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SmartBall®

Free-swimming solution for water, wastewater, and oil and gas pipelines that can complete long inspections in a single deployment.

Accurate leak and gas pocket detection without service interruption.

Make short-term repair and long term asset management decisions with Pure’s SmartBall free-swimming inspection platform.

Leaks on any type of pressure pipe can be a precursor to larger failures, failures that will cost utilities money, and reduce public confidence in service levels. By using Pure’s SmartBall platform leaks can be addressed before larger, more severe failures occur. Finding leaks is an important aspect of managing pipelines and understanding their condition. Inline leak detection, when combined with other Pure Engineering Services, can be used as a screening solution as part of a comprehensive condition assessment inspection or program.

SmartBall based mapping utilizes the latest accelerometer and gyroscope technology to create a field generated X and Y map of a pipeline, which can be used by pipeline mangers to better understand the alignment of their pipes relative to other critical assets, plan maintenance work more efficiently, reduce the likelihood of third party damage and conduct more accurate hydraulic modelling.

SmartBall can also be a key solution in reducing water loss in previously neglected assets by detecting leaks on large diameter mains, helping utilities locate and repair leaks before they surface. These large, long run-time leaks have a significant impact on Non-Revenue Water as the volume of water lost with these leaks is often more than those of small diameter mains.

Benefits

  • Easy to deploy through existing pipeline features
  • No disruption to regular pipeline service
  • Ability to live track up to 3,000ft (1,000m) before and after each tracking point
  • Can complete long inspections in a single deployment
  • Preliminary leak locations provided 48 hours after the inspection
  • Mapping to confirm pipeline alignment
  • Measures pressure profile

Related Article

In June of 2016, Suez retained the services of Pure Technologies to perform a SmartBall® inspection of two critical water mains, the Grigny Water Main and Les Halles Water Main, both located near Lyon.

Learn more

Featured Case Study

Waternet

The Netherlands faces unique challenges with their underground pipe networks due to their proximity to numerous dykes that regulate water levels.

Because pipe failures can lead to drastic consequences for Dutch infrastructure, Waternet undertook a leak detection program for three major pipelines that pass various critical infrastructure including dykes, motorways and airport runways.

Over the past decade, several high profile oil and gas pipeline failures have shown that the consequences of a rupture can be extremely severe for both the environment and human life, and can result in billions of dollars in remediation costs. Because of all these negative consequences, governments have made it mandatory to conduct routine inspections on these assets to prevent catastrophic events.

Today, the most common form of pipeline assessment is inline inspection (ILI) with smart pigs. These pigs flow with the product, collecting data on the condition of the pipe wall. When these tools are operating in a live pipeline, it is important to track their precise location and speed, as a lost or stuck pig can obstruct product flow, cause unwanted service disruptions or damage the pipeline.

A common misconception about pig tracking is that a run always goes as planned.  In the majority of runs, nothing unexpected will occur, but there have been a few cases where a minor event can quickly derail the smoothest of jobs, resulting in cost escalations and unnecessary hassle for the pipeline owner. By taking proper precautions and using advanced tracking technology, pipeline owners can ensure that they are prepared for any unexpected event that may occur.

Traditionally, pigs have been tracked by a single technician equipped with a standard geophone to identify the pig passing. This method can be extremely challenging and unreliable, and can result in a lost pig. In order to mitigate the risks of conventional tracking, owners can use remote tracking technology which provides greater reliability and accuracy.

Remote Tracking Prepares Asset Owners for the Unexpected

Remote tracking combines above ground markers (AGMs) equipped with multiple sensors with remote communication technology. This ensures that the pig is being tracked using more than one sensor, which is significantly more reliable than a standard geophone. In addition to tracking with multiple sensors, pipeline owners and ILI vendors are provided with a record of each passage that is downloaded from the AGMs. This record shows the signal of the pig passage, along with other information such as time and speed. The AGMs provide snapshots into a software where they can be used for real-time tracking of the pig’s position, speed, and estimated time of arrival. Pipeline owners can be sure that the results are accurate because the AGMs constantly record data to confirm pig passages when they are turned on.

If a pig gets stuck, the AGMs will know if the pig has not passed a tracking location, making it much easier for field technicians to retrieve it in a timely manner, so no damage is caused to the pipeline. Remote tracking provides reliable information and when unexpected events occur, enables pipeline owners to be better prepared for any issues that may arise.

To learn more about remote tracking and its benefits, download the white paper below.

Sensor with remote communication technology

In order to reduce the costs of tracking and gain market share, pig tracking vendors will often cut a few corners by reducing the number of hours spent on training or lowering training expectations for its field technicians. By reducing the quality of tracking, tracking providers are then able to offer more competitive pricing.

Although this can be an effective cost cutting technique, reducing tracking quality can cause significant risk during an ILI run. In most cases, pig trackers will experience nothing out of the ordinary and will spend the entire run simply driving from site to site. But, when an unexpected event – such as a speed increase –  suddenly occurs, the quality of tracking becomes crucial.

Cartoon truck and mountains

Legacy tracking methods use a standard geophone to identify a pig passage and locating a pig using these methods requires training and experience. If the field technician has not received enough training, they can easily miss the pig passage or falsely report that the pig has passed with only a geophone to back up their word. This lack of experience can make small incidents worse than they need to be

Remote Tracking Eliminates Guess Work

During an unexpected event, legacy pig tracking can result in a guessing game – there is no definitive information on the whereabouts of a pig. However, using remote tracking eliminates guess work and provides a real-time update of a pig’s position.

Remote tracking uses AGMs equipped with multiple sensors combined with remote tracking units (RTUs). The ability to track remotely allows several pigs to be tracked simultaneously by a single technician at a central location.  If something unexpected occurs, the remote tracker has a significant amount of available information to help solve the problem, unlike conventional method. To learn more about remote pig tracking and how remote tracking works, download the pig tracking white paper below.

Download full PDF

*Published in World Pipelines Magazine

Oil and gas pipelines have been around for well over a century, and some of the earliest constructed are still in service today.  Although early pipelines were made of wood, and in the past few decades plastics and composite materials have increased in popularity, the vast majority of pipelines in service today are constructed with steel.

Like any pipe material, steel pipe has its downfalls. Steel has a propensity to dent, buckle, corrode and crack when exposed to the environment.  Steel pipeline’s carrying combustible hydrocarbons are buried underground with typically ~1 meter (3 feet) of cover to protect them.  In order to mitigate corrosion, pipelines are covered with a protective coating, utilize cathodic protection (CP), and have their pressure regulated to reduce crack formation and propagation.

Despite all of the design innovations made over the past century, it has not been enough to prevent failures – even the most recently constructed pipelines.  Weather cycles, frost heaves, and road loadings cause physical damage to the pipeline and protective coating.  Operational errors and material defects cause the steel to succumb after years of relentless pressure cycles from the pipeline product itself.  Therefore, proactive pipeline inspections are needed to identify defects, before they cause a leak or rupture.

Pipeline integrity can be validated and assessed using three primary techniques: hydro-testing, the use of Inline Inspection (ILI) tools, and Direct Assessment.

