Deepwater pipelines – Taking the challenge to new depths

Theme : Deepwater pipeline

Deepwater pipeline challenges

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.

Distribution curve depicting ovality of Perdido pipe (457 mm x 20.62 mm thick).

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.

This diagram represents the relationship between stress and strain when a material is placed in tension (top right quadrant) and then into compression (bottom left quadrant). When material is first placed in tension, such that it is deformed plastically, the yield stress in compression is reduced (compare this with the projected compressive strength in the bottom left quadrant had the pre-tension not been applied).

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.

By : Martin Connelly

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

Pipeline Flanges

Theme : Pipeline mechanical connector/flange

                                    

Image Credit: George Fisher Piping Systems, Sandvik Materials Technology, British Metrics

Pipe flanges are protruding rims, edges, ribs, or collars used to make a connection between two pipes or between a pipe and any type of fitting or equipment component. Pipe flanges are used for dismantling piping systems, temporary or mobile installations, transitions between dissimilar materials, and connections in environments not conducive to solvent cementing.

Flanges are relatively simple mechanical connectors that have been used successfully for high-pressure piping applications. They are well understood, reliable, cost-effective, and readily available from a wide range of suppliers. In addition, the moment-carrying capacity of flanges is significant compared to other mechanical connectors. This is an important feature for systems that experience pipe-walking or lateral buckling from temperature and pressure variations (e.g. deep water lines). Flanges can be designed to meet a wide range of application requirements such as high-temperature and corrosion resistance.

How do Pipe Flanges Work?

Pipe flanges have flush or flat surfaces that are perpendicular to the pipe to which they attach. Two of these surfaces are mechanically joined via bolts, collars, adhesives or welds.

This video depicts the layout of a flange connection using bolts.

Typically, flanges are attached to pipes via welding, brazing, or threading.

• Welding joins materials by melting the workpieces and adding a filler material. For strong, high pressure connections of similar materials, welding tends to be the most effective method of flange connection. Most pipe flanges are designed to be welded to pipes.
• Brazing is used to join materials by melting a filler metal which solidifies to act as the connector. This method does not melt the workpieces or induce thermal distortion, allowing for tighter tolerances and clean joints. It also can be used to connect very dissimilar materials such as metals and metalized ceramics.
• Threading is applied to flanges and pipes to allow the connections to be screwed together in a manner similar to nuts or bolts.

While the method of attachment can be a distinguishing feature, there are other considerations more important to pipe flange selection. Factors an industrial buyer should consider first are the flange’s physical specifications, type, material, and performance features most suitable for the application.

Physical Specifications

First and foremost, a flange must fit the pipe or equipment for which it is designed. Physical specifications for pipe flanges include dimensions and design shapes.

Flange Dimensions

Physical dimensions should be specified in order to size flanges correctly.

• Outside diameter (OD) is the distance between two opposing edges of a flange’s face. This can a
• Thickness refers to the thickness of the attaching outer rim, and does not include the part of the flange that holds the pipe.
• Bolt circle diameter is the length from the center of a bolt hole to the center of the opposing hole.
• Pipe size is a pipe flange’s corresponding pipe size, generally made according to accepted standards. It is usually specified by two non-dimensional numbers, nominal pipe size (NPS) and schedule (SCH).
• Nominal bore size is the inner diameter of the flange connector. When manufacturing and ordering any type of pipe connector, it is important to match the bore size of the piece with the bore size of the mating pipe.

Flange Faces

Flange faces can be manufactured to a large number of custom shapes based design requirements. Some examples include:

• Flat
• Raised face (RF)
• Ring type joint (RTJ)
• O-ring groove

Types of Pipe Flanges

Pipe flanges can be divided into eight types based on design. These types are blind, lap joint, orifice, reducing, slip-on, socket-weld, threaded, and weld neck.

• Blind flanges are round plates with no center hold used to close the ends of pipes, valves, or equipment. They assist in allowing easy access to a line once it has been sealed. They can also be used for flow pressure testing. Blind flanges are made to fit standard pipes in all sizes at higher pressure ratings than other flange types.

Blind flange. Image Credit: thepipefittings.com

• Lap joint flanges are used on piping fitted with lapped pipe or with lap joint stub ends. They can rotate around the pipe to allow for an easy alignment and assembly of bolt holes even after the welds have been completed. Because of this advantage, lap joint flanges are used in systems requiring frequent disassembly of the flanges and pipe. They are similar to slip-on flanges, but have a curved radius at the bore and face to accommodate a lap joint stub end. The pressure ratings for lap joint flanges are low, but are higher than for slip-on flanges.

Typical lap joint flange. Image Credit: thepipefittings.com

• Slip-on flanges are designed to slide over the end of piping and then be welded in place. They provide easy and low-cost installation and are ideal for lower pressure applications.

Typical slip-on flange. Image Credit: thepipefittings.com

• Socket weld flanges are ideal for small-sized, high-pressure piping. Their fabrication is similar to that of slip-on flanges, but the internal pocket design allows for a smooth bore and better fluid flow. When internally welded, these flanges also have fatigue strength 50% greater than double welded slip-on flanges.

                        

 Photo and diagram for a typical socket weld flange. Image Credit: thepipefittings.com

• Threaded flanges are special types of pipe flange that can be attached to the pipe without welding. They are threaded in the bore to match external threading on a pipe and are tapered to create a seal between the flange and the pipe. Seal welds can also be used along with threaded connections for added reinforcement and sealing. They are best used for small pipes and low pressures, and should be avoided in applications with large loads and high torques.

Typical threaded flange. Image Credit: thepipefittings.com

• Welding neck flanges have a long tapered hub and are used for high pressure applications. The tapered hub transfers stress from the flange to the pipe itself and provides strength reinforcement that counteracts dishing.

Typical welding neck flange. Image Credit: thepipefittings.com

Type	Pressure Capacity	Pipe Sizes	Applications / Advantages
Blind	Very high	All	Closing pipes, flow pressure testing
Lap joint	Low	All	Systems requiring frequent disassembly
Slip-on	Low	All	Low installation cost, simple assembly
Socket weld	High	Small	Smooth bore for better fluid flow
Threaded	Low	Small	Attachment without welding
Welding neck	High	All	High pressures and extreme temperatures

Overview and comparison of pipe flange types by pressure capacity, suitable pipe sizes, and applications or advantages.

Special Flange Designs

Some flange types can be designed to incorporate special functions, such as size reduction or orifice mounting.

• Orifice flanges are used in place of standard flanges to allow an orifice meter to be installed on the flange. Orifice plate carriers are designed into the flanges for fitting meter connections. These meters are used to measure the flow rate through the system at that point.

Typical orifice flange. Image Credit: thepipefittings.com

• Reducing flanges are used in place of standard flanges to allow for a change in pipe size. The flange consists of one specified diameter with a smaller diameter bore size. Except for the bore and hub dimensions, a reducing flange has dimensions of the larger pipe size. Welding neck, slip-on, and threaded flanges can be reducers, and are considered an economical means to make a pipe size transition.

 Various reducing flanges and a typical cross sectional diagram. Image Credit: thepipefittings.com

Materials of Construction

Pipe flanges can be made from a number of different materials depending on the piping material and the requirements of the application. Selection depends on factors such as environmental corrosion, operating temperature, flow pressure, and economy. Some of the most common materials include carbon steel, alloy steel, stainless steel, cast iron, copper, and PVC.

