IGS Piping Guide

8/10/2019 IGS Piping Guide

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4.0CONTENTS TO MODULE 4

.4.1. VALVES4.1.1 Process Valve Types And Applications

4.1.2 Design Features4.1.2.1 Internal Sealing Systems And Materials4.1.2.2 Body/Housing Materials4.1.2.3 External Sealing Systems And Materials4.1.2.4 Actuation of Valves4.1.2.5 Standards of Manufacture4.1.2.6 Quick Closing Valves

4.1.3 Specific Types4.1.3.1 Gate Valves4.1.3.2 Ball/Plug Valves4.1.3.3 Globe Valves4.1.3.4 Butterfly Valves4.1.3.5 Relief Valves4.1.3.6 Check Valves

4.1.3.7 Twin-Seal Valves4.1.3.8 Semi-Needle Valves4.1.3.9 Ball-Check Gauge Glass Valves

4.1.4 Operating Points

4.2. PIPEWORK4.2.1 Applications

4.2.1.1 Process4.2.1.2 Service4.2.1.3 Transportation

4.2.2 Design Features4.2.2.1 Pipe Materials4.2.2.2 Pipe Sizes

4.2.2.3 Methods of Joining Pipe4.2.3 Butt-Welded Systems Fittings4.2.3.1 Reducing Elbow4.2.3.2 Return4.2.3.3 Bends4.2.3.4 Reducer4.2.3.5 Flange4.2.3.6 Tee

4.2.4 Socket-Welded and Screwed Systems4.2.5 Flanged Joints

4.2.5.1 Flat-Face4.2.5.2 Raised Face4.2.5.3 Ring-Type Joint (RTJ)4.2.5.4 Gaskets

4.2.5.5 Line Isolation and Blinding4.2.5.6 Pipe Supports4.2.6 Operation

4.2.6.1 Checks During Operation

4.2.6.2 Maintenance and Inspection

4.3. FLANGES4.3.1 Introduction

Prepare and Arrange by Reza Manafi


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4.3.2 API Classification of Flanges4.3.3 Pressure


4.3.3.1 Test And Working Pressures

4.3.3.2 ASA Flanges4.3.4 Flange Physical Characteristics4.3.5 Flange Make-Up4.3.6 Line Pipe4.3.7 Threading Data for Line Pipe

4.5. PIPELINES4.5.1 Introduction4.5.2 Pipeline Design

4.5.2.1 General4.5.2.2 Liquids Pipelines4.5.2.3 Pressure Drop4.5.2.4 Valves And Fittings4.5.2.5 Heavy Crudes4.5.2.6 Gas Pipelines

4.5.2.7 Allowable Operating Pressure4.5.2.8 Looping4.5.2.9 Two-phase Flow

4.5.3 Sizing Of Pipelines4.5.3.1 Oil Pipelines4.5.3.2 Gas Pipelines

4.5.4 Fouling4.5.5 Pipeline Construction

4.5.5.1 Pipeline Design Codes4.5.5.2 Grades of Steel4.5.5.3 Process of Manufacture4.5.5.4 Seamless Line Pipe4.5.5.5 Furnace Welded Line Pipe4.5.5.6 Electric Welded Line Pipe4.5.5.7 Pipe Diameters4.5.5.8 Pipe End Connections

4.5.6 Pipe Coating and Protection4.5.6.1 Land Pipelines4.5.6.2 Submarine Pipelines

4.5.7 Pipeline Risers4.5.7.1 General4.5.7.2 Flanged Connections4.5.7.3 Hyperbaric Welding4.5.7.4 Subsea Atmospheric Welding4.5.7.5 Mechanical Connectors4.5.7.6 Surface Welding

4.5.8 Pipeline Pigging

4.5.8.1 General4.5.8.2 Pigging Operations4.5.8.3 Launching And Receiving4.5.8.4 Pig Launching And Receiving Procedures4.5.8.5 Pigging Problems


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VALVES

4.1.1 Process Valve Types And Applications

Valves are used in both domestic and industrial situations to control the flow of liquids, solids and gases.The most common and familiarvalves are the taps used in the home to control the hot and cold water. Inthe oil industry, valves are a major element in the control of operations. In general, valves are used forone or more of three main purposes:

1. To control the rate of flow (throttle);

2. To shut off/permit flow (ON/OFF function);

3. To isolate systems and protect products.

There are a wide variety of valve types and designs available from many suppliers in a wide range of

materials; the main types and their uses are

Gate Valve:Used for shut off - ON/OFFfunction.

Ball/Plug Valves:Used for shut off - ON/OFF function

Globe Valves:Used for control of flow and shut off.

Butterfly Valves:Used for control of flow and shut off.

Relief Valves:Spring loaded to open at a given pressure, and used to protect systems from over-pressure.

Check Valves:To allow flow in one direction only.

Fusible Link Valves/Piston Operated Valves:Quick acting and used for emergency shut off.

Twin Sea valves:Used when tight shut off required.

Semi-Needle Valves:Used in conjunction instruments to bleed off part of the flow.

Ball Check Valves:Used with gauge glasses as safety precaution.

There are other less commonly used types of valves.The actual construction/design of gate valves, for example, may vary widely depending on its application,the materials used, or the manufacturers own special features. The basic principle, however, will be thesame.Valves can be specially made to work at high or low temperatures (cryogenic), or to very high standards

for use in explosive atmospheres, or when no leakage is permissible.4.1.2 Design Features

4.1.2.1 Internal Sealing Systems And Materials

All valves are prone to leakage as it is difficult to obtain a perfect seal, although the use of special sealmaterials and designs can have very good result If high security is required, use can be made of twovalves in series, one to act as the main valve and the second as a back-up should the first fail.


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Some valves have bleed holes installed to detect leakage across the seal. If two valves are used together, ableed hole may be fitted in the pipe between them, which can be opened when the valves are closed todrain any leakage.(Block and Bleed valves)


4.1.2.2 Body/Housing Materials

A wide range of materials is used in valve manufacture, the particular material depending largely on thefluids to be handled. Iron and steel are mainly used for oil/petroleum applications with most valves beingmade of mild or alloy steel. Brass valves are used for water (as well as cast iron, steel and other alloys).Stainless steel is used for acids and other corrosive liquids. Bronze is also a commonly used materialwhich can cope with most liquids.

4.1.2.3 External Sealing Systems And Materials

As well as the main seal between valve and disc, wedge, etc. there are other seals required to preventexternal leaks. Gaskets or 0 rings are used between surfaces such as flanges, where no relativemovement takes place. The main problems occur around the valve stem, which both rotates and, in some

cases, moves vertically as well.

Special glands or packings are used which can be compressed by gland nuts to increase sealing. Specialmaterials have to be used in corrosive applications, but an asbestos based fibre is a commonly usedpacking material with PTFE/Teflon being increasingly common. O rings can also be used as shaft sealsand are generally made of rubber.

