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Subsea jumpers are tie-in systems with a characteristic M-shaped geometry, employed to connect subsea facilities such as wellhead trees to manifolds. During well restart after a prolonged shut-down, subsea jumpers are exposed to a significant driving force for hydrate formation. Employing the recently-constructed HyJump flowloop, designed to mimic subsea jumpers operating at hydrate forming conditions, an experimental campaign was conducted to assess the influence of pipeline temperature, gas flow rate, liquid inventory, and inhibitor content on hydrate deposition during simulated shut-down and restart operations. In this work, we acquired baseline data on the gas sweep efficiency in HyJump for a wide range of gas restart velocities to characterize hydrodynamic behaviour in the absence of hydrates. Preliminary experiments were also conducted to evaluate the jumper operability in hydrate forming conditions. The HyJump flowloop consists of a test section connected to independent gas and liquid injection equipment at the inlet and gas separation facilities at the outlet which allows a continuous recirculation of gas and a once-through pass of the liquid. The test section has a complex geometry, with three identical low points and two high points with horizontal length of 12′ 10˝ and 7′ 7˝, respectively, and total height is 13′ 2˝. The test section is equipped with 12 pressure and temperature sensors regularly distributed, a MEG sensor in the second low point, a throttling valve downstream of the first high point to mimic the wellhead choke, and a viewing window at the outlet. In gas sweep experiments, each of the three low points was loaded with 1.6 gallons of water and natural gas at 1200 psi. During these tests, the pipeline temperature was maintained above 60 °F where hydrates are not expected to form. The system was maintained for six hours at a pipeline temperature of 41 °F (17 °F sub-cooling) for hydrate formation tests. Gas sweep velocities were varied in a range between 0.06 and 3 ft/s. The results illustrate that a superficial gas velocity of 3 ft/s was required to fully remove liquids from the jumper. However, gas velocities below 0.16 ft/s did not result in any substantive changes to the liquid inventory. Thus, low flow restart conditions could offer a significant driving force for hydrate formation in the jumper at low temperature. The preliminary gas restart tests conducted in hydrate forming conditions provided clear evidence of hydrate deposition at gas velocities below 0.16 ft/s. Hydrate formation in subsea jumper spools is poorly understood and a rare topic of discussion within scientific literature. This unique "HyJump" facility offers new insight to assist operators mitigate the risk of hydrate blockage by manipulating gas restart rates after well shut-down in the absence of (or with severely limited) chemical inhibition.

To date, there are no publicly available, validated tools or industry accepted guidelines for the assessment of Vortex-Induced Vibration (VIV) fatigue of rigid Jumper (spool) systems. The existing state of practice has been to treat rigid jumper systems as free spanning pipelines and apply the associated design principles in DNV GL recommended practice DNV-RP-F105/DNVGL-RP-F105 (Free Spanning Pipelines). However, widely used rigid jumper systems such as the M-shape jumper systems are subjected to complex flow fields around their legs and bends and fall outside of the test data used to generate the free-span response model in DNV GL Recommended Practice (RP). A Joint Industry Project (JIP) ‘Jumper VIV JIP’ that included BP, ExxonMobil, Petrobras, Saipem and DNV GL was conducted between Dec. of 2014-2016 to collectively tackle the technical issues related to the VIV design of rigid jumper systems. Through the JIP study, measured responses from ExxonMobil's jumper tow test data were used to develop new response curves for jumper systems in pure-current condition. Curves for in-line and cross-flow responses were initially developed by classifying the measured responses into in-line or cross-flow directions and compared against the existing DNVGL-RP-F105 response curves. Due to potential ambiguity in classification and application to Jumper Design, a more general curve that does not rely on directional classification has also been generated. Due to the differences in behavior of rigid jumper systems to that of free spanning pipelines, a new VIV guidance report was developed as part of the JIP deliverable. Principles and philosophies in the DNV-RP-F105 were followed in the development, but with the intent of identifying unique behavior of jumper systems for a subsequent update of the RP. This paper presents the Guidance notes from the JIP and forms the first release of Jumper VIV fatigue assessment approach to the Industry. ExxonMobil's model test data, the only known test data available in the industry, was used in the development of unique response model and the new design guidance. The paper includes the new response model along with VIV screening, safety factors and unique considerations required for fatigue assessment of jumper systems.

In subsea production operations, wellhead jumpers are one of the subsea facilities more liable to the formation of hydrate blockages during restart operations. To manage hydrate formation and optimize the amount of thermodynamic hydrate inhibitors (e.g. mono-ethylene glycol; MEG) injected, a newly-constructed jumper-like facility (the HyJump flowloop) has been developed in Perth, to simulate shut-down and restart operations over a range of superficial gas velocities. The test section of the flowloop has a unique geometry to mimic subsea jumpers, with three low points and two high points standing 13′ 2″ tall. The test section is fitted with twelve pressure and temperature sensors spread regularly, a MEG sensor, a valve to simulate the wellhead choke, and a viewing window. In each test, the jumper low points were loaded with aqueous solutions of MEG (0 to 30 wt%) and pressurized with domestic Perth natural gas at a pressure of 1200 psig and pipeline temperature ranging from 41°F to 25.8°F (+5 to -4°C). The extent of hydrate restrictions or blockages was evaluated through the dynamic pressure drop behavior observed throughout the flowloop. A closer assessment of the pressure drop trace during gas restart suggests that the severity of the hydrate restriction decreases as the MEG content is increased above 10 wt%. Further, our preliminary experimental results illustrate that severe hydrate deposition in the jumper could be completely avoided by injecting MEG at concentrations above 20 wt%. This corresponds to an approximately 50% reduction in MEG content, where ≈38 wt% MEG dosage was required for complete thermodynamic hydrate inhibition at the pressure and temperature conditions used in this trial. Our unique flowloop facility offers new insight toward hydrate formation in complex subsea jumper-like geometries. Our findings may assist operators in controlling the extent of hydrate formation and deposition in jumper geometries, by optimizing the MEG injection and subsequently supporting lower-CAPEX tieback development concepts.

