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Copyright 2001 Scientific Surveys Ltd. All rights reserved. 1

Basic operational pigging proceduresfor rigid and non-rigid pigsby P Wilson

1, G Smith

2, R. Craig Tucker

3, and F T Connor

3

1H. O. Mohr & Associates, USA

2Knapp Polly Pig Inc,USA

3PHE Company Inc

Contents of this Paper:

Introduction

Definitions

Pipeline hardware

Pig launchers and receivers

Barrel receiver

Sphere launchers and receivers

Pigging during commissioning

Gauging

Cleaning

Dewatering

Drying

Hydrate removal

Paraffin removal

Two-phase flow

Pre-inspection cleaning

Magnetic flux leakage inspection pigs

Ultrasonic inspection pigs

Subsea applications

References

Figure 1: Batching/displacement cup pig Figure 2: Flexible brush cleaning pig

Figure 3: Batching pig (cup type)

Figure 4: Foam pigs

Figure 5: Inflatable sphere

Figure 6: Bi-directional pig

Figure 7: Blade cleaning pig (scraper pig)

Figure 8: Wire brush pig

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Pipeline Pigging and Integrity Monitoring Conference: Houston, 1990

2 Copyright 2001 Scientific Surveys Ltd. All rights reserved.

Figure 9: Examples of pig trains

Figure 10: Pig launcher for liquid and gas lines

Figure 11: Pig receivers for liquid and gas lines

Figure 12: Sphere launcher

Figure 13: Sphere receiver

Figure 14: Gauging pig Figure 15: Flow patterns in two phase horizontal flow

Figure 16: Multiphase flow over hills

Figure 17: Principles of electro-magnetic corrosion pig

Figure 18: Linalog inspection pig

Figure 19: Principles of ultrasonic corrosion pig stand-off method

Figure 20: Satellite well field development

Figure 21: Subsea pig receiver schematic

Figure 22: Basic flexible pipe designs

Figure 23: Subsea pig launcher general configuration

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Basic operational pigging procedures for rigid and non-rigid pigs


Various pipeline pigging operations are required during the life-span of a pipeline to ensure safe and economicalfunction. This presentation centers on some of the basic descriptions of common pipeline pigging operations.

Introduction

This paper provides an introduction to various common pipeline pigging operations. Included are descriptions, in

general terms, of the various pigging scenarios which can typically arise during the life-span of a pipeline. Thesescenarios will include commissioning, pre-inspection cleaning, paraffin removal, multi-phase lines, and subseaapplications.

These operations, when reduced to their simplest form, fall into two distinct categories: liquid separation andcleaning. Similarly, each of these categories can be subdivided into rigid pig and non-rigid pig categories.

Definitions

Rigid pigs

A rigid pig can be defined as a pig constructed with a rigid body. The center of the pig body may be constructedof a rigid metal or plastic member that prevents flexure. As a result, the pig's ability to negotiate tight bends orskip over obstacles in the pipeline will be limited by cup deflection only. For an example of a rigid batching pig,see Fig.1.

Figure 1: Batching/displacement cup pig

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Non-rigid pigs

On the other hand, non-rigid pigs are constructed of flexible bodies (i.e., foam) or are fitted with articulatingjoints between short, small-diameter rigid members. These types of pigs are capable of traversing tight bends andare usually capable of skipping over obstacles in the pipeline, see Fig.2.

Figure 2: Flexible brush cleaning pig

Liquid-separation/removal pigs The essential requirement of a liquid-separation/removal pig is to maintain a seal

with the bore of the pipeline. The most difficult area of maintaining a seal is at a tight bend. As a pig begins totraverse a tight bend, the pig cup alignment to the bore of the pipe is distorted, resulting in a loss of seal. Toovercome this problem, liquid-separation/removal pigs are constructed with up to four deep conical cups, seeFig.3.

Figure 3: Batching pig (cup type)

The deep conical cups are more flexible than scraper cups and can conform to the ovality of the pipe in the bends.Cup spacing is an important feature to consider also. The lead and final cups should be separated by a distancegreater than any side opening, in order to ensure the best possible seal with the pipe while traversing valves,branches, and fittings.

Polyurethane foam pigs and spheres are also used for liquid separation/removal. Foam pigs (Fig.4) maintain fullbody contact with the pipe wall and are flexible enough to negotiate tight bends. On the other hand, spheres(Fig.5) maintain only line contact with the pipe wall (resulting in a less positive seal) but are well-suited toautomated launching systems.

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Figure 4: Foam pigs

Figure 5: Inflatable sphere

Bi-directional pigs are designed with straight disc cups instead of conical cups so that the pig can be pumped ineither direction, see Fig.6. These pigs may include two or four discs. If four discs are used, normally, there aretwo located at the front and two located near the rear of the pig. Bi-directional pigs can be used for liquidremoval; however, this type of pig provides the least effective seal with the pipeline bore. The most importantadvantage of this type of pig is the fact that it can be pumped in either direction. Therefore, the likelihood of thispig sticking is minimized.

