Seamless Pipe (English Ver.)

Seamless pipe is formed by hot working steel to form a pipe without a welded seam. Several processes are available, illustrated schematically in figure 1.

The initially formed pipe may be subsequently cold-worked to obtain the required diameter and wall thickness and heat-treated to modify the mechanical properties. A solid bar of steel, termed a billet, is cut from a slab and is heated and formed by rollers around a piercer to produce a length of pipe. The Mannesmann mill is perhaps the best-known type of piercing mill. In this mill, the steel billet is driven between rotating, barrel-shaped rolls set at a slight angle to each other. The rolls rotate at about 100-150 rpm. The billet also rotates. The piercer is placed just beyond the point where the billet is squeezed by the rolls, so that as the formed billet passes through the pinch zone between the two rollers, the reducing stress tend to open the metal over the piercer.

Fig. 1 Seamless pipe-manufacturing processes

The piercing mill produces the primary tube that requires finishing to form the pipe. During finishing, the wall thickness is further reduced. In a plug-rolling mill, the pipe is driven over mandrels fitted with plugs of increasing diameters between rollers that extrude the tube to the required external diameter. Other methods use multiple conical or conventional horizontal rolls or offset rollers. Pipe is finished in a reeling process in which it is driven between slightly conical rollers, followed by passage through a sizing mill that ensures circularity.

An older process is the Pilger process. This process uses eccentric rolls to form the pipe in discrete stages. A mandrel is inserted into the partly formed pipe from the piercing mill. The assembly is driven into the open rolls and, as the rolls rotate back and forth, sequential sections of the pipe are drawn into the eccentric rolls; the outer diameter formed to the required dimension set by the roller eccentricity. This process is also used for production of corrosion-resistant alloy pipe.

After forming, the pipe may be delivered as produced or, more usual for the oil industry, as either normalized or quenched and tempered. These heat treatments homogenize the mechanical properties and further improve strength and toughness. After forming is completed, the pipe is inspected for internal laminations and pressure-tested hydraulically.

This type of pipe is generally available in diameters up to 16 in but can be obtained from a restricted number of suppliers in sizes up to a maximum of 28 in with wall thickness to 2 in. The larger diameter pipe is made by hydraulically expanding smaller diameter pipe. Seamless pipe is the preferred material of several operators for small-diameter pipelines. Its main advantages are its good track record in service and the absence of welds in the pipe sections. However, the larger-diameter, seamless pipe may be more expensive than pipe fabricated by the alternative processes. The disadvantages of seamless pipe are fairly wide variation of wall thickness, typically +15% to -12.5% and out-of-roundness-and-straigtness. The premier pipe fabrication mills can produce seamless pipe to closer tolerances.

The outer surface of the pipe may be highly distorted such that when it is grit-blasted, prior to coating, tiny slivers of steel rise up. These slivers can be a drawback when the pipe is to be coated with a thin anticorrosion coating such as fusion-bounded epoxy (FBE), and it is prudent for the pipeline engineer to check for such effects when prequalifying pipe suppliers.

Source:

• Subsea Pipeline Engineering by Andrew Clennel Palmer, Roger A. King

HDPE Pipe for Offshore Pipeline

Piping made from polyethylene is a cost effective solution for a broad range of piping problems in municipal, industrial, marine, mining, landfill, duct and agricultural applications. It has been tested and proven effective for above ground, sur face, buried, sliplined, floating, and sub-sur face marine applications. 

High-density polyethylene pipe (HDPE) can carry potable water, wastewater, slurries, chemicals, hazardeous wastes, and compressed gases. In fact, polyethylene pipe has a long and distinguished history of service to the gas, oil, mining and other industries. It has the lowest repair frequency per mile of pipe per year compared with all other pressure pipe materials used for urban gas distribution. 

Polyethylene is strong, extremely tough and very durable. Whether you’re looking for long service, trouble-free installation, fle xibility, resistance to chemicals or a myriad of other features, high-density polyethylene pipe will meet all your requirements.

Consider the following features of HDPE pipe:

• Flexible HDPE pipeline is very suitable for soils with poor bearing capacity. 
• Favorable HDPE rheology properties (strainability and stress relaxation property) are very welcome in marine conditions and poor soil settings. 
• Unlike metal and composite material pipes, homogeneity of the pipe wall structure enables long-life in marine applications, with no corrosion and/or material deterioration problems. 
• Minor pipe damages (scratches) that can be expected to occur in installation phase are normally of no importance for the operational quality of the product. 
• HDPE has excellent abrasion resistance properties. 
• Hydraulically, long HDPE pipe strings represent the smoothest possible solution, both in terms of the pipe wall roughness and pipeline bore hydraulic properties. 
• Simplicity of HDPE pipe bedding design and trench backfill solution. 
• Proven high resistance of HDPE against seismic impacts. 

