IN-LINE INSPECTION PROGRAMS FOR

Corrosion & Prevention 2013 Paper 100 - Page 1

IN-LINE INSPECTION PROGRAMS FOR CORRODED PIPELINES

A. Low1, C. Selman1 1Wood Group Integrity Management, Perth

SUMMARY: This paper presents an overview of the status in-line inspection technologies that are currently available in the industry, including the theory behind each inspection technique. It discusses application of in-line inspection technology for the use of detecting corrosion features. The main focus of this paper will be to discuss the practical aspects of performing an in-line inspection of a pipeline including planning, execution, data evaluation and interpretation. The objective of this paper is to provide the reader with an appreciation of the capabilities and limitations of using in-line inspection technology to inspect corroded pipelines.

Keywords: Inspection, Corrosion, Integrity, Fitness-for-Purpose, Pipeline.

1. INTRODUCTION In-line inspection tools are instrumented devices sent down the inside of an operating pipeline system to collect information about the integrity, physical state, position or conditions in a pipeline using a variety of highly complex instrumentation and sensors. They are also known as intelligent or smart pigs, which distinguishes these tools from their less sophisticated counterpart, utility pigs which generally do not have instrumentation, and are used for cleaning, gauging, dewatering or other pipeline operations or maintenance purposes.

The planning of an in-line inspection campaign is challenging, as there are many variables to consider. The physical design and current condition of the pipeline, the physical and chemical conditions within the pipeline, the objectives of the inspection program, and the size and type of defects that are required to be identified define and limit the inspection technology that can be utilised. This determines the vendors with the required capability and how the program will be executed.

The execution of an in-line inspection program has many practical challenges relating to handling, logistics, environmental, available facilities, inspection procedures and the handling of hazardous materials. Planning and preparation is critical to avoid the primary risk of getting a pig stuck.

Figure 1: Example in-line inspection tool (Source: Public image library of Nord Stream AG)

The final challenge lies in interpretation of in-line inspection data when the final report is received. Engineering assessment of the reported features is required, so that the impact of any features on the integrity of the pipeline can be determined.

2. IN-LINE INSPECTION TECHNOLOGIES There are a number of inspection technologies that are currently available. The different technologies have been developed to address specific inspection requirements and inspection conditions.

2.1 Geometry (GEO) Geometry or caliper tools are designed to record the internal radius and cross section profile of a pipeline along its length. Types of information that may be collected from a geometry tool include pipeline length, diameter, dents, wrinkles, ovality, location of features (e.g. bends, flanges, welds, tees, wyes), bend radius and angle. The wall thickness can be inferred from


the internal radius. Caliper pigs work by running a number of fingers along the wall of the pipe, with the radius calculated from the angle of the finger.

Geometry pigs can also be fitted with a Geographic Information System (GIS) data logger to record exact pipeline route information. Data loggers to record pressure and temperature along the pipeline are also an option.

Inspection using geometry in-line inspection tools can be performed as a stand-alone operation and is often required to precede a metal loss inspection to demonstrate that the metal loss tool can readily traverse the line, especially where there is a lack of detailed design information available on the pipeline. Geometry tools are not as complex, expensive or challenging to run as a metal loss inspection tool.

2.2 Magnetic Flux Leakage (MFL) Magnetic Flux Leakage (MFL) technology is one of the most common metal loss inspection technologies used by in-line inspection tools, particularly in gas systems.

Magnetic modules on the in-line inspection tools generate a magnetic flux that penetrates the thickness of the pipe wall. Any in-homogeneities in the pipe wall (e.g. internal or external corrosion, dents, welds or cracks) cause a disruption to the magnetic flux. Sensors are used to measure the disruption in the flux and the response pattern. This is then used to characterise, locate and size the feature that has been detected.

MFL tools can operate in both gas and liquid pipelines. A key advantage of MFL over techniques such as ultrasonic is that it does not require an acoustic coupling, so is ideal for gas systems.

Figure 2: Basis of Magnetic Flux Leakage

The ability to achieve a sufficiently powerful magnetic flux in the pipe wall is critical for a successful inspection, and determines the size of defect that can be detected. For this reason, a number of key variables must be considered when this technology is being considered. First, the magnet strength required to penetrate the pipe wall is directly related to wall thickness. The challenge with heavy wall pipe is that strong magnets are required to achieve sufficient flux penetration however, this increasing magnet strength makes it challenging to launch the tool and keep it moving.

The correct sensors must also be specified. High-resolution inspections should be specified wherever possible. This is where the tool is fitted with sensors that are able to differentiate whether a detected feature is located on the internal surface, outer surface or within the pipe wall. The majority of modern MFL tools now provide this inspection resolution as a standard capability.

2.3 Ultrasonic Tools (UT) Ultrasonic (UT) inspection is another common in-line inspection technology. It based on the common non-destructive testing method that has been used for many years on external pipe surfaces.

A UT inspection involves sending a short sound or pulse wave into a material and measuring the time taken for the pulse to be reflected back (the pulse-echo). The ultrasound is reflected from any interface, such as the back wall of the pipe, or any inhomogeneity within the material, such as a crack. The features are detected using sensors and sized according to the amplitude and time taken for the signal to return.

