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What is ICDA?
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Gas transmission pipelines, under normal operating conditions, carry under-saturated gas processed by upstream dehydrating units. These pipelines are generally operated with no protection or inhibition and rely on the performance of the dehydrating units to process gas within acceptable standards. It is not unusual for instabilities and other process perturbations contributing to creation of near saturated gas or some liquid water carryover in such pipelines. These upsets lead to water accumulation in some parts of the pipeline further downstream or cause water condensation due to pressure and temperature changes along the length of the pipeline.

The amount of liquid water, the flow parameters such as gas velocity and wall shear stress, pipeline inclination and other factors determine whether water accumulates in a particular part of the pipeline. The length of the time for which these upsets last affect the amount of stagnation of liquid water and cause higher corrosion rates. Such critical zones in a pipeline system are the first to experience water accumulation and hence the most susceptible for internal corrosion. Identifying and inspecting such critical zones reduces the effort in inspecting entire pipeline segments for internal corrosion and forms the basis for Internal Corrosion Direct Assessment (ICDA). The PredictPipe 3.0 software system was developed to identify such water accumulation zones and predict their worst case corrosion rates.

Illustration

An illustration to show critical angle for water accumulation in dry gas transmission lines.

Click on "Introduce Process Upsets", "Increase Inclination" or "Decrease Inclination"
At a critical inclination water starts accumulating.

Critical Angle Defn: the balance between gravitational forces causing liquid to drain backwards and shear stress between gas and liquid causing the liquid to move forward in the direction of flow defines the critical angle for liquid accumulation in a pipeline.

ICDA


Internal corrosion in pipelines is difficult to locate and measure due to a number of factors. Most internal corrosion detection measures require access to the internal of a pipe for inline inspection and visualization tools such as inline pigs, and a substantial portion of the pipeline does not allow inline inspection mostly due to physical and mechanical constraints. Other inspection techniques such as ultrasonic technology and radiography are implemented to measure wall thickness and estimate metal loss from the outside of a pipe, but excavation, cleaning, and other physical constraints allow for only a small area to be inspected at a time.

The ICDA approach to evaluate the likelihood of water accumulation and internal corrosion, and identify critical zones can enhance the actual measurement techniques and ensure safe operation of natural gas pipelines. A detailed analysis of critical locations where water would most likely accumulate provides information about the other parts of the piping system.

Moghissi et. al discuss in the detail the procedure for a ICDA approach. A two tiered procedure has been outlined. The first step deals with identifying the zones with inclination greater than the critical angle and selecting the first such segment. Performing detailed examination of this segment for corrosion forms the second step. If on inspection no corrosion is found, it is concluded that downstream corrosion is unlikely. Performing inspection at the highest inclination upstream of the initial location will provide integrity information of the pipe between these two points. Progressing upstream, identifying susceptible segments and inspecting these segments, the entire pipeline is assessed for internal corrosion.

If the locations identified as most susceptible to internal corrosion are determined to be free from damage by examination, the integrity of a significant part of the pipeline system is assured. If such locations are found to be experiencing corrosion a potential integrity problem is identified.


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