Offshore Pipeline

7/30/2019 Offshore Pipeline

1/26

PIPELINE ENGINEERING: MATERIALS & WELDING MODULE: OFFSHORE

355

PIPELINE REPAIR

9.1 INTRODUCTION........................................................................................................... 356

9.2 REPAIR TECHNIQUES ................................................................................................ 3589.2.1 Do nothing............................................................................................................... 358

9.2.2 Do nothing but monitor the defect. ......................................................................... 359

9.2.3 Downrate the pipeline ............................................................................................. 359

9.2.4 Remove the defect by dressing it out. ..................................................................... 359

9.2.5 Mechanical Clamps................................................................................................. 360

9.2.6 Epoxy grouted repair sleeves. ................................................................................. 362

9.2.7 Clock Spring Repair................................................................................................ 365

9.2.8 Alternative Composite Repair Systems .................................................................. 366

9.2.9 Welded patches and half shells. .............................................................................. 367

9.2.10 Welded full encirclement shells and hot tap fittings............................................... 3689.2.11 Local weld deposition repair................................................................................... 369

9.2.12 Cut out pipe section and replace welded spool piece...........................................372

9.2.13 Cut out pipe section and replace - mechanical connectors ..................................... 374

9.2.13.1 Elastomer systems........................................................................................... 374

9.2.13.2 Forging systems .............................................................................................. 374

9.2.13.3 Metal seals....................................................................................................... 375

9.3 ANCILLIARY REPAIR EQUIPMENT ......................................................................... 375

9.4 REFERENCES ............................................................................................................... 380

Main Menu


2/26


356

MODULE 9B: PIPELINE REPAIR

9.1 INTRODUCTION

The cost of repair of damaged offshore pipelines is very much greater than that for

onshore pipelines, since an offshore repair usually requires at least a diving support

vessel and diving crew, but possibly a full hyperbaric welding spread and associated

pipe handling frames etc. If the pipeline is at a depth beyond that at which divers are

able to work then a remotely deployed repair system may need to be used.

For these reasons before any decision to repair is taken all other possibilities should be

explored, for example the use of engineering critical assessment calculations to allow

acceptance of the defect, supported by full scale trials if necessary, or even downrating

of the pipeline to allow continued operation at lower pressure without repair.

Before a repair is attempted on an offshore pipeline a number of details should beobtained. These include :

pipe details (dimensions, grade, material, manufacturing route) pipeline operating conditions (including those at the time of damage if known). pipeline product specification type and dimensions of any external corrosion/weight coatings.

type of CP system.

pipe burial conditions. water depth, temperature. current conditions. seabed conditions. details of damage (type, extent, location).The nature of the damage will influence the type of repair that may be chosen. Damage

to offshore pipelines may be of many types but can be classified into four main groups :

1. Manufacturing/Design/Construction fault. material/quality problem with pipe or fitting. welding defect. overload etc. due to design deficiency. damage/buckling during construction.

Main Menu


3/26


357

2. Internal corrosion general corrosion. mesa corrosion. preferential corrosion of welds/heat affected zones. pitting corrosion. crevice corrosion. microbiological corrosion. hydrogen induced cracking. stress corrosion cracking.

3. External corrosion general corrosion. local corrosion (e.g. pitting). stress corrosion cracking. failure of CP system.

4. Mechanical damage internal mechanical damage from pigs. buckles/fatigue damage (e.g. from free spans). denting/gouging from dropped objects. denting/gouging from external interference (trawl boards, anchors etc.). damaged/missing external weight coating. damaged/missing external corrosion protection coating. erosion/abrasion (internal or external). storm damage. buckling/distortion due to seabed movement.

Main Menu


4/26


358

Depending on the nature and extent of the damage, and whether the pipeline is leaking

or not, the repair operation may need to be carried out:

immediately, without interrupting the flow, perhaps using a temporary leakclamp in the first instance (e.g for a large leak).

immediately by replacing the pipe section after stopping the flow (e.g. for amajor rupture).

as soon as practicable by any appropriate method (e.g. for a minor leak ordamage which does not immediately threaten the integrity of the pipeline).