UT inspections require an acoustic coupling medium between the transducer and the surface of the material being inspected which generally means this technology can only be used for the in-line inspection of pipelines that are liquid filled. If UT is required in a gas system, either the pipeline must be flooded prior to the inspection, or the pig must be run in a liquid slug between other pigs. Both are significantly onerous procedures.

Figure 3 Principle of ultrasonic testing

Flooding a gas line requires careful chemical treatment of the flooding liquid, and dewatering (and possibly drying) of the line post-inspection. Running an inspection tool in a liquid slug requires co-ordination of launching and receiving a series of pigs, with the liquid slug suspended between them. The liquid slug must be injected and disposed of correctly, and loss of the liquid slug as the survey is carried out will prevent successful inspection.


2.4 Pulsed Eddy Current (PEC) Pulsed eddy current (PEC) is a more recent development for use with in-line inspection tools. Eddy current testing uses electromagnetic induction to detect flaws in conductive materials.

Alternating current is passed through a primary coil on the inspection tool to generate a magnetic field within the adjacent pipe wall. The eddy currents generated are measured and used to size detected features.

As the strength of eddy currents that are generated decreases with distance from the electric coil, PEC technology for in-line inspection is typically only used to detect and size small features that are located on the pipe internal wall.

PEC is less suitable if features are located on the external surface, especially in thick wall pipelines. It is most often used in conjunction with other technologies such as UT in a combined tool configuration.

Figure 4 Pulsed eddy current theory

2.5 Electromagnetic Acoustic Transducer (EMAT) Electromagnetic acoustic transducer (EMAT) technology is a new development for use with in-line inspection tools and is still undergoing development and process improvements.

An EMAT transducer is made up of a magnet and an electric coil. Independent magnetic fields are generated by the magnet and electric coil, when an alternating current is introduced. When this is placed in close proximity to the test surface, an ultrasonic wave is generated from the interaction of both magnetic fields. A conventional UT transducer then detects this wave. This can be used in the same way as conventional UT pulses to detect wall thicknesses and flaws.

The benefit of the EMAT transducer is that it does not need to be in contact with the test surface and does not require an acoustic coupling. EMAT can therefore be used for in-line inspection of both liquid and gas filled pipelines.

Figure 4 Principle of EMAT technology

However, the EMAT signal is more complex and generates a weaker signal in comparison to traditional UT probes, so analysing the signal is more difficult. Current EMATs are also large in size, making them less practical for installation on in-line inspection tools, though the size and practicality is likely to improve with over time. Once developed and modified for in-line inspection tools, EMATs could present an attractive alternative to MFL for the inspection of gas pipelines, particularly those with walls too thick for MFL.

2.6 Acoustic Resonance Technology (ART) Acoustic resonance technology (ART) is another relatively new development by Det Norske Veritas (DNV) [1] for use with in-line inspection tools. Field trials and continuous development is on going, though initial trials are showing promising results.

ART works by sending an ultra-broadband pulse acoustic signal through the test material. As the pulse passes through the material, a resonance is generated with frequencies that are characteristic of the material and its thickness. After the transmitter has passed a given location, a weak narrow-band signal leaks from the material, which is detected by the trailing receiver. The frequency spectrum, resonance peaks and their spacing in the narrow band signal are measured to determine the thickness of the material at that location [1]. ART does not require an acoustic coupling or contact with the pipe and therefore is applicable to inspection of both gas and liquid filled pipelines. Figure 5 ART technology theory


The lower frequencies and longer wave lengths mean that ART is able to achieve a greater depth of penetration compared to conventional UT signals and inspection of non-ferrous materials is also possible. ART is also more tolerant of deviations from the inspection angle (i.e. is better on rough surfaces) than traditional UT. At the present time, there is only one large-diameter tool available but there are plans to develop additional tools to address different pipe sizes and commercialise this technology in the near future.

2.7 Combined Technologies Combined technologies are often specified and utilised during in-line inspection programs. This is where more than one technology is utilised on a single inspection vehicle. This is commonly used to improve the quantity and quality of data that is collected. The data that is returned to the NDT transducers are typically in a form of a signal, which still needs to be processed and interpreted. Having more or different signal types can assist with processing, as more detailed information is available.

3. METHOD OF PROPULSION

3.1 Free-Swimming The most common propulsion method for in-line inspection is to use free-swimming inspection tools. These are tools that propelled through the pipeline using flow in the pipeline. Normal production flow is used in the majority of cases, but where this is not practical or does not provide favourable flow conditions, a suitable non-process fluid such as nitrogen, air, potable water or treated seawater can be used.

Free swimming tools can be used when there are launching and receiving facilities, adequate propulsion medium, as well as the required differential pressure to propel the tool. Most of these tools are uni-directional however; a number of bi-directional tools are available.