Hydro-testing

Hydro-testing became common practice for pipelines in the 1940s. The process involves taking the pipeline out of service and purging the product, then the pipeline is pressurized above the maximum operating pressure (MOP) with the intent to determine the ability to operate the pipeline at MOP.  While hydro-testing is still widely used today, there are several drawbacks to the process. The water used in hydro-testing is considered hazardous material after being used, meaning owners incur the additional risk and cost associated with disposing of the water after testing. The information gained from the test is also limited in that it provides no information of the actual condition of the pipe, coating, or surrounding environment.

Hydro-testing can also promote internal corrosion of pipelines, especially if the water used is not properly treated for microbiologically influenced corrosion (MIC) and chlorides. Internal corrosion usually occurs if the pipeline is not properly cleaned and dried after the test.  Hydro-testing can also result in pressure reversals, which worsen the integrity of the pipeline [1].  Finally, the pipeline may be required to be out of service for a significant amount of time, resulting in a significant loss of revenue.

Inline Inspection

ILI tools – which are commonly referred to as smart pigs – were developed in the 1960s and commercialized in the 1970s.  These tools are designed to survey the conditions of the pipeline wall with limited disruption and can identify and quantify the corrosion and cracking in steel pipelines [2].  Magnetic flux leakage (MFL) and ultrasonic testing (UT) are common ILI tools used widely by owners today.

ILI is a significant part of pipeline integrity management, and promote safe, efficient and cost-effective pipeline operation [2].  However, it is important to remember that ILI is just a subset of a family of inspection tools used to verify pipeline fitness for service.  As with any inspection technology, ILI tools have a threshold for detection – the tools are unable to reliably detect anomalies that are below their design specifications’ detection ability. Also, internal pipeline inspections are primarily reactive, requiring the damage or wall loss to occur before defect detection is possible.

Direct Assessment (DA)

The most recently developed solution for pipeline integrity management is Direct Assessment (DA), which is a structured, iterative integrity assessment protocol used by pipeline operators to assess and evaluate the integrity of their pipelines.

Adoption and demand for DA is increasing in modern integrity programs due to more stringent industry regulations, aging pipeline networks, limitations of alternate inspection techniques, and the fact that roughly 70 percent of pipelines within North America are difficult to pig.  Direct assessment surveys provide pipeline owners with important information on both the pipeline’s condition and its surrounding conditions, both of which can lead to degradation and eventual failure.

The Stages of Direct Assessment

It should be noted that geotechnical, dent, and buckle threats are not specifically addressed with any of the DA techniques.  All DA protocols are four-step iterative processes which include a Pre-Assessment, an Indirect Inspection, a Direct Examination and a Post-Assessment.  Inspections involve the integration of as much pipeline available integrity data as possible, which includes physical characteristics and operational history, historical and multiple indirect inspections, and direct pipe surface examinations.

In the pre-assessment step, historic and current pipeline data is collected to determine whether DA is feasible, define DA regions, select indirect inspection tools and determine if additional integrity data is needed.

The second step in DA methodology involves the use of non-intrusive and aboveground techniques. These tools assess the effectiveness of the coating and cathodic protection for pipeline external corrosion assessment (EDCA an ECCDA), and predictive modelling, or critical angle calculations for pipeline internal corrosion assessment (ICDA) to identify and define areas susceptible to internal corrosion.

For external corrosion assessment, the state of cathodic protection, coating and soil resistivity are critical factors in determining high-risk areas. For internal corrosion assessment, fluid flow, mass transfer, solid accumulation, mineral scales, corrosion products, and MIC are critical components [3].  For stress corrosion cracking, critical factors include operating stresses, operating temperatures, distance from a compressor station, age of the pipeline, and coating type.

The direct examination step involves the analysis of pre-assessment and indirect inspection data to select sites for excavation and examination of pipe surface. This process validates the inspection data and provides a first-hand evaluation of the pipe surface and surrounding environment.

Finally, the post-assessment phase involves the analysis and integration of integrity data collected from the previous three steps to assess the effectiveness of the DA process and determine the necessary reassessment intervals.

There are six DA standards developed by National Association of Corrosion Engineers (NACE) and they include:

2002 -NACE SP0502-2010 ECDA (External Corrosion Direct Assessment)

2004 -NACE SP0204-2008 SCC-DA (Stress Corrosion Cracking Direct Assessment)

2006 -NACE SP0206-2006 DG-ICDA (Dry Gas Internal Corrosion Direct Assessment)

2008 -NACE SP0208-2008 LP-ICDA (Liquid Petroleum Internal Corrosion Direct Assessment)

2010 -NACE SP0110-2010 WG-ICDA (Wet Gas Internal Corrosion Direct Assessment)

2010 -NACE SP0210-2010 ECCDA (External Corrosion Confirmatory Direct Assessment)

DA is also covered in ASME B31.8S (Section 6.4).  In the United States, DA is covered in US Code of Federal Regulation CFR 49 Part 192.923 (for natural gas pipelines) and 195.888 (for liquid hazardous pipelines).  It is now one of the three accepted inspections (ILI and Hydro-testing being the other two) allowed for oil and gas pipelines.

Identifying Pipeline Anomalies Using Directing Assessment

When completing a DA inspection, there are three types of anomalies that owners are aiming to identify:

1.         External Corrosion (EDCA and ECCDA)

2.         Internal Corrosion (dry gas, wet gas, and liquid petroleum ICDA)

3.         Stress Corrosion Cracking (SCCDA).

Due to the serious consequences of corrosion and leaks in underground pipelines, external corrosion direct assessment (ECDA), and external corrosion confirmatory direct assessment (ECCDA) – as described in ANSI/NACE SP0502 and NACE SP0210 – were developed in an attempt to proactively prevent external corrosion and ensure the integrity of oil and gas pipelines that are difficult to pig.

ECDA is a continuous improvement process intended to identify and address locations at which corrosion activity has occurred, is occurring, or might occur. For instance, ECDA identifies areas where coating defects have already formed, and can ascertain where cathodic protection is insufficient and corrosion is possible, before major repairs are required.

The success of any ECDA requires strong knowledge of the soil/environment, pipeline material, coating, cathodic protection, and foreign/interference current on the pipeline. Also, the accurate selection of susceptible areas for external corrosion relies on using at least two complementary advanced aboveground inspection techniques. These aboveground indirect inspection techniques may include: direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG) surveys, a cathodic protection close interval potential survey (CP CIPS), alternating current—current attenuation (ACCA) and side drain (for bare or ineffectively coated pipelines) surveys. Normally these aboveground inspections are used in conjunction with pipe locating.

The development of internal corrosion in pipelines is partly because of its complex nature and interaction between constituents that are found in transported gas and liquid products (e.g., oxygen, carbon dioxide, hydrogen sulfide, chloride, bacteria, etc.). When in the presence of water, these contaminants can lead to conditions conducive to the occurrence of internal corrosion. The susceptible locations for internal corrosion are usually where liquids, solids and gas accumulate. In order to ensure that susceptible locations along the pipeline are prevented from internal corrosion, internal corrosion direct assessment methodology is implemented.