This paper presents various case studies of projects in Gulf of Mexico and West Africa, which demonstrate how innovative jumper mounted flow access technology was successfully adopted to provide a differentiated field development strategy based on standard subsea hardware while still accommodating production enhancing technologies across multiple subsea field developments. The paper also will explain how the technology supports fast track, cost effective subsea tiebacks, by promoting standard equipment and allowing concurrent hardware deliveries to deliver first oil faster. The paper will share client considerations regarding standardization of the main subsea hardware elements, subsea system flexibility and the existing solutions for measurement and intervention packages, such as multiphase flow meters. Project critical paths typically dictate that technologies such as flow meters must be available to synchronize with XT, manifold and jumper manufacture, testing and installation. Thereafter, any retrofit or rework requires significant operational downtime to recover and replace that element of the subsea system. Integrating the retrievable flow access module (FAM) technology into subsea architecture within the jumper envelope addresses these concerns. Promoting standardized XT and manifolds on a field or regional basis, while the FAM technology provides the flexibility to address the individual well production requirements. Further explanation will be provided as to how operators can use the technology to maximize ultimate recovery by accessing a suite of technologies throughout the life of field for both new greenfield and existing brownfield applications. Technologies such as, flow measurement and control, well and flowline hydraulic intervention and remediation, well production pumping and compression, pre-commissioning and secondary well control. Finally, the paper considers the strategic benefits of adopting the flow access technology for subsea field development, promoting subsea system standardization, Capex, schedule and risk reduction compared to the more typical alternatives.

The risk of gas hydrate formation is one of the major concerns for offshore flow assurance. Solutions of methanol (MeOH) and mono-ethylene-glycol (MEG) are most often employed as thermodynamic inhibitors (THI) to prevent the formation of hydrate plugs. This study involves experimental and modeling work to investigate and compare the suitability and effectiveness of methanol and MEG on inhibiting and displacing the water in jumper type configurations during flushing procedures. Numerical analysis aims to investigate the mixing and displacing mechanisms that occur during jumper flushing to optimize key factors such as the position of the injection port and the flowrate of a required chemical inhibitor. This paper presents the experimental results with respect to effect of inhibitor type, injection rate, brine salinity and liquid loading. All experiments were carried out in a 3" jumper system at The University of Tulsa. Simulations using 1D transient multiphase flow simulator were conducted to evaluate its capacity to predict the thermodynamic inhibitor dispersion by using the inhibitor tracking module. The 3D computational fluid dynamic (CFD) simulations were performed with the commercial software to help predict the amount and flowrates of chemicals required, and to serve optimizing the location of injection ports. Comparisons were made between the simulation results and experimental data from full fresh water loading jumper displacement tests with MEG and methanol. From the experiments, several conclusions are drawn. Different dispersion and partitioning mechanisms were observed for methanol and MEG through experiments, especially in the vertical sections and low spots of the jumper. Methanol overriding the water phase at horizontal low spots was captured for the low velocity experimental cases, leaving a large amount of water behind that could result in under-inhibited situations. For the 12% brine tests, less water was displaced for each MEG injection rate, whereas a better mixing of methanol with brine was measured. The 1D and 3D simulations provided reasonable prediction for THI distribution along the jumper after displacement tests, except that neither was able to reproduce methanol overriding the water phase at both low spots. 3D CFD simulations results obtained generally gave better agreement with the results from the experiment. This study provides a better understanding of the displacement and mixing mechanisms of thermodynamic hydrate inhibitors. It helps operators minimize operational risks, reducing the size of the umbilical and decreasing capital costs related to equipment and chemicals.

