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December issue 1999:

Pilot Study Demonstrates Benefits Of Pipeline Inspection And Risk Assessment

By David Jones, Stephen Peet & Luis Espinosa, Pipeline Integrity International Group Limited, England, and  Adrian Espinoza, Pemex E&P, Southern Region, Mexico

Throughout the world, pipeline companies—large and small—are conducting pipeline inspections and risk management assessments. Their objectives are to ensure the safety of the public and the environment. Mexico’s Pemex E&P (PEP), Southern Region, that operates 7,320 miles of crude oil and gas transmission lines, has been carrying out pipeline risk evaluation work on its pipeline systems for several years.

PEP contracted Pipeline Intergrity International (PII) to conduct a pilot study and rehabilitate 90 miles of crude oil and gas pipelines operated by PEP. The six lines selected for the pilot study had an in-service life ranging from 2- to 36 years. Other pertinent pipeline details are summarized in Figure 1.

To determine the current condition of the six pipelines, intelligent pig inspections were conducted from 1996 to 1997. PII’s high resolution magnetic flux leakage (MFL) inspection tool, was used for finding and sizing corrosion and other metal loss defects.

Fitness-For-Purpose  (FFP) Assessment
Subsequently, a Fitness-For-Purpose (FFP) assessment was conducted as the basis for recommending an appropriate rehabilitation strategy, including pipeline coating repairs and scheduling appropriate re-inspection intervals of the respective pipelines. An additional part of the study involved a qualitative risk assessment to prioritize the future maintenance activities of the pipelines.

Included in the assessment data were the dimensions of any feature detected by the inspection to the actual pipeline operating conditions. This allowed the identification of any features that required immediate repair. It also provided a strategy to determine the long-term integrity of the pipelines.

Findings
The inspections reported internal and external corrosion, manufacturing defects, dents and girth weld anomalies (Figure 2).

The inspections were typically conducted 18 months prior to the FFP. The first stage of the FFP was to estimate maximum conceivable corrosion rates, following the inspection, as the basis for estimating the current dimensions of the corrosion and the need for immediate repairs.
On this basis, 13 (12 external and one internal) corrosion features were found to require immediate investigation to confirm their current dimensions as the basis for a repair decision (Figure 3).

It should be noted that appropriate assessment methods were utilized to avoid unnecessary repairs. For example, under the published ANSI/ASME B31.G guidelines, 407 pipeline repairs were required immediately following the inspections (Figure 4).

All of the manufacturing defects detected were found to be insignificant. However, two dents (associated with metal loss defects) and one girth weld anomaly required immediate excavation as the basis for a repair decision.

The next stage was to consider the longer-term integrity of the pipelines, taking into account further corrosion growth (Figure 5). The strategy was to determine optimal re-inspection intervals to allow actual corrosion rates to be determined as the basis for defining further rehabilitation. The intervals were (i) based on estimated future maximum corrosion rates and (ii) devised to ensure that (theoretically) only a ‘few’ (32) coating repairs to external corrosion and (3) pipeline repairs to internal corrosion would be required before the lines were scheduled for re-inspection. It should be emphasised that re-inspection intervals have been individually determined for each pipeline and range from 5 to 10 years after the previous inspection.

Palomas to Cangrejera Pipeline
In looking at the pipeline results, the 3.6-mile, 24-inch diameter Palomas to Cangrejera crude oil pipeline was inspected by PII on June 12, 1997. The 1.8 mile Palomas to Nuero Tampa section entered service in 1995. The 1.8-mile Nuevo Teapa to Cangrejera section was placed into service in 1995 and the Nuevo to Cangrejera section, also measuring 1.8-miles in length, entered service in 1978. The pipeline is constructed from X35 pipe, predominantly of 12.7mm wall thickness, and currently operates at a pressure of 8 bar.

The inspection report identified:

(i) 4,329 external corrosion features (563 in the Palomas to Nuevo Teapa section and 3,766 in the Nuevo Teapa to Cangrejera section),

(ii) 1,890 internal corrosion features (1495 in the Palomas to Nuevo Teapa section and 395 in the Nuevo Teapa to Cangrejera section), and

(iii) 579 manufacturing defects (542 in the Palomas to Nuevo Teapa section and 37 in the Nuevo Teapa to Cangrejera section).


The number and depths of the reported external corrosion features found in the Paloma to Neuve Teapa section was not considered to be consistent with a pipeline that had only been in service for two years (at the time of the inspection). Furthermore, the pipeline section (which entered service in 1997) was found to contain significantly more manufacturing defects (112/mile) than the Nuevo to Cangrejera section, which entered service in 1978. ‘Modern’ pipe produced circa. 1995 would be expected to contain significantly fewer manufacturing defects than pipe produced circa. 1978. It was therefore concluded that the pipeline was very likely constructed from ‘old’ pipe containing corrosion.

Consequently the external corrosion in this section is anticipated to be in an inactivestate. However, the study recommended that the nine deepest reported features be investigated to provide confirmation (e.g. to confirm that the ‘old’ pipe has been re-coated as required by ANSI/ASME B31.4) that the external corrosion was pre-serviced and is now inactive.

