Top of line corrosion (TLC) is experienced on the upper section of gas or multiphase pipelines operated in a stratified flow regime. TLC occurs when water vapor, contained in the gas phase, condenseson the internal upper pipe wall. The condensation may be caused by the cold wall effect generated by external cooling sources (river water, sea water or cold air) when the pipe is not properly heat insulated or buried. Both dissolved CO2 and possible presence of organic acids reduce the pH of condensedwater and enhance corrosiveness. Instantaneous high corrosion rates, up to 10 mm/y, can occur in the first production period, although worst corrosion rates averaged over a longer period of 2‐3 years are rather in the range of 1 to 3 mm/y. In addition, as long as the flow regime is stratified, usual corrosion inhibitors cannot reach the upper surface of the pipeline.

This study covers TLC assessment on new 8 km pipeline that will transport multiphase hydrocarbon from a new platform to existing facilities. Expected production life of the field is quite short, less than 10 years, maximum wellhead flowing temperature is 105℃ and CO2 content is about 8%. Based on TLC assessment performed during conceptual study, TLC has been considered as a significant issue in case of water condensation rate (WCR) > 0.05 gr/m2s. Being WCR far above such limit, the use of cladding pipe was proposed as the main mitigation measure to limit TLC consequences. However during the next stage of Project, TLC risk was re‐assessed in more detail by using more accurate data in order to find the best solution in term of CAPEX and OPEX.

Following studies were performed:

  • Water condensation rate study

    WCR study is performed in order to identify the pipeline length where TLC will be occured and how long TLC risks will last. Such calculation is done by using OLGA software based on the data of wellhead flowing temperature (WHFT).

  • Top of line corrosion rate study

    TLC rate is calculated to assess the feasibility of the mitigation that consists in having a sufficient corrosion allowance to cover TLC risk and to evaluate the required corrosion allowance

  • Sensitivity study of using thermal insulation and buried pipe

Performed to assess whether the used of thermal insulation and buried pipe can be an option to mitigate TLC

Result of these studies demonstrated that the utilization of carbon steel with extra corrosion allowance, combined with cold spot prevention as the best technical‐economic option for TLC mitigation. It was also possible to conclude that thermal insulation or bury the pipe may not always be the most appropriate option due to the quality assurance along the years, the constructability constraint and the cost.

Keywords:
flowline corrosion, upstream oil & gas, tlc, mitigation, thermal insulation, riser corrosion, thickness, condensation rate, operation, materials and corrosion
Subjects:
Pipelines, Flowlines and Risers, Materials and corrosion
Copyright 2013, Society of Petroleum Engineers
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