Proceedings of the ASME 2011 30th International Conference on Ocean, Offshore and Arctic Engineering OMAE2011 June 19-24, 2011, Rotterdam, The Netherlands OMAE2011-49550 DESIGN OPTIMIZATION OF TOP-TENSIONED RISERS FOR DEEPWATER HPHT APPLICATIONS (PART II) Lixin Xu Technip Houston, Texas, USA ABSTRACT Dry-tree solutions with top-tensioned risers (TTRs) have been successfully used with floating production systems (FPS), such as Spars and TLPs, in a wide range of deepwater applications. Both single-casing and dual-casing top-tensioned risers are field-proven in existing field developments. The toptensioned risers can bring technical advantages and operational cost benefits. Moreover, recent oil and gas developments that have high pressure and high temperature (HPHT) in combination with severe environmental loads lead to more design challenges for steel risers in deepwater, pushing the design limits of conventional steel pipes in deepwater risers. High-strength steel pipes are therefore considered for both technical and economic reasons. The objective of the study that forms the basis for this paper is to provide top-tensioned riser system configurations that meet challenges of the extremely high operational pressure and environmental loads in deep and ultra-deep waters. Part I of the paper was published in OMAE 2010 [1], addressing strategies for top-tensioned riser sizing and weight management for HPHT applications in deep and ultra-deep waters, and also design considerations for TTR specialty joints. Part II here present spar top-tensioned risers and their support tensioning systems. The paper illustrates the HPHT riser global configuration on spar and the tensioning system performance optimization, as well as coupled motion compensation with the spar platform. The impact of riser loads on spar global performance is also discussed. KEY WORDS High Pressure and High Temperature (HPHT), Floating Production System (FPS), Spar, Top Tensioned Riser (TTR) NOMENCLATURE BOP = Blowout Preventer DDSS = Deep Draft Semi-Submersible DRT = Drilling Riser Tensioner FPS = Floating Production System FPSO = Floating Production, Storage and Offloading GOM = Gulf of Mexico HPHT = High Pressure and High Temperature HPT = Hydro-Pneumonic Tensioner PRT = Production Riser Tensioner TLP = Tension Leg Platform TTF = Top Tension Factor; ratio between net tension at riser top (the tensioning system attachment point) to the riser hanging weight (submerged) TTR = Top-Tensioned Riser T&C = Threaded and Coupled VIV = Vortex Induced Vibration INTRODUCTION Recent development of floating systems has provided technology and opportunities for exploiting oil and gas reservoirs in deep and ultra-deep waters. Figure 1 shows 1 Copyright 2011 by ASME
typical floating platforms for applications in deepwater offshore oil and gas field development, including FPSO, TLP, semi-submersible, and Spar. Top-tensioned risers (TTRs) have so far been used with Spars and TLPs, and potentially with low-motion deep-draft semi-submersibles (DDSS) in the future. Floating structures with dry-tree top-tensioned risers have been installed in a wide range of deepwater applications, in particular, in the Gulf of Mexico (GOM). When applications move to ultra-deep water up to 10,000 feet, Spar is the most suited host platform for supporting top-tensioned risers. The world's deepest dry-tree offshore platform is currently the Perdido Spar in the Gulf of Mexico, which was installed in 2008, floating in almost 8,000 feet of water. Dry-tree solutions with top-tensioned risers can offer technical and cost advantages for drilling and completion, and also a greater benefit for long term well maintenance and intervention. The capabilities of the floating platforms are strongly dependent on riser system performances. The design of top-tensioned risers encounters significant challenges when they are used for high pressure and high temperature (HPHT) applications in ultra-deep water and harsh environments. Furthermore, cutting down riser payloads on the floating facility creates overall system cost savings. Part I of this paper [1] has already addressed top-tensioned riser sizing to account for the extremely high internal pressure up to 20, 000 psi, management of the riser weight and optimization of the top tension requirement, which become key design factors for