PIPELINE GLOBAL BUCKLING

Pipeline buckling: time to straighten up

With E&P activities moving into deeper waters and harsher onshore environments, oil and gas pipelines are under strain. Despite the best-laid plans, pipeline buckling caused by changes in temperature and pressure can often occur. Peter Don Bosco, Petrofac’s project manager, explains how the effects of buckling can be mitigated or prevented altogether.

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Upheaval and lateral buckling are inherent problems for offshore pipelines where impact must be considered from the initial planning and engineering phases. Onshore lines operating at higher temperatures and different pressures can also experience incidents of lateral and vertical buckling, especially where the pipeline is installed through environments of rolling desert and swampy soils with poor soil cohesion.

The buckling of onshore pipelines can be global and local in nature. Local buckling is mostly confined to specific places on the pipe, whereas global buckling affects entire sections along the pipeline.

"Local buckling is mostly confined to specific places on the pipe, whereas global buckling affects entire sections along the pipeline."

Internal pipeline pressure and temperature often reach higher values during start-up operations than those prevalent during installation/backfilling of the line. Such an increase in temperature and pressure can cause the buried, restrained or partially restrained pipeline to expand during the start-up and operation cycles.

Friction between the pipe surface and the surrounding soil resists the axial expansion of the pipe, which generates a restraining force across the pipe section. Passive soil pressure developed from the sidewalls of the trench restricts lateral expansion of the pipe. Meanwhile, any uplifting of the pipe is resisted by the weight of the pipe and its contents, and the weight of the backfill soil, combined with its sheer resistance.

This restraint against the expansion of the pipe generates axial compression within the pipe section, which can upset the existing equilibrium of the opposing forces. When the axial compressive force exceeds the soil-pipe frictional force, the excess energy will move the pipe through a path of least resistance until a new equilibrium is attained. This movement could either be lateral buckling or upheaval buckling (UHB), while the solid ground below restricts downward movement. The main factors contributing to the UHB of onshore pipelines are:

• high operating temperature: the difference between the installation temperature and the maximum operating temperature causes thermal expansion of the pipe
• high operating pressure: internal fluid pressure results in axial Poisson's tensile component
• pipe diameter and wall thickness: the cross-sectional steel area of the pipe directly affects the thermal expansion force
• topography and ground strata
• of pipeline route: pipelines laid through rolling desert/undulating terrain with poor soil cohesive characteristics have a tendency to buckle upwards
• trench bottom/pipe profile (out of straightness or imperfections): at locations of over-bends where the vertical component of compressive force along the pipe axis exerts higher upward thrust against the friction of the surrounding soil.

The main factors in resisting UHB are:

• pipe weight and content weight: depending on the material used for the pipeline construction and the material being transported
• pipe embedment ratio or breakout ratio: the ratio between backfill height and pipe diameter; for example, deeper soil cover provides greater stability against upward pipe buckling
• unit weight of backfill soil and its cohesiveness: these provide the effective downward load against the uplift force - such properties of soil depend on its specific weight, shear strength and angle of internal friction
• friction between pipe surface and soil adhesion: depends on the type of external pipe coating for a given soil type
• the pipe and the soil forms the engineered system as the pipe-soil interaction provides uplift resistance to the pipeline: upheaval buckling triggers when the vertical component of the axial pipeline force acting upwards exceeds the available resistance force of the soil above, disturbing the existing equilibrium.

Prevention at source

What can be done at the design and planning stages to minimise the risk of UHB? Pipelines should be designed buckle-resistant for the most severe coincident conditions of pressure and temperature, which may occur during start-up and normal operation of the pipelines.

"Pipelines should be designed buckle-resistant for the most severe coincident conditions of pressure and temperature."

The approach at the design and planning stage should, therefore, be to develop a system that incorporates measures to optimise the upheaval buckling driving and resisting forces in a cost-effective manner.

In consideration of the above criteria, lines could be shortlisted in order to focus on obtaining input data specific to buckling-related aspects. The critical areas/sections may be identified for further evaluation while acquiring topographical/geotechnical data. To optimise UHB driving and resisting forces, the following issues must be considered:

• View the expected pipeline temperatures for any possible increase in tie-in temperature resulting in the reduction of the buckle-driving force.
• Review the material grade of the pipe to establish the wall thickness that will generate the optimum smaller axial force due to thermal expansion. A sectional area of steel causes higher axial force due to thermal expansion that causes buckling.
• The normal depth of the pipe cover is determined based on the stability of the installed pipe during its lifecycle and considering the general terrain features. The stability of the pipeline in its installed position depends on the local profile. The governing factors for the pipe to remain in that position are the constrained axial force and the pipe flexural rigidity.
• For pipeline alignment and profile, avoid sharp peaks and hummocks along rolling terrains. Smooth the right of way profile by cutting/grading at peaks. Where feasible, bypass areas of loose boulders and sections that are prone to washout. At locations susceptible to buckling, implement a deeper trench to reduce the bend angles and increase soil cover weight above.