4.1.2.4 Actuation of Valves

Many smaller valves are hand operated if they are accessible. Larger valves require poweractuators and inaccessible valves of all types require some form of mechanical or electricalactuator. Pneumatic (compressed air) and hydraulic cylinders and mechanisms are widely used inlarger applications. Smaller valves can be operated with solenoids, but larger valves require more

complex motors and mechanisms for electrical power operation.

4.1.2.5 Standards of Manufacture

There are many standards to which valves can be made:

Metric/Imperial dimensions;

British Standards -BS;

German Standards -DIN;

US Standards -ANSI (previously ASA);

American Petroleum Institution - API.

Care must be taken that valves, flanges, etc. and other equipment are compatible, or leakage may occur.API flanges and other equipment are commonly used in the oil industry. The standards lay downperformance requirements as well as dimensions and material. Valves are rated according to themaximum pressure and temperature at which they can safelybe used.


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4.1.3.3 Globe Valves

Purpose Globe valves are used to control flow as they can operate quite safely at part openings. A good

shutoff can also be achieved if required

Operation: Refer to Figure 4.3

When the hand wheel is turned clockwise, the disc is against a seat, stopping the flow. Turning the handwheel anti-clockwiselifts the disc from its seat and allows flow to continue.

The high pressure is usually on the bottom of the plug, so that the stem, seal, etc. are not under continuouspressure. Applications are widespread, including domestic water taps..

.4.1.3.4 Butterfly Valves

Purpose:Butterfly valves are used for controlling flow and can act as a shutuoff ~va1ve, if the sealingarrangement is designed accordingly.

Operation:Refer to Figure 4.4

The disc or wafer rotates about a vertical axis and can be turned through 90. The disc seals against theopening to cut off flow and can be positioned at a point between fully closed and fully open as required.Some butterfly valves have a direct acting lever, others are operated through gearboxes when finer controlis required. In most cases, a clockwise movement will close the valve.

4.1.3.5 Relief Valves

Purpose: Relief valves are used to protect systems from over-pressure or to control processes by allowingflow to commence when a certain pressure has been reached.


force will then release the valve.grinpressure. The sp

A spring holds the valve disc in place against the seat. The valve, therefore, will not open until the forceexerted on the valve disc by the fluid pressure exceeds the force exerted by the spring. When this occurs,flow can take place through the outlet port until the fluid pressure is reduced to below the valve operating

Relief valves operate automatically and are usually pre-set to a specified relief setting by themanufacturers or adjusted when in use, if required. Re-calibration is then required.

4.1.3.6 Check Valves

Purpose: Check valves allow flow in one direction only. One common application is in the dischargeline of a centrifugal pump to prevent reverse suction.

Operation: Refer to Figure 4.6

The two designs operate on the same principle: flow through the valve holds the plug or disc in an openposition. If flow ceases or falls to below the backpressure ahead of the valve, then gravity or the back


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pressure will tend to return the plug to its seat.


Check valves are automatic in action.

4.1.3.7 Twin-Seal Valves

Purpose: Twin-seal valves may be used when an extra tight shut-off is required. They are basically plugvalves, but have an additional action which forces sealing segments against the inlet and outlet portsproviding a positive seal.

Operation: Refer to Figure 4. 7

The opening action consists of two stages:

1. Unsealing the sealing segments.

2. Rotating the plug.

The first stage breaks the seal and retracts the segments from the ports; the second stage allows properflow to begin. Usually 1 to 2 1/2 turns are required to withdraw the segments and a further 1/4 turn torotate the plug.(Up to 2 turns to open the valve.)

4.1.3.8 Semi-Needle Valves

Purpose: Semi-needle valves are used to control instruments and can stand high pressures of up to2,000 psi.


When used with an instrument, the valve should only be opened enough to permit flow and allow theinstrument to register correctly. One or two turns should be sufficient The valve works by pushing aneedle or small rod into a slightly tapered seat When the needle is fully home, then flow is shut off. Therate of flow can be adjusted as required by raising the needle.

4.1.3.9 Ball-Check Gauge Glass Valves

Purpose:These valves are used to prevent loss of liquid and consequent damage or injury, in case ofbreakage of gauge glasses.


When a reading is required, both valves should be opened slowly 1 to 1 1/2 turns to allow the fluid to findits level. The tip of the valve stem prevents the ball from seating at this point As soon as flow stops and

the level stabilises, the valves must be opened fully so that the ball can be pushed into the outer seat bythe escaping fluid if the glass should break. To close or reset the valve, the handle should be turnedclockwise until the valve top is firmly against the inner seat, and then re-opened slowly after the gaugeglass has been replaced, if necessary.


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4.1.4 Operating Points


When using valves, the following points should be observed:

Direction of Flow:Direction of flow is usually marked with an arrow in the case of check valves and

globe valves.

Direction of Opening/Closing:Hand wheels and levers - clockwiseto close, anti-clockwiseto open.

Levers - usually lever in line with pipe - open, lever at 90 to pipe - closed.

Open and close valves slowly.

Valves should always be opened and closed slowly, except in emergencies. Too rapid closing can causepressure waves to build up and travel back through the system, possibly causing severe damage, burst orinjuries. This phenomenon is known as water hammer in domestic water systems and a loud knockingnoise can be heard in the pipe.

Gate and Ball/Plug Valves:Gate and ball valves must only be used in the fully open or closed positions.Intermediate setting can cause turbulence, which can wear away the valve very quickly and cause internalleakage.

Gauge Glass Valves:Gauge or sight glass valves must be fully openedas soon as the fluid has reachedits level or there will be no protection if the glass breaks.

Interlock/Keys: Some valves are not fitted with hand wheels or levers and can only be operated byspecial keys or spanners. This is because the setting of the valve is critical and must not be altered exceptby an authorised person.

Similarly, some valves are sealed with wire; locks or other means and must not be tampered with oraltered as serious damage could result.

Do not Open/Close too far or use unnecessary force.

If gate and globe valves are jammed too far open, they may seize or be damaged. This is calledbackseating and puts unnecessary strain on the disc, which may break off. It is best to re-close gate andglobe valves by 1/2 to 1 full turn after they are fully opened.

Similarly, over-tightening the valve when closing it may damage the disc and seat leading to seizure orleakage.

If valves prove stubborn to open, mechanical assistance such as a valve wrench or spanner can be used.The minimum amount of force should be used and before applying the persuader, check that the valveis not already open.

Do not use persuaders on twin seal valves or on very small valves, which may break off.


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4.2. PIPEWORK

4.2.1 Applications

Pipework is extensively used throughout an offshore installation to move fluids and gases from onelocation to another. It can generally be classified into the following three broad groupings:

4.2.1.1 Process

Used to transport the produced fluids and gases between processing units on the platform.