HPHT TTRs in ultra-deep water. Enhanced design methodology and the use of high strength steel and/or alternate lightweight materials offer effective and feasible solutions in this respect. Part II herein presents a global arrangement and components of the spar-supported high pressure top-tensioned riser system, for achieving a feasible design configuration. The paper then discusses the top-tensioned riser tensioning system design and tension performance optimization, as well as the coupled motion compensation on the host spar platform. TTR GLOBAL CONFIGURATION The spar supported top-tensioner riser offers direct access to the reservoir in deepwater. This enables drilling/completion and workover of the well directly from the spar. While buoyancy cans or hydraulic tensioners have been used to provide top-tensioning support for TTRs, the Ram style hydropneumatic tensioner (HPT) is considered for this HPHT riser in the ultra-deep water. The top-tensioned riser weight increases as the water depth increases; the TTR also becomes much heavier while using very thick pipes for the extremely high pressure requirements. Moreover, higher tension factors may be needed for better fatigue performance of the riser in deeper water considering riser VIV effects. The extremely high weight of the riser system requires very large buoyancy cans that are impractically large to incorporate within the wellbay area and result in high costs and significant challenges in design, fabrication and installation for practical applications. Figure 1: Deepwater Floating Production Systems The first dry tree spar application with the Ram style hydropneumatic tensioned risers was the BP Holstein project. These TTRs are dual-casing comb risers, for production and drilling through the production risers. The tensioner solution was successful, and also applicable to heavier risers such as the HPHT risers in deeper water. Meanwhile, enhanced design methodology and the use of high strength steel offers effective and feasible solutions in respect of riser weight reduction. HPHT risers are usually configured with dual-casings to provide a double pressure barrier in addition to the production tubing, and give better thermal insulation. High strength steel can be used for reducing casing wall thicknesses in order to lower riser weight and attain a manageable top tension load. Figure 2 is a schematic sketch of a dual casing top-tensioned production riser that is supported by a RAM style tensioner mounted on the platform. The riser extends down inside the platform and further to a wellhead on the seafloor. The riser has centralizers/guides, laterally interfacing with the tensioner, the hull, and at the keel. SPAR TTR DESIGN The spar risers in the Gulf of Mexico (GOM) are typically designed for normal operating under 10-year winter storm or 10-year loop current environments, and for extreme operating under 100-year weather environments. Per API RP 2RD [2], 2 Copyright 2011 by ASME
Figure 2: TTR Supported by a Ram Style Tensioner Figure 3: Drilling and Production Risers on Spar any damage condition, or an extreme pressure event, combining with the 100-year environment is considered as a survival condition. In addition, robustness checks for the risers in the 1000-year hurricane event may be recommended. A B C The riser design therefore calls for various load conditions which include (1) intact, (2) mooring damaged, (3) hull damaged and (4) tensioner damaged cases. The riser analysis also considers cases where the hull is located at the nominal position and when it is over the well. D A B C E D F E G H I F TTR General Arrangement G I Figure 3 shows a typical top-tensioned riser stack-up on the Spar, with the drilling riser and production risers installed on the spar. The risers are supported by the Ram style hydropneumatic tensioners (HPT) that are mounted on the Spar deck. The risers and tensioners are integral parts of the spar hull system, and affect spar global responses to a certain extent. This will be discussed in a later section. With multiple number of top-tensioned risers used on the spar, the riser spacing between adjacent risers is determined within the wellbay area and the spar centerwell by the space needed to arrange the riser tensioning system and other surface equipment. To suite the field layout, wellheads are arranged in a pattern that helps to avoid risers interfering with each other due to the Figure 4: Illustration of Well Arrangement spar motions, and caused by waves and current. A larger separation is therefore needed at the seabed to reduce the clashing potential. However, with increasing separation at the seabed, greater bending loads are produced at the keel and stress joints. Thus, the seabed spacing is determined to best suit these two opposing requirements. Figure 4 illustrates a sample layout of the wellbay and the wellhead arrangement on the seafloor. H 3 Copyright 2011 by ASME
