A Disconnectable Fluid Transfer System for Dynamically Position Ship Shaped provide great means for managing risk as it relates to avoiding harsh environmental events and protecting the subsea facilities in the event of a drive off. A set of alarm systems on the vessel, provide disconnect criteria due to weather conditions, fire, process emergency shut down and vessel offset from nominal position. A buoy, connected to the vessel, detaches to allow the vessel to either relocate or resolve the issue triggering the disconnect. The buoy sinks to a preset level via an attached clump weight. This operation has profound implications for the riser and umbilical system design as it must be designed for two operating modes, connected and disconnected, along with the transient dynamic cases going from one to the other under both planned and emergency scenarios. The paper presents the challenges faced during the Phoenix field riser and umbilical analysis to define the operational envelope for these components, including the development of the load case matrix from the huge parameter space to satisfy regulatory requirements, and the operational importance of the connection and disconnection procedures. Additionally the paper addresses the implemented passive monitoring system developed as part of the integrity assurance for the disconnectable system. Introduction The application of floating ship-shaped vessels as offshore platform solutions, either as tanker conversions or newlybuilds, was first introduced in the late 70s of the last century. Since then, the number of these platforms steadily grew and nowadays there are nearly 200 of these in operation. The increase is down to more flexibility and value they offer compared to other options. Depending on development philosophy, they can have processing facilities onboard (Floating Production Unit - FPU), they can be used for storage only (Floating Storage Offloading- FSO) or both (Floating Production Storage and Offloading - FPSO). Further development of on-board facilities is currently under way and the first Liquefied Natural Gas (LNG) FPSOs will be commissioned in the near future. Geographically, they can be found in virtually every offshore oil and gas producing corner of the world, West Africa, Middle East, North Sea, Asia-Pacific and South America. Depending on the local environmental conditions, these vessels can be spread moored, turret moored with weathervaning capabilities and in hurricane/typhoon-prone areas they are moored through a disconnectable turret, which allows them to release the turret and sail away until the weather conditions improve and they can resume operation. Until recently, the only oil and gas producing part of the world without FPSOs in operation has been the Gulf of Mexico (GoM). The reasons for this vary, from available infrastructure to previous lack of regulations for the FPSO operations in the GoM (Regg 1999, [1]). However, the trend is now changing and last year saw the first FPU, Helix Producer 1, in the GoM going into operation in the Helix ESG operated Phoenix field.

This paper presents important findings while executing a detailed qualified design of a large (3,000 + barrel), subsea (to depths of 10,000 fsw) production chemical storage and injection system. The design drivers for the system were safety first, extensive utilization of existing commercially available equipment / tools / methods, and a re-usable shuttle system that allows for delivery of production chemicals as a service versus the current approach where an operator / owner makes a capital investment. The system is designed to be compatible with existing production chemical formulations and features multiple barrier design between the chemicals and the environment. Placement of the storage and injection system directly on the seafloor in close proximity to the point of need eliminates expensive chemical umbilicals, removes significant topside chemical storage and injection kit weight and space requirements at host facility and isolates hazardous chemicals from platform workers. The re-deployable shuttle economically allows inspection, repair and maintenance to take place quayside with the ability to upgrade equipment as technology progresses and / or quickly and cost effectively adjust to ever-changing field requirements. Subsea wells have been proliferating over the last decade with ever-longer tie-backs to enable commercial recovery of small resource pools that are unable to support a traditional floating system development. Virtually all wells, especially subsea, require various volumes and types of production chemistries during their operational life. For subsea wells, the incumbent technology is chemistry delivery via umbilicals. In rare occasions, small volumes are sometimes delivered via single trip, disposable containers, principally during intervention activities. As tie-back distances have increased, so have the technical challenges with their attendant mushrooming costs. These challenges include the needs for; special corrosion resistant materials, resistance to high pressures differentials, material flexibility and ‘crimp – resistance’, and long term reliability. Additionally, some of these chemicals are high viscosity and as the tie-back distances increase, so does the pressure drop of the flowing fluids. In some cases, the risks of plugging and the magnitude of the delta-pressure drop in ½? – ¾? chemical tubing within the typical umbilical can preclude tie-backs of long offsets from the host / hub facility. The subject system overcomes many of these challenges by locating a large, pressure compensated storage and injection facility directly on the seafloor in close proximity to the point of need, thus qualifying it as enabling technology for extra-long tie-backs and enhancing technology for short tie-backs, de-bottlenecking, or early production system usage.

This study is part of a public-private partnership / industry sponsored project developing a detailed design of a qualified subsea 3,000+ barrel chemical storage and injection system, that requires maturing an innovative subsea facilities deployment and recovery technique for large and heavy loads. This paper describes the innovative Anchor Handling Tug Supply (AHTS) based method that was developed to provide this installation capability which is readily adaptable for accurate, safe, and cost effective subsea placement of a wide range of subsea systems and components. Design and simulation studies, supplemented with an industry Subject Matter Expert (SME) populated Qualitative Risk Assessment (QRA), have validated the features and functional performance for installing and recovering the chemical and injection facilities, which have a projected mass of around 1,000mT. The initial application is to install the 3,000 useable barrel chemical storage and injection system, after which with minor engineering and procedure updates, will be suitable for the cost effective installation and recovery of other large and heavy subsea facilities. The business driver to mature this technology is the operational cost savings that is achieved by using two anchor handling vessels of opportunity for operational support. In addition, the same installation spread is capable of recovering the installed facilities should facility repair, maintenance, or refurbishment be required. The recovery procedure is essentially the reverse of the installation operations. Thus the potential exists for this deployment technology to create an environment for game changing conditions impacting the architecture, installation, and maintenance of major subsea installations as the technology is matured and field utilized. This significant developmental project is being monitored and advised by industry representatives through the active representation of operators, service companies, and OEMs participating in the project's technical advisory committee and through the significant contribution of data and expertise.