Internal Corrosion Direct Assessment (ICDA) methodology has been developed to verify pipeline integrity, especially for pipelines that are not able to accept inline inspection (ILI) tools. ICDA includes Wet Gas Internal Corrosion Direct Assessment (WG-ICDA), Dry Gas Internal Corrosion Assessment (DG-ICDA) and Liquid Petroleum Internal Corrosion Direct Assessment (LP-ICDA). WG-ICDA (NACE SP110-2010) is used in pipelines that assumes that water, or a combination of water and hydrocarbons can be present in the pipeline. It is intended for onshore and offshore systems where liquid to gas ratio is small. It tends to identify locations in the pipeline where corrosion is expected to be severe. DG-ICDA (NACE SP206-2006) is applicable to pipelines that transport gas that is normally dry, but may suffer infrequent upsets, which may introduce water to the pipeline. LP-ICDA (NACE SP208-2008) is employed to assess the susceptibility of internal corrosion on pipelines that transport incompressible liquid hydrocarbons that normally contain less than 5 percent base sediment and water. The success of any ICDA process is dependent on using an accurate corrosion model to predict a precise elevation profile in order to determine susceptible locations for internal corrosion.

DA technology has also proven successful in stress corrosion cracking direct assessment (SCCDA), offering pipeline operators a comprehensive pipeline integrity management portfolio. SCCDA (referenced in NACE SP0204-2008 and ASME B31.8S) is a proactive structured process that seeks to improve pipeline safety by assessing and reducing the impact of stress corrosion cracking. Stress corrosion cracking can occur at neutral or high pH when susceptible pipeline material is exposed to stress, specific susceptible temperature, and a corrosive environment.

The Benefits of Direct Assessment

Direct Assessment is non-intrusive and inspections can be completed during normal operation of the pipeline.  DA is also a proactive integrity management tool that can find anomalies before they become critical defects, while traditional ILI tools are reactive in that they identify existing pipeline damage.

While hydro-testing and ILI tools are an important part of integrity management, the development of DA provides pipeline owners with another solution to identify at-risk areas of pipe before they become a major problem. A combined integrity approach that employs DA can help pipeline owners ensure containment and prevent costly, reputation-harming pipe failures.

References

1.    Pipeline Research Committee, American Gas Association, NG-18 Report No. 111 (Nov. 3, 1980)

2.    NACE 35100, In-Line Inspection of Pipelines, NACE International, May 2012

3.    NACE Training Course, Direct Assessment, NACE International, November 2012

*Published in World Pipelines Magazine

The oil and gas pipeline industry has been under close scrutiny for a long time. It leads the way as one of the most regulated industries in the world, and for good reason.  With so many safety-related, social and environmental factors at stake, comprehensive regulation ensures rigorous standards for the design, construction, operation and maintenance of O&G pipeline systems.

Global economics and political activism also play a role in shaping today’s conversation about pipelines. In North America, public debates about the Keystone XL Pipeline have dominated much of the recent news, compelling operators to vigorously participate in the discussion and advocate their integrity management programs. Although Keystone has been put on hold, social capital can assist in getting projects of this magnitude on the radar again.

Through it all, much of the dialogue has focused on the industry’s commitment to protecting communities and the environment from risk by means of rigorous pipeline integrity management programs. As a result, the requirement for increased pipeline safety drives innovative research into improving the sensitivity and reliability of inline inspection (ILI) tools.

Most operators already deploy trusted inline technologies that detect structural deterioration and help maintain pipeline integrity. However, with pressure mounting from stricter regulation, increased operational costs, commodity price-driven budgetary pressure, and often limited available resources, operators face an increasing number of challenges, including vigilance from highly engaged consumer groups.

Although the pressure to perform is greater than ever, operators are responding appropriately with greater confidence in modern technologies to assist in the operation and monitoring of their pipeline systems.

Better ILI tools instill better confidence in containment

To have confidence in the pipeline, operators must have confidence in the capabilities of ILI tools to detect small anomalies that could lead to potential failures.  They must also trust the reliability and interpretation of the data, knowing with as much certainly as possible that the depth, size and location of the pipe wall anomaly is correct.

Overall the news is good. Between 2002 and 2013, Canadian Energy Pipeline Association (CEPA) member companies were able to transport oil and natural gas with a 99.999 percent safety record. While that statistic sounds impressive, headline-grabbing pipeline incidents do occur, (in 2014 there were 122 natural gas and liquid releases) and when that happens, the repercussions can undo years of containment management trust and goodwill.

While the oil and gas industry boasts a remarkable safety record, a reliance on conventional tools limit the near perfect record.  As much as the technologies have been refined, regulators have noted that inline inspections don’t pick up all defects, and expedient follow-through often depends on the people analyzing the data and planning repairs, a process that can take months.

“Despite their sophistication, the detection capabilities of inline inspection tools have limitations,” the US National Transportation Safety Board noted in its report on the 3.3-million-liter 2010 spill in Michigan.

Limitations of conventional ILI inline inspection technologies

The oil and gas pipeline industry has access to an extensive toolbox of technologies for robust integrity programs. Some tools address cracks or corrosion issues, while other tools focus on stress, pressure and product containment. Cost, resolution, reliability, data analysis speed – each technology has its own strengths and limitations, with no silver bullet as the single solution for collecting pipeline condition information.

For example, there is a strongly-held belief in hydrostatic testing as a reliable method to test a pipeline’s integrity. One of the earliest inspection techniques, hydrostatic testing determines if a pipeline can hold its operating pressure. A form of destructive testing, hydrostatic inspection involves purging the product, flooding the line with water, pressurizing it to a predetermined level and maintaining the pressure for a period. Based on the results, detected anomalies in pressure, volume and density can be a precursor to leaks.

Critics however, argue and have quite effectively demonstrated that the hydrostatic tests lack the ability to monitor ongoing corrosion or cracking and that the high pressure environment can exacerbate previously small defects, increasing risk of future rupture.

Smart pigs for detecting large cracks and corrosion

Unlike hydrostatic testing, which is often conducted on pipelines for acceptance testing or for pipelines recently rehabilitated, pigging is the more commonly accepted method of testing pipeline integrity.

While newer “smart” pigs have an excellent reputation for accuracy, their efficacy is often limited to detecting corrosion and cracking that exceeds the threshold for detection of the technology.  Small corrosion pits and cracks, especially cracks grouped in a colony, can pose a challenge to most conventional ILI pigging devices.

The various ILI technologies are sensitive to axial or circumferential defects, and each has limitation for minimum aspect ratios or cross sectional wall loss area before the ILI tool can report the anomaly.  It is also possible to have cracks and wall loss pits that are in close proximity to girth welds, long seams, and other features in the pipe, which can mask the defect, preventing the ILI tool from properly identifying and sizing.  As a result, it is possible to have leaking cracks and corrosion pits that are too small to be sized and reported from conventional ILI.