• Carbon steel is steel alloyed primarily with carbon. It has a high hardness and strength which increases with carbon content, but lowers ductility and melting point. For more information on carbon and alloy steels, please visit the Carbon Steels and Alloy Steels area on GlobalSpec.
• Alloy steel is steel alloyed with one or more elements which enhance or change the steel’s properties. Common alloys include manganese, vanadium, nickel, molybdenum, and chromium. Alloy steels are differentiated based on standard grades. For specific information on individual types of alloying elements, please visit the Metals and Alloys section on GlobalSpec.
• Stainless steel is steel alloyed with chromium in amounts above 10%. Chromium enables stainless steel to have a much higher corrosion resistance than carbon steel, which rusts readily from air and moisture exposure. This makes stainless steel better suited for corrosive applications that also require high strength. For more information on stainless steel alloys, please visit the Stainless Steel Alloys area on GlobalSpec.
• Cast iron is iron alloyed with carbon, silicon, and a number of other alloyants. Silicon forces carbon out of the iron, forming a black graphite layer on the exterior of the metal. Cast irons have good fluidity, castability, machinability, and wear resistance but tend to be somewhat brittle with low melting points. For more information on cast irons, please visit the Cast Irons area on GlobalSpec.
• Aluminum is a malleable, ductile, low density metal with medium strength. It has better corrosion resistance than typical carbon and alloy steels. It is most useful in constructing flanges requiring both strength and low weight. For more information on aluminum, please visit theAluminum and Aluminum Alloys area on GlobalSpec.
• Brass is an alloy of copper and zinc, often with additional elements such as lead or tin. It is characterized by good strength, excellent high temperature ductility,reasonable cold ductility, good conductivity, excellent corrosion resistance, and good bearing properties. For more information on brass and other copper alloys, please visit the Copper, Brass, and Bronze Alloys area on GlobalSpec.
• PVC or polyvinyl chloride is a thermoplastic polymer that is inexpensive, durable, and easy to assemble. It is resistant to both chemical and biological corrosion. By adding plasticizers it can be made softer and more flexible.

Performance Features

Performance features are properties of a flange that may be dependent on a number of other factors, but are nonetheless important to consider. These properties include weight, ease of assembly, and durability.

• Weight is the mass or heaviness of a flange. It is dependent on size and material density. Industrial buyers should consider the strength of the pipe or pipe supports when dealing with large or high density flanges to ensure the weight can be properly supported.
• Ease of assembly is a qualitative measure of the efficiency of the assembly and disassembly process. For applications where a flange is used as a temporary attachment or fix, the ease of set up and take down time can be very important.
• Durability is the strength or toughness of a pipe flange under stress or pressure. Durability is dependent on the compatibility of the flange design with the pipe and the material strength. Flanges operating at high pressures require durable seals to operate effectively. Pipe flange products generally have a pressure rating that defines the maximum pressure the flange is designed to hold.

References

A.R.I. Flow Control Accessories – Nominal Pipe Size

Pipe Fittings & Flanges –  Pipe Flanges

Coastal Flange – Pipe Flanges

Source : http://www.globalspec.com/learnmore/flow_control_fluid_transfer/pipe_tubing_hose_fittings_accessories/pipe_flanges

POLYPROPYLENE SYSTEM SCOPES HIGH AS PIPELINE ANTI-CORROSION COATING

Theme : Pipeline thermal insulation/ pipeline corrosion coating

Polypropylene is attracting increasing attention as a highly desirable component in oil and gas pipeline coating systems. Though long-term in ground or underwater experience is limited with such systems, actual completed projects have been in the field since 1986.

The earliest anti-corrosion coatings for buried pipelines were bitumen-type coatings: asphalt mastic and enamel, and coal tar enamel. The asphalt coatings absorb water to a greater degree than the coal tar enamel coating, but both are subject to cracking, leading to contact of water with the pipe, and coating disbandment.

Later, epoxy-based coatings were developed. These provided good adhesion to the steel pipe but suffered from poor impact and abrasion resistance. Initially, low density polyethylene was used as an outer coating to protect the epoxy.

Polyethylene is still considered an excellent outer coating but has high temperature limitations.

POLYPROPYLENE

Both polyethylene and polypropylene coatings offer highly desirable qualities, with polypropylene holding, as noted, an advantage at higher temperatures. But neither alone, at present, is the answer to corrosion control. Both are being applied over an initial layer of fusion bonded epoxy (FBE) coating.

MOBIL PROJECT

The reasons were recently detailed by Richard Norsworthy and J.A. Nunn of Mobil Pipe Line Co. in a paper presented at the American Petroleum Institute’s pipeline division meeting. Mobil is installing some 140 miles (225 km) of what will be the longest polypropylene coated line laid to date.

The corrosion specialists say that Mobil’s efforts to find a coating that will withstand temperatures from 150 to 210 F. (65 to 99 C.) led to the development of the Du-Val coating system. It employs a two-layer coating: a chemically modified polypropylene (CMPP) over FBE.

FBE and the polyolefins have properties that complement each other when used together.

FBE strongly bonds to steel and offers excellent corrosion protection. It allows very little oxygen through the substrate but will absorb small amounts of water. FBE also weathers relatively poorly.

The CMPP, on the other hand, is an excellent water barrier and provides mechanical protection to the FBE during pipe transportation and installation. For instance, special bed preparation in rocky areas wouldn’t be necessary to protect the FBE if the pipe were coated with polypropylene, The use of this outer coating also dramatically cuts down on the anodes needed for corrosion protection.

The epoxy/polyethylene system is now being used on numerous installations, but the maximum operating temperature for these systems is in the region of 60-70 C. (140-160 C.). Norsworthy and Nunn report that the development of tests for the new CMPP system have been a challenge.

Twenty-four hr hot water soaks of up to 212 F. (100 C.) have been used with excellent results. Twenty-four hr cathodic disbondments at 180 to 200 F. (82-93 C. and 3.5 v have shown from 0 to 1 mm radius of disbandment.

A weight test has shown that the temperature of the pipe may reach 230 F. or more (110 C.) before the CMPP fails if the bond is good.

A key challenge, however, was to modify the polypropylene so it would bond to the FBE. The Mobil specialists report that Mobil Pipeline Co., Valspar Inc. (Canada), and DuPont Canada Inc. worked several years to develop the coating process, quality control testing, and inspection procedures. Valspar brought its experience with FBE to the program, while DuPont modified the polypropylene.

Mobil Oil first used this dual coating system on pipelines near its Torrance, Calif., refinery (OGJ, Dec. 31, 1990, p. 118). The lines carry heavy San Joaquin Valley crude that requires heating before it will flow. Operating temperatures of about 85 C. (180 F.) make the lines vulnerable to corrosion.

The current project will replace, as noted, 140 miles of an existing crude oil line carrying heavy crude from Lebec in Kern County, Calif., to Mobil’s Torrance refinery. The existing 8-in. and 10-in. diameter line is being replaced with 16-in. diameter pipe coated with the DuVal polypropylene system.

To date, 110 miles have been installed. The remainder is scheduled to be laid by the end of this year.

This system has also been applied to a 10 mile section of Mobil’s hot oil Oso pipeline offshore Nigeria. It was installed earlier this year.

