HDPE Pipe/FRP Pipe for Subsea or Offshore Pipeline

HDPE PIPE

ISCO Industries is the largest high-density polyethylene (HDPE) pipe distributor in North America. We can serve your HDPE needs anywhere in the U.S. and internationally.

HDPE pipe is ideal for many different applications including municipal, industrial, energy, geothermal, landfill and more. HDPE pipe is strong, durable, flexible and light weight. When fused together, HDPE has a zero leak rate because the fusion process creates a monolithic HDPE system. HDPE pipe is also a more environmentally sustainable option as it is non-toxic, corrosion and chemical resistant, has a long design life, and is ideal for trenchless installation methods because of its flexibility.

HDPE industrial applications and advantages:

• FM Approved piping
• Underground piping meets or exceeds operating temperatures and pressures
• Cooling Water Applications:
  • HDPE pipe is an excellent insulator, with minimal heat transfer. Copper transfers heat 2700 times more than HDPE.
  • HDPE does not become brittle at 32 deg. F
  • HDPE does not leak, it is seamlessly fused
  • HDPE does not corrode
• Instrument Air
• Fire Water
• Steam Condensate and Blow Down
• Raw Water
• Process Water
• Withstands freezing water better than traditional metal piping
• Systems maintain high fluid flow properties throughout their service life due to excellent chemical and abrasion resistance
• Pipe is available in coils through 6" for multiple applications
• Is weather resistant:
  • Carbon black is added to HDPE to provide UV protection
  • Frozen water will not crack or break HDPE pipe
• Is durable:
  • Withstands fatigue and surges
  • Safer due to operating pressure capabilities
  • Butt fused joints eliminate need for thrust blocks
• Delivers long term economy, value, and dependability

Sumber: http://www.isco-pipe.com/products-and-services/hdpe-pipe/

Pipeline Expansion Loop/Expansion Spool

Allowance for expansion

All pipes will be installed at ambient temperature. Pipes carrying hot fluids such as water or steam operate at higher temperatures

It follows that they expand, especially in length, with an increase from ambient to working temperatures. This will create stress upon certain areas within the distribution system, such as pipe joints, which, in the extreme, could fracture. The amount of the expansion is readily calculated using Equation 10.4.1, or read from an appropriate chart such as Figure 10.4.1.

Equation 10.4.1


Where:



L = Length of pipe between anchors (m)

ΔT = Temperature difference between ambient temperature and operating temperatures (°C)

α = Expansion coefficient (mm/m °C) x 10-3

Table 10.4.1 Expansion coefficients (a) (mm/m °C x 10-3)

Example 10.4.1
A 30 m length of carbon steel pipe is to be used to transport steam at 4 bar g (152°C). If the pipe is installed at 10°C, determine the expansion using Equation 10.4.1.





Alternatively, the chart in Figure 10.4.1 can be used for finding the approximate expansion of a variety of steel pipe lengths - see Example 10.4.2 for explanation of use.
Example 10.4.2


Using Figure 10.4.1. Find the approximate expansion from 15°C, of 100 metres of carbon steel pipework used to distribute steam at 265°C.

Temperature difference is 265 - 15°C = 250°C.

Where the diagonal temperature difference line of 250°C cuts the horizontal pipe length line at 100 m, drop a vertical line down. For this example an approximate expansion of 330 mm is indicated.

Fig. 10.4.1 A chart showing the expansion in various steel pipe lengths at various temperature differences

Table 10.4.2 Temperature of saturated steam



Pipework flexibility

The pipework system must be sufficiently flexible to accommodate the movements of the components as they expand. In many cases the flexibility of the pipework system, due to the length of the pipe and number of bends and supports, means that no undue stresses are imposed. In other installations, however, it will be necessary to incorporate some means of achieving this required flexibility.

An example on a typical steam system is the discharge of condensate from a steam mains drain trap into the condensate return line that runs along the steam line (Figure 10.4.2). Here, the difference between the expansions of the two pipework systems must be taken into account. The steam main will be operating at a higher temperature than that of the condensate main, and the two connection points will move relative to each other during system warm-up.

Fig. 10.4.2 Flexibility in connection to condensate return line


The amount of movement to be taken up by the piping and any device incorporated in it can be reduced by 'cold draw'. The total amount of expansion is first calculated for each section between fixed anchor points. The pipes are left short by half of this amount, and stretched cold by pulling up bolts at a flanged joint, so that at ambient temperature, the system is stressed in one direction. When warmed through half of the total temperature rise, the piping is unstressed. At working temperature and having fully expanded, the piping is stressed in the opposite direction. The effect is that instead of being stressed from 0 F to +1 F units of force, the piping is stressed from -½ F to + ½ F units of force.

In practical terms, the pipework is assembled cold with a spacer piece, of length equal to half the expansion, between two flanges. When the pipework is fully installed and anchored at both ends, the spacer is removed and the joint pulled up tight (see Figure 10.4.3).

