Risk Based Internal Corrosion Assessment of Pipe in Pipe Flowline
- P. T. Hogelin (Noble Energy Inc) | J. T. Webb (Noble Energy Inc) | Y. Ruocco (Clarus Subsea Integrity Inc) | D. Vadel (Clarus Subsea Integrity Inc) | R. Hill (Microalloying International Inc)
- Document ID
- Offshore Technology Conference
- Offshore Technology Conference, 30 April - 3 May, Houston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2018. Offshore Technology Conference
- 4.2 Pipelines, Flowlines and Risers, 4.5 Offshore Facilities and Subsea Systems, 4.2.3 Materials and Corrosion, 6.3 Safety, 7.2 Risk Management and Decision-Making, 4.2 Pipelines, Flowlines and Risers, 7 Management and Information, 7.2.1 Risk, Uncertainty and Risk Assessment, 4.5 Offshore Facilities and Subsea Systems
- risk assessment, internal corrosion, flowlines, key performance indicator, integrity management
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Safety and protection of the environment are paramount to successful, effective operations. A prominent challenge in the offshore oil and gas industry is striking a balance between maximizing production from a field and managing risks to meet or exceed regulatory compliance and safety goals. Noble Energy currently manages integrity of its Gulf of Mexico deepwater assets through implementation of a riskbased integrity management (IM) program. The objective of this paper is to demonstrate the value of a risk-based assessment process to mitigate internal corrosion of a pipe-in-pipe (PIP) flowline by progressively advancing detailed engineering assessments from routine monitoring activities. The results improved understanding of internal corrosion degradation mechanism and allowed for an update to the IM plan for remaining service life.
As part of Noble Energy's subsea IM program, annual asset risk assessments are conducted to identify, assess and control operational risks. Key performance indicators (KPIs) have been implemented to manage degradation mechanisms during design review and flag potentially unfavorable operational conditions. The exceedance of a KPI limit and the reliability of monitoring data directly affect the predictability of the associated degradation mechanisms. Elevated corrosion rates from a conservative corrosion model, combined with discrepancies in topsides corrosion coupon sampling, resulted in lower confidence for threat predictability. This prompted a more detailed assessment to confirm integrity of the flowline. The assessment included a review of design and historical monitoring data. A complete produced water analysis was executed to update the corrosion model. A flow regime analysis was conducted to assess the pipeline water-wet condition and water hold-up potential for current operational conditions.
This paper presents challenges and assumptions in identifying representative load cases from a 10-year operational history. The result of the assessment was the identification of areas along the flowline with medium to high water-wetting probability, and understanding of the hazards associated with internal corrosion at the identified locations. This study provided significant improvement in visibility of the internal corrosion degradation mechanism of the flowline and develop continued risk management strategy.
This paper presents a holistic approach to managing internal corrosion threats for subsea flowlines. It demonstrates the value of linking data to degradation mechanisms to improve understanding of risks on the assets, and the value of a structured program to ensure informed and confident decisions can be made by an operator.
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