This case history tracks the continual improvement cycle for the fluid separation process of a heavy oil / oil sands production facility in Northern Alberta over a period of three years. The major challenge posed by the operator of this 13 - 16° API crude oil was to move away from injection of two separate demulsifier formulations to a single product. This was not an easy task due to the very different conditions that existed at the two injection locations. The first location was at a series of injection points upstream of the gathering stations, prior to separation, where temperatures could reach sub-zero conditions and the second was at the battery receiving facility where heating increased temperatures to 100°C. Water cut and shear were also very different and the operator required a very strict 0.2% BS&W on the crude exiting any of the four treater tanks; to further complicate issues crude oil viscosity ranged from 500 - 5000 cP.

A unique bottle testing method was developed and used to simulate the field conditions as accurately as possible. Details are given on the chemistry of the individual components of the demulsifier determined to be so crucial to adequate performance and how this was optimized in the field after being identified from the bottle tests.

Results show how careful consideration needed to be given to the concentration of the demulsifier bases in the blends and the curious observation that dilution of the final product made a big difference to the final performance in the field. Elaboration is given on potential mechanisms explaining the dilution effect and the paper goes on to conclude how careful design of field testing followed by field implementation can indeed solve complex separation issues and address individual well, battery and field requirements.

You can access this article if you purchase or spend a download.