4.2.1.2 Service

Used to convey air, water, etc. to where it is needed for processing, life support and other services orutility functions.

4.2.1.3 Transportation

Usually large diameter pipelines as used to carry the production products from installation to installationor from the field to the onshore terminal.

Pumps and compressors are used to drive fluids and gases along pipes and valves to route and control thevarious substances and ensure that they are correctly segregated from each other.

The contents of the pipework are carried at widely varying temperatures, pressures and flow rates and,therefore, different types of pipework and associated equipment are required.

Because of the inherent danger in carrying the oil and gas associated with offshore operations, the design,installation, testing and inspection of certain pipework is ngourously controlled to exacting standards, sothat leakage and bursting do not occur.

4.2.2 Design Features

4.2.2.1 Pipe Materials

Pipes are made in a number of materials, the particular one chosen being dependent upon pressure,temperature, resistance to corrosion, cost etc.

The most commonly used is carbon steel and for process work, this is normally of seamless construction.

It is strong, weldable, ductile, and usually cheaper than pipe made from other materials. It can standtemperatures up to 750F and is used whenever it can stand the duty required of it.

Other metals and alloys are sometimes used although they tend to be more expensive. Traditionally, corer

and copper alloys were used for instrument lines although they have largely been replaced by stainless

steel. They are still used for heat transfer equipment because of their high thermal conductivity.

Pipe can be lined or coated with materials such as vitreous substances, to provide resistance to chemicalattack, corrosion, etc.


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GRP(Glass Reinforced Plastic) is commonly used offshore on smaller service/potable water lines.

4.2.2.2 Pipe Sizes

The wall thickness of pipe used is determined by the pipework designer, taking into account the internalpressure, mechanical stresses to which it is subjected (i.e. dead/live loads and expansion stresses), thecorrosion allowance and the safety factor to be applied. Wall thickness is determined in the ANSI systemby Schedule Number, Schedule 40 being the most generally used.

Pipe size is determined by the design requirements of flow rate and head loss. Pipe sizes are identified bythe Nominal Pipe Size (NPS). It is common practice to refer to Nominal Pipe Sizes 0-12 inches diameteras Nominal Bore (NB) and greater than 12 inches diameter as Outside Diameter (OD).

4.2.2.3 Methods of Joining Pipe

There are three main methods of joining pipes together and attaching fittings to them. Lines of 2 inch orlarger are usuallybutt-welded, this being the most economic, leak-proof method. Smaller lines are usuallyjoined by socket-weldingor screwing.

Examples of typical butt-welded, socket-welded and screwed pipe joints are shown in Figure 4. 9

Where larger diameter piping is required to join up with flanged vessels, valves and other equipment, orwhere the line has to be opened for periodic cleaning, bolted flange joints are used instead of butt-welding.These are described more fully later.

4.2.3 Butt-Welded Systems Fittings

Refer to Figure 4.10

Elbows:These are used for making 45 or 90 changes in the direction of the pipe run. Normally

used are long radius, in which the centre line radius of curvature is equal to 1 1/2 times the

nominal pipe size (MPS). Also available are short radius in which the centre line radius of curvatureis equal to the NIS.

4.2.3.1 Reducing Elbow

This makes a change in line size together with a change in direction.

4.2.3.2 Return

A return makes a 180 change in direction and is used in the construction of heating coils, etc.

4.2.3.3 Bends

Bends are made from straight pipe and common bending radii are 3 and 5 times the NIS (indicated by 3Rand SR respectively).


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4.2.3.4 Reducer

This joins a larger pipe to a smaller one.

4.2.3.5 Flange

Refer to Figure 4.10 is a welding-neck flange (the most common type) and a slip-on flange. Flanges arefitted to the ends of pipes, valves, vessels, etc. to enable them to be connected by bolting.

4.2.3.6 Tee

A tee is used to make a 90 branch from a main pipe run. If the branch is smaller than the main run, areducing tee is used.

4.2.4 Socket-Welded and Screwed Systems

Some typical fittings used in socket-welded and screwed systems are shown in Figure 4.11 and Figure

4.12. Their uses are similar to those described for butt-welded fittings.

4.2.5 Flanged Joints

Refer to Figure 4.13. As described earlier, flanged joints are used whenever the pipes, valves, vessels,fittings etc. require to be connected together by bolting for ease of dismantling and reassembly.

This section describes types of flanged joints, which are commonly encountered.

4.2.5.1 Flat-Face

Most commonly used for mating with non-steel flanges on the bodies of pumps, valves, etc. The gasketsused (see Gaskets below) have an outside diameter equal to that of the flange itself. This ensures an evenpressure distribution across the flange and reduces the risk of cracking of cast-iron or bronze flange ontightening or from plant vibration.

4.2.5.2 Raised Face

The raised face is the most common type of flange, in which the gasket covers only the raised faces.

4.2.5.3 Ring-Type Joint (RTJ)

This is a more expensive type of joint, but it is the best type for high temperature, high pressureand corrosive use

4.2.5.4 Gaskets

Gaskets are used to make a tight leak-proof seal between two joint surfaces. For pipe flanges, thecommon types of gaskets are the full-face and ring types which are used for flat-face and raised-face


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flanges respectively.

Gaskets are made from compressed asbestos, asbestos-filled metal (spiral-wound) and other materialsdependent on the conditions to which they are subjected. Spiral-wound gaskets separate cleanly and canoften be re-used. They are useful, therefore, if the joint has to be frequently disconnected.

The finish on the joint faces differs according to the type of gasket to be used. A serrated face is usedwith asbestos gaskets and a smooth face with spiral-wound ones.

Typical gasket materials and their uses are shown in Figure 4.14

4.2.5.5 Line Isolation and Blinding


Frequently, a completely leak-proof means of stopping the flow in a line has to be made. This may bebecause:

The line, or a piece of equipment in it, has to be isolated to allow maintenance work to be carried out;

A change in the process requires that the line be closed.

Valves do not offer complete security, as there may always be some degree of leakage and therefore, theline is closed by one of the following methods:

Spectacle Plate and Line Blind:The spectacle plate can be changed over quickly without disturbing thepipework and gives immediate visual evidence of whether the line is open or blinded. it is generallypreferable to the simple line blind which is only used where frequent changing is not required.

Line Blind Valve:This allows a line to be quickly and simply blinded by a process operator. There aremany types, but a typical one, a spool type line blind, is shown in Figure 15 on page4/28.?

Removable Spool and Blind Flanges:This method involves removing a complete section of the linebetween two flanges (the spool) and fitting blind flanges to close the two ends of the line. This gives avery positive visual indication that the line is closed. Blind flanges are used to close any pipe end, vesselentry, etc.

4.2.5.6 Pipe Supports


Methods of supporting pipework vary greatly, but a selection of some of the more common is covered inthis section.Support:The term support refers to any device used to carry the weight of the pipework. Supports areusually made from structural steel.

