5 m (longitudinal) at Mid Point Tie-In location (KP 66.0).
• Perform Mid Point Tie-In (Refer to Document No. SR-TKM-ENG-MCRA-OGT-P208, 26’’, MCR-A/OGT Mid Point Tie-In Procedure).
• Perform post-lay survey on the newly laid pipeline, determine free span locations and
  Refer to Document No. SR-TKM-OPR-GEN-03, Post-Installation Survey Procedure for Proposed Pipelines and SPM/PLEM. Free span rectification works shall be carried out using grout bags prior to flooding pipeline for spool installation.
• If smart plug is to be utilized for spool installation at MCR-A, flooding the entire pipeline is not required. Free span rectification work shall be performed before pipeline pre-commissioning. (Note: Utilization of smart plug is subjected to CONTRACTOR’s confirmation)
• Install subsea spool at MCR-A. Refer to Document No. SR-TKM-OPR-GEN-07, Subsea Spool Installation Procedure.
• Perform pre-commissioning work on the newly laid 26” Æ Refer to Document No. SR-TKM-OPR-MCRA-OGT-P203, Pre-Commissioning of 26” Æ Gas Pipeline from MCR-A to OGT.
• Provision of as-built documentation. Refer to Document No. SR-TKM-OPR-MCRA-OGT P204, As-Built Report – 26” Æ Pipeline from MCR-A to OGT.

The final sequence of pipelay may be revised as required to suit the agreed offshore installation schedule with COMPANY.
INSTALLATION SUMMARY

Proposed MCR-A Coordinate (Centre of Jacket)	: E 603521.16 N 4397139.31
Start Point Coordinate at MCR-A  (KP 0.00)	: E 603520.01 N 4397172.61
Landing Point Coordinate at OGT (KP 72.952)	: E 650584.68 N 444697.97
Coordinate at Mid Point Tie-In (KP 66.0)	C2 : E 644069.736 : N 4447593.310
Tension During Pipelay	: Section A (OGT To Mid Point Tie-In) Start-up tension at 26 MT Normal tension: Min. 26 MT & Max. 41 MT
	: Section B (Proposed MCR-A Platform To Mid Point Tie-In) Start-up tension at 137 MT Normal tension: Min. 41 MT & Max. 137 MT
Stinger Tip Clearance to Seabed	: Section A (OGT To Mid Point Tie-In) 2.59 m (min) at 11 m water depth 3.01 m (max) at 7.6 m water depth
	: Section B (Proposed MCR-A Platform To Mid Point Tie-In) 2.59 m (min) at 11 m water depth 49.26 m (max) at 63 m water depth

LOAD-OUT AND TRANSPORTATION

GENERAL

The linepipes will be transferred to Turkmenistan Block-1 Gas Development Field using two nos. 200ft class barge and two nos. 272ft class barge.

Upon completion of each loadout, the tiedown and seafastening will be carried out to the satisfaction of COMPANY and the appointed third party surveyors.

Refer to Document No. SR-TKM-OPR-GEN-14 (General Loadout Coordination Manual for Pipelines) for further details on stowage plan and other related information.

PRE-LOADOUT

Prior to loadout from the coating yard, inspection list included in Document No. SR-TKM-OPR-GEN-14 (General Loadout Coordination Manual for Pipelines) will be reviewed and completed. Any areas of potential concern will be highlighted to COMPANY. The loadout is also detailed in the above document.

Particular attention will be given to:

• End condition of linepipe.
• Condition of linepipe coating.
• Linepipes magnetic properties.
• Concrete and anti-corrosion coating cutback.

LOADOUT AND TRANSPORTATION

Loadout list for the linepipes barge for 26” Æ Pipeline from MCR-A to OGT is shown in the Document No. SR-TKM-OPR-GEN-14 (General Loadout Coordination Manual for Pipelines). General arrangement and seafastening details for loadout of the pipeline and miscellaneous items are also included in the above report.

A detailed review of all components and materials loaded out will be conducted and checked against the loadout list as described in the Loadout Coordination Manual. Any discrepancies in the quantity and conditions of the pipelines will be highlighted to CONTRACTOR representative and recorded prior to transfer of custody of the transportation barge to SUBCONTRACTOR. A loadout and tie-down arrangements of linepipe bays on the transportation barge are shown in Fig. 2.3-1 and 2.3-2 respectively. The tie-down and loadout arrangements for the subsequent voyages are detailed further in Document No SR-TKM-OPR-GEN-14, General Loadout Coordination Manual for Pipelines.

Prior to departure of each transportation barge from the respective loadout location, a three (3) day weather outlook will be obtained from the Meteorological Service and forwarded to the tug boat captain master for his further action. Shelter and safe tow route shall also be identified and briefed to the Tug Master by the Marine Captain.

START-UP PROCEDURE

INTRODUCTION

SECTION A

Refer to Document No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull for the start-up procedure at Section A.The 26” Ø x 4 km from OGT to Mid-Point Pipeline will be laid from OGT shore (KP 73.0) to Mid Point Tie-In (KP 66.0) location utilizing DLB Armada Installer. The barge will be equipped with truss stinger for installation. The 26” Ø pipeline will be started-up utilizing shore approach and beach pull method at the OGT shore, approximately 4km from the landfall point (approx. at KP 0.114).

SECTION B

The 26” Ø MCR-A/OGT pipeline shall be started-up at proposed MCR-A platform (KP 0.00) and laid towards near shore, Mid-Point (KP 66.0) by DLB Armada Installer. DLB Armada Installer will be equipped with truss stinger for installation.

The laying of 26” Ø MCR-A/OGT pipeline shall commence by using 2 nos. 10 MT Delta Flipper for deadman anchor (DMA) start-up method. DLB Armada Installer will be positioned on the Northeast side of proposed MCR-A platform, along the proposed pipeline route. Refer to Section 3.4 for details of the offshore start-up procedure.

BARGE SET-UP AND ANCHOR PATTERN

The proposed barge approach for set-up anchor patterns for linepipe start-up and pipelay for 26” Ø. Gas Pipeline from OGT is shown in Fig. 3.2-1.

Note:

This is for information only as actual details will be obtained from General Procedure for Shore Approach and Beach Pull, Doc. No. SR-TKM-OPR-GEN-08.

The proposed barge approach for set-up anchor patterns for linepipe start-up and pipelay for 26” Æ. Gas Pipeline from MCR-A is shown in Fig. 3.2-2 and Fig. 3.2-3.

PREPARATION AND EQUIPMENT LIST

Preparations required primarily for linepipe start-up will be described under General Procedure for Shore Approach and Beach Pull, Doc. No. SR-TKM-OPR-GEN-08 and Section 4.2.2.

The start-up equipment, installation aids and materials as detailed in the Table A below. Table B gives the check list for the start-up head.

ITEM	DESCRIPTION	TOTAL QUANTITY
	DMA START-UP OPERATION
1	Start-up head OD 660 mm, flange type c/w by pass	1 no.
2	DMA cable, size 2-1/4” Æ x 3000 ft lgth	1 lgth
3	DMA cable, size 2-1/4” Æ x 600 ft lgth	1 lgth
4	Pennant wire, size 2-1/4” Æ x 400 ft lgth	1 lgth
5	Shackle, Green Pin bow shackle G-6036, WLL 150 MT	2 nos.
6	Delta flipper anchor, 10 MT	2 nos.
7	Wire lock, 500 cc	20 nos.
8	Pressure gauge c/w valid cert (max. test pressure @ 20 bar)	2 nos.
9	BI-DI pig 26”  Æ c/w 2 nos. sealing dics at each end, pipe ID 625 mm	2 nos.
10	Wire rope clips for 2-1/4” Æ wire rope	15 nos.
11	26” Æ half shell temporary flange protector	1 no.
	PIPE HANDLING
1	Pipe handling spreader bar	2 lot
2	Pipe handling slings and riggings	2 lot
	PIPELAY
1	26” Æ internal line-up clamp	2 ea
2	26” Æ external line-up clamp	2 ea
3	26” Æ stop trolley	1 ea
4	Holiday detector	2 ea
5	7/8” Æ IWRC 6×19 Galvanized EIPS for stop trolley	1,000 ft
6	Copper tubing 1” ID x 1.25mm WT (10ft per length)	20 lgth
7	White paint (5 litre/can)	10 cans
8	Welding consumables	2 lot
9	Beveling machines and assembly	2 ea
10	Field Joint Coating (Polyken Tape)	As required
11	Foam infill (HDPF)	As required
12	Galvanized sheet (1200 mm  x 3200 mm)
	GENERAL
1	NDT equipment and consumables	1 lot
2	ROV spread	1 lot
3	Survey spread	1 lot
4	Diving spread	1 lot
5	General equipment and consumables related to pipelay activities	2 lot
6	A&R winch c/w cable	1 unit

 

SR. NO.	ACTIVITY	STATUS	CHECKED BY (SUBCONTRACTOR)	CHECKED BY (CONTRACTOR/ COMPANY)
1.	Check pull head dimension as per drawing
2.	Carry out MPI on all WELDS
3.	Check the valve location
4	Check the condition of ball valves
5.	Check the direction of flow through check valve:
6.	Check the Bi-di pigs
7.	Check bursting disc orientation
8.	Leak test completed (7 bar)

DETAILED PROCEDURE

This section details out the steps for DMA start-up operation of 26” Ø MCR-A/OGT pipeline (Section B). For Section A, the detailed procedure of the start-up is covered in Document No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull.

This section covers the pipeline start-up activities at proposed MCR-A Platform. The start-up activities are listed below:

1. Upon DLB Armada Installer arrival at proposed MCR-A platform, set-up barge as per anchor pattern in Fig. 3.2-2. Tension test shall be carried out for all anchor winches before setting up the barge at location. Also, ROV will be deployed within newly laid 12’’x4’’ Ø piggy back pipeline and the area around the proposed 26’’ Ø pipeline start-up target box to ensure that there are no obstructions, limitations or debris that will interfere with the DMA start-up. Any obstructions found shall be removed or relocated.

Safety Note: SUBCONTRACTOR Marine Capt. (MC) and Offshore Construction Supt. (OCS) to ensure proper coordination and communication between anchor handling tugs and main work barge during anchor handling activities and ensure all survey & positioning equipment in working condition and calibrated. Reference for anchor positioning shall be made to the approved anchor patterns and pre-lay survey reports by SUBCONTRACTOR. Limiting weather criteria specifications for all activities will be at Subcontractor’s OCS discretion and governed by Company’s marine guidelines of permitted operations.

2. At the end of Position 2 of anchor set-up in Fig. 3.2-2, bring alongside pipe haul barge on portside and transfer linepipes to the pipe rack and barge deck. The maximum tier for 26’’ Æ is 4.
3. Pre-weld start-up head with 900# WN flange on deck and weld permanent 900# WN flange to the 1^st pipe at beadstall. Perform RT on the weldment. Flange tie-in start-up head (with 1 no. bi-di pig inside) to the first linepipe joint. Install flange guide and transponder. Refer Fig. 3.4-2 to Fig. 3.4-4 for detail.
4. Insert internal line-up clamp into the first pipe joint and commence welding the pipe until the first joint reaches Station No.7. Stop trolley, x-ray crawler and reach rod should be inserted inside the pipes after 7 joints have been welded. Refer to Document No. SR-TKM-WLD-GEN-01, Welding Procedure Specification.
5. Reposition the barge at start-up location. The proposed location of the start-up head will be indicated by the survey target box as per Fig. 3.2-3. However the actual position of the barge will be determined on site base on surveyor’s DGPS positioning and the length of deadman anchor cable.
6. Deploy 2 DMA’s with marker buoy utilizing Anchor Handling Tug (AHT). Refer Fig. 3.4-6a & Fig. 3.4-6b for the proposed sequence of DMA deployment. Field Engineer, Marine Captain and Surveyor to finalize the sequence and deployment location at field based on the actual rigging. Refer Fig. 3.4-5 for the DMA rigging arrangement at MCR-A.
7. Once the anchor is at the seabed, bring the other end of the DMA cable to the DLB Armada Installer. Messenger wire rope will be laid along the stinger to the stinger back-end roller and AHT will pick up the end of the messenger wire rope and connect to the DMA cable end. Another end of the messenger wire rope will be connected to the DLB capstan or tugger winch to pull the DMA cable to the A&R winch.
8. Perform DMA soak test with 1.25 times of the maximum DMA start-up bottom tension which is 121 MT (268 kips) by using A & R winch & & hold for 30 minutes prior to pipelay start-up. Refer to Fig 3.4-7a for the option one of DMA soak test using A & R winch. Refer to Fig. 3.4-7b for the option of DMA soak test using crawler crane.
9. Upon completion of the soak test and no anchor drag is found, finalize the DMA line by applying maximum DMA start-up tension at 137 MT (301 kips) and cut off access length on the DMA sling.
10. Connect the start-up head padeye with 1 no. 150 MT Green Pin GP-6036 shackle to the main DMA cable.
11. Reposition the barge as Fig 3.2-2. Continue welding as per the procedure in Section 4 until the start-up head and half joint is protruding on the stinger. Once the start-up head has protruded on the stinger, the tensioner machine is adjusted manually to provide 20 MT (45 kips) of linear tension.

Note: Double check on all valve systems with zero leak tolerance. Ensure ball valves at start-up head is in closed                     position.

12. Continue movement of the barge ahead until tension is transferred to the start-up cable and further movement ahead increases or allow the pipeline in the tunnel to travel.
13. Continue welding and pull the barge ahead. Monitor tension, stinger profile and pipeline profile. Increase tension gradually as per engineering analysis and the details are attached in Section 3.4. There will be no stinger back end roller adjustment throughout the 26’’ Æ Refer to Appendix 5 for anchor uplift force at DMA.
14. When start-up head is approximately 3 meters from seabed, ensure the barge heading is on the proposed route. Deploy ROV to closely monitor the start-up head during lowering down and the pipeline profile. ROV shall take fix coordinate of the start-up head once its on the seabed.
15. ROV shall also take fixes at particular field joint locations along the pipeline from the start-up head to check the sagbend profiles. At this moment, the tension should be as specified in the engineering analysis in Section 3.5. The tension on the tensioner will be monitored to avoid DMA dragging during start-up, pipelaying and at any point of time.
16. ROV shall continue to closely monitor the pipeline from 1^st joint until the deployment of the buckle detector. The buckle detector will be deployed inside the pipes and attach to the internal line-up clamp using 7/8” Ø x 1444.92 ft length cable.

NOTE: The insertion of buckle detector inside the pipes will be easier when more pipe joints are on the seabed such that the back-pressure inside the pipeline being laid is minimized. When pipe joint is no. 93 or more is at the beadstall, buckle detector shall be deployed. Refer Appendix 7 for buckle detector insertion calculation.

17. Continue laying pipe towards OGT as per normal pipelay procedure detailed in Section 4.0.
18. The recovery of the DMA as shown in Fig. 3.4-8 & 3.4-9 utilizing AHT after DLB Armada Installer is 3 km away from proposed MCR-A platform. AHT will move toward North side during DMA line freely drop to ensure that the DMA line is clear from other pipelines routes after resting on seabed. However, the sequence may vary to suit condition at site. Refer Appendix 6 for no. of pipe joints required for DMA retrieval.

PIPELAYING PROCEDURE

INTRODUCTION

The following section describes the method of the pipeline installation deemed applicable for both Section A & Section B. Subcontractor will lay the pipeline in accordance to the conventional lay barge method of welding pipe joints on the barge and pulling the barge along the pipeline route after welding is completed at each welding station.

Automatic welding will be primarily be utilized for the pipelay. Refer to Document No. SR-TKM-WLD-GEN-01, Welding Procedure Specification for the various WPS qualified for the installation.

Installation Summary

Max. Water Depth	C2 : Section A Various from 0.2 m at OGT (KP 73.0) to 18 m at Mid Point Tie-In location (KP 66.0) : Section Be Various from 63 m at proposed MCR-A platform (KP 0.00) to 18 m at Mid Point Tie-In location (KP 66.0)
Pipelay Tension	: Section A Various from Min. 26 MT to Max. of 41 MT: Section B Various from Min. 41 MT to Max. of 137 MT
Stinger Tip Clearance to Seabed	: Section A Min. 2.59 m to Max 3.01 m: Section B Min. 3.01 m to Max 49.26 m

The following parameters will constantly be controlled and recorded during pipelay:

1. Elevation of stinger stern-most roller by air diver and onboard pneumo.
2. Pipelay tension.
3. Pipeline profile between stinger end to touchdown as observed by ROV.
4. Pipeline touchdown location as observed by ROV.
5. Gap between stinger back end roller to pipeline.

EQUIPMENT LIST AND PREPARATION

Prior to commencement of pipelay, all preparatory work for the installation will be completed. Equipment required will also be checked and verified for their operation.

MATERIAL AND EQUIPMENT LIST FOR PIPELAYING

The following materials and equipments are required for general pipelay of 26” Ø pipeline.

ITEM	DESCRIPTION	TOTAL QUANTITY	REMARKS
PIPELAYING EQUIPMENTS AND FIELD JOINT MATERIALS
1	26” Æ internal line-up clamp	2 nos.
2	7/8” Æ x 4000 ft length IWRC 6×19 galvanized extra improved wire rope for stop trolley	2 reel
3	1” ID x  1.25mm WT x 10ft length ea. of copper tubing	20 length
4	Field Joint Coating (Polyken Tape)	As required
5	Foam infill (HDPF)	As required
6	White paint (5 litre/can)	120 cans
7	Swabbing rabbit c/w brush to suit ID 625mm for internal cleaning	2 nos.
8	External line-up clamp to suit OD 660	2 nos.
9	Blow down cap c/w valve & fitting to suit 26” Æ pipe	1 no.
10	Buckle detector to suit ID 625 mm	2 nos.
11	Gauging plate OD 593.9 mm	4 nos.

