OTC 21209

Technical Challenges and Success for Rigid Pipeline with PLET, Jumper and Flying Leads Installation in Conger 9 Field Jun Wang, Rune Krister Hagen, Ecaterina Radan, and Jack Bullock, Subsea 7 Copyright 2011, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 25 May 2011. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract A 346 m long of 6 inch rigid pipeline with a Single Hub PLET (SHP) at one end and Double Hub PLET (DHP) at the other end was installed in Conger 9 Field for connecting existing Well No. 5 and future Well No. 9 in Garden Bank 215 N/2, Gulf of Mexico. The water depth at the location is approximately 457 m. Three jumpers with two M-shape (2D) and one Z-shape (3D) were installed for Conger 9 field expansion. Flying leads including two EFL and three HFL were also installed. The Well No. 9 was due online at the end of 2009. This paper will present the highlights of the technical challenges for Acergy Falcon to install the rigid pipeline shorter than water depth with one PLET at each end from the analytical and operation aspects and how the main challenges (e.g. relationship of PLET COG and yoke hinge location, installation stages vs vessel capacity, etc) were overcame. Meanwhile, the difficulties for jumper design and flying leads installation will be also highlighted in this paper. Conclusion, recommendation and lessons learned will be made. Introduction

The Conger Field is an existing subsea development comprising four wells (and one proposed) tied in to a central manifold located in approximately 1500ft/457m of water in Garden Banks 215 N/2. The manifold is then connected to the host platform by two piggable flowlines. Well No. 9 was connected to a four slot manifold which was already occupied by four wells. Therefore, Conger No. 9 well had to be combined with Well No. 5. Well No. 8 is 65 ft north of manifold, Well No. 5 is 65 ft southwest of manifold, Well No. 6 is 12,000 feet of manifold, and well No. 4 is 4,900 feet south of manifold. Both Well No. 6 and No. 4 tie back to SHP via a rigid flowline. The proposed fifth well in the development Well GB 215-9 (No. 9) is located approximately a quarter mile west-southwest of the manifold and its production flowline will terminate into a DHP near the existing manifold. Well No. 9 was due online at the end of 2009.

Figure 1 - Conger Field Layout

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The scope of work of the Conger 9 Project was divided into the following packages, and Acergy Falcon was nominated vessel for installation:

Design and Fabrication of PLETs and Jumpers Mobilization Installation of pipeline (6.625 inch OD API 5L X65, 356m long) with 2 PLETS Installation of three hydraulic flying leads and two electric flying leads Installation of 3 new rigid jumpers, and removing 1 existing one

The controls scope for well No. 9 included disconnecting Well No. 5 HFL, and adding New HFL from SUTA to new splitter, and reconnecting Well No. 5 HFL to Splitter, and installing Well No. 9 HFL. Install new EFL to Well No. 9 from SUTA. Installation Vessel Acergy Falcon is DP2 class installation vessel for both rigid pipeline and flexible installation. The pipeline will be installed by welding linepipe horizontally in a firing line on the deck of the ship and deploying through a lay ramp located at the stern. Acergy Falcon has six work stations in the production line. In addition, work can be performed at the work platform in the ramp (anode installation, laydown heads etc). Figure 2 below shows the vessel in side elevation view. The pipeline is laid in a J-lay configuration using a variably inclined ramp, which can be adjusted between 25.5 and 90. The pipeline leaves the firing line and passes under a deck radius controller, which guides the pipeline up towards the top of the lay ramp. The pipeline is then reverse bent to pass into the ramp where it passes through a pipe straightener. The straightener imposes a reverse curvature, such that the residual curvature in the line is zero.

