Pipeline pigging

Pipeline pigs are devices that are placed inside the pipe and traverse the pipeline.

Uses

Pigs may be used in hydrostatic testing and pipeline drying, internal cleaning, internal coating, liquid management, batching, and inspection. Fig. 1 shows several types of pipeline pigs.

• 

  Fig. 1—Types of pigs (courtesy of AMEC Paragon).

Hydrostatic testing

Pigs are used during hydrostatic testing operations to allow the pipeline to be filled with water, or other test medium, without entrapping air. The pig is inserted ahead of the fill point, and water is pumped behind the pig to keep the pipe full of water and force air out ahead of the pig. Pigs are then used to remove the test waters and to dry the pipeline.

Pipeline cleanup

Operations may conduct pigging on a regular basis to clean solids, scale, wax buildup (paraffin), and other debris from the pipe wall to keep the pipeline flow efficiency high. In addition to general cleaning, natural-gas pipelines use pigs to manage liquid accumulation and keep the pipe free of liquids. Water and natural-gas liquids can condense out of the gas stream as it cools and contacts the pipe wall and pocket in low places, which affects flow efficiency and can lead to enhanced corrosion.

Batch transportation

Pigs are used in product pipelines to physically separate, or “batch,” the variety of hydrocarbons that are transported through the line. Product pipelines may simultaneously transport gasoline, diesel fuel, fuel oils, and other products, which are kept separated by batching pigs.

Prevention of solid accumulation and corrosion

Crude-oil pipelines are sometimes pigged to keep water and solids from accumulating in low spots and creating corrosion cells. This can be especially necessary when flow velocities are less than 3 ft/sec. Multiphase pipelines may have to be pigged frequently to limit liquid holdup and minimize the slug volumes of liquid which can be generated by the system.

Coating

Pigs may be used to apply internal pipe coatings, such as epoxy coating materials, in operating pipelines. Pigs may also be used with corrosion inhibitors to distribute and coat the entire internal wetted perimeter.

Inspection

Pigs are being used more frequently as inspection tools. Gauging or sizing pigs are typically run following the completion of new construction or line repair to determine if there are any internal obstructions, bends, or buckles in the pipe. Pigs can also be equipped with cameras to allow viewing of the pipe internals. Electronic intelligent, or smart, “pigs” that use magnetic and ultrasonic systems have been developed and refined that locate and measure internal and external corrosion pitting, dents, buckles, and any other anomalies in the pipe wall.

Intelligent pigs

The accuracy of location and measurement of anomalies by the intelligent pigs has continued to improve. Initially, the electronics and power systems were so large that intelligent pigs could be used only in lines 30 in. and greater in size. The continued sophistication and miniaturization of the electronic systems used in the intelligent pigs has allowed the development of smaller pigs that can be used in small-diameter pipelines. Newly enacted DOT pipeline-integrity regulations and rules acknowledge the effectiveness of the intelligent pigs and incorporate their use in the pipeline-integrity testing process.

Pig launchers and receivers

Pigging facilities and considerations should be incorporated into the pipeline system design. Basic pigging facilities require a device to launch the pig into the pipeline and a receiver system to retrieve the pig as shown in Fig. 2. The launcher barrel is typically made from a short segment of pipe that is one to two sizes larger than the main pipeline and is fitted with a transition fitting (eccentric reducer) and a special closure fitting on the end. The barrel is isolated from the pipeline with full-port gate or ball valves. A “kicker” line, a minimum of 25% capacity of the main line, is tied from the main pipeline to the barrel, approximately 1 1/2 to 2 pig lengths upstream of the transition reducer, to provide the fluid flow to “launch” the pig into the pipeline. The barrel is fitted with blowdown valves, vent valves, and pressure gauges on the top and drain valves on the bottom. The length of the barrel is determined by the length and number of pigs to be launched at any one time. Receivers have many of the same features.

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  Fig. 2—Typical sphere launcher and receiver traps (courtesy of AMEC Paragon).

Hinge type closure

A typical hinge-type closure for pig launching and receiving traps consists of a forged hub, a hinged blanking head, split-yoke clamps, operating bolts, and a self-energizing O-ring gasket. Materials of construction are in accordance with American Society for Testing and Materials (ASTM) specifications and manufacture complies with applicable rules of the American National Standards Institute (ANSI) code for pressure piping and with the American Society of Mechanical Engineers (ASME) boiler and pressure vessel code.

