OTC 20650 Parque das Conchas (BC-10) Pipeline, Flowline and Riser System Design, Installation and Challenges J. Hoffman, H. Yun, and A. Modi, Shell International Exploration & Production, Inc., and R. Pearce, Nomad Consulting
Copyright 2010, Offshore Technology Conference This paper was prepared for presentation at the 2010 Offshore Technology Conference held in Houston, Texas, USA, 3–6May2010. May2010. 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 The Parque das Conchas (BC-10) project is a deepwater project off the coast of Brazil that has a number of subsea fields that are tied back to a centrally located turret moored Floating Production Storage and Offloading (FPSO) host in 1,780 meters of water. The project is a two-phased development where the Ostra, Ostra, Abalone and Argonauta-BW fields are developed developed in Phase 1 and the Argonauta Argonauta O-North field field in Phase 2. The Pipeline, Flowline and Riser (PFR) (PFR) infrastructure infrastructure of Phase 1 of the project consists of ten flowlines, seven risers, one gas export pipeline, fifteen pipeline end terminations, four manifolds and twenty five rigid steel steel jumpers. Pipeline diameters diameters range from 6” to 12” with with both insulated and non-insulated non-insulated lines. Within the system there are a number of “first” that made the project particularly challenging, the foremost of which is the design of the riser system. Due to the host motions and the water depth, a Steel Lazy Wave Riser (SLWR) system was selected selected for the field. Given that this was the first time time a steel riser was fixed to a turret moored FPSO, FPSO, Shell had to design and fabricate fabricate a specific riser interface system that would accommodate the riser. In addition to the “worlds first” SLWR system there were a number of other challenges that the project team had to overcome. These included fabrication of the risers to tight tight flaw acceptance criterion to to meet the targeted design life of the field, installation of the heavily insulated flowlines, failure of rigging during the initiation of a PLET and failure of the winch during a riser pull-in pull-in operation. This paper will will provide a high level overview of the Parque das Conchas Conchas Phase 1 pipeline, flowline and riser system, the design and interfacing of the SLWRs to the FPSO turret and the challenges that occurred throughout execution of the project.
Introduction The Parque das Conchas (BC-10) project is a deepwater project off the coast of Brazil. Shell Brasil E&P is the operator of the field with a 50% working interest in a joint venture with partners Petróleo Brasileiro S.A. (Petrobras) and ONGC Campos Ltda. (ONGC), with a 35% and 15% working interest, respectively. The Pipeline, Flowline and Riser (PFR) infrastructure for Phase 1 of the project consists of ten flowlines, seven risers, one gas export pipeline, fifteen pipeline end terminations, four manifolds manifolds and twenty five rigid steel jumpers. Pipeline diameters range from 6” to 12” with both insulated and non-insulated lines. Figure 1 below depicts the overall BC-10 development. development. Within the system there are a number of “firsts” that made the project particularly particularly challenging. The foremost of which was the design of the riser system. Due to the host motions and the water depth, depth, a Steel Lazy Wave Riser (SLWR) (SLWR) system was selected for the field. The following paper provides provides a brief description of the flowline flowline and riser system, system, design challenges associated with the SLWR system and a brief description of the fabrication and installation of the pipeline, flowline and riser infrastructure.
