[Article Sharing] Pipeline Gooseneck

Gooseneck (Piping) | Wikipedia

Source: https://en.wikipedia.org/wiki/Gooseneck_(piping)

Gooseneck vent with check valve being repainted

A gooseneck (or goose neck) is a 180° pipe fitting at the top of a vertical pipe that prevents entry of water. Common implementations of goosenecks are ventilator piping or ducting for bathroom and kitchen exhaust fans, ship holds, landfill methane vent pipes, or any other piping implementation exposed to the weather where water ingress would be undesired. It is so named because the word comes from the similarity of the pipe fitting to the bend in a goose's neck.

Gooseneck may also refer to a style of kitchen or bathroom faucet with a long vertical pipe terminating in a 180° bend.

To avoid hydrocarbon accumulation, a thermosiphon should be installed at the low point of the gooseneck.

[Article Sharing] Pipeline Decommissioning

UK pipeline decommissioning provides potential for innovation | Offshore Magazine

by Mick Borwell - Oil & Gas UK

Source: http://www.offshore-mag.com/articles/print/volume-74/issue-2/engineering-construction-installation/uk-pipeline-decommissioning-provides-potential-for-innovation.html

Since 1966, 45,000 km (27,962 mi) of pipeline has been installed in the North Sea to transport hydrocarbons from the UK continental shelf (UKCS) to shore. Of this pipeline, less than 2% has been decommissioned.

The UK government and industry continue to focus on maximizing recovery of around 15-24 Bboe from the UKCS, and 2013 brought record investment in new projects. Collaborative work has resulted in fiscal change and technological advances, but as the basin continues to mature, decommissioning is emerging as a parallel and growing business opportunity.

Decommissioning expertise is available within the UK supply chain, but without significant activity in this area, the sector has not been fully tested. To help contractors better understand the opportunities, Oil & Gas UK has produced several documents.

In its "Decommissioning Insight" published in 2013, the association forecasts that between 2013 and 2022 more than 2,300 km (1,429 mi) of pipeline, infrastructure from 74 fields, more than 70 subsea projects, and about 130 installations are scheduled for decommissioning at a total forecast expenditure of £10.4 billion ($17 billion).

Inventory of UKCS pipelines

The pipelines mentioned in the forecast represent a fraction of the extensive network of pipeline currently installed in the North Sea to transport oil and gas production to host platforms or to shore. Overall, the UKCS pipeline inventory covers a broad range of equipment designed to accommodate the transportation of many different fluids under diverse conditions, varying water depths, and different oceanographic environments.

In many cases, the existence of nearby pipeline infrastructure has led directly to the exploitation of marginal fields that would otherwise be uneconomic. Such opportunities remain a key factor in the timing of any pipeline decommissioning. A more detailed description of the different types of pipeline infrastructure can be found in Oil & Gas UK's 2013 report, "The Decommissioning of Pipelines in the North Sea Region."

Trunklines represent the major element of subsea infrastructure transporting large quantities of oil and gas from offshore to onshore receiving facilities and end users across Europe. They account for 18% of the total number of pipelines and 63% of the total pipeline length in the North Sea inventory.

Such pipelines include some of the longest in the North Sea, often with diameters of more than 30 in., and tend to be installed offshore using the S-lay pipelay method from a specialist lay vessel.

The pipeline inventory also includes rigid flowlines, flexible flowlines, umbilicals, and power cables, as well as associated equipment such as the concrete mattresses used extensively in the UKCS to provide protection and stability to subsea pipelines, cables, and umbilicals. These flexible mattresses are typically manufactured by joining different shapes of concrete blocks together with polypropylene or Kevlar rope. Oil & Gas UK estimates that 35,000-40,000 mattresses have been deployed since operations began in the North Sea.

While pipelines are integral to field life extension and future development opportunities, some fields in the UKCS have reached the end of their economic life. Specific parts of the pipeline system naturally become redundant, and with no potential future use, they are available to be decommissioned.

Seven Navica reeling vessel. (Image reproduced with permission from Subsea 7)

Decommissioning to date

Oil and gas pipeline decommissioning has been taking place in the North Sea since the early 1990s, when the Crawford field pipelines were decommissioned. Since then, pipeline decommissioning has continued at a modest rate and only when all potential reuse options for the infrastructure, including new field developments, have been carefully considered.

