Ultra-deep water port: feasibility study

Appendix D: Analysis of decommissioning sector

Appendix D provides an overview of the offshore oil and gas UKCS decommissioning market, it covers:

• A breakdown of the current UKCS platforms and floating assets;
• An explanation of the decommissioning process and expenditure forecast; and
• Reviews previous decommissioning projects and future projects that have been submitted to BEIS for approval.

Each area is examined in turn.

UKCS Platforms and Floating Assets

All data used in this section has been collated from the OSPAR list of offshore installations^[24], which was refined by EY to account for certain installations which have already been removed to shore for decommissioning.

Location of offshore installations

There are 322 offshore installations, being platforms and floating assets, in the UKCS as at 2018:

• 290 of these installations are platforms with 282 being fixed steel structure, while 8 are gravity-based concrete; and
• The remaining 32 are floating assets.

The installations are grouped across five areas, with the number in each area illustrated by the following figure.

Figure 8: Location of UKCS Platforms and Floating Assets

Source OSPAR

With 175 the majority of these installations are therefore located in the Southern North Sea (SNS), followed by CNS with 80 and NNS with 43.

Platform Tonnage

While the majority of platforms are located in the SNS, these platforms tend to be smaller than those which are located in the CNS and NNS. The average topside weight for a platform located in the SNS is c 1,500 tonnes compared to c18,900 tonnes in the NNS. The total tonnage of platforms sub-structures and topsides located in the UKCS is outlined in the figure below.

Figure 9: UKCS Platform Weights - including concrete gravity based sub-structures

Source OSPAR

In total, platforms in the NNS have significantly greater weight than those in other locations. However, it should be noted that the weights for the NNS include seven sub-structures which are gravity-based concrete. These structures account for 75% of the total sub-structure weight for the NNS. Operators of concrete gravity based sub-structures may be able to apply for derogation from the regulations requiring these parts of the structure to be removed onshore. As such, the total weights presented in the table above, may not directly correlate with the total expected tonnage that will come onshore.

The figure below restates the analysis to remove gravity based sub structures.

Figure 10: UKCS Platform Weights - excluding concrete gravity based sub-structures

Source OSPAR

If the concrete gravity based structures are excluded from the analysis, the total weight of all UKCS assets is 1.2m tonnes for sub-structures and 1.6m for topsides. The majority of platform tonnage is located in the NNS and CNS. These two locations account for 78% of UKCS platform sub-structure tonnage and 76% UKCS platform topside tonnage.

Decommissioning Process

The need for decommissioning

In the oil & gas field life cycle, operators will eventually reach a point where the continued production at the site becomes uneconomical. There are a number of factors which impact this, but a key issue is the prevailing oil price. In periods of long term low oil prices, operators may find that future returns from the field are outweighed by future costs. Once an operator has made its decision to cease production, it needs to apply to the OGA for approval for a permanent CoP.

Following the decision to permanently cease production at a field, an operator must decide what it will do with the assets located at the field - platforms, substructures, pipelines etc. If possible, assets will be re-used elsewhere or, with the exception of some structures, they must be returned to shore for recycling and disposal.

The requirement for offshore operators to perform asset decommissioning is established in UK and international legislation. The most significant obligations for operators are outlined in OSPAR decision 98/3 (OSPAR 98/3) which prohibits the dumping or leaving wholly or partially in place offshore installations. Derogations to allow certain structures to remain in situ can and have been granted in the past. Where no derogation for the requirements is granted, all offshore assets must be removed and re-used or recycled.

The decommissioning process

The activities in a decommissioning process are generally allocated to the phases of work outlined in the table below.

Table 33: Decommissioning work breakdown structure

Phase	Description
Owner costs	Project management core team, stakeholder engagement, studies to support decommissioning programme and scope definition/method development, decommissioning programme preparation and decommissioning programme reporting/close-out (admiralty charts, fish safe etc). Logistics (aviation and marine), operations team, deck crew, power generation, platform services, integrity management (inspection and maintenance) and operations specialist services e.g. waste management.
Well Abandonement	Rig upgrades, studies to support well programmes, well suspension (spread rate/duration), wells project management, operations support, specialist services e.g. wireline, conductor recovery, cleaning and recycling, vessel.
Topside removal	Operations (drain, fluch, purge and vent), physical isolation (de-energise, vent, drain), cleaning, pipeline pigging and waste management. Engineering-up of temporary utilities (power, air and water), module process/utilities separation, dropped object survey and subsequesnt remedial actions. Removal preparation (reinforcements and structural separation for removal), removal, vessel operations, sea-fastening, transportation and load-in.
Substructure removal	Removal preparation, removal, vessel, sea-fastening, transportation and load-in.
Subsea Infrastructure	Vessel preparation for subsea end-state (remove, trench, rock-dump), sea fastening and transportation, load-in, subsea project management and waste management accounting (tracability of all streams) Cuttings pile management, oil field debris clearance (500m zone and 200m pipeline corrifor) and over-trawl surveys. Activities include navigation aids, maintenance and monitoring programme for any facilities that remain.
Onshore recycling and disposal	Cleaning and handling hazardous waste, deconstruction, re-use, recycling, disposal and waste management accounting (tracability of all streams).