Hanger: A hanger is a particular type of support by which pipework is suspended from a structure.Hangers are usually adjustable for height

Anchor: An anchor is a rigid support, which prevents transmission of movement along pipework.

Tie: An arrangement of rods, bars, etc. to restrict movement of pipework.


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Dummy Leg: An extension piece of pipe or steel section welded to an elbow.


Guide or Shoe: A means of allowing a pipe to move along its length whilst restricting its lateralmovements.

4.2.6 Operation

4.2.6.1 Checks During Operation

The operation of a piping system is dictated by the operation of the equipment, which it connects.Nevertheless, care must be taken at all times to ensure that

The piping is not operated beyond its design range of pressure and temperature;

All joints are checked regularly for leaks and any leaks discovered are reported immediately;

The piping is correctly isolated and purged, if necessary, before any maintenance work is

performed on it;

Line markings are clearly visible and re-made if not;

Any abnormal vibration, damage, missing supports, etc are reported immediately.

4.2.6.2 Maintenance and Inspection

Legislative and other statutory requirements dictate the type and frequency of maintenance and inspectionrequired on piping systems installed on offshore Installations. This maintenance and inspection isnecessary to ensure that the Certificate of Fitness of the installation in question remains valid. The

responsibility for ensuring that these requirements are met does not lie with the process operator.However, he will be involved in isolating. purging, etc. at the time the maintenance and inspection arecarried out.


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4.3. FLANGES

4.3.1 Introduction

Flanges are normally used to connect sections of pipe, valves, vessels or other fittings by forming a sealwith either a ring or flat type gasket. They are assembled with stud bolts, which when tightened, force thetwo flange faces towards each other on the gasket to form a pressure tight seal. Flanges in the oil industryare classified according to their construction, pressure rating and diameter.

The two classifications of flanges are:

1. ASA (ANSI) American Nation Standards Institute.

2. API American Petroleum Institute

4.3.2 API Classification of Flanges

There are three common types of API flanges: API 2000,3000,5000 and there are two high pressureseries, API 10,000 and 15,000. The number of the series indicated corresponds to the maximum workingpressure expressed in psi at a temperature of l00F.

This maximum working pressure is affected by temperature. The maximum working pressure of theflange will be reduced by a factor of 1.8% for each 50 F increase in temperature above 100F to amaximum of 450F. The following table gives the maximum working pressure as a function oftemperature.

TemperatureF

Maximum Working Pressure in PSIAPI 2000 API 3000 API 5000 API 10000 API 15000

100 2000 3000 5000 10000 15000150 1964 2946 4910 9820 14730200 1928 2892 4820 9460 14460250 1892 2838 4730 9280 14190300 1856 2784 4640 9199 13920350 1820 2730 4550 8929 13650400 1784 2676 4460 8740 13380450 1748 2622 4370 8560 13110


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4.3.3 Pressure Ratings


4.3.3.1 Test And Working Pressures

The hydrostatic test pressure is equal to twice the maximum working pressures for flanges of diameterbelow or equal to 14 inches. The test pressure is equal to 1.5 times the maximum working pressure forflanges of diameter equal to or greater than 16 inches.

Series API Maximum Working

Pressure (p.s.i.)

Test Pressures for

flanges of 14 & less

(p.s.i.)

Test Pressure for

Flanges above 16

(p.s.i.)

2000 2000 4000 3000

3000 3000 6000 4500

5000 5000 10000 7500

4.3.3.2 ASA Flanges

With the exception of the ASA 150 series, the number corresponds to the maximum working pressure ofthe flange in psi at a temperature of 85OF for carbon steel flanges.

To obtain the working pressure of the flange at temperature from 20 to + 100F, the number is multipliedby 2.4. For example:

ASA 300 Max WP = 2.4 x 300 = 720psi

ASA 900 Max WP = 22.4 x 900 =2160psi

The following table gives the working pressures of all flanges in this classification. The hydrostatic testpressure is equal to 1.5 times the working pressure at 100F.

Class A.S.A

Max. Working Pressure

-20F to 100F

Test Pressure

-20F to 100F

150 275 425

300 720 1100

400 960 1450

600 1440 2175

900 2160 3250

1500 3600 5400

2500 6000 9000

2900 10000 15000

4.3.4 Flange Physical Characteristics

To avoid any confusion when describing or ordering flanges, the following information should be given:

1. Type ASA or API;


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2. Description of connection:

a) Weld neck flange

b) Slip on welding flange

c) Threaded flange

d) Blind flange.

3. Nominal diameter;

4. Number in ASA or API classification;

5. Type of face and gasket;

5. Bore if necessary;

7. Type of steel used for manufacture.

4.3.5 Flange Make-Up

To ensure that the flange will form a good seal, care should be taken when making them up. The studsshould first be made hand tight with the faces of the flanges parallel to each other. The studs should thenbe gradually tightened in the sequence shown in the diagram below.

4.3.6 Line Pipe

Line pipe is required by the oil and gas industry to convey oil, gas, water, chemicals, etc. in its operations.

The API with cooperation of the American Gas Association has developed specifications meeting theneeds of the oil and gas industry for steel and wrought-iron line pipe and published these in API standards5L and 5LX. These provide standard dimensions, strengths and performance properties and the requiredthread gauging practice to ensure complete interchangeability.


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4.5. PIPELINES

4.5.1 Introduction

Pipelines are the most common means of transporting oil or gas.

A pipeline is like any other flowline. The main differences are that pipelines are long and continuouslywelded, they have a minimum number of curves, they have no sharp bends, and they are most often eitherburied or otherwise inaccessible due to their location over the majority of their length.

These differences mean that small sections of pipeline are not easily removed for maintenance andconsequently great care is taken to prevent problemsarising in the first place.

A pipeline is extremely expensive to lay, and in the case of offshore pipelines, costs in the order ofseveral million pounds per subsea mile have been encountered.

Maintenance on pipelines is also expensive but this expenditure is necessary since, regardless of theexpense, pipelines frequently form the most efficient and cost-effective method of transporting thequantifies of oil or gas produced. Pipeline sharing agreements may result in the flow from a number of oilfields being transported through a single pipeline. A problem in a pipeline of this type can mean the shut-down of all of these fields with a resulting operating loss of several million pounds per day.

Thissituation can be further aggravated for gas production to gas consumer companies where theproducing company can not only lose operating revenue but can incur fines for failing to fulfillcontractual obligations.

4.5.2 Pipeline Design

4.5.2.1 General

When designing a pipeline, the engineer considers the following factors:

The physical and chemical propertiesof the fluid, or to pumped through the pipeline;

The maximum volume of fluidthat will be pumped through the pipeline at any time during the life ofcurrent and future developments likely to be served by the pipeline.