There are also technological innovations that can help to overcome UHB. Because UHB is closely allied with offshore pipelines, the technological innovations on the mitigation measures are more prevalent in the offshore industry. Some innovative techniques can be transferred to onshore pipelines in order to overcome potential UHB issues. These include:

• use of selected suitable backfill material, stabilisation of backfill/crown and provision of stone riprap
• stabilisation of over-bend sections by placing rocks, extra soil, mattresses, berms/dumps or geo-textile wraps over them
• place continuous riprap stone pitching over the pipeline to enhance effective backfill weight
• placing saddle/set-on weights, concrete slabs, articulated concrete mats or sand bags on the pipe
• concrete coating of pipes
• using screw anchors can be an option where the terrain soil is unstable and has poor load-bearing capacity
• continuous or intermittent use of geo-textiles to increase the effectiveness of the soil, rock-dumps and berms
• in areas of non-cohesive soil, the buried pipeline may be installed with added slackness (in snaking configuration) so that the likely axial expansion will be distributed more uniformly and directed sideways over the turning points
• where sections with steep slopes and sharp bends are unavoidable, explore the possibility of reducing wall thickness of the pipe by substituting higher grade material in order to decrease the buckle driving axial force due to thermal expansion.

Once laid, the following inspection and measurement techniques allow UHB to be monitored:

• Accurate as-built data should be gathered progressively during the pipeline installation and the pipe profile/pipe cover should be verified against the design requirements of UHB. Any discrepancies should be rectified by deepening the trench or by installing extra cover or stable crowns, as necessary.
• Any significant upheaval of the pipeline could be identified during the routine patrolling drives/flights along the pipeline route. Upheaval buckling causes the backfill soil to be pushed upwards and, in the case of severe upheavals, the pipe would protrude out of the ground. Immediate remedial measures should be carried out to protect the exposed section and to prevent the buckling spreading to adjoining pipes.
• Locations susceptible for upheaval buckling - such as sharp over-bends and areas prone to occasional flooding and washout/subsidence - should be inspected more closely.
• Periodical intelligent pigging reports will provide data on the relative movements of pipe in relation to its baseline positions. The trend of any significant movement of the pipe can be derived from such reports and, based on the results, mitigation measures against potential upheaval can be implemented as necessary.

International collaboration

A unified approach in the R&D of UHB prevention and mitigation techniques seems inadequate within today's onshore pipeline industry; however, a number of individuals and organisations have been performing research in developing methods to assess UHB risks quantitatively.

Though a convergence in the identification and quantification of the upheaval driving forces has emerged, there is a varied approach on the establishment of the upheaval resistance forces and its quantification. The pipe and the soil together form the engineered system where the pipe-soil interaction results from the nonlinear (elastic-plastic) soil spring behaviour.

Based on theoretical soil mechanics and laboratory/field investigations, calculations have been developed for arriving at design factors for resistance related to the soil types. Recently, some pipeline operators have started specifying the requirements for UHB analysis and the implementation of mitigation measures; however, given the variety of environments in which pipelines are laid, is it possible to completely eradicate the risk of UHB?

"The key to implementing viable mitigation measures against upheaval risk lies with the availability of data on the variety of environments in which pipelines are laid."

The key to implementing viable mitigation measures against upheaval risk lies with the availability of data on the variety of environments in which pipelines are laid. Prudent detailed engineering, based on reliable topographic and geotechnical survey input, followed by quality installation work can significantly exclude the risk of upheaval buckling of a pipeline.

While engineers can calculate the uplifting forces fairly accurately by taking into consideration the longitudinal profile of the pipeline, determination of available downward resistance forces along the pipeline route passing through terrain with varying geophysical conditions remains tedious. In the absence of location-specific topographic and geotechnical data, engineers adopt more conservative input data for such calculations.

Risks may increase in the future as E&P gradually moves to harsher environments. Harsher areas of undulating and unstable terrain with non-cohesive soil will, by definition, be more prone to upheaval buckling. While UHB risks could be assessed reasonably well based on field data obtained through the latest survey techniques, the cost of implementing the measures to mitigate such risks would tend to be high. Reliable and more location-specific terrain and soil data should always be acquired.

Software programmes for pipeline stress analysis also need to be more flexible. This would allow for the incorporation of such input data in order to assess the upheaval buckling accurately and thereby develop cost-effective mitigation measures.

(Sumber : http://www.worldexpro.com/features/featurepipeline-buckling-petrofac/. Diakses tanggal 2 Februari 2014 pukul 17.15 WIB)

PIPELINE MANUFACTURE

Pipe production  

The Australian Pipeliner — October 2010

The pipe-making process comprises three key processes: steel production, pipe manufacture and pipe coating. Within each of these steps, a number of processes are carried out to ensure the manufacture of high quality, functional pipe. BlueScope Steel, Orrcon Steel, OneSteel and Bredero Shaw have opened their factory doors to share the secrets of the pipe-making process with readers of The Australian Pipeliner.

Sourcing steel

The ingredients required for the production of line pipe steels come from all corners of Australia, with iron ore from Western Australia and South Australia, coal from the Illawarra and limestone from Marulan in New South Wales all brought to BlueScope Steel’s Port Kembla operation.

Before the production of steel can begin, high-quality iron – the basic ingredient for steelmaking – needs to be produced. The iron-making process is carefully controlled by blending various grades of iron ore to produce a mix which is exact in its content. Fines of iron ore and coal are also mixed and fused together in a sintering process to form a lumpy feed for charging into the blast furnace, and constitute approximately 60 per cent of the charge.

The last components of the reduction process are coke and limestone. Coke, a strong porous product, is formed by burning coal in ovens and is charged into the blast furnace to support the iron ore and sinter. It is coke which provides the carbon necessary for reducing the iron ore to iron. Limestone is used as a flux or cleaning agent in the reduction process.

These products are charged into either one of two blast furnaces, which are as tall as a 27 storey building and heated by the injection of air and gas to a temperature of 2,300 degrees Celsius. As the charge melts, the molten material makes its way to the bottom of the furnace where it is taken off and stored in refractory-lined ladles awaiting transfer to the next stage of production, where the liquid iron will be converted into steel at a production facility called the BOS or basic oxygen steelmaking.