Figure 6: Bi-directional pig

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Cleaning pigs

Cleaning pigs are defined by their application. Scraper pigs are constructed of a standard multi-cup pig andincludes polyurethane or steel blades attached to the body of the pig between the front and rear cups, see Fig.7.These scraper cups are not as deep as the conical cup used on liquid-separation/removal pigs, and do not provideas effective a seal. Usually the cleaning blades are spring loaded in order to ensure contact with the pipe wall. Theprimary application for scraper pigs with blades is the removal of soft deposits, such as paraffin. However, debrishas a tendency to collect in the blades between the cups, reducing the efficiency of deposit removal. This debriscan be flushed from between the cups by installing a by-pass port. This port, located on the side of the pig body,will allow a small portion of the higher-pressure driving fluid to flow through and across the pig body. This fluidwill flush the debris forward and ahead of the pig.

Figure 7: Blade cleaning pig (scraper pig)

The scratcher (wire brush) pig is another type of cleaning pig, see Fig.8. This pig is constructed much like thescraper pig except that steel brushes are located in place of the blades. This type of pig is used to remove harddeposits such as hydrates, mill scale, or corrosion which may form along the pipe wall.

Figure 8: Wire brush pig

Foam pigs can be constructed with wire brushes also, see Fig.4. The brushes are molded along the outside of thepig in a spiral pattern. This spiral pattern can induce a slight rotation to the pig as it moves through the line, whichwould provide for uniform wear during pigging.

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Fluid by-pass

Fluid by-pass can be divided into two categories: leakage and by-pass. Leakage occurs with all types of pigs, andis the fluid that leaks past the cups as the pig moves through the line. Fluid leaks between the pig cups and thepipe wall due to an imperfect seal. This cup/pipe wall seal is affected by cup wear, longitudinal seams in the pipe,surface roughness, and loss of contact in tight bends. Typically, leakage is estimated at 3-5% of the volume of thepipe. It is the fluid leakage that accounts for the late arrival of pigs at a trap.

Sometimes fluid by-pass is purposefully designed into a pig. This type of by-pass is utilized to clear debris frompig brushes, blades, or directly ahead of the pig. Cleaning brushes or blades sometimes require an openingthrough the side of the pig body so that fluid can pass through the body across the brushes or blades and clearthem of debris. The cleaning efficiencies of the blades and brushes are enhanced by keeping them free of debris.

Pig trains

Pig trains (Fig.9) provide a cost-effective method of conducting complex pigging operations simultaneously andare used in a variety of applications, such as cleaning, batching, and coating operations. Pig trains have been usedmany times in pipelines as a method of expediting a process (cleaning, dehydrating, coating, etc.) by conductingmultiple operations during the same run. For example, multiple pigs may be used in a cleaning run. The design ofa pig train, especially the quantity and spacing of the pigs, is very important and should be developed by the

operator and vendor. In-depth working knowledge of the pipeline system must be developed prior to running pigtrains.

Figure 9: Examples of pig trains

Most pipeline operators will not allow more than one pig in the system at a time, out of concern that a pig may getstuck and create a log jam in the line. However, many multiple pig runs have been conducted safely andsuccessfully.

Pig traps are a specific concern of pig trains. The number of pigs loaded into a line should not exceed the capacityof the traps. On surface systems it may be possible to break this rule if the pigs can be spaced at distances thatwould allow the operator to receive a pig in the trap, remove it safely, and reset the trap for the next pig. Althoughthis may seem simple enough, as the pigs exit the line they may not be spaced at the same intervals as when theywere launched. Therefore, pig indicators will play an important role in running pig trains.

Pipeline hardwareAll valving to be used in a piggable pipeline must be full-opening. Check valves must be full-opening and notcontain stabilizer fins on the back of the flapper or any other device that would extend within the bore of thepipeline.

Ball and gate valves must be checked to ensure a full-open passage. A partially-closed ball or gate valve mayexpose a sharp edge to incoming pigs, damaging or stopping the sphere.

All tees must be barred to prevent a sphere from entering. These bars must be flush with the inside diameter of themainline.

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All line bends and dents must be well documented in order to ensure the proper selection of a pig, especiallyintelligent pigs.

Pig indicators should be used at launching and receiving stations as well as at critical locations along the line toensure pig location. These pig indicators should not protrude a further distance from the pipe wall beyond thatnecessary to indicate pig passage.

Pig launchers and receivers

The commonly-recognized pig launchers and receivers are the barrel type; Fig.10 describes a typical barrellauncher for liquid and gas lines. The primary differences between gas and liquid launchers and receivers are thevents and drains. Pig stations for gas lines require vents to relieve pressure and liquid lines require drains. Notethat the reducer pup is eccentric such that the bottom is flat with the launcher bottom. The pup is the samediameter as the pipeline and is at least as long as one pig to ensure that the driving medium remains behind the piguntil it has safely passed the pig launcher valve. Two pressure gauges should be mounted on launchers andreceivers with one near the closure door and the other near the trap valve (B). A pig indicator is located at the endof the pipe pup near the launcher valve (A). A small-diameter equalizing line is used to equalize the pressure oneach side of the pig to prevent damage to the pig or launcher valve during launching. Drain valve (H) should

ensure complete draining of the launcher on each side of the pig. The vent valve (I) on top of the launcher allowsthe launcher to be purged of air when filling. The kicker/bypass connection line is located such that it is in theright location for launching operations. The launcher barrel is oversized (to facilitate easy loading of the pigs) by2in for pipelines up to 10in, 4in for pipelines 10-26in, and 6in for pipelines greater than 26in. The launcher barrelis approximately three pig lengths long. A 2-in flanged connection should be located between the pig trap valveand the mainline tee, which can be used for chemical injection between batching pigs when required.