Less than 2% of the North Sea pipeline inventory has been decommissioned, and of the pipelines which have been decommissioned, 80% are less than 16-in. in diameter. Half of the larger diameter pipelines (16 in. or greater) decommissioned to date were removed; these were all infield pipelines less than 1 km (0.6 mi) long. The longest large diameter trunkline to be decommissioned so far is the 35-km (21.7-mi) Piper A to Claymore 30-in. export line, which was decommissioned in situ.

Under current regulations, decommissioning of oil and gas pipelines is considered on a case-by-case basis using the comparative assessment (CA) process to determine the best option for decommissioning. The CA process enables the particular diameter, length, and configuration of individual pipelines to be taken into account when considering decommissioning options against the criteria of safety, environmental impact, cost, and technical feasibility.

Health and safety is a dominant factor in any CA, with the focus aimed at minimizing the long-term risks to other users of the sea and the short-term risks to those carrying out decommissioning operations. An integral part of the process is the environmental impact assessment, which is prepared to support all pipeline decommissioning plans.

Each decommissioning solution needs to be considered on its individual merits, as pipeline installations vary widely according to model, location, environment, and maintenance status. It is at the CA stage, when a number of options are considered, that significant opportunities exist for supply chain companies to develop innovative technologies for decommissioning pipelines.

Opportunities for innovation

When evaluating a preferred option for decommissioning a pipeline and its associated equipment, the availability and track record of technology used in previous projects provides the context for the other key CA criteria of safety, environmental impact, and cost.

Supply chain companies specializing in particular services will have the opportunity to develop innovative techniques in the key technology areas for pipeline decommissioning, many of which are in their infancy. These are:

• Pipeline cleaning
• Trenching, burial, and de-burial
• Subsea cutting
• Lifting
• Reverse installation methods
• Mattress removal.

Pipeline cleaning is performed prior to decommissioning and involves the depressurization of a pipeline and the removal of any hydrocarbons in accordance with the Pipelines Safety Regulations. At this stage there are opportunities for companies skilled at minimizing the potential contamination of the marine environment.

The technology for trenching and burial of pipelines during installation is well established, and a number of contractors offer a range of trenching tools capable of trenching and burying pipelines of various diameters in all soil types. There is, however, limited experience of existing pipelines, laid on the seabed surface, being buried specifically for decommissioning in situ.

While there are different methods and types of equipment for cutting pipelines subsea using "cold cutting" tools such as abrasive water jets, diamond wire cutting, reciprocating cutting, and hydraulic shears, significant opportunities exist for contractors capable of developing new technologies to improve these techniques. These might include automated techniques to help reduce the use of divers in these activities. Lifting sections of infrastructure from the seabed is another area where innovative thinking is in demand. The "cut and lift" process of decommissioning requires cut sections of pipeline to be lifted from the seabed to a transportation vessel; supply chain companies providing innovative cutting techniques could help increase efficiency in this area by reducing the duration of lifting operations for long lengths of pipeline.

Reverse installation methods encompass both reverse reeling and reverse S-lay techniques. The process by which rigid or flexible pipelines can be recovered from the seabed by reeling them from the seabed using a specialist reel vessel is known as "reverse reeling."

For rigid pipe, there are a limited number of specialist reel vessels available from the leading installation contractors. These vessels are usually engaged in installation activities, but can be adapted to recover pipelines as part of a decommissioning project. Subsea 7's Seven Navica is one vessel capable of performing this work.

For larger diameter and concrete coated trunklines, the industry is considering a reversal of the S-lay installation process by which pipelines could be removed and recovered on to the deck of a specialist S-lay vessel. However, this has not been done in the North Sea, and more study is needed before the technique can be considered feasible for decommissioning long distance large diameter pipelines.

As yet, no established technique or technology has been universally adopted for mattress recovery. Solutions developed by contractors will need to take into account the age and condition of the mattresses being recovered.

Regional variations

Oil & Gas UK's 2013 "Decommissioning Insight" highlights the contrast between different UKCS basins, noting that in the central and northern North Sea (CNS and NNS), decommissioning of pipelines and mattresses is estimated to cost more than £400 million ($655 million) from 2013 to 2022. Over this period, nearly 40 trunklines (130 km/81 mi), 115 rigid and flexible flowlines (420 km/261 mi), 87 umbilicals (250 km/155 mi), and almost 900 mattresses have been identified for decommissioning in these basins.

