Viscosity Modelling of Pyrenees Crude Oil Emulsions, SPE-182326 By ?, 13 Oct 2016

The formation of oil-water emulsions presents a major challenge for the petroleum industry. Emulsions in wells and flowlines cause higher viscosities and lead to larger pressure drops, reducing production performance.

The empirical modelling of emulsion viscosity as a function of water cut is presented. Measurement techniques for emulsion viscosity in a laboratory are explored and their use in a multiphase flow simulator to predict well and flowline pressure drops is explained. The reverse of this methodology can also be used with field data to back calculate the ostensible emulsion viscosity curve.

Using the BHP Billiton operated Pyrenees oil development as a case study, this paper contrasts the laboratory derived and reverse engineered viscosity curves generated across a number of wells that have produced to the point of natural emulsion inversion. A possible mechanism for the differences between the two is proposed.

In the latter part of 2014, a campaign of downhole demulsifier dosing across the Pyrenees fields was intiated with considerable success. The impact of this chemical injection on emulsion viscosity modelling is also explored in detail.

The Pyrenees oil development is located in the Exmouth Sub-basin 20 kilometres offshore from the North West Cape of Western Australia in water depths of up to 250 metres. The development currently consists of 20 subsea wells producing from the Ravensworth, Crosby, Stickle, Tanglehead, Wild Bull and Moondyne oil reservoirs. These wells are tied back by means of production flowlines and flexible risers to a Floating Production Storage and Offtake (FPSO) vessel located adjacent to the field.

Since field commissioning in 2010, producing water cuts from Pyrenees wells have steadily increased, with the formation of oil-water emulsions inferred in both wells and pipelines. Emulsions in wells and flowlines lead to higher viscosities and pressure drops, reducing production performance. A sound understanding of emulsion formation and its flow assurance effects thus forms an important part of optimising oil production.

This paper will begin by outlining the modelling of emulsion viscosity as a function of water cut. Measurement techniques in a laboratory are summarised and their use in a commercially available multiphase flow simulator to predict well and flowline pressure drops is explained. The reverse of this methodology can also be used with field data to back calculate the ostensible emulsion viscosity curve.

Using production data from the Pyrenees oil development, this paper compares the laboratory derived and reverse engineered viscosity curves generated across a number of wells that have produced to the point of natural emulsion inversion. A theory which reconciles the differences between the two is presented. Finally, the impact of chemical demulsifier injection on emulsion modelling is also assessed.