Not all lines are piggable

Some pipes are more suitable for pigging than others. While most oil and gas transmission lines were built in long straight sections suitable for pig runs, sections with small diameter pipe and small bend radius pipe configurations can limit many ILI tools.  Lines with expansion loops and miter bends, and in the case of natural gas lines, those with reduced port valves, are factors that can prohibit or restrict the traversing of online tools.

Mass balance measurement and other leak detection tools

To make up for the limitations of conventional ILI technologies, operators often deploy measurement methods and leak detection technologies to complement their integrity programs.

Mass balance is a means of detecting leaks by measuring the mass of product entering the pipeline compared to the mass exiting the pipeline. The limitation for detecting small leaks is the sensitivity of the mass meters being used (2-4% accuracy for conventional orifice meters and 0.25% for turbine meters), and the fact that the product temperature and pressure changes as it moves through the pipeline.

While mass balance is a means to determine leaks, it is also recognized that making actual measurement of mass from volume (through a meter) at different temperature and pressure going in versus coming out of the pipeline, in real time, is difficult, and not very precise or sensitive to small leaks.

As a result, a leak has to release more product than the total tolerance of the mass balance system before a positive leak/release event is alarmed.

Acoustic leak detection

Minute cracks are often preliminary indicators of potential small leaks that produce acoustic emissions at levels often unrecognizable over background noise.

Acoustic leak detection can be conducted with geophones/hydrophones, comparators and acoustic fiber optic techniques, and each of these acoustic tools is subject to different background noise limitations to determine leak detection thresholds.  Not only can these tools have limitations to prevent small leak detection, the expense from installing permanent acoustic systems may reduce the practicality of these technologies.

Emerging technologies on the horizon

To complement hydrostatic testing, conventional pigging tools, and leak detection technologies, the oil and gas industry is evaluating a growing number of emerging external confirmation of containment technologies. These include vapour-sensor systems, hydrocarbon-sensing cables that change in the presence of hydrocarbons, internal pressure wave based tools and fibre-optic based systems that detect temperature changes and acoustic signals associated with leaks.

While these technologies offer hope for more precise surveys, they have yet to be universally accepted or proven. Many are still under development and often require economically impractical installation requirements.

However, there is an innovative, multi-sensor ILI platform that has been used in integrity management programs since 2006, gaining the attention of major pipeline players who have tested the platform, which has now been used on over 25,000 kilometers of pipeline in total.

Introducing SmartBall® technology for Oil & Gas pipelines

To provide a realistic snapshot of a pipe’s condition, many proactive operators are deploying SmartBall technology,  a free-swimming multi-sensor tool for long inspections of piggable and difficult to pig liquid and gas pipelines 4 inches and larger. This advantage makes the ball-shaped tool an excellent choice for traversing not just standard diameter pipes, but for smaller diameter liquid lines and for gas pipelines with loops and frequent sharp bends and heavy wall fittings.

During an inspection, the SmartBall sensors collect acoustic, pressure, temperature, magnetic and inertial data from inside the pipeline.

Primary applications for the SmartBall tool

SmartBall surveys can be conducted independently, at regular intervals, as part of a routine pipeline integrity management program, or as a value-add to inspection programs along with hydro-testing, ILI, or direct assessment.

The tool is launched and retrieved at existing pig traps and is tracked using proprietary acoustic receivers and/or Armadillo pig tracking boxes (AGMs). The location data from acoustic receivers and tracking boxes is used during data analysis to locate any anomalies.

SmartBall technology has three primary applications, and the multi-sensor tool can provide a variety of pipeline data.

1. Confirmation of Containment

Regular confirmation of containment surveys are an important part of integrity management as leaks are often a preliminary indicator of pipe failure.

Unlike conventional leak detection systems, confirmation of containment with SmartBall supplements these systems. The SmartBall tool directly passes leaks, and is therefore capable of detecting losses as small as 150 mL/min, which can be several orders of magnitude more sensitive than conventional methods.

SmartBall surveys can also complement regular ILI surveys by addressing potential pinhole anomalies that have aspect ratios below the reporting threshold of ILI systems.

2. Pressure and Temperature profiles

As the SmartBall is rolling and not sealing against the pipe ID, as conventional pigs do, the tool can also record precise pressure and temperature profiles. The SmartBall platform can be deployed in gas pipelines, where pressure and temperature profiles can be integrated into flow models to assess the points where water vapor may condense out of the gas.

The tool can also be used to assess the point where high temperatures from pump or compressor output may have affected the pipe coating, as well as in settings to validate and improve SCADA and mass balance systems.

3. Pipe Wall Assessment and Inertial Mapping

During inspection, the SmartBall Pipe Wall Assessment (PWA) tool collects magnetic data that can provide a screening of the pipe wall for stress resulting from features like large cracks, large wall loss, dents and points of excessive loading.  The test can also complement hydrostatic testing, as it can survey the pipeline before and after hydro-tests to identify stress that is indicative of pressure reversals.

In addition, the SmartBall PWA tool can produce a girth weld and joint tally for the pipeline, as well as can confirm locations of bends and general geometry of the pipeline.

Helping operators make better decisions

Admittedly, SmartBall is not designed to compete with high resolution technologies like Magnetic Flux Leakage (MFL), which can provide detailed wall loss data.

What SmartBall can do is complement other integrity tools by providing additional data sets to ensure pipeline integrity. In a single deployment, it can detect anomalies associated with pinhole leaks and stress that doesn’t necessarily involve wall loss; e.g. geotechnical strains.  It can also detect change in pressure and temperatures.

Ultimately, the SmartBall tool can help capture enough data to confirm the integrity of the pipe and give operators enough microscopic knowledge to make better, informed, risk-based decisions on the health of their pipelines.

Oil and gas pipeline owners routinely conduct inspections of their assets by using inline inspection pigs. These tools are used to identify defects within the pipeline and need to be tracked throughout an inspection. Pipeline owners have several options to track a pig such as legacy tracking, remote tracking, and batch tracking, which is sometimes considered as a viable alternative to legacy or remote tracking.

Batch Tracking can be Difficult and Risky

Batch tracking involves measuring pump and flow rates to estimate how far a pig has traveled through a pipeline. The data measured is then compared to pipeline drawings to make an estimate of the pig’s location at a given time.

Depending on the tolerance of the metering system and the bypass rates on an individual pig, locating the tool can be very challenging. Batch tracking also does not provide any dynamic information about a pig. For example, an unexpected speed excursion or stoppage will go unnoticed.

Remote Tracking provides a more Reliable Option

Although traditional or remote tracking is more expensive than batch tracking, its cost is far outweighed by the risk of losing a pig. Lost pigs can result in costly, unplanned shutdowns to locate and retrieve the pig, which would ultimately negate any costs saved by using batch tracking. Technological advancements such as remote tracking provide a cost-effective alternative to batch tracking.

Sensor for tracking

Remote tracking can reduce an asset owner’s risk exposure by providing reliable information during an ILI run. Tracking a pig is the best way to ensure your assets are safe and that you can respond to any incident.