Figure 2 Acergy Falcon Side Elevation View

Acergy Falcon fireline arrangement for pipeline installation as follows:

Station 1 - GTAW & FCAW Set-up Station 2 - FCAW Set-up Station 4 - AUT (Phased Array) Station 5 - Grit Blasting Station 5 Induction Heating Station 5 FBE Application & Holiday Detection Station 6 - PU Primer Application Station 6 SPU Injection & Mould Removal Ramp Workstation /PLET Frame Grit Blast + Liquid Epoxy Application

A list of relevant equipment on board the Acergy Falcon is as follows:

Main crane capacity = 64 te with 450 m of operating water depth Auxiliary crane capacity = 22.5 te Accommodates pipline from 4 inch to 12 inch 2 work class ROV with operating depth rating 3000m PHF A&R wire capacity = 254 te Ramp A&R wire capacity = 225 te Tensioner capacity =75 te

Pipeline Installation Strategy and Challenges Figure 3 Acergy Falcon PLET Design and Fabrication SHP was designed to allow connection of flowline to subsea well No. 9. DHP was designed to allow connection of flowline to

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the subsea well No.5 and central Cameron manifold. They included folding wing mudmats, foundation skirts, internal piping, skid and a yoke. The design premise stipulated by Acergy ensured that both PLETs could be interfaced with the Acergy Falcon PLET Handling Frame with minimal modification or change. Both yokes for SHP and DHP are able to rotate to 90 deg. The SHP was designed assuming a both first and second-end installation and included holdback padeyes for the purpose of attaching to the pre-installed anchor pile bridle. The DHP was designed assuming a second-end installation

(a) (b)

Figure 4 Illustration of (a) SHP and (b) DHP Systems

Key Issues/Developments/changes that took place during PLET Design are as follows: DHP skirt height was increased from 1/2 to 1 to lower the COG. The height of the connector hubs on the DHP were lowered to lower the COG. Height of Yoke Hinge raised by approx 8 above COG to mitigate against PLET and flowline over-turning during

deployment of DHP. Yoke rest angle changed to -9 degrees from horizontal to allow for straight pull to PLET Handling Frame wire

sheave. Sliding mechanism added to SHP to allow for flowline expansion and reduction of Jumper loading (included a skip

lock pinning feature for installation). Jumper reactions on PLETs were increased which resulted in a major change in PLET design. ROV pin details were changed from T-bar to Fish tail due to vessel preference. Skid lock detail on SHP was changed from threaded pin to regular pin to avoid pin being stuck due to shear load

during unlock operation. Anchor Flange design was finalized to have a full penetration weld between the piping anchor flange and the PLET

Anchor bulkhead.

Pipeline Installation Philosophy Due to pipeline length being shorter than the water depth, the conventional method of PLET installation (reliant on pipeline holdback) could not be executed. Therefore, the Pipeline and PLETs were installed using the following steps:

The pipeline was pulled though the lay system and straightening trials performed. The initiation head was welded to the end of the pipeline.

The pipeline was paid out from the ramp (set at 90 degrees). The laydown head was installed on the second end.

The pipeline was connected to the A&R winch and lowered through the water column.

The initiation head was connected to the initiation rigging. The pipeline was laid down along a temporary lay route (approx

100m short of the final laydown position and 0.5 degrees off the final lay route). The A&R wire was disconnected.

The pipeline end was recovered to the PLET Handling Frame (PHF) shown in Figure 5.

The SHP was installed and laid down with the pipeline along the temporary lay route shown in Figure 6.

A 13Te DMA and 60m long hold hack wire was connected to Figure 5 The PLET Deployment System the SHP.

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The main initiation wire was disconnected from the pipeline end and a make up sling added (though not connected).

The pipeline A&R head was connected to the PLET A&R Winch wire, the pipeline lifted from the seabed, SHP broken-out and lifted off the seabed and DMA disconnected.

The vessel transited to the other end of the line and SHP connected to the main initiation rigging (including make-up sling).