In the current market, operators are exploring the potential opportunities to optimize the production of existing assets. The goal was to tie a respudded well into existing field architecture, with minimum equipment, time, and cost. The operator respudded a cluster manifold well approximately 50 meters from the tie-in manifold. At roughly twice the distance of the existing well jumper, this approach posed a challenge for a traditional vertical in-plane jumper. A study was completed to compare a few traditional approaches. The options considered werea 50-meter-long jumper able to reach from existing manifold to the new subsea treea tie-in skid with a flow loop supported by a mud mat and two approximately 25-meter-long jumpersa tie-in skid with a flow loop supported by the abandoned wellhead from the replaced treea step-over jumper (SOJ) supported by a suction pilea SOJ supported by the abandoned wellhead. Evaluation concluded that the last option was the most cost-effective solution, with 60% capex savings when compared with the SOJ with a suction pile. The benefit of using the SOJ is that the vessel size can be significantly reduced while minimizing the amount of subsea hardware on the seafloor. Essentially, the SOJ works as an extension of the production jumper. First, the production fluid travels from the subsea tree into a conventional jumper. Then, the production fluid travels through the SOJ, where one end of the SOJ is supported by the abandoned subsea wellhead. Finally, the production fluid travels into the manifold. The SOJ is similar to a conventional half-"M"-shape jumper, which has one outboard hub (connector) at each end. The SOJ, however, replaces one of the connectors with an inboard hub and a step-over module (SOM). The SOM provides a firm connection and an inboard hub interface to connect a conventional jumper. The firm connection is accomplished by landing and attaching the SOM to the plugged and abandoned wellhead. Then, a conventional 25-meter half-"M"-shaped vertical jumper is installed between the tree and the SOM to make the final tie-in to the new respudded well. This is an opportunity for operators to utilize their existing subsea architecture to accomplish cost-saving ventures in their brownfield assets. The SOJ is an efficient solution that allows tie-ins to respudded wells that are farther away from the core field architecture.

The design verification analysis and validation testing of an 8 inch jumper and integrated breakaway joint for the Stones subsea development is described. To control the jumper's failure mode in the event of an accidental pipeline displacement, the assembly was designed such that the maximum bending moment occurred at the location of the breakaway joint. The design and analysis investigated a series of U and M shaped jumper configurations and notched failure point geometries to achieve the desired objective. Linearly-elastic finite element analysis was performed for a series of code check cases to ensure stresses in the jumper and breakaway joint due to normal in-service loads were below allowable values. Nonlinear elastic-plastic finite element analysis was performed to determine the capacity of the jumper and breakaway joint due to pipeline snag loads. The material properties for the nonlinear elastic-plastic analysis were based on tensile tests on specimens taken from prolongations on the actual breakaway joint forgings. The results of the analysis indicate the breakaway joint notch is the weak point in the final jumper configuration, with a moment capacity well below the rated capacity of the manifold connectors. The fatigue analysis concludes the design life of the breakaway joint is greater than that of the jumper assembly welds. Validation tests were conducted to confirm the design of the jumper and breakaway joint. A pure bending test was performed on the breakaway joint and a full-scale test was performed on a portion of the jumper (quarter jumper). A test fixture for the full size quarter-jumper pull test was modified to ensure enough stroke was available to fail the jumper sample in a single, continuous pull. Strain gauges, a data acquisition system, and video system were used to monitor and record the strains and displacements along the quarter-jumper test sample. Both tests demonstrated excellent agreement (96%) with the predicted analytical results obtained during the jumper assembly design phase.

Low hydrocarobon prices have raised concerns over the viability of offshore field development and maintenance over next several years. These oil and gas prices have called for engineering efforts to innovate new technologies to reduce the operational costs and improve the life span of the subsea exploration and production (E&P) systems in inhospitable environments like deep water. Subsea pipeline and jumpers are among these subsea E&P systems and it is crucial for operators to have these systems function in smarter and more efficient way, to adapt the inhospitable environment while generating profits. Due to their geometry and location, these pipelines are typically susceptible to vibrations induced by multiple factors, such as flow-induced vibrations (FIV) and vortex-induced vibrations (VIV). FIV and VIV can cause excessive stress on pipeline joints, thus limiting the operational lifespan of pipelines, specifically jumpers and risers. Every year, oil and gas operators spend significant amounts of money analyzing the cause and effect of these vibrations on the fatigue life of jumpers and pipelines, and installing traditional vibration mitigation devices like strakes and shrouds that have proven to be only partially effective. In most situations, these devices fail to suppress the vibrations and force operators to choke the flow from the well for safety, resulting in lost revenue. This paper introduces the pounding tuned mass damper (PTMD) - a novel device developed in a joint collaboration between OneSubsea and the University of Houston to absorb and dissipate the undesired vibrations in subsea pipelines and jumpers. The PTMD is based on principles of both the tuned mass damper and the impact damper. The tuned mass in the PTMD absorbs the kinetic energy of the structure and dissipates the absorbed energy through collisions on viscoelastic material. During development, detailed numerical analysis and experimentation were performed to study the effectiveness of the PTMD on the jumper. In the experiment, a full size M-shaped jumper was tested in both air and shallow water conditions for VIV at NASA's Natural Buoyancy Laboratory (NBL). The experiment also examined the robustness of PTMD for different frequency VIVs. Experimental results showed that the PTMD effectively reduced the in-plane and out-plane vibration of the jumper up to 90%. The observed reduction in vibration amplitude can reduce fatigue damage to jumpers, thus enabling operators to optimize spending on vibration mitigation devices, minimize lost revenues, improve system lifespan and availability, and enhance operational flexibility. Reduction in stress also means improved reliability and reduction in costs associated with inspection, maintenance, and repair of subsea jumpers and pipelines. These long-term financial benefits and ability to be installed on existing and new jumpers (pipelines) makes the PTMD a desired solution for vibration suppression in deep water environments.