Remote tracking uses a combination of above ground markers (AGMs) and remote tracking units (RTUs) to track a pig during an ILI run. Pig passages are detected using multiple sensors to ensure that the pig is being tracked using more than one indicator. In addition to tracking with multiple sensors, pipeline owners and ILI vendors are provided with a record of each pig passage, making it easier to see when passages are not auditable using a standard geophone.

To learn more about advanced pig tracking, download PureHM’s pig tracking whitepaper.

Download full PDF

*Published in World Pipelines Magazine

The oil and gas pipeline industry has been under close scrutiny for a long time. It leads the way as one of the most regulated industries in the world, and for good reason.  With so many safety-related, social and environmental factors at stake, comprehensive regulation ensures rigorous standards for the design, construction, operation and maintenance of O&G pipeline systems.

Global economics and political activism also play a role in shaping today’s conversation about pipelines. In North America, public debates about the Keystone XL Pipeline have dominated much of the recent news, compelling operators to vigorously participate in the discussion and advocate their integrity management programs. Although Keystone has been put on hold, social capital can assist in getting projects of this magnitude on the radar again.

Through it all, much of the dialogue has focused on the industry’s commitment to protecting communities and the environment from risk by means of rigorous pipeline integrity management programs. As a result, the requirement for increased pipeline safety drives innovative research into improving the sensitivity and reliability of inline inspection (ILI) tools.

Most operators already deploy trusted inline technologies that detect structural deterioration and help maintain pipeline integrity. However, with pressure mounting from stricter regulation, increased operational costs, commodity price-driven budgetary pressure, and often limited available resources, operators face an increasing number of challenges, including vigilance from highly engaged consumer groups.

Although the pressure to perform is greater than ever, operators are responding appropriately with greater confidence in modern technologies to assist in the operation and monitoring of their pipeline systems.

Better ILI tools instill better confidence in containment

To have confidence in the pipeline, operators must have confidence in the capabilities of ILI tools to detect small anomalies that could lead to potential failures.  They must also trust the reliability and interpretation of the data, knowing with as much certainly as possible that the depth, size and location of the pipe wall anomaly is correct.

Overall the news is good. Between 2002 and 2013, Canadian Energy Pipeline Association (CEPA) member companies were able to transport oil and natural gas with a 99.999 percent safety record. While that statistic sounds impressive, headline-grabbing pipeline incidents do occur, (in 2014 there were 122 natural gas and liquid releases) and when that happens, the repercussions can undo years of containment management trust and goodwill.

While the oil and gas industry boasts a remarkable safety record, a reliance on conventional tools limit the near perfect record.  As much as the technologies have been refined, regulators have noted that inline inspections don’t pick up all defects, and expedient follow-through often depends on the people analyzing the data and planning repairs, a process that can take months.

“Despite their sophistication, the detection capabilities of inline inspection tools have limitations,” the US National Transportation Safety Board noted in its report on the 3.3-million-liter 2010 spill in Michigan.

Limitations of conventional ILI inline inspection technologies

The oil and gas pipeline industry has access to an extensive toolbox of technologies for robust integrity programs. Some tools address cracks or corrosion issues, while other tools focus on stress, pressure and product containment. Cost, resolution, reliability, data analysis speed – each technology has its own strengths and limitations, with no silver bullet as the single solution for collecting pipeline condition information.

For example, there is a strongly-held belief in hydrostatic testing as a reliable method to test a pipeline’s integrity. One of the earliest inspection techniques, hydrostatic testing determines if a pipeline can hold its operating pressure. A form of destructive testing, hydrostatic inspection involves purging the product, flooding the line with water, pressurizing it to a predetermined level and maintaining the pressure for a period. Based on the results, detected anomalies in pressure, volume and density can be a precursor to leaks.

Critics however, argue and have quite effectively demonstrated that the hydrostatic tests lack the ability to monitor ongoing corrosion or cracking and that the high pressure environment can exacerbate previously small defects, increasing risk of future rupture.

Smart pigs for detecting large cracks and corrosion

Unlike hydrostatic testing, which is often conducted on pipelines for acceptance testing or for pipelines recently rehabilitated, pigging is the more commonly accepted method of testing pipeline integrity.

While newer “smart” pigs have an excellent reputation for accuracy, their efficacy is often limited to detecting corrosion and cracking that exceeds the threshold for detection of the technology.  Small corrosion pits and cracks, especially cracks grouped in a colony, can pose a challenge to most conventional ILI pigging devices.

The various ILI technologies are sensitive to axial or circumferential defects, and each has limitation for minimum aspect ratios or cross sectional wall loss area before the ILI tool can report the anomaly.  It is also possible to have cracks and wall loss pits that are in close proximity to girth welds, long seams, and other features in the pipe, which can mask the defect, preventing the ILI tool from properly identifying and sizing.  As a result, it is possible to have leaking cracks and corrosion pits that are too small to be sized and reported from conventional ILI.

Not all lines are piggable

Some pipes are more suitable for pigging than others. While most oil and gas transmission lines were built in long straight sections suitable for pig runs, sections with small diameter pipe and small bend radius pipe configurations can limit many ILI tools.  Lines with expansion loops and miter bends, and in the case of natural gas lines, those with reduced port valves, are factors that can prohibit or restrict the traversing of inline tools.

Mass balance measurement and other leak detection tools

To make up for the limitations of conventional ILI technologies, operators often deploy measurement methods and leak detection technologies to complement their integrity programs.

Mass balance is a means of detecting leaks by measuring the mass of product entering the pipeline compared to the mass exiting the pipeline. The limitation for detecting small leaks is the sensitivity of the mass meters being used (2-4% accuracy for conventional orifice meters and 0.25% for turbine meters), and the fact that the product temperature and pressure changes as it moves through the pipeline.

While mass balance is a means to determine leaks, it is also recognized that making actual measurement of mass from volume (through a meter) at different temperature and pressure going in versus coming out of the pipeline, in real time, is difficult, and not very precise or sensitive to small leaks.

As a result, a leak has to release more product than the total tolerance of the mass balance system before a positive leak/release event is alarmed.

Acoustic leak detection

Minute cracks are often preliminary indicators of potential small leaks that produce acoustic emissions at levels often unrecognizable over background noise.

Acoustic leak detection can be conducted with geophones/hydrophones, comparators and acoustic fiber optic techniques, and each of these acoustic tools is subject to different background noise limitations to determine leak detection thresholds.  Not only can these tools have limitations to prevent small leak detection, the expense from installing permanent acoustic systems may reduce the practicality of these technologies.

Emerging technologies on the horizon

To complement hydrostatic testing, conventional pigging tools, and leak detection technologies, the oil and gas industry is evaluating a growing number of emerging external confirmation of containment technologies. These include vapour-sensor systems, hydrocarbon-sensing cables that change in the presence of hydrocarbons, internal pressure wave based tools and fibre-optic based systems that detect temperature changes and acoustic signals associated with leaks.

While these technologies offer hope for more precise surveys, they have yet to be universally accepted or proven. Many are still under development and often require economically impractical installation requirements.

However, there is an innovative, multi-sensor ILI platform that has been used in integrity management programs since 2006, gaining the attention of major pipeline players who have tested the platform, which has now been used on over 25,000 kilometers of pipeline in total.