Most important is the pressure warning safety device with yoke positioning plate. This safety device provides visual and mechanical assurance that the yokes are in the correct position over the head for commencement of operations. Additionally, the devices serve the purpose of alerting the operator to any residual pressure in the pig launcher or receiver trap should he inadvertently attempt to open the closure before all pressure has been relieved. A pressure warning device is located at each of the yoke splits with one of the positioning lugs attached to each yoke half. Tightening the holding screw on the nipple provides a seal and locks the hinged positioning plate on the positioning lugs. Loosening the holding screw breaks the seal and provides a means by which the operator can determine whether the pig launcher or receiver trap has been completely relieved of internal pressure. Continued loosening of the hold screw will allow disengagement of the positioning plate from the positioning lugs, permitting the yoke halves to be spread and the closure to be opened. There are several manufacturers of end closures, but most often Tube Turns or Modco closures are used worldwide.

Elbows and bends

Elbows and pipe bends installed in the pipeline should have a minimum radius of three times the main-line pipe diameter—3D bends. Intelligent pigs may require greater radius to diameter elbows and bends because of the longer length of the pigs. Tees installed in the pipeline with an outlet size 75% of the main-line inner diameter (ID) should be equipped with bars across the tee outlet to prevent the pigs from attempting to turn into the tee and lodging in the line. Hot taps greater than 6-in. diameter added to the pipeline should be barred. If possible, tees should not be installed adjacent to one another. Check valves should be full open, and the pigs or spheres should be sized such that the pig or sphere is larger than the “bowl” cavity of the check valve.

Pig selection

Pig runs of between 50 to 100 miles are normal, but pig runs exceeding 200 miles should be avoided as the pig may wear and get stuck in the line. Cleaning pigs may be constructed of steel body with polyurethane cups or discs and foam pigs with polyurethane wrapping, solid urethane disc, and steel body with metallic brushes. Drying pigs are usually low-density foam or multicup urethane. The intelligent pigs may be:

• Magnetic flux leakage
• Ultrasonic
• Elastic/shear wave
• Transponder/transducer
• Or combinations thereof

Internal-coating pigs are generally multicup urethane type. Batching pigs are typically bidirectional, multidisk rubber, which maintain efficiency up to 50 miles. Pigs used for obstruction inspection are typically urethane, multicup type fitted with an aluminum gauge plate or a gel type.

Spheres are generally sized to be approximately 2% greater diameter than the pipe internal diameter. Cups and discs are typically sized to be 1/16 to 1/8 in. larger in diameter than the pipe ID. Foam pigs have to be significantly oversized. Foam pigs 1 to 6 in. in diameter should be oversized by 1/4 in.; foam pigs 8 to 16 in. in diameter should be oversized 3/8 to 1/2 in.; foam pigs 18 to 24 in. in diameter should be oversized 1/2 to 1 in.; and foam pigs 28 to 48 in. in diameter should be oversized 1 to 2 in.

Slug catchers

The receiving end of the pipeline should have surge containment to accommodate the slugs of liquid carried by the pigs. For liquid lines, additional storage capacity (tankage) will provide surge containment. Gas and multiphase lines need specially designed "slug" catcher systems to handle the intermittent liquid slugs generated by the pigging activities. When a normal gas flow is pushing the pig through a gas pipeline, the velocity can be quite large and the flow rate of liquids being pushed ahead is given by

 (Eq. 1)
where

QL	=	liquid-flow rate in front of the pig, B/D,
Qg	=	gas-flow rate behind the pig, MMscf/D,
T	=	temperature, °R,
P	=	line pressure, psia,
and
Z	=	compressibility factor, dimensionless.

In most systems, the instantaneous liquid-flow rate and "energy" surge ahead of the pig will exceed the processing design capacity and capability of the receiving facility. The slug catcher provides excess storage capacity within the receiving facility and helps dissipate the excess energy generated by the high-velocity liquid slug. The basic slug catcher is essentially a liquid-separation system where the incoming liquid enters a larger-diameter pipe or a vessel, which provides additional volume for the liquid surge and provides for separation of the vapor from the liquid stream. The additional volume provided by the slug catcher reduces the stream velocity and dissipates the excess energy produced by the liquid slug.