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Figure 1 – BC-10 Overall Field Layout
Field Summary The Parque das Conchas reservoirs can be characterized as relatively shallow with low pressures, temperatures, and API gravity. Because of the deep water and low pressure reservoirs, artificial lift via cassions and Electrical Submersible Pumps (ESPs) are required to boost the production from the fields. To maintain product temperature, all production flowlines are insulated with syntactic polypropylene with insulation thickness ranging from 40mm to 90mm depending on the line type. To compliment the insulation on the flowlines, hot oil circulation is used for startup conditions. At the Ostra field there are two production manifolds separated by approximately 1.8 km distance. At each manifold, there are up to four producing wells. There are two 8-inch insulated production flowlines between the two manifolds. The lines are used for transporting the produced fluids between the two manifolds and allow for hot oil circulation as required. The product from the production manifolds is transported to an artificial lift manifold (ALM1) via jumpers. The artificial lift manifold includes four caissons with submersible pumps for pressure boosting. The artificial lift system is also designed for subsea separation. Because of the subsea fluid separation, there are two flowlines and risers for transportation of the oil and gas. The oil line consists of a 12-inch nominal diameter insulated flowline and 10-inch nominal diameter insulated riser. The gas line consists of an 8-inch nominal diameter flowline and riser. A third 6-inch nominal diameter insulated service line is used for dead oil displacement for shut-in conditions, hot oil circulation for startup conditions or excess production capacity. The Abalone field has a single well that is tied back to the Ostra field artificial lift manifold by two 6-inch nominal diameter insulated flowlines. Flowline jumpers connect the flowlines to ALM1. At the Abalone field, the flowlines also have a common flowline jumper that allows for hot oil circulation for startup conditions. The Argonauta-BW field consists of two wells and an artificial lift manifold (ALM2). The Argonauta-BW field also has caisson ESP pressure boosting systems does not utilize subsea separation. The multi-phase product is transported to the FPSO turret through dual 8-inch nominal diameter insulated flowlines/risers. A 40 km 6-inch gas export pipeline was preinstalled to export gas from the BC-10 development to the Sul Capixaba pipeline. At the time of construction of the Parque das Conchas development, it was identified that the Sul Capixaba line would be brought online approximately one year after start-up. At the Ostra field a temporary gas disposal well is utilized until the gas export pipeline through the Sul Capixaba development is constructed. Both the gas export pipeline and gas injection lines have Fusion Bond Epoxy (FBE) as the corrosion protection system for the line.
Steel Lazy Wave Riser Design A SLWR is a Steel Catenary Riser (SCR) that has buoyancy added to the riser to decouple the FPSO dynamic motions at the touch down point of the riser. By doing so, the fatigue life of the riser is significantly increased. The SLWR consists of 4
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sections: an upper catenary section, a buoyant section, a lower catenary section, and a bottom section. The concept is illustrated in Figure 2. The upper catenary section usually constitutes the majority of the riser length and it interfaces with the host. The buoyant section is fitted with syntactic foam buoyancy modules and their negative weight in water creates a wave in the riser. The lower catenary is a short section below the buoyant length and it interfaces with the sea floor. The bottom section lays on the sea floor most of the time and it extends to the flowline-riser transition point. The complete design of the SLWRs was performed in-house by Shell engineers with the exception of the flexible joint itself. Oil States Industries performed the flexible joint design. The Shell riser analyst performed detailed riser response, fatigue, Vortex Induced Vibration (VIV) response, response based analysis, riser interference and installation analyses. Other engineers within Shell performed the wall thickness selection, flow assurance internal/external corrosion analyses and cathodic protection design.
Figure 2 – Steel Lazy Wave Concept
The design process used for SCR risers was also employed for the SLWR. The main parameters investigated included riser stresses, top angular rotations, VIV response, fatigue, amount of distributed buoyancy required and interference. Riser design is complicated by nature and with the addition of the buoyancy the analysis is even more challenging. Iteration in the riser design is required to determine the optimal riser configuration. Shell’s in-house software COSMOS and TIARA were used to perform the analyses of the BC-10 risers. The design of the wave in the riser is a trade off between the amount of buoyancy and the increased fatigue performance of the riser. Generally a larger wave will increase the fatigue life of the riser. However buoyancy material and installation is expensive so iteration is required to determine the optimal amount. Generally, the wave was placed as close to the seafloor as possible to reduce the amount of buoyancy. Vessel offset and riser fluid content were also considered. Buoyancy is modeled as a uniformly distributed uplift force in the global motion analysis of the system. This was done for simplicity and efficiency in the riser analysis. In reality the buoyancy force is installed at discrete locations along the riser. In order to account for the stress concentrations effects from the buoyancy clamps, additional sensitivity analysis was performed to verify the stresses and fatigue performance of the riser. Figures 3 and 4 below show the effects of the discrete buoyancy modules versus the distributed method.
