Decommissioning and abandonment

Decommissioning and abandonment

Subsea engineering and training experts

Enhanced reference notes

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Decommissioning and abandonment

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 2018 Notes created: October 2018

Table of Contents DECOMMISSIONING AND ABANDONMENT

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Expectation Introduction Legislation

7 8

13 21 22 24 25 28 35 39

Decommissioning in-situ

Cleaning

Product removal

Trenching

Recovery

Re-use Costs

ACRONYMS AND ABBREVIATIONS

45 59

ACKNOWLEDGEMENTS AND REFERENCES

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EXPECTATION

EXPECTATION

EXPECTATION

ƒ Pipeline decommissioning ƒ Principal factors influencing selection of method ƒ Legislation and current thinking ƒ Differences worldwide ƒ Options for a disused pipeline ƒ Operations for decommissioning and leaving in-situ ƒ Recovery of pipelines ƒ Potential for re-use ƒ Hazard/safety and financial costs ƒ Expected UKCS market from 2014 - 2019 ƒ £4,5 billion ($6 billion)

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 are discussed. An estimation is provided of the likely financial and safety costs and benefits for removal of pipelines. The estimated UKCS decommissioning market in the next 5 years will be about £4.5 billion ($6 billion) focusing on 40 platforms at their associated wells, pipelines and subsea structures across 80 fields. The estimate for similar operations in the Gulf of Mexico is £20 to £25 billion ($30 to $40 billion). The Brent decommissioning has been announced by Shell and is scheduled to start 2014/2015 for Brent Delta

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INTRODUCTION

INTRODUCTION

INTRODUCTION

ƒ Need to decommission ƒ Increasingly environmentally- conscious world ƒ Pollutants and toxins ƒ Effects of seabed debris ƒ Fishing and dredging interests ƒ Congestion of seabed ƒ Now a legal requirement ƒ Determine methodology for removal at design phase ƒ Involve stakeholders early on

ƒ Avoid ‘decide and defend’ approach

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. It is important that all stakeholders be involved early on. We must avoid making a decision and then trying to defend it. This can result in a huge increase in additional costs. The upper picture shows 12 shore-end pipe connections exposed at low tide, at the Thorness Bay SOLO pipeline terminal (part of the PLUTO pipeline system) on the Isle of Wight. They have survived over half a century of battering by the sea. The lower photograph shows the effect of a century of oil spillages that are currently being cleaned up in Baku, Azerbaijan on the shores of the Caspian Sea. The historical remediation work is a prerequisite condition for new abstraction concessions.

ENVIRONMENTALANDSAFETYINFLUENCES

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ENVIRONMENTAL AND SAFETY INFLUENCES 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 ƒ If cannot present a good safety case – leave as is! ƒ Consider all risks during removal and disposal Shell Brent Spar 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: 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 cleaner option overall Safety Hazards relating to subsea pipelines Snagging of trawl equipment Nuisance to future seabed construction

IMAGEANDPUBLICPERCEPTION

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IMAGE AND PUBLIC PERCEPTION

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 ƒ Macondo, GoM 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 (12 500 ft) 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 (6 in) bore hose. The Macondo blowout and explosion in the Gulf of Mexico in 2010 resulted in 11 people loosing their lives and considerable environmental pollution. The consequences of this disaster have had a major impact on deepwater operations in the GoM and elsewhere.

BENEFITSANDCOSTEFFECTIVENESS

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BENEFITS AND COST EFFECTIVENESS

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 Pipelines are ‘out-of-sight and out-of-mind’ of public ƒ Reuse for another field ƒ Reuse for CO 2 disposal ƒ International agreement reached February 2007 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 budgetted 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. An international agreement was reached in February 2007 on the use of hydrocarbon reservoirs for carbon sequestration. One benefit to us is the fact that offshore pipelines are hidden from view of the press and public. Providing they remain inert and safe, they can often be left on the seabed with little concern. This contrasts with the landfall and offshore jackets and other topside structures. 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. The pipelines provide a conduit for power lines to shore.

OPTIONS FORABANDONMENT,DECOMMISSIONINGANDREMOVAL

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OPTIONS FOR ABANDONMENT, DECOMMISSIONING AND REMOVAL ƒ Leave pipeline on seabed ƒ Bury pipeline below seabed ƒ Recover pipeline to shore ƒ In all options: ƒ Remove all end and crossings structures

ƒ Manifolds, SSIVs, wellheads, drilling templates and mattresses ƒ Make safe ƒ Clean, seal and water-fill all pipelines left on or buried beneath seabed