The jumpers are typically curved pieces used to connect manifold system to wells head. In the area, it is normally exposed to significant currents. So the jumpers are subject to vortex induced vibration (VIV). However, the experimental method for prediction of vortex induced vibration (VIV) of subsea jumpers has so far been limited hence the present work advances with ad hoc experimental tests with jumpers. The experiment investigation was performed for one degree of freedom vortex-induced vibration (VIV) in a set of tests to evaluate VIV response of vertically oriented cylinder in the current channel. The experiments were conducted in the Reduced Velocity corresponding to Reynolds the number range: 10000~30000.

Abstract Flow induced vibrations (FIV) have been observed in subsea jumpers. This studywas undertaken to assist the prediction and prevention of FIV in subseaequipment. This paper presents a multi-disciplinary methodology and solutionfor simulating and solving multiphase slug flow induced vibration in a pipelinespan, a jumper and a riser section. The methodology is implemented in userdefined subroutines and functions in CFD and FEA software usingthree-dimensional Computational Fluid Dynamics of multiphase flow and transientnonlinear Computational Structural Dynamics. This technique is equally validfor analyzing flexible and rigid pipelines. This paper has many applications, such as, pipeline, risers, jumpers, manifold/tree piping, and other piping in general. The methodology andtechniques from this paper are applicable to both rigid and flexible pipes withinternal multiphase flows. The results illustrate the process of slug formation and decay inside the pipe, and the dynamic response of the pipe, including dynamic stresses andfrequencies. The mixed flow of gas and liquid in a pipeline span, a jumper anda riser section is shown to form slug flow, induce vibration and potentiallymay lead to resonance of the piping, ultimately resulting in fatigue damage. Acomplete solution of three-dimensional fluid domain and structural domain witha multi-disciplinary approach accounting for interaction and deformationbetween two domains is provided. The proposed procedure provides insight into understanding slug formation anddecay in a pipe while the pipe is also vibrating in response to this slug flow, accounting for the interaction between the two domains. This is a veryrealistic approach for simulating this process and solving this challengingproblem. A platform for analyzing and quantifying the fatigue damage andresonant response due to slug flow induced vibrations, and for betterengineering designs is presented. The methodology and techniques are notlimited to any particular type of equipment. It is robust enough to apply tomany pipe structures, such as, pipeline, risers, jumpers, manifold/tree piping, etc, and for both rigid and flexible pipes.

Abstract The Single Hybrid Riser (SHR) concept has been used successfully in industry onfloaters such as Floating Production, Storage and Offloading (FPSO) vessels indeepwater applications. This concept is especially effective with floaters inareas where challenging metocean environments result in severe vessel motions. The flexible jumper connecting the vessel to the rigid steel riser effectivelyisolates the dynamic vessel motions from the top-tensioned steel riser section. This results in lower strength and fatigue demand in the steel pipe section ascompared to other riser concepts such as a Steel Catenary Riser (SCR). However, the SHR concept also reaches the design limits of the flexible jumper aspressure, temperature, and sour service operating conditions become moresevere. ExxonMobil has demonstrated the feasibility of using a Steel Catenary Jumper(SCJ) as an alternative to the flexible jumper for extending the operationallimits of the SHR concept. This paper presents the results and designconsiderations for a SHR with a SCJ in 10,000 ft. Water Depth (WD) andpressures up to 10 ksi. The SHR/SCJ configuration was determined iteratively byassessing its strength performance in response to wave and current loading, vessel offset, internal content and pressure. Satisfactory strength and fatigueperformance is achieved under harsh North Atlantic and West Africa environmentswith a predominant fatigue condition. As is the case for SHRs with flexiblejumpers in similar conditions, vessel heading control is required to maintainacceptable response during extreme and long term environmental loading. Installation of the SHR/SCJ concept is determined to be within the presentmarket capability of heavy lift vessels, new generation J-lay vessels and FPSOpull-in facilities. A fabrication and installation procedure for the SHR/SCJconfiguration is presented. Introduction The SCJ was investigated as an alternative to the conventional flexible jumperfor connecting a SHR to a turret moored FPSO vessel. The primary advantage ofusing a SCJ is higher pressure and temperature service limits. Increasedresistance to sour service can also be achieved using Corrosion Resistant Alloy(CRA) lined pipe. The SHR/SCJ configuration was adapted from an existing 9-inID flexible jumper SHR conceptual design sized for a design pressure of 10 ksiand 10,000 ft. WD. Modest increases to the air (buoyancy) can depth, jumper length and distancebetween the FPSO turret and SHR base were made to the flexible jumper SHRconfiguration to arrive at the nominal SHR/SCJ configuration. The SCJ wasconnected to the FPSO vessel and SHR using typical flexible joints with taperedextensions. The SHR comprises a buoyancy can, rigid structural tether, TopRiser Assembly (TRA) with goose neck, dual thickness riser section with taperedsteel stress joints at each end, offtake spool assembly and roto-latchassembly. Strength analyses were performed to North Atlantic extreme storm conditions andfatigue analyses were performed to both North Atlantic and West Africa motionresponses. The harsher North Atlantic environment required an internal turretwhile the milder West Africa environment permitted an external turret. Production, water injection and gas injection riser applications were assessedfor feasibility. The SCJ and SHR were designed to standards API-RP-2RD [1], API-RP-1111[2], and DnV RP-F109 [3].

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.

