As more satellite wells are tied into existing subsea infrastructure, fluid flow velocities in subsea piping can be significantly higher than was anticipated during design. These higher velocities may lead to increased flow-induced vibration (FIV) as well as erosion due to sand transport. FIV is caused by flow-induced turbulence and associated pressure fluctuations, typically generated at piping geometry, such as bends or tees. These flow-induced fluctuating forces pose structural integrity concerns for subsea piping in terms of cyclic stressing and, over time, a threat of fatigue failure. Currently, a high-level screening approach for FIV exists as part of the Energy Institute (EI) Guidelines on the Avoidance of Vibration Induced Fatigue Failure (AVIFF). However, the EI AVIFF guideline does not provide a framework for the direct estimation of vibration levels, stress levels, or fatigue life. To address this gap, we have developed a comprehensive screening procedure for FIV in subsea piping. Assets which fail a screening based on published guidelines (e.g., EI AVIFF guidelines), may undergo a more detailed screening based on numerical simulation. The paper gives an overview of such a screening, based on computational fluid dynamics (CFD) and structural finite element analysis (FEA). CFD is a specialized field requiring specific expertise and a significant amount of computational resources. The CFD calculates the unsteady signature of flow-induced forcing on the piping for a given flow condition (i.e., multiphase flow). This forcing is then applied to a structural Finite Element (FE) model of the piping, with the output being displacement, acceleration, stress (among possible others) and ultimately a fatigue life estimate. FIV and erosion measurements are much more costly subsea than they are on topsides. Hence, advanced simulation techniques are valuable tools in determining the integrity status as well as the safe operating limits of subsea piping.

Abstract Development of the Hudson field took place over the period December 1992 to January 1995. This was a time of generally low oil prices and one in which the combined effects of oil price, smaller discoveries and diminishing reserves but increasing development and operating costs, were being faced by the industry. The Hudson field development was conceived under these circumstances and demanded that a cost effective solution be identified in order to make the development viable. Initial studies of conventional stand-alone and tie-back options, whilst endorsing the commerciality of the project, failed to maximise its economic potential or to meet the business-driven objectives of the co-venturers. In light of this, an innovative two-phase development was devised, utilising a leased FPSO for the first phase of production and a subsea tie-back to the Tern platform for the second phase. This gave the benefits of an optimised reservoir development plan for the second phase, minimum capital outlay at the front end and early production and generation of cash-flow, which effectively financed the main field development. In addition to this novel facilities solution, the development also implemented many of the concepts which have since become synonymous with the industry's CRINE initiative, most notably the use of functional specifications, standard components, minimum operator intervention in contractor/supplier activities, minimum size of operator's management team and a novel contracting strategy, giving greatest opportunity for cost savings. The net result of these various initiatives was completion of the facilities installation and commissioning two months ahead of the targeted first oil date and at a cost of 29% below the original budget. Field Location/Description The Hudson field is located in 157 metres of water in Blocks 210/24a and b of the northern North Sea and at the western edge of the East Shetland Basin (fig 1). It is the most westerly of the Brent group of fields, the Tern platform lying 11 kilometres to the east and providing the closest point of access to the Brent system infrastructure. Participants in the field are:- Amerada Hess Limited: 28A62% Cieco UK Limited: 25.769% Mobil North Sea Limited: 20.000% Shell UK Limited: 12.885% Esso Expro Limited: 12.885% The field was discovered in 1987 by the then Operator, Amoco UK Ltd. In 1988, Amoco disposed of its equity share to Shell/Esso, with operatorship passing to Amerada Hess Ltd. A development plan was subsequently submitted to the DTI in October 1992, with approval being granted at the end of that year. The reservoir sandstones in the Hudson field are assigned to the Brent Group which comprises five formations; Tarbert and Ness which form the Upper Brent Unit and Etive, Rannoch and Broom, forming the Lower Brent Unit. As with many Brent sandstone oilfields, significant heterogeneities are present within the formations and in addition, variation in sand quality at the layer boundaries affects vertical transmissibility. At the time of preparation of the Field Development Plan appraisal data was limited and oil water contacts (different for Upper and Lower Brent) were inferred from IFFT pressure measurements and were therefore uncertain as pressures in the field were affected by other field developments in the basin. This, coupled with ranges and uncertainties assigned to seismic depth conversion, oil saturation, net to gross ratio and possible erosion, led to a range of Stock Tank Oil In Place estimates (STOIP) of between 109 and 341 mmbbls, the most likely figure being 209 mmbbls with corresponding recoverable reserves of 86 mmbbls. Anticipated peak production of oil was 46 MBPD in year one, an annual average rate of 38 MBPD and a forecast field life of 12 years. Peak fluids production rate was predicted to be 55 MBPD. P. 219

Abstract The Argyll field came onstream in June 1975 and produced the first oil from the United Kingdom Continental Shelf (UKCS). The floating production concept adopted for the field demonstrated an innovative cost efficient approach to developing a marginal field. The initial field life expectancy was three to five years and cost sensitivity was embraced as the only viable way to ensure that the field survived longer than originally forecast. This paper reviews some of the Argyll field innovations from initial design into ongoing operations and on through to abandonment. Technical solutions which result in low capital investment but then give higher than preferred operational costs, do not necessarily result in reduced field life. A "Tight' approach to operational cost control is vital in the early years of a field's life so that later year cost control is a natural progression and not a desperate rearguard action. Cost control is a state of mind and must be engendered into the Ethos of a company. The question, why?, is probably the most powerful tool that any individual can apply in the approval process, no matter the level of that approval. Expenditure approval set at an appropriate level coupled with staff committed to a continuous search for improvement, results in an operations group which manages their own business, This level of understanding acts on market changes rather than reacting to change, thus resulting in true cost control. Introduction Hamilton Oil Company Ltd. (Hamilton Brothers Oil and Gas) was Operator of the Argyll field in Block 30/24 of the UKCS in conjunction with other field owners, Elf Enterprise (Caledonia) Ltd., Texaco North Sea UK Ltd., Lasmo (ULX) Ltd., and Monument Resources., from first oil in June 1975 to last oil in October 1992. During that period two satellite fields were added to the Argyll system, Duncan in 1981 and Innes in 1985. The initial, albeit uncertain, reservoir assessment of recoverable oil for the Argyll area was 25 million barrels over 5 years. Argyll ultimately produced 73 million barrels, Duncan produced 19 million barrels and Innes produced 5 million barrels. The total production from the field complex was 97 million barrels of oil over a 17 year period.