Source:

• https://plasticpipe.org/pdf/high_density_polyethylene_pipe_systems.pdf
• https://bib.irb.hr/datoteka/242879.final_paper_ravlic_et_al.pdf

Above Water Tie In (English Ver.)

Above Water Tie-in (AWTI) is an operation where two laid down pipelines on the seabed are welded together after being lifted above water using vessel davits. For AWTI we determine/provide:

• Steps for recovering the pipelines
• Welded Configuration for recovered pipes
• Steps for lowering the completed pipeline
• Weld excavation analysis
• Minimum weld thickness assessment for removal of the welding clamp
• Offshore Procedures to be followed during execution

Static Code checks (pipeline integrity) are performed for every static loadcase. Dynamic Analysis is performed for the respective worst case in Pipe Recovery, Welded configuration and Laydown. DNV buckle checks are used to ascertain pipe integrity during dynamics.

Source: https://vladvamphire.files.wordpress.com/2009/06/11.jpg

Source:

• http://www.oesl.nl/expertise/pipelay

Horizontal and Vertical Tree (English Ver.)

Vertical and horizontal trees are built and installed with proven technology based on extensive subsea experience and years of testing under some of the most demanding conditions. The trees provide reliable operations in all environments, including shallow water, deep water, and ultra-deep water. They have the flexibility and durability to meet specific job requirements with minimal customization. Monitoring and feedback capabilities reduce operator risk and provide data and communication for operations management. 

Innovative subsea tree technology providing benefits from both conventional vertical and horizontal subsea trees with greater flexibility at a lower overall cost. The system is designed so that the tubing hanger and tree installation are totally independent. 

Horizontal Subsea Tree

Establishing an industry standard through the development of the SpoolTree^TMhorizontal subsea tree, with systems available for 10,000-psi shallow-water environments and 10,000-psi and 15,000-psi deepwater environments.

Vertical Monobore Subsea Tree

Production valves are located vertically above the tubing hanger in the main valve body.

Vertical Dual-Bore Subsea Tree

Offering a wide range of configurations, from conventional shallow-water trees to deepwater monobore riser versions.

All-Electric System

Pioneering the development of electric subsea technology by creating the first electric subsea production system, which has been operating in the North Sea since 2008.

High-Pressure, High-Temperature Systems

Including 10,000- and 15,000-psi systems rated up to 350 degF [177 degC], with horizontal and vertical monobore tree configurations.

Retrievable Process Module

Allowing interchangeability of modules across subsea tree types through a standard interface.

Source: http://opstatic.com/img/usermedia/TU0DgTRgXEmcXLSQH91f_w/original.png

Source:

• https://www.onesubsea.com/products_and_services/production_systems/subsea_trees.aspx

Flexible Riser (English Ver.)

Flexible Risers are composed of multiple spiral laid materials as shown in Figure 4, the flexible riser demonstrates excellent bending capacity while still possessing exceptional strength, making it extremely versatile with regards to application. Originally designed for flowline applications between vessels, the flexible riser has gained popularity in deep water due to its ability to withstand significant dynamic environments making it an excellent choice for harsh sea conditions.

Source: https://hub.globalccsinstitute.com/sites/default/files/publications/24452/advanced/fig-020.jpg

Installation methods are also a positive aspect of flexible flowlines in that normal installation campaigns can typically be completed much more quickly than other risers due to the high spooling capacity and offload speeds that can average up to 500 meters per hour. The ability to be wet stored (material choice permitting) prior to installation also proves a benefit of the flexible pipe in that it allows for schedule flexibility during an offshore installation campaign.

Throughout the design phase of flexible pipe, careful consideration must be made with regards to the hydrostatic pressure that will be observed at full depth. As depth increases, the pressure differential becomes greater and supporting layers, such as the pressure sheath and armor layers, must be designed with a thickness that is capable of withstanding the associated forces of deep water. If one of these supporting layers were to not be adequately designed to withstand these forces, the pipe would be crushed as it was lowered to the sea floor. Sufficient designs, however,  have proven the flexible riser to be applicable to depths of 10,000 feet and operating pressures of 10,000 psi at 300oF.

