Summary This case summarizes tension-leg platform (TLP) rigid riser designconsiderations and presents results of TLP riser analysis for aproduction/injection riser in the North production/injection riser in the North Sea. Analysis methods, design criteria, and design optimization are addressed. The riser is designed for 300-m water depth in compliance with Norwegianregulations. Emphasis is placed on application of the regulations andquantitative comparison of alternative methods for analysis of fatigue andextremes. Introduction This paper summarizes TLP rigid riser design considerations and presentsresults of the TLP riser analysis. TLP functions include drilling, production/injection, and export through rigid risers. TLP design is mostsensitive to the many production/injection risers. Such parameters as riserspacing, top tension, stroke, and pontoon clearance strongly influence globaldimensions and deck spacing/layout. Parameters used in this case study aresummarized in Table 1. Fig. 1 is a schematic of the TLP riser system. Thedesign is based on Norwegian Petroleum Directorate regulations and guidelines. Criteria for local design are summarized in Ref. 3. Analysis Methods Both frequency domain and time do analysis methods were used. Fatigueanalysis is primarily based on frequency domain and extremes on time domain. The riser is a nonlinear dynamic system, and the inaccuracy in using frequencydomain (assuming constant top tension and using stochastic linearization) isdiscussed below. The approach adopted for extreme responses is regular waveanalysis. This method was used to overcome uncertainty in statisticalextrapolation from an irregular time simulation and, for efficiency, to enablemany design iterations. Dynamic analysis was carried out without introducingload factors. Load factors are applied to responses when carrying out codechecks and when preparing design values for component specifications (e.g., stroke results). Boundary conditions include TLP motion, tensionercharacteristics (see Stroke section) and template/subsea wellhead interface(see Components and Interfaces). The riser analysis included TLP offsets in therange corresponding to TLP extreme motions. First-order response is includeddirectly as a transfer function in the riser analysis, and all other TLP motioncomponents are taken into account by defining a range of riser mean positionsupon which the first-order response is superimposed. TLP setdown is included ateach timestep in the time domain analysis. Sensitivity and Optimization As usual for deterministic design, an extensive sensitivity study must becarried out. The following were investigated:wave periods;currentvelocity;riser periods;current velocity;riser location andgeometric phase;hydrodynamic parameters, variation with depth, Reynoldsparameters, variation with depth, Reynolds number, Keulegan-Carpenter's number, and roughness;annulus and tubing fluids;top tension and tensionercharacteristics;TLP offset;extent of marine growth; andTLP huginfluence on wave kinematics. Quantitative sensitivity results vary widely forthe various responses along the riser, and the resulting priority is influencedby those responses that govern the design. The rigid risers tend to be inconflict with the overall TLP optimization on such parameters as top tensionand riser spacing. parameters as top tension and riser spacing. Optimization, therefore, is an iterative process carried out on the basis of the sensitivityresults for both the risers and the TLP. Handling and operational weatherlimitations are most sensitive to riser spacing and wellbay layout. Theserequire early detailed consideration because they are important to TLPefficiency in service. An alternative analytical approach to sensitivityanalysis and optimization with probabilistic methods could be used whereprobabilistic methods could be used where quantitative sensitivity results aregenerated directly in one analysis. This method has been applied successfullyto TLP tethers. Extreme Stresses Allowable tensile stresses in the riser wall were checked against values in Ref. 2. The Von Mises (combined) stresses were solved with a minimum wallthickness, taking into account corrosion/wear allowance and wall-thicknesstolerances. Ref. 9 is used for sum calculations. Compressive stresses also werechecked for load where axial stresses were low. Local buckling checks did notlead to additional design requirements. Extreme results vary considerably withanalysis method.