 

WELDING AND QC EQUIPMENT
12	Welding machines	4 sets
13	Welding consumables	2 lot
14	NDT related equipment and consumable	1 lot
15	Holiday Detector (Refer Appendix 8 For Specification)	2 nos.
PIPE HANDLING
16	Spreader/monkey bar, size 3” dia. SCH 40 x 20 ft lgth pipe	2 nos.
17	Wire rope sling, size 1-1/4” dia. X 55 ft lgth, IWRC 6×36 ungalvanized w/2 ft soft eye and the other end w/5 ft soft eye, both mechanical spliced	4 length
18	Wire rope sling, size 1-1/4” dia. X 15 ft lgth, IWRC 6×36 ungalvanized w/2 ft soft eye, both mechanical spliced	4 length
19	Shackle, green pin bow shackle G-4163, WLL 8.5 MT	4 nos.
SURVEY / DIVING / ROV
20	ROV spread	1 lot
21	Survey spread c/w side scans, transponder etc	1 lot
22	Diving equipment	1 lot
GENERAL
23	General equipments and consumables related to pipelay activities	2 lot

 PREPARATION FOR PIPELAY
The following preparation prior to pipelay start-up will be performed:

1. Adjust barge and stinger roller heights according to engineering analysis Document No. SR-TKM-OPR- MCRA-OGT-P201, Pipelay and Weld Repair Analysis – 26’’ Gas Pipeline from MCR-A to OGT. The stinger roller height configuration for 26” pipelay from beach pull to mid line tie-in point (Section A pipeline)is the same as 2×12″ dia. NPS condensate export pipeline OGT to/from SPM and 12” condensate pipeline MCR-A to OGT and 4” MEG pipeline piggy back pipelay.Note:For the Section B pipeline, the stinger rollers height configurations are different from the Section A pipeline. Prior commence Section B pipeline DMA start-up at proposed MCR-A platform, the stinger shall be de-rigged and towed back to shore for stinger roller height adjustment. The height adjustment shall accordance to engineering analysis Document No. SR-TKM-OPR- MCRA-OGT-P201, Pipelay and Weld Repair Analysis – 26’’ Gas Pipeline from MCR-A to OGT.
2. Service and adjust tracks on pipe tensioning machines prior to start-up operation.
3. Check pipe rack and line-up station equipment is operational including buckle detector, X-ray crawler, stop trolley, internal line-up clamp.
4. Check stinger valves, control panel, video, underwater cameras, rollers and load cell are in working order.
5. Insert Bi-Di pig into start-up head.
6. Check the valve at the start-up head is closed and plugs are installed. Ensure compatible hose connections are available (for contingency).
7. Ensure materials and equipments for the field joint coating i.e. Polyken 980-SSJ-X and foam operations are readily available.
8. Check that the constant tension winch for laydown/abandonment of pipeline is operational.
9. Ensure sufficient quantity of white marine paint is available for marking joint.
10. Test all survey equipment of both pipelay barge and Anchor Handling Tug (AHT). Test and calibrate accordingly.
11. Test all NDT equipment i.e. NDT crawler, automatic processor etc. Ensure sufficient supplies of radiographic films, chemical, screen etc are available.
12. Set-up current meter at bow of pipelay to monitor change in current speed and direction during pipelay.

DETAILED PROCEDURE

The following subsections detail the procedures relevant to the pipelay operation.

BARGE RAMP AND STINGER DETAILS

Barge/Stinger Roller Height and Spacing

The 26” Æ pipelay will be carried out by Armada Installer with the barge and stinger roller heights set in accordance to Fig. 4.3.1-3 to 4.3.1-4 for both Section A & Section B.

Barge/Stinger Details

The installation engineering has assumed the following barge attitude for pipelay activities:

Fwd draught                  =          4.1 m (bow)

Aft draught                    =          4.1 m (stern)

Trim by Stern                 =          0 degree

Stinger                          =          50.5m Floating Stinger

Stinger Operation

The stinger ballasting operations will be controlled from the control panel located at the stern of the barge. The pipe will be monitored visually by the stinger technician/diving crew using a subsea camera mounted at the last stern rollers of the stinger. A closed-circuit TV will be made available in the diver shack and connected to the subsea camera. The elevation of the rollers shall be logged every 30 minutes of the pipe pull.

During pipelay operation, pipeline monitoring by diver and ROV shall be conducted at minimum frequency of three (3) times per shift. However, the frequency may be increased as required during critical situations or activities such as pipelay start-up and laydown operations.

The stinger-rollers elevation will be constantly monitored especially when the water depth changes by installing a depth gauge at the end of the stinger. The designed elevations for various water depths along the pipeline route shall follow those in the Procedure No. SR-TKM-OPR- MCRA-OGT-P201, Pipelay and Weld Repair Analysis – 26’’ Gas Pipeline from MCR-A to OGT.

PIPELAY BARGE ARRANGEMENT
The table below shows the details the activities that will be performed in each station of the pipe ramp on the barge during the 26” Æ pipelay. The pipe ramp is illustrated in Fig. 4.3.2-1.

Pipe Ramp Activity Arrangement (Automatic Welding)

STATION NO.	ACTIVITY
1	Root / Hot Pass / Fill #1 & #2 / Fill #3 & #4 / Capping, Visual Touch-up / Radiographic Inspection
2	Fill #1 & #2 / Fill #3 & #4 / Capping, Visual & Touch-up / Radiographic Inspection
3	Fill #3 & #4 / Capping, Visual & Touch-up / Radiographic Inspection
4	Capping, Visual and Touch-up
5	Radiographic Inspection / Repair
6	Radiographic Inspection / Repair
7	Polyken 980-SSJ-X Application
8	Field Joint Foam Infill

BARGE SET-UP

For barge anchor patterns, refer Fig. 3.2-2 & 5.3-1 for pipelay start-up at proposed MCR-A platform and laydown at proposed Mid Point Tie-In location respectively at Section A. For Section B the barge set-up is covered in Document No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull.

During normal pipelay, four (4) bow anchors will be run at a maximum of approximately 1200 m and minimum cable length paid out on the stern anchors is approximately 700 m. The total anchor wire length in the drum is about 1700 m.

For further details of the anchor handling procedure and anchor cable catenaries, please refer to Document No. SR-TKM-MRN-GEN-06, Anchor Handling Procedure.

PIPELAY VARIABLES

The pipelay engineering analysis recommendation of the optimum pipelay tension is shown in the following page, extracted from the Engineering Analysis Document No. SR-TKM-OPR- MCRA-OGT-P201, Pipelay and Weld Repair Analysis – 26’’ Gas Pipeline from MCR-A to OGT. Optimum stinger roller heights at stern for the entire pipelay route are also stipulated in the analysis.

Since the variation in tide is very minimal, the sensitivity analysis for water depth variation is not carried out. The pipelay analysis allows for the following variations from the optimum  whilst still maintaining a combined stress level below the allowable value.

• Barge tension of ± 10 MT for all the varying water depths
• ± 5% increase in submerged weight
• ± 0.5 deg. in barge trim
• 90 deg. beam sea current (1 year)
• Max & min stinger elevation

SURVEY & POSITIONING

Tolerance (According to PTS 20.120)

The pipeline will be laid along the routes defined in alignment sheets. The maximum deviation from alignment along the prescribed route shall be 15 m except within 450 m of the riser where the maximum allowable deviation shall be reduced as follows:
i) From 450 m to 150 m from riser – tapering from 15 m to 3 m
ii) Within 150 m from riser – 3 m
iii) At pipeline/riser interface the deviation shall be sufficiently small to allow installation in the riser clamps without introducing bending stresses in the riser

Where the pipeline is installed adjacent to an existing pipeline a minimum separation of 15 meters shall be maintained, except at the platform approach.

During critical lay at curvatures, ROV will monitor pipeline location to monitor pipeline location ensuring the pipeline within +/- 15 m tolerance. Refer Appendix 9 for the 26’’ Æ pipelay route curvature.

Pre-Survey

The pre-installation route survey for the 26” Æ pipeline will be carried out prior to pipelay. Refer to Document No. SR-TKM-OPR-GEN-01, Pre-Installation Survey Procedure for Proposed Pipeline and SPM/PLEM.

Barge Positioning
Barge will be positioned primarily using navigation DGPS Positioning Systems. The systems use multiple onshore reference DGPS station to determine pseudo range data link. The DGPS

positioning system will be available onboard as a back-up system if required and to provide constant online QA/QC checks against the navigation DGPS Positioning Systems.

Anchor Handling Tug Positioning
The anchor handling vessels will be using the Barge Management System (BMS) controlled from barge as their positioning system. The system works in conjunction with the Tug Management System installed on both anchor handling tugs. The tug’s position will be continually transmitted to the barge via UHF radio link. On the BMS monitor the outline of each tug is shown in a different colour for easy identification. During anchor running, the Surveyor on duty will enter the coordinates of the proposed anchor position into the BMS system. A printout of the target position will be automatically generated and the position will be transmitted by telemetry link to the selected Tug Management System on the Tug.

Pipeline Positioning / Survey
A software package will be used as the online computer navigation system provided by Veripos, which is interfaced with 1 x Inmarsat DGPS as Primary through High Power Spot Beam 109E and 1 x Secondary DGPS through High Power IOR. For positioning of pipeline start-up and laydown, the ultra-short baseline (USBL) beacon will be mounted on the ROV which will be tracked using a USBL Transceiver which will be installed on the over the side pole mounting and a long deck cable is used to connect to the top side unit in the barge bridge. Control will be interfaced to the surface navigation system. All subsea pipeline/cable positioning will be carried out using the USBL system and the ROV.

As-Laid Survey
The as-laid side-scan survey of the 26” Æ pipeline will be carried out by SUBCONTRACTOR. This will be completed to determine the free span locations. The details of allowable free spans are shown in COMPANY’s approved for construction pipeline alignment sheets.

LINEPIPE HANDLING

The sling arrangements for lifting of the linepipes from the material barge onto the deck of derrick lay barge and from the deck into the transfer station are shown in Fig. 4.3.6-1. Use average pipe length = 12.2m. Linepipe joint unit weights are as follows:

PIPE DESCRIPTION	CONCRETE COATING THICKNESS/DENSITY	EMPTY WEIGHT IN AIR (MT)	EMPTY WEIGHT IN WATER (MT)
660mm OD x 17.5mm WT x 5.5 AE	125mm / 3,040kg/m3	15.151	6.806
660mm OD x 17.5mm WT x 5.5 AE	105mm / 3,040kg/m3	13.052	5.417
660mm OD x 17.5mm WT x 5.5 AE	90mm / 3,040kg/m3	11.540	4.415
660mm OD x 17.5mm WT x 5.5 AE	80mm / 3,040kg/m3	10.560	3.766
660mm OD x 17.5mm WT x 5.5 AE	75mm / 3,040kg/m3	10.078	3.447
660mm OD x 17.5mm WT x 5.5 AE	65mm / 3,040kg/m3	9.133	2.822
660mm OD x 17.5mm WT x 5.5 AE	50mm / 3,040kg/m3	7.760	1.913

LINEPIPE PREPARATION 

Followings are activities to be carried out for each pipe joint before reaching the line-up station:

• Bevel/end-prep the joint ends to J-bevel using 26’’ Æ pipe facing machines prior to transferring into ready rack. Refer to Appendix 10 for bevel requirement.
• Prepare the ready rack with the appropriate pipe joints. The linepipe description (i.e. anode, plain, colour code etc) for each joint number assignment is given in Table 1.2.1 & Table 1.2.4. The input i.e. pipes in the table will be updated continuously depending on the exact pipe length and the actual measured KP by surveyor.
• Register the pipe joint number, plain/anode and length in the standard pipe tally sheets for daily submission to COMPANY. Refer to Fig. 4.3.7-1 for pipe tally sheet pro-forma.
• Pre-heat both ends of the pipe joint when pipe enters the line-up station.
• Paint the sequential joint number onto each pipe. The number needs to be painted on the “bow” end of each pipe joint in the 10 o’clock and 2 o’clock positions with white quick drying marine paint.

WELDING / NDT / WELD REPAIR

Welding, NDT and weld repair procedures have been prepared in accordance to COMPANY Specification, Pipeline Welding and Inspection. Details of the welding, NDT, repair and field joint coating activities at each station are summarized in Section 4.3.2 table. The drawings for internal pipeline equipment are shown in Fig. 4.3.8-1 to 4.3.8-6. The cut back requirement for the auto welding machine is shown in Fig. 4.3.8-7.

WELDING

Pipeline Welding Procedures can be found in Document No. SR-TKM-WLD-GEN-01, Welding Procedure Specification.

An internal line-up clamp will be used to align and fix the pipe for the root and hot pass in weld Station No.1 or otherwise known as beadstall. Note that the linepipe is seamed pipe and at the ends of each joint will be re-beveled outside the ready rack prior to transfer to the beadstall.

NDT

All pipeline welds shall be subjected to 100% radiographic inspection which will be carried out in Station No.5 or 6. Station No. 1 to 4 will be used as an optional radiographic inspection station if required. SUBCONTRACTOR will carry-out a mock-up on the barge to verify the quality of the film and measure radiation level prior to pipelaying. Project specific pipeline NDT procedure are detailed in Document No. SR-TKM-NDT-GEN-06, Provision of General NDT Procedure for Pipeline (26” OD/12” OD/4” Piggyback).

An internal X-ray crawler will be utilized to obtain radiographic image of every field joint weldment. The X-ray crawler arrangement for the 26’’ Æ pipeline is shown in Fig. 4.3.8-3. Re-shoot needs to be carried if the quality and density of the film does not meet the specification requirement. The film will be developed and image interpreted by radiograph interpreters.

Precautions as listed below will be implemented to reduce risk of personnel exposure to radiation (on the derrick barge and adjacent materials barges/vessels).

1. Adherence to warning signs – only authorized personnel shall be in the immediate radiograph location.
2. Whilst the radiograph warning light is flashing, all personnel are keep out of the area.
3. A safe distance from the radiograph station will be pre-determine and fenced off.
4. For radiograph inspection outside of the dedicated station (i.e. for weld repair situations), the following steps will be taken:
   i) A moveable “dog house” lead shield shall be placed over the immediate radiograph The lead shield shall prevent radiation exposure above and from the sides of the shield.
   ii) Shielding shall be placed upon the floor to protect those below.
   iii) Radiation survey meters shall be used to ensure the operation is not exposing   personnel to radiation.
5. Audible signals are also provided to warn personnel.

WELD REPAIR

Weld repair will be carried out subject to approval in conjunction with Doc. No. PTS 20.120 by COMPANY, The weld acceptance criteria shall be in accordance to API 1104 Section 6.

Weld repair length calculations are as per engineering calculation for weld repairs at Station No. 5 and 6 on the barge. The maximum gouge lengths for both stations are as specified in the above document. Weld repair will be carried out manually using SMAW process. Refer to Section 4.4 for extract from Document No. SR-TKM-OPR-MCRA-OGT-P201, Pipelay and Weld Repair Analysis – 26’’ Gas Pipeline from MCR-A to OGT.

BUCKLE DETECTION

A buckle detector assembly will be positioned at a minimum of 4 joints past the furthest touchdown point. This assembly will provide a mean of identifying any deformity occurring in the pipe string after the string has left the lay barge.

The buckle detector system set-up will consist of the following components:

• One buckle detector system completes with 6mm thk. aluminium gauging plate.
• 7/8” OD x 4000 ft lgth (inclusive 100% back up) wire cable
• 1” ID x 0.049” WT x 10 ft lgth copper tubbing (20 nos. inclusive 100% back up)
• X-ray stop trolley
• 26” Æ internal line-up clamp
• 5 MT air tugger
• 5 MT Load cell with gauge readout

The X-ray stop trolley will be attached to the 7/8” dia. cable between Station 7 & 8. A 7/8” dia. cable connected to the end of the line-up clamp reach rod and terminating at an air tugger located on the bow completes the assembly.

Refer to Fig. 4.3.8-1 & 4.3.8-2 for the proposed assembly of a 26” Æ buckle detector. Gauging plate will be fixed at 593.9 mm diameter which is based on the DnV 1981 rule:

Ø          =          (D – 2t) – 0.01D – 0.4t – 5P

Where

D          =          Nominal OD of pipe (660 mm)

t           =          Wall thickness of pipe (17.5 mm)

P          =          0.2t or 5 mm whichever is smaller

The insertion of buckle detector inside the pipes will be easier when more joints are on the seabed such that the back pressure inside the pipeline being laid is minimized. When the pipe joint No. 93 or more at the beadstall, buckle detector shall be deployed by blowing down. The deployment will be carried by means of a pneumatic system (blow down cap) incorporated in the assembly. An air hose will be pre-attached to the blowdown cap to supply pressurised air so that the buckle detector can be blown down along the pipeline profile and moves toward touchdown. With each pull of the pipeline, the wire cable will pay out one joint length of cable. Once all cable is paid out, the buckle detector assembly will be pulled forward using air tugger at the bow of the barge. Refer to Fig. 4.3.9-1 for blow down cap assembly.

The buckle detector assembly will operate typically as follows:

1. When welding has been completed at all stations along the mainline, the cable from the air tugger to the reach rod will be disconnected and the barge move ahead 12.2m.
2. The next joint will be transferred from the ready rack to the line-up station. The air tugger line will then be pulled through the new joint and connected to the line-up clamp reach rod.
3. The air tugger will commence to haul in the cable, the line-up clamp and buckle detector assembly, which will travel up along the pipe string towards the beadstall (Station No.1).
4. The load on the buckle detector assembly, indicated by a gauge mounted on the air tugger will be recorded for each corresponding joint number during each pull.
5. Any excessive deviations from the average pull force being recorded will initiate the alarm on the load cell. An immediate investigation will be carried out to ascertain the cause
6. The line-up clamp will be activated and welding commenced.