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Figure 3 - Extreme Stresses in the Buoyant Section
Figure 4: Fatigue Life in the Buoyant Section
Another important consideration is that a SLWR design requires more riser quality welds when compared to a SCR design. Generally speaking, the length of riser (and corresponding riser welds) can be increased by 25 to 50 percent. Despite the overall increase in riser length the overall length of the system (riser and flowline) remains relatively the same when compared to a SCR design. Importantly, the top tensions are reduced by 10% or more. Finally, because of the relatively low tension at the touch down point the SLWR is sensitive to lateral displacements in the presence of deepwater currents. Because of this sensitivity, additional analyses were performed for the riser system accounting for the actual properties of the riser including submerged weight of the riser joints, their coating, individual
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buoyancy uplift and riser content. The design of the BC-10 risers accounted for an additional 5% of buoyancy loss over the life of the project due to compression affects from possible water ingress and creep. The results of the final analysis were used for the final adjustment of the number of buoyancy modules for each SLWR before installation. This resulted in three of the seven risers requiring one additional buoyancy module to achieve the optimum fatigue performance of each riser.
FPSO Interface Initially the project selected a Flexible Pipe Spool Piece (FPSP) as the mechanism to interface the riser with the FPSO turret. With this concept the riser design would have taken advantage of the flexibility of the flexible pipe and used a proven bending stiffener attachment mechanism to interface with the turret guide tubes. However, for optimization reasons, the project elected to drop the FPSP design and develop a new design for the riser to turret interface. The design of the riser to turret interface is a Shell developed system that consists of an upper attachment assembly, journal forging, flexible joint and transition joint. The upper attachment assembly and journal forging allow the riser to be pulled into existing guide tubes in the FPSO turret. At the bottom of the guide tube there is a clamp casting assembly with locking screws that centralizes the riser in the guide tube. The flexible joint allows for angular rotation of the riser while the transition joint increases the fatigue performance at the top of the riser. Figure 5 below depicts the interface assembly.
Figure 5 – BC-10 SLWR Interface Assembly
Riser and Flowline Stalk Fabrication The pipeline, flowline and riser installation method selected for the project was the reel lay method. A significant feature of the reel lay approach to pipelay is that the preparatory works are completed at an onshore facility where weather and cycle time are not critical factors. Pipe, which has previously been coated with an anti-corrosion or insulation coating, is fabricated and inspected in to predetermined pipe lengths known as ‘stalks’. The required numbers of stalks to complete a specific project are prepared ready for load out on arrival of the pipelay vessel. As one stalk is reeled onto the pipelay vessel, a consecutive stalk is lined up to allow the stalk tie-in to be completed. The cycle is repeated until the desired pipeline length has been loaded onto the reel. The selected contractor for the operation was Subsea 7. Fabrication of the pipeline, flowline and riser stalks was performed at Subsea 7’s Ponta Ubu spool base in the state of Espírito Santo, Brazil. Figure 6 shows the layout of the Subsea 7 Spoolbase.
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Figure 6 – Subsea 7 Ubu Overall Layout
The welding of the risers and flowlines was considered one of the key challenges for the project execution. Subsea 7 developed and qualified repeatable processes for producing ductile welds that overmatched the strength of the parent pipe and therefore mitigated / minimized the potential of fracture during the reeling process. The welding process selected for the risers was a fully automatic, pulsed TIG system. The process was chosen specifically to produce high quality welds with very small defect sizes. This process is slower than other possible welding processes but it was deemed to have a better overall quality when compared to other processes. Flowline welding, which followed riser welding, also utilized the TIG system for the application of the weld roots. A flux core process was selected for the fill and cap region of the welds. An Engineering Critical Assessment (ECA) was developed for each of the flowlines and risers to calculate the flaw growth during the installation process and in-place service, and allowed the calculation of initial allowable flaw sizes during the fabrication process. Inspection of the welds was performed with Automatic Ultrasonic Testing (AUT) and was subcontracted by Subsea 7 to RTD Quality Services using the rotoscan method. The rotoscan method is an automatic inspection system that uses pulse echo, mapping and time of flight probes to inspect the weld. A full validation of the AUT system was performed to prove-up the system.
