Offshore Pipeline Construction Volume Two

August 16, 2017 | Author: SUNLAMOR | Category: Quality Assurance, Pipeline Transport, Leak, Risk, Risk Management
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Offshore Pipeline Construction V.2...


Pipeline, riser and subsea engineering

Offshore pipeline construction


All information contained in this document has been prepared solely to illustrate engineering principles for a training course, and is not suitable for use for engineering purposes. Use for any purpose other than general engineering design training constitutes infringement of copyright and is strictly forbidden. No liability can be accepted for any loss or damage of whatever nature, for whatever reason, arising from use of this information for purposes other than general engineering design training. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means whether electronic, mechanical, photographic or otherwise, or stored in any retrieval system of any nature without the written permission of the copyright holder. Copyright of this book remains the sole property of: Jee Limited Hildenbrook House The Slade Tonbridge Kent TN9 1HR England © Jee Limited 2006

Table of contents Volume one PREFACE








What is S-Lay?


S-Lay Vessel Types


S-Lay Process


Market and Vessels


Welding and NDT


Procedure Methods Defects NDT

61 66 74 75

Insulated Lines


Lay Curve Control






What is J-lay?


J-lay Vessels


J-lay projects


J-lay Sequence


J-lay Performance


Rapid Pipe Welding


Mechanical Connectors


Drilling Rig



Offshore pipeline construction





Track Record


Bundle Design


Bundle Fabrication


Towhead Structures


Towing Methods


Insulation & Heating Systems


Re-usable & Deepwater Bundles


Advantages of Bundles


Surface Tow








Unbonded flexibles


Load-out Pipe lay J tube pull End pull-ins Riser installation

192 195 200 202 204

Umbilical cables


Bonded hoses


Manufacture Installation

210 212





What is Reel-lay?


Reel Lay Process


Reel-Lay Market & Vessels


Special Considerations


Technical Analyses






Pull ashore


Pull offshore


Directionally drilled landfalls








Flanged connection by diver


Hyperbaric welding


Diverless tie-ins








Gauging and Flooding






Air and Vacuum Drying


Testing of valves and controls








Quality Assurance


Health Safety and Environment


Commercial risk management


















Survey methods


Geophysical surveys Geotechnical surveys Visual surveys

Survey Operations


428 433 436


453 455


Offshore pipeline construction



Rock removal




Rock dump


Concrete Mattresses


Protective structures
















Cable trenching


Trench Transitions










Diving & Equipment


Physiology Saturation diving Surface diving and hard suits Market

Remotely Operated Vehicles Types Tools Specialist ROVs Deck equipment Market


533 540 551 554

561 561 568 569 579 583








Decommissioning in-situ


Cleaning Product removal Trenching

600 602 603

















EXPECTATION ƒ Understand the processes of ƒ Pigging, ƒ Gauging and ƒ Flooding of line

ƒ Know the hydrotest procedure and how to find leaks ƒ Understand the need for dewatering and drying of line prior to it entering service

Here we examine the precommissioning stage of a pipeline construction project. This stage involves the pipeline being tested to ensure its integrity and then having the product introduced to the pipeline system. The processes of pigging, gauging and flooding the line prior to hydrotest are presented. The hydrotest procedure is discussed along with the methods available to determine leaks in the system. Finally, the dewatering process and the need to dry the line are described.

Offshore pipeline construction


INTRODUCTION This section addresses pre-commissioning, by which we mean the flooding, testing and dewatering of a pipeline ready to receive product. The presentation reflects the sequence of precommissioning events normally seen in practice. They fit between completion of pipelay and startup of the pipeline. However, trenching and tie-in also need to be fitted in during the same period, giving rise to a number of possible overall sequences of events.

WHAT IS PRECOMMISSIONING? ƒ Purpose is to prepare pipe for operation ƒ Convince client that line is ‘fit for purpose’ ƒ Main steps ƒ ƒ ƒ ƒ ƒ

Remove construction debris Check pipeline bore Perform hydrotest Dewater pipe Dry pipe if a gas line



WHO DOES IT? ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Copipe (PSL Group, took over Chorley) PII Technomarine (now part of GE Energy) Weatherford McAlpine BJ Services Green Hydrotest Val Hydrotest LGS Halliburton

A number of specialist contractors are used to undertake pre-commissioning work. They may also supply compressor rigs earlier during the laying operations as part of a buckling contingency system. This can be then used during the final handover to the client.

Offshore pipeline construction





Vent valve D and gauge

Mainline trap valve B

Pig signaller

Pig Trap kicker valve C

Flow Mainline bypass valve A


Launch tray

Under normal operation, valves A, B and C are left open and the pig launcher door is kept closed. When a pig is to be launched, the valves B and C are closed and the vent valve D is used to release gas pressure. The door is opened and the pig pushed into the trap. Valve D is shut again. The door resealed and valve C cracked open again until the trap pressure equalises with that of the pipeline. Valve C is closed and valve B opened. The pig can be launched by opening valve C again and then gradually closing valve A. A pig signaller indicates passage of the pig. Once the pig is in the main pipeline, valves A, B and C are fully opened again for normal operation. For pig receipt, a similar unit (called a pig catcher in USA) is used except that the pig signaller is on the other side of valve B to indicate that the pig has been caught. The photographs show a typical landline pig launcher and a subsea unit supplied by Pipeline Engineering ( to installation contractor Subsea 7. This operates at a depth of 130 m (426ft) in Esso’s Jotun field in the North Sea (Norwegian sector). It is a 150 mm by 250 mm (6in by 10in) subsea class 1500 vertical pig launcher with receiver facilities. The unit can launch or receive both conventional and intelligent pigs.



It has full subsea capabilities including a soft landing system and ROV operations compatibility. The unit consists of three sections: a manifold interface, the protection head and pig launcher. The manifold section is bolted to the subsea manifold and includes three pedestals for the Soft Landing System. When the launcher/receiver is not in use, the protection head is used to protect the manifold from damage and corrosion. It is fitted with hydraulic quick connect/disconnect collett connectors and a control panel to allow removal and connection of the head by ROV. The pig launcher assembly, which is kept either onshore or on the barge until required, is fitted with three pig release fingers and three baskets capable of launching and receiving three conventional pigs or one intelligent pig respectively. The pig launcher and receiver is designed in accordance with BS 5500, permanent pipework to Det Norske Veritas (DNV), and the launcher/receiver structure to DNV and NORSOK.


ƒ Treated water

ƒ Pinger for location

ƒ ƒ ƒ ƒ

ƒ Bypass port ƒ Breaks up and sweeps out debris in suspension

ƒ Prior to trenching

Deoxygenator Biocide Corrosion inhibitors Fluorescent dye

ƒ Drives pigs forward

ƒ After burial for landlines Metal or plastic body Bypass jets Flow Debris Pipe wall

Suspension rubber cups

The pipeline is flooded with treated seawater using a bi-directional pig. The purpose of using a Bi-Di pig is that it can, if necessary, be driven in the reverse direction if it does become blocked with debris or stuck at a dent. This pig has the additional function of sweeping out debris and dust. The pinger acts as a sound source in case the pig needs to be located or tracked. It may be fitted with bypass ports to allow some flow past the pig to keep debris in suspension in front of it, rather than accumulating into a plug. It is run prior to trenching the line to increase self weight and permit repairs should defects be detected. Landlines are pigged following trenching because of safety concerns during pressure testing. The pig is driven using seawater that is treated to prevent it causing corrosion of the line. It is typically deoxygenated and contains corrosion inhibitors, biocides and a fluorescent dye to assist in detecting any leaks. Some chemicals may not be added initially, because of environmental concerns.

Offshore pipeline construction


When arctic landlines are flooded, either hot water with methanol can be used or even hot oil. This is to prevent freezing during the hydrotesting but may prove more difficult to dispose of and runs the risk of environmental discharges if the line leaks.

PUMPS ƒ Reciprocating/positive displacement pumps ƒ Volume measurement ƒ Hydrotest pressure capability

ƒ Monitor and record volume and pressure versus time

Monitoring flow volumes and pressure versus time is vital in determining when to expect the pig to arrive, and in helping to locate it if lost. For example, a pressure blip might occur on contact with a dent.

GAUGING ƒ Performed using a gauging pig ƒ Aluminium disk slightly smaller than bore ƒ DNV 97% ƒ US 12.7 mm (½in)

ƒ Inspect for damage – confirm minimum bore ƒ Disk saved as proof

ƒ Indicates blockage ƒ Dents require repair

ƒ Front disk ƒ Shows debris height



The size of minimum bore is confirmed using a gauging pig. This is fitted with an aluminium disk that is slightly smaller than the design diameter of the pipeline. If there are no indications of damage on the edges such as scores or bent areas, this indicates a clear bore. The disk can be removed and saved as positive evidence by the client. Rather unusually, the pig shown in the photograph has an additional disk at the front. This would provide indication of the height or size of any debris detected. Inspection of the disk will indicate whether any significant blockages are in the line. If so, then the damaged section would have to be found and repaired. One way of finding the damage is to run the pig again with an accelerometer attached to a recorder. This will pick up the girth weld beads as it moves down the pipe. When the pig hits the debris or damage, a characteristic spike of acceleration is recorded. Other defects found might include weld ‘icicles’ at the girth welds and pipe impact damage due to anchor handling during lay.

SUBSEA PIGGING UNITS ƒ Controls launch of pig train and flooding of pipe ƒ Combined with pull head ƒ Preloaded with pigs Combined pull head and multiple pig launcher

The above subsea pigging unit from PSL allows the diverless flooding and pigging of the pipe. The combined pulling head and pig launcher for the Claymore line holds a number of pigs for the initial pre-commissioning. Each can be fired individually to flood and prove the bore.

Offshore pipeline construction


INTELLIGENT PIG RUN ƒ Baseline record of pipe wall ƒ Magnetic flux pigs

Though not always undertaken, good practice now suggests that an intelligent pig run be undertaken to provide a baseline record of the pipe wall and any surface defects. Intelligent pigs are normally run at intervals of 5 or 10 years to detect corrosion. Knowing the initial condition helps in determining future inspection frequency. The picture above shows the PII magnetic flux pig. In the picture you can see the magnetic brushes and the finger-like arrays of magnetic flux detectors. The rest of the pig contains power and data storage facilities. It is used to detect internal and external corrosion defects in oil and gas pipelines. Variants are available to detect both axiallyoriented and hoopwise-oriented cracks. Typical speeds of intelligent pigs are from 0.3 to 5 m/s (1ft/s to 16 ft/s). If the product flow is faster than this, it is normal to include a bypass system to permit the pig to travel slower than the oil. Head losses for pigs are typically less than 1 bar (15 psi).



GAUGING AND FLOODING SUMMARY ƒ Gauging ƒ Use gauge pig to confirm minimum bore ƒ Establish presence of dents or debris

ƒ Flooding ƒ Fill pipeline with water to enable hydrotest

Any questions?

Once the pipeline has been installed, a gauge pig is sent through to confirm that the minimum bore has been achieved and there are no dents or debris in the line. Once gauged, the pipeline is flooded with water. The water is then pressurised to hydrotest the pipeline and confirm its strength.

Offshore pipeline construction



HYDROTESTING ƒ Pressurise all parts of system – repeat tests ƒ Code dependent ƒ 1.5 times maximum allowable operating pressure (MAOP) or design pressure (or 90% hoop stress) for 24 hours ƒ Time for latent defects to reveal themselves ƒ 1.25 times for 8 hours in USA ƒ Gas lines – may exceed yield wall (105%) for stress relief

ƒ Risers ƒ Separate strength test to a higher pressure ƒ Increased safety (wall thickness) adjacent to personnel

ƒ Tie-in joints ƒ If all components of pipeline have been strength tested then leak test at 1.1 times MAOP for 3 to 6 hours

The purpose of hydrotesting is to prove the strength of the pipe. The reason for using water is to minimise the energy contained in the pipeline in case there is a failure (which could be far more catastrophic in a pneumatic test). The hydrotest may be carried out on individual sections and components of the pipeline. There may be many repeat tests at each stage – prior to and following trenching of a subsea pipeline then once again after burial. Hydrotesting should be distinguished from leak testing, which is at a lower level of pressure and simply proves that the joints between the assembled components seal. This is usually carried out on the complete pipeline after all tie-ins have been completed. A satisfactory result usually signals contractual end of pipelay activity. The hydrotest pressure on the pipeline is set to 1.5 times MAOP, or 90% of hoop stress (whichever is less). The test is held for 24 hours. This is for two reasons: ■ to ensure that small leaks are detected ■ in the past, some failures have been shown to be time-dependent and have occurred within the 24-hour period



Once the pipeline, the spoolpieces, the risers, the valves and the pig traps have all been strength-tested individually, the pipeline is assembled and leak-tested to 1.1 times MAOP for 3 to 6 hours, or as long as it takes to prove that all assembly joints are sealing.

HYDROTESTING FLEXIBLES ƒ API 17J ƒ Factory acceptance test ƒ 24 hours ƒ 1.5 x design pressure ƒ Fresh water with stainless armour wire ƒ Gradual reduction in pressure

ƒ Offshore leak test ƒ 6-8 hours ƒ 1.1 x design ƒ Repaired structural damage ƒ 1.25 x design

API 17J defines the pressure testing requirements for flexibles. They follow a similar pattern to rigid lines except that the strength test is the factory acceptance test, ie it is done on completion of manufacture of the flexible, before it is installed. The factory acceptance test is at 1.5 times the design pressure, and is held for 24 hours after an initial settling down period. Fresh water is normally used, particularly where there is a 316L stainless steel liner which can suffer chloride stress corrosion cracking when subject to seawater. Some manufacturers will increase the initial test pressure by (say) 4% so that the minimum pressure during the 24 hour period remains above 1.5 x design pressure, despite slight relaxation of the layers and variations due to temperature. There will be a gradual reduction in pressure with all flexible lines because the water permeates through the lining. So a limit is set on both time and pressure. Once installed, the flexible is leak tested to 1.1 x design pressure for 6-8 hours. Practical constraints often dictate that this test is done with seawater. This can be accommodated even with 316L liners, so long as the seawater is removed promptly and completely afterwards. One reason for the shorter duration and lower pressure of the leak test is to guard against extrusion of the polymer liner into the gaps in the pressure vault layer. If damage has occurred during installation and repairs have been undertaken, then the flexible must be retested to 125% of the design pressure at this stage.

Offshore pipeline construction



ƒ Flood and pressurise line


P/V p lot

ƒ Likely source of leak ƒ Weld sealed

retica l

ƒ Small bore connectors

Pressure head

T heo

ƒ Safety in pressure testing

c line

ƒ Exclusion area apart from operator ƒ BS 8010-2.8 ƒ HSE guidance note GS4


ƒ Monitor head loss Volume of Volume of air water added ƒ Assess air content ƒ Correct for temperature and expansion fluctuations The hydrotest operation should be carried out by trained personnel within an exclusion area in case anything should occur. This is one reason that air tests at high bar ratings are now discouraged. Lines may have a rating of 200 bar (2.9 ksi) or more. The basics of pressure testing are covered in Section 8 of BS 8010-2.8. Safety considerations whilst dealing with unproven pressurised vessels are detailed in the HSE guidance note GS4. A common source of apparent failure of pipelines is the very test equipment itself. Small bore screwed connectors are often welded tight to prevent minor leaks. The pipeline is flooded and pressurised and the head monitored. An assessment is made of air content by extrapolating the measured trace back to the lower axis. For land lines, corrections need also to be made for diurnal temperature effects, which cause the pipe wall to expand.



FINDING A LEAK ƒ Check tie-in connections ƒ If in the body of pipeline: ƒ ROV or aircraft (helicopter) finding dye slick ƒ Acoustic detection of noise from leak ƒ Set remote plug and test against in systematic pattern

ƒ Difficult with multiple leaks and with trenched pipe

If the pressure does not hold, the rate of decay (given the volume of the pipeline) will point to how big the leak is. The obvious points to check first are all the flanges and tieins. With those eliminated, it is a matter of finding the leak in a pipeline. The slide lists various approaches: ■ Run an ROV along the pipe looking for the fluorescent dye, and perhaps also carrying an acoustic detector to listen for the noise of the leak. ■ Fly the route and look for a slick: sometimes the dye has an oily element which can be seen, or picked up due to its fluorescence. ■ If neither of these is successful (as could well be the case if the pipeline is buried), then it is necessary to run a remote set plug in a search pattern. It would be set at the half way point and one side of the pipeline pressured up. If it held, then the leak would be in the other half, and the plug would be set at the quarter point in that half, and the process repeated until the area of the leak could be found. ■ An alternative is for the remote set pig to detect the direction of flow of the leaking water. ■ The process becomes still more complex when there is more than one leak.

Offshore pipeline construction



As an alternative to a pinger, the above shows the Pig Home Tracker system (from PSL), where the pig carries a transponder allowing its position on the Earth’s surface to be determined using GPS.

HYDROTESTING - SUMMARY ƒ Confirms ƒ Strength of the pipe ƒ Leak-tightness of flanges and tie-ins

Any questions?

Hydrotesting is the pressurising of the water-filled pipeline to a pressure greater than the normal operating pressure. The purpose is to confirm the strength of the pipeline and to check for leaks at vulnerable locations, such as flanges and tie-in points.




DEWATERING Direction of pigs trains

Oil line

Hydrotest water

Dewatering of oil trunk lines to terminal or refinery Oil or Gas



Methanol/ water mix

Fresh water

Hydrotest water

Fresh water

Hydrotest water

Dewatering of process lines Nitrogen

Methanol or gel

Methanol/gel water mix

Dewatering of sour gas lines or high purity sales gas lines to national transmission system

Dewatering is removing the water from the pipeline. The pipeline is dewatered after all hydrotesting and leak-testing activities have been carried out. Where the pipeline is used for oil, it may be sufficient to use a single pig together with a separator tank at the terminal facility. The above diagram shows a commissioning train of high-seal mechanical pigs with slugs of methanol between them. Immediately following the first pig, a slug of fresh water flushes any salt from the line. The first slug of methanol will pick up water left behind on the pipe wall, and will become diluted. The second and third slug will leave a small amount of ‘hydrate-inhibited’ water on the pipe wall. A slug of nitrogen behind the methanol separates it from the production oil or gas which drives the train. This situation is sufficient for most purposes:

Offshore pipeline construction


■ ■ ■

Oil lines (and other liquid lines) Two phase lines Gas/condensate production lines

Where a high product purity is needed, or a very low dew point (as in high purity sales gas for the national transmission system, or in sour gas lines), then the pipe also needs to be dried. In these cases, the train will be driven by nitrogen instead of oil or gas. Another alternative is for aqueous gels to be used instead of methanol.


Nitrogen skid – requires separate supply of nitrogen in tanks

Deoxygenating and drying unit

A nitrogen skid is required to store liquid nitrogen, vapourise it, and pump it up to line pressure. Where supplies of nitrogen are difficult to obtain or where large volumes are required, one alternative may be to use deoxygenated air. This is of a similar modular size containing the oxygen separator and drying units but does not require the supply of costly nitrogen in remote areas of the world. Occasionally in Nigeria and other remote regions, hot air has been used instead of nitrogen. However, this causes the same safety concerns as air (rather than hydro) testing.



DISPOSAL OF TEST WATER ƒ Disposal of test water ƒ Aeration and neutralisation of additives

ƒ Recovery of methanol for processing ƒ Separator tanks for oil/water/methanol mix

It is necessary to safely dispose of the test water following use. This is usually fed back to the sea once the additives have been neutralised with additional chemicals. Hydrogen peroxide or sodium bisulphide detoxifies the biocide. Aeration removes the effects of the oxygen scavenger. The methanol/water mix can be run into separator tanks for recovery and processing. As the product arrives, separator tanks are used to remove any remaining water from the oil.

Offshore pipeline construction


DEWATERING - SUMMARY ƒ Cannot mix product with hydrotest water ƒ Use pig train to introduce slugs of methanol or gel ƒ Absorb water and dry the line

ƒ Final pig followed by product or nitrogen ƒ Sufficient in itself for oil and most gas lines

Any questions?

Dewatering is the process of removing the hydrotest water from the pipeline, in preparation for flooding the line with product. The water and product are separated by a pig train, within the pig train are slugs of drying chemicals. As the pig train passes along the line, these absorb the water and so dry the pipeline ready for receipt of the product.




AIR/NITROGEN DRYING OF PIPELINE ƒ Foam pig swabs – absorb & push water out ƒ Warm desiccated gas (air or nitrogen) ƒ Nitrogen preferred for hydrocarbon lines (safety)

ƒ Reduction in outlet hygrometer readings ƒ Indicates reduction of dew point ƒ Completion of drying ƒ Typically a differential of 5C° (9F°) between inlet and outlet

ƒ Usually completed within a few days even for large diameter trunk lines Foam pig trains may initially be run to act as swabs, removing any condensed water from the walls and push any liquid out in front of them. Then warm dry gas is delivered to the inlet. Either air or nitrogen is used. The latter is an inert gas so has the advantage for hydrocarbon lines in that we can safely introduce gas without fear of explosion. The picture shows BJ process air drier unit. This can deliver -73°C (-100°F) dewpoint air which is used to achieve extremely low dewpoints during pipeline drying. As the differential dew point readings reduce, the drying process is completed. It is common to achieve a final dewpoint of -20°C (-4°F). This is a rapid process, but which may be followed by additional vacuum drying.

Offshore pipeline construction


VACUUM DRYING ƒ Export gas lines only ƒ Follows nitrogen drying A - Pump down phase B - Vapourisation/evacuation phase C - Dehumidification/vacuum purging phase (check for ice crystal formation – allow to re-melt) D - Vacuum release & return to atmospheric pressure

Pressure (millibar) Logarithmic Scale



0 0

B Drying Time (days)




Vacuum drying means attaching vacuum pumps to one or both ends of the pipeline and drawing a vacuum. It is only used for gas lines where water vapour would be a problem. If you reduce the pressure above water, you also reduce its boiling point. An example of this is that mountaineers find that water boils at less than 100°C (212°F) at altitude, and consequently boiled eggs take longer to cook. Inside the pipeline, the pumps reduce the pressure to the point where water will boil at (say) 4°C (39°F), or whatever the ambient temperature is. The drawdown curve flattens as the water vapour comes off. The finishing process involves stopping the pumps and checking whether the pressure rises. As the pipeline reaches that of the seawater, further vacuum will freeze ice crystals on the inside of the wall. Thus the air will initially appear to be fully dried. However, by releasing the vacuum slightly, these crystals will melt. Only when all the water is converted to vapour and removed from the system will the graph stabilise. It only works where the line has already been dried using other means. Puddles of water take a very long time to clear. If necessary at pig traps, valve chambers etc, it may be possible to enter the line and remove standing water using squeegees. The process can last for 4-12 weeks, depending on the pipeline size and length. For this reason and the costly delays, it is avoided wherever possible.




TEST VALVES AND CONTROLS ƒ Final stage ƒ Confirm all valves and controls are working ƒ May require use of ROV or diver

The main pre-commissioning activity is to de-water the pipeline. For gas trunk lines, this would be done with a train of pigs, perhaps with gel or methanol between them. The line would then be vacuum-dried to remove all traces of water before the introduction of export-quality gas. Such a procedure would not be necessary with two-phase flowlines or an oil trunk line, where the likelihood is that the water would be displaced by a pig train driven by the production. The remaining activity within pre-commissioning is to test and prove the valves and control systems.

Offshore pipeline construction


PRECOMMISSIONING - SUMMARY ƒ Processes of pigging, gauging and flooding of lines ƒ Hydrotest procedure and how to find leaks ƒ Need for dewatering and drying of lines prior to entering service Any questions?

Here we have examined the precommissioning stage of a pipeline construction project. This stage involves the pipeline being tested to ensure its integrity and then having the product introduced to the pipeline system. The processes of pigging, gauging and flooding the line prior to hydrotest were presented. The hydrotest procedure was discussed along with the methods available to determine leaks in the system. Finally, the dewatering process and the need to dry the line were described.





EXPECTATION ƒ Understand the main aspects of the following: ƒ Law ƒ Legal environment applicable to pipeline construction projects

ƒ QA ƒ Quality assurance system to make the work happen as planned

ƒ HSE ƒ System to protect Health, Safety & Environment

ƒ Commercial ƒ System to assess & guard against commercial risk

In this section on Management, we address four main topics, as given above.

Offshore pipeline construction



ACTS ƒ UK ƒ Health and Safety at Work Act 1974 ƒ Petroleum and Submarine Pipeline Act 1998

ƒ US ƒ Outer Continental Shelf Act ƒ River and Harbor Act, 1899 ƒ Federal Power Act, 1920

There are two main UK Acts which set the legal environment for pipeline construction. The Health and Safety at Work Act covers the safety aspects and is promulgated by the Health and Safety Executive. The Petroleum and Submarine Pipeline Act covers the commercial side, and is used with regard to consents for the construction and operation of pipelines. For landfalls, there are additional legal matters to consider, such as interfaces with the Crown Commissioners (who own the beaches) and Local Authorities or local landowners. In the US, the listed acts empower the Department of Interior, the Department of Transportation and the US Army Corp of Engineers as detailed in the following slides.



UK REGULATORY AUTHORITIES ƒ DTI ƒ Department of Trade and Industry ƒ Planning and resource management ƒ Consent to build and operate

ƒ HSE ƒ Health and Safety Executive (Offshore Safety Division) ƒ Safety of people ƒ Day to day inspection and enforcement of regulations

To match the Acts, there are two regulatory authorities in the UK - the DTI and HSE. The Department of Trade and Industry is responsible for planning and resourcemanagement. They give consent to build and operate pipelines. Essentially, this is a commercial role seeking to exploit the resources in the North Sea. The Health and Safety Executive is responsible for the safety of people under the Health and Safety at Work Act 1974.

US REGULATORY AUTHORITIES ƒ Mineral Management Services (MMS) ƒ Department of Interior ƒ Federal landowner & regulator

ƒ Office of Pipeline Safety (OPS) ƒ Department of Transportation ƒ Federal regulator

ƒ States ƒ Louisiana - 1 marine league (3 naut. miles) ƒ Texas - 3 marine leagues (9 naut. miles)

Offshore pipeline construction


The regulators in the US are the MMS and the OPS for federal waters. The MMS is responsible for the exploitation of oil and their scope will include the production facility and any process equipment on the facility. The OPS is responsible for the pipeline system from the first/last flange beyond the process equipment. In nearshore regions, developments and pipelines will come under the control of the state authorities.

MARITIME AUTHORITIES ƒ UK ƒ The Maritime & Coastguard Agency ƒ The Marine Accident Investigation Branch

ƒ US ƒ Coastguard ƒ Corp of Engineers

In addition, offshore construction will interface with the Coastguard and, in the US, the Corp of Engineers. Should there be an accident to a ship, then the MAIB would also become involved.




HSE (doing it safely)




(managing job)

(making a profit)


We are now going to look at QA, HSE and Risk Management. Before going into details, let us look at an overview of how they fit together. They all interlink and follow a similar pattern. The overall pattern is that a Construction Contractor will have corporate policies and procedures in place. These record (respectively) what he does and how he does it. They embody the lessons learned from his previous work, and the experience of his workforce. When a bid comes in, he will develop a plan specific to that job. On award, he will put that plan into effect, and will have an audit loop to see if it is on track. Once finished, he will reflect on what happened and incorporate the lessons learned back into his corporate procedures. The above pattern applies to the three elements (Safety, QA, and Commercial risk), which parallel each other throughout. Let us now examine how this works.

Offshore pipeline construction


LAW - SUMMARY ƒ Government bodies set laws covering the construction and operation of oil and gas pipelines ƒ Need awareness of these laws when undertaking pipeline projects Any questions?

When undertaking pipeline construction projects, it is necessary to be aware of the laws specified by the relevant government body.




