Pipelines Expansion Loops

Pipelines Expansion Loops

A pipeline will expand or contract when temperature and pressure vary from installation conditions. Conditions during construction, therefore, become the reference temperature and pressure. For present purposes, discussion will be limited to expansion, but similar issues may require addressing for contraction.

As the pipeline expands, it will follow the path of least resistance, which leads directly to the risers to the platform.

If the lower riser span is insufficiently flexible to absorb expansion within the permissible stress limit, expansion loops are typically placed just before each riser. When the loops do not function properly, as when buried, they overstress at the first bend experiencing the pipeline expansion.

The several methods readily available to reduce the expansion in the pipeline result in build-up of axial forces in the pipeline and lead to upheaval buckling, a mode of failure in trenched and buried pipelines. Pipelines resting on the seabed may also buckle but tend to buckle laterally where there is insignificant resistance.

Upheaval buckling results from the axial force generated from the expanding pipeline combined with an uneven trench bottom which results from the trenching process, undulations in the seabed, a rock formation, or an area of denser soil. Trench unevenness is generally referred to as an "imperfection."

Axial force and imperfection are related. In general terms, the more uneven the trench profile, the lower the axial force required to produce an upheaval buckle.

Methods to control expansion and upheaval buckling, discussed presently, were investigated for the design of a high pressure and temperature, buried sour gas flow line offshore in Mobile Bay, Ala., for a major operator.

Controlling expansion

There are several conventional methods used to handle expansion which, along with some unconventional methods, were investigated and include the following:

• Anchor flanges and concrete and/or rough fusion-bonded epoxy (FBE) coatings each performs the same function of increasing the friction, thus reducing or eliminating expansion in the pipeline. This increase in friction, however, results in the build-up of axial forces in the pipeline contributing to increased risk of upheaval buckling.
• Cold springing the riser has proven successful for many pipelines. Cold springing prestresses the riser during construction, resulting in splitting the difference between the prestress and the expansion loads to be encountered during operation. This allows the riser to accommodate larger amounts of expansion. Cold springing allows for the natural relief of the pipeline stresses through the riser. Even allowing for cold springing, the middle of the pipeline may be anchored because of friction and experience the maximum axial force possibly resulting in upheaval buckling.
• The riser bend may be reinforced with a brace, distributing the forces over more of the riser. Reinforcing is limited in the amount of expansion it may accommodate, however, and does not alleviate the forces in the middle of the pipeline.
• Pipe-in-pipe construction is an option that has been utilized when other solutions fail. It is costly because the product carrier pipe is inside a jacket pipe normally two sizes larger. The two pipes are mechanically connected with bulkheads that transfer the loads from the carrier pipe to the jacket pipe.

While the carrier pipe expands, the jacket pipe resists the expansion loads. The spacing and size of the bulkheads are determined to eliminate buckling of the carrier pipe within the jacket pipe to minimize installation expense.

The structural design of the pipe-in-pipe virtually eliminates expansion and the potential of upheaval buckling if the system is properly designed. The cost of extra materials, however, and the lengthy process of fabricating the pipe-in-pipe warrant investigation of other options.

• Expansion loops and doglegs serve the purpose of acting as a spring to accommodate expansion at the risers. Several expansion loop and dogleg configurations were investigated for the installation in Mobile Bay, including conventional U-loops of various dimensions, and various angles for the doglegs.

It was found that buried expansion loops and doglegs experience high lateral resistance that in turn creates localized high stresses at the first bend. Only a short length of the expansion loop was buried, with minimal effectiveness.

To illustrate the relative effectiveness, it was found that a conventional expansion loop 40 x 40 ft was effective only over 4 ft when buried and had a much-reduced capacity for expansion. Similar to other methods, the expansion loop placed at the riser would not relieve the stresses in the middle of the pipeline.

• A zig-zag shaped pipeline has been employed to accommodate expansion and relieve axial forces throughout the pipeline. The pipe joints were bent in a zig-zag configuration and double jointed for installation. Each joint accommodated some of the expansion and relieved some of the axial force.

Although this solution has applications, the additional cost and concerns of fabrication and installation limit its applicability.

• Snaking the pipeline during installation appeared promising in principal. The pipeline would act as its own spring throughout the length, accommodating the expansion and alleviating the axial forces.