All inspection tools have limits of velocity (typically 1-5m/s) outwith, which the probability of detection of defects and also the accuracy of location and size data is adversely affected, due to limitations on sensor and data recorder technology. Acceptable operating speeds vary with the inspection tool and vendor. Where practical, the appropriate velocity is achieved by adjusting the flowrate to give an acceptable tool velocity, but where this is impractical (e.g. in pipelines with high minimum flowrates), tools are available with active bypass technology for speed control process fluids are allowed past the tool to lower the tool velocity at a given flowrate. Velocity excursions are common in risers, or scarp crossings, and where slugging behaviour is observed. Managing velocity is a critical factor in successful inspections.

3.2 Tethered Tools Tethered tools are those that are tethered to a winch for deployment or retrieval. In vertical systems such as risers, the winch is used to lower the tool into the line at a controlled rate. Tethered tools can also be pushed down the line with process or service fluids. Once inspection is complete, or the tool has reached the limit of the tether length, the winch system is used to recover the tool. The tether can also function as an umbilical, so that only the primary sensors need to be located on the tool itself; recording and analysis equipment can remain outside the pipeline, reducing the size and complexity of the tool.

Tethered tools are useful in situations where there is only a single-point topsides access to the pipeline (for example on tanker loading lines or subsea tie-backs). There are obviously limitations on the length able to be surveyed based on winch capacity and tethered tools require additional safety considerations due to the requirement to maintain access to the pipeline during inspection works, though gland arrangements for the tether can allow tethered inspection of pressurised or hazardous lines.

3.3 Crawlers and Tractors Crawlers and tractors are in-line inspection tools that have the ability to fully self-propel either in one or both directions. Some crawlers are fully self-contained, whereas others are tethered. Self contained crawlers and tractors do not require the system to be open to the environment, however controlling the speed and position in vertical or steeply inclined lines can be difficult. Tethers allow more reliable recovery via a winch, but the drag of the tether limits the range of the survey. Like gravity or flow propelled tethered tools, many crawlers are sensor packages only, transmitting data back to storage and analysis facilities outside the pipeline. They are often fitted with lights and remote controlled high definition cameras to permit live visual inspection of the line. All crawlers have relatively short ranges; long pipelines cannot be inspected due to limits in battery technology.


4. IN-LINE INSPECTION TOOL CONFIGURATION In-line inspection tools comprise of a number of modules joined by articulated couplings. The configuration of each module varies with each vendor and depends on the inspection technology of the tool, and the objective of the inspection program. Typical modules are described in Table 1.

Table 1. Typical Components of an In-Line Inspection Tool

Component Function

Drive Unit In a free-swimming tool or flow driven tethered tool, the drive unit is a set of drive cups, which provide the seal against the pipe wall against which differential pressure and propulsion is achieved. Crawler tools have one or more mechanical drive units, with caterpillar tracks, wheels or other propulsion system.

Sensor Unit(s) Holds the sensors used to perform the inspection. Combined inspection technique tools may have a single unit with multiple sensor types, or there may be a separate unit for each sensor type.

Magnets Generates the magnetic flux (MFL tools only). Battery Unit(s) Provides electrical power for the in-line inspection. Data Recorder Records and stores the signals from the sensor unit and odometer.

Odometer Provides a measure of the log distance during an in-line inspection run.

The various components are modules typically mounted in a train, connected by an articulated joint system. The joints and the length of the units limit the bending radius of the tool, so pipeline features such as bends, tees, wyes and valves can be obstacles to a survey. For existing pipelines, this means that the design of the proposed tool train must be carefully matched to the features and restrictions of the pipeline to be inspected. For a new design pipeline, it is necessary to identify the generic limitations of tools appropriate to the pipeline, and design the pipeline accordingly.

The length of an in-line inspection tool generally increases as the pipe internal diameter decreases, and also increases with the intended length of the survey (to accommodate the extra battery, sensors and storage capacity). If in-line inspection is anticipated during the service life of a pipeline, the appropriate inspection technology must be identified at the design stage, so that pipe bends and pig traps can be correctly sized. This means that identifying the likely inspection tool is a critical design decision. For existing pipelines, the existing pig traps must be matched to the proposed tool; if the existing traps are inadequately sized, new traps may need to be constructed, which can add to the lead time and cost of a survey. Space limitations in the pig trap location may also affect the available size of the trap, and so limit the tool selection.

5. INSPECTION OF CORROSION FEATURES

5.1 Pipeline Operators Forum (POF) As in-line inspection technology developed, a group of operators formed the Pipeline Operators Forum (POF) to develop a specification for in-line inspections [2], which is commonly referred to as the POF specification. The objective of the forum was to ensure consistency on in-line inspection terminology, feature detection and reporting standards across the industry. More recent POF publications include guidance documents to achieve successful in-line inspections [3] and on field verification procedures for in-line inspection [4].

5.2 Feature Detection The in-line inspection technology that will be used will depend primarily on the corrosion features to be measured. In the majority of cases, inspections are performed to quantify metal loss features such as corrosion. Inspections can also be performed to detect the presence of axial or longitudinal cracks, dents, wrinkles, weld anomalies, buckles, coating disbondment and leaks.