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A summary of the number o f welds performed for the project is summarized in Tables 1 and 2 below. PIPE SIZE (Inch) 10 8 6 8 8 6 6
Line Designation Ostra C Oil Ostra C Gas Ostra C Service Argonauta B West 1 Argonauta B West 2 Gas Export Gas Injection
Wall Thickness (mm) 22.2 19.1 25.4/15.9 19.1 19.1 15.9 15.9
Coating Type
Welds
SPP TLPE & FBE SPP SPP SPP TLPE & FBE TLPE & FBE
232 240 261 250 244 221 243
Coating Type
Welds
SPP FBE SPP SPP SPP SPP SPP FBE FBE
671 605 261 362 2626 493 541 3160 393
Table 1 - Riser Welds PIPE SIZE (Inch) 12 8 6 8 6 8 8 6 6
Line Designation Ostra C Oil Ostra C Gas Ostra C Service Ostra C Intrafield Abalone (A-West) Argonauta B West 1 Argonauta B West 2 Gas Export Gas Injection
Wall Thickness (mm) 19.1 14.3 15.9 15.9 15.9 19.1 19.1 15.9 15.9/12.7
Table 2 – Pipeline and Flowline Welds • • •
SPP = Syntactic Polypropylene FBE = Fusion Bonded Epoxy TLPE = Three Layer Polyethylene
The total number of welds was approximately 11,100 with a total stalk fabrication time of approximately 15 months.
Manifold Installation Manifold installations were performed with Subsea 7’s multi purpose construction vessel Seven Seas. Manifold weights ranged from approximately 100 mt for the two production manifolds, 140 mt for the artificial lift manifold at the ArgonautaBW field and 235 mt for the artificial lift manifold at the Ostra field. For the two production manifolds, the manifolds were installed in a single fall mode with the Seven Seas 400 mt crane. The artificial lift manifolds were installed in a double fall mode with the crane. Because the crane wire could not reach the bottom in the double fall mode, the inclusion of a pennant wire was required for the installations. With the inclusion of the pennant wire the lift required the manifolds to be temporarily hung off the vessel. Thereafter, the manifold was transferred back to the main crane wire for final installation. Figure 7 shows the deployment of the artificial lift manifold at the Ostra field.
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Figure 7 – Ostra Artificial Lift Manifold Installation
Jumper Fabrication and Installation Twenty-five steel jumpers were fabricated and installed for the project. Subsea 7 performed fabrication of the jumpers at their yard in Vila Velha, near Vitoria. Fabrication of the jumpers included performing the metrology of the jumpers, closure welding for Company provided jumper kits, field joint coating and factory acceptance testing thereof. Cycle time from metrology to completion of jumper fabrication took approximately ten days per jumper. A typical jumper configuration is provided in the figure below.
Figure 8 – Typical Flowline and Artificial Lift Jumper
Due to the flowline installation schedule, the Seven Seas and Seven Oceans installation vessels performed installation of the jumpers. Cycle time for a single jumper installation was less than one day. The following figure shows installation off one of the production flowline jumper.
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Figure 9 – Seven Seas Jumper Installation
Overall, the jumper fabrication and installation were one of the highlights of the overall project given the cycle times from performing the metrology of the welds, fabrication of the jumper and installation.
Pipeline, Flowline and Riser Installation Installation of the pipeline, flowlines and risers was performed using Subsea 7’s reel lay vessel Seven Oceans. In principle, the flowlines were initiated from the pipeline end terminations (PLETs) and laid towards the FPSO. Initial plans were to have the flowlines and risers pre-installed on the seafloor prior to the FPSO arriving on site. However, due to delays by the Seven Oceans, only half of the risers were pre-installed with the remaining risers a direct handover to the FPSO. The pre-installation configuration of the risers on the sea floor was extremely complex due to both installation and recovery requirements. Shell engineers performed the initial layout configuration and then provided it to Subsea 7 as a go by for subsequent pipe and umbilical lay and recovery analyses. Figure 10 shows the riser and umbilical pre-installation configuration for the field.