The nature of the environmentthrough which the pipeline is going to traverse.

The required delivery pressure.

More specifically the engineer considers

Pipe diameter required.(The larger the diameter of the pipeline, the more fluid can be moved

through it, assuming other variables such as pump capacity are fixed.)

Pipe length.(The greater the length of a segment of pipeline, the greater the total pressure drop.

Pressure drop can be the same per unit of length for a given size and type of pipe but total pressure

drop increases with length.)

Specific gravity and densityof the fluid to be transported, (The specific gravity and density of thetransported fluid will affect the potential amount of mass flow available.)


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Compressibility. (Because most liquids are only slightly compressible, this term is not usuallysignificant in calculating liquids pipeline capacity at normal operating conditions. In gas and gasliquids (mixtures of methane, ethane, propane, butane, etc, transported as a liquid) pipeline design,however, it is necessary to include a term in many design calculations to account for the fact thatgases deviate from laws describing ideal gas behaviour under conditions other than standard or base

conditions. This term, supercompressibility factor, is very significant at high temperatures andpressures. If in the pipeline, pressure is likely to be in the order of 1000 to 2000 psig then this termmust be included.)

Operating temperatures and ambient temperatures: (Temperature affects pipeline capacity bothdirectly and indirectly. In natural gas pipelines, the lower the operating temperature, the greater thecapacity, assuming all other variables are fixed.

Operating temperature also can affect other terms in equations used to calculate the capacity of bothliquids and natural gas pipelines. Viscosity, for example, varies with temperature. Designing apipeline for heavy (viscous) crude is one case in which it is necessary to know operating temperaturesaccurately to calculate pipeline capacity. The possibility of water freezing and of hydrate formation ingas pipelines are other temperature considerations.

Viscosity:(The property of a fluid that resists flow or relative motion between adjacent parts of thefluid is viscosity. It is an important term in calculating line size and horsepower requirement when

designing liquid pipelines).

Pour Point (The lowest temperature at which an oil will pour, or flow, when cooled under specific

test conditions is the pour point. oils can be pumped below their pour points, but the design and

operation of a pipeline under these conditions presents special problems.)

Vapour Pressure.(The pressure that holds a volatile liquid in equilibrium with its vapour at a given

temperature is its vapour pressure; whenpage 73 determined for petroleum products under specific test conditions and using specificprocedures it is called the RVP (Reid Vapour Pressure). Vapour pressure is an especially importantdesign criterion when handling volatile petroleum products such as propane or butane.

The minimum pressure in the pipeline must be high enough to maintain these fluids in their liquid state.

Reynolds Number, which is a dimensionless number, which is used to describe the type of flowexhibited by a flowing fluid. In streamlined (or laminar) flow, the molecules move parallel to theaxis of flow. In turbulent flow, the molecules move back and forward across the flow axis. Othertypes of flow are also possible and the Reynolds number can be used to determine which types offlow are likely to occur under specified conditions. In turn, the type of flow exhibited by a fluidaffects pressure drop in the pipeline. Strictly speaking. a Reynolds Number below 1000describes streamlined flow.

At Reynolds Numbers between 1000 and 2000 flow is unstable. At Reynolds Numbers greater than 2000flow is turbulent These figures are not always used. In general usage, how is considered laminar forR


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Absolute pressure is the pressure of a pipeline or vessel above a perfect vacuum and is abbreviated bara.Gauge pressure is the pressure measured in a pipeline or vessel above atmospheric pressure and isabbreviated barg. Standard atmospheric pressure is usualIy considered to be the head pressure of 760 mmof mercury, but atmospheric pressure varies with elevation above sea level. Many contracts for thepurchase of natural gas, for instance, specify that the standard, or base, pressure will be other than

760mm/kg.

Formulas describing the flow of fluids in a pipe are derived from Bernoullis theorem and are modified toaccount for losses due to friction. Bernoullis theorem expresses the application of the law of conservationof energy to the flow of fluids in a conduit To describe the actual flow of gases and liquids properly,howeyer, solutions based on Bernoullis theorem require the use of coefficients that must be determinedexperimentally.

As a basic rule, the amount of flow along a pipeline (or across any restriction) will be a function of thedifferential pressure. The basic equation is:

%Q = % Dp x 10

where:

0= Flow (In %)

Dp = Differential pressure (in %)

The theoretical equation for fluid flow neglects friction and assumes no energy is added to the systems bypumps or compressors. Of course, in the design and operation of a pipeline, friction losses are veryimportant, and pumps and compressors are required to overcome those losses. So practical pipeline designequations depend on empirical coefficients that have been determined during years of research andtesting.

The basic theory of fluid flow does not change. But modifications continue to be made in coefficient asmore information is available, and the application of various forms of basic formulas continues to berefined. The use of computers for solving pipeline design problems has also enhanced the accuracy andinflexibility possible in pipeline design.

4.5.2.2 Liquids Pipelines

In the design of liquids and natural gas pipelines, pressure drop, flow capacity and pumping orcompression horsepower required are key calculations. The design of a liquids pipeline is similar inconcept to the design of a natural gas pipeline. In both cases, a delivery pressure and the volume thepipeline must handle are known. The allowable working pressure of the pipe can be determined using thepipe size and type and specified safety factors.

In most pipeline calculations, assumptions must be made initially. For instance, a line size may beassumed in order to determine maximum operating pressure and the pressure drop in a given length ofpipe for a given flow volume. If the resulting pressure drop, when added to the known delivery pressureexceeds the allowable working pressure, a larger pipe size must usually be chosen.

It may be possible to change the capacity and spacing of booster pumping stations to stay withinoperating pressure. But in the simplest case, if the calculation yields an operating pressure greater thanallowed, a larger pipe size must be selected and the calculation repeated.

It is apparent that many options are available in even a moderately complex pipeline system. But todays


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computer programs for pipeline design can analyze many variables and many options in a short time,greatly easing the design process.


4.5.2.3Pressure Drop

An equation for the flow of liquids in a pipe was developed by Darcy in the early 18th Century and theequations, formulae and standards defined by Dary are still valid today.

The Darcy equation can be derived mathematically (except for a friction factor which must be determinedby experiment) and can be used to calculate for laminar and turbulent flow of liquid in a pipe.

4.5.2.4 Valves And Fittings

In addition to the pressure loss due to fluid friction with the walls of the pipeline, valves and fittings alsocontribute to overall system pressure loss. The pressure loss due to a single valve in several thousand feetof straight piping will be insignificant but in a pumping station, for example, where many valves exist andmany changes in flow direction occur, pressure loss in valves and fittings is important Pressure loss in

valves and fittings is made up of both the friction loss within the valve or fitting itself and the additionalloss upstream and downstream of the fitting above that which would have occurred in the absence of thefitting. Calculation of the pressure loss in a valve or fitting is based on experimental data. One approach isthe use of a resistance factor for a given valve or fitting. The resistance coefficient is normally treated as aconstant for a given valve or fitting under all flow conditions.