Another typical slug-catcher design employs an inline liquid header system attached to a series of horizontal liquid accumulators which may be several hundred feet in length. The liquid-slug stream enters the header and disperses into the accumulators, while the gas continues through the system and exits at the vapor-outlet collection header. The slug catcher may incorporate vortex breakers or other impingement devices to slow the liquid and mist extractors at the vapor outlet to capture entrained liquids. The liquid is transferred from the accumulators to the facility processing or storage. Fig. 3 shows an example slug-catcher design.

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  Fig. 3—Typical slug catcher for two-phase flow-front elevation (courtesy of AMEC Paragon).
 
• 

  Fig. 3—Typical slug catcher for two-phase flow-front elevation (courtesy of AMEC Paragon).

The volume of the slug catcher is expressed as
 (Eq. 2)
where

(Vol)SC	=	volume of slug catcher, bbl,
Vol	=	volume of liquid holdup, bbl,
and
Qd	=	design liquid dump rate from the slug catcher, B/D.

 (Eq. 3)
where TR = time during which slug is processed, in days. The volume of the slug catcher should be designed with a minimum 25% safety factor.

Nomenclature

QL	=	liquid-flow rate in front of the pig, B/D,
Qg	=	gas-flow rate behind the pig, MMscf/D,
T	=	temperature, °R,
P	=	line pressure, psia,
Z	=	compressibility factor, dimensionless.
(Vol)SC	=	volume of slug catcher, bbl
Vol	=	volume of liquid holdup, bbl
Qd	=	design liquid dump rate from the slug catcher, B/D.
TR	=	time during which slug is processed, in days

Source: http://petrowiki.org/Pipeline_pigging

Crack on Offshore Pipeline

PIPELINE MAINTENANCE: Magnetic leakage detection used to spot, measure pipeline cracks

A standard axial configuration high-resolution inspection vehicle.

Magnetic flux leakage (MFL) inspection is the most commonly used tech-nology for the inspection of in-service pressurized pipelines. It is estimated that about 80% of line inspection missions are carried out using this technique. The technique is robust and reliable, and advances over the last 25 years have resulted in high resolution inspection systems that achieve accurate and repeatable measurement of defects in the pipeline. High quality inspection can be achieved with minimal disruption to daily operations.

The traditional use of MFL technology has been the detection and measurement of metal loss defects, primarily corrosion, and this is the inspection mission for which the technology is best known. What is less well known is that high resolution MFL technology can be used and adapted for the location and measurement of cracks in the pipeline, in circumferential and longitudinal directions.

Principles of inspection

The basic physics of the technique are very well known. The pipe-wall is magnetized axially by a pair of magnet and bristle rings at each end of the magnetizer vehicle. Any disruption to the flow of magnetic field in the pipeline steel, as caused by metal loss in the wall, will cause disruption to and leakage of the field. It is this leakage that is detected and measured by the sensors on board the inspection vehicle.

The axial configuration was initially chosen as the most practical engineering solution and because this configuration enabled the inspection vendor to detect and measure those defects that most commonly occurred in pipelines and were of the most concern to pipeline operators. There are some shortcomings in this technique when looking for defects that have a more longitudinal component. These shortcomings can be addressed by altering the magnetic configuration of the inspection vehicle.

Circumferential cracking

A standard grey scale output of inspection data from the PII tool. The girth weld can be seen in the center of the plot.

The most common form of circumferentially aligned crack-like defect occurs within the girth weld. Girth weld defects, introduced during construction, can include incomplete weld passes, stop-start, unauthorized weld repairs, and cracking caused by inadequate heat treatment of the weld area.

As these defects are circumferentially aligned, and therefore at right angles to the flow of magnetic flux, they can cause a disruption and leakage of the field that is readily detected. However, the fact that these defects by their very nature are within a girth weld, poses significant technical challenges.

The girth weld itself presents a barrier to axial flux flow, causing a large disturbance to the signal, which can mask defects within the weld. In addition, and perhaps more significantly, the protrusion of the weld bead into the pipeline bore can cause the MFL sensors to "lift off" the inside of the pipe wall.

