Subscribing to a new ILI approach

Figure 4. IntelliCOAT system’s infrared heating panels.

Bringing automation to the field – Capacity4gas Located in Plzen, Czech Republic, construction of the Capacity4Gas pipeline project commenced in December 2019 and is an ongoing project for 2021.

Recognised for an extensive and proven track record of product performance and project excellence, through the Italian partner LK2, Canusa-CPS was selected as the supplier of the field joint coatings utilising GTS-65 heat shrinkable sleeves with IntelliCOAT equipment on a 56 in. diameter pipe. This system provides superior corrosion protection and excellent bonding on pipelines operating up to 65˚C.

In addition to supply of HSS and lease of IntelliCOAT equipment, installation training and certification for the SICIM coating team was provided by the Canusa-CPS Field Service team to give the client, Net4Gas confidence that all best practices were adhered to while ensuring high productivity rates.

The principal challenge detailed by the contractor, SICIM, was maintaining productivity in a safe manner for the duration of this project. Automation and process control were paramount to successfully deliver this project in the assigned time frame. A system which ensured consistency with every FJC installed on the pipeline minimising risks and uncertainty was essential.

The IntelliCOAT system enabled SICIM to accurately forecast the daily FJC productivity without reliance on operators to conduct any labour-intensive work steps. Application time per joint was pre-set during the qualification stage to ensure production could proceed on schedule. Utilising this system, SICIM averaged 30 joints per day and a maximum daily rate of 45 joints per day.

Further benefits to SICIM were significant manpower savings, as FJC installation on large diameter pipelines can be completed without the addition of extra labourers to install the coating over a larger surface area as would typically be required for manual applications. This project is expected to be completed in 2021 and demonstrates the operational benefits that Canusa-CPS training and certification programmes have on maintaining competency in applying field joint coatings on long duration large diameter onshore projects.

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Graham Marshall, Sonomatic, UK, looks at ways to manage the life and integrity of aged unpiggable pipelines.

Across the globe in the oil and gas industry, there is a continued importance placed on integrity management of ageing assets and maintaining the longevity of pipelines and structures that are reaching the end of their design life. In most regions, these pipelines may only be operated beyond their intended design life if an extension study has been conducted and approved by stakeholders.

In recent years, the idea of continuing use beyond a pipeline’s design life has become increasingly accepted. This could be considered for example, due to a new field development that needs to be tied back to an existing pipeline, or simply that there are still reserves to be recovered after expiration of production asset lifetimes.

Corrosion damage is the main concern with ageing pipelines that dominates any plans to extend their life cycle. Corrosion is the breakdown of the parent material due primarily to electrochemical processes where there is an exchange of electrons between two materials. Corrosion has the potential to reduce a product’s design life by premature degradation. The rates of attack and severity of corrosion will vary depending on certain influencing factors. Typical corrosion mechanisms include uniform corrosion, stress corrosion cracking, and pitting corrosion.

Other scenarios that could cause integrity concerns are: ) Third party: This is more a concern in shallower waters and can be the result of trawl/anchor damage to a pipeline.

) Mechanical: These can be related to the manufacturing or installation process of the pipeline.

) Natural hazards: Wave action and currents can cause scouring and accentuate free span issues.

Although pipelines are designed and manufactured in accordance with design codes, unanticipated changes in the environment in which the assets operate can result in unexpected corrosion damage. Moreover, the combined effects of corrosion and mechanical damage, together with environmentally assisted material damage can result in unexpected failures.

Given the typical lengths of subsea pipelines, most operators would consider an internal inspection method to use as the basis for the life extension study. These are conducted utilising intelligent inline inspection (ILI) tools that provide comprehensive coverage over the full length of the pipeline. In some cases, it is not possible to carry out an ILI inspection due to reduced product flows and the absence of launch and receive facilities etc. In these cases, tethered or bi-directional tools may be required. These options, however, require the pipeline to be taken out of service for the duration of the inspection with associated production losses.

Pipeline targeted inspections online In this situation, an operator will need to consider an alternate means of inspection of the pipeline. Most operators would consider the use of a sampling or targeted inspection of selected locations along the length of the pipeline following a detailed corrosion risk assessment (CRA). The locations are selected on the basis of highest susceptibility to degradation as determined by the CRA.

Not all circumstances are predictable, but many are. Examples include low points in the pipeline where water may collect, cooler locations where condensation may occur, or locations where inhibiters may have been ineffective and are no longer protecting the internal surfaces of the pipeline etc.

However, when conducting an external sampling or targeted inspection, any access restrictions at the selected locations need to be assessed. Consideration should be given to whether the pipeline is buried, as well as the external coating type, as this can prove challenging to inspect through with certain inspection technologies. Removal of the coating could be carefully considered, however this will impact the life extension study, as removal of insulation/coating will affect the pipeline protection and condition.