Another term used in determining the pressure drop through valves and fittings is the flow coefficient, CvThe flow coefficient of a valve is the flow of water at 6OF, in gal/min, at a pressure drop of one psiacross the valve. The flow coefficients of any other liquid can be calculated using the relation of itsdensity to that of water.

4.5.2.5 Heavy Crudes

Some crudes with very high pour points or high wax contents that require pipelines of special designPipelining such crudes can be especially troublesome offshore where heat loss to the water is greatand any heat added to the crude before it enters the pipeline is dissipated within a short distanceif a conventional pipeline is used. If the crude cools, excessive wax deposits in the pipeline canlower operating efficiency. In cases of extremely viscous crudes, flow can even be halted if thetemperature is allowed to fail too low. Not only is the baiting of flow a problem, but restartingflow after such an occurrence can be difficult

To handle these special crudes, pipelines have been successfully installed and operated simply byinsulating the pipelines, but other approaches include:

Heating the crude to a high temperature at the inlet to the pipeline, allowing it to reach its n destinationbefore cooling below the pour point (The pipeline may or may not be insulated);

Pumping the crude at a temperature below the pour point using high pressure pumps;

Adding a hydrocarbon dilutant such as a less waxy crude or a light distillate;

Injecting water to form a layer between the pipe wall and the crude;

Processing the crude before pipelining to change the wax crystal structure and reduce pour point andviscosity.

Mixing water with the crude to form an emulsion; Processing the crude before pipelining to change


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the wax crystal structure and reduce pour point and viscosity;


Heating both crude and pipeline by steam tracing or electrical heating;

Injecting wax solvents such as benzene or toluene.

A combination of these methods can alsobe used and the choice of method will depend upon the physicalproperties of the crude and the economics of its production.

If waxy crude is pumped below its pour point, more pumping energy is required and, if pumping isstopped, more energy will be required to put the crude in motion again than was required to keep itflowing.

When flow is stopped wax crystals form, causing the crude to gel in the pipeline.The wax in crude whichis being pumped at temperatures above its pour point will form cohesive lattice structures if it is allowedto cool down to below its pour point whilst stationary. Experiments have shown that restart pressures canbe five to ten times higher for a pipeline that was above the pour point and cooled after shut-down thanfor one that was below its pour point before shut-down.

4.5.2.6 Gas Pipelines

Several formulae can be used to calculate the flow of gas in a pipeline. These formulas account for theeffects of pressure, temperature,pipe diameter,pipe length, specific gravity, pipe roughness and gasdeviation.

The Darcy equation can also be used in flow calculations involving gases but it must be done with careand restrictions on its use are recommended. If, for instance, pressure drop in the line is large relative tothe inlet pressure, the Darcy equation is not recommended. Because this is often the case and becauseother restrictions also apply to its use in gas flow calculations, other more practical equations arecommonly used for gas flow calculations.

4.5.2.7 Allowable Operating Pressure

An important pipeline design calculation is the maximum pressure at which a given size, grade andweight of pipe may operate.

Maximum operating pressure determines how much a pipeline may carry . Other factors being fixed anddepends on the physical and chemical properties of the pipe steel. Since standard pipe grades, sizes andweights are normally used, the maximum operating pressure can usually be obtained from tablescontained in recognised specifications.

4.5.2.8 Looping

This is the term used when laying a pipeline parallel to an existing line in order to increase the totalcapacity throughput.

4.5.2.9 Two-phase Flow

The combined flow of oil and gas in a pipeline presents many design and operational difficulties notpresent in single phase liquid or vapour flow. Frictional pressure drops are harder to estimate.


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Liquid is likely to gather at low points in the pipeline and reduce the pipeline capacity to a point whenslugs of liquid are pushed ahead by the gas.

The movement of large liquid slugs along the pipeline can cause additional pipeline stresses and thepipeline terminal facilities must be designed to receive such volumes of liquid by provision of large,

specially designed vessels or energy absorbing pipework, known as slug-catchers.

The type of flow in a pipe is known as its flow regime. We have already come across laminar andturbulent flow regimes. These are single phase flow regimes and which phase will exist can be found bycalculating the Reynolds number.

Pipelines are seldom horizontal, as they have to follow the undulations of the seabed or the countryside,and often have vertical sections as they rise to join platforms or enter process streams.

In view of this, flows regimes can exist which are considerably more complex than those alreadydiscussed.

The key difference between single-phase flow and two-phase flow is that it is much more difficult todetermine pressure drops for two-phase flow. This is complicated if you consider that a difference in

incline of several degrees, never mind 90; can change entirely the nature of the flow regime.

Undulating terrain will generally not be a problem for single-phase pipelines; however, it can materiallyaffect pressure drop in two-phase pipelines if there are a large number of. rises and falls, which thepipeline must cross.

Some two-phase regimes are caused by liquid condensation or fall-out from the gas due to reducing

temperature and pressure along the length of the pipeline. For onshore gas lines liquid knock-outs can be

provided at intervals such that liquids can be drained off by blow-down of the line.

Well flow lines often work in a two-phase regime, particularly because the well fluids usually containboth oil and gas and there may be no facility at the wellhead (E.g. at sub-sea wells) prior to the fluidreaching the gathering station (or platform).

Despite the problems associated with the prediction of two-phase estimates, more and more pipelines arebeing designed for such flow systems.

For example when hydrocarbon condensate is separated from the gas at offshore platforms, it is invariablyspiked back into the gas for transport to the shore in the pipeline. This is mainly because te economicswould not support a separate line for condensate sales.

Several empirical flow patterns have been presented that determine vapour/liquid flow as a function offluid proportions and flow rates. Diagrams of these flow patterns are shown Figure 4.27.

Care should be taken in the interpretation of these diagrams, as the regime boundaries of bubble, slug,annular, mist and wave conditions are strongly affected by pipe inclination. Even very low pipeinclination of one or two degrees can cause considerable movement of the regime boundaries and, inaddition, adjustment has been observed due to fluid pressure, pipe diameter and surface tension.

In both vertical and horizontal directions, the avoidance of slug flow is desirable. Slug flow mightpossibly be avoided by choice of a smaller pipe diameter. This will increase fluid velocities and reducethe pipeline liquid inventory.


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4.5.3 Sizing Of Pipelines

4.5.3.1 Oil Pipelines

Pumping a specified quantity of a given oil over a given distance may be achieved by using a largediameter pipe with a small pressure drop, or small diameter pipe with a greater pressure drop.

The first alternative will tend to a higher capital cost with lower running costs. It is necessary to strike aneconomic balance between these two.