Prior to this, there is one more important step which is key to the production of high-quality pipeline steel grades – the process of desulphurising the molten steel iron. Sulphur is an undesirable element in pipe steels as it reduces the cleanliness of the steel, decreases the ductility and restricts the weld properties of the final pipe. Once desulphurised, the molten iron is ready for conversion into steel.

In the BOS, iron is converted to steel around 50 times a day, and the Port Kembla operation produces in excess of 5 MMt/a of steel. In the process, the iron, which has a carbon content of around 4 per cent, is refined to levels of less than 1 per cent. It is this process that differentiates iron from steel. A vessel containing a mixture of approximately 300 t of charge, made up of 50 t of scrap and 250 t of iron from the blast furnace, is converted to steel by injection of pure oxygen, which creates a chemical reaction and increases the temperature to 1,700 degrees Celsius. Fluxes are added to absorb the impurities, the scrap melts and the carbon content is lowered to form steel.

The molten steel then moves to the vacuum degassing station where precise additions of the necessary alloys such as niobium, manganese, aluminium and titanium are made to meet the tight specification limits of pipe steels. Then, to further enhance the cleanliness of the steel, the molten steel is injected with a calcium silicide powder, which combines with some of the last remaining impurities and removes them from the molten steel. At this point the final chemical composition of the pipe steel grade is set and the molten steel is transferred to the slab casting facility.

In the slab caster, the steel is poured into a water-cooled mould and drawn through a series of segments, which chill the outer surface and slowly solidify the steel to a stage where it is fully hardened. The continuous strand of steel is then cut to length by automated gas torches to individually designed lengths or slabs. At this stage, the slab is approximately 12 m long and 230 mm thick.

After cooling, the slabs are inspected for any defects that may have been induced during the casting operation. Once the slabs have passed this quality assessment they move onto the final major processing stage where they are converted to a hot rolled strip to the exact dimensional and mechanical property requirements of the customer.

The purpose of rolling the cast slab is two-fold; firstly to achieve the final product dimensions and secondly to produce a finer grain structure; thereby giving the steel greater toughness and strength. In the Hot Strip Mill the slabs are reheated prior to rolling the steel down to its final desired thickness by passing it through a number of rolling stands. BlueScope Steel’s Port Kembla Hot Strip Mill uses six finishing stands to achieve the final desired strip thickness. The strip is then water-cooled on a long ‘run-out’ table prior to coiling. Precise control of slab reheating and rolling temperatures, scale removal, width and thickness ensure that the final strip meets all the dimensional, strength and toughness requirements of the ordered steel grade.

The steel coils are now allowed to cool before being strapped and labelled for despatch to the pipe manufacturing mills.

Producing pipe Before steel is released from the steel mill, it is required by pipe manufacturers Orrcon Steel and OneSteel to have passed various quality tests, including: composition, strength, toughness, surface condition, and coil shape. When steel is despatched from the steel mill, a test certificate is also sent from the steel mill’s data system. When each coil arrives at these plants, checks are performed to ensure there has been no transport damage and that the identity of the coil matches its paperwork, markings and labels. Each coil is then unloaded into the warehouse, and its identity carefully recorded at OneSteel using a barcode process, or at Orrcon Steel using a traceability system called OrrTrace. The coil is then ready to be loaded onto a mill to make pipe.

After identifying the coil, the key stages involved in the pipe making process include:

• Loading the coil into the mill;
• Forming;
• Welding;
• Cut-off;
• Bevelling;
• Hydrostatic testing;
• Ultrasonic inspection; and,
• Marking.

According to OneSteel Piping Systems Quality Assurance Manager Dr John Piper these are merely the manufacturing processes and much of the company’s effort is spent verifying the quality of each pipe as it is made via a multitude of test and inspection processes. These include visual inspection of the coils, weld visual monitoring, cooling process control, preliminary inspection of dimensions and surface quality, mill control ultrasonic testing, sampling for strength, composition and toughness testing, flattening and hydrostatic testing, and the final inspection process. This final process consists of ultrasonic testing, length and mass measurement, visual and dimensional inspection of the weld and body, and the bevel inspection. The outcome against the unique identity of each pipe is recorded to ensure that all pipe has passed all tests before being placed to order.

Orrcon Steel employs approximately 100 people at its Wollongong API Pipe Mill. This includes technical and quality, operations, administrative, maintenance, laboratory, logistics and other support staff. At OneSteel, the number of employees required at the plant is dependent on market demand and whether the company is running one, two or three shifts.

According to Mr Piper, the number of man hours required to make a pipe depends on the section and diameter, which range from 6–18 m in length and 168.3–508 mm in diameter. A production crew at the plant typically produces between 100 and 400 pipes per shift depending on the diameter, thickness, length and grade of the product being produced. Large diameter heavy wall pipe is produced at a slower rate than small diameter light wall pipe, however large diameter heavy wall pipe delivers a much higher output on a tonne per shift basis.

Orrcon Steel Technical Manager – Pipelines and Infrastructure Dr Cameron Dinnis says “Depending on the pipe size, the welding speed will be anywhere from 14–21m per minute. The pipe spends 10seconds at pressure during the hydrostatic test and will spend about one minute being ultrasonically tested. All of this means that the total man hours that go into a pipe can range between 1.5 and 5 hours.”

Welding the seam

As an electric resistance welded (ERW) pipe manufacturer, Orrcon Steel is essentially a manufacturer of weld seams.

