Gasunie has utilized external corrosion direct assessment (ECDA) as proposed by the National Association of Corrosion Engineers (NACE) as a valuable method of assessing the corrosion threat in unpiggable pipelines.
Structural-reliability analysis (SRA) combined with Bayesian statistics make it possible to quantify the results of an ECDA process. This combined method allows automatic adjustment of the expected number of both coating and corrosion defects based on the results of two aboveground surveys (one for the detection of each).
The method makes it possible to use the results of excavations to adjust the following variables:
- The probabilities of detection and of false indication of each survey technique.
- The time of initiation of corrosion defects and the defect density.
- The corrosion rate and the defect depth.
Adjusting these variables allows the probability of failure of the pipeline being inspected to be calculated and updated on a per-kilometer basis. This updating process can in turn be performed after each (x) number of excavations, until the system reaches a sufficiently low probability of failure, allowing the integrity manager to minimize the number of excavations required.
Gasunie has been implementing this approach as part of its pipeline integrity management system, PIMSlider, during 2006. Gasunie intends the approach to be an integral part of the system, providing access to all relevant data of both the pipeline under investigation and direct assessments performed on other pipelines.
History
Gasunie owns roughly 12,000 km of high-pressure pipeline in the Netherlands, most of which were built between 1960 and 1980. Aging of the grid has led increasingly to spots with coating degeneration and reduced wall thickness caused by both corrosion and mechanical damage. Gasunie also detected microbiologically influenced corrosion (MIC) on the grid in 1999.
These circumstances led Gasunie’s asset-management department to reexamine its pipeline management policy in order to maintain a high standard on risk and integrity control. Gasunie concluded that a change from verification of preventive measures to verification of the actual condition of the pipelines was required.
This conclusion resulted in the introduction of two strategies:
- Integrity management: to comply with prescribed governmental requirements and restrictions on the integrity of the assets; to prioritize and perform preventive activities; and to monitor the actual condition of pipelines.
- Risk management: to realize and preserve the environmental integrity of the pipeline within acceptable (or agreed) levels and to prioritize and perform mitigating activities.
These strategies led to the intensification of Gasunie’s in-line inspection (ILI) program to 5-10 ILI runs/year, resulting in a significant increase in the amount of inspection data needing analysis.
Gasunie implemented a new IT solution (PIMSlider) to allow efficient and reliable data processing and support all pipeline integrity-management processes.
Since only 50% of Gasunie’s pipelines are conventionally piggable, it decided in 2005 to develop a computerized direct-assessment module for PIMSlider, enabling integrity analyses of unpiggable pipelines and meeting the requirements of the ECDA process described in NACE RP0502-2002.1
This first of two articles focuses on the direct assessment module of PIMSlider, currently being developed by Gasunie in cooperation with Andrew Francis & Associates Ltd. (AFAA), Derbyshire, UK, ATP Ltd., Hampshire, UK, and ATP Neftegazsystema, Gomel, Belarus. The concluding article will detail the ECDA results for a section of Gasunie line.
PIMSlider
The PIMSlider system consists of a number of modules, the center of which is Slider.2 The modules cover the spectrum of data management (pipeline, environmental, and incident data), CP system monitoring data, analyses of ILI data, defect assessments, and quantitative risk calculations with consideration of the economics involved.
The Slider module stores all pipeline-related data concerning position, equipment, crossings, operational data, ILI data, maps, photographs, population density along its route, etc. It mainly provides information retrieval. The operator can track relationships between various data points (Fig. 1) and schedule actions accordingly (surveys, repair, maintenance, etc).
The CP Expert module allows the operator to analyze the effectiveness and the efficiency of an existing CP system. A modeling function supports the CP engineer in the design of the CP system in case of construction or modification of a pipeline. CP Expert uses data from Slider. It also allows calculation of the optimum operation mode for CP stations, ensuring reliable and effective protection of the pipeline.