A design characteristic that may deter the use of flexible pipe in some applications is the need for bend stiffeners or Bell mouths. Utilized to ensure that the stress throughout the joint is kept at a minimum, these stiffening methods should always be considered during the design process though topside space requirements may cause complications. A method of venting the annular space of the pipe layers should also be implemented to ensure any gas migration through the pressure sheath can be vented at the topside.

Source: http://subseaworldnews.com/wp-content/uploads/2012/08/4Subsea-to-Monitor-Statoils-Flexible-Risers-Norway.jpg

Source:

• http://www.gateinc.com/gatekeeper/gat2004-gkp-2015-02

Flexible Pipe (English Ver.)

Flexible pipe is characterized by a composite construction of layers of different materials, which allows large amplitude deflections without adverse effects on the pipe. This product may be delivered in one continuous length or joined together with connectors.

Assembly of a pipe body and end fittings where the pipe body is composed of a composite of layered materials that form a pressure-containing conduit and the pipe structure allows large deflections without a significant increase in bending stresses. NOTE Normally the pipe body is built up as a composite structure composed of metallic and polymer layers. The term “pipe” is used in this document as a generic term for flexible pipe.

Source: https://www.youtube.com/watch?v=6cGlWeNkkME

Sources:

• API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011
• API SPEC 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008

Deepwater Pipeline (English Ver.)

Conventional pipeline design, although concerned with many factors, is dominated generally by the need to withstand an internal pressure. The higher the pressure that products can be passed down the line, the higher the flow rate and greater the revenue potential. However, factors critical for deepwater pipelines become dominated by the need to resist external pressure, particularly during installation.

Local infield lines, such as subsea umbilicals, risers, and flowlines (SURF) usually are modest challenges as they are small in diameter and inherently resistant to hydrostatic collapse. In smaller sizes, these lines generally are produced as seamless pipe which is readily available and generally economical.

However, deepwater trunklines and long-distance tiebacks present a greater challenge. To increase subsea production these lines tend to be larger in diameter with a thicker pipe wall to withstand the hydrostatic pressure and bending as it is laid to the seabed.

Typically these lines are often 16 in. to 20 in. (40 cm to 50 cm) in diameter, which presents a further complication as the pipe sizes lie at the top end of economical production for seamless (Pilger) pipes. The Pilger process can produce the thick walled pipe required for these developments but often the manufacturing process is slow, the cost of material high, and the pipe lengths short. As a result, the most economical method to manufacture these lines is the UOE process. The increasingly stringent industry demands have driven this design toward its practical limits of manufacture and installation.

Corus Tubes has responded by manufacturing UOE double submerged arc welded (DSAW) linepipe to the deepest pipelines in the world. This pipe overcomes significant challenges associated with deepwater developments and facilitated a number of pioneering projects such as Bluestream and Perdido.

In the UOE process, steel plate is pressed into a “U” and then into an “O” shape and then is expanded circumferentially. Wall thickness and diameter requirements for deepwater trunkline pipe continue to be challenging for manufacturing economics and installation capabilities.

While few producers manufacture UOE pipes at 16- to 20-in. outside diameter, this manufacturing method is quicker to market and more cost-effective than seamless alternatives. Corus Tubes’ process seeks to optimize the design of the material and minimize the wall thickness to:

• Reduce material cost
• Reduce welding cost
• Reduce installation time
• Reduce pipe weight for logistics and submerged pipe weight considerations
• Increase design scope enabling a wider range of deepwater developments.

Det Norske Veritas (DNV) says the acceptability of a pipeline design for a given water depth is determined by means of standard equations that measure the relationship between OD, wall thickness, pipe shape, and material compressive strength.

Pipe shape

Finished pipe shape is optimized by balancing the manufacturing parameters, pipe compression, and expansion. The crimp, U-press, and O-press combination ensures that the pipe size is controlled, often beyond most offshore specifications. Enhanced pipe “roundness”, wall thickness, and diameter tolerance removes uncertainty in the design and production stages and allows pipe wall thickness optimization.

Compressive strength

Pipe manufactured by the UOE process undergoes various strain cycles, both tensile and compressive. The combination of these cycles affects the overall behavior of the material in compression. This is indicated in the equation given in the offshore design standard DNV OS F101 by the presence of the Fabrication Factor αfab. For standard UOE processes, the term represents a de-rating of 15% in the compressive strength as a result of the material response to the strain cycles during forming, known as the Bauschinger Effect.