The techniques for carrying out repairs to defects discovered in pipelines include:

a) do nothing.

b) do nothing but monitor the defect.

c) downrate the pipeline.

d) remove the defect by dressing it out.

e) use mechanical leak clamps.

e) use epoxy grouted repair sleeves.

f) use composite repair collars such as Clock Spring.

g) use welded patches or half shells.

h) use welded full encirclement shells or hot tap fittings.

i) cut out pipe section and replace with welded pipe section.

j) cut out pipe section and replace with mechanically connected pipe section

These are discussed individually below:

9.2 REPAIR TECHNIQUES

9.2.1 Do nothing

In certain circumstances, for example when defects outside the workmanship standards

used during construction are discovered, it may be possible to apply fitness-for-purpose

principles to accept the defects. For example, girth weld defect acceptance limits in

standards such as API1104 or BS4515 are based on good workmanship. It is usually

possible for defects to be much larger before they affect the integrity of the pipeline.

This is now recognised, and most national and international standards have fitness-for-

purpose appendices which allow defect sizes based on engineering critical assessment to

Main Menu


5/26


359

be calculated. For these calculations to be carried out it is usually necessary to have

some measure of material notch toughness (eg CTOD), as well as a knowledge of defect

size and stress on the defect.

These approaches can be applied to defects in girth welds, seam welds, or the pipe body,

provided the input data (defect size, stress on the defect and material toughness) isknown.

Therefore, the heading 'do nothing' is simplistic, since it is normally necessary to carry

out a paper or computer based analysis before nothing can be done!

9.2.2 Do nothing but monitor the defect.

Assuming that an engineering critical assessment has been carried out, and the defect is

well within acceptable limits then it may be appropriate to ignore the defect and treat

that section of the pipeline like any other section, ie. carry out only the normal routine

inspection programmes. However, if the defect is close to the acceptable limit, or ifthere is a possible defect growth mechanism in operation (such as fatigue), and a repair

is impracticable or uneconomic, then it may be appropriate to monitor the defect in

some way. For subsea pipelines routine access for defect monitoring is not available so

that this option may not be a practical proposition unless the defect lends itself to

examination by some form of remote monitoring system.

9.2.3 Downrate the pipeline

If an engineering critical assessment analysis demonstrates that the defect is likely to

lead to failure of the pipeline at the current operating pressure, but the defect is too

extensive or too difficult to repair then an option might be to lower the maximumpermissible operating pressure of the pipeline (ie. downrate the pipeline). Such a case

might be, for example, when there is extensive corrosion along the seam welds of a

pipeline. An alternative to re-laying the pipeline would be to downrate the pipeline to an

operating pressure at which there is no danger of pipeline failure. Obviously if the

source of the corrosion cannot be eliminated further deterioration of the pipeline should

be anticipated and further downrating may be necessary, depending on the results of

regular surveys.

9.2.4 Remove the defect by dressing it out.

The approach here is to reduce the stress concentration caused by the defect by

removing metal around it to produce a smooth surface contour, Figure 1. This technique

is used mainly for the removal of metal loss defects such as mechanical damage (eg

gouges, spalling) and corrosion, although it has also been used for minor cracking. In

repair standards such as that used by British Gas, defects are classified as superficial,

moderate, severe and extreme(1)

. Those classified as superficial and moderate can be

repaired by dressing and an algorithm has been produced to ensure that appropriate

precautions, such as pressure reduction, degree of metal removal, etc. are taken Figure 2.

Main Menu


6/26


360

Figure 1. Dressing of a defect in a pipeline

Dressing of defects in live pipelines must be carried out with care, by trained operators,

using the correct equipment. The most common form of dressing is by grinding,

preferably using the 100mm dia. wheel grinderette type, taking care not to overheat the

surface. Tensile residual stresses may be produced underneath the ground excavation,

but the depth is typically only 0.01-0.06mm and this is insignificant as far as pipeline

integrity is concerned.