Source: Oil & Gas UK: Decommissioning Insights 2017, OGA: UKCS Decommissioning 2017 Cost Estimate Report

The feasibility study focuses on the onshore recycling and disposal element of the decommissioning process.

Onshore disposal largely constitutes the work performed by the onshore contractor to dismantle, recycle and where applicable dispose of materials from installations transported onshore.

Total Decommissioning Costs

Using operator feedback, the OGA has performed a costing exercise to estimate the total costs of decommissioning across the UKCS^[25]. The approach used was to determine a probalistic cost estimate which captures the high degree of uncertainty in current decommissioning cost estimates. This provided a cost distribution of £44.5bn to £82.7bn with the OGA using £59.7bn as its base for future cost reduction targets.

The OGA used the information collected from operators to apportion costs to the decommissioning phases, this is illustrated in the following figure:

Figure 11: Decommissioning costs per WBS

Source: OGA

This demonstrates:

• Well abandonment is the most significant category of cost accounting for 48% of expected expenditure;
• Topside and substructure removal combined account for 21% of expected future costs; and
• Onshore recycling & disposal is the smallest expected cost category at 2%. When considering this within the context of the decommissioning cost estimates from the OGA, this would amount to expected expenditure between £890m and £1.7bn. According to the OGA's base estimate the cost of onshore recycling and disposal is £1.2bn.

Decommissioning projects

Approved decommissioning projects

A number of decommissioning projects have already been completed in the UKCS to date which provide an evidence base of decommissioning methodologies, vessels and disposal yards used in the process. A list of BEIS approved platform decommissioning projects since 2007 onwards is outlined in the table overleaf.

Table 34: Approved decommissioning projects

Platform	Operator at approval	Basin	Topside Weight (Tonnes)	Jacket Weight (Tonnes)	Methodology	Vessel	Disposal Yard
Audrey A (WD)	Spirit Energy North Sea Limited	SNS	1,276	1,063	Not available
Audrey B (XW)		SNS	1,298	865	Not available
Markham ST-1	Centrica Production Nederland B.V.	SNS	1,299	1,219	Reverse Engineer	Stanislav Yudin	Not available
Vulcan UR	ConocoPhillips (U.K.) Limited	SNS	916	1,138	Reverse Engineer	Not available
Viscount VO		SNS	330	731
Vampire OD		SNS	345	587
Leman	Shell U.K. Limited	SNS	1,039	566	Reverse Engineer	Not available	Greater Yarmouth
Janice (FPU)	Maersk Oil UK Limited	CNS	30,600	n/a	Towed to shore	N/a	Vats, Norway
Viking - CD	ConocoPhillips (U.K.) Limited	SNS	172	1,185	Not available
Viking - DD		SNS	171	756
Viking - ED		SNS	409	752
Viking - GD		SNS	164	586
Viking - HD		SNS	164	743
Horne & Wren	Tullow Oil SK Limited	SNS	90	455	Reverse Engineer	Rambiz	Holland
Thames Complex AP	Perenco UK Limited	SNS	6,488	1,100	Reverse Engineer	Rambiz	Holland
Thames Complex AW		SNS	2,035	950
Thames Complex AR		SNS	406	600
Brent Delta	Shell U.K. Limited	NNS	24,200	n/a	Single lift	Pioneering Spirit	Able Seaton, UK
Murchison	CNR	NNS	24,584	24,640	Reverse Engineer and piece small	Thialf	Vats, Norway
Miller	BP Exploration (Alpha) Limited	NNS	28,732	18,584	Reverse Engineer	Saipem 7000	Kvaerner Stord, Norway
Camelot CA	Energy Resource Technology (UK) Limited	SNS	1,220	600	Reverse Engineer	Rambiz	Holland
MCP-01	Total E&P UK Limited	NNS	13,500	0	Piece Small and Reverse Engineer	Saipem 7000	Greenhead Base, Lerwick and Kvaerner Stord, Norway
Juliet-D	Shell U.K. Limited	SNS	2,345	910	Piece small and reverse Engineer	Stanislav Yudin	Swan Hunter, Newcastle
Juliet-P		SNS	655	363
Kilo		SNS	2,818	816
Lima		SNS	1,448	836	Reverse Engineer
Mike		SNS	522	637
November		SNS	495	703

Source: https://www.gov.uk/guidance/oil-and-gas-decommissioning-of-offshore-installations-and-pipelines, https://www.ogauthority.co.uk/data-centre/data-downloads-and-publications/infrastructure/

Of the 28 platforms, reverse engineering was used in some form on all occasions except two, highlighting that has been the most frequently used method in the decommissioning industry. For MCP-01, Juliet-D, Juliet-P and Kilo, where piece small decommissioning was used, close out reports for these projects highlighted that the use of piece small led to an increased expenditure.