Figure 10: Pig launcher for liquid and gas lines

The pig launcher operating sequence is:

1. close valves A, C, D, E, F, and H.

2. drain the launching trap (if liquid line) by opening drain valve H and open the vent valve I. If gas line,blow down the launcher through the blowdown valve G while venting (to a flare if necessary) through thevent valve I.

3. with the launcher drained, ensure that the pressure gauge reads 0psig.

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4. open the closure door and insert the pig. Push the pig forward until the leading cup forms a tight seal inthe reducer.

5. close the closure door.

6. close the drain valve H and blowdown valve G and leave vent valve I open. Open valves D & E and purgethe launcher piping through the vent valve I by slowly opening valve F. When purge is completed closevalve I.

7. allow the trap to equalize the line pressure, then close valves D, E, and F.

8. to prepare for launching, open valve A first and then valve C.

9. slowly close valve B to force the flow of liquid (or gas) through valve C and behind the pig. Continueclosing valve B until the pig moves into the pipeline as indicated by the pig launcher.

10.when the pig enters the pipeline past the pig indicator, open valve B completely and close valves A and C.

Barrel receiver

The receiver for gas and liquid lines appears similar to the launcher and has similar operating principles. A typicalreceiver for gas and liquid lines is described in Fig.11. A primary difference between the launcher and receiver isthe location of the by-pass line relative to the reducer. The receiver allows flow out of the by-pass as soon as thepig passes the reducer. This is done to reduce the driving force and fluid momentum following the pig as it entersthe receiver. (The launcher has the by-pass line located near the closure to get flow behind a pig being launched.)

Figure 11: Pig receiver for liquid and gas lines

The pig receiving sequence is:

1. close valves A and C. Ensure that the internal pressure of the receiver is 0psig. If not, vent the systemusing vent valve F. If necessary, blow down the receiver through the blowdown valve D with the ventvalve F open. Drain the receiver by opening valves E1 and E2.

2. after ensuring that no pressure exists within the receiver, open the closure and inspect the interior of thereceiver and remove any objects that would prevent a pig from entering the trap.

3. close valves E1, E2, F and D. Close the closure.

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4. open vent valves F and E and fill the receiver by opening by-pass valve C. After filling, close valves Fand E and allow receiver pressure to equalize with line pressure through by-pass valve C.

5. open valves A and C.

6. the pig indicator will signal when the pig arrives at the receiver. It will stop between valve A and the mainline side tee, providing its velocity is not excessive.

7. partially close Valve B. This will divert additional gas/liquid behind the pig and force it into the receiver,and the gas or liquid will exhaust out through the by-pass valve C.

8. when the pig is in the receiver, open valve B completely and close valves A and C.

9. for gas lines, open valves E1 and then D to reduce the trap pressure, and vent to a flare if necessary. Thisoperation should be conducted so as to prevent sudden movement of the pig within the barrel.

10. for liquid lines, the receiver pressure can be eliminated by opening drain valves E1 and E2 and drainingthe trap.

11.open the closure door and remove the pig.

12.close the closure door of valves E1, E2, E and D, fill the trap and equalize to line pressure; then closevalve C.

Sphere launchers and receivers

Sphere launchers and receivers are designed using principles similar to standard launchers and receivers but thefeatures of automation and multiple pig launching capability are added. Some of the applications of sphere pigscorrespond to periodic needs in operating a pipeline; examples are:

Periodic liquid removal in gas lines;

Separation of different products flowing in the same line (batching);

Clearing lines of product when normal flow is interrupted.

These applications may result in use of an automated sphere launching and receiving system as described in thissection.

Figs 12 and 13 describe typical sphere launchers and receivers. Sphere launchers and receivers use gravity insteadof a kicker line to assist sphere movement out of the launcher and into the receiver. The launcher valve can be aball valve with a blind opening, such that a sphere can drop into the valve and be launched as the valve is rotated180. In this position, the sphere will gravitate from the valve through the oversize line to the mainline. The blindopening in the valve will isolate the launcher while in this position.

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Figure 12: Sphere launcher

Figure 13: Sphere receiver

The sphere launch sequence is:

1. close valves A, B, D and C.

2. blow down the launching trap through blowdown valve C.

3. when the trap is completely blown down, open the closure door and insert the required number of spheres.

4. close the closure door and open vent valve D. Purge the launcher barrel through vent valve D by slowlyopening equalizer valve B. When purging is completed, close vent valve D.

5. allow the trap to equalize to line pressure.

6. open equalizer valve B, then trap valve A.The spheres are now ready for launching.

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The sphere receiver operates similar to the launcher:

1. if trap purging is necessary, close valve A and B and open vent valve D and purge by opening drain valveB.

2. after purging, close vent valve D and allow trap pressure to equalize to line pressure.

3. open valves A and B. Trap is ready to receive spheres.

