The 4 Most Common Pipeline Integrity Anomalies
Pipeline anomalies, if not addressed, can have potentially catastrophic environmental consequences resulting in extensive and costly production downtime. An effective anomaly management plan should therefore be a crucial part of an operator’s pipeline integrity management program. This ensures early detection of deviations from an asset’s intended design or operating parameters and timely mitigation to prevent failures. In this article, we discuss the most common pipeline anomalies that we have encountered and managed in over two decades of project experience.
11 Sep 2024
Authors
Yohanna Ruocco
Principal Engineer, Clarus Subsea Integrity
About
Yohanna Ruocco is a Principal Engineer with Clarus Subsea Integrity and has worked in the offshore integrity management field for 10 years. Yohanna started in the industry conducting analysis for deepwater risers and conductors. She has managed the subsea integrity program for various operators in the Gulf of Mexico and conducted life extension evaluations for subsea tiebacks. She graduated from the University of Houston with a degree in Civil Engineering.
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Dhawal Nashikkar
Principal Engineer, Clarus Subsea Integrity, Houston, USA
Dhawal Nashikkar
Principal Engineer, Clarus Subsea Integrity, Houston, USA
About
Dhawal is a principal engineer with Clarus Subsea and has experience in the development of Risk Based integrity management plans for onshore and offshore assets including Fixed Equipment, Pressurized Piping, Pipelines, Subsea Equipment and Subsea controls. His areas of expertise includes Risk Management, Root Cause Assessment, Inspection planning and execution, In-Line Inspections, Anomaly Management, Developing project specific Key Performance Indicators, Life Extension assessment and development of IDMS system.
Dhawal is a registered Professional Engineer in State of Texas and holds a Master's in Structural Engineering from University of Florida.
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1. Unplanned Pipeline Buckling and Walking
Although pipeline system design is continuously improving, there will always be uncertainty around pipe to soil interaction parameters, buckle mitigation device effectiveness and operating profile changes throughout the life of the asset which can result in unplanned “rogue” buckles and/or excessive axial walking of high temperature production flowlines.
Unplanned buckling can result in reduced fatigue life and excessive walking of the end structures that has the potential to overstress any rigid jumpers connected to it. In our experience, conducting a baseline survey in a steady state condition 12 to 18 months from first production allows for early anomaly identification and validation of design predictions.
Inspection results can serve as input to calibrate FEA analysis and structural digital twins to confirm fitness for service and allow for monitoring of thermal fatigue, stress cycles, and walking for the remaining life of the asset.
2. Excessive Pipeline Spans
Discrepancies in bathymetry survey, pipeline installation factors, and changes to operating conditions can result in free spans exceeding the allowable limits determined in the design phase. An engineering assessment of the inspection data, as well as understanding environmental and soil data is critical to determine the vortex induced vibration (VIV) and fatigue response, confirm acceptability of ultimate limit state checks and identify the preferred solutions for monitoring and improving structural response of the free spans to acceptable levels. Monitoring solutions can include in-situ data loggers for both pipeline movement and current velocity. Based on our project experience, bottom current data for deepwater pipelines might not be well understood which can result in overly conservatism assessments. Developing an optimised instrumentation and monitoring package can reduce conservative design assumptions and ensure rectification measures are applied at the highest risk spans.
3. Internal Pipeline Corrosion
Internal corrosion is one of the main design considerations for subsea equipment and pipeline design. The initial design of the pipeline is conducted with assumptions around the production chemistry and water cut. However, with time, the production chemistry and water cut from a well can change resulting in a higher likelihood of internal corrosion. It is critical to monitor internal corrosion by development and tracking of key performance indicators such as corrosion inhibitor availability, production chemistry (e.g. CO2 and H2S content, acetate, chlorides etc), water cut, corrosion coupon results, and electrical resistance probe results.
Corrosion modelling using commercially available software can be conducted using actual production profiles and inhibitor records to identify potential internal corrosion hot spots due to high shear stress not allowing the corrosion inhibitor film to form on the surface of pipeline/piping. Such locations would require an in-situ inspection for measurement of wall thickness verification. Proactive hot spot selection has shown to significantly reduce vessel time and fine tune in-line inspection frequency intervals.
4. Excessive Anode Consumption
For subsea pipelines, sacrificial anodes with an alloy of Al/Zn/IN are the most common means of external corrosion protection for pipelines. Pipeline anodes can experience accelerated corrosion due to a number of factors such as current draw from the connected structure, elevated production temperatures, incorrect anode placement, etc.
Field experience has shown us that pipeline anodes installed in proximity to a large structure such as a subsea tree, manifold or production platform can experience excessive anode consumption due to current draw from the connected structure. Potential mitigation for pipeline anode consumption is more complex compared to a subsea structure as anode SLEDs would have to be installed at periodic distances to provide adequate cathodic protection (CP).
To avoid excessive current drain on the pipeline near large structure, it is critical to ensure that a proper system review of the entire CP system as a whole is conducted. If CP design for such structures is found to be deficient, additional anodes can be installed on any connected structure to provide the required current demand. This will prevent excessive current drawn by the connected structure from the pipeline anodes.
Conclusion
Pipeline integrity management requires a thorough understanding of the original pipeline design criteria and how the pipelines behave in operation under different loading conditions. Having a comprehensive integrity management plan will ensure that all failure possibilities are accounted for and inspected or monitored to ensure no unforeseen failure of the pipeline occurs that may impact the personal safety, the surrounding environment and production uptime.
2H’s integrity division, Clarus Subsea Integrity, provides comprehensive integrity services for pipelines, flowlines and all other subsea systems including integrity plan development, inspections and assessments, anomaly management and data management.
Authors
Yohanna Ruocco
Principal Engineer, Clarus Subsea Integrity
About
Yohanna Ruocco is a Principal Engineer with Clarus Subsea Integrity and has worked in the offshore integrity management field for 10 years. Yohanna started in the industry conducting analysis for deepwater risers and conductors. She has managed the subsea integrity program for various operators in the Gulf of Mexico and conducted life extension evaluations for subsea tiebacks. She graduated from the University of Houston with a degree in Civil Engineering.
Language
Dhawal Nashikkar
Principal Engineer, Clarus Subsea Integrity, Houston, USA
Dhawal Nashikkar
Principal Engineer, Clarus Subsea Integrity, Houston, USA
About
Dhawal is a principal engineer with Clarus Subsea and has experience in the development of Risk Based integrity management plans for onshore and offshore assets including Fixed Equipment, Pressurized Piping, Pipelines, Subsea Equipment and Subsea controls. His areas of expertise includes Risk Management, Root Cause Assessment, Inspection planning and execution, In-Line Inspections, Anomaly Management, Developing project specific Key Performance Indicators, Life Extension assessment and development of IDMS system.
Dhawal is a registered Professional Engineer in State of Texas and holds a Master's in Structural Engineering from University of Florida.