QA ƒ What is QA? Any views ƒ Policy and Procedures ƒ Quality Plan ƒ Improvement

This section will address Quality Assurance throughout pipeline construction. As per the previous slide, this will work from the corporate level of policy and procedures, through to the project level of quality plans and quality control, and then look at the feedback/self improvement loop. Quality Assurance in layman’s terms is delivering what you promise, being able to prove it, and learning from your mistakes (getting things right first time). The quality management system is the way you manage a project. It is not some external add-on to police the project manager!

Offshore pipeline construction



Continual improvement of the quality management system Customers (and other interested parties)

Management responsibility Customers (and other interested parties)

Resource management




Value-adding activities Information flow

Measurement analysis and improvement

Product realisation





Any activity, or set of activities, that uses resources to transform inputs to outputs can be considered as a process. For organisations to function effectively, they have to identify and manage numerous interrelated and interacting processes. Often, the output from one process will directly form the input into the next process. The systematic identification and management of the processes employed within an organisation and particularly the interactions between such processes is referred to as the “process approach”. The diagram above demonstrates this process approach which ISO 9000 recommends be adopted in order to manage an organisation. This illustration shows that interested parties play a significant role in providing inputs to the organisation. Monitoring the satisfaction of interested parties requires the evaluation of information relating to the perception of interested parties as to the extent to which their needs and expectations have been met. The figure does not show processes at a detailed level. Quality policy and quality objectives are established to provide a focus to direct the organisation. Both determine the desired results and assist the organisation to apply its resources to achieve these results. The quality policy provides a framework for establishing and reviewing quality objectives. The quality objectives need to be consistent with the quality policy and the commitment to continual improvement, and their achievement needs to be measurable. The achievement of quality objectives can have a positive impact on product quality, operational effectiveness and financial performance and thus on the satisfaction and confidence of interested parties.



QUALITY POLICY ƒ To ISO 9001 ƒ Example contents ƒ ƒ ƒ ƒ ƒ

Company profile Policy and objectives statements Organisation Responsibility and authority Policies

ƒ ‘It is the policy of this company to listen to client requirements and reflect these in our proposed scope of work’ etc. The Quality Policy is a corporate document set out (normally) by a Director in line with the requirements of ISO 9001. It sets out what the Company is, what it is seeking to achieve, how it is organised and who is responsible. It then specifies the policies such as the example given above. Policies comprise a few general statements. They are brought down to earth in the procedures, which state how these things are done.

QUALITY PROCEDURES ƒ Client interface ƒ Subcontractor interface ƒ Technical work ƒ ƒ ƒ ƒ

Welding and NDT Survey and positioning Reeling Lay curve control, etc

ƒ Records and document numbering ƒ Nonconformance, preventive and corrective action

Offshore pipeline construction


Corporate procedures will be organised to suit the needs of the Company. However, they are likely to cover the above subjects. Their content will be along the lines of a definition of the scope of the procedure, a step by step guide on how to do it, and possibly a flow diagram. Work instructions provide detail on how a particular operation or service must be carried out in order to achieve consistent and repeatable quality. Work instructions must include the acceptance criteria applicable to that product or service. Where it is identified (for instance, during final inspection) that the product or service fails to meet the defined criteria, a non-conformance report must be raised and corrective action taken before the product or service can be released to the customer for use. Preventative action must also be taken to ensure that a recurrence of the same nonconformance cannot occur.

QUALITY PLAN ƒ ƒ ƒ ƒ ƒ

Written for each project covering: Responsibilities Audit Document control QC plan ƒ Step-by-step plan for each activity ƒ Defining controls needed at each point ƒ Checks, inspections, approvals and responsibilities

When a job comes in it is necessary to focus the procedures on that job. The Quality Plan does this. It normally reiterates policy and cross-references the corporate procedures. The meat of it is then to define the following: ■ Responsibilities of the people who will be on the project, from project director to project manager, engineers, inspectors, auditors, etc. ■ An audit schedule defining what is to be audited and when, in order to see if the project is on track. ■ Document control for the project, particularly the interface with the document control systems of client and subcontractors. ■ Quality control plan: a step by step plan, going through from start to finish of the job, identifying what controls (checks, inspections, approvals, responsibilities) are needed at each point.



QUALITY CONTROL PLAN FLOWCHART 1 Contract review 2 Preparation of project procedures

3A Review / Amend

3 Submit to client

5 Develop temporary works / design documents

4 Source / order proprietary materials & equipment 7 Develop installation engineering / equipment documents

6 Placement of subcontracts

8 Obtain ‘F L’ materials and carry out WPQTs and WQTs 9 Pipe welding •Visual inspection •NDT •Mechanical tests

9A Accept / Reject

This and the following slide show parts of the QC Plan flowchart of an actual contract. This section covers initiation and inspection for pipeline welding. numbered for identification.

Each node is

The implementation phase takes the above plan and makes it happen.

MORE OF THE FLOWCHART 48 Post lower pipes within cofferdam 49 Post trenching survey

51 Backfill pipes within cofferdam

50 Submit to client for review

52 Remove back anchor wall

53 Extract cofferdam piles 56A Accept / Reject

54 Install cathodic protection system 56 Hydrotest landline (option) 55A Accept / Reject

55 Test and commission CP system

57 Reinstate primary dunes

This section covers restoration of a landfall site following lowering of the pipe in a cofferdam through dunes.

Offshore pipeline construction



Job close-out Lessons learned Amend procedures Management of change

Implementation rarely follows the exact plan and, with hindsight, one would often have taken a different approach. Part of this is automatically captured in the experience of the people working on the job. However, in order to feed into the more general and more permanent corporate memory, it is important to feed the lessons learned back into procedures. All changes, either at work instruction level or at corporate procedure level, must be properly managed by recording and implementing the change to ensure that the latest issue is available for subsequent use. Where a quality management system is certified by an accredited body (e.g. LRQA as complying with the applicable part of the ISO 9000 system), it must be periodically audited by the third party to ensure it’s on-going compliance. Additionally, all of the elements of the quality management system must be audited internally, preferably by the owners of the system, at least once every 12 months.



QA - SUMMARY ƒ Quality Assurance systems specify policies and procedures ƒ Ensure sufficient quality of the product

Any questions?

Quality Assurance (QA) systems enable companies to work towards improving the quality of their product and ensuring the product meets the requirements of the customer. The product could be a pipeline system.

Offshore pipeline construction



HEALTH SAFETY AND ENVIRONMENT ƒ Purpose: ƒ to avoid accidents

ƒ Also called safety management system ƒ ƒ ƒ ƒ

Policy and Procedures Project safety and environmental plan Implementation Feedback

The purpose of the HSE system (typically called a safety management system) is to avoid accidents, both to people and to the environment. HSE management follows the same pattern as QA in terms of starting with corporate procedures, developing a project plan, implementing it and looking for feedback.




Reporting accidents Risk assessments Diver safety Marine vessel procedures Board (accountable for accidents) Company safety advisor

Project manager

(responsible for audit)

(responsible for safety)

The set-up for safety needs to report back outside the project. A generic arrangement is shown in the diagram above, with the Project Manager being responsible for safety on the project, and a competent Company Safety Advisor auditing him. Both of them report back to the board (normally to two different Directors), who will be accountable if there is an accident. Also above are examples of (corporate) safety procedures, which in our experience are normally recorded separately from the quality management system.

PROJECT SAFETY PLAN ƒ Objectives ƒ Avoid accidents

ƒ Scope ƒ Define limits of job

ƒ Responsibilities ƒ Training ƒ Who needs what

ƒ Site safety support ƒ ƒ ƒ ƒ

Visits, meetings, posters Risk assessment, MAPD Accident reporting HSE and local interfaces

ƒ Project specific paragraphs on: ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Signs Lifting Welding NDT Coatings Chemicals Power Trenching Diving etc

The above slide sets out typical contents of a project safety plan.

Offshore pipeline construction



Living document Safety officer on site Safety audits Security regime ƒ Deliberate and accidental breaches

ƒ ƒ ƒ ƒ

Reporting of LTA (lost time accidents) Major Accident Prevention Document (MAPD) Major accident response drills Risk assessment through HAZOP

During the project, the whole team will be made aware of safety and their responsibilities. They will be reminded and audited by the Project Safety Officer, who will also record any LTAs (Lost Time Accidents), and will handle the interface with the HSE.

MAPD ƒ Under pipeline safety regulations, 1996 ƒ Introduced following Piper Alpha

ƒ Major accident prevention document ƒ Write during design ƒ Periodic review to keep updated

ƒ Have documents to prove ƒ You have identified major hazards ƒ You have taken adequate steps to reduce risks (both probability and consequence of hazard) ƒ You have an adequate system for dealing with major accidents In reaction to the Piper Alpha disaster in 1988, the pipeline safety regulations of 1996 required a “Major Accident Prevention Document (MAPD)” for pipelines, much along the lines of the platform safety case.



The MAPD will be drafted by the pipeline designers. It will form part of the safety management system during construction, and will then be handed on to the Operator. The MAPD requires the pipeline operator to identify major hazards and take adequate steps to reduce the risks arising from them. By risks, we mean both the probability of an accident occurring and the consequence of that accident. These documents must be in writing, kept up to date, and available to the operator. They also have to include an emergency procedure for dealing with major accidents. As part of the MAPD requirements, it may be necessary to carry out a drill to simulate an accident, and to see the response. One vital tool in the safety armoury is risk assessment to spot hazards and mitigate against them. Nowadays, it is likely that questions would be asked by the media and government agencies if a large operator were to permit more than an average of perhaps two deaths a year due to his worldwide activities. Failure modes and effects analysis (FMEA) is a tool used by engineers at the equipment and systems design stage. A hazard and operability study (HAZOP) and value engineering (VE) respectively are tools used to identify and eliminate unacceptable risks and to ensure that fitness for purpose is achieved within commercially-acceptable limits. A team (typically of 6-8 people) from various disciplines is required to achieve a productive assessment.

BOSTON CUBE ƒ Risk = probability x consequence

C os el t o im f in ha at za io rd n



Lo w


ƒ High consequence (death rate) ƒ Mid band Low Probability of failure probability Completely safe but ƒ High cost


ƒ Bird flu

Consequence of failure

ƒ Usually 6 x 6 x 6 box ƒ Numerical values for each High

Hazard must be removed

uneconomic design

Risk is normally defined as the product of probability of an event occurring and the consequences of that event. A simple Boston cube is illustrated, which gives a means of presenting and comparing levels of risk. The third axis adds the cost of removal of risk in monetary terms. The consequence of failure is often determined in money terms with a price being put on each life lost.

Offshore pipeline construction


The probability of an event happening is usually determined by the use of event fault trees, reliability block diagram or Markov methods, where reliability values and Boolean logic calculate the likelihood of failure. A failure that has a high probability of occurring and a high consequence would be considered high risk. For most systems, risks in the high risk regions must be removed by design. Even those in the low risk squares should be removed if the costs of doing so are low. The modern risk assessment approach uses fully detailed systems with more boxes than shown, numerically quantifying the likelihood levels for each axis. Perhaps these would have six bands – the lowest being something likely to occur at least once per year, and the highest being an event occurring less frequently than every 10 000 years. Knowing the consequence of failure, we can determine the appropriate or target level for the probability of failure. A current example of assessment may be the bird flu which might become infections by person to person contact. Such pandemics occur perhaps every 100 years: the last was the Spanish flu after the first world war causing more deaths than during the war itself. Estimates of bird flu is that it may kill 1 in 4 (or some sources think 3 in 4). This is much more than for the black death in Europe in the middle ages. So we have a consequence of death of 1 in 4 (High) and a probability of 1 in 100 years (Mid-band) – although currently it is highly likely. However, the cost of removal of the risk is very high with destruction of domestic and wild fowl, even before it mutates into a contagious form. Costs of supplying everyone with the preventative Tamiflu or developing a true antiviral drug once it does mutate are extremely high. The World Bank estimates a total cost of $1.4billion for worldwide elimination. Different governments are undertaking the difficult task of risk assessments using their best estimates for each with slightly imperfect data.

HAZOP ƒ Hazard and operability assessment ƒ Assemble group, define procedure ƒ Brainstorm risks using key words ƒ ƒ ƒ ƒ

More, less, faster, slower, reverse Access, escape, fails, continues Weather, night, visibility Third party,etc

ƒ Assess risk and mitigation ƒ Report and follow up



A HAZOP is a way of risk-assessing a process (e.g. lifting an item onto the seabed). The technique is to assemble a group, some from the project and some with external expertise. This group will review the proposed procedure, will break this up into manageable sections and will then brainstorm using suitable prompt words as above. Ideas of what could go wrong are then assessed in terms of their risk (their likelihood and consequence - low, medium or high in each case). This is risk assessment. Actions are then agreed to prevent the failure occurring, or to forestall the consequences.

HAZOP TABLE AND ACTION SHEET Deviation N° Cause Consequence Safeguards Mitigation Hazard category Deviation N° Cause Consequence Safeguards

Mitigation Hazard category

Deviation Impact damage D7 – 9LPGH1 Dropped load onto fire-fighting pumps/supply cables Potential loss of fire-fighting water supply. Operator training and procedures. Protective cover slabs designed to withstand loads. Limitation of crane lifting within area None identified 2, 3 Deviation Fire/Overheating D8 – 9LPGH1 Fire beneath LPG tank Loss of strength in tank wall leading to rupture and ignition of LPG Flammable liquid prevented from gathering beneath tank due to slope of plinth. Provision of automatic sprinkler system to cool tank. Daily inspection to ensure no debris stored within compound which is liable to catch fire. None identified 1, 2, 3

Action N° Description

On Due A3 – 9LPGH1 A Designer 29 Feb 2003 Quantify the gas production rate and ventilation air-exchange rate in the culvert. Compare this with the flammable limit. If it exceeds the flammable limit, consider providing gas detection system in the culvert.

Deviation N° Cause Consequence

Deviation Explosion/Detonation D9 – 9LPGH1 Leak from flange, gas build-up in culvert system Structural damage to foundations. Loss of adjacent pipework. Potential loss of fire-fighting water supply. Maintenance. Operator training and procedures Robust design of culvert. Alternative fire-fighting supply available within 15 minutes 1, 2

Safeguards Mitigation Hazard category

The HAZOP would consider an individual ‘node’ or section of the design (in this case numbered 9LPGH1), and set out exactly what documents were presented, the key words considered and members of the team (both full time and part time). Any exclusions would be noted at the front of the report. In the fictitious example above, three deviations have been examined. The consequences have been described. Note the use of ‘potential’. This aids the assessment of risk at a subsequent stage. A safeguard prevents an initiating event. Examples of safeguards: ■ Design codes and materials specifications of a system ■ Regular EMIT (examination, monitoring, inspection and testing) will prevent a leak due to incorrect materials being used ■ Installation of load cells and a cut-out (not an alarm) on a crane or hoist to ensure that it is unable to lift any loads greater than the design load. However, there is no safeguard that could be put in place to prevent an external hazard (such as vehicle or aircraft impact, or a seismic event). A mitigator reduces the consequences following a failure having occurred. Examples of mitigators:

Offshore pipeline construction


■ ■ ■

A properly designed bund which will prevent liquor leaking from a pipe to spread too far A sump alarm which will alert operators that the leak has taken place Designing a building to withstand a vehicle impact which will reduce the effects on plant within, such as critical pumps or safety-related pipework.

A hazard category is agreed by the team depending on the consequences to loss of life, damage to equipment, loss of production. Actions to find out further information must be placed on a team member present at the meeting. These actions must be closed out by a set date at the HAZOP review meeting or defined as ‘on-going’ to be resolved prior to commissioning.

HAZID ƒ HAzard IDentification ƒ HAZID methods ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

HAZOP I HAZOP II FMEA (failure modes & effects analysis) Walkdowns Checklist Optioneering (Kepner-Tragoe) or value engineering study Fault tree analysis Reliability diagram analysis

ƒ Need complete up-to-date drawings/specs ƒ Need SQEP members of teams There are many methods of identifying and removing hazards. Some of the arsenal of tools are listed above. Different methods are appropriate for different purposes. No one method can be applied to all. It is likely that a combination of methods will be used to complete on a safety evaluation. A hazard and operability study (HAZOP) combined with value engineering (VE) are tools used to identify and eliminate unacceptable risks and to ensure that fitness for purpose is achieved within commercially-acceptable limits. Failure modes and effects analysis (FMEA) is a tool used by engineers at the equipment and systems design stage. What all these methods have in common is the need to use an up-to-date and full set of drawings, procedures and specifications, which are particular to the node being examined. The session should not attempt to cover too much ground. The drawings should provide such information as, ‘Does this pipeline contain a caustic liquid?’ or ‘Is this cabling part of the safety system?’. The members of the study team should be Suitably Qualified and Experienced Personnel (SQEP), with expertise in the different aspects of the system or process being assessed. For example, you would need a Designer to explain how the safety factors have been built in to the system; the Author of the procedure to explain how the system is designed to operate; and, most importantly, a User to explain the normal system of working on



the site. A Safety Engineer is required to advise the team on perceived risks. Other system-specific members would also attend different types of HAZID study.


Note: Called Job Safety Analysis in USA

The risk assessment plan summarises (in this case in just eleven pages) all the hazards and safeguards from the HAZOP analysis. Ownership of the safety solutions (associated with each task) is placed onto the main contractor or one of the subcontractors, and bound with signatures by all parties.

FEEDBACK ƒ The feedback from lessons learned during the project should be documented and incorporated into future procedures and safety plans to ensure continuous improvement

Offshore pipeline construction


HSE - SUMMARY ƒ Heath, Safety and Environment policies and procedures ƒ Ensure safe working practices for employees ƒ Limit damage to environment

ƒ Risk assessment ƒ Identify risks and hazards ƒ Implement systems to prevent failure or limit consequences

Any questions?

Policies and procedures should be implemented to improve the Health, Safety and Environment in which employees are required to work. The procedures should ensure safe working practices for employees and minimise the risk of damage to the environment. Risk assessment methods are used to identify potential risks and hazards associated with any particular task within a project. When the risks have been identified, then procedures can be implemented that either prevent failure or minimise the consequences in the event of a failure.




COMMERCIAL RISK MANAGEMENT ƒ Purpose: secure a profit ƒ Identify at tender stage using a risk log ƒ Manage throughout project using a risk register ƒ Originally a decision made internally ƒ Gut feeling for commercial risk

ƒ Now client asks contractor to manage risk ƒ Open book philosophy

All projects face risks which may have an adverse effect on the outcome of the work. The identification, assessment and control of such risks is fundamental to the successful completion of a project in safety, commercial, technical and contractual terms. Operators are now starting to expect that risks are managed in a structured process and risk-management procedures are therefore required to ensure that: ■ Risks are identified, understood and recorded at tender stage. ■ Risks associated with a project are identified, quantified, recorded and ultimately either mitigated, eliminated or reduced to acceptable levels. There are many ways of undertaking this risk-management process, but one that has been developed for a Contractor is outlined in the following slide.

Offshore pipeline construction








Size, standing, previous experience


Known, one-off Existing or good record

Market opportunity and competition

Level of return

Below normal


Above normal

Unfamiliar, clients own

Standard or known client form with acceptable revisions


Contract terms Conditions of contract



Within existing experience Developing, or new evolutionary

Known within the industry

Established and familiar with company


Equipment and facilities

Limited internal availability

All internal

All external


As soon as the bid documents are received, the tender coordinator, or tendering manager, undertakes an initial review of the various sections including the scope of work, contractual and commercial conditions and then completes a Risk Log Proforma. This proforma lists the key parameters requiring classification for all major aspects of the work being tendered. For each item/category listed, the level of risk or uncertainty can be considered either high, medium or low. Comments to clearly describe specific risk items in more detail are also included. As an example, 5 of the 16 categories from a typical risk log are shown in the above overhead.



ACTIONS DURING TENDER PERIOD ƒ Risks more clearly defined ƒ Solutions developed and risks engineered out ƒ Cost allowances made to cover risks ƒ Clarification and qualifications raised ƒ Started by bid manager and handed to project manager as a living document

At contract award, the first draft of a Risk Register is produced and issued to the Project Manager at a contract handover meeting. The risk register identifies, prioritises, mitigates and manages the resolution of risks during the project execution. It starts with the risks that have been identified on the risk log and is a “living document” that should be regularly reviewed and updated throughout the life of a project. The key areas on the risk register are: ■ Reference number and category – provides details of the risk area. ■ Description of risk and impacts – provides a brief summary of the risk and details all impacts and consequences to the project if the risk occurs. ■ Action plan/risk action owner – provides a brief summary of the actions under consideration to mitigate the risk and identifies the individual with direct responsibility for completing the action plan. ■ Ranking priority – provides a subjective assessment of the risk in terms of likelihood and impact of the risk occurring. ■ Cost impact – an order of magnitude of the cost to the project if the risk occurs. ■ Status – states whether risk item either ‘ongoing’ or ‘closed’. An example of 3 items from a typical risk register are shown on the following overhead.

Offshore pipeline construction






Contract terms

5 days allowed in High LDs for late completion tender sum. Internal progress meeting held every week to review procedures and resources required


Number of Change welding weld repairs on equipment 13% chrome line


Availability of nominated DSV for tie-ins in accordance with work schedule

Maintain weekly contact with subcontractor. Investigate availability of alternative vessels







£50K per day


Weld Eng




Sub Con


£200K for additional mobilisation


The above simple table focuses minds on where profit can be lost. It does this by identifying who ‘owns’ the risk, how much priority should be given to it and the possible costs if failure occurs. Clarifications of clients’ requirements may allow refinement of the cost impact. Feedback from the team will allow identification of possible risk removal stratagems and their financial impact. As decisions are taken to close each risk by changing the equipment or other means of engineering them out, the risk status changes from ongoing to closed. This table is usually reviewed weekly, with old items deleted and new items added, as they are identified. The client will normally receive a copy under the open book approach. Where ■ LD = liquidated damages ■ PM = project manager ■ Weld Eng = welding engineer ■ Sub Con = subcontractor ■ DSV = dive support vessel



REPORTING ƒ Reporting ƒ Feedback lessons learned for next project

Risk-management reporting provides an integral part of the project management process, not only during tender preparation and project execution, but also for project close-out when the information can be fed back for implementation of actions/recommendations in future tenders.

COMMERCIAL - SUMMARY ƒ Commercial risk management is the managing of risks in a structured process ƒ Purpose is to secure a profit

ƒ Implement systems to ƒ Identify, understand and record potential risks prior to tender ƒ Mitigate, eliminate or reduce consequences throughout project

Any questions? The primary commercial objective of any project is to make a profit. To do this it is necessary to identify, understand and record the potential risks prior to tendering. Commercial risk management systems should then provide the methods for managing the potential risks in a structured process. They should include systems to mitigate, eliminate or reduce the consequences of these risks throughout the project.

Offshore pipeline construction


MANAGEMENT - SUMMARY ƒ Management disciplines - Law ; QA; HSE; Risk ƒ Quality Assurance ƒ corporate policy and procedures ƒ quality plan for project ƒ implementation and feedback

ƒ HSE ƒ corporate policy and procedures ƒ safety plan for project ƒ implementation, including preparation of MAPD and riskassessment ƒ feedback to ensure improvement

ƒ Commercial risk management ƒ identify and control risks using a risk log and risk register ƒ feedback for future projects

The above slide summarises the key elements of four management disciplines encountered during pipeline construction projects.





EXPECTATION ƒ HSE issues for pipe installation ƒ Health ƒ Loss of personal capability due to exposure to conditions onboard a laybarge

ƒ Safety ƒ Injuries to operators or third parties due to accidents associated with pipeline installation

ƒ Environment ƒ Environmental damage or loss of use by third parties due to pipelay operations or the presence of the pipeline itself ƒ ISO 14000 series We are going to classify the health, safety and environmental issues under the above three categories. A different approach needs to be taken for each. We are limiting the study to the effects associated with pipelines. It is possible to minimise damage to health through careful choice of materials and operational methods. Accidents will always happen, but we should attempt to prevent as many as we can by training and provision of appropriate equipment. Some operations have particular hazards associated with them and will be considered individually. Environmental damage during pipeline laying and its subsequent operation mainly affects fishermen. However, when the effect is nearshore, then the local inhabitants are also affected. Mitigation measures such as compensation or provision of improved amenities must be considered. Again, particular operations will be considered individually. Environmental management should follow the ISO 14000 series requirements.

Offshore pipeline construction



ILL HEALTH ƒ Often no immediate signs ƒ Not contemporaneous with cause

ƒ Ill health may take years to develop ƒ Work force is transient ƒ Difficult to identify causal link ƒ Reluctance to wear PPE in hot conditions

ƒ Some ill effects only recently identified

It is easy to identify when safety issues occur. An injury can quickly be linked to a particular accident. However, poor health can be the result of many years of working on a number of different barges. It is often difficult to pin down the exact cause of a chronic illness. Especially in tropical conditions, there is a tendency to wear light clothing (shorts) and avoidance of using personal protection equipment (PPE) such as gloves, which could result in dermatitis or skin cancers sometime in the future. Diligence on ensuring proper protection is required. The causes of some of the following ill health effects have only recently been identified.



CONTACT HEALTH PROBLEMS ƒ Muscular/skeletal strain and injuries ƒ Poor stance/manual lifting/repetitive tasks

ƒ Hand-arm vibration (HAV) - white finger ƒ Tool handling ƒ Internal grinding/welding repairs

ƒ Dermatitis ƒ Caused by wet concrete and coating materials ƒ 95% HCl used to remove tack welding scars

ƒ Blood/lungs/internal organs ƒ Caused by fumes from welding or coating ƒ Carcinogens such as asphalt ƒ Phosphoric acid/chromates used to degrease pipe The above gives the main health issues associated with offshore laybarge construction. Many of the tasks on the firing line require unusual stance to gain access to the weld around the pipe. The need to keep the laybarge in operation 24 hours a day means that operators repeat exactly the same movements time and again, causing damage to muscles, tendons, joints or bone. Cleaning and repair of welds means prolonged use of grinders but the use of impact tools to fix coating shutters can also cause vibration damage especially to the hands and arms. A classic symptom is vibration white finger, now known as HAV. The new UK HSE limits for this are set in terms of exposure action values (EAV) and exposure limit levels (ELL). The EAV is set at 2.5 m/s² and is a daily limit above which employers are required to take action to control exposure. That is, by limiting the exposure time, equipment can impart more than the EAV limit for a short time each day. The ELL of 5 m/s² is also an average which must not be exceeded in a day. Note that some tool manufacturers’ tests for their equipment severely underestimates the vibrations transmitted to the hand when actually in use. It is advisable to double the manufacturer’s quoted values for tools. Wet concrete can cause severe burns to the skin. Initial contact can feel like a tickle. During this time, the nerves are lost and if the cement is not cleaned off quickly, the flesh can be eaten away down to bone in a single shift. However, in the long term, sensitivity of the skin can be lost. Sometimes, strong hydrochloric acid is used to remove tack welding scars. This too can eat away at the body if spilt or over many years, the fumes can deteriorate the capacity of the lungs. Welding operations and the many chemicals used to rapidly cure coatings give off fumes which can damage lungs or internal organs via the blood. Exposure to this can result in chronic (long term) or instantaneous injury. Exposure to isocyanates is a known cause of occupational asthma. In its volatile form, this is particularly aggressive and is a component of foamed polyurethane, which may be used for field joints. Other causes are fine powders and dusts (from grinding of coatings), latex (used for work gloves) and gluteraldehyde (disinfectant and sterilising agent) which is a common biocide used for flooding and hydrotest operations.

Offshore pipeline construction


OCCUPATIONAL HEALTH PROBLEMS ƒ Hearing loss ƒ Noisy environment

ƒ Eye damage ƒ Welding flash

ƒ Radiation ƒ NDT shine

ƒ General stress ƒ 24-7 operations/shift work

ƒ Diving operations ƒ Guidance ƒ DNV RP H101 and DNV F107 Laybarges are noisy and chronic hearing loss can result. In general, any noise above 90 decibels risks injury to the ears. The louder the noise, the shorter exposure needed for damage. Higher tones are the first to be lost. Welding flash can cause temporary or even permanent injury to the vision. Radiographers need to ensure protection against shine or exposure to X or gamma rays. General stress can result from the nature of continuous operation of the laybarge and shift working. We have not repeated the health issues associated with diving here. But they include deterioration in lung capacity and necrosis of bone. Guidance on health issues associated with offshore pipeline installation is given by the DNV publications above.