4. when the receiver barrel fills up with spheres, close trap valve A and drain the barrel through the drainvalve B.

5. close drain valve B and blow the trap down through blowdown valve C.

6. open the closure door and remove the spheres.

7. close the closure door. Purge the trap as described in Item 1 and equalize the trap to line pressures; thenopen valves A and B for operation.

In actual operation, the receiver should be set up for pig arrival before the pigs are launched. This way, functionof the trap is verified in advance and without a pig in the line. A pig indicator should be installed upstream from

the trap in case the volume of gas or liquid flowing through the trap has to be minimized. The operator must havesufficient time to open/close valves to capture the pig without diverting all flow during the pig run through thetrap.

Pigging during commissioning

Commissioning of a pipeline is the process by which the pipeline is prepared to accept the product, and includesthe introduction of that product to the system. In this context, commissioning will entail several piggingoperations:

gauging,

cleaning,

dewatering, and

drying (for gas pipelines).

Hydrostatic pressure testing, to confirm pipeline integrity, is considered part of the construction phase and willnot be included in this discussion beyond the extent that the pipeline is assumed to have been hydrostaticallytested and left full of water.

Gauging

The pipeline, especially a new pipeline, should be gauged prior to conducting extensive pigging operations toensure easy passage of subsequent pigs. Gauging of the pipeline can fall into two categories: general gauging forrestrictions, and gauging to quantify the size of a restriction and determine its location.

General gauging of a pipeline consists of using a cup-type pig that has been modified to include a gauge plate (analuminium plate typically 0.25-in thick) mounted to the leading face of the pig. The outer diameter of the plate islimited to 90-95% of the pipeline inside diameter, and is based on the line operator's specifications.

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The theory of the gauging pig design is very simple and basic. If the gauge plate is damaged during the pig run,then there must be a restriction in the line. Unfortunately, the degree of the restriction and its location cannot bedetermined by examining the gauge plate.

A quantitative method of gauging the pipeline would require the use of a caliper pig. A typical caliper pigincludes multiple mechanical fingers that extend behind the pig and contact the pipe wall or a flexible pig cup thatis in contact with the pipe wall. An electronic module in the body of the pig interprets the signal produced by eachcaliper finger as it follows the profile of the pipe wall. Upon completion of the pig run, a log of pipe-wall profileversus location from a specified datum can be produced. Typically, this log will provide information regarding thesize, shape, and location of the restriction on the pipe circumference, as well as distance from a datum point. Theoperator can then evaluate the restriction and determine if the pipeline must be repaired or if the restriction can betolerated.

Figure 14: Gauging pig

Cleaning

The cleaning process of the pipeline is conducted to remove foreign material from the system. During the courseof construction and hydrostatic testing, foreign material (welding rods, gloves, dirt, animals, etc.) may enter thepipeline. The cleaning of the pipeline is normally done to the specification of the owner or operator and thereappears to be no set criteria. The pipeline should be cleaned to the maximum extent possible, as debris left in thesystem may initiate or promote corrosion. Similarly, debris in the pipeline could damage and/or impede pigmovement.

Ferrous debris could prevent proper data acquisition of an intelligent corrosion inspection pig. While degrees ofcleanliness are difficult to define, a standard for "clean" pipe which is generally agreed upon is that the walls mustbe free of rust, mill scale, and other deposits, and the pipe surface must have the appearance of "white metal".This "white metal" is actually a mat gray and is further described in NACE publication 53.1.

The cleaning is often performed by more than one type of pig run through the line, sometimes together andsometimes separately. Spheres and cup-type pigs with wire brushes are generally used to remove debris.Sometimes gel pigs are used with cup pigs with the gel functioning as a medium to keep debris in suspension.

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Dewatering

Dewatering generally takes on the meaning of removing 92-98% of the free water in the pipeline. This isaccomplished by using compressed air to drive spheres, cup-type pigs, and/or foam pigs through the line todisplace the water. Typically, multiple pig runs are required until a minimal amount of water is pushed out aheadof the pigs. The amount of moisture remaining in the line is a function of internal surface roughness, since theremaining water is distributed about the inner surface of the pipe.

Foam pigs can provide a unique function in the dewatering of a pipeline. After multiple cup-type pig runs, foampigs can be utilized to soak up the residual water remaining in the line.

Drying

Absolute drying of a gas transmission line may be necessary to prevent corrosion. Several methods are used toremove the residual moisture left in a pipeline after dewatering, including:

drying by methanol displacement,

drying using super-dry air,

drying by nitrogen, and

drying by evacuation.

Each method listed above has advantages and disadvantages and not all of the above methods require the use ofpigs.

Drying the pipeline by methanol displacement entails displacing slugs of methanol separated by pigs through theline. These pig trains are displaced by product gas or nitrogen. Typically, multiple runs are required and thedegree of dryness is determined by the amount of water measured in the methanol as it exits the line. Care must

be taken when using methanol, since it is toxic, has a low flash point, and can be explosive at the proper mixturewith air. Therefore the pipeline should be purged of air with an inert gas prior to the introduction of methanol.

Due to the fact that some fluid by-passes a pig during displacement, this method of drying will always leave asmall quantity of methanol/water (distributed as a thin film about the internal surface of the pipeline) in thepipeline.

