In this paper a flexible, innovative solution was applied in order to perform the first-ever inline inspection of a small, multi-diameter buried pipeline located within a refinery setting. The product pipeline could not be inspected due to a combination of various challenges, including its unique geometry, no launcher or receiver, conditions of low flow and pressure, and unpiggable components such as unbarred tees, and small bend radius. This paper describes how the most economical, practical and clever solution could open doors for the inspection of a previously considered unpiggable hazardous liquid pipeline.

This paper outlines the specific challenges that typically prevent the successful, economical, and complete inline inspection of pipe segments, and more important, it highlights the key success factors: the refusal to accept that a pipeline is unpiggable and the development of a specific multi-diameter tool to perform a comprehensive inline inspection. These two key success factors made possible the design of a tool that could negotiate many of the complex pipeline fittings and navigate under extremely low-pressure and flow-conditions.


TransCanada owns and operates more than 55,000 miles of natural gas pipelines in North America, and since 2014 they’ve been aggressively pursuing the assessment of the unpigged portion of their system. In order to expand the inline inspection coverage in the system, TransCanada identified the need to develop a bi-directional caliper tool. This development allowed TransCanada to attain more MFL and caliper data while reducing the overall cost of its multi-year baseline assessment program. This paper will discuss the technical features of the bi-directional caliper tool and an overview of the model used by TransCanada to drive the development of the bi-directional caliper technology and to demonstrate the advantages of utilizing unconventional ILI technology in order to obtain MFL and caliper data.


The Pacific Gas and Electric Company (PG&E) has initiated a program to verify maximum allowable operating pressure (MAOP) of facility pipe without traceable, verifiable, and complete (TVC) records of an initial life strength test. The scope of this effort encompasses the over 400 gas transmission stations, with an average age of approximately 35 years old, spread throughout PG&E’s service territory. Comparing station piping to transmission pipe, challenges to MAOP verification include the difficulty in applying conventional inline inspection tools. Additionally, traditional hydrostatic pressure testing can negatively impact the long-term integrity of facilities. Pipeline and Hazardous Materials Administration’s (PHMSA) 2016 Notice for Proposed Rulemaking (NPRM) § 192.624 equates pressure testing and engineering critical assessment (ECA) with inline inspection for MAOP verification. Within this framework PG&E’s approach to MAOP verification for station pipe utilizes state-of-the-art nondestructive examination (NDE) technologies for flaw detection and materials verification combined with probabilistic fracture mechanics ECA. Multiple prior publications and presentations by PG&E have described different facets of our program including NDE for material verification and the probabilistic fracture mechanics computations. This paper and presentation focus on the NDE technologies used to detect, characterize, and size manufacturing and construction defects in the pipe body, long seams, and girth welds.

In 2018, PG&E began the field pilot phase of this program at regulation and metering gas transmission stations. In this paper we will discuss outcomes of the pilot phase. This will include discussion of the challenges faced and protocols developed to rigorously establish field data quality assurance. The goal of which was to minimize uncertainties in data collected and more rapidly highlight lower quality data. Additional discussion will illustrate prescriptive protocols which provide a systematic process for tool selection and minimum resolution requirements. Finally, we will highlight lessons learned in field flaw detection NDE sequencing.


Pipeline operators apply inspection methods and technologies for the purposes of assessing, or providing confidence in, the operational integrity of pipeline systems. Inline inspection (ILI), hydrostatic testing, and direct assessment (DA) methods are well-established and heavily relied upon by the industry; however additional technologies and methods continue to be developed and advanced. The ASME, API and PHMSA integrity management codes, standards and regulations recognize the potential for “other technologies” to emerge to address physical challenges to inspection or provide improved capability to assess selected threats. All current US regulatory guidance requires operators demonstrate “equivalent understanding” of line pipe condition when using the other methods (as compared to established inspection methods). Current regulatory guidance does not, however, specify any process or criteria for justification of equivalent understanding. As additional assessment technologies continue to develop and advance, guidance to the industry is needed to ensure an appropriate and consistent approach for use of both emerging technologies and those not explicitly covered by prescriptive codes.