Abstract The increased number of hybrid riser systems, either installed or planned, in deepwater regions across the world has driven a corresponding growth in the use of dynamic riser base steel jumper jumpers to connect these towers to subsea pipelines. The experience of the authors across several West of Africa and Gulf of Mexico hybrid riser projects has identified several key design challenges and highlighted the importance of robust design analysis methodologies. This experience has also demonstrated the key strength and fatigue response issues associated with the design of these jumpers. The analysis techniques and design solutions presented in this paper are applicable to dynamic steel jumpers/spools and are therefore also applicable to static jumpers. These techniques encompass the strength, wave-induced fatigue, modal response and VIV fatigue, riser VIV induced fatigue, slugging-induced fatigue and thermal fatigue analyses, some of which have proved particularly challenging for jumper design. The paper also reviews key input parameters such as flowline expansion, slug profiles and metrology and their impact on the design. The use of finite element riser design software for this design problem has also been evaluated and validated against other general purpose finite element analysis packages. A coupled analysis model of the hybrid riser and base jumpers has proven to be an effective tool for the design and analysis of dynamic riser base jumpers, by implicitly considering the effect of riser dynamic response on the jumpers. Among these responses, the effect of riser VIV on the jumpers has been found to influence jumper feasibility and configuration. One of the key aspects identified was the importance of considering the effects of all fatigue sources at an early stage of the project, and the impact on the extreme response of changes to the configuration to improve fatigue life. The paper will highlight the alternative fatigue and extreme response optimisation solutions that have been developed for efficient jumper design. Moreover, the knowledge of the challenges associated with the design of dynamic jumpers and the accurate definition of input parameters will be shown to be key to an efficient system definition. Introduction Hybrid risers (Single Hybrid Riser and Riser Bundle Towers) have been designed and installed on a number of fields and are mainly used in combination with FPSO type floating structures, either spread moored or turret moored. The majority have been designed for application in the West of Africa (Angola and Nigeria), but have been used more recently in Brazilian waters as well as in the Gulf of Mexico. Rigid Riser Base Jumpers (RBJ) (or riser base spools) are used to connect the bottom of a hybrid riser to the flowline end termination (FLET). Figure 1 shows a typical hybrid riser for West of Africa application [1] while Figure 2 shows typical M-shape and 3-D RBJ designs. The dimensions of the RBJs can vary significantly depending on their shapes. The height of an M-shape RBJ can be between 15 and 25 meters while its length can vary between 25 and 60 meters, depending on the application and limitations that are discussed further in this paper. Riser base jumpers are significantly more challenging to design than static flowline jumpers as they experience dynamic loading as a result of the motions of the hybrid riser subjected to wave and current loading. More specifically, the rigid riser base jumper experiences wave, VIV and hybrid riser VIV induced fatigue from the motions of the riser at the connection point with the RBJ.

ABSTRACT The flow assurance aspects of all subsea projects have a major contribution to the pipe design, field layout, choice of lifting equipment (subsea-pump or air lift), power requirement and system operability. In the context of deepwater mining, the main task is to estimate the pressure drop in the jumper and riser as well as the liquid-solid or gas-liquid-solid flow regime directly impacting the erosion rate and risk of pipe clogging. These are needed to guarantee the production target at steady state and to guarantee the system operability in transient mode at shut-down and system start-up cycles. Current knowledge of solid transport has successfully characterized pneumatic and hydraulic transport of fine particles (powders, sand, or small gravel) in large diameter pipelines. Semi-empirical theories based on concepts such as isolated or hindered slip velocities, mixture properties, and in-situ concentration have emerged to analytically resolve the flow behavior in vertical, horizontal, and inclined pipe. The context of deepwater mining pushes these theories beyond the existing application cases due to the significantly larger particle size combined with small diameter riser and jumper including wave shape to accommodate vessel motions and excursion requirements. The current papers summarize the the flow tests made in a subsea mining experimental flow loop including horizontal and S-shape sections. These tests allows to identify the main flow characteristics of the slurry in subsea mining condition transporting large particles (5mm to 20 mm) in reduced diameter flexible pipe (4??). INTRODUCTION As described in P. Espinasse paper [1], Technip is supporting an internal R&D program that should allow the understanding of critical parameters essential to the design and operability of a subsea mining system. Within this R&D program, a flow assurance study takes place in order to estimate the pressure drop through the riser and jumpers both including an S-shape configuration to respectively accommodate the vessel motion and a large excavation range. An illustration is presented in [T. Parenteau [2] has reviewed the current knowledge for vertical slurry transport to show that the actual available theory based on in-situ concentration is plenty satisfactory to estimate the pressure drop through a straight riser transporting large particle size (2??) in small diameter riser (8?? to 10??). In the same review, T. Parenteau has shown that when introducing an inclined part in the experimental set-up the pressure drop correlations diverge from the prediction due to the formation of significant bed at the bottom of the pipe. In order to understand the key parameters influencing the pressure drop in the S-Shape riser and jumper Technip has built a small scale flow loop test to visualize the flow and measure pressure drop. The parameters that are studied are the flow regime, variation of concentrations, diameters and densities in both S-Shape and Horizontal sections are studied. Figure 1]. T. Parenteau [2] has reviewed the current knowledge for vertical slurry transport to show that the actual available theory based on in-situ concentration is plenty satisfactory to estimate the pressure drop through a straight riser transporting large particle size (2??) in small diameter riser (8?? to 10??). In the same review, T. Parenteau has shown that when introducing an inclined part in the experimental set-up the pressure drop correlations diverge from the prediction due to the formation of significant bed at the bottom of the pipe.