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

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LEGISLATION

CONVENTIONSONOFFSHORESTRUCTURESANDPIPELINES

CONVENTIONS ON OFFSHORE STRUCTURES AND PIPELINES ƒ International ƒ Geneva Convention on the Continental Shelf 1958 ƒ London Dumping Convention 1972 ƒ UN Convention on Law of the Sea (UNCLOS) 1982 ƒ International Maritime Organisation Guidelines 1989 ƒ IMO is part of UN – sets MARPOL, SOLAS and ISPS standards ƒ European ƒ Oslo Convention 1972 ƒ Oslo Commission Guidelines 1991 ƒ OSPAR (Oslo-Paris) Convention 1992 and 1998 ƒ USA ƒ Bureau of Ocean Energy Management (BOEM) ƒ Bureau of Safety and Environment Enforcement (BSEE) There is 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. In Europe (the European Union and signatory countries, together with Norway, Iceland and Switzerland), the OSPAR convention holds. The International Maritime Organisation is part of the United Nations and is headquartered in London. IMO sets international maritime standards, such as MARPOL (prevention of marine pollution), SOLAS (safety of life at sea) and ISPS (international ship and port security). These standards are not law but are binding for signatories, which includes all the major trading nations as well as many minor ones. The United States of America is not a signatory to OSPAR. The former MMS legislation – which has similar aims – is applicable under the auspices of the US Department of the Interior. BOEM, BSEE together with the US Department of Transportation (DOT) Research and Special Programs Administration Office of Pipeline Safety (RSPA/OPS) have jurisdiction in US waters.

OTHERNATIONALREGULATIONS

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OTHER NATIONAL REGULATIONS

ƒ Netherlands ƒ Mining Act 2002 and Mining Decree (Mijnbouwbesluit) ƒ Norway ƒ Petroleum Act 72 1996 ƒ UK ƒ Petroleum Act 1998

In addition to the OSPAR convention, other national regulations apply. Guidance from these national bodies further interprets the international agreements.

PRAGMATICAPPROACHTOPIPELINEDISPOSAL

PRAGMATIC APPROACH TO PIPELINE DISPOSAL ƒ Comparative assessment ƒ A balanced judgement

Technical Feasibility Complexity (variable burial depths)

Social Sea users Community Stakeholders

Environmental Energy usage Air Sea Land

Press and media

Economic Cost/benefit Uncertainty Legacy/liability

Safety Risk assessment (diving operations) Implementation

Operating company’s reputation

The BOEM, BSEE and DTI take a pragmatic approach to the requirements of the legislation. This makes a balanced judgement of all factors including the environmental, safety, cost and feasibility. The underlying criteria for any pipeline left on the seabed should involve its cleanliness, stability, burial and the interests of other users.

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Some aspects of pipeline removal may involve danger to the diving team charged with removal of equipment. For example, the lifting of mattresses may involve the use of hooks/ lifting lugs well outside their certification date. With the sandwaves in the southern North Sea and elsewhere, and the soft mud of the GoM, West Africa and Brazil, unburial equipment may no longer be able to reach the depth they are now covered to. The weight of soil and destruction of the seabed during removal operations effectively prevents removal. Finally, the operating company’s own reputation should be included. The press and other media can quickly distort the real picture – a case of ‘give a dog a bad name’ – particularly when dealing with the oil industry. EUROPEAN AND US APPROACHES ‘EVERYTHING TO BE REMOVED’ ƒ OSPAR July 1999 ƒ Signed at ministerial meeting in Sintra, Portugal ƒ Presumption of total removal ƒ Concentrates on offshore rigs and wellheads ƒ Larger structures may be ‘derogated’ ƒ Pipelines likely to be assessed case-by-case ƒ Flowlines probably removed along with wellheads ƒ Trunk lines left in place – except at shoreline ƒ BOEM/BSEE removal studies ƒ Same approach but slightly different interpretation ƒ All large lines ‘deemed to be an obstruction’ to be removed ƒ Some deepwater infield flowlines may be left (buried in mud) The OSPAR meeting decreed that the approach to be followed must minimise damage to the environment. The basis of the treaty is that everything will be removed apart from those items that are ‘derogated’ or exempted, after an impact and risk assessment study. Smaller platform structures must be removed. Larger structures may be partly demolished and removed, apart from sections that would be difficult or dangerous to take away. Pipelines may also be dealt with on a case-by-case basis. The UK DTI guidance means that it is expected that wellheads and associated flowlines will be removed, whilst the large diameter trunk lines to shore will be capped and left in a safe condition, apart from at the shoreline, where they will be removed. In the USA, the same basic assumption is used, in that everything should be removed. However, it is expected that BOEM/BSEE (Bureau of Ocean Energy Management / Bureau of Safety & Environment Enforcement) will allow small flowlines to be left buried in the mud, whereas the larger diameter trunk lines must all eventually be removed. The decision of the BOEM/BSEE Regional Supervisor will determine whether a line is an obstruction and thus require its removal, under code 30 CFR 250.1754. Other applicable regulations are 30 CFR 250.1750 to 1754 and 30 CFR 250.1006. The BOEM / BSEE grants a 61 m (200 ft) ROW corridor for trunk lines and their license requires removal within 1 year of cessation of use: nevertheless, there is a waiver granted in 95% of cases. Only pipelines that are an obstruction have been removed. EUROPEANANDUSAPPROACHES‘EVERYTHINGTOBEREMOVED’

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An BSEE (formally MMS) report examines the best options for this work: Report N° 32.701.001/R1 16 th September 2004, An assessment of safety, risks and costs associated with subsea pipeline disposals. See www.mms.gov/tarprojects/480/ScanPower%20Final%20Report.pdf and addenda.