To make the seam, the company uses a precise machine to trim the edges of the steel coil in a process known as edge milling, then heats the edges using high frequency electrical current and pushes them together to form the weld. The external and internal weld bead, which is the material that is ejected from the weld area when the strip edges are forced together, is then trimmed off by carbide cutting tools, leaving the weld seam flush with the surface of the pipe. The weld seam is then immediately subjected to an initial ultrasonic inspection. The seam is then heat-treated to ensure the microstructure is suitable for service. Following this, the pipe is tested to ensure that the weld seam and the pipe body have structural integrity and are within dimensional tolerances.

Specifically, the seam is subjected to a hydrostatic test and the full length of the weld seam is subjected to an ultrasonic inspection from both sides by 36 differently angled beams. The inspection frequency is such that a 0.5 mm long defect will be detected five times by each of the 36 angles in the time the ultrasonic probes traverse across it.

OneSteel achieves the weld seam using a similar process. “The integrity of the weld seam is of course, critical to the end use of the pipe so we are very careful in both process control and inspection,” says Mr Piper.

Ensuring a quality product

At OneSteel and Orrcon Steel, quality assurance is a high priority and is addressed on a number of levels. Both companies have third-party accreditation of their quality management systems, product and laboratory practices. They are accredited to ISO 9001 and API Q1, with API Monogramming privileges. Both companies have been accredited by NATA for conducting mechanical tests and chemical analyses.

Orrcon Steel ensures quality at a fundamental level through process control, product inspection and testing regimes. At OneSteel, employees apply the principles of quality, test and inspection systems to ensure that no substandard pipe is placed to order.

Innovation at the mills

In the past decade, Orrcon Steel and OneSteel have introduced and successfully implemented numerous technical innovations at their pipe manufacturing plants.

Orrcon Steel has introduced the following methods at its Wollongong Pipe Mill:

• Edge milling, which involves machining the edge of the coil to provide clean and sound surfaces to weld together, resulting in higher weld integrity;
• Cage-forming: an automated pipe-forming technology that is designed to cradle the coil as it is deformed into a pipe, resulting in lower forming strains;
• On-line monitoring of welding parameters and heat treatment parameters;
• Phased array ultrasonic technology, which allows the generation of various ultrasonic beams from the one transducer;
• Integration of pipe mill data with construction management systems using OrrTrace;
• Long-lengths, with the capability to produce pipe up to 24 m in length; and,
• Testing and examination: computer-controlled Ring Expansion yield strength determination.

In the past ten years, OneSteel has:

• Rebuilt its Ultrasonic Inspection systems;
• Increased mill capability to 508 mm diameter in both X70 and X80 grades;
• Upgraded mill drives and pipe handling capability to cope with heavier sections;
• Implemented weld line accelerated cooling capability to enhance weld line toughness;
• Developed improved steel compositions in conjunction with steel manufacturers; and,
• Upgraded the plant’s computerised factory control, test and inspection data management systems.

Industry challenges

There are a number of challenges facing the pipeline industry today. Dr Dinnis of Orrcon Steel says that one of the main challenges is “ensuring that the pipeline industry recognises the value provided by local manufacturers, versus foreign economies, in terms of compliance with and understanding of local design specifications”.

Dr Dinnis adds “The intermittent nature of pipeline projects, particularly from a pipemaking perspective, ensures that the companies that make up the Australian pipeline industry must be able to operate very flexibly and allocate resources appropriately.”

Meanwhile, OneSteel is pleased that the pipeline and other industry segments are improving following the global financial crisis. “There are continuing demands on the pipemaker to increase the range of sections available and improve the mechanical properties of line pipe while maintaining competitive pricing,” says Mr Piper.

Before the pipe is coated...

Pipe is extensively tested before it moves onto being coated. It is measured, pressurised and probed by ultrasound. Key physical dimensions are checked to ensure compliance with specifications including length, mass, gauge, diameter, and bevel dimensions. Samples are also taken for destructive testing to ensure that the chemistry, strength and fracture toughness of the pipe comply with the specification and that the strength, fracture toughness, hardness and microstructure of the weld seam comply with the specification.

Coating the pipe

Bredero Shaw Technical Services Manager Peter Mayes says that the first order of business when pipe arrives for coating involves the collection of data. Generally this will include pipe size, wall thickness, manufacturer and steel heat number. This information is immediately uploaded into Bredero’s pipe tracking system, PipeTrak, to provide reference and checking ability. The pipe is given a cursory inspection for damage or obvious steel defects on arrival and then stockpiled in the company’s yard.

Nine steps to a successful coat

1. The first stage in the application of coatings is to wash away surface dirt then dry the pipe with a heater before blasting the pipe clean with a mixture of round shot and angular grit. The shot removes mill scale and the grit provides a consistently rough surface profile. The blasting process assists in reducing the potential for stress corrosion cracking in service. 2. The pipe is acid washed to remove any other surface contaminants and rinsed using a high-pressure water spray utilising low-conductivity water. 3. The pipe is heated using high-frequency induction coils to the required application temperature. 4. Epoxy powder is conveyed by clean-chilled compressed air, which is electrostatically-charged, then spray-applied to the rotating pipe. If pipe is to be fusion-bonded epoxy (FBE) coated only, then at this stage, it would be quenched and inspected. However, in the case of a three-layer coating, the adhesion powder or second-layer is then spray-applied by multi-heads while the FBE layer is still liquid and forms a chemical link. 5. The final third-layer or top coat of polypropylene (PP) or polyethylene (PE) is then extruded and spirally applied to the pipe with the molten material combining with the adhesive. 6. The coated pipe progresses to a water quench where it is cooled. Both external quenching and internal quenching may be utilised. 7. The pipe then rolls onto the final inspection racks. Here the coating thickness is measured, and an electrical inspection is conducted to locate pinhole defects – which are commonly called holidays – and the pipes are tallied. The tally station records the raw material batches against the pipe number. Barcode labels are automatically positioned on the pipe ends and a centre line marking may be applied to assist in identifying the mid-point of the pipe during subsequent pipe handling and laying at the right-of-way. An integral non-conformance database controls integrity of the product. 8. The ends are brushed clean and the coating chamfered to facilitate the field joint coating. 9. The finished pipe is removed and transported to the yard for stockpiling.