The pipeline end was recovered to the PHF. The DHP was installed. The DHP, Pipeline and SHP were laid down

in their final location shown in Figure 7. Figure 6 Pipeline & SHP Temporary Laydown Route To secure the flowline to Acergy Falcon after the recovery operation, the PLET deployment frame is equipped with a hydraulically operable hang-off clamp. Hydraulic cylinders are used to open and close the lock-off system as well as tilting it. Pipeline Installation Analysis The pipeline and PLET installation are done in a series of temporary laydown, recovery and permanent laydown. This is due to the vessel set-up where the firing line runs along the middle of the vessel and ends at the stern lay tower. However, the PHF is at the portside of the vessel, hence the pipeline and PLETs cannot be installed in one Figure 7 Pipeline & PLETs Final Laydown operation. The analysis was done in 7 stages described below to capture every stage of installation in the proper vessel lay configuration and location.

Stage 1- Flowline Initiation and temporary lay down (Figure 8) Stage 2 - Flowline recovery to portside PHF Stage 3 - SHP weld connection Stage 4 - SHP and flowline temporary laydown (Figure 9) Stage 5 - Flowline with SHP 2nd end recovery to PHF Stage 6 - DHP weld and connection Stage 7 - Final laydown of flowline with DHP and SHP (Figure

10) The flowline is modeled as rigid member with element lengths of between 3m to 0.5m depending on the location of the elements. Elements at sagbend and close to touchdown have finer mesh than elements in straight catenary. Figure 8 Pipeline Temporary Laydown (Stage

-50m

A&R/ Hang-off Head

Flowline

A&R/Hang-off Head

1)

ness.

The key components SHP and DHP are modeled as 6D buoys in the Orcaflex model. The hub skid model is assumed to be rigid without rotation along pivot during the lowering, and free rotation is allowed after PLET touches down seabed. The yoke in connection with either A&R winch or initiation wire is assumed to be able to free rotate during the entire operation. With this assumption, the model is much simpler with a bit of conservative The COG of the PLETs has a great impact on pipeline installation for two reasons: one is the COG vertical position (higher than yoke hinge axis) will cause PLET overturn, and other is the horizontal position (far away from PLET/pipeline interface connection) will result in high stress at the interface location (refer to Figure 11 for details). During the project execution, PLET COG had to be revised a few times to ensure the PLETs Figure 9 - SHP Temporary Laydown (Stage 4)

SHP

Flowline

A&R/Hang-off Head

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do not overturn or twist excessively during installation. The final solution was to get the yoke hinge point above the overall COG of the PLET with the wings in the closed position. During analysis, it was important to get the COG modeled correctly, not only in the horizontal position, but also the vertical position so that the stresses on the pipeline are accurate.

The SHP is designed as a hinged connection between the mudmat and the skid piping, which can rotate by 90 deg, shown in Figure 12. This function is important during the recovery of the pipeline with the SHP to weld on the DHP. The SHP recovery model was done in 2 levels i.e. global analysis and local analysis. In global analysis, the SHP is at about 10m off the seabed and Figure 10 DHP and Pipeline Laydown (Stage 7)

DHP

Flowline

SHP

it is raised in stages until the laydown head is at the hang-off clamp. In this model, skid piping is not allowed to rotate, which results in the conservative stress for pipe close to the SHP. The local

Figure 11 - Illustration of PLET behavior when COG is incorrectly designed Figure 12 Hinged SHP 90 degree Test

model (refer to Figure 13) is to examine the local effect of skid piping free rotation on pipe stress before off sea bed and after 10 m off seabed during the recovery.

(a) (b)

Figure 13 - SHP Recovery Snapshot by Orcaflex (10m off seabed); (a) before DEA wire is release; (b) After DEA wire is disconnected

igure 14 - Anchor Pull Test by Orcaflex load test and flowline and PLET installation.

The initiation wire is 550m (1804FT) long with additional 85m (279ft) to 100m (328ft) of 3 inch studless chain and wire to keep drag anchor in horizontal tension because of very soft soil condition.