Metal loss anomalies are classified by the POF in accordance with its geometry. Figure 6 shows the graphical presentation of the standard POF anomaly classifications based upon the relative length (L) and width (W) divided by the geometrical parameter A. For pipes with wall thickness (t) less than 10mm, then A = 10mm. For pipes with wall thickness (t) equal to or greater than 10mm, then A = t.

A key variable that must be understood with reference to feature detection is the probability of detection (POD). The POD refers to the likelihood that a feature present in the pipe wall will be detected. The POD largely depends on sensor technology, construction of the in-line inspection tool and inspection run conditions (such as velocity).


The POD can decrease in the heat affected zone (HAZ) and weld metal areas. This occurs in particular when MFL technology is used where the internal weld bead lifts the magnet and sensor from the pipe wall, disrupting the magnetic field. The POD can also decrease around pipeline features such as bends, tees, wyes and valves for the same reason.

As the objective of any in-line inspection is to detect and size features, understanding the key variables that can affect the POD and inspection accuracy is critical (see Section 6).

5.3 Feature Reporting The majority of inspection techniques have two thresholds. The first is the detection threshold, which represents the limits for the tool to detect and size a feature. MFL and similar tools have a detection threshold determined by the thickness of the pipe wall; advanced MFL tools have a detection threshold of 5% of the pipe wall thickness, however typical tools are around 10% of the pipe wall thickness. Figure 6 Feature Classification (Source: Reference 2)

UT and similar tools have a more absolute size threshold, of the order of 0.1-0.5mm. The second is the feature-reporting threshold, which represents the smallest feature that will individually be reported in the final inspection report.

The majority of inspection techniques have two thresholds. The first is the detection threshold, which represents the limits for the tool to detect and size a feature. MFL and similar tools have a detection threshold determined by the thickness of the pipe wall; advanced MFL tools have a detection threshold of 5% of the pipe wall thickness, however typical tools are around 10% of the pipe wall thickness. UT and similar tools have a more absolute size threshold, of the order of 0.1-0.5mm. The second is the feature-reporting threshold, which represents the smallest feature that will individually be reported in the final inspection report.

The reporting threshold can be the detection threshold however, is typically set at much higher limits, often determined by pipeline operator based on the defect tolerance of the pipeline.

Figure 7 illustrates a typical signal that is recorded by a MFL inspection tool. This signal is then processed by specialist data processors, who translate these signals into reported features. Signal processing is very complex and time consuming. A lower reporting threshold means more processing time, as the small features are harder to size due to noise interference.

Figure 7 Typical MFL Signal Report

6. KEY INSPECTION VARIABLES When planning an in-line inspection program, a number of key variables must be taken into consideration. These variables influence the ability to perform an in-line inspection, to execute a successful inspection run, and to generate high quality inspection data, in terms of high POD and sizing accuracy.

6.1 Content Pipeline content (phase, and composition) during the inspection run is a key variable that determines which in-line inspection technology can be used. This should be the primary consideration when planning an inspection program.

Liquid pipelines can be inspected by all the available technologies, so the key considerations for selection of tools for liquid lines are typically in relation to acceptable pressure, temperature and flow rates. Gas pipelines can limit the use of UT based tools as described in Section 2.3, as well as being limited by the physical conditions.

Vendors also need to be advised of content in terms of presence of highly corrosive products (e.g. H2S or CO2), sand, debris, wax, mercury and any other elements that may affect performance of their inspection tool.


6.2 Pressure and Temperature Pipeline pressure may need to be reduced during the inspection run to protect the tool. A pressure limitation is dependent on the physical build of the tool and therefore varies with each vendor. Planning has to consider the effect of content and pressure on the flow rate during the inspection (see Section 6.3). The maximum operating temperature for most in-line inspection tools is around 65C. The majority of tools can tolerate temperatures up to 80C for short periods, but bespoke inspection tools are required for sustained higher temperatures.

6.3 Flow Rates

All inspection tools have an optimum operating velocity range as described in Section 3.1. The tool velocity is mostly determined by the flow rate during the inspection run which can usually be adjusted by choking the production flow. Flow rate variations and speed excursions can also occur due to slug flow, bends, features, and inclines and changes in the line diameter or internal surface condition. Some vendors have designed tools with active bypass function so that the tool can maintain its own speed during the inspection.

The selection of the in-line inspection tool therefore must include consideration for the limits of velocity of the tool compared with the flowrates expected during the inspection run, and whether active bypassing is required. Figure 8 Example velocity profile with excursion

6.4 Physical Properties of the Pipeline Physical properties of the pipeline that need to be considered include its length, wall thickness, minimum bend radius, diameter changes, and the presence of other appurtenances such as wyes and tees.

Length is important as it dictates power requirements for the in-line inspection tool, and may require special material considerations. Wear of the driving and sealing cups is also a key consideration for long pipelines, as a loss in the sealing capacity could result in the pig losing drive and becoming stuck. Another common problem is wear to sensors as they drag along the pipe wall, resulting in loss of data. With improvements in sensor, battery and drive cup material technology, inspection of long pipelines is becoming less of a challenge. Pipelines >1000km in length have been successfully inspected in a single run.