ACTUALPRACTICEFORREMOVAL

ACTUAL PRACTICE FOR REMOVAL

ƒ Driven by political expediency ƒ Not science or logic ƒ Hydrocarbons still being found & recovered ƒ Possible future use for redundant pipelines ƒ Remain as a company asset ƒ Most disused rigid lines are still left in situ 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 disposal of pipeline assets is not necessarily logical, but instead is dependent upon politics. It might be foolish to remove lines when hydrocarbons are still being developed – and will continue to be until around 2030 or more. Future use could therefore be made of these lines. Therefore, to date, most rigid lines have been decommissioned by cleaning and leaving them in place. Nevertheless, 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.

UKDTIGUIDANCENOTES

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UK DTI GUIDANCE NOTES

ƒ Legislation set out in HSE 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 & Inspection ƒ Unlimited time period !

The current status of legislation is set out in HSE 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 (<12¾ in) Rigid lines and flexibles that are not trenched or buried Monitoring & Inspection : If decommissioned in-situ, monitoring and inspection programme to be established on case-by-case basis

CURRENTSTATUS FORPLATFORMS

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CURRENT STATUS FOR PLATFORMS

ƒ Platforms ƒ Structures under 10 000 tonnes removed ƒ Remaining 34 structures case-by-case – derogation? ƒ 112 000 tonne Maureen removed 2001 ƒ Gravity structure with base storage tanks ƒ Refloated and towed to fjord

ƒ No buyer found ƒ Now scrapped

The OSPAR meeting agreed that the smaller platforms should be removed, and that larger structures should be evaluated. In 2001, the 112 000 tonne (120 000 US ton) Maureen gravity platform with a height of 241 m (790 ft) was refloated and towed to a Norwegian fjord for disposal. Originally, it was hoped to resell the unit intact, but there were no buyers. It has been scrapped. There are currently plans to remove a number of steel jackets from the North Sea, whereas, for some of the early concrete structures this is extremely difficult and they are being left in place. Derogation is the partial revocation of a law.

ALLSEASPIONEERINGSPIRIT

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ALLSEAS PIONEERING SPIRIT

ƒ New build for 2014 ƒ 48 000 tonne topside ƒ 25 000 tonne jacket

ƒ S-lay capability ƒ Planned Work

ƒ Brent Delta in 2015/16

Allseas is constructing a new-build heavy lift vessel to remove topsides and jacket legs in two operations (as on right). It has been commissioned to meet the expected boom in North Sea decommissioning work. It may be thought of as a linked catamaran that can dock on either side of the platform. It is designed to handle topsides lifts up to 48 000 tonnef (105 000 kip) and jacket lifts over half this, operating in significant wave heights of 3 m (10 ft). The photograph is of a model showing the original concept of adapting a pair of tankers. The new-build has a strengthened central section which limits the transit speed to 11 knots (5.7 m/s). The slot and eight lifting beams are retained. The tilting beams are designed to accommodate any wind and wave movement. However, it can also accommodate a full curve S-lay stinger to lay pipe vertically. Its 1361 tonnef (3000 kip) tensioning capacity will far outstrip anything currently available in the global fleet. The 170 m (558 ft) stinger and seven welding stations will be able to lay up to 1524 mm (60 in) pipe. Vessel length by breadth: 477 m (1,565 ft) by 124 m (407 ft) Slot width by length: 559 m (194 ft) by 122 m (400 ft) Dynamic positioning: LR DP (AAA), fully redundant Kongsberg K-Pos DP-22 and 2 x cJoy system Other heavy lift vessels are available, such as Saipem’s S7000 and Heerema’s Thialf and Balder. They may be used in combination with submersible transport vessels such as the Mighty Servant 3.

LEGISLATIONSUMMARY

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LEGISLATION – SUMMARY

ƒ Governments provide legislation to give guidance on decommissioning ƒ Most structures assessed uniquely ƒ Not all equipment must be removed ƒ Decommission in-situ if no detrimental effects to environment ƒ May require monitoring program

Any questions?

Governments have introduced legislation to cover the decommissioning of offshore structures and subsea pipelines. The legislation gives guidance on considerations for decommissioning, but most substantial structures will be assessed individually for their unique requirements. We need to be aware that not all offshore equipment requires removing from the installed location. Decommissioning in-situ may be acceptable if no detrimental affect to the environment can be proven. To ensure this, a monitoring program may need to be implemented to ensure there is no long term damage to the environment.