The vessel is Acergy Falcon and is modeled with the PHF and stern ramp, the related RAOs and a draft of 6.49m (21.3ft). Prior to installing the flowline and PLETs, the Drag Embedment Anchor (DEA) was tested for holding capacity by applying a constant pull for a period of time. The aim of the test is to confirm that the anchored has bedded in and can hold back the expected installation loads without slipping. The

uplift at the anchor during Fassociated analysis shows that there will be no

Y

900m A&R Wire

Chain & Wire

550m Initiation Wire

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The load test target is 30Te and maximum allowable load is 35Te. The pull test was modeled in Orcaflex to determine the required length of the A&R wire and the limiting seastates to not exceed 35Te horizontal pull on the anchor. The illustration of the model is presented in the Figure 14. The offshore operation sea state window will be limited by the following criteria based on DNV-OS-F101 simplified lay criteria. For the sagbend section of the flowline, the combined static and dynamic loads equivalent stress (Von Mises) shall be less than:

Von Mises Stress 0.87 x SMYS

All acceptance criteria for the analysis scope are summarized in the Table 1:

Criteria Acceptance Code Basis

Von Mises Stress 390x103 kPa DNV-OS-F101Simplified Laying Criteria

Anchor Load 20 Te N/A Rigging design

Flowline Laydown Tension

35 Te N/A ROV Shackle

SHP and DHP Laydown Tension

80 Te N/A PHF Winch Capacity

Flowline Recovery with SHP Tension

60 Te N/A Recovery Head design

Table 1 Pipeline Installation Analysis Acceptance Criteria

Pipeline Offshore Installation The pipeline installation with SHP and DHP occurred over one trip. Overall, the offshore operations were conducted in a safe and efficient manner. No significant personnel injuries were sustained and all equipment was installed during offshore campaign. There were only two undesired event reports (UERs) issued during the operation. Appendix I presents the offshore operation photo log during the offshore operation. The offshore operation lessons learned will be discussed in the following Lessons Learned section. The following highlights two major offshore pipeline installation challenges: 30 Joint Handling - Linepipe was supplied to Acergy Falcon from Hess in 30 feet joint lengths (very limited pipe quantites, insufficient to cover any buckle incidents); the average joint length was 31.67 ft (9.65m). This caused problems in the following areas:

Pipe joints could not fit into U-Frames - all pipe joints were loaded into pipe skips The pipe handling Hiab cranes (beveling station) could not be used with their convention rigging set-up. Both ends of a joint could not be beveled simultaneously Weld Line-up the powered alignment roller in Station 0 could not be used. Static rigging had to be used instead. Individual pipe joints could not be fed down the line with out the use of rigging support. Joint positions in Firing Line Stations were set up as follows: Line-up, Root/Hot-pass & Fill Station 1 Fill & Cap Station 2-1/2 AUT Station 3-1/2 or Station 4 Grit-blast, Pre-heat, FBE, IMPU Prep. Station 5 IMPU Infill Station 6 Due to weld positions activities in Station 6 had to be performed independently to all other stations. Therefore, the

overall cycle time was compounded over 2 pulls.

Pipeline GSPU Coating Bonding Issue - Prior to mobilization it is normal practice for insulated pipe projects on the Acergy Falcon to have sections of coating removed from the joints that will be used for pull-through and straightening trials. This helps on the vessel when removing the cut pipe sections from the ramp. This is normally performed by using a circular saw to cut 2 circumferential cuts and 2 longitudinal cuts and then using an induction coil to dis-bond the FBE to GSPU interface. 6 joints were received from Hess (who free-issued the coated linepipe to Acergy). These were sent to field joint coating subcontractor (FJCS) to perform the work. After three pulls test at FJCS facility, it concluded that the required shear stress at the Hang-off clamp is only around 47psi which is way below the minimum shear stress of 300 psi stated on the GSPU data sheet. A series of further tests were conducted at Stress Engineering, Project agreed with Hess that the safest way of handling the linepipe in the Acergy Falcon Lock-off Clamp would be to grip onto an uncoated area. Therefore, sufficient coating was removed in the ramp workstation (approx 3.5m) prior to laying down the pipeline. Because of this, the Lock-off clamp shoes that were fitted for lay were sized for un-coated pipe.