The forecast indicates significant expenditure will take place from 2019 to 2022, suggesting that pipeline decommissioning will occur toward the latter end of decommissioning programs. The peak in 2019 can be attributed to at least 10 pipeline decommissioning projects.

While containing a similar number of pipelines to the southern North Sea (SNS), the decommissioning of rigid and flexible flowlines in the CNS and NNS basins is more expensive, suggesting a greater degree of complexity in these regions.

Over the same period in the SNS and the Irish Sea, four trunklines (64 km), 116 other pipelines (1,300 km/808 mi), and 21 umbilicals (150 km/93 mi) will be decommissioned at a cost of around £100 million ($164 million). Additionally, 2,100 mattresses have been scheduled for decommissioning.

While these decommissioning activities represent a fraction of the overall market of oil and gas activities, they are part of a burgeoning sector. By making more information on decommissioning available, Oil & Gas UK aims to help the industry prepare for decommissioning projects, increase the efficiency of processes involved, and help ensure that future projects are enabled by an "at the ready" supply chain.

[Article Sharing] Hydrate in Subsea Pipeline

Hydrate problems in production | PetroWiki

Source: http://petrowiki.org/Hydrate_problems_in_production

Natural-gas hydrates are ice-like solids that form when free water and natural gas combine at high pressure and low temperature. This can occur in gas and gas/condensate wells, as well as in oil wells. Location and intensity of hydrate accumulations in a well vary and depend on:

• Operating regime
• Design
• Geothermal gradient in the well
• Fluid composition
• Other factors

Detailed reviews of gas-hydrate chemistry, physics, and oilfield engineering are found in Makogon and Sloan. This page focuses on prevention, inhibition, and removal of hydrates in production. Other pages provide more detail on hydrate formation and predicting hydrate formation.

Special situations

Shut-in gas wells are particularly prone to serious hydrate problems, if the well has been producing some water. Subsequent equilibration of the tubular and its contents with cold zones of the rock can lower the temperature into the hydrate-formation region. Hydrate nuclei form from the films of water on the tubular walls. The subsequent crystallization can result in large plugs of hydrate tens or hundreds of meters long.

Hydrate formation also can take place within a shut-in oil well, generating a slurry of solid that is capable of accumulating and plugging the pipe. The logic is that oil will dissolve some water—generally small amounts. Under high-temperature/high-pressure (HT/HP) conditions, the amounts can be 5 to 10 mol% (at 300°F). The oil is produced up the wellbore, temperature falls, and liquid water comes out of solution, remaining in suspension as microdroplets. In a static condition, the microdroplets gradually coalesce and precipitate. This liquid water is saturated with gas so that hydrates can form at the appropriate pressure/volume/temperature (PT) values.

Controlling hydrate formation

The first step in controlling hydrate formation is to understand which pressure and temperature conditions/locations in the specific system are conducive to gas hydrate formation. A number of computer simulators are available for this purpose, usually as adjuncts to more general phase PVT simulators. The models vary in how well they compute the chemical activity of the water phase, the effect of higher-molecular-weight hydrocarbons, and the effect of hydrate inhibitors (see the discussion that follows). A comparative assessment of models is given in Sawyer. Fig. 1 shows the results of simulations with one of the models—the line is computed, the dots are experimental points. Besides the dissociation PT points for the hydrate, the information required and derivable from such models is the amount of hydrate formed, the composition of all phases, and the distribution of inhibitors throughout all phases.

Fig. 1 - Simulated and experimental gas hydrate equilibrium diagram for a natural-gas mixture (points are experimental)

The second control step is the comparison of this information with the measured or expected PT profile within the production system. A method of coping with hydrate formation is then selected (e.g., producing the hydrocarbons under conditions that avoid the hydrate PT formation zone or using a suitable inhibition method. The simulator should also be capable of evaluating the consequences of the inhibitor strategy. An example of adjusting production conditions to avoid hydrate formation is PT curves for producing wet gas at various rates.