Although this defect dressing technique is used regularly on onshore pipelines, its use

on offshore pipelines is limited. This is because the cost of gaining access to the defect

is so high that it is usually considered worthwhile to carry out a more extensive repair,

such as with a repair sleeve, in case there is further damage at the site of the ground

excavation.

9.2.5 Mechanical Clamps

The high pressure versions of these clamps consist of flanged and bolted heavy wall

split shells with a number of elastomeric seals, often reinforced with metal anti-

extrusion supports to enable them to seal and contain high pressures, Figure 3. Some

clamps are claimed to act as a permanent repair if they are subsequently welded to the

pipeline (see Figure 11), but the complex sealing welds required around threaded

components such as stud bolts make it difficult to guarantee a satisfactory finished

repair.

The installation of mechanical (i.e. bolted) repair clamps offshore relies on :

good preparation of the pipe surface installation of heavy half shells without damage to the seals application of the correct torque to the bolts

Main Menu


7/26


361

Figure 2. Example of defect classification system used by British Gas (from Ref 1).

Main Menu


8/26


362

A number of aids to achieving these requirements have been developed, such as clamp

handling frames and torque indicating bolts, which enable more consistent performance

from mechanical clamps to be obtained.

For onshore pipelines companies prefer to regard mechanical clamps as a short term

repair and aim to replace them with welded repairs or to replace the damaged pipesection when operational conditions allow. For offshore pipelines, because of the costs

involved in subsea intervention, mechanical clamps may often be left in place as a semi-

permanent repair subject to regular inspection.

Figure 3. Bolted repair clamp

(courtesy Plidco).

9.2.6 Epoxy grouted repair sleeves.

Repair of pipeline damage with epoxy grouted shells is not new. However, due to the

lack of satisfactory published performance data, and familiarity with welded shells, they

have only recently been generally adopted. The technique is suitable for repair of all

types of damage, including cracking, corrosion, gouges, gouged dents and defective

girth welds. The technique avoids the need for welding on to live pipelines and fit-upproblems are reduced compared to welded shell repairs.

The epoxy filled shell repair comprises two half shells which are joined to encircle the

damage leaving an annular gap of between 3 to 40mm. The shells are usually the same

thickness and grade as the damaged pipe and are at least one diameter longer than the

damage. The half shells may be joined together by a longitudinal seam weld (Figure 4),

or by fitting the abutting edges with flanges which may be bolted together. Examples of

welded and flanged epoxy repairs are shown in Figures 5 and 6.

The ends of the annular gap can be sealed with a fast setting epoxy putty and the

enclosed cavity is then filled with a high stiffness epoxy grout. The grout may be

Main Menu


9/26


363

injected at high pressure, in which case the repair works by transfer of the pipeline stress

to the shell, or a low (less than 7 bar) pressure, in which case the main effect is to

prevent bulging of the defective area. Some stress transfer to the shell may be obtained

with the low pressure technique by carrying out the repair at reduced pipeline pressure

(15-30% reduction), and this is done for the more severe defects (Fig 7).

Figure 4. Schematic of welded epoxy grouted repair shell (from Ref 2)

Figure 5. Flanged repair shell (from Ref 2) Figure 6. Welded repair shell (from Ref 2)

Main Menu


10/26


364

Experimental tests have shown that repairs are stronger than the pipe in static burst tests,

even for repairs to defects which would have failed at 30% pipe yield strength without

repair. Fatigue tests have shown that even defects which would fail on the first cycle in

the unrepaired condition had acceptable fatigue lives after repair(2)

.

Although grouted repair shells have been used extensively for the repair of onshorepipelines, it is believed that their use offshore has been restricted to strengthening of

platform tubulars and to the reinforcement of riser pipes. The use of epoxy repair shells

subsea would be difficult and entail using a dry habitat so that the required high

standards of pipe preparation could be achieved.

Figure 7. Low pressure grouting procedure from (Ref 2).

Main Menu


11/26


365

9.2.7 Clock Spring Repair

The Clock Spring repair is a multi layer pre-formed fibreglass bandage which is wound

around the pipe and held in place partly by its own 'springiness' (like a spring in a watch

or clock), and partly by polyester resin adhesive placed between the layers, Figure 8, 9.