HEALTH - SUMMARY ƒ Short term contracts ƒ Long cumulative period at risk or time to develop

ƒ Immediate damage handling equipment ƒ Risk from chemicals used ƒ Specific risks to welders, divers, NDT operators ƒ Not an issue for third-parties Any questions?

The usually short term nature of contracts may result in cumulative damage over a number of contracts. However the operator may not show any signs of health deterioration for some years. Where there is an immediate reduction in health, this may be from handling equipment or materials or breathing in fumes. In addition, there are known problems specific to operators undertaking particular tasks. Those at risk are the barge crew rather than third parties, such as fishermen.

Offshore pipeline construction



SAFETY- LAYBARGE OPERATIONS ƒ Lifting ƒ Pipe storage and handling

ƒ Working at height ƒ Falls (J-lay flexible towers, reels) - dropped objects

ƒ Welding ƒ Fumes - sparks - hotwork

ƒ Coating ƒ Fumes - accelerators - splashes - spills - hotwork

ƒ Loss of tension ƒ S or J laybarge - adjacent welders or coaters

ƒ Reel barge ƒ High tension in drum - energy release - clockspring Safety considerations associated with laybarge operations include the risks associated with transport and storage of pipes both in the stockpiles on land and in the stillages onboard the support craft and laybarges. Swinging of these large items during transfer can cause injury to personnel involved in these operations. Operators need to work at height on laybarges. For example, in the J-lay and flexible towers or during pipeline storage/packing on a reelbarge. Objects can be dropped from heights onto the deck or even from deck down to divers on the seabed. During welding operations, there are risks associated hot work as well as with the fumes and sparks given off. This includes chips and sparks from grinding off slag and weld repair work. Protective coating is designed to cure within a single 6 or 8 minute cycle time. The effects of chemical fumes (especially from the accelerators used) need to be assessed. When asphalt or hot bitumen is applied, there will be additional risks from the hotworking and possible spills and splashes.



With such workers operating very near to the pipeline (in S lay and J lay), they are at risk if the tensioners fail. Similarly, the high energy stored on a reel drum can be released suddenly if a weld or the tensioners should fail. Any workers in the vicinity would be placed at risk.

SAFETY- CONSTRUCTION ACTIVITIES ƒ Bundles ƒ N2 in carrier - explosion - adjacent plant & personnel ƒ Trimming (diving) and towing (wire parting)

ƒ Hydrostatic/pneumatic (air) testing ƒ Explosive failure - small fittings burst - limit access

ƒ Site clearance of munitions - CDM duties ƒ Diving operations ƒ Depth, operating time, decompression limitations ƒ Gas mixture, emergency supply in bell

ƒ Dropped objects, chemical contamination, marine life

ƒ Above water or subsea tie-ins ƒ Cold work - flanges - loss of tension in flexibles For bundles, the main additional hazard is associated with the high pressure in the carrier. A rupture of this thin walled pipe (8 mm to 12 mm) could be caused by adjacent plant operations or personnel who would be placed at risk. After launch, divers are used to trim the bundle to a neutral buoyancy. Tow wires could part during launch, tow or laydown. Most pipelines are tested to 1½ times the operating pressure. Because of a number of pneumatic test failures in the US some 30 years ago, it is common to limit the possible explosive damage by specifying the use of hydrotesting. However, explosive failure of the small fittings (valves, gauges and pipework) used for this means that it isstill sensible to limit access to the test personnel only. During site clearance, the Construction (Design and Management) regulations require an assessment to be made for munitions. These are the UK implementation of the requirements of the European Agency for Safety and Health at Work based on the EC directive on construction (92/57/EEC). In many areas of the seabed (eg North Sea, Red Sea, Philippines, Sakhalin), navies have lost or deliberately dumped old mines and explosives which may need to be swept from the lay corridor. Diving operations are particularly potentially dangerous. The diver is limited to the time and the depth which a particular mixture permits him to dive. However, the dive is often limited by time needed for decompression. Emergency breathing mixture supplies kept by the diver, his assistant or in the bell also need to be assessed. But divers can also be injured by dropped objects, contamination on his suit (for example, diesel fumes), which are not able to be dispersed in the habitat or in the bell. Marine life of various species can be attracted by the lights. Even remains of jellyfish in his mouthpiece has been known to cause divers injury.

Offshore pipeline construction


Simple ‘cold work’ operations at tie-ins can present difficulties with the handling of heavy bolts and flanges. Flexibles need to be held under tension during connection. Underwater, the same considerations apply for divers handling heavy equipment.


Sheet pile installation (working at height) Cofferdam or back anchor soil failure Wire parting Pig trap

ƒ Proximity to operating production facilities ƒ Within restricted safety zone ƒ Possible release of gas (ignition or H2S) ƒ Other third party activities

ƒ Plus all normal marine operations ƒ Fire, collision, grounding, sinking, anchor or wire loss ƒ Made worse because of frequent transfer of personnel and equipment at sea Where a pipeline comes ashore, the sheet piling for the cofferdam and back anchor requires care both during installation and design. Collapse of the cofferdam due to soil pressures may occur if struts and walings are inadequate. During the pull itself, the low factors of safety in the wires may cause them to part. It is also common to site the pig trap near the emergency shutdown valve (ESDV), which separates the offshore from landline. These should always be operated following the laid-down procedure. Worldwide, there is approximately one death each year associated with pig traps. Because pipelines come close to live platforms (within the 500 m restricted zone) or other pipelines, there is always the possibility of release of gas or oil, resulting in fire or explosions. Release of poisonous H2S in contaminated gas is debilitating even in very small quantities. Typically, levels above 10 ppm cause a respiratory hazard (this is below the 20 ppm level that commercial alarms will sound), and a 30 minute exposure to 500 ppm or more may prove fatal. Other third party operations on the platform or in support/safety vessels may also cause safety risks which require careful consideration prior to lay operations. In addition to the above, the normal risks associated with vessels at sea should be considered. These include fire, collision with other vessels, grounding in shallow waters nearshore, loss of the anchor during moving operations or parting of the wire can cause injury to the vessel operatives. Because personnel and equipment is transferred between vessels or helicopters at sea (whereas with normal shipping, this would be done in port), additional risks are inherent with pipelaying.



PERSONNEL TRANSFER ƒ Billy Pugh personnel basket ƒ ƒ ƒ ƒ

Risk of impact with side of vessel Risk of falling from basket Risk of hitting adjacent personnel Not permitted in North Sea

Billy Pugh

ƒ Prohibited by HSE LOLER regulations ƒ Cannot make a safety case ƒ Only for emergency use

ƒ Better alternatives


ƒ Reflex Marine ‘Frog’ ƒ Strapped-in transfer HSE Assessors have taken the view that it is not possible to make a proper lifting plan for the use of the Billy Pugh in an emergency. Therefore, it cannot be used to evacuate to an attendant support craft. This is despite the fact that whenever an evacuation takes place anywhere in the world, this is how it is done. Of course, the LOLER Regulations also effectively prevent the Billy Pugh being used, because those standing on its periphery could be injured if they were accidentally swing against something. The latter legislative requirement has resulted in an increasing use of the ‘Frog’ which is a sort of rigid tent shaped object with three open sides. The sides have seats set into them and the object is lifted at the apex by the crane. The resultant lift conforms with the LOLER Regs and may be a little less frightening than the Billy Pugh. Other acceptable equipment exists.

Offshore pipeline construction


LOSS OF ANCHOR-HANDLING TUG STEVNS POWER ƒ Tug lost with all hands in calm conditions ƒ Principle causes included ƒ Open hatch and possible open watertight doors ƒ Water flooded into engine room ƒ Very rapid sinking

ƒ Contribution ƒ Poor trim ƒ Inexperience ƒ SMS did not include anchor handling On 19th October 2003 the anchor handling tug Stevns Power was lost with all hands in calm conditions while supporting the pipelaying vessel Castoro Otto offshore Nigeria. The circumstances surrounding this event were investigated by the Danish Authorities, whose report was published in June 2004. The Castoro Otto is a ship shape vessel almost 200 m (650ft) long and has a heavy lift crane on the aft end. It is owned by the Italian company Saibos Construceos Maritimas. Its task off Nigeria was to lay pipe in 75 m (250ft) of water. Its position was held by twelve anchors which were repositioned one at a time by two support tugs: the Stevns Power was serving the port side anchors with Maersk Terrier on the starboard. The action of a tug depends on which anchor is being repositioned. A common method is to lift the anchor backwards and get it up on the stern roller. The boat is backed towards the barge to get some slack in the mooring, and then the boat is spun to get her pointing to the barge. In the case of a stern breast anchor, the tug aims for a point forward of the moorings fairlead. Once turned, it is then powered at full speed towards the barge; at the same time, the barge winch must recover in the wire full speed. The trick is to match the vessel’s speed to the winch so that the mooring does not pull on the stern. As the tug approaches the barge, the wire can be felt starting to unstick from the sea bed. A watch is kept for when the lead of the wire in the fairlead starts to move forward. All the time, the boat would be angling more to the bow of the barge. A point comes when the mooring wire starts to shake loose from the sea bed: with good judgement, the boat should then be over the new run line. Then the boat is spun onto the new run heading, and the winch operator on the barge is contacted to say the boat was now heading out. The winch operator must then throw the winch out of gear and then control the mooring on the brake. The inquiry found that during the incident: ■ The tug was trimmed too far by the stern, giving little freeboard at the roller. ■ The speed of recovery of the mooring was extremely fast. ■ The safety management system of the company did not mention anchor-handling. ■ It is possible that the rudders went hard over due to the influence of sternway. ■ It is possible that the Master of the Stevns Power failed to react by operating engines or the winch when problems started. ■ The Chief Officer lacked necessary training in anchor handling..



Regardless of all of the above there was a single factor which could have prevented this terrible tragedy. This is stated in the report as follows: ‘An open hatch and maybe open watertight doors resulted in water flooding the engine room. Therefore the vessel sank very fast.’

SAFETY - PIPELINE OPERATION ƒ Through and end-life activities ƒ Daily operations ƒ Chemical dosing ƒ Sphering/pigging ƒ Verification of pressures and gauge readings

ƒ Internal inspection ƒ Intelligent pigging - pig traps

ƒ External inspection ƒ Survey using ROV, ROTV or divers

ƒ Maintenance of valves or buckle/dent repair ƒ Decommissioning

During the life of the pipeline, a number of operations will be carried out by the owners. We will not cover these in detail but some of these may have attendant safety risks, which are worth noting for installation of adjacent pipelines. The line may be dosed on a continual or batch process with chemicals. These may be injected at the wellhead using a small piggyback line. Some lines are flushed using spheres or pigs. Continued monitoring of pressures and gauges must be carried out to ensure the line does not burst and release its inventory (contents). Approximately once every five or ten years, an intelligent pig run is undertaken to ensure that internal corrosion is not removing too much of the wall. Again, pig traps are used to capture these instruments. Externally, a survey is also undertaken to ensure that there are no unexpected spans or loss of coating or anodes. This is undertaken using survey vessels and ROTVs where possible. In shallow waters, a diver may be used. Maintenance of subsea valves or repairs to damaged sections of pipelines may involve construction activities as detailed before for tie-ins. Finally, the decommissioning of a line will involve many of the same activities needed to install it in the first place.

Offshore pipeline construction


SAFETY - THIRD PARTIES (FISHERMEN) ƒ Spans uneven seabed - otterboards snags ƒ Pipeline rupture or sinking of trawler ƒ North Sea - bury lines ≤ 300 mm (12in) - risk to pipeline ƒ US - bury lines nearshore > 300 mm (12in) - risk to vessel

ƒ Mounds, lumps of clay, berms or trenches ƒ Soft mud in ‘repaired’ anchor scars and depressions ƒ Snagging or muddying of trawls - loss of gear

ƒ Protective structures ƒ Overtrawlable or ‘fisher friendly’ approaches

ƒ Munitions ƒ Drawn towards pipelines - disposal

ƒ Rock dump - caught in or damage to nets ƒ 125 mm (5in) - larger or smaller - maintain stability When pipelines are laid on the seabed, there a is risk that the otterboards (trawl doors) may snag on a span. Fishermen will tend to tighten up on the warp wires and haul in their gear on the swell, in order to releases it. Two possible effects may result: either the pipeline will buckle and possibly rupture or the trawler may pull itself under. Because of separate incidents and different seabed conditions, different regulations have been applied around the world. In the North Sea, the ‘Westhaven’ was snagged on a span of a large diameter line; because of an unusual rigging arrangement, it capsized with the loss of all hands. Small diameter lines on a hard, sandy or clayey seabed are perceived to be at risk from the large trawlers that operate in the area - so they are normally buried. However, in the Gulf of Mexico, the seabed is soft mud and the vessels are generally small, ‘mom-and-pop’, shrimp boats. One of these hit a large diameter pipe which ruptured, enveloping the trawler in flame and loss of crew. For this reason, larger diameter pipes (which do not self bury) are required to be trenched nearshore where these boats operate. In the Persian Gulf, some areas of the seabed are closed to fishing. However, vessels can snag on any unevenness on the seabed. In some instances, trawlermen have been employed to repair the disturbance by dragging a chain between two boats. The hollows left by trawl scars can fill with soft mud which itself can muddy or snag boards or nets. Protection structures over wellheads or valves can be either designed as overtrawlable or ‘fisher friendly’. This means that they will stop a boat in its tracks but will permit it to easily back track and recover the gear undamaged. The latter is preferred by some enlightened fishing organisations. Munitions tend to be drawn towards a pipeline during its life by trawling operations. The net releases the item of ordnance as the trawl gear lifts over the pipe. Fishermen are sometimes employed to clear such items by dragging nets alongside the pipeline. Safe detonation or disposal is then the responsibility of the pipeline operator. With rock dump protection to lines, fishermen tend to dislike stone of a similar diameter to the net mesh size. This is around 125 mm; the stone breaks or wears away the net. It is preferable to have stone smaller (goes through net without damage) or larger (which is not picked up in the first place). However, a check is needed on the resulting stability of



the stone protection, and on the likelihood of it filling a net, causing capsize of a small boat.

FISHING SAFETY ƒ Loss of MFV Harvest Hope – 28 August 2005 ƒ 28 m (93ft) long twin rig trawler built 1996 ƒ No loss of life – seven crew saved by Fruitful Bough

ƒ Probable cause – mudding up of nets ƒ Sank from stern – flooded though open transom door ƒ Modifications and greater displacement than allowed ƒ 35 knot wind and moderate state seas

ƒ Shell Goldeneye line ƒ 60 km (35 miles) NE of Aberdeen

ƒ Site guard vessel A large twin rig demersal trawler, the MFV Harvest Hope sank rapidly (in 15 minutes), initially due to mudding up of the nets, fouling on a natural fastener close to the Goldeneye pipeline. The weather and sea conditions were not severe at the time. Water flooded compartments through openings in the vessel. Other contributory factors involved the aft freeboard (which was less than permissible), operation of the automatic trawl winch control gear, and modifications that were made to the structure of the craft. The pipeline had been buried using a backfill plough, which may have jumped leaving the lumps of clay. Fortunately, all crew were saved from the liferaft by the MFV Fruitful Bough which heard the emergency signal SOS and steamed to the area. The vessel had a 354 gross tonnage and 106 nominal tonnage, with a draught of 7.4 m (24.3ft). Her engines were 742 kW (995 HP). Until the nets and equipment were recovered, a guard vessel patrolled the site. The full accident investigation report can be found at

Offshore pipeline construction



This ROV photograph shows the nets held fast by the boulder clay. Within the net, you can make out the rock hopper disks on the ground rope. Not shown are the trawl’s chain bridle and tickler chain, which the report states initiated the sinking, once they got caught. The mound of compacted boulder clay resulted from backfill ploughing to protect the 100 mm (4in) MEG line piggybacked to the main pipeline. It is suggested that the plough had possibly stalled or jumped.

SAFETY RELIABILITY INFORMATION ƒ OREDA ƒ Offshore reliability database

ƒ PARLOC ƒ Database for loss of containment ƒ Section on pipelines

ƒ Concawe ƒ Hydrocarbon liquids only



There are a number of sources which aid in assessing safety risks associated with pipelines. Among these are the offshore reliability database ( tl/projects/oreda/), which details failure frequencies for offshore equipment. The pipeline section of the PARLOC database from the site describes collated incidents in the North Sea. The site covers oil pipelines in Western Europe only.

SAFETY - SUMMARY ƒ Laybarge operations for pipelines ƒ Bundles, flexible and reel assembly sites ƒ CDM requirements

ƒ Associated installation activities ƒ Diving, protection installation and commissioning

ƒ Pipeline operation through life ƒ Third-parties at risk ƒ Databases of incidents Any questions? Safety hazards exist both at sea (on the laybarge) where operators are assembling the pipelines, and onshore at construction sites and quaysides. The latter may have more severe safety regulations. Incidents also occur whilst commissioning or installing associated equipment. Some activities such as diving require particular procedures to avoid incidents. The through life nature of safety must now be considered. It must be possible to operate and maintain the pipeline with equipment fitted at installation stage. Safety of third parties must be considered and a number of databases are available (by subscription) to assess the likelihood of incidents occurring.

Offshore pipeline construction




ƒ Damage ƒ Loss of amenity ƒ Turbidity of water ƒ Flooding behind beach - death of vegetation such as mangroves

ƒ Local inhabitants / sportsmen / anglers / yachtsmen / surfers / beach walkers ƒ Amelioration measures ƒ Provision of wildfowl ponds at Point of Ayr (Wales) ƒ Cleanup of historic pollution at Baku (Caspian) ƒ Leave the area better than we find it

At the landfall or nearshore, the damage that occurs is generally loss of amenity or deterioration in the clarity of the water. If the landfall site is not able to withstand storms without overtopping, then flooding of the adjacent land may occur with death to vegetation (mangroves) or increased salinity of brackish ponds. The general approach to ameliorate matters with the locals and summer visitors is to provide improvements to the area. This has taken the form of wildfowl pond or clean up of earlier pollution. However, discussion with the local inhabitants may demand different solutions for each particular landfall. We should aim to improve the site from its original condition.



ENVIRONMENT - OFFSHORE ƒ Damage - disruption of seabed ƒ Silt/turbidity damage to spawn or nursery areas (open gravel) ƒ Anchor scars/lumps of clay/soft mud in holes ƒ Berms/trenches causing loss or muddying of nets ƒ Pipeline itself may be a barrier to fish and decapods ƒ Loss of permanent fish traps and nets

ƒ Fishermen ƒ Approaches differ ƒ Japan - owners of sea - buy area or time ƒ US/UK/Norway/Canada - pay compensation for loss of net notify claims - decline to pay out for second loss in same area ƒ Russia - recognise damage will occur - improvements to other areas (same species if possible)

Damage offshore can be classified as disruption to the seabed. This means that fishermen cannot trawl as previously or they may suffer a reduction in stock levels or loss of permanent fish traps. We will look at these in detail later. Different countries have different approaches to the environmental damage that is inevitable with pipelay operations. In Japan, the fishermen have ownership of the seabed in the same way as a farmer owns his fields. Here, pipeline owners need to buy an area or rent time for the laybarge to cross the fishing grounds. Specific spawning periods of the year could then be avoided. In most countries, the approach is to pay compensation to the fishermen for snagged, damaged or lost nets. Alongside this, the fishermen are informed of the location of spans, snags and subsea structures. It is common that second claims in known problem areas are then dismissed. Effectively, the oil companies are ‘buying’ areas of the seabed along their routes. Russia recognises that some environmental deterioration is inevitable. The approach taken is to provide improvements to fish spawning grounds, nurseries in other areas. It may take the form of fish ladders at river dams but normally, the improvement should be for the same species that has suffered damage.

Offshore pipeline construction


ENVIRONMENT IMPACT LEGISLATION ƒ MARPOL 2004 ƒ Common approach with tankers and ships ƒ Covers ƒ Oil and noxious or harmful substances ƒ Limited discharge ƒ Sewage and garbage ƒ Disinfected and macerated to achieve BOD ƒ Air quality now added to list

ƒ Caspian ƒ Zero discharge approach ƒ Everything returned to port ƒ Additional tanks ƒ Bunding to deck

An international agreement has been developed for discharges from ships. Normally, this can be adopted for pipelay activities. The MARPOL convention can be found at the International Marine Organisation website: It strictly limits the discharge of oil and noxious or harmful substances. In some areas such as the Persian Gulf, the Mediterranean, Black, Baltic and Red Seas additional restrictions apply. Sewage and garbage should be chopped up finely using macerators, disinfected and discharged slowly to achieve an acceptable biological oxygen demand (BOD). With the large numbers of personnel onboard laybarges compared to tankers, this may require an onboard sewage treatment works. Material which cannot be discharged (such as boxes and tin cans) must be stored on board and taken back to port. The quality of air has now (19 May 2005) been added to the list of discharges. This covers nitric oxides (NOx) and sulphur oxides (SOx) from fuel oils, the release of halons and chloroflurocarbons (CFCs), which deplete ozone and incineration of contaminated packaging and polychlorinated biphenyls (PCBs). However, in certain closed seas such as the Caspian, this is not appropriate. A zero discharge policy is adopted to prevent further pollution. Extra tanks are used to enable everything to be brought back to port. Accidental spills from the scuppers are prevented by the use of deck bunding and drains to tanks.



ENVIRONMENT - PIPELINES & EQUIPMENT ƒ Pipelines ƒ Crossings by fish/lobster/crab - differential sex ratio ƒ Spans / mounds along pipe permit crossing

ƒ FAD or barrier? - artificial reef - enhancement

ƒ Surveys ƒ Sound pollution from sonar equipment ƒ Mammals - hearing loss - deep sub-bottom surveys ƒ Pipeline survey - use of chirpers rather than boomers

ƒ SPT/CPT/vibrocores - minor disruption

ƒ Pipelay vessels/tugs/supply craft/helicopters ƒ Sound/anchor wire noise & scars - similar to ships ƒ Light - attracts squid away from fishermen ƒ Dropped debris - zero discharge approach Pipelines in themselves have been accused of separating populations of fish or decapods. Tests in tanks using partly buried or fully exposed pipelines have shown lobsters or crabs reluctant (or unable) to cross pipelines. With crabs, the relative size difference between males and females can result in the ratios being different on either side of the tank. However, the tank tests may give misleading results in that the creatures were induced to cross a short section of bare or coated pipeline using attractants. Normal pipelines have frequent spans or partly buried sections with mounds either side. These provide convenient crossing points. Indeed, a pipeline can enhance the bio-diversity of the seabed and act as a fish attractive device (FAD). This is well known to fishermen who frequently trawl along pipelines. They also tend to act as an artificial reef once some growth occurs on the concrete coating and may increase biodiversity. Surveys send sound waves to the seabed. These can affect marine life. In particular deep sub-bottom surveys using explosions are thought to cause hearing loss or disorientation in whales. Many groundings are blamed on seismic surveys. For pipeline installation, we are interested in only the upper few metres of the seabed so can use chirpers rather than pingers or boomers. These do not have the high energy sound waves that cause fish damage. Direct measurement of soil properties causes very local minor disruption. Even for deep hydrocarbon surveys, the Scientific Committee on Antarctic Research study showed the risk to marine mammal populations posed by an individual air-gun survey was likely to be small. Evidence from areas that are heavily surveyed by marine seismic vessels, such as the Gulf of Mexico and the continental shelf around the British Isles, shows that whales remain abundant even during surveys, though they tend to keep away from the vessels that are actually conducting them. With pre-lay seabed modification, care needs to be taken to avoid creating a plume of silt from sandwave removal during disposal. Blasting undoubtedly causes death of fish and should be used with caution. However, dredgers and drill equipment themselves are inherently noisy and can disrupt fish life. The cumulative effects of pipelay and support vessels are noisy and have been measured at between 160 dB to 180 dB. Sound can travel long distances (10 km or more) especially within a shallow bay. It should be remembered that the sea itself is noisy: ambient levels have been measured at 114 dB. The 24 hour operations of laybarges require lights which can attract squid and other creatures such as birds, turtles and fish.

Offshore pipeline construction


Divers, ROVs and ploughs are also equipped with lights. A zero discharge approach is used to avoid any objects such as wire or cans being dropped from the laybarge.

ENVIRONMENT - SOIL ALTERATION ƒ Seabed modification ƒ Sandwave removal - plume from suction dredgers ƒ Blasting - sound pollution - fish death ƒ Cutter suction dredging (landfalls) - noisy operation

ƒ Directional drilling (landfalls) ƒ Muds - non-toxic with food grade thickeners ƒ Clay - turbidity - problem with corals and spawn beds

ƒ Jetting ƒ Eductors (large diam) - turbidity 3 km down current ƒ Thin layer smothering of seabed - similar to trawlers During sandwave removal, the smaller particles of silt may create a plume that pollutes the water. This normally occurs when the suction dredger disposes of the removed soil on the seafloor. This can be done back down the suction tubes to minimise the depth of water affected. It can easily be appreciated that blasting of the seabed can kill fish in a wide area. But the sound from vessels involved in all these activities can disrupt marine creature movement. A typical cutter suction dredge used at landfalls is estimated to produce 170 dB. Directional drill muds are based on bentonite, a naturally occurring thixotropic clay that is non-toxic. It thickens up and supports the surrounding soil, keeping the hole open. To this small amounts of thickeners are added. These are often food grade, so are also not toxic. However, if the clay particles get mixed in the seawater, they can produce a plume that does affect corals and spawning beds. The effects are described on the following slide. Similarly, when large diameter lines are jetted into silts, it is necessary to use eductors that ‘side cast’ the soil and can create a plume reaching up to 3 km (2 miles) down current of the machine. Because the area affected is so wide, only a thin layer is formed when the plume clears. This can be likened to the effect of plumes created by many passes of trawlers.




ƒ Trenching - barrier to trawl ƒ Berm 25°, trench 35° to 30° ƒ Many years to recover ƒ Soft deposits in trench

ƒ Rock dump ƒ Snagging/damage to nets ƒ Turbidity plume - pre-wash stone ƒ Micro-organisms with marine sand

With ploughs in clays or sands, there are two berms or windrows of soil either side of a trench (perhaps as deep as 3 m). The berms tend to have side slopes of around 25° in sand but in finer materials, it can produce lumps which resemble sculptors clay. The trench itself has side slopes of up to 35°. Both of these do affect the ability of trawlers to cross the pipe route and may not change much for many years unless the seabed is mobile. Even when the trench is naturally backfilled, the deposits may remain softer than over the rest of the seabed, causing muddying of the otterboards or nets. Rock dump can cause snagging of nets as discussed earlier. However, in laying the stone (particularly with side dump), there is a risk of creating a plume of smaller particles. This can be avoided by pre-washing the stone at the quarry. Occasionally, sand berms are used to improve insulation (Gannet bundles). If this is marine sand, then the risk of micro organisms transfer to a new site should be considered.