This work was accomplished through PRCI in collaboration with members to learn the steps each use in application of “other” technologies. The result is a structured process for use by pipeline operators and service companies as a technology independent framework in the planning and execution of pipeline integrity assessments. This guidance presents requirements intended to be applicable for any inspection technology such as qualification, development of a performance specification, and validation. It should be noted that these elements are required in application of any inspection method; in this regard, any established inspection method could be applied using these principles. This guideline was thus created with many aspects and references to established standards and procedures such as API 1163 Inline Inspection Systems Qualification and the family of NACE Standard Practices for Direct Assessment and ILI.


Material strength and mechanical fracture toughness are critical parameters for fitness-for-service evaluations, especially evaluations focused on cracks, dents, and long-seam anomalies. For vintage pipeline assets, strength and toughness can vary depending on the year of installation due to changes in manufacturing techniques and improvements in seam welding methods. Since laboratory testing requirements during fabrication were not a common practice prior to the 1980s, many of these pipelines lack material records.

To gain this valuable data now, traditional assessment requires the removal of a standardized specimen for destructive laboratory testing. This process can be both expensive and detrimental to the tested asset. A nondestructive method for evaluating strength and toughness is an efficient solution for applications where sample cutouts are not feasible.

This work describes new developments in contact mechanics testing that use frictional sliding with a hard stylus to locally deform the surface of a softer substrate to evaluate both the material strength and the fracture toughness of pipelines. The Nondestructive Toughness Tester (NDTT) provides an NDE solution for measuring fracture toughness by using a wedge-shaped stylus with an internal stretch passage to generate a Mode I tensile loading condition on the surface of a sample, resulting in a ductile fracture response on a ligament of material. The geometry of the fractured ligament indicates the materials’ ability to stretch in tension near a propagating crack and is strongly correlated to the crack tip opening displacement (CTOD) measured from traditional laboratory toughness testing.

The Hardness, Strength, and Ductility (HSD) Tester is a portable device that provides an accurate tensile stress-strain curve for assessment of the yield and ultimate tensile strength. The HSD incorporates four styluses of different geometries, each applied at a specified load, to generate shallow grooves on the surface of a material during a test. The resulting geometry of these grooves, in addition to set stylus geometries and applied forces, have been correlated to representative stress-strain values through finite element analysis (FEA) simulations. The HSD has been incorporated into over 200 dig sites, providing enough data to look at statistical distributions which can benefit operators and provide added value to material records.

Frictional sliding tests are also used to detect material variation during a test, giving the HSD the ability to identify differences in welding processes and the effectiveness of post weld heat treatments (PWHT) as it travels across a seam. Implementation of these new instruments and methods of material verification to gather data for integrity management programs, fitness for service assessments and quality control of new manufacturing will help to reduce risk and uncertainty in structural applications.


In early August 2018, Intero Integrity began field work on an exceptionally difficult-to-inspect jet fuel pipeline in California. The inspection scope included Intero’s full turn-key service for cleaning, tracking, XYZ collection, fuel filtration/preservation and combined caliper and corrosion inspection. As expected, this project also included the provision of several frac tanks and a vacuum truck. The operation had several obstacles to overcome to be successful. There were 1D bends in the line and several, full-bore unbarred tees. The line was also divided into 3 separate legs: the current active pipeline section, an out-of-service section, and a lateral line that would require inspection from a single entry/exit point. All three pipeline sections required inspection to be recommissioned for service.

This paper will outline the challenges, technology and successes realized on this difficult-to-inspect pipeline.


Ingu Solutions’ Pipers® technology provides oil and gas companies with immediate and affordable access to pipeline assets even in the most challenging conditions. This revolutionary technology uses miniaturized inline sensors to detect leaks, geometric defects and deposits that threaten pipeline performance and safety with zero-downtime. Pipers® eliminate complex deployments, reduce inspection costs, and strengthen preventive maintenance.

The small free-floating nature of the Pipers® allows for deployment during regular operations in any liquid pipeline and they are able to navigate complex line geometries such as sharp bends, diameter changes and risers, even at low flow rates. The ease of deployment allows for frequent inspection ensuring early detection of changes in pipeline conditions such as deposit formation or metal loss and facilitates the timely detection and localization of leaks or similar hazardous conditions.