Fig. 4.3.8-1 to 4.3.8-6 shows the details of internal pipeline equipments, arrangement, cable make-up and installation process.

The buckle detector assembly will be removed prior to pipe laydown. The buckle detector will be monitored from the tension gauge for every each pipe pull.

FIELD JOINT COATING

The field joint coating will be applied in two field joint stations namely Station No. 7 and 8 (if required) after the field welds have been radiographed and visually inspected. The field joint area will be wrapped with cold application coating Polyken 980-SSJ-X and field joint foam infill. The field joint coating is detailed further in Document No. SR-TKM-OPR-GEN-10, Field Joint Coating, Infill and Coating Repair Procedure.

The first portion of the field joint coating system i.e. Polyken 980-SSJ-X will be carried out in Station No.7 and 8 (if required). The second portion of the field joint coating system i.e. foam infill will be carried out in Station No.8.

Similar application system will be utilized for repair of existing corrosion and concrete coating. If damage on the yard corrosion coating is outside the coverage of the Polyken 980-SSJ-X, an addition 150 mm wide strip will be wrapped around the affected area.

POLYKEN 980-SSJ-X APPLICATION

Primer will not be required with the Polyken 980-SSJ-X proposed for the pipelines temperature ranges when they are utilized on concrete weight coated lines under a joint filling material. The following procedure will be adopted for the application.

1. As specified in the Polyken 980-SSJ-X Datasheet, total weld area, including exposed corrosion coat will be power-wire brushed to remove all rust, weld spatter, insecure mill scale, dirt, dust and other deleterious matter and to be cleaned and dry.
2. The application of Polyken 980-SSJ-X as follows (and also shown in Fig. 4.3.10-1).
   – 450 mm wide Polyken 980-SSJ-X, cold applied pipe wrap, will be applied in a single continuous layer, cigarette wrap, centering on the line of the weld.
   – 150 mm wide strips will be applied in a single continuous layer, cigarette wrap, one at each extremity of the 450 mm wide Polyken 980-SSJ-X pipe wrap, overlapping the corrosion coating by 10 mm.
3. For all cigarettes – wrap method, application should be with a minimum of 50 mm overlap.
4. Application of Polyken 980-SSJ-X will take place on a clean, dry, firm surface, employing sufficient hand tension to assure a smooth, wrinkle free application.
5. After application, the surface will be holiday tested using Holiday Detector with circle spring electrode capable of measuring at up to 30 kV for Polyken 980-SSJ-X to check integrity between the pipe surface and Polyken 980-SSJ-X. If holiday is detected, the Polyken 980-SSJ-X will be removed and steps 1 to 5 repeated.

FOAM INFILL ADDITION

Foam infill shall be High Density Polyurethane Foam (Sethane F 160M).

The foam shall be applied as a one part system to an O.D equal to the O.D of the concrete weight coating after application of the field joint corrosion coating. Refer to Fig. 4.3.10-2 & Fig. 4.3.10-3 for details.

Galvanized sheet (1200 mm x 3200 mm) shall be wrapped over the entire field joint area and extend onto the plant-applied, concrete coating by 200 mm on each side. This form shall be securely mild steel strapped or banded (0.6 mm THK & 19 mm wide) at each end over the concrete coating. To use the form, an opening at the top of the form shall be utilized to fill joint with foam. After filling the mould, the opening will be strapped shut.

The following pages are Technical Data Sheet and MSDS of Polyken 980-SSJ-X and  Sethane F 160M.

PIPELAY DURING TRANSITION

During the 26’’ Æ pipelay there will be several pipe transition (different concrete thickness) ranging from 50 mm to 125 mm. Stinger and tensioner need to be adjusted accordingly. Refer Document No. SR-TKM-OPR-MCRA-OGT-P201, Pipelay and Weld Repair Analysis – 26’’ Gas Pipeline from MCR-A to OGT.

PIPELINE LAYDOWN / ABANDONMENT AND RECOVERY

GENERAL

The following laydown procedures will be used at the end of the Section A & Section B pipelay where the laydown target box is pre-determined at KP 66.0 at proposed pipeline Mid-Point tie-in location.  However, the exact KP shall be confirmed with Surveyor based on real time final position. The laydown/abandonment and recovery procedures will also be used if it is required to suspend the pipelay operations due to some unforeseen circumstances such as bad weather.

Safety Note:

All non-related personnel to stay clear of pipe tunnel during laydown/abandonment operation.

EQUIPMENT LIST AND PREPARATION

The following items are required in Table A for pipeline laydown. Table B gives the check list for the start-up head.

ITEM	DESCRIPTION	TOTAL QUANTITY
1	Shackle, 150MT Green Pin Standard Shackles P-6036 bow type with safety bolt.	2 ea
2	26” OD (660mm) laydown head, welded type	2 nos
3	Underwater video camera mounted end of stinger	1 set
4	Strip out block to suit laydown winch cable (if required)	1 set
5	Wire rope sling, size 2 inch dia. x 20 ft length, IWRC 6×36 EIPS ungalvanized w/ 2ft soft eye both end mechanical spliced (for sacrificial sling)	2 nos.
6	180MT Capacity of A&R Winch c/w 76mm (3”) dia. x 1,100 m length cable	1 unit
7	ROV c/w hydraulic cutting arm (Max. wire 3’’ Æ size)	1 unit
8	White  Paint (5 liter/Can)	10 cans
9	Brocco cutting equipment	1 set

 

SR. NO.	ACTIVITY	STATUS	CHECKED BY (SUBCONTRACTOR)	CHECKED BY (CONTRACTOR/ COMPANY)
1.	Check pull head dimension as per drawing
2.	Carry out MPI on all WELDS
3.	Check the valve location
4.	Check the condition of valves Status(open/close)
5.	Check the Two Bi-di Pigs
6.	Gauge Plate signed by all parties
7.	Location of pig with gauging plate at the end of pull head.
8.	Leak test completed (7 bar)

LAYDOWN PROCEDURE

The following steps will be carried out for laydown of the pipeline. Refer to Fig. 5.3-1 for the pipeline laydown anchor pattern at Section A and Section B:

1. As the lay barge approaches target laydown KP and coordinates (to be confirmed with Surveyor), prepare the rigging for pipeline laydown. Refer to Fig. 5.3-3 & Fig. 5.3-4 for pipeline laydown rigging arrangement at Section A & Section B. The water depth at the proposed laydown KP is approximately 11 In case of laydown at deeper water depth, the buoyancy tanks may be required for Mid Point Tie-In (Refer to Document No. SR-TKM-ENG-MCRA-OGT-P208, 26’’ Inch MCR-A/OGT Mid-Point Tie-In Procedure).
2. Weld the laydown head to the last joint of the pipeline and complete all X-ray of the remaining field joints at their respective station.
3. Recover the followings from inside of the pipeline:
   i) Internal Clamp
   ii) X-Ray Crawler
   iii) Stop Trolley
   iv) Buckle Detector
4. Paint (white) the laydown head and weld the laydown head to the last joint of the pipeline. The laydown head is illustrated in Fig. 5.3-5 & Fig. 5.3-6 for Section A & Section B.
5. Install the rigging for the multiple davits lift. These choker slings arrangement are for the future multiple davits lift during for the Mid-Point tie-in. Refer to Fig. 5.3-7 & Fig. 5.3-8 for the choker slings arrangement for Section A & Section B.
6. Connect the end of the A&R cable to the laydown head via a sacrificial sling with one (1) no. of 150 MT shackles. The sacrificial sling will be painted white for easy identification by ROV to cut the cable.
7. Install the remaining rigging for the multiple davit lift on their respective location as per Fig. 5.3-7 & Fig. 5.3-8 for Section A & Section B.
8. Pull the barge until the laydown head just entering the forward tensioner. Gradually transfer the tension to the 3” dia. A&R cable.
9. Continue pull the barge ahead until the laydown head is at the aft tensioner. Gradually transfer all the tension to the 3” dia. A&R cable. At this stage both tensioner shoes are free from pipeline.
10. Continue advancing the barge forward until the laydown head is at the stern of the barge.
11. Deploy ROV to monitor the laydown head. The pipelay tension is maintained at as per Section 5.6. ROV may be used as an additional aid in providing visual of the laydown head.
12. De-ballast the stinger to meet the required back-end roller elevation as per data from Field Data Book while laying down.
13. Continue advancing the barge until the laydown head past the stinger stern. This is indicated when the first mark is at the stern of the barge. ROV will provide the visual on the laydown head.
14. Gradually reduced the tension on the 3” dia. A&R cable and let the laydown head settle on the seabed.
15. Back up the barge for about 20m to provide slack on the A&R cable. The actual distance will be determined at site.
16. ROV to take fix on the laydown head and next of minimum 5 nos. field joints for the future Mid-Point tie-in at KP 66.0.
17. ROV will locate the sacrificial sling and cut the sling using hydraulic cutting arm (The ROV hydraulic cutting arm to be functioned tested prior ROV mobilization and deployment). Another alternative is to use shallow team saturation diver or air diver to disconnect the sling or cut by brocco rod.

ABANDONMENT PROCEDURE

The abandonment procedure shall be executed under circumstances such as bad weather or pipe buckle. The steps for abandonment procedure are the same as laydown procedure. However there are a few exceptions as listed below:

1. The choker sling will not be installed on the pipeline.
2. USBL beacon will not be installed on the pipeline.
3. Emergency laydown head with pre-installed market buoy will be used. Refer to Fig. 5.4-1 for details of the emergency laydown head.
4. The sacrificial sling connected from A&R cable end (A&R sheave at Station No. 2) to the emergency laydown head may not be cut. The barge will back up to provide slack on the cable. However this will be determined based on site condition.
5. If the need arises to cut the sacrificial sling, the marker buoy will be used as a marking for the emergency laydown head.
   Note: In the event of abandonment, the pipeline has to be completely laid down to the seabed and not to be suspended midway.

RECOVERY

The following steps will be carried out if it is necessary to recover a pipeline and recommence pipelay. The recovery is essentially the reverse of the abandonment procedure:

1. The barge will be positioned so that the stern of the barge is at laydown head location.
2. Pay out the A&R cable (complete with spelter socket) towards stern (A&R sheave at Station No. 2) and lower it down to seabed.
3. Position the A&R cable to the stinger with the assistance of snatch block and/or air tuggers and continue lower it down to seabed. ROV to monitor this exercise.
4. Deploy diver to connect the A&R cable to laydown head on the seabed.
5. Ballast the stinger as required with reference to extracts from engineering analysis Document No. SR-TKM-OPR- MCRA-OGT-P201, Pipelay and Weld Repair Analysis – 26’’ Gas Pipeline from MCR-A to OGT.
6. Back up the barge and gradually increase the pipelay tension as per Section 5.6.
7. Maintain the pipelay tension and the stinger back-end roller elevation as per Section 5.6.
8. Activate the aft tensioner when the laydown head just passed the aft tensioner. Maintain the tension as per Section 5.6. Do not reduce the tension in the A&R cable.
9. Continue backing up the barge until the laydown head passed the forward tensioner. Activate the tensioner. Gradually reduced the tension on the A&R cable.
10. Dismantle all the rigging on the laydown head. Cut the laydown head and perform necessary NDT inspection.
11. ROV will be deployed during the operation to provide visual display pipeline profile. Refer to Fig 5.4-2 for details on the recovery operation.
    Note: ROV will be deployed during the operation to provide visual display pipeline profile. Refer to Fig. 5.4-2 for details on the recovery operation.

CONTINGENCY PROCEDURE – PIPELINE BUCKLE

GENERAL

During pipelaying, abandonment or recovery of a pipeline, it is possible that the pipeline could buckle if there is a loss of tension in the pipeline or incorrect pipeline profile control.

The following contingency procedures detail the steps to be adhered to for:

1. Minor Dry Buckle
2. Severe Dry Buckle
3. Wet Buckle

EQUIPMENT LIST AND PREPARATION

In addition to the equipment/materials for abandonment and recovery as detailed in Section 5, the following Table 6.2-1 will also need to be available in case a buckle occurs.

ITEM	DESCRIPTION	QUANTITY
1	Stopper pin (1-1/4” dia. X 650mm lg.) to stop/trap when dewatering line to suit 26” OD pipeline.	2 nos.
2	Underwater cutting and equipment	1 lot
3	Compressor (650cfm/115-190 psig)	1 no.
4	Air hose (4” dia.) for 65m working depth c/w flange end	1 lot
5	4’’ hex nipple	1 no.
6	Marker buoy c/w pennant wire	1 no.

MINOR DRY BUCKLE

In the event a pipeline buckle is suspected, the following steps will be taken:

1. Cease all barge movement and pipelay.
2. Notify Superintendent, Field Engineers and COMPANY Representative immediately.
3. Observe the open end of the pipeline for any exhaust of air. Pipeline profile will be observed to note any profile change from normal profile.
4. ROV inspects to confirm whether the buckle is dry or wet, minor or severe. ROV should survey pipeline from stinger to buckle detector location to ensure no other buckles have occurred.

A decision will be taken if the buckled section as surveyed can pass through the tension machine and support the recovery tension without causing further damage to the pipeline. If pipeline is able to pass through the tension machine proceed with Step 5. If not, the buckle is classified as major and further steps should be taken as outlined in Section 6.1.4.

5. Meanwhile, remove internal line-up clamp and x-ray crawler from inside the pipeline.
6. Under the direction of the Superintendent, commence moving the barge astern along the pipeline route while maintaining constant tension in the tension machine.
7. Cease barge movement when a welded joint is at the line-up station.
8. Cut out the weld and remove the pipe joint.
9. Resume backing the barge astern until the next welded joint is at the line-up station. Remove the pipe joint as before.
10. Continue backing the barge astern and remove pipe joints until the buckled joint(s) is at the stern tension machine.
11. Inspect the buckled section thoroughly to ascertain feasibility of proceeding through the tension machine.
12. If it is assessed that no further damage to the pipeline will occur by passing the buckled portion of the line through the tension machine tracks, the barge will continue to back up until the buckled section of pipe is at the line-up station. Then proceed as per Step 18.
13. Cease all cutting of line pipe. If the buckled portion cannot safely pass through the tension machine.
14. Weld the laydown head to the end of the pipeline and attach the laydown cable. Apply tension to the cable until it is equivalent to the tension in the tension machine. Concurrently, lower the load on the tensioner in order not to exceed the current and recovery tension being applied.
15. Raise tension machines jaws and recover the pipe using the recovery procedure detailed previously.
16. Cease barge movement when the buckled portion is at the line-up station.
17. Lower tension machine jaws onto the pipe and set the machine at the required lay tension. Disconnect the laydown cable.
18. Remove the buckled section. Meanwhile, re-bevel the end of the pipeline and perform NDT.
19. Re-deploy the x-ray stop trolley, the x-ray crawler and the internal line-up clamp inside the pipeline.
20. Recommence normal pipelaying operations only after determining the reason for the buckle and taking corrective steps.
    Note : If the buckle occurred at the weldment, then a ring shall be cut to preserve the weld for further inspection and underwriter review

SEVERE DRY BUCKLE

1. If the buckle is still dry but severe, weld the lay down pull head to the pipeline.
2. Shackle the laydown cable to the laydown head with 1 each 150 MT shackle and perform abandonment procedure as outlined in Section 5.4.
3. Re-position the barge alongside the pipeline for a standard davit lifts. However, site assessment to be made between COMPAY Representative, Superintendent and Field Engineers whether a single lift or multiple davits lifts to be exercised.
4. Attach davit lines to the pipeline and perform a multiple davit lift as detailed in Engineering Analysis, Document No. SR-TKM-OPR- MCRA-OGT-P201, Pipelay and Weld Repair Analysis – 26’’ Gas Pipeline from MCR-A to OGT.
5. Maintaining the pipeline profile, remove successive pipe joints to the buckled joint.
6. Remove the buckled joint and weld the laydown head to the pipeline. Tie one end of a length of 1” dia. rope to the laydown head and the other end to a marker buoy. Lower line to seabed and disconnect all rigging.
7. Re-position the barge for recovery of the pipeline.
8. Pay out the recovery line with 1 each 150 MT shackle.
9. Shackle the recovery line to the laydown head, remove the marker line and perform recovery process as detailed in Section 5.5.
10. Once the laydown head reaches the beadstall, it will be removed and the pipeline re-bevelled.
11. Resume pipe laying operation.

Note: If the severe dry buckle occurs, a significant distance from the barge such that a multiple davit lift is not possible (i.e. buckle in the sag bend region), then the pipeline will be flooded and the wet buckle procedure (Case B) followed.

WET BUCKLE

This refers to a pipeline buckle where the pipeline has been flooded with seawater. The wet buckle repair procedure is outlined as follows:

1. Cease all barge movement and pipelay operation.
2. Superintendent, Field Engineers and CONTRACTOR Representatives notified immediately.
3. Deploy divers/ROV to inspect pipeline from end of stinger to touch down point on seabed.
4. Determine location and type of buckle, namely:
   Case A – Pipeline buckled but not broken off
   Case B – Pipeline buckled, broken off and lying on seabed
5. Remove internal line-up clamp and x-ray crawler from inside the pipeline, (and x-ray stop trolley, if possible).
6. Under the direction of the Superintendent, commence moving the barge astern whilst simultaneously retrieving as many joints as possible up through the stern ramp. Cut out the joints and remove from the tunnel.

Case A

1. Retrieve pipe until in the opinion of the Superintendent, it is not safe to bring the buckle up the stinger.
2. Fit and weld the emergency laydown head onto the end of the pipeline. Meanwhile, shackle the lay down cable to the lay down head.
3. Upon completion of welding, abandon the pipeline using the Abandonment Procedure detailed in Section 5.
4. Proceed to step b) of Case B.