There are no hard and fast rules, which can be laid down for achieving this balance. For instance, apumping station in a populated area may consist of a simple building, involving the provision ofelectrically driven pumps, taking power from outside sources and little else. To obtain the same pumpingpower in remote or undeveloped countries would involve a considerably more complicated and expensiveinstallation. Obviously in this latter case, it is desirable to reduce the number of pumping stations at thecost of using larger diameter piping.

Similarly, the cost of the pipeline will vary considerably, depending upon circumstances. It will be costlyin highly industrialised areas, environmentally sensitive areas, offshore or in hostile, mountainous orswamp areas; cheaper in flat, soft but firm, undeveloped terrain.

4.5.3.2 Gas Pipelines

Sizing problems encountered in gas lines differ considerably from those of oil lines. A simplificationresults from the negligible weight of the gas as the pressure in the line is virtually independent of theground elevation on the other hand, the compressibility of gas introduces the complication of the densitydecreasing and consequently the volume rate of flow increasing in the direction of flow. In an oil line ofconstant diameter laid on level ground, the pressure decreases uniformly with distance and the velocitystays constant whereas, in a gas line, the velocity increases as the pressure gradient decreases with an

exponential, which becomes progressively steeper.

The characteristics of pumps and compressors also determine the site of any pipeline booster stations aswell as the initial pipeline conditions which have to be met Pumps need to be sited in positions wherethey are receiving the crude oil at a pressure greater than the vapour pressure of the crude oil, whereascompressors have to be sited at a location where both the pressure and velocity of the gas are at optimumconditions.

4.5.4 Fouling

The deposition of paraffin, salt or scale on flowline wells can materially reduce the cross-sectional area ofthe pipe and severely restrict flow.

Paraffin can usually be removed by scraping or by pumping hot oil or condensate through the lines. Saltand/or scale similarly may require removal by a pipeline scraper pig, or in some cases by chemicaltreatment. These factors should be carefully considered when designing and sizing the flowlines. If eitherof these factors are suspected, it may be wise to weight the estimated cleaning frequency with the cost ofinstalling slightly larger pipelines.


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4.5.5 Pipeline Construction


4.5.5.1 Pipeline Design Codes

Most of the codes of practice are derivatives from studies conducted by the American Society of

Mechanical Engineers (ASMIE) and the American Standards Association (ASA), which later changed itsname to the American National Standards Institute (ANSI).

The UK Pipeline Safety Code is Part 6 of the IP Model code of Safe Practice in the Petroleum industry,which includes and takes note of the British Standard Code of Practice for Pipelines, BS CP 2010, whichrelates to pipeline construction in the UK.

Gas distribution lines up to a working pressure of 70 bar are adequately covered by the Institution of GasEngineers series Recommendations on Transmission and Distribution Practice. The IIP Code does notclaim to be a design handbook and does not replace the need for appropriate experience and engineeringjudgment.

The IP Code of Practice sets forth general requirements for the safe design, construction and operation ofpipelines for the conveyance of petroleum (crude oil and liquid products) and gas (natural gas and

gaseous products).

It specifies considerations for pipe materials, flanges fittings and valves etc.

Submarine pipelines are designed to internationally accepted codes, such as in Norway the Det Norske

Veritas Rules for the Design, Construction and Inspection of Submarine Pipelines and Pipeline Risers.

By definition pipelines normally start at the scraper launcher and ends at the scraper receiver or slugcatcher.

It should be remembered that wherever national codes are more stringent than internationally acceptedcodes, the national codes must take precedence.

4.5.5.2 Grades of Steel

The pipe from which flow lines and pipelines are constructed is known in the oil industry as 1ine pipe.As with casing and tubing, line pipe is manufactured from different grades or strengths of steel and indifferent wall thickness to enable economical as well as safe design. The physical properties of thevarious grades of steels used in the manufacture of most of the line pipe of importance to the industry areset out in API Standards.

The requirement for high pressure, large diameter, cross-country, oil and gas transmission lines developeda need for a high strength, field weldable steel. As a result, API grades X-42 through X-65 with yieldstrengths of 42,000 psi to 65,000 psi were developed. These higher strength steels are available for useunder the requirements of the IP Code.

The higher working pressures resulting from the use of the higher strength steels enable a substantial

saving in steel tonnage and can be economical in use.

Submarine pipelines are subject to external stresses not considered so far in our discussions. In addition tohydrostatic pressure due to immersion depth, the motion of the sea introduces currents and swell andpossibly thermal stress. During and after laying greater consideration must be given to the weight andcurvature of the pipe.


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4.5.5.3 Process of Manufacture

Three different processes are used to manufacture pipe that is used for line pipe. The properties andcapabilities of the pipe vary with the type of process used.

4.5.5.4 Seamless Line Pipe

Seamless pipe is generally the industries first choice for high-pressure flow lines and pipelines.

Seamless pipe is a wrought steel tube without a welded seam, manufactured by hot working steel and, if

necessary, subsequently cold finished to produce the desired properties.

Generally speaking, seamless pipe is preferred by the oil industry for use in well flow lines and other highpressure lines, although welded pipe described below is similarly used for high pressure lines in largersizes where seamless pipe is not available. Availability is limited to a maximum diameter of about 20inches because of the process of forming seamless pipe.

4.5.5.5 Furnace Welded Line Pipe

About the only type of furnace welded pipe available today is manufactured by the continuous welding,

butt-weld process.

In the butt-weld process, pipe is manufactured with one longitudinal seam formed by mechanical pressureto make the welded junction after the entire steel strip from which the tube is formed has been heated toproper welding temperature.

The cost of the CW, continuous weld, butt weld line pipe is 15 to 20% lower than Grade B seamless orelectric weld line pipe.

4.5.5.6 Electric Welded Line Pipe

Electric welded pipe has one longitudinal seam formed by electric flash welding, electric resistancewelding or electric induction welding without the addition of extraneous metal. There is probably morepipe manufactured by the electric weld process than any other method because of the low initialinvestment for the equipment and the adaptability to different wall thicknesses. Most electric weld linepipe is not fully normalised after welding. Some is normalised in the weld zone only. Therefore, there is aheat runout zone on each side of the weld resulting in non-uniformity of hardness and grain structure.

Like furnace weld, electric weld is not recommended for use where internal corrosion is expected.Electric weld is the same price as seamless when made from the same grade of steel with the same wallthickness.

4.5.5.7 Pipe Diameters

Steel pipes are referred to according to their nominal inside diameter up to 12 in. Pipes of above 12diameter are usually identified by their outside diameter (OD). All classes (weights) of pipe of a givennominal size have the same OD, the extra thickness for different weights being on the inside.


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Some operators favour flanges, while others favour hyperbaric welding. The advantage of flanges is thatthey permit easier repairs in the event of pipeline/riser damage or corrosion. There have been somereports of leaks and they can take a long time to locate. But this is not generally regarded as a major factorfor eliminating flanges.

