Cost Effective Innovations in Riser Installation

Jack Pollack, Vice President of Corporate Research and Development, David Riggs, Development Engineering, SBM-Imodco, 1255 Enclave Parkway, Suite 400, Houston, Tx., 77077.

ABSTRACT Deepwater pipeline integrity and cost can be improved with two recently developed approaches in pipeline installations: The Gravity Actuated Pipeline (GAP) system, and Riser Self-installation from FPUs/FPSOs (Floating Production Units / Floating Production Storage and Offloading). The GAP is a bundled mid-water pipeline composed of horizontal rigid pipes. It is neutrally buoyant, and it is held at relatively shallow depths by a counter weight system. The system operates in warmer water thereby mitigating waxing and hydrate formation due to temperature and pressure differentials. The GAP also allows pipelines to traverse rugged seafloor conditions and canyons, which eliminates the need for free span corrections. The second innovation provides for the self-installation of steel risers onto FPUs/FPSOs in deepwater. This paper summarizes a study where Steel Catenary Risers (SCRs) are assembled on the host vessel and pulled out by a tug for lay down and connection to wellheads or pipelines. Self-installed risers are less vulnerable to damage because of the stability of the host vessel. Riser installation may also be mobilized at any opportune time during field development in optimal weather windows. GAP SYSTEM A recent pipeline innovation is the GAP system that is a neutrally buoyant pipeline bundle that is horizontally suspended beneath the ocean surface. The GAP bundle provides for the transfer of fluids in deep water between two production facilities such as an FPSO and Dry Completion Unit (DCU). This is accomplished by bundling multiple rigid pipelines onto a larger carrier pipe. The carrier pipe acts as the structural member that is sized to keep the entire pipeline bundle near neutral buoyancy and stabilized beneath the surface. The carrier is supported at each end by angled chains connected to the production facilities and is tensioned by counterweights suspended below the angled supports. The angles of the support chains in conjunction with the vertical loads of the counter weights provide passive tensioning of the GAP. Flexible jumpers at each end connect the rigid pipelines to the production facilities (see Figures 1 and 2). Conventional deepwater pipelines that are laid on the seabed are subject to lower temperatures and pressure gradients. These conditions can cause waxing or hydrate formation resulting in pipeline blockage. Because the GAP system locates the lines in relatively warm and shallow water, the need for pipeline insulation or active heating is greatly reduced. The pipelines are also shorter since they do not travel to the sea bottom and back to the surface. This makes it possible to transport well production fluids over several kilometers with improved flow assurance. Figure 3 shows how two or more DCUs producing from distant fields may be connected to a centrally located FPSO. The produced fluids would be transported from the DCUs to the FPSO for processing and storage. Processed oil would then be offloaded to tankers at a CALM (Catenary Anchor Line Mooring) buoy approximately 2 kilometers from the FPSO. An added benefit of the improved flow assurance of the GAP is the elimination or reduced needs for separation equipment on the DCU topsides. This makes it possible to utilize the weight savings and topside space for additional riser production. DETAILED STUDY – 30 KM GAP The GAP fluid transfer system was studied for conditions in offshore West Africa where an FPSO and DCU would be connected over a distance of 30 kilometers. This configuration was considered to be an extreme case for gathering fluids from satellite fields in a water depth of 2500 meters. The 30-kilometer GAP would consist of four 7.5-kilometer lengths that are in turn supported and moored by three submerged Buoyant Mid-Water Supports (BMSs). These BMS connections are necessary to control the pipeline vertical movements (hog and sag) due to density variations in production fluids and lateral excursions due to cross currents (see Figures 4 and 5). The use of 7.5-kilometer GAP lengths would also facilitate tow-out. This is consistent with existing towing technology and tug bollard capacities. GAP Bundle and Vessel Data The GAP bundle was configured onto a 40-inch carrier pipe with two 10-inch oil lines positioned symmetrically at the outer and lower extremities of the bundle supports. Two 8-inch gas lines were positioned in the supports just below the carrier pipe neutral axis, and a third gas line was located underneath the carrier pipe adjacent to a control umbilical (see Figure 6). 2-D Computational Fluid Dynamics (CFD) analyses were carried out on this bundle configuration to determine the normal lift and drag coefficients of the carrier pipe (see Figure 7). The carrier pipe and pipelines were subjected to horizontal and vertical transverse flow using four different Reynolds numbers. The moment induced by the flow force and its point of action were also calculated.