When material is first placed in tension such that it is deformed plastically, the yield stress in compression is reduced. This originally was reported by Bauschinger in 1881. It is relevant to pipe making because during the forming process the material is placed in tension during expansion. Following this, the material is dispatched for installation, where the pipe sees compressive stress from the pressure of the seawater. Conventionally, the 15% reduction in compressive strength compensates for the Bauschinger Effect.

Since the early 1990s, Corus Tubes has observed that the results it obtained from the forming process often yielded higher compressive strengths than those obtained from the standard equations. Research and process development leads to a greater understanding of the metallurgical transformations during pipe forming. It is possible to reverse the Bauschinger Effect to deliver pipe with compressive strengths higher than conventionally expected.

Three things influence the final pipe mechanical properties in compression:

1. Choice of plate feedstock. The strength of the final pipe is a function of the chemistry and grain structure of the mother plate from which it is fabricated. All aspects of plate manufacture, the chemistry, rolling schedule as well as cooling rates ensure that the final plate properties change to give the required pipe characteristics.
2. Choice of mill compression and expansion parameters. By optimizing the various compression and expansion cycles, a set of manufacturing conditions can be determined to enhance collapse performance to potentially reduce pipe wall thickness in future deepwater applications.
3. Controlled low temperature heat treatment. With the correct plate chemistry it is possible to deliver a lift in compression strength through the application of a low temperature heat treatment. This final part of the process can be measured and assured only if the correct attention has been paid to the previous manufacturing stages.

A number of groundbreaking projects have pushed the boundaries of deepwater exploration and production, and enhanced understanding of pipeline capabilities and limits. In 2000, ExxonMobil used 64 km (40 mi) of line pipe for the Hoover/Diana project which reached depths of 1,450 m (4,800 ft). This also was the first time that small diameter pipe from Corus Tubes’ UOE mill in Hartlepool, UK, was supplied to the deepwater Gulf of Mexico market.

In 2001, Corus Tubes supplied 94 km (45,000 metric tons [49,604 tons]) of three-layer polypropylene coated, high grade, sour service linepipe and bends for the technically challenging Bluestream project which supplies gas from Russia to Turkey under the Black Sea. Corus also was selected to provide pipe for the deepest section of the pipeline at 2,150 m (7,054 ft) water depth.

Corus Tubes recently supplied line pipe to the Perdido Norte project in the Gulf of Mexico. Williams commissioned the production of small diameter UOE pipe and approximately 312 km (194 mi) of uncoated steel line pipe for ultra deepwater depths from 3,500-8,300 ft (1,067-2,530 m) with a rugged seabed terrain. The pipe, manufactured to withstand a service rating equivalent to ANSI 1500, is one of the deepest pipelines in the world.

One section of the pipeline transfers hydrocarbons from the FPS host in Alaminos Canyon block 857 and terminates in East Breaks block 994 (78 mi [126 km]). The gas pipeline terminates at Williams Seahawk pipeline in East Breaks block 599 (106 mi [171 km]). The 18-in. (46-cm) diameter pipe was manufactured in wall thicknesses ranging from 19.1 mm to 27.0 mm (¾ in. to 1 in.).

Further to the experiences on Perdido, Corus has produced a thicker pipe at 18-in. diameter for the Petrobras Tupi project. The pipe has a wall thickness of 31.75 mm (1 ¼ in.) and lies in a water depth of 2,200 m (7,218 ft) offshore Brazil. While this project is not the deepest, it represents a milestone in pipe forming. This is the thickest UOE pipe ever manufactured at 18-in. diameter (note as the diameter of a pipe reduces and thickness increases, the levels of strain and power required to forming it increases).

Tupi is a testimony to the complexity of deepwater pipe design. While collapse at these water depths is a critical design state, there also were concerns about corrosion, since the Tupi production has some small amounts of contaminants in the exportation gas (about 5% CO2 and a very small amount of H2S). Even though the exported gas should be dehydrated, the CO2 raises concerns about pipe corrosion and is managed by increasing the nominal wall thickness to account for loss of material during life. At the end of the pipe life it still must withstand the pressure at the seabed even with a reduced wall thickness.

The H2S, although not expected in the exported gas, could cause cracking to occur in steels where the grain structure and cleanliness is not optimized. In addition, high levels of forming strain can exacerbate the situation. Corus Tubes applied its knowledge of steel production and pipe forming to ensure that the plate it procured from Dillinger Hutte and Voest Alpine provided ultimate resistance to H2S corrosion.