The paper will demonstrate the outcome of multiple demonstration projects conducted during 2018. The demonstrated advantages of using a free-floating integrated device include the direct measurement of pressure and elevation in a line, positional reconstruction, localization of pipeline defects and anomalies (including deposits), and the identification of inner diameter changes. Data collected from the Pipers® allows operators to understand the condition of their pipeline and to optimize their operational and maintenance efforts to ensure safe and reliable operation of their pipelines.


Naturally occurring pipeline scales such as wax, asphaltenes and mineral scales have plagued the pipeline industry for over 150 years. Recent developments in advanced analytics have improved flow assurance programs to help prevent pipeline scale accumulation. However, even with the best mechanical pigging programs, pipeline deposition will eventually form that can make the use of conventional pigging too high-risk.

Viscoelastic surveillance gel pigs (VSGP) were developed for both water and hydrocarbon base applications. This chemistry is infinitely shear thinning, which allows it to pass through openings that are less than 1/4 inch in diameter and then regain full rheological properties. The shear thinning and rheological recovery of VSGPs creates a pressure response that is recorded with an off-the-shelf crystal gauge. When the VSGP contacts a restriction, a resultant pressure spike is recorded. The magnitude of the pressure spike and slope of the pressure drop enables the location of the most severe restrictions. Once located, custom chemicals can be placed right on the restrictions for more cost-effective removal. Additional VSGPs can be pumped to confirm deposit removal, as well as, identify additional restrictions for remediation.

Case histories are provided that show successful remediation of wax and asphaltene blockage, a combination wax and hydrate obstruction and iron carbonate scale dissolution.


It can be an advantage to use ILI tools that can run with a low differential pressure when inspecting difficult pipelines. A substantial proportion of the lines that have yet to be inspected for the first time, such as loading lines from ships, have been designed to operate at low pressures. When the configuration does not allow or makes it very expensive to conduct a traditional inspection, a bi-directional (BiDi) inspection can be a good alternative if the inspection does not exceed the MAOP for the line.

For the BiDi inspection of a pipeline riser coming from a subsea gas well, low differential pressure (DP) across an ILI tool can assist in enabling a BiDi inspection with the help of a gas spring. An ILI tool with a high DP would require a high-pressure gas spring and has a reduced working envelope for the safe execution of the inspection. This setup allows for the inspection of part of a dead-leg pipeline without resorting to either a crawler or a tethered inspection with an umbilical cable.

A substantial number of the difficult-to-inspect pipelines are hard to clean. Often, it is a challenge to find cleaning pigs that can navigate the line as easily as some ILI tools can. Running a gauge pig through these lines is an even bigger, often impossible, challenge as they are more likely to hang up in the pipelines than some modern ILI tools. Utilizing an ILI tool that can be easily reversed out and does not jam itself to the point that it needs to be cut out is advised. The use of a traditional ILI tool would increase the risk of undertaking the inspection beyond the risk level acceptable for most pipeline owners. A bi-directional ILI tool with a low differential pressure and without a hard seal minimizes the risk of the tool getting stalled.

Several examples will be shown during the presentation of ILI inspections that took advantage of the low differential pressure and/or low seal ILI tools.

The paper will focus on case histories of several 3-inch and 4-inch MFL inspection of lines that were previously unpiggable. It will discuss some of the challenges and lessons learned from these inspections.


National Grid and its partner organizations have been engaged in an exciting project that is addressing the challenge of how to inspect the complex, below-ground pipework existing at high-pressure installations. The robotic platform negotiates its way through complex pipework geometries and varying gas-flows whilst withstanding extreme pressures of up to 100 Bar(g).

The robotic platform provides real-time data on the condition of high-pressure underground assets not previously inline inspected, allowing National Grid to more effectively manage the asset life.

National Grid is working with three organizations to develop methods to accurately assess the condition of its pipework assets that cannot currently be inspected via traditional pipeline inspection gauges (PIGs). The complexity of pipework at high-pressure installations, combined with the extreme conditions within the gas network, presents a significant challenge for any robotic solution.