Another method for drying a pipeline requires the use of super-dry air and foam pigs. Drying plants andcompressors are used to produce and inject super-dry air into the pipeline to displace multiple foam pigs. Thefoam pigs displace water from the pipeline as well as absorb water and transport it. The dewpoint inside thepipeline is monitored at the pig launcher and receiver. When the specified dewpoint is obtained, (after multiplepig runs) then the pipeline is packed with dry air. Some of the disadvantages of this method are that largequantities of energy are required to dry and compress the air, line length must be limited, and branch lines notsubject to the air flow will not dry.

Nitrogen drying is similar to the above except that nitrogen gas is substituted for the super-dry air. Nitrogen gas isutilized to displace multiple foam pigs through the pipeline to displace the water and vapor from the system. Thedewpoint is monitored at the pipeline inlet and outlet to determine when the process is complete. When thespecified dewpoint is attained, then the line is readied for commissioning by packing with dry nitrogen.Unfortunately, large quantities of pure nitrogen gas are required for this drying process which is expensive andnot readily available.

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Drying a pipeline with the use of a vacuum does not require the use of pipeline pigs except to remove the bulk ofthe water in the system. The vacuum drying method relies on the evacuation of a sealed line which causesremaining water in the system to boil off. This is achieved by lowering the pressure in the line to less than thatrequired for the water to boil at the ambient temperature of the line. The dewpoint and internal pressure at eachend of the system are monitored until the required level of dryness has been attained. A dewpoint of -20C isgenerally considered to provide "permanent" corrosion protection. After reaching the specified dewpoint, the low-pressure water vapor in the line must be removed. However, care must be taken not to over-pressure the line, orelse the water vapor will revert back to a liquid.

Even small amounts of water in the line will be counterproductive in preventing corrosion. Therefore the watervapor must be purged from the system by applying a vacuum to one end of the pipeline while injecting dry air ornitrogen (or any inert gas) into the other end. Purging is considered complete when the packing medium(nitrogen) is detected at the vacuum pump. After purging the water vapor, the line should be pressurized with dryair or nitrogen to prevent accidental entry of moist ambient air into the line. (The use of dry air to purge and packthe pipeline may create a safety problem preventing the commissioning of the pipeline until an intermediateoperation to displace the dry air with an inert gas is conducted.)

Hydrate removal

Hydrocarbon gas hydrate build-up in natural gas pipelines can narrow the pipe profile and cause a loss ofefficiency due to an increase in friction factors. The primary condition affecting the formation of hydrates in a gasline is free water. This residual water was left in the line after hydrostatic testing and/or insufficient drying. Inexisting natural gas lines, free water is separated from the gas in modern drying and separation plants prior totransportation.

Hydrocarbon gas hydrates are formed when free water is available in the presence of hydrocarbon gases. They arecrystalline in structure and form a hard granular substance which can be compared to ice or snow. The individualcrystals consist of water and the molecules of one or several hydrate-forming gases, such as, methane, ethane,propane, and butane or isobutane. Hydrate formations can be caused by other components contained in naturalgas, such as nitrogen, carbon dioxide, and hydrogen sulfide. These hydrates form a crystalline lattice which isstronger than the original water compound and therefore is not water soluble.

The most important conditions for the formation and stability of hydrates are:

the presence of free water,

sufficiently low temperatures,

sufficiently high pressures,

a minimum density of the hydrate-forming gas.

Low temperatures capable of supporting hydrate growth can occur due to ambient pipeline conditions and/or the

loss of energy which occurs in a gas molecule as it expands through a pressure drop. Pressure drops resultingfrom restrictions or unevenness in the pipe wall, i.e. large internal weld seams, cavities in valve bodies, grooves inold threaded and coupled pipe joints, and areas of corrosion, are sufficient to create a drop in temperature capableof supporting hydrate growth. Crystals will form on valves and fittings, also. Once these hydrates begin to formthey can become self-perpetuating, since restrictions in the pipe bore foster hydrate formation which creates largerrestrictions and so on. Hydrate deposits can become a harbinger of free water which will promote corrosion alongthe pipe wall.

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The best method of handling hydrate build-up is to prevent it in the first place. Proper drying techniques(described above) can eliminate the free water required for their formation. However, if hydrates have formed,then pigging to remove them may become necessary. Typically, wire brush pigs (Fig.8) are used to scour thehydrates from the pipe wall. These pigs may be constructed of a foam or cup-type pig. If large quantities ofhydrates are anticipated, it may be necessary to use a gel slug in a pig train to suspend the hydrates and otherdebris to prevent pig "sticking". Gel slurries will improve the efficiency of debris removal as well. Once the linehas been cleaned, then the process of removing any residual free water should be repeated to prevent a recurrence.

Paraffin removal

If an oil pipeline transports a highly-paraffinic fluid that goes through the cloud point for paraffin drop out, thereis continuous deposition of the paraffin on the pipe walls as long as the pipeline is operating, and this ambienttemperature is below the cloud point. If this paraffin deposit is not removed, the build-up continues, restricting theflow of product, and increasing the pressure drop across the pipeline. The increased pressure drop is a function ofthe reduction of the pipe bore and the increase in surface roughness along the pipe wall (due to the irregular shapeof the deposits). This increase in pressure drop will result in an increase in input energy to maintain a constantthroughput, i.e. a more costly pipeline operation.