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Jumper Installation Challenges Three jumpers were designed and installed for Conger field well No. 9 expansion. The total length of each jumper was 65 ft, 43 ft and 71 ft long in nominal, respectively as described below. All of three jumpers were flooded for installation.

Jumper No. 1 - 6 (65-ft long) vertical connection rigid jumper to the DHP and corresponding vertical hub connector on the Well No.5.

Jumper No. 2 - 6 (43-ft long) vertical connection rigid jumper to the DHP and corresponding vertical hub connector on the Central Conger Manifold.

Jumper No. 3 - 6 (71-ft long) vertical connection rigid jumper to the SHP and corresponding vertical hub connector on the Well No. 9.

In addition, the scope also included removing and recovering one existing jumper. Jumper Design and Fabrication All jumpers were originally designed with a 2D in-plane M configuration and a minimum of 4 ft above sea floor). No ROV access through shoulder is required.

However, as the project was progressing, 3D designed jumper No 2 with Z-shape shown in Figure 15 was proposed to avoid the ROV interfering with the jumper during installation of flying leads nearby (see Figure 16), and also allow to access to manifold ROV panel. The beta angle of jumper was calculated based on the worst scenario of DHP possible location in target zone to ROV working space. Note that because 3D jumper has more flexibility than 2D in-plane jumper, lower stress and load are expected if the shoulder and leg lengths are same as 2D jumper.

Each jumper design has been checked for acceptable yield stress, collapse buckling, vortex induced vibration (VIV) and Figure 15 3D Z-Shape Jumper No.2 Configuration connector load criteria against the following requirements:

Functional requirements (weight, pressure, thermal expansion/contraction)

Environmental conditions (wave and current) Physical constraints (geometry and dimension) Installation tolerance which causes CVC

misalignment due to measurement metrology and fabrication inaccuracy

PLED (Manifold) and Manifold differential settlements, after the jumpers are installed.

Jumper length variation and orientation have been considered based on PLET installation target box (see Figure 16) and allowable load on PLET. This is a trial and error process Figure 16 Plan View of Jumper No. 2 between jumper design and PLET design. Jumper loads on PLET have to meet the PLET design criteria, and vice versa PLET design has to restrict jumper configuration design. Figure 17 shows the modified DHP/jumper No 2 targeted location during the execution of project for mitigating the load on DHP due to thermal expansion along pipeline route. The following load cases were considered in the jumper design by using Caesar II software:

Surface hydro test case (weight and internal pressure, CA=0) Jumper hook-up case (weight, buoyancy, drag,, installation tolerance,

CA=0) Subsea Leaking test case (weight, buoyancy, drag, internal pressure,

hydraulic expansion, installation tolerance, CA=0) Operation case (weight, buoyancy, drag, internal pressure, installation

tolerance ,thermal expansion, long term settlement, CA) Figure 17 Modified DHP Location Fatigue case (VIV check)

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After PLET was installed, metrology data (surge, roll and pitch at each end) conducted using EHF acoustics were obtained and analyzed for generating jumper final fabrication drawing based on the following calculations at the either end:

Differential surge at end = Surge_p Surge_m Differential roll at end = Roll_p Roll_m Differential pictch at end = Pitch_p Pitch_m

where subscripts p and m represent PLET end and Manifold/Well end, respectively. The vertical distance between hubs was also measured by ROV placing a Digiquartz at the hubs.