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DECOMMISSIONING IN-SITU

DECOMMISSIONING /ABANDONMENT IN-SITU

DECOMMISSIONING / ABANDONMENT IN-SITU ƒ Cleaned, sealed and left in-situ ƒ Do not disturb! ƒ Leave in a safe state ƒ Likely to be the preferred option for: ƒ Pipelines that are already trenched/buried ƒ Trunk lines in North Sea ƒ It may involve the following operations ƒ Cleaning ƒ Product removal ƒ Trenching

Decommissioning or abandonment in-situ is the preferred option for pipelines that are already trenched or buried and North Sea trunk lines. The terms differ in UK and US with ‘abandonment’ being preferred in America. There is less disturbance of the seabed by this method, especially where the seabed takes many decades to repair itself. In the soft seabeds of the Gulf of Mexico, this is less of a concern. There are three main operations for decommissioning in-situ, these are cleaning, product removal and trenching. These operations do not necessarily have to occur in that order.

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Cleaning

CLEANING

CLEANING

ƒ Cleaning required to remove deposits from pipe wall ƒ Wax, gas dust, scale, asphaltenes ƒ Internal LSA (NORM) scale ƒ Cleaning by running through trains of pigs ƒ Trains consist of foam, batch, brush and scraper pigs as required ƒ Most likely done before water filling (avoid problems of contaminated water disposal) ƒ Pigging programme during last months of production Cleaning is required for the removal of wax, gas dust and scale from the pipe wall. These may contain heavy metals and other toxins. This operation is achieved by driving pig trains through the line. The pig trains will include brush pigs or scraper pigs. LSA (low specific activity) scale forms in well tubulars and contains a relatively low level of radioactivity per unit mass, which however, is in excess of the background level. LSA scale is a term used in Europe; elsewhere, it may be referred to as NORM (naturally-occurring radioactive materials) scale. Note that on older pipelines with external coal tar epoxy, there is sufficient radioactivity to be detected should the coating break off and float to shore.

BRUSHPIGS

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BRUSH PIGS

ƒ Removal of scale, rust, dust (gas) and wax

Brush pigs are used for removing scale, rust, dust and wax from the pipe wall. By-pass ports are used to produce flow in front of the pig. This flow helps prevent the build-up of debris or wax in-front of the pig. By-pass ports are typically threaded holes with plugs. The operator can therefore adjust how much by-pass occurs.

SCRAPERPIGS

SCRAPER PIGS

ƒ Polyurethane or steel blades or ploughs ƒ Wax removal ƒ Disposal of wax-loosening chemicals

Scraper pigs are used for the removal of heavy wax deposits from the pipe wall. If chemicals are used to loosen the wax first, then there must be tanks to separate and recover them for safe disposal.

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Product removal

PRODUCTREMOVAL

PRODUCT REMOVAL

ƒ Remaining product displaced by water ƒ Pig train provides separation

Water

Oily water

Oil

ƒ Batch pigs

ƒ Spaced 20 m to 30 m (60 ft to 100 ft) apart ƒ Depends on diameter ƒ Number depends on line length and wall corrosion

An essential step of decommissioning is to remove the product from the pipeline. This is achieved by driving the product out with water. A train of batch pigs provides the separation between the water and the product. The batch pigs are arranged such that they are pushed by water from behind, displacing the product ahead of them. They are spaced to allow for some mixing of the liquids: typically, this is a function of the diameter of the pipeline. The number of pigs in the train depends on how much will pass each of the seals – a function of the length of the pipeline and the pitting on the pipe wall.

INHIBITION

INHIBITION

ƒ Water contains high doses of ƒ Corrosion inhibitor ƒ Oxygen scavenger ƒ Biocide ƒ Pipe left in safe condition ƒ Minimise any further deterioration or rusting

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The water contains a number of inhibitors to ensure the continuing integrity of the pipeline for an indefinite period. Doses are much higher than would be expected for pre- commissioning, which lasts only a few weeks. Corrosion inhibitors and oxygen scavengers prevent aerobic and acidic corrosion. The biocide prevents the growth of sulphate-reducing bacteria (SRB), which in turn will produce anaerobic corrosion.

Trenching

TRENCHING

TRENCHING

ƒ Lower pipeline below surface of seabed ƒ Backfill ƒ Methods covered in detail elsewhere ƒ Why bury now when not at installation? ƒ Open trench ƒ Scour of seabed ƒ Is wall corroded? ƒ Reduced strength ƒ But no longer pressurised

ƒ Spalled concrete in nets ƒ Crossings at live pipelines

The pipe may need to be both lowered into a trench and then buried to leave a smooth seabed. This is as discussed in the other modules. However, we need to ask how it is possible to bury the pipeline now when it was not undertaken earlier during installation. Perhaps the pipe was only trenched and not buried or some scour has since occurred. What if there is corrosion of the wall and the steel strength is reduced.? It may not be a problem since it does not have to withstand operating pressure anymore. Will deteriorated concrete spall off and end up in fishermen’s nets? Also, where the pipeline crosses another live line, detailed analysis is required. Can the line be lowered sufficiently or is it necessary to cut the line?