It was assumed that the 30-kilometer bundle was connected to an FPSO and DCU that would be spread-moored in taut leg configurations. Loaded displacements of these vessels would be 400,000 and 350,000 tonnes, respectively, for the FPSO and DCU. GAP ANALYSES To perform the GAP analysis, an analytic model was built of the GAP system. The overall system included the: FPSO, DCU, their mooring systems, vertical chain connections, clump weights, the four 7.5-kilometer bundles and three BMS buoys with their moorings. This model was run both statically and dynamically in the time domain using the ORCAFLEX offshore/marine systems analysis suite. The bundle was modeled as an equivalent single pipe with the hydrodynamic properties of the bundle and mechanical properties of the carrier pipe. This modeling resulted in proper hydrodynamic behavior and provided conservative carrier pipe stresses since the rigidity of the flow lines are small in comparison to the carrier pipe. Quasi-Static and Dynamic Results The system model was subjected to 100-year current profiles in 3 directions at 0, 45 and 90 degrees to the GAP longitudinal axis. Figures 8A and 8B show the effects of orthogonal currents on the GAP system with the piping fluids at their operating density. Such currents result in offset and set-down of the GAP at the BMS buoys, which can be seen in the elevation view. At mean operating densities the GAP was designed to be neutrally buoyant at a constant depth of 117 meters. However, density fluctuations and/or currents cause the GAP to move toward different vertical or horizontal positions. A detailed dynamic analysis of the mid-water GAP system, with the FPSO and DCU dynamic motions included, was performed for 100-year currents and waves. The analyses were performed for several combinations of current and wave directions in 45-degree intervals. A regular wave approach was employed using the 3-hour maximum wave height from the wave spectra. The dynamic analyses showed that the maximum tension in the GAP carrier pipe was 1240 tonnes. This was for the FPSO and DCU in their “far” offset positions while the pipeline bundle was in a neutrally buoyant condition. This load case also caused the highest stress in the carrier pipe (164 Mpa). Also, as expected, the maximum hogging and sagging conditions were associated with minimum and maximum fluid densities, respectively, while the vessels were in “near” offset positions. The results of the analysis showed that the GAP system varied in depth from 67 to 304 meters from a mean depth of 117 meters. VIV and Fatigue Analyses Calculations were performed to assess local VIV (Vortex Induced Vibration) within the pipe bundle. Based on those results, the maximum allowable pipe free spans were determined to be 24 meters for the 8-inch pipes and 29 meters for the 10-inch oil pipes. Since the pipelines were clamped at 12-meter intervals, VIV was not a design issue for the individual pipelines. A preliminary analysis of the entire bundle was also performed to assess in-line and cross-line VIV lock-in and the associated stresses. Current velocities ranging from 0.25 to 1.5 m/sec were considered at various GAP pretensions (assumed constant along the span). Since the axial and bending stiffness of the satellite pipes were small compared to that of the carrier pipe, the natural frequencies of the bundle were assumed to be the same as the carrier pipe. It was found that current velocities up to 0.5 m/sec induced stresses below the endurance limits for the pipeline material. Higher current velocities would likely increase the sensitivity of the carrier to VIV damage; however, velocities greater than 0.5 m/sec are only encountered above the 70-meter maximum hogging depth. The need for a more detailed VIV analysis was therefore identified. Fatigue analysis of the carrier pipe was performed by analyzing several combinations of typical West African wave and swell data. The fatigue life was calculated around the carrier pipe circumference using the API X' curve and a stress concentration factor of 1.2. The minimum life was found to be 1047 years. The maximum fatigue damage was located near the FPSO connection where vessel motion caused the highest pipe bending stresses. The fatigue life plotted along the span near the FPSO is shown in Figure 9. FABRICATION AND INSTALLATION OF THE GAP The preferred fabrication method of the GAP bundle would be to construct the bundle onshore in a yard similar to a spool base. Conceptually, coated pipe would be welded, assembled into a bundle and then pulled offshore by a moored winching barge. The barge would be progressively moved further from shore as the GAP bundle is extended to the full 7.5-kilometer length. This process would then be repeated for each of the four 7.5 kilometer GAP bundles (see Figure 10). Typical shore fabrication equipment would consist of:

• Line-up stations for the initial assembly of the pipelines; • Longitudinal conveyors for the movement of pipelines; • A back- tensioning winch to maintain bundle tension; • Transverse pipeline conveyors;

• Individual firing lines for welding, nondestructive testing and field joint coating: • Bending shoe rollers to guide the flow lines into slots for clamping to the carrier pipe and • Bogey wheels on a track to support the GAP bundle to the shoreline.