Introducing SmartBall® technology for Oil & Gas pipelines

To provide a realistic snapshot of a pipe’s condition, many proactive operators are deploying SmartBall technology,  a free-swimming multi-sensor tool for long inspections of piggable and difficult to pig liquid and gas pipelines 4 inches and larger. This advantage makes the ball-shaped tool an excellent choice for traversing not just standard diameter pipes, but for smaller diameter liquid lines and for gas pipelines with loops and frequent sharp bends and heavy wall fittings.

During an inspection, the SmartBall sensors collect acoustic, pressure, temperature, magnetic and inertial data from inside the pipeline.

Primary applications for the SmartBall tool

SmartBall surveys can be conducted independently, at regular intervals, as part of a routine pipeline integrity management program, or as a value-add to inspection programs along with hydro-testing, ILI, or direct assessment.

The tool is launched and retrieved at existing pig traps and is tracked using proprietary acoustic receivers and/or Armadillo pig tracking boxes (AGMs). The location data from acoustic receivers and tracking boxes is used during data analysis to locate any anomalies.

SmartBall technology has three primary applications, and the multi-sensor tool can provide a variety of pipeline data.

1. Confirmation of Containment

Regular confirmation of containment surveys are an important part of integrity management as leaks are often a preliminary indicator of pipe failure.

Unlike conventional leak detection systems, confirmation of containment with SmartBall supplements these systems. The SmartBall tool directly passes leaks, and is therefore capable of detecting losses as small as 150 mL/min, which can be several orders of magnitude more sensitive than conventional methods.

SmartBall surveys can also complement regular ILI surveys by addressing potential pinhole anomalies that have aspect ratios below the reporting threshold of ILI systems.

2. Pressure and Temperature profiles

As the SmartBall is rolling and not sealing against the pipe ID, as conventional pigs do, the tool can also record precise pressure and temperature profiles. The SmartBall platform can be deployed in gas pipelines, where pressure and temperature profiles can be integrated into flow models to assess the points where water vapor may condense out of the gas.

The tool can also be used to assess the point where high temperatures from pump or compressor output may have affected the pipe coating, as well as in settings to validate and improve SCADA and mass balance systems.

3. Pipe Wall Assessment and Inertial Mapping

During inspection, the SmartBall Pipe Wall Assessment (PWA) tool collects magnetic data that can provide a screening of the pipe wall for stress resulting from features like large cracks, large wall loss, dents and points of excessive loading.  The test can also complement hydrostatic testing, as it can survey the pipeline before and after hydro-tests to identify stress that is indicative of pressure reversals.

In addition, the SmartBall PWA tool can produce a girth weld and joint tally for the pipeline, as well as can confirm locations of bends and general geometry of the pipeline.

Helping operators make better decisions

Admittedly, SmartBall is not designed to compete with high resolution technologies like Magnetic Flux Leakage (MFL), which can provide detailed wall loss data.

What SmartBall can do is complement other integrity tools by providing additional data sets to ensure pipeline integrity. In a single deployment, it can detect anomalies associated with pinhole leaks and stress that doesn’t necessarily involve wall loss; e.g. geotechnical strains.  It can also detect change in pressure and temperatures.

Ultimately, the SmartBall tool can help capture enough data to confirm the integrity of the pipe and give operators enough microscopic knowledge to make better, informed, risk-based decisions on the health of their pipelines.

Oil and gas pipeline owners conduct routine inspections of their pipelines using inline inspection (ILI) tools known as pigs. ILI pigs can identify defects within the pipe wall and need to be tracked when they are travelling through a pipeline.

Pig tracking can be expensive (as much as 25% of the ILI budget) and costs can vary from vendor-to-vendor, especially when you factor in the different methods used to track pigs, such as remote tracking and conventional tracking. In order to ensure that tracking budgets are used efficiently and defensibly, each ILI run should be thoughtfully planned to determine the most appropriate tracking method.

Per Mile Cost Fluctuations

Drawing of a worker

Even after thorough planning, cost estimates can vary from vendor-to-vendor, raising questions about per mile cost fluctuations. To reduce the per mile cost of tracking, service providers often reduce the quality of tracking per mile. In traditional tracking, sending out lesser-trained technicians at cheaper rates, enacting only minimum safety measurements and using only one tracking sensor to identify pig passages are all ways that vendors can reduce per mile tracking costs.

An important consideration for pipeline owners and ILI vendors is determining how much risk they are willing to take when tracking their ILI programs. In most cases reducing the per mile costs by 10 to 15 percent is not worth the risk of using low-quality tracking techniques. A single missed or lost pig can easily negate the savings from using the lowest-cost provider.

In most cases, using remote tracking can decrease both the risk and cost of an ILI run. Remote tracking requires fewer staff and equipment resources than conventional tracking and is much safer.

To learn more about remote tracking and its benefits, download PureHM’s pig tracking white paper.

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Historically, inline inspection (ILI) tools used to identify defects on oil and gas pipelines have been tracked by field teams. However, recent technology advancements now allow pipeline owners to track pigs remotely, which is a much safer and cheaper alternative to traditional tracking. As pipeline integrity technology advances, asset owners are now using a wide variety of tools to detect problems, and often run multiple tools on the same pipeline. Using traditional methods – which many owners still use – tracking multiple pigs using field staff is expensive and risky. More trackers in the field increases the risk of any job, as well as increases the project costs to staff appropriately for multiple pigs.

Reduction in number of field technicians

In remote tracking runs, technicians only need to be in the field to deploy and collect the remote tracking units, and only one technician is needed to track multiple pigs during the run. In comparison, Legacy tracking methods require multiple field technicians to track multiple pigs. As the number of pigs increase in a run, more man power is needed, whereas remote tracking can do all this using a single tracker in a central location.

Reduction in truck costs

When the number of field technicians needed is reduced, the number of trucks in the field and number of kilometers driven also decreases. This not only reduces the project costs incurred, but also reduces the environmental footprint of tracking.

Reduction in field technician time

When using remote tracking methods, the cost savings are not only reflected in fewer billed technician hours, but also in terms of reduced costs relating to standby days and fewer flights. It also eliminates the need for long field shifts and night shifts, making it the safe alternative to traditional tracking. While many pipeline companies still us traditional methods, best-in-class integrity programs are now leveraging remote pig tracking to reduce cost and increase safety.

To learn more about remote tracking, download PureHM’s pig tracking whitepaper.

Drawing of a worker

The most common form of pipeline integrity used by oil and gas pipeline owners is inline inspection (ILI). Inspection pigs are widely used to clean pipelines, as well as identify areas of damage along the pipe wall to ensure the safe delivery of energy products.

Historically, once a pig is deployed in a pipeline, a technician confirms the tool’s arrival time at various tracking locations throughout the planned inspection distance. Once the tool has passed each location, it is out of sight until it reaches the next tracking point. However, recent technological advancements in tracking technology now allow for pigs to be tracked remotely throughout an entire ILI run.