The coating process is defined by what system and thickness the client has requested. On average, normal production speeds range from 3,500–4,500 m/d. These rates are calculated for a nine-hour shift.

Popular coatings

According to Mr Mayes, presently the most popular coating systems in Australia are either single or dual-layer FBE and three-layer PE, with smaller quantities of Yellow Jacket. Internal epoxy lining is provided for gas flow enhancement or for corrosion protection.

This popularity is due to the exceptional corrosion properties of the provided products, which are suitable for Australian operating conditions and temperatures. This is enhanced by its excellent mechanical properties, suitable for all modes of transportation in Australia.

Quality Assurance At Bredero, all coatings are applied in accordance with relevant Australian standards or as otherwise specified by the client. The company’s quality assurance team reviews all customer specifications and ensures bilateral agreement in the development of an encompassing Quality Plan. Bredero utilises a fully-equipped quality control laboratory to ensure all coatings meet specification.

Experienced supervisors and team leaders at key stations throughout the process take responsibility for the quality control of their product. When requested, full detailed manufacturer’s data records are available to the customer, which cover the history of pipe during the coating process.

Mr Mayes says that quality control and quality assurance are important elements at every stage of the coating process. Customers’ free-issue material is checked on receipt and the many thousands of individual pipes are logged into the PipeTrak system to maintain traceability and status. Barcodes can also be applied to suit specific project requirements.

Coating quality is assured through the use of audited operating procedures and verified by inspection and testing in the factory and in the laboratory. Depending on the type of coating and the relevant Quality Plan, testing may include: thickness of coating (DFT), holiday testing, adhesion, differential scanning calorimetry, flexibility, resistance to hot water soak, resistance to cathodic disbondment, cross section and interfacial porosity, interface contamination, impact resistance, peel testing, yield strength, per cent elongation, and residual magnetism. Finally, before any pipe leaves the site, one last visual check is always performed.

Coating innovations

Throughout the past decade, Mr Mayes says that a number of technological innovations have been successfully integrated at Bredero’s pipe coating facilities. These include:

• Newer coatings for higher operating temperatures;
• New coatings to assist in gouge resistance and to enhance flexibility and impact resistance;
• Other coatings available for use where existing coatings may be considered ‘overkill’;
• Real-time entry of quality control date to touch-screens, providing data for analysis and reporting;
• Automatic barcode application and pipe centre line marking;
• Introduction of low VOC paint products for flow lining;
• Phosphoric acid pre-treatment for all FBE coatings;
• Automated high voltage holiday detector; and,
• The ongoing investigation of applying FBE coatings at lower temperatures with similar desirable properties, thus saving energy cost.

In addition, PipeTrak, in conjunction with the company’s automated barcode application, provides clients with assurance that processes will maintain their unique numbering system as supplied by the pipe manufacturers.

Challenges

According to Bredero Business Development Manager Dean Bennett, the competitive challenge from overseas companies is always prevalent. “However, through advances in coating technology, continuous improvement of the coating process, training and enabling our workforce, working with our customers to ensure their pipeline’s corrosion protection works with repeatable manufacturing processes, and liaising with our suppliers to get the best raw materials has placed Bredero in a competitive position in the Australian marketplace.”

Industry collaboration

With the ever-changing nature of requirements for gas transmission pipelines, all contributors to the manufacture and supply chain are committed to maintaining their technical and manufacturing excellence and providing solutions to new challenges.

(Sumber : http://pipeliner.com.au/news/pipe_production_101/043584/. Diakses 2 Februari 2014 pukul 16.45 WIB)

DEEPWATER PIPELINE

Deep-water Pipeline Innovations

Production from deep-water and ultra-deepwater requires pipelines with high thermal insulation coatings and resistance to aggressive fluids. Innovation is crucial.

X-Stream can significantly reduce the cost of deep-water and ultra-deepwater pipelines and stay within stringent safety and integrity boundaries

As oil consistently trades north of USD 80 per barrel and with natural gas coming more to the fore, a good deal of the easily accessible supplies are gone or dwindling. Production from the hard to reach places, such as deep-water, will increasingly become the norm. For that to happen, pipeline technology has to innovate for the environment where a diver simply cannot go. 

X-Stream pipeline for extreme environments

Norwegian independent foundation, DNV says that it has developed a new pipeline concept. It claims its so-called ‘X-Stream’ system can significantly reduce the cost of deep-water and ultra-deepwater pipelines and stay within stringent safety and integrity boundaries. The foundation, which says that 65 per cent of the world’s offshore pipelines are designed to its standards, believes that using X-Stream means a reduction in the pipeline thickness, welding time and installation when compared to current deep-water pipelines.

“Typically, for a gas pipeline in water depths of 2,500m, the wall thickness reduction can be 25 to 30 per cent compared to traditional designs,” according to DNV. Dr. Henrik O. Madsen, DNV’s CEO. Deep-water gas transportation market will “experience massive investments and considerable growth over the coming years,” he said adding: “new safe and cost-efficient solutions are needed.”