Figure 8. Clock Spring Figure 9. Applying adhesive to Clock Spring

The width of the Clock Spring is approximately 300mm and the number of layerswrapped around the pipe is typically about 8, giving a total thickness of 12.7mm. The

repair is suitable for pipe diameters from 100mm to 1400mm, and only a small

clearance is required around the pipe to install it. Longer defects can be repaired by the

use of multiple adjacent Clock Springs.

The Clock Spring repair is applicable to the repair of blunt defects such as general

corrosion. The defective area is thoroughly cleaned and the metal loss region is filled

with a compound to allow load transfer to the spring to be achieved. Whilst the filler

compound is still pliable the composite is installed by wrapping the flexible layers of

composite over the defect, applying adhesive between the layers to create an essentially

monolithic sleeve around the pipe (Fig 10).

There is a concern that the composite strength and stiffness might diminish with time,

although it is claimed that Clock Springs removed after 2-7 years exposure time show

no significant loss of mechanical performance or chemical breakdown(4)

. Composite

Clock Spring repairs have performed very well in short term burst tests, but further work

is ongoing to explore their long term behaviour(5)

. One disadvantage of the technique is

that it provides very little end load resistance, so that it is not suitable for the repair of

circumferential damage such as defective girth welds.

Offshore applications of clock spring repairs have been for topside piping and riser

strengthening.

Main Menu


12/26


366

Figure 10. Example of clock spring repair on land pipeline.

9.2.8 Alternative Composite Repair Systems

Although the Clock Spring is perhaps the most well known composite pipe repair

technique, there are other techniques using composites which usually involve eitherapplying partially cured wraps, wet laminates, or dry fabrics which are then loaded with

resin(6)

.

The partially cured spiral wraps such as Technowrap, Stop It, or Super Wrap are

claimed to work on leaking pipe and can be used for chemicals, oil, and gas. Some

systems can be used underwater and use a water initiated curing system, based on epoxy

or polyurethane resins. The systems are supplied as tape 25 to 200mm wide which is

wrapped around the pipe under hand tension to build up several layers. Leaks must first

be sealed with putty or a rubber patch.

Wet laminates are applied by painting the pipe and reinforcing material with an epoxy orvinyl ester resin and wrapping the pipe. Alternate layers of chopped strand and woven

wroving may be used. Leak sealing capabilities of the repairs depend on the pressure

and pipe diameter, but repairs using carbon fibre reinforcement have been used to seal

leaks up to 200bar.

A third technique is to apply a dry pre-formed carbon fibre fabric which is then injected

with resin so that it cures in-situ. Devonport Royal Dockyard have developed a repair

system called the RIFT process (Resin Infusion under Flexible Tooling) and it is

claimed that the repairs produced by this process can be inspected using ultrasonic

techniques because of the low void content. Trial repairs to pipes and tees underwater

have been undertaken and are continuing (7).

Main Menu


13/26


367

9.2.9 Welded patches and half shells.

Fillet welded patches and half shells are simpler to install than full encirclement shells

or hot tap tees, Figure 11. However, their use is not permitted by many offshore pipeline

operators. Their main disadvantage is that they involve fillet welds which are orientated,

at least in part, along the length of the pipe. Since fillet welds have poor fatigueproperties, are difficult to inspect thoroughly, and since the longitudinal direction on a

pipe sees twice the stress of the circumferential direction, there is a danger that they

would constitute a potential source of problems.

Figure 11. Comparison of welded repair fittings

Main Menu


14/26


368

Although some local welded repairs to subsea pipelines have been carried out by wet

welding or welding using a local habitat around the welding torch, for high integrity

there is a need to install a hyperbaric chamber around the pipe and this operation is very

expensive. For this reason the additional extra cost of installation of a full encirclement

shell compared to a half shell or a patch is probably not very significant.