Offshore pipeline construction


ENVIRONMENT - COMMON ISSUES ƒ Blanketing of spawning and nursery gravel beds or coral smothered by silt ƒ Consequential loss of food for higher predators ƒ Larvae or whale krill

ƒ Filter feeders starve ƒ Clogging of fish gills ƒ Prevention of burrow formation by invertebrates

ƒ ƒ ƒ ƒ

Accidents at sea/leaking flanges - oil spills Ship impacts with marine mammals (whales) Employ trawlers - guard/restoration/cleanup Pay compensation for loss of gear/grounds ƒ Common fund

As can be seen, a number of different activities can result in a plume of silt being deposited over the seabed. Some species of fish need to lay their eggs in clean gravel, which provides well aerated water to let them hatch and grow. If silt covers these beds, the larvae die and are not then available as food for higher predators such as filter feeders or even whales. Corals can also be killed if smothered by a layer of silt. Fish can even ‘drown’ if the silt clogs their gills. Other species may be prevented from burrowing into a sandy seabed if there is a blanket of silt that falls into any holes formed. All pipelay activities involve the use of laybarges, tugs, ships and supply boats, any of which may be involved in a collision. Although most of these vessels do not hold large quantities of oil, any spillage will affect the environment. Leaks can also occur from flanges or ruptured pipelines due to damage. Vessels may impact with marine mammals causing their death. This is of particular concern at the Sakhalin developments, where the Western North Pacific Grey Whale is down to approximately 40 breeding females. Many of our activities will disrupt the seabed. As a ‘sweetener’, it is common to employ fishing boats as guard vessels, for overtrawling trials, removal of debris in the pipeline corridor or to restore the undulations in the seafloor to preinstallation conditions. Pipeline owners will pay compensation for damage to nets along their line. This may be due to stone dump or debris which has accumulated along the route (even when it is not from the original installation). Where blame cannot be pinned on any particular pipelay operation, it is usual to have a common fund able to pay fishermen for loss of gear.



ENVIRONMENT - HYDROTESTING ƒ Filtered seawater to 50 μm (2thou) ƒ Biocide ƒ Tetrakis hydroxymethyl phosponium sulphate (THPS) at 150 to 500 ppm or ƒ Gluteraldehyde at 250 ppm or ƒ Solid quaternary amine at 300 ppm ƒ THPS is best for environment

ƒ Oxygen scavenger ƒ Ammonium bisulphite at 100 ppm or ƒ Sodium bisulphite at 100 ppm

ƒ Dye ƒ Fluorescein or ƒ Rhodamine B at 40 ppm Because we actually discharge hydrotest water to the sea, it is worth examining what additives we may encounter. During hydrotesting of offshore lines, filtered seawater is used. Seawater is readily available and by careful filtering, it is possible to avoid silty mud being deposited inside the pipeline. It is common to add a biocide to kill any bacteria (especially sulphate reducing bacteria (SRB)) that may be present. The proportion is dependent upon how long the water is to remain in the line. THPS at a dose of 150 ppm is sufficient for up to 90 days. Higher dosing as above may be used for longer periods up to 2 years (delayed commissioning). To avoid internal corrosion (rust), an oxygen scavenger is added. If leaks are suspected, a dye for is used for tracing them. Note that this is not a complete list of additives that might be used worldwide. All doses given above are by volume and are guidance only.

Offshore pipeline construction


ENVIRONMENT - HYDROTEST DISCHARGES ƒ Permit to discharge required ƒ Biocide ƒ Neutralise using hydrogen peroxide for THPS or sodium bisulphate for Gluteraldehyde

ƒ Oxygen scavenger ƒ Neutralise using aeration - surface spraying

ƒ Leak detection dyes ƒ Not biodegradable so use only with permission

ƒ ƒ ƒ ƒ

Scour at discharge point Salinity Temperature Micro-organisms

A permit to discharge the hydrotest water is needed, with an environmental assessment of potential damage that might occur. In the US, this is granted by the EIA at The biocide and oxygen scavenger are neutralised using appropriate means, leaving the water itself relatively environmentally innocuous. Many of these biocides biodegrade naturally in water. At present the commonly used dyes are not biodegradable and suppliers are currently testing suitable substitutes. The approach should be that dye is only used where a leak is suspected. Even then, alternative methods should first be considered, such as diver inspection of flanges using cling film (Saran wrap or PolyVinyliDene Chloride - PVDC) and instruments to detect the sounds of leak. Dispensation should be gained for use of dyes from the appropriate regulatory authority. Care needs to be taken to avoid scour of the seabed during discharge. Normally, problems with changes in salinity, temperature or transference of microorganisms will not be a problem. Distances are generally too short for the latter and the salinity and temperature will be similar at both ends of a pipeline. However, care is needed with these aspects in areas such as the Caspian Sea, where the environment is already fragile.



ENVIRONMENT - SUMMARY ƒ Landfalls and inshore waters ƒ Disturbance to seabed sediments ƒ Different approaches worldwide ƒ Legislation

ƒ Sound due to supply and survey vessels ƒ Particular problems with trenching ƒ Pre-commissioning Any questions?

Although with care most environmental damage can be avoided or at worst minimised, there are particular problems at landfalls and to fishermen. Most problems arises from disturbance to the seabed sediments by anchors or trenching activities. Different legislation and approaches are used worldwide, from purchasing seabed from owners to compensating fishermen for loss of gear or damage to nets. Care must be taken to minimise sonic equipment energy and disturbance from helicopters and supply boats. During pre-commissioning, we need to avoid the use of chemicals as much as possible.

Offshore pipeline construction


H, S AND E - SUMMARY ƒ Health ƒ Safety ƒ Environment Any questions?

Each of the above aspects has its own considerations. Whilst proper considerations to procedures can ensure good health of the team, careless operators may suffer injury through lack of safety. In this age of environmental concern, third-parties can suffer loss and ultimately cause delays, fines and cost overruns should lack of attention to detail in the procedures.





EXPECTATION ƒ Know the main survey methods ƒ Know the survey equipment used and the data that can be obtained ƒ Know which survey operation to perform at each stage in the installation of the pipeline

We introduce the main methods of surveying the seabed for the installation of subsea pipelines. The typical survey equipment and the information that can be obtained from the main survey methods are described. The surveying procedures are discussed and the correct survey operation is identified for each of the main stages of the pipeline installation.

Offshore pipeline construction



INTRODUCTION ƒ Surveys are for finding information about: ƒ the seabed along the pipeline route ƒ the as-built condition of the pipeline ƒ the pipeline status during construction

ƒ Three types of survey: ƒ Geophysical ƒ Geotechnical ƒ Visual

The three types of survey and the methods used are described in this section. A fourth type of survey, Metocean, is carried out as part of the of pipeline design stage. It is concerned with currents and tides likely to be acting on the pipeline during its lifetime. It is fully covered in our design course.



INTRODUCTION ƒ Prior to construction: ƒ Route survey ƒ During construction, the following are carried out: ƒ Pre-lay survey ƒ Pipelay survey ƒ As-built/hydrotest survey ƒ Post-trench survey ƒ Post-burial survey

Offshore pipeline construction


SURVEY METHODS Geophysical surveys

GEOPHYSICAL SURVEY ƒ Reconnaissance of potential hazards ƒ Seabed bathymetry ƒ Sub-bottom profile

A geophysical survey plots the shape of the seabed (its contours) and those of the soil layers underneath. In the case of a pipeline route survey, we are really only interested in the very top layer, or down to about 3 metres if we are trenching or dredging.








Swathe bathymetry




Sidescan sonar





Sideways and downwards Omni




Sub-bottom profile (pinger) Deep sub-bottom profile (boomer)

All of the geophysical survey tools use sound waves to develop an image of what is being surveyed. The basic differences are the frequency, amplitude and directionality of the sound waves. High frequency, low amplitude waves are used in sonar applications investigating seabed surface features and bathymetry. Swathe bathymetry uses a downward-pointing beam and is good for measuring depths accurately. Sidescan sonar directs the sound beam sideways and downwards, detecting obstructions such as wrecks or pinnacles which may snag anchor wires. Low frequency, high amplitude waves are used in pinger and boomer applications for investigating sub-surface features. Pingers are used for pipeline surveys, while the lowerfrequency boomers are used for examining the deeper rock layers.

Offshore pipeline construction


SWATHE BATHYMETRY ƒ Medium resolution ƒ ƒ ƒ ƒ

Single beam echo sounder Hull mounted 750 m (½ mile) wide swathe Best resolution ƒ 8 m (26ft) footprint size

ƒ High resolution ƒ Multi-beam ƒ Towed close to seabed ƒ Much narrower swathe

Bathymetry (water depth and seabed profile) is determined using echo sounders. Multibeam systems towed close to the seabed can be used to produce 3-D images of the seabed. Different methods are used, depending on the width and the resolution of the survey. The greater the distance between the seabed and the sensor, the wider the survey corridor but the lower the resolution. For example, with a 750m wide swathe, the sonar can pick up objects down to 8m across. For high-resolution surveys, the sensor is mounted on an ROV which is flown along the route a few metres above the seabed. The sensors provide a huge amount of data that then has to be post-processed and smoothed (cleared of noise). Maps of the route are then produced.



SIDESCAN SONAR ƒ Used to find seabed profile, wrecks, wellheads, rock outcrops ƒ Towed fish

Sidescan sonar techniques use a towed fish such as that shown in the picture above. They are based on sonar, whereby the device emits a sound pulse and listens for the echo. It interprets the strength, time and direction of the echo to give a picture of the seabed sufficient in detail to gauge contours, wellheads, rock outcrops, wrecks and other similar features. It is even possible, with practice, to distinguish different types of seabed such as sand, gravel or shells.

SUB-BOTTOM PROFILER ƒ General purpose pinger ƒ Seabed layers of top 10 m to 20 m (33ft to 66ft) ƒ Sufficient for trenching and foundation piles of bundle towhead structures

ƒ Looking for reflector horizons ƒ Acoustic signature and magnetometer

In addition to the sonar devices, chirpers, pingers and boomers can be used to penetrate the seabed and get reflections from the soil layers beneath it. Understanding the patterns of seabed structure or soil horizons (layers) beneath the surface can help predict

Offshore pipeline construction


the soil types at the surface, with the minimum number of data points from geotechnical surveys. Magnetometers are used to detect metal objects buried under the seabed.

AUV ƒ Autonomous underwater vehicle (AUV) ƒ Un-tethered ROV ƒ Does not require support vehicle at close proximity

AUVs are un-tethered ROVs that are programmed with the survey route, launched from the support vessel and then recovered at the end of the survey. The geophysical survey information is then downloaded from the AUV. The benefit is in the detail and speed of the survey, and the fact that the support vessel does not have to be close to the vehicle. For pipelines that are reasonably close to land, the AUV does not even require a support vessel, as it can be launched and recovered from land.



Geotechnical surveys

GEOTECHNICAL SURVEYS ƒ Sample and test seabed soils ƒ Use cone penetrometer (CPT) and/or vibrocores or gravity corers

Geotechnical surveys establish the nature of the soil along the pipeline route. They typically use a cone penetrometer tester (CPT), as shown in the picture above. This is a small device dropped onto the seabed with a coiled probe which is forced into the seabed. On its way in, it measures the pressure at its tip and friction on its side. By cross-referring to calibration data, these features can be used to determine whether the soil is sand or clay and what strength or friction angle it has. The results of the CPTs are also used to confirm and strengthen the sub-bottom profile survey. Vibrocores are taken on sandy seabeds, but on clay a gravity corer would be used. These instruments take a sample of the seabed, which can be analysed later in a laboratory.

Offshore pipeline construction


CPT ƒ Types of soil or rock at or below seabed ƒ Thickness of layers ƒ Engineering characteristics - strength, density, porosity/permeability

From the measurements of friction and tip resistance, the above-mentioned data can be interpreted.

VIBROCORE ƒ Samples a column of soil ƒ Analysed on site and back in laboratory

A typical vibrocore would be 5 to 10 m long (16 to 33 ft) and about 0.1 m (4 in) in diameter. Vibrocoring is the state-of-the-art sediment sampling methodology for retrieving continuous, undisturbed cores. Vibrocorers can work in up to 5000 m of water and can retrieve core samples up to 12 m (40ft) in length.



The principle behind a vibrocore is the development of high-frequency, low amplitude vibration that is transferred from the vibrocore head, down through the attached barrel or core tube. This vibrational energy liquifies sediments, enabling the core barrel attached to the vibrocore unit to penetrate into the liquified sediments. A core-catcher is attached to the end of the barrel, which holds the sediment inside the barrel when withdrawn. A variety of vibrocore units are available. Some are small, lightweight and portable; others are large, heavy units that can only be deployed from large vessels. Note the feet of the vibrocore are an open cruciform which is good for sandy seabeds. In soft clays, a fully plated base may be used. In this case, the dynamic crane loading may be great when the added mass of water is added. The solution is to lower the vibrocore on its side and rotate upright when at the seabed.


CPT sample interval

Untrenched sections

1 km to 5 km (0.6 miles to 3 miles) Trenched sections 0.5 km to 1 km (offshore) (0.3 miles to 0.6 miles) Trenched sections 0.3 km to 0.5 km (shore approach) (0.18 miles to 0.3 miles) Soil transition zones 0.3 km to 0.5 km (0.18 miles to 0.3 miles) Features (pock marks, 3 per feature iceberg scars, etc) Pipeline crossings 2 per crossings

CPT sampling density along the pipeline route has traditionally been at 1 km spacings. The Guidance Notes on Geotechnical Investigations for Marine Pipelines, produced by the Pipeline Working Group of the Offshore Site Investigation Forum gives a more logical approach to sampling density. This table illustrates the recommended sampling intervals. In areas of very soft clays or unstable slopes, the intervals should be decreased. The exact locations for each CPT sample would be selected by examining the subbottom profile. It is useful to undertake vibrocores immediately adjacent to a CPT sample. Undisturbed soil tests carried out on the vibrocore samples may then be used to correlate some of the CPT samples. Intermediate grab samples are useful in areas of sand or gravel.

Offshore pipeline construction


Where there are piled wyes, tees, wellheads or manifolds, it is necessary to undertake at least one deep CPT and vibrocore to determine the ground conditions. Visual surveys

VISUAL SURVEY ƒ On-line visual monitoring during operation ƒ Visual identification and record of As-Built features ƒ Methods ƒ ROTV ƒ ROV ƒ Diver – touch and clear away marine growth

Visual survey is provided by video cameras and lights mounted on a vehicle or on a divers helmet. The diver has the advantage that he can move marine growth out of the way to see better. He can also pass his hand beneath the pipeline and feel for free-spans.



ROTV ƒ Remotely-operated towed vehicles ƒ Controlled survey height above seabed ƒ Fin pitch operated from vessel through umbilical ƒ Speedy survey of large areas of seabed

Deploying BRUTIV

Use of ROTVs is now the main source of pipeline route survey information. By flying the equipment at a controlled height above the seabed, it is possible to rapidly obtain topological and pipeline span data. The operator on the vessel is able to change the pitch of the fins through the data umbilical cable. The BRUTIV (Bottom-Referenced Underwater Towed Instrumented Vehicle) can be towed at a speed of several knots just a few metres above the seafloor to obtain continuous colour video imagery along transect lines several kilometres long.

ROV ƒ Can be used for most survey work ƒ Low survey speed ~ 0.26 m/s (0.5 knots)

Hercules 600 fitted with survey mountings

Offshore pipeline construction


The ROV can be used for most of the surveys mentioned earlier, and additional equipment can be fitted for geotechnical surveys along the pipeline route. It also has the benefit of the video camera to observe any anomalies. Bathymetric equipment to obtain depth data and provide seabed contours for the pipe route can be fitted. Sidescan sonar surveys ascertain the presence of obstructions on the seabed and, in conjunction with shallow seismic surveys, can provide information as to the nature of the seabed materials. Shallow seismic surveys provide the depth of overburden laying on top of rock. As mentioned earlier, for sidescan sonar, the height at which the ROV is flown will dictate the width of the survey corridor.

ROV ƒ In addition to visual/video record can give detailed sonar images

Vertical cross-section

Vertical profile

ROVs can be equipped with high-resolution sonars that produce a cross-sectional image of the pipe and the seabed. By producing these images at close spacings along the pipeline, an image of the axial profile can be produced. This is a typical output from a trench profiler, showing a cross-section through the pipe and a vertical profile of the pipe and seabed.



DIVER SURVEY ƒ To cover small areas in high detail ƒ Ideal for approaches to platforms and subsea developments ƒ Where ROTVs and ROVs can’t go: ƒ very shallow water ƒ splash zone

Diver surveys are the least common of the surveys we have listed, but have specific applications for areas in which ROVs cannot operate. Diver surveys provide high detail for a small area, and benefit from having the diver at the survey location to comment on any aspects that are highlighted.

SURVEY METHODS - SUMMARY ƒ Geophysical ƒ Determine shape of seabed (contours) ƒ Swathe bathymetry, side-scan sonar, sub-bottom profiler

ƒ Geotechnical ƒ Determine nature of soil ƒ Cone penetrometer (CPT) ƒ Vibrocores

ƒ Visual ƒ Real-time monitoring of operations ƒ Diver, ROTV or ROV

Any questions? There are three methods of surveying the seabed prior to pipeline installation. ■ Geophysical surveys to determine the shape of the seabed along the pipeline route. ■ Geotechnical surveys to determine the nature of the soil


Offshore pipeline construction

Visual surveys enable the real-time monitoring of the operation. Examples could be the remote viewing of a pipeline installation or rockdump.





Route survey Pre-lay survey Pipelay survey As-built/hydrotest survey Post-trench survey Post-burial survey

Surveys are needed at several points during pipeline construction. We will examine what is needed at each stage.

Offshore pipeline construction


SURVEY VESSEL ƒ Seaway Surveyor

The Seaway Surveyor is a typical survey vessel. Dimensions: Max. speed: Thrusters: A-frame capacity: Accommodation:

65.7 x 11.0 x 6.1m 14 knots 5 15 tonnes 41 persons

ROUTE SURVEY ƒ Geophysical and geotechnical surveys of route options ƒ Identification of obstructions and problems help select final route ƒ Geotechnical data for pipeline foundation and trenching feasibility



During the pipeline design phase, a geophysical and geotechnical route survey will be performed on the prospective route options. This survey will identify seabed features, obstructions and soil types/properties which will be used to help select the final route.

PRE-LAY SURVEY ƒ Sonar used to find seabed profile, wrecks, wellheads, rock outcrops ƒ Survey width should include entire pipelay corridor ƒ Pipelay from an anchored vessel will increase survey width

The pipeline route should already have been decided from the data obtained during the route survey (normally a low detail, wide survey that allows a number of routes to be investigated). The installation contractor takes the proposed pipeline route coordinates and then asks the survey contractor to carry out a pre-lay survey. This survey concentrates on the requirements of the installation operation and any limitations of the pipelay vessel. Hence, it is limited to the pipelay corridor and is more detailed than the previous route survey. If debris or wrecks are found, then slight deviations in the route can be made, as long as they stay inside the route corridor as detailed in the pipeline works authorisation. If pipelay is being carried using an anchored vessel then a wider corridor is surveyed to provide data that is used in the anchor spread designs. This can include some geotechnical surveys along the route.

Offshore pipeline construction


DEBRIS ƒ Side scan sonar of a wreck

The above slide shows the side scan sonar image of a wreck that was found during the pre-lay route survey for the Draugen Gas export pipeline in the Norwegian sector of the North Sea. The pipeline route ran northwest to southeast and crossed over the centre of this wreck. Therefore, the pipeline route had to be altered to give the wreck sufficient clearance.


Sidescan sonar images

The above photographs shows typical debris that might be found along the route.



A recent pipeline in the Mediterranean Sea was installed successfully but when the as-laid survey team returned, they encountered a small sunken fishing boat touching the side of the pipe.


This shows the Troll-Oljerør pipeline route survey and an overview of the offshore pipeline design and construction techniques. Very tight tolerances were achieved on the pipelay operations. These were down to ±2 m or ±3 m (6ft or 10ft) horizontally for certain sections – rather than the normal ±5 m (16ft) – with a vertical survey tolerance of ±0.2 m (8in) in 500 m (1640ft) of water. This was achieved using seabottom transponders monitored over a year. Spans were permitted to remain where current speeds permitted.

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PIPELAY SURVEY ƒ Pipeline monitoring for: ƒ Buckles ƒ Coating damage ƒ Loss of anodes

ƒ Touchdown monitoring to give: ƒ Pipeline coordinates ƒ Touchdown distance

The main task of the survey spread during pipelay is to monitor the pipeline at the touchdown point of the pipestring. This is done with an observation ROV, also fitted with a GPS transponder to provide the coordinates of the touchdown point, making sure the pipeline is being laid to the correct route. The pipeline is monitored for any signs of buckles, coating damage or the loss of anodes. The distance of the touchdown point from the lay vessel is also constantly monitored, and the lay vessel is informed of any changes in this distance which may indicate unwarranted changes to the pipelay configuration. Depending on the seastate and type of soil, the visibility can be very low, meaning the ROV will have to fly very close to the pipeline.



AS-BUILT SURVEY ƒ Determines whether pipeline is laid in accordance with Installation specification ƒ Highlights areas of remedial works prior to trenching operation (if applicable) ƒ Checks location of any leaks during hydrotest

The as-built survey is carried out to make sure the pipeline has been laid in accordance with the pipelay specification, and also to pinpoint any leaks during the hydrotest. Any remedial works needed will be highlighted from the as-built survey and may have to be carried out before the hydrotest operation. Any leaks are spotted using the observation capabilities of the ROV to find the dye that is injected into the pipeline during the filling operation.

POST-TRENCH SURVEY ƒ Sometimes called Out-Of-Straightness Survey - OOSS ƒ Highlights areas of post-trench remedial works such as: ƒ greater than allowable spans ƒ greater than allowable bending

ƒ Can be used to calculate potential areas of upheaval buckling ƒ Data has to be ‘smoothed’

Offshore pipeline construction


The post lay survey provides the three-dimensional co-ordinates of the pipeline and gives the surrounding seabed depth. From this data, the shape of the as-laid pipeline can be assessed for spans, excessive overbends and areas likely to buckle due to operational temperature and pressure. The raw survey data is a scatter of points around the actual pipeline axis which then have to be post-processed or ‘smoothed’ before the data can be used for post lay assessments. Care has to be taken when carrying out the post-processing, as areas of potential problems can be smoothed out completely to give a false impression of the straightness of the pipeline.

SURVEY DATA POST PROCESSING What is the true shape of the pipeline? Raw Survey Data

-119 -121 -123 Pipe Depth

-125 -127 -129 -131 -133 -135 -137 -139 0


40 Chainage KP 60



The above slide shows a fabricated piece of survey data to highlight some of the problems associated with raw survey data. The spread of data is known as the survey noise and some surveys are so noisy they cannot be smoothed. The scatter is due to the tides and movement of the vessel or ROV, and it needs to be corrected so that the true shape of the pipeline is known. The first section has not been corrected for a change in the water level due to tidal conditions, causing a discontinuity at KP 0.1. The section between KP 0.6 and KP 0.8 is effectively missing. Between these sections, we do not know what the pipeline route is, so we have to approximate it.



SMOOTHED DATA ƒ Two options: conservative or unconservative Smoothed Survey Data -119 -121 -123 Pipe Depth

-125 -127 -129 -131 -133 -135 -137 -139 0


40 Chainage 60 KP



The pipeline route has a number of options through the raw data as shown above, with the first section corrected for tidal variations. The red line shows the most conservative estimate of the pipeline route with regard to upheaval buckling, and the blue line shows the least conservative route through the data.

POST-BURIAL SURVEY ƒ Determines whether pipeline is buried in accordance with burial specification ƒ Gives depth of cover/burial ƒ Rock-dumped pipelines require pipetracker ƒ Ferrous component of rock dump

As the name suggests, this survey is carried out after the burial operation, either by mechanically backfilling or rock dumping to give the height of cover above the pipeline.

Offshore pipeline construction


There will be a minimum cover height (and possibly a maximum) in the burial specification, and locations where that amount of cover have not been achieved must be recovered or rock dumped. If a pipeline has been rock-dumped, its position has to be determined using a pipetracker, a magnetic device which detects the pipe-steel. Care needs to be taken when processing the data, as most rock-dump contains ferrous deposits which will also give a reading on the pipetracker.

SURVEY OPERATIONS - SUMMARY ƒ Surveys required for following activities ƒ Route - Geophysical and geotechnical data for route planning ƒ Pre-lay - Identify obstructions along route ƒ Pipe-lay - Monitor pipeline during installation ƒ As-built - Identify leaks during hydrotest ƒ Post-trench (Out-of-straightness) - Check for excessive spans and bending ƒ Post-burial - Ensure correct level of burial

Any questions? The following different survey operations will be carried out at various stages in the pipeline installation: ■ Route - Establish geophysical and geotechnical data for route planning ■ Pre-lay - Identify hazards and obstructions along route prior to pipe-lay ■ Pipe-lay - Monitor pipeline during installation ■ As-built - Identify leaks during hydrotest ■ Post-trench (Out-of-straightness) - Check for excessive spans and bending ■ Post-burial - Ensure correct level of burial



SURVEY - SUMMARY ƒ Knowledge of main survey methods ƒ What survey equipment is used and the data that can be obtained ƒ Survey operations performed at each stage in the installation of the pipeline Any questions?

We have introduced the main methods of surveying the seabed for the installation of subsea pipelines. The typical survey equipment and the information that can be obtained from the main survey methods were described. The surveying procedures were discussed and the correct survey operation was identified for each of the main stages of the pipeline installation.


Offshore pipeline construction

Seabed modification

Seabed modification



EXPECTATION ƒ Understand the activities required to prepare the pipeline route for pipelay ƒ Activities covered in this module being ƒ Sandwave sweeping ƒ Rock removal

ƒ Know what can be done to protect the pipeline once it has been laid

We examine the activities required to prepare the pipeline route for pipelay and what can be done to protect the pipeline once it has been laid. Seabed preparation may also include the following operations: ■ Shore approaches - see Landfalls module ■ Seabed preparation for pipeline start-up and laydown ■ Removal of debris (e.g. wrecks, munitions, abandoned anchors and chains)

Offshore pipeline construction



SWEEPING ƒ When pipeline route runs through sandwave field: ƒ Risk of long spans and high stresses ƒ Risk of exposure if sandwaves are mobile

ƒ Options if risks unacceptable: ƒ Pipeline re-route ƒ Sweep sandwaves to reduce pipeline stresses, span and exposure risks

The design and construction of trunklines through sandwave areas can present major technical challenges and have an important input to the cost-effectiveness and long-term safety of some pipelines. Sandwave fields exist primarily in the Southern North Sea and waves can be up to 10m high. They tend to travel in a uniform direction. Detailed surveys and engineering design are necessary to achieve the best balance between the amount of pre-sweeping required and the extent of trenching to ensure long-term pipeline integrity. In some instances, methods to improve the design by reducing the potential for free spans and the associated impact on construction costs have to be evaluated. Some of these methods can include: ■ Evaluation of a pipeline re-route. ■ Undertaking detailed on-bottom stress analysis. ■ Consideration of strain-based acceptance criteria. ■ Investigation of seabed movement and erosion patterns. ■ Evaluation of CAPEX and OPEX risks.

Seabed modification


Re-routing pipelines through sandwave troughs can avoid traversing large sandwaves, and thus eliminate substantial pre-sweep dredging, therefore reducing the potential for exposure after trenching. When the final route has been selected, further analysis has to be performed to optimise the on-bottom pipe profile and define pre-sweep and trenching details for construction. Long-term stability of sandbanks and sandwaves is generally unknown and presents both CAPEX risks during construction (natural back-filling of pre-dredged trench) and OPEX risks associated with intervention works if the pipeline becomes exposed and freespans are generated.

SANDWAVE SWEEPING ƒ Pre-sweep dredging usually by trailing suction hopper dredger ƒ Sandwaves are formed: ƒ in shallow seas ƒ with strong tidal currents ~0.6 m/s (1.2 knots)

Pre-sweep dredging of sandwaves along the selected pipeline route is undertaken using trailing suction hopper dredgers.

Offshore pipeline construction


TRAILING SUCTION HOPPER ƒ Operating depth in excess of 100 m (300ft) ƒ Accurately positioned drag head ƒ Material lifted to surface for disposal elsewhere

HAM 318 - with twin drag heads

Trailing suction hopper dredgers will trench through sandwaves and other obstructions, and can operate in depths in excess of 100 metres. The drag head on the dredger is accurately positioned using sophisticated electronic equipment and the progress is continuously monitored to ensure that the designed profile is obtained.