The majority of decommissioning projects have been on smaller platforms which are based in the SNS. These projects have used smaller crane vessels such as the Stanislav Yudin or the Rambiz. Larger structures, such as the Miller, Murchison and Brent Delta have used UHLVs or SLVs for their decommissioning projects.

The Janice Floating Production Unit was towed to shore using the same methodology employed for the Buchan Alpha floating production vessel. Highlighting that the decommissioning of floating structures does not necessarily require UHLVs or SLVs.

The Brent Delta platform, which was decommissioned via single lift was the second platform to be removed in this manner. It set a world lifting record and effectively demonstrated the methodology as viable for large scale decommissioning projects going forward.

No projects on the list using an UHLV have been taken to the UK for decommissioning. As noted in the MCP-01 close out report:

'Initially the intention was that 100% of the topsides would be sent to Shetland. However, the decision to remove the large modules using the Saipem 7000 and transporting them on deck to shore meant that Shetland could not be used for that purpose as the water depth at quayside is insufficient. In the final accounting some 5400 tons went to Shetland and the remainder - 9600 tons - went to Stord.'

This issue is further highlighted in an article discussing the Miller decommissioning project

'This does require access to an ultra-deepwater quayside and port so that the S7000 can remain ballasted down at transit depth until off-load is complete. Given the current lack of such facilities in the UK, Saipem has opted to take the Miller sections to the Kværner Stord AS yard in Norway for final disposal and recycling'^[26].

Thus highlighting vessel operators' unwillingness to bring decommissioning projects using UHLVs to the UK due to a lack of an UDW port.

As such, from a review of past decommissioning programmes it appears that UHLV will be required to decommission larger structures which tend to be focused in the NNS. For smaller structures, typically found in the SNS, smaller vessels are used, while floating units can be towed to shore.

Planned decommissioning projects

The table below outlines planned projects which have decommissioning programmes submitted with BEIS for approval.

Table 35: Planned UKCS decommissioning projects

Platform	Location	CoP	Expected topside removal timing	Expected jacket removal timing	Topside weight	Jacket Weight	Decommissioning methods being considered
Windemere	SNS	2016	2021	2021	452	382	Reverse engineer with small HLV
Jacky wellhead platform	MF	2017	2022	2022	663	596	Reverse engineer with small HLV
East Brae	NNS	2020	2021	2023	20,000	10,054	All considered
Brae Alpha	NNS	2021	2023-2025	2026	30,200	20,000	All considered
Brae Bravo	NNS	2018	2026-2028	2029	36,200	22,000	All considered
Ninian Northern Platform	NNS	2017	2019-2020	2032	12,453	15,561	All considered
Brent Alpha	NNS	2014	2021	2022	16,000	10,113	Single lift
Brent Bravo	NNS	2014	2020	N/a	24,100	Leave in Place	Single lift
Brent Charlie	NNS	tbc	Not before 2025	N/a	31,000	Leave in Place	Considering HLV, SLV or piece small

Source: https://www.gov.uk/guidance/oil-and-gas-decommissioning-of-offshore-installations-and-pipelines

Of the planned decommissioning projects, those with smaller tonnages have outlined plans to use smaller HLVs, which is in line with past projects.

The Brent Alpha and Brent Bravo platforms will use the single lift removal method which is in line with the method used on the Brent Delta field. All other decommissioning programmes outline they will select the appropriate method following a tendering process with removal operators. As such, there does not appear to be a clear correlation between the characteristics of a platform and the preferred decommissioning method.

For the large platforms, topside removal is expected to be between one and ten years following CoP with substructures generally being removed the following year. Even within these expected timeframes, operators often highlight in decommissioning programmes that topside removal could take place over a three to four year window of opportunity. As such there is no clear definition of when a topside could be removed and may ultimately take place when market and other conditions prove favourable for the operator.

Decommissioning Market Summary

The key findings from the decommissioning market overview are as follows:

• There are over 300 platforms in the UKCS. While the majority are located in the SNS, the largest structures are based in the CNS and NNS.
• The overall expected expenditure on UKCS platform decommissioning is estimated at £59.7bn, with onshore recycling and disposal activities estimated to account for £1.2 billion, 2%, of it.
• Reverse engineer decommissioning has been frequently applied, either for the full removal or as part of the process of completed decommissioning projects. Large platforms using this method require the use of an UHLV. Due to a lack of UDW at UK ports, all projects using an UHLV have been taken to Norway, where there are ports with UDW.
• The successful completion of the Brent Delta platform decommissioning using SLV effectively demonstrated the methodology as viable for large scale decommissioning projects going forward.
• Going forward, there is expected to be competition for each platform from existing UHLVs and SLVs, with the potential for new solutions to enter the market due to the long timespan of the remaining platforms.
• Selection of the removal method is likely to be driven by a number of factors such as cost, complexity of the platform, operator confidence in the vessel operator, health and safety considerations and other requirements.