Wall thickness is also a critical consideration. Each inspection tool and technology has limits on the wall thickness that it can inspect (see Sections 2.2 to 2.6). Higher pressure pipelines being installed with ever thicker walls pose a severe challenge to in-line inspection, as the threshold of detectability for thick walls approaches the defect tolerances of the lines, reducing the predictive value of inspections. Feature detection and reporting thresholds for an inspection tool are usually quoted in relation to the pipe wall thickness and must be checked against the defect tolerance of the pipeline to ensure that the tool is sufficiently sensitive to obtain useful predictive data.

The tightest bend radius in a system can determine whether a given tool can traverse the pipeline. Historically, the limits for intelligent pigging were 5D bends, but many modern tools are able to traverse 3D bends as a standard, and some have capability to navigate tighter bends down to 1.5D radius. The distance between bends can also restrict the passage of tools and the inspection vendor will typically request piping isometrics to confirm this.

Pipelines with internal diameter changes are becoming more common, particular, in subsea developments and long lines. If using a free-swimming tool, bespoke multi-diameter solutions are available using flexible driving cups that are able to expand and contract with diameter changes. This does affect the passage of the tool and there are practical limits to the diameter differentials that can be accommodated. Currently this is a maximum of 4 to 6 change in diameter.

Appurtenances present along the pipeline must also be taken into consideration. Tees and wyes in particular, can result in a stuck pig scenario if they have not been designed to accommodate pigging activities. Valves within the system can also present a threat if not fully open, as a tool can get stuck.

6.5 Pigging Facilities Physical considerations shall include available pigging facilities and physical properties of the pipeline. Facilities that are required include pig launchers and receivers that have been designed for intelligent pigging, the ability to gain access to the pipeline, sufficient space around the access point for launching and receiving activities; as well as facilities to handle debris and hydrocarbons from pigging operations.


Pig launchers and receivers are a proprietary design that is dependent on the requirements for pigging activities during the installation, pre-commissioning, commissioning and operations phases of a pipeline. Some are designed as permanent installation and others are temporary, stored in a warehouse and installed only when pigging activity is required.

These items are classed as pressure vessels, as full pressure is contained within launchers and receivers during launching and receiving activities. The design of the closure mechanism therefore is critical, as well as the ability to bleed down pressure, and handle any debris and hydrocarbons that may be pushed into the vessel during pigging operations.

In-line inspection tools can be long and heavy, so design of launching and receiving facilities needs to consider space and handling requirements during launching and receiving activities.

As pig traps are only periodically used, it is also critical that the trap is thoroughly inspected, with emphasis on the sealing surfaces and door hinges and quick closure devices, before being used.

7. PRACTICAL CONSIDERATIONS An in-line inspection program is usually triggered by the inspection plan for the pipeline, by corrosion monitoring data (e.g. probes, sampling, etc.) that indicates active corrosion in the pipeline or other associated event that have caused concern about the integrity of the wall (e.g. excessive exposure to untreated seawater during installation). This section details the practical aspects of planning and executing and in-line inspection program.

7.1 Planning the Inspection The first decision to make is which technology to use. This is determined by the type and size of corrosion features that are expected for the pipeline, as well as the product in the pipe (i.e. gas, wet gas, liquid) and physical conditions. The next step is to do a general assessment of whether the pipeline can be pigged. This involves reviewing the design of the pipeline, including major components to determine for example, whether there are adequate launching and receiving facilities, the condition of the valves, the product flow rate, pressure, temperature, and so forth. The selection between a free-swimming, tethered or crawler tool will be driven by the pipeline configuration; lines with free traversal and pig taps on each end favour free swimming. Short, obstructed or dead end pipelines will favour tethered or crawler tools.

At this stage, selecting and engaging an in-line inspection vendor is beneficial. The vendor may be determined by the tool requirements, if only one can supply the correct service. Otherwise, the Pigging Products and Services Association (PPSA) [5] maintain a global directory of vendors that provide pigging services. There is an on-line guide to vendors that specialise in providing in-line inspection services, categorised by the type of features to be inspected.

Once engaged, a good in-line inspection vendor will firstly request the operator to complete a Pipeline Questionnaire. This document is used to gather information on the pipeline that will be relevant to designing an in-line inspection program and select or build a tool that is optimal for the inspection program. An example questionnaire is available from the Pipeline Operators Forum [3]. This information gathering step is highly critical to the success of the program. As discussed earlier, the more information that is available on the pipeline; the less risky the in-line inspection program. In-line inspection is a hazardous operation and lack of planning or knowledge can lead to damage to the asset, a loss of production and/or loss of the in-line inspection tool.

During the planning process, API 1163 [6] can be used as a guideline. This document covers the use of in-line inspection systems for onshore and offshore gas and hazardous liquid pipelines. It includes tethered or free swimming systems for detecting metal loss, cracks, mechanical damage, pipeline geometrics, and pipeline location or mapping. This document is an umbrella document that provides performance-based requirements for in-line inspection systems, including procedures, personnel, equipment, and associated software.