Launching and Tow-out As the GAP bundle is fabricated it would be winched toward the beach while supported on a bogey wheel track. A winch wire connected to the onshore end of the carrier pipe would hold back-tension on the bundle assembly. Temporary buoyancy and anodes would be added to the completed bundle while final inspection is performed along the track. The bogey wheels would be removed just before the bundle is pulled off the beach and into the water. The completed 7.5-kilometer bundles would then be stored and hydrostatically tested in sheltered water prior to tow-out. Tow-out operations would commence when the BMSs are installed at the towing depth along the 30-kilometer GAP route. Two tugs would recover the GAP towheads from their stored location and tension the bundles into a towing configuration. A support vessel would survey the bundle to ensure that towing buoys are in place and not fouled along the bundle length (see Figure 11). Towing tensions would be monitored by the tugs while a support vessel would monitor the bundle depth via transponders. Once the bundle is towed into deeper water, towing conditions would be stabilized at the transit towing speed of approximately 3 to 4 knots. Installation Offshore On approaching the installation site, the GAP bundle would be brought to a complete stop while maintaining the towing configuration. The first GAP bundle would be installed at the FPSO in order to link the GAP to a fixed mooring system. The support vessel would then assist in transferring pull-in lines from the BMS receptacle to the GAP carrier pipe. The carrier pipe would be pulled into the first BMS receptacle thereby activating a passive latching system. The same procedure would be repeated for all BMS and GAP bundle connections. The remaining three bundles would be installed in sequence, working from the FPSO, until the final connection is made at the DCU. The counter weights would then be connected to the carrier pipe at the extreme ends of the GAP. The entire 30-kilometer GAP would be stabilized in tension when the weights are lowered to their final position. Flexible jumpers would be installed from their pre-rigged locations on the BMSs using an ROV (Remote Operated Vehicle). The “Flexconnect” system would be employed whereby a specially equipped ROV would grab the ends of individual jumpers and winch them into the porch connection sites on the carrier pipe. Similar procedures would be used for connecting the pipeline jumpers to the FPSO and DCU. GAP ADVANTAGES The GAP fluid transfer system offers the possibility to link two deepwater floaters while minimizing the impact of flow assurance, i.e., wax or hydrate formation, potential energy loss, slugging, etc. Features that make the GAP a practical solution for this use are the following:

• Any number of pipes can be put in one bundle configuration; • Bundle can tolerate large density fluctuations in individual pipes; • Pipe operating water depth can be in desired pressure and temperature regimes; • In multiple spans there is no practical limit on length between floaters; • Bundle can tolerate pipe differential thermal growth; • Pipes can be insulated to prevent heat loss; • No diameter limitations for individual pipes; • Individual pipes are accessible and easy to inspect; • Bundle is fatigue resistant; • Bundle fabrication is onshore; • Bundle is easy to tow and install and • The overall system is composed of proven components.

SELF-INSTALLED STEEL RISERS ON FPU/FPSOs Deepwater field developments usually consist of a several subsea wells connected by steel flow lines that are tied back to FPUs (Floating Production Units). On the seabed, steel jumpers typically connect the wellheads to nearby PLETs (Pipeline End Terminations), which are in turn connected to the pipelines running along the seabed. Once the pipelines are near the FPU, they become “risers” as they are elevated from the seabed to the FPU on the surface. A simple riser system is an SCR that forms a sagging catenary shape between the FPU and seabed. The termination of the pipeline on the FPU is usually by means of a flexible joint in a receptacle. The bottom end of the SCR simply converges with the seabed at a region called the