Fig. 10.4.3 Use of spacer for expansion when pipework is installed


The remaining part of the expansion, if not accepted by the natural flexibility of the pipework will call for the use of an expansion fitting.

In practice, pipework expansion and support can be classified into three areas as shown in Figure 10.4.4.

Fig. 10.4.4 Diagram of pipeline with fixed point, variable anchor point and expansion fitting


The fixed or 'anchor' points 'A' provide a datum position from which expansion takes place.

The sliding support points 'B' allow free movement for expansion of the pipework, while keeping the pipeline in alignment.

The expansion device at point 'C' is to accommodate the expansion and contraction of the pipe.


Fig. 10.4.5 Chair and roller


Fig. 10.4.6 Chair roller and saddle





Roller supports (Figure 10.4.5 and 10.4.6) are ideal methods for supporting pipes, at the same time allowing them to move in two directions. For steel pipework, the rollers should be manufactured from ferrous material. For copper pipework, they should be manufactured from non-ferrous material. It is good practice for pipework supported on rollers to be fitted with a pipe saddle bolted to a support bracket at not more than distances of 6 metres to keep the pipework in alignment during any expansion and contraction.




Where two pipes are to be supported one below the other, it is poor practice to carry the bottom pipe from the top pipe using a pipe clip. This will cause extra stress to be added to the top pipe whose thickness has been sized to take only the stress of its working pressure.




All pipe supports should be specifically designed to suit the outside diameter of the pipe concerned.



Expansion fittings


The expansion fitting ('C' Figure 10.4.4) is one method of accommodating expansion. These fittings are placed within a line, and are designed to accommodate the expansion, without the total length of the line changing. They are commonly called expansion bellows, due to the bellows construction of the expansion sleeve.

Other expansion fittings can be made from the pipework itself. This can be a cheaper way to solve the problem, but more space is needed to accommodate the pipe.
Full loop
This is simply one complete turn of the pipe and, on steam pipework, should preferably be fitted in a horizontal rather than a vertical position to prevent condensate accumulating on the upstream side.

The downstream side passes below the upstream side and great care must be taken that it is not fitted the wrong way round, as condensate can accumulate in the bottom. When full loops are to be fitted in a confined space, care must be taken to specify that wrong-handed loops are not supplied.

The full loop does not produce a force in opposition to the expanding pipework as in some other types, but with steam pressure inside the loop, there is a slight tendency to unwind, which puts an additional stress on the flanges.

Fig. 10.4.7 Full loop


This design is used rarely today due to the space taken up by the pipework, and proprietary expansion bellows are now more readily available. However large steam users such as power stations or establishments with large outside distribution systems still tend to use full loop type expansion devices, as space is usually available and the cost is relatively low.



Horseshoe or lyre loop

When space is available this type is sometimes used. It is best fitted horizontally so that the loop and the main are on the same plane. Pressure does not tend to blow the ends of the loop apart, but there is a very slight straightening out effect. This is due to the design but causes no misalignment of the flanges.

If any of these arrangements are fitted with the loop vertically above the pipe then a drain point must be provided on the upstream side as depicted in Figure 10.4.8.

Fig. 10.4.8 Horseshoe or lyre loop
Expansion loops

Fig. 10.4.9 Expansion loop


The expansion loop can be fabricated from lengths of straight pipes and elbows welded at the joints (Figure 10.4.9). An indication of the expansion of pipe that can be accommodated by these assemblies is shown in Figure 10.4.10.

It can be seen from Figure 10.4.9 that the depth of the loop should be twice the width, and the width is determined from Figure 10.4.10, knowing the total amount of expansion expected from the pipes either side of the loop.

Fig. 10.4.10 Expansion loop capacity for carbon steel pipes

Sliding joint
These are sometimes used because they take up little room, but it is essential that the pipeline is rigidly anchored and guided in strict accordance with the manufacturers' instructions; otherwise steam pressure acting on the cross sectional area of the sleeve part of the joint tends to blow the joint apart in opposition to the forces produced by the expanding pipework (see Figure 10.4.11). Misalignment will cause the sliding sleeve to bend, while regular maintenance of the gland packing may also be needed.

Fig. 10.4.11 Sliding joint

Expansion bellows

An expansion bellows, Figures 10.4.12, has the advantage that it requires no packing (as does the sliding joint type). But it does have the same disadvantages as the sliding joint in that pressure inside tends to extend the fitting, consequently, anchors and guides must be able to withstand this force.

Fig. 10.4.12 Simple expansion bellows


Bellows may incorporate limit rods, which limit over-compression and over-extension of the element. These may have little function under normal operating conditions, as most simple bellows assemblies are able to withstand small lateral and angular movement. However, in the event of anchor failure, they behave as tie rods and contain the pressure thrust forces, preventing damage to the unit whilst reducing the possibility of further damage to piping, equipment and personnel (Figure 10.4.13 (b)).