WATER INJECTION DREDGER ƒ Jetprop and Jetflow - alternative to trailing suction hopper for offshore applications ƒ Water jet system cuts trench and displaces soil to either side ƒ 2 m (6ft) depth per pass Flow down tube ƒ 10 m to 15 m (30ft to 50ft) wide

Sand blasted from trench

ƒ Rotech’s Aquaflow T8000 ƒ Twin counter-thrust propellers keep suction unit stable whilst suspended The new Jetflow and Jetprop excavation systems (Underwater Excavation Limited / PSL Energy Services / International Dredging) has been developed to give lower cost and more efficient trenching of pipeline landfalls and offshore trenches than conventional trailing suction hopper dredging.

Seabed modification


It is a propeller-driven system designed to distribute material evenly to each side of the trench, leaving a clean and deep trench. Using a 10 bar pressure in sand layers, jet-flow technology can achieve a 2 metre deep trench at first pass, and a bottom-width of 10 to 15 metres. In clay, a 1.5 metre deep trench can be produced during the initial pass. It is installed on the drag head of a conventional trailing suction hopper, although it does not use the suction hopper in the usual way. The vessel’s hopper remains empty, as its pumps are used to generate a powerful water jet through the suction pipe. No material is taken on board the dredger. The digging force of the jets is much greater than with conventional systems. The reportedly good results are realised by the combination of fine nozzles and twin main jets, located at each side of the jet-flow head, distributing material evenly beyond each side of the trench. The Jetflow system can also be used to remove rock dumped over pipelines.


Dredged areas Predicted as laid BOP Original seabed

Pipeline then lowered by a further 2 m (7ft) during burial

469 000

470 000

471 000

472 000

Chainage or KP in m (ft)

473 000

474 000

The figure above shows the profile along a 1500 m (5000ft) section of the Interconnector pipeline. The original seabed with five major static sandwaves is clearly shown, together with the “as-dredged” profile. The predicted profile of the pipe is also shown (by courtesy of Brown & Root). The dredging operation is normally undertaken one to two weeks ahead of the pipe laybarging activities. Once the pipeline is on the seabed, it is surveyed to ensure that there are no excessive freespans before the post-trenching operations commence.

Offshore pipeline construction


SWEEPING - SUMMARY ƒ Sandwaves naturally occur on seabed ƒ North Sea - up to 10 m (30 ft) wave heights

ƒ Need to install pipeline at sufficient depth ƒ Otherwise risk of spans and loss of burial protection

ƒ Sweeping is process of removing peaks of the sandwave ƒ Suction hopper dredger ƒ Water injection dredger

Any questions? The North Sea is an area where sandwaves are commonly encountered. The waves can be up to 10 m (30ft) in amplitude. They then pose a serious problem if the pipeline is to be buried and its burial maintained throughout the design life. Sweeping is a method of reducing the height of the sandwaves to a level that enables a trenching machine to then lower the pipeline below the lowest trough of the sandwaves.

Seabed modification



ROCK REMOVAL ƒ When rock is encountered on the route there are a number of options: ƒ ƒ ƒ ƒ ƒ

Reroute pipeline (as for Corrib) Heavy dredger (for soft rock) Rockdump to provide smooth bed Rock anchors Drilling and blasting

When rock is encountered on a proposed subsea pipeline route, there are a number of potential methods of overcoming the problem, as shown above. One option is rerouting the pipeline, diverting around rock outcrops so that the pipeline is laid on sedimentary materials. This method is proposed on the inshore sections of the Corrib sealine.

Offshore pipeline construction


HEAVY DREDGER ƒ May be possible to cut rock using heavy dredger ƒ Mechanical cutter ƒ Bucket dredger ƒ used at Milford Haven to cut trench 8 m (26ft) deep

Depending upon the strength, texture and extent of the rock, a subsea trench for the pipeline can be formed without resorting to blasting, by using heavy dredging equipment. At Milford Haven, a bucket dredger excavated a pipeline trench up to 8 metres deep in a water depth of 30 metres. Dipper dredgers are also used to excavate rock in shallow water.

ROCK DUMP ƒ Rock-dump to build causeway over rock ƒ e.g. Cormorant pipeline, Shetland approaches ƒ May need additional protection after laying

Dump rock-fill materials on the seabed above the height of the rock outcrops to form an underwater causeway to lay the pipeline on at an acceptable profile. After the pipeline is installed, it is covered with more rock to provide stability and protection. This technique

Seabed modification


was used for the Cormorant pipeline on its approach to the Shetland Islands, where more than 300,000m³ of rock was dumped.

ROCK ANCHORS ƒ Where rock runs close below surface ƒ i.e. cannot trench


Grout Drill pipe

Seabed Sand


When the rockhead is at, or near, seabed level and an acceptable profile can be obtained without removing extensive quantities of rock, the line can be laid directly on the seabed. It will then require either rock anchors to stabilise it in position, or rock dump to provide protection and stability. In this type of situation, underwater trenching machines with rock cutters have also been used to pre-form a suitable trench.

DRILLING AND BLASTING ƒ Most successful technique ƒ All rock types – tills through granites

ƒ Slow (and therefore costly) ƒ Rock debris removed by dredging ƒ Drill rigs arranged to suit production needs ƒ Jackups in high currents

Offshore pipeline construction


When rock has been encountered, the route cannot be altered and it is too hard to dredge directly, the contractor has to resort to other methods to form an underwater trench. Drilling and blasting is the most successful technique but it is time-consuming and therefore costly. Conditions vary widely from substantial layers of glacial till-type overburden, to the hardest Scottish granites. Drilling barges can be used in shallow waters to cut a trench in hard rock such as granite. A pattern of holes are made and charges inserted. These are then detonated milliseconds apart to blast and displace the excavated rock in one operation. The depth of water and the exposure of the site also has a major impact on the type of equipment to be utilised for each particular project. Drill barges with a varying number of rigs to suit the production requirements (see overhead) are the preferred support vessels. In fast-flowing and exposed locations, jack-up platforms have to be used. The rock is drilled in a pre-established pattern and each hole packed with explosives. In a subsea trench, a multi-row delayed-firing sequence is used to loosen the rock, which is then removed by dredger.

SHAPED CHARGES ƒ Used for small areas ƒ Placed directly onto seabed ƒ Rock material blasted out of trench

ƒ Not as effective as drilling ƒ No specialist barge needed ƒ Environmental issues

1 m (3ft) dia

ƒ Marine life

Blast directed downward shatters rock

If small quantities of shallow rock have to be removed, ‘shaped charges’ can be placed directly on the seabed. These explosives are contained in a weighted canister with an internal conical shape. When the explosives are fired, the material is displaced from the trench, avoiding the need for subsequent dredging. These charges are obviously not as efficient as drilling and blasting but can save high mobilisation costs. The use of shaped charges avoids expensive drilling but also have severe detrimental effects on marine life. One incident in the west of Ireland caused damage to surrounding property. The initial explosions used 100 kg (220 lb) charges to remove a 4 m (13ft) depth of rock from a

Seabed modification


trench. This was subsequently increased in charge weight, first to three times, then five times, as it was perceived that the rock was stronger than expected. The final blast took out the office windows.

ROCK REMOVAL - SUMMARY ƒ Methods available for pipe installation in areas of rock ƒ ƒ ƒ ƒ ƒ

Reroute pipeline, e.g. Corrib Heavy dredger Rockdump to provide smooth bed Rock anchors Drilling and blasting

Any questions?

The above options are available if the pipeline route encounters rocky terrain. ■ If the rocks cannot be removed, then the pipeline may need re-routing around the rocky outcrops. An example of this was the route selection for the Corrib pipeline. ■ Heavy dredgers may be capable of cutting a trench through the rock. ■ If the pipeline is to pass over small areas of rock, then it may be possible to provide a smooth mound, as opposed to the jagged rock, by placing a bed of finer rockdump over the rock. ■ Rock anchors can be used to fix the pipeline in place if the rock head is covered with a layer of sand. ■ Rock can also be drilled and blasted to remove it. However, these processes are time consuming and underwater blasting has serious environmental concerns.

Offshore pipeline construction



PIPELINE PROTECTION ƒ Introduction to protection ƒ Codes ƒ Hazards ƒ Protection methods

This section looks at the methods available for protecting pipelines and how the protection is installed.

Seabed modification


CODES ƒ DNV standards ƒ Offshore standard OS-F101

Offshore Standard OS-F101 provides general pipeline construction criteria and guidance on design, materials, fabrication and installation, testing, commissioning, operation and maintenance of submarine pipelines.

HAZARDS ƒ Dropped objects ƒ Platform supply ƒ Drilling and well work-over

ƒ Trawling ƒ Anchors ƒ Ships foundering ƒ Special precautions in shipping channels ƒ Cannot bury lines deep enough to avoid anchors

ƒ Munitions ƒ Use of dragged beam as ‘rake’ along route These are the potential hazards. The first three are described in the following slides. ■ Wrecks are a very high load, low probability incident against which we can’t protect. There have only been two incidents in the North Sea of ships wrecking pipelines by impacting with them in shallow water. Special protection is usually provided in shipping channels but are expensive for pipelines on the general seabed because of the lengths required.

Offshore pipeline construction


Munitions are again a high load, low probability incident which is not protected against. In the North Sea, munitions do occasionally turn-up close to pipelines, probably dragged there by trawls. The SNIPS pipeline in the Irish Sea runs through a known munitions dumping ground and removal of munitions is a regular activity. There were also problems during the laying of the Malampia pipeline in 2001 when war munitions were found causing major delays.

DROPPED OBJECTS ƒ Platform supply ƒ Container ƒ Drill pipe ƒ Scaffold pole

ƒ Drilling and work-over ƒ Drill collar ƒ BOP stack

Dropped objects are a potential hazard in the vicinity of installations or where vessels are working over or close to flowlines. This is often a design condition. Energies range from less than 1 kJ for a scaffold pole to 50 kJ for a drill collar. The damage caused by a dropped object will depend not only on the magnitude of the impact energy, but also in the way the energy is dissipated (whether the load is locally or globally absorbed). For example, a scaffold pole travelling at high velocity may puncture a protection structure, because all the energy is absorbed at the point of impact; whereas the impact from a dropped container may be absorbed globally through a structure with little or no damage.

Seabed modification


TRAWLING ƒ Impact of otter doors, beams, clump weights ƒ Pullover ƒ Hooking

Trawling activity routinely interferes with pipelines at all locations along the pipeline length. This is therefore a design condition for any pipeline that is not buried, with typical impact from otter trawls being 20 kJ, and 35 kJ from beam trawls.


Effect Impact

Failure mode Dent

Remedy Coating





Gear loss Inform

There are three main interaction effects due to trawl gear passing over pipelines. The first is the impact when the gear first comes into contact with the pipeline. This is similar to a dropped object impact and can result in a dent. The main protective measure against it is to apply a coating to the pipe.

Offshore pipeline construction


The second effect is the pullover force as the gear is pulled over the top of the pipeline. This can drag the pipeline and bend it, and in extreme cases can result in a local buckle. The remedy for this would be to trench the pipeline to get it out of the way of the trawl gear. The third effect is hooking of fishing gear on the pipeline. In other words, the gear passes under the pipeline and becomes entangled to the point where it comes fast. For small diameter lines, when the fishing vessel pulls hard it will lift the line and release the gear, so there is no permanent entrapment of the gear. The implication is that the design of the flowline needs to accommodate accidental lifting of the line by half the trawlboard length. For larger diameter lines (12” to 16” and above) the vessel may not be able to lift the pipeline sufficiently before the warps break, and this tends to be more of a problem for the fishermen than the pipeline.

TRAWL GEAR PROTECTION ƒ Generally coating and trenching ƒ Large diameter lines ƒ Left unburied in North Sea ƒ Requires burial in Gulf of Mexico (smaller trawlers)

ƒ Specific localised protection required for: ƒ crossings ƒ spools ƒ valves and fittings

Localised protection requirements are: ■ At crossings - rockdump or grout bags used to fill gaps beneath pipe to prevent hooking of trawl gear ■ Spools - rockdump, mattresses or, if movement is required, tunnels to give trawl and dropped object protection ■ Valves and fittings - usually dedicated protection structure for vulnerable components

Seabed modification



Impact small Sustained high load Dent and bending damage Soft measures to protect Normally not a pipeline design case except in shipping channels Anchor chain

Wide berm of armour stone protection

Path of anchor

There have been a number of incidents of vessels dragging anchors onto pipelines, even in exclusion zones. This event is accidental, ultimately resulting from human error. The magnitude of loads is very high. This is not normally a design condition unless the pipeline crosses shipping channels. Here, the pipeline is buried to a sufficient depth and protected by a wide enough cover of large armour stone to ensure that the anchor will be lifted over before it hits the pipe. The width of rock may be 16 m to 20 m (50ft to 65ft) over a 3 m (10ft) deep trench. In Hong Kong, a pipeline crossing a major shipping route was covered with thickness rock dump for 16 km (10 miles). This is, however, exceptional and required 16 million tonnes of rock.

Offshore pipeline construction


PROTECTION METHODS ƒ Can be done in a number of different ways: ƒ Rock dumping ƒ Man-made protection devices ƒ Concrete mattresses ƒ Spool protection structures ƒ Valve protection structures

ƒ Have to make sure that installing the protection does not damage pipeline!

Having trenched the pipeline, it is sometimes necessary to backfill it (for protection or thermal insulation). Backfilling means replacing the soil so that the pipeline becomes buried. There are four main ways of doing this, which are presented here in order of escalating cost: ■ Natural backfill ■ Mechanical backfill ■ Rock dumping ■ Fabricated protection devices Historically, large-diameter pipelines were not covered after lowering, as this task was undertaken with jet-sledges and the only backfill came from deposition of seabed material that was thrown up during the operation, or normal seabed deposition over time. In the late seventies, the Danish authorities insisted that a section of the Ekofisk to Emden pipeline be covered, as that was what was defined in the specification. This was the first time rock-dump was used for an offshore pipeline.

Seabed modification


PROTECTION - SUMMARY ƒ Common hazards to protect against ƒ Dropped objects ƒ Trawl gear ƒ Anchors

ƒ Protection methods ƒ Rock dump ƒ Trench then bury ƒ Man-made devices

Any questions? The common hazards that can result in damage to a pipeline and protection methods that can be used to prevent the damage are summarised above.

Offshore pipeline construction



ROCK DUMP USING A FALL PIPE ƒ Fall pipe ƒ Used for placing rock along lines ƒ Efficient use of rock to form windrow of protection

ƒ Washed rock to prevent turbidity

One method of protection is to rock dump. In the picture above, Rollingstone (Tideway’s DP rock dump vessel) works on the Wintershall offshore stabilisation project through a fall pipe.

Seabed modification


SIDE DUMP VESSELS ƒ General coverage of a wide area ƒ Scour prevention ƒ Around platforms and jackups

ƒ Not generally used for pipelines ƒ Poor control of berm profile – costly in rock ƒ Shallow water in trenches

Side and bottom dumping vessels are used for scour prevention around shallow water installations . The above picture shows the DP stone dumping vessel HAM 601 rock side dumping near a platform.

FALL PIPE ƒ Accurate placement ƒ $200 000 per km ($322 000 per mile) ƒ Water depths of more than 1000 m (3300ft) ƒ DP vessels equipped to monitor path of pipeline ƒ ROV to monitor results ƒ Rock impact onto pipeline negligible – terminal velocity

The precision placement of rock using the fall pipe technique, to protect and stabilize subsea pipelines and structures, is common practice.

Offshore pipeline construction


The support vessel is dynamically positioned and carries up to 18,500 tonnes of rock. The rock is loaded at designated quarries with quayside facilities, and then the vessel sails directly to the pipeline site. The vessel is equipped with pipe-tracking packages and an active spider for subsea navigation. This equipment is integrated through a survey suite to ensure that the fall pipe follows the pipeline as it moves along the route. A separate ROV also operates from the vessel to monitor the results of the rock dumping. Typically, a digger loads gravel from the hold onto a conveyor system, which drops it down a fall pipe . The fall pipe runs from the ship down to close to the seabed. The end position is remotely controlled to shape the rock berm. Rock dump vessels can operate in water depths of more than 1000 m (3300ft). The fall pipe technique is usually used for accurately placing high-density rock as a protection over subsea pipelines. However, it can also be used to place sand and gravel over existing pipelines and bundles to improve their insulation capability.


Controls fallpipe position Accurate positioning of rocks on seabed

Medusa ROV

The above figures show the Medusa ROV used on Van Oord’s rock dump vessel, Rocknes. The ROV is a 300 kW rock dump ROV designed and built by the Engineering Business Ltd. (EB). It is located at the bottom of the flexible fallpipe. Thrusters on the ROV manoeuvre the end of the fallpipe to give accurate positioning of the fallpipe exit point. This enables accurate control of the location of rock placement on the seabed. It is designed to precisely direct rocks onto the seabed in water depths up to 1200 m.

Seabed modification



Built 2001 Dynamic positioning Flexible fallpipe „



Dumping capacity „


Dumping depth 800 m (2624ft) Diameter 1.1 m (3.6ft) 2000 tonnes/hour

Survey equipment to confirm coverage

The Van Oord ACZ Rocknes rock dump vessel was constructed in 2001 in Hamburg, Germany. It was designed as a flexible fallpipe vessel and bulk carrier. It had an overall length of 166 m and beam of 24.5 m with a deadweight of 25000 tonnes. The vessel used a Kongsberg Simrad dynamic positioning system, utilising six thrusters and a main engine with a top speed of 14 knots. The flexible fallpipe diameter was 1.1 m and had a dumping depth of 800 m. The dumping capacity was up to 2000 tonnes/hour. At the base of the fall pipe was an ROV that utilised four 75 kW thrusters to allow accurate rock placement. The vessel also carries an array of survey equipment such as scanning sonar and underwater cameras. This equipment is used to monitor that placement of rocks and confirm that the correct level of coverage has been achieved. The survey data is then passed onto the client as evidence. Unfortunately, on Monday 19th January 2004, the vessel capsized in a Norwegian Fjord with the loss of at least 3 of the 30 crew members with 15 still missing. An investigation into this incident continues.

Offshore pipeline construction



This video details the rock dumping capabilities of the “Rollingstone” vessel operated by Tideway. The vessel utilises a class 2 dynamic positioning (DP) system with 6 thrusters. The DP system eliminates the need for anchors and tugboats to hold the vessels station which enables it to safely work in close proximity to offshore structures. The Rollingstone has a loading capacity of 12000 tonnes and can accurately place rock on the seabed at 1000 tonnes per hour in depths of up to 1000 m (3281 ft). The vessel dumps the rock to the seabed through a fall pipe with a ROV connected to the seabed end. The ROV utilises four 300 kW thrusters to position the end of the fall pipe relative to the vessel and pipeline and so enable accurate placement of the rock over the pipeline. The ROV also carries survey equipment consisting of cameras, pipeline trackers and scanning profilers to ensure the rock is being placed in the required location. The survey information is instantly accessible to the operators and client representatives on the vessel, which enables them to quickly assess that the correct level of protection is being achieved. Shown in the video is the assembly of the fall pipe and deployment of the ROV through a moonpool in the ship’s hull which allows the vessel to operate in adverse weather conditions. The fall pipe and ROV incorporate an active heave compensated system which allows the end of the fall pipe to be accurately controlled by compensating for vessel movement at the sea surface in bad weather. Also detailed in the video is the design of the fall pipe, which is made-up of closed pipe segments to enable the delivery of fine gravel for pipeline coverage without it being washed out of the pipe, as can be the problem with cage-type fall pipe.

Seabed modification


ROCK DUMP - SUMMARY Controlled delivery of rock to seabed Stabilise the seabed Provide level foundations Cover permanent subsea equipment to give protection ƒ Two types of rock dump delivery ƒ ƒ ƒ ƒ

ƒ Side dump ƒ Fall pipe

Any questions? Rock dumping is the process where quantities of small rocks are transferred to the seabed under controlled conditions from vessels on the sea surface. The rock may be required to stabilise areas of the seabed (i.e. prevent scour), provide a level foundation for facilities such as Gravity Based Structures and provide a protective layer of permanent subsea equipment, such as pipelines. There are two methods of rock dumping. One is where large quantities are dumped from the side of the transport vessel. The other is to deliver the rock through a chute in small amounts. The second method gives greater accuracy on placement of small amounts of rock.

Offshore pipeline construction



CONCRETE MATTRESSES ƒ Concrete linked on polypropylene ropes ƒ Two types ƒ Log ƒ Flex in 1 direction ƒ Over pipeline

ƒ Segment ƒ Flex in 2 directions ƒ Over bends and tie-ins (junctions)

ƒ Blocks vary from ⅓ m to 1½ m (1ft to 5ft) high ƒ Removable for inspection ƒ Concerns with rope deterioration ƒ Can incorporate anodes using steel wire This shows a segmented mattress. Suppliers of stabilisation mattresses include: ■ Seamark Systems ■ Seabed Scour Control Systems Sizes of blocks are dependent upon the current velocity and stability. Although they can be removed for inspection, there are concerns regarding the strength of the polypropylene at the connections between the blocks after a number of years flexing on the seabed. When lifted, they may fall apart onto the pipeline !

Seabed modification


MATTRESSES ƒ Installed from DSV or MSV ƒ crane lift

ƒ Installed using a handling frame ƒ Problem issues ƒ alignment ƒ coverage

These are the most common forms of fabricated protection as they can be purchased ‘off the shelf’ and are relatively quick to install. In addition to the link-lok mattresses, as shown in the previous slide, there are a number of alternative designs. The method of installing them is very similar. One particular advantage of matresses is that they can be easily removed for subsequent tie-in works or alterations to the pipeline system. These are normally installed from a DSV or MSV using a lifting frame and ROVs or divers to enable them to be positioned accurately over the pipeline. The seabed at the edges of mattresses or covers may have to be stabilised to prevent scour using scour mats, also positioned using an ROV or divers.

Offshore pipeline construction



This illustrates a mattress about to be installed using a purpose built handling frame.

CONCRETE MATTRESSES SUMMARY ƒ Common method for providing local protection for subsea structures ƒ Prevent scour ƒ Protect from impacts ƒ Stabilise pipelines in the event of concrete coating loss

ƒ Cost effective for short pipeline lengths and small areas Any questions? Concrete mattresses are an off-the-shelf solution of protecting subsea structures. They can be positioned around the structure to prevent seabed scour. They can protect structures and pipelines from impacts with dropped objects and trawl gear. They become cost effective when the areas requiring protection are small, as they can be installed from Diver Support Vessels, which have relatively lower day-rates and can undertake other operations at the same time. For larger areas requiring protection it may be more cost-effective to use rock dump.

Seabed modification



PROTECTION STRUCTURES ƒ Spool covers ƒ Valve protection covers ƒ Protection over subsea cooling loops ƒ Spool covers ƒ Tunnel sections ƒ Allow pipe movement ƒ Steel or concrete

ƒ Panels filled in later to aid lowering operations

The top picture shows pre-cast concrete tunnel sections for spool protection. Protection covers are fabricated with lifting eyes and are lifted straight into position from the DSV. They can be fabricated in the shape of the spool to be protected, which is beneficial for L or Z-shaped tie-in spools. In the bottom picture, the tunnel units are some 3 m (10ft) high, by 10 m (30ft) long, by 6 m (20ft) wide, weighing 30 to 50 tonnes. An alternative is to place a lightweight steel structure over the pipeline and then pump concrete into the structure. This avoids heavy offshore lifts.

Offshore pipeline construction


PROTECTION STRUCURES ƒ Valve or manifold protection covers ƒ Open, grated or plated ƒ Usually steel or concrete ƒ GRP has also been used ƒ monocoque structures ƒ Access required for maintenance

SUBSEA PROTECTIVE STRUCTURES Shell Cocoon wellhead protection (fisher-friendly)

Conventional pyramidal well protection (‘overtrawlable’)

Composite materials can be used for many protective subsea structures including wellhead and valve protection. The main value to be gained from the use of composites is weight saving, which can enable substantial savings in installation cost by enabling the use of lower-cost lift vessels, or to enable the protective structure to be attached to the flowline during pipe installation.

Seabed modification


The fabrication cost is competitive with that of conventional steel and concrete technology. The lower material modulus of GRP may impose limitations for some structural applications, for example templates.

COMPOSITE PROTECTION STRUCTURE ƒ Lightweight composite ƒ Installed during laying ƒ Light enough for stinger

ƒ Shallow water for Liverpool Bay developments ƒ Provides controlled environment for valves

Composite materials were used to provide protection for four pipeline valves in the flowlines for the Liverpool Bay development. Here, the lightweight nature of composites provided savings in total installed cost by enabling the protective structure to be attached to the flowline during pipe laying.

Offshore pipeline construction


PROTECTIVE STRUCTURES SUMMARY ƒ Purpose built structures to give specific levels of protection ƒ Include ƒ Spool covers ƒ Valve and manifold covers

ƒ Manufactured from ƒ Steel, concrete and composite materials

Any questions?

Protective structures are ‘purpose built’ structures, designed to give specific levels of protection from certain types of probable hazards. Examples of frequently used protective structures are spool, valve and manifold covers. The structures can be manufactured from steel, concrete or composite materials, depending on cost and design requirements.

Seabed modification


CROSSINGS ƒ Common requirement for protection ƒ Need to provide: ƒ physical separation of pipelines ƒ bury spans produced by pipe passing over other ƒ provide impact protection Plan of a typical North Sea development showing multiple pipeline crossings.


Offshore pipeline construction


CROSSINGS ƒ Build supports ƒ concrete sleepers or steel fames ƒ mattress stacks ƒ grout bags

ƒ Rock dump ƒ to provide protection ƒ alternative is to position large inflatable grout bags

ƒ Differential settlement in soft sediments

■ ■ ■ ■ ■

Separation between pipelines is usually a minimum of 300 mm (12in) to allow for any settlement. The US practice is to demand greater separation at 450 mm (18in) The supports for the ‘bridge’ are installed prior to installation of the new pipeline If existing pipeline can be lowered, it can save a number of supports and rock dump Grout bags can be post-installed to overcome any excessive free spans To avoid rock dump, an inflatable sewn bag can be placed over the crossing and then filled with cement grout

Concerns have been raised at the ends of rock dump (for the new and existing pipelines) in soft sediments where differential settlement may occur, causing overstressing of the wall.

Seabed modification


CROSSINGS - SUMMARY ƒ Provide physical separation between crossing pipelines ƒ Use concrete sleepers, mattress stacks, grout bags

ƒ Issues to consider ƒ Burial of spans ƒ Provide sufficient impact protection ƒ Can use rock dump or inflatable grout bags

Any questions?

Crossings are the points where one pipeline has to pass over an existing pipeline. These are a common problem in congested locations. The requirement of a crossing is to provide a minimum separation between the two pipelines. This can be achieved by using concrete sleepers, mattress stacks or grout bags to raise the newly installed pipeline above the existing pipeline at the crossing location. Issues to consider when designing a crossing are the prevention of spans forming and providing sufficient impact protection from trawling equipment. Protection is usually achieved by rock dumping the crossing location or by using inflatable grout bags.


Offshore pipeline construction


The video shows some of the aspects of seabed modification carried out as part of the foundations preparation for the Malampaya project. The Malampaya project involved the installation of a Concrete Gravity Structure (CGS) in 43 m (141 ft) of water and a 500 km (311 mile) pipeline to shore. Seabed preparation at the site of the CGS installation was done by covering the seabed with rock. The CGS was constructed on land and towed out to location, then sunk to the seabed and stabilised with more rock. The video also covers the installation of the pipeline and the placement of rock over the pipeline for both protection and stabilisation.

SEABED MODIFICATION - SUMMARY ƒ Activities which may be required to prepare the pipeline route for pipelay ƒ Know what can be done to protect the pipeline once it has been laid Any questions?

We have examined the activities required to prepare the pipeline route for pipelay and what can be done to protect the pipeline once it has been laid.





EXPECTATION ƒ Know the methods of trenching pipelines and the associated equipment ƒ Be able to select the correct trenching method for different seabed soil types ƒ Appreciate the need for a transition zone between untrenched and trenched pipe ƒ Understand the methods available for backfilling trenches

Here we introduce the concept of trenching pipelines. The main methods of trenching are outlined and examples of the equipment used in each method are provided. The effectiveness of each trenching method in different types of seabed soil and the need to consider the transition zone between sections of trenched and untrenched pipe are detailed. Finally, the methods of backfilling the trench are discussed.