Case B

1. Retrieve all pipes in the stinger.
2. Reposition lay barge for a multiply davit lift of pipeline. Refer to Field Data Book (FDB).
3. Deploy the diver with cutting equipment to cut out all the buckled section.
4. Diver will attach rigging around the pipeline as per the wet multiple davit lift procedure detailed in the FDB and secure to the side of barge.
5. Recover the pipeline using the wet multiple davit lift procedure as detailed in FDB.
6. Re-cut and re-bevel the end of the pipeline on surface.
7. Weld laydown head complete with dewatering pig inside to the pipeline and attach a marker buoy using of 1” dia. rope.
8. Lower pipeline to the seabed using the reverse of the wet multiple davit lift procedure and disconnect lowering cables.
9. Diver to connect air hose to the laydown head and commence dewatering the pipeline.
10. Disconnect the air hose and close valve inlet.
11. Pay out the recovery line with 1ea x 150 MT shackles at the end.
12. Diver to shackle recovery line to the laydown head and detach marker buoy pennant line. Position recovery line in the stinger.
13. Perform recovery of pipeline as per Section 5.
14. Removed laydown head once reaches bead stall and re-beveled pipeline.
15. Resume pipelaying operation, only after determining the reason for the buckle and taking corrective steps.

12″ CONDENSATE  PIPELINE MCR-A TO OGT and 4″ MEG PIPELINE PIGGY BACK

DESCRIPTION OF PIPELINES

The proposed 12″ 0 condensate and 4″0 MEG pipelines will be laid as follows:

73km x 12″0  condensate with 4″0 piggy-back pipeline from OGT to MCR-A platform. Approximate number of joints to be laid is, 5984 joints for 12″ pipeline and 5,984 joint for 4″ pipeline. This is based on 12.2m average length.

Table 1.2-1A & Bon the following page give a summary of the pipelines sequence and Table 1.2-2A & B shows the detail sequence.

SCOPE I SEQUENCE OF WORK

Pipelines installation involves a 73.103km x  12″0 condensate with 73.113km x 4″0 piggy-back pipelines. SUBCONTRACTOR scope and work sequences are as follows:

• Transport linepipes and other appurtenances (under separate procedure).
• Start-up with beach pull method to proposed OGT shore. Refer to Doc. No. SR-TKM-OPR-GEN-08, General Procedure for Shore Approach and Beach Pull.
• Total joint of linepipes to be installed for each pipeline approximately 5984 joints.
• Lay pipelines approximately 368 joints for 12″ pipeline from KP 72.987 to KP 68.500 while for    1\ 4″ pipeline approximately 361 joints from KP 72.995 for 4″ until KP 68.500. Laydown head for 4″ pipeline will be installed at 7 joints earlier than 12″ pipeline, due to recovery purpose.
• 12″ + 4″ pipeline will be recovered and continue laying and laydown at MCR-A after 26″  1\ pipeline beach pull completed till KP 69.000.
• Lay down pipelines in designated target  5.0 m (lateral) x 5.0 m (longitudinal) at proposed location (KP 0.00).
  Note: Separation between 12″ + 4″ Piggy-Back and Pipeline 26″ is 5.0m starting at KP 64.0 while separation   between 12″ (Out-Going to SPM) also 5.0m start at KP 70.0 till to shore approach.
• Perform post-lay survey on  the  newly  laid  12″  dia.  with  piggy  backed  4″0  pipelines, determine free span locations and rectify. (Refer to Doc. No. SR-TKM-OPR-GEN-03,  Post­ Installation Survey Procedure for Proposed Pipelines and SPM/PLEM.)
• Free span rectification works shall be performed using grout bags before flooding the pipeline prior to straight spool installation.
• Flooding the pipelines prior to straight spools installation (under separate procedure).
• Install straight spool installation at MCR-A  (upon completion of MCR-A installation by others). (Refer to Doc. No. SR-TKM-OPR-GEN-07, Subsea Spool Installation Procedure.)
• Installation  of   Flexmat  Anchors.   (Refer   to   Doc.   No.  SR-TKM·OPR-GEN-09,   Grout   Bags Installation and Span Correction General  Procedure.)
• Installation of Grout Bag and Concrete mattress – platform approach. (Refer to Doc. No. SR­ TKM-OPR-GEN-09, Grout Bags Installation and Span Correction General Procedure.)
• Perform pre-commissioning works on the newly 12″ dia. and 4″ dia. Pipelines (under separate procedure).
• Provision of as-built documentation.

The final sequence of pipelay may be revised as required to suit the agreed offshore installation schedule with COMPANY.

Note: All KP’s provided herein this document are approximate. For latest KP’s and coordinates, please refer to the latest AFC drawings. Do not base solely on the data provided in this procedure

INSTALLATION SUMMARY

Proposed Start Point Coordinate 12″ P/L at OGT                  E  650702.63 N 4449721.71

Proposed End Point Coordinate 12″ P/L at MCR-A               E  603528.74 N 4397182.56

Proposed Start Point Coordinate 4″ P/L at OGT                     E 650707.43 N 4449721.27

Proposed End Point Coordinate 4″ P/L at MCR-A                 E 603518.88 N 4397172.17

Tie-In Spools at MCR-A                                                               60.2m  water  depth

Tension During Pipelay                                                                Start-up Tension 245 kN. Normal Tension 845 kN (max).

Stinger Tip Clearance to Seabed                                                 varies (water depth 1O.Om to 62.0m)

Note: All coordinate are in meter unless otherwise noted.

LOADOUT AND TRANSPORTATION

GENERAL

The linepipes will be transferred to Turkmenistan  Block-1  Gas  Development  Field  using  200ft class and 270ft class barge.

Upon completion of each load out, the tie down and sea fastening will be carried out to the satisfaction of COMPANY and the appointed third party surveyors.

Refer to Document No. : SR-TKM-ENG-MCRA-OGT-P100, Line pipe Transportation Study – 12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked.

PRE-LOADOUT

Prior to loadout from the storage yard, inspection list included in Document No. : SR-TKM-ENG­ MCRA-OGT-P106- Loadout Coordination Manual for 12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked, will be reviewed and completed. Any areas of potential concern will be highlighted to COMPANY. The load-out is also detailed in the above document.

Particular attention will be given to:

• End condition of line pipe.
• Condition of line-pipe coating.
• Line-pipe magnetic properties.
• Concrete and anti-corrosion coat cutback.

LOADOUT AND TRANSPORTATION

Loadout list for the line-pipes barge for 12″ dia. condensate pipeline MCR-A to OGT is shown in the Document No. : “SR-TKM-ENG-MCRA-OGT-P106 – Loadout Coordination Manual for 12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked.”. General arrangement and sea fastening details for load out of the pipeline and miscellaneous items are also included in the above report.

A detailed review of all components and material loadout will be conducted and checked against the loadout list as described in the Load out Coordination Manual.  Any  discrepancies  in  the quantity and conditions of the pipelines will be highlighted to COMPANY representative  and recorded prior to transfer of custody of the transportation barge to SUBCONTRACTOR. A load-out and tie-down arrangements of linepipe bays on the transportation barge are shown in Fig. 2.3-01 and Fig. 2.3-02 respectively. The tie-down  and  load-out  arrangements  for  the  subsequent voyages are detailed further in Document No. “SR·TKM-ENG-MCRA-OGT-P106 –  Loadout Coordination Manual for 12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked”.

Prior to departure of each transportation barge from the respective loadout location, a three (3) day weather outlook will be obtained from the Meteorological Service and forwarded to the tug boat captain (master) for his further action. Shelter and safe tow route shall also be identified and briefed to the tug master by Marine Captain.

START-UP PROCEDURE

GENERAL

The 12″ Dia. Condensate with 4″ MEG Piggyback will be started-up utilizing the conventional beach pull method at the OGT shore, with the laybarge  position approximately  400m from landfall point (approx. at KP 72.551 ).

The beach pull operation for 12″ Dia. Condensate with 4″ MEG Piggyback are covered in detail under Doc. No. SR-TKM-OPR-GEN-08 “General Procedure for Shore Approach and Beach Pull”. Barge will start normal pipe-lay mode approximately after joint no. 33.

BARGE SET-UP AND ANCHOR PATTERN

The proposed barge approach for set-up anchor patterns for linepipe start-up and pipelay for 12″ Dia. Pipeline is shown in Fig. 3.2-1.

Note: This  is for  information  only  as  actual details  will  be obtained  from  General  Procedure for Shore Approach and Beach Pull, Doc. No.SR- TKM-OPR-GEN-08.

PREPARATION AND  EQUIPMENT LIST

After the barge stern has been relocated at 400m  approx. from landfall tie-in point and the position confirmed by surveyors, the following preparatory works for the beach pull and pipelay operation will be completed.

This section covers the preparation required primarily for linepipe start-up:

1. Carry out preparation as detailed in Section 2.1.
2. Fabricate and prepare start-up head for 12″ 0 Pipeline and 4″. Refer to Fig. 3.3-1 and Fig. 3.3-2 for 12″ and 4″ start-up head respectively.
3. Check pipe tunnel, equipment and facilities at all stations, operational and in safe
4. Check pipe rack and line-up station equipment including buckle detector, load cell/gauge, X­ ray crawler, stop trolley, internal line-up clamp and beveling
5. Inspect tension machine, set its dead bands and set appropriate tension
6. Set roller heights as per Engineering
7. Inspect stinger,  set  the  required  roller  height,  stinger  blown with  dry  air  and  check  the ballasting
8. Check and prepare the start-up equipment, installation aids and materials as detailed in the table

• 12″ Pulling head 2 ea
• 4″ Pulling head 2 ea
• 85 MT Shackles 3 ea
• Bi-Di batching pig (Wet buckle contingency pig) 1 ea
• Buoyancy Foam Block (Beach pull operation) 1 lot
• Strip-out cable (Buoyancy Foam Block banding material) 1 lot

PIPE HANDLING

1	Pipe handling spreader bar	1 lot
2	Pipe handling slings to suit 12″ dia. pipe spreader	1 lot

PIPELAY

• Internal line-up clamp 1 ea
• External line-up clamp 1 ea
• Stop trolley 1 ea
• Holiday detector 2 ea
• 5/8″ IWRC 6×19 Galvanized Extra Improved wire rope for stop 2,000 ft trolley
• Copper tubing 7/8″ ID x 25mm WT (10ft per length) 14 length
• Polyken #980-SSJ·X (450mm) 1 lot
• Polyken #980-SSJ-X (150mm) 1 lot
• Heat Shrink Sleeve 1 lot
• Propane Heating system 1 set
• Pigy Back Block 1 lot
• Strap for piggy back block 1 lot
• Strap for field joint coating 1 lot
• Strapping machines 2 set
• Anodes for 4″ pipeline 1 lot
• Anodes auxiliaries component
• Anode Welding system
• Anode lnfill material
• White paint (7 liter/can) 10 cans
• White Emulsion paint I oil base paint (?liter/can) 5 lot
• Welding consumables 1 lot
• Beveling machines and assembly 2 ea
• Foam infill 1 lot
• NDT equipment and consumables 1 lot
• ROV spread 1 lot
• Survey spread 1 lot
• Diving spread 1 lot
• General equipment and consumables related to pipelay activities 1 lot
• A&R winch c/w cable                                                                                      1 lot

PIPELAYING PROCEDURE

INTRODUCTION

The following section describes the method of the pipeline installation. SUBCONTRACTOR  will lay the pipeline partially  from approximately KP 73.000 till  KP 68.500. After 26″ pipeline beach pull operation completed at KP 69.000, DLB Armada will return to KP 68.500 to recover 12″ + 4″ pipelines and continue pipelay from KP 68.500 to KP 0.00 in accordance to the conventional lay barge method of welding  pipe joints on the barge and pulling the barge along the pipeline route after welding is completed at each welding station.

Automatic welding will primarily be utilized for 12″ 0 pipelay. Refer to Document No. SR-TKM·WLD­ GEN·02, Welding Procedure Specification for the various WPS qualified for the installation.

Manual welding will be used for the 4″ 0 pipelay piggy-back pipeline. Refer to Doc. no. SR·TKM-WLD­ GEN-01, Welding Procedure Specification.

Installation Summary

Max. Water Depth                       60.2m (KP 0.0 at MCR-A platform) Maximum

Pipelay Tension                           1000.85 kN (225 kips)

Minimum Pipelay Tension       200.17 kN ( 45 kips)

Stinger Tip Clearance to seabed        varies (water depth 10.0m to 62.0m)

The following parameters will constantly be controlled and recorded during pipelay:

1. Elevation of stinger stern-most roller by air diver and onboard
2. Pipe-lay tension
3. Pipeline profile between stinger end to touchdown as observed by
4. Pipeline touchdown location as observed by
5. Gap between stinger back-end roller to pipeline

EQUIPMENT LIST AND  PREPARATION

Prior to commencement  of pipelay, all preparatory work for the installation will be completed. Equipment required will also be checked and verified for their operation.

MATERIAL AND EQUIPMENT LIST FOR PIPELAYING

The following  materials and equipments are required for general pipelay of  12″ dia. with 4″ dia. Piggy-back pipeline.

PIPELAYING  EQUIPMENTS AND FIELD JOINT MATERIALS

• 12″ Internal line-up clamp 2 ea
• 4″ External line-up clamp 2 ea
• 5/8″ IWRC 6 x 19 Galvanized Extra Improved 1,250 ft wire rope for stop trolley and buckle detector
• 718″ ID x 50ft length Of copper tubing 10 ea.
• Foam infill As required
• lnfill material Pump 2 ea
• Galvanize Sheet (electrode galvanize type)  As  required
• Polyken #980-SSJ-X (450mm) As required
• Polyken #980-SSJ-X (150mm) As  required
• Heat Shrink Sleeve As  required
• Holiday Detector (capable of measuring  up 15kV)  2 ea
• White paint (16 liters/can) 90 cans
• Buckle detector and blow-down head for 12″ pipe 1 ea

WELDING AND QC EQUIPMENT

• Welding machines for 12″ pipe 4 sets
• Welding consumables for 12″ pipe 1 lot
• Welding machines for 4″ pipe 3 sets
• Welding consumables for 4″ pipe 1 lot
• NDT related equipment and consumable  As required
• Welding machines
• Welding consumables
• NDT related equipment  and consumable

PIPE HANDLING

• Pipe handling spreader bar 2 ea
• Pipe handling slings 2 lots

SURVEY I DIVING I ROV

• ROV spread 1 lot
• Survey spread clw side scans, transponder etc 1 lot
• Diving equipment 1 lot

GENERAL

• General equipments and consumables related to 1 lot pipelay  activities

PREPARATION FOR PIPELAY

The following preparation prior to pipe-lay start-up will be performed:

1. Adjust barge and stinger roller heights according to 12″ + 4″ dia, pipelay analysis.
2. Service and adjust tracks on pipe tensioning machines prior to start-up/beach pull
3. Check pipe rack and line-up station equipment is operational including buckle detector, X-ray crawler, stop trolley, internal line-up
4. Check stinger valves, control panel, video,  underwater  cameras,  rollers and load cell are in working
5. Check  the  valve   at  start-up   head  is  closed  and   plugs     Ensure  compatible   hose connections  are available  (if  required).
6. Ensure materials and equipments for the field joint  coating, anode and foam operations are readily
7. Check that the constant tension winch for laydown/abandonment of pipeline is £
8. Ensure sufficient quantity of white marine paint is available for marking
9. Test all survey equipment  of both pipelay barge and Anchor  Handling Tug (AHT). Test and calibrate
10. Test all NDT equipment e. NDT crawler, automatic processor etc. Ensure sufficient supplies of radiographic films, chemical, screen etc are available.
11. Set-up current meter at bow of pipelay to monitor change in current speed and direction during

DETAILED PROCEDURE

The following subsections detail the procedures relevant to the pipelay operation.

BARGE RAMP STINGER DETAILS

Barge/Stinger  Roller Height and Spacing

The  12″ dia.  pipelay will be carried out by a derrick  lay barge with the barge and stinger  roller heights set in accordance to Fig.4.3.1-1 and Fig. 4.3.1-2.

Barge / Stinger Details

The installation engineering has assumed the following barge attitude for pipelay activities:

Fwd Draft Aft Draft

Trim by Stern Stinger

4.1 m (bow)

4.1 m (stern)

0 degree

50.5m Floating Stinger

Stinger Operation

The stinger ballasting operations will be controlled from the control panel located at the stern of the barge. The pipe will be monitored visually by the stinger technician/diving crew using a subsea camera mounted at the last stern rollers of the stinger. A closed-circuit TV will be made available in the diver shack and connected to the subsea camera. The elevation of the rollers shall be logged every 30 minutes of the pipe pull.

SUBCONTRACTOR shall monitor the installation of pipelines with an ROY and/or diver. During laying operation, pipeline profile monitoring by diver and ROY shall be conducted at a minimum frequency of three (3) times per shift.

During Critical lay in each curve, ROV must be in function to monitor pipeline location ensuring in +/- 15m tolerance. Pipelay route calculation will be provided by Party Chief for review.

The stinger-rollers elevation  will be constantly monitored especially when the water depth changes. The depth gauge shall be installed at the end of the stinger to monitor  the  stinger  end  depth. Designed elevations for various water depths along the pipeline route shall follow those in Doc. No. SR-TKM-ENG-MCRA-OGT-P1 01, Pipelay and Weld Repair Analysis – 12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked.

Note: Depth gauge at the end of the stinger to be installed to monitor stinger depth.

PIPELAY BARGE ARRANGEMENT

Table 4.3.2  details  the  activities  that  will  be  performed  in  each  station  of  the  pipe  ramp  on  the barge during the 12″ dia. pipelay. The pipe ramp is illustrated  in Fig. 4.3.2·1.

Table 4.3.2

Pipe Ramp Activity Arrangement for 12″ dia. & 4″ dia. pipes.