Where larger forces are expected, some form of additional mechanical reinforcement should be built into the device, such as hinged stay bars (Figure 10.4.13 (c)).

There is invariably more than one way to accommodate the relative movement between two laterally displaced pipes depending upon the relative positions of bellows anchors and guides. In terms of preference, axial displacement is better than angular, which in turn, is better than lateral. Angular and lateral movement should be avoided wherever possible.

Figure 10.4.13 (a), (b), and (c) give a rough indication of the effects of these movements, but, under all circumstances, it is highly recommended that expert advice is sought from the bellows' manufacturer regarding any installation of expansion bellows.

Fig. 10.4.13 (a) Axial movement of bellows

Fig. 10.4.13 (b) Lateral and angular movement of bellows

Fig. 10.4.13 (c) Angular and axial movement of bellows



Pipe support spacing


The frequency of pipe supports will vary according to the bore of the pipe; the actual pipe material (i.e. steel or copper); and whether the pipe is horizontal or vertical.

Some practical points worthy of consideration are as follows:
Pipe supports should be provided at intervals not greater than shown in Table 10.4.3, and run along those parts of buildings and structures where appropriate supports may be mounted.
Where two or more pipes are supported on a common bracket, the spacing between the supports should be that for the smallest pipe.
When an appreciable movement will occur, i.e. where straight pipes are greater than 15 metres in length, the supports should be of the roller type as outlined previously.
Vertical pipes should be adequately supported at the base, to withstand the total weight of the vertical pipe and the fluid within it. Branches from vertical pipes must not be used as a means of support for the pipe, because this will place undue strain upon the tee joint.
All pipe supports should be specifically designed to suit the outside diameter of the pipe concerned. The use of oversized pipe brackets is not good practice.

Table 10.4.3 can be used as a guide when calculating the distance between pipe supports for steel and copper pipework.

Table 10.4.3 Recommended support for pipework

Sumber: http://www2.spiraxsarco.com/resources/steam-engineering-tutorials/steam-distribution/pipe-expansion-and-support.asp

Flexible Riser

How To Identify The Features And Benefits Of A Flexible Riser?





A flexible riser works in such a mechanism that it allows a riser to stand in a perfect position so that there are no joint problems.

What are the features of a flexible riser?

There are certain basic features of a flexible riserFlexible Riser that allows an individual to sit and rise up properly from the toilet. It includes the luxury of the toilet and at the same time, it also allows a user to adjust to the height that is required in case of the riser. Some of its basic features include:



– This kind of flexible riser is tough, resilient and durable and the finer varieties are made of hard materials which make them rust-proof and corrosion-proof.

– The best benefit that you get of a flexible riser is that, you can use it more as an ordinary flexibility, so you do not have to pressurize yourself when you want to adjust your position and posture. This also allows for enough space to clean the underneath.

– There are some models of a flexible riser which are used as fine models made of polyethylene. These are more affordable, can be cleaned easily and they suit all types of risers.

– As there are more number of options available in the market, the demand for flexible riser is increasing constantly. If you search through the internet, you can find a host of options regarding a flexible riser.

Styles that blend well with the background



As there a lot of options, when it comes to using a flexible riser, you can easily get them in different styles, patterns and designs. Moreover, you can also get the customized toilet risers from different dealers, if you tell them about your preferences and choice. Similar to other uncommon medical-related hardware meant they will also be able to tackle some of your main transportability and also selected lifestyle factors. What’s more you will be able to get them in different colors along with the covering materials used which also vary so as to ensure that any type of style could be allowed with any kind of a covering to build the risers inexpensive to an unbelievable number of families.

What are the utilities of a flexible riser?

When you start using the flexible risers, then you get the flexibility and the easy attachment to the riser, which actually allows you to work comfortably. So now you can contact the online dealers and to get the best varieties of flexible risers.

Sumber: http://inspiration.theownerbuildernetwork.co/how-to-identify-the-features-and-benefits-of-a-flexible-riser/

Horizontal and Vertical Christmas Tree

Enhanced Horizontal Subsea Tree (EHXT)

Horizontal trees are known for their installation efficiency, being workover friendly, and offering easy access for tubing retrieval due to the horizontal positioning of the primary valves. FMC Technologies is a market leader in horizontal tree technology and has successfully installed more than 1,000 worldwide.  

The Enhanced Horizontal Christmas Tree (EHXT), introduced in 2002, offers an elongated tubing hanger incorporating two wireline plug profiles. This enhanced hanger along with the elimination of the internal tree cap removes the problem of trapped debris resulting in a cost effective and reliable tree solution. The tree has a modular design that allows easy manufacturability and offers flexibility for low to high functionality in accordance with operator requirements.