X-Stream technology

By constantly controlling the external and internal pressure differential of the pipeline the amount of steel, and therefore the thickness of the pipe wall, can be reduced by up to 30 per cent and perhaps more depending on the product, making manufacturing cheaper installation easier and less expensive, believes DNV. The foundation’s engineers led by DNV in Rio de Janeiro, Brazil utilised and inverted a high pressure protection system (i-HIPPS) and inverted double block and bleed valves (i-DBB) that will immediately isolate the deep-water pressure in the event of a pressure failure so that the internal pipeline pressure can be maintained above the critical level. During the installation process the pipeline is fully or partially flooded to control the differential pressure, while the i-HIPPS and i-DBB systems ensure that pressure never falls below the collapse pressure, says DNV. Minimum pressure needs to be maintained during pre-commissioning too and DNV says that this is achieved by using produced gas separated from the water by a set of separation pigs and gel; an industry standard practice. X-Stream has just completed the innovation project phase and DNV says that it intends to continue to work with industry on refining and testing.

Mechanically lined pipelines in action

Aberdeen based Subsea 7 has already been working with German group BUTTING to install its  mechanically lined BuBi lined pipe for production from ever deeper and more corrosive reservoirs. Together the two companies have developed a technology deemed by DNV to be, “fit for service,” to allow the successful reeling of the mechanically lined pipe without affecting the performance of the BuBi lined product. “The exploration and production of deeper and more corrosive subsea reservoirs demands that we design more subsea infrastructures and pipelines to cope with increasing amounts of carbon dioxide and/or hydrogen sulphide. Our solution, using the mechanically lined pipe (BuBi lined pipe) with BUTTING by reel-lay, offers a cost effective solution to transporting corrosive fluids,” said Stuart N Smith, Subsea 7 VP technology and asset development.

Tried and tested

The companies say they have established a methodology for the full installation sequence and pipe samples have been fatigue tested in the post reeled condition. The results indicated that the BuBi lined pipe suffered no detrimental impact from the reeling and testing and could be reliably used under existing practices. Qualification of the technology led to the award of Guará-Lula NE contract by Petrobras in 2011, which Subsea 7 says included the reel-lay installation of several BuBi pipe steel catenary risers in a water depth of 2,100m. “Technological developments and how we apply them to clients’ projects are crucial. We aligned with BUTTING and have developed together a world class product that can be used in some of the most demanding environments, from the North Sea to Brazil,” said John Mair, Subsea 7 global technology director.

Subsea tapping machine unveiled

Operating primarily out of Stavanger, Norway the offshore arm of T.D. Williamson Inc., TDW Offshore Services (TDW), has developed and now deployed in the field its Subsea 1200RC tapping machine. The lightweight, remote controlled system means that hot tapping can be carried out from a diving support vessel (DSV) in shallow water and also at depths of up to 3,000 metres. “The most critical part of the hot tapping process is the point at which the drill penetrates the pipe,” said Mike Benjamin, TDW’s vice president, offshore pipeline solutions for TDW in a statement. “The direct control and visibility from a laptop will revolutionise hot tapping, giving way to a more efficient and safer process.”

Field tested

TDW says that the system has already been successfully tested in relatively shallow water (91m) and aside from the safety benefits the company says the new technology “offers total control and visibility of the tapping operation where there was none before. Built-in sensors allow continuous recording of actual pressures, temperatures, rotation and movement of the pilot drill and cutter.” Operated from a programme on a laptop computer, the end result of the hot tapping operation results in accurate and quality operations, believes TDW.

Other benefits

Other benefits highlighted by TDW for the Subsea 1200RC tapping machine include easier handling because of its weight and no pipeline shutdowns because the system works without disrupting the flow of the pipeline during routine maintenance or in the event of an emergency shutdown. Furthermore, when the system is required for tapping into existing subsea tees the company says there is no requirement for a hot tap fitting as the system can be deployed and hooked up to the isolation valve with a mechanical connector. In particular, TDW considers that its hot tapping system will prove especially useful for the emergency pipeline repair system (EPRS) programmes that it offers to its customers. 

(Sumber : http://www.oilandgastechnology.net/upstream-news/deep-water-pipeline-innovations. Diakses 2 Februari 2014 pukul 16.15 WIB)

OFFSHORE PIPELINE CORROSION PREVENTION

Pipa bawah laut biasanya didesain agar bisa beroperasi 10 hingga 40 tahun. Agar dapat bertahan selama itu, pipa perlu dilindungi dari korosi, baik internal maupun eksternal. Korosi internal berkaitan dengan fluida yang dialirkan di dalam pipa, dibahas di Flow Assurance.

External coating dapat mencegah korosi pada pipa. Walaupun begitu, tetap ada kemungkinan coating rusak pada saat shipping atau instalasi. Proteksi katodik dengan pengorbanan anoda digunakan untuk mencegah bagian yang rusak dari korosi.

External Pipe Coating

External coating berfungsi untuk melindungi pipa dari korosi. Single layer coating digunakan jika pipa selalu berada dalam kondisi statis, stabil, berada di tanah seperti tanah liat atau pasir. Lapisan (layer) tambahan diperlukan untuk tambahan proteksi, menjaga pipa agar stabil di dasar laut (dengan weight), atau memberi isolasi. Isolasi berfungsi untuk menjaga agar temperatur fluida di dalam pipa lebih tinggi daripada temperatur lingkungan. Multi-layer coating biasanya digunakan di lingkungan di mana external coating mudah tergerus, misalnya di tanah berbatu.