There are several ways to control the paraffin build-up; by using chemical inhibitors, pigging, and varying the lineoperating parameters.

Some researchers have determined that the formation of paraffins is a function of pressure and temperature. Anincrease in line pressure will keep the lighter crudes in solution which may tend to keep the paraffin in solutionalso. This phenomenon seems to be dependent on the composition of the wax and the oil. In actual application, itwas found that increasing line pressure does reduce build-up rates, but in insignificant amounts.

The injection of a paraffin inhibitor can help control the deposit of wax. These compounds have the ability tochemically coat small particles and alter their ability to adhere to each other or to the pipe surface. In the smallparticle state, paraffin will stay suspended in the oil for trouble-free movement all the way to the refinery.

In some lines, inhibitors might not be used or be ineffective or uneconomical. Pigging may then be required to

remove paraffin. The objective is to loosen the paraffin and return it to suspension in the liquid. Various types ofpigs can be used. There are several types of cup-driven scraper pigs.

A cup-type scraper pig with urethane blades is commonly used. When these pigs are used for paraffin control,they normally have a by-pass system to clear the blades of debris. Another type of pig for paraffin removalincorporates a urethane disc mounted to the front of a multi-cup pig, much like a gauging pig. It is felt that thisdisc will plow or scrape layers of paraffin away from the pipe wall, in a more effective manner than a blade-typecleaning pig.

Foam pigs have been used to remove soft paraffin from lines (especially offshore). Cup pigs can sometimesbecome stuck in a line with considerable (and unknown) paraffin. A safe practice that is sometimes used is to runa foam pig that is considerably smaller than the expected or calculated flow diameter (restricted diameter) of theline. Then keep running progressively-larger foam pigs until the line is fully cleaned.

Sphere pigs have been used to reduce the pressure drop of a pipeline restricted by paraffin. Although the sphereremoved little, if any, paraffin, it did smooth the surface irregularities of the build-up along the wall, therebyreducing the friction factor.

If the formation of paraffin is expected or experienced, then flow rates and flow pressures on the pipeline shouldbe frequently monitored. Then a pigging program for paraffin removal should be planned and started. The safeapproach is to pig frequently at first and then reduce the pigging until a known balance is achieved betweenpigging frequency and the amount of paraffin that must be removed per pass.

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Two-phase flow

Multi-phase flow ("two-phase flow") is normally defined as the simultaneous flow of gas and liquid through apipeline. Offshore platforms delivering production gas from reservoirs at pipeline inlet pressure and temperatureconditions can, as a result of the physical composition of the gas, deliver several thousand barrels of liquid to thepipeline. An understanding of the characteristics of this flow as it applies to large-diameter pipelines is necessaryto predict pressure gradients as well as volumes of accumulating liquids.

The production of natural gas from high-pressure, high-temperature reservoirs generates considerable quantitiesof water and hydrocarbon condensates. These liquids form when the dense single-phase vapor in the reservoir hasits pressure cut prior to delivery to the appropriate transmission pipeline. This pressure drop has the effect ofreducing the fluid temperature which further accelerates liquid formation. Since offshore platform space islimited, treatment of the produced gas offshore is usually limited to the prevention of water formation in thepipeline. Gas and the associated condensates are therefore combined into a common two-phase stream at the inletto the pipeline. As the fluid travels along the pipeline, its temperature generally is lowered due to the sinktemperature of the pipeline's surroundings. Hence, additional condensation normally occurs along the pipelineroute.

The design and operation of a two-phase pipeline must take these substantial quantities of liquids into account,particularly when considering the handling of large continuous liquid volumes, called slugs. There are two basic

operating situations that create significant slugs in a two-phase pipeline. The most obvious situation is the runningof a pig or sphere for maintenance, inspection, or liquid inventory control. The second situation is associated witha relatively-large and abrupt increase in flow rate. Slugs resulting from pigging are generally much larger thanthose resulting from flow rate increases, and form the basis for sizing slug-handling equipment. Slug-handlingmethods can be broadly categorized as: no slug catcher, separator-vessel type slug catcher, parallel or extendedpipe-loop type slug catcher, and parallel-bottle type slug catcher.

After the gas and liquid separate in the line, the gas flows away rapidly and leaves the liquid to move along at amuch slower rate. The liquid is moved by the friction of the gas against the liquid surface. As the velocity of thegas in the pipeline increases (due to the restriction created by the liquid) the increased friction against the surfaceof the liquid causes the surface of the liquid to ebb and flow in random waves, see Fig.15. The liquid accumulates,filling from 15 to 80% of the pipe cross-sectional area. A slug is formed when a wave is picked up periodically by

the more rapidly moving gas to form a frothy slug which passes through the pipe at an accelerated velocity,greater than the average liquid velocity. The movement of the slug creates a higher pressure drop in the pipeline.The pressure drop in the system increases as more slugs are formed.