The broad product portfolio provides solutions for deepwater, shallow water, and template applications and is rated for up to 10,000 feet water depth. EHXTs are capable of operating at pressures up to 10,000 psi and 15,000 psi. In addition, the EHXT is available in the field proven large bore design and is configurable for gas lift operations and downhole ESP completions.

EHXT Advantages:

• Traditional pressure containing internal tree cap has been eliminated, and the pressure barriers moved to an elongated tubing hanger resulting in more cost effective and reliable completions.

• Well control and vertical access to downhole equipment are gained through a conventional marine drilling riser and subsea BOP eliminating the need for costly and specialized completion risers.

• Large bore configuration allows installation and retrieval of downhole equipment without disturbing the tree or external connections to flowlines, service lines, or control umbilicals.

• The tubing hanger is landed within the tree body making it possible to recover the completion without removal of the tree.

• Patented and field proven solution for incorporation of downhole ESP penetrator.

• Common tooling package across 10,000 psi and 15,000 psi EHXT systems improves availability and significantly reduces hardware costs and lead time on projects.

Sumber: http://www.fmctechnologies.com/en/SubseaSystems/Technologies/SubseaProductionSystems/SubseaTrees/EHXT.aspx

Deepwater Pipeline

Deepwater pipelines – Taking the challenge to new depths

Martin Connelly - Corus Tubes

To ensure continuity of supply, E&P companies have to consider opportunities in ever increasing water depths. Assisting this are new technological advances, including pipeline manufacture and design that increase the technical feasibility of deepwater developments.

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.

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

Pipeline Corrosion

Ceramic coatings can prevent corrosion

Written by  Tony Collins 

Corrosion has long been the bane of the oil industry. Now new approaches and coatings are resolving the difficulties and providing intriguing possibilities for offshore pipelines, explains Tony Collins of EonCoat.

In the oil and gas industry, corrosion accounts for over 25% of failures, according to a recent National Association of Corrosion Engineers (NACE) International report. Corroded pipe repair or replacement costs the industry over US$7 billion per year, based on estimates from NACE. This figure can double when lost revenue, productivity, and spill or leak cleanup costs are tallied.

As deepwater exploration accelerates, protecting offshore pipelines from seawater corrosion is becoming more vital than ever to preserve deeper and more costly oil and gas assets. While offshore pipelines supplement corrosion protection with cathodic protection, the main defense against corrosion remains external pipeline coatings, particularly fusion-bonded, epoxy-powder coatings.

“Corrosion is a major industry challenge,” says Scott Justice, Tank Division operations manager of Bolin Enterprises Inc. (BEI), a Casey, Ill.-based pipeline and tank maintenance contractor serving the oil and gas industry.

While traditional corrosion protection has relied mostly on short-lived, physically-bonded coverings of substrate surfaces such as tapes, elaborate three-part coating systems (zinc, epoxy, and urethane), and cathodic protection, these merely attempt to lengthen the time before the steel asset inevitably rusts.

Now a growing number of proactive, oil and gas industry maintenance professionals are turning to a new category of tough, chemically-bonded, phosphate ceramics (CBPC) that can prevent corrosion, extend equipment life, and minimize the cost and production downtime required to recoat, repair, or replace corroded equipment.

New approach

“What caught my eye about [CBPC coating] was its unique adhesion and chemical properties,” says Justice, who visited Wilson, N.C.-based EonCoat LLC to view its corrosion testing lab, processes, and procedures for its CBPC coating. “If its hard outer shell is breached or knocked off, it still has corrosion protection where traditional coatings do not. Whether its coating is aged, beaten, or banged around, it still protects the surface. If you remove the outer ceramic shell, the chemical bond with the substrate still stops corrosion at the surface.”

In contrast to typical paint polymer coatings that sit on top of the substrate, the anti-corrosion coating bonds through a chemical reaction with the substrate, and slight surface oxidation actually improves the reaction. This makes it impossible for corrosion promoters like oxygen and humidity to get behind the coating the way they can with ordinary paints. The corrosion barrier is covered by a true ceramic shell, which resists corrosion, fire, water, abrasion, chemicals, and temperatures up to 1000°F.

While traditional polymer coatings create a film structure, which mechanically bonds to substrates that have been extensively prepared, if gouged, moisture and oxygen will migrate under the coating’s film from all sides of the gouge. Moisture and heat are then trapped by the film, creating a “greenhouse effect,” promoting corrosion and blistering. By contrast, the same damage to the ceramic-coated substrate will not spread corrosion because the steel is essentially alloyed. Its surface oxides have been converted into an inert, electrochemically stable metal incapable of supporting oxidation.

Ceramic coatings such as this consist of two, non-hazardous ingredients that do not interact until applied by a plural-component spray gun like those commonly used to apply polyurethane foam or polyurea coatings. Since the components are not mixed and do not meet prior to application, the need for hazardous volatile organic compound (VOC)-generating ingredients is eliminated, as are hazardous atmospheric particles and odor. This means that the work can be done in occupied areas.