Offshore pipeline construction



INTRODUCTION ƒ Lowering the pipeline below the natural seabed level for protection or stability ƒ 3 methods are used ƒ Plough ƒ Jet ƒ Cut

ƒ Backfill to cover pipeline

Trenching means removing the soil under the laid pipeline so that it falls below the natural seabed level. This is called ‘post trenching’. There are three methods of trenching: ploughing, jetting and cutting. In some instances, the trench can be pre-formed, using either dredging equipment or a plough, before the pipeline is installed. This is called ‘pre-trenching’. The trench can be backfilled with imported material or allowed to fill naturally to cover the pipeline. The picture shows a pipeline plough.





The picture above shows a typical pipeline plough. It has skids at the front (left hand side) and plough shares at the back. Offshore, the plough is lowered over the pipeline with the shares open. (It splits in half down a vertical plane and opens about a hinge at the top of the plough). The pipeline is picked up by rollers at the back and the shares are closed underneath. Tugs then pull the plough forward via a warp attachment at the front. The shares dig in and produce a triangular trench under the pipe into which it falls as the plough moves forward.

Offshore pipeline construction



This overhead shows a typical post trenching operation, using a split-share plough in water depths of up to 400 metres.


The animation by CTC shows how their plough is lowered from the vessel on a wire and located over the pipeline with its split shares open. Lights and cameras on the ROV allow this to be accomplished safely using the plough’s onboard thruster units. The pipeline is lifted into the forward and stern roller boxes and the shares closed using the ram. By lowering the skids at the front, the depth of cut is adjusted as the plough is pulled forward by the bridle chain.



It is necessary to check the stresses in the pipeline during the initiation and trenching (with pipe resting at the base of trench to the stern).

PLOUGHING SPREAD ƒ Ploughing spread is one DSV/MSV ($100 000 per day) and one or two tugs ($30 000 per day each)

The plough spread comprises a DSV or MSV and tugs. The DSV/MSV transports the plough to site, lowers to and recovers from the seabed and provides any diver support necessary for these operations. The plough will be controlled from this vessel. As high pull loads are often required, one or two tugs are used to tow the plough, or alternatively a heavy-duty workbarge.


First pass trench partly excavated mouldboards push soil to side

Final pass trench fully excavated remaining spoil deposited over windrows

Offshore pipeline construction


This plough is capable of forming a trench up to 2 metres deep and can be pulled by a host vessel or barge with a maximum bollard pull of 300 tonnes.


As illustrated by this picture, pipeline ploughs are often large, and therefore the lowering of the plough onto the pipeline is a critical operation.


800 m/hr (2600ft/hr) ƒ Soft clay ƒ Stiff clay 100 to 200 m/hr (330 to 660 ft/hr) cu ~400 kPa (58psi) ƒ Loose sand 500 m/hr (1650ft/hr) ƒ Med/dense 75 m/hr (250ft/hr) ƒ Dense sand 20 m/hr (65ft/hr) ƒ V. dense sand refusal ƒ Chalk/rock variable, rough trench ƒ Maximum depth - 400 m (1300ft) for pipelines Typical values for plough performance are given in the table above. The plough is capable of working on nearly all types of soil, including friable chalk and rock.



The major difficulty that it encounters is in very dense sand where the permeability is low. The reason for this refusal in dense sand is that, as the plough tries to cut and lift a segment of the sand, it requires water to fill the void created. In low permeability sand, the water cannot reach that site and a hydraulic lock results.


Dense sand Boulder clay Large forces to tow warps Deep water ƒ Control of DP and bollard pull

ƒ Multiple passes

There are several issues to consider when ploughing is an option. Dense sand can give rise to problems, as noted earlier. The plough locks into the seabed and refuses to move. This is caused by the inability of water to pass through the sand. Water injection and vibration of the plough shares has been tried on some ploughs. Boulder clay may cause the plough to deviate when a boulder is encountered. This can give rise to problems later, as it may result in an out-of straightness in the as-laid pipe, and therefore make it prone to upheaval buckling. The towing warps are transmitting large forces that could easily cause damage if they were transmitted to the pipe. As a result, a bridle arrangement is used to try to ensure that the forces are transmitted to the plough in the correct (forward) direction, and that the plough does not go sideways into the pipe. In deep water, the warps are too flexible to allow controlled progress. The plough will tend to stop at obstructions, wait until the warp tension rises sufficiently to pull the plough forward again, then jerk forward quickly, release the tension and stop again. Careful control of the vessel DP and gradually raising and accurately holding the bollard pull in steps of 1 tonne to 5 tonnes can extend the depth of operation. The positioning of a plough over a deepwater pipeline is also difficult. Ploughs need a virgin seabed for their skids in order to orientate the plough share. As a result, they cannot do multiple passes over the top of spoil heaps, so the full depth must be achieved in one pass. Multi-pass ploughs are available. These deflect the spoil beyond the trench to leave a reference portion of flat seabed adjacent to the trench.

Offshore pipeline construction


PLOUGHING - SUMMARY ƒ Ploughs produce a trench into which the pipeline is positioned ƒ Towed from a surface vessel ƒ High pull loads may require several vessels

ƒ Care to be taken when lowering plough ƒ Efficiency is dependant on soil conditions ƒ Difficulty in controlling plough in deepwater Any questions?

Ploughs can be used to create a trench into which the pipeline is positioned for protection. They are towed behind a surface vessel. However, the loads required to tow the plough may be large and so one vessel may be insufficient. It is also common to have a Diver Support Vessel to monitor the ploughing activity with an ROV and provide diver support if required. Ploughs are often very large structures and so great care must be taken when lowering them to the seabed to prevent damage to the pipeline. Their effectiveness is also dependant on the soil conditions, as refusal can generate very large towing forces. There are also issues regarding the control of ploughs when used in deepwater, that may render them an ineffective means of trenching the pipeline.




JETTING EQUIPMENT ƒ Two approaches ƒ Large pumped units with eductor pipes ƒ ƒ ƒ ƒ

Pumps on barge at surface with hoses to machine Electrical cables driving subsea pumps Capable of cutting soft clays Excavates material so leaves open trench

ƒ Small machines – fluidises sand with no eductors ƒ Requires sandy seabed to operate ƒ Backfills whilst burying

Offshore pipeline construction



This overhead shows Saipem’s Diverless Jet Sled DJS1, which is capable of lowering pipes of up to 60 inch diameter into a trench of up to 6 metres in depth. Deployment system - DJS1 is deployed from the host vessel and lowered over the trench with positioning being facilitated by the real time sonar and video systems. Remotely operated jet tools can be opened out clear of the pipeline during deployment and recovery. Jet trenching - Trenching is carried out, making use of two separate systems to cut the trench and remove the spoil High-pressure water from surface supply pumps is delivered to nozzles located on the sled claws to break the seabed soil. A separate suction system removes the spoil via eductors using a venturi fed water lift eduction system. Trench depth control - The depth of the trench may be altered during trenching by changing the height of the hydraulically actuated jet legs. The maximum trench depth achievable in a single pass is dependent on soil type and trenching speed.



JETTING SPREAD ƒ Jet sledge spread is a flat-bottom barge with water jet pumps or electric supply ($70k per day) and an anchor handling tug ($20k per day)

The jetting spread comprises of a dedicated barge, together with an anchor-handling tug and the jetting machine with a high-pressure water or electric supply.


The video shows how trenching was accomplished during the Zeepipe in the southern North Sea. High pressure jets attached to sledges were used to fluidise the sand.

Offshore pipeline construction



Soft clay Firm clay Stiff clay All sands Chalk/rock

400 m/hr (1300ft/hr) 100 to 200 m/hr (330 to 660ft/hr) refusal (surface fractures) 400 m/hr (1300ft/hr) refusal (surface fractures)

ƒ Maximum water depth - 300 m (1000ft)

The jet sled is primarily intended for use in granular soil conditions, although it is also effective in soft to firm clays. It has the advantage that multiple passes can be made along a pipeline to achieve a required depth in difficult soils. It may be the preferred system in some clays, where pull loads for a plough become prohibitively high. Disadvantages of the system are that in loose sands the trench can collapse and become very shallow. Also, in variable soil conditions, spans can be created where some sections of seabed are more rapidly dispersed than others. The above table gives some general performance characteristics in a range of soils. Although normally restricted to about 300 m, Van Oord/Ham have reportedly achieved 2000 m in favourable conditions.



JETTING ISSUES ƒ ƒ ƒ ƒ ƒ ƒ

Staying straight in variable soils No spoil Cobbles Trench collapse Shallow trench angles in fine soils Changes in soil type ƒ Blasting hole in seabed

Jetting machines sometimes have problems cutting a straight line in variable soils, as they work best in consistent conditions. For example, if one is on full pressure to excavate some clay and moves into an area of soft sand, it could excavate a large, unwanted crater in seconds. The soil is whipped away and dispersed, so is not available as backfill. Backfill may be provided by the sled doing a second pass to undercut the sides of the trench, causing it to fall on top of the pipe. If the soil contains cobbles, then these will accumulate in the bottom of the trench, protecting the seabed underneath and prohibiting a second pass. In some soils, it is possible that the trench will collapse before the pipe touches down, leaving the pipe improperly trenched. Such trenches are less effective in hydrodynamic shielding, and may be ineffective in protecting against trawl gear. Also, as discussed later, if the soil remains in a fluidised state and the pipeline is not sufficiently heavy, the pipeline can float up in the trench.

Offshore pipeline construction


JETTING - SUMMARY ƒ High pressure water jets used to liquefy seabed in localised area ƒ Suction system removes spoil which can be used for backfill ƒ Can make multiple passes and is useful in clay ƒ Difficulty maintaining trench walls in loose soils Any questions? The jetting system utilises a tracked machine that incorporates high pressure water jets that liquefy the seabed soil and create a trench into which the pipeline is lowered. The jetter can then make a secondary pass and backfill the trench with the spoil to bury the pipeline. One advantage of the jetting system is that it can make multiple passes to achieve a deeper trench than the ploughing system. It is also useful for clay type seabed soils, which would be difficult to plough. A disadvantage is that in loose soil types, it can be difficult to maintain the trench wall between the time of jetting and the time of positioning the pipeline.




MECHANICAL CUTTER ƒ Digging Donald ƒ Uses sensors to avoid contact with the pipe

As the name implies, the mechanical cutter is a device that drives along the pipeline with mechanical teeth or buckets, excavating a trench. The above picture shows the Digging Donald - a trench vehicle with two chainsaw arms reaching under the pipe. This vehicle uses a series of sensors to ensure that the cutters do not come into contact with the pipe.

Offshore pipeline construction


MECHANICAL CUTTER ƒ Giano ƒ Driving wheels clamp around pipe ƒ Cutter contact with pipe not possible

This picture shows the Sonsub Giano, a new mechanical cutting system.

MECHANICAL CUTTER SPREAD ƒ Mechanical cutter spread on specialist support vessel ($150 000 per day)

Trenchsetter and Digging Donald

The mechanical cutter spread uses a specialist support vessel to deploy and control the cutter vehicle.



TALON TRENCHER ƒ Cutter and jetter on ROV for deep water flowlines

In deep water it becomes difficult to plough due to the length and flexibility of the towing warps. Devices such as the Talon Trencher, pictured above, have therefore been developed. These consist of jet cutters mounted under an ROV (remotely operated vehicle).


300 m/hr (990ft/hr)

ƒ but may sink or skid

ƒ ƒ ƒ ƒ ƒ ƒ

Stiff clay 100 to 200 m/hr (330 to 660ft/hr) Loose sand 200 to 300 m/hr (660 to 990ft/hr) Med/dense 200 m/hr (660ft/hr) Dense sand 100 m/hr (330ft/hr) V. dense sand 75 m/hr (990ft/hr) Chalk/rock variable high tooth wear

Again, cutters can be used in most types of soil. Their particular ‘bête noire’ is to cut through chalk or soft clay where boulders or flint embedded within the soil tend to break or blunt the teeth on the cutters.

Offshore pipeline construction



Tooth damage in flinty soils Cutter near pipe Weight /traction of vehicle in soft soils Good shape of trench

Cutters may have problems cutting through chalk or soft clay where boulders or flint embedded within the soil tend to break or blunt the teeth on the cutters. This necessitates regular recovery of the machine to the support vessel. It is important to remember that there is a very efficient cutter in close proximity to the pipe. If the cutter goes off course, it could very quickly damage the pipe. It should be noted that this is only a small risk as the cutters have safety systems. Cutters are heavy vehicles and may have problems in soft soils. They need to be correctly ballasted so that they have enough weight to get good traction, but not so much that they may sink into the soil. Finally, cutters give a good trench shape and are even capable of cutting a slot, if the soil conditions are right.



CUTTING - SUMMARY ƒ Cutters excavate trenches by mechanically removing the soil ƒ Give good trench profiles ƒ Can produce a slot in certain soil conditions

ƒ Need to ensure no contact between cutter and pipe ƒ Some issues with soil conditions ƒ Vehicle may sink in soft soils ƒ If soils contain rock then cutter teeth may be blunted

Any questions? Cutters are Remotely Operated Vehicles that incorporate mechanical cutters that excavate a trench. They can give good trench profiles and in certain soil types can actually produce a slot into which the pipe can be positioned. Care must be taken to ensure the cutters do not contact the pipe. There will usually be cutter monitoring systems to ensure this does not happen. Cutters have some issues regarding the soil conditions. In soft soils, the heavy cutter may sink and become inoperable. Also if the soils contain rock fragments, these can blunt the cutter teeth and reduce the efficiency of the cutter.

Offshore pipeline construction



CABLE TRENCHING ƒ Cables buried by similar means ƒ Plough, jet or cut

ƒ Vulnerable to damage ƒ Trench and bury in same operation when possible ƒ Duplex cables may suffer damage so require two operations ƒ Cutting in rock also may use two passes

ƒ Soil strength tested prior to burial along whole route

Cables are buried using similar approaches but with their own specialised equipment. Since cables are vulnerable to damage, it is common to trench and bury them in a single operation. The force required to trench is now normally determined accurately prior to the actual burial operations.



GLOBAL MARINE GRAPNEL ƒ Additional continuous soils measurement ƒ Undertaken prior to ploughing ƒ Fluke depth up to 1.1 m (3.6ft)

ƒ Correlated with client’s survey ƒ Variation in soil properties

ƒ Determines ƒ Soil strength ƒ Burial depth ƒ Bollard pull It is now common for the cable lay contractor to re-examine the soils along the whole route prior to laying the cable. The existing client’s soils report is used and the values compared. From this, it is possible to determine the soil strength as it varies along the route, so the optimum burial depth and bollard pull are determined. It avoids unexpected changes in ground conditions which could cause snatching of the burial equipment and breaking of the cable itself.


Offshore pipeline construction


The CTC plough is located over the cable, which it lifts into the guide chutes before being towed forward by the tug. Depth of trench is controlled using the forward skids. It is different from a pipeline plough in that the ploughshare is very narrow, enabling it to trench and bury the cable in a single operation.


Soil Machine Dynamics specialise in the design and manufacture of vehicles and support equipment for operation on the seabed. The plough shown in the slide above is one of the latest generation of SMD cable ploughs which include a 500kW (700hp) patented jetting system for enhanced deep cable burial up to 3m, combined with a tow force capability of 80 tonnes.




The slide shows a cable plough capable of forming a trench up to 1.5 m (5ft) deep.


The CTC tracked trencher can jet cut and disperse the seabed sediment lowering the cable into a trench.

Offshore pipeline construction



This picture illustrates a tracked jetting machine for cables. With this system, the water jets are located in the jetting head on the articulated arm.


The above overhead shows the outline of a trenching machine, operated by TechnipCoflexip, that is suitable for simultaneously laying and trenching cables and smalldiameter flexibles in rock and coral. Trench depths of up to 1.5 m (5ft) can be obtained.




The above overhead shows trenching machine TM9, operated by Technip-Coflexip, that is suitable for simultaneously laying and trenching flexibles and cables.


SMD Trenching ROV Soil Machine Dynamics have also manufactured a 400 HP cable maintenance and trenching ROV for use in deep water.

Offshore pipeline construction


CABLE TRENCHING - SUMMARY ƒ Additional survey to confirm soil properties ƒ Similar burial methods as for pipelines ƒ Deeper depths achievable by plough and jet ƒ ROVs smaller for deepest water

ƒ Backfill in same operation when possible ƒ Duplex and some rocky seabeds

Any questions?

Because cables are particularly vulnerable to damage during installation, it is now common to confirm the variation in soil strengths along the whole route prior to ploughing. Similar methods of burial are used as for pipelines, but deeper water depths can be accommodated with ploughing and jetting. ROVs for cables can be much smaller than the specialist tools used for pipelines. Wherever possible, the cable is backfilled in a single operation with the trenching. The exceptions being for duplex lines and sometimes in rock.




Machine Used on… Pipelines

Degree of burial Open trench


Pulled Cables

Jetting machine Cutter


Self buried

Usually selfPipelines, cables, bury – wide flexibles open U trench

Pulled, tracked, ROV self-swimming Tracked, ROV Pipelines, cables, Open V but can propulsion flexibles be self bury (rollers)

The above slide gives a comparison of the different types of trenching system.

Offshore pipeline construction



TRENCH TRANSITIONS ƒ Section between trenched and untrenched sections of pipeline ƒ Normally found at: ƒ Start and end ƒ Mid-line spools or tie-ins ƒ Crossings of other lines – plough handling section Transition length



Elevation Seabed

The trench transition is where the pipeline enters and exits the trench, and where the trenching operation starts and finishes. Trench transitions occur close to the pipeline ends or at mid-line expansion spools etc. where the pipeline is tied into an expansion spool, riser or manifold at the normal seabed level. The transition is normally at a gradient of 50:1 but, depending on the buckling potential of the pipeline, this may have to be greater. The plough (or jetting/cutting machine) will need an untrenched length between the transition and the crossing to enable it to be lifted off and onto the pipeline again on either side. The important aspects to consider during the trenching operation are: ■ Prevent overstressing of the pipe during the start and end of trenching (lifting the pipeline to install the trenching device causes high bending stresses). ■ Soil types and the number of required passes to achieve the correct trench depth.




BACKFILLING ƒ Can be done in different ways: ƒ Backfill of seabed material ƒ Rock dumping

ƒ Rock dumping is addressed in a different section

Having trenched the pipeline, it is sometimes necessary to backfill it (for protection or thermal insulation). Backfilling means replacing the soil so that the pipeline becomes buried. There are three main ways of doing this, which are presented here in order of escalating cost: ■ Natural backfill ■ Mechanical backfill ■ Rock dumping Historically, large diameter pipelines were not covered after lowering, as this task was undertaken with jet-sledges and the only backfill came from deposition of seabed material that was thrown up during the operation, or normal seabed deposition over time. In the late seventies, the Danish authorities insisted that a section of the Ekofisk to Emden pipeline be covered (to comply with what was said in the specification). This was the first time rock-dump was used for an offshore pipeline.

Offshore pipeline construction


BACKFILLING ƒ Natural backfill ƒ Free ƒ May take some time

ƒ Mechanical backfill ƒ Carried out using a backfill plough or cutter ƒ Volume of seabed material being backfilled is hard to control ƒ Normally aim to give greater height than that specified to achieve minimum ƒ Expensive to carry out remedial works after demob of the trenching spread Natural backfill means leaving the pipe in the trench and waiting for tide and waves to wash the soil into the trench and to fill it over the pipe. This has the advantage of being free, and the disadvantage that it may take some time and is only feasible in certain areas like the Southern North Sea, which have sufficiently high sediment transport. Natural backfill would be very slow in the Central North Sea and negligible in the Northern North Sea. The next level up is to use a mechanical backfill plough to push the soil from the sides of the trench, or spoil heaps, back over the pipeline. The height of mechanical backfill is hard to control when using a backfill plough.




The above slide shows a backfill plough. The skids at the front are set to run on the sides of the trench and the shares at the back of the plough force the spoil heaps back into the trench.


This shows an illustration of Saipem’s BPL2 backfill plough, which was used on the Goldeneye project in the North Sea. It measures 22 m long x 21 m wide when in operation, and weighs 95 tonnes.

Offshore pipeline construction


FLOTATION ƒ Pipeline flotation is an issue

1.Pipeline in trench

2. Backfill soil fluidises as pushed into trench

3. Pipeline floats on fluidised soil

Flotation is an issue when backfilling a trench. backfilling.

Loose soils may fluidise during

The specific gravity of the fluidised soil will typically be in the range 1.4 to 1.6. If the specific gravity of the pipeline is less than this, it will float on the soil as illustrated above.


This video shows a practical demonstration of a pipeline floating in fluidised soil.



BACKFILLING - SUMMARY ƒ Backfill trench to protect pipeline ƒ Three methods available ƒ Natural backfill ƒ No cost ƒ Not immediate

ƒ Mechanical backfill ƒ Hard to control amount of backfill ƒ Issues with flotation

ƒ Rockdump ƒ Most costly method of backfill ƒ Can accurately control coverage

Any questions? The trench is backfilled to give the pipeline the required coverage for protection. There are three main methods of backfilling the trench, these are shown above along with some advantages and disadvantages.

TRENCHING - SUMMARY ƒ Methods for trenching pipelines and umbilicals with the associated equipment ƒ Correct trenching method is dependant on seabed soil types ƒ Appreciate the need for a transition zone between untrenched and trenched pipe ƒ Understand the methods available for backfilling trenches Any questions? We have introduced the concept of trenching pipelines. The main methods of trenching were outlined and examples of the equipment used in each method were provided. The effectiveness of each trenching method in different types of seabed soil and the need to consider the transition zone between sections of trenched and untrenched pipe was detailed. Finally, the methods of backfilling the trench were discussed.


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Diving and ROV operations

Diving and ROV operations



EXPECTATION ƒ Know the capabilities of divers and the required support equipment ƒ Know the various types of ROV available ƒ Required support equipment, available tooling and operational capabilities

ƒ Know the different ROV launch and recovery systems ƒ Be aware of the ROV market and their availability when planning ROV operations

The operations of Diving and Remote Operated Vehicles (ROVs) are introduced. Diving operations and their capabilities and limitations are examined, along with the health and safety requirements and support equipment required for safe diving operations. The issues of ROV operation are presented. Information is provided on the various types of ROV available and the different operational capabilities, support equipment and available tooling. The different methods of launching and recovering ROVs from vessels are examined. Finally, an overview is given for the ROV market, detailing the leading companies and the different options available to companies looking to make use of ROV systems.

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INTRODUCTION This section considers diving and ROV operations in support of pipelay. It sets the scene with regard to the types of task that may be required, the market for these services, and the factors that influence whether the tasks are done by ROV or divers. We then go on to look at ROVs, diving operations and support vessels in more detail. Please note that survey activities have already been covered, so are not repeated, and pipeline operations and repair activities are addressed in our advanced Subsea Pipeline Integrity Management course.

TYPES OF DIVING AND ROV ƒ Diving ƒ Surface ƒ Saturation ƒ Hard suit

ƒ ROV (remotely-operated vehicle) ƒ Eyeball ƒ Workclass ƒ Specialist machines

Free-swimming sports diving has some aspects in common with commercial diving. However, the latter type requires an umbilical from the surface to supply gas, heat, communications and perhaps hydraulic power for tools. Surface or saturation diving can be carried out from the surface using a range of different gas mixtures. Such diving requires long periods of decompression after each operation in order to avoid some of the deleterious effects of gas entering the body under pressure at depth. The decompression period is a function both of working time

Diving and ROV operations


and depth. It effectively limits the maximum operating depths. To extend the usefulness of a dive team, saturation diving may be carried out where the team stay compressed for a week or more: they only need to decompress once at the end of operations. A third dive method, little used in the pipeline industry, is a hard suit which enables the operator to stay unpressurised at depth (effectively a shirt-sleeve environment). There are three main classes of ROV. All have lights and cameras to enable the pilots on the surface to operate them. The simplest and smallest is the eyeball ROV, which is used for inspection work. Some of these have simple manipulator arms for recovery of small tools etc. The workclass ROV may be thought of as a tractor to which various tools or survey equipment can be attached. They generally have a pair of manipulator arms: the simpler left one will hold onto grasp handles and the right will push, pull or rotate. There are also specialist ROV based machines that can trench pipelines or keep a rock-dumping hopper on location.

PIPELAY SUPPORT TASKS ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Pipelay stinger checks Initiation and laydown preparation Touchdown monitoring Route survey Installation of PLEMs and valves Tie-ins, hot taps Hyperbaric welding Precommissioning Most tasks done by Lost pipe retrieval ROVs

Diver survey operations are covered in the survey section. Some other diving operations for pipeline construction operations are listed above. Divers must be used for inspection and maintenance in areas not accessible by ROV, such as in shallow water (shore approach) and the splash zone around platforms, where their thrusters do not operate efficiently. Divers can carryout unexpected maintenance tasks, whereas ROVs may require preplanned special access ports. This is especially true for emergency operations, where the flexibility of a diver is paramount.

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WHY USE DIVERS? ƒ Drivers for divers: ƒ Complex tasks ƒ Need of flexibility

Underwater welding

ƒ Concerns: ƒ Health and safety ƒ Water depth limit ƒ Cost

The main factors influencing whether divers are used are as follows: ■ More complex operations (e.g. a hot tap) are likely to be more efficiently performed by divers. ROV work is generally planned in advance. ■ There are Health and Safety issues to consider for divers. These have moved the Norwegian government to push not to use divers. However, these regulations are being relaxed. ■ If the water depth is much beyond 200 m, diving becomes problematic and the system needs to be designed to be diverless. ■ Where either divers or ROVs could be used, cost is normally the decider. Diving safety has improved out of all recognition over the years, as has diving equipment. As an aside, you would not expect to see wet welding on a pipeline: the weld cools quickly due to the water quenching and cannot attain the fracture toughness (fatigue resistance) required. Therefore, welds on pipelines need to be done using a hyperbaric environment or, in diverless depths, need to be replaced by mechanical attachment techniques.

Diving and ROV operations



PHYSIOLOGICAL EFFECTS ƒ How deep? ƒ How long? ƒ 4 effects concern us: ƒ ƒ ƒ ƒ

Oxygen toxicity Nitrogen narcosis Decompression sickness (the ‘bends’) Hypothermia

ƒ Factors ƒ Gas mixture ƒ Surface or saturation dive What are the main diving limitations? The physiological effects of breathing pressurised gases at depth provide limits on the depth and time available for work at the seabed. In the short term, there are three effects that divers may be subject to as a direct consequence of pressurised gas mixes. Hypothermia is a consequence of the low ambient temperature and whether the diver is using helium. We need to examine the gas mixture and the type of operation; whether a surface or a saturation dive.

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PRESSURE ƒ Ambient water pressure ƒ Increases by 1 bar (1 atmosphere) for every 10 m (32 ft) in depth

ƒ Gas must be at same pressure as ambient ƒ Differential pressure large ƒ Chest muscles are weak ƒ Lungs collapse

pth 30m 4 bara

Water is dense and ambient pressure rapidly increases with depth. Chest muscles are too weak to cope with more than a very small differential pressure. This means that the gas breathed by divers must be balanced almost exactly with the ambient water pressure. When swimming, we can dive below the surface because we do not try to breath in. If we were to use an extra-long snorkel, our lungs would collapse because of the differential pressure.

HENRY’S LAW ƒ Henry’s Law states: ‘The amount of any given gas that will dissolve in a liquid at a given temperature is a function of the partial pressure of that gas in contact with the liquid’

ƒ Concentration of dissolved gases in blood is proportional to partial pressures in the breathing gas

Diving and ROV operations


The concentration of dissolved gases in the blood is proportional to partial pressures in the breathing gas. The following slides detail the consequences of this law when diving and how to calculate safe gas mixtures for divers.