If the vehicle is traveling at normal pipeline speeds and the sensor design has high inertia, then a dead zone can be created both at the girth weld and for some distance downstream of the girth weld. This means that inspection vehicles cannot detect defects within the girth weld, and indeed for some distance beyond it. In some cases, this non inspected dead zone can be as much as 200 mm.

When a high resolution inspection vehicle was first developed by PII in the mid-1970s, these shortcomings in available technologies were recognized. The initial specification of the vehicle performance required that 100% of the pipeline be reliably inspected, including the girth weld and the area around it. So care was taken at the very start of the project to ensure that full inspection capability was not compromised by the presence of the girth weld.

The first problem, that of the large and sometimes confused signal generated by the weld, was tackled by using the very high magnetic field of the PII tool (necessary to saturate the pipe wall and generate repeatable signals from small defects). This, coupled with the very high sensor density of the high-resolution tool, means that the signal from normal girth welds is remarkably repeatable, and any abnormality in the weld can be easily identified.

Designing the sensor heads themselves to have very low mass solved the more serious problem of sensor lift-off. This design, coupled with very light spring suspension, means that the sensor carrier has low inertia and 'bends' with the weld bead, traveling over it smoothly rather than bouncing off the pipe wall.

The fact that all girth weld anomalies are by definition very short in the axial direction can pose problems for the analyst. It can be difficult to discriminate between the various types of defects that can occur in girth welds. The solution lies in the experience and training of data analysts. The first girth weld crack was identified and confirmed in the early 1980s. Since that time, we have located and confirmed more than 1,000 girth weld cracks in operational pipelines.

Longitudinal cracking

A further example of NAEC illustrates the view achieved by this technique.

The extent of the flux leakage created by a pipe wall anomaly, and therefore the size of the signal collected by the in-line inspection device, is affected by the width of the anomaly. A circumferentially wide defect will set up greater opposition to the flux induced by the tool, and a larger signal will result.

The reverse also holds true. As a longitudinally aligned defect becomes narrower, its opposition to flux flow diminishes, and the resultant signal will decrease in magnitude. The extreme of this phenomenon is demonstrated by the fact that longitudinally aligned cracks cannot be detected using conventional magnetic flux leakage technology.

The result is that with inspection devices carrying only a few MFL sensors, a longitudinally aligned defect will not be detected. With high-resolution tools the high sensor density enables the defect to be detected, but the reduction of the signal strength can lead to an underestimation of the size of the defect.

The defects that have been recognized as present in some pipelines and designated as narrow axial external corrosion (NAEC) are very rare in PII's experience, as they are not only narrow but are longitudinally orientated, axially long and relatively smooth in profile.

Following the discovery of NAEC on one particular pipeline, the data from the previous MFL inspections of that line was examined closely by a PII-client team. Although it was confirmed that the inspection tool had collected data from these defects, the level of signal was such that the depth of the NAEC had indeed been underestimated.

An attempt was made to create algorithms that would recognize the character of NAEC, and correct the sizing model to compensate for the problem and predict depth more accurately. This project met with some limited success, but was found not to be 100% reliable for the purpose of establishing confidence in the condition of the pipeline, given the extent of the NAEC phenomenon.

Transverse field inspection

Samples of the Transcan data are shown alongside sections of the actual defects that were excavated and removed from the pipeline.

If metal loss that is long and narrow will not produce signal strengths compatible with accurate sizing when the magnetic field is longitudinal, then another approach is to magnetize the defect in the orthogonal direction. This means that a tool had to be devised and constructed that would magnetize the pipe in the circumferential direction.

Theoretically, this means that the signal obtained will be far more prominent and will allow more accurate characterization. In addition, the axial extent of the defect should be clearer.

The idea of applying the magnetic field in the transverse direction is not new. AMF (formerly American Machine and Foundry) was probably the first to develop the idea as part of their mill inspection technology in the 1960-1970 period and patented a rotating transverse field system in 1978.

PII also examined it.

The reason these designs and prototypes never came to fruition was due to a limitation of the technology available at the time, rather than in the technique itself. Data in the 1970s was usually stored on reel-to-reel recorders, and displayed on UV sensitive paper. Given the advances in computing techniques, materials science, and electronics since then, confidence that a solution for the problem of long narrow defects could be achieved was high. However, without a commercial impetus, the technique was probably destined for obscurity. The discovery of NAEC and several long seam defect failures in North America provided the impetus to develop a commercially viable inspection system. A prototype, dubbed the Transcan tool was designed, constructed, and launched within a five week period and collected good quality data on its first inspection run of more than 200 km.