TRENCHING ISSUES

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TRENCHING ISSUES

ƒ Remaining strength of pipeline ƒ Will it withstand trenching operation? ƒ Must avoid leakage – corrosion defects and welds ƒ No longer has high internal pressure ƒ Loss of concrete weight coating ƒ Especially at field joints ƒ Must avoid debris ƒ Loss of coal-tar epoxy ƒ Radioactivity ƒ Jetter arm/machine burial ƒ Lower stress than plough ƒ Slower in stiff clays

We need to assess how the pipeline will behave during the lowering process. Perhaps a less efficient option may be chosen, such as jetting. Ploughs may cause higher loads to be applied to the pipeline. Although coal-tar epoxy is not used nowadays for corrosion coating, there are many lines that used it historically. It may break off during the recovery of a corroded pipeline. Not only is coal-tar carcinogenic, but it contains natural radioactivity, which can cause concern should it be washed to shore.

DECOMMISSIONING IN-SITU SUMMARY

DECOMMISSIONING IN-SITU – SUMMARY

ƒ Preferred option for trunk lines and buried/ trenched pipelines ƒ Need to remove product and clean ƒ Exposed lines may require trenching ƒ Ensure pipe strength is sufficient to withstand trenching operation ƒ Avoid concrete break-up

Any questions?

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Decommissioning in-situ is often the preferred method for trunk lines and pipelines that are already buried or trenched. To decommission in-situ, it will be necessary to ensure that all product is removed from the pipeline and the pipeline interior cleaned of debris and harmful deposits. Cleaning can be done with specialist cleaning pigs and batches of cleaning chemicals during the final months of producing. The final removal of the product itself is done with pig trains, pushed through by water. There may be a requirement that the decommissioned pipeline is buried to ensure it does not become a future obstacle on the seabed. It may be necessary to ensure the strength of pipe is sufficient to withstand the trenching operation. Care should also be taken to ensure the concrete coating does not break-up and become debris on the seabed.

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RECOVERY

RECOVERY

RECOVERY

ƒ Recovery preferred option in UK for: ƒ Small diameter rigid and flexible lines that are not trenched or buried ƒ Up to 323.8 mm or even 406.4 mm (12¾ in or 16 in) ƒ Short flowlines rather than long, large diameter trunklines ƒ Bundles with integral towhead manifolds ƒ Recovery presumed in US for all lines ƒ BOEM / BSEE may permit derogation based on safety case ƒ In all cases certain lines must be removed: ƒ Contaminated pipelines (mercury or cadmium) ƒ Landfalls and inshore lines, subject to local authority control Smaller unburied lines are easiest to remove. Even 406.4 mm (16 in) lines (larger than required by legislation) may be disposed of in this way. It is becoming the policy to remove all the small diameter and short flowlines within fields, leaving the main length of large diameter, long trunk (export) lines in place. Bundles are large diameter structures that sit on the seabed. These are unburied and may be towed away on-bottom. However, the East Frigg bundle in Norway only had the manifold ends removed. Contaminated lines and the landfall section of other lines may require removal by the appropriate regulatory authorities. For example, the Dutch P15 lines recover oil with significant amounts of mercury. The developers were given permission on the understanding that all these lines – some 60 km (37 miles) of both flow and trunk lines – must be removed as the fields become depleted. At landfalls, there is often a local authority requirement for the beach section (only) to be removed. This prevents concerns regarding far-future (50 years plus) erosion of the shoreline and any protective cliffs or sand dunes.

RECOVERY

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RECOVERY

ƒ Recovery methods: ƒ Small diameter rigid or flexible flowlines – reel barge ƒ Thin walled downhole or flowline tubing – reeled ƒ Larger diameter pipelines – laybarge ƒ Pipeline and bundle recovery – cut and lift process or float and tow method ƒ Bundle recovery – off-bottom towing method

A number of different approaches have been used, as listed above. Where the wall and particularly the welds can withstand the stresses, small lines can be removed by reel barge. A simple laybarge can be used to dispose of larger diameters. An alternative used for larger lines in poor condition (unable to withstand stresses) is to cut into short sections and lift vertically. If buoyancy can be provided to bundles, then these could be towed to shore using an off- bottom method. This may be accomplished either with individual buoys or use of gel to flush the water from the annulus. A similar process may be used for pipelines.