Inhibitors

The alternative to production control is the use of inhibitors. These are classified as:

• Environmental inhibitors
• Thermodynamic inhibitors
• Kinetic inhibitors

The conceptually simplest “environmental inhibition” method is to dry the gas before it is cooled—remove the water and hydrates so they cannot form. This involves adsorption onto, for example, silica gel, or cooling and condensation, absorption of water into alcohols, or adsorption onto hydroscopic salts.

“Thermodynamic inhibition” has been the most common method for controlling gas hydrates. There are a number of alternatives:

• Heating the gas
• Decreasing pressure in the system
• Injecting salt solutions
• Injecting alcohol or glycol

One method of providing heat to the hydrate-formation zone is the use of electrical-resistance heating via cables connected to a transformer. Another is placing the choke in a sufficiently hot zone of the production system. The injection of salts (primarily CaCl2) reduces hydrate formation by lowering the chemical activity of water, and by lowering the solubility of gas in water.

The last alternative is used more frequently now with a transition from methanol to ethylene glycols for health, safety, and environment (HSE) reasons. The general effect of such inhibitors is shown in Fig. 2 (not a total removal of the problem but a shift of the hydrate-formation curve to lower temperatures, ostensibly outside the PT production regime). It is possible to compute thisphase diagram for gas/water/methanol or the glycols with reasonable accuracy. The major drawback to this inhibition technique is the large quantity of methanol or glycol required. This impacts both operating costs and logistics, particularly important for offshore wells and pipelines.

Fig. 2 - A general phase diagram illustrating the effect of inhibitors on hydrate prevention

Such problems have resulted in the search for kinetic hydrate inhibitors —low-dosage chemicals that prevent the growth of hydrate nuclei or prevent the agglomeration of nuclei into large crystals (also called “threshold hydrate inhibitors”). Klomp, et al. describes the field testing of such inhibitors. The compounds were primarily quaternary ammonium salts; polymeric n-vinyl-2-pyrrolidone was particularly effective. The application of kinetic hydrate inhibitors to black-oil flowlines is described in Pakulski, et al. The additive here was a methanol-based solution of the polymer n-vinyl, n-methyl acetamide-covinyl caprolactam (“VIMA-VCap”). In the example given, the dose rate was low (0.5 gal/D in 16 B/D of produced water). Nonpolymeric gas hydrate inhibitors have been successfully field tested on an offshore platform containing gas lift injection wells, and they have been used in long wet-gas subsea pipelines. A novel gas hydrate inhibitor controlling hydrate formation during startup uses a borate-crosslinked gel system; this inhibited gel system ostensibly also exhibits fracturing-fluid performance equal to that of more conventional borate-gel systems.

Removal of solid hydrates

Solid hydrates are removed with many of the same chemicals and technology used to inhibit hydrate formation. The simplest method is, if possible, to reduce pressure above the hydrate plug sufficiently enough to reverse the equilibrium reaction. Addition of solvents, such as alcohols and glycols, is the most common technique (well completions will often provide for a methanol-injection line). An example of hydrate-plug removal with coiled-tubing jetting from a deepwater test well is given in Reyma and Stewars. Chemical heating, such as described for wax removal, has been used. See also hydrate plug removal

[Article Sharing] Crack on Offshore Pipeline

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

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

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

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

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

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.

[Article Sharing] Pipeline Construction

Pipeline Construction | Canadian Energy Pipeline Association

Source: http://www.cepa.com/about-pipelines/pipeline-design-construction/pipeline-construction

Pipeline construction is divided into three phases, each with its own activities: pre-construction, construction and post-construction.

Pre-Construction

- Surveying and staking

Once the pipeline route is finalized crews survey and stake the right-of-way and temporary workspace. Not only will the right-of-way contain the pipeline, it is also where all construction activities occur.

- Preparing the right-of-way

The clearly marked right of way is cleared of trees and brush and the top soil is removed and stockpiled for future reclamation. The right-of-way is then leveled and graded to provide access for construction equipment.

- Digging the trench

Once the right-of-way is prepared, a trench is dug and the centre line of the trench is surveyed and re-staked. The equipment used to dig the trench varies depending on the type of soil.

- Stringing the pipe

Individual lengths of pipe are brought in from stock pile sites and laid out end-to-end along the right-of-way.

