tag:blogger.com,1999:blog-18393333760798380572024-03-14T04:59:08.220+07:00Albert Hutamaalberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.comBlogger22125tag:blogger.com,1999:blog-1839333376079838057.post-84009381508214470112014-02-01T03:54:00.001+07:002014-02-01T03:54:08.685+07:00Underwater Welding<p>The fact that electric arc could operate was known for over a 100 years. The first ever underwater welding was carried out by British Admiralty – Dockyard for sealing leaking ship rivets below the water line. Underwater welding is an important tool for underwater fabrication works. In 1946, special waterproof electrodes were developed in Holland by ‘Van der Willingen’. In recent years the number of offshore structures including oil drilling rigs, pipelines, platforms are being installed significantly. Some of these structures will experience failures of its elements during normal usage and during unpredicted occurrences like storms, collisions. Any repair method will require the use of underwater welding.</p> <p><strong><a href="http://lh6.ggpht.com/-KtV4CGULu7A/UuwNYS7wKiI/AAAAAAAABlY/sHEUZrUxqL8/s1600-h/image%25255B4%25255D.png"><img title="image" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="image" src="http://lh5.ggpht.com/-YwBnsQ8jPqQ/UuwNZ00htGI/AAAAAAAABlg/n-k1gIxQpGE/image_thumb%25255B2%25255D.png?imgmax=800" width="347" height="237"></a></strong></p> <p><strong>Classification</strong></p> <p>Underwater welding can be classified as <br>1) Wet Welding <br>2) Dry Welding <br> <br>In wet welding the welding is performed underwater, directly exposed to the wet environment. In dry welding, a dry chamber is created near the area to be welded and the welder does the job by staying inside the chamber. <br></p> <p><u>WET WELDING</u> <br>Wet Welding indicates that welding is performed underwater, directly exposed to the wet environment. A special electrode is used and welding is carried out manually just as one does in open air welding. The increased freedom of movement makes wet welding the most effective, efficient and economical method. Welding power supply is located on the surface with connection to the diver/welder via cables and hoses.</p> <p>In wet welding MMA (manual metal arc welding) is used. <br>Power Supply used : DC <br>Polarity : -ve polarity <br>When DC is used with +ve polarity, electrolysis will take place and cause rapid deterioration of any metallic components in the electrode holder. For wet welding AC is not used on account of electrical safety and difficulty in maintaining an arc underwater. <br><a href="http://lh4.ggpht.com/-HKu-MewkNgA/UuwNa0CIO9I/AAAAAAAABlo/L8QCuya08Ss/s1600-h/image%25255B9%25255D.png"><img title="image" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="image" src="http://lh4.ggpht.com/-GYVIif6-Ss0/UuwNbmJdplI/AAAAAAAABlw/bFPEUij2evE/image_thumb%25255B5%25255D.png?imgmax=800" width="440" height="246"></a></p> <p>The power source should be a direct current machine rated at 300 or 400 amperes. Motor generator welding machines are most often used for underwater welding in the wet. The welding machine frame must be grounded to the ship. The welding circuit must include a positive type of switch, usually a knife switch operated on the surface and commanded by the welder-diver. The knife switch in the electrode circuit must be capable of breaking the full welding current and is used for safety reasons. The welding power should be connected to the electrode holder only during welding.<br>Direct current with electrode negative (straight polarity) is used. Special welding electrode holders with extra insulation against the water are used. The underwater welding electrode holder utilizes a twist type head for gripping the electrode. It accommodates two sizes of electrodes.<br>The electrode types used conform to AWS E6013 classification. The electrodes must be waterproofed. All connections must be thoroughly insulated so that the water cannot come in contact with the metal parts. If the insulation does leak, seawater will come in contact with the metal conductor and part of the current will leak away and will not be available at the arc. In addition, there will be rapid deterioration of the copper cable at the point of the leak.</p> <p><u>Hyperbaric Welding (dry welding)<br></u>Hyperbaric welding is carried out in chamber sealed around the structure o be welded. The chamber is filled with a gas (commonly helium containing 0.5 bar of oxygen) at the prevailing pressure. The habitat is sealed onto the pipeline and filled with a breathable mixture of helium and oxygen, at or slightly above the ambient pressure at which the welding is to take place. This method produces high-quality weld joints that meet X-ray and code requirements. The gas tungsten arc welding process is employed for this process. The area under the floor of the Habitat is open to water. Thus the welding is done in the dry but at the hydrostatic pressure of the sea water surrounding the Habitat.</p> <p><strong>Risk Involved</strong></p> <p>There is a risk to the welder/diver of electric shock. Precautions include achieving adequate electrical insulation of the welding equipment, shutting off the electricity supply immediately the arc is extinguished, and limiting the open-circuit voltage of MMA (SMA) welding sets. Secondly, hydrogen and oxygen are produced by the arc in wet welding.<br>Precautions must be taken to avoid the build-up of pockets of gas, which are potentially explosive. The other main area of risk is to the life or health of the welder/diver from nitrogen introduced into the blood steam during exposure to air at increased pressure. Precautions include the provision of an emergency air or gas supply, stand-by divers, and decompression chambers to avoid nitrogen narcosis following rapid surfacing after saturation diving.<br>For the structures being welded by wet underwater welding, inspection following welding may be more difficult than for welds deposited in air. Assuring the integrity of such underwater welds may be more difficult, and there is a risk that defects may remain undetected.</p> <p><strong>Advantages and Disadvantages of Wet Welding</strong></p> <p><u>Advantages</u></p> <p>Wet underwater MMA welding has now been widely used for many years in the repair of offshore platforms. The benefits of wet welding are: -<br>1) The versatility and low cost of wet welding makes this method highly desirable.<br>2) Other benefits include the speed. With which the operation is carried out.<br>3) It is less costly compared to dry welding.<br>4) The welder can reach portions of offshore structures that could not be welded using other methods.<br>5) No enclosures are needed and no time is lost building. Readily available standard welding machine and equipments are used. The equipment needed for mobilization of a wet welded job is minimal.</p> <p><u>Disadvantages</u></p> <p>Although wet welding is widely used for underwater fabrication works, it suffers from the following drawbacks: -<br>1) There is rapid quenching of the weld metal by the surrounding water. Although quenching increases the tensile strength of the weld, it decreases the ductility and impact strength of the weldment and increases porosity and hardness.<br>2) Hydrogen Embrittlement – Large amount of hydrogen is present in the weld region, resulting from the dissociation of the water vapour in the arc region. The H2 dissolves in the Heat Affected Zone (HAZ) and the weld metal, which causes Embrittlement, cracks and microscopic fissures. Cracks can grow and may result in catastrophic failure of the structure.<br>3) Another disadvantage is poor visibility. The welder some times is not able to weld properly.</p> <p><strong>Advantages and Disadvantages of Dry Welding</strong></p> <p><u>Advantages</u></p> <p>1) Welder/Diver Safety – Welding is performed in a chamber, immune to ocean currents and marine animals. The warm, dry habitat is well illuminated and has its own environmental control system (ECS).<br>2) Good Quality Welds – This method has ability to produce welds of quality comparable to open air welds because water is no longer present to quench the weld and H2 level is much lower than wet welds.<br>3) Surface Monitoring – Joint preparation, pipe alignment, NDT inspection, etc. are monitored visually.<br>4) Non-Destructive Testing (NDT) – NDT is also facilitated by the dry habitat environment.</p> <p><u>Disadvantages</u></p> <p>1) The habitat welding requires large quantities of complex equipment and much support equipment on the surface. The chamber is extremely complex.<br>2) Cost of habitat welding is extremely high and increases with depth. Work depth has an effect on habitat welding. At greater depths, the arc constricts and corresponding higher voltages are required. The process is costly – a $ 80000 charge for a single weld job. One cannot use the same chamber for another job, if it is a different one.</p> <p><strong>Principle of operation of Wet Welding<br></strong>The process of underwater wet welding takes in the following manner:<br>The work to be welded is connected to one side of an electric circuit, and a metal electrode to the other side. These two parts of the circuit are brought together, and then separated slightly. The electric current jumps the gap and causes a sustained spark (arc), which melts the bare metal, forming a weld pool. At the same time, the tip of electrode melts, and metal droplets are projected into the weld pool. During this operation, the flux covering the electrode melts to provide a shielding gas, which is used to stabilize the arc column and shield the transfer metal. The arc burns in a cavity formed inside the flux covering, which is designed to burn slower than the metal barrel of the electrode.<br></p> <p><strong>Developments in Under Water Welding<br></strong>Wet welding has been used as an underwater welding technique for a long time and is still being used. With recent acceleration in the construction of offshore structures underwater welding has assumed increased importance. This has led to the development of alternative welding methods like friction welding, explosive welding, and stud welding. Sufficient literature is not available of these processes.<br></p> <p><strong>Scope for further developments<br></strong>Wet MMA is still being used for underwater repairs, but the quality of wet welds is poor and are prone to hydrogen cracking. Dry Hyperbaric welds are better in quality than wet welds. Present trend is towards automation. THOR – 1 (TIG Hyperbaric Orbital Robot) is developed where diver performs pipefitting, installs the trac and orbital head on the pipe and the rest process is automated.<br>Developments of diverless Hyperbaric welding system is an even greater challenge calling for annexe developments like pipe preparation and aligning, automatic electrode and wire reel changing functions, using a robot arm installed. This is in testing stage in deep waters. Explosive and friction welding are also to be tested in deep waters.</p> <p> </p> <p>Reference: </p> <p>Joshi, Amit Mukund. –. “Underwater Welding”. Bombay: Indian Institute of Technology. Link: <a href="http://www.metalwebnews.com/howto/underwater-welding/underwater-welding.pdf">http://www.metalwebnews.com/howto/underwater-welding/underwater-welding.pdf</a></p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com3tag:blogger.com,1999:blog-1839333376079838057.post-82936441292664568402014-02-01T03:30:00.001+07:002014-02-01T03:30:12.975+07:00Deepwater Pipeline Installation<p><b>Asle Venas</b><br><i>DNV</i> <p>Since the 1970s, offshore oil and gas development has gradually proceeded from shallow-water installations up to around 400 m (1,312 ft) to the ultra-deep waters around 3,000 m (9,842 ft) that represent the maximum today. The question is whether the curve will flatten at 3,000 m, or if this is just a temporary pause on the way to even greater depths. There have been plans for a gas trunkline from Oman to India at 3,500 m (11,483 ft) depth, but it is yet to be seen if there will be many such projects in the near future. <h4> </h4> <h4>Pipe wall thickness</h4> <p>The main design challenge for development beyond 3,000 m is related to the high external pressure that may cause collapse of the pipeline. From depths of 900 m (2,953 ft) onwards, external over-pressure is normally the most critical failure mode for pipelines. The risk of collapse is typically most critical during installation when the pipe is empty and external over-pressure is at its maximum. <p><img alt="Many of the world's offshore pipelines are designed and constructed to DNV's pipeline standard DNV-OS-F101, and new concepts such as pipe-in-pipe may easily be accounted for by adjusting the relevant failure modes. (Photo courtesy DNV) " src="http://www.offshore-mag.com/content/dam/offshore/print-articles/Volume%2073/08/dnv1-1308off.jpg"> <p>Many of the world's offshore pipelines are designed and constructed to DNV's pipeline standard DNV-OS-F101, and new concepts such as pipe-in-pipe may easily be accounted for by adjusting the relevant failure modes. (Photo courtesy DNV) <p>In addition, the pipe will be exposed to large bending deformation in the sag bend during installation that may trigger collapse, and collapse may also be relevant for operational pipelines subject to significant corrosion. <p>The main manufacturing processes relevant for larger-diameter, heavy-wall line pipes are UO shaped, welded and expanded/compressed (UOE/C, JCOE) and three roll bending. These processes provide a combination of excellent mechanical properties, weldability, dimensional tolerances, high production capacities and relatively low costs compared to seamless pipes. <p>There are at least six pipe mills that regularly supply heavy-wall, welded line pipe for offshore projects based on the UOE process: Tata Steel, Europipe, JFE, Nippon Steel, Sumitomo, and Tenaris. Research into further improving manufacturing techniques continues in the industry, and we also see several "newcomers" that can produce good quality pipes for deepwater. <p>This potential failure mode is normally dealt with by increasing the pipe wall thickness. But at ultra-deepwater depths, this may require a very thick walled pipe that becomes costly, difficult to manufacture, and hard to install due to its weight. Currently, there is a practical limit on wall thickness that limits the maximum water depth for 42-in. pipes to around 2,000 m (6,562 ft) while for a 24-in. pipe, this limit is approximately doubled to 4,000 m (13,123 ft). <p>Three factors have a major influence on the final compressive strength of the pipeline: quality of plate feedstock, optimization of compression and expansion during pipe forming, and light heat treatment. By focusing on these factors together with improving the ovality of the final pipe, it is possible to obtain a collapse resistance comparable to that of seamless pipes. <h4> </h4> <h4>X-Stream</h4> <p>X-Stream is a novel pipeline concept developed by DNV that aims to solve the collapse challenge by limiting and controlling the external over-pressure. In a typical scenario, the pipeline is installed partially water-filled, and is thus pressurized at large water depths. Then, to ensure that the internal pressure does not drop below a certain limit during the operational phase when it is filled with gas, it is equipped with a so-called inverse HIPPS (i-HIPPS). <p>This system also includes some inverse double-block-and-bleed (i-DBB) valves. It is inverse in the sense that instead of bleeding off any leakage to avoid pressure build up in standard DBB systems, any leakage and loss of pressure is avoided by a pressurized void between the double blocks. This is needed to avoid unintended depressurization by a leaking valve which may not be 100% pressure tight when the pipeline system is shut down. Studies undertaken during the development of X-Stream show that the weight increase due to flooding is more or less balanced by the reduction in steel weight. <p>X-Stream is still at the concept development stage. Some practical aspects need to be studied, such as how to install large valves in ultra- deepwater. Another aspect is repair procedures and equipment, even though that should not be much different from normal ultra-deepwater pipelines. There are also some optimizations to be performed with respect to pressure loss during operation and equalization of the pressure during shutdown. <p>However, the potential benefits of the X-Stream concept to gas export and trunk lines at ultra-deep waters are quite significant, such as: <ul> <li>Reduced steel quantity and associated costs <li>Use of standard pipe dimensions, even for ultra-deepwater and large diameters, reduces line pipe costs <li>No need for buckle arrestors <li>No need for reserve tension capacity in case of accidental flooding.</li></ul> <p>In addition, a rough cost comparison indicates a 10-30% cost reduction (steel cost, transportation cost, welding cost) compared with a traditional gas trunk line. <h4> </h4> <h4>Installation methods</h4> <p>There are three main methods used to install offshore pipelines: reeling, S-lay, and J-Lay. In ultra-deep waters, the combined loading of axial force, bending, and external over-pressure during installation can also be critical to wall thickness design. A significant external over-pressure in ultra-deep waters sets up both a compressive longitudinal stress and a compressive hoop stress. Both tend to trigger local buckling at less bending compared to a pipe without the external over-pressure. <p>A common challenge for all installation methods when it comes to deep and ultra-deep waters is the tension capacity. The catenary length before the pipeline rests at the seabed can become quite long, due to the water depth. The pipe needs to be very thick walled to have the necessary collapse capacity; and thus the submerged weight can become high. It is also often required that the installation vessel be capable of holding the pipe in case of accidental flooding (e.g. a wet buckle). However, it is still a topic of discussion whether it is absolutely necessary to be able to hold an accidentally flooded pipe. <p>The tension capacity of current vessels limits the water depth for 18 to 24-in. pipelines to around 3,000 m, when not accounting for the accidental flooding case. The limit for 30-in. pipelines is around 2,100 to 2,500 m (6,890 to 8,202 ft). New vessels with a tension capacity of 2,000 metric tons (2,204 tons) will be able to install up to 24-in. or maybe 26-in. pipes at 4,000 m (13,123 ft) water depth, while for 42-in. pipelines the maximum depth will be around 2,500 m (8,202 ft). <p>Another challenge related to deepwater installation is how to detect buckles during installation. Normally, a gauge plate is pulled through the pipeline by a wire at a certain distance behind the touchdown point. In case of a buckle, the wire pulling force will increase to indicate that something is wrong. However, in ultra-deep waters, the length of the wire and the friction between the wire and the curved pipeline may give challenges in detecting minor buckles. Having a long wire and buckle detector inside a pipeline during installation can also be risky. If the pipeline is lost, the water will push the wire and gauge plate inside the pipeline and it may not be possible to get it out again. <h4> </h4> <h4>Suspended installation</h4> <p>The Ormen Lange field is located in a pre-historic slide area, with an uneven seabed at nearly 900 m (2,953 ft) water depth. In its early development phase, a submerged, floating pipeline concept was studied to overcome the challenging seabed conditions. By mooring the buoyant pipeline to the seabed, no seabed intervention work would be required. The concept was left for the benefit of a more traditional concept with the pipeline on the seabed mainly because of the challenges with interference between trawl gear and the mooring lines, but it is still considered feasible both with respect to installation and operation. <p>Another floating pipeline concept has been developed by Single Buoy Moorings. Here the buoyancy is ensured by a large-diameter carrier pipe to which the smaller pipelines are attached. Buoyancy modules, clump weights, and the end anchoring system ensure tension in the pipeline bundle. A short bundle connecting the FPSO and the spar has been installed at Kikeh offshore Malaysia. However, the maximum length of this concept can be extended by use of intermediate vertical supports. Potential challenges will be hydrodynamic forces, both the steady-state drag and the cyclic ones, including vortex-induced vibrations. The challenge is to balance the need for anchoring with the need for flexibility to absorb the forces. (e.g., by making the attachment to the mooring lines in such a way that it does not cause too concentrated bending deformations). <h4> </h4> <h4>Spiral installation</h4> <p>A future solution for ultra-deep and topologically challenging locations may be to further develop the SpiralLay method developed by Eurospiraal. In this application, the line pipes are joined onshore and wound into a spiral for towing offshore. The spiral can take a quite long length of pipeline which makes it possible to pressurize it. On location, the pipeline is un-wound and installed in a short time. The concept involves installing a pressurized pipeline from a submerged spiral floating at a safe distance above the seabed, thus avoiding the challenges with the combined loading in the sag bend at deep and ultra-deepwater depths. This is a novel concept and needs further development and testing. <h4> </h4> <h4>Seabed intervention</h4> <p>Seabed intervention and tie-in become more challenging with increasing water depth. Some of the equipment, such as fall pipes for rock installation vessels, have practical limitations (e.g. the maximum length of the fall pipe). The same is the case with ROVs and other equipment needed for installation. Some repair methods - such as retrieving a damaged part to the surface or using subsea welding with divers - are limited by water depth, and can only be used in 200 to 400-m (656 to 1,132-ft) waters. For deepwater, repair methods based on remotely controlled equipment are needed. <p>Recently developed repair methods for deepwater are based on different types of clamps that are fitted over a locally damaged area; or involve cutting and replacing a section with use of end flanges/couplings and spool pieces. In cases with extreme or comprehensive damage, a new pipeline section may be installed. Typically, both the clamps and the end couplings need to be sealed with grouting or metallic seals. Examples are the Oceaneering systems based on Smart Flange/Connector/Clamp and the Chevron deepwater repair system. These are under development, and designed to operate down to 3,000 m water depths. The Statoil-led PRS consortium is also developing a repair system for deepwater based on remotely welded sleeves. This system is based on two lifting frames, cutting the damaged part, then installing some couplings and a new spool piece. <h4> </h4> <h4>Notation fosters innovation</h4> <p>Today, 65% of the world's offshore pipelines are designed and constructed to DNV's pipeline standard DNV-OS-F101. It is the only internationally recognized offshore pipeline standard that complies with the ISO codes. The ISO pipeline standard itself, the ISO-13623, is more like a goal setting standard with basically one hoop stress criterion and one equivalent stress criterion, and with little guidance for engineers on how to actually design a pipeline. Here, DNV-OS-F101 has found its niche, giving more detailed requirements in compliance with ISO-13623. <p>Another reason for the standard's success is that it is based on the so-called limit state design, where all potential failure modes have to be checked according to specific design criteria with given safety factors. This makes it easy to apply the code to novel designs and outside the typical application range (e.g. in deep and ultra-deep waters, in Arctic environments). <p>The collapse capacity and the fabrication factor for UOE line pipes may be taken as a good example of the flexibility of the DNV-OS-F101 code. The code contains a clause allowing for upgrading the fabrication factor due to different aspects such as light heat treatment and/or compression, instead of expansion at the end of the manufacturing process. The code is also quite transparent in the way the design criterion is written in order to facilitate and take into account innovation and improvements in the fabrication process. Similarly, new concepts such as the X-stream or various pipe-in-pipe concepts may easily be accounted for by adjusting the relevant failure modes, and adding new ones if relevant. <p>The most likely deep and ultra-deep potential field development areas known today are Gulf of Mexico, the Brazilian presalt areas, and East and West Africa. All pose challenges that could benefit from technology development and innovation. <p>Reference: “New installation methods may facilitate ultra-deepwater pipelay” ,<a href="http://www.offshore-mag.com/articles/print/volume-73/issue-8/flowlines-and-pipelines/new-installation-methods-may-facilitate-ultra-deepwater-pipelay.html">http://www.offshore-mag.com/articles/print/volume-73/issue-8/flowlines-and-pipelines/new-installation-methods-may-facilitate-ultra-deepwater-pipelay.html</a>, August 2013.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com2tag:blogger.com,1999:blog-1839333376079838057.post-30092338662730710412014-01-28T16:53:00.001+07:002014-01-28T16:53:51.095+07:00Pipe-in-Pipe New Design<p>Increasing demand for energy, matched with high commodity prices and advances in technology, are driving operators to extract whatever reserves remain in the challenging UK continental shelf. Therefore, the requirement to transfer these multi-phase products from often high-pressure/high-temperature (HP/HT) wells back onshore is an even more demanding prospect.