 

STATION NO.	ACTIVITY
	12″ Dia.	4″ Dia.
1	Root I Hot Pass I Fill #1 & #2 I Fill #3 & #4 I Capping, Visual Touch-up I Radiographic Inspection		Root I Hot Pass, Fill #1 Repair   Capping, Visual and Touch-up / Repair
2	Fill #1 & #2 I Fill #3 & #4 I Capping, Visual & Touch-up I Radiographic Inspection
3	Fill #3 & #4 I Capping, Visual & Touch-up I Radiographic Inspection	Capping, Visual and Touch-up / Repair
4	Capping, Visual and Touch-up	Capping, Visual and Touch-up / Repair
5	Radiographic Inspection I Repair	Radiographic Inspection
6	Radiographic Inspection I Repair	Radiographic Inspection I Repair
7	Polyken 980-SSJ-X Application	Heat Shrink Sleeve Application
8	Field Joint Foam  lnfill	i.       Anode Installation ii.     Piggy-Back  Block installation

BARGE AND ANCHOR SET-UP

For the pipeline start-up at OGT shore, the barge will be set up for shore approach for beach pull operation. The location of barge stern is approximate 400m from OGT shore.

During normal pipelay, four (4) bow anchors will be run at a maximum of approximately 1200m. The remaining cable length in the drum is approximately 600m. The minimum cable length paid out on the stern anchors is approximately 500m.

For further details of the anchor handling procedure and anchor cable catenaries, please refer to Document No. SR-TKM-MRN-GEN-06, Anchor Handling Procedure.

PIPELAY VARIABLES

The pipelay engineering analysis recommendation of the optimum pipelay tension is shown in the following page, extracted from Engineering Analysis Document No. SR-TKM-ENG- MCRA-OGT-P101, Pipelay and Weld Repair Analysis – 12″‘ Condensate Pipeline from MCR-A to OGT and 4″‘ MEG Pipeline Piggybacked. Optimum stinger roller heights  at  stern  for  the  entire   pipelay  route  are  also stipulated  in the  analysis.

Since the variation in tide is very minimal, the sensitivity analysis for water depth variation is not carried out. The pipelay analysis allows for the following variations from the optimum whilst still maintaining a combined stress level below the allowable value.

• Barge tension of ±10 MT for all the varying water depths.
• ± 5% increase in submerged weight
• ± 5 deg. in barge trim angle
• 90 and 0 deg. beam sea current (1 year)
• Sensitivity of the stinger elevation (from sea water level) e. :

Maximum elev. Is 13.39m (15.85 deg. Of max stinger rotation at 20. 77m water depth) Minimum elev. Is- 2.43m (2.97 deg of min. Stinger rotation at 7.60m water depth)

SURVEY AND POSITIONING

Tolerance

The pipeline will be laid along the routes defined in alignment sheets and its position will be within ± 15m except within 450m at riser location and ± 5m at trenching area. Maximum allowable deviation shall be reduced as follows:

• From 450m to 150m from riser – tapering from 15m to
• Within 150m from riser – 3m
• At pipeline/riser interface the deviation shall be sufficiently small to allow installation in the riser clamps without introducing bending stresses in the

Minimum separation of 15m shall be maintained where pipeline is installed adjacent to an existing pipeline.

Pre-Survey

The pre-installation route survey for the 12″ dia. pipeline with 4″ dia. piggy back will be carried out prior to pipelay. Refer to Document No. SR-TKM-OPR-GEN-01, Pre-Installation Survey Procedure for Proposed Pipeline and SPM/PLEM.

Barge Positioning

Barge will be positioned primarily using navigation DGPS Positioning Systems. The systems use multiple onshore reference DGPS station to determine pseudo range data link. The DGPS positioning system will be available onboard as a back-up system if required and to provide constant online QAIQC checks against the navigation DGPS Positioning Systems.

Anchor  Handling Tug Positioning

The anchor handling vessels will be using the Barge Management System (BMS) controlled from barge as their positioning system. The system works in conjunction with the Tug Management System (TMS) installed on both anchor handling tugs. The tug’s position will be continually transmitted to the barge via UHF radio link. On the BMS monitor the outline of each tug is shown in a different colour for easy identification. During anchor running, the Surveyor on duty will enter the coordinates of the proposed anchor position into the BMS system. A printout of the target position will be automatically generated and the position will be transmitted by telemetry  link  to  the selected Tug Management System on the Tug.

Pipeline Positioning / Survey

A software package will be used as the online computer navigation system provided by Veripos, which is interfaced with 1 x lmmarsat DGPS as Primary through High Power Spot Beam 109E and 1 x Secondary DGPS through High Power lOR. For positioning of pipeline start-up and laydown, the ultra-short baseline (USBL) beacon will be mounted on the ROV which will be tracked using a USBL Transceiver which will be installed on the over the side pole mounting and a long deck cable is used to connect to the top side unit in the barge bridge. Control  will be interfaced to the surface navigation system. All subsea pipeline/cable positioning will be carried out using the USBL system and the ROV.

As-Laid Survey

The as-laid side-scan survey of the 12″dia. with 4″ piggy-back pipeline will be carried out by SUBCONTRACTOR. This will be completed to determine the free span locations. The allowable free spans are shown in COMPANY approved for construction pipeline alignment sheets.

LINEPIPE HANDLING

The sling arrangements for lifting of the line pipes from the material barge on to the deck of derrick lay barge and from the deck into the transfer station are shown in Fig. 4.3.6-1.

Use average pipe length= 12.2m. line pipe joint unit weights are as follows:

PIPE DESCRIPTION	CONCRETE  COATING THICKNESS/DENSITY	EMPTY WEIGHT IN AIR (MT)	EMPTY WEIGHT IN WATER (MT)
114.3mm OD x 10.0mm  x 4.0mm 3LPP	N/A	0.331	0.183
323.9mm OD x 15.9mm x 5. 5mm Asphalt Enamel	45 mm I 3,040kg/m 3	3.553	1.777
323.9mm OD x 15.9mm x 5.5mm Asphalt Enamel	65 mm I 3,040kg/m 3	4.589	2.464
323.9mm OD x 15.9mm x 5.5mm Asphalt Enamel	90 mm I 3,040kg/m 3	6.017	3.408
323.9mm OD x 15.9mm x 5. 5mm Asphalt Enamel	120 mm I 3,040kg/m 3	7.921	4.669
323.9mm OD x 15.9mm x 5.5mm Asphalt Enamel	130 mm I 3,040kg/m3	8.601	5.120

LINEPIPE PREPARATION

Followings are activities to be carried out for each pipe joint before reaching the line-up station:

• Bevel/end-preparation the joint ends to J-bevel using 12″ dia. pipe facing machines prior to transferring into ready rack. Bevel preparation for 4″ pipe will be carried-out at station no. 1.
• Prepare the ready rack with the appropriate pipe joints. The linepipe description (i.e. anode, plain, colour code etc.) for each joint number assignment is given in Tables 1.2-1A for 4″ dia. line pipe and for 12″ dia. Pipeline respectively.
• Register the pipe joint number, plain/anode and the input i.e. pipes in the table  will  be updated continuously depending on the exact pipe length and the actual measured KP by Surveyor. Standard pipe tally sheets for daily submission to COMPANY. (Refer to Fig.4.3.7-1 for pipe tally sheet pro-forma).
• Pre-heat both ends of the pipe joint when pipe enters the line-up station.
• Paint the sequential joint number onto each pipe. The number needs to be painted on the “bow” end of each pipe joint in the 10 o’clock and 2 o’clock positions with white quick drying marine paint.

WELDING I NDT I WELD REPAIR

Welding,  NDT  and  weld  repair  procedures  have  been  prepared  in  accordance  to  COMPANY Specification, Pipeline Welding and Inspection.

Details of the welding, NDT, repair and field joint coating activities at each station are summarized in Table 4.3.2. The drawings for internal pipeline equipment are shown in Fig. 4.3.8-1 to 4.3.8·4

Welding

Detail pipeline welding procedures can be referred in Document No. SR·TKM·WLD-GEN-01, Welding Procedure Specification. Automatic welding system will be utilized for 12″ pipeline root pass, hot pass, filler and capping passes. Manual welding system; “Shielded Metal Arc Welding” will be deployed for 4″ dia. pipeline.

An internal line-up clamp will be used to align and fix the 12″ dia. pipe but an external line-up clamp will be used to align and fix the 4″ pipe for the root and hot pass in weld Station No. 1 and or otherwise known as bead-stall. Note that the linepipe is HFWIERW pipe and at the ends of each joint will be re-beveled outside the ready rack prior to transfer to the bead stall.

NDT

All pipeline welds shall be subjected to 100% radiographic inspection which will be carried out in Station No. 5 or 6. Station No. 1 to 4 will be used as an optional radiographic inspection station if required. Project specific pipeline NDT procedures are detailed in Document No. SR·TKM·NDT· GEN-06, Provisions of General NDT Procedure for Pipelines (26″ OD I 12″ OD I 4″ Piggyback). An internal x-ray crawler will be utilized to obtain radiographic  image  of  every  field  joint weldment. Its arrangement is shown in Fig. 4.3.8-3. The film will be developed and image interpreted  by radiograph interpreters.

An external portable x-ray will be utilized for 4″ pipeline to obtain radiographic image of every field joint weldment.

If re-shot needs to be carried out after application of anti-corrosion coating tape, the x-ray film will be placed over the anti-corrosion coating tape without needs for its removal and the weld will be re-shot.

SUBCONTRACTOR  will carry-out a mock-up on the barge to verify the quality of the film and measure radiation level.

Should the quality and density of the re-shot film does not meet the specification requirement, the anti-corrosion coating tape shall be removed and the weld re-shot.

Precautions as listed below will be implemented  to  reduce  risk  of  personnel  exposure  to radiation (on the derrick barge and adjacent materials  barges/vessels).  Refer  to  the  Radiation Safety Procedure, Doc. No. SR-TKM·NDT·GEN-02 for detailed safety precautions.

1. Adherence to warning signs – Only authorized personnel shall be in the immediate radiograph
2. Whilst the radiograph warning light is flashing, all personnel are to keep out of the area
3. A safe distance from the radiograph station will be pre-determined and fenced
4. For radiograph inspection outside of the dedicated station (i.e. for weld repair situations),  the following steps will be taken:
   i) A moveable “dog house” lead shield shall be placed over the immediate radiograph. The lead shield shall prevent radiation exposure above and from the sides of the shield.
   ii) Shielding shall be placed upon the floor to protect those
   iii) Radiation survey meters shall be used to ensure the operation is not exposing personnel to radiation
5. Audible signal are also provided to worn

WELD REPAIR

Weld repair will be carried out subject to approval in conjunction with Document No. PTS 20.120 by COMPANY. The weld acceptance criteria shall be in accordance to API 1104 Section 6 and DEP.61.40.20.30 GEN Section 6.

Weld repair length calculations are as per engineering calculation for weld repairs at Station No.   1\

6  on  the  barge.  The  maximum  gouge  lengths  for  both  stations  are  as  specified  in  the  above document. Weld repair will be carried out manually using SMAW process. Refer to Section 4.4 for extract from Document No. SR-TKM-ENG-MCRA-OGT-P101,  Pipelay and Weld Repair Analysis- 12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked

BUCKLE DETECTION

A buckle detector assembly will be positioned at a minimum of 4 joints past the furthest touchdown point. This assembly will provide a mean of identifying any deformity occurring in the pipe string after the string has left the lay barge.

The buckle detector system set·up will consist of the following components:

– One buckle detector system completes with 6mm thk. aluminium gauging plate.

– 5/8″ OD x 2000ft wire cable

– 1″ ID x 0.049″ WT x 10ft lg. copper tubbing

– X·ray stop trolley

– 12″ internal line-up clamp        

– 5T air tugger

– Load cell with gauge readout

The X·ray stop trolley will be attached to the 5/8″ dia. cable approximately  at  station  8  or between station 7 8: 8. A 5/8″ dia. cable connected to the end of the line·up clamp reach rod and terminating at an air tugger located on the bow completes the assembly.

Refer to Fig. 4.3.9·1 for the proposed assembly of a 12″ dia. buckle detector. Gauging plate will be fixed at 266.6 mm diameter which is based on the DnV 1989  rule:

0 = (D- 2t) ·0.01D- 0.4t- 5P

Where              

D = Nominal OD of pipe (323.9 mm)

t =  Wall thickness of pipe (15.9 mm) 

p = 0.2t or 5 mm whichever  is smaller

The insertion of buckle detector inside the pipes will be easier when more joints are on the seabed such that the back pressure inside the pipeline being laid is minimized. When the pipe joint No. 150 or more at the beadstall. buckle detector shall be deployed by blowing down. The deployment will be carried by means of a pneumatic system (blow down cap) incorporated in the assembly. An air hose will be pre-attached to the blowdown cap to supply pressurised air so that the buckle detector can be blown down along the pipeline profile and moves toward touchdown. With each pull of the pipeline. the wire cable will pay out one joint length of cable. Once all cable is paid out, the buckle detector assembly will be pulled forward using air tugger at the bow of the barge.

The buckle detector assembly will operate typically as follows:

1. When welding has been completed at all stations along the mainline, the cable from the air tugger to the reach rod will be disconnected and the barge move ahead 2m.
2. The next joint will be transferred  from the  ready rack to the line-up  The air tugger line will then be pulled through the new joint and connected to the line-up clamp reach rod.
3. The air tugger  will commence  to  haul in the cable,  the line-up clamp  and buckle detector assembly, which will travel up along the pipe string towards the beadstall (Station 1).
4. The load on the buckle detector assembly, indicated by a gauge mounted on the air tugger will be recorded for each corresponding joint number during each
5. Any excessive deviations from the average pull force being recorded will initiate the alarm on the load An immediate investigation will be carried out to ascertain the cause
6. The line-up clamp will be activated and welding

Fig.  4.3.9-1  to 4.3.9-5  shows  the  details  of  internal  pipeline  equipments,  arrangement,  cable make-up and installation process.

The buckle detector assembly will be removed prior to pipe laydown. The buckle detector will be monitored from the tension gauge for every each pipe pull

FIELD JOINT COATING

The field joint coating will be applied in two field joint stations after the fields welds have been radio graphed and visually inspected. The field joint area for 12″ Condensate pipeline will  be wrapped with cold-applied anti-corrosion coating tape “Polyken”  and HDPU foam  infill while  4″ MEG pipeline will be wrapped with heat shrink sleeve.

The first portion of the field joint coating system i.e. Polyken #980·SSJ·X or heat shrink sleeve will be carried out in Station No. 7 and 8 (if required). The second portion of the field joint  coating system i.e. foam infill will be carried out in Station No. 8.

Similar application system will be utilized for repair of existing corrosion and concrete coating. If damage on the yard corrosion coating is outside the coverage of the  Polyken  #980-SSJ·X,  an addition 150mm wide strip will be  wrapped  around  the  affected  area.  Excessively  damaged concrete joints  will be returned  to the coating yard.

Polyken #980-SSJ-X Application

Primer will not be required with the Polyken #980·SSJ·X proposed for the pipelines temperature ranges when they are utilized on concrete weight coated lines under a joint filling material. The following procedure will be adopted for the application.

1. As specified in the Polyken #980-SSJ·X Datasheet, total weld area, including exposed corrosion coat will be power-wire brushed to remove all rust, weld spatter, insecure mill scale, dirt, dust and other deleterious  matter  and  to be cleaned  and dry
2. The application of  Polyken  #980-SSJ·X  as follows (and also shown in 4.3.10·1 ):
3. 450mm wide  Polyken  #980-SSJ·X,  cold  applied  pipewrap,  will  be  applied  in  a  single continuous layer, cigarette wrap, centring on the line of the
4. 150 mm wide strips will be applied in a single continuous layer,  cigarette wrap,  one at each extremity of the 450 mm wide Polyken 980-SSJ·X.
5. For all cigarettes wrap method, application should be with a minimum of 25mm overlap.
6. Application of Polyken #980-SSJ·X will take place on a  clean,  dry,  firm  surface,  employing sufficient  hand  tension  to assure a smooth, wrinkle free
7. After application, the surface will be holiday tested using Holiday Detector with circle spring electrode capable of measuring at up to 15kV for Polyken #980·SSJ·X to check  integrity between the pipe surface and Polyken #980-SSJ·X. If holiday is detected, the Polyken #980-SSJ· X will be removed and steps 1 to 5

The following pages are the Technical Data Sheet ft MSDS for Polyken #980-SSJ·X.

Foam lnfill Addition

Foam infill shall be High Density Poly Urethane -Sethane F160M (HDPU).

The foam shall be applied as a one part system to an OD equal to the OD of the concrete weight coating after application of the field joint corrosion coating.

Refer to Fig. 4.3.10-2 for details.

Metal sheet shall be wrapped over the entire field joint area and extend onto the plant­ applied, concrete coating by 6 inches on each side. This form shall be securely strapped or banded at each end over the concrete coating. To use the form, an opening at the top of the form shall be utilized to fill joint with foam. After filling the mould, the opening will be strapped shut.

The following pages are the Technical Data Sheet 8: MSDS for HDPU.

Heat Shrink Sleeve for 4″ Pipe

Heat shrink sleeve is a wrap around sleeve shall consist of radiation cross-linked, high density polyethylene with PCI (Permanent Change Indicator). Heat shrink sleeves especially suitable for higher stress condition caused both by elevated temperature and by soils with severe contraction between wet-dry cycles.

The heat-shrinkable sleeve is wrapped around and shrunk to form a tight fit around the joint as Fig. 4.3.10-3. During recovery, the adhesive softens and flows to form a perfect bond with the pipe surface providing protection against corrosion. The radiation cross-linked outer layer forms a tough barrier against mechanical damage and moisture transmission.

Refer to Appendix 5 for ‘”‘ technical data.

For more detail, please refer  to  Field Joint  Coating,  lnfill and  Coating  Repair  Procedure”  Doc. No.  SR-TKM-OPR-GEN-10.

The following pages are the Technical Data Sheet & MSDS for Raychem WPC100M.