This case study presents a Production/Injection rigid riser. The riser is designed for 300 meter water depth in compliance with Norwegian regulations. Emphasis is placed on application of the regulations and quantitive comparison of altemative methods for analysis of Fatigue and Extremes. Introduction TLP functions include Drilling, Production/Injection and Export through rigid risers. TLP design is most sensitive to the many Production/Injection risers and parameters such as riser spacing, top tension, stroke and pontoon clearance strongly influence global dimensions and deck spacing layout. Parameters used in this case study are summarised in table 1. Figure 1 shows a schematic of the TLP Riser System. The design is based on NPD Regulations (ref. 1) and Guidelines (ref. 2). API RP 2T (ref.3) was used for local design. Analysis Methods Both Frequency domain and Time domain analysis methods (refs 4,5) were used. Fatigue analysis is primarily based on Frequency domain and Extremes on Time domain. The riser is a non-linear dynamic system and the inaccuracy in using Frequency domain (assuming constant top tension and using stochastic Iinearisation) is discussed below. The approach adopted for extreme responses is regular wave analysis. This method was used to overcome uncertainty in statistical extrapolation from an irregular time simulation and for efficiency in order to enable many design iterations. Dynamic analysis was carried out without introducing load factors. Load factors are applied to responses when carrying out code checks and in the process of preparing design values for component specifications (eg. Stroke results below). Boundary conditions include TLP motion, Tensioner characteristics (see Stroke) and Template/Subsea Wellhead interface (see Components). The riser analysis included TLP offsets in the range corresponding to TLP extreme motions (ref. 6). First orderresponse is included directly as a transfer function inthe riser analysis and all other TLP motion components are taken into account by defining a range of riser mean positions upon which the first order response is superimposed. TLP setdown is included at each time step in the Time domain analysis. Sensitivity and Optimisation As usual for Deterministic design, an extensive sensitivity study must be carried out. The following were investigated:wave periodscurrent velocityriser location, geometric phasehydrodynamic parameters, variation with depth, Re, KC and roughnessannulus and tubing fluidstop tension and tensioned stiffness characteristicsTLP offsetextent of marine growthTLP Hull influence on wave kinematics Quantities sensitivity results vary widely for the various responses along the riser and the resulting priority is influenced by those responses which govern the design. The rigid risers tend to be in conflict with the overall TLP optimization on parameters such as top tension and riser spacing. Optimization is therefore an iterative process carried out on the basis of the sensitivity results both for the risers and the TLP. Handling and operational weather limitations are most sensitive to riser spacing and Waubay layout. These require early detail consideration as they are an important input to TLP efficiency in service.
The cylindrical FPSO is now in operation at three offshore oilfields, on in Brazil and two in the UK Central North Sea. It is furthermore selected for a field development in the harsh and sub-arctic Norwegian Barents Sea. Full scale monitoring of motions on units in operation has verified predictions, confirming very favorable motions when compared to shipshape FPSOs and even semi submersibles. In 2009, a study was awarded by a major oil company to investigate the feasibility of applying Steel Catenary Risers (SCR) with a cylindrical FPSO at a location with deep water and very harsh environment. Results from the initial analysis proved feasibility and associated model testing has allowed calibration of first order and second order analysis methods and particularily have lead to a better understanding of second order and heave coupled pitch motion effects. Adaptation of the cyclindrical hull to improve its characteristics as a host platform for steel catenary risers has been the incentive for the case study outlined in this paper. Platform and riser optimisation should be field specific, but the results presented for a very harsh environment, demonstrate the feasibility of steel catenary risers with a cylindrical FPSO at any location, worldwide. In this paper, the focus is on demonstrating how a cylindrical FPSO/SCR design spiral can progress towards meeting the challenges of a harsh environment with competitive hull/riser combinations. Introduction The cyclindrical FPSO/SCR challenge is to provide an SCR hang-off location with motions, as follows, even in very harsh environments.The maximum downwards vertical velocity in 100-year design conditions should be less than 2,4 m/s (1,9m/s in 100 year conditions is achieved)The long term distribution of all motions at the riser hang-off shall provide a robust SCR fatigue life (achieved with low amplitude heave RAO within Tp range with high % occurrence)Angular motion should stay within a range of +/- 25 degrees at hang-off (achieved 18,1 degres)Horizontal offsets envelope within 2,5% of waterdepth in 100 year conditions with intact mooring (achieved 2,3%) A cylindrical FPSO with SCR hang-off in a moonpool is demonstrated to meet the above criteria with margins, even for very harsh environments. The Cylindrical FPSO is arranged so that the SCR hang-off is located very close to the centre of the FPSO, within a moonpool, and thus the predominantly heave induced vertical motion at the riser hang-off meets SCR hang-off motion targets. Mooring systems are developed to meet the offset criteria. The case study responses are reported for a 16" gas export riser, based on API standard seamless pipe dimensions with 5 mm corrosion protection coating, resulting in an "OD/weight submerged" ratio with 148 kg/m3 contents of 3,0 m2/tonne. Equivalent 123/4" and 103/4" production SCRs with contents 800 kg/m3 and high insulation are outlined for benchmarking.
