Evaluation of the Need for Scale Inhibitor Injection During Formation Water Production in a Subsea Gas Field Using Partly PH Stabilised Mono Ethylene Glycol

Abstract

Abstract A subsea gas field uses MEG with pH stabiliser and film forming corrosion inhibitor for hydrate and corrosion control. Formation water production from some of the wells is expected and when mixed with partly pH stabilised MEG, there is an increased risk for carbonate scaling in the mixing point at the wellhead and in the production pipeline. Scale calculations gives calcium carbonate saturation ratios at a level where scale formation is expected in produced water systems which indicate a need for scale inhibitor. It is assumed that precipitation of salts in MEG systems is slower than in water-based systems and a work was started to investigate if higher saturation ratios could be tolerated in a system containing MEG than in a water system without MEG. Scale testing were performed with and without MEG at relevant field conditions to evaluate if formation water can be produced without use of scale inhibitor at a low risk for scaling. Glass equipment with a mixing cell connected to short steel pipes mounted upstream and downstream of a glass coil were used in the scale testing. Calcium carbonate scale was identified by SEM/EDS on the steel pipes and the amounts of deposited calcium carbonate were found by weighing. Amounts of deposition in the tests were compared with the theoretically amounts that could precipitate. These results were further combined with deposition considerations in the piping in the field as a function of time to evaluate the risk for blocking the piping downstream the MEG injection point with calcium carbonate scale. Based on the scale testing and deposition evaluations it was concluded that use of scale inhibitor was not necessary since the risk for build-up of scale in the piping was very low.