Pipelines in deepwater require the tightest dimensional tolerances to maximize resistance to collapse and to maximize girth weld fatigue resistance. Furthermore, pipelines from 16-in. to 28-in. (71-cm) are seen as the future for deepwater export pipeline systems.

Source:

• http://www.offshore-mag.com/articles/print/volume-69/issue-7/flowlines-__pipelines/deepwater-pipelines.html

Pipeline Corrosion (English Ver.)

Unprotected pipelines, whether buried in the ground, exposed to the atmosphere, or submerged in water, are susceptible to corrosion. Without proper maintenance, every pipeline system will eventually deteriorate. Corrosion can weaken the structural integrity of a pipeline and make it an unsafe vehicle for transporting potentially hazardous materials. However, technology exists to extend pipeline structural life indefinitely if applied correctly and maintained consistently.

How Do We Control Pipeline Corrosion? 

Four common methods used to control corrosion on pipelines are protective coatings and linings, cathodic protection, materials selection, and inhibitors. 

Coatings and linings are principal tools for defending against corrosion. They are often applied in conjunction with cathodic protection systems to provide the most cost-effective protection for pipelines.

• Cathodic protection (CP) is a technology that uses direct electrical current to counteract the normal external corrosion of a metal pipeline. CP is used where all or part of a pipeline is buried underground or submerged in water. On new pipelines, CP can help prevent corrosion from starting; on existing pipelines; CP can help stop existing corrosion from getting worse.
• Materials selection refers to the selection and use of corrosion-resistant materials such as stainless steels, plastics, and special alloys to enhance the life span of a structure such as a pipeline. Materials selection personnel must consider the desired life span of the structure as well as the environment in which the structure will exist. Corrosion inhibitors are substances that, when added to a particular environment, decrease the rate of attack of that environment on a material such as metal or steel reinforced concrete.
• Corrosion inhibitors can extend the life of pipelines, prevent system shutdowns and failures, and avoid product contamination. 

Evaluating the environment in which a pipeline is or will be located is very important to corrosion control, no matter which method or combination of methods is used. Modifying the environment immediately surrounding a pipeline, such as reducing moisture or improving drainage, can be a simple and effective way to reduce the potential for corrosion.

Furthermore, using persons trained in corrosion control is crucial to the success of any corrosion mitigation program. When pipeline operators assess risk, corrosion control must be an integral part of their evaluation.

What Is the Solution? 

Corrosion control is an ongoing, dynamic process. The keys to effective corrosion control of pipelines are quality design and installation of equipment, use of proper technologies, and ongoing maintenance and monitoring by trained professionals. An effective maintenance and monitoring program can be an operator’s best insurance against preventable corrosion-related problems. 

Effective corrosion control can extend the useful life of all pipelines. The increased risk of pipeline failure far outweighs the costs associated with installing, monitoring, and maintaining corrosion control systems. Preventing pipelines from deteriorating and failing will save money, preserve the environment, and protect public safety

Source:

• https://www.nace.org/uploadedFiles/Corrosion_Central/Pipeline%20Corrosion.pdf

Pipeline Goose Neck (English Ver.)

A gooseneck (or goose neck) is a 180° pipe fitting at the top of a vertical pipe that prevents entry of water. Common implementations of goosenecks are ventilator piping or ducting for bathroom and kitchen exhaust fans, ship holds, landfill methane vent pipes, or any other piping implementation exposed to the weather where water ingress would be undesired. It is so named because the word comes from the similarity of the pipe fitting to the bend in a goose's neck.^[1]

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

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

Source: http://www.winteb.com/uploads/File/Fitting%20instructions.jpg

Source:

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

Pipeline Commissioning (English Ver.)

The Pipeline commissioning means introducing crude/ product/Gas in the pipeline from originating station, filling the entire length and then start delivering to receipt system.

What we need prior to commissioning?

• The pipeline and associated facilities are completed in all respect
• All Fire and Safety equipments / facilities are tested and commissioned
• Availability of dedicated communication
• Statutory Clearances obtained 
• Availability of Product (HSD)/ Crude oil – Not less than line-fill 
• Required Manpower is placed at all locations 
• Availability of water and its disposal plan 
• Availability of a dedicated commissioning team

Critical issues in commissioning a Petroleum Pipeline:

• Movement of hydrocarbon in empty pipeline can generate static current.
• Hydrocarbon Vapor mixed with oxygen may lead to explosion. 
• There may be formation of Air / Vapor pocket that may get compressed leading to rise in pressure. 
• Air / vapor pocket may explode in receiving tank leading to damage of the tank roof seal. 
• Leakage of any hydrocarbon may lead to fire or damage to environment 

Source:

• http://petrofed.winwinhosting.net/upload/15-18June11/13.pdf

Pipeline Decommissioning (English Ver.)