Typical Piggy Back Block Installation

Piggyback blocks manufactured by Lankhorst/ Mouldings where they can be swiftly installed onto a pipeline during a vessel lay operation. The blocks are lightweight and easy to handle, and do not require a great deal of force to be installed.

With the exception of the pneumatic strapping tool, no special equipment is required to install a Lankhorst/ Mouldings piggy back block system.

Piggy Back Block Component

The Piggy Back Blocks (PBB’s) for this project consist of a body and a cap.

There are two size of Piggy Back Block to suite different range of concrete coating thickness:

1. Type 1

16.5inch-4.8inch is meant to suit 12″ OD pipeline with concrete thickness range from 45mm to 65mm.

2. Type 2

23.5inch-4.8inch is meant to suit 12″ OD pipeline with concrete thickness range from 90 to 130mm.

PBB’s shall be installed (at regular intervals) on the main line with the 4″ OD piggy line positioned in the designated slot. The slot shall be closed/covered by a single cap (166 x 166 x 15 mm). The body and cap shall be fastened to the main pipe by two (2) Carbon Steel and one (1) Alloy 625

Refer to Appendix 4 for System Quality Test.

Piggy Back Block Installation Sequence

The describe sequence of activities for installing a piggy back block shall be repeated for every individual piggy back block.

Installation sequence for applying the Piggy Back Blocks as follow:-

1. Place “Piggy Back Block” onto the main Position the block at the desired location along the main pipe line. Maximum spacing between piggy back blocks is 10m.
2. Lower the 4″ pipeline into the designated piggy line cavity. Place cap on top of the body.
3. Install bandings the “Piggy Back Blocks” shall be installed using two (2) Carbon Steel straps and one (1) Alloy 625
4. Feed band around the pipe and “Piggy Back Block”.
5. Slide band through seal clip.
6. Tighten band by hand
7. Repeat step 4 ·no. 6 for each individual strap until three (3) bandings are installed.
8. Tighten the bandings with the Pneumatic
   i) Tighten the carbon steel bands first and the Alloy625 band will be the last
   ii) Ensure that the banding is seated correctly or else the tool jaws may not engage properly onto the
   iii) Position the tool over the loose end of the band piece and operate the tool in accordance with the manufacturer’s Refer to Appendix 4.
   iv) Once the band has been sealed and cut, check the seal clip for its teeth If properly sealed the seal clip should have four (4) teeth marks as shown on the pictures below. If not, then remove the band and install a new band.
   v) Repeat this process for every band that is to be tightened and

Typical Anode Installation on 4″ Dia. Line Pipe

Anode Installation Sequence

1. Carefully removed 4mm 3LPE coating from 4″ pipeline surface with 1 Y, inch puncher for cable termination point. Each termination point shall be equally spaced at 180° around the circumference of the pipeline, approximately at middle of line pipe.
2. Termination points shall be at 3 o’clock and 9 o’clock
3. The surface of line pipe or doubler plates shall cleaned of any rust, mill scale or coating by using appropriate tools such as pencil grinder, wire brush, abrasive paper and rags to clean it
4. Crimp copper cable lug to the end of the termination cable (if copper lug is not installed).
   Note: Each anode (halves shell) had a pre-install termination cable.
5. Matching anodes pairs shall be attached around the anti-corrosion.  One anode  half  section position on the top of the pipe while the other half shall be placed under the top
6. Clamped halves shell tightly to the 4″ dia. pipe and weld the steel tab together according to approved welding procedure. Refer to Doc. no. SR-TKM-WLD-GEN-01 -Welding Procedure Specification.
7. Cable lug will be secured to 0 8.0 mm bolt or stud which welded to the doubler plate. The bolt or stud shall be welded to doubler before assembling anode on the pipe. Refer to Fig. 4.3.12.1-1 and Fig. 4.3.12.1-2 for detail.
8. Mastic filler is used to repair the expose area caused by the removing corrosion coating prior to weld the doubler plate. Refer to Fig. 4.3.12.1-3.
9. Use a low intensity yellow flame for  pre-heating the coating and applying the repair products. With quick back and forth strokes, pre-heat the repair zone sufficiently to remove moisture and assist in adhesion.
10. Place the filler material onto the damaged area with the release paper facing Firmly press the material into the damaged area by hand and remove the release paper.
11. After filling the damaged area, remove the excess filler to create a smooth As  an option, use a low intensity yellow flame to warm the filler material and assist in smoothing it out.
12. All internal and external of each anode half shelf surfaces shall be inspected for any dirt, unspecified oils, grease foreign material, grit or metallic Use appropriate tools such as wire brush and rags to clean it up.
13. The maximum gap between the anode half is Refer to Fig. 4.3.12-4.
14. The steel straps of anode should be fillet weld Prior to fillet welding the anode steel strap, the corrosion coating should be protected by using fire blanket. The plate shall be placed in the anode gaps to prevent any burning or melting of the coating during welding operation.
15. The surface of doubler plate should be clean from any rust, mill scale or coating by using appropriate tools such as abrasive paper and rags to clean it
16. The doubler plate shall be fillet weld to the anode steel The plate shall be placed in the anode gaps to prevent any burning or melting of the coating during welding operation.
17. Any slack cable shall be laid into the gap between the anode The cable shall be retrained at the bottom of this gap during application of the filler compound such that the connected cables are entirely covered.
18. Cover the anode gap with steel
19. Set the requirement volume need to infill the gap between halves at the foam machine control
20. Connect the foam machine nozzle with the flexi plastic Tight the hose using hose clips.
21. Begins to fill the gaps of anode at the hole of Open the mould after 1 minute and reshape the solid foam.
    Note: lnfill material could be prepared either manually or automatically mix by machine. And the infill material can be applied manually.

Mechanical Test

The mechanical test shall consist of one firm blow from hammer having a mass of 1 kg at the weld area and then checked visually for any sign of inadequate  and no visible fracture was observed.

Electrical Test

An electrical continuity test shall be conducted between anode and pipe joint with an ohmmeter. The test shall shown that a low resistance between the anode body and the pipe. Measured between the anode and the pipe steel, shall not exceed 50 Ohms.

Visually Inspected

All attachment welds shall be visually inspected to meet the requirement of API 1104.

PIPELINE LAYDOWN I ABANDONMENT AND RECOVERY

GENERAL

The following laydown procedures will be applied at KP 68.500 and at the end of the pipelay where the laydown coordinates are pre-determined at platform MCR·A location. After 26″ pipeline beach pull operation completed and abandon at KP 69.000, 12″ + 4″ piggy back pipelines to be recovered at KP 68.500 in order to complete approximately 73 Km pipelines installation.

However, the exact KP shall be confirmed by Surveyor based on real time final position. The laydown/abandonment and recovery procedures will also be used if it is required to suspend the pipelay operations due to some unforeseen circumstances such as bad weather.

The final pipeline route and length for 12″ dia. with 4″ piggy-back pipeline OGT to MCR-A laydown point will be based on Surveyor final position.

Safety Note: All non-related personnel to stay clear of pipe tunnel during laydown/abandonment and recovery operation.

EQUIPMENT LIST AND PREPARATIONS

The following items are required for pipeline laydown:

ITEM	DESCRIPTION	QUANTITY
1	Shackle, 85MT Green Pin Standard Shackles bow shackles with safety bolt G-4163  (for item no. 7)	2 nos
2	12″ (323.9mm)  OD  Laydown Head, pre-welded with  temporary  12″ WN RTJ flange, class 1500# (ASME B16.5)	2 nos
3	12″ (323.9mm) OD Start-up Head, welded to pipe.	1 nos
4	55 316 Octagonal Ring Gasket RTJ, R58	2 nos
5	Temporary stud bolt 2″ dia. x 390mm length c/w 2 nuts with UNC threaded, Blacken Type (for 12″ Dia.)	32 nos
6	4″ (114.3mm) OD Laydown Head, welded to pipe.	1 nos
7	4″ Blind flange RTJ flange, class 2500# (ASME B16.5)	1 nos
8	55 316 Octagonal Ring Gasket RTJ, R38	2 nos
9	Temporary stud bolt  1 1/2″ dia. x 260mm length c/w 2 nuts UNC threaded, Blacken Type (for 4″ Dia.)	16 nos
10	Underwater video camera mounted end of stinger	1 set
11	Strip out block to suit laydown winch cable (if required)	1 set
12	Wire rope sling, size 2 inch dia. x 20 ft length, IWRC 6×36 EIPS ungalvanized w/ 2ft soft eye both end mechanical spliced (for sacrificial sling)	2 nos
13	180MT Capacity of A&R Winch c/w 76mm (3″) dia. x 1,100 m length cable	1 unit
14	ROY c/w 76mm (3″) hydraulic anvil cutter	1 unit
15	White  Paint (7 liter/Can)	20 can
16	Temporary half shell flange guide c/w clamps on each side  and bolts and nuts	2 nos

LAYDOWN PROCEDURE

The following  steps will be carried out for laydown of the pipelines.  Refer to Fig. 5.3-1 for the anchor patterns set-up:

1. As the lay barge approaches target laydown KP coordinates (to be confirmed with Surveyor), begin preparing the rigging for pipeline Refer to Fig.  5.3-4 for  pipeline laydown rigging arrangement.
2. Weld the permanent flanges to the last joint of the pipeline and complete all x-ray of the remaining field joints at their respective
   Note: The internal bevel on min 1:3 gradient shall be performed on permanent flanges:
   – 4″ dia- 0 mm WT prior to welding with last joint, 10.0mm WT.
   – 12″ – 15.9mm WT prior to welding with last joint, 15.9mm WT.
3. Recover the followings from inside of the pipeline:
   – Internal line-up clamp
   – X-ray crawler
   – Stop trolley
   – Buckle Detector
4. Paint (white) the 12″ laydown head and perform flange tie-in between the laydown head and the last joint of the pipeline. lnstall4″ 2500# blind flange complete with 2″ ball valve on the permanent 4″ dia. flange. Fix the temporary half shell flange guide on bottom side of the flange tie-in position.  Ensure the cut back have adequate space for stud bolt inserting and bolt tensioning equipment. The temporary flange protector need to be modified accordingly. Laydown head and temporary flange guide  are  illustrated  in  Fig.  5.3-5,  Fig.5.3·6  and Fig. 5.3-7 respectively.
5. Close valve and install plugs on the laydown head and 4″ blind
6. Connect the end of the 3″ A&R cable and the laydown head via a sacrificial sling with two (2) nos. of 85 MT shackles on the both end configuration. The sacrificial sling will be painted white for easy identification by ROV to cut the sacrificial sling. Refer to Fig. 5.3·4 for the laydown rigging arrangement.
7. Pull the barge until the laydown head just entering the forward Gradually transfer all the tension to the A&R cable and open up the tensioner top track.
8. Continue pull the barge ahead until the laydown head is at the aft Gradually transfer all the tension to the A8:R cable. At this stage, both tensioner shoes are free from pipeline.
9. Continue advancing the barge forward until the laydown head is at stern of the barge.
10. Deploy ROV to monitor the laydown ROV may be used as an additional aid in providing visual of the laydown head.
11. De-ballast the stinger to meet the required back-end roller elevation as per data from Field Data Book (FDB).
12. Continue advancing the barge until the laydown head past the stinger This is indicated when the first is at the stern of the barge. ROV will provide the visual on the laydown head.
13. Gradually reduced the tension on the A8:R cable and let the laydown head settle on the seabed
14. Back up the barge for about 20m to provide slack on the A8:R The actual distance will be determined at site.
15. Send ROV to check the condition of the ROV will locate the sacrificial sling and cut the sling using hydraulic cutting arm. Another alternative is to use diver to unshackle the sling. ROV technician/ pilot shall perform the wire cutter  trial cut  prior  mobilization  and launch ROV.
16. ROV and Survey to take fixes in order to find deviation between the as laid route and design

ABANDONMENT PROCEDURE

The abandonment procedure shall be executed under circumstances such as  bad  weather  or buckle. The steps for abandonment procedure are  the  same  as  laydown  procedure.  However, there are few  exceptions  as listed below:

1. USBL beacon will be installed on the pipeline
2. Emergency laydown head will be Refer to Fig. 5.4-1 for details of the emergency laydown head.
   Note: For this pipeline installation, emergency  laydown head is similar to the normal laydown head but without WN Flange end.
3. The sacrificial sling connected from A&R cable end (A&R sheave at station 2) to the laydown may not be cut. The barge will back up to provide slack on the cable. However this will be determined based on site condition.
4. If the need arises to cut the sacrificial sling, install a marker buoy on the laydown head before laydown to seabed
   Note: In the event of abandonment,  the pipeline has to be completely laid down to the seabed and not to be suspended midway.

Fig. 5.4·2 and Fig. 5.4-3 present the steps for laydown and abandonment procedure.

RECOVERY

The following steps will be carried out if it is necessary to recover a pipeline and recommence pipelay. The recovery is essentially the reverse of the abandonment procedure:

1. The barge will be positioned so that the stern of the barge is at laydown head
2. Pay out the 3″ AftR cable (complete with spelter socket) towards stern and lower it down to seabed.
3. Position the AftR cable to the stinger with assistance of snatch blocks and/or air
4. Deploy diver to connect the AftR cable to laydown head on the seabed
5. Deploy ROV to monitor the recovery
6. Ballast the stinger as required with reference to extracts from Field Data
7. Start recovering the cable through the stinger and pipe ramp towards AftR sheave at station 2.
8. Back up the barge and gradually increase the pipelay tension as per pipelay analysis, increase additional 3MT to 5MT tension from the abandonment tension to counter efficiency lost in the winch
9. Maintain the pipelay tension and the stinger back-end roller elevation as per data from Field Data Book (FOB).
10. Activate the aft tensioner when the laydown head just passed the aft Maintain the tension at 600.5 kN (135 kips). Do not reduce the tension in the AftR cable.
11. Continue backing up the barge until the laydown head passed the forward Activate the tensioner. Gradually reduced the tension on the AftR cable.
12. Dismantle all riggings on the laydown Cut the laydown head and perform necessary NOT inspection.

Abandonment and Recovery

Introduction

The purpose of the A&R analysis is to define the safe working limits for the tension in the cable and the length of cable paid out, so as to ensure that the sagbend stresses in the pipeline remain within the maximum allowable value during the operations. The A&R procedure is similar to the laydown procedure. Reference is made to section 3.8 for the results of the A&R analysis at every section.

Two marks are recommended to be placed on the pulling cable from the laydown head i.e. 1st and 2nd Mark for the respective lay section. As an example for Section 1, the recommended 1st mark is 59.24 m and 2nd mark is 84.25 m. When the 1st mark from the pulling head, reaches the centreline  of the stern barge roller, the pulling head will be at the stern of the stinger. When the 2nd Mark from the pulling head reaches the centreline of the stern barge roller, the cable tension can be gradually released and the pipeline can be allowed to settle to the bottom.

When the 1st mark from the end of the cable, reaches the centreline of the stern barge roller during the recovery of the pipeline, the pulling head is at the stern of the stinger. At this point, care should be taken to ensure that the pulling head has not hung up on the stinger. After the pulling head is safely on the stinger, the barge can be backed up under the pipeline while holding the particular minimum cable tension. As the pulling head proceeds up the stinger, the net buoyancy is automatically decreased to account for the added pipe weight.

Results of Analysis

The minimum tension level for each step is calculated using the static  stress criterion in the sagbend and overbend. Furthermore, a positive vessel movement is maintained. The cable “pay-out” is defined as the amount of cable between the A&R head and stinger hinge.

The detail results of the A&R analyses are provided in Appendix VII. Computer output can be found in Appendix XV, A summary of the results is presented in Table 3.8.

Dry Buckle

If a dry buckle occurs, the pipeline is recovered by moving the vessel backward, while cutting the pipeline during the take in. At the moment the buckle approaches the stinger tip, the geometry of the buckle determines whether or not the pipeline buckle pass the stinger and tensioners. If the buckle can pass the stinger, the pipeline will be taken in and the damaged section will be removed. If the buckle cannot pass the stinger, the A&R head is welded on and the pipeline is abandoned according to the A&R procedure as described in Section 3.6. Subsequently, the pipeline is flooded and cut off beyond the buckle, the procedure is now similar to the wet buckle contingency as described in Section 3.7.3.

In term of analysis, recovery of a dry buckle is considered as either as reversal of the pipeline installation if it will physically pass through the stinger. If the buckle pipe cannot pass the stinger, the pipeline will be abandoned and treated as a wet buckle.

Wet Buckle

When the pipeline buckles to the extent that a leak occurs, the pipeline will be abandoned in a controlled manner, and thoroughly inspected to check for evidence of the pipeline damage and to verify the extend of flooding.

Flooded lay analyses have been carried out in order to simulate pipelay in case a wet buckle occurs. Results of the analysis are presented in Table 3.9. For graphs concerning flooded lay reference is also made to Appendix VIII. In terms of analysis the S-mode recovery of the de-watered pipeline is identical to an A&R operation as described in section 3.6.

Abandonment and Recovery Wet Buckle

Flooded A&R analyses have been carried out to simulate the A&R operation in case of wet buckle occurs. Summary of analyses are presented in Table 3.9 and references is also made to Appendix VIII for detailed result.