Once the appropriate studies have been performed, the inspection vendor will provide a proposal based on the inspection specification that is required. If a bespoke build is required, the lead time for an inspection tool can be significant. Inspection plans and procedures will need to be developed with the on-site operations team, and these are best developed in close cooperation with the inspection vendor.

7.2 Risks of Stuck Pig One of the biggest risks in relation to performing an in-line inspection program is getting a pig stuck in the pipeline during the inspection program. The consequences include deferred production for the operator, and potential loss of a high-value inspection tool for the vendor. A number of practical measures can be taken to mitigate this risk.

The main prevention is to collect as much information as possible, on the construction and condition of the pipeline so that the tool itself, and the procedures for the survey minimise the risk of sticking. Cleaning of the pipeline may be required prior to an in-line inspection run to remove solids which may build up in front of the pig and prevent progress, and a


gauging or caliper pig run may be required to prove the internal diameter of the line is sufficient to pass the tool. The vendor will advise on any additional inspection or preparation requirements during the planning phase.

The second prevention is controlling the flow and speed of the pig to ensure that it progresses smoothly, and does not come to a stop; as it is much more difficult to start a pig moving than keep it to moving.

Monitoring the position of the pig is important to detect whether or where a pig has become stuck. Pig signallers can be mounted on pig launchers and receivers to indicate when the tool has left the launcher, and has arrived at the receiver. Some pipelines are specified with acoustic pig detectors, usually on manifolds or mid line tees, which detects the sound as a pig passing and checks that a pig passed that location.

Pipeline markers can also be used. These markers are mounted at known distances along the pipeline and the in-line inspection tool can be programmed to send a signal as it passes each marker. The distance between markers is agreed during the planning phase. Markers add to the cost and duration of the inspection program as they need to be positioned, monitored and subsequently removed. The use of subsea pipeline markers mean that a support vessel and remotely operated vehicle (ROV) is required during in-line inspection runs.

Figure 9 Pig signalling device (mounted)

Pig tracking devices are often specified on the tool itself so that the location and progress of the inspection tool can be monitored during the inspection run. A number of devices are readily available and are based on acoustic methods (pingers) or radioactive isotopes (tracers). If the pig becomes stuck, its location can be determined using these indicators.

In the event that a pig does become stuck, the first action is to locate the its position in the pipeline. In most cases, the tool can usually be un-stuck by increasing the differential pressure across the tool or by rocking the pig by decreasing the pressure in the pipeline to allow the pig to relax, then increasing the pressure again.

If the above procedures fail, more drastic intervention maybe required and in a worst-case scenario, the tool will need to be cut out of the pipeline.

Figure 10 Remote pig tracking system (Source: Tracerco Diagnostics)

7.3 Preparing the Pipeline for Inspection In order to minimise the risk of getting an in-line inspection tool stuck in the pipeline, the pipeline owner is usually required to execute a series of cleaning and gauging runs to prepare the pipeline.

The design of a cleaning pig will largely depend on what debris is expected in a pipeline (e.g. if there is sand, wax, etc.). Where severe build-up of solids is suspected, multiple cleaning pig runs may be required, using increasingly aggressive pigs will be required with the first few pigs specified to be tolerant of solids so that they do not get stuck. Where sufficient cleaning cannot be achieved, specific fluidisation tools can be used. These are a variant of the active bypass tools, but instead of speed control, the bypass is used to sweep and fluidise solids in front of the tool, to prevent them building into a solid dune which can stop the pig.

Gauge pigs are used to confirm clear passage of the pig through the pipeline. Utility pigs are fitted with an aluminium disc, usually at 95% of the internal diameter of the pipe wall however, this may vary depending on the requirement of the in-line inspection tool. This gauge plate must be relatively undamaged upon receipt to confirm that the in-line inspection tool can be run in the pipeline.

Depending on the in-line inspection vendor, known history of the pipeline and level of perceived risk, it is possible that the in-line inspection vendor may request to be on-site during these preparation runs; so that they can verify the outcomes of the cleaning and gauging runs. Cleaning and gauging runs should be executed immediately before the in-line inspection run and a full record (e.g. run conditions, run times, wear of the pig, debris in the receiver, etc.) should be maintained.

7.4 Performing the In-Line Inspection Once planning and preparation work is completed, performing the in-line inspection itself should be relatively straight-forward. As per any work performed on site, a job hazard analysis is required on the procedure as well as a pre-start meeting. There are a number of additional considerations for performing an in-line inspection program.

The first is to consider how the in-line inspection tool will be transported and handled into the launcher. In-line inspection tools can be several metres in length, and weigh several tonnes. MFL tools also have large magnet units. Retrieving the tool from the receiver has the same requirements plus handling and disposal of process fluids and debris, some of which may be hazardous or flammable.


