Abstract
This paper presents field results from scale squeeze treatments carried out on platform and subsea horizontal wells from a oilfield in the UK sector of the North Sea. Downhole scale control and the resulting squeeze treatments to production wells were highlighted as one of the most expensive items in the production chemical budget and impacted topside separation during treatment back production. The development of optimized scale squeeze treatments and monitoring policy has been critical to reducing the operating cost and deferred oil production of this asset as the produced water cut rose.
Scale squeeze treatments have been optimised over the years with the aid of detailed reservoir simulation indicating water rates along the production wells being input into scale squeeze design software. The requirement to extend treatment life while minimising the deferred oil was one of the critical factors in selecting improved scale inhibitor chemistry. The field data from these wells will be presented comparing treatment lifetime rates between conventional treatments and the improved scale inhibitor chemistry.
Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs. All these methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and providing the confidence to extend the period between scale squeeze treatments and in some cases stop treatment where brine analysis alone would have suggested further scale squeeze applications.