The Gasunie Pipeline Incidents Database (GDLI) contains all pipeline incidents that have occurred on the Gasunie grid. The GDLI module analyzes these incidents.
Inpipe enables the analysis of any kind of pipeline defect or other feature drawn from data provided by ILI tools. This involves linking the features to map coordinates and accurate positioning of the in-line data along a 3D model of the pipeline. The software calculates the remaining strength of the pipeline using the methods of ASME B31G and RSTRENG.
The Rehab Expert module allows the operator to assess the significance of defects in the pipeline and to define the most appropriate repair program. Either defect-geometry data, as reported by the ILI contractor, or raw data from inspection tools (such as individual sensor signals) can provide the basis for assessing defects. Using more than one ILI program allows comparison of the same defect at different stages of its lifetime, enabling the operator to optimize the economics of inspection and repair.
The PSL module provides the core of the system with respect to risk management of gas transmission pipelines. It is a hazard and risk-assessment package and enables automatic quantitative risk calculations to be made at any moment for any pipeline in the Slider database. It also allows the engineer to calculate the effect of risk mitigating measures on existing pipeline.
The approaches and assumptions used in PIPESAFE, a risk-assessment model for gas transmission pipelines developed by a group of international gas transmission companies, provide the basis for PSL.
The Risk Expert module allows the operator to carry out a relative risk assessment of the pipeline, prioritizing maintenance and inspection. This data-based method uses a model that identifies and quantifies the major threats and consequences of pipeline objects and the pipeline environment. Operational experience, expert opinion, and industry experience quantify the likelihood of all threats, with calculations performed for all pipeline sections (parts of the pipeline with unchanged conditions) making it possible to identify local high-risk areas.
Direct-assessment module
The DA module of PIMSlider allows computerized storage, retrieval, and processing of all appropriate pipeline data stored in the PIMSlider database, guaranteeing highly accurate, reproducible, and time-saving integrity analyses of the entire Gasunie grid.
The module is based on the NACE Recommended Practice for ECDA1 in combination with SRA. The ECDA process integrates information on the pipeline’s physical characteristics including operating history (preassessment) with data from multiple field examinations (indirect inspections) and pipe surface evaluations (direct examinations).
SRA in combination with Bayesian statistics allows quantifying the effect of inspections and excavations on the integrity of the pipeline, supporting the integrity manager in the definition of a required inspection program.3-7 Increasing reliability through SRA and Bayesian statistics can result in substantial inspection cost savings.
The DA module models the external corrosion failure mode in detail. A constant represents other failure modes.
Ongoing research at Gasunie Engineering & Technology and contributions by AAFA have led to improvements on the model originally developed by Gasunie in 2004.8 9 The current module consists of the following parts:
- Preassessment.
- Indirect inspections.
- Direct examination and postassessment.
Preassessment includes data collection and visualization, identification of so-called ECDA regions, and calculation of the baseline probability of failure of the pipeline. Indirect inspection identifies and defines the severity of coating faults, other anomalies, and areas at which corrosion activity might be occurring.
Direct examinations determine which indications from the indirect inspections are most severe, collect data to assess corrosion activity, and repair critical defects. Finally, postassessment defines reassessment intervals and assesses the overall effectiveness of the ECDA. This step integrates all ECDA regions as well as the failure frequencies of other failure modes.
Failure modes
Integrity management requires that all the potential threats to a pipeline (failure modes) be considered. The direct-assessment module uses the American Society of Mechanical Engineer’s guidelines. The DA module evaluates the integrity of a pipeline by assessing its failure rate, expressed as the probability of failure/kilometer/year.
Direct assessment of external corrosion (ECDA) is modeled in detail. The DA module, however, allows models for other relevant failure modes to be added as they become necessary. For now, the module models contributions of other failure modes to the overall integrity of the pipeline as a constant.