Pipeline decommissioning, or pipeline abandonment programmes are extensively used for pipelines, especially in the oil and gas industries.

Pipelines or power cables may be decommissioned in place if they do not interfere with navigation or commercial fishing operations or pose an environmental hazard. However, if the BOEMRE rules that it is a hazard during the technical and environmental review during the permitting process, it must be removed. The first step to pipeline decommissioning in place requires a flushing it with water followed by disconnecting it from the platform and filling it with seawater. The open end is plugged an buried 3 ft below the seafloor and covered with concrete.

Within the industry, the North Sea and Gulf of Mexico are likely to experience a great deal of pipeline decommissioning and abandonment within the next 30 years. The North Sea Offshore Decommissioning work will see 470 pipelines wholly or partially removed. New legislation within the Gulf of Mexico has also forced the industry to put in place decommissioning programmes.

To ensure proper site clearance, operators need to follow a four-step site clearance procedure.

1. Pre-decommissioning survey maps the location and quantity of debris, pipelines, power cables, and natural marine environments.
2. Post decommissioning survey identifies debris left behind during the removal process and notes any environmental damage
3. ROVs and divers target are deployed to further identify and remove any debris that could interfere with other uses of the area.
4. Test trawling verifies that the area is free of any potential obstructions.

Sources:

• http://www.inpipeproducts.com/pipeline-decommissioning/
• http://www.rigzone.com/training/insight.asp?i_id=354

Pipeline Construction (English Ver.)

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

Pre-Construction

Surveying and staking

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

Preparing the right-of-way

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

Digging the trench

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

Stringing the pipe

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

Construction

Bending and joining the pipe

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

Coating the pipeline

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

Positioning the pipeline

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

Installing valves and fittings

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

Backfilling the trench

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

Post Construction

Pressure Testing

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

Final clean-up

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

Source:

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

Pipeline Corrosion Resistant Alloy Material (English Ver.)

As the world-wide search is turning to deeper reservoirs an increasing number of situations are being encountered where corrosive production environments are present. In many of these cases often significant amounts of hydrogen sulphide, carbon dioxide and brine are present with oil and gas production. These crudes show, therefore a high corrosivity with respect to general corrosion and stress corrosion cracking by sulphides ( SSCC ), by chloride ( CSCC) or their combined action. 

In addition, other factors such high pressures and temperatures can complicate the material selection process. In fact, the mechanical requirements for material used for production equipment increase with well depth because of the greater hangoff loads and pressure; while the elevated temperatures have detrimental influence on mechanical properties. Under these circumstances CRA materials may offer a valid alternative to conventional methods of corrosion control. Based on that the use of corrosion-resistant alloy in oil field has substantially increased during the last years. 

With the term CRA is intended a metal that achieves a high corrosion resistance by means of alloying. A variety of CRA materials are now available for tubing. Table 1 shows some of the commonly use for oil and gas production application. Depending on the environment the CRA choice could range from AISI 420 ( 13% Chrome) for CO2 service to titanium alloys for very severe applications. The first topic of discussion will be manufacturing process, with some discussion on how the different processes can influence the final product performances. 

For manufacturing the CRA alloys there are essentially two processes. Group 1 comprises martensitic and martensicferritic stainless steel, they are manufactured in a manner similar to carbon steel. The alloy is melted in an electric furnace then it is cast into ingots. The ingot is forged to form a billet that is heated to a suitable forging temperature, pierced and hot rolled to form a pipe. In order to achieve the mechanical properties, the pipe then is quenched and tempered.

Groups 2, 3 and 4 alloys, such as duplex stainless steel and austenitic-nickel-base alloys, are fabricated in different manner. After melting the material can mold to form an ingot or it can be continuously cast. The ingot is then forged into billets that are extruded by the back-extrusion press. In the majority of cases these grades are required in relatively high strengths which require the alloys to be cold worked. This cold work is performed on either cold draw benches or in a cold pilger mill. Several passes on the draw bench may be necessary to achieve the correct strength while in general only a sizing pass and the finishing pass are requested on the pilger mill. 