Mobil’s Norsworthy and Nunn describe the coating process in their API paper. In general, after surface preparation, the pipe is heated with heat induction and spiraled through an FBE spray booth where about 22 mils (550 m) of FBE is applied.

Before the extended gel FBE is gelled (12-15 sec), the 22 mils of CMPP are side extruded or flocked on in powder form. The coating is then quenched with water to remove as much heat as possible.

After quenching, the pipe is visually and electrically inspected for holidays and other damage.

FIELD JOINTING

A two-part epoxy patching compound is used when necessary, but the perfect patch is still being sought, the Mobil corrosion specialists say.

For field jointing, the induction, heated joint is first flocked with 22 mils of FBE, which is followed by 22 mils of CMPP. This process, the Mobil specialists say, gives the field joint the same coating as the main pipe.

Ultraviolet rays will deteriorate the polypropylene and cause the surface to crack and discolor. Some of the pipe has been in storage for over a year with very little damage, Norsworthy and Nunn report. But Mobil pipeline believes that long-term storage could be a problem if the coating is not protected properly. This problem is being studied.

HIMONT

Himont Italia, an operating subsidiary of Himont Inc., the world’s largest producer of polypropylene, has done pioneering work on three-layer polypropylene coating systems.

This system has been used on the projects shown in Table 1. The company has also developed a two-layer system.

Himont says that the polyolefins, in contrast to FBE, bond poorly to steel because of their non-polar nature. Himont has therefore developed a range of polypropylene-based copolymers modified by the addition of polar monomers onto their ” backbones.”

The functional polar groups in this intermediate layer, or bonding resin, trademarked Questron by Himont, are able to bond with the free epoxy within the FBE primer layer, while the non-polar backbone of this intermediate layer can be easily welded to the polypropylene outer coat, or third layer, trademarked Moplen by Himont.

ZEEPIPE

As an example of polypropylene required, a three-layer polypropylene system of 4 mm thickness is applied to the final 6 km onshore section of the Zeepipe North Sea gas line on the approach to the Statoil terminal at Zeebrugge, Belgium. A 40 ft (12.2 m) long joint of the 40-in. (1,031 mm) diameter pipe requires, depending on the polypropylene thickness, some 100-125 kg (220-275 lb) of polypropylene (Fig. 1).

The offshore anti-corrosion coating for Zeepipe is asphalt enamel surrounded by concrete. But had the entire 820 km long pipeline been coated with polypropylene, up to 18 million lb of polymer could have been required. For comparisons sake, this much polypropylene would represent less than 4% of the 500 million lb of polypropylene capacity added at Antwerp this spring by North Sea Petrochemicals, a joint venture of Statoil and Himont.

RISER

The Himont coating system was used to coat a 10-in. diameter, 480 m long gas line riser in the North Sea earlier this year (Table 1). This is believed to be the first time a polypropylene coating has been used to protect a riser,

The thicker than usual coating (Fig. 2) furnishes both mechanical and corrosion protection. G. Pietro Guidetti, who heads up applications and market development of the polypropylene coating system for Himont Italia, says the splash zone is a critical area with a combination of factors that stress the coating system. It is exposed to large amounts of oxygen and sunlight, large temperature changes, and mechanical forces from wave action. He believes this system is more economical than traditional solutions.

Fig. 3 gives the recommended thickness for low density polyethylene and polypropylene as set out by the Ceocor norm. Figs. 4a, 4b, 4c, and 4d compare some of the characteristics of low density polyethylene (LDPE) and Himont’s polypropylene, Moplen.

Himont’s ranking of various coatings in several categories is given in Table 2.

THREE, TWO LAYERS

The Himont three-layer mill coating procedure is basically similar to that described by Mobil. However, as noted, the epoxy primer is followed by the intermediate layer that is applied to a thickness of about 300 m.

The polypropylene outer coat can then be applied with a normal lateral or cross heat extruder. A pressure roller is used to eliminate air bubbles and ensure good contact between the layers.

At an extrusion temperature of 240 C., normal line speeds of 3.6 m/min can be achieved, depending on the pipe diameter.

Himont has developed a two-coat epoxy/polypropylene system. The company says it offers the same high level of performance as a three-layer system but is easier to install and permits a reduced coating thickness (less than 1.5 mm compared with 3 mm for traditional polyethylene systems).

The Himont-recommended field jointing process is similar to that of Mobil’s, employing induction heating and powdered polypropylene.

However, Guidetti says there are systems developed by others for “cold” field jointing at ambient temperature. One involves a three ply with a core of polypropylene within inside and outside layers of butyl rubber adhesive.

This tape is wrapped with overlaps at the weld joint. Then this layer is covered with a shrinkable polypropylene sheet. When this sheet is shrunk by a flame, it and the three-ply tape bond.

ENVIRONMENT

In a presentation last March at the International Conference for Corrosion Prevention of the European Gas Grid, Gunnar Friberg, Norwegian Pipeline A/S, and Peter A. Blome, Blome GmbH & Co. KG, covered the environmental and economical aspects of multilayer coatings.

They compared coal tar, asphalt, FBE, and combinations of FBE/polyethylene, and FBE/polypropylene. They designated the latter two respectively as System 1 (30-70 m of FBIF as the corrosion coating with a top layer of 2-3 mm of polyethylene) and System 2 (250-400 m FBF and 2-4 mm of polypropylene),

They note that traditional asphalt and coal tar coatings require solvent-based primers containing volatiles and polyaromatic hydrocarbons. Such coatings can pose health risks to workers during the application process. They also add hydrocarbons to the atmosphere,

Friberg and Blome find few if any health or environmental risks associated with FBE or the multilayer polyolefin systems.

ECONOMICS

Table 3 shows a cost comparison developed by Friberg and Blome for the various systems. The cost of cathodic protection (i.e., cost of anodes) is strikingly lower for the polyolefin systems when compared to the asphalt and coal tar coatings. They conclude that the use of multilayer coatings reduces costs.

DuPont Canada says based on an expectancy of 30 years of operations that the ratio of the costs of pipeline cathodic protection for the various coating systems is 10 for coal tar, 5 for FBE, and 2.5 for the Du-Vall system.

By : L.R. Aalund

Source : http://www.ogj.com/articles/print/volume-90/issue-50/in-this-issue/pipeline/polypropylene-system-scopes-high-as-pipeline-anti-corrosion-coating.html

Basics for Stress Analysis of Underground Piping using Caesar II

Theme : Stress analysis for buried pipeline/underground pipeline

Underground or buried piping are all piping which runs below grade. In every process industry there will be few lines (Sewer or drainage system, Sanitary and Storm Water lines, Fire water or drinking water lines etc), part of which normally runs underground. However the term buried piping or underground piping, in true sense, appears for pipeline industry as miles of long pipe run carrying fluids will be there.

Analyzing an underground pipe line is quite different from analyzing plant piping. Special problems are involved because of the unique characteristics of a pipeline, code requirements and techniques required in analysis. Elements of analysis include pipe movements, anchorage force, soil friction, lateral soil force and soil pipe interaction.