</p> <p>Up until now, the common belief in the industry was that pipe-in-pipe systems able to withstand environmental challenges such as corrosion, structural integrity, and thermal management, would be too costly and complex to apply to riser systems. <p>Tata Steel worked closely with supply partners to engineer, procure, and construct these assemblies to further develop this innovative technology as a cost-effective solution to flow assurance issues. <h4>Need for insulation</h4> <p>HP/HT fields are technically more complex to develop because of the inherently higher energy in the well fluid and its multi-phase composition. Managing the extreme pressure and operating temperature must be based and evaluated on criteria such as corrosion, maintaining structural integrity, and thermal management. <p>One particular challenge is the management of pipeline shutdown. Less expensive solutions for managing the insulation of bends such as wet coatings, compromise overall shutdown times due to reduced thermal efficiency. Solutions, such as "self-draining" spools, present a significant design challenge that can be mitigated by the inclusion of pipe-in-pipe bends, enabling the same thermal integrity to be maintained in the whole line. <p>Tata Steel has previously implemented a solution for pipe-in-pipe bends for a North Sea development. Since then, new insulation techniques have been developed that give far superior insulation properties. <h4>Risers, spools, and bends</h4> <p>The main challenge with the construction of pipe-in-pipe bends is how to pass the inner flowline bend into the outer casing pipe. It is important that pipe bends have a straight portion on the end to enable efficient welding to the next pipe section and this can present the insertion of one bend into the other. <p>The second construction challenge is efficient insulation. Wrapping or sheathing is simply not practical here as the insulation would occupy the annulus of the assembly and prevent the integration. <h4>New insulation system</h4> <p><img alt="Drawing of the geometry of one pipe into another." src="http://www.offshore-mag.com/content/dam/offshore/print-articles/Volume%2073/04/tata1-1304off.jpg"> <p>Drawing of the geometry of one pipe into another. <p>The system developed by Tata Steel overcomes these problems by deploying granular Nanogel insulation into the annulus of the pipe-in-pipe system. Nanogel is made by first forming a silica gel, then expelling the water from the silica matrix. The resulting material is granular with trapped nanopores of air, inhibiting heat transfer by conduction, convection, and radiation (with the inclusion of an opacifier). <p>The deployment of a novel polymeric bulkhead, cast directly into the annulus, provides a solid barrier to retain the insulation, which allows for the relative movement of the inner and outer bends. The polymer is a "syntactic" material, silicone rubber with glass microspheres dispersed through the matrix with high strength, flexibility, and thermal efficiency. The tangent ends of the inner and outer bends are held rigidly to ensure that the assembly tolerances achieved at manufacture are retained when the unit is transferred to the welding contractor for incorporation into the pipeline spool or riser. <p>In order for the insulation to be effectively deployed and provide the consistent thermal performance, the annular gap throughout the assembly must be uniform. It is important the manufacturing tolerances of the pipe and bends are closely controlled. <h4>Steel pipe and bend manufacture</h4> <p>Together with Tata Steel, Eisenbau Krämer (EBK) and the pipe bending plant of Salzgitter Mannesmann Grobblech (SMGB) have developed a series of controls, including a process and measurement system, to ensure all bend dimensions are closely controlled and mating bends can be produced, matched, and paired to ensure the most accurate assembly is produced. <p>In respect to the process-related thinning in the extrados of the hot induction bends, the wall thickness for the inner and outer mother pipes was increased accordingly. To match precisely, the mother pipes have been manufactured with the same ID as the riser pipes. <p><img alt="16-in. clad bends being transferred to the quenching tank after austenitization at SMGB pipe bending mill." src="http://www.offshore-mag.com/content/dam/offshore/print-articles/Volume%2073/04/tata2-1304off.jpg"> <p>16-in. clad bends being transferred to the quenching tank after austenitization at SMGB pipe bending mill. <p>EBK supplied Tata Steel with the mother pipe, which has material properties that allow formation through hot induction bending. The main material challenges are to ensure the mechanical properties are suitable after bending. Therefore, SMGB is taking responsibility for the chemical design of the pre-material. This also involves the consideration of a series of heat treatment and forming processes. EBK uses a multi-pass welding process and steel plate from premium mills in Europe. The manufacturing process at EBK generates pipe of the closest dimensional control through a series of cold forming and sizing operations such as external calibration. <p>At the SMGB pipe bending plant, the special mother pipes are bent by hot induction bending. Heat is applied through electrical induction to the mother pipe materials and the pipe is slowly formed to give the correct geometry. In most pipeline applications the critical dimensions are the positions and attitudes of the ends of the bends (center-to-end dimension) to maintain the overall geometry of the pipeline. However, with pipe-in-pipe bends it is important that the bend radius is also accurately controlled to ensure the two bends can be integrated. The precise dimensions after bending also need to be maintained following heat treatment. For the inner clad bends, a full-body quench and temper heat treatment is applied at the SMGB bending mill in order to guarantee homogenized material properties for the bends, to fulfill mechanical and corrosion requirements. <h4>HP/HT material properties</h4> <p>Additional material complexities have to be overcome. Generally, in HP/HT lines there are challenges because of corrosion, low temperature toughness, and strength. These parameters require careful material selection to maintain the balance of properties from the outset through to bend production. Thermal stresses need to be managed as the loads are shared between inner and outer pipe. In addition, the insulation can lead to extremes of temperature being retained in the pipe materials during operation and shutdown that can form challenging conditions for conventional steel products. <h4>Conclusion</h4> <p>HP/HT well environments present some of the most challenging and technologically demanding conditions for field developments, not least because the properties in each reserve offer significant challenges in terms of material selection and design. <p>Tata Steel and its supply partners have expanded capabilities further with the design and creation of cost-effective insulated pipe-in-pipe bends for risers and spools - an accomplishment previously considered too difficult. <p>Pipe-in-pipe bends, while challenging technologically, can lead to simplification of overall pipeline design and can give better pipeline performance in times of operation and shutdown. <p>Reference: “New pipe-in-pipe design ensures effective insulation”, <a href="http://www.offshore-mag.com/articles/print/volume-73/issue-4/engineering-construction-installation/new-pipe-in-pipe-design-ensures-effective-insulation.html">http://www.offshore-mag.com/articles/print/volume-73/issue-4/engineering-construction-installation/new-pipe-in-pipe-design-ensures-effective-insulation.html</a>, January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-81963383858985233652014-01-28T16:51:00.001+07:002014-01-28T16:51:24.665+07:00Pipeline Buckling and Collapse<p>With ultra deepwater pipelines being considered for water depths of nearly 3,000 m, pipe collapse, in many instances, will govern design. For example, bending loads imposed on the pipeline near the seabed (sagbend region) during installation will reduce the external pressure resistance of the pipeline, and this design case will influence (and generally govern) the final selection of an appropriate pipeline wall thickness. <p>To date, the deepest operating pipelines have been laid using the J-lay method, where the pipeline departs the lay vessel in a near-vertical orientation, and the only bending condition resulting from installation is near the touchdown point in the sagbend. More recently, however, the S-lay method is being considered for installation of pipelines to water depths of nearly 2,800 m. During deepwater S-lay, the pipeline originates in a horizontal orientation, bends around a stinger located at the stern or bow of the vessel, and then departs the lay vessel in a near-vertical orientation. During S-lay, the installed pipe experiences bending around the stinger (overbend region), followed by combined bending and external pressure in the sagbend region. <p><img border="0" alt="" src="http://images.pennnet.com/articles/os/thm/th_z0611offdwpl1.gif" width="331" align="center" height="234"><br><i>Initial bending in the overbend during pipe installation may result in stress concentrations in pipe-to-pipe weld offsets or in pipe-to-buckle arrestor interfaces.</i> <p>In light of these bending and external pressure-loading conditions, analytical work was performed to better understand the local buckling behavior of thick-walled line pipe due to bending, and the influence of bending on pipe collapse. Variables considered in the analytical evaluations include pipe material properties, geometric properties, pipe thermal treatment, the definition of critical strain, and imperfections such as ovality and girth weld offset. <h4>Design considerations</h4> <p>As the offshore industry engages in deeper water pipeline installations, design limits associated with local buckling must be considered and adequately addressed. Instances of local buckling include excessive bending resulting in axial compressive local buckling, excessive external pressure resulting in hoop compressive local buckling, or combinations of axial and hoop loading creating either local buckling states. In particular, deepwater pipe installation presents perhaps the greatest risk of local buckling, and a thorough understanding of these limiting states and loading combinations must be gained in order to properly address installation design issues. <p>Initial bending in the overbend may result in stress concentrations in pipe-to-pipe weld offsets or in pipe-to-buckle arrestor interfaces. Initial overbend strains, if large enough, may also give rise to increases in pipe ovalization, perhaps reducing its collapse strength when installed at depth. Active bending strains in the sagbend will also reduce pipe collapse strength, as has been previously demonstrated experimentally. <h4>Overall modeling approach</h4> <p>In an attempt to better understand pipe behavior and capacities under the various installation loading conditions, the development and validation of an all-inclusive finite element model was performed to address the local buckling limit states of concern during deepwater pipe installation. The model can accurately predict pipe local buckling due to bending, due to external pressure, and to predict the influence of initial permanent bending deformations on pipe collapse. Although model validation is currently being performed for the case of active bending and external pressure (sagbend), no data has been provided for this case. <p>The finite element model developed includes non-linear material and geometry effects that are required to accurately predict buckling limit states. Analysis input files were generated using our proprietary parametric generator for pipe type models that allows for variation of pipe geometry (including imperfections), material properties, mesh densities, boundary conditions and applied loads. <p>A shell type element was selected for the model due to increased numerical efficiency with sufficient accuracy to predict global responses. The Abaqus S4R element is a four-node, stress/displacement shell element with large-displacement and reduced integration capabilities. <p>All material properties were modeled using a conventional plasticity model (von Mises) with isotropic hardening. Material stress-strain data was characterized by fitting experimental, uniaxial test results to the Ramberg-Osgood equation. <p>Pipe ovalizations were also introduced into all models to simulate actual diameter imperfections, and to provide a trigger for buckling failure mode. This was done during model generation by pre-defining ovalities at various locations in the pipe model. <h4>Bending case</h4> <p>A pipe bend portion of the model was developed to investigate local buckling under pure moment loading. Due to the symmetry in the geometry and loading conditions, only one half of the pipe was modeled, in order to reduce the required computational effort. The pipe mesh was categorized into four regions <ul> <li>Two refined mesh areas located over a length of one pipe diameter on each side of the mid-point of the pipe to improve the solution convergence (location of elevated bending strains and subsequent buckle formation) <li>Two coarse mesh areas at each end to reduce computational effort.</li></ul> <p>Clamped-end boundaries were imposed on each end of the pipe model to simulate actual test conditions (fully welded, thick end plate). Under these assumptions, the end planes (nodes on the face) of both ends of the pipe were constrained to remain plane during bending. Loading was applied by controlled rotation of the pipe ends. <p>In terms of material properties, the axial compressive stress-strain response tends to be different from the axial tensile behavior for UOE pipeline steels. To accurately capture this difference under bending conditions, the upper (compressive) and lower (tension) halves of the pipe were modeled with separate axial material properties (derived from independent axial tension and compression coupon tests). <p>In general, the local compressive strains along the outer length of a pipe undergoing bending will not be uniform due to formation of a buckle profile. In order to specify the critical value at maximum moment for an average strain, four methods were selected based on available model data and equivalence to existing experimental methods. <h4>Collapse case</h4> <p>The same model developed for the bending case was used to predict critical buckling under external hydrostatic pressure. This included the use of shell type elements and the same mesh configuration. In the analyses, a uniform external pressure load was incrementally applied to all exterior shell element faces. Radially constrained boundary conditions were also imposed on the nodes at each end of the pipe to simulate actual test conditions (plug at each end). In contrast to the pipe bend analysis, only a single stress-strain curve (based on compressive hoop coupon data) was used to model the material behavior of the entire pipe. <h4>Bending case validation</h4> <p>The pipe bend finite element model was validated using full-scale and materials data obtained from the Blue Stream test program, both for “as received” (AR) and “heat treated” (HT) pipe samples. Geometrical parameters were taken from the Blue Stream test specimens and used in the model validation runs. Initial ovalities based on average and maximum measurements were also assigned to the model. The data distribution reflects the relative variation in ovality measured along the length of the Blue Stream test specimens. <p><img border="0" alt="" src="http://images.pennnet.com/articles/os/thm/th_z0611offdwpl2.gif" width="316" align="center" height="201"><br><i>All of finite element models included analysis input files generated using parametric generator for pipe type models that allows for variation of pipe geometry (including imperfections), material properties, mesh densities, boundary conditions, and applied loads.</i> <p>Axial tension and compression engineering stress-strain data used in the model validation were based on curves fit to experimental coupon test results. As pointed out previously, separate compression and tension curves were assigned to the upper and lower pipe sections, respectively, in order to improve model accuracy. <p>In the validation process, a number of analyses were performed to simulate the Blue Stream test results (base case analyses), and to investigate the effects of average strain definition, gauge length, and pipe geometry. These analyses, comparisons and results were: <ul> <li>The progressive deformation during pipe bending for the AR pipe bend showed the development of plastic strain localization at the center of the specimen <li>A comparison between the resulting local and average axial strain distributions for two nominal strain levels indicated that at the lower strain level the distribution of local strain is relatively uniform, at the critical value (peak moment) a strain gradient is observed over the length of the specimen with localization occurring in the middle, the end effects are quite small due to specimen constraint and were observed at both strain levels <li>The resulting moment-strain response for the AR pipe base case analysis found the calculated critical (axial) strain slightly higher than that determined from the Blue Stream experiments <li>The effect of chosen strain definition and gauge length on the critical bending strain for the AR pipe base case analysis, using the four methods for calculating average strain, gave similar results <li>The critical strain value is somewhat sensitive to gauge length for a variety of OD/t ratios <li>The finite element results are seen to compare favorably with existing analytical solutions and available experimental data taken from the literature. For pipe under bending, heat treatment results in only a slight increase in critical bending strain capacity.</li></ul> <h4>Collapse case validation</h4> <p>Similar to the pipe bending analysis, the plain pipe collapse model was also validated using full-scale and materials data obtained from the Blue Stream test program, both for “as received” (AR) and “heat treated” (HT) pipe samples. Pipe geometry and ovalities measurements taken from the Blue Stream collapse specimens were used in the validation analyses. Initial ovalities based on average and maximum measurements were also assigned to the model at different reference points. Hoop compression stress-strain data was used in the model, and was based on the average of best fit curves from both ID and OD coupon specimens, respectively. To validate the pipe collapse model, comparison was made to full-scale results from the Blue Stream test program which demonstrated a very good correlation between the model predictions and the experimental results. <p>In addition to the base case, further analyses were run for a number of alternate OD/t ratios ranging from 15 to 35. Similar to the pipe bend validation, the OD/t ratio was adjusted by altering the assumed wall thickness of the pipe. The finite element results have compared favorably with available experimental data taken from the literature. <p>The beneficial effect of pipe heat treatment for collapse has resulted in a significant increase in critical pressure (at least 10% for an OD/t ratio of 15). The greatest benefit, however, is observed only at lower OD/t ratios (thick-wall pipe). This can be attributed to the dominance of plastic behaviour in the buckling response as the wall thickness increases (for a fixed diameter). At higher OD/t ratios, buckling is elastic and unaffected by changes in material yield strength. <h4>Pre-bent effect on collapse</h4> <p>Finite element analyses were also performed to simulate recent collapse tests conducted on pre-bent and straight UOE pipe samples for both “as received” (AR) and “heat treated” (HT) conditions. The intent of these tests was to demonstrate that there was no detrimental effect on collapse capacity due to imposed bending as a result of the overbend process. In the pre-bend pipe tests, specimens were bent up to a nominal strain value of 1%, unloaded, then collapse tested under external pressure only. <p><img border="0" alt="" src="http://images.pennnet.com/articles/os/thm/th_z0611offdwpl3.gif" width="327" align="center" height="176"><br>To address the pre-bend effect on collapse, a simplified modeling approach was used whereby the increased ovalities and modified stress-strain properties in hoop compression due to the pre-bend were input directly into the existing plain pipe collapse model (the physical curvature in the pipe was ignored). <p>To address this loading case, a simplified modeling approach was used whereby the increased ovalities and modified stress-strain properties in hoop compression due to the pre-bend were input directly into the existing plain pipe collapse model (the physical curvature in the pipe was ignored). <p>A comparison between the predicted and experimental collapse pressures for both pre-bent and straight AR and HT pipes indicates that the model does a reasonable job of predicting the collapse pressure for both pipe conditions. It is also clear that the effect of moderate pre-bend (1%) on critical collapse pressure is relatively small. <p>While the pre-bend cycle results in an increased ovality in the pipe, this detrimental effect is offset by a corresponding strengthening due to strain hardening. As a result, the net effect on collapse is relatively small. For the AR pipe samples, there was a slight increase in collapse pressure when the pipe was pre-bent. Conversely, for the HT pipe, the opposite trend was observed. This latter decrease in collapse pressure can be attributed to two effects: the larger ovality that resulted from the pre-bend cycle and the limited strengthening capacity available in the HT pipe (the HT pipe thermal treatment increased the hoop compressive strength, offering less availability for cold working increases due to the pre-bend). <p>Similar to previous experimental studies on thermally aged UOE pipe, the beneficial effect of heat treatment was demonstrated in the pre-bend analysis. The collapse pressure for the pre-bent heat treated (HT) pipe is approximately 8-9% higher than that for the as received (AR) pipe, based on both the analytical and experimental results. This increase, however, is lower than that observed for un-bent pipe (approximately 15-20% based on analysis and experiments). <p>This unique case of an initial permanent bend demonstrated that the influence on the collapse strength of a pipeline was minimal resulting from an increase in hoop compressive strength (increasing collapse strength), and an increase in ovality (reducing collapse strength). This directly suggests that excessive bending in the overbend will not significantly influence collapse strength. <p>Future work includes advancing the model validation to the case of active bending while under external pressure. This condition exists at the sagbend region of a pipeline during pipelay and, in many cases, will govern overall pipeline wall thickness design. <p>Reference: “Understanding pipeline buckling in deepwater applications”, <a href="http://www.offshore-mag.com/articles/print/volume-66/issue-11/pipeline-transportation/understanding-pipeline-buckling-in-deepwater-applications.html">http://www.offshore-mag.com/articles/print/volume-66/issue-11/pipeline-transportation/understanding-pipeline-buckling-in-deepwater-applications.html</a>, Janaury 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com1tag:blogger.com,1999:blog-1839333376079838057.post-2304005153600581022014-01-28T16:38:00.001+07:002014-01-28T16:38:42.400+07:00Pipeline Crack Propagation<p>Polyethylene (PE) is the primary material used for gas pipe applications. Because of its flexibility, ease of joining and long-term durability, along with lower installed cost and lack of corrosion, gas companies want to install PE pipe instead of steel pipe in larger diameters and higher pressures. As a result, rapid crack propagation (RCP) is becoming a more important property of PE materials. <p>This article reviews the two key ISO test methods that are used to determine RCP performance (full-scale test and small-scale steady state test), and compare the values obtained with various PE materials on a generic basis. It also reviews the status of RCP requirements in industry standards; such as ISO 4437, ASTM D 2513 and CSA B137.4. In addition, it reviews progress within CSA Z662 Clause 12 and the AGA Plastic Materials Committee to develop industry guidelines based on the values obtained in the RCP tests to design against an RCP incident. <p><strong>Background</strong> <p>Although the phenomenon of RCP has been known and researched for several years 1, the number of RCP incidents has been very low. A few have occurred in the gas industry in North America, such as a 12-inch SDR 13.5 in the U.S. and a 6-inch SDR 11 in Canada, and a few more in Europe. <p>With gas engineers desiring to use PE pipe at higher operating pressures (up to 12 bar or 180 psig) and larger diameters (up to 30 inches), a key component of a PE piping material - resistance to rapid crack propagation (RCP) - becomes more important. <p>Most of the original research work conducted on RCP was for metal pipe. As plastic pipe became more prominent, researchers applied similar methodologies used for metal pipe on the newer plastic pipe materials, and particularly polyethylene (PE) pipe 2. Most of this research was done in Europe and through the ISO community. <p>Rapid crack propagation, as its name implies, is a very fast fracture. Crack speeds up to 600 ft/sec have been measured. These fast cracks can also travel long distances, even hundreds of feet. The DuPont Company had two RCP incidents with its high-density PE pipe, one that traveled about 300 feet and the other that traveled about 800 feet. <p>RCP cracks usually initiate at internal defects during an impact or impulse event. They generally occur in pressurized systems with enough stored energy to drive the crack faster than the energy is released. Based on several years of RCP research, whether an RCP failure occurs in PE pipe depends on several factors: <ol> <li>Pipe size. <li>Internal pressure. <li>Temperature. <li>PE material properties/resistance to RCP. <li>Pipe processing.</li></ol> <p>Typical features of an RCP crack are a sinusoidal (wavy) crack path along the pipe, and “hackle” marks along the pipe crack surface that indicate the direction of the crack. At times, the crack will bifurcate (split) into two directions as it travels along the pipe.<br><strong><br>Test Methods</strong> <p>The RCP test method that is considered to be the most reliable is the full-scale (FS) test method, as described in ISO 13478. This method requires at least 50 feet of plastic pipe for each test and another 50 feet of steel pipe for the reservoir. It is very expensive and time consuming. The cost to obtain the desired RCP information can be in the hundreds of thousands of dollars. <p>Due to the high cost for the FS RCP test, Dr. Pat Levers of Imperial College developed the small-scale steady state (S4) test method to correlate with the full-scale test3. This accelerated RCP test uses much smaller pipe samples (a few feet) and a series of baffles, and is described in ISO 13477. The cost of conducting this S4 testing is still expensive, but less than FS testing. Several laboratories now have S4 equipment. A photograph with this article shows the S4 apparatus used by Jana Laboratories. <p>Whether conducting FS or S4 RCP testing, there are two key results used by the piping industry; one is the critical pressure and the other is the critical temperature. <p>The critical pressure is obtained by conducting a series of FS or S4 tests at a constant temperature (generally 0C) and varying the internal pressure. At low pressures, where there is insufficient energy to drive the crack, the crack initiates and immediately arrests (stops). At higher pressures, the crack propagates (goes) to the end of the pipe. The critical pressure is shown by the red line in Figure 1 as the transition between arrest at low pressures and propagation at high pressures. In this case, the critical pressure is 10 bar (145 psig). <p>Figure 1: Critical Pressure (Plot of crack length vs. pressure)<br>Data obtained at 0° C (32°F). <p>Due to the baffles in the S4 test, the critical pressure obtained must be corrected to correlate with the FS critical pressure. There has been considerable research within the ISO community conducted in this area. Dr. Philippe Vanspeybroeck of Becetel chaired a working group - ISO/TC 138/SC 5/WG RCP - that conducted S4 and FS testing on several PE pipes 4. Based on their extensive research effort, the WG arrived at the following correlation formula 5 to convert the S4 critical pressure (Pc,S4) to the FS critical pressure (Pc,FS): <p>Pc,FS = 3.6 Pc,S4 + 2.6 bar (1) <p>It is important to note that this S4/FS correlation formula may not be applicable to other piping materials, such as PVC or polyamide (PA). For example, Arkema has conducted S4 and FS testing on PA-11 pipe and found a different correlation formula for PA-11 pipe 6. <p>The critical temperature is obtained by conducting a series of FS or S4 tests at a constant pressure (generally 5 bar or 75 psig) and varying the temperature 7. At high temperatures the crack initiates and immediately arrests. At low temperatures, the crack propagates to the end of the pipe. The critical temperature is shown by the red line in Figure 2 as the transition between arrest at high temperatures and propagation at low temperatures. In this case, the critical temperature is 35°F (2°C). <p>Figure 2: Critical Temperature (Plot of crack length vs. temperature)<br>Data obtained at 5 bar (75 psig).