Sifat coating yang perlu dipertimbangkan untuk pipa bawah laut adalah :

resistensi terhadap absorpsi air laut

resistensi terhadap bahan kimia di air laut

resistensi terhadap cathodic disbondment

fleksibilitas

resistensi terhadap benturan dan abrasi

resistensi terhadap cuaca

kompatibilitas dengan proteksi katodik

Single-layer coating kemungkinan tidak bisa menyediakan semua sifat yang diperlukan pipa pada berbagai kondisi operasi. Oleh karena itu diperlukan multi-layer coating. Agar coating menempel pada pipa, proses manufaktur surface finish perlu mendapat perhatian. Jika proses surface finish tidak baik, coating tidak akan menempel dengan semestinya pada pipa.

Single-Layer Coating

Single-layer coating yang sering dipilih untuk perpipaan bawah laut adalah Fusion Bonded Epoxy (FBE), khususnya di Amerika dan Inggris. Tabel di bawah menyajikan sifat FBE. Sebagian besar pipa penyaluran minyak dan gas menggunakan FBE karena biayanya murah. FBE dapat dipadukan dengan concrete weight coating.

Coating lain yang dapat digunakan bersama dengan concrete coating adalah coal tar enamel dan coal tar epoxy. Keduanya merupakan bituminous coating yang diperkuat dengan fiberglass. Walaupun demikian, sebagian besar bituminous coating biasanya tidak digunakan terkait dengan peraturan lingkungan dan penurunan efisiensi (sagging, cracking, permeasi, dan deteriorasi kimia).

Multi-layer Coating

Dual-Layer FBE

Dual-layer FBE coating digunakan jika proteksi tambahan diperlukan untuk layer luar, seperti temperatur tinggi, resistensi terhadap abrasi, dan lain-lain. Untuk pipa bawah laut, temperatur fluida di dalam pipa menurun mendekati ambien setelah menempuh jarak beberapa km. Kebutuhan coating dibatasi untuk SCR (steel catenary riser) pada area touchdown di mana abrasi tinggi dan coating tambahan dengan resistensi tinggi terhadap abrasi diperlukan. Sistem Duval terdiri dari FBE base coat (20 mil) yang berikatan dengan polypropylene coating (20 mil). Polypropylene layer memberikan proteksi mekanik.

Three-Layer

3-layer polypropylene (PP) coating terdiri dari epoxy atau FBE, thermoplastic adhesive coating, dan polypropylene top coat. Polyethylene (PE) dan polypropylene (PP) coating merupakan extruded coating. Coating ini digunakan untuk proteksi tambahan mengatasi korosi, biasanya digunakan untuk sistem dinamis, seperti SCR (steel catenary riser), dan lokasi di mana temperatur fluida di dalam pipa cukup tinggi. Di Eropa, PE dan PP coating banyak digunakan karena memiliki dielectric strength, water tightness, thickness yang baik, serta kebutuhan arus untuk proteksi katodik yang rendah.

Concrete Weight Coating 

Concrete weight coating digunakan jika kestabilan perpipaan di dasar laut menjadi isu utama. Densitas concrete yang umum digunakan adalah 140 lbs/ft3 dan 190 lbs/ft3. Densitas yang lebih besar diperoleh dengan menambahkan bijih besi ke dalam concrete mix. Pada saat ini bijih besi sudah ditambahkan ke dalam concrete menghasilkan densitas 275 hingga 300 lbs/ft3.

Proteksi Katodik

Proteksi katodik merupakan metode untuk mencegah korosi pada logam. Terdapat dua metode utama untuk proteksi katodik, yaitu sistem anoda galvanik dan impressed current. Untuk pipa bawah laut, sistem anoda galvanik umum digunakan.

Korosi merupakan reaksi elektrokimia. Permukaan pipa baja terdiri dari area katoda dan anoda yang distribusinya sembarang. Air laut merupakan elektrolit yang melengkapi sel galvanik. Hal ini menyebabkan elektron mengalir dari satu titik ke titik lainnya, menghasilkan korosi. Dengan mengoneksikan logam yang potensialnya lebih tinggi daripada pipa baja, dapat dibuat sel elektrokimia di mana pipa baja menjadi katoda dan diproteksi.

Coating pipa merupakan penghalang pertama untuk menahan korosi. Walaupun demikian, proses pengangkutan dan instalasi pipa dapat menghasilkan kerusakan pada coating. Proteksi katodik menggunakan logam lain yang akan melepas elektron (anoda). Logam tersebut biasanya aloy aluminium dan seng. Dengan menempatkan anoda pada pipa, area pipa yang coatingnya rusak dapat diproteksi dari korosi.

Anoda seng biasanya tidak digunakan untuk pipa laut dalam karena tidak efisien, membutuhkan massa yang besar untuk memproteksi pipa. Walaupun demikian, anoda seng dapat dipasang pada sambungan pipa sehingga tidak diperlukan kabel untuk koneksi listrik ke pipa. Seng tidak menunjukkan kinerja yang baik untuk hot buried pipelines. Sedangkan kinerja anoda aluminum lebih baik dan dapat digunakan untuk hot buried pipe.

Desain Proteksi Katodik

Dalam mendesain proteksi katodik untuk pipa bawah laut, parameter-parameter yang perlu diketahui adalah :

. Umur desain (tahun)

. Coating breakdown (%)

. Densitas arus untuk proteksi (mA/m2), ditanam (buried) atau tidak (unburied)

. Resistivitas air laut (ohm-cm)

. Resistivitas tanah (ohm-cm)

. Pipeline protective potential (umumnya -900 mV w.r.t Ag/AgCl)

. Output anoda (amp-hr/kg)

. Potensial anoda (mV w.r.t. Ag/AgCl)

. Anode utilization factor (%)

. Temperatur air laut

. Temperatur pipa

. Kedalaman pipa

Umur desain pipa berdasarkan jenis pipa, apakah merupakan trunkline atau infield line. Umur trunkline bisa mencapai 40 tahun, sedangkan infield line 20 tahun. Coating breakdown factor bergantung pada tipe coating.