TTR Design and Specialty Joints The spar supported top-tensioned risers can have very high pressure ratings of 10,000 psi for the outer casing and 20,000 psi for the inner casing and tubing. In such cases, the outer riser uses high stress steel pipe with the minimum material yield stress up to 125 ksi; and the inner riser steel pipes and production tubing have a minimum yield stress of 110 ksi. Refer to Figure 5 for riser pipe sizing and top tensioner requirements for the dual casing top-tensioned risers [1]. As shown in Figure 3, the top-tensioned riser consists of the following components on the top of the spar: BOP stack (for the drilling riser) Surface wellhead equipment, tree and jumpers; Riser tensioning system (Ram tensioner); The top-tensioned riser also has a tension joint at its top for engaging the tensioner load ring and transferring the tensioner tensile force onto the riser. The load ring can adjust its position on the tension joint for proper riser stack-up. The tension joint is usually a forging piece for better fatigue performance; forging materials with 80 ksi and 100 ksi of the yield strength are considered. Furthermore, the top-tensioned riser uses a keel joint at the spar keel and a stress joint near the seafloor (which is connecting to the wellhead using a tieback connector). The keel joint and the stress joint are forged pieces and have tapered sections in order to withstand high bending due to riser displacements and/or the spar motions. Special joints are needed for transitions from the forged components (such as the tension joint, the keel joint and the stress joint, etc.) to the high strength steel riser joints. These specialty joints, also called crossover joints, provide smooth transitions from the forging joints to the standard joints. System design of the top-tensioned riser is an iterative process, and involves comprehensive analyses through design inputs, riser sizing and global configuration, global analysis, component design, installation and interface. The complexities of riser analysis can be illustrated by a typical analysis model for the top segment of a riser, as shown in Figure 6. TENSIONER DESIGN The Ram style hydro-pneumatic tensioners are preferred for spar supported HPHT top-tensioned risers in ultra deepwater applications. The riser tensioner is designed to accommodate the heaviest weight and the maximum stroke of Wall Thickness (in) 2.20 2.00 1.80 1.60 1.40 1.20 1.00 0.80 Wall Thickness Tension 65 80 95 110 125 140 Min. Yielding Stress (ksi) 3,200 3,000 2,800 2,600 2,400 2,200 2,000 1,800 Figure 5: Riser Wall Thickness and Top Tension [1] Rigid Beam Spar CG Surface Weight Bottom Tension Deck Roller(s) Stem Joint Inner Casing and Tubing Tension Joint Centralizer Tension Ring Figure 6: Schematic of Stem Joint FE Model the TTR, and to ensure that the top tension factor (TTF) of the riser does not fall below 1.0 in the spar hull damaged conditions (e.g., with a hull compartment flooded). The tensioner should also be able to remain operational with one cylinder off, and, by pressuring up in the other cylinders, to provide an equivalent top tension for the risers. The stiffness of the tensioner (tension vs. stroke curve) is selected to encompass the maximum tension and the stroke range, and also in account for compensation of the spar motions. Figure 7 shows tension-stroke plots used in various projects. The tensioners have different nominal stiffness at the null position from the softest to the stiffest systems. Nominal Tension (kips) 4 Copyright 2011 by ASME
