Pipeline Integrity management

The US Department of Transportation (DOT) Office of Pipeline Safety (OPS) regulations 49 CFR Part 192 for natural gas pipelines and 49 CFR Part 195 for liquid lines require pipeline operators to implement pipeline integrity management programs to address various integrity threats. The threats are categorized into three categories: time-dependent, time-independent and static. One of the three time-dependent threats is internal corrosion. While dry gas systems that are known not to have experienced liquid upsets or liquid lines that carry refined products may be considered to have a minimal threat of internal corrosion, the majority of pipelines are subject to an internal corrosion threat to a varying degree.

Once the threat of internal corrosion has been identified, operators are required to conduct an integrity assessment to assess the integrity of the pipeline with respect to the threat. For internal corrosion, there are currently three acceptable integrity assessment methods for gas pipelines and two acceptable integrity assessment methods for liquid lines. In addition, an operator may use ‘other technology’ provided that they notify OPS prior to implementation.

Hydrostatic testing

Periodic hydrostatic testing is one of the acceptable methods to ensure the integrity of both liquid and gas pipelines. The most significant benefit of hydrostatic testing is that it will remove all axial defects, regardless of geometry, that have critical dimensions at test pressure. For in-line inspection (ILI) and direct assessment (DA) there is always a chance that a near-critical defect will be missed by the assessment method.

There are, however, a number of limitations to hydrostatic testing. It is not practical for pipelines that cannot be taken out of service. Additionally, no information is gained regarding the presence or absence of sub-critical flaws. Finally, from an internal corrosion control standpoint, hydrostatic testing raises a concern regarding the ability to effectively de-water the pipeline. Any water that remains in the pipeline following a hydrostatic test may create conditions conducive to internal corrosion. De-watering pigs may be used to help remove the water and reduce this concern. Corrosion inhibitors could be added to the test water; however, water disposal then becomes an environmental issue.

In-line inspection

ILI is the second accepted technique to ensure pipeline integrity for gas and liquid pipelines. A wide variety of ILI tools are available to pipeline operators. The current technologies for metal loss inspections are magnetic-flux leakage (MFL) and ultrasonic (UT) wall thickness measurement. MFL technology can be applied axially or circumferentially. ILI provides information regarding the location and depth of corrosion defects. Digs are typically performed to verify the accuracy of the ILI results.

Successive ILI runs on the same line segment may be used to help determine whether active corrosion is occurring and potentially estimate a corrosion growth rate, based on the change in indication depth with time. This can be a difficult task, especially if a different tool was used for each ILI run. The presence of waxes or solids in a pipeline can lead to erroneous ILI results, therefore it is important that the line be cleaned using a cleaning pig prior to an ILI run.
ILI is likely the preferred method for operators whose lines are piggable. However, some pipeline designs (telescoping pipe diameters, the presence of offsets, multiple valves, etc.) may prohibit the use of ILI tools. In such cases, line modification to allow ILI may be impractical, if not impossible.

Direct assessment

The third approved assessment method for natural gas pipeline operators is internal corrosion direct assessment (ICDA). NACE approved the Standard Practice SP0206, “Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)” in late 2006. The standard is a four-step process, similar to the other NACE direct assessment standards (ECDA and SCCDA). The standard practice is applicable to pipelines that carry normally dry natural gas but may experience short-term, intermittent liquid upsets. The basis of DG-ICDA is that internal corrosion is most likely where water (electrolyte) first accumulates and detailed examination of these locations provides information regarding the remaining length of the line. If the locations most likely to have accumulated electrolyte are free from internal corrosion, then other locations less likely to accumulate electrolyte are unlikely to have suffered corrosion.