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Figure 15: Flow patterns in two phase horizontal flow

Elevation changes in the pipeline system further aggravate the pressure drop problem. Liquid tends to collect inthe low and uphill sections of the pipeline, see Fig.16. The same phenomenon, described above, occurs while theuphill section is gradually filling with liquid. A large wave of liquid is picked up by the rapidly-moving gas andcarried over the crest of the hill. The liquid slug will settle after it passes the crest of the hill and will run into thenext valley and accumulate there, hence the process repeats itself. Since the liquid flow over the crest of a hill isnot continuous then the siphoning action that normally occurs on the downhill side of a crest will be broken.Therefore the pressure drops required to push the liquid slugs over each crest become accumulative.

Figure 16: Multiphase flow over hills

Multi-phase pipelines will have the same pigging requirements as single-phase pipelines, such as pigging toremove liquids, debris, paraffin, hydrates, and corrosion scale, and distribute chemical inhibitors. Similarly, thesepipelines will need to be inspected for metal loss in the wall. Since most of the listed pigging operations arediscussed in other sections of this paper, this discussion will be limited to liquid removal and chemicaldistribution.

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Multi-phase pipelines must be pigged frequently in order to remove the liquids and improve the operatingefficiency of the system. Although other types of pigs could be used, typically spheres are used to push the liquidfrom the pipeline because they provide an adequate seal with the pipeline bore and are particularly well suited toautomatic launching. Automatic launching is a very important aspect of pig selection in this case, since it may benecessary to launch a pig as often as every 4 to 6 hours.

Another reason to pig a multi-phase pipeline is to distribute chemical inhibitors. One of the best ways to ensurethe uniform distribution of chemicals for inhibiting corrosion is to pig a batch of the chemical between twospheres through the pipeline.

Pre-inspection cleaning

Pre-inspection cleaning of a pipeline is usually the responsibility of the operator and not the inspection company.It is important that the operator understands and strives to meet the cleaning requirements recommended by theinspection company to ensure that accurate data is acquired in the least number of runs. Failure to clean thepipeline to an acceptable level can result in a wasted run, costing additional time and money.

Sometime during the life of the pipeline it will become necessary to conduct an inspection of the pipe wall.

Corrosion and erosion of the pipe wall will cause a reduction in the structural strength of the pipeline. It isimportant to detect corrosive areas before a failure occurs, especially if the lines run offshore or through heavily-populated areas.

Early detection can assist the operator in developing better corrosion inhibition programs. If the corrosion islocalized and exceeds a specified limit, then it will be necessary to identify and replace that section of pipeaccording to a maintenance schedule, preferably. In the upcoming years pipeline operators will have to meetFederal standards, currently being developed, which specify the frequency and degree of inspection of pipelines.The two most common methods of inspecting pipe wall thickness are: magnetic flux leakage and ultrasonicdetection pigs. However, the pipeline and pipe wall must be free of debris, to ensure the validity of the acquireddata prior to the introduction of the inspection pigs. A brief description of the function of the magnetic flux andultrasonic inspection pigs will aid in the understanding of the pre-inspection cleaning requirements.

Magnetic flux leakage inspection pigs

A magnetic flux leakage inspection pig saturates the pipe wall with a magnetic field. The flux lines emanate fromthe pole brushes located above and below the sensor pads, and normally run parallel to the pipe axis, see Fig.17.At a surface irregularity such as a pit, the flux lines no longer run parallel to the pipe axis but will flow around theanomaly. The spring sensor pads attached to the pig slide along the surface of the pipe wall. If the path of thesensors crosses over the flux line then a signal (voltage) will be produced indicating a flaw in the surface of thepipe wall. The size of the surface anomaly will determine the extent of the deformation of the flux lines and thesignal produced by the sensors.

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Figure 17: Principles of electro-magnetic corrosion pig

Magnetic flux inspection pigs contain another set of sensors that can determine if the surface anomaly is on theinner or outer surface of the pipe wall.

he ability of the sensors to obtain credible data can be affected by their proximity to the pipe wall. If the pads arelifted away from the pipe wall, by debris or build-up, then the signal will be attenuated or lost completely.Therefore, inspection companies require that the line be cleaned of loose debris and that paraffin build-up alongthe wall not exceed 1/16in approximately. The best way to verify that the pipeline is clean is to run a dummy pig,since it is not feasible to visually inspect the line for cleanliness. The running of a dummy pig (same size and

shape as the inspection pig with gauge rings in place of the sensors) will ensure safe passage of the actual pig, andallow verification of the line cleanliness. Cleanliness is a subjective analysis of the type and quantity of the debristhat is trapped between the pole brushes. Typically, a quantity of debris in excess of a gallon or that which hindersthe movement of the sensor linkages, is considered too much, indicating a need for further cleaning, see Fig.18.

Figure 18: Linalog inspection pig

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Ultrasonic inspection pigs

Ultrasonic corrosion-detection pigs are based on the use of multiple ultrasonic transducers placedcircumferentially around the body of the pig, Fig.19. The sensors are spaced a short distance away from the innerpipeline wall. These transducers transmit and receive ultrasonic signals at a very high rate of speed. Pipe wall ismonitored by determining the time difference of the sound waves reflected by the inner and outer pipe surfaces.These inspection pigs must be run in a liquid medium since ultrasonic transducers require a liquid coupling

between the transducer and the pipe wall.