To appreciate pipe code requirements and visualize problems involved in pipe line stress analysis, it is necessary to first distinguish a pipe line from plant piping. Unique characteristics of a pipe line include:

• High allowable stress: A pipe line has a rather simple shape. It is circular and very often runs several miles before making a turn. Therefore, the stresses calculated are all based on simple static equilibrium formulas which are very reliable. Since stresses produced are predictable, allowable stress used is considerable higher than that used in plant piping.
• High yield strength pipe: To raise the allowable, the first obstacle is yield strength. Although a pipe line operating beyond yield strength may not create structural integrity problems, it may cause undesirable excessive deformation and possibility of strain follow up. Therefore, high test line with a very high yield to ultimate strength ratio is normally used in pipe line construction. Yield strength in some pipe can be as high as 80 percent of ultimate strength. All allowable stresses are based only on yield strength.
• High pressure elongation: Movement of pipe line is normally due to expansion of a very long line at low temperature difference. Pressure elongation, negligible in plant piping, contributes much of the total movement and must be included in the analysis.
• Soil- pipe interaction: The main portion of a pipe line is buried underground. Any pipe movement has to overcome soil force, which can be divided into two categories: Friction force created from sliding and pressure force resulting from pushing. The major task of pipe line analysis is to investigate soil- pipe interaction which has never been a subject in plant piping analysis.

Normally these lines does not have high design temperatures (of the order of 60 to 80 degree centigrade) and only thermal stress checking is sufficient for underground part. Common materials used for underground piping are Carbon Steel, Ductile iron, cast Iron, Stainless Steel and FRP/GRP.

In this article I will try to explain the steps followed while analysing such systems using Caesar II. However this article does not cover the basic theory for analysis.

Inputs Required for Analysis:

Before proceeding for analysis of buried piping using Caesar II collect the following information from related department
1. Isometric drawings or GA drawings of the pipeline from Piping layout Department.
2. Line parameters (Temperature, Pressure, Material, Fluid Density, etc) from process Department.
3. Soil Properties from Civil Department.

Caesar II for Underground Piping Analysis:

The CAESAR II underground pipe modeler is designed to simplify user input of buried pipe data. To achieve this objective the “Modeler” performs the following functions for analyst:

• Allows the direct input of soil properties. The “Modeler” contains the equations for buried pipe stiffnesses that are outlined later in this report. These equations are used to calculate first the stiffnesses on a per length of pipe basis, and then generate the restraints that simulate the discrete buried pipe restraint.
• Breaks down straight and curved lengths of pipe to locate soil restraints. CAESAR II uses a zone concept to break down straight and curved sections. Where transverse bearing is a concern (near bends, tees, and entry/exit points), soil restraints are located in close proximity and where axial load dominates, soil restraints are spaced far apart.
• Allows the direct input of user-defined soil stiffnesses on a per length of pipe basis. Input parameters include axial, transverse, upward, and downward stiffnesses, as well as ultimate loads. Users can specify user-defined stiffnesses separately, or in conjunction with CAESAR II’s automatically generated soil stiffnesses.

Modeling steps followed in Caesar II: 

The modeling of buried piping is very easy if you have all the data at your hand. The following steps are followed for modeling:

• From the isometric model the line in the same way as you follow in case of above ground pipe model i.e, enter line properties in Caesar Spreadsheet, enter lengths by breaking the line into several nodes or select an existing job for converting it into an underground model.
• Analyst can start the Buried Pipe Modeler by selecting an existing job and then choosing Input-Underground from the CAESAR II Main Menu. The Modeler is designed to read a standard CAESAR II input data file that describes the basic layout of the piping system as if it was not buried. From this basic input CAESAR II creates a second input data file that contains the buried pipe model. This second input file typically contains a much larger number of elements and restraints than the first job. The first job that serves as the “pattern” is termed the original job. The second file that contains the element mesh refinement and the buried pipe restraints is termed the buried job. CAESAR II names the buried job by appending a “B” to the name of the original job.
• When the Buried Pipe Modeler is initially started up, the following screen appears:

This spreadsheet is used to enter the buried element descriptions for the job. The buried element description spreadsheet serves several functions:

• Allows analyst to define which part of the piping system is buried.
• Allows analyst to define mesh spacing at specific element ends.
• Allows the input of user-defined soil stiffnesses.

From/ To node:-

Any element of pipe in CAESAR II can be define by two elements first is start point and second is end point. In buried pipe model, before conversion the From/ To nodes remains same as unburied model.

Soil model no. :-
This column is used to define which of the elements in the model are buried. A nonzero entry in this column implies that the associated element is buried. A 1 in this column implies that the analyst wishes to enter user defined stiffnesses, on a per length of pipe basis, at this point in the model. These stiffnesses must follow in column numbers 6 through 13. Any number greater than 1 in the soil model no. column points to a CAESAR II soil restraint model generated using the equations outlined later under Soil Models from analyst entered soil data.

From/ To mesh type:-
A critical part of the modeling of an underground piping system is the proper definition of Zone 1 bearing regions. These regions primarily occur:
• On either side of a change in direction
• For all pipes framing into an intersection
• At points where the pipe enters or leaves the soil
CAESAR II automatically puts a Zone 1 mesh gradient at each side of the pipe framing into an elbow. Note it is the analyst’s responsibility to tell CAESAR II where the other Zone 1 areas are located in the piping system.

User defined stiffness & ultimate load :-
There are 13 columns in the spreadsheet. Column 6 to 13 carry the user defined soil stiffnesses and ultimate loads if analyst defines soil model 1. Analyst has to enter lateral, axial, upward, downward stiffnesses & loads.

Procedure :-

1. Select the original job and enter the buried pipe modeler. The original job must already exist, and will serve as the basis for the new buried pipe model. The original model should only contain the basic geometry of the piping system to be buried. The modeler will remove any existing restraints (in the buried portion). Add any underground restraints to the buried model. Rename the buried job if CAESAR II default name is not appropriate.
2. Enter the soil data using Soil Models.
3. Describe the sections of the piping system that are buried, and define any required fine mesh areas using the buried element data spreadsheet.
4. Convert the original model into the buried model by the activation of option Convert Input. This step produces a detailed description of the conversion.
5. Exit the Buried Pipe Modeler and return to the CAESAR II Main Menu. From here the analyst may perform the analysis of the buried pipe job.

Source : http://www.whatispiping.com/underground-piping

How Does Offshore Pipeline Installation Work?

Theme : Pipeline Installation method in shallow water/deep water/shore crossing

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.

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.

Tow-In Pipeline Installation

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.

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.

Surface Tow Pipeline InstallationSource: www.pipelife.no

There are four main forms of tow-in pipeline installation. The first, thesurface tow 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.

Using less buoyancy modules than the surface tow, the mid-depth tow 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.

Off-bottom tow 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.

Lastly, the bottom tow 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.

S-Lay Pipeline Installation

When performing S-lay 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.

S-Lay Pipeline InstallationSource: www.pbjv.com.my

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.

Pipe being lowered into the water via a stinger for S-lay installationSource: www.nord-stream.com

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.

J-Lay Pipeline Installation

Overcoming some of the obstacles of S-lay installation, J-lay 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.

J-Lay Pipeline InstallationSource: www.technip.com

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.

J-Lay Pipelay Vessel S7000Source: www.hydro.com

Types Of Pipelay Vessels

There are three main types of pipelay vessels. There are J-lay and S-lay barges 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.

On the other hand, reel barges 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.