Touch Down Point (TDP) and is free to lift up and down with the vessel. A conceptual arrangement of SCRs connected to an FPU is shown in Figure 12. FIELD DEVELOPMENT The wells in a subsea development may be spread-out and separated by several kilometers from a centralized FPU. Considering that there is at least one pipeline for each well, this can result in hundreds of kilometers of pipe on the seabed. These pipelines are normally installed by pipe lay vessels that can deploy a pipe string from the surface to a designated pipe lay route on the sea bottom. Pipe lay vessels can cost millions of dollars to mobilize, and once on location, these vessels have working rates exceeding one or two hundred thousand dollars per day. Because a large deepwater field may take years to fully develop, there can be several mobilizations of lay vessels to connect the wells to the FPU according to drilling and completion schedules. ADVANTAGES OF J-LAY FROM THE FPU A more cost effective solution is to self-install the pipelines and risers from the FPU using pipe lay equipment that is used on lay vessels. In this concept, a J-lay tower is mounted on the deck of the FPU that can deploy a pipe string at a controlled near-vertical angle (see Figure 13). As the pipe string is extended from the J-lay tower it is pulled out by a Dynamically Positioned (DP) tug capable of computer-controlled movements and station keeping. The DP tug position and movement may be programmed with respect to a Global Positioning System (GPS) or transponder array located on the seabed. Instead of moving the lay vessel with respect to the pipeline, the FPU remains stationary as the pipeline is dragged outward from the FPU towards a subsea well or tie-in location. The economic advantageous of this installation method would be realized through:

• The elimination of lay vessel mobilization and associated day rates during field development; • The utilization of lower cost pipe lay equipment and DP tugs that are usually available; • Less standby due to weather since pipe lay would be conducted from a larger and more stable FPU platform; • On-demand pipe lay as wells are completed so that production can be realized immediately and • The use of modular J-lay equipment that can be utilized on other FPUs as needed.

Further economic advantages may also be gained by using mechanically connected risers in lieu of conventional welding. Fatigue-rated connectors are now available for dynamic riser applications in lieu of conventionally welded pipe. This method of connection can be 10 times faster than welding, and the mobilization of welding and nondestructive testing crews in the field can be avoided. SCR INSTALLATION STUDY

A detailed study was performed to validate the self-installation of pipelines and SCRs from an FPU. The study considered a scenario where a 10-inch pipeline is laid from the FPU in a water depth of 2000 meters. The OFFPIPE program was utilized which is a sophisticated FEA computer program developed for structural analysis of risers and offshore pipelines. It was assumed that the J-lay tower is capable of laying 24-meter double joints from 0 to 10 degrees from vertical, and the bollard pull of the DP tug is 250 tonnes. Several steps in the SCR pullout operation were identified and analyzed. These steps in the order of their execution are listed as follows:

• Transfer of the pullout wire, • SCR initiation, • Stabilizing the pipeline on-bottom, • Pipeline pullout, • PLET lay down and • SCR pull-in.

Monitoring and control of the pullout process would be performed on the surface by keeping track of a several parameters. This would include: the relative position of the DP tug from the FPU, the monitoring of the pullout wire and pipe string angles, the determination the pullout wire length deployed from the DP tug, and the measurement of loads on the pullout wire and J-lay tower. Subsea monitoring of the pipeline position, Touch Down Point (TDP) and pulling head locations would be performed with an ROV. This vehicle would normally be tethered on the FPU, DP tug or on a separate ROV vessel. Transponders would be attached to the ROV and locations along the pipeline to verify pipeline movement and position. This system would allow the accurate verification of points along the pipeline within a few meters, over a distance of several kilometers. Pipe String Initiation