Project GRAID commenced in January 2015 and was completed in November 2018. All stages of the project have been completed successfully, and this presentation gives a brief overview into the project including live trials and the challenges faced to get it accepted into business as usual.


The primary reasons pipelines are classified as unpiggable are accessibility, negotiability and drivability. You need all three elements to ensure free swimming pigging operations. Rerouting a pipeline to enable negotiability can also affect the pig dynamics through the modified section. Gas simulation software combined with extensive industry knowledge in inspection tool behaviour enables operators to make informed decisions prior to pipeline modifications, ensuring they’re suitable for inline inspection thus safeguarding the pipelines future integrity.

This case study will demonstrate where gas simulation tools and ILI expertise can support operators with the execution of pigging operations.


Quickly and effectively diagnosing flaws within a pipeline is vital to ensure integrity, regulatory compliance and continuous uninterrupted production performance. With improved inspection technologies for “unpiggable” pipelines and new innovations coming into the market every day, operators now have the ability to accurately locate defects and visualize integrity data all in real time. This allows critical decisions to be made quickly and with confidence.

Following up to the UPSF 2015 paper introducing the new DiscoveryTM tool, this paper reports on continued project experience and enhancements to its reliability, as well as development of a new “fast-screening” application that allows the system to screen any type of pipeline to quickly identify metal loss defects for further inspection via Discovery.

With this enhanced technology, operators now have a field-proven CT tool with which they can now quickly and accurately screen unpiggable subsea pipelines to determine whether they are within the acceptable tolerance specification. With non-intrusive inspection through any type of protective pipeline coating, defects can be fully characterized faster than ever, without interrupting production.

Once a potential anomaly has been identified via the fast screening method, a more detailed and accurate scan to fully characterize it can be undertaken, simply by extending the duration of the fast scan. This eliminates the requirement of a separate scan and the need to deploy a secondary technology to validate the findings from the initial fast screening inspection.

This presentation will outline the development of the tool and discuss recent case studies on the deployment of the fast scanning application. Also discussed will be how the tool has enabled customers to detect and locate metal loss defects on difficult to inspect pipelines up to five times faster than before, as well as reduce the average cost to inspect 3 feet of pipeline by over 80%.


Managing the long-term integrity of a critical 10-inch subsea crude oil pipeline is dependent on being able to use the correct inspection technologies; however, the current structure of the pipeline does not allow for any inline inspections. Consequently, managing the short-term integrity of the pipeline becomes a priority until the pipeline is made piggable. This paper describes where and how to investigate along the pipeline to determine the current internal condition.

A desktop feasibility study was completed in order to determine the locations and the confidence in the use of an external ultrasonic scanning survey (auto-UT) to determine the short-term integrity of the pipeline. This comprised the following:

In addition, a review of the current sacrificial anode protection of the pipeline was completed to ensure that any investigative works completed would not result in any external corrosion issues.



Inline inspection of offshore pipelines using conventional tools and procedures is not always possible due to a combination of various challenges. This paper discusses a recent example of such a case: the inline inspection of an 8-inch fuel gas line feeding a platform located in the North Sea.
The pipeline was found to have a leaking subsea isolation valve (SSIV). The SSIV is about 755-ft. (230-meters) away from the platform and riser. In addition, the topside emergency shut down valve (ESDV) had failed in the open position. Due to a combination of the ESDV being in an open position and the SSIV slowly leaking, it was determined that the riser could not safely import the gas to power the platform. The SSIV was closed, but since it was slowly leaking, the riser was regularly bled to ambient pressure with the gas being sent to the flare.

In order to provide critical safety isolation of the fuel gas pipeline, the ESDV needed to be replaced. The integrity of the riser then needed to be confirmed by performing an inline inspection. However, for the inspection to successfully take place, several challenges had to be overcome, including:

The ROSEN team, together with the operator, settled on a free-swimming, bi-directional, UT inspection solution. In order to provide a couplant for the UT, a liquid batch was proposed to be used. To overcome the fact that there was no flow possible, the team agreed to use external pumps to propel the bi-directional UT tool in a liquid batch into the riser, while, at the same time, compressing nitrogen against the SSIV. Once the tool had reached the desired location, the compressed nitrogen was used to push the pig train back to the launcher.