Several configurations that were considered easily layable were investigated for a range of soil conditions. It was determined that the pipeline follows the path of least resistance, which is axially.

Snaking the pipeline requires additional pipe which contributes to more costs and more expansion at the ends.

source :

http://www.ogj.com/articles/print/volume-96/issue-31/in-this-issue/pipeline/expansion-loop-enclosure-resolves-subsea-line-problems.html

Subsea pipeline tie-in / piggable wye tie-in

Piggable wyes have been used extensively in deepwater oil and gas pipeline operations to allow cleaning and inspection pigs and intelligent pigs access through main lines and the laterals that tie into them. Being able to run these state-of-the-art pigs through the wye improves the operating efficiency and the long-term integrity of the pipeline system. Although wyes improve operations on some levels, there are cases when operators need to run pigs counter to the normal flow direction in the lines. This presents no problem in a pipeline with no piggable wyes, but the internal profile at the wye fitting juncture does not permit reverse flow pigging.

Traditional piggable wye operations

Operators of oil and gas pipelines wage a constant battle against the harmful effects of internal corrosion, paraffin, and condensate accumulation. Commonly accepted practice dictates that the operator run pipeline pigs through the line. The pipeline product flow pushes these cleaning devices through the length of the line. The pig maintains contact with the internal wall of the pipe, pushing hydrates, paraffin, condensate, and other potentially harmful agents in advance of its passage through the pipeline. Corrosive elements are removed from the line at its termination point, enhancing the long-term integrity of the pipeline.

Pigging a single line is a straightforward process, requiring only that the pig be launched from one end and pushed the length of the line using a liquid or gas medium as the propelling force until it is captured in the pig receiver at the end of its journey. However, pigging lateral line tie-in connections requires that the operator pre-plan the installation of a piggable wye fitting in the main line during the construction process. A piggable wye is a Y-shaped fitting that has two inlets, one for each incoming pipeline, and a single outlet that merges the flow of the two converging pipelines. The two lines converge in the Y at an intersecting angle of 30°. This basic wye configuration was originally tested in the 1980s and has proven to be a reliable design.

For years, the question has been whether it would be feasible to run pigs backward through a wye from the outlet through one of the inlets in a reverse flow pigging application. Until now, the answer has been no.

The internal profile of the wye at the juncture of the two pipelines would likely cause the pig stick in the fitting. Alternatively, if the pig managed to traverse the juncture area of the wye, there would be no way to determine which of the two converging pipelines the pig would flow into.

Bi-directional pigging

A recently developed product now allows pigs to run forward or backward through a wye. The Director Wye has the unique ability to accommodate reverse flow pigging. This new direction in piggable wye technology uses an internal diverter sleeve that is actuated from the exterior of the wye. The diverter can be actuated by an ROV or diver. The internal diverter sleeve rotates within the mainline bore of the wye to direct the pig.

The open position permits normal pigging operations that originate through the main line and/or the lateral line that converges into the single main line downstream of the wye. When the internal sleeve of the Director Wye is rotated to the closed position, the barrel of the sleeve closes the access port within the wye from the lateral line to the main line. Conventional pigging can still be conducted through the main line in the closed position, but the diverter sleeve allows a pig to run in the reverse flow direction through the main line as well. With the lateral line bore closed, the pig cannot jam in the juncture of the wye and cannot inadvertently enter the bore of the lateral line.

The Dual Director Wye

The Director Wye had no more entered the market than an operator asked if the design could be modified to permit bi-directional pigging through both the main line and the lateral legs of the wye. The Dual Director Wye accomplishes this feat through the addition of a mirror-image internal diverter sleeve in the lateral leg of the fitting.

Like its predecessor, the Dual Director can be used as a standard wye with both diverter sleeves in the open position. When the main line diverter is operated to shut off access to the lateral opening, the Dual Director also permits bi-directional pigging through the main line. The differentiating feature of the Dual Director is that if the mainline sleeve closes the main line and the lateral line sleeve is open, bi-directional pigging can be accomplished through the lateral line. The design of the dual internal diverter sleeves and the actuation system is the same for both the Director Wye and Dual Director Wye.