Analysis of the data and subsequent excavation revealed that the tool did provide an improved characterization of NAEC. This was particularly promising when considering that both the tool and the analysis technique were first attempts. The short times cales available for right-of-way access meant that only a limited amount of information could be gathered from field excavations, but the wealth of data obtained from the excavations carried out in 1996 means that extensive detailed correlation is possible.

Hook cracking

Encouraged by this success, PII refined the process still further to build an in-line inspection tool that would reliably detect and characterize long seam defects. This work was encouraged by one client who had experienced operational failures caused by hook-cracking in a 20-in. crude oil pipeline.

Defects, such as hook cracks and lack of fusion, have caused many in-service and hydrotest failures, especially in liquid lines subject to pressure cycling. Hook cracks occur when inclusions at the plate edge are turned out of the plane of the steel during the pipe manufacturing and welding process. These may pass the initial hydrotest, but fail later through fatigue-induced cracking. It is the turning out of the metal at the weld which gives the crack its characteristic "hook" or "J" shaped appearance.

Although such defects can be det-ected by manual non-destructive testing (NDT) methods, they have remained largely outside the domain of automated methods and in-line tools, which are used for the mass inspection of pipelines. Until recently, the only option was to hydrotest the line. This has limitations in as much as it gives an "all or nothing" or "yes/no" indication. It is not a quantitative technique.

Severe defects are identified through failure, but no information is conveyed about less significant defects which may themselves grow to criticality within a short time after the test. To ensure these defects are found, repeated testing at frequent intervals is required. In addition, following a hydrotest where there has been a failure, the line must be repaired and hydrotested repeatedly until there are no more failures. This is costly in terms of effort and lost throughput.

In this case, the service failures experienced in this 1500-km-long, 20-in. pipeline had resulted in a significant reduction in throughput for the pipeline, with subsequent loss in revenue, and a regulatory requirement to hydrotest the entire pipeline, at a projected cost of tens of millions of dollars.

In the spring of 1998, PII developed a high-resolution 20-in. Transcan tool carrying 400 primary sensors, which was laboratory tested and used to inspect 140 miles of 20-in. pipeline. The tool was successful. In order to validate the technology, the client excavated the reported defects and repaired and hyrotested the line. Two separate sections of the line, totaling 118 miles, were hydrotested to 125% MOP without failures.

More than 50 hook-cracks were detected by the tool and validated by "in the ditch" NDE. The smallest was 5-10% of pipe-wall thickness (Fig 11 and 12). In addition, many examples of lack of fusion and stitching, and three examples of cracks within dents were detected. Only two of the cracks verified would have failed a hydrotest at 125% MOP. The hydrotest requirement was lifted and following the inspection and repair of the remainder of the 1500-km line, full operating pressure was restored.

During the course of the remaining inspection, many hundreds of long-seam defects were revealed and repaired.

The Transcan has been used to inspect over 4,000 km of pipeline, and plans are to extend the range up to 42 in. and down to 8-in., with a 6-in. tool being a distinct possibility in the future.

Stress corrosion cracking

Given its sensitivity to axial features, would TFI be able to detect stress corrosion cracking? Recent work on behalf of the operator of a refined products line has shown some initial promise. Specifications of the line are seamless, 12-in. in diameter, 100 km in length, wall thickness of 6.35-7 mm X52 & X60 grade steel, and is 30 years old.

The pipeline had suffered from several failures due to stress corrosion cracking (SCC) and regulatory authorities required that the operating pressure be reduced from 90 bar to 60 bar and a program of hydrotesting be implemented. To investigate the capability of detecting SCC, a test program was undertaken on samples of defective pipe.

In parallel, a 12-in TFI tool was prepared for a trial run in the pipeline. The results from this run have been analyzed, and reporting will be followed up by proving excavations. The laboratory tests showed that it was possible to observe some colonies of SCC using the Transcan technique. However, as always, the true test is in the ability to discriminate these signals from other features in the line, such as manufacturing variations, corrosion sites, surface roughness, etc.

