So, what is wrong with this method?
1. The “close” reference cell must be maintained very close to the pipeline under surveillance, ideally within 50 mm. If this is not maintained, the value of the remote variation reading is diminished to the point of unacceptable inaccuracy.
2. It’s very difficult to do this at all on a buried pipeline, where depth of cover can be from 1-5 meters.
3. In attempting to maintain the electrode position, it is necessary to equip the ROV with wheels that can actually run along the line, or to try to free-fly the line (very difficult to do). In either of these events, the ROV must slow to a survey speed of < 1 Knot, or around 0.3 - 0.5 meters/sec. This means that the cost of the survey is unnecessarily escalated in an attempt to assess the “true” condition of the pipeline.
4. Calibration stabs are required at regular intervals (5 Km is often specified). If this is not done, then the close interval data are being compared to an invalid number. Because it is difficult to get these calibrations on buried lines, they are very often ignored, which makes the surveys worthless for integrity assessment purposes.
5. All “real” potential measurements are usually taken on bracelets, so obviously, the potentials are very negative and unrepresentative of the actual pipeline potential. It is rare to get a real calibration at a cathode (pipeline metal) stab.
6. Because the data are computer generated, there is no real-time assessment available, and post-project reporting can be expensive and time-consuming.
There is now a much better way.
THE IMPROVED STRATEGY
The improved strategy is a modification for pipelines. To appreciate the elegance of this, it is first necessary to step back and revisit the basic strategy for external corrosion control of offshore pipelines. This is a global strategy that really doesn’t vary in any offshore area, and has been the same since offshore pipelines were first laid in the late 1940s. The corrosion control system on better than 99.5% of offshore pipelines consists of two synergistic elements:
1. A coating system. This is the primary corrosion barrier, usually organic in nature and designed to provide a dielectric barrier that shields the pipeline from corrosive seawater and seabed environments. This coating is usually factory applied to very high standards and is designed to cover up as close to 100% of the steel pipe as feasible. In order for the pipe to be constructed offshore, it is necessary to have field joints where sections of the pipe are welded together in the field. The areas where these welds are to be made are left uncoated in the coating factory and are provided with a compatible “field joint” coating to cover the bare steel before the pipe is lowered to the sea bed.
2. A cathodic protection system. This is designed solely to protect defects in the pipe coating system, and is a key point. The cathodic protection (CP) system may consist of bracelet-type anodes attached at intervals to the pipeline, or there may be discreet anode sled systems. The line may even be short enough to be protected with CP applied at the extremities; in any event its function is the same, to protect defects or deterioration of the pipe coating system that will expose more bare steel to the corrosive environment. It is because of this that the design codes recommend “coating breakdown factors” as percentage coverage loss versus time.
Now that we understand the intended function of the CP system, let’s leverage this to test the resilience of the CP system in routine monitoring; lets test the ability of the CP system to cover a degrading coating system. One way is to remove some coating from the pipeline and verify that the CP system was able to efficiently protect the defect. Of course, this would be counter-productive. But we can introduce a non-critical defect:
Install a “coupon” on the outside of the pipeline with an electrical contact to the pipeline. This coupon would simulate a coating defect and would test the CP system. If the CP system could easily polarize the defect, we would know that there were no other smaller area defects in the region that would not be adequately protected. Moreover, this coupon, if correctly designed, could remain in place and serve as a sample test point for future surveys to give us the pipe (cathode) contact that we really want to see. However, once this coupon were polarized it would behave like any other coating defect on the protected pipeline, but would still represent a worse case scenario, and would reflect other changes in the pipeline’s cathodic protection equilibrium over a large sample area.
We have been asked if it is wise to add these defects to a pipeline, and will they deplete the CP system prematurely? Here is a critical analysis:
Area of a 12” pipeline 10 Km Long = 1017 m2 surface area
Assume each field joint has 10 cm2 bare = 820 joints x 100 (0.82m2 ) = 0.08% bare
Our test cathode coupon is 100 cm2 bare = 0.01 m2 = 9.8x10-6 % bare
This area would expect to require 600 microamps 0.6 mA of protective current (which would be about 0.5% of the current available from a single bracelet anode). It could hardly be considered a drain on the system, but the fact that it’s a single defect that has been recently placed still gives us the critical information we need.
Such devices are shown in Fig. 2 for bottom-laid pipelines and in Fig. 3 for buried offshore pipelines.