Abstract

This work focuses on the interplay between protective iron carbonate surface scales and hydrate particles deposition. An iron carbonate layer was formed on API 5L X65 carbon steel in a glass reactor cell under aqueous CO2 saturated conditions using a three-electrode system. The protectiveness of the surface film was determined in situ using electrochemical techniques, which included open-circuit potential (OCP) and linear polarization (LP) measurements. As expected, the microscopic surface layer acted as a mass-transfer barrier, which reduced the corrosion rate of the carbon steel sample to various degrees depending on the pH of the electrolyte and polarization condition. After testing, the structure and composition of the films were characterized using surface analysis techniques, including, scanning electron microscopy (SEM) coupled with energy dispersive X-ray spectroscopy (EDS). The influence of the surface film on hydrate adhesion was subsequently investigated using a micromechanical force (MMF) apparatus, which indirectly measures the adhesion force between a clathrate hydrate particle and a nominated solid substrate surface. The combination of methods enabled the comparison of how corrosion products and surface film formation affect hydrate deposition tendency. Results indicate that the presence of an iron carbonate layer increases the propensity for hydrate deposition, through both higher growth rates.

Introduction

The development of new long subsea tiebacks will provide crucial infrastructure to bridge the gap between recent energy discoveries and existing offshore and onshore facilities, driving continued production of key energy resources. Looking at the challenges that need to be overcome for future energy production, the safe and reliable transport through subsea networks is one of the main initiatives of the flow assurance community. Additionally, subsea tiebacks provide a critical path to the delivery of the low-emissions future of the energy sector.

There are many challenges related to the production and transportation of oil and gas within subsea pipelines, largely associated to the hostile environment and extreme operation conditions. Particularly, considering that several prominent Australian offshore gas fields produce a significant volume of CO2, which may account for up to 14% of recoverable fluid on a molar basis.1 This CO2 must be removed from the raw gas stream before reaching gas production facilities, transiting subsea production lines on the order of 100+km before treatment onshore. The fact that subsea pipelines are typically made of carbon steel,2 a material prone to internal corrosion when exposed to an aqueous environment containing CO2,3 implies that corrosion is a chief concern for pipeline integrity management.

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