Figure 18 Jumper Final Cut

One or more fabrication cuts were required to meet the metrology data resolved at the either end depending on magnitude of roll and pitch angles from metrology by applying 2 deg rule per ASME B31.3. Only one end needs meeting the above calculated metrology results since this is a relative value between two ends (see Figure 18). The fabrication acceptance criteria are based on the following formula:

Rotation = R (max reading min reading + 0.5 deg) Length = L (max reading min reading + 0.5 inch)

where R is total tolerance of metrology + fab in rotation assumed in the analysis; L is total tolerance of metrology + fab in length assumed in the analysis. Jumper hydrotest stand setup was based on metrology data at each end, i.e. test hub Figure 19 - Jumper No.1 under SIT rientation at each end was exactly same as field situation. Figure 19 shows the jumper No.1 was experiencing SIT. It is worth to note that jumper metrology was completed with Well No. 5 jumper still in place and producing. Jumper Mobilization and Installation The jumpers were transported to the field on supply boats after hydrotest. Jumper No. 3 went out to the field first, with a Project Engineer to assist with the lift and as the point of contact between the Acergy Falcon and the supply boat. Jumpers 1 and 2 went out to the field in a separate supply boat (see Figure 20)with another Project Engineer. The jumpers were pre-rigged to the spreader bar and the running tools were attached.The Cameron jumpers required an HPU as well as a technician onboard the supply boat to undock the running tools from the transportation hubs. The Acergy Falcon crane was used to lift the jumper and spreader bar and deploy it subsea. Once the jumper was landed and locked, the spreader bar was recovered to the Falcon. The back seal test was conducted at each hub and the running tools were Figure 20 Jumpers Were Transported to recovered. The insulation shrouds were then installed around each hub. Field Jumper lowering installation analysis was conducted by applying Orcaflex (see Figure 21) to ensure the integrity of the structure, the standard operations criteria were respected:

Maximum load below maximum crane capacity DAF smaller than 2 (i.e. hoist and slings not slack) Top tension below wire SWL Maximum stress in pipe below maximum allowable

stress Both jumpers tilted 3 degrees and various payout speeds (sensitivity) were investigated to determined installation sea states window. Figure 21 Jumper lowering Analysis by Orcaflex Snapshot

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Flying Leads Installation Challenges

There are three separate hydraulic flying leads with respective length of 200ft, 1800ft (by Aker), and 5900 ft (by Duco) that were installed individually using a horizontal lay system. There are two separate electric flying leads that were installed individually using two different methodologies. Two were spooled off a Deepdown carousel and over a chute and the starboard side; the other was piggybacked to a jumper. HFL Installation The hydraulic flying leads (HFL) were transpooled onto the Acergy Falcon carousel at the quayside in Galveston. The first end was brought out of the carousel via the crane. The crane guided the first end up and over the radius controller, and through the tensioner. At this point the tensioner was closed around the product and guided to the overboarding chute. Here the crane was disconnected, the buoyancy modules were connected, and the first end was deployed. The second end was brought out in the same fashion. The whole line was laid out on the seabed first and connected onto the structures at where the sequence allowed for a more efficient timing. The HFL installation analysis was performed in 4 stages:

Lowering of the HFL First end cobra head landing and lay away Normal lay (for the long HFL) Laydown of the second end cobra head

For the short HFL (200ft), the 1st end and 2nd end installation are performed in a Figure 22 Short HFL deployment single continuous analysis shown in Figure 22. For the 1800ft length HFL, there is a very short stage of normal lay. Because top tensioner capacity was limited, three buoyancy modules were proposed to install with HFL to relieve the top tension. Each module has 140 kg of lift force (existing and only available) and was distributed at 100m, 150m, and 200m from the 1st end cobra head. The distribution separation was carefully designed based on calculation for the best configuration without violating pipe MBR. Figure 23 shows 1800ft HFL laydown with floatations. Since 5900ft length HFL has a lighter submerged weighted (80% of 1800ft HFL), the pipe top tension no longer posed an issue to tensioner. Figure 23 1800 HFL Laydown EFL Installation The electrical flying leads (EFL) were transpooled onto two separate carousels. A RDS (reel drive system) was used to deploy the product subsea. The crane was used to transfer the termination head box (ETH) out of the carousel and over the over-boarding chute. As the product was paid out, the line (black in color) was spray painted with white markings to allow for better visualization subsea. The second end was transferred to the overboarding chute with a combination of the crane and winch movements, using a yale grip as holdback aid. The whole line was laid out on the seabed first and connected onto the structures at where the sequence allowed for a more efficient timing.