“The results of the corrosion tank test were impressive,” says Justice. Among the corrosion tests frequently run by the manufacturer of the CBPC product is one where the ceramic coating has gone more than 10,000 hours with no corrosion in a salt spray ASTM B117 test. “If the coating works as well as we hope, it could help to stop or minimize corrosion and extend the longevity of a range of oil and gas assets,” adds Justice.

Independent electrochemical corrosion potential testing of the CBPC product also indicates its usefulness for offshore pipeline corrosion protection. Steel plates coated with EonCoat were placed in a beaker of saltwater by Dr. Ki Yong Ann, Dept. of Civil and Environmental Engineering, in a lab at Hanyang University, Seoul, Korea. When voltage was run through the solution and the corrosion rate determined by measuring current leakage across the coating in ma/sq m, the coated plates were found to have no corrosion potential. Any result below “2” is considered to have no corrosion potential, and the coated plates tested at 1.15 the first time, and 0.85 the second time.

For submerged offshore pipeline applications, an anti-fouling topcoat can be added to the CBPC coating, which enhances appearance and reduces barnacle growth.

Unlike organic, carbon polymerbased paints and coatings, which may give a foothold for corrosion causing microbes to grow, ceramic coatings are completely inorganic, so they are inhospitable to mold or bacteria. “Since EonCoat is inorganic, it cannot sustain mold or bacteria growth,” says Justice. While not widely considered, the Achilles heel of many traditional corrosion coatings may be in how exact the environmental conditions must be during their application to meet specifications.

“A lot of coating products fail due to changes in temperature, humidity, dew point, and other atmospheric factors during application,” says Justice. “As conditions change seasonally throughout the year, it can be difficult to provide perfect coating conditions.”

Protective ceramic coatings can be applied on hot or cold surfaces, from 40-150°F in 0-95% humidity, excluding direct rain.

“Since the ceramic coating takes changes in temperature, humidity, and dew point out of the equation during pplication, it can be reliably used in tough environmental conditions that might otherwise compromise the corrosion protection of typical coatings,” says Justice.

Cutting downtime

Shane Bartko, a director at TKO Specialty Surfaces, a Calgary, Albertabased tank, pipeline, and structure maintenance contractor, has used the ceramic coating for corrosion control on a variety of oil and gas projects. “To keep a corrosive coating working well, you want one that will be resistant to high temperature, abrasion, chemicals, UV sunlight, and other environmental factors,” says Bartko.

The time saved on a corrosion coating project with ceramic coating comes both from simplified surface preparation and expedited curing time. “With a typical corrosion coating, you have to blast to white metal to prepare the surface,” says Bartko. “But with the ceramic coating, you typically only have to do a NACE 3 commercial brush blast.” Bartko explains that on coating projects using typical polymer paints such as polyurethanes or epoxies, the cure time may be days or weeks before the next coat of three coatings can be applied, depending on the product. The cure time is necessary to allow each coat to achieve its full properties, even though it may feel dry to the touch.

In contrast, ceramic coating is applied in a single coat, with almost no curing time necessary. Return to service can be achieved in as little as one hour.

“With the ceramic coating for corrosion protection, we’re able to get facilities back up and running right away after spraying, sometimes in an hour,” says Bartko. “That kind of speed in getting an oil and gas facility producing again can potentially save millions per day in reduced downtime. It makes sense to use the ceramic coating anywhere steel is used and may corrode, from pipelines and processing to storage.” OE

Sumber: http://www.oedigital.com/subsea/item/4265-ceramic-coatings-can-prevent-corrosion

Pipeline Gooseneck

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

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

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

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

Pipeline Inspection

Pipeline Inspection

In the United States, millions of miles of pipeline carrying everything from water to crude oil. The pipe is vulnerable to attack by internal and external corrosion, cracking, third party damage and manufacturing flaws. If a pipeline carrying water springs a leak bursts, it can be a problem but it usually doesn't harm the environment. However, if a petroleum or chemical pipeline leaks, it can be a environmental disaster. More information on recent US pipeline accidents can be found at the, National Transportation Safety Board's Internet site. In an attempt to keep pipelines operating safely, periodic inspections are performed to find flaws and damage before they become cause for concern.

When a pipeline is built, inspection personnel may use visual, X-ray, magnetic particle, ultrasonic and other inspection methods to evaluate the welds and ensure that they are of high quality. The image to the left show two NDT technicians setting up equipment to perform an X-ray inspection of a pipe weld. These inspections are performed as the pipeline is being constructed so gaining access the inspection area is not problem. In some areas like Alaska, sections of pipeline are left above ground like shown above, but in most areas they get buried. Once the pipe is buried, it is undesirable to dig it up for any reason.

So, how do you inspect a buried pipeline?