This paper will discuss why this solution was selected and how the collaboration between ROSEN and the operator successfully tackled the challenges to develop and apply the free-swimming UT-based solution and safely inspect the pipeline.


KMAX Inspection has been focused on small-diameter (3-inch to 6-inch) MFL/deformation combo tools to inspect small-diameter pipelines that have previously been unpiggable. Advances in electronics and magnetic modeling have allowed construction of these small-diameter tools. 87% of KMAX's inspections to date have been in lines that have not been inspected before.


Inline inspections are commonly used to ensure safe operation of oil and gas pipelines. These inspections provide reliable information on the status of the pipeline’s integrity. Traditionally, gas pipelines are inspected using magnetic flux leakage (MFL) technology, and liquid pipelines are inspected using either MFL or ultrasonic wall measurement (UTWM) technology.

Recently, an additional technology has been introduced to the market based on acoustic resonance technology (ART). ART allows for the inspection of both liquid and gas pipelines with acoustic testing. The ART technology overcomes typical limitations of prior methods, such as limited wall thickness capability and speed (for MFL), and cleanliness criteria (for UTWM).

The authors will present the theoretical background of acoustic resonance technology and practical applications at a product level. Furthermore, a case study will be presented where the technology was applied in the field.




Inline inspection (ILI) is a pipeline assessment method used by operators to receive a comprehensive integrity assessment of their pipeline. Unfortunately, ILI may become unfeasible due to factors such as insufficient flow/pressure parameters for propulsion, pipeline features such as valves, back-to-back elbows and unbarred tees, as well as the lack of infrastructure such as launcher & receiver for tool entry and exit. These pipelines are deemed as difficult to inspect, or “unpiggable,” and are often limited to other integrity assessment methods such as direct assessment, or hydrostatic testing.

Pipetel Technologies has been providing ILI solutions for unpiggable pipelines since 2011. The Explorer ILI robot fleet, powered by rechargeable batteries, can travel up to 2,000-ft before returning to the size-on-size hot tap fitting. The inspection configuration may include an out-and-back run, as described above, or a point-to-point run with the use of an exit hot tap fitting. The inspection distance may be extended by cascading inline charge (ILC) stations until the desired inspection length is obtained. A charge station requires 2-inch hot tap fittings which mate with Pipetel’s inline charge system. Explorer is charged inline and subsequently may continue the inspection up to another 2,500-ft (point-to-point) to the next ILC station or receiver hot tap fitting.  

One of the longest consecutive inspections performed by Pipetel to date is 2.3 miles. The two-day inspection utilized two hot tap fittings for Explorer entry and exit, as well as three charge points. The comprehensive MFL, dent and video data provided the operator with the integrity information required for continual undisrupted operation. This paper reviews the process, execution and data from the use of Explorer ILI for long distance inspections that are several miles in length.


Inline inspection (ILI) is the standard assessment method for pipelines that are piggable. However, not all pipelines which require inspection can accommodate standard “smart pigs.” Performing inspections for many pipelines can be challenging, and at times free-swimming ILI is not feasible. Inability to use typical ILI tools can range from lack of facilities to insert and remove inspection equipment, bend configurations and product pressure/flow, among others. One solution for pipelines that can be taken offline with access to one end, is bi-directional inspection. These tools capture data in both directions, which means redundant information for comparison and assurance of complete inspection.

A second option for pipelines that are not able to be inspected with a typical free-swimming ILI tool is pull through using properly configured ILI tools. When operators have access to both ends of the pipeline, and other conditions can be met, pull-through geometry and metal loss tools are another option for difficult to inspect pipelines.

This paper will discuss some of the significant benefits and capabilities associated with a bi-directional 8-inch MFL tool, along with various sizes of deformation and MFL wire line pull-through capable tools.


To reduce uncertainty and risk of pigging through difficult to pig pipelines, a best practice is to establish pig passage through any unpiggable features and pipeline geometries in a series of controlled above ground experiments.

