The Na Kika Basin in the eastern Gulf of Mexico experienced debris-flow events in geologically recent times (Late Pleistocene to Recent). To assess the potential risk of such debris-flows to the pipelines and structures associated with the Na Kika field development we performed a semi-quantitative risk assessment of the potential impact of debris-flows to the proposed pipeline network. The numerical model BING was used in conjunction with available sediment core information, seismic, and bathymetric data to model a number of sediment failure scenarios. Calibration of the model was done using data from two existing debris flow deposits. After calibration the model was used to simulate specific scenarios, using bathymetric profiles extending from potential source failure areas to proposed pipeline locations. We found that flows with sufficient volumes to impact the proposed engineering structures are generally inconsistent with observed geologic conditions in the area. Introduction This study was motivated by the proposed development of the oil and gas reservoirs located in the greater Na Kika Basin. Figure 1 shows the study area location in the eastern Gulf of Mexico. Seafloor attributes illustrate the complex topography associated with salt domes surrounding the basin (Figure 2). A previous studies of the seafloor in the greater Na Kika Basin identified two subsurface debris flow deposits (GEMS report, 1998). Deep-tow data acquired recently as part of pipeline route evaluation showed a debris flow deposit located on the seafloor in block MC 470 (Figure 3). These observations suggest the Na Kika Basin may be susceptible to future debris flow events that may pose risk to engineered structures in the area, such as pipelines, flexible tubing and anchors. Results of simulations using the numerical model BING (Imran et al., 2001) are used to better understand the risks associated with potential debris flow events in the Na Kika Basin. The inputs parameters for the model are estimated from available field data. These input conditions include information about sediment rheology, flow-path bathymetry (Figure 4), and size of failure. The simulations were performed in two phases. In Phase I we perform a calibration of BING using available seismic and core data from two debris flow deposits located in the Na Kika Basin. In Phase II, we use the calibrated model and fieldderived input parameters to simulate several "attack" scenarios, i.e., forward simulations to determine the conditions at which a pipeline or seafloor structure would be impacted in case a debris-flow occurred. For a given flow-path we explore a range of failure positions and failure volumes and gauge risk to the proposed engineering structures in the area. The present study does not include an assessment of slope stability, or probability of a seafloor failure occurring at a particular location. Instead, our approach is to evaluate what happens to the failed sediment after failure. The results are evaluated vis-Ã -vis the local geological conditions. The volume of failed sediment, the rheological properties of the failed mass, and to a lesser extent the geometry of the failure, influence the runout distance of the flow. In the simulations, we iteratively vary these parameters until a best match is found between the model and field data for both runout distance and thickness, given the rheological conditions and initiation point assigned as input.

Subsea pipeline spans, when experiencing bottom ocean currents, are prone to vortex-induced vibration (VIV). Experiments and computational fluid dynamics (CFD) are conducted to evaluate the effects of the pipe stiffness on its first mode in-line VIV motion, primarily in the reduced velocity range from approximately 1.0 to 4.0. Experimental results also indicated that there was obliqueness in motion trajectories, which could have impacts on VIV design of the free spans. The main findings of this investigation are presented in this paper.

The Auger export pipelines are connected to the TLP by steel catenary risers (SCRs). This is believed to be theftrst time steel pipe has been used for catenary risers. SCRs offer advantages over tensioned risers, since SCRs need no heave compensation and no subsea connections, and over risers made of "flexible pipe", since SCRs are much less expensive. However, significant design effort was required to prove that the SCRs could safely withstand environmental loads and the effects of TLP motions. The design effort consisted of extensive dynamic analyses as well as full scale fatigue testing of both the riser joint welds and the flexible joint that connects the riser to the TLP pontoon. Devices which suppress vortex induced vibrations were also tested. SCR installation is accomplished by lowering the riser on the abandonment and recovery cable from the J-Lay installation vessel and transferring the riser on a chain that is run through a chain jack hung from the TLP upper deck structure. A special Installation and Maintenance System was built for this purpose. INTRODUCTION Oil and gas export pipelines are connected to Shell's Auger Tension Leg Platform (TLP) by steel catenary risers (SCRs). Each SCR is essentially an extension of the pipeline [1], suspended in a near-catenary shape from a TLP pontoon to the seafloor. See Figure 1. The SCRs are composed of steel pipe sections welded end-to-end, terminating at a flexible joint which is supported by a receptacle mounted on the pontoon. Piping is routed from the deck down a TLP column and along the pontoon, where there is a flange connection to the top of thei1exible joint. This is believed to be the first application of steel pipe for catenary risers. SCRs offer advantages over risers made of "flexible pipe" since SCRs are much less expensive. SCRs also offer advantages over top tensioned risers since SCRs need no heave compensation, no subsea connections, and no flexible jumpers to transition to fixed piping at the production deck. For some applications a disadvantage of catenary risers compared to top tensioned risers is the length of active footprint on the seafloor, but this is not the case for Auger. Each SCR has an outside diameter of 12.75 inches and a wall thickness of 0.688 inch. The pipe material is API 5LX-52. The entire riser has a triple coat epoxy/polyethylene coating for corrosion protection and high abrasion resistance in the touchdown area. The upper 500 feet has a 0.5-inch thick neoprene coating for additional protection and marine growth prevention, plus triple-start helical strakes for suppression of vortex induced ibration (VIV). The flexible joint provides a rotation capacity for the upper end of the riser of ±14 degrees from the installed orientation of the riser, which is 11 degrees from vertical. See Figure 2. The maximum operating pressure is 2160 psi and the maximum operating temperature is 100 degrees F.

Electrically-heated flowlines offer a fundamentally different and simpler approach to managing hydrates in deep water subsea oil flowlines, when compared with conventional solutions. Current operating and design strategies used to manage hydrates are compared with strategies that could be adopted in fields having electrically-heated flowlines. The paper also identifies additional opportunities to handle other flow assurance challenges.

During offshore lifting operations, appropriate characterization of the dynamic forces is critical to ensuring that the proper lifting equipment has been selected and designed. When a load is supported by a wire rope, or any member that will not support compression, there is a possibility of the rope becoming slack during the lift. The resulting shock load when the rope becomes taut again can produce significant impact loads in the lifting equipment, which is a situation preferably avoided. Thus, of particular importance is the reasonably accurate estimate of the probability of occurrence of sudden loading events. During offshore lifting operations, this situation can occur under the following circumstances: 1) During a transfer of a weighted load between two vessels in an offshore wave environment. 2) Lowering a load through the water surface, particularly in a wave environment. 3) Lowering a load through the water column with significant motions of the support at the surface. This paper deals with the first two situations. First, a model to predict the probability of slacking the rope while lowering a load through the water surface in a wave environment will be presented. Secondly, some commentary will be made about the possible magnitude of the shock loads that can occur during vessel to vessel transfers and lowering through the water surface. Finally, a brief comparison will be made between these models and others that have been proposed within the industry, some of which have been incorporated in design standards and guidelines.