9.2.10 Welded full encirclement shells and hot tap fittings.

Full encirclement shells are lighter, and have better weldability than forged repair

fittings such as mechanical clamps, since they are thinner and normally made from

rolled plate. Although the full encirclement repair shells are nominally classed as snug

fit shells, work has shown that if the fit is too good then defect stress may increase due

to the ovality in the shell created when the longitudinal seam welds cool and contract

(Fig 12). The problem can be overcome by making sure that when the seam welds cool

the shell does not clamp the pipeline. However, the gap between the shell and the pipe

should not be too great otherwise the risk of weld cracking when the circumferential

fillet welds are made increases.

Figure 12. Pipe bending stresses due to pipe and shell ovality and weld shrinkage (from Ref 1).

Main Menu


15/26


369

The shell thickness is normally chosen to be twice the carrier pipe thickness, so that the

fillet weld leg length is at least twice the wall thickness. This is important, because if the

annulus between the pipe and the shell is pressurised, the fillet weld throat can be

stressed to near yield if the pipeline is operating at 72%SMYS. The annulus should only

be pressurised, therefore, when it is essential to do so. One example is to prevent the

propagation of defects which are longer than the critical length for rupture. Pressurisingthe annulus by under pressure drilling of the shell and the pipeline to allow gas pressure

to equalise on each side of the damage will reduce the stress on the defect. Usually this

option is only undertaken rarely, in the case of extreme damage, since it is expensive

and leaves fittings welded to the sleeve which make wrapping it with protective tapes

difficult.

Although sleeve repairs to offshore pipelines could be carried out by wet welding, the

highest quality repair would be achieved by installing the sleeve inside a hyperbaric

weld chamber.

9.2.11 Local weld deposition repair

Weld deposition repair of localised defects, such as corrosion, on a live pipeline is an

operation which needs to be carried out with great care and little published research is

available. However, the technique has been used on a number of occasions for onshore

pipelines, particularly where an Engineering Critical Assessment may not require an

immediate repair but further corrosion may be anticipated due to the location or

geometry of the pipeline. Recently the technique has been incorporated into the AGA

pipeline repair codes.(8)

.

Although such a technique is useful to have available for special situations, the potential

for the general use of this technique is not very great. This is because the defect depth

window for application of the technique is rather small, lying between the depth of

corrosion which may be dressed and left intact without further repair (up to 40% of wall

thickness in some cases) and the minimum remaining ligament for safe welding (usually

about 5mm) which must remain after the corrosion has been dressed. (Fig 13). Also the

technique is not economically attractive for the recovery of large areas of pipe surface

because of the welding times involved. In these cases a welded or epoxy grouted shell

repair would be more suitable.

Also, for offshore pipelines the same arguments would apply as those previously

discussed for patches and half shells. In order to produce a technically acceptable repairthe weld deposition operation would have to be carried out in a hyperbaric chamber and

the extra cost of using a full encirclement fitting would not be very great.

Main Menu


16/26


370

Figure 13. Schematic of weld deposition repair window.

The weld deposition repair method discussed above is suitable for the repair of external

defects, such as corrosion and, of course, requires access to the external surface of the

pipeline. Some pipeline corrosion problems are internal, such as the preferential

corrosion of weld root beads in wet gas or oil pipelines or process pipework. This

problem can be very serious in old pipelines and has led to the need for complete

pipeline replacement in some cases(9)

. There has, therefore, been an interest in

equipment which will carry out remote internal repair welding of pipelines without the

need to excavate the pipeline, or to use expensive habitats in the case of subsea

pipelines.

The technology to carry out welding inside a pipe has existed for many years. One of the

oldest mechanised welding systems for pipeline construction, the CRC Evans process,

uses an internal pipe alignment clamp containing GMAW welding heads which deposit

the root bead from inside the pipe(10)

. Similarly internal welding machines have been

constructed to weld tubular tethers for floating platforms(11)

.