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Figure 10 – Riser and Umbilical Pre-Installation Configuration
The entire pipelay campaign was completed in nine months including time for transits, mobilizations for pipe spooling, loading equipment, deck reconfiguration and re-fuelling, plus delays due to weather. Delays due to weather were mitigated by performing extensive up-front analysis as well as specific detailed analysis based on actual site observations and shortterm weather forecasting. For some of the flowline and risers, the lines were installed full of water to improve vessel weather performance. The Seven Oceans was capable of installing all lines in the flooded conditions with no special modifications. The following figures show the general steps for the offshore installation of the Ostra Service Flowline and Riser.
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Figure 11 – Seven Oceans Installation Vessel
Figure 12 – Pipe Spooling
Figure 13 – Plet Initiation
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Figure 14- Buoyancy Installation
Figure 15 – VIV Fairing Installation
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Figure 16 – F lexible Joint Installation
Figure 17 - Riser Transfer to FPSO
Installation Challenge In addition to the challenges of performing deepwater pipe lay in the southern Atlantic Ocean, failures of key equipment at critical times during operations required rapid assessment, analysis and revised planning from both the onshore and offshore teams. The first such incident occurred during initiation of one of the 8” Ostra Intrafield lines, when a component of the rigging connecting the Pipeline End Termination (PLET) to the holdback pile failed (Figure 18).
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Figure 18 - Intrafield PLET Initiation
The failure occurred in the hard eye termination of a 2” ¼ (57mm) diameter wire rope sling as the initiation catenary was being established. The maximum tension at the time of failure was estimated to be around 60 mt and the resulting loss of tension caused the PLET to slide approximately 350 meters along the lay route. Immediately after the incident, the pipe catenary and PLET were both inspected and found to be undamaged and Seven Oceans was repositioned based on the stable location of the PLET. The two key factors that mitigated any damage to the system were the hinged piping module in the PLET, which minimized the bending stresses in the pipe as the PLET slid along the seabed, and the water depth, which meant that the change in catenary departure angle from the vessel was small. Once the system was stabilized, the operations could focus on recovery of the failed components and establish the cause of the incident. The failure of the eye of the sling (Figure 19) was determined a quality issue from the sling supplier and all rigging from this supplier was subsequently identified and quarantined pending further investigation. The initiation pile was designed with two sets of initiation rigging and the pipe lay support vessel Seisranger was used to reconfigure this rigging. The Seven Oceans recovered the required length of pipe back onto the reel to lift the PLET clear of the seabed to allow the vessel to translate back to the initiation location to resume the operations. The total delay incurred to the Seven Oceans’ operations to assess the problem, perform inspection, recover pipe, install new rigging and reinitiate pipe lay to an equivalent position was slightly over five and a half days.
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Figure 19 - PLET Initiation Rigging Failure
The second equipment failure that affected the pipe lay operations occurred during pull-in of the 10” Ostra Oil Production Riser to the FPSO. Prior to this riser transfer, two risers had already been successfully transferred, pulled-in and hung-off on the FPSO although the Ostra Oil riser would present the highest pull-in loads at around 250 mt but still well within the rated capacity of the FPSO pull-in winch. The installation of the Ostra Oil riser was planned as a ‘direct transfer’ meaning the riser would be installed with the Seven Oceans moving towards the FPSO and the transfer operation performed on the ‘near’ side of the catenary. The operations proceeded according to plan and the Seven Oceans transferred the riser to the FPSO pull-in winch and disconnected its own abandonment and recovery (A&R) winch. After the FPSO winch had recovered approximately 20m of wire, the pull-in winch experienced a mechanical failure. The winch was assessed as stable and able to support the load however it was unable to operate. The Ostra Oil riser was therefore effectively suspended on the fixed wire length of 130m from the guide tube entrance. In order to repair the winch, the riser tension had to be removed and so a plan was developed to transfer the riser back to the Seven Oceans on the ‘far’ side of the FPSO and then lay the riser to the seabed allowing time for the winch repair and other pipe lay operations to be performed. Recognizing the safety issues of working under the catenary supported only by the damaged winch, the main challenge in the operation involved reconnecting the heavy rigging components using ROV. The project had prepared a contingency procedure for back-transfer of the riser based on a problem with the riser hang-off or fit through the guide tube and hence this procedure involved divers working from the FPSO. Fortunately, the key items of equipment in this operation being a high capacity synthetic sling (suitable for diver and now ROV handling) and an ROV cutter suitable for wire diameters up to 115mm had been procured. Working with these key items of equipment, a procedure was developed involving the pipe lay support vessel, the Seisranger, working on the opposite side of the FPSO to pull the A&R winch wire with a high capacity ROV hook from the Seven Oceans under the FPSO to the Ostra Oil riser. The Seisranger ROV then pulled the synthetic sling through a shackle (Figure 20) in the pull-in rigging train and back onto the ROV hook allowing the Seven Oceans A&R winch to take-up tension (Figure 21).
