ABSTRACT:

A mature field located in UK sector of the North Sea, comprises one central platform with several subsea satellite tie-backs fabricated from carbon steel. Internal corrosion mitigation of these flowlines was based on the application of a combined scale/corrosion inhibitor. Following corrosion failures at the inlet sections (towhead) of the flowlines, the requirement for an effective inhibitor increased. Subsequent inspection of the towhead pipework revealed significant preferential weld corrosion. There had been improvements in inhibitor injection compliance; however, the selection of the incumbent inhibitor was based on limited performance test work. An appraisal of the chemical injection system and a corrosion risk assessment of the flowlines highlighted short falls in the required corrosion management process. Rectifying the integrity issues involved significant economic, operational and technological challenges that had to be overcome to achieve continued integrity of the flowlines. Hardware upgrades of the chemical injection system were essential to deliver the high uptime required. Controlling preferential weld corrosion and growth rate of existing pits in a high shear stress environment was examined using a variety of novel corrosion testing techniques that mimic the corrosion morphology in the flowlines.

INTRODUCTION:

A mature field located in the UK sector of the North Sea with a central processing facility (CPF), supports a number of platform wells and several subsea completions producing oil and gas (Table 1). The processed oil and gas is exported via pipelines to an onshore oil terminal and gas plant. The subsea completions produce oil and gas with different gas oil ratio (GOR) and water cut. The produced fluids typically contain 0.5 to 2 mol% carbon dioxide (CO2) and hydrogen dioxide (trace) with chlorides in the formation water measured at ~50,000 mg/l. The towhead was part of the construction used to lay the subsea flowlines in a carrier pipe (bundle) that includes a number of oil and gas lift lines. A 40 meter jumper of flexible construction or duplex stainless steel spool connects the towhead to the wellhead trees. The carbon steel subsea flowlines are susceptible to internal corrosion due to the corrosive nature of the produced fluid. As part of the corrosion control program at the facility, a combined scale/corrosion inhibitor is employed to provide both corrosion and scale control. It is important to ensure high on-line availability of the chemical injection system for the subsea flowline system. This is because data obtained from an intelligent pig (IP) inspection carried out in 1998 indicated moderate corrosion in two of the subsea flowlines. Although the scaling tendency of the formation water was low it was agreed that it was more cost effective to prevent scale formation subsea at wellhead valves, chokes etc. than remediation. The incumbent inhibitor (scale/corrosion inhibitor) deployed was based on limited test work carried out in the 1990s. Concerns over the ability of the incumbent inhibitor to protect the flowlines against localized corrosion were raised as documentation indicated inhibitor dose was based on general corrosion not localized corrosion in 2003.

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