Managing pipeline integrity holds identification of potential existing threats as its first step, with all threats to the integrity of the pipeline needing consideration. The Pipeline Research Committee International (PRCI) has analyzed a large number of gas pipeline and established 22 different causes. The ASME has grouped these causes into nine different failure mode categories (Table 1).10
The PIMSlider DA module uses a division in failure modes to the level of Table 1’s subcategories.
Gasunie has recorded all incidents on its grid in the Gasunie Database for Pipeline Incidents. The incidents include leaks and ruptures, as well as coating damage and damage caused by corrosion.
The main failure modes are:
- External interference (third party) 71%.
- External corrosion 6%.
- Material and welding defects 4% (mostly welding defects).
- Ground movement (sinking) 2%.
The PIMSlider PSL module addresses external interference and its consequences.
The PIMSlider DA module models external corrosion.
The effects of aging on the pipeline grid and the growth of corrosion defects over time only heighten the importance of modeling external corrosion as a failure mode.
Studies indicate that material and welding defects and internal corrosion are more important failure modes for other pipeline operators than they are for Gasunie.11-13
Gasunie believes that external corrosion should not contribute significantly to total incident frequency but has yet to set a criterion for the maximum failure rate from this cause.
A NACE standard exists for ECDA and a complete model has been established, based on the work of Francis et al. The DA module of PIMSlider implements this model.
NACE has developed standards for other corrosion direct assessments, such as internal corrosion (ICDA) and stress-corrosion cracking (SCCDA), but no comprehensive models are available yet.
The outlines of these standards are largely comparable to that of external corrosion, but they will not be included in PIMSlider until corresponding probabilistic models have been developed. Gasunie does not consider either of these failure modes to be a significant threat to its grid at present.
Various causes lead to external corrosion. When a coating defect is present (however small) and the cathodic protection applied is insufficient (or even too high), stray currents, AC interference, bacteria (MIC), tensile stress (SCC), and shielding of CP or overprotection may all lead to corrosion. ECDA does not cover MIC, SCC, or shielding of CP and overprotection. Since MIC is often associated with disbonded coating (i.e. shielding of CP), ECDA should not be applied in areas where MIC is known to occur.
ECDA covers general corrosion, AC corrosion, and stray current corrosion.
ECDA techniques can be used to find MIC corrosion, since experience with MIC at Gasunie indicates that it often occurs in combination with (or leads to) degenerated coating. This implies that an initially shielded defect suffering from MIC may eventually become accessible to CP currents due to degeneration of the coating, thereby enabling aboveground detection of the defect.
Preassessment
There are three main purposes to the preassessment step:
- Data collection and visualization.
- Identification of ECDA regions.
- Establishing the prior condition of the pipeline.
The first part of the preassessment, as set out by NACE, calls for a sufficient amount of data collection, integration, and analysis. Initial ECDA applications shall consider all parameters that affect the selection of the indirect inspection tools and the definition of the ECDA regions. Table 2 lists the elements of the Gasunie grid identified as essential in order to assess the prior condition of the pipeline.
In the second part of the preassessment, the gathered information defines a number of ECDA regions. An ECDA region consists of one (or more) section(s) of the pipeline with similar physical characteristics, corrosion histories, expected future corrosion conditions, and the ability to be examined by the same indirect inspection tools.
After the user has defined the parameters to be considered for identification of the ECDA regions, the DA module calculates the regions. These ECDA regions can then assist the user in interpreting results, deciding which indirect inspection tools can be used, and where direct examinations should be performed.
The third part of the preassessment quantifies the previous condition of the pipeline under investigation by assessing the failure probability of each ECDA region. Key parameters for which estimates must be made in calculating the probability of failure include:
- Time of initiation of corrosion defects. During the time between construction and going into service, the conditions for corrosion are established and the first instances of early corrosion growth take place.
- Defect density (for both coating and corrosion defects). This is a value that consists primarily of a starting value representing damages originating in the transportation and construction phases of the pipe and pipeline. Secondly, it represents the rate of introduction of new defects, starting from the initiation of service.