Remote tracking combines the use of above ground markers (AGMs) and Remote Tracking Units (RTUs) that are deployed before an ILI run is scheduled to take place and are used to track the pig from a central location. When a pig approaches a tracking site, the RTU and AGM are activated to track the tool, which eliminates the need to have a field technician to be on site.

Consistent Live Tracking

PureHM has developed a web-based software called LiveMap that tracks a pig throughout the entire ILI run. LiveMap provides real-time updates via email or SMS with the pig’s location, speed, and estimated time of arrival to ensure that there is better visibility for stakeholders during a project. This advanced technology mitigates the risk of unexpected challenges in an ILI run, such as a stuck pig or speed excursion.

Live tracking offers more control throughout an inspection, and can help prevent costly incidents such as lost pigs by providing accurate information on a pig’s location. A lost pig can interrupt or stop product flow in a pipeline, and can lead to pipeline damage and unforeseen service disruptions.

LiveMap drawing

During an ILI run, the time and speed information collected each time the pig passes the AGM is updated and presented in LiveMap. In traditional legacy tracking runs, this is completed and reported by the field tracker, while in remote tracking runs this is completed automatically with a defensible record of the passage.

To learn more about remote tracking, download PureHM’s pig tracking white paper.

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Pigging is the most common form of inline inspection used by oil and gas pipeline owners. There are two ways of tracking a pig through a pipeline; legacy tracking and remote tracking. Historically, pigs have been tracked using legacy methods, where a field technician would follow the pig from site to site to confirm its location and ensure the pig reaches the trap.

Remote tracking combines leading-edge above ground markers (AGMs) and Remote Tracking Units (RTU’s) that are pre-deployed before an ILI run and are used to track the pig from a central location. As a pig approaches a tracking site, the remote unit is activated to track the tool, and does not require a field technician to be on site.

It is a common misconception that remote tracking is more expensive than traditional legacy tracking methods due to the presence of advanced technology; however, remote tracking is often significantly cheaper than legacy tracking.

When to use remote tracking

Moon, Earth and satellite

Remote tracking is less expensive than legacy tracking when there are multiple pig runs or accessibility issues with tracking locations. Using remote tracking, each site only needs to be accessed twice – for equipment deployment and retrieval. Using legacy methods for a multi-pig run would require trackers to access each site multiple times, which can significantly increase costs.

While this seems insignificant, reducing the number of field trackers, trucks, and subsistence charges can drastically reduce a project’s cost. In addition, remote tracking helps to normalize project costs, as unexpected delays or standby days don’t result in additional costs for the pipeline owner.

Before any ILI run, pipeline owners should evaluate all the potential risks and costs to determine the best method of tracking the pig. If multiple pig runs need to be conducted, tracking locations are inaccessible, or if the run will span over a long distance, remote tracking can save pipeline owners upwards of 50 percent compared to traditional legacy tracking.

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Inline inspection (ILI) of oil and gas pipelines has been common practice for asset owners since the 1970s. Historically, companies have tracked these ILI tools with field teams to confirm its location and ensure that the pig reaches the trap. While tracking a tool seems simple in concept, several misconceptions have become conventional wisdom when it comes to the challenges of pig tracking.

Before completing any run, it is important for pipeline owners to consider these myths and their validity. One common misconception about pig tracking is that speed excursions are unavoidable, and when this happens, the tool can’t be effectively tracked. While it is true that speed changes are common and sometimes unexpected, it is a misconception that the tool can’t be effectively tracked when this happens.

Pig tracking tool inside a pipe

Any time there is a live tool in the pipeline, it is important to know its precise location and speed. Not only are ILI tools expensive to replace, but a lost or stuck pig can obstruct product flow leading to unwanted service disruptions.

Although an increase in a pig’s speed is sometimes unavoidable, a pipeline owner can take steps to ensure the tool is tracked regardless of speed increases using Advanced Pig Tracking methods, such as remote pig tracking. Remote tracking combines leading-edge above ground markers (AGMs) and Remote Tracking Units (RTU’s) that are pre-deployed before an ILI run and are used to track the pig from a central location. As a pig approaches a tracking site, the remote unit is activated to track the tool, and does not require a field technician to be on site.

If a speed excursion occurs, the remote unit can be activate quickly at the next site to track the tool. This is far less risky than traditional tracking, which would require the field trackers to chase the pig from site to site, which is dangerous in urban or high traffic areas or during inclement weather. Chasing a fast moving pig also results in missed passages as the tool gets ahead of the field teams.

Before any run, pipeline owners should evaluate all the potential risks and determine the best method of tracking a tool. If there is a reasonable chance of a speed excursion, remote tracking is significantly more reliable than traditional legacy tracking.

To learn more about when to use remote or legacy tracking, as well as the other myths of pig tracking, download our white paper here.

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Every day, oil and gas pipelines transport critical resources that help fuel the economy, vital industries, and our communities. Without pipelines, it would take thousands of tanker trucks to transport these resources, which is impractical from both a safety and cost standpoint. Although pipelines are an extremely efficient means of transport, they also carry significant risk for owners and the communities they operate in. To ensure safe operation, pipelines are one of the most regulated assets in the world. The most common form of pipeline integrity is the use of inline inspection (ILI) tools known as smart pigs.

Pipeline pigs are inserted into a pipeline and pushed along by the flow of the product. The tools have multiple functions, and can be used to clean and assess the condition of the pipeline, as well as to purge different products in a multiproduct pipeline. Historically, technicians needed to be physically present to track a pig throughout the run, moving from site to site to track multiple pigs. This method requires a lot of driving and manpower, which adds risk to the run and can result in cost escalations if there are unexpected delays. In recent years, there have been developments in pig tracking which allow pigs to be tracked remotely.

During multiple pig runs, remote tracking is the most efficient method of tracking. It eliminates the need for field technicians to commute from location to location, as pigs are tracked from a central location start to finish. It also reduces the risk associated with having trackers out in the field and the environmental footprint by reducing the number of trucks on the road.

How it works

Before a remote tracking run, technicians temporarily deploy Armadillo above ground markers (AGMs) and remote tracking units. The AGMs are only activated before the run and do not increase project costs on unplanned standby days, unlike field technicians.

Cartoon drawing of a boss sending work to an employee over a wireless network

Once a pig has passed a tracking location, their progress is updated into the LiveMap software, which provides a live view of the pig’s position, velocity and estimated time of arrival for inline inspection (ILI) vendors and pipeline owners.

In some situations, such as single-pig or short distance runs, it is more efficient to have trackers in the field, but using remote tracking during multi-pig runs can significantly reduce costs and increase tracking reliability.

Click here to get your price estimate on a remote tracking inspection run.

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In order to mitigate risk, pipeline owners spend approximately $1.5 billion every year on pipeline integrity for the thousands of kilometers of pipe across North America. Pipeline integrity often employs the use of inline inspection (ILI) tools known as pigs. These pigs are inserted into a pipeline and pushed along the pipeline by the flow of product. ILI tools have multiple functions, and can be used to clean and assess the condition of the pipeline, as well as to purge different products in a multiproduct pipeline. There is a risk of the deployed pig getting stuck or lost if it is not tracked properly. Locating a lost pig can be costly to the vendors if it is not found quickly and can cause severe damage to the pipeline.