RECOVERYBYREELBARGE

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RECOVERY BY REEL BARGE

ƒ Reverse lay operation for un-concreted pipe ƒ Reassessment of weld stresses ƒ Loss of section – risk if rupture occurs on reel ƒ Already well established for small diameter lines and flexibles (Phillips in GoM in 2001)

Phillips recovered a line using reeling techniques. However, care needs to be taken with the stresses at welds, bearing in mind that the line may have already been yielded during the lay and now with thinner wall it will be further damaged. The tensioner has to work in reverse to keep tension on the reel and yet be able to lift the line up from the seabed. Ideally, it needs to be undertaken on lines that were initially laid from a reel barge. However, it may be possible to permit damage on recovery of lines that were laid by other methods, providing that they are not concrete coated. The consequence of breakage on the reel can be catastrophic. The welds in particular may be subject to fatigue fracture. The pipelines can then be brought ashore for disposal. This method has been used for a number of lines in the Gulf of Mexico and for one in the North Sea. (Amerada Hess-Dubious / Doubtful Flowline) Flexibles do not suffer from yielding on recovery and can be spooled up safely.

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RECOVERY BY LAYBARGE

ƒ Simpler (cheaper) than normal lay vessel ƒ J-lay does not require high tension or overbend

This method is intended for the recovery of pipelines that are either exposed on the seabed or have been unburied with specialist equipment. Either an existing laybarge or converted workbarge could be used. The J-lay approach is preferred because it requires less tension on the (possibly corroded) steel pipeline and there is no overbend on a stinger, which requires the steel to normally be taken to around 90% of yield during laying operations. Outline procedure: Deploy retrieval clamp and recovery wire to pipeline end; Recover wire through the A winch and secure pipeline with tensioners; Move barge with pipeline being recovered through tensioners; Cut pipe into pre-determined lengths and store on barge deck; Transfer pipe lengths onto supply vessel for disposal/recycling on shore or re-use after refurbishment. Advantages Utilisation of existing equipment High speed operation for long lengths Disadvantages High operating costs

CUTANDLIFT

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CUT AND LIFT

ƒ Removal of three BNFL outfalls in 2005/6 ƒ Demanded by local authority as part of planning

ƒ Severely corroded line breakup ƒ Coal-tar radioactivity on beach

Lifting stillages onto transport barge

This method is intended for the recovery of ‘short’ lengths of pipeline or bundle that are either exposed on the seabed or have been unburied with specialist equipment. A shallow- draught first-generation workbarge could be utilised. Outline procedure: Pipeline cut on seabed into pre-determined lengths Recovery grabs deployed to lift sections out of water onto barge deck Transfer pipe sections onto supply vessel for disposal/recycling onshore or re-use after refurbishment Advantages The pipeline does not require high degree of structural integrity Work could be undertaken inshore in shallow water Disadvantages Subsea cutting equipment for large diameter lines would need further development Debris from cutting released into the marine environment Barge operations slow and weather-dependent A small barge was used by Land & Marine to recover three rain water outfalls, which were potentially contaminated with low level radioactivity, in 2005. Their removal was a requirement of original planning consent. Seabed stillages (storage racks) were used to store the sections prior to lifting onto the barge. Of particular concern was the condition of one line, which was so severely corroded that there were fist-size holes in the wall. Additionally, pieces of coal-tar enamel breaking off and floating ashore (with its natural inherent radioactivity) could give a false reading of unapproved releases.

REFLOATPIPELINEANDTOWTOSHORE

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REFLOAT PIPELINE AND TOW TO SHORE

ƒ Use of divers to attach buoyancy to line ƒ In deeper water, pull back onto barge and relaunch ƒ Bottom tow or CDT to shore Converted recovery vessel Pipe-lift davits

Hold-back winch

Sea level

Flotation bags

Seabed Abandoned pipeline Unburied pipeline

Stingers fore and aft

Cut and install end cap

Offshore tow tug

Flotation bags

Tow head

Seabed

An alternative would be to attach buoys to long sections of the pipeline – perhaps up to 4 km (2½ miles) and then tow it to shore, where it can be cut up. In shallower water, divers could undertake this. An alternative would be to pull it up onto a specially-designed barge, where buoyancy could be added. A pair of stingers would be required to be fitted to the specially-designed laybarge for support. It is likely that a flat- bottomed anchor barge could be adapted. Once ashore, the steel and concrete could be recovered.

BUNDLERECOVERY

BUNDLE RECOVERY

ƒ Bundle recovery by off-bottom towing ƒ Use ballast to raise bundle off the seabed ƒ Fill bundle with air ƒ Use ballast chains to stabilise ƒ Tow to an onshore facility ƒ Advantage ƒ No offshore cutting of pipeline ƒ Disadvantages ƒ Depends on structural integrity of bundle ƒ Extensive preparatory work

This method is intended to recover continuous lengths of bundles that are lying on the seabed with minimal rock dump protection.

