New Pipeline Coating Inspection Technology

Trenchless installation of coated pipeline segments is an attractive option for construction areas that include wetlands, congested areas, and road crossings. Trenchless installation is predominantly carried out using Horizontal Directional Drilling (HDD), a versatile form of utility construction that has experienced enormous growth the past two decades. This technology works well for installing pipelines and conduits for major utilities including gas, electric, telecommunications, water, and sewer. However, coating damage can occur as part of the HDD installation process. SwRI has developed a new coating inspection technology that can be used to detect damage from installation, as well as damage due to the normal aging process.

HDD construction generally consists of drilling a pilot hole, reaming the hole to enlarge it and, for larger diameter pipelines, pulling a reaming head back through the opening. The pipe is then pulled or pushed through the pilot hole.

One of the operational risks of trenchless installation, though, is damage to the pipe coating, which can result in premature external corrosion of metallic pipeline segments because of exposure to soil and water. Coatings can be damaged during pull-through as a result of the forces involved, and by contact with soils, rocks, and other debris present in the borehole.

Therefore, it is important to determine the initial condition of the coating on the pipeline segment with a high degree of certainty immediately after trenchless installation. Understanding
the extent of coating damage will help with deciding whether coating damage is too severe to be
protected by cathodic protection (CP) or designing a CP system to protect the pipeline segment.

Additionally, in existing buried pipelines, whether installed by HDD or not, coatings may be damaged over time by material degradation or unplanned contact by third-party equipment. If damage is suspected, it would be advantageous to be able to inspect the coating before significant damage to the pipe itself occurs.

Several techniques are routinely used to estimate the extent of coating damage in buried pipelines. These include coating conductance measurements per National Association of Corrosion Engineers (NACE) Standard TM0102–2002, pipeline current mapping, close interval
survey leading to on- and off-potential measurements, direct current voltage gradient, and alternating current voltage gradient. However, all of these techniques require access to the ground surface directly above the pipeline segment. The ground surface may not be available, for example, if the pipeline segment is installed under a riverbed or pavement.

One device that provides information on coating quality and effectiveness of CP current from the pipe interior is the Baker Hughes CPCM tool. This tool measures CP current flow in a pipeline by recording the voltage drop across a length of pipe (~ 2-3 m) as the tool is transported through the pipe. The tool has been shown to be effective at finding breaks in the coating and areas of the pipeline where no CP is functioning. One limitation of this tool, however, is that it requires low resistance contacts to the pipe wall be established by large brushes that, because of the distributed contact area, cannot provide good spatial resolution.

As an alternative to directly measuring the voltage drop across a length of pipe, changes in the
CP-generated current flowing along the pipe can be detected by measuring the circumferential magnetic field at the inner wall of the pipe. With this technique, a ring of magnetic field sensors measures the magnetizing force in the circumferential direction around the entire circumference of the pipe. A diagram of this tool is shown on page 35. As seen in the figure, in areas where the coating is damaged and excessive currents leak from the pipe wall to the soil, the currents in the pipe wall decrease, causing a corresponding decrease in the local circumferential magnetic field. With this approach, direct electrical contact between the pipe wall and the sensors is not required, allowing for the use of more sensors to provide greater spatial resolution. Furthermore, a clean wall is not required.

In the case of an axial current that is uniform around the circumference of the pipe, a circumferential magnetic field in the pipe interior will not be generated. Thus, the absolute magnitude of the impressed CP currents on the pipe will not be measured. However, wherever the axial symmetry is broken (e.g., due to coating breaks or lack of contact with the soil), circumferential fields will be generated that can be detected by the proposed sensor array.

The sensitivity of this tool can be enhanced by temporarily increasing the current supplied by
the CP system and by injecting low frequency AC signals at the CP system. The low frequency used would depend on the length of pipe needing inspection but would be kept away from 60 Hz and its low order harmonics sufficiently to be independent of stray currents. Using injected AC signals and synchronous detection or narrow bandpass detection at the transmitted frequency
provides two advantages: The measured magnetic field is not affected by residual magnetism in the pipe; and the measured magnetic field is not affected by magnetic fields caused by stray currents from electrical power sources.

The effect of localized coating breaks, coating disbondments, pipe-to-soil gaps, or the presence of shielding objects increases the circumferential magnetic field because the capacitive losses of current would be greatly different at those locations compared to the normal losses through the coating.

This new pipeline inspection technology was developed to locate regions of coating degradation from inside pipelines and can be applied in locations where the CP system has not yet been set up as well as areas without access to the soil above the pipe. This technology can help operators
make key decisions, including whether it is necessary to install a new pipeline segment, design a new CP system to protect the existing segment after it is tied in with the rest of the pipeline, or place the corrosion monitoring probes near the damaged regions of the pipeline segment.


Dr. Jay Fisher is a Program Director in the Structural Engineering Department of the mechanical Engineering Division at Southwest Research Institute. He can be reached at jay.fisher@swri.org.

Dr. Pavan Shukla is a Principal Engineer in the Center for Nuclear Waste Regulatory Analyses at Southwest Research Institute. He can be reached at  avan.shukla@swri.org.

SwRI is an independent, nonprofit, applied research and development organization based in San Antonio, Texas. In 2017, SwRI celebrates 70 years of benefiting government, industry and the public with innovative R&D.

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