SEVERE DRY BUCKLE

1. If the buckle is still dry but severe, weld the “lay down pull head” to the pipeline.
2. Shackle the  lay down  cable to the  pull head with  1 ea x  85MT shackles  and perform abandonment procedure as outlined in Section 5.
3. Re-position the barge alongside the pipeline for a multiple davit
4. Attach davit lines to the pipeline and perform a multiple davit lift as detailed in the Field Data Book (FDB).
5. Maintaining the pipeline profile, remove successive pipe joints to the buckled
6. Remove the buckled joint(s) and weld the pull head to the pipeline. Tie one end of a length of 1″ rope to the pull head and the other end to a marker buoy. Lower line to seabed and disconnect all rigging.
7. Re-position the barge for recovery of the pipeline
8. Pay-out the recovery line with 1 ea x 85MT
9. Shackle the recovery line to the pull head, remove the marker line and perform recovery process as detailed in Section
10. Once the pulling head reaches the bead stall, it will be removed and the pipeline re­-bevelled.
11. Resume pipelaying
    Note: If the sever buckle occurs, a significant distance from the barge such that a multiple davit lift is not possible (i.e. buckle in the sag bend region), then pipeline will be flooded and wet buckle procedure (case B) followed

WET BUCKLE

This refers to a pipeline buckle where the pipeline has been flooded with seawater. The wet buckle repair procedure is outlined as follows:

1. Cease all barge movement and pipelay
2. Superintendent, Field Engineers and CONTRACTOR  Representatives notified
3. Deploy divers/ROY to inspect pipeline from end of stinger to touch down point on seabed
4. Determine location and type of buckle, namely:
   Case A – Pipeline buckled but not broken off
   Case B – Pipeline buckled, broken off and lying on seabed
5. Remove internal line-up clamp and x-ray crawler from inside the pipeline, (and x-ray stop trolley, if possible).
6. Under the direction of the Superintendent, commence moving the barge astern whilst simultaneously retrieving as many joints as possible up through the stern Cut out the joints and remove from the tunnel.

Case A

1. Retrieve pipe until in the opinion of the Superintendent, it is not safe to bring the buckle up the stinger
2. Fit and weld the emergency laydown head onto the end of the Meanwhile, shackles the lay down cable to the lay down head.
3. Upon completion of welding, abandon the pipeline using the Abandonment Procedure detailed in Section 5
4. Proceed to step b) of Case B

Case B

1. Retrieve all pipes in the stinger.
2. Re-position lay barge for a multiple davit lift of Refer to Field Data Book (FOB). Refer Fig. 6.1.5-1.
3. Deploy the diver with cutting equipment to cut out all the buckled section
4. Diver will attach rigging around the pipeline (12″ + 4″) as per Wet Multiple Davit Lift procedure detailed in the Field Data Book and secure to the side of barge.
5. Recover the pipelines using the Multiple Davit Lift Procedure as detailed in Refer Fig. 6.1.5·2 and Fig. 6.1.5-3.
6. Weld 12″ and 4″ “emergency laydown head” (equipped with Bi-di pig) to the pipeline at the side of the barge
7. An air hose will be connected to the emergency laydown head (require minimum 130psi air pressure). Sufficient compressed air supply will be provided by 750cfm compressor on board DLB Sea water discharging will take place to the allocated pond onshore.
8. Commence dewatering the pipelines by launching pre-install bi-di pig from individual emergency laydown
9. Continue pumping air into the pipeline until the dewatering pig arrives at the pig receiver. 
   Safety Note: Divers to keep clear of pipeline end during pigging operations.
10. Communicate with in-charge personnel on shore to confirm the pigs
11. Cease pumping air after confirmation arrival of the pig
12. Disconnect the hose, closed the ball valve and install the 2″ plug on each emergency
13. Lower-down the pipelines gradually to seabed using the Multiple Davit Lift Procedure as detailed in FBD
14. Recover the pipelines as per section 5.
15. Resume pipelaying operation, only after determining the reason for the buckle and taking corrective steps

SHORE APPROACH AND BEACH PULL – 26” & 12”+4” Piggy Back Pipeline

INTRODUCTION

The proposed pipelines for the beach pull will be laid as follows:

• 12″ 0 x 400m condensate pipeline from OGT to SPM (North).
• 12″ 0 x 400m condensate pipeline from OGT to SPM (South).
• 26″ 0 x 400m gas export pipeline from OGT to MCR·A.
• 12″ 0 x 400m condensate export pipeline and 4″ 0 MEG supply pipeline (piggyback for 12″ 0 condensate export pipeline) from OGT to MCR·A.

The approximate number of joints for each pipeline to be laid is 33 joints. This is based on 12.2m average length. Table 1.2·1 to Table 1.2·8 on the following pages give the details of pipeline sequence

SCOPE & SEQUENCE OF WORK

SUBCONTRACTOR scope and work sequences for the beach pull are as follows:

• Site preparation at the Right of Way (ROW) location.
• Transport linepipes and other appurtenances. Refer to:
  – Document    SR-TKM-ENG-MCRA-OGT-P100 (Linepipes    Transportation    Study    –    12” Condensate  Pipeline from MCR-A to OGT and 4″ MEG  Pipeline Piggybacked)
  – Document SR-TKM-ENG-MCRA-OGT-P200 (Linepipes Transportation Study – 26″ Gas Pipeline from MCR-A to OGT)
  – Document SR- TKM-ENG-OGT -SPM-P301 (Linepipes   Transportation    Study   –    12″ Condensate Export Pipeline OGT to/from SPM)
• Handling of linepipes, staking and storage prior to installation.
• Construction of concrete anchor blocks at onshore.
• Preparation and execution of the beach pull.
• Lay down pipelines at a designated  landing point  (approximately  120m from  tie-in flanges at OGT).
• Installation of the onshore pipelines from the landing point to the tie-in flanges  at OGT complete with all associated civil works i.e. pipe supports, welding,  NDT, Field  Joint Coating etc.
• Site re-instatement.

The construction of temporary  rock berm, pre-trenching,  post-trenching and backfilling will be undertaken by CONTRACTOR using designated specialist subcontractors.

SUBCONTRACTOR will use Armada Installer barge to perform the beach pull operation. The barge will be positioned at approximately 400m from the landing point and the linepipes will be welded to a start-up head, pulled to the beach and towered to the seabed.

The pipelines will be pulled to the shore using one of the following options:

Option 1: 25MT  pulling winch with  1 1/2″ 0 cable. The pulling winch  is anchored to the concrete anchor blocks at onshore.

Option 2:  P5 anchor cable of 2.44″ 0 of the DLB Armada Installer barge. A messenger cable of 1″ 0 wire rope is connected to the P5 anchor cable at one end and the other end at the start-up head. The wire rope is snatched through 150MT snatch block anchored to the concrete anchor blocks at onshore.

Foam buoys will be attached to the pipe string to float the pipeline and minimize the pull and drag forces. After the pipeline has arrived at the targeted landing point and lowered to seabed, the pipelay process will resume until the end of the offshore section and subsequent pipelines installation will take place.

The site location is shown in Figure 1 .4-1

INSTALLATION SUMMARY

12″ 0 x 400m condensate pipeline from OGT to SPM (North)

Start Point Coordinate at Landing Point (KP0.114) E   650590.26 N 4449707. 11

End Point Coordinate at OGT (KP 0.00) E   650702.58 N 4449724.72

Max. Tension during Beach Pull   10MT

Stinger Tip Clearance to Seabed    2.5m

12″ 0 x 400m condensate pipeline from OGT to SPM (South)

Start Point Coordinate at Landing Point (KP0.114) E   650590.26 N 4449704.76

End Point Coordinate at OGT (KP 0.00) E     650702.73 N 4449723.23

Max. Tension during Beach Pull   10MT

Stinger Tip Clearance to Seabed    2.5m

26″ 0 x 400m gas export pipeline from OGT to MCR-A

Start Point Coordinate at Landing Point (KP 72. 952) E   650584.68 N 4449697.95

End Point Coordinate at OGT (KP 73.073) E   650702.89 N 4449719.22

Max. Tension during Beach Pull 12MT

Stinger Tip Clearance to Seabed 2m

12″ 0 x 400m condensate export pipeline from OGT to MCR-A

Start Point Coordinate at Landing Point (KP 72.987)  E   650584.73 N 4449701 .41

End Point Coordinate at OGT (KP 73.107) E   650702.63 N 4449721.71

Max. Tension during Beach Pull  10MT

Stinger Tip Clearance to Seabed  1.6m

4″ 0 x 400m MEG supply pipeline (piggyback for 12″ 0 condensate export pipeline) from OGT to MCR-A

Start Point Coordinate at Landing Point (KP 72.995) E     650584.73 N 4449701 .41

End Point Coordinate at OGT (KP 73.113) E  650707.43 N 4449721.27

Max. Tension during Beach Pull   N/A

Stinger Tip Clearance to Seabed  As per 12″ x  400m   condensate  export pipeline from OGT to MCR

LOADOUT AND TRANSPORTATION

GENERAL

The  linepipes will be transferred to Turkmenistan  Block-1 Gas Development  Field using two  nos. 200ft class barge and two nos. 272ft class barge.

Upon  completion  of  each  loadout,  the  tiedown  and  seafastening  will  be carried  out  to  the satisfaction of CONTRACTOR and the appointed third party surveyors.

Refer  to  the following  documents  for  further  details  on stowage  plan and other  related information.

• Document    SR-TKM-ENG-MCRA-OGT-P106       (Loadout    Coordination   Manual    for    12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked)
• Document  SR-TKM-OPR-MCRA-OGT-P207   (Loadout  Coordination  Manual  for  26″  Gas Pipeline from MCR-A to OGT)
• Document    SR-TKM-ENG-MCRA-OGT -P106      (Loadout   Coordination    Manual    for    12″ Condensate Export Pipeline OGT to/from MCR-A)

PRE-LOADOUT

Prior to loadout from the coating yard, inspection list included in the above documents will be reviewed and completed. Any areas of potential concern will be highlighted to CONTRACTOR.

Particular attention will be given to:

• End condition of linepipes.
• Condition of linepipes coating.
• Linepipes magnetic properties.
• Concrete and anti-corrosion coating cutback.

LOADOUT AND TRANSPORTATION

Loadout list for the linepipes barge for 2 x 12″ dia. pipeline from OGT to SPM,  26″ dia.  pipeline from MCR-A to OGT and 12″ dia. pipeline and 4″ dia. piggyback pipeline from MCR-A to OGT is shown in the documents as per Section 2.1 above. General arrangement and seafastening details for  loadout of the pipeline and  miscellaneous  items are also included in the above report.

A detailed review of all components  and materials  loaded out will be conducted and checked against the loadout list as described in the Loadout Coordination Manual. Any discrepancies in the quantity and conditions of the pipelines will be highlighted to CONTRACTOR representative and recorded prior to transfer of custody of the transportation barge to SUBCONTRACTOR. A loadout and tie-down arrangements of linepipe bays on the transportation barge are shown in Fig. 2.3·1 to Figure 2.3-3 respectively.

Prior to departure of each transportation barge from the respective loadout location, a three (3) day weather outlook will be obtained from the Meteorological Service and forwarded to the tug boat captain for his further action. Shelter or safe tow route shall be identified and briefed to the Tug Master by the Marine Captain.

LANDFALL SITE CONSTRUCTION

GENERAL

The start-up head landing point is located on the ROW on the west side of OGT, approximately 114m to 126m from the first tie-in flange for permanent receiver facilities. The site has been extensively surveyed and marked to indicate the pipelines alignment prior to the work commencement. Refer to Figure 3.1·1 and Figure 3.1·2 for the details of the beach site layout.

To ensure the smooth flow of the work program and to avoid disruption, proper coordination between all authorities will be provided onsite. SUBCONTRACTOR with the assistance of CONTRACTOR shall be responsible for obtaining the necessary approval and permits for the access and construction work.

The construction site will be cordoned off to prevent unauthorized access and to provide a safety barrier to the public from the open excavations and construction.

PIPE PULL METHOD STATEMENT

This document outlines the pipeline start-up utilizing one of the options as described in Section 1.4:

• Prior to commencement of SUBCONTRACTOR’s work, the CONTRACTOR shall prepare and make ready the following  on the shore portion:
  – Site preparation, clearing, levelling, compaction, etc. of the site.
  – Trenching and rock berm
  – Fabrication and installation of concrete anchor blocks and concrete base for 25MT pulling
• DLB Armada Installer barge will be anchored at approximately 400m offshore, with the stern facing the shore. The pipe string will be welded on the barge and pushed out onto the stinger. Floaters will be installed on the pipeline at the stern of the barge. The pipeline will be pulled to the shore using either a 25MT pulling winch attached to concrete anchor blocks on the shore, or via a 1″ 0 cable snatched around a sheave block attached to the concrete anchor blocks and pulled in by the P5 anchor cable on the barge.
• The pipe string is designed to be floating on the water surface with the floaters. Once the start-up head has reached the shore position, the floaters will be removed by pulling a strip out cable to rip out the steel straps on floaters. The floaters will be collected with shallow water boats.
• To  ensure  correct  lateral alignment  of  the  pipeline,  appropriate  tension  assisted  with shallow water tug boats shall be used, depending on the actual site conditions.
• Once the floaters are removed and pipeline is on seabed, normal pipelay may commence.

SURVEY AND POSITIONING

The site has been surveyed by the CONTRACTOR’s survey subcontractor, and sufficient recovery marks have been placed to ensure the pipelines route through the beach crossing and tie-in to the OGT facility can be easily marked. Prior to starting work, the survey subcontractor will mark out, as a minimum, the followings:

• Site boundary
• Centre of pipeline o Excavation extents
• Offset elevation and position benchmarks
• OGT plant reference benchmarks

Following establishment of these points, the Civil and Earthwork subcontractor will handle the daily survey activities. This will basically involve the transfer of level and shooting the alignments based on the established horizontal and vertical control benchmarks.

SITE PREPARATION

The land equipment for the beach pull operation will be mobilized directly to the site. Once onsite, the excavators will clear the area and establish the site boundary, access road and erect the portable office cabins and containers.

Security guards will be provided at the temporary guardhouse and gate 24 hours. Only CONTRACTOR and SUBCONTRACTOR authorized personnel, equipments and materials are allowed access through the gate.

EQUIPMENTS AND MATERIALS MOBILIZATION

A partial inventory of necessary beach pull equipments and materials to be mobilized is as follows:

 

DESCRIPTION	SIZE	QUANTITY
FOAM BUOYS
Galvanised steel strap	0.6mm thickness x 19mm wide	5,600 m
Galvanised overlap seal clip	0.6mm thickness x 19mm wide x 25mm long	2,400 pcs
Wire rope sling	1″ 0 x 1DOOm length, IWRC 6×36 ungalvanized c/w 2 ft soft eyes both ends mechanical  spliced	2 nos
Norwegian buoy	24″ 0	8 nos
Plywood	12mm x 8′ x 4′	200 nos
Heavy duty plastic wrap	20″ x 800 ft per roll	88 rolls
Polypropylene rope	1/2″ 0 x 200m	5 reels
Shackle, Green Pin standard bow shackle with safety pin G-4163	12MT	4 nos
Closed spelter socket	1″ 0	2 nos
BEACH  PULL ACTIVITIES
Wire rope sling	1 Y4″ 0 x 15m length, IWRC 6×36 ungalvanized c/w 2ft soft eyes both ends mechanical spliced	6 length
Snatch block 431 Crossby, shackle type, bronze bushed	30MT, to suit 1 1/4″ wire rope size	2 nos
Shackle, Green Pin standard bow shackle with safety pin G-4163	25MT	8 nos
Wire rope sling	1 W’ 0 x 3m length, IWRC 6×36 ungalvanized c/w 2ft soft eyes both ends mechanical spliced	2 length
Shackle, Green Pin standard bow shackle with safety pin G-4163	85MT	4 nos
Norwegian buoy	24″ 0	4 nos
Heavy duty snatch block	150MT	3 nos

 

Shackle, Green Pin standard bow shackle with safety pin  G-6036	150MT	3 nos
Polypropylene rope size	1    “0 x 200m	3 reels

TEMPORARY ROCK BERM

A temporary rock berm will be constructed by CONTRACTOR. This rock berm will give access to the cranes during the trench excavation and beach pull operation. The final height of the rock berm will be approximately between 1.66m (min) to 2.66m (min). This is as shown in Figure 3.6-1.

TRENCH EXCAVATION

Soil from excavation of the trench shall be stockpiled to build the temporary rock berm. The details of the trench dredging works (by CONTRACTOR) are as shown in Figure 3.7-1 to Figure 3.7-6.

CONCRETE ANCHOR BLOCKS CONSTRUCTION

The construction of concrete anchor blocks will be undertaken by CONTRACTOR and the blocks will be installed on the west side of the tie-in position. The concrete blocks will provide anchoring points for the pulling of pipelines to the shore  and also for the barge deadman anchor during beach pull. Refer to Figure 3.8-1 to Figure 3.8-3 for detail drawings and Appendix 3 for design calculation of the concrete anchor blocks.

The methodology for the concrete anchor blocks construction is described as follows:

• Surveyors will determine the accurate location for the concrete blocks After the site has been confirmed by the surveyors, excavate the area according to the pre­ determined sizes as illustrated in Figure 3.8-2 and Figure 3.8-3.
• Lift and set the concrete blocks in the excavated area using crawler
• The concrete blocks will be backfilled until three-quarter full using the  previously excavated material and the ground is

The details of the concrete anchor blocks location and the rigging arrangements are illustrated in Figure 3.8-4 to Figure 3.8-7.

DLB ARMADA INSTALLER DEADMAN INSTALLATION

DLB Armada Installer will be positioned as close as possible to the beach in order to minimize the pipeline submerged weight. Hence the pulling force can be reduced with the assistance of foam buoys. Simultaneously this will provide barge stability during the beach pull.

The concrete anchor blocks for the Armada Installer deadman anchor will be installed at two locations as illustrated in Figure 3.8-6 and Figure 3.8-7. 55 and P4 anchor cables of the barge will be connected to those concrete blocks in which they will provide shore anchoring for the Armada Installer during beach approaching.