Concept to reality

The Director Wye was initially proposed to a client by means of a hand sketch on a marker board. That rough sketch led to the final product.

An operator planned to commission a pipeline by flushing the water from the line using a pig from the platform to a subsea pig receiver. The plan required that a second operation be performed to remove the subsea pig receiver and to make the final tie-in to a wye on the pre-existing pipeline. This approach entailed several technical and environmental difficulties and was costly in the deepwater environment.

The Director Wye allows the operator to make the subsea connection to the existing pipeline first. Then, the pipeline can be dewatered by opening the valve at the subsea tie-in point and using the pipeline product to push a pre-installed pig in a reverse flow direction through the Director Wye all the way to the platform. Reportedly, this innovative approach will simplify the operational process and reduce commissioning costs for the pipeline.

Future applications

There are other potential applications for the Director Wye, many of which offer benefits to shallow-water and onshore operators. Potential applications for the bi-directional piggable wye include:

• Deepwater tie-backs: Standard practice for deepwater subsea tiebacks dictates the installation of dual pipelines to permit roundtrip pigging of the lines. In many cases, the dual lines are several miles long. The installation of a Director Bi-Directional Wye would enable the operator to install a single line and still be able to pig the system. The pig would enter the wye in the reverse flow direction on its way to the wellhead. The internal director sleeve would be rotated to permit the pig to enter the lateral leg of the wye in a standard flow direction and traverse the wye on its return journey to the platform. Eliminating the redundant flowline reduces capital expense. This procedure also reduces the number of marine risers on the platform to a single riser.
• Permanent reverse flow projects: In certain cases a subsea pipeline system is designed to accommodate a future need to use reverse flow to provide feed gas for offshore operations from an onshore processing facility. In this case, the wye functions as a standard wye as long as the offshore structure can produce enough gas for its operational purposes. Once this is no longer the case, the internal sleeve of the Director Wye can be rotated to permit reverse flow of the product and any required pigging operations to one or more offshore structures.
• Coiled tubing access for deepwater risers: A Director Wye could be installed topside in a marine riser to permit more efficient coiled tubing access. The wye would be installed such that pigging the riser and pipeline could follow the conventional flow. The internal director sleeve would be rotated to close off access to the lateral leg of the wye. When coiled tubing access is required, the internal director sleeve would be rotated to open access to the lateral and permit the installation and withdrawal of the coiled tubing. At the conclusion of the operation, the internal sleeve would be rotated again to close off the tubing access lateral opening to permit pigging of the riser once again.
• Onshore applications: The Director Wye would permit the use of intelligent pigs alternatively through either the main line or the lateral without compromising piggability in either line.

source :

http://www.offshore-mag.com/articles/print/volume-67/issue-11/drilling-completion/new-direction-in-piggable-wye-technology.html

Pipeline Commisioning

The critical procedure of drying offshore pipelines to allow safe transportation of natural gas is greatly aided by use of pigs of borate-crosslinked gel, uncrosslinked gel, and methanol pumped through the pipelines. A pig can be a piece of hardware or a compartment of liquid pushed through a line by pressure to clean the line, remove obstructions, dry out the line, or other functions.

A single train of mechanical pigs and gel, driven by gas or drying liquid, can be pumped through the pipeline to dewater the line as part of the commissioning process.

Some operators choose to dewater the pipelines with mechanical pigs to remove most of the water, then complete the drying by pumping a second train of pigs including foam pigs, nitrogen, and methanol.

Commissioning, the process of bringing a pipeline to a state of readiness for use, can present a challenge rivaling the challenges faced by pipeline construction teams. To allow for safe transport of dry natural gas through the completed system, operators must purge the line of all debris left during construction and all water left by subsea construction, cleaning, and hydrotesting procedures. A gas pipeline must be dried to specific levels to control:

• Hydrate formation within the pipe
• Corrosion in lines when sulfur is a component of the gas
• Formation of carbonic acid when carbon dioxide is a gas component.

Dryness defined

Pipelines that will be used to transport gas must he dry before put into service. Dryness is expressed in several different ways:

• Dew point in degrees F at 14.7 psia
• Dew point in degrees C at 14.7 psia or 1 bar absolute
• Parts per million (ppm) by volume
• Parts per million (ppm) by weight
• Pounds of water per volume (lb/MMcf) of air.