Project planning should consider the time taken to for launching, running and receiving the tool. Some in-line inspection tools can be fitted with pressure-activated power units, which allow the tool to remain in a suspended condition in the launcher, until such time that it is convenient to launch the tool. When the launcher is pressurised to launch, the tool powers itself up. Without one of these, the battery life of the tool must take into account the preparation time between being loaded into the launcher, and actually launching.

If the pipeline has not been subjected to a rigorous cleaning program, it is possible that debris handling will need to be considered. The tool itself will be covered in hydrocarbons on receipt, so a procedure to transport and clean the tool to acceptable environmental standards is required.

Once the tool is retrieved and cleaned, the inspectors require a clean workspace (e.g. a dedicated area in a workshop) where data download will occur. This initial download of data is purely to verify if inspection has recorded the minimum required volume of data. Whether the inspection has been successful can usually be confirmed within a day. If there has been insufficient data collected, multiple runs maybe required and this should always be included in the plans as a contingency.

On completion and demobilisation of the in-line inspection tool, most vendors deliver the final report within 1 to 2 months, depending on the level of complexity that is required for data processing.

7.5 Verification Activities Verification is an additional step that should be performed, if this is within practical limits of time and budget. The objective of verification is to confirm the detection threshold and accuracy of in-line inspection tool. The sizing accuracy of an in-line inspection tool can vary significantly and often, features can either be undersized or oversized. As engineering assessments will be based on the sized features, verification improves confidence levels in the assessment.

The vendor, prior to the in-line inspection, performs calibration of the tool by running it through a test pipe that contains machined sample defects. Verification however, is and additional step to be performed by the operator to compare the in-line inspection results with known accessible features on the inspected pipeline.

On onshore pipelines, verification is performed by accessing the location of selected or critical features from the pig record and using conventional external non-destructive testing (NDT) methods to verify the location size and geometry of the reported feature. Verification should be performed on a sufficient number of features, to increase confidence levels in the pig results. Verification is less practical for subsea pipelines, but accessible features (e.g. on the riser or where the pipeline comes onshore) can be used. Severe defects on subsea pipelines can be verified by external inspection, for example by ROV deployed UT, or subsea radiography to confirm the defect before expensive remedial action is taken.

8. ENGINEERING ASSESSMENT OF FEATURES

8.1 General The in-line inspection report provided by the vendor should summarise all aspects of the inspection campaign, including pre-inspection runs, tool specification, how the tool performed, inspection conditions and so forth. The main component of the report will be the pipe tally or list of features that have been detected. The POF Standard [2] provides a guide for feature reporting, which is used by the majority of in-line inspection vendors.

8.2 Assessment Codes The next step required will be to perform an engineering assessment of the reported features. There are a number of fitness for service assessment codes that are available, depending on the defect assessment that is required, the regulatory requirements of the pipeline, and the original pipeline design code. For subsea pipelines, DNV RP F101 [7], ASME B31G [8] and the Pipeline Defect Assessment Manual (PDAM) [9] are used for assessment of metal loss features. Onshore pipelines can use ASME B31G [8], the PDAM [9] and API 579 [10]. In the majority of cases, ASME B31G [8] is used. Dents, cracks and gouges can be addressed by API 579 [10] or through engineering criticality assessment (ECA) with guidance from BS7910 [11].

8.3 Assessment of Metal Loss Features The most common assessment performed is on metal loss features, to determine pressure retaining capability and corrosion rates in the pipeline. The objective is to predict remaining life and plan intervention work, as it is required, to maintain the required integrity for the pipeline.

As metal loss occurs, the pressure retaining capability of the pipeline decreases. The engineering assessment involves determining the safe working pressure of the pipeline, given the presence of the individual and clustered features.


The rate of corrosion since the last inspection can be determined by extrapolation between surveys, and applied to the features to predict the time until the feature will grow to become unacceptable. If a previous inspection has not been performed, the corrosion rate can be averaged from the time that the pipeline was commissioned, though this is an extremely rough estimate and a large factor of uncertainty should be applied. Corrosion modelling techniques, or corrosion monitoring data from the line can also be used to predict anomaly growth.

This corrosion growth modelling is used to predict when the feature (or cluster of features) is likely to lose its pressure retaining capability and therefore, when remediation may be required. This information can also be used to schedule the next inspection using Risk Based Inspection techniques.

Figure 14 Example Defect Assessment Curve

Other inspection, maintenance or monitoring data should be considered in the assessment process; especially if a specific event may have triggered an excessive corrosion rate. If a feature (or cluster of features) fails the assessment (i.e. the safe working pressure is less than the maximum allowable operating pressure), the mitigation options include de-rating the pipeline (i.e. lower the maximum allowable operating pressure), or repair of the defect. Engineering assessment is performed based on the length, width and depth of the features. As discussed throughout this paper, a significant number of variables could affect the sizing accuracy of the features. Confidence on feature size and location can be improved through verification activities, but any assessment of a features fitness for purpose must include adequate consideration of the accuracy of the source tool.