The extrusion process, particularly when associated with cold working, is costly and time-consuming tube-making process. Table 2 reassumes the various manufacturing process. 

The problem of material selection may involve several factors like the high strength requirements combined with high corrosion resistance of the material. 

A chemical analyses of the produced fluids is generally required for evaluation of the corrosive components as hydrogen sulphide, carbon dioxide and chlorides. Other components like scaling potential, water production, temperature profile, pressure profile and stresses on the tubulars have also to be considered. If no water is present there will be no corrosion and the material selection is simple. However, no well can be designed on the basis that it will always be dry and therefore the material selection shall take into account the water production and the material must be selected accordingly. 

The proportion of H2S and CO2 present in the water are also important ; generally it is ignored but should be taken into account where the well conditions are severe for a particular alloy and to make a conservative design decision would involve the selection of a much more expensive tubular. 

Other points to be considered are the potential for scale and the presence of asphaltene associated with production. Scale will provide a barrier between the tubulars and the aggressive fluids reducing therefore the velocity of corrosion process, but pitting and crevice can occur beneath the scale and damage the tubular in its integrity. For our scope we assume that water and chloride are always present therefore a number of different scenarios can be discussed. 

Experience has shown that manufacturing process qualification achieved by means of a pre-production has been necessary for particular material/ process to provide evidence of the performance characteristics of the product and the adequacy of the manufacturer to produce tubular that meet the user’s performance guidelines. Qualification of a size and grade doesn’t mean the process is automatically qualified for all the sizes. 

Pre-production discussion and a continuing dialogue with manufacturers are generally necessary to reach a satisfactory quality level. Inspectors should be used to assure manufacturers compliance to the technical specification during extrusion, microstucure evaluation, mechanical and NDE testing. 

Some operational experience on CRA’s suggest to prepare proper storing and handling procedures to minimise the galling during make/break of the connection. 

Acidizing is another operation that can cause problems. Generally Group 1 and 2 can suffer severe corrosion attack from mud acid even in presence of inhibitors. Extensive laboratories tests have demonstrated that superaustenitic stainless steel is much more resistant than duplex steel during stimulation. To reduce the risk it is important to select the appropriate inhibitor package. 

Source:

• http://www.gruppofrattura.it/ocs/index.php/cigf/igf14/paper/viewFile/564/11238

Risk Based Inspection for Offshore Pipeline (English Ver.)

In the pipeline industry much effort has been taken to ensure safety. Therefore, in-depth research has been carried out with respect to allowable failure probabilities. Since also the consequences of failure play a more important role, risk based approaches are becoming more common. They can be used during design as well as during operation. The focus is here on the operational phase regarding risk based inspection. 

The implementation of a risk based inspection (RBI) procedure starts with the determination of the relevant failure modes that should be regarded (Figure 1). 

After identification of the relevant failure modes, the corresponding probability and consequence have to be estimated. The probability of failure can be estimated by using different methods, such as: 

• Qualitative methods
• Semi-quantitative methods
• Quantitative methods

Qualitative methods are based on few essential data and lead to a rough estimation of the failure probability. Semi-quantitative methods use more information and some calculations are carried out, which results into a more accurate failure probability. The quantitative methods consider fully probabilistic approaches and lead to an accurate determination of the existing failure probability. However, in engineering praxis the data required for the fully quantitative approach is typically not available. 

Therefore, in the following the semi-quantitative approach is used. This approach gives a more detailed failure probability than the pure qualitative approach and is normally applicable. Details of the complete risk assessment, i.e. by also taking into account the consequences, are given below. 

As the risk is not constant along the pipeline route, a segmentation of the pipeline is carried out. After estimating the risk related to each segment, an appropriate inspection strategy has to be developed. The inspection effort and interval should be determined taking into account the current and the future risk of the segment regarded.

The combination of remaining life time and index procedure is able to cover all relevant failure modes. When only using the remaining life time approach threats like impact damage, which is the reason for 30% of all pipeline damages, are not covered. The proposed procedure fits well within the framework suggested in current codes like DNV RP F116 [4] and has been successfully applied to different offshore pipelines.

Source:

• http://www.pm-pipeliner.safan.com/mag/pploctdec13/t30.pdf

Pipeline Welding Technology (English Ver.)

When one looks on a huge oil and gas installation like a refinery spread across many acres and representing millions of dollars on equipment and infrastructure investment, one does not see the raw crude oil injected into the refinery for the refining process. This is because the crude oil is transported through an underground pipeline. The pump station which pumps oil into the pipeline is also located far away from the refinery.