Have you ever felt the ground move under your feet? If you're standing in New York City, it may be the subway train passing by. However, if you're standing in the middle of a field in Kansas it may be a pig passing under your feet. Huh??? Engineers have developed devices, called pigs, that are sent through the buried pipe to perform inspections and clean the pipe. If you're standing near a pipeline, vibrations can be felt as these pigs move through the pipeline. The pigs are about the same diameter of the pipe so they range in size from small to huge. The pigs are carried through the pipe by the flow of the liquid or gas and can travel and perform inspections over very large distances. They may be put into the pipe line on one end and taken out at the other. The pigs carry a small computer to collect, store and transmit the data for analysis. In 1997, a pig set a world record when it completed a continuous inspection of the Trans Alaska crude oil pipeline, covering a distance of 1,055 km in one run. 

Pigs use several nondestructive testing methods to perform the inspections. Most pigs use a magnetic flux leakage method but some also use ultrasound to perform the inspections. The pig shown to the left and below uses magnetic flux leakage. A strong magnetic field is established in the pipe wall using either magnets or by injecting electrical current into the steel. Damaged areas of the pipe can not support as much magnetic flux as undamaged areas so magnetic flux leaks out of the pipe wall at the damaged areas. An array of sensor around the circumference of the pig detects the magnetic flux leakage and notes the area of damage. Pigs that use ultrasound, have an array of transducers that emits a high frequency sound pulse perpendicular to the pipe wall and receives echo signals from the inner surface and the outer surface of the pipe. The tool measures the time interval between the arrival of a reflected echos from inner surface and outer surface to calculate the wall thickness.

On some pipelines it is easier to use remote visual inspection equipment to assess the condition of the pipe. Robotic crawlers of all shapes and sizes have been developed to navigate the pipe. The video signal is typically fed to a truck where an operator reviews the images and controls the robot.

Sumber: https://www.nde-ed.org/AboutNDT/SelectedApplications/PipelineInspection/PipelineInspection.htm

Pipeline Commissioning

Pipeline commissioning: purging air with gas

By Phillip Venton, Principal, Venton & Associates Pty Ltd

Featured in April 2015

     

Phillip Venton.

When gas pipelines were in their infancy in Australia, it was common practice to displace air from the pipeline using gas.

Since nitrogen is used in process industries to displace air from process vessels and complex piping prior to introducing a flammable gas, people in the pipeline industry thought more about the risk and it became more common to separate the air from the gas using a large slug of an inert gas such as nitrogen.

This introduced significant complexity into the operation, requiring large tankers of liquid nitrogen, vaporising equipment and fuel to be transported to very remote locations.

Mechanical separation (a pig), is an alternative, but rarely used because the velocity during a purge is usually too high.

A few pipelines such as the Moomba to Wilton pipeline were left filled with water following construction.

The water was displaced using gas to propel a relatively complex pig train to separate the water and gas.

The effort to dry the pipeline was considerable and this approach has rarely been used since.

When it became necessary to introduce gas into the 800 km long Eastern Gas Pipeline (EGP) a range of options were considered, including; nitrogen slugs, a separating pig train and a return to the early practice of simply displacing the air with gas.

The review concluded that the quickest, simplest and safest approach was to displace the air with gas.

The operation was successful, and subsequently a similar approach was used on the Tasmanian Gas Pipeline and the SEA Gas Pipeline.

More recently, pipeline commissioning has reverted to using an inert gas slug to separate the air and gas.

While this approach may have been appropriate for those pipelines, there are concerns that the simple gas purge approach is not considered because of a basic lack of understanding of the process, and indeed the potential ignition risk.

This article uses the EGP purge process as an example that purging air without the complexity of an inert gas slug, or mechanical separation of air and gas with a pig, is a safe and predictable process.

AGA Purging Principles and Practice

Research undertaken by the Gas Research Institute (GRI) was published in 1997 (GRI-97/0104 Pipeline Purging Principles and Practices Research) together with a software application, PURGE.EXE, designed to model the purge process.

The EGP commissioning team used both this report and PURGE.EXE in evaluating options for purging air from the pipeline.

Much of the GRI research was incorporated into the 2001 revision of the AGA Purging Principles and Practice.

The research was undertaken by South West Research Institute (SWRI) (this report is still available from the Gas Technology Institute, although unfortunately the PURGE.EXE application, developed for Windows XP, appears to no longer be available).

Ignition risk

The risk that the gas-air mixture at the purge interface ignites (explosively) within the pipe is often quoted as the reason for separating the gas and air with an inert gas slug.

In new, steel pipelines this risk is vanishingly small because there is no ignition source in the pipeline.

There may be a small risk in an existing pipeline containing pyrophoric dust.

The SWRI research concluded that in the unlikely event of interface ignition, the maximum overpressure in the pipe is approximately 10 times the pressure in the pipe at the time of ignition – for this reason the AGA Purging Principles document recommends limiting the maximum pressure in the pipe during a gas purge to 100 psig (thus limiting the maximum pressure should combustion occur to ~1,000 psig, the typical maximum pipeline pressure in North America at the date of the research).