The followings  are step-by-step  procedure for  connecting  55 and  P4 anchor  cables  to the concrete blocks:

• A 25MT pulling winch is positioned in line with the temporary rock
• 1″ 0 polypropylene rope is connected to the 1 h” 0 pulling winch
• A fishing boat will be deployed to take up the end of the polypropylene
• The fishing boat will then carry the polypropylene rope towards DLB Armada This is to be done slowly to prevent the pulling winch cable from tangling up on the beach. Personnel onshore will assist to pay out the cable to prevent the entanglement.
• When the fishing boat has been arrived at the barge, the pulling winch cable will be transferred and connected to the 55 I P4 anchor
• The 25MT pulling winch will haul in to pull the 55 I P4 anchor cable to the The barge crew will assist to pay out the cable on the 55 I P4 anchor winch to prevent excessive cable dumping onto the seabed that would otherwise increase the drag and pulling forces. Large Norwegian buoys shall be attached to the anchor cable to provide additional buoyancy.
• When the connection point between the 55 I P4 anchor cable and the 1 Y,” 0 pulling winch cable approaches the shore, a crawler crane will pick up the connection point and transfer it onto the rock
• The 1 y,” 0 pulling winch cable will be unconnected from the connection point and then the 55 I P4 anchor cable is connected to a pre-installed 4″ 0 polypropylene rope to the concrete anchor
• After the connection between the 55 I P4 anchor cable and the 4″ 0 polypropylene rope is secured, the connection point is transferred from the rock berm into the water using the crawler
• The 55 I P4 anchor winch will be spooled in to take up tension between the 55 I P4 anchor cable and the 4″ 0 polypropylene

The above procedure is illustrated in Figure 3.9-1.

BEACH PULL PROCEDURE

GENERAL

This section describes the methodology of the beach pull operation for all  pipelines. DLB Armada Installer barge will be positioned at 400m from the shore. However site conditions may dictate the final position of the barge prior to the pipe pulling.

SURVEY AND POSITIONING

A DGPS based survey system will be used to determine the final position of the barge prior to the commencement of pipe pulling. The barge will be set-up with the centreline of pipe tunnel in line with the pipeline route, which is parallel to the rock berm.

When the barge has arrived at the specified location, a land-based theodolite may be used to observe the barge position relative to the centreline of the pipeline route, if required. Minor deviation in the heading and position may be expected and adjustment will be made to ensure the pipeline will be in the correct alignment.

BARGE SET-UP AND ANCHOR MOVES

This section details out the beach pull start-up operation for the following pipelines:

• 12″ 0 x 400m condensate pipeline from OGT to SPM (North).
• 12″ 0 x 400m condensate pipeline from OGT to SPM (South).
• 26″ 0 x 400m gas export pipeline from OGT to MCR·A.
• 12″ 0 x 400m condensate export pipeline and 4″ 0 MEG supply pipeline (piggyback for 12″ 0 condensate export pipeline) from OGT to MCR·A.

The start-up activities are listed below:

• Upon DLB Armada Installer arrival at the proposed location, set-up barge as per anchor pattern in Figure 3·1. Tension test shall be carried out for all anchor winches before setting up the barge at location.

Safety Note: SUBCONTRACTOR Marine Captain (MC) and Offshore Construction Superintendent  (OCS) to ensure proper coordination and communication between anchor  handling tugs and main work barge during anchor  handling activities and ensure all survey  and positioning equipment  in working condition and calibrated.  Reference for  anchor  positioning shall be made to the approved anchor patterns and pre-lay survey reports by SUBCONTRACTOR.  Limiting weather criteria specifications for all activities will be at SUBCONTRACTOR’s OCS discretion and governed by COMPANY’s marine guidelines  of  permitted  operations.

• At the end of Position 3 of anchor set-up in 4.3-1, bring alongside pipe haul barge on portside and transfer linepipes to the pipe rack and barge deck.
• Insert internal line-up clamp into the first pipe joint and commence welding the pipe until the first joint reaches Station 7. Stop trolley, x-ray crawler and reach rod should be inserted inside the pipes after 7 joints have been welded. Refer to Document No. SR-TKM­ WLD-GEN-01, Welding Procedure Specification.
• Reposition the barge at start-up However the actual position of the barge will be determined on site base on surveyor’s DGPS positioning.
• Continue welding until the start-up head and half joint is protruding on the stringer

Note: Double check on all valve systems with zero leak tolerance. Ensure ball valves at start-up head is in closed position.

The anchor patterns for the final position of DLB Armada Installer during beach pull using either Option 1 or Option 2 are as shown in Figure 4.3-2. These anchor patterns may be revised as required to suit prevailing conditions. The final anchor patterns are subjected to the discretion of SUBCONTRACTOR’d Marine Captain (MC) and Offshore Construction Superintendent (OCS), with approval from CONTRACTOR.

PREPARATION FOR PIPE PULL

After the final position of the barge has been confirmed by the surveyors, the following preparatory works will take place:

1) Pipeline String

The start-up head and beach pull section of the pipeline will be welded out in the pipe tunnel, radiographed, field joint wrapped with anti corrosion coating and filled with polyurethane materials.

Refer to Figure 4.4-1 to Figure 4.4-4 for the start-up head details of 12″ 0 OGT to SPM, 26″ 0, 12″ 0 MCR-A to OGT and 4″ pipelines respectively.

2) Attachment and Preparation of Pulling Cable

The pulling cable will be attached to the start up head. This can be performed at the stern of the barge or at the end of stinger, Refer to Section 4.5 for details.

3) Stinger

The stinger will be ballasted according to the profiles given in Table 4.4 1, in preparation of pipe pulling,

NO	PIPELINE	BER ELEVATION FROM SEABED (m)
	2 x 12″ Ql condensate pipeline from OGT to SPM	4.17
1
2	26″ Ql gas export pipeline from OGT to MCR A	4,17
3	12″ Ql condensate export pipeline and 4″ 0 MEG supply pipeline (piggyback for 12″ Ql condensate export pipeline) from OGT to MCR A	4.17

4) Foam Buoys

To maintain the anticipated pull force within  acceptable  limit, additional  buoyancy  will be provided to the pipeline using foam buoys installed at the stern of the barge using banding straps and clips The first floatation buoy to be attached is close to the start up head. The buoy size and numbers are given in Table 4.4 2.

Strip out cable shall be installed at the same time the buoys are installed (see details in Section 4.6).

Refer to Appendix 4 and Appendix 5 for the pulling force calculation for all pipelines and the foam buoy design respectively.

NO	PIPELINE	BUOY SIZE(m)	NO. OF BUOY/PIPE JOINT
1	2 x 12” 0 condensate pipeline from OGT to SPM	1 X 0.85 X  2.5	2
	26″ 0 gas export pipeline from OGT to MCR·A	1x1x2.5	3
3	12″ 0 condensate export pipeline and 4″ 0 MEG supply pipeline (piggyback for 12″ 0 condensate export pipeline) from OGT to MCR·A	1 X 0.85 X  2.5	3

 

BEACH PULL CABLE ATTACHMENT

The  followings  are  step-by-step  procedure  for connecting the  pulling cable  to  the start-up head.

Option 1

• A 25MT pulling winch is positioned in front of the concrete anchor
• 1″ 0 polypropylene rope is connected to the 1 Yz” 0 pulling winch
• A shallow water boat will be deployed to take up the end of the polypropylene
• The boat will then carry the polypropylene rope towards DLB Armada This is to be done slowly  to  prevent  the  pulling winch  cable  from  tangling  up  on  the  beach. Personnel onshore will assist to pay out the cable to prevent the entanglement.
• When the boat has arrived at the barge, the pulling winch cable will be transferred and connected to the start-up

The above procedure is illustrated in Figure 4.5-1. Option 2

• Connect 1″ 0 wire rope to the start-up
• Transfer the wire rope to a shallow water boat near the stinger, which in turn will carry the wire rope to the shore and eventually connected to the concrete anchor blocks through a 150MT snatch If necessary, use a 1″ 0 polypropylene rope as a messenger to bring the 1″ 0 wire rope to the beach.
• After going through the snatch block, the boat will take up the wire rope again and carry it towards DLB Armada
• Simultaneously, an AHT boat will take up the P5 anchor cable from the lay barge and carry it towards the The barge crew will assist to pay out the cable on the P5 anchor winch to prevent excessive cable dumping onto the seabed that would otherwise increase the drag and pulling forces. Large Norwegian buoys shall be attached to the anchor cable to provide additional buoyancy.
• When the AHT boat and fishing boat are side-by-side, the 1″ 0 wire rope will be connected to the P5 anchor
• The P5 anchor winch will be spooled in to take up tension in the anchor

The above procedure is illustrated in Figure 4.5-2. Figure 4.5-3 shows the final start-up head rigging arrangement prior to the start of beach pull operation.

The beach pull operation will be controlled from DLB Armada  Installer with communication to the onshore crew. Each pull will be initiated by the completion of welding, NDT and Field Joint Coating activities in the pipe tunnel.

FOAM BUOYS AND STRIP-OUT CABLE INSTALLATION

Low Density Closed Cell Polyurethane Foam buoys will be used to reduce the submerged weight of the pipeline during the beach pull. These buoys will be connected to the top of pipeline using steel banding straps and sealed with clips. A 1″ 0 wire rope strip-out cable will be pre­ installed through  all banding straps during the installation. The starting end of the strip-out cable will be spooled to a 5T air tugger located on top of the pipe tunnel at the stern of the barge, while the other end is shackled to a padeye on the start-up head. When being pulled, the strip-out cable will break the banding straps and release the buoys from the pipe string. The buoys will subsequently be recovered and returned to the lay barge. Refer to Figure 4.6-1 to Figure 4.6-4 for the installation method and Appendix 6 for the Product Datasheet of the Low Density Closed Cell Polyurethane Foam.

The foam buoys attached to the pipe string will be tied together in a train to ensure that they do not float away uncontrollably following the strip-out. Each of the two adjacent buoys in the train will be tied-up using polypropylene rope.

Each buoy in the train will be given a unique tag number to ensure all the buoys are accounted for following the strip-out process.

BEACH PULL ACTIVITIES

The following is a step-by-step procedure for performing the beach pull activity using either Option 1 or Option 2. At this point, the pipe string will be secured in the tensioners and set in a brake condition.

Option 1

• The tensioners are adjusted slowly to match the beach pull tension, while the 25MT pulling winch takes up the slack and tension up the 1 W’ 0 wire Refer to Table 4.7·1 for the tension required.
• When the appropriate tension has been reached, the tensioners brakes are  released and the  pipes  are  allowed  to  pay  This  can  be  done  in  a  manual  or  automatic  mode.
  Note: When the tensioners brakes are released to pay out the pipeline, make sure the tension on the 25MT pulling winch is adequate to pull  the  pipeline  out.  Otherwise  the tensioners  may haul-in the pipeline instead.
• When one joint has been pulled towards the beach, the brakes are set on the tensioners and the pipeline is
• One joint will be added up at the line up station and various activities at the other stations will proceed
• When the pipe tunnel activities have been completed, the brake is released and the pipe string is started to be pulled away the lay barge towards the beach
• The above sequences are repeated until the pipeline reaches the
  Note: During pipe pulling, to ensure the pipeline is in the correct route, a STair tugger may be placed on the shore for the purpose of pipeline alignment.

NO	PIPELINE	MIN. TENSION  (MT) NO CURRENT	MAX. TENSION (MT) 1 KNOT CURRENT
1	2 x 12″ 0 condensate pipeline from OGT to SPM	10	10
2	26″ 0 gas export pipeline from OGT to MCR A	10	12
3	12″ 0 condensate export pipeline and 4″ 0 MEG supply pipeline (piggyback for 12″ 0 condensate export pipeline) from OGT to MCR A	10	10

Option 2

• The tension on the P5 anchor winch is increased slowly to match the beach pull tension as shown in Table 7-1.
• When the appropriate tension has been reached, the tensioners brakes are released and the pipes are allowed to pay This can be done in a manual or automatic mode.
• When one joint has been pulled towards the beach, the brakes are set on the tensioners and the pipeline is
• One joint will be added up at the line up station and various activities at the other stations will proceed
• When the pipe tunnel activities have been completed, the brake is released and the pipe string is started to be pulled away the lay barge towards the beach
• The above sequences are repeated until the pipeline reaches the shore
  Note: During pipe pulling,  to ensure the  pipeline is in the correct  route, a  5T air tugger  may be placed on the shore for  the purpose of pipeline alignment.
• Note that the pull force may increase as more pipes are being paid An increase in the constant tension setting on the anchor winch may be required. However the  pipeline tension should be maintained at the tensioners according to Table 4.7-1.

When the start-up head approaches the shore, the crawler cranes parked on the rock berm will be positioned to lift the start-head up onto the designated landing point. This is as shown in Figure 4.7-1 to Figure 4.7-7.

When the start-up head reaches the end of the pull, a strict coordination between the beach and barge crews will be required to stop the pull operation.

STRIPPING OUT THE FOAM BUOYS

Upon completion of the beach pull operation and a confirmation that  the pipeline is in the correct route, the foam buoys along the pipe string will be removed and recovered by stripping out the banding straps holding the buoys to the pipeline. This activity will be carried out using the 5MT tugger. By pulling up the 1″ 0 strip-out cable, a force will be applied to each band, causing it to break. The followings are step-by·step procedure for this activity:

• The tensioners will be placed in a brake set condition to anticipate a higher pull force when the buoys are being stripped
• On the lay barge, the tugger begins to haul-in the strip-out cable and this will cause the banding straps to start
• The hauling in action of the tugger will strip”out the buoys from the start”UP head section of the When the strip”out process is complete, the strip-out cable can be recovered to the barge. The banding straps should remain fastened to the cable.
• The shallow draft tugboat can then be deployed to pick up the foam buoys The tag number on each of the buoy shall be recorded to ensure that all the buoys are removed and recovered.
  Notes: As a contingency  measure,  divers  with  SCUBA  replacement  equipments  can also be ‘     deployed to cut the bands manually and retrieve the blocks.

BEACH PULL COMPLETION ACTIVITIES

When  the  foam  buoys  and strip-out  cable  have  been  retrieved,  the  beach  cable  can  be recovered for the lay barge to proceed with regular pipe lay.

PIPE HANDLING, STACKING AND STORAGE

MATERIAL DELIVERY

Free issued line pipes of approximately 8 joints for each pipeline will be delivered to the site from a storage area in Kiyanly. Other free issued materials, for example, the pipeline bends and flanges will also be delivered in the same manner.

COMPANY’s supplied materials are as shown in Table 5.1·1 to Figure 5.1-4.

INSPECTION

A joint inspection between SUBCONTRACTOR, CONTRACTOR and COMPANY will be carried out at the stringing locations on site. Refer to the following  documents  for  further  details  on loadout  plan  and  other  related  information:

• Document SR-TKM-ENG-MCRA·OGT-P106  (Loadout   Coordination    Manual   for  12″ Condensate Pipeline from MCR-A to OGT and 4″ MEG Pipeline Piggybacked)
• Document    SR-TKM-OPR-MCRA·OGT -P207   (Loadout  Coordination   Manual  for   26″  Gas Pipeline from MCR-A  to OGT)
• Document SR-TKM-ENG·MCRA·OGT-P106  (Loadout    Coordination    Manual   for 12″ Condensate Export Pipeline OGT to/from MCR-A)

The purpose of the inspection is to check the line pipe conditions before and after deliveries. After checking, the inspection reports need to be signed off by all parties. The same procedure goes to the other free issued materials, such as  under and above ground pipe bends and materials for corrosion insulation.

PIPE TRANSPORTATION

Line pipes will be delivered  to the site using low loader trucks. CONTRACTOR will provide SUBCONTRACTOR with the delivery schedule. Therefore the pipe delivery, stringing and fit-up works can be coordinated effectively.

UNLOADING

A crane will be used to unload the line pipes piece by piece, using lifting belts. A reasonably sizeable crane is required for stability during movement. This unloading process is as shown in Figure 5.4·1 and Figure 5.4-2.

STORAGE AND STACKING

All line pipes will be stored in-line along ROW. Sandbag or timber will  be used  to protect  the line pipes from a direct contact with  the ground.

If  necessary,   line  pipes  will  be  stored  near  the  dedicated  storage  area  without  the  need  of stacking up the pipes.

PIPE STRINGING

INSTALLATION SEQUENCE

Stringing of pipes will be started upon completion of beach pull. Pipeline stringing will be carried out at the proposed ROW which is next to the temporary storage area outside OGT This is as shown in Figure 6 1 1 to Figure 6.1 5. The line pipes will be laid onto the ground on a piece by piece basis Where necessary, protection against yard applied corrosion coatings and bare pipe damage by sandbags will be done especially on hard or slopping grounds.

Refer to Figure 6 1 6 and Figure 6 1 7 for the anode installation details starting from the start up head landing point to the tie in valve

INSTALLATION OF PIPE AT AN OPEN TRENCH

The installation steps are as follows:

• The line pipes will be prewelded to two joints
• Upon completion and acceptance of NDT and Field Joint Coating, the line pipes will be rig up onto a crane and gradually lowered onto the open trench Timber blocks will be put at each end of the line pipes in the trench to support the pipeline and to facilitate the removal of lifting belts This is as shown in Figure 2 1.
• Fit up for tie in weld will be commenced
• Upon acceptance of the fit up inspection, the welding activity for the joint will

WELD, NDT AND WELD REPAIR

An externalline up clamp will be used to line up the line pipes The seam pipe will be supplied with a pre bevelled to 30 degree. All completed welds shall be subjected to 100% radiograph Project specification NDT procedure is detailed in the following documents:

• Document No SR TKM NDT GEN 06  (Provisions of General NDT Procedure for Pipelines (26″ OD I 12″ OD I 4″ Piggyback)
• Document No. SR TKM WLD GEN-01  (Welding Procedure Specification)

FIELD JOINT COATING AND REPAIR

Project specification Field Joint Coating procedure is detailed in the following document:

i) Document  No.  SR-TKM-OPR-GEN-10 (Field   Joint    Coating, lnfill   and   Coating    Repair Procedure)

The pipeline coating details are as shown in Figure 6.4-1 and Figure 6.4-2.