Construction

- Bending and joining the pipe

Individual joints of pipe are bent to fit the terrain using a hydraulic bending machine. Welders join the pipes together using either manual or automated welding technologies. Welding shacks are placed over the joint to prevent the wind from affecting the weld. The welds are then inspected and certified by X-ray or ultrasonic methods.

- Coating the pipeline

Coating both inside and outside the pipeline are necessary to prevent it from corroding either from ground water or the product carried in the pipeline. The composition of the internal coating varies with the nature of the product to be transported. The pipes arrive at the construction site pre-coated, however the welded joints must be coated at the site.

- Positioning the pipeline

The welded pipeline is lowered into the trench using bulldozers with special cranes called sidebooms.

- Installing valves and fittings

Valves and other fittings are installed after the pipeline is in the trench. The valves are used once the line is operational to shut off or isolate part of the pipeline.

- Backfilling the trench

Once the pipeline is in place in the trench the topsoil is replaced in the sequence in which it was removed and the land is re-contoured and re-seeded for restoration.

Post Construction

- Pressure Testing

The pipeline is pressure tested for a minimum of eight hours using nitrogen, air, water or a mixture of water and methanol.

- Final clean-up

The final step is to reclaim the pipeline right-of-way and remove any temporary facilities.

[Article Sharing] Pipeline Welding Technology

NEW WELDING TECHNOLOGIES PROVIDE DRAMATIC ADVANTAGES FOR ON-SITE PIPE WELDING | LINCOLN ELECTRIC

Source: http://www.lincolnelectric.com/en-us/support/application-stories/Pages/sunland-surface-tension-transfer-welding.aspx

The installation of gas pipe through the designated wetland areas of Mississippi and Alabama could prove challenging for any contractor, but the thick-walled pipe specified on the Gulfstream Project presented new welding challenges for contractor Sunland Construction Inc. Because the pipe is two times as thick as that typically used, Sunland relies on innovative welding techniques to decrease the number of weld passes necessary and most importantly, to assure the welds produced are consistent, x-ray quality.

Sunland Construction Inc., headquartered in Eunice, Louisiana, turned to The Lincoln Electric Company's Autoweld® automatic orbital pipe welding system for the fill and cap passes and the STT® (Surface Tension Transfer®) process to lay the critical root pass. By implementing these new welding technologies, Sunland has been able to remove one electrode pass from the root pass process as well as eliminate all grinding from this step. With the Autoweld system, the company has reduced the time to put in the fill and cap passes.

"We have realized dramatic improvements since using the new Lincoln welding systems in both higher quality and time savings," said Joe Ratcliff, Project Manager for Sunland Construction Inc. "Our welders are proud of the new equipment, it has made the welding portion of this job run smoothly."

Gulfstream Project

The Gulfstream Project is a natural gas pipeline that originates near Pascagoula, Mississippi and crosses the Gulf of Mexico to Manatee County, Florida. Once onshore, the pipeline stretches across south and central Florida to Palm Beach County. This natural gas pipeline will serve Florida utilities and power generation facilities, generating 1.1 billion cubic feet per day of additional natural gas - enough to supply electricity for 4.5 million homes.

Sunland Construction Inc.'s portion of the pipeline includes installation of 6.1 miles of 36" diameter pipe in Jackson County, Mississippi and 9 miles in Mobile County, Alabama.

A 27-year-old company with five divisions, Sunland won the Gulfstream job through a competitive bid process. More than 250 employees are being utilized on this project - taking a total of seven months to complete. Sunland expects its portion of the Gulfstream project to be wrapped up in early 2002.

According to Ratcliff, preparing for pipe installation on this job is no small feat. "Before we can even begin to weld, we must first clear the land, prepare a right of way, install piling in some areas, erect construction bridges and bring in additional soil where need. Because of the conditions of the wetland areas, all welding crews have to work on large, 4 ft. x 20-ft. timber mats. These mats, sometimes put down in a number of layers, provide a stable, dry work surface. Once work is complete in an area, Sunland Construction Inc. is also responsible for restoring the surrounding area to its original condition.

"Welding for this job is completed with three crews, one welding right after the other," noted Ratcliff. "The first crew installs the root pass, the second crew immediately follows using stick welding to accomplish a hot filler pass, and then the Autoweld crew completes the welding process with fill and cap passes."