A dryness level of -35° C dew point at 14.7 psia means the same as the following: (1) -3l° dew point at 14.7 psia, (2) 222 ppm by volume, (3) 140 ppm by weight, and (4) 11.1 lb/MMcf.

One train or two?

Operators dewater pipelines by using the pumping methods listed as follows:

1. Pumping mechanical pigs to swab out most of the water, then pumping drying pigs (consisting of foam or methanol),
2. Pumping mechanical pigs to remove most of the water, then vacuum-dry the line or dry it by air convection,
3. Pumping a combination pig train to swab out water and complete drying of the line by chemical means in one trip.

Method 3 above offers many economic benefits, especially in drying long, low-temperature subsea pipelines. Use of hygroscopic fluids (fluids that readily take up and retain water) in pig trains eliminates the need for vacuum or air-convection drying to remove the last traces of moisture from pipe-wall matrices.

In vacuum drying, pressure in the line is reduced to atmospheric level (sometimes as low as 0.l atmospheric) for a time, then air is sent through the line to evaporate moisture. However, air is not effective at drying subsea lines.

Hygroscopic fluids in the pig train absorb most of the water left behind by the dewatering pigs in the train. Further, any fluid left behind by the pig train will be hygroscopic and hydrate-inhibiting in nature. The first contact with the product sent through the line will absorb the last traces of moisture remaining in the line.

The advantages of including hygroscopic compartments in the dewatering train and drying the pipeline in a single pass are:

• The pipeline can be used for delivery at an earlier time, while vacuum and air-convection drying times can require months to accomplish. Hygroscopic fluid-drying can be accomplished concurrent with the dewatering process.
• Hygroscopic-fluid drying eliminates the need for deck space required for vacuum/air-drying equipment.

Not every pipeline is a candidate for single-pass dewatering/drying. Those exceptions include:

1. Multiple tie-ins with connections that cannot be swept by the dewatering train.
2. Valve stations that allow water to drain into them.
3. Manifold sections that preclude pig access cannot be commissioned in a single pass.

It is still advantageous to include gel compartments in any dewatering train that can be used, since the gel helps reduce the amount of water that must be dried by vacuum or heated air. Disposal of hygroscopic fluids may present a challenge in some areas, but in most cases will not preclude use of such fluids.

Selection of the most appropriate commissioning method should include the following considerations: the level of dryness required, the product that will be delivered through the pipeline, and conditions in the pipeline that may affect drying methods.

Parameters

The volume of water left in the pipeline by passage of pigs is influenced by (1) coating or the lack of coating on the internal pipe (ID), (2) pipe roughness, (3) pig bypass, and (4) pig lubrication.

• Coating: Pipeline coatings may be added to leave an almost nonporous ID, except for weld ends. Coated pipelines are easiest to dewater for use, since the volume of water left by swabbing is very small. To dry most coated pipelines, operators include compartments of methanol in the pig train to contact water on the pipeline walls. Methanol dries water rapidly on contact. Operators may even dry coated pipelines by including a hydrate inhibitor in the dewatering pig train sent through the line, and allowing the gas to dry out the last remnants of water.
• Pipe roughness: In lines already in service as liquid carriers but being converted to gas pipelines, pipe roughness causes a high level of moisture retention in the pipe. The volume of water requiring removal can be twice the volume required in new pipe. The film of water left after use of foam pigs or other dewatering methods may require drying by vacuum or air convection to remove the water contained in the matrix of the pipe wall.
• Pig bypass: If a pig train is moved too slowly through the pipeline, the train will start and stop in a jerking movement. Each time a pig train stops, it may bypass fluids and gas ahead, bypass fluids or gas to the rear, or reverse directions. Fluid and gas bypass around static pigs occurs commonly at weld seams. Reversal of direction can occur during fast shutdown of train movement. When a pig reverses direction, a great volume of water can bypass the pig.
• Pig lubrication: Proper lubrication is necessary to prolong the life of the cups/discs that contact pipeline walls to wipe moisture and debris from the walls. Water or methanol based gels help lubricate pigs when small amounts of fluids bypass the pig during travel. Gels also influence the flow regime around the pig. The viscosity of these gels aids in prevention of forward and reverse bypass of gas and fluid.