ICDA is most useful for pipelines that are not currently piggable (or cannot be made piggable) and for which hydrostatic testing is not feasible. DG-ICDA when performed on long lines with limited liquid inputs, may allow the internal corrosion integrity of a number of miles to be ensured with a small number of digs. However, for shorter lines with multiple liquid inputs a large number of examinations may be required to ensure pipeline integrity, making implementation costly. Using DG-ICDA, detailed information regarding the actual pipeline condition is only obtained at locations selected for examination, as opposed to ILI, where locations of metal loss indications are obtained for the entire length assessed. Additionally, the DG-ICDA methodology is intended for use in systems that only experience intermittent upsets; therefore, storage or gathering systems and other lines known to regularly contain liquids cannot be assessed using this methodology.

Standard Practices for Wet Gas Internal Corrosion Direct Assessment (WG-ICDA) and Liquid Petroleum Internal Corrosion Direct Assessment (LP-ICDA) are currently under development at NACE. These processes follow the same four-step approach used in DG-ICDA and other DA methods. Both LP-ICDA and WG-ICDA are considered ‘other technologies’ and would require OPS notification prior to implementation. WG-ICDA is intended for natural gas pipelines that contain less than 10 percent liquid. WG-ICDA considers the factors that influence the corrosion severity for each flow regime (i.e. stratified flow, slug flow, annular flow, mist flow) experienced by the pipeline segment. LP-ICDA is intended for pipelines that are fully packed with a hydrocarbon product that normally contains less than five percent basic sediment and water (BS&W). Similar to DG-ICDA, LP-ICDA is concerned with identifying locations where water (electrolyte) accumulation may occur. Solid accumulation is also considered for lines in which solids are known to exist. Both documents are expected to go to ballot in the near future.

Continual evaluation and preventative and mitigative measures

Once an operator had performed an integrity assessment, they are required to perform a continual evaluation of the pipeline segment and implement preventive and mitigative measures. Identifying internal corrosion, through integrity assessments, that has already occurred becomes a reactive practice. However, the use of continual evaluation and preventive and mitigative measures are proactive practices to help reduce the future impact of corrosion. For internal corrosion, continual evaluation may include the use of corrosion monitoring devices, and gas or liquid sample analyses. Additionally, for pipeline systems where integrity assessments identify extensive or significant internal corrosion, continual evaluation measures may include periodic examinations at selected locations, such as low points or dead legs. Preventative and mitigative measures may include the use of corrosion inhibitor, performing pig cleaning, installing separation or dehydration units, or establishing more restrictive gas or liquid quality limits to reduce corrosive constituents present in the pipeline system. These measures may also be a part of an operator’s routine internal corrosion control activities.

Explained: DG-ICDA

The four steps of DG-ICDA are pre-assessment, indirect inspection, detailed examination and post assessment.

1. During the pre-assessment step of DG-ICDA, an operator must collect data regarding the current and historic operating condition of the pipeline. The data is then used to establish the feasibility of performing DG-ICDA and identify regions based on locations of potential liquid input.
2. The indirect inspection step involves performing flow calculations to determine the critical inclination angle, beyond which liquid cannot travel. Stratified film flow is considered the primary liquid-water transport mechanism for these flow calculations. Pipeline elevation profiles are also determined during the indirect inspection step. Elevation profiles are typically obtained by performing GPS surveys along the pipeline. Depth-of-cover measurements are also collected during the survey so that the pipeline elevation can be established by subtracting the depth of cover from the land elevation. The pipeline elevation profile is then compared to the results from flow calculations to identify locations where liquid accumulation may occur.
3. When performing the detailed examination step, the operator must excavate (if buried) the locations selected identified for potential liquid hold-up and inspect them for the presence of internal corrosion. Many different non-destructive testing (NDT) techniques are available to determine the presence of internal corrosion; currently no standard exists to guide operators in determining the length of pipe to inspect and the detail with which the inspection should be performed.
4. The final step of the DG-ICDA process is the post assessment. During this step the operator must determine the effectiveness of DG-ICDA for the pipeline being assessed and establish re-assessment intervals.