Abstract This paper describes the design and installation of the twin 12- inch flowlines for the Canyon Express project. In addition to the world record-breaking water depth of 7,280 ft (2,220 m) in Mississippi Canyon block 348, several challenges were met and overcome by the design and installation team. Some of these challenges were: the fast track nature of the project; ten in-line sleds and two end-of-line sleds to be installed within tight tolerance areas on the seafloor; in the King's Peak field three sleds to be in the flowline catenary simultaneously with two of these 3,200 feet apart landing in a curve in 6,400-foot water depth; in the Aconcagua field two sleds to be in the catenary 3,700 feet apart in 7,100-foot water depth. The Canyon Express project management team was lead by TotalFinaElf and included engineers in lead positions from the operating partners (BP and Marathon Oil). INTEC Engineering provided support from conceptual to detailed design in all aspects of the project, except drilling. Saipem was the flowline sled detail designer, fabricator, and installation contractor. The vessel used for the deepwater portion of the work was the SaiBOS Field Development Ship (FDS). Shallow water flowline installation work was performed with EMC's Castoro 10. This paper describes several aspects of the Canyon Express project which includes a number of issues pertinent to deepwater flowline work: field development concept leading to selection of the daisy chain concept, flowline mechanical design, installation scope of work and bid strategy, the King's Peak multiple sled installation challenge, multi-phase flow meter and jumper design, installation procedures, and execution of the offshore work. Saipem completed installation of the Canyon Express flowlines in the summer of 2002. The success of this endeavor is due in large part to the collaborative and team philosophy adopted by TotalFinaElf, as well as careful planning and attention to detail of the subsea components and equipment involved. Introduction One of the unique features of the Canyon Express development is that it commingles in a single delivery system the production of three different fields: BP's King's Peak (currently with three producing wells), TotalFinaElf's Aconcagua (four producing wells), and Marathon's Camden Hills (two producing wells). Production from each field is dry gas with nominal amounts of condensate. Expected production rates are in the range of 100 to 250 MMSCFD per flowline. As can be seen in Figure 1, the fields are connected by two (an east and a west) 12-inch flowlines (each approximately 55 mile long) in a daisy chain layout forming a piggable loop. Joining of the two flowlines at the deep end is made with the aid of a 12-inch jumper. The flowlines connect the MP261 JP Canyon Station platform (located in Main Pass 261 in 299 feet water depth) to the King's Peak field 39 miles away at a 6,400 ft water depth, then to the Aconcagua field 11 miles away at 7,100 feet water depth, and finally to the Camden Hills field 5 miles away at 7,280 feet water depth. The flowlines are routed such that they are laid at 60 feet nominal distance to each well.

Abstract The well, flowline, and midline hardpipe jumpers utilized for the Troika subsea production system represent a significant and challenging engineering and construction effort. The system was designed using a horizontal connection method, which is common to all three jumper types. Each of the two 10–3/4 in. OD flowline jumpers that connect the flowlines to the cluster manifold system incorporates a load-limiting joint. Additionally, the flowline and midline jumpers have to allow for significant thermal elongation of the flowlines. The 5-9/16 in. OD well jumpers used to connect the subsea trees to the manifold include not only a production conduit, but hydraulic and chemical injection lines. The production pipe is also insulated. The effect of vortex-induced vibration (VIV), insulation design, flexibility, and rig installation of the jumpers will also be discussed. Introduction The Troika subsea production system is a cluster-type development in 2,700 ft of water in Green Canyon Block 200 in the Gulf of Mexico.1 The manifold is tied-back to and controlled from Shell's Bullwinkle platform, which is approximately 14 miles to the northwest. The two are tied together by means of two 10-3/4 in. OD flowlines and separate hydraulic and electrical umbilicals (Fig. 1). The two flowlines, were installed as a four-part towed bundle.2 Each section is approximately seven miles long. The four flowline sections were connected approximately at the midway point with the midline jumpers. The decision was made to utilize the GC-200 #1 delineation well previously drilled by Marathon, so the template/manifold would have to be located so as to allow completion and connection of that well to one of the system's eight slots. Since the GC-200 #1 well did not encounter any shallow water flow problems, it was felt that locating the remainder of the Troika wells in close proximity to that well would maximize the probability of the same results. Well spacing was driven primarily by the desire to eliminate gyroscopic surveys of the shallow portions of the wells, thus creating the need to separate the wells and template piles enough to prevent magnetic interference. A minimum separation of fifty-five feet was needed, so the proposed well locations were set at a separation of 60 ft ± 2.5 ft. Additionally, the well locations were chosen so as to provide a clear area adjacent to the flowline end of the template/manifold for jumper connections to the flowlines, and to minimize the possibility of impacting a well if a flowline were to be snagged and pulled loose. These same considerations were given to the area adjacent to the pigging loop end of the template/manifold due to the possibility that the Troika system would be expanded into another area. This possibility was, however, given less weight in that a more restricted access corridor was preserved for the pigging loop end than for the flowline end. Common components of all three jumper types are the hub termination assembly, the hub support alignment structure (HSAS) and the jumper pipe itself (Fig. 2). The hub termination assembly contains the hub used to seal the various conduits and is manufactured from a solid forging. The well jumpers were designed using stainless steel since they were on the upstream side of the manifold corrosion inhibitor injection points.