Four sensors were installed on the Snorre A TLP (Tension Leg Platform) on 16th April 2014 and retrieved on 10th May 2014, to document motions of the vessel, top tensioned riser (TTR) and flexible jumper connecting the TTR (Top Tensioned Riser) with the topside piping. The data recorded represents 3828 data sets. Associated significant wave height and peak period is synchronous data extracted from the Miros wave measurement radar and stored in the environmental data base. The SmartMotion riser sensors are certified for service in the Wellbay. The sensors are modelled into the OrcaFlex (1) “calibration” analysis model in order to simulate the motion responses in the same format as recorded offshore (accelerations and rates of rotation), and to carry out verification of the OrcaFlex model by comparing both raw data and filtered/integrated derivatives. This work provides a basis for life extension of the Jumpers and provides valuable feedback to design and analysis of TLP and Spar Jumpers between TTRs and topside Headers.
The paper presents the Snorre well systems including the production/injection risers, the drilling riser and the workover assembly. Design bases are presented with particular emphasis on fatigue, fire protection, installation and operability requirements as well as overall safety requirements. The installation sequence and monitoring and maintenance equipment are also presented. INTRODUCTION The well systems on the Snorre Tension Leg Platform (TLP) comprise the many components of the production/injection risers, connections to the platform production facilities and the subsea well template and the well completion. The Snorre TLP is designed with 44 wellslots and to accommodate up to 36 production/injection risers. Six wells will be pre-drilled. The well spacing is 4 m in either direction. SYSTEM DESCRIPTION The wells are drilled through a seafloor well template using a high pressure drilling riser. The BOP is located at the surface in the drilling substructure. Subsea wellhead equipment is used to land the casing strings at the well template. Each well is then tied back to the platform with a production/injection riser. The Snore production/injection risers (Fig. 1) consist of 9 5/8-inch pipes running from the subsea wellhead on the seafloor well template to the Xmas trees in the wellbay, thereby extending the 9 5/8-inch diameter production casing string back to the platform for well completion. The risers are equipped with remotely installed tie-back connectors at their lower end for connection to the subsea wellhead. The production/injection riser string consists of tapered joints at the lower end, 12 m long coupled riser joints and a tensioner joint at the top extending up into the wellbay. The tensioner joint incorporates a tubing head to suspend the 5 1/2-inch production tubing string and the attachment for the monoblock Xmas tree. The production/injection trees are connected to the platform's piping manifold with flexible jumpers. The risers are supported by tensioner assemblies located on the tree deck structure. A workover assembly (Fig. 1) is used for workover and well completion operations. It is mounted on the surface wellhead and consists of a connector, two flex joints, workover spool piece and tensioner spool piece. The drilling riser (Fig. 2) is a 17 1/2-inch I.D. X-70 grade pipe. It guides the drill string and tools into the well, and conducts circulation returns to the drill rig substructure where the BOP stack is installed. It is connected to the subsea wellhead equipment on the drilling template and is kept in tension by drilling tensioners. It also includes flex joints at the lower end and at the lower deck level. Four one-inch guidelines provide guidance for installation and retrieval of the risers. Special procedures are developed for installing the guidelines between the platform and the well template. The Snorre well template (Fig. 3) is a simple space frame structural design utilising tubular construction with mainly simple joints. The structural arrangement mirrors the wellbay layout on the TLP with the well receptacles designed to support both pre-drilling and TLP drilling operations.
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