Since EFL has a small diameter (26.14mm) with weak bend stiffness (0.043 KN.m2) and no bend stiffener between EFL and ETH as well, a conventional initiation method (directly link initiation wire to ETH ) was not working for two reasons: one is kinking pipe (allowable MBR =1.0m) when ETH landing on seabed, and other is high tension on pipe (allowable tension =11KN); instead a 100 kg of sandbags was proposed to install with the termination head to avoid pipe kinking when it was launched through the splash zone, and the ETH was upended by ROV when it was off sea bed around 10-20m, then landing on seabed softly by hooking up with 200kg clump weight to hold the pipe for completing initiation. Figure 24 shows the ETH initiation process by Orcaflex snapshot. Similarly, EFL 2nd end was deployed down to 20 m off seabed, then using ROV hold ETH to finish the installation. The designed sea state was 2.0m of Hs with 1.0 knot of surface current. Figure 24 EFL initiation This methodology has been later proved very efficient and successful in offshore campaign.

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Lessons Learned The following are some highlights of lessons learned from the engineering and design to the offshore operation for this Project:

A test fit of all equipment to be connected subsea should be done. Ensuring proper fits of equipment will save on critical path time.

The method of deployment should be taken into consideration when talking to suppliers. High pressure hosing for pre-commissioning should be packed for deployment, either spooled onto reels with end fittings accessible or in a basket.

When jumper stabbing into an existing piece of equipment a heave compensated crane or winch can be beneficial in reducing installtion duration.

During transpooling it would be advantageous to spray paint (as necessary) black products with white markings for EFL better visibility subsea.

Layout of the mudmat and mudline should be included in the survey drawing for proper jumper leg design to prevent from numerous attempts of jumper fit-up.

The Yale grip should be used on all projects because of its wide variety of holdback uses (i.e. flexible pipe, umbilicals, HFLs, EFLs) based on Subsea 7 past experience on varity projects.

Conclusions The Acergy Falcon has successfully installed 1169.2 ft (356.4m) of 6.625 inch OD API 5L X65 rigid pipe, 2 PLETs, 3 hydraulic flying leads, 2 electrical flying leads, 3 rigid jumpers, removing 1 rigid jumper, and disconnecting 1 electrical flying lead, and 1 hydraulic flying lead; especially, pipeline and PLETs installation is within 1 ft of target location in 1500 ft of water depth. The entire operation was last 28 days. Overall offshore operations were conducted in a safe and efficient manner with an excellent interface and a lean decision making process. No significant personnel injuries were sustained and no damage to Acergy or Client equipment was encountered. Acknowledgement Authors wish to thank Subsea 7 pipeline lead, Graham Mackay, for his leadership and contribution in preparing pipeline installation procedures and executing offshore operation. Many thanks go to Sanjay Parikh, Selva Subramanian, Brain Elliott and Edgar Uribe for their diligent work in PLET design and pipeline installation analysis. Thanks also go to all team members for their great efforts to make this project success. Special thanks extended to project manager, Tom Borresen for his leadership and management in this fast track project. Additional thanks to Hess project responsible Tor Gavem and his team for providing a strong one team atmosphere. It is also acknowledged the generous support from Subsea 7 management and Hess managements to publish this paper. Nevertheless, this paper reflects the opinion of its authors and do not imply endorsement by companies to which acknowledgments are made.

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Appendix I Offshore Operation Photo Log

(a) (b) (c) (d)

(e) (f) (g) (h)

(i) (j) (k) (a) pipeline is welding; (b) Pipe pull-though; (c) PLETs on PHF; (d) SHP is launched; (e)SHP near seabed; (f) DHP is connection with pipe on PHF;(g)DHP is launched; (h) DHP is landing with wings down; (i) Cameron shroud on DHP jumper; (j) HFL 1st end through radius controller; (k)Cobra head engaging in structure

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