PARTIAL PRESSURE ƒ What are partial pressures? ƒ Equal to proportion of gas x pressure ƒ A measure of the volumetric concentration of gas molecules Surface 1 bar abs

30 m (99 ft) depth 4 bar abs 4 ATA

Nitrogen Partial Pressure = 0.8

Nitrogen Partial Pressure = 3.2

Oxygen Partial Pressure = 0.2

Oxygen Partial Pressure = 0.8

We define partial pressure as the proportion of a particular gas multiplied by the pressure at depth. It is a measure of the volumetric concentration of gas molecules. At the surface, the normal air pressure is one bar (1 atmosphere). The proportion of oxygen is around 20% with the rest of air being made up of other gases such as nitrogen. So the partial pressure of oxygen is given as 0.2. At 30 m depth, the same ratio of gases apply, but the pressure increases to 4 bar abs (3 bar gauge), and the air molecules are compressed. The partial pressure of oxygen therefore reaches 4 x 20% = 0.8.

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O2 Partial Pressure Limits

Safe Limited survival


-S (e afe xe lim rti on i t 1. 6 ) -S af (a e l t r im es i t t)

1. 0


1 .4

r fa su at

Ai r




yp o



-1 0 at 0% su ox rfa yg ce e n



The first major danger with gas is oxygen toxicity. We can safely breath oxygen over a wide range of partial pressures. Normally we breath air at a partial pressure of 0.2. However, if partial pressures become too large or too small then we find the oxygen becomes toxic. The left hand of this chart, shows the effect of lack of oxygen, such as up Everest, which leads to Hypoxia. At the right-hand side, we show the effects of air diving, where the partial pressure of oxygen is high and there becomes a risk of Central Nervous Systems (CNS) oxygen toxicity. At the centre, it shows that it is quite safe to breath 100% oxygen at the surface. Providing divers do not exert themselves too much, they can withstand a partial pressure of O2 of up to 1.6. This is the equivalent to 8 bar abs pressure or 70 m water depth. (However, it should be noted that commercial air dives would never go this deep in practice.)

Diving and ROV operations


OXYGEN TOXICITY ƒ Severest effect ƒ Oxygen enters bloodstream

ƒ Consequences ƒ Severe convulsions ƒ Resulting in drowning

ƒ Deeper diving ƒ Reduce oxygen content

Oxygen toxicity is the severest physiological effect in diving. As the excess of oxygen enters the bloodstream, it causes severe convulsions and results in the death of the diver by drowning. If we need to go deeper, then the oxygen content must be reduced. We cannot reduce the ambient pressure at depth: therefore the proportion of other gases must be increased.

NITROGEN NARCOSIS ƒ N2 molecules are big ƒ Slow to enter body ƒ Can go above 3.2 bar abs for short periods

ƒ Effects likened to alcohol inebriation ƒ Occurs at pN2 greater than 3.2 bar abs ƒ ~30 m (99 ft) if breathing air

ƒ Deeper diving ƒ Reduce nitrogen content in breathing mixture ƒ Replace nitrogen with helium

Nitrogen narcosis is not as critical as oxygen toxicity but serious nevertheless.

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It has the effect on the diver of being slightly drunk. It occurs at a partial nitrogen pressure greater than 3.2 bar abs. This is the equivalent of around 30 m water depth if breathing air. Because nitrogen molecules are big they are slow to pass through the membranes of the lungs. It is thus possible to briefly dive deeper with few ill effects. (However, nitrogen molecules are also slow to leave the body when surfacing, causing other problems.) If deeper diving is required, then the proportion of nitrogen in the mix is reduced by introducing helium replacement. We thus end up with a tri-mix of oxygen, nitrogen and helium.

DECOMPRESSION SICKNESS ƒ Decompression ƒ ƒ ƒ ƒ

Pressure is reduced N2 does not pass easily though body membranes Dissolved nitrogen forms bubbles in blood Bubbles grow as diver surfaces

ƒ Bends effects = many, including death ƒ Need to decompress slowly ƒ Dissolved nitrogen can escape through lungs ƒ If bends occur, prompt surface recompression

ƒ Helium similar but smaller molecule As mentioned, nitrogen molecules are large. As a diver decompresses and the ambient pressure reduces, they tend to form bubbles in the blood rather than pass out of the body through the lungs. This is also known as the bends, and the effects are many. This may show as lack of balance if the bubble is in the ear, or aching joints where the nitrogen lodges in porous bone tissue. The effects may manifest days later. In the extreme, death can result. Chronic effects may be caused by osteonecosis where gas bubbles enter the bones and they deteriorate over many years. To avoid build-up of nitrogen, divers decompress slowly following published navy tables. These dictate for each depth and length of dive, just how long and at what depths the diver must wait, as he resurfaces. Where bends are suspected, the diver must be quickly recompressed fully in a dry chamber on board the vessel. The increased pressure collapses the bubbles again, and the diver can then go through the full decompression sequence to enable the nitrogen to be released safely. The same effect occurs with helium. However, this is a smaller molecule, which is quicker to come out of the body.

Diving and ROV operations























Max Depth 30 – 60 m (99 to 197 ft) 30 m (99 ft) 180 m (590 ft) 270 m (886 ft)

Air and Heliox mixtures are the commonest used for commercial diving.

Air mixtures can reach 60 m, although normally it is limited to 30 m because of the working time limitation at depth. Nitrox has higher percentage of oxygen in order to reduce the risk of bends. This limits its use to shallower water because it increases the dangers of oxygen toxicity. By substituting some of the oxygen in the Trimix with helium, this danger can be reduced while still keeping the nitrogen percentage low. The Heliox mix replaces all of the nitrogen (and some more of the oxygen) with helium, so permitting even greater depth. Although Heliox mixtures can potentially reach 270 m, the normal commercial diving limit is 200 m.

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Saturation diving


ƒ Diver lives at pressure for up to 28 days ƒ Decompression time 3 to 4 days

ƒ Breaths heliox ƒ Saturation bell and habitat

ƒ Extends performance: ƒ Ultimate depth ƒ ~400 m (1300ft)

ƒ Practical limit ƒ 200 m or 300 m (660ft or 1000ft)

ƒ Maximum dive work : 8 hr Saturation diving is a technique developed by the US Navy in the late 1950s. It permits divers to remain at high pressures for weeks or months without having to often undergo decompression and waste the diver’s time. Researchers discovered that when a diver is underwater for a long time - days or weeks, for example - the time needed to decompress reaches a maximum and stable point. The diver becomes saturated and no longer accumulates additional gas such as nitrogen or helium. In other words, decompression time for a diver who has been underwater for one day may be the same as for a diver who has been down for a week. Commercial saturation diving requires the divers to live in saturation conditions for up to 28 days. The last 3 to 4 days of this period is needed for decompression (depending on depth). They use a bell to reach the seabed and can work for up to 8 hr at a time. Then they transfer and spend 16 hr in a habitat at the surface but under pressure. This work is very tiring and divers tend to spend most of the 16 hr off-shift time sleeping. The ultimate depth for this type of diving is around 400 m (1300 ft) but there is a practical limit of between 200 m and 300 m (656 ft and 984 ft). It is possible to use hydrogen (Hydrox) in place of helium to extend diver performance further, to 500 m (1 640 ft) plus, but this is not used commercially.

Diving and ROV operations




ƒ Shift ƒ 8 hours

ƒ Requirements ƒ Umbilical to supply ƒ ƒ ƒ ƒ

Breathing mixture Heat - hot water Lights/camera Communications

Setting up transfer from bell to habitat ƒ ROV eyeball - safety ƒ At depth - dive companion ƒ Topsides - dive control

The typical working shift for a saturation diver is 8 hr. Whilst working he will require an umbilical connected to the bell (and another from the bell to the surface). This will supply the breathing mixture of gases along with a hot water pipe to keep him warm. He carries lights and a camera on his helmet so that work can be monitored and a range of communications cabling for the camera and voice. Sometimes, hydraulic power is supplied for tools.

Offshore pipeline construction


It is now commonplace for a small eyeball ROV to be used to monitor the work from a different angle from that of the helmet camera. In some parts of the world, this is a mandatory safety requirement. Since the major dive operators work world-wide, this is now considered in their documentation as just part of the standard package. Divers will always work with a dive companion or two. This too is part of the safety regime. The companion monitors the diver for effects such as oxygen toxicity, which reduces the divers ability to recognise that something is wrong. Sometimes three divers are allowed to work at depth: with one in bell monitoring two working together. In the topsides habitat, the dive controller will also monitor conditions of the divers and conditions inside the bell.


ƒ ƒ ƒ ƒ

Compress in habitat Change to heliox Transfer via bell Transfer Medic


passage Compression/ decompression chamber Food hatch

Living accommodation

The photograph shows a saturation diving system for up to 12 divers. Sometimes two bells are used to speed transfer to and from the seabed. At the start of operations, the divers enter the compression chamber from outside and are pressurised to depth. The breathing mixture is gradually changed to heliox. At the start and end of each shift, the divers transfer between the chamber and the bell through the ‘air-locked’ passage, always keeping the same breathing mixture and pressure. Food is transferred from the galley to the habitat through a safety-locked hatch system, and is brought up to the habitat gas/pressure conditions. Should a diver require a medic, then one can be transferred into the habitat though the compression chamber. He too will require the 3 to 4 days decompressing to return to ambient conditions.

Diving and ROV operations



The diving system is incorporated within the hull of the support vessel. This unit is located adjacent to the moon pool to enable transfer from the bell.


ƒ Mobile saturation dive system ƒ Bell access from side of barge ƒ Alternative to moon pool

This overhead shows a mobile saturation diving spread on a construction barge.

Offshore pipeline construction



ƒ Control centre within habitat ƒ Full life-support system ƒ Constant monitoring and control of atmosphere ƒ Control of depressurisation Information from various systems such as pressure and environmental controls are displayed on the central control unit, which can be monitored and operated by two people. The environmental control system is capable of continuous elimination of carbon dioxide, moisture and odours, as well as temperature and humidity control. The gas system can automatically or manually pressurise and depressurise the chamber with various gases over a wide range of pressures. To supply a breathable atmosphere (a mixture of air, oxygen and helium), each chamber is connected to the gas reservoir via decompression valves. The concentrations of gas components can also be controlled.

Diving and ROV operations



ƒ Also required for surface dives ƒ 6 divers ƒ 150 m (492ft)

Emergency decompression facilities are also required for surface diving operations. DSV ‘Bergen Viking’ is equipped with a DNV-certified saturation diving system for six divers, rated to 150 m (492 ft). The system comprises the following main components: ■ diving control ■ regeneration and workshop containers ■ A-frame handling system ■ diving bell and winch container for bell handling ■ decompression/rescue/transfer chambers ■ HP and LP air compressors ■ umbilical basket and bell guiding system installed in and above the moonpool

Offshore pipeline construction



ƒ Emergency transfer from habitat ƒ Floating pressurised chamber ƒ Self contained gas system

In the event that the mother vessel has to be abandoned, or the area of the diving system is threatened, there must be a facility for evacuating the saturation divers under pressure. This capability is provided by a hyperbaric lifeboat, shown in the slide above. Lifeboat: Hyperbaric Chamber:

Harding Safety MCD 7.9 m (26 ft) Gas bottle 50 L - 200 Bar Air bottle 50 L - 200 Bar

Medical Lock View Port Engine Ventilation Lifting Hook Automatic Load Release


ƒ Fits side of different vessels ƒ Ease / speed of installation ƒ Lower mob/ demob cost ƒ 6 divers

Diving and ROV operations


Mobile Saturation Diving System: A complete mobile saturation diving system for 6 divers, consisting of the following main components: ■ Diving control container ■ Work-shop container ■ Regeneration container ■ A-frame handling system ■ Winch container for bell handling ■ Diving bell ■ Decompression rescue chamber ■ Vertical wet pot (transfer chamber) ■ HP air compressor ■ LP air compressor ■ Umbilical basket ■ Umbilical guide system


Hot water


Hot water Gas


Tracking Pneumo

Gas Main bell umbilical

Diver umbilical

Main Bell Umbilical ■ 1 x HFG0108 ½" NB Flexlite gas hose ■ 1 x HAF0312 ¾" NB Armaflex non collapse gas hose ■ 1 x HFG0112 ¾" NB Flexilite gas hose ■ 1 x HFH0112 ¾" NB Flexilite hot water hose ■ 1 x power cable, comprising 34 x 2.5 mm² cores ■ 1 x comms/video cable, comprising 3 x 75 ohms coaxial cables, 18 x 1.0 mm² screened twisted pairs and 17 x 0.75 mm² cores ■ 5 x HFG0104 ¼" NB Flexilite gas hoses ■ Polyethylene monofilament overbraid ■ Polyurethane sheath with circular vents to allow drainage Finished diameter: Theoretical break load:

106 mm 8.0 Tonnes

Divers Umbilical ■ 1 x HFG0110 5/8" NB Reflex gas hose

Offshore pipeline construction


■ ■ ■ ■ ■ ■

1 x HFG0108 ½" NB Flexilite hot water hose 1 x HFG0106 3/8" NB Flexilite gas hose 1 x HFG0102 1/8" NB Flexilite tracking hose 1 x HFG0104 ¼" NB Flexilite pneumo hose 1 x comms/video cable, comprising 2 x 0.50 mm² screened twisted pairs 1 x mini-TV cable, comprising 1 x 1.34 mm² screened twisted pair, 1 x 0.50 mm² screened twisted pair, 1 x 0.22 mm² twisted pair, 1 x 1.34 mm² conductor, 1 x 75 ohms coaxial cable

Finished diameter:

52 mm


The National Hyperbaric Centre (NHC), located in Aberdeen, was set up to provide a facility for the research, development, testing and demonstration of high and low pressure applications for industry. Designed essentially for subsea simulation, the NHC has developed into a facility that encourages and enables engineering developments in both high and low pressure technology. The Centre also houses a deep sea simulation facility, which can emulate subsea conditions to a depth of 1000 m (3 280 ft. Incorporating other pressure chambers gives emulated depth to 3000 m (~10 000 ft). The facility can also be adapted for use to simulate high altitude conditions to a height of 50 000 m (~160 000 ft).

Diving and ROV operations



ƒ Short and long term health effects ƒ Respiratory and circulatory risks ƒ Umbilical loss – small tank on back ƒ Hypothermia

ƒ Chemicals/jellyfish in seawater ƒ On exposed skin in water ƒ Breathing from dive suit in bell

ƒ Physical injury ƒ Tool handling or dropped objects

ƒ Marine life interference ƒ Lights attract ƒ Environmental concerns – spotters

ƒ Reliance on 3rd parties topsides Commercial diving has long been considered one of the more dangerous occupations associated with offshore construction. Divers are exposed not only to the possibility of drowning, but also to a variety of occupational safety and health hazards such as respiratory and circulatory risks, hypothermia, low visibility and physical injury from the operation of heavy equipment under water. In the case of loss of the umbilical line, a small tank is held on the divers back with 10 minutes of air. Sometimes re-breathers can be used as emergency systems for short periods. Chemicals or diesel in the water have attacked exposed skin or caused breathing problems if brought back into the diving bell on the suit or equipment. Jellyfish tentacles can cause lesions of skin. The type of dive, the length of dive, the frequency of dive, and the type of operation increase the already high risk of the work. Additional hazards are associated with the actual work of underwater cutting and welding, materials handling and other types of work utilising hand and power tools. Marine life which may stop diving operations include sharks, sea turtles, manatees, monkfish and even small burrowing fish have pestered divers that got too close to their nests. Lights used by divers attract fish. Even when the diver is not under risk of personal injury, diving disturbance causes environmental concerns: these may require sonic pingers to keep sealife away. A recent trend in the Gulf of Mexico is the need for ‘spotters’ or mammal watchers to protect the sealife from diving activities! A major hazard is the total reliance a diver has on his surface control team for his life support (breathing mixture and hot water supply). As a result of these risks, there is a move towards more use of ROVs for many tasks, even in shallow water.

Offshore pipeline construction



ƒ Seabed temperatures 5°C (39°F) or less ƒ Continuous hot water supply ƒ Diver loses heat quickly ƒ When operating ƒ In saturation dive bell

ƒ Effect exacerbated by helium use ƒ Even in habitat

ƒ Bell emergency equipment Hypothermia or loss of heat from the body is caused by close contact with very cold sea temperature of 5°C or less. The diver is kept warm by ensuring a continuous supply of hot water to under garments fitted with small bore flexible piping. The diver loses heat even when in the dive bell. The effect is made worse when the divers are using helium as part of their mix as this gas permits the heat to be transferred quickly from the lungs. This applies also during time spent in the topside habitat. The emergency bell equipment shown here has a heat recovery mask. It is designed to be used should the saturation dive bell lose power or heating because of accidental umbilical rupture.

Diving and ROV operations


Surface diving and hard suits


ƒ Shallow water ƒ Air, Nitrox or Trimix ƒ Short work duration ƒ May use a mini-bell to increase working time

ƒ Depths ƒ Air ƒ Ultimate 60 m (197 ft) ƒ HSE 20 minutes bottom time at 51 m (173 ft)

ƒ Nitrox ƒ Ultimate 30 m (98 ft)

Surface diving, where the diver returns to ambient atmospheric conditions between dives, is carried out in shallow water. A mini-bell may be used to facilitate transfer to the seabed. Work can only be carried out in short durations because of decompression requirements. The time spent on work has to take into account the time needed for decompression stops on the return back to the surface. Where air is used for breathing, the practical working depth is limited by the required working time at depth. In practice, the working depth is typically between 20 m and 30 m (65 ft and 98 ft).

Offshore pipeline construction



ƒ Air diving bells ƒ For surface diving only ƒ Used for travel to/from seabed ƒ Do not extend dive times

Air diving bells can be used to transfer divers to and from the seabed. They are a simplistic design, similar to an upturned bowl, it is not a pressurised diving bell. The bell is only useful for shallow water work and is used to allow the diver to remove his mask if necessary. It can be used in emergencies to give the diver a temporary habitat. It also saves the diver’s energy when being lowered or lifted to depth.


ƒ Newt suit ƒ ƒ ƒ ƒ

Thruster-propelled One atmosphere vehicle Articulated joints Diver-operated manipulators ƒ Less force compared to ROV ƒ Improved dexterity

ƒ Less expensive than sat-diving

ƒ Performance ƒ Maximum depth 305 m (1000ft) ƒ 6 hr to 8 hr operation (with 48 hr reserve) An example of a hard suit is the Newt Suit. This is a lightweight, single atmospheric diving system that can dive to a depth of 305 m (1000 ft). The Newt Suit is typically utilised with a thruster pack, which allows the pilot to fly the suit or work mid-water,

Diving and ROV operations


rather than walking on the seabed. They were developed from earlier systems without thrusters such as the JIM suit. The system is capable of supporting a wide range of equipment such as cameras, sonar and tracking systems. The suit, thruster and diver weigh about 326 kg (720 lb). It uses articulated joints to keep the diver in ‘shirt-sleeve’ conditions and no decompression is needed. This makes it less expensive than saturation diving. However, the diver operated manipulators - whilst giving better dexterity - have less force than an ROV. The joints also tend to stick with depth. These units are now rarely used by the pipeline industry. Specifications: Depth Height Weight Hull Thrusters Power Comms Life Support Safety

305 m (1 000 feet) 1.120 m (81.2 inches) adjustable 378 kg ( 832 lbs) A356 Cast Aluminum Constant with variable pitch 2 x 2.25 HP at 400 Hz Digital voice/data 6 - 8 hr, emergency reserve backup 48 hr Tether cut, pinger, ballast jettison


ƒ Newt suit rated to 610 m (2000 ft) ƒ US Navy

However, such units are commonly used by the US Navy. This unit and the operator shown here can reach double the depth of the Newt suit. One advantage is that they require no umbilical to control operations, though the diver has a tether for emergency recovery, and could make use of hydraulic supply hose for tool power. These ADS (atmospheric diving suits) require no dedicated ship and are easier to airfreight to an incident than an ROV. Other ADS systems are the Spider and the Hornet.

Offshore pipeline construction


Control of the thrusters is through use of foot pedals and hand controls. They are normally operated slightly negatively buoyant (but they could also be slightly buoyant, should operations require it). Normally, a 4 or 5 man working crew would have a support team of 4 on deck. Market


ƒ Diving companies in 4 main groups ƒ ƒ ƒ ƒ

Stolt Offshore Subsea 7 Technip Torch Inc

ƒ Others ƒ ƒ ƒ ƒ

Caldive Hydrodive Oceaneering DMT (GoM)

The diving companies are in the four main groups above, although there are many other companies including very small local ones. The following gives company fleet sizes, based on information from Underwater Contractor International magazine.

Diving and ROV operations



ƒ DSV Bergen Viking ƒ ƒ ƒ ƒ ƒ

DP system Saturation diving system ROV capability Crane Moon pool ƒ 3.6 m x 3.6 m (12ft x 12ft)

An example of a DSV is the ‘Bergen Viking’, which is equipped with a saturation diving system rated down to 150 m (492 ft), and may be delivered with air diving facilities. The Argus Mariner Work Class ROV is permanently installed on board. Deck Specifications and Equipment Deck: Main crane/hoist: Secondary crane: Capstans: Moonpool:

Area 520 m2, strength 5.0 t/m2, max deck load 1340 t 50 t at 6 m, 25 t at 12 m 5.0 t 2 x 10 t (aft) 3.6 m x 3.6 m

Offshore pipeline construction



ƒ Pipelay vessel ƒ Diving facilities

Type of Vessel: Dimensions: Mooring Stations Keeping Method: Area(s) of Operation:

DP MSV 98 x 18 x 5 m (323 x 59 x 17 ft) DP, 4-point mooring Worldwide

Notes: Deck cargo capacity, Clear deck:

2 500 t (2 750 short tons) 5 480 m² (59 000 ft²)


ƒ Pipelay/construction vessel ƒ Diving facilities

Diving and ROV operations

Type of Vessel: Dimensions: Year Built: Range of Pipe Diameters Handled: Pipe Installation Method: Maximum Pipelaying Water Depth: Mooring Station Keeping Method: Area(s) of Operations:


Construction/Lay vessel 138 x 19 x 6.86 m Converted in 1996 6 to 10in Reel Deepwater DP Asia Pacific, West Africa and Gulf of Mexico

Note: Hyperbaric diving and welding capabilities. ROV and ROT operations. Dolly base arrangement for 4 reels on deck and additional area for 2 reels to be loaded at sea. ■ 19.3 km capacity for 6in pipe, ■ 15.2 km for 8in and ■ 8.6 km for 10in


ƒ Diving support vessel ƒ Pipelay facilities

Type of Vessel: Dimensions: Range of Pipe Diameters Handled: Welding Method(s) Used: Pipe Installation Method(s) Used: Minimum Pipelaying Water Depth: Maximum Pipelaying Water Depth: Mooring Station Keeping Method: Area(s) of Operation:

DSV 85 x 14 m (278 x 47 ft) 3.5 to 4.5 in API 1104 Reel, S-Lay 9 m (30 ft) 305 m (1 000 ft) DP Gulf of Mexico

Offshore pipeline construction



ƒ Construction vessel ƒ Diving facilities

Type of Vessel: Dimensions: Mooring Stations Keeping System: Lifting Capacity: Area(s) of Operation:

DP MSV, Semi-submersible 63 x 49 x 12/9 m (208 x 160 x 41/30 ft) DP 227 t (250 short tons) North Sea

Note: Deck cargo capacity: Clear deck:

544 t (600 short tons) 1200 m² (12 900 ft²)

Diving and ROV operations



ƒ Pipelay/construction vessel ƒ Diving facilities

Type of Vessel: Dimensions: Range of Pipe Diameters Handled: Welding Method(s) Used: Pipe Installation Method(s) Used: Minimum Pipelaying Water Depth: Maximum Pipelaying Water Depth: Mooring Station Keeping Method: Area(s) of Operation: Note: Pontoons are 77 m (254 ft) long.

Semisubmersible 49 x 48 m (160 x 158 ft) 2 to 4.5 in reel; 6 to 10 in., J-Lay API 1104 Reel, J-Lay 61 m (200 ft) Reel; 213 m (700 ft) J-Lay 610 m (2 000 ft) Reel; 1372 m (4 500 ft) J-Lay DP Gulf of Mexico

Offshore pipeline construction



ƒ This section has covered ƒ Three main types of diving ƒ Surface diving, saturation, hard suit

ƒ Basics of depth limitation and gas mix needs ƒ Minimising the risks ƒ Equipment used for diving

Any questions?

This section has examined the three main types of diving and has covered the basic reasons for limitations of depth and the gas mix needs of each method. The risks of each method have also been discussed and methods of minimising these risks described. These include the use of dive companions, ROV monitoring, hyperbaric lifeboats and the prevention of hypothermia. Some of the equipment required for diver support have also been discussed.

Diving and ROV operations




Subsea 7 Eyeball and Hercules ROVs

The above shows an eyeball and workclass ROV in Subsea 7’s workshop in Aberdeen. To the left, a white tethered management system (TMS) may be seen. The Eagle-eye has a 2000 m depth rating and is deployed from a garage. It can have a tooling skid fitted beneath. The Hercules has a depth rating from 1000 m to 3000 m and weighs between 2.8 T and 3.5 T (depending on buoyancy configuration).

Offshore pipeline construction


HOW ARE ROVS USED? A-frames or moonpool

In shallow water, use a direct umbilical Workclass or eyeball ROV

Strong umbilicals supplying control, power and support

Sea current

Heavy equipment & tools lowered from surface

Lightweight tether

‘Cursor’ launch system Tether management system (TMS) or ‘Top Hat’

Workclass ROV carries tool pack or equipment slung beneath Steerable garage unit with thrusters

Secondary eyeball ROV

The figure shows different procedures for operating ROVs, two of which are specifically designed for deepwater applications. When operating in deepwater environments, one of the main concerns is the time taken to lower the ROV to the seabed (this can be several hours). As the ROV requires a power supply cable there is a problem in that the umbilicals become both heavy (due to their length and strength requirements) and are subjected to large loads due to sea currents. Two of the systems utilise a powered unit with separate thrusters to carry the workclass ROV down to the work site. This unit can be sized to withstand the loads from the main umbilical. When in position, it then releases the ROV on a lightweight umbilical or tether. This is normally up to a few hundred metres long, but can be made up to 1 km (3280 ft). The figure shows two different methods of deepwater ROV installation. One involves lowering the ROV in a steerable garage. Any heavy equipment or selections of tooling can then be lowered to the seabed on a separate frame. This method may also include a secondary eyeball class ROV slung beneath, which can be used to oversee the operations of the workclass ROV or other tasks. The second method involves lowering the ROV on a device known as a TMS (tether management system) or Top Hat which releases the ROV at the worksite. The ROV in this case grasps a separate tool unit beneath. This may be a trencher, burial device, flowline connection module, suction anchor installation, mining or military. Launch using a ‘Cursor’ enables the almost neutrally buoyant ROV to be pushed safely through the surface zone (where the thrusters have difficulty operating) into the deeper water beneath the vessel. The cursor can run down a set of rails or wires, and it holds the TMS or garage. Typically, workclass ROVs locate themselves by the left arm grasper, and manipulate using the right arm. Where following a pipeline, the ROV may fly above the route, run on tracks or grip the line using wheels.

Diving and ROV operations



$70 000

Video inspections

ƒ Offshore observation

$150 000

Survey, diver and drill support


ƒ Work class

$2 000 000 Survey, drill support, construction and interception (Hire $1800 to $2700 per day)

ƒ Specials: $3 000 000 Tracked / free eg cable burial swim or skids The typical purchase costs given above are for the ROV alone and do not include launch recovery system or topsides support containers etc. The special ROV class may be much more than indicated - depending upon the purpose needed. As can be seen, the cost of the work class and special ROVs are an order of magnitude greater than the inshore and offshore eyeball/observation class. In many cases, hire costs will be incorporated within those of the vessel and launch system. Typical hire costs for the work class ROV shown above are for the unit alone – excluding support staff.