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Figure 20 – Synthetic Sling being Pulled through Shackle
Figure 21 – Seven Oceans A&R Wire Taking up Tension
Due to the reduced length of wire, the FPSO pull-in wire was not able to be fully slackened prior to the cutting so risks related to the swing path of the wire had to be carefully assessed considering two risers were already installed. With two vessels working in close proximity, either side of the FPSO, connected together with lateral loading applied, the DP aspects of both vessels were investigated in detail. A software simulation was performed estimating the potential shock load on the system in case the winch suffered a catastrophic failure during the load transfer process and contingency plans were prepared. In parallel with the above work, fatigue analysis of the Ostra Oil riser at the secondary touchdown location was performed, structural supports to the winch drum were installed and video monitoring of the FPSO winch wire at the guide tube entrance was set-up. This allowed the Seven Oceans to continue with other pipe lay operations minimizing overall schedule impact to the project. The time from the initial winch failure to having the riser laid on the seabed took just over eleven days with six of these days used to progress other pipe lay operations. Once the procedure, analysis and detailed risk assessment was performed, the operation was successfully executed and the Ostra Oil riser was laid to the seabed. After winch repair, the riser was recovered, transferred and pulled-in to the riser turret per standard procedure.
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Conclusion The Parque das Conchas project is the first project to use Steel Lazy Wave Risers fixed to a turret moored FPSO. The design of the riser system was performed by Shell engineers and based on the design methodology for Steel Catenary risers. In addition to the standard riser design process, additional engineering was required to determine the amount of buoyancy required for the risers, local fatigue analysis at the buoyancy clamps and lateral displacements of the riser from subsea currents. To facilitate hang-off of the riser, a turret interface system was designed by Shell and installed for the system. Subsea 7 performed installation of the pipeline, flowline and riser infrastructure with their flagship construction vessels Seven Oceans and Seven Seas. All in all, the two vessels installed: • • • • •
Ten steel flowlines totaling approximately 90 km of pipe One gas export pipeline totaling 40 km of pipe Seven SLWR totaling 21 km of pipe Four manifolds with weights up to 235 mt Twenty-five rigid steel jumpers
The overall duration offshore was equivalent to more than 900 days of vessel time offshore including the survey support operations During the pipe lay operations, there were two major installation challenges that included the failure of the initiation rigging of a PLET and the failure of the pull-in winch onboard the FPSO. Successful outcomes of the two incidents were achieved because of the response of all parties involved. Key learning’s from the incidents were the proper contingency planning and developing a clearly aligned culture regarding safety and technical integrity across all companies involved in the project. This allowed the project to achieve the best possible outcome especially during unexpected situations. The design, fabrication and installation of the Parque das Conchas pipeline, flowline and riser is truly a remarkable feat given the various challenges that had to be overcome throughout the project.
Acknowledgements: The authors wish to thank Shell, Petrobras and ONGC for permission to publish this paper. Special recognition is given to all the Shell staff, onshore and offshore inspection personnel and the many vendors and contractors that worked on this extremely challenging project. Without their tireless support, hard work and effort the project would not have been as successful as it turned out.
