The Buoyancy Can Riser Tensioner (BCRT) systems are designed to provide tension to Top-Tensioned Risers (TTRs). BCRT systems do not transfer the riser weight to the floater and they minimize the interaction between the floating platform and the riser system. For deepwater field developments, this attractive feature allows efficient design of the floaters as well as the riser systems. Although, the vertical riser load is not transferred to the hull, the BCRT system makes lateral contact with the hull at several locations. During the past 3 years, analytical models have been developed to characterize mechanics of the contact between two large floating bodies (buoyancy can and hull) and compliant guide hardware has been developed. Placement of a compliant guide between the hull and the BCRT has become the current practice for design of Spar floaters. The initial development of the analytical models and the compliant guide hardware coincided with the Horn Mountain project. The project team placed extensive instrumentation on the hull and compliant guides with a vision to confirm robustness of the guides and to calibrate analytical models used during the design phase. This paper presents a summary of the data collected on the performance of the Spar hull, compliant guides, and the riser systems for storms up to 25 ft of significant wave height. Analytical methods and predictions are presented to characterize the dynamic interaction between the BCRT system and Spar hull.
The increasing need to develop marginal accumulations using subsea equipment and common facilities has highlighted the challenge of the allocation and optimum distribution of fluids within these systems. The commingling of produced fluids requires that an auditible procedure is employed to accurately back-allocate fluids produced from different fiscal regimes. Similarly, there is a requirement to optimise lift gas allocation to ensure that the available gas provides the maximum incremental oil production. A method of optimising lift gas allocation and allocating production within a manifolded subsea development has been developed for use on a portable computer. The basic requirements for the model were that it should be usable by offshore personnel and allow a quick comparison of different operating scenarios. INTRODUCTION Prior to start up of the Ivanhoe and Rob Roy fields, one of the development scenarios considered early water breakthrough with an immediate need for gas lift as an artificial lift mechanism. The variable nature of the two reservoir units within each field dictates that some method of optimising the distribution of lift gas between wells will be necessary to ensure that the available gas-lift gas is used to best effect. Software has been developed to allocate the lift gas in order to maximise productivity by balancing incremental oil production per unit of injected gas for each well. The gas lift optimisation model can then be operated as a decision support system whereby the current and optimum production rates can be compared to recommend operator action according to a set of decision criteria. The production asllocation model can be used to monitor production by utilising the wellhead pressure performance curves created by the system performance module of the optimisation model. This feature enables the correct allocation of total production to individual wells between well tests. The model will be fully employed in the day-to-day management of the field when gas-lift is required to maintain production rates. In its predictive mode the model can be used in combination with reservoir simulation data to identify the incremental improvements that may be achieved through gas lift later in the field life and the impact of gas deficiency. PROJECT BACKGROUND Reservoirs The Ivanhoe and Rob Roy fields are located in the UK Sector Block 15121a, approximately 110 miles north east of Aberdeen. As development of the Ivanhoe and Rob Roy fields progressed, exploration in the 15/21 area continued, resulting in the discovery of the Hamish field with well 15/21b-21. Hamish was appraised, developed and on production two years after its discovery, using the existing Ivanhoe/Rob Roy infrastructure (Figures 1 and 2). The Ivanhoe and Rob Roy and fields produce from two Jurassic intervals, the Main and Supra Piper. The Hamish field produces only from the Main Piper. The Main Piper sands are thicker and generally more productive than the Supra Piper. There are three distinct crude types within the fields (Table 1). Reservoirs The Ivanhoe and Rob Roy fields are located in the UK Sector Block 15121a, approximately 110 miles north east of Aberdeen. As development of the Ivanhoe and Rob Roy fields progressed, exploration in the 15/21 area continued, resulting in the discovery of the Hamish field with well 15/21b-21. Hamish was appraised, developed and on production two years after its discovery, using the existing Ivanhoe/Rob Roy infrastructure (Figures 1 and 2). The Ivanhoe and Rob Roy and fields produce from two Jurassic intervals, the Main and Supra Piper. The Hamish field produces only from the Main Piper. The Main Piper sands are thicker and generally more productive than the Supra Piper. There are three distinct crude types within the fields (Table 1).
A 10-inch Steel Catenary Riser (SCR) was installed in the Petrobras XVIII semi-submersible production platform, moored in 910 meters water depth in the Marlim field, Campos Basin, offshore Brasil. This is the first SCR ever installed on a floating moored platform. In order to evaluate and verify the methodologies and to calibrate the numerical models used in the riser, mooring system, and platform design, it was necessary to establish a monitoring program for all the relevant parameters (environmental, platform positions and motions, riser loads and stresses at the top and at the touch down point (TDP), and vortex induced vibrations). The TDP monitoring system consists of several strain-gage collars in pipe sections close to the TDP, subsea strain conditioning, control and data storage electronics, and an acoustic telemetry data transmission system. Mobilising this complex system required several innovative solutions. The paper describes the monitoring system developed to measure tension and moments at the Touch Down Point (TDP) region of an SCR, its installation and operational aspects, and its performance to this date. Introduction As part of its continuing effort to develop hydrocarbons in deep water responsibly and cost effectively, Petrobras initiated a project to assess the feasibility of using Steel Catenary Risers (SCR) on moored, floating production platforms in deep water. Numerical analyses to predict the stress history in the touch down region of the SCR sometimes presented different results depending on the numerical model used. Accordingly, Petrobras considered it essential to obtain full-scale data from a prototypical 10 inch SCR installed in the PXVIII, a semisubmersible FPSO moored in 910 meters of water. The experiment was outlined by the Petrobras R&D Center's Exploitation Projects Division. Its Subsea Engineering Group prepared Technical Specifications for the Environmental, Platform Positions and Motions, Top Loads, TDP Loads and Vortex Induced Vibrations Monitoring Systems and its processing, and is conducting this monitoring project. The measurement of the stresses in the touch down point of an SCR in deep water had never been done before and presented several difficulties. This paper describes the development of a monitoring system to do that.
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