Ultrasonic inspection pigs are not susceptible to the lift-off problems described above. However, hard depositssuch as silica sand or hydrates can affect the response time of the sound wave reflected from the inner surface ofthe pipe, thereby masking the location of the actual surface. It is recommended that, prior to running an ultrasonicinspection pig, the line be pigged until hard deposits are removed from the pipe wall and that the quantity ofdebris removed by a pig run not exceed 1 kg, approximately.

Figure 19: Principles of ultrasonic corrosion pig stand-off method

Subsea applications

The provision of underwater pigging facilities is necessitated by the same needs and environmental factors thatdictated the development of surface pigging.

The general purposes for pigging are:

1. internal cleaning of the pipe (oxides & debris);

2. removal of wax and/or asphaltic deposits;

3. removal of free H2O;

4. batch separation;

5. transport of precipitated gas liquids;

6. removal of hydrates;

7. better distribution of injected inhibitors;

8. internal survey of pipe internal and external corrosion.

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Review of the above list indicates a number of pigging applications that relate to corrosion reduction and/ormonitoring in all pipelines. The real "crunch" comes in the new offshore lines being laid in very deep water.Deep-water pipelines introduce Gulf of Mexico operators to new operating criteria:

1. much lower year round operating temperatures;

2. in two-phase flow much higher pressures for liquid column displacement.

The colder temperatures introduce the rapid precipitation of wax/paraffin or asphaltic deposits plus bring gashydrate formation thresholds into various ranges of conditions found during the day-to-day operation of thepipeline. Procedures such as shutdowns in waxy crude lines introduce greater wax deposits. A "blow down" of anatural gas-gathering line can produce excessive liquid drop-out and precipitate any residual free water, furtheropening the door to hydrate formation.

The advent of new cost-saving facilities introduces satellite well completions with a seabed wellhead-to-platform-facility pipeline that can fall into any of the pigging requirement categories, see Fig.20. An additional factor inoffshore construction is the practice of subsea tie-in into major oil and gas-gathering pipeline systems.

Many of these tie-ins are accomplished with tap valve assemblies on the transmission or gathering line, limitingthe branch line pigging operation to poly-pigs, spheres or not at all. The spheres are moved with mainline spheresthrough the line to the terminating station. The introduction of corrosion monitoring has now introduced a newcriterion of the lateral pipelines, and a subsea pig receiver of simplistic design will be needed at tie-in facilities. Itis envisioned that the receiver will need to be diver- or ROV-operated, and that "smart" pig recovery will bepossible utilizing a normal Gulf of Mexico diving work vessel, see Fig.21.

Figure 20: Satellite well field development

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Figure 21: Subsea pig receiver schematic

The basic hardware for a subsea pig trap is on the market today. Additional equipment designs under developmentwill become available commercially in 1990. The American Gas Association recently invited proposals from theindustry for project work regarding pigging of branch lines which tie-in to a larger main pipeline. A veryimportant benefit of the projects would be the ability to monitor corrosion in the branch lines.

It should be noted that the "new" flexible pipe being used in deep-water lines produces some further demarcationfrom "so called" standard practices, Fig.22. First, the stainless steel internal spiral wrap is not bonded to themating vinyl layer, providing a rather large cavity for H2O entrapment. For instance, in the 6-in ID riser pipe, aretention of up to 660US gallons per mile is indicated. Further, the stainless steel liner is presently limited to non-

metallic scrapers or brushes making wax and/or asphalt removal more difficult. A plus factor is the absence ofoxide formation with the stainless.

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Figure 22: Basic flexible pipe designs

Pig launchers for subsea become more complex than their platform or land-based counterparts. Designrequirements for subsea launchers and receivers may include special hydraulic connectors, protective structures,remote sensors and controls and guidance frames. Besides the additional costs associated with these features, theability to conduct pigging operations may depend on the availability of diving support vessels, drill ships, and theweather. Fig.23 describes the general configuration of a subsea pig launcher.

Figure 23: Subsea pig launcher general configuration

A number of subsea systems have been constructed but operating data on existing development facilities takes afew years to surface. The noted AGA study should produce substantially more data during this year.

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References

1. H.O.Mohr Research & Engineering, Inc., 1989. Pipeline pigging - state of the art study, No 0389-1357,October.

2. F.T.Conner and J.Barnett, 1982. Pipeline two-phase flow analysis, PHE Company internal report, Houston, TX.

3. A.E.McDonald and O.Baker, 1964.Multiline flow in pipelines, Oil and Gas Journ., June 15.

4. G.Kopp, 1981. Why and how to dry gas pipelines, Pipe Line Industry, October.

5. B.Peska, Tuboscope-Linalog Division, discussion in 1990 with P.Wilson.

6. G.Pullan, 1989. Alfred McAlpine Services & Pipelines Ltd - brochure of services/products, June.

7. J.N.H.Tiratsoo, 1988. Pipeline pigging technology, Gulf Publishing Co.

8. R.Craig Tucker, F.T.Connor, and P.Wilson, 1990.Multi-phase flow in pipelines - pigging and mechanicalapplications, American Society of Corrosion Engineers, Pipeline Corrosion Conference, February.

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