- Defect depth. A certain initial distribution for the defect depth is assumed at the time service is initiated, after which it gradually increases, depending on the corrosion rate.
- Corrosion rate. This is the rate at which the defect depth grows and is a major cause of uncertainty and likely to vary considerably between pipelines.
Information collected during the first part of preassessment provides the basis for these estimations. Combining data regarding factors such as the age of the pipeline, coating type, level of CP, and soil conditions determines the prior distribution of the densities of coating and corrosion defects, with the prior distributions defining the geometry of corrosion defects.
If relevant information is not available for a specific pipeline, the user can fall back on the complete database of all pipelines for the required analysis. This functionality (automatic retrieval of data from pipelines with similar specifications or environmental conditions) results in a huge increase of accessible data (now and especially in future) and makes it possible to reduce the cost of inspections substantially by applying statistics.
In practice, parameters concerning the geometry of the pipeline (e.g., WT) or material properties (e.g., flow stress) are also associated with uncertainties, especially in the case of older pipelines. The DA module treats these quantities as probability density functions as well, rather than using constant values.
The model can also calculate the probability that a single defect will fail, depending on the age of the pipeline and the uncertainties described earlier. Guidelines from the Linepipe Corrosion Group-sponsored JIP, developed through a combination of analysis and full-scale testing, predict the failure pressure of part-wall corrosion defects.14 Combining the probability of failure for a single defect with the previously determined defect density allows calculation of the probability of failure for each ECDA region.
Indirect inspection
Indirect inspection seeks to identify and define the severity of coating faults, other anomalies, and areas at which corrosion activity may have occurred or may be occurring. NACE requires the use of at least two aboveground inspections over the entire length of each ECDA region. Gasunie indirect inspections for ECDA purposes usually consist of:
- Direct Current Voltage Gradient (DCVG) survey to detect and pinpoint coating defects along the pipeline.
- Close Interval Potential Survey (CIPS) to measure both the pipeline’s on-off potentials and the on-off potential gradients to remote earth. These measurements determine whether a possible coating defect is sufficiently protected by the CP system.
- Wenner measurements to measure the soil resistivity at regular intervals along the route.
- dGPS measurements to measure the position of coating-defect indications, soil resistivity, and characteristic features along the pipeline.
Fig. 3 shows a typical survey team. In this approach, CIPS does not detect coating defects but instead assesses corrosion activity at possible anomaly locations detected by DCVG. Francis et al., however, produced complete derivations for the use of 1 or 2 coating surveys or 1 coating and 1 corrosion survey.
The lack of a 100% reliable inspection technique requires that the performance of the inspection tools used is also taken into account, including other variables such as type of coating, soil conditions, and depth of cover.
Two variables characterize tool performance:
- Probability of Detection (PoD): the probability that a defect present is detected by the survey technique.
- Probability of False Indication (PoFI): the probability that the survey technique gives an indication where no actual defect is present.
Indirect inspection consists of:
- Data storage. The data from the aboveground surveys are stored in a database for processing and future reference.
- Data processing, interpretation, and visualization. If required, the data from the surveys can be corrected for factors such as the depth of cover and currents through the pipeline.
The DA module also calculates the IR-free potential (the potential of the steel at the exact point where the surface of the steel meets the surrounding environment, not distorted by the soil resistance between reference electrode and pipeline) and its uncertainty. The DA module presents the required data in a clear and comprehensive manner by plotting (combinations of) graphs on the screen, simplifying interpretation of data by the operator.
- Generation of a priority list of direct examination (excavation) sites. This list will be generated based on parameters chosen by the operator such as coating defect size, expected corrosion, and soil resistivity.
- Establishing the condition of the pipeline after indirect inspection. Based on findings from the aboveground surveys, the distribution of coating and corrosion defects are updated with Bayesian statistics. The performance characteristics of the applied survey techniques play an important role in these calculations.
The prior distributions of the PoD and the PoFI of a survey technique can be constructed from previous experience with the technique or from manufacturer recommendations.