Many legacy tracking providers do not provide a record of each pig passage to prove a pig has actually passed a location. Instead, this is left to the word of the tracker and sometimes is not a reliable source of information. Trackers are not intentionally misleading stakeholders about where a pig is, but traditional methods often make it difficult to tell if a pig has passed or not.

Traditional legacy tracking providers typically use standard geophones to track and identify a pig passage. It is often difficult to determine if a pig has passed because the signal on the geophone is quick and sometimes difficult to hear. This leads to false positives showing a pig has passed even when it hasn’t.

Using more than one sensor to reduce incidents

Using Advanced Pig Tracking, pig passages are detected using multiple sensors to ensure information is defensible and reliable. Advanced tracking systems are equipped with multiple channels. These sensors work simultaneously and reduce incidents of false positives or missed pigs. Not only do these systems come equipped with multiple sensors, but they also provide stakeholders with a record of each pig passage throughout the run.

Sensor for tracking pigs

The record shows the signal of the pig passage as well as the timestamp and pig speed at the specific location. These snapshots can then be uploaded into LiveMap, and are used for real time tracking of the pig’s position, speed, and estimated time of arrival. Conventional above ground markers (AGMs) rely on triggered passage files unlike Advanced Pig Tracking AGMs, which constantly record data when turned on.

To find out more about the other myths of pig tracking, and how Advanced Pig Tracking is more reliable than traditional methods, click the link below.

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Over the past decade, the world has been gripped by many stories of pipeline failures, especially those with severe consequences to the environment and human life. These failures have resulted in billions of dollars in remediation costs, and understandably, this makes pipelines some of the most regulated assets in the world. The use of inline inspection (ILI) tools, such as pigs, is the most common form of pipeline integrity. Pipeline pigs are tools inserted into a pipeline and pushed along by the flow of product through the pipeline. The tool has multiple functions, and can be used to clean and inspect the pipeline, as well as to purge different products in a multiproduct pipeline. When these tools are operating in a live pipeline, it is important to know their precise location and speed, as they are very expensive to replace. A lost or stuck pig can obstruct product flow, causing unwanted service disruptions, or at worst, pipeline ruptures.
Geophone

When tracking a pig through an oil or gas pipeline, it is often difficult to know if it has passed a tracking location, especially for inexperienced pig trackers. The majority of legacy tracking is done only with a standard geophone, a device which converts ground movement into voltage, and relies solely on the word of the technician tracking the pig. By using only a standard geophone, a technician cannot reassure an ILI vendor when the pig has passed a location. The geophone can give a technician many false positives; therefore, the technician’s word will not inspire much confidence in an ILI vendor.

Lack of experience can lead to tracking challenges

To be able to identify a pig passage with only the use of a standard geophone, an experienced tracker needs to reduce the likelihood of error. Many of the trackers who are sent out in the field are inexperienced and are unable to provide this. By solely relying on a standard geophone, field technicians can easily miss a pig passing through a station, and can lead to problems later in the run. Accurate pig tracking requires the right tools and defensible data. Remote tracking can be a more efficient system and provides more concrete data than legacy tracking systems.

Reliable tools and data

The Armadillo Tracks system uses multiple sensors to track every pig deployed into a pipeline. The sensors work simultaneously and record a snapshot of each pig passage. These snapshots prove when a pig has passed a tracking location and helps ILI vendors with benchmarking and reporting. With more reliable tools and data, vendors can have peace of mind knowing problems during a pig run will be minimized.

Technical map generated by Pure & Armadillo Tracks

To learn more about how remote tracking systems benefit ILI vendors and the other myths of pig tracking, download the White Paper here.

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Abstract

Acoustic leak detection inspection tools have become a common technique to identify minute pipeline leakage before the leak and the defect producing it can become a larger problem or even a rupture level event. While these inspection tools only identify small defects once they reach the through wall stage and result in leakage, they can be an effective means of demonstrating the pressure tightness of a pipeline and ruling out the presence of through wall defects that are below the detection threshold of other ILI inspection tools; in so doing finding a way into both the leak detection and pipeline integrity toolboxes.

Enbridge Pipelines owns and operates a 12” pipeline that transports crude oil over 870KM. A majority of the line resides in permafrost conditions in a remote region, thus the window for inspections or work to be done on the pipeline is limited. Additionally the pipeline consists of long segment lengths between traps, which traverse multiple water crossings and experiences large changes in elevation. Therefore, availability, scheduling, and transport of inspection equipment are critical. The SmartBall® leak detection tool was selected for a twofold purpose: to test the technology’s capabilities, and to inspect the line specifically for any leaks.

Inspection of 3 segments of the 12” pipeline provides some unique challenges to inspection providers, requiring tools with up to 12 days of operational run-time capability and the ability to operate in product temperatures as low as -15 degrees Celsius. The generation of SmartBall® tools at the time did not have the run time and data capacity required to inspect the entire length of each of the pipeline segments. As a result, Enbridge and Pure Technologies collaborated on the development of a custom, long duration, high data capacity, SmartBall acoustic leak detection tool specifically for the 12” pipeline application.

Authors

  • Laura Seto, P.Eng., Pipeline Integrity Department, Enbridge Pipelines Inc., Calgary, AB, Canada
  • Tim Ross, P.Eng., Pure Technologies Ltd., Calgary, AB, Canada
Bloomberg TV Story

Initially, owners and operators perceived that once a pipe was constructed and buried, inspecting pipelines was not necessary as long as they were in proper working order. But with the trend of urbanization and development, the risk of operating these pipelines became greater, as leaks or failures can significantly threaten communities and the environment.

The challenge of managing aging pipelines that were not built with the thought of inline inspection is daunting. To best mitigate risk, oil and gas operators should use a multi tool approach that incorporates both real-time and survey-based condition assessment technologies.

SmartBall® leak detection for oil and gas pipelines is an innovative tool that can effectively compliment integrity programs. The tool identifies acoustic anomalies associated with leaks which differ from anomalies created by other sounds and pipeline features. SmartBall technology is highly sensitive and can identify leaks that aren’t typically found using other systems.

 

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Pipeline Leak Detection Systems

Pipeline Leak Detection Systems

Highly accurate inline leak detection systems that can detect leaks and gas pockets in operational pipelines. These systems are used primarily on larger diameter water and wastewater transmission mains of all materials as well as oil & gas pipelines.

Technical Paper

Development of a Long Duration, Free Swimming, Inline Acoustic Leak Detection Inspection Tool

Acoustic leak detection inspection tools have become a common technique to identify minute pipeline leakage before the leak and the defect producing it can become a larger problem or even a rupture level event. While these inspection tools only identify small defects once they reach the through wall stage and result in leakage, they can be an effective means of demonstrating the pressure tightness of a pipeline and ruling out the presence of through wall defects that are below the detection threshold of other ILI inspection tools; in so doing finding a way into both the leak detection and pipeline integrity toolboxes.