Because of the extreme conditions on the site, the Autoweld process is performed inside of a welding "house" or modular unit that is lifted and moved every 40 ft. (from joint to joint) by a Caterpillar Challenger with a side boom.

The Pipe

Pipe for the on-land portion of the Gulfstream Project is provided by Berg Steel Pipe Corporation of Panama City, Florida and its parent company, Europipe GmbH of Germany. The X70 pipe ranges in wall thickness from 0.635 to 1.22. This thick-walled pipe was specified so the pipeline could handle the pressure range of the Gulfstream system. Pipe is coated with a Fusion Bond Epoxy (FBE) on both the interior and exterior, and a majority of the pipe is also concrete coated for buoyancy control.

Root Pass

Sunland Construction Inc. utilized the STT process because of the advantages it offered.

STT is a modified MIG process that uses high frequency inverter technology with advanced Waveform Control to produce high quality welds while also significantly reducing spatter and smoke. STT technology has the ability to control weld puddle heat independently of wire feed speed - this allows the welder more control over the puddle and provides the ability to adjust the heat input to achieve the desired root bead profile. The welder simply positions the arc on the forward portion of the weld puddle and follows it around the pipe in a vertical down fashion.
With the system, Sunland welders can achieve a uniform gap by using an internal, pneumatic clamp to line up and space the pipe for accurate welding.

For the Gulfstream Project in particular, STT is able to produce a quality weld and allows an increased amount of weld metal to be placed on the heavy wall pipe for improved resistance to cracking. With STT, Sunland only has to make one pass for the root bead as compared to two passes plus grinding time with stick.

"Since the root pass is the foundation for the rest of the weld, achieving a high quality, strong and uniform weld is very important to us," said Ratcliff. "We are very pleased with the STT. It has allowed us to save time and is an easy system for our welders to learn. The STT process is very forgiving, meaning that it helps compensate for misalignments, if and when necessary."

The two STT machines on the Gulfstream job site are used in conjunction with Lincoln's .045 L-56™ SuperArc® wire and 100 percent CO2 shielding gas. As compared to blended gases, CO2 is able to provide better penetration and is less expensive.

"The STT is able to apply a root bead with great consistency over a wide variety of joint conditions" explained Ratcliff.

Hot Filler Pass

Once the root pass is complete, the next team of welders follows closely behind to weld in the hot filler pass. Due to the thickness of the pipe on this job, Sunland Construction Inc. elected to put a single downhill hot filler pass over the root with a downhill, low hydrogen stick process. "The added filler metal we deposited at this stage gives us additional backing to lay the first wire filler and means that we don't have to make quite as many passes with the Autoweld system," noted Ratcliff.

To do this interim step, Sunland is using Lincoln's LH-D 80 rod with a conventional 300-amp Lincoln belt-driven welder.

Fill and Cap

For the Gulfstream Project, Sunland Construction Inc. decided to invest in an automated process to weld the fill and cap passes. Previously, Sunland has been completing the fill and cap passes with a 70+ stick electrode, welded vertical down and requiring numerous passes.

"We wanted an automatic method to increase efficiencies and decrease overall costs," said Ratcliff. "It was also important for us to find a system that could provide a quality product but yet was easy to operate.

In its quest, the company contacted a number of manufacturers to research which system would work best in this application. "We narrowed down our choices and visited a couple of manufacturers to try out their systems, one of those being Lincoln Electric," noted Ratcliff. "Our team traveled to Lincoln's Cleveland headquarters where we had the opportunity to run our procedures on an actual Autoweld set-up. After we returned, we listed the pros and cons of every system and Lincoln's Autoweld came out on top. A big factor in our decision was the amount of technical support that Lincoln could provide to us."
The Autoweld system is enclosed in a house, so that welding can be done out of the elements. These houses are moved by sidebooms ( Challengers ) from one length of pipe to the next. Sunland uses six Caterpillar Challengers with PTO driven generators to produce the 100 amps at 460 volts needed to operate the Autoweld and accessories.