4.5.7.3 Hyperbaric Welding

Hyperbaric welding is conducted in an inlet atmosphere (nitrogen, argon or helium) at pressures relativeto the depth of water. It has been used mostly for pipeline-riser tie-ins in the deep waters of the North Sea.

The hyperbaric work chamber and alignment frame are normally handled by a pipe-lay barge, a derrickbarge or a large work vessel.

4.5.7.4 Subsea Atmospheric Welding

Subsea atmospheric welding is carried out inside a caisson, which is maintained at atmospheric pressureon the seabed. The gas within the caisson may be air, nitrogen, helium or argon, depending upon weld

specification. Higher-quality welds can be obtained than those obtained under hyperbaric weldingconditions.

An alternative system consists of a habitat chamber, which is a permanent part of the platform and intowhich pipe is pulled.

After pipe is pulled into the chamber, the chamber is sealed and pumped dry.

4.5.7.5 Mechanical Connectors

Mechanical connectors clamp two pipe ends together without the need for welding.

4.5.7.6 Surface Welding

The surface welding method is used for simultaneous installation of a pipeline and riser. It ismost widely employed for pipelines up to about 30 in. diameter and in water depths to about 350ft.

In this method, pipe is first laid on bottom near the platform. The lay barge lifts the pipe to the surfaceusing davits, buoyancy devices, or both. A carefully planned pick-up procedure is used so that pipe issafely lifted without over-stressing. The riser is then set into position next to the platform leg and clampsare installed to fasten the riser to the platform legs.

4.5.8 Pipeline Pigging

4.5.8.1General

Pipeline pigs and spheres are used for a variety of purposes in both liquids and natural gas pipelines.Pigs and spheres are forced through the pipeline by the pressure of the flowing fluid. A pig usuallyconsists of a steel body with rubber or plastic cups attached to seal against the inside of the pipeline and toallow pressure to move the pig along the pipeline. Different types of brushes and scrapers can be attached


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to the body of the pig for cleaning or to perform other functions. Figure 4.28 illustrates a variety ofpipeline pigs.


Pipeline pigging is done for the following reasons:

To clean up pipelines before use (foam pigs);

To fill lines for hydrostatic testing, dewatering following hydrostatic testing, and drying and purgingoperations (spheres and foam pigs);

To periodically remove wax, dirt and water from the pipeline (scraper pigs and brush pigs);

To sweep liquids from gas pipelines (spheres)

To separate products to reduce the amount of mixing between different types of crude oil or refinedproducts (squeegee pigs and Go-Devil pigs);

To control liquids in a pipeline, including two-phase pipelines (spheres and foam pigs);

To inspect pipelines for defects such as dents, buckles or corrosion (intelligent-pigs or caliper pigs).(Figure 4.29illustrates a caliper pig.)

Differential pressure is required to move a pig or sphere through the pipeline. The force required depends

on elevation changes in the pipeline, friction between the pig and the pipe wall and the amount of

lubrication available in the line. (A dry gas pipeline provides less lubrication tan a crude oil pipeline, for

example).

Cups are designed to seal against the wall by making them larger than the inside diameter of the pipe. Asthe cups become worn, the amount of blow-by fluid by-passing the pigs increases because the seal is notas effective.

In the case of spheres, a certain amount of over-inflation is required to provide a seal. (In two-phasepipelines, spheres are sometimes under-inflated to allow some blow-by to lower the density of the fluidahead of the sphere).

Pigs and spheres travel at about the same velocity as the fluid in the pipeline and travel speed is relativelyconstant.

4.5.8.2 Pigging Operations

Pigs are used in all types of pipelines to increase efficiency and avoid problems at pump or compressorstations that could result from the presence of unwanted materials. Brushes and scrapers on a cleaning pigremove dirt and scale from the pipeline walls. Brush and scraper pigs feature longitudinal boles, whichpass through the body of the pig. The holes allow a flow of fluid through the pig to prevent the build-upof wax or debris in front of the pig.

A pig can remove very large amounts of debris if it is run over a long distance.

For example, assume a pig is run in a 24 in. pipeline, 100 miles long, and removes 0.016 in. of waxmaterial from the wall of the pipeline. After 100 miles, a plug about 1,450 ft long would form. For thisreason, pipelines are operated to very definite pigging programmes.

Pipelines are often pigged first during testing following construction. Most pipelines are tested with water(hydrostatic testing) either in sections or over the entire length. A foam pig or pigs is normally sent aheadof the water when filling the test section to prevent mixing the test water with air in the line. Internally


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met within the system. Figure 4.33illustrates the logic of a simple interlock system.


In the last decade at least two launchers have been involved in major explosions in Britain.

When pigs are launched into a pipeline there is always the possibility that the pig will stop or reduce theflow of fluid through the pipeline. The most common incidents and their causes are:

The pig fails to launch (this only becomes apparent alter the launch procedure is at its final stages. Thepossible causes are:

1. The pig is too small (wrong pig or under- sized) and the flow cannot pick up the pig in the launcherbarrel.

2. The pig is too large, wrong pig or oversized and it is jammed in the exit to the launcher.

3. The pig is too far back in the launcher.

The pig indicator, Figure 4.35should show that the pig has launched. They are, however, not alwaysreliable.

The pig is launched successfully but fails to arrive on time with no major changes in pipeline pressures orflows. The possible causes are:

1. The pig is too small (wrong size) and cannot climb the riser into the receiver.

2. The pig has disintegrated into its component parts.

3. The pig is hung on a bend and the cups have flipped forwards to allow full flow.

The pig is launched successfully but fails to arrive on time and there is an increase in pipeline pressuredrop in pipeline flow. The possible causes are:

1. The pig has hung up on a bend or T piece (pig is too long for bend radius).

2. The wrong size of pig was launched (too large in diameter).

3. The pipeline has been dented and the pig is stuck at the damaged section.

The pigs leap-frog each other in the pipeline; (usually foam pigs). The possible causes are:

1. The operator launched them 1, 3, 2 but did not realise (most common);

2. The front pig hangs up on an obstruction and is only cleared by the second pig rolling over it.

Spheres arrive with huge chunks missing. The most likely cause is that the launcher valve has taken a biteout of the sphere as it was launched.

Launcher valves are often half-cup ball valves, which rotate through 180 to launch the sphere. Oversizedspheres hang over the side of the cup and are sliced as the cup rotates.

Pigs and spheres go into by-pass lines, junction T pieces or other pipelines. Operator error or processupsets may often create situations where the sphere or pig can deviate from its normal path. In one knowninstance a 28 diameter neoprene sphere travelled into a 12 diameter pipe for some considerable distancebefore flow was stopped.

Whatever the Causes of pigging problems, the effects can be severe and in some instances thepipeline has had to be cut out to remove the offending pig.


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Documents

IGS Piping Guide