A double pipe joint 24 meters in length would be suspended from the J-lay tower with a pulling head. The pulling head is a structural member that transmits the tension forces to the pipeline and provides a welded bulkhead seal. This keeps the pipeline from flooding and thereby minimizes the pipeline weight. The initiation sequence is shown in Figure 14 where the DP tug is alongside the FPU and transfers a winch wire to the J-lay tower. The wire would then be attached to a pad eye on the pulling head. The offset positions of the tug, wire length and topside angles were sequentially analyzed so that the catenary length of the pipeline could be increased and gradually brought into contact with the seabed without over-stressing the pipe. As noted in this figure, the DP tug receives the pullout wire at Point A and then advances through Points B and C, suspending the pipeline in a full catenary. Further tug offset and pipe lay sets the pipeline down on the seabed in 2000 meters water depth when the tug reaches Point D. During the initiation process the departure angle of the pipe from the J-lay tower is maintained near 10 degrees from vertical. Likewise, this is the approximate angle of the wire from the tug. When the tug reaches a distance of 1932 meters from the FPU, with 750 meters of wire paid out, there is 140 meters of pipe laid on the seabed. The tug would then remain in position at point D while 100 meters of pipe is deployed from the J-lay tower. This reduces the pipe exit angle at the J-lay tower and improves the pipeline on-bottom stability by laying 425 meters of pipe on the seabed. The resulting J-lay angle of 6 degrees from vertical is then sufficient to prevent excessive TDP stresses during pipe lay. Pipeline Movement on the Seabed Pipe lay using the pullout method may begin after the on-bottom length is adjusted and stabilized. During this process the DP tug moves forward to increase the pipeline bottom tension. This in turn overcomes the longitudinal pipeline frictional resistance and SCR bottom tension at the FPU. Conceptually, this would be performed in incremental steps using different methods of advancing the pipeline such as:

• Pulling the pipeline by a length of wire while the pulling head is lifted from the seabed; • Using a wire connected to a bottom chain to pull and keep the pipeline on the seabed; • Using a long wire from the DP tug connected to the pull head, also keeping the pipe on the seabed; and/or • Pulling the pipe upward to a DP tug in a fixed position, thereby utilizing pipeline catenary forces to pull the pipeline.

In a pullout scenario, the pipe on the seabed would begin to move when the on-bottom tension is large enough to overcome soil frictional plus the bottom tension at the FPU catenary. Equation (1) describes the balance in forces when the pipeline begins to move:

fWTDPLTDPFF SVSSV )( 02 ∆−+∆+≥ (1)

where, FV = required on-bottom pulling tension of the DP tug FC2 = pipe lay on-bottom tension at FPU after a length of pipe is lowered WS = pipe submerged weight f = soil friction coefficient L0 = pipe length on the seabed before lowering a length of pipe ����S = change in on-bottom pipe length at FPU end as pipe is deployed �TDPV = change in on-bottom pipe length at tug end as the DP tug moves The seabed friction coefficient directly affects the required pulling force for the SCR pullout operation. It was assumed that the seabed consists of soft clay with an undrained shear strength of 1436 to 4788 N/m2. These are typical characteristics for deepwater projects with the following soil friction coefficients: Longitudinal Friction Coefficient: 0.40 Lateral Friction Coefficient: 0.55 Phase I - Pullout Phases of the pullout operation were identified and analyzed. Phase I is summarized in Figure 15. Starting from Point D, the DP tug would stabilize the pipeline on the bottom by paying out 1500 meters of wire while simultaneously advancing 1300 meters to Point E. This increases the pipeline on the seabed to 1662 meters and provides sufficient on-bottom stability to prevent the pipe from shifting both longitudinally and laterally. It also allows curves with large radii (approximately 2000 meters) to be laid so that the pipeline can be directed in various directions. This can be a requirement to lay pipe in a wide SCR corridor, since the final TDPs must be separated and placed at specific locations.