Sonomatic has developed an exciting new inspection technology that enables inspection to be conducted through certain challenging subsea coatings where conventional ultrasonic is ineffective. Dynamic response spectroscopy (DRS) is an innovative ultrasonic inspection technique for corrosion mapping through attenuative coatings.

A custom DRS probe excites the steel with a range of low ultrasonic frequencies, which pass easily through the challenging coatings (such as neoprene, polypropylene/ polyethylene, composite wrap repairs, and Thermotite). The steel responds, vibrating at natural frequencies related to its thickness profile. Using advanced algorithms, these frequencies are extracted from the returning signal at each location and used to determine the steel thickness.

Due to the reduced coverage achievable by conducting externally applied technologies, typically at a tiny fraction of the total line, the purpose of inspection is not to locate all the degradation present in each pipeline, or even to confidently locate the worst-case location. The actual

Figure 1. A high-resolution ultrasonic corrosion map of a subsea pipeline subject to degradation by microbial induced corrosion (MIC). The corrosion morphology can be compared directly with the predictions of the corrosion risk assessment.

Figure 2. Polar plots and cumulative thickness distributions generated.

Figure 3. The Sonomatic MAG-ST crawler conducts 360˚ screening inspections with SH-EMAT or Multiskip.

Figure 4. Subsea ROV-iT conducts quantitative data collection over an area identified by screening techniques.

purpose is to gather sufficient information to underpin with confidence the assumptions of the CRA study.

Any inspection technology considered needs to provide data that will offer the accuracies of inspection that will be suitable to use as part of the life extension study. Inspection performance requirements, with respect to accuracy of measurement and probability of detection (POD), would need to be defined to ensure a low coverage inspection will provide a sufficient basis for statistical analysis of data. POD is key when performing a life extension study. A key factor when considering POD is the accuracy of the measurement and scan resolution, particularly for small diameter pits. Trials conducted by Sonomatic, supported by inspection modelling to estimate POD values for a 1 mm x 4 mm resolution identified that POD was greater than 90% for 1 mm deep flaws with an aspect ratio of 5.

Sonomatic has supported their clients by providing the following services in support of the evaluation of unpiggable pipelines: ) Bayesian statistical analysis for planning and evaluation of compliance inspections for dry gas lines where the purpose of the inspection is to validate absence of corrosion. ) Sampling inspection scheme development and evaluation of results for lines where the conditions are sufficiently homogeneous to allow a sufficient quantification of degradation characteristics based on small coverage.

) Statistical simulation to assess the effectiveness of sampling options and to evaluate the reliability of the results. This includes consideration of both quantified sampling and screening type approaches.

) Planning and evaluation based on direct assessment methods, for example, ICDA or ECDA.

An advanced integrity services capability incorporating statistical processes adds value to the inspection data. Critical comparisons between repeat inspections with high degrees of precision, circumferential profiling of the external surfaces of pipelines, and extrapolation of collected data over un-inspected areas are examples.

Thickness distribution plots are graphical representations of measured thicknesses plotted against proportion of area on a logarithmic scale. These plots can be highly informative in terms of portraying the actual corrosion behaviour. Often, historic corrosion behaviour can be extracted. This is highly informative in terms of correlating observed corrosion behaviour to that predicted through the CRA. (Figure 2) It can be seen that the value is far beyond the concept of conventional ultrasonic corrosion mapping that typically generates minimum, maximum, and average thicknesses. The adage ‘garbage in, garbage out’ applies and an integrated, appropriately controlled inspection generates the quality of source data that is used to maximum effect in the integrity assessment.

Pipeline screening to maximise coverage It is not a realistic option to conduct full length coverage of a pipeline using externally applied inspection technologies such as 0-degree corrosion mapping. This would be very costly and time consuming due not only to the impractical duration of the inspection itself, but also the implications of dredging, weight-coat, and coating removal.

From an operator’s perspective, it would be more desirable and cost effective, where possible, to use a less invasive screening inspection technique. Screening techniques such as medium range horizontally polarised guided shear waves introduced by electromagnetic acoustical transducers (EMATs) and/or Multiskip using shear wave pulse echo probes in a pitch/catch mode of operation, make screening of the pipeline possible and can provide a more global perspective of the pipeline, suggesting which area may require additional attention.

The optimum approach to inspection will depend on the nature of the potential degradation. In some cases, a screening approach will be appropriate. Screening methods typically provide for higher coverage; however, these techniques provide ‘qualitative’ results and will only offer a general understanding of wall loss in a particular area (typically a coarse percentage of wall loss at each location).