At first sight it would seem possible to combine such technology with a specialised pigwhich could carry out internal repairs to de-commissioned, but not excavated, offshore

pipelines. The difficulty in using such technology to carry out remote repairs is the

problem of transmitting sufficient power to the repair equipment to allow the welding

process to operate. Consequently, the only remote internal repairs of this type have

been carried out in onshore pipelines by tethered vehicles which are supplied with

power via an umbilical from a suitable access point in the pipeline. The Japan Gas

Association reported the development of an internal welding robot system for 600mm

diameter pipelines which was designed to produce an internal weld root reinforcement

for old pipelines with partial penetration girth welds, Figure 14(12)

. The system, which

employs internal grinding of the weld preparation, followed by gas metal arc (GMAW)

Main Menu


17/26


371

welding controlled by video monitoring, can negotiate 1.5D bends in the pipeline but is

limited to a maximum distance of 150m from the access point, Figure 15.

Figure 14. Schematic of girth weld internal repair welding procedure (from Ref 12)

Figure 15. Schematic of remote repair robot (from Ref 12)

Although there have been proposals to develop similar equipment for the internal repair

of offshore pipelines the high development costs and logistical difficulties of deploying

such a device offshore have prevented any progress in this direction.

Main Menu


18/26


372

9.2.12 Cut out pipe section and replace welded spool piece

If the corrosion or damage in the pipeline is too severe to allow a local repair, such as

the welded sleeve, then the damaged section may have to be replaced. This can be

carried out without disrupting the supply through the pipeline by a technique known as a

stopple and bypass operation, Figure 16. A pair of split tee pieces are welded to thepipeline either side of the damaged section of the pipeline and under-pressure drilling

equipment attached to the outer two tees is used to penetrate the pipe wall (hot

tapping). It is then possible to install a bypass pipe between the valves attached to these

tees. The inner two tees are then drilled in a similar manner and stopple plugs are

inserted into the pipeline to stop the flow in the damaged section. After purging the

product from the isolated section it can then be removed and replaced with a new

section. It also possible to obtain combined stopple and bypass tees so that the number

of large diameter tees which need to be welded to the line is halved, Figure 17. If the

pipeline is designed for sour service then the welding procedure for attaching the fittings

to the pipeline must be designed to ensure that NACE hardness limits are met(13)

.

The stopple fittings have to be welded to the pipeline inside a hyperbaric chamber,

Figure 18 although the tapping operation can be carried out in the wet by divers, Figure

19(14)

.

Obviously such a major operation, which involves leaving a large number of expensive

fittings permanently attached to the pipeline, is very time consuming and expensive and

hence the importance of regular inspection programs to help avoid the need for such

repairs. The number of such bypass operations for subsea pipeline repair was only

estimated at three in total in 1990(15)

Figure 16. Schematic of stopple and bypass operation

Main Menu


19/26


373

Figure 17. Combined Stopple and Bypass Tee. (courtesy T D Williamson).

Figure 18. Welding tee to subsea pipeline inside hyperbaric chamber(14)

Main Menu


20/26


374

Figure 16. Tapping a subsea pipeline.(14)

9.2.13 Cut out pipe section and replace - mechanical connectors

An alternative to the expensive hyperbaric welding operations involved in the

conventional replacement of damaged pipe sections is the option to use in-line

mechanical connectors to tie-in the new pipe section.

Mechanical connectors can be of several types :

those which use elastomer seals. those which use metal to metal seals initiated by bolts or studs. those which use metal to metal seals initiated by deformation of the pipe/coupling.

9.2.13.1 Elastomer systemsThese systems use elastomer seals (which may be bolt activated) to contain the internal

pressure and usually a separate system, such as mechanical locking slips which grip thepipe outer surface to contain the axial loads. Some systems also rely on grout injection

behind the seals as an additional precaution. The long term performance of elastomeric

seals may be questionable and the seal material has to be chosen carefully for the

anticipated service environment..

9.2.13.2 Forging systemsOne cold forging system uses an internal forging tool which expands the pipe bore by

means of rollers so that the pipe yields circumferentially and makes intimate contact

with the bore of the coupling. The bore of the coupling may have grooves into which the

pipe material is deformed in order to give greater pull out resistance. After forging the

Main Menu


21/26


375

pipe yields plastically by about 2% and the coupling is in a state of elastic tensile hoop

stress, so maintaining metal to metal contact.