Offshore pipeline construction



ƒ Hydrovision ƒ Offshore Hyball ƒ 300 m (1000ft) water depth ƒ Simple grasper ƒ 0.15 to 0.25 m/s (0.3 to 0.5 knot) current

ƒ Seaeye Falcon ƒ ƒ ƒ ƒ

300 m (1000 ft) water depth 2.5 kVA 50 kg (110 lb) weight 490 N (110 lbf) thrust

Two of Hydrovision’s standard observation class ROVs.


ƒ The Sea Owl 500 Mk IV ROV System ƒ General purpose shallow water operations ƒ Can be configured with TMS for offshore application

With a weight in the air of approximately 100 kg (220 lb), and a 12 kg (26 lb) payload, the Sea Twin and Sea Owl can operate in depths up to 500 m (1640 ft). The ROVs incorporate an internal colour close circuit digital camera, external camera and scanning sonar, and are available with launching cage and main lift winch.

Diving and ROV operations



ƒ ƒ ƒ ƒ

Hydrovision Venom Construction, Intervention & Survey 3000 m (10 000ft) water depth Track, skid or free-fly options

Hydrovision standard workclass ROV shown here can be adapted to various tasks including burial/de-burial of telecommunications and power cables in soils to 100 kPa (14 lbf/in²) to 1 m (3 ft) depth, by the addition of skid tools.

WORK CLASS ƒ Perry Slingsby MRV® workclass ROV ƒ Work packages up to 5000 kg (11kip), in addition to own weight ƒ Can work to depths over 4000 m (13 100ft) ƒ Can be operated with or without a TMS (shown here) The MRV® workclass ROV is based around a core vehicle, to which options are added to satisfy specific task requirements without redesign. MRV® will accommodate work packages up to 5 000 kg (11 000 lb), in addition to its own weight, and can work to depths in excess of 4 000 m (13 100 ft).

Offshore pipeline construction


MRV® can be operated with or without a Tether Management System (TMS), which allows the operator further flexibility for different operations. Changeover is easily facilitated as termination components allow for rapid installation and removal of the TMS.


ƒ Flies 0.3 m to 0.5 m (1ft to 18in) above pipeline (or tracks along on wheels) ƒ Extra pipeline survey equipment ƒ Use of third-party ROV

The example shown here from Fugro shows the typical attachments to the front of the ROV to enable additional survey equipment to be fitted. Survey companies often have to make use of a third-party ROV that is chartered with the vessel by the client. They therefore have to fit their equipment to a variety of ROVs from different manufacturers.

Diving and ROV operations



ƒ Equipment attached to workclass ROV ƒ ƒ ƒ ƒ

Obstacle avoidance system sidescan sonar CP protection probe tester Depth meter, gyrocompass and position fixing ROV location device ƒ Constant acoustic positioning with vessel

ƒ Pipeline location device ƒ ƒ ƒ ƒ

‘Flying’ ROV - thrusters keep pipeline clear of sediment Trolley unit grabs pipeline and travels along Tracked unit on seabed Electromagnetic detection of buried pipeline potential

When a workclass ROV is fitted out for surveys, a range of different sonar and electromagnetic devices are used. The above list provides a typical selection. Some means of controlling the route of the ROV in relation to the pipeline are required. For a flying ROV (0.3 to 0.5 m above pipe), a combination of up and down thrusters can keep the water clear of sediments helping the pilot to visually maintain the ROV position close to the pipe. Some use a trolley unit to grasp the pipeline between bogies or wheels: the ROV is then driven forward on these. Where the ROV has caterpillar tracks perhaps for a buried line, then the steel of the pipeline can be detected using electromagnetic devices.

Offshore pipeline construction




Many ROVs use Alstom manipulator arms. The unit on the right of the screen is used for grasping. It is the Conan Remote Manipulator System and has a claw like hand. It would be controlled by a simple joystick in the control cabin. The unit on the left of the screen is used to pick up items. It is the Titan 3 Remote Manipulator System and the hand is designed to pick up T-bar handles on tools. The centre photographs show a typical joystick and a more delicate replica master slave arm. These have an intuitive operation - in the same manner as a computer mouse. However the system is more expensive than the simpler single-speed operation controls.

Diving and ROV operations


REMOTE TOOLING SKIDS Diverless connection systems Pipeline repair Component replacement Pig launcher / receivers Remote manifold valve operation Remote well fluid sampling ƒ Tool deployment

ƒ ƒ ƒ ƒ ƒ ƒ

API standard low torque tools with ROV T grab handles

Typical uses for remote tooling are given above. Some of these are shown in more detail in the following slides. Where operation of third party equipment is foreseen, the connectors are generally built to remote tooling standards API 17D & 17H (depending on field location in the world). Some low torque tools are shown here with T bar attachments to permit the manipulators to hold them. Higher torque tools are similar but more robust. Specialist ROVs


ƒ Pigging unit assembled with ROV in basket ƒ Pig launcher unit

Pig launcher unit

Pig launcher unit on ROV

Offshore pipeline construction


The workclass ROV connects up to the launch unit which is lowered separately to the seabed in a basket. This is because the weight of the launcher is greater than can be lifted in with the ROV. In the photograph, they are shown connected up sitting in the basket but with the hinged handle inclined forward out of the way to enable the ROV to dock. The pig launcher is sat on a saddle type frame which is bolted into the lowering basket. This combination weighs approximately 7 T in air.


ƒ Phoenix connector during shop trials ƒ DMaC connector system

DMaC connector

Phoenix connector

These are two systems used to connect flowlines. Note the buoyancy fitted to the flanges on the Phoenix. Both are shown slung beneath the ROV during trials.

Diving and ROV operations



ƒ Spoolpiece make-up ƒ Skid units ƒ Sonsub-Saipem connection system

These tool units are docked beneath the ROV and the flanges of the pipeline are mated together.


ƒ Sonsub-Saipem ƒ Bluestream wet buckle repair system

Diamond cutter unit

This cutter can be used to repair a wet buckle at depths of up to 2200 m. It was developed for use on the Bluestream Project in the Black Sea, but fortunately was not needed. The intention was to cut the pipe below the buckle and insert a recovery head. The evacuated pipe would then be brought back to the surface and J-lay continued.

Offshore pipeline construction



ƒ Drill support ƒ Now few divers do this ƒ Recovery of plug in well ƒ Choke replacement

ƒ Tubular inspection work ƒ ƒ ƒ ƒ ƒ

Sticky feet to hold on location Suction pad Rotary wire/nylon brush to remove marine growth Ultrasonic testing for thickness Visual inspection of concrete

Other bespoke specialist units will be designed for IRM (inspection, repair and maintenance) of subsea equipment, drill support or platform tubulars or risers. Installation of can anchors for pipeline start-up is usually accomplished by ROV. Note that ROVs are the method of choice for drill support. The drilling units are specifically designed with ROV in mind. They can perform many planned operation, maintenance and emergency tasks. Typical attachments used in platform inspection and maintenance are listed above.


ƒ Sonsub-Saipem ƒ Beluga trencher

Diving and ROV operations


This purpose built ROV can operate at a depth of up to 2200 m. Unlike the other systems, which connect a standard workclass tractor unit to a skid, this huge ROV is a fully dedicated system. It was used on the Bluestream project. It can attach itself to a pipeline with an incline of up to 30°. It flies down to pipe and then grasps onto it, protecting the line against the cutter drums. Multiple passes with the cutters in different orientations means that it can lower the pipe in stages.


The above slide shows the sequence of trenching a pipeline using the Beluga ROV trenching cutter. Initially the ROV attaches to the pipeline, it then makes a first pass cutting a narrow small groove. The second pass widens and deepens the trench and the final pass cuts the trench deep enough for the pipe and the pipe is released at the end of the trench route.

Offshore pipeline construction



ƒ ƒ ƒ ƒ

Bolted aluminium frame Thrusters - electrical or electro-hydraulic Control system - sealed dry electronic pods Buoyancy - designed neutral in water ƒ Less efficient with depth

ƒ Tooling - Class 1 to 7 (torque dependent) ƒ API 17D - ISO 13628-6 ƒ W Africa, GoM, Far East

ƒ API 17H - ISO 13628-8 ƒ North Sea

Most ROVs have an open-sided bolted aluminium frame which is easier to repair than welded. The open frame permits some passage of water and gives easy access to service the equipment on deck. The frame is typically designed with a dynamic factor of 3 or 4 to permit impacts during launch and recovery. The thrusters are either direct electrical or through an electro-hydraulic power pack. A typical workclass ROV will demand around 90 to 110 kW (120 to 150 shaft HP). The thrusters provide full control in all directions. Typically these will be located at the corners and operate in a diagonal direction. There may be between four and twelve of these units. The controlling software operated by the pilot at the surface, integrates the thruster components to permit logical movement of the ROV (up-down, forwardreverse and port-starboard). The control system for a typical workclass ROV will have one or two banks of 12 station solenoid valve packs and a single main electronics pod with extra task-specific pods. Buoyancy is located above the frame and usually consists of syntactic foam. This is surprisingly heavy in air. In deeper waters, the efficiency of this foam is less due to the requirement for increased resistance to crushing. Consequently, a larger volume of buoyancy is needed for deep water operation. The typical weight in air of a workclass ROV with buoyancy fitted is around 3 tonnes. This rises by about 25% if it needs to go to 3000 m depth. Two standards are used for tools: API 17D and 17H. These are also referred to as ISO 1328-6 or ISO 1328-8, respectively being dual standards. The latter is commonplace in the North Sea though elsewhere the earlier standard predominates. Some tools are common to both. A range of different classes are recognised (from 1 to 7) depending on the torque requirements.

Diving and ROV operations



ƒ ROV typically rebuilt 3 times in life ƒ Maintained after operations ƒ Frequent mob/demob ƒ (or dedicated vessel)

ƒ Down time following maintenance ƒ Requires ƒ Care in rebuilds/maintenance ƒ Standardisation of units ƒ Training

ROVs are typically totally rebuilt three or more times throughout their life. They are also maintained after operations. Where they are used on different vessels rather than kept onboard a dedicated ship, there are frequent connection / disconnection of cables for power and control during the mobilisation / demobilisation. All these contribute to the risk of down time. Most failures occur during the first few hours of operation due to adjustments, swap outs or changes made since the last usage. To avoid these failures, care and checking needs to be undertaken during repair or maintenance. It is preferable that units are standardised throughout the fleet to enable a control cabin from one unit to have identical plug-in to those of other units. Pilots can easily transfer their skills during operations. The risk of down time can thus be minimised by thorough training both of operators and mechanics.

Offshore pipeline construction



ƒ Sonar, gyrocompass and bathymeter ƒ Lights and cameras ƒ Survey or span identification ƒ Forward, port & starboard - pan & tilt arms

ƒ SIT low light ƒ HD colour ƒ Photogrammetric 3D video

ƒ 1 or 2 manipulators

Kraft TeleRobotics Predator-7 seven points of rotation

ƒ 3, 7 or 9 function graspers

ƒ Flexible mounts The ROV operator or pilot needs to be aware of its location and depth. Sonar, gyrocompass and depth indicators provide this general navigation. Workclass ROVs usually have some degree of autoheading and depth control built in to help the pilot. However, most ROVs depend on vision to permit fine control adjacent to subsea equipment. This requires a bank of lights and cameras. The type of camera depends on the usage. Low light level cameras (outputting black and white images) or full high definition colour cameras may be fitted. For specialist use, a pair of cameras may be used to capture full 3D images on the video system. Often, more than one camera is fitted: for example, for survey or span identification, three cameras will capture both sides of the pipeline and the forward view. Most ROVs have a pair of manipulators. These may have between 3 and 9 functions corresponding to the movements of the hand, wrist, elbow and shoulder of the operator. In general, the left hand will be simpler and used for grasping onto handles fitted to the seabed system. The right hand will be able to carry out more delicate tasks. Most manipulators fitted to ROVs have no control of speed. They open or close at the same rate. However, some (more expensive) have a master-slave arm at the surface which can be use for sensitive tasks. Tools are held by the manipulators using T-shaped handles fixed to flexible mounts. The latter have been developed from wind surfer mast attachments. These are available in a variety of resiliences: sometimes a single mount is used - or a pair of steel plates can be fixed between four bobbin-shaped mounts.

Diving and ROV operations



ƒ Hydraulic power supply ƒ Separate from ROV itself

ƒ Wet-mateable hydraulic connectors ƒ ƒ ƒ ƒ ƒ ƒ

No oil loss No water ingress Pressure balanced ±10° capture angle 200 bar (3 000 psi) MP rating Typically 0.3 m (1 ft) high

The tooling skids require separate hydraulic power from that supplied to the ROV itself. Some skids are lowered separately to the seabed in a basket for subsequent connection to the ROV. Some considerations for the connectors are listed above.


API 17D Class 4 tool

XYZ hot stab tool

Flexible pipe connector unit

The above slide shows three types of skid unit that may be linked to a workclass ROV.

Offshore pipeline construction


The XYZ tool connects to the front of the ROV rather than slung beneath. It can be used to operate a bank of valves or, as shown here, to pressure test/ inject a bank of nozzles.


ƒ API 17H tooling

Grab tool


Torque tool

This slide shows a stab plate for a fly to place umbilical connection. The proposed standard API 17H (used in North Sea), has complex tooling but light hardware. It can be lightweight because the ROV is docked in - resulting in no ROV loads on the system. The male is on the fixed structure: the female is on the ROV tool. In comparison API 17D is a light simple tool but requires heavy hardware. The third system is the DMaC, which is used in West of Shetlands by BP.

Diving and ROV operations


Deck equipment


ƒ Typical requirements ƒ ƒ ƒ ƒ ƒ

Control cabin container Workshop Store Independent power generators A-frame launch system

The ROV power is supplied through the umbilical at 3 kV. This power may be generated independently from the ship supply which is usually at 440 V. Transformer conversion is required. The reason that it is sent at high voltage is to reduce the diameter of the umbilical. Large specialist ROVs such as the NamSSol underwater mining machine require 2 MW at 3 kV. Trenching machines also have heavy power demands. In contrast, small eyeball ROVs may only require 1 or 2 kW of power for lights and thrust.

Offshore pipeline construction



ƒ ƒ ƒ ƒ

Outboard crane A-frame Moonpool Cursor

Outboard crane


Cursor wire guide

Cursor rail guide

These systems are needed to push the ROVs beyond the sea/air interface, and allow the thrusters to operate without cavitation. The simplest is an overside crane. Cranes and A-frame launch systems shown here are non-guided. They are very weather dependent but A-frames are probably the commonest launch method because they can be fixed to the side of any vessel. They can operate up to about sea-state 6. This is dependent upon the response of the vessel and snatch loading in the wire, surge and wave motion which could cause swinging. Dedicated ROV support vessels and offshore drilling vessels have customised launch systems. It is common nowadays to include a ROV as part of the standard equipment list. Launch through moon pools can be cursor, rail or wire guided to enable launch and recovery in any sea state. Semi-submersibles tend to use a wire or rail guided system to prevent impact with the vessel below the water line. Wire guided systems can rapidly launch up to sea-state 8.

Diving and ROV operations



ƒ Hydrovision launch system and garage

This is the simplest launch system whereby the hydraulic arm simply pushes the garage through the sea/air interface. It is used for the Hydrovision Seaeye Tiger observation class ROV.


ƒ Tether management system (TMS)

The umbilical provides power, fibre optic data and video communications back to the control cabin. The TMS is suspended from the vessel on an armoured cable but the unit has some degree of control by using its own thrusters. This enables it to stay close to the work site even in strong currents.

Offshore pipeline construction


The ROV is latched to the bottom of the Top Hat or TMS during launch and recovery. The ROV is connected to the TMS using a neutrally-buoyant tether up to 1000 m long but which is stored on the drum during launch. The pilot controls the TMS as well as the ROV. The main umbilical is either Kevlar or wire armoured. Kevlar is not as robust and is much more expensive, but has a better strength-weight ratio so is used in deeper water. A typical triple wire armoured cable used to lower a TMS and a ROV (such as the Hercules) will be around 43 mm diameter, 3300 m long with a 920 kN breaking strain (27 T SWL). Over around 3 km water depth, such cables cannot support their own weight. They weigh 6.36 kg/m in air or 5.08 kg/m in water and have a minimum bend radius of 700 mm.


ƒ Pilot on left ƒ ƒ ƒ ƒ ƒ

Integrated ROV and TMS/garage controls Joysticks and primary control buttons Video switching and distribution systems CCTV monitors & VCRs Software control and diagnostics screens

ƒ Log-keeper on right ƒ Second eyeball pilot ƒ Similar controls to ROV

The picture shows the pilot and co-pilot in one of Oceaneering’s five training centres. The ROV pilot controls both the ROV and the TMS or garage using joysticks and primary control buttons and switches. The co-pilot keeps a log, recording relevant pressure levels on equipment or other data from onscreen readings. If there is a second eyeball ROV operator, then he tends to sit to the right again, and he has similar joystick controls to the main panel.

Diving and ROV operations



ƒ Typical control panel ƒ Screen displays for ƒ Control ƒ Diagnostics

These are typical views of Subsea 7 pilot control system showing the joystick and main panel. Just visible above are the video screens. Market


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Subsea 7 Oceaneering International Perry Slingsby Systems Racal Sonsub Stolt Offshore

Fleet 55 113 57 37 41 70

The above is a list of the main operators (those with 30 or more) of Workclass ROVs. All of the above are also suppliers of ROVs. There are 45 operators in total, giving a world fleet of 476 ROVs. (Source: Offshore Magazine 2000/2001 Workclass ROV survey.)

Offshore pipeline construction



ƒ Construction - two approaches ƒ Bought-in ƒ In-house construction & maintenance

ƒ Survey houses ƒ Own equipment ƒ Use what client has on vessel ƒ Mount their own survey units onto vessel ROV

Companies may either buy their ROVs from a specialist manufacturer or build and service their own design of machine. The costs are much larger for the latter in setting up the design team and workshop. However. bearing in mind downtime following maintenance, this may be still be costeffective for larger companies. Survey houses generally own their own equipment but may be obliged to use the ROV that is already part of the vessel chartered by the client. In this instance, their own seismic, pipe location equipment etc is mounted onto the ‘tractor’ unit.


ƒ This section has detailed the following ƒ The four main types of ROV ƒ ƒ ƒ ƒ

Observation Workclass Survey Specialist

ƒ The required deck support equipment ƒ Power supply ƒ Control systems ƒ Launch and recover systems

Any questions?

Diving and ROV operations


This section has introduced the main considerations for the use of ROVs, identifying the different types of ROV and the tooling systems available. It also gives details of the typical deck support equipment required to conduct ROV operations.


ƒ Capabilities of divers ƒ Required support equipment

ƒ Various types of ROV available ƒ Required support equipment, available tooling and operational capabilities

ƒ Different ROV launch and recovery systems ƒ ROV market and availability Any questions?

The operations of diving and remote operated vehicles (ROVs) were introduced. Diving operations and their capabilities and limitations were examined, along with the health and safety requirements and support equipment required for safe diving operations. The issues of ROV operation were presented. Information was provided on the various types of ROV available and the different operational capabilities, support equipment and available tooling. The different methods of launching and recovering ROVs from vessels were examined. Finally, an overview was given for the ROV market, detailing the leading companies and the different options available to companies looking to make use of ROV systems.


Offshore pipeline construction






ƒ Know the principal factors that influence the available method of decommissioning ƒ Understand the latest legislation and current thinking ƒ Know the operations required for decommissioning pipelines in-situ ƒ Know the methods available for the recovery of pipeline systems ƒ Appreciate the potential for re-using certain pipeline systems An overview is given of the processes for decommissioning pipelines and other offshore components. The principal factors that influence the methods of decommissioning are identified; these being environmental and safety concerns, public opinion, political needs and finally cost effectiveness. The latest legislation and current thinking regarding the correct decommissioning strategy is discussed. Decommissioning of pipelines in-situ is examined in detail and the required operations are detailed. Also, the methods available for the possible recovery or re-use of certain pipeline systems is discussed.

Offshore pipeline construction




ƒ Understand the purpose of decommissioning ƒ Be aware of existing legislation regarding pipelines and structures ƒ Review methods and equipment ƒ Consider alternate methods of recovery ƒ Review the feasibility of re-use

This section on decommissioning looks at the various reasons for, and alternative methods of, making redundant sub-sea piping safe. The process of preparation for decommissioning in-situ is studied, as well as the alternative of recovery for re-use. The methods and equipment employed during decommissioning are considered.




ƒ Why decommission? ƒ Increasingly environmentallyconscious world ƒ Pollutants and toxins ƒ Effects of seabed debris ƒ Congestion of seabed

At the end of the operational life of a pipeline, there is a need to address the future condition and status of the pipeline, so that it never presents a risk of pollution or interference with the activities of other users of the sea. The above picture shows 12 shore-end pipe connections exposed at low tide, at the Thorness Bay SOLO pipeline terminal on the Isle of Wight. They have survived over half a century of battering by the sea.


ƒ Environment ƒ Look for environmental benefits ƒ Least-impact option ƒ Assess environment hazards and injury to personnel

ƒ ‘Sterilisation’ of seabed for future pipelines ƒ Return shoreline to original

ƒ Safety ƒ Safety – nuisance on seabed ƒ Snagging of trawler nets

Shell Brent Spar

ƒ If cannot present a good safety case – leave as is! ƒ Consider all risks during removal and disposal

The decision as to whether the pipeline is abandoned in-situ or recovered to land for disposal or recycling, is influenced by the above issues. The considerations include:

Offshore pipeline construction


Environmental ■ Would the removal represent a benefit to the environment or would resources required be better spent in other directions? It is common for coastal and local authorities to demand the removal of lines at the landfall, allowing the sea to erode beaches and cliffs naturally (for decades to come). ■ Contamination from unclean lines. ■ Determine best possible environmental option. Greenpeace demonstrated about the decommissioning of the Shell Brent Spar. Finally, they admitted the original solution would have been a net cleaner option Safety ■ Hazards relating to subsea pipelines. ■ Snagging of trawl equipment. ■ Nuisance to future seabed construction.


ƒ Political need ƒ International guidelines and common approach ƒ Installation reviewed for best solution

ƒ Public opinion ƒ Pressure groups ƒ Media sensationalism ƒ Local politicians

ƒ Exxon Valdez, Alaska ƒ Erica and Prestige, Biscay and Spain ƒ Fishing and tourism Prestige

Political Need/Public Opinion ■ Legislation and guidelines. ■ Each installation to be viewed on its own merits. ■ Operators being persuaded to take action. ■ Public now more aware of issues. However, pressure groups do not always reach a considered opinion (for example, the Brent Spar situation). They are sometimes heavily influenced by the press or local politicians. It was right that huge amounts of money were spent cleaning up long lengths of the formerly pristine Alaskan coastline following the leaks from the Valdez in 1988. The sinking of the tankers Erica and Prestige in the Atlantic off south-western Europe in 1999 and 2002 caused an outrage. Local holiday and fishing industries had just recovered from the first incident when the Prestige sank with some of her cargo remaining sealed on board. Though there was no financial gain to be made for heavy oil remaining in the tanks, public outcry demanded that it be recovered from a depth of 3800 m (12 500ft) to prevent it gradually seeping for decades to come. It is unclear how much of a threat this might have been, given the viscosity of the heavy oil and the low rate of corrosion at that



depth. The fuel had to be pumped out of holes drilled into the hold through a 150 mm (6in) hose.


ƒ Benefits and cost-effectiveness ƒ Sale of recovered materials is negligible ƒ Hazard has been removed with any liability

ƒ Minimum maintenance on empty line ƒ Can accountants delay for another fiscal year? ƒ Sell on the facility? ƒ Was money left in budget (or included in sale)?

ƒ Reuse for another field or for CO2 disposal ƒ Have they sold the liability with facility ƒ Sale of platforms to wind generator companies ƒ Trunk pipelines used for power lines

Benefits and Cost Effectiveness ■ Total removal of a hazard. ■ Eliminates future monitoring. ■ Sale of recycled materials generates little income. ■ Have the operators budgeted for pipeline removal? It is in the interests of the company to delay removal of facilities. They can undertake minimum survey and maintenance for a number of years whilst the line is empty. Perhaps it is possible to find a new use for the pipeline. Perhaps further smaller fields can be discovered and developed. Or we may find in the future that carbon dioxide can be disposed of in reservoirs, gaining carbon credits. One important aspect to note is whether the current owner of the subsea facilities has a budget to de-commission them. It is now common for the original owner to have sold them on to smaller oil companies. Problems may arise in the future should these small companies go into liquidation with no assets for removal. Proposals have been made to sell platforms to wind generation companies. pipelines provide a conduit for power lines to shore.


Offshore pipeline construction



ƒ Leave pipeline on seabed ƒ Bury pipeline below seabed ƒ Recover pipeline to shore ƒ In all options ƒ End structures (manifolds, drilling centres) should be removed ƒ Pipelines left on seabed or buried below the seabed should be cleaned, sealed and water filled

These are the decommissioning options that are addressed later in this section.





ƒ Geneva Convention on the Continental Shelf 1958 ƒ UN Convention on the Law of the Sea 1982 ƒ IMO Guidelines 1989 ƒ Oslo Convention 1972 ƒ London Dumping Convention 1972 ƒ Oslo Commission Guidelines 1991 ƒ OSPAR Convention 1992 ƒ USA not a signatory – use of own legislation

There are a plethora of conventions relating in some way to the removal of installations from the seabed. Most of them have been aimed at shaping what should happen to structures and platforms when decommissioned. By comparison, pipelines have received far less attention. As yet, the United States of America is not a signatory to OSPAR. It applies its own legislation – which has similar aims.

Offshore pipeline construction



ƒ OSPAR (Oslo-Paris) convention ministerial meeting in Sintra, Portugal, July 1999 ƒ Pipelines case-by-case

ƒ In practice we find: ƒ Driven by political expediency ƒ Not science or logic

ƒ Most decommissioned rigid lines left insitu ƒ Many removed in Norway and Gulf of Mexico

ƒ Most flexibles removed and re-used ƒ Spares stored in Brazil and new ends fitted for reuse ƒ Practice proscribed in Australia

The recent OSPAR meeting decreed that pipelines should be dealt with on a case-bycase basis, with reference to minimising the damage to the environment. To date, most rigid lines have been decommissioned by leaving them in place. A number of pipelines have been removed in Norway and Gulf of Mexico. Most flexibles have been removed and re-used, particularly in Brazil where many spare lines are stored underwater in a sheltered bay. However, in Australia, such reuse is deemed to be too high a risk.


ƒ Platforms ƒ Structures under 10 000 tonnes removed ƒ Remaining 34 structures case-by-case ƒ 112 000 tonne Maureen removed 2001 ƒ Gravity structure with base storage tanks ƒ Refloated and towed to fjord ƒ No buyer found



The OSPAR meeting agreed that the smaller platforms should be removed, and that larger structures should be evaluated. In 2001, the 112 000 tonne Maureen gravity platform with a height of 241 m (790ft) was refloated and towed to a Norwegian fjord for disposal. Originally, it was hoped to resell the unit intact, but there were no buyers.


ƒ Legislation set out in DTI Guidance Notes ƒ Based on The Petroleum Act 1998 ƒ Converts convention into good practice

ƒ Gives guidance on pipelines ƒ Approach to be taken ƒ Consider all options and effects ƒ Future consequences of corrosion

ƒ Lines that can be left in place ƒ Buried and long trunk lines

ƒ Lines that should be removed ƒ Small diameter and untrenched lines

ƒ Monitoring ƒ Unlimited time period !

The current status of legislation is set out in DTI Guidance Notes based on The Petroleum Act 1998, and covers the areas shown above. Approach to be taken: ■ Based on individual circumstances. ■ All feasible options to be considered. ■ Removal to have no effect on environment. ■ If left in place (decommissioned in-situ), decision based on rate of deterioration and possible future effect on marine environment. ■ Consider other users of the sea. Lines can be left in place: ■ If adequately trenched. ■ If likely to self-bury. ■ If exposed sections retrenched. ■ If trunk lines. Lines that should be removed: ■ Small diameter of up to 323.8 mm (
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