5,000 4,500 4,000 conditions, or well operations such as workover and drilling/completion. This relative movement is translated into riser stroke. The riser stroke also includes other components such as riser stack-up tolerance, thermal growth, spar draft variation, seabed subsidence, surge/tide, etc. Tensioner Tension (kips) 3,500 3,000 2,500 2,000 1,500-15 -10-5 0 5 10 Stroke (ft) Figure 7: Typical Tension Performance vs. Stroke Natural Period (sec.) Table 1: Spar Motion Natural Periods Tensioner Nominal Stiffness (kips/ft)* No TTR 42 63 84 Surge 188.8 164.7 164.7 164.6 Heave 25.9 21.9 20.9 20.0 Sway 216.8 183.7 183.7 183.6 Roll 48.1 36.7 36.7 36.7 Yaw 36.2 34.0 34.0 34.0 Pitch 47.4 36.2 36.1 36.1 Note: 8 top-tensioned risers are installed on the spar. While increasing the riser top tension helps reducing the potential for riser interference, it also directly applies vertical load onto the spar and increases the buoyancy requirement of the hull. These two factors need to be balanced in this respect to achieve an efficient design. In particular, for ultra deepwater applications, the HPHT riser tends to be very heavy. The maximum riser tension increases with stiffness. It is therefore optimal to use a medium or lower stiffness. Meanwhile, a subsea well layout that provides an acceptably low interference potential is necessary. For instance, a well pattern on the seabed may be arranged such that none of the adjacent outer pairs of risers are coplanar, which will reduce the potential for riser clashing. Tensioner Effect on Spar Motions The spar motions are coupled with the riser/tensioner systems; in particular, the riser tensioner stiffness affects the platform heave motion. Figure 8 shows free decay tests of heave motions coupled with different tensioner stiffnesses applied. The natural periods of the spar motions vary as described in Table 1. The heave period decrease as higher stiffness riser tensioners are used. Figure 9 shows RAO motions of a spar with top-tensioned riser installed. The Spar has low motions, which greatly benefit the riser fatigue design. Riser Stroke A TTR moves with respect to the hull when the spar deviates from its nominal position due to environmental loads, damage Figure 8: Spar Heave Period vs. Tensioner Stiffness (8 TTRs are installed on the Spar) Spar heave motions have a contribution to the design tensioner stroke and are coupled with the tensioner stiffness. The maximum upstroke of the riser/tensioner systems usually occurs with the spar s maximum set-down due to a hull damaged condition (with compartments flooded). The maximum downstroke is mainly governed by the maximum spar offset under the severest design weather combined with one mooring line broken. The maximum upstroke and downstroke are slightly smaller for the system with higher stiffness tensioners. CONCLUSIONS The spar is the most suitable host platform for dry-tree top-tensioned risers for oil and gas developments in deep and 5 Copyright 2011 by ASME
ultra-deep waters. Using high strength steel pipes, the dual casing top-tensioned riser configuration provides a feasible solution for the HPHT applications, with manageable riser weight and achievable top tension requirements. The Ram style hydro-pneumatic tensioners are successfully used to provide top tension support for the riser system. The spar global responses are coupled with riser and tensioner systems; in particular, combining with the riser/tensioner system stiffness, the spar heave natural period decreases. Overall the spar has low motions, which will benefit riser strength and fatigue design. The optimization of riser design utilizes advanced design methodology and comprehensive analyses to obtain the most efficient engineering solution. ACKNOWLEDGMENTS The authors would like to thank Technip management support in publishing this paper, and also thank Dr. Jiulong Sun of Technip for generating spar motion simulations. REFERENCES [1] Lixin Xu and Paul Stanton, Design Optimization of Top- Tensioned Risers for Deepwater HPHT Application (Part I), OMAE 2010, Shanghai, China, 2010 [2] API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), 1998 Heave RAO (ft/ft) Surge RAO (ft/ft) Pitch RAO (deg/ft) Heave 1.2 1.0 0.8 0.6 0.4 0.2 0.0 0 5 10 15 20 25 30 35 40 wave period (s) Pitch 0.14 0.12 0.10 0.08 0.06 0.04 0.02 0.00 0 5 10 15 20 25 30 35 40 wave period (s) Surge 0.90 0.80 0.70 0.60 0.50 0.40 0.30 0.20 0.10 0.00 0 5 10 15 20 25 30 35 40 wave period (s) Figure 9: Spar RAO Motions 0 45 90 135 180 0 45 90 135 180 0 45 90 135 180 6 Copyright 2011 by ASME