Lincoln's Autoweld system uses a specially designed lightweight-welding head to travel around the circumference of the pipe. In addition, the unit utilizes an external crawler band placed on the pipe to one side of the field joint weld bevel. Two machines operating simultaneously complete the vertical up welding - one machine starts at the bottom with the other starts on the side. Once the machine that started on the side reaches the top, it then is positioned to start at the bottom to complete its side of the pipe. Using the vertical up process is a break from the traditional, vertical down welding typically utilized for pipe.

Each wall thickness of pipe requires different machine settings for each specific pass. These settings are charted and can easily be set from the machine. The Autoweld system uses a flux core .052" wire and a shielding gas of 25 CO2/75 argon.

With Autoweld, Sunland Construction Inc. is achieving repetitiously consistent, x-ray quality welds. "Autoweld makes a very consistent, uniform, and precision-controlled metal deposit," noted Ratcliff. "The weld has high tensile strength and good Charpy values in the weld and pipe heat zones. The machine is also very durable and dependable."

Sunland's Autoweld system is powered by an Invertec® V350-PRO, an extremely lightweight inverter that is able to handle multi-process applications. The hallmark of this power source is an extremely smooth arc due to the unit's advanced inverter technology.

"We feel the V-350 is the state of art in welding equipment, it gives you the ability to maintain precise settings and arc performance," claimed Ratcliff. "Even after long hours of use on our construction site, the machine was dependable."

Quality Control

All welds once completed are visually inspected and then x-rayed with an internal crawler. All welds must meet API 1104 Section 9 requirements.

Service

Sunland Construction Inc. has been extremely pleased with the service it receives from Lincoln. "The on site support provided by the Lincoln Electric Mobile team of Troy Gurkin and Steven Brown has been superb," said Ratcliff. "We also enjoyed tremendous support from the Cleveland based Autoweld group including Eric Stewart, Autoweld technician, who was on site for much of the project. Lincoln has gone out of its way to help us implement our new processes and suggest new technologies when appropriate."

Sunland has also taken advantage of Lincoln's training programs on-site and in Cleveland. "Lincoln was challenged with taking welders at all different levels of expertise and work with them to learn to understand and operate the Autoweld system. It was a massive training effort that required quite a bit of Lincoln's time. We appreciate all they have done to make this job run smoothly."

Future

Sunland Construction Inc. is already planning on how the new STT and Autoweld machines can be used on future jobs to increase efficiencies.

[Article Sharing] Pipeline Integrity Management

A step-by-step approach to pipeline integrity management | Pipelines International

by Karine Kutrowski, Murielle Bouchardy, Audrey Le Mercier, Rodolphe Jamo, and Jean-Charles Andraud, Bureau Veritas, Paris, Fran

Source: http://pipelinesinternational.com/news/a_step-bystep_approach_to_pipeline_integrity_management/077277/

Figure 1: An example of a threat-based methodology;figure 2: PIM continuously improving loop. An example of threat-based methodology; figure 3: Bureau Veritas' network

As a testing, inspection and certification company acting in the field of asset integrity management, Bureau Veritas is in contact with many different operators. In the oil and gas market, all operators are preoccupied by the availability and integrity of their assets (structure, pressure vessels, rotating machinery, pipelines). This article explains the importance of implementing an integrity management system using a step-by-step approach.

The 360° view

In the early 1990s asset integrity management was addressed by increasing inspection programmes. In the late 1990s, increasingly sophisticated IT tools were developed, and today a complex mix of strategies, IT solutions and inspections are often employed. This can potentially lead to client dissatisfaction, since from an operator’s point of view ‘it costs a lot, it’s complicated and we’re not sure we really need it’.

Bureau Veritas attended a conference where an operator presented on the issues involved in implementing a highly sophisticated integrity management system. In particular the issue of anticipating difficulties related to methodologies, data, management of change, etc. In response, Bureau Veritas explained the difficulties of taking on such a wide scope at once. The operator immediately replied: “Guys, you have the 360° view, we don’t. You should teach us all that and warn us!”

No revolution but simply common sense

There are many different definitions of pipeline integrity management (PIM), including those listed within API 1160 and ASME B31.8S.

As a simple and understood-by-all definition, the following is proposed: “a system to ensure that a pipeline network is safe, reliable, sustainable and optimised.”