Vertical Reel BargeSource: www.jee.co.uk

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.

Source : https://www.rigzone.com/training/insight.asp?i_id=311

Free Span Fatigue Analysis

Theme : Free Span Fatigue Analysis

Construction of unburied pipeline is the most common method in offshore pipeline system. Unburied pipeline should be designed appropriately due to the bathymetry condition. And it is inevitable founding the existence of free span. Free spanning in offshore pipelines mainly occurs as a consequence of uneven seabed and local scouring due to flow turbulence. An illustration of free span is showed by the figure below:

According to Fredso and Sumer (1997), resonance is the main problem for offshore pipelines laid on the free spanning. Resonance happens when the environment’s frequency becomes equal to the pipe natural frequency. Resonance may lead to develop more fatigue on pipelines. In order to reduce the risk caused by free spanning, a maximum allowable length of free span should be determined. Span length is described with the following image:

An allowable length of free span can be calculated by the following formula (DNV 1998 & ABS 2001) :

in which E = modulus of elasticity; I = bending moment of inertia pipeline; C = coefficient of seabed condition; Vr = reduced velocity (Fredso and Sumer, 1997).

Vr defined as:

where U = streamwise flow velocity; D = outer diameter of pipe; me = effective mass (including structural mass, mass of content and added mass); fn = natural frequency of the pipe free span.

Natural frequency of free span pipe defined as:

In practice, the use of these formula for estimation of maximum free span length is not very applicable since there is difficulties in determining the exact seabed conditions.Therefore, different approaches usually adopted. One of the method is modal analysis.

Modal Analysis

Natural frequency of pipelines can be obtained using the Euler-Bernoulli beam equation which is defined as (Xu et al, 1999 and Bai, 2000):

with y = in-line displacement of pipe; x = position along the pipe span; t = time; C = total damping ratio; T = axial force of pipe (positive under tension); and F(t,u,y) = total external forces.

External forces and damping ratio only influence the resonance amplitude, so it can be ignored and the pipe free vibration equation is expressed in the following equation:

There are several codes that can be used as reference containing free spanning on offshore pipeline, like DnV RP F105 (Pipeline Free Spanning) and API RP 11 11, 1999.

PREVENTION

In order to prevent crack due to free spanning, supports can be made to reduce the stress on the free span area. These supports include sand-filling or mini structure. A mini structure is shown in figure below:

Source :

http://www.teknakurs.no/ikbViewer/Content/777784/Vedeld%201%20-%20Introduction.pdf

Bakhtiary, Abbas Yeganeh et al. Analysis of Offshore Pipeline Allowable Free Span Length. Iran University of Science and Technology. Iran. 2007.

Advanced pipe-soil interaction models in finite element pipeline analysis

Theme : Soil and pipeline interaction finite element modeling

Offshore pipelines laid on the seabed are exposed to hydrodynamic and cyclic operational loading. As a result, they may experience on-bottom instabilities, walking and lateral buckling. Finite element simulations are required at different stages of the pipeline design to check the different loading cases. Pipeline design depends on accurately modelling axial and lateral soil resistances.

Conventional pipeline design practice is to model the interaction between the pipe and the seabed with simple “spring-slider” elements at intervals along the pipe, as finite element methods with elaborated contact and interface elements between the pipeline and the foundation do not allow for comprehensive modeling of long pipeline systems with current computational power (Tian et al, 2008). These “spring-slider” elements provide a bi-linear, linear-elastic, perfectly plastic response in the axial and lateral directions. The limiting axial and lateral forces are based on empirical friction models, which relate axial and lateral resistance to the vertical soil reaction by using a “friction factor”. In the vertical direction, a non-linear elastic load embedment response derived from bearing capacity theory is usually assumed, the pipeline being treated as a surface strip foundation of width equal to the chord length of pipe-soil contact at the assumed embedment.

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 shear strength s_u 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 seabed. As a result, an accurate prediction of the pipeline embedment, which can be large in very soft cay, becomes of primary importance.

These simple models were improved to better predict pipeline embedment and axial and lateral resistances and were implemented in a Finite Element software program for pipeline analysis to better simulate the pipe-soil interaction of surface laid pipelines in soft clay and to more accurately simulate full routes. The new features are briefly explained in this paper. A more recent pipe-soil vertical reaction law that models plastic unloading is built into the program. It considers lay and dynamic installation effects to compute a more representative pipeline embedment. Axial and lateral resistance is now linked to pipeline embedment.
Finally, peak-residual axial and lateral reaction laws are implemented.

Vertical reaction law

Solutions for estimating the resistance profile have been provided by Murff et al. (1989), Aubeny et al. (2005) and Randolph & White (2008). The pipeline penetration z may be estimated from the conventional bearing capacity equation, modified for the curved shape of a pipeline:

where V is the vertical load per unit length, D is the pipeline diameter, s_u the undrained shear strength at the pipeline invert and A_s the nominal submerged area of the pipeline crosssection. For design, the bearing capacity factor N_c can be estimated using rounded values of the power law coefficients a and b, for example a = 6 and b = 0.25 (Randolph & White, 2008). Buoyancy has an influence in extremely soft soil conditions. This is captured by the buoyancy factor Nb. The factor f_b should be taken equal to 1.5 because of heave (Randolph & White, 2008).

The accuracy of this calculation approach, of the order of +/- 10%, is sufficient given the other uncertainties such as the installation effects, which influence the vertical load V (see below) (White & Randolph, 2007).

Installation effects
During installation of a pipeline, the vertical and horizontal motion of the lay barge and the load concentration at pipe touch-down will yield larger penetration than calculated based on the pipe submerged unit weight. The load concentration can be taken into account by multiplying the pipe weight by an amplification factor flay as proposed by Bruton (2006). In order to take into account the effect of pipe motion during installation, a partially remoulded shear strength can be used to compute the pipe embedment, as proposed by Dendani & Jaeck (2007), instead of the intact strength. These features combined with the vertical
reaction law described above allow predicting a more realistic pipeline embedment, which is of primary importance to compute a realistic axial and lateral resistance.

Plastic unloading
A non-linear elastic load embedment response is conventionally assumed for the vertical soil spring. However, it is essential to model a spring as behaving plastically to avoid predicting an unrealistic rebound when the pipe is unloaded. In practice, a pipe is often overpenetrated, meaning that its operating weight is lower than the maximum vertical force that had been applied to it. In effect, it has been unloaded. It is important to model a spring with plastic behaviour and “memory” to calculate the appropriate vertical soil stiffness. The behaviour of an over-penetrated pipe can be described by the stiff unload-reload line. When
reloaded to its normally-penetrated range, the pipe’s behaviour can be described as following the virgin load embedment curve. This is illustrated in the example below and in Figure 1. Let us first consider an elastic spring. During installation, the pipe moves to A1 due to load concentration and then rebounds to A2, to a vertical displacement corresponding to its submerged empty weight. During the hydrotest, the vertical force increases and the pipe moves to B. During operational conditions, if the content is lighter than water, the pipe is unloaded to point C. The pipe embedment and the tangent stiffness at this point are not realistic. In the case of an elasto-plastic spring, the pipe goes to A1 during installation and then to A2* following an unload-reload line. During the hydrotest, the vertical force increases
to B* along the unload-reload line. Finally, the pipe is unloaded to C*. At this point, the pipeline embedment and the tangent stiffness are more realistic. An accurate pipe embedment is especially important when it is coupled to axial and lateral resistance (see next Section).