Abstract The subsea development scheme for the Tahoe field utilizes an innovative approach to tie-ins of multiple flowlines using hard pipe fabricated jumpers and vertical collet connections. Umbilical connections take advantage of recent advances in ROV "flying lead" technology to connect bundles of control system and chemical injection lines. The Tahoe field will see between six and ten subsea satellite wells completed with flowlines routed back to a host platform. This approach to tie-ins mimics simple, diver installed spool piece connections and umbilical stab plate connections which were the industry standard methods for several decades. The jumper/flying lead approach also leads to improved (reduced) project cycle time by:allowing tree and flowline hardware manufacturers to concentrate on their manufactured design requirements,building trees, jumper connectors, flowline sleds, flying leads, and other flowline components concurrently,opening up the possibility to use different flowline types, installation methods, and scheduling logistics, andpromoting equipment standardization in the tree, jumper running tools, and structural interfaces. The paper also discusses the "off tree" design philosophy which was influential in gravitating to the jumper/flying lead approach. Introduction The use of simple, diver installed spool piece connections between pipelines and trees for subsea completions have been an industry standard for several decades. As the industry moved beyond efficient diver depths, these were replaced with numerous diverless connection methods such as deflect-toconnect and flexible pipe pull-in, and lay-away connections, requiring additional hardware and/or structural bracing on the tree (or subsea facility). Similarly, umbilical control connections which were done by divers were replaced with multi-bore connectors at the diverless flowline connection for their make-up. The need for reduced project cycle time, the push toward equipment standardization, and the expanded capabilities of ROVs and their tooling, has brought diverless flowline connection technology full circle, back to the simple approach to field connections. The first full utilization of diverless spool piece flowline connection between separately installed flowlines, umbilicals, and individual subsea trees in an "old fashioned" field fitted configuration has been at Shell Offshore Inc.'s Tahoe field, offshore Louisiana, in water depths up to 1800 feet: Shell's Tahoe field will see between six and ten individual subsea satellite wells connected with flowlines back to a host platform twelve miles away. Standardization of tree and flowline connection completion equipment, along with concurrent design and manufacture were strong design preferences in light of reducing manufactured equipment cycle time and overall project cycle time. Each satellite well has common and specific requirements based on its service. Every subsea completion required flowlines which accommodate paraffin, hydrate, and corrosion remdiation. Unique requirements for each well include:flowline size, insulation, multiple or future well connections, and future intervention needs.

ABSTRACT This paper describes practical aspects of the diverless jumper connection system used to connect Enserch's two 12-inch pipelines to the subseatempiatein2110 feet water depth. The paper is a follow-on paper to OTC 7543 which describes engineering aspects of the same jumper system. Project costs, schedule, and details of the jumper testing and installation are discussed. Testing was performed to verify ]umper design and installation operations. Offshore installation used two measurement methods for verification of jumper geometry. INTRODUCTION Two rigid pipe jumpers were connected in August of 1994, one each for oil and gas export, in 2110 feet water depth. The jumpers were made of 12.75"0 × 0.888" wall thickness API-5L Grade X8Opipe, with lengths of 71' and 105' for the oil and gas lines respectively. All subsea activities were performed using Remotely Operated Vehicles (ROVS); including jumper measurements and installation. Prefabricated jumper pieces were sent offshore where final cuts and welds were made. Prior to offshore activities, testing of all jumper components and fully assembled jumpers were performed. Testing included full scale failure tests of the load limiting flange, tank tests using ROVS to verify diverless operations, and simulated jumper measurement and fabrication on shore. The previous paper (OTC 7543), presented at last years OTC, addresses in some detail the design considerations. It discusses election of the connection method, describes each of the main jumper components, presents jumper flexibility and stress analyses, and describes in general the installation procedure. PROJECT SCHEDULE The overall project schedule from study phase through Installation took 1 year and 4 months beginning in May of 1993. Evaluation of connection methods and installation options took two months. Jumper design began in July of 1993, and was complete in October of 1993 (a total durationof four months). Supply of mechanical connectors and jumper fabrication was bid in November, and awarded in the first week of December 1993. Enserch received delivery of the first components in April, and final components at the beginning of June, 1994. Pipeline installation began in May, 1994 and was complete by mid August of 1994. Jumper installation occurred during the last two weeks of August 1994. PROJECT COSTS Because of the fast project schedule, jumper connectors and pre-fabricated jumper piping assemblies were bid together. Included in the jumper package were two spare cullet connectors, functional testing of the connectors, and ROV wet testing of the connectors. This portion of the package cost approximately $700,000. Additional jumper testing and components cost less than $200,000;h?ckfting load-limiting flange testing, measurement tool testing, site integration testing, and fabrication testing. Ail offshore jumper operations were performed using the DB-50. Slightly less than 4 days total, for both jumpers, were attributable to jumper operations (including sled installation). This equates to approximately $600,000. Therefore, the total costs attributable to the jumpers, Incorporating engineering, was approximately$1,600,000. JUMPER SYSTEM DESCRIPTION The components of the rigid jumper system developed for the GB 388 project include:Jumper or spod piece, including:Mechanical connection system at each end