Bureau Veritas’ PIM step-by-step approach is comprised of the following six stages:
Policy and strategy: where are you now, where do you want to go and what should you put in place to reach your target?
Methodology: do you want/need to use a risk-based, threat-based or consequence-based approach or something else?
Data: start thinking about data collection and modelling only once the policy and strategy, and methodology have been identified.
Systems and tools: once policy and strategy have been defined, methodology has been selected and data gathered, select the most appropriate tool to use (simple or sophisticated software).
Study and analysis: the tools will enable an assessment of the pipeline network and definition of your inspection plans.
Inspection and expertise: after implementing the inspection plans, specific expertise should be used to analyse the inspection results. The knowledge gained will then be used during the regular PIM review.

Company policy and methodology is key

As a first step, it is important to properly define the roots of the PIM approach chosen. Local constraints, in-house specific requirements, international guidelines and adequacy will help set up the basis of the methodology to be developed.

The most appropriate approach will be found by referencing the local regulatory body’s policy (safety/inspections-oriented or risk/threat mitigation-oriented) along with common practices and existing procedures, the assets’ typology and age, the existing international best practices, and the level of in-house expertise. Several approaches may be considered, such as qualitative versus quantitative, threat-based versus damage-based, and probabilistic versus deterministic.

The identification of expected results (primary target) should be properly specified: restricted impact on the environment, corrosion-related failure prevention, inspection strategy, and means of mitigation. This will ensure that the PIM is set up in-line with the project targets.

The PIM methodology can then be chosen and tailored to the specific case.

A PIM approach that may be suitable for one operator may not be acceptable for another operator.

Only once the methodology is developed and understood by all project stakeholders can the data and tool issues be properly addressed.

Data and tools: you don’t need a video game

Data management is a crucial task within the PIM process. It should provide a complete system capable of delivering the right data in the right shape, at the right place and for the right purpose. This requires very organised and step-wise work.

By defining the PIM strategy, key performance indicators can be identified and data requirements can be defined. This refers to the format, accuracy, and frequency requirements of the data. It is also beneficial to think mid-term about PIM requirements, for example, consider the tools that will be used and any modifications that might be planned to the asset.

Finally, it is advised that data quality control/quality assurance is performed to obtain the ‘green light’ before processing data into the PIM process.

The same applies to the tools to be used. While there is a temptation to use a very ‘high tech’ tool, the most important consideration is for an easy-to-use tool that will monitor the health of the pipeline network and point out pipeline segments which require mitigation or inspection due to their threat or risk levels.

Depending on the pipeline’s length, a Microsoft Excel macro could be sufficient. However, an automated and integrated tool is necessary for longer pipelines or complicated networks.

Study and analysis: from integrity assessment to inspection plans

Now with an operational and clear pipeline database along with a PIM tool, the chosen PIM methodology can be implemented. The PIM tool will enable the first integrity assessment to be carried out – ‘first’ because PIM is a continuous loop where previous results are used to improve the following assessments. Following this, a ‘pipeline prioritisation’ can be obtained, which will form the basis to analyse and understand the pipeline network’s condition. Frrom here, the PIM can be expanded to include a mitigation plan plus inspection plan.

Here an important question arises: what actions should be performed in order to reduce the threat/risk level on the pipeline? Should the inspection frequency be increased, a mitigation action applied, or both? The decision should rely on the inspection and mitigation policies defined in the first step of the PIM process.

Inspection and expertise: method qualification and trustworthy results

Undoubtedly, one of the most visible steps of the PIM process is the inspection itself. There are many inspection techniques for pipelines but the most widely used are magnetic-flux leakage and ultrasonic testing. The in-line inspection provider should be selected very carefully, evaluating their qualification by referring to the specific requirements of the project.

The most critical part of this process is the analysis of results and the expertise required to obtain crucial information on the actual condition of the pipeline.

An effective PIM should be comparable to a high-quality management system.

This article started by outlining that a PIM is a system allowing operators to ensure that their pipeline networks operate in a safe, reliable, sustainable and optimised way.

If neglected and unused, even the most expensive and ‘high tech’ PIM solution will fail to be beneficial. A PIM needs to be accepted and embedded into the company’s processes.

Therefore, as a conclusion, Bureau Veritas would advise operators to keep in mind that a PIM, like a quality management system, is a continuous process. Therefore it is important to break down the PIM plan into manageable steps.