In parallel with this investigative inspection program, extensive testing was carried out on the Transcan tool using known colonies of SCC installed in a pull through string. TFI is not intended to be a primary inspection tool for SCC (ultrasonic tools probably offer the best performance here), but any success in this area is regarded as a bonus on top of its capability at inspection for axial metal loss features and defects in long seam welds.

Third party damage

During the inspection and subsequent repair of the 20-in. pipeline described previously, several instances of third party damage were located and confirmed. - Shown is an instance of third party damage uncovered on this pipeline.

As third party damage is the largest cause of pipeline failure in most countries, we feel that the technology has potential to allow pipeline operators to not only detect, but also characterize these kinds of defects. A development program has begun in the US with the Battelle Institute, the Gas Research Institute, and the Office of Pipeline Safety. This program should allow the development of a system for accurate location, identification, and characterization of this difficult-to-detect defect.

Crack-like defects in operating pipelines have long been the most difficult defect to locate using in-line inspection techniques. For many years, the pipeline industry has had to rely on the inexact science of hydrotesting to mitigate risk from failure due to cracking. New tools are superior to hydrotesting, technically and financially.

Source: http://www.offshore-mag.com/articles/print/volume-60/issue-11/news/pipeline-maintenance-magnetic-leakage-detection-used-to-spot-measure-pipeline-cracks.html

Offshore Pipeline Buckling

Understanding pipeline buckling in deepwater applications

Finite element model predicts local conditions

D. DeGeer - C-FER Technologies

With ultra deepwater pipelines being considered for water depths of nearly 3,000 m, pipe collapse, in many instances, will govern design. For example, bending loads imposed on the pipeline near the seabed (sagbend region) during installation will reduce the external pressure resistance of the pipeline, and this design case will influence (and generally govern) the final selection of an appropriate pipeline wall thickness.

To date, the deepest operating pipelines have been laid using the J-lay method, where the pipeline departs the lay vessel in a near-vertical orientation, and the only bending condition resulting from installation is near the touchdown point in the sagbend. More recently, however, the S-lay method is being considered for installation of pipelines to water depths of nearly 2,800 m. During deepwater S-lay, the pipeline originates in a horizontal orientation, bends around a stinger located at the stern or bow of the vessel, and then departs the lay vessel in a near-vertical orientation. During S-lay, the installed pipe experiences bending around the stinger (overbend region), followed by combined bending and external pressure in the sagbend region.

Initial bending in the overbend during pipe installation may result in stress concentrations in pipe-to-pipe weld offsets or in pipe-to-buckle arrestor interfaces.

In light of these bending and external pressure-loading conditions, analytical work was performed to better understand the local buckling behavior of thick-walled line pipe due to bending, and the influence of bending on pipe collapse. Variables considered in the analytical evaluations include pipe material properties, geometric properties, pipe thermal treatment, the definition of critical strain, and imperfections such as ovality and girth weld offset.

Design considerations

As the offshore industry engages in deeper water pipeline installations, design limits associated with local buckling must be considered and adequately addressed. Instances of local buckling include excessive bending resulting in axial compressive local buckling, excessive external pressure resulting in hoop compressive local buckling, or combinations of axial and hoop loading creating either local buckling states. In particular, deepwater pipe installation presents perhaps the greatest risk of local buckling, and a thorough understanding of these limiting states and loading combinations must be gained in order to properly address installation design issues.

Initial bending in the overbend may result in stress concentrations in pipe-to-pipe weld offsets or in pipe-to-buckle arrestor interfaces. Initial overbend strains, if large enough, may also give rise to increases in pipe ovalization, perhaps reducing its collapse strength when installed at depth. Active bending strains in the sagbend will also reduce pipe collapse strength, as has been previously demonstrated experimentally.

Overall modeling approach

In an attempt to better understand pipe behavior and capacities under the various installation loading conditions, the development and validation of an all-inclusive finite element model was performed to address the local buckling limit states of concern during deepwater pipe installation. The model can accurately predict pipe local buckling due to bending, due to external pressure, and to predict the influence of initial permanent bending deformations on pipe collapse. Although model validation is currently being performed for the case of active bending and external pressure (sagbend), no data has been provided for this case.

The finite element model developed includes non-linear material and geometry effects that are required to accurately predict buckling limit states. Analysis input files were generated using our proprietary parametric generator for pipe type models that allows for variation of pipe geometry (including imperfections), material properties, mesh densities, boundary conditions and applied loads.