Drying gels

Use of gels (included as compartments in the pig train) as sealants/lubricants has proven to be critical to the success of drying long, undersea pipelines, contributing greatly to the longevity of the pig discs/wipers. Schreurs et al. reported the successful commissioning of a 500-mile undersea line using gel pigs and mechanical pigs in a single train.

Results of extensive computer simulation and laboratory experimentation led Schreurs et al to recommend use of uncrosslinked, methanol and/or water-based gels for pipeline drying. In actual practice, the gelled methanol pigs performed best, showing minimal degradation. The water-based gel pigs performed adequately. Where environmental concerns restrict the use of methanol, or when a pipeline does not have critical dryness requirements, water-based gels can be used with only slight degradation in gel performance.

In laboratory testing, it was observed that uncrosslinked water gels and methanol gels provide significantly more friction reduction than that provided by water or methanol. High-viscosity crosslinked gels, however, provide no lubrication to the pig train and make the train difficult to start into motion. The viscosity decline on uncrosslinked gels compares favorably with that of borate-crosslinked gels. Therefore, uncrosslinked gels are the preferred choice for use in dewatering pig trains.

Operating the train

The pig train illustrated on page 70 includes a displacement fluid supply, a dewatering train, and a valve for water flow rate control. Flow rate helps determine the speed of pig train travel.

On page 72, a typical pig train that was placed in sequence to cleanse pipe walls, push debris ahead of the train, lubricate the pigs, dry the walls (drying by hygroscopic fluid such as methanol), and help prevent bypass of driving gas ahead of the train. Escape of gas ahead of the train can cause formation of hydrates, which can completely block the pipeline. A very heavy methanol gel can be designed to help prevent bypass of propellant gas, but leave minimal residue on the pipeline walls.

To control pig train operation, operators modulate the supply gas rate, hold a constant pressure, and control the water discharge through the valve at the downstream end of the line. A rapid valve-opening schedule results in high hydraulic transient pressures that may cause rapid velocity changes. An opening schedule that is too slow would cause start-stop or jerky pig movement, which would result in forward pig bypass.

During startup, the train must be accelerated rapidly enough to avoid start-stop pig motion. During shutdown, the train must be decelerated to a stop as quickly as possible without causing a pig reversal. Single-pass dewatering/drying of subsea pipelines offers economy of time and resources when conditions allow. When single-pass drying is precluded by conditions or pipeline arrangement, inclusions of gel compartments in any pig train used reduces subsequent drying time required.

References

Azevedo, L.F.A., Braga, A.M.B., Nieckele, A.O., Naccache, M. F., Gomes, M.G.F.M.: "Simple hydrodynamic models for the prediction of pig motion in pipelines," Pipeline Pigging Conference, Houston, February, 1995.

Schreurs, S., Falck, C., Hamid, S., Burman, P., Maribu, J., Ashwell, C.: "Development of Gel Systems for Pipeline Dewatering and Drying Applications," OTC 007577, Offshore Technology Conference, Houston, TX, May 2-4, 1994

Hamid, S., Falck, C., Wissing, M., and Grotberg, I.: "Dynamic Characteristics of a Pipeline Dewatering Train," OTC 007578, Offshore Technology Conference, Houston May 2-4, 1994.

http://www.offshore-mag.com/articles/print/volume-55/issue-4/news/pipeline/pipeline-technology-gel-pigs-effective-in-single-pass-drying-of-new-offshore-pipelines.html

Pipeline Decommisioning

The method and standards employed in the decommissioning and abandonment of offshore oil and gas pipeline assets at the end of their useful life are determined by a framework of national legislation, international protocols and treaties, and corporate governance standards. The framework will impose legal obligations upon operators to ensure marine environments are protected.  Fines and penalties may be imposed if the asset owner fails to meet these requirements.

A regulatory, or any similar, body will not prescribe a detailed planning process. Nonetheless, the body will usually expect to approve details from an asset owner on how the decommissioned activities will be planned, executed, and monitored within the regulatory framework. Additional requirements from other stakeholders within an operating company and corporate governance standards will also impose obligations on the decommissioning project.