Figure 1 – Behaviour of non-Linear Elasto-Plastic Vertical Springs

Coupling of axial and lateral resistance with pipeline embedment
The axial and lateral resistances depend on the contact area between the pipe and the seabed and thus the pipe embedment, when a total stress approach is followed. The formula used to compute peak axial and lateral resistances Fpa and Fpl are in the form:

where αs_u is the unit interface shear resistance, Ac is the area of contact between the pipe and the seabed which is a function of the pipe embedment z, μ is a “friction factor” in the range 0.2-0.8 (Randolph & White, 2007) and λ a coefficient typically in the range 0.5-2. The axial and lateral resistances have been linked to the pipeline embedment so that they are automatically calculated and can change during the analysis.
Tri-linear axial and lateral model
Models of the simple bi-linear frictional axial and lateral springs were improved so they can use peak and residual resistances to model the softening of the axial and lateral response often observed in clay. As explained earlier, pipelines are often over-penetrated in practice. When this occurs in soft clay, lateral breakout resistance Fpl, is high and drops sharply when suction at the rear face of the pipe is lost, then decreases further to a residual value Frl as the pipe rises to a shallower embedment. When the residual resistance is reached, the lateral resistance may increase again because a soil berm forms in front of the pipe (see Figure 2). The axial resistance may experience strain softening as well due to suction release and clay remoulding.

Figure 2 – Tri-linear Lateral Resistance Model

Conclusions
Simple soil models conventionally used in pipeline design practice have been improved and implemented in a Finite Element software program for pipeline analysis. There are several improvements. A more recent pipe-soil vertical reaction law that models plastic unloading is built into the program. It considers lay and dynamic installation effects to compute a more representative pipeline embedment. Axial and lateral resistance is now linked to pipeline embedment. Finally, peak-residual axial and lateral reaction laws have been implemented. The new features are basic but important first steps towards more accurate full route simulations, especially those in soft clay.

By : Ballard, Jean-Christophe, Hendrik Falepin, Jean-François Wintgens.

Source : http://www.sage-profile.com/publications/advanced-pipe-soil-interaction-models-in-finite-element-pipeline-analysis/

Pipeline Safety Inspections

Theme : Pipeline inspection

Operator compliance with pipeline safety regulations that establish minimal federal safety standards is critical to preventing pipeline accidents. Ensuring compliance involves regular inspections of pipeline operator programs and facilities and, when compliance violations are identified, the application of appropriate administrative, civil, or criminal remedies.

Federal and state pipeline inspectors conduct these compliance inspections and also conduct accident investigations and respond to public complaints concerning pipeline operations.

Federal Inspections: More than 100 full-time pipeline inspectors operate out of PHMSA’s Office of Pipeline Safety (OPS) regional offices in Trenton, NJ; Atlanta, GA; Kansas City, MO; Houston, TX; and Denver, CO. These inspectors implement a comprehensive inspection and enforcement program to verify that pipeline operators comply with pipeline safety regulations. OPS is responsible for oversight of interstate pipelines that cross state boundaries and intrastate pipeline systems in states where there is no certified state partner.

State Inspections: While the federal government is primarily responsible for developing, issuing, and enforcing pipeline safety regulations, the pipeline safety statutes provide for states to assume intrastate regulatory, inspection, and enforcement responsibilities under an annual certification. The majority of pipeline inspections in the nation are carried out by state inspectors who work for state agencies. If a state has a certified pipeline safety program, a state agency is responsible for conducting inspections of intrastate pipelines that lie entirely within a state’s borders.

For more information on federal/state authorities.

Pipeline safety regulations were originally established in the early 1970s and were based primarily on industry consensus standards in effect at the time. The regulations have been updated throughout the years with the addition of several significant new regulatory programs. As these took effect, OPS implemented an inspection program for each specific new regulatory program. In 2008, OPS began pilot testing an integrated inspection process. By using data and information about a specific operator and pipeline system, an inspector can custom-build a list of regulatory requirements to be evaluated during an inspection. This data-driven process allows OPS to focus inspection resources on the regulatory provisions addressing the greatest identified risks. OPS maintains the ability to conduct the program-based inspections listed below, and has been conducting an increasing number of integrated inspections since 2008. State partners may choose to conduct integrated inspections or continue with the program-based inspections.

Standard Inspections

Standard inspections are conducted to review operator compliance with the pipeline safety regulations originally put in place in the early 1970s. Both gas and hazardous liquid pipeline safety regulations include minimum requirements for an operator to safely operate and maintain its pipeline systems. Inspectors review the operator’s documented processes, procedures and records, they observe operator employees performing work in accordance with the operators processes and procedures, and check operating records to ensure the operator’s pipeline systems are operated at or below the maximum parameters allowed by regulations. They also examine the operator’s emergency procedures to determine if the operator is prepared to respond promptly and effectively if an abnormal condition or pipeline failure occurs.

Click here for a detailed description of Standard Inspections for various pipeline system types.

Operator Qualification (OQ) Inspections

In 2001, pipeline safety regulations were revised to require pipeline operators to document the training and qualifications of their employees. Operators are required to prepare a written operator qualification program that identifies employee positions that perform safety-sensitive operation or maintenance tasks. Employees in these positions must be trained and tested to ensure they have the necessary knowledge, skills and abilities to perform each task, as well as to recognize and react to emergencies that may arise while performing those tasks.

OPS and state inspections verify that operators have created acceptable OQ programs and identified all safety-sensitive employee positions. Inspectors also review records to verify that employees in these positions have been trained and tested. Operator employees performing operations and maintenance tasks are observed to ensure the tasks are completed in accordance with the operator’s program.

Integrity Management (IM) Inspections

In the context of pipeline operations, the term “integrity” means that a pipeline system is of sound and unimpaired condition and can safely carry out its function under the conditions and parameters for which it was designed. “Integrity management” encompasses the many activities pipeline operators must undertake to ensure the integrity of their pipeline systems. Integrity management regulations were promulgated and tailored for the different pipeline system types at different times – for hazardous liquid pipelines in 2001, for gas transmission pipelines in 2004, and for gas distribution pipeline systems in 2009. The IM regulations are tailored to each of these system types. Inspections of IM programs generally verify that an operator uses all available information about its pipeline system to assess risks and take appropriate action to mitigate those risks. Inspections include reviewing the written IM program and associated records.

A separate briefing on integrity management is available. For more detailed information, please select one of the links below:

• Hazardous Liquids
• Gas Transmission
• Gas Distribution

Source : http://www.inpipeproducts.com/pipeline-inspection/

RAPID CRACK PROPAGATION INCREASINGLY IMPORTANT IN GAS APPLICATIONS: A STATUS REPORT

Theme : Crack propagation on pipeline

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.

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.

Background

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.

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.

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.

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.

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:

1. Pipe size.
2. Internal pressure.
3. Temperature.
4. PE material properties/resistance to RCP.
5. Pipe processing.

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.

Test Methods

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.

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.

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.

The critical pressure is obtained by conducting a series of FS or S4 tests at a constant temperature (generally 0C) 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).

Figure 1: Critical Pressure (Plot of crack length vs. pressure)
Data obtained at 0° C (32°F).