A shell type element was selected for the model due to increased numerical efficiency with sufficient accuracy to predict global responses. The Abaqus S4R element is a four-node, stress/displacement shell element with large-displacement and reduced integration capabilities.

All material properties were modeled using a conventional plasticity model (von Mises) with isotropic hardening. Material stress-strain data was characterized by fitting experimental, uniaxial test results to the Ramberg-Osgood equation.

Pipe ovalizations were also introduced into all models to simulate actual diameter imperfections, and to provide a trigger for buckling failure mode. This was done during model generation by pre-defining ovalities at various locations in the pipe model.

Bending case

A pipe bend portion of the model was developed to investigate local buckling under pure moment loading. Due to the symmetry in the geometry and loading conditions, only one half of the pipe was modeled, in order to reduce the required computational effort. The pipe mesh was categorized into four regions

• Two refined mesh areas located over a length of one pipe diameter on each side of the mid-point of the pipe to improve the solution convergence (location of elevated bending strains and subsequent buckle formation)
• Two coarse mesh areas at each end to reduce computational effort.

Clamped-end boundaries were imposed on each end of the pipe model to simulate actual test conditions (fully welded, thick end plate). Under these assumptions, the end planes (nodes on the face) of both ends of the pipe were constrained to remain plane during bending. Loading was applied by controlled rotation of the pipe ends.

In terms of material properties, the axial compressive stress-strain response tends to be different from the axial tensile behavior for UOE pipeline steels. To accurately capture this difference under bending conditions, the upper (compressive) and lower (tension) halves of the pipe were modeled with separate axial material properties (derived from independent axial tension and compression coupon tests).

In general, the local compressive strains along the outer length of a pipe undergoing bending will not be uniform due to formation of a buckle profile. In order to specify the critical value at maximum moment for an average strain, four methods were selected based on available model data and equivalence to existing experimental methods.

Collapse case

The same model developed for the bending case was used to predict critical buckling under external hydrostatic pressure. This included the use of shell type elements and the same mesh configuration. In the analyses, a uniform external pressure load was incrementally applied to all exterior shell element faces. Radially constrained boundary conditions were also imposed on the nodes at each end of the pipe to simulate actual test conditions (plug at each end). In contrast to the pipe bend analysis, only a single stress-strain curve (based on compressive hoop coupon data) was used to model the material behavior of the entire pipe.

Bending case validation

The pipe bend finite element model was validated using full-scale and materials data obtained from the Blue Stream test program, both for “as received” (AR) and “heat treated” (HT) pipe samples. Geometrical parameters were taken from the Blue Stream test specimens and used in the model validation runs. Initial ovalities based on average and maximum measurements were also assigned to the model. The data distribution reflects the relative variation in ovality measured along the length of the Blue Stream test specimens.

All of finite element models included analysis input files generated using parametric generator for pipe type models that allows for variation of pipe geometry (including imperfections), material properties, mesh densities, boundary conditions, and applied loads.

Axial tension and compression engineering stress-strain data used in the model validation were based on curves fit to experimental coupon test results. As pointed out previously, separate compression and tension curves were assigned to the upper and lower pipe sections, respectively, in order to improve model accuracy.

In the validation process, a number of analyses were performed to simulate the Blue Stream test results (base case analyses), and to investigate the effects of average strain definition, gauge length, and pipe geometry. These analyses, comparisons and results were:

• The progressive deformation during pipe bending for the AR pipe bend showed the development of plastic strain localization at the center of the specimen
• A comparison between the resulting local and average axial strain distributions for two nominal strain levels indicated that at the lower strain level the distribution of local strain is relatively uniform, at the critical value (peak moment) a strain gradient is observed over the length of the specimen with localization occurring in the middle, the end effects are quite small due to specimen constraint and were observed at both strain levels
• The resulting moment-strain response for the AR pipe base case analysis found the calculated critical (axial) strain slightly higher than that determined from the Blue Stream experiments
• The effect of chosen strain definition and gauge length on the critical bending strain for the AR pipe base case analysis, using the four methods for calculating average strain, gave similar results
• The critical strain value is somewhat sensitive to gauge length for a variety of OD/t ratios
• The finite element results are seen to compare favorably with existing analytical solutions and available experimental data taken from the literature. For pipe under bending, heat treatment results in only a slight increase in critical bending strain capacity.