Acknowledgments
The author expresses his gratitude to Piet van Mastrigt, Gasunie Engineering & Technology, for his collaboration on this project. Andrew Francis, AFAA, is acknowledged for the contributions made to the SRA model. Giorgio Achterbosch, Rob Bos, Kees Dijkstra, Henk Horstink and Wytze Sloterdijk, N.V. Nederlandse Gasunie, are acknowledged for their input throughout the project. Finally, ATP Neftegazsystema is acknowledged for support and feedback during the process of developing the functional specifications of the DA module for PIMSlider, and for building the DA module.
References
1. NACE Standard Recommended Practice RP0502-2002, Pipeline External Corrosion Direct Assessment Methodology, 2002.
2. Bos, R., “The PIMS Implementation Program for Sasol’s Gas Operations,” Journal of Pipeline Integrity, Quarter 1, 2005.
3. Francis, A., Edwards, A.M., Espiner, R.J., and Senior, G., “Applying Structural Reliability Methods to Ageing Pipelines,” Paper C571/011/99, IMechE Conference on Ageing Pipelines, Newcastle, UK, Oct. 11-13, 1999.
4. Francis, A., and McCallum, M.A., “Integrity Management Using Direct Assessment and Structural Reliability Analysis,” Workshop at Gasunie Research, Groningen, The Netherlands, 2003.
5. Andrew Francis & Associates Ltd., “A Robust Methodology for External Corrosion Direct Assessment,” Report AFAA-R0003-04, 2004.
6. Andrew Francis & Associates Ltd., “A Robust Methodology for External Corrosion Direct Assessment-Supplement,” Report AFAA-R0004-04, 2004.
7. Francis A., Harris, J., McCallum, M.A., McQueen, M., Sansom, A., and Ward, C.R., “Structural Reliability Analysis for ECDA,” prepared for Gas Research Institute, GRI-04/0093.2, 2005.
8. Os, M.T. van, Mastrigt, P. van, Horstink, G.H., Achterbosch, G.G.J., Stallenberg, G.A.J., and Dam, A.M., “A Structural Reliability Based Assessment of Non-Piggable Pipelines,” Paper 05151, NACE Corrosion2005, Houston, Apr. 3-7, 2005.
9. Andrew Francis & Associates Ltd, “A Detailed Methodology for External Corrosion Direct Assessment Taking Account of Two Above Ground Surveys,” AFAA-R0013-05, 2005.
10. ASME B31.8S, “Managing System Integrity of Gas Pipelines, Supplement to ASME B31.8,” 2005.
11. EGIG, “Gas Pipeline Incidents (1970-2001),” 5th Report of the European Gas Pipeline Incident Data Group, EGIG 02.R.0058, 2002.
12. UKOPA, “Pipeline Product Loss Incidents (1961-2000),” 2nd Report of the UKOPA Fault Database Management Group, Advantica Report R 4798, 2002.
13. PRCI, “Analysis of DOT Reportable Incidents for Gas Transmission and Gathering System Pipelines, 1985 through 1997,” Report PR-219-9801, 2002.
14. Batte, A.D., Fu, B., Kirkwood, M.G. and Vu, D, “New Methods for Determining the Remaining Strength of Corroded Pipelines,” 16th International Conference on Offshore Mechanics and Arctic Engineering, Yokohama, Japan, Apr. 13-17, 1997.
Based on presentation to the World Gas Conference, Amsterdam, June 5-9, 2006
The author
Menno van Os ([email protected]) is a pipeline-integrity specialist with Gasunie Engineering & Technology, Groningen. His primary fields of interest are coatings, corrosion, cathodic protection, and direct assessment. Before joining Gasunie, he served as a development chemist of coatings for optical glass fibre at DSM, Hoek van Holland. He received an MSc (1996) in chemical engineering and a PhD (2000) in materials science and polymer technology, both from the University of Twente.