This can be readily confirmed by calculating the volume change when methane is burnt, using the equation 
CH4 + 2O2 = CO2 + 2H2O.

The plume ignition risk is also low, provided simple safety procedures are followed.

Moreover, the high plume velocity at the vent provides momentum to propel the plume above most credible ignition sources (like the vent from a pipeline blowdown).

Hydraulics – the length of the mixed air-gas interface

There are two distinct flow regimes within a pipeline – laminar flow, which is characterised by a parabolic velocity profile across the pipeline cross section, and turbulent flow, which is characterised by a constant velocity profile across the pipe cross section, except for a thin boundary layer at the pipe wall where the velocity transitions to zero at the wall.

In laminar flow, the fluid in the central region moves at a higher velocity than that in the outer region, causing continuous longitudinal mixing of the pipe contents.

In turbulent flow the essentially constant velocity profile prevents longitudinal mixing.

There is a minor mixing at the batch interface resulting from a combination of dispersion across the interface, and from the velocity change in the boundary layer.

The interface volume can be calculated from the pipeline flow and product properties, while the constant velocity profile enables the interface position to be accurately tracked from the flow rate.

This phenomena is used in many multi-product pipelines to separate batches of different products, eliminating the need to provide positive separation using, for example, batching pigs.

In a multi-product pipeline, the batches are usually sequenced so that mixed interface fluid can be blended into the following uncontaminated batch without degrading it.

Various publications discuss prediction of the interface length in liquids pipelines – these provide useful background to understanding the phenomena.

Similar concepts apply to the interface length calculation for gases, although the velocity (Reynolds number) variation during the purge increase the calculation complexity.

These methods incorporate an estimate of the interphase dispersion along the travel length.

Eastern Gas Pipeline Purge example

Gas was used to purge the Eastern Gas Pipeline (DN 450), a continuous operation between the inlet compressor station at Longford and an intermediate station at Kembla Grange, a distance of 713 km.

Once gas was received, the Kembla Grange vent isolation valve was closed and the pipeline packing operation followed.

The purge operation was designed using the principles and recommendations from GRI-97/0104 Pipeline Purging Principles and Practices Research.

Additional modelling was undertaken using WINFLOW/WINTRAN hydraulic modelling software, licensed to Duke Energy.

The initial study concluded that the additional complexity introduced using a nitrogen slug to separate the air and gas was not justified by the ignition or operational risk – and neither was the use of a batching pig train.

Consequently, design effort concentrated on developing a gas purge procedure.

For purging the pipeline using gas, the key principles are:

The purge gas flow must be continuous:

1. Continuous purge flow is essential when purging with gas – if the gas flow is lost, the mixed gas-air interface volume increases rapidly, primarily through buoyancy driven mixing 
(gas density is approximately half that of air).

For this purge operation, gas supply was assessed as being secure since it was drawn from the Longford Gas Plant delivery pipeline used to supply the Victorian market. Had there been a concern about the supply reliability, the purge design may have been changed to use either positive separation with a pig, or a slug of inert gas.

2. The maximum pressure should not exceed 10 per cent of the pipeline maximum allowable operation pressure (MAOP).

Simulation studies were undertaken to assess the purge performance using controls recommended from the research, namely:

• Purge at constant inlet pressure; and,
• Purge at constant inlet flow.

The constant pressure approach was discarded because the gas supplier advised that the variable flow required through the purge operation was not desirable, and it was considered more difficult to control than simply maintaining a constant flow.

It was decided to vent air at the Mila and Oallen scraper stations (kP291 and kP564 respectively).

This limited the volume of gas mixture discharged at Kembla Grange, while limiting the pipeline pressure and allowing physical tracking of the interface.

The purge process commenced with the pipeline isolation valves at Kembla Grange, Oallen and Mila stations closed, and the pipeline vent valve at Mila open.

Gas was introduced at Longford, and the flow adjusted to 15,000 scm/h (and adjusted as required).

Commissioning staff were located at the Mila vent, equipped with gas detectors.

Once detected, the gas concentration in the vent was monitored until the mixed interface was discharged.

The vent valve was closed and pipeline isolation valve opened, together with the vent valve at Oallen.

The process was repeated until gas was received at Kembla Grange.

The pipeline purge was completed in 32.5 hours.

Once gas was received, the vent valve was closed and gas flow increased to pack the pipeline with the linepack needed to sustain the intended flow rate.

The application PURGE.EXE developed by SWRI is limited to a pipeline length of 999,999 feet, requiring it to be used iteratively. 

Figures 2 to 6 show the output from the purge simulation at an inlet flow of 15,000 scm/h for the 291 km pipeline section between Longford and Mila.

The calculation predicts the mixed gas volume is approximately 5000 ft3 and approximately 5100 ft long, while the prediction shows that the pipeline velocity at the time that the mixed volume reaches the vent is approximately 40 ft/s.