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):

Pc,FS = 3.6 Pc,S4 + 2.6 bar (1)

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.

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).

Figure 2: Critical Temperature (Plot of crack length vs. temperature)
Data obtained at 5 bar (75 psig).

RCP In ISO

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:

Pc > 1.5 x MOP (2)

Where: Pc = full scale critical pressure, psig
MOP = maximum operating pressure, psig

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.

RCP In ASTM

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.

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:

1. PC,FS > leak test pressure.
3. Leak test pressure = 1.5 X MOP.

RCP In CSA

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.

12.4.3.6 Rapid Crack Propagation (RCP) Requirements

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.
(end of box)

RCP Test Data

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.

PE Material S4 Critical Pressure (PC,S4) at 32°F (0°C)/Full Scale Critical Pressure (PC,FS) @ 0°C

Unimodal MDPE 1 bar (15 psig)/6.2 bar (90 psig)
Bimodal MDPE 10 bar (145 psig) /38.6 bar (560 psig)

Unimodal HDPE 2 bar (30 psig)/9.8 bar (140 psig)
Bimodal HDPE (PE 100+) 12 bar (180 psig)/45.8 bar (665 psig)

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.

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.

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.

PE Material/Critical Temperature (TC) at 5 bar (75 psig)

Unimodal MDPE 15°C (60°F)
Bimodal MDPE -2°C (28°F)

Unimodal HDPE 9°C (48°F)
Bimodal HDPE -17°C (1°F)

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.

Conclusion

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.

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.

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.

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.

By : Dr. Gene Palermo, Palermo Plastics Pipe (P3) Consulting; William J. Michie, Jr. and Dr. Dane Chang, The Dow Chemical Company

Source : http://pipelineandgasjournal.com/rapid-crack-propagation-increasingly-important-gas-applications-status-report?page=show

Deepwater remote welding technology for pipeline repair and hot-tapping

Theme : Pipeline welding technology

The second paper highlighted from the subsea/flow assurance track addresses flowline and pipelines. Remotely operated dry hyperbaric welding technology has been further developed in recent years and is now becoming the basis for offshore applications both in subsea pipeline repair and hot-tapping technology. This paper outlines the welding technology and the operational systems developed and built to provide an offshore service.

The Pipeline Repair System pool (PRS pool) is a joint development between Statoil and Hydro to provide repair and construction support for the large oil and gas pipeline transportation system on and from the Norwegian Continental Shelf in the North Sea.

The development is funded by a consortium of companies sharing costs in exchange for access to the equipment. In 1987 Statoil was appointed to manage and operate the system and since then a continuous development has been undertaken. Currently PRS is the main repair contingency for approximately 10,000 km of subsea pipelines with dimensions ranging from 8 to 44 in. and water depths down to 600 m. This coverage is now being extended to water depths of 1,000 m as new pipelines come onstream.

The PRS is a comprehensive suite of subsea pipeline construction and repair tools, from isolation plugs and cleaning tools to large manipulation and installation frames, and welding habitat enclosures. The repair methods range from applying support clamps to weakened sections to cutting away damaged sections and replacing with new pipe, joining to the old by either mechanical connections or hyperbaric welding.

The PRS pool has over the last few years also invested in technology for remote hot-tapping into subsea pipelines, the objective being to provide technology for development projects which the commercial supplier market does not provide on short notice.

In order to achieve this, new unique equipment and welding technology has been developed and qualified with the objective to provide a fully remote operated system without the need for diver-assisted tasks.

Pipeline repair by welded sleeve technique

Traditional hyperbaric welding techniques involve the use of precision machining of the pipe ends and performing butt welds using the GTAW (gas tungsten arc welding) process. This involves precision alignment that can be very demanding (particularly on the second end and especially for large-diameter pipes).

The new approach avoids the need to achieve butt to butt closure and limits the requirement on precision alignment by threading a sleeve (slightly oversized to the pipe) over one end and drawing it back over the two pipe ends to be joined and making the welded join between the end of the sleeve and the pipe using a GMAW (gas metal arc welding) fillet weld. This technique is used on relatively small-diameter onshore pipelines and is part of the tools of the plumbing trade, but it has not been deployed subsea for production pipeline repair.

The development described in this paper is intended for use for repair of up to 44-in. pipelines down to depths in excess of 1,000 m.

Such a method is not covered directly in the existing regulations and codes of practice, although some work has been performed to establish fitness for purpose assessment criteria for sleeve welds, and as a result the project has been working in conjunction with Det Norske Veritas to establish criteria that could eventually form a code of practice.

The authors discuss next the structural design of the welded sleeve against all relevant limit states for maximum loads that can occur and with a safety margin dictated by the use of appropriate safety factors.

The relevant limit states are bursting, global yielding (including buckling), local overstressing/overstraining, unstable fracture (including possible lifetime crack growth) and fatigue. The relevant load cases are pressure testing (after repair), maximum loading during operation and fatigue during operation. It is necessary to consider axial loads that are both tensile-dominated (e.g., for unrestrained pipe segments) and compressive-dominated (e.g., for partially or fully restrained segments). Generally the design is governed by the tensile-dominated maximum loading case in operation.

Remote hot-tapping into subsea pipelines

The basic principle of hot-tapping is to establish a new branch pipeline connection to an existing (mother) pipeline while under full pressure. This involves connecting the branch pipe, including a valve, to the mother pipeline, usually by means of welding or mechanical clamp connections, cutting a hole in the pipe wall by a machine attached to the valve, retracting the cutting head, closing the valve, and disconnecting and recovering the cutting machine. The pipe branch may now be extended by spools and tied-in to a new pipeline in the usual manner. This strategy has been shown to be very cost-effective compared to alternative methods, including shutdown and tie-in at ambient pressure.

So far, divers have been used to weld the branch pipe to the mother pipeline and for all installation and cutting operations.

The primary focus of the remote hot-tap project is the development of a novel design combining the use of a remotely installed mechanical clamp (the retrofit tee), providing the necessary structural strength as well as interfaces toward the isolation valve module and the hot-tap cutting tool, and a saddle-formed “seal weld” made by remotely operated hyperbaric GMA welding inside the branch pipe.

The authors continue to provide a comprehensive overview of the structural design of the hot-tap tee, the hyperbaric GMAW process, welding qualifications, experimental equipment, procedural development, and installation of the welded sleeve and hot-tap tee.

Dry hyperbaric GMAW technology has been formally qualified for water depths down to 1,000 m and demonstrated and verified to a water depth down to 2,500 m.

The offshore systems and welding technology is part of the PRS pool in Norway and is ready for real applications offshore

By : Kjell Edvard Apeland, Jan Olav Berge, Richard Verley – Statoil ASA
Michael Armstrong, Neil Woodward – Isotek Electronics Ltd.

Source : http://www.offshore-mag.com/articles/print/volume-66/issue-11/dot-technical-preview/deepwater-remote-welding-technology-for-pipeline-repair-and-hot-tapping.html

Subsea pig launcher option on marginal, deepwater fields

Theme : Pig trap /pig launcher/intelligent pig

The rapidly expanding development of deepwater marginal fields using subsea production systems with long flow lines has led to the need to consider routine pigging operations as an integral part of the pipeline maintenance program.