A flanged coupling is attached to each end of the damaged pipeline and then a flanged

spool piece is fabricated topside to go between the two flanges. In order to

accommodate any misalignment in the two pipe ends and to ease the difficulty infabricating the spool piece exactly to length, various articulated ball joint connectors and

sliding joints are available. However, care must be taken to ensure that these connectors

do not pose an obstacle to pigging operations.

9.2.13.3 Metal sealsAnother mechanical coupling system uses an expandable steel bladder which is inflated

inside the coupling to grip the pipe by means of hydraulic pressure or a chemical action.

A further form of metal/metal seal is the use of heat shrinkable alloy couplings.

Couplings made from the memory alloy Tinel can be expanded by immersing them inliquid nitrogen, after which they are placed over the ends of the pipe to be joined and

allowed to warm up. At this stage they contract, and sealing glands in the bore of the

coupling grip the pipe.

9.3 ANCILLIARY REPAIR EQUIPMENT

Two of the first problems that may be encountered when carrying out an emergency

repair to a subsea pipeline are excavation of the pipeline and the removal of any

damaged concrete weight coating in the area of interest. The former will be necessary to

access the damaged area and the latter may be required to investigate the pipeline

damage and to ensure sealing of any temporary clamps.

9.3.1 Pipeline excavation

Excavation of the damaged pipeline can be problematic in unstable seabed conditions

and a coffer dam may need to be constructed around the pipeline to prevent the

excavation from being re-filled and to provide protection from tidal currents during the

repair, Figure 20.

BG plc developed a self-burying coffer dam to keep on standby for emergency repairs to

its Rough Field and Morecambe Bay pipelines. This used a series of water jets built into

the base of the dam which were fed from a ring main at the top of the dam. The waterjets fluidised the seabed, which was then pumped away by jet pumps, also built into the

wall of the dam, so allowing the dam to sink into the channel which had been formed,

Figure 21.

Main Menu


22/26


376

Figure 20. Use of coffer dam for subsea excavation (from Ref 3).

Figure 21. Prototype self burying coffer dam (from Ref 3)

Main Menu


23/26


377

For more difficult clay seabeds a rotary clay cutting device was also developed which

uses water jet cutters to break up the clay, the debris again being removed by jet suction.

This equipment can be mounted on a seabed crawler to manoeuvre it over the seabed,

Figure 22.

Figure 22. Prototype clay cutting equipment (from Ref 3)

9.3.2 Concrete weight coating removal

Once the pipeline has been excavated the concrete weight coating must be removed. The

weight coating is reinforced with steel reinforcing bars, and both the concrete and the

reinforcing can be removed with underwater disc cutters or high pressure water jetting.

Although this can be done manually by divers, a mechanised system has been developed

by BGplc and this allows greater control of the operation, with less risk of damage to the

pipe.

The mechanised system consists of a saddle frame which straddles the damaged area of

pipe and is held in place by chain tensioners, Figure 23. A diver operated hydraulically

driven diamond tipped saw is mounted on the frame and can cut in both the longitudinal

and circumferential directions. Then concrete is cut into two semi-cylindrical shells

which are removed from the pipe with a second machine.

Main Menu


24/26


378

Figure 23. Schematic of concrete coating slitting equipment (from Ref 3).

The second machine consists of another saddle frame held in place by chains, but in this

case four rams are arranged to grip the two half shells of concrete and prise them apart

in order to remove them without damaging the pipe, Figure 24. Experience with the

equipment suggests that 2m long sections of concrete can be removed from the pipe in

four to six hours, depending on the visibility.

Figure 5 Schematic of concrete coating removal equipment (from Ref 3).

Main Menu


25/26


379

The optimum solution for concrete weight coating removal will depend on a

combination of factors, such as equipment availability, area to be removed, and the

location of the reinforcing bars through the concrete thickness.