From this, the time for the mixed gas-air volume (from 100 per cent air to 100 per cent gas) to be discharged through the pipeline vent is approximately 127 seconds (2.1 minutes).

Figure 7 presents pressure data taken from supervisory control and data acquisition (SCADA) during the purge, together with the prediction from the SWRI application PURGE.EXE.

The following notes:

• The SCADA pressure measurement at Mila and Oallen did not report pressures higher than 50 kPa (a commissioning error).
• The Mila pressure shows a relatively large pressure drop after gas arrival, once the vent valve is closed and the mainline valve at that site is opened. The effect is reflected at each other measurement point. The effect was not seen at Oallen, probably because of this instrument error.
• The interface arrival time at Mila predicted by the PURGE application (Figure 5) is 700 minutes (11.67 hours). Gas arrived at Mila 11.62 hours after the purge commencing.
• The PURGE application requires a reasonable estimate of the pipeline roughness to reasonably reflect the actual flow. The EGP was a new pipeline, and the construction team applied considerable effort in the drying and cleaning phase to burnish the inner pipe surface. The predicted arrival time assumed a pipe roughness of 20 microns.
• Gas concentration was assessed using portable detectors set to monitor nitrogen (not methane). Gas arrival was reported at the time that the nitrogen concentration started to drop, and 100 per cent gas was reported at the time that the nitrogen concentration was essentially zero. The instruments did not provide data logging capability, so the recorded data reflects human and sampling errors.
• At Mila, 100 per cent gas was reported eight minutes after it was first detected (longer than the 2.1 minutes predicted from the PURGE application). Records at Oallen indicate that the time between first and 100 per cent gas was 15 minutes (unreasonably high, and probably reflects the time taken to complete the valve changeover).

Conclusion – EGP Purge

The EGP purge showed conclusively that, provided a constant gas flow can be guaranteed for the duration of the purge, purging air from a pipeline using gas is simple, predictable and, above all, safe.

It showed that the model PURGE.EXE provided an accurate prediction of the hydraulics during the purge process, and a good estimate of the mixed air-gas volume to be discharged.

This methodology was subsequently used successfully to purge and pack the onshore Tasmanian Gas Pipeline sections and the SEA Gas pipeline.

Purge Planning – Future Pipelines

As mentioned earlier, the application PURGE.EXE is no longer available with the SWRI report, and GRI has advised that there is no intention to revise it for current desktop operating systems.

(Note: The writer is attempting to determine whether SWRI is prepared to update the application).

Transient gas hydraulics applications can be used to predict the interface arrival time provided the model used is carefully developed with an understanding of the computational methodology of the application.

Table 1 illustrates predictions from the application used by the writer (FLOWTRAN) for the Longford-Mila pipe section.

Two purge options are considered to assess the application’s capacity to predict the arrival of the first gas, and purge of the last of the nitrogen:

• The pipe was filled with a simulated air mixture at atmospheric pressure and purged with a typical Longford gas.
• The pipe was filled with nitrogen, and purged with methane.

The calculated first gas arrival shown in the table is the time that the nitrogen concentration falls by 2 per cent from the pre-purge concentration, and the ‘all gas’ arrival is the time that the calculated nitrogen concentration falls to 2 per cent.

The purge was also tracked using the ‘pig tracking’ option in the application, assuming zero slip.

The table shows:

• The pig tracking option provides a good prediction of the arrival of the mid-point in the air-gas mixture when a simulated air mixture is purged with a typical gas mixture. Purging nitrogen with methane under-predicts the mixture arrival time.
• The model significantly over-predicts the mixture volume (approximately 100 minutes, compared with 8-10 minutes). Other transient hydraulic models may calculate the mixture differently and give different results.
• More calculation nodes did not significantly change the predicted arrival time, except that the model with 308 nodes did not calculate the ‘pig’ arrival time.

Conclusion

Purging a new pipeline (or refilling a section of an existing pipeline) using gas without an inert slug or mechanical separation, is a safe and predictable operation which reduces the cost and complexity of the activity.

Transient hydraulic models can be used with care to reasonably predict the arrival time of the gas-air mixture, although they may not provide a reliable estimate of the mixture volume that must be purged.

Designers using these tools should carefully evaluate the model predictions.

Those who have access to an application that can execute Windows XP executable files can also use PURGE.EXE to support the prediction.

Notes:

1. The fully turbulent (plug) flow for this pipe requires a velocity of approximately 1 m/s.
2. The predicted pipeline velocity at the end of the DN 450 pipe section (40 ft/s) suggests that the plume velocity from the DN150 vent will be in the order of 100 m/s – providing significant momentum to propel the mixed air-gas interface well beyond ignition sources.

Sumber: http://pipeliner.com.au/news/pipeline_commissioning_purging_air_with_gas/92260