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Decommissioning and abandonment

The bundle and towheads are prepared and raised clear of the seabed for towing to an onshore bundle fabrication area in the on or off-bottom mode. Outline procedure: Remove flowline spools and fit pig launchers and receivers Fit carrier pipe clamps with fill and drain valves at suitable points Check integrity of ballast chains and replace as necessary Purge carrier with air to displace inhibited water Purge flowlines to raise bundle clear of seabed (fit any supplementary buoyancy) Connect tow and trail tugs Shorten rigging to raise towheads clear of seabed Tow to fabrication area along pre-surveyed route with protected pipeline crossing points Recover on fabrication area for disposal/recycling or re-use after refurbishment Advantages No offshore cutting of pipeline Less dependency on specialist vessels Disadvantages Extent of preparatory work before tow can commence Probable use of divers Dependent upon structural integrity of bundle Need to protect third party crossings

RECOVERYSUMMARY

RECOVERY – SUMMARY

ƒ Recover the following ƒ Small diameter rigid and flexible pipes ƒ Downhole and flowline tubing

ƒ Bundles and contaminated pipelines ƒ Landfalls if required by local authority ƒ Methods of recovery ƒ Reeling or lay-barge recovery (pipe lay in reverse)

ƒ Cut and lift or refloat and tow ƒ Off-bottom tow for bundles

Any questions?

Recovery of pipelines is a viable options for the above listed pipeline types. The methods of recovery are detailed above and are specific to the type of pipeline being recovered. The method available will be dependent on the type of pipeline and we have examined the appropriate methods for different pipeline types.

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RE-USE

RE-USE

RE-USE

ƒ Re-use feasible for: ƒ Flexibles ƒ Thin-walled downhole or flowline tubing ƒ Bundles ƒ Rigid flowlines ƒ Consider methods in following slides ƒ Although feasible, it is unlikely that reuse of rigid lines will be commercially viable

Some pipeline re-use is possible. We consider how this may be done in the following slides. However, with corrosion issues on rigid lines, and the difficulty of recovering without overstressing, reuse of these is unlikely to be economic.

FLEXIBLES

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Decommissioning and abandonment

FLEXIBLES

ƒ Re-use of flexibles

ƒ Common offshore Brazil ƒ End lifted and re-reeled ƒ Cleaned, inspected and overhauled prior to re- use ƒ End fittings usually replaced ƒ Australian QA / insurance recertification concerns

Any damage tends to occur near the end fittings so that is why these are replaced. The whole length is fully inspected and any repairs carried out. Brazil has a stockpile of flexibles, stored in a lake (out of sunlight), that are ready for reuse. Nevertheless, in Australia, reused flexibles cannot get insurance.

BUNDLES

BUNDLES

ƒ Bundle dewatered ƒ Some chains released by ROV or diver ƒ Towed to new location using off-bottom method ƒ Reflooded and weight mattresses added ƒ Goosander field, north of Kittiwake ƒ Installed by Subsea 7 for Venture ƒ Reusable bundle 12.3 km (7½ miles) in two lengths ƒ Production flowline, water injection, gas lift with chemical injection and control lines

There is the possibility of a bundle being reused. However, this would require a very similar configuration (both length and flowline cross-section) for the second field. It would need to be refloated by purging the flowlines with gas. The annulus could be dewatered using a gel slug, which could pass the pipeline spacers.

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If additional weight needs removal, then an ROV or divers could cut the straps and release some of the chains. When it has been towed to the new location in the on-bottom configuration, the weight would be restored by reflooding and the addition of weight blocks or concrete mattresses. At least one reusable bundle has recently been installed in the North Sea. The Goosander field, some 12 km (7½ miles) northwest of Kittiwake (in block 21/12 of UK sector of the North Sea) is being developed by Venture using a reusable pipeline bundle, fabricated in two main sections, 4.9 km (3 miles) and 7.4 km (4½ miles) long, both of which were engineered and installed by Subsea 7. The bundles each comprise a 219.1 mm (8⅝ in) production flowline, a 168.3 mm (6⅝ in) water injection flowline, a 101.6 mm (4 in) gas lift line, and a chemical injection/control line. The system has also been designed to allow other fields to flow through the infrastructures. Currently, the bundle is still producing at the original field.

RIGIDFLOWLINES

RIGID FLOWLINES

ƒ Bottom tow to near-by location ƒ Re-reel ƒ Issue of total plastic strain ƒ Weld fatigue

ƒ Serious issues with weld quality after internal corrosion ƒ JIP currently underway at The Welding Institute ƒ Unlikely to be financially viable

Bottom tow can also be used to relocate rigid pipelines at a new route nearby. Although flowlines can be recovered onto a reel barge, there are some concerns with the condition of the welds when subject to additional cumulative yielding again during recovery and reinstallation. This is particularly the case when considerations of corrosion are allowed for. Neither is likely to be economic. Which operator wants to start production with all the damage from a previous operation?

RE-USESUMMARY

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RE-USE – SUMMARY

ƒ Some pipeline types can be re-used ƒ Flexibles, tubing, bundles, rigid flowlines ƒ May need to carry out some or all of following operations ƒ De-water, clean, inspect, recondition, replace end fittings ƒ Relocating method depends on pipeline type ƒ Lift, bottom tow, off-bottom tow, re-reel

Any questions?