Collapse case validation

Similar to the pipe bending analysis, the plain pipe collapse model was also validated using full-scale and materials data obtained from the Blue Stream test program, both for “as received” (AR) and “heat treated” (HT) pipe samples. Pipe geometry and ovalities measurements taken from the Blue Stream collapse specimens were used in the validation analyses. Initial ovalities based on average and maximum measurements were also assigned to the model at different reference points. Hoop compression stress-strain data was used in the model, and was based on the average of best fit curves from both ID and OD coupon specimens, respectively. To validate the pipe collapse model, comparison was made to full-scale results from the Blue Stream test program which demonstrated a very good correlation between the model predictions and the experimental results.

In addition to the base case, further analyses were run for a number of alternate OD/t ratios ranging from 15 to 35. Similar to the pipe bend validation, the OD/t ratio was adjusted by altering the assumed wall thickness of the pipe. The finite element results have compared favorably with available experimental data taken from the literature.

The beneficial effect of pipe heat treatment for collapse has resulted in a significant increase in critical pressure (at least 10% for an OD/t ratio of 15). The greatest benefit, however, is observed only at lower OD/t ratios (thick-wall pipe). This can be attributed to the dominance of plastic behaviour in the buckling response as the wall thickness increases (for a fixed diameter). At higher OD/t ratios, buckling is elastic and unaffected by changes in material yield strength.

Pre-bent effect on collapse

Finite element analyses were also performed to simulate recent collapse tests conducted on pre-bent and straight UOE pipe samples for both “as received” (AR) and “heat treated” (HT) conditions. The intent of these tests was to demonstrate that there was no detrimental effect on collapse capacity due to imposed bending as a result of the overbend process. In the pre-bend pipe tests, specimens were bent up to a nominal strain value of 1%, unloaded, then collapse tested under external pressure only.

To address the pre-bend effect on collapse, a simplified modeling approach was used whereby the increased ovalities and modified stress-strain properties in hoop compression due to the pre-bend were input directly into the existing plain pipe collapse model (the physical curvature in the pipe was ignored).

To address this loading case, a simplified modeling approach was used whereby the increased ovalities and modified stress-strain properties in hoop compression due to the pre-bend were input directly into the existing plain pipe collapse model (the physical curvature in the pipe was ignored).

A comparison between the predicted and experimental collapse pressures for both pre-bent and straight AR and HT pipes indicates that the model does a reasonable job of predicting the collapse pressure for both pipe conditions. It is also clear that the effect of moderate pre-bend (1%) on critical collapse pressure is relatively small.

While the pre-bend cycle results in an increased ovality in the pipe, this detrimental effect is offset by a corresponding strengthening due to strain hardening. As a result, the net effect on collapse is relatively small. For the AR pipe samples, there was a slight increase in collapse pressure when the pipe was pre-bent. Conversely, for the HT pipe, the opposite trend was observed. This latter decrease in collapse pressure can be attributed to two effects: the larger ovality that resulted from the pre-bend cycle and the limited strengthening capacity available in the HT pipe (the HT pipe thermal treatment increased the hoop compressive strength, offering less availability for cold working increases due to the pre-bend).

Similar to previous experimental studies on thermally aged UOE pipe, the beneficial effect of heat treatment was demonstrated in the pre-bend analysis. The collapse pressure for the pre-bent heat treated (HT) pipe is approximately 8-9% higher than that for the as received (AR) pipe, based on both the analytical and experimental results. This increase, however, is lower than that observed for un-bent pipe (approximately 15-20% based on analysis and experiments).

This unique case of an initial permanent bend demonstrated that the influence on the collapse strength of a pipeline was minimal resulting from an increase in hoop compressive strength (increasing collapse strength), and an increase in ovality (reducing collapse strength). This directly suggests that excessive bending in the overbend will not significantly influence collapse strength.

Future work includes advancing the model validation to the case of active bending while under external pressure. This condition exists at the sagbend region of a pipeline during pipelay and, in many cases, will govern overall pipeline wall thickness design.

Source: http://www.offshore-mag.com/articles/print/volume-66/issue-11/pipeline-transportation/understanding-pipeline-buckling-in-deepwater-applications.html