The Dollars and Sense of In-Line Inspection Evaluation

Often, pipeline owners and managers just look at the final reports from their inspection vendors and base their remediation plans on that. But, by making the effort to thoroughly evaluate and compare in-line inspection reports, operators can reap big rewards. Marc Lamontagne explains.

Typically, after receiving the final in-line inspection report, pipeline operators excavate those trouble spots identified as immediately necessary. Then they shelve the report. But that can be a costly way to manage a pipeline.

An integrated integrity management program includes a full evaluation and comparison of in-line inspection (ILI) reports. These programs can provide a more complete picture of pipeline integrity. As a result, disasters from line failures can be averted or extensive digs can be avoided. Here are a couple of examples where in-line inspection evaluation resulted in significant savings for operators.

Avoiding in-service failure
Here is a case where ILI evaluation revealed the need for additional excavations. Without them, leaks of hazardous liquids could possibly have occurred before to the next in-line inspection.

An engineering evaluation was made on the NPS 12, 140-mile pipeline section based on the comparison of 2003 and 2006 MFL inspections. The initial run in April 2003 identified 13,667 anomalies down to an estimated depth of 10% wall loss. The comparative run in May 2006 identified 30,170. Of the anomalies identified in 2003 and 2006, over 10,000 of them were matched between the inspections. Most of the new features since the 2003 inspection were in the same areas of high corrosion; a pattern had emerged.

This evaluation clearly documented the areas of significant corrosion growth. Those 10,000 plus anomalies that could be matched from 2003 to 2006 showed that internal corrosion growth was more rapid where product is injected into the line. In addition, when those points were graphed according to their orientation on the pipe wall, an interesting pattern emerged. Corrosion growth was not only clustered in the same region of the wall (at or near the 6 o’clock position), those regions also showed the fastest growth.

With this comparison information, growth rates could be more accurately projected. A new 10-year forecast was calculated based on anticipated operating pressure, acceptable depth limits and a conservative growth rate. This new information meant that the dig schedule had to be revised. Eight more excavations were needed for 2006 and another nine for 2007. Those extra digs possibly averted a disaster. During the first eight excavations, four spots were actually sand blasted through as the pipe was being cleaned for examination. They had become dangerously thin.

The new information was also used to develop an economic forecast to optimize the mitigation plan. The forecast, using net present value (NPV), indicates that a re-inspection is due in May 2008. An NPV assessment calculates future repair costs versus the cost of re-inspection. It also assumes the current dig schedule through 2007 is followed.

In this case, four anomalies in different locations were found and repaired just prior to failing in-service. Disaster mitigation resulted in untold savings.

Saving a 120-mile pipeline replacement
The Seaside Pipeline Company (SPC) has a 270-mile pipeline that carries refined product from the east coast of Africa to markets inland. The 14-in, X52 electrical resistance welded pipeline operates at a stress level of 68% SMYS and a flow rate of up to 440 m3/hr.

In 1999 they hired a contractor to inspect the line with high-resolution MFL tools. Based solely on the results of this inspection, they were faced with the prospect of replacing over 120 miles of the line – nearly half. The inspection of the 270 miles identified 1.34 million anomalies deeper than 1% in the first half of the line and 2.81 million in the latter section. Things were looking bad. Another vendor was contracted to confirm the 1999 findings.

This vendor performed a high-resolution inspection in 2004. They found just under 40,000 anomalies down to a depth of 10% in the first half and approximately 51,000 in the latter section. Since these numbers were so different, the accuracy of their inspection was verified by excavation.

Lamontagne Pipeline Assessment Corporation was called in to make sense of the inspection results and come up with a remediation plan. They compared the predicted depths from the 1999 inspection with the actual results from 2004. Knowing that 2004 inspections were accurate, it became clear that the 1999 inspection was over estimating the depth of corrosion. In fact, the comparison, when taken at face value, showed a negative growth rate! The key question remained. If the 1999 inspection was inaccurate, how could one determine a realistic corrosion growth rate through comparison? While examining the first 139-mile section it was noted that many joints that had no corrosion in 1999 were highly corroded in 2004. This new corrosion became the basis of a realistic time line.

Once a growth rate had been calculated and the operator had specified its failure limits, a timeline was calculated. The failure points were determined and then grouped into excavation locations to provide a manageable maintenance schedule. As a result, SPC can now maintain the line in a more organized fashion, balancing manpower, cost and throughput. A re-inspection date of 2009 was proposed based on the information.

Lamontagne’s contract was fulfilled, but they also helped SPC better understand the reason behind the corrosion issues, to reduce costs in the future.

The corrosion was found to be in three specific areas. Most of the external corrosion was found to be in the first 24 miles. Internal corrosion was found in two distinct locations inland. Since the corrosion is not evenly spread along the line there had to be a physical or operational issue. Some sleuthing had to be done.

With the external corrosion problem, the questions focused on what was different about the first 24 miles. It turned out that the heat of the product as it entered the line from the pump station at Mile 0 was causing deterioration of the coating. This allowed the particularly salty soils of the coastal region to attack the pipe. Lamontagne was able to recommend an easy remediation program: re-coat some short sections of the line in problem areas, specific excavations and continued re-inspections.

A few more questions helped solve the puzzle about the internal corrosion problem areas. It turned out that, with only a single pumping station, the product cooled appreciably as it moved farther inland. At the same time the problem areas were in hilly regions. Therefore, some corrosive element was coming out of solution as the temperature decreased and was allowed to accumulate due to the slower flow rate in low-lying areas.

To remedy these corrosion problem areas, it was suggested that sensors be installed to more accurately monitor the line and to inject inhibitors just before of the problem areas. Coincidentally, SPC is looking into expanding their pipeline and doubling the pumping volume. This may be just the solution for the internal corrosion problem because it may prevent the drop-out of the undesirable corrosive element.

Seaside Pipeline Company now feels assured that there is no need for immediate replacement of 120 miles of pipeline. It is quite relieved that a realistic, manageable and affordable integrity plan has provided the company with the continued assurance of their fuel supply as well as comfort in knowing that large sums of money have been saved by doing an appropriate evaluation of in-line inspections.

A profitable investment
These are just two examples that demonstrate how the investment in an integrated integrity maintenance program with the evaluation of in-line inspections at its core can have a significant operational and financial impact on pipeline operations. The cost to an operator to have ILI evaluations completed for their whole system is negligible relative to the cost of one in-service failure or unnecessary excavation. The result is also a more definitive answer to dig scheduling and re-inspection intervals.

Considering the benefit to operators, in-line inspection evaluation certainly makes dollars and sense.