But the underground pipeline and the aboveground refinery are there for one purpose. That is to provide refined oil and other products to the public. The pipeline is for transporting the crude oil and the refinery is for refining this crude oil.

It is interesting to know that the welding techniques for these complementary structures are entirely opposite to each other. Downhill welding techniques are used for welding pipeline whereas uphill welding is used for welding refinery piping systems. Even the welding codes and inspection methods are different. The pipeline welding is controlled by API 1104 whereas refinery piping work is controlled by ASME Sec IX.

Weld Joint

The pipe thickness used on pipeline is usually less than that used in refinery piping and the pipe ends of a pipeline are machine beveled whereas pipe ends of a refinery piping joint are manually cut and beveled. These two factors play a major role in determining the opposite welding techniques.

Since the pipe end of a pipeline pipe is factory machined and smooth, it is easy to use an internal clamp to adjust both ends of a pipeline joint keeping uniform root gap without tacks, thus downhill welding technique (Figure 1) is a better choice for speedy welding. In contrast, in the case of refinery piping, not only is the pipe thickness greater but also the handmade bevels are not so smooth. Tack welds are also used instead of clamps and the root gap is not as uniform as in the case of the pipeline joint. Therefore the uphill welding technique (Figure 2) is a better choice.

One more reason is the size of root gap between pipeline and piping weld joints. Root gap for pipeline joint is 1.6 mm (Figure 3) as compared to 3 mm in piping weld joint (Figure 4). A joint with a smaller root gap can be easily welded with downhill technique, fusing both the root faces, whereas in bigger root gaps you need a weaving motion of the electrode to fuse both root faces.

Use Of Clamps

Cross-country pipelines which are spread for miles are welded on the right-of-way. In contrast, plant piping joints are prepared and welded in a workshop. Weld joint preparation are done keeping this factor.

An internal clamp (Figure 5) is used inside the pipeline joint for speedy alignment and can be removed from the second end of the pipe once the root and hot passes are complete. Whereas, due to short and bent lengths of piping joints having fittings, the weld joints are prepared with or without using external clamps.

Another difference is the use of tacks. On pipeline joints, no tacks are used as the root and hot passes are completed immediately when the internal clamp is in place whereas in the case of plant piping, weld tacks are used to prepare weld joints for weld at a later stage.

Welding Technique

As explained earlier as to why pipelines are welded by using the downhill technique and piping with an uphill technique, in the downhill technique two welders weld one joint simultaneously from the top to bottom of the pipe on opposite sides whereas in a piping joint job, one welder completes the whole joint welding from bottom to top of a piping joint.

Electrode Coating

For downhill welding, all electrodes used are of cellulose coating whereas for uphill welding the electrode used for the root pass is of cellulose coating and the rest are accomplished with low hydrogen-coated electrodes. The reasons for this are 1) The pipeline wall thickness, which is usually less than 12.5 mm; 2) easy removal of slag; 3) welding speed, and 4) a thin bead of a cellulose electrode. All of these are the requirements of pipeline welding whereas in plant piping the pipe thickness is greater, therefore a weaving motion of an electrode is required to weld heavy thickness piping joints. For this purpose low-hydrogen electrodes are used.

Welding Speed

The last – but not least – big difference between pipeline and plant piping welding is the welding production speed. Here are some of the reasons for this difference in welding speed:

1. Piping joints are adjusted and tacked in a workshop and usually one welder completes the whole joint, welding root, filling and cap passes. Whereas on a cross-country pipeline, the joint is adjusted with an internal clamp on the site and welding is performed by a team of mostly two root pass welders, two hot pass welders, two filling pass welders and two capping pass welders. Both welders perform welding on opposite side of a pipeline joint and the welding crew moves in a caravan in open air. As a result, welding production speed is much more than piping joints welded in a workshop.
2. Downhill welding technique gives good welding production on a pipeline where pipe thickness is mostly 12 mm or less, whereas piping joints are of greater thickness and the uphill welding technique requires more time; thus, the welding production is less as compared to the pipeline.
3. Another reason for faster welding speeds on pipelines is the electrode movement from top to bottom and with no weaving motion. Whereas the electrode moves from bottom to top on a piping joint and the weaving of the electrode slows the welding speed

Source:

• http://pgjonline.com/2012/01/30/contrasting-welding-techniques-used-on-pipelines-and-refinery-piping-uphill-versus-downhill/