9.3.3 Flow stopping pigs

The replacement of pipe sections using conventional stopple and bypass methods is very

expensive. An alternative is to use flow stopping plugs and these can either be directly

or remotely operated. Directly operated plugs can be used to replace components such as

valves and risers at the end of the pipeline and are operated by umbilicals passing

through pressure seals(16)

. Because of the need to use umbilicals these types of flow

stopping pig can only operate at a distance of a few hundred metres from the access

point.

Remotely deployed plugs rely on battery power and computer control to allow them to

be deployed several kilometres down a pipeline. A recent example of the use of such a

plug was to carry out a subsea tie-in on the Phillips 34inch Ekofisk oil pipeline whilethe pressure in the line was 35 bar

(17). A two stage (low pressure and high pressure

differential) plug was designed which was over 4 metres long, Figure 6. Communication

with the plug was via the pipe wall using magnetic modulation techniques from a skid

unit placed on the pipe wall, with signals relayed to the surface control vessel. Pressure

sensors were used to monitor pressures in the various parts of the plug so that any

leakage in the high or low pressure parts of the plug could be detected. The plug was

tested at 70 bar and successfully deployed for operation at 35 bar.

Figure 6. Hydroplug flow stopping pig schematic(17)

Main Menu


26/26


9.4 REFERENCES

1. W PALLAN Pipeline Maintenance and Repair Pipeline Industries GuildMeeting, 9 September 1987, Killingworth, UK.2. I CORDER, P HOPKINS The Repair of Pipeline Defects Using Epoxy Filled

Sleeve Repair AGA 8th Symposium on Line Pipe Research, 26-29, September 1993

3. L M JOHNSON, Maintenance and Repair of Pipeline Systems PipelineIndusriesGuild/Institute of Gas Engineers Joint Meeting, Ambergate 14

thSeptember 1994.

4. N BLOCK Rehabilitation of Corroded Pipelines : Strength Restored withComposites Rehabilitation : Piping and Infrastructure Conference, Newcastle upon

Tyne 24-25March 1999.

5. D R STEPHENS Composite Reinforcement of Pipeline Corrosion Defects - : NewAnomalies EPRG/PRC 10th Biennial Joint Technical Meeting on Linepipe

Research, 18-21 April, Cambridge, England.

6. P A C MEDLICOTT Overview of Composite Offshore Repair SystemsRehabilitation : Piping and Infrastructure Conference, Newcastle upon Tyne 24-

25March 1999.

7. P S HILL Strengthening and Repair of Pipes and Structures using Carbon FibreReinforced Composite Materials Piping and Infrastructure Conference, Newcastle

upon Tyne 24-25March 1999.

8. J F KIEFNER, W A BRUCE, AND D R STEPHENS Pipeline Repair ManualAmerican Gas Association Catalog No L51716, December 31, 1994.

9. C J LONDON The Forties Export Pipeline Project Pipes and PipelinesInternational May-June 1991, 7-13.

10.R L JONES CRC Automatic Pipeline Welding Pipeline Industries Guild Journal

67, 1979, 5-18.

11. ANON New techniques for Heidrun Highland Fabricators house magazine

March 1994.

12. JAPAN GAS ASSOCIATION Internal Welding Robot System for 600mm Steel

Pipelines Berlin 18th

World Gas Conference 1990

13.ANON Innovative EWI Hot tap welding procedure helps BP EWI Insights,

May 1992.

14.G HUTT, A WEST, R STARSMORE Hot Tapping on a Subsea Pipeline Welding

and Metal Fabrication 136-139 April 1995.15. R WILLIAMS Subsea Hot Tapping : A Review of Applicable Codes and

Standards. Pipelines for Marginal Field Studies 280-281 1990.

16. J NAYLOR New Pipeline Isolation Systems Benefit Maintenance and Servicing

of On-Shore and Offshore Lines Pipes and Pipelines International, 17-18, July-

August 1977.

17. J A FARQUE Remotely Operated Hydroplug Keeps Vital Pipeline Online

Pipeline & Gas Journal 44-47, February 1999.

Main Menu

Offshore Pipeline

Documents

Transcript of Offshore Pipeline