9. CURRENT TECHNOLOGY LIMITATIONS

9.1 General In-line inspections are the main basis of the integrity management programme for most oil and gas pipelines, as inspections provide the most complete data set on pipeline wall thickness. Some pipeline licenses require design for in-line inspections and the regulator may require scheduled inspections. As with any technology, continuous improvements and developments are on going to address more challenging pipelines, achieve better feature detection; provide more robust or mobile inspection tools. The in-line inspection industry is a dynamic, with a high rate of new technology development. Some of the current limitations are discussed below; however it is likely that these will be reduce or be overcome in the near future.

9.2 Heavy Wall Thickness Each technology has limitations on the wall thickness that can be inspected with regards to the defects that can be detected or sized. This mostly relates to inspection techniques such as MFL and PEC due to the proximity limitations in the generation of the magnetic flux or eddy current within the adjacent pipe wall. The boundaries of what is considered heavy wall however, continues to increase with the emergence of new technologies driven by the requirement to inspect heavy wall pipe for deepwater pipelines. The thicknesses that can be practically inspected are expected to keep rising.

9.3 Pressure and Temperature Every inspection tool has limits on its operating pressure and temperature, dictated by the tolerance of the electronic components in the tool, and the ability of seals to exclude the process fluids. With increasing numbers of high pressure and high temperature pipelines in the world, it is likely that as with heavy wall, the tools will continue to evolve to cope with ever-higher pressures and temperatures.

9.4 Corrosion Resistant Alloy Pipeline designs using carbon steel internally clad or lined with corrosion resistant alloys are becoming increasingly prevalent. The most common cladding or lining materials are AISI 316L and Alloy 625. The lining is specified to protect the carbon steel from highly corrosive environments in the pipe. The CRA however, is still susceptible to pitting corrosion under some conditions, and breaches of the lining may occur. This is giving rise to the requirement to inspect the CRA layer for evidence of pitting; or to inspect behind the CRA layer for evidence of corrosion of the substrate carbon steel. At the present time, no in-line inspection tools have been qualified for inspecting CRA cladding or linings, but development is underway to fill this expected need, and new technologies are expected in the near future.


10. CONCLUSIONS When specified and executed correctly, an in-line inspection of a pipeline is currently the most comprehensive inspection method to detect and size corrosion in pipelines. In-line inspections are complex programs to execute as there are many variables to be taken into consideration. A successful program will return invaluable data on the condition of the pipeline that cannot be replicated by any other inspection technology that is currently available in the industry.

In-line inspection programs are a hazardous operation with many operational risks. The health, safety and environmental risks must be considered at every step of the inspection program; and all efforts must be taken to mitigate the risk of having a pig stuck in the pipeline.

The final step in any program is not the delivery of the report, but the engineering assessment of reported features. This is to determine whether metal loss features in the pipeline will affect its integrity, at the present time or in the future. Being able to predict potential failure is a positive and proactive integrity management approach.

11. ACKNOWLEDGMENTS The authors acknowledge Chris Saunders (Engineering Manager) and Enda OSullivan (Asia-Pacific Manager) for their continuous support to ensure technical knowledge is shared within the industry, for the benefit of all.

12. REFERENCES 1. Norli Petter, Haland Erling, Olsen Age A.F. and Waag, Grunde (2011) Using half-wave resonances to measuring

thickness and lack of mechanical contact in lined pipes (In) Proceedings of the 24th International Congress on Condition Monitoring and Diagnostics Engineering Management, 30 May 01 June 2011, Stavanger, Norway.

2. Pipeline Operators Forum (2009) Specifications and requirements for intelligent pig inspection of pipelines. 3. Pipeline Operators Forum (2012) Guidance document to achieve in-line inspection first run success. 4. Pipeline Operators Forum (2012) Guidance on field verification procedures for in-line inspection. 5. Pigging Products & Services Association, http://www.ppsa-online.com/

6. API 1163 (2005) In-line Inspection Systems Qualification Standard. 7. DNV RP F101 (2010) Recommended Practice for Corroded Pipelines. 8. ASME B31G (2012) Manual for Determining the Remaining Strength of Corroded Pipelines. 9. Pipeline Defect Assessment Manual (PDAM) Joint Industry Project. 10. API 579 (2000) Recommended Practice for Fitness for Service. 11. BS7910 (2005) Guide to Methods for Assessing the Acceptability of Flaws in Metallic Structures.

13. AUTHOR DETAILS

Allison Low is Pipeline Integrity Team Leader at Wood Group Integrity Management, a position she has held since 2009. She and her team focus on the planning and execution of pipeline integrity management plans, IMMR programs, fitness for service assessments and failure assessments for operators within the APAC region. She also supports a number of pipeline integrity technology initiatives.

Chris Selman is a Principal Materials and Corrosion Engineer at Wood Group Integrity Management, a position he has held since 2006. He consults on all the major North West Shelf developments with regards to materials selection, corrosion assessments and the development of corrosion management plans. He specialises in corrosion modelling and monitoring techniques.

Date post:	16-Dec-2015
Category:	Documents
Upload:	camilo-godoy-v
View:	7 times
Download:	1 times

IN-LINE INSPECTION PROGRAMS FOR

Documents