Some pipeline types can be re-used at other locations. Re-use may have been an initial requirement for which the pipeline was initially designed or the pipeline is found to be in a suitable condition for re-use at the end of its service life. If re-using the pipeline, then the above operations may need to be carried out before the pipeline can be moved and reinstalled. The required operations for the type of pipeline have been detailed in this section. Also detailed have been the methods available for each pipeline type.

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COSTS

ENVIRONMENTALANDFINANCIALCOSTS

ENVIRONMENTAL AND FINANCIAL COSTS ƒ In all cases, cleaning is required ƒ Burial contracts placed ‘at-cost’

ƒ Limited data to date for HAZOP/SAFOP ƒ Qualitative rather than quantitative assessments ƒ All lift and recovery has safety issues ƒ Outweighs leave in-situ by a factor of ten ƒ Risks to divers ƒ Steel and concrete reclamation not cost-effective ƒ Anodes depleted

For all options, it is necessary to first clean the pipeline. Burial contracts for those pipelines that require reburial or deeper burial have been let in Norway to CTC. These have been bid on the basis that work will only be carried out if the vessels and trenching equipment have no other work. The rates are quoted per kilometre buried, and are effectively charged at minimal costs to keep the equipment busy in off seasons. If other commitments do not allow any work in a particular year, it can be passed over to the following quiet period. Pipelines up to 1524 mm (60 in) are trenched on a one- pass ‘reasonable endeavours’ basis. Because there have been very limited removal operations to date, the hazard or safety assessments are necessarily of a qualitative nature. The salvage costs for the materials do not nearly make the operations cost-effective. With the exception of removal of anodes – which can cause metal pollution of the seabed – there are little environmental benefits either. Where: HAZOP = hazard and operability (analysis study) SAFOP = safe operations (analysis)

LINEREMOVALCHECKSHEET

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LINE REMOVAL CHECKSHEET

ƒ Environmental issues ƒ Soil disturbance – seabed modification issues ƒ Coral – primary or secondary growth (on pipe) ƒ Disposal of steel ƒ Disposal of concrete and other coatings ƒ Disposal/storage of residual contents ƒ Health and safety issues ƒ Divers hours at depth ƒ Handling of pipeline offshore and onshore ƒ Radioactivity of residual product ƒ Proximity of live adjacent assets or adjacent pipelines This and the following slides show some of the issues that must be considered when carrying out an assessment and selecting the best removal method. When using this list to determine weightings, remember it all depends on your perspective! Thus, it is recommended that wide advance stakeholder engagement helps. Cost estimates should be undertaken for each option. ƒ Pipeline criteria ƒ Burial condition – additional costs for unburial ƒ Diameter – larger lines more expensive ƒ Overcrossings – cut 30 m (100 ft) either side ƒ Cannot reverse lay – requires cut-and-lift options ƒ Heavy corrosion or build-up prevents cleaning ƒ Injury to personnel hot cutting or spillages to sea ƒ Piggability – may require fitting of temporary pig traps ƒ Line integrity for removal – strong enough to lift ƒ Water depth – use of ROVs or divers to recover ƒ Removal of mattresses and crossings ƒ Re-qualification of lifting points LINEREMOVALCHECKSHEET LINE REMOVAL CHECKSHEET

LINEREMOVALCHECKSHEET

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LINE REMOVAL CHECKSHEET

ƒ Future liability ƒ Fishing – snagging of nets on disturbed spoil ƒ Tourism – diving on coral areas ƒ Other operators – future use of area ƒ Reputation / stakeholder views – rubbish left behind ƒ Possible benefit to fishing – providing shelter ƒ Future management/monitoring – none, if removed ƒ Remaining life – remove whole infrastructure at EOFL ƒ Future lines – require more crossings ƒ Use of local contractors – may need new expertise ƒ Precedence – may set standard for line removal

Where:

EOFL = end of field life

BSEE(FORMERLYMMS) COSTESTIMATES(2004)

BSEE (FORMERLY MMS) COST ESTIMATES (2004) ƒ Gulf of Mexico – local equipment ƒ Total of over 4320 km (2683 miles)

ƒ 62% in range 101.6 mm to 323.8 mm (4 in to 12¾ in) ƒ 3.2% over 762 mm (30 in) ƒ Shallow water depths, 60 m to 150 m (200 ft to 500 ft) ƒ Initially concentrating on nearshore, and areas where with shrimp trawler interaction is likely ƒ Typical pipeline length 6.5 km (4 miles) ƒ Does not include onshore costs ƒ Crossings and other difficult sections excluded

The above cost estimates are taken from BSEE (formerly MMS) paper 32.701.001/R1 of 2004. They refer to the Gulf of Mexico and assume that a suitable barge could be adapted within two days mobilisation/demobilisation. For other areas of the US – fields such as Alaska or California, where there are much shorter lengths of pipeline (>2% of total) to be recovered – sailing costs become significant for specialist equipment and expertise.