Controlled flow loop testing, using either pumped liquids or compressed gases as a driving medium, can be used to prove pig passage through replicated pipeline defects or difficult to pig features. In this method, a partial pig or full pig train assembly can be inserted into an accessible above ground closed loop pipeline test system. The pig is driven through the loop using the energized drive fluids (liquids or compressed gases). Flow loop testing may closely simulate the actual pipeline conditions and passage of the pig through the features being tested due to the presence of compressed pipeline fluids around the pig body. Flow loop testing is complex and potentially dangerous due to the presence of energized fluids in an above ground pipeline test system. This type of testing can also be expensive due to the complex pumping/compression equipment required, and handling of the fluids at the surface.

An alternative method for testing pig passage is the use of a winch pulling test apparatus to pull the pig assemblies through the pipeline features being evaluated. In this method, a partial pig or full pig train assembly is inserted into an above ground pipeline test section. The pig assembly is simply pulled through the test section of pipe using the mechanical winch apparatus. The complexity and potential danger of using energized drive fluids can be eliminated as the test section can be operated open to the atmosphere with no elevated differential pressures.
Through past and ongoing product development and research efforts, Fiberbuilt has had the opportunity to test many different seal, brush and pig assembly combinations through both pumped flow-loop tests and dry-pull tests.

This paper outlines the dry-pull and closed-loop testing methods and limitations and compares the drag/passage data of various pig features through different pipeline anomalies. Several different pig features are isolated and evaluated separately: seals, radial cleaning brushes and complex corrosion pit cleaning brushes. Flow loop (differential pressure) and dry pull load test data for several complete pig assemblies are also presented and the results compared.

To illustrate a typical design-test-verify cycle used in the development of unique pigging tools for difficult to pig applications, the flow-loop data proving passage of a new 3-inch to 6-inch multi-diameter cleaning pig is compared to the dry-pull test data through the same test section.

In summary, dry-pull testing pipeline pigs and pig components through difficult to pig features in a controlled environment can be a useful tool for rapidly proving and assessing pig passage. In conjunction with targeted design efforts, these dry-pull tests can be used to iteratively assess and improve pig designs to maximize performance.



Hydrostatic pressure testing is the most widely accepted approach to verify the integrity of assets used for the transportation of natural gas. It is required by Federal Regulations 49 CFR §192 to substantiate the intended maximum allowable operating pressure (MAOP) of new gas transmission pipelines.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) Notice of Proposed Rulemaking (NPRM) with docket No. PHMSA-2011-0023, proposes an additional requirement for MAOP verification of existing pipelines that: i) do not have reliable, traceable, verifiable or complete records of a pressure test; or ii) were grandfathered into present service via 49 CFR §192.619(c). To meet this requirement, the NPRM proposes that an engineering critical assessment (ECA) can be considered as an alternative to pressure testing if the operator establishes and develops an inline inspection (ILI) program.

The ECA must analyze cracks or crack-like defects remaining or that could remain in the pipe and must perform both predicted failure pressure (PFP) and crack growth calculations using established fracture mechanics techniques. For assets that cannot be assessed by ILI, however, the implementation of an ECA is hindered by the lack of defect size information. This work documents a statistical approach to determine the most probable PFP and remaining life for assets that cannot be assessed by ILI.

The first step is to infer a distribution of initial defect size accumulated through multiple ILI and in-ditch programs. The initial defect size distribution is established according to the as-identified seam type, e.g. low-frequency electric resistance weld (LF-ERW), high-frequency electric resistance weld (HF-ERW), flash weld (FW), single submerged arc weld (SSAW), or seamless (SMLS). The second step is to perform fracture mechanics assessment to generate a probabilistic distribution of PFPs for the asset. In conjunction with the defect size distribution, inputs into the calculation also include the variations of mechanical strength and toughness properties informed by the operator’s materials verification program. Corresponding to a target reliability level, a nominal PFP is selected through its statistical distribution. Subsequently applying the appropriate class location factor to the nominal PFP gives the operator a basis to verify their current MAOP. The last step is to perform probabilistic fatigue life calculations to derive the remaining life distribution, which drives reassessment intervals and integrity management decisions for the asset.

This paper will present some case studies as a demonstration of the methodology developed and details of calculation and establishment of database.