Once the pipeline is stabilized on the bottom, the tug with 1500 meters of wire deployed, pulls the pipeline along the seabed from Point F to Point G as the same amount of pipe is lowered from the J-lay tower. At this location there is 3092 meters of pipe on the seabed. Phase II - Pullout Phase II of the operation is carried out with the tug located in a fixed position. The pipeline is winched upward near the stern of the tug while pipe is deployed off of the FPU. Because the added length of pipe is actually suspended in a catenary from the DP tug, this process allows a significant length of pipe to be added without increasing on-bottom tension. In a water depth of 2000 meters, 1488 meters of pipe can be added without increasing the pipe length on the bottom. Figure 16 shows the transition from Phase I to Phase II of the operation. Beginning at Point E, the DP tug moves forward until the onset of pipeline movement on the seabed at Point F. The tug continues to move and pull the pipeline along the seabed until it comes to a stop at Point G. From Point G the tug remains in a fixed position and winches the pipeline upward, thereby dragging the pipe along the seabed. Phase III - Pullout After the pulling head is retrieved to the designated elevation, the DP tug may resume forward movement. This final Phase III of the pullout scenario is limited by the 250 tonne bollard pull of the tug. This analysis limited the bollard pull requirements to approximately 180 tonnes, which would allow sufficient power reserve for environmental conditions. The transitions of Phases I, II and III are shown in Figure 17. As discussed above, Phase I is shown between Points E and G where pullout is performed with 1500 meters of winch wire. Phase II is shown at Point G as the pipeline is pulled up to the stern of the tug, and then finally Phase III is reached when the tug moves from Points G to H. In this operation an additional 2616 meters of pipe is installed. Therefore, the total length of the pipeline when laid down on the seabed is approximately 9 kilometers. Pipeline Lay Down The maximum pipeline tension occurs at the end of the final pullout phase. The DP tug reduces this tension by backing up until the departure angle is approximately 8 degrees. While the tug is backing up, an ROV is used to carefully monitor the TDP distance to prevent buckling. The end of the pipeline is retrieved to the stern of the tug and suspended by an A-frame. When the pipeline is locked-off on the stern, the pulling head is removed and replaced with a PLET. The pipeline is then laid down to a designated location of the seabed by controlled movements of the tug and wire payout. SCR Termination Just before termination of the pipeline pullout, a flexible joint would be connected to the FPU end of the pipeline. An installation wire from the J-lay tower would then be attached to the flexible joint and lowered. When the joint is below the tower, a slackened pull-in wire would also be attached. The length of wire deployed from the tower is predetermined with respect to the final SCR top angle. For the purposes of this study, the wire angle is maintained from the FPU at 6 degrees from vertical by continued pipeline pullout. This would require 517 meters of installation wire to be deployed from the top of the flexible joint to the J-lay tower to achieve a final pull in angle of 20 degrees in the FPU receptacle (see Figure 18). This mean angle is typically what is required to withstand all environmental conditions and fatigue over the lifetime of the riser. CONCLUSIONS FROM THE SELF-INSTALLATION STUDY

• It is feasible to self-install multiple SCRs from an FPU using a stationary J-lay tower and the pullout method. • Pipeline lengths of 9 kilometers (or longer for pipe sizes less than 10-inches) may be installed. • PLETs can be laid down near subsea tie-ins within the range of the pullout installation method. • Pipe lay vessels are not needed to install pipelines provided subsea wells or tie-ins are within range. • The pullout method utilizes vessels with lower day rate, mob and demob costs. • The self-installation method uses existing pipe lay equipment and technology.

Figure 1. GAP System Connecting an FPSO to a DCU

Figure 2A. GAP Chain Connections and Jumpers Figure 2B. GAP End View

Figure 3. GAP Gathering Concept from DCUs to a Centralized FPSO

Figure 4. 30 km GAP System Connected to an FPSO and DCU Figure 5. BMS Buoy with Flexconnect Jumpers Supported by Intermediate Buoyant Mid-water Supports on a Mid-water Arch

40” Carrier Pipe

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Figure 6. Cross Section of 30 km GAP Bundle Configuration

Figure 7. CFD Analysis Plot of 0.5 m/s Horizontal Flow Past Pipe Bundle

Figure 8A. Figure 8 B. Isometric View Nominal Flow Elevation View of Nominal Flow Density GAP in X-current Condition Density GAP in X-current Condition

Swell + Wave Final fatigue prediction with API-X’FPSO end

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Figure 9. Results of Fatigue Life Analysis for FPSO End of GAP Carrier Pipe

Figure 10. GAP Being Pulled Offshore During Fabrication

Figure 11. GAP in Controlled Depth Tow

Figure 12. Typical Plan View of Several SCRs Connected to an FPU/FPSO

Figure 13. J-lay Tower Located on a FPSO/FPU

Figure 14. Initiation of Pipeline During Pullout

Figure 15. Phase I of Pipeline Pullout and Stabilizing the Pipeline on the Seabed

Figure 16. Phase II of Pipeline Pullout where Pipeline is pulled to Tug Stern

Figure 17. Phase III of Pullout where Tug Movement advances Pipeline

Figure 18. Final Pull-in of the SCR at the FPU