ABSTRACT In the development of the Tahoe prospect, Shell Oil Company, designed the flowlines to be dual 4" nominal lines to begin in 1500 feet of water and laid to the Bud Platform in 273 feet of water. The flowlines were to be laidsimultaneously since they were to be tied into previously laid flexible jumper lines. The flexible jumpers were retrieved, the rigid pipewelded to the ends and the flowlines laidutilizing the Reeled Pipe Method to Main Pass 252, the location of the Bud Platform, where conventional risers were installed to make the surface connection. This paper will describes the pipe laying techniques used for this project. Specifically, the improvements in stinger design to permit lower horizontal tension loads, the use of dualpipe reels to maximize productivity, and the advantages of laying from a DP vessel. INTRODUCTION Shell decided to utilize sub-sea technology in the development of the Tahoe Field. It Wi3S decided to pre-drill a well, install a control umbilical and lay the flowlines from the well location to an existing platform. The flowlines and control umbilical were tied into the well with the use of a Flowline Connector Assembly (FCA). The FCA was lowered and connected to the well by a drilling rig which was positioned at the well sight. Tahoe is located in 1500 feet of water at Viosca Knoll 783 and the existing platform, Bud, is in 273 feet of water at Main Pass 252. The project consisted of laying approximately 60,500' of 4.5" × 0.438" wt, X-42 Production Line pipe and approximately 60,500' × 0.438" wt, X-42 Annulus pipe. Each flowline terminated with 300 feet of 4.5" × 0.531" wt, X-52 pipe. Both lines arc coated with Fusion Bonded Epoxy (FBE) coating as arc the field welds. Sixty-five (65) pounds of sacrificial aluminum anodes are attached to the pipe at 640 feet intervals. The plan was to recover two previously laid flexible pipe jumpers, approximately 2,()()() feet long, weld the rigid pipe to the flexible pipe and lay away from the WCII to the Bud Platform. Because of the water depth and the complexity of the job, the DB 50 was the vessel of choice. The water depth was such that moored vessels arc difficult to work, although, there halve been some recent development to mooring systems that have increased water depths limitations. The DB 50's Dynamic Positioning (DP) system is well suited for this water depth. It was also decided to utilize the Reeled Pipe Method to install the flowlines. This would minimize the time in the field, as well as weather exposure for the construction vessel. This combination made for a very cost effectivesolution for this project. PIPE REELING The pipe, delivered in double random lengths, was welded and reeled onto the pipe reels at the land facilities in Morgan City, Louisiana, The pipe was fabricated into 360 feet long stalks and rolled onto the storage rack until sufficient stalks were completed to begin the pipe reeling process.

ABSTRACT This paper describes the diverless pipeline jumper connection system that will be used to tie-in two 12-inch export pipelines to a subsea template in 2130 feet water depth. The paper discusses selection of the connection method and design of the jumper system. Key features of the system include a ROV deployed and operated measurement tool, diverless mechanical connectors, a load-limiting anchor flange, flexibility to accommodate installation and operating conditions, and a pipeline Iaydown sled capable of being layed through a stinger. INTRODUCTION Several diverless pipeline connection systems have been used in the past and several others are being developed. These systems are designed with hydraulically operated mechanical connectors and rely on the ROV (Remote Operated Vehicle) to execute the activities previously performed by divers. To facilitate ROV intervention, connection operations are made simple and reversible to allow recovery of malfunctioning equipment for diagnosis and repair or replacement. This approach has been adopted for design of the jumper connection system for tie-in of two 12-inch export pipelines to Enserch's Garden Banks 388 subsea template in 2130 foot water depth, described in this paper. Alternative jumper configurations were evaluated prior to selection of the system depicted in Figures 1 and 2. The design of the jumper system involved:Flexibility analysis to determine jumper length, overall geometry and required measurement/fabrication accuracy. In addition, target areas for pipe end placement relative to the subsea template were defined.Evaluation of the mechanism for aligning the mating halves of the mechanical connector. A coarse alignment system was needed to bring the mating halves within the capabilities of the mechanical connector.Installation and operation analysis to determine loadings and verify that all stresses in the piping and structural components of the jumper system were within allowable limits.Failure mode analysis of the jumper piping and load- Iimiting flange to verify that the design loads for the template mounted receiver structure and associated piping were sufficient to prevent damage resulting from a pipelines nag load. Fabrication and land testing of the jumper system depicted in Figures 1 and 2 is scheduled to be completed in April 1994. The jumper system is currently planned to be used to tie-in the oil and gas export pipelines to the subsea template in August 1994. BACKGROUND Two diverless tie-in methods were evaluated prior to selection of jumpers for connection of the 12"diameter oil and gas export pipelines to the subsea template. These included:the lateraldeflection method;andpipejumper or spool piece method. First end connection methods such as direct pull and stab & hinge-over were considered and eliminated early in the evaluation process, since these methods impact selection of installation equipment. The direct pull method requires two vessels and results in high loads imparted onto the template. The stab & hinge-over method requires a purpose built connection system and requires the pipe end to be lowered in a vertical orientation which is most suitable to the J-lay method of pipeline installation.