Abstract

The Nova subsea oilfield development is located in the Norwegian sector of the Northern North Sea and will be developed with 3 oil-producer / water-injector pairs. Two of the production wells will be open hole horizontal wells of moderate length (400 – 1000 m) completed with sand screens equipped with ICDs (inflow control devices) to facilitate the best possible clean-up and to optimize inflow distribution.

The injection of filtered and treated seawater has been selected for reservoir pressure support. Despite the relatively low Barium content (<70 mg/L) in the formation water, sulphate scaling is expected to appear in the production wells once injection water breakthrough occurs. In order to maintain well productivity, periodic successfully placed scale squeezes are essential.

As the horizontal wells are completed across multiple reservoir segments in the same layer, uncertainties in fault transmissibility and water injector connectivity may result in variation of pressure along the well, thereby complicating squeeze placement. Traditionally, variation in rate and fluid viscosity have been applied to improve placement of scale inhibitor in the higher-pressure layers connected to the water injector. Chemical vendor simulations indicated that for a pressure variation below 5 bar adequate placement could be achieved with non-Newtonian fluids, however for higher differential pressures significant portions of the well would go untreated.

The Nova sand screens are equipped with inflow control devices designed to allow the best possible clean-up after drilling and optimize inflow during production by distribution of drawdown and limiting of annular flow. The idea of using the same principles for scale squeeze was difficult to prove due to limitations in vendor placement software and other industry standard modelling packages not being able to model the combination of ICDs and non-Newtonian fluids.

Computational Fluid Dynamics (CFD) on the other hand can simulate various factors that could influence the placement of scale inhibitors along the well length. Factors such as Newtonian versus non-Newtonian scale inhibitors, different reservoir pressure profile, ICD nozzle sizes and different well completions. This is all possible because CFD is largely based on physics and rigorous geometry, which is a significant step forward compared to the industry-standard scale squeeze placement software (Byrne 2010, 2011, 2014).

Application of a computational fluid dynamics well model has provided confidence that the combination of non-Newtonian fluids and production ICDs would allow scale squeeze placement along the whole reservoir interval despite significant pressure variations across it.

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