To maintain pipeline operating efficiency, wax and liquid removal may be required on a continuous basis using conventional pigging and/or chemical treatments. Until now, subsea pig launchers have been technically inflexible and not always reliable. As a result, they have only been installed where there was no real option, their use being mainly restricted to commissioning operations.

Reliable pigging facilities are critical to the development of marginal fields which use subsea production systems. Many of these fields are located some distance from the production platform, requiring long flow lines to be laid. The ability to reliably and economically pig these lines from the subsea installation, without the need to lay a second line to provide a round trip pigging facility, can result in substantial overall cost savings when full account is taken of the CAPEX and OPEX costs.

Even when the field layout does allow round trip operations, the problems inherent in pushing solids and wax to the wellhead before returning it to the platform may eliminate this as an option. Pipeline insulation costs can impact significantly achievement of a favorable cost trade between CAPEX and OPEX for dual lines.

Temporary launcher

GD Engineering in Worksop, UK has developed a new subsea pig launching unit which combines economic and technical flexibility with positive pig launching. Two basic systems have been developed around the need to match system deployment and operation with the field’s operational philosophy.

The recent provision of a subsea multiple pig launching system for BP ETAP is an example of a temporarily installed launcher deployed subsea only when pigging operations are stipulated. ETAP is the largest North Sea development for a decade and also one of the most complex. The pig launching system was originally developed to meet the demanding requirements for continuous pigging of the 22-mile, 16-in. multiphase flow line from the Machar Field subsea manifold to the Marnock central processing facilities platform.

The length of this pipeline and the resulting temperature drop from the 120! well temperature meant that heavy wax deposition could be expected in the pipeline. Process studies indicated that a continuous program of mechanical pigging would be needed through the field’s life in order to maintain maximum operating efficiency.

Two pigging philosophies were considered:

• Round trip, two-line pigging using surface launchers and receivers
• A single-line subsea pig launcher then installed on the Machar manifold.

Comparisons between the two systems showed that the single line subsea pig launcher would be most cost-effective when CAPEX/ OPEX, pigging philosophy and operational factors were fully evaluated. But the overriding factor was the prohibitive cost of providing an additional flow line to the manifold for the total round trip pigging distance of 44 miles.

Brown & Root, which performed ETAP development engineering, contracted GD for the launcher system, which comprises the following elements:

• Vertically deployed pig launcher with a capacity for three conventional pigs or a single intelligent pig
• High pressure cap structure to provide positive sealing of the pipeline when the launcher is not installed
• Test stand to allow on-site pressure and function testing
• Manifold interface framework to provide terminations for the flowline and pig kicker line
• Conventional guide wire deployment system to allow deployment/retrieval of the launcher using a standard diving support vessel
• Pig stop and bypass (PSB) mechanism to provide positive pig launching.

This equipment, operated by a work class ROV using standard API tooling interfaces, was developed by GD Engineering to meet the continuous demand for reliable pig launching at pre-determined intervals throughout the field’s operating life.

A standard DSV is required for installation of the launcher using guide wire alignment (guide post and funnel) and heave-compensated lifting equipment. Two hydraulic subsea connectors (16-3/4-in. nominal size for the pipeline and 5-1/8-in. nominal size for the kicker line) would provide the interface between launcher and manifold. Installation of the launcher demanded simultaneous makeup of both connectors to their respective hubs, installed on the manifold structure.

Pig launcher installations are anticipated to be performed four times annually, assuming current predictions of wax deposition are accurate. On each occasion, three pigs will be deployed, each removing up to 10 tons of wax.

The pigs’ sealing discs form a tight fit with the launcher bore, which provides a positive launch situation when kicker fluid is introduced behind the pigs. The launcher barrel is long enough to hold three pigs or a single intelligent pig.

Each pig launcher will require the high pressure cap assembly to be retrieved from the manifold, after first establishing pipeline sealing integrity. Deployment of the launcher and subsequent fill and pressurization with manifold product (multiphase hydrocarbon) would follow.

Pig release mechanism

The mechanism developed by GD Engineering for pig release comprises a pressure balanced spool mounted in a rigid housing. This arrangement provides the integrated function of a pig stop and bypass (PSB) facility. In operation, the pigs are loaded into the line-sized launcher barrel to predetermined positions.

The PSB mechanism spools are extended to provide positive retention of the pigs should they slip during installation of the launcher. The PSB mechanisms are interconnected by pipework to provide a continuous flow path for the kicker fluid. Connection of this pipework to the manifold kicker line is achieved through the 5-1/8-in. connector.

Following pressurization with hydrocarbon, flow from the kicker line will pass through the mechanisms to the front and back of each pig, and between the sealing discs via the pigs’ bypass facility, giving a pressure-balanced situation.

To launch the first pig, the spool of the first PSB mechanism is retracted. As the spool is withdrawn level with the inside bore of the launcher barrel, the kicker flow passing through the spool is restricted and full flow is diverted through this mechanism to the adjacent PSB mechanism. A pressure differential is created that causes the first pig to be pushed along the barrel into the pipeline.

Launching of subsequent pigs follows the same procedure. The PSB mechanism design ensures that the pig stop is fully retracted before full bypass occurs to prevent the pig from creeping under the stop as pressure differential increases.

The selected configuration contains a blend of proven subsea technology with new innovations, where required. By its nature, new technology carries some technical risk until proven in service. To offset this, detailed test procedures have been introduced to determine, as far as is practical, the likely performance of such equipment.

The Machar manifold pipelay was completed in March 1997, with site integration testing of the complete structure last September. GD Engineering manufactured the equipment described, which was integrated into the manifold structure this February. Pigging operations are due to begin in October.

Deepwater version

For deepwater applications, an alternative to the temporary installation of the launcher uses a pig cassette system, the pig launcher being permanently located on the subsea manifold. Instead of deploying the pre-loaded launcher, a lightweight cassette containing the pigs is used to re-load the subsea launcher with pigs.

Both ROVs or conventional guide wire systems can be used to deploy the cassette, which is loaded into the launcher through a subsea closure. Sequential release of the pigs is achieved by operation of pig release latches mounted on the cassette. Kicker flow is directed to each pig in sequence, in a similar manner to the PSB mechanism on ETAP. This method is especially economic for large diameter pipelines requiring subsea pigging operations or when continual ROV interventions are required on the manifold system.

The cassette system incorporates numerous design features to suit different operating philosophies:

• A lightweight cassette (reduces installation needs)
• No requirement for multi-make/break and aliagnment of connectors for launcher barrel
• Deployment by conventional guidance systems or ROV
• Horizontal or vertical launcher orientation
• Control and operation by ROV or umbilical
• Launcher barrel of simple construction – pig release mechanism forms integral part of the cassette and is recovered to the surface for routine maintenance
• Intelligent pig launching and pipeline intervention tool capability with same cassette replenishment of pigs from subsea storage when availability of surface vessels is limited.

In conclusion, the single line pig launcher can provide a cost-effective solution for marginal and deepwater applications, whether the requirement is for frequent routine pigging or infrequent intelligent pig inspections. The system’s basic building blocks are designed to provide a standard interface to other subsea equipment and may allow equipment pooling, leading to further cost savings.

By : Brian Smith

Source : http://www.offshore-mag.com/articles/print/volume-58/issue-4/news/production/subsea-pig-launcher-option-on-marginal-deepwater-fields.html