The decision to decommission a pipeline is often complicated by a long list of technical, business, and safety issues. For example, a pipeline may need to be completely removed from the seabed due to changes in legislation governing marine environments since installation. This may be potentially very costly and carry a high consequence of failure during execution, because the pipe spools may not be in satisfactory condition in order to be lifted from the seabed, e.g. due to internal corrosion. If a decommissioning activity is not thoroughly examined and planned, the consequences of failure may become apparent at a later, critical, phase of the decommissioning activity. Safer, more ‘traditional’, options may become less clear-cut during the planning and execution and result in simply ‘road blocking’ the project. Therefore, the need for the development of a clear and thorough decommissioning programme to guide, assist, adjudicate and support decision-making at critical junctures in the project development is crucial. This exercise will also help to determine a low risk, cost effective and technically feasible option for decommissioning each pipeline, taking into consideration the various technical, environmental, safety, and regulatory challenges that are often encountered whilst working on decommissioning projects. 

Source :

https://www.onepetro.org/conference-paper/SPE-171898-MS

Offshore pipeline buckling and collapse

Thousands of Smart Flange Plus Connectors have been installed worldwide in shallow to deepwater applications with some exceeding 5,000 fsw.  Oceaneering developed the unique mechanical end connectors for various offshore oil and gas application including:

·         Pipeline Spool Piece Repairs

·         Pipeline Reroutes

·         Pipeline Abandonments

·         Riser Repairs

·         Structural Repairs

·         Valve Installations

·         Tee Installations

The Smart Way To Connect

Permanent subsea pipeline repairs are easier, safer and take less time with Smart Flange Plus Connectors. The product  offers pipeline and riser repairs without the need for hyperbaric welding and can be installed in diverless applications.  Available worldwide, the end connectors are stocked in a variety of sizes to accommodate from 2 inch up to 24 inch pipeline diameters.  End connectors up to 48 inch have been delivered and installed.  All are type approved by Bureau Veritas (BV).

The Smart Flange Plus Connectors can be installed by commercial divers as well as by utilizing Oceaneering’s Atmospheric Diving Systems (ADS).  Hydraulic Smart Flange Plus Connectors are installed by Remotely Operated Vehicles (ROVs).  No other special equipment or trained personnel is required.

Features

·         Can be seal-tested

·         Easy to install

·         Subsea or topside use

·         Fully mechanical

·         Accepts external loading

Benefits

·         Hotwork permits not required

·         Straight pipe cuts unnecessary

·         Minimal pipe preparation

·         Cost-effective

source :

http://www.oceaneering.com/pipeline-connection-repair-systems/diver-installed-pipeline-systems/smart-flange-plus-connector/

Understanding and preventing corrosion on pipeline

Corrosion causes billions of dollars worth of damage each year. As a result of this chemical-physical process, pipeline sections often have to be taken out of service and replaced.

Corrosion can be caused by ineffective pipeline coatings, soil conditions and the circumstances under which a pipeline’s coating is rehabilitated onsite. In practice, surface preparation and the application circumstances appear to be critical in creating a long-lasting, high-performance coating.

The chemistry of corrosion

Corrosion can also be described as oxidation because the process involves the formation of bonds between steel and oxygen. Oxygen, however, is not solely responsible for the oxidation process. In dry environments, many materials, including steel, do not rust. The cause of oxidation is to be found in the presence of water.

Coating types

In order to prevent corrosion, the bare substrate can be protected by means of several available coatings including:

Factory coatings

• Fusion-bonded epoxy (FBE), high-density polyethylene (HDPE) and urethanes.

Field-applied coatings

• Spray coatings like epoxy, urethane and zinc;
• Residues of refinery like waxes and petrolatum;
• Bitumen-based coatings; and,
• Single or multiple-layer PE/butyl tapes.

The selection of the coating depends on various factors such as:

• The estimated lifetime of substrate;
• Environment;
• Material, shape, and position of the substrate; and,
• Application and repair costs.

Phenomena and problems facing pipe coating

There are a number of phenomena that contribute to the corrosion process and that should be considered when discussing the application of pipeline coatings and the corrosion process.

Salts and osmosis

The presence of salt plays an important role in a corrosion mechanism because salt particles are present in most situations and are difficult to remove. Rinsing a blasted pipeline coating with clean water will not remove the salt particles and other contaminations in the voids of the pipe. As many pipeline coatings are not 100 per cent water resistant, the presence of salt is always a risk because it attracts water. When water and salt are present, the phenomenon of osmosis occurs.

Water permeability

If the slightest permeability for water exists, corrosion will occur. Regardless of how well a coating has been applied in the factory, practice has revealed that disbondment due to the presence of water may still occur. While corrosion is always caused by a combination of factors, permeability for water should be viewed as a serious hazard to pipeline health.

Adhesion problems

Any pipeline coating must have good adhesion to the substrate. To obtain an effective adhesion is not easy because application circumstances must be taken into consideration, and many coatings require a perfect surface preparation. The difference between tensions of the surface and coating material also play an important factor in adhesion failures.

Surface preparation

Studies have shown that bad surface preparation appears to be a main cause of corrosion problems. Very often field-applied coatings need a well-prepared surface in order to secure excellent adhesion and sandblasting is often required. However, remaining pollutions in the voids of the blasted surface and salt particles can create problems, and rapid disbondment may occur.

Microbiologically-influenced corrosion

Microbiologically-influenced corrosion (MIC) is a phenomenon in which corrosion is initiated or accelerated by the activities of micro-organisms. The first case of MIC was discovered in 1934 in which sulphate-reducing bacteria were responsible for the corrosion failure of cast iron pipe.

MIC is responsible for a large portion of corrosion problems experienced in the pipeline industry. During the metabolic process, sulphate is reduced to sulphide, which reacts with hydrogen to produce hydrogen sulphide. Hydrogen sulphide is very corrosive to ferrous metals and further reacts with dissolved iron to form an iron sulphide film over the metal pipe.

Overcoming these problems

In order to prevent corrosion, steel parts must be protected from contact with water. This can be achieved through the application of a protective coating. This coating must be 100 per cent water-repellent, with the capability to perfectly-match the surface of the pipeline. It should have a perfect adhesion and reduce the risk for MIC.

Source :

http://pipelinesinternational.com/news/understanding_and_preventing_corrosion/43736

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.

Source :

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

Engineering Critical Assessment for offshore pipeline

An engineering critical assessment (ECA) – also known as fracture analysis – is a fitness-for-service procedure that uses fracture mechanics principles to determine the defect tolerance of safety critical items.

When evaluating the integrity of structures such as pipelines and pressure vessels, platforms, rigs and wind turbines, an ECA enables the user to make informed and confident decisions on the most appropriate remedial measures to take.

An ECA is used to decide whether a given flaw is safe from brittle fracture, plastic collapse, fatigue crack growth or creep crack growth under specified loading conditions. It can therefore be used:

·         During design, to assist in the choice of welding procedure and/or inspection techniques.

·         During fabrication, to assess:

o    a) the significance of known defects which are unacceptable to a given fabrication code; or 

o    b) the maximum critical flaw size, minimum fracture toughness or maximum operating stresses.

·         During operation, to assess flaws found in service and to make decisions as to whether they can safely remain, or whether down-rating, repair or replacement are necessary. 

There are standardised methods for ECA and these are now used routinely by the oil and gas, nuclear, aerospace,petrochemical and power industries to determine the safety of their structures. TWI has been deeply involved in the development of methods for conducting ECAs for more than 40 years, and can offer this service to its members on a consultancy basis. Our broad range of expertise and facilities, including advanced NDT, fatigue and fracture testingallows us to gather in-depth data as the basis for our ECAs.

ECA analysis to develop girth weld flaw acceptance criteria in accordance with the following codes:

·   API 1104 – Appendix A (19th and 20th editions)

·   DNV OS F101

·   DNV RP F108

·   BS 7910

·   API 579

Critical components assessed:

·   Flow lines including high pressure and high temperature (HP/HT)

·   Risers (SCRs, TTRs, hybrid, etc.)

·   Export pipelines

Pipeline installation methods include:

·   S-Lay

·   J-Lay

·   Reeled installation

Special ECA considerations:

·   Analysis, qualification and validation requirements for strain-based design, including reeling

·   Sour service ECA analysis and validation testing

Source :

http://www.microalloying.com/offshore-services/eca

http://www.twi-global.com/capabilities/integrity-management/engineering-critical-assessment/