Densitas arus, resistivitas, dan temperatur bergantung pada lokasi geografis di mana pipa diletakkan. Pada pipa laut dalam, temperatur air laut berkisar 0,7oC hingga 7,5oC. DnV dan NACE menyajikan nilai densitas arus dan resistivitas untuk lokasi-lokasi offshore. Untuk pipa yang ditanam di sedimen, nilai densitas arus sebesar 0,020A/m2 direkomendasikan oleh DnV.

Tipe anoda yang digunakan menentukan sifat elektrokimianya. Anoda Galvalum III, misalnya, memiliki output anoda sekitar 2.250 amp-hr/kg di dalam air laut dengan temperatur kurang dari 25oC dan potensialnya sekitar -1.050 mV.

Anode utilization factor bergantung pada bentuk dan aplikasi anoda. Anoda bracelet diasumsikan dapat digunakan hingga 80% dari umurnya, sedangkan anoda stand-off 90%. Untuk temperatur pipa di atas 25oC, densitas arus meningkat. Di atas 25 derajat Celcius, setiap peningkatan 1derajat Celcius, densitas arus meningkat 0,001 A/m2.

Organisasi yang Berkaitan dengan Pipe Coating

Organisasi di Amerika :

. American Society of Testing Methods (ASTM)

. Steel Structures Painting Council (SSPC)

. National Association of Corrosion Engineers (NACE)

. National Bureau of Standards (NBS)

. International Organization for Standardization (ISO)

Di Eropa :

. Det Norske Veritas (DnV)

. Deutsches Institut fur Nurmung (DIN)

. British Standards (BS)

. International Organization for Standardization (ISO)

(Sumber : http://kegiatan-migas.blogspot.com/2009/05/pipa-pencegahan-korosi-2.html. Diakses tanggal 2 Februari 2014 pukul 16.00 WIB)

PIPELINE ON BOTTOM STABILITY

Breaking new ground in pipeline on-bottom stability design  

The Australian Pipeliner — October 2011

The need to better understand pipeline stability in the unique environment of Western Australia’s North West Shelf has lead to the establishment of a research facility in Perth that is attracting worldwide interest.

In February this year, the O-Tube – a closed-loop channel of water that can simulate hydrodynamics near seabed generated by tropical cyclones and their effects on pipeline stability – was used commercially for the first time by researchers and engineers from the University of Western Australia (UWA) and Atteris, on behalf of Woodside Energy.

The team has been running a series of tests over a four- to five-month period to assess pipeline stability on mobile seabeds. The north of Australia is subject to frequent severe tropical cyclones, and the continental shelf comprises unique seabed materials, including carbonate marine sediments. The O-Tube facility provides an opportunity to better understand the physics behind the behaviour of subsea pipelines on these seabed conditions under extreme hydrodynamic loadings.

In 2005, Woodside engaged Atteris to undertake pipeline stability studies. Theoretical assessments comprised studies of pipeline behaviour as well as seabed behaviour under extreme storm events such as tropical cyclones. This approach was unique because conventional pipeline on-bottom stability design methods ignore seabed instability occurring during the build-up, peak and ramp-down of a storm. This work culminated in the concept of building a brand new laboratory testing facility in which the three-way pipeline on-bottom stability processes – fluid-pipe, fluid-soil and pipe-soil – could be physically tested.

UWA designed, supervised the construction of, and commissioned the O-Tube testing facility. UWA has a long track record of delivering specialist numerical and physical model testing services to the offshore hydrocarbon industry, and is regarded worldwide as a state-of-the-art research centre for the subsea pipeline engineering industry.

The O-Tube comprises a closed-loop channel of water driven by an axial flow pump, with a 1 m wide and 1.4 m high test section. This test section allows large diameter pipelines to be modeled at scales of 1:5 to 1:6, with smaller pipelines such as flowlines capable of being modelled at prototype scale. The O-Tube is unique because it can generate a combination of steady and oscillatory flow to produce realistic on-bottom flow conditions.

The pipeline designers have been particularly interested in studying the effects of fluid-soil interaction on pipeline stability. Fluid-soil interaction includes processes such as free field scour, local scour, pore pressure build-up and soil liquefaction. These processes are difficult to predict analytically and can contribute significantly to the overall stability of a pipeline.

The O-Tube is being used to assess the stability of new and existing subsea pipelines and flowlines. These assessments will aim to reduce the level of conservatism associated with current design approaches and minimise costs relating to potentially unnecessary stabilisation measures. The work that has gone into this research program is unique on a worldwide scale, and has attracted the attention of multi-national companies and bodies, including Det Norske Veritas.

The physical model tests performed by a team of engineers and academics from Woodside Energy, UWA and Atteris will pave new ground in the development of a comprehensive subsea pipeline stability assessment method, inclusive of fluid-soil interactions.

The delivery of the O-Tube has been possible thanks to financial contributions from Woodside Energy, Chevron Australia, UWA and the Australian Research Council.

(Sumber : http://pipeliner.com.au/news/breaking_new_ground_in_pipeline_on-bottom_stability_design/063943/. Diakses tanggal 2 Februari 2014 pukul 15.55 WIB)