<br><strong><br>RCP In ISO</strong> <p>The International Standards Organization (ISO) product standard for PE gas pipe, ISO 4437, has included an RCP requirement for many years 8. This is because there were some RCP failures in early generation European PE gas pipes, and the Europeans had conducted considerable research on RCP in PE pipes. Also, European gas companies were using large-diameter pipes and higher operating pressures for PE pipes, both of which make the pipe more susceptible to RCP failures. Below is the current requirement for RCP taken from ISO 4437: <p>Pc > 1.5 x MOP (2) <p>Where: Pc = full scale critical pressure, psig<br>MOP = maximum operating pressure, psig <p>Most manufacturers use the S4 test to meet this ISO 4437 RCP requirement. If the requirement is not met, then the manufacturer may use the FS test. Therefore, the ISO 4437 product standard requires that RCP testing be done, and also provides values for the RCP requirement. <p><strong>RCP In ASTM</strong> <p>Until recently, ASTM D 2513 did not address RCP at all 9. The AGA Plastic Materials Committee (PMC) requested that an RCP requirement be added to ASTM D 2513, similar to the RCP requirement in the ISO PE gas pipe standard ISO 4437. The manufacturers agreed to include a requirement in ASTM D 2513 that RCP testing (FS or S4) must be performed. The ASTM product standard D 2513 does not include any required values. <p>PMC has agreed with this approach and will develop its own industry requirement in the form of a “white paper.” 10 The first draft was just issued within PMC with the following proposed requirement: <ol> <li>PC,FS > leak test pressure. <li> <li>Leak test pressure = 1.5 X MOP.</li></ol> <p><strong><br>RCP In CSA</strong> <p>CSA followed the direction of ASTM. The product standard CSA B137.4 11 requires that the RCP testing must be done. The values of the RCP test will be stipulated in CSA Z662 Clause 12, which is the Code of Practice for gas distribution in Canada. Clause 12 recently approved the requirement as shown nearby.<br><strong></strong> <p>12.4.3.6 Rapid Crack Propagation (RCP) Requirements <p>When tested in accordance with B137.4 requirements for PE pipe and compounds, the standard PE pipe RCP Full-Scale critical pressure shall be at least 1.5 times the maximum operating pressure. If the RCP Small-Scale Steady State method is used, the RCP Full-Scale critical pressure shall be determined using the correlation formula in B137.4.<br>(end of box)<br><strong><br>RCP Test Data</strong> <p>The critical pressure is the pressure - below which - RCP will not occur. The higher the critical pressure, the less likely the gas company will have an RCP event. In most cases, as the pipe diameter or wall thickness increases, the critical pressure decreases. Therefore, RCP is more of a concern with large-diameter or thick-walled pipe. Following are some typical critical pressure values for various generic PE materials. For most cases, the pipe size tested is 12-inch SDR 11 pipe. <p><strong>PE Material S4 Critical Pressure (PC,S4) at 32°F (0°C)/Full Scale Critical Pressure (PC,FS) @ 0°C</strong> <p>Unimodal MDPE 1 bar (15 psig)/6.2 bar (90 psig)<br>Bimodal MDPE 10 bar (145 psig) /38.6 bar (560 psig) <p>Unimodal HDPE 2 bar (30 psig)/9.8 bar (140 psig)<br>Bimodal HDPE (PE 100+) 12 bar (180 psig)/45.8 bar (665 psig) <p>In general, the RCP resistance is greater for HDPE (high-density PE) than MDPE (medium-density PE). However, there is a significant difference when comparing a unimodal PE to a bimodal PE material, about a ten-fold difference. <p>Bimodal PE technology was developed in Asia and Europe in the 1980s. This technology is known to provide superior performance for both slow crack growth and RCP, as evidenced by the table. For the bimodal PE 100+ materials used in Europe and Asia, the S4 critical pressure minimum requirement is 10 bar (145 psig), which converts to 560 psig operating pressure. This means that with these bimodal PE 100+ materials, RCP will not be a concern. Today, there are several HDPE resin manufacturers that use this bimodal technology. Recently, a new bimodal MDPE material was introduced for the gas industry 12,13 with a significantly higher S4 critical pressure compared to unimodal MDPE - 10 bar compared to 1 bar. <p>Another measure of RCP resistance is the critical temperature. This is defined as the temperature above which RCP will not occur. Therefore, a gas engineer wants to use a PE material with a critical temperature as low as possible. Although critical temperature is not used as a requirement in the product standards, it is an important parameter, and perhaps should be given more consideration. Following is a table with some typical critical temperature values for various generic PE materials. For most cases, the pipe size tested is 12-inch SDR 11 pipe. <p><strong>PE Material/Critical Temperature (TC) at 5 bar (75 psig)</strong> <p>Unimodal MDPE 15°C (60°F)<br>Bimodal MDPE -2°C (28°F) <p>Unimodal HDPE 9°C (48°F)<br>Bimodal HDPE -17°C (1°F) <p>Again, we see that RCP performance for HDPE is slightly better than MDPE, but there is a significant difference between bimodal PE and unimodal PE. The bimodal MDPE and HDPE materials have the lowest critical temperatures, which means the greatest resistance to RCP.<br><strong><br>Conclusion</strong> <p>As gas companies use PE pipe in more demanding applications, such as larger pipe diameters and higher operating pressures, the resistance of the PE pipe to rapid crack propagation (RCP) becomes more important. In this article we have discussed the phenomenon of RCP and the two primary test methods used to determine RCP resistance - the S4 test and the Full Scale test. We reviewed the correlation formula between the FS test and S4 test for critical pressure. We have also discussed the two primary results of RCP testing - the critical pressure and the critical temperature. <p>ISO standards were the first to recognize the importance of RCP, especially in larger diameter pipe sizes, and incorporated RCP requirements in product standards, such as ISO 4437. The Canadian standards soon followed, and an RCP test requirement has been added to CSA B137.4. The required values for RCP testing are being added to the CSA Code of Practice in CSA Z662 Clause 12 for gas piping. ASTM just added an RCP requirement to its gas pipe standard ASTM D 2513. The corresponding AGA PMC project to develop RCP recommendations for required values from RCP testing is in progress. <p>In this article, we also discussed some results of RCP testing. In general, the HDPE materials have slightly greater RCP resistance than MDPE materials used in the gas industry. A more significant difference is observed when comparing unimodal PE materials to bimodal PE materials. Existing data indicate that bimodal HDPE materials show a significant increase in critical pressure compared to unimodal HDPE materials and also have considerably lower critical temperature values. <p>In addition, this bimodal technology has now just been introduced for MDPE. This bimodal MDPE material also has a significantly higher S4 critical pressure (10 bar vs. 1 bar) and a lower critical temperature than unimodal MDPE materials. With several PE resin manufacturers being able to produce bimodal PE materials, it is likely that in the near future, all PE materials used for the gas industry will be bimodal materials because of their superior RCP resistance. <p>Reference: <p>“Rapid Crack Propagation Increasingly Important in Gas Applications: A Status Report”, Dr. Gene Palermo, <a href="http://pipelineandgasjournal.com/rapid-crack-propagation-increasingly-important-gas-applications-status-report">http://pipelineandgasjournal.com/rapid-crack-propagation-increasingly-important-gas-applications-status-report</a>, January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-22484073200643092562014-01-28T16:31:00.001+07:002014-01-28T16:32:40.284+07:00Pipeline Free Span Analysis and Mitigation<p>Nowadays, offshore pipelines have a significant role in development of oil and gas industry in different parts of the world. This crucial industry is laid on seabed by various methods either embedded in a trench (buried method) or laid on uneven seabed (unburied method). Construction of unburied pipeline is the most common method for its rapid and economic performance. In this method, however, the pipelines are subjected to various lengths of free spanning throughout the route during its life time, which may threaten the pipelines safety. Free spanning in offshore pipelines mainly occurs as a consequence of uneven seabed and local scouring due to flow turbulence and instability; hence, with no doubt, free spanning occurrences for unburied pipelines are completely inevitable. <p>Fredsoe and Sumer (1997) assessed the role of free spans in unburied offshore pipelines. They acknowledged the previous studies and mentioned that resonance is the main problem for offshore pipelines laid on the free spanning. Pipelines resonance happens when the external load frequency as a result of vortex shedding becomes equal to the pipe Natural Frequency. This phenomenon may burst the pipe coating and may lead to develop more fatigue on the pipelines. Different design guidelines, e.g. DNV (1998) and ABS (2001), have accepted a less stringent approach and recommend the free spanning to be reduced to the allowable length to avoid fatigue damage. These guidelines proposed a simple formulation to calculate the first Natural Frequency based on the pipelines specifications and seabed conditions; however, all of the guidelines encourages using modal analysis at the final phase of design. <p>Choi (2000) studied the effect of axial forces on free spanning of offshore pipelines. The results indicated that the axial force has a significant influence on the first Natural Frequency of the pipe. In this research, the different seabed condition has been broken down into three main types and the general beam equation for the boundary conditions was analytically solved. He also compared his result with Lloyd’s approximate formula, which estimates the first Natural Frequency of the beam considering axial load effect. Xu et al. (1999) applied the modal analysis to incorporate the real seabed condition to assess pipelines fatigue and Natural Frequency (NF). Later, Bai (2001) approved Xu et al. (1999) approach and emphasis on applying the modal analysis to determine the allowable length of free span for offshore pipelines. <p>In practice, a considerable amount of works have been applied to determine the allowable free span length, however, there is still lack of knowledge in assessing the role of all effective parameters in determination of allowable free span length. The objective of this paper is two folds: (i) to assess the role of main effective parameters on Natural Frequency; and (ii) to present a simple formula for allowable free span length with accounting for the seabed condition. To do so, first the approaches of DNV (1998) and ABS guidelines are discussed and then the modal analysis is outlined to have a useful tool to assess the role of all involved parameters. Finally, a case study on the Qeshem pipelines is performed to evaluate the free span allowable length. <p>During pipeline routing evaluation, consideration has to be given to the shortest pipeline length, environment conservation, and smooth sea bottom to avoid excessive free spanning of the pipeline. If the free span cannot be avoided due to rough sea bottom topography, the excessive free span length must be corrected. Free spanning causes problems in both static and dynamic aspects. If the free span length is too long, the pipe will be over-stressed by the weight of the pipe plus its contents. The drag force due to near-bottom current also contributes to the static load. <p>To mitigate the static span problem, mid-span supports, such as mechanical legs or sand-cement bags/mattresses, can be used. Free spans are also subject to dynamic motions induced by current, which is referred to as a vortex induced vibration (VIV). The vibration starts when the vortex shedding frequency is close to the natural frequency of the pipe span. As the pipe natural frequency is increased, by reducing the span length, the VIV will be diminished and eliminated. Adding VIV suppression devices, such as strakes or hydrofoils, can also prevent the pipe from vibrating under certain conditions. The VIV is an issue even in the deepwater field since there exists severe near-bottom loop currents. To prevent static and dynamic spanning problems, a number of offshore pipeline spanning mitigation methods in Table 3 have been identified. Based on soil conditions, water depth, and span height from the seabed, the appropriate method should be selected. If the span off-bottom height is relatively low, say less than 1 m (3 ft), sand-cement bags or mattresses are recommended. If the span off-bottom height is greater than 1 m (3 ft), clamp-on supports with telescoping legs or auger screw legs are more practical. <p>References: <p>Bakhtiary, Abbas Yeganeh, Abbas Ghaheri, Reza Valipour. 2007. “Analysis of Offshore Pipeline Allowable Free Span Length”. <p><a href="http://www.jylpipeline.com">http://www.jylpipeline.com</a>, January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-56638630826927271612014-01-28T16:11:00.001+07:002014-01-28T16:11:21.301+07:00Pipeline Hot Tap<p>Hot Taps or Hot Tapping is the ability to safely tie into a pressurized system, by drilling or cutting, while it is on stream and under pressure. <p>Typical connections consist: <ul> <li>Tapping fittings like Weldolet®, Reinforced Branch or Split Tee.<br>Split Tees often to be used as branch and main pipe has the same diameters. <li>Isolation Valve like gate or Ball Valve. <li>Hot tapping machine which includes the cutter, and housing.</li></ul> <p>Mechanical fittings may be used for making hot taps on pipelines and mains provided they are designed for the operating pressure of the pipeline or main, and are suitable for the purpose. <ul> <li>Design: ANSI B31.1, B31.3, ANSI B31.4 & B31.8, ASME Sec. VIII Div.1 & 2 <li>Fabrication: ASME Sec. VIII Div.1 <li>Welding: ASME Sec. IX <li>NDT: ASME Sec. V</li></ul> <p>There are many reasons to made a Hot Tap. While is preferred to install nozzles during a turnaround, installing a nozzle with equipment in operation is sometimes advantageous, especially if it averts a costly shut down. <h3>Remarks before made a Hot Tap</h3> <ul> <li>A hot tap shall not be considered a routine procedure, but shall be used only when there is no practical alternative. <li>Hot Taps shall be installed by trained and experienced crews. <li>It should be noted that hot tapping of sour gas lines presents special health and metallurgical concerns and shall be done only to written operating company approved plans. <li>For each hottap shall be ensured that the pipe that is drilled or sawed has sufficient wall thickness, which can be measured with ultrasonic thickness gauges. The existing pipe wall thickness (actual) needs to be at least equal to the required thickness for pressure plus a reasonable thickness allowance for welding. If the actual thickness is barely more than that required for pressure, then loss of containment at the weld pool is a risk. <li>Welding on in-service pipelines requires weld procedure development and qualification, as well as a highly trained workforce to ensure integrity of welds when pipelines are operating at full pressure and under full flow conditions.</li></ul> <p><img alt="Hot Tap fittings" src="http://www.wermac.org/images/hottap_fittings.jpg" width="405" height="191"> <h3>Hot Tap setup</h3> <p>For a hot tap, there are three key components necessary to safely drill into a pipe; the fitting, the Valve, and the hot tap machine. The fitting is attached to the pipe, mostly by welding.<br>In many cases, the fitting is a Weldolet® where a flange is welded, or a split tee with a flanged outlet (see image above).<br>Onto this fitting, a Valve is attached, and the hot tap machine is attached to the Valve (see images on the right). For hot taps, new Stud Bolts, gaskets and a new Valve should always be used when that components will become part of the permanent facilities and equipment.<br>The fitting/Valve combination, is attached to the pipe, and is normally pressure tested. The pressure test is very important, so as to make sure that there are no structural problems with the fitting, and so that there are no leaks in the welds.<br>The hot tap cutter, is a specialized type of hole saw, with a pilot bit in the middle, mounted inside of a hot tap adapter housing.<br>The hot tap cutter is attached to a cutter holder, with the pilot bit, and is attached to the working end of the hot tap machine, so that it fits into the inside of the tapping adapter.<br>The tapping adapter will contain the pressure of the pipe system, while the pipe is being cut, it houses the cutter, and cutter holder, and bolts to the Valve. <h3>Hot Tap operation</h3> <p>The Hot Tap is made in one continuous process, the machine is started, and the cut continues, until the cutter passes through the pipe wall, resulting in the removal of a section of pipe, known as the "coupon".<br>The coupon is normally retained on one or more u-wires, which are attached to the pilot bit. Once the cutter has cut through the pipe, the hot tap machine is stopped, the cutter is retracted into the hot tap adapter, and the Valve is closed.<br>Pressure is bled off from the inside of the Tapping Adapter, so that the hot tap machine can be removed from the line. The machine is removed from the line, and the new service is established. <h3>Hot Tap Coupon</h3> <p>The Coupon, is the section of pipe that is removed, to establish service. It is very highly desirable to "retain" the coupon, and remove it from the pipe, and in the vast majority of hot taps, this is the case.<br><em>Please note, short of not performing the hot tap, there is no way to <strong>absolutely guarantee</strong> that the coupon will not be "dropped".</em><br>Coupon retention is mostly the "job" of the u-wires. These are wires which run through the pilot bit, and are cut and bent, so that they can fold back against the bit, into a relief area milled into the bit, and then fold out, when the pilot bit has cut through the pipe.<br>In almost all cases, multiple u-wires are used, to act as insurance against losing the coupon. <h3>Line Stopping</h3> <p>Line Stops, sometimes called Stopples (Stopple® is a trademark of TD Williamson Company) start with a hot tap, but are intended to stop the flow in the pipe.<br>Line Stops are of necessity, somewhat more complicated than normal hot taps, but they start out in much the same way. A fitting is attached to the pipe, a hot tap is performed as previously detailed. Once the hot tap has been completed, the Valve is closed, then another machine, known as a line stop actuator is installed on the pipe.<br>The line stop actuator is used to insert a plugging head into the pipe, the most common type being a pivot head mechanism. Line stops are used to replace Valves, fittings and other equipment. Once the job is done, pressure is equalized, and the line stop head is removed.<br>The Line Stop Fitting has a specially modified flange, which includes a special plug, that allows for removal of the Valve. There are several different designs for these flanges, but they all work pretty much the same, the plug is inserted into the flange through the Valve, it is securely locked in place, with the result that the pressure can be bled off of the housing and Valve, the Valve can then be removed, and the flange blinded off. <h3>Line Stop setup</h3> <p>The Line Stop Setup includes the hot tap machine, plus an additional piece of equipment, a line stop actuator. The Line Stop Actuator can be either mechanical (screw type), or hydraulic, it is used, to place the line stop head into the line, therefore stopping the flow in the line.<br>The Line Stop Actuator is bolted to a Line Stop Housing, which has to be long enough to include the line stop head (pivot head, or folding head), so that the Line Stop Actuator, and Housing, can be bolted to the line stop Valve.<br>Line stops often utilize special Valves, called Sandwich Valves.<br>Line Stops are normally performed through rental Valves, owned by the service company who performs the work, once the work is completed, the fitting will remain on the pipe, but the Valve and all other equipment is removed. <h3>Line Stop operation</h3> <p>A Line Stop starts out the same way as does a Hot Tap, but a larger cutter is used,.<br>The larger hole in the pipe, allows the line stop head to fit into the pipe.<br>Once the cut is made, the Valve is closed the hot tap machine is removed from the line, and a line stop actuator is bolted into place.<br>New gaskets are always to be used for every setup, but "used" studs and nuts are often used, because this operation is a temporary operation, the Valve, machine, and actuator are removed at the end of the job.<br>New studs, nuts, and gaskets should be used on the final completion, when a blind flange is installed outside of the completion plug.<br>The line stop actuator is operated, to push the plugging head (line stop head), down, into the pipe, the common pivot head, will pivot in the direction of the flow, and form a stop, thus stopping the flow in the pipe. <h3>Completion Plug</h3> <p>In order to remove the Valve used for line stop operations, a completion plug is set into the line stop fitting flange (Completion Flange).<br>There are several different types of completion flange/plug sets, but they all operate in basically the same manner, the completion plug and flange are manufactured, so as to allow the flange, to accept and lock into place, a completion plug.<br>This completion plug is set below the Valve, once set, pressure above the plug can be bled off, and the Valve can then be removed.<br>Once the plug has been properly positioned, it is locked into place with the lock ring segments, this prevents plug movement, with the o-ring becoming the primary seal.<br>Several different types of completion plugs have been developed with metal to metal seals, in addition to the o-ring seal. <p>Line Stopping<br>Procedure <p>All following images are from Furmanite.<br>They are a little matched to the style<br>of this website requirements. <p><img alt="Line Stop" src="http://www.wermac.org/images/hottap_1.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_2.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_3.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_4.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_5.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_6.gif" width="237" height="307"><br><img alt="Line Stop" src="http://www.wermac.org/images/hottap_7.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_8.gif" width="237" height="307"> <p><img alt="Line Stop" src="http://www.wermac.org/images/hottap_9.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_10.gif" width="237" height="307"><br><img alt="Line Stop" src="http://www.wermac.org/images/hottap_11.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_12.gif" width="237" height="307"><br><img alt="Line Stop" src="http://www.wermac.org/images/hottap_13.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_14.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_15.gif" width="237" height="307"><img alt="Line Stop" src="http://www.wermac.org/images/hottap_16.gif" width="237" height="307"><br><img alt="Line Stop" src="http://www.wermac.org/images/hottap_17.gif" width="237" height="307"> <p>Reference:</p> <p>“Introduction to Hot Tapping and Line Stopping”. <a href="http://www.wermac.org/specials/hottap.html">http://www.wermac.org/specials/hottap.html</a>. January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-86622559878033725972014-01-28T16:02:00.001+07:002014-01-28T16:02:41.726+07:00Soil-Pipeline Interaction Using FEM<p>Offshore pipelines laid on the seabed are exposed to hydrodynamic and cyclic operational <br>loading. As a result, they may experience on-bottom instabilities, walking and lateral <br>buckling. Finite element simulations are required at different stages of the pipeline design to <br>check the different loading cases. Pipeline design depends on accurately modelling axial and <br>lateral soil resistances. <br> <br>Conventional pipeline design practice is to model the interaction between the pipe and the <br>seabed with simple “spring-slider” elements at intervals along the pipe, as finite element <br>methods with elaborated contact and interface elements between the pipeline and the <br>foundation do not allow for comprehensive modeling of long pipeline systems with current <br>computational power (Tian et al, 2008). These “spring-slider” elements provide a bi-linear, <br>linear-elastic, perfectly plastic response in the axial and lateral directions. The limiting axial <br>and lateral forces are based on empirical friction models, which relate axial and lateral <br>resistance to the vertical soil reaction by using a “friction factor”. In the vertical direction, a <br>non-linear elastic load embedment response derived from bearing capacity theory is usually <br>assumed, the pipeline being treated as a surface strip foundation of width equal to the chord <br>length of pipe-soil contact at the assumed embedment.</p> <p>These simple models can be adequate for sand but are too simplistic for clay, especially soft clay. Due to the slow rate of consolidation of clay, a total stress approach using an undrained <br>shear strength <em>s<sub>u</sub></em> should be employed. In this case, the axial and lateral resistances do not directly depend on the vertical soil reaction but on the contact area between the pipe and the <br>seabed. As a result, an accurate prediction of the pipeline embedment, which can be large in <br>very soft cay, becomes of primary importance. <br> <br>These simple models were improved to better predict pipeline embedment and axial and <br>lateral resistances and were implemented in a Finite Element software program for pipeline <br>analysis to better simulate the pipe-soil interaction of surface laid pipelines in soft clay and to <br>more accurately simulate full routes. The new features are briefly explained in this paper. A <br>more recent pipe-soil vertical reaction law that models plastic unloading is built into the <br>program. It considers lay and dynamic installation effects to compute a more representative <br>pipeline embedment. Axial and lateral resistance is now linked to pipeline embedment. <br>Finally, peak-residual axial and lateral reaction laws are implemented.</p> <p><strong>Vertical reaction law</strong> <br> <br>Solutions for estimating the resistance profile have been provided by Murff et al. (1989), <br>Aubeny et al. (2005) and Randolph & White (2008). The pipeline penetration z may be <br>estimated from the conventional bearing capacity equation, modified for the curved shape of <br>a pipeline:</p><a href="http://lh5.ggpht.com/-eGccbwqCL1w/UudyGyleaqI/AAAAAAAABkI/XgHsURfTLNc/s1600-h/image%25255B18%25255D.png"><img title="image" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="image" src="http://lh3.ggpht.com/-7CLOoOga1Zc/UudyHlDVrbI/AAAAAAAABkQ/4Qr60jZ8NcA/image_thumb%25255B8%25255D.png?imgmax=800" width="339" height="47"></a> <p>where V is the vertical load per unit length, D is the pipeline diameter, s<sub>u</sub> the undrained shear<br>strength at the pipeline invert and A<sub>s</sub> the nominal submerged area of the pipeline crosssection.<br>For design, the bearing capacity factor N<sub>c</sub> can be estimated using rounded values of<br>the power law coefficients a and b, for example a = 6 and b = 0.25 (Randolph & White,<br>2008). Buoyancy has an influence in extremely soft soil conditions. This is captured by the<br>buoyancy factor Nb. The factor f<sub>b</sub> should be taken equal to 1.5 because of heave (Randolph<br>& White, 2008).</p> <p>The accuracy of this calculation approach, of the order of +/- 10%, is sufficient given the<br>other uncertainties such as the installation effects, which influence the vertical load V (see<br>below) (White & Randolph, 2007).</p> <p><strong>Installation effects</strong><br>During installation of a pipeline, the vertical and horizontal motion of the lay barge and the<br>load concentration at pipe touch-down will yield larger penetration than calculated based on<br>the pipe submerged unit weight. The load concentration can be taken into account by<br>multiplying the pipe weight by an amplification factor flay as proposed by Bruton (2006). In<br>order to take into account the effect of pipe motion during installation, a partially remoulded<br>shear strength can be used to compute the pipe embedment, as proposed by Dendani &<br>Jaeck (2007), instead of the intact strength. These features combined with the vertical<br>reaction law described above allow predicting a more realistic pipeline embedment, which is<br>of primary importance to compute a realistic axial and lateral resistance.