Although the study assumed that the internal corrosion mechanism in this section was active (the Nuevo to Cangrejera section contains internal corrosion), the extent to which the corrosion was pre-service or occurred in-service could not be determined. A repair schedule was devised to ensure the pipeline integrity based on a maximum conceivable future corrosion rate. The number of repairs was shown to increase significantly after July 1999.

Nuevo Teapa to Cangrejera Section
At the time of the inspection, this section of the pipeline had been in-service for approximately 20 years and the extent of the corrosion (external and internal) was found consistent with pipe of this age. It was assumed that both corrosion mechanisms were still active and a repair/re-coating schedule for the external corrosion (three that were immediate) was devised. No repairs of any internal corrosion features were found to be required before 2015.
Consequently it is recommended that the pipeline be re-inspected before this date. Furthermore, in the period before the inspection, PEP was advised to monitor the condition of the external coating, efficiency of the CP system, monitor product chemistry and to utilized suitable corrosion inhibitors. After the re-inspection, actual corrosion rates should be determined and the future rehabilitation determined.

Dents
Two dents were reported by the inspection (one plain and one associated with metal loss). In the study plan, plain dents are defined as smooth dents not associated with welds or metal loss. Plain dents with a depth of £ 7% of the pipe diameter are considered as insignificant at a hoop stress of 72% SMYS in the absence of significant pressure cycling. Dents associated with defects are the severest form of pipeline damage. Cracks associated with gouges or weld toes in dents can record very low failure pressure. The reported dent identified is of a depth less than 5 percent of the diameter, the operating stress level 8 percent SMYS, and there is no significant pressure cycling. Therefore the dent is considered insignificant in relation to the integrity of the pipeline.

Conversely, the dent associated with the metal loss was located at the top of the pipe and is therefore likely to have occurred after the line was placed in service. The study considered it conceivable that there could be cracking associated with this defect. PEP was therefore advised to investigate this defect to confirm the extent of any damage and make a repair decision.

The inspection also detected a girth weld anomaly whose signal is characteristic of a crack-like defect. Therefore it is recommended that the defect be excavated and the crack confirmed and repaired with epoxy filled shell.

Risk Assessment
A study was also conducted to prioritize the future maintenance of the six pipelines.
The aim is to identify the greatest damage/defect risk to a pipeline that allows the selection of an appropriate maintenance (monitoring/inspection) method to reduce the risk. An accepted method for determining which maintenance technique to use on a pipeline is a ‘Prioritization Scheme.’ These types of schemes are increasingly being used to guide operators on the optimum use of maintenance methods. For example, if a pipeline’s major cause of damage is third party interference, increased surveillance would be appropriate. However, if a pipeline is at greatest risk from internal or external corrosion, then an inspection using an intelligent pig would be appropriate.

The prioritization scheme considers the probability and consequences of failure within a group of pipelines (or sections of a single pipeline) by systematically assessing the pipelines’ design, operation and failure history and allocating points. High points are awarded to high risk (Figure 6). For example, the probability of failure due to external corrosion is evaluated by considering the quality of the pipe coating, the effectiveness of the CP system, the soil condition, the operating stress of the pipeline, etc. The consequences of failure are considered by estimating the density of the surrounding population, the volume of product released, the risk to the population and surrounding buildings, the security of supply and environmental impact.

  • By customizing the scheme to a group or section of a pipeline can result in the following advantages:
  • Rank all pipelines within a group (or sections of a pipeline) in terms of probability of failure and the consequences of failure,
  • Determine which pipeline (or section of a pipeline) is most in need of some type of maintenance measure, i.e. identify ‘hot-spots’ of risk, and
  • Identify the most appropriate maintenance measure to use.


In this case, PII’s PC software based ASIRE ( A System for Pipeline Risk Evaluation) was applied, following the inspections, to prioritize the six pipelines in terms of total risk. Figure 7 presents the relative risk of the six PEP pipelines, while Figure 8 shows the failure index for the Cunduancan to Dos Bocas pipeline. The failure index also shows the Cunduancan to Dos Bocas at much most risk from sabotage/pilferage, and increased surveillance is recommended, Although the study assumed that the internal corrosion mechanism in this section was active (the Nuevo to Cangrejera section contains internal corrosion), the extent to which the corrosion was pre-service or occurred in-service could not be determined. A repair schedule was devised to ensure the pipeline integrity based on a maximum conceivable future corrosion rate. The number of repairs was shown to increase significantly after July 1999.

Conclusions
To date the assessment of five of the six pipelines has been completed. In particular, utilizing appropriate assessment methods, 13 corrosion features require investigation to ensure their immediate integrity; the published guidance (ANSI/ASME B31.G) requires 407 pipeline repairs immediately after the inspections (i.e. 18 months ago).

To ensure the longer-term integrity, individual re-inspection intervals (5 to 10 years) have been defined for each pipeline. Before the re-inspections, 32 coating repairs and three pipeline repairs of internal corrosion are required and the timing has been defined. Following the re-inspections, actual corrosion rates should be determined as the basis for defining further cost-effective rehabilitation.

Finally, the risk assessment has prioritized the six pipelines for future maintenance activities. Currently the Cunduancan to Dos Bocas is most at risk from sabotage/pilferage and increased surveillance is recommended. P&GJ

This article is based on a technical paper originally presented by the authors.