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.