</p> <p><strong>Plastic unloading</strong><br>A non-linear elastic load embedment response is conventionally assumed for the vertical soil<br>spring. However, it is essential to model a spring as behaving plastically to avoid predicting<br>an unrealistic rebound when the pipe is unloaded. In practice, a pipe is often overpenetrated,<br>meaning that its operating weight is lower than the maximum vertical force that<br>had been applied to it. In effect, it has been unloaded. It is important to model a spring with<br>plastic behaviour and “memory” to calculate the appropriate vertical soil stiffness. The<br>behaviour of an over-penetrated pipe can be described by the stiff unload-reload line. When<br>reloaded to its normally-penetrated range, the pipe’s behaviour can be described as following<br>the virgin load embedment curve. This is illustrated in the example below and in Figure 1.<br>Let us first consider an elastic spring. During installation, the pipe moves to A1 due to load<br>concentration and then rebounds to A2, to a vertical displacement corresponding to its<br>submerged empty weight. During the hydrotest, the vertical force increases and the pipe<br>moves to B. During operational conditions, if the content is lighter than water, the pipe is<br>unloaded to point C. The pipe embedment and the tangent stiffness at this point are not<br>realistic. In the case of an elasto-plastic spring, the pipe goes to A1 during installation and<br>then to A2* following an unload-reload line. During the hydrotest, the vertical force increases<br>to B* along the unload-reload line. Finally, the pipe is unloaded to C*. At this point, the<br>pipeline embedment and the tangent stiffness are more realistic. An accurate pipe<br>embedment is especially important when it is coupled to axial and lateral resistance (see<br>next Section).</p> <p align="center"><a href="http://lh5.ggpht.com/-BUiwNMPf8Os/UudyIYu88ZI/AAAAAAAABkY/K4KQXtrQFds/s1600-h/image%25255B29%25255D.png"><img title="image" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="image" src="http://lh3.ggpht.com/-Y-JzapRXDxw/UudyJIlDy3I/AAAAAAAABkg/HSy9sfqwJmU/image_thumb%25255B13%25255D.png?imgmax=800" width="337" height="268"></a></p> <p align="center">Figure 1 – Behaviour of non-Linear Elasto-Plastic Vertical Springs</p> <p><strong>Coupling of axial and lateral resistance with pipeline embedment</strong><br>The axial and lateral resistances depend on the contact area between the pipe and the<br>seabed and thus the pipe embedment, when a total stress approach is followed. The formula<br>used to compute peak axial and lateral resistances Fpa and Fpl are in the form:</p> <p><a href="http://lh6.ggpht.com/-PbW8DxEiUrM/UudyJ0wbtEI/AAAAAAAABko/X7dOwinbdrE/s1600-h/image%25255B33%25255D.png"><img title="image" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="image" src="http://lh5.ggpht.com/-ahmGhX8QmpU/UudyKgyXNbI/AAAAAAAABkw/nWrSL80byxA/image_thumb%25255B15%25255D.png?imgmax=800" width="204" height="69"></a></p> <p>where αs<sub>u</sub> is the unit interface shear resistance, Ac is the area of contact between the pipe<br>and the seabed which is a function of the pipe embedment z, μ is a “friction factor” in the<br>range 0.2-0.8 (Randolph & White, 2007) and λ a coefficient typically in the range 0.5-2.<br>The axial and lateral resistances have been linked to the pipeline embedment so that they<br>are automatically calculated and can change during the analysis.</p> <p><br><strong>Tri-linear axial and lateral model</strong><br>Models of the simple bi-linear frictional axial and lateral springs were improved so they can<br>use peak and residual resistances to model the softening of the axial and lateral response<br>often observed in clay. As explained earlier, pipelines are often over-penetrated in practice.<br>When this occurs in soft clay, lateral breakout resistance Fpl, is high and drops sharply when<br>suction at the rear face of the pipe is lost, then decreases further to a residual value Frl as<br>the pipe rises to a shallower embedment. When the residual resistance is reached, the<br>lateral resistance may increase again because a soil berm forms in front of the pipe (see<br>Figure 2). The axial resistance may experience strain softening as well due to suction<br>release and clay remoulding.</p> <p align="center"><a href="http://lh3.ggpht.com/-Qh8sMM98rnE/UudyLXcWtkI/AAAAAAAABk4/Wz81jLZJyGk/s1600-h/image%25255B38%25255D.png"><img title="image" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="image" src="http://lh4.ggpht.com/-MM6Uzhw3x0I/UudyMAgI94I/AAAAAAAABlA/oTFHrFGAXVQ/image_thumb%25255B18%25255D.png?imgmax=800" width="507" height="175"></a></p> <p align="center">Figure 2 – Tri-linear Lateral Resistance Model</p> <p><strong>Conclusions</strong><br>Simple soil models conventionally used in pipeline design practice have been improved and<br>implemented in a Finite Element software program for pipeline analysis. There are several<br>improvements. A more recent pipe-soil vertical reaction law that models plastic unloading is<br>built into the program. It considers lay and dynamic installation effects to compute a more<br>representative pipeline embedment. Axial and lateral resistance is now linked to pipeline<br>embedment. Finally, peak-residual axial and lateral reaction laws have been implemented.<br>The new features are basic but important first steps towards more accurate full route<br>simulations, especially those in soft clay.</p> <p> </p> <p>References:</p> <p>Ballard, Jean-Christophe, Hendrik Falepin, Jean-François Wintgens. 2009. “Towards More Advanced Pipe-Soil Interaction Models in Finite Element Pipeline Analysis”. Belgium: Fugro.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-7661561317289257942014-01-28T15:42:00.001+07:002014-01-28T15:42:23.786+07:00Pipeline Bend Computer Simulation<p>The induction bending process for large-diameter pipes is very popular technology. An important problem in the bending process is prediction and improvement of the bending quality. In this article, a thermo-elastic-plastic mechanical model is used to simulate induction bending of large-diameter pipes. The bending experiments of the API 5L X65 induction bend pipes were performed to clarify the deformation behavior of the pipes. The large deformation behaviors of these experiments were simulated by finite element method, using ADINA software.</p> <p><a href="http://lh6.ggpht.com/-uXDwUUI3KxI/Uudse7S7tEI/AAAAAAAABhI/BI7ZCm_ZmFQ/s1600-h/sim1%25255B4%25255D.png"><img title="sim1" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="sim1" src="http://lh3.ggpht.com/-oBQfTPzZgrE/Uudsfy045UI/AAAAAAAABhQ/D0Asuu8Sdks/sim1_thumb%25255B2%25255D.png?imgmax=800" width="396" height="299"></a></p> <p>Triple D Bending has been bending pipe for 26 years and induction bending for seven years. Customer specifications and requirements for material properties are becoming increasingly stringent and the company is continually improving processes to meet these requirements. For some customer applications, ovality of the pipe bends is of major concern. For this reason Triple D Bending desired to have a method of predicting the ovality of completed bends in order to find ways to improve the ovality of the pipe bends.</p> <p>In pipe production, pipe bending using local induction heating is an advanced technique to produce large diameter pipes with a large or small bend radius.</p> <p>Induction bending as a technique is relatively quick and cheap, but induction bending can produce unwanted changes in geometry such as wall thinning at the extrados, wall thickening and wrinkling at the intrados, and steep transitions in wall thickness between tangent and bend. These problems increase in severity as the bend radius is reduced. However, there are a lot of other problems, such as springback and cross-section ovality when bending thinwall pipe with a large diameter.</p> <ul> <li>Pipe diameter ØD = 30-inches (762 mm),</li> <li>Wall thickness t = 0.562 inch (14.27 mm),</li> <li>Material API 5L X65,</li> <li>Bend radius R = 189 inches (4800 mm),</li> <li>Bend angle φ= 90°.</li></ul> <p>The fundamental tasks which had to be solved can be summarized as follows:</p> <ul> <li>material characteristics identification;</li> <li>implementation of material characteristics into computational model;</li> <li>finite element modelling (geometry, definition of thermal contact problem, thermo-plasticity and large strain analysis);</li> <li>FE stress, strain, displacement analysis;</li> <li>computational ovality prediction.</li></ul> <p>Line pipe for constructing oil and gas pipelines is made from steel, and in particular, either low-carbon steel or low-alloy steel. Low-carbon or low-alloy steels are suitable for line pipe materials and most other steel structures such as buildings or bridges because they provide a durable, strong material to withstand the service loads imposed on such structures. Other iron-based materials such as wrought iron and cast iron are either too low strength or too brittle to function well as structural materials.</p> <p>Stainless or high-alloy steels are essential for special applications such as in high-temperature piping and pressure vessels or tool steels, but they are not suitable and cannot be made economically in the quantities needed for use in structures including pipelines. Only low-carbon steels or low-alloy steels offer the appropriate ranges of desirable properties (i.e., strength, toughness, ductility and weldability) that are required for structural applications. <p>The performance of steels depends on the properties associated with their microstructures. Each type of microstructure and product is developed to characteristic property ranges by specific processing routes that control and exploit microstructural changes. Carbon steels and low-alloy steels with ferrite-pearlite or ferrite-bainite microstructures are used extensively at elevated temperatures. Carbon steels are often used up to about 370ºC under continuous loading, but also have allowable stresses defined up to 540ºC. Effect of elevated-temperature exposure on the room-temperature tensile properties of normalized 0.17% C steel after exposure (without stress) to indicated temperature for 83,000 hours is shown in Figure 1. <p>The allowable design stresses for steels at elevated temperatures may be controlled by different mechanical properties, depending on the application and temperature exposure. <p>In designing components that are to be produced from low-alloy steels and to be exposed to temperatures up to 370ºC, the yield and ultimate strengths at the maximum service temperature can be used much as they would be used in the design of components for service at room temperature. <p>During operation, microstructure of experimental steel XH API 5L X65 is exposed to different levels of temperatures, thus we need to account for the influence of temperature on the behavior of this structural steel. Mechanical properties of a structural steel vary with temperature. In material behavior, changes in temperature can cause the following effects: 1) elastic constants (e.g., E, ν) of the material can change; 2) strain can develop without mechanical loading; 3) material yield strength decreases with increase in temperature; and 4) the material can lose ductility with decrease in temperature. <p>For the material properties, analysis at room and elevated temperatures were selected as the experimental methods – mechanical properties tests (tensile test) and mathematical approximation of statistical data. The results, tensile test at room temperature and other mechanical characteristics are presented in Table 1. <p align="center">Table 1: Mechanical properties of API 5L X65 at room and elevated (850ºC) temperature. <p><a href="http://lh6.ggpht.com/-p0xRa2MSYpk/UudshI0CkMI/AAAAAAAABhY/P0iCKT_CmAI/s1600-h/simtable%25255B4%25255D.png"><img title="simtable" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; float: none; padding-top: 0px; padding-left: 0px; margin-left: auto; border-left: 0px; display: block; padding-right: 0px; margin-right: auto" border="0" alt="simtable" src="http://lh3.ggpht.com/-LRWPqiqL1vY/UudtKOG39SI/AAAAAAAABhg/_AyXn7aDQbs/simtable_thumb%25255B2%25255D.png?imgmax=800" width="387" height="127"></a></p> <p>For many structural materials, a change in temperature of a few tens of degrees Celsius from room temperature may not result in much change in the elastic constants. At high enough temperatures, the stiffness and strength of structural steels may be reduced even if the ductility increases. Elevated temperature values of elastic modulus can be determined during tensile testing or dynamic testing. Figure 2 a) shows values of elastic modulus API 5L X65 between room temperature and elevated temperature. The influence of elevated temperature on Yield strength, Ultimate tensile strength and Poisson’s ratio are shown in Figure 2 a) to Figure 2 d). These results were determined during static tensile loading and the statistical data obtained using mathematical approximation. <p><a href="http://lh6.ggpht.com/-klOndgLYuLc/UudtLSN1MvI/AAAAAAAABho/WMKxUCAkb2w/s1600-h/sim2%25255B4%25255D.png"><img title="sim2" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; float: none; padding-top: 0px; padding-left: 0px; margin-left: auto; border-left: 0px; display: block; padding-right: 0px; margin-right: auto" border="0" alt="sim2" src="http://lh3.ggpht.com/-bJCHs2p6cbQ/UudtMtVlvqI/AAAAAAAABhw/Z6Csyvk-DIE/sim2_thumb%25255B2%25255D.png?imgmax=800" width="338" height="255"></a><a href="http://lh6.ggpht.com/-4rKWf33mRWY/UudtNjPUaKI/AAAAAAAABh4/_9a7fuhT3z8/s1600-h/sim2-2%25255B4%25255D.png"><img title="sim2-2" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; float: none; padding-top: 0px; padding-left: 0px; margin-left: auto; border-left: 0px; display: block; padding-right: 0px; margin-right: auto" border="0" alt="sim2-2" src="http://lh3.ggpht.com/-Pfk_lo4kr9g/UudtOVqWChI/AAAAAAAABiA/QGyS1BpcG58/sim2-2_thumb%25255B2%25255D.png?imgmax=800" width="339" height="280"></a><a href="http://lh6.ggpht.com/-FQickbf5gPg/UudtPcBV60I/AAAAAAAABiI/iDHQMHpsIHk/s1600-h/sim2-3%25255B4%25255D.png"><img title="sim2-3" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; float: none; padding-top: 0px; padding-left: 0px; margin-left: auto; border-left: 0px; display: block; padding-right: 0px; margin-right: auto" border="0" alt="sim2-3" src="http://lh4.ggpht.com/-oM0rMuAkcYw/UudtQtrmEHI/AAAAAAAABiQ/yEUa3nt-TSw/sim2-3_thumb%25255B2%25255D.png?imgmax=800" width="339" height="298"></a><a href="http://lh5.ggpht.com/-BY1bPFYwE0c/UudtRd0kafI/AAAAAAAABiY/FDcGsbcqgAE/s1600-h/sim2-4%25255B4%25255D.png"><img title="sim2-4" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; float: none; padding-top: 0px; padding-left: 0px; margin-left: auto; border-left: 0px; display: block; padding-right: 0px; margin-right: auto" border="0" alt="sim2-4" src="http://lh4.ggpht.com/-bwcuJ_ev4rA/UudtSbCfogI/AAAAAAAABig/euG9TSN5hUo/sim2-4_thumb%25255B2%25255D.png?imgmax=800" width="338" height="293"></a> <p align="center">Figure 2 a), b), c), d): Effect of elevated temperature on mechanical characteristic API 5L X65.</p> <p>Final values of mechanical parameters at the temperature of 850ºC were obtained from extrapolated curve lines shown in Figure 3, where: σ is engineering stress, ε is engineering strain, E is modulus of elasticity or Young’s modulus at room temperature, E850ºC is modulus of elasticity or Young’s modulus at elevated temperature, H is isotropic hardening modulus at room temperature, and H850ºC is isotropic hardening modulus at elevated temperature. These values were used as input parameters for the FEM analysis of bending process.</p> <p align="center"><a href="http://lh6.ggpht.com/-zqmxpvJEPUE/UudtTeURgaI/AAAAAAAABio/cw4_ZbLQBzM/s1600-h/sim3%25255B3%25255D.png"><img title="sim3" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="sim3" src="http://lh5.ggpht.com/-qLSV9NXB810/UudtUGOljxI/AAAAAAAABiw/ywFP9OddB2w/sim3_thumb%25255B1%25255D.png?imgmax=800" width="240" height="211"></a></p> <p align="center">Figure 3: Schematic view of temperature dependent material bilinear model.</p> <p><strong>Computational Assumptions</strong><br>The finite element method was used for modeling the process of induction bending (Figure 4). The computational model contains the following assumptions: <ul> <li>The model is built as a half model satisfying symmetrical, boundary and initial conditions.</li> <li>They are considered large displacements and large strains (enable to model the shape changes and plasticity during calculation).</li> <li>A temperature dependent material bilinear model is needed (Figure 3).</li> <li>Induction heating is substitute by heat transfer in contact between bodies (in inductor position, bodies which come into contact by pipe have temperature equal 850˚C, occur heating of pipe material). Contact is modeled without friction and contact pressure is considered 1 MPa.</li> <li>Water cooling system is substitute by heat transfer in contact between bodies (in water cooling system position, bodies which come into contact by pipe have temperature equal 20˚C, occur cooling of pipe material). Contact is modeled without friction and contact pressure is 1 MPa.</li> <li>Guiding devices are substitute by tight contact surface which come into contact with pipe during simulation, contact is modelled without friction.</li> <li>The movement of the pipe is imposed in the free end by velocity equal 0.0018 m s-1.</li> <li>The solution time is 18,720 seconds and corresponds to bending of pipe about 90˚.</li> <li>Pipe diameter is 762 mm, wall thickness is 14.27 mm and bending radius is 4,800 mm.</li></ul> <p align="center"><a href="http://lh5.ggpht.com/-ScXl5F8qVUA/UudtVB8p0UI/AAAAAAAABi4/xI3c1Q1SpqA/s1600-h/sim4%25255B4%25255D.png"><img title="sim4" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="sim4" src="http://lh5.ggpht.com/-qJi46e6Uw9M/UudtWCIVThI/AAAAAAAABjA/DRmdn7-yeYM/sim4_thumb%25255B2%25255D.png?imgmax=800" width="345" height="226"></a></p> <p align="center">Figure 4: Finite element model of induction bending process.</p> <p>Necessary inputs for modeling of technological process of the induction bending of pipes: <ul> <li>accurate geometrical characteristics of device (inductor position, water cooling system position, pipe diameter, wall thickness, bending radius, guiding device position, displacement velocity, initial temperature of pipe);</li> <li>material characteristics (Young’s modulus, Poisson’s ratio, Yield strength, isotropic hardening modulus, coefficient of thermal expansion) for temperature range 20 - 850˚C.</li></ul> <p><strong>Finite Element Modeling Process</strong><br>The modeling process is realized by using the “classic” finite element computational approach. The Grab mechanism is substituted by a set of solid elements inside the pipe. The bending arm is modeled as two rigid truss elements (Figure 4). These trusses are connected to pin (center of the bending) and solid elements substitute for the grab mechanism. There is in the pin no degree of freedom. In this manner, the bending arm, grab mechanism and pipe may freely rotate around the pin. The grab mechanism is modelled as one layer of solid elements inside the pipe. Low number of elements is used to simulate the bending arm and the grab mechanism, reducing bandwidth of the stiffness matrix [2,6]. <p>The induction bending process is characterized by energy lost from the material surface to the environment. Conduction, convection and radiation cause non-constant temperature distribution across the pipe wall. In order to determine the temperature difference between the outer and inner wall surfaces a thermal FE analysis was performed. There are two thermal boundary conditions applied. First is boundary convection, second is boundary radiation. These boundary conditions are applied on the inner and outer face of the pipe. Application of these boundary conditions and heating mechanism causes the temperature gradient from the outer to the inner face of the pipe. These differences of surface temperatures are low and therefore it can be neglected. <p>The chosen results of the computational simulation are presented in Figure 5 and Figure 6. Ovalization of the pipe cross-section shall be limited in design to prevent section collapse. The pipe diameter changes are evaluated in two directions: first is in the radial direction, second is in the binormal direction. These changes of diameters are dependent on the angle of the bending arm (Figure 7). The pipe was 30-inch/762 mm - API 5L X65. The applied bending angle was taken from range 0 to 90 degrees. Bend radius was 4800 mm and wall thickness was 0.562 inch / 14.27 mm. <p align="center"><a href="http://lh6.ggpht.com/-w80xc5YZY64/UudtW6Ar6SI/AAAAAAAABjI/L__OFgK5wSc/s1600-h/sim5%25255B4%25255D.png"><img title="sim5" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="sim5" src="http://lh4.ggpht.com/-0VvhxkL0C-o/UudtXli-XFI/AAAAAAAABjQ/4igR_ulc8zM/sim5_thumb%25255B2%25255D.png?imgmax=800" width="340" height="204"></a></p> <p align="center">Figure 5. Distribution of plastic strains (plastic deformation). <p align="center"><a href="http://lh5.ggpht.com/-UqMK9PORdZI/UudtYViUJrI/AAAAAAAABjY/t_PKaK3ma6g/s1600-h/sim6%25255B4%25255D.png"><img title="sim6" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="sim6" src="http://lh6.ggpht.com/-oEbCK-JGgwU/UudtZgvQNAI/AAAAAAAABjg/YzLZI_jdfYQ/sim6_thumb%25255B2%25255D.png?imgmax=800" width="338" height="203"></a></p> <p align="center">Figure 6: Von Mises stress distribution after bending process.</p> <p align="center"><a href="http://lh4.ggpht.com/-UCregLVKZdw/UudtaWIvnBI/AAAAAAAABjo/20aUM_Nxu_w/s1600-h/sim7%25255B4%25255D.png"><img title="sim7" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="sim7" src="http://lh3.ggpht.com/-qiHGASmrGPo/UudtbWGqibI/AAAAAAAABjw/pUIGJzqxw_4/sim7_thumb%25255B2%25255D.png?imgmax=800" width="337" height="263"></a></p> <p align="center">Figure 7. Ovality behavior measured during induction bending test realized by computational finite element analysis.</p> <p><strong>Conclusion </strong><br>This article presents finite element analysis of the complicated technological problem. The results of the analysis provide information about shape (diameter) changes of the bending pipe. The computational process complicates temperature dependence of the material characteristics and the substitution of induction heating. <p>Induction heating is a physically complex action. Modeling of this process is not included in FEM software for such structural problems. For this reason it is necessary to substitute induction heating by contact between bodies with heat transfer. Using this substitution simplifies the whole FE model; on the other hand, this solution has the right accuracy. <p>The main goal of this material has been to present the possibilities of the finite element analysis in the induction bending process of large-diameter pipes. The results of the introduced simulation approach can be summarized as follows: 1) analysis of the residual stress, strain and displacement distribution in pipe; 2) analysis of the plastic stress, strain and displacement distribution in pipe; 3) analysis of the temperature distribution; and 4) analysis of the pipe shape modification – ovality modification. <p> <p>References: “Computer Simulation of Induction Bending Process”. <a href="http://pipelineandgasjournal.com/computer-simulation-induction-bending-process">http://pipelineandgasjournal.com/computer-simulation-induction-bending-process</a>. January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com1tag:blogger.com,1999:blog-1839333376079838057.post-17840177805591631542014-01-26T13:44:00.001+07:002014-01-26T13:44:03.814+07:00Horizontal Directional Drilling (HDD)<p>For many decades the only way we could extract natural gas was to drill a well straight down into the ground. However, in many instances, this is not possible, not economically feasible, or simply not efficient. Technological advances now allow us to efficiently deviate from 'straight line' drilling, and steer the drilling equipment to reach a point that is not directly underneath the point of entry. While what is known as 'slant drilling', where the well is drilled at an angle instead of directly vertical, has been around for years, new technology is allowing for the drilling of tightly curved well holes, and even wells that can take a 90 degree turn underground.</p> <p><a href="http://lh6.ggpht.com/-Z3mJuYIit0Q/UuSupDshJfI/AAAAAAAABgg/vaA3Mu1SH-Q/s1600-h/directional_drill_site%25255B4%25255D.jpg"><img title="directional_drill_site" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="directional_drill_site" src="http://lh6.ggpht.com/-2P8ljP2PcV0/UuSup8D6A3I/AAAAAAAABgo/ix2q8R0NLKU/directional_drill_site_thumb%25255B2%25255D.jpg?imgmax=800" width="345" height="348"></a></p> <p>Directional drilling is the process of drilling a curved well, in order to reach a target that is not directly beneath the drill site. This is useful in many circumstances where the area above the targeted deposit is inaccessible. For example, to reach reservoirs that exist under shallow lakes, protected areas, railroads, or any other area on which the rig cannot be set up, directional drilling is employed. It is also useful for long, thin reservoirs. These types of reservoirs are not efficiently mined with a vertical completion. However, horizontal entry into the reservoir allows it to be drained more efficiently. Directional drilling is especially useful for offshore locations. The cost of offshore drilling rigs can make it uneconomical to drill a single well. With directional drilling, the offshore rig can gain access to deposits that are not directly beneath the rig, meaning that 20 or more wells can be drilled from a single rig, making it much more cost effective to drill offshore.</p> <h3>Horizontal Drilling</h3> <p>The difference between traditional directional or slant drilling and modern day horizontal drilling, is that with directional drilling it can take up to 2,000 feet for the well to bend from drilling at a vertical to drilling horizontally. Modern horizontal drilling, however, can make a 90 degree turn in only a few feet! The concept of horizontal drilling is not new. In fact, the first patent for horizontal drilling was issued in 1891 to Robert E. Lee, for drilling a horizontal drainhole for a vertical well. The advances in technology and the increasing focus on accessing less accessible reservoirs to meet rising demand have allowed for a proliferation of horizontal drilling.</p> <p>Horizontal drilling technologies have been heralded by many as the greatest advances since the conception of the rotary drilling bit. Horizontal drilling now accounts for 5 to 8 percent of active onshore wells in the U.S., and seems to be increasing every year. The ability of horizontal drilling to reach and extract petroleum from formations that are not accessible with vertical drilling has made it an invaluable technology. Horizontal drilling allows for an increase in the recoverable petroleum in a given formation, and even increases the production in fields previously thought of as marginal or mature. Horizontal drilling also allows for more economical drilling, and less impact on environmentally sensitive areas. In fact, in some areas in which drilling is not allowed for environmental reasons, it is possible to drill horizontal wells to the targeted deposit without harming the environment above. In addition, with this technology, fewer wells are needed to produce the same amount of hydrocarbons.</p> <p><a href="http://lh5.ggpht.com/-r6jtTMQ6gTA/UuSuqgwux1I/AAAAAAAABgw/B4-jiWCaJcI/s1600-h/slant_and_horizontal_drill_diagram%25255B3%25255D.gif"><img title="slant_and_horizontal_drill_diagram" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="slant_and_horizontal_drill_diagram" src="http://lh6.ggpht.com/-STSQVfwlXYg/UuSurpb_RwI/AAAAAAAABg4/uObU1b96au4/slant_and_horizontal_drill_diagram_thumb%25255B1%25255D.gif?imgmax=800" width="394" height="297"></a></p> <p>A number of advances were crucial to the progression of horizontal drilling. Measurement-while-drilling technology (or 'borehole telemetry') has allowed engineers and geologists to gain up-to-the-minute subsurface information, even while the well is being drilled. This avoids some of the complications of normal logging practices, and greatly increases the drilling engineer's knowledge of the well characteristics. Steerable downhole motor assemblies have also allowed for advances in horizontal drilling. While conventional drilling occasionally employs the use of downhole motors just above the drill bit to penetrate hard formations, steerable drilling motors allow the actual path of the well to be controlled while drilling.</p> <p>There are three main types of horizontal wells; short-radius, medium-radius, and long-radius. Short-radius wells typically have a curvature radius of 20 to 45 feet, being the 'sharpest turning' of the three types. These wells, which can be easily dug outwards from a previously drilled vertical well, are ideal for increasing the recovery of natural gas or oil from an already developed well. They can also be used to drill non-conventional formations, including coalbed methane and tight sand reservoirs.</p> <p>Medium-radius wells typically have a curvature radius of 300 to 700 feet, with the horizontal portion of the well measuring up to 3,500 feet. These wells are useful when the drilling target is a long distance away from the drillsite, or where reservoirs are spaced apart underground. Multiple completions may be used to gain access to numerous deposits at the same time.</p> <p>Long-radius wells typically have a curvature radius of 1,000 to 4,500 feet, and can extend a great distance horizontally. These wells are typically used to reach deposits offshore, where it is economical to drill outwards from a single platform to reach reservoirs inaccessible with vertical drilling.</p> <p>To give an idea of the effectiveness of horizontal drilling, the U.S. Department of Energy indicates that using horizontal drilling can lead to an increase in reserves in place by 2% of the original oil in place. The production ratio for horizontal wells versus vertical wells is 3.2 to 1, while the cost ratio of horizontal versus vertical wells is only 2 to 1. In carbonate formations, where 90 percent of horizontal drilling is done, productivity of horizontal wells is almost 400 percent higher than vertical wells, while they cost only 80 percent more.</p> <p>Horizontal drilling is an important innovation that will likely find countless new applications as the technology is developed. With increasing demand for natural gas, innovations like these will be invaluable to securing and bringing to surface these much needed hydrocarbons.</p> <p>Reference: “Directional and Horizontal Drilling”. <a href="http://www.naturalgas.org/naturalgas/extraction_directional.asp">http://www.naturalgas.org/naturalgas/extraction_directional.asp</a>. January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com1tag:blogger.com,1999:blog-1839333376079838057.post-69386811459016707092014-01-26T13:26:00.001+07:002014-01-26T13:26:24.727+07:00Pipeline Corrosion in GoM<p>Originally written by: J. S. Mandke, Southwest Research Institute, San Antonio.</p> <p>Corrosion is the leading cause of failures of subsea pipelines in the U.S. Gulf of Mexico. Third-party incidents, storms, and mud slides are additional principal causes of offshore pipeline failures. These are among the major conclusions of an analysis of 20-year pipeline-failure data compiled by the U.S. Minerals Management Service. For small size lines, additionally, failures due to external corrosion were more frequent during the period studied than internal corrosion. In medium and large-size lines, failures due to internal corrosion were more frequent than those due to external corrosion. Also, the majority of corrosion failures occurred on or near the platform and among the small-size pipelines. The motivation for the study described here was to perform a more in-depth evaluation of the pipeline failure data for the Gulf of Mexico than reported earlier, using an extended data base for the period 1967-87, and to compare the results with those reported earlier. The study results presented here provide an improved basis for assessment of safety of pipelines and for further improvements to current pipeline design, inspection, maintenance, and construction procedures. <h3></h3> <h3> </h3> <h3>Failure Data Analysis</h3> <p>The significant components of a typical offshore pipeline system transporting hydrocarbons are: Platform risers, expansion loops or thermal offsets, subsea valves and fittings, tie-in spools, and the main trunk line or the infield flow line. An understanding of the varying risks of damage and their consequences associated with these components can be developed from an evaluation of the historical data on the reported pipeline failures. <p>Failure data on offshore pipelines are not readily available for all regions of the world. Most of the reported information is on the pipelines in the Gulf of Mexico and the North Sea. In the U.S., the Department of Interior's MMS has kept a record of offshore pipeline failures since 1967. No other data source with comparable details is available in the public domain on failures of offshore pipelines. Failure data published by the MMS' for about 690 failures that occurred during 1967-87 was compiled into a personal-computer data base. <p>Although the MMS data on pipeline failures are the most comprehensive source of information available, the information for some of the failures reported is either insufficient or unclear. In those instances, some judgment and assumptions had to be exercised during compilation of these data. This did not affect the actual results, however, because the emphasis of this study has been on detecting the overall failure trends for offshore pipelines rather than the absolute numbers on failures. <p> <h3>Pipeline Failure Causes in GoM</h3> <ul> <li>Material failures. Material failures include instances where the pipe material ruptured or the weld cracked and failed. Equipment failures were primarily due to leakages or malfunctioning of fittings such as flanges, clamps, valves, etc. Out of the 60 total failures that were grouped under this category, about 23% were attributed to material failure, and the remaining 77% were attributed to equipment failure.</li> <li>Operational problems. Only seven failures were attributed to operational problems. These were mostly the result of lines being overpressured either during the normal operation or the pigging operation.</li> <li>Corrosion failures. Three subcategories comprise corrosion failures. In the first two cases, the failure was clearly identified as the result of either internal or external corrosion. In the third case, the origin of the corrosion was not clearly identified. We will refer to this as general corrosion. Out of the 343 total cases of corrosion failures, 15% resulted from internal corrosion, 46% from external corrosion, and 39% from general corrosion. Further evaluation of these data showed that for the smaller-sized pipe, external corrosion failures were more common, whereas for medium and larger-sized pipe internal corrosion was more common. This latter observation is consistent with the observation made by Andersen and Misund. About 78% of the total corrosion failures occurred on the platform, in the riser section or its vicinity on the seabed, and 20% occurred on pipelines on the seabed away from the platform.</li> <li>Storms, mud slides. </li></ul> <p>The analysis of the failure data presented here has indicated significant trends in pipeline failures. It is customary to convert the failure data to probability of failure or the failure rate per km-year or mile-year of the pipeline. Because the appropriate actuarial details on these failures were not available, probabilistic analysis of the failure data could not be performed. Corrosion is the leading cause of pipeline failures. It is followed by third-party incidents and storms and mud slides as the other principal causes of offshore pipeline failures in the Gulf of Mexico. <p>References: “Corrosion Causes Most Pipeline Failures in Gulf of Mexico”. <a href="http://www.ogj.com/articles/print/volume-88/issue-44/in-this-issue/pipeline/corrosion-causes-most-pipeline-failures-in-gulf-of-mexico.html">http://www.ogj.com/articles/print/volume-88/issue-44/in-this-issue/pipeline/corrosion-causes-most-pipeline-failures-in-gulf-of-mexico.html</a>. January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-76264666457017639422014-01-26T13:13:00.001+07:002014-01-26T13:13:50.083+07:00Vortex Induced Vibration of Offshore Pipeline<p>In fluid dynamics, vortex-induced vibrations (VIV) are motions induced on bodies interacting with an external fluid flow, produced by – or the motion producing – periodical irregularities on this flow.<br>A classical example is the VIV of an underwater cylinder. You can see how this happens by putting a cylinder into the water (a swimming-pool or even a bucket) and moving it through the water in the direction perpendicular to its axis. Since real fluids always present some viscosity, the flow around the cylinder will be slowed down while in contact with its surface, forming the so called boundary layer. At some point, however, this boundary layer can separate from the body because of its excessive curvature. Vortices are then formed changing the pressure distribution along the surface. When the vortices are not formed symmetrically around the body (with respect to its midplane), different lift forces develop on each side of the body, thus leading to motion transverse to the flow. This motion changes the nature of the vortex formation in such a way as to lead to a limited motion amplitude (differently, then, from what would be expected in a typical case of resonance).<br>VIV manifests itself on many different branches of engineering, from cables to heat exchanger tube arrays. It is also a major consideration in the design of ocean structures. Thus study of VIV is a part of a number of disciplines, incorporating fluid mechanics, structural mechanics, vibrations, computational fluid dynamics (CFD), acoustics, statistics, and smart materials.</p> <p><a href="http://lh4.ggpht.com/-dyeBwla83f8/UuSnj6pAzdI/AAAAAAAABf4/qbLjh_lVd5s/s1600-h/images%25255B4%25255D.jpg"><img title="images" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="images" src="http://lh4.ggpht.com/-wWSxxyB75MM/UuSnlUn2BGI/AAAAAAAABgA/R4h2tdjnmfc/images_thumb%25255B2%25255D.jpg?imgmax=800" width="507" height="175"></a></p> <p>Pipelines at the bottom of the sea are susceptible to ocean currents. Even relatively calm currents can induce turbulences in the wake of the pipeline, which results in the pipeline to start 'dancing'. Pipe vibrations can trigger fatigue, with catastrophic fracture as a result. Consequently, when designing submarine pipelines, caution is being paid to avoid such vibrations. Our research engineers use powerful software to predict submarine pipeline stability.</p> <h3>“Dancing at Great Depth”</h3> <p>Even relatively calm currents can induce turbulences in the wake of the pipeline, resulting in pipeline oscillations. The pipeline vibrations can trigger fatigue, causing accelerated damage. Since fatigue damage can give rise to complete fracture with catastrophic consequences, extreme caution is being paid in order to avoid such vibrations when designing submarine pipelines. Flow patterns around submarine pipelines greatly depend on the velocity of the sea currents and on the tube diameter. When the current becomes too strong, turbulences show up in the wake of the pipeline. This vortex shedding exerts an alternating force on the pipeline. Consequently, the pipeline is being subjected to cyclic loading. The pipeline starts to dance, following a characteristic ‘number-eight’ path. Under cyclic loading, the pipe is being exposed to fatigue, which could cause the pipe to fail under surprisingly modest stresses.</p> <p><a href="http://lh6.ggpht.com/-hJAQUtf8zug/UuSnmSa8-BI/AAAAAAAABgI/vxCOhjNaW9I/s1600-h/Vortex%252520induced%252520vibrations%25255B4%25255D.jpg"><img title="Vortex induced vibrations" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="Vortex induced vibrations" src="http://lh4.ggpht.com/-BUnZQTXr4jM/UuSnnPmf4dI/AAAAAAAABgQ/N9euTJCKZxE/Vortex%252520induced%252520vibrations_thumb%25255B2%25255D.jpg?imgmax=800" width="223" height="295"></a></p> <h3></h3> <h3>Current State of Art</h3> <p>Much progress has been made during the past decade, both numerically and experimentally, toward the understanding of the kinematics (dynamics) of VIV, albeit in the low-Reynolds number regime. The fundamental reason for this is that VIV is not a small perturbation superimposed on a mean steady motion. It is an inherently nonlinear, self-governed or self-regulated, multi-degree-of-freedom phenomenon. It presents unsteady flow characteristics manifested by the existence of two unsteady shear layers and large-scale structures.<br>There is much that is known and understood and much that remains in the empirical/descriptive realm of knowledge: what is the dominant response frequency, the range of normalized velocity, the variation of the phase angle (by which the force leads the displacement), and the response amplitude in the synchronization range as a function of the controlling and influencing parameters? Industrial applications highlight our inability to predict the dynamic response of fluid–structure interactions. They continue to require the input of the in-phase and out-of-phase components of the lift coefficients (or the transverse force), in-line drag coefficients, correlation lengths, damping coefficients, relative roughness, shear, waves, and currents, among other governing and influencing parameters, and thus also require the input of relatively large safety factors. Fundamental studies as well as large-scale experiments (when these results are disseminated in the open literature) will provide the necessary understanding for the quantification of the relationships between the response of a structure and the governing and influencing parameters.<br>It cannot be emphasized strongly enough that the current state of the laboratory art concerns the interaction of a rigid body (mostly and most importantly for a circular cylinder) whose degrees of freedom have been reduced from six to often one (i.e., transverse motion) with a three-dimensional separated flow, dominated by large-scale vortical structures.</p> <p>References:</p> <p>”Vortex-induced Vibration”. <a href="http://en.wikipedia.org/wiki/Vortex-induced_vibration">http://en.wikipedia.org/wiki/Vortex-induced_vibration</a>. January 2014.</p> <p>“Vortex Induced Vibrations, A Swinging Problem”. <a href="http://www.ocas.be/Vortex-Induced-Vibrations">http://www.ocas.be/Vortex-Induced-Vibrations</a>. Janaury 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-35585684454059693832014-01-26T12:56:00.001+07:002014-01-26T12:56:55.914+07:00Pipeline Construction<p>Pipeline construction is divided into three phases, each with its own activities: pre-construction, construction and post-construction. <h3> </h3> <h3>Pre-Construction</h3> <p><strong>Surveying and staking</strong></p> <p>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. <p><strong>Preparing the right-of-way</strong></p> <p>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. <p><strong>Digging the trench</strong></p> <p>Once the right-of-way is prepare, 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. <p><strong>Stringing the pipe</strong></p> <p>Individual lengths of pipe are brought in from stock pile sites and laid out end-to-end along the right-of-way. <h4> </h4> <h3>Construction</h3> <p><strong>Bending and joining the pipe</strong></p> <p>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. <p><strong>Coating the pipeline</strong></p> <p>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. <p><strong>Positioning the pipeline</strong></p> <p>The welded pipeline is lowered into the trench using bulldozers with special cranes called sidebooms. <p><strong>Installing valves and fittings</strong></p> <p>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. <p><strong>Backfilling the trench</strong></p> <p>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. <h3> </h3> <h3>Post Construction</h3> <p><strong>Pressure Testing</strong></p> <p>The pipeline is pressure tested for a minimum of eight hours using nitrogen, air, water or a mixture of water and methanol. <p><strong>Final clean-up</strong></p> <p>The final step is to reclaim the pipeline right-of-way and remove any temporary facilities. <p> <p>Reference: “Pipeline Construction”. <a href="http://www.cepa.com/about-pipelines/pipeline-design-construction/pipeline-construction">http://www.cepa.com/about-pipelines/pipeline-design-construction/pipeline-construction</a>. January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-42971496690625556912014-01-26T12:48:00.001+07:002014-01-26T12:49:44.291+07:00Pipeline Installation in Deep Water<p>Pipeline is a transportation of goods through a pipe. For underwater pipeline the most common goods is oil and gas. Generally pipeline is welding using 5G position with two kind welding techniques. First one is downhill, the most common use for pipeline. The welding start from above the pipe and go through the bottom of the pipe. Second is uphill, the opposite way of downhill. Pipeline welding using downhill technique because this technique is faster than uphill. But for toughness, uphill technique is still better than downhill. Celluloid is the most common welding consumable that use for welding in pipeline. For welding technique is depend on client requirement, but nowadays welding in pipeline is using MIG or for manual is GTAW. <p>The pipeline have some several parts, there are: <ul> <li>Mainline. Mainline is the primary line that transport goods such as oil or gas from manifold to ship or rig.</li> <li>Tie-in. Tie-in contains of flange, pipe, and pipe bend. The function of tie-in is a connector between risers and mainline.</li> <ul> <li>Flange: Flange is a joint that can freely open or close. Flange is bolting not welding to make it easier to maintain.</li> <li>Pipe bend: A pipe that bend to transport the goods from mainline to riser.</li></ul> <li>Riser: A part of pipeline to transport the goods from mainline to sea surface. </li></ul> <p>Generally for pipeline construction there are two kind of design, strain-based pipeline and stress-based pipeline. Stress-based pipeline is a conventional design of pipeline. The pipeline characteristic is stress-based, in the other word is the pipeline can bear the stress good enough. This is designed for safety use but the cost is expensive because using too many material. Nowadays the pipeline design is using strain-based design. It is cheaper and more efficient, but need a good calculation of design. <h3> </h3> <h3>Pipe Laying</h3> <p>Installing pipeline underwater is called pipe laying. There are three types of laying, S-lay, J-lay, and nowadays there is a reeling installation. The different from three of them is the shape of the pipe when went from a barge to seabed. S-lay laying pipe usually use for small size of pipe, when J-lay and reeling is for big size installation.</p> <h4>Pipeline Construction Line</h4> <p>There are two types of pipeline construction, conventional construction and reeling. Nowadays contractor start change their pipeline construction to reeling method. Conventional construction is to construct the pipeline above the ship/ barge. In the other hand reeling construction is to make the pipe in land, reel it and take it to the sea. <p>The example of conventional pipeline method is on US EPCI company’s barge. Figure 1 is a flow chart of pipeline conventional method. <p><a href="http://lh6.ggpht.com/-7dn_oVOXvAg/UuShwrOfYtI/AAAAAAAABfg/0x02gqMikiY/s1600-h/image%25255B4%25255D.png"><img title="image" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; float: none; padding-top: 0px; padding-left: 0px; margin-left: auto; border-left: 0px; display: block; padding-right: 0px; margin-right: auto" border="0" alt="image" src="http://lh4.ggpht.com/-Ai4TbbyJsjE/UuShxYmGpUI/AAAAAAAABfo/w9Ap42m9gfs/image_thumb%25255B2%25255D.png?imgmax=800" width="518" height="272"></a> <p align="center">Figure 1. Conventional pipeline installation flowchart. <p>The barge will bring the pipe to the construction site, another barge also bring it into the site. In location site the barge will put down the anchor. Using a help from tugboat the barge need to get a good position of an anchor to hold the barge getting pulled by pipeline when the pipeline start to release from the barge. When it settle the barge start their construction line. <p>First the pipe from deck or barge will go into construction line. The pipe will went through beadstall. In beadstall, the pipe will be check the code, cleaning the pipe, and also some preheating is applied into the pipe. If there is something wrong with the pipe code or rejected the pipe will go to quarantine place. After preheating, the pipe will go to the station. Station is a place where the pipe start to weld, NDT test, coating, and in the end is release it into the seabed. How many station on the ship is depends on client demand, but usually there is 9 stations on the ship. First station is for root welding station. Welding technique use in project is depend on the client demand. When it finish it will go to other station to do another welding layer, and so on in other station until finishing the capping weld. After finishing the welding, NDT test will do to check the welding result. The most common NDT test is UT or nowadays is AUT. But sometimes radiography test also use to inspect the welding. If there is a problem, the construction line will stop and welder will be call to repair the welding. If it can't be repair, the pipeline will be cut off and replace with a new pipe. After the NDT station pipeline will go to the next station which is a coating station. In this station they will applied a coating for pipeline joint, a pipeline coating already installed in land. The coating that use for joint is Heat Shrink Sleeves (HSS) coating. After finishing the coating, anode installation will be done, depends on client demand. Later the pipe will be release into the sea. Pipe will go from the barge trough a stinger and later go into the seabed. The pipeline will leave the barge and went through the seabed create an "S" shape. That pipe laying is called S-lay pipe. <p> <p>Reference: Hutagalung, Andi A., Albert Hutama. 2013. “Phase III Preparation CAPEX NO102 and QC Department Batam Marine Base”. Bandung: ITB.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-18722086759887627852014-01-26T12:41:00.001+07:002014-01-26T12:41:13.186+07:00Pipeline Material Selection<p> <p>Originally written by <strong>Krupavaram Nalli</strong>, Tebodin & Partners LLC, Sultanate of Oman <p>With the recent spate of material failures in the oil and gas industry around the world, the role of a material and corrosion engineer in selecting suitable material has become more complex, controversial and difficult. Further, the task had become more diverse, since now modern engineering materials offer a wide spectrum of attractive properties and viable benefits. <p>From the earlier years or late ’70s, the process of materials selection that had been confined exclusively to a material engineer, a metallurgist or a corrosion specialist has widened today to encompass other disciplines like process, operations, integrity, etc. Material selection is no more under a single umbrella but has become an integrated team effort and a multidisciplinary approach. The material or corrosion specialist in today’s environment has to play the role of negotiator or mediator between the conflicting interests of other peer disciplines like process, operations, concept, finance, budgeting, etc. <p>With this as backdrop, this article presents various stages in the material selection process and offers a rational path for the selection process toward a distinctive, focused and structured holistic approach. <p>What is material selection in oil and gas industry? Material selection in the oil and gas industry - by and large - is the process of short listing technically suitable material options and materials for an intended application. Further to these options, it is the process of selecting the most cost- effective material option for the specified operating life of the asset, bearing in mind the health, safety and environmental aspects and sustainable development of the asset, technical integrity and any asset operational constraints envisaged in the operating life of the asset. <p>What stages are involved? The stages involved in the material selection process can be outlined as material selection 1) during the concept or basic engineering stage, 2) during the detailed engineering stage, and 3) for failure prevention (lessons learned). <p> <h3>Concept Stage</h3> <p>Material selection during the concept stage basically means the investigative approach for the various available material options for the intended function and application. In this stage, a key factor for the material selection is an up-front activity taking into consideration operational flexibility, cost, availability or sourcing and, finally, the performance of the material for the intended service and application. <p>The material and corrosion engineer’s specialized expertise or skills become more important as the application becomes critical, such as highly sour conditions, highly corrosive and aggressive fluids, high temperatures and highly stressed environments, etc. <p>It is imperative at this concept stage that the material selection process becomes an interdisciplinary team approach rather an individualistic material and corrosion engineer’s choice. However, some level of material selection must be made in order to proceed with the detailed design activities or engineering phase. <p>The number and availability of material options in today’s industry have grown tremendously and have made the selection process more intricate than a few decades back. The trend with research and development in the materials sciences will continue to grow and may make the selection even more complex and intriguing. <p>It should be understood that, at the concept design stage, the selection is broad and wide. This stage defines the options available for specific application with the available family of materials like metals, non metals, composites, plastics, etc. If an innovative and cost-effective material choice is to be made from an available family of options, it is normally done at this stage. <p>At times, material constraints from the client or operating company or the end user may dictate the material selections as part of a contractual obligation. Sourcing, financial and cost constraints at times may also limit and obstruct the material selections except for vey critical applications where the properties and technical acceptability of the material is more assertive and outweighs the cost of the material. <p>Materials availability is another important criterion on the material selection which impacts the demanding project schedules for the technically suitable material options. Also, different engineering disciplines may have different and specific requirements like constructability, maintainability, etc. However, a compromise shall be reached at this stage among all the disciplines concerned to arrive at a viable economic compromise on the candidate material. <h3> </h3> <h3>Detailed Engineering Stage</h3> <p>Materials selection during the detailed design stage becomes more focused and specific. The material selection process narrows down to a small group or family of materials, say: carbon steels, stainless steels, duplex stainless steels, Inconels or Incoloys, etc. In the detail design stage, it narrows down to a single material and other conditions of supply like Austenitic stainless steels, Martensitic stainless steels, cast materials, forged materials, etc. <p>Depending on the criticality of the application at this stage the material properties, manufacturing processes and quality requirements will be addressed to more precise levels and details. This may sometimes involve extensive material-testing programs for corrosion, high temperature, and simulated heat treatment as well as proof testing. <p>From the concept to detailing stage is a progressive process ranging from larger broad possibilities to screening to a specific material and supply condition. <p>At times, the selection activity may involve a totally new project (greenfield) or to an extension of existing project (brownfield). In the case of an existing project, it could be necessary to check and evaluate the adequacy of the current materials; it may be necessary at times to select a material with enhanced properties. The candidate material shall normally be investigated for more details in terms of cost, performance, fabricability, availability and any requirements of additional testing in the detail engineering stage.<br><strong><br></strong> <h3><strong>Failure Prevention (Lessons Learned)</strong></h3> <p>Material selection and the sustainability of material to prevent any failure during the life of the component is the final selection criterion in the process. <p>Failure is defined as an event where the material or the component did not accomplish the intended function or application. In most cases, the material failure is attributed to the selection of the wrong material for the particular application. Hence, the review and analysis of the failure is a very important aspect in the material selection process to avert any similar failures of the material in future. <p>The failure analysis - or the lessons learned - may not always result in better material. The analysis may, at times, study and consider the steps to reduce the impact on the factors that caused the failure. A typical example would be to introduce a chemical inhibition system into the process to mitigate corrosion of the material or to carry out a post-weld heat treatment to minimize the residual stresses in the material which has led to stress corrosion cracking failure. <p>An exhaustive review and study of the existing material that failed, including inadequacy checks and a review of quality levels imposed on the failed materials, is required before an alternate and different material is selected for the application. <p>The importance of the failure analysis cannot be overstressed in view of the spate of failures in recent times in the oil and gas industry. The results of failure analysis and study will provide valuable information to guide the material selection process and can serve as input for the recommendation in the concept and design stages of the project. It strengthens and reinforces the material selection process with sound back-up information. <p>Let us take a general view of material recommendations for pipelines. Some of the materials most relevant for use in pipelines in the Middle East are indicated for information and guidance in Table 1. The recommendations are general in nature and each pipeline is to be studied in detail case by case as regards operating conditions, fluid compositions, etc. before any final selections. <p>Also, other considerations - like the total length of the pipeline, above or below ground installation, nature of the pipeline (export line or processing line, etc.) – that are to be taken into consideration during the detailed engineering phase. <p align="center"><em>Table 1: General Material Selection for Pipelines in Oil and Gas Industry.</em> <p align="center"><a href="http://lh4.ggpht.com/-e8O0hnkuSoQ/UuSf7xOsa9I/AAAAAAAABfQ/WmnUBK4eEes/s1600-h/materialchart%25255B4%25255D.png"><img title="materialchart" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="materialchart" src="http://lh4.ggpht.com/-PwKHK1f6zA4/UuSf93kwP-I/AAAAAAAABfY/TzRApkuD4LY/materialchart_thumb%25255B2%25255D.png?imgmax=800" width="471" height="377"></a> <p><strong>Notes: </strong>CA: Corrosion Allowance, CS: Carbon Steel, CRA: Corrosion Resistant Alloy and GRP: Glass Reinforced Plastics. The recommendations in Table 1 are for guidance only. Each pipeline is to be analyzed on a case-by-case basis based on operating conditions and fluid compositions. <h3> </h3> <h3>Conclusion</h3> <p>To maintain the integrity of the asset and provide a safe, healthful working environment it is always a welcome event to have the material selection process be executed as a holistic team approach rather than an individual metallurgist’s or corrosion specialist’s choice. <p> </p> <p>References: “A Rational Approach To Pipeline Material Selection”. <a href="http://www.pipelineandgasjournal.com/rational-approach-pipeline-material-selection">http://www.pipelineandgasjournal.com/rational-approach-pipeline-material-selection</a>. January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-14489697046565582312014-01-26T12:13:00.001+07:002014-02-01T03:23:20.899+07:00Pipeline Routing ConsiderationOil and gas pipeline routes are pivotal pieces of information upon which pipeline engineering depends. The route will define the pipeline size, terrain, soils, and engineering analysis requirements. Engineering assessment based upon agreed alignment selection criteria is an important part of a linear project. To be able to reach the best construction line and optimise its components, the phases – namely corridor, route, alignment, and construction line selection — should be studied in the given order.<br />
<a href="http://lh4.ggpht.com/-HIHtn4BKvHc/UuSZa78g5gI/AAAAAAAABeo/hYbhW80g09Q/s1600-h/IPLOCA%25255B4%25255D.jpg"><img alt="IPLOCA" border="0" src="http://lh4.ggpht.com/-LHDE0mkR8rA/UuSZb1ToZ9I/AAAAAAAABew/2dcoajOZNuI/IPLOCA_thumb%25255B2%25255D.jpg?imgmax=800" height="244" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: inline; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="IPLOCA" width="431" /></a><br />
Selecting the optimum route does not end with geotechnical challenges, as it also requires interactive coordination between the owner, the engineer, the regulator, the landowners, the construction contractor and a multitude of other project stakeholders and interested parties. <br />
In North America, pipeline route selection is driven by regulatory requirements at the federal, state and local levels and involves finding a route that minimizes the impact on the environment and archaeological artefacts and recognises the concerns of the landowners while considering the geotechnical challenges which affect the construction of the pipeline. <br />
In arctic regions like Siberia, the soil conditions are an important consideration where areas of permafrost are interspersed with normal soils. In the permafrost areas, the pipeline will be installed above ground on supports and the depth of the permafrost determines the design of the supports, while in normal soil areas the pipeline is buried in a trench in the conventional manner. <br />
In mountainous terrain, such as in Turkey, geotechnical considerations are a significant aspect of pipeline route selection, as well as environmental and landowner concerns. The pipeline design must address geohazard mitigation for seismic areas and sections of the route which could be subject to landslides. <br />
Geo-political factors can also affect the route selection. Bringing Caspian Sea gas to Europe requires, among other pipelines, a new pipeline in Europe. A northern route requires a longer pipeline routed through environmentally sensitive areas, but this route supports future expansion of the pipeline system’s capacity. A southern route is shorter and reduces environmental concerns, but as this route also involves a marine crossing, the future expansion of the pipeline system is curtailed. <br />
<br />
<strong></strong> <br />
<h3>
Primary selection factors</h3>
The detailed pipeline route selection is preceded by defining a broad area of search between the two fixed start and end points. That is, possible pipeline corridors. The route can then be filtered with consideration of public safety, pipeline integrity, environmental impact, consequences of escape of fluid, and based on social, economic, technical environmental grounds, constructability, land ownership, access, regulatory requirements and cost. <br />
Economic, technical, environmental and safety considerations should be the primary factors governing the choice of pipeline routes. The shortest route might not be the most suitable, and physical obstacles, environmental constraints and other factors, such as locations of intermediate offtake points to end users along the pipeline route should be considered. Offtake points may dictate mainline routing so as to minimise the need or impact of the offtake lines or spurs. <br />
Many route constraints will have technical solutions (e.g. routing through flood plains), and each will have an associated cost. <br />
<br />
<h3>
Corridor selection in project key stages</h3>
Pipeline routing is an iterative process, which starts with a wide ‘corridor of interest’ and then narrows down to a more defined route at each design stage as more data is acquired, to a final ‘right of way’ (ROW). Initially, a number of alternative corridors with widths up to 10 km wide are reviewed. Each project will have its own specific corridor-narrowing process depending on project size and location. <br />
Pipeline corridors should initially be selected to avoid key constraints. The route can then be further refined through an iterative process, involving consultation with stakeholders and landowners and a review of the EIA criteria, to avoid additional identified constraints. The ultimate aim is to achieve an economically and environmentally-feasible route for construction. <br />
<strong></strong> <br />
<h3>
Terrain, subterranean conditions, geotechnical and hydrographical conditions</h3>
The geography of the terrain traversed can generally be divided into surface topography and subterranean geology. Both natural and man-made geographical features can be considered under these two headings. <br />
The principal geographical features which are likely to be encountered and should be taken into account include: <br />
<ul>
<li>Surface:</li>
<ul>
<li>Crops, livestock, woodlands; </li>
<li>Natural beauty, archaeological, ornamental rivers, mountains;</li>
<li>Water catchment areas, forestry;</li>
<li>Population, communications, services;</li>
<li>Contouring, soil or rock type, water, soil corrosivity;</li>
<li>Designated areas, protected habitats, flora and fauna</li>
</ul>
<li>Subterranean:</li>
<ul>
<li>Earthquake zone;</li>
<li>Geological features;</li>
<li>Infill land and waste disposal sites, including those contaminated by disease, radioactivity or chemicals;</li>
<li>The proximity of past, present and future mineral extractions, including uncharted workings, pipelines and underground services;</li>
<li>Areas of geological instability, including faults, fissuring and earthquake zones;</li>
<li>Existing or potential areas of land slippage, subsidence and differential settlement;</li>
<li>Tunnels;</li>
</ul>
<li>Ground water hydrology, including flood plains.</li>
</ul>
<br />
<h3>
Geo-hazards</h3>
Geo-hazards are widespread phenomena that are influenced by geological and environmental conditions and which involve both long-term and short-term processes. They range in size, magnitude and effect. Many geo-hazards are naturally occurring features and processes (e.g. landslides, debris flow, seismic activity, rock falls, etc.) but there are also many geo-hazards that are caused by anthropogenic processes (e.g. undermining, landfills, engineered fill, chemistry and contamination, etc.), and these too need to be taken into account during the pipeline routing exercise. <br />
Geo-hazards are identified as geological, hydro-geological or geomorphological events that pose an immediate or potential risk that may lead to damage or uncontrolled risk. The type, nature, magnitude, extent and rate of geological processes and hazards directly influence pipeline route selection. Therefore, the process of early-stage terrain evaluation and the identification and assessment of geo-hazards and ground conditions are important as they can lead to extensive cost and time savings in the design and construction of a pipeline. <br />
The process enables the routing of the pipeline through the most suitable terrain, problem areas are identified, serious geo-hazards are avoided, where possible, and risks are minimised and mitigated. In addition, terrain evaluation is undertaken so that the need for expensive remedial measures or site restoration works is limited or prevented and the operability of the pipeline is safeguarded through a proper appreciation of the terrain conditions. By minimizing the risk of damage to the pipeline the risk to human safety is reduced. <br />
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<h3>
Terrain evaluation</h3>
Terrain evaluation along the pipeline corridor can be achieved using a variety of low-cost techniques that include satellite imagery and aerial photography interpretation, surface mapping and various other remote sensing techniques. This data can be incorporated, together with historical data on seismic events, geological features, meteorological processes and hydrological data, within a geographic information system (GIS – see below) and detailed terrain and hazard models developed. <br />
Terrain evaluation supports the anticipation, identification and assessment of the physical hazards and constraints within and outside of the pipeline corridor. It is essential that features outside the corridor be evaluated, as hazardous events outside of the corridor may be triggered by construction activity within the corridor and the resultant event may impact upon the pipeline. <br />
The risks associated with geo-hazards or the likelihood of an event occurring and its consequences can be qualitatively and quantitatively assessed using a scoring system or by a quantitative risk assessment (QRA). <br />
Safety of the pipeline is paramount in the routing selection. The extreme effect of a geological hazard on the pipeline is a rupture and it is this event that terrain evaluation and risk analysis seeks to avoid by improving the decision-making progress used in selecting the most appropriate route for the pipeline. <br />
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<h3>
Conclusion</h3>
In onshore and pipeline projects alike, the potential for catastrophe is always lurking close at hand to catch the naïve or complacent investor and contractor off-guard. However, when these challenges are successfully addressed, leaving a pipeline system with solid integrity and performance as well as satisfied investors, contractors and communities, projects can be very rewarding, both in financial terms as well as in the esteem accorded to all those involved. <br />
References: “Pipeline Route Selection”. <a href="http://www.oilandgastechnology.net/pipeline-news/pipeline-route-selection-%E2%80%93-route-success">http://www.oilandgastechnology.net/pipeline-news/pipeline-route-selection-%E2%80%93-route-success</a>. January 2014. <br />
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alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-45861897605291157612014-01-24T10:17:00.001+07:002014-01-24T10:17:25.939+07:00Pipeline Inspection<p align="justify">In the United States, millions of miles of pipeline carrying everything from water to crude oil. The pipe is vulnerable to attack by internal and external corrosion, cracking, third party damage and manufacturing flaws. If a pipeline carrying water springs a leak bursts, it can be a problem but it usually doesn't harm the environment. However, if a petroleum or chemical pipeline leaks, it can be a environmental disaster. More information on recent US pipeline accidents can be found at the, National Transportation Safety Board's Internet site. In an attempt to keep pipelines operating safely, periodic inspections are performed to find flaws and damage before they become cause for concern.<br>When a pipeline is built, inspection personnel may use visual, X-ray, magnetic particle, ultrasonic and other inspection methods to evaluate the welds and ensure that they are of high quality. The image to the left show two NDT technicians setting up equipment to perform an X-ray inspection of a pipe weld. These inspections are performed as the pipeline is being constructed so gaining access the inspection area is not problem. In some areas like Alaska, sections of pipeline are left above ground like shown above, but in most areas they get buried. Once the pipe is buried, it is undesirable to dig it up for any reason.</p> <h3 align="justify">So, how do you inspect a buried pipeline?</h3> <p align="justify">Have you ever felt the ground move under your feet? If you're standing in New York City, it may be the subway train passing by. However, if you're standing in the middle of a field in Kansas it may be a pig passing under your feet. Huh??? Engineers have developed devices, called pigs, that are sent through the buried pipe to perform inspections and clean the pipe. If you're standing near a pipeline, vibrations can be felt as these pigs move through the pipeline. The pigs are about the same diameter of the pipe so they range in size from small to huge. The pigs are carried through the pipe by the flow of the liquid or gas and can travel and perform inspections over very large distances. They may be put into the pipe line on one end and taken out at the other. The pigs carry a small computer to collect, store and transmit the data for analysis. In 1997, a pig set a world record when it completed a continuous inspection of the Trans Alaska crude oil pipeline, covering a distance of 1,055 km in one run. <br>Pigs use several nondestructive testing methods to perform the inspections. Most pigs use a magnetic flux leakage method but some also use ultrasound to perform the inspections. The pig shown to the left and below uses magnetic flux leakage. A strong magnetic field is established in the pipe wall using either magnets or by injecting electrical current into the steel. Damaged areas of the pipe can not support as much magnetic flux as undamaged areas so magnetic flux leaks out of the pipe wall at the damaged areas. An array of sensor around the circumference of the pig detects the magnetic flux leakage and notes the area of damage. Pigs that use ultrasound, have an array of transducers that emits a high frequency sound pulse perpendicular to the pipe wall and receives echo signals from the inner surface and the outer surface of the pipe. The tool measures the time interval between the arrival of a reflected echos from inner surface and outer surface to calculate the wall thickness.</p> <p align="justify"><a href="http://lh4.ggpht.com/-88_FkIKVBbg/UuHa63pLtqI/AAAAAAAABdw/AF-HfltOAQk/s1600-h/ISUPIG%25255B7%25255D.jpg"><img title="ISUPIG" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; margin: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="ISUPIG" src="http://lh5.ggpht.com/-9hOPPemjU58/UuHbA4wE71I/AAAAAAAABd4/K0dnsDT3EIQ/ISUPIG_thumb%25255B3%25255D.jpg?imgmax=800" width="211" height="329"></a><a href="http://lh3.ggpht.com/-i1tAG04AWyE/UuHbFjGzVyI/AAAAAAAABeA/clIP5koHzKY/s1600-h/PIGDiagram%25255B7%25255D.jpg"><img title="PIGDiagram" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="PIGDiagram" src="http://lh5.ggpht.com/-9lACi6TVEBQ/UuHbJ07EUoI/AAAAAAAABeI/eJZqv2T4W-c/PIGDiagram_thumb%25255B3%25255D.jpg?imgmax=800" width="407" height="136"></a></p> <p align="justify"><em>Figure 1. Pig and the diagram.</em></p> <p align="justify"><br>On some pipelines it is easier to use remote visual inspection equipment to assess the condition of the pipe. Robotic crawlers of all shapes and sizes have been developed to navigate the pipe. The video signal is typically fed to a truck where an operator reviews the images and controls the robot.</p> <p align="justify"><a href="http://lh4.ggpht.com/-dG_T-ToR6_c/UuHbMqwMQAI/AAAAAAAABeQ/ghCozyCRlkc/s1600-h/PipeCrawler%25255B4%25255D.jpg"><img title="PipeCrawler" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="PipeCrawler" src="http://lh3.ggpht.com/-oOtp7LftdoI/UuHbQcC4flI/AAAAAAAABeY/IETUgN7WGuI/PipeCrawler_thumb%25255B2%25255D.jpg?imgmax=800" width="311" height="286"></a></p> <p align="justify"><em>Figure 2. Pipe crawler.</em></p> <p align="left">References: </p> <p align="left">“Pipeline Inspection”. <a href="http://www.ndt-ed.org/AboutNDT/SelectedApplications/PipelineInspection/PipelineInspection.htm">http://www.ndt-ed.org/AboutNDT/SelectedApplications/PipelineInspection/</a>. January 2014</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-11463675095393177332014-01-24T10:04:00.001+07:002014-01-24T10:04:55.954+07:00Pipeline Manufacturing: Seamless or Welded?<p align="justify">Pipes and tubings are vital elements in upstream oil and gas. From control lines to electrical lines, tubings can be used in diverse applications. In deepwater environments, coiled tubings could run up more than 70,000 feet to produce hydrocarbon.</p> <p align="justify">Here, seamless and welded tube and pipe provider RathGibson, discusses the points to consider when choosing welded, welded and drawn, or seamless tubing or pipe in various applications. The US-based firm recently invited regional players to a forum in Dubai to give an overview of its business, its product lines and its best advice on seamless versus welded. Following the forum, David Manuel talks to experts at the company.</p> <p align="justify"><strong>Choosing between different types of tubing or pipe is complex. How are they different from each other? Where do each best fit?</strong></p> <p align="justify">Welded can mean longitudinal seam welded tubing manufactured by an autogenous (without filler metal) fusion welding process, as opposed to tubing manufactured by other welding processes, such as solid-state processes.<br>Welded tubing is made by forming flat products (strip, sheet or plate) into the desired shape, in this case, normally round. Once the desired shape has been achieved, a high energy source is used to melt the metal locally at the weld joint. It is squeezed together and allowed to solidify, forming a weld bead. The high energy source may be an electric arc, a plasma arc, a laser beam, or even an electron beam. The as-welded weld bead is typically somewhat thicker than the adjacent base metal and needs to be modified to match the base metal thickness, and to correct the undesirable physical, chemical and corrosion resistance attributes of the weld. <br>Some manufacturers will simply remove the excess material of the weld bead by scarfing the inside portion and either grinding or scarfing the outside portion. This method of weld bead modification only changes the physical dimension and leaves the undesirable as-welded physical, chemical and corrosion resistance properties as they were.<br>To properly modify this condition the weld bead is cold worked locally and is given a solution anneal heat treatment. This results in a microstructure that exhibits the same physical, chemical, mechanical, and corrosion resistance properties as the base metal.<br>Meanwhile, seamless tubing, sometimes referred to as drawn tubing, starts with a solid block or bar of steel that is pierced by extrusion, drilling, oxygen lance, or some other means to create a bore through the length of the starting stock. This is then called a hollow. The hollow is then extruded through a die and mandrel combination to simultaneously reduce the outside diameter and to expand the diameter of the bore. The net result is a reduction in the wall thickness. Before the hollow can be drawn through the die, however, it must be pointed which means one end of the hollow must be tapered to facilitate entry into the die. This tapered section is then cut off and discarded. <br>Depending on the ductility and malleability of the alloy and the starting and finished sizes this process may need to be repeated several times. Alloys that harden rapidly, like the Hastelloy and Incoloy types, require more cycles than standard austenitic stainless steels like 304 or 316. Because of extreme forces applied in the drawing operations, a very thick high pressure lubricant must be used to preserve both the inside and outside surface integrity.<br>These lubricants must be removed by cleaning before heat treatment can be performed. The cleaning cycle must use aggressive solvents, and is not always effective on small diameter tubing. The residual lubricants can result corrosion issues in service.<br>The net result is that all of this handling and additional scrap often results in a more expensive process that has its own unique set of potential defects.<br>One of the most common problems with seamless tubing is variation of wall thickness around the circumference of the tube at a single point along the length. Because the inside tooling cannot be held in a fixed position and is allowed to float in response to variations in hardness or strength along the hollow, the concentricity of the inside surface relative to the outside surface can become unacceptable. It is not uncommon for the actual wall thickness of a seamless tube of 2.11 mm minimum, to vary from 2.11 mm to 2.31 mm at a single point. This is one of the reasons that seamless tube is normally ordered as a minimum nominal wall thickness where the tolerance is X.XX mm +20% / -0. Welded tubing, on the other hand, being made from flat rolled strip material exhibits extremely consistent wall thickness. A 2.11mm nominal wall tube typically shows actual variation of 0.07 mm or less at a point. The variation from production lot to production lot is typically 0.1 mm or less.<br>The dimensional flaw of welded tubing may be its ovality, or roundness. Seamless tubing has a very round and very consistent diameter as a result of being extruded through a die, with typical measured variations in diameter of +/- 0.025mm for a 25 mm OD size. Roll formed welded tubing on the other hand, typically varies about +/- 0.050 mm to +/- 0.075 mm for the same nominal OD. However, for most applications, good concentricity is more valuable than good ovality. Ovality can be corrected or compensated for during fabrication or installation. A non-concentric (or eccentric) condition cannot.<br>Welded and drawn tubing is a compromise or combination of the two processes. It combines the positive attributes of each process. It is basically the same as the seamless process, except that the starting hollow is a welded product that has the usual excellent consistency of wall thickness. When the starting wall thickness is consistent, the final wall thickness is consistent. It also cold works the full cross-section of the metal normally resulting in a very desirable microstructure and its associated properties. Dimensional control is excellent; it is a little bit less expensive than seamless and a bit more expensive than welded. It can be produced as either finite length sticks or as coil forms in lengths that are only limited by handling and transportation capacities, up to 25,000 meters.</p> <p align="justify"><strong>What are the criteria that should be considered?</strong></p> <p align="justify">Specifying a manufacturing process rather than specifying measurable results in any product is always a slippery slope. The type of results and the value of measureable results need to be performance-based and to consider application critical attributes. If working pressure is of concern, then a minimum tensile or yield strength or burst pressure value should be considered, along with dimensional attributes like wall thickness and concentricity.<br>Wall thickness and concentricity should also be of concern when heat transfer rates are an issue. Tubes that exhibit a non-concentric or eccentric geometry may develop hot spots or weak spots at thin or thick sections around the circumference, as well as along the length. This could significantly affect process parameters in a heat exchanger.<br>If working temperature, either elevated or cryogenic, is of concern, test methods and data representative of the field conditions should be considered. Basically, if material selection is properly executed, the product form should be insignificant.</p> <p align="justify"><strong>What is the advantage of seamless over welded?</strong></p> <p align="justify">When welded tubing is properly manufactured by a reputable supplier, seamless does not have any advantage over welded.</p> <p align="justify"><strong>Which is more cost-effective? Why?</strong></p> <p align="justify">From a tube manufacturing standpoint, typically welded is more cost-effective as a result of the minimised labour input and reduced manufacturing scrap.<br>From a fabrication standpoint, welded is more cost effective because of the reduced number of field orbital welds needed to join individual lengths of tube together to create the umbilical.<br>Seamless tubes are typically available in fixed finite lengths such as 6 or 12 metres. Welded tube on the other hand is available in continuous lengths up to 25,000 metres. A single continuous tube from a coil of strip material is typically about 500 metres long. A splice weld is made on the strip material at these 500 metre intervals and is cold worked before roll forming the tube. It is then solution anneal heat treated and X-ray examined. The net result is that strip material is infinitely long and the final length of the tube is then limited only by the size of the spool on which it can be coiled and the associated material shipping and handling capabilities.<br>Because these splice (orbital) welds are made and processed at the factory in a controlled environment the potential for corrosion is significantly reduced as compared to the field orbital welds which cannot be cold worked and are typically not heat treated. The microstructure and the physical, chemical and corrosion resistance properties of the factory welds are virtually identical to those of the base metal.</p> <p align="justify"><strong>In an oil and gas application, such as control lines, downhole and umbilical applications, what is more advisable between the two product types?</strong></p> <p align="justify">When purchased from a reputable reliable supplier, welded tubing can offer advantages of economy without sacrifice of performance. The economy is realised in both initial purchase costs and in time and labour in fabrication / installation. Coiled welded tubing can be supplied with a splice (orbital) weld that has been cold worked and solution annealed at intervals of about 500 metres. The maximum distance between splice welds in coiled seamless tubes is typically about 30 metres. The wall thickness dimension control of welded tubing is superior to that of seamless tubing. Both products must meet the same minimum tensile strength and burst strength requirements. Both must meet the same corrosion testing requirements. Both must meet the same chemical composition requirements. The differences lie in the efficiencies of the manufacturing method.</p> <p align="justify"><strong>According to industry players, the regions specifications are inclined towards seamless pipes and tubes. Why is there a preference/bias over its welded counterparts? Is it a manufacturing issue?<br></strong>One of the biggest roadblocks to the implementation of welded tubing is the perception that the weld itself is a defect and ergo, welded tubing contains one continuous defect along its entire length. It is perceived as a weak spot in an otherwise continuous material. For many years, the industry was not able to provide a suitable quality welded product. However, since the 1950s, the industry has advanced significantly and modern day seam welded tubulars, from reputable conscientious manufacturers, perform equally as well as seamless products in field service. If the seam weld can be identified by the naked eye, some consider it a defect. This is the attitude that has prevailed in the industry for so long. One needs only to look at the microstructure and physical and corrosion test data to see that this is not necessarily so. A properly processed fusion weld is nearly indistinguishable from the base metal in a metallographic laboratory examination. A properly processed weld exhibits the same physical and corrosion resistance properties as the base metal.</p> <p align="justify"><strong>Do you think seamless are more marketable than welded tubes and pipes?</strong> </p> <p align="justify">Seamless is marketed on an outdated myth that it does not have flaws but that welded has an inherent flaw throughout the length of each tube, as stated above. Intuitively this concept is easily accepted by purchasers and designers with limited experience with the various products. Each product form and manufacturing method has its own inherent problems and potential defects.<br>Consumers must become familiar with what those problems and defects are, and how they might affect particular applications. Then they can make an informed decision based on facts, rather than myth. It is easy to market a manufacturing process and to have it specified in consumer documents rather than market on an in service performance basis. Once a process is written into a specification it is normally very difficult to change that perception and requirement. It is easy to keep the status quo as long as it appears to be working. There is often not sufficient motivation to evaluate alternative materials and manufacturing methods. It is usually a matter of economy that leads to change.<br>Welded tubing is acceptable as per most pressure vessel codes, and with additional non-destructive examination it can be used in place of seamless for lethal service applications. Why not for energy applications?</p> <p align="justify"><strong>Are there specific industrial standards the region has to follow?</strong></p> <p align="justify">The industrial standards required are related to the specific industry. The American Petroleum Institute standards are the primary standards followed in the Middle East. However, tubing specifications used most widely are the ASTM and ASME standards. The National Association of Corrosion Engineers (NACE) standards and guidelines are also commonly used. </p> <p align="justify">Answered by:</p> <p>Carl Kettermann, Technical Director, RathGibson Inc.<br>Rick Lore, President of Mid-South Control Line – a division of RathGibson Inc<br>Alfredo D’Souza, Director of Business Development, Middle East, Africa & India, RathGibson Inc. <p> <p>References: “Seamless vs. Welded?”. <a href="http://www.pipelineme.com/features/features/2010/06/seamless-vs-welded/">http://www.pipelineme.com/features/features/2010/06/seamless-vs-welded/</a>. January 2014.</p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com1tag:blogger.com,1999:blog-1839333376079838057.post-73925178165967477242014-01-24T09:45:00.001+07:002014-01-24T09:45:09.663+07:00Pipeline Pigging<p>Pipeline pigs are devices that are placed inside the pipe and traverse the pipeline. While buildup in a pipeline can cause transmittal slows or even plugging of the pipeline, cracks or flaws in the line can be disastrous. A form of flow assurance for oil and gas pipelines and flowlines, pipeline pigging ensures the line is running smoothly.</p> <p>The maintenance tool, pipeline pigs are introduced into the line via a pig trap, which includes a launcher and receiver. Without interrupting flow, the pig is then forced through it by product flow, or it can be towed by another device or cable. Usually cylindrical or spherical, pigs sweep the line by scraping the sides of the pipeline and pushing debris ahead. As the travel along the pipeline, there are a number functions the pig can perform, from clearing the line to inspecting the interior. <p><a href="http://lh5.ggpht.com/-RKbKUHyp5lU/UuHTQ69UdeI/AAAAAAAABc4/_u_Ya0Ro04o/s1600-h/HIW_pigging_1%25255B4%25255D.jpg"><img title="HIW_pigging_1" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="HIW_pigging_1" src="http://lh5.ggpht.com/--zrWE56AIOc/UuHTUNuvbSI/AAAAAAAABdA/ezk7tdAhT4Y/HIW_pigging_1_thumb%25255B2%25255D.jpg?imgmax=800" width="302" height="264"></a> <p><em>Figure 1. Foam pig [www.pollypig.com].</em> <p> <h3><strong>Types of Pipeline Pigs</strong></h3> <p align="justify">Although first used simply to clear the line, the purpose of pipeline pigging has evolved with the development of technologies. Utility pigs are inserted into the pipeline to remove unwanted materials, such as wax, from the line. Inline inspection pigs can also be used to examine the pipeline from the inside, and specialty pigs are used to plug the line or isolate certain areas of the line. Lastly, gel pigs are a liquid chemical pigging system.</p> <p align="justify">Similar to cleaning your plumbing line, <strong>utility pigs</strong> are used to clean the pipeline of debris or seal the line. Debris can accumulate during construction, and the pipeline is pigged before production commences. Also, debris can build up on the pipeline, and the utility pig is used to scrape it away. Additionally, sealing pigs are used to remove liquids from the pipeline, as well as serve as an interface between two different products within a pipeline. Types of utility pigs include mandrel pigs, foam pigs, solid cast pigs and spherical pigs.</p> <p align="justify"><a href="http://lh5.ggpht.com/-kwrsrnzkGkE/UuHTZ-_QIPI/AAAAAAAABdI/0TLbMdNRTKo/s1600-h/HIW_pigging_3%25255B4%25255D.jpg"><img title="HIW_pigging_3" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="HIW_pigging_3" src="http://lh5.ggpht.com/-ML4gNdpNVuE/UuHTfyb44fI/AAAAAAAABdQ/NP6Ha2D_6vM/HIW_pigging_3_thumb%25255B2%25255D.jpg?imgmax=800" width="324" height="250"></a></p> <p align="justify"><em>Figure 2. Pipeline pig [www.pipeline-pigging.com].</em></p> <p align="justify"><strong>Inspection pigs</strong>, also referred to as in-line inspection pigs or smart pigs, gather information about the pipeline from within. . The type of information gathered by smart pigs includes the pipeline diameter, curvature, bends, temperature and pressure, as well as corrosion or metal loss. Inspection pigs utilize two methods to gather information about the interior condition of the pipeline: magnetic flux leakage (MFL) and ultrasonics (UT). MFL inspects the pipeline by sending magnetic flux into the walls of the pipe, detecting leakage, corrosion, or flaws in the pipeline. Ultrasonic inspection directly measures the thickness of the pipe wall by using ultrasonic sounds to measure the amount of time it takes an echo to return to the sensor <p align="justify"><strong>Specialty pigs</strong>, such as plugs, are used to isolate a section of the pipeline for maintenance work to be performed. The pig plug keeps the pipeline pressure in the line by stopping up the pipeline on either side of where the remedial work is being done. <p align="justify">A combination of gelled liquids, <strong>gel pigs</strong> can be used in conjunction with conventional pigs or by themselves. Pumped through the pipeline, there are a number of uses for gel pigs, including product separation, debris removal, hydrotesting, dewatering and condensate removal, as well as removing a stuck pig. <p align="justify">Because there now exist multi-diameter pipelines, dual and multi-diameter pigs have been developed, as well. <p align="justify"> <h3 align="justify">Intelligent Pigs</h3> <p align="justify">The accuracy of location and measurement of anomalies by the intelligent pigs has continued to improve. Initially, the electronics and power systems were so large that intelligent pigs could be used only in lines 30 in. and greater in size. The continued sophistication and miniaturization of the electronic systems used in the intelligent pigs has allowed the development of smaller pigs that can be used in small-diameter pipelines. Newly enacted DOT pipeline-integrity regulations and rules acknowledge the effectiveness of the intelligent pigs and incorporate their use in the pipeline-integrity testing process. <p align="justify"> <h3 align="justify">Pig Launchers and Receivers</h3> <p align="justify">Pigging facilities and considerations should be incorporated into the pipeline system design. Basic pigging facilities require a device to launch the pig into the pipeline and a receiver system to retrieve the pig as shown in <b>Fig. 3.</b> The launcher barrel is typically made from a short segment of pipe that is one to two sizes larger than the main pipeline and is fitted with a transition fitting (eccentric reducer) and a special closure fitting on the end. The barrel is isolated from the pipeline with full-port gate or ball valves. A “kicker” line, a minimum of 25% capacity of the main line, is tied from the main pipeline to the barrel, approximately 1 1/2 to 2 pig lengths upstream of the transition reducer, to provide the fluid flow to “launch” the pig into the pipeline. The barrel is fitted with blowdown valves, vent valves, and pressure gauges on the top and drain valves on the bottom. The length of the barrel is determined by the length and number of pigs to be launched at any one time. Receivers have many of the same features.</p> <p align="justify"><a href="http://lh3.ggpht.com/-0zhCKfRzxZY/UuHTmUzA5kI/AAAAAAAABdY/PGgDr4j7w2k/s1600-h/361px-Vol3_Page_385_Image_0001%25255B5%25255D.png"><img title="361px-Vol3_Page_385_Image_0001" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="361px-Vol3_Page_385_Image_0001" src="http://lh4.ggpht.com/-vDKEKdIkNFE/UuHTsM0GGAI/AAAAAAAABdg/UyuMJhZZevM/361px-Vol3_Page_385_Image_0001_thumb%25255B3%25255D.png?imgmax=800" width="369" height="611"></a></p> <p align="justify"><em>Figure 3. Typical sphere launcher and receiver traps.</em></p> <h3 align="justify">Pig Selection</h3> <p align="justify">Pig runs of between 50 to 100 miles are normal, but pig runs exceeding 200 miles should be avoided as the pig may wear and get stuck in the line. Cleaning pigs may be constructed of steel body with polyurethane cups or discs and foam pigs with polyurethane wrapping, solid urethane disc, and steel body with metallic brushes. Drying pigs are usually low-density foam or multicup urethane. The intelligent pigs may be: <ul> <li> <div align="justify">Magnetic flux leakage </div> <li> <div align="justify">Ultrasonic </div> <li> <div align="justify">Elastic/shear wave </div> <li> <div align="justify">Transponder/transducer </div> <li> <div align="justify">Or combinations thereof</div></li></ul> <p align="justify">Internal-coating pigs are generally multicup urethane type. Batching pigs are typically bidirectional, multidisk rubber, which maintain efficiency up to 50 miles. Pigs used for obstruction inspection are typically urethane, multicup type fitted with an aluminum gauge plate or a gel type. <p align="justify">Spheres are generally sized to be approximately 2% greater diameter than the pipe internal diameter. Cups and discs are typically sized to be 1/16 to 1/8 in. larger in diameter than the pipe ID. Foam pigs have to be significantly oversized. Foam pigs 1 to 6 in. in diameter should be oversized by 1/4 in.; foam pigs 8 to 16 in. in diameter should be oversized 3/8 to 1/2 in.; foam pigs 18 to 24 in. in diameter should be oversized 1/2 to 1 in.; and foam pigs 28 to 48 in. in diameter should be oversized 1 to 2 in. <p align="justify">References: <ul> <li> <div align="justify">“How Does Pipeline Pigging Work?”. <a href="http://www.rigzone.com/training/insight.asp?insight_id=310&c_id=19">http://www.rigzone.com/training/insight.asp?insight_id=310&c_id=19</a>. January 2014.</div></li> <li> <div align="justify">“Pipeline Pigging”. <a href="http://petrowiki.org/Pipeline_pigging">http://petrowiki.org/Pipeline_pigging</a>. January 2014.</div></li></ul> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-34517299545313600962014-01-24T09:22:00.001+07:002014-01-24T09:22:12.834+07:00Offshore Pipeline Installation<p>Laying pipe on the seafloor can pose a number of challenges, especially if the water is deep. There are three main ways that subsea pipe is laid -- S-lay, J-lay and tow-in -- and the pipelay vessel is integral to the success of the installation.</p> <p>Buoyancy affects the pipelay process, both in positive and negative ways. In the water, the pipe weighs less if it is filled with air, which puts less stress on the pipelay barge. But once in place on the sea bed, the pipe requires a downward force to remain in place. This can be provided by the weight of the oil passing through the pipeline, but gas does not weigh enough to keep the pipe from drifting across the seafloor. In shallow-water scenarios, concrete is poured over the pipe to keep it in place, while in deepwater situations, the amount of insulation and the thickness required to ward of hydrostatic pressure is usually enough to keep the line in place.</p> <h3>Tow-In Pipeline Installation</h3> <p>While jumpers are typically short enough to be installed in sections by ROVs, flowlines and pipelines are usually long enough to require a different type of installation, whether that is tow-in, S-lay or J-lay. <p>Tow-in installation is just what it sounds like; here, the pipe is suspended in the water via buoyancy modules, and one or two tug boats tow the pipe into place. Once on location, the buoyancy modules are removed or flooded with water, and the pipe floats to the seafloor. <p><a href="http://lh3.ggpht.com/-nzRsUWntdVA/UuHMcBlt39I/AAAAAAAABbU/9wE-K0OfvVM/s1600-h/HIW_Pipelay_1%25255B4%25255D.jpg"><img title="HIW_Pipelay_1" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="HIW_Pipelay_1" src="http://lh6.ggpht.com/-4T8yNZXIAEg/UuHMhf0ngyI/AAAAAAAABbc/cegAWV5tVos/HIW_Pipelay_1_thumb%25255B2%25255D.jpg?imgmax=800" width="244" height="270"></a> <p><em>Figure 1: pipeline towing installation [www.pipeline.no].</em> <p>There are four main forms of tow-in pipeline installation. The first, the<strong>surface tow</strong> involves towing the pipeline on top of the water. In this method, a tug tows the pipe on top of the water, and buoyancy modules help to keep it on the water's surface. <p>Using less buoyancy modules than the surface tow, the <strong>mid-depth tow</strong> uses the forward speed of the tug boat to keep the pipeline at a submerged level. Once the forward motion has stopped, the pipeline settles to the seafloor. <p><strong>Off-bottom tow</strong> uses buoyancy modules and chains for added weight, working against each other to keep the pipe just above the sea bed. When on location, the buoyancy modules are removed, and the pipe settles to the seafloor. <p>Lastly, the <strong>bottom tow</strong> drags the pipe along the sea bed, using no buoyancy modules. Only performed in shallow-water installations, the sea floor must be soft and flat for this type of installation. <p> <h3>S-Lay Pipeline Installation</h3> <p>When performing <strong>S-lay</strong> pipeline installation, pipe is eased off the stern of the vessel as the boat moves forward. The pipe curves downward from the stern through the water until it reaches the "touchdown point," or its final destination on the seafloor. As more pipe is welded in the line and eased off the boat, the pipe forms the shape of an "S" in the water.</p> <p><a href="http://lh4.ggpht.com/-ZJa0Z3mdp6w/UuHMlNfW82I/AAAAAAAABbk/txx3ZUHNI9Y/s1600-h/HIW_Pipelay_2%25255B4%25255D.jpg"><img title="HIW_Pipelay_2" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="HIW_Pipelay_2" src="http://lh5.ggpht.com/-ambFmFZRQyo/UuHMvcX-KGI/AAAAAAAABbs/QY_durCC4UM/HIW_Pipelay_2_thumb%25255B2%25255D.jpg?imgmax=800" width="327" height="162"></a></p> <p><em>Figure 2: S-Lay pipeline installation [www.pbjv,com.my].</em></p> <p>Stingers, measuring up to 300 feet (91 meters) long, extend from the stern to support the pipe as it is moved into the water, as well as control the curvature of the installation. Some pipelay barges have adjustable stingers, which can be shortened or lengthened according to the water depth.</p> <p><a href="http://lh6.ggpht.com/-MipwyFAGanM/UuHM0FNssdI/AAAAAAAABb0/_kjMDwvwzRo/s1600-h/HIW_Pipelay_3%25255B4%25255D.jpg"><img title="HIW_Pipelay_3" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="HIW_Pipelay_3" src="http://lh5.ggpht.com/-dnqOjq1aU2k/UuHM5z1oizI/AAAAAAAABb8/KgSN6I6WFM8/HIW_Pipelay_3_thumb%25255B2%25255D.jpg?imgmax=800" width="254" height="285"></a></p> <p><em>Figure 3: Pipe being lowered into the water via a stinger for S-lay installation.</em></p> <p>Proper tension is integral during the S-lay process, which is maintained via tensioning rollers and a controlled forward thrust, keeping the pipe from buckling. S-lay can be performed in waters up to 6,500 feet (1,981 meters) deep, and as many as 4 miles (6 kilometers) a day of pipe can be installed in this manner.</p> <h3>J-Lay Pipeline Installation</h3> <p>Overcoming some of the obstacles of S-lay installation, <strong>J-lay</strong> pipeline installation puts less stress on the pipeline by inserting the pipeline in an almost vertical position. Here, pipe is lifted via a tall tower on the boat, and inserted into the sea. Unlike the double curvature obtained in S-lay, the pipe only curves once in J-lay installation, taking on the shape of a "J" under the water.</p> <p><a href="http://lh3.ggpht.com/-kvQ_6GAHuNY/UuHM-i2nCLI/AAAAAAAABcE/khnnNoD9GpE/s1600-h/HIW_Pipelay_4%25255B4%25255D.jpg"><img title="HIW_Pipelay_4" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="HIW_Pipelay_4" src="http://lh3.ggpht.com/-PRugNgAn7dw/UuHNRbjMunI/AAAAAAAABcM/XuoCbaMyxFw/HIW_Pipelay_4_thumb%25255B2%25255D.jpg?imgmax=800" width="332" height="176"></a></p> <p><em>Figure 4. J-Lay pipeline installation [www.technip.com].</em></p> <p>The reduced stress on the pipe allows J-lay to work in deeper water depths. Additionally, the J-lay pipeline can withstand more motion and underwater currents than pipe being installed in the S-lay fashion.</p> <p><a href="http://lh6.ggpht.com/-UbIhMcMHlfU/UuHNkoamBrI/AAAAAAAABcU/uPRBh5KImXo/s1600-h/HIW_Pipelay_5%25255B4%25255D.jpg"><img title="HIW_Pipelay_5" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="HIW_Pipelay_5" src="http://lh6.ggpht.com/-E9PrxC1kRa8/UuHNrEW83TI/AAAAAAAABcc/D_V3zwd4Rgw/HIW_Pipelay_5_thumb%25255B2%25255D.jpg?imgmax=800" width="328" height="205"></a></p> <p><em>Figure 5. J-Lay Pipelay Vessel S7000</em></p> <h3>Types Of Pipelay Vessels</h3> <p>There are three main types of pipelay vessels. There are <strong>J-lay and S-lay barges</strong> that include a welding station and lifting crane on board. The 40- or 80-foot (12- or 24-meter) pipe sections are welded away from wind and water, in an enclosed environment. On these types of vessels, the pipe is laid one section at a time, in an assembly-line method. <p>On the other hand, <strong>reel barges</strong> contain a vertical or horizontal reel that the pipe is wrapped around. Reel barges are able to install both smaller diameter pipe and flexible pipe. Horizontal reel barges perform S-lay installation, while vertical reel barges can perform both S-lay and J-lay pipeline installation. <p><a href="http://lh3.ggpht.com/-3m1_kMcqu6A/UuHNu8ziuPI/AAAAAAAABck/6OynGA3AD14/s1600-h/HIW_Pipelay_6%25255B4%25255D.jpg"><img title="HIW_Pipelay_6" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="HIW_Pipelay_6" src="http://lh4.ggpht.com/-RElkXukr3dM/UuHOGhPsT0I/AAAAAAAABcs/K1NlMQkyryo/HIW_Pipelay_6_thumb%25255B2%25255D.jpg?imgmax=800" width="303" height="198"></a> <p><em>Figure 6. Vertical reel barge [www.jee.co.uk].</em> <p>When using reel barges, the welding together of pipe sections is done onshore, reducing installation costs. Reeled pipe is lifted from the dock to the vessel, and the pipe is simply rolled out as installation is performed. Once all of the pipe on the reel has been installed, the vessel either returns to shore for another, or some reel barges are outfitted with cranes that can lift a new reel from a transport vessel and return the spent reel, which saves time and money. <p>References: “How Does Offshore Pipeline Installation Work?”. <a href="http://www.rigzone.com/training/insight.asp?insight_id=311&c_id=19">http://www.rigzone.com/training/insight.asp?insight_id=311&c_id=19</a>. January 2014. alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com2tag:blogger.com,1999:blog-1839333376079838057.post-47156347447235788472014-01-24T08:52:00.001+07:002014-01-24T08:54:38.041+07:00Hyperbaric Welding<p align="justify">Hyperbaric welding is the process of welding at elevated pressures, normally underwater. Hyperbaric welding can either take place wet in the water itself or dry inside a specially constructed positive pressure enclosure and hence a dry environment. It is predominantly referred to as "hyperbaric welding" when used in a dry environment, and "underwater welding" when in a wet environment. The applications of hyperbaric welding are diverse—it is often used to repair ships, offshore oil platforms, and pipelines. Steel is the most common material welded.<br>Dry hyperbaric welding is used in preference to wet underwater welding when high quality welds are required because of the increased control over conditions which can be exerted, such as through application of prior and post weld heat treatments. This improved environmental control leads directly to improved process performance and a generally much higher quality weld than a comparative wet weld. Thus, when a very high quality weld is required, dry hyperbaric welding is normally utilized. Research into using dry hyperbaric welding at depths of up to 1,000 metres (3,300 ft) is ongoing. In general, assuring the integrity of underwater welds can be difficult (but is possible using various nondestructive testing applications), especially for wet underwater welds, because defects are difficult to detect if the defects are beneath the surface of the weld.<br>Underwater hyperbaric welding was invented by the Russian metallurgist Konstantin Khrenov in 1932.</p> <p align="justify"><a href="http://lh4.ggpht.com/-Ac-DbkNOk_E/UuHG7nXM4vI/AAAAAAAABaw/xwvzMQIFjms/s1600-h/391px-Working_Diver_01%25255B4%25255D.jpg"><img title="391px-Working_Diver_01" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="391px-Working_Diver_01" src="http://lh3.ggpht.com/-k2ehFwq4qsU/UuHHEUkwfxI/AAAAAAAABa4/Hzde5JyzV18/391px-Working_Diver_01_thumb%25255B2%25255D.jpg?imgmax=800" width="285" height="438"></a></p> <p align="justify"><em>Figure 1: Underwater welding performed by US Navy diver.</em></p> <p><strong>1. Dry</strong></p> <p align="justify">Dry hyperbaric welding involves the weld being performed at the prevailing pressure in a chamber filled with a gas mixture sealed around the structure being welded.<br>Most welding processes SMAW, FCAW, GTAW, GMAW, PAW could be operated at hyperbaric pressures, but all suffer as the pressure increases. Gas tungsten arc welding is most commonly used. The degradation is associated with physical changes of the arc behaviour as the gas flow regime around the arc changes and the arc roots contract and become more mobile. Of note is a dramatic increase in arc voltage which is associated with the increase in pressure. Overall a degradation in capability and efficiency results as the pressure increases. Welding processes have become increasingly important in almost all manufacturing industries and for structural application [Khanna, 2004]. Although a large number of techniques are available for welding in atmosphere, many of these techniques cannot be applied in offshore and marine application where presence of water is of major concern. In this regard, it is relevant to note that a great majority of offshore repairing and surfacing work is carried out at a relatively shallow depth, in the region intermittently covered by the water known as the splash zone. Though numerically most ship repair and welding jobs are carried out at a shallow depth, most technologically challenging task lies in the repairing at a deeper water level, especially in pipelines and occurrence/creation of sudden defects leading to a catastrophic accidental failure. The advantages of underwater welding are of economical nature, because underwater-welding for marine maintenance and repair jobs bypasses the need to pull the structure out of the sea and saves valuable time and dry docking costs.<br>Special control techniques have been applied which have allowed welding down to 2500m simulated water depth in the laboratory, but dry hyperbaric welding has thus far been limited operationally to less than 400m water depth by the physiological capability of divers to operate the welding equipment at high pressures and practical considerations concerning construction of an automated pressure / welding chamber at depth.</p> <p align="justify"><strong>2. Wet</strong></p> <p align="justify">Wet underwater welding commonly uses a variation of shielded metal arc welding, employing a waterproof electrode. Other processes that are used include flux-cored arc welding and friction welding. In each of these cases, the welding power supply is connected to the welding equipment through cables and hoses. The process is generally limited to low carbon equivalent steels, especially at greater depths, because of hydrogen-caused cracking.</p> <p align="justify"><a href="http://lh3.ggpht.com/-whFiRhYOsso/UuHHJNn1I3I/AAAAAAAABbA/M8l2f5zplLM/s1600-h/Underwater_welding%25255B4%25255D.jpg"><img title="Underwater_welding" style="border-top: 0px; border-right: 0px; background-image: none; border-bottom: 0px; padding-top: 0px; padding-left: 0px; border-left: 0px; display: inline; padding-right: 0px" border="0" alt="Underwater_welding" src="http://lh5.ggpht.com/-ckfd_AafdZg/UuHHVcXuSlI/AAAAAAAABbI/j4eAc6mdMI8/Underwater_welding_thumb%25255B2%25255D.jpg?imgmax=800" width="389" height="292"></a></p> <p align="justify"><em>Figure 2: underwater wet welding</em></p> <p align="justify"><strong>3. Risks</strong></p> <p align="justify">The risks of underwater welding include the risk of electric shock to the welder. To prevent this, the welding equipment must be adaptable to a marine environment, properly insulated and the welding current must be controlled. Commercial divers must also consider the safety issues that normal divers face; most notably, the risk of decompression sickness following saturation diving due to the increased pressure of inhaled breathing gases. Many divers have reported a metallic taste that is related to the breakdown of dental amalgam. There may also be long term cognitive and possibly musculoskeletal effects associated with underwater welding.</p> <p>References: “Hyperbaric welding”, <a href="http://en.wikipedia.org/wiki/Hyperbaric_welding">http://en.wikipedia.org/wiki/Hyperbaric_welding</a></p> alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0tag:blogger.com,1999:blog-1839333376079838057.post-61906460254248070552014-01-22T22:33:00.001+07:002014-02-01T03:19:29.479+07:002LPE Coating Technology for Pipeline ProtectionAuthor: S. Guan and P. Mayes (Bredero Shaw); A. Andrenacci and D. Wong (ShawCor)<br />
SUMMARY: Oil and Gas pipelines are protected by various types of external coatings in conjunction with CP systems. Polyethylene is commonly used as the top coat in two or three layer systems. The existing two layer system found in the North American and Australian markets uses an adhesive that is mastic-based. It provides excellent corrosion resistant properties and has relatively low shear resistance in the adhesive layer, particularly at higher temperatures. The three layer system uses a copolymer adhesive to provide excellent shear properties and an epoxy layer which provides corrosion resistance. Both are excellent coatings when used in the proper environment. The major differences between the two systems are the mechanical properties at higher temperatures and the cost. The intention of this paper is to introduce a new system that bridges the gap in cost and performance between the two existing products. The new coating uses a hybrid adhesive which combines both the mastic and the copolymer functions, hence providing excellent corrosion resistance and adequate shear properties to withstand pipe movement and significantly reduce stockpiling and handling problems in high climate temperatures. The paper presents both the laboratory and plant production results and compares them to the properties of the other two existing coatings.<br />
<strong>1. Introduction</strong><br />
Today’s pipelines in the oil, gas and water transportation industries worldwide are usually protected by external coatings in conjunction with cathodic protection systems. Pipe coating solution providers are offering various types of products tailored to the needs of their clients. Some of these common pipeline coating products include two-layer and three-layer coating systems that provide excellent anti-corrosion protection to pipes.<br />
Two-layer systems refer to coatings that contain one layer of adhesive and another of polyethylene. Currently, the adhesives used in two-layer systems are either mastic-based or copolymers of polyethylene. Mastic-based adhesives, although being relatively inexpensive and providing good cathodic disbondment (C.D.) resistance, have low shear and peel strength values and are restricted to low temperature applications. Two-layer products based on copolymers have very good adhesion and shear resistance but generally poor cathodic disbondment resistance.<br />
A three-layer system generally consists of an epoxy layer, a copolymer adhesive layer and a layer of polyethylene. This system can be operated at higher temperatures, however, due to the fact that an epoxy layer is required, it is more expensive with a more complex and critical application process.<br />
The motivation for the product development introduced by this paper is to provide pipeline operators with a third alternative, one which joins the benefits of the two systems while eliminating most of their disadvantages. The development was designed and completed by Bredero Shaw – A ShawCor Company. Using a hybrid adhesive which combines the mastic and the copolymer functions, the product provides excellent corrosion resistance and adequate shear properties to withstand pipe movement and eliminate any stockpiling and handling problems in high climate temperatures. The paper presents both the laboratory and production results and compares them to the properties of the other two existing coatings.<br />
<strong>2. The Product Development Approach</strong><br />
There are two types of adhesives used in the pipeline coating industry, mastic and copolymers. Mastic adhesives are mainly made from rubbers with the addition of modifiers. Just like rubber, they appear tacky and soft. Mastic adhesives can be broken further into two types: the asphalt based and the non-asphalt based. The asphalt based adhesives are inexpensive and provide excellent cathodic protection. The benefits and disadvantages of using mastic adhesives are outlined in Table 1.<br />
<div align="center">
<em>Table 1: Advantages and Disadvantages of Using Mastic Adhesives in Pipeline Protection</em></div>
<table border="1" cellpadding="2" cellspacing="0" style="width: 600px;"> <tbody>
<tr> <td valign="top" width="297"><div align="center">
<strong>Advantages</strong></div>
</td> <td valign="top" width="301"><div align="center">
<strong>Disadvantages</strong></div>
</td></tr>
<tr> <td valign="top" width="297">Lower manufacturing cost</td> <td valign="top" width="301">Relatively low shear and peel resistance</td></tr>
<tr> <td valign="top" width="297">Mostly amorphous</td> <td valign="top" width="301">Lower operating temperature</td></tr>
<tr> <td valign="top" width="297">Pressure sensitive</td> <td valign="top" width="301">Poorer compression resistance (stock piling)</td></tr>
<tr> <td valign="top" width="297">Forgiving to application temperature</td> <td valign="top" width="301">Less resistance to soil stress</td></tr>
<tr> <td valign="top" width="297">Forgiving to surface preparation</td> <td valign="top" width="301">Limited to small diameter pipes (<600 mm or 26”)</td></tr>
<tr> <td valign="top" width="297">Goof C.D resistance</td> <td valign="top" width="301"></td></tr>
<tr> <td valign="top" width="297">Excellent water repellents</td> <td valign="top" width="301"></td></tr>
<tr> <td valign="top" width="297">Easy to apply</td> <td valign="top" width="303"></td></tr>
</tbody></table>
Copolymer adhesives are commonly used in the pipeline coating industry. They are non-tacky and hard at room temperature but become sticky and soft at high temperatures. They are generally made from semi- crystalline resins or copolymers of polyethylene and polypropylene. Maleic anhydrides are often grafted onto the polyolefin backbone to improve adhesion.<br />
There are advantages and disadvantages of using copolymer adhesives in pipeline protection, which are outlined in Table 2. Copolymer adhesives, as previously mentioned, give outstanding shear and peel values, and can withstand high temperatures. However, they require more complex application procedures; they are higher in costs and have poor cathodic disbondment resistances without an epoxy under layer.<br />
<div align="center">
<em>Table 2: Advantages and Disadvantages of Using Copolymer Adhesives in Pipeline Protection</em></div>
<table border="1" cellpadding="2" cellspacing="0" style="width: 600px;"> <tbody>
<tr> <td valign="top" width="299"><div align="center">
<strong>Advantages</strong></div>
</td> <td valign="top" width="299"><div align="center">
<strong>Disadvantages</strong></div>
</td></tr>
<tr> <td valign="top" width="299">High shear and peel values</td> <td valign="top" width="299">More complex to apply</td></tr>
<tr> <td valign="top" width="299">Higher operating temperatures</td> <td valign="top" width="299">Surface pre-heat is critical</td></tr>
<tr> <td valign="top" width="299">Better compression resistance</td> <td valign="top" width="299">Poor wetting characteristics</td></tr>
<tr> <td valign="top" width="299">Excellent resistance to soil stress</td> <td valign="top" width="299">Requires perfectly prepared and cleaned surface</td></tr>
<tr> <td valign="top" width="299"></td> <td valign="top" width="299">More expensive</td></tr>
<tr> <td valign="top" width="299"></td> <td valign="top" width="299">Poor C.D. resistance without epoxy primer</td></tr>
<tr> <td valign="top" width="299"></td> <td valign="top" width="299">Sensitive to wet conditions and to cycling temperatures</td></tr>
</tbody></table>
A novel approach was taken in this study by formulating a two-layer pipe coating system through the use of a hybrid adhesive. The hybrid adhesive was made by combining some key raw materials used in mastic adhesives with those used in the copolymer adhesives. The intention was to bring together the desirable qualities of mastic-based and copolymer-based systems while minimizing their disadvantages as shown in Figure 1. In short we were able to incorporate the same crystalline polymers into the rubber matrix, hence increasing the adhesive shear and peel properties while maintaining some of the mastic elastic properties.<br />
The hybrid adhesive was then applied in both laboratory and plant production settings using standard two layer extrusion equipment with minor modifications. After the application of the hybrid adhesive, an HDPE top layer was cross-head extruded. The HDPE was the same material that is normally used for standard two layer or three layer coating systems, having the typical material properties as shown in Table 3. Various materials and performance tests were conducted on both the new hybrid adhesive and the coated pipe samples as per standard AS/NZS 1518:2002 as well as other international pipe coating standards such as CSAZ245.21 and ISO 21809-4.Test data was then compared with typical values from standard 2 Layer Polyethylene (2LPE) and 3 Layer Polyethylene (3LPE) coating systems.<br />
<a href="http://lh5.ggpht.com/-E8hgc4cBhm8/Ut_dO-qSkvI/AAAAAAAABYM/XuscKegHfwE/s1600-h/image%25255B5%25255D.png"><img alt="image" border="0" src="http://lh4.ggpht.com/-Dvxlm8Lbaok/Ut_dS2qdixI/AAAAAAAABYU/WqdJ2RkzZD8/image_thumb%25255B3%25255D.png?imgmax=800" height="376" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: block; float: none; margin-left: auto; margin-right: auto; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="image" width="442" /></a><br />
<div align="center">
<em>Figure 1: New hybrid adhesive brings together the desirable qualities of mastic-based and copolymer-based systems.</em></div>
<div align="center">
<em>Table 3: Material properties of HDPE used as per AS/NZS 1518:2002</em></div>
<table border="1" cellpadding="2" cellspacing="0" style="width: 599px;"> <tbody>
<tr> <td valign="top" width="180"><div align="center">
<strong>Property</strong></div>
</td> <td valign="top" width="138"><div align="center">
<strong>Test Method</strong></div>
</td> <td valign="top" width="146"><div align="center">
<strong>Acceptance Criteria</strong></div>
</td> <td valign="top" width="133"><div align="center">
<strong>Typical Values</strong></div>
</td></tr>
<tr> <td valign="top" width="179">Density</td> <td valign="top" width="139">ASTM D1505</td> <td valign="top" width="146">940 kg/m<sup>3</sup> min.</td> <td valign="top" width="132">941 kg/m<sup>3</sup></td></tr>
<tr> <td valign="top" width="179">Melt flow rate</td> <td valign="top" width="139">ASTM D1238 <br />
190°C/2.16 kg</td> <td valign="top" width="146">≤ 0.60 g/10 min.</td> <td valign="top" width="132">0.3-0.45 g/10 min</td></tr>
<tr> <td valign="top" width="179">Environmental stress-cracking at 100% Igepal concentration</td> <td valign="top" width="139">ASTM D1693 Condition<br />
B(F50)</td> <td valign="top" width="146">900 hrs.</td> <td valign="top" width="132">>1000 hrs.</td></tr>
<tr> <td valign="top" width="179">Ultraviolet light resistance</td> <td valign="top" width="139">AS1518</td> <td valign="top" width="146">400% min.</td> <td valign="top" width="132">>600%</td></tr>
<tr> <td valign="top" width="179">Tensile strength at yield</td> <td valign="top" width="139">AS1518</td> <td valign="top" width="146">17 MPa min.</td> <td valign="top" width="132">18.5 MPa</td></tr>
<tr> <td valign="top" width="179">Elongation to fracture</td> <td valign="top" width="139">ASTM D638 Type IV</td> <td valign="top" width="146">400% min.</td> <td valign="top" width="132">>600%</td></tr>
<tr> <td valign="top" width="179">Resistance to thermal degradation</td> <td valign="top" width="139">AS1518</td> <td valign="top" width="146">30% max. variation of melt flow index</td> <td valign="top" width="132">10%</td></tr>
<tr> <td valign="top" width="179">Resistance to splitting</td> <td valign="top" width="139">AS1518</td> <td valign="top" width="147">2 mm max.</td> <td valign="top" width="132">1.2 mm</td></tr>
</tbody></table>
<br />
<strong>3. Performance Results and Discussions</strong><br />
Table 4 shows the material properties of the new hybrid adhesive versus typical mastic and copolymer adhesives used in standard 2LPE and 3LPE systems as per AS/NZS 1518:2002. It can be seen that the hybrid adhesive has a softening point of 110±10<sup>o</sup>C, which is slightly higher than that of standard mastic based adhesives used in 2LPE but much lower than that of copolymer adhesives for 3LPE. Adhesives with high softening points require more energy and time to coat the pipes, making pipe coating production less economical. On the other hand, adhesives with too low softening points restrict coatings to be used only for low temperature applications. The lap shear strength of the hybrid adhesive is significantly higher than the current mastic-based adhesives and similar to those of the copolymer adhesives.<br />
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<em>Table 4: Material properties of new hybrid adhesive vs. mastic and copolymer as per AS/NZS 1518:2002</em></div>
<table border="1" cellpadding="2" cellspacing="0" style="width: 598px;"> <tbody>
<tr> <td valign="top" width="100"><div align="center">
<strong>Property</strong></div>
</td> <td valign="top" width="97"><div align="center">
<strong>Test Method</strong></div>
</td> <td valign="top" width="102"><div align="center">
<strong>Acceptance Criteria</strong></div>
</td> <td valign="top" width="98"><div align="center">
<strong>Mastic Adhesive</strong></div>
</td> <td valign="top" width="98"><div align="center">
<strong>Hybrid Adhesive</strong></div>
</td> <td valign="top" width="101"><div align="center">
<strong>Copolymer Adhesive (with Epoxy)</strong></div>
</td></tr>
<tr> <td valign="top" width="99">Flow at 20±3<sup>o</sup>C</td> <td valign="top" width="96">CSA Z245.21</td> <td valign="top" width="104">5 mm max.</td> <td valign="top" width="98">No Flow</td> <td valign="top" width="98">No Flow</td> <td valign="top" width="102">No Flow</td></tr>
<tr> <td valign="top" width="98">Flow at 70<sup>o</sup>C</td> <td valign="top" width="95">CSA Z245.21</td> <td valign="top" width="106">20 mm max.</td> <td valign="top" width="97">9.8 mm</td> <td valign="top" width="97">No Flow</td> <td valign="top" width="103">No Flow</td></tr>
<tr> <td valign="top" width="98">Softening point</td> <td valign="top" width="95">AS1518</td> <td valign="top" width="107">80°C min.</td> <td valign="top" width="97">96°C</td> <td valign="top" width="97">110±10°C</td> <td valign="top" width="103">~ 130-140°C</td></tr>
<tr> <td valign="top" width="98">Coarse particle<br />
contamination</td> <td valign="top" width="95">AS1518</td> <td valign="top" width="108">No retention on a 250 μm<br />
aperture sieve</td> <td valign="top" width="97">Pass</td> <td valign="top" width="97">Pass</td> <td valign="top" width="103">Pass</td></tr>
<tr> <td valign="top" width="98">Lap shear at 23°C @25.4<br />
mm/min</td> <td valign="top" width="94">AS1518</td> <td valign="top" width="109">34 N/cm<sup>2</sup> min.</td> <td valign="top" width="97">35 N/cm<sup>2</sup></td> <td valign="top" width="97">300 N/cm<sup>2</sup></td> <td valign="top" width="103">400 N/cm<sup>2</sup></td></tr>
<tr> <td valign="top" width="98">Water absorption</td> <td valign="top" width="94">AS1518</td> <td valign="top" width="109">0.1 wt% max.</td> <td valign="top" width="97">0.04 wt%</td> <td valign="top" width="97">0.04 wt%</td> <td valign="top" width="103">0.1 wt%</td></tr>
<tr> <td valign="top" width="98">Penetration</td> <td valign="top" width="94">AS1518</td> <td valign="top" width="109">5 mm max.</td> <td valign="top" width="97">4.3 mm</td> <td valign="top" width="97">0.85 mm</td> <td valign="top" width="103">~ 0.6 mm</td></tr>
<tr> <td valign="top" width="98">Plasticity at 5<sup>o</sup>C</td> <td valign="top" width="94">AS1518</td> <td valign="top" width="109">180°bend at 5°C</td> <td valign="top" width="97">Pass</td> <td valign="top" width="97">Pass</td> <td valign="top" width="103">Pass</td></tr>
<tr> <td valign="top" width="98">Plasticity at -20<sup>o</sup>C</td> <td valign="top" width="94">AS1518</td> <td valign="top" width="109">180° bend at -20°C</td> <td valign="top" width="97">Pass</td> <td valign="top" width="97">Pass</td> <td valign="top" width="103">Pass</td></tr>
<tr> <td valign="top" width="98">Cathodic disbondment</td> <td valign="top" width="94">AS4352</td> <td valign="top" width="110">Less than 12 mm at 22.5°C,<br />
28 days</td> <td valign="top" width="97">6-11 mm</td> <td valign="top" width="97">7-9 mm</td> <td valign="top" width="104">4-9 mm</td></tr>
</tbody></table>
Table 5 shows the performance properties of the new hybrid 2LPE pipe coating versus standard mastic-based 2LPE and standard 3LPE systems as per AS/NZS 1518:2002. It can be seen that the new hybrid 2LPE coating has less of a cut back of adhesive than mastic-based adhesives. It can also be seen that the new coating will have significantly improved flow resistance when exposed to the Australian high ambient temperature and stockpiling weights. The peel test showed the hybrid coating to have much stronger peel strength than the current mastic-based 2LPE.<br />
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<em>Table 5: Performance properties of the new hybrid 2LPE coating vs. standard 2LPE and 3LPE as per AS/NZS 1518:2002</em></div>
<a href="http://lh6.ggpht.com/-dM7vJwQl8Jg/Ut_dZEjmS0I/AAAAAAAABYc/iO2Ohk5aw5g/s1600-h/image%25255B10%25255D.png"><img alt="image" border="0" src="http://lh6.ggpht.com/-7nj1xzQ3ih8/Ut_devA8t5I/AAAAAAAABYk/MhkaFRO6Vnk/image_thumb%25255B6%25255D.png?imgmax=800" height="277" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: inline; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="image" width="633" /></a><br />
Extensive testing was conducted at different temperatures to confirm that the new hybrid coating system has adequate shear properties to withstand pipe movement and sigficantly reduce any stockpiling and handling problems in high climate temperatures. As seen in Table 6, the lap shear strengths of the hybrid 2LPE system are significantly higher than that of the current mastic-based 2LPE and similar to those of the copolymer-based 3LPE at 23°C. At 70°C, the hybrid 2LPE exhibited quite similar lap shear strength values that would be otherwise achieved by standard mastic-based 2LPE systems at 23°C.<br />
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<em>Table 6: Comparison of lap shear strength at different temperatures</em></div>
<a href="http://lh4.ggpht.com/-qPRlziwrui4/Ut_djl5ibiI/AAAAAAAABYs/Hyi4sA5B-RE/s1600-h/image%25255B15%25255D.png"><img alt="image" border="0" src="http://lh3.ggpht.com/-cvClSGNgMhk/Ut_dppYdKPI/AAAAAAAABY0/hZIHfGAjHLU/image_thumb%25255B9%25255D.png?imgmax=800" height="164" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: inline; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="image" width="635" /></a><br />
Two additional types of peel adhesion tests were performed as per CSA Z245.21 and ISO21809-4 standards: the hanging weight peel test and the constant rate of peel (Instron peel test), with the testing results shown in Table 7. For the hanging weight peel test, a pipe coating system was rated as pass if its displacement was less than or equal to 10mm/min. The new hybrid 2LPE system passed the test with 300g, 2000g, 4000g and 5000g weights, while current mastic-based 2LPE would only meet 300g (as required by CSA Z245.21 for this type of coating). With the Instron peel test, the test values as well as the ways in which the systems failed were recorded. There are three modes of failure for a coating system: cohesive (separation occurs within the adhesive layer), adhesive-pipe (separation of adhesive layer completely from the steel surface of the pipe) and adhesive-topcoat (adhesive layer separation from topcoat but remains bonded to pipe). These peel tests showed the hybrid system to have much stronger peel strengths than the current mastic-based 2LPE and to fail cohesively.<br />
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<em>Table 7: Comparison of peel adhesion strength by hanging weight testing and Instron peel testing</em></div>
<a href="http://lh5.ggpht.com/-kFd1aZqlRdk/Ut_dub5oUxI/AAAAAAAABY8/WxhJVZTxSBs/s1600-h/image%25255B20%25255D.png"><img alt="image" border="0" src="http://lh3.ggpht.com/-WRLpGxJW8yo/Ut_dx-P81QI/AAAAAAAABZE/nQcO69uoLPc/image_thumb%25255B12%25255D.png?imgmax=800" height="290" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: inline; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="image" width="633" /></a><br />
Table 8 shows the comparison of cathodic disbondment resistance of the new hybrid 2LPE pipe coating versus standard mastic-based 2LPE and standard 3LPE systems at different temperatures. Figure 2 shows the cathodic disbondment resistance testing setup at 65°C. At both room temperatures and 65°C the results obtained were comparable to the current mastic-based 2LPE products. Short-term cathodic disbondment testing at higher temperatures (70°C and 80°C) provided acceptable results.<br />
Table 9 shows the testing results of additional performance properties related to the ability of the new hybrid two-layer coating system for pipe handling and stockpile loading, including flexibility, peel adhesion after stockpiling, cathodic disbondment resistance after stockpiling and impact resistance. Flexibility refers to how much a material can be bended without rupturing. When coated pipes are laid into the ground, they are often bended to a certain degree to comform to the contour of the land. Therefore, it is important that any adhesive coated on the pipes are flexible enough to withstand the bend without cracking. Figure 3 shows good results of the flexibility testing as per ISO 21809-4. The results of both peel adhesion and cathodic disbondment resistance after stockpiling at 55oC and 75oC were also excellent. The impact resistance of the new hybrid 2LPE system was better than that of standard mastic-based 2LPE systems and about the same as 3LPE systems.<br />
<div align="center">
<em>Table 8: Comparison of cathodic disbondment resistance at different temperatures</em></div>
<a href="http://lh3.ggpht.com/-I7w3H1UkMe8/Ut_d27h8GiI/AAAAAAAABZM/kTf5SttHxdQ/s1600-h/image%25255B25%25255D.png"><img alt="image" border="0" src="http://lh5.ggpht.com/-PbKtD5ewhZ4/Ut_d7nEfU0I/AAAAAAAABZU/BF52fbinRgg/image_thumb%25255B15%25255D.png?imgmax=800" height="188" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: inline; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="image" width="627" /></a><br />
<div align="center">
<em>Table 9: Additional performance properties related to handling and stockpile loading</em></div>
<a href="http://lh6.ggpht.com/-Hf0RLkYtr3s/Ut_kUfGlH4I/AAAAAAAABZ4/_t82rN3pxyc/s1600-h/image%25255B30%25255D.png"><img alt="image" border="0" src="http://lh6.ggpht.com/-AVh365v1rP4/Ut_kdIVuNkI/AAAAAAAABaA/36F7SAkX11w/image_thumb%25255B18%25255D.png?imgmax=800" height="274" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: inline; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="image" width="626" /></a><br />
<a href="http://lh4.ggpht.com/-9NSnYDTtW1s/Ut_kinvO2gI/AAAAAAAABaI/H4HTuX5sr_c/s1600-h/image%25255B35%25255D.png"><img alt="image" border="0" src="http://lh6.ggpht.com/-d26swghG5zk/Ut_koBZqDTI/AAAAAAAABaQ/10V1Wf0V_vc/image_thumb%25255B21%25255D.png?imgmax=800" height="280" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: inline; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="image" width="373" /></a><br />
<em>Figure 2 Cathodic disbondment resistance testing at 65°C</em><br />
<a href="http://lh5.ggpht.com/-FX5f8p7YOxg/Ut_kvlpfo1I/AAAAAAAABaY/rGK1T043AaI/s1600-h/image%25255B40%25255D.png"><img alt="image" border="0" src="http://lh3.ggpht.com/-dUl3oDx9WZs/Ut_k2tWhODI/AAAAAAAABag/xYlf9BuHZxU/image_thumb%25255B24%25255D.png?imgmax=800" height="280" style="background-image: none; border-bottom: 0px; border-left: 0px; border-right: 0px; border-top: 0px; display: inline; padding-left: 0px; padding-right: 0px; padding-top: 0px;" title="image" width="373" /></a><br />
<em>Figure 3 Samples of the new hybrid 2LPE coating after flexibility testing</em><br />
<strong>4. Conclusions</strong><br />
A new two layer coating system has been developed to bring together the desirable qualities of mastic-based and copolymer-based systems while minimizing their disadvantages.<br />
The new hybrid two layer coating system meets and exceeds the materials and performance property requirements of AS/NZS 1518:2002, CSAZ245.21, and ISO 21809-4 standards.<br />
The new two layer coating system has better lap shear strength, peel adhesion strength, and impact resistance for temperatures up to 80°C than the current mastic-based 2LPE coating system and similar to that of the copolymer based 3LPE coating system offered in the North American and Australian markets. At both room temperatures and 65°C, the cathodic disbondment resistances of the new hybrid two layer coating system are comparable to the current mastic based 2LPE products. Short-term cathodic disbondment testing at higher temperatures (70°C and 80°C) also show acceptable results. These results demonstrate that the hybrid adhesive allows the achievement of excellent corrosion resistance and adequate shear properties to withstand pipe movement and eliminates any stockpiling and handling problems in high climate temperatures.<br />
<strong><em>References:</em></strong><br />
Guan, S., P. Mayes, et. al. 2007. “Advanced Two Layer Polyethylene Coating Technology for Pipeline Protection”. Sydney, Australia.<br />
<a href="http://www.brederoshaw.com/non_html/techpapers/BrederoShaw_TP_G_07.pdf">http://www.brederoshaw.com/non_html/techpapers/BrederoShaw_TP_G_07.pdf</